[Title 30 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2013 Edition]
[From the U.S. Government Printing Office]



[[Page i]]

          

          Title 30

Mineral Resources


________________________

Parts 200 to 699

                         Revised as of July 1, 2013

          Containing a codification of documents of general 
          applicability and future effect

          As of July 1, 2013
                    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                                                 291
          Chapter V--Bureau of Ocean Energy Management, 
          Department of the Interior                               303
  Finding Aids:
      Table of CFR Titles and Chapters........................     573
      Alphabetical List of Agencies Appearing in the CFR......     593
      List of CFR Sections Affected...........................     603

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

                     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 
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into 50 titles which represent broad areas subject to Federal 
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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 
noticed (44 U.S.C. 1507). The Code of Federal Regulations is prima facie 
evidence of the text of the original documents (44 U.S.C. 1510).

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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    Charles A. Barth,
    Director,
    Office of the Federal Register.
    July 1, 2013.







[[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, 2013.

    For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of 
Michael L. White, assisted by Ann Worley.


[[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
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...................................         245
252             Outer Continental Shelf (OCS) Oil and Gas 
                    Information Program.....................         250
253             [Reserved]

254             Oil-spill response requirements for 
                    facilities located seaward of the coast 
                    line....................................         255
256             Leasing of sulphur or oil and gas in the 
                    Outer Continental Shelf.................         268
259-260         [Reserved]

270             Nondiscrimination in the Outer Continental 
                    Shelf...................................         270
280             Prospecting for minerals other than oil, 
                    gas, and sulphur on the Outer 
                    Continental Shelf.......................         272
281             [Reserved]

282             Operations in the Outer Continental Shelf 
                    for minerals other than oil, gas, and 
                    sulphur.................................         272
285             [Reserved]

                          SUBCHAPTER C--APPEALS
290             Appeal procedures...........................         284
291             Open and nondiscriminatory access to oil and 
                    gas pipelines under the Outer 
                    Continental Shelf Lands Act.............         285

[[Page 5]]



                SUBCHAPTER A_MINERALS REVENUE MANAGEMENT



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?
203.69 If my application is approved, what royalty relief will I 
          receive?
203.70 What information must I provide after BSEE approves relief?

[[Page 6]]

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.
    Complete application means an original and two copies of the six 
reports consisting of the data specified in Sec. Sec. 203.81, 203.83, 
and 203.85 through

[[Page 7]]

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 Sec. Sec. 203.30 through 203.36 
or Sec. Sec. 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 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

[[Page 8]]

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 Sec. Sec. 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 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

[[Page 9]]

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.
    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

[[Page 10]]

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 Sec. Sec.
                                            rate,                                       203.50 through 203.56).
(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 Sec. Sec.  203.60
                                                                                      through 203.79).

[[Page 11]]

 
(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 Sec. Sec.
                                                                                      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 Sec.
                                                                                       Sec.  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 Sec. Sec.
                                                                                        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 Sec. Sec.
                                                                                      .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 Sec.
                                            lease is not enough to make development    Sec.  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 Pay.gov 
Web site and you must include a copy of the Pay.gov confirmation receipt 
page with your application or assessment. The Pay.gov Web site may be 
accessed through a link on the BSEE Offshore Web site at: http://
www.bsee.gov/offshore/ homepage or directly through Pay.gov at: https://
www.pay.gov/paygov/.



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 Sec. Sec. 203.50 to 203.91. Because royalty 
relief for deep gas on leases not subject to deep water royalty relief, 
as provided for under Sec. Sec. 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.
    (a) We require the information elements indicated by an X in the 
following table and described in Sec. Sec. 203.51, 203.62, and 203.81 
through 203.89 for applications for royalty relief.

[[Page 12]]



----------------------------------------------------------------------------------------------------------------
                                                                                       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 Sec. Sec. 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 Sec. Sec. 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 Sec. Sec. 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.......................
----------------------------------------------------------------------------------------------------------------

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

[[Page 13]]



----------------------------------------------------------------------------------------------------------------
                                                                                       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 Sec. Sec. 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 Sec. Sec. 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 1010-0071. 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 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

[[Page 14]]

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, 381 Elden Street, Herndon, VA 
20170.



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

[[Page 15]]



------------------------------------------------------------------------
                                         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), 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

[[Page 16]]

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 Sec. Sec. 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 Sec. Sec. 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.



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.

[[Page 17]]

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:
    (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

[[Page 18]]

    (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.
(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;

[[Page 19]]

 
                                         (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. 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-

[[Page 20]]

deep well (see definition in Sec. 203.0), and would earn the lease an 
RSV of 35 BCF under Sec. Sec. 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 Sec. Sec. 203.41 through 
203.44, and may receive an RSS under Sec. Sec. 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 Sec. Sec. 203.41 through 203.47. (Note: Because 
the original Sec. 203.41 has been divided into new Sec. Sec. 203.41 
and 203.42 and subsequent sections have been redesignated as Sec. Sec. 
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 Sec. Sec. 
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 Sec. Sec. 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.

------------------------------------------------------------------------
                               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,
------------------------------------------------------------------------


[[Page 21]]

    (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 Sec. Sec. 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 Sec. Sec. 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 Sec. Sec. 203.43 and 203.48, even 
though 4 BCF plus 600 MCF per foot of sidetrack measured 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

[[Page 22]]

gas production from qualified wells on your lease, as prescribed in 
Sec. Sec. 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 
Sec. Sec. 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 Sec. Sec. 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)]{time}  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 Sec. Sec. 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
 the top of which is 18,000 feet TVD SS or   a 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.
(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.

[[Page 23]]



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 Sec. Sec. 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 Sec. Sec. 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 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

[[Page 24]]

    (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
    (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.

[[Page 25]]

    (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 Sec. Sec. 203.31 
through 203.33 and Sec. Sec. 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 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.

[[Page 26]]

    (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 Sec. Sec. 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.
    (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.

[[Page 27]]

    (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 Sec. Sec. 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 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.

[[Page 28]]



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 Sec. Sec. 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 
Sec. Sec. 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 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

[[Page 29]]

    (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 Sec. Sec. 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.
    (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.

[[Page 30]]



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 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.

[[Page 31]]



------------------------------------------------------------------------
                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 Sec. Sec.
                               suspension volumes     203.70 and 203.76.
                               specified in Sec.
                               203.69,
(b) An expansion project,     You get a royalty     Abide by Sec. Sec.
                               suspension for the     203.70 and 203.76.
                               first year of
                               production,
(c) A development project,    You get a royalty     Abide by Sec. Sec.
                               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 Sec. Sec. 203.40 through 203.49 or ultra-deep gas royalty relief 
under Sec. Sec. 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 Sec. Sec. 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 Sec. Sec. 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 Sec. Sec. 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, 381 Elden Street, Herndon, VA 
20170.



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 specify in the RSVP. You may provide supplemental 
information, including

[[Page 40]]

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 
(Sec. Sec. 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;
    (3) Maps indicating well surface and bottom hole locations, location 
of development facilities, and shot points; and

[[Page 41]]

    (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 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

[[Page 42]]

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 existed on the application submission date).

[[Page 43]]



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 and operate electrical equipment?
250.115-250.117 [Reserved]
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?

      Primary Lease Requirements, Lease Term Extensions, and Lease 
                              Cancellations

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

[[Page 45]]

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 Who is subject to the requirements of this subpart?
250.401 What must I do to keep wells under control?
250.402 When and how must I secure a well?
250.403 What drilling unit movements must I report?
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 What additional safety measures must I take when I conduct 
          drilling operations on a platform that has producing wells or 
          has other hydrocarbon flow?
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 and BOP descriptions?
250.417 What must I provide if I plan to use a mobile offshore drilling 
          unit (MODU)?
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?

[[Page 46]]

250.423 What are the requirements for pressure testing casing?
250.424 What are the requirements for prolonged drilling operations?
250.425 What are the requirements for pressure testing liners?
250.426 What are the recordkeeping requirements for casing and liner 
          pressure tests?
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?

               Blowout Preventer (BOP) System Requirements

250.440 What are the general requirements for BOP systems and system 
          components?
250.441 What are the requirements for a surface BOP stack?
250.442 What are the requirements for a subsea BOP system?
250.443 What associated systems and related equipment must all BOP 
          systems include?
250.444 What are the choke manifold requirements?
250.445 What are the requirements for kelly valves, inside BOPs, and 
          drill-string safety valves?
250.446 What are the BOP maintenance and inspection requirements?
250.447 When must I pressure test the BOP system?
250.448 What are the BOP pressure tests requirements?
250.449 What additional BOP testing requirements must I meet?
250.450 What are the recordkeeping requirements for BOP tests?
250.451 What must I do in certain situations involving BOP equipment or 
          systems?

                       Drilling Fluid Requirements

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 What records must I keep?
250.467 How long must I keep records?
250.468 What well records am I required to submit?
250.469 What other well records could I be required to submit?

                            Hydrogen Sulfide

250.490 Hydrogen sulfide.

            Subpart E_Oil and Gas Well-Completion Operations

250.500 General requirements.
250.501 Definition.
250.502 Equipment movement.
250.503 Emergency shutdown system.
250.504 Hydrogen sulfide.
250.505 Subsea completions.
250.506 Crew instructions.
250.507-250.508 [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 What BOP information must I submit?
250.516 Blowout prevention equipment.
250.517 Blowout preventer system tests, inspections, and maintenance.
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?

[[Page 47]]

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 Equipment movement.
250.603 Emergency shutdown system.
250.604 Hydrogen sulfide.
250.605 Subsea workovers.
250.606 Crew instructions.
250.607-250.608 [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.
250.613 Approval and reporting for well-workover operations.
250.614 Well-control fluids, equipment, and operations.
250.615 What BOP information must I submit?
250.616 Blowout prevention equipment.
250.617 Blowout preventer system testing, records, and drills.
250.618 What are my BOP inspection and maintenance requirements?
250.619 Tubing and wellhead equipment.
250.620 Wireline operations.

Subpart G [Reserved]

             Subpart H_Oil and Gas Production Safety Systems

250.800 General requirements.
250.801 Subsurface safety devices.
250.802 Design, installation, and operation of surface production-safety 
          systems.
250.803 Additional production system requirements.
250.804 Production safety-system testing and records.
250.805 Safety device training.
250.806 Safety and pollution prevention equipment quality assurance 
          requirements.
250.807 Additional requirements for subsurface safety valves and related 
          equipment installed in high pressure high temperature (HPHT) 
          environments.
250.808 Hydrogen sulfide.

                   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?
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.

[[Page 48]]

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.

                          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 Index table.
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?

[[Page 49]]

 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?

                          Bonding Requirements

250.1490 What standards must my BOEM-specified surety instrument meet?
250.1491 How will BOEM determine the amount of my bond or other surety 
          instrument?

                     Financial Solvency Requirements

250.1495 How do I demonstrate financial solvency?
250.1496 How will BOEM determine if I am financially solvent?
250.1497 When will BOEM monitor my financial solvency?

          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.
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.

[[Page 50]]

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 When must I submit decommissioning applications and reports?
250.1705 What BOP information must I submit?
250.1706 What are the requirements for blowout prevention equipment?
250.1707 What are the requirements for blowout preventer system testing, 
          records, and drills?
250.1708 What are my BOP inspection and maintenance requirements?
250.1709 What are my well-control fluid requirements?

                       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 After I permanently plug a well, what information must I 
          submit?

                        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?
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]

[[Page 51]]

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, 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.

       Table--Where To Find Information for Conducting Operations
------------------------------------------------------------------------
        For information about . . .                Refer to . . .
------------------------------------------------------------------------
(1) Applications for permit to drill,       30 CFR 250, subpart D.
(2) Development and Production Plans        30 CFR 550, subpart B.
 (DPP),
(3) Downhole commingling,                   30 CFR 250, subpart K.

[[Page 52]]

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



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 of physical and chemical properties,

[[Page 53]]

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.
    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.
    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 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.
    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

[[Page 54]]

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.
    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 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

[[Page 55]]

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 Sec. Sec. 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 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

[[Page 56]]

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 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

[[Page 57]]

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 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.
    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;

[[Page 58]]

    (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.
    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]

                          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; and
    (2) Maintaining all equipment and work areas in a safe condition.
    (b) You must immediately control, remove, or otherwise correct any 
hazardous oil and gas accumulation or other health, safety, or fire 
hazard.
    (c) You must use the best available and safest technology (BAST) 
whenever practical on all exploration, development, and production 
operations. In general, we consider your compliance with BSEE 
regulations to be the use of BAST.
    (d) The Director may require additional measures to ensure the use 
of BAST:
    (1) To avoid the failure of equipment that would have a significant 
effect on safety, health, or the environment;
    (2) If it is economically feasible; and
    (3) If the benefits outweigh the costs.



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).
    (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

[[Page 59]]

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 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.

[[Page 60]]

    (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 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, 
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.



Sec. Sec. 250.115-250.117  [Reserved]



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 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:

[[Page 61]]

    (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) [Reserved]
(2) [Reserved]
(3) Suspension of Operations/     $1,968............  Sec.  250.171(e).
 Suspension of Production (SOO/
 SOP) Request.
(4) [Reserved]
(5) [Reserved]
(6) Deepwater Operations Plan...  $3,336............  Sec.  250.292(p).
(7) [Reserved]
(8) Application for Permit to     $1,959 for initial  Sec.  250.410(d);
 Drill (APD; Form BSEE-0123).      applications        Sec.
                                   only; no fee for    250.513(b); Sec.
                                   revisions.           250.1617(a).
(9) Application for Permit to     $116..............  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 62]]

 
(10) New Facility Production      $5,030 A component  Sec.  250.802(e).
 Safety System Application for     is a piece of
 facility with more than 125       equipment or
 components.                       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);
                                   $13,238
                                   additional fee
                                   will be charged
                                   if BSEE deems it
                                   necessary to
                                   visit a facility
                                   offshore, and
                                   $6,884 to visit a
                                   facility in a
                                   shipyard.
(11) New Facility Production      $1,218 Additional   Sec.  250.802(e).
 Safety System Application for     fee of $8,313
 facility with 25-125 components.  will be charged
                                   if BSEE deems it
                                   necessary to
                                   visit a facility
                                   offshore, and
                                   $4,766 to visit a
                                   facility in a
                                   shipyard.
(12) New Facility Production      $604..............  Sec.  250.802(e).
 Safety System Application for
 facility with fewer than 25
 components.
(13) Production Safety System     $561..............  Sec.  250.802(e).
 Application--Modification with
 more than 125 components
 reviewed.
(14) Production Safety System     $201..............  Sec.  250.802(e).
 Application--Modification with
 25-125 components reviewed.
(15) Production Safety System     $85...............  Sec.  250.802(e).
 Application--Modification with
 fewer than 25 components
 reviewed.
(16) Platform Application--       $21,075...........  Sec.  250.905(l).
 Installation--Under the
 Platform Verification Program.
(17) Platform Application--       $3,018............  Sec.  250.905(l).
 Installation--Fixed Structure
 Under the Platform Approval
 Program.
(18) Platform Application--       $1,536............  Sec.  250.905(l)
 Installation--Caisson/Well
 Protector.
(19) Platform Application--       $3,601............  Sec.  250.905(l).
 Modification/Repair.
(20) New Pipeline Application     $3,283............  Sec.
 (Lease Term).                                         250.1000(b).
(21) Pipeline Application--       $1,906............  Sec.
 Modification (Lease Term).                            250.1000(b).
(22) Pipeline Application--       $3,865............  Sec.
 Modification (ROW).                                   250.1000(b).
(23) Pipeline Repair              $360..............  Sec.
 Notification.                                         250.1008(e).
(24) Pipeline Right-of-Way (ROW)  $2,569............  Sec.
 Grant Application.                                    250.1015(a).
(25) Pipeline Conversion of       $219..............  Sec.
 Lease Term to ROW.                                    250.1015(a).
(26) Pipeline ROW Assignment....  $186..............  Sec.
                                                       250.1018(b).
(27) 500 Feet From Lease/Unit     $3,608............  Sec.
 Line Production Request.                              250.1156(a).
(28) Gas Cap Production Request.  $4,592............  Sec.  250.1157.
(29) Downhole Commingling         $5,357............  Sec.
 Request.                                              250.1158(a).
(30) Complex Surface Commingling  $3,760............  Sec.
 and Measurement Application.                          250.1202(a); Sec.
                                                         250.1203(b);
                                                       Sec.
                                                       250.1204(a).
(31) Simple Surface Commingling   $1,271............  Sec.
 and Measurement Application.                          250.1202(a); Sec.
                                                         250.1203(b);
                                                       Sec.
                                                       250.1204(a).
(32) Voluntary Unitization        $11,698...........  Sec.
 Proposal or Unit Expansion.                           250.1303(d).
(33) Unitization Revision.......  $831..............  Sec.
                                                       250.1303(d).
(34) Application to Remove a      $4,342............  Sec.  250.1727.
 Platform or Other Facility.
(35) Application to Decommission  $1,059............  Sec.  250.1751(a)
 a Pipeline (Lease Term).                              or Sec.
                                                       250.1752(a).
(36) Application to Decommission  $2,012............  Sec.  250.1751(a)
 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]

[[Page 63]]



Sec. 250.126  Electronic payment instructions.

    You must file all payments electronically through Pay.gov. This 
includes, but is not limited to, all OCS applications or filing fee 
payments. The Pay.gov Web site may be accessed through a link on the 
BSEE Offshore Web site at: http://www.bsee.gov/offshore/ homepage or 
directly through Pay.gov at: https://www.pay.gov/paygov/.
    (a) If you submitted an application through eWell, you must use the 
interactive payment feature in that system, which directs you through 
Pay.gov.
    (b) For applications not submitted electronically through eWell, you 
must use credit card or automated clearing house (ACH) payments through 
the Pay.gov Web site, and you must include a copy of the Pay.gov 
confirmation receipt page with your application.

                        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.



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.

[[Page 64]]

                       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.



Sec. Sec. 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 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.

[[Page 65]]

  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.



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.

[[Page 66]]

    (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.



Sec. Sec. 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 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 180-day 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.



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;

[[Page 67]]

    (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;
    (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

[[Page 68]]

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
    (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 180 days of the 
primary term, and whenever production resumes during the last 180 days 
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 180 days 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

[[Page 69]]

end of the 180th day 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 180th day after you stop operations.
    (e) You may ask the Regional Supervisor to allow you more than 180 
days 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 180-day period 
after having ceased, or whenever drilling or well-reworking operations 
begin before the end of the 180-day 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 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 180-day period.



Sec. Sec. 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

[[Page 70]]

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 Sec. Sec. 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 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.



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;

[[Page 71]]

    (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.);
    (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

[[Page 72]]

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).
    (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, 
Herndon, VA 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

[[Page 73]]

    (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]



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);
    (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:

[[Page 74]]



------------------------------------------------------------------------
                              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]
(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.

[[Page 75]]

 
(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
                                       Sec. Sec.        adjacent lease
                                       250.197(b)(5)      according to
                                       and (b)(6),        Subpart D of
                                       whichever occurs   this part.
                                       earlier,
(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

[[Page 76]]

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 Sec. Sec. 250.141 and 250.142, you may comply with a 
later edition of a 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, 381 Elden Street, Room 3313, Herndon, 
Virginia 20170; phone: 703-787-1587; 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, P. O. Box 
9094, Farmington Hill, MI 48333-9094: 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, 
ATTN: Sales Department, 25 West 43rd Street, 4th Floor, New York, NY 
10036; http://www.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: 973-882-5155:
    (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 Sec. Sec. 250.803 and 250.1629;

[[Page 77]]

    (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 Sec. Sec. 250.803 and 250.1629;
    (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 and 2, and all Section VIII 
Interpretations Volumes 54 and 55, incorporated by reference at 
Sec. Sec. 250.803 and 250.1629;
    (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/ASME SPPE-1-1994, Quality Assurance and Certification of 
Safety and Pollution Prevention Equipment Used in Offshore Oil and Gas 
Operations, incorporated by reference at Sec. 250.806;
    (7) ANSI/ASME SPPE-1d-1996 Addenda, Quality Assurance and 
Certification of Safety and Pollution Prevention Equipment Used in 
Offshore Oil and Gas Operations, incorporated by reference at Sec. 
250.806;
    (8) 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 Sec. Sec. 250.803 and 250.1629;
    (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;
    (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

[[Page 78]]

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 
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,

[[Page 79]]

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 [deg]F, and Table 6A--Generalized Crude 
Oils and JP-4 Correction of Volume to 60 [deg]F Against API Gravity at 
60 [deg]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 [deg]F/60 [deg]F) and -50 
[deg]F to 140 [deg]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;
    (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 Sec. Sec. 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;

[[Page 80]]

    (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 Sec. Sec. 250.800; 250.901 and 250.1002;
    (52) API RP 2SK, Design and Analysis of Stationkeeping Systems for 
Floating Structures, Third Edition, October 2005, Addendum, May 2008; 
incorporated by reference at Sec. Sec. 250.800 and 250.901;
    (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 Sec. 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) API RP 14B, Recommended Practice for Design, Installation, 
Repair and Operation of Subsurface Safety Valve Systems, Fifth Edition, 
October 2005, also available as ISO 10417: 2004, (Identical) Petroleum 
and natural gas industries--Subsurface safety valve systems--Design, 
installation, operation and redress; incorporated by reference at 
Sec. Sec. 250.801 and 250.804;
    (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 Sec. Sec. 250.125, 250.292, 250.802, 
250.803, 250.804, 250.1002, 250.1004, 250.1628, 250.1629, and 250.1630;
    (57) API RP 14E, Recommended Practice for Design and Installation of 
Offshore Production Platform Piping Systems, Fifth Edition, October 
1991; reaffirmed, March 2007; incorporated by reference at Sec. Sec. 
250.802 and 250.1628;
    (58) API RP 14F, Design, Installation, and Maintenance of Electrical 
Systems for Fixed and Floating Offshore Petroleum Facilities for 
Unclassified and Class I, Division 1 and Division 2 Locations, Fifth 
Edition, July 2008; incorporated by reference at Sec. Sec. 250.114, 
250.803, and 250.1629;
    (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 Sec. Sec. 250.114, 250.803, and 250.1629;
    (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 Sec. Sec. 250.803 and 
250.1629;
    (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 
Sec. Sec. 250.802 and 250.804;
    (62) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, Second Edition, May 2001; 
reaffirmed: March 2007; incorporated by reference at Sec. Sec. 250.800 
and 250.901;
    (63) API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells, Third Edition, March 1997; 
reaffirmed September 2004; incorporated by reference at Sec. Sec. 
250.442, 250.446, 250.517, 250.618, and 250.1708;
    (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; reaffirmed November 2002; incorporated by reference at 
Sec. Sec. 250.114, 250.459, 250.802, 250.803, 250.1628, and 250.1629;
    (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 November 2002;

[[Page 81]]

incorporated by reference at Sec. Sec. 250.114, 250.459, 250.802, 
250.803, 250.1628, and 250.1629;
    (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 Spec. Q1, Specification for Quality Programs for the 
Petroleum, Petrochemical and Natural Gas Industry, ISO TS 29001:2007 
(Identical), Petroleum, petrochemical and natural gas industries--Sector 
specific requirements--Requirements for product and service supply 
organizations, Eighth Edition, December 2007, Effective Date: June 15, 
2008; incorporated by reference at Sec. 250.806;
    (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 Spec. 6A, Specification for Wellhead and Christmas 
Tree Equipment, Nineteenth Edition, July 2004; Effective Date: February 
1, 2005; Contains API Monogram Annex as Part of U.S. National Adoption; 
ISO 10423:2003 (Modified), Petroleum and natural gas industries--
Drilling and production equipment--Wellhead and Christmas tree 
equipment; Errata 1, September 2004, Errata 2, April 2005, Errata 3, 
June 2006, Errata 4, August 2007, Errata 5, May 2009; Addendum 1, 
February 2008; Addendum 2, 3, and 4, December 2008; incorporated by 
reference at Sec. Sec. 250.806 and 250.1002;
    (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 January 2003; incorporated 
by reference at Sec. 250.806;
    (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 2005, Effective Date: May 1, 2006; 
also available as ISO 10432:2004; incorporated by reference at Sec. 
250.806;
    (74) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe, 
Third Edition, July 2008; Effective Date: January 1, 2009, Contains API 
Monogram Annex as Part of U.S. National Adoption; ISO 13628-2:2006 
(Identical), Petroleum and natural gas industries--Design and operation 
of subsea production systems--Part 2: Unbonded flexible pipe systems for 
subsea and marine application; incorporated by reference at Sec. Sec. 
250.803, 250.1002, and 250.1007;
    (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 Sec. Sec. 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);

[[Page 82]]

    (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).
    (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: 610-832-9500:
    (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, 550 NW, LeJeune Road, 
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), NACE 
Standards, 1440 South Creek Drive, 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 Sec. Sec. 250.901 and 250.490;

[[Page 83]]

    (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).
    (m) International Organization for Standardization (ISO), 1, ch. De 
la Voi-Creuse, Case postale 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 Sec. Sec. 
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.center foroff shoresafety.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 Sec. Sec. 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 Sec. Sec. 
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 Sec. Sec. 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]



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, 381 Elden Street, Herndon, VA 
20170.
    (e) BSEE is collecting this information for the reasons given in the 
following table:

[[Page 84]]



------------------------------------------------------------------------
 30 CFR subpart, title and/or BSEE Form       Reasons for collecting
           (OMB Control No.)                 information and how used
------------------------------------------------------------------------
(1) Subpart A, General (1010-0114),      To inform BSEE of actions taken
 including Forms BSEE-0132, Evacuation    to comply with general
 Statistics; BSEE-0143, Facility/         operational requirements on
 Equipment Damage Report; BSEE-1832,      the OCS. To ensure that
 Notification of Incidents of             operations on the OCS meet
 Noncompliance.                           statutory and regulatory
                                          requirements, are safe and
                                          protect the environment, and
                                          result in diligent
                                          exploration, development, and
                                          production on OCS leases. To
                                          support the unproved and
                                          proved reserve estimation,
                                          resource assessment, and fair
                                          market value determinations.
                                          To allow BSEE to rapidly
                                          assess damage and project any
                                          disruption of oil and gas
                                          production from the OCS after
                                          a major natural occurrence.
(2) Subpart B, Exploration and           To inform BSEE, States, and the
 Development and Production Plans (1010-  public of planned exploration,
 0151).                                   development, and production
                                          operations on the OCS. To
                                          ensure that operations on the
                                          OCS are planned to comply with
                                          statutory and regulatory
                                          requirements, will be safe and
                                          protect the human, marine, and
                                          coastal environment, and will
                                          result in diligent
                                          exploration, development, and
                                          production of leases.
(3) Subpart C, Pollution Prevention and  To inform BSEE of measures to
 Control (1010-0057).                     be taken to prevent water
                                          pollution. To ensure that
                                          appropriate measures are taken
                                          to prevent water pollution.
(4) Subpart D, Oil and Gas and Drilling  To inform BSEE of the equipment
 Operations (1010-0141), including        and procedures to be used in
 Forms BSEE-0123, Application for         drilling operations on the
 Permit to Drill; BSEE-0123S,             OCS. To ensure that drilling
 Supplemental APD Information Sheet;      operations are safe and
 BSEE-0124, Application for Permit to     protect the human, marine, and
 Modify; BSEE-0125, End of Operations     coastal environment.
 Report; BSEE-0133, Well Activity
 Report; BSEE-0133S, Open Hole Data
 Report; and BSEE-144, Rig Movement
 Notification Report.
(5) Subpart E, Oil and Gas Well-         To inform BSEE of the equipment
 Completion Operations (1010-0067).       and procedures to be used in
                                          well-completion operations on
                                          the OCS. To ensure that well-
                                          completion operations are safe
                                          and protect the human, marine,
                                          and coastal environment.
(6) Subpart F, Oil and Gas Well          To inform BSEE of the equipment
 Workover Operations (1010-0043).         and procedures to be used
                                          during well-workover
                                          operations on the OCS. To
                                          ensure that well-workover
                                          operations are safe and
                                          protect the human, marine, and
                                          coastal environment.
(7) Subpart H, Oil and Gas Production    To inform BSEE of the equipment
 Safety Systems (1010-0059).              and procedures to be used
                                          during production operations
                                          on the OCS. To ensure that
                                          production operations are safe
                                          and protect the human, marine,
                                          and coastal environment.
(8) Subpart I, Platforms and Structures  To provide BSEE with
 (1010-0149).                             information regarding the
                                          design, fabrication, and
                                          installation of platforms on
                                          the OCS. To ensure the
                                          structural integrity of
                                          platforms installed on the
                                          OCS.
(9) Subpart J, Pipelines and Pipeline    To provide BSEE with
 Rights-of-Way (1010-0050), including     information regarding the
 Form BSEE-0149, Assignment of Federal    design, installation, and
 OCS Pipeline Right-of-Way Grant.         operation of pipelines on the
                                          OCS. To ensure that pipeline
                                          operations are safe and
                                          protect the human, marine, and
                                          coastal environment.
(10) Subpart K, Oil and Gas Production   To inform BSEE of production
 Rates (1010-0041), including Forms       rates for hydrocarbons
 BSEE-0126, Well Potential Test Report    produced on the OCS. To ensure
 and BSEE-0128, Semiannual Well Test      economic maximization of
 Report.                                  ultimate hydrocarbon recovery
(11) Subpart L, Oil and Gas Production   To inform BSEE of the
 Measurement, Surface Commingling, and    measurement of production,
 Security (1010-0051).                    commingling of hydrocarbons,
                                          and site security plans. To
                                          ensure that produced
                                          hydrocarbons are measured and
                                          commingled to provide for
                                          accurate royalty payments and
                                          security is maintained.
(12) Subpart M, Unitization (1010-0068)  To inform BSEE of the
                                          unitization of leases. To
                                          ensure that unitization
                                          prevents waste, conserves
                                          natural resources, and
                                          protects correlative rights.
(13) 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.
(14) Subpart O, Well Control and         To inform BSEE of training
 Production Safety Training (1010-0128).  program curricula, course
                                          schedules, and attendance. To
                                          ensure that training programs
                                          are technically accurate and
                                          sufficient to meet safety and
                                          environmental requirements,
                                          and that workers are properly
                                          trained to operate on the OCS.
(15) Subpart P, Sulphur Operations       To inform BSEE of sulphur
 (1010-0086).                             exploration and development
                                          operations on the OCS. To
                                          ensure that OCS sulphur
                                          operations are safe; protect
                                          the human, marine, and coastal
                                          environment; and will result
                                          in diligent exploration,
                                          development, and production of
                                          sulphur leases.

[[Page 85]]

 
(16) Subpart Q, Decommissioning          To determine that
 Activities (1010-0142).                  decommissioning activities
                                          comply with regulatory
                                          requirements and approvals. To
                                          ensure that site clearance and
                                          platform or pipeline removal
                                          are properly performed to
                                          protect marine life and the
                                          environment and do not
                                          conflict with other users of
                                          the OCS.
(17) Subpart S, Safety and               The SEMS program will describe
 Environmental Management Systems (1010-  management commitment to
 0186), including Form BSEE-0131,         safety and the environment, as
 Performance Measures Data.               well as policies and
                                          procedures to assure safety
                                          and environmental protection
                                          while conducting OCS
                                          operations (including those
                                          operations conducted by
                                          contractor and subcontractor
                                          personnel). The information
                                          collected is the form to
                                          gather the raw Performance
                                          Measures Data relating to risk
                                          and number of accidents,
                                          injuries, and oil spills
                                          during OCS activities.
------------------------------------------------------------------------



                     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, 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)).

[[Page 86]]



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.



Sec. Sec. 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.

          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

[[Page 87]]

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.



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;

[[Page 88]]

    (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; and
    (p) Payment of the service fee listed in Sec. 250.125.



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.
    (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.

[[Page 89]]

    (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 which 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.
    (2) Approval of the method of disposal of drill cuttings, sand, and 
other well solids shall be obtained from the District Manager.
    (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.



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  Who is subject to the requirements of this subpart?

    The requirements of this subpart apply to lessees, operating rights 
owners, operators, and their contractors and subcontractors.

[[Page 90]]



Sec. 250.401  What must I do to keep wells under control?

    You must take necessary precautions to keep wells under control at 
all times. You must:
    (a) Use the best available and safest drilling technology to monitor 
and evaluate well conditions and to minimize the potential for the well 
to flow or kick;
    (b) Have a person onsite during drilling operations who represents 
your interests and can fulfill your responsibilities;
    (c) Ensure that the toolpusher, operator's representative, or a 
member of the drilling crew maintains continuous surveillance on the rig 
floor from the beginning of drilling 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 subpart O; 
and
    (e) Use and maintain equipment and materials necessary to ensure the 
safety and protection of personnel, equipment, natural resources, and 
the environment.



Sec. 250.402  When and how must I secure a well?

    Whenever you interrupt drilling operations, you must install a 
downhole safety device, such as a cement plug, bridge plug, or packer. 
You must install the device at an appropriate depth within a properly 
cemented casing string or liner.
    (a) Among the events that may cause you to interrupt drilling 
operations are:
    (1) Evacuation of the drilling crew;
    (2) Inability to keep the drilling rig on location; or
    (3) Repair to major drilling or well-control equipment.
    (b) For floating drilling operations, the District Manager may 
approve the use of blind or blind-shear rams or pipe rams and an inside 
BOP if you don't have time to install a downhole safety device or if 
special circumstances occur.



Sec. 250.403  What drilling unit movements must I report?

    (a) You must report the movement of all drilling units on and off 
drilling locations to the District Manager. This includes both MODU and 
platform rigs. You must inform the District Manager 24 hours before:
    (1) The arrival of an MODU on location;
    (2) The movement of a platform rig to a platform;
    (3) The movement of a platform rig to another slot;
    (4) The movement of an MODU to another slot; and
    (5) The departure of an MODU 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) In the Gulf of Mexico OCS Region, you must report drilling unit 
movements on form BSEE-0144, Rig Movement Notification Report.



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 take 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;

[[Page 91]]

    (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.



Sec. 250.406  What additional safety measures must I take when I conduct 

drilling operations on a platform that has producing wells or has other 

hydrocarbon flow?

    You must take the following safety measures when you conduct 
drilling operations on a platform with producing wells or that has other 
hydrocarbon flow:
    (a) You must install an emergency shutdown station near the 
driller's console;
    (b) You must shut in all producible wells located in the affected 
wellbay below the surface and at the wellhead when:
    (1) You move a drilling rig 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 drilling unit between wells on a platform;
    (3) A mobile offshore drilling unit (MODU) moves within 500 feet of 
a platform. You may resume production once the MODU is in place, 
secured, and ready to begin drilling operations.



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 Sec. Sec. 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
    (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 described in the following table.

[[Page 92]]



------------------------------------------------------------------------
Information that you must include with an
                   APD                      Where to find a description
------------------------------------------------------------------------
(a) Plat that shows locations of the       Sec.  250.412
 proposed well.
(b) Design criteria used for the proposed  Sec.  250.413
 well.
(c) Drilling prognosis...................  Sec.  250.414
(d) Casing and cementing programs........  Sec.  250.415
(e) Diverter and BOP systems descriptions  Sec.  250.416
(f) Requirements for using an MODU.......  Sec.  250.417
(g) Additional information...............  Sec.  250.418
------------------------------------------------------------------------



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 estimated pore pressures, formation 
fracture gradients, proposed drilling fluid weights, 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.



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:
    (a) Projected plans for coring at specified depths;
    (b) Projected plans for logging;
    (c) Planned safe drilling margin between proposed drilling fluid 
weights and estimated pore pressures. This safe drilling margin may be 
shown on the plot required by Sec. 250.413(g);
    (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 alternative 
procedures or departures from the requirements of this subpart in one 
place in the APD. You must explain how the alternative procedures afford 
an equal or greater degree of protection, safety, or performance, or why 
you need the departures; and
    (i) Projected plans for well testing (refer to Sec. 250.460 for 
safety requirements).

[[Page 93]]



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

    Your casing and cementing programs must include:
    (a) Hole sizes and casing sizes, including: weights; grades; 
collapse, and burst values; types of connection; and setting depths 
(measured and true vertical depth (TVD));
    (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
    (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]



Sec. 250.416  What must I include in the diverter and BOP descriptions?

    You must include in the diverter and BOP descriptions:
    (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 annular BOP 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;
    (c) A description of the BOP system and system components, including 
pressure ratings of BOP equipment and proposed BOP test pressures;
    (d) A schematic drawing of the BOP system that shows the inside 
diameter of the BOP stack, number and type of preventers, all control 
systems and pods, location of choke and kill lines, and associated 
valves;
    (e) Independent third-party verification and supporting 
documentation that show the blind-shear rams installed in the BOP stack 
are capable of shearing any drill pipe (including workstring and tubing) 
in the hole under maximum anticipated surface pressure. The 
documentation must include actual shearing and subsequent pressure 
integrity test results for the most rigid pipe to be used and 
calculations of shearing capacity of all pipe to be used in the well, 
including correction for MASP;
    (f) When you use a subsea BOP stack or surface BOP stack on a 
floating facility, independent third-party verification that shows:
    (1) The BOP stack is designed for the specific equipment on the rig 
and for the specific well design;
    (2) The BOP stack has not been compromised or damaged from previous 
service;
    (3) The BOP stack will operate in the conditions in which it will be 
used; and
    (g) The qualifications of the independent third-party referenced in 
paragraphs (e) and (f) of this section:
    (1) The independent third-party in this section must be a technical 
classification society, or a licensed professional engineering firm, or 
a registered professional engineer capable of providing the 
verifications required under this part.

[[Page 94]]

    (2) You must:
    (i) Include evidence that the registered professional engineer, or a 
technical classification society, or engineering firm you are using or 
its employees hold appropriate licenses to perform the verification in 
the appropriate jurisdiction, and evidence to demonstrate that the 
individual, society, or firm has the expertise and experience necessary 
to perform the required verifications.
    (ii) Ensure that an official representative of BSEE will have access 
to the location to witness any testing or inspections, and verify 
information submitted to BSEE. Prior to any shearing ram tests or 
inspections, you must notify the BSEE District Manager at least 72 hours 
in advance.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50891, Aug. 22, 2012]



Sec. 250.417  What must I provide if I plan to use a mobile offshore drilling 

unit (MODU)?

    If you plan to use a MODU, you must provide:
    (a) Fitness requirements. You must provide information and data to 
demonstrate the drilling unit's capability to perform at the proposed 
drilling location. This information must include the maximum 
environmental and operational conditions that the unit 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, the District 
Manager may approve your APD but require you to collect and report this 
information during operations. Under this circumstance, the District 
Manager has the right to revoke the approval of the APD if information 
collected during operations show that the drilling unit is not capable 
of performing at the proposed location.
    (b) Foundation requirements. You must provide information to show 
that site-specific soil and oceanographic conditions are capable of 
supporting the proposed drilling unit. If you provided sufficient site-
specific information in your EP, DPP, or DOCD submitted to BOEM, you may 
reference that information. The District Manager may require you to 
conduct additional surveys and soil borings before approving the APD if 
additional information is needed to make a determination that the 
conditions are capable of supporting the drilling unit.
    (c) Frontier areas. (1) If the design of the drilling unit 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 unit's design. If required, you must obtain 
the third-party review according to Sec. Sec. 250.915 through 250.918. 
You may submit this information before submitting an APD.
    (2) If you plan to drill in a frontier area, you must have a 
contingency plan that addresses design and operating limitations of the 
drilling unit. 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 drilling or rig 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) U.S. Coast Guard (USCG) documentation. You must provide the 
current Certificate of Inspection or Letter of Compliance from the USCG. 
You must also provide current documentation of any operational 
limitations imposed by an appropriate classification society.
    (e) Floating drilling unit. If you use a floating drilling unit, you 
must indicate that you have a contingency plan for moving off location 
in an emergency situation.
    (f) Inspection of unit. The drilling unit must be available for 
inspection by the District Manager before commencing operations.
    (g) Once the District Manager has approved a MODU for use, you do 
not need to re-submit the information required by this section for 
another APD to use the same MODU unless changes in equipment affect its 
rated capacity to operate in the District.

[[Page 95]]



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 Sec. Sec. 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 below the mudline 
or displace some cement to facilitate casing removal upon well 
abandonment;
    (h) Certification of your casing and cementing program as required 
in Sec. 250.420(a)(6);
    (i) Descriptions of qualifications required by Sec. 250.416(g) of 
the independent third-party; and
    (j) Such other information as the District Manager may require.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012]

                    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 requirements of this section and of Sec. Sec. 
250.421 through 250.428.
    (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; and
    (6)(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).
    (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).
    (c) Cementing requirements. You must design and conduct your 
cementing jobs so that cement composition, placement techniques, and 
waiting

[[Page 96]]

times ensure that the cement placed behind the bottom 500 feet of casing 
attains a minimum compressive strength of 500 psi before drilling out of 
the casing or before commencing completion operations.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012]



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.
(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 conductor or       requirements for
                               surface casing, you   specific casing
                               must set the top of   types. For example,
                               the liner at least    a liner used as
                               200 feet above the    intermediate casing
                               previous casing/      must be cemented
                               liner shoe.           according to the
                              If you use a liner     cementing
                               as an intermediate    requirements for
                               string below a        intermediate
                               surface string or     casing.
                               production casing
                               below an
                               intermediate
                               string, you must
                               set the top of the
                               liner at least 100
                               feet above the
                               previous casing
                               shoe.
------------------------------------------------------------------------



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

[[Page 97]]

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 pressure testing casing?

    (a) The table in this section describes the minimum test pressures 
for each string of casing. You may not resume drilling or other down-
hole 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 investigate the cause and 
receive approval from the appropriate BSEE District Manager for the 
repair to resolve the problem ensuring that the casing will provide a 
proper seal. The BSEE District Manager may approve or require other 
casing test pressures.

------------------------------------------------------------------------
                Casing type                    Minimum test  pressure
------------------------------------------------------------------------
(1) Drive or Structural...................  Not required.
(2) Conductor.............................  200 psi.
(3) Surface, Intermediate, and Production.  70 percent of its minimum
                                             internal yield.
------------------------------------------------------------------------

    (b) You must ensure proper installation of casing in the subsea 
wellhead or liner in the liner hanger.
    (1) You must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon installation of each casing string.
    (2) 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 installation of the liner.
    (3) 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 liner.
    (i) You must submit for approval with your APD, test procedures and 
criteria for a successful test.
    (ii) You must document all your test results and make them available 
to BSEE upon request.
    (c) You must perform a negative pressure test on all wells that use 
a subsea BOP stack or wells with mudline suspension systems. The BSEE 
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.
    (1) You must perform a negative pressure test on your final casing 
string or liner.
    (2) You must perform a negative test prior to unlatching the BOP at 
any point in the well. The negative 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) You must submit for approval with your APD, test procedures and 
criteria for a successful 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.
    (4) You must document all your test results and make them available 
to BSEE upon request.
    (5) 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 contact the appropriate BSEE 
District Manager.
    (ii) Submit a description of the corrective action taken and you 
must receive approval from the appropriate BSEE District Manager for the 
retest.
    (6) You must have two barriers in place, as required in Sec. 
250.420(b)(3), prior to performing the negative pressure test.
    (7) You must include documentation of the successful negative 
pressure test in the End-of-Operations Report (Form BSEE-0125).

[77 FR 50892, Aug. 22, 2012]

[[Page 98]]



Sec. 250.424  What are the requirements for prolonged drilling operations?

    If wellbore operations continue for more than 30 days within a 
casing string run to the surface:
    (a) You must stop drilling operations as soon as practicable, and 
evaluate the effects of the prolonged operations on continued drilling 
operations and the life of the well. At a minimum, you must:
    (1) Caliper or pressure test the casing; and
    (2) Report the results of your evaluation to the District Manager 
and obtain approval of those results before resuming operations.
    (b) If casing integrity has deteriorated to a level below minimum 
safety factors, you must:
    (1) Repair the casing or run another casing string; and
    (2) Obtain approval from the District Manager before you begin 
repairs.



Sec. 250.425  What are the requirements for pressure testing liners?

    (a) You must test each drilling liner (and liner-lap) to a pressure 
at least equal to the anticipated pressure to which the liner will be 
subjected during the formation pressure-integrity test below that liner 
shoe, or subsequent liner shoes if set. The District Manager may approve 
or require other liner test pressures.
    (b) You must test each production liner (and liner-lap) to a minimum 
of 500 psi above the formation fracture pressure at the casing shoe into 
which the liner is lapped.
    (c) You may not resume drilling or other down-hole 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 re-cement, repair the liner, or run additional casing/
liner to provide a proper seal.



Sec. 250.426  What are the recordkeeping requirements for casing and liner 

pressure tests?

    You must record the time, date, and results of each pressure test in 
the driller's report maintained under standard industry practice. In 
addition, you must record each test on a pressure chart and have your 
onsite representative sign and date the test as being correct.



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 margin 
identified in the approved APD. When you cannot maintain this safe 
margin, you must suspend drilling operations and remedy the situation.



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.

[[Page 99]]

 
(b) Need to increase casing setting depths  Submit those changes to the
 more than 100 feet true vertical depth      District Manager for
 (TVD) from the approved APD due to          approval.
 conditions encountered during drilling
 operations,
(c) Have indication of inadequate cement    (1) Run a temperature
 job (such as, but not limited to, lost      survey; (2) Run a cement
 returns, cement channeling, gas cut mud,    evaluation log; or (3) Use
 or failure of equipment),                   a combination of these
                                             techniques.
(d) Inadequate cement job,                  Re-cement or take other
                                             remedial actions as
                                             approved by 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.
(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.
------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012]

                      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.

[[Page 100]]



------------------------------------------------------------------------
        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.
(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.

               Blowout Preventer (BOP) System Requirements



Sec. 250.440  What are the general requirements for BOP systems and system 

components?

    You must design, install, maintain, test, and use the BOP system and 
system components to ensure well control. The working-pressure rating of 
each BOP component must exceed maximum anticipated surface pressures. 
The BOP system includes the BOP stack and associated BOP systems and 
equipment.



Sec. 250.441  What are the requirements for a surface BOP stack?

    (a) When you drill with a surface BOP stack, you must install the 
BOP system before drilling below surface casing. The surface BOP stack 
must include at least four remote-controlled, hydraulically operated 
BOPs, consisting of an annular BOP, two BOPs equipped with pipe rams, 
and one BOP equipped with blind or blind-shear rams.
    (b) Your surface BOP stack must include at least four remote-
controlled, hydraulically operated BOPs consisting of an annular BOP, 
two BOPs equipped with pipe rams, and one BOP equipped with blind-shear 
rams. The blind-shear rams must be capable of shearing the drill pipe 
that is in the hole.
    (c) You must install an accumulator system that provides 1.5 times 
the volume of fluid capacity necessary to close and hold closed all BOP 
components. The system must perform with a minimum pressure of 200 psi 
above the precharge pressure without assistance from a charging system. 
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

[[Page 101]]

other devices to ensure capability of hydraulic operations if rig air is 
lost.
    (d) In addition to the stack and accumulator system, you must 
install the associated BOP systems and equipment required by the 
regulations in this subpart.



Sec. 250.442  What are the requirements for a subsea BOP system?

    When you drill with a subsea BOP system, you must install the BOP 
system before drilling below the surface casing. The District Manager 
may require you to install a subsea BOP system before drilling below the 
conductor casing if proposed casing setting depths or local geology 
indicate the need. The table in this paragraph outlines your 
requirements.

------------------------------------------------------------------------
When drilling with a subsea BOP system,
               you must:                     Additional requirements
------------------------------------------------------------------------
(a) Have at least four remote-           You must have at least one
 controlled, hydraulically operated       annular BOP, two BOPs equipped
 BOPs.                                    with pipe rams, and one BOP
                                          equipped with blind-shear
                                          rams. The blind-shear rams
                                          must be capable of shearing
                                          any drill pipe (including
                                          workstring and tubing) in the
                                          hole under maximum anticipated
                                          surface pressures.
(b) Have an operable dual-pod control
 system to ensure proper and
 independent operation of the BOP
 system.
(c) Have an accumulator system to        The accumulator system must
 provide fast closure of the BOP          meet or exceed the provisions
 components and to operate all critical   of Section 13.3, Accumulator
 functions in case of a loss of the       Volumetric Capacity, in API RP
 power fluid connection to the surface.   53, Recommended Practices for
                                          Blowout Prevention Equipment
                                          Systems for Drilling Wells (as
                                          incorporated by reference in
                                          Sec.  250.198). The District
                                          Manager may approve a suitable
                                          alternate method.
(d) Have a subsea BOP stack equipped     At a minimum, the ROV must be
 with remotely operated vehicle (ROV)     capable of closing one set of
 intervention capability.                 pipe rams, closing one set of
                                          blind-shear rams and
                                          unlatching the LMRP.
(e) Maintain an ROV and have a trained   The crew must be trained in the
 ROV crew on each drilling rig on a       operation of the ROV. The
 continuous basis once BOP deployment     training must include
 has been initiated from the rig until    simulator training on stabbing
 recovered to the surface. The crew       into an ROV intervention panel
 must examine all ROV related well-       on a subsea BOP stack.
 control equipment (both surface and
 subsea) to ensure that it is properly
 maintained and capable of shutting in
 the well during emergency operations.
(f) Provide autoshear and deadman        (1) Autoshear system means a
 systems for dynamically positioned       safety system that is designed
 rigs.                                    to automatically shut in the
                                          wellbore in the event of a
                                          disconnect of the LMRP. When
                                          the autoshear is armed, a
                                          disconnect of the LMRP closes,
                                          at a minimum, one set of blind-
                                          shear rams. This is considered
                                          a ``rapid discharge'' system.
                                         (2) Deadman System means a
                                          safety system that is designed
                                          to automatically close, at a
                                          minimum, one set of blind-
                                          shear rams 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.
                                         (3) You may also have an
                                          acoustic system as a secondary
                                          control system. If you intend
                                          to install an acoustic control
                                          system, you must demonstrate
                                          to BSEE as part of the
                                          information submitted under
                                          Sec.  250.416 that the
                                          acoustic system will function
                                          in the proposed environment
                                          and conditions.
(g) Have operational or physical         Incorporate enable buttons on
 barrier(s) on BOP control panels to      control panels to ensure two-
 prevent accidental disconnect            handed operation for all
 functions.                               critical functions.
(h) Clearly label all control panels     Label other BOP control panels
 for the subsea BOP system.               such as hydraulic control
                                          panel.
(i) Develop and use a management system  The management system must
 for operating the BOP system,            include written procedures for
 including the prevention of accidental   operating the BOP stack and
 or unplanned disconnects of the system.  LMRP (including proper
                                          techniques to prevent
                                          accidental disconnection of
                                          these components) and minimum
                                          knowledge requirements for
                                          personnel authorized to
                                          operate and maintain BOP
                                          components.
(j) Establish minimum requirements for   Personnel must have:
 personnel authorized to operate
 critical BOP equipment.
                                         (1) Training in deepwater well
                                          control theory and practice
                                          according to the requirements
                                          of 30 CFR 250, subpart O; and
                                         (2) A comprehensive knowledge
                                          of BOP hardware and control
                                          systems.
(k) Before removing the marine riser,    You must maintain sufficient
 displace the fluid in the riser with     hydrostatic pressure or take
 seawater.                                other suitable precautions to
                                          compensate for the reduction
                                          in pressure and to maintain a
                                          safe and controlled well
                                          condition.
------------------------------------------------------------------------


[[Page 102]]


[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50893, Aug. 22, 2012]



Sec. 250.443  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 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.
    (b) At least two BOP control stations. One station must be on the 
drilling floor. You must locate the other station in a readily 
accessible location away from the drilling floor.
    (c) Side outlets on the BOP stack for separate kill and choke lines. 
If your stack does not have side outlets, you must install a drilling 
spool with side outlets.
    (d) A choke and a kill line on the BOP stack. You must equip each 
line with two full-opening valves, one of which must be remote-
controlled. For a subsea BOP system, both valves in each line must be 
remote-controlled. In addition:
    (1) You must install the choke line above the bottom ram;
    (2) You may install the kill line below the bottom ram; and
    (3) For a surface BOP system, 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.
    (e) A fill-up line above the uppermost BOP.
    (f) Locking devices installed on the ram-type BOPs.
    (g) A wellhead assembly with a rated working pressure that exceeds 
the maximum anticipated wellhead pressure.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50893, Aug. 22, 2012]



Sec. 250.444  What are the choke manifold requirements?

    (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 rated working pressure at 
least as great as the rated working pressure 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 rated working pressure at least as 
great as the rated working pressure of the ram BOPs.



Sec. 250.445  What are the requirements for kelly valves, inside BOPs, and 

drill-string safety valves?

    You must use or provide the following BOP equipment during drilling 
operations:
    (a) A kelly valve installed below the swivel (upper kelly valve);
    (b) A kelly valve installed at the bottom of the kelly (lower kelly 
valve). You must be able to strip the lower kelly valve through the BOP 
stack;
    (c) If you drill with a mud motor and use drill pipe instead of a 
kelly, you must install one kelly valve above, and one strippable kelly 
valve below, the joint of drill pipe used in place of a kelly;
    (d) On a top-drive system equipped with a remote-controlled valve, 
you must install a strippable kelly-type valve below the remote-
controlled valve;
    (e) 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 
drill string;
    (f) 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 drill string;
    (g) When running casing, you must have a safety valve in the open 
position

[[Page 103]]

available on the rig floor to fit the casing string being run in the 
hole;
    (h) All required manual and remote-controlled kelly valves, drill-
string safety valves, and comparable-type valves (i.e., kelly-type valve 
in a top-drive system) must be essentially full-opening; and
    (i) The drilling crew must have ready access to a wrench to fit each 
manual valve.



Sec. 250.446  What are the BOP maintenance and inspection requirements?

    (a) You must maintain and inspect your BOP system to ensure that the 
equipment functions properly. The BOP maintenance and inspections must 
meet or exceed the provisions of Sections 17.10 and 18.10, Inspections; 
Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, 
Quality Management, described in API RP 53, Recommended Practices for 
Blowout Prevention Equipment Systems for Drilling Wells (incorporated by 
reference as specified in Sec. 250.198). You must document how you met 
or exceeded the provisions of Sections 17.10 and 18.10, Inspections; 
Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, 
Quality Management, described in API RP 53, record the results of your 
BOP inspections and maintenance actions, and make the records available 
to BSEE upon request. You must maintain your records on the rig for 2 
years from the date the records are created, or for a longer period if 
directed by BSEE;
    (b) You must visually inspect your surface BOP system on a daily 
basis. You must visually inspect your subsea BOP system and marine riser 
at least once every 3 days if weather and sea conditions permit. You may 
use television cameras to inspect subsea equipment.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50893, Aug. 22, 2012]



Sec. 250.447  When must I pressure test the BOP system?

    You must pressure test your BOP system (this includes the choke 
manifold, kelly valves, inside BOP, and drill-string safety valve):
    (a) When installed;
    (b) Before 14 days have elapsed since your last BOP pressure test. 
You must begin to test your BOP system before midnight on the 14th day 
following the conclusion of the previous test. However, the District 
Manager may require more frequent testing if conditions or BOP 
performance warrant; and
    (c) Before drilling out each string of casing or a liner. The 
District Manager may allow you to omit this test if you didn't remove 
the BOP stack to run the casing string or liner and the required BOP 
test pressures for the next section of the hole are not greater than the 
test pressures for the previous BOP test. You must indicate in your APD 
which casing strings and liners meet these criteria.



Sec. 250.448  What are the BOP pressure tests requirements?

    When you pressure test the BOP system, you must conduct a low-
pressure and a high-pressure test for each BOP component. You must 
conduct the low-pressure test before the high-pressure test. Each 
individual pressure test must hold pressure long enough to demonstrate 
that the tested component(s) holds the required pressure. Required test 
pressures are as follows:
    (a) Low-pressure test. All low-pressure tests must be between 200 
and 300 psi. Any initial pressure above 300 psi must be bled back to a 
pressure between 200 and 300 psi before starting the test. If the 
initial pressure exceeds 500 psi, you must bleed back to zero and 
reinitiate the test.
    (b) High-pressure test for ram-type BOPs, the choke manifold, and 
other BOP components. The high-pressure test must equal the rated 
working pressure of the equipment or be 500 psi greater than your 
calculated maximum anticipated surface pressure (MASP) 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) High pressure test for annular-type BOPs. The high pressure test 
must equal 70 percent of the rated working pressure of the equipment or 
to a pressure approved in your APD.
    (d) Duration of pressure test. Each test must hold the required 
pressure for 5

[[Page 104]]

minutes. However, for surface BOP systems and surface equipment of a 
subsea BOP system, a 3-minute test duration is acceptable if you record 
your test pressures on the outermost half of a 4-hour chart, on a 1-hour 
chart, or on a digital recorder. If the equipment does not hold the 
required pressure during a test, you must correct the problem and retest 
the affected component(s).



Sec. 250.449  What additional BOP testing requirements must I meet?

    You must meet the following additional BOP testing requirements:
    (a) Use water to test a surface BOP system;
    (b) Stump test a subsea BOP system before installation. You must use 
water to conduct this test. You may use drilling fluids to conduct 
subsequent tests of a subsea BOP system. You must perform the initial 
subsea BOP test on the seafloor within 30 days of the stump test.
    (c) Alternate tests between control stations and pods;
    (d) Pressure test the blind or blind-shear ram BOP during stump 
tests and at all casing points;
    (e) The interval between any blind or blind-shear ram BOP pressure 
tests may not exceed 30 days;
    (f) Pressure test variable bore-pipe ram BOPs against the largest 
and smallest sizes of pipe in use, excluding drill collars and bottom-
hole tools;
    (g) Pressure test affected BOP components following the 
disconnection or repair of any well-pressure containment seal in the 
wellhead or BOP stack assembly;
    (h) Function test annular and ram BOPs every 7 days between pressure 
tests;
    (i) Actuate safety valves assembled with proper casing connections 
before running casing;
    (j) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. Each ROV must be fully compatible with the BOP 
stack ROV intervention panels. You must also test and verify closure of 
at least one set of rams during the initial test on the seafloor through 
an ROV hot stab. You must submit test procedures, including how you will 
test each ROV intervention function, with your APD or APM for BSEE 
District Manager approval. You must:
    (1) Ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams, one set of 
blind-shear rams, and unlatching the Lower Marine Riser Package (LMRP);
    (2) Notify the appropriate BSEE District Manager a minimum of 72 
hours prior to the stump test and initial test on the seafloor; and
    (3) Document all your test results and make them available to BSEE 
upon request;
    (k) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system and 
verify closure of at least one set of blind-shear rams during the 
initial test on the seafloor. 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.
    (1) You must submit test procedures with your APD or APM for 
District Manager approval. The procedures for these function tests must 
include documentation of the controls and circuitry of the system 
utilized during each test. The procedure must also describe how the ROV 
will be utilized during this operation.
    (2) You must document all your test results and make them available 
to BSEE upon request.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50893, Aug. 22, 2012]



Sec. 250.450  What are the recordkeeping requirements for BOP tests?

    You must record the time, date, and results of all pressure tests, 
actuations, and inspections of the BOP system, system components, and 
marine riser in the driller's report. In addition, you must:
    (a) Record BOP test pressures on pressure charts;
    (b) Require your onsite representative to sign and date BOP test 
charts and reports as correct;
    (c) Document the sequential order of BOP and auxiliary equipment 
testing

[[Page 105]]

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 the control station and pod used during the test;
    (e) Identify any problems or irregularities observed during BOP 
system testing and record actions taken to remedy the problems or 
irregularities; and
    (f) Retain all records, including pressure charts, driller's report, 
and referenced documents pertaining to BOP tests, actuations, and 
inspections at the facility for the duration of drilling.



Sec. 250.451  What must I do in certain situations involving BOP equipment or 

systems?

    The table in this section describes actions that lessees must take 
when certain situations occur with BOP systems during drilling 
activities.

------------------------------------------------------------------------
 If you encounter the following situation:       Then you must . . .
------------------------------------------------------------------------
(a) BOP equipment does not hold the         Correct the problem and
 required pressure during a test,            retest the affected
                                             equipment.
(b) Need to repair or replace a surface or  First place the well in a
 subsea BOP system,                          safe, controlled condition
                                             (e.g., before drilling out
                                             a casing shoe or after
                                             setting a cement plug,
                                             bridge plug, or a packer).
(c) Need to postpone a BOP test due to      Record the reason for
 well-control problems such as lost          postponing the test in the
 circulation, formation fluid influx, or     driller's report and
 stuck drill pipe,                           conduct the required BOP
                                             test on the first trip out
                                             of the hole.
(d) BOP control station or pod that does    Suspend further drilling
 not function properly,                      operations until that
                                             station or pod is operable.
(e) Want to drill with a tapered drill-     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 drill string.
(f) Install casing rams in a BOP stack,     Test the ram bonnets before
                                             running casing.
(g) Want to use an annular BOP with a       Demonstrate that your well
 rated working pressure less than the        control procedures or the
 anticipated surface pressure,               anticipated well conditions
                                             will not place demands
                                             above its rated working
                                             pressure and obtain
                                             approval from the District
                                             Manager.
(h) Use a subsea BOP system in an ice-      Install the BOP stack in a
 scour area,                                 well 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 blind-shear rams or        Retrieve, physically
 casing shear rams during a well control     inspect, and conduct a full
 situation, in which pipe or casing is       pressure test of the BOP
 sheared,                                    stack after the situation
                                             is fully controlled.
(j) Need to remove the BOP stack            Have a minimum of two
                                             barriers in place prior to
                                             BOP removal. The BSEE
                                             District Manager may
                                             require additional
                                             barriers.
------------------------------------------------------------------------


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

                       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:
    (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.

[[Page 106]]

    (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;
    (j) Before you displace kill-weight fluid from the wellbore and/or 
riser to an underbalanced state, you must obtain approval from the BSEE 
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; and
    (k) 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]



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

[[Page 107]]

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 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.

[[Page 108]]

                       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:
    (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 requirements for well-control drills?

    You must conduct a weekly well-control drill with each drilling 
crew. Your drill must familiarize the crew with its roles and functions 
so that all crew members can perform their duties promptly and 
efficiently.
    (a) Well-control drill plan. You must prepare a well control drill 
plan for each well. Your plan must outline the assignments for each crew 
member and establish times to complete each portion of the drill. You 
must post a copy of the well control drill plan on the rig floor or 
bulletin board.
    (b) Timing of drills. You must conduct each drill during a period of 
activity that minimizes the risk to drilling operations. The timing of 
your drills must cover a range of different operations, including 
drilling with a diverter, on-bottom drilling, and tripping.

[[Page 109]]

    (c) Recordkeeping requirements. For each drill, you must record the 
following in the driller's report:
    (1) The time to be ready to close the diverter or BOP system; and
    (2) The total time to complete the entire drill.
    (d) BSEE ordered drill. A BSEE authorized 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. 250.463  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.

            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 form 
BSEE-0124 with detailed information about the work to the District 
Manager, unless you have already provided sufficient information in a 
Well Activity Report, form BSEE-0133 (Sec. 250.468(b)).



Sec. 250.466  What records must I keep?

    You must keep complete, legible, and accurate records for each well. 
You must keep drilling records onsite while drilling activities 
continue. After completion of drilling activities, you must keep all 
drilling and other well records for the time periods shown in Sec. 
250.467. You may keep these records at a location of your choice. The 
records must contain complete information on all of the following:
    (a) Well operations;

[[Page 110]]

    (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 in the 
interests of resource evaluation, waste prevention, conservation of 
natural resources, and the protection of correlative rights, safety, and 
environment.



Sec. 250.467  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,                               Ninety days after you
                                             complete drilling
                                             operations.
(b) Casing and liner pressure tests,        Two years after the
 diverter tests, and BOP tests,              completion of drilling
                                             operations.
(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 forward the records
 hydrocarbon-bearing zone,                   with a lease assignment.
------------------------------------------------------------------------



Sec. 250.468  What well records am I required to submit?

    (a) You must submit 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 to BSEE. Each Region will provide specific instructions for 
submitting well logs and surveys.
    (b) For drilling operations in the GOM OCS Region, you must submit 
form BSEE-0133, Well Activity Report, to the District Manager on a 
weekly basis.
    (c) For drilling operations in the Pacific or Alaska OCS Regions, 
you must submit form BSEE-0133, Well Activity Report, to the District 
Manager on a daily basis.



Sec. 250.469  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. 250.466;
    (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 prescribes 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.

                            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

[[Page 111]]

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 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

[[Page 112]]

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 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;

[[Page 113]]

    (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:
    (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.

[[Page 114]]

    (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.
    (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-

[[Page 115]]

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:
    (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

[[Page 116]]

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 
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 Sec. Sec. 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:

[[Page 117]]

    (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 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.

[[Page 118]]

    (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-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 shall 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

[[Page 119]]

leased and not leased), the National security or defense, or the marine, 
coastal, or human environment.



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  Equipment movement.

    The movement of well-completion rigs and related equipment on and 
off a platform or from well to well on the same platform, including 
rigging up and rigging down, shall be conducted in a safe manner. All 
wells in the same well-bay which are capable of producing hydrocarbons 
shall 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 well-
completion rigs and related equipment, unless otherwise approved by the 
District Manager. 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. The well from which the rig or related equipment is to be 
moved shall also be equipped with a back-pressure valve prior to 
removing the blowout preventer (BOP) system and installing the tree.



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.



Sec. 250.506  Crew instructions.

    Prior to engaging in well-completion operations, crew members shall 
be instructed in the safety requirements of the operations to be 
performed, possible hazards to be encountered, and general safety 
considerations to protect personnel, equipment, and the environment. 
Date and time of safety meetings shall be recorded and available at the 
facility for review by BSEE representatives.



Sec. Sec. 250.507-250.508  [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

[[Page 120]]

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 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 Sec. Sec. 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. 250.515.
    (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]



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;

[[Page 121]]

    (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.
    (d) Before you displace kill-weight fluid from the wellbore and/or 
riser to an underbalanced state, you must obtain approval from the BSEE 
District Manager. To obtain approval, you must submit with your 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.

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



Sec. 250.515  What BOP information must I submit?

    For completion operations, your APM must include the following BOP 
descriptions:
    (a) A description of the BOP system and system components, including 
pressure ratings of BOP equipment and proposed BOP test pressures;
    (b) A schematic drawing of the BOP system that shows the inside 
diameter of the BOP stack, number and type of preventers, all control 
systems and pods, location of choke and kill lines, and associated 
valves;
    (c) Independent third-party verification and supporting 
documentation that show the blind-shear rams installed in the BOP stack 
are capable of shearing any drill pipe (including workstring and tubing) 
in the hole under maximum anticipated surface pressure. The 
documentation must include actual shearing and subsequent pressure 
integrity test results for the most rigid pipe to be used, and 
calculations of shearing capacity of all pipe to be used in the well 
including correction for maximum anticipated surface pressure;
    (d) When you use a subsea BOP stack, independent third-party 
verification that shows:
    (1) The BOP stack is designed for the specific equipment on the rig 
and for the specific well design;
    (2) The BOP stack has not been compromised or damaged from previous 
service;
    (3) The BOP stack will operate in the conditions in which it will be 
used; and
    (e) The qualifications of the independent third-party referenced in 
paragraphs (c) and (d) of this section:
    (1) The independent third-party in this section must be a technical 
classification society, or a licensed professional engineering firm, or 
a registered professional engineer capable of providing the 
verifications required under this part.
    (2) You must:
    (i) Include evidence that the registered professional engineer, or a 
technical classification society, or engineering firm you are using or 
its employees hold appropriate licenses to perform the verification in 
the appropriate jurisdiction, and evidence to demonstrate that the 
individual, society, or firm has the expertise and experience necessary 
to perform the required verifications; and
    (ii) Ensure that an official representative of BSEE will have access 
to the

[[Page 122]]

location to witness any testing or inspections, and verify information 
submitted to BSEE. Prior to any shearing ram tests or inspections, you 
must notify the BSEE District Manager at least 72 hours in advance.

[77 FR 50894, Aug. 22, 2012]



Sec. 250.516  Blowout prevention equipment.

    (a) The BOP system and system components and related well-control 
equipment shall be designed, used, maintained, and tested in a manner 
necessary to assure well control in foreseeable conditions and 
circumstances, including subfreezing conditions. The working pressure 
rating of the BOP system and BOP system components shall exceed the 
expected surface pressure to which they may be subjected. If the 
expected surface pressure exceeds the rated working pressure of the 
annular preventer, the lessee shall submit with Form BSEE-0124 or Form 
BSEE-0123, as appropriate, a well-control procedure that indicates how 
the annular preventer will be utilized, and the pressure limitations 
that will be applied during each mode of pressure control.
    (b) The minimum BOP system for well-completion operations must meet 
the appropriate standards from the following table:

------------------------------------------------------------------------
                                             The minimum BOP stack must
                When . . .                          include . . .
------------------------------------------------------------------------
(1) The expected pressure is less than      Three BOPs consisting of an
 5,000 psi,                                  annular, one set of pipe
                                             rams, and one set of blind-
                                             shear rams.
(2) The expected pressure is 5,000 psi or   Four BOPs consisting of an
 greater or you use multiple tubing          annular, two sets of pipe
 strings,                                    rams, and one set of blind-
                                             shear rams.
(3) You handle multiple tubing strings      Four BOPs consisting of an
 simultaneously,                             annular, one set of pipe
                                             rams, one set of dual pipe
                                             rams, and one set of blind-
                                             shear rams.
(4) You use a tapered drill string,         At least one set of pipe
                                             rams that are capable of
                                             sealing around each size of
                                             drill string. If the
                                             expected pressure is
                                             greater than 5,000 psi,
                                             then you must have at least
                                             two sets of pipe rams that
                                             are capable of sealing
                                             around the larger size
                                             drill string. You may
                                             substitute one set of
                                             variable bore rams for two
                                             sets of pipe rams.
(5) You use a subsea BOP stack,             The requirements in Sec.
                                             250.442(a) of this part.
------------------------------------------------------------------------

    (c) The BOP systems for well completions must be equipped with the 
following:
    (1) A hydraulic-actuating system that provides sufficient 
accumulator capacity to supply 1.5 times the volume necessary to close 
all BOP equipment units with a minimum pressure of 200 psi above the 
precharge pressure without assistance from a charging system. 
Accumulator regulators supplied by rig air and without a secondary 
source of pneumatic supply, must be equipped with manual overrides, or 
alternately, other devices provided to ensure capability of hydraulic 
operations if rig air is lost.
    (2) A secondary power source, independent from the primary power 
source, with sufficient capacity to close all BOP system components and 
hold them closed.
    (3) Locking devices for the pipe-ram preventers.
    (4) At least one remote BOP-control station and one BOP-control 
station on the rig floor.
    (5) A choke line and a kill line each equipped with two full opening 
valves and a choke manifold. At least one of the valves on the choke 
line shall be remotely controlled. At least one of the valves on the 
kill line shall be remotely controlled, except that a check valve on the 
kill line in lieu of the remotely controlled valve may be installed 
provided that two readily accessible manual valves are in place and the 
check valve is placed between the manual valves and the pump. This 
equipment shall have a pressure rating at least equivalent to the ram 
preventers.
    (d) 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-
completion operations. 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.

[[Page 123]]

    (e) The subsea BOP system for well-completions must meet the 
requirements in Sec. 250.442 of this part.

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



Sec. 250.517  Blowout preventer system tests, inspections, and maintenance.

    (a) BOP pressure testing timeframes. You must pressure test your BOP 
system:
    (1) When installed; and
    (2) Before 14 days have elapsed since your last BOP pressure test. 
You must begin to test your BOP system before 12 a.m. (midnight) on the 
14th day following the conclusion of the previous test. However, the 
District Manager may require testing every 7 days if conditions or BOP 
performance warrant.
    (b) BOP test pressures. When you test the BOP system, you must 
conduct a low pressure and a high pressure test for each BOP component. 
Each individual pressure test must hold pressure long enough to 
demonstrate that the tested component(s) holds the required pressure. 
The District Manager may approve or require other test pressures or 
practices. Required test pressures are as follows:
    (1) All low pressure tests must be between 200 and 300 psi. Any 
initial pressure above 300 psi must be bled back to a pressure between 
200 and 300 psi before starting the test. If the initial pressure 
exceeds 500 psi, you must bleed back to zero and reinitiate the test. 
You must conduct the low pressure test before the high pressure test.
    (2) For ram-type BOP's, choke manifold, and other BOP equipment, the 
high pressure test must equal the rated working pressure of the 
equipment.
    (3) For annular-type BOP's, the high pressure test must equal 70 
percent of the rated working pressure of the equipment.
    (c) Duration of pressure test. Each test must hold the required 
pressure for 5 minutes.
    (1) For surface BOP systems and surface equipment of a subsea BOP 
system, a 3-minute test duration is acceptable if you record your test 
pressures on the outermost half of a 4-hour chart, on a 1-hour chart, or 
on a digital recorder.
    (2) If the equipment does not hold the required pressure during a 
test, you must remedy the problem and retest the affected component(s).
    (d) Additional BOP testing requirements. You must:
    (1) Use water to test the surface BOP system;
    (2) Stump test a subsea BOP system before installation. You must use 
water to conduct this test. You may use drilling or completion fluids to 
conduct subsequent tests of a subsea BOP system. You must perform the 
initial subsea BOP test on the seafloor within 30 days of the stump 
test.
    (3) Alternate tests between control stations and pods. If a control 
station or pod is not functional, you must suspend further completion 
operations until that station or pod is operable;
    (4) Pressure test the blind or blind-shear ram at least every 30 
days;
    (5) Function test annulars and rams every 7 days;
    (6) Pressure-test variable bore-pipe rams against all sizes of pipe 
in use, excluding drill collars and bottom-hole tools;
    (7) Test affected BOP components following the disconnection or 
repair of any well-pressure containment seal in the wellhead or BOP 
stack assembly;
    (8) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. Each ROV must be fully compatible with the BOP 
stack ROV intervention panels. You must also test and verify closure of 
at least one set of rams during the initial test on the seafloor through 
an ROV hot stab. You must submit test procedures, including how you will 
test each ROV function, with your APM for BSEE District Manager 
approval. You must:
    (i) Ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams, one set of 
blind-shear rams, and unlatching the LMRP;
    (ii) Notify the appropriate BSEE District Manager a minimum of 72 
hours prior to the stump test and initial test on the seafloor;
    (iii) Document all your test results and make them available to BSEE 
upon request; and
    (9) Function test autoshear and deadman systems on your subsea BOP

[[Page 124]]

stack during the stump test. You must also test the deadman system and 
verify closure of at least one set of blind-shear rams during the 
initial test on the seafloor. 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. You must:
    (i) Submit test procedures with your APM for BSEE District Manager 
approval. The procedures for these function tests must include 
documentation of the controls and circuitry of the system utilized 
during each test. The procedure must also describe how the ROV will be 
utilized during this operation.
    (ii) Document all your test results and make them available to BSEE 
upon request.
    (e) Postponing BOP tests. You may postpone a BOP test if you have 
well-control problems. You must conduct the required BOP test as soon as 
possible (i.e., first trip out of the hole) after the problem has been 
remedied. You must record the reason for postponing any test in the 
driller's report.
    (f) Weekly crew drills. You must conduct a weekly drill to 
familiarize all personnel engaged in well-completion operations with 
appropriate safety measures.
    (g) BOP inspections. (1) You must inspect your BOP system to ensure 
that the equipment functions properly. The BOP inspections must meet or 
exceed the provisions of Sections 17.10 and 18.10, Inspections, 
described in API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells (incorporated by reference as 
specified in Sec. 250.198). You must document how you met or exceeded 
the provisions of Sections 17.10 and 18.10 described in API RP 53, the 
procedures used, record the results, and make the records available to 
BSEE upon request. You must maintain your records on the rig for 2 years 
from the date the records are created, or for a longer period if 
directed by BSEE.
    (2) You must visually inspect your surface BOP system on a daily 
basis. You must visually inspect your subsea BOP system and marine riser 
at least once every 3 days if weather and sea conditions permit. You may 
use television cameras to inspect subsea equipment. The BSEE District 
Manager may approve alternate methods and frequencies to inspect a 
marine riser.
    (h) BOP maintenance. You must maintain your BOP system to ensure 
that the equipment functions properly. The BOP maintenance must meet or 
exceed the provisions of Sections 17.11 and 18.11, Maintenance; and 
Sections 17.12 and 18.12, Quality Management, described in API RP 53, 
Recommended Practices for Blowout Prevention Equipment Systems for 
Drilling Wells (incorporated by reference as specified in Sec. 
250.198). You must document how you met or exceeded the provisions of 
Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, 
Quality Management, described in API RP 53, the procedures used, record 
the results, and make the records available to BSEE upon request. You 
must maintain your records on the rig for 2 years from the date the 
records are created, or for a longer period if directed by BSEE.
    (i) BOP test records. You must record the time, date, and results of 
all pressure tests, actuations, crew drills, and inspections of the BOP 
system, system components, and marine riser in the driller's report. In 
addition, you must:
    (1) Record BOP test pressures on pressure charts;
    (2) Have your onsite representative certify (sign and date) BOP test 
charts and reports as correct;
    (3) Document the sequential order of BOP and auxiliary equipment 
testing and the pressure and duration of each test. You may reference a 
BOP test plan if it is available at the facility;
    (4) Identify the control station or pod used during the test;
    (5) Identify any problems or irregularities observed during BOP 
system and equipment testing and record actions taken to remedy the 
problems or irregularities;
    (6) Retain all records including pressure charts, driller's report, 
and referenced documents pertaining to BOP tests, actuations, and 
inspections at the facility for the duration of the completion activity; 
and

[[Page 125]]

    (7) After completion of the well, you must retain all the records 
listed in paragraph (i)(6) of this section for a period of 2 years at 
the facility, at the lessee's field office nearest the OCS facility, or 
at another location conveniently available to the District Manager.
    (j) Alternate methods. The District Manager may require, or approve, 
more frequent testing, as well as different test pressures and 
inspection methods, or other practices.

[76 FR 64462, Oct. 18, 2011. Redesignated and amended at 77 FR 50894, 
50895, Aug. 22, 2012]



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) In the event of prolonged operations such as milling, fishing, 
jarring, or washing over that could damage the casing, the casing shall 
be pressure-tested, calipered, or otherwise evaluated every 30 days and 
the results submitted to the District Manager.
    (c) 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.

    (d) 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.
    (e) Subsurface safety equipment shall be installed, maintained, and 
tested in compliance with Sec. 250.801 of this part.

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

                       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 Sec. Sec. 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.
(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,

[[Page 126]]

 
(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 Sec. Sec. 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 127]]



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 128]]

    (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 shall 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.



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 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:

[[Page 129]]

    (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  Equipment movement.

    The movement of well-workover rigs and related equipment on and off 
a platform or from well to well on the same platform, including rigging 
up and rigging down, shall be conducted in a safe manner. All wells in 
the same well-bay which are capable of producing hydrocarbons shall 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 well-workover 
rigs and related equipment unless otherwise approved by the District 
Manager. 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. 
The well to which a well-workover rig or related equipment is to be 
moved shall also be equipped with a back-pressure valve prior to 
removing the tree and installing and testing the blowout-preventer (BOP) 
system. The well from which a well-workover rig or related equipment is 
to be moved shall also be equipped with a back pressure valve prior to 
removing the BOP system and installing the tree. Coiled tubing units, 
snubbing units, or wireline units may be moved onto a platform without 
shutting in wells.



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.



Sec. 250.606  Crew instructions.

    Prior to engaging in well-workover operations, crew members shall be 
instructed in the safety requirements of the operations to be performed, 
possible hazards to be encountered, and general safety considerations to 
protect personnel, equipment, and the environment. Date and time of 
safety meetings shall be recorded and available at the facility for 
review by a BSEE representative.

[[Page 130]]



Sec. Sec. 250.607-250.608  [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.

    No later than May 31, 1989, diesel engine air intakes shall be 
equipped with a device to shut down the diesel engine in the event of 
runaway. Diesel engines which are continuously attended shall be 
equipped with either remote operated manual or automatic shutdown 
devices. Diesel engines which are not continuously attended shall be 
equipped with automatic shutdown devices.



Sec. 250.611  Traveling-block safety device.

    After May 31, 1989, all units being used for well-workover 
operations which have both a traveling block and a crown block shall be 
equipped with a safety device which is designed to prevent the traveling 
block from striking the crown block. The device shall be checked for 
proper operation weekly and after each drill-line slipping operation. 
The results of the operational check shall be entered in the operations 
log.



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. 250.615.
    (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-

[[Page 131]]

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]



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 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.
    (d) Before you displace kill-weight fluid from the wellbore and/or 
riser to an underbalanced state, you must obtain approval from the BSEE 
District Manager. To obtain approval, you must submit with your 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.

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



Sec. 250.615  What BOP information must I submit?

    For well-workover operations, your APM must include the following 
BOP descriptions:
    (a) A description of the BOP system and system components, including 
pressure ratings of BOP equipment and proposed BOP test pressures;
    (b) A schematic drawing of the BOP system that shows the inside 
diameter of the BOP stack, number and type of preventers, all control 
systems and pods, location of choke and kill lines, and associated 
valves;
    (c) Independent third-party verification and supporting 
documentation that show the blind-shear rams installed in the BOP stack 
are capable of shearing any drill pipe (including workstring and tubing) 
in the hole under maximum anticipated surface pressure. The 
documentation must include actual shearing and subsequent pressure 
integrity test results for the most rigid pipe to be used and 
calculations of shearing capacity of all pipe to be used in the well, 
including correction for under maximum anticipated surface pressure;
    (d) When you use a subsea BOP stack, independent third-party 
verification that shows:

[[Page 132]]

    (1) The BOP stack is designed for the specific equipment on the rig 
and for the specific well design;
    (2) The BOP stack has not been compromised or damaged from previous 
service;
    (3) The BOP stack will operate in the conditions in which it will be 
used; and
    (e) The qualifications of the independent third-party referenced in 
paragraphs (c) and (d) of this section:
    (1) The independent third-party in this section must be a technical 
classification society, or a licensed professional engineering firm, or 
a registered professional engineer capable of providing the 
verifications required under this part.
    (2) You must:
    (i) Include evidence that the registered professional engineer, or a 
technical classification society, or engineering firm you are using or 
its employees hold appropriate licenses to perform the verification in 
the appropriate jurisdiction, and evidence to demonstrate that the 
individual, society, or firm has the expertise and experience necessary 
to perform the required verifications.
    (ii) Ensure that an official representative of BSEE will have access 
to the location to witness any testing or inspections, and verify 
information submitted to BSEE. Prior to any shearing ram tests or 
inspections, you must notify the BSEE District Manager at least 72 hours 
in advance.

[77 FR 50895, Aug. 22, 2012]



Sec. 250.616  Blowout prevention equipment.

    (a) The BOP system, system components and related well-control 
equipment shall be designed, used, maintained, and tested in a manner 
necessary to assure well control in foreseeable conditions and 
circumstances, including subfreezing conditions. The working pressure 
rating of the BOP system and system components shall exceed the expected 
surface pressure to which they may be subjected. If the expected surface 
pressure exceeds the rated working pressure of the annular preventer, 
the lessee shall submit with Form BSEE-0124, requesting approval of the 
well-workover operation, a well-control procedure that indicates how the 
annular preventer will be utilized, and the pressure limitations that 
will be applied during each mode of pressure control.
    (b) The minimum BOP system for well-workover operations with the 
tree removed must meet the appropriate standards from the following 
table:

------------------------------------------------------------------------
                                             The minimum BOP stack must
                When . . .                          include . . .
------------------------------------------------------------------------
(1) The expected pressure is less than      Three BOPs consisting of an
 5,000 psi,                                  annular, one set of pipe
                                             rams, and one set of blind-
                                             shear rams.
(2) The expected pressure is 5,000 psi or   Four BOPs consisting of an
 greater or you use multiple tubing          annular, two sets of pipe
 strings,                                    rams, and one set of blind-
                                             shear rams.
(3) You handle multiple tubing strings      Four BOPs consisting of an
 simultaneously,                             annular, one set of pipe
                                             rams, one set of dual pipe
                                             rams, and one set of blind-
                                             shear rams.
(4) You use a tapered drill string,         At least one set of pipe
                                             rams that are capable of
                                             sealing around each size of
                                             drill string. If the
                                             expected pressure is
                                             greater than 5,000 psi,
                                             then you must have at least
                                             two sets of pipe rams that
                                             are capable of sealing
                                             around the larger size
                                             drill string. You may
                                             substitute one set of
                                             variable bore rams for two
                                             sets of pipe rams.
(5) You use a subsea BOP stack,             The requirements in Sec.
                                             250.442(a) of this part.
------------------------------------------------------------------------

    (c) The BOP systems for well-workover operations with the tree 
removed must be equipped with the following:
    (1) A hydraulic-actuating system that provides sufficient 
accumulator capacity to supply 1.5 times the volume necessary to close 
all BOP equipment units with a minimum pressure of 200 psi above the 
precharge pressure without assistance from a charging system. 
Accumulator regulators supplied by rig air and without a secondary 
source of pneumatic supply, must be equipped with manual overrides, or 
alternately, other devices provided to ensure capability of hydraulic 
operations if rig air is lost;
    (2) A secondary power source, independent from the primary power

[[Page 133]]

source, with sufficient capacity to close all BOP system components and 
hold them closed;
    (3) Locking devices for the pipe-ram preventers;
    (4) At least one remote BOP-control station and one BOP-control 
station on the rig floor; and
    (5) A choke line and a kill line each equipped with two full opening 
valves and a choke manifold. At least one of the valves on the choke-
line shall be remotely controlled. At least one of the valves on the 
kill line shall be remotely controlled, except that a check valve on the 
kill line in lieu of the remotely controlled valve may be installed 
provided two readily accessible manual valves are in place and the check 
valve is placed between the manual valves and the pump. This equipment 
shall have a pressure rating at least equivalent to the ram preventers.
    (d) The minimum BOP-system components for well-workover operations 
with the tree in place and performed through the wellhead inside of 
conventional tubing using small-diameter jointed pipe (usually \3/4\ 
inch to 1\1/4\ inch) as a work string, i.e., small-tubing operations, 
shall include the following:
    (1) Two sets of pipe rams, and
    (2) One set of blind rams.
    (e) The subsea BOP system for well-workover operations must meet the 
requirements in Sec. 250.442 of this part.
    (f) 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 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

[[Page 134]]

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-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.
    (g) 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.
    (h) 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]



Sec. 250.617  Blowout preventer system testing, records, and drills.

    (a) BOP pressure tests. When you pressure test the BOP system you 
must conduct a low-pressure test and a high-pressure test for each 
component. You must conduct the low-pressure test before the high-
pressure test. For purposes of this section, BOP system components 
include ram-type BOP's, related control equipment, choke and kill lines, 
and valves, manifolds, strippers, and safety valves. Surface BOP systems 
must be pressure tested with water.
    (1) Low pressure tests. All BOP system components must be 
successfully tested to a low pressure between 200 and 300 psi. Any 
initial pressure equal to or greater than 300 psi must be bled back to a 
pressure between 200 and 300 psi before starting the test. If the 
initial pressure exceeds 500 psi, you must bleed back to zero before 
starting the test.
    (2) High pressure tests. All BOP system components must be 
successfully tested to the rated working pressure of the BOP equipment, 
or as otherwise approved by the District Manager. The annular-type BOP 
must be successfully tested at 70 percent of its rated working pressure 
or as otherwise approved by the District Manager.
    (3) Other testing requirements. Variable bore pipe rams must be 
pressure tested against the largest and smallest sizes of tubulars in 
use (jointed pipe, seamless pipe) in the well.
    (b) Times. The BOP systems shall be tested at the following times:
    (1) When installed;
    (2) At least every 7 days, alternating between control stations and 
at staggered intervals to allow each crew to operate the equipment. If 
either control system is not functional, further operations shall be 
suspended until the nonfunctional, system is operable. The test every 7 
days is not required for blind or blind-shear rams. The blind or blind-
shear rams shall be tested at least once every 30 days during operation. 
A longer period between blowout preventer tests is allowed when there is 
a stuck pipe or pressure-control operation and remedial efforts are 
being performed. The tests shall be conducted as soon as possible and 
before normal operations resume. The reason for postponing testing shall 
be entered into the operations log.

[[Page 135]]

    (3) Following repairs that require disconnecting a pressure seal in 
the assembly, the affected seal will be pressure tested.
    (c) Drills. All personnel engaged in well-workover operations shall 
participate in a weekly BOP drill to familiarize crew members with 
appropriate safety measures.
    (d) Stump tests. You may conduct a stump test for the BOP system on 
location. A plan describing the stump test procedures must be included 
in your Form BSEE-0124, Application for Permit to Modify, and must be 
approved by the District Manager.
    (e) Coiled tubing tests. You must test the coiled tubing connector 
to a low pressure of 200 to 300 psi, followed by a high pressure test to 
the rated working pressure of the connector or the expected surface 
pressure, whichever is less. You must successfully pressure test the 
dual check valves to the rated working pressure of the connector, the 
rated working pressure of the dual check valve, expected surface 
pressure, or the collapse pressure of the coiled tubing, whichever is 
less.
    (f) Recordings. You must record test pressures during BOP and coiled 
tubing tests on a pressure chart, or with a digital recorder, unless 
otherwise approved by the District Manager. The test interval for each 
BOP system component must be 5 minutes, except for coiled tubing 
operations, which must include a 10 minute high-pressure test for the 
coiled tubing string. Your representative at the facility must certify 
that the charts are correct.
    (g) Operations log. The time, date, and results of all pressure 
tests, actuations, inspections, and crew drills of the BOP system, 
system components, and marine risers shall be recorded in the operations 
log. The BOP tests shall be documented in accordance with the following:
    (1) The documentation shall indicate the sequential order of BOP and 
auxiliary equipment testing and the pressure and duration of each test. 
As an alternate, the documentation in the operations log may reference a 
BOP test plan that contains the required information and is retained on 
file at the facility.
    (2) The control station used during the test shall be identified in 
the operations log. For a subsea system, the pod used during the test 
shall be identified in the operations log.
    (3) Any problems or irregularities observed during BOP and auxiliary 
equipment testing and any actions taken to remedy such problems or 
irregularities shall be noted in the operations log.
    (4) Documentation required to be entered in the operation log may 
instead be referenced in the operations log. All records including 
pressure charts, operations log, and referenced documents pertaining to 
BOP tests, actuations, and inspections, shall be available for BSEE 
review at the facility for the duration of well-workover activity. 
Following completion of the well-workover activity, all such records 
shall be retained for a period of 2 years at the facility, at the 
lessee's filed office nearest the OCS facility, or at another location 
conveniently available to the District Manager.
    (h) Stump test a subsea BOP system before installation. You must use 
water to conduct this test. You may use drilling or completion fluids to 
conduct subsequent tests of a subsea BOP system. You must perform the 
initial subsea BOP test on the seafloor within 30 days of the stump 
test. You must:
    (1) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. Each ROV must be fully compatible with the BOP 
stack ROV intervention panels. You must also test and verify closure of 
at least one set of rams during the initial test on the seafloor through 
an ROV hot stab. You must submit test procedures, including how you will 
test each ROV function, with your APM for BSEE District Manager 
approval. You must:
    (i) Ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams, one set of 
blind-shear rams, and unlatching the LMRP;
    (ii) Notify the appropriate BSEE District Manager a minimum of 72 
hours prior to the stump test and initial test on the seafloor;
    (iii) Document all your test results and make them available to BSEE 
upon request; and

[[Page 136]]

    (2) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system and 
verify closure of at least one set of blind-shear rams during the 
initial test on the seafloor. 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. You must:
    (i) Submit test procedures with your APM for BSEE District Manager 
approval. The procedures for these function tests must include 
documentation of the controls and circuitry of the system utilized 
during each test. The procedure must also describe how the ROV will be 
utilized during this operation.
    (ii) Document the results of each test and make them available to 
BSEE upon request.

[76 FR 64462, Oct. 18, 2011. Redesignated and amended at 77 FR 50895, 
50896, Aug. 22, 2012]



Sec. 250.618  What are my BOP inspection and maintenance requirements?

    (a) BOP inspections. (1) You must inspect your BOP system to ensure 
that the equipment functions properly. The BOP inspections must meet or 
exceed the provisions of Sections 17.10 and 18.10, Inspections, 
described in API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells (incorporated by reference as 
specified in Sec. 250.198). You must document how you met or exceeded 
the provisions of Sections 17.10 and 18.10 described in API RP 53, the 
procedures used, record the results, and make the records available to 
BSEE upon request. You must maintain your records on the rig for 2 years 
from the date the records are created, or for a longer period if 
directed by BSEE.
    (2) You must visually inspect your surface BOP system on a daily 
basis. You must visually inspect your subsea BOP system and marine riser 
at least once every 3 days if weather and sea conditions permit. You may 
use television cameras to inspect subsea equipment. The BSEE District 
Manager may approve alternate methods and frequencies to inspect a 
marine riser.
    (b) BOP maintenance. You must maintain your BOP system to ensure 
that the equipment functions properly. The BOP maintenance must meet or 
exceed the provisions of Sections 17.11 and 18.11, Maintenance; and 
Sections 17.12 and 18.12, Quality Management, described in API RP 53, 
Recommended Practices for Blowout Prevention Equipment Systems for 
Drilling Wells (incorporated by reference as specified in Sec. 
250.198). You must document how you met or exceeded the provisions of 
Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, 
Quality Management, described in API RP 53, the procedures used, record 
the results, and make the records available to BSEE upon request. You 
must maintain your records on the rig for 2 years from the date the 
records are created, or for a longer period if directed by BSEE.

[77 FR 50896, Aug. 22, 2012]



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) In the event of prolonged operations such as milling, fishing, 
jarring, or washing over that could damage the casing, the casing shall 
be pressure tested, calipered, or otherwise evaluated every 30 days and 
the results submitted to the District Manager.
    (c) 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).

[[Page 137]]

 
(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.
    (d) 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.
    (e) Subsurface safety equipment shall be installed, maintained, and 
tested in compliance with Sec. 250.801 of this part.

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



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 [Reserved]



             Subpart H_Oil and Gas Production Safety Systems



Sec. 250.800  General requirements.

    (a) Production safety equipment shall be designed, installed, used, 
maintained, and tested in a manner to assure the safety and protection 
of the human, marine, and coastal environments. Production safety 
systems operated in subfreezing climates shall utilize equipment and 
procedures selected with consideration of floating ice, icing, and other 
extreme environmental conditions that may occur in the area. Production 
shall not commence until the production safety system has been approved 
and a preproduction inspection has been requested by the lessee.
    (b) For all new floating production systems (FPSs) (e.g., column-
stabilized-units (CSUs); floating production, storage and offloading 
facilities (FPSOs); tension-leg platforms (TLPs); spars, etc.), you must 
do all of the following:
    (1) Comply with API RP 14J (as incorporated by reference in 30 CFR 
250.198);
    (2) Meet the drilling and production riser standards of API RP 2RD 
(as incorporated by reference in 30 CFR 250.198);
    (3) Design all stationkeeping systems for floating facilities to 
meet the standards of API RP 2SK (as incorporated by reference in 30 CFR 
250.198), as well as relevant U.S. Coast Guard regulations; and
    (4) Design stationkeeping systems for floating facilities to meet 
structural requirements in subpart I, Sec. Sec. 250.900 through 250.921 
of this part.



Sec. 250.801  Subsurface safety devices.

    (a) General. All tubing installations open to hydrocarbon-bearing 
zones

[[Page 138]]

shall be equipped with subsurface safety devices that will shut off the 
flow from the well in the event of an emergency unless, after 
application and justification, the well is determined by the District 
Manager to be incapable of natural flowing. These devices may consist of 
a surface-controlled subsurface safety valve (SSSV), a subsurface-
controlled SSSV, an injection valve, a tubing plug, or a tubing/annular 
subsurface safety device, and any associated safety valve lock or 
landing nipple.
    (b) Specifications for SSSVs. Surface-controlled and subsurface-
controlled SSSVs and safety valve locks and landing nipples installed in 
the OCS shall conform to the requirements in Sec. 250.806 of this part.
    (c) Surface-controlled SSSVs. All tubing installations open to a 
hydrocarbon-bearing zone which is capable of natural flow shall be 
equipped with a surface-controlled SSSV, except as specified in 
paragraphs (d), (f), and (g) of this section. The surface controls may 
be located on the site or a remote location. Wells not previously 
equipped with a surface-controlled SSSV and wells in which a surface-
controlled SSSV has been replaced with a subsurface-controlled SSSV in 
accordance with paragraph (d)(2) of this section shall be equipped with 
a surface-controlled SSSV when the tubing is first removed and 
reinstalled.
    (d) Subsurface-controlled SSSVs. Wells may be equipped with 
subsurface-controlled SSSVs in lieu of a surface-controlled SSSV 
provided the lessee demonstrates to the District Manager's satisfaction 
that one of the following criteria are met:
    (1) Wells not previously equipped with surface-controlled SSSVs 
shall be so equipped when the tubing is first removed and reinstalled,
    (2) The subsurface-controlled SSSV is installed in wells completed 
from a single-well or multiwell satellite caisson or seafloor 
completions, or
    (3) The subsurface-controlled SSSV is installed in wells with a 
surface-controlled SSSV that has become inoperable and cannot be 
repaired without removal and reinstallation of the tubing.
    (e) Design, installation, and operation of SSSVs. The SSSVs shall be 
designed, installed, operated, and maintained to ensure reliable 
operation.
    (1) The device shall be installed at a depth of 100 feet or more 
below the seafloor within 2 days after production is established. When 
warranted by conditions such as permafrost, unstable bottom conditions, 
hydrate formation, or paraffins, an alternate setting depth of the 
subsurface safety device may be approved by the District Manager.
    (2) Until a subsurface safety device is installed, the well shall be 
attended in the immediate vicinity so that emergency actions may be 
taken while the well is open to flow. During testing and inspection 
procedures, the well shall not be left unattended while open to 
production unless a properly operating subsurface-safety device has been 
installed in the well.
    (3) The well shall not be open to flow while the subsurface safety 
device is removed, except when flowing of the well is necessary for a 
particular operation such as cutting paraffin, bailing sand, or similar 
operations.
    (4) All SSSVs must be inspected, installed, maintained, and tested 
in accordance with American Petroleum Institute Recommended Practice 
14B, Recommended Practice for Design, Installation, Repair, and 
Operation of Subsurface Safety Valve Systems (as specified in Sec. 
250.198).
    (f) Subsurface safety devices in shut-in wells. (1) New completions 
(perforated but not placed on production) and completions shut in for a 
period of 6 months shall be equipped with either--
    (i) A pump-through-type tubing plug;
    (ii) A surface-controlled SSSV, provided the surface control has 
been rendered inoperative; or
    (iii) An injection valve capable of preventing backflow.
    (2) The setting depth of the subsurface safety device shall be 
approved by the District Manager on a case-by-case basis, when warranted 
by conditions such as permafrost, unstable bottom conditions, hydrate 
formations, and paraffins.
    (g) Subsurface safety devices in injection wells. A surface-
controlled SSSV or an injection valve capable of preventing backflow 
shall be installed in all injection wells. This requirement is not 
applicable if the District Manager

[[Page 139]]

concurs that the well is incapable of flowing. The lessee shall verify 
the no-flow condition of the well annually.
    (h) Temporary removal for routine operations. (1) Each wireline- or 
pumpdown-retrievable subsurface safety device may be removed, without 
further authorization or notice, for a routine operation which does not 
require the approval of a Form BSEE-0124, Application for Permit to 
Modify, in Sec. 250.601 of this part for a period not to exceed 15 
days.
    (2) The well shall be identified by a sign on the wellhead stating 
that the subsurface safety device has been removed. The removal of the 
subsurface safety device shall be noted in the records as required in 
Sec. 250.804(b) of this part. If the master valve is open, a trained 
person shall be in the immediate vicinity of the well to attend the well 
so that emergency actions may be taken, if necessary.
    (3) A platform well shall be monitored, but a person need not 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 or a pump-through 
plug installed in the tubing at least 100 feet below the mud line and 
the master valve closed, unless otherwise approved by the District 
Manager.
    (4) The well shall not be allowed to flow while the subsurface 
safety device is removed, except when flowing the well is necessary for 
that particular operation. The provisions of this paragraph are not 
applicable to the testing and inspection procedures in Sec. 250.804 of 
this part.
    (i) Additional safety equipment. All tubing installations in which a 
wireline- or pumpdown-retrievable subsurface safety device is installed 
after the effective date of this subpart shall be equipped with a 
landing nipple with flow couplings or other protective equipment above 
and below to provide for the setting of the SSSV. The control system for 
all surface-controlled SSSVs shall be an integral part of the platform 
Emergency Shutdown System (ESD). 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 shall close in 
response to shut-in signals from the ESD and in response to the fire 
loop or other fire detection devices.
    (j) Emergency action. In the event of an emergency, such as an 
impending storm, any well not equipped with a subsurface safety device 
and which is capable of natural flow shall have the device properly 
installed as soon as possible with due consideration being given to 
personnel safety.



Sec. 250.802  Design, installation, and operation of surface production-safety 

systems.

    (a) General. All production facilities, including separators, 
treaters, compressors, headers, and flowlines shall be designed, 
installed, and maintained in a manner which provides for efficiency, 
safety of operation, and protection of the environment.
    (b) Platforms. 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 API RP 14C (as incorporated by reference 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 therein to determine the effects 
and requirements of these components on the safety system. Safety device 
requirements for pipelines are under Sec. 250.1004.
    (c) Specification for surface safety valves (SSV) and underwater 
safety valves (USV). All wellhead SSVs, USVs, and their actuators which 
are installed in the OCS shall conform to the requirements in Sec. 
250.806 of this part.
    (d) Use of SSVs and USV's. All SSVs and USVs must be inspected, 
installed, maintained, and tested in accordance with API RP 14H, 
Recommended Practice for Installation, Maintenance, and Repair of 
Surface Safety Valves and Underwater Safety Valves Offshore (as 
incorporated by reference in Sec. 250.198). If any SSV or USV does not 
operate properly or if any fluid flow is observed during the leakage 
test, the valve shall be repaired or replaced.

[[Page 140]]

    (e) Approval of safety-systems design and installation features. 
Prior to installation, the lessee shall submit, in duplicate for 
approval to the District Manager a production safety system application 
containing information relative to design and installation features. 
Information concerning approved design and installation features shall 
be maintained by the lessee at the lessee's offshore field office 
nearest the OCS facility or other location conveniently available to the 
District Manager. All approvals are subject to field verifications. The 
application shall include the following:
    (1) A schematic flow diagram showing tubing pressure, size, 
capacity, design working pressure of separators, flare scrubbers, 
treaters, storage tanks, compressors, pipeline pumps, metering devices, 
and other hydrocarbon-handling vessels.
    (2) A schematic piping flow diagram (API RP 14C, Figure E, as 
incorporated by reference in Sec. 250.198) and the related Safety 
analysis Function Evaluation chart (API RP 14C, subsection 4.3c, as 
incorporated by reference in Sec. 250.198).
    (3) A schematic piping diagram showing the size and maximum 
allowable working pressures as determined in accordance with API RP 14E, 
Design and Installation of Offshore Production Platform Piping Systems 
(as incorporated by reference in Sec. 250.198).
    (4) Electrical system information including the following:
    (i) A plan for each platform deck outlining all hazardous areas 
classified 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, 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), and 
outlining areas in which potential ignition sources, other than 
electrical, are to be installed. The area outlined will include the 
following information:
    (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) Location of generators, control rooms, panel boards, major 
cabling/conduit routes, and identification of the primary wiring method 
(e.g., type cable, conduit, or wire).
    (ii) Elementary electrical schematic of any platform safety shut-
down system with a functional legend.
    (5) Certification that the design for the mechanical and electrical 
systems to be installed were approved by registered professional 
engineers. After these systems are installed, the lessee shall submit a 
statement to the District Manager certifying that new installations 
conform to the approved designs of this subpart.
    (6) The design and schematics of the installation and maintenance of 
all fire- and gas-detection systems shall include the following:
    (i) Type, location, and number of detection sensors;
    (ii) Type and kind of alarms, including emergency equipment to be 
activated;
    (iii) Method used for detection;
    (iv) Method and frequency of calibration; and
    (v) A functional block diagram of the detection system, including 
the electric power supply.
    (7) The service fee listed in Sec. 250.125. The fee you must pay 
will be determined by the number of components involved in the review 
and approval process.



Sec. 250.803  Additional production system requirements.

    (a) For all production platforms, you must comply with the following 
production safety system requirements, in addition to the requirements 
of Sec. 250.802 of this subpart and the requirements of API RP 14C (as 
incorporated by reference in Sec. 250.198).
    (b) Design, installation, and operation of additional production 
systems--(1) Pressure and fired vessels. Pressure and fired vessels must 
be designed, fabricated, and code stamped in accordance with the 
applicable provisions of Sections I, IV, and VIII of the American 
Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. 
Pressure and fired vessels must

[[Page 141]]

have maintenance inspection, rating, repair, and alteration performed in 
accordance with the applicable provisions of API Pressure Vessel 
Inspections Code: In-Service Inspection, Rating, Repair, and Alteration, 
API 510 (except Sections 5.8 and 9.5) (as incorporated by reference in 
Sec. 250.198).
    (i) Pressure relief valves shall be designed, installed, and 
maintained in accordance with applicable provisions of sections I, IV, 
and VIII of the ASME Boiler and Pressure Vessel Code. The relief valves 
shall conform to the valve-sizing and pressure-relieving requirements 
specified in these documents; however, the relief valves, except 
completely redundant relief valves, shall be set no higher than the 
maximum-allowable working pressure of the vessel. All relief valves and 
vents shall be piped in such a way as to prevent fluid from striking 
personnel or ignition sources.
    (ii) Steam generators operating at less than 15 pounds per square 
inch gauge (psig) shall be equipped with a level safety low (LSL) sensor 
which will shut off the fuel supply when the water level drops below the 
minimum safe level. Steam generators operating at greater than 15 psig 
require, in addition to an LSL, a water-feeding device which will 
automatically control the water level.
    (iii) The lessee shall use pressure recorders to establish the new 
operating pressure ranges of pressure vessels at any time when there is 
a change in operating pressures that requires new settings for the high-
pressure shut-in sensor and/or the low-pressure shut-in sensor as 
provided herein. The pressure-recorder charts used to determine current 
operating pressure ranges shall be maintained at the lessee's field 
office nearest the OCS facility or at other locations conveniently 
available to the District Manager. The high-pressure shut-in sensor 
shall be set no higher than 15 percent or 5 psi, whichever is greater, 
above the highest operating pressure of the vessel. This setting shall 
also be set sufficiently below (5 percent or 5 psi, whichever is 
greater) the relief valve's set pressure to assure that the pressure 
source is shut in before the relief valve activates. The low-pressure 
shut-in sensor shall activate no lower than 15 percent or 5 psi, 
whichever is greater, below the lowest pressure in the operating range. 
The activation of low-pressure sensors on pressure vessels which operate 
at less than 5 psi shall be approved by the District Manager on a case-
by-case basis.
    (2) Flowlines. (i) You must equip flowlines from wells with high- 
and low-pressure shut-in sensors located in accordance with section A.1 
and Figure A1 of API RP 14C (as incorporated by reference in Sec. 
250.198). The lessee shall use pressure recorders to establish the new 
operating pressure ranges of flowlines at any time when there is a 
significant change in operating pressures. The most recent pressure-
recorder charts used to determine operating pressure ranges shall be 
maintained at the lessee's field office nearest the OCS facility or at 
other locations conveniently available to the District Manager. The 
high-pressure shut-in sensor(s) shall be set no higher than 15 percent 
or 5 psi, whichever is greater, above the highest operating pressure of 
the line. But in all cases, it shall be set sufficiently below the 
maximum shut-in wellhead pressure or the gas-lift supply pressure to 
assure actuation of the SSV. The low-pressure shut-in sensor(s) shall be 
set no lower than 15 percent or 5 psi, whichever is greater, below the 
lowest operating pressure of the line in which it is installed.
    (ii) If a well flows directly to the pipeline before separation, the 
flowline and valves from the well located upstream of and including the 
header inlet valve(s) shall 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:
    (A) A relief valve which vents into the platform flare scrubber or 
some other location approved by the District Manager. The platform flare 
scrubber shall be designed to handle, without liquid-hydrocarbon 
carryover to the flare, the maximum-anticipated flow of liquid 
hydrocarbons which may be relieved to the vessel.
    (B) Two SSV's with independent high-pressure sensors installed with 
adequate volume upstream of any block valve to allow sufficient time for

[[Page 142]]

the valve(s) to close before exceeding the maximum allowable working 
pressure.
    (iii) If you are installing flowlines constructed of unbonded 
flexible pipe on a floating platform, you must:
    (A) 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 (as 
incorporated by reference in Sec. 250.198);
    (B) Determine that the unbonded flexible pipe is suitable for its 
intended purpose on the lease or pipeline right-of-way;
    (C) Submit to the BSEE District Manager the manufacturer's design 
specifications for the unbonded flexible pipe; and
    (D) Submit to the BSEE 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 (as incorporated by 
reference in Sec. 250.198).
    (3) Safety sensors. All shutdown devices, valves, and pressure 
sensors shall function in a manual reset mode. Sensors with integral 
automatic reset shall be equipped with an appropriate device to override 
the automatic reset mode. All pressure sensors shall be equipped to 
permit testing with an external pressure source.
    (4) ESD. The ESD must conform to the requirements of Appendix C, 
section C1, of API RP 14C (as incorporated by reference in Sec. 
250.198), and the following:
    (i) The manually operated ESD valve(s) shall be quick-opening and 
nonrestricted to enable the rapid actuation of the shutdown system. Only 
ESD stations at the boat landing may utilize a loop of breakable 
synthetic tubing in lieu of a valve.
    (ii) Closure of the SSV shall not exceed 45 seconds after automatic 
detection of an abnormal condition or actuation of an ESD. The surface-
controlled SSSV shall close in not more than 2 minutes after the shut-in 
signal has closed the SSV. Design-delayed closure time greater than 2 
minutes shall be justified by the lessee based on the individual well's 
mechanical/production characteristics and be approved by the District 
Manager.
    (iii) A schematic of the ESD which indicates the control functions 
of all safety devices for the platforms shall be maintained by the 
lessee on the platform or at the lessee's field office nearest the OCS 
facility or other location conveniently available to the District 
Manager.
    (5) Engines: (i) Engine exhaust. You must equip engine exhausts to 
comply with the insulation and personnel protection requirements of API 
RP 14C, section 4.2c(4) (as incorporated by reference in Sec. 250.198). 
Exhaust piping from diesel engines must be equipped with spark 
arresters.
    (ii) Diesel engine air intake. All diesel engine air intakes must be 
equipped with a device to shutdown 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.
    (6) Glycol dehydration units. A pressure relief system or an 
adequate vent shall be installed on the glycol regenerator (reboiler) 
which will prevent overpressurization. The discharge of the relief valve 
shall be vented in a nonhazardous manner.
    (7) Gas compressors. You must equip compressor installations with 
the following protective equipment as required in API RP 14C, Sections 
A4 and A8 (as incorporated by reference in Sec. 250.198).
    (i) A Pressure Safety High (PSH), a Pressure Safety Low (PSL), a 
Pressure Safety Valve (PSV), and a Level Safety High (LSH), and an LSL 
to protect each interstage and suction scrubber.
    (ii) A Temperature Safety High (TSH) on each compressor discharge 
cylinder.
    (iii) The PSH and PSL shut-in sensors and LSH shut-in controls 
protecting compressor suction and interstage scrubbers shall be 
designated to actuate automatic shutdown valves (SDV) located in each 
compressor suction and fuel gas line so

[[Page 143]]

that the compressor unit and the associated vessels can be isolated from 
all input sources. All automatic SDV's installed in compressor suction 
and fuel gas piping shall 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 a compressor suction 
shall be diverted to the pipeline or shut in at the wellhead.
    (iv) A blowdown valve is required on the discharge line of all 
compressor installations of 1,000 horsepower (746 kilowatts) or greater.
    (8) Firefighting systems. Firefighting systems for both open and 
totally enclosed platforms installed for extreme weather conditions or 
other reasons shall conform to subsection 5.2, Firewater systems, of API 
RP 14G (as incorporated by reference in Sec. 250.198), Fire Prevention 
and Control Open Type Offshore Production Platforms, and shall require 
approval of the District Manager. The following additional requirements 
shall apply for both open- and closed-production platforms:
    (i) A firewater system consisting of rigid pipe with firehose 
stations or fixed firewater monitors shall be installed. The firewater 
system shall be installed to provide needed protection in all areas 
where production-handling equipment is located. A fixed waterspray 
system shall be installed in enclosed well-bay areas where hydrocarbon 
vapors may accumulate.
    (ii) Fuel or power for firewater pump drivers shall be available for 
at least 30 minutes of run time during a platform shut-in. If necessary, 
an alternate fuel or power supply shall be installed to provide for this 
pump-operating time unless an alternate firefighting system has been 
approved by the District Manager.
    (iii) A firefighting system using chemicals may be used in lieu of a 
water system if the District Manager determines that the use of a 
chemical system provides equivalent fire-protection control.
    (iv) A diagram of the firefighting system showing the location of 
all firefighting equipment shall be posted in a prominent place on the 
facility or structure.
    (v) For operations in subfreezing climates, the lessee shall furnish 
evidence to the District Manager that the firefighting system is 
suitable for the conditions.
    (9) Fire- and gas-detection system. (i) Fire (flame, heat, or smoke) 
sensors shall be installed in all enclosed classified areas. Gas sensors 
shall be installed in all inadequately ventilated, enclosed classified 
areas. Adequate ventilation is defined as ventilation which is 
sufficient to prevent accumulation of significant quantities of vapor-
air mixture in concentrations over 25 percent of the lower explosive 
limit (LEL). One approved method of providing adequate ventilation is 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. 
Enclosed areas (e.g., buildings, living quarters, or doghouses) are 
defined as those areas confined on more than four of their six possible 
sides by walls, floors, or ceilings more restrictive to air flow than 
grating or fixed open louvers and of sufficient size to all entry of 
personnel. A classified area is any area classified Class I, Group D, 
Division 1 or 2, following the guidelines of API RP 500 (as incorporated 
by reference in Sec. 250.198), or any area classified Class I, Zone 0, 
Zone 1, or Zone 2, following the guidelines of API RP 505 (as 
incorporated by reference in Sec. 250.198).
    (ii) All detection systems shall be capable of continuous 
monitoring. Fire-detection systems and portions of combustible gas-
detection systems related to the higher gas concentration levels shall 
be of the manual-reset type. Combustible gas-detection systems related 
to the lower gas-concentration level may be of the automatic-reset type.
    (iii) 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. Living quarters and doghouses 
not containing a gas source and not located in a classified area do not 
require a gas detection system.
    (iv) The District Manager may require the installation and 
maintenance of a gas detector or alarm in any potentially hazardous 
area.

[[Page 144]]

    (v) Fire- and gas-detection systems must be an approved type, 
designed and installed according to API RP 14C, API RP 14G, and either 
API RP 14F or API RP 14FZ (the preceding four documents as incorporated 
by reference in Sec. 250.198).
    (10) Electrical equipment. Electrical equipment and systems shall be 
designed, installed, and maintained in accordance with the requirements 
in Sec. 250.114 of this part.
    (11) Erosion. A program of erosion control shall be in effect for 
wells or fields having a history of sand production. The erosion-control 
program may include sand probes, X-ray, ultrasonic, or other 
satisfactory monitoring methods. Records by lease, indicating the wells 
which have erosion-control programs in effect and the results of the 
programs, shall be maintained by the lessee for a period of 2 years and 
shall be made available to BSEE upon request.
    (c) General platform operations. (1) Surface or subsurface safety 
devices shall not be bypassed or blocked out of service unless they are 
temporarily out of service for startup, maintenance, or testing 
procedures. Only the minimum number of safety devices shall be taken out 
of service. Personnel shall 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 
shall be flagged.
    (2) When wells are disconnected from producing facilities and blind 
flanged, 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 (as incorporated by reference in Sec. 250.198) or this 
regulation concerning the following:
    (i) Automatic fail-close SSV's on wellhead assemblies, and
    (ii) The PSH and PSL shut-in sensors in flowlines from wells.
    (3) When pressure or atmospheric vessels are isolated from 
production facilities (e.g., inlet valve locked closed or inlet blind-
flanged) and are to remain isolated for an extended period of time, 
safety device compliance with API RP 14C or this subpart is not 
required.
    (4) All open-ended lines connected to producing facilities and wells 
shall be plugged or blind-flanged, except those lines designed to be 
open-ended such as flare or vent lines.
    (d) Welding and burning practices and procedures. All welding, 
burning, and hot-tapping activities shall be conducted according to the 
specific requirements in Sec. Sec. 250.109 through 250.113 of this 
part.



Sec. 250.804  Production safety-system testing and records.

    (a) Inspection and testing. The safety-system devices shall be 
successfully inspected and tested by the lessee at the interval 
specified below or more frequently if operating conditions warrant. 
Testing must be in accordance with API RP 14C, Appendix D (as 
incorporated by reference in Sec. 250.198), and the following:
    (1) Testing requirements for subsurface safety devices are as 
follows:
    (i) Each surface-controlled subsurface safety device installed in a 
well, including such devices in shut-in and injection wells, shall be 
tested in place for proper operation when installed or reinstalled and 
thereafter at intervals not exceeding 6 months. If the device does not 
operate properly, or if a liquid leakage rate in excess of 200 cubic 
centimeters per minute or a gas leakage rate in excess of 5 cubic feet 
per minute is observed, the device shall be removed, repaired and 
reinstalled, or replaced. Testing shall be in accordance with API RP 14B 
(as incorporated by reference in Sec. 250.198) to ensure proper 
operation.
    (ii) Each subsurface-controlled SSSV installed in a well shall be 
removed, inspected, and repaired or adjusted, as necessary, and 
reinstalled or replaced at intervals not exceeding 6 months for those 
valves not installed in a landing nipple and 12 months for those valves 
installed in a landing nipple.
    (iii) Each tubing plug installed in a well shall be inspected for 
leakage by opening the well to possible flow at intervals not exceeding 
6 months. If a liquid leakage rate in excess of 200 cubic centimeters 
per minute or a gas leakage rate in excess of 5 cubic feet per minute is 
observed, the device shall be removed, repaired and reinstalled, or 
replaced. An additional tubing plug may be installed in lieu of removal.

[[Page 145]]

    (iv) Injection valves shall be tested in the manner as outlined for 
testing tubing plugs in paragraph (a)(1)(iii) of this section. Leakage 
rates outlined in paragraph (a)(1)(iii) of this section shall apply.
    (2) All PSV's shall be tested for operation at least once every 12 
months. These valves shall be either bench-tested or equipped to permit 
testing with an external pressure source. Weighted disk vent valves used 
as PSV's on atmospheric tanks may be disassembled and inspected in lieu 
of function testing.
    (3) The following safety devices (excluding electronic pressure 
transmitters and level sensors) must be tested at least once each 
calendar month, but at no time will more than 6 weeks elapse between 
tests:
    (i) All PSH and PSL,
    (ii) All LSH and LSL controls,
    (iii) All automatic inlet SDV's which are actuated by a sensor on a 
vessel or compressor, and
    (iv) All SDV's in liquid discharge lines and actuated by vessel low-
level sensors.
    (4) The following electronic pressure transmitters and level sensors 
must be tested at least once every 3 months, but at no time may more 
than 120 days elapse between tests:
    (i) All PSH and PSL, and
    (ii) All LSH and LSL controls.
    (5) All SSV's and USV's shall be tested for operation and for 
leakage at least once each calendar month, but at no time shall more 
than 6 weeks elapse between tests. The SSV's and USV's must be tested in 
accordance with the test procedures specified in API RP 14H (as 
incorporated by reference in Sec. 250.198). If the SSV or USV does not 
operate properly or if any fluid flow is observed during the leakage 
test, the valve shall be repaired or replaced.
    (6) All flowline Flow Safety Valves (FSV) shall be checked for 
leakage at least once each calendar month, but at no time shall more 
than 6 weeks elapse between tests. The FSV's must be tested for leakage 
in accordance with the test procedures specified in API RP 14C, Appendix 
D, section D4, table D2, subsection D (as incorporated by reference in 
Sec. 250.198). If the leakage measured exceeds a liquid flow of 200 
cubic centimeters per minute or a gas flow of 5 cubic feet per minute, 
the FSV's shall be repaired or replaced.
    (7) The TSH shutdown controls installed on compressor installations 
which can be nondestructively tested shall be tested every 6 months and 
repaired or replaced as necessary.
    (8) All pumps for firewater systems shall be inspected and operated 
weekly.
    (9) All fire- (flame, heat, or smoke) detection systems shall be 
tested for operation and recalibrated every 3 months provided that 
testing can be performed in a nondestructive manner. Open flame or 
devices operating at temperatures which could ignite a methane-air 
mixture shall not be used. All combustible gas-detection systems shall 
be calibrated every 3 months.
    (10) All TSH devices shall be tested at least once every 12 months, 
excluding those addressed in paragraph (a)(7) of this section and those 
which would be destroyed by testing. Burner safety low and flow safety 
low devices shall also be tested at least once every 12 months.
    (11) The ESD shall be tested for operation at least once each 
calendar month, but at no time shall more than 6 weeks elapse between 
tests. The test shall be conducted 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.
    (12) Prior to the commencement of production, the lessee shall 
notify the District Manager when the lessee is ready to conduct a 
preproduction test and inspection of the integrated safety system. The 
lessee shall also notify the District Manager upon commencement of 
production in order that a complete inspection may be conducted.
    (b) Records. The lessee shall maintain records for a period of 2 
years for each subsurface and surface safety device installed. These 
records shall be maintained by the lessee at the lessee's field office 
nearest the OCS facility or other locations conveniently available to 
the District Manager. These records shall be available for review by a 
representative of BSEE. The records shall show the present status and 
history of each device, including dates and details of

[[Page 146]]

installation, removal, inspection, testing, repairing, adjustments, and 
reinstallation.



Sec. 250.805  Safety device training.

    Personnel installing, inspecting, testing, and maintaining these 
safety devices and personnel operating the production platforms shall be 
qualified in accordance with 30 CFR 250, subpart O.



Sec. 250.806  Safety and pollution prevention equipment quality assurance 

requirements.

    (a) General requirements. (1) Except as provided in paragraph (b)(1) 
of this section, you may install only certified safety and pollution 
prevention equipment (SPPE) in wells located on the OCS. SPPE includes 
the following:
    (i) Surface safety valves (SSV) and actuators;
    (ii) Underwater safety valves (USV) and actuators; and
    (iii) Subsurface safety valves (SSSV) and associated safety valve 
locks and landing nipples.
    (2) Certified SPPE is equipment the manufacturer certifies as 
manufactured under a quality assurance program BSEE recognizes. BSEE 
considers all other SPPE as noncertified. BSEE recognizes two quality 
assurance programs:
    (i) ANSI/ASME SPPE-1-1994 and SPPE-1d-1996 Addenda, Quality 
Assurance and Certification of Safety and Pollution Prevention Equipment 
Used in Offshore Oil and Gas Operations (as incorporated by reference in 
Sec. 250.198); and
    (ii) API Spec Q1, Specification for Quality Programs for the 
Petroleum, Petrochemical and Natural Gas Industry (as incorporated by 
reference in Sec. 250.198).
    (3) All SSV's and USV's must meet the technical specifications of 
API Spec 6A and 6AV1. All SSSVs must meet the technical specifications 
of API Specification 14A (as incorporated by reference in Sec. 
250.198). However, SSSVs and related equipment planned to be used in 
high pressure high temperature environments must meet the additional 
requirements set forth in Sec. 250.807.
    (4) For information on all standards mentioned in this section, see 
Sec. 250.198.
    (b) Use of noncertified SPPE. (1) Before April 1, 1998, you may 
continue to use and install noncertified SPPE if it was in your 
inventory as of April 1, 1988, and was included in a list of 
noncertified SPPE submitted to BSEE prior to August 29, 1988.
    (2) On or after April 1, 1998:
    (i) You may not install additional noncertified SPPE; and
    (ii) When noncertified SPPE that is already in service requires 
offsite repair, remanufacturing, or hot work such as welding, you must 
replace it with certified SPPE.
    (c) Recognizing other quality assurance programs. The BSEE will 
consider recognizing other quality assurance programs covering the 
manufacture of SPPE. If you want BSEE to evaluate other quality 
assurance programs, submit relevant information about the program and 
reasons for recognition by BSEE to the Chief, Office of Offshore 
Regulatory Programs; Bureau of Safety and Environmental Enforcement; MS-
4020; 381 Elden Street, Herndon, Virginia 20170-4817.



Sec. 250.807  Additional requirements for subsurface safety valves 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), Application for Permit to Modify (APM), or 
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 analysis;
    (2) A discussion of the SSSVs' and related equipment's design 
validation and functional testing process and procedures used; and
    (3) An explanation of why the analysis, process, and procedures 
ensure that the SSSVs and related equipment are fit-for-service in the 
applicable HPHT environment.

[[Page 147]]

    (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 psig 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 psig 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. 250.808  Hydrogen sulfide.

    Production operations 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, shall be conducted in 
accordance with that section and other relevant requirements of subpart 
H, Production Safety Systems.



                   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.
    (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.

[[Page 148]]

 
(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 Sec. Sec. 
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 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);

[[Page 149]]

    (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);
    (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.
    (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;

[[Page 150]]

 
(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
------------------------------------------------------------------------



Sec. 250.902  What are the requirements for platform removal and location 

clearance?

    You must remove all structures according to Sec. Sec. 250.1725 
through 250.1730 of Subpart Q--Decommissioning Activities of this part.



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 Sec. Sec. 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.

[[Page 151]]

    (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 
Sec. Sec. 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.
(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
                               elevations relative   11x17x17
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

[[Page 153]]

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;
    (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 analysis
 redundancy to prevent catastrophic          must indicate a maximum
 failure of the platform or structure        calculated life of twice
 under consideration,                        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

[[Page 154]]

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.

                      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 Sec. Sec. 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:

------------------------------------------------------------------------
                 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.

[[Page 155]]



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 Sec. Sec. 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 Sec. Sec. 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 Sec. Sec. 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.



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.

[[Page 156]]

    (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.
    (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 Sec. Sec. 
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.

[[Page 157]]

    (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;
    (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

[[Page 158]]

 
                                                      (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.



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 Sec.
 Sec.  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

[[Page 159]]

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.
    (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 Sec. Sec. 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, or inadequate deck height your 
platform 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.

[[Page 160]]

    (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.



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.



             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 Sec. Sec. 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 by April 14, 1999, or the date a 
pipeline begins service, whichever is later.
    (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 by April 14, 1999, the BSEE Regional Supervisor and 
the Department of Transportation (DOT) Office of Pipeline Safety (OPS) 
Regional Director may jointly determine the transfer point.
    (4) The transfer point serves as a regulatory boundary. An operator 
may write to the BSEE Regional Supervisor to request an exception to 
this requirement for an individual facility or area. The Regional 
Supervisor, in consultation with the OPS Regional Director and affected 
parties, may grant the request.

[[Page 161]]

    (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 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 Office of Pipeline Safety 
(OPS) Regional Director.
    (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 OPS Regional Director and the BSEE Regional Supervisor.
    (ii) The BSEE Regional Supervisor and the OPS Regional Director 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).

[[Page 162]]



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.
    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.

[[Page 163]]

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 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

[[Page 164]]

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.
    (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

[[Page 165]]

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.
    (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 Sec. Sec.
                                                       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.

[[Page 166]]

    (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.
    (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-

[[Page 167]]

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 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 Sec. Sec. 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.

[[Page 168]]

    (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 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,

[[Page 169]]

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 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

[[Page 170]]

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 in Employment form (YN 
3341-1 dated July 1982). These forms are available at each BSEE regional 
office.
    (e) Notwithstanding the provisions of paragraph (a) of this section, 
the requirements to pay filing fees under that paragraph are suspended 
until January 3, 2006.



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.

[[Page 171]]

    (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.
    (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.
    (c) Notwithstanding the provisions of paragraph (b) of this section, 
the requirement to pay a filing fee under

[[Page 172]]

that paragraph is suspended until January 3, 2006.



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 Sec. Sec. 
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.
------------------------------------------------------------------------

    (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 Sec. Sec. 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 [deg]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.

[[Page 173]]



Sec. Sec. 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
    (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

[[Page 174]]

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.
(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.
------------------------------------------------------------------------


[[Page 175]]

    (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:
    (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

[[Page 176]]

    (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.
    (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 

H2S?

    (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 Sec. Sec. 250.1160, 250.1161, 250.1163, and the 
following additional requirements:

[[Page 177]]

    (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 from a reservoir. The proposed plan must include, for 
each project reservoir, a geologic and engineering overview, Form BOEM-
0127, and supporting data as required in Sec. 250.1167, 30 CFR 
550.1167, and any additional information required by the BSEE Regional 
Supervisor.
    (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.



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,    ...............        [bcheck]         [bcheck]         [bcheck]
     and completion locations with respect
     to the unit or lease line and the
     orientation of representative seismic
     lines or cross-sections................

[[Page 178]]

 
    (2) Structure maps with penetration             [bcheck]         [bcheck]         [bcheck]         [bcheck]
     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  ...............        [bcheck]         [bcheck]
     penetrated for each well, identified at
     the penetration point..................
    (4) Net hydrocarbon isopach with net      ...............        [bcheck]         [bcheck]
     feet of pay for each well, identified
     at the penetration point...............
(b) Seismic data:
    (1) Representative seismic lines,         ...............        [bcheck]         [bcheck]         [bcheck]
     including strike and dip lines that
     confirm the structure; indicate
     polarity...............................
    (2) Amplitude extraction of seismic       ...............        [bcheck]         [bcheck]         [bcheck]
     horizon, if applicable.................
(c) Logs:
    (1) Well log sections with tops and             [bcheck]         [bcheck]         [bcheck]         [bcheck]
     bottoms of the reservoir(s) and
     proposed or existing perforations......
    (2) Structural cross-sections showing     ...............        [bcheck]         [bcheck]                *
     the subject well and nearby wells......
(d) Engineering data:
    (1) Estimated recoverable reserves for    ...............        [dagger]         [dagger]         [bcheck]
     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   ...............        [bcheck]         [bcheck]         [bcheck]
     proposed conditions....................
    (3) The drive mechanism of each           ...............        [bcheck]         [bcheck]         [bcheck]
     reservoir..............................
    (4) Pressure data, by date, and whether   ...............        [bcheck]         [bcheck]
     they are estimated or measured.........
    (5) Production data and decline curve     ...............        [bcheck]         [bcheck]
     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  ...............        [bcheck]         [bcheck]         [bcheck]
     is competitive as defined under Sec.
     250.105................................
    (3) Operator name, lessee name(s),        ...............        [bcheck]         [bcheck]         [bcheck]
     block, lease number, royalty rate, and
     unit number (if applicable) of all
     relevant leases........................
    (4) Geologic overview of project........  ...............        [bcheck]         [bcheck]         [bcheck]
    (5) Explanation of why the proposed       ...............        [bcheck]         [bcheck]         [bcheck]
     completion scenario will maximize
     ultimate recovery......................
    (6) List of all wells in subject          ...............        [bcheck]         [bcheck]         [bcheck]
     reservoirs that have ever produced or
     been used for injection................
----------------------------------------------------------------------------------------------------------------
[bcheck] Required.
[dagger] 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.

[[Page 179]]



------------------------------------------------------------------------
            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)
------------------------------------------------------------------------



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 
[deg]F) to 60.5 degrees Fahrenheit (60.5 [deg]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.

[[Page 180]]

    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.
    Standard conditions--atmospheric pressure of 14.73 pounds per square 
inch absolute (psia) and 60 [deg]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 [deg]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

[[Page 181]]

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);
    (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

[[Page 182]]

    (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 meters, ensure that the run tickets clearly identify 
all observed data, all correction factors not included in the meter 
factor, and the net standard volume.
    (2) For royalty tanks, ensure that the run tickets clearly identify 
all observed data, all applicable correction factors, on/off seal 
numbers, and the net standard volume.
    (3) Pull a run ticket at the beginning of the month and immediately 
after establishing the monthly meter factor or a malfunction meter 
factor.
    (4) Send all run tickets for royalty meters and tanks to the 
Regional Supervisor within 15 days after the end of the month;
    (d) What are the requirements for liquid hydrocarbon royalty meter 
provings? You must:
    (1) Permit BSEE representatives to witness provings;
    (2) Ensure that the integrity of the prover calibration is traceable 
to test measures certified by the National Institute of Standards and 
Technology;
    (3) Prove each operating royalty meter to determine the meter factor 
monthly, but the time between meter factor determinations must not 
exceed 42 days. When a force majeure event precludes the required 
monthly meter proving, meters must be proved within 15 days after being 
returned to service. The meters must be proved monthly thereafter, but 
the time between meter factor determinations must not exceed 42 days;
    (4) Obtain approval from the Regional Supervisor before proving on a 
schedule other than monthly; and
    (5) Submit copies of all meter proving reports for royalty meters to 
the Regional Supervisor monthly within 15 days after the end of the 
month.
    (e) What are the requirements for calibrating a master meter used in 
royalty meter provings? You must:
    (1) Calibrate the master meter to obtain a master meter factor 
before using it to determine operating meter factors;
    (2) Use a fluid of similar gravity, viscosity, temperature, and flow 
rate as the liquid hydrocarbons that flow through the operating meter to 
calibrate the master meter;
    (3) Calibrate the master meter monthly, but the time between 
calibrations must not exceed 42 days;
    (4) Calibrate the master meter by recording runs until the results 
of two consecutive runs (if a tank prover is used) or five out of six 
consecutive runs (if a mechanical-displacement prover is used) produce 
meter factor differences of no greater than 0.0002. Lessees must use the 
average of the two (or the five) runs that produced acceptable results 
to compute the master meter factor;
    (5) Install the master meter upstream of any back-pressure or 
reverse flow check valves associated with the operating meter. However, 
the master meter may be installed either upstream or downstream of the 
operating meter; and
    (6) Keep a copy of the master meter calibration report at your field 
location for 2 years.
    (f) What are the requirements for calibrating mechanical-
displacement provers and tank provers? You must:
    (1) Calibrate mechanical-displacement provers and tank provers at 
least once every 5 years according to the API MPMS 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 12, Section 2, Part 4 (incorporated by 
reference as specified in Sec. 250.198);
    (2) Submit a copy of each calibration report to the Regional 
Supervisor within 15 days after the calibration.
    (g) What correction factors must I use when proving meters with a 
mechanical-displacement prover, tank prover, or master meter? Calculate 
the following correction factors using the API MPMS as

[[Page 183]]

referenced in 30 CFR 250.198, including the following additional 
editions:
    (1) API MPMS, Chapter 4, Section 8 (incorporated by reference as 
specified in Sec. 250.198);
    (2) API MPMS Chapter 11, Section 1 (incorporated by reference as 
specified in Sec. 250.198);
    (3) API MPMS Chapter 12, Section 2, Part 3 (incorporated by 
reference as specified in Sec. 250.198);
    (4) API MPMS Chapter 12, Section 2, Part 4 (incorporated by 
reference as specified in Sec. 250.198);
    (h) What are the requirements for establishing and applying 
operating meter factors for liquid hydrocarbons? (1) If you use a 
mechanical-displacement prover, you must record proof runs until five 
out of six consecutive runs produce a difference between individual runs 
of no greater than .05 percent. You must use the average of the five 
accepted runs to compute the meter factor.
    (2) If you use a master meter, you must record proof runs until 
three consecutive runs produce a total meter factor difference of no 
greater than 0.0005. The flow rate through the meters during the proving 
must be within 10 percent of the rate at which the line meter will 
operate. The final meter factor is determined by averaging the meter 
factors of the three runs;
    (3) If you use a tank prover, you must record proof runs until two 
consecutive runs produce a meter factor difference of no greater than 
.0005. The final meter factor is determined by averaging the meter 
factors of the two runs; and
    (4) You must apply operating meter factors forward starting with the 
date of the proving.
    (i) Under what circumstances does a liquid hydrocarbon royalty meter 
need to be taken out of service, and what must I do? (1) If the 
difference between the meter factor and the previous factor exceeds 
0.0025 it is a malfunction factor, and you must:
    (i) Remove the meter from service and inspect it for damage or wear;
    (ii) Adjust or repair the meter, and reprove it;
    (iii) Apply the average of the malfunction factor and the previous 
factor to the production measured through the meter between the date of 
the previous factor and the date of the malfunction factor; and
    (iv) Indicate that a meter malfunction occurred and show all 
appropriate remarks regarding subsequent repairs or adjustments on the 
proving report.
    (2) If a meter fails to register production, you must:
    (i) Remove the meter from service, repair and reprove it;
    (ii) Apply the previous meter factor to the production run between 
the date of that factor and the date of the failure; and
    (iii) Estimate and report unregistered production on the run ticket.
    (3) If the results of a royalty meter proving exceed the run 
tolerance criteria and all measures excluding the adjustment or repair 
of the meter cannot bring results within tolerance, you must:
    (i) Establish a factor using proving results made before any 
adjustment or repair of the meter; and
    (ii) Treat the established factor like a malfunction factor (see 
paragraph (i)(1) of this section).
    (j) How must I correct gross liquid hydrocarbon volumes to standard 
conditions? To correct gross liquid hydrocarbon volumes to standard 
conditions, you must:
    (1) Include Cpl factors in the meter factor calculation or list and 
apply them on the appropriate run ticket.
    (2) List Ctl factors on the appropriate run ticket when the meter is 
not automatically temperature compensated.
    (k) What are the requirements for liquid hydrocarbon allocation 
meters? For liquid hydrocarbon allocation meters you must:
    (1) Take samples continuously proportional to flow or daily (use the 
procedure in the applicable chapter of the API MPMS as incorporated by 
reference in Sec. 250.198;
    (2) For turbine meters, take the sample proportional to the flow 
only;
    (3) Prove operating allocation meters monthly if they measure 50 or 
more barrels per day per meter the previous month. When a force majeure 
event precludes the required monthly meter proving, meters must be 
proved within 15 days after being returned to service. The meters must 
be proved monthly thereafter; or

[[Page 184]]

    (4) Prove operating allocation meters quarterly if they measure less 
than 50 barrels per day per meter the previous month. When a force 
majeure event precludes the required quarterly meter proving, meters 
must be proved within 15 days after being returned to service. The 
meters must be proved quarterly thereafter;
    (5) Keep a copy of the proving reports at the field location for 2 
years;
    (6) Adjust and reprove the meter if the meter factor differs from 
the previous meter factor by more than 2 percent and less than 7 
percent;
    (7) For turbine meters, remove from service, inspect and reprove the 
meter if the factor differs from the previous meter factor by more than 
2 percent and less than 7 percent;
    (8) Repair and reprove, or replace and prove the meter if the meter 
factor differs from the previous meter factor by 7 percent or more; and
    (9) Permit BSEE representatives to witness provings.
    (l) What are the requirements for royalty and inventory tank 
facilities? You must:
    (1) Equip each royalty and inventory tank with a vapor-tight thief 
hatch, a vent-line valve, and a fill line designed to minimize free fall 
and splashing;
    (2) For royalty tanks, submit a complete set of calibration charts 
(tank tables) to the Regional Supervisor before using the tanks for 
royalty measurement;
    (3) For inventory tanks, retain the calibration charts for as long 
as the tanks are in use and submit them to the Regional Supervisor upon 
request; and
    (4) Obtain the volume and other measurement parameters by using 
corrections factors and procedures in the API MPMS as incorporated by 
reference in 30 CFR 250.198, including: API MPMS Chapter 11, Section 1 
(incorporated by reference as specified in Sec. 250.198).

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 18921, Mar. 29, 2012]



Sec. 250.1203  Gas measurement.

    (a) To which meters do BSEE requirements for gas measurement apply? 
BSEE requirements for gas measurements apply to all OCS gas royalty and 
allocation meters.
    (b) What are the requirements for measuring gas? You must:
    (1) Submit a written application to, and obtain approval from, the 
Regional Supervisor before commencing gas production, or making any 
changes to the previously-approved measurement and/or allocation 
procedures. Your application (which may also include any relevant liquid 
hydrocarbon 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, see table 
in Sec. 250.1202(a)(1).
    (2) Design, install, use, maintain, and test measurement equipment 
and procedures to ensure accurate and verifiable measurement. You must 
follow the recommendations in API MPMS or RP and AGA as incorporated by 
reference in 30 CFR 250.198, including the following additional 
editions:
    (i) API RP 86 (incorporated by reference as specified in Sec. 
250.198);
    (ii) AGA Report No. 7 (incorporated by reference as specified in 
Sec. 250.198);
    (iii) AGA Report No. 9 (incorporated by reference as specified in 
Sec. 250.198);
    (iv) AGA Report No. 10 (incorporated by reference as specified in 
Sec. 250.198);
    (3) Ensure that the measurement components demonstrate consistent 
levels of accuracy throughout the system.
    (4) Equip the meter with a chart or electronic data recorder. If an 
electronic data recorder is used, you must follow the recommendations in 
API MPMS.
    (5) Take proportional-to-flow or spot samples upstream or downstream 
of the meter at least once every 6 months.
    (6) When requested by the Regional Supervisor, provide available 
information on the gas quality.
    (7) Ensure that standard conditions for reporting gross heating 
value (Btu) are at a base temperature of 60 [deg]F and at a base 
pressure of 14.73 psia and reflect the same degree of water saturation 
as in the gas volume.
    (8) When requested by the Regional Supervisor, submit copies of gas 
volume statements for each requested gas meter. Show whether gas volumes 
and

[[Page 185]]

gross Btu heating values are reported at saturated or unsaturated 
conditions; and
    (9) When requested by the Regional Supervisor, provide volume and 
quality statements on dispositions other than those on the gas volume 
statement.
    (c) What are the requirements for gas meter calibrations? You must:
    (1) Verify/calibrate operating meters monthly, but do not exceed 42 
days between verifications/calibrations. When a force majeure event 
precludes the required monthly meter verification/calibration, meters 
must be verified/calibrated within 15 days after being returned to 
service. The meters must be verified/calibrated monthly thereafter, but 
do not exceed 42 days between meter verifications/calibrations;
    (2) Calibrate each meter by using the manufacturer's specifications;
    (3) Conduct calibrations as close as possible to the average hourly 
rate of flow since the last calibration;
    (4) Retain calibration reports at the field location for 2 years, 
and send the reports to the Regional Supervisor upon request; and
    (5) Permit BSEE representatives to witness calibrations.
    (d) What must I do if a gas meter is out of calibration or 
malfunctioning? If a gas meter is out of calibration or malfunctioning, 
you must:
    (1) If the readings are greater than the contractual tolerances, 
adjust the meter to function properly or remove it from service and 
replace it.
    (2) Correct the volumes to the last acceptable calibration as 
follows:
    (i) If the duration of the error can be determined, calculate the 
volume adjustment for that period.
    (ii) If the duration of the error cannot be determined, apply the 
volume adjustment to one-half of the time elapsed since the last 
calibration or 21 days, whichever is less.
    (e) What are the requirements when natural gas from a Federal lease 
on the OCS is transferred to a gas plant before royalty determination? 
If natural gas from a Federal lease on the OCS is transferred to a gas 
plant before royalty determination:
    (1) You must provide the following to the Regional Supervisor upon 
request:
    (i) A copy of the monthly gas processing plant allocation statement; 
and
    (ii) Gross heating values of the inlet and residue streams when not 
reported on the gas plant statement.
    (2) You must permit BSEE to inspect the measurement and sampling 
equipment of natural gas processing plants that process Federal 
production.
    (f) What are the requirements for measuring gas lost or used on a 
lease? (1) You must either measure or estimate the volume of gas lost or 
used on a lease.
    (2) If you measure the volume, document the measurement equipment 
used and include the volume measured.
    (3) If you estimate the volume, document the estimating method, the 
data used, and the volumes estimated.
    (4) You must keep the documentation, including the volume data, 
easily obtainable for inspection at the field location for at least 2 
years, and must retain the documentation at a location of your choosing 
for at least 7 years after the documentation is generated, subject to 
all other document retention and production requirements in 30 U.S.C. 
1713 and 30 CFR part 1212.
    (5) Upon the request of the Regional Supervisor, you must provide 
copies of the records.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 18922, Mar. 29, 2012]



Sec. 250.1204  Surface commingling.

    (a) What are the requirements for the surface commingling of 
production? You must:
    (1) Submit a written application to, and obtain approval from, the 
Regional Supervisor before commencing the commingling of production or 
making any changes to the previously approved commingling procedures. 
Your application (which may also include any relevant liquid hydrocarbon 
and gas measurement 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, see table in Sec. 250.1202(a)(1).
    (2) Upon the request of the Regional Supervisor, lessees who deliver 
State lease production into a Federal commingling system must provide 
volumetric or fractional analysis data on the State lease production 
through the designated system operator.

[[Page 186]]

    (b) What are the requirements for a periodic well test used for 
allocation? You must:
    (1) Conduct a well test at least once every 60 days unless the 
Regional Supervisor approves a different frequency. When a force majeure 
event precludes the required well test within the prescribed 60 day 
period (or other frequency approved by the Regional Supervisor), wells 
must be tested within 15 days after being returned to production. 
Thereafter, well tests must be conducted at least once every 60 days (or 
other frequency approved by the Regional Supervisor);
    (2) Follow the well test procedures in 30 CFR part 250, subpart K; 
and
    (3) Retain the well test data at the field location for 2 years.



Sec. 250.1205  Site security.

    (a) What are the requirements for site security? You must:
    (1) Protect Federal production against production loss or theft;
    (2) Post a sign at each royalty or inventory tank which is used in 
the royalty determination process. The sign must contain the name of the 
facility operator, the size of the tank, and the tank number;
    (3) Not bypass BSEE-approved liquid hydrocarbon royalty meters and 
tanks; and
    (4) Report the following to the Regional Supervisor as soon as 
possible, but no later than the next business day after discovery:
    (i) Theft or mishandling of production;
    (ii) Tampering or bypassing any component of the royalty measurement 
facility; and
    (iii) Falsifying production measurements.
    (b) What are the requirements for using seals? You must:
    (1) Seal the following components of liquid hydrocarbon royalty 
meter installations to ensure that tampering cannot occur without 
destroying the seal:
    (i) Meter component connections from the base of the meter up to and 
including the register;
    (ii) Sampling systems including packing device, fittings, sight 
glass, and container lid;
    (iii) Temperature and gravity compensation device components;
    (iv) All valves on lines leaving a royalty or inventory storage 
tank, including load-out line valves, drain-line valves, and connection-
line valves between royalty and non-royalty tanks; and
    (v) Any additional components required by the Regional Supervisor.
    (2) Seal all bypass valves of gas royalty and allocation meters.
    (3) Number and track the seals and keep the records at the field 
location for at least 2 years; and
    (4) Make the records of seals available for BSEE inspection.



                          Subpart M_Unitization



Sec. 250.1300  What is the purpose of this subpart?

    This subpart explains how Outer Continental Shelf (OCS) leases are 
unitized. If you are an OCS lessee, use the regulations in this subpart 
for both competitive reservoir and unitization situations. The purpose 
of joint development and unitization is to:
    (a) Conserve natural resources;
    (b) Prevent waste; and/or
    (c) Protect correlative rights, including Federal royalty interests.



Sec. 250.1301  What are the requirements for unitization?

    (a) Voluntary unitization. You and other OCS lessees may ask the 
Regional Supervisor to approve a request for voluntary unitization. The 
Regional Supervisor may approve the request for voluntary unitization if 
unitized operations:
    (1) Promote and expedite exploration and development; or
    (2) Prevent waste, conserve natural resources, or protect 
correlative rights, including Federal royalty interests, of a reasonably 
delineated and productive reservoir.
    (b) Compulsory unitization. The Regional Supervisor may require you 
and other lessees to unitize operations of a reasonably delineated and 
productive reservoir if unitized operations are necessary to:
    (1) Prevent waste;
    (2) Conserve natural resources; or

[[Page 187]]

    (3) Protect correlative rights, including Federal royalty interests.
    (c) Unit area. The area that a unit includes is the minimum number 
of leases that will allow the lessees to minimize the number of 
platforms, facility installations, and wells necessary for efficient 
exploration, development, and production of mineral deposits, oil and 
gas reservoirs, or potential hydrocarbon accumulations common to two or 
more leases. A unit may include whole leases or portions of leases.
    (d) Unit agreement. You, the other lessees, and the unit operator 
must enter into a unit agreement. The unit agreement must: allocate 
benefits to unitized leases, designate a unit operator, and specify the 
effective date of the unit agreement. The unit agreement must terminate 
when: the unit no longer produces unitized substances, and the unit 
operator no longer conducts drilling or well-workover operations (Sec. 
250.180) under the unit agreement, unless the Regional Supervisor orders 
or approves a suspension of production under Sec. 250.170.
    (e) Unit operating agreement. The unit operator and the owners of 
working interests in the unitized leases must enter into a unit 
operating agreement. The unit operating agreement must describe how all 
the unit participants will apportion all costs and liabilities incurred 
maintaining or conducting operations. When a unit involves one or more 
net-profit-share leases, the unit operating agreement must describe how 
to attribute costs and credits to the net-profit-share lease(s), and 
this part of the agreement must be approved by the Regional Supervisor. 
Otherwise, you must provide a copy of the unit operating agreement to 
the Regional Supervisor, but the Regional Supervisor does not need to 
approve the unit operating agreement.
    (f) Extension of a lease covered by unit operations. If your unit 
agreement expires or terminates, or the unit area adjusts so that no 
part of your lease remains within the unit boundaries, your lease 
expires unless:
    (1) Its initial term has not expired;
    (2) You conduct drilling, production, or well-reworking operations 
on your lease consistent with applicable regulations; or
    (3) BSEE orders or approves a suspension of production or operations 
for your lease.
    (g) Unit operations. If your lease, or any part of your lease, is 
subject to a unit agreement, the entire lease continues for the term 
provided in the lease, and as long thereafter as any portion of your 
lease remains part of the unit area, and as long as operations continue 
the unit in effect.
    (1) If you drill, produce or perform well-workover operations on a 
lease within a unit, each lease, or part of a lease, in the unit will 
remain active in accordance with the unit agreement. Following a 
discovery, if your unit ceases drilling activities for a reasonable time 
period between the delineation of one or more reservoirs and the 
initiation of actual development drilling or production operations and 
that time period would extend beyond your lease's primary term or any 
extension under Sec. 250.180, the unit operator must request and obtain 
BSEE approval of a suspension of production under Sec. 250.170 in order 
to keep the unit from terminating.
    (2) When a lease in a unit agreement is beyond the primary term and 
the lease or unit is not producing, the lease will expire unless:
    (i) You conduct a continuous drilling or well reworking program 
designed to develop or restore the lease or unit production; or
    (ii) BSEE orders or approves a suspension of operations under Sec. 
250.170.



Sec. 250.1302  What if I have a competitive reservoir on a lease?

    (a) The Regional Supervisor may require you to conduct development 
and production operations in a competitive reservoir under either a 
joint Development and Production Plan, submitted to BOEM or a 
unitization agreement. A competitive reservoir has one or more producing 
or producible well completions on each of two or more leases, or 
portions of leases, with different lease operating interests. For 
purposes of this paragraph, a producible well completion is a well which 
is capable of production and which is shut in at the

[[Page 188]]

well head or at the surface but not necessarily connected to production 
facilities and from which the operator plans future production.
    (b) You may request that the Regional Supervisor make a preliminary 
determination whether a reservoir is competitive. When you receive the 
preliminary determination, you have 30 days (or longer if the Regional 
Supervisor allows additional time) to concur or to submit an objection 
with supporting evidence if you do not concur. The Regional Supervisor 
will make a final determination and notify you and the other lessees.
    (c) If you conduct drilling or production operations in a reservoir 
determined competitive by the Regional Supervisor, you and the other 
affected lessees must submit for approval a joint plan of operations. 
You must submit the joint plan within 90 days after the Regional 
Supervisor makes a final determination that the reservoir is 
competitive. The joint plan must provide for the development and/or 
production of the reservoir. You may submit supplemental plans for the 
Regional Supervisor's approval.
    (d) If you and the other affected lessees cannot reach an agreement 
on a joint Development and Production Plan, submitted to BOEM within the 
approved period of time, each lessee must submit a separate plan to the 
Regional Supervisor. The Regional Supervisor will hold a hearing to 
resolve differences in the separate plans. If the differences in the 
separate plans are not resolved at the hearing and the Regional 
Supervisor determines that unitization is necessary under Sec. 
250.1301(b), BSEE will initiate unitization under Sec. 250.1304.



Sec. 250.1303  How do I apply for voluntary unitization?

    (a) You must file a request for a voluntary unit with the Regional 
Supervisor. Your request must include:
    (1) A draft of the proposed unit agreement;
    (2) A proposed initial plan of operation;
    (3) Supporting geological, geophysical, and engineering data; and
    (4) Other information that may be necessary to show that the 
unitization proposal meets the criteria of Sec. 250.1300.
    (b) The unit agreement must comply with the requirements of this 
part. BSEE will maintain and provide a model unit agreement for you to 
follow. If BSEE revises the model, BSEE will publish the revised model 
in the Federal Register. If you vary your unit agreement from the model 
agreement, you must obtain the approval of the Regional Supervisor.
    (c) After the Regional Supervisor accepts your unitization proposal, 
you, the other lessees, and the unit operator must sign and file copies 
of the unit agreement, the unit operating agreement, and the initial 
plan of operation with the Regional Supervisor for approval.
    (d) You must pay the service fee listed in Sec. 250.125 of this 
part with your request for a voluntary unitization proposal or the 
expansion of a previously approved voluntary unit to include additional 
acreage. Additionally, you must pay the service fee listed in Sec. 
250.125 with your request for unitization revision.



Sec. 250.1304  How will BSEE require unitization?

    (a) If the Regional Supervisor determines that unitization of 
operations within a proposed unit area is necessary to prevent waste, 
conserve natural resources of the OCS, or protect correlative rights, 
including Federal royalty interests, the Regional Supervisor may require 
unitization.
    (b) If you ask BSEE to require unitization, you must file a request 
with the Regional Supervisor. You must include a proposed unit agreement 
as described in Sec. Sec. 250.1301(d) and 250.1303(b); a proposed unit 
operating agreement; a proposed initial plan of operation; supporting 
geological, geophysical, and engineering data; and any other information 
that may be necessary to show that unitization meets the criteria of 
Sec. 250.1300. The proposed unit agreement must include a counterpart 
executed by each lessee seeking compulsory unitization. Lessees who seek 
compulsory unitization must simultaneously serve on the nonconsenting 
lessees copies of:

[[Page 189]]

    (1) The request;
    (2) The proposed unit agreement with executed counterparts;
    (3) The proposed unit operating agreement; and
    (4) The proposed initial plan of operation.
    (c) If the Regional Supervisor initiates compulsory unitization, 
BSEE will serve all lessees of the proposed unit area with a proposed 
unitization plan and a statement of reasons for the proposed 
unitization.
    (d) The Regional Supervisor will not require unitization until BSEE 
provides all lessees of the proposed unit area written notice and an 
opportunity for a hearing. If you want BSEE to hold a hearing, you must 
request it within 30 days after you receive written notice from the 
Regional Supervisor or after you are served with a request for 
compulsory unitization from another lessee.
    (e) BSEE will not hold a hearing under this paragraph until at least 
30 days after BSEE provides written notice of the hearing date to all 
parties owning interests that would be made subject to the unit 
agreement. The Regional Supervisor must give all lessees of the proposed 
unit area an opportunity to submit views orally and in writing and to 
question both those seeking and those opposing compulsory unitization. 
Adjudicatory procedures are not required. The Regional Supervisor will 
make a decision based upon a record of the hearing, including any 
written information made a part of the record. The Regional Supervisor 
will arrange for a court reporter to make a verbatim transcript. The 
party seeking compulsory unitization must pay for the court reporter and 
pay for and provide to the Regional Supervisor within 10 days after the 
hearing three copies of the verbatim transcript.
    (f) The Regional Supervisor will issue an order that requires or 
rejects compulsory unitization. That order must include a statement of 
reasons for the action taken and identify those parts of the record 
which form the basis of the decision. Any adversely affected party may 
appeal the final order of the Regional Supervisor under 30 CFR part 290.



            Subpart N_Outer Continental Shelf Civil Penalties

            Outer Continental Shelf Lands Act Civil Penalties



Sec. 250.1400  How does BSEE begin the civil penalty process?

    This subpart explains BSEEs civil penalty procedures whenever a 
lessee, operator or other person engaged in oil, gas, sulphur or other 
minerals operations in the OCS has a violation. Whenever BSEE 
determines, on the basis of available evidence, that a violation 
occurred and a civil penalty review is appropriate, it will prepare a 
case file. BSEE will appoint a Reviewing Officer.



Sec. 250.1401  Index table.

    The following table is an index of the sections in this subpart:

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



Sec. 250.1402  Definitions.

    Terms used in this subpart have the following meaning:
    Case file means a BSEE document file containing information and the 
record of evidence related to the alleged violation.
    Civil penalty means a fine. It is a BSEE regulatory enforcement tool 
used in addition to Notices of Incidents of Noncompliance and directed 
suspensions of production or other operations.
    Reviewing Officer means a BSEE employee assigned to review case 
files and assess civil penalties.

[[Page 190]]

    Violation means failure to comply with the Outer Continental Shelf 
Lands Act (OCSLA) or any other applicable laws, with any regulations 
issued under the OCSLA, or with the terms or provisions of leases, 
licenses, permits, rights-of-way, or other approvals issued under the 
OCSLA.
    Violator means a person responsible for a violation.



Sec. 250.1403  What is the maximum civil penalty?

    The maximum civil penalty is $40,000 per day per violation.



Sec. 250.1404  Which violations will BSEE review for potential civil 

penalties?

    BSEE will review each of the following violations for potential 
civil penalties:
    (a) Violations that you do not correct within the period BSEE 
grants;
    (b) Violations that BSEE determines may constitute, or constituted, 
a threat of serious, irreparable, or immediate harm or damage to life 
(including fish and other aquatic life), property, any mineral deposit, 
or the marine, coastal, or human environment; or
    (c) Violations that cause serious, irreparable, or immediate harm or 
damage to life (including fish and other aquatic life), property, any 
mineral deposit, or the marine, coastal, or human environment.
    (d) Violations of the oil spill financial responsibility 
requirements at 30 CFR part 553.



Sec. 250.1405  When is a case file developed?

    BSEE will develop a case file during its investigation of the 
violation, and forward it to a Reviewing Officer if any of the 
conditions in Sec. 250.1404 exist. The Reviewing Officer will review 
the case file and determine if a civil penalty is appropriate. The 
Reviewing Officer may administer oaths and issue subpoenas requiring 
witnesses to attend meetings, submit depositions, or produce evidence.



Sec. 250.1406  When will BSEE notify me and provide penalty information?

    If the Reviewing Officer determines that a civil penalty should be 
assessed, the Reviewing Officer will send the violator a letter of 
notification. The letter of notification will include:
    (a) The amount of the proposed civil penalty;
    (b) Information on the violation(s); and
    (c) Instruction on how to obtain a copy of the case file, schedule a 
meeting, submit information, or pay the penalty.



Sec. 250.1407  How do I respond to the letter of notification?

    You have 30 calendar days after you receive the Reviewing Officer's 
letter to either:
    (a) Request, in writing, a meeting with the Reviewing Officer;
    (b) Submit additional information; or
    (c) Pay the proposed civil penalty.



Sec. 250.1408  When will I be notified of the Reviewing Officer's decision?

    At the end of the 30 calendar days or after the meeting and 
submittal of additional information, the Reviewing Officer will review 
the case file, including all information you submitted, and send you a 
decision. The decision will include the amount of any final civil 
penalty, the basis for the civil penalty, and instructions for paying or 
appealing the civil penalty.



Sec. 250.1409  What are my appeal rights?

    (a) When you receive the Reviewing Officer's final decision, you 
have 60 days to either pay the penalty or file an appeal in accordance 
with 30 CFR part 290, subpart A.
    (b) If you file an appeal, you must either:
    (1) Submit a surety bond in the amount of the penalty to the 
appropriate Leasing Office in the Region where the penalty was assessed, 
following instructions that the Reviewing Officer will include in the 
final decision; or
    (2) Notify the appropriate Leasing Office, in the Region where the 
penalty was assessed, that you want your lease-specific/area-wide bond 
on file to be used as the bond for the penalty amount.
    (c) If you choose the alternative in paragraph (b)(2) of this 
section, the BOEM Regional Director may require

[[Page 191]]

additional security (i.e., security in excess of your existing bond) to 
ensure sufficient coverage during an appeal. In that event, the Regional 
Director will require you to post the supplemental bond with the 
regional office in the same manner as under 30 CFR 556.53(d) through 
(f). If the Regional Director determines the appeal should be covered by 
a lease-specific abandonment account then you must establish an account 
that meets the requirements of 30 CFR part 556.56.
    (d) If you do not either pay the penalty or file a timely appeal, 
BSEE will take one or more of the following actions:
    (1) We will collect the amount you were assessed, plus interest, 
late payment charges, and other fees as provided by law, from the date 
you received the Reviewing Officer's final decision until the date we 
receive payment;
    (2) We may initiate additional enforcement, including, if 
appropriate, cancellation of the lease, right-of-way, license, permit, 
or approval, or the forfeiture of a bond under this part; or
    (3) We may bar you from doing further business with the Federal 
Government according to Executive Orders 12549 and 12689, and section 
2455 of the Federal Acquisition Streamlining Act of 1994, 31 U.S.C. 
6101. The Department of the Interior's regulations implementing these 
authorities are found at 43 CFR part 12, subpart D.

 Federal Oil and Gas Royalty Management Act Civil Penalties Definitions



Sec. 250.1450  What definitions apply to this subpart?

    The terms used in this subpart have the same meaning as in 30 U.S.C. 
1702.

                   Penalties After a Period To Correct



Sec. 250.1451  What may BSEE do if I violate a statute, regulation, order, or 

lease term relating to a Federal oil and gas lease?

    (a) If we believe that you have not followed any requirement of a 
statute, regulation, order, or lease term for any Federal oil or gas 
lease, we may send you a Notice of Noncompliance informing you what the 
violation is and what you need to do to correct it to avoid civil 
penalties under 30 U.S.C. 1719(a) and (b).
    (b) We will serve the Notice of Noncompliance by registered mail or 
personal service using the most current address on file as maintained by 
the BOEM Leasing Office in your respective Region.



Sec. 250.1452  What if I correct the violation?

    The matter will be closed if you correct all of the violations 
identified in the Notice of Noncompliance within 20 days after you 
receive the Notice (or within a longer time period specified in the 
Notice).



Sec. 250.1453  What if I do not correct the violation?

    (a) We may send you a Notice of Civil Penalty if you do not correct 
all of the violations identified in the Notice of Noncompliance within 
20 days after you receive the Notice of Noncompliance (or within a 
longer time period specified in that Notice). The Notice of Civil 
Penalty will tell you how much penalty you must pay. The penalty may be 
up to $500 per day, beginning with the date of the Notice of 
Noncompliance, for each violation identified in the Notice of 
Noncompliance for as long as you do not correct the violations.
    (b) If you do not correct all of the violations identified in the 
Notice of Noncompliance within 40 days after you receive the Notice of 
Noncompliance (or 20 days following the expiration of a longer time 
period specified in that Notice), we may increase the penalty to up to 
$5,000 per day, beginning with the date of the Notice of Noncompliance, 
for each violation for as long as you do not correct the violations.



Sec. 250.1454  How may I request a hearing on the record on a Notice of 

Noncompliance?

    You may request a hearing on the record on a Notice of Noncompliance 
by filing a request within 30 days of the date you received the Notice 
of Noncompliance with the Hearings Division (Departmental), Office of 
Hearings and

[[Page 192]]

Appeals, U.S. Department of the Interior, 801 North Quincy Street, 
Arlington, Virginia 22203. You may do this regardless of whether you 
correct the violations identified in the Notice of Noncompliance.



Sec. 250.1455  Does my request for a hearing on the record affect the 

penalties?

    (a) If you do not correct the violations identified in the Notice of 
Noncompliance, the penalties will continue to accrue even if you request 
a hearing on the record.
    (b) You may petition the Hearings Division (Departmental) of the 
Office of Hearings and Appeals, to stay the accrual of penalties pending 
the hearing on the record and a decision by the Administrative Law Judge 
under Sec. 250.1472.
    (1) You must file your petition within 45 calendar days of receiving 
the Notice of Noncompliance.
    (2) To stay the accrual of penalties, you must post a bond or other 
surety instrument, or demonstrate financial solvency, using the 
standards and requirements as prescribed in Sec. Sec. 250.1490 through 
250.1497, for the principal amount of any unpaid amounts due that are 
the subject of the Notice of Noncompliance, including interest thereon, 
plus the amount of any penalties accrued before the date a stay becomes 
effective.
    (3) The Hearings Division will grant or deny the petition under 43 
CFR 4.21(b).



Sec. 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?

    (a) You may request a hearing on the record to challenge only the 
amount of a civil penalty when you receive a Notice of Civil Penalty, if 
you did not previously request a hearing on the record under Sec. 
250.1454. If you did not request a hearing on the record on the Notice 
of Noncompliance under Sec. 250.1454, you may not contest your 
underlying liability for civil penalties.
    (b) You must file your request within 10 days after you receive the 
Notice of Civil Penalty with the Hearings Division (Departmental), 
Office of Hearings and Appeals, U.S. Department of the Interior, 801 
North Quincy Street, Arlington, Virginia 22203.

                  Penalties Without a Period To Correct



Sec. 250.1460  May I be subject to penalties without prior notice and an 

opportunity to correct?

    The Federal Oil and Gas Royalty Management Act sets out several 
specific violations for which penalties accrue without an opportunity to 
first correct the violation.
    (a) Under 30 U.S.C. 1719(c), you may be subject to penalties of up 
to $10,000 per day per violation for each day the violation continues if 
you:
    (1) Fail or refuse to permit lawful entry, inspection, or audit; or
    (2) Knowingly or willfully fail or refuse to notify the Secretary, 
within 5 business days after any well begins production on a lease site 
or allocated to a lease site, or resumes production in the case of a 
well which has been off production for more than 90 days, of the date on 
which production has begun or resumed.
    (b) Under 30 U.S.C. 1719(d), you may be subject to civil penalties 
of up to $25,000 per day for each day each violation continues if you:
    (1) Knowingly or willfully prepare, maintain, or submit false, 
inaccurate, or misleading reports, notices, affidavits, records, data, 
or other written information;
    (2) Knowingly or willfully take or remove, transport, use or divert 
any oil or gas from any lease site without having valid legal authority 
to do so; or
    (3) Purchase, accept, sell, transport, or convey to another person, 
any oil or gas knowing or having reason to know that such oil or gas was 
stolen or unlawfully removed or diverted.



Sec. 250.1461  How will BSEE inform me of violations without a period to 

correct?

    We will inform you of any violation, without a period to correct, by 
issuing a Notice of Noncompliance and Civil Penalty explaining the 
violation, how to correct it, and the penalty assessment. We will serve 
the Notice of Noncompliance and Civil Penalty by registered mail or 
personal service using

[[Page 193]]

your address of record as specified under 30 CFR part 1218, Subpart H.



Sec. 250.1462  How may I request a hearing on the record on a Notice of 

Noncompliance regarding violations without a period to correct?

    You may request a hearing on the record of a Notice of Noncompliance 
regarding violations without a period to correct by filing a request 
within 30 days after you receive the Notice of Noncompliance with the 
Hearings Division (Departmental), Office of Hearings and Appeals, U.S. 
Department of the Interior, 801 North Quincy Street, Arlington, Virginia 
22203. You may do this regardless of whether you correct the violations 
identified in the Notice of Noncompliance.



Sec. 250.1463  Does my request for a hearing on the record affect the 

penalties?

    (a) If you do not correct the violations identified in the Notice of 
Noncompliance regarding violations without a period to correct, the 
penalties will continue to accrue even if you request a hearing on the 
record.
    (b) You may ask the Hearings Division (Departmental) to stay the 
accrual of penalties pending the hearing on the record and a decision by 
the Administrative Law Judge under Sec. 250.1472.
    (1) You must file your petition within 45 calendar days after you 
receive the Notice of Noncompliance.
    (2) To stay the accrual of penalties, you must post a bond or other 
surety instrument, or demonstrate financial solvency, using the 
standards and requirements as prescribed in Sec. Sec. 250.1490 through 
250.1497, for the principal amount of any unpaid amounts due that are 
the subject of the Notice of Noncompliance, including interest thereon, 
plus the amount of any penalties accrued before the date a stay becomes 
effective.
    (3) The Hearings Division will grant or deny the petition under 43 
CFR 4.21(b).



Sec. 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?

    (a) You may request a hearing on the record to challenge only the 
amount of a civil penalty when you receive a Notice of Civil Penalty 
regarding violations without a period to correct, if you did not 
previously request a hearing on the record under Sec. 250.1462. If you 
did not request a hearing on the record on the Notice of Noncompliance 
under Sec. 250.1462, you may not contest your underlying liability for 
civil penalties.
    (b) You must file your request within 10 days after you receive 
Notice of Civil Penalty with the Hearings Division (Departmental), 
Office of Hearings and Appeals, U.S. Department of the Interior, 801 
North Quincy, Arlington, Virginia 22203.

                           General Provisions



Sec. 250.1470  How does BSEE decide what the amount of the penalty should be?

    We determine the amount of the penalty by considering the severity 
of the violations, your history of compliance, and if you are a small 
business.



Sec. 250.1471  Does the penalty affect whether I owe interest?

    If you do not pay the penalty by the date required under Sec. 
250.1475(d), BSEE will assess you late payment interest on the penalty 
amount at the same rate interest is assessed under 30 CFR 1218.54.



Sec. 250.1472  How will the Office of Hearings and Appeals conduct the hearing 

on the record?

    If you request a hearing on the record under Sec. Sec. 250.1454, 
250.1456, 250.1462, or 250.1464, the hearing will be conducted by a 
Departmental Administrative Law Judge from the Office of Hearings and 
Appeals. After the hearing, the Administrative Law Judge will issue a 
decision in accordance with the evidence presented and applicable law.



Sec. 250.1473  How may I appeal the Administrative Law Judge's decision?

    If you are adversely affected by the Administrative Law Judge's 
decision,

[[Page 194]]

you may appeal that decision to the Interior Board of Land Appeals under 
43 CFR part 4, subpart E.



Sec. 250.1474  May I seek judicial review of the decision of the Interior 

Board of Land Appeals?

    Under 30 U.S.C. 1719(j), you may seek judicial review of the 
decision of the Interior Board of Land Appeals. A suit for judicial 
review in the District Court will be barred unless filed within 90 days 
after the final order.



Sec. 250.1475  When must I pay the penalty?

    (a) You must pay the amount of the Notice of Civil Penalty issued 
under Sec. 250.1453 or Sec. 250.1461, if you do not request a hearing 
on the record under Sec. 250.1454, Sec. 250.1456, Sec. 250.1462, or 
Sec. 250.1464.
    (b) If you request a hearing on the record under Sec. Sec. 
250.1454, 250.1456, 250.1462, or 250.1464, but you do not appeal the 
determination of the Administrative Law Judge to the Interior Board of 
Land Appeals under Sec. 250.1473, you must pay the amount assessed by 
the Administrative Law Judge.
    (c) If you appeal the determination of the Administrative Law Judge 
to the Interior Board of Land Appeals, you must pay the amount assessed 
in the IBLA decision.
    (d) You must pay the penalty assessed within 40 days after:
    (1) You received the Notice of Civil Penalty, if you did not request 
a hearing on the record under either Sec. 250.1454, Sec. 250.1456, 
Sec. 250.1462, or Sec. 250.1464;
    (2) You received an Administrative Law Judge's decision under Sec. 
250.1472, if you obtained a stay of the accrual of penalties pending the 
hearing on the record under Sec. 250.1455(b) or Sec. 250.1463(b) and 
did not appeal the Administrative Law Judge's determination to the IBLA 
under Sec. 250.1473;
    (3) You received an IBLA decision under Sec. 250.1473 if the IBLA 
continued the stay of accrual of penalties pending its decision and you 
did not seek judicial review of the IBLA's decision; or
    (4) A final non-appealable judgment of a court of competent 
jurisdiction is entered, if you sought judicial review of the IBLA's 
decision and the Department or the appropriate court suspended 
compliance with the IBLA's decision pending the adjudication of the 
case.
    (e) If you do not pay, that amount is subject to collection under 
the provisions of Sec. 250.1477.



Sec. 250.1476  Can BSEE reduce my penalty once it is assessed?

    Under 30 U.S.C. 1719(g), the Director or his or her delegate may 
compromise or reduce civil penalties assessed under this part.



Sec. 250.1477  How may BSEE collect the penalty?

    (a) BSEE may use all available means to collect the penalty 
including, but not limited to:
    (1) Requiring the lease surety, for amounts owed by lessees, to pay 
the penalty;
    (2) Deducting the amount of the penalty from any sums the United 
States owes to you; and
    (3) Using judicial process to compel your payment under 30 U.S.C. 
1719(k).
    (b) If the Department uses judicial process, or if you seek judicial 
review under Sec. 250.1474 and the court upholds assessment of a 
penalty, the court shall have jurisdiction to award the amount assessed 
plus interest assessed from the date of the expiration of the 90-day 
period referred to in Sec. 250.1474. The amount of any penalty, as 
finally determined, may be deducted from any sum owing to you by the 
United States.

                           Criminal Penalties



Sec. 250.1480  May the United States criminally prosecute me for violations 

under Federal oil and gas leases?

    If you commit an act for which a civil penalty is provided at 30 
U.S.C. 1719(d) and Sec. 250.1460(b), the United States may pursue 
criminal penalties as provided at 30 U.S.C. 1720, in addition to any 
authority for prosecution under other statutes.

                          Bonding Requirements



Sec. 250.1490  What standards must my BOEM-specified surety instrument meet?

    (a) A BOEM-specified surety instrument must be in a form specified 
in

[[Page 195]]

BOEM instructions. BSEE will give you written information and standard 
forms for BOEM-specified surety instrument requirements.
    (b) BOEM will use a bank-rating service to determine whether a 
financial institution has an acceptable rating to provide a surety 
instrument adequate to indemnify the lessor from loss or damage.
    (1) Administrative appeal bonds must be issued by a qualified surety 
company which the Department of the Treasury has approved.
    (2) Irrevocable letters of credit or certificates of deposit must be 
from a financial institution acceptable to BOEM with a minimum 1-year 
period of coverage subject to automatic renewal up to 5 years.



Sec. 250.1491  How will BOEM determine the amount of my bond or other surety 

instrument?

    (a) The BOEM bond-approving officer may approve your surety if he or 
she determines that the amount is adequate to guarantee payment. The 
amount of your surety may vary depending on the form of the surety and 
how long the surety is effective.
    (1) The amount of the BOEM-specified surety instrument must include 
the principal amount owed under the Notice of Noncompliance or Notice of 
Civil Penalty plus any accrued interest we determine is owed plus 
projected interest for a 1-year period.
    (2) Treasury book-entry bond or note amounts must be equal to at 
least 120 percent of the required surety amount.
    (b) If your appeal is not decided within 1 year from the filing 
date, you must increase the surety amount to cover additional estimated 
interest for another 1-year period. You must continue to do this 
annually on the date your appeal was filed. We will determine the 
additional estimated interest and notify you of the amount so you can 
amend your surety instrument.
    (c) You may submit a single surety instrument that covers multiple 
appeals. You may change the instrument to add new amounts under appeal 
or remove amounts that have been adjudicated in your favor or that you 
have paid, if you:
    (1) Amend the single surety instrument annually on the date you 
filed your first appeal; and
    (2) Submit a separate surety instrument for new amounts under appeal 
until you amend the instrument to cover the new appeals.

                     Financial Solvency Requirements



Sec. 250.1495  How do I demonstrate financial solvency?

    (a) To demonstrate financial solvency under this part, you must 
submit an audited consolidated balance sheet, and, if requested by the 
BOEM bond-approving officer, up to 3 years of tax returns to BOEM using 
the U.S. Postal Service, private delivery, courier, or overnight 
delivery at:
    (1) For Alaska OCS: Jeffrey Walker, RS/FO, BOEM Alaska OCS Region, 
3801 Centerpoint Drive, Suite 500, Anchorage, AK 99503-5823, 
jeffrey.walker@boem.gov, (907) 334-5300.
    (2) For Gulf of Mexico and Atlantic OCS: Joshua Joyce, Regional FARM 
Program Coordinator, BOEM Gulf of Mexico OCS Region, 1201 Elmwood Park 
Boulevard New Orleans, LA 70123-2394, joshua.joyce@boem.gov, (504) 736-
2779.
    (3) For Pacific OCS: Jaron Ming, Lead Leasing Specialist, BOEM 
Pacific OCS Region, 770 Paseo Camarillo, 2nd Floor, Camarillo, CA 93010, 
jaron.ming@boem.gov, (805) 389-7514.
    (b) You must submit an audited consolidated balance sheet annually, 
and, if requested, additional annual tax returns on the date BSEE first 
determined that you demonstrated financial solvency as long as you have 
active appeals, or whenever BSEE requests.
    (c) If you demonstrate financial solvency in the current calendar 
year, you are not required to redemonstrate financial solvency for new 
appeals of orders during that calendar year unless you file for 
protection under any provision of the U.S. Bankruptcy Code (Title 11 of 
the United States Code), or BSEE notifies you that you must 
redemonstrate financial solvency.



Sec. 250.1496  How will BOEM determine if I am financially solvent?

    (a) The BOEM bond-approving officer will determine your financial 
solvency

[[Page 196]]

by examining your total net worth, including, as appropriate, the net 
worth of your affiliated entities.
    (b) If your net worth, minus the amount we would require as surety 
under Sec. Sec. 250.1490 and 250.1491 for all orders you have appealed 
is greater than $300 million, you are presumptively deemed financially 
solvent, and we will not require you to post a bond or other surety 
instrument.
    (c) If your net worth, minus the amount we would require as surety 
under Sec. Sec. 250.1490 and 250.1491 for all orders you have appealed 
is less than $300 million, you must submit the following to BSEE by one 
of the methods in Sec. 250.1495(a):
    (1) A written request asking us to consult a business-information, 
or credit-reporting service or program to determine your financial 
solvency; and
    (2) A nonrefundable $50 processing fee:
    (i) You must pay the processing fee to us following the requirements 
for making payments found in 30 CFR 250.126. You are required to use 
Electronic Funds Transfer (EFT) for these payments;
    (ii) You must submit the fee with your request under paragraph 
(c)(1) of this section, and then annually on the date we first 
determined that you demonstrated financial solvency, as long as you are 
not able to demonstrate financial solvency under paragraph (a) of this 
section and you have active appeals.
    (d) If you request that we consult a business-information or credit-
reporting service or program under paragraph (c) of this section:
    (1) We will use criteria similar to that which a potential creditor 
would use to lend an amount equal to the bond or other surety instrument 
we would require under Sec. Sec. 250.1490 and 250.1491;
    (2) For us to consider you financially solvent, the business-
information or credit-reporting service or program must demonstrate your 
degree of risk as low to moderate:
    (i) If our bond-approving officer determines that the business-
information or credit-reporting service or program information 
demonstrates your financial solvency to our satisfaction, our bond-
approving officer will not require you to post a bond or other surety 
instrument under Sec. Sec. 250.1490 and 250.1491;
    (ii) If our bond-approving officer determines that the business-
information or credit-reporting service or program information does not 
demonstrate your financial solvency to our satisfaction, our bond-
approving officer will require you to post a bond or other surety 
instrument under Sec. Sec. 250.1490 and 250.1491 or pay the obligation.



Sec. 250.1497  When will BOEM monitor my financial solvency?

    (a) If you are presumptively financially solvent under Sec. 
250.1496(b), BOEM will determine your net worth as described under Sec. 
250.1496(b) and (c) to evaluate your financial solvency at least 
annually on the date we first determined that you demonstrated financial 
solvency as long as you have active appeals and each time you appeal a 
new order.
    (b) If you ask us to consult a business-information or credit-
reporting service or program under Sec. 250.1496(c), we will consult a 
service or program annually as long as you have active appeals and each 
time you appeal a new order.
    (c) If our bond-approving officer determines that you are no longer 
financially solvent, you must post a bond or other BOEM-specified surety 
instrument under Sec. Sec. 250.1490 and 250.1491.



          Subpart O_Well Control and Production Safety Training



Sec. 250.1500  Definitions.

    Terms used in this subpart have the following meaning:
    Contractor and contract personnel mean anyone, other than an 
employee of the lessee, performing well control, deepwater well control, 
or production safety duties for the lessee.
    Deepwater well control means well control when you are using a 
subsea BOP system.
    Employee means direct employees of the lessees who are assigned well 
control, deepwater well control, or production safety duties.
    I or you means the lessee engaged in oil, gas, or sulphur operations 
in the Outer Continental Shelf (OCS).

[[Page 197]]

    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 an owner of operating rights for that lease 
and the BOEM-approved assignee of that lease.
    Periodic means occurring or recurring at regular intervals. Each 
lessee must specify the intervals for periodic training and periodic 
assessment of training needs in their training programs.
    Production operations include, but are not limited to, separation, 
dehydration, compression, sweetening, and metering operations.
    Production safety includes measures, practices, procedures, and 
equipment to ensure safe, accident-free, and pollution-free production 
operations, as well as installation, repair, testing, maintenance, and 
operation of surface and subsurface safety equipment.
    Well completion/well workover means those operations following the 
drilling of a well that are intended to establish or restore production.
    Well-control means methods used to minimize the potential for the 
well to flow or kick and to maintain control of the well in the event of 
flow or a kick. Well-control applies to drilling, well-completion, well-
workover, abandonment, and well-servicing operations. It includes 
measures, practices, procedures and equipment, such as fluid flow 
monitoring, to ensure safe and environmentally protective drilling, 
completion, abandonment, and workover operations as well as the 
installation, repair, maintenance, and operation of surface and subsea 
well-control equipment.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50896, Aug. 22, 2012]



Sec. 250.1501  What is the goal of my training program?

    The goal of your training program must be safe and clean OCS 
operations. To accomplish this, you must ensure that your employees and 
contract personnel engaged in well control, deepwater well control, or 
production safety operations understand and can properly perform their 
duties.



Sec. 250.1503  What are my general responsibilities for training?

    (a) You must establish and implement a training program so that all 
of your employees are trained to competently perform their assigned well 
control, deepwater well control, and production safety duties. You must 
verify that your employees understand and can perform the assigned well 
control, deepwater well control, or production safety duties.
    (b) If you conduct operations with a subsea BOP stack, your 
employees and contract personnel must be trained in deepwater well 
control. The trained employees and contract personnel must have a 
comprehensive knowledge of deepwater well control equipment, practices, 
and theory.
    (c) You must have a training plan that specifies the type, 
method(s), length, frequency, and content of the training for your 
employees. Your training plan must specify the method(s) of verifying 
employee understanding and performance. This plan must include at least 
the following information:
    (1) Procedures for training employees in well control, deepwater 
well control, or production safety practices;
    (2) Procedures for evaluating the training programs of your 
contractors;
    (3) Procedures for verifying that all employees and contractor 
personnel engaged in well control, deepwater well control, or production 
safety operations can perform their assigned duties;
    (4) Procedures for assessing the training needs of your employees on 
a periodic basis;
    (5) Recordkeeping and documentation procedures; and
    (6) Internal audit procedures.
    (d) Upon request of the District Manager or Regional Supervisor, you 
must provide:
    (1) Copies of training documentation for personnel involved in well 
control, deepwater well control, or production safety operations during 
the past 5 years; and
    (2) A copy of your training plan.

[[Page 198]]



Sec. 250.1504  May I use alternative training methods?

    You may use alternative training methods. These methods may include 
computer-based learning, films, or their equivalents. This training 
should be reinforced by appropriate demonstrations and ``hands-on'' 
training. Alternative training methods must be conducted according to, 
and meet the objectives of, your training plan.



Sec. 250.1505  Where may I get training for my employees?

    You may get training from any source that meets the requirements of 
your training plan.



Sec. 250.1506  How often must I train my employees?

    You determine the frequency of the training you provide your 
employees. You must do all of the following:
    (a) Provide periodic training to ensure that employees maintain 
understanding of, and competency in, well control, deepwater well 
control, or production safety practices;
    (b) Establish procedures to verify adequate retention of the 
knowledge and skills that employees need to perform their assigned well 
control, deepwater well control, or production safety duties; and
    (c) Ensure that your contractors' training programs provide for 
periodic training and verification of well control, deepwater well 
control, or production safety knowledge and skills.



Sec. 250.1507  How will BSEE measure training results?

    BSEE may periodically assess your training program, using one or 
more of the methods in this section.
    (a) Training system audit. BSEE or its authorized representative may 
conduct a training system audit at your office. The training system 
audit will compare your training program against this subpart. You must 
be prepared to explain your overall training program and produce 
evidence to support your explanation.
    (b) Employee or contract personnel interviews. BSEE or its 
authorized representative may conduct interviews at either onshore or 
offshore locations to inquire about the types of training that were 
provided, when and where this training was conducted, and how effective 
the training was.
    (c) Employee or contract personnel testing. BSEE or its authorized 
representative may conduct testing at either onshore or offshore 
locations for the purpose of evaluating an individual's knowledge and 
skills in perfecting well control, deepwater well control, and 
production safety duties.
    (d) Hands-on production safety, simulator, or live well testing. 
BSEE or its authorized representative may conduct tests at either 
onshore or offshore locations. Tests will be designed to evaluate the 
competency of your employees or contract personnel in performing their 
assigned well control, deepwater well control, and production safety 
duties. You are responsible for the costs associated with this testing, 
excluding salary and travel costs for BSEE personnel.



Sec. 250.1508  What must I do when BSEE administers written or oral tests?

    BSEE or its authorized representative may test your employees or 
contract personnel at your worksite or at an onshore location. You and 
your contractors must:
    (a) Allow BSEE or its authorized representative to administer 
written or oral tests; and
    (b) Identify personnel by current position, years of experience in 
present position, years of total oil field experience, and employer's 
name (e.g., operator, contractor, or sub-contractor company name).



Sec. 250.1509  What must I do when BSEE administers or requires hands-on, 

simulator, or other types of testing?

    If BSEE or its authorized representative conducts, or requires you 
or your contractor to conduct hands-on, simulator, or other types of 
testing, you must:
    (a) Allow BSEE or its authorized representative to administer or 
witness the testing;
    (b) Identify personnel by current position, years of experience in 
present position, years of total oil field experience, and employer's 
name (e.g., operator, contractor, or sub-contractor company name); and

[[Page 199]]

    (c) Pay for all costs associated with the testing, excluding salary 
and travel costs for BSEE personnel.



Sec. 250.1510  What will BSEE do if my training program does not comply with 

this subpart?

    If BSEE determines that your training program is not in compliance, 
we may initiate one or more of the following enforcement actions:
    (a) Issue an Incident of Noncompliance (INC);
    (b) Require you to revise and submit to BSEE your training plan to 
address identified deficiencies;
    (c) Assess civil/criminal penalties; or
    (d) Initiate disqualification procedures.



                      Subpart P_Sulphur Operations



Sec. 250.1600  Performance standard.

    Operations to discover, develop, and produce sulphur in the OCS 
shall be in accordance with a BOEM-approved Exploration Plan or 
Development and Production Plan and shall 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 or not leased), the National security or 
defense, and the marine, coastal, or human environment.



Sec. 250.1601  Definitions.

    Terms used in this subpart shall have the meanings as defined below:
    Air line means a tubing string that is used to inject air within a 
sulphur producing well to airlift sulphur out of the well.
    Bleedwater means a mixture of mine water or booster water and 
connate water that is produced by a bleedwell.
    Bleedwell means a well drilled into a producing sulphur deposit that 
is used to control the mine pressure generated by the injection of mine 
water.
    Brine means the water containing dissolved salt obtained from a 
brine well by circulating water into and out of a cavity in the salt 
core of a salt dome.
    Brine well means a well drilled through cap rock into the core at a 
salt dome for the purpose of producing brine.
    Cap rock means the rock formation, a body of limestone, anhydride, 
and/or gypsum, overlying a salt dome.
    Sulphur deposit means a formation of rock that contains elemental 
sulphur.
    Sulphur production rate means the number of long tons of sulphur 
produced during a certain period of time, usually per day.



Sec. 250.1602  Applicability.

    (a) The requirements of this subpart P are applicable to all 
exploration, development, and production operations under an OCS sulphur 
lease. Sulphur operations include all activities conducted under a lease 
for the purpose of discovery or delineation of a sulphur deposit and for 
the development and production of elemental sulphur. Sulphur operations 
also include activities conducted for related purposes. Activities 
conducted for related purposes include, but are not limited to, 
production of other minerals, such as salt, for use in the exploration 
for or the development and production of sulphur. The lessee must have 
obtained the right to produce and/or use these other minerals.
    (b) Lessees conducting sulphur operations in the OCS shall comply 
with the requirements of the applicable provisions of subparts A, B, C, 
I, J, M, N, O, and Q of this part and the applicable provisions of 30 
CFR 550 subparts A, B, C, J and N.
    (c) Lessees conducting sulphur operations in the OCS are also 
required to comply with the requirements in the applicable provisions of 
subparts D, E, F, H, K, and L of this part and the applicable provisions 
of 30 CFR 550, subpart K, where such provisions specifically are 
referenced in this subpart.



Sec. 250.1603  Determination of sulphur deposit.

    (a) Upon receipt of a written request from the lessee, the District 
Manager will determine whether a sulphur deposit has been defined that 
contains sulphur in paying quantities (i.e., sulphur in quantities 
sufficient to yield a return in excess of the costs, after completion of 
the wells, of producing minerals at the wellheads).

[[Page 200]]

    (b) A determination under paragraph (a) of this section shall be 
based upon the following:
    (1) Core analyses that indicate the presence of a producible sulphur 
deposit (including an assay of elemental sulphur);
    (2) An estimate of the amount of recoverable sulphur in long tons 
over a specified period of time; and
    (3) Contour map of the cap rock together with isopach map showing 
the extent and estimated thickness of the sulphur deposit.



Sec. 250.1604  General requirements.

    Sulphur lessees shall comply with requirements of this section when 
conducting well-drilling, well-completion, well-workover, or production 
operations.
    (a) Equipment movement. The movement of well-drilling, well-
completion, or well-workover rigs and related equipment on and off an 
offshore platform, or from one well to another well on the same offshore 
platform, including rigging up and rigging down, shall be conducted in a 
safe manner.
    (b) Hydrogen sulfide (H2S). When a drilling, well-completion, well-
workover, or production operation is being conducted on a well in zones 
known to contain 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, especially during operations such as dismantling wellhead 
equipment and flow lines and circulating the well. The lessee shall also 
take appropriate precautions when H2S is generated as a 
result of sulphur production operations. The lessee shall comply with 
the requirements in Sec. 250.490 of this part as well as the 
requirements of this subpart.
    (c) Welding and burning practices and procedures. All welding, 
burning, and hot-tapping activities involved in drilling, well-
completion, well-workover or production operations shall be conducted 
with properly maintained equipment, trained personnel, and appropriate 
procedures in order to minimize the danger to life and property 
according to the specific requirements in Sec. Sec. 250.109 through 
250.113 of this part.
    (d) Electrical requirements. All electrical equipment and systems 
involved in drilling, well-completion, well-workover, and production 
operations shall be designed, installed, equipped, protected, operated, 
and maintained so as to minimize the danger to life and property in 
accordance with the requirements of Sec. 250.114 of this part.
    (e) Structures on fixed OCS platforms. Derricks, cranes, 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. Prior to moving equipment such as a well-drilling, well-
completion, or well-workover rig or associated equipment or production 
equipment onto a platform, the lessee shall determine the structural 
capability of the platform to safely support the equipment and 
operations, taking into consideration corrosion protection, platform 
age, and previous stresses.
    (f) Traveling-block safety device. All drilling units being used for 
drilling, well-completion, or well-workover 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. 250.1605  Drilling requirements.

    (a) Sulphur leases. Lessees of OCS sulphur leases shall conduct 
drilling operations in accordance with Sec. Sec. 250.1605 through 
250.1619 of this subpart and with other requirements of this part, as 
appropriate.
    (b) Fitness of drilling unit. (1) Drilling units shall be capable of 
withstanding the oceanographic and meteorological conditions for the 
proposed season and location of operations.
    (2) Prior to commencing operation, drilling units shall be made 
available for a complete inspection by the District Manager.
    (3) The lessee shall provide information and data on the fitness of 
the drilling unit to perform the proposed

[[Page 201]]

drilling operation. The information shall be submitted with, or prior 
to, the submission of Form BSEE-0123, Application for Permit to Drill 
(APD), in accordance with Sec. 250.1617 of this subpart. After a 
drilling unit has been approved by a BSEE district office, the 
information required in this paragraph need not be resubmitted unless 
required by the District Manager or there are changes in the equipment 
that affect the rated capacity of the unit.
    (c) Oceanographic, meteorological, and drilling unit performance 
data. Where oceanographic, meteorological, and drilling unit performance 
data are not otherwise readily available, lessees shall collect and 
report such data upon request to the District Manager. The type of 
information to be collected and reported will be determined by the 
District Manager in the interests of safety in the conduct of operations 
and the structural integrity of the drilling unit.
    (d) Foundation requirements. When the lessee fails to provide 
sufficient information pursuant to 30 CFR 550.211 through 550.228 and 30 
CFR 550.241 through 550.262 to support a determination that the seafloor 
is capable of supporting a specific bottom-founded drilling unit under 
the site-specific soil and oceanographic conditions, the District 
Manager may require that additional surveys and soil borings be 
performed and the results submitted for review and evaluation by the 
District Manager before approval is granted for commencing drilling 
operations.
    (e) Tests, surveys, and samples. (1) Lessees shall drill and take 
cores and/or run well and mud logs through the objective interval to 
determine the presence, quality, and quantity of sulphur and other 
minerals (e.g., oil and gas) in the cap rock and the outline of the 
commercial sulphur deposit.
    (2) Inclinational surveys shall be obtained on all vertical wells at 
intervals not exceeding 1,000 feet during the normal course of drilling. 
Directional surveys giving both inclination and azimuth shall be 
obtained on all directionally drilled wells at intervals not exceeding 
500 feet during the normal course of drilling and at intervals not 
exceeding 200 feet in all planned angle-change portions of the borehole.
    (3) Directional surveys giving both inclination and azimuth shall be 
obtained on both vertically and directionally drilled wells at intervals 
not exceeding 500 feet prior to or upon setting a string of casing, or 
production liner, and at total depth. Composite directional surveys 
shall be prepared with the interval shown from the bottom of the 
conductor casing. In calculating all surveys, a correction from the true 
north to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north 
shall be made after making the magnetic-to-true-north correction. A 
composite dipmeter directional survey or a composite measurement while-
drilling directional survey will be acceptable as fulfilling the 
applicable requirements of this paragraph.
    (4) Wells are classified as vertical if the calculated average of 
inclination readings weighted by the respective interval lengths between 
readings from surface to drilled depth does not exceed 3 degrees from 
the vertical. When the calculated average inclination readings weighted 
by the length of the respective interval between readings from the 
surface to drilled depth exceeds 3 degrees, the well is classified as 
directional.
    (5) At the request of a holder of an adjoining lease, the Regional 
Supervisor may, for the protection of correlative rights, furnish a copy 
of the directional survey to that leaseholder.
    (f) Fixed drilling platforms. Applications for installation of fixed 
drilling platforms or structures including artificial islands shall be 
submitted in accordance with the provisions of subpart I, Platforms and 
Structures, of this part. Mobile drilling units that have their jacking 
equipment removed or have been otherwise immobilized are classified as 
fixed bottom founded drilling platforms.
    (g) Crane operations. You must operate a crane installed on fixed 
platforms according to Sec. 250.108 of this subpart.
    (h) 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

[[Page 202]]

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. 250.1606  Control of wells.

    The lessee shall take necessary precautions to keep its wells under 
control at all times. Operations shall be conducted in a safe and 
workmanlike manner. The lessee shall utilize the best available and 
safest drilling technologies and state-of-the-art methods to evaluate 
and minimize the potential for a well to flow or kick. The lessee shall 
utilize personnel who are trained and competent and shall utilize and 
maintain equipment and materials necessary to assure the safety and 
protection of personnel, equipment, natural resources, and the 
environment.



Sec. 250.1607  Field rules.

    When geological and engineering information in a field enables a 
District Manager to determine specific operating requirements, field 
rules may be established for drilling, well completion, or well workover 
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 rules have been established, operations in the field shall 
be conducted in accordance with such rules and other requirements of 
this subpart. Field 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. 250.1608  Well casing and cementing.

    (a) General requirements. (1) For the purpose of this subpart, the 
several casing strings in order of normal installation are:
    (i) Drive or structural,
    (ii) Conductor,
    (iii) Cap rock casing,
    (iv) Bobtail cap rock casing (required when the cap rock casing does 
not penetrate into the cap rock),
    (v) Second cap rock casing (brine wells), and
    (vi) Production liner.
    (2) The lessee shall case and cement all wells with a sufficient 
number of strings of casing cemented in a manner necessary to prevent 
release of fluids from any stratum through the wellbore (directly or 
indirectly) into the sea, protect freshwater aquifers from 
contamination, support unconsolidated sediments, and otherwise provide a 
means of control of the formation pressures and fluids. Cement 
composition, placement techniques, and waiting time shall be designed 
and conducted so that the cement in place behind the bottom 500 feet of 
casing or total length of annular cement fill, if less, attains a 
minimum compressive strength of 160 pounds per square inch (psi).
    (3) The lessee shall install casing designed to withstand the 
anticipated stresses imposed by tensile, compressive, and buckling 
loads; burst and collapse pressures; thermal effects; and combinations 
thereof. Safety factors in the drilling and casing program designs shall 
be of sufficient magnitude to provide well control during drilling and 
to assure safe operations for the life of the well.
    (4) In cases where cement has filled the annular space back to the 
mud line, the cement may be washed out or displaced to a depth not 
exceeding the depth of the structural casing shoe to facilitate casing 
removal upon well abandonment if the District Manager determines that 
subsurface protection against damage to freshwater aquifers and against 
damage caused by adverse loads, pressures, and fluid flows is not 
jeopardized.
    (5) If there are indications of inadequate cementing (such as lost 
returns, cement channeling, or mechanical failure of equipment), the 
lessee shall evaluate the adequacy of the cementing operations by 
pressure testing the casing shoe. If the test indicates inadequate 
cementing, the lessee shall initiate remedial action as approved by the 
District Manager. For cap rock casing, the test for adequacy of 
cementing shall be the pressure testing of the annulus between the cap 
rock and the conductor casings. The pressure shall

[[Page 203]]

not exceed 70 percent of the burst pressure of the conductor casing or 
70 percent of the collapse pressure of the cap rock casing.
    (b) Drive or structural casing. This casing shall be set by driving, 
jetting, or drilling to a minimum depth of 100 feet below the mud line 
or such other depth, as may be required or approved by the District 
Manager, in order to support unconsolidated deposits and to provide hole 
stability for initial drilling operations. If this portion of the hole 
is drilled, a quantity of cement sufficient to fill the annular space 
back to the mud line shall be used.
    (c) Conductor and cap rock casing setting and cementing 
requirements. (1) Conductor and cap rock casing design and setting 
depths shall be based upon relevant engineering and geologic factors 
including the presence or absence of hydrocarbons, potential hazards, 
and water depths. The proposed casing setting depths may be varied, 
subject to District Manager approval, to permit the casing to be set in 
a competent formation or through formations determined desirable to be 
isolated from the wellbore by casing for safer drilling operations. 
However, the conductor casing shall be set immediately prior to drilling 
into formations known to contain oil or gas or, if unknown, upon 
encountering such formations. Cap rock casing shall be set and cemented 
through formations known to contain oil or gas or, if unknown, upon 
encountering such formations. Upon encountering unexpected formation 
pressures, the lessee shall submit a revised casing program to the 
District Manager for approval.
    (2) Conductor casing shall be cemented with a quantity of cement 
that fills the calculated annular space back to the mud line. Cement 
fill shall be verified by the observation of cement returns. In the 
event that observation of cement returns is not feasible, additional 
quantities of cement shall be used to assure fill to the mud line.
    (3) Cap rock casing shall be cemented with a quantity of cement that 
fills the calculated annular space to at least 200 feet inside the 
conductor casing. When geologic conditions such as near surface 
fractures and faulting exist, cap rock casing shall be cemented with a 
quantity of cement that fills the calculated annular space to the mud 
line, unless otherwise approved by the District Manager. In brine wells, 
the second cap rock casing shall be cemented with a quantity of cement 
that fills the calculated annular space to at least 200 feet above the 
setting depth of the first cap rock casing.
    (d) Bobtail cap rock casing setting and cementing requirements. (1) 
Bobtail cap rock casing shall be set on or just in cap rock and lapped a 
minimum of 100 feet into the previous casing string.
    (2) Sufficient cement shall be used to fill the annular space to the 
top of the bobtail cap rock casing.
    (e) Production liner setting and cementing requirements. (1) 
Production liners for sulphur wells and bleedwells shall be set in cap 
rock at or above the bottom of the open hole (hole that is open in cap 
rock, below the bottom of the cap rock casing) and lapped into the 
previous casing string or to the surface. For brine wells, the liner 
shall be set in salt and lapped into the previous casing string or to 
the surface.
    (2) The production liner is not required to be cemented unless the 
cap rock contains oil or gas. If the cap rock contains oil or gas, 
sufficient cement shall be used to fill the annular space to the top of 
the production liner.



Sec. 250.1609  Pressure testing of casing.

    (a) Prior to drilling the plug after cementing, all casing strings, 
except the drive or structural casing, shall be pressure tested. The 
conductor casing shall be tested to at least 200 psi. All casing strings 
below the conductor casing shall be tested to 500 psi or 0.22 psi/ft, 
whichever is greater. (When oil or gas is not present in the cap rock, 
the production liner need not be cemented in place; thus, it would not 
be subject to pressure testing.) If the pressure declines more than 10 
percent in 30 minutes or if there is another indication of a leak, the 
casing shall be recemented, repaired, or an additional casing string run 
and the casing tested again. The above procedures shall be repeated 
until a satisfactory test is obtained. The time, conditions of testing, 
and results of all casing pressure tests shall be recorded in the 
driller's report.

[[Page 204]]

    (b) After cementing any string of casing other than structural, 
drilling shall not be resumed until there has been a timelapse of at 
least 8 hours under pressure for the conductor casing string or 12 hours 
under pressure for all other casing strings. Cement is considered under 
pressure if one or more float valves are shown to be holding the cement 
in place or when other means of holding pressure are used.



Sec. 250.1610  Blowout preventer systems and system components.

    (a) General. The blowout preventer (BOP) systems and system 
components shall be designed, installed, used, maintained, and tested to 
assure well control.
    (b) BOP stacks. The BOP stacks shall consist of an annular preventer 
and the number of ram-type preventers as specified under paragraphs (e) 
and (f) of this section. The pipe rams shall be of proper size to fit 
the drill pipe in use.
    (c) Working pressure. The working-pressure rating of any BOP shall 
exceed the surface pressure to which it may be anticipated to be 
subjected.
    (d) BOP equipment. All BOP systems shall be equipped and provided 
with the following:
    (1) An accumulator system that provides sufficient capacity to 
supply 1.5 times the volume necessary to close and hold closed all BOP 
equipment units with a minimum pressure of 200 psi above the precharge 
pressure, without assistance from a charging system. Accumulator 
regulators supplied by rig air that do not have a secondary source of 
pneumatic supply must be equipped with manual overrides or other devices 
alternately provided to ensure capability of hydraulic operations if rig 
air is lost.
    (2) An automatic backup to the accumulator system. The backup system 
shall be supplied by a power source independent from the power source to 
the primary accumulator system. The automatic backup system shall 
possess sufficient capability to close the BOP and hold it closed.
    (3) At least one operable remote BOP control station in addition to 
the one on the drilling floor. This control station shall be in a 
readily accessible location away from the drilling floor.
    (4) A drilling spool with side outlets, if side outlets are not 
provided in the body of the BOP stack, to provide for separate kill and 
choke lines.
    (5) A choke line and a kill line each equipped with two full-opening 
valves. At least one of the valves on the choke line and one valve on 
the kill line shall be remotely controlled, except that a check valve 
may be installed on the kill line in lieu of the remotely controlled 
valve, provided that two readily accessible manual valves are in place 
and the check valve is placed between the manual valve and the pump.
    (6) A fill-up line above the uppermost preventer.
    (7) A choke manifold designed with consideration of anticipated 
pressures to which it may be subjected, method of well control to be 
employed, surrounding environment, and corrosiveness, volume, and 
abrasiveness of fluids. The choke manifold shall also meet the following 
requirements:
    (i) Manifold and choke equipment subject to well and/or pump 
pressure shall have a rated working pressure at least as great as the 
rated working pressure of the ram-type BOP's or as otherwise approved by 
the District Manager;
    (ii) All components of the choke manifold system shall be protected 
from freezing by heating, draining, or filling with proper fluids; and
    (iii) When buffer tanks are installed downstream of the choke 
assemblies for the purpose of manifolding the bleed lines together, 
isolation valves shall be installed on each line.
    (8) Valves, pipes, flexible steel hoses, and other fittings upstream 
of, and including, the choke manifold with a pressure rating at least as 
great as the rated working pressure of the ram-type BOP's unless 
otherwise approved by the District Manager.
    (9) A wellhead assembly with a rated working pressure that exceeds 
the pressure to which it might be subjected.
    (10) The following system components:
    (i) A kelly cock (an essentially full-opening valve) installed below 
the swivel and a similar valve of such design that it can be run through 
the BOP stack installed at the bottom of the kelly. A wrench to fit each 
valve

[[Page 205]]

shall be stored in a location readily accessible to the drilling crew;
    (ii) An inside BOP and an essentially full-opening, drill-string 
safety valve in the open position on the rig floor at all times while 
drilling operations are being conducted. These valves shall be 
maintained on the rig floor to fit all connections that are in the drill 
string. A wrench to fit the drill-string safety valve shall be stored in 
a location readily accessible to the drilling crew;
    (iii) A safety valve available on the rig floor assembled with the 
proper connection to fit the casing string being run in the hole; and
    (iv) Locking devices installed on the ram-type preventers.
    (e) BOP requirements. Prior to drilling below cap rock casing, a BOP 
system shall be installed consisting of at least three remote-
controlled, hydraulically operated BOP's including at least one equipped 
with pipe rams, one with blind rams, and one annular type.
    (f) Tapered drill-string operations. Prior to commencing tapered 
drill-string operations, the BOP stack shall be equipped with 
conventional and/or variable-bore pipe rams to provide either of the 
following:
    (1) One set of variable bore rams capable of sealing around both 
sizes in the string and one set of blind rams, or
    (2) One set of pipe rams capable of sealing around the larger size 
string, provided that blind-shear ram capability is present, and 
crossover subs to the larger size pipe are readily available on the rig 
floor.



Sec. 250.1611  Blowout preventer systems tests, actuations, inspections, and 

maintenance.

    (a) Prior to conducting high-pressure tests, all BOP systems shall 
be tested to a pressure of 200 to 300 psi.
    (b) Ram-type BOP's and the choke manifold shall be pressure tested 
with water to rated working pressure or as otherwise approved by the 
District Manager. Annular type BOP's shall be pressure tested with water 
to 70 percent of rated working pressure or as otherwise approved by the 
District Manager.
    (c) In conjunction with the weekly pressure test of BOP systems 
required in paragraph (d) of this section, the choke manifold valves, 
upper and lower kelly cocks, and drill-string safety valves shall be 
pressure tested to pipe-ram test pressures. Safety valves with proper 
casing connections shall be actuated prior to running casing.
    (d) BOP system shall be pressure tested as follows:
    (1) When installed;
    (2) Before drilling out each string of casing or before continuing 
operations in cases where cement is not drilled out;
    (3) At least once each week, but not exceeding 7 days between 
pressure tests, alternating between control stations. If either control 
system is not functional, further drilling operations shall be suspended 
until that system becomes operable. A period of more than 7 days between 
BOP tests is allowed when there is a stuck drill pipe or there are 
pressure control operations and remedial efforts are being performed, 
provided that the pressure tests are conducted as soon as possible and 
before normal operations resume. The date, time, and reason for 
postponing pressure testing shall be entered into the driller's report. 
Pressure testing shall be performed at intervals to allow each drilling 
crew to operate the equipment. The weekly pressure test is not required 
for blind and blind-shear rams;
    (4) Blind and blind-shear rams shall be actuated at least once every 
7 days. Closing pressure on the blind and blind-shear rams greater than 
necessary to indicate proper operation of the rams is not required;
    (5) Variable bore-pipe rams shall be pressure tested against all 
sizes of pipe in use, excluding drill collars and bottomhole tools; and
    (6) Following the disconnection or repair of any well-pressure 
containment seal in the wellhead/BOP stack assembly. In this situation, 
the pressure tests may be limited to the affected component.
    (e) All BOP systems shall be inspected and maintained to assure that 
the equipment will function properly. The BOP systems shall be visually 
inspected at least once each day. The manufacturer's recommended 
inspection and maintenance procedures are

[[Page 206]]

acceptable as guidelines in complying with this requirement.
    (f) The lessee shall record pressure conditions during BOP tests on 
pressure charts, unless otherwise approved by the District Manager. The 
test duration for each BOP component tested shall be sufficient to 
demonstrate that the component is effectively holding pressure. The 
charts shall be certified as correct by the operator's representative at 
the facility.
    (g) The time, date, and results of all pressure tests, actuations, 
inspections, and crew drills of the BOP system and system components 
shall be recorded in the driller's report. The BOP tests shall be 
documented in accordance with the following:
    (1) The documentation shall indicate the sequential order of BOP and 
auxiliary equipment testing and the pressure and duration of each test. 
As an alternate, the documentation in the driller's report may reference 
a BOP test plan that contains the required information and is retained 
on file at the facility.
    (2) The control station used during the test shall be identified in 
the driller's report.
    (3) Any problems or irregularities observed during BOP and auxiliary 
equipment testing and any actions taken to remedy such problems or 
irregularities shall be noted in the driller's report.
    (4) Documentation required to be entered in the driller's report may 
instead be referenced in the driller's report. All records, including 
pressure charts, driller's report, and referenced documents, pertaining 
to BOP tests, actuations, and inspections, shall be available for BSEE 
review at the facility for the duration of the drilling activity. 
Following completion of the drilling activity, all drilling records 
shall be retained for a period of 2 years at the facility, at the 
lessee's field office nearest the OCS facility, or at another location 
conveniently available to the District Manager.



Sec. 250.1612  Well-control drills.

    Well-control drills shall be conducted for each drilling crew in 
accordance with the requirements set forth in Sec. 250.462 of this part 
or as approved by the District Manager.



Sec. 250.1613  Diverter systems.

    (a) When drilling a conductor or cap rock hole, all drilling units 
shall be equipped with a diverter system consisting of a diverter 
sealing element, diverter lines, and control systems. The diverter 
system shall be designed, installed, and maintained so as to divert 
gases, water, mud, and other materials away from the facilities and 
personnel.
    (b) The diverter system shall be equipped with remote-control valves 
in the flow lines that can be operated from at least one remote-control 
station in addition to the one on the drilling floor. Any valve used in 
a diverter system shall be full opening. No manual or butterfly valves 
shall be installed in any part of a diverter system. There shall be a 
minimum number of turns in the vent line(s) downstream of the spool 
outlet flange, and the radius of curvature of turns shall be as large as 
practicable. Flexible hose may be used for diversion lines instead of 
rigid pipe if the flexible hose has integral end couplings. The entire 
diverter system shall be firmly anchored and supported to prevent 
whipping and vibrations. All diverter control equipment and lines shall 
be protected from physical damage from thrown and falling objects.
    (c) For drilling operations conducted with a surface wellhead 
configuration, the following shall apply:
    (1) If the diverter system utilizes only one spool outlet, branch 
lines shall be installed to provide downwind diversion capability, and
    (2) No spool outlet or diverter line internal diameter shall be less 
than 10 inches, except that dual spool outlets are acceptable if each 
outlet has a minimum internal diameter of 8 inches, and both outlets are 
piped to overboard lines and that each line downstream of the changeover 
nipple at the spool has a minimum internal diameter of 10 inches.
    (d) The diverter sealing element and diverter valves shall be 
pressure tested to a minimum of 200 psi when nippled upon conductor 
casing. No more than 7 days shall elapse between subsequent pressure 
tests. The diverter sealing element, diverter valves, and diverter 
control systems (including the remote)

[[Page 207]]

shall be actuation tested, and the diverter lines shall be tested for 
flow prior to spudding and thereafter at least once each 24-hour period 
alternating between control stations. All test times and results shall 
be recorded in the driller's report.



Sec. 250.1614  Mud program.

    (a) The quantities, characteristics, use, and testing of drilling 
mud and the related drilling procedures shall be designed and 
implemented to prevent the loss of well control.
    (b) The lessee shall comply with requirements concerning mud 
control, mud test and monitoring equipment, mud quantities, and safety 
precautions in enclosed mud handling areas as prescribed in Sec. Sec. 
250.455 through 250.459 of this part, except that the installation of an 
operable degasser in the mud system as required in Sec. 250.456(g) is 
not required for sulphur operations.



Sec. 250.1615  Securing of wells.

    A downhole-safety device such as a cement plug, bridge plug, or 
packer shall be timely installed when drilling operations are 
interrupted by events such as those that force evacuation of the 
drilling crew, prevent station keeping, or require repairs to major 
drilling units or well-control equipment. The use of blind-shear rams or 
pipe rams and an inside BOP may be approved by the District Manager in 
lieu of the above requirements if cap rock casing has been set.



Sec. 250.1616  Supervision, surveillance, and training.

    (a) The lessee shall provide onsite supervision of drilling 
operations at all times.
    (b) From the time drilling operations are initiated and until the 
well is completed or abandoned, a member of the drilling crew or the 
toolpusher shall maintain rig-floor surveillance continuously, unless 
the well is secured with BOP's, bridge plugs, packers, or cement plugs.
    (c) Lessee and drilling contractor personnel shall be trained and 
qualified in accordance with the provisions of subpart O of this part. 
Records of specific training that lessee and drilling contractor 
personnel have successfully completed, the dates of completion, and the 
names and dates of the courses shall be maintained at the drill site.



Sec. 250.1617  Application for permit to drill.

    (a) Before drilling a well under a BOEM-approved Exploration Plan, 
Development and Production Plan, or Development Operations Coordination 
Document, you must file Form BSEE-0123, APD, with the District Manager 
for approval. The submission of your APD must be accompanied by payment 
of the service fee listed in Sec. 250.125. Before starting operations, 
you must receive written approval from the District Manager unless you 
received oral approval under Sec. 250.140.
    (b) An APD shall include rated capacities of the proposed drilling 
unit and of major drilling equipment. After a drilling unit has been 
approved for use in a BSEE district, the information need not be 
resubmitted unless required by the District Manager or there are changes 
in the equipment that affect the rated capacity of the unit.
    (c) An APD shall include a fully completed Form BSEE-0123 and the 
following:
    (1) A plat, drawn to a scale of 2,000 feet to the inch, showing the 
surface and subsurface location of the well to be drilled and of all the 
wells previously drilled in the vicinity from which information is 
available. For development wells on a lease, the wells previously 
drilled in the vicinity need not be shown on the plat. Locations shall 
be indicated in feet from the nearest block line;
    (2) The design criteria considered for the well and for well 
control, including the following:
    (i) Pore pressure;
    (ii) Formation fracture gradients;
    (iii) Potential lost circulation zones;
    (iv) Mud weights;
    (v) Casing setting depths;
    (vi) Anticipated surface pressures (which for purposes of this 
section are defined as the pressure that can reasonably be expected to 
be exerted upon a casing string and its related wellhead equipment). In 
the calculation of anticipated surface pressure, the lessee shall take 
into account the drilling,

[[Page 208]]

completion, and producing conditions. The lessee shall consider mud 
densities to be used below various casing strings, fracture gradients of 
the exposed formations, casing setting depths, and cementing intervals, 
total well depth, formation fluid type, and other pertinent conditions. 
Considerations for calculating anticipated surface pressure may vary for 
each segment of the well. The lessee shall include as a part of the 
statement of anticipated surface pressure the calculations used to 
determine this pressure during the drilling phase and the completion 
phase, including the anticipated surface pressure used for production 
string design; and
    (vii) If a shallow hazards site survey is conducted, the lessee 
shall submit with or prior to the submittal of the APD, two copies of a 
summary report describing the geological and manmade conditions present. 
The lessee shall also submit two copies of the site maps and data 
records identified in the survey strategy.
    (3) A BOP equipment program including the following:
    (i) The pressure rating of BOP equipment,
    (ii) A schematic drawing of the diverter system to be used (plan and 
elevation views) showing spool outlet internal diameter(s); diverter 
line lengths and diameters, burst strengths, and radius of curvature at 
each turn; valve type, size, working-pressure rating, and location; the 
control instrumentation logic; and the operating procedure to be used by 
personnel, and
    (iii) A schematic drawing of the BOP stack showing the inside 
diameter of the BOP stack and the number of annular, pipe ram, variable-
bore pipe ram, blind ram, and blind-shear ram preventers.
    (4) A casing program including the following:
    (i) Casing size, weight, grade, type of connection and setting 
depth, and
    (ii) Casing design safety factors for tension, collapse, and burst 
with the assumptions made to arrive at these values.
    (5) The drilling prognosis including the following:
    (i) Estimated coring intervals,
    (ii) Estimated depths to the top of significant marker formations, 
and
    (iii) Estimated depths at which encounters with fresh water, 
sulphur, oil, gas, or abnormally pressured water are expected.
    (6) A cementing program including type and amount of cement in cubic 
feet to be used for each casing string;
    (7) A mud program including the minimum quantities of mud and mud 
materials, including weight materials, to be kept at the site;
    (8) A directional survey program for directionally drilled wells;
    (9) An H2S Contingency Plan, if applicable, and if not 
previously submitted; and
    (10) Such other information as may be required by the District 
Manager.
    (d) Public information copies of the APD shall be submitted in 
accordance with Sec. 250.186 of this part.



Sec. 250.1618  Application for permit to modify.

    (a) You must submit requests for changes in plans, changes in major 
drilling equipment, proposals to deepen, sidetrack, complete, workover, 
or plug back a well, or engage in similar activities to the District 
Manager on Form BSEE-0124, Application for Permit to Modify (APM). The 
submission of your APM must be accompanied by payment of the service fee 
listed in Sec. 250.125. Before starting operations associated with the 
change, you must receive written approval from the District Manager 
unless you received oral approval under Sec. 250.140.
    (b) The Form BSEE-0124 submittal shall contain a detailed statement 
of the proposed work that will materially change from the work described 
in the approved APD. Information submitted shall include the present 
state of the well, including the production liner and last string of 
casing, the well depth and production zone, and the well's capability to 
produce. Within 30 days after completion of the work, a subsequent 
detailed report of all the work done and the results obtained shall be 
submitted.
    (c) Public information copies of Form BSEE-0124 shall be submitted 
in accordance with Sec. 250.186 of this part.

[[Page 209]]



Sec. 250.1619  Well records.

    (a) Complete and accurate records for each well and all well 
operations shall be retained for a period of 2 years at the lessee's 
field office nearest the OCS facility or at another location 
conveniently available to the District Manager. The records shall 
contain a description of any significant malfunction or problem; all the 
formations penetrated; the content and character of sulphur in each 
formation if cored and analyzed; the kind, weight, size, grade, and 
setting depth of casing; all well logs and surveys run in the wellbore; 
and all other information required by the District Manager in the 
interests of resource evaluation, prevention of waste, conservation of 
natural resources, protection of correlative rights, safety of 
operations, and environmental protection.
    (b) When drilling operations are suspended or temporarily prohibited 
under the provisions of Sec. 250.170 of this part, the lessee shall, 
within 30 days after termination of the suspension or temporary 
prohibition or within 30 days after the completion of any activities 
related to the suspension or prohibition, transmit to the District 
Manager duplicate copies of the records of all activities related to and 
conducted during the suspension or temporary prohibition on, or attached 
to, Form BSEE-0125, End of Operations Report, or Form BSEE-0124, 
Application for Permit to Modify, as appropriate.
    (c) Upon request by the District Manager or Regional Supervisor, the 
lessee shall furnish the following:
    (1) Copies of the records of any of the well operations specified in 
paragraph (a) of this section;
    (2) Copies of the driller's report at a frequency as determined by 
the District Manager. Items to be reported include spud dates, casing 
setting depths, cement quantities, casing characteristics, mud weights, 
lost returns, and any unusual activities; and
    (3) Legible, exact copies of reports on cementing, acidizing, 
analyses of cores, testing, or other similar services.
    (d) As soon as available, the lessee shall transmit copies of logs 
and charts developed by well-logging operations, directional-well 
surveys, and core analyses. Composite logs of multiple runs and 
directional-well surveys shall be transmitted to the District Manager in 
duplicate as soon as available but not later than 30 days after 
completion of such operations for each well.
    (e) If the District Manager determines that circumstances warrant, 
the lessee shall submit any other reports and records of operations in 
the manner and form prescribed by the District Manager.



Sec. 250.1620  Well-completion and well-workover requirements.

    (a) Lessees shall conduct well-completion and well-workover 
operations in sulphur wells, bleedwells, and brine wells in accordance 
with Sec. Sec. 250.1620 through 250.1626 of this part and other 
provisions of this part as appropriate (see Sec. Sec. 250.501 and 
250.601 of this part for the definition of well-completion and well-
workover operations).
    (b) Well-completion and well-workover operations shall 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.



Sec. 250.1621  Crew instructions.

    Prior to engaging in well-completion or well-workover operations, 
crew members shall be instructed in the safety requirements of the 
operations to be performed, possible hazards to be encountered, and 
general safety considerations to protect personnel, equipment, and the 
environment. Date and time of safety meetings shall be recorded and 
available for BSEE review.



Sec. 250.1622  Approvals and reporting of well-completion and well-workover 

operations.

    (a) No well-completion or well-workover operation shall begin until 
the lessee receives written approval from the District Manager. Approval 
for such operations shall be requested on Form BSEE-0124. Approvals by 
the District Manager shall be based upon a determination that the 
operations will be conducted in a manner to protect

[[Page 210]]

against harm or damage to life, property, natural resources of the OCS, 
including any mineral deposits, the National security or defense, or the 
marine, coastal, or human environment.
    (b) The following information shall be submitted with Form BSEE-0124 
(or with Form BSEE-0123):
    (1) A brief description of the well-completion or well-workover 
procedures to be followed;
    (2) When changes in existing subsurface equipment are proposed, a 
schematic drawing showing the well equipment; and
    (3) Where the well is in zones known to contain H2S or 
zones where the presence of H2S is unknown, a description of 
the safety precautions to be implemented.
    (c)(1) Within 30 days after completion, Form BSEE-0125, including a 
schematic of the tubing and the results of any well tests, shall be 
submitted to the District Manager.
    (2) Within 30 days after completing the well-workover operation, 
except routine operations, Form BSEE-0124 shall be submitted to the 
District Manager and shall include the results of any well tests and a 
new schematic of the well if any subsurface equipment has been changed.



Sec. 250.1623  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 and well-workover 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 or a workover 
string, the annulus shall be filled with well-control fluid before the 
change in fluid level decreases the hydrostatic pressure 75 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 for measuring the amount of well-
control fluid required to fill the hole shall be utilized.



Sec. 250.1624  Blowout prevention equipment.

    (a) The BOP system and system components and related well-control 
equipment shall be designed, used, maintained, and tested in a manner 
necessary to assure well control in foreseeable conditions and 
circumstances, including subfreezing conditions. The working pressure of 
the BOP system and system components shall equal or exceed the expected 
surface pressure to which they may be subjected.
    (b) The minimum BOP stack for well-completion operations or for 
well-workover operations with the tree removed shall consist of the 
following:
    (1) Three remote-controlled, hydraulically operated preventers 
including at least one equipped with pipe rams, one with blind rams, and 
one annular type.
    (2) When a tapered string is used, the minimum BOP stack shall 
consist of either of the following:
    (i) An annular preventer, one set of variable bore rams capable of 
sealing around both sizes in the string, and one set of blind rams; or
    (ii) An annular preventer, one set of pipe rams capable of sealing 
around the larger size string, a preventer equipped with blind-shear 
rams, and a crossover sub to the larger size pipe that shall be readily 
available on the rig floor.
    (c) The BOP systems for well-completion operations, or for well-
workover

[[Page 211]]

operations with the tree removed, shall be equipped with the following:
    (1) An accumulator system that provides sufficient capacity to 
supply 1.5 times the volume necessary to close and hold closed all BOP 
equipment units with a minimum pressure of 200 psi above the precharge 
pressure without assistance from a charging system. After February 14, 
1992, accumulator regulators supplied by rig air which do not have a 
secondary source of pneumatic supply shall be equipped with manual 
overrides or alternately other devices provided to ensure capability of 
hydraulic operations if rig air is lost;
    (2) An automatic backup to the accumulator system supplied by a 
power source independent from the power source to the primary 
accumulator system and possessing sufficient capacity to close all BOP's 
and hold them closed;
    (3) Locking devices for the pipe-ram preventers;
    (4) At least one remote BOP-control station and one BOP-control 
station on the rig floor; and
    (5) A choke line and a kill line each equipped with two full-opening 
valves and a choke manifold. One of the choke-line valves and one of the 
kill-line valves shall be remotely controlled except that a check valve 
may be installed on the kill line in lieu of the remotely-controlled 
valve provided that two readily accessible manual valves are in place, 
and the check valve is placed between the manual valve and the pump.
    (d) The minimum BOP-stack components for well-workover operations 
with the tree in place and performed through the wellhead inside of the 
sulphur line using small diameter jointed pipe (usually \3/4\ inch to 
1\1/4\ inch) as a work string; i.e., small-tubing operations, shall 
consist of the following:
    (1) For air line changes, the well shall be killed prior to 
beginning operations. The procedures for killing the well shall be 
included in the description of well-workover procedures in accordance 
with Sec. 250.1622 of this part. Under these circumstances, no BOP 
equipment is required.
    (2) For other work inside of the sulphur line, a tubing stripper or 
annular preventer shall be installed prior to beginning work.
    (e) An essentially full-opening, work-string safety valve shall be 
maintained on the rig floor at all times during well-completion 
operations. A wrench to fit the work-string safety valve shall be 
readily available. Proper connections shall be readily available for 
inserting a safety valve in the work string.



Sec. 250.1625  Blowout preventer system testing, records, and drills.

    (a) Prior to conducting high-pressure tests, all BOP systems shall 
be tested to a pressure of 200 to 300 psi.
    (b) Ram-type BOP's and the choke manifold shall be pressure tested 
with water to a rated working pressure or as otherwise approved by the 
District Manager. Annular type BOP's shall be pressure tested with water 
to 70 percent of rated working pressure or as otherwise approved by the 
District Manager.
    (c) In conjunction with the weekly pressure test of BOP systems 
required in paragraph (d) of this section, the choke manifold valves, 
upper and lower kelly cocks, and drill-string safety valves shall be 
pressure tested to pipe-ram test pressures. Safety valves with proper 
casing connections shall be actuated prior to running casing.
    (d) BOP system shall be pressure tested as follows:
    (1) When installed;
    (2) Before drilling out each string of casing or before continuing 
operations in cases where cement is not drilled out;
    (3) At least once each week, but not exceeding 7 days between 
pressure tests, alternating between control stations. If either control 
system is not functional, further drilling operations shall be suspended 
until that system becomes operable. A period of more than 7 days between 
BOP tests is allowed when there is a stuck drill pipe or there are 
pressure control operations, and remedial efforts are being performed, 
provided that the pressure tests are conducted as soon as possible and 
before normal operations resume. The time, date, and reason for 
postponing pressure testing shall be entered into the driller's report. 
Pressure

[[Page 212]]

testing shall be performed at intervals to allow each drilling crew to 
operate the equipment. The weekly pressure test is not required for 
blind and blind-shear rams;
    (4) Blind and blind-shear rams shall be actuated at least once every 
7 days. Closing pressure on the blind and blind-shear rams greater than 
necessary to indicate proper operation of the rams is not required;
    (5) Variable bore-pipe rams shall be pressure tested against all 
sizes of pipe in use, excluding drill collars and bottomhole tools; and
    (6) Following the disconnection or repair of any well-pressure 
containment seal in the wellhead/BOP stack assembly, the pressure tests 
may be limited to the affected component.
    (e) All personnel engaged in well-completion operations shall 
participate in a weekly BOP drill to familiarize crew members with 
appropriate safety measures.
    (f) The lessee shall record pressure conditions during BOP tests on 
pressure charts, unless otherwise approved by the District Manager. The 
test duration for each BOP component tested shall be sufficient to 
demonstrate that the component is effectively holding pressure. The 
charts shall be certified as correct by the operator's representative at 
the facility.
    (g) The time, date, and results of all pressure tests, actuations, 
inspections, and crew drills of the BOP system and system components 
shall be recorded in the operations log. The BOP tests shall be 
documented in accordance with the following:
    (1) The documentation shall indicate the sequential order of BOP and 
auxiliary equipment testing and the pressure and duration of each test. 
As an alternate, the documentation in the operations log may reference a 
BOP test plan that contains the required information and is retained on 
file at the facility.
    (2) The control station used during the test shall be identified in 
the operations log.
    (3) Any problems or irregularities observed during BOP and auxiliary 
equipment testing and any actions taken to remedy such problems or 
irregularities shall be noted in the operations log.
    (4) Documentation required to be entered in the driller's report may 
instead be referenced in the driller's report. All records, including 
pressure charts, driller's report, and referenced documents, pertaining 
to BOP tests, actuations, and inspections shall be available for BSEE 
review at the facility for the duration of the drilling activity. 
Following completion of the drilling activity, all drilling records 
shall be retained for a period of 2 years at the facility, at the 
lessee's field office nearest the OCS facility, or at another location 
conveniently available to the District Manager.



Sec. 250.1626  Tubing and wellhead equipment.

    (a) No tubing string shall be placed into 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) Wellhead, tree, and related equipment shall be designed, 
installed, tested, used, and maintained so as to achieve and maintain 
pressure control.



Sec. 250.1627  Production requirements.

    (a) The lessee shall conduct sulphur production operations in 
compliance with the approved Development and Production Plan 
requirements of Sec. Sec. 250.1627 through 250.1634 of this subpart and 
requirements of this part, as appropriate.
    (b) Production safety equipment shall be designed, installed, used, 
maintained, and tested in a manner to assure the safety of operations 
and protection of the human, marine, and coastal environments.



Sec. 250.1628  Design, installation, and operation of production systems.

    (a) General. All production facilities shall be designed, installed, 
and maintained in a manner that provides for efficiency and safety of 
operations and protection of the environment.
    (b) Approval of design and installation features for sulphur 
production facilities. Prior to installation, the lessee shall submit a 
sulphur production system

[[Page 213]]

application, in duplicate, to the District Manager for approval. The 
application shall include information relative to the proposed design 
and installation features. Information concerning approved design and 
installation features shall be maintained by the lessee at the lessee's 
offshore field office nearest the OCS facility or at another location 
conveniently available to the District Manager. All approvals are 
subject to field verification. The application shall include the 
following:
    (1) A schematic flow diagram showing size, capacity, design, working 
pressure of separators, storage tanks, compressor pumps, metering 
devices, and other sulphur-handling vessels;
    (2) A schematic piping diagram showing the size and maximum 
allowable working pressures as determined in accordance with API RP 14E, 
Recommended Practice for Design and Installation of Offshore Production 
Platform Piping Systems (as incorporated by reference in Sec. 250.198);
    (3) Electrical system information including a plan of each platform 
deck, outlining all hazardous areas classified 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, 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), and outlining areas in which potential 
ignition sources are to be installed;
    (4) Certification that the design for the mechanical and electrical 
systems to be installed were approved by registered professional 
engineers. After these systems are installed, the lessee shall submit a 
statement to the District Manager certifying that the new installations 
conform to the approved designs of this subpart.
    (c) Hydrocarbon handling vessels associated with fuel gas system. 
You must protect hydrocarbon handling vessels associated with the fuel 
gas system with a basic and ancillary surface safety system. This system 
must be designed, analyzed, installed, tested, and maintained in 
operating condition in accordance with API RP 14C, Analysis, Design, 
Installation, and Testing of Basic Surface Safety Systems for Offshore 
Production Platforms (as incorporated by reference in Sec. 250.198). If 
processing components are to be utilized, other than those for which 
Safety Analysis Checklists are included in API RP 14C, you must use the 
analysis technique and documentation specified therein to determine the 
effect and requirements of these components upon the safety system.
    (d) Approval of safety-systems design and installation features for 
fuel gas system. Prior to installation, the lessee shall submit a fuel 
gas safety system application, in duplicate, to the District Manager for 
approval. The application shall include information relative to the 
proposed design and installation features. Information concerning 
approved design and installation features shall be maintained by the 
lessee at the lessee's offshore field office nearest the OCS facility or 
at another location conveniently available to the District Manager. All 
approvals are subject to field verification. The application shall 
include the following:
    (1) A schematic flow diagram showing size, capacity, design, working 
pressure of separators, storage tanks, compressor pumps, metering 
devices, and other hydrocarbon-handling vessels;
    (2) A schematic flow diagram (API RP 14C, Figure E1, as incorporated 
by reference in Sec. 250.198) and the related Safety Analysis Function 
Evaluation chart (API RP 14C, subsection 4.3c, as incorporated by 
reference in Sec. 250.198).
    (3) A schematic piping diagram showing the size and maximum 
allowable working pressures as determined in accordance with API RP 14E, 
Design and Installation of Offshore Production Platform Piping Systems 
(as incorporated by reference in Sec. 250.198);
    (4) Electrical system information including the following:
    (i) A plan of each platform deck, outlining all hazardous areas 
classified 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, or API RP

[[Page 214]]

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), and 
outlining areas in which potential ignition sources are to be installed;
    (ii) All significant hydrocarbon sources and a description of the 
type of decking, ceiling, walls (e.g., grating or solid), and firewalls; 
and
    (iii) Elementary electrical schematic of any platform safety 
shutdown system with a functional legend.
    (5) Certification that the design for the mechanical and electrical 
systems to be installed was approved by registered professional 
engineers. After these systems are installed, the lessee shall submit a 
statement to the District Manager certifying that the new installations 
conform to the approved designs of this subpart; and
    (6) Design and schematics of the installation and maintenance of all 
fire- and gas-detection systems including the following:
    (i) Type, location, and number of detection heads;
    (ii) Type and kind of alarm, including emergency equipment to be 
activated;
    (iii) Method used for detection;
    (iv) Method and frequency of calibration; and
    (v) A functional block diagram of the detection system, including 
the electric power supply.



Sec. 250.1629  Additional production and fuel gas system requirements.

    (a) General. Lessees shall comply with the following production 
safety system requirements (some of which are in addition to those 
contained in Sec. 250.1628 of this part).
    (b) Design, installation, and operation of additional production 
systems, including fuel gas handling safety systems. (1) Pressure and 
fired vessels must be designed, fabricated, and code stamped in 
accordance with the applicable provisions of sections I, IV, and VIII of 
the American Society of Mechanical Engineers (ASME) Boiler and Pressure 
Vessel Code (as specified in Sec. 250.198). Pressure and fired vessels 
must have maintenance inspection, rating, repair, and alteration 
performed in accordance with the applicable provisions of API Pressure 
Vessel Inspections Code: In-Service Inspection, Rating, Repair, and 
Alteration, API 510 (except Sections 5.8 and 9.5) (as incorporated by 
reference in Sec. 250.198).
    (i) Pressure safety relief valves shall be designed, installed, and 
maintained in accordance with applicable provisions of sections I, IV, 
and VIII of the ANSI/ASME Boiler and Pressure Vessel Code (as specified 
in Sec. 250.198). The safety relief valves shall conform to the valve-
sizing and pressure-relieving requirements specified in these documents; 
however, the safety relief valves shall be set no higher than the 
maximum-allowable working pressure of the vessel. All safety relief 
valves and vents shall be piped in such a way as to prevent fluid from 
striking personnel or ignition sources.
    (ii) The lessee shall use pressure recorders to establish the 
operating pressure ranges of pressure vessels in order to establish the 
pressure-sensor settings. Pressure-recording charts used to determine 
operating pressure ranges shall be maintained by the lessee for a period 
of 2 years at the lessee's field office nearest the OCS facility or at 
another location conveniently available to the District Manager. The 
high-pressure sensor shall be set no higher than 15 percent or 5 psi, 
whichever is greater, above the highest operating pressure of the 
vessel. This setting shall also be set sufficiently below (15 percent or 
5 psi, whichever is greater) the safety relief valve's set pressure to 
assure that the high-pressure sensor sounds an alarm before the safety 
relief valve starts relieving. The low-pressure sensor shall sound an 
alarm no lower than 15 percent or 5 psi, whichever is greater, below the 
lowest pressure in the operating range.
    (2) Engine exhaust. You must equip engine exhausts to comply with 
the insulation and personnel protection requirements of API RP 14C, 
section 4.2c(4) (as incorporated by reference in Sec. 250.198). Exhaust 
piping from diesel engines must be equipped with spark arresters.
    (3) Firefighting systems. Firefighting systems must conform to 
subsection 5.2, Fire Water Systems, of API RP 14G, Recommended Practice 
for Fire

[[Page 215]]

Prevention and Control on Open Type Offshore Production Platforms (as 
incorporated by reference in Sec. 250.198), and must be subject to the 
approval of the District Manager. Additional requirements must apply as 
follows:
    (i) A firewater system consisting of rigid pipe with firehose 
stations shall be installed. The firewater system shall be installed to 
provide needed protection, especially in areas where fuel handling 
equipment is located.
    (ii) Fuel or power for firewater pump drivers shall be available for 
at least 30 minutes of run time during platform shut-in time. If 
necessary, an alternate fuel or power supply shall be installed to 
provide for this pump-operating time unless an alternate firefighting 
system has been approved by the District Manager;
    (iii) A firefighting system using chemicals may be used in lieu of a 
water system if the District Manager determines that the use of a 
chemical system provides equivalent fire-protection control; and
    (iv) A diagram of the firefighting system showing the location of 
all firefighting equipment shall be posted in a prominent place on the 
facility or structure.
    (4) Fire- and gas-detection system. (i) Fire (flame, heat, or smoke) 
sensors shall be installed in all enclosed classified areas. Gas sensors 
shall be installed in all inadequately ventilated, enclosed classified 
areas. Adequate ventilation is defined as ventilation that is sufficient 
to prevent accumulation of significant quantities of vapor-air mixture 
in concentrations over 25 percent of the lower explosive limit. One 
approved method of providing adequate ventilation is 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. Enclosed areas 
(e.g., buildings, living quarters, or doghouses) are defined as those 
areas confined on more than four of their six 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. A 
classified area is any area classified Class I, Group D, Division 1 or 
2, following the guidelines of API RP 500 (as incorporated by reference 
in Sec. 250.198), or any area classified Class I, Zone 0, Zone 1, or 
Zone 2, following the guidelines of API RP 505 (as incorporated by 
reference in Sec. 205.198).
    (ii) All detection systems shall be capable of continuous 
monitoring. Fire-detection systems and portions of combustible gas-
detection systems related to the higher gas concentration levels shall 
be of the manual-reset type. Combustible gas-detection systems related 
to the lower gas-concentration level may be of the automatic-reset type.
    (iii) A fuel-gas odorant or an automatic gas-detection and alarm 
system is required in enclosed, continuously manned areas of the 
facility that are provided with fuel gas. Living quarters and doghouses 
not containing a gas source and not located in a classified area do not 
require a gas detection system.
    (iv) The District Manager may require the installation and 
maintenance of a gas detector or alarm in any potentially hazardous 
area.
    (v) Fire- and gas-detection systems must be an approved type, 
designed and installed according to API RP 14C, API RP 14G, and either 
API RP 14F or API RP 14FZ (the preceding four documents as incorporated 
by reference in Sec. 250.198).
    (c) General platform operations. Safety devices shall not be 
bypassed or blocked out of service unless they are temporarily out of 
service for startup, maintenance, or testing procedures. Only the 
minimum number of safety devices shall be taken out of service. 
Personnel shall monitor the bypassed or blocked out functions until the 
safety devices are placed back in service. Any safety device that is 
temporarily out of service shall be flagged by the person taking such 
device out of service.



Sec. 250.1630  Safety-system testing and records.

    (a) Inspection and testing. You must inspect and successfully test 
safety system devices at the interval specified below or more frequently 
if operating conditions warrant. Testing must be in accordance with API 
RP 14C, Appendix D (as incorporated by reference in Sec. 250.198). For 
safety system devices

[[Page 216]]

other than those listed in API RP 14C, Appendix D, you must utilize the 
analysis technique and documentation specified therein for inspection 
and testing of these components, and the following:
    (1) Safety relief valves on the natural gas feed system for power 
plant operations such as pressure safety valves shall be inspected and 
tested for operation at least once every 12 months. These valves shall 
be either bench tested or equipped to permit testing with an external 
pressure source.
    (2) The following safety devices (excluding electronic pressure 
transmitters and level sensors) must be inspected and tested at least 
once each calendar month, but at no time may more than 6 weeks elapse 
between tests:
    (i) All pressure safety high or pressure safety low, and
    (ii) All level safety high and level safety low controls.
    (3) The following electronic pressure transmitters and level sensors 
must be inspected and tested at least once every 3 months, but at no 
time may more than 120 days elapse between tests:
    (i) All PSH or PSL, and
    (ii) All LSH and LSL controls.
    (4) All pumps for firewater systems shall be inspected and operated 
weekly.
    (5) All fire- (flame, heat, or smoke) and gas-detection systems 
shall be inspected and tested for operation and recalibrated every 3 
months provided that testing can be performed in a nondestructive 
manner.
    (6) Prior to the commencement of production, the lessee shall notify 
the District Manager when the lessee is ready to conduct a preproduction 
test and inspection of the safety system. The lessee shall also notify 
the District Manager upon commencement of production in order that a 
complete inspection may be conducted.
    (b) Records. The lessee shall maintain records for a period of 2 
years for each safety device installed. These records shall be 
maintained by the lessee at the lessee's field office nearest the OCS 
facility or another location conveniently available to the District 
Manager. These records shall be available for BSEE review. The records 
shall show the present status and history of each safety device, 
including dates and details of installation, removal, inspection, 
testing, repairing, adjustments, and reinstallation.



Sec. 250.1631  Safety device training.

    Prior to engaging in production operations on a lease and 
periodically thereafter, personnel installing, inspecting, testing, and 
maintaining safety devices shall be instructed in the safety 
requirements of the operations to be performed; possible hazards to be 
encountered; and general safety considerations to be taken to protect 
personnel, equipment, and the environment. Date and time of safety 
meetings shall be recorded and available for BSEE review.



Sec. 250.1632  Production rates.

    Each sulphur deposit shall be produced at rates that will provide 
economic development and depletion of the deposit in a manner that would 
maximize the ultimate recovery of sulphur without resulting in waste 
(e.g., an undue reduction in the recovery of oil and gas from an 
associated hydrocarbon accumulation).



Sec. 250.1633  Production measurement.

    (a) General. Measurement equipment and security procedures shall be 
designed, installed, used, maintained, and tested so as to accurately 
and completely measure the sulphur produced on a lease for purposes of 
royalty determination.
    (b) Application and approval. The lessee shall not commence 
production of sulphur until the Regional Supervisor has approved the 
method of measurement. The request for approval of the method of 
measurement shall contain sufficient information to demonstrate to the 
satisfaction of the Regional Supervisor that the method of measurement 
meets the requirements of paragraph (a) of this section.



Sec. 250.1634  Site security.

    (a) All locations where sulphur is produced, measured, or stored 
shall be operated and maintained to ensure against the loss or theft of 
produced sulphur and to assure accurate and

[[Page 217]]

complete measurement of produced sulphur for royalty purposes.
    (b) Evidence of mishandling of produced sulphur from an offshore 
lease, or tampering or falsifying any measurement of production for an 
offshore lease, shall be reported to the Regional Supervisor as soon as 
possible but no later than the next business day after discovery of the 
evidence of mishandling.



                  Subpart Q_Decommissioning Activities

                                 General



Sec. 250.1700  What do the terms ``decommissioning'', ``obstructions'', and 

``facility'' mean?

    (a) Decommissioning means:
    (1) Ending oil, gas, or sulphur operations; and
    (2) Returning the lease or pipeline right-of-way to a condition that 
meets the requirements of regulations of BSEE and other agencies that 
have jurisdiction over decommissioning activities.
    (b) Obstructions mean structures, equipment, or objects that were 
used in oil, gas, or sulphur operations or marine growth that, if left 
in place, would hinder other users of the OCS. Obstructions may include, 
but are not limited to, shell mounds, wellheads, casing stubs, mud line 
suspensions, well protection devices, subsea trees, jumper assemblies, 
umbilicals, manifolds, termination skids, production and pipeline 
risers, platforms, templates, pilings, pipelines, pipeline valves, and 
power cables.
    (c) Facility means any installation other than a pipeline used for 
oil, gas, or sulphur activities that is permanently or temporarily 
attached to the seabed on the OCS. Facilities include production and 
pipeline risers, templates, pilings, and any other facility or equipment 
that constitutes an obstruction such as jumper assemblies, termination 
skids, umbilicals, anchors, and mooring lines.



Sec. 250.1701  Who must meet the decommissioning obligations in this subpart?

    (a) Lessees and owners of operating rights are jointly and severally 
responsible for meeting decommissioning obligations for facilities on 
leases, including the obligations related to lease-term pipelines, as 
the obligations accrue and until each obligation is met.
    (b) All holders of a right-of-way are jointly and severally liable 
for meeting decommissioning obligations for facilities on their right-
of-way, including right-of-way pipelines, as the obligations accrue and 
until each obligation is met.
    (c) In this subpart, the terms ``you'' or ``I'' refer to lessees and 
owners of operating rights, as to facilities installed under the 
authority of a lease, and to right-of-way holders as to facilities 
installed under the authority of a right-of-way.



Sec. 250.1702  When do I accrue decommissioning obligations?

    You accrue decommissioning obligations when you do any of the 
following:
    (a) Drill a well;
    (b) Install a platform, pipeline, or other facility;
    (c) Create an obstruction to other users of the OCS;
    (d) Are or become a lessee or the owner of operating rights of a 
lease on which there is a well that has not been permanently plugged 
according to this subpart, a platform, a lease term pipeline, or other 
facility, or an obstruction;
    (e) Are or become the holder of a pipeline right-of-way on which 
there is a pipeline, platform, or other facility, or an obstruction; or
    (f) Re-enter a well that was previously plugged according to this 
subpart.



Sec. 250.1703  What are the general requirements for decommissioning?

    When your facilities are no longer useful for operations, you must:
    (a) Get approval from the appropriate District Manager before 
decommissioning wells and from the Regional Supervisor before 
decommissioning

[[Page 218]]

platforms and pipelines or other facilities;
    (b) Permanently plug all wells;
    (c) Remove all platforms and other facilities, except as provided in 
Sec. Sec. 250.1725(a) and 250.1730.
    (d) Decommission all pipelines;
    (e) Clear the seafloor of all obstructions created by your lease and 
pipeline right-of-way operations; and
    (f) Conduct all decommissioning activities in a manner that is safe, 
does not unreasonably interfere with other uses of the OCS, and does not 
cause undue or serious harm or damage to the human, marine, or coastal 
environment.



Sec. 250.1704  When must I submit decommissioning applications and reports?

    You must submit decommissioning applications and receive approval 
and submit subsequent reports according to the table in this section.

                                 Decommissioning Applications and Reports Table
----------------------------------------------------------------------------------------------------------------
  Decommissioning applications and
              reports                      When to submit                          Instructions
----------------------------------------------------------------------------------------------------------------
(a) Initial platform removal         In the Pacific OCS Region   Include information required under Sec.
 application [not required in the     or Alaska OCS Region,       250.1726.
 Gulf of Mexico OCS Region].          submit the application to
                                      the Regional Supervisor
                                      at least 2 years before
                                      production is projected
                                      to cease.
(b) Final removal application for a  Before removing a platform  Include information required under Sec.
 platform or other facility.          or other facility in the    250.1727.
                                      Gulf of Mexico OCS
                                      Region, or not more than
                                      2 years after the
                                      submittal of an initial
                                      platform removal
                                      application to the
                                      Pacific OCS Region and
                                      the Alaska OCS Region.
(c) Post-removal report for a        Within 30 days after you    Include information required under Sec.
 platform or other facility.          remove a platform or        250.1729.
                                      other facility.
(d) Pipeline decommissioning         Before you decommission a   Include information required under Sec.
 application.                         pipeline.                   250.1751(a) or Sec.  250.1752(a), as
                                                                  applicable.
(e) Post-pipeline decommissioning    Within 30 days after you    Include information required under Sec.
 report.                              decommission a pipeline.    250.1753.
(f) Site clearance report for a      Within 30 days after you    Include information required under Sec.
 platform or other facility.          complete site clearance     250.1743(b).
                                      verification activities.
(g) Form BSEE-0124, Application for  (1) Before you temporarily  (i) Include information required under Sec.
 Permit to Modify (APM). The          abandon or permanently      Sec.  250.1712 and 250.1721.
 submission of your APM must be       plug a well or zone.       (ii) When using a BOP for abandonment
 accompanied by payment of the                                    operations include information required under
 service fee listed in Sec.                                      Sec.  250.1705.
 250.125.
                                     (2) Within 30 days after    Include information required under Sec.
                                      you plug a well.            250.1717.
                                     (3) Before you install a    Refer to Sec.  250.1722(a).
                                      subsea protective device.
                                     (4) Within 30 days after    Include information required under Sec.
                                      you complete a protective   250.1722(d).
                                      device trawl test.
                                     (5) Before you remove any   Refer to Sec.  250.1723.
                                      casing stub or mud line
                                      suspension equipment and
                                      any subsea protective
                                      device.
                                     (6) Within 30 days after    Include information required under Sec.
                                      you complete site           250.1743(a).
                                      clearance verification
                                      activities.
----------------------------------------------------------------------------------------------------------------


[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50896, Aug. 22, 2012]



Sec. 250.1705  What BOP information must I submit?

    If you plan to use a BOP for abandonment operations, your 
decommissioning application must include the following BOP descriptions:
    (a) A description of the BOP system and system components, including 
pressure ratings of BOP equipment and proposed BOP test pressures;
    (b) A schematic drawing of the BOP system that shows the inside 
diameter of the BOP stack, number and type of preventers, all control 
systems and

[[Page 219]]

pods, location of choke and kill lines, and associated valves;
    (c) Independent third-party verification and supporting 
documentation that show the blind-shear rams installed in the BOP stack 
are capable of shearing any drill pipe (including workstring and tubing) 
in the hole under maximum anticipated surface pressure. The 
documentation must include actual shearing and subsequent pressure 
integrity test results for the most rigid pipe to be used and 
calculations of shearing capacity of all pipe to be used in the well, 
including correction for Maximum Anticipated Surface Pressure (MASP);
    (d) When you use a subsea BOP stack, independent third-party 
verification that shows:
    (1) The BOP stack is designed for the specific equipment on the rig 
and for the specific well design;
    (2) The BOP stack has not been compromised or damaged from previous 
service;
    (3) The BOP stack will operate in the conditions in which it will be 
used; and
    (e) The qualifications of the independent third-party referenced in 
paragraphs (c) and (d) of this section including evidence that:
    (1) The independent third-party in this section is a technical 
classification society, or a licensed professional engineering firm, or 
a registered professional engineer capable of providing the 
verifications required under this part.
    (2) You must:
    (i) Include evidence that the registered professional engineer, or a 
technical classification society, or engineering firm you are using or 
its employees hold appropriate licenses to perform the verification in 
the appropriate jurisdiction, and evidence to demonstrate that the 
individual, society, or firm has the expertise and experience necessary 
to perform the required verifications.
    (ii) Ensure that an official representative of BSEE will have access 
to the location to witness any testing or inspections, and verify 
information submitted to BSEE. Prior to any shearing ram tests or 
inspections, you must notify the BSEE District Manager at least 72 hours 
in advance.

[77 FR 50897, Aug. 22, 2012]



Sec. 250.1706  What are the requirements for blowout prevention equipment?

    If you use a BOP for any well abandonment operations, your BOP must 
meet the following requirements:
    (a) The BOP system, system components, and related well-control 
equipment must be designed, used, maintained, and tested in a manner 
necessary to assure well-control in foreseeable conditions and 
circumstances, including subfreezing conditions. The working pressure 
rating of the BOP system and system components must exceed the expected 
surface pressure to which they may be subjected. If the expected surface 
pressure exceeds the rated working pressure of the annular preventer, 
you must submit with Form BSEE-0124, requesting approval of the well 
abandonment operations, a well-control procedure that indicates how the 
annular preventer will be utilized, and the pressure limitations that 
will be applied during each mode of pressure control.
    (b) The minimum BOP system for well abandonment operations with the 
tree removed must meet the appropriate standards from the following 
table:

------------------------------------------------------------------------
          When . . .            The minimum BOP stack must include . . .
------------------------------------------------------------------------
(1) The expected pressure is   Three BOPs consisting of an annular, one
 less than 5,000 psi,           set of pipe rams, and one set of blind-
                                shear rams.
(2) The expected pressure is   Four BOPs consisting of an annular, two
 5,000 psi or greater or you    sets of pipe rams, and one set of blind-
 use multiple tubing strings,   shear rams.
(3) You handle multiple        Four BOPs consisting of an annular, one
 tubing strings                 set of pipe rams, one set of dual pipe
 simultaneously,                rams, and one set of blind-shear rams.
(4) You use a tapered drill    (i) At least one set of pipe rams that
 string,                        are capable of sealing around each size
                                of drill string.
                               (ii) If the expected pressure is greater
                                than 5,000 psi, then you must have at
                                least two sets of pipe rams that are
                                capable of sealing around the larger
                                size drill string.
                               (iii) You may substitute one set of
                                variable bore rams for two sets of pipe
                                rams.

[[Page 220]]

 
(5) You use a subsea BOP       The requirements in Sec.  250.442(a) of
 stack,                         this part.
------------------------------------------------------------------------

    (c) The BOP systems for well abandonment operations with the tree 
removed must be equipped with the following:
    (1) A hydraulic-actuating system that provides sufficient 
accumulator capacity to supply 1.5 times the volume necessary to close 
all BOP equipment units with a minimum pressure of 200 psi above the 
precharge pressure without assistance from a charging system. 
Accumulator regulators supplied by rig air and without a secondary 
source of pneumatic supply, must be equipped with manual overrides, or 
alternately, other devices provided to ensure capability of hydraulic 
operations if rig air is lost;
    (2) A secondary power source, independent from the primary power 
source, with sufficient capacity to close all BOP system components and 
hold them closed;
    (3) Locking devices for the pipe-ram preventers;
    (4) At least one remote BOP-control station and one BOP-control 
station on the rig floor; and
    (5) A choke line and a kill line each equipped with two full opening 
valves and a choke manifold. At least one of the valves on the choke-
line must be remotely controlled. At least one of the valves on the kill 
line must be remotely controlled, except that a check valve on the kill 
line in lieu of the remotely controlled valve may be installed, provided 
two readily accessible manual valves are in place and the check valve is 
placed between the manual valves and the pump. This equipment must have 
a pressure rating at least equivalent to the ram preventers. You must 
install the choke line above the bottom ram and may install the kill 
line below the bottom ram.
    (d) The minimum BOP system components for well abandonment 
operations with the tree in place and performed through the wellhead 
inside of conventional tubing using small-diameter jointed pipe (usually 
\3/4\ inch to 1\1/4\ inch) as a work string, i.e., small-tubing 
operations, must include the following:
    (1) Two sets of pipe rams, and
    (2) One set of blind rams.
    (e) The subsea BOP system for well abandonment operations must meet 
the requirements in Sec. 250.442 of this part.
    (f) 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     through an outlet on
                                    3,500 psi          the BOP stack
------------------------------------------------------------------------
(i) Stripper or annular-type    Stripper or        Stripper or annular-
 well-control component,         annular-type       type well-control
                                 well-control       component.
                                 component,
(ii) Hydraulically-operated     Hydraulically-     Hydraulically-
 blind rams,                     operated blind     operated blind rams.
                                 rams,.
(iii) Hydraulically-operated    Hydraulically-     Hydraulically-
 shear rams,                     operated shear     operated shear rams.
                                 rams,.
(iv) Kill line inlet,           Kill line inlet,   Kill line inlet.
(v) Hydraulically-operated two- Hydraulically-     Hydraulically-
 way slip rams,                  operated two-way   operated two-way
                                 slip rams,         slip rams.
                                                   Hydraulically-
                                                    operated pipe rams.
(vi) Hydraulically-operated     Hydraulically-     A flow tee or cross.
 pipe rams,                      operated pipe     Hydraulically-
                                 rams.              operated pipe rams.
                                Hydraulically-     Hydraulically-
                                 operated blind-    operated blind-shear
                                 shear rams.        rams on wells with
                                 These rams         surface pressures
                                 should be          3,500
                                 located as close   psi. As an option,
                                 to the tree as     the pipe rams can be
                                 practical,.        placed below the
                                                    blind-shear rams.
                                                    The blind-shear rams
                                                    should be located as
                                                    close to the tree as
                                                    practical.
------------------------------------------------------------------------


[[Page 221]]

    (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 abandonment 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 BSEE 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-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.
    (g) The minimum BOP system components for well abandonment 
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, must 
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.
    (h) An inside BOP or a spring-loaded, back-pressure safety valve, 
and an essentially full-opening, work-string safety valve in the open 
position must be maintained on the rig floor at all times during well 
abandonment operations when the tree is removed or during well 
abandonment operations with the tree installed and using small tubing as 
the work string. A wrench to fit the work-string safety valve must be 
readily available. Proper connections must be readily available for 
inserting valves in the work string. The full-opening safety valve is 
not required for coiled tubing or snubbing operations.

[77 FR 50897, Aug. 22, 2012]



Sec. 250.1707  What are the requirements for blowout preventer system testing, 

records, and drills?

    (a) BOP pressure tests. When you pressure test the BOP system, you 
must conduct a low-pressure test and a high-pressure test for each 
component. You must conduct the low-pressure test before the high-
pressure test. For purposes of this section, BOP system components 
include ram-type BOP's, related control equipment, choke and kill lines, 
and valves, manifolds, strippers, and safety valves. Surface BOP systems 
must be pressure tested with water.
    (1) Low pressure tests. You must successfully test all BOP system 
components to a low pressure between 200 and 300 psi. Any initial 
pressure equal to or greater than 300 psi must be bled back to a 
pressure between 200 and 300 psi before starting the test. If the 
initial pressure exceeds 500 psi, you must bleed back to zero before 
starting the test.
    (2) High pressure tests. You must successfully test all BOP system 
components to the rated working pressure of the BOP equipment, or as 
otherwise approved by the BSEE District Manager.

[[Page 222]]

You must successfully test the annular-type BOP at 70 percent of its 
rated working pressure or as otherwise approved by the BSEE District 
Manager.
    (3) Other testing requirements. You must test variable bore pipe 
rams against the largest and smallest sizes of tubulars in use (jointed 
pipe, seamless pipe) in the well.
    (b) You must test the BOP systems at the following times:
    (1) When installed;
    (2) At least every 7 days, alternating between control stations and 
at staggered intervals to allow each crew to operate the equipment. If 
either control system is not functional, further operations must be 
suspended until the nonfunctional system is operable. The test every 7 
days is not required for blind or blind-shear rams. The blind or blind-
shear rams must be tested at least once every 30 days during operation. 
A longer period between blowout preventer tests is allowed when there is 
a stuck pipe or pressure-control operation and remedial efforts are 
being performed. The tests must be conducted as soon as possible and 
before normal operations resume. The reason for postponing testing must 
be entered into the operations log. The BSEE District Manager may 
require alternate test frequencies if conditions or BOP performance 
warrant.
    (3) Following repairs that require disconnecting a pressure seal in 
the assembly, the affected seal will be pressure tested.
    (c) All personnel engaged in well abandonment operations must 
participate in a weekly BOP drill to familiarize crew members with 
appropriate safety measures.
    (d) You may conduct a stump test for the BOP system on location. A 
plan describing the stump test procedures must be included in your 
Application for Permit to Modify, Form BSEE-0124, and must be approved 
by the BSEE District Manager.
    (e) You must test the coiled tubing connector to a low pressure of 
200 to 300 psi, followed by a high pressure test to the rated working 
pressure of the connector or the expected surface pressure, whichever is 
less. You must successfully pressure test the dual check valves to the 
rated working pressure of the connector, the rated working pressure of 
the dual check valve, expected surface pressure, or the collapse 
pressure of the coiled tubing, whichever is less.
    (f) You must record test pressures during BOP and coiled tubing 
tests on a pressure chart, or with a digital recorder, unless otherwise 
approved by the BSEE District Manager. The test interval for each BOP 
system component must be 5 minutes, except for coiled tubing operations, 
which must include a 10 minute high-pressure test for the coiled tubing 
string. Your representative at the facility must certify that the charts 
are correct.
    (g) The time, date, and results of all pressure tests, actuations, 
inspections, and crew drills of the BOP system, system components, and 
marine risers must be recorded in the operations log. The BOP tests must 
be documented in accordance with the following:
    (1) The documentation must indicate the sequential order of BOP and 
auxiliary equipment testing, the pressure, and duration of each test. As 
an alternate, the documentation in the operations log may reference a 
BOP test plan that contains the required information and is retained on 
file at the facility.
    (2) The control station used during the test must be identified in 
the operations log. For a subsea system, the pod used during the test 
must be identified in the operations log.
    (3) Any problems or irregularities observed during BOP and auxiliary 
equipment testing and any actions taken to remedy such problems or 
irregularities, must be noted in the operations log.
    (4) Documentation required to be entered in the operations log may 
instead be referenced in the operations log. You must make all records 
including pressure charts, operations log, and referenced documents 
pertaining to BOP tests, actuations, and inspections, available for BSEE 
review at the facility for the duration of well abandonment activity. 
Following completion of the well abandonment activity, you must retain 
all such records for a period of two years at the facility, at the

[[Page 223]]

lessee's field office nearest the OCS facility, or at another location 
conveniently available to the BSEE District Manager.
    (h) Stump test a subsea BOP system before installation. You must use 
water to conduct this test. You may use drilling fluids to conduct 
subsequent tests of a subsea BOP system. You must stump test the subsea 
BOP within 30 days of the initial test on the seafloor. You must:
    (1) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. Each ROV must be fully compatible with the BOP 
stack ROV intervention panels. You must also test and verify closure of 
at least one set of rams during the initial test on the seafloor. You 
must submit test procedures, including how you will test each ROV 
function, with your APM for BSEE District Manager approval. You must:
    (i) Ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams and one set of 
blind-shear rams and unlatching the LMRP;
    (ii) Document all your test results and make them available to BSEE 
upon request; and
    (2) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system and 
verify closure of at least one set of blind-shear rams during the 
initial test on the seafloor. 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. You must:
    (i) Submit test procedures with your APM for BSEE District Manager 
approval. The procedures for these function tests must include 
documentation of the controls and circuitry of the system utilized 
during each test. The procedure must also describe how the ROV will be 
utilized during this operation.
    (ii) Document the results of each test and make them available to 
BSEE upon request.

[77 FR 50899, Aug. 22, 2012]



Sec. 250.1708  What are my BOP inspection and maintenance requirements?

    (a) BOP inspections. (1) You must inspect your BOP system to ensure 
that the equipment functions properly. The BOP inspections must meet or 
exceed the provisions of Sections 17.10 and 18.10, Inspections, 
described in API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells (incorporated by reference as 
specified in Sec. 250.198). You must document how you met or exceeded 
the provisions of Sections 17.10 and 18.10 described in API RP 53, 
document the procedures used, record the results, and make the records 
available to BSEE upon request. You must maintain your records on the 
rig for 2 years from the date the records are created, or for a longer 
period if directed by BSEE.
    (2) You must visually inspect your BOP system and marine riser at 
least once every 3 days if weather and sea conditions permit. You may 
use television cameras to inspect this equipment. The BSEE District 
Manager may approve alternate methods and frequencies to inspect a 
marine riser.
    (b) BOP maintenance. You must maintain your BOP system to ensure 
that the equipment functions properly. The BOP maintenance must meet or 
exceed the provisions of Sections 17.11 and 18.11, Maintenance; and 
Sections 17.12 and 18.12, Quality Management, described in API RP 53, 
Recommended Practices for Blowout Prevention Equipment Systems for 
Drilling Wells (incorporated by reference as specified in Sec. 
250.198). You must document how you met or exceeded the provisions of 
Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, 
Quality Management, described in API RP 53, document the procedures 
used, record the results, and make the records available to BSEE upon 
request. You must maintain your records on the rig for 2 years from the 
date the records are created, or for a longer period if directed by 
BSEE.

[77 FR 50900, Aug. 22, 2012]

[[Page 224]]



Sec. 250.1709  What are my well-control fluid requirements?

    Before you displace kill-weight fluid from the wellbore and/or riser 
to an underbalanced state, you must obtain approval from the BSEE 
District Manager. To obtain approval, you must submit with your 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:
    (a) 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,
    (b) Tests you will conduct to ensure integrity of independent 
barriers,
    (c) BOP procedures you will use while displacing kill weight fluids, 
and
    (d) Procedures you will use to monitor the volumes and rates of 
fluids entering and leaving the wellbore.

[77 FR 50900, Aug. 22, 2012]

                       Permanently Plugging Wells



Sec. 250.1710  When must I permanently plug all wells on a lease?

    You must permanently plug all wells on a lease within 1 year after 
the lease terminates.



Sec. 250.1711  When will BSEE order me to permanently plug a well?

    BSEE will order you to permanently plug a well if that well:
    (a) Poses a hazard to safety or the environment; or
    (b) Is not useful for lease operations and is not capable of oil, 
gas, or sulphur production in paying quantities.



Sec. 250.1712  What information must I submit before I permanently plug a well 

or zone?

    Before you permanently plug a well or zone, you must submit form 
BSEE-0124, Application for Permit to Modify, to the appropriate District 
Manager and receive approval. A request for approval must contain the 
following information:
    (a) The reason you are plugging the well (or zone), for completions 
with production amounts specified by the Regional Supervisor, along with 
substantiating information demonstrating its lack of capacity for 
further profitable production of oil, gas, or sulfur;
    (b) Recent well test data and pressure data, if available;
    (c) Maximum possible surface pressure, and how it was determined;
    (d) Type and weight of well-control fluid you will use;
    (e) A description of the work;
    (f) A current and proposed well schematic and description that 
includes:
    (1) Well depth;
    (2) All perforated intervals that have not been plugged;
    (3) Casing and tubing depths and details;
    (4) Subsurface equipment;
    (5) Estimated tops of cement (and the basis of the estimate) in each 
casing annulus;
    (6) Plug locations;
    (7) Plug types;
    (8) Plug lengths;
    (9) Properties of mud and cement to be used;
    (10) Perforating and casing cutting plans;
    (11) Plug testing plans;
    (12) Casing removal (including information on explosives, if used);
    (13) Proposed casing removal depth; and
    (14) Your plans to protect archaeological and sensitive biological 
features, including anchor damage during plugging operations, a brief 
assessment of the environmental impacts of the plugging operations, and 
the procedures and mitigation measures you will take to minimize such 
impacts; and
    (g) Certification by a Registered Professional Engineer of the well 
abandonment design and procedures and that all plugs meet the 
requirements in the table in Sec. 250.1715. In addition to the 
requirements of Sec. 250.1715, the Registered Professional Engineer 
must also certify the design will include two independent barriers, one 
of which must be a mechanical barrier, in the center wellbore as 
described in Sec. 250.420(b)(3). The Registered Professional Engineer 
must be registered in a State of the United States and have sufficient 
expertise

[[Page 225]]

and experience to perform the certification. You must submit this 
certification with your APM (Form BSEE-0124).

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012]



Sec. 250.1713  Must I notify BSEE before I begin well plugging operations?

    You must notify the appropriate District Manager at least 48 hours 
before beginning operations to permanently plug a well.



Sec. 250.1714  What must I accomplish with well plugs?

    You must ensure that all well plugs:
    (a) Provide downhole isolation of hydrocarbon and sulphur zones;
    (b) Protect freshwater aquifers; and
    (c) Prevent migration of formation fluids within the wellbore or to 
the seafloor.



Sec. 250.1715  How must I permanently plug a well?

    (a) You must permanently plug wells according to the table in this 
section. The District Manager may require additional well plugs as 
necessary.

                                      Permanent Well Plugging Requirements
----------------------------------------------------------------------------------------------------------------
                 If you have . . .                                    Then you must use . . .
---------------------------------------------------------------------------------------------------------------
(1) Zones in open hole,                              Cement plug(s) set from at least 100 feet below the
                                                      bottom to 100 feet above the top of oil, gas, and fresh-
                                                      water zones to isolate fluids in the strata.
(2) Open hole below casing,                          (i) A cement plug, set by the displacement method, at
                                                      least 100 feet above and below deepest casing shoe;
                                                     (ii) A cement retainer with effective back-pressure
                                                      control set 50 to 100 feet above the casing shoe, and a
                                                      cement plug that extends at least 100 feet below the
                                                      casing shoe and at least 50 feet above the retainer; or
                                                     (iii) A bridge plug set 50 feet to 100 feet above the
                                                      shoe with 50 feet of cement on top of the bridge plug,
                                                      for expected or known lost circulation conditions.
(3) A perforated zone that is currently open and     (i) A method to squeeze cement to all perforations;
 not previously squeezed or isolated,                (ii) A cement plug set by the displacement method, at
                                                      least 100 feet above to 100 feet below the perforated
                                                      interval, or down to a casing plug, whichever is less;
                                                      or.
                                                     (iii) If the perforated zones are isolated from the hole
                                                      below, you may use any of the plugs specified in
                                                      paragraphs (a)(3)(iii)(A) through (E) of this section
                                                      instead of those specified in paragraphs (a)(3)(i) and
                                                      (a)(3)(ii) of this section..
                                                     (A) A cement retainer with effective back-pressure
                                                      control set 50 to 100 feet above the top of the
                                                      perforated interval, and a cement plug that extends at
                                                      least 100 feet below the bottom of the perforated
                                                      interval with at least 50 feet of cement above the
                                                      retainer;
                                                     (B) A bridge plug set 50 to 100 feet above the top of the
                                                      perforated interval and at least 50 feet of cement on
                                                      top of the bridge plug;
                                                     (C) A cement plug at least 200 feet in length, set by the
                                                      displacement method, with the bottom of the plug no more
                                                      than 100 feet above the perforated interval;
                                                     (D) A through-tubing basket plug set no more than 100
                                                      feet above the perforated interval with at least 50 feet
                                                      of cement on top of the basket plug; or
                                                     (E) A tubing plug set no more than 100 feet above the
                                                      perforated interval topped with a sufficient volume of
                                                      cement so as to extend at least 100 feet above the
                                                      uppermost packer in the wellbore and at least 300 feet
                                                      of cement in the casing annulus immediately above the
                                                      packer.
(4) A casing stub where the stub end is within the   (i) A cement plug set at least 100 feet above and below
 casing,                                              the stub end;
                                                     (ii) A cement retainer or bridge plug set at least 50 to
                                                      100 feet above the stub end with at least 50 feet of
                                                      cement on top of the retainer or bridge plug; or
                                                     (iii) A cement plug at least 200 feet long with the
                                                      bottom of the plug set no more than 100 feet above the
                                                      stub end.
(5) A casing stub where the stub end is below the    A plug as specified in paragraph (a)(1) or (a)(2) of this
 casing,                                              section, as applicable.
(6) An annular space that communicates with open     A cement plug at least 200 feet long set in the annular
 hole and extends to the mud line,                    space. For a well completed above the ocean surface, you
                                                      must pressure test each casing annulus to verify
                                                      isolation.
(7) A subsea well with unsealed annulus,             A cutter to sever the casing, and you must set a stub
                                                      plug as specified in paragraphs (a)(4) and (a)(5) of
                                                      this section.
(8) A well with casing,                              A cement surface plug at least 150 feet long set in the
                                                      smallest casing that extends to the mud line with the
                                                      top of the plug no more than 150 feet below the mud
                                                      line.
(9) Fluid left in the hole,                          A fluid in the intervals between the plugs that is dense
                                                      enough to exert a hydrostatic pressure that is greater
                                                      than the formation pressures in the intervals.

[[Page 226]]

 
(10) Permafrost areas,                               (i) A fluid to be left in the hole that has a freezing
                                                      point below the temperature of the permafrost, and a
                                                      treatment to inhibit corrosion; and
                                                     (ii) Cement plugs designed to set before freezing and
                                                      have a low heat of hydration.
(11) Removed the barriers required in Sec.          Two independent barriers, one of which must be a
 250.420(b)(3) for the well to be completed           mechanical barrier, in the center wellbore as described
                                                      in Sec.  250.420(b)(3) once the well is to be placed in
                                                      a permanent or temporary abandonment..
----------------------------------------------------------------------------------------------------------------

    (b) You must test the first plug below the surface plug and all 
plugs in lost circulation areas that are in open hole. The plug must 
pass one of the following tests to verify plug integrity:
    (1) A pipe weight of at least 15,000 pounds on the plug; or
    (2) A pump pressure of at least 1,000 pounds per square inch. Ensure 
that the pressure does not drop more than 10 percent in 15 minutes. The 
District Manager may require you to tests other plug(s).

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012]



Sec. 250.1716  To what depth must I remove wellheads and casings?

    (a) Unless the District Manager approves an alternate depth under 
paragraph (b) of this section, you must remove all wellheads and casings 
to at least 15 feet below the mud line.
    (b) The District Manager may approve an alternate removal depth if:
    (1) The wellhead or casing would not become an obstruction to other 
users of the seafloor or area, and geotechnical and other information 
you provide demonstrate that erosional processes capable of exposing the 
obstructions are not expected; or
    (2) You determine, and BSEE concurs, that you must use divers, and 
the seafloor sediment stability poses safety concerns; or
    (3) The water depth is greater than 800 meters (2,624 feet).



Sec. 250.1717  After I permanently plug a well, what information must I 

submit?

    Within 30 days after you permanently plug a well, you must submit 
form BSEE-0124, Application for Permit to Modify (subsequent report), to 
the appropriate District Manager, and include the following information:
    (a) Information included in Sec. 250.1712 with a final well 
schematic;
    (b) Description of the plugging work;
    (c) Nature and quantities of material used in the plugs; and
    (d) If you cut and pulled any casing string, the following 
information:
    (1) A description of the methods used (including information on 
explosives, if used);
    (2) Size and amount of casing removed; and
    (3) Casing removal depth.

                        Temporary Abandoned Wells



Sec. 250.1721  If I temporarily abandon a well that I plan to re-enter, what 

must I do?

    You may temporarily abandon a well when it is necessary for proper 
development and production of a lease. To temporarily abandon a well, 
you must do all of the following:
    (a) Submit form BSEE-0124, Application for Permit to Modify, and the 
applicable information required by Sec. 250.1712 to the appropriate 
District Manager and receive approval;
    (b) Adhere to the plugging and testing requirements for permanently 
plugged wells listed in the table in Sec. 250.1715, except for Sec. 
250.1715(a)(8). You do not need to sever the casings, remove the 
wellhead, or clear the site;
    (c) Set a bridge plug or a cement plug at least 100-feet long at the 
base of the deepest casing string, unless the casing string has been 
cemented and has not been drilled out. If a cement plug is set, it is 
not necessary for the cement plug to extend below the casing shoe into 
the open hole;
    (d) Set a retrievable or a permanent-type bridge plug or a cement 
plug at least 100 feet long in the inner-most casing. The top of the 
bridge plug or cement plug must be no more than

[[Page 227]]

1,000 feet below the mud line. BSEE may consider approving alternate 
requirements for subsea wells case-by-case;
    (e) Identify and report subsea wellheads, casing stubs, or other 
obstructions that extend above the mud line according to U.S. Coast 
Guard (USCG) requirements;
    (f) Except in water depths greater than 300 feet, protect subsea 
wellheads, casing stubs, mud line suspensions, or other obstructions 
remaining above the seafloor by using one of the following methods, as 
approved by the District Manager or Regional Supervisor:
    (1) A caisson designed according to 30 CFR 250, subpart I, and 
equipped with aids to navigation;
    (2) A jacket designed according to 30 CFR 250, subpart I, and 
equipped with aids to navigation; or
    (3) A subsea protective device that meets the requirements in Sec. 
250.1722.
    (g) Within 30 days after you temporarily plug a well, you must 
submit form BSEE-0124, Application for Permit to Modify (subsequent 
report), and include the following information:
    (1) Information included in Sec. 250.1712 with a well schematic;
    (2) Information required by Sec. 250.1717(b), (c), and (d); and
    (3) A description of any remaining subsea wellheads, casing stubs, 
mudline suspension equipment, or other obstructions that extend above 
the seafloor; and
    (h) Submit certification by a Registered Professional Engineer of 
the well abandonment design and procedures and that all plugs meet the 
requirements of paragraph (b) of this section. In addition to the 
requirements of paragraph (b) of this section, the Registered 
Professional Engineer must also certify the design will include two 
independent barriers, one of which must be a mechanical barrier, in the 
center wellbore as described in Sec. 250.420(b)(3). The Registered 
Professional Engineer must be registered in a State of the United States 
and have sufficient expertise and experience to perform the 
certification. You must submit this certification with your APM (Form 
BSEE-0124) required by Sec. 250.1712 of this part.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012]



Sec. 250.1722  If I install a subsea protective device, what requirements must 

I meet?

    If you install a subsea protective device under Sec. 
250.1721(f)(3), you must install it in a manner that allows fishing gear 
to pass over the obstruction without damage to the obstruction, the 
protective device, or the fishing gear.
    (a) Use form BSEE-0124, Application for Permit to Modify to request 
approval from the appropriate District Manager to install a subsea 
protective device.
    (b) The protective device may not extend more than 10 feet above the 
seafloor (unless BSEE approves otherwise).
    (c) You must trawl over the protective device when you install it 
(adhere to the requirements at Sec. 250.1741(d) through (h)). If the 
trawl does not pass over the protective device or causes damage to it, 
you must notify the appropriate District Manager within 5 days and 
perform remedial action within 30 days of the trawl;
    (d) Within 30 days after you complete the trawling test described in 
paragraph (c) of this section, submit a report to the appropriate 
District Manager using form BSEE-0124, Application for Permit to Modify 
that includes the following:
    (1) The date(s) the trawling test was performed and the vessel that 
was used;
    (2) A plat at an appropriate scale showing the trawl lines;
    (3) A description of the trawling operation and the net(s) that were 
used;
    (4) An estimate by the trawling contractor of the seafloor 
penetration depth achieved by the trawl;
    (5) A summary of the results of the trawling test including a 
discussion of any snags and interruptions, a description of any damage 
to the protective covering, the casing stub or mud line suspension 
equipment, or the trawl, and a discussion of any snag removals requiring 
diver assistance; and

[[Page 228]]

    (6) A letter signed by your authorized representative stating that 
he/she witnessed the trawling test.
    (e) If a temporarily abandoned well is protected by a subsea device 
installed in a water depth less than 100 feet, mark the site with a buoy 
installed according to the USCG requirements.
    (f) Provide annual reports to the Regional Supervisor describing 
your plans to either re-enter and complete the well or to permanently 
plug the well.
    (g) Ensure that all subsea wellheads, casing stubs, mud line 
suspensions, or other obstructions in water depths less than 300 feet 
remain protected.
    (1) To confirm that the subsea protective covering remains properly 
installed, either conduct a visual inspection or perform a trawl test at 
least annually.
    (2) If the inspection reveals that a casing stub or mud line 
suspension is no longer properly protected, or if the trawl does not 
pass over the subsea protective covering without causing damage to the 
covering, the casing stub or mud line suspension equipment, or the 
trawl, notify the appropriate District Manager within 5 days, and 
perform the necessary remedial work within 30 days of discovery of the 
problem.
    (3) In your annual report required by paragraph (f) of this section, 
include the inspection date, results, and method used and a description 
of any remedial work you will perform or have performed.
    (h) You may request approval to waive the trawling test required by 
paragraph (c) of this section if you plan to use either:
    (1) A buoy with automatic tracking capabilities installed and 
maintained according to USCG requirements at 33 CFR part 67 (or its 
successor); or
    (2) A design and installation method that has been proven successful 
by trawl testing of previous protective devices of the same design and 
installed in areas with similar bottom conditions.



Sec. 250.1723  What must I do when it is no longer necessary to maintain a 

well in temporary abandoned status?

    If you or BSEE determines that continued maintenance of a well in a 
temporary abandoned status is not necessary for the proper development 
or production of a lease, you must:
    (a) Promptly and permanently plug the well according to Sec. 
250.1715;
    (b) Remove any casing stub or mud line suspension equipment and any 
subsea protective covering. You must submit a request for approval to 
perform such work to the appropriate District Manager using form BSEE-
0124, Application for Permit to Modify; and
    (c) Clear the well site according to Sec. Sec. 250.1740 through 
250.1742.

                 Removing Platforms and Other Facilities



Sec. 250.1725  When do I have to remove platforms and other facilities?

    (a) You must remove all platforms and other facilities within 1 year 
after the lease or pipeline right-of-way terminates, unless you receive 
approval to maintain the structure to conduct other activities. 
Platforms include production platforms, well jackets, single-well 
caissons, and pipeline accessory platforms. Other activities include 
those supporting OCS oil and gas production and transportation, as well 
as other energy-related or marine-related uses (including LNG) for which 
adequate financial assurance for decommissioning has been provided to a 
Federal agency which has given BSEE a commitment that it has and will 
exercise authority to compel the performance of decommissioning within a 
time following cessation of the new use acceptable to BSEE. The approval 
will specify:
    (1) Whether you must continue to maintain any financial assurance 
for decommissioning; and
    (2) Whether, and under what circumstances, you must perform any 
decommissioning not performed by the new facility owner/user.
    (b) Before you may remove a platform or other facility, you must 
submit a final removal application to the Regional Supervisor for 
approval and

[[Page 229]]

include the information listed in Sec. 250.1727.
    (c) You must remove a platform or other facility according to the 
approved application.
    (d) You must flush all production risers with seawater before you 
remove them.
    (e) You must notify the Regional Supervisor at least 48 hours before 
you begin the removal operations.



Sec. 250.1726  When must I submit an initial platform removal application and 

what must it include?

    An initial platform removal application is required only for leases 
and pipeline rights-of-way in the Pacific OCS Region or the Alaska OCS 
Region. It must include the following information:
    (a) Platform or other facility removal procedures, including the 
types of vessels and equipment you will use;
    (b) Facilities (including pipelines) you plan to remove or leave in 
place;
    (c) Platform or other facility transportation and disposal plans;
    (d) Plans to protect marine life and the environment during 
decommissioning operations, including a brief assessment of the 
environmental impacts of the operations, and procedures and mitigation 
measures that you will take to minimize the impacts; and
    (e) A projected decommissioning schedule.



Sec. 250.1727  What information must I include in my final application to 

remove a platform or other facility?

    You must submit to the Regional Supervisor, a final application for 
approval to remove a platform or other facility. Your application must 
be accompanied by payment of the service fee listed in Sec. 250.125. If 
you are proposing to use explosives, provide three copies of the 
application. If you are not proposing to use explosives, provide two 
copies of the application. Include the following information in the 
final removal application, as applicable:
    (a) Identification of the applicant including:
    (1) Lease operator/pipeline right-of-way holder;
    (2) Address;
    (3) Contact person and telephone number; and
    (4) Shore base.
    (b) Identification of the structure you are removing including:
    (1) Platform Name/BSEE Complex ID Number;
    (2) Location (lease/right-of-way, area, block, and block 
coordinates);
    (3) Date installed (year);
    (4) Proposed date of removal (Month/Year); and
    (5) Water depth.
    (c) Description of the structure you are removing including:
    (1) Configuration (attach a photograph or a diagram);
    (2) Size;
    (3) Number of legs/casings/pilings;
    (4) Diameter and wall thickness of legs/casings/pilings;
    (5) Whether piles are grouted inside or outside;
    (6) Brief description of soil composition and condition;
    (7) The sizes and weights of the jacket, topsides (by module), 
conductors, and pilings; and
    (8) The maximum removal lift weight and estimated number of main 
lifts to remove the structure.
    (d) A description, including anchor pattern, of the vessel(s) you 
will use to remove the structure.
    (e) Identification of the purpose, including:
    (1) Lease expiration/right-of-way relinquishment date; and
    (2) Reason for removing the structure.
    (f) A description of the removal method, including:
    (1) A brief description of the method you will use;
    (2) If you are using explosives, the following:
    (i) Type of explosives;
    (ii) Number and sizes of charges;
    (iii) Whether you are using single shot or multiple shots;
    (iv) If multiple shots, the sequence and timing of detonations;
    (v) Whether you are using a bulk or shaped charge;
    (vi) Depth of detonation below the mud line; and
    (vii) Whether you are placing the explosives inside or outside of 
the pilings;
    (3) If you will use divers or acoustic devices to conduct a pre-
removal survey to detect the presence of turtles

[[Page 230]]

and marine mammals, a description of the proposed detection method; and
    (4) A statement whether or not you will use transducers to measure 
the pressure and impulse of the detonations.
    (g) Your plans for transportation and disposal (including as an 
artificial reef) or salvage of the removed platform.
    (h) If available, the results of any recent biological surveys 
conducted in the vicinity of the structure and recent observations of 
turtles or marine mammals at the structure site.
    (i) Your plans to protect archaeological and sensitive biological 
features during removal operations, including a brief assessment of the 
environmental impacts of the removal operations and procedures and 
mitigation measures you will take to minimize such impacts.
    (j) A statement whether or not you will use divers to survey the 
area after removal to determine any effects on marine life.



Sec. 250.1728  To what depth must I remove a platform or other facility?

    (a) Unless the Regional Supervisor approves an alternate depth under 
paragraph (b) of this section, you must remove all platforms and other 
facilities (including templates and pilings) to at least 15 feet below 
the mud line.
    (b) The Regional Supervisor may approve an alternate removal depth 
if:
    (1) The remaining structure would not become an obstruction to other 
users of the seafloor or area, and geotechnical and other information 
you provide demonstrate that erosional processes capable of exposing the 
obstructions are not expected; or
    (2) You determine, and BSEE concurs, that you must use divers and 
the seafloor sediment stability poses safety concerns; or
    (3) The water depth is greater than 800 meters (2,624 feet).



Sec. 250.1729  After I remove a platform or other facility, what information 

must I submit?

    Within 30 days after you remove a platform or other facility, you 
must submit a written report to the Regional Supervisor that includes 
the following:
    (a) A summary of the removal operation including the date it was 
completed;
    (b) A description of any mitigation measures you took; and
    (c) A statement signed by your authorized representative that 
certifies that the types and amount of explosives you used in removing 
the platform or other facility were consistent with those set forth in 
the approved removal application.



Sec. 250.1730  When might BSEE approve partial structure removal or toppling 

in place?

    The Regional Supervisor may grant a departure from the requirement 
to remove a platform or other facility by approving partial structure 
removal or toppling in place for conversion to an artificial reef if you 
meet the following conditions:
    (a) The structure becomes part of a State artificial reef program, 
and the responsible State agency acquires a permit from the U.S. Army 
Corps of Engineers and accepts title and liability for the structure; 
and
    (b) You satisfy any U.S. Coast Guard (USCG) navigational 
requirements for the structure.



Sec. 250.1731  Who is responsible for decommissioning an OCS facility subject 

to an Alternate Use RUE?

    (a) The holder of an Alternate Use RUE issued under 30 CFR part 585 
is responsible for all decommissioning obligations that accrue following 
the issuance of the Alternate Use RUE and which pertain to the Alternate 
Use RUE. See 30 CFR part 585, subpart J, for additional information 
concerning the decommissioning responsibilities of an Alternate Use RUE 
grant holder.
    (b) The lessee under the lease originally issued under 30 CFR part 
556 will remain responsible for decommissioning obligations that accrued 
before issuance of the Alternate Use RUE, as well as for decommissioning 
obligations that accrue following issuance of the Alternate Use RUE to 
the extent associated with continued activities authorized under this 
part.

[[Page 231]]

    (c) If a lease issued under 30 CFR part 556 is cancelled or 
otherwise terminated under any provision of this subchapter, the lessee, 
upon our approval, may defer removal of any OCS facility within the 
lease area that is subject to an Alternate Use RUE. If we elect to grant 
such a deferral, the lessee remains responsible for removing the 
facility upon termination of the Alternate Use RUE and will be required 
to retain sufficient bonding or other financial assurances to ensure 
that the structure is removed or otherwise decommissioned in accordance 
with the provisions of this subpart.

        Site Clearance for Wells, Platforms, and Other Facilities



Sec. 250.1740  How must I verify that the site of a permanently plugged well, 

removed platform, or other removed facility is clear of obstructions?

    Within 60 days after you permanently plug a well or remove a 
platform or other facility, you must verify that the site is clear of 
obstructions by using one of the following methods:
    (a) For a well site, you must either:
    (1) Drag a trawl over the site;
    (2) Scan across the location using sonar equipment;
    (3) Inspect the site using a diver;
    (4) Videotape the site using a camera on a remotely operated vehicle 
(ROV); or
    (5) Use another method approved by the District Manager if the 
particular site conditions warrant.
    (b) For a platform or other facility site in water depths less than 
300 feet, you must drag a trawl over the site.
    (c) For a platform or other facility site in water depths 300 feet 
or more, you must either:
    (1) Drag a trawl over the site;
    (2) Scan across the site using sonar equipment; or
    (3) Use another method approved by the Regional Supervisor if the 
particular site conditions warrant.



Sec. 250.1741  If I drag a trawl across a site, what requirements must I meet?

    If you drag a trawl across the site in accordance with Sec. 
250.1740, you must meet all of the requirements of this section.
    (a) You must drag the trawl in a grid-like pattern as shown in the 
following table:

------------------------------------------------------------------------
                                               You must drag the trawl
                For a . . .                        across a . . .
------------------------------------------------------------------------
(1) Well site,                              300-foot-radius circle
                                             centered on the well
                                             location.
(2) Subsea well site,                       600-foot-radius circle
                                             centered on the well
                                             location.
(3) Platform site,                          1,320-foot-radius circle
                                             centered on the location of
                                             the platform.
(4) Single-well caisson, well protector     600-foot-radius circle
 jacket, template, or manifold,              centered on the structure
                                             location.
------------------------------------------------------------------------

    (b) You must trawl 100 percent of the limits described in paragraph 
(a) of this section in two directions.
    (c) You must mark the area to be cleared as a hazard to navigation 
according to USCG requirements until you complete the site clearance 
procedures.
    (d) You must use a trawling vessel equipped with a calibrated 
navigational positioning system capable of providing position accuracy 
of 30 feet.
    (e) You must use a trawling net that is representative of those used 
in the commercial fishing industry (one that has a net strength equal or 
greater than that provided by No. 18 twine).
    (f) You must ensure that you trawl no closer than 300 feet from a 
shipwreck, and 500 feet from a sensitive biological feature.
    (g) If you trawl near an active pipeline, you must meet the 
requirements in the following table:

----------------------------------------------------------------------------------------------------------------
                For . . .                            You must trawl . . .                 And you must . . .
----------------------------------------------------------------------------------------------------------------
(1) Buried active pipelines,               ........................................  First contact the pipeline
                                                                                      owner or operator to
                                                                                      determine the condition of
                                                                                      the pipeline before
                                                                                      trawling over the buried
                                                                                      pipeline.

[[Page 232]]

 
(2) Unburied active pipelines that are 8   no closer than 100 feet to the either     Trawl parallel to the
 inches in diameter or larger,              side of the pipeline,                     pipeline Do not trawl
                                                                                      across the pipeline.
(3) Unburied smaller diameter active       no closer than 100 feet to either side    Trawl parallel to the
 pipelines in the trawl area that have      of the pipeline,                          pipeline. Do not trawl
 obstructions (e.g., pipeline valves)                                                 across the pipeline.
 present,
(4) Unburied active pipelines in the       parallel to the pipeline,                 ...........................
 trawl area that are smaller than 8
 inches in diameter and have no
 obstructions present,
----------------------------------------------------------------------------------------------------------------

    (h) You must ensure that any trawling contractor you may use:
    (1) Has no corporate or other financial ties to you; and
    (2) Has a valid commercial trawling license for both the vessel and 
its captain.



Sec. 250.1742  What other methods can I use to verify that a site is clear?

    If you do not trawl a site, you can verify that the site is clear of 
obstructions by using any of the methods shown in the following table:

----------------------------------------------------------------------------------------------------------------
             If you use . . .                           You must . . .                    And you must . . .
----------------------------------------------------------------------------------------------------------------
(a) Sonar,                                 cover 100 percent of the appropriate      Use a sonar signal with a
                                            grid area listed in Sec.  250.1741(a),   frequency of at least 500
                                                                                      kHz.
(b) A diver,                               ensure that the diver visually inspects   Ensure that the diver uses
                                            100 percent of the appropriate grid       a search pattern of
                                            area listed in Sec.  250.1741(a),        concentric circles or
                                                                                      parallel lines spaced no
                                                                                      more than 10 feet apart.
(c) An ROV (remotely operated vehicle),    ensure that the ROV camera records        Ensure that the ROV uses a
                                            videotape over 100 percent of the         pattern of concentric
                                            appropriate grid area listed in Sec.     circles or parallel lines
                                            250.1741(a),                              spaced no more than 10
                                                                                      feet apart.
----------------------------------------------------------------------------------------------------------------



Sec. 250.1743  How do I certify that a site is clear of obstructions?

    (a) For a well site, you must submit to the appropriate District 
Manager within 30 days after you complete the verification activities a 
form BSEE-0124, Application for Permit to Modify, to include the 
following information:
    (1) A signed certification that the well site area is cleared of all 
obstructions;
    (2) The date the verification work