[Title 30 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2017 Edition]
[From the U.S. Government Publishing Office]



[[Page i]]

          

          Title 30

Mineral Resources


________________________

Parts 200 to 699

                         Revised as of July 1, 2017

          Containing a codification of documents of general 
          applicability and future effect

          As of July 1, 2017
                    Published by the Office of the Federal Register 
                    National Archives and Records Administration as a 
                    Special Edition of the Federal Register

[[Page ii]]

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                            Table of contents



                                                                    Page
  Explanation.................................................       v

  Title 30:
          Chapter II--Bureau of Safety and Environmental 
          Enforcement, Department of the Interior                    3
          Chapter IV--Geological Survey, Department of the 
          Interior                                                 335
          Chapter V--Bureau of Ocean Energy Management, 
          Department of the Interior                               347
  Finding Aids:
      Table of CFR Titles and Chapters........................     629
      Alphabetical List of Agencies Appearing in the CFR......     649
      List of CFR Sections Affected...........................     659

[[Page iv]]


      


                     ----------------------------

                     Cite this Code:  CFR
                     To cite the regulations in 
                       this volume use title, 
                       part and section number. 
                       Thus, 30 CFR 203.0 refers 
                       to title 30, part 203, 
                       section 0.

                     ----------------------------

[[Page v]]



                               EXPLANATION

    The Code of Federal Regulations is a codification of the general and 
permanent rules published in the Federal Register by the Executive 
departments and agencies of the Federal Government. The Code is divided 
into 50 titles which represent broad areas subject to Federal 
regulation. Each title is divided into chapters which usually bear the 
name of the issuing agency. Each chapter is further subdivided into 
parts covering specific regulatory areas.
    Each volume of the Code is revised at least once each calendar year 
and issued on a quarterly basis approximately as follows:

Title 1 through Title 16.................................as of January 1
Title 17 through Title 27..................................as of April 1
Title 28 through Title 41...................................as of July 1
Title 42 through Title 50................................as of October 1

    The appropriate revision date is printed on the cover of each 
volume.

LEGAL STATUS

    The contents of the Federal Register are required to be judicially 
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HOW TO USE THE CODE OF FEDERAL REGULATIONS

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[[Page vi]]

Many agencies have begun publishing numerous OMB control numbers as 
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[[Page vii]]

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    Oliver A. Potts,
    Director,
    Office of the Federal Register.
    July 1, 2017.

                                
                                      
                            

  

[[Page ix]]



                               THIS TITLE

    Title 30--Mineral Resources is composed of three volumes. The parts 
in these volumes are arranged in the following order: parts 1--199, 
parts 200--699, and part 700 to end. The contents of these volumes 
represent all current regulations codified under this title of the CFR 
as of July 1, 2017.

    For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of John 
Hyrum Martinez, assisted by Stephen J. Frattini.

[[Page 1]]



                       TITLE 30--MINERAL RESOURCES




                  (This book contains parts 200 to 699)

  --------------------------------------------------------------------
                                                                    Part

chapter ii--Bureau of Safety and Environmental Enforcement, 
  Department of the Interior................................         203

chapter iv--Geological Survey, Department of the Interior...         401

chapter v--Bureau of Ocean Energy Management, Department of 
  the Interior..............................................         519

[[Page 3]]



 CHAPTER II--BUREAU OF SAFETY AND ENVIRONMENTAL ENFORCEMENT, DEPARTMENT 
                             OF THE INTERIOR




  --------------------------------------------------------------------

                SUBCHAPTER A--MINERALS REVENUE MANAGEMENT
Part                                                                Page
200-202         [Reserved]

203             Relief or reduction in royalty rates........           5
219             [Reserved]

                         SUBCHAPTER B--OFFSHORE
250             Oil and gas and sulphur operations in the 
                    Outer Continental Shelf.................          44
251             Geological and geophysical (G&G) 
                    explorations of the Outer Continental 
                    Shelf...................................         286
252             Outer Continental Shelf (OCS) Oil and Gas 
                    Information Program.....................         291
253             [Reserved]

254             Oil-spill response requirements for 
                    facilities located seaward of the coast 
                    line....................................         296
256             Leasing of sulphur or oil and gas in the 
                    Outer Continental Shelf.................         311
259-260         [Reserved]

270             Nondiscrimination in the Outer Continental 
                    Shelf...................................         313
280             Prospecting for minerals other than oil, 
                    gas, and sulphur on the Outer 
                    Continental Shelf.......................         315
281             [Reserved]

282             Operations in the Outer Continental Shelf 
                    for minerals other than oil, gas, and 
                    sulphur.................................         316
285             [Reserved]

                          SUBCHAPTER C--APPEALS
290             Appeal procedures...........................         327
291             Open and nondiscriminatory access to oil and 
                    gas pipelines under the Outer 
                    Continental Shelf Lands Act.............         328
292-299         [Reserved]

[[Page 5]]



                SUBCHAPTER A_MINERALS REVENUE MANAGEMENT



                        PARTS 200	202 [RESERVED]



PART 203_RELIEF OR REDUCTION IN ROYALTY RATES--Table of Contents



                      Subpart A_General Provisions

Sec.
203.0  What definitions apply to this part?
203.1  What is BSEE's authority to grant royalty relief?
203.2  How can I obtain royalty relief?
203.3  Do I have to pay a fee to request royalty relief?
203.4  How do the provisions in this part apply to different types of 
          leases and projects?
203.5  What is BSEE's authority to collect information?

               Subpart B_OCS Oil, Gas, and Sulfur General

 Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to 
                        Deep Water Royalty Relief

203.30  Which leases are eligible for royalty relief as a result of 
          drilling a phase 2 or phase 3 ultra-deep well?
203.31  If I have a qualified phase 2 or qualified phase 3 ultra-deep 
          well, what royalty relief would that well earn for my lease?
203.32  What other requirements or restrictions apply to royalty relief 
          for a qualified phase 2 or phase 3 ultra-deep well?
203.33  To which production do I apply the RSV earned by qualified phase 
          2 and phase 3 ultra-deep wells on my lease or in my unit?
203.34  To which production may an RSV earned by qualified phase 2 and 
          phase 3 ultra-deep wells on my lease not be applied?
203.35  What administrative steps must I take to use the RSV earned by a 
          qualified phase 2 or phase 3 ultra-deep well?
203.36  Do I keep royalty relief if prices rise significantly?

Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to Deep 
                          Water Royalty Relief

203.40  Which leases are eligible for royalty relief as a result of 
          drilling a deep well or a phase 1 ultra-deep well?
203.41  If I have a qualified deep well or a qualified phase 1 ultra-
          deep well, what royalty relief would my lease earn?
203.42  What conditions and limitations apply to royalty relief for deep 
          wells and phase 1 ultra-deep wells?
203.43  To which production do I apply the RSV earned from qualified 
          deep wells or qualified phase 1 ultra-deep wells on my lease?
203.44  What administrative steps must I take to use the royalty 
          suspension volume?
203.45  If I drill a certified unsuccessful well, what royalty relief 
          will my lease earn?
203.46  To which production do I apply the royalty suspension 
          supplements from drilling one or two certified unsuccessful 
          wells on my lease?
203.47  What administrative steps do I take to obtain and use the 
          royalty suspension supplement?
203.48  Do I keep royalty relief if prices rise significantly?
203.49  May I substitute the deep gas drilling provisions in this part 
          for the deep gas royalty relief provided in my lease terms?

                  Royalty Relief for End-of-Life Leases

203.50  Who may apply for end-of-life royalty relief?
203.51  How do I apply for end-of-life royalty relief?
203.52  What criteria must I meet to get relief?
203.53  What relief will BSEE grant?
203.54  How does my relief arrangement for an oil and gas lease operate 
          if prices rise sharply?
203.55  Under what conditions can my end-of-life royalty relief 
          arrangement for an oil and gas lease be ended?
203.56  Does relief transfer when a lease is assigned?

  Royalty Relief for Pre-Act Deep Water Leases and for Development and 
                           Expansion Projects

203.60  Who may apply for royalty relief on a case-by-case basis in deep 
          water in the Gulf of Mexico or offshore of Alaska?
203.61  How do I assess my chances for getting relief?
203.62  How do I apply for relief?
203.63  Does my application have to include all leases in the field?
203.64  How many applications may I file on a field or a development 
          project?
203.65  How long will BSEE take to evaluate my application?
203.66  What happens if BSEE does not act in the time allowed?
203.67  What economic criteria must I meet to get royalty relief on an 
          authorized field or project?
203.68  What pre-application costs will BSEE consider in determining 
          economic viability?

[[Page 6]]

203.69  If my application is approved, what royalty relief will I 
          receive?
203.70  What information must I provide after BSEE approves relief?
203.71  How does BSEE allocate a field's suspension volume between my 
          lease and other leases on my field?
203.72  Can my lease receive more than one suspension volume?
203.73  How do suspension volumes apply to natural gas?
203.74  When will BSEE reconsider its determination?
203.75  What risk do I run if I request a redetermination?
203.76  When might BSEE withdraw or reduce the approved size of my 
          relief?
203.77  May I voluntarily give up relief if conditions change?
203.78  Do I keep relief approved by BSEE under this part for my lease, 
          unit or project if prices rise significantly?
203.79  How do I appeal BSEE's decisions related to royalty relief for a 
          deepwater lease or a development or expansion project?
203.80  When can I get royalty relief if I am not eligible for royalty 
          relief under other sections in the subpart?

                            Required Reports

203.81  What supplemental reports do royalty-relief applications 
          require?
203.82  What is BSEE's authority to collect this information?
203.83  What is in an administrative information report?
203.84  What is in a net revenue and relief justification report?
203.85  What is in an economic viability and relief justification 
          report?
203.86  What is in a G&G report?
203.87  What is in an engineering report?
203.88  What is in a production report?
203.89  What is in a cost report?
203.90  What is in a fabricator's confirmation report?
203.91  What is in a post-production development report?

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

Subpart E--Solid Minerals, General [Reserved]

Subpart F [Reserved]

Subpart G--Other Solid Minerals [Reserved]

Subpart H--Geothermal Resources [Reserved]

Subpart I--OCS Sulfur [Reserved]

    Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 
2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 
1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-
15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 
1801 et seq.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.



                      Subpart A_General Provisions



Sec. 203.0  What definitions apply to this part?

    Authorized field means a field:
    (1) Located in a water depth of at least 200 meters and in the Gulf 
of Mexico (GOM) west of 87 degrees, 30 minutes West longitude;
    (2) That includes one or more pre-Act leases; and
    (3) From which no current pre-Act lease produced, other than test 
production, before November 28, 1995.
    Certified unsuccessful well means an original well or a sidetrack 
with a sidetrack measured depth (i.e., length) of at least 10,000 feet, 
on your lease that:
    (1) You begin drilling on or after March 26, 2003, and before May 3, 
2009, on a lease that is located in water partly or entirely less than 
200 meters deep and that is not a non-converted lease, or on or after 
May 18, 2007, and before May 3, 2013, on a lease that is located in 
water entirely more than 200 meters and entirely less than 400 meters 
deep;
    (2) You begin drilling before your lease produces gas or oil from a 
well with a perforated interval the top of which is at least 18,000 feet 
true vertical depth subsea (TVD SS), (i.e., below the datum at mean sea 
level);
    (3) You drill to at least 18,000 feet TVD SS with a target reservoir 
on your lease, identified from seismic and related data, deeper than 
that depth;
    (4) Fails to meet the producibility requirements of 30 CFR part 550, 
subpart A, and does not produce gas or oil, or meets those producibility 
requirements and Bureau of Ocean Energy Management (BOEM) agrees it is 
not commercially producible; and
    (5) For which you have provided the notices and information required 
under Sec. 203.47.

[[Page 7]]

    Complete application means an original and two copies of the six 
reports consisting of the data specified in Secs. 203.81, 203.83, and 
203.85 through 203.89, along with one set of digital information, which 
Bureau of Safety and Environmental Enforcement (BSEE) has reviewed and 
found complete.
    Deep well means either an original well or a sidetrack with a 
perforated interval the top of which is at least 15,000 feet TVD SS and 
less than 20,000 feet TVD SS. A deep well subsequently re-perforated at 
less than 15,000 feet TVD SS in the same reservoir is still a deep well.
    Determination means the binding decision by BSEE on whether your 
field qualifies for relief or how large a royalty-suspension volume must 
be to make the field economically viable.
    Development project means a project to develop one or more oil or 
gas reservoirs located on one or more contiguous leases that have had no 
production (other than test production) before the current application 
for royalty relief and are either:
    (1) Located in a planning area offshore Alaska; or
    (2) Located in the GOM in a water depth of at least 200 meters and 
wholly west of 87 degrees, 30 minutes West longitude, and were issued in 
a sale held after November 28, 2000.
    Draft application means the preliminary set of information and 
assumptions you submit to seek a nonbinding assessment on whether a 
field could be expected to qualify for royalty relief.
    Eligible lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
1995, and before November 28, 2000;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper;
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
    (4) Is offered subject to a royalty suspension volume.
    Expansion project means a project that meets the following 
requirements:
    (1) You must propose the project in a (BOEM) Development and 
Production Plan, a BOEM Development Operations Coordination Document 
(DOCD), or a BOEM Supplement to a DOCD, approved by the Secretary of the 
Interior after November 28, 1995.
    (2) The project must be located on either:
    (i) A pre-Act lease in the GOM, or a lease in the GOM issued in a 
sale held after November 28, 2000, located wholly west of 87 degrees, 30 
minutes West longitude; or
    (ii) A lease in a planning area offshore Alaska.
    (3) On a pre-Act lease in the GOM, the project:
    (i) Must significantly increase the ultimate recovery of resources 
from one or more reservoirs that have not previously produced (extending 
recovery from reservoirs already in production does not constitute a 
significant increase); and
    (ii) Must involve a substantial capital investment (e.g., fixed-leg 
platform, subsea template and manifold, tension-leg platform, multiple 
well project, etc.).
    (4) For a lease issued in a planning area offshore Alaska, or in the 
GOM after November 28, 2000, the project must involve a new well drilled 
into a reservoir that has not previously produced.
    (5) On a lease in the GOM, the project must not include a reservoir 
the production from which an RSV under Secs. 203.30 through 203.36 or 
Secs. 203.40 through 203.48 would be applied.
    Fabrication (or start of construction) means evidence of an 
irreversible commitment to a concept and scale of development. Evidence 
includes copies of a binding contract between you (as applicant) and a 
fabrication yard, a letter from a fabricator certifying that continuous 
construction has begun, and a receipt for the customary down payment.
    Field means an area consisting of a single reservoir or multiple 
reservoirs all grouped on, or related to, the same general geological 
structural feature or stratigraphic trapping condition. Two or more 
reservoirs may be in a field, separated vertically by intervening 
impervious strata or laterally by local geologic barriers, or both.
    Lease means a lease or unit.
    New production means any production from a current pre-Act lease 
from which no royalties are due on production, other than test 
production, before November 28, 1995. Also, it means any

[[Page 8]]

additional production resulting from new lease-development activities on 
a lease issued in a sale after November 28, 2000, or a current pre-Act 
lease under a BOEM DOCD or a BOEM Supplement approved by the Secretary 
of the Interior after November 28, 1995.
    Nonbinding assessment means an opinion by BSEE of whether your field 
could qualify for royalty relief. It is based on your draft application 
and does not entitle the field to relief.
    Non-converted lease means a lease located partly or entirely in 
water less than 200 meters deep issued in a lease sale held after 
January 1, 2001, and before January 1, 2004, whose original lease terms 
provided for an RSV for deep gas production and the lessee has not 
exercised the option under Sec. 203.49 to replace the lease terms for 
royalty relief with those in Sec. 203.0 and Secs. 203.40 through 203.48.
    Original well means a well that is drilled without utilizing an 
existing wellbore. An original well includes all sidetracks drilled from 
the original wellbore either before the drilling rig moves off the well 
location or after a temporary rig move that BSEE agrees was forced by a 
weather or safety threat and drilling resumes within 1 year. A bypass 
from an original well (e.g., drilling around material blocking the hole 
or to straighten crooked holes) is part of the original well.
    Participating area means that part of the unit area that BSEE 
determines is reasonably proven by drilling and completion of producible 
wells, geological and geophysical information, and engineering data to 
be capable of producing hydrocarbons in paying quantities.
    Performance conditions mean minimum conditions you must meet, after 
we have granted relief and before production begins, to remain qualified 
for that relief. If you do not meet each one of these performance 
conditions, we consider it a change in material fact significant enough 
to invalidate our original evaluation and approval.
    Phase 1 ultra-deep well means an ultra-deep well on a lease that is 
located in water partly or entirely less than 200 meters deep for which 
drilling began before May 18, 2007, and that begins production before 
May 3, 2009, or that meets the requirements to be a certified 
unsuccessful well.
    Phase 2 ultra-deep well means an ultra-deep well for which drilling 
began on or after May 18, 2007; and that either meets the requirements 
to be a certified unsuccessful well or that begins production:
    (1) Before the date which is 5 years after the lease issuance date 
on a non-converted lease; or
    (2) Before May 3, 2009, on all other leases located in water partly 
or entirely less than 200 meters deep; or
    (3) Before May 3, 2013, on a lease that is located in water entirely 
more than 200 meters and entirely less than 400 meters deep.
    Phase 3 ultra-deep well means an ultra-deep well for which drilling 
began on or after May 18, 2007, and that begins production:
    (1) On or after the date which is 5 years after the lease issuance 
date on a non-converted lease; or
    (2) On or after May 3, 2009, on all other leases located in water 
partly or entirely less than 200 meters deep; or
    (3) On or after May 3, 2013, on a lease that is located in water 
entirely more than 200 meters and entirely less than 400 meters deep.
    Pre-Act lease means a lease that:
    (1) Results from a sale held before November 28, 1995;
    (2) Is located in the GOM in water depths of 200 meters or deeper; 
and
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude.
    Production means all oil, gas, and other relevant products you save, 
remove, or sell from a tract or those quantities allocated to your tract 
under a unitization formula, as measured for the purposes of determining 
the amount of royalty payable to the United States.
    Project means any activity that requires at least a permit to drill.
    Qualified deep well means:
    (1) On a lease that is located in water partly or entirely less than 
200 meters deep that is not a non-converted lease, a deep well for which 
drilling began on or after March 26, 2003, that produces natural gas 
(other than test production), including gas associated with oil 
production, before May 3, 2009, and for

[[Page 9]]

which you have met the requirements prescribed in Sec. 203.44;
    (2) On a non-converted lease, a deep well that produces natural gas 
(other than test production) before the date which is 5 years after the 
lease issuance date from a reservoir that has not produced from a deep 
well on any lease; or
    (3) On a lease that is located in water entirely more than 200 
meters but entirely less than 400 meters deep, a deep well for which 
drilling began on or after May 18, 2007, that produces natural gas 
(other than test production), including gas associated with oil 
production before May 3, 2013, and for which you have met the 
requirements prescribed in Sec. 203.44.
    Qualified ultra-deep well means:
    (1) On a lease that is located in water partly or entirely less than 
200 meters deep that is not a non-converted lease, an ultra-deep well 
for which drilling began on or after March 26, 2003, that produces 
natural gas (other than test production), including gas associated with 
oil production, and for which you have met the requirements prescribed 
in Sec. 203.35 or Sec. 203.44, as applicable; or
    (2) On a lease that is located in water entirely more than 200 
meters and entirely less than 400 meters deep, or on a non-converted 
lease, an ultra-deep well for which drilling began on or after May 18, 
2007, that produces natural gas (other than test production), including 
gas associated with oil production, and for which you have met the 
requirements prescribed in Sec. 203.35.
    Qualified well means either a qualified deep well or a qualified 
ultra-deep well.
    Redetermination means our reconsideration of our determination on 
royalty relief because you request it after:
    (1) We have rejected your application;
    (2) We have granted relief but you want a larger suspension volume;
    (3) We withdraw approval; or
    (4) You renounce royalty relief.
    Renounce means action you take to give up relief after we have 
granted it and before you start production.
    Reservoir means an underground accumulation of oil or natural gas, 
or both, characterized by a single pressure system and segregated from 
other such accumulations.
    Royalty suspension (RS) lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
2000;
    (2) Is in locations or planning areas specified in a particular 
Notice of OCS Lease Sale offering that lease; and
    (3) Is offered subject to a royalty suspension specified in a Notice 
of OCS Lease Sale published in the Federal Register.
    Royalty suspension supplement (RSS) means a royalty suspension 
volume resulting from drilling a certified unsuccessful well that is 
applied to future natural gas and oil production generated at any 
drilling depth on, or allocated under a BSEE-approved unit agreement to, 
the same lease.
    Royalty suspension volume (RSV) means a volume of production from a 
lease that is not subject to royalty under the provisions of this part.
    Sidetrack means, for the purpose of this subpart, a well resulting 
from drilling an additional hole to a new objective bottom-hole location 
by leaving a previously drilled hole. A sidetrack also includes drilling 
a well from a platform slot reclaimed from a previously drilled well or 
re-entering and deepening a previously drilled well. A bypass from a 
sidetrack (e.g., drilling around material blocking the hole, or to 
straighten crooked holes) is part of the sidetrack.
    Sidetrack measured depth means the actual distance or length in feet 
a sidetrack is drilled beginning where it exits a previously drilled 
hole to the bottom hole of the sidetrack, that is, to its total depth.
    Sunk costs for an authorized field means the after-tax eligible 
costs that you (not third parties) incur for exploration, development, 
and production from the spud date of the first discovery on the field to 
the date we receive your complete application for royalty relief. The 
discovery well must be qualified as producible under 30 CFR part 550, 
subpart A. Sunk costs include the rig mobilization and material costs 
for the discovery well that you incurred before its spud date.

[[Page 10]]

    Sunk costs for an expansion or development project means the after-
tax eligible costs that you (not third parties) incur for only the first 
well that encounters hydrocarbons in the reservoir(s) included in the 
application and that meets the producibility requirements under 30 CFR 
part 550, subpart A on each lease participating in the application. Sunk 
costs include rig mobilization and material costs for the discovery 
wells that you incurred before their spud dates.
    Ultra-deep well means either an original well or a sidetrack 
completed with a perforated interval the top of which is at least 20,000 
feet TVD SS. An ultra-deep well subsequently re-perforated less than 
20,000 feet TVD SS in the same reservoir is still an ultra-deep well.
    Withdraw means action we take on a field that has qualified for 
relief if you have not met one or more of the performance conditions.



Sec. 203.1  What is BSEE's authority to grant royalty relief?

    The Outer Continental Shelf (OCS) Lands Act, 43 U.S.C. 1337, as 
amended by the OCS Deep Water Royalty Relief Act (DWRRA), Public Law 
104-58 and the Energy Policy Act of 2005, Public Law 109-058 authorizes 
us to grant royalty relief in four situations.
    (a) Under 43 U.S.C. 1337(a)(3)(A), we may reduce or eliminate any 
royalty or a net profit share specified for an OCS lease to promote 
increased production.
    (b) Under 43 U.S.C. 1337(a)(3)(B), we may reduce, modify, or 
eliminate any royalty or net profit share to promote development, 
increase production, or encourage production of marginal resources on 
certain leases or categories of leases. This authority is restricted to 
leases in the GOM that are west of 87 degrees, 30 minutes West 
longitude, and in the planning areas offshore Alaska.
    (c) Under 43 U.S.C. 1337(a)(3)(C), we may suspend royalties for 
designated volumes of new production from any lease if:
    (1) Your lease is in deep water (water at least 200 meters deep);
    (2) Your lease is in designated areas of the GOM (west of 87 
degrees, 30 minutes West longitude);
    (3) Your lease was acquired in a lease sale held before the DWRRA 
(before November 28, 1995);
    (4) We find that your new production would not be economic without 
royalty relief; and
    (5) Your lease is on a field that did not produce before enactment 
of the DWRRA, or if you propose a project to significantly expand 
production under a Development Operations Coordination Document (DOCD) 
or a supplementary DOCD, that the Bureau of Ocean Energy Management 
(BOEM) approved after November 28, 1995.
    (d) Under 42 U.S.C. 15904-15905, we may suspend royalties for 
designated volumes of gas production from deep and ultra-deep wells on a 
lease if:
    (1) Your lease is in shallow water (water less than 400 meters deep) 
and you produce from an ultra-deep well (top of the perforated interval 
is at least 20,000 feet TVD SS) or your lease is in waters entirely more 
than 200 meters and entirely less than 400 meters deep and you produce 
from a deep well (top of the perforated interval is at least 15,000 feet 
TVD SS);
    (2) Your lease is in the designated area of the GOM (wholly west of 
87 degrees, 30 minutes west longitude); and
    (3) Your lease is not eligible for deep water royalty relief.



Sec. 203.2  How can I obtain royalty relief?

    We may reduce or suspend royalties for Outer Continental Shelf (OCS) 
leases or projects that meet the criteria in the following table.

----------------------------------------------------------------------------------------------------------------
                                                                                     Then we may grant you . . .
        If you have a lease . . .                      And if you . . .
----------------------------------------------------------------------------------------------------------------
(a) With earnings that cannot sustain      Would abandon otherwise potentially       A reduced royalty rate on
 production (i.e., End-of-life lease),      recoverable resources but seek to         current monthly production
                                            increase production by operating beyond   and a higher royalty rate
                                            the point at which the lease is           on additional monthly
                                            economic under the existing royalty       production (see Secs.
                                            rate,                                     203.50 through 203.56).

[[Page 11]]

 
(b) Located in a designated GOM deep       Propose an expansion project and can      A royalty suspension for a
 water area (i.e., 200 meters or greater)   demonstrate your project is uneconomic    minimum production volume
 and acquired in a lease sale held before   without royalty relief,                   plus any additional
 November 28, 1995, or after November 28,                                             production large enough to
 2000,                                                                                make the project economic
                                                                                      (see Secs.  203.60 through
                                                                                      203.79).
(c) Located in a designated GOM deep       Are on a field from which no current pre- A royalty suspension for a
 water area and acquired in a lease sale    Act lease produced (other than test       minimum production volume
 held before November 28, 1995 (Pre-Act     production) before November 28, 1995,     plus any additional volume
 lease),                                    (Authorized field,)                       needed to make the field
                                                                                      economic (see Secs.
                                                                                      203.60 through 203.79).
(d) Located in a designated GOM deep       Propose a development project and can     A royalty suspension for a
 water area and acquired in a lease sale    demonstrate that the suspension volume,   minimum production volume
 held after November 28, 2000,              if any, for your lease is not enough to   plus any additional volume
                                            make development economic,                needed to make your
                                                                                      project economic (see
                                                                                      Secs.  203.60 through
                                                                                      203.79).
(e) Where royalty relief would recover     Are not eligible to apply for end-of-     A royalty modification in
 significant additional resources or,       life or deep water royalty relief, but    size, duration, or form
 offshore Alaska or in certain areas of     show us you meet certain eligibility      that makes your lease or
 the GOM, would enable development,         conditions,                               project economic (see Sec.
                                                                                       203.80).
(f) Located in a designated GOM shallow    Drill a deep well on a lease that is not  A royalty suspension for a
 water area and acquired in a lease sale    eligible for deep water royalty relief    volume of gas produced
 held before January 1, 2001, or after      and you have not previously produced      from successful deep and
 January 1, 2004, or have exercised an      oil or gas from a deep well or an ultra-  ultra-deep wells, or, for
 option to substitute for royalty relief    deep well,                                certain unsuccessful deep
 in your lease terms,                                                                 and ultra-deep wells, a
                                                                                      smaller royalty suspension
                                                                                      for a volume of gas or oil
                                                                                      produced by all wells on
                                                                                      your lease (see Secs.
                                                                                      203.40 through 203.49).
(g) Located in a designated GOM shallow    Drill and produce gas from an ultra-deep  A royalty suspension for a
 water area,                                well on a lease that is not eligible      volume of gas produced
                                            for deep water royalty relief and you     from successful ultra-deep
                                            have not previously produced oil or gas   and deep wells on your
                                            from an ultra-deep well,                  lease (see Secs.  203.30
                                                                                      through 203.36).
(h) Located in planning areas offshore     Propose an expansion project or propose   A royalty suspension for a
 Alaska,                                    a development project and can             minimum production volume
                                            demonstrate that the project is           plus any additional volume
                                            uneconomic without relief or that the     needed to make your
                                            suspension volume, if any, for your       project economic (see
                                            lease is not enough to make development   Secs.  203.60, 203.62,
                                            economic,                                 203.67 through 203.70,
                                                                                      203.73, and 203.76 through
                                                                                      203.79).
----------------------------------------------------------------------------------------------------------------



Sec. 203.3  Do I have to pay a fee to request royalty relief?

    When you submit an application or ask for a preview assessment, you 
must include a fee to reimburse us for our costs of processing your 
application or assessment. Federal policy and law require us to recover 
the cost of services that confer special benefits to identifiable non-
Federal recipients. The Independent Offices Appropriation Act (31 U.S.C. 
9701), Office of Management and Budget Circular A-25, and the Omnibus 
Appropriations Bill (Pub. L. 104-134, 110 Stat. 1321, April 26, 1996) 
authorize us to collect these fees.
    (a) We will specify the necessary fees for each of the types of 
royalty relief applications and possible BSEE audits in a Notice to 
Lessees. We will periodically update the fees to reflect changes in 
costs, as well as provide other information necessary to administer 
royalty relief.
    (b) You must file all payments electronically through the Fees for 
Services page on the BSEE Web site at http://www.bsee.gov, and you must 
include a copy of the Pay.gov confirmation receipt page with your 
application or assessment.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]



Sec. 203.4  How do the provisions in this part apply to different
types of leases and projects?

    The tables in this section summarize the similar application and 
approval provisions for the discretionary end-of-life and deep water 
royalty relief programs in Secs. 203.50 to 203.91. Because royalty 
relief for deep gas on leases not subject to deep water royalty relief, 
as provided for under Secs. 203.40 to 203.48, does not involve an 
application, its provisions do not parallel the other two royalty relief 
programs and are not summarized in this section.

[[Page 12]]

    (a) We require the information elements indicated by an X in the 
following table and described in Secs. 203.51, 203.62, and 203.81 
through 203.89 for applications for royalty relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
                 Information elements                        lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information report.................              X            X            X               X
(2) Net revenue and relief justification report                     X   ...........  ...........
 (prescribed format)..................................
(3) Economic viability and relief justification report  ..............           X            X               X
 (Royalty Suspension Viability Program (RSVP) model
 inputs justified with Geological and Geophysical
 (G&G), Engineering, Production, & Cost reports)......
(4) G&G report........................................  ..............           X            X               X
(5) Engineering report................................  ..............           X            X               X
(6) Production report.................................  ..............           X            X               X
(7) Deep water cost report............................  ..............           X            X               X
----------------------------------------------------------------------------------------------------------------

    (b) We require the confirmation elements indicated by an X in the 
following table and described in Secs. 203.70, 203.81, 203.90 and 203.91 
to retain royalty relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
                 Confirmation elements                       lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) Fabricator's confirmation report..................  ..............           X            X               X
(2) Post-production development report approved by an               X            X            X
 independent certified public accountant (CPA) * * *..
----------------------------------------------------------------------------------------------------------------

    (c) The following table indicates by an X, and Secs. 203.50, 203.52, 
203.60 and 203.67 describe, the prerequisites for our approval of your 
royalty relief application.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
                  Approval conditions                        lease                     Pre-act      Development
                                                                         Expansion      lease         project
----------------------------------------------------------------------------------------------------------------
(1) At least 12 of the last 15 months have the                      X
 required level of production.........................
(2) Already producing.................................              X   ...........
(3) A producible well into a reservoir that has not     ..............           X            X               X
 produced before......................................
(4) Royalties for qualifying months exceed 75 percent               X   ...........  ...........
 of net revenue (NR)..................................
(5) Substantial investment on a pre-Act lease (e.g.,    ..............  ...........  ...........
 platform, subsea template)...........................
(6) Determined to be economic only with relief........  ..............           X            X               X
----------------------------------------------------------------------------------------------------------------

    (d) The following table indicates by an X, and Secs. 203.52, 203.74, 
and 203.75 describe, the prerequisites for a redetermination of our 
royalty relief decision.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
              Redetermination conditions                     lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) After 12 months under current rate, criteria same               X   ...........  ...........
 as for approval......................................
(2) For material change in geologic data, prices,       ..............           X            X               X
 costs, or available technology.......................
----------------------------------------------------------------------------------------------------------------


[[Page 13]]

    (e) The following table indicates by an X, and Secs. 203.53 and 
203.69 describe, the characteristics of approved royalty relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
 Relief rate and volume, subject to certain conditions       lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) One-half pre-application effective lease rate on                X   ...........  ...........
 the qualifying amount, 1.5 times pre-application
 effective lease rate on additional production up to
 twice the qualifying amount, and the pre-application
 effective lease rate for any larger volumes..........
(2) Qualifying amount is the average monthly                        X   ...........  ...........
 production for 12 qualifying months..................
(3) Zero royalty rate on the suspension volume and the  ..............           X            X               X
 original lease rate on additional production.........
(4) Suspension volume is at least 17.5, 52.5 or 87.5    ..............  ...........           X
 million barrels of oil equivalent (MMBOE)............
(5) Suspension volume is at least the minimum set in    ..............           X   ...........              X
 the Notice of Sale, the lease, or the regulations....
(6) Amount needed to become economic..................  ..............           X            X               X
----------------------------------------------------------------------------------------------------------------

    (f) The following table indicates by an X, and Secs. 203.54 and 
203.78 describe, circumstances under which we discontinue your royalty 
relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
               Full royalty resumes when                     lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) Average NYMEX price for last 12 months is at least              X   ...........  ...........
 25 percent above the average for the qualifying
 months...............................................
(2) Average NYMEX price for last calendar year exceeds  ..............           X            X
 $28/bbl or $3.50/mcf, escalated by the gross domestic
 product (GDP) deflator since 1994....................
(3) Average prices for designated periods exceed        ..............           X   ...........              X
 levels we specify in the Notice of Sale or the lease.
----------------------------------------------------------------------------------------------------------------

    (g) The following table indicates by an X, and Secs. 203.55, 203.76, 
and 203.77 describe, circumstances under which we end or reduce royalty 
relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
              Relief withdrawn or reduced                    lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) If recipient requests.............................              X            X            X               X
(2) Lease royalty rate is at the effective rate for 12              X   ...........  ...........
 consecutive months...................................
(3) Conditions occur that we specified in the approval              X   ...........  ...........
 letter in individual cases...........................
(4) Recipient does not submit post-production report    ..............           X            X               X
 that compares expected to actual costs...............
(5) Recipient changes development system..............  ..............           X            X               X
(6) Recipient excessively delays starting fabrication.  ..............           X            X               X
(7) Recipient spends less than 80 percent of proposed   ..............           X            X               X
 pre-production costs prior to start of production....
(8) Amount of relief volume is produced...............  ..............           X            X               X
----------------------------------------------------------------------------------------------------------------



Sec. 203.5  What is BSEE's authority to collect information?

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part under 44 U.S.C. 3501 et 
seq., and assigned OMB Control Number 1014-0005. The title of this 
information collection is ``30 CFR part 203, Relief or Reduction in 
Royalty Rates.''
    (b) BSEE collects this information to make decisions on the economic 
viability of leases requesting a suspension or elimination of royalty or 
net profit share. Responses are required to obtain

[[Page 14]]

a benefit or are mandatory according to 43 U.S.C. 1331 et seq. BSEE will 
protect information considered proprietary under applicable law and 
under regulations at Sec. 203.61, ``How do I assess my chances for 
getting relief?'' and 30 CFR 250.197, ``Data and information to be made 
available to the public or for limited inspection.''
    (c) An agency may not conduct or sponsor, and a person is not 
required to respond to a collection of information unless it displays a 
currently valid OMB control number.
    (d) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA 
20166.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]



               Subpart B_OCS Oil, Gas, and Sulfur General

 Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to 
                        Deep Water Royalty Relief



Sec. 203.30  Which leases are eligible for royalty relief as a result
of drilling a phase 2 or phase 3 ultra-deep well?

    Your lease may receive a royalty suspension volume (RSV) under 
Secs. 203.31 through 203.36 if the lease meets all the requirements of 
this section.
    (a) The lease is located in the GOM wholly west of 87 degrees, 30 
minutes West longitude in water depths entirely less than 400 meters 
deep.
    (b) The lease has not produced gas or oil from a deep well or an 
ultra-deep well, except as provided in Sec. 203.31(b).
    (c) If the lease is located entirely in more than 200 meters and 
entirely less than 400 meters of water, it must either:
    (1) Have been issued before November 28, 1995, and not been granted 
deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by 
section 302 of the Deep Water Royalty Relief Act; or
    (2) Have been issued after November 28, 2000, and not been granted 
deep water royalty relief under Secs. 203.60 through 203.79.



Sec. 203.31  If I have a qualified phase 2 or qualified phase 3 ultra-
deep well, what royalty relief would that well earn for my lease?

    (a) Subject to the administrative requirements of Sec. 203.35 and 
the price conditions in Sec. 203.36, your qualified well earns your 
lease an RSV shown in the following table in billions of cubic feet 
(BCF) or in thousands of cubic feet (MCF) as prescribed in Sec. 203.33:

------------------------------------------------------------------------
   If you have a qualified phase 2 or    Then your lease earns an RSV on
 qualified phase 3 ultra-deep well that   this volume of gas production:
                  is:
------------------------------------------------------------------------
(1) An original well,                    35 BCF.
(2) A sidetrack with a sidetrack         35 BCF.
 measured depth of at least 20,000
 feet,
(3) An ultra-deep short sidetrack that   4 BCF plus 600 MCF times
 is a phase 2 ultra-deep well,           sidetrack measured depth
                                          (rounded to the nearest 100
                                          feet) but no more than 25 BCF.
(4) An ultra-deep short sidetrack that   0 BCF.
 is a phase 3 ultra-deep well,
------------------------------------------------------------------------

    (b)(1) This paragraph applies if your lease:
    (i) Has produced gas or oil from a deep well with a perforated 
interval the top of which is less than 18,000 feet TVD SS;
    (ii) Was issued in a lease sale held between January 1, 2004, and 
December 31, 2005; and
    (iii) The terms of your lease expressly incorporate the provisions 
of Secs. 203.41 through 203.47 as they existed at the time the lease was 
issued.
    (2) Subject to the administrative requirements of Sec. 203.35 and 
the price conditions in Sec. 203.36, your qualified well earns your 
lease an RSV shown in the

[[Page 15]]

following table in BCF or MCF as prescribed in Sec. 203.33:

------------------------------------------------------------------------
                                         Then your lease earns an RSV on
 If you have a qualified phase 2 ultra-   this volume of gas production:
        deep well that is . . .
------------------------------------------------------------------------
(i) An original well or a sidetrack      10 BCF.
 with a sidetrack measured depth of at
 least 20,000 feet TVD SS,
(ii) An ultra-deep short sidetrack,      4 BCF plus 600 MCF times
                                          sidetrack measured depth
                                          (rounded to the nearest 100
                                          feet) but no more than 10 BCF.
------------------------------------------------------------------------

    (c) Lessees may request a refund of or recoup royalties paid on 
production from qualified phase 2 or phase 3 ultra-deep wells that:
    (1) Occurs before December 18, 2008, and
    (2) Is subject to application of an RSV under either Sec. 203.31 or 
Sec. 203.41.
    (d) The following examples illustrate how this section applies. 
These examples assume that your lease is located in the GOM west of 87 
degrees, 30 minutes West longitude and in water less than 400 meters 
deep (see Sec. 203.30(a)), has no existing deep or ultra-deep wells and 
that the price thresholds prescribed in Sec. 203.36 have not been 
exceeded.

    Example 1: In 2008, you drill and begin producing from an ultra-deep 
well with a perforated interval the top of which is 25,000 feet TVD SS, 
and your lease has had no prior production from a deep or ultra-deep 
well. Assuming your lease has no deepwater royalty relief (see 
Sec. 203.30(c)), your lease is eligible (according to Sec. 203.30(b)) to 
earn an RSV under Sec. 203.31 because it has not yet produced from a 
deep well. Your lease earns an RSV of 35 BCF under this section when 
this well begins producing. According to Sec. 203.31(a), your 25,000 
foot well qualifies your lease for this RSV because the well was drilled 
after the relief authorized here became effective (when the proposed 
version of this rule was published on May 18, 2007) and produced from an 
interval that meets the criteria for an ultra-deep well (i.e., is a 
phase 2 ultra-deep well as defined in Sec. 203.0). Then in 2014, you 
drill and produce from another ultra-deep well with a perforated 
interval the top of which is 29,000 feet TVD SS. Your lease earns no 
additional RSV under this section when this second ultra-deep well 
produces, because your lease no longer meets the condition in 
(Sec. 203.30(b)) of no production from a deep well. However, any 
remaining RSV earned by the first ultra-deep well on your lease would be 
applied to production from both the first and the second ultra-deep 
wells as prescribed in Sec. 203.33(a)(2), or Sec. 203.33(b)(2) if your 
lease is part of a unit.
    Example 2: In 2005, you spudded and began producing from an ultra-
deep well with a perforated interval the top of which is 23,000 feet TVD 
SS. Your lease earns no RSV under this section from this phase 1 ultra-
deep well (as defined in Sec. 203.0) because you spudded the well before 
the publication date (May 18, 2007) of the proposed rule when royalty 
relief under Sec. 203.31(a) became effective. However, this ultra-deep 
well may earn an RSV of 25 BCF for your lease under Sec. 203.41 (that 
became effective May 3, 2004), if the lease is located in water depths 
partly or entirely less than 200 meters and has not previously produced 
from a deep well (Sec. 203.30(b)).
    Example 3: In 2000, you began producing from a deep well with a 
perforated interval the top of which is 16,000 feet TVD SS and your 
lease is located in water 100 meters deep. Then in 2008, you drill and 
produce from a new ultra-deep well with a perforated interval the top of 
which is 24,000 feet TVD SS. Your lease earns no RSV under either this 
section or Sec. 203.41 because the 16,000-foot well was drilled before 
we offered any way to earn an RSV for producing from a deep well (see 
dates in the definition of qualified well in Sec. 203.0) and because the 
existence of the 16,000-foot well means the lease is not eligible (see 
Sec. 203.30(b)) to earn an RSV for the 24,000-foot well. Because the 
lease existed in the year 2000, it cannot be eligible for the exception 
to this eligibility condition provided in Sec. 203.31(b).
    Example 4: In 2008, you spud and produce from an ultra-deep well 
with a perforated interval the top of which is 22,000 feet TVD SS, your 
lease is located in water 300 meters deep, and your lease has had no 
previous production from a deep or ultra-deep well. Your lease earns an 
RSV of 35 BCF under this section when this well begins producing because 
your lease meets the conditions in Sec. 203.30 and the well fits the 
definition of a phase 2 ultra-deep well (in Sec. 203.0). Then in 2010, 
you spud and produce from a deep well with a perforated interval the top 
of which is 16,000 feet TVD SS. Your 16,000-foot well earns no RSV 
because it is on a lease that already has a producing well at least 
18,000 feet subsea (see Sec. 203.42(a)), but any remaining RSV earned by 
the ultra-deep well would also be applied to production from the deep 
well as prescribed in Sec. 203.33(a)(2), or Sec. 203.33(b)(2) if your 
lease is part of a unit and Sec. 203.43(a)(2),

[[Page 16]]

or Sec. 203.43(b)(2) if your lease is part of a unit. However, if the 
16,000-foot deep well does not begin production until 2016 (or if your 
lease were located in water less than 200 meters deep), then the 16,000-
foot well would not be a qualified deep well because this well does not 
begin production within the interval specified in the definition of a 
qualified well in Sec. 203.0, and the RSV earned by the ultra-deep well 
would not be applied to production from this (unqualified) deep well.
    Example 5: In 2008, you spud a deep well with a perforated interval 
the top of which is 17,000 feet TVD SS that becomes a qualified well and 
earns an RSV of 15 BCF under Sec. 203.41 when it begins producing. Then 
in 2011, you spud an ultra-deep well with a perforated interval the top 
of which is 26,000 feet TVD SS. Your 26,000-foot well becomes a 
qualified ultra-deep well because it meets the date and depth conditions 
in this definition under Sec. 203.0 when it begins producing, but your 
lease earns no additional RSV under this section or Sec. 203.41 because 
it is on a lease that already has production from a deep well (see 
Sec. 203.30(b)). Both the qualified deep well and the qualified ultra-
deep well would share your lease's total RSV of 15 BCF in the manner 
prescribed in Secs. 203.33 and 203.43.
    Example 6: In 2008, you spud a qualified ultra-deep well that is a 
sidetrack with a sidetrack measured depth of 21,000 feet and a 
perforated interval the top of which is 25,000 feet TVD SS. This well 
meets the definition of an ultra-deep well but is too long to be 
classified an ultra-deep short sidetrack in Sec. 203.0. If your lease is 
located in 150 meters of water and has not previously produced from a 
deep well, your lease earns an RSV of 35 BCF because it was drilled 
after the effective date for earning this RSV. Further, this RSV applies 
to gas production from this and any future qualified deep and qualified 
ultra-deep wells on your lease, as prescribed in Sec. 203.33. The 
absence of an expiration date for earning an RSV on an ultra-deep well 
means this long sidetrack well becomes a qualified well whenever it 
starts production. If your sidetrack has a sidetrack measured depth of 
14,000 feet and begins production in March 2009, it earns an RSV of 12.4 
BCF under this section because it meets the definitions of a phase 2 
ultra-deep well (production begins before the expiration date for the 
pre-existing relief in its water depth category) and an ultra-deep short 
sidetrack in Sec. 203.0. However, if it does not begin production until 
2010, it earns no RSV because it is too short as a phase 3 ultra-deep 
well to be a qualified ultra-deep well.
    Example 7: Your lease was issued in June 2004 and expressly 
incorporates the provisions of Secs. 203.41 through 203.47 as they 
existed at that time. In January 2005, you spud a deep well (well no. 1) 
with a perforated interval the top of which is 16,800 feet TVD SS that 
becomes a qualified well and earns an RSV of 15 BCF under Sec. 203.41 
when it begins producing. Then in February 2008, you spud an ultra-deep 
well (well no. 2) with a perforated interval the top of which is 22,300 
feet that begins producing in November 2008, after well no. 1 has 
started production. Well no. 2 earns your lease an additional RSV of 10 
BCF under paragraph (b) of this section because it begins production in 
time to be classified as a phase 2 ultra-deep well. If, on the other 
hand, well no. 2 had begun producing in June 2009, it would earn no 
additional RSV for the lease because it would be classified as a phase 3 
ultra-deep well and thus is not entitled to the exception under 
paragraph (b) of this section.



Sec. 203.32  What other requirements or restrictions apply to royalty
relief for a qualified phase 2 or phase 3 ultra-deep well?

    (a) If a qualified ultra-deep well on your lease is within a 
unitized portion of your lease, the RSV earned by that well under this 
section applies only to your lease and not to other leases within the 
unit or to the unit as a whole.
    (b) If your qualified ultra-deep well is a directional well (either 
an original well or a sidetrack) drilled across a lease line, then 
either:
    (1) The lease with the perforated interval that initially produces 
earns the RSV or
    (2) If the perforated interval crosses a lease line, the lease where 
the surface of the well is located earns the RSV.
    (c) Any RSV earned under Sec. 203.31 is in addition to any royalty 
suspension supplement (RSS) for your lease under Sec. 203.45 that 
results from a different wellbore.
    (d) If your lease earns an RSV under Sec. 203.31 and later produces 
from a deep well that is not a qualified well, the RSV is not forfeited 
or terminated, but you may not apply the RSV earned under Sec. 203.31 to 
production from the non-qualified well.
    (e) You owe minimum royalties or rentals in accordance with your 
lease terms notwithstanding any RSVs allowed under paragraphs (a) and 
(b) of Sec. 203.31.
    (f) Unused RSVs transfer to a successor lessee and expire with the 
lease.

[[Page 17]]



Sec. 203.33  To which production do I apply the RSV earned by qualified
phase 2 and phase 3 ultra-deep wells on my lease or in my unit?

    (a) You must apply the RSV allowed in Sec. 203.31(a) and (b) to gas 
volumes produced from qualified wells on or after May 18, 2007, reported 
on the Oil and Gas Operations Report, Part A (OGOR-A) for your lease 
under 30 CFR 1210.102. All gas production from qualified wells reported 
on the OGOR-A, including production not subject to royalty, counts 
toward the total lease RSV earned by both deep or ultra-deep wells on 
the lease.
    (b) This paragraph applies to any lease with a qualified phase 2 or 
phase 3 ultra-deep well that is not within a BSEE-approved unit. Subject 
to the price conditions of Sec. 203.36, you must apply the RSV 
prescribed in Sec. 203.31 as required under the following paragraphs 
(b)(1) and (b)(2) of this section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of May 18, 2007, or the date the first qualified 
phase 2 or phase 3 ultra-deep well that earns your lease the RSV begins 
production (other than test production).
    (2) You must apply the RSV to only gas production from qualified 
wells on your lease, regardless of their depth, for which you have met 
the requirements in Sec. 203.35 or Sec. 203.44.
    (c) This paragraph applies to any lease with a qualified phase 2 or 
phase 3 ultra-deep well where all or part of the lease is within a BSEE-
approved unit. Under the unit agreement, a share of the production from 
all the qualified wells in the unit participating area would be 
allocated to your lease each month according to the participating area 
percentages. Subject to the price conditions of Sec. 203.36, you must 
apply the RSV prescribed in Sec. 203.31 as follows:
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of May 18, 2007, or the date that the first 
qualified phase 2 or phase 3 ultra-deep well that earns your lease the 
RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production:
    (i) From qualified wells on the non-unitized area of your lease, 
regardless of their depth, for which you have met the requirements in 
Sec. 203.35 or Sec. 203.44; and
    (ii) Allocated to your lease under a BSEE-approved unit agreement 
from qualified wells on unitized areas of your lease and on other leases 
in participating areas of the unit, regardless of their depth, for which 
the requirements in Sec. 203.35 or Sec. 203.44 have been met. The 
allocated share under paragraph (a)(2)(ii) of this section does not 
increase the RSV for your lease.

    Example: The east half of your lease A is unitized with all of lease 
B. There is one qualified phase 2 ultra-deep well on the non-unitized 
portion of lease A that earns lease A an RSV of 35 BCF under 
Sec. 203.31, one qualified deep well on the unitized portion of lease A 
(drilled after the ultra-deep well on the non-unitized portion of that 
lease) and a qualified phase 2 ultra-deep well on lease B that earns 
lease B a 35 BCF RSV under Sec. 203.31. The participating area 
percentages allocate 40 percent of production from both of the unit 
qualified wells to lease A and 60 percent to lease B. If the non-
unitized qualified phase 2 ultra-deep well on lease A produces 12 BCF, 
and the unitized qualified well on lease A produces 18 BCF, and the 
qualified well on lease B produces 37 BCF, then the production volume 
from and allocated to lease A to which the lease A RSV applies is 34 BCF 
[12 + (18 + 37)(0.40)]. The production volume allocated to lease B to 
which the lease B RSV applies is 33 BCF [(18 + 37)(0.60)]. None of the 
volumes produced from a well that is not within a unit participating 
area may be allocated to other leases in the unit.

    (d) You must begin paying royalties when the cumulative production 
of gas from all qualified wells on your lease, or allocated to your 
lease under paragraph (b) of this section, reaches the applicable RSV 
allowed under Sec. 203.31 or Sec. 203.41. For the month in which 
cumulative production reaches this RSV, you owe royalties on the portion 
of gas production from or allocated to your lease that exceeds the RSV 
remaining at the beginning of that month.



Sec. 203.34  To which production may an RSV earned by qualified phase
2 and phase 3 ultra-deep wells on my lease not be applied?

    You may not apply an RSV earned under Sec. 203.31:

[[Page 18]]

    (a) To production from completions less than 15,000 feet TVD SS, 
except in cases where the qualified well is re-perforated in the same 
reservoir previously perforated deeper than 15,000 feet TVD SS;
    (b) To production from a deep well or ultra-deep well on any other 
lease, except as provided in paragraph (c) of Sec. 203.33;
    (c) To any liquid hydrocarbon (oil and condensate) volumes; or
    (d) To production from a deep well or ultra-deep well that commenced 
drilling before:
    (1) March 26, 2003, on a lease that is located entirely or partly in 
water less than 200 meters deep; or
    (2) May 18, 2007, on a lease that is located entirely in water more 
than 200 meters deep.



Sec. 203.35  What administrative steps must I take to use the RSV
earned by a qualified phase 2 or phase 3 ultra-deep well?

    To use an RSV earned under Sec. 203.31:
    (a) You must notify the BSEE Regional Supervisor for Production and 
Development in writing of your intent to begin drilling operations on 
all your ultra-deep wells.
    (b) Before beginning production, you must meet any production 
measurement requirements that the BSEE Regional Supervisor for 
Production and Development has determined are necessary under 30 CFR 
part 250, subpart L.
    (c)(1) Within 30 days of the beginning of production from any wells 
that would become qualified phase 2 or phase 3 ultra-deep wells by 
satisfying the requirements of this section:
    (i) Provide written notification to the BSEE Regional Supervisor for 
Production and Development that production has begun; and
    (ii) Request confirmation of the size of the RSV earned by your 
lease.
    (2) If you produced from a qualified phase 2 or phase 3 ultra-deep 
well before December 18, 2008, you must provide the information in 
paragraph (c)(1) of this section no later than January 20, 2009.
    (d) If you cannot produce from a well that otherwise meets the 
criteria for a qualified phase 2 ultra-deep well that is an ultra-deep 
short sidetrack before May 3, 2009, on a lease that is located entirely 
or partly in water less than 200 meters deep, or before May 3, 2013, on 
a lease that is located entirely in water more than 200 meters but less 
than 400 meters deep, the BSEE Regional Supervisor for Production and 
Development may extend the deadline for beginning production for up to 1 
year, based on the circumstances of the particular well involved, if it 
meets all the following criteria.
    (1) The delay occurred after drilling reached the total depth in 
your well.
    (2) Production (other than test production) was expected to begin 
from the well before May 3, 2009, on a lease that is located entirely or 
partly in water less than 200 meters deep or before May 3, 2013, on a 
lease that is located entirely in water more than 200 meters but less 
than 400 meters deep. You must provide a credible activity schedule with 
supporting documentation.
    (3) The delay in beginning production is for reasons beyond your 
control, such as adverse weather and accidents which BSEE deems were 
unavoidable.



Sec. 203.36  Do I keep royalty relief if prices rise significantly?

    (a) You must pay the Office of Natural Resources Revenue royalties 
on all gas production to which an RSV otherwise would be applied under 
Sec. 203.33 for any calendar year in which the average daily closing New 
York Mercantile Exchange (NYMEX) natural gas price exceeds the 
applicable threshold price shown in the following table.

------------------------------------------------------------------------
 A price threshold in year 2007 dollars
                of . . .                         Applies to . . .
------------------------------------------------------------------------
(1) $10.15 per MMBtu,                    (i) The first 25 BCF of RSV
                                          earned under Sec. 203.31(a)
                                          by a phase 2 ultra-deep well
                                          on a lease that is located in
                                          water partly or entirely less
                                          than 200 meters deep issued
                                          before December 18, 2008; and
                                         (ii) Any RSV earned under Sec.
                                          203.31(b) by a phase 2 ultra-
                                          deep well.

[[Page 19]]

 
(2) $4.55 per MMBtu,                     (i) Any RSV earned under Sec.
                                          203.31(a) by a phase 3 ultra-
                                          deep well unless the lease
                                          terms prescribe a different
                                          price threshold;
                                         (ii) The last 10 BCF of the 35
                                          BCF of RSV earned under Sec.
                                          203.31(a) by a phase 2 ultra-
                                          deep well on a lease that is
                                          located in water partly or
                                          entirely less than 200 meters
                                          deep issued before December
                                          18, 2008, and that is not a
                                          non-converted lease;
                                         (iii) The last 15 BCF of the 35
                                          BCF of RSV earned under Sec.
                                          203.31(a) by a phase 2 ultra-
                                          deep well on a non-converted
                                          lease;
                                         (iv) Any RSV earned under Sec.
                                          203.31(a) by a phase 2 ultra-
                                          deep well on a lease in water
                                          partly or entirely less than
                                          200 meters deep issued on or
                                          after December 18, 2008,
                                          unless the lease terms
                                          prescribe a different price
                                          threshold; and
                                         (v) Any RSV earned under Sec.
                                          203.31(a) by a phase 2 ultra-
                                          deep well on a lease in water
                                          entirely more than 200 meters
                                          deep and entirely less than
                                          400 meters deep.
(3) $4.08 per MMBtu,                     (i) The first 20 BCF of RSV
                                          earned by a well that is
                                          located on a non-converted
                                          lease issued in OCS Lease Sale
                                          178.
(4) $5.83 per MMBtu,                     (i) The first 20 BCF of RSV
                                          earned by a well that is
                                          located on a non-converted
                                          lease issued in OCS Lease
                                          Sales 180, 182, 184, 185, or
                                          187.
------------------------------------------------------------------------

    (b) For purposes of paragraph (a) of this section, determine the 
threshold price for any calendar year after 2007 by:
    (1) Determining the percentage of change during the year in the 
Department of Commerce's implicit price deflator for the gross domestic 
product; and
    (2) Adjusting the threshold price for the previous year by that 
percentage.
    (c) The following examples illustrate how this section applies.

    Example 1: Assume that a lessee drills and begins producing from a 
qualified phase 2 ultra-deep well in 2008 on a lease issued in 2004 in 
less than 200 meters of water that earns the lease an RSV of 35 BCF. 
Further, assume the well produces a total of 18 BCF by the end of 2009 
and in both of those years, the average daily NYMEX closing natural gas 
price is less than $10.15 (adjusted for inflation after 2007). The 
lessee does not pay royalty on the 18 BCF because the gas price 
threshold under paragraph (a)(1) of this section applies to the first 25 
BCF of this RSV earned by this phase 2 ultra-deep well. In 2010, the 
well produces another 13 BCF. In that year, the average daily closing 
NYMEX natural gas price is greater than $4.55 per MMBtu (adjusted for 
inflation after 2007), but less than $10.15 per MMBtu (adjusted for 
inflation after 2007). The first 7 BCF produced in 2010 will exhaust the 
first 25 BCF (that is subject to the $10.15 threshold) of the 35 BCF RSV 
that the well earned. The lessee must pay royalty on the remaining 6 BCF 
produced in 2010, because it is subject to the $4.55 per MMBtu threshold 
under paragraph (a)(2)(ii) of this section which was exceeded.
    Example 2: Assume that a lessee:
    (1) Drills and produces from well no.1, a qualified deep well in 
2008 to a depth of 15,500 feet TVD SS that earns a 15 BCF RSV for the 
lease under Sec. 203.41, which would be subject to a price threshold of 
$10.15 per MMBtu (adjusted for inflation after 2007), meaning the lease 
is partly or entirely in less than 200 meters of water;
    (2) Later in 2008, drills and produces from well no. 2, a second 
qualified deep well to a depth of 17,000 feet TVD SS that earns no 
additional RSV (see Sec. 203.41(c)(1)); and
    (3) In 2015, drills and produces from well no. 3, a qualified phase 
3 ultra-deep well that earns no additional RSV since the lease already 
has an RSV established by prior deep well production. Further assume 
that in 2015, the average daily closing NYMEX natural gas price exceeds 
$4.55 per MMBtu (adjusted for inflation after 2007) but does not exceed 
$10.15 per MMBtu (adjusted for inflation after 2007). In 2015, any 
remaining RSV earned by well no. 1 (which would have been applied to 
production from well nos. 1 and 2 in the intervening years), would be 
applied to production from all three qualified wells. Because the price 
threshold applicable to that RSV was not exceeded, the production from 
all three qualified wells would be royalty-free until the 15 BCF RSV 
earned by well no. 1 is exhausted.
    Example 3: Assume the same initial facts regarding the three wells 
as in Example 2. Further assume that well no. 1 stopped producing in 
2011 after it had produced 8 BCF, and that well no. 2 stopped producing 
in 2012 after it had produced 5 BCF. Two BCF of the RSV earned by well 
no. 1 remain. That RSV would be applied to production from well no.

[[Page 20]]

3 until it is exhausted, and the lessee therefore would not pay royalty 
on those 2 BCF produced in 2015, because the $10.15 per MMBtu (adjusted 
for inflation after 2007) price threshold is not exceeded. The 
determination of which price threshold applies to deep gas production 
depends on when the first qualified well earned the RSV for the lease, 
not on which wells use the RSV.
    Example 4: Assume that in February 2010, a lessee completes and 
begins producing from an ultra-deep well (at a depth of 21,500 feet TVD 
SS) on a lease located in 325 meters of water with no prior production 
from any deep well and no deep water royalty relief. The ultra-deep well 
would be a phase 2 ultra-deep well (see definition in Sec. 203.0), and 
would earn the lease an RSV of 35 BCF under Secs. 203.30 and 203.31. 
Further assume that the average daily closing NYMEX natural gas price 
exceeds $4.55 per MMBtu (adjusted for inflation after 2007) but does not 
exceed $10.15 per MMBtu (adjusted for inflation after 2007) during 2010. 
Because the lease is located in more than 200 but less than 400 meters 
of water, the $4.55 per MMBtu price threshold applies to the whole RSV 
(see paragraph (a)(2)(v) of this section), and the lessee will owe 
royalty on all gas produced from the ultra-deep well in 2010.

    (d) You must pay any royalty due under this section no later than 
March 31 of the year following the calendar year for which you owe 
royalty. If you do not pay by that date, you must pay late payment 
interest under 30 CFR 1218.54 from April 1 until the date of payment.
    (e) Production volumes on which you must pay royalty under this 
section count as part of your RSV.

Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to Deep 
                          Water Royalty Relief



Sec. 203.40  Which leases are eligible for royalty relief as a result
of drilling a deep well or a phase 1 ultra-deep well?

    Your lease may receive an RSV under Secs. 203.41 through 203.44, and 
may receive an RSS under Secs. 203.45 through 203.47, if it meets all 
the requirements of this section.
    (a) The lease is located in the GOM wholly west of 87 degrees, 30 
minutes West longitude in water depths entirely less than 400 meters 
deep.
    (b) The lease has not produced gas or oil from a well with a 
perforated interval the top of which is 18,000 feet TVD SS or deeper 
that commenced drilling either:
    (1) Before March 26, 2003, on a lease that is located partly or 
entirely in water less than 200 meters deep; or
    (2) Before May 18, 2007, on a lease that is located in water 
entirely more than 200 meters and entirely less than 400 meters deep.
    (c) In the case of a lease located partly or entirely in water less 
than 200 meters deep, the lease was issued in a lease sale held either:
    (1) Before January 1, 2001;
    (2) On or after January 1, 2001, and before January 1, 2004, and, in 
cases where the original lease terms provided for an RSV for deep gas 
production, the lessee has exercised the option provided for in 
Sec. 203.49; or
    (3) On or after January 1, 2004, and the lease terms provide for 
royalty relief under Secs. 203.41 through 203.47. (Note: Because the 
original Sec. 203.41 has been divided into new Secs. 203.41 and 203.42 
and subsequent sections have been redesignated as Secs. 203.43 through 
203.48, royalty relief in lease terms for leases issued on or after 
January 1, 2004, should be read as referring to Secs. 203.41 through 
203.48.)
    (d) If the lease is located entirely in more than 200 meters and 
less than 400 meters of water, it must either:
    (1) Have been issued before November 28, 1995, and not been granted 
deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by 
section 302 of the Deep Water Royalty Relief Act; or
    (2) Have been issued after November 28, 2000, and not been granted 
deep water royalty relief under Secs. 203.60 through 203.79.



Sec. 203.41  If I have a qualified deep well or a qualified phase 1
ultra-deep well, what royalty relief would my lease earn?

    (a) To qualify for a suspension volume under paragraphs (b) or (c) 
of this section, your lease must meet the requirements in Sec. 203.40 
and the requirements in the following table.

[[Page 21]]



------------------------------------------------------------------------
                               And if it later . .   Then your lease . .
 If your lease has not . . .            .                     .
------------------------------------------------------------------------
(1) produced gas or oil from  Has a qualified deep  earns an RSV
 any deep well or ultra-deep   well or qualified     specified in
 well,                         phase 1 ultra-deep    paragraph (b) of
                               well,                 this section.
(2) produced gas or oil from  Has a qualified deep  earns an RSV
 a well with a perforated      well with a           specified in
 interval whose top is         perforated interval   paragraph (c) of
 18,000 feet TVD SS or         whose top is 18,000   this section.
 deeper,                       feet TVD SS or
                               deeper or a
                               qualified phase 1
                               ultra-deep well,
------------------------------------------------------------------------

    (b) If your lease meets the requirements in paragraph (a)(1) of this 
section, it earns the RSV prescribed in the following table:

------------------------------------------------------------------------
 If you have a qualified deep well or a  Then your lease earns an RSV on
 qualified phase 1 ultra-deep well that   this volume of gas production:
                  is:
------------------------------------------------------------------------
(1) An original well with a perforated   15 BCF.
 interval the top of which is from
 15,000 to less than 18,000 feet TVD
 SS,
(2) A sidetrack with a perforated        4 BCF plus 600 MCF times
 interval the top of which is from        sidetrack measured depth
 15,000 to less than 18,000 feet TVD      (rounded to the nearest 100
 SS,                                      feet) but no more than 15 BCF.
(3) An original well with a perforated   25 BCF.
 interval the top of which is at least
 18,000 feet TVD SS,
(4) A sidetrack with a perforated        4 BCF plus 600 MCF times
 interval the top of which is at least    sidetrack measured depth
 18,000 feet TVD SS,                      (rounded to the nearest 100
                                          feet) but no more than 25 BCF.
------------------------------------------------------------------------

    (c) If your lease meets the requirements in paragraph (a)(2) of this 
section, it earns the RSV prescribed in the following table. The RSV 
specified in this paragraph is in addition to any RSV your lease already 
may have earned from a qualified deep well with a perforated interval 
whose top is from 15,000 feet to less than 18,000 feet TVD SS.

------------------------------------------------------------------------
 If you have a qualified deep well or a
 qualified phase 1 ultra-deep well that    Then you earn an RSV on this
                is . . .                    amount of gas production:
------------------------------------------------------------------------
(1) An original well or a sidetrack      0 BCF.
 with a perforated interval the top of
 which is from 15,000 to less than
 18,000 feet TVD SS,
(2) An original well with a perforated   10 BCF.
 interval the top of which is 18,000
 feet TVD SS or deeper,
(3) A sidetrack with a perforated        4 BCF plus 600 MCF times
 interval the top of which is 18,000      sidetrack measured depth
 feet TVD SS or deeper,                   (rounded to the nearest 100
                                          feet) but no more than 10 BCF.
------------------------------------------------------------------------

    (d) Lessees may request a refund of or recoup royalties paid on 
production from qualified wells on a lease that is located in water 
entirely deeper than 200 meters but entirely less than 400 meters deep 
that:
    (1) Occurs before December 18, 2008; and
    (2) Is subject to application of an RSV under either Sec. 203.31 or 
Sec. 203.41.
    (e) The following examples illustrate how this section applies, 
assuming your lease meets the location, prior production, and lease 
issuance conditions in Sec. 203.40 and paragraph (a) of this section:

    Example 1: If you have a qualified deep well that is an original 
well with a perforated interval the top of which is 16,000 feet TVD SS, 
your lease earns an RSV of 15 BCF under paragraph (b)(1) of this 
section. This RSV must be applied to gas production from all qualified 
wells on your lease, as prescribed in Secs. 203.43 and 203.48. However, 
if the top of the perforated interval is 18,500 feet TVD SS, the RSV is 
25 BCF according to paragraph (b)(3) of this section.
    Example 2: If you have a qualified deep well that is a sidetrack, 
with a perforated interval the top of which is 16,000 feet TVD SS and a 
sidetrack measured depth of 6,789 feet, we round the measured depth to 
6,800 feet and your lease earns an RSV of 8.08 BCF under paragraph 
(b)(2) of this section. This RSV would be applied to gas production from 
all qualified wells on your lease, as prescribed in Secs. 203.43 and 
203.48.
    Example 3: If you have a qualified deep well that is a sidetrack, 
with a perforated interval the top of which is 16,000 feet TVD SS and a 
sidetrack measured depth of 19,500 feet, your lease earns an RSV of 15 
BCF. This RSV would be applied to gas production from all qualified 
wells on your lease, as prescribed in Secs. 203.43 and 203.48, even 
though 4 BCF plus 600 MCF per foot of sidetrack measured

[[Page 22]]

depth equals 15.7 BCF because paragraph (b)(2) of this section limits 
the RSV for a sidetrack at the amount an original well to the same depth 
would earn.
    Example 4: If you have drilled and produced a deep well with a 
perforated interval the top of which is 16,000 feet TVD SS before March 
26, 2003 (and the well therefore is not a qualified well and has earned 
no RSV under this section), and later drill:
    (i) A deep well with a perforated interval the top of which is 
17,000 feet TVD SS, your lease earns no RSV (see paragraph (c)(1) of 
this section);
    (ii) A qualified deep well that is an original well with a 
perforated interval the top of which is 19,000 feet TVD SS, your lease 
earns an RSV of 10 BCF under paragraph (c)(2) of this section. This RSV 
would be applied to gas production from qualified wells on your lease, 
as prescribed in Secs. 203.43 and 203.48; or
    (iii) A qualified deep well that is a sidetrack with a perforated 
interval the top of which is 19,000 feet TVD SS, that has a sidetrack 
measured depth of 7,000 feet, your lease earns an RSV of 8.2 BCF under 
paragraph (c)(3) of this section. This RSV would be applied to gas 
production from qualified wells on your lease, as prescribed in 
Secs. 203.43 and 203.48.
    Example 5: If you have a qualified deep well that is an original 
well with a perforated interval the top of which is 16,000 feet TVD SS, 
and later drill a second qualified well that is an original well with a 
perforated interval the top of which is 19,000 feet TVD SS, we increase 
the total RSV for your lease from 15 BCF to 25 BCF under paragraph 
(c)(2) of this section. We will apply that RSV to gas production from 
all qualified wells on your lease, as prescribed in Secs. 203.43 and 
203.48. If the second well has a perforated interval the top of which is 
22,000 feet TVD SS (instead of 19,000 feet), the total RSV for your 
lease would increase to 25 BCF only in 2 situations: (1) If the second 
well was a phase 1 ultra-deep well, i.e., if drilling began before May 
18, 2007, or (2) the exception in Sec. 203.31(b) applies. In both 
situations, your lease must be partly or entirely in less than 200 
meters of water and production must begin on this well before May 3, 
2009. If drilling of the second well began on or after May 18, 2007, the 
second well would be qualified as a phase 2 or phase 3 ultra-deep well 
and, unless the exception in Sec. 203.31(b) applies, would not earn any 
additional RSV (as prescribed in Sec. 203.30), so the total RSV for your 
lease would remain at 15 BCF.
    Example 6: If you have a qualified deep well that is a sidetrack, 
with a perforated interval the top of which is 16,000 feet TVD SS and a 
sidetrack measured depth of 4,000 feet, and later drill a second 
qualified well that is a sidetrack, with a perforated interval the top 
of which is 19,000 feet TVD SS and a sidetrack measured depth of 8,000 
feet, we increase the total RSV for your lease from 6.4 BCF [4 + (600 * 
4,000)/1,000,000] to 15.2 BCF 6.4 + [4 + (600 * 8,000)/1,000,000)]  
under paragraphs (b)(2) and (c)(3) of this section. We would apply that 
RSV to gas production from all qualified wells on your lease, as 
prescribed in Secs. 203.43 and 203.48. The difference of 8.8 BCF 
represents the RSV earned by the second sidetrack that has a perforated 
interval the top of which is deeper than 18,000 feet TVD SS.



Sec. 203.42  What conditions and limitations apply to royalty relief
for deep wells and phase 1 ultra-deep wells?

    The conditions and limitations in the following table apply to 
royalty relief under Sec. 203.41.

------------------------------------------------------------------------
                 If . . .                            Then . . .
------------------------------------------------------------------------
(a) Your lease has produced gas or oil      your lease cannot earn an
 from a well with a perforated interval      RSV under Sec. 203.41 as a
 the top of which is 18,000 feet TVD SS or   result of drilling any
 deeper,                                     subsequent deep wells or
                                             phase 1 ultra-deep wells.
(b) You determine RSV under Sec. 203.41    that determination
 for the first qualified deep well or        establishes the total RSV
 qualified phase 1 ultra-deep well on your   available for that drilling
 lease (whether an original well or a        depth interval on your
 sidetrack) because you drilled and          lease (i.e., either 15,000-
 produced it within the time intervals set   18,000 feet TVD SS, or
 forth in the definitions for qualified      18,000 feet TVD SS and
 wells,                                      deeper), regardless of the
                                             number of subsequent
                                             qualified wells you drill
                                             to that depth interval.
(c) A qualified deep well or qualified      the RSV earned by that well
 phase 1 ultra-deep well on your lease is    under Sec. 203.41 applies
 within a unitized portion of your lease,    only to production from
                                             qualified wells on or
                                             allocated to your lease and
                                             not to other leases within
                                             the unit.
(d) Your qualified deep well or qualified   the lease with the
 phase 1 ultra-deep well is a directional    perforated interval that
 well (either an original well or a          initially produces earns
 sidetrack) drilled across a lease line,     the RSV. However, if the
                                             perforated interval crosses
                                             a lease line, the lease
                                             where the surface of the
                                             well is located earns the
                                             RSV.
(e) You earn an RSV under Sec. 203.41,     that RSV is in addition to
                                             any RSS for your lease
                                             under Sec. 203.45 that
                                             results from a different
                                             wellbore.
(f) Your lease earns an RSV under Sec. the RSV is not forfeited or
 203.41 and later produces from a well       terminated, but you may not
 that is not a qualified well,               apply the RSV under Sec.
                                             203.41 to production from
                                             the non-qualified well.
(g) You qualify for an RSV under            you still owe minimum
 paragraphs (b) or (c) of Sec. 203.41,      royalties or rentals in
                                             accordance with your lease
                                             terms.

[[Page 23]]

 
(h) You transfer your lease,                unused RSVs transfer to a
                                             successor lessee and expire
                                             with the lease.
------------------------------------------------------------------------


    Example to paragraph (b): If your first qualified deep well is a 
sidetrack with a perforated interval whose top is 16,000 feet TVD SS and 
earns an RSV of 12.5 BCF, and you later drill a qualified original deep 
well to 17,000 feet TVD SS, the RSV for your lease remains at 12.5 BCF 
and does not increase to 15 BCF. However, under paragraph (c) of 
Sec. 203.41, if you subsequently drill a qualified deep well to a depth 
of 18,000 feet or greater TVD SS, you may earn an additional RSV.



Sec. 203.43  To which production do I apply the RSV earned from 
qualified deep wells or qualified phase 1 ultra-deep wells on my lease?

    (a) You must apply the RSV prescribed in Sec. 203.41(b) and (c) to 
gas volumes produced from qualified wells on or after May 3, 2004, 
reported on the OGOR-A for your lease under 30 CFR 1210.102, as and to 
the extent prescribed in Secs. 203.43 and 203.48.
    (1) Except as provided in paragraph (a)(2) of this section, all gas 
production from qualified wells reported on the OGOR-A, including 
production that is not subject to royalty, counts toward the lease RSV.
    (2) Production to which an RSS applies under Secs. 203.45 and 203.46 
does not count toward the lease RSV.
    (b) This paragraph applies to any lease with a qualified deep well 
or qualified phase 1 ultra-deep well when no part of the lease is within 
a BSEE-approved unit. Subject to the price conditions in Sec. 203.48, 
you must apply the RSV prescribed in Sec. 203.41 as required under the 
following paragraphs (b)(1) and (b)(2) of this section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of:
    (i) May 3, 2004, for an RSV earned by a qualified deep well or 
qualified phase 1 ultra-deep well on a lease that is located entirely or 
partly in water less than 200 meters deep;
    (ii) May 18, 2007, for an RSV earned by a qualified deep well on a 
lease that is located entirely in water more than 200 meters deep; or
    (iii) The date that the first qualified well that earns your lease 
the RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production from qualified 
wells on your lease, regardless of their depth, for which you have met 
the requirements in Sec. 203.35 or Sec. 203.44.

    Example 1: On a lease in water less than 200 meters deep, you began 
drilling an original deep well with a perforated interval the top of 
which is 18,200 feet TVD SS in September 2003, that became a qualified 
deep well in July 2004, when it began producing and using the RSV that 
it earned. You subsequently drill another original deep well with a 
perforated interval the top of which is 16,600 feet TVD SS, which 
becomes a qualified deep well when production begins in August 2008. The 
first well earned an RSV of 25 BCF (see Sec. 203.41(a)(1) and (b)(3)). 
You must apply any remaining RSV each month beginning in August 2008 to 
production from both wells until the 25 BCF RSV is fully utilized 
according to paragraph (b)(2) of this section. If the second well had 
begun production in August 2009, it would not be a qualified deep well 
because it started production after expiration in May 2009 of the 
ability to qualify for royalty relief in this water depth, and could not 
share any of the remaining RSV (see definition of a qualified deep well 
in Sec. 203.0).
    Example 2: On a lease in water between 200 and 400 meters deep, you 
begin drilling an original deep well with a perforated interval the top 
of which is 17,100 feet TVD SS in November 2010 that becomes a qualified 
deep well in June 2011 when it begins producing and using the RSV. You 
subsequently drill another original deep well with a perforated interval 
the top of which is 15,300 feet TVD SS which becomes a qualified deep 
well by beginning production in October 2011 (see definition of a 
qualified deep well in Sec. 203.0). Only the first well earns an RSV 
equal to 15 BCF (see Sec. 203.41(a) and (b)). You must apply any 
remaining RSV each month beginning in October 2011 to production from 
both qualified deep wells until the 15 BCF RSV is fully utilized 
according to paragraph (b)(2) of this section.

    (c) This paragraph applies to any lease with a qualified deep well 
or qualified phase 1 ultra-deep well when all or part of the lease is 
within a BSEE-approved unit. Under the unit agreement, a share of the 
production from all the qualified wells in the unit

[[Page 24]]

participating area would be allocated to your lease each month according 
to the participating area percentages. Subject to the price conditions 
in Sec. 203.48, you must apply the RSV prescribed under Sec. 203.41 as 
required under the following paragraphs (c)(1) through (3) of this 
section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of:
    (i) May 3, 2004, for an RSV earned by a qualified well or qualified 
phase 1 ultra-deep well on a lease that is located entirely or partly in 
water less than 200 meters deep;
    (ii) May 18, 2007, for an RSV earned by a qualified deep well on a 
lease that is located entirely in water more than 200 meters deep; or
    (iii) The date that the first qualified well that earns your lease 
the RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production:
    (i) From all qualified wells on the non-unitized area of your lease, 
regardless of their depth, for which you have met the requirements in 
Sec. 203.35 or Sec. 203.44; and,
    (ii) Allocated to your lease under a BSEE-approved unit agreement 
from qualified wells on unitized areas of your lease and on unitized 
areas of other leases in the unit, regardless of their depth, for which 
the requirements in Sec. 203.35 or Sec. 203.44 have been met.
    (3) The allocated share under paragraph (c)(2)(ii) of this section 
does not increase the RSV for your lease. None of the volumes produced 
from a well that is not within a unit participating area may be 
allocated to other leases in the unit.

    Example: The east half of your lease A is unitized with all of lease 
B. There is one qualified 19,000-foot TVD SS deep well on the non-
unitized portion of lease A, one qualified 18,500-foot TVD SS deep well 
on the unitized portion of lease A, and a qualified 19,400-foot TVD SS 
deep well on lease B. The participating area percentages allocate 32 
percent of production from both of the unit qualified deep wells to 
lease A and 68 percent to lease B. If the non-unitized qualified deep 
well on lease A produces 12 BCF and the unitized qualified deep well on 
lease A produces 15 BCF, and the qualified deep well on lease B produces 
10 BCF, then the production volume from and allocated to lease A to 
which the lease an RSV applies is 20 BCF [12 + (15 + 10) * (0.32)]. The 
production volume allocated to lease B to which the lease B RSV applies 
is 17 BCF [(15 + 10) * (0.68)].

    (d) You must begin paying royalties when the cumulative production 
of gas from all qualified wells on your lease, or allocated to your 
lease under paragraph (c) of this section, reaches the applicable RSV 
allowed under Sec. 203.31 or Sec. 203.41. For the month in which 
cumulative production reaches this RSV, you owe royalties on the portion 
of gas production that exceeds the RSV remaining at the beginning of 
that month.
    (e) You may not apply the RSV allowed under Sec. 203.41 to:
    (1) Production from completions less than 15,000 feet TVD SS, except 
in cases where the qualified deep well is re-perforated in the same 
reservoir previously perforated deeper than 15,000 feet TVD SS;
    (2) Production from a deep well or phase 1 ultra-deep well on any 
other lease, except as provided in paragraph (c) of this section;
    (3) Any liquid hydrocarbon (oil and condensate) volumes; or
    (4) Production from a deep well or phase 1 ultra-deep well that 
commenced drilling before:
    (i) March 26, 2003, on a lease that is located entirely or partly in 
water less than 200 meters deep, or
    (ii) May 18, 2007, on a lease that is located entirely in water more 
than 200 meters deep.



Sec. 203.44  What administrative steps must I take to use the royalty
suspension volume?

    (a) You must notify the BSEE Regional Supervisor for Production and 
Development in writing of your intent to begin drilling operations on 
all deep wells and phase 1 ultra-deep wells; and
    (b) Within 30 days of the beginning of production from all wells 
that would become qualified wells by satisfying the requirements of this 
section, you must:
    (1) Provide written notification to the BSEE Regional Supervisor for 
Production and Development that production has begun; and

[[Page 25]]

    (2) Request confirmation of the size of the royalty suspension 
volume earned by your lease.
    (c) Before beginning production, you must meet any production 
measurement requirements that the BSEE Regional Supervisor for 
Production and Development has determined are necessary under 30 CFR 
part 250, subpart L.
    (d) You must provide the information in paragraph (b) of this 
section by January 20, 2009, if you produced before December 18, 2008, 
from a qualified deep well or qualified phase 1 ultra-deep well on a 
lease that is located entirely in water more than 200 meters and less 
than 400 meters deep.
    (e) The BSEE Regional Supervisor for Production and Development may 
extend the deadline for beginning production for up to one year for a 
well that cannot begin production before the applicable date prescribed 
in the definition of ``qualified deep well'' in Sec. 203.0 if it meets 
all of the following criteria.
    (1) The well otherwise meets the criteria in the definition of a 
qualified deep well in Sec. 203.0.
    (2) The delay in production occurred after reaching total depth in 
the well.
    (3) Production (other than test production) was expected to begin 
from the well before the applicable deadline in the definition of a 
qualified deep well in Sec. 203.0. You must provide a credible activity 
schedule with supporting documentation.
    (4) The delay in beginning production is for reasons beyond your 
control, such as adverse weather and accidents which BSEE deems were 
unavoidable.



Sec. 203.45  If I drill a certified unsuccessful well, what royalty
relief will my lease earn?

    Your lease may earn a royalty suspension supplement. Subject to 
paragraph (d) of this section, the royalty suspension supplement is in 
addition to any royalty suspension volume your lease may earn under 
Sec. 203.41.
    (a) If you drill a certified unsuccessful well and you satisfy the 
administrative requirements of Sec. 203.47, subject to the price 
conditions in Sec. 203.48, your lease earns an RSS shown in the 
following table. The RSS is shown in billions of cubic feet of gas 
equivalent (BCFE) or in thousands of cubic feet of gas equivalent (MCFE) 
and is applicable to oil and gas production as prescribed in 
Sec. 203.46.

------------------------------------------------------------------------
                                            Then your lease earns an RSS
                                              on this volume of oil and
 If you have a certified unsuccessful well  gas production as prescribed
                that is:--                    in this section and Sec.
                                                      203.46:--
------------------------------------------------------------------------
(1) An original well and your lease has     5 BCFE.
 not produced gas or oil from a deep well
 or an ultra-deep well,
(2) A sidetrack (with a sidetrack measured  0.8 BCFE plus 120 MCFE times
 depth of at least 10,000 feet) and your     sidetrack measured depth
 lease has not produced gas or oil from a    (rounded to the nearest 100
 deep well or an ultra-deep well,            feet) but no more than 5
                                             BCFE.
(3) An original well or a sidetrack (with   2 BCFE.
 a sidetrack measured depth of at least
 10,000 feet) and your lease has produced
 gas or oil from a deep well with a
 perforated interval the top of which is
 from 15,000 to less than 18,000 feet TVD
 SS,
------------------------------------------------------------------------

    (b) This paragraph applies to oil and gas volumes you report on the 
OGOR-A for your lease under 30 CFR 1210.102.
    (1) You must apply the RSS prescribed in paragraph (a) of this 
section, in accordance with the requirements in Sec. 203.46, to all oil 
and gas produced from the lease:
    (i) On or after December 18, 2008, if your lease is located in water 
more than 200 meters but less than 400 meters deep; or
    (ii) On or after May 3, 2004, if your lease is located in water 
partly or entirely less than 200 meters deep.
    (2) Production to which an RSV applies under Secs. 203.31 through 
203.33 and Secs. 203.41 through 203.43 does not count toward the lease 
RSS. All other production, including production that is not subject to 
royalty, counts toward the lease RSS.

    Example 1: If you drill a certified unsuccessful well that is an 
original well to a target 19,000 feet TVD SS, your lease earns an RSS of 
5 BCFE that would be applied to gas

[[Page 26]]

and oil production if your lease has not previously produced from a deep 
well or an ultra-deep well, or you earn an RSS of 2 BCFE of gas and oil 
production if your lease has previously produced from a deep well with a 
perforated interval from 15,000 to less than 18,000 feet TVD SS, as 
prescribed in Sec. 203.46.
    Example 2: If you drill a certified unsuccessful well that is a 
sidetrack that reaches a target 19,000 feet TVD SS, that has a sidetrack 
measured depth of 12,545 feet, and your lease has not produced gas or 
oil from any deep well or ultra-deep well, BSEE rounds the sidetrack 
measured depth to 12,500 feet and your lease earns an RSS of 2.3 BCFE of 
gas and oil production as prescribed in Sec. 203.45.

    (c) The conversion from oil to gas for using the royalty suspension 
supplement is specified in Sec. 203.73.
    (d) Each lease is eligible for up to two royalty suspension 
supplements. Therefore, the total royalty suspension supplement for a 
lease cannot exceed 10 BCFE.
    (1) You may not earn more than one royalty suspension supplement 
from a single wellbore.
    (2) If you begin drilling a certified unsuccessful well on one lease 
but the completion target is on a second lease, the entire royalty 
suspension supplement belongs to the second lease. However, if the 
target straddles a lease line, the lease where the surface of the well 
is located earns the royalty suspension supplement.
    (e) If the same wellbore that earns an RSS as a certified 
unsuccessful well later produces from a perforated interval the top of 
which is 15,000 feet TVD or deeper and becomes a qualified well, it will 
be subject to the following conditions:
    (1) Beginning on the date production starts, you must stop applying 
the royalty suspension supplement earned by that wellbore to your lease 
production.
    (2) If the completion of this qualified well is on your lease or, in 
the case of a directional well, is on another lease, then you must 
subtract from the royalty suspension volume earned by that qualified 
well the royalty suspension supplement amounts earned by that wellbore 
that have already been applied either on your lease or any other lease. 
The difference represents the royalty suspension volume earned by the 
qualified well.
    (f) If the same wellbore that earned a royalty suspension supplement 
later has a sidetrack drilled from that wellbore, you are not required 
to subtract any royalty suspension supplement earned by that wellbore 
from the royalty suspension volume that may be earned by the sidetrack.
    (g) You owe minimum royalties or rentals in accordance with your 
lease terms notwithstanding any royalty suspension supplements under 
this section.



Sec. 203.46  To which production do I apply the royalty suspension
supplements from drilling one or two certified unsuccessful wells
on my lease?

    (a) Subject to the requirements of Secs. 203.40, 203.43, 203.45, 
203.47, and 203.48 you must apply an RSS in Sec. 203.45 to the earliest 
oil and gas production:
    (1) Occurring on and after the day you file the information under 
Sec. 203.47(b),
    (2) From, or allocated under a BSEE-approved unit agreement to, the 
lease on which the certified unsuccessful well was drilled, without 
regard to the drilling depth of the well producing the gas or oil.
    (b) If you have a royalty suspension volume for the lease under 
Sec. 203.41, you must use the royalty suspension volumes for gas 
produced from qualified wells on the lease before using royalty 
suspension supplements for gas produced from qualified wells.

    Example to paragraph (b): You have two shallow oil wells on your 
lease. Then you drill a certified unsuccessful well and earn a royalty 
suspension supplement of 5 BCFE. Thereafter, you begin production from 
an original well that is a qualified well that earns a royalty 
suspension volume of 15 BCF. You use only 2 BCFE of the royalty 
suspension supplement before the oil wells deplete. You must use up the 
15 BCF of royalty suspension volume before you use the remaining 3 BCFE 
of the royalty suspension supplement for gas produced from the qualified 
well.

    (c) If you have no current production on which to apply the RSS 
allowed under Sec. 203.45, your RSS applies to the earliest subsequent 
production of gas and oil from, or allocated under a BSEE-approved unit 
agreement to, your lease.

[[Page 27]]

    (d) Unused royalty suspension supplements transfer to a successor 
lessee and expire with the lease.
    (e) You may not apply the RSS allowed under Sec. 203.45 to 
production from any other lease, except for production allocated to your 
lease from a BSEE-approved unit agreement. If your certified 
unsuccessful well is on a lease subject to a BSEE-approved unit 
agreement, the lessees of other leases in the unit may not apply any 
portion of the RSS for your lease to production from the other leases in 
the unit.
    (f) You must begin or resume paying royalties when cumulative gas 
and oil production from, or allocated under a BSEE-approved unit 
agreement to, your lease (excluding any gas produced from qualified 
wells subject to a royalty suspension volume allowed under Sec. 203.41) 
reaches the applicable royalty suspension supplement. For the month in 
which the cumulative production reaches this royalty suspension 
supplement, you owe royalties on the portion of gas or oil production 
that exceeds the amount of the royalty suspension supplement remaining 
at the beginning of that month.



Sec. 203.47  What administrative steps do I take to obtain and use the
royalty suspension supplement?

    (a) Before you start drilling a well on your lease targeted to a 
reservoir at least 18,000 feet TVD SS, you must notify, in writing, the 
BSEE Regional Supervisor for Production and Development of your intent 
to begin drilling operations and the depth of the target.
    (b) After drilling the well, you must provide the BSEE Regional 
Supervisor for Production and Development within 60 days after reaching 
the total depth in your well:
    (1) Information that allows BSEE to confirm that you drilled a 
certified unsuccessful well as defined under Sec. 203.0, including:
    (i) Well log data, if your original well or sidetrack does not meet 
the producibility requirements of 30 CFR part 550, subpart A; or
    (ii) Well log, well test, seismic, and economic data, if your well 
does meet the producibility requirements of 30 CFR part 550, subpart A; 
and
    (2) Information that allows BSEE to confirm the size of the royalty 
suspension supplement for a sidetrack, including sidetrack measured 
depth and supporting documentation.
    (c) If you commenced drilling a well that otherwise meets the 
criteria for a certified unsuccessful well on a lease located entirely 
in more than 200 meters and entirely less than 400 meters of water on or 
after May 18, 2007, and finished it before December 18, 2008, you must 
provide the information in paragraph (b) of this section no later than 
February 17, 2009.



Sec. 203.48  Do I keep royalty relief if prices rise significantly?

    (a) You must pay royalties on all gas and oil production for which 
an RSV or an RSS otherwise would be allowed under Secs. 203.40 through 
203.47 for any calendar year when the average daily closing NYMEX 
natural gas price exceeds the applicable threshold price shown in the 
following table.

------------------------------------------------------------------------
For a lease located in                          The applicable threshold
      water . . .          And issued . . .          price is . . .
------------------------------------------------------------------------
(1) Partly or entirely  before December 18,    $10.15 per MMBtu,
 less than 200 meters    2008,                  adjusted annually after
 deep,                                          calendar year 2007 for
                                                inflation.
(2) Partly or entirely  after December 18,     $4.55 per MMBtu, adjusted
 less than 200 meters    2008,                  annually after calendar
 deep,                                          year 2007 for inflation
                                                unless the lease terms
                                                prescribe a different
                                                price threshold.
(3) Entirely more than  on any date,           $4.55 per MMBtu, adjusted
 200 meters and                                 annually after calendar
 entirely less than                             year 2007 for inflation
 400 meters deep,                               unless the lease terms
                                                prescribe a different
                                                price threshold.
------------------------------------------------------------------------

    (b) Determine the threshold price for any calendar year after 2007 
by adjusting the threshold price in the previous year by the percentage 
that the implicit price deflator for the gross domestic product, as 
published by the Department of Commerce, changed during the calendar 
year.
    (c) You must pay any royalty due under this section no later than 
March

[[Page 28]]

31 of the year following the calendar year for which you owe royalty. If 
you do not pay by that date, you must pay late payment interest under 30 
CFR 1218.54 from April 1 until the date of payment.
    (d) Production volumes on which you must pay royalty under this 
section count as part of your RSV and RSS.



Sec. 203.49  May I substitute the deep gas drilling provisions in this
part for the deep gas royalty relief provided in my lease terms?

    (a) You may exercise an option to replace the applicable lease terms 
for royalty relief related to deep-well drilling with those in 
Sec. 203.0 and Secs. 203.40 through 203.48 if you have a lease issued 
with royalty relief provisions for deep-well drilling. Such leases:
    (1) Must be issued as part of an OCS lease sale held after January 
1, 2001, and before April 1, 2004; and
    (2) Must be located wholly west of 87 degrees, 30 minutes West 
longitude in the GOM entirely or partly in water less than 200 meters 
deep.
    (b) To exercise the option under paragraph (a) of this section, you 
must notify, in writing, the BSEE Regional Supervisor for Production and 
Development of your decision before September 1, 2004, or 180 days after 
your lease is issued, whichever is later, and specify the lease and 
block number.
    (c) Once you exercise the option under paragraph (a) of this 
section, you are subject to all the activity, timing, and administrative 
requirements pertaining to deep gas royalty relief as specified in 
Secs. 203.40 through 203.48.
    (d) Exercising the option under paragraph (a) of this section is 
irrevocable. If you do not exercise this option, then the terms of your 
lease apply.

                  Royalty Relief for End-of-Life Leases



Sec. 203.50  Who may apply for end-of-life royalty relief?

    You may apply for royalty relief in two situations.
    (a) Your end-of-life lease (as defined in Sec. 203.2) is an oil and 
gas lease and has average daily production of at least 100 barrels of 
oil equivalent (BOE) per month (as calculated in Sec. 203.73) in at 
least 12 of the past 15 months. The most recent of these 12 months are 
considered the qualifying months. These 12 months should reflect the 
basic operation you intend to use until your resources are depleted. If 
you changed your operation significantly (e.g., begin re-injecting 
rather than recovering gas) during the qualifying months, or if you do 
so while we are processing your application, we may defer action on your 
application until you revise it to show the new circumstances.
    (b) Your end-of-life lease is other than an oil and gas lease (e.g., 
sulphur) and has production in at least 12 of the past 15 months. The 
most recent of these 12 months are considered the qualifying months.



Sec. 203.51  How do I apply for end-of-life royalty relief?

    You must submit a complete application and the required fee to the 
appropriate BSEE Regional Director. Your BSEE regional office will 
provide specific guidance on the report formats. A complete application 
for relief includes:
    (a) An administrative information report (specified in Sec. 203.83) 
and
    (b) A net revenue and relief justification report (specified in 
Sec. 203.84).



Sec. 203.52  What criteria must I meet to get relief?

    (a) To qualify for relief, you must demonstrate that the sum of 
royalty payments over the 12 qualifying months exceeds 75 percent of the 
sum of net revenues (before-royalty revenues minus allowable costs, as 
defined in Sec. 203.84).
    (b) To re-qualify for relief, e.g., either applying for additional 
relief on top of relief already granted, or applying for relief sometime 
after your earlier agreement terminated, you must demonstrate that:
    (1) You have met the criterion listed in paragraph (a) of this 
section, and
    (2) The 12 required qualifying months of operation have occurred 
under the current royalty arrangement.



Sec. 203.53  What relief will BSEE grant?

    (a) If we approve your application and you meet certain conditions, 
we

[[Page 29]]

will reduce the pre-application effective royalty rate by one-half on 
production up to the relief volume amount. If you produce more than the 
relief volume amount:
    (1) We will impose a royalty rate equal to 1.5 times the effective 
royalty rate on your additional production up to twice the relief volume 
amount; and
    (2) We will impose a royalty rate equal to the effective rate on all 
production greater than twice the relief volume amount.
    (b) Regardless of the level of production or prices (see 
Sec. 203.54), royalty payments due under end-of-life relief will not 
exceed the royalty obligations that would have been due at the effective 
royalty rate.
    (1) The effective royalty rate is the average lease rate paid on 
production during the 12 qualifying months.
    (2) The relief volume amount is the average monthly BOE production 
for the 12 qualifying months.



Sec. 203.54  How does my relief arrangement for an oil and gas lease
operate if prices rise sharply?

    In those months when your current reference price rises by at least 
25 percent above your base reference price, you must pay the effective 
royalty rate on all monthly production.
    (a) Your current reference price is a weighted average of daily 
closing prices on the NYMEX for light sweet crude oil and natural gas 
over the most recent full 12 calendar months;
    (b) Your base reference price is a weighted average of daily closing 
prices on the NYMEX for light sweet crude oil and natural gas during the 
qualifying months; and
    (c) Your weighting factors are the proportions of your total 
production volume (in BOE) provided by oil and gas during the qualifying 
months.



Sec. 203.55  Under what conditions can my end-of-life royalty relief
arrangement for an oil and gas lease be ended?

    (a) If you have an end-of-life royalty relief arrangement, you may 
renounce it at any time. The lease rate will return to the effective 
rate during the qualifying period in the first full month following our 
receipt of your renouncement of the relief arrangement.
    (b) If you pay the effective lease rate for 12 consecutive months, 
we will terminate your relief. The lease rate will return to the 
effective rate in the first full month following this termination.
    (c) We may stipulate in the letter of approval for individual cases 
certain events that would cause us to terminate relief because they are 
inconsistent with an end-of-life situation.



Sec. 203.56  Does relief transfer when a lease is assigned?

    Yes. Royalty relief is based on the lease circumstances, not 
ownership. It transfers upon lease assignment.

  Royalty Relief for Pre-Act Deep Water Leases and for Development and 
                           Expansion Projects



Sec. 203.60  Who may apply for royalty relief on a case-by-case basis
in deep water in the Gulf of Mexico or offshore of Alaska?

    You may apply for royalty relief under Secs. 203.61(b) and 203.62 
for an individual lease, unit or project if you:
    (a) Hold a pre-Act lease (as defined in Sec. 203.0) that we have 
assigned to an authorized field (as defined in Sec. 203.0);
    (b) Propose an expansion project (as defined in Sec. 203.0); or
    (c) Propose a development project (as defined in Sec. 203.0).



Sec. 203.61  How do I assess my chances for getting relief?

    You may ask for a nonbinding assessment (a formal opinion on whether 
a field would qualify for royalty relief) before turning in your first 
complete application on an authorized field. This field must have a 
qualifying well under 30 CFR part 550, subpart A, or be on a lease that 
has allocated production under an approved unit agreement.
    (a) To request a nonbinding assessment, you must:
    (1) Submit a draft application in the format and detail specified in 
guidance from the BSEE regional office for the GOM;
    (2) Propose to drill at least one more appraisal well if you get a 
favorable assessment; and
    (3) Pay a fee under Sec. 203.3.

[[Page 30]]

    (b) You must wait at least 90 days after receiving our assessment to 
apply for relief under Sec. 203.62.
    (c) This assessment is not binding because a complete application 
may contain more accurate information that does not support our original 
assessment. It will help you decide whether your proposed inputs for 
evaluating economic viability and your supporting data and assumptions 
are adequate.



Sec. 203.62  How do I apply for relief?

    (a) You must send a complete application and the required fee to the 
BSEE Regional Director for your region.
    (b) Your application for royalty relief offshore Alaska or in deep 
water in the GOM must include an original and two copies (one set of 
digital information) of:
    (1) Administrative information report;
    (2) Economic viability and relief justification report;
    (3) G&G report;
    (4) Engineering report;
    (5) Production report; and
    (6) Cost report.
    (c) Section 203.82 explains why we are authorized to require these 
reports.
    (d) Sections 203.81, 203.83, and 203.85 through 203.89 describe what 
these reports must include. The BSEE regional office for your region 
will guide you on the format for the required reports, and we encourage 
you to contact this office before preparing your application for this 
guidance.



Sec. 203.63  Does my application have to include all leases in the
field?

    (a) For authorized fields, we will accept only one joint application 
for all leases that are part of the designated field on the date of 
application, except as provided in paragraph (a)(3) of this section and 
Sec. 203.64. However, we will evaluate all acreage that may eventually 
become part of the authorized field. Therefore, if you have any other 
leases that you believe may eventually be part of the authorized field, 
you must submit data for these leases according to Sec. 203.81.
    (1) The Regional Director maintains a Field Names Master List with 
updates of all leases in each designated field.
    (2) To avoid sharing proprietary data with other lessees on the 
field, you may submit your proprietary G&G report separately from the 
rest of your application. Your application is not complete until we 
receive all the required information for each lease on the field. We 
will not disclose proprietary data when explaining our assumptions and 
reasons for our determinations under Sec. 203.67.
    (3) We will not require a joint application if you show good cause 
and honest effort to get all lessees in the field to participate. If you 
must exclude a lease from your application because its lessee will not 
participate, that lease is ineligible for the royalty relief for the 
designated field.
    (b) If your application seeks only relief for a development project 
or an expansion project, your application does not have to include all 
leases in the field.



Sec. 203.64  How many applications may I file on a field or a
development project?

    You may file one complete application for royalty relief during the 
life of the field or for a development project or an expansion project 
designed to produce a reservoir or set of reservoirs. However, you may 
send another application if:
    (a) You are eligible to apply for a redetermination under 
Sec. 203.74;
    (b) You apply for royalty relief for an expansion project;
    (c) You withdraw the application before we make a determination; or
    (d) You apply for end-of-life royalty relief.



Sec. 203.65  How long will BSEE take to evaluate my application?

    (a) We will determine within 20 working days if your application for 
royalty relief is complete. If your application is incomplete, we will 
explain in writing what it needs. If you withdraw a complete 
application, you may reapply.
    (b) We will evaluate your first application on a field within 180 
days, evaluate your first application on a development project or an 
expansion project

[[Page 31]]

within 150 days and evaluate a redetermination under Sec. 203.75 within 
120 days after we determine that it is complete.
    (c) We may ask to extend the review period for your application 
under the conditions in the following table.

------------------------------------------------------------------------
                If . . .                        Then we may . . .
------------------------------------------------------------------------
(1) We need more records to audit sunk   Ask to extend the 120-day or
 costs,                                   180-day evaluation period. The
                                          extension we request will
                                          equal the number of days
                                          between when you receive our
                                          request for records and the
                                          day we receive the records.
(2) We cannot evaluate your application  Add another 30 days. We may add
 for a valid reason, such as missing      more than 30 days, but only if
 vital information or inconsistent or     you agree.
 inconclusive supporting data,
(3) We need more data, explanations, or  Ask to extend the 120-day or
 revision,                                180-day evaluation period. The
                                          extension we request will
                                          equal the number of days
                                          between when you receive our
                                          request and the day we receive
                                          the information.
------------------------------------------------------------------------

    (d) We may change your assumptions under Sec. 203.62 if our 
technical evaluation reveals others that are more appropriate. We may 
consult with you before a final decision and will explain any changes.
    (e) We will notify all designated lease operators within a field 
when royalty relief is granted.



Sec. 203.66  What happens if BSEE does not act in the time allowed?

    If we do not act within the timeframes established under 
Sec. 203.65, you get royalty relief according to the following table.

------------------------------------------------------------------------
                              And we do not decide
  If you apply for royalty       within the time       As long as you
         relief for                specified,
------------------------------------------------------------------------
(a) An authorized field,      You get the minimum   Abide by Secs.
                               suspension volumes    203.70 and 203.76.
                               specified in Sec.
                               203.69,
(b) An expansion project,     You get a royalty     Abide by Secs.
                               suspension for the    203.70 and 203.76.
                               first year of
                               production,
(c) A development project,    You get a royalty     Abide by Secs.
                               suspension for        203.70 and 203.76.
                               initial production
                               for the number of
                               months that a
                               decision is delayed
                               beyond the
                               stipulated
                               timeframes set by
                               Sec. 203.65, plus
                               all the royalty
                               suspension volume
                               for which you
                               qualify,
------------------------------------------------------------------------



Sec. 203.67  What economic criteria must I meet to get royalty relief
on an authorized field or project?

    We will not approve applications if we determine that royalty relief 
cannot make the field, development project, or expansion project 
economically viable. Your field or project must be uneconomic while you 
are paying royalties and must become economic with royalty relief.



Sec. 203.68  What pre-application costs will BSEE consider in 
determining economic viability?

    (a) We will not consider ineligible costs as set forth in 
Sec. 203.89(h) in determining economic viability for purposes of royalty 
relief.
    (b) We will consider sunk costs according to the following table.

----------------------------------------------------------------------------------------------------------------
                    We will . . .                                       When determining . . .
----------------------------------------------------------------------------------------------------------------
(1) Include sunk costs,                               Whether a field that includes a pre-Act lease which has
                                                       not produced, other than test production, before the
                                                       application or redetermination submission date needs
                                                       relief to become economic.
(2) Not include sunk costs,                           Whether an authorized field, a development project, or an
                                                       expansion project can become economic with full relief
                                                       (see Sec. 203.67).
(3) Not include sunk costs,                           How much suspension volume is necessary to make the field,
                                                       a development project, or an expansion project economic
                                                       (see Sec. 203.69(c)).
(4) Include sunk costs for the project discovery      Whether a development project or an expansion project
 well on each lease,                                   needs relief to become economic.
----------------------------------------------------------------------------------------------------------------


[[Page 32]]



Sec. 203.69  If my application is approved, what royalty relief
will I receive?

    If we approve your application, subject to certain conditions, we 
will not collect royalties on a specified suspension volume for your 
field, development project, or expansion project. Suspension volumes 
include volumes allocated to a lease under an approved unit agreement, 
but exclude any volumes of production that are not normally royalty-
bearing under the lease or the regulations of this chapter (e.g., fuel 
gas).
    (a) For authorized fields, the minimum royalty-suspension volumes 
are:
    (1) 17.5 million barrels of oil equivalent (MMBOE) for fields in 200 
to 400 meters of water;
    (2) 52.5 MMBOE for fields in 400 to 800 meters of water; and
    (3) 87.5 MMBOE for fields in more than 800 meters of water.
    (b) For development projects, any relief we grant applies only to 
project wells and replaces the royalty relief, if any, with which we 
issued your lease.
    (c) If your project is economic given the royalty relief with which 
we issued your lease, we will reject the application.
    (d) If the lease has earned or may earn deep gas royalty relief 
under Secs. 203.40 through 203.49 or ultra-deep gas royalty relief under 
Secs. 203.30 through 203.36, we will take the deep gas royalty relief or 
ultra-deep gas royalty relief into account in determining whether 
further royalty relief for a development project is necessary for 
production to be economic.
    (e) If neither paragraph (c) nor (d) of this section apply, the 
minimum royalty suspension volumes are as shown in the following table:

------------------------------------------------------------------------
                                  The minimum royalty
           For . . .            suspension volume is .     Plus . . .
                                          . .
------------------------------------------------------------------------
(1) RS leases in the GOM or     A volume equal to the   10 percent of
 leases offshore Alaska,         combined royalty        the median of
                                 suspension volumes      the
                                 (or the volume          distribution of
                                 equivalent based on     known
                                 the data in your        recoverable
                                 approved application    resources upon
                                 for other forms of      which BSEE
                                 royalty suspension)     based approval
                                 with which BSEE         of your
                                 issued the leases       application
                                 participating in the    from all
                                 application that have   reservoirs
                                 or plan a well into a   included in the
                                 reservoir identified    project.
                                 in the application,
(2) Leases offshore Alaska or   A volume equal to 10
 other deep water GOM leases     percent of the median
 issued in sales after           of the distribution
 November 28, 2000,              of known recoverable
                                 resources upon which
                                 BSEE based approval
                                 of your application
                                 from all reservoirs
                                 included in the
                                 project.
------------------------------------------------------------------------

    (f) If your application includes pre-Act leases in different 
categories of water depth, we apply the minimum royalty suspension 
volume for the deepest such lease then assigned to the field. We base 
the water depth and makeup of a field on the water-depth delineations in 
the ``Lease Terms and Economic Conditions'' map and the ``Fields 
Directory'' documents and updates in effect at the time your application 
is deemed complete. These publications are available from the BSEE Gulf 
of Mexico Regional Office.
    (g) You will get a royalty suspension volume above the minimum if we 
determine that you need more to make the field or development project 
economic.
    (h) For expansion projects, the minimum royalty suspension volume 
equals 10 percent of the median of the distribution of known recoverable 
resources upon which we based approval of your application from all 
reservoirs included in your project plus any suspension volumes required 
under Sec. 203.66. If we determine that your expansion project may be 
economic only with more relief, we will determine and grant you the 
royalty suspension volume necessary to make the project economic.
    (i) The royalty suspension volume applicable to specific leases will 
continue through the end of the month in which cumulative production 
reaches that volume. You must calculate cumulative production from all 
the leases in the authorized field or project that are entitled to share 
the royalty suspension volume.

[[Page 33]]



Sec. 203.70  What information must I provide after BSEE approves 
relief?

    You must submit reports to us as indicated in the following table. 
Sections 203.81, 203.90, and 203.91 describe what these reports must 
include. The BSEE Regional Office for your region will prescribe the 
formats.

------------------------------------------------------------------------
       Required report          When due to BSEE     Due date extensions
------------------------------------------------------------------------
(a) Fabricator's              Within 18 months      BSEE Director may
 confirmation report.          after approval of     grant you an
                               relief.               extension under
                                                     Sec. 203.79(c) for
                                                     up to 6 months.
(b) Post-production report.   Within 120 days       With acceptable
                               after the start of    justification from
                               production that is    you, the BSEE
                               subject to the        Regional Director
                               approved royalty      for your region may
                               suspension volume.    extend the due date
                                                     up to 30 days.
------------------------------------------------------------------------



Sec. 203.71  How does BSEE allocate a field's suspension volume 
between my lease and other leases on my field?

    The allocation depends on when production occurs, when we issued the 
lease, when we assigned it to the field, and whether we award the volume 
suspension by an approved application or establish it in the lease 
terms, as prescribed in this section.
    (a) If your authorized field has an approved royalty suspension 
volume under Secs. 203.67 and 203.69, we will suspend payment of 
royalties on production from all leases in the field that participate in 
the application until their cumulative production equals the approved 
volume. The following conditions also apply:

------------------------------------------------------------------------
          If . . .                 Then . . .             And . . .
------------------------------------------------------------------------
(1) We assign an eligible     We will not change    Production from the
 lease to your authorized      your authorized       assigned eligible
 field after we approve        field's royalty       lease(s) counts
 relief,                       suspension volume     toward the royalty
                               determined under      suspension volume
                               Sec. 203.69,         for the authorized
                                                     field, but the
                                                     eligible lease will
                                                     not share any
                                                     remaining royalty
                                                     suspension volume
                                                     for the authorized
                                                     field after the
                                                     eligible lease has
                                                     produced the volume
                                                     applicable under 30
                                                     CFR 560.114.
(2) We assign a pre-Act or    We will not change    The assigned
 post-November 2000 deep       your field's          lease(s) may share
 water lease to your field     royalty suspension    in any remaining
 after we approve your         volume,               royalty relief by
 application,                                        filing the short-
                                                     form application
                                                     specified in Sec.
                                                     203.83 and
                                                     authorized in Sec.
                                                     203.82. An assigned
                                                     RS lease also gets
                                                     any portion of its
                                                     royalty suspension
                                                     volume remaining
                                                     even after the
                                                     field has produced
                                                     the approved relief
                                                     volume.
(3) We assign another lease   In our evaluation of  (i) You toll the
 that you operate to your      your authorized       time period for
 field while we are            field, we will take   evaluation until
 evaluating your               into account the      you modify your
 application,                  value of any          application to be
                               royalty relief the    consistent with the
                               added lease already   newly constituted
                               has under 30 CFR      field;
                               560.114 or its       (ii) We have an
                               lease document. If    additional 60 days
                               we find your          to review the new
                               authorized field      information; and
                               still needs          (iii) The assigned
                               additional royalty    pre-Act lease or
                               suspension volume,    royalty suspension
                               that volume will be   lease shares the
                               at least the          royalty suspension
                               combined royalty      we grant to the
                               suspension volume     newly constituted
                               to which all added    field. An eligible
                               leases on the field   lease does not
                               are entitled, or      share the royalty
                               the minimum           suspension we grant
                               suspension volume     to the new field.
                               of the authorized     If you do not agree
                               field, whichever is   to toll, we will
                               greater,              have to reject your
                                                     application due to
                                                     incomplete
                                                     information.
                                                     Production from an
                                                     assigned eligible
                                                     lease counts toward
                                                     the royalty
                                                     suspension volume
                                                     that we grant under
                                                     Sec. 203.69 for
                                                     your authorized
                                                     field, but you will
                                                     not owe royalty on
                                                     production from the
                                                     eligible lease
                                                     until it has
                                                     produced the volume
                                                     applicable under 30
                                                     CFR 560.114.

[[Page 34]]

 
(4) We assign another         We will change your   (i) You both toll
 operator's lease to your      field's minimum       the time period for
 field while we are            suspension volume     evaluation until
 evaluating your               provided the          both of you modify
 application,                  assigned lease        your application to
                               joins the             be consistent with
                               application and is    the new field;
                               entitled to a        (ii) We have an
                               larger minimum        additional 60 days
                               suspension volume,    to review the new
                                                     information; and
                                                    (iii) The assigned
                                                     lease(s) shares the
                                                     royalty suspension
                                                     we grant to the new
                                                     field. If you (the
                                                     original applicant)
                                                     do not agree to
                                                     toll, the other
                                                     operator's lease
                                                     retains any
                                                     suspension volume
                                                     it has or may share
                                                     in any relief that
                                                     we grant by filing
                                                     the short form
                                                     application
                                                     specified in Sec.
                                                     203.83 and
                                                     authorized in Sec.
                                                     203.82.
(5) We reassign a well on a   The past production   For any field based
 pre-Act, eligible, or         from the well         relief, the past
 royalty suspension lease      counts toward the     production for that
 from field A to field B,      royalty suspension    well will not count
                               volume that we        toward any royalty
                               grant under Sec. suspension volume
                               203.69 to field B,    that we grant under
                                                     Sec. 203.69 to
                                                     field A. Moreover,
                                                     past production
                                                     from that well will
                                                     count toward the
                                                     royalty suspension
                                                     volume applicable
                                                     for the lease under
                                                     30 CFR 560.114 if
                                                     the well is on an
                                                     eligible lease or
                                                     under 30 CFR
                                                     560.124 if the well
                                                     is on a royalty
                                                     suspension lease.
------------------------------------------------------------------------

    (b) When a project has more than one lease, the royalty suspension 
volume for each lease equals that lease's actual production from the 
project (or production allocated under an approved unit agreement) until 
total production for all leases in the project equals the project's 
approved royalty suspension volume.
    (c) You may receive a royalty-suspension volume only if your entire 
lease is west of 87 degrees, 30 minutes West longitude. If the field 
lies on both sides of this meridian, only leases located entirely west 
of the meridian will receive a royalty-suspension volume.



Sec. 203.72  Can my lease receive more than one suspension volume?

    Yes. You may apply for royalty relief that involves more than one 
suspension volume under Sec. 203.62 in two circumstances.
    (a) Each field that includes your lease may receive a separate 
royalty-suspension volume, if it meets the evaluation criteria of 
Sec. 203.67.
    (b) An expansion project on your lease may receive a separate 
royalty-suspension volume, even if we have already granted a royalty-
suspension volume to the field that encompasses the project. But the 
reserves associated with the project must not have been part of our 
original determination, and the project must meet the evaluation 
criteria of Sec. 203.67.



Sec. 203.73  How do suspension volumes apply to natural gas?

    You must measure natural gas production under the royalty-suspension 
volume as follows: 5.62 thousand cubic feet of natural gas, measured in 
accordance with 30 CFR part 250, subpart L, equals one barrel of oil 
equivalent.



Sec. 203.74  When will BSEE reconsider its determination?

    You may request a redetermination after we withdraw approval or 
after you renounce royalty relief, unless we withdraw approval due to 
your providing false or intentionally inaccurate information. Under 
certain conditions you may also request a redetermination if we deny 
your application or if you want your approved royalty suspension volume 
to change. In these instances, to be eligible for a redetermination, at 
least one of the following four conditions must occur.
    (a) You have significant new G&G data and you previously have not 
either requested a redetermination or reapplied for relief after we 
withdrew approval or you relinquished royalty relief. ``Significant'' 
means that the new G&G data:
    (1) Results from drilling new wells or getting new three-dimensional 
seismic data and information (but not reinterpreting old data);
    (2) Did not exist at the time of the earlier application; and

[[Page 35]]

    (3) Changes your estimates of gross resource size, quality, or 
projected flow rates enough to materially affect the results of our 
earlier determination.
    (b) You demonstrate in your new application that the technology that 
most efficiently develops this field or lease was not considered or 
deemed feasible in the original application. Your newly proposed 
technology must improve the profitability, under equivalent market 
conditions, of the field or lease relative to the development system 
proposed in the prior application.
    (c) Your current reference price decreases by more than 25 percent 
from your base reference price as calculated under this paragraph.
    (1) Your current reference price is a weighted-average of daily 
closing prices on the NYMEX for light sweet crude oil and natural gas 
over the most recent full 12 calendar months;
    (2) Your base reference price is a weighted average of daily closing 
prices on the NYMEX for light sweet crude oil and natural gas for the 
full 12 calendar months preceding the date of your most recently 
approved application for this royalty relief; and
    (3) The weighting factors are the proportions of the total 
production volume (in BOE) for oil and gas associated with the most 
likely scenario (identified in Secs. 203.85 and 203.88) from your most 
recently approved application for this royalty relief.
    (d) Before starting to build your development and production system, 
you have revised your estimated development costs, and they are more 
than 120 percent of the eligible development costs associated with the 
most likely scenario from your most recently approved application for 
this royalty relief.



Sec. 203.75  What risk do I run if I request a redetermination?

    If you request a redetermination after we have granted you a 
suspension volume, you could lose some or all of the previously granted 
relief. This can happen because you must file a new complete application 
and pay the required fee, as discussed in Sec. 203.62. We will evaluate 
your application under Sec. 203.67 using the conditions prevailing at 
the time of your redetermination request. In our evaluation, we may find 
that you should receive a larger, equivalent, smaller, or no suspension 
volume. This means we could find that you do not qualify for the amount 
of relief previously granted or for any relief at all.



Sec. 203.76  When might BSEE withdraw or reduce the approved size
of my relief?

    We will withdraw approval of relief for any of the following 
reasons.
    (a) You change the type of development system proposed in your 
application (e.g., change from a fixed platform to floating production 
system, or from an independent development and production system to one 
with subsea wells tied back to a host production facility, etc.).
    (b) You do not start building the proposed development and 
production system within 18 months of the date we approved your 
application, unless the BSEE Director grants you an extension under 
Sec. 203.79(c). If you start building the proposed system and then 
suspend its construction before completion, and you do not restart 
continuous building of the proposed system within 18 months of our 
approval, we will withdraw the relief we granted.
    (c) Your actual development costs are less than 80 percent of the 
eligible development costs estimated in your application's most likely 
scenario, and you do not report that fact in your post-production 
development report (Sec. 203.70). Development costs are those 
expenditures defined in Sec. 203.89(b) incurred between the application 
submission date and start of production. If you report this fact in the 
post-production development report, you may retain the lesser of 50 
percent of the original royalty suspension volume or 50 percent of the 
median of the distribution of the potentially recoverable resources 
anticipated in your application.
    (d) We granted you a royalty-suspension volume after you qualified 
for a redetermination under Sec. 203.74(c), and we find out your actual 
development costs are less than 90 percent of the eligible development 
costs associated with your application's most likely scenario. 
Development costs are those

[[Page 36]]

expenditures defined in Sec. 203.89(b) incurred between your application 
submission date and start of production.
    (e) You do not send us the fabrication confirmation report or the 
post-production development report, or you provide false or 
intentionally inaccurate information that was material to our granting 
royalty relief under this section. You must pay royalties and late-
payment interest determined under 30 U.S.C. 1721 and 30 CFR 1218.54 on 
all volumes for which you used the royalty suspension. You also may be 
subject to penalties under other provisions of law.



Sec. 203.77  May I voluntarily give up relief if conditions change?

    Yes, you may voluntarily give up relief by sending a letter to that 
effect to the BSEE Regional office for your region.



Sec. 203.78  Do I keep relief approved by BSEE under this part for my
lease, unit or project if prices rise significantly?

    If prices rise above a base price threshold for light sweet crude 
oil or natural gas, you must pay full royalties on production otherwise 
subject to royalty relief approved by BSEE under Secs. 203.60-203.77 for 
your lease, unit or project as prescribed in this section.
    (a) The following table shows the base price threshold for various 
types of leases, subject to paragraph (b) of this section. Note that, 
for post-November 2000 deepwater leases in the GOM, price thresholds 
apply on a lease basis, so different leases on the same development 
project or expansion project approved for royalty relief may have 
different price thresholds.

------------------------------------------------------------------------
                                             The base price threshold is
                 For . . .                              . . .
------------------------------------------------------------------------
(1) Pre-Act leases in the GOM,              set by statute.
(2) Post-November 2000 deep water leases    indicated in your original
 in the GOM or leases offshore of Alaska     lease agreement or, if
 for which the lease or Notice of Sale set   none, those in the Notice
 a base price threshold,                     of Sale under which your
                                             lease was issued.
(3) Post-November 2000 deep water leases    the threshold set by statute
 in the GOM or leases offshore of Alaska     for pre-Act leases.
 for which the lease or Notice of Sale did
 not set a base price threshold,
------------------------------------------------------------------------

    (b) An exception may occur if we determine that the price thresholds 
in paragraphs (a)(2) or (a)(3) of this section mean the royalty 
suspension volume set under Sec. 203.69 and in lease terms would provide 
inadequate encouragement to increase production or development, in which 
circumstance we could specify a different set of price thresholds on a 
case-by-case basis.
    (c) Suppose your base oil price threshold set under paragraph (a) is 
$28.00 per barrel, and the daily closing NYMEX light sweet crude oil 
prices for the previous calendar year exceeds $28.00 per barrel, as 
adjusted in paragraph (h) of this section. In this case, we retract the 
royalty relief authorized in this subpart and you must:
    (1) Pay royalties on all oil production for the previous year at the 
lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 and 30 
CFR 1218.54) by March 31 of the current calendar year, and
    (2) Pay royalties on all your oil production in the current year.
    (d) Suppose your base gas price threshold set under paragraph (a) is 
$3.50 per million British thermal units (Btu), and the daily closing 
NYMEX light sweet crude oil prices for the previous calendar year 
exceeds $3.50 per million Btu, as adjusted in paragraph (h) of this 
section. In this case, we retract the royalty relief authorized in this 
subpart and you must:
    (1) Pay royalties on all gas production for the previous year at the 
lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 and 30 
CFR 1218.54) by March 31 of the current calendar year, and
    (2) Pay royalties on all your gas production in the current year.
    (e) Production under both paragraphs (c) and (d) of this section 
counts as part of the royalty-suspension volume.
    (f) You are entitled to a refund or credit, with interest, of 
royalties paid on any production (that counts as part of the royalty-
suspension volume):

[[Page 37]]

    (1) Of oil if the arithmetic average of the closing prices for the 
current calendar year is $28.00 per barrel or less, as adjusted in 
paragraph (h) of this section, and
    (2) Of gas if the arithmetic average of the closing natural gas 
prices for the current calendar year is $3.50 per million Btu or less, 
as adjusted in paragraph (h) of this section.
    (g) You must follow our regulations in the Office of Natural 
Resources Revenue, 30 CFR chapter XII, for receiving refunds or credits.
    (h) We change the prices referred to in paragraphs (c), (d), and (f) 
of this section periodically. For pre-Act leases, these prices change 
during each calendar year after 1994 by the percentage that the implicit 
price deflator for the gross domestic product changed during the 
preceding calendar year. For post-November 2000 deepwater leases, these 
prices change as indicated in the lease instrument or in the Notice of 
Sale under which we issued the lease.



Sec. 203.79  How do I appeal BSEE's decisions related to royalty relief
for a deepwater lease or a development or expansion project?

    (a) Once we have designated your lease as part of a field and 
notified you and other affected operators of the designation, you can 
request reconsideration by sending the BSEE Director a letter within 15 
days that also states your reasons. The BSEE Director's response is the 
final agency action.
    (b) Our decisions on your application for relief from paying royalty 
under Sec. 203.67 and the royalty-suspension volumes under Sec. 203.69 
are final agency actions.
    (c) If you cannot start construction by the deadline in 
Sec. 203.76(b) for reasons beyond your control (e.g., strike at the 
fabrication yard), you may request an extension up to 1 year by writing 
the BSEE Director and stating your reasons. The BSEE Director's response 
is the final agency action.
    (d) We will notify you of all final agency actions by certified 
mail, return receipt requested. Final agency actions are not subject to 
appeal to the Interior Board of Land Appeals under 30 CFR part 290 and 
43 CFR part 4. They are judicially reviewable under section 10(a) of the 
Administrative Procedure Act (5 U.S.C. 702) only if you file an action 
within 30 days of the date you receive our decision.



Sec. 203.80  When can I get royalty relief if I am not eligible for
royalty relief under other sections in the subpart?

    We may grant royalty relief when it serves the statutory purposes 
summarized in Sec. 203.1 and our formal relief programs, including but 
not limited to the applicable levels of the royalty suspension volumes 
and price thresholds, provide inadequate encouragement to promote 
development or increase production. Unless your lease lies offshore of 
Alaska or wholly west of 87 degrees, 30 minutes West longitude in the 
GOM, your lease must be producing to qualify for relief. Before you may 
apply for royalty relief apart from our programs for end-of-life leases 
or for pre-Act deep water leases and development and expansion projects, 
we must agree that your lease or project has two or more of the 
following characteristics:
    (a) The lease has produced for a substantial period and the lessee 
can recover significant additional resources. Significant additional 
resources mean enough to allow production for at least a year more than 
would be profitable without royalty relief.
    (b) Valuable facilities (e.g., a platform or pipeline that would be 
removed upon lease relinquishment) exist that we do not expect a 
successor lessee to use. If the facilities are located off the lease, 
their preservation must depend on continued production from the lease 
applying for royalty relief. We will only consider an allocable share of 
costs for off-lease facilities in the relief application.
    (c) A substantial risk exists that no new lessee will recover the 
resources.
    (d) The lessee made major efforts to reduce operating costs too 
recently to use the formal program for royalty relief (e.g., recent 
significant change in operations).
    (e) Circumstances beyond the lessee's control, other than water 
depth, preclude reliance on one of the existing royalty relief programs.

[[Page 38]]

                            Required Reports



Sec. 203.81  What supplemental reports do royalty-relief applications
require?

    (a) You must send us the supplemental reports, indicated in the 
following table by an X, that apply to your field. Sections 203.83 
through 203.91 describe these reports in detail.

----------------------------------------------------------------------------------------------------------------
                                                                                   Deep water
                                                End-of-life   --------------------------------------------------
              Required reports                     lease          Expansion                        Development
                                                                   project       Pre-act lease       project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information Report.......               X                X                X                X
(2) Net revenue & relief justification                     X   ...............  ...............
 report.....................................
(3) Economic viability & relief               ...............               X                X                X
 justification report (RSVP model inputs
 justified by other required reports).......
(4) G&G report..............................  ...............               X                X                X
(5) Engineering report......................  ...............               X                X                X
(6) Production report.......................  ...............               X                X                X
(7) Deep water cost report..................  ...............               X                X                X
(8) Fabricator's confirmation report........  ...............               X                X                X
(9) Post-production development report......  ...............               X                X                X
----------------------------------------------------------------------------------------------------------------

    (b) You must certify that all information in your application, 
fabricator's confirmation and post-production development reports is 
accurate, complete, and conforms to the most recent content and 
presentation guidelines available from the BSEE Regional office for your 
region.
    (c) With your application and post-production development report, 
you must submit an additional report prepared by an independent CPA 
that:
    (1) Assesses the accuracy of the historical financial information in 
your report; and
    (2) Certifies that the content and presentation of the financial 
data and information conform to our most recent guidelines on royalty 
relief. This means the data and information must:
    (i) Include only eligible costs that are incurred during the 
qualification months; and
    (ii) Be shown in the proper format.
    (d) You must identify the people in the CPA firm who prepared the 
reports referred to in paragraph (c) of this section and make them 
available to us to respond to questions about the historical financial 
information. We may also further review your records to support this 
information.



Sec. 203.82  What is BSEE's authority to collect this information?

    The Office of Management and Budget (OMB) approved the information 
collection requirements in part 203 under 44 U.S.C. 3501 et seq., and 
assigned OMB control number 1010-0071.
    (a) We use the information to determine whether royalty relief will 
result in production that wouldn't otherwise occur. We rely largely on 
your information to make these determinations.
    (1) Your application for royalty relief must contain enough 
information on finances, economics, reservoirs, G&G characteristics, 
production, and engineering estimates for us to determine whether:
    (i) We should grant relief under the law, and
    (ii) The requested relief will ultimately recover more resources and 
return a reasonable profit on project investments.
    (2) Your fabricator confirmation and post-production development 
reports must contain enough information for us to verify that your 
application reasonably represented your plans.
    (b) Applicants (respondents) are Federal OCS oil and gas lessees. 
Applications are required to obtain or retain a benefit. Therefore, if 
you apply for royalty relief, you must provide this information. We will 
protect information considered proprietary under applicable law and 
under regulations at Sec. 203.63 and 30 CFR part 250.
    (c) The Paperwork Reduction Act of 1995 requires us to inform you 
that we may not conduct or sponsor, and you are not required to respond 
to, a collection of information unless it displays a currently valid OMB 
control number.

[[Page 39]]

    (d) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA 
20166.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]



Sec. 203.83  What is in an administrative information report?

    This report identifies the field or lease for which royalty relief 
is requested and must contain the following items:
    (a) The field or lease name;
    (b) The serial number of leases we have assigned to the field, names 
of the lease title holders of record, the lease operators, and whether 
any lease is part of a unit;
    (c) Well number, API number, location, and status of each well that 
has been drilled on the field or lease or project (not required for non-
oil and gas leases);
    (d) The location of any new wells proposed under the terms of the 
application (not required for non-oil and gas leases);
    (e) A description of field or lease history;
    (f) Full information as to whether you will pay royalties or a share 
of production to anyone other than the United States, the amount you 
will pay, and how much you will reduce this payment if we grant relief;
    (g) The type of royalty relief you are requesting;
    (h) Confirmation that BOEM approved a DOCD or supplemental DOCD 
(Deep Water expansion project applications only); and
    (i) A narrative description of the development activities associated 
with the proposed capital investments and an explanation of proposed 
timing of the activities and the effect on production (Deep Water 
applications only).



Sec. 203.84  What is in a net revenue and relief justification report?

    This report presents cash flow data for 12 qualifying months, using 
the format specified in the ``Guidelines for the Application, Review, 
Approval, and Administration of Royalty Relief for End-of-Life Leases'', 
U.S. Department of the Interior, BSEE. Qualifying months for an oil and 
gas lease are the most recent 12 months out of the last 15 months that 
you produced at least 100 BOE per day on average. Qualifying months for 
other than oil and gas leases are the most recent 12 of the last 15 
months having some production.
    (a) The cash flow table you submit must include historical data for:
    (1) Lease production subject to royalty;
    (2) Total revenues;
    (3) Royalty payments out of production;
    (4) Total allowable costs; and
    (5) Transportation and processing costs.
    (b) Do not include in your cash flow table the non-allowable costs 
listed at 30 CFR 1220.013 or:
    (1) OCS rental payments on the lease(s) in the application;
    (2) Damages and losses;
    (3) Taxes;
    (4) Any costs associated with exploratory activities;
    (5) Civil or criminal fines or penalties;
    (6) Fees for your royalty relief application; and
    (7) Costs associated with existing obligations (e.g., royalty 
overrides or other forms of payment for acquiring the lease, 
depreciation on previously acquired equipment or facilities).
    (c) We may, in reviewing and evaluating your application, disallow 
costs when you have not shown they are necessary to operate the lease, 
or if they are inconsistent with end-of-life operations.



Sec. 203.85  What is in an economic viability and relief justification
report?

    This report should show that your project appears economic without 
royalties and sunk costs using the RSVP model we provide. The format of 
the report and the assumptions and parameters we specify are found in 
the ``Guidelines for the Application, Review, Approval and 
Administration of the Deep Water Royalty Relief Program,'' U.S. 
Department of the Interior, BSEE. Clearly justify each parameter you set 
in every scenario you

[[Page 40]]

specify in the RSVP. You may provide supplemental information, including 
your own model and results. The economic viability and relief 
justification report must contain the following items for an oil and gas 
lease.
    (a) Economic assumptions we provide which include:
    (1) Starting oil and gas prices;
    (2) Real price growth;
    (3) Real cost growth or decline rate, if any;
    (4) Base year;
    (5) Range of discount rates; and
    (6) Tax rate (for use in determining after-tax sunk costs).
    (b) Analysis of projected cash flow (from the date of the 
application using annual totals and constant dollar values) which shows:
    (1) Oil and gas production;
    (2) Total revenues;
    (3) Capital expenditures;
    (4) Operating costs;
    (5) Transportation costs; and
    (6) Before-tax net cash flow without royalties, overrides, sunk 
costs, and ineligible costs.
    (c) Discounted values which include:
    (1) Discount rate used (selected from within the range we specify).
    (2) Before-tax net present value without royalties, overrides, sunk 
costs, and ineligible costs.
    (d) Demonstrations that:
    (1) All costs, gross production, and scheduling are consistent with 
the data in the G&G, engineering, production, and cost reports 
(Secs. 203.86 through 203.89) and
    (2) The development and production scenarios provided in the various 
reports are consistent with each other and with the proposed development 
system. You can use up to three scenarios (conservative, most likely, 
and optimistic), but you must link each to a specific range on the 
distribution of resources from the RSVP Resource Module.



Sec. 203.86  What is in a G&G report?

    This report supports the reserve and resource estimates used in the 
economic evaluation and must contain each of the following elements.
    (a) Seismic data which includes:
    (1) Non-interpreted 2D/3D survey lines reflecting any available 
state-of-the-art processing technique in a format readable by BSEE and 
specified by the deep water royalty relief guidelines;
    (2) Interpreted 2D/3D seismic survey lines reflecting any available 
state-of-the-art processing technique identifying all known and 
prospective pay horizons, wells, and fault cuts;
    (3) Digital velocity surveys in the format of the GOM region's 
letter to lessees of 10/1/90;
    (4) Plat map of ``shot points;'' and
    (5) ``Time slices'' of potential horizons.
    (b) Well data which includes:
    (1) Hard copies of all well logs in which--
    (i) The 1-inch electric log shows pay zones and pay counts and 
lithologic and paleo correlation markers at least every 500-feet,
    (ii) The 1-inch type log shows missing sections from other logs 
where faulting occurs,
    (iii) The 5-inch electric log shows pay zones and pay counts and 
labeled points used in establishing resistivity of the formation, 100 
percent water saturated (Ro) and the resistivity of the 
undisturbed formation (Rt), and
    (iv) The 5-inch porosity logs show pay zones and pay counts and 
labeled points used in establishing reservoir porosity or labeled points 
showing values used in calculating reservoir porosity such as bulk 
density or transit time;
    (2) Digital copies of all well logs spudded before December 1, 1995;
    (3) Core data, if available;
    (4) Well correlation sections;
    (5) Pressure data;
    (6) Production test results;
    (7) Pressure-volume-temperature analysis, if available; and
    (8) A table listing the wells and completions, and indicating which 
sands and fault blocks will be targeted for completion or recompletion.
    (c) Map interpretations which includes for each reservoir in the 
field:
    (1) Structure maps consisting of top and base of sand maps showing 
well and seismic shot point locations;
    (2) Isopach maps for net sand, net oil, net gas, all with well 
locations;

[[Page 41]]

    (3) Maps indicating well surface and bottom hole locations, location 
of development facilities, and shot points; and
    (4) An explanation for excluding the reservoirs you are not planning 
to develop.
    (d) Reservoir-specific data which includes:
    (1) Probability of reservoir occurrence with hydrocarbons;
    (2) Probability the hydrocarbon in the reservoir is all oil and the 
probability it is all gas;
    (3) Distributions or point estimates (accompanied by explanations of 
why distributions less appropriately reflect the uncertainty) for the 
parameters used to estimate reservoir size, i.e., acres and net 
thickness;
    (4) Most likely values for porosity, salt water saturation, volume 
factor for oil formation, and volume factor for gas formation;
    (5) Distributions or point estimates (accompanied by explanations of 
why distributions less appropriately reflect the uncertainty) for 
recovery efficiency (in percent) and oil or gas recovery (in stock-tank-
barrels per acre-foot or in thousands of cubic feet per acre foot);
    (6) A gas/oil ratio distribution or point estimate (accompanied by 
explanations of why distributions less appropriately reflect the 
uncertainty) for each reservoir;
    (7) A yield distribution or point estimate (accompanied by 
explanations of why distributions less appropriately reflect the 
uncertainty) for each gas reservoir; and
    (8) Reserve or resource distribution by reservoir.
    (e) Aggregated reserve and resource data which includes:
    (1) The aggregated distributions for reserves and resources (in BOE) 
and oil fraction for your field computed by the resource module of our 
RSVP model;
    (2) A description of anticipated hydrocarbon quality (i.e., specific 
gravity); and
    (3) The ranges within the aggregated distribution for reserves and 
resources that define the development and production scenarios presented 
in the engineering and production reports. Typically there will be three 
ranges specified by two positive reserve and resource points on the 
aggregated distribution. The range at the low end of the distribution 
will be associated with the conservative development and production 
scenario; the middle range will be related to the most likely 
development and production scenario; and, the high end range will be 
consistent with the optimistic development and production scenario.



Sec. 203.87  What is in an engineering report?

    This report defines the development plan and capital requirements 
for the economic evaluation and must contain the following elements.
    (a) A description of the development concept (e.g., tension leg 
platform, fixed platform, floater type, subsea tieback, etc.) which 
includes:
    (1) Its size along with basic design specifications and drawings; 
and
    (2) The construction schedule.
    (b) An identification of planned wells which includes:
    (1) The number;
    (2) The type (platform, subsea, vertical, deviated, horizontal);
    (3) The well depth;
    (4) The drilling schedule;
    (5) The kind of completion (single, dual, horizontal, etc.); and
    (6) The completion schedule.
    (c) A description of the production system equipment which includes:
    (1) The production capacity for oil and gas and a description of 
limiting component(s);
    (2) Any unusual problems (low gravity, paraffin, etc.);
    (3) All subsea structures;
    (4) All flowlines; and
    (5) Schedule for installing the production system.
    (d) A discussion of any plans for multi-phase development which 
includes the conceptual basis for developing in phases and goals or 
milestones required for starting later phases.
    (e) A set of development scenarios consisting of activity timing and 
scale associated with each of up to three production profiles 
(conservative, most likely, optimistic) provided in the production 
report for your field (Sec. 203.88). Each development scenario and 
production profile must denote the likely

[[Page 42]]

events should the field size turn out to be within a range represented 
by one of the three segments of the field size distribution. If you send 
in fewer than three scenarios, you must explain why fewer scenarios are 
more efficient across the whole field size distribution.



Sec. 203.88  What is in a production report?

    This report supports your development and production timing and 
product quality expectations and must contain the following elements.
    (a) Production profiles by well completion and field that specify 
the actual and projected production by year for each of the following 
products: oil, condensate, gas, and associated gas. The production from 
each profile must be consistent with a specific level of reserves and 
resources on the aggregated distribution of field size.
    (b) Production drive mechanisms for each reservoir.



Sec. 203.89  What is in a cost report?

    This report lists all actual and projected costs for your field, 
must explain and document the source of each cost estimate, and must 
identify the following elements.
    (a) Sunk costs. Report sunk costs in dollars not adjusted for 
inflation and only if you have documentation.
    (b) Appraisal, delineation and development costs. Base them on 
actual spending, current authorization for expenditure, engineering 
estimates, or analogous projects. These costs cover:
    (1) Platform well drilling and average depth;
    (2) Platform well completion;
    (3) Subsea well drilling and average depth;
    (4) Subsea well completion;
    (5) Production system (platform); and
    (6) Flowline fabrication and installation.
    (c) Production costs based on historical costs, engineering 
estimates, or analogous projects. These costs cover:
    (1) Operation;
    (2) Equipment; and
    (3) Existing royalty overrides (we will not use the royalty 
overrides in evaluations).
    (d) Transportation costs, based on historical costs, engineering 
estimates, or analogous projects. These costs cover:
    (1) Oil or gas tariffs from pipeline or tankerage;
    (2) Trunkline and tieback lines; and
    (3) Gas plant processing for natural gas liquids.
    (e) Abandonment costs, based on historical costs, engineering 
estimates, or analogous projects. You should provide the costs to plug 
and abandon only wells and to remove only production systems for which 
you have not incurred costs as of the time of application submission. 
You should also include a point estimate or distribution of prospective 
salvage value for all potentially reusable facilities and materials, 
along with the source and an explanation of the figures provided.
    (f) A set of cost estimates consistent with each one of up to three 
field-development scenarios and production profiles (conservative, most 
likely, optimistic). You should express costs in constant real dollar 
terms for the base year. You may also express the uncertainty of each 
cost estimate with a minimum and maximum percentage of the base value.
    (g) A spending schedule. You should provide costs for each year (in 
real dollars) for each category in paragraphs (a) through (f) of this 
section.
    (h) A summary of other costs which are ineligible for evaluating 
your need for relief. These costs cover:
    (1) Expenses before first discovery on the field;
    (2) Cash bonuses;
    (3) Fees for royalty relief applications;
    (4) Lease rentals, royalties, and payments of net profit share and 
net revenue share;
    (5) Legal expenses;
    (6) Damages and losses;
    (7) Taxes;
    (8) Interest or finance charges, including those embedded in 
equipment leases;
    (9) Fines or penalties; and
    (10) Money spent on previously existing obligations (e.g., royalty 
overrides or other forms of payment for acquiring a financial position 
in a lease, expenditures for plugging wells and removing and abandoning 
facilities that

[[Page 43]]

existed on the application submission date).



Sec. 203.90  What is in a fabricator's confirmation report?

    This report shows you have committed in a timely way to the approved 
system for production. This report must include the following (or its 
equivalent for unconventionally acquired systems):
    (a) A copy of the contract(s) under which the fabrication yard is 
building the approved system for you;
    (b) A letter from the contractor building the system to the BSEE 
Regional Director for your region certifying when construction started 
on your system; and
    (c) Evidence of an appropriate down payment or equal action that 
you've started acquiring the approved system.



Sec. 203.91  What is in a post-production development report?

    For each cost category in the deep water cost report, you must 
compare actual costs up to the date when production starts to your 
planned pre-production costs. If your application included more than one 
development scenario, you need to compare actual costs with those in 
your scenario of most likely development. Also, you must have this 
report certified by an independent CPA according to Sec. 203.81(c).

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

Subpart E--Solid Minerals, General [Reserved]

Subpart F [Reserved]

Subpart G--Other Solid Minerals [Reserved]

Subpart H--Geothermal Resources [Reserved]

Subpart I--OCS Sulfur [Reserved]

[[Page 44]]



                          SUBCHAPTER B_OFFSHORE





PART 250_OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL
SHELF--Table of Contents



                            Subpart A_General

                    Authority and Definition of Terms

Sec.
250.101  Authority and applicability.
250.102  What does this part do?
250.103  Where can I find more information about the requirements in 
          this part?
250.104  How may I appeal a decision made under BSEE regulations?
250.105  Definitions.

                          Performance Standards

250.106  What standards will the Director use to regulate lease 
          operations?
250.107  What must I do to protect health, safety, property, and the 
          environment?
250.108  What requirements must I follow for cranes and other material-
          handling equipment?
250.109  What documents must I prepare and maintain related to welding?
250.110  What must I include in my welding plan?
250.111  Who oversees operations under my welding plan?
250.112  What standards must my welding equipment meet?
250.113  What procedures must I follow when welding?
250.114  How must I install, maintain, and operate electrical equipment?
250.115-250.117  [Reserved]

                        Gas Storage or Injection

250.118  Will BSEE approve gas injection?
250.119  [Reserved]
250.120  How does injecting, storing, or treating gas affect my royalty 
          payments?
250.121  What happens when the reservoir contains both original gas in 
          place and injected gas?
250.122  What effect does subsurface storage have on the lease term?
250.123  [Reserved]
250.124  Will BSEE approve gas injection into the cap rock containing a 
          sulphur deposit?

                                  Fees

250.125  Service fees.
250.126  Electronic payment instructions.

                        Inspection of Operations

250.130  Why does BSEE conduct inspections?
250.131  Will BSEE notify me before conducting an inspection?
250.132  What must I do when BSEE conducts an inspection?
250.133  Will BSEE reimburse me for my expenses related to inspections?

                            Disqualification

250.135  What will BSEE do if my operating performance is unacceptable?
250.136  How will BSEE determine if my operating performance is 
          unacceptable?

                       Special Types of Approvals

250.140  When will I receive an oral approval?
250.141  May I ever use alternate procedures or equipment?
250.142  How do I receive approval for departures?
250.143-250.144  [Reserved]
250.145  How do I designate an agent or a local agent?
250.146  Who is responsible for fulfilling leasehold obligations?

  Naming and Identifying Facilities and Wells (Does Not Include MODUs)

250.150  How do I name facilities and wells in the Gulf of Mexico 
          Region?
250.151  How do I name facilities in the Pacific Region?
250.152  How do I name facilities in the Alaska Region?
250.153  Do I have to rename an existing facility or well?
250.154  What identification signs must I display?
250.160-250.167  [Reserved]

                               Suspensions

250.168  May operations or production be suspended?
250.169  What effect does suspension have on my lease?
250.170  How long does a suspension last?
250.171  How do I request a suspension?
250.172  When may the Regional Supervisor grant or direct an SOO or SOP?
250.173  When may the Regional Supervisor direct an SOO or SOP?
250.174  When may the Regional Supervisor grant or direct an SOP?
250.175  When may the Regional Supervisor grant an SOO?
250.176  Does a suspension affect my royalty payment?
250.177  What additional requirements may the Regional Supervisor order 
          for a suspension?

[[Page 45]]

      Primary Lease Requirements, Lease Term Extensions, and Lease 
                              Cancellations

250.180  What am I required to do to keep my lease term in effect?
250.181-250.185  [Reserved]

                 Information and Reporting Requirements

250.186  What reporting information and report forms must I submit?
250.187  What are BSEE's incident reporting requirements?
250.188  What incidents must I report to BSEE and when must I report 
          them?
250.189  Reporting requirements for incidents requiring immediate 
          notification.
250.190  Reporting requirements for incidents requiring written 
          notification.
250.191  How does BSEE conduct incident investigations?
250.192  What reports and statistics must I submit relating to a 
          hurricane, earthquake, or other natural occurrence?
250.193  Reports and investigations of possible violations.
250.194  How must I protect archaeological resources?
250.195  What notification does BSEE require on the production status of 
          wells?
250.196  Reimbursements for reproduction and processing costs.
250.197  Data and information to be made available to the public or for 
          limited inspection.

                               References

250.198  Documents incorporated by reference.
250.199  Paperwork Reduction Act statements--information collection.

                     Subpart B_Plans and Information

                           General Information

250.200  Definitions.
250.201  What plans and information must I submit before I conduct any 
          activities on my lease or unit?
250.202-250.203  [Reserved]
250.204  How must I protect the rights of the Federal government?
250.205  Are there special requirements if my well affects an adjacent 
          property?

          Post-Approval Requirements for the EP, DPP, and DOCD

250.282  Do I have to conduct post-approval monitoring?

                    Deepwater Operations Plans (DWOP)

250.286  What is a DWOP?
250.287  For what development projects must I submit a DWOP?
250.288  When and how must I submit the Conceptual Plan?
250.289  What must the Conceptual Plan contain?
250.290  What operations require approval of the Conceptual Plan?
250.291  When and how must I submit the DWOP?
250.292  What must the DWOP contain?
250.293  What operations require approval of the DWOP?
250.294  May I combine the Conceptual Plan and the DWOP?
250.295  When must I revise my DWOP?

               Subpart C_Pollution Prevention and Control

250.300  Pollution prevention.
250.301  Inspection of facilities.

                Subpart D_Oil and Gas Drilling Operations

                          General Requirements

250.400  General requirements.
250.401-250.403  [Reserved]
250.404  What are the requirements for the crown block?
250.405  What are the safety requirements for diesel engines used on a 
          drilling rig?
250.406  [Reserved]
250.407  What tests must I conduct to determine reservoir 
          characteristics?
250.408  May I use alternative procedures or equipment during drilling 
          operations?
250.409  May I obtain departures from these drilling requirements?

                     Applying for a Permit to Drill

250.410  How do I obtain approval to drill a well?
250.411  What information must I submit with my application?
250.412  What requirements must the location plat meet?
250.413  What must my description of well drilling design criteria 
          address?
250.414  What must my drilling prognosis include?
250.415  What must my casing and cementing programs include?
250.416  What must I include in the diverter description?
250.417  [Reserved]
250.418  What additional information must I submit with my APD?

                    Casing and Cementing Requirements

250.420  What well casing and cementing requirements must I meet?
250.421  What are the casing and cementing requirements by type of 
          casing string?
250.422  When may I resume drilling after cementing?
250.423  What are the requirements for casing and liner installation?
250.424-250.426  [Reserved]

[[Page 46]]

250.427  What are the requirements for pressure integrity tests?
250.428  What must I do in certain cementing and casing situations?

                      Diverter System Requirements

250.430  When must I install a diverter system?
250.431  What are the diverter design and installation requirements?
250.432  How do I obtain a departure to diverter design and installation 
          requirements?
250.433  What are the diverter actuation and testing requirements?
250.434  What are the recordkeeping requirements for diverter actuations 
          and tests?
250.440-250.451  [Reserved]

                       Drilling Fluid Requirements

250.452  What are the real-time monitoring requirements for Arctic OCS 
          exploratory drilling operations?
250.455  What are the general requirements for a drilling fluid program?
250.456  What safe practices must the drilling fluid program follow?
250.457  What equipment is required to monitor drilling fluids?
250.458  What quantities of drilling fluids are required?
250.459  What are the safety requirements for drilling fluid-handling 
          areas?

                       Other Drilling Requirements

250.460  What are the requirements for conducting a well test?
250.461  What are the requirements for directional and inclination 
          surveys?
250.462  What are the requirements for well-control drills?
250.463  Who establishes field drilling rules?

            Applying for a Permit To Modify and Well Records

250.465  When must I submit an Application for Permit to Modify (APM) or 
          an End of Operations Report to BSEE?
250.466-250.469  [Reserved]

                   Additional Arctic OCS Requirements

250.470  What additional information must I submit with my APD for 
          Arctic OCS exploratory drilling operations?
250.471  What are the requirements for Arctic OCS source control and 
          containment?
250.472  What are the relief rig requirements for the Arctic OCS?
250.473  What must I do to protect health, safety, property, and the 
          environment while operating on the Arctic OCS?

                            Hydrogen Sulfide

250.490  Hydrogen sulfide.

            Subpart E_Oil and Gas Well-Completion Operations

250.500  General requirements.
250.501  Definition.
250.502  [Reserved]
250.503  Emergency shutdown system.
250.504  Hydrogen sulfide.
250.505  Subsea completions.
250.506-250.508  [Reserved]
250.509  Well-completion structures on fixed platforms.
250.510  Diesel engine air intakes.
250.511  Traveling-block safety device.
250.512  Field well-completion rules.
250.513  Approval and reporting of well-completion operations.
250.514  Well-control fluids, equipment, and operations.
250.515-250.517  [Reserved]
250.518  Tubing and wellhead equipment.

                       Casing Pressure Management

250.519  What are the requirements for casing pressure management?
250.520  How often do I have to monitor for casing pressure?
250.521  When do I have to perform a casing diagnostic test?
250.522  How do I manage the thermal effects caused by initial 
          production on a newly completed or recompleted well?
250.523  When do I have to repeat casing diagnostic testing?
250.524  How long do I keep records of casing pressure and diagnostic 
          tests?
250.525  When am I required to take action from my casing diagnostic 
          test?
250.526  What do I submit if my casing diagnostic test requires action?
250.527  What must I include in my notification of corrective action?
250.528  What must I include in my casing pressure request?
250.529  What are the terms of my casing pressure request?
250.530  What if my casing pressure request is denied?
250.531  When does my casing pressure request approval become invalid?

             Subpart F_Oil and Gas Well-Workover Operations

250.600  General requirements.
250.601  Definitions.
250.602  [Reserved]
250.603  Emergency shutdown system.
250.604  Hydrogen sulfide.
250.605  Subsea workovers.
250.606-250.608  [Reserved]
250.609  Well-workover structures on fixed platforms.
250.610  Diesel engine air intakes.
250.611  Traveling-block safety device.
250.612  Field well-workover rules.

[[Page 47]]

250.613  Approval and reporting for well-workover operations.
250.614  Well-control fluids, equipment, and operations.
250.615  [Reserved]
250.616  Coiled tubing and snubbing operations.
250.617-250.618  [Reserved]
250.619  Tubing and wellhead equipment.
250.620  Wireline operations.

Subpart G--Well Operations and Equipment

                          General Requirements

250.700  What operations and equipment does this subpart cover?
250.701  May I use alternate procedures or equipment during operations?
250.702  May I obtain departures from these requirements?
250.703  What must I do to keep wells under control?

                            Rig Requirements

250.710  What instructions must be given to personnel engaged in well 
          operations?
250.711  What are the requirements for well-control drills?
250.712  What rig unit movements must I report?
250.713  What must I provide if I plan to use a mobile offshore drilling 
          unit (MODU) for well operations?
250.714  Do I have to develop a dropped objects plan?
250.715  Do I need a global positioning system (GPS) for all MODUs?

                             Well Operations

250.720  When and how must I secure a well?
250.721  What are the requirements for pressure testing casing and 
          liners?
250.722  What are the requirements for prolonged operations in a well?
250.723  What additional safety measures must I take when I conduct 
          operations on a platform that has producing wells or has other 
          hydrocarbon flow?
250.724  What are the real-time monitoring requirements?

               Blowout Preventer (BOP) System Requirements

250.730  What are the general requirements for BOP systems and system 
          components?
250.731  What information must I submit for BOP systems and system 
          components?
250.732  What are the BSEE-approved verification organization (BAVO) 
          requirements for BOP systems and system components?
250.733  What are the requirements for a surface BOP stack?
250.734  What are the requirements for a subsea BOP system?
250.735  What associated systems and related equipment must all BOP 
          systems include?
250.736  What are the requirements for choke manifolds, kelly-type 
          valves inside BOPs, and drill string safety valves?
250.737  What are the BOP system testing requirements?
250.738  What must I do in certain situations involving BOP equipment or 
          systems?
250.739  What are the BOP maintenance and inspection requirements?

                          Records and Reporting

250.740  What records must I keep?
250.741  How long must I keep records?
250.742  What well records am I required to submit?
250.743  What are the well activity reporting requirements?
250.744  What are the end of operation reporting requirements?
250.745  What other well records could I be required to submit?
250.746  What are the recordkeeping requirements for casing, liner, and 
          BOP tests, and inspections of BOP systems and marine risers?

             Subpart H_Oil and Gas Production Safety Systems

                          General Requirements

Sec.
250.800  General.
250.801  Safety and pollution prevention equipment (SPPE) certification.
250.802  Requirements for SPPE.
250.803  What SPPE failure reporting procedures must I follow?
250.804  Additional requirements for subsurface safety valves (SSSVs) 
          and related equipment installed in high pressure high 
          temperature (HPHT) environments.
250.805  Hydrogen sulfide.
250.806-250.809  [Reserved]

            Surface and Subsurface Safety Systems--Dry Trees

250.810  Dry tree subsurface safety devices--general.
250.811  Specifications for SSSVs--dry trees.
250.812  Surface-controlled SSSVs--dry trees.
250.813  Subsurface-controlled SSSVs.
250.814  Design, installation, and operation of SSSVs--dry trees.
250.815  Subsurface safety devices in shut-in wells--dry trees.
250.816  Subsurface safety devices in injection wells--dry trees.
250.817  Temporary removal of subsurface safety devices for routine 
          operations.

[[Page 48]]

250.818  Additional safety equipment--dry trees.
250.819  Specification for surface safety valves (SSVs).
250.820  Use of SSVs.
250.821  Emergency action and safety system shutdown--dry trees.
250.822-250.824  [Reserved]

           Subsea and Subsurface Safety Systems--Subsea Trees

250.825  Subsea tree subsurface safety devices--general.
250.826  Specifications for SSSVs--subsea trees.
250.827  Surface-controlled SSSVs--subsea trees.
250.828  Design, installation, and operation of SSSVs--subsea trees.
250.829  Subsurface safety devices in shut-in wells--subsea trees.
250.830  Subsurface safety devices in injection wells--subsea trees.
250.831  Alteration or disconnection of subsea pipeline or umbilical.
250.832  Additional safety equipment--subsea trees.
250.833  Specification for underwater safety valves (USVs).
250.834  Use of USVs.
250.835  Specification for all boarding shutdown valves (BSDVs) 
          associated with subsea systems.
250.836  Use of BSDVs.
250.837  Emergency action and safety system shutdown--subsea trees.
250.838  What are the maximum allowable valve closure times and 
          hydraulic bleeding requirements for an electro-hydraulic 
          control system?
250.839  What are the maximum allowable valve closure times and 
          hydraulic bleeding requirements for a direct-hydraulic control 
          system?

                        Production Safety Systems

250.840  Design, installation, and maintenance--general.
250.841  Platforms.
250.842  Approval of safety systems design and installation features.
250.843-250.849  [Reserved]

                Additional Production System Requirements

250.850  Production system requirements--general.
250.851  Pressure vessels (including heat exchangers) and fired vessels.
250.852  Flowlines/Headers.
250.853  Safety sensors.
250.854  Floating production units equipped with turrets and turret-
          mounted systems.
250.855  Emergency shutdown (ESD) system.
250.856  Engines.
250.857  Glycol dehydration units.
250.858  Gas compressors.
250.859  Firefighting systems.
250.860  Chemical firefighting system.
250.861  Foam firefighting systems.
250.862  Fire and gas-detection systems.
250.863  Electrical equipment.
250.864  Erosion.
250.865  Surface pumps.
250.866  Personnel safety equipment.
250.867  Temporary quarters and temporary equipment.
250.868  Non-metallic piping.
250.869  General platform operations.
250.870  Time delays on pressure safety low (PSL) sensors.
250.871  Welding and burning practices and procedures.
250.872  Atmospheric vessels.
250.873  Subsea gas lift requirements.
250.874  Subsea water injection systems.
250.875  Subsea pump systems.
250.876  Fired and exhaust heated components.
250.877-250.879  [Reserved]

                          Safety Device Testing

250.880  Production safety system testing.
250.881-250.889  [Reserved]

                          Records and Training

250.890  Records.
250.891  Safety device training.
250.892-250.899  [Reserved]

                   Subpart I_Platforms and Structures

                   General Requirements for Platforms

250.900  What general requirements apply to all platforms?
250.901  What industry standards must your platform meet?
250.902  What are the requirements for platform removal and location 
          clearance?
250.903  What records must I keep?

                        Platform Approval Program

250.904  What is the Platform Approval Program?
250.905  How do I get approval for the installation, modification, or 
          repair of my platform?
250.906  What must I do to obtain approval for the proposed site of my 
          platform?
250.907  Where must I locate foundation boreholes?
250.908  What are the minimum structural fatigue design requirements?

                      Platform Verification Program

250.909  What is the Platform Verification Program?
250.910  Which of my facilities are subject to the Platform Verification 
          Program?

[[Page 49]]

250.911  If my platform is subject to the Platform Verification Program, 
          what must I do?
250.912  What plans must I submit under the Platform Verification 
          Program?
250.913  When must I resubmit Platform Verification Program plans?
250.914  How do I nominate a CVA?
250.915  What are the CVA's primary responsibilities?
250.916  What are the CVA's primary duties during the design phase?
250.917  What are the CVA's primary duties during the fabrication phase?
250.918  What are the CVA's primary duties during the installation 
          phase?

          Inspection, Maintenance, and Assessment of Platforms

250.919  What in-service inspection requirements must I meet?
250.920  What are the BSEE requirements for assessment of fixed 
          platforms?
250.921  How do I analyze my platform for cumulative fatigue?

             Subpart J_Pipelines and Pipeline Rights-of-Way

250.1000  General requirements.
250.1001  Definitions.
250.1002  Design requirements for DOI pipelines.
250.1003  Installation, testing, and repair requirements for DOI 
          pipelines.
250.1004  Safety equipment requirements for DOI pipelines.
250.1005  Inspection requirements for DOI pipelines.
250.1006  How must I decommission and take out of service a DOI 
          pipeline?
250.1007  What to include in applications.
250.1008  Reports.
250.1009  Requirements to obtain pipeline right-of-way grants.
250.1010  General requirements for pipeline right-of-way holders.
250.1011  [Reserved]
250.1012  Required payments for pipeline right-of-way holders.
250.1013  Grounds for forfeiture of pipeline right-of-way grants.
250.1014  When pipeline right-of-way grants expire.
250.1015  Applications for pipeline right-of-way grants.
250.1016  Granting pipeline rights-of-way.
250.1017  Requirements for construction under pipeline right-of-way 
          grants.
250.1018  Assignment of pipeline right-of-way grants.
250.1019  Relinquishment of pipeline right-of-way grants.

              Subpart K_Oil and Gas Production Requirements

                                 General

250.1150  What are the general reservoir production requirements?

                         Well Tests and Surveys

250.1151  How often must I conduct well production tests?
250.1152  How do I conduct well tests?
250.1153  [Reserved]

                         Classifying Reservoirs

250.1154-250.1155  [Reserved]

                      Approvals Prior to Production

250.1156  What steps must I take to receive approval to produce within 
          500 feet of a unit or lease line?
250.1157  How do I receive approval to produce gas-cap gas from an oil 
          reservoir with an associated gas cap?
250.1158  How do I receive approval to downhole commingle hydrocarbons?

                            Production Rates

250.1159  May the Regional Supervisor limit my well or reservoir 
          production rates?

                laring, Venting, and Burning Hydrocarbons

250.1160  When may I flare or vent gas?
250.1161  When may I flare or vent gas for extended periods of time?
250.1162  When may I burn produced liquid hydrocarbons?
250.1163  How must I measure gas flaring or venting volumes and liquid 
          hydrocarbon burning volumes, and what records must I maintain?
250.1164  What are the requirements for flaring or venting gas 
          containing H2S?

                           Other Requirements

250.1165  What must I do for enhanced recovery operations?
250.1166  What additional reporting is required for developments in the 
          Alaska OCS Region?
250.1167  What information must I submit with forms and for approvals?

 Subpart L_Oil and Gas Production Measurement, Surface Commingling, and 
                                Security

250.1200  Question index table.
250.1201  Definitions.
250.1202  Liquid hydrocarbon measurement.
250.1203  Gas measurement.
250.1204  Surface commingling.
250.1205  Site security.

[[Page 50]]

                          Subpart M_Unitization

250.1300  What is the purpose of this subpart?
250.1301  What are the requirements for unitization?
250.1302  What if I have a competitive reservoir on a lease?
250.1303  How do I apply for voluntary unitization?
250.1304  How will BSEE require unitization?

            Subpart N_Outer Continental Shelf Civil Penalties

            Outer Continental Shelf Lands Act Civil Penalties

250.1400  How does BSEE begin the civil penalty process?
250.1401  [Reserved]
250.1402  Definitions.
250.1403  What is the maximum civil penalty?
250.1404  Which violations will BSEE review for potential civil 
          penalties?
250.1405  When is a case file developed?
250.1406  When will BSEE notify me and provide penalty information?
250.1407  How do I respond to the letter of notification?
250.1408  When will I be notified of the Reviewing Officer's decision?
250.1409  What are my appeal rights?

 Federal Oil and Gas Royalty Management Act Civil Penalties Definitions

250.1450  What definitions apply to this subpart?

                   Penalties After a Period To Correct

250.1451  What may BSEE do if I violate a statute, regulation, order, or 
          lease term relating to a Federal oil and gas lease?
250.1452  What if I correct the violation?
250.1453  What if I do not correct the violation?
250.1454  How may I request a hearing on the record on a Notice of 
          Noncompliance?
250.1455  Does my request for a hearing on the record affect the 
          penalties?
250.1456  May I request a hearing on the record regarding the amount of 
          a civil penalty if I did not request a hearing on the Notice 
          of Noncompliance?

                  Penalties Without a Period To Correct

250.1460  May I be subject to penalties without prior notice and an 
          opportunity to correct?
250.1461  How will BSEE inform me of violations without a period to 
          correct?
250.1462  How may I request a hearing on the record on a Notice of 
          Noncompliance regarding violations without a period to 
          correct?
250.1463  Does my request for a hearing on the record affect the 
          penalties?
250.1464  May I request a hearing on the record regarding the amount of 
          a civil penalty if I did not request a hearing on the Notice 
          of Noncompliance?

                           General Provisions

250.1470  How does BSEE decide what the amount of the penalty should be?
250.1471  Does the penalty affect whether I owe interest?
250.1472  How will the Office of Hearings and Appeals conduct the 
          hearing on the record?
250.1473  How may I appeal the Administrative Law Judge's decision?
250.1474  May I seek judicial review of the decision of the Interior 
          Board of Land Appeals?
250.1475  When must I pay the penalty?
250.1476  Can BSEE reduce my penalty once it is assessed?
250.1477  How may BSEE collect the penalty?

                           Criminal Penalties

250.1480  May the United States criminally prosecute me for violations 
          under Federal oil and gas leases?

          Subpart O_Well Control and Production Safety Training

250.1500  Definitions.
250.1501  What is the goal of my training program?
250.1503  What are my general responsibilities for training?
250.1504  May I use alternative training methods?
250.1505  Where may I get training for my employees?
250.1506  How often must I train my employees?
250.1507  How will BSEE measure training results?
250.1508  What must I do when BSEE administers written or oral tests?
250.1509  What must I do when BSEE administers or requires hands-on, 
          simulator, or other types of testing?
250.1510  What will BSEE do if my training program does not comply with 
          this subpart?

                      Subpart P_Sulphur Operations

250.1600  Performance standard.
250.1601  Definitions.
250.1602  Applicability.
250.1603  Determination of sulphur deposit.
250.1604  General requirements.
250.1605  Drilling requirements.
250.1606  Control of wells.
250.1607  Field rules.
250.1608  Well casing and cementing.
250.1609  Pressure testing of casing.
250.1610  Blowout preventer systems and system components.

[[Page 51]]

250.1611  Blowout preventer systems tests, actuations, inspections, and 
          maintenance.
250.1612  Well-control drills.
250.1613  Diverter systems.
250.1614  Mud program.
250.1615  Securing of wells.
250.1616  Supervision, surveillance, and training.
250.1617  Application for permit to drill.
250.1618  Application for permit to modify.
250.1619  Well records.
250.1620  Well-completion and well-workover requirements.
250.1621  Crew instructions.
250.1622  Approvals and reporting of well-completion and well-workover 
          operations.
250.1623  Well-control fluids, equipment, and operations.
250.1624  Blowout prevention equipment.
250.1625  Blowout preventer system testing, records, and drills.
250.1626  Tubing and wellhead equipment.
250.1627  Production requirements.
250.1628  Design, installation, and operation of production systems.
250.1629  Additional production and fuel gas system requirements.
250.1630  Safety-system testing and records.
250.1631  Safety device training.
250.1632  Production rates.
250.1633  Production measurement.
250.1634  Site security.

                  Subpart Q_Decommissioning Activities

                                 General

250.1700  What do the terms ``decommissioning'', ``obstructions'', and 
          ``facility'' mean?
250.1701  Who must meet the decommissioning obligations in this subpart?
250.1702  When do I accrue decommissioning obligations?
250.1703  What are the general requirements for decommissioning?
250.1704  What decommissioning applications and reports must I submit 
          and when must I submit them?
250.1705  [Reserved]
250.1706  Coiled tubing and snubbing operations.
250.1707-250.1709  [Reserved]

                       Permanently Plugging Wells

250.1710  When must I permanently plug all wells on a lease?
250.1711  When will BSEE order me to permanently plug a well?
250.1712  What information must I submit before I permanently plug a 
          well or zone?
250.1713  Must I notify BSEE before I begin well plugging operations?
250.1714  What must I accomplish with well plugs?
250.1715  How must I permanently plug a well?
250.1716  To what depth must I remove wellheads and casings?
250.1717  [Reserved]

                        Temporary Abandoned Wells

250.1721  If I temporarily abandon a well that I plan to re-enter, what 
          must I do?
250.1722  If I install a subsea protective device, what requirements 
          must I meet?
250.1723  What must I do when it is no longer necessary to maintain a 
          well in temporary abandoned status?

                 Removing Platforms and Other Facilities

250.1725  When do I have to remove platforms and other facilities?
250.1726  When must I submit an initial platform removal application and 
          what must it include?
250.1727  What information must I include in my final application to 
          remove a platform or other facility?
250.1728  To what depth must I remove a platform or other facility?
250.1729  After I remove a platform or other facility, what information 
          must I submit?
250.1730  When might BSEE approve partial structure removal or toppling 
          in place?
250.1731  Who is responsible for decommissioning an OCS facility subject 
          to an Alternate Use RUE?

        Site Clearance for Wells, Platforms, and Other Facilities

250.1740  How must I verify that the site of a permanently plugged well, 
          removed platform, or other removed facility is clear of 
          obstructions?
250.1741  If I drag a trawl across a site, what requirements must I 
          meet?
250.1742  What other methods can I use to verify that a site is clear?
250.1743  How do I certify that a site is clear of obstructions?

                        Pipeline Decommissioning

250.1750  When may I decommission a pipeline in place?
250.1751  How do I decommission a pipeline in place?
250.1752  How do I remove a pipeline?
250.1753  After I decommission a pipeline, what information must I 
          submit?
250.1754  When must I remove a pipeline decommissioned in place?

Subpart R [Reserved]

      Subpart S_Safety and Environmental Management Systems (SEMS)

250.1900  Must I have a SEMS program?

[[Page 52]]

250.1901  What is the goal of my SEMS program?
250.1902  What must I include in my SEMS program?
250.1903  Acronyms and definitions.
250.1904  Special instructions.
250.1905-250.1908  [Reserved]
250.1909  What are management's general responsibilities for the SEMS 
          program?
250.1910  What safety and environmental information is required?
250.1911  What hazards analysis criteria must my SEMS program meet?
250.1912  What criteria for management of change must my SEMS program 
          meet?
250.1913  What criteria for operating procedures must my SEMS program 
          meet?
250.1914  What criteria must be documented in my SEMS program for safe 
          work practices and contractor selection?
250.1915  What training criteria must be in my SEMS program?
250.1916  What criteria for mechanical integrity must my SEMS program 
          meet?
250.1917  What criteria for pre-startup review must be in my SEMS 
          program?
250.1918  What criteria for emergency response and control must be in my 
          SEMS program?
250.1919  What criteria for investigation of incidents must be in my 
          SEMS program?
250.1920  What are the auditing requirements for my SEMS program?
250.1921  What qualifications must the ASP meet?
250.1922  What qualifications must an AB meet?
250.1923  [Reserved]
250.1924  How will BSEE determine if my SEMS program is effective?
250.1925  May BSEE direct me to conduct additional audits?
250.1926  [Reserved]
250.1927  What happens if BSEE finds shortcomings in my SEMS program?
250.1928  What are my recordkeeping and documentation requirements?
250.1929  What are my responsibilities for submitting OCS performance 
          measure data?
250.1930  What must be included in my SEMS program for SWA?
250.1931  What must be included in my SEMS program for UWA?
250.1932  What are my EPP requirements?
250.1933  What procedures must be included for reporting unsafe working 
          conditions?

    Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, 33 U.S.C. 1321(j)(1)(C), 
43 U.S.C. 1334.

    Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

    Editorial Note: Nomenclature changes to part 250 appear at 77 FR 
50891, Aug. 22, 2012.



                            Subpart A_General

                    Authority and Definition of Terms



Sec. 250.101  Authority and applicability.

    The Secretary of the Interior (Secretary) authorized the Bureau of 
Safety and Environmental Enforcement (BSEE) to regulate oil, gas, and 
sulphur exploration, development, and production operations on the Outer 
Continental Shelf (OCS). Under the Secretary's authority, the Director 
requires that all operations:
    (a) Be conducted according to the OCS Lands Act (OCSLA), the 
regulations in this part, BSEE orders, the lease or right-of-way, and 
other applicable laws, regulations, and amendments; and
    (b) Conform to sound conservation practice to preserve, protect, and 
develop mineral resources of the OCS to:
    (1) Make resources available to meet the Nation's energy needs;
    (2) Balance orderly energy resource development with protection of 
the human, marine, and coastal environments;
    (3) Ensure the public receives a fair and equitable return on the 
resources of the OCS;
    (4) Preserve and maintain free enterprise competition; and
    (5) Minimize or eliminate conflicts between the exploration, 
development, and production of oil and natural gas and the recovery of 
other resources.



Sec. 250.102  What does this part do?

    (a) This part 250 contains the regulations of the BSEE Offshore 
program that govern oil, gas, and sulphur exploration, development, and 
production operations on the OCS. When you conduct operations on the 
OCS, you must submit requests, applications, and notices, or provide 
supplemental information for BSEE approval.
    (b) The following table of general references shows where to look 
for information about these processes.

------------------------------------------------------------------------
      For information about . . .                 Refer to . . .
------------------------------------------------------------------------
(1) Applications for permit to drill,..  30 CFR part 250, subpart D.
(2) Development and Production Plans     30 CFR part 550, subpart B.
 (DPP),.

[[Page 53]]

 
(3) Downhole commingling,..............  30 CFR part 250, subpart K.
(4) Exploration Plans (EP),............  30 CFR part 550, subpart B.
(5) Flaring,...........................  30 CFR part 250, subpart K.
(6) Gas measurement,...................  30 CFR part 250, subpart L.
(7) Off-lease geological and             30 CFR part 551.
 geophysical permits,.
(8) Oil spill financial responsibility   30 CFR part 553.
 coverage,.
(9) Oil and gas production safety        30 CFR part 250, subpart H.
 systems,.
(10) Oil spill response plans,.........  30 CFR part 254.
(11) Oil and gas well-completion         30 CFR part 250, subpart E.
 operations,.
(12) Oil and gas well-workover           30 CFR part 250, subpart F.
 operations,.
(13) Decommissioning Activities,.......  30 CFR part 250, subpart Q.
(14) Platforms and structures,.........  30 CFR part 250, subpart I.
(15) Pipelines and Pipeline Rights-of-   30 CFR part 250, subpart J and
 Way,.                                    30 CFR part 550, subpart J.
(16) Sulphur operations,...............  30 CFR part 250, subpart P.
(17) Training,.........................  30 CFR part 250, subpart O.
(18) Unitization,......................  30 CFR part 250, subpart M.
(19) Safety and Environmental            30 CFR part 250, subpart S.
 Management Systems (SEMS),.
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 36148, June 6, 2016]



Sec. 250.103  Where can I find more information about the requirements
in this part?

    BSEE may issue Notices to Lessees and Operators (NTLs) that clarify, 
supplement, or provide more detail about certain requirements. NTLs may 
also outline what you must provide as required information in your 
various submissions to BSEE.



Sec. 250.104  How may I appeal a decision made under BSEE regulations?

    To appeal orders or decisions issued under BSEE regulations in 30 
CFR parts 250 to 282, follow the procedures in 30 CFR part 290.



Sec. 250.105  Definitions.

    Terms used in this part will have the meanings given in the Act and 
as defined in this section:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Affected State means with respect to any program, plan, lease sale, 
or other activity proposed, conducted, or approved under the provisions 
of the Act, any State:
    (1) The laws of which are declared, under section 4(a)(2) of the 
Act, to be the law of the United States for the portion of the OCS on 
which such activity is, or is proposed to be, conducted;
    (2) Which is, or is proposed to be, directly connected by 
transportation facilities to any artificial island or installation or 
other device permanently or temporarily attached to the seabed;
    (3) Which is receiving, or according to the proposed activity, will 
receive oil for processing, refining, or transshipment that was 
extracted from the OCS and transported directly to such State by means 
of vessels or by a combination of means including vessels;
    (4) Which is designated by the Secretary as a State in which there 
is a substantial probability of significant impact on or damage to the 
coastal, marine, or human environment, or a State in which there will be 
significant changes in the social, governmental, or economic 
infrastructure, resulting from the exploration, development, and 
production of oil and gas anywhere on the OCS; or
    (5) In which the Secretary finds that because of such activity there 
is, or will be, a significant risk of serious damage, due to factors 
such as prevailing winds and currents to the marine or coastal 
environment in the event of any oil spill, blowout, or release of oil or 
gas from vessels, pipelines, or other transshipment facilities.
    Air pollutant means any airborne agent or combination of agents for 
which the Environmental Protection Agency (EPA) has established, under 
section 109 of the Clean Air Act, national primary or secondary ambient 
air quality standards.
    Analyzed geological information means data collected under a permit 
or a lease that have been analyzed. Analysis may include, but is not 
limited to, identification of lithologic and fossil content, core 
analysis, laboratory analyses

[[Page 54]]

of physical and chemical properties, well logs or charts, results from 
formation fluid tests, and descriptions of hydrocarbon occurrences or 
hazardous conditions.
    Ancillary activities mean those activities on your lease or unit 
that you:
    (1) Conduct to obtain data and information to ensure proper 
exploration or development of your lease or unit; and
    (2) Can conduct without Bureau of Ocean Energy Management (BOEM) 
approval of an application or permit.
    Archaeological interest means capable of providing scientific or 
humanistic understanding of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurement, 
controlled collection, analysis, interpretation, and explanation.
    Archaeological resource means any material remains of human life or 
activities that are at least 50 years of age and that are of 
archaeological interest.
    Arctic OCS means the Beaufort Sea and Chukchi Sea Planning Areas 
(for more information on these areas, see the Proposed Final OCS Oil and 
Gas Leasing Program for 2012-2017 (June 2012) at http://www.boem.gov/
Oil-and-Gas-Energy-Program/Leasing/Five-Year-Program/2012-2017/Program-
Area-Maps/index.aspx).
    Arctic OCS conditions means, for the purposes of this part, the 
conditions operators can reasonably expect during operations on the 
Arctic OCS. Such conditions, depending on the time of year, include, but 
are not limited to: Extreme cold, freezing spray, snow, extended periods 
of low light, strong winds, dense fog, sea ice, strong currents, and 
dangerous sea states. Remote location, relative lack of infrastructure, 
and the existence of subsistence hunting and fishing areas are also 
characteristic of the Arctic region.
    Attainment area means, for any air pollutant, an area that is shown 
by monitored data or that is calculated by air quality modeling (or 
other methods determined by the Administrator of EPA to be reliable) not 
to exceed any primary or secondary ambient air quality standards 
established by EPA.
    Best available and safest technology (BAST) means the best available 
and safest technologies that the BSEE Director determines to be 
economically feasible wherever failure of equipment would have a 
significant effect on safety, health, or the environment.
    Best available control technology (BACT) means an emission 
limitation based on the maximum degree of reduction for each air 
pollutant subject to regulation, taking into account energy, 
environmental and economic impacts, and other costs. The Regional 
Supervisor will verify the BACT on a case-by-case basis, and it may 
include reductions achieved through the application of processes, 
systems, and techniques for the control of each air pollutant.
    Cap and flow system means an integrated suite of equipment and 
vessels, including a capping stack and associated flow lines, that, when 
installed or positioned, is used to control the flow of fluids escaping 
from the well by conveying the fluids to the surface to a vessel or 
facility equipped to process the flow of oil, gas, and water. A cap and 
flow system is a high pressure system that includes the capping stack 
and piping necessary to convey the flowing fluids through the choke 
manifold to the surface equipment.
    Capping stack means a mechanical device, including one that is pre-
positioned, that can be installed on top of a subsea or surface wellhead 
or blowout preventer to stop the uncontrolled flow of fluids into the 
environment.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial ecosystem 
from the shoreline inward to the boundaries of the coastal zone.
    Coastal zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder) strongly influenced by each other and in 
proximity to the shorelands of the several coastal States. The coastal 
zone includes islands, transition and intertidal areas, salt marshes, 
wetlands, and beaches. The coastal zone extends seaward to the outer 
limit of the U.S. territorial

[[Page 55]]

sea and extends inland from the shorelines to the extent necessary to 
control shorelands, the uses of which have a direct and significant 
impact on the coastal waters, and the inward boundaries of which may be 
identified by the several coastal States, under the authority in section 
305(b)(1) of the Coastal Zone Management Act (CZMA) of 1972.
    Competitive reservoir means a reservoir in which there are one or 
more producible or producing well completions on each of two or more 
leases or portions of leases, with different lease operating interests, 
from which the lessees plan future production.
    Containment dome means a non-pressurized container that can be used 
to collect fluids escaping from the well or equipment below the sea 
surface or from seeps by suspending the device over the discharge or 
seep location. The containment dome includes all of the equipment 
necessary to capture and convey fluids to the surface.
    Correlative rights when used with respect to lessees of adjacent 
leases, means the right of each lessee to be afforded an equal 
opportunity to explore for, develop, and produce, without waste, 
minerals from a common source.
    Data means facts and statistics, measurements, or samples that have 
not been analyzed, processed, or interpreted.
    Departures mean approvals granted by the appropriate BSEE or BOEM 
representative for operating requirements/procedures other than those 
specified in the regulations found in this part. These requirements/
procedures may be necessary to control a well; properly develop a lease; 
conserve natural resources, or protect life, property, or the marine, 
coastal, or human environment.
    Development means those activities that take place following 
discovery of minerals in paying quantities, including but not limited to 
geophysical activity, drilling, platform construction, and operation of 
all directly related onshore support facilities, and which are for the 
purpose of producing the minerals discovered.
    Development geological and geophysical (G&G) activities mean those 
G&G and related data-gathering activities on your lease or unit that you 
conduct following discovery of oil, gas, or sulphur in paying quantities 
to detect or imply the presence of oil, gas, or sulphur in commercial 
quantities.
    Director means the Director of BSEE of the U.S. Department of the 
Interior, or an official authorized to act on the Director's behalf.
    District Manager means the BSEE officer with authority and 
responsibility for operations or other designated program functions for 
a district within a BSEE Region. For activities on the Alaska OCS, any 
reference in this part to District Manager means the BSEE Regional 
Supervisor.
    Easement means an authorization for a nonpossessory, nonexclusive 
interest in a portion of the OCS, whether leased or unleased, which 
specifies the rights of the holder to use the area embraced in the 
easement in a manner consistent with the terms and conditions of the 
granting authority.
    Eastern Gulf of Mexico means all OCS areas of the Gulf of Mexico the 
BOEM Director decides are adjacent to the State of Florida. The Eastern 
Gulf of Mexico is not the same as the Eastern Planning Area, an area 
established for OCS lease sales.
    Emission offsets mean emission reductions obtained from facilities, 
either onshore or offshore, other than the facility or facilities 
covered by the proposed Exploration Plan (EP) or Development and 
Production Plan (DPP).
    Enhanced recovery operations mean pressure maintenance operations, 
secondary and tertiary recovery, cycling, and similar recovery 
operations that alter the natural forces in a reservoir to increase the 
ultimate recovery of oil or gas.
    Existing facility, as used in 30 CFR 550.303, means an OCS facility 
described in an Exploration Plan or a Development and Production Plan 
approved before June 2, 1980.
    Exploration means the commercial search for oil, gas, or sulphur. 
Activities classified as exploration include but are not limited to:
    (1) Geophysical and geological (G&G) surveys using magnetic, 
gravity, seismic reflection, seismic refraction, gas

[[Page 56]]

sniffers, coring, or other systems to detect or imply the presence of 
oil, gas, or sulphur; and
    (2) Any drilling conducted for the purpose of searching for 
commercial quantities of oil, gas, and sulphur, including the drilling 
of any additional well needed to delineate any reservoir to enable the 
lessee to decide whether to proceed with development and production.
    Facility means:
    (1) As used in Sec. 250.130, all installations permanently or 
temporarily attached to the seabed on the OCS (including manmade islands 
and bottom-sitting structures). They include mobile offshore drilling 
units (MODUs) or other vessels engaged in drilling or downhole 
operations, used for oil, gas or sulphur drilling, production, or 
related activities. They include all floating production systems (FPSs), 
variously described as column-stabilized-units (CSUs); floating 
production, storage and offloading facilities (FPSOs); tension-leg 
platforms (TLPs); spars, etc. They also include facilities for product 
measurement and royalty determination (e.g., lease Automatic Custody 
Transfer Units, gas meters) of OCS production on installations not on 
the OCS. Any group of OCS installations interconnected with walkways, or 
any group of installations that includes a central or primary 
installation with processing equipment and one or more satellite or 
secondary installations is a single facility. The Regional Supervisor 
may decide that the complexity of the individual installations justifies 
their classification as separate facilities.
    (2) As used in 30 CFR 550.303, means all installations or devices 
permanently or temporarily attached to the seabed. They include mobile 
offshore drilling units (MODUs), even while operating in the ``tender 
assist'' mode (i.e., with skid-off drilling units) or other vessels 
engaged in drilling or downhole operations. They are used for 
exploration, development, and production activities for oil, gas, or 
sulphur and emit or have the potential to emit any air pollutant from 
one or more sources. They include all floating production systems 
(FPSs), including column-stabilized-units (CSUs); floating production, 
storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); 
spars, etc. During production, multiple installations or devices are a 
single facility if the installations or devices are at a single site. 
Any vessel used to transfer production from an offshore facility is part 
of the facility while it is physically attached to the facility.
    (3) As used in Sec. 250.490(b), means a vessel, a structure, or an 
artificial island used for drilling, well completion, well-workover, or 
production operations.
    (4) As used in Secs. 250.900 through 250.921, means all 
installations or devices permanently or temporarily attached to the 
seabed. They are used for exploration, development, and production 
activities for oil, gas, or sulphur and emit or have the potential to 
emit any air pollutant from one or more sources. They include all 
floating production systems (FPSs), including column-stabilized-units 
(CSUs); floating production, storage and offloading facilities (FPSOs); 
tension-leg platforms (TLPs); spars, etc. During production, multiple 
installations or devices are a single facility if the installations or 
devices are at a single site. Any vessel used to transfer production 
from an offshore facility is part of the facility while it is physically 
attached to the facility.
    (5) As used in subpart S of this part, all types of structures 
permanently or temporarily attached to the seabed (e.g., mobile offshore 
drilling units (MODUs); floating production systems; floating 
production, storage and offloading facilities; tension-leg platforms; 
and spars) that are used for exploration, development, and production 
activities for oil, gas, or sulphur in the OCS. Facilities also include 
DOI-regulated pipelines.
    Flaring means the burning of natural gas as it is released into the 
atmosphere.
    Gas reservoir means a reservoir that contains hydrocarbons 
predominantly in a gaseous (single-phase) state.
    Gas-well completion means a well completed in a gas reservoir or in 
the associated gas-cap of an oil reservoir.
    Geological and geophysical (G&G) explorations mean those G&G surveys 
on

[[Page 57]]

your lease or unit that use seismic reflection, seismic refraction, 
magnetic, gravity, gas sniffers, coring, or other systems to detect or 
imply the presence of oil, gas, or sulphur in commercial quantities.
    Governor means the Governor of a State, or the person or entity 
designated by, or under, State law to exercise the powers granted to 
such Governor under the Act.
    H2S absent means:
    (1) Drilling, logging, coring, testing, or producing operations have 
confirmed the absence of H2S in concentrations that could 
potentially result in atmospheric concentrations of 20 ppm or more of 
H2S; or
    (2) Drilling in the surrounding areas and correlation of geological 
and seismic data with equivalent stratigraphic units have confirmed an 
absence of H2S throughout the area to be drilled.
    H2S present means drilling, logging, coring, testing, or producing 
operations have confirmed the presence of H2S in 
concentrations and volumes that could potentially result in atmospheric 
concentrations of 20 ppm or more of H2S.
    H2S unknown means the designation of a zone or geologic formation 
where neither the presence nor absence of H2S has been 
confirmed.
    Human environment means the physical, social, and economic 
components, conditions, and factors that interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Interpreted geological information means geological knowledge, often 
in the form of schematic cross sections, 3-dimensional representations, 
and maps, developed by determining the geological significance of data 
and analyzed geological information.
    Interpreted geophysical information means geophysical knowledge, 
often in the form of schematic cross sections, 3-dimensional 
representations, and maps, developed by determining the geological 
significance of geophysical data and analyzed geophysical information.
    Lease means an agreement that is issued under section 8 or 
maintained under section 6 of the Act and that authorizes exploration 
for, and development and production of, minerals. The term also means 
the area covered by that authorization, whichever the context requires.
    Lease term pipelines mean those pipelines owned and operated by a 
lessee or operator that are completely contained within the boundaries 
of a single lease, unit, or contiguous (not cornering) leases of that 
lessee or operator.
    Lessee means a person who has entered into a lease with the United 
States to explore for, develop, and produce the leased minerals. The 
term lessee also includes the BOEM-approved assignee of the lease, and 
the owner or the BOEM-approved assignee of operating rights for the 
lease.
    Major Federal action means any action or proposal by the Secretary 
that is subject to the provisions of section 102(2)(C) of the National 
Environmental Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., an action that 
will have a significant impact on the quality of the human environment 
requiring preparation of an environmental impact statement under section 
102(2)(C) of the National Environmental Policy Act).
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the marine ecosystem. 
These include the waters of the high seas, the contiguous zone, 
transitional and intertidal areas, salt marshes, and wetlands within the 
coastal zone and on the OCS.
    Material remains mean physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which such evidence is situated.
    Maximum efficient rate (MER) means the maximum sustainable daily oil 
or gas withdrawal rate from a reservoir that will permit economic 
development and depletion of that reservoir without detriment to 
ultimate recovery.
    Maximum production rate (MPR) means the approved maximum daily rate 
at which oil or gas may be produced from a specified oil-well or gas-
well completion.
    Minerals include oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals

[[Page 58]]

that are authorized by an Act of Congress to be produced.
    Natural resources include, without limiting the generality thereof, 
oil, gas, and all other minerals, and fish, shrimp, oysters, clams, 
crabs, lobsters, sponges, kelp, and other marine animal and plant life 
but does not include water power or the use of water for the production 
of power.
    Nonattainment area means, for any air pollutant, an area that is 
shown by monitored data or that is calculated by air quality modeling 
(or other methods determined by the Administrator of EPA to be reliable) 
to exceed any primary or secondary ambient air quality standard 
established by EPA.
    Nonsensitive reservoir means a reservoir in which ultimate recovery 
is not decreased by high reservoir production rates.
    Oil reservoir means a reservoir that contains hydrocarbons 
predominantly in a liquid (single-phase) state.
    Oil reservoir with an associated gas cap means a reservoir that 
contains hydrocarbons in both a liquid and gaseous (two-phase) state.
    Oil-well completion means a well completed in an oil reservoir or in 
the oil accumulation of an oil reservoir with an associated gas cap.
    Operating rights mean any interest held in a lease with the right to 
explore for, develop, and produce leased substances.
    Operator means the person the lessee(s) designates as having control 
or management of operations on the leased area or a portion thereof. An 
operator may be a lessee, the BSEE-approved or BOEM-approved designated 
agent of the lessee(s), or the holder of operating rights under a BOEM-
approved operating rights assignment.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Person includes a natural person, an association (including 
partnerships, joint ventures, and trusts), a State, a political 
subdivision of a State, or a private, public, or municipal corporation.
    Pipelines are the piping, risers, and appurtenances installed for 
transporting oil, gas, sulphur, and produced waters.
    Processed geological or geophysical information means data collected 
under a permit or a lease that have been processed or reprocessed. 
Processing involves changing the form of data to facilitate 
interpretation. Processing operations may include, but are not limited 
to, applying corrections for known perturbing causes, rearranging or 
filtering data, and combining or transforming data elements. 
Reprocessing is the additional processing other than ordinary processing 
used in the general course of evaluation. Reprocessing operations may 
include varying identified parameters for the detailed study of a 
specific problem area.
    Production means those activities that take place after the 
successful completion of any means for the removal of minerals, 
including such removal, field operations, transfer of minerals to shore, 
operation monitoring, maintenance, and workover operations.
    Production areas are those areas where flammable petroleum gas, 
volatile liquids or sulphur are produced, processed (e.g., compressed), 
stored, transferred (e.g., pumped), or otherwise handled before entering 
the transportation process.
    Projected emissions mean emissions, either controlled or 
uncontrolled, from a source or sources.
    Prospect means a geologic feature having the potential for mineral 
deposits.
    Regional Director means the BSEE officer with responsibility and 
authority for a Region within BSEE.
    Regional Supervisor means the BSEE officer with responsibility and 
authority for operations or other designated program functions within a 
BSEE Region.
    Right-of-use means any authorization issued under 30 CFR Part 550 to 
use OCS lands.
    Right-of-way pipelines are those pipelines that are contained 
within:
    (1) The boundaries of a single lease or unit, but are not owned and 
operated

[[Page 59]]

by a lessee or operator of that lease or unit;
    (2) The boundaries of contiguous (not cornering) leases that do not 
have a common lessee or operator;
    (3) The boundaries of contiguous (not cornering) leases that have a 
common lessee or operator but are not owned and operated by that common 
lessee or operator; or
    (4) An unleased block(s).
    Routine operations, for the purposes of subpart F, mean any of the 
following operations conducted on a well with the tree installed:
    (1) Cutting paraffin;
    (2) Removing and setting pump-through-type tubing plugs, gas-lift 
valves, and subsurface safety valves that can be removed by wireline 
operations;
    (3) Bailing sand;
    (4) Pressure surveys;
    (5) Swabbing;
    (6) Scale or corrosion treatment;
    (7) Caliper and gauge surveys;
    (8) Corrosion inhibitor treatment;
    (9) Removing or replacing subsurface pumps;
    (10) Through-tubing logging (diagnostics);
    (11) Wireline fishing;
    (12) Setting and retrieving other subsurface flow-control devices; 
and
    (13) Acid treatments.
    Sensitive reservoir means a reservoir in which the production rate 
will affect ultimate recovery.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility to the 
National Register of Historic Places as defined in 36 CFR 60.4, or its 
successor.
    Source control and containment equipment (SCCE) means the capping 
stack, cap and flow system, containment dome, and/or other subsea and 
surface devices, equipment, and vessels the collective purpose of which 
is to control a spill source and stop the flow of fluids into the 
environment or to contain fluids escaping into the environment. 
``Surface devices'' refers to equipment mounted or staged on a barge, 
vessel, or facility to separate, treat, store and/or dispose of fluids 
conveyed to the surface by the cap and flow system or the containment 
dome. ``Subsea devices'' includes, but is not limited to, remotely 
operated vehicles, anchors, buoyancy equipment, connectors, cameras, 
controls and other subsea equipment necessary to facilitate the 
deployment, operation, and retrieval of the SCCE. The SCCE does not 
include a blowout preventer.
    Suspension means a granted or directed deferral of the requirement 
to produce (Suspension of Production (SOP)) or to conduct leaseholding 
operations (Suspension of Operations (SOO)).
    Venting means the release of gas into the atmosphere without 
igniting it. This includes gas that is released underwater and bubbles 
to the atmosphere.
    Waste of oil, gas, or sulphur means:
    (1) The physical waste of oil, gas, or sulphur;
    (2) The inefficient, excessive, or improper use, or the unnecessary 
dissipation of reservoir energy;
    (3) The locating, spacing, drilling, equipping, operating, or 
producing of any oil, gas, or sulphur well(s) in a manner that causes or 
tends to cause a reduction in the quantity of oil, gas, or sulphur 
ultimately recoverable under prudent and proper operations or that 
causes or tends to cause unnecessary or excessive surface loss or 
destruction of oil or gas; or
    (4) The inefficient storage of oil.
    Welding means all activities connected with welding, including hot 
tapping and burning.
    Wellbay is the area on a facility within the perimeter of the 
outermost wellheads.
    Well-completion operations mean the work conducted to establish 
production from a well after the production-casing string has been set, 
cemented, and pressure-tested.
    Well-control fluid means drilling mud, completion fluid, or workover 
fluid as appropriate to the particular operation being conducted.
    Western Gulf of Mexico means all OCS areas of the Gulf of Mexico 
except those the BOEM Director decides are adjacent to the State of 
Florida. The Western Gulf of Mexico is not the same as the Western 
Planning Area, an area established for OCS lease sales.

[[Page 60]]

    Workover operations mean the work conducted on wells after the 
initial well-completion operation for the purpose of maintaining or 
restoring the productivity of a well.
    You means a lessee, the owner or holder of operating rights, a 
designated operator or agent of the lessee(s), a pipeline right-of-way 
holder, or a State lessee granted a right-of-use and easement.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20439, Apr. 5, 2013; 81 
FR 46560, July 15, 2016]

                          Performance Standards



Sec. 250.106  What standards will the Director use to regulate lease
operations?

    The Director will regulate all operations under a lease, right-of-
use and easement, or right-of-way to:
    (a) Promote orderly exploration, development, and production of 
mineral resources;
    (b) Prevent injury or loss of life;
    (c) Prevent damage to or waste of any natural resource, property, or 
the environment; and
    (d) Cooperate and consult with affected States, local governments, 
other interested parties, and relevant Federal agencies.



Sec. 250.107  What must I do to protect health, safety, property, 
and the environment?

    (a) You must protect health, safety, property, and the environment 
by:
    (1) Performing all operations in a safe and workmanlike manner;
    (2) Maintaining all equipment and work areas in a safe condition;
    (3) Utilizing recognized engineering practices that reduce risks to 
the lowest level practicable when conducting design, fabrication, 
installation, operation, inspection, repair, and maintenance activities; 
and
    (4) Complying with all lease, plan, and permit terms and conditions.
    (b) You must immediately control, remove, or otherwise correct any 
hazardous oil and gas accumulation or other health, safety, or fire 
hazard.
    (c) Best available and safest technology. (1) On all new drilling 
and production operations and, except as provided in paragraph (c)(3) of 
this section, on existing operations, you must use the best available 
and safest technologies (BAST) which the Director determines to be 
economically feasible whenever the Director determines that failure of 
equipment would have a significant effect on safety, health, or the 
environment, except where the Director determines that the incremental 
benefits are clearly insufficient to justify the incremental costs of 
utilizing such technologies.
    (2) Conformance with BSEE regulations will be presumed to constitute 
the use of BAST unless and until the Director determines that other 
technologies are required pursuant to paragraph (c)(1) of this section.
    (3) The Director may waive the requirement to use BAST on a category 
of existing operations if the Director determines that use of BAST by 
that category of existing operations would not be practicable. The 
Director may waive the requirement to use BAST on an existing operation 
at a specific facility if you submit a waiver request demonstrating that 
the use of BAST would not be practicable.
    (d) BSEE may issue orders to ensure compliance with this part, 
including, but not limited to, orders to produce and submit records and 
to inspect, repair, and/or replace equipment. BSEE may also issue orders 
to shut-in operations of a component or facility because of a threat of 
serious, irreparable, or immediate harm to health, safety, property, or 
the environment posed by those operations or because the operations 
violate law, including a regulation, order, or provision of a lease, 
plan, or permit.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26014, Apr. 29, 2016; 
81 FR 61915, Sept. 7, 2016]



Sec. 250.108  What requirements must I follow for cranes and other
material-handling equipment?

    (a) All cranes installed on fixed platforms must be operated in 
accordance with American Petroleum Institute's Recommended Practice for 
Operation and Maintenance of Offshore Cranes, API RP 2D (as incorporated 
by reference in Sec. 250.198).

[[Page 61]]

    (b) All cranes installed on fixed platforms must be equipped with a 
functional anti-two block device.
    (c) If a fixed platform is installed after March 17, 2003, all 
cranes on the platform must meet the requirements of American Petroleum 
Institute Specification for Offshore Pedestal Mounted Cranes, API Spec 
2C (as incorporated by reference in Sec. 250.198).
    (d) All cranes manufactured after March 17, 2003, and installed on a 
fixed platform, must meet the requirements of API Spec 2C.
    (e) You must maintain records specific to a crane or the operation 
of a crane installed on an OCS fixed platform, as follows:
    (1) Retain all design and construction records, including 
installation records for any anti-two block safety devices, for the life 
of the crane. The records must be kept at the OCS fixed platform.
    (2) Retain all inspection, testing, and maintenance records of 
cranes for at least 4 years. The records must be kept at the OCS fixed 
platform.
    (3) Retain the qualification records of the crane operator and all 
rigger personnel for at least 4 years. The records must be kept at the 
OCS fixed platform.
    (f) You must operate and maintain all other material-handling 
equipment in a manner that ensures safe operations and prevents 
pollution.



Sec. 250.109  What documents must I prepare and maintain related 
to welding?

    (a) You must submit a Welding Plan to the District Manager before 
you begin drilling or production activities on a lease. You may not 
begin welding until the District Manager has approved your plan.
    (b) You must keep the following at the site where welding occurs:
    (1) A copy of the plan and its approval letter; and
    (2) Drawings showing the designated safe-welding areas.



Sec. 250.110  What must I include in my welding plan?

    You must include all of the following in the welding plan that you 
prepare under Sec. 250.109:
    (a) Standards or requirements for welders;
    (b) How you will ensure that only qualified personnel weld;
    (c) Practices and procedures for safe welding that address:
    (1) Welding in designated safe areas;
    (2) Welding in undesignated areas, including wellbay;
    (3) Fire watches;
    (4) Maintenance of welding equipment; and
    (5) Plans showing all designated safe-welding areas.
    (d) How you will prevent spark-producing activities (i.e., grinding, 
abrasive blasting/cutting and arc-welding) in hazardous locations.



Sec. 250.111  Who oversees operations under my welding plan?

    A welding supervisor or a designated person in charge must be 
thoroughly familiar with your welding plan. This person must ensure that 
each welder is properly qualified according to the welding plan. This 
person also must inspect all welding equipment before welding.



Sec. 250.112  What standards must my welding equipment meet?

    Your welding equipment must meet the following requirements:
    (a) All engine-driven welding equipment must be equipped with spark 
arrestors and drip pans;
    (b) Welding leads must be completely insulated and in good 
condition;
    (c) Hoses must be leak-free and equipped with proper fittings, 
gauges, and regulators; and
    (d) Oxygen and fuel gas bottles must be secured in a safe place.



Sec. 250.113  What procedures must I follow when welding?

    (a) Before you weld, you must move any equipment containing 
hydrocarbons or other flammable substances at least 35 feet horizontally 
from the welding area. You must move similar equipment on lower decks at 
least 35 feet from the point of impact where slag, sparks, or other 
burning materials could fall. If moving this equipment is impractical, 
you must protect that equipment with flame-proofed

[[Page 62]]

covers, shield it with metal or fire-resistant guards or curtains, or 
render the flammable substances inert.
    (b) While you weld, you must monitor all water-discharge-point 
sources from hydrocarbon-handling vessels. If a discharge of flammable 
fluids occurs, you must stop welding.
    (c) If you cannot weld in one of the designated safe-welding areas 
that you listed in your safe welding plan, you must meet the following 
requirements:
    (1) You may not begin welding until:
    (i) The welding supervisor or designated person in charge advises in 
writing that it is safe to weld.
    (ii) You and the designated person in charge inspect the work area 
and areas below it for potential fire and explosion hazards.
    (2) During welding, the person in charge must designate one or more 
persons as a fire watch. The fire watch must:
    (i) Have no other duties while actual welding is in progress;
    (ii) Have usable firefighting equipment;
    (iii) Remain on duty for 30 minutes after welding activities end; 
and
    (iv) Maintain a continuous surveillance with a portable gas detector 
during the welding and burning operation if welding occurs in an area 
not equipped with a gas detector.
    (3) You may not weld piping, containers, tanks, or other vessels 
that have contained a flammable substance unless you have rendered the 
contents inert and the designated person in charge has determined it is 
safe to weld. This does not apply to approved hot taps.
    (4) You may not weld within 10 feet of a wellbay unless you have 
shut in all producing wells in that wellbay.
    (5) You may not weld within 10 feet of a production area, unless you 
have shut in that production area.
    (6) You may not weld while you drill, complete, workover, or conduct 
wireline operations unless:
    (i) The fluids in the well (being drilled, completed, worked over, 
or having wireline operations conducted) are noncombustible; and
    (ii) You have precluded the entry of formation hydrocarbons into the 
wellbore by either mechanical means or a positive overbalance toward the 
formation.



Sec. 250.114  How must I install, maintain, and operate electrical 
equipment?

    The requirements in this section apply to all electrical equipment 
on all platforms, artificial islands, fixed structures, and their 
facilities.
    (a) You must classify all areas according to API RP 500, Recommended 
Practice for Classification of Locations for Electrical Installations at 
Petroleum Facilities Classified as Class I, Division 1 and Division 2 
(as incorporated by reference in Sec. 250.198), or API RP 505, 
Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities Classified as Class I, Zone 0, 
Zone 1, and Zone 2 (as incorporated by reference in Sec. 250.198).
    (b) Employees who maintain your electrical systems must have 
expertise in area classification and the performance, operation and 
hazards of electrical equipment.
    (c) You must install all electrical systems according to API RP 14F, 
Recommended Practice for Design and Installation of Electrical Systems 
for Fixed and Floating Offshore Petroleum Facilities for Unclassified 
and Class I, Division 1, and Division 2 Locations (as incorporated by 
reference in Sec. 250.198), or API RP 14FZ, Recommended Practice for 
Design and Installation of Electrical Systems for Fixed and Floating 
Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 
1, and Zone 2 Locations (as incorporated by reference in Sec. 250.198).
    (d) On each engine that has an electric ignition system, you must 
use an ignition system designed and maintained to reduce the release of 
electrical energy.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36149, June 6, 2016]



Secs. 250.115-250.117  [Reserved]

                        Gas Storage or Injection



Sec. 250.118  Will BSEE approve gas injection?

    The Regional Supervisor may authorize you to inject gas on the OCS, 
on and off-lease, to promote conservation

[[Page 63]]

of natural resources and to prevent waste.
    (a) To receive BSEE approval for injection, you must:
    (1) Show that the injection will not result in undue interference 
with operations under existing leases; and
    (2) Submit a written application to the Regional Supervisor for 
injection of gas.
    (b) The Regional Supervisor will approve gas injection applications 
that:
    (1) Enhance recovery;
    (2) Prevent flaring of casinghead gas; or
    (3) Implement other conservation measures approved by the Regional 
Supervisor.



Sec. 250.119  [Reserved]



Sec. 250.120  How does injecting, storing, or treating gas affect
my royalty payments?

    (a) If you produce gas from an OCS lease and inject it into a 
reservoir on the lease or unit for the purposes cited in 
Sec. 250.118(b), you are not required to pay royalties until you remove 
or sell the gas from the reservoir.
    (b) If you produce gas from an OCS lease and store it according to 
30 CFR 550.119, you must pay royalty before injecting it into the 
storage reservoir.
    (c) If you produce gas from an OCS lease and treat it at an off-
lease or off-unit location, you must pay royalties when the gas is first 
produced.



Sec. 250.121  What happens when the reservoir contains both original
gas in place and injected gas?

    If the reservoir contains both original gas in place and injected 
gas, when you produce gas from the reservoir you must use a BSEE-
approved formula to determine the amounts of injected or stored gas and 
gas original to the reservoir.



Sec. 250.122  What effect does subsurface storage have on the lease term?

    If you use a lease area for subsurface storage of gas, it does not 
affect the continuance or expiration of the lease.



Sec. 250.123  [Reserved]



Sec. 250.124  Will BSEE approve gas injection into the cap rock 
containing a sulphur deposit?

    To receive the Regional Supervisor's approval to inject gas into the 
cap rock of a salt dome containing a sulphur deposit, you must show that 
the injection:
    (a) Is necessary to recover oil and gas contained in the cap rock; 
and
    (b) Will not significantly increase potential hazards to present or 
future sulphur mining operations.

                                  Fees



Sec. 250.125  Service fees.

    (a) The table in this paragraph (a) shows the fees that you must pay 
to BSEE for the services listed. The fees will be adjusted periodically 
according to the Implicit Price Deflator for Gross Domestic Product by 
publication of a document in the Federal Register. If a significant 
adjustment is needed to arrive at the new actual cost for any reason 
other than inflation, then a proposed rule containing the new fees will 
be published in the Federal Register for comment.

------------------------------------------------------------------------
  Service--processing of the
          following:                  Fee amount         30 CFR citation
------------------------------------------------------------------------
(1) Suspension of Operations/   $2,123................  Sec. 250.171(e)
 Suspension of Production (SOO/                          .
 SOP) Request.
(2) Deepwater Operations Plan   $3,599................  Sec. 250.292(q)
 (DWOP).                                                 .
(3) Application for Permit to   $2,113 for initial      Sec. 250.410(d)
 Drill (APD); Form BSEE-0123.    applications only; no   ; Sec.
                                 fee for revisions.      250.513(b);
                                                         Sec. 250.1617(
                                                         a).
(4) Application for Permit to   $125..................  Sec. 250.465(b)
 Modify (APM); Form BSEE-0124.                           ; Sec.
                                                         250.513(b);
                                                         Sec. 250.613(b
                                                         ); Sec.
                                                         250.1618(a);
                                                         Sec. 250.1704(
                                                         g).

[[Page 64]]

 
(5) New Facility Production     $5,426................  Sec. 250.842.
 Safety System Application for  $14,280 additional fee
 facility with more than 125     will be charged if
 components.                     BSEE conducts a pre-
                                 production inspection
                                 of a facility
                                 offshore, and $7,426
                                 for an inspection of
                                 a facility while in a
                                 shipyard.
                                A component is a piece
                                 of equipment or
                                 ancillary system that
                                 is protected by one
                                 or more of the safety
                                 devices required by
                                 API RP 14C (as
                                 incorporated by
                                 reference in Sec.
                                 250.198).
(6) New Facility Production     $1,314................  Sec. 250.842.
 Safety System Application for  $8,967 additional fee
 facility with 25-125            will be charged if
 components.                     BSEE conducts a pre-
                                 production inspection
                                 of a facility
                                 offshore, and $5,141
                                 for an inspection of
                                 a facility while in a
                                 shipyard.
(7) New Facility Production     $652..................  Sec. 250.842.
 Safety System Application for
 facility with fewer than 25
 components.
(8) Production Safety System    $605..................  Sec. 250.842.
 Application--Modification
 with more than 125 components
 reviewed.
(9) Production Safety System    $217..................  Sec. 250.842.
 Application--Modification
 with 25-125 components
 reviewed.
(10) Production Safety System   $92...................  Sec. 250.842.
 Application--Modification
 with fewer than 25 components
 reviewed.
(11) Platform Application--     $22,734...............  Sec. 250.905(l)
 Installation--Under the                                 .
 Platform Verification Program.
(12) Platform Application--     $3,256................  Sec. 250.905(l)
 Installation--Fixed Structure                           .
 Under the Platform Approval
 Program.
(13) Platform Application--     $1,657................  Sec. 250.905(l)
 Installation--Caisson/Well
 Protector.
(14) Platform Application--     $3,884................  Sec. 250.905(l)
 Modification/Repair.                                    .
(15) New Pipeline Application   $3,541................  Sec. 250.1000(b
 (Lease Term).                                           ).
(16) Pipeline Application--     $2,056................  Sec. 250.1000(b
 Modification (Lease Term).                              ).
(17) Pipeline Application--     $4,169................  Sec. 250.1000(b
 Modification (ROW).                                     ).
(18) Pipeline Repair            $388..................  Sec. 250.1008(e
 Notification.                                           ).
(19) Pipeline Right-of-Way      $2,771................  Sec. 250.1015(a
 (ROW) Grant Application.                                ).
(20) Pipeline Conversion of     $236..................  Sec. 250.1015(a
 Lease Term to ROW.                                      ).
(21) Pipeline ROW Assignment..  $201..................  Sec. 250.1018(b
                                                         ).
(22) 500 Feet From Lease/Unit   $3,892................  Sec. 250.1156(a
 Line Production Request.                                ).
(23) Gas Cap Production         $4,953................  Sec. 250.1157.
 Request.
(24) Downhole Commingling       $5,779................  Sec. 250.1158(a
 Request.                                                ).
(25) Complex Surface            $4,056................  Sec. 250.1202(a
 Commingling and Measurement                             ); Sec.
 Application.                                            250.1203(b);
                                                         Sec. 250.1204(
                                                         a).
(26) Simple Surface             $1,371................  Sec. 250.1202(a
 Commingling and Measurement                             ); Sec.
 Application.                                            250.1203(b);
                                                         Sec. 250.1204(
                                                         a).
(27) Voluntary Unitization      $12,619...............  Sec. 250.1303(d
 Proposal or Unit Expansion.                             ).
(28) Unitization Revision.....  $896..................  Sec. 250.1303(d
                                                         ).
(29) Application to Remove a    $4,684................  Sec. 250.1727.
 Platform or Other Facility.
(30) Application to             $1,142................  Sec. 250.1751(a
 Decommission a Pipeline                                 ) or Sec.
 (Lease Term).                                           250.1752(a).

[[Page 65]]

 
(31) Application to             $2,170................  Sec. 250.1751(a
 Decommission a Pipeline (ROW).                          ) or Sec.
                                                         250.1752(a).
------------------------------------------------------------------------

    (b) Payment of the fees listed in paragraph (a) of this section must 
accompany the submission of the document for approval or be sent to an 
office identified by the Regional Director. Once a fee is paid, it is 
nonrefundable, even if an application or other request is withdrawn. If 
your application is returned to you as incomplete, you are not required 
to submit a new fee when you submit the amended application.
    (c) Verbal approvals are occasionally given in special 
circumstances. Any action that will be considered a verbal permit 
approval requires either a paper permit application to follow the verbal 
approval or an electronic application submittal within 72 hours. Payment 
must be made with the completed paper or electronic application.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50891, Aug. 22, 2012; 
78 FR 60213, Oct. 1, 2013; 81 FR 26014, Apr. 29, 2016; 81 FR 61916, 
Sept. 7, 2016]



Sec. 250.126  Electronic payment instructions.

    (a) You must file all payments electronically through the Fees for 
Services page on the BSEE Web site at http://www.bsee.gov. This 
includes, but is not limited to, all OCS applications, permits, or any 
filing fees. You must include a copy of the Pay.gov confirmation receipt 
page with your application, permit, or filing fee.
    (b) If you submitted an application or permit through eWell, you 
must use the interactive payment feature in that system, which directs 
you through Pay.gov to make a payment. It is recommended that you keep a 
copy of your payment confirmation receipt in the event that any 
questions arise regarding your transaction.

[81 FR 36149, June 6, 2016]

                        Inspections of Operations



Sec. 250.130  Why does BSEE conduct inspections?

    BSEE will inspect OCS facilities and any vessels engaged in drilling 
or other downhole operations. These include facilities under 
jurisdiction of other Federal agencies that we inspect by agreement. We 
conduct these inspections:
    (a) To verify that you are conducting operations according to the 
Act, the regulations, the lease, right-of-way, the BOEM-approved 
Exploration Plan or Development and Production Plans; or right-of-use 
and easement, and other applicable laws and regulations; and
    (b) To determine whether equipment designed to prevent or ameliorate 
blowouts, fires, spillages, or other major accidents has been installed 
and is operating properly according to the requirements of this part.



Sec. 250.131  Will BSEE notify me before conducting an inspection?

    BSEE conducts both scheduled and unscheduled inspections.



Sec. 250.132  What must I do when BSEE conducts an inspection?

    (a) When BSEE conducts an inspection, you must provide:
    (1) Access to all platforms, artificial islands, and other 
installations on your leases or associated with your lease, right-of-use 
and easement, or right-of-way; and
    (2) Helicopter landing sites and refueling facilities for any 
helicopters we use to regulate offshore operations.
    (b) You must make the following available for us to inspect:
    (1) The area covered under a lease, right-of-use and easement, 
right-of-way, or permit;
    (2) All improvements, structures, and fixtures on these areas; and
    (3) All records of design, construction, operation, maintenance, 
repairs, or investigations on or related to the area.

[[Page 66]]



Sec. 250.133  Will BSEE reimburse me for my expenses related 
to inspections?

    Upon request, BSEE will reimburse you for food, quarters, and 
transportation that you provide for BSEE representatives while they 
inspect lease facilities and operations. You must send us your 
reimbursement request within 90 days of the inspection.

                            Disqualification



Sec. 250.135  What will BSEE do if my operating performance
is unacceptable?

    BSEE will determine if your operating performance is unacceptable. 
BSEE will refer a determination of unacceptable performance to BOEM, who 
may disapprove or revoke your designation as operator on a single 
facility or multiple facilities. We will give you adequate notice and 
opportunity for a review by BSEE officials before making a determination 
that your operating performance is unacceptable.



Sec. 250.136  How will BSEE determine if my operating performance
is unacceptable?

    In determining if your operating performance is unacceptable, BSEE 
will consider, individually or collectively:
    (a) Accidents and their nature;
    (b) Pollution events, environmental damages and their nature;
    (c) Incidents of noncompliance;
    (d) Civil penalties;
    (e) Failure to adhere to OCS lease obligations; or
    (f) Any other relevant factors.

                       Special Types of Approvals



Sec. 250.140  When will I receive an oral approval?

    When you apply for BSEE approval of any activity, we normally give 
you a written decision. The following table shows circumstances under 
which we may give an oral approval.

------------------------------------------------------------------------
    When you . . .           We may . . .              And . . .
------------------------------------------------------------------------
(a) Request approval    Give you an oral       You must then confirm the
 orally                  approval,              oral request by sending
                                                us a written request
                                                within 72 hours.
(b) Request approval    Give you an oral       We will send you a
 in writing,             approval if quick      written approval
                         action is needed,      afterward. It will
                                                include any conditions
                                                that we place on the
                                                oral approval.
(c) Request approval    Give you an oral       You don't have to follow
 orally for gas          approval,              up with a written
 flaring,                                       request unless the
                                                Regional Supervisor
                                                requires it. When you
                                                stop the approved
                                                flaring, you must
                                                promptly send a letter
                                                summarizing the
                                                location, dates and
                                                hours, and volumes of
                                                liquid hydrocarbons
                                                produced and gas flared
                                                by the approved flaring
                                                (see 30 CFR 250, subpart
                                                K).
------------------------------------------------------------------------



Sec. 250.141  May I ever use alternate procedures or equipment?

    You may use alternate procedures or equipment after receiving 
approval as described in this section.
    (a) Any alternate procedures or equipment that you propose to use 
must provide a level of safety and environmental protection that equals 
or surpasses current BSEE requirements.
    (b) You must receive the District Manager's or Regional Supervisor's 
written approval before you can use alternate procedures or equipment.
    (c) To receive approval, you must either submit information or give 
an oral presentation to the appropriate Regional Supervisor. Your 
presentation must describe the site-specific application(s), performance 
characteristics, and safety features of the proposed procedure or 
equipment.



Sec. 250.142  How do I receive approval for departures?

    We may approve departures to the operating requirements. You may 
apply for a departure by writing to the District Manager or Regional 
Supervisor.



Secs. 250.143-250.144  [Reserved]



Sec. 250.145  How do I designate an agent or a local agent?

    (a) You or your designated operator may designate for the Regional 
Supervisor's approval, or the Regional Director may require you to 
designate an

[[Page 67]]

agent empowered to fulfill your obligations under the Act, the lease, or 
the regulations in this part.
    (b) You or your designated operator may designate for the Regional 
Supervisor's approval a local agent empowered to receive notices and 
submit requests, applications, notices, or supplemental information.



Sec. 250.146  Who is responsible for fulfilling leasehold 
obligations?

    (a) When you are not the sole lessee, you and your co-lessee(s) are 
jointly and severally responsible for fulfilling your obligations under 
the provisions of 30 CFR parts 250 through 282 and 30 CFR parts 550 
through 582 unless otherwise provided in these regulations.
    (b) If your designated operator fails to fulfill any of your 
obligations under 30 CFR parts 250 through 282 and 30 CFR parts 550 
through 582, the Regional Supervisor may require you or any or all of 
your co-lessees to fulfill those obligations or other operational 
obligations under the Act, the lease, or the regulations.
    (c) Whenever the regulations in 30 CFR parts 250 through 282 and 30 
CFR parts 550 through 582 require the lessee to meet a requirement or 
perform an action, the lessee, operator (if one has been designated), 
and the person actually performing the activity to which the requirement 
applies are jointly and severally responsible for complying with the 
regulation.

  Naming and Identifying Facilities and Wells (Does Not Include MODUs)



Sec. 250.150  How do I name facilities and wells in the Gulf of
Mexico Region?

    (a) Assign each facility a letter designation except for those types 
of facilities identified in paragraph (c)(1) of this section. For 
example, A, B, CA, or CB.
    (1) After a facility is installed, rename each predrilled well that 
was assigned only a number and was suspended temporarily at the mudline 
or at the surface. Use a letter and number designation. The letter used 
must be the same as that of the production facility, and the number used 
must correspond to the order in which the well was completed, not 
necessarily the number assigned when it was drilled. For example, the 
first well completed for production on Facility A would be renamed Well 
A-1, the second would be Well A-2, and so on; and
    (2) When you have more than one facility on a block, each facility 
installed, and not bridge-connected to another facility, must be named 
using a different letter in sequential order. For example, EC 222A, EC 
222B, EC 222C.
    (3) When you have more than one facility on multiple blocks in a 
local area being co-developed, each facility installed and not connected 
with a walkway to another facility should be named using a different 
letter in sequential order with the block number corresponding to the 
block on which the platform is located. For example, EC 221A, EC 222B, 
and EC 223C.
    (b) In naming multiple well caissons, you must assign a letter 
designation.
    (c) In naming single well caissons, you must use certain criteria as 
follows:
    (1) For single well caissons not attached to a facility with a 
walkway, use the well designation. For example, Well No. 1;
    (2) For single well caissons attached to a facility with a walkway, 
use the same designation as the facility. For example, rename Well No.10 
as A-10; and
    (3) For single well caissons with production equipment, use a letter 
designation for the facility name and a letter plus number designation 
for the well. For example, the Well No. 1 caisson would be designated as 
Facility A, and the well would be Well A-1.



Sec. 250.151  How do I name facilities in the Pacific Region?

    The operator assigns a name to the facility.



Sec. 250.152  How do I name facilities in the Alaska Region?

    Facilities will be named and identified according to the Regional 
Director's directions.

[[Page 68]]



Sec. 250.153  Do I have to rename an existing facility or well?

    You do not have to rename facilities installed and wells drilled 
before January 27, 2000, unless the Regional Director requires it.



Sec. 250.154  What identification signs must I display?

    (a) You must identify all facilities, artificial islands, and mobile 
offshore drilling units with a sign maintained in a legible condition.
    (1) You must display an identification sign that can be viewed from 
the waterline on at least one side of the platform. The sign must use at 
least 3-inch letters and figures.
    (2) When helicopter landing facilities are present, you must display 
an additional identification sign that is visible from the air. The sign 
must use at least 12-inch letters and figures and must also display the 
weight capacity of the helipad unless noted on the top of the helipad. 
If this sign is visible to both helicopter and boat traffic, then the 
sign in paragraph (a)(1) of this section is not required.
    (3) Your identification sign must:
    (i) List the name of the lessee or designated operator;
    (ii) In the GOM OCS Region, list the area designation or 
abbreviation and the block number of the facility location as depicted 
on OCS Official Protraction Diagrams or leasing maps;
    (iii) In the Pacific OCS Region, list the lease number on which the 
facility is located; and
    (iv) List the name of the platform, structure, artificial island, or 
mobile offshore drilling unit.
    (b) You must identify singly completed wells and multiple 
completions as follows:
    (1) For each singly completed well, list the lease number and well 
number on the wellhead or on a sign affixed to the wellhead;
    (2) For wells with multiple completions, downhole splitter wells, 
and multilateral wells, identify each completion in addition to the well 
name and lease number individually on the well flowline at the wellhead; 
and
    (3) For subsea wells that flow individually into separate pipelines, 
affix the required sign on the pipeline or surface flowline dedicated to 
that subsea well at a convenient location on the receiving platform. For 
multiple subsea wells that flow into a common pipeline or pipelines, no 
sign is required.



Secs. 250.160-250.167  [Reserved]

                               Suspensions



Sec. 250.168  May operations or production be suspended?

    (a) You may request approval of a suspension, or the Regional 
Supervisor may direct a suspension (Directed Suspension), for all or any 
part of a lease or unit area.
    (b) Depending on the nature of the suspended activity, suspensions 
are labeled either Suspensions of Operations (SOO) or Suspensions of 
Production (SOP).



Sec. 250.169  What effect does suspension have on my lease?

    (a) A suspension may extend the term of a lease (see 
Sec. 250.180(b), (d), and (e)). The extension is equal to the length of 
time the suspension is in effect, except as provided in paragraph (b) of 
this section.
    (b) A Directed Suspension does not extend the term of a lease when 
the Regional Supervisor directs a suspension because of:
    (1) Gross negligence; or
    (2) A willful violation of a provision of the lease or governing 
statutes and regulations.



Sec. 250.170  How long does a suspension last?

    (a) BSEE may issue suspensions for up to 5 years per suspension. The 
Regional Supervisor will set the length of the suspension based on the 
conditions of the individual case involved. BSEE may grant consecutive 
suspension periods.
    (b) An SOO ends automatically when the suspended operation 
commences.
    (c) An SOP ends automatically when production begins.
    (d) A Directed Suspension normally ends as specified in the letter 
directing the suspension.
    (e) BSEE may terminate any suspension when the Regional Supervisor 
determines the circumstances that justified the suspension no longer 
exist or

[[Page 69]]

that other lease conditions warrant termination. The Regional Supervisor 
will notify you of the reasons for termination and the effective date.



Sec. 250.171  How do I request a suspension?

    You must submit your request for a suspension to the Regional 
Supervisor, and BSEE must receive the request before the end of the 
lease term (i.e., end of primary term, end of the 1-year period 
following the last leaseholding operation, and end of a current 
suspension). Your request must include:
    (a) The justification for the suspension including the length of 
suspension requested;
    (b) A reasonable schedule of work leading to the commencement or 
restoration of the suspended activity;
    (c) A statement that a well has been drilled on the lease and 
determined to be producible according to Sec. 250.1603 (SOP only), 30 
CFR 550.115, or 30 CFR 550.116;
    (d) A commitment to production (SOP only); and
    (e) The service fee listed in Sec. 250.125 of this subpart.

[76 FR 64462, Oct. 18, 2011, as amended at 82 FR 26744, June 9, 2017]



Sec. 250.172  When may the Regional Supervisor grant or direct 
an SOO or SOP?

    The Regional Supervisor may grant or direct an SOO or SOP under any 
of the following circumstances:
    (a) When necessary to comply with judicial decrees prohibiting any 
activities or the permitting of those activities. The effective date of 
the suspension will be the effective date required by the action of the 
court;
    (b) When activities pose a threat of serious, irreparable, or 
immediate harm or damage. This would include a threat to life (including 
fish and other aquatic life), property, any mineral deposit, or the 
marine, coastal, or human environment. BSEE may require you to do a 
site-specific study (see Sec. 250.177(a)).
    (c) When necessary for the installation of safety or environmental 
protection equipment;
    (d) When necessary to carry out the requirements of NEPA or to 
conduct an environmental analysis; or
    (e) When necessary to allow for inordinate delays encountered in 
obtaining required permits or consents, including administrative or 
judicial challenges or appeals.



Sec. 250.173  When may the Regional Supervisor direct an SOO or SOP?

    The Regional Supervisor may direct a suspension when:
    (a) You failed to comply with an applicable law, regulation, order, 
or provision of a lease or permit; or
    (b) The suspension is in the interest of National security or 
defense.



Sec. 250.174  When may the Regional Supervisor grant or direct an SOP?

    The Regional Supervisor may grant or direct an SOP when the 
suspension is in the National interest, and it is necessary because the 
suspension will meet one of the following criteria:
    (a) It will allow you to properly develop a lease, including time to 
construct and install production facilities;
    (b) It will allow you time to obtain adequate transportation 
facilities;
    (c) It will allow you time to enter a sales contract for oil, gas, 
or sulphur. You must show that you are making an effort to enter into 
the contract(s); or
    (d) It will avoid continued operations that would result in 
premature abandonment of a producing well(s).



Sec. 250.175  When may the Regional Supervisor grant an SOO?

    (a) The Regional Supervisor may grant an SOO when necessary to allow 
you time to begin drilling or other operations when you are prevented by 
reasons beyond your control, such as unexpected weather, unavoidable 
accidents, or drilling rig delays.
    (b) The Regional Supervisor may grant an SOO when all of the 
following conditions are met:
    (1) The lease was issued with a primary lease term of 5 years, or 
with a primary term of 8 years with a requirement to drill within 5 
years;
    (2) Before the end of the third year of the primary term, you or 
your predecessor in interest must have acquired and interpreted 
geophysical information that indicates:
    (i) The presence of a salt sheet;

[[Page 70]]

    (ii) That all or a portion of a potential hydrocarbon-bearing 
formation may lie beneath or adjacent to the salt sheet; and
    (iii) The salt sheet interferes with identification of the potential 
hydrocarbon-bearing formation.
    (3) The interpreted geophysical information required under paragraph 
(b)(2) of this section must include full 3-D depth migration beneath the 
salt sheet and over the entire lease area.
    (4) Before requesting the suspension, you have conducted or are 
conducting additional data processing or interpretation of the 
geophysical information with the objective of identifying a potential 
hydrocarbon-bearing formation.
    (5) You demonstrate that additional time is necessary to:
    (i) Complete current processing or interpretation of existing 
geophysical data or information;
    (ii) Acquire, process, or interpret new geophysical data or 
information; or
    (iii) Drill into the potential hydrocarbon-bearing formation 
identified as a result of the activities conducted in paragraphs (b)(2), 
(b)(4), and (b)(5) of this section.
    (c) The Regional Supervisor may grant an SOO to conduct additional 
geological and geophysical data analysis that may lead to the drilling 
of a well below 25,000 feet true vertical depth below the datum at mean 
sea level (TVD SS) when all of the following conditions are met:
    (1) The lease was issued with a primary lease term of:
    (i) Five years; or
    (ii) Eight years with a requirement to drill within 5 years.
    (2) Before the end of the fifth year of the primary term, you or 
your predecessor in interest must have acquired and interpreted 
geophysical information that:
    (i) Indicates that all or a portion of a potential hydrocarbon-
bearing formation lies below 25,000 feet TVD SS; and
    (ii) Includes full 3-D depth migration over the entire lease area.
    (3) Before requesting the suspension, you have conducted or are 
conducting additional data processing or interpretation of the 
geophysical information with the objective of identifying a potential 
hydrocarbon-bearing geologic structure or stratigraphic trap lying below 
25,000 feet TVD SS.
    (4) You demonstrate that additional time is necessary to:
    (i) Complete current processing or interpretation of existing 
geophysical data or information;
    (ii) Acquire, process, or interpret new geophysical or geological 
data or information that would affect the decision to drill the same 
geologic structure or stratigraphic trap, as determined by the Regional 
Supervisor, identified in paragraphs (c)(2) and (c)(3) of this section; 
or
    (iii) Drill a well below 25,000 feet TVD SS into the geologic 
structure or stratigraphic trap identified as a result of the activities 
conducted in paragraphs (c)(2), (c)(3), and (c)(4)(i) and (ii) of this 
section.



Sec. 250.176  Does a suspension affect my royalty payment?

    A directed suspension may affect the payment of rental or royalties 
for the lease as provided in 30 CFR 1218.154.



Sec. 250.177  What additional requirements may the Regional Supervisor
order for a suspension?

    If BSEE grants or directs a suspension under paragraph 
Sec. 250.172(b), the Regional Supervisor may require you to:
    (a) Conduct a site-specific study.
    (1) The Regional Supervisor must approve or prescribe the scope for 
any site-specific study that you perform.
    (2) The study must evaluate the cause of the hazard, the potential 
damage, and the available mitigation measures.
    (3) You must pay for the study unless you request, and the Regional 
Supervisor agrees to arrange, payment by another party.
    (4) You must furnish copies and results of the study to the Regional 
Supervisor.
    (5) BSEE will make the results available to other interested parties 
and to the public.
    (6) The Regional Supervisor will use the results of the study and 
any other information that becomes available:
    (i) To decide if the suspension can be lifted; and

[[Page 71]]

    (ii) To determine any actions that you must take to mitigate or 
avoid any damage to the environment, life, or property.
    (b) Submit a revised Exploration Plan (including any required 
mitigating measures);
    (c) Submit a revised Development and Production Plan (including any 
required mitigating measures); or
    (d) Submit a revised Development Operations Coordination Document 
according to 30 CFR part 550, subpart B.

      Primary Lease Requirements, Lease Term Extensions, and Lease 
                              Cancellations



Sec. 250.180  What am I required to do to keep my lease term 
in effect?

    (a) If your lease is in its primary term:
    (1) You must submit a report to the District Manager according to 
paragraphs (h) and (i) of this section whenever production begins 
initially, whenever production ceases during the last year of the 
primary term, and whenever production resumes during the last year of 
the primary term.
    (2) Your lease expires at the end of its primary term unless you are 
conducting operations on your lease (see 30 CFR part 556). For purposes 
of this section, the term operations means, drilling, well-reworking, or 
production in paying quantities. The objective of the drilling or well-
reworking must be to establish production in paying quantities on the 
lease.
    (b) If you stop conducting operations during the last year of your 
primary lease term, your lease will expire unless you either resume 
operations or receive an SOO or an SOP from the Regional Supervisor 
under Sec. 250.172, Sec. 250.173, Sec. 250.174, or Sec. 250.175 before 
the end of the year after you stop operations.
    (c) If you extend your lease term under paragraph (b) of this 
section, you must pay rental or minimum royalty, as appropriate, for 
each year or part of the year during which your lease continues in force 
beyond the end of the primary lease term.
    (d) If you stop conducting operations on a lease that has continued 
beyond its primary term, your lease will expire unless you resume 
operations or receive an SOO or an SOP from the Regional Supervisor 
under Sec. 250.172, Sec. 250.173, Sec. 250.174, or Sec. 250.175 before 
the end of the year after you stop operations.
    (e) You may ask the Regional Supervisor to allow you more than a 
year to resume operations on a lease continued beyond its primary term 
when operating conditions warrant. The request must be in writing and 
explain the operating conditions that warrant a longer period. In 
allowing additional time, the Regional Supervisor must determine that 
the longer period is in the National interest, and it conserves 
resources, prevents waste, or protects correlative rights.
    (f) When you begin conducting operations on a lease that has 
continued beyond its primary term, you must immediately notify the 
District Manager either orally or by fax or e-mail and follow up with a 
written report according to paragraph (g) of this section.
    (g) If your lease is continued beyond its primary term, you must 
submit a report to the District Manager under paragraphs (h) and (i) of 
this section whenever production begins initially, whenever production 
ceases, whenever production resumes before the end of the 1-year period 
after having ceased, or whenever drilling or well-reworking operations 
begin before the end of the 1-year period.
    (h) The reports required by paragraphs (a) and (g) of this section 
must contain:
    (1) Name of lessee or operator;
    (2) The well number, lease number, area, and block;
    (3) As appropriate, the unit agreement name and number; and
    (4) A description of the operation and pertinent dates.
    (i) You must submit the reports required by paragraphs (a) and (g) 
of this section within the following timeframes:
    (1) Initialization of production--within 5 days of initial 
production.
    (2) Cessation of production--within 15 days after the first full 
month of zero production.
    (3) Resumption of production--within 5 days of resuming production 
after

[[Page 72]]

ceasing production under paragraph (i)(2) of this section.
    (4) Drilling or well reworking operations--within 5 days of 
beginning and completing the leaseholding operations.
    (j) For leases continued beyond the primary term, you must 
immediately report to the District Manager if operations do not begin 
before the end of the 1-year period.

[76 FR 64462, Oct. 18, 2011, as amended at 82 FR 26744, June 9, 2017]



Secs. 250.181-250.185  [Reserved]

                 Information and Reporting Requirements



Sec. 250.186  What reporting information and report forms must
I submit?

    (a) You must submit information and reports as BSEE requires.
    (1) You may obtain copies of forms from, and submit completed forms 
to, the District Manager or Regional Supervisor.
    (2) Instead of paper copies of forms available from the District 
Manager or Regional Supervisor, you may use your own computer-generated 
forms that are equal in size to BSEE's forms. You must arrange the data 
on your form identical to the BSEE form. If you generate your own form 
and it omits terms and conditions contained on the official BSEE form, 
we will consider it to contain the omitted terms and conditions.
    (3) You may submit digital data when the Region/District is equipped 
to accept it.
    (b) When BSEE specifies, you must include, for public information, 
an additional copy of such reports.
    (1) You must mark it Public Information
    (2) You must include all required information, except information 
exempt from public disclosure under Sec. 250.197 or otherwise exempt 
from public disclosure under law or regulation.



Sec. 250.187  What are BSEE's incident reporting requirements?

    (a) You must report all incidents listed in Sec. 250.188(a) and (b) 
to the District Manager. The specific reporting requirements for these 
incidents are contained in Secs. 250.189 and 250.190.
    (b) These reporting requirements apply to incidents that occur on 
the area covered by your lease, right-of-use and easement, pipeline 
right-of-way, or other permit issued by BOEM or BSEE, and that are 
related to operations resulting from the exercise of your rights under 
your lease, right-of-use and easement, pipeline right-of-way, or permit.
    (c) Nothing in this subpart relieves you from making notifications 
and reports of incidents that may be required by other regulatory 
agencies.
    (d) You must report all spills of oil or other liquid pollutants in 
accordance with 30 CFR 254.46.



Sec. 250.188  What incidents must I report to BSEE and when must
I report them?

    (a) You must report the following incidents to the District Manager 
immediately via oral communication, and provide a written follow-up 
report (hard copy or electronically transmitted) within 15 calendar days 
after the incident:
    (1) All fatalities.
    (2) All injuries that require the evacuation of the injured 
person(s) from the facility to shore or to another offshore facility.
    (3) All losses of well control. ``Loss of well control'' means:
    (i) Uncontrolled flow of formation or other fluids. The flow may be 
to an exposed formation (an underground blowout) or at the surface (a 
surface blowout);
    (ii) Flow through a diverter; or
    (iii) Uncontrolled flow resulting from a failure of surface 
equipment or procedures.
    (4) All fires and explosions.
    (5) All reportable releases of hydrogen sulfide (H2S) 
gas, as defined in Sec. 250.490(l).
    (6) All collisions that result in property or equipment damage 
greater than $25,000. ``Collision'' means the act of a moving vessel 
(including an aircraft) striking another vessel, or striking a 
stationary vessel or object (e.g., a boat striking a drilling rig or 
platform). ``Property or equipment damage'' means the cost of labor and 
material to

[[Page 73]]

restore all affected items to their condition before the damage, 
including, but not limited to, the OCS facility, a vessel, helicopter, 
or equipment. It does not include the cost of salvage, cleaning, gas-
freeing, dry docking, or demurrage.
    (7) All incidents involving structural damage to an OCS facility. 
``Structural damage'' means damage severe enough so that operations on 
the facility cannot continue until repairs are made.
    (8) All incidents involving crane or personnel/material handling 
operations.
    (9) All incidents that damage or disable safety systems or equipment 
(including firefighting systems).
    (b) You must provide a written report of the following incidents to 
the District Manager within 15 calendar days after the incident:
    (1) Any injuries that result in one or more days away from work or 
one or more days on restricted work or job transfer. One or more days 
means the injured person was not able to return to work or to all of 
their normal duties the day after the injury occurred;
    (2) All gas releases that initiate equipment or process shutdown;
    (3) All incidents that require operations personnel on the facility 
to muster for evacuation for reasons not related to weather or drills;
    (4) All other incidents, not listed in paragraph (a) of this 
section, resulting in property or equipment damage greater than $25,000.
    (c) On the Arctic OCS, in addition to the requirements of paragraphs 
(a) and (b) of this section, you must provide to the BSEE inspector on 
location, if one is present, or to the Regional Supervisor, both of the 
following:
    (1) An immediate oral report if any of the following occur:
    (i) Any sea ice movement or condition that has the potential to 
affect your operation or trigger ice management activities;
    (ii) The start and termination of ice management activities; or
    (iii) Any ``kicks'' or operational issues that are unexpected and 
could result in the loss of well control.
    (2) Within 24 hours after completing ice management activities, a 
written report of such activities that conforms to the content 
requirements in Sec. 250.190.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 46560, July 15, 2016]



Sec. 250.189  Reporting requirements for incidents requiring 
immediate notification.

    For an incident requiring immediate notification under 
Sec. 250.188(a), you must notify the District Manager via oral 
communication immediately after aiding the injured and stabilizing the 
situation. Your oral communication must provide the following 
information:
    (a) Date and time of occurrence;
    (b) Operator, and operator representative's, name and telephone 
number;
    (c) Contractor, and contractor representative's name and telephone 
number (if a contractor is involved in the incident or injury/fatality);
    (d) Lease number, OCS area, and block;
    (e) Platform/facility name and number, or pipeline segment number;
    (f) Type of incident or injury/fatality;
    (g) Operation or activity at time of incident (i.e., drilling, 
production, workover, completion, pipeline, crane, etc.); and
    (h) Description of the incident, damage, or injury/fatality.



Sec. 250.190  Reporting requirements for incidents requiring
written notification.

    (a) For any incident covered under Sec. 250.188, you must submit a 
written report within 15 calendar days after the incident to the 
District Manager. The report must contain the following information:
    (1) Date and time of occurrence;
    (2) Operator, and operator representative's name and telephone 
number;
    (3) Contractor, and contractor representative's name and telephone 
number (if a contractor is involved in the incident or injury);
    (4) Lease number, OCS area, and block;
    (5) Platform/facility name and number, or pipeline segment number;
    (6) Type of incident or injury;
    (7) Operation or activity at time of incident (i.e., drilling, 
production, workover, completion, pipeline, crane etc.);

[[Page 74]]

    (8) Description of incident, damage, or injury (including days away 
from work, restricted work or job transfer), and any corrective action 
taken; and
    (9) Property or equipment damage estimate (in U.S. dollars).
    (b) You may submit a report or form prepared for another agency in 
lieu of the written report required by paragraph (a) of this section, 
provided the report or form contains all required information.
    (c) The District Manager may require you to submit additional 
information about an incident on a case-by-case basis.



Sec. 250.191  How does BSEE conduct incident investigations?

    Any investigation that BSEE conducts under the authority of sections 
22(d)(1) and (2) of the Act (43 U.S.C. 1348(d)(1) and (2)) is a fact-
finding proceeding with no adverse parties. The purpose of the 
investigation is to prepare a public report that determines the cause or 
causes of the incident. The investigation may involve panel meetings 
conducted by a chairperson appointed by BSEE. The following requirements 
apply to any panel meetings involving persons giving testimony:
    (a) A person giving testimony may have legal or other 
representative(s) present to provide advice or counsel while the person 
is giving testimony. The chairperson may require a verbatim transcript 
to be made of all oral testimony. The chairperson also may accept a 
sworn written statement in lieu of oral testimony.
    (b) Only panel members, and any experts the panel deems necessary, 
may address questions to any person giving testimony.
    (c) The chairperson may issue subpoenas to persons to appear and 
provide testimony or documents at a panel meeting. A subpoena may not 
require a person to attend a panel meeting held at a location more than 
100 miles from where a subpoena is served.
    (d) Any person giving testimony may request compensation for 
mileage, and fees for services, within 90 days after the panel meeting. 
The compensated expenses must be similar to mileage and fees the U.S. 
District Courts allow.



Sec. 250.192  What reports and statistics must I submit relating
to a hurricane, earthquake, or other natural occurrence?

    (a) You must submit evacuation statistics to the Regional Supervisor 
for a natural occurrence, such as a hurricane, a tropical storm, or an 
earthquake. Statistics include facilities and rigs evacuated and the 
amount of production shut-in for gas and oil. You must:
    (1) Submit the statistics by fax or e-mail (for activities in the 
BSEE GOM OCS Region, use Form BSEE-0132) as soon as possible when 
evacuation occurs. In lieu of submitting your statistics by fax or e-
mail, you may submit them electronically in accordance with 30 CFR 
250.186(a)(3);
    (2) Submit the statistics on a daily basis by 11 a.m., as conditions 
allow, during the period of shut-in and evacuation;
    (3) Inform BSEE when you resume production; and
    (4) Submit the statistics either by BSEE district, or the total 
figures for your operations in a BSEE region.
    (b) If your facility, production equipment, or pipeline is damaged 
by a natural occurrence, you must:
    (1) Submit an initial damage report to the Regional Supervisor 
within 48 hours after you complete your initial evaluation of the 
damage. You must use Form BSEE-0143, Facility/Equipment Damage Report, 
to make this and all subsequent reports. In lieu of submitting Form 
BSEE-0143 by fax or e-mail, you may submit the damage report 
electronically in accordance with 30 CFR 250.186(a)(3). In the report, 
you must:
    (i) Name the items damaged (e.g., platform or other structure, 
production equipment, pipeline);
    (ii) Describe the damage and assess the extent of the damage (major, 
medium, minor); and
    (iii) Estimate the time it will take to replace or repair each 
damaged structure and piece of equipment and return it to service. The 
initial estimate need not be provided on the form until availability of 
hardware and repair capability has been established (not to exceed 30 
days from your initial report).

[[Page 75]]

    (2) Submit subsequent reports monthly and immediately whenever 
information submitted in previous reports changes until the damaged 
structure or equipment is returned to service. In the final report, you 
must provide the date the item was returned to service.



Sec. 250.193  Reports and investigations of possible violations.

    (a) Any person may report to BSEE any hazardous or unsafe working 
condition on any facility engaged in OCS activities, and any possible 
violation or failure to comply with:
    (1) Any provision of the Act,
    (2) Any provision of a lease, approved plan, or permit issued under 
the Act,
    (3) Any provision of any regulation or order issued under the Act, 
or
    (4) Any other Federal law relating to safety of offshore oil and gas 
operations.
    (b) To make a report under this section, a person is not required to 
know whether any legal requirement listed in paragraph (a) of this 
section has been violated.
    (c) When BSEE receives a report of a possible violation, or when a 
BSEE employee detects a possible violation, BSEE will investigate 
according to BSEE procedures and notify any other Federal agency(ies) 
for further investigation, as appropriate.
    (d) BSEE investigations of possible violations may include:
    (1) Conducting interviews of personnel;
    (2) Requiring the prompt production of documents, data, and other 
evidence;
    (3) Requiring the preservation of all relevant evidence and access 
for BSEE investigators to such evidence; and
    (4) Taking other actions and imposing other requirements as 
necessary to investigate possible violations and assure an orderly 
investigation.
    (e)(1) Reports should contain sufficient credible information to 
establish a reasonable basis for BSEE to investigate whether a violation 
or other hazardous or unsafe working condition exists.
    (2) To report hazardous or unsafe working conditions or a possible 
violation:
    (i) Contact BSEE by:
    (A) Phone at 1-877-440-0173 (BSEE Toll-free Safety Hotline),
    (B) Internet at www.bsee.gov, or
    (C) Mail to: U.S. DOI/BSEE, 1849 C Street NW., Mail Stop 5438, 
Washington, DC 20240 Attention: IRU Hotline Operations.
    (ii) Include the following items in the report:
    (A) Name, address, and telephone number should be provided if you do 
not want to remain anonymous;
    (B) The specific concern, provision or Federal law, if known, 
referenced in (a) that a person violated or with which a person failed 
to comply; and
    (C) Any other facts, data, and applicable information.
    (f) When a possible violation is reported, BSEE will protect a 
person's identity to the extent authorized by law.

[78 FR 20439, Apr. 5, 2013, as amended at 81 FR 36149, June 6, 2016]



Sec. 250.194  How must I protect archaeological resources?

    (a)-(b) [Reserved]
    (c) If you discover any archaeological resource while conducting 
operations in the lease or right-of-way area, you must immediately halt 
operations within the area of the discovery and report the discovery to 
the BSEE Regional Director. If investigations determine that the 
resource is significant, the Regional Director will tell you how to 
protect it.



Sec. 250.195  What notification does BSEE require on the production
status of wells?

    You must notify the appropriate BSEE District Manager when you 
successfully complete or recomplete a well for production. You must:
    (a) Notify the District Manager within 5 working days of placing the 
well in a production status. You must confirm oral notification by 
telefax or e-mail within those 5 working days.
    (b) Provide the following information in your notification:
    (1) Lessee or operator name;
    (2) Well number, lease number, and OCS area and block designations;
    (3) Date you placed the well on production (indicate whether or not 
this is first production on the lease);

[[Page 76]]

    (4) Type of production; and
    (5) Measured depth of the production interval.



Sec. 250.196  Reimbursements for reproduction and processing costs.

    (a) BSEE will reimburse you for costs of reproducing data and 
information that the Regional Director requests if:
    (1) You deliver geophysical and geological (G&G) data and 
information to BSEE for the Regional Director to inspect or select and 
retain;
    (2) BSEE receives your request for reimbursement and the Regional 
Director determines that the requested reimbursement is proper; and
    (3) The cost is at your lowest rate or at the lowest commercial rate 
established in the area, whichever is less.
    (b) BSEE will reimburse you for the costs of processing geophysical 
information (that does not include cost of data acquisition):
    (1) If, at the request of the Regional Director, you processed the 
geophysical data or information in a form or manner other than that used 
in the normal conduct of business; or
    (2) If you collected the information under a permit that BSEE issued 
to you before October 1, 1985, and the Regional Director requests and 
retains the information.
    (c) When you request reimbursement, you must identify reproduction 
and processing costs separately from acquisition costs.
    (d) BSEE will not reimburse you for data acquisition costs or for 
the costs of analyzing or processing geological information or 
interpreting geological or geophysical information.



Sec. 250.197  Data and information to be made available to the public
or for limited inspection.

    BSEE will protect data and information that you submit under this 
part, and 30 CFR part 203, as described in this section. Paragraphs (a) 
and (b) of this section describe what data and information will be made 
available to the public without the consent of the lessee, under what 
circumstances, and in what time period. Paragraph (c) of this section 
describes what data and information will be made available for limited 
inspection without the consent of the lessee, and under what 
circumstances.
    (a) All data and information you submit on BSEE forms will be made 
available to the public upon submission, except as specified in the 
following table:

------------------------------------------------------------------------
                              Data and information
                                 not immediately     Excepted data will
        On form . . .          available are . . .   be made available .
                                                             . .
------------------------------------------------------------------------
(1) BSEE-0123, Application    Items 15, 16, 22      When the well goes
 for Permit to Drill,          through 25,           on production or
                                                     according to the
                                                     table in paragraph
                                                     (b) of this
                                                     section, whichever
                                                     is earlier.
(2) BSEE-0123S, Supplemental  Items 3, 7, 8, 15     When the well goes
 APD Information Sheet,        and 17,               on production or
                                                     according to the
                                                     table in paragraph
                                                     (b) of this
                                                     section, whichever
                                                     is earlier.
(3) BSEE-0124, Application    Item 17,              When the well goes
 for Permit to Modify,                               on production or
                                                     according to the
                                                     table in paragraph
                                                     (b) of this
                                                     section, whichever
                                                     is earlier.
(4) BSEE-0125, End of         Items 12, 13, 17,     When the well goes
 Operations Report,            21, 22, 26 through    on production or
                               38,                   according to the
                                                     table in paragraph
                                                     (b) of this
                                                     section, whichever
                                                     is earlier.
                                                     However, items 33
                                                     through 38 will not
                                                     be released when
                                                     the well goes on
                                                     production unless
                                                     the period of time
                                                     in the table in
                                                     paragraph (b) has
                                                     expired.
(5) BSEE-0126, Well           Item 101,             2 years after you
 Potential Test Report,                              submit it.
(6) [Reserved]
(7) BSEE-0133 Well Activity   Item 10 Fields        When the well goes
 Report,                       [WELLBORE START       on production or
                               DATE, TD DATE, OP     according to the
                               STATUS, END DATE,     table in paragraph
                               MD, TVD, AND MW       (b) of this
                               PPG]. Item 11         section, whichever
                               Fields [WELLBORE      is earlier.
                               START DATE, TD
                               DATE, PLUGBACK
                               DATE, FINAL MD, AND
                               FINAL TVD] and
                               Items 12 through
                               15,
(8) BSEE-0133S Open Hole      Boxes 7 and 8,        When the well goes
 Data Report,                                        on production or
                                                     according to the
                                                     table in paragraph
                                                     (b) of this
                                                     section, whichever
                                                     is earlier.
(9) [Reserved]

[[Page 77]]

 
(10) [Reserved]
------------------------------------------------------------------------

    (b) BSEE will release lease and permit data and information that you 
submit and BSEE retains, but that are not normally submitted on BSEE 
forms, according to the following table:

------------------------------------------------------------------------
                                                             Special
     If . . .      BSEE will release   At this time . .   provisions . .
                         . . .                .                 .
------------------------------------------------------------------------
(1) The Director   Geophysical data,  At any time,       BSEE will
 determines that    Geological data                       release data
 data and           Interpreted G&G                       and
 information are    information,                          information
 needed for         Processed G&G                         only if
 specific           information,                          release would
 scientific or      Analyzed                              further the
 research           geological                            National
 purposes for the   information,                          interest
 Government,                                              without unduly
                                                          damaging the
                                                          competitive
                                                          position of
                                                          the lessee.
(2) Data or        Geophysical data,  60 days after      BSEE will
 information is     Geological data,   BSEE receives      release the
 collected with     Interpreted G&G    the data or        data and
 high-resolution    information,       information, if    information
 systems (e.g.,     Processed          the Regional       earlier than
 bathymetry, side-  geological         Supervisor deems   60 days if the
 scan sonar,        information,       it necessary,      Regional
 subbottom          Analyzed                              Supervisor
 profiler, and      geological                            determines it
 magnetometer) to   information,                          is needed by
 comply with                                              affected
 safety or                                                States to make
 environmental                                            decisions
 protection                                               under 30 CFR
 requirements,                                            550, subpart
                                                          B. The
                                                          Regional
                                                          Supervisor
                                                          will
                                                          reconsider
                                                          earlier
                                                          release if you
                                                          satisfy him/
                                                          her that it
                                                          would unduly
                                                          damage your
                                                          competitive
                                                          position.
(3) Your lease is  Geophysical data,  When your lease    This release
 no longer in       Geological data,   terminates,        time applies
 effect,            Processed G&G                         only if the
                    information                           provisions in
                    Interpreted G&G                       this table
                    information,                          governing high-
                    Analyzed                              resolution
                    geological                            systems and
                    information,                          the provisions
                                                          in 30 CFR
                                                          552.7 do not
                                                          apply. The
                                                          release time
                                                          applies to the
                                                          geophysical
                                                          data and
                                                          information
                                                          only if
                                                          acquired
                                                          postlease for
                                                          a lessee's
                                                          exclusive use.
(4) Your lease is  Geophysical data,  10 years after     This release
 still in effect,   Processed          you submit the     time applies
                    geophysical        data and           only if the
                    information,       information,       provisions in
                    Interpreted G&G                       this table
                    information,                          governing high-
                                                          resolution
                                                          systems and
                                                          the provisions
                                                          in 30 CFR
                                                          552.7 do not
                                                          apply. This
                                                          release time
                                                          applies to the
                                                          geophysical
                                                          data and
                                                          information
                                                          only if
                                                          acquired
                                                          postlease for
                                                          a lessee's
                                                          exclusive use.
(5) Your lease is  Geological data,   2 years after the  These release
 still in effect    Analyzed           required           times apply
 and within the     geological         submittal date     only if the
 primary term       information,       or 60 days after   provisions in
 specified in the                      a lease sale if    this table
 lease,                                any portion of     governing high-
                                       an offered lease   resolution
                                       is within 50       systems and
                                       miles of a well,   the provisions
                                       whichever is       in 30 CFR
                                       later,             552.7 do not
                                                          apply. If the
                                                          primary term
                                                          specified in
                                                          the lease is
                                                          extended under
                                                          the heading of
                                                          ``Suspensions'
                                                          ' in this
                                                          subpart, the
                                                          extension
                                                          applies to
                                                          this
                                                          provision.
(6) Your lease is  Geological data,   2 years after the  None.
 in effect and      Analyzed           required
 beyond the         geological         submittal date,
 primary term       information,
 specified in the
 lease,
(7) Data or        Descriptions of    When the well      Directional
 information is     downhole           goes on            survey data
 submitted on       locations,         production or      may be
 well operations,   operations, and    when geological    released
                    equipment,         data is released   earlier to the
                                       according to       owner of an
                                       Secs.  250.197(b   adjacent lease
                                       )(5) and (b)(6),   according to
                                       whichever occurs   Subpart D of
                                       earlier,           this part.

[[Page 78]]

 
(8) Data and       Any data or        At any time,       None.
 information are    information
 obtained from      obtained,
 beneath unleased
 land as a result
 of a well
 deviation that
 has not been
 approved by the
 District Manager
 or Regional
 Supervisor,
(9) Except for     G&G data,          Geological data    None.
 high-resolution    analyzed           and information:
 data and           geological         10 years after
 information        information,       BOEM issues the
 released under     processed and      permit;
 paragraph (b)(2)   interpreted G&G    Geophysical
 of this section    information,       data: 50 years
 data and                              after BOEM
 information                           issues the
 acquired by a                         permit;
 permit under 30                       Geophysical
 CFR part 551 are                      information: 25
 submitted by a                        years after BOEM
 lessee under 30                       issues the
 CFR part 203, 30                      permit,
 CFR part 250, or
 30 CFR part 550,
------------------------------------------------------------------------

    (c) BSEE may allow limited inspection, but only by persons with a 
direct interest in related BSEE decisions and issues in specific 
geographic areas, and who agree in writing to its confidentiality, of 
G&G data and information submitted under this part or 30 CFR part 203 
that BSEE uses to:
    (1) Make unitization determinations on two or more leases;
    (2) Make competitive reservoir determinations;
    (3) Ensure proper plans of development for competitive reservoirs;
    (4) Promote operational safety;
    (5) Protect the environment;
    (6) [Reserved]; or
    (7) Determine eligibility for royalty relief.

                               References



Sec. 250.198  Documents incorporated by reference.

    (a) The BSEE is incorporating by reference the documents listed in 
paragraphs (e) through (k) of this section. Paragraphs (e) through (k) 
identify the publishing organization of the documents, the address and 
phone number where you may obtain these documents, and the documents 
incorporated by reference. The Director of the Federal Register has 
approved the incorporations by reference according to 5 U.S.C. 552(a) 
and 1 CFR part 51.
    (1) Incorporation by reference of a document is limited to the 
edition of the publication that is cited in this section. Future 
amendments or revisions of the document are not included. The BSEE will 
publish any changes to a document in the Federal Register and amend this 
section.
    (2) The BSEE may make the rule amending the document effective 
without prior opportunity for public comment when BSEE determines:
    (i) That the revisions to a document result in safety improvements 
or represent new industry standard technology and do not impose undue 
costs on the affected parties; and
    (ii) The BSEE meets the requirements for making a rule immediately 
effective under 5 U.S.C. 553.
    (3) The effect of incorporation by reference of a document into the 
regulations in this part is that the incorporated document is a 
requirement. When a section in this part incorporates all of a document, 
you are responsible for complying with the provisions of that entire 
document, except to the extent that the section which incorporates the 
document by reference provides otherwise. When a section in this part 
incorporates part of a document, you are responsible for complying with 
that part of the document as provided in that section.
    (b) The BSEE incorporated each document or specific portion by 
reference in the sections noted. The entire document is incorporated by 
reference, unless the text of the corresponding sections in this part 
calls for compliance with specific portions of the listed documents. In 
each instance, the applicable document is the specific edition or 
specific edition and supplement or addendum cited in this section.
    (c) Under Secs. 250.141 and 250.142, you may comply with a later 
edition of a

[[Page 79]]

specific document incorporated by reference, provided:
    (1) You show that complying with the later edition provides a degree 
of protection, safety, or performance equal to or better than would be 
achieved by compliance with the listed edition; and
    (2) You obtain the prior written approval for alternative compliance 
from the authorized BSEE official.
    (d) You may inspect these documents at the Bureau of Safety and 
Environmental Enforcement, 45600 Woodland Rd, Sterling, VA 20166; phone: 
1-844-259-4779; or at the National Archives and Records Administration 
(NARA). For information on the availability of this material at NARA, 
call 202-741-6030, or go to: http://www.archives.gov/federal_register/
code_of_federal_regulations/ibr_locations.html.
    (e) American Concrete Institute (ACI), ACI Standards, 38800 Country 
Club Drive, Farmington Hills, MI 48331-3439: http://www.concrete.org; 
phone: 248-848-3700:
    (1) ACI Standard 318-95, Building Code Requirements for Reinforced 
Concrete (ACI 318-95), incorporated by reference at Sec. 250.901.
    (2) ACI 318R-95, Commentary on Building Code Requirements for 
Reinforced Concrete, incorporated by reference at Sec. 250.901.
    (3) ACI 357R-84, Guide for the Design and Construction of Fixed 
Offshore Concrete Structures, 1984; reapproved 1997, incorporated by 
reference at Sec. 250.901.
    (f) American Institute of Steel Construction, Inc. (AISC), AISC 
Standards, One East Wacker Drive, Suite 700, Chicago, IL 60601-1802; 
http://www.aisc.org; phone: 312-670-2400:
    (1) ANSI/AISC 360-05, Specification for Structural Steel Buildings 
incorporated by reference at Sec. 250.901.
    (2) [Reserved]
    (g) American National Standards Institute (ANSI), ANSI/ASME Codes, 
http://www.webstore.ansi.org; phone: 212-642-4900; and/or American 
Society of Mechanical Engineers (ASME), 22 Law Drive, P.O. Box 2900, 
Fairfield, NJ 07007-2900; http://www.asme.org; phone: 1-800-843-2763:
    (1) ANSI/ASME Boiler and Pressure Vessel Code, Section I, Rules for 
Construction of Power Boilers; including Appendices, 2004 Edition; and 
July 1, 2005 Addenda, and all Section I Interpretations Volume 55, 
incorporated by reference at Secs. 250.851(a) and 250.1629(b).
    (2) ANSI/ASME Boiler and Pressure Vessel Code, Section IV, Rules for 
Construction of Heating Boilers; including Appendices 1, 2, 3, 5, 6, and 
Non-mandatory Appendices B, C, D, E, F, H, I, K, L, and M, and the Guide 
to Manufacturers Data Report Forms, 2004 Edition; July 1, 2005 Addenda, 
and all Section IV Interpretations Volume 55, incorporated by reference 
at Secs. 250.851(a) and 250.1629(b).
    (3) ANSI/ASME Boiler and Pressure Vessel Code, Section VIII, Rules 
for Construction of Pressure Vessels; Divisions 1 and 2, 2004 Edition; 
July 1, 2005 Addenda, Divisions 1, 2, and 3 and all Section VIII 
Interpretations Volumes 54 and 55, incorporated by reference at 
Secs. 250.851(a) and 250.1629(b).
    (4) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings 
incorporated by reference at Sec. 250.1002;
    (5) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping 
Systems incorporated by reference at Sec. 250.1002;
    (6) ANSI Z88.2-1992, American National Standard for Respiratory 
Protection, incorporated by reference at, Sec. 250.490.
    (h) American Petroleum Institute (API), API Recommended Practices 
(RP), Specs, Standards, Manual of Petroleum Measurement Standards (MPMS) 
chapters, 1220 L Street, NW., Washington, DC 20005-4070; http://
www.api.org; phone: 202-682-8000:
    (1) API 510, Pressure Vessel Inspection Code: In-Service Inspection, 
Rating, Repair, and Alteration, Downstream Segment, Ninth Edition, June 
2006; incorporated by reference at Secs. 250.851(a) and 250.1629(b);
    (2) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore 
Structures for Hurricane Conditions, May 2007; incorporated by reference 
at Sec. 250.901;
    (3) API Bulletin 2INT-EX, Interim Guidance for Assessment of 
Existing Offshore Structures for Hurricane Conditions, May 2007; 
incorporated by reference at Sec. 250.901;

[[Page 80]]

    (4) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions 
in the Gulf of Mexico, May 2007; incorporated by reference at 
Sec. 250.901;
    (5) API MPMS, Chapter 1--Vocabulary, Second Edition, July 1994; 
incorporated by reference at Sec. 250.1201;
    (6) API MPMS, Chapter 2--Tank Calibration, Section 2A--Measurement 
and Calibration of Upright Cylindrical Tanks by the Manual Tank 
Strapping Method, First Edition, February 1995; reaffirmed February 
2007; incorporated by reference at Sec. 250.1202;
    (7) API MPMS, Chapter 2--Tank Calibration, Section 2B--Calibration 
of Upright Cylindrical Tanks Using the Optical Reference Line Method, 
First Edition, March 1989; reaffirmed, December 2007; incorporated by 
reference at Sec. 250.1202;
    (8) API MPMS, Chapter 3--Tank Gauging, Section 1A--Standard Practice 
for the Manual Gauging of Petroleum and Petroleum Products, Second 
Edition, August 2005; incorporated by reference at Sec. 250.1202;
    (9) API MPMS, Chapter 3--Tank Gauging, Section 1B--Standard Practice 
for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by 
Automatic Tank Gauging, Second Edition, June 2001, reaffirmed, October 
2006; incorporated by reference at Sec. 250.1202;
    (10) API MPMS, Chapter 4--Proving Systems, Section 1--Introduction, 
Third Edition, February 2005; incorporated by reference at 
Sec. 250.1202;
    (11) API MPMS, Chapter 4--Proving Systems, Section 2--Displacement 
Provers, Third Edition, September 2003; incorporated by reference at 
Sec. 250.1202;
    (12) API MPMS, Chapter 4--Proving Systems, Section 4--Tank Provers, 
Second Edition, May 1998, reaffirmed November 2005; incorporated by 
reference at Sec. 250.1202;
    (13) API MPMS, Chapter 4--Proving Systems, Section 5--Master-Meter 
Provers, Second Edition, May 2000, reaffirmed: August 2005; incorporated 
by reference at Sec. 250.1202;
    (14) API MPMS, Chapter 4--Proving Systems, Section 6--Pulse 
Interpolation, Second Edition, May 1999; reaffirmed 2003; incorporated 
by reference at Sec. 250.1202;
    (15) API MPMS, Chapter 4--Proving Systems, Section 7--Field Standard 
Test Measures, Second Edition, December 1998; reaffirmed 2003; 
incorporated by reference at Sec. 250.1202;
    (16) API MPMS, Chapter 5--Metering, Section 1--General 
Considerations for Measurement by Meters, Fourth Edition, September 
2005; incorporated by reference at Sec. 250.1202;
    (17) API MPMS, Chapter 5--Metering, Section 2--Measurement of Liquid 
Hydrocarbons by Displacement Meters, Third Edition, September 2005; 
incorporated by reference at Sec. 250.1202;
    (18) API MPMS Chapter 5--Metering, Section 3--Measurement of Liquid 
Hydrocarbons by Turbine Meters, Fifth Edition, September 2005; 
incorporated by reference at Sec. 250.1202;
    (19) API MPMS, Chapter 5--Metering, Section 4--Accessory Equipment 
for Liquid Meters, Fourth Edition, September 2005; incorporated by 
reference at Sec. 250.1202;
    (20) API MPMS, Chapter 5--Metering, Section 5--Fidelity and Security 
of Flow Measurement Pulsed-Data Transmission Systems, Second Edition, 
August 2005; incorporated by reference at Sec. 250.1202;
    (21) API MPMS, Chapter 6--Metering Assemblies, Section 1--Lease 
Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991; 
reaffirmed, April 2007; incorporated by reference at Sec. 250.1202;
    (22) API MPMS, Chapter 6--Metering Assemblies, Section 6--Pipeline 
Metering Systems, Second Edition, May 1991; reaffirmed, February 2007; 
incorporated by reference at Sec. 250.1202;
    (23) API MPMS, Chapter 6--Metering Assemblies, Section 7--Metering 
Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed, April 2007; 
incorporated by reference at Sec. 250.1202;
    (24) API MPMS, Chapter 7--Temperature Determination, First Edition, 
June 2001; reaffirmed, March 2007; incorporated by reference at 
Sec. 250.1202;
    (25) API MPMS, Chapter 8--Sampling, Section 1--Standard Practice for 
Manual Sampling of Petroleum and Petroleum Products, Third Edition, 
October 1995; reaffirmed, March 2006; incorporated by reference at 
Sec. 250.1202;
    (26) API MPMS, Chapter 8--Sampling, Section 2--Standard Practice for

[[Page 81]]

Automatic Sampling of Liquid Petroleum and Petroleum Products, Second 
Edition, October 1995; reaffirmed, June 2005; incorporated by reference 
at Sec. 250.1202;
    (27) API MPMS, Chapter 9--Density Determination, Section 1--Standard 
Test Method for Density, Relative Density (Specific Gravity), or API 
Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer 
Method, Second Edition, December 2002; reaffirmed October 2005; 
incorporated by reference at Sec. 250.1202(a)(3) and (l)(4);
    (28) API MPMS, Chapter 9--Density Determination, Section 2--Standard 
Test Method for Density or Relative Density of Light Hydrocarbons by 
Pressure Hydrometer, Second Edition, March 2003; incorporated by 
reference at Sec. 250.1202;
    (29) API MPMS, Chapter 10--Sediment and Water, Section 1--Standard 
Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction 
Method, Third Edition, November 2007; incorporated by reference at 
Sec. 250.1202;
    (30) API MPMS, Chapter 10--Sediment and Water, Section 2--Standard 
Test Method for Water in Crude Oil by Distillation, Second Edition, 
November 2007; incorporated by reference at Sec. 250.1202;
    (31) API MPMS, Chapter 10--Sediment and Water, Section 3--Standard 
Test Method for Water and Sediment in Crude Oil by the Centrifuge Method 
(Laboratory Procedure), Third Edition, May 2008; incorporated by 
reference at Sec. 250.1202;
    (32) API MPMS, Chapter 10--Sediment and Water, Section 4--
Determination of Water and/or Sediment in Crude Oil by the Centrifuge 
Method (Field Procedure), Third Edition, December 1999; incorporated by 
reference at Sec. 250.1202;
    (33) API MPMS, Chapter 10--Sediment and Water, Section 9--Standard 
Test Method for Water in Crude Oils by Coulometric Karl Fischer 
Titration, Second Edition, December 2002; reaffirmed 2005; incorporated 
by reference at Sec. 250.1202;
    (34) API MPMS, Chapter 11.1--Volume Correction Factors, Volume 1, 
Table 5A--Generalized Crude Oils and JP-4 Correction of Observed API 
Gravity to API Gravity at 60 F, and Table 6A--Generalized Crude Oils 
and JP-4 Correction of Volume to 60 F Against API Gravity at 60 F, API 
Standard 2540, First Edition, August 1980; reaffirmed March 1997; 
incorporated by reference at Sec. 250.1202;
    (35) API MPMS, Chapter 11.2.2--Compressibility Factors for 
Hydrocarbons: 0.350-0.637 Relative Density (60 F/60 F) and ^50 F to 
140 F Metering Temperature, Second Edition, October 1986; reaffirmed: 
December 2007; incorporated by reference at Sec. 250.1202;
    (36) API MPMS, Chapter 11--Physical Properties Data, Addendum to 
Section 2, Part 2--Compressibility Factors for Hydrocarbons, Correlation 
of Vapor Pressure for Commercial Natural Gas Liquids, First Edition, 
December 1994; reaffirmed, December 2002; incorporated by reference at 
Sec. 250.1202;
    (37) API MPMS, Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic Measurement 
Methods and Volumetric Correction Factors, Part 1--Introduction, Second 
Edition, May 1995; reaffirmed March 2002; incorporated by reference at 
Sec. 250.1202;
    (38) API MPMS, Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic Measurement 
Methods and Volumetric Correction Factors, Part 2--Measurement Tickets, 
Third Edition, June 2003; incorporated by reference at Sec. 250.1202;
    (39) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
3--Concentric, Square-Edged Orifice Meters, Part 1--General Equations 
and Uncertainty Guidelines, Third Edition, September 1990; reaffirmed 
January 2003; incorporated by reference at Sec. 250.1203;
    (40) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
3--Concentric, Square-Edged Orifice Meters, Part 2--Specification and 
Installation Requirements, Fourth Edition, April 2000; reaffirmed March 
2006; incorporated by reference at Sec. 250.1203;
    (41) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
3--Concentric, Square-Edged Orifice Meters; Part 3--Natural Gas 
Applications; Third Edition, August 1992; Errata March 1994, reaffirmed, 
February 2009; incorporated by reference at Sec. 250.1203;

[[Page 82]]

    (42) API MPMS, Chapter 14.5/GPA Standard 2172-09; Calculation of 
Gross Heating Value, Relative Density, Compressibility and Theoretical 
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody 
Transfer; Third Edition, January 2009; incorporated by reference at 
Sec. 250.1203;
    (43) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
6--Continuous Density Measurement, Second Edition, April 1991; 
reaffirmed, February 2006; incorporated by reference at Sec. 250.1203;
    (44) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
8--Liquefied Petroleum Gas Measurement, Second Edition, July 1997; 
reaffirmed, March 2006; incorporated by reference at Sec. 250.1203;
    (45) API MPMS, Chapter 20--Section 1--Allocation Measurement, First 
Edition, September 1993; reaffirmed October 2006; incorporated by 
reference at Sec. 250.1202;
    (46) API MPMS, Chapter 21--Flow Measurement Using Electronic 
Metering Systems, Section 1--Electronic Gas Measurement, First Edition, 
August 1993; reaffirmed, July 2005; incorporated by reference at 
Sec. 250.1203;
    (47) API RP 2A-WSD, Recommended Practice for Planning, Designing and 
Constructing Fixed Offshore Platforms--Working Stress Design, Twenty-
first Edition, December 2000; Errata and Supplement 1, December 2002; 
Errata and Supplement 2, September 2005; Errata and Supplement 3, 
October 2007; incorporated by reference at Secs. 250.901, 250.908, 
250.919, and 250.920;
    (48) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth 
Edition, May 2007; incorporated by reference at Sec. 250.108;
    (49) API RP 2FPS, RP for Planning, Designing, and Constructing 
Floating Production Systems; First Edition, March 2001; incorporated by 
reference at Sec. 250.901;
    (50) API RP 2I, In-Service Inspection of Mooring Hardware for 
Floating Structures; Third Edition, April 2008; incorporated by 
reference at Sec. 250.901(a) and (d);
    (51) API RP 2RD, Recommended Practice for Design of Risers for 
Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), 
First Edition, June 1998; reaffirmed, May 2006, Errata, June 2009; 
incorporated by reference at Secs. 250.292, 250.733, 250.800(c), 
250.901(a), (d), and 250.1002(b);
    (52) API RP 2SK, Recommended Practice for Design and Analysis of 
Stationkeeping Systems for Floating Structures, Third Edition, October 
2005, Addendum, May 2008; incorporated by reference at Secs. 250.800(c) 
and 250.901(a), (d);
    (53) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, First Edition, March 2001, Addendum, May 2007; incorporated by 
reference at Secs. 250.800(c) and 250.901;
    (54) API RP 2T, Recommended Practice for Planning, Designing, and 
Constructing Tension Leg Platforms, Second Edition, August 1997; 
incorporated by reference at Sec. 250.901;
    (55) ANSI/API RP 14B, Recommended Practice for Design, Installation, 
Repair and Operation of Subsurface Safety Valve Systems, Fifth Edition, 
October 2005; incorporated by reference at Secs. 250.802(b), 250.803(a), 
250.814(d), 250.828(c), and 250.880(c);
    (56) API RP 14C, Recommended Practice for Analysis, Design, 
Installation, and Testing of Basic Surface Safety Systems for Offshore 
Production Platforms, Seventh Edition, March 2001, Reaffirmed: March 
2007; incorporated by reference at Secs. 250.125(a), 250.292(j), 
250.841(a), 250.842(a), 250.850, 250.852(a), 250.855, 250.856(a), 
250.858(a), 250.862(e), 250.865(a), 250.867(a), 250.869(a) through (c), 
250.872(a), 250.873(a), 250.874(a), 250.880(b) and (c), 250.1002(d), 
250.1004(b), 250.1628(c) and (d), 250.1629(b), and 250.1630(a);
    (57) API RP 14E, Recommended Practice for Design and Installation of 
Offshore Production Platform Piping Systems, Fifth Edition, October 
1991; Reaffirmed, January 2013; incorporated by reference at 
Secs. 250.841(b), 250.842(a), and 250.1628(b) and (d);
    (58) API RP 14F, Recommended Practice for Design, Installation, and 
Maintenance of Electrical Systems for Fixed and Floating Offshore 
Petroleum Facilities for Unclassified and Class 1, Division 1 and 
Division 2 Locations, Upstream Segment, Fifth Edition, July

[[Page 83]]

2008, Reaffirmed: April 2013; incorporated by reference at 
Secs. 250.114(c), 250.842(b), 250.862(e), and 250.1629(b);
    (59) API RP 14FZ, Recommended Practice for Design and Installation 
of Electrical Systems for Fixed and Floating Offshore Petroleum 
Facilities for Unclassified and Class I, Zone 0, Zone 1 and Zone 2 
Locations, First Edition, September 2001, Reaffirmed: March 2007; 
incorporated by reference at Secs. 250.114(c), 250.842(b), 250.862(e), 
and 250.1629(b);
    (60) API RP 14G, Recommended Practice for Fire Prevention and 
Control on Fixed Open-type Offshore Production Platforms, Fourth 
Edition, April 2007; incorporated by reference at Secs. 250.859(a), 
250.862(e), 250.880(c), and 250.1629(b);
    (61) API RP 14H, Recommended Practice for Installation, Maintenance 
and Repair of Surface Safety Valves and Underwater Safety Valves 
Offshore, Fifth Edition, August 2007; incorporated by reference at 
Secs. 250.820, 250.834, 250.836, and 250.880(c);
    (62) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, Second Edition, May 2001; 
Reaffirmed: January 2013; incorporated by reference at Secs. 250.800(b) 
and (c), 250.842(b), and 250.901(a);
    (63) API Standard 53, Blowout Prevention Equipment Systems for 
Drilling Wells, Fourth Edition, November 2012, incorporated by reference 
at Secs. 250.730, 250.735, 250.737, and 250.739;
    (64) API RP 65, Recommended Practice for Cementing Shallow Water 
Flow Zones in Deepwater Wells, First Edition, September 2002; 
incorporated by reference at Sec. 250.415;
    (65) API RP 500, Recommended Practice for Classification of 
Locations for Electrical Installations at Petroleum Facilities 
Classified as Class I, Division 1 and Division 2, Second Edition, 
November 1997; Errata (August 17, 1998), Reaffirmed November 2002; 
incorporated by reference at Secs. 250.114(a), 250.459, 250.842(a), 
250.862(a) and (e), 250.872(a), 250.1628(b) and (d), and 250.1629(b);
    (66) API RP 505, Recommended Practice for Classification of 
Locations for Electrical Installations at Petroleum Facilities 
Classified as Class I, Zone 0, Zone 1, and Zone 2, First Edition, 
November 1997; Reaffirmed, August 2013; incorporated by reference at 
Secs. 250.114(a), 250.459, 250.842(a), 250.862(a) and (e), 250.872(a), 
250.1628(b) and (d), and 250.1629(b);
    (67) API RP 2556, Recommended Practice for Correcting Gauge Tables 
for Incrustation, Second Edition, August 1993; reaffirmed November 2003; 
incorporated by reference at Sec. 250.1202;
    (68) ANSI/API Specification Q1 (ANSI/API Spec. Q1), Specification 
for Quality Programs for the Petroleum, Petrochemical and Natural Gas 
Industry, Eighth Edition, December 2007, Addendum 1, June 2010; 
incorporated by reference at Secs. 250.730, 250.801(b) and (c);
    (69) API Spec. 2C, Specification for Offshore Pedestal Mounted 
Cranes, Sixth Edition, March 2004, Effective Date: September 2004; 
incorporated by reference at Sec. 250.108;
    (70) ANSI/API Specification 6A (ANSI/API Spec. 6A), Specification 
for Wellhead and Christmas Tree Equipment, Nineteenth Edition, July 
2004; Errata 1 (September 2004), Errata 2 (April 2005), Errata 3 (June 
2006) Errata 4 (August 2007), Errata 5 (May 2009), Addendum 1 (February 
2008), Addenda 2, 3, and 4 (December 2008); incorporated by reference at 
Secs. 250.730, 250.802(a), 250.803(a), 250.833, 250.873(b), 250.874(g), 
and 250.1002(b);
    (71) API Spec. 6AV1, Specification for Verification Test of Wellhead 
Surface Safety Valves and Underwater Safety Valves for Offshore Service, 
First Edition, February 1, 1996; reaffirmed April 2008; incorporated by 
reference at Secs. 250.802(a), 250.833, 250.873(b), and 250.874(g);
    (72) ANSI/API Spec. 6D, Specification for Pipeline Valves, Twenty-
third Edition, April 2008; Effective Date: October 1, 2008, Errata 1, 
June 2008; Errata 2, November 2008; Errata 3, February 2009; Addendum 1, 
October 2009; Contains API Monogram Annex as Part of U.S. National 
Adoption; ISO 14313:2007 (Identical), Petroleum and natural gas 
industries--Pipeline transportation systems--Pipeline valves; 
incorporated by reference at Sec. 250.1002;
    (73) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve 
Equipment, Eleventh Edition, October

[[Page 84]]

2005, Reaffirmed, June 2012; incorporated by reference at 
Secs. 250.802(b) and 250.803(a);
    (74) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe, 
Third Edition, July 2008, incorporated by reference at Secs. 250.852(e), 
250.1002(b), and 250.1007(a).
    (75) API Standard 2552, USA Standard Method for Measurement and 
Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed, 
October 2007; incorporated by reference at Sec. 250.1202;
    (76) API Standard 2555, Method for Liquid Calibration of Tanks, 
First Edition, September 1966; reaffirmed March 2002; incorporated by 
reference at Sec. 250.1202;
    (77) API RP 90, Annular Casing Pressure Management for Offshore 
Wells, First Edition, August 2006, incorporated by reference at 
Sec. 250.518;
    (78) API Standard 65--Part 2, Isolating Potential Flow Zones During 
Well Construction; Second Edition, December 2010; incorporated by 
reference at Sec. 250.415(f);
    (79) API RP 75, Recommended Practice for Development of a Safety and 
Environmental Management Program for Offshore Operations and Facilities, 
Third Edition, May 2004, Reaffirmed May 2008; incorporated by reference 
at Secs. 250.1900, 250.1902, 250.1903, 250.1909, 250.1920;
    (80) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
4--Proving Systems, Section 8--Operation of Proving Systems; First 
Edition, reaffirmed March 2007; incorporated by reference at 
Sec. 250.1202(a)(2), (a)(3), (f)(1), and (g);
    (81) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
5--Metering, Section 6--Measurement of Liquid Hydrocarbons by Coriolis 
Meters; First Edition, reaffirmed March 2008; incorporated by reference 
at Sec. 250.1202(a)(2) and (3);
    (82) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
5--Metering, Section 8--Measurement of Liquid Hydrocarbons by Ultrasonic 
Flow Meters Using Transit Time Technology; First Edition, February 2005; 
incorporated by reference at Sec. 250.1202(a)(2) and (3);
    (83) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
11--Physical Properties Data, Section 1--Temperature and Pressure Volume 
Correction Factors for Generalized Crude Oils, Refined Products, and 
Lubricating Oils; May 2004, (incorporating Addendum 1, September 2007); 
incorporated by reference at Sec. 250.1202(a)(2), (a)(3), (g), and 
(l)(4);
    (84) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
12--Calculation of Petroleum Quantities, Section 2--Calculation of 
Petroleum Quantities Using Dynamic Measurement Methods and Volumetric 
Correction Factors, Part 3--Proving Reports; First Edition, reaffirmed 
2009; incorporated by reference at Sec. 250.1202(a)(2), (a)(3), and (g);
    (85) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
12--Calculation of Petroleum Quantities, Section 2--Calculation of 
Petroleum Quantities Using Dynamic Measurement Methods and Volumetric 
Correction Factors, Part 4--Calculation of Base Prover Volumes by the 
Waterdraw Method, First Edition, reaffirmed 2009; incorporated by 
reference at Sec. 250.1202(a)(2), (a)(3), (f)(1), and (g);
    (86) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
21--Flow Measurement Using Electronic Metering Systems, Section 2--
Electronic Liquid Volume Measurement Using Positive Displacement and 
Turbine Meters; First Edition, June 1998; incorporated by reference at 
Sec. 250.1202(a)(2);
    (87) API Manual of Petroleum Measurement Standards Chapter 21--Flow 
Measurement Using Electronic Metering Systems, Addendum to Section 2--
Flow Measurement Using Electronic Metering Systems, Inferred Mass; First 
Edition, reaffirmed February 2006; incorporated by reference at 
Sec. 250.1202(a)(2);
    (88) API RP 86, API Recommended Practice for Measurement of 
Multiphase Flow; First Edition, September 2005; incorporated by 
reference at Sec. 250.1202(a)(2), (a)(3), and Sec. 250.1203(b)(2);
    (89) ANSI/API Specification 11D1, Packers and Bridge Plugs, Second 
Edition, July 2009, incorporated by reference at Secs. 250.518, 250.619, 
and 250.1703;

[[Page 85]]

    (90) ANSI/API Specification 16A, Specification for Drill-through 
Equipment, Third Edition, June 2004, Reaffirmed August 2010, 
incorporated by reference at Sec. 250.730;
    (91) ANSI/API Specification 16C, Specification for Choke and Kill 
Systems, First Edition, January 1993, Reaffirmed July 2010; incorporated 
by reference at Sec. 250.730;
    (92) API Specification 16D, Specification for Control Systems for 
Drilling Well Control Equipment and Control Systems for Diverter 
Equipment, Second Edition, July 2004, Reaffirmed August 2013, 
incorporated by reference at Sec. 250.730;
    (93) ANSI/API Specification 17D, Design and Operation of Subsea 
Production Systems--Subsea Wellhead and Tree Equipment, Second Edition, 
May 2011, incorporated by reference at Sec. 250.730;
    (94) ANSI/API Recommended Practice 17H, Remotely Operated Vehicle 
Interfaces on Subsea Production Systems, First Edition, July 2004, 
Reaffirmed January 2009, incorporated by reference at Sec. 250.734;
    (95) ANSI/API RP 2N, Third Edition, ``Recommended Practice for 
Planning, Designing, and Constructing Structures and Pipelines for 
Arctic Conditions'', Third Edition, April 2015; incorporated by 
reference at Sec. 250.470(g); and
    (96) API 570 Piping Inspection Code: In-service Inspection, Rating, 
Repair, and Alteration of Piping Systems, Third Edition, November 2009; 
incorporated by reference at Sec. 250.841(b).
    (i) American Society for Testing and Materials (ASTM), ASTM 
Standards, 100 Bar Harbor Drive, P.O. Box C700, West Conshohocken, PA 
19428-2959; http://www.astm.org; phone: 1-877-909-2786:
    (1) ASTM Standard C 33-07, approved December 15, 2007, Standard 
Specification for Concrete Aggregates; incorporated by reference at 
Sec. 250.901;
    (2) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard 
Specification for Ready-Mixed Concrete; incorporated by reference at 
Sec. 250.901;
    (3) ASTM Standard C 150-07, approved May 1, 2007, Standard 
Specification for Portland Cement; incorporated by reference at 
Sec. 250.901;
    (4) ASTM Standard C 330-05, approved December 15, 2005, Standard 
Specification for Lightweight Aggregates for Structural Concrete; 
incorporated by reference at Sec. 250.901;
    (5) ASTM Standard C 595-08, approved January 1, 2008, Standard 
Specification for Blended Hydraulic Cements; incorporated by reference 
at Sec. 250.901;
    (j) American Welding Society (AWS), AWS Codes, 8669 NW 36 Street, 
#130, Miami, FL 33126; http://www.aws.org; phone: 800-443-9353:
    (1) AWS D1.1:2000, Structural Welding Code--Steel, 17th Edition, 
October 18, 1999; incorporated by reference at Sec. 250.901;
    (2) AWS D1.4-98, Structural Welding Code--Reinforcing Steel, 1998 
Edition; incorporated by reference at Sec. 250.901;
    (3) AWS D3.6M:1999, Specification for Underwater Welding (1999); 
incorporated by reference at Sec. 250.901.
    (k) National Association of Corrosion Engineers (NACE) 
International, NACE Standards, Park Ten Place, Houston, TX 77084; http:/
/www.nace.org; phone: 281-228-6200:
    (1) NACE Standard MR0175-2003, Standard Material Requirements, 
Metals for Sulfide Stress Cracking and Stress Corrosion Cracking 
Resistance in Sour Oilfield Environments, Revised January 17, 2003; 
incorporated by reference at Secs. 250.901 and 250.490;
    (2) NACE Standard RP0176-2003, Standard Recommended Practice, 
Corrosion Control of Steel Fixed Offshore Structures Associated with 
Petroleum Production; incorporated by reference at Sec. 250.901.
    (l) American Gas Association (AGA Reports), 400 North Capitol 
Street, NW., Suite 450, Washington, DC 20001, http://www.aga.org; phone: 
202-824-7000;
    (1) AGA Report No. 7--Measurement of Natural Gas by Turbine Meters; 
Revised February 2006; incorporated by reference at Sec. 250.1203(b)(2);
    (2) AGA Report No. 9--Measurement of Gas by Multipath Ultrasonic 
Meters; Second Edition, April 2007; incorporated by reference at 
Sec. 250.1203(b)(2);
    (3) AGA Report No. 10--Speed of Sound in Natural Gas and Other 
Related Hydrocarbon Gases; Copyright 2003; incorporated by reference at 
Sec. 250.1203(b)(2).

[[Page 86]]

    (m) International Organization for Standardization (ISO), 1, ch. de 
la Voie-Creuse, CP 56, CH-1211, Geneva 20, Switzerland; www.iso.org; 
phone: 41-22-749-01-11:
    (1) ISO/IEC (International Electrotechnical Commission) 17011, 
Conformity assessment--General requirements for accreditation bodies 
accrediting conformity assessment bodies, First edition 2004-09-01; 
Corrected version 2005-02-15; incorporated by reference at 
Secs. 250.1900, 250.1903, 250.1904, and 250.1922.
    (2) [Reserved]
    (n) Center for Offshore Safety (COS), 1990 Post Oak Blvd., Suite 
1370, Houston, TX 77056; www.centerforoffshoresafety.org; phone: 832-
495-4925.
    (1) COS Safety Publication COS-2-01, Qualification and Competence 
Requirements for Audit Teams and Auditors Performing Third-party SEMS 
Audits of Deepwater Operations, First Edition, Effective Date October 
2012; incorporated by reference at Secs. 250.1900, 250.1903, 250.1904, 
and 250.1921.
    (2) COS Safety Publication COS-2-03, Requirements for Third-party 
SEMS Auditing and Certification of Deepwater Operations, First Edition, 
Effective Date October 2012; incorporated by reference at 
Secs. 250.1900, 250.1903, 250.1904, and 250.1920.
    (3) COS Safety Publication COS-2-04, Requirements for Accreditation 
of Audit Service Providers Performing SEMS Audits and Certification of 
Deepwater Operations, First Edition, Effective Date October 2012; 
incorporated by reference at Secs. 250.1900, 250.1903, 250.1904, and 
250.1922.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 18921, Mar. 29, 2012; 
77 FR 50891, Aug. 22, 2012; 78 FR 20440, Apr. 5, 2013; 81 FR 26015, Apr. 
29, 2016; 81 FR 36149, June 6, 2016; 81 FR 46560, July 15, 2016; 81 FR 
61917, Sept. 7, 2016]



Sec. 250.199  Paperwork Reduction Act statements--information 
collection.

    (a) OMB has approved the information collection requirements in part 
250 under 44 U.S.C. 3501 et seq. The table in paragraph (e) of this 
section lists the subpart in the rule requiring the information and its 
title, provides the OMB control number, and summarizes the reasons for 
collecting the information and how BSEE uses the information. The 
associated BSEE forms required by this part are listed at the end of 
this table with the relevant information.
    (b) Respondents are OCS oil, gas, and sulphur lessees and operators. 
The requirement to respond to the information collections in this part 
is mandated under the Act (43 U.S.C. 1331 et seq.) and the Act's 
Amendments of 1978 (43 U.S.C. 1801 et seq.). Some responses are also 
required to obtain or retain a benefit or may be voluntary. Proprietary 
information will be protected under Sec. 250.197, Data and information 
to be made available to the public or for limited inspection; parts 30 
CFR Parts 251, 252; and the Freedom of Information Act (5 U.S.C. 552) 
and its implementing regulations at 43 CFR part 2.
    (c) The Paperwork Reduction Act of 1995 requires us to inform the 
public that an agency may not conduct or sponsor, and you are not 
required to respond to, a collection of information unless it displays a 
currently valid OMB control number.
    (d) Send comments regarding any aspect of the collections of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA 
20166.
    (e) BSEE is collecting this information for the reasons given in the 
following table:

------------------------------------------------------------------------
 30 CFR Subpart, title and/or BSEE Form   BSEE collects this information
            (OMB Control No.)                     and uses it to:
------------------------------------------------------------------------
(1) Subpart A, General (1014-0022),       (i) Determine that activities
 including Forms BSEE-0011, iSEE; BSEE-    on the OCS comply with
 0132, Evacuation Statistics; BSEE-0143,   statutory and regulatory
 Facility/Equipment Damage Report; BSEE-   requirements; are safe and
 1832, Notification of Incidents of        protect the environment; and
 Noncompliance.                            result in diligent
                                           development and production on
                                           OCS leases.
                                          (ii) Support the unproved and
                                           proved reserve estimation,
                                           resource assessment, and fair
                                           market value determinations.

[[Page 87]]

 
                                          (iii) Assess damage and
                                           project any disruption of oil
                                           and gas production from the
                                           OCS after a major natural
                                           occurrence.
(2) Subpart B, Plans and Information      Evaluate Deepwater Operations
 (1014-0024).                              Plans for compliance with
                                           statutory and regulatory
                                           requirements
(3) Subpart C, Pollution Prevention and   (i) Evaluate measures to
 Control (1014-0023).                      prevent unauthorized
                                           discharge of pollutants into
                                           the offshore waters.
                                          (ii) Ensure action is taken to
                                           control pollution.
(4) Subpart D, Oil and Gas and Drilling   (i) Evaluate the equipment and
 Operations (1014-0018), including Forms   procedures to be used in
 BSEE-0125, End of Operations Report;      drilling operations on the
 BSEE-0133, Well Activity Report; and      OCS.
 BSEE-0133S, Open Hole Data Report.
                                          (ii) Ensure that drilling
                                           operations meet statutory and
                                           regulatory requirements.
(5) Subpart E, Oil and Gas Well-          (i) Evaluate the equipment and
 Completion Operations (1014-0004).        procedures to be used in well-
                                           completion operations on the
                                           OCS.
                                          (ii) Ensure that well-
                                           completion operations meet
                                           statutory and regulatory
                                           requirements.
(6) Subpart F, Oil and Gas Well Workover  (i) Evaluate the equipment and
 Operations (1014-0001).                   procedures to be used during
                                           well-workover operations on
                                           the OCS.
                                          (ii) Ensure that well-workover
                                           operations meet statutory and
                                           regulatory requirements.
(7) Subpart G, Blowout Preventer Systems  (i) Evaluate the equipment and
 (1014-0028), including Form BSEE-0144,    procedures to be used during
 Rig Movement Notification Report.         well drilling, completion,
                                           workover, and abandonment
                                           operations on the OCS.
                                          (ii) Ensure that well
                                           operations meet statutory and
                                           regulatory requirements.
(8) Subpart H, Oil and Gas Production     (i) Evaluate the equipment and
 Safety Systems (1014-0003).               procedures that will be used
                                           during production operations
                                           on the OCS.
                                          (ii) Ensure that production
                                           operations meet statutory and
                                           regulatory requirements.
(9) Subpart I, Platforms and Structures   (i) Evaluate the design,
 (1014-0011).                              fabrication, and installation
                                           of platforms on the OCS.
                                          (ii) Ensure the structural
                                           integrity of platforms
                                           installed on the OCS.
(10) Subpart J, Pipelines and Pipeline    (i) Evaluate the design,
 Rights-of-Way (1014-0016), including      installation, and operation
 Form BSEE-0149, Assignment of Federal     of pipelines on the OCS.
 OCS Pipeline Right-of-Way Grant.
                                          (ii) Ensure that pipeline
                                           operations meet statutory and
                                           regulatory requirements.
(11) Subpart K, Oil and Gas Production    (i) Evaluate production rates
 Rates (1014-0019), including Forms BSEE-  for hydrocarbons produced on
 0126, Well Potential Test Report and      the OCS.
 BSEE-0128, Semiannual Well Test Report.
                                          (ii) Ensure economic
                                           maximization of ultimate
                                           hydrocarbon recovery.
(12) Subpart L, Oil and Gas Production    (i) Evaluate the measurement
 Measurement, Surface Commingling, and     of production, commingling of
 Security (1014-0002).                     hydrocarbons, and site
                                           security plans.
                                          (ii) Ensure that produced
                                           hydrocarbons are measured and
                                           commingled to provide for
                                           accurate royalty payments and
                                           security.
(13) Subpart M, Unitization (1014-0015).  (i) Evaluate the unitization
                                           of leases.
                                          (ii) Ensure that unitization
                                           prevents waste, conserves
                                           natural resources, and
                                           protects correlative rights.
(14) Subpart N, Remedies and Penalties..  (The requirements in subpart N
                                           are exempt from the Paperwork
                                           Reduction Act of 1995
                                           according to 5 CFR 1320.4).
(15) Subpart O, Well Control and          (i) Evaluate training program
 Production Safety Training (1014-0008).   curricula for OCS workers,
                                           course schedules, and
                                           attendance.
                                          (ii) Ensure that training
                                           programs are technically
                                           accurate and sufficient to
                                           meet statutory and regulatory
                                           requirements, and that
                                           workers are properly trained.
(16) Subpart P, Sulfur Operations (1014-  (i) Evaluate sulfur
 0006).                                    exploration and development
                                           operations on the OCS.
                                          (ii) Ensure that OCS sulfur
                                           operations meet statutory and
                                           regulatory requirements and
                                           will result in diligent
                                           development and production of
                                           sulfur leases.

[[Page 88]]

 
(17) Subpart Q, Decommissioning           Ensure that decommissioning
 Activities (1014-0010).                   activities, site clearance,
                                           and platform or pipeline
                                           removal are properly
                                           performed to meet statutory
                                           and regulatory requirements
                                           and do not conflict with
                                           other users of the OCS.
(18) Subpart S, Safety and Environmental  (i) Evaluate operators'
 Management Systems (1014-0017),           policies and procedures to
 including Form BSEE-0131, Performance     assure safety and
 Measures Data.                            environmental protection
                                           while conducting OCS
                                           operations (including those
                                           operations conducted by
                                           contractor and subcontractor
                                           personnel).
                                          (ii) Evaluate Performance
                                           Measures Data relating to
                                           risk and number of accidents,
                                           injuries, and oil spills
                                           during OCS activities.
(19) Application for Permit to Drill      (i) Evaluate and approve the
 (APD, Revised APD), Form BSEE-0123; and   adequacy of the equipment,
 Supplemental APD Information Sheet,       materials, and/or procedures
 Form BSEE-0123S, and all supporting       that the lessee or operator
 documentation (1014-0025).                plans to use during drilling.
                                          (ii) Ensure that applicable
                                           OCS operations meet statutory
                                           and regulatory requirements.
(20) Application for Permit to Modify     (i) Evaluate and approve the
 (APM), Form BSEE-0124, and supporting     adequacy of the equipment,
 documentation (1014-0026).                materials, and/or procedures
                                           that the lessee or operator
                                           plans to use during drilling
                                           and to evaluate well plan
                                           modifications and changes in
                                           major equipment.
                                          (ii) Ensure that applicable
                                           OCS operations meet statutory
                                           and regulatory requirements.
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26015, Apr. 29, 2016; 
81 FR 36149, June 6, 2016]



                     Subpart B_Plans and Information

                           General Information



Sec. 250.200  Definitions.

    Acronyms and terms used in this subpart have the following meanings:
    (a) Acronyms used frequently in this subpart are listed 
alphabetically below:
    BOEM means Bureau of Ocean Energy Management of the Department of 
the Interior.
    BSEE means Bureau of Safety and Environmental Enforcement of the 
Department of the Interior.
    CID means Conservation Information Document.
    CZMA means Coastal Zone Management Act.
    DOCD means Development Operations Coordination Document.
    DPP means Development and Production Plan.
    DWOP means Deepwater Operations Plan.
    EIA means Environmental Impact Analysis.
    EP means Exploration Plan.
    NPDES means National Pollutant Discharge Elimination System.
    NTL means Notice to Lessees and Operators.
    OCS means Outer Continental Shelf.
    (b) Terms used in this subpart are listed alphabetically below:
    Amendment means a change you make to an EP, DPP, or DOCD that is 
pending before BOEM for a decision (see 30 CFR 550.232(d) and 
550.267(d)).
    Modification means a change required by the Regional Supervisor to 
an EP, DPP, or DOCD (see 30 CFR 550.233(b)(2) and 550.270(b)(2)) that is 
pending before BOEM for a decision because the OCS plan is inconsistent 
with applicable requirements.
    New or unusual technology means equipment or procedures that:
    (1) Have not been used previously or extensively in a BSEE OCS 
Region;
    (2) Have not been used previously under the anticipated operating 
conditions; or
    (3) Have operating characteristics that are outside the performance 
parameters established by this part.
    Non-conventional production or completion technology includes, but 
is not limited to, floating production systems, tension leg platforms, 
spars, floating production, storage, and offloading systems, guyed 
towers, compliant towers,

[[Page 89]]

subsea manifolds, and other subsea production components that rely on a 
remote site or host facility for utility and well control services.
    Offshore vehicle means a vehicle that is capable of being driven on 
ice.
    Resubmitted OCS plan means an EP, DPP, or DOCD that contains changes 
you make to an OCS plan that BOEM has disapproved (see 30 CFR 
550.234(b), 550.272(a), and 550.273(b)).
    Revised OCS plan means an EP, DPP, or DOCD that proposes changes to 
an approved OCS plan, such as those in the location of a well or 
platform, type of drilling unit, or location of the onshore support base 
(see 30 CFR 550.283(a)).
    Supplemental OCS plan means an EP, DPP, or DOCD that proposes the 
addition to an approved OCS plan of an activity that requires approval 
of an application or permit (see 30 CFR 550.283(b)).



Sec. 250.201  What plans and information must I submit before I
conduct any activities on my lease or unit?

    (a) Plans and documents. Before you conduct the activities on your 
lease or unit listed in the following table, you must submit, and BSEE 
must approve, the listed plans and documents. Your plans and documents 
may cover one or more leases or units.

------------------------------------------------------------------------
    You must submit a(n) . . .                Before you . . .
------------------------------------------------------------------------
(1) [Reserved]
(2) [Reserved]
(3) [Reserved]
(4) Deepwater Operations Plan      Conduct post-drilling installation
 (DWOP),                            activities in any water depth
                                    associated with a development
                                    project that will involve the use of
                                    a non-conventional production or
                                    completion technology.
(5) [Reserved]
(6) [Reserved]
------------------------------------------------------------------------

    (b) Submitting additional information. On a case-by-case basis, the 
Regional Supervisor may require you to submit additional information if 
the Regional Supervisor determines that it is necessary to evaluate your 
proposed plan or document.
    (c) Limiting information. The Regional Director may limit the amount 
of information or analyses that you otherwise must provide in your 
proposed plan or document under this subpart when:
    (1) Sufficient applicable information or analysis is readily 
available to BSEE;
    (2) Other coastal or marine resources are not present or affected;
    (3) Other factors such as technological advances affect information 
needs; or
    (4) Information is not necessary or required for a State to 
determine consistency with their CZMA Plan.
    (d) Referencing. In preparing your proposed plan or document, you 
may reference information and data discussed in other plans or documents 
you previously submitted or that are otherwise readily available to 
BSEE.



Secs. 250.202-250.203  [Reserved]



Sec. 250.204  How must I protect the rights of the Federal 
government?

    (a) To protect the rights of the Federal government, you must 
either:
    (1) Drill and produce the wells that the Regional Supervisor 
determines are necessary to protect the Federal government from loss due 
to production on other leases or units or from adjacent lands under the 
jurisdiction of other entities (e.g., State and foreign governments); or
    (2) Pay a sum that the Regional Supervisor determines as adequate to 
compensate the Federal government for your failure to drill and produce 
any well.
    (b) Payment under paragraph (a)(2) of this section may constitute 
production in paying quantities for the purpose of extending the lease 
term.
    (c) You must complete and produce any penetrated hydrocarbon-bearing 
zone that the Regional Supervisor determines is necessary to conform to 
sound conservation practices.



Sec. 250.205  Are there special requirements if my well affects an
adjacent property?

    For wells that could intersect or drain an adjacent property, the 
Regional Supervisor may require special measures to protect the rights 
of the Federal government and objecting lessees or operators of adjacent 
leases or units.

[[Page 90]]

          Post-Approval Requirements for the EP, DPP, and DOCD



Sec. 250.282  Do I have to conduct post-approval monitoring?

    The Regional Supervisor may direct you to conduct monitoring 
programs. You must retain copies of all monitoring data obtained or 
derived from your monitoring programs and make them available to BSEE 
upon request. The Regional Supervisor may require you to:
    (a) Monitoring plans. Submit monitoring plans for approval before 
you begin work; and
    (b) Monitoring reports. Prepare and submit reports that summarize 
and analyze data and information obtained or derived from your 
monitoring programs. The Regional Supervisor will specify requirements 
for preparing and submitting these reports.

                    Deepwater Operations Plan (DWOP)



Sec. 250.286  What is a DWOP?

    (a) A DWOP is a plan that provides sufficient information for BSEE 
to review a deepwater development project, and any other project that 
uses non-conventional production or completion technology, from a total 
system approach. The DWOP does not replace, but supplements other 
submittals required by the regulations such as BOEM Exploration Plans, 
Development and Production Plans, and Development Operations 
Coordination Documents. BSEE will use the information in your DWOP to 
determine whether the project will be developed in an acceptable manner, 
particularly with respect to operational safety and environmental 
protection issues involved with non-conventional production or 
completion technology.
    (b) The DWOP process consists of two parts: a Conceptual Plan and 
the DWOP. Section 250.289 prescribes what the Conceptual Plan must 
contain, and Sec. 250.292 prescribes what the DWOP must contain.



Sec. 250.287  For what development projects must I submit a DWOP?

    You must submit a DWOP for each development project in which you 
will use non-conventional production or completion technology, 
regardless of water depth. If you are unsure whether BSEE considers the 
technology of your project non-conventional, you must contact the 
Regional Supervisor for guidance.



Sec. 250.288  When and how must I submit the Conceptual Plan?

    You must submit four copies, or one hard copy and one electronic 
version, of the Conceptual Plan to the Regional Director after you have 
decided on the general concept(s) for development and before you begin 
engineering design of the well safety control system or subsea 
production systems to be used after well completion.



Sec. 250.289  What must the Conceptual Plan contain?

    In the Conceptual Plan, you must explain the general design basis 
and philosophy that you will use to develop the field. You must include 
the following information:
    (a) An overview of the development concept(s);
    (b) A well location plat;
    (c) The system control type (i.e., direct hydraulic or electro-
hydraulic); and
    (d) The distance from each of the wells to the host platform.



Sec. 250.290  What operations require approval of the Conceptual Plan?

    You may not complete any production well or install the subsea 
wellhead and well safety control system (often called the tree) before 
BSEE has approved the Conceptual Plan.



Sec. 250.291  When and how must I submit the DWOP?

    You must submit four copies, or one hard copy and one electronic 
version, of the DWOP to the Regional Director after you have 
substantially completed safety system design and before you begin to 
procure or fabricate the safety and operational systems (other than the 
tree), production platforms, pipelines, or other parts of the production 
system.

[[Page 91]]



Sec. 250.292  What must the DWOP contain?

    You must include the following information in your DWOP:
    (a) A description and schematic of the typical wellbore, casing, and 
completion;
    (b) Structural design, fabrication, and installation information for 
each surface system, including host facilities;
    (c) Design, fabrication, and installation information on the mooring 
systems for each surface system;
    (d) Information on any active stationkeeping system(s) involving 
thrusters or other means of propulsion used with a surface system;
    (e) Information concerning the drilling and completion systems;
    (f) Design and fabrication information for each riser system (e.g., 
drilling, workover, production, and injection);
    (g) Pipeline information;
    (h) Information about the design, fabrication, and operation of an 
offtake system for transferring produced hydrocarbons to a transport 
vessel;
    (i) Information about subsea wells and associated systems that 
constitute all or part of a single project development covered by the 
DWOP;
    (j) Flow schematics and Safety Analysis Function Evaluation (SAFE) 
charts (API RP 14C, subsection 4.3c, incorporated by reference in 
Sec. 250.198) of the production system from the Surface Controlled 
Subsurface Safety Valve (SCSSV) downstream to the first item of 
separation equipment;
    (k) A description of the surface/subsea safety system and emergency 
support systems to include a table that depicts what valves will close, 
at what times, and for what events or reasons;
    (l) A general description of the operating procedures, including a 
table summarizing the curtailment of production and offloading based on 
operational considerations;
    (m) A description of the facility installation and commissioning 
procedure;
    (n) A discussion of any new technology that affects hydrocarbon 
recovery systems;
    (o) A list of any alternate compliance procedures or departures for 
which you anticipate requesting approval;
    (p) If you propose to use a pipeline free standing hybrid riser 
(FSHR) on a permanent installation that utilizes a critical chain, wire 
rope, or synthetic tether to connect the top of the riser to a buoyancy 
air can, provide the following information in your DWOP in the 
discussions required by paragraphs (f) and (g) of this section:
    (1) A detailed description and drawings of the FSHR, buoy and the 
tether system;
    (2) Detailed information on the design, fabrication, and 
installation of the FSHR, buoy and tether system, including pressure 
ratings, fatigue life, and yield strengths;
    (3) A description of how you met the design requirements, load 
cases, and allowable stresses for each load case according to API RP 2RD 
(as incorporated by reference in Sec. 250.198);
    (4) Detailed information regarding the tether system used to connect 
the FSHR to a buoyancy air can;
    (5) Descriptions of your monitoring system and monitoring plan to 
monitor the pipeline FSHR and tether for fatigue, stress, and any other 
abnormal condition (e.g., corrosion) that may negatively impact the 
riser or tether; and
    (6) Documentation that the tether system and connection accessories 
for the pipeline FSHR have been certified by an approved classification 
society or equivalent and verified by the CVA required in subpart I of 
this part; and
    (q) Payment of the service fee listed in Sec. 250.125.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26017, Apr. 29, 2016]



Sec. 250.293  What operations require approval of the DWOP?

    You may not begin production until BSEE approves your DWOP.



Sec. 250.294  May I combine the Conceptual Plan and the DWOP?

    If your development project meets the following criteria, you may 
submit a combined Conceptual Plan/DWOP on or before the deadline for 
submitting the Conceptual Plan.

[[Page 92]]

    (a) The project is located in water depths of less than 400 meters 
(1,312 feet); and
    (b) The project is similar to projects involving non-conventional 
production or completion technology for which you have obtained approval 
previously.



Sec. 250.295  When must I revise my DWOP?

    You must revise either the Conceptual Plan or your DWOP to reflect 
changes in your development project that materially alter the 
facilities, equipment, and systems described in your plan. You must 
submit the revision within 60 days after any material change to the 
information required for that part of your plan.



               Subpart C_Pollution Prevention and Control



Sec. 250.300  Pollution prevention.

    (a) During the exploration, development, production, and 
transportation of oil and gas or sulphur, the lessee shall take measures 
to prevent unauthorized discharge of pollutants into the offshore 
waters. The lessee shall not create conditions that will pose 
unreasonable risk to public health, life, property, aquatic life, 
wildlife, recreation, navigation, commercial fishing, or other uses of 
the ocean.
    (1) When pollution occurs as a result of operations conducted by or 
on behalf of the lessee and the pollution damages or threatens to damage 
life (including fish and other aquatic life), property, any mineral 
deposits (in areas leased or not leased), or the marine, coastal, or 
human environment, the control and removal of the pollution to the 
satisfaction of the District Manager shall be at the expense of the 
lessee. Immediate corrective action shall be taken in all cases where 
pollution has occurred. Corrective action shall be subject to 
modification when directed by the District Manager.
    (2) If the lessee fails to control and remove the pollution, the 
Director, in cooperation with other appropriate Agencies of Federal, 
State, and local governments, or in cooperation with the lessee, or 
both, shall have the right to control and remove the pollution at the 
lessee's expense. Such action shall not relieve the lessee of any 
responsibility provided for by law.
    (b)(1) The District Manager may restrict the rate of drilling fluid 
discharges or prescribe alternative discharge methods. The District 
Manager may also restrict the use of components that could cause 
unreasonable degradation to the marine environment. No petroleum-based 
substances, including diesel fuel, may be added to the drilling mud 
system without prior approval of the District Manager. For Arctic OCS 
exploratory drilling, you must capture all petroleum-based mud to 
prevent its discharge into the marine environment. The Regional 
Supervisor may also require you to capture, during your Arctic OCS 
exploratory drilling operations, all water-based mud from operations 
after completion of the hole for the conductor casing to prevent its 
discharge into the marine environment, based on various factors 
including, but not limited to:
    (i) The proximity of your exploratory drilling operation to 
subsistence hunting and fishing locations;
    (ii) The extent to which discharged mud may cause marine mammals to 
alter their migratory patterns in a manner that impedes subsistence 
users' access to, or use of, those resources, or increases the risk of 
injury to subsistence users; or
    (iii) The extent to which discharged mud may adversely affect marine 
mammals, fish, or their habitat.
    (2) You must obtain approval from the District Manager of the method 
you plan to use to dispose of drill cuttings, sand, and other well 
solids. For Arctic OCS exploratory drilling, you must capture all 
cuttings from operations that utilize petroleum-based mud to prevent 
their discharge into the marine environment. The Regional Supervisor may 
also require you to capture, during your Arctic OCS exploratory drilling 
operations, all cuttings from operations that utilize water-based mud 
after completion of the hole for the conductor casing to prevent their 
discharge into the marine environment, based on various factors 
including, but not limited to:
    (i) The proximity of your exploratory drilling operation to 
subsistence hunting and fishing locations;

[[Page 93]]

    (ii) The extent to which discharged cuttings may cause marine 
mammals to alter their migratory patterns in a manner that impedes 
subsistence users' access to, or use of, those resources, or increases 
the risk of injury to subsistence users; or
    (iii) The extent to which discharged cuttings may adversely affect 
marine mammals, fish, or their habitat.
    (3) All hydrocarbon-handling equipment for testing and production 
such as separators, tanks, and treaters shall be designed, installed, 
and operated to prevent pollution. Maintenance or repairs which are 
necessary to prevent pollution of offshore waters shall be undertaken 
immediately.
    (4) Curbs, gutters, drip pans, and drains shall be installed in deck 
areas in a manner necessary to collect all contaminants not authorized 
for discharge. Oil drainage shall be piped to a properly designed, 
operated, and maintained sump system which will automatically maintain 
the oil at a level sufficient to prevent discharge of oil into offshore 
waters. All gravity drains shall be equipped with a water trap or other 
means to prevent gas in the sump system from escaping through the 
drains. Sump piles shall not be used as processing devices to treat or 
skim liquids but may be used to collect treated-produced water, treated-
produced sand, or liquids from drip pans and deck drains and as a final 
trap for hydrocarbon liquids in the event of equipment upsets. 
Improperly designed, operated, or maintained sump piles which do not 
prevent the discharge of oil into offshore waters shall be replaced or 
repaired.
    (5) On artificial islands, all vessels containing hydrocarbons shall 
be placed inside an impervious berm or otherwise protected to contain 
spills. Drainage shall be directed away from the drilling rig to a sump. 
Drains and sumps shall be constructed to prevent seepage.
    (6) Disposal of equipment, cables, chains, containers, or other 
materials into offshore waters is prohibited.
    (c) Materials, equipment, tools, containers, and other items used in 
the Outer Continental Shelf (OCS) which are of such shape or 
configuration that they are likely to snag or damage fishing devices 
shall be handled and marked as follows:
    (1) All loose material, small tools, and other small objects shall 
be kept in a suitable storage area or a marked container when not in use 
and in a marked container before transport over offshore waters;
    (2) All cable, chain, or wire segments shall be recovered after use 
and securely stored until suitable disposal is accomplished;
    (3) Skid-mounted equipment, portable containers, spools or reels, 
and drums shall be marked with the owner's name prior to use or 
transport over offshore waters; and
    (4) All markings must clearly identify the owner and must be durable 
enough to resist the effects of the environmental conditions to which 
they may be exposed.
    (d) Any of the items described in paragraph (c) of this section that 
are lost overboard shall be recorded on the facility's daily operations 
report, as appropriate, and reported to the District Manager.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 46560, July 15, 2016]



Sec. 250.301  Inspection of facilities.

    Drilling and production facilities shall be inspected daily or at 
intervals approved or prescribed by the District Manager to determine if 
pollution is occurring. Necessary maintenance or repairs shall be made 
immediately. Records of such inspections and repairs shall be maintained 
at the facility or at a nearby manned facility for 2 years.



                Subpart D_Oil and Gas Drilling Operations

                          General Requirements



Sec. 250.400  General requirements.

    Drilling operations must be conducted in a safe manner to protect 
against harm or damage to life (including fish and other aquatic life), 
property, natural resources of the Outer Continental Shelf (OCS), 
including any mineral deposits (in areas leased and not leased), the 
National security or defense, or the marine, coastal, or human 
environment. In addition to the requirements of this subpart, you must

[[Page 94]]

also follow the applicable requirements of subpart G of this part.

[81 FR 26017, Apr. 29, 2016]



Secs. 250.401-250.403  [Reserved]



Sec. 250.404  What are the requirements for the crown block?

    You must have a crown block safety device that prevents the 
traveling block from striking the crown block. You must check the device 
for proper operation at least once per week and after each drill-line 
slipping operation and record the results of this operational check in 
the driller's report.



Sec. 250.405  What are the safety requirements for diesel engines
used on a drilling rig?

    You must equip each diesel engine with an air intake device to shut 
down the diesel engine in the event of a runaway.
    (a) For a diesel engine that is not continuously manned, you must 
equip the engine with an automatic shutdown device;
    (b) For a diesel engine that is continuously manned, you may equip 
the engine with either an automatic or remote manual air intake shutdown 
device;
    (c) You do not have to equip a diesel engine with an air intake 
device if it meets one of the following criteria:
    (1) Starts a larger engine;
    (2) Powers a firewater pump;
    (3) Powers an emergency generator;
    (4) Powers a BOP accumulator system;
    (5) Provides air supply to divers or confined entry personnel;
    (6) Powers temporary equipment on a nonproducing platform;
    (7) Powers an escape capsule; or
    (8) Powers a portable single-cylinder rig washer.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36149, June 6, 2016]



Sec. 250.406  [Reserved]



Sec. 250.407  What tests must I conduct to determine reservoir
characteristics?

    You must determine the presence, quantity, quality, and reservoir 
characteristics of oil, gas, sulphur, and water in the formations 
penetrated by logging, formation sampling, or well testing.



Sec. 250.408  May I use alternative procedures or equipment during
drilling operations?

    You may use alternative procedures or equipment during drilling 
operations after receiving approval from the District Manager. You must 
identify and discuss your proposed alternative procedures or equipment 
in your Application for Permit to Drill (APD) (Form BSEE-0123) (see 
Sec. 250.414(h)). Procedures for obtaining approval are described in 
Sec. 250.141 of this part.



Sec. 250.409  May I obtain departures from these drilling
requirements?

    The District Manager may approve departures from the drilling 
requirements specified in this subpart. You may apply for a departure 
from drilling requirements by writing to the District Manager. You 
should identify and discuss the departure you are requesting in your APD 
(see Sec. 250.414(h)).

                     Applying for a Permit To Drill



Sec. 250.410  How do I obtain approval to drill a well?

    You must obtain written approval from the District Manager before 
you begin drilling any well or before you sidetrack, bypass, or deepen a 
well. To obtain approval, you must:
    (a) Submit the information required by Secs. 250.411 through 
250.418;
    (b) Include the well in your approved Exploration Plan (EP), 
Development and Production Plan (DPP), or Development Operations 
Coordination Document (DOCD);
    (c) Meet the oil spill financial responsibility requirements for 
offshore facilities as required by 30 CFR part 553; and
    (d) Submit the following to the District Manager:
    (1) An original and two complete copies of Form BSEE-0123, 
Application for Permit to Drill (APD), and Form BSEE-0123S, Supplemental 
APD Information Sheet;
    (2) A separate public information copy of forms BSEE-0123 and BSEE-
0123S that meets the requirements of Sec. 250.186; and

[[Page 95]]

    (3) Payment of the service fee listed in Sec. 250.125.



Sec. 250.411  What information must I submit with my application?

    In addition to forms BSEE-0123 and BSEE-0123S, you must include the 
information required in this subpart and subpart G of this part, 
including the following:

----------------------------------------------------------------------------------------------------------------
  Information that you must include with an APD                     Where to find a description
----------------------------------------------------------------------------------------------------------------
(a) Plat that shows locations of the proposed      Sec. 250.412.
 well,.
(b) Design criteria used for the proposed well,..  Sec. 250.413.
(c) Drilling prognosis,..........................  Sec. 250.414.
(d) Casing and cementing programs,...............  Sec. 250.415.
(e) Diverter systems descriptions,...............  Sec. 250.416.
(f) BOP system descriptions,.....................  Sec. 250.731.
(g) Requirements for using a MODU, and...........  Sec. 250.713.
(h) Additional information.......................  Sec. 250.418.
----------------------------------------------------------------------------------------------------------------


[81 FR 26017, Apr. 29, 2016]



Sec. 250.412  What requirements must the location plat meet?

    The location plat must:
    (a) Have a scale of 1:24,000 (1 inch = 2,000 feet);
    (b) Show the surface and subsurface locations of the proposed well 
and all the wells in the vicinity;
    (c) Show the surface and subsurface locations of the proposed well 
in feet or meters from the block line;
    (d) Contain the longitude and latitude coordinates, and either 
Universal Transverse Mercator grid-system coordinates or state plane 
coordinates in the Lambert or Transverse Mercator Projection system for 
the surface and subsurface locations of the proposed well; and
    (e) State the units and geodetic datum (including whether the datum 
is North American Datum 27 or 83) for these coordinates. If the datum 
was converted, you must state the method used for this conversion, since 
the various methods may produce different values.



Sec. 250.413  What must my description of well drilling design criteria
address?

    Your description of well drilling design criteria must address:
    (a) Pore pressures;
    (b) Formation fracture gradients, adjusted for water depth;
    (c) Potential lost circulation zones;
    (d) Drilling fluid weights;
    (e) Casing setting depths;
    (f) Maximum anticipated surface pressures. For this section, maximum 
anticipated surface pressures are the pressures that you reasonably 
expect to be exerted upon a casing string and its related wellhead 
equipment. In calculating maximum anticipated surface pressures, you 
must consider: drilling, completion, and producing conditions; drilling 
fluid densities to be used below various casing strings; fracture 
gradients of the exposed formations; casing setting depths; total well 
depth; formation fluid types; safety margins; and other pertinent 
conditions. You must include the calculations used to determine the 
pressures for the drilling and the completion phases, including the 
anticipated surface pressure used for designing the production string;
    (g) A single plot containing curves for estimated pore pressures, 
formation fracture gradients, proposed drilling fluid weights, planned 
safe drilling margin, and casing setting depths in true vertical 
measurements;
    (h) A summary report of the shallow hazards site survey that 
describes the geological and manmade conditions if not previously 
submitted; and
    (i) Permafrost zones, if applicable.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26017, Apr. 29, 2016]



Sec. 250.414  What must my drilling prognosis include?

    Your drilling prognosis must include a brief description of the 
procedures you will follow in drilling the well. This prognosis includes 
but is not limited to the following:

[[Page 96]]

    (a) Projected plans for coring at specified depths;
    (b) Projected plans for logging;
    (c) Planned safe drilling margin that is between the estimated pore 
pressure and the lesser of estimated fracture gradients or casing shoe 
pressure integrity test and that is based on a risk assessment 
consistent with expected well conditions and operations.
    (1) Your safe drilling margin must also include use of equivalent 
downhole mud weight that is:
    (i) Greater than the estimated pore pressure; and
    (ii) Except as provided in paragraph (c)(2) of this section, a 
minimum of 0.5 pound per gallon below the lower of the casing shoe 
pressure integrity test or the lowest estimated fracture gradient.
    (2) In lieu of meeting the criteria in paragraph (c)(1)(ii) of this 
section, you may use an equivalent downhole mud weight as specified in 
your APD, provided that you submit adequate documentation (such as risk 
modeling data, off-set well data, analog data, seismic data) to justify 
the alternative equivalent downhole mud weight.
    (3) When determining the pore pressure and lowest estimated fracture 
gradient for a specific interval, you must consider related off-set well 
behavior observations.
    (d) Estimated depths to the top of significant marker formations;
    (e) Estimated depths to significant porous and permeable zones 
containing fresh water, oil, gas, or abnormally pressured formation 
fluids;
    (f) Estimated depths to major faults;
    (g) Estimated depths of permafrost, if applicable;
    (h) A list and description of all requests for using alternate 
procedures or departures from the requirements of this subpart in one 
place in the APD. You must explain how the alternate procedures afford 
an equal or greater degree of protection, safety, or performance, or why 
the departures are requested;
    (i) Projected plans for well testing (refer to Sec. 250.460);
    (j) The type of wellhead system and liner hanger system to be 
installed and a descriptive schematic, which includes but is not limited 
to pressure ratings, dimensions, valves, load shoulders, and locking 
mechanisms, if applicable; and
    (k) Any additional information required by the District Manager 
needed to clarify or evaluate your drilling prognosis.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26017, Apr. 29, 2016]



Sec. 250.415  What must my casing and cementing programs include?

    Your casing and cementing programs must include:
    (a) The following well design information:
    (1) Hole sizes;
    (2) Bit depths (including measured and true vertical depth (TVD));
    (3) Casing information, including sizes, weights, grades, collapse 
and burst values, types of connection, and setting depths (measured and 
TVD) for all sections of each casing interval; and
    (4) Locations of any installed rupture disks (indicate if burst or 
collapse and rating);
    (b) Casing design safety factors for tension, collapse, and burst 
with the assumptions made to arrive at these values;
    (c) Type and amount of cement (in cubic feet) planned for each 
casing string;
    (d) In areas containing permafrost, setting depths for conductor and 
surface casing based on the anticipated depth of the permafrost. Your 
program must provide protection from thaw subsidence and freezeback 
effect, proper anchorage, and well control;
    (e) A statement of how you evaluated the best practices included in 
API RP 65, Recommended Practice for Cementing Shallow Water Flow Zones 
in Deep Water Wells (as incorporated by reference in Sec. 250.198), if 
you drill a well in water depths greater than 500 feet and are in either 
of the following two areas:
    (1) An ``area with an unknown shallow water flow potential'' is a 
zone or geologic formation where neither the presence nor absence of 
potential for a shallow water flow has been confirmed.
    (2) An ``area known to contain a shallow water flow hazard'' is a 
zone or geologic formation for which drilling has confirmed the presence 
of shallow water flow; and

[[Page 97]]

    (f) A written description of how you evaluated the best practices 
included in API Standard 65--Part 2, Isolating Potential Flow Zones 
During Well Construction, Second Edition (as incorporated by reference 
in Sec. 250.198). Your written description must identify the mechanical 
barriers and cementing practices you will use for each casing string 
(reference API Standard 65--Part 2, Sections 4 and 5).

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50891, Aug. 22, 2012; 
81 FR 26018, Apr. 29, 2016]



Sec. 250.416  What must I include in the diverter description?

    You must include in the diverter description:
    (a) A description of the diverter system and its operating 
procedures;
    (b) A schematic drawing of the diverter system (plan and elevation 
views) that shows:
    (1) The size of the element installed in the diverter housing;
    (2) Spool outlet internal diameter(s);
    (3) Diverter-line lengths and diameters; burst strengths and radius 
of curvature at each turn; and
    (4) Valve type, size, working pressure rating, and location.

[81 FR 26018, Apr. 29, 2016]



Sec. 250.417  [Reserved]



Sec. 250.418  What additional information must I submit with my APD?

    You must include the following with the APD:
    (a) Rated capacities of the drilling rig and major drilling 
equipment, if not already on file with the appropriate District office;
    (b) A drilling fluids program that includes the minimum quantities 
of drilling fluids and drilling fluid materials, including weight 
materials, to be kept at the site;
    (c) A proposed directional plot if the well is to be directionally 
drilled;
    (d) A Hydrogen Sulfide Contingency Plan (see Sec. 250.490), if 
applicable, and not previously submitted;
    (e) A welding plan (see Secs. 250.109 to 250.113) if not previously 
submitted;
    (f) In areas subject to subfreezing conditions, evidence that the 
drilling equipment, BOP systems and components, diverter systems, and 
other associated equipment and materials are suitable for operating 
under such conditions;
    (g) A request for approval, if you plan to wash out or displace 
cement to facilitate casing removal upon well abandonment. Your request 
must include a description of how far below the mudline you propose to 
displace cement and how you will visually monitor returns;
    (h) Certification of your casing and cementing program as required 
in Sec. 250.420(a)(7); and
    (i) Such other information as the District Manager may require.
    (j) For Arctic OCS exploratory drilling operations, you must provide 
the information required by Sec. 250.470.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012; 
81 FR 26018, Apr. 29, 2016; 81 FR 46561, July 15, 2016]

                    Casing and Cementing Requirements



Sec. 250.420  What well casing and cementing requirements must
I meet?

    You must case and cement all wells. Your casing and cementing 
programs must meet the applicable requirements of this subpart and of 
subpart G of this part.
    (a) Casing and cementing program requirements. Your casing and 
cementing programs must:
    (1) Properly control formation pressures and fluids;
    (2) Prevent the direct or indirect release of fluids from any 
stratum through the wellbore into offshore waters;
    (3) Prevent communication between separate hydrocarbon-bearing 
strata;
    (4) Protect freshwater aquifers from contamination;
    (5) Support unconsolidated sediments;
    (6) Provide adequate centralization to ensure proper cementation; 
and
    (7)(i) Include a certification signed by a registered professional 
engineer that the casing and cementing design is appropriate for the 
purpose for which it is intended under expected wellbore conditions, and 
is sufficient to satisfy the tests and requirements of this section and 
Sec. 250.423. Submit this certification with your APD (Form BSEE-0123).

[[Page 98]]

    (ii) You must have the registered professional engineer involved in 
the casing and cementing design process.
    (iii) The registered professional engineer must be registered in a 
state of the United States and have sufficient expertise and experience 
to perform the certification.
    (b) Casing requirements. (1) You must design casing (including 
liners) to withstand the anticipated stresses imposed by tensile, 
compressive, and buckling loads; burst and collapse pressures; thermal 
effects; and combinations thereof.
    (2) The casing design must include safety measures that ensure well 
control during drilling and safe operations during the life of the well.
    (3) On all wells that use subsea BOP stacks, you must include two 
independent barriers, including one mechanical barrier, in each annular 
flow path (examples of barriers include, but are not limited to, primary 
cement job and seal assembly). For the final casing string (or liner if 
it is your final string), you must install one mechanical barrier in 
addition to cement to prevent flow in the event of a failure in the 
cement. A dual float valve, by itself, is not considered a mechanical 
barrier. These barriers cannot be modified prior to or during completion 
or abandonment operations. The BSEE District Manager may approve 
alternative options under Sec. 250.141. You must submit documentation of 
this installation to BSEE in the End-of-Operations Report (Form BSEE-
0125).
    (4) If you need to substitute a different size, grade, or weight of 
casing than what was approved in your APD, you must contact the District 
Manager for approval prior to installing the casing.
    (c) Cementing requirements. (1) You must design and conduct your 
cementing jobs so that cement composition, placement techniques, and 
waiting times ensure that the cement placed behind the bottom 500 feet 
of casing attains a minimum compressive strength of 500 psi before 
drilling out the casing or before commencing completion operations. (If 
a liner is used refer to Sec. 250.421(f)).
    (2) You must use a weighted fluid during displacement to maintain an 
overbalanced hydrostatic pressure during the cement setting time, except 
when cementing casings or liners in riserless hole sections.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012; 
81 FR 26018, Apr. 29, 2016]



Sec. 250.421  What are the casing and cementing requirements by type
of casing string?

    The table in this section identifies specific design, setting, and 
cementing requirements for casing strings and liners. For the purposes 
of subpart D, the casing strings in order of normal installation are as 
follows: drive or structural, conductor, surface, intermediate, and 
production casings (including liners). The District Manager may approve 
or prescribe other casing and cementing requirements where appropriate.

------------------------------------------------------------------------
                                                          Cementing
         Casing type           Casing requirements      requirements
------------------------------------------------------------------------
(a) Drive or Structural.....  Set by driving,       If you drilled a
                               jetting, or           portion of this
                               drilling to the       hole, you must use
                               minimum depth as      enough cement to
                               approved or           fill the annular
                               prescribed by the     space back to the
                               District Manager.     mudline.
(b) Conductor...............  Design casing and     Use enough cement to
                               select setting        fill the calculated
                               depths based on       annular space back
                               relevant              to the mudline.
                               engineering and      Verify annular fill
                               geologic factors.     by observing cement
                               These factors         returns. If you
                               include the           cannot observe
                               presence or absence   cement returns, use
                               of hydrocarbons,      additional cement
                               potential hazards,    to ensure fill-back
                               and water depths.     to the mudline.
                              Set casing            For drilling on an
                               immediately before    artificial island
                               drilling into         or when using a
                               formations known to   well cellar, you
                               contain oil or gas.   must discuss the
                               If you encounter      cement fill level
                               oil or gas or         with the District
                               unexpected            Manager.
                               formation pressure
                               before the planned
                               casing point, you
                               must set casing
                               immediately and set
                               it above the
                               encountered zone.

[[Page 99]]

 
(c) Surface.................  Design casing and     Use enough cement to
                               select setting        fill the calculated
                               depths based on       annular space to at
                               relevant              least 200 feet
                               engineering and       inside the
                               geologic factors.     conductor casing.
                               These factors        When geologic
                               include the           conditions such as
                               presence or absence   near-surface
                               of hydrocarbons,      fractures and
                               potential hazards,    faulting exist, you
                               and water depths.     must use enough
                                                     cement to fill the
                                                     calculated annular
                                                     space to the
                                                     mudline.
(d) Intermediate............  Design casing and     Use enough cement to
                               select setting        cover and isolate
                               depth based on        all hydrocarbon-
                               anticipated or        bearing zones and
                               encountered           isolate abnormal
                               geologic              pressure intervals
                               characteristics or    from normal
                               wellbore conditions.  pressure intervals
                                                     in the well.
                                                    As a minimum, you
                                                     must cement the
                                                     annular space 500
                                                     feet above the
                                                     casing shoe and 500
                                                     feet above each
                                                     zone to be
                                                     isolated.
(e) Production..............  Design casing and     Use enough cement to
                               select setting        cover or isolate
                               depth based on        all hydrocarbon-
                               anticipated or        bearing zones above
                               encountered           the shoe.
                               geologic             As a minimum, you
                               characteristics or    must cement the
                               wellbore conditions.  annular space at
                                                     least 500 feet
                                                     above the casing
                                                     shoe and 500 feet
                                                     above the uppermost
                                                     hydrocarbon-bearing
                                                     zone.
(f) Liners..................  If you use a liner    Same as cementing
                               as surface casing,    requirements for
                               you must set the      specific casing
                               top of the liner at   types. For example,
                               least 200 feet        a liner used as
                               above the previous    intermediate casing
                               casing/liner shoe.    must be cemented
                              If you use a liner     according to the
                               as an intermediate    cementing
                               string below a        requirements for
                               surface string or     intermediate
                               production casing     casing. If you have
                               below an              a liner lap and are
                               intermediate          unable to cement
                               string, you must      500 feet above the
                               set the top of the    previous shoe, as
                               liner at least 100    provided by
                               feet above the        paragraphs (d) and
                               previous casing       (e) of this
                               shoe.                 section, you must
                              You may not use a      submit and receive
                               liner as conductor    approval from the
                               casing.               District Manager on
                              A subsea well casing   a case-by-case
                               string whose top is   basis.
                               above the mudline
                               and that has been
                               cemented back to
                               the mudline will
                               not be considered a
                               liner.
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26018, Apr. 29, 2016]



Sec. 250.422  When may I resume drilling after cementing?

    (a) After cementing surface, intermediate, or production casing (or 
liners), you may resume drilling after the cement has been held under 
pressure for 12 hours. For conductor casing, you may resume drilling 
after the cement has been held under pressure for 8 hours. One 
acceptable method of holding cement under pressure is to use float 
valves to hold the cement in place.
    (b) If you plan to nipple down your diverter or BOP stack during the 
8- or 12-hour waiting time, you must determine, before nippling down, 
when it will be safe to do so. You must base your determination on a 
knowledge of formation conditions, cement composition, effects of 
nippling down, presence of potential drilling hazards, well conditions 
during drilling, cementing, and post cementing, as well as past 
experience.



Sec. 250.423  What are the requirements for casing and liner 
installation?

    You must ensure proper installation of casing in the subsea wellhead 
or liner in the liner hanger.
    (a) You must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon successfully installing and cementing the 
casing string. If there is an indication of an inadequate cement job, 
you must comply with Sec. 250.428(c).
    (b) If you run a liner that has a latching mechanism or lock down 
mechanism, you must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon successfully installing and cementing the 
liner. If there is an indication of an inadequate cement job, you must 
comply with Sec. 250.428(c).
    (c) You must perform a pressure test on the casing seal assembly to 
ensure proper installation of casing or liner. You must perform this 
test for the intermediate and production casing strings or liners.
    (1) You must submit for approval with your APD, test procedures and 
criteria for a successful test.

[[Page 100]]

    (2) You must document all your test results and make them available 
to BSEE upon request.

[81 FR 26019, Apr. 29, 2016]



Secs. 250.424-250.426  [Reserved]



Sec. 250.427  What are the requirements for pressure integrity tests?

    You must conduct a pressure integrity test below the surface casing 
or liner and all intermediate casings or liners. The District Manager 
may require you to run a pressure-integrity test at the conductor casing 
shoe if warranted by local geologic conditions or the planned casing 
setting depth. You must conduct each pressure integrity test after 
drilling at least 10 feet but no more than 50 feet of new hole below the 
casing shoe. You must test to either the formation leak-off pressure or 
to an equivalent drilling fluid weight if identified in an approved APD.
    (a) You must use the pressure integrity test and related hole-
behavior observations, such as pore-pressure test results, gas-cut 
drilling fluid, and well kicks to adjust the drilling fluid program and 
the setting depth of the next casing string. You must record all test 
results and hole-behavior observations made during the course of 
drilling related to formation integrity and pore pressure in the 
driller's report.
    (b) While drilling, you must maintain the safe drilling margins 
identified in Sec. 250.414. When you cannot maintain the safe margins, 
you must suspend drilling operations and remedy the situation.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26019, Apr. 29, 2016]



Sec. 250.428  What must I do in certain cementing and casing 
situations?

    The table in this section describes actions that lessees must take 
when certain situations occur during casing and cementing activities.

------------------------------------------------------------------------
 If you encounter the following situation:       Then you must . . .
------------------------------------------------------------------------
(a) Have unexpected formation pressures or  Submit a revised casing
 conditions that warrant revising your       program to the District
 casing design,                              Manager for approval.
(b) Need to change casing setting depths    Submit those changes to the
 or hole interval drilling depth (for a      District Manager for
 BHA with an under-reamer, this means bit    approval and include a
 depth) more than 100 feet true vertical     certification by a
 depth (TVD) from the approved APD due to    professional engineer (PE)
 conditions encountered during drilling      that he or she reviewed and
 operations,                                 approved the proposed
                                             changes.
(c) Have indication of inadequate cement    (1) Locate the top of cement
 job (such as lost returns, no cement        by:
 returns to mudline or expected height,     (i) Running a temperature
 cement channeling, or failure of            survey;
 equipment),                                (ii) Running a cement
                                             evaluation log; or
                                            (iii) Using a combination of
                                             these techniques.
                                            (2) Determine if your cement
                                             job is inadequate. If your
                                             cement job is determined to
                                             be inadequate, refer to
                                             paragraph (d) of this
                                             section.
                                            (3) If your cement job is
                                             determined to be adequate,
                                             report the results to the
                                             District Manager in your
                                             submitted WAR.
(d) Inadequate cement job,                  Take remedial actions. The
                                             District Manager must
                                             review and approve all
                                             remedial actions before you
                                             may take them, unless
                                             immediate actions must be
                                             taken to ensure the safety
                                             of the crew or to prevent a
                                             well-control event. If you
                                             complete any immediate
                                             action to ensure the safety
                                             of the crew or to prevent a
                                             well-control event, submit
                                             a description of the action
                                             to the District Manager
                                             when that action is
                                             complete. Any changes to
                                             the well program will
                                             require submittal of a
                                             certification by a
                                             professional engineer (PE)
                                             certifying that he or she
                                             reviewed and approved the
                                             proposed changes, and must
                                             meet any other requirements
                                             of the District Manager.
(e) Primary cement job that did not         Isolate those intervals from
 isolate abnormal pressure intervals,        normal pressures by squeeze
                                             cementing before you
                                             complete; suspend
                                             operations; or abandon the
                                             well, whichever occurs
                                             first.
(f) Decide to produce a well that was not   Have at least two cemented
 originally contemplated for production,     casing strings (does not
                                             include liners) in the
                                             well. Note: All producing
                                             wells must have at least
                                             two cemented casing
                                             strings.
(g) Want to drill a well without setting    Submit geologic data and
 conductor casing,                           information to the District
                                             Manager that demonstrates
                                             the absence of shallow
                                             hydrocarbons or hazards.
                                             This information must
                                             include logging and
                                             drilling fluid-monitoring
                                             from wells previously
                                             drilled within 500 feet of
                                             the proposed well path down
                                             to the next casing point.

[[Page 101]]

 
(h) Need to use less than required cement   Submit information to the
 for the surface casing during floating      District Manager that
 drilling operations to provide protection   demonstrates the use of
 from burst and collapse pressures,          less cement is necessary.
(i) Cement across a permafrost zone,        Use cement that sets before
                                             it freezes and has a low
                                             heat of hydration.
(j) Leave the annulus opposite a            Fill the annulus with a
 permafrost zone uncemented,                 liquid that has a freezing
                                             point below the minimum
                                             permafrost temperature and
                                             minimizes opposite a
                                             corrosion.
(k) Plan to use a valve(s) on the drive     Include a description of the
 pipe during cementing operations for the    plan in your APD. Your
 conductor casing, surface casing, or        description must include a
 liner,                                      schematic of the valve and
                                             height above the water
                                             line. The valve must be
                                             remotely operated and full
                                             opening with visual
                                             observation while taking
                                             returns. The person in
                                             charge of observing returns
                                             must be in communication
                                             with the drill floor. You
                                             must record in your daily
                                             report and in the WAR if
                                             cement returns were
                                             observed. If cement returns
                                             are not observed, you must
                                             contact the District
                                             Manager and obtain approval
                                             of proposed plans to locate
                                             the top of cement before
                                             continuing with operations.
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012; 
81 FR 26019, Apr. 29, 2016]

                      Diverter System Requirements



Sec. 250.430  When must I install a diverter system?

    You must install a diverter system before you drill a conductor or 
surface hole. The diverter system consists of a diverter sealing 
element, diverter lines, and control systems. You must design, install, 
use, maintain, and test the diverter system to ensure proper diversion 
of gases, water, drilling fluid, and other materials away from 
facilities and personnel.



Sec. 250.431  What are the diverter design and installation
requirements?

    You must design and install your diverter system to:
    (a) Use diverter spool outlets and diverter lines that have a 
nominal diameter of at least 10 inches for surface wellhead 
configurations and at least 12 inches for floating drilling operations;
    (b) Use dual diverter lines arranged to provide for downwind 
diversion capability;
    (c) Use at least two diverter control stations. One station must be 
on the drilling floor. The other station must be in a readily accessible 
location away from the drilling floor;
    (d) Use only remote-controlled valves in the diverter lines. All 
valves in the diverter system must be full-opening. You may not install 
manual or butterfly valves in any part of the diverter system;
    (e) Minimize the number of turns (only one 90-degree turn allowed 
for each line for bottom-founded drilling units) in the diverter lines, 
maximize the radius of curvature of turns, and target all right angles 
and sharp turns;
    (f) Anchor and support the entire diverter system to prevent 
whipping and vibration; and
    (g) Protect all diverter-control instruments and lines from possible 
damage by thrown or falling objects.



Sec. 250.432  How do I obtain a departure to diverter design and
installation requirements?

    The table below describes possible departures from the diverter 
requirements and the conditions required for each departure. To obtain 
one of these departures, you must have discussed the departure in your 
APD and received approval from the District Manager.

------------------------------------------------------------------------
        If you want a departure to:              Then you must . . .
------------------------------------------------------------------------
(a) Use flexible hose for diverter lines    Use flexible hose that has
 instead of rigid pipe,                      integral end couplings.
(b) Use only one spool outlet for your      (1) Have branch lines that
 diverter system,                            meet the minimum internal
                                             diameter requirements; and
                                             (2) Provide downwind
                                             diversion capability.
(c) Use a spool with an outlet with an      Use a spool that has dual
 internal diameter of less than 10 inches    outlets with an internal
 on a surface wellhead,                      diameter of at least 8
                                             inches.

[[Page 102]]

 
(d) Use a single diverter line for          Maintain an appropriate
 floating drilling operations on a           vessel heading to provide
 dynamically positioned drillship,           for downwind diversion.
------------------------------------------------------------------------



Sec. 250.433  What are the diverter actuation and testing requirements?

    When you install the diverter system, you must actuate the diverter 
sealing element, diverter valves, and diverter-control systems and 
control stations. You must also flow-test the vent lines.
    (a) For drilling operations with a surface wellhead configuration, 
you must actuate the diverter system at least once every 24-hour period 
after the initial test. After you have nippled up on conductor casing, 
you must pressure-test the diverter-sealing element and diverter valves 
to a minimum of 200 psi. While the diverter is installed, you must 
conduct subsequent pressure tests within 7 days after the previous test.
    (b) For floating drilling operations with a subsea BOP stack, you 
must actuate the diverter system within 7 days after the previous 
actuation.
    (c) You must alternate actuations and tests between control 
stations.



Sec. 250.434  What are the recordkeeping requirements for diverter
actuations and tests?

    You must record the time, date, and results of all diverter 
actuations and tests in the driller's report. In addition, you must:
    (a) Record the diverter pressure test on a pressure chart;
    (b) Require your onsite representative to sign and date the pressure 
test chart;
    (c) Identify the control station used during the test or actuation;
    (d) Identify problems or irregularities observed during the testing 
or actuations and record actions taken to remedy the problems or 
irregularities; and
    (e) Retain all pressure charts and reports pertaining to the 
diverter tests and actuations at the facility for the duration of 
drilling the well.



Secs. 250.440--250.451  [Reserved]



Sec. 250.452  What are the real-time monitoring requirements for
Arctic OCS exploratory drilling operations?

    (a) When conducting exploratory drilling operations on the Arctic 
OCS, you must gather and monitor real-time data using an independent, 
automatic, and continuous monitoring system capable of recording, 
storing, and transmitting data regarding the following:
    (1) The BOP control system;
    (2) The well's fluid handling systems on the rig; and
    (3) The well's downhole conditions as monitored by a downhole 
sensing system, when such a system is installed.
    (b) During well operations, you must transmit the data identified in 
paragraph (a) of this section as they are gathered, barring 
unforeseeable or unpreventable interruptions in transmission, and have 
the capability to monitor the data onshore, using qualified personnel. 
Onshore personnel who monitor real-time data must have the capability to 
contact rig personnel during operations. After well operations, you must 
store the data at a designated location for recordkeeping purposes as 
required in Secs. 250.740 and 250.741. You must provide BSEE with access 
to your real-time monitoring data onshore upon request.

[81 FR 46561, July 15, 2016]

                       Drilling Fluid Requirements



Sec. 250.455  What are the general requirements for a drilling fluid
program?

    You must design and implement your drilling fluid program to prevent 
the loss of well control. This program must address drilling fluid safe 
practices, testing and monitoring equipment, drilling fluid quantities, 
and drilling fluid-handling areas.



Sec. 250.456  What safe practices must the drilling fluid program
follow?

    Your drilling fluid program must include the following safe 
practices:

[[Page 103]]

    (a) Before starting out of the hole with drill pipe, you must 
properly condition the drilling fluid. You must circulate a volume of 
drilling fluid equal to the annular volume with the drill pipe just off-
bottom. You may omit this practice if documentation in the driller's 
report shows:
    (1) No indication of formation fluid influx before starting to pull 
the drill pipe from the hole;
    (2) The weight of returning drilling fluid is within 0.2 pounds per 
gallon (1.5 pounds per cubic foot) of the drilling fluid entering the 
hole; and
    (3) Other drilling fluid properties are within the limits 
established by the program approved in the APD.
    (b) Record each time you circulate drilling fluid in the hole in the 
driller's report;
    (c) When coming out of the hole with drill pipe, you must fill the 
annulus with drilling fluid before the hydrostatic pressure decreases by 
75 psi, or every five stands of drill pipe, whichever gives a lower 
decrease in hydrostatic pressure. You must calculate the number of 
stands of drill pipe and drill collars that you may pull before you must 
fill the hole. You must also calculate the equivalent drilling fluid 
volume needed to fill the hole. Both sets of numbers must be posted near 
the driller's station. You must use a mechanical, volumetric, or 
electronic device to measure the drilling fluid required to fill the 
hole;
    (d) You must run and pull drill pipe and downhole tools at 
controlled rates so you do not swab or surge the well;
    (e) When there is an indication of swabbing or influx of formation 
fluids, you must take appropriate measures to control the well. You must 
circulate and condition the well, on or near-bottom, unless well or 
drilling-fluid conditions prevent running the drill pipe back to the 
bottom;
    (f) You must calculate and post near the driller's console the 
maximum pressures that you may safely contain under a shut-in BOP for 
each casing string. The pressures posted must consider the surface 
pressure at which the formation at the shoe would break down, the rated 
working pressure of the BOP stack, and 70 percent of casing burst (or 
casing test as approved by the District Manager). As a minimum, you must 
post the following two pressures:
    (1) The surface pressure at which the shoe would break down. This 
calculation must consider the current drilling fluid weight in the hole; 
and
    (2) The lesser of the BOP's rated working pressure or 70 percent of 
casing-burst pressure (or casing test otherwise approved by the District 
Manager);
    (g) You must install an operable drilling fluid-gas separator and 
degasser before you begin drilling operations. You must maintain this 
equipment throughout the drilling of the well;
    (h) Before pulling drill-stem test tools from the hole, you must 
circulate or reverse-circulate the test fluids in the hole. If 
circulating out test fluids is not feasible, you may bullhead test 
fluids out of the drill-stem test string and tools with an appropriate 
kill weight fluid;
    (i) When circulating, you must test the drilling fluid at least once 
each tour, or more frequently if conditions warrant. Your tests must 
conform to industry-accepted practices and include density, viscosity, 
and gel strength; hydrogenion concentration; filtration; and any other 
tests the District Manager requires for monitoring and maintaining 
drilling fluid quality, prevention of downhole equipment problems and 
for kick detection. You must record the results of these tests in the 
drilling fluid report; and
    (j) In areas where permafrost and/or hydrate zones are present or 
may be present, you must control drilling fluid temperatures to drill 
safely through those zones.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50894, Aug. 22, 2012; 
81 FR 26020, Apr. 29, 2016]



Sec. 250.457  What equipment is required to monitor drilling fluids?

    Once you establish drilling fluid returns, you must install and 
maintain the following drilling fluid-system monitoring equipment 
throughout subsequent drilling operations. This equipment must have the 
following indicators on the rig floor:
    (a) Pit level indicator to determine drilling fluid-pit volume gains 
and

[[Page 104]]

losses. This indicator must include both a visual and an audible warning 
device;
    (b) Volume measuring device to accurately determine drilling fluid 
volumes required to fill the hole on trips;
    (c) Return indicator devices that indicate the relationship between 
drilling fluid-return flow rate and pump discharge rate. This indicator 
must include both a visual and an audible warning device; and
    (d) Gas-detecting equipment to monitor the drilling fluid returns. 
The indicator may be located in the drilling fluid-logging compartment 
or on the rig floor. If the indicators are only in the logging 
compartment, you must continually man the equipment and have a means of 
immediate communication with the rig floor. If the indicators are on the 
rig floor only, you must install an audible alarm.



Sec. 250.458  What quantities of drilling fluids are required?

    (a) You must use, maintain, and replenish quantities of drilling 
fluid and drilling fluid materials at the drill site as necessary to 
ensure well control. You must determine those quantities based on known 
or anticipated drilling conditions, rig storage capacity, weather 
conditions, and estimated time for delivery.
    (b) You must record the daily inventories of drilling fluid and 
drilling fluid materials, including weight materials and additives in 
the drilling fluid report.
    (c) If you do not have sufficient quantities of drilling fluid and 
drilling fluid material to maintain well control, you must suspend 
drilling operations.



Sec. 250.459  What are the safety requirements for drilling fluid-
handling areas?

    You must classify drilling fluid-handling areas according to API RP 
500, Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities, Classified as Class I, Division 1 
and Division 2 (as incorporated by reference in Sec. 250.198); or API RP 
505, Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities, Classified as Class 1, Zone 0, 
Zone 1, and Zone 2 (as incorporated by reference in Sec. 250.198). In 
areas where dangerous concentrations of combustible gas may accumulate, 
you must install and maintain a ventilation system and gas monitors. 
Drilling fluid-handling areas must have the following safety equipment:
    (a) A ventilation system capable of replacing the air once every 5 
minutes or 1.0 cubic feet of air-volume flow per minute, per square foot 
of area, whichever is greater. In addition:
    (1) If natural means provide adequate ventilation, then a mechanical 
ventilation system is not necessary;
    (2) If a mechanical system does not run continuously, then it must 
activate when gas detectors indicate the presence of 1 percent or more 
of combustible gas by volume; and
    (3) If discharges from a mechanical ventilation system may be 
hazardous, then you must maintain the drilling fluid-handling area at a 
negative pressure. You must protect the negative pressure area by using 
at least one of the following: a pressure-sensitive alarm, open-door 
alarms on each access to the area, automatic door-closing devices, air 
locks, or other devices approved by the District Manager;
    (b) Gas detectors and alarms except in open areas where adequate 
ventilation is provided by natural means. You must test and recalibrate 
gas detectors quarterly. No more than 90 days may elapse between tests;
    (c) Explosion-proof or pressurized electrical equipment to prevent 
the ignition of explosive gases. Where you use air for pressuring 
equipment, you must locate the air intake outside of and as far as 
practicable from hazardous areas; and
    (d) Alarms that activate when the mechanical ventilation system 
fails.

                       Other Drilling Requirements



Sec. 250.460  What are the requirements for conducting a well test?

    (a) If you intend to conduct a well test, you must include your 
projected plans for the test with your APD (form BSEE-0123) or in an 
Application for Permit to Modify (APM) (form BSEE-0124). Your plans must 
include at least the following information:

[[Page 105]]

    (1) Estimated flowing and shut-in tubing pressures;
    (2) Estimated flow rates and cumulative volumes;
    (3) Time duration of flow, buildup, and drawdown periods;
    (4) Description and rating of surface and subsurface test equipment;
    (5) Schematic drawing, showing the layout of test equipment;
    (6) Description of safety equipment, including gas detectors and 
fire-fighting equipment;
    (7) Proposed methods to handle or transport produced fluids; and
    (8) Description of the test procedures.
    (b) You must give the District Manager at least 24-hours notice 
before starting a well test.



Sec. 250.461  What are the requirements for directional and
inclination surveys?

    For this subpart, BSEE classifies a well as vertical if the 
calculated average of inclination readings does not exceed 3 degrees 
from the vertical.
    (a) Survey requirements for a vertical well. (1) You must conduct 
inclination surveys on each vertical well and record the results. Survey 
intervals may not exceed 1,000 feet during the normal course of 
drilling;
    (2) You must also conduct a directional survey that provides both 
inclination and azimuth, and digitally record the results in electronic 
format:
    (i) Within 500 feet of setting surface or intermediate casing;
    (ii) Within 500 feet of setting any liner; and
    (iii) When you reach total depth.
    (b) Survey requirements for directional well. You must conduct 
directional surveys on each directional well and digitally record the 
results. Surveys must give both inclination and azimuth at intervals not 
to exceed 500 feet during the normal course of drilling. Intervals 
during angle-changing portions of the hole may not exceed 100 feet.
    (c) Measurement while drilling. You may use measurement-while-
drilling technology if it meets the requirements of this section.
    (d) Composite survey requirements. (1) Your composite directional 
survey must show the interval from the bottom of the conductor casing to 
total depth. In the absence of conductor casing, the survey must show 
the interval from the bottom of the drive or structural casing to total 
depth; and
    (2) You must correct all surveys to Universal-Transverse-Mercator-
Grid-north or Lambert-Grid-north after making the magnetic-to-true-north 
correction. Surveys must show the magnetic and grid corrections used and 
include a listing of the directionally computed inclinations and 
azimuths.
    (e) If you drill within 500 feet of an adjacent lease, the Regional 
Supervisor may require you to furnish a copy of the well's directional 
survey to the affected leaseholder. This could occur when the adjoining 
leaseholder requests a copy of the survey for the protection of 
correlative rights.



Sec. 250.462  What are the source control, containment, and collocated
equipment requirements?

    For drilling operations using a subsea BOP or surface BOP on a 
floating facility, you must have the ability to control or contain a 
blowout event at the sea floor.
    (a) To determine your required source control and containment 
capabilities you must do the following:
    (1) Consider a scenario of the wellbore fully evacuated to reservoir 
fluids, with no restrictions in the well.
    (2) Evaluate the performance of the well as designed to determine if 
a full shut-in can be achieved without having reservoir fluids broach to 
the sea floor. If your evaluation indicates that the well can only be 
partially shut-in, then you must determine your ability to flow and 
capture the residual fluids to a surface production and storage system.
    (b) You must have access to and the ability to deploy Source Control 
and Containment Equipment (SCCE) and all other necessary supporting and 
collocated equipment to regain control of the well. SCCE means the 
capping stack, cap-and-flow system, containment dome, and/or other 
subsea and surface devices, equipment, and vessels, which have the 
collective purpose to control a spill source and stop the flow of fluids 
into the environment or

[[Page 106]]

to contain fluids escaping into the environment. This SCCE, supporting 
equipment, and collocated equipment must include, but is not limited to, 
the following:
    (1) Subsea containment and capture equipment, including containment 
domes and capping stacks;
    (2) Subsea utility equipment including hydraulic power sources and 
hydrate control equipment;
    (3) Collocated equipment including dispersant injection equipment;
    (4) Riser systems;
    (5) Remotely operated vehicles (ROVs);
    (6) Capture vessels;
    (7) Support vessels; and
    (8) Storage facilities.
    (c) You must submit a description of your source control and 
containment capabilities to the Regional Supervisor and receive approval 
before BSEE will approve your APD, Form BSEE-0123. The description of 
your containment capabilities must contain the following:
    (1) Your source control and containment capabilities for controlling 
and containing a blowout event at the seafloor;
    (2) A discussion of the determination required in paragraph (a) of 
this section; and
    (3) Information showing that you have access to and the ability to 
deploy all equipment required by paragraph (b) of this section.
    (d) You must contact the District Manager and Regional Supervisor 
for reevaluation of your source control and containment capabilities if 
your:
    (1) Well design changes; or
    (2) Approved source control and containment equipment is out of 
service.
    (e) You must maintain, test, and inspect the source control, 
containment, and collocated equipment identified in the following table 
according to these requirements:

------------------------------------------------------------------------
                                Requirements, you        Additional
          Equipment                   must:              information
------------------------------------------------------------------------
(1) Capping stacks,.........  (i) Function test     Pressure containing
                               all pressure          critical components
                               containing critical   are those
                               components on a       components that
                               quarterly frequency   will experience
                               (not to exceed 104    wellbore pressure
                               days between          during a shut-in
                               tests),               after being
                                                     functioned.
                              (ii) Pressure test    Pressure containing
                               pressure containing   critical components
                               critical components   are those
                               on a bi-annual        components that
                               basis, but not        will experience
                               later than 210 days   wellbore pressure
                               from the last         during a shut-in.
                               pressure test. All    These components
                               pressure testing      include, but are
                               must be witnessed     not limited to: All
                               by BSEE (if           blind rams,
                               available) and a      wellhead
                               BSEE-approved         connectors, and
                               verification          outlet valves.
                               organization.
                              (iii) Notify BSEE at
                               least 21 days prior
                               to commencing any
                               pressure testing.
(2) Production safety         (i) Meet or exceed
 systems used for flow and     the requirements
 capture operations,           set forth in Secs.
                               250.800 through
                               250.808, excluding
                               required equipment
                               that would be
                               installed below the
                               wellhead or that is
                               not applicable to
                               the cap and flow
                               system.
                              (ii) Have all
                               equipment unique to
                               containment
                               operations
                               available for
                               inspection at all
                               times.
(3) Subsea utility            Have all referenced   Subsea utility
 equipment,.                   containment           equipment includes,
                               equipment available   but is not limited
                               for inspection at     to: Hydraulic power
                               all times.            sources, debris
                                                     removal, and
                                                     hydrate control
                                                     equipment.
(4) Collocated equipment,...  Have equipment        Collocated equipment
                               available for         includes, but is
                               inspection at all     not limited to,
                               times.                dispersant
                                                     injection equipment
                                                     and other subsea
                                                     control equipment.
------------------------------------------------------------------------


[81 FR 26020, Apr. 29, 2016]



Sec. 250.463  Who establishes field drilling rules?

    (a) The District Manager may establish field drilling rules 
different from the requirements of this subpart when geological and 
engineering information shows that specific operating requirements are 
appropriate. You must comply with field drilling rules and 
nonconflicting requirements of this subpart. The District Manager may 
amend or cancel field drilling rules at any time.
    (b) You may request the District Manager to establish, amend, or 
cancel field drilling rules.

[[Page 107]]

            Applying for a Permit To Modify and Well Records



Sec. 250.465  When must I submit an Application for Permit to Modify
(APM) or an End of Operations Report to BSEE?

    (a) You must submit an APM (form BSEE-0124) or an End of Operations 
Report (form BSEE-0125) and other materials to the Regional Supervisor 
as shown in the following table. You must also submit a public 
information copy of each form.

------------------------------------------------------------------------
    When you . . .       Then you must . . .           And . . .
------------------------------------------------------------------------
(1) Intend to revise    Submit form BSEE-0124  Receive written or oral
 your drilling plan,     or request oral        approval from the
 change major drilling   approval,              District Manager before
 equipment, or                                  you begin the intended
 plugback,                                      operation. If you get an
                                                approval, you must
                                                submit form BSEE-0124 no
                                                later than the end of
                                                the 3rd business day
                                                following the oral
                                                approval. In all cases,
                                                or you must meet the
                                                additional requirements
                                                in paragraph (b) of this
                                                section.
(2) Determine a well's  Immediately Submit a   Submit a plat certified
 final surface           form BSEE-0124,        by a registered land
 location, water                                surveyor that meets the
 depth, and the rotary                          requirements of Sec.
 kelly bushing                                  250.412.
 elevation,
(3) Move a drilling     Submit forms BSEE-     Submit appropriate copies
 unit from a wellbore    0124 and BSEE-0125     of the well records.
 before completing a     within 30 days after
 well,                   the suspension of
                         wellbore operations,
------------------------------------------------------------------------

    (b) If you intend to perform any of the actions specified in 
paragraph (a)(1) of this section, you must meet the following additional 
requirements:
    (1) Your APM (Form BSEE-0124) must contain a detailed statement of 
the proposed work that would materially change from the approved APD. 
The submission of your APM must be accompanied by payment of the service 
fee listed in Sec. 250.125;
    (2) Your form BSEE-0124 must include the present status of the well, 
depth of all casing strings set to date, well depth, present production 
zones and productive capability, and all other information specified; 
and
    (3) Within 30 days after completing this work, you must submit an 
End of Operations Report (EOR), Form BSEE-0125, as required under 
Sec. 250.744.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26021, Apr. 29, 2016]



Secs. 250.466--250.469  [Reserved]

                   Additional Arctic OCS Requirements

    Source: 81 FR 46561, July 15, 2016, unless otherwise noted.



Sec. 250.470  What additional information must I submit with my APD
for Arctic OCS exploratory drilling operations?

    In addition to complying with all other applicable requirements 
included in this part, you must provide with your APD all of the 
following information pertaining to your proposed Arctic OCS exploratory 
drilling:
    (a) A detailed description of:
    (1) The environmental, meteorological, and oceanic conditions you 
expect to encounter at the well site(s);
    (2) How you will prepare your equipment, materials, and drilling 
unit for service in the conditions identified in paragraph (a)(1) of 
this section, and how your drilling unit will be in compliance with the 
requirements of Sec. 250.713.
    (b) A detailed description of all operations necessary in Arctic OCS 
conditions to transition the rig from being under way to conducting 
drilling operations and from ending drilling operations to being under 
way, as well as any anticipated repair and maintenance plans for the 
drilling unit and equipment. You should include, among other things, a 
description of how you plan to:
    (1) Recover the subsea equipment, including the marine riser and the 
lower marine riser package;

[[Page 108]]

    (2) Recover the BOP;
    (3) Recover the auxiliary sub-sea controls and template;
    (4) Lay down the drill pipe and secure the drill pipe and marine 
riser;
    (5) Secure the drilling equipment;
    (6) Transfer the fluids for transport or disposal;
    (7) Secure ancillary equipment like the draw works and lines;
    (8) Refuel or transfer fuel;
    (9) Offload waste;
    (10) Recover the Remotely Operated Vehicles;
    (11) Pick up the oil spill prevention booms and equipment; and
    (12) Offload the drilling crew.
    (c) A description of well-specific drilling objectives, timelines, 
and updated contingency plans for temporary abandonment of the well, 
including but not limited to the following:
    (1) When you will spud the particular well (i.e., begin drilling 
operations at the well site) identified in the APD;
    (2) How long you will take to drill the well;
    (3) Anticipated depths and geologic targets, with timelines;
    (4) When you expect to set and cement each string of casing;
    (5) When and how you would log the well;
    (6) Your plans to test the well;
    (7) When and how you intend to abandon the well, including 
specifically addressing your plans for how to move the rig off location 
and how you will meet the requirements of Sec. 250.720(c);
    (8) A description of what equipment and vessels will be involved in 
the process of temporarily abandoning the well due to ice; and
    (9) An explanation of how you will integrate these elements into 
your overall program.
    (d) A detailed description of your weather and ice forecasting 
capability for all phases of the drilling operation, including:
    (1) How you will ensure your continuous awareness of potential 
weather and ice hazards at, and during transition between, wells;
    (2) Your plans for managing ice hazards and responding to weather 
events; and
    (3) Verification that you have the capabilities described in your 
BOEM-approved EP.
    (e) A detailed description of how you will comply with the 
requirements of Sec. 250.472.
    (f) A statement that you own, or have a contract with a provider 
for, source control and containment equipment (SCCE), which is capable 
of controlling and/or containing a worst case discharge, as described in 
your BOEM-approved EP, when proposing to use a MODU to conduct 
exploratory drilling operations on the Arctic OCS. The following 
information must be included in your SCCE submittal:
    (1) A detailed description of your or your contractor's SCCE 
capability to stop or contain flow from an out-of-control well, 
including your operating assumptions and limitations; your access to and 
ability to deploy, in accordance with Sec. 250.471, all necessary SCCE; 
and your ability to evaluate the performance of the well design to 
determine how you can achieve a full shut-in without having reservoir 
fluids discharged into the environment;
    (2) An inventory of the local and regional SCCE, supplies, and 
services that you own or for which you have a contract with a provider. 
You must identify each supplier of such equipment and services and 
provide their locations and telephone numbers;
    (3) Where applicable, proof of contracts or membership agreements 
with cooperatives, service providers, or other contractors who will 
provide you with the necessary SCCE or related supplies and services if 
you do not possess them. The contract or membership agreement must 
include provisions for ensuring the availability of the personnel and/or 
equipment on a 24-hour per day basis while you are drilling below or 
working below the surface casing;
    (4) A detailed description of the procedures you plan to use to 
inspect, test, and maintain your SCCE; and
    (5) A detailed description of your plan to ensure that all members 
of your operating team, who are responsible for operating the SCCE, have 
received the necessary training to deploy and operate such equipment in 
Arctic

[[Page 109]]

OCS conditions and demonstrate ongoing proficiency in source control 
operations. You must also identify and include the dates of prior and 
planned training.
    (g) Where it does not conflict with other requirements of this 
subpart, and except as provided in paragraphs (g)(1) through (11) of 
this section, you must comply with the requirements of API RP 2N, Third 
Edition ``Planning, Designing, and Constructing Structures and Pipelines 
for Arctic Conditions'' (incorporated by reference as specified in 
Sec. 250.198), and provide a detailed description of how you will 
utilize the best practices included in API RP 2N during your exploratory 
drilling operations. You are not required to incorporate the following 
sections of API RP 2N into your drilling operations:
    (1) Sections 6.6.3 through 6.6.4;
    (2) The foundation recommendations in Section 8.4;
    (3) Section 9.6;
    (4) The recommendations for permanently moored systems in Section 
9.7;
    (5) The recommendations for pile foundations in Section 9.10;
    (6) Section 12;
    (7) Section 13.2.1;
    (8) Sections 13.8.1.1, 13.8.2.1, 13.8.2.2, 13.8.2.4 through 
13.8.2.7;
    (9) Sections 13.9.1, 13.9.2, 13.9.4 through 13.9.8;
    (10) Sections 14 through 16; and
    (11) Section 18.



Sec. 250.471  What are the requirements for Arctic OCS source control
and containment?

    You must meet the following requirements for all exploration wells 
drilled on the Arctic OCS:
    (a) If you use a MODU when drilling below or working below the 
surface casing, you must have access to the following SCCE capable of 
stopping or capturing the flow of an out-of-control well:
    (1) A capping stack, positioned to ensure that it will arrive at the 
well location within 24 hours after a loss of well control and can be 
deployed as directed by the Regional Supervisor pursuant to paragraph 
(h) of this section;
    (2) A cap and flow system, positioned to ensure that it will arrive 
at the well location within 7 days after a loss of well control and can 
be deployed as directed by the Regional Supervisor pursuant to paragraph 
(h) of this section. The cap and flow system must be designed to capture 
at least the amount of hydrocarbons equivalent to the calculated worst 
case discharge rate referenced in your BOEM-approved EP; and
    (3) A containment dome, positioned to ensure that it will arrive at 
the well location within 7 days after a loss of well control and can be 
deployed as directed by the Regional Supervisor pursuant to paragraph 
(h) of this section. The containment dome must have the capacity to pump 
fluids without relying on buoyancy.
    (b) You must conduct a monthly stump test of dry-stored capping 
stacks. If you use a pre-positioned capping stack, you must conduct a 
stump test prior to each installation on each well.
    (c) As required by Sec. 250.465(a), if you propose to change your 
well design, you must submit an APM. For Arctic OCS operations, your APM 
must include a reevaluation of your SCCE capabilities for any new Worst 
Case Discharge (WCD) rate, and a demonstration that your SCCE 
capabilities will meet the criteria in Sec. 250.470(f) under the changed 
well design.
    (d) You must conduct tests or exercises of your SCCE, including 
deployment of your SCCE, when directed by the Regional Supervisor.
    (e) You must maintain records pertaining to testing, inspection, and 
maintenance of your SCCE for at least 10 years and make the records 
available to any authorized BSEE representative upon request.
    (f) You must maintain records pertaining to the use of your SCCE 
during testing, training, and deployment activities for at least 3 years 
and make the records available to any authorized BSEE representative 
upon request.
    (g) Upon a loss of well control, you must initiate transit of all 
SCCE identified in paragraph (a) of this section to the well.
    (h) You must deploy and use SCCE when directed by the Regional 
Supervisor.
    (i) Operators may request approval of alternate procedures or 
equipment to

[[Page 110]]

the SCCE requirements of subparagraph (a) of this section in accordance 
with Sec. 250.141. The operator must show and document that the 
alternate procedures or equipment will provide a level of safety and 
environmental protection that will meet or exceed the level of safety 
and environmental protection required by BSEE regulations, including 
demonstrating that the alternate procedures or equipment will be capable 
of stopping or capturing the flow of an out-of-control well.



Sec. 250.472  What are the relief rig requirements for the Arctic OCS?

    (a) In the event of a loss of well control, the Regional Supervisor 
may direct you to drill a relief well using the relief rig able to kill 
and permanently plug an out-of-control well as described in your APD. 
Your relief rig must comply with all other requirements of this part 
pertaining to drill rig characteristics and capabilities, and it must be 
able to drill a relief well under anticipated Arctic OCS conditions.
    (b) When you are drilling below or working below the surface casing 
during Arctic OCS exploratory drilling operations, you must have access 
to a relief rig, different from your primary drilling rig, staged in a 
location such that it can arrive on site, drill a relief well, kill and 
abandon the original well, and abandon the relief well prior to expected 
seasonal ice encroachment at the drill site, but no later than 45 days 
after the loss of well control.
    (c) Operators may request approval of alternative compliance 
measures to the relief rig requirement in accordance with Sec. 250.141. 
The operator must show and document that the alternate compliance 
measure will meet or exceed the level of safety and environmental 
protection required by BSEE regulations, including demonstrating that 
the alternate compliance measure will be able to kill and permanently 
plug an out-of-control well.



Sec. 250.473  What must I do to protect health, safety, property,
and theenvironment while operating on the Arctic OCS?

    In addition to the requirements set forth in Sec. 250.107, when 
conducting exploratory drilling operations on the Arctic OCS, you must 
protect health, safety, property, and the environment by using the 
following:
    (a) Equipment and materials that are rated or de-rated for service 
under conditions that can be reasonably expected during your operations; 
and
    (b) Measures to address human factors associated with weather 
conditions that can be reasonably expected during your operations 
including, but not limited to, provision of proper attire and equipment, 
construction of protected work spaces, and management of shifts.

                            Hydrogen Sulfide



Sec. 250.490  Hydrogen sulfide.

    (a) What precautions must I take when operating in an H2S 
    area? You 
must:
    (1) Take all necessary and feasible precautions and measures to 
protect personnel from the toxic effects of H2S and to 
mitigate damage to property and the environment caused by 
H2S. You must follow the requirements of this section when 
conducting drilling, well-completion/well-workover, and production 
operations in zones with H2S present and when conducting 
operations in zones where the presence of H2S is unknown. You 
do not need to follow these requirements when operating in zones where 
the absence of H2S has been confirmed; and
    (2) Follow your approved contingency plan.
    (b) Definitions. Terms used in this section have the following 
meanings:
    Facility means a vessel, a structure, or an artificial island used 
for drilling, well-completion, well-workover, and/or production 
operations.
    H2S absent means:
    (1) Drilling, logging, coring, testing, or producing operations have 
confirmed the absence of H2S in concentrations that could 
potentially result in atmospheric concentrations of 20 ppm or more of 
H2S; or
    (2) Drilling in the surrounding areas and correlation of geological 
and seismic data with equivalent stratigraphic units have confirmed an 
absence of H2S throughout the area to be drilled.
    H2S present means that drilling, logging, coring, testing, or 
producing operations have confirmed the presence

[[Page 111]]

of H2S in concentrations and volumes that could potentially 
result in atmospheric concentrations of 20 ppm or more of 
H2S.
    H2S unknown means the designation of a zone or geologic formation 
where neither the presence nor absence of H2S has been 
confirmed.
    Well-control fluid means drilling mud and completion or workover 
fluid as appropriate to the particular operation being conducted.
    (c) Classifying an area for the presence of H2S. You must:
    (1) Request and obtain an approved classification for the area from 
the Regional Supervisor before you begin operations. Classifications are 
``H2S absent,'' H2S present,'' or ``H2S 
unknown'';
    (2) Submit your request with your application for permit to drill;
    (3) Support your request with available information such as geologic 
and geophysical data and correlations, well logs, formation tests, cores 
and analysis of formation fluids; and
    (4) Submit a request for reclassification of a zone when additional 
data indicate a different classification is needed.
    (d) What do I do if conditions change? If you encounter 
H2S that could potentially result in atmospheric 
concentrations of 20 ppm or more in areas not previously classified as 
having H2S present, you must immediately notify BSEE and 
begin to follow requirements for areas with H2S present.
    (e) What are the requirements for conducting simultaneous 
operations? When conducting any combination of drilling, well-
completion, well-workover, and production operations simultaneously, you 
must follow the requirements in the section applicable to each 
individual operation.
    (f) Requirements for submitting an H2S Contingency Plan. Before you 
begin operations, you must submit an H2S Contingency Plan to 
the District Manager for approval. Do not begin operations before the 
District Manager approves your plan. You must keep a copy of the 
approved plan in the field, and you must follow the plan at all times. 
Your plan must include:
    (1) Safety procedures and rules that you will follow concerning 
equipment, drills, and smoking;
    (2) Training you provide for employees, contractors, and visitors;
    (3) Job position and title of the person responsible for the overall 
safety of personnel;
    (4) Other key positions, how these positions fit into your 
organization, and what the functions, duties, and responsibilities of 
those job positions are;
    (5) Actions that you will take when the concentration of 
H2S in the atmosphere reaches 20 ppm, who will be responsible 
for those actions, and a description of the audible and visual alarms to 
be activated;
    (6) Briefing areas where personnel will assemble during an H2S 
alert. You must have at least two briefing areas on each facility and 
use the briefing area that is upwind of the H2S source at any 
given time;
    (7) Criteria you will use to decide when to evacuate the facility 
and procedures you will use to safely evacuate all personnel from the 
facility by vessel, capsule, or lifeboat. If you use helicopters during 
H2S alerts, describe the types of H2S emergencies 
during which you consider the risk of helicopter activity to be 
acceptable and the precautions you will take during the flights;
    (8) Procedures you will use to safely position all vessels attendant 
to the facility. Indicate where you will locate the vessels with respect 
to wind direction. Include the distance from the facility and what 
procedures you will use to safely relocate the vessels in an emergency;
    (9) How you will provide protective-breathing equipment for all 
personnel, including contractors and visitors;
    (10) The agencies and facilities you will notify in case of a 
release of H2S (that constitutes an emergency), how you will 
notify them, and their telephone numbers. Include all facilities that 
might be exposed to atmospheric concentrations of 20 ppm or more of 
H2S;
    (11) The medical personnel and facilities you will use if needed, 
their addresses, and telephone numbers;
    (12) H2S detector locations in production facilities 
producing gas containing

[[Page 112]]

20 ppm or more of H2S. Include an ``H2S Detector 
Location Drawing'' showing:
    (i) All vessels, flare outlets, wellheads, and other equipment 
handling production containing H2S;
    (ii) Approximate maximum concentration of H2S in the gas 
stream; and
    (iii) Location of all H2S sensors included in your 
contingency plan;
    (13) Operational conditions when you expect to flare gas containing 
H2S including the estimated maximum gas flow rate, 
H2S concentration, and duration of flaring;
    (14) Your assessment of the risks to personnel during flaring and 
what precautionary measures you will take;
    (15) Primary and alternate methods to ignite the flare and 
procedures for sustaining ignition and monitoring the status of the 
flare (i.e., ignited or extinguished);
    (16) Procedures to shut off the gas to the flare in the event the 
flare is extinguished;
    (17) Portable or fixed sulphur dioxide (SO2)-detection 
system(s) you will use to determine SO2 concentration and 
exposure hazard when H2S is burned;
    (18) Increased monitoring and warning procedures you will take when 
the SO2 concentration in the atmosphere reaches 2 ppm;
    (19) Personnel protection measures or evacuation procedures you will 
initiate when the SO2 concentration in the atmosphere reaches 
5 ppm;
    (20) Engineering controls to protect personnel from SO2; 
and
    (21) Any special equipment, procedures, or precautions you will use 
if you conduct any combination of drilling, well-completion, well-
workover, and production operations simultaneously.
    (g) Training program: (1) When and how often do employees need to be 
trained? All operators and contract personnel must complete an 
H2S training program to meet the requirements of this 
section:
    (i) Before beginning work at the facility; and
    (ii) Each year, within 1 year after completion of the previous 
class.
    (2) What training documentation do I need? For each individual 
working on the platform, either:
    (i) You must have documentation of this training at the facility 
where the individual is employed; or
    (ii) The employee must carry a training completion card.
    (3) What training do I need to give to visitors and employees 
previously trained on another facility?
    (i) Trained employees or contractors transferred from another 
facility must attend a supplemental briefing on your H2S 
equipment and procedures before beginning duty at your facility;
    (ii) Visitors who will remain on your facility more than 24 hours 
must receive the training required for employees by paragraph (g)(4) of 
this section; and
    (iii) Visitors who will depart before spending 24 hours on the 
facility are exempt from the training required for employees, but they 
must, upon arrival, complete a briefing that includes:
    (A) Information on the location and use of an assigned respirator; 
practice in donning and adjusting the assigned respirator; information 
on the safe briefing areas, alarm system, and hazards of H2S 
and SO2; and
    (B) Instructions on their responsibilities in the event of an 
H2S release.
    (4) What training must I provide to all other employees? You must 
train all individuals on your facility on the:
    (i) Hazards of H2S and of SO2 and the 
provisions for personnel safety contained in the H2S 
Contingency Plan;
    (ii) Proper use of safety equipment which the employee may be 
required to use;
    (iii) Location of protective breathing equipment, H2S 
detectors and alarms, ventilation equipment, briefing areas, warning 
systems, evacuation procedures, and the direction of prevailing winds;
    (iv) Restrictions and corrective measures concerning beards, 
spectacles, and contact lenses in conformance with ANSI Z88.2, American 
National Standard for Respiratory Protection (as specified in 
Sec. 250.198);
    (v) Basic first-aid procedures applicable to victims of 
H2S exposure. During all drills and training sessions, you 
must address procedures for rescue and first aid for H2S 
victims;
    (vi) Location of:

[[Page 113]]

    (A) The first-aid kit on the facility;
    (B) Resuscitators; and
    (C) Litter or other device on the facility.
    (vii) Meaning of all warning signals.
    (5) Do I need to post safety information? You must prominently post 
safety information on the facility and on vessels serving the facility 
(i.e., basic first-aid, escape routes, instructions for use of life 
boats, etc.).
    (h) Drills. (1) When and how often do I need to conduct drills on 
H2S safety discussions on the facility? You must:
    (i) Conduct a drill for each person at the facility during normal 
duty hours at least once every 7-day period. The drills must consist of 
a dry-run performance of personnel activities related to assigned jobs.
    (ii) At a safety meeting or other meetings of all personnel, discuss 
drill performance, new H2S considerations at the facility, 
and other updated H2S information at least monthly.
    (2) What documentation do I need? You must keep records of 
attendance for:
    (i) Drilling, well-completion, and well-workover operations at the 
facility until operations are completed; and
    (ii) Production operations at the facility or at the nearest field 
office for 1 year.
    (i) Visual and audible warning systems: (1) How must I install wind 
direction equipment? You must install wind-direction equipment in a 
location visible at all times to individuals on or in the immediate 
vicinity of the facility.
    (2) When do I need to display operational danger signs, display 
flags, or activate visual or audible alarms?
    (i) You must display warning signs at all times on facilities with 
wells capable of producing H2S and on facilities that process 
gas containing H2S in concentrations of 20 ppm or more.
    (ii) In addition to the signs, you must activate audible alarms and 
display flags or activate flashing red lights when atmospheric 
concentration of H2S reaches 20 ppm.
    (3) What are the requirements for signs? Each sign must be a high-
visibility yellow color with black lettering as follows:

------------------------------------------------------------------------
               Letter height                           Wording
------------------------------------------------------------------------
12 inches.................................  Danger.
                                            Poisonous Gas.
                                            Hydrogen Sulfide.
7 inches..................................  Do not approach if red flag
                                             is flying.
(Use appropriate wording at right)........  Do not approach if red
                                             lights are flashing.
------------------------------------------------------------------------

    (4) May I use existing signs? You may use existing signs containing 
the words ``Danger-Hydrogen Sulfide-H2S,'' provided the words 
``Poisonous Gas. Do Not Approach if Red Flag is Flying'' or ``Red Lights 
are Flashing'' in lettering of a minimum of 7 inches in height are 
displayed on a sign immediately adjacent to the existing sign.
    (5) What are the requirements for flashing lights or flags? You must 
activate a sufficient number of lights or hoist a sufficient number of 
flags to be visible to vessels and aircraft. Each light must be of 
sufficient intensity to be seen by approaching vessels or aircraft any 
time it is activated (day or night). Each flag must be red, rectangular, 
a minimum width of 3 feet, and a minimum height of 2 feet.
    (6) What is an audible warning system? An audible warning system is 
a public address system or siren, horn, or other similar warning device 
with a unique sound used only for H2S.
    (7) Are there any other requirements for visual or audible warning 
devices? Yes, you must:
    (i) Illuminate all signs and flags at night and under conditions of 
poor visibility; and
    (ii) Use warning devices that are suitable for the electrical 
classification of the area.
    (8) What actions must I take when the alarms are activated? When the 
warning devices are activated, the designated responsible persons must 
inform personnel of the level of danger and issue instructions on the 
initiation of appropriate protective measures.
    (j) H2S-detection and H2S monitoring 
equipment: (1) What are the requirements for an H2S detection 
system? An H2S detection system must:
    (i) Be capable of sensing a minimum of 10 ppm of H2S in 
the atmosphere; and
    (ii) Activate audible and visual alarms when the concentration of 
H2S in the atmosphere reaches 20 ppm.

[[Page 114]]

    (2) Where must I have sensors for drilling, well-completion, and 
well-workover operations? You must locate sensors at the:
    (i) Bell nipple;
    (ii) Mud-return line receiver tank (possum belly);
    (iii) Pipe-trip tank;
    (iv) Shale shaker;
    (v) Well-control fluid pit area;
    (vi) Driller's station;
    (vii) Living quarters; and
    (viii) All other areas where H2S may accumulate.
    (3) Do I need mud sensors? The District Manager may require mud 
sensors in the possum belly in cases where the ambient air sensors in 
the mud-return system do not consistently detect the presence of 
H2S.
    (4) How often must I observe the sensors? During drilling, well-
completion and well-workover operations, you must continuously observe 
the H2S levels indicated by the monitors in the work areas 
during the following operations:
    (i) When you pull a wet string of drill pipe or workover string;
    (ii) When circulating bottoms-up after a drilling break;
    (iii) During cementing operations;
    (iv) During logging operations; and
    (v) When circulating to condition mud or other well-control fluid.
    (5) Where must I have sensors for production operations? On a 
platform where gas containing H2S of 20 ppm or greater is 
produced, processed, or otherwise handled:
    (i) You must have a sensor in rooms, buildings, deck areas, or low-
laying deck areas not otherwise covered by paragraph (j)(2) of this 
section, where atmospheric concentrations of H2S could reach 
20 ppm or more. You must have at least one sensor per 400 square feet of 
deck area or fractional part of 400 square feet;
    (ii) You must have a sensor in buildings where personnel have their 
living quarters;
    (iii) You must have a sensor within 10 feet of each vessel, 
compressor, wellhead, manifold, or pump, which could release enough 
H2S to result in atmospheric concentrations of 20 ppm at a 
distance of 10 feet from the component;
    (iv) You may use one sensor to detect H2S around multiple 
pieces of equipment, provided the sensor is located no more than 10 feet 
from each piece, except that you need to use at least two sensors to 
monitor compressors exceeding 50 horsepower;
    (v) You do not need to have sensors near wells that are shut in at 
the master valve and sealed closed;
    (vi) When you determine where to place sensors, you must consider:
    (A) The location of system fittings, flanges, valves, and other 
devices subject to leaks to the atmosphere; and
    (B) Design factors, such as the type of decking and the location of 
fire walls; and
    (vii) The District Manager may require additional sensors or other 
monitoring capabilities, if warranted by site specific conditions.
    (6) How must I functionally test the H2S Detectors? (i) Personnel 
trained to calibrate the particular H2S detector equipment 
being used must test detectors by exposing them to a known concentration 
in the range of 10 to 30 ppm of H2S.
    (ii) If the results of any functional test are not within 2 ppm or 
10 percent, whichever is greater, of the applied concentration, 
recalibrate the instrument.
    (7) How often must I test my detectors? (i) When conducting 
drilling, drill stem testing, well-completion, or well-workover 
operations in areas classified as H2S present or 
H2S unknown, test all detectors at least once every 24 hours. 
When drilling, begin functional testing before the bit is 1,500 feet 
(vertically) above the potential H2S zone.
    (ii) When conducting production operations, test all detectors at 
least every 14 days between tests.
    (iii) If equipment requires calibration as a result of two 
consecutive functional tests, the District Manager may require that 
H2S-detection and H2S-monitoring equipment be 
functionally tested and calibrated more frequently.
    (8) What documentation must I keep? (i) You must maintain records of 
testing and calibrations (in the drilling or production operations 
report, as applicable) at the facility to show the present status and 
history of each device, including dates and details concerning:

[[Page 115]]

    (A) Installation;
    (B) Removal;
    (C) Inspection;
    (D) Repairs;
    (E) Adjustments; and
    (F) Reinstallation.
    (ii) Records must be available for inspection by BSEE personnel.
    (9) What are the requirements for nearby vessels? If vessels are 
stationed overnight alongside facilities in areas of H2S 
present or H2S unknown, you must equip vessels with an 
H2S-detection system that activates audible and visual alarms 
when the concentration of H2S in the atmosphere reaches 20 
ppm. This requirement does not apply to vessels positioned upwind and at 
a safe distance from the facility in accordance with the positioning 
procedure described in the approved H2S Contingency Plan.
    (10) What are the requirements for nearby facilities? The District 
Manager may require you to equip nearby facilities with portable or 
fixed H2S detector(s) and to test and calibrate those 
detectors. To invoke this requirement, the District Manager will 
consider dispersion modeling results from a possible release to 
determine if 20 ppm H2S concentration levels could be 
exceeded at nearby facilities.
    (11) What must I do to protect against SO2 if I burn gas containing 
H2S? You must:
    (i) Monitor the SO2concentration in the air with portable 
or strategically placed fixed devices capable of detecting a minimum of 
2 ppm of SO2;
    (ii) Take readings at least hourly and at any time personnel detect 
SO2 odor or nasal irritation;
    (iii) Implement the personnel protective measures specified in the 
H2S Contingency Plan if the SO2 concentration in 
the work area reaches 2 ppm; and
    (iv) Calibrate devices every 3 months if you use fixed or portable 
electronic sensing devices to detect SO2.
    (12) May I use alternative measures? You may follow alternative 
measures instead of those in paragraph (j)(11) of this section if you 
propose and the Regional Supervisor approves the alternative measures.
    (13) What are the requirements for protective-breathing equipment? 
In an area classified as H2S present or H2S 
unknown, you must:
    (i) Provide all personnel, including contractors and visitors on a 
facility, with immediate access to self-contained pressure-demand-type 
respirators with hoseline capability and breathing time of at least 15 
minutes.
    (ii) Design, select, use, and maintain respirators in conformance 
with ANSI Z88.2 (as specified in Sec. 250.198).
    (iii) Make available at least two voice-transmission devices, which 
can be used while wearing a respirator, for use by designated personnel.
    (iv) Make spectacle kits available as needed.
    (v) Store protective-breathing equipment in a location that is 
quickly and easily accessible to all personnel.
    (vi) Label all breathing-air bottles as containing breathing-quality 
air for human use.
    (vii) Ensure that vessels attendant to facilities carry appropriate 
protective-breathing equipment for each crew member. The District 
Manager may require additional protective-breathing equipment on certain 
vessels attendant to the facility.
    (viii) During H2S alerts, limit helicopter flights to and 
from facilities to the conditions specified in the H2S 
Contingency Plan. During authorized flights, the flight crew and 
passengers must use pressure-demand-type respirators. You must train all 
members of flight crews in the use of the particular type(s) of 
respirator equipment made available.
    (ix) As appropriate to the particular operation(s), (production, 
drilling, well-completion or well-workover operations, or any 
combination of them), provide a system of breathing-air manifolds, 
hoses, and masks at the facility and the briefing areas. You must 
provide a cascade air-bottle system for the breathing-air manifolds to 
refill individual protective-breathing apparatus bottles. The cascade 
air-bottle system may be recharged by a high-pressure compressor 
suitable for providing breathing-quality air, provided the compressor 
suction is located in an uncontaminated atmosphere.
    (k) Personnel safety equipment: (1) What additional personnel-safety

[[Page 116]]

equipment do I need? You must ensure that your facility has:
    (i) Portable H2S detectors capable of detecting a 10 ppm 
concentration of H2S in the air available for use by all 
personnel;
    (ii) Retrieval ropes with safety harnesses to retrieve incapacitated 
personnel from contaminated areas;
    (iii) Chalkboards and/or note pads for communication purposes 
located on the rig floor, shale-shaker area, the cement-pump rooms, 
well-bay areas, production processing equipment area, gas compressor 
area, and pipeline-pump area;
    (iv) Bull horns and flashing lights; and
    (v) At least three resuscitators on manned facilities, and a number 
equal to the personnel on board, not to exceed three, on normally 
unmanned facilities, complete with face masks, oxygen bottles, and spare 
oxygen bottles.
    (2) What are the requirements for ventilation equipment? You must:
    (i) Use only explosion-proof ventilation devices;
    (ii) Install ventilation devices in areas where H2S or 
SO2 may accumulate; and
    (iii) Provide movable ventilation devices in work areas. The movable 
ventilation devices must be multidirectional and capable of dispersing 
H2S or SO2 vapors away from working personnel.
    (3) What other personnel safety equipment do I need? You must have 
the following equipment readily available on each facility:
    (i) A first-aid kit of appropriate size and content for the number 
of personnel on the facility; and
    (ii) At least one litter or an equivalent device.
    (l) Do I need to notify BSEE in the event of an H2S release? You 
must notify BSEE without delay in the event of a gas release which 
results in a 15-minute time-weighted average atmospheric concentration 
of H2S of 20 ppm or more anywhere on the OCS facility. You 
must report these gas releases to the District Manager immediately by 
oral communication, with a written follow-up report within 15 days, 
pursuant to Secs. 250.188 through 250.190.
    (m) Do I need to use special drilling, completion and workover 
fluids or procedures? When working in an area classified as 
H2S present or H2S unknown:
    (1) You may use either water- or oil-base muds in accordance with 
Sec. 250.300(b)(1).
    (2) If you use water-base well-control fluids, and if ambient air 
sensors detect H2S, you must immediately conduct either the 
Garrett-Gas-Train test or a comparable test for soluble sulfides to 
confirm the presence of H2S.
    (3) If the concentration detected by air sensors in over 20 ppm, 
personnel conducting the tests must don protective-breathing equipment 
conforming to paragraph (j)(13) of this section.
    (4) You must maintain on the facility sufficient quantities of 
additives for the control of H2S, well-control fluid pH, and 
corrosion equipment.
    (i) Scavengers. You must have scavengers for control of 
H2S available on the facility. When H2S is 
detected, you must add scavengers as needed. You must suspend drilling 
until the scavenger is circulated throughout the system.
    (ii) Control pH. You must add additives for the control of pH to 
water-base well-control fluids in sufficient quantities to maintain pH 
of at least 10.0.
    (iii) Corrosion inhibitors. You must add additives to the well-
control fluid system as needed for the control of corrosion.
    (5) You must degas well-control fluids containing H2S at 
the optimum location for the particular facility. You must collect the 
gases removed and burn them in a closed flare system conforming to 
paragraph (q)(6) of this section.
    (n) What must I do in the event of a kick? In the event of a kick, 
you must use one of the following alternatives to dispose of the well-
influx fluids giving consideration to personnel safety, possible 
environmental damage, and possible facility well-equipment damage:
    (1) Contain the well-fluid influx by shutting in the well and 
pumping the fluids back into the formation.
    (2) Control the kick by using appropriate well-control techniques to 
prevent formation fracturing in an open hole within the pressure limits 
of the

[[Page 117]]

well equipment (drill pipe, work string, casing, wellhead, BOP system, 
and related equipment). The disposal of H2S and other gases 
must be through pressurized or atmospheric mud-separator equipment 
depending on volume, pressure and concentration of H2S. The 
equipment must be designed to recover well-control fluids and burn the 
gases separated from the well-control fluid. The well-control fluid must 
be treated to neutralize H2S and restore and maintain the 
proper quality.
    (o) Well testing in a zone known to contain H2S. When testing a well 
in a zone with H2S present, you must do all of the following:
    (1) Before starting a well test, conduct safety meetings for all 
personnel who will be on the facility during the test. At the meetings, 
emphasize the use of protective-breathing equipment, first-aid 
procedures, and the Contingency Plan. Only competent personnel who are 
trained and are knowledgeable of the hazardous effects of H2S 
must be engaged in these tests.
    (2) Perform well testing with the minimum number of personnel in the 
immediate vicinity of the rig floor and with the appropriate test 
equipment to safely and adequately perform the test. During the test, 
you must continuously monitor H2S levels.
    (3) Not burn produced gases except through a flare which meets the 
requirements of paragraph (q)(6) of this section. Before flaring gas 
containing H2S, you must activate SO2 monitoring 
equipment in accordance with paragraph (j)(11) of this section. If you 
detect SO2 in excess of 2 ppm, you must implement the 
personnel protective measures in your H2S Contingency Plan, 
required by paragraph (f) of this section. You must also follow the 
requirements of Sec. 250.1164. You must pipe gases from stored test 
fluids into the flare outlet and burn them.
    (4) Use downhole test tools and wellhead equipment suitable for 
H2S service.
    (5) Use tubulars suitable for H2S service. You must not 
use drill pipe for well testing without the prior approval of the 
District Manager. Water cushions must be thoroughly inhibited in order 
to prevent H2S attack on metals. You must flush the test 
string fluid treated for this purpose after completion of the test.
    (6) Use surface test units and related equipment that is designed 
for H2S service.
    (p) Metallurgical properties of equipment. When operating in a zone 
with H2S present, you must use equipment that is constructed 
of materials with metallurgical properties that resist or prevent 
sulfide stress cracking (also known as hydrogen embrittlement, stress 
corrosion cracking, or H2S embrittlement), chloride-stress 
cracking, hydrogen-induced cracking, and other failure modes. You must 
do all of the following:
    (1) Use tubulars and other equipment, casing, tubing, drill pipe, 
couplings, flanges, and related equipment that is designed for 
H2S service.
    (2) Use BOP system components, wellhead, pressure-control equipment, 
and related equipment exposed to H2S-bearing fluids in 
conformance with NACE Standard MR0175-03 (as specified in Sec. 250.198).
    (3) Use temporary downhole well-security devices such as retrievable 
packers and bridge plugs that are designed for H2S service.
    (4) When producing in zones bearing H2S, use equipment 
constructed of materials capable of resisting or preventing sulfide 
stress cracking.
    (5) Keep the use of welding to a minimum during the installation or 
modification of a production facility. Welding must be done in a manner 
that ensures resistance to sulfide stress cracking.
    (q) General requirements when operating in an H2S zone: (1) Coring 
operations. When you conduct coring operations in H2S-bearing 
zones, all personnel in the working area must wear protective-breathing 
equipment at least 10 stands in advance of retrieving the core barrel. 
Cores to be transported must be sealed and marked for the presence of 
H2S.
    (2) Logging operations. You must treat and condition well-control 
fluid in use for logging operations to minimize the effects of 
H2S on the logging equipment.
    (3) Stripping operations. Personnel must monitor displaced well-
control fluid returns and wear protective-

[[Page 118]]

breathing equipment in the working area when the atmospheric 
concentration of H2S reaches 20 ppm or if the well is under 
pressure.
    (4) Gas-cut well-control fluid or well kick from H2S-bearing zone. 
If you decide to circulate out a kick, personnel in the working area 
during bottoms-up and extended-kill operations must wear protective-
breathing equipment.
    (5) Drill- and workover-string design and precautions. Drill- and 
workover-strings must be designed consistent with the anticipated depth, 
conditions of the hole, and reservoir environment to be encountered. You 
must minimize exposure of the drill- or workover-string to high stresses 
as much as practical and consistent with well conditions. Proper 
handling techniques must be taken to minimize notching and stress 
concentrations. Precautions must be taken to minimize stresses caused by 
doglegs, improper stiffness ratios, improper torque, whip, abrasive wear 
on tool joints, and joint imbalance.
    (6) Flare system. The flare outlet must be of a diameter that allows 
easy nonrestricted flow of gas. You must locate flare line outlets on 
the downside of the facility and as far from the facility as is 
feasible, taking into account the prevailing wind directions, the wake 
effects caused by the facility and adjacent structure(s), and the height 
of all such facilities and structures. You must equip the flare outlet 
with an automatic ignition system including a pilot-light gas source or 
an equivalent system. You must have alternate methods for igniting the 
flare. You must pipe to the flare system used for H2S all 
vents from production process equipment, tanks, relief valves, burst 
plates, and similar devices.
    (7) Corrosion mitigation. You must use effective means of monitoring 
and controlling corrosion caused by acid gases (H2S and 
CO2) in both the downhole and surface portions of a 
production system. You must take specific corrosion monitoring and 
mitigating measures in areas of unusually severe corrosion where 
accumulation of water and/or higher concentration of H2S 
exists.
    (8) Wireline lubricators. Lubricators which may be exposed to fluids 
containing H2S must be of H2S-resistant materials.
    (9) Fuel and/or instrument gas. You must not use gas containing 
H2S for instrument gas. You must not use gas containing 
H2S for fuel gas without the prior approval of the District 
Manager.
    (10) Sensing lines and devices. Metals used for sensing line and 
safety-control devices which are necessarily exposed to H2S-
bearing fluids must be constructed of H2S-corrosion resistant 
materials or coated so as to resist H2S corrosion.
    (11) Elastomer seals. You must use H2S-resistant 
materials for all seals which may be exposed to fluids containing 
H2S.
    (12) Water disposal. If you dispose of produced water by means other 
than subsurface injection, you must submit to the District Manager an 
analysis of the anticipated H2S content of the water at the 
final treatment vessel and at the discharge point. The District Manager 
may require that the water be treated for removal of H2S. The 
District Manager may require the submittal of an updated analysis if the 
water disposal rate or the potential H2S content increases.
    (13) Deck drains. You must equip open deck drains with traps or 
similar devices to prevent the escape of H2S gas into the 
atmosphere.
    (14) Sealed voids. You must take precautions to eliminate sealed 
spaces in piping designs (e.g., slip-on flanges, reinforcing pads) which 
can be invaded by atomic hydrogen when H2S is present.



            Subpart E_Oil and Gas Well-Completion Operations



Sec. 250.500  General requirements.

    Well-completion operations must be conducted in a manner to protect 
against harm or damage to life (including fish and other aquatic life), 
property, natural resources of the OCS, including any mineral deposits 
(in areas leased and not leased), the National security or defense, or 
the marine, coastal, or human environment. In addition to the 
requirements of this subpart,

[[Page 119]]

you must also follow the applicable requirements of subpart G of this 
part.

[81 FR 26021, Apr. 29, 2016]



Sec. 250.501  Definition.

    When used in this subpart, the following term shall have the meaning 
given below:
    Well-completion operations means the work conducted to establish the 
production of a well after the production-casing string has been set, 
cemented, and pressure-tested.



Sec. 250.502  [Reserved]



Sec. 250.503  Emergency shutdown system.

    When well-completion operations are conducted on a platform where 
there are other hydrocarbon-producing wells or other hydrocarbon flow, 
an emergency shutdown system (ESD) manually controlled station shall be 
installed near the driller's console or well-servicing unit operator's 
work station.



Sec. 250.504  Hydrogen sulfide.

    When a well-completion operation is conducted in zones known to 
contain hydrogen sulfide (H2S) or in zones where the presence 
of H2S is unknown (as defined in Sec. 250.490 of this part), 
the lessee shall take appropriate precautions to protect life and 
property on the platform or completion unit, including, but not limited 
to operations such as blowing the well down, dismantling wellhead 
equipment and flow lines, circulating the well, swabbing, and pulling 
tubing, pumps, and packers. The lessee shall comply with the 
requirements in Sec. 250.490 of this part as well as the appropriate 
requirements of this subpart.



Sec. 250.505  Subsea completions.

    No subsea well completion shall be commenced until the lessee 
obtains written approval from the District Manager in accordance with 
Sec. 250.513 of this part. That approval shall be based upon a case-by-
case determination that the proposed equipment and procedures will 
adequately control the well and permit safe production operations.



Secs. 250.506-250.508  [Reserved]



Sec. 250.509  Well-completion structures on fixed platforms.

    Derricks, masts, substructures, and related equipment shall be 
selected, designed, installed, used, and maintained so as to be adequate 
for the potential loads and conditions of loading that may be 
encountered during the proposed operations. Prior to moving a well-
completion rig or equipment onto a platform, the lessee shall determine 
the structural capability of the platform to safely support the 
equipment and proposed operations, taking into consideration the 
corrosion protection, age of platform, and previous stresses to the 
platform.



Sec. 250.510  Diesel engine air intakes.

    Diesel engine air intakes must be equipped with a device to shut 
down the diesel engine in the event of runaway. Diesel engines that are 
continuously attended must be equipped with either remote operated 
manual or automatic-shutdown devices. Diesel engines that are not 
continuously attended must be equipped with automatic-shutdown devices.



Sec. 250.511  Traveling-block safety device.

    All units being used for well-completion operations that have both a 
traveling block and a crown block must be equipped with a safety device 
that is designed to prevent the traveling block from striking the crown 
block. The device must be checked for proper operation weekly and after 
each drill-line slipping operation. The results of the operational check 
must be entered in the operations log.



Sec. 250.512  Field well-completion rules.

    When geological and engineering information available in a field 
enables the District Manager to determine specific operating 
requirements, field well-completion rules may be established on the 
District Manager's initiative or in response to a request from a lessee. 
Such rules may modify the specific requirements of this subpart. After 
field well-completion rules have been established, well-completion 
operations in the field shall be conducted in

[[Page 120]]

accordance with such rules and other requirements of this subpart. Field 
well-completion rules may be amended or canceled for cause at any time 
upon the initiative of the District Manager or upon the request of a 
lessee.



Sec. 250.513  Approval and reporting of well-completion operations.

    (a) No well-completion operation may begin until the lessee receives 
written approval from the District Manager. If completion is planned and 
the data are available at the time you submit the Application for Permit 
to Drill and Supplemental APD Information Sheet (Forms BSEE-0123 and 
BSEE-0123S), you may request approval for a well-completion on those 
forms (see Secs. 250.410 through 250.418 of this part). If the District 
Manager has not approved the completion or if the completion objective 
or plans have significantly changed, you must submit an Application for 
Permit to Modify (Form BSEE-0124) for approval of such operations.
    (b) You must submit the following with Form BSEE-0124 (or with Form 
BSEE-0123; Form BSEE-0123S):
    (1) A brief description of the well-completion procedures to be 
followed, a statement of the expected surface pressure, and type and 
weight of completion fluids;
    (2) A schematic drawing of the well showing the proposed producing 
zone(s) and the subsurface well-completion equipment to be used;
    (3) For multiple completions, a partial electric log showing the 
zones proposed for completion, if logs have not been previously 
submitted;
    (4) All applicable information required in Sec. 250.731.
    (5) When the well-completion is in a zone known to contain 
H2S or a zone where the presence of H2S is 
unknown, information pursuant to Sec. 250.490 of this part; and
    (6) Payment of the service fee listed in Sec. 250.125.
    (c) Within 30 days after completion, you must submit to the District 
Manager an End of Operations Report (Form BSEE-0125), including a 
schematic of the tubing and subsurface equipment.
    (d) You must submit public information copies of Form BSEE-0125 
according to Sec. 250.186.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50894, Aug. 22, 2012; 
81 FR 26021, Apr. 29, 2016]



Sec. 250.514  Well-control fluids, equipment, and operations.

    (a) Well-control fluids, equipment, and operations shall be 
designed, utilized, maintained, and/or tested as necessary to control 
the well in foreseeable conditions and circumstances, including 
subfreezing conditions. The well shall be continuously monitored during 
well-completion operations and shall not be left unattended at any time 
unless the well is shut in and secured.
    (b) The following well-control-fluid equipment shall be installed, 
maintained, and utilized:
    (1) A fill-up line above the uppermost BOP;
    (2) A well-control, fluid-volume measuring device for determining 
fluid volumes when filling the hole on trips; and
    (3) A recording mud-pit-level indicator to determine mud-pit-volume 
gains and losses. This indicator shall include both a visual and an 
audible warning device.
    (c) When coming out of the hole with drill pipe, the annulus shall 
be filled with well-control fluid before the change in such fluid level 
decreases the hydrostatic pressure 75 pounds per square inch (psi) or 
every five stands of drill pipe, whichever gives a lower decrease in 
hydrostatic pressure. The number of stands of drill pipe and drill 
collars that may be pulled prior to filling the hole and the equivalent 
well-control fluid volume shall be calculated and posted near the 
operator's station. A mechanical, volumetric, or electronic device for 
measuring the amount of well-control fluid required to fill the hole 
shall be utilized.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50894, Aug. 22, 2012; 
81 FR 26021, Apr. 29, 2016]

[[Page 121]]



Secs. 250.515-250.517  [Reserved]



Sec. 250.518  Tubing and wellhead equipment.

    (a) No tubing string shall be placed in service or continue to be 
used unless such tubing string has the necessary strength and pressure 
integrity and is otherwise suitable for its intended use.
    (b) When the tree is installed, you must equip wells to monitor for 
casing pressure according to the following chart:

------------------------------------------------------------------------
     If you . . .        you must equip . . .   so you can monitor . . .
------------------------------------------------------------------------
(1) fixed platform      the wellhead,          all annuli (A, B, C, D,
 wells,                                         etc., annuli).
(2) subsea wells,       the tubing head,       the production casing
                                                annulus (A annulus).
(3) hybrid * wells,     the surface wellhead,  all annuli at the surface
                                                (A and B riser annuli).
                                                If the production casing
                                                below the mudline and
                                                the production casing
                                                riser above the mudline
                                                are pressure isolated
                                                from each other,
                                                provisions must be made
                                                to monitor the
                                                production casing below
                                                the mudline for casing
                                                pressure.
------------------------------------------------------------------------
* Characterized as a well drilled with a subsea wellhead and completed
  with a surface casing head, a surface tubing head, a surface tubing
  hanger, and a surface christmas tree.

    (c) Wellhead, tree, and related equipment shall have a pressure 
rating greater than the shut-in tubing pressure and shall be designed, 
installed, used, maintained, and tested so as to achieve and maintain 
pressure control. New wells completed as flowing or gas-lift wells shall 
be equipped with a minimum of one master valve and one surface safety 
valve, installed above the master valve, in the vertical run of the 
tree.
    (d) Subsurface safety equipment must be installed, maintained, and 
tested in compliance with the applicable sections in Secs. 250.810 
through 250.839.
    (e) When installed, packers and bridge plugs must meet the 
following:
    (1) All permanently installed packers and bridge plugs must comply 
with API Spec. 11D1 (as incorporated by reference in Sec. 250.198);
    (2) The production packer must be set at a depth that will allow for 
a column of weighted fluids to be placed above the packer that will 
exert a hydrostatic force greater than or equal to the force created by 
the reservoir pressure below the packer;
    (3) The production packer must be set as close as practically 
possible to the perforated interval; and
    (4) The production packer must be set at a depth that is within the 
cemented interval of the selected casing section.
    (f) Your APM must include a description and calculations for how you 
determined the production packer setting depth.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012; 
81 FR 26021, Apr. 29, 2016; 81 FR 61918, Sept. 7, 2016]

                       Casing Pressure Management



Sec. 250.519  What are the requirements for casing pressure management?

    Once you install your wellhead, you must meet the casing pressure 
management requirements of API RP 90 (as incorporated by reference in 
Sec. 250.198) and the requirements of Secs. 250.519 through 250.530. If 
there is a conflict between API RP 90 and the casing pressure 
requirements of this subpart, you must follow the requirements of this 
subpart.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec. 250.520  How often do I have to monitor for casing pressure?

    You must monitor for casing pressure in your well according to the 
following table:

----------------------------------------------------------------------------------------------------------------
                                                                                with a minimum one pressure data
               If you have . . .                    you must monitor . . .          point recorded per . . .
----------------------------------------------------------------------------------------------------------------
(a) fixed platform wells,                       monthly,                       month for each casing.

[[Page 122]]

 
(b) subsea wells,                               continuously,                  day for the production casing.
(c) hybrid wells,                               continuously,                  day for each riser and/or the
                                                                                production casing.
(d) wells operating under a casing pressure     daily,                         day for each casing.
 request on a manned fixed platform,
(e) wells operating under a casing pressure     weekly,                        week for each casing.
 request on an unmanned fixed platform,
----------------------------------------------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec. 250.521  When do I have to perform a casing diagnostic test?

    (a) You must perform a casing diagnostic test within 30 days after 
first observing or imposing casing pressure according to the following 
table:

------------------------------------------------------------------------
                                              you must perform a casing
            If you have a . . .               diagnostic test if . . .
------------------------------------------------------------------------
(1) fixed platform well,                    the casing pressure is
                                             greater than 100 psig.
(2) subsea well,                            the measurable casing
                                             pressure is greater than
                                             the external hydrostatic
                                             pressure plus 100 psig
                                             measured at the subsea
                                             wellhead.
(3) hybrid well,                            a riser or the production
                                             casing pressure is greater
                                             than 100 psig measured at
                                             the surface.
------------------------------------------------------------------------

    (b) You are exempt from performing a diagnostic pressure test for 
the production casing on a well operating under active gas lift.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec. 250.522  How do I manage the thermal effects caused by initial
production on a newly completed or recompleted well?

    A newly completed or recompleted well often has thermal casing 
pressure during initial startup. Bleeding casing pressure during the 
startup process is considered a normal and necessary operation to manage 
thermal casing pressure; therefore, you do not need to evaluate these 
operations as a casing diagnostic test. After 30 days of continuous 
production, the initial production startup operation is complete and you 
must perform casing diagnostic testing as required in Secs. 250.520 and 
250.522.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec. 250.523  When do I have to repeat casing diagnostic testing?

    Casing diagnostic testing must be repeated according to the 
following table:

------------------------------------------------------------------------
                                             you must repeat diagnostic
                When . . .                          testing . . .
------------------------------------------------------------------------
(a) your casing pressure request approved   immediately.
 term has expired,
(b) your well, previously on gas lift, has  immediately on the
 been shut-in or returned to flowing         production casing (A
 status without gas lift for more than 180   annulus). The production
 days,                                       casing (A annulus) of wells
                                             on active gas lift are
                                             exempt from diagnostic
                                             testing.
(c) your casing pressure request becomes    within 30 days.
 invalid,
(d) a casing or riser has an increase in    within 30 days.
 pressure greater than 200 psig over the
 previous casing diagnostic test,
(e) after any corrective action has been    within 30 days.
 taken to remediate undesirable casing
 pressure, either as a result of a casing
 pressure request denial or any other
 action,
(f) your fixed platform well production     once per year, not to exceed
 casing (A annulus) has pressure exceeding   12 months between tests.
 10 percent of its minimum internal yield
 pressure (MIYP), except for production
 casings on active gas lift,
(g) your fixed platform well's outer        once every 5 years, at a
 casing (B, C, D, etc., annuli) has a        minimum.
 pressure exceeding 20 percent of its
 MIYP,
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

[[Page 123]]



Sec. 250.524  How long do I keep records of casing pressure and 
diagnostic tests?

    Records of casing pressure and diagnostic tests must be kept at the 
field office nearest the well for a minimum of 2 years. The last casing 
diagnostic test for each casing or riser must be retained at the field 
office nearest the well until the well is abandoned.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec. 250.525  When am I required to take action from my casing
diagnostic test?

    You must take action if you have any of the following conditions:
    (a) Any fixed platform well with a casing pressure exceeding its 
maximum allowable wellhead operating pressure (MAWOP);
    (b) Any fixed platform well with a casing pressure that is greater 
than 100 psig and that cannot bleed to 0 psig through a \1/2\-inch 
needle valve within 24 hours, or is not bled to 0 psig during a casing 
diagnostic test;
    (c) Any well that has demonstrated tubing/casing, tubing/riser, 
casing/casing, riser/casing, or riser/riser communication;
    (d) Any well that has sustained casing pressure (SCP) and is bled 
down to prevent it from exceeding its MAWOP, except during initial 
startup operations described in Sec. 250.521;
    (e) Any hybrid well with casing or riser pressure exceeding 100 
psig; or
    (f) Any subsea well with a casing pressure 100 psig greater than the 
external hydrostatic pressure at the subsea wellhead.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec. 250.526  What do I submit if my casing diagnostic test requires
action?

    Within 14 days after you perform a casing diagnostic test requiring 
action under Sec. 250.524:

----------------------------------------------------------------------------------------------------------------
You must submit either . .                              and it must include . . .
             .               to the appropriate . . .                                   You must also . . .
----------------------------------------------------------------------------------------------------------------
(a) a notification of       District Manager and copy   requirements under Sec. submit an Application for
 corrective action; or,      the Regional Supervisor,    250.526,                   Permit to Modify or
                             Field Operations,                                      Corrective Action Plan
                                                                                    within 30 days of the
                                                                                    diagnostic test.
(b) a casing pressure       Regional Supervisor, Field  requirements under Sec. .............................
 request,                    Operations,                 250.527.
----------------------------------------------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec. 250.527  What must I include in my notification of corrective action?

    The following information must be included in the notification of 
corrective action:
    (a) Lessee or Operator name;
    (b) Area name and OCS block number;
    (c) Well name and API number; and
    (d) Casing diagnostic test data.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec. 250.528  What must I include in my casing pressure request?

    The following information must be included in the casing pressure 
request:
    (a) API number;
    (b) Lease number;
    (c) Area name and OCS block number;
    (d) Well number;
    (e) Company name and mailing address;
    (f) All casing, riser, and tubing sizes, weights, grades, and MIYP;
    (g) All casing/riser calculated MAWOPs;
    (h) All casing/riser pre-bleed down pressures;
    (i) Shut-in tubing pressure;
    (j) Flowing tubing pressure;
    (k) Date and the calculated daily production rate during last well 
test (oil, gas, basic sediment, and water);
    (l) Well status (shut-in, temporarily abandoned, producing, 
injecting, or gas lift);
    (m) Well type (dry tree, hybrid, or subsea);

[[Page 124]]

    (n) Date of diagnostic test;
    (o) Well schematic;
    (p) Water depth;
    (q) Volumes and types of fluid bled from each casing or riser 
evaluated;
    (r) Type of diagnostic test performed:
    (1) Bleed down/buildup test;
    (2) Shut-in the well and monitor the pressure drop test;
    (3) Constant production rate and decrease the annular pressure test;
    (4) Constant production rate and increase the annular pressure test;
    (5) Change the production rate and monitor the casing pressure test; 
and
    (6) Casing pressure and tubing pressure history plot;
    (s) The casing diagnostic test data for all casing exceeding 100 
psig;
    (t) Associated shoe strengths for casing shoes exposed to annular 
fluids;
    (u) Concentration of any H2S that may be present;
    (v) Whether the structure on which the well is located is manned or 
unmanned;
    (w) Additional comments; and
    (x) Request date.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec. 250.529  What are the terms of my casing pressure request?

    Casing pressure requests are approved by the Regional Supervisor, 
Field Operations, for a term to be determined by the Regional Supervisor 
on a case-by-case basis. The Regional Supervisor may impose additional 
restrictions or requirements to allow continued operation of the well.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec. 250.530  What if my casing pressure request is denied?

    (a) If your casing pressure request is denied, then the operating 
company must submit plans for corrective action to the respective 
District Manager within 30 days of receiving the denial. The District 
Manager will establish a specific time period in which this corrective 
action will be taken. You must notify the respective District Manager 
within 30 days after completion of your corrected action.
    (b) You must submit the casing diagnostic test data to the 
appropriate Regional Supervisor, Field Operations, within 14 days of 
completion of the diagnostic test required under Sec. 250.522(e).

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



Sec. 250.531  When does my casing pressure request approval become
invalid?

    A casing pressure request becomes invalid when:
    (a) The casing or riser pressure increases by 200 psig over the 
approved casing pressure request pressure;
    (b) The approved term ends;
    (c) The well is worked-over, side-tracked, redrilled, recompleted, 
or acid stimulated;
    (d) A different casing or riser on the same well requires a casing 
pressure request; or
    (e) A well has more than one casing operating under a casing 
pressure request and one of the casing pressure requests become invalid, 
then all casing pressure requests for that well become invalid.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]



             Subpart F_Oil and Gas Well-Workover Operations



Sec. 250.600  General requirements.

    Well-workover operations must be conducted in a manner to protect 
against harm or damage to life (including fish and other aquatic life), 
property, natural resources of the Outer Continental Shelf (OCS) 
including any mineral deposits (in areas leased and not leased), the 
National security or defense, or the marine, coastal, or human 
environment. In addition to the requirements of this subpart, you must 
also follow the applicable requirements of subpart G of this part.

[81 FR 26021, Apr. 29, 2016]



Sec. 250.601  Definitions.

    When used in this subpart, the following terms shall have the 
meanings given below:
    Expected surface pressure means the highest pressure predicted to be 
exerted upon the surface of a well. In calculating expected surface 
pressure, you

[[Page 125]]

must consider reservoir pressure as well as applied surface pressure.
    Routine operations mean any of the following operations conducted on 
a well with the tree installed:
    (a) Cutting paraffin;
    (b) Removing and setting pump-through-type tubing plugs, gas-lift 
valves, and subsurface safety valves which can be removed by wireline 
operations;
    (c) Bailing sand;
    (d) Pressure surveys;
    (e) Swabbing;
    (f) Scale or corrosion treatment;
    (g) Caliper and gauge surveys;
    (h) Corrosion inhibitor treatment;
    (i) Removing or replacing subsurface pumps;
    (j) Through-tubing logging (diagnostics);
    (k) Wireline fishing; and
    (l) Setting and retrieving other subsurface flow-control devices.
    Workover operations mean the work conducted on wells after the 
initial completion for the purpose of maintaining or restoring the 
productivity of a well.



Sec. 250.602  [Reserved]



Sec. 250.603  Emergency shutdown system.

    When well-workover operations are conducted on a well with the tree 
removed, an emergency shutdown system (ESD) manually controlled station 
shall be installed near the driller's console or well-servicing unit 
operator's work station, except when there is no other hydrocarbon-
producing well or other hydrocarbon flow on the platform.



Sec. 250.604  Hydrogen sulfide.

    When a well-workover operation is conducted in zones known to 
contain hydrogen sulfide (H2S) or in zones where the presence 
of H2S is unknown (as defined in Sec. 250.490 of this part), 
the lessee shall take appropriate precautions to protect life and 
property on the platform or rig, including but not limited to operations 
such as blowing the well down, dismantling wellhead equipment and flow 
lines, circulating the well, swabbing, and pulling tubing, pumps and 
packers. The lessee shall comply with the requirements in Sec. 250.490 
of this part as well as the appropriate requirements of this subpart.



Sec. 250.605  Subsea workovers.

    No subsea well-workover operation including routine operations shall 
be commenced until the lessee obtains written approval from the District 
Manager in accordance with Sec. 250.613 of this part. That approval 
shall be based upon a case-by-case determination that the proposed 
equipment and procedures will maintain adequate control of the well and 
permit continued safe production operations.



Secs. 250.606-250.608  [Reserved]



Sec. 250.609  Well-workover structures on fixed platforms.

    Derricks, masts, substructures, and related equipment shall be 
selected, designed, installed, used, and maintained so as to be adequate 
for the potential loads and conditions of loading that may be 
encountered during the operations proposed. Prior to moving a well-
workover rig or well-servicing equipment onto a platform, the lessee 
shall determine the structural capability of the platform to safely 
support the equipment and proposed operations, taking into consideration 
the corrosion protection, age of the platform, and previous stresses to 
the platform.



Sec. 250.610  Diesel engine air intakes.

    You must equip diesel engine air intakes with a device to shut down 
the diesel engine in the event of runaway. Diesel engines that are 
continuously attended must be equipped with remotely operated, manual, 
or automatic shutdown devices. Diesel engines that are not continuously 
attended must be equipped with automatic shutdown devices.

[81 FR 36149, June 6, 2016]



Sec. 250.611  Traveling-block safety device.

    You must equip all units being used for well-workover operations 
that have both a traveling block and a crown block with a safety device 
that is designed to prevent the traveling block from striking the crown 
block. You

[[Page 126]]

must check the device for proper operation weekly and after each drill-
line slipping operation. You must enter the results of the operational 
check in the operations log.

[81 FR 36149, June 6, 2016]



Sec. 250.612  Field well-workover rules.

    When geological and engineering information available in a field 
enables the District Manager to determine specific operating 
requirements, field well-workover rules may be established on the 
District Manager's initiative or in response to a request from a lessee. 
Such rules may modify the specific requirements of this subpart. After 
field well-workover rules have been established, well-workover 
operations in the field shall be conducted in accordance with such rules 
and other requirements of this subpart. Field well-workover rules may be 
amended or canceled for cause at any time upon the initiative of the 
District Manager or upon the request of a lessee.



Sec. 250.613  Approval and reporting for well-workover operations.

    (a) No well-workover operation except routine ones, as defined in 
Sec. 250.601 of this part, shall begin until the lessee receives written 
approval from the District Manager. Approval for these operations must 
be requested on Form BSEE-0124, Application for Permit to Modify.
    (b) You must submit the following with Form BSEE-0124:
    (1) A brief description of the well-workover procedures to be 
followed, a statement of the expected surface pressure, and type and 
weight of workover fluids;
    (2) When changes in existing subsurface equipment are proposed, a 
schematic drawing of the well showing the zone proposed for workover and 
the workover equipment to be used;
    (3) All information required in Sec. 250.731.
    (4) Where the well-workover is in a zone known to contain 
H2S or a zone where the presence of H2S is unknown, 
information pursuant to Sec. 250.490 of this part; and
    (5) Payment of the service fee listed in Sec. 250.125.
    (c) The following additional information shall be submitted with 
Form BSEE-0124 if completing to a new zone is proposed:
    (1) Reason for abandonment of present producing zone including 
supportive well test data, and
    (2) A statement of anticipated or known pressure data for the new 
zone.
    (d) Within 30 days after completing the well-workover operation, 
except routine operations, Form BSEE-0124, Application for Permit to 
Modify, shall be submitted to the District Manager, showing the work as 
performed. In the case of a well-workover operation resulting in the 
initial recompletion of a well into a new zone, a Form BSEE-0125, End of 
Operations Report, shall be submitted to the District Manager and shall 
include a new schematic of the tubing subsurface equipment if any 
subsurface equipment has been changed.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50895, Aug. 22, 2012; 
81 FR 26021, Apr. 29, 2016]



Sec. 250.614  Well-control fluids, equipment, and operations.

    The following requirements apply during all well-workover 
    operations 
with the tree removed:
    (a) Well-control fluids, equipment, and operations shall be 
designed, utilized, maintained, and/or tested as necessary to control 
the well in foreseeable conditions and circumstances, including 
subfreezing conditions. The well shall be continuously monitored during 
well-workover operations and shall not be left unattended at anytime 
unless the well is shut in and secured.
    (b) When coming out of the hole with drill pipe or a workover 
string, the annulus shall be filled with well-control fluid before the 
change in such fluid level decreases the hydrostatic pressure 75 pounds 
per square inch (psi) or every five stands of drill pipe or workover 
string, whichever gives a lower decrease in hydrostatic pressure. The 
number of stands of drill pipe or workover string and drill collars that 
may be pulled prior to filling the hole and the equivalent well-control 
fluid volume shall be calculated and posted near the operator's station. 
A mechanical, volumetric, or electronic device

[[Page 127]]

for measuring the amount of well-control fluid required to fill the hold 
shall be utilized.
    (c) The following well-control-fluid equipment shall be installed, 
maintained, and utilized:
    (1) A fill-up line above the uppermost BOP;
    (2) A well-control, fluid-volume measuring device for determining 
fluid volumes when filling the hole on trips; and
    (3) A recording mud-pit-level indicator to determine mud-pit-volume 
gains and losses. This indicator shall include both a visual and an 
audible warning device.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50895, Aug. 22, 2012; 
81 FR 26021, Apr. 29, 2016]



Sec. 250.615  [Reserved]



Sec. 250.616  Coiled tubing and snubbing operations.

    (a) For coiled tubing operations with the production tree in place, 
you must meet the following minimum requirements for the BOP system:
    (1) BOP system components must be in the following order from the 
top down:

------------------------------------------------------------------------
                                 BOP system when
  BOP system when expected      expected surface    BOP system for wells
 surface pressures are less       pressures are      with returns taken
 than or equal to 3,500 psi    greater than 3,500   through an outlet on
                                       psi              the BOP stack
------------------------------------------------------------------------
Stripper or annular-type      Stripper or annular-  Stripper or annular-
 well control component.       type well control     type well control
                               component.            component.
Hydraulically-operated blind  Hydraulically-        Hydraulically-
 rams.                         operated blind rams.  operated blind rams
Hydraulically-operated shear  Hydraulically-        Hydraulically-
 rams.                         operated shear rams.  operated shear
                                                     rams.
Kill line inlet.............  Kill line inlet.....  Kill line inlet.
Hydraulically-operated two-   Hydraulically-        Hydraulically-
 way slip rams.                operated two-way      operated two-way
                               slip rams.            slip rams.
                                                    Hydraulically-
                                                     operated pipe rams.
Hydraulically-operated pipe   Hydraulically-        A flow tee or cross.
 rams.                         operated pipe rams.  Hydraulically-
                              Hydraulically-         operated pipe rams.
                               operated blind-      Hydraulically-
                               shear rams. These     operated blind-
                               rams should be        shear rams on wells
                               located as close to   with surface
                               the tree as           pressures >3,500
                               practical.            psi. As an option,
                                                     the pipe rams can
                                                     be placed below the
                                                     blind-shear rams.
                                                     The blind-shear
                                                     rams should be
                                                     located as close to
                                                     the tree as
                                                     practical.
------------------------------------------------------------------------

    (2) You may use a set of hydraulically-operated combination rams for 
the blind rams and shear rams.
    (3) You may use a set of hydraulically-operated combination rams for 
the hydraulic two-way slip rams and the hydraulically-operated pipe 
rams.
    (4) You must attach a dual check valve assembly to the coiled tubing 
connector at the downhole end of the coiled tubing string for all coiled 
tubing well-workover operations. If you plan to conduct operations 
without downhole check valves, you must describe alternate procedures 
and equipment in Form BSEE-0124, Application for Permit to Modify and 
have it approved by the District Manager.
    (5) You must have a kill line and a separate choke line. You must 
equip each line with two full-opening valves and at least one of the 
valves must be remotely controlled. You may use a manual valve instead 
of the remotely controlled valve on the kill line if you install a check 
valve between the two full-opening manual valves and the pump or 
manifold. The valves must have a working pressure rating equal to or 
greater than the working pressure rating of the connection to which they 
are attached, and you must install them between the well control stack 
and the choke or kill line. For operations with expected surface 
pressures greater than 3,500 psi, the kill line must be connected to a 
pump or manifold. You must not use the kill line inlet on the BOP stack 
for taking fluid returns from the wellbore.
    (6) You must have a hydraulic-actuating system that provides 
sufficient accumulator capacity to close-open-close each component in 
the BOP stack. This cycle must be completed with at least 200 psi above 
the pre-

[[Page 128]]

charge pressure, without assistance from a charging system.
    (7) All connections used in the surface BOP system from the tree to 
the uppermost required ram must be flanged, including the connections 
between the well control stack and the first full-opening valve on the 
choke line and the kill line.
    (b) The minimum BOP-system components for well-workover operations 
with the tree in place and performed by moving tubing or drill pipe in 
or out of a well under pressure utilizing equipment specifically 
designed for that purpose, i.e., snubbing operations, shall include the 
following:
    (1) One set of pipe rams hydraulically operated, and
    (2) Two sets of stripper-type pipe rams hydraulically operated with 
spacer spool.
    (c) An inside BOP or a spring-loaded, back-pressure safety valve and 
an essentially full-opening, work-string safety valve in the open 
position shall be maintained on the rig floor at all times during well-
workover operations when the tree is removed or during well-workover 
operations with the tree installed and using small tubing as the work 
string. A wrench to fit the work-string safety valve shall be readily 
available. Proper connections shall be readily available for inserting 
valves in the work string. The full-opening safety valve is not required 
for coiled tubing or snubbing operations.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50895, Aug. 22, 2012, 
as amended at 81 FR 26021, Apr. 29, 2016]



Secs. 250.617-250.618  [Reserved]



Sec. 250.619  Tubing and wellhead equipment.

    The lessee shall comply with the following requirements during well-
workover operations with the tree removed:
    (a) No tubing string shall be placed in service or continue to be 
used unless such tubing string has the necessary strength and pressure 
integrity and is otherwise suitable for its intended use.
    (b) When reinstalling the tree, you must:
    (1) Equip wells to monitor for casing pressure according to the 
following chart:

------------------------------------------------------------------------
   If you have . . .     you must equip . . .   so you can monitor . . .
------------------------------------------------------------------------
(i) fixed platform      the wellhead,          all annuli (A, B, C, D,
 wells,                                         etc., annuli).
(ii) subsea wells,      the tubing head,       the production casing
                                                annulus (A annulus).
(iii) hybrid* wells,    the surface wellhead,  all annuli at the surface
                                                (A and B riser annuli).
                                                If the production casing
                                                below the mudline and
                                                the production casing
                                                riser above the mudline
                                                are pressure isolated
                                                from each other,
                                                provisions must be made
                                                to monitor the
                                                production casing below
                                                the mudline for casing
                                                pressure.
------------------------------------------------------------------------
* Characterized as a well drilled with a subsea wellhead and completed
  with a surface casing head, a surface tubing head, a surface tubing
  hanger, and a surface christmas tree.

    (2) Follow the casing pressure management requirements in subpart E 
of this part.
    (c) Wellhead, tree, and related equipment shall have a pressure 
rating greater than the shut-in tubing pressure and shall be designed, 
installed, used, maintained, and tested so as to achieve and maintain 
pressure control. The tree shall be equipped with a minimum of one 
master valve and one surface safety valve in the vertical run of the 
tree when it is reinstalled.
    (d) Subsurface safety equipment must be installed, maintained, and 
tested in compliance with the applicable sections in Secs. 250.810 
through 250.839.
    (e) If you pull and reinstall packers and bridge plugs, you must 
meet the following requirements:
    (1) All permanently installed packers and bridge plugs must comply 
with API Spec. 11D1 (as incorporated by reference in Sec. 250.198);
    (2) The production packer must be set at a depth that will allow for 
a column of weighted fluids to be placed above the packer that will 
exert a hydrostatic force greater than or equal to the force created by 
the reservoir pressure below the packer;
    (3) The production packer must be set as close as practically 
possible to the perforated interval; and

[[Page 129]]

    (4) The production packer must be set at a depth that is within the 
cemented interval of the selected casing section.
    (f) Your APM must include a description and calculations for how you 
determined the production packer setting depth.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50895, Aug. 22, 2012, 
as amended at 81 FR 26021, Apr. 29, 2016; 81 FR 61918, Sept. 7, 2016]



Sec. 250.620  Wireline operations.

    The lessee shall comply with the following requirements during 
routine, as defined in Sec. 250.601 of this part, and nonroutine 
wireline workover operations:
    (a) Wireline operations shall be conducted so as to minimize leakage 
of well fluids. Any leakage that does occur shall be contained to 
prevent pollution.
    (b) All wireline perforating operations and all other wireline 
operations where communication exists between the completed hydrocarbon-
bearing zone(s) and the wellbore shall use a lubricator assembly 
containing at least one wireline valve.
    (c) When the lubricator is initially installed on the well, it shall 
be successfully pressure tested to the expected shut-in surface 
pressure.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50895, Aug. 22, 2012]



                 Subpart G_Well Operations and Equipment

    Source: 81 FR 26022, Apr. 29, 2016, unless otherwise noted.

                          General Requirements



Sec. 250.700  What operations and equipment does this subpart cover?

    This subpart covers operations and equipment associated with 
drilling, completion, workover, and decommissioning activities. This 
subpart includes regulations applicable to drilling, completion, 
workover, and decommissioning activities in addition to applicable 
regulations contained in subparts D, E, F, and Q of this part unless 
explicitly stated otherwise.



Sec. 250.701  May I use alternate procedures or equipment during 
operations?

    You may use alternate procedures or equipment during operations 
after receiving approval as described in Sec. 250.141. You must identify 
and discuss your proposed alternate procedures or equipment in your 
Application for Permit to Drill (APD) (Form BSEE-0123) (see 
Sec. 250.414(h)) or your Application for Permit to Modify (APM) (Form 
BSEE-0124). Procedures for obtaining approval of alternate procedures or 
equipment are described in Sec. 250.141.



Sec. 250.702  May I obtain departures from these requirements?

    You may apply for a departure from these requirements as described 
in Sec. 250.142. Your request must include a justification showing why 
the departure is necessary. You must identify and discuss the departure 
you are requesting in your APD (see Sec. 250.414(h)) or your APM.



Sec. 250.703  What must I do to keep wells under control?

    You must take the necessary precautions to keep wells under control 
at all times, including:
    (a) Use recognized engineering practices to reduce risks to the 
lowest level practicable when monitoring and evaluating well conditions 
and to minimize the potential for the well to flow or kick;
    (b) Have a person onsite during operations who represents your 
interests and can fulfill your responsibilities;
    (c) Ensure that the toolpusher, operator's representative, or a 
member of the rig crew maintains continuous surveillance on the rig 
floor from the beginning of operations until the well is completed or 
abandoned, unless you have secured the well with blowout preventers 
(BOPs), bridge plugs, cement plugs, or packers;
    (d) Use personnel trained according to the provisions of subparts O 
and S of this part;
    (e) Use and maintain equipment and materials necessary to ensure the 
safety and protection of personnel, equipment, natural resources, and 
the environment; and

[[Page 130]]

    (f) Use equipment that has been designed, tested, and rated for the 
maximum environmental and operational conditions to which it may be 
exposed while in service.

                            Rig Requirements



Sec. 250.710  What instructions must be given to personnel engaged 
in well operations?

    Prior to engaging in well operations, personnel must be instructed 
in:
    (a) Hazards and safety requirements. You must instruct your 
personnel regarding the safety requirements for the operations to be 
performed, possible hazards to be encountered, and general safety 
considerations to protect personnel, equipment, and the environment as 
required by subpart S of this part. The date and time of safety meetings 
must be recorded and available at the facility for review by BSEE 
representatives.
    (b) Well control. You must prepare a well-control plan for each 
well. Each well-control plan must contain instructions for personnel 
about the use of each well-control component of your BOP, procedures 
that describe how personnel will seal the wellbore and shear pipe before 
maximum anticipated surface pressure (MASP) conditions are exceeded, 
assignments for each crew member, and a schedule for completion of each 
assignment. You must keep a copy of your well-control plan on the rig at 
all times, and make it available to BSEE upon request. You must post a 
copy of the well-control plan on the rig floor.



Sec. 250.711  What are the requirements for well-control drills?

    You must conduct a weekly well-control drill with all personnel 
engaged in well operations. Your drill must familiarize personnel 
engaged in well operations with their roles and functions so that they 
can perform their duties promptly and efficiently as outlined in the 
well-control plan required by Sec. 250.710.
    (a) Timing of drills. You must conduct each drill during a period of 
activity that minimizes the risk to operations. The timing of your 
drills must cover a range of different operations, including drilling 
with a diverter, on-bottom drilling, and tripping. The same drill may 
not be repeated consecutively with the same crew.
    (b) Recordkeeping requirements. For each drill, you must record the 
following in the daily report:
    (1) Date, time, and type of drill conducted;
    (2) The amount of time it took to be ready to close the diverter or 
use each well-control component of BOP system; and
    (3) The total time to complete the entire drill.
    (c) A BSEE ordered drill. A BSEE representative may require you to 
conduct a well-control drill during a BSEE inspection. The BSEE 
representative will consult with your onsite representative before 
requiring the drill.



Sec. 250.712  What rig unit movements must I report?

    (a) You must report the movement of all rig units on and off 
locations to the District Manager using Form BSEE-0144, Rig Movement 
Notification Report. Rig units include MODUs, platform rigs, snubbing 
units, wire-line units used for non-routine operations, and coiled 
tubing units. You must inform the District Manager 24 hours before:
    (1) The arrival of a rig unit on location;
    (2) The movement of a rig unit to another slot. For movements that 
will occur less than 24 hours after initially moving onto location 
(e.g., coiled tubing and batch operations), you may include your 
anticipated movement schedule on Form BSEE-0144; or
    (3) The departure of a rig unit from the location.
    (b) You must provide the District Manager with the rig name, lease 
number, well number, and expected time of arrival or departure.
    (c) If a MODU or platform rig is to be warm or cold stacked, you 
must inform the District Manager:
    (1) Where the MODU or platform rig is coming from;
    (2) The location where the MODU or platform rig will be positioned;
    (3) Whether the MODU or platform rig will be manned or unmanned; and
    (4) If the location for stacking the MODU or platform rig changes.

[[Page 131]]

    (d) Prior to resuming operations after stacking, you must notify the 
appropriate District Manager of any construction, repairs, or 
modifications associated with the drilling package made to the MODU or 
platform rig.
    (e) If a drilling rig is entering OCS waters, you must inform the 
District Manager where the drilling rig is coming from.
    (f) If you change your anticipated date for initially moving on or 
off location by more than 24 hours, you must submit an updated Form 
BSEE-0144, Rig Movement Notification Report.



Sec. 250.713  What must I provide if I plan to use a mobile offshore
drilling unit (MODU) for well operations?

    If you plan to use a MODU for well operations, you must provide:
    (a) Fitness requirements. Information and data to demonstrate the 
MODU's capability to perform at the proposed location. This information 
must include the maximum environmental and operational conditions that 
the MODU is designed to withstand, including the minimum air gap 
necessary for both hurricane and non-hurricane seasons. If sufficient 
environmental information and data are not available at the time you 
submit your APD or APM, the District Manager may approve your APD or 
APM, but require you to collect and report this information during 
operations. Under this circumstance, the District Manager may revoke the 
approval of the APD or APM if information collected during operations 
shows that the MODU is not capable of performing at the proposed 
location.
    (b) Foundation requirements. Information to show that site-specific 
soil and oceanographic conditions are capable of supporting the proposed 
bottom-founded MODU. If you provided sufficient site-specific 
information in your EP, DPP, or DOCD submitted to BOEM for that well 
location and conditions, you may reference that information. The 
District Manager may require you to conduct additional surveys and soil 
borings before approving the APD or APM if additional information is 
needed to make a determination that the conditions are capable of 
supporting the MODU, or equipment installed on a subsea wellhead. For a 
moored rig, you must submit a plat of the rig's anchor pattern approved 
in your EP, DPP, or DOCD in your APD or APM.
    (c) For frontier areas. (1) If the design of the MODU you plan to 
use in a frontier area is unique or has not been proven for use in the 
proposed environment, the District Manager may require you to submit a 
third-party review of the MODU design. If required, you must obtain a 
third-party review of your MODU similar to the process outlined in 
Secs. 250.915 through 250.918. You may submit this information before 
submitting an APD or APM.
    (2) If you plan to conduct operations in a frontier area, you must 
have a contingency plan that addresses design and operating limitations 
of the MODU. Your plan must identify the actions necessary to maintain 
safety and prevent damage to the environment. Actions must include the 
suspension, curtailment, or modification of operations to remedy various 
operational or environmental situations (e.g., vessel motion, riser 
offset, anchor tensions, wind speed, wave height, currents, icing or 
ice-loading, settling, tilt or lateral movement, resupply capability).
    (d) Additional documentation. You must provide the current 
Certificate of Inspection (for U.S.-flag vessels) or Certificate of 
Compliance (for foreign-flag vessels) from the USCG and Certificate of 
Classification. You must also provide current documentation of any 
operational limitations imposed by an appropriate classification 
society.
    (e) Dynamically positioned MODU. If you use a dynamically positioned 
MODU, you must include in your APD or APM your contingency plan for 
moving off location in an emergency situation. At a minimum, your plan 
must address emergency events caused by storms, currents, station-
keeping failures, power failures, and losses of well control. The 
District Manager may require your plan to include additional events that 
may require movement of the MODU and other information needed to clarify 
or further address how the MODU will respond to emergencies or other 
events.
    (f) Inspection of MODU. The MODU must be available for inspection by 
the District Manager before commencing

[[Page 132]]

operations and at any time during operations.
    (g) Current monitoring. For water depths greater than 400 meters 
(1,312 feet), you must include in your APD or APM:
    (1) A description of the specific current speeds that will cause you 
to implement rig shutdown, move-off procedures, or both; and
    (2) A discussion of the specific measures you will take to curtail 
rig operations and move off location when such currents are encountered. 
You may use criteria, such as current velocities, riser angles, watch 
circles, and remaining rig power to describe when these procedures or 
measures will be implemented.

[81 FR 26022, Apr. 29, 2016, as amended at 81 FR 36150, June 6, 2016]



Sec. 250.714  Do I have to develop a dropped objects plan?

    If you use a floating rig unit in an area with subsea 
infrastructure, you must develop a dropped objects plan and make it 
available to BSEE upon request. This plan must be updated as the 
infrastructure on the seafloor changes. Your plan must include:
    (a) A description and plot of the path the rig will take while 
running and pulling the riser;
    (b) A plat showing the location of any subsea wells, production 
equipment, pipelines, and any other identified debris;
    (c) Modeling of a dropped object's path with consideration given to 
metocean conditions for various material forms, such as a tubular (e.g., 
riser or casing) and box (e.g., BOP or tree);
    (d) Communications, procedures, and delegated authorities 
established with the production host facility to shut-in any active 
subsea wells, equipment, or pipelines in the event of a dropped object; 
and
    (e) Any additional information required by the District Manager as 
appropriate to clarify, update, or evaluate your dropped objects plan.



Sec. 250.715  Do I need a global positioning system (GPS) for all MODUs?

    All MODUs must have a minimum of two functioning GPS transponders at 
all times, and you must provide to BSEE real-time access to the GPS data 
prior to and during each hurricane season.
    (a) The GPS must be capable of monitoring the position and tracking 
the path in real-time if the MODU moves from its location during a 
severe storm.
    (b) You must install and protect the tracking system's equipment to 
minimize the risk of the system being disabled.
    (c) You must place the GPS transponders in different locations for 
redundancy to minimize risk of system failure.
    (d) Each GPS transponder must be capable of transmitting data for at 
least 7 days after a storm has passed.
    (e) If the MODU is moved off location in the event of a storm, you 
must immediately begin to record the GPS location data.
    (f) You must contact the Regional Office and allow real-time access 
to the MODU location data. When you contact the Regional Office, provide 
the following:
    (1) Name of the lessee and operator with contact information;
    (2) MODU name;
    (3) Initial date and time; and
    (4) How you will provide GPS real-time access.

                             Well Operations



Sec. 250.720  When and how must I secure a well?

    (a) Whenever you interrupt operations, you must notify the District 
Manager. Before moving off the well, you must have two independent 
barriers installed, at least one of which must be a mechanical barrier, 
as approved by the District Manager. You must install the barriers at 
appropriate depths within a properly cemented casing string or liner. 
Before removing a subsea BOP stack or surface BOP stack on a mudline 
suspension well, you must conduct a negative pressure test in accordance 
with Sec. 250.721.
    (1) The events that would cause you to interrupt operations and 
notify the District Manager include, but are not limited to, the 
following:
    (i) Evacuation of the rig crew;

[[Page 133]]

    (ii) Inability to keep the rig on location;
    (iii) Repair to major rig or well-control equipment; or
    (iv) Observed flow outside the well's casing (e.g., shallow water 
flow or bubbling).
    (2) The District Manager may approve alternate procedures or 
barriers, in accordance with Sec. 250.141, if you do not have time to 
install the required barriers or if special circumstances occur.
    (b) Before you displace kill-weight fluid from the wellbore and/or 
riser, thereby creating an underbalanced state, you must obtain approval 
from the District Manager. To obtain approval, you must submit with your 
APD or APM your reasons for displacing the kill-weight fluid and provide 
detailed step-by-step written procedures describing how you will safely 
displace these fluids. The step-by-step displacement procedures must 
address the following:
    (1) Number and type of independent barriers, as described in 
Sec. 250.420(b)(3), that are in place for each flow path that requires 
such barriers;
    (2) Tests you will conduct to ensure integrity of independent 
barriers;
    (3) BOP procedures you will use while displacing kill-weight fluids; 
and
    (4) Procedures you will use to monitor the volumes and rates of 
fluids entering and leaving the wellbore.
    (c) For Arctic OCS exploratory drilling operations, in addition to 
the requirements of paragraphs (a) and (b) of this section:
    (1) If you move your drilling rig off a well prior to completion or 
permanent abandonment, you must ensure that any equipment left on, near, 
or in a wellbore that has penetrated below the surface casing is 
positioned in a manner to:
    (i) Protect the well head; and
    (ii) Prevent or minimize the likelihood of compromising the down-
hole integrity of the well or the effectiveness of the well plugs.
    (2) In areas of ice scour you must use a well mudline cellar or an 
equivalent means of minimizing the risk of damage to the well head and 
wellbore. BSEE may approve an equivalent means that will meet or exceed 
the level of safety and environmental protection provided by a mudline 
cellar if the operator can show that utilizing a mudline cellar would 
compromise the stability of the rig, impede access to the well head 
during a well control event, or otherwise create operational risks.

[81 FR 26022, Apr. 29, 2016, as amended at 81 FR 46563, July 15, 2016]



Sec. 250.721  What are the requirements for pressure testing casing 
and liners?

    (a) You must test each casing string that extends to the wellhead 
according to the following table:

------------------------------------------------------------------------
              Casing type                     Minimum test pressure
------------------------------------------------------------------------
(1) Drive or Structural,...............  Not required.
(2) Conductor, excluding subsea          250 psi.
 wellheads,.
(3) Surface, Intermediate, and           70 percent of its minimum
 Production,.                             internal yield.
------------------------------------------------------------------------

    (b) You must test each drilling liner and liner-top to a pressure at 
least equal to the anticipated leak-off pressure of the formation below 
that liner shoe, or subsequent liner shoes if set. You must conduct this 
test before you continue operations in the well.
    (c) You must test each production liner and liner-top to a minimum 
of 500 psi above the formation fracture pressure at the casing shoe into 
which the liner is lapped.
    (d) The District Manager may approve or require other casing test 
pressures as appropriate under the circumstances to ensure casing 
integrity.
    (e) If you plan to produce a well, you must:
    (1) For a well that is fully cased and cemented, pressure test the 
entire well to maximum anticipated shut-in tubing pressure, not to 
exceed 70% of the burst rating limit of the weakest component before 
perforating the casing or liner; or

[[Page 134]]

    (2) For an open-hole completion, pressure test the entire well to 
maximum anticipated shut-in tubing pressure, not to exceed 70% of the 
burst rating limit of the weakest component before you drill the open-
hole section.
    (f) You may not resume operations until you obtain a satisfactory 
pressure test. If the pressure declines more than 10 percent in a 30-
minute test, or if there is another indication of a leak, you must 
submit to the District Manager for approval your proposed plans to re-
cement, repair the casing or liner, or run additional casing/liner to 
provide a proper seal. Your submittal must include a PE certification of 
your proposed plans.
    (g) You must perform a negative pressure test on all wells that use 
a subsea BOP stack or wells with mudline suspension systems.
    (1) You must perform a negative pressure test on your final casing 
string or liner. This test must be conducted after setting your second 
barrier just above the shoe track, but prior to conducting any 
completion operations.
    (2) You must perform a negative pressure test prior to unlatching 
the BOP at any point in the well. The negative pressure test must be 
performed on those components, at a minimum, that will be exposed to the 
negative differential pressure that will occur when the BOP is 
disconnected.
    (3) The District Manager may require you to perform additional 
negative pressure tests on other casing strings or liners (e.g., 
intermediate casing string or liner) or on wells with a surface BOP 
stack as appropriate to demonstrate casing or liner integrity.
    (4) You must submit for approval with your APD or APM, test 
procedures and criteria for a successful negative pressure test. If any 
of your test procedures or criteria for a successful test change, you 
must submit for approval the changes in a revised APD or APM.
    (5) You must document all your test results and make them available 
to BSEE upon request.
    (6) If you have any indication of a failed negative pressure test, 
such as, but not limited to, pressure buildup or observed flow, you must 
immediately investigate the cause. If your investigation confirms that a 
failure occurred during the negative pressure test, you must:
    (i) Correct the problem and immediately notify the appropriate 
District Manager; and
    (ii) Submit a description of the corrective action taken and receive 
approval from the appropriate District Manager for the retest.
    (7) You must have two barriers in place, as described in 
Sec. 250.420(b)(3), at any time and for any well, prior to performing 
the negative pressure test.
    (8) You must include documentation of the successful negative 
pressure test in the End-of-Operations Report (Form BSEE-0125).



Sec. 250.722  What are the requirements for prolonged operations
in a well?

    If wellbore operations continue within a casing or liner for more 
than 30 days from the previous pressure test of the well's casing or 
liner, you must:
    (a) Stop operations as soon as practicable, and evaluate the effects 
of the prolonged operations on continued operations and the life of the 
well. At a minimum, you must:
    (1) Evaluate the well casing with a pressure test, caliper tool, or 
imaging tool. On a case-by-case basis, the District Manager may require 
a specific method of evaluation of the effects on the well casing of 
prolonged operations; and
    (2) Report the results of your evaluation to the District Manager 
and obtain approval of those results before resuming operations. Your 
report must include calculations that show the well's integrity is above 
the minimum safety factors, if an imaging tool or caliper is used.
    (b) If well integrity has deteriorated to a level below minimum 
safety factors, you must:
    (1) Obtain approval from the District Manager to begin repairs or 
install additional casing. To obtain approval, you must also provide a 
PE certification showing that he or she reviewed and approved the 
proposed changes;
    (2) Repair the casing or run another casing string; and
    (3) Perform a pressure test after the repairs are made or additional 
casing is installed and report the results to the

[[Page 135]]

District Manager as specified in Sec. 250.721.



Sec. 250.723  What additional safety measures must I take when I
conduct operations on a platform that has producing wells or has
other hydrocarbon flow?

    You must take the following safety measures when you conduct 
operations with a rig unit or lift boat on or jacked-up over a platform 
with producing wells or that has other hydrocarbon flow:
    (a) The movement of rig units and related equipment on and off a 
platform or from well to well on the same platform, including rigging up 
and rigging down, must be conducted in a safe manner;
    (b) You must install an emergency shutdown station for the 
production system near the rig operator's console;
    (c) You must shut-in all producible wells located in the affected 
wellbay below the surface and at the wellhead when:
    (1) You move a rig unit or related equipment on and off a platform. 
This includes rigging up and rigging down activities within 500 feet of 
the affected platform;
    (2) You move or skid a rig unit between wells on a platform; or
    (3) A MODU or lift boat moves within 500 feet of a platform. You may 
resume production once the MODU or lift boat is in place, secured, and 
ready to begin operations.
    (d) All wells in the same well-bay which are capable of producing 
hydrocarbons must be shut-in below the surface with a pump-through-type 
tubing plug and at the surface with a closed master valve prior to 
moving rig units and related equipment, unless otherwise approved by the 
District Manager.
    (1) A closed surface-controlled subsurface safety valve of the pump-
through-type may be used in lieu of the pump-through-type tubing plug 
provided that the surface control has been locked out of operation.
    (2) The well to which a rig unit or related equipment is to be moved 
must be equipped with a back-pressure valve prior to removing the tree 
and installing and testing the BOP system.
    (3) The well from which a rig unit or related equipment is to be 
moved must be equipped with a back pressure valve prior to removing the 
BOP system and installing the production tree.
    (e) Coiled tubing units, snubbing units, or wireline units may be 
moved onto and off of a platform without shutting in wells.



Sec. 250.724  What are the real-time monitoring requirements?

    (a) No later than April 29, 2019, when conducting well operations 
with a subsea BOP or with a surface BOP on a floating facility, or when 
operating in an high pressure high temperature (HPHT) environment, you 
must gather and monitor real-time well data using an independent, 
automatic, and continuous monitoring system capable of recording, 
storing, and transmitting data regarding the following:
    (1) The BOP control system;
    (2) The well's fluid handling system on the rig; and
    (3) The well's downhole conditions with the bottom hole assembly 
tools (if any tools are installed).
    (b) You must transmit these data as they are gathered, barring 
unforeseeable or unpreventable interruptions in transmission, and have 
the capability to monitor the data onshore, using qualified personnel in 
accordance with a real-time monitoring plan, as provided in paragraph 
(c) of this section. Onshore personnel who monitor real-time data must 
have the capability to contact rig personnel during operations. After 
operations, you must preserve and store these data onshore for 
recordkeeping purposes as required in Secs. 250.740 and 250.741. You 
must provide BSEE with access to your designated real-time monitoring 
data onshore upon request. You must include in your APD a certification 
that you have a real-time monitoring plan that meets the criteria in 
paragraph (c) of this section.
    (c) You must develop and implement a real-time monitoring plan. Your 
real-time monitoring plan, and all real-time monitoring data, must be 
made available to BSEE upon request. Your real-time monitoring plan must 
include the following:
    (1) A description of your real-time monitoring capabilities, 
including the types of the data collected;

[[Page 136]]

    (2) A description of how your real-time monitoring data will be 
transmitted onshore during operations, how the data will be labeled and 
monitored by qualified onshore personnel, and how it will be stored 
onshore;
    (3) A description of your procedures for providing BSEE access, upon 
request, to your real-time monitoring data including, if applicable, the 
location of any onshore data monitoring or data storage facilities;
    (4) The qualifications of the onshore personnel monitoring the data;
    (5) Your procedures for, and methods of, communication between rig 
personnel and the onshore monitoring personnel; and
    (6) Actions to be taken if you lose any real-time monitoring 
capabilities or communications between rig and onshore personnel, and a 
protocol for how you will respond to any significant and/or prolonged 
interruption of monitoring or onshore-offshore communications, including 
your protocol for notifying BSEE of any significant and/or prolonged 
interruptions.

               Blowout Preventer (BOP) System Requirements



Sec. 250.730  What are the general requirements for BOP systems and 
system components?

    (a) You must ensure that the BOP system and system components are 
designed, installed, maintained, inspected, tested, and used properly to 
ensure well control. The working-pressure rating of each BOP component 
(excluding annular(s)) must exceed MASP as defined for the operation. 
For a subsea BOP, the MASP must be taken at the mudline. The BOP system 
includes the BOP stack, control system, and any other associated 
system(s) and equipment. The BOP system and individual components must 
be able to perform their expected functions and be compatible with each 
other. Your BOP system (excluding casing shear) must be capable of 
closing and sealing the wellbore at all times, including under 
anticipated flowing conditions for the specific well conditions, without 
losing ram closure time and sealing integrity due to the corrosiveness, 
volume, and abrasiveness of any fluids in the wellbore that the BOP 
system may encounter. Your BOP system must meet the following 
requirements:
    (1) The BOP requirements of API Standard 53 (incorporated by 
reference in Sec. 250.198) and the requirements of Secs. 250.733 through 
250.739. If there is a conflict between API Standard 53, and the 
requirements of this subpart, you must follow the requirements of this 
subpart.
    (2) Those provisions of the following industry standards (all 
incorporated by reference in Sec. 250.198) that apply to BOP systems:
    (i) ANSI/API Spec. 6A;
    (ii) ANSI/API Spec. 16A;
    (iii) ANSI/API Spec. 16C;
    (iv) API Spec. 16D; and
    (v) ANSI/API Spec. 17D.
    (3) For surface and subsea BOPs, the pipe and variable bore rams 
installed in the BOP stack must be capable of effectively closing and 
sealing on the tubular body of any drill pipe, workstring, and tubing 
(excluding tubing with exterior control lines and flat packs) in the 
hole under MASP, as defined for the operation, with the proposed 
regulator settings of the BOP control system.
    (4) The current set of approved schematic drawings must be available 
on the rig and at an onshore location. If you make any modifications to 
the BOP or control system that will change your BSEE-approved schematic 
drawings, you must suspend operations until you obtain approval from the 
District Manager.
    (b) You must ensure that the design, fabrication, maintenance, and 
repair of your BOP system is in accordance with the requirements 
contained in this part, Original Equipment Manufacturers (OEM) 
recommendations unless otherwise directed by BSEE, and recognized 
engineering practices. The training and qualification of repair and 
maintenance personnel must meet or exceed any OEM training 
recommendations unless otherwise directed by BSEE.
    (c) You must follow the failure reporting procedures contained in 
API Standard 53, ANSI/API Spec. 6A, and ANSI/API Spec 16A (all 
incorporated by reference in Sec. 250.198), and:

[[Page 137]]

    (1) You must provide a written notice of equipment failure to the 
Chief, Office of Offshore Regulatory Programs, and the manufacturer of 
such equipment within 30 days after the discovery and identification of 
the failure. A failure is any condition that prevents the equipment from 
meeting the functional specification.
    (2) You must ensure that an investigation and a failure analysis are 
performed within 120 days of the failure to determine the cause of the 
failure. You must also ensure that the results and any corrective action 
are documented. If the investigation and analysis are performed by an 
entity other than the manufacturer, you must ensure that the Chief, 
Office of Offshore Regulatory Programs and the manufacturer receive a 
copy of the analysis report.
    (3) If the equipment manufacturer notifies you that it has changed 
the design of the equipment that failed or if you have changed operating 
or repair procedures as a result of a failure, then you must, within 30 
days of such changes, report the design change or modified procedures in 
writing to the Chief, Office of Offshore Regulatory Programs.
    (4) You must send the reports required in this paragraph to: Chief, 
Office of Offshore Regulatory Programs; Bureau of Safety and 
Environmental Enforcement; 45600 Woodland Road, Sterling, VA 20166.
    (d) If you plan to use a BOP stack manufactured after the effective 
date of this regulation, you must use one manufactured pursuant to an 
API Spec. Q1 (as incorporated by reference in Sec. 250.198) quality 
management system. Such quality management system must be certified by 
an entity that meets the requirements of ISO 17011.
    (1) BSEE may consider accepting equipment manufactured under quality 
assurance programs other than API Spec. Q1, provided you submit a 
request to the Chief, Office of Offshore Regulatory Programs for 
approval, containing relevant information about the alternative program.
    (2) You must submit this request to the Chief, Office of Offshore 
Regulatory Programs; Bureau of Safety and Environmental Enforcement; 
45600 Woodland Road, Sterling, Virginia 20166.



Sec. 250.731  What information must I submit for BOP systems and 
system components?

    For any operation that requires the use of a BOP, you must include 
the information listed in this section with your applicable APD, APM, or 
other submittal. You are required to submit this information only once 
for each well, unless the information changes from what you provided in 
an earlier approved submission or you have moved off location from the 
well. After you have submitted this information for a particular well, 
subsequent APMs or other submittals for the well should reference the 
approved submittal containing the information required by this section 
and confirm that the information remains accurate and that you have not 
moved off location from that well. If the information changes or you 
have moved off location from the well, you must submit updated 
information in your next submission.

------------------------------------------------------------------------
         You must submit:                        Including:
------------------------------------------------------------------------
(a) A complete description of the   (1) Pressure ratings of BOP
 BOP system and system components,   equipment;
                                    (2) Proposed BOP test pressures (for
                                     subsea BOPs, include both surface
                                     and corresponding subsea
                                     pressures);
                                    (3) Rated capacities for liquid and
                                     gas for the fluid-gas separator
                                     system;
                                    (4) Control fluid volumes needed to
                                     close, seal, and open each
                                     component;
                                    (5) Control system pressure and
                                     regulator settings needed to
                                     achieve an effective seal of each
                                     ram BOP under MASP as defined for
                                     the operation;
                                    (6) Number and volume of accumulator
                                     bottles and bottle banks (for
                                     subsea BOP, include both surface
                                     and subsea bottles);
                                    (7) Accumulator pre-charge
                                     calculations (for subsea BOP,
                                     include both surface and subsea
                                     calculations);
                                    (8) All locking devices; and
                                    (9) Control fluid volume
                                     calculations for the accumulator
                                     system (for a subsea BOP system,
                                     include both the surface and subsea
                                     volumes).
(b) Schematic drawings,...........  (1) The inside diameter of the BOP
                                     stack;
                                    (2) Number and type of preventers
                                     (including blade type for shear
                                     ram(s));

[[Page 138]]

 
                                    (3) All locking devices;
                                    (4) Size range for variable bore
                                     ram(s);
                                    (5) Size of fixed ram(s);
                                    (6) All control systems with all
                                     alarms and set points labeled,
                                     including pods;
                                    (7) Location and size of choke and
                                     kill lines (and gas bleed line(s)
                                     for subsea BOP);
                                    (8) Associated valves of the BOP
                                     system;
                                    (9) Control station locations; and
                                    (10) A cross-section of the riser
                                     for a subsea BOP system showing
                                     number, size, and labeling of all
                                     control, supply, choke, and kill
                                     lines down to the BOP.
(c) Certification by a BSEE-        Verification that:
 approved verification              (1) Test data demonstrate the shear
 organization (BAVO),                ram(s) will shear the drill pipe at
                                     the water depth as required in Sec.
                                      250.732;
                                    (2) The BOP was designed, tested,
                                     and maintained to perform under the
                                     maximum environmental and
                                     operational conditions anticipated
                                     to occur at the well; and
                                    (3) The accumulator system has
                                     sufficient fluid to operate the BOP
                                     system without assistance from the
                                     charging system.
(d) Additional certification by a   Verification that:
 BAVO, if you use a subsea BOP, a   (1) The BOP stack is designed and
 BOP in an HPHT environment as       suitable for the specific equipment
 defined in Sec. 250.807, or a      on the rig and for the specific
 surface BOP on a floating           well design;
 facility,                          (2) The BOP stack has not been
                                     compromised or damaged from
                                     previous service; and
                                    (3) The BOP stack will operate in
                                     the conditions in which it will be
                                     used.
(e) If you are using a subsea BOP,  A listing of the functions with
 descriptions of autoshear,          their sequences and timing.
 deadman, and emergency disconnect
 sequence (EDS) systems,
(f) Certification stating that the  ....................................
 MIA Report required in Sec.
 250.732(d) has been submitted
 within the past 12 months for a
 subsea BOP, a BOP being used in
 an HPHT environment as defined in
 Sec. 250.807, or a surface BOP
 on a floating facility.
------------------------------------------------------------------------



Sec. 250.732  What are the BSEE-approved verification organization
(BAVO) requirements for BOP systems and system components?

    (a) BSEE will maintain a list of BSEE-approved verification 
organizations (BAVOs) on its public website that you must use to satisfy 
any provision in this subpart that requires a BAVO certification, 
verification, report, or review. You must comply with all requirements 
in this subpart for BAVO certification, verification, or reporting no 
later than 1 year from the date BSEE publishes a list of BAVOs.
    (1) Until such time as you use a BAVO to perform the actions that 
this subpart requires to be performed by a BAVO, but not after 1 year 
from the date BSEE publishes a list of BAVOs, you must use an 
independent third-party meeting the criteria specified in paragraph 
(a)(2) of this section to prepare certifications, verifications, and 
reports as required by Secs. 250.731(c) and (d), 250.732 (b) and (c), 
250.734(b)(1), 250.738(b)(4), and 250.739(b).
    (2) The independent third-party must be a technical classification 
society, or a licensed professional engineering firm, or a registered 
professional engineer capable of providing the certifications, 
verifications, and reports required under paragraph (a)(1) of this 
section.
    (3) For an organization to become a BAVO, it must submit the 
following information to the Chief, Office of Offshore Regulatory 
Programs; Bureau of Safety and Environmental Enforcement; 45600 Woodland 
Road, Sterling, Virginia, 20166, for BSEE review and approval:
    (i) Previous experience in verification or in the design, 
fabrication, installation, repair, or major modification of BOPs and 
related systems and equipment;
    (ii) Technical capabilities;
    (iii) Size and type of organization;
    (iv) In-house availability of, or access to, appropriate technology. 
This should include computer programs, hardware, and testing materials 
and equipment;

[[Page 139]]

    (v) Ability to perform the verification functions for projects 
considering current commitments;
    (vi) Previous experience with BSEE requirements and procedures; and
    (vii) Any additional information that may be relevant to BSEE's 
review.
    (b) Prior to beginning any operation requiring the use of any BOP, 
you must submit verification by a BAVO and supporting documentation as 
required by this paragraph to the appropriate District Manager and 
Regional Supervisor.

------------------------------------------------------------------------
 You must submit verification and
     documentation related to:                      That:
------------------------------------------------------------------------
(1) Shear testing,................  (i) Demonstrates that the BOP will
                                     shear the drill pipe and any
                                     electric-, wire-, and slick-line to
                                     be used in the well, no later than
                                     April 30, 2018;
                                    (ii) Demonstrates the use of test
                                     protocols and analysis that
                                     represent recognized engineering
                                     practices for ensuring the
                                     repeatability and reproducibility
                                     of the tests, and that the testing
                                     was performed by a facility that
                                     meets generally accepted quality
                                     assurance standards;
                                    (iii) Provides a reasonable
                                     representation of field
                                     applications, taking into
                                     consideration the physical and
                                     mechanical properties of the drill
                                     pipe;
                                    (iv) Ensures testing was performed
                                     on the outermost edges of the
                                     shearing blades of the shear ram
                                     positioning mechanism as required
                                     in Sec. 250.734(a)(16);
                                    (v) Demonstrates the shearing
                                     capacity of the BOP equipment to
                                     the physical and mechanical
                                     properties of the drill pipe; and
                                    (vi) Includes relevant testing
                                     results.
(2) Pressure integrity testing,     (i) Shows that testing is conducted
 and.                                immediately after the shearing
                                     tests;
                                    (ii) Demonstrates that the equipment
                                     will seal at the rated working
                                     pressures (RWP) of the BOP for 30
                                     minutes; and
                                    (iii) Includes all relevant test
                                     results.
(3) Calculations..................  Include shearing and sealing
                                     pressures for all pipe to be used
                                     in the well including corrections
                                     for MASP.
------------------------------------------------------------------------

    (c) For wells in an HPHT environment, as defined by Sec. 250.807(b), 
you must submit verification by a BAVO that the verification 
organization conducted a comprehensive review of the BOP system and 
related equipment you propose to use. You must provide the BAVO access 
to any facility associated with the BOP system or related equipment 
during the review process. You must submit the verifications required by 
this paragraph (c) to the appropriate District Manager and Regional 
Supervisor before you begin any operations in an HPHT environment with 
the proposed equipment.

------------------------------------------------------------------------
           You must submit:                        Including:
------------------------------------------------------------------------
(1) Verification that the
 verification organization conducted
 a detailed review of the design
 package to ensure that all critical
 components and systems meet
 recognized engineering practices,
(2) Verification that the designs of   (i) Identification of all
 individual components and the          reasonable potential modes of
 overall system have been proven in a   failure; and
 testing process that demonstrates     (ii) Evaluation of the design
 the performance and reliability of     verification tests. The design
 the equipment in a manner that is      verification tests must assess
 repeatable and reproducible,           the equipment for the identified
                                        potential modes of failure.
(3) Verification that the BOP
 equipment will perform as designed
 in the temperature, pressure, and
 environment that will be
 encountered, and
(4) Verification that the              For the quality control and
 fabrication, manufacture, and          assurance mechanisms, complete
 assembly of individual components      material and quality controls
 and the overall system uses            over all contractors,
 recognized engineering practices and   subcontractors, distributors,
 quality control and assurance          and suppliers at every stage in
 mechanisms.                            the fabrication, manufacture,
                                        and assembly process.
------------------------------------------------------------------------

    (d) Once every 12 months, you must submit a Mechanical Integrity 
Assessment Report for a subsea BOP, a BOP being used in an HPHT 
environment as defined in Sec. 250.807, or a surface BOP on a floating 
facility. This report must be completed by a BAVO. You must submit this 
report to the Chief, Office of Offshore Regulatory Programs; Bureau

[[Page 140]]

of Safety and Environmental Enforcement; 45600 Woodland Road, Sterling, 
VA 20166. This report must include:
    (1) A determination that the BOP stack and system meets or exceeds 
all BSEE regulatory requirements, industry standards incorporated into 
this subpart, and recognized engineering practices.
    (2) Verification that complete documentation of the equipment's 
service life exists that demonstrates that the BOP stack has not been 
compromised or damaged during previous service.
    (3) A description of all inspection, repair and maintenance records 
reviewed, and verification that all repairs, replacement parts, and 
maintenance meet regulatory requirements, recognized engineering 
practices, and OEM specifications.
    (4) A description of records reviewed related to any modifications 
to the equipment and verification that any such changes do not adversely 
affect the equipment's capability to perform as designed or invalidate 
test results.
    (5) A description of the Safety and Environmental Management Systems 
(SEMS) plans reviewed related to assurance of quality and mechanical 
integrity of critical equipment and verification that the plans are 
comprehensive and fully implemented.
    (6) Verification that the qualification and training of inspection, 
repair, and maintenance personnel for the BOP systems meet recognized 
engineering practices and any applicable OEM requirements.
    (7) A description of all records reviewed covering OEM safety 
alerts, all failure reports, and verification that any design or 
maintenance issues have been completely identified and corrected.
    (8) A comprehensive assessment of the overall system and 
verification that all components (including mechanical, hydraulic, 
electrical, and software) are compatible.
    (9) Verification that documentation exists concerning the 
traceability of the fabrication, repair, and maintenance of all critical 
components.
    (10) Verification of use of a formal maintenance tracking system to 
ensure that corrective maintenance and scheduled maintenance is 
implemented in a timely manner.
    (11) Identification of gaps or deficiencies related to inspection 
and maintenance procedures and documentation, documentation of any 
deferred maintenance, and verification of the completion of corrective 
action plans.
    (12) Verification that any inspection, maintenance, or repair work 
meets the manufacturer's design and material specifications.
    (13) Verification of written procedures for operating the BOP stack 
and Lower Marine Riser Package (LMRP) (including proper techniques to 
prevent accidental disconnection of these components) and minimum 
knowledge requirements for personnel authorized to operate and maintain 
BOP components.
    (14) Recommendations, if any, for how to improve the fabrication, 
installation, operation, maintenance, inspection, and repair of the 
equipment.
    (e) You must make all documentation that supports the requirements 
of this section available to BSEE upon request.



Sec. 250.733  What are the requirements for a surface BOP stack?

    (a) When you drill or conduct operations with a surface BOP stack, 
you must install the BOP system before drilling or conducting operations 
to deepen the well below the surface casing and after the well is 
deepened below the surface casing point. The surface BOP stack must 
include at least four remote-controlled, hydraulically operated BOPs, 
consisting of one annular BOP, one BOP equipped with blind shear rams, 
and two BOPs equipped with pipe rams.
    (1) The blind shear rams must be capable of shearing at any point 
along the tubular body of any drill pipe (excluding tool joints, bottom-
hole tools, and bottom hole assemblies that include heavy-weight pipe or 
collars), workstring, tubing provided that the capability to shear 
tubing with exterior control lines is not required prior to April 30, 
2018, and any electric-, wire-, and slick-line that is in the hole and 
sealing the wellbore after shearing. If your blind shear rams are unable 
to

[[Page 141]]

cut any electric-, wire-, or slick-line under MASP as defined for the 
operation and seal the wellbore, you must use an alternative cutting 
device capable of shearing the lines before closing the BOP. This device 
must be available on the rig floor during operations that require their 
use.
    (2) The two BOPs equipped with pipe rams must be capable of closing 
and sealing on the tubular body of any drill pipe, workstring, and 
tubing under MASP, as defined for the operation, except for tubing with 
exterior control lines and flat packs, a bottom hole assembly that 
includes heavy-weight pipe or collars, and bottom-hole tools.
    (b) If you plan to use a surface BOP on a floating production 
facility you must:
    (1) For BOPs installed after April 29, 2019, follow the BOP 
requirements in Sec. 250.734(a)(1).
    (2) For risers installed after July 28, 2016, use a dual bore riser 
configuration before drilling or operating in any hole section or 
interval where hydrocarbons are, or may be, exposed to the well. The 
dual bore riser must meet the design requirements of API RP 2RD (as 
incorporated by reference in Sec. 250.198), including appropriate design 
for the maximum anticipated operating and environmental conditions.
    (i) For a dual bore riser configuration, the annulus between the 
risers must be monitored for pressure during operations. You must 
describe in your APD or APM your annulus monitoring plan and how you 
will secure the well in the event a leak is detected.
    (ii) The inner riser for a dual riser configuration is subject to 
the requirements at Sec. 250.721 for testing the casing or liner.
    (c) You must install separate side outlets on the BOP stack for the 
kill and choke lines. If your stack does not have side outlets, you must 
install a drilling spool with side outlets. The outlet valves must hold 
pressure from both directions.
    (d) You must install a choke and a kill line on the BOP stack. You 
must equip each line with two full-bore, full-opening valves, one of 
which must be remote-controlled. On the kill line, you may install a 
check valve and a manual valve instead of the remote-controlled valve. 
To use this configuration, both manual valves must be readily accessible 
and you must install the check valve between the manual valves and the 
pump.



Sec. 250.734  What are the requirements for a subsea BOP system?

    (a) When you drill or conduct operations with a subsea BOP system, 
you must install the BOP system before drilling to deepen the well below 
the surface casing or before conducting operations if the well is 
already deepened beyond the surface casing point. The District Manager 
may require you to install a subsea BOP system before drilling or 
conducting operations below the conductor casing if proposed casing 
setting depths or local geology indicate the need. The following table 
outlines your requirements.

------------------------------------------------------------------------
 When operating with a subsea BOP system,
                 you must:                    Additional requirements:
------------------------------------------------------------------------
(1) Have at least five remote-controlled,   You must have at least one
 hydraulically operated BOPs;                annular BOP, two BOPs
                                             equipped with pipe rams,
                                             and two BOPs equipped with
                                             shear rams. For the dual
                                             ram requirement, you must
                                             comply with this
                                             requirement no later than
                                             April 29, 2021.
                                            (i) Both BOPs equipped with
                                             pipe rams must be capable
                                             of closing and sealing on
                                             the tubular body of any
                                             drill pipe, workstring, and
                                             tubing under MASP, as
                                             defined for the operation,
                                             except tubing with exterior
                                             control lines and flat
                                             packs, a bottom hole
                                             assembly that includes
                                             heavy-weight pipe or
                                             collars, and bottom-hole
                                             tools.

[[Page 142]]

 
                                            (ii) Both shear rams must be
                                             capable of shearing at any
                                             point along the tubular
                                             body of any drill pipe
                                             (excluding tool joints,
                                             bottom-hole tools, and
                                             bottom hole assemblies such
                                             as heavy-weight pipe or
                                             collars), workstring,
                                             tubing provided that the
                                             capability to shear tubing
                                             with exterior control lines
                                             is not required prior to
                                             April 30, 2018, appropriate
                                             area for the liner or
                                             casing landing string,
                                             shear sub on subsea test
                                             tree, and any electric-,
                                             wire-, slick-line in the
                                             hole no later than April
                                             30, 2018; under MASP. At
                                             least one shear ram must be
                                             capable of sealing the
                                             wellbore after shearing
                                             under MASP conditions as
                                             defined for the operation.
                                             Any non-sealing shear
                                             ram(s) must be installed
                                             below a sealing shear
                                             ram(s).
(2) Have an operable redundant pod control
 system to ensure proper and independent
 operation of the BOP system;
(3) Have the accumulator capacity located   The accumulator capacity
 subsea, to provide fast closure of the      must:
 BOP components and to operate all          (i) Operate each required
 critical functions in case of a loss of     shear ram, ram locks, one
 the power fluid connection to the           pipe ram, and disconnect
 surface;                                    the LMRP.
                                            (ii) Have the capability of
                                             delivering fluid to each
                                             ROV function i.e., flying
                                             leads.
                                            (iii) No later than April
                                             29, 2021, have bottles for
                                             the autoshear, and deadman
                                             that are dedicated to, but
                                             may be shared between,
                                             those functions.
                                            (iv) Perform under MASP
                                             conditions as defined for
                                             the operation.
(4) Have a subsea BOP stack equipped with   The ROV must be capable of
 remotely operated vehicle (ROV)             opening and closing each
 intervention capability;                    shear ram, ram locks, one
                                             pipe ram, and LMRP
                                             disconnect under MASP
                                             conditions as defined for
                                             the operation. The ROV
                                             panels on the BOP and LMRP
                                             must be compliant with API
                                             RP 17H (as incorporated by
                                             reference in Sec.
                                             250.198).
(5) Maintain an ROV and have a trained ROV  The crew must be trained in
 crew on each rig unit on a continuous       the operation of the ROV.
 basis once BOP deployment has been          The training must include
 initiated from the rig until recovered to   simulator training on
 the surface. The ROV crew must examine      stabbing into an ROV
 all ROV-related well-control equipment      intervention panel on a
 (both surface and subsea) to ensure that    subsea BOP stack. The ROV
 it is properly maintained and capable of    crew must be in
 carrying out appropriate tasks during       communication with
 emergency operations;                       designated rig personnel
                                             who are knowledgeable about
                                             the BOP's capabilities.
(6) Provide autoshear, deadman, and EDS     (i) Autoshear system means a
 systems for dynamically positioned rigs;    safety system that is
 provide autoshear and deadman systems for   designed to automatically
 moored rigs;                                shut-in the wellbore in the
                                             event of a disconnect of
                                             the LMRP. This is
                                             considered a rapid
                                             discharge system.
                                            (ii) Deadman system means a
                                             safety system that is
                                             designed to automatically
                                             shut-in the wellbore in the
                                             event of a simultaneous
                                             absence of hydraulic supply
                                             and signal transmission
                                             capacity in both subsea
                                             control pods. This is
                                             considered a rapid
                                             discharge system.
                                            (iii) Emergency Disconnect
                                             Sequence (EDS) system means
                                             a safety system that is
                                             designed to be manually
                                             activated to shut-in the
                                             wellbore and disconnect the
                                             LMRP in the event of an
                                             emergency situation. This
                                             is considered a rapid
                                             discharge system.
                                            (iv) Each emergency function
                                             must close at a minimum,
                                             two shear rams in sequence
                                             and be capable of
                                             performing its expected
                                             shearing and sealing action
                                             under MASP conditions as
                                             defined for the operation.
                                            (v) Your sequencing must
                                             allow a sufficient delay
                                             for closing the upper shear
                                             ram after beginning closure
                                             of the lower shear ram to
                                             provide for maximum sealing
                                             efficiency.
                                            (vi) The control system for
                                             the emergency functions
                                             must be a fail-safe design
                                             once activated.
(7) Demonstrate that any acoustic control   If you choose to use an
 system will function in the proposed        acoustic control system in
 environment and conditions;                 addition to the autoshear,
                                             deadman, and EDS
                                             requirements, you must
                                             demonstrate to the District
                                             Manager, as part of the
                                             information submitted under
                                             Sec. 250.731, that the
                                             acoustic control system
                                             will function in the
                                             proposed environment and
                                             conditions. The District
                                             Manager may require
                                             additional information as
                                             appropriate to clarify or
                                             evaluate the acoustic
                                             control system information
                                             provided in your
                                             demonstration.
(8) Have operational or physical            You must incorporate enable
 barrier(s) on BOP control panels to         buttons, or a similar
 prevent accidental disconnect functions;    feature, on control panels
                                             to ensure two-handed
                                             operation for all critical
                                             functions.
(9) Clearly label all control panels for    Label other BOP control
 the subsea BOP system;                      panels, such as hydraulic
                                             control panel.

[[Page 143]]

 
(10) Develop and use a management system    The management system must
 for operating the BOP system, including     include written procedures
 the prevention of accidental or unplanned   for operating the BOP stack
 disconnects of the system;                  and LMRP (including proper
                                             techniques to prevent
                                             accidental disconnection of
                                             these components) and
                                             minimum knowledge
                                             requirements for personnel
                                             authorized to operate and
                                             maintain BOP components.
(11) Establish minimum requirements for     Personnel must have:
 personnel authorized to operate critical   (i) Training in deepwater
 BOP equipment;                              well-control theory and
                                             practice according to the
                                             requirements of Subparts O
                                             and S; and
                                            (ii) A comprehensive
                                             knowledge of BOP hardware
                                             and control systems.
(12) Before removing the marine riser,      You must maintain sufficient
 displace the fluid in the riser with        hydrostatic pressure or
 seawater;                                   take other suitable
                                             precautions to compensate
                                             for the reduction in
                                             pressure and to maintain a
                                             safe and controlled well
                                             condition. You must follow
                                             the requirements of Sec.
                                             250.720(b).
(13) Install the BOP stack in a well        Your well cellar must be
 cellar when in an ice-scour area;           deep enough to ensure that
                                             the top of the stack is
                                             below the deepest probable
                                             ice-scour depth.
(14) Install at least two side outlets for  (i) If your stack does not
 a choke line and two side outlets for a     have side outlets, you must
 kill line;                                  install a drilling spool
                                             with side outlets.
                                            (ii) Each side outlet must
                                             have two full-bore, full-
                                             opening valves.
                                            (iii) The valves must hold
                                             pressure from both
                                             directions and must be
                                             remote-controlled.
                                            iv) You must install a side
                                             outlet below the lowest
                                             sealing shear ram. You may
                                             have a pipe ram or rams
                                             between the shearing ram
                                             and side outlet.
(15) Install a gas bleed line with two      (i) The valves must hold
 valves for the annular preventer no later   pressure from both
 than April 30, 2018;                        directions;
                                            (ii) If you have dual
                                             annulars, you must install
                                             the gas bleed line below
                                             the upper annular.
(16) Use a BOP system that has the          (i) A mechanism coupled with
 following mechanisms and capabilities;      each shear ram to position
                                             the entire pipe, completely
                                             within the area of the
                                             shearing blade and ensure
                                             shearing will occur any
                                             time the shear rams are
                                             activated. This mechanism
                                             cannot be another ram BOP
                                             or annular preventer, but
                                             you may use those during a
                                             planned shear. You must
                                             install this mechanism no
                                             later than May 1, 2023;
                                            (ii) The ability to mitigate
                                             compression of the pipe
                                             stub between the shearing
                                             rams when both shear rams
                                             are closed;
                                            (iii) If your control pods
                                             contain a subsea electronic
                                             module with batteries, a
                                             mechanism for personnel on
                                             the rig to monitor the
                                             state of charge of the
                                             subsea electronic module
                                             batteries in the BOP
                                             control pods.
------------------------------------------------------------------------

    (b) If operations are suspended to make repairs to any part of the 
subsea BOP system, you must stop operations at a safe downhole location. 
Before resuming operations you must:
    (1) Submit a revised permit with a verification report from a BAVO 
documenting the repairs and that the BOP is fit for service;
    (2) Upon relatch of the BOP, perform an initial subsea BOP test in 
accordance with Sec. 250.737(d)(4), including deadman. If repairs take 
longer than 30 days, once the BOP is on deck, you must test in 
accordance with the requirements of Sec. 250.737; and
    (3) Receive approval from the District Manager.
    (c) If you plan to drill a new well with a subsea BOP, you do not 
need to submit with your APD the verifications required by this subpart 
for the open water drilling operation. Before drilling out the surface 
casing, you must submit for approval a revised APD, including the 
verifications required in this subpart.



Sec. 250.735  What associated systems and related equipment must 
all BOP systems include?

    All BOP systems must include the following associated systems and 
related equipment:
    (a) An accumulator system (as specified in API Standard 53, and 
incorporated by reference in Sec. 250.198) that provides the volume of 
fluid capacity (as specified in API Standard 53, Annex C) necessary to 
close and hold closed all BOP components against MASP. The system must 
operate under MASP conditions as defined for the operation. You must be 
able to operate the BOP functions as defined in API Standard 53, without 
assistance from a charging

[[Page 144]]

system, and still have a minimum pressure of 200 psi remaining on the 
bottles above the pre-charge pressure. If you supply the accumulator 
regulators by rig air and do not have a secondary source of pneumatic 
supply, you must equip the regulators with manual overrides or other 
devices to ensure capability of hydraulic operations if rig air is lost;
    (b) An automatic backup to the primary accumulator-charging system. 
The power source must be independent from the power source for the 
primary accumulator-charging system. The independent power source must 
possess sufficient capability to close and hold closed all BOP 
components under MASP conditions as defined for the operation;
    (c) At least two full BOP control stations. One station must be on 
the rig floor. You must locate the other station in a readily accessible 
location away from the rig floor;
    (d) The choke line(s) installed above the bottom well-control ram;
    (e) The kill line must be installed beneath at least one well-
control ram, and may be installed below the bottom ram;
    (f) A fill-up line above the uppermost BOP;
    (g) Locking devices for all BOP sealing rams (i.e., blind shear 
rams, pipe rams and variable bore rams), as follows:
    (1) For subsea BOPs, hydraulic locking devices must be installed on 
all sealing rams;
    (2) For surface BOPs:
    (i) Remotely-operated locking devices must be installed on blind 
shear rams no later than April 29, 2019;
    (ii) Manual or remotely-operated locking devices must be installed 
on pipe rams and variable bore rams; and
    (h) A wellhead assembly with a RWP that exceeds the maximum 
anticipated wellhead pressure.



Sec. 250.736  What are the requirements for choke manifolds, kelly-type
valves inside BOPs, and drill string safety valves?

    (a) Your BOP system must include a choke manifold that is suitable 
for the anticipated surface pressures, anticipated methods of well 
control, the surrounding environment, and the corrosiveness, volume, and 
abrasiveness of drilling fluids and well fluids that you may encounter.
    (b) Choke manifold components must have a RWP at least as great as 
the RWP of the ram BOPs. If your choke manifold has buffer tanks 
downstream of choke assemblies, you must install isolation valves on any 
bleed lines.
    (c) Valves, pipes, flexible steel hoses, and other fittings upstream 
of the choke manifold must have a RWP at least as great as the RWP of 
the ram BOPs.
    (d) You must use the following BOP equipment with a RWP and 
temperature of at least as great as the working pressure and temperature 
of the ram BOP during all operations:
    (1) The applicable kelly-type valves as described in API Standard 53 
(incorporated by reference in Sec. 250.198);
    (2) On a top-drive system equipped with a remote-controlled valve, a 
strippable kelly-type valve must be installed below the remote-
controlled valve;
    (3) An inside BOP in the open position located on the rig floor. You 
must be able to install an inside BOP for each size connection in the 
pipe;
    (4) A drill string safety valve in the open position located on the 
rig floor. You must have a drill-string safety valve available for each 
size connection in the pipe;
    (5) When running casing, a safety valve in the open position 
available on the rig floor to fit the casing string being run in the 
hole;
    (6) All required manual and remote- controlled kelly-type valves, 
drill-string safety valves, and comparable-type valves (i.e., kelly-type 
valve in a top-drive system) that are essentially full opening; and
    (7) A wrench to fit each manual valve. Each wrench must be readily 
accessible to the drilling crew.



Sec. 250.737  What are the BOP system testing requirements?

    Your BOP system (this includes the choke manifold, kelly-type 
valves, inside BOP, and drill string safety valve) must meet the 
following testing requirements:
    (a) Pressure test frequency. You must pressure test your BOP system:

[[Page 145]]

    (1) When installed;
    (2) Before 14 days have elapsed since your last BOP pressure test, 
or 30 days since your last blind shear ram BOP pressure test. You must 
begin to test your BOP system before midnight on the 14th day (or 30th 
day for your blind shear rams) following the conclusion of the previous 
test;
    (3) Before drilling out each string of casing or a liner. You may 
omit this pressure test requirement if you did not remove the BOP stack 
to run the casing string or liner, the required BOP test pressures for 
the next section of the hole are not greater than the test pressures for 
the previous BOP test, and the time elapsed between tests has not 
exceeded 14 days (or 30 days for blind shear rams). You must indicate in 
your APD which casing strings and liners meet these criteria;
    (4) The District Manager may require more frequent testing if 
conditions or your BOP performance warrant.
    (b) Pressure test procedures. When you pressure test the BOP system, 
you must conduct a low-pressure test and a high-pressure test for each 
BOP component. You must begin each test by conducting the low-pressure 
test then transition to the high-pressure test. Each individual pressure 
test must hold pressure long enough to demonstrate the tested 
component(s) holds the required pressure. The table in this paragraph 
(b) outlines your pressure test requirements.

------------------------------------------------------------------------
                                         According to the following
     You must conduct a . . .                 procedures . . .
------------------------------------------------------------------------
(1) Low-pressure test.............  All low-pressure tests must be
                                     between 250 and 350 psi. Any
                                     initial pressure above 350 psi must
                                     be bled back to a pressure between
                                     250 and 350 psi before starting the
                                     test. If the initial pressure
                                     exceeds 500 psi, you must bleed
                                     back to zero and reinitiate the
                                     test.
(2) High-pressure test for blind    The high-pressure test must equal
 shear ram-type BOPs, ram-type       the RWP of the equipment or be 500
 BOPs, the choke manifold, outside   psi greater than your calculated
 of all choke and kill side outlet   MASP, as defined for the operation
 valves (and annular gas bleed       for the applicable section of hole.
 valves for subsea BOP), inside of   Before you may test BOP equipment
 all choke and kill side outlet      to the MASP plus 500 psi, the
 valves below uppermost ram, and     District Manager must have approved
 other BOP components.               those test pressures in your APD.
(3) High-pressure test for annular- The high pressure test must equal 70
 type BOPs, inside of choke or       percent of the RWP of the equipment
 kill valves (and annular gas        or be 500 psi greater than your
 bleed valves for subsea BOP)        calculated MASP, as defined for the
 above the uppermost ram BOP.        operation for the applicable
                                     section of hole. Before you may
                                     test BOP equipment to the MASP plus
                                     500 psi, the District Manager must
                                     have approved those test pressures
                                     in your APD.
------------------------------------------------------------------------

    (c) Duration of pressure test. Each test must hold the required 
pressure for 5 minutes, which must be recorded on a chart not exceeding 
4 hours. However, for surface BOP systems and surface equipment of a 
subsea BOP system, a 3-minute test duration is acceptable if recorded on 
a chart not exceeding 4 hours, or on a digital recorder. The recorded 
test pressures must be within the middle half of the chart range, i.e., 
cannot be within the lower or upper one-fourth of the chart range. If 
the equipment does not hold the required pressure during a test, you 
must correct the problem and retest the affected component(s).
    (d) Additional test requirements. You must meet the following 
additional BOP testing requirements:

------------------------------------------------------------------------
          You must . . .                Additional requirements . . .
------------------------------------------------------------------------
(1) Follow the testing              If there is a conflict between API
 requirements of API Standard 53     Standard 53, testing requirements
 (as incorporated in Sec. and this section, you must follow
 250.198).                           the requirements of this section.
(2) Use water to test a surface     (i) You must submit test procedures
 BOP system on the initial test.     with your APD or APM for District
 You may use drilling/completion/    Manager approval.
 workover fluids to conduct         (ii) Contact the District Manager at
 subsequent tests of a surface BOP   least 72 hours prior to beginning
 system.                             the initial test to allow BSEE
                                     representative(s) to witness
                                     testing. If BSEE representative(s)
                                     are unable to witness testing, you
                                     must provide the initial test
                                     results to the appropriate District
                                     Manager within 72 hours after
                                     completion of the tests.
(3) Stump test a subsea BOP system  (i) You must use water to conduct
 before installation.                this test. You may use drilling/
                                     completion/workover fluids to
                                     conduct subsequent tests of a
                                     subsea BOP system.

[[Page 146]]

 
                                    (ii) You must submit test procedures
                                     with your APD or APM for District
                                     Manager approval
                                    (iii) Contact the District Manager
                                     at least 72 hours prior to
                                     beginning the stump test to allow
                                     BSEE representative(s) to witness
                                     testing. If BSEE representative(s)
                                     are unable to witness testing, you
                                     must provide the test results to
                                     the appropriate District Manager
                                     within 72 hours after completion of
                                     the tests.
                                    (iv) You must test and verify
                                     closure of all ROV intervention
                                     functions on your subsea BOP stack
                                     during the stump test.
                                    (v) You must follow paragraphs (b)
                                     and (c) of this section.
(4) Perform an initial subsea BOP   (i) You must perform the initial
 test.                               subsea BOP test on the seafloor
                                     within 30 days of the stump test.
                                    (ii) You must submit test procedures
                                     with your APD or APM for District
                                     Manager approval.
                                    (iii) You must pressure test well-
                                     control rams according to
                                     paragraphs (b) and (c) of this
                                     section.
                                    (iv) You must notify the District
                                     Manager at least 72 hours prior to
                                     beginning the initial subsea test
                                     for the BOP system to allow BSEE
                                     representative(s) to witness
                                     testing.
                                    (v) You must test and verify closure
                                     of at least one set of rams during
                                     the initial subsea test through a
                                     ROV hot stab.
                                    (vi) You must pressure test the
                                     selected rams according to
                                     paragraphs (b) and (c) of this
                                     section.
(5) Alternate testing pods between  (i) For two complete BOP control
 control stations.                   stations:
                                    (A) Designate a primary and
                                     secondary station, and both
                                     stations must be function-tested
                                     weekly;
                                    (B) The control station used for the
                                     pressure test must be alternated
                                     between pressure tests; and
                                    (C) For a subsea BOP, the pods must
                                     be rotated between control stations
                                     during weekly function testing and
                                     14 day pressure testing.
                                    (ii) Remote panels where all BOP
                                     functions are not included (e.g.,
                                     life boat panels) must be function-
                                     tested upon the initial BOP tests
                                     and monthly thereafter.
(6) Pressure test variable bore-
 pipe ram BOPs against pipe sizes
 according to API Standard 53,
 excluding the bottom hole
 assembly that includes heavy-
 weight pipe or collars and bottom-
 hole tools.
(7) Pressure test annular type
 BOPs against pipe sizes according
 to API Standard 53.
(8) Pressure test affected BOP
 components following the
 disconnection or repair of any
 well-pressure containment seal in
 the wellhead or BOP stack
 assembly.
(9) Function test annular and pipe/
 variable bore ram BOPs every 7
 days between pressure tests.
(10) Function test shear ram(s)
 BOPs every 14 days.
(11) Actuate safety valves
 assembled with proper casing
 connections before running casing.

[[Page 147]]

 
(12) Function test autoshear/       (i) You must submit test procedures
 deadman, and EDS systems            with your APD or APM for District
 separately on your subsea BOP       Manager approval. The procedures
 stack during the stump test. The    for these function tests must
 District Manager may require        include the schematics of the
 additional testing of the           actual controls and circuitry of
 emergency systems. You must also    the system that will be used during
 test the deadman system and         an actual autoshear or deadman
 verify closure of the shearing      event.
 rams during the initial test on    (ii) The procedures must also
 the seafloor.                       include the actions and sequence of
                                     events that take place on the
                                     approved schematics of the BOP
                                     control system and describe
                                     specifically how the ROV will be
                                     utilized during this operation.
                                    (iii) When you conduct the initial
                                     deadman system test on the
                                     seafloor, you must ensure the well
                                     is secure and, if hydrocarbons have
                                     been present, appropriate barriers
                                     are in place to isolate
                                     hydrocarbons from the wellhead. You
                                     must also have an ROV on bottom
                                     during the test.
                                    (iv) The testing of the deadman
                                     system on the seafloor must
                                     indicate the discharge pressure of
                                     the subsea accumulator system
                                     throughout the test.
                                    (v) For the function test of the
                                     deadman system during the initial
                                     test on the seafloor, you must have
                                     the ability to quickly disconnect
                                     the LMRP should the rig experience
                                     a loss of station-keeping event.
                                     You must include your quick-
                                     disconnect procedures with your
                                     deadman test procedures.
                                    (vi) You must pressure test the
                                     blind shear ram(s) according to
                                     paragraphs (b) and (c) of this
                                     section.
                                    (vii) If a casing shear ram is
                                     installed, you must describe how
                                     you will verify closure of the ram.
                                    (viii) You must document all your
                                     test results and make them
                                     available to BSEE upon request.
------------------------------------------------------------------------

    (e) Prior to conducting any shear ram tests in which you will shear 
pipe, you must notify the District Manager at least 72 hours in advance, 
to ensure that a BSEE representative will have access to the location to 
witness any testing.



Sec. 250.738  What must I do in certain situations involving BOP 
equipment or systems?

    The table in this section describes actions that you must take when 
certain situations occur with BOP systems.

------------------------------------------------------------------------
    If you encounter the following
              situation:                      Then you must . . .
------------------------------------------------------------------------
(a) BOP equipment does not hold the    Correct the problem and retest
 required pressure during a test;       the affected equipment. You must
                                        report any problems or
                                        irregularities, including any
                                        leaks, on the daily report as
                                        required in Sec. 250.746.
(b) Need to repair, replace, or        (1) First place the well in a
 reconfigure a surface or subsea BOP    safe, controlled condition as
 system;                                approved by the District Manager
                                        (e.g., before drilling out a
                                        casing shoe or after setting a
                                        cement plug, bridge plug, or a
                                        packer).
                                       (2) Any repair or replacement
                                        parts must be manufactured under
                                        a quality assurance program and
                                        must meet or exceed the
                                        performance of the original part
                                        produced by the OEM.
                                       (3) You must receive approval
                                        from the District Manager prior
                                        to resuming operations with the
                                        new, repaired, or reconfigured
                                        BOP.
                                       (4) You must submit a report from
                                        a BAVO to the District Manager
                                        certifying that the BOP is fit
                                        for service.
(c) Need to postpone a BOP test due    Record the reason for postponing
 to well-control problems such as       the test in the daily report and
 lost circulation, formation fluid      conduct the required BOP test
 influx, or stuck pipe;                 after the first trip out of the
                                        hole.
(d) BOP control station or pod that    Suspend operations until that
 does not function properly;            station or pod is operable. You
                                        must report any problems or
                                        irregularities, including any
                                        leaks, to the District Manager.
(e) Plan to operate with a tapered     Install two or more sets of
 string;                                conventional or variable-bore
                                        pipe rams in the BOP stack to
                                        provide for the following: two
                                        sets of rams must be capable of
                                        sealing around the larger-size
                                        drill string and one set of pipe
                                        rams must be capable of sealing
                                        around the smaller size pipe,
                                        excluding the bottom hole
                                        assembly that includes heavy
                                        weight pipe or collars and
                                        bottom-hole tools.
(f) Plan to install casing rams or     Test the affected connections
 casing shear rams in a surface BOP     before running casing to the RWP
 stack;                                 or MASP plus 500 psi. If this
                                        installation was not included in
                                        your approved permit, and
                                        changes the BOP configuration
                                        approved in the APD or APM, you
                                        must notify and receive approval
                                        from the District Manager.
(g) Plan to use an annular BOP with a  Demonstrate that your well-
 RWP less than the anticipated          control procedures or the
 surface pressure;                      anticipated well conditions will
                                        not place demands above its RWP
                                        and obtain approval from the
                                        District Manager.

[[Page 148]]

 
(h) Plan to use a subsea BOP system    Install the BOP stack in a well
 in an ice-scour area;                  cellar. The well cellar must be
                                        deep enough to ensure that the
                                        top of the stack is below the
                                        deepest probable ice-scour
                                        depth.
(i) You activate any shear ram and     Retrieve, physically inspect, and
 pipe or casing is sheared;             conduct a full pressure test of
                                        the BOP stack after the
                                        situation is fully controlled.
                                        You must submit to the District
                                        Manager a report from a BSEE-
                                        approved verification
                                        organization certifying that the
                                        BOP is fit to return to service.
(j) Need to remove the BOP stack;      Have a minimum of two barriers in
                                        place prior to BOP removal. You
                                        must obtain approval from the
                                        District Manager of the two
                                        barriers prior to removal and
                                        the District Manager may require
                                        additional barriers and test(s).
(k) In the event of a deadman or       Place the blind shear ram opening
 autoshear activation, if there is a    function in the block position
 possibility of the blind shear ram     prior to re-establishing power
 opening immediately upon re-           to the stack. Contact the
 establishing power to the BOP stack;   District Manager and receive
                                        approval of procedures for re-
                                        establishing power and functions
                                        prior to latching up the BOP
                                        stack or re-establishing power
                                        to the stack.
(l) If a test ram is to be used;       The wellhead/BOP connection must
                                        be tested to the MASP plus 500
                                        psi for the hole section to
                                        which it is exposed. This can be
                                        done by:
                                       (1) Testing wellhead/BOP
                                        connection to the MASP plus 500
                                        psi for the well upon
                                        installation;
                                       (2) Pressure testing each casing
                                        to the MASP plus 500 psi for the
                                        next hole section; or
                                       (3) Some combination of
                                        paragraphs (l)(1) and (2) of
                                        this section.
(m) Plan to utilize any other well-    Contact the District Manager and
 control equipment (e.g., but not       request approval in your APD or
 limited to, subsea isolation device,   APM. Your request must include a
 subsea accumulator module, or gas      report from a BAVO on the
 handler) that is in addition to the    equipment's design and
 equipment required in this subpart;    suitability for its intended use
                                        as well as any other information
                                        required by the District
                                        Manager. The District Manager
                                        may impose any conditions
                                        regarding the equipment's
                                        capabilities, operation, and
                                        testing.
(n) You have pipe/variable bore rams   Indicate in your APD or APM which
 that have no current utility or well-  pipe/variable bore rams meet
 control purposes;                      these criteria and clearly label
                                        them on all BOP control panels.
                                        You do not need to function test
                                        or pressure test pipe/variable
                                        bore rams having no current
                                        utility, and that will not be
                                        used for well-control purposes,
                                        until such time as they are
                                        intended to be used during
                                        operations.
(o) You install redundant components   Comply with all testing,
 for well control in your BOP system    maintenance, and inspection
 that are in addition to the required   requirements in this subpart
 components of this subpart (e.g.,      that are applicable to those
 pipe/variable bore rams, shear rams,   well-control components. If any
 annular preventers, gas bleed lines,   redundant component fails a
 and choke/kill side outlets or         test, you must submit a report
 lines);                                from a BAVO that describes the
                                        failure and confirms that there
                                        is no impact on the BOP that
                                        will make it unfit for well-
                                        control purposes. You must
                                        submit this report to the
                                        District Manager and receive
                                        approval before resuming
                                        operations. The District Manager
                                        may require you to provide
                                        additional information as needed
                                        to clarify or evaluate your
                                        report.
(p) Need to position the bottom hole   Ensure that the well is stable
 assembly, including heavy-weight       prior to positioning the bottom
 pipe or collars, and bottom-hole       hole assembly across the BOP.
 tools across the BOP for tripping or   You must have, as part of your
 any other operations.                  well-control plan required by
                                        Sec. 250.710, procedures that
                                        enable the removal of the bottom
                                        hole assembly from across the
                                        BOP in the event of a well-
                                        control or emergency situation
                                        (for dynamically positioned
                                        rigs, your plan must also
                                        include steps for when the EDS
                                        must be activated) before MASP
                                        conditions are reached as
                                        defined for the operation.
------------------------------------------------------------------------



Sec. 250.739  What are the BOP maintenance and inspection requirements?

    (a) You must maintain and inspect your BOP system to ensure that the 
equipment functions as designed. The BOP maintenance and inspections 
must meet or exceed any OEM recommendations, recognized engineering 
practices, and industry standards incorporated by reference into the 
regulations of this subpart, including API Standard 53 (incorporated by 
reference in Sec. 250.198). You must document how you met or exceeded 
the provisions of API Standard 53, maintain complete records to ensure 
the traceability of BOP stack equipment beginning at fabrication, and 
record the results of your BOP inspections and maintenance actions. You 
must make all records available to BSEE upon request.
    (b) A complete breakdown and detailed physical inspection of the BOP 
and every associated system and component must be performed every 5 
years. This complete breakdown and inspection may be performed in phased 
intervals. You must track and document all system and component 
inspection dates. These records must be available on the rig. A BAVO is 
required to be present during each inspection and must compile a 
detailed report documenting the inspection, including descriptions of 
any problems

[[Page 149]]

and how they were corrected. You must make these reports available to 
BSEE upon request. This complete breakdown and inspection must be 
performed every 5 years from the following applicable dates, whichever 
is later:
    (1) The date the equipment owner accepts delivery of a new build 
drilling rig with a new BOP system;
    (2) The date the new, repaired, or remanufactured equipment is 
initially installed into the system; or
    (3) The date of the last 5 year inspection for the component.
    (c) You must visually inspect your surface BOP system on a daily 
basis. You must visually inspect your subsea BOP system, marine riser, 
and wellhead at least once every 3 days if weather and sea conditions 
permit. You may use cameras to inspect subsea equipment.
    (d) You must ensure that all personnel maintaining, inspecting, or 
repairing BOPs, or critical components of the BOP system, are trained in 
accordance with applicable training requirements in subpart S of this 
part, any applicable OEM criteria, recognized engineering practices, and 
industry standards incorporated by reference in this subpart.
    (e) You must make all records available to BSEE upon request. You 
must ensure that the rig unit owner maintains the BOP maintenance, 
inspection, and repair records on the rig unit for 2 years from the date 
the records are created or for a longer period if directed by BSEE. You 
must ensure that all equipment schematics, maintenance, inspection, and 
repair records are located at an onshore location for the service life 
of the equipment.

                          Records and Reporting



Sec. 250.740  What records must I keep?

    You must keep a daily report consisting of complete, legible, and 
accurate records for each well. You must keep records onsite while well 
operations continue. After completion of operations, you must keep all 
operation and other well records for the time periods shown in 
Sec. 250.741 at a location of your choice, except as required in 
Sec. 250.746. The records must contain complete information on all of 
the following:
    (a) Well operations, all testing conducted, and any real-time 
monitoring data as required by Sec. 250.724;
    (b) Descriptions of formations penetrated;
    (c) Content and character of oil, gas, water, and other mineral 
deposits in each formation;
    (d) Kind, weight, size, grade, and setting depth of casing;
    (e) All well logs and surveys run in the wellbore;
    (f) Any significant malfunction or problem; and
    (g) All other information required by the District Manager as 
appropriate to ensure compliance with the requirements of this section 
and to enable BSEE to determine that the well operations are consistent 
with conservation of natural resources and protection of safety and the 
environment on the OCS.



Sec. 250.741  How long must I keep records?

    You must keep records for the time periods shown in the following 
table.

------------------------------------------------------------------------
  You must keep records relating to . . .            Until . . .
------------------------------------------------------------------------
(a) Drilling;                               90 days after you complete
                                             operations.
(b) Casing and liner pressure tests,        2 years after the completion
 diverter tests, BOP tests, and real-time    of operations.
 monitoring data;
(c) Completion of a well or of any          You permanently plug and
 workover activity that materially alters    abandon the well or until
 the completion configuration or affects a   you assign the lease and
 hydrocarbon-bearing zone.                   forward the records to the
                                             assignee.
------------------------------------------------------------------------



Sec. 250.742  What well records am I required to submit?

    You must submit to BSEE copies of logs or charts of electrical, 
radioactive, sonic, and other well logging operations; directional and 
vertical well surveys; velocity profiles and surveys; and analysis of 
cores. Each Region will provide specific instructions for submitting 
well logs and surveys.

[[Page 150]]



Sec. 250.743  What are the well activity reporting requirements?

    (a) For operations in the BSEE Gulf of Mexico (GOM) OCS Region, you 
must submit Form BSEE-0133, Well Activity Report (WAR), to the District 
Manager on a weekly basis. The reporting week is defined as beginning on 
Sunday (12 a.m.) and ending on the following Saturday (11:59 p.m.). This 
reporting week corresponds to a week (Sunday through Saturday) on a 
standard calendar. Report any well operations that extend past the end 
of this weekly reporting period on the next weekly report. The reporting 
period for the weekly report is never longer than 7 days, but could be 
less than 7 days for the first reporting period and the last reporting 
period for a particular well operation. Submit each WAR and accompanying 
Form BSEE-0133S, Open Hole Data Report, to the BSEE GOM OCS Region no 
later than close of business on the Friday immediately after the closure 
of the reporting week. The District Manager may require more frequent 
submittal of the WAR on a case-by-case basis.
    (b) For operations in the Pacific or Alaska OCS Regions, you must 
submit Form BSEE-0133, WAR, to the District Manager on a daily basis.
    (c) The WAR must include a description of the operations conducted, 
any abnormal or significant events that affect the permitted operation 
each day within the report from the time you begin operations to the 
time you end operations, any verbal approval received, the well's as-
built drawings, casing, fluid weights, shoe tests, test pressures at 
surface conditions, and any other information concerning well activities 
required by the District Manager. For casing cementing operations, 
indicate type of returns (i.e., full, partial, or none). If partial or 
no returns are observed, you must indicate how you determined the top of 
cement. For each report, indicate the operation status for the well at 
the end of the reporting period. On the final WAR, indicate the status 
of the well (completed, temporarily abandoned, permanently abandoned, or 
drilling suspended) and the date you finished such operations.



Sec. 250.744  What are the end of operation reporting requirements?

    (a) Within 30 days after completing operations, except routine 
operations as defined in Sec. 250.601, you must submit Form BSEE-0125, 
End of Operations Report (EOR), to the District Manager. The EOR must 
include: a listing, with top and bottom depths, of all hydrocarbon zones 
and other zones of porosity encountered with any cored intervals; 
details on any drill-stem and formation tests conducted; documentation 
of successful negative pressure testing on wells that use a subsea BOP 
stack or wells with mudline suspension systems; and an updated schematic 
of the full wellbore configuration. The schematic must be clearly 
labeled and show all applicable top and bottom depths, locations and 
sizes of all casings, cut casing or stubs, casing perforations, casing 
rupture discs (indicate if burst or collapse and rating), cemented 
intervals, cement plugs, mechanical plugs, perforated zones, completion 
equipment, production and isolation packers, alternate completions, 
tubing, landing nipples, subsurface safety devices, and any other 
information required by the District Manager regarding the end of well 
operations. The EOR must indicate the status of the well (completed, 
temporarily abandoned, permanently abandoned, or drilling suspended) and 
the date of the well status designation. The well status date is subject 
to the following:
    (1) For surface well operations and riserless subsea operations, the 
operations end date is subject to the discretion of the District 
Manager; and
    (2) For subsea well operations, the operations end date is 
considered to be the date the BOP is disconnected from the wellhead 
unless otherwise specified by the District Manager.
    (b) You must submit public information copies of Form BSEE-0125 
according to Sec. 250.186(b).



Sec. 250.745  What other well records could I be required to submit?

    The District Manager or Regional Supervisor may require you to 
submit copies of any or all of the following well records:
    (a) Well records as specified in Sec. 250.740;

[[Page 151]]

    (b) Paleontological interpretations or reports identifying 
microscopic fossils by depth and/or washed samples of drill cuttings 
that you normally maintain for paleontological determinations. The 
Regional Supervisor may issue a Notice to Lessees that sets forth the 
manner, timeframe, and format for submitting this information;
    (c) Service company reports on cementing, perforating, acidizing, 
testing, or other similar services; or
    (d) Other reports and records of operations.



Sec. 250.746  What are the recordkeeping requirements for casing,
liner, and BOP tests, and inspections of BOP systems and marine 
risers?

    You must record the time, date, and results of all casing and liner 
pressure tests. You must also record pressure tests, actuations, and 
inspections of the BOP system, system components, and marine riser in 
the daily report described in Sec. 250.740. In addition, you must:
    (a) Record test pressures on pressure charts or digital recorders;
    (b) Require your onsite lessee representative, designated rig or 
contractor representative, and pump operator to sign and date the 
pressure charts or digital recordings and daily reports as correct;
    (c) Document on the daily report the sequential order of BOP and 
auxiliary equipment testing and the pressure and duration of each test. 
For subsea BOP systems, you must also record the closing times for 
annular and ram BOPs. You may reference a BOP test plan if it is 
available at the facility;
    (d) Identify on the daily report the control station and pod used 
during the test (identifying the pod does not apply to coiled tubing and 
snubbing units);
    (e) Identify on the daily report any problems or irregularities 
observed during BOP system testing and record actions taken to remedy 
the problems or irregularities. Any leaks associated with the BOP or 
control system during testing must be documented in the WAR. If any 
problems that cannot be resolved promptly are observed during testing, 
operations must be suspended until the District Manager determines that 
you may continue; and
    (f) Retain all records, including pressure charts, daily reports, 
and referenced documents pertaining to tests, actuations, and 
inspections at the rig unit for the duration of the operation. After 
completion of the operation, you must retain all the records listed in 
this section for a period of 2 years at the rig unit. You must also 
retain the records at the lessee's field office nearest the facility or 
at another location available to BSEE. You must make all the records 
available to BSEE upon request.



             Subpart H_Oil and Gas Production Safety Systems

    Source: 81 FR 60918, Sept. 7, 2016, unless otherwise noted.

                          General Requirements



Sec. 250.800  General.

    (a) You must design, install, use, maintain, and test production 
safety equipment in a manner to ensure the safety and protection of the 
human, marine, and coastal environments. For production safety systems 
operated in subfreezing climates, you must use equipment and procedures 
that account for floating ice, icing, and other extreme environmental 
conditions that may occur in the area. You must not commence production 
until BSEE approves your production safety system application and you 
have requested a preproduction inspection.
    (b) For all new production systems on fixed leg platforms, you must 
comply with API RP 14J (incorporated by reference as specified in 
Sec. 250.198);
    (c) For all new floating production systems (FPSs) (e.g., column-
stabilized-units (CSUs); floating production, storage and offloading 
facilities (FPSOs); tension-leg platforms (TLPs); and spars), you must:
    (1) Comply with API RP 14J;
    (2) Meet the production riser standards of API RP 2RD (incorporated 
by reference as specified in Sec. 250.198), provided that you may not 
install single bore production risers from floating production 
facilities;
    (3) Design all stationkeeping (i.e., anchoring and mooring) systems 
for floating production facilities to meet

[[Page 152]]

the standards of API RP 2SK and API RP 2SM (both incorporated by 
reference as specified in Sec. 250.198); and
    (4) Design stationkeeping (i.e., anchoring and mooring) systems for 
floating facilities to meet the structural requirements of Secs. 250.900 
through 250.921.
    (d) If there are any conflicts between the documents incorporated by 
reference and the requirements of this subpart, you must follow the 
requirements of this subpart.
    (e) You may use alternate procedures or equipment during operations 
after receiving approval from the District Manager. You must present 
your proposed alternate procedures or equipment as required by 
Sec. 250.141.
    (f) You may apply for a departure from the operating requirements of 
this subpart as provided by Sec. 250.142. Your written request must 
include a justification showing why the departure is necessary and 
appropriate.



Sec. 250.801  Safety and pollution prevention equipment (SPPE)
certification.

    (a) SPPE equipment. In wells located on the OCS, you must install 
only safety and pollution prevention equipment (SPPE) considered 
certified under paragraph (b) of this section or accepted under 
paragraph (c) of this section. BSEE considers the following equipment to 
be types of SPPE:
    (1) Surface safety valves (SSV) and actuators, including those 
installed on injection wells capable of natural flow;
    (2) Boarding shutdown valves (BSDV) and their actuators, as of 
September 7, 2017. For subsea wells, the BSDV is the surface equivalent 
of an SSV on a surface well;
    (3) Underwater safety valves (USV) and actuators; and
    (4) Subsurface safety valves (SSSV) and associated safety valve 
locks and landing nipples.
    (b) Certification of SPPE. SPPE that is manufactured and marked 
pursuant to ANSI/API Spec. Q1 (incorporated by reference as specified in 
Sec. 250.198), is considered as certified SPPE under this part. All 
other SPPE is considered as not certified, unless approved in accordance 
with paragraph (c) of this section.
    (c) Accepting SPPE manufactured under other quality assurance 
programs. BSEE may exercise its discretion to accept SPPE manufactured 
under a quality assurance program other than ANSI/API Spec. Q1, provided 
that the alternative quality assurance program is verified as equivalent 
to API Spec. Q1 by an appropriately qualified entity and that the 
operator submits a request to BSEE containing relevant information about 
the alternative program and receives BSEE approval. In addition, an 
operator may request that BSEE accept SPPE that is marked with a third-
party certification mark other than the API monogram. All requests under 
this paragraph should be submitted to the Chief, Office of Offshore 
Regulatory Programs; Bureau of Safety and Environmental Enforcement; 
VAE-ORP; 45600 Woodland Road, Sterling, VA 20166.



Sec. 250.802  Requirements for SPPE.

    (a) All SSVs, BSDVs, and USVs and their actuators must meet all of 
the specifications contained in ANSI/API Spec. 6A and API Spec. 6AV1 
(both incorporated by reference as specified in Sec. 250.198).
    (b) All SSSVs and their actuators must meet all of the 
specifications and recommended practices of ANSI/API Spec. 14A and ANSI/
API RP 14B, including all annexes (both incorporated by reference as 
specified in Sec. 250.198). Subsurface-controlled SSSVs are not allowed 
on subsea wells.
    (c) Requirements derived from the documents incorporated in this 
section for SSVs, BSDVs, USVs, and SSSVs and their actuators, include, 
but are not limited to, the following:
    (1) Each device must be designed to function and to close in the 
most extreme conditions to which it may be exposed, including 
temperature, pressure, flow rates, and environmental conditions. You 
must have an independent third-party review and certify that each device 
will function as designed under the conditions to which it may be 
exposed. The independent third-party must have sufficient expertise and 
experience to perform the review and certification.

[[Page 153]]

    (2) All materials and parts must meet the original equipment 
manufacturer specifications and acceptance criteria.
    (3) The device must pass applicable validation tests and functional 
tests performed by an API-licensed test agency.
    (4) You must have requalification testing performed following 
manufacture design changes.
    (5) You must comply with and document all manufacturing, 
traceability, quality control, and inspection requirements.
    (6) You must follow specified installation, testing, and repair 
protocols.
    (7) You must use only qualified parts, procedures, and personnel to 
repair or redress equipment.
    (d) You must install and use SPPE according to the following table.

------------------------------------------------------------------------
                If . . .                            Then . . .
------------------------------------------------------------------------
(1) You need to install any SPPE . . ..  You must install SPPE that
                                          conforms to Sec. 250.801.
(2) A non-certified SPPE is already in   It may remain in service on
 service . . ..                           that well.
(3) A non-certified SPPE requires        You must replace it with SPPE
 offsite repair, re-manufacturing, or     that conforms to Sec.
 any hot work such as welding . . ..      250.801.
------------------------------------------------------------------------

    (e) You must retain all documentation related to the manufacture, 
installation, testing, repair, redress, and performance of the SPPE 
until 1 year after the date of decommissioning of the equipment.



Sec. 250.803  What SPPE failure reporting procedures must I follow?

    (a) You must follow the failure reporting requirements contained in 
section 10.20.7.4 of API Spec. 6A for SSVs, BSDVs, and USVs and section 
7.10 of API Spec. 14A and Annex F of API RP 14B for SSSVs (all 
incorporated by reference in Sec. 250.198). You must provide a written 
notice of equipment failure to the Chief, Office of Offshore Regulatory 
Programs or to the Chief's designee and to the manufacturer of such 
equipment within 30 days after the discovery and identification of the 
failure. A failure is any condition that prevents the equipment from 
meeting the functional specification or purpose.
    (b) You must ensure that an investigation and a failure analysis are 
performed within 120 days of the failure to determine the cause of the 
failure. If the investigation and analyses are performed by an entity 
other than the manufacturer, you must ensure that manufacturer and the 
Chief, Office of Offshore Regulatory Programs or the Chief's designee 
receives a copy of the analysis report. You must also ensure that the 
results of the investigation and any corrective action are documented in 
the analysis report.
    (c) If the equipment manufacturer notifies you that it has changed 
the design of the equipment that failed or if you have changed operating 
or repair procedures as a result of a failure, then you must, within 30 
days of such changes, report the design change or modified procedures in 
writing to the Chief, Office of Offshore Regulatory Programs or the 
Chief's designee.
    (d) Any notifications or reports submitted to the Chief, Office of 
Offshore Regulatory Programs under paragraphs (a), (b), and (c) of this 
section must be sent to: Bureau of Safety and Environmental Enforcement; 
VAE-ORP, 45600 Woodland Road, Sterling, VA 20166.



Sec. 250.804  Additional requirements for subsurface safety valves
(SSSVs) and related equipment installed in high pressure high 
temperature (HPHT) environments.

    (a) If you plan to install SSSVs and related equipment in an HPHT 
environment, you must submit detailed information with your Application 
for Permit to Drill (APD) or Application for Permit to Modify (APM), and 
Deepwater Operations Plan (DWOP) that demonstrates the SSSVs and related 
equipment are capable of performing in the applicable HPHT environment. 
Your detailed information must include the following:
    (1) A discussion of the SSSVs' and related equipment's design 
verification analyses;
    (2) A discussion of the SSSVs' and related equipment's design 
validation

[[Page 154]]

and functional testing processes and procedures used; and
    (3) An explanation of why the analyses, processes, and procedures 
ensure that the SSSVs and related equipment are fit-for-service in the 
applicable HPHT environment.
    (b) For this section, HPHT environment means when one or more of the 
following well conditions exist:
    (1) The completion of the well requires completion equipment or well 
control equipment assigned a pressure rating greater than 15,000 psia or 
a temperature rating greater than 350 degrees Fahrenheit;
    (2) The maximum anticipated surface pressure or shut-in tubing 
pressure is greater than 15,000 psia on the seafloor for a well with a 
subsea wellhead or at the surface for a well with a surface wellhead; or
    (3) The flowing temperature is equal to or greater than 350 degrees 
Fahrenheit on the seafloor for a well with a subsea wellhead or at the 
surface for a well with a surface wellhead.
    (c) For this section, related equipment includes wellheads, tubing 
heads, tubulars, packers, threaded connections, seals, seal assemblies, 
production trees, chokes, well control equipment, and any other 
equipment that will be exposed to the HPHT environment.



Sec. 250.805  Hydrogen sulfide.

    (a) In zones known to contain hydrogen sulfide (H2S) or 
in zones where the presence of H2S is unknown, as defined in 
Sec. 250.490, you must conduct production operations in accordance with 
that section and other relevant requirements of this subpart.
    (b) You must receive approval through the DWOP process 
(Secs. 250.286 through 250.295) for production operations in HPHT 
environments known to contain H2S or in HPHT environments 
where the presence of H2S is unknown.



Secs. 250.806--250.809  [Reserved]

            Surface and Subsurface Safety Systems--Dry Trees



Sec. 250.810  Dry tree subsurface safety devices--general.

    For wells using dry trees or for which you intend to install dry 
trees, you must equip all tubing installations open to hydrocarbon-
bearing zones with subsurface safety devices that will shut off the flow 
from the well in the event of an emergency unless, after you submit a 
request containing a justification, the District Manager determines the 
well to be incapable of natural flow. You must install flow couplings 
above and below the subsurface safety devices. These subsurface safety 
devices include the following devices and any associated safety valve 
lock and landing nipple:
    (a) An SSSV, including either:
    (1) A surface-controlled SSSV; or
    (2) A subsurface-controlled SSSV.
    (b) An injection valve.
    (c) A tubing plug.
    (d) A tubing/annular subsurface safety device.



Sec. 250.811  Specifications for SSSVs--dry trees.

    All surface-controlled and subsurface-controlled SSSVs, safety valve 
locks, and landing nipples installed in the OCS must conform to the 
requirements specified in Secs. 250.801 through 250.803.



Sec. 250.812  Surface-controlled SSSVs--dry trees.

    You must equip all tubing installations open to a hydrocarbon-
bearing zone that is capable of natural flow with a surface-controlled 
SSSV, except as specified in Secs. 250.813, 250.815, and 250.816.
    (a) The surface controls must be located on the site or at a BSEE-
approved remote location. You may request District Manager approval to 
situate the surface controls at a remote location.
    (b) You must equip dry tree wells not previously equipped with a 
surface-controlled SSSV, and dry tree wells in which a surface-
controlled SSSV has

[[Page 155]]

been replaced with a subsurface-controlled SSSV, with a surface-
controlled SSSV when the tubing is first removed and reinstalled.



Sec. 250.813  Subsurface-controlled SSSVs.

    You may submit an APM or a request to the District Manager for 
approval to equip a dry tree well with a subsurface-controlled SSSV in 
lieu of a surface-controlled SSSV, if the subsurface-controlled SSSV is 
installed in a well equipped with a surface-controlled SSSV that has 
become inoperable and cannot be repaired without removal and 
reinstallation of the tubing. If you remove and reinstall the tubing, 
you must equip the well with a surface-controlled SSSV.



Sec. 250.814  Design, installation, and operation of SSSVs--dry trees.

    You must design, install, and operate (including repair, maintain, 
and test) an SSSV to ensure its reliable operation.
    (a) You must install the SSSV at a depth at least 100 feet below the 
mudline within 2 days after production is established. When warranted by 
conditions such as permafrost, unstable bottom conditions, hydrate 
formation, or paraffin problems, the District Manager may approve an 
alternate setting depth on a case-by-case basis.
    (b) The well must not be open to flow while the SSSV is inoperable, 
except when flowing the well is necessary for a particular operation 
such as cutting paraffin or performing other routine operations as 
defined in Sec. 250.601.
    (c) Until the SSSV is installed, the well must be attended in the 
immediate vicinity so that any necessary emergency actions can be taken 
while the well is open to flow. During testing and inspection 
procedures, the well must not be left unattended while open to 
production unless you have installed a properly operating SSSV in the 
well.
    (d) You must design, install, maintain, inspect, repair, and test 
all SSSVs in accordance with API RP 14B (incorporated by reference as 
specified in Sec. 250.198). For additional SSSV testing requirements, 
refer to Sec. 250.880.



Sec. 250.815  Subsurface safety devices in shut-in wells--dry trees.

    (a) You must equip all new dry tree completions (perforated but not 
placed on production) and completions that are shut-in for a period of 6 
months with one of the following:
    (1) A pump-through-type tubing plug;
    (2) A surface-controlled SSSV, provided the surface control has been 
rendered inoperative; or
    (3) An injection valve capable of preventing backflow.
    (b) When warranted by conditions such as permafrost, unstable bottom 
conditions, hydrate formation, and paraffin problems, the District 
Manager must approve the setting depth of the subsurface safety device 
for a shut-in well on a case-by-case basis.



Sec. 250.816  Subsurface safety devices in injection wells--dry trees.

    You must install a surface-controlled SSSV or an injection valve 
capable of preventing backflow in all injection wells. This requirement 
is not applicable if the District Manager determines that the well is 
incapable of natural flow. You must verify the no-flow condition of the 
well annually.



Sec. 250.817  Temporary removal of subsurface safety devices for
routine operations.

    (a) You may remove a wireline- or pumpdown-retrievable subsurface 
safety device without further authorization or notice, for a routine 
operation that does not require BSEE approval of a Form BSEE-0124, 
Application for Permit to Modify (APM). For a list of these routine 
operations, see Sec. 250.601. The removal period must not exceed 15 
days.
    (b) Prior to removal, you must identify the well by placing a sign 
on the wellhead stating that the subsurface safety device was removed. 
You must note the removal of the subsurface safety device in the records 
required by Sec. 250.890. If the master valve is open, you must ensure 
that a trained person (see Sec. 250.891) is in the immediate vicinity to 
attend the well and take any necessary emergency actions.
    (c) You must monitor a platform well when a subsurface safety device 
has been removed, but a person does not

[[Page 156]]

need to remain in the well-bay area continuously if the master valve is 
closed. If the well is on a satellite structure, it must be attended by 
a support vessel, or a pump-through plug must be installed in the tubing 
at least 100 feet below the mudline and the master valve must be closed, 
unless otherwise approved by the appropriate District Manager.
    (d) You must not allow the well to flow while the subsurface safety 
device is removed, except when it is necessary for the particular 
operation for which the SSSV is removed. The provisions of this 
paragraph are not applicable to the testing and inspection procedures 
specified in Sec. 250.880.



Sec. 250.818  Additional safety equipment--dry trees.

    (a) You must equip all tubing installations that have a wireline- or 
pumpdown-retrievable subsurface safety device with a landing nipple, 
with flow couplings or other protective equipment above and below it to 
provide for the setting of the device.
    (b) The control system for all surface-controlled SSSVs must be an 
integral part of the platform emergency shutdown system (ESD).
    (c) In addition to the activation of the ESD by manual action on the 
platform, the system may be activated by a signal from a remote 
location. Surface-controlled SSSVs must close in response to shut-in 
signals from the ESD and in response to the fire loop or other fire 
detection devices.



Sec. 250.819  Specification for surface safety valves (SSVs).

    All wellhead SSVs and their actuators must conform to the 
requirements specified in Secs. 250.801 through 250.803.



Sec. 250.820  Use of SSVs.

    You must install, maintain, inspect, repair, and test all SSVs in 
accordance with API RP 14H (incorporated by reference as specified in 
Sec. 250.198). If any SSV does not operate properly, or if any gas and/
or liquid fluid flow is observed during the leakage test as described in 
Sec. 250.880, then you must shut-in all sources to the SSV and repair or 
replace the valve before resuming production.



Sec. 250.821  Emergency action and safety system shutdown--dry trees.

    (a) In the event of an emergency, such as an impending National 
Weather Service-named tropical storm or hurricane:
    (1) Any well not yet equipped with a subsurface safety device and 
that is capable of natural flow must have the subsurface safety device 
properly installed as soon as possible, with due consideration being 
given to personnel safety.
    (2) You must shut-in (by closing the SSV and the surface-controlled 
SSSV) the following types of wells:
    (i) All oil wells, and
    (ii) All gas wells requiring compression.
    (b) Closure of the SSV must not exceed 45 seconds after automatic 
detection of an abnormal condition or actuation of an ESD. The surface-
controlled SSSV must close within 2 minutes after the shut-in signal has 
closed the SSV. The District Manager must approve any alternative 
design-delayed closure time of greater than 2 minutes based on the 
mechanical/production characteristics of the individual well.



Secs. 250.822--250.824  [Reserved]

           Subsea and Subsurface Safety Systems--Subsea Trees



Sec. 250.825  Subsea tree subsurface safety devices--general.

    (a) For wells using subsea (wet) trees or for which you intend to 
install subsea trees, you must equip all tubing installations open to 
hydrocarbon-bearing zones with subsurface safety devices that will shut 
off the flow from the well in the event of an emergency. You must also 
install flow couplings above and below the subsurface safety devices. 
For instances where the well at issue is incapable of natural flow, you 
may seek District Manager approval for using alternative procedures or 
equipment, if you propose to use a subsea safety system that is not 
capable of shutting off the flow from the

[[Page 157]]

well in the event of an emergency. Subsurface safety devices include the 
following and any associated safety valve lock and landing nipple:
    (1) A surface-controlled SSSV;
    (2) An injection valve;
    (3) A tubing plug; and
    (4) A tubing/annular subsurface safety device.
    (b) After installing the subsea tree, but before the rig or 
installation vessel leaves the area, you must test all valves and 
sensors to ensure that they are operating as designed and meet all the 
conditions specified in this subpart.



Sec. 250.826  Specifications for SSSVs--subsea trees.

    All SSSVs, safety valve locks, and landing nipples installed on the 
OCS must conform to the requirements specified in Secs. 250.801 through 
250.803 and any Deepwater Operations Plan (DWOP) required by 
Secs. 250.286 through 250.295.



Sec. 250.827  Surface-controlled SSSVs--subsea trees.

    You must equip all tubing installations open to a hydrocarbon-
bearing zone that is capable of natural flow with a surface-controlled 
SSSV, except as specified in Secs. 250.829 and 250.830. The surface 
controls must be located on the host facility.



Sec. 250.828  Design, installation, and operation of SSSVs--subsea trees.

    You must design, install, and operate (including repair, maintain, 
and test) an SSSV to ensure its reliable operation.
    (a) You must install the SSSV at a depth at least 100 feet below the 
mudline. When warranted by conditions, such as unstable bottom 
conditions, permafrost, hydrate formation, or paraffin problems, the 
District Manager may approve an alternate setting depth on a case-by-
case basis.
    (b) The well must not be open to flow while an SSSV is inoperable, 
unless specifically approved by the District Manager in an APM.
    (c) You must design, install, maintain, inspect, repair, and test 
all SSSVs in accordance with your Deepwater Operations Plan (DWOP) and 
API RP 14B (incorporated by reference as specified in Sec. 250.198). For 
additional SSSV testing requirements, refer to Sec. 250.880.



Sec. 250.829  Subsurface safety devices in shut-in wells--subsea trees.

    (a) You must equip all new subsea tree completions (perforated but 
not placed on production) and completions shut-in for a period of 6 
months with one of the following:
    (1) A pump-through-type tubing plug;
    (2) An injection valve capable of preventing backflow; or
    (3) A surface-controlled SSSV, provided the surface control has been 
rendered inoperative. For purposes of this section, a surface-controlled 
SSSV is considered inoperative if, for a direct hydraulic control 
system, you have bled the hydraulics from the control line and have 
isolated it from the hydraulic control pressure. If your controls employ 
an electro-hydraulic control umbilical and the hydraulic control 
pressure to the individual well cannot be isolated, a surface-controlled 
SSSV is considered inoperative if you perform the following:
    (i) Disable the control function of the surface-controlled SSSV 
within the logic of the programmable logic controller which controls the 
subsea well;
    (ii) Place a pressure alarm high on the control line to the surface-
controlled SSSV of the subsea well; and
    (iii) Close the USV and at least one other tree valve on the subsea 
well.
    (b) When warranted by conditions, such as unstable bottom 
conditions, permafrost, hydrate formation, and paraffin problems, the 
District Manager must approve the setting depth of the subsurface safety 
device for a shut-in well on a case-by-case basis.



Sec. 250.830  Subsurface safety devices in injection wells--subsea
trees.

    You must install a surface-controlled SSSV or an injection valve 
capable of preventing backflow in all injection wells. This requirement 
is not applicable if the District Manager determines that the well is 
incapable of natural flow. You must verify the no-flow condition of the 
well annually.

[[Page 158]]



Sec. 250.831  Alteration or disconnection of subsea pipeline or
umbilical.

    If a necessary alteration or disconnection of the pipeline or 
umbilical of any subsea well would affect your ability to monitor casing 
pressure or to test any subsea valves or equipment, you must contact the 
appropriate District Office at least 48 hours in advance and submit a 
repair or replacement plan to conduct the required monitoring and 
testing. You must not alter or disconnect until the repair or 
replacement plan is approved.



Sec. 250.832  Additional safety equipment--subsea trees.

    (a) You must equip all tubing installations that have a wireline- or 
pump down-retrievable subsurface safety device installed after May 31, 
1988, with a landing nipple, with flow couplings, or other protective 
equipment above and below it to provide for the setting of the device.
    (b) The control system for all surface-controlled SSSVs must be an 
integral part of the platform ESD.
    (c) In addition to the activation of the ESD by manual action on the 
platform, the system may be activated by a signal from a remote 
location.



Sec. 250.833  Specification for underwater safety valves (USVs).

    All USVs, including those designated as primary or secondary, and 
any alternate isolation valve (AIV) that acts as a USV, if applicable, 
and their actuators, must conform to the requirements specified in 
Secs. 250.801 through 250.803. A production master or wing valve may 
qualify as a USV under API Spec. 6A and API Spec. 6AV1 (both 
incorporated by reference as specified in Sec. 250.198).
    (a) Primary USV (USV1). You must install and designate one USV on a 
subsea tree as the USV1. The USV1 must be located upstream of the choke 
valve. As provided in paragraph (b) of this section, you must inform 
BSEE if the primary USV designation changes.
    (b) Secondary USV (USV2). You may equip your tree with two or more 
valves qualified to be designated as a USV, one of which may be 
designated as the USV2. If the USV1 fails to operate properly or 
exhibits a leakage rate greater than allowed in Sec. 250.880, you must 
notify the appropriate District Office and designate the USV2 or another 
qualified valve (e.g., an AIV) that meets all the requirements of this 
subpart for USVs as the USV1. The USV2 must be located upstream of the 
choke.



Sec. 250.834  Use of USVs.

    You must install, maintain, inspect, repair, and test any valve 
designated as the primary USV in accordance with this subpart, your DWOP 
(as specified in Secs. 250.286 through 250.295), and API RP 14H 
(incorporated by reference as specified in Sec. 250.198). For additional 
USV testing requirements, refer to Sec. 250.880.



Sec. 250.835  Specification for all boarding shutdown valves (BSDVs) 
associated with subsea systems.

    You must install a BSDV on the pipeline boarding riser. All new 
BSDVs and any BSDVs removed from service for remanufacturing or repair 
and their actuators installed on the OCS must meet the requirements 
specified in Secs. 250.801 through 250.803. In addition, you must:
    (a) Ensure that the internal design pressure(s) of the pipeline(s), 
riser(s), and BSDV(s) is fully rated for the maximum pressure of any 
input source and complies with the design requirements set forth in 
subpart J, unless BSEE approves an alternate design.
    (b) Use a BSDV that is fire rated for 30 minutes, and is pressure 
rated for the maximum allowable operating pressure (MAOP) approved in 
your pipeline application.
    (c) Locate the BSDV within 10 feet of the first point of access to 
the boarding pipeline riser (i.e., within 10 feet of the edge of 
platform if the BSDV is horizontal, or within 10 feet above the first 
accessible working deck, excluding the boat landing and above the splash 
zone, if the BSDV is vertical).
    (d) Install a temperature safety element (TSE) and locate it within 
5 feet of each BSDV.



Sec. 250.836  Use of BSDVs.

    You must install, inspect, maintain, repair, and test all new BSDVs 
and BSDVs that you remove from service

[[Page 159]]

for remanufacturing or repair in accordance with API RP 14H 
(incorporated by reference as specified in Sec. 250.198) for SSVs. If 
any BSDV does not operate properly or if any gas fluid and/or liquid 
fluid flow is observed during the leakage test, as described in 
Sec. 250.880, you must shut-in all sources to the BSDV and immediately 
repair or replace the valve.



Sec. 250.837  Emergency action and safety system shutdown--subsea trees.

    (a) In the event of an emergency, such as an impending named 
tropical storm or hurricane, you must shut-in all subsea wells unless 
otherwise approved by the District Manager. A shut-in is defined as a 
closed BSDV, USV, and surface-controlled SSSV.
    (b) When operating a mobile offshore drilling unit (MODU) or other 
type of workover vessel in an area with producing subsea wells, you 
must:
    (1) Suspend production from all such wells that could be affected by 
a dropped object, including upstream wells that flow through the same 
pipeline; or
    (2) Establish direct, real-time communications between the MODU or 
other type of workover vessel and the production facility control room 
and prepare a plan to be submitted to the appropriate District Manager 
for approval, as part of an Application for Permit to Drill (BSEE-0123) 
or an Application for Permit to Modify (BSEE-0124), to shut-in any wells 
that could be affected by a dropped object. If an object is dropped, the 
driller (or other authorized rig floor personnel) must immediately 
secure the well directly under the MODU or other type of workover vessel 
using the ESD station near the driller's console while simultaneously 
communicating with the platform to shut-in all affected wells. You must 
also maintain without disruption, and continuously verify, communication 
between the platform and the MODU or other type of workover vessel. If 
communication is lost between the MODU or other type of workover vessel 
and the platform for 20 minutes or more, you must shut-in all wells that 
could be affected by a dropped object.
    (c) In the event of an emergency, you must operate your production 
system according to the valve closure times in the applicable tables in 
Secs. 250.838 and 250.839 for the following conditions:
    (1) Process upset. In the event an upset in the production process 
train occurs downstream of the BSDV, you must close the BSDV in 
accordance with the applicable tables in Secs. 250.838 and 250.839. You 
may reopen the BSDV to blow down the pipeline to prevent hydrates, 
provided you have secured the well(s) and ensured adequate protection.
    (2) Pipeline pressure safety high and low (PSHL) sensor. In the 
event that either a high or a low pressure condition is detected by a 
PSHL sensor located upstream of the BSDV, you must secure the affected 
well and pipeline, and all wells and pipelines associated with a dual or 
multi pipeline system, by closing the BSDVs, USVs, and surface-
controlled SSSVs in accordance with the applicable tables in 
Secs. 250.838 and 250.839. You must obtain approval from the appropriate 
District Manager to resume production in the unaffected pipeline(s) of a 
dual or multi pipeline system. If the PSHL sensor activation was a false 
alarm, you may return the wells to production without contacting the 
appropriate District Manager.
    (3) ESD/TSE (platform). In the event of an ESD activation that is 
initiated because of a platform ESD or platform TSE not associated with 
the BSDV, you must close the BSDV, USV, and surface-controlled SSSV in 
accordance with the applicable tables in Secs. 250.838 and 250.839.
    (4) Subsea ESD (platform) or BSDV TSE. In the event of an emergency 
shutdown activation that is initiated by the host platform due to an 
abnormal condition subsea, or a TSE associated with the BSDV, you must 
close the BSDV, USV, and surface-controlled SSSV in accordance with the 
applicable tables in Secs. 250.838 and 250.839.
    (5) Subsea ESD (MODU). In the event of an ESD activation that is 
initiated by a dropped object from a MODU or other type of workover 
vessel, you must secure all wells in the proximity of the MODU or other 
type of workover vessel by closing the USVs and surface-controlled SSSVs 
in accordance with

[[Page 160]]

the applicable tables in Secs. 250.838 and 250.839. You must notify the 
appropriate District Manager before resuming production.
    (d) Following an ESD or fire, you must bleed your low pressure (LP) 
and high pressure (HP) hydraulic systems in accordance with the 
applicable tables in Secs. 250.838 and 250.839 to ensure that the valves 
are locked out of service and cannot be reopened inadvertently.



Sec. 250.838  What are the maximum allowable valve closure times and 
hydraulic bleeding requirements for an electro-hydraulic control 
system?

    (a) If you have an electro-hydraulic control system, you must:
    (1) Design the subsea control system to meet the valve closure times 
listed in paragraphs (b) and (d) of this section or your approved DWOP; 
and
    (2) Verify the valve closure times upon installation. The District 
Manager may require you to verify the closure time of the USV(s) through 
visual authentication by diver or ROV.
    (b) You must comply with the maximum allowable valve closure times 
and hydraulic system bleeding requirements listed in the following table 
or your approved DWOP as long as communication is maintained with the 
platform or with the MODU or other type of workover vessel:

                                                 Valve Closure Timing, Electro-Hydraulic Control System
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                            Your LP          Your HP
 If you have the following. .    Your pipeline    Your USV1 must.   Your USV2 must.   Your alternate    Your surface-      hydraulic        hydraulic
              .                 BSDV must. . .          . .               . .         isolation valve  controlled SSSV   system must. .   system must. .
                                                                                         must. . .        must. . .            .                .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............  Close within 45   [no requirements]                                     [no              [no              [no
                                seconds after                                                           requirements].   requirements].   requirements].
                                sensor
                                activation.
(2) Pipeline PSHL............  Close within 45   Close one or more valves within 2 minutes and 45      Close within 60  [no              Initiate
                                seconds after     seconds after sensor activation. Close the            minutes after    requirements].   unrestricted
                                sensor            designated USV1 within 20 minutes after sensor        sensor                            bleed within
                                activation.       activation.                                           activation. If                    24 hours after
                                                                                                        you use a 60-                     sensor
                                                                                                        minute manual                     activation.
                                                                                                        resettable
                                                                                                        timer, you may
                                                                                                        continue to
                                                                                                        reset the time
                                                                                                        for closure up
                                                                                                        to a maximum
                                                                                                        of 24 hours
                                                                                                        total.
(3) ESD/TSE (Platform).......  Close within 45   Close within 5    Close within 20 minutes after ESD   Close within 20  Initiate         Initiate
                                seconds after     minutes after     or sensor activation.               minutes after    unrestricted     unrestricted
                                ESD or sensor     ESD or sensor                                         ESD or sensor    bleed within     bleed within
                                activation.       activation. If                                        activation. If   60 minutes       60 minutes
                                                  you use a 5-                                          you use a 20-    after ESD or     after ESD or
                                                  minute                                                minute manual    sensor           sensor
                                                  resettable                                            resettable       activation. If   activation. If
                                                  timer, you may                                        timer, you may   you use a 60-    you use a 60-
                                                  continue to                                           continue to      minute manual    minute manual
                                                  reset the time                                        reset the time   resettable       resettable
                                                  for closure up                                        for closure up   timer you must   timer you must
                                                  to a maximum of                                       to a maximum     initiate         initiate
                                                  20 minutes                                            of 60 minutes    unrestricted     unrestricted
                                                  total.                                                total.           bleed within     bleed within
                                                                                                                         24 hours.        24 hours.

[[Page 161]]

 
(4) Subsea ESD (Platform) or   Close within 45   Close one or more valves within 2 minutes and 45      Close within 10  Initiate         Initiate
 BSDV TSE.                      seconds after     seconds after ESD or sensor activation. Close all     minutes after    unrestricted     unrestricted
                                ESD or sensor     tree valves within 10 minutes after ESD or sensor     ESD or sensor    bleed within     bleed within
                                activation.       activation                                            activation.      60 minutes       60 minutes
                                                                                                                         after ESD or     after ESD or
                                                                                                                         sensor           sensor
                                                                                                                         activation.      activation.
(5) Subsea ESD (MODU or other  [no               Initiate valve closure immediately. You may allow for closure of the   Initiate         Initiate
 type of workover vessel,       requirements].    tree valves immediately prior to closure of the surface-controlled     unrestricted    unrestricted
 Dropped object).                                 SSSV if desired.                                                       bleed            bleed within
                                                                                                                         immediately.     10 minutes
                                                                                                                                          after ESD
                                                                                                                                          activation.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (c) If you have an electro-hydraulic control system and experience a 
loss of communications (EH Loss of Comms), you must comply with the 
following:
    (1) If you can meet the EH Loss of Comms valve closure timing 
conditions specified in the table in paragraph (d) of this section, you 
must notify the appropriate District Office within 12 hours of detecting 
the loss of communication.
    (2) If you cannot meet the EH Loss of Comms valve closure timing 
conditions specified in the table in paragraph (d) of this section, you 
must notify the appropriate District Office immediately after detecting 
the loss of communication. You must shut-in production by initiating a 
bleed of the low pressure (LP) hydraulic system or the high pressure 
(HP) hydraulic system within 120 minutes after loss of communication. 
You must bleed the other hydraulic system within 180 minutes after loss 
of communication.
    (3) You must obtain approval from the appropriate District Manager 
before continuing to produce after loss of communication when you cannot 
meet the EH Loss of Comms valve closure times specified in the table in 
paragraph (d) of this section. In your request, include an alternate 
valve closure timing table that your system is able to achieve. The 
appropriate District Manager may also approve an alternate hydraulic 
bleed schedule to allow for hydrate mitigation and orderly shut-in.
    (d) If you experience a loss of communications, you must comply with 
the maximum allowable valve closure times and hydraulic system bleeding 
requirements listed in the following table or your approved DWOP:

                                    Valve Closure Timing, Electro-Hydraulic Control System With Loss of Communication
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                            Your LP          Your HP
 If you have the following. .    Your pipeline    Your USV1 must.   Your USV2 must.   Your alternate    Your surface-      hydraulic        hydraulic
              .                 BSDV must. . .          . .               . .         isolation valve  controlled SSSV   system must. .   system must. .
                                                                                         must. . .        must. . .            .                .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............  Close within 45   [no requirements]                                     [no              [no              [no
                                seconds after                                                           requirements].   requirements].   requirements].
                                sensor
                                activation.

[[Page 162]]

 
(2) Pipeline PSHL............  Close within 45   Initiate closure when LP hydraulic system is bled     Initiate         Initiate         Initiate
                                seconds after     (close valves within 5 minutes after sensor           closure when     unrestricted     unrestricted
                                sensor            activation).                                          HP hydraulic     bleed            bleed within
                                activation.                                                             system is bled   immediately,     24 hours after
                                                                                                        (close within    concurrent       sensor
                                                                                                        24 hours after   with sensor      activation.
                                                                                                        sensor           activation.
                                                                                                        activation).
(3) ESD/TSE (Platform).......  Close within 45   Initiate closure when LP hydraulic system is bled     Initiate         Initiate         Initiate
                                seconds after     (close valves within 20 minutes after ESD or sensor   closure when     unrestricted     unrestricted
                                ESD or sensor     activation).                                          HP hydraulic     bleed            bleed within
                                activation.                                                             system is bled   concurrent       60 minutes
                                                                                                        (close within    with BSDV        after ESD or
                                                                                                        60 minutes       closure (bleed   sensor
                                                                                                        after ESD or     within 20        activation.
                                                                                                        sensor           minutes after
                                                                                                        activation).     ESD or sensor
                                                                                                                         activation).
(4) Subsea ESD (Platform) or   Close within 45   Initiate closure when LP hydraulic system is bled     Initiate         Initiate         Initiate
 BSDV TSE.                      seconds after     (close valves within 5 minutes after ESD or sensor    closure when     unrestricted     unrestricted
                                ESD or sensor     activation).                                          HP hydraulic     bleed            bleed
                                activation.                                                             system is bled   immediately.     immediately,
                                                                                                        (close within                     allowing for
                                                                                                        20 minutes                        surface-
                                                                                                        after ESD or                      controlled
                                                                                                        sensor                            SSSV closure.
                                                                                                        activation).
(5) Subsea ESD (MODU or other  [no               Initiate closure immediately. You may allow for closure of the tree    Initiate         Initiate
 type of workover vessel),      requirements].    valves immediately prior to closure of the surface-controlled SSSV     unrestricted     unrestricted
 Dropped object.                                  if desired.                                                            bleed            bleed
                                                                                                                         immediately.     immediately.
--------------------------------------------------------------------------------------------------------------------------------------------------------



Sec. 250.839  What are the maximum allowable valve closure times and
hydraulic bleeding requirements for a direct-hydraulic control system?

    (a) If you have a direct-hydraulic control system, you must:
    (1) Design the subsea control system to meet the valve closure times 
listed in this section or your approved DWOP; and
    (2) Verify the valve closure times upon installation. The District 
Manager may require you to verify the closure time of the USV(s) through 
visual authentication by diver or ROV.
    (b) You must comply with the maximum allowable valve closure times 
and hydraulic system bleeding requirements listed in the following table 
or your approved DWOP:

                                                  Valve Closure Timing, Direct-Hydraulic Control System
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                            Your LP          Your HP
 If you have the following. .    Your pipeline    Your USV1 must.   Your USV2 must.   Your alternate    Your surface-      hydraulic        hydraulic
              .                 BSDV must. . .          . .               . .         isolation valve  controlled SSSV   system must. .   system must. .
                                                                                         must. . .        must. . .            .                .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............  Close within 45   [no requirements]                                     [no              [no              [no
                                seconds after                                                           requirements].   requirements].   requirements]
                                sensor
                                activation.

[[Page 163]]

 
(2) Flowline PSHL............  Close within 45   Close one or more valves within 2 minutes and 45      Close within 24  Complete bleed   Complete bleed
                                seconds after     seconds after sensor activation. Close the            hours after      of USV1, USV2,   within 24
                                sensor            designated USV1 within 20 minutes after sensor        sensor           and the AIV      hours after
                                activation.       activation.                                           activation.      within 20        sensor
                                                                                                                         minutes after    activation.
                                                                                                                         sensor
                                                                                                                         activation.
(3) ESD/TSE (Platform).......  Close within 45   Close all valves within 20 minutes after ESD or       Close within 60  Complete bleed   Complete bleed
                                seconds after     sensor activation.                                    minutes after    of USV1, USV2,   within 60
                                ESD or sensor                                                           ESD or sensor    and the AIV      minutes after
                                activation.                                                             activation.      within 20        ESD or sensor
                                                                                                                         minutes after    activation.
                                                                                                                         ESD or sensor
                                                                                                                         activation.
(4) Subsea ESD (Platform) or   Close within 45   Close one or more valves within 2 minutes and 45      Close within 10  Complete bleed   Complete bleed
 BSDV TSE.                      seconds after     seconds after ESD or sensor activation. Close all     minutes after    of USV1, USV2,   within 10
                                ESD or sensor     tree valves within 10 minutes after ESD or sensor     ESD or sensor    and the AIV      minutes after
                                activation.       activation.                                           activation.      within 10        ESD or sensor
                                                                                                                         minutes after    activation.
                                                                                                                         ESD or sensor
                                                                                                                         activation.
(5) Subsea ESD (MODU or other  [no               Initiate closure immediately. If desired, you may allow for closure    Initiate         Initiate
 type of workover vessel),      requirements].    of the tree valves immediately prior to closure of the surface-        unrestricted     unrestricted
 Dropped object.                                  controlled SSSV.                                                       bleed            bleed
                                                                                                                         immediately.     immediately.
--------------------------------------------------------------------------------------------------------------------------------------------------------

                        PRODUCTION SAFETY SYSTEMS



Sec. 250.840  Design, installation, and maintenance--general.

    You must design, install, and maintain all production facilities and 
equipment including, but not limited to, separators, treaters, pumps, 
heat exchangers, fired components, wellhead injection lines, 
compressors, headers, and flowlines in a manner that is efficient, safe, 
and protects the environment.



Sec. 250.841  Platforms.

    (a) You must protect all platform production facilities with a basic 
and ancillary surface safety system designed, analyzed, installed, 
tested, and maintained in operating condition in accordance with the 
provisions of API RP 14C (incorporated by reference as specified in 
Sec. 250.198). If you use processing components other than those for 
which Safety Analysis Checklists are included in API RP 14C, you must 
utilize the analysis technique and documentation specified in API RP 14C 
to determine the effects and requirements of these components on the 
safety system. Safety device requirements for pipelines are contained in 
Sec. 250.1004.
    (b) You must design, install, inspect, repair, test, and maintain in 
operating condition all platform production process piping in accordance 
with API RP 14E and API 570 (both incorporated by reference as specified 
in Sec. 250.198). The District Manager may approve temporary repairs to 
facility piping on a case-by-case basis for a period not to exceed 30 
days.

[[Page 164]]



Sec. 250.842  Approval of safety systems design and installation
features.

    (a) Before you install or modify a production safety system, you 
must submit a production safety system application to the District 
Manager for approval. The application must include the information 
prescribed in the following table:

------------------------------------------------------------------------
                                            Details and/or additional
            You must submit:                      requirements:
------------------------------------------------------------------------
(1) A schematic piping and               Showing the following:
 instrumentation diagram.                (i) Well shut-in tubing
                                          pressure;
                                         (ii) Piping specification
                                          breaks, piping sizes;
                                         (iii) Pressure relief valve set
                                          points;
                                         (iv) Size, capacity, and design
                                          working pressures of
                                          separators, flare scrubbers,
                                          heat exchangers, treaters,
                                          storage tanks, compressors and
                                          metering devices;
                                         (v) Size, capacity, design
                                          working pressures, and maximum
                                          discharge pressure of
                                          hydrocarbon-handling pumps;
                                         (vi) Size, capacity, and design
                                          working pressures of
                                          hydrocarbon-handling vessels,
                                          and chemical injection systems
                                          handling a material having a
                                          flash point below 100 degrees
                                          Fahrenheit for a Class I
                                          flammable liquid as described
                                          in API RP 500 and 505 (both
                                          incorporated by reference as
                                          specified in Sec. 250.198);
                                          and
                                         (vii) Size and maximum
                                          allowable working pressures as
                                          determined in accordance with
                                          API RP 14E (incorporated by
                                          reference as specified in Sec.
                                           250.198).
(2) A safety analysis flow diagram (API  If processing components are
 RP 14C, Appendix E) and the related      used, other than those for
 Safety Analysis Function Evaluation      which Safety Analysis
 (SAFE) chart (API RP 14C, subsection     Checklists are included in API
 4.3.3) (incorporated by reference as     RP 14C, you must use the same
 specified in Sec. 250.198).             analysis technique and
                                          documentation to determine the
                                          effects and requirements of
                                          these components upon the
                                          safety system.
(3) Electrical system information,       (i) A plan for each platform
 including.                               deck and outlining all
                                          classified areas. You must
                                          classify areas according to
                                          API RP 500 or API RP 505 (both
                                          incorporated by reference as
                                          specified in Sec. 250.198).
                                         (ii) Identification of all
                                          areas where potential ignition
                                          sources, including non-
                                          electrical ignition sources,
                                          are to be installed showing:
                                         (A) All major production
                                          equipment, wells, and other
                                          significant hydrocarbon
                                          sources, and a description of
                                          the type of decking, ceiling,
                                          walls (e.g., grating or
                                          solid), and firewalls and;
                                         (B) The location of generators,
                                          control rooms, panel boards,
                                          major cabling/conduit routes,
                                          and identification of the
                                          primary wiring method (e.g.,
                                          type cable, conduit, wire)
                                          and;
                                         (iii) One-line electrical
                                          drawings of all electrical
                                          systems including the safety
                                          shutdown system. You must also
                                          include a functional legend.
(4) Schematics of the fire and gas-      Showing a functional block
 detection systems.                       diagram of the detection
                                          system, including the
                                          electrical power supply and
                                          also including the type,
                                          location, and number of
                                          detection sensors; the type
                                          and kind of alarms, including
                                          emergency equipment to be
                                          activated; the method used for
                                          detection; and the method and
                                          frequency of calibration.
(5) The service fee listed in Sec. The fee you must pay will be
 250.125.                                 determined by the number of
                                          components involved in the
                                          review and approval process.
------------------------------------------------------------------------

    (b) In the production safety system application, you must also 
certify the following:
    (1) That all electrical installations were designed according to API 
RP 14F or API RP 14FZ, as applicable (incorporated by reference as 
specified in Sec. 250.198);
    (2) That the designs for the mechanical and electrical systems under 
paragraph (a) of this section were reviewed, approved, and stamped by an 
appropriate registered professional engineer(s). The registered 
professional engineer must be registered in a State or Territory of the 
United States and have sufficient expertise and experience to perform 
the duties; and
    (3) That a hazards analysis was performed in accordance with 
Sec. 250.1911 and API RP 14J (incorporated by reference as specified in 
Sec. 250.198), and

[[Page 165]]

that you have a hazards analysis program in place to assess potential 
hazards during the operation of the facility.
    (c) Before you begin production, you must certify, in a letter to 
the District Manager, that the mechanical and electrical systems were 
installed in accordance with the approved designs.
    (d) Within 60 days after production commences, you must certify, in 
a letter to the District Manager, that the as-built diagrams for the new 
or modified production safety systems outlined in paragraphs (a)(1) and 
(2) of this section and the piping and instrumentation diagrams are on 
file and have been certified correct and stamped by an appropriate 
registered professional engineer(s). The registered professional 
engineer must be registered in a State or Territory in the United States 
and have sufficient expertise and experience to perform the duties.
    (e) All as-built diagrams outlined in paragraphs (a)(1) and (2) of 
this section must be submitted to the District Manager within 60 days 
after production commences.
    (f) You must maintain information concerning the approved designs 
and installation features of the production safety system at your 
offshore field office nearest the OCS facility or at other locations 
conveniently available to the District Manager. As-built piping and 
instrumentation diagrams must be maintained at a secure onshore location 
and readily available offshore. These documents must be made available 
to BSEE upon request and be retained for the life of the facility. All 
approvals are subject to field verifications.



Secs. 250.843-250.849  [Reserved]

                Additional Production System Requirements



Sec. 250.850  Production system requirements--general.

    You must comply with the production safety system requirements in 
Secs. 250.851 through 250.872, in addition to the practices contained in 
API RP 14C (incorporated by reference as specified in Sec. 250.198).



Sec. 250.851  Pressure vessels (including heat exchangers) and fired vessels.

    (a) Pressure vessels (including heat exchangers) and fired vessels 
supporting production operations must meet the requirements in the 
following table:

------------------------------------------------------------------------
                                               Applicable codes and
               Item name                           requirements
------------------------------------------------------------------------
(1) Pressure and fired vessels.........  (i) Must be designed,
                                          fabricated, and code stamped
                                          according to applicable
                                          provisions of sections I, IV,
                                          and VIII of the ANSI/ASME
                                          Boiler and Pressure Vessel
                                          Code (incorporated by
                                          reference as specified in Sec.
                                           250.198).
                                         (ii) Must be repaired,
                                          maintained, and inspected in
                                          accordance with API 510
                                          (incorporated by reference as
                                          specified in Sec. 250.198).
(2) Existing uncoded pressure and fired  Must be justified and approval
 vessels (i) in use on November 7,        obtained from the District
 2016; (ii) with an operating pressure    Manager for their continued
 greater than 15 psig; and (iii) that     use after March 1, 2018.
 are not code stamped in accordance
 with the ANSI/ASME Boiler and Pressure
 Vessel Code.
(3) Pressure relief valves.............  (i) Must be designed and
                                          installed according to
                                          applicable provisions of
                                          sections I, IV, and VIII of
                                          the ASME Boiler and Pressure
                                          Vessel Code (incorporated by
                                          reference as specified in Sec.
                                           250.198).
                                         (ii) Must conform to the valve
                                          sizing and pressure-relieving
                                          requirements specified in
                                          these documents, but must be
                                          set no higher than the maximum-
                                          allowable working pressure of
                                          the vessel (except for cases
                                          where staggered set pressures
                                          are required for
                                          configurations using multiple
                                          relief valves or redundant
                                          valves installed and
                                          designated for operator use
                                          only).
                                         (iii) Vents must be positioned
                                          in such a way as to prevent
                                          fluid from striking personnel
                                          or ignition sources.
(4) Steam generators operating at less   Must be equipped with a level
 than 15 psig.                            safety low (LSL) sensor which
                                          will shut off the fuel supply
                                          when the water level drops
                                          below the minimum safe level.

[[Page 166]]

 
(5) Steam generators operating at 15     (i) Must be equipped with a
 psig or greater.                         level safety low (LSL) sensor
                                          which will shut off the fuel
                                          supply when the water level
                                          drops below the minimum safe
                                          level.
                                         (ii) Must be equipped with a
                                          water-feeding device that will
                                          automatically control the
                                          water level except when closed
                                          loop systems are used for
                                          steam generation.
------------------------------------------------------------------------

    (b) Operating pressure ranges. You must use pressure recording 
devices to establish the new operating pressure ranges of pressure 
vessels at any time that the normalized system pressure changes by 50 
psig or 5 percent. Once system pressure has stabilized, pressure 
recording devices must be utilized to establish the new operating 
pressure ranges. The pressure recording devices must document the 
pressure range over time intervals that are no less than 4 hours and no 
more than 30 days long. You must maintain the pressure recording 
information you used to determine current operating pressure ranges at 
your field office nearest the OCS facility or at another location 
conveniently available to the District Manager for as long as the 
information is valid.
    (c) Pressure shut-in sensors must be set according to the following 
table (initial set points for pressure sensors must be set utilizing 
gauge readings and engineering design):

------------------------------------------------------------------------
                                                         Additional
        Type of sensor               Settings           requirements
------------------------------------------------------------------------
(1) High pressure shut-in       Must be set no     Must also be set
 sensor,.                        higher than 15     sufficiently below
                                 percent or 5 psi   (5 percent or 5 psi,
                                 (whichever is      whichever is
                                 greater) above     greater) the relief
                                 the highest        valve's set pressure
                                 operating          to assure that the
                                 pressure of the    pressure source is
                                 vessel.            shut-in before the
                                                    relief valve
                                                    activates.
(2) Low pressure shut-in        Must be set no     You must receive
 sensor,.                        lower than 15      specific approval
                                 percent or 5 psi   from the District
                                 (whichever is      Manager for
                                 greater) below     activation limits on
                                 the lowest         pressure vessels
                                 pressure in the    that have a pressure
                                 operating range.   safety low (PSL)
                                                    sensor set less than
                                                    5 psi.
------------------------------------------------------------------------



Sec. 250.852  Flowlines/Headers.

    (a) You must:
    (1) Equip flowlines from wells with both PSH and PSL sensors. You 
must locate these sensors in accordance with section A.1 of API RP 14C 
(incorporated by reference as specified in Sec. 250.198).
    (2) Use pressure recording devices to establish the new operating 
pressure ranges of flowlines at any time when the normalized system 
pressure changes by 50 psig or 5 percent, whichever is higher. The 
pressure recording devices must document the pressure range over time 
intervals that are no less than 4 hours and no more than 30 days long.
    (3) Maintain the most recent pressure recording information you used 
to determine operating pressure ranges at your field office nearest the 
OCS facility or at another location conveniently available to the 
District Manager for as long as the information is valid.
    (b) Flowline shut-in sensors must meet the requirements in the 
following table (initial set points for pressure sensors must be set 
using gauge readings and engineering design):

------------------------------------------------------------------------
        Type of flowline sensor                      Settings
------------------------------------------------------------------------
(1) PSH sensor,........................  Must be set no higher than 15
                                          percent or 5 psi (whichever is
                                          greater) above the highest
                                          operating pressure of the
                                          flowline. In all cases, the
                                          PSH must be set sufficiently
                                          below the maximum shut-in
                                          wellhead pressure or the gas-
                                          lift supply pressure to ensure
                                          actuation of the SSV. Do not
                                          set the PSH sensor above the
                                          maximum allowable working
                                          pressure of the flowline.

[[Page 167]]

 
(2) PSL sensor,........................  Must be set no lower than 15
                                          percent or 5 psi (whichever is
                                          greater) below the lowest
                                          operating pressure of the
                                          flowline in which it is
                                          installed.
------------------------------------------------------------------------

    (c) If a well flows directly to a pipeline before separation, the 
flowline and valves from the well located upstream of and including the 
header inlet valve(s) must have a working pressure equal to or greater 
than the maximum shut-in pressure of the well unless the flowline is 
protected by one of the following:
    (1) A relief valve which vents into the platform flare scrubber or 
some other location approved by the District Manager. You must design 
the platform flare scrubber to handle, without liquid-hydrocarbon 
carryover to the flare, the maximum-anticipated flow of hydrocarbons 
that may be relieved to the vessel; or
    (2) Two SSVs with independent PSH sensors connected to separate 
relays and sensing points and installed with adequate volume upstream of 
any block valve to allow sufficient time for the SSVs to close before 
exceeding the maximum allowable working pressure. Each independent PSH 
sensor must close both SSVs along with any associated flowline PSL 
sensor. If the maximum shut-in pressure of a dry tree satellite well(s) 
is greater than 1\1/2\ times the maximum allowable pressure of the 
pipeline, a pressure safety valve (PSV) of sufficient size and relief 
capacity to protect against any SSV leakage or fluid hammer effect may 
be required by the District Manager. The PSV must be installed upstream 
of the host platform boarding valve and vent into the platform flare 
scrubber or some other location approved by the District Manager.
    (d) If a well flows directly to the pipeline from a header without 
prior separation, the header, the header inlet valves, and pipeline 
isolation valve must have a working pressure equal to or greater than 
the maximum shut-in pressure of the well unless the header is protected 
by the safety devices as outlined in paragraph (c) of this section.
    (e) If you are installing flowlines constructed of unbonded flexible 
pipe on a floating platform, you must:
    (1) Review the manufacturer's Design Methodology Verification Report 
and the independent verification agent's (IVA's) certificate for the 
design methodology contained in that report to ensure that the 
manufacturer has complied with the requirements of API Spec. 17J 
(incorporated by reference as specified in Sec. 250.198);
    (2) Determine that the unbonded flexible pipe is suitable for its 
intended purpose;
    (3) Submit to the District Manager the manufacturer's design 
specifications for the unbonded flexible pipe; and
    (4) Submit to the District Manager a statement certifying that the 
pipe is suitable for its intended use and that the manufacturer has 
complied with the IVA requirements of API Spec. 17J (incorporated by 
reference as specified in Sec. 250.198).
    (f) Automatic pressure or flow regulating choking devices must not 
prevent the normal functionality of the process safety system that 
includes, but is not limited to, the flowline pressure safety devices 
and the SSV.
    (g) You may install a single flow safety valve (FSV) on the platform 
to protect multiple subsea pipelines or wells that tie into a single 
pipeline riser provided that you install an FSV for each riser on the 
platform and test it in accordance with the criteria prescribed in 
Sec. 250.880(c)(2)(v).
    (h) You may install a single PSHL sensor on the platform to protect 
multiple subsea pipelines that tie into a single pipeline riser provided 
that you install a PSHL sensor for each riser on the platform and locate 
it upstream of the BSDV.



Sec. 250.853  Safety sensors.

    You must ensure that:
    (a) All shutdown devices, valves, and pressure sensors function in a 
manual reset mode;

[[Page 168]]

    (b) Sensors with integral automatic reset are equipped with an 
appropriate device to override the automatic reset mode; and
    (c) All pressure sensors are equipped to permit testing with an 
external pressure source.



Sec. 250.854  Floating production units equipped with turrets and 
turret-mounted systems.

    (a) For floating production units equipped with an auto slew system, 
you must integrate the auto slew control system with your process safety 
system allowing for automatic shut-in of the production process, 
including the sources (subsea wells, subsea pumps, etc.) and releasing 
of the buoy. Your safety system must immediately initiate a process 
system shut-in according to Secs. 250.838 and 250.839 and release the 
buoy to prevent hydrocarbon discharge and damage to the subsea 
infrastructure when the following are encountered:
    (1) Your buoy is clamped,
    (2) Your auto slew mode is activated, and
    (3) You encounter a ship heading/position failure or an exceedance 
of the rotational tolerances of the clamped buoy.
    (b) For floating production units equipped with swivel stack 
arrangements, you must equip the portion of the swivel stack containing 
hydrocarbons with a leak detection system. Your leak detection system 
must be tied into your production process surface safety system allowing 
for automatic shut-in of the system. Upon seal system failure and 
detection of a hydrocarbon leak, your surface safety system must 
immediately initiate a process system shut-in according to Secs. 250.838 
and 250.839.



Sec. 250.855  Emergency shutdown (ESD) system.

    The ESD system must conform to the requirements of Appendix C, 
section C1, of API RP 14C (incorporated by reference as specified in 
Sec. 250.198), and the following:
    (a) The manually operated ESD valve(s) must be quick-opening and 
non-restricted to enable the rapid actuation of the shutdown system. 
Electronic ESD stations must be wired as de-energize to trip circuits or 
as supervised circuits. Because of the key role of the ESD system in the 
platform safety system, all ESD components must be of high quality and 
corrosion resistant and stations must be uniquely identified. Only ESD 
stations at the boat landing may utilize a loop of breakable synthetic 
tubing in lieu of a valve or electric switch. This breakable loop is not 
required to be physically located on the boat landing, but must be 
accessible from a vessel adjacent to or attached to the facility.
    (b) You must maintain a schematic of the ESD that indicates the 
control functions of all safety devices for the platforms on the 
platform, at your field office nearest the OCS facility, or at another 
location conveniently available to the District Manager, for the life of 
the facility.



Sec. 250.856  Engines.

    (a) Engine exhaust. You must equip all engine exhausts to comply 
with the insulation and personnel protection requirements of API RP 14C, 
section 4.2 (incorporated by reference as specified in Sec. 250.198). 
You must equip exhaust piping from diesel engines with spark arresters.
    (b) Diesel engine air intake. You must equip diesel engine air 
intakes with a device to shut down the diesel engine in the event of 
runaway (i.e., overspeed). You must equip diesel engines that are 
continuously attended with either remotely operated manual or automatic 
shutdown devices. You must equip diesel engines that are not 
continuously attended with automatic shutdown devices. The following 
diesel engines do not require a shutdown device: Engines for fire water 
pumps; engines on emergency generators; engines that power BOP 
accumulator systems; engines that power air supply for confined entry 
personnel; temporary equipment on non-producing platforms; booster 
engines whose purpose is to start larger engines; and engines that power 
portable single cylinder rig washers.

[[Page 169]]



Sec. 250.857  Glycol dehydration units.

    (a) You must install a pressure relief system or an adequate vent on 
the glycol regenerator (reboiler) to prevent over pressurization. The 
discharge of the relief valve must be vented in a nonhazardous manner.
    (b) You must install the FSV on the dry glycol inlet to the glycol 
contact tower as near as practical to the glycol contact tower.
    (c) You must install the shutdown valve (SDV) on the wet glycol 
outlet from the glycol contact tower as near as practical to the glycol 
contact tower.



Sec. 250.858  Gas compressors.

    (a) You must equip compressor installations with the following 
protective equipment as required in API RP 14C, sections A.4 and A.8 
(incorporated by reference as specified in Sec. 250.198).
    (1) A pressure safety high (PSH) sensor, a pressure safety low (PSL) 
sensor, a pressure safety valve (PSV), a level safety high (LSH) sensor, 
and a level safety low (LSL) sensor to protect each interstage and 
suction scrubber.
    (2) A temperature safety high (TSH) sensor in the discharge piping 
of each compressor cylinder or case discharge.
    (3) You must design the PSH and PSL sensors and LSH controls 
protecting compressor suction and interstage scrubbers to actuate 
automatic SDVs located in each compressor suction and fuel gas line so 
that the compressor unit and the associated vessels can be isolated from 
all input sources. All automatic SDVs installed in compressor suction 
and fuel gas piping must also be actuated by the shutdown of the prime 
mover. Unless otherwise approved by the District Manager, gas-well gas 
affected by the closure of the automatic SDV on the suction side of a 
compressor must be diverted to the pipeline, diverted to a flare or vent 
in accordance with Secs. 250.1160 or 250.1161, or shut-in at the 
wellhead.
    (4) You must install a blowdown valve on the discharge line of all 
compressor installations that are 1,000 horsepower (746 kilowatts) or 
greater.
    (b) Once system pressure has stabilized, you must use pressure 
recording devices to establish the new operating pressure ranges for 
compressor discharge sensors whenever the normalized system pressure 
changes by 50 psig or 5 percent, whichever is higher. The pressure 
recording devices must document the pressure range over time intervals 
that are no less than 4 hours and no more than 30 days long. You must 
maintain the most recent pressure recording information that you used to 
determine operating pressure ranges at your field office nearest the OCS 
facility or at another location conveniently available to the District 
Manager.
    (c) Pressure shut-in sensors must be set according to the following 
table (initial set points for pressure sensors must be set utilizing 
gauge readings and engineering design):

[[Page 170]]



----------------------------------------------------------------------------------------------------------------
         Type of sensor                               Settings                         Additional requirements
----------------------------------------------------------------------------------------------------------------
(1) PSH sensor,                   Must be set no higher than 15 percent or 5 psi    Must also be set
                                   (whichever is greater) above the highest          sufficiently below (5
                                   operating pressure of the discharge line and      percent or 5 psi, whichever
                                   sufficiently below the maximum discharge          is greater) the set
                                   pressure to ensure actuation of the suction SDV.  pressure of the PSV to
                                                                                     assure that the pressure
                                                                                     source is shut-in before
                                                                                     the PSV activates.
(2) PSL sensor,                   Must be set no lower than 15 percent or 5 psi     ............................
                                   (whichever is greater) below the lowest
                                   operating pressure of the discharge line in
                                   which it is installed.
----------------------------------------------------------------------------------------------------------------


[[Page 171]]



Sec. 250.859  Firefighting systems.

    (a) On fixed facilities, to protect all areas where production-
handling equipment is located, you must install firefighting systems 
that meet the requirements of this paragraph. You must install a 
firewater system consisting of rigid pipe with fire hose stations and/or 
fixed firewater monitors to protect all areas where production-handling 
equipment is located. Your firewater system must include installation of 
a fixed water spray system in enclosed well-bay areas where hydrocarbon 
vapors may accumulate.
    (1) Your firewater system must conform to API RP 14G (incorporated 
by reference as specified in Sec. 250.198).
    (2) Fuel or power for firewater pump drivers must be available for 
at least 30 minutes of run time during a platform shut-in. If necessary, 
you must install an alternate fuel or power supply to provide for this 
pump operating time unless the District Manager has approved an 
alternate firefighting system. In addition:
    (i) As of September 7, 2017, you must have equipped all new 
firewater pump drivers with automatic starting capabilities upon 
activation of the ESD, fusible loop, or other fire detection system.
    (ii) For electric-driven firewater pump drivers, to provide for a 
potential loss of primary power, you must install an automatic transfer 
switch to cross over to an emergency power source in order to maintain 
at least 30 minutes of run time. The emergency power source must be 
reliable and have adequate capacity to carry the locked-rotor currents 
of the fire pump motor and accessory equipment.
    (iii) You must route power cables or conduits with wires installed 
between the fire water pump drivers and the automatic transfer switch 
away from hazardous-classified locations that can cause flame 
impingement. Power cables or conduits with wires that connect to the 
fire water pump drivers must be capable of maintaining circuit integrity 
for not less than 30 minutes of flame impingement.
    (3) You must post, in a prominent place on the facility, a diagram 
of the firefighting system showing the location of all firefighting 
equipment.
    (4) For operations in subfreezing climates, you must furnish 
evidence to the District Manager that the firefighting system is 
suitable for those conditions.
    (5) You must obtain approval from the District Manager before 
installing any firefighting system.
    (6) All firefighting equipment located on a facility must be in good 
working order whether approved as the primary, secondary, or ancillary 
firefighting system.
    (b) On floating facilities, to protect all areas where production-
handling equipment is located, you must install a firewater system 
consisting of rigid pipe with fire hose stations and/or fixed firewater 
monitors. You must install a fixed water spray system in enclosed well-
bay areas where hydrocarbon vapors may accumulate. Your firewater system 
must conform to the USCG requirements for firefighting systems on 
floating facilities.
    (c) Except as provided in paragraph (c)(1) and (2) of this section, 
on fixed and floating facilities, if you are required to maintain a 
firewater system and the system becomes inoperable, you must shut-in 
your production operations while making the necessary repairs. For fixed 
facilities only, you may continue your production operations on a 
temporary basis while you make the necessary repairs, provided that:
    (1) You request that the appropriate District Manager approve the 
use of a chemical firefighting system on a temporary basis (for a period 
up to 7 days) while you make the necessary repairs;
    (2) If you are unable to complete repairs during the approved time 
period because of circumstances beyond your control, the District 
Manager may grant multiple extensions to your previously approved 
request to use a chemical firefighting system for periods up to 7 days 
each.



Sec. 250.860  Chemical firefighting system.

    For fixed platforms:
    (a) On minor unmanned platforms, you may use a U.S. Coast Guard type 
and size rating ``B-II'' portable dry chemical unit (with a minimum UL 
Rating (US) of 60-B:C) or a 30-pound portable dry chemical unit, in lieu 
of a

[[Page 172]]

water system, as long as you ensure that the unit is available on the 
platform when personnel are on board.
    (1) A minor platform is a structure with zero to five completions 
and no more than one item of production processing equipment.
    (2) An unmanned platform is one that is not attended 24 hours a day 
or one on which personnel are not quartered overnight.
    (b) On major platforms and minor manned platforms, you may use a 
firefighting system using chemicals-only in lieu of a water-based system 
if the District Manager determines that the use of a chemical system 
provides equivalent fire-protection control and would not increase the 
risk to human safety.
    (1) A major platform is a structure with either six or more 
completions or zero to five completions with more than one item of 
production processing equipment.
    (2) A minor platform is a structure with zero to five completions 
and no more than one item of production processing equipment.
    (3) A manned platform is one that is attended 24 hours a day or one 
on which personnel are quartered overnight.
    (c) On major platforms and minor manned platforms, to obtain 
approval to use a chemical-only fire prevention and control system in 
lieu of a water system under paragraph (b) of this section, you must 
submit to the District Manager:
    (1) A justification for asserting that the use of a chemical system 
provides equivalent fire-protection control. The justification must 
address fire prevention, fire protection, fire control, and firefighting 
on the platform; and
    (2) A risk assessment demonstrating that a chemical-only system 
would not increase the risk to human safety. You must provide the 
following and any other important information in your risk assessment:

------------------------------------------------------------------------
     For the use of a chemical
 firefighting system on major and
 minor manned platforms, you must              Including . . .
provide the following in your risk
         assessment . . .
------------------------------------------------------------------------
(i) Platform description..........  (A) The type and quantity of
                                     hydrocarbons (i.e., natural gas,
                                     oil) that are produced, handled,
                                     stored, or processed at the
                                     facility.
                                    (B) The capacity of any tanks on the
                                     facility that you use to store
                                     either liquid hydrocarbons or other
                                     flammable liquids.
                                    (C) The total volume of flammable
                                     liquids (other than produced
                                     hydrocarbons) stored on the
                                     facility in containers other than
                                     bulk storage tanks. Include
                                     flammable liquids stored in paint
                                     lockers, storerooms, and drums.
                                    (D) If the facility is manned,
                                     provide the maximum number of
                                     personnel on board and the
                                     anticipated length of their stay.
                                    (E) If the facility is unmanned,
                                     provide the number of days per week
                                     the facility will be visited, the
                                     average length of time spent on the
                                     facility per visit, the mode of
                                     transportation, and whether or not
                                     transportation will be available at
                                     the facility while personnel are on
                                     board.
                                    (F) A diagram that depicts: quarters
                                     location, production equipment
                                     location, fire prevention and
                                     control equipment location,
                                     lifesaving appliances and equipment
                                     location, and evacuation plan
                                     escape routes from quarters and all
                                     manned working spaces to primary
                                     evacuation equipment.
(ii) Hazard assessment (facility    (A) Identification of all likely
 specific).                          fire initiation scenarios
                                     (including those resulting from
                                     maintenance and repair activities).
                                     For each scenario, discuss its
                                     potential severity and identify the
                                     ignition and fuel sources.
                                    (B) Estimates of the fire/radiant
                                     heat exposure that personnel could
                                     be subjected to. Show how you have
                                     considered designated muster areas
                                     and evacuation routes near fuel
                                     sources and have verified proper
                                     flare boom sizing for radiant heat
                                     exposure.
(iii) Human factors assessment      (A) Descriptions of the fire-related
 (not facility specific).            training your employees and
                                     contractors have received. Include
                                     details on the length of training,
                                     whether the training was hands-on
                                     or classroom, the training
                                     frequency, and the topics covered
                                     during the training.
                                    (B) Descriptions of the training
                                     your employees and contractors have
                                     received in fire prevention,
                                     control of ignition sources, and
                                     control of fuel sources when the
                                     facility is occupied.
                                    (C) Descriptions of the instructions
                                     and procedures you have given to
                                     your employees and contractors on
                                     the actions they should take if a
                                     fire occurs. Include those
                                     instructions and procedures
                                     specific to evacuation. State how
                                     you convey this information to your
                                     employees and contractors on the
                                     platform.
(iv) Evacuation assessment          (A) A general discussion of your
 (facility specific).                evacuation plan. Identify your
                                     muster areas (if applicable), both
                                     the primary and secondary
                                     evacuation routes, and the means of
                                     evacuation for both.

[[Page 173]]

 
                                    (B) Description of the type,
                                     quantity, and location of
                                     lifesaving appliances available on
                                     the facility. Show how you have
                                     ensured that lifesaving appliances
                                     are located in the near vicinity of
                                     the escape routes.
                                    (C) Description of the types and
                                     availability of support vessels,
                                     whether the support vessels are
                                     equipped with a fire monitor, and
                                     the time needed for support vessels
                                     to arrive at the facility.
                                    (D) Estimates of the worst case time
                                     needed for personnel to evacuate
                                     the facility should a fire occur.
(v) Alternative protection          (A) Discussion of the reasons you
 assessment.                         are proposing to use an alternative
                                     fire prevention and control system.
                                    (B) Lists of the specific standards
                                     used to design the system, locate
                                     the equipment, and operate the
                                     equipment/system.
                                    (C) Description of the proposed
                                     alternative fire prevention and
                                     control system/equipment. Provide
                                     details on the type, size, number,
                                     and location of the prevention and
                                     control equipment.
                                    (D) Description of the testing,
                                     inspection, and maintenance program
                                     you will use to maintain the fire
                                     prevention and control equipment in
                                     an operable condition. Provide
                                     specifics regarding the type of
                                     inspection, the personnel who
                                     conduct the inspections, the
                                     inspection procedures, and
                                     documentation and recordkeeping.
(vi) Conclusion...................  A summary of your technical
                                     evaluation showing that the
                                     alternative system provides an
                                     equivalent level of personnel
                                     protection for the specific hazards
                                     located on the facility.
------------------------------------------------------------------------

    (d) On major or minor platforms, if BSEE has approved your request 
to use a chemical-only fire suppressant system in lieu of a water system 
under paragraphs (b) and (c) of this section, and if you make an 
insignificant change to your platform subsequent to that approval, you 
must document the change and maintain the documentation for the life of 
the facility at either the facility or nearest field office for BSEE 
review and/or inspection. Do not submit this documentation to the 
District Manager. However, if you make a significant change to your 
platform (e.g., placing a storage vessel with a capacity of 100 barrels 
or more on the facility, adding production equipment), or if you plan to 
man an unmanned platform temporarily, you must submit a new request for 
approval, including an updated risk assessment if previously required, 
to the appropriate District Manager. You must maintain, for the life of 
the facility, the most recent documentation that you submitted to BSEE 
at the facility or nearest field office.



Sec. 250.861  Foam firefighting systems.

    When you install foam firefighting systems as part of a firefighting 
system that protects production handling areas, you must:
    (a) Annually conduct an inspection of the foam concentrates and 
their tanks or storage containers for evidence of excessive sludging or 
deterioration;
    (b) Annually send samples of the foam concentrate to the 
manufacturer or authorized representative for quality condition testing. 
You must have the sample tested to determine the specific gravity, pH, 
percentage of water dilution, and solid content. Based on these results, 
the foam must be certified by an authorized representative of the 
manufacturer as suitable firefighting foam consistent with the original 
manufacturer's specifications. The certification document must be 
readily accessible for field inspection. In lieu of sampling and 
certification, you may choose to replace the total inventory of foam 
with suitable new stock;
    (c) Ensure that the quantity of concentrate meets design 
requirements, and that tanks or containers are kept full, with space 
allowed for expansion.



Sec. 250.862  Fire and gas-detection systems.

    For production processing areas only:
    (a) You must install fire (flame, heat, or smoke) sensors in all 
enclosed classified areas. You must install gas sensors in all 
inadequately ventilated, enclosed classified areas.
    (1) Adequate ventilation is defined as ventilation that is 
sufficient to prevent accumulation of significant quantities of vapor-
air mixture in concentrations

[[Page 174]]

over 25 percent of the lower explosive limit. An acceptable method of 
providing adequate ventilation is one that provides a change of air 
volume each 5 minutes or 1 cubic foot of air-volume flow per minute per 
square foot of solid floor area, whichever is greater.
    (2) Enclosed areas (e.g., buildings, living quarters, or doghouses) 
are defined as those areas confined on more than 4 of their 6 possible 
sides by walls, floors, or ceilings more restrictive to air flow than 
grating or fixed open louvers and of sufficient size to allow entry of 
personnel.
    (3) A classified area is any area classified Class I, Group D, 
Division 1 or 2, following the guidelines of API RP 500 (incorporated by 
reference as specified in Sec. 250.198), or any area classified Class I, 
Zone 0, Zone 1, or Zone 2, following the guidelines of API RP 505 
(incorporated by reference as specified in Sec. 250.198).
    (b) All detection systems must be capable of continuous monitoring. 
Fire-detection systems and portions of combustible gas-detection systems 
related to the higher gas-concentration levels must be of the manual-
reset type. Combustible gas-detection systems related to the lower gas-
concentration level may be of the automatic-reset type.
    (c) A fuel-gas odorant or an automatic gas-detection and alarm 
system is required in enclosed, continuously manned areas of the 
facility which are provided with fuel gas. A gas detection system is not 
required for living quarters and doghouses that do not contain a gas 
source and that are not located in a classified area.
    (d) The District Manager may require the installation and 
maintenance of a gas detector or alarm in any potentially hazardous 
area.
    (e) Fire- and gas-detection systems must be an approved type, and 
designed and installed in accordance with API RP 14C, API RP 14G, API RP 
14F, API RP 14FZ, API RP 500, and API RP 505 (all incorporated by 
reference as specified in Sec. 250.198), provided that, if compliance 
with any provision of those standards would be in conflict with 
applicable regulations of the U.S. Coast Guard, compliance with the U.S. 
Coast Guard regulations controls.



Sec. 250.863  Electrical equipment.

    You must design, install, and maintain electrical equipment and 
systems in accordance with the requirements in Sec. 250.114.



Sec. 250.864  Erosion.

    You must have a program of erosion control in effect for wells or 
fields that have a history of sand production. The erosion-control 
program may include sand probes, X-ray, ultrasonic, or other 
satisfactory monitoring methods. You must maintain records for each 
lease that indicate the wells that have erosion-control programs in 
effect. You must also maintain the results of the programs for at least 
2 years and make them available to BSEE upon request.



Sec. 250.865  Surface pumps.

    (a) You must equip pump installations with the protective equipment 
required in API RP 14C, Appendix A--A.7, Pumps (incorporated by 
reference as specified in Sec. 250.198).
    (b) You must use pressure recording devices to establish the new 
operating pressure ranges for pump discharge sensors at any time when 
the normalized system pressure changes by 50 psig or 5 percent, 
whichever is higher. Once system pressure has stabilized, pressure 
recording devices must be utilized to establish the new operating 
pressure ranges. The pressure recording devices must document the 
pressure range over time intervals that are no less than 4 hours and no 
more than 30 days long. You must only maintain the most recent pressure 
recording information that you used to determine operating pressure 
ranges at your field office nearest the OCS facility or at another 
location conveniently available to the District Manager.
    (c) Pressure shut-in sensors must be set according to the following 
table (initial set points for pressure sensors must be set utilizing 
gauge readings and engineering design):

[[Page 175]]



------------------------------------------------------------------------
                                                         Additional
      Type of sensor               Settings             requirements
------------------------------------------------------------------------
(1) PSH sensor............  Must be no higher      Must be set
                             than 15 percent or 5   sufficiently below
                             psi (whichever is      the maximum
                             greater) above the     allowable working
                             highest operating      pressure of the
                             pressure of the        discharge piping.
                             discharge line.        The PSH must also be
                                                    set at least 5
                                                    percent or 5 psi
                                                    (whichever is
                                                    greater) below the
                                                    set pressure of the
                                                    PSV to assure that
                                                    the pressure source
                                                    is shut-in before
                                                    the PSV activates.
(2) PSL sensor............  Must be set no lower
                             than 15 percent or 5
                             psi (whichever is
                             greater) below the
                             lowest operating
                             pressure of the
                             discharge line in
                             which it is
                             installed.
------------------------------------------------------------------------

    (d) The PSL must be placed into service when the pump discharge 
pressure has risen above the PSL sensing point, or within 45 seconds of 
the pump coming into service, whichever is sooner.
    (e) You may exclude the PSH and PSL sensors on small, low-volume 
pumps such as chemical injection-type pumps. This is acceptable if such 
a pump is used as a sump pump or transfer pump, has a discharge rating 
of less than \1/2\ gallon per minute (gpm), discharges into piping that 
is 1 inch or less in diameter, and terminates in piping that is 2 inches 
or larger in diameter.
    (f) You must install a TSE in the immediate vicinity of all pumps in 
hydrocarbon service or those powered by platform fuel gas.
    (g) The pump maximum discharge pressure must be determined using the 
maximum possible suction pressure and the maximum power output of the 
driver as appropriate for the pump type and service.



Sec. 250.866  Personnel safety equipment.

    You must maintain all personnel safety equipment located on a 
facility, whether required or not, in good working condition.



Sec. 250.867  Temporary quarters and temporary equipment.

    (a) The District Manager must approve all temporary quarters to be 
installed in production processing areas or other classified areas on 
OCS facilities. You must equip such temporary quarters with all safety 
devices required by API RP 14C, Appendix C (incorporated by reference as 
specified in Sec. 250.198).
    (b) The District Manager may require you to install a temporary 
firewater system for temporary quarters in production processing areas 
or other classified areas.
    (c) Temporary equipment associated with the production process 
system, including equipment used for well testing and/or well clean-up, 
must be approved by the District Manager.



Sec. 250.868  Non-metallic piping.

    On fixed OCS facilities, you may use non-metallic piping (such as 
that made from polyvinyl chloride, chlorinated polyvinyl chloride, and 
reinforced fiberglass) only in accordance with the requirements of 
Sec. 250.841(b).



Sec. 250.869  General platform operations.

    (a) Surface or subsurface safety devices must not be bypassed or 
blocked out of service unless they are temporarily out of service for 
startup, maintenance, or testing. You may take only the minimum number 
of safety devices out of service. Personnel must monitor the bypassed or 
blocked-out functions until the safety devices are placed back in 
service. Any surface or subsurface safety device which is temporarily 
out of service must be flagged. A designated visual indicator must be 
used to identify the bypassed safety device. You must follow the 
monitoring procedures as follows:
    (1) If you are using a non-computer-based system, meaning your 
safety system operates primarily with pneumatic supply or non-
programmable electrical systems, you must monitor bypassed safety 
devices by positioning monitoring personnel at either the control panel 
for the bypassed safety device, or at the bypassed safety device, or at 
the

[[Page 176]]

component that the bypassed safety device would be monitoring when in 
service. You must also ensure that monitoring personnel are able to view 
all relevant essential operating conditions until all bypassed safety 
devices are placed back in service and are able to initiate shut-in 
action in the event of an abnormal condition.
    (2) If you are using a computer-based technology system, meaning a 
computer-controlled electronic safety system such as supervisory control 
and data acquisition and remote terminal units, you must monitor 
bypassed safety devices by maintaining instantaneous communications at 
all times among remote monitoring personnel and the personnel performing 
maintenance, testing, or startup. Until all bypassed safety devices are 
placed back in service, you must also position monitoring personnel at a 
designated control station that is capable of the following:
    (i) Displaying all relevant essential operating conditions that 
affect the bypassed safety device, well, pipeline, and process 
component. If electronic display of all relevant essential conditions is 
not possible, you must have field personnel monitoring the level gauges 
(sight glass) and pressure gauges in order to know the current operating 
conditions. You must be in communication with all field personnel 
monitoring the gauges;
    (ii) Controlling the production process equipment and the entire 
safety system;
    (iii) Displaying a visual indicator when safety devices are placed 
in the bypassed mode; and
    (iv) Upon command, overriding the bypassed safety device and 
initiating shut-in action in the event of an abnormal condition.
    (3) You must not bypass for startup any element of the emergency 
support system or other support system required by API RP 14C, Appendix 
C (incorporated by reference as specified in Sec. 250.198) without first 
receiving BSEE approval to depart from this operating procedure. These 
systems include, but are not limited to:
    (i) The ESD system to provide a method to manually initiate platform 
shutdown by personnel observing abnormal conditions or undesirable 
events. You do not have to receive approval from the District Manager 
for manual reset and/or initial charging of the system;
    (ii) The fire loop system to sense the heat of a fire and initiate 
platform shutdown, and other fire detection devices (flame, thermal, and 
smoke) that are used to enhance fire detection capability. You do not 
have to receive approval from the District Manager for manual reset and/
or initial charging of the system;
    (iii) The combustible gas detection system to sense the presence of 
hydrocarbons and initiate alarms and platform shutdown before gas 
concentrations reach the lower explosive limit;
    (iv) Adequate ventilation;
    (v) The containment system to collect escaped liquid hydrocarbons 
and initiate platform shutdown;
    (vi) Subsurface safety valves, including those that are self-
actuated (subsurface-controlled SSSVs) or those that are activated by an 
ESD system and/or a fire loop (surface-controlled SSSV). You do not have 
to receive approval from the District Manager for routine operations in 
accordance with Sec. 250.817;
    (vii) The pneumatic supply system; and
    (viii) The system for discharging gas to the atmosphere.
    (4) In instances where components of the ESD, as listed in paragraph 
(a)(3) of this section, are bypassed for maintenance, precautions must 
be taken to provide the equivalent level of protection that existed 
prior to the bypass.
    (b) When wells are disconnected from producing facilities and blind 
flanged, or equipped with a tubing plug, or the master valves have been 
locked closed, you are not required to comply with the provisions of API 
RP 14C (incorporated by reference as specified in Sec. 250.198) or this 
regulation concerning the following:
    (1) Automatic fail-close SSVs on wellhead assemblies, and
    (2) The PSH and PSL sensors in flowlines from wells.
    (c) When pressure or atmospheric vessels are isolated from 
production facilities (e.g., inlet valve locked closed

[[Page 177]]

or inlet blind-flanged) and are to remain isolated for an extended 
period of time, safety device testing in accordance with API RP 14C 
(incorporated by reference as specified in Sec. 250.198), or this 
subpart is not required, with the exception of the PSV, unless the 
vessel is open to the atmosphere.
    (d) All open-ended lines connected to producing facilities and wells 
must be plugged or blind-flanged, except those lines designed to be 
open-ended such as flare or vent lines.
    (e) On all new production safety system installations, component 
process control devices and component safety devices must not be 
installed utilizing the same sensing points.
    (f) All pneumatic control panels and computer based control stations 
must be labeled according to API RP 14C nomenclature.



Sec. 250.870  Time delays on pressure safety low (PSL) sensors.

    (a) You may apply any or all of the industry standard Class B, Class 
C, or Class B/C logic to all applicable PSL sensors installed on process 
equipment, as long as the time delay does not exceed 45 seconds. Use of 
a PSL sensor with a time delay greater than 45 seconds requires BSEE 
approval in accordance with Sec. 250.141. You must document on your 
field test records any use of a PSL sensor with a time delay greater 
than 45 seconds. For purposes of this section, PSL sensors are 
categorized as follows:
    (1) Class B safety devices have logic that allows for the PSL 
sensors to be bypassed for a fixed time period (typically less than 15 
seconds, but not more than 45 seconds). Examples include sensors used in 
conjunction with the design of pump and compressor panels such as PSL 
sensors, lubricator no-flows, and high-water jacket temperature 
shutdowns.
    (2) Class C safety devices have logic that allows for the PSL 
sensors to be bypassed until the component comes into full service 
(i.e., the time at which the startup pressure equals or exceeds the set 
pressure of the PSL sensor, the system reaches a stabilized pressure, 
and the PSL sensor clears).
    (3) Class B/C safety devices have logic that allows for the PSL 
sensors to incorporate a combination of Class B and Class C circuitry. 
These devices are used to ensure that the PSL sensors are not 
unnecessarily bypassed during startup and idle operations, (e.g., Class 
B/C bypass circuitry activates when a pump is shut down during normal 
operations). The PSL sensor remains bypassed until the pump's start 
circuitry is activated and either:
    (i) The Class B timer expires no later than 45 seconds from start 
activation, or
    (ii) The Class C bypass is initiated until the pump builds up 
pressure above the PSL sensor set point and the PSL sensor comes into 
full service.
    (b) If you do not install time delay circuitry that bypasses 
activation of PSL sensor shutdown logic for a specified time period on 
process and product transport equipment during startup and idle 
operations, you must manually bypass (pin out or disengage) the PSL 
sensor, with a time delay not to exceed 45 seconds.



Sec. 250.871  Welding and burning practices and procedures.

    All welding, burning, and hot-tapping activities must be conducted 
according to the specific requirements in Sec. 250.113.



Sec. 250.872  Atmospheric vessels.

    (a) You must equip atmospheric vessels used to process and/or store 
liquid hydrocarbons or other Class I liquids as described in API RP 500 
or 505 (both incorporated by reference as specified in Sec. 250.198) 
with protective equipment identified in API RP 14C, section A.5 
(incorporated by reference as specified in Sec. 250.198). Transport 
tanks approved by the U.S. Department of Transportation, that are sealed 
and not connected via interconnected piping to the production process 
train and that are used only for storage of refined liquid hydrocarbons 
or Class I liquids, are not required to be equipped with the protective 
equipment identified in API RP 14C, section A.5.
    (b) You must ensure that all atmospheric vessels are designed and 
maintained to ensure the proper working conditions for LSH sensors. The 
LSH

[[Page 178]]

sensor bridle must be designed to prevent different density fluids from 
impacting sensor functionality. For atmospheric vessels that have oil 
buckets, the LSH sensor must be installed to sense the level in the oil 
bucket.
    (c) You must ensure that all flame arrestors are maintained to 
ensure proper design function (installation of a system to allow for 
ease of inspection should be considered).



Sec. 250.873  Subsea gas lift requirements.

    If you choose to install a subsea gas lift system, you must design 
your system as approved in your DWOP or as follows:
    (a) Design the gas lift supply pipeline in accordance with API RP 
14C (incorporated by reference as specified in Sec. 250.198) for the gas 
lift supply system located on the platform.
    (b) Meet the applicable requirements in the following table:

[[Page 179]]



--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     Then you must install a
                                  ---------------------------------------------------------------------------------------------
                                    API Spec 6A and API Spec
  If your subsea gas lift system    6AV1 (both incorporated                                                API Spec 6A and API
 introduces the lift gas to the .  by reference as specified   FSV on the gas-lift  PSHL on the gas-lift    Spec 6AV1 manual      In addition, you must
               . .                   in Sec. 250.198) gas-    supply pipeline . .      supply . . .       isolation valve . .
                                      lift shutdown valve               .                                           .
                                       (GLSDV), and . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Subsea pipelines, pipeline     Meet all of the            on the platform       pipeline on the       downstream (out       (i) Ensure that the MAOP
 risers, or manifolds via an        requirements for the       upstream (in-board)   platform downstream   board) of the PSHL    of a subsea gas lift
 external gas lift pipeline or      BSDV described in Secs.    of the GLSDV.         (out board) of the    and above the         supply pipeline is
 umbilical.                         250.835 and 250.836 on                           GLSDV.                waterline. This       equal to the MAOP of
                                    the gas-lift supply                                                    valve does not have   the production
                                    pipeline. Locate the                                                   to be actuated.       pipeline.
                                    GLSDV within 10 feet of                                                                     (ii) Install an actuated
                                    the first point of                                                                           fail-safe close gas-
                                    access to the gas-lift                                                                       lift isolation valve
                                    riser or topsides                                                                            (GLIV) located at the
                                    umbilical termination                                                                        point of intersection
                                    assembly (TUTA) (i.e.,                                                                       between the gas lift
                                    within 10 feet of the                                                                        supply pipeline and the
                                    edge of the platform if                                                                      production pipeline,
                                    the GLSDV is horizontal,                                                                     pipeline riser, or
                                    or within 10 feet above                                                                      manifold.
                                    the first accessible                                                                        (iii) Install the GLIV
                                    working deck, excluding                                                                      downstream of the
                                    the boat landing and                                                                         underwater safety
                                    above the splash zone,                                                                       valve(s) (USV) and/or
                                    if the GLSDV is in the                                                                       AIV(s).
                                    vertical run of a riser,
                                    or within 10 feet of the
                                    TUTA if using an
                                    umbilical).
(2) Subsea well(s) through the     Meet all of the            on the platform       pipeline on the       downstream (out       (i) Install an actuated,
 casing string via an external      requirements for the       upstream (in-board)   platform down-        board) of the PSHL    fail-safe-closed GLIV
 gas lift pipeline or umbilical.    GLSDV described in Secs.   of the GLSDV.         stream (out board)    and above the         on the gas lift supply
                                    250.835 and 250.836 on                           of the GLSDV.         waterline. This       pipeline near the
                                    the gas-lift supply                                                    valve does not have   wellhead to provide the
                                    pipeline. Locate the                                                   to be actuated..      dual function of
                                    GLSDV within 10 feet of                                                                      containing annular
                                    the first point of                                                                           pressure and shutting
                                    access to the gas-lift                                                                       off the gas lift supply
                                    riser or topsides                                                                            gas.
                                    umbilical termination                                                                       (ii) If your subsea tree
                                    assembly (TUTA) (i.e.,                                                                       or tubing head is
                                    within 10 feet of the                                                                        equipped with an
                                    edge of the platform if                                                                      annulus master valve
                                    the GLSDV is horizontal,                                                                     (AMV) or an annulus
                                    or within 10 feet above                                                                      wing valve (AWV), one
                                    the first accessible                                                                         of these may be
                                    working deck, excluding                                                                      designated as the GLIV.
                                    the boat landing and                                                                        (iii) Consider
                                    above the splash zone,                                                                       installing the GLIV
                                    if the GLSDV is in the                                                                       external to the subsea
                                    vertical run of a riser,                                                                     tree to facilitate
                                    or within 10 feet of the                                                                     repair and or
                                    TUTA if using an                                                                             replacement if
                                    umbilical).                                                                                  necessary.

[[Page 180]]

 
(3) Pipeline risers via a gas-     Meet all of the            upstream (in-board)   flowline upstream     downstream (out       (i) Ensure that the gas-
 lift line contained within the     requirements for the       of the GLSDV.         (in-board) of the     board) of the GLSDV.  lift supply flowline
 pipeline riser.                    GLSDV described in Secs.                         FSV.                                        from the gas-lift
                                    250.835(a), (b), and (d)                                                                     compressor to the GLSDV
                                    and 250.836 on the gas-                                                                      is pressure-rated for
                                    lift supply pipeline.                                                                        the MAOP of the
                                    Attach the GLSDV by                                                                          pipeline riser.
                                    flanged connection                                                                          (ii) Ensure that any
                                    directly to the API                                                                          surface equipment
                                    Spec. 6A component used                                                                      associated with the gas-
                                    to suspend and seal the                                                                      lift system is rated
                                    gas-lift line contained                                                                      for the MAOP of the
                                    within the production                                                                        pipeline riser.
                                    riser. To facilitate the                                                                    (iii) Ensure that the
                                    repair or replacement of                                                                     gas-lift compressor
                                    the GLSDV or production                                                                      discharge pressure
                                    riser BSDV, you may                                                                          never exceeds the MAOP
                                    install a manual                                                                             of the pipeline riser.
                                    isolation valve between                                                                     (iv) Suspend and seal
                                    the GLSDV and the API                                                                        the gas-lift flowline
                                    Spec. 6A component used                                                                      contained within the
                                    to suspend and seal the                                                                      production riser in a
                                    gas-lift line contained                                                                      flanged API Spec. 6A
                                    within the production                                                                        component such as an
                                    riser, or outboard of                                                                        API Spec. 6A tubing
                                    the production riser                                                                         head and tubing hanger
                                    BSDV and inboard of the                                                                      or a component
                                    API Spec. 6A component                                                                       designed, constructed,
                                    used to suspend and seal                                                                     tested, and installed
                                    the gas-lift line                                                                            to the requirements of
                                    contained within the                                                                         API Spec. 6A.
                                    production riser.                                                                           (v) Ensure that all
                                                                                                                                 potential leak paths
                                                                                                                                 upstream or near the
                                                                                                                                 production riser BSDV
                                                                                                                                 on the platform provide
                                                                                                                                 the same level of
                                                                                                                                 safety and
                                                                                                                                 environmental
                                                                                                                                 protection as the
                                                                                                                                 production riser BSDV.
                                                                                                                                (vi) Ensure that this
                                                                                                                                 complete assembly is
                                                                                                                                 fire-rated for 30
                                                                                                                                 minutes.
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 181]]

    (c) Follow the valve closure times and hydraulic bleed requirements 
according to your approved DWOP for the following:
    (1) Electro-hydraulic control system with gas lift,
    (2) Electro-hydraulic control system with gas lift with loss of 
communications,
    (3) Direct-hydraulic control system with gas lift.
    (d) Follow the gas lift system valve testing requirements according 
to the following table:

[[Page 182]]



----------------------------------------------------------------------------------------------------------------
      Type of gas lift system              Valve           Allowable leakage rate         Testing frequency
----------------------------------------------------------------------------------------------------------------
(1) Gas lifting a subsea pipeline,   GLSDV              Zero leakage...............  Monthly, not to exceed 6
 pipeline riser, or manifold via an                                                   weeks.
 external gas lift pipeline.
                                     GLIV               N/A........................  Function tested quarterly,
                                                                                      not to exceed 120 days.
(2) Gas lifting a subsea well        GLSDV              Zero leakage...............  Monthly, not to exceed 6
 through the casing string via an                                                     weeks.
 external gas lift pipeline.
                                     GLIV               400 cc per minute of liquid  Function tested quarterly,
                                                         or 15 scf per minute of      not to exceed 120 days
                                                         gas..
(3) Gas lifting the pipeline riser   GLSDV              Zero leakage...............  Monthly, not to exceed 6
 via a gas lift line contained                                                        weeks.
 within the pipeline riser.
----------------------------------------------------------------------------------------------------------------


[[Page 183]]



Sec. 250.874  Subsea water injection systems.

    If you choose to install a subsea water injection system, your 
system must comply with your approved DWOP, which must meet the 
following minimum requirements:
    (a) Adhere to the water injection requirements described in API RP 
14C (incorporated by reference as specified in Sec. 250.198) for the 
water injection equipment located on the platform. In accordance with 
Sec. 250.830, either a surface-controlled SSSV or a water injection 
valve (WIV) that is self-activated and not controlled by emergency shut-
down (ESD) or sensor activation must be installed in a subsea water 
injection well.
    (b) Equip a water injection pipeline with a surface FSV and water 
injection shutdown valve (WISDV) on the surface facility.
    (c) Install a PSHL sensor upstream (in-board) of the FSV and WISDV.
    (d) Use subsea tree(s), wellhead(s), connector(s), and tree valves, 
and surface-controlled SSSV or WIV associated with a water injection 
system that are rated for the maximum anticipated injection pressure.
    (e) Consider the effects of hydrogen sulfide (H2S) when designing 
your water flood system, as required by Sec. 250.805.
    (f) Follow the valve closure times and hydraulic bleed requirements 
according to your approved DWOP for the following:
    (1) Electro-hydraulic control system with water injection,
    (2) Electro-hydraulic control system with water injection with loss 
of communications, and
    (3) Direct-hydraulic control system with water injection.
    (g) Comply with the following injection valve testing requirements:
    (1) You must test your injection valves as provided in the following 
table:

------------------------------------------------------------------------
                                   Allowable leakage
              Valve                      rate          Testing frequency
------------------------------------------------------------------------
(i) WISDV.......................  Zero leakage......  Monthly, not to
                                                       exceed 6 weeks
                                                       between tests.
(ii) Surface-controlled SSSV or   400 cc per minute   Semiannually, not
 WIV.                              of liquid or.       to exceed
                                  15 scf per minute   6 calendar months
                                   of gas.             between tests.
------------------------------------------------------------------------

    (2) If a designated USV on a water injection well fails the 
applicable test under Sec. 250.880(c)(4)(ii), you must notify the 
appropriate District Manager and request approval to designate another 
API Spec 6A and API Spec. 6AV1 (both incorporated by reference as 
specified in Sec. 250.198) certified subsea valve as your USV.
    (3) If a USV on a water injection well fails the test and the 
surface-controlled SSSV or WIV cannot be tested as required under 
(g)(1)(ii) of this section because of low reservoir pressure, you must 
submit a request to the appropriate District Manager with an alternative 
plan that ensures subsea shutdown capabilities.
    (h) If you experience a loss of communications during water 
injection operations, you must comply with the following:
    (1) Notify the appropriate District Manager within 12 hours after 
detecting loss of communication; and
    (2) Obtain approval from the appropriate District Manager to 
continue to inject during the loss of communication.



Sec. 250.875  Subsea pump systems.

    If you choose to install a subsea pump system, your system must 
comply with your approved DWOP, which must meet the following minimum 
requirements:
    (a) Include the installation of an isolation valve at the inlet of 
your subsea pump module.
    (b) Include a PSHL sensor upstream of the BSDV, if the maximum 
possible discharge pressure of the subsea pump operating in a dead head 
condition (that is the maximum shut-in tubing pressure at the pump inlet 
and a closed BSDV) is less than the MAOP of the associated pipeline.
    (c) If the maximum possible discharge pressure of the subsea pump 
operating in a dead head situation could

[[Page 184]]

be greater than the MAOP of the pipeline:
    (1) Include, at minimum, 2 independent functioning PSHL sensors 
upstream of the subsea pump and 2 independent functioning PSHL sensors 
downstream of the pump, that:
    (i) Are operational when the subsea pump is in service; and
    (ii) Will, when activated, shut down the subsea pump, the subsea 
inlet isolation valve, and either the designated USV1, the USV2, or the 
alternate isolation valve.
    (iii) If more than 2 PSHL sensors are installed both upstream and 
downstream of the subsea pump for operational flexibility, then 2 out of 
3 voting logic may be implemented in which the subsea pump remains 
operational provided a minimum of 2 independent PSHL sensors are 
functional both upstream and downstream of the pump.
    (2) Interlock the subsea pump motor with the BSDV to ensure that the 
pump cannot start or operate when the BSDV is closed, incorporate at a 
minimum the following permissive signals into the control system for 
your subsea pump, and ensure that the subsea pump is not able to be 
started or re-started unless:
    (i) The BSDV is open;
    (ii) All automated valves downstream of the subsea pump are open;
    (iii) The upstream subsea pump isolation valve is open; and
    (iv) All parameters associated with the subsea pump operation (e.g., 
pump temperature high, pump vibration high, pump suction pressure high, 
pump discharge pressure high, pump suction flow low) must be cleared 
(i.e., within operational limits) or continuously monitored by personnel 
who observe visual indicators displayed at a designated control station 
and have the capability to initiate shut-in action in the event of an 
abnormal condition.
    (3) Monitor the separator for seawater.
    (4) Ensure that the subsea pump systems are controlled by an 
electro-hydraulic control system.
    (d) Follow the valve closure times and hydraulic bleed requirements 
according to your approved DWOP for the following:
    (1) Electro-hydraulic control system with a subsea pump;
    (2) A loss of communication with the subsea well(s) and not a loss 
of communication with the subsea pump control system without an ESD or 
sensor activation;
    (3) A loss of communication with the subsea pump control system, and 
not a loss of communication with the subsea well(s);
    (4) A loss of communication with the subsea well(s) and the subsea 
pump control system.
    (e) For subsea pump testing:
    (1) Perform a complete subsea pump function test, including full 
shutdown, after any intervention or changes to the software and 
equipment affecting the subsea pump; and
    (2) Test the subsea pump shutdown, including PSHL sensors both 
upstream and downstream of the pump, each quarter (not to exceed 120 
days between tests). This testing may be performed concurrently with the 
ESD function test required by Sec. 250.880(c)(4)(v).



Sec. 250.876  Fired and exhaust heated components.

    No later than September 7, 2018, and at least once every 5 years 
thereafter, you must have a qualified third-party remove and inspect, 
and then you must repair or replace, as needed, the fire tube for tube-
type heaters that are equipped with either automatically controlled 
natural or forced draft burners installed in either atmospheric or 
pressure vessels that heat hydrocarbons and/or glycol. If removal and 
inspection indicates tube-type heater deficiencies, you must complete 
and document repairs or replacements. You must document the inspection 
results, retain such documentation for at least 5 years, and make the 
documentation available to BSEE upon request.



Secs. 250.877--250.879  [Reserved]

                          Safety Device Testing



Sec. 250.880  Production safety system testing.

    (a) Notification. You must:
    (1) Notify the District Manager at least 72 hours before commencing 
production, so that BSEE may conduct a

[[Page 185]]

preproduction inspection of the integrated safety system.
    (2) Notify the District Manager upon commencement of production so 
that BSEE may conduct a complete inspection.
    (3) Notify the District Manager and receive BSEE approval before you 
perform any subsea intervention that modifies the existing subsea 
infrastructure in a way that may affect the casing monitoring 
capabilities and testing frequencies specified in the table set forth in 
paragraph (c)(4) of this section.
    (b) Testing methodologies. You must:
    (1) Test safety valves and other equipment at the intervals 
specified in the tables set forth in paragraph (c) of this section or 
more frequently if operating conditions warrant; and
    (2) Perform testing and inspections in accordance with API RP 14C, 
Appendix D (incorporated by reference as specified in Sec. 250.198), and 
the additional requirements specified in the tables of this section or 
as approved in the DWOP for your subsea system.
    (c) Testing frequencies. You must:
    (1) Comply with the following testing requirements for subsurface 
safety devices on dry tree wells:

[[Page 186]]



----------------------------------------------------------------------------------------------------------------
                                                                     Testing frequency, allowable leakage rates,
                             Item name                                          and other requirements
----------------------------------------------------------------------------------------------------------------
(i) Surface-controlled SSSVs (including devices installed in shut-   Semi-annually, not to exceed 6 calendar
 in and injection wells.                                              months between tests. Also test in place
                                                                      when first installed or reinstalled. If
                                                                      the device does not operate properly, or
                                                                      if a liquid leakage rate > 400 cubic
                                                                      centimeters per minute or a gas leakage
                                                                      rate > 15 standard cubic feet per minute
                                                                      is observed, the device must be removed,
                                                                      repaired, and reinstalled or replaced.
                                                                      Testing must be according to API RP 14B
                                                                      (incorporated by reference as specified in
                                                                      Sec. 250.198) to ensure proper operation.
(ii) Subsurface-controlled SSSVs...................................  Semi-annually, not to exceed 6 calendar
                                                                      months between tests for valves not
                                                                      installed in a landing nipple and 12
                                                                      months for valves installed in a landing
                                                                      nipple. The valve must be removed,
                                                                      inspected, and repaired or adjusted, as
                                                                      necessary, and reinstalled or replaced.
(iii) Tubing plug..................................................  Semi-annually, not to exceed 6 calendar
                                                                      months between tests. Test by opening the
                                                                      well to possible flow. If a liquid leakage
                                                                      rate > 400 cubic centimeters per minute or
                                                                      a gas leakage rate > 15 standard cubic
                                                                      feet per minute is observed, the plug must
                                                                      be removed, repaired, and reinstalled or
                                                                      replaced. An additional tubing plug may be
                                                                      installed in lieu of removal.
(iv) Injection valves..............................................  Semi-annually, not to exceed 6 calendar
                                                                      months between tests. Test by opening the
                                                                      well to possible flow. If a liquid leakage
                                                                      rate > 400 cubic centimeters per minute or
                                                                      a gas leakage rate > 15 standard cubic
                                                                      feet per minute is observed, the valve
                                                                      must be removed, repaired and reinstalled
                                                                      or replaced.
----------------------------------------------------------------------------------------------------------------


[[Page 187]]

    (2) Comply with the following testing requirements for surface 
valves:

[[Page 188]]



----------------------------------------------------------------------------------------------------------------
                             Item name                                    Testing frequency and requirements
----------------------------------------------------------------------------------------------------------------
(i) PSVs...........................................................  Annually, not to exceed 12 calendar months
                                                                      between tests. Valve must either be bench-
                                                                      tested or equipped to permit testing with
                                                                      an external pressure source. Weighted disc
                                                                      vent valves used as PSVs on atmospheric
                                                                      tanks may be disassembled and inspected in
                                                                      lieu of function testing. The main valve
                                                                      piston must be lifted during this test.
(ii) Automatic inlet SDVs that are actuated by a sensor on a vessel  Once each calendar month, not to exceed 6
 or compressor.                                                       weeks between tests.
(iii) SDVs in liquid discharge lines and actuated by vessel low-     Once each calendar month, not to exceed 6
 level sensors.                                                       weeks between tests.
(iv) SSVs..........................................................  Once each calendar month, not to exceed 6
                                                                      weeks between tests. Valves must be tested
                                                                      for both operation and leakage. You must
                                                                      test according to API RP 14H (incorporated
                                                                      by reference as specified in Sec.
                                                                      250.198). If an SSV does not operate
                                                                      properly or if any gas and/or liquid fluid
                                                                      flow is observed during the leakage test,
                                                                      the valve must be immediately repaired or
                                                                      replaced.
(v) Flowline FSVs..................................................  Once each calendar month, not to exceed 6
                                                                      weeks between tests. All flowline FSVs
                                                                      must be tested, including those installed
                                                                      on a host facility in lieu of being
                                                                      installed at a satellite well. You must
                                                                      test flowline FSVs for leakage in
                                                                      accordance with the test procedure
                                                                      specified in API RP 14C (incorporated by
                                                                      reference as specified in Sec. 250.198).
                                                                      If leakage measured exceeds a liquid flow
                                                                      of 400 cubic centimeters per minute or a
                                                                      gas flow of 15 standard cubic feet per
                                                                      minute, the FSV must be repaired or
                                                                      replaced.
----------------------------------------------------------------------------------------------------------------


[[Page 189]]

    (3) Comply with the following testing requirements for surface 
safety systems and devices:

[[Page 190]]



----------------------------------------------------------------------------------------------------------------
                             Item name                                    Testing frequency and requirements
----------------------------------------------------------------------------------------------------------------
(i) Pumps for firewater systems....................................  Must be inspected and operated according to
                                                                      API RP 14G, Section 7.2 (incorporated by
                                                                      reference as specified in Sec. 250.198).
(ii) Fire- (flame, heat, or smoke) and gas detection systems.......  Must be tested for operation and
                                                                      recalibrated every 3 months, not to exceed
                                                                      120 days between tests, provided that
                                                                      testing can be performed in a non-
                                                                      destructive manner. Open flame or devices
                                                                      operating at temperatures that could
                                                                      ignite a methane-air mixture must not be
                                                                      used. All combustible gas-detection
                                                                      systems must be calibrated every 3 months.
(iii) ESD systems..................................................  (A) Pneumatic based ESD systems must be
                                                                      tested for operation at least once each
                                                                      calendar month, not to exceed 6 weeks
                                                                      between tests. You must conduct the test
                                                                      by alternating ESD stations monthly to
                                                                      close at least one wellhead SSV and verify
                                                                      a surface-controlled SSSV closure for that
                                                                      well as indicated by control circuitry
                                                                      actuation. All stations must be checked
                                                                      for functionality at least once each
                                                                      calendar month, not to exceed 6 weeks
                                                                      between tests. No station may be reused
                                                                      until all stations have been tested.
                                                                     (B) Electronic based ESD systems must be
                                                                      tested for operation at least once every 3
                                                                      calendar months, not to exceed 120 days
                                                                      between tests. The test must be conducted
                                                                      by alternating ESD stations to close at
                                                                      least one wellhead SSV and verify a
                                                                      surface-controlled SSSV closure for that
                                                                      well as indicated by control circuitry
                                                                      actuation. All stations must be checked
                                                                      for functionality at least once every 3
                                                                      calendar months, not to exceed 120 days
                                                                      between checks. No station may be reused
                                                                      until all stations have been tested.
                                                                     (C) Electronic/pneumatic based ESD systems
                                                                      must be tested for operation at least once
                                                                      every 3 calendar months, not to exceed 120
                                                                      days between tests. The test must be
                                                                      conducted by alternating ESD stations to
                                                                      close at least one wellhead SSV and verify
                                                                      a surface-controlled SSSV closure for that
                                                                      well as indicated by control circuitry
                                                                      actuation. All stations must be checked
                                                                      for functionality at least once every 3
                                                                      calendar months, not to exceed 120 days
                                                                      between checks. No station may be reused
                                                                      until all stations have been used.
(iv) TSH devices...................................................  Must be tested for operation annually, not
                                                                      to exceed 12 calendar months between
                                                                      tests, excluding those addressed in
                                                                      paragraph (c)(3)(v) of this section and
                                                                      those that would be destroyed by testing.
                                                                      Those that could be destroyed by testing
                                                                      must be visually inspected and the circuit
                                                                      tested for operations at least once every
                                                                      12 months.
(v) TSH shutdown controls installed on compressor installations      Must be tested every 6 months and repaired
 that can be nondestructively tested.                                 or replaced as necessary.
(vi) Burner safety low.............................................  Must be tested annually, not to exceed 12
                                                                      calendar months between tests.
(vii) Flow safety low devices......................................  Must be tested annually, not to exceed 12
                                                                      calendar months between tests.
(viii) Flame, spark, and detonation arrestors......................  Must be visually inspected annually, not to
                                                                      exceed 12 calendar months between
                                                                      inspections.
(ix) Electronic pressure transmitters and level sensors: PSH and     Must be tested at least once every 3
 PSL; LSH and LSL.                                                    months, not to exceed 120 days between
                                                                      tests.
(x) Pneumatic/electronic switch PSH and PSL; pneumatic/electronic    Must be tested at least once each calendar
 switch/electric analog with mechanical linkage LSH and LSL           month, not to exceed 6 weeks between
 controls.                                                            tests.
----------------------------------------------------------------------------------------------------------------


[[Page 191]]

    (4) Comply with the following testing requirements for subsurface 
safety devices and associated systems on subsea tree wells:

[[Page 192]]



----------------------------------------------------------------------------------------------------------------
                                                                     Testing frequency, allowable leakage rates,
                             Item name                                          and other requirements
----------------------------------------------------------------------------------------------------------------
(i) Surface-controlled SSSVs (including devices installed in shut-   Tested semiannually, not to exceed 6 months
 in and injection wells).                                             between tests. If the device does not
                                                                      operate properly, or if a liquid leakage
                                                                      rate > 400 cubic centimeters per minute or
                                                                      a gas leakage rate > 15 standard cubic
                                                                      feet per minute is observed, the device
                                                                      must be removed, repaired, and reinstalled
                                                                      or replaced. Testing must be according to
                                                                      API RP 14B (incorporated by reference as
                                                                      specified in Sec. 250.198) to ensure
                                                                      proper operation, or as approved in your
                                                                      DWOP.
(ii) USVs..........................................................  Tested at least once every 3 calendar
                                                                      months, not to exceed 120 days between
                                                                      tests. If the device does not function
                                                                      properly, or if a liquid leakage rate >
                                                                      400 cubic centimeters per minute or a gas
                                                                      leakage rate > 15 standard cubic feet per
                                                                      minute is observed, the valve must be
                                                                      removed, repaired, and reinstalled or
                                                                      replaced.
(iii) BSDVs........................................................  Tested at least once each calendar month,
                                                                      not to exceed 6 weeks between tests.
                                                                      Valves must be tested for both operation
                                                                      and leakage. You must test according to
                                                                      API RP 14H for SSVs (incorporated by
                                                                      reference as specified in Sec. 250.198).
                                                                      If a BSDV does not operate properly or if
                                                                      any fluid flow is observed during the
                                                                      leakage test, the valve must be
                                                                      immediately repaired or replaced.
(iv) Electronic ESD logic..........................................  Tested at least once each calendar month,
                                                                      not to exceed 6 weeks between tests.
(v) Electronic ESD function........................................  Tested at least once every 3 calendar
                                                                      months, not to exceed 120 days between
                                                                      tests. Shut-in at least one well during
                                                                      the ESD function test. If multiple wells
                                                                      are tied back to the same platform, a
                                                                      different well should be shut-in with each
                                                                      quarterly test.
----------------------------------------------------------------------------------------------------------------


[[Page 193]]

    (d) Subsea wells. (1) Any subsea well that is completed and 
disconnected from monitoring capability may not be disconnected for more 
than 24 months, unless authorized by BSEE.
    (2) Any subsea well that is completed and disconnected from 
monitoring capability for more than 6 months must meet the following 
testing and other requirements:
    (i) Each well must have 3 pressure barriers:
    (A) A closed and tested surface-controlled SSSV,
    (B) A closed and tested USV, and
    (C) One additional closed and tested tree valve.
    (ii) For new completed wells, prior to the rig leaving the well, the 
pressure barriers must be tested as follows:
    (A) The surface-controlled SSSV must be tested for leakage in 
accordance with Sec. 250.828(c);
    (B) The USV and other pressure barrier must be tested to confirm 
zero leakage rate.
    (iii) A sealing pressure cap must be installed on the flowline 
connection hub until the flowline is installed and connected. The 
pressure cap must be designed to accommodate monitoring for pressure 
between the production wing valve and cap. The pressure cap must also be 
designed so that a remotely operated vehicle can bleed pressure off, 
monitor for buildup, and confirm barrier integrity.
    (iv) Pressure monitoring at the sealing pressure cap on the flowline 
connection hub must be performed in each well at intervals not to exceed 
12 months from the time of initial testing of the pressure barrier 
(prior to demobilizing the rig from the field).
    (v) You must have a drilling vessel capable of intervention into the 
disconnected well in the field or readily accessible for use until the 
wells are brought on line.



Secs. 250.881--250.889  [Reserved]

                          Records and Training



Sec. 250.890  Records.

    (a) You must maintain records that show the present status and 
history of each safety device. Your records must include dates and 
details of installation, removal, inspection, testing, repairing, 
adjustments, and reinstallation.
    (b) You must maintain these records for at least 2 years. You must 
maintain the records at your field office nearest the OCS facility and a 
secure onshore location. These records must be available for review by a 
representative of BSEE.
    (c) You must submit to the appropriate District Manager a contact 
list for all OCS facilities at least annually or when contact 
information is revised. The contact list must include:
    (1) Designated operator name;
    (2) Designated primary point of contact for the facility;
    (3) Facility phone number(s), if applicable;
    (4) Facility fax number, if applicable;
    (5) Facility radio frequency, if applicable;
    (6) Facility helideck rating and size, if applicable; and
    (7) Facility records location if not contained on the facility.



Sec. 250.891  Safety device training.

    You must ensure that personnel installing, repairing, testing, 
maintaining, and operating surface and subsurface safety devices, and 
personnel operating production platforms (including, but not limited to, 
separation, dehydration, compression, sweetening, and metering 
operations), are trained in accordance with the procedures in subpart O 
and subpart S of this part.



Secs. 250.892-250.899  [Reserved]



                   Subpart I_Platforms and Structures

                   General Requirements for Platforms



Sec. 250.900  What general requirements apply to all platforms?

    (a) You must design, fabricate, install, use, maintain, inspect, and 
assess all platforms and related structures on the Outer Continental 
Shelf (OCS) so as to ensure their structural integrity for the safe 
conduct of drilling, workover, and production operations. In doing this, 
you must consider the specific environmental conditions at the platform 
location.

[[Page 194]]

    (b) You must also submit an application under Sec. 250.905 of this 
subpart and obtain the approval of the Regional Supervisor before 
performing any of the activities described in the following table:

------------------------------------------------------------------------
   Activity requiring application and     Conditions for conducting the
                approval                             activity
------------------------------------------------------------------------
(1) Install a platform. This includes    (i) You must adhere to the
 placing a newly constructed platform     requirements of this subpart,
 at a location or moving an existing      including the industry
 platform to a new site.                  standards in Sec. 250.901.
                                         (ii) If you are installing a
                                          floating platform, you must
                                          also adhere to U.S. Coast
                                          Guard (USCG) regulations for
                                          the fabrication, installation,
                                          and inspection of floating OCS
                                          facilities.
(2) Major modification to any platform.  (i) You must adhere to the
 This includes any structural changes     requirements of this subpart,
 that materially alter the approved       including the industry
 plan or cause a major deviation from     standards in Sec. 250.901.
 approved operations and any             (ii) Before you make a major
 modification that increases loading on   modification to a floating
 a platform by 10 percent or more.        platform, you must obtain
                                          approval from both the BSEE
                                          and the USCG for the
                                          modification.
(3) Major repair of damage to any        (i) You must adhere to the
 platform. This includes any corrective   requirements of this subpart,
 operations involving structural          including the industry
 members affecting the structural         standards in Sec. 250.901.
 integrity of a portion or all of the    (ii) Before you make a major
 platform.                                repair to a floating platform,
                                          you must obtain approval from
                                          both the BSEE and the USCG for
                                          the repair.
(4) Convert an existing platform at the  (i) The Regional Supervisor
 current location for a new purpose.      will determine on a case-by-
                                          case basis the requirements
                                          for an application for
                                          conversion of an existing
                                          platform at the current
                                          location.
                                         (ii) At a minimum, your
                                          application must include: the
                                          converted platform's intended
                                          use; and a demonstration of
                                          the adequacy of the design and
                                          structural condition of the
                                          converted platform.
                                         (iii) If a floating platform,
                                          you must also adhere to USCG
                                          regulations for the
                                          fabrication, installation, and
                                          inspection of floating OCS
                                          facilities.
(5) Convert an existing mobile offshore  (i) The Regional Supervisor
 drilling unit (MODU) for a new purpose.  will determine on a case-by-
                                          case basis the requirements
                                          for an application for
                                          conversion of an existing
                                          MODU.
                                         (ii) At a minimum, your
                                          application must include: the
                                          converted MODU's intended
                                          location and use; a
                                          demonstration of the adequacy
                                          of the design and structural
                                          condition of the converted
                                          MODU; and a demonstration that
                                          the level of safety for the
                                          converted MODU is at least
                                          equal to that of re-used
                                          platforms.
                                         (iii) You must also adhere to
                                          USCG regulations for the
                                          fabrication, installation, and
                                          inspection of floating OCS
                                          facilities.
------------------------------------------------------------------------

    (c) Under emergency conditions, you may make repairs to primary 
structural elements to restore an existing permitted condition without 
submitting an application or receiving prior BSEE approval for up to 
120-calendar days following an event. You must notify the Regional 
Supervisor of the damage that occurred within 24 hours of its discovery, 
and you must provide a written completion report to the Regional 
Supervisor of the repairs that were made within 1 week after completing 
the repairs. If you make emergency repairs on a floating platform, you 
must also notify the USCG.
    (d) You must determine if your new platform or major modification to 
an existing platform is subject to the Platform Verification Program 
(PVP). Section 250.910 of this subpart fully describes the facilities 
that are subject to the PVP. If you determine that your platform is 
subject to the PVP, you must follow the requirements of Secs. 250.909 
through 250.918 of this subpart.
    (e) You must submit notification of the platform installation date 
and the final as-built location data to the Regional Supervisor within 
45-calendar days of completion of platform installation.
    (1) For platforms not subject to the Platform Verification Program 
(PVP), BSEE will cancel the approved platform application 1 year after 
the approval has been granted if the platform has not been installed. If 
BSEE cancels the approval, you must resubmit your platform application 
and receive BSEE approval if you still plan to install the platform.
    (2) For platforms subject to the PVP, cancellation of an approval 
will be on an individual platform basis. For these

[[Page 195]]

platforms, BSEE will identify the date when the installation approval 
will be cancelled (if installation has not occurred) during the 
application and approval process. If BSEE cancels your installation 
approval, you must resubmit your platform application and receive BSEE 
approval if you still plan to install the platform.



Sec. 250.901  What industry standards must your platform meet?

    (a) In addition to the other requirements of this subpart, your 
plans for platform design, analysis, fabrication, installation, use, 
maintenance, inspection and assessment must, as appropriate, conform to:
    (1) ACI Standard 318-95, Building Code Requirements for Reinforced 
Concrete (ACI 318-95) and Commentary (ACI 318R-95) (incorporated by 
reference at Sec. 250.198);
    (2) ACI 357R-84, Guide for the Design and Construction of Fixed 
Offshore Concrete Structures, 1984; reapproved 1997 (incorporated by 
reference at Sec. 250.198);
    (3) ANSI/AISC 360-05, Specification for Structural Steel Buildings, 
(as specified in Sec. 250.198);
    (4) American Petroleum Institute (API) Bulletin 2INT-DG, Interim 
Guidance for Design of Offshore Structures for Hurricane Conditions, (as 
incorporated by reference in Sec. 250.198);
    (5) API Bulletin 2INT-EX, Interim Guidance for Assessment of 
Existing Offshore Structures for Hurricane Conditions, (as incorporated 
by reference in Sec. 250.198);
    (6) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions 
in the Gulf of Mexico, (as incorporated by reference in Sec. 250.198);
    (7) API Recommend Practice (RP) 2A-WSD, RP for Planning, Designing, 
and Constructing Fixed Offshore Platforms--Working Stress Design (as 
incorporated by reference in Sec. 250.198);
    (8) API RP 2FPS, Recommended Practice for Planning, Designing, and 
Constructing Floating Production Systems, (as incorporated by reference 
in Sec. 250.198);
    (9) API RP 2I, In-Service Inspection of Mooring Hardware for 
Floating Drilling Units (as incorporated by reference in Sec. 250.198);
    (10) API RP 2RD, Design of Risers for Floating Production Systems 
(FPSs) and Tension-Leg Platforms (TLPs), (as incorporated by reference 
in Sec. 250.198);
    (11) API RP 2SK, Recommended Practice for Design and Analysis of 
Station Keeping Systems for Floating Structures, (as incorporated by 
reference in Sec. 250.198);
    (12) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, (as incorporated by reference in Sec. 250.198);
    (13) API RP 2T, Recommended Practice for Planning, Designing and 
Constructing Tension Leg Platforms, (as incorporated by reference in 
Sec. 250.198);
    (14) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, (as incorporated by 
reference in Sec. 250.198);
    (15) American Society for Testing and Materials (ASTM) Standard C 
33-07, approved December 15, 2007, Standard Specification for Concrete 
Aggregates (as incorporated by reference in Sec. 250.198);
    (16) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard 
Specification for Ready-Mixed Concrete (as incorporated by reference in 
Sec. 250.198);
    (17) ASTM Standard C 150-07, approved May 1, 2007, Standard 
Specification for Portland Cement (as incorporated by reference in 
Sec. 250.198);
    (18) ASTM Standard C 330-05, approved December 15, 2005, Standard 
Specification for Lightweight Aggregates for Structural Concrete (as 
incorporated by reference in Sec. 250.198);
    (19) ASTM Standard C 595-08, approved January 1, 2008, Standard 
Specification for Blended Hydraulic Cements (as incorporated by 
reference in Sec. 250.198);
    (20) AWS D1.1, Structural Welding Code--Steel, including Commentary, 
(as incorporated by reference in Sec. 250.198);
    (21) AWS D1.4, Structural Welding Code--Reinforcing Steel, (as 
incorporated by reference in Sec. 250.198);
    (22) AWS D3.6M, Specification for Underwater Welding, (as 
incorporated by reference in Sec. 250.198);

[[Page 196]]

    (23) NACE Standard MR0175, Sulfide Stress Cracking Resistant 
Metallic Materials for Oilfield Equipment, (as incorporated by reference 
in Sec. 250.198);
    (24) NACE Standard RP0176-2003, Item No. 21018, Standard Recommended 
Practice, Corrosion Control of Steel Fixed Offshore Structures 
Associated with Petroleum Production (as incorporated by reference in 
Sec. 250.198).
    (b) You must follow the requirements contained in the documents 
listed under paragraph (a) of this section insofar as they do not 
conflict with other provisions of 30 CFR part 250. You may use 
applicable provisions of these documents, as approved by the Regional 
Supervisor, for the design, fabrication, and installation of platforms 
such as spars, since standards specifically written for such structures 
do not exist. You may also use alternative codes, rules, or standards, 
as approved by the Regional Supervisor, under the conditions enumerated 
in Sec. 250.141.
    (c) For information on the standards mentioned in this section, and 
where they may be obtained, see Sec. 250.198 of this part.
    (d) The following chart summarizes the applicability of the industry 
standards listed in this section for fixed and floating platforms:

------------------------------------------------------------------------
                                                       Applicable to . .
                  Industry standard                            .
------------------------------------------------------------------------
(1) ACI Standard 318-95, Building Code Requirements    Fixed and
 for Reinforced Concrete (ACI 318-95) and Commentary    floating
 (ACI 318R-95),                                         platform, as
                                                        appropriate.
(2) ANSI/AISC 360-05, Specification for Structural
 Steel Buildings;
(3) API Bulletin 2INT-DG, Interim Guidance for Design
 of Offshore Structures for Hurricane Conditions;
(4) API Bulletin 2INT-EX, Interim Guidance for
 Assessment of Existing Offshore Structures for
 Hurricane Conditions;
(5) API Bulletin 2INT-MET, Interim Guidance on
 Hurricane Conditions in the Gulf of Mexico;
(6) API RP 2A-WSD, RP for Planning, Designing, and
 Constructing Fixed Offshore Platforms--Working
 Stress Design;
(7) ASTM Standard C 33-07, approved December 15,
 2007, Standard Specification for Concrete
 Aggregates;
(8) ASTM Standard C 94/C 94M-07, approved January 1,
 2007, Standard Specification for Ready-Mixed
 Concrete;
(9) ASTM Standard C 150-07, approved May 1, 2007,
 Standard Specification for Portland Cement;
(10) ASTM Standard C 330-05, approved December 15,
 2005, Standard Specification for Lightweight
 Aggregates for Structural Concrete;
(11) ASTM Standard C 595-08, approved January 1,
 2008, Standard Specification for Blended Hydraulic
 Cements;
(12) AWS D1.1, Structural Welding Code--Steel;
(13) AWS D1.4, Structural Welding Code--Reinforcing
 Steel;
(14) AWS D3.6M, Specification for Underwater Welding;
(15) NACE Standard RP 0176-2003, Standard Recommended
 Practice (RP), Corrosion Control of Steel Fixed
 Offshore Platforms Associated with Petroleum
 Production;
(16) ACI 357R-84, Guide for the Design and             Fixed platforms.
 Construction of Fixed Offshore Concrete Structures,
 1984; reapproved 1997,
(17) API RP 14J, RP for Design and Hazards Analysis    Floating
 for Offshore Production Facilities;                    platforms.
(18) API RP 2FPS, RP for Planning, Designing, and
 Constructing, Floating Production Systems;
(19) API RP 2RD, Design of Risers for Floating
 Production Systems (FPSs) and Tension-Leg Platforms
 (TLPs);
(20) API RP 2SK, RP for Design and Analysis of
 Station Keeping Systems for Floating Structures;
(21) API RP 2T, RP for Planning, Designing, and
 Constructing Tension Leg Platforms;
(22) API RP 2SM, RP for Design, Manufacture,
 Installation, and Maintenance of Synthetic Fiber
 Ropes for Offshore Mooring;
(23) API RP 2I, In-Service Inspection of Mooring       .................
 Hardware for Floating Drilling Units
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec. 250.902  What are the requirements for platform removal and
location clearance?

    You must remove all structures according to Secs. 250.1725 through 
250.1730 of Subpart Q--Decommissioning Activities of this part.

[[Page 197]]



Sec. 250.903  What records must I keep?

    (a) You must compile, retain, and make available to BSEE 
representatives for the functional life of all platforms:
    (1) The as-built drawings;
    (2) The design assumptions and analyses;
    (3) A summary of the fabrication and installation nondestructive 
examination records;
    (4) The inspection results from the inspections required by 
Sec. 250.919 of this subpart; and
    (5) Records of repairs not covered in the inspection report 
submitted under Sec. 250.919(b).
    (b) You must record and retain the original material test results of 
all primary structural materials during all stages of construction. 
Primary material is material that, should it fail, would lead to a 
significant reduction in platform safety, structural reliability, or 
operating capabilities. Items such as steel brackets, deck stiffeners 
and secondary braces or beams would not generally be considered primary 
structural members (or materials).
    (c) You must provide BSEE with the location of these records in the 
certification statement of your application for platform approval as 
required in Sec. 250.905(j).

                        Platform Approval Program



Sec. 250.904  What is the Platform Approval Program?

    (a) The Platform Approval Program is the BSEE basic approval process 
for platforms on the OCS. The requirements of the Platform Approval 
Program are described in Secs. 250.904 through 250.908 of this subpart. 
Completing these requirements will satisfy BSEE criteria for approval of 
fixed platforms of a proven design that will be placed in the shallow 
water areas (400 ft.) of the Gulf of Mexico OCS.
    (b) The requirements of the Platform Approval Program must be met by 
all platforms on the OCS. Additionally, if you want approval for a 
floating platform; a platform of unique design; or a platform being 
installed in deepwater ( 400 ft.) or a frontier area, you must also 
meet the requirements of the Platform Verification Program. The 
requirements of the Platform Verification Program are described in 
Secs. 250.909 through 250.918 of this subpart.



Sec. 250.905  How do I get approval for the installation, 
modification, or repair of my platform?

    The Platform Approval Program requires that you submit the 
information, documents, and fee listed in the following table for your 
proposed project. In lieu of submitting the paper copies specified in 
the table, you may submit your application electronically in accordance 
with 30 CFR 250.186(a)(3).

------------------------------------------------------------------------
     Required submittal         Required contents    Other requirements
------------------------------------------------------------------------
(a) Application cover letter  Proposed structure    You must submit
                               designation, lease    three copies. If,
                               number, area, name,   your facility is
                               and block number,     subject to the
                               and the type of       Platform
                               facility your         Verification
                               facility (e.g.,       Program (PVP), you
                               drilling,             must submit four
                               production,           copies.
                               quarters). The
                               structure
                               designation must be
                               unique for the
                               field (some fields
                               are made up of
                               several blocks);
                               i.e. once a
                               platform ``A'' has
                               been used in the
                               field there should
                               never be another
                               platform ``A'' even
                               if the old platform
                               ``A'' has been
                               removed. Single
                               well free standing
                               caissons should be
                               given the same
                               designation as the
                               well. All other
                               structures are to
                               be designated by
                               letter designations.

[[Page 198]]

 
(b) Location plat...........  Latitude and          Your plat must be
                               longitude             drawn to a scale of
                               coordinates,          1 inch equals 2,000
                               Universal Mercator    feet and include
                               grid-system           the coordinates of
                               coordinates, state    the lease block
                               plane coordinates     boundary lines. You
                               in the Lambert or     must submit three
                               Transverse Mercator   copies.
                               Projection System,
                               and distances in
                               feet from the
                               nearest block
                               lines. These
                               coordinates must be
                               based on the NAD
                               (North American
                               Datum) 27 datum
                               plane coordinate
                               system.
(c) Front, Side, and Plan     Platform dimensions   Your drawing sizes
 View drawings.                and orientation,      must not exceed 11"
                               elevations relative    x  17". You must
                               to M.L.L.W. (Mean     submit three copies
                               Lower Low Water),     (four copies for
                               and pile sizes and    PVP applications).
                               penetration.
(d) Complete set of           The approved for      Your drawing sizes
 structural drawings.          construction          must not exceed 11"
                               fabrication            x  17". You must
                               drawings should be    submit one copy.
                               submitted
                               including; e.g.,
                               cathodic protection
                               systems; jacket
                               design; pile
                               foundations;
                               drilling,
                               production, and
                               pipeline risers and
                               riser tensioning
                               systems; turrets
                               and turret-and-hull
                               interfaces; mooring
                               and tethering
                               systems;
                               foundations and
                               anchoring systems.
(e) Summary of environmental  A summary of the      You must submit one
 data.                         environmental data    copy.
                               described in the
                               applicable
                               standards
                               referenced under
                               Sec. 250.901(a) of
                               this subpart and in
                               Sec. 250.198 of
                               Subpart A, where
                               the data is used in
                               the design or
                               analysis of the
                               platform. Examples
                               of relevant data
                               include information
                               on waves, wind,
                               current, tides,
                               temperature, snow
                               and ice effects,
                               marine growth, and
                               water depth.
(f) Summary of the            Loading information   You must submit one
 engineering design data.      (e.g., live, dead,    copy.
                               environmental),
                               structural
                               information (e.g.,
                               design-life;
                               material types;
                               cathodic protection
                               systems; design
                               criteria; fatigue
                               life; jacket
                               design; deck
                               design; production
                               component design;
                               pile foundations;
                               drilling,
                               production, and
                               pipeline risers and
                               riser tensioning
                               systems; turrets
                               and turret-and-hull
                               interfaces;
                               foundations,
                               foundation pilings
                               and templates, and
                               anchoring systems;
                               mooring or
                               tethering systems;
                               fabrication and
                               installation
                               guidelines), and
                               foundation
                               information (e.g.,
                               soil stability,
                               design criteria).
(g) Project-specific studies  All studies           You must submit one
 used in the platform design   pertinent to          copy of each study.
 or installation.              platform design or
                               installation, e.g.,
                               oceanographic and/
                               or soil reports
                               including the
                               overall site
                               investigative
                               report required in
                               Sec. 250.906.
(h) Description of the loads  Loads imposed by      You must submit one
 imposed on the facility.      jacket; decks;        copy.
                               production
                               components;
                               drilling,
                               production, and
                               pipeline risers,
                               and riser
                               tensioning systems;
                               turrets and turret-
                               and-hull
                               interfaces;
                               foundations,
                               foundation pilings
                               and templates, and
                               anchoring systems;
                               and mooring or
                               tethering systems.
(i) Summary of safety         A summary of          You must submit one
 factors utilized.             pertinent derived     copy.
                               factors of safety
                               against failure for
                               major structural
                               members, e.g.,
                               unity check ratios
                               exceeding 0.85 for
                               steel-jacket
                               platform members,
                               indicated on
                               ``line'' sketches
                               of jacket sections.
(j) A copy of the in-service  This plan is          You must submit one
 inspection plan.              described in Sec. copy.
                               250.919.

[[Page 199]]

 
(k) Certification statement.  The following         An authorized
                               statement: ``The      company
                               design of this        representative must
                               structure has been    sign the statement.
                               certified by a        You must submit one
                               recognized            copy.
                               classification
                               society, or a
                               registered civil or
                               structural engineer
                               or equivalent, or a
                               naval architect or
                               marine engineer or
                               equivalent,
                               specializing in the
                               design of offshore
                               structures. The
                               certified design
                               and as-built plans
                               and specifications
                               will be on file at
                               (give location)''.
(l) Payment of the service
 fee listed in Sec.
 250.125.
------------------------------------------------------------------------



Sec. 250.906  What must I do to obtain approval for the proposed
site of my platform?

    (a) Shallow hazards surveys. You must perform a high-resolution or 
acoustic-profiling survey to obtain information on the conditions 
existing at and near the surface of the seafloor. You must collect 
information through this survey sufficient to determine the presence of 
the following features and their likely effects on your proposed 
platform:
    (1) Shallow faults;
    (2) Gas seeps or shallow gas;
    (3) Slump blocks or slump sediments;
    (4) Shallow water flows;
    (5) Hydrates; or
    (6) Ice scour of seafloor sediments.
    (b) Geologic surveys. You must perform a geological survey relevant 
to the design and siting of your platform. Your geological survey must 
assess:
    (1) Seismic activity at your proposed site;
    (2) Fault zones, the extent and geometry of faulting, and 
attenuation effects of geologic conditions near your site; and
    (3) For platforms located in producing areas, the possibility and 
effects of seafloor subsidence.
    (c) Subsurface surveys. Depending upon the design and location of 
your proposed platform and the results of the shallow hazard and 
geologic surveys, the Regional Supervisor may require you to perform a 
subsurface survey. This survey will include a testing program for 
investigating the stratigraphic and engineering properties of the soil 
that may affect the foundations or anchoring systems for your facility. 
The testing program must include adequate in situ testing, boring, and 
sampling to examine all important soil and rock strata to determine its 
strength classification, deformation properties, and dynamic 
characteristics. If required to perform a subsurface survey, you must 
prepare and submit to the Regional Supervisor a summary report to 
briefly describe the results of your soil testing program, the various 
field and laboratory test methods employed, and the applicability of 
these methods as they pertain to the quality of the samples, the type of 
soil, and the anticipated design application. You must explain how the 
engineering properties of each soil stratum affect the design of your 
platform. In your explanation you must describe the uncertainties 
inherent in your overall testing program, and the reliability and 
applicability of each test method.
    (d) Overall site investigation report. You must prepare and submit 
to the Regional Supervisor an overall site investigation report for your 
platform that integrates the findings of your shallow hazards surveys 
and geologic surveys, and, if required, your subsurface surveys. Your 
overall site investigation report must include analyses of the potential 
for:
    (1) Scouring of the seafloor;
    (2) Hydraulic instability;
    (3) The occurrence of sand waves;
    (4) Instability of slopes at the platform location;
    (5) Liquefaction, or possible reduction of soil strength due to 
increased pore pressures;
    (6) Degradation of subsea permafrost layers;
    (7) Cyclic loading;
    (8) Lateral loading;
    (9) Dynamic loading;
    (10) Settlements and displacements;

[[Page 200]]

    (11) Plastic deformation and formation collapse mechanisms; and
    (12) Soil reactions on the platform foundations or anchoring 
systems.



Sec. 250.907  Where must I locate foundation boreholes?

    (a) For fixed or bottom-founded platforms and tension leg platforms, 
your maximum distance from any foundation pile to a soil boring must not 
exceed 500 feet.
    (b) For deepwater floating platforms which utilize catenary or taut-
leg moorings, you must take borings at the most heavily loaded anchor 
location, at the anchor points approximately 120 and 240 degrees around 
the anchor pattern from that boring, and, as necessary, other points 
throughout the anchor pattern to establish the soil profile suitable for 
foundation design purposes.



Sec. 250.908  What are the minimum structural fatigue design
requirements?

    (a) API RP 2A-WSD, Recommended Practice for Planning, Designing and 
Constructing Fixed Offshore Platforms (as incorporated by reference in 
Sec. 250.198), requires that the design fatigue life of each joint and 
member be twice the intended service life of the structure. When 
designing your platform, the following table provides minimum fatigue 
life safety factors for critical structural members and joints.

------------------------------------------------------------------------
                 If . . .                            Then . . .
------------------------------------------------------------------------
(1) There is sufficient structural          The results of the fatigue
 redundancy to prevent catastrophic          analysis must indicate a
 failure of the platform or structure        minimum calculated life of
 under consideration,                        twice the design life of
                                             the platform.
(2) There is not sufficient structural      The results of a fatigue
 redundancy to prevent catastrophic          analysis must indicate a
 failure of the platform or structure,       minimum calculated life or
                                             three times the design life
                                             of the platform.
(3) The desirable degree of redundancy is   The results of a fatigue
 significantly reduced as a result of        analysis must indicate a
 fatigue damage,                             minimum calculated life of
                                             three times the design life
                                             of the platform.
------------------------------------------------------------------------

    (b) The documents incorporated by reference in Sec. 250.901 may 
require larger safety factors than indicated in paragraph (a) of this 
section for some key components. When the documents incorporated by 
reference require a larger safety factor than the chart in paragraph (a) 
of this section, the requirements of the incorporated document will 
prevail.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]

                      Platform Verification Program



Sec. 250.909  What is the Platform Verification Program?

    The Platform Verification Program is the BSEE approval process for 
ensuring that floating platforms; platforms of a new or unique design; 
platforms in seismic areas; or platforms located in deepwater or 
frontier areas meet stringent requirements for design and construction. 
The program is applied during construction of new platforms and major 
modifications of, or repairs to, existing platforms. These requirements 
are in addition to the requirements of the Platform Approval Program 
described in Secs. 250.904 through 250.908 of this subpart.



Sec. 250.910  Which of my facilities are subject to the Platform
Verification Program?

    (a) All new fixed or bottom-founded platforms that meet any of the 
following five conditions are subject to the Platform Verification 
Program:
    (1) Platforms installed in water depths exceeding 400 feet (122 
meters);
    (2) Platforms having natural periods in excess of 3 seconds;
    (3) Platforms installed in areas of unstable bottom conditions;
    (4) Platforms having configurations and designs which have not 
previously been used or proven for use in the area; or
    (5) Platforms installed in seismically active areas.
    (b) All new floating platforms are subject to the Platform 
Verification Program to the extent indicated in the following table:

[[Page 201]]



------------------------------------------------------------------------
                 If . . .                            Then . . .
------------------------------------------------------------------------
(1) Your new floating platform is a         The entire platform is
 buoyant offshore facility that does not     subject to the Platform
 have a ship-shaped hull,                    Verification Program
                                             including the following
                                             associated structures:
                                            (i) Drilling, production,
                                             and pipeline risers, and
                                             riser tensioning systems
                                             (each platform must be
                                             designed to accommodate all
                                             the loads imposed by all
                                             risers and riser does not
                                             have tensioning systems);
                                            (ii) Turrets and turret-and-
                                             hull interfaces;
                                            (iii) Foundations,
                                             foundation pilings and
                                             templates, and anchoring
                                             systems; and
                                            (iv) Mooring or tethering
                                             systems.
(2) Your new floating platform is a         Only the following
 buoyant offshore facility with a ship-      structures that may be
 shaped hull,                                associated with a floating
                                             platform are subject to the
                                             Platform Verification
                                             Program:
                                            (i) Drilling, production,
                                             and pipeline risers, and
                                             riser tensioning systems
                                             (each platform must be
                                             designed to accommodate all
                                             the loads imposed by all
                                             risers and riser tensioning
                                             systems);
                                            (ii) Turrets and turret-and-
                                             hull interfaces;
                                            (iii) Foundations,
                                             foundation pilings and
                                             templates, and anchoring
                                             systems; and
                                            (iv) Mooring or tethering
                                             systems.
------------------------------------------------------------------------

    (c) If a platform is originally subject to the Platform Verification 
Program, then the conversion of that platform at that same site for a 
new purpose, or making a major modification of, or major repair to, that 
platform, is also subject to the Platform Verification Program. A major 
modification includes any modification that increases loading on a 
platform by 10 percent or more. A major repair is a corrective operation 
involving structural members affecting the structural integrity of a 
portion or all of the platform. Before you make a major modification or 
repair to a floating platform, you must obtain approval from both the 
BSEE and the USCG.
    (d) The applicability of Platform Verification Program requirements 
to other types of facilities will be determined by BSEE on a case-by-
case basis.



Sec. 250.911  If my platform is subject to the Platform Verification
Program, what must I do?

    If your platform, conversion, or major modification or repair meets 
the criteria in Sec. 250.910, you must:
    (a) Design, fabricate, install, use, maintain and inspect your 
platform, conversion, or major modification or repair to your platform 
according to the requirements of this subpart, and the applicable 
documents listed in Sec. 250.901(a) of this subpart;
    (b) Comply with all the requirements of the Platform Approval 
Program found in Secs. 250.904 through 250.908 of this subpart.
    (c) Submit for the Regional Supervisor's approval three copies each 
of the design verification, fabrication verification, and installation 
verification plans required by Sec. 250.912;
    (d) Submit a complete schedule of all phases of design, fabrication, 
and installation for the Regional Supervisor's approval. You must 
include a project management timeline, Gantt Chart, that depicts when 
interim and final reports required by Secs. 250.916, 250.917, and 
250.918 will be submitted to the Regional Supervisor for each phase. On 
the timeline, you must break-out the specific scopes of work that 
inherently stand alone (e.g., deck, mooring systems, tendon systems, 
riser systems, turret systems).
    (e) Include your nomination of a Certified Verification Agent (CVA) 
as a part of each verification plan required by Sec. 250.912;
    (f) Follow the additional requirements in Secs. 250.913 through 
250.918;
    (g) Obtain approval for modifications to approved plans and for 
major deviations from approved installation procedures from the Regional 
Supervisor; and
    (h) Comply with applicable USCG regulations for floating OCS 
facilities.

[[Page 202]]



Sec. 250.912  What plans must I submit under the Platform Verification
Program?

    If your platform, associated structure, or major modification meets 
the criteria in Sec. 250.910, you must submit the following plans to the 
Regional Supervisor for approval:
    (a) Design verification plan. You may submit your design 
verification plan to BSEE with or subsequent to the submittal of your 
Development and Production Plan (DPP) or Development Operations 
Coordination Document (DOCD) to BOEM. Your design verification must be 
conducted by, or be under the direct supervision of, a registered 
professional civil or structural engineer or equivalent, or a naval 
architect or marine engineer or equivalent, with previous experience in 
directing the design of similar facilities, systems, structures, or 
equipment. For floating platforms, you must ensure that the requirements 
of the USCG for structural integrity and stability, e.g., verification 
of center of gravity, etc., have been met. Your design verification plan 
must include the following:
    (1) All design documentation specified in Sec. 250.905 of this 
subpart;
    (2) Abstracts of the computer programs used in the design process; 
and
    (3) A summary of the major design considerations and the approach to 
be used to verify the validity of these design considerations.
    (b) Fabrication verification plan. The Regional Supervisor must 
approve your fabrication verification plan before you may initiate any 
related operations. Your fabrication verification plan must include the 
following:
    (1) Fabrication drawings and material specifications for artificial 
island structures and major members of concrete-gravity and steel-
gravity structures;
    (2) For jacket and floating structures, all the primary load-bearing 
members included in the space-frame analysis; and
    (3) A summary description of the following:
    (i) Structural tolerances;
    (ii) Welding procedures;
    (iii) Material (concrete, gravel, or silt) placement methods;
    (iv) Fabrication standards;
    (v) Material quality-control procedures;
    (vi) Methods and extent of nondestructive examinations for welds and 
materials; and
    (vii) Quality assurance procedures.
    (c) Installation verification plan. The Regional Supervisor must 
approve your installation verification plan before you may initiate any 
related operations. Your installation verification plan must include:
    (1) A summary description of the planned marine operations;
    (2) Contingencies considered;
    (3) Alternative courses of action; and
    (4) An identification of the areas to be inspected. You must specify 
the acceptance and rejection criteria to be used for any inspections 
conducted during installation, and for the post-installation 
verification inspection.
    (d) You must combine fabrication verification and installation 
verification plans for manmade islands or platforms fabricated and 
installed in place.



Sec. 250.913  When must I resubmit Platform Verification Program
plans?

    (a) You must resubmit any design verification, fabrication 
verification, or installation verification plan to the Regional 
Supervisor for approval if:
    (1) The CVA changes;
    (2) The CVA's or assigned personnel's qualifications change; or
    (3) The level of work to be performed changes.
    (b) If only part of a verification plan is affected by one of the 
changes described in paragraph (a) of this section, you can resubmit 
only the affected part. You do not have to resubmit the summary of 
technical details unless you make changes in the technical details.



Sec. 250.914  How do I nominate a CVA?

    (a) As part of your design verification, fabrication verification, 
or installation verification plan, you must nominate a CVA for the 
Regional Supervisor's approval. You must specify whether the nomination 
is for the design, fabrication, or installation phase of verification, 
or for any combination of these phases.

[[Page 203]]

    (b) For each CVA, you must submit a list of documents to be 
forwarded to the CVA, and a qualification statement that includes the 
following:
    (1) Previous experience in third-party verification or experience in 
the design, fabrication, installation, or major modification of offshore 
oil and gas platforms. This should include fixed platforms, floating 
platforms, manmade islands, other similar marine structures, and related 
systems and equipment;
    (2) Technical capabilities of the individual or the primary staff 
for the specific project;
    (3) Size and type of organization or corporation;
    (4) In-house availability of, or access to, appropriate technology. 
This should include computer programs, hardware, and testing materials 
and equipment;
    (5) Ability to perform the CVA functions for the specific project 
considering current commitments;
    (6) Previous experience with BSEE requirements and procedures;
    (7) The level of work to be performed by the CVA.



Sec. 250.915  What are the CVA's primary responsibilities?

    (a) The CVA must conduct specified reviews according to 
Secs. 250.916, 250.917, and 250.918 of this subpart.
    (b) Individuals or organizations acting as CVAs must not function in 
any capacity that would create a conflict of interest, or the appearance 
of a conflict of interest.
    (c) The CVA must consider the applicable provisions of the documents 
listed in Sec. 250.901(a); the alternative codes, rules, and standards 
approved under Sec. 250.901(b); and the requirements of this subpart.
    (d) The CVA is the primary contact with the Regional Supervisor and 
is directly responsible for providing immediate reports of all incidents 
that affect the design, fabrication and installation of the platform.



Sec. 250.916  What are the CVA's primary duties during the design
phase?

    (a) The CVA must use good engineering judgment and practices in 
conducting an independent assessment of the design of the platform, 
major modification, or repair. The CVA must ensure that the platform, 
major modification, or repair is designed to withstand the environmental 
and functional load conditions appropriate for the intended service life 
at the proposed location.
    (b) Primary duties of the CVA during the design phase include the 
following:

----------------------------------------------------------------------------------------------------------------
               Type of facility . . .                                     The CVA must . . .
----------------------------------------------------------------------------------------------------------------
(1) For fixed platforms and non-ship-shaped floating  Conduct an independent assessment of all proposed:
 facilities,                                          (i) Planning criteria;
                                                      (ii) Operational requirements;
                                                      (iii) Environmental loading data;
                                                      (iv) Load determinations;
                                                      (v) Stress analyses;
                                                      (vi) Material designations;
                                                      (vii) Soil and foundation conditions;
                                                      (viii) Safety factors; and
                                                      (ix) Other pertinent parameters of the proposed design.
(2) For all floating facilities,                      Ensure that the requirements of the U.S. Coast Guard for
                                                       structural integrity and stability, e.g., verification of
                                                       center of gravity, etc., have been met. The CVA must also
                                                       consider:
                                                      (i) Drilling, production, and pipeline risers, and riser
                                                       tensioning systems;
                                                      (ii) Turrets and turret-and-hull interfaces;
                                                      (iii) Foundations, foundation pilings and templates, and
                                                       anchoring systems; and
                                                      (iv) Mooring or tethering systems.
----------------------------------------------------------------------------------------------------------------

    (c) The CVA must submit interim reports and a final report to the 
Regional Supervisor, and to you, during the design phase in accordance 
with the approved schedule required by Sec. 250.911(d). In each interim 
and final report the CVA must:
    (1) Provide a summary of the material reviewed and the CVA's 
findings;

[[Page 204]]

    (2) In the final CVA report, make a recommendation that the Regional 
Supervisor either accept, request modifications, or reject the proposed 
design unless such a recommendation has been previously made in an 
interim report;
    (3) Describe the particulars of how, by whom, and when the 
independent review was conducted; and
    (4) Provide any additional comments the CVA deems necessary.



Sec. 250.917  What are the CVA's primary duties during the fabrication
phase?

    (a) The CVA must use good engineering judgment and practices in 
conducting an independent assessment of the fabrication activities. The 
CVA must monitor the fabrication of the platform or major modification 
to ensure that it has been built according to the approved design and 
the fabrication plan. If the CVA finds that fabrication procedures are 
changed or design specifications are modified, the CVA must inform you. 
If you accept the modifications, then the CVA must so inform the 
Regional Supervisor.
    (b) Primary duties of the CVA during the fabrication phase include 
the following:

----------------------------------------------------------------------------------------------------------------
               Type of facility . . .                                     The CVA must . . .
----------------------------------------------------------------------------------------------------------------
(1) For all fixed platforms and non-ship-shaped       Make periodic onsite inspections while fabrication is in
 floating facilities,                                  progress and must verify the following fabrication items,
                                                       as appropriate:
                                                      (i) Quality control by lessee and builder;
                                                      (ii) Fabrication site facilities;
                                                      (iii) Material quality and identification methods;
                                                      (iv) Fabrication procedures specified in the approved
                                                       plan, and adherence to such procedures;
                                                      (v) Welder and welding procedure qualification and
                                                       identification;
                                                      (vi) Structural tolerances specified and adherence to
                                                       those tolerances;
                                                      (vii) The nondestructive examination requirements, and
                                                       evaluation results of the specified examinations;
                                                      (viii) Destructive testing requirements and results;
                                                      (ix) Repair procedures;
                                                      (x) Installation of corrosion-protection systems and
                                                       splash-zone protection;
                                                      (xi) Erection procedures to ensure that overstressing of
                                                       structural members does not occur;
                                                      (xii) Alignment procedures;
                                                      (xiii) Dimensional check of the overall structure,
                                                       including any turrets, turret-and-hull interfaces, any
                                                       mooring line and chain and riser tensioning line
                                                       segments; and
                                                      (xiv) Status of quality-control records at various stages
                                                       of fabrication.
(2) For all floating facilities,                      Ensure that the requirements of the U.S. Coast Guard
                                                       floating for structural integrity and stability, e.g.,
                                                       verification of center of gravity, etc., have been met.
                                                       The CVA must also consider:
                                                      (i) Drilling, production, and pipeline risers, and riser
                                                       tensioning systems (at least for the initial fabrication
                                                       of these elements);
                                                      (ii) Turrets and turret-and-hull interfaces;
                                                      (iii) Foundation pilings and templates, and anchoring
                                                       systems; and
                                                      (iv) Mooring or tethering systems.
----------------------------------------------------------------------------------------------------------------

    (c) The CVA must submit interim reports and a final report to the 
Regional Supervisor, and to you, during the fabrication phase in 
accordance with the approved schedule required by Sec. 250.911(d). In 
each interim and final report the CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Describe the CVA's activities during the verification process;
    (3) Summarize the CVA's findings;
    (4) Confirm or deny compliance with the design specifications and 
the approved fabrication plan;
    (5) In the final CVA report, make a recommendation to accept or 
reject the fabrication unless such a recommendation has been previously 
made in an interim report; and
    (6) Provide any additional comments that the CVA deems necessary.

[[Page 205]]



Sec. 250.918  What are the CVA's primary duties during the installation
phase?

    (a) The CVA must use good engineering judgment and practice in 
conducting an independent assessment of the installation activities.
    (b) Primary duties of the CVA during the installation phase include 
the following:

----------------------------------------------------------------------------------------------------------------
                 The CVA must . . .                          Operation or equipment to be inspected . . .
----------------------------------------------------------------------------------------------------------------
(1) Verify, as appropriate,                           (i) Loadout and initial flotation operations;
                                                      (ii) Towing operations to the specified location, and
                                                       review the towing records;
                                                      (iii) Launching and uprighting operations;
                                                      (iv) Submergence operations;
                                                      (v) Pile or anchor installations;
                                                      (vi) Installation of mooring and tethering systems;
                                                      (vii) Final deck and component installations; and
                                                      (viii) Installation at the approved location according to
                                                       the approved design and the installation plan.
(2) Witness (for a fixed or floating platform),       (i) The loadout of the jacket, decks, piles, or structures
                                                       from each fabrication site;
                                                      (ii) The actual installation of the platform or major
                                                       modification and the related installation activities.
(3) Witness (for a floating platform),                (i) The loadout of the platform;
                                                      (ii) The installation of drilling, production, and
                                                       pipeline risers, and riser tensioning systems (at least
                                                       for the initial installation of these elements);
                                                      (iii) The installation of turrets and turret-and-hull
                                                       interfaces;
                                                      (iv) The installation of foundation pilings and templates,
                                                       and anchoring systems; and
                                                      (v) The installation of the mooring and tethering systems.
(4) Conduct an onsite survey,                         Survey the platform after transportation to the approved
                                                       location.
(5) Spot-check as necessary to determine compliance   (i) Equipment;
 with the applicable documents listed in Sec. (ii) Procedures; and
 250.901(a); the alternative codes, rules and         (iii) Recordkeeping.
 standards approved under Sec. 250.901(b); the
 requirements listed in Sec. 250.903 and Secs.
 250.906 through 250.908 of this subpart and the
 approved plans,
----------------------------------------------------------------------------------------------------------------

    (c) The CVA must submit interim reports and a final report to the 
Regional Supervisor, and to you, during the installation phase in 
accordance with the approved schedule required by Sec. 250.911(d). In 
each interim and final report the CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Describe the CVA's activities during the verification process;
    (3) Summarize the CVA's findings;
    (4) Confirm or deny compliance with the approved installation plan;
    (5) In the final report, make a recommendation to accept or reject 
the installation unless such a recommendation has been previously made 
in an interim report; and
    (6) Provide any additional comments that the CVA deems necessary.

          Inspection, Maintenance, and Assessment of Platforms



Sec. 250.919  What in-service inspection requirements must I meet?

    (a) You must submit a comprehensive in-service inspection report 
annually by November 1 to the Regional Supervisor that must include:
    (1) A list of fixed and floating platforms you inspected in the 
preceding 12 months;
    (2) The extent and area of inspection for both the above-water and 
underwater portions of the platform and the pertinent components of the 
mooring system for floating platforms;
    (3) The type of inspection employed (e.g., visual, magnetic 
particle, ultrasonic testing);
    (4) The overall structural condition of each platform, including a 
corrosion protection evaluation; and
    (5) A summary of the inspection results indicating what repairs, if 
any, were needed.

[[Page 206]]

    (b) If any of your structures have been exposed to a natural 
occurrence (e.g., hurricane, earthquake, or tropical storm), the 
Regional Supervisor may require you to submit an initial report of all 
structural damage, followed by subsequent updates, which include the 
following:
    (1) A list of affected structures;
    (2) A timetable for conducting the inspections described in section 
14.4.3 of API RP 2A-WSD (as incorporated by reference in Sec. 250.198); 
and
    (3) An inspection plan for each structure that describes the work 
you will perform to determine the condition of the structure.
    (c) The Regional Supervisor may also require you to submit the 
results of the inspections referred to in paragraph (b)(2) of this 
section, including a description of any detected damage that may 
adversely affect structural integrity, an assessment of the structure's 
ability to withstand any anticipated environmental conditions, and any 
remediation plans. Under Secs. 250.900(b)(3) and 250.905, you must 
obtain approval from BSEE before you make major repairs of any damage 
unless you meet the requirements of Sec. 250.900(c).



Sec. 250.920  What are the BSEE requirements for assessment of fixed 
platforms?

    (a) You must document all wells, equipment, and pipelines supported 
by the platform if you intend to use either the A-2 or A-3 assessment 
category. Assessment categories are defined in API RP 2A-WSD, Section 
17.3 (as incorporated by reference in Sec. 250.198). If BSEE objects to 
the assessment category you used for your assessment, you may need to 
redesign and/or modify the platform to adequately demonstrate that the 
platform is able to withstand the environmental loadings for the 
appropriate assessment category.
    (b) You must perform an analysis check when your platform will have 
additional personnel, additional topside facilities, increased 
environmental or operational loading, inadequate deck height, or 
suffered significant damage (e.g., experienced damage to primary 
structural members or conductor guide trays or global structural 
integrity is adversely affected); or the exposure category changes to a 
more restrictive level (see Sections 17.2.1 through 17.2.5 of API RP 2A-
WSD, incorporated by reference in Sec. 250.198, for a description of 
assessment initiators).
    (c) You must initiate mitigation actions for platforms that do not 
pass the assessment process of API RP 2A-WSD. You must submit 
applications for your mitigation actions (e.g., repair, modification, 
decommissioning) to the Regional Supervisor for approval before you 
conduct the work.
    (d) The BSEE may require you to conduct a platform design basis 
check when the reduced environmental loading criteria contained in API 
RP 2A-WSD Section 17.6 are not applicable.
    (e) By November 1, 2009, you must submit a complete list of all the 
platforms you operate, together with all the appropriate data to support 
the assessment category you assign to each platform and the platform 
assessment initiators (as defined in API RP 2A-WSD) to the Regional 
Supervisor. You must submit subsequent complete lists and the 
appropriate data to support the consequence-of-failure category every 5 
years thereafter, or as directed by the Regional Supervisor.
    (f) The use of Section 17, Assessment of Existing Platforms, of API 
RP 2A-WSD is limited to existing fixed structures that are serving their 
original approved purpose. You must obtain approval from the Regional 
Supervisor for any change in purpose of the platform, following the 
provisions of API RP 2A-WSD, Section 15, Re-use.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec. 250.921  How do I analyze my platform for cumulative fatigue?

    (a) If you are required to analyze cumulative fatigue on your 
platform because of the results of an inspection or platform assessment, 
you must ensure that the safety factors for critical elements listed in 
Sec. 250.908 are met or exceeded.
    (b) If the calculated life of a joint or member does not meet the 
criteria of Sec. 250.908, you must either mitigate the load, strengthen 
the joint or member, or develop an increased inspection process.

[[Page 207]]



             Subpart J_Pipelines and Pipeline Rights-of-Way



Sec. 250.1000  General requirements.

    (a) Pipelines and associated valves, flanges, and fittings shall be 
designed, installed, operated, maintained, and abandoned to provide safe 
and pollution-free transportation of fluids in a manner which does not 
unduly interfere with other uses in the Outer Continental Shelf (OCS).
    (b) An application must be accompanied by payment of the service fee 
listed in Sec. 250.125 and submitted to the Regional Supervisor and 
approval obtained before:
    (1) Installation, modification, or abandonment of a lease term 
pipeline;
    (2) Installation or modification of a right-of-way (other than lease 
term) pipeline; or
    (3) Modification or relinquishment of a pipeline right-of way.
    (c)(1) Department of the Interior (DOI) pipelines, as defined in 
Sec. 250.1001, must meet the requirements in Secs. 250.1000 through 
250.1008.
    (2) A pipeline right-of-way grant holder must identify in writing to 
the Regional Supervisor the operator of any pipeline located on its 
right-of-way, if the operator is different from the right-of-way grant 
holder.
    (3) A producing operator must identify for its own records, on all 
existing pipelines located on its lease or right-of-way, the specific 
points at which operating responsibility transfers to a transporting 
operator.
    (i) Each producing operator must, if practical, durably mark all of 
its above-water transfer points as of the date a pipeline begins 
service.
    (ii) If it is not practical to durably mark a transfer point, and 
the transfer point is located above water, then the operator must 
identify the transfer point on a schematic located on the facility.
    (iii) If a transfer point is located below water, then the operator 
must identify the transfer point on a schematic and provide the 
schematic to BSEE upon request.
    (iv) If adjoining producing and transporting operators cannot agree 
on a transfer point, the BSEE Regional Supervisor and the appropriate 
Department of Transportation (DOT) pipeline official may jointly 
determine the transfer point.
    (4) The transfer point serves as a regulatory boundary. An operator 
may request that the BSEE Regional Supervisor grant an exception to this 
requirement for an individual facility or area. The Regional Supervisor, 
in consultation with the appropriate DOT pipeline official and affected 
parties, may grant the request.
    (5) Pipeline segments designed, constructed, maintained, and 
operated under DOT regulations but transferring to DOI regulation as of 
October 16, 1998, may continue to operate under DOT design and 
construction requirements until significant modifications or repairs are 
made to those segments. After October 16, 1998, BSEE operational and 
maintenance requirements will apply to those segments.
    (6) Any producer operating a pipeline that crosses into State waters 
without first connecting to a transporting operator's facility on the 
OCS must comply with this subpart. Compliance must extend from the point 
where hydrocarbons are first produced, through and including the last 
valve and associated safety equipment (e.g., pressure safety sensors) on 
the last production facility on the OCS.
    (7) Any producer operating a pipeline that connects facilities on 
the OCS must comply with this subpart.
    (8) Any operator of a pipeline that has a valve on the OCS 
downstream (landward) of the last production facility may ask in writing 
that the BSEE Regional Supervisor recognize that valve as the last point 
BSEE will exercise its regulatory authority.
    (9) A pipeline segment is not subject to BSEE regulations for 
design, construction, operation, and maintenance if:
    (i) It is downstream (generally shoreward) of the last valve and 
associated safety equipment on the last production facility on the OCS; 
and
    (ii) It is subject to regulation under 49 CFR parts 192 and 195.
    (10) DOT may inspect all upstream safety equipment (including 
valves, over-pressure protection devices, cathodic protection equipment, 
and pigging devices, etc.) that serve to protect

[[Page 208]]

the integrity of DOT-regulated pipeline segments.
    (11) OCS pipeline segments not subject to DOT regulation under 49 
CFR parts 192 and 195 are subject to all BSEE regulations.
    (12) A producer may request that its pipeline operate under DOT 
regulations governing pipeline design, construction, operation, and 
maintenance.
    (i) The operator's request must be in the form of a written petition 
to the BSEE Regional Supervisor that states the justification for the 
pipeline to operate under DOT regulation.
    (ii) The Regional Supervisor will decide, on a case-by-case basis, 
whether to grant the operator's request. In considering each petition, 
the Regional Supervisor will consult with the appropriate DOT pipeline 
official.
    (13) A transporter who operates a pipeline regulated by DOT may 
request to operate under BSEE regulations governing pipeline operation 
and maintenance. Any subsequent repairs or modifications will also be 
subject to BSEE regulations governing design and construction.
    (i) The operator's request must be in the form of a written petition 
to the appropriate DOT pipeline official and the BSEE Regional 
Supervisor.
    (ii) The BSEE Regional Supervisor and the appropriate DOT pipeline 
official will decide how to act on this petition.
    (d) A pipeline which qualifies as a right-of-way pipeline (see 
Sec. 250.1001, Definitions) shall not be installed until a right-of-way 
has been requested and granted in accordance with this subpart.
    (e)(1) The Regional Supervisor may suspend any pipeline operation 
upon a determination by the Regional Supervisor that continued activity 
would threaten or result in serious, irreparable, or immediate harm or 
damage to life (including fish and other aquatic life), property, 
mineral deposits, or the marine, coastal, or human environment.
    (2) The Regional Supervisor may also suspend pipeline operations or 
a right-of-way grant if the Regional Supervisor determines that the 
lessee or right-of-way holder has failed to comply with a provision of 
the Act or any other applicable law, a provision of these or other 
applicable regulations, or a condition of a permit or right-of-way 
grant.
    (3) The Secretary of the Interior (Secretary) may cancel a pipeline 
permit or right-of-way grant in accordance with 43 U.S.C. 1334(a)(2). A 
right-of-way grant may be forfeited in accordance with 43 U.S.C. 
1334(e).

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec. 250.1001  Definitions.

    Terms used in this subpart shall have the meanings given below:
    DOI pipelines include:
    (1) Producer-operated pipelines extending upstream (generally 
seaward) from each point on the OCS at which operating responsibility 
transfers from a producing operator to a transporting operator;
    (2) Producer-operated pipelines extending upstream (generally 
seaward) of the last valve (including associated safety equipment) on 
the last production facility on the OCS that do not connect to a 
transporter-operated pipeline on the OCS before crossing into State 
waters;
    (3) Producer-operated pipelines connecting production facilities on 
the OCS;
    (4) Transporter-operated pipelines that DOI and DOT have agreed are 
to be regulated as DOI pipelines; and
    (5) All OCS pipelines not subject to regulation under 49 CFR parts 
192 and 195.
    DOT pipelines include:
    (1) Transporter-operated pipelines currently operated under DOT 
requirements governing design, construction, maintenance, and operation;
    (2) Producer-operated pipelines that DOI and DOT have agreed are to 
be regulated under DOT requirements governing design, construction, 
maintenance, and operation; and
    (3) Producer-operated pipelines downstream (generally shoreward) of 
the last valve (including associated safety equipment) on the last 
production facility on the OCS that do not connect to a transporter-
operated pipeline on the OCS before crossing into State waters and that 
are regulated under 49 CFR parts 192 and 195.

[[Page 209]]

    Lease term pipelines are those pipelines owned and operated by a 
lessee or operator and are wholly contained within the boundaries of a 
single lease, unitized leases, or contiguous (not cornering) leases of 
that lessee or operator.
    Out-of-service pipelines are those pipelines that have not been used 
to transport oil, natural gas, sulfur, or produced water for more than 
30 consecutive days.
    Pipelines are the piping, risers, and appurtenances installed for 
the purpose of transporting oil, gas, sulphur, and produced water. 
(Piping confined to a production platform or structure is covered in 
Subpart H, Production Safety Systems, and is excluded from this 
subpart.)
    Production facilities means OCS facilities that receive hydrocarbon 
production either directly from wells or from other facilities that 
produce hydrocarbons from wells. They may include processing equipment 
for treating the production or separating it into its various liquid and 
gaseous components before transporting it to shore.
    Right-of-way pipelines are those pipelines which--
    (1) Are contained within the boundaries of a single lease or group 
of unitized leases but are not owned and operated by the lessee or 
operator of that lease or unit,
    (2) Are contained within the boundaries of contiguous (not 
cornering) leases which do not have a common lessee or operator,
    (3) Are contained within the boundaries of contiguous (not 
cornering) leases which have a common lessee or operator but are not 
owned and operated by that common lessee or operator, or
    (4) Cross any portion of an unleased block(s).



Sec. 250.1002  Design requirements for DOI pipelines.

    (a) The internal design pressure for steel pipe shall be determined 
in accordance with the following formula:
[GRAPHIC] [TIFF OMITTED] TR18OC11.000

    For limitations see section 841.121 of American National Standards 
Institute (ANSI) B31.8 (as incorporated by reference in Sec. 250.198) 
where--

P = Internal design pressure in pounds per square inch (psi).
S = Specified minimum yield strength, in psi, stipulated in the 
          specification under which the pipe was purchased from the 
          manufacturer or determined in accordance with section 
          811.253(h) of ANSI B31.8.
D = Nominal outside diameter of pipe, in inches.
t = Nominal wall thickness, in inches.
F = Construction design factor of 0.72 for the submerged component and 
          0.60 for the riser component.
E = Longitudinal joint factor obtained from Table 841.1B of ANSI B31.8 
          (see also section 811.253(d)).
T = Temperature derating factor obtained from Table 841.1C of ANSI 
          B31.8.

    (b)(1) Pipeline valves shall meet the minimum design requirements of 
American Petroleum Institute (API) Spec 6A (as incorporated by reference 
in Sec. 250.198), API Spec 6D (as incorporated by reference in 
Sec. 250.198), or the equivalent. A valve may not be used under 
operating conditions that exceed the applicable pressure-temperature 
ratings contained in those standards.
    (2) Pipeline flanges and flange accessories shall meet the minimum 
design requirements of ANSI B16.5, API Spec 6A, or the equivalent (as 
incorporated by reference in 30 CFR 250.198). Each flange assembly must 
be able to withstand the maximum pressure at which the pipeline is to be 
operated and to maintain its physical and chemical properties at any 
temperature to which it is anticipated that it might be subjected in 
service.
    (3) Pipeline fittings shall have pressure-temperature ratings based 
on stresses for pipe of the same or equivalent material. The actual 
bursting strength of the fitting shall at least be equal to the computed 
bursting strength of the pipe.
    (4) If you are installing pipelines constructed of unbonded flexible 
pipe, you must design them according to the standards and procedures of 
API Spec 17J, as incorporated by reference in 30 CFR 250.198.
    (5) You must design pipeline risers for tension leg platforms and 
other

[[Page 210]]

floating platforms according to the design standards of API RP 2RD, 
Design of Risers for Floating Production Systems (FPSs) and Tension Leg 
Platforms (TLPs) (as incorporated by reference in Sec. 250.198).
    (c) The maximum allowable operating pressure (MAOP) shall not exceed 
the least of the following:
    (1) Internal design pressure of the pipeline, valves, flanges, and 
fittings;
    (2) Eighty percent of the hydrostatic pressure test (HPT) pressure 
of the pipeline; or
    (3) If applicable, the MAOP of the receiving pipeline when the 
proposed pipeline and the receiving pipeline are connected at a subsea 
tie-in.
    (d) If the maximum source pressure (MSP) exceeds the pipeline's 
MAOP, you must install and maintain redundant safety devices meeting the 
requirements of section A9 of API RP 14C (as incorporated by reference 
in Sec. 250.198). Pressure safety valves (PSV) may be used only after a 
determination by the Regional Supervisor that the pressure will be 
relieved in a safe and pollution-free manner. The setting level at which 
the primary and redundant safety equipment actuates shall not exceed the 
pipeline's MAOP.
    (e) Pipelines shall be provided with an external protective coating 
capable of minimizing underfilm corrosion and a cathodic protection 
system designed to mitigate corrosion for at least 20 years.
    (f) Pipelines shall be designed and maintained to mitigate any 
reasonably anticipated detrimental effects of water currents, storm or 
ice scouring, soft bottoms, mud slides, earthquakes, subfreezing 
temperatures, and other environmental factors.



Sec. 250.1003  Installation, testing, and repair requirements for
DOI pipelines.

    (a)(1) Pipelines greater than 8\5/8\ inches in diameter and 
installed in water depths of less than 200 feet shall be buried to a 
depth of at least 3 feet unless they are located in pipeline congested 
areas or seismically active areas as determined by the Regional 
Supervisor. Nevertheless, the Regional Supervisor may require burial of 
any pipeline if the Regional Supervisor determines that such burial will 
reduce the likelihood of environmental degradation or that the pipeline 
may constitute a hazard to trawling operations or other uses. A trawl 
test or diver survey may be required to determine whether or not 
pipeline burial is necessary or to determine whether a pipeline has been 
properly buried.
    (2) Pipeline valves, taps, tie-ins, capped lines, and repaired 
sections that could be obstructive shall be provided with at least 3 
feet of cover unless the Regional Supervisor determines that such items 
present no hazard to trawling or other operations. A protective device 
may be used to cover an obstruction in lieu of burial if it is approved 
by the Regional Supervisor prior to installation.
    (3) Pipelines shall be installed with a minimum separation of 18 
inches at pipeline crossings and from obstructions.
    (4) Pipeline risers installed after April 1, 1988, shall be 
protected from physical damage that could result from contact with 
floating vessels. Riser protection on pipelines installed on or before 
April 1, 1988, may be required when the Regional Supervisor determines 
that significant damage potential exists.
    (b)(1) Pipelines shall be pressure tested with water at a stabilized 
pressure of at least 1.25 times the MAOP for at least 8 hours when 
installed, relocated, uprated, or reactivated after being out-of-service 
for more than 1 year.
    (2) Prior to returning a pipeline to service after a repair, the 
pipeline shall be pressure tested with water or processed natural gas at 
a minimum stabilized pressure of at least 1.25 times the MAOP for at 
least 2 hours.
    (3) Pipelines shall not be pressure tested at a pressure which 
produces a stress in the pipeline in excess of 95 percent of the 
specified minimum-yield strength of the pipeline. A temperature recorder 
measuring test fluid temperature synchronized with a pressure recorder 
along with deadweight test readings shall be employed for all pressure 
testing. When a pipeline is pressure tested, no observable leakage shall 
be allowed. Pressure gauges and recorders shall be of sufficient 
accuracy to verify that leakage is not occurring.

[[Page 211]]

    (4) The Regional Supervisor may require pressure testing of 
pipelines to verify the integrity of the system when the Regional 
Supervisor determines that there is a reasonable likelihood that the 
line has been damaged or weakened by external or internal conditions.
    (c) When a pipeline is repaired utilizing a clamp, the clamp shall 
be a full encirclement clamp able to withstand the anticipated pipeline 
pressure.



Sec. 250.1004  Safety equipment requirements for DOI pipelines.

    (a) The lessee shall ensure the proper installation, operation, and 
maintenance of safety devices required by this section on all incoming, 
departing, and crossing pipelines on platforms.
    (b)(1)(i) Incoming pipelines to a platform shall be equipped with a 
flow safety valve (FSV).
    (ii) For sulphur operations, incoming pipelines delivering gas to 
the power plant platform may be equipped with high- and low-pressure 
sensors (PSHL), which activate audible and visual alarms in lieu of 
requirements in paragraph (b)(1)(i) of this section. The PSHL shall be 
set at 15 percent or 5 psi, whichever is greater, above and below the 
normal operating pressure range.
    (2) Incoming pipelines boarding a production platform shall be 
equipped with an automatic shutdown valve (SDV) immediately upon 
boarding the platform. The SDV shall be connected to the automatic- and 
remote-emergency shut-in systems.
    (3) Departing pipelines receiving production from production 
facilities shall be protected by high- and low-pressure sensors (PSHL) 
to directly or indirectly shut in all production facilities. The PSHL 
shall be set not to exceed 15 percent above and below the normal 
operating pressure range. However, high pilots shall not be set above 
the pipeline's MAOP.
    (4) Crossing pipelines on production or manned nonproduction 
platforms which do not receive production from the platform shall be 
equipped with an SDV immediately upon boarding the platform. The SDV 
shall be operated by a PSHL on the departing pipelines and connected to 
the platform automatic- and remote-emergency shut-in systems.
    (5) The Regional Supervisor may require that oil pipelines be 
equipped with a metering system to provide a continuous volumetric 
comparison between the input to the line at the structure(s) and the 
deliveries onshore. The system shall include an alarm system and shall 
be of adequate sensitivity to detect variations between input and 
discharge volumes. In lieu of the foregoing, a system capable of 
detecting leaks in the pipeline may be substituted with the approval of 
the Regional Supervisor.
    (6) Pipelines incoming to a subsea tie-in shall be equipped with a 
block valve and an FSV. Bidirectional pipelines connected to a subsea 
tie-in shall be equipped with only a block valve.
    (7) Gas-lift or water-injection pipelines on unmanned platforms need 
only be equipped with an FSV installed immediately upstream of each 
casing annulus or the first inlet valve on the christmas tree.
    (8) Bidirectional pipelines shall be equipped with a PSHL and an SDV 
immediately upon boarding each platform.
    (9) Pipeline pumps must comply with section A7 of API RP 14C (as 
incorporated by reference in Sec. 250.198). The setting levels for the 
PSHL devices are specified in paragraph (b)(3) of this section.
    (c) If the required safety equipment is rendered ineffective or 
removed from service on pipelines which are continued in operation, an 
equivalent degree of safety shall be provided. The safety equipment 
shall be identified by the placement of a sign on the equipment stating 
that the equipment is rendered ineffective or removed from service.



Sec. 250.1005  Inspection requirements for DOI pipelines.

    (a) Pipeline routes shall be inspected at time intervals and methods 
prescribed by the Regional Supervisor for indication of pipeline 
leakage. The results of these inspections shall be retained for at least 
2 years and be made available to the Regional Supervisor upon request.

[[Page 212]]

    (b) When pipelines are protected by rectifiers or anodes for which 
the initial life expectancy of the cathodic protection system either 
cannot be calculated or calculations indicate a life expectancy of less 
than 20 years, such pipelines shall be inspected annually by taking 
measurements of pipe-to-electrolyte potential.



Sec. 250.1006  How must I decommission and take out of service 
a DOI pipeline?

    (a) The requirements for decommissioning pipelines are listed in 
Sec. 250.1750 through Sec. 250.1754.
    (b) The table in this section lists the requirements if you take a 
DOI pipeline out of service:

----------------------------------------------------------------------------------------------------------------
    If you have the pipeline out of service for:                            Then you must:
----------------------------------------------------------------------------------------------------------------
(1) 1 year or less,                                   Isolate the pipeline with a blind flange or a closed block
                                                       valve at each end of the pipeline.
(2) More than 1 year but less than 5 years,           Flush and fill the pipeline with inhibited seawater.
(3) 5 or more years,                                  Decommission the pipeline according to Secs.  250.1750-
                                                       250.1754.
----------------------------------------------------------------------------------------------------------------



Sec. 250.1007  What to include in applications.

    (a) Applications to install a lease term pipeline or for a pipeline 
right-of-way grant must be submitted in quadruplicate to the Regional 
Supervisor. Right-of-way grant applications must include an 
identification of the operator of the pipeline. Each application must 
include the following:
    (1) Plat(s) drawn to a scale specified by the Regional Supervisor 
showing major features and other pertinent data including area, lease, 
and block designations; water depths; route; length in Federal waters; 
width of right-of-way, if applicable; connecting facilities; size; 
product(s) to be transported with anticipated gravity or density; burial 
depth; direction of flow; X-Y coordinates of key points; and the 
location of other pipelines that will be connected to or crossed by the 
proposed pipeline(s). The initial and terminal points of the pipeline 
and any continuation into State jurisdiction shall be accurately located 
even if the pipeline is to have an onshore terminal point. A plat(s) 
submitted for a pipeline right-of-way shall bear a signed certificate 
upon its face by the engineer who made the map that certifies that the 
right-of-way is accurately represented upon the map and that the design 
characteristics of the associated pipeline are in accordance with 
applicable regulations.
    (2) A schematic drawing showing the size, weight, grade, wall 
thickness, and type of line pipe and risers; pressure-regulating devices 
(including back-pressure regulators); sensing devices with associated 
pressure-control lines; PSV's and settings; SDV's, FSV's, and block 
valves; and manifolds. This schematic drawing shall also show input 
source(s), e.g., wells, pumps, compressors, and vessels; maximum input 
pressure(s); the rated working pressure, as specified by ANSI or API, of 
all valves, flanges, and fittings; the initial receiving equipment and 
its rated working pressure; and associated safety equipment and pig 
launchers and receivers. The schematic must indicate the point on the 
OCS at which operating responsibility transfers between a producing 
operator and a transporting operator.
    (3) General information as follows:
    (i) Description of cathodic protection system. If pipeline anodes 
are to be used, specify the type, size, weight, number, spacing, and 
anticipated life;
    (ii) Description of external pipeline coating system;
    (iii) Description of internal protective measures;
    (iv) Specific gravity of the empty pipe;
    (v) MSP;
    (vi) MAOP and calculations used in its determination;
    (vii) Hydrostatic test pressure, medium, and period of time that the 
line will be tested;
    (viii) MAOP of the receiving pipeline or facility,
    (ix) Proposed date for commencing installation and estimated time 
for construction; and
    (x) Type of protection to be afforded crossing pipelines, subsea 
valves, taps, and manifold assemblies, if applicable.

[[Page 213]]

    (4) A description of any additional design precautions you took to 
enable the pipeline to withstand the effects of water currents, storm or 
ice scouring, soft bottoms, mudslides, earthquakes, permafrost, and 
other environmental factors.
    (i) If you propose to use unbonded flexible pipe, your application 
must include:
    (A) The manufacturer's design specification sheet;
    (B) The design pressure (psi);
    (C) An identification of the design standards you used; and
    (D) A review by a third-party independent verification agent (IVA) 
according to API Spec 17J (as incorporated by reference in 
Sec. 250.198), if applicable.
    (ii) If you propose to use one or more pipeline risers for a tension 
leg platform or other floating platform, your application must include:
    (A) The design fatigue life of the riser, with calculations, and the 
fatigue point at which you would replace the riser;
    (B) The results of your vortex-induced vibration (VIV) analysis;
    (C) An identification of the design standards you used; and
    (D) A description of any necessary mitigation measures such as the 
use of helical strakes or anchoring devices.
    (5) The application shall include a shallow hazards survey report 
and, if required by the Regional Director, an archaeological resource 
report that covers the entire length of the pipeline. A shallow hazards 
analysis may be included in a lease term pipeline application in lieu of 
the shallow hazards survey report with the approval of the Regional 
Director. The Regional Director may require the submission of the data 
upon which the report or analysis is based.
    (b) Applications to modify an approved lease term pipeline or right-
of-way grant shall be submitted in quadruplicate to the Regional 
Supervisor. These applications need only address those items in the 
original application affected by the proposed modification.



Sec. 250.1008  Reports.

    (a) The lessee, or right-of-way holder, shall notify the Regional 
Supervisor at least 48 hours prior to commencing the installation or 
relocation of a pipeline or conducting a pressure test on a pipeline.
    (b) The lessee or right-of-way holder shall submit a report to the 
Regional Supervisor within 90 days after completion of any pipeline 
construction. The report, submitted in triplicate, shall include an 
``as-built'' location plat drawn to a scale specified by the Regional 
Supervisor showing the location, length in Federal waters, and X-Y 
coordinates of key points; the completion date; the proposed date of 
first operation; and the HPT data. Pipeline right-of-way ``as-built'' 
location plats shall be certified by a registered engineer or land 
surveyor and show the boundaries of the right-of-way as granted. If 
there is a substantial deviation of the pipeline route as granted in the 
right-of-way, the report shall include a discussion of the reasons for 
such deviation.
    (c) The lessee or right-of-way holder shall report to the Regional 
Supervisor any pipeline taken out of service. If the period of time in 
which the pipeline is out of service is greater than 60 days, written 
confirmation is also required.
    (d) The lessee or right-of-way holder shall report to the Regional 
Supervisor when any required pipeline safety equipment is taken out of 
service for more than 12 hours. The Regional Supervisor shall be 
notified when the equipment is returned to service.
    (e) The lessee or right-of-way holder must notify the Regional 
Supervisor before the repair of any pipeline or as soon as practicable. 
Your notification must be accompanied by payment of the service fee 
listed in Sec. 250.125. You must submit a detailed report of the repair 
of a pipeline or pipeline component to the Regional Supervisor within 30 
days after the completion of the repairs. In the report you must include 
the following:
    (1) Description of repairs;
    (2) Results of pressure test; and
    (3) Date returned to service.
    (f) The Regional Supervisor may require that DOI pipeline failures 
be analyzed and that samples of a failed section be examined in a 
laboratory to assist in determining the cause of the

[[Page 214]]

failure. A comprehensive written report of the information obtained 
shall be submitted by the lessee to the Regional Supervisor as soon as 
available.
    (g) If the effects of scouring, soft bottoms, or other environmental 
factors are observed to be detrimentally affecting a pipeline, a plan of 
corrective action shall be submitted to the Regional Supervisor for 
approval within 30 days of the observation. A report of the remedial 
action taken shall be submitted to the Regional Supervisor by the lessee 
or right-of-way holder within 30 days after completion.
    (h) The results and conclusions of measurements of pipe-to-
electrolyte potential measurements taken annually on DOI pipelines in 
accordance with Sec. 250.1005(b) of this part shall be submitted to the 
Regional Supervisor by the lessee before March of each year.



Sec. 250.1009  Requirements to obtain pipeline right-of-way grants.

    (a) In addition to applicable requirements of Secs. 250.1000 through 
250.1008 and other regulations of this part, regulations of the 
Department of Transportation, Department of the Army, and the Federal 
Energy Regulatory Commission (FERC), when a pipeline qualifies as a 
right-of-way pipeline, the pipeline shall not be installed until a 
right-of-way has been requested and granted in accordance with this 
subpart. The right-of-way grant is issued pursuant to 43 U.S.C. 1334(e) 
and may be acquired and held only by citizens and nationals of the 
United States; aliens lawfully admitted for permanent residence in the 
United States as defined in 8 U.S.C. 1101(a)(20); private, public, or 
municipal corporations organized under the laws of the United States or 
territory thereof, the District of Columbia, or of any State; or 
associations of such citizens, nationals, resident aliens, or private, 
public, or municipal corporations, States, or political subdivisions of 
States.
    (b) A right-of-way shall include the site on which the pipeline and 
associated structures are to be situated, shall not exceed 200 feet in 
width unless safety and environmental factors during construction and 
operation of the associated right-of-way pipeline require a greater 
width, and shall be limited to the area reasonably necessary for pumping 
stations or other accessory structures.



Sec. 250.1010  General requirements for pipeline right-of-way holders.

    An applicant, by accepting a right-of-way grant, agrees to comply 
with the following requirements:
    (a) The right-of-way holder shall comply with applicable laws and 
regulations and the terms of the grant.
    (b) The granting of the right-of-way shall be subject to the express 
condition that the rights granted shall not prevent or interfere in any 
way with the management, administration, or the granting of other rights 
by the United States, either prior or subsequent to the granting of the 
right-of-way. Moreover, the holder agrees to allow the occupancy and use 
by the United States, its lessees, or other right-of-way holders, of any 
part of the right-of-way grant not actually occupied or necessarily 
incident to its use for any necessary operations involved in the 
management, administration, or the enjoyment of such other granted 
rights.
    (c) If the right-of-way holder discovers any archaeological resource 
while conducting operations within the right-of-way, the right-of-way 
holder shall immediately halt operations within the area of the 
discovery and report the discovery to the Regional Director. If 
investigations determine that the resource is significant, the Regional 
Director will inform the right-of-way holder how to protect it.
    (d) The Regional Supervisor shall be kept informed at all times of 
the right-of-way holder's address and, if a corporation, the address of 
its principal place of business and the name and address of the officer 
or agent authorized to be served with process.
    (e) The right-of-way holder shall pay the United States or its 
lessees or right-of-way holders, as the case may be, the full value of 
all damages to the property of the United States or its said lessees or 
right-of-way holders and shall indemnify the United States against any 
and all liability for damages to life, person, or property arising

[[Page 215]]

from the occupation and use of the area covered by the right-of-way 
grant.
    (f)(1) The holder of a right-of-way oil or gas pipeline shall 
transport or purchase oil or natural gas produced from submerged lands 
in the vicinity of the pipeline without discrimination and in such 
proportionate amounts as the FERC may, after a full hearing with due 
notice thereof to the interested parties, determine to be reasonable, 
taking into account, among other things, conservation and the prevention 
of waste.
    (2) Unless otherwise exempted by FERC pursuant to 43 U.S.C. 
1334(f)(2), the holder shall:
    (i) Provide open and nondiscriminatory access to a right-of-way 
pipeline to both owner and nonowner shippers, and
    (ii) Comply with the provisions of 43 U.S.C. 1334(f)(1)(B) under 
which FERC may order an expansion of the throughput capacity of a right-
of-way pipeline which is approved after September 18, 1978, and which is 
not located in the Gulf of Mexico or the Santa Barbara Channel.
    (g) The area covered by a right-of-way and all improvements thereon 
shall be kept open at all reasonable times for inspection by the Bureau 
of Safety and Environmental Enforcement (BSEE). The right-of-way holder 
shall make available all records relative to the design, construction, 
operation, maintenance and repair, and investigations on or with regard 
to such area.
    (h) Upon relinquishment, forfeiture, or cancellation of a right-of-
way grant, the right-of-way holder shall remove all platforms, 
structures, domes over valves, pipes, taps, and valves along the right-
of-way. All of these improvements shall be removed by the holder within 
1 year of the effective date of the relinquishment, forfeiture, or 
cancellation unless this requirement is waived in writing by the 
Regional Supervisor. All such improvements not removed within the time 
provided herein shall become the property of the United States but that 
shall not relieve the holder of liability for the cost of their removal 
or for restoration of the site. Furthermore, the holder is responsible 
for accidents or damages which might occur as a result of failure to 
timely remove improvements and equipment and restore a site. An 
application for relinquishment of a right-of-way grant shall be filed in 
accordance with Sec. 250.1019 of this part.



Sec. 250.1011  [Reserved]



Sec. 250.1012  Required payments for pipeline right-of-way holders.

    (a) You must pay ONRR, under the regulations at 30 CFR part 1218, an 
annual rental of $15 for each statute mile, or part of a statute mile, 
of the OCS that your pipeline right-of-way crosses.
    (b) This paragraph applies to you if you obtain a pipeline right-of-
way that includes a site for an accessory to the pipeline, including but 
not limited to a platform. This paragraph also applies if you apply to 
modify a right-of-way to change the site footprint. In either case, you 
must pay the amounts shown in the following table.

----------------------------------------------------------------------------------------------------------------
                      If . . .                                                Then . . .
----------------------------------------------------------------------------------------------------------------
(1) Your accessory site is located in water depths    You must pay ONRR, under the regulations at 30 CFR part
 of less than 200 meters;                              1218, a rental of $5 per acre per year with a minimum of
                                                       $450 per year. The area subject to annual rental includes
                                                       the areal extent of anchor chains, pipeline risers, and
                                                       other facilities and devices associated with the
                                                       accessory.
(2) Your accessory site is located in water depths    You must pay ONRR, under the regulations at 30 CFR part
 of 200 meters or greater;                             1218, a rental of $7.50 per acre per year with a minimum
                                                       of $675 per year. The area subject to annual rental
                                                       includes the areal extent of anchor chains, pipeline
                                                       risers, and other facilities and devices associated with
                                                       the accessory.
----------------------------------------------------------------------------------------------------------------

    (c) If you hold a pipeline right-of-way that includes a site for an 
accessory to your pipeline and you are not covered by paragraph (b) of 
this section, then you must pay ONRR, under the regulations at 30 CFR 
part 1218, an annual rental of $75 for use of the affected area.
    (d) You may make the rental payments required by paragraphs (a), 
(b)(1), (b)(2), and (c) of this section on an annual basis, for a 5-year 
period, or

[[Page 216]]

for multiples of 5 years. You must make the first payment at the time 
you submit the pipeline right-of-way application. You must make all 
subsequent payments before the respective time periods begin.
    (e) Late payments. An interest charge will be assessed on unpaid and 
underpaid amounts from the date the amounts are due, in accordance with 
the provisions found in 30 CFR 1218.54. If you fail to make a payment 
that is late after written notice from ONRR, BSEE may initiate 
cancellation of the right-of-use grant and easement under Sec. 250.1013.



Sec. 250.1013  Grounds for forfeiture of pipeline right-of-way grants.

    Failure to comply with the Act, regulations, or any conditions of 
the right-of-way grant prescribed by the Regional Supervisor shall be 
grounds for forfeiture of the grant in an appropriate judicial 
proceeding instituted by the United States in any U.S. District Court 
having jurisdiction in accordance with the provisions of 43 U.S.C. 1349.



Sec. 250.1014  When pipeline right-of-way grants expire.

    Any right-of-way granted under the provisions of this subpart 
remains in effect as long as the associated pipeline is properly 
maintained and used for the purpose for which the grant was made, unless 
otherwise expressly stated in the grant. Temporary cessation or 
suspension of pipeline operations shall not cause the grant to expire. 
However, if the purpose of the grant ceases to exist or use of the 
associated pipeline is permanently discontinued for any reason, the 
grant shall be deemed to have expired.



Sec. 250.1015  Applications for pipeline right-of-way grants.

    (a) You must submit an original and three copies of an application 
for a new or modified pipeline ROW grant to the Regional Supervisor. The 
application must address those items required by Sec. 250.1007(a) or (b) 
of this subpart, as applicable. It must also state the primary purpose 
for which you will use the ROW grant. If the ROW has been used before 
the application is made, the application must state the date such use 
began, by whom, and the date the applicant obtained control of the 
improvement. When you file your application, you must pay the rental 
required under Sec. 250.1012 of this subpart, as well as the service 
fees listed in Sec. 250.125 of this part for a pipeline ROW grant to 
install a new pipeline, or to convert an existing lease term pipeline 
into a ROW pipeline. An application to modify an approved ROW grant must 
be accompanied by the additional rental required under Sec. 250.1012 if 
applicable. You must file a separate application for each ROW.
    (b)(1) An individual applicant shall submit a statement of 
citizenship or nationality with the application. An applicant who is an 
alien lawfully admitted for permanent residence in the United States 
shall also submit evidence of such status with the application.
    (2) If the applicant is an association (including a partnership), 
the application shall also be accompanied by a certified copy of the 
articles of association or appropriate reference to a copy of such 
articles already filed with BSEE and a statement as to any subsequent 
amendments.
    (3) If the applicant is a corporation, the application shall also 
include the following:
    (i) A statement certified by the Secretary or Assistant Secretary of 
the corporation with the corporate seal showing the State in which it is 
incorporated and the name of the person(s) authorized to act on behalf 
of the corporation, or
    (ii) In lieu of such a statement, an appropriate reference to 
statements or records previously submitted to BSEE (including material 
submitted in compliance with prior regulations).
    (c) The application shall include a list of every lessee and right-
of-way holder whose lease or right-of-way is intersected by the proposed 
right-of-way. The application shall also include a statement that a copy 
of the application has been sent by registered or certified mail to each 
such lessee or right-of-way holder.
    (d) The applicant shall include in the application an original and 
three copies of a completed Nondiscrimination

[[Page 217]]

in Employment form (YN 3341-1 dated July 1982). These forms are 
available at each BSEE regional office.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec. 250.1016  Granting pipeline rights-of-way.

    (a) In considering an application for a right-of-way, the Regional 
Supervisor shall consider the potential effect of the associated 
pipeline on the human, marine, and coastal environments, life (including 
aquatic life), property, and mineral resources in the entire area during 
construction and operational phases. The Regional Supervisor shall 
prepare an environmental analysis in accordance with applicable policies 
and guidelines. To aid in the evaluation and determinations, the 
Regional Supervisor may request and consider views and recommendations 
of appropriate Federal Agencies, hold public meetings after appropriate 
notice, and consult, as appropriate, with State agencies, organizations, 
industries, and individuals. Before granting a pipeline right-of-way, 
the Regional Supervisor shall give consideration to any recommendation 
by the intergovernmental planning program, or similar process, for the 
assessment and management of OCS oil and gas transportation.
    (b) Should the proposed route of a right-of-way adjoin and 
subsequently cross any State submerged lands, the applicant shall submit 
evidence to the Regional Supervisor that the State(s) so affected has 
reviewed the application. The applicant shall also submit any comment 
received as a result of that review. In the event of a State 
recommendation to relocate the proposed route, the Regional Supervisor 
may consult with the appropriate State officials.
    (c)(1) The applicant shall submit photocopies of return receipts to 
the Regional Supervisor that indicate the date that each lessee or 
right-of-way holder referenced in Sec. 250.1015(c) of this part has 
received a copy of the application. Letters of no objection may be 
submitted in lieu of the return receipts.
    (2) The Regional Supervisor shall not take final action on a right-
of-way application until the Regional Supervisor is satisfied that each 
such lessee or right-of-way holder has been afforded at least 30 days 
from the date determined in paragraph (c)(1) of this section in which to 
submit comments.
    (d) If a proposed right-of-way crosses any lands not subject to 
disposition by mineral leasing or restricted from oil and gas 
activities, it shall be rejected by the Regional Supervisor unless the 
Federal Agency with jurisdiction over such excluded or restricted area 
gives its consent to the granting of the right-of-way. In such case, the 
applicant, upon a request filed within 30 days after receipt of the 
notification of such rejection, shall be allowed an opportunity to 
eliminate the conflict.
    (e)(1) If the application and other required information are found 
to be in compliance with applicable laws and regulations, the right-of-
way may be granted. The Regional Supervisor may prescribe, as conditions 
to the right-of-way grant, stipulations necessary to protect human, 
marine, and coastal environments, life (including aquatic life), 
property, and mineral resources located on or adjacent to the right-of-
way.
    (2) If the Regional Supervisor determines that a change in the 
application should be made, the Regional Supervisor shall notify the 
applicant that an amended application shall be filed subject to 
stipulated changes. The Regional Supervisor shall determine whether the 
applicant shall deliver copies of the amended application to other 
parties for comment.
    (3) A decision to reject an application shall be in writing and 
shall state the reasons for the rejection.



Sec. 250.1017  Requirements for construction under pipeline
right-of-way grants.

    (a) Failure to construct the associated right-of-way pipeline within 
5 years of the date of the granting of a right-of-way shall cause the 
grant to expire.
    (b)(1) A right-of-way holder shall ensure that the right-of-way 
pipeline is constructed in a manner that minimizes deviations from the 
right-of-way as granted.

[[Page 218]]

    (2) If, after constructing the right-of-way pipeline, it is 
determined that a deviation from the proposed right-of-way as granted 
has occurred, the right-of-way holder shall--
    (i) Notify the operators of all leases and holders of all right-of-
way grants in which a deviation has occurred, and within 60 days of the 
date of the acceptance by the Regional Supervisor of the completion of 
pipeline construction report, provide the Regional Supervisor with 
evidence of such notification; and
    (ii) Relinquish any unused portion of the right-of-way.
    (3) Substantial deviation of a right-of-way pipeline as constructed 
from the proposed right-of-way as granted may be grounds for forfeiture 
of the right-of-way.
    (c) If the Regional Supervisor determines that a significant change 
in conditions has occurred subsequent to the granting of a right-of-way 
but prior to the commencement of construction of the associated 
pipeline, the Regional Supervisor may suspend or temporarily prohibit 
the commencement of construction until the right-of-way grant is 
modified to the extent necessary to address the changed conditions.



Sec. 250.1018  Assignment of pipeline right-of-way grants.

    (a) Assignment may be made of a right-of-way grant, in whole or of 
any lineal segment thereof, subject to the approval of the Regional 
Supervisor. An application for approval of an assignment of a right-of-
way or of a lineal segment thereof, shall be filed in triplicate with 
the Regional Supervisor.
    (b) Any application for approval for an assignment, in whole or in 
part, of any right, title, or interest in a right-of-way grant must be 
accompanied by the same showing of qualifications of the assignees as is 
required of an applicant for a ROW in Sec. 250.1015 of this subpart and 
must be supported by a statement that the assignee agrees to comply with 
and to be bound by the terms and conditions of the ROW grant. The 
assignee must satisfy the bonding requirements in 30 CFR 550.1011. No 
transfer will be recognized unless and until it is first approved, in 
writing, by the Regional Supervisor. The assignee must pay the service 
fee listed in Sec. 250.125 of this part for a pipeline ROW assignment 
request.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec. 250.1019  Relinquishment of pipeline right-of-way grants.

    A right-of-way grant or a portion thereof may be surrendered by the 
holder by filing a written relinquishment in triplicate with the 
Regional Supervisor. It must contain those items addressed in 
Secs. 250.1751 and 250.1752 of this part. A relinquishment shall take 
effect on the date it is filed subject to the satisfaction of all 
outstanding debts, fees, or fines and the requirements in 
Sec. 250.1010(h) of this part.



              Subpart K_Oil and Gas Production Requirements

                                 General



Sec. 250.1150  What are the general reservoir production requirements?

    You must produce wells and reservoirs at rates that provide for 
economic development while maximizing ultimate recovery and without 
adversely affecting correlative rights.

                         Well Tests and Surveys



Sec. 250.1151  How often must I conduct well production tests?

    (a) You must conduct well production tests as shown in the following 
table:

------------------------------------------------------------------------
                                             And you must submit to the
             You must conduct:                  Regional Supervisor:
------------------------------------------------------------------------
(1) A well-flow potential test on all new,  Form BSEE-0126, Well
 recompleted, or reworked well completions   Potential Test Report,
 within 30 days of the date of first         along with the supporting
 continuous production,                      data as listed in the table
                                             in Sec. 250.1167, within
                                             15 days after the end of
                                             the test period.
(2) At least one well test during a         Results on Form BSEE-0128,
 calendar half-year for each producing       Semiannual Well Test
 completion,                                 Report, of the most recent
                                             well test obtained. This
                                             must be submitted within 45
                                             days after the end of the
                                             calendar half-year.
------------------------------------------------------------------------


[[Page 219]]

    (b) You may request an extension from the Regional Supervisor if you 
cannot submit the results of a semiannual well test within the specified 
time.
    (c) You must submit to the Regional Supervisor an original and two 
copies of the appropriate form required by paragraph (a) of this 
section; one of the copies of the form must be a public information copy 
in accordance with Secs. 250.186 and 250.197, and marked ``Public 
Information.'' You must submit two copies of the supporting information 
as listed in the table in Sec. 250.1167 with form BSEE-0126.



Sec. 250.1152  How do I conduct well tests?

    (a) When you conduct well tests you must:
    (1) Recover fluid from the well completion equivalent to the amount 
of fluid introduced into the formation during completion, recompletion, 
reworking, or treatment operations before you start a well test;
    (2) Produce the well completion under stabilized rate conditions for 
at least 6 consecutive hours before beginning the test period;
    (3) Conduct the test for at least 4 consecutive hours;
    (4) Adjust measured gas volumes to the standard conditions of 14.73 
pounds per square inch absolute (psia) and 60 F for all tests; and
    (5) Use measured specific gravity values to calculate gas volumes.
    (b) You may request approval from the Regional Supervisor to conduct 
a well test using alternative procedures if you can demonstrate test 
reliability under those procedures.
    (c) The Regional Supervisor may also require you to conduct the 
following tests and complete them within a specified time period:
    (1) A retest or a prolonged test of a well completion if it is 
determined to be necessary for the proper establishment of a Maximum 
Production Rate (MPR) or a Maximum Efficient Rate (MER); and
    (2) A multipoint back-pressure test to determine the theoretical 
open-flow potential of a gas well.
    (d) A BSEE representative may witness any well test. Upon request, 
you must provide advance notice to the Regional Supervisor of the times 
and dates of well tests.



Secs. 250.1153-250.1155  [Reserved]

                      Approvals Prior to Production



Sec. 250.1156  What steps must I take to receive approval to produce
within 500 feet of a unit or lease line?

    (a) You must obtain approval from the Regional Supervisor before you 
start producing from a reservoir within a well that has any portion of 
the completed interval less than 500 feet from a unit or lease line. 
Submit to BSEE the service fee listed in Sec. 250.125, according to the 
instructions in Sec. 250.126, and the supporting information, as listed 
in the table in Sec. 250.1167, with your request. The Regional 
Supervisor will determine whether approval of your request will maximize 
ultimate recovery, avoid the waste of natural resources, or protect 
correlative rights. You do not need to obtain approval if the adjacent 
leases or units have the same unit, lease (record title and operating 
rights), and royalty interests as the lease or unit you plan to produce. 
You do not need to obtain approval if the adjacent block is unleased.
    (b) You must notify the operator(s) of adjacent property(ies) that 
are within 500 feet of the completion, if the adjacent acreage is a 
leased block in the Federal OCS. You must provide the Regional 
Supervisor proof of the date of the notification. The operators of the 
adjacent properties have 30 days after receiving the notification to 
provide the Regional Supervisor letters of acceptance or objection. If 
an adjacent operator does not respond within 30 days, the Regional 
Supervisor will presume there are no objections and proceed with a 
decision. The notification must include:
    (1) The well name;
    (2) The rectangular coordinates (x, y) of the location of the top 
and bottom of the completion or target completion referenced to the 
North American Datum 1983, and the subsea depths of the top and bottom 
of the completion or target completion;
    (3) The distance from the completion or target completion to the 
unit or lease line at its nearest point; and

[[Page 220]]

    (4) A statement indicating whether or not it will be a high-capacity 
completion having a perforated or open hole interval greater than 150 
feet measured depth.



Sec. 250.1157  How do I receive approval to produce gas-cap gas from
an oil reservoir with an associated gas cap?

    (a) You must request and receive approval from the Regional 
Supervisor:
    (1) Before producing gas-cap gas from each completion in an oil 
reservoir that is known to have an associated gas cap.
    (2) To continue production from a well if the oil reservoir is not 
initially known to have an associated gas cap, but the oil well begins 
to show characteristics of a gas well.
    (b) For either request, you must submit the service fee listed in 
Sec. 250.125, according to the instructions in Sec. 250.126, and the 
supporting information, as listed in the table in Sec. 250.1167, with 
your request.
    (c) The Regional Supervisor will determine whether your request 
maximizes ultimate recovery.



Sec. 250.1158  How do I receive approval to downhole commingle
hydrocarbons?

    (a) Before you perforate a well, you must request and receive 
approval from the Regional Supervisor to commingle hydrocarbons produced 
from multiple reservoirs within a common wellbore. The Regional 
Supervisor will determine whether your request maximizes ultimate 
recovery. You must include the service fee listed in Sec. 250.125, 
according to the instructions in Sec. 250.126, and the supporting 
information, as listed in the table in Sec. 250.1167, with your request.
    (b) If one or more of the reservoirs proposed for commingling is a 
competitive reservoir, you must notify the operators of all leases that 
contain the reservoir that you intend to downhole commingle the 
reservoirs. Your request for approval of downhole commingling must 
include proof of the date of this notification. The notified operators 
have 30 days after notification to provide the Regional Supervisor with 
letters of acceptance or objection. If the notified operators do not 
respond within the specified period, the Regional Supervisor will assume 
the operators do not object and proceed with a decision.

                            Production Rates



Sec. 250.1159  May the Regional Supervisor limit my well or reservoir
production rates?

    (a) The Regional Supervisor may set a Maximum Production Rate (MPR) 
for a producing well completion, or set a Maximum Efficient Rate (MER) 
for a reservoir, or both, if the Regional Supervisor determines that an 
excessive production rate could harm ultimate recovery. An MPR or MER 
will be based on well tests and any limitations imposed by well and 
surface equipment, sand production, reservoir sensitivity, gas-oil and 
water-oil ratios, location of perforated intervals, and prudent 
operating practices.
    (b) If the Regional Supervisor sets an MPR for a producing well 
completion and/or an MER for a reservoir, you may not exceed those rates 
except due to normal variations and fluctuations in production rates as 
set by the Regional Supervisor.

               Flaring, Venting, and Burning Hydrocarbons



Sec. 250.1160  When may I flare or vent gas?

    (a) You must request and receive approval from the Regional 
Supervisor to flare or vent natural gas at your facility, except in the 
following situations:

------------------------------------------------------------------------
               Condition                     Additional requirements
------------------------------------------------------------------------
(1) When the gas is lease use gas        The volume of gas flared or
 (produced natural gas which is used on   vented may not exceed the
 or for the benefit of lease operations   amount necessary for its
 such as gas used to operate production   intended purpose. Burning
 facilities) or is used as an additive    waste products may require
 necessary to burn waste products, such   approval under other
 as H2S.                                  regulations.
(2) During the restart of a facility     Flaring or venting may not
 that was shut in because of weather      exceed 48 cumulative hours
 conditions, such as a hurricane.         without Regional Supervisor
                                          approval.

[[Page 221]]

 
(3) During the blow down of              (i) You must report the
 transportation pipelines downstream of   location, time, flare/vent
 the royalty meter.                       volume, and reason for flaring/
                                          venting to the Regional
                                          Supervisor in writing within
                                          72 hours after the incident is
                                          over.
                                         (ii) Additional approval may be
                                          required under subparts H and
                                          J of this part.
(4) During the unloading or cleaning of  You may not exceed 48
 a well, drill-stem testing, production   cumulative hours of flaring or
 testing, other well-evaluation           venting per unloading or
 testing, or the necessary blow down to   cleaning or testing operation
 perform these procedures.                on a single completion without
                                          Regional Supervisor approval.
(5) When properly working equipment      You may not flare or vent more
 yields flash gas (natural gas released   than an average of 50 MCF per
 from liquid hydrocarbons as a result     day during any calendar month
 of a decrease in pressure, an increase   without Regional Supervisor
 in temperature, or both) from storage    approval.
 vessels or other low-pressure
 production vessels, and you cannot
 economically recover this flash gas.
(6) When the equipment works properly    (i) For oil-well gas and gas-
 but there is a temporary upset           well flash gas (natural gas
 condition, such as a hydrate or          released from condensate as a
 paraffin plug.                           result of a decrease in
                                          pressure, an increase in
                                          temperature, or both), you may
                                          not exceed 48 continuous hours
                                          of flaring or venting without
                                          Regional Supervisor approval.
                                         (ii) For primary gas-well gas
                                          (natural gas from a gas well
                                          completion that is at or near
                                          its wellhead pressure; this
                                          does not include flash gas),
                                          you may not exceed 2
                                          continuous hours of flaring or
                                          venting without Regional
                                          Supervisor approval.
                                         (iii) You may not exceed 144
                                          cumulative hours of flaring or
                                          venting during a calendar
                                          month without Regional
                                          Supervisor approval.
(7) When equipment fails to work         (i) For oil-well gas and gas-
 properly, during equipment maintenance   well flash gas, you may not
 and repair, or when you must relieve     exceed 48 continuous hours of
 system pressures.                        flaring or venting without
                                          Regional Supervisor approval.
                                         (ii) For primary gas-well gas,
                                          you may not exceed 2
                                          continuous hours of flaring or
                                          venting without Regional
                                          Supervisor approval.
                                         (iii) You may not exceed 144
                                          cumulative hours of flaring or
                                          venting during a calendar
                                          month without Regional
                                          Supervisor approval.
                                         (iv) The continuous and
                                          cumulative hours allowed under
                                          this paragraph may be counted
                                          separately from the hours
                                          under paragraph (a)(6) of this
                                          section.
------------------------------------------------------------------------

    (b) Regardless of the requirements in paragraph (a) of this section, 
you must not flare or vent gas over the volume approved in your 
Development Operations Coordination Document (DOCD) or your Development 
and Production Plan (DPP) submitted to BOEM.
    (c) The Regional Supervisor may establish alternative approval 
procedures to cover situations when you cannot contact the BSEE office, 
such as during non-office hours.
    (d) The Regional Supervisor may specify a volume limit, or a shorter 
time limit than specified elsewhere in this part, in order to prevent 
air quality degradation or loss of reserves.
    (e) If you flare or vent gas without the required approval, or if 
the Regional Supervisor determines that you were negligent or could have 
avoided flaring or venting the gas, the hydrocarbons will be considered 
avoidably lost or wasted. You must pay royalties on the loss or waste, 
according to 30 CFR part 1202. You must value any gas or liquid 
hydrocarbons avoidably lost or wasted under the provisions of 30 CFR 
part 1206.
    (f) Fugitive emissions from valves, fittings, flanges, pressure 
relief valves or similar components do not require approval under this 
subpart unless specifically required by the Regional Supervisor.



Sec. 250.1161  When may I flare or vent gas for extended periods
of time?

    You must request and receive approval from the Regional Supervisor 
to flare or vent gas for an extended period of time. The Regional 
Supervisor will specify the approved period of time, which will not 
exceed 1 year. The Regional Supervisor may deny your request if it does 
not ensure the conservation of natural resources or is not consistent 
with National interests relating to development and production of 
minerals of the OCS. The Regional Supervisor may approve your request 
for one of the following reasons:

[[Page 222]]

    (a) You initiated an action which, when completed, will eliminate 
flaring and venting; or
    (b) You submit to the Regional Supervisor an evaluation supported by 
engineering, geologic, and economic data indicating that the oil and gas 
produced from the well(s) will not economically support the facilities 
necessary to sell the gas or to use the gas on or for the benefit of the 
lease.



Sec. 250.1162  When may I burn produced liquid hydrocarbons?

    (a) You must request and receive approval from the Regional 
Supervisor to burn any produced liquid hydrocarbons. The Regional 
Supervisor may allow you to burn liquid hydrocarbons if you demonstrate 
that transporting them to market or re-injecting them is not technically 
feasible or poses a significant risk of harm to offshore personnel or 
the environment.
    (b) If you burn liquid hydrocarbons without the required approval, 
or if the Regional Supervisor determines that you were negligent or 
could have avoided burning liquid hydrocarbons, the hydrocarbons will be 
considered avoidably lost or wasted. You must pay royalties on the loss 
or waste, according to 30 CFR part 1202. You must value any liquid 
hydrocarbons avoidably lost or wasted under the provisions of 30 CFR 
part 1206.



Sec. 250.1163  How must I measure gas flaring or venting volumes
and liquid hydrocarbon burning volumes, and what records must
I maintain?

    (a) If your facility processes more than an average of 2,000 bopd 
during May 2010, you must install flare/vent meters within 180 days 
after May 2010. If your facility processes more than an average of 2,000 
bopd during a calendar month after May 2010, you must install flare/vent 
meters within 120 days after the end of the month in which the average 
amount of oil processed exceeds 2,000 bopd.
    (1) You must notify the Regional Supervisor when your facility 
begins to process more than an average of 2,000 bopd in a calendar 
month;
    (2) The flare/vent meters must measure all flared and vented gas 
within 5 percent accuracy;
    (3) You must calibrate the meters regularly, in accordance with the 
manufacturer's recommendation, or at least once every year, whichever is 
shorter; and
    (4) You must use and maintain the flare/vent meters for the life of 
the facility.
    (b) You must report all hydrocarbons produced from a well 
completion, including all gas flared, gas vented, and liquid 
hydrocarbons burned, to Office of Natural Resources Revenue on Form 
ONRR-4054 (Oil and Gas Operations Report), in accordance with 30 CFR 
1210.102.
    (1) You must report the amount of gas flared and the amount of gas 
vented separately.
    (2) You may classify and report gas used to operate equipment on the 
lease, such as gas used to power engines, instrument gas, and gas used 
to maintain pilot lights, as lease use gas.
    (3) If flare/vent meters are required at one or more of your 
facilities, you must report the amount of gas flared and vented at each 
of those facilities separately from those facilities that do not require 
meters and separately from other facilities with meters.
    (4) If flare/vent meters are not required at your facility:
    (i) You may report the gas flared and vented on a lease or unit 
basis. Gas flared and vented from multiple facilities on a single lease 
or unit may be reported together.
    (ii) If you choose to install meters, you may report the gas volume 
flared and vented according to the method specified in paragraph (b)(3) 
of this section.
    (c) You must prepare and maintain records detailing gas flaring, gas 
venting, and liquid hydrocarbon burning for each facility for 6 years.
    (1) You must maintain these records on the facility for at least the 
first 2 years and have them available for inspection by BSEE 
representatives.
    (2) After 2 years, you must maintain the records, allow BSEE 
representatives to inspect the records upon request and provide copies 
to the Regional Supervisor upon request, but are not required to keep 
them on the facility.

[[Page 223]]

    (3) The records must include, at a minimum:
    (i) Daily volumes of gas flared, gas vented, and liquid hydrocarbons 
burned;
    (ii) Number of hours of gas flaring, gas venting, and liquid 
hydrocarbon burning, on a daily and monthly cumulative basis;
    (iii) A list of the wells contributing to gas flaring, gas venting, 
and liquid hydrocarbon burning, along with gas-oil ratio data;
    (iv) Reasons for gas flaring, gas venting, and liquid hydrocarbon 
burning; and
    (v) Documentation of all required approvals.
    (d) If your facility is required to have flare/vent meters:
    (1) You must maintain the meter recordings for 6 years.
    (i) You must keep these recordings on the facility for 2 years and 
have them available for inspection by BSEE representatives.
    (ii) After 2 years, you must maintain the recordings, allow BSEE 
representatives to inspect the recordings upon request and provide 
copies to the Regional Supervisor upon request, but are not required to 
keep them on the facility.
    (iii) These recordings must include the begin times, end times, and 
volumes for all flaring and venting incidents.
    (2) You must maintain flare/vent meter calibration and maintenance 
records on the facility for 2 years.
    (e) If your flaring or venting of gas, or burning of liquid 
hydrocarbons, required written or oral approval, you must submit 
documentation to the Regional Supervisor summarizing the location, 
dates, number of hours, and volumes of gas flared, gas vented, and 
liquid hydrocarbons burned under the approval.



Sec. 250.1164  What are the requirements for flaring or venting gas
containing H 2S?

    (a) You may not vent gas containing H2S, except for minor 
releases during maintenance and repair activities that do not result in 
a 15-minute time-weighted average atmosphere concentration of 
H2S of 20 ppm or higher anywhere on the platform.
    (b) You may flare gas containing H2S only if you meet the 
requirements of Secs. 250.1160, 250.1161, 250.1163, and the following 
additional requirements:
    (1) For safety or air pollution prevention purposes, the Regional 
Supervisor may further restrict the flaring of gas containing 
H2S. The Regional Supervisor will use information provided in 
the lessee's H2S Contingency Plan (Sec. 250.490(f)), 
Exploration Plan, DPP, DOCD submitted to BOEM, and associated documents 
to determine the need for restrictions; and
    (2) If the Regional Supervisor determines that flaring at a facility 
or group of facilities may significantly affect the air quality of an 
onshore area, the Regional Supervisor may require you to conduct an air 
quality modeling analysis, under 30 CFR 550.303, to determine the 
potential effect of facility emissions. The Regional Supervisor may 
require monitoring and reporting, or may restrict or prohibit flaring, 
under 30 CFR 550.303 and 30 CFR 550.304.
    (c) The Regional Supervisor may require you to submit monthly 
reports of flared and vented gas containing H2S. Each report 
must contain, on a daily basis:
    (1) The volume and duration of each flaring and venting occurrence;
    (2) H2S concentration in the flared or vented gas; and
    (3) The calculated amount of SO2 emitted.

                           Other Requirements



Sec. 250.1165  What must I do for enhanced recovery operations?

    (a) You must promptly initiate enhanced oil and gas recovery 
operations for all reservoirs where these operations would result in an 
increase in ultimate recovery of oil or gas under sound engineering and 
economic principles.
    (b) Before initiating enhanced recovery operations, you must submit 
a proposed plan to the BSEE Regional Supervisor and receive approval for 
pressure maintenance, secondary or tertiary recovery, cycling, and 
similar recovery operations intended to increase the ultimate recovery 
of oil and gas

[[Page 224]]

from a reservoir. The proposed plan must include, for each project 
reservoir, a geologic and engineering overview and any additional 
information required by the BSEE Regional Supervisor. You also must 
submit Form BOEM-0127 to BOEM along with the supporting data specified 
in BOEM regulations, 30 CFR part 550, subpart K.
    (c) You must report to Office of Natural Resources Revenue the 
volumes of oil, gas, or other substances injected, produced, or produced 
for a second time under 30 CFR 1210.102.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]



Sec. 250.1166  What additional reporting is required for developments
in the Alaska OCS Region?

    (a) For any development in the Alaska OCS Region, you must submit an 
annual reservoir management report to the Regional Supervisor. The 
report must contain information detailing the activities performed 
during the previous year and planned for the upcoming year that will:
    (1) Provide for the prevention of waste;
    (2) Provide for the protection of correlative rights; and
    (3) Maximize ultimate recovery of oil and gas.
    (b) If your development is jointly regulated by BSEE and the State 
of Alaska, BSEE and the Alaska Oil and Gas Conservation Commission will 
jointly determine appropriate reporting requirements to minimize or 
eliminate duplicate reporting requirements.
    (c) [Reserved]



Sec. 250.1167  What information must I submit with forms and for
approvals?

    You must submit the supporting information listed in the following 
table with the form identified in column 1 and for the approvals 
required under this subpart identified in columns 2 through 4:

----------------------------------------------------------------------------------------------------------------
                                                                                                    Production
                                               WPT BSEE-0126       Gas cap          Downhole      within 500-ft
                                                 (2 copies)       production      commingling      of a unit or
                                                                                                    lease line
----------------------------------------------------------------------------------------------------------------
(a) Maps:
    (1) Base map with surface, bottomhole,    ...............                             
     and completion locations with respect
     to the unit or lease line and the
     orientation of representative seismic
     lines or cross-sections................
    (2) Structure maps with penetration                                            
     point and subsea depth for each well
     penetrating the reservoirs,
     highlighting subject wells; reservoir
     boundaries; and original and current
     fluid levels...........................
    (3) Net sand isopach with total net sand  ...............                   
     penetrated for each well, identified at
     the penetration point..................
    (4) Net hydrocarbon isopach with net      ...............                   
     feet of pay for each well, identified
     at the penetration point...............
(b) Seismic data:
    (1) Representative seismic lines,         ...............                             
     including strike and dip lines that
     confirm the structure; indicate
     polarity...............................
    (2) Amplitude extraction of seismic       ...............                             
     horizon, if applicable.................
(c) Logs:
    (1) Well log sections with tops and                                            
     bottoms of the reservoir(s) and
     proposed or existing perforations......
    (2) Structural cross-sections showing     ...............                                   *
     the subject well and nearby wells......
(d) Engineering data:
    (1) Estimated recoverable reserves for    ...............                                         
     each well completion in the reservoir;
     total recoverable reserves for each
     reservoir; method of calculation;
     reservoir parameters used in volumetric
     and decline curve analysis.............
    (2) Well schematics showing current and   ...............                             
     proposed conditions....................
    (3) The drive mechanism of each           ...............                             
     reservoir..............................
    (4) Pressure data, by date, and whether   ...............                   
     they are estimated or measured.........

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    (5) Production data and decline curve     ...............                   
     analysis indicative of the reservoir
     performance............................
    (6) Reservoir simulation with the         ...............               *                *                *
     reservoir parameters used, history
     matches, and prediction runs (include
     proposed development scenario).........
(e) General information:
    (1) Detailed economic analysis..........  ...............               *                *
    (2) Reservoir name and whether or not it  ...............                             
     is competitive as defined under Sec.
     250.105................................
    (3) Operator name, lessee name(s),        ...............                             
     block, lease number, royalty rate, and
     unit number (if applicable) of all
     relevant leases........................
    (4) Geologic overview of project........  ...............                             
    (5) Explanation of why the proposed       ...............                             
     completion scenario will maximize
     ultimate recovery......................
    (6) List of all wells in subject          ...............                             
     reservoirs that have ever produced or
     been used for injection................
----------------------------------------------------------------------------------------------------------------
 Required.
 Each Gas Cap Production request and Downhole Commingling request must include the estimated recoverable
  reserves for (1) the case where your proposed production scenario is approved, and (2) the case where your
  proposed production scenario is denied.
* Additional items the Regional Supervisor may request.
Note: All maps must be at a standard scale and show lease and unit lines. The Regional Supervisor may waive
  submittal of some of the required data on a case-by-case basis.

    (f) Depending on the type of approval requested, you must submit the 
appropriate payment of the service fee(s) listed in Sec. 250.125, 
according to the instructions in Sec. 250.126.



 Subpart L_Oil and Gas Production Measurement, Surface Commingling, and 
                                Security



Sec. 250.1200  Question index table.

    The table in this section lists questions concerning Oil and Gas 
Production Measurement, Surface Commingling, and Security.

------------------------------------------------------------------------
            Frequently asked questions                  CFR citation
------------------------------------------------------------------------
1. What are the requirements for measuring liquid   Sec. 250.1202(a)
 hydrocarbons?
2. What are the requirements for liquid             Sec. 250.1202(b)
 hydrocarbon royalty meters?
3. What are the requirements for run tickets?       Sec. 250.1202(c)
4. What are the requirements for liquid             Sec. 250.1202(d)
 hydrocarbon royalty meter provings?
5. What are the requirements for calibrating a      Sec. 250.1202(e)
 master meter used in royalty meter provings?
6. What are the requirements for calibrating        Sec. 250.1202(f)
 mechanical-displacement provers and tank provers?
7. What correction factors must a lessee use when   Sec. 250.1202(g)
 proving meters with a mechanical displacement
 prover, tank prover, or master meter?
8. What are the requirements for establishing and   Sec. 250.1202(h)
 applying operating meter factors for liquid
 hydrocarbons?
9. Under what circumstances does a liquid           Sec. 250.1202(i)
 hydrocarbon royalty meter need to be taken out of
 service, and what must a lessee do?
10. How must a lessee correct gross liquid          Sec. 250.1202(j)
 hydrocarbon volumes to standard conditions?
11. What are the requirements for liquid            Sec. 250.1202(k)
 hydrocarbon allocation meters?
12. What are the requirements for royalty and       Sec. 250.1202(l)
 inventory tank facilities?
13. To which meters do BSEE requirements for gas    Sec. 250.1203(a)
 measurement apply?
14. What are the requirements for measuring gas?    Sec. 250.1203(b)
15. What are the requirements for gas meter         Sec. 250.1203(c)
 calibrations?
16. What must a lessee do if a gas meter is out of  Sec. 250.1203(d)
 calibration or malfunctioning?
17. What are the requirements when natural gas      Sec. 250.1203(e)
 from a Federal lease is transferred to a gas
 plant before royalty determination?
18. What are the requirements for measuring gas     Sec. 250.1203(f)
 lost or used on a lease?
19. What are the requirements for the surface       Sec. 250.1204(a)
 commingling of production?
20. What are the requirements for a periodic well   Sec. 250.1204(b)
 test used for allocation?
21. What are the requirements for site security?    Sec. 250.1205(a)
22. What are the requirements for using seals?      Sec. 250.1205(b)
------------------------------------------------------------------------


[[Page 226]]



Sec. 250.1201  Definitions.

    Terms not defined in this section have the meanings given in the 
applicable chapter of the API MPMS, which is incorporated by reference 
in Sec. 250.198. Terms used in Subpart L have the following meaning:
    Allocation meter--a meter used to determine the portion of 
hydrocarbons attributable to one or more platforms, leases, units, or 
wells, in relation to the total production from a royalty or allocation 
measurement point.
    API MPMS--the American Petroleum Institute's Manual of Petroleum 
Measurement Standards, chapters 1, 20, and 21.
    British Thermal Unit (Btu)--the amount of heat needed to raise the 
temperature of one pound of water from 59.5 degrees Fahrenheit (59.5 F) 
to 60.5 degrees Fahrenheit (60.5 F) at standard pressure base (14.73 
pounds per square inch absolute (psia)).
    Compositional Analysis--separating mixtures into identifiable 
components expressed in mole percent.
    Force majeure event--an event beyond your control such as war, act 
of terrorism, crime, or act of nature which prevents you from operating 
the wells and meters on your OCS facility.
    Gas lost--gas that is neither sold nor used on the lease or unit nor 
used internally by the producer.
    Gas processing plant--an installation that uses any process designed 
to remove elements or compounds (hydrocarbon and non-hydrocarbon) from 
gas, including absorption, adsorption, or refrigeration. Processing does 
not include treatment operations, including those necessary to put gas 
into marketable conditions such as natural pressure reduction, 
mechanical separation, heating, cooling, dehydration, desulphurization, 
and compression. The changing of pressures or temperatures in a 
reservoir is not processing.
    Gas processing plant statement--a monthly statement showing the 
volume and quality of the inlet or field gas stream and the plant 
products recovered during the period, volume of plant fuel, flare and 
shrinkage, and the allocation of these volumes to the sources of the 
inlet stream.
    Gas royalty meter malfunction--an error in any component of the gas 
measurement system which exceeds contractual tolerances.
    Gas volume statement--a monthly statement showing gas measurement 
data, including the volume (Mcf) and quality (Btu) of natural gas which 
flowed through a meter.
    Inventory tank--a tank in which liquid hydrocarbons are stored prior 
to royalty measurement. The measured volumes are used in the allocation 
process.
    Liquid hydrocarbons (free liquids)--hydrocarbons which exist in 
liquid form at standard conditions after passing through separating 
facilities.
    Malfunction factor--a liquid hydrocarbon royalty meter factor that 
differs from the previous meter factor by an amount greater than 0.0025.
    Natural gas--a highly compressible, highly expandable mixture of 
hydrocarbons which occurs naturally in a gaseous form and passes a meter 
in vapor phase.
    Operating meter--a royalty or allocation meter that is used for gas 
or liquid hydrocarbon measurement for any period during a calibration 
cycle.
    Pipeline (retrograde) condensate--liquid hydrocarbons which drop out 
of the separated gas stream at any point in a pipeline during 
transmission to shore.
    Pressure base--the pressure at which gas volumes and quality are 
reported. The standard pressure base is 14.73 psia.
    Prove--to determine (as in meter proving) the relationship between 
the volume passing through a meter at one set of conditions and the 
indicated volume at those same conditions.
    Royalty meter--a meter approved for the purpose of determining the 
volume of gas, oil, or other components removed, saved, or sold from a 
Federal lease.
    Royalty tank--an approved tank in which liquid hydrocarbons are 
measured and upon which royalty volumes are based.
    Run ticket--the invoice for liquid hydrocarbons measured at a 
royalty point.
    Sales meter--a meter at which custody transfer takes place (not 
necessarily a royalty meter).
    Seal--a device or approved method used to prevent tampering with 
royalty measurement components.

[[Page 227]]

    Standard conditions--atmospheric pressure of 14.73 pounds per square 
inch absolute (psia) and 60 F.
    Surface commingling--the surface mixing of production from two or 
more leases and/or unit participating areas prior to royalty 
measurement.
    Temperature base--the temperature at which gas and liquid 
hydrocarbon volumes and quality are reported. The standard temperature 
base is 60 F.
    Verification/Calibration--testing and correcting, if necessary, a 
measuring device to ensure compliance with industry accepted, 
manufacturer's recommended, or regulatory required standard of accuracy.
    You or your--the lessee or the operator or other lessees' 
representative engaged in operations in the Outer Continental Shelf 
(OCS).



Sec. 250.1202  Liquid hydrocarbon measurement.

    (a) What are the requirements for measuring liquid hydrocarbons? You 
must:
    (1) Submit a written application to, and obtain approval from, the 
Regional Supervisor before commencing liquid hydrocarbon production, or 
making any changes to the previously-approved measurement and/or 
allocation procedures. Your application (which may also include any 
relevant gas measurement and surface commingling requests) must be 
accompanied by payment of the service fee listed in Sec. 250.125. The 
service fees are divided into two levels based on complexity as shown in 
the following table.

------------------------------------------------------------------------
      Application type                          Actions
------------------------------------------------------------------------
(i) Simple applications,      Applications to temporarily reroute
                               production (for a duration not to exceed
                               six months); Production tests prior to
                               pipeline construction; Departures related
                               to meter proving, well testing, or
                               sampling frequency.
(ii) Complex applications,    Creation of new facility measurement
                               points (FMPs); Association of leases or
                               units with existing FMPs; Inclusion of
                               production from additional structures;
                               Meter updates which add buy-back gas
                               meters or pigging meters; Other
                               applications which request deviations
                               from the approved allocation procedures.
------------------------------------------------------------------------

    (2) Use measurement equipment and procedures that will accurately 
measure the liquid hydrocarbons produced from a lease or unit to comply 
with the following additional API MPMS industry standards or API RP:
    (i) API MPMS, Chapter 4, Section 8 (incorporated by reference as 
specified in Sec. 250.198);
    (ii) API MPMS, Chapter 5, Section 6 (incorporated by reference as 
specified in Sec. 250.198);
    (iii) API MPMS, Chapter 5, Section 8 (incorporated by reference as 
specified in Sec. 250.198);
    (iv) API MPMS, Chapter 11, Section 1 (incorporated by reference as 
specified in Sec. 250.198);
    (v) API MPMS Chapter 12, Section 2, Part 3 (incorporated by 
reference as specified in Sec. 250.198);
    (vi) API MPMS Chapter 12, Section 2, Part 4 (incorporated by 
reference as specified in Sec. 250.198);
    (vii) API MPMS, Chapter 21, Section 2 (incorporated by reference as 
specified in Sec. 250.198);
    (viii) API MPMS, Chapter 21, Addendum to Section 2 (incorporated by 
reference as specified in Sec. 250.198);
    (ix) API RP 86 (incorporated by reference as specified in 
Sec. 250.198);
    (3) Use procedures and correction factors according to the 
applicable chapters of the API MPMS or RP as incorporated by reference 
in 30 CFR 250.198, including the following additional editions:
    (i) API MPMS, Chapter 4, Section 8 (incorporated by reference as 
specified in Sec. 250.198);
    (ii) API MPMS, Chapter 5, Section 6 (incorporated by reference as 
specified in Sec. 250.198);
    (iii) API MPMS, Chapter 5, Section 8 (incorporated by reference as 
specified in Sec. 250.198);
    (iv) API MPMS Chapter 11, Section 1 (incorporated by reference as 
specified in Sec. 250.198);
    (v) API MPMS Chapter 12, Section 2, Part 3 (incorporated by 
reference as specified in Sec. 250.198);

[[Page 228]]

    (vi) API MPMS Chapter 12, Section 2, Part 4 (incorporated by 
reference as specified in Sec. 250.198);
    (vii) API RP 86 (incorporated by reference as specified in 
Sec. 250.198); when obtaining net standard volume and associated 
measurement parameters; and
    (4) When requested by the Regional Supervisor, provide the pipeline 
(retrograde) condensate volumes as allocated to the individual leases or 
units.
    (b) What are the requirements for liquid hydrocarbon royalty meters? 
You must:
    (1) Ensure that the royalty meter facilities include the following 
approved components (or other BSEE-approved components) which must be 
compatible with their connected systems:
    (i) A meter equipped with a nonreset totalizer;
    (ii) A calibrated mechanical displacement (pipe) prover, master 
meter, or tank prover;
    (iii) A proportional-to-flow sampling device pulsed by the meter 
output;
    (iv) A temperature measurement or temperature compensation device; 
and
    (v) A sediment and water monitor with a probe located upstream of 
the divert valve.
    (2) Ensure that the royalty meter facilities accomplish the 
following:
    (i) Prevent flow reversal through the meter;
    (ii) Protect meters subjected to pressure pulsations or surges;
    (iii) Prevent the meter from being subjected to shock pressures 
greater than the maximum working pressure; and
    (iv) Prevent meter bypassing.
    (3) Maintain royalty meter facilities to ensure the following:
    (i) Meters operate within the gravity range specified by the 
manufacturer;
    (ii) Meters operate within the manufacturer's specifications for 
maximum and minimum flow rate for linear accuracy; and
    (iii) Meters are reproven when changes in metering conditions affect 
the meters' performance such as changes in pressure, temperature, 
density (water content), viscosity, pressure, and flow rate.
    (4) Ensure that sampling devices conform to the following:
    (i) The sampling point is in the flowstream immediately upstream or 
downstream of the meter or divert valve in accordance with the API MPMS 
(as incorporated by reference in Sec. 250.198);
    (ii) The sample container is vapor-tight and includes a power mixing 
device to allow complete mixing of the sample before removal from the 
container; and
    (iii) The sample probe is in the center half of the pipe diameter in 
a vertical run and is located at least three pipe diameters downstream 
of any pipe fitting within a region of turbulent flow. The sample probe 
can be located in a horizontal pipe if adequate stream conditioning such 
as power mixers or static mixers are installed upstream of the probe 
according to the manufacturer's instructions.
    (c) What are the requirements for run tickets? You must:
    (1) For royalty met