[Title 30 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2011 Edition]
[From the U.S. Government Printing Office]



[[Page 1]]

          

          Title 30

Mineral Resources


________________________

Parts 200 to 699

                         Revised as of July 1, 2011

          Containing a codification of documents of general 
          applicability and future effect

          As of July 1, 2011
                    Published by the Office of the Federal Register 
                    National Archives and Records Administration as a 
                    Special Edition of the Federal Register

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                            Table of Contents



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

  Title 30:
          Chapter II--Bureau of Ocean Energy Management, 
          Regulation, and Enforcement, Department of the 
          Interior                                                   3
          Chapter IV--Geological Survey, Department of the 
          Interior                                                 515
  Finding Aids:
      Table of CFR Titles and Chapters........................     529
      Alphabetical List of Agencies Appearing in the CFR......     549
      List of CFR Sections Affected...........................     559

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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 
departments and agencies of the Federal Government. The Code is divided 
into 50 titles which represent broad areas subject to Federal 
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name of the issuing agency. Each chapter is further subdivided into 
parts covering specific regulatory areas.
    Each volume of the Code is revised at least once each calendar year 
and issued on a quarterly basis approximately as follows:

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

    The appropriate revision date is printed on the cover of each 
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LEGAL STATUS

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HOW TO USE THE CODE OF FEDERAL REGULATIONS

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[[Page vi]]

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

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    Director,
    Office of the Federal Register.
    July 1, 2011.







[[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, 2011.

    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 Ocean Energy Management, Regulation, 
  and Enforcement, Department of the Interior...............         203

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

[[Page 3]]



     CHAPTER II--BUREAU OF OCEAN ENERGY MANAGEMENT, REGULATION, AND 
                 ENFORCEMENT, DEPARTMENT OF THE INTERIOR




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

                SUBCHAPTER A--MINERALS REVENUE MANAGEMENT
Part                                                                Page
203             Relief or reduction in royalty rates........           5
219             Distribution and disbursement of royalties, 
                    rentals, and bonuses....................          44
                         SUBCHAPTER B--OFFSHORE
250             Oil and gas and sulphur operations in the 
                    Outer Continental Shelf.................          49
251             Geological and geophysical (G&G) 
                    explorations of the Outer Continental 
                    Shelf...................................         281
252             Outer Continental Shelf (OCS) oil and gas 
                    information program.....................         295
253             Oil spill financial responsibility for 
                    offshore facilities.....................         301
254             Oil-spill response requirements for 
                    facilities located seaward of the coast 
                    line....................................         314
256             Leasing of sulphur or oil and gas in the 
                    Outer Continental Shelf.................         327
259             Mineral leasing: Definitions................         357
260             Outer Continental Shelf oil and gas leasing.         357
270             Nondiscrimination in the Outer Continental 
                    Shelf...................................         364
280             Prospecting for minerals other than oil, 
                    gas, and sulphur on the Outer 
                    Continental Shelf.......................         365
281             Leasing of minerals other than oil, gas, and 
                    sulphur in the Outer Continental Shelf..         377
282             Operations in the Outer Continental Shelf 
                    for minerals other than oil, gas, and 
                    sulphur.................................         390
285             Renewable energy alternate uses of existing 
                    facilities on the Outer Continental 
                    Shelf...................................         412
                          SUBCHAPTER C--APPEALS
290             Appeals procedures..........................         508

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291             Open and nondiscriminatory access to oil and 
                    gas pipelines under the Outer 
                    Continental Shelf Lands Act.............         509

[[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 MMS'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 MMS'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 Sec. 203.0 
          and Sec. Sec. 203.40 through 203.47 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 MMS 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 MMS take to evaluate my application?
203.66 What happens if MMS 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 MMS consider in determining 
          economic viability?
203.69 If my application is approved, what royalty relief will I 
          receive?

[[Page 6]]

203.70 What information must I provide after MMS approves relief?
203.71 How does MMS 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 MMS reconsider its determination?
203.75 What risk do I run if I request a redetermination?
203.76 When might MMS 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 MMS under Sec. Sec. 203.60-203.77 
          for my lease, unit or project if prices rise significantly?
203.79 How do I appeal MMS'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 MMS'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.



                      Subpart A_General Provisions

    Source: 63 FR 2616, Jan. 16, 1998, unless otherwise noted.



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 250, 
subpart A, and does not produce gas or oil, or meets those producibility 
requirements and MMS 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 30 CFR 203.81, 203.83 and 
203.85 through

[[Page 7]]

203.89, along with one set of digital information, which MMS 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 MMS 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 Development and Production 
Plan, a Development Operations Coordination Document (DOCD), or a 
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 DOCD or a Supplement approved by the Secretary of the Interior 
after November, 28, 1995.
    Nonbinding assessment means an opinion by MMS 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 MMS 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 MMS 
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 means 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 an MMS-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 part 250, subpart A 
of this title. 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 and that meets the producibility requirements under part 
250, subpart A of

[[Page 10]]

this chapter 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.

[63 FR 2616, Jan. 16, 1998, as amended at 67 FR 1872, Jan. 15, 2002; 69 
FR 3509, Jan. 26, 2004; 69 FR 24053, Apr. 30, 2004; 73 FR 69504, Nov. 
18, 2008]



Sec. 203.1  What is MMS'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 MMS 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.

[63 FR 2616, Jan. 16, 1998, as amended at 73 FR 69506, Nov. 18, 2008]



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
    If you have a lease . . .      And if you . . .        you . . .
------------------------------------------------------------------------
(a) With earnings that cannot     Would abandon       A reduced royalty
 sustain production (i.e., End-    otherwise           rate on current
 of-life lease).                   potentially         monthly
                                   recoverable         production and a
                                   resources but       higher royalty
                                   seek to increase    rate on
                                   production by       additional
                                   operating beyond    monthly
                                   the point at        production. (See
                                   which the lease     Sec. Sec.
                                   is economic under   203.50 through
                                   the existing        203.56.)
                                   royalty rate.
(b) Located in a designated GOM   Propose an          A royalty
 deep water area (i.e., 200        expansion project   suspension for a
 meters or greater) and acquired   and can             minimum
 in a lease sale held before       demonstrate your    production volume
 November 28, 1995, or after       project is          plus any
 November 28, 2000.                uneconomic          additional
                                   without royalty     production large
                                   relief.             enough to make
                                                       the project
                                                       economic (see
                                                       Sec. Sec.
                                                       203.60 through
                                                       203.79).

[[Page 11]]

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


[67 FR 1872, Jan. 15, 2002, as amended at 73 FR 69506, Nov. 18, 2008]



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 MMS 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 MMS Offshore Web site at: http://
www.mms.gov/offshore/ homepage or directly through Pay.gov at: https://
www.pay.gov/paygov/.

[73 FR 49946, Aug. 25, 2008]



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.

[[Page 12]]

    (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.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                   Information elements                        life       Expansion     Pre-act     Development
                                                              lease        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 and 203.90 
through 203.91 to retain royalty relief.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                   Confirmation elements                       life       Expansion     Pre-act     Development
                                                              lease        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-  ------------------------------------------
                    Approval conditions                        life                     Pre-act     Development
                                                              lease       Expansion      lease        project
----------------------------------------------------------------------------------------------------------------
(1) At least 12 of the last 15 months have the required            X
 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% of net              X
 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 and 
203.74 through 203.75 describe, the prerequisites for a redetermination 
of our royalty relief decision.

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                Redetermination conditions                     Life       Expansion     Pre-act     Development
                                                              lease        project       lease        project
----------------------------------------------------------------------------------------------------------------
(1) After 12 months under current rate, criteria same as           X
 for approval.............................................
(2) For material change in geologic data, prices, costs,    .........              X          X               X
 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-  ------------------------------------------
   Relief rate and volume, subject to certain conditions       life       Expansion     Pre-act     Development
                                                              lease        project       lease        project
----------------------------------------------------------------------------------------------------------------
(1) One-half pre-application effective lease rate on the           X
 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 production            X
 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 the    .........              X   .........              X
 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-  ------------------------------------------
                 Full royalty resumes when                     life       Expansion     Pre-act     Development
                                                              lease        project       lease        project
----------------------------------------------------------------------------------------------------------------
(1) Average NYMEX price for last 12 months is at least 25          X
 percent above the average for the qualifying months......
(2) Average NYMEX price for last calendar year exceeds $28/ .........              X          X
 bbl or $3.50/mcf, escalated by the gross domestic product
 (GDP) deflator since 1994................................
(3) Average prices for designated periods exceed levels we  .........              X   .........              X
 specify in the Notice of Sale or the lease...............
----------------------------------------------------------------------------------------------------------------

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

----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                             End-of-  ------------------------------------------
                Relief withdrawn or reduced                    life       Expansion     Pre-act     Development
                                                              lease        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 that   .........              X          X               X
 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 pre-  .........              X          X               X
 production costs prior to start of production............
(8) Amount of relief volume is produced...................  .........              X          X               X
----------------------------------------------------------------------------------------------------------------


[67 FR 1873, Jan. 15, 2002, as amended at 69 FR 3509, Jan. 26, 2004]



Sec. 203.5  What is MMS'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) The MMS 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

[[Page 14]]

seq. The MMS will protect information considered proprietary under 
applicable law and under regulations at 30 CFR 203.63, ``How do I assess 
my chances for getting relief?'' and 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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.

[74 FR 46907, Sept. 14, 2009]



               Subpart B_OCS Oil, Gas, and Sulfur General

    Source: 63 FR 2618, Jan. 16, 1998, unless otherwise noted.

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

    Source: 73 FR 69506, Nov. 18, 2008, unless otherwise noted.



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
 qualified phase 3 ultra-deep well     Then your lease earns an RSV on
              that is:                  this volume of gas production:
------------------------------------------------------------------------
(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    4 BCF plus 600 MCF times sidetrack
 that is a phase 2 ultra-deep well,   measured depth (rounded to the
                                      nearest 100 feet) but no more than
                                      25 BCF.
(4) An ultra-deep short sidetrack    0 BCF.
 that 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.

[[Page 15]]

    (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:

------------------------------------------------------------------------
  If you have a qualified phase 2      Then your lease earns an RSV on
    ultra-deep well that is . .         this volume of gas production:
------------------------------------------------------------------------
(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

[[Page 16]]

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 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.

[[Page 17]]



Sec. 203.33  To which production do I apply the RSV earned 

by qualified phase 2 and phase 3 ultra-deep wells on my lease or in my unit?

    (a) You must apply the RSV allowed in Sec. 203.31(a) and (b) to gas 
volumes produced from qualified wells on or after May 18, 2007, reported 
on the Oil and Gas Operations Report, Part A (OGOR-A) for your lease 
under Sec. 216.53. 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 an MMS-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 an MMS-
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 an MMS-approved unit agreement 
from qualified wells on unitized areas of your lease and on other leases 
in participating areas of the unit, regardless of their depth, for which 
the requirements in Sec. 203.35 or Sec. 203.44 have been met. The 
allocated share under paragraph (a)(2)(ii) of this section does not 
increase the RSV for your lease.

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

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



Sec. 203.34  To which production may an RSV earned 

by qualified phase 2 and phase 3 ultra-deep wells on my lease not be applied?

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

[[Page 18]]

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



Sec. 203.35  What administrative steps must I take to use the RSV earned 

by a qualified phase 2 or phase 3 ultra-deep well?

    To use an RSV earned under Sec. 203.31:
    (a) You must notify the MMS 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 MMS 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 MMS 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 MMS 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 MMS deems were 
unavoidable.



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

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

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

[[Page 19]]

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

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

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

[[Page 20]]

TVD SS) on a lease located in 325 meters of water with no prior 
production from any deep well and no deep water royalty relief. The 
ultra-deep well would be a phase 2 ultra-deep well (see definition in 
Sec. 203.0), and would earn the lease an RSV of 35 BCF under 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 Sec. 218.54 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

    Source: 69 FR 3510, Jan. 26, 2004, unless otherwise noted.



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 of this part. 
(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.

[73 FR 69510, Nov. 18, 2008]



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.

[[Page 21]]

 
(2) produced gas or oil from  has a qualified deep  earns an RSV
 a well with a perforated      well with a           specified in
 interval whose top is         perforated interval   paragraph (c) of
 18,000 feet TVD SS or         whose top is 18,000   this section.
 deeper,                       feet TVD SS or
                               deeper or a
                               qualified phase 1
                               ultra-deep well,.
------------------------------------------------------------------------

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

------------------------------------------------------------------------
 If you have a qualified deep well
 or a qualified phase 1 ultra-deep     Then your lease earns an RSV on
           well that is:                this volume of gas production:
------------------------------------------------------------------------
(1) An original well with a          15 BCF.
 perforated 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 sidetrack
 interval the top of which is from    measured depth (rounded to the
 15,000 to less than 18,000 feet      nearest 100 feet) but no more than
 TVD SS,                              15 BCF.
(3) An original well with a          25 BCF.
 perforated 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 sidetrack
 interval the top of which is at      measured depth (rounded to the
 least 18,000 feet TVD SS,            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 is . .        Then you earn an RSV on this amount of gas production:
                      .
----------------------------------------------------------------------------------------------------------------
(1) An original well or a sidetrack with a     0 BCF.
 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 interval     4 BCF plus 600 MCF times sidetrack measured depth (rounded to the
 the top of which is 18,000 feet TVD SS or      nearest 100 feet) but no more than 10 BCF.
 deeper,
----------------------------------------------------------------------------------------------------------------

    (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

[[Page 22]]

(b)(2) of this section limits the RSV for a sidetrack at the amount an 
original well to the same depth would earn.
    Example 4: If you have drilled and produced a deep well with a 
perforated interval the top of which is 16,000 feet TVD SS before March 
26, 2003 (and the well therefore is not a qualified well and has earned 
no RSV under this section), and later drill:
    (i) A deep well with a perforated interval the top of which is 
17,000 feet TVD SS, your lease earns no RSV (see paragraph (c)(1) of 
this section);
    (ii) A qualified deep well that is an original well with a 
perforated interval the top of which is 19,000 feet TVD SS, your lease 
earns an RSV of 10 BCF under paragraph (c)(2) of this section. This RSV 
would be applied to gas production from qualified wells on your lease, 
as prescribed in 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.

[73 FR 69510, Nov. 18, 2008]



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

[[Page 23]]

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

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

[73 FR 69512, Nov. 18, 2008]



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 Sec. 216.53, 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 
an MMS-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 an MMS-approved unit. Under the unit

[[Page 24]]

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 
(c)(3) of this section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of:
    (i) May 3, 2004, for an RSV earned by a qualified well or qualified 
phase 1 ultra-deep well on a lease that is located entirely or partly in 
water less than 200 meters deep;
    (ii) May 18, 2007, for an RSV earned by a qualified deep well on a 
lease that is located entirely in water more than 200 meters deep; or
    (iii) The date that the first qualified well that earns your lease 
the RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production:
    (i) From all qualified wells on the non-unitized area of your lease, 
regardless of their depth, for which you have met the requirements in 
Sec. 203.35 or Sec. 203.44; and,
    (ii) Allocated to your lease under an MMS-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.

[73 FR 69512, Nov. 18, 2008]



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

    (a) You must notify the MMS 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:

[[Page 25]]

    (1) Provide written notification to the MMS 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 MMS Regional Supervisor for Production 
and Development has determined are necessary under 30 CFR part 250, 
subpart L.
    (d) You must provide the information in paragraph (b) of this 
section by January 20, 2009 if you produced before December 18, 2008 
from a qualified deep well or qualified phase 1 ultra-deep well on a 
lease that is located entirely in water more than 200 meters and less 
than 400 meters deep.
    (e) The MMS 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 MMS deems were 
unavoidable.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004. 
Redesignated and amended at 73 FR 69512, 69513, Nov. 18, 2008]



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. 
204.46.

----------------------------------------------------------------------------------------------------------------
  If you have a certified unsuccessful well        Then your lease earns an RSS on this volume of oil and gas
                   that is:                       production as prescribed in this section and Sec.  203.46:
----------------------------------------------------------------------------------------------------------------
(1) An original well and your lease has not    5 BCFE.
 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 sidetrack measured depth (rounded to
 depth of at least 10,000 feet) and your        the nearest 100 feet) but no more than 5 BCFE.
 lease has not produced gas or oil from a
 deep well or an ultra-deep well,
(3) An original well or a sidetrack (with a    2 BCFE.
 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 Sec. 216.53.
    (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

[[Page 26]]

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, MMS rounds the sidetrack 
measured depth to 12,500 feet and your lease earns an RSS of 2.3 BCFE of 
gas and oil production as prescribed in Sec. 203.45.

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

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004; 72 
FR 25198, May 4, 2007; 73 FR 15890, Mar. 26, 2008. Redesignated and 
amended at 73 FR 69512, 69513, Nov. 18, 2008; 74 FR 46907, Sept. 14, 
2009]



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. 204.47(b),
    (2) From, or allocated under an MMS-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

[[Page 27]]

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 an MMS-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 an MMS-approved unit agreement. If your certified 
unsuccessful well is on a lease subject to an MMS-approved unit 
agreement, the lessees of other leases in the unit may not apply any 
portion of the RSS for your lease to production from the other leases in 
the unit.
    (f) You must begin or resume paying royalties when cumulative gas 
and oil production from, or allocated under an MMS-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.

[69 FR 3510, Jan. 26, 2004. Redesignated and amended at 73 FR 69512, 
69514, Nov. 18, 2008]



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 
MMS 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 MMS Regional 
Supervisor for Production and Development within 60 days after reaching 
the total depth in your well:
    (1) Information that allows MMS 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 250, subpart A; or
    (ii) Well log, well test, seismic, and economic data, if your well 
does meet the producibility requirements of 30 CFR part 250, subpart A; 
and
    (2) Information that allows MMS 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.

[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004. 
Redesignated and amended at 69512, 69514, Nov. 18, 2008]



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.

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

[[Page 28]]

 
(3) Entirely more than 200 meters and  on any date,                                $4.55 per MMBtu, adjusted
 entirely less than 400 meters deep,                                                annually after calendar year
                                                                                    2007 for inflation 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 Sec. 218.54 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.

[73 FR 69514, Nov. 18, 2008]



Sec. 203.49  May I substitute the deep gas drilling provisions in 

Sec. 203.0 and Sec. Sec. 203.40 through 203.47 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 MMS 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.

[69 FR 3510, Jan. 26, 2004. Redesignated and amended at 73 FR 69512, 
69515, Nov. 18, 2008]

                  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.

[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]



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 MMS Regional Director. Your MMS regional office will provide 
specific guidance on the report formats. A

[[Page 29]]

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 MMS 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
    (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.

[[Page 30]]

  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).

[73 FR 69515, Nov. 18, 2008]



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 250, 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 MMS 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.



Sec. 203.62  How do I apply for relief?

    (a) You must send a complete application and the required fee to the 
MMS 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 MMS 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.

[73 FR 69515, Nov. 18, 2008]



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

[[Page 31]]

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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]



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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]



Sec. 203.65  How long will MMS 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.

------------------------------------------------------------------------
                If--                            Then we may--
------------------------------------------------------------------------
We need more records to audit sunk   Ask to extend the 120-day or 180-
 costs.                               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.
We cannot evaluate your application  Add another 30 days. We may add
 for a valid reason, such as          more than 30 days, but only if you
 missing vital information or         agree.
 inconsistent or inconclusive
 supporting data.
We need more data, explanations, or  Ask to extend the 120-day or 180-
 revision.                            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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]



Sec. 203.66  What happens if MMS 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
 If you apply for royalty relief   decide within the    As long as you
               for                  time specified
------------------------------------------------------------------------
(a) An authorized field.........  You get the         Abide by Sec.
                                   minimum             Sec.  203.70 and
                                   suspension          203.76.
                                   volumes specified
                                   in Sec.  203.69.
(b) An expansion project........  You get a royalty   Abide by Sec.
                                   suspension for      Sec.  203.70 and
                                   the first year of   203.76.
                                   production.

[[Page 32]]

 
(c) A development project.......  You get a royalty   Abide by Sec.
                                   suspension for      Sec.  203.70 and
                                   initial             203.76.
                                   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.
------------------------------------------------------------------------


[67 FR 1875, Jan. 15, 2002]



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.

[67 FR 1876, Jan. 15, 2002]



Sec. 203.68  What pre-application costs will MMS 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   Whether a development project
 discovery well on each lease.            or an expansion project needs
                                          relief to become economic.
------------------------------------------------------------------------


[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002]



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

[[Page 33]]

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

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002; 73 
FR 58472, Oct. 7, 2008; 73 FR 69515, Nov. 18, 2008]



Sec. 203.70  What information must I provide after MMS 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 MMS Regional Office for your region will prescribe the 
formats.

------------------------------------------------------------------------
                                                           Due date
         Required report            When due to MMS       extensions
------------------------------------------------------------------------
(a) Fabricator's confirmation     Within 18 months    MMS Director may
 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     justification
                                   of production       from you, the MMS
                                   that is subject     Regional Director
                                   to the approved     for your region
                                   royalty             may extend the
                                   suspension volume.  due date up to 30
                                                       days.
------------------------------------------------------------------------


[67 FR 1876, Jan. 15, 2002, as amended at 73 FR 69515, Nov. 18, 2008]

[[Page 34]]



Sec. 203.71  How does MMS 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 lease   We will not change  Production from
 to your authorized field after    your authorized     the assigned
 we approve relief.                field's royalty     eligible lease(s)
                                   suspension volume   counts toward the
                                   determined under    royalty
                                   Sec.  203.69.      suspension volume
                                                       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 Sec.
                                                       260.114 of this
                                                       chapter.
(2) We assign a pre-Act or post-  We will not change  The assigned
 November 2000 deep water lease    your field's        lease(s) may
 to your field after we approve    royalty             share in any
 your application.                 suspension volume.  remaining royalty
                                                       relief by 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 that  In our evaluation   (i) You toll the
 you operate to your field while   of your             time period for
 we are evaluating your            authorized field,   evaluation until
 application.                      we will take into   you modify your
                                   account the value   application to be
                                   of any royalty      consistent with
                                   relief the added    the newly
                                   lease already has   constituted
                                   under Sec.         field;
                                   260.114 or its     (ii) We have an
                                   lease document.     additional 60
                                   If we find your     days to review
                                   authorized field    the new
                                   still needs         information; and
                                   additional         (iii) The assigned
                                   royalty             pre-Act lease or
                                   suspension          royalty
                                   volume, that        suspension lease
                                   volume will be at   shares the
                                   least the           royalty
                                   combined royalty    suspension we
                                   suspension volume   grant to the
                                   to which all        newly constituted
                                   added leases on     field. An
                                   the field are       eligible lease
                                   entitled, or the    does not share
                                   minimum             the royalty
                                   suspension volume   suspension we
                                   of the authorized   grant to the new
                                   field, whichever    field. If you do
                                   is greater.         not agree to
                                                       toll, we will
                                                       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 Sec.
                                                       260.114 of this
                                                       chapter.
(4) We assign another operator's  We will change      (i) You both toll
 lease to your field while we      your field's        the time period
 are evaluating your application.  minimum             for evaluation
                                   suspension volume   until both of you
                                   provided the        modify your
                                   assigned lease      application to be
                                   joins the           consistent with
                                   application and     the new field;
                                   is entitled to a   (ii) We have an
                                   larger minimum      additional 60
                                   suspension volume.  days 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.

[[Page 35]]

 
(5) We reassign a well on a pre-  The past            For any field
 Act, eligible, or royalty         production from     based relief, the
 suspension lease from field A     the well counts     past production
 to field B.                       toward the          for that well
                                   royalty             will not count
                                   suspension volume   toward any
                                   that we grant       royalty
                                   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
                                                       Sec.  260.114 if
                                                       the well is on an
                                                       eligible lease or
                                                       under Sec.
                                                       260.124 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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1877, Jan. 15, 2002; 73 
FR 58472, Oct. 7, 2008]



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 MMS 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
    (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.

[[Page 36]]

    (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.

[63 FR 2618, Jan. 16, 1998; 63 FR 24747, May 5, 1998, as amended at 67 
FR 1878, Jan. 15, 2002]



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 MMS 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 within18 months of the date we approved your 
application, unless the MMS 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 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

[[Page 37]]

granting royalty relief under this section. You must pay royalties and 
late-payment interest determined under 30 U.S.C. 1721 and Sec. 218.54 
of this chapter on all volumes for which you used the royalty 
suspension. You also may be subject to penalties under other provisions 
of law.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1878, Jan. 15, 2002]



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 MMS Regional office for your region.

[73 FR 69516, Nov. 18, 2008]



Sec. 203.78  Do I keep relief approved by MMS under 

Sec. Sec. 203.60-203.77 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 MMS 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.

----------------------------------------------------------------------------------------------------------------
                  For . . .                                    The base price threshold is . . .
----------------------------------------------------------------------------------------------------------------
(1) Pre-Act leases in the GOM,                 set by statute.
(2) Post-November 2000 deep water leases in    indicated in your original lease agreement or, if none, those in
 the GOM or leases offshore of Alaska for       the Notice of Sale under which your lease was issued.
 which the lease or Notice of Sale set a base
 price threshold,
(3) Post-November 2000 deep water leases in    the threshold set by statute for pre-Act leases.
 the GOM or leases offshore of Alaska 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) 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 
Sec. 218.54 of this chapter) 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 
Sec. 218.54 of this chapter) 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):
    (1) Of oil if the arithmetic average of the closing prices for the 
current calendar year is $28.00 per barrel or less,

[[Page 38]]

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 part 230 of this chapter 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.

[73 FR 69516, Nov. 18, 2008]



Sec. 203.79  How do I appeal MMS'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 MMS Director a letter within 15 
days that also states your reasons. The MMS 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 MMS Director and stating your reasons. The MMS 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 means 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.

[67 FR 1879, Jan. 15, 2002, as amended at 73 FR 69516, Nov. 18, 2008]

[[Page 39]]

                            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-  ------------------------------------------
                     Required reports                          life       Expansion     Pre-act     Development
                                                              lease        project       lease        project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information Report.....................         X               X          X               X
(2) Net revenue & relief justification report.............         X
(3) Economic viability & relief justification report (RSVP  .........              X          X               X
 model imputs 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 MMS 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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002; 73 
FR 69516, Nov. 18, 2008]



Sec. 203.82  What is MMS'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(b) and part 250 of this chapter.

[[Page 40]]

    (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.
    (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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.

[63 FR 2618, Jan. 16, 1998, as amended at 65 FR 2875, Jan. 19, 2000; 74 
FR 46907, Sept. 14, 2009]



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 we 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).

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]



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, MMS. 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 220.013 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.

[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]

[[Page 41]]



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, MMS. Clearly justify each parameter you set 
in every scenario you specify in the RSVP. You may provide supplemental 
information, including your own model and results. The economic 
viability and relief justification report must contain the following 
items for an oil and gas lease.
    (a) Economic assumptions we provide which include:
    (1) Starting oil and gas prices;
    (2) Real price growth;
    (3) Real cost growth or decline rate, if any;
    (4) Base year;
    (5) Range of discount rates; and
    (6) Tax rate (for use in determining after-tax sunk costs).
    (b) Analysis of projected cash flow (from the date of the 
application using annual totals and constant dollar values) which shows:
    (1) Oil and gas production;
    (2) Total revenues;
    (3) Capital expenditures;
    (4) Operating costs;
    (5) Transportation costs; and
    (6) Before-tax net cash flow without royalties, overrides, sunk 
costs, and ineligible costs.
    (c) Discounted values which include:
    (1) Discount rate used (selected from within the range we specify).
    (2) Before-tax net present value without royalties, overrides, sunk 
costs, and ineligible costs.
    (d) Demonstrations that:
    (1) All costs, gross production, and scheduling are consistent with 
the data in the G&G, engineering, production, and cost reports 
(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 MMS 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;

[[Page 42]]

    (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
    (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.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]



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

[[Page 43]]

    (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 three 
scenarios, you must explain why fewer scenarios are more efficient 
across the whole field size distribution.

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]



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;

[[Page 44]]

    (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).

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]



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 MMS 
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.

[63 FR 2618, Jan. 16, 1998, as amended at 73 FR 69516, Nov. 18, 2008]



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).

[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]

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]



PART 219_DISTRIBUTION AND DISBURSEMENT OF ROYALTIES, RENTALS, AND BONUSES--Table of Contents



Subpart A--General Provision [Reserved]

Subpart B--Oil and Gas, General [Reserved]

Subpart C [Reserved]

                     Subpart D_Oil and Gas, Offshore

Sec.
219.410 What does this subpart contain?
219.411 What definitions apply to this subpart?
219.412 How will the qualified OCS revenues be divided?
219.413 How will the coastal political subdivisions of Gulf producing 
          States share in the qualified OCS revenues?
219.414 How will MMS determine each Gulf producing State's share of the 
          qualified OCS revenues?
219.415 How will bonus and royalty credits affect revenues allocated to 
          Gulf producing States?
219.416 How will the qualified OCS revenues be allocated to coastal 
          political subdivisions within the Gulf producing States?
219.417 How will MMS disburse qualified OCS revenues to the coastal 
          political subdivisions if, during any fiscal year, there are 
          no applicable leased tracts in

[[Page 45]]

          the 181 Area in the Eastern Gulf of Mexico Planning Area?
219.418 When will funds be disbursed to Gulf producing States and 
          eligible coastal political subdivisions?

    Authority: Section 104, Pub. L. 97-451, 96 Stat. 2451 (30 U.S.C. 
1714), Pub. L. 109-432, Div C, Title I, 120 Stat. 3000.

    Source: 49 FR 37347, Sept. 21, 1984, unless otherwise noted.

Subpart A--General Provisions [Reserved]

Subpart B--Oil and Gas, General [Reserved]

Subpart C [Reserved]



                     Subpart D_Oil and Gas, Offshore

    Source: 73 FR 78629, Dec. 23, 2008, unless otherwise noted.



Sec. 219.410  What does this subpart contain?

    (a) The Gulf of Mexico Energy Security Act of 2006 (GOMESA) directs 
the Secretary of the Interior to disburse a portion of the rentals, 
royalties, bonus, and other sums derived from certain Outer Continental 
Shelf (OCS) leases in the Gulf of Mexico (GOM) to the States of Alabama, 
Louisiana, Mississippi, and Texas (collectively identified as the Gulf 
producing States); to eligible coastal political subdivisions within 
those States; and to the Land and Water Conservation Fund. Shared GOMESA 
revenues are reserved for the following purposes:
    (1) Projects and activities for the purposes of coastal protection, 
including conservation, coastal restoration, hurricane protection, and 
infrastructure directly affected by coastal wetland losses.
    (2) Mitigation of damage to fish, wildlife, or natural resources.
    (3) Implementation of a federally-approved marine, coastal, or 
comprehensive conservation management plan.
    (4) Mitigation of the impact of OCS activities through the funding 
of onshore infrastructure projects.
    (5) Planning assistance and administrative costs not-to-exceed 3 
percent of the amounts received.
    (b) This subpart sets forth the formula and methodology MMS will use 
to determine the amount of revenues to be disbursed and the amount to be 
allocated to each Gulf producing State and each eligible coastal 
political subdivision. For questions related to the revenue sharing 
provisions in this subpart, please contact: Chief, Financial Management, 
Minerals Revenue Management; P.O. Box 25165; Denver Federal Center, 
Building 85; MS-350B1; Denver, CO 80225-0165, or at (303) 231-3429.



Sec. 219.411  What definitions apply to this subpart?

    Terms in this subpart have the following meaning:
    181 Area means the area identified in map 15, page 58, of the 
Proposed Final Outer Continental Shelf Oil and Gas Leasing Program for 
1997-2002, dated August 1996, of the Minerals Management Service, 
available in the Office of the Director of the Minerals Management 
Service, excluding the area offered in OCS Lease Sale 181, held on 
December 5, 2001.
    181 Area in the Eastern Planning Area is comprised of the area of 
overlap of the two geographic areas defined as the ``181 Area'' and the 
``Eastern Planning Area.''
    181 South Area means any area--
    (1) Located--
    (i) South of the 181 Area;
    (ii) West of the Military Mission Line; and
    (iii) In the Central Planning Area;
    (2) Excluded from the Proposed Final Outer Continental Shelf Oil and 
Gas Leasing Program for 1997-2002, dated August 1996, of the Minerals 
Management Service; and
    (3) Included in the areas considered for oil and gas leasing, as 
identified in map 8, page 37, of the document entitled, Draft Proposed 
Program Outer Continental Shelf Oil and Gas Leasing Program 2007-2012, 
dated February 2006.
    Applicable leased tract means a tract that is subject to a lease 
under section 8 of the Outer Continental Shelf Lands Act for the purpose 
of drilling for, developing, and producing oil or natural gas resources, 
and is located fully or partially in either the 181 Area in the

[[Page 46]]

Eastern Planning Area, or in the 181 South Area.
    Central Planning Area means the Central Gulf of Mexico Planning Area 
of the Outer Continental Shelf, as designated in the document entitled, 
Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing 
Program 2007-2012, dated February 2006.
    Coastal political subdivision means a political subdivision of a 
Gulf producing State any part of which political subdivision is--
    (1) Within the coastal zone (as defined in section 304 of the 
Coastal Zone Management Act of 1972 (16 U.S.C. 1453)) of the Gulf 
producing State as of December 20, 2006; and
    (2) Not more than 200 nautical miles from the geographic center of 
any leased tract.
    Coastline means the line of ordinary low water along that portion of 
the coast which is in direct contact with the open sea and the line 
marking the seaward limit of inland waters. This is the same definition 
used in section 2 of the Submerged Lands Act (43 U.S.C. 1301).
    Distance means the minimum great circle distance.
    Eastern Planning Area means the Eastern Gulf of Mexico Planning Area 
of the Outer Continental Shelf, as designated in the document entitled, 
Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing 
Program 2007-2012, dated February 2006.
    Gulf producing State means each of the States of Alabama, Louisiana, 
Mississippi, and Texas.
    Leased tract means any tract that is subject to a lease under 
section 6 or 8 of the Outer Continental Shelf Lands Act for the purpose 
of drilling for, developing, and producing oil or natural gas resources.
    Military Mission Line means the north-south line at 86[deg]41[min] 
W. longitude.
    Qualified OCS revenues mean--
    (1) The term qualified OCS revenues means, in the case of each of 
fiscal years 2007 through 2016, all rentals, royalties, bonus bids, and 
other sums received by the U.S. from leases entered into on or after 
December 20, 2006, located:
    (i) In the 181 Area in the Eastern Planning Area; and
    (ii) In the 181 South Area.
    (iii) For applicable leased tracts intersected by the planning area 
administrative boundary line (e.g., separating the GOM Central Planning 
Area from the Eastern Planning Area), only the percent of revenues 
equivalent to the percent of surface acreage in the 181 Area in the 
Eastern Planning Area will be considered qualified OCS revenues.
    (2) Exclusions to the term qualified OCS revenues include:
    (i) Revenues from the forfeiture of a bond or other surety securing 
obligations other than royalties;
    (ii) Civil penalties;
    (iii) Royalties taken by the Secretary in-kind and not sold;
    (iv) User fees; and
    (v) Lease revenues explicitly circumscribed from GOMESA revenue 
sharing by statute or appropriations law.



Sec. 219.412  How will the qualified OCS revenues be divided?

    For each of the fiscal years 2007 through 2016, 50 percent of the 
qualified OCS revenues will be placed in a special U.S. Treasury account 
from which 75 percent of the revenues will be disbursed to the Gulf 
producing States, and 25 percent will be disbursed to the Land and Water 
Conservation Fund. Each Gulf producing State will receive at least 10 
percent of the qualified OCS revenues available for allocation to the 
Gulf producing States each fiscal year.

       Revenue Distribution of Qualified OCS Revenues Under GOMESA
------------------------------------------------------------------------
                                                         Percentage of
                                                         qualified OCS
         Recipient of qualified OCS revenues                revenues
                                                           (percent)
------------------------------------------------------------------------
U.S. Treasury (General Fund).........................               50
Land and Water Conservation Fund.....................               12.5
Gulf Producing States................................               30
Gulf Producing State Coastal Political Subdivisions..                7.5
------------------------------------------------------------------------



Sec. 219.413  How will the coastal political subdivisions of Gulf

producing States share in the qualified OCS revenues?

    Of the revenues allocated to a Gulf producing State, 20 percent will 
be distributed to the coastal political subdivisions within that State.

[[Page 47]]



Sec. 219.414  How will MMS determine each Gulf producing State's share of the qualified OCS revenues?

    (a) The MMS will determine the geographic centers of each applicable 
leased tract and, using the great circle distance method, will determine 
the closest distance from the geographic centers of each applicable 
leased tract to each Gulf producing State's coastline.
    (b) Based on these distances, we will calculate the qualified OCS 
revenues to be disbursed to each Gulf producing State using the 
following procedure:
    (1) For each Gulf producing State, we will calculate and total, over 
all applicable leased tracts, the mathematical inverses of the distances 
between the points on the State's coastline that are closest to the 
geographic centers of the applicable leased tracts and the geographic 
centers of the applicable leased tracts. For applicable leased tracts 
intersected by the planning area administrative boundary line, the 
geographic center used for the inverse distance determination will be 
the geographic center of the entire lease as if it were not intersected.
    (2) For each Gulf producing State, we will divide the sum of each 
State's inverse distances, from all applicable leased tracts, by the sum 
of the inverse distances from all applicable leased tracts across all 
four Gulf producing States. We will multiply the result by the amount of 
qualified OCS revenues to be shared as shown below. In the formulas, 
IAL, ILA, IMS, and ITX represent the sum of the inverses of the closest 
distances between Alabama, Louisiana, Mississippi, and Texas and all 
applicable leased tracts, respectively.

Alabama Share = (IAL / (IAL + ILA + IMS + ITX)) x Qualified OCS Revenues
Louisiana Share = (ILA / (IAL + ILA + IMS + ITX)) x Qualified OCS 
    Revenues
Mississippi Share = (IMS / (IAL + ILA + IMS + ITX)) x Qualified OCS 
    Revenues
Texas Share = (ITX / (IAL + ILA + IMS + ITX)) x Qualified OCS Revenues

    (3) If in any fiscal year, this calculation results in less than a 
10 percent allocation of the qualified OCS revenues to any Gulf 
producing State, we will recalculate the distribution. We will allocate 
10 percent of the qualified OCS revenues to the State and recalculate 
the other States' shares of the remaining qualified OCS revenues 
omitting the State receiving the 10 percent minimum share and its 10 
percent share from the calculation.



Sec. 219.415  How will bonus and royalty credits affect revenues allocated 

to Gulf producing States?

    If bonus and royalty credits issued under Section 104(c) of the Gulf 
of Mexico Energy Security Act are used to pay bonuses or royalties on 
leases in the 181 Area located in the Eastern Planning Area and the 181 
South Area, then there will be a corresponding reduction in qualified 
OCS revenues available for distribution.



Sec. 219.416  How will the qualified OCS revenues be 

allocated to coastal political subdivisions within the Gulf producing States?

    The MMS will disburse funds to the coastal political subdivisions in 
accordance with the following criteria:
    (a) Twenty-five percent of the qualified OCS revenues will be 
allocated to a Gulf producing State's coastal political subdivisions in 
the proportion that each coastal political subdivision's population 
bears to the population of all coastal political subdivisions in the 
producing State;
    (b) Twenty-five percent of the qualified OCS revenues will be 
allocated to a Gulf producing State's coastal political subdivisions in 
the proportion that each coastal political subdivision's miles of 
coastline bears to the number of miles of coastline of all coastal 
political subdivisions in the producing State. Except that, for the 
State of Louisiana, proxy coastline lengths for coastal political 
subdivisions without a coastline will be considered to be \1/3\ the 
average length of the coastline of all political subdivisions within 
Louisiana having a coastline.
    (c) Fifty percent of the revenues will be allocated to a Gulf 
producing State's coastal political subdivisions in amounts that are 
inversely proportional to the respective distances between the 
geographic center of each applicable leased tract and the point in each 
coastal political subdivision that is closest to the geographic center 
of each applicable leased tract. Except that, an applicable leased tract 
will be

[[Page 48]]

excluded from this calculation if any portion of the tract is located in 
a geographic area that was subject to a leasing moratorium on January 1, 
2005, unless that tract was in production on that date.



Sec. 219.417  How will MMS disburse qualified OCS revenues to the coastal 

political subdivisions if, during any fiscal year, there are no applicable leased 
          tracts in the 181 Area in the Eastern Gulf of Mexico Planning 
          Area?

    If, during any fiscal year, there are no applicable leased tracts in 
the 181 Area in the Eastern Gulf of Mexico Planning Area, MMS will 
disburse funds to the coastal political subdivisions in accordance with 
the following criteria:
    (a) Fifty percent of the revenues will be allocated to a Gulf 
producing State's coastal political subdivisions in the proportion that 
each coastal political subdivision's population bears to the population 
of all coastal political subdivisions in the State; and
    (b) Fifty percent of the revenues will be allocated to a Gulf 
producing State's coastal political subdivisions in the proportion that 
each coastal political subdivision's miles of coastline bears to the 
number of miles of coastline of all coastal political subdivisions in 
the State. Except that, for the State of Louisiana, proxy coastline 
lengths for coastal political subdivisions without a coastline will be 
considered to be \1/3\ the average length of the coastline of all 
political subdivisions within Louisiana having a coastline.



Sec. 219.418  When will funds be disbursed to Gulf producing States and 

eligible coastal political subdivisions?

    (a) The MMS will disburse allocated funds in the fiscal year after 
MMS collects the qualified OCS revenues. For example, MMS will disburse 
funds in fiscal year 2010 from the qualified OCS revenues collected 
during fiscal year 2009.
    (b) We intend to disburse funds on or before March 31st of the year 
following the fiscal year of qualified OCS revenues.

[[Page 49]]



                          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 MMS 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 How do I determine well producibility?
250.116 How do I determine producibility if my well is in the Gulf of 
          Mexico?
250.117 How does a determination of well producibility affect royalty 
          status?
250.118 Will MMS approve gas injection?
250.119 Will MMS approve subsurface gas storage?
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 Will MMS allow gas storage on unleased lands?
250.124 Will MMS 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 MMS conduct inspections?
250.131 Will MMS notify me before conducting an inspection?
250.132 What must I do when MMS conducts an inspection?
250.133 Will MMS reimburse me for my expenses related to inspections?

                            Disqualification

250.135 What will MMS do if my operating performance is unacceptable?
250.136 How will MMS 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 How do I designate an operator?
250.144 How do I designate a new operator when a designation of operator 
          terminates?
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?

                        Right-of-Use and Easement

250.160 When will MMS grant me a right-of-use and easement, and what 
          requirements must I meet?
250.161 What else must I submit with my application?
250.162 May I continue my right-of-use and easement after the 
          termination of any lease on which it is situated?
250.163 If I have a State lease, will MMS grant me a right-of-use and 
          easement?
250.164 If I have a State lease, what conditions apply for a right-of-
          use and easement?
250.165 If I have a State lease, what fees do I have to pay for a right-
          of-use and easement?

[[Page 50]]

250.166 If I have a State lease, what surety bond must I have for a 
          right-of-use and easement?

                               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?
250.181 When may the Secretary cancel my lease and when am I compensated 
          for cancellation?
250.182 When may the Secretary cancel a lease at the exploration stage?
250.183 When may MMS or the Secretary extend or cancel a lease at the 
          development and production stage?
250.184 What is the amount of compensation for lease cancellation?
250.185 When is there no compensation for a lease cancellation?

                 Information and Reporting Requirements

250.186 What reporting information and report forms must I submit?
250.187 What are MMS' incident reporting requirements?
250.188 What incidents must I report to MMS 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 MMS 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 apparent violations.
250.194 How must I protect archaeological resources?
250.195 What notification does MMS 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 What criteria must the Exploration Plan (EP), Development and 
          Production Plan (DPP), or Development Operations Coordination 
          Document (DOCD) meet?
250.203 Where can wells be located under an EP, DPP, or DOCD?
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?
250.206 How do I submit the EP, DPP, or DOCD?

                          Ancillary Activities

250.207 What ancillary activities may I conduct?
250.208 If I conduct ancillary activities, what notices must I provide?
250.209 What is the MMS review process for the notice?
250.210 If I conduct ancillary activities, what reporting and data/
          information retention requirements must I satisfy?

                   Contents of Exploration Plans (EP)

250.211 What must the EP include?
250.212 What information must accompany the EP?
250.213 What general information must accompany the EP?
250.214 What geological and geophysical (G&G) information must accompany 
          the EP?
250.215 What hydrogen sulfide (H2S) information must 
          accompany the EP?
250.216 What biological, physical, and socioeconomic information must 
          accompany the EP?
250.217 What solid and liquid wastes and discharges information and 
          cooling water intake information must accompany the EP?
250.218 What air emissions information must accompany the EP?
250.219 What oil and hazardous substance spills information must 
          accompany the EP?

[[Page 51]]

250.220 If I propose activities in the Alaska OCS Region, what planning 
          information must accompany the EP?
250.221 What environmental monitoring information must accompany the EP?
250.222 What lease stipulations information must accompany the EP?
250.223 What mitigation measures information must accompany the EP?
250.224 What information on support vessels, offshore vehicles, and 
          aircraft you will use must accompany the EP?
250.225 What information on the onshore support facilities you will use 
          must accompany the EP?
250.226 What Coastal Zone Management Act (CZMA) information must 
          accompany the EP?
250.227 What environmental impact analysis (EIA) information must 
          accompany the EP?
250.228 What administrative information must accompany the EP?

                 Review and Decision Process for the EP

250.231 After receiving the EP, what will MMS do?
250.232 What actions will MMS take after the EP is deemed submitted?
250.233 What decisions will MMS make on the EP and within what 
          timeframe?
250.234 How do I submit a modified EP or resubmit a disapproved EP, and 
          when will MMS make a decision?
250.235 If a State objects to the EP's coastal zone consistency 
          certification, what can I do?

   Contents of Development and Production Plans (DPP) and Development 
                Operations Coordination Documents (DOCD)

250.241 What must the DPP or DOCD include?
250.242 What information must accompany the DPP or DOCD?
250.243 What general information must accompany the DPP or DOCD?
250.244 What geological and geophysical (G&G) information must accompany 
          the DPP or DOCD?
250.245 What hydrogen sulfide (H2S) information must 
          accompany the DPP or DOCD?
250.246 What mineral resource conservation information must accompany 
          the DPP or DOCD?
250.247 What biological, physical, and socioeconomic information must 
          accompany the DPP or DOCD?
250.248 What solid and liquid wastes and discharges information and 
          cooling water intake information must accompany the DPP or 
          DOCD?
250.249 What air emissions information must accompany the DPP or DOCD?
250.250 What oil and hazardous substance spills information must 
          accompany the DPP or DOCD?
250.251 If I propose activities in the Alaska OCS Region, what planning 
          information must accompany the DPP?
250.252 What environmental monitoring information must accompany the DPP 
          or DOCD?
250.253 What lease stipulations information must accompany the DPP or 
          DOCD?
250.254 What mitigation measures information must accompany the DPP or 
          DOCD?
250.255 What decommissioning information must accompany the DPP or DOCD?
250.256 What related facilities and operations information must 
          accompany the DPP or DOCD?
250.257 What information on the support vessels, offshore vehicles, and 
          aircraft you will use must accompany the DPP or DOCD?
250.258 What information on the onshore support facilities you will use 
          must accompany the DPP or DOCD?
250.259 What sulphur operations information must accompany the DPP or 
          DOCD?
250.260 What Coastal Zone Management Act (CZMA) information must 
          accompany the DPP or DOCD?
250.261 What environmental impact analysis (EIA) information must 
          accompany the DPP or DOCD?
250.262 What administrative information must accompany the DPP or DOCD?

             Review and Decision Process for the DPP or DOCD

250.266 After receiving the DPP or DOCD, what will MMS do?
250.267 What actions will MMS take after the DPP or DOCD is deemed 
          submitted?
250.268 How does MMS respond to recommendations?
250.269 How will MMS evaluate the environmental impacts of the DPP or 
          DOCD?
250.270 What decisions will MMS make on the DPP or DOCD and within what 
          timeframe?
250.271 For what reasons will MMS disapprove the DPP or DOCD?
250.272 If a State objects to the DPP's or DOCD's coastal zone 
          consistency certification, what can I do?
250.273 How do I submit a modified DPP or DOCD or resubmit a disapproved 
          DPP or DOCD?

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

250.280 How must I conduct activities under the approved EP, DPP, or 
          DOCD?
250.281 What must I do to conduct activities under the approved EP, DPP, 
          or DOCD?
250.282 Do I have to conduct post-approval monitoring?

[[Page 52]]

250.283 When must I revise or supplement the approved EP, DPP, or DOCD?
250.284 How will MMS require revisions to the approved EP, DPP, or DOCD?
250.285 How do I submit revised and supplemental EPs, DPPs, or DOCDs?

                    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?

                Conservation Information Documents (CID)

250.296 When and how must I submit a CID or a revision to a CID?
250.297 What information must a CID contain?
250.298 How long will MMS take to evaluate and make a decision on the 
          CID?
250.299 What operations require approval of the CID?

               Subpart C_Pollution Prevention and Control

250.300 Pollution prevention.
250.301 Inspection of facilities.
250.302 Definitions concerning air quality.
250.303 Facilities described in a new or revised Exploration Plan or 
          Development and Production Plan.
250.304 Existing 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?
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?

[[Page 53]]

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 (AMP) or 
          an End of Operations Report to MMS?
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 Blowout prevention equipment.
250.516 Blowout preventer system tests, inspections, and maintenance.
250.517 Tubing and wellhead equipment.

                       Casing Pressure Management

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

[[Page 54]]

250.614 Well-control fluids, equipment, and operations.
250.615 Blowout prevention equipment.
250.616 Blowout preventer system testing, records, and drills.
250.617 What are my BOP inspection and maintenance requirements?
250.618 Tubing and wellhead equipment.
250.619 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 MMS requirements for assessment of fixed platforms?
250.921 How do I analyze my platform for cumulative fatigue?

             Subpart J_Pipelines and Pipeline Rights-of-Way

250.1000 General requirements.
250.1001 Definitions.
250.1002 Design requirements for DOI pipelines.
250.1003 Installation, testing and repair requirements for DOI 
          pipelines.
250.1004 Safety equipment requirements for DOI pipelines.
250.1005 Inspection requirements for DOI pipelines.
250.1006 Abandonment and out-of-service requirements for DOI pipelines.
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 Bond requirements for pipeline right-of-way holders.
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.

[[Page 55]]

              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 When must I conduct a static bottomhole pressure survey?

                         Classifying Reservoirs

250.1154 How do I determine if my reservoir is sensitive?
250.1155 What information must I submit for sensitive reservoirs?

                      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?

               Flaring, 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 MMS require unitization?

            Subpart N_Outer Continental Shelf Civil Penalties

            Outer Continental Shelf Lands Act Civil Penalties

250.1400 How does MMS 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 MMS review for potential civil penalties?
250.1405 When is a case file developed?
250.1406 When will MMS notify me and provide penalty information?
250.1407 How do I respond to the letter of notification?
250.1408 When will I be notified of the Reviewing Officer's decision?
250.1409 What are my appeal rights?

 Federal Oil and Gas Royalty Management Act Civil Penalties Definitions

250.1450 What definitions apply to this subpart?

                   Penalties After a Period To Correct

250.1451 What may the Bureau of Ocean Energy Management, Regulation, and 
          Enforcement (BOEMRE) 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 BOEMRE inform me of violations without a period to 
          correct?

[[Page 56]]

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 BOEMRE 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 BOEMRE reduce my penalty once it is assessed?
250.1477 How may BOEMRE 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 BOEMRE-specified surety instrument meet?
250.1491 How will BOEMRE 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 BOEMRE determine if I am financially solvent?
250.1497 When will BOEMRE 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 MMS measure training results?
250.1508 What must I do when MMS administers written or oral tests?
250.1509 What must I do when MMS administers or requires hands-on, 
          simulator, or other types of testing?
250.1510 What will MMS 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.
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?

[[Page 57]]

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?

                       Permanently Plugging Wells

250.1710 When must I permanently plug all wells on a lease?
250.1711 When will MMS 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 MMS 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 MMS 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 Definitions.
250.1904 Documents incorporated by reference
250.1905-250.1908 [Reserved]
250.1909 What are management's general responsibilities for the SEMS 
          program?
250.1910 What safety and environmental information is required?
250.1911 What criteria for hazards analyses 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 criteria for training 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?
250.1921-250.1923 [Reserved]
250.1924 How will BOEMRE determine if my SEMS program is effective?
250.1925 May BOEMRE direct me to conduct additional audits?
250.1926 What qualifications must an independent third party or my 
          designated and qualified personnel meet?
250.1927 What happens if BOEMRE 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?


[[Page 58]]


    Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 43 U.S.C. 1334.

    Source: 53 FR 10690, Apr. 1, 1988, unless otherwise noted. 
Redesignated at 63 FR 29479, May 29, 1998.

    Editorial Note: Nomenclature changes to part 250 appear at 71 FR 
46399 and 46400, Aug. 14, 2006.



                            Subpart A_General

    Source: 64 FR 72775, Dec. 28, 1999, unless otherwise noted.

                    Authority and Definition of Terms



Sec. 250.101  Authority and applicability.

    The Secretary of the Interior (Secretary) authorized the Minerals 
Management Service (MMS) 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, MMS 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) 30 CFR part 250 contains the regulations of the MMS 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 MMS 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
------------------------------------------------------------------------
                                                Refer to  30 CFR 250
           For information about                     subpart or
------------------------------------------------------------------------
(1) Applications for permit to drill......  D.
(2) Development and Production Plans (DPP)  B.
(3) Downhole commingling..................  K.
(4) Exploration Plans (EP)................  B.
(5) Flaring...............................  K.
(6) Gas measurement.......................  L.
(7) Off-lease geological and geophysical    30 CFR 251.
 permits.
(8) Oil spill financial responsibility      30 CFR 253.
 coverage.
(9) Oil and gas production safety systems.  H.
(10) Oil spill response plans.............  30 CFR 254.
(11) Oil and gas well-completion            E.
 operations.
(12) Oil and gas well-workover operations.  F.
(13) Decommissioning Activities...........  Q.
(14) Platforms and structures.............  I.
(15) Pipelines and Pipeline Rights-of-Way.  J.
(16) Sulphur operations...................  P.
(17) Training.............................  O.
(18) Unitization..........................  M.
------------------------------------------------------------------------


[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 35405, May 17, 2002; 68 
FR 8422, Feb. 20, 2003; 70 FR 51500, Aug. 30, 2005; 72 FR 25198, May 4, 
2007]



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

    MMS 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 MMS.



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

    To appeal orders or decisions issued under MMS 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

[[Page 59]]

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, well 
logs or charts, results from formation fluid tests, and descriptions of 
hydrocarbon occurrences or hazardous conditions.
    Ancillary activities means 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 MMS 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 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 
Director 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.

[[Page 60]]

    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 means approvals granted by the appropriate MMS 
representative for operating requirements/procedures other than those 
specified in the regulations found in this part. These requirements/
procedures may be necessary to control a well; properly develop a lease; 
conserve natural resources, or protect life, property, or the marine, 
coastal, or human environment.
    Development means those activities that take place following 
discovery of minerals in paying quantities, including but not limited to 
geophysical activity, drilling, platform construction, and operation of 
all directly related onshore support facilities, and which are for the 
purpose of producing the minerals discovered.
    Development geological and geophysical (G&G) activities means 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 MMS of the U.S. Department of the 
Interior, or an official authorized to act on the Director's behalf.
    District Manager means the MMS officer with authority and 
responsibility for operations or other designated program functions for 
a district within an MMS 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 
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 means 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 means 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 Sec. 250.303, means an OCS facility 
described in an Exploration Plan or a Development and Production Plan 
approved before June 2, 1980.
    Exploration means the commercial search for oil, gas, or sulphur. 
Activities classified as exploration include but are not limited to:
    (1) Geophysical and geological (G&G) surveys using magnetic, 
gravity, seismic reflection, seismic refraction, gas

[[Page 61]]

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 Sec. 250.303, means all installations or devices 
permanently or temporarily attached to the seabed. They include mobile 
offshore drilling units (MODUs), even while operating in the ``tender 
assist'' mode (i.e. with skid-off drilling units) or other vessels 
engaged in drilling or downhole operations. They are used for 
exploration, development, and production activities for oil, gas, or 
sulphur and emit or have the potential to emit any air pollutant from 
one or more sources. They include all floating production systems 
(FPSs), including column-stabilized-units (CSUs); floating production, 
storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); 
spars, etc. During production, multiple installations or devices are a 
single facility if the installations or devices are at a single site. 
Any vessel used to transfer production from an offshore facility is part 
of the facility while it is physically attached to the facility.
    (3) As used in Sec. 250.490(b), means a vessel, a structure, or an 
artificial island used for drilling, well completion, well-workover, or 
production operations.
    (4) As used in 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.
    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 means 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:

[[Page 62]]

    (1) Drilling, logging, coring, testing, or producing operations have 
confirmed the absence of H2S in concentrations that could 
potentially result in atmospheric concentrations of 20 ppm or more of 
H2S; or
    (2) Drilling in the surrounding areas and correlation of geological 
and seismic data with equivalent stratigraphic units have confirmed an 
absence of H2S throughout the area to be drilled.
    H2S present means drilling, logging, coring, testing, or 
producing operations have confirmed the presence of H2S in 
concentrations and volumes that could potentially result in atmospheric 
concentrations of 20 ppm or more of H2S.
    H2S unknown means the designation of a zone or geologic 
formation where neither the presence nor absence of H2S has 
been confirmed.
    Human environment means the physical, social, and economic 
components, conditions, and factors that interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Interpreted geological information means geological knowledge, often 
in the form of schematic cross sections, 3-dimensional representations, 
and maps, developed by determining the geological significance of data 
and analyzed geological information.
    Interpreted geophysical information means geophysical knowledge, 
often in the form of schematic cross sections, 3-dimensional 
representations, and maps, developed by determining the geological 
significance of geophysical data and analyzed geophysical information.
    Lease means an agreement that is issued under section 8 or 
maintained under section 6 of the Act and that authorizes exploration 
for, and development and production of, minerals. The term also means 
the area covered by that authorization, whichever the context requires.
    Lease term pipelines means 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 MMS-approved assignee of the lease, and 
the owner or the MMS-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 means 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 includes 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 includes, 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.

[[Page 63]]

    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 means 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 MMS-approved designated agent of the 
lessee(s), or the holder of operating rights under an MMS-approved 
operating rights assignment.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose 
subsoil and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Person includes a natural person, an association (including 
partnerships, joint ventures, and trusts), a State, a political 
subdivision of a State, or a private, public, or municipal corporation.
    Pipelines are the piping, risers, and appurtenances installed for 
transporting oil, gas, sulphur, and produced waters.
    Processed geological or geophysical information means data collected 
under a permit or a lease that have been processed or reprocessed. 
Processing involves changing the form of data to facilitate 
interpretation. Processing operations may include, but are not limited 
to, applying corrections for known perturbing causes, rearranging or 
filtering data, and combining or transforming data elements. 
Reprocessing is the additional processing other than ordinary processing 
used in the general course of evaluation. Reprocessing operations may 
include varying identified parameters for the detailed study of a 
specific problem area.
    Production means those activities that take place after the 
successful completion of any means for the removal of minerals, 
including such removal, field operations, transfer of minerals to shore, 
operation monitoring, maintenance, and workover operations.
    Production areas are those areas where flammable petroleum gas, 
volatile liquids or sulphur are produced, processed (e.g., compressed), 
stored, transferred (e.g., pumped), or otherwise handled before entering 
the transportation process.
    Projected emissions means 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 MMS officer with responsibility and 
authority for a Region within MMS.
    Regional Supervisor means the MMS officer with responsibility and 
authority for operations or other designated program functions within an 
MMS Region.
    Right-of-use means any authorization issued under this part 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).

[[Page 64]]

    Routine operations, for the purposes of subpart F, means 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;
    (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 means 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 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 means 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.

[64 FR 72775, Dec. 28, 1999, as amended at 68 FR 8422, Feb. 20, 2003; 70 
FR 41573, July 19, 2005; 70 FR 51500, Aug. 30, 2005; 71 FR 23862, Apr. 
25, 2006; 75 FR 20288, Apr. 19, 2010]

                          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.

[[Page 65]]



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 MMS 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.

[64 FR 72775, Dec. 28, 1999, as amended at 73 FR 20171, Apr. 15, 2008]



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), incorporated 
by reference as specified in 30 CFR 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 Cranes (API Spec 
2C), incorporated by reference as specified in 30 CFR 250.198.
    (d) All cranes manufactured after March 17, 2003, and installed on a 
fixed platform, must meet the requirements of API Spec 2C, incorporated 
by reference as specified in 30 CFR 250.198.
    (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.

[68 FR 7426, Feb. 14, 2003, as amended at 72 FR 12092, Mar. 15, 2007; 74 
FR 46907, Sept. 14, 2009]



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

[[Page 66]]

    (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.
    (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

[[Page 67]]

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.
    (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 (incorporated by 
reference as specified 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 (incorporated by reference as 
specified 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.

[64 FR 72775, Dec. 28, 1999, as amended at 65 FR 219, Jan. 4, 2000; 68 
FR 43298, July 22, 2003]



Sec. 250.115  How do I determine well producibility?

    You must follow the procedures in this section to determine well 
producibility if your well is not in the GOM. If your well is in the GOM 
you must follow the procedures in either this section or in Sec. 
250.116 of this subpart.
    (a) You must write to the Regional Supervisor asking for permission 
to determine producibility.
    (b) You must either:
    (1) Allow the District Manager to witness each test that you conduct 
under this section; or
    (2) Receive the District Manager's prior approval so that you can 
submit either test data with your affidavit or third party test data.
    (c) If the well is an oil well, you must conduct a production test 
that lasts at least 2 hours after flow stabilizes.
    (d) If the well is a gas well, you must conduct a deliverability 
test that lasts at least 2 hours after flow stabilizes, or a four-point 
back pressure test.



Sec. 250.116  How do I determine producibility if my well is in the Gulf of Mexico?

    If your well is in the GOM, you must follow either the procedures in 
Sec. 250.115 of this subpart or the procedures in this section to 
determine producibility.
    (a) You must write to the Regional Supervisor asking for permission 
to determine producibility.
    (b) You must provide or make available to the Regional Supervisor, 
as requested, the following log, core, analyses, and test criteria that 
MMS will consider collectively:
    (1) A log showing sufficient porosity in the producible section.
    (2) Sidewall cores and core analyses that show that the section is 
capable of producing oil or gas.
    (3) Wireline formation test and/or mud-logging analyses that show 
that the section is capable of producing oil or gas.
    (4) A resistivity or induction electric log of the well showing a 
minimum of 15 feet (true vertical thickness except for horizontal wells) 
of producible sand in one section.
    (c) No section that you count as producible under paragraph (b)(4) 
of this section may include any interval that appears to be water 
saturated.
    (d) Each section you count as producible under paragraph (b)(4) of 
this section must exhibit:
    (1) A minimum true resistivity ratio of the producible section to 
the nearest clean or water-bearing sand of at least 5:1; and
    (2) One of the following:
    (i) Electrical spontaneous potential exceeding 20-negative 
millivolts beyond the shale baseline; or
    (ii) Gamma ray log deflection of at least 70 percent of the maximum 
gamma ray deflection in the nearest clean water-bearing sand--if mud 
conditions prevent a 20-negative millivolt reading beyond the shale 
baseline.

[[Page 68]]



Sec. 250.117  How does a determination of well producibility affect royalty status?

    A determination of well producibility invokes minimum royalty status 
on the lease as provided in 30 CFR 202.53.



Sec. 250.118  Will MMS 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 MMS approval for injection, you must:
    (1) Show that the injection will not result in undue interference 
with operations under existing leases; and
    (2) Submit a written application to the Regional Supervisor for 
injection of gas.
    (b) The Regional Supervisor will approve gas injection applications 
that:
    (1) Enhance recovery;
    (2) Prevent flaring of casinghead gas; or
    (3) Implement other conservation measures approved by the Regional 
Supervisor.



Sec. 250.119  Will MMS approve subsurface gas storage?

    The Regional Supervisor may authorize subsurface storage of gas on 
the OCS, on and off-lease, for later commercial benefit. To receive MMS 
approval you must:
    (a) Show that the subsurface storage of gas will not result in undue 
interference with operations under existing leases; and
    (b) Sign a storage agreement that includes the required payment of a 
storage fee or rental.



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 
Sec. 250.119, 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 an MMS-
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  Will MMS allow gas storage on unleased lands?

    You may not store gas on unleased lands unless the Regional 
Supervisor approves a right-of-use and easement for that purpose, under 
Sec. Sec. 250.160 through 250.166 of this subpart.



Sec. 250.124  Will MMS 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 MMS 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.

[[Page 69]]



                            Service Fee Table
------------------------------------------------------------------------
  Service--processing of the
          following:                  Fee amount         30 CFR citation
------------------------------------------------------------------------
(1) Change in Designation of    $164..................  Sec.
 Operator.                                               250.143(d).
(2) Right-of-Use and Easement   $2,569................  Sec.  250.165.
 for State lessee.
(3) Suspension of Operations/   $1,968................  Sec.
 Suspension of Production (SOO/                          250.171(e).
 SOP) Request.
(4) Exploration Plan (EP).....  $3,442 for each         Sec.
                                 surface location; no    250.211(d).
                                 fee for revisions.
(5) Development and Production  $3,971 for each well    Sec.
 Plan (DPP) or Development       proposed; no fee for    250.241(e).
 Operations Coordination         revisions.
 Document (DOCD).
(6) Deepwater Operations Plan.  $3,336................  Sec.
                                                         250.292(p).
(7) Conservation Information    $25,629...............  Sec.
 Document.                                               250.296(a).
(8) Application for Permit to   $1,959 for initial      Sec.
 Drill (APD; Form MMS-123).      applications only; no   250.410(d);
                                 fee for revisions.      Sec.  250.411;
                                                         Sec.  250.460;
                                                         Sec.
                                                         250.513(b);
                                                         Sec.  250.515;
                                                         Sec.
                                                         250.1605; Sec.
                                                          250.1617(a);
                                                         Sec.
                                                         250.1622.
(9) Application for Permit to   $116..................  Sec.  250.460;
 Modify (APM; Form MMS-124).                             Sec.
                                                         250.465(b);
                                                         Sec.
                                                         250.513(b);
                                                         Sec.  250.515;
                                                         Sec.
                                                         250.613(b);
                                                         Sec.  250.615;
                                                         Sec.
                                                         250.1618(a);
                                                         Sec.
                                                         250.1622; Sec.
                                                          250.1704(g).
(10) New Facility Production    $5,030 A component is   Sec.
 Safety System Application for   a piece of equipment    250.802(e).
 facility with more than 125     or ancillary system
 components.                     that is protected by
                                 one or more of the
                                 safety devices
                                 required by API RP
                                 14C (incorporated by
                                 reference as
                                 specified in Sec.
                                 250.198); $13,238
                                 additional fee will
                                 be charged if MMS
                                 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 fee   Sec.
 Safety System Application for   of $8,313 will be       250.802(e).
 facility with 25-125            charged if MMS deems
 components.                     it necessary to visit
                                 a facility offshore,
                                 and $4,766 to visit a
                                 facility in a
                                 shipyard.
(12) New Facility Production    $604..................  Sec.
 Safety System Application for                           250.802(e).
 facility with fewer than 25
 components.
(13) Production Safety System   $561..................  Sec.
 Application--Modification                               250.802(e).
 with more than 125 components
 reviewed.
(14) Production Safety System   $201..................  Sec.
 Application--Modification                               250.802(e).
 with 25-125 components
 reviewed.
(15) Production Safety System   $85...................  Sec.
 Application--Modification                               250.802(e).
 with fewer than 25 components
 reviewed.
(16) Platform Application--     $21,075...............  Sec.
 Installation--Under the                                 250.905(k).
 Platform Verification Program.
(17) Platform Application--     $3,018................  Sec.
 Installation--Fixed Structure                           250.905(k).
 Under the Platform Approval
 Program.
(18) Platform Application--     $1,536................  Sec.
 Installation--Caisson/Well                              250.905(k).
 Protector.
(19) Platform Application--     $3,601................  Sec.
 Modification/Repair.                                    250.905(k).
(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      $2,569................  Sec.
 (ROW) 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         $4,592................  Sec.  250.1157.
 Request.
(29) Downhole Commingling       $5,357................  Sec.
 Request.                                                250.1158(a).
(30) Complex Surface            $3,760................  Sec.
 Commingling and Measurement                             250.1202(a);
 Application.                                            Sec.
                                                         250.1203(b);
                                                         Sec.
                                                         250.1204(a).

[[Page 70]]

 
(31) Simple Surface             $1,271................  Sec.
 Commingling and Measurement                             250.1202(a);
 Application.                                            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             $1,059................  Sec.
 Decommission a Pipeline                                 250.1751(a) or
 (Lease Term).                                           Sec.
                                                         250.1752(a).
(36) Application to             $2,012................  Sec.
 Decommission a Pipeline (ROW).                          250.1751(a) 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.

[70 FR 49875, Aug. 25, 2005, as amended at 71 FR 40909, July 19, 2006; 
72 FR 25199, May 4, 2007; 73 FR 49946, Aug. 25, 2008; 75 FR 20288, Apr. 
19, 2010]



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 MMS 
Offshore Web site at: http://www.mms.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.

[73 FR 49947, Aug. 25, 2008]

                        Inspection of Operations



Sec. 250.130  Why does MMS conduct inspections?

    MMS 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 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 MMS notify me before conducting an inspection?

    MMS conducts both scheduled and unscheduled inspections.



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

    (a) When MMS 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

[[Page 71]]

    (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 MMS reimburse me for my expenses related to inspections?

    Upon request, MMS will reimburse you for food, quarters, and 
transportation that you provide for MMS 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 MMS do if my operating performance is unacceptable?

    If your operating performance is unacceptable, MMS 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 MMS officials before imposing a disqualification.



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

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

                       Special Types of Approvals



Sec. 250.140  When will I receive an oral approval?

    When you apply for MMS 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 orally.............  Give you an oral approval..  You must then confirm the oral request by
                                                                        sending us a written request within 72
                                                                        hours.
(b) Request approval in writing.........  Give you an oral approval    We will send you a written approval
                                           if quick action is needed.   afterward. It will include any
                                                                        conditions that we place on the oral
                                                                        approval.
(c) Request approval orally for gas       Give you an oral approval..  You don't have to follow up with a
 flaring.                                                               written 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 MMS 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 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.

[65 FR 6536, Feb. 10, 2000]

[[Page 72]]



Sec. 250.143  How do I designate an operator?

    (a) You must provide the Regional Supervisor an executed Designation 
of Operator form (Form MMS-1123) unless you are the only lessee and are 
the only person conducting lease operations. When there is more than one 
lessee, each lessee must submit the Designation of Operator form and the 
Regional Supervisor must approve the designation before the designated 
operator may begin operations on the leasehold.
    (b) This designation is authority for the designated operator to act 
on your behalf and to fulfill your obligations under the Act, the lease, 
and the regulations in this part.
    (c) You, or your designated operator, must immediately provide the 
Regional Supervisor a written notification of any change of address.
    (d) If you change the designated operator on your lease, you must 
pay the service fee listed in Sec. 250.125 of this subpart with your 
request for a change in designation of operator. Should there be 
multiple lessees, all designation of operator forms must be collected by 
one lessee and submitted to MMS in a single submittal, which is subject 
to only one filing fee.

[64 FR 72775, Dec. 28, 1999, as amended at 70 FR 49876, Aug. 25, 2005; 
72 FR 25200, May 4, 2007]



Sec. 250.144  How do I designate a new operator when a designation of operator terminates?

    (a) When a Designation of Operator terminates, the Regional 
Supervisor must approve a new designated operator before you may 
continue operations. Each lessee must submit a new executed Designation 
of Operator form.
    (b) If your Designation of Operator is terminated, or a controversy 
develops between you and your designated operator, you and your 
designated operator must protect the lessor's interests.



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, 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, 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 require 
the lessee to meet a requirement or perform an action, the lessee, 
operator (if one has been designated), and the person actually 
performing the activity to which the requirement applies are jointly and 
severally responsible for complying with the regulation.

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



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

    (a) Assign each facility a letter designation except for those types 
of facilities identified in paragraph (c)(1) of this section. For 
example, A, B, CA, or CB.
    (1) After a facility is installed, rename each predrilled well that 
was assigned only a number and was suspended temporarily at the mudline 
or at the surface. Use a letter and number designation. The letter used 
must be the same as that of the production facility, and the number used 
must correspond to the order in which the well was completed, not 
necessarily the number assigned when it was drilled. For example, the 
first well completed for production on Facility A would be

[[Page 73]]

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.
    (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.

[[Page 74]]

                        Right-of-use and Easement



Sec. 250.160  When will MMS grant me a right-of-use and easement, and what 

requirements must I meet?

    MMS may grant you a right-of-use and easement on leased and unleased 
lands on the OCS, if you meet these requirements:
    (a) You must need the right-of-use and easement to construct and 
maintain platforms, artificial islands, and installations and other 
devices at an OCS site other than an OCS lease you own, that are:
    (1) Permanently or temporarily attached to the seabed; and
    (2) Used for conducting exploration, development, and production 
activities or other operations on or off lease; or
    (3) Used for other purposes approved by MMS.
    (b) You must exercise the right-of-use and easement according to the 
regulations of this part;
    (c) You must meet the requirements at 30 CFR 256.35 (Qualification 
of lessees); establish a regional Company File as required by MMS; and 
must meet bonding requirements;
    (d) If you apply for a right-of-use and easement on a leased area, 
you must notify the lessee and give her/him an opportunity to comment on 
your application; and
    (e) You must receive MMS approval for all platforms, artificial 
islands, and installations and other devices permanently or temporarily 
attached to the seabed.
    (f) You must pay a rental amount as required by paragraph (g) of 
this section if:
    (1) You obtain a right-of-use and easement after January 12, 2004; 
or
    (2) You ask MMS to modify your right-of-use and easement to change 
the footprint of the associated platform, artificial island, or 
installation or device.
    (g) If you meet either of the conditions in paragraph (f) of this 
section, you must pay a rental amount to MMS as shown in the following 
table:

------------------------------------------------------------------------
               If...                               Then...
------------------------------------------------------------------------
(1) Your right-of-use and easement   You must pay a rental of $5 per
 site is located in water depths of   acre per year with a minimum of
 less than 200 meters;                $450 per year. The area subject to
                                      annual rental includes the areal
                                      extent of anchor chains, pipeline
                                      risers, and other equipment
                                      associated with the platform,
                                      artificial island, installation or
                                      device.
(2) Your right-of-use and easement   You must pay a rental of $7.50 per
 site is located in water depths of   acre per year with a minimum of
 200 meters or greater;               $675 per year. The area subject to
                                      annual rental includes the areal
                                      extent of anchor chains, pipeline
                                      risers, and other equipment
                                      associated with the platform,
                                      artificial island, or installation
                                      or device.
------------------------------------------------------------------------

    (h) You may make the rental payments required by paragraph (g)(1) 
and (g)(2) of this section on an annual basis, for a 5-year period, or 
for multiples of 5 years. You must make the first payment electronically 
through Pay.gov and you must include a copy of the Pay.gov confirmation 
receipt page with your right-of-use and easement application. You must 
make all subsequent payments before the respective time periods begin.
    (i) 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 218.54. If you fail to make a payment 
that is late after written notice from MMS, MMS may initiate 
cancellation of the right-of-use grant and easement.

[64 FR 72775, Dec. 28, 1999, as amended at 68 FR 69311, Dec. 12, 2003; 
69 FR 29433, May 24, 2004; 72 FR 25200, May 4, 2007; 73 FR 49948, Aug. 
25, 2008]



Sec. 250.161  What else must I submit with my application?

    With your application, you must describe the proposed use giving:
    (a) Details of the proposed uses and activities including access 
needs and special rights of use that you may need;
    (b) A description of all facilities for which you are seeking 
authorization;
    (c) A map or plat describing primary and alternate project 
locations; and

[[Page 75]]

    (d) A schedule for constructing any new facilities, drilling or 
completing any wells, anticipated production rates, and productive life 
of existing production facilities.



Sec. 250.162  May I continue my right-of-use and easement after the termination 

of any lease on which it is situated?

    If your right-of-use and easement is on a lease, you may continue to 
exercise the right-of-use and easement after the lease on which it is 
situated terminates. You must only use the right-of-use and easement for 
the purpose that the grant specifies. All future lessees of that portion 
of the OCS on which your right-of-use and easement is situated must 
continue to recognize the right-of-use and easement for the purpose that 
the grant specifies.



Sec. 250.163  If I have a State lease, will MMS grant me a right-of-use and easement?

    (a) MMS may grant a lessee of a State lease located adjacent to or 
accessible from the OCS a right-of-use and easement on the OCS.
    (b) MMS will only grant a right-of-use and easement under this 
paragraph to enable a State lessee to conduct and maintain a device that 
is permanently or temporarily attached to the seabed (i.e., a platform, 
artificial island, or installation). The lessee must use the device to 
explore for, develop, and produce oil and gas from the adjacent or 
accessible State lease and for other operations related to these 
activities.



Sec. 250.164  If I have a State lease, what conditions apply for a right-of-use and easement?

    (a) A right-of-use and easement granted under the heading of 
``Right-of-use and easement'' in this subpart is subject to MMS 
regulations, 30 CFR parts 250 through 282, and any terms and conditions 
that the Regional Director prescribes.
    (b) For the whole or fraction of the first calendar year, and 
annually after that, you must pay to MMS, in advance, an annual rental 
payment.



Sec. 250.165  If I have a State lease, what fees do I have to pay for a

right-of-use and easement?

    When you apply for a right-of-use and easement, you must pay:
    (a) A nonrefundable filing fee as specified in Sec. 250.125; and
    (b) The first year's rental as specified in Sec. 250.160(g).

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25200, May 4, 2007]



Sec. 250.166  If I have a State lease, what surety bond must I have for

a right-of-use and easement?

    (a) Before MMS issues you a right-of-use and easement on the OCS, 
you must furnish the Regional Director a surety bond for $500,000.
    (b) The Regional Director may require additional security from you 
(i.e., security above the prescribed $500,000) to cover additional costs 
and liabilities for regulatory compliance. This additional surety:
    (1) Must be in the form of a supplemental bond or bonds meeting the 
requirements of 30 CFR 256.54 (General requirements for bonds) or an 
increase in the coverage of an existing surety bond.
    (2) Covers additional costs and liabilities for regulatory 
compliance, including well abandonment, platform and structure removal, 
and site clearance from the seafloor of the right-of-use and easement.

                               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

[[Page 76]]

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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25200, May 4, 2007]



Sec. 250.170  How long does a suspension last?

    (a) MMS 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. MMS 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) MMS 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 MMS 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. Sec. 250.115, 250.116, or 
250.1603 (SOP only);
    (d) A commitment to production (SOP only); and
    (e) The service fee listed in Sec. 250.125 of this subpart.

[70 FR 49876, Aug. 25, 2005]



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

    The Regional Supervisor may grant or direct an SOO or SOP under any 
of the following circumstances:
    (a) When necessary to comply with judicial decrees prohibiting any 
activities or the permitting of those activities. The effective date of 
the suspension will be the effective date required by the action of the 
court;
    (b) When activities pose a threat of serious, irreparable, or 
immediate harm or damage. This would include a threat to life (including 
fish and other aquatic life), property, any mineral deposit, or the 
marine, coastal, or human environment. MMS 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:

[[Page 77]]

    (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) 5 years; or
    (ii) 8 years with a requirement to drill within 5 years.
    (2) Before the end of the fifth year of the primary term, you or 
your predecessor in interest must have acquired and interpreted 
geophysical information that:
    (i) Indicates that all or a portion of a potential hydrocarbon-
bearing formation lies below 25,000 feet TVD SS; and
    (ii) Includes full 3-D depth migration over the entire lease area.
    (3) Before requesting the suspension, you have conducted or are 
conducting additional data processing or interpretation of the 
geophysical information with the objective of identifying a potential 
hydrocarbon-bearing geologic structure or stratigraphic trap lying below 
25,000 feet TVD SS.
    (4) You demonstrate that additional time is necessary to:
    (i) Complete current processing or interpretation of existing 
geophysical data or information;
    (ii) Acquire, process, or interpret new geophysical or geological 
data or information that would affect the decision to drill the same 
geologic structure or stratigraphic trap, as determined by the Regional 
Supervisor, identified in paragraphs (c)(2) and (c)(3) of this section; 
or
    (iii) Drill a well below 25,000 feet TVD SS into the geologic 
structure or stratigraphic trap identified as a result of the activities 
conducted in paragraphs

[[Page 78]]

(c)(2), (c)(3), and (c)(4)(i) and (ii) of this section.

[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 44360, July 2, 2002; 70 
FR 74663, Dec. 16, 2005; 72 FR 25200, May 4, 2007]



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 Sec. 218.154.



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

    If MMS 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) MMS 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 250, 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 256). 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. Sec. 250.172, 250.173, 250.174, or 250.175 before the 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, 250.173, 250.174, or 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

[[Page 79]]

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. 250.181  When may the Secretary cancel my lease and when am I compensated for cancellation?

    If the Secretary cancels your lease under this part or under 30 CFR 
part 256, you are entitled to compensation under Sec. 250.184. Section 
250.185 states conditions under which you will receive no compensation. 
The Secretary may cancel a lease after notice and opportunity for a 
hearing when:
    (a) Continued activity on the lease would probably cause harm or 
damage to life (including fish and other aquatic life), property, any 
mineral deposits (in areas leased or not leased), or the marine, 
coastal, or human environment;
    (b) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time;
    (c) The advantages of cancellation outweigh the advantages of 
continuing the lease in force; and
    (d) A suspension has been in effect for at least 5 years or you 
request termination of the suspension and lease cancellation.



Sec. 250.182  When may the Secretary cancel a lease at the exploration stage?

    MMS may not approve an exploration plan (EP) under 30 CFR part 250, 
subpart B, if the Regional Supervisor determines that the proposed 
activities may cause serious harm or damage to life (including fish and 
other aquatic life), property, any mineral deposits, the national 
security or defense, or to the marine, coastal, or human environment, 
and that the proposed activity cannot be modified to avoid the 
condition(s). The Secretary may cancel the lease if:
    (a) The primary lease term has not expired (or if the lease term has 
been extended) and exploration has been prohibited for 5 years following 
the disapproval; or
    (b) You request cancellation at an earlier time.



Sec. 250.183  When may MMS or the Secretary extend or cancel a lease at 

the development and production stage?

    (a) MMS may extend your lease if you submit a DPP and the Regional

[[Page 80]]

Supervisor disapproves the plan according to the regulations in 30 CFR 
part 250, subpart B. Following the disapproval:
    (1) MMS will allow you to hold the lease for 5 years, or less time 
at your request;
    (2) Any time within 5 years after the disapproval, you may reapply 
for approval of the same or a modified plan; and
    (3) The Regional Supervisor will approve, disapprove, or require 
modification of the plan under 30 CFR part 250, subpart B.
    (b) If the Regional Supervisor has not approved a DPP or required 
you to submit a DPP for approval or modification, the Secretary will 
cancel the lease:
    (1) When the 5-year period in paragraph (a)(1) of this section 
expires; or
    (2) If you request cancellation at an earlier time.



Sec. 250.184  What is the amount of compensation for lease cancellation?

    When the Secretary cancels a lease under Sec. Sec. 250.181, 250.182 
or 250.183 of this subpart, you are entitled to receive compensation 
under 43 U.S.C. 1334 (a)(2)(C). You must show the Director that the 
amount of compensation claimed is the lesser of paragraph (a) or (b) of 
this section:
    (a) The fair value of the cancelled rights as of the date of 
cancellation, taking into account both:
    (1) Anticipated revenues from the lease; and
    (2) Costs reasonably anticipated on the lease, including:
    (i) Costs of compliance with all applicable regulations and 
operating orders; and
    (ii) Liability for cleanup costs or damages, or both, in the case of 
an oil spill.
    (b) The excess, if any, over your revenues from the lease (plus 
interest thereon from the date of receipt to date of reimbursement) of:
    (1) All consideration paid for the lease (plus interest from the 
date of payment to the date of reimbursement); and
    (2) All your direct expenditures (plus interest from the date of 
payment to the date of reimbursement):
    (i) After the issue date of the lease; and
    (ii) For exploration or development, or both.
    (c) Compensation for leases issued before September 18, 1978, will 
be equal to the amount specified in paragraph (a) of this section.



Sec. 250.185  When is there no compensation for a lease cancellation?

    You will not receive compensation from MMS for lease cancellation 
if:
    (a) MMS disapproves a DPP because you do not receive concurrence by 
the State under section 307(c)(3)(B) (i) or (ii) of the CZMA, and the 
Secretary of Commerce does not make the finding authorized by section 
307(c)(3)(B)(iii) of the CZMA;
    (b) You do not submit a DPP under 30 CFR part 250, subpart B or do 
not comply with the approved DPP;
    (c) As the lessee of a nonproducing lease, you fail to comply with 
the Act, the lease, or the regulations issued under the Act, and the 
default continues for 30 days after MMS mails you a notice by overnight 
mail;
    (d) The Regional Supervisor disapproves a DPP because you fail to 
comply with the requirements of applicable Federal law; or
    (e) The Secretary forfeits and cancels a producing lease under 
section 5(d) of the Act (43 U.S.C. 1334(d)).

                 Information and Reporting Requirements



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

    (a) You must submit information and reports as MMS 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 MMS's forms. You must arrange the data 
on your form identical to the MMS form. If you generate your own form 
and it omits terms and conditions contained on the official MMS form, we 
will consider it to contain the omitted terms and conditions.

[[Page 81]]

    (3) You may submit digital data when the Region/District is equipped 
to accept it.
    (b) When MMS specifies, you must include, for public information, an 
additional copy of such reports.
    (1) You must mark it Public Information.
    (2) You must include all required information, except information 
exempt from public disclosure under Sec. 250.197 or otherwise exempt 
from public disclosure under law or regulation.

[64 FR 72775, Dec. 28, 1999. Redesignated at 71 FR 19644, Apr. 17, 2006, 
as amended at 72 FR 25200, May 4, 2007]



Sec. 250.187  What are MMS' 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 MMS, 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.

[71 FR 19644, Apr. 17, 2006]



Sec. 250.188  What incidents must I report to MMS 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

[[Page 82]]

in property or equipment damage greater than $25,000.

[71 FR 19644, Apr. 17, 2006]



Sec. 250.189  Reporting requirements for incidents requiring immediate notification.

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

[71 FR 19644, Apr. 17, 2006]



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.

[71 FR 19644, Apr. 17, 2006]



Sec. 250.191  How does MMS conduct incident investigations?

    Any investigation that MMS 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 MMS. 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

[[Page 83]]

expenses must be similar to mileage and fees the U.S. District Courts 
allow.

[71 FR 19645, Apr. 17, 2006]



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 
MMS GOM OCS Region, use Form MMS-132) as soon as possible when 
evacuation occurs. In lieu of submitting your statistics by fax or e-
mail, you may submit them electronically in accordance with 30 CFR 
250.186(a)(3);
    (2) Submit the statistics on a daily basis by 11 a.m., as conditions 
allow, during the period of shut-in and evacuation;
    (3) Inform MMS when you resume production; and
    (4) Submit the statistics either by MMS district, or the total 
figures for your operations in an MMS 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 MMS-143, Facility/Equipment Damage Report, to 
make this and all subsequent reports. In lieu of submitting Form MMS-143 
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.

[73 FR 64545, Oct. 30, 2008]



Sec. 250.193  Reports and investigations of apparent violations.

    Any person may report to MMS an apparent violation or failure to 
comply with any provision of the Act, any provision of a lease, license, 
or permit issued under the Act, or any provision of any regulation or 
order issued under the Act. When MMS receives a report of an apparent 
violation, or when an MMS employee detects an apparent violation after 
making an initial determination of the validity, MMS will investigate 
according to MMS procedures.



Sec. 250.194  How must I protect archaeological resources?

    (a) If the Regional Director has reason to believe that an 
archaeological resource may exist in the lease area, the Regional 
Director will require in writing that your EP, DOCD, or DPP be 
accompanied by an archaeological report. If the archaeological report 
suggests that an archaeological resource may be present, you must 
either:
    (1) Locate the site of any operation so as not to adversely affect 
the area where the archaeological resource may be; or
    (2) Establish to the satisfaction of the Regional Director that an 
archaeological resource does not exist or will not be adversely affected 
by operations. This requires further archaeological investigation, 
conducted by an archaeologist and a geophysicist, using survey equipment 
and techniques the Regional Director considers appropriate. You must 
submit the investigation report to the Regional Director for review.
    (b) If the Regional Director determines that an archaeological 
resource

[[Page 84]]

is likely to be present in the lease area and may be adversely affected 
by operations, the Regional Director will notify you immediately. You 
must not take any action that may adversely affect the archaeological 
resource until the Regional Director has told you how to protect the 
resource.
    (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 Regional Director. If investigations determine that the resource is 
significant, the Regional Director will tell you how to protect it.

[64 FR 72775, Dec. 28, 1999, as amended at 71 FR 23862, Apr. 25, 2006; 
72 FR 25200, May 4, 2007]



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

    You must notify the appropriate MMS 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.

[71 FR 23862, Apr. 25, 2006]



Sec. 250.196  Reimbursements for reproduction and processing costs.

    (a) MMS 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 MMS for the Regional Director to inspect or select and 
retain;
    (2) MMS 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) MMS 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 MMS 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) MMS will not reimburse you for data acquisition costs or for the 
costs of analyzing or processing geological information or interpreting 
geological or geophysical information.

[64 FR 72775, Dec. 28, 1999. Redesignated at 71 FR 23862, Apr. 25, 2006]



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

    MMS will protect data and information that you submit under this 
part, and part 203 of this chapter, 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 MMS forms will be made 
available to the public upon submission, except as specified in the 
following table:

[[Page 85]]



------------------------------------------------------------------------
                                     Data and
                                 information not
         On form . . .             immediately     Excepted data will be
                                available are . .   made available . . .
                                        .
------------------------------------------------------------------------
(1) MMS-123, Application for    Items 15, 16, 22   When the well goes on
 Permit to Drill.                through 25.        production or
                                                    according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier.
(2) MMS-123S, Supplemental APD  Items 3, 7, 8, 15  When the well goes on
 Information Sheet.              and 17.            production or
                                                    according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier.
(3) MMS-124, Application for    Item 17..........  When the well goes on
 Permit to Modify.                                  production or
                                                    according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier.
(4) MMS-125, End of Operations  Items 12, 13, 17,  When the well goes on
 Report.                         21, 22, 26         production or
                                 through 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) MMS-126, Well Potential     Item 101.........  2 years after you
 Test Report.                                       submit it.
(6) MMS-127, Sensitive          Items 124 through  2 years after the
 Reservoir Information Report.   168.               effective date of
                                                    the Sensitive
                                                    Reservoir
                                                    Information Report.
(7) MMS-133 Well Activity       Item 10 Fields     When the well goes on
 Report.                         [WELLBORE START    production or
                                 DATE, TD DATE,     according to the
                                 OP STATUS, END     table in paragraph
                                 DATE, MD, TVD,     (b) of this section,
                                 AND MW PPG].       whichever is
                                 Item 11 Fields     earlier.
                                 [WELLBORE START
                                 DATE, TD DATE,
                                 PLUGBACK DATE,
                                 FINAL MD, AND
                                 FINAL TVD] and
                                 Items 12 through
                                 15.
(8) MMS-133S Open Hole Data     Boxes 7 and 8....  When the well goes on
 Report.                                            production or
                                                    according to the
                                                    table in paragraph
                                                    (b) of this section,
                                                    whichever is
                                                    earlier.
(9) MMS-137 OCS Plan            Items providing    When the well goes on
 Information.                    the bottomhole     production or
                                 location, true     according to the
                                 vertical depth,    table in paragraph
                                 and measured       (b) of this section,
                                 depth of wells.    whichever is
                                                    earlier.
(10) MMS-140, Bottomhole        All items........  2 years after the
 Pressure Survey Report.                            date of the survey.
------------------------------------------------------------------------

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

----------------------------------------------------------------------------------------------------------------
                 If                     MMS will release          At this time            Special provisions
----------------------------------------------------------------------------------------------------------------
(1) The Director determines that     Geophysical data,       At any time...........  MMS will release data and
 data and information are needed      Geological data                                 information only if
 for specific scientific or           Interpreted G&G                                 release would further the
 research purposes for the            information,                                    national interest without
 Government.                          Processed G&G                                   unduly damaging the
                                      information, Analyzed                           competitive position of
                                      geological                                      the lessee.
                                      information.
(2) Data or information is           Geophysical data,       60 days after MMS       MMS will release the data
 collected with high-resolution       Geological data,        receives the data or    and information earlier
 systems (e.g., bathymetry, side-     Interpreted G&G         information, if the     than 60 days if the
 scan sonar, subbottom profiler,      information,            Regional Supervisor     Regional Supervisor
 and magnetometer) to comply with     Processed geological    deems it necessary.     determines it is needed by
 safety or environmental protection   information, Analyzed                           affected States to make
 requirements.                        geological                                      decisions under subpart B.
                                      information.                                    The Regional Supervisor
                                                                                      will reconsider earlier
                                                                                      release if you satisfy him/
                                                                                      her that it would unduly
                                                                                      damage your competitive
                                                                                      position.
(3) Your lease is no longer in       Geophysical data,       When your lease         This release time applies
 effect.                              Geological data,        terminates.             only if the provisions in
                                      Processed G&G                                   this table governing high-
                                      information                                     resolution systems and the
                                      Interpreted G&G                                 provisions in Sec.  252.7
                                      information, Analyzed                           do not apply. The release
                                      geological                                      time applies to the
                                      information.                                    geophysical data and
                                                                                      information only if
                                                                                      acquired postlease for a
                                                                                      lessee's exclusive use.

[[Page 86]]

 
(4) Your lease is still in effect..  Geophysical data        10 years after you      This release time applies
                                      Processed geophysical   submit the data and     only if the provisions in
                                      information,            information.            this table governing high-
                                      Interpreted G&G                                 resolution systems and the
                                      information.                                    provisions in Sec.  252.7
                                                                                      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 still in effect    Geological data,        2 years after the       These release times apply
 and within the primary term          Analyzed geological     required submittal      only if the provisions in
 specified in the lease.              information.            date or 60 days after   this table governing high-
                                                              a lease sale if any     resolution systems and the
                                                              portion of an offered   provisions in Sec.  252.7
                                                              lease is within 50      do not apply. If the
                                                              miles of a well,        primary term specified in
                                                              whichever is later.     the lease is extended
                                                                                      under the heading of
                                                                                      ``Suspensions'' in this
                                                                                      subpart, the extension
                                                                                      applies to this provision.
(6) Your lease is in effect and      Geological data,        2 years after the       None.
 beyond the primary term specified    Analyzed geological     required submittal
 in the lease.                        information.            date.
(7) Data or information is           Descriptions of         When the well goes on   Directional survey data may
 submitted on well operations.        downhole locations,     production or when      be released earlier to the
                                      operations, and         geological data is      owner of an adjacent lease
                                      equipment.              released according to   according to Subpart D of
                                                              Sec. Sec.             this part.
                                                              250.197(b)(5) and
                                                              (b)(6), whichever
                                                              occurs earlier.
(8) Data and information are         Any data or             At any time...........  None.
 obtained from beneath unleased       information obtained.
 land as a result of a well
 deviation that has not been
 approved by the District Manager
 or Regional Supervisor.
(9) Except for high-resolution data  G&G data, analyzed      Geological data and     None.
 and information released under       geological              information: 10 years
 paragraph (b)(2) of this section     information,            after MMS issues the
 data and information acquired by a   processed and           permit; Geophysical
 permit under part 251 are            interpreted G&G         data: 50 years after
 submitted by a lessee under 30 CFR   information.            MMS issues the
 part 203 or part 250.                                        permit; Geophysical
                                                              information: 25 years
                                                              after MMS issues the
                                                              permit.
----------------------------------------------------------------------------------------------------------------

    (c) MMS may allow limited inspection, but only by persons with a 
direct interest in related MMS 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 part 203 of this 
chapter that MMS 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) Make field determinations; or
    (7) Determine eligibility for royalty relief.

[64 FR 72775, Dec. 28, 1999, as amended at 71 FR 16039, Mar. 30, 2006. 
Redesignated and amended at 71 FR 23862, Apr. 25, 2006; 72 FR 25200, May 
4, 2007]

                               References



Sec. 250.198  Documents incorporated by reference.

    (a) The MMS 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

[[Page 87]]

by reference. The Director of the Federal Register has approved the 
incorporations by reference according to 5 U.S.C. 552(a) and 1 CFR part 
51.
    (1) Incorporation by reference of a document is limited to the 
edition of the publication that is cited in this section. Future 
amendments or revisions of the document are not included. The MMS will 
publish any changes to a document in the Federal Register and amend this 
section.
    (2) The MMS may make the rule amending the document effective 
without prior opportunity for public comment when MMS 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 MMS 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 section 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. If any incorporated document uses the word should, it 
means must for purposes of these regulations.
    (b) The MMS 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 MMS official.
    (d) You may inspect these documents at the Minerals Management 
Service, 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) and Commentary (ACI 318R-95), incorporated by 
reference at Sec. 250.901(a), (d).
    (2) ACI 357R-84, Guide for the Design and Construction of Fixed 
Offshore Concrete Structures, 1984; reapproved 1997, incorporated by 
reference at Sec. 250.901(a), (d).
    (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(a), (d).
    (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. 250.803(b)(1), (b)(1)(i); and Sec. 
250.1629(b)(1), (b)(1)(i);
    (2) ANSI/ASME Boiler and Pressure Vessel Code, Section IV, Rules for 
Construction of Heating Boilers; including

[[Page 88]]

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. 250.803(b)(1), (b)(1)(i); and 
Sec. 250.1629(b)(1), (b)(1)(i);
    (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. 
250.803(b)(1), (b)(1)(i); and Sec. 250.1629(b)(1), (b)(1)(i);
    (4) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings 
incorporated by reference at Sec. 250.1002(b)(2);
    (5) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping 
Systems incorporated by reference at Sec. 250.1002(a);
    (6) 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, incorporated by reference at 
Sec. 250.806(a)(2)(i);
    (7) ANSI Z88.2-1992, American National Standard for Respiratory 
Protection, incorporated by reference at, Sec. 250.490(g)(4)(iv), 
(j)(13)(ii).
    (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, Product No. C51009; incorporated by reference at Sec. 
250.803(b)(1); and Sec. 250.1629(b)(1);
    (2) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore 
Structures for Hurricane Conditions, May 2007, Product No. G2DGINT; 
incorporated by reference at Sec. 250.901(a), (d);
    (3) API Bulletin 2INT-EX, Interim Guidance for Assessment of 
Existing Offshore Structures for Hurricane Conditions, May 2007, Product 
No. G2EXINT; incorporated by reference at Sec. 250.901(a), (d);
    (4) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions 
in the Gulf of Mexico, May 2007, Product No. G2INTMET; incorporated by 
reference at Sec. 250.901(a), (d);
    (5) API MPMS, Chapter 1--Vocabulary, Second Edition, July 1994, 
Order No. 852-01002; 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, Order No. 852-022A1; incorporated by reference at Sec. 
250.1202(l)(4);
    (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, Order No. H30023; 
incorporated by reference at Sec. 250.1202(l)(4);
    (8) API MPMS, Chapter 3--Tank Gauging, Section 1A--Standard Practice 
for the Manual Gauging of Petroleum and Petroleum Products, Second 
Edition, August 2005, Product No. H301A02; incorporated by reference at 
Sec. 250.1202(l)(4);
    (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, Product No. H301B2; incorporated by reference at Sec. 
250.1202(l)(4);
    (10) API MPMS, Chapter 4--Proving Systems, Section 1--Introduction, 
Third Edition, February 2005, Product No. H04013; incorporated by 
reference at Sec. 250.1202(a)(3), (f)(1);
    (11) API MPMS, Chapter 4--Proving Systems, Section 2--Displacement 
Provers, Third Edition, September 2003, Product No. H04023; incorporated 
by reference at Sec. 250.1202(a)(3), (f)(1);
    (12) API MPMS, Chapter 4--Proving Systems, Section 4--Tank Provers, 
Second Edition, May 1998, reaffirmed November 2005, Order No. H04042; 
incorporated by reference at Sec. 250.1202(a)(3), (f)(1);
    (13) API MPMS, Chapter 4--Proving Systems, Section 5--Master-Meter

[[Page 89]]

Provers, Second Edition, May 2000, reaffirmed: August 2005, Order No. 
H04052; incorporated by reference at Sec. 250.1202(a)(3), (f)(1);
    (14) API MPMS, Chapter 4--Proving Systems, Section 6--Pulse 
Interpolation, Second Edition, May 1999; reaffirmed 2003, Order No. 
H04062; incorporated by reference at Sec. 250.1202(a)(3), (f)(1);
    (15) API MPMS, Chapter 4--Proving Systems, Section 7--Field Standard 
Test Measures, Second Edition, December 1998; reaffirmed 2003, Order No. 
H04072; incorporated by reference at Sec. 250.1202(a)(3), (f)(1);
    (16) API MPMS, Chapter 5--Metering, Section 1--General 
Considerations for Measurement by Meters, Fourth Edition, September 
2005, Product No. H05014; incorporated by reference at Sec. 
250.1202(a)(3);
    (17) API MPMS, Chapter 5--Metering, Section 2--Measurement of Liquid 
Hydrocarbons by Displacement Meters, Third Edition, September 2005, 
Product No. H05023; incorporated by reference at Sec. 250.1202(a)(3);
    (18) API MPMS Chapter 5--Metering, Section 3--Measurement of Liquid 
Hydrocarbons by Turbine Meters, Fifth Edition, September 2005, Product 
No. H05035; incorporated by reference at Sec. 250.1202(a)(3);
    (19) API MPMS, Chapter 5--Metering, Section 4--Accessory Equipment 
for Liquid Meters, Fourth Edition, September 2005, Product No. H05044; 
incorporated by reference at Sec. 250.1202(a)(3);
    (20) API MPMS, Chapter 5--Metering, Section 5--Fidelity and Security 
of Flow Measurement Pulsed-Data Transmission Systems, Second Edition, 
August 2005, Product No. H50502; incorporated by reference at Sec. 
250.1202(a)(3);
    (21) API MPMS, Chapter 6--Metering Assemblies, Section 1--Lease 
Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991; 
reaffirmed, April 2007, Order No. H30121; incorporated by reference at 
Sec. 250.1202(a)(3);
    (22) API MPMS, Chapter 6--Metering Assemblies, Section 6--Pipeline 
Metering Systems, Second Edition, May 1991; reaffirmed, February 2007, 
Order No. 852-30126; incorporated by reference at Sec. 250.1202(a)(3);
    (23) API MPMS, Chapter 6--Metering Assemblies, Section 7--Metering 
Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed, April 2007, 
Order No. 852-30127; incorporated by reference at Sec. 250.1202(a)(3);
    (24) API MPMS, Chapter 7--Temperature Determination, First Edition, 
June 2001; reaffirmed, March 2007; Product No. H07001; incorporated by 
reference at Sec. 250.1202(a)(3), (l)(4);
    (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, Order No. H08013; incorporated by 
reference at Sec. 250.1202(b)(4)(i), (l)(4);
    (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, Order No. H08022; 
incorporated by reference at Sec. 250.1202(a)(3), (l)(4);
    (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, Product 
No. H09012; incorporated by reference at Sec. 250.1202(a)(3), (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, Product No. H09022; 
incorporated by reference at Sec. 250.1202(a)(3), (l)(4);
    (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, Product No. H10013; incorporated 
by reference at Sec. 250.1202(a)(3), (l)(4);
    (30) API MPMS, Chapter 10--Sediment and Water, Section 2--Standard 
Test Method for Water in Crude Oil by Distillation, Second Edition, 
November 2007, Product No. H10022; incorporated by reference at Sec. 
250.1202(a)(3), (l)(4);
    (31) API MPMS, Chapter 10--Sediment and Water, Section 3--Standard 
Test Method for Water and Sediment in

[[Page 90]]

Crude Oil by the Centrifuge Method (Laboratory Procedure), Third 
Edition, May 2008, Product No. H10033; incorporated by reference at 
Sec. 250.1202(a)(3), (l)(4);
    (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, Order No. 
H10043; incorporated by reference at Sec. 250.1202(a)(3), (l)(4);
    (33) API MPMS, Chapter 10--Sediment and Water, Section 9--Standard 
Test Method for Water in Crude Oils by Coulometric Karl Fischer 
Titration, Second Edition, December 2002; reaffirmed 2005, Product No. 
H10092; incorporated by reference at Sec. 250.1202(a)(3), (l)(4);
    (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, API Stock No. H27000; incorporated by reference at Sec. 
250.1202(a)(3), (g)(3), (l)(4);
    (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, Order No. 852-27307; incorporated by 
reference at Sec. 250.1202(a)(3), (g)(4);
    (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, Order No. H27308; incorporated 
by reference at Sec. 250.1202(a)(3);
    (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, Order No. H12021; incorporated 
by reference at Sec. 250.1202(a)(3), (g)(1), (g)(2);
    (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, Product No. H12223; incorporated by reference 
at Sec. 250.1202(a)(3), (g)(1), (g)(2);
    (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, Order No. 852-30350; incorporated by reference at Sec. 
250.1203(b)(2);
    (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, Order No. H14324; incorporated by reference at Sec. 
250.1203(b)(2);
    (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, Product No. H143303; incorporated by reference at Sec. 
250.1203(b)(2);
    (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; Adopted as Tentative Standard, 
1972; Revised and Adopted as Standard, 1976; Revised 1984, 1986, 1996, 
2009; Product No. H140503; incorporated by reference at Sec. 
250.1203(b)(2);
    (43) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
6--Continuous Density Measurement, Second Edition, April 1991; 
reaffirmed, February 2006, Order No. H30346; incorporated by reference 
at Sec. 250.1203(b)(2);
    (44) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
8--Liquefied Petroleum Gas Measurement, Second Edition, July 1997; 
reaffirmed, March 2006, Order No. H14082; incorporated by reference at 
Sec. 250.1203(b)(2);

[[Page 91]]

    (45) API MPMS, Chapter 20--Section 1--Allocation Measurement, First 
Edition, September 1993; reaffirmed October 2006, Order No. 852-30701; 
incorporated by reference at Sec. 250.1202(k)(1);
    (46) API MPMS, Chapter 21--Flow Measurement Using Electronic 
Metering Systems, Section 1--Electronic Gas Measurement, First Edition, 
August 1993; reaffirmed, July 2005, Order No. 852-30730; incorporated by 
reference at Sec. 250.1203(b)(4);
    (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; Product No. G2AWSD; incorporated by reference at Sec. 
250.901(a), (d); Sec. 250.908(a); Sec. 250.919(b)(2); Sec. 
250.920(a), (b), (c), (d), (e), (f);
    (48) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth 
Edition, May 2007, Product No. G02D06; incorporated by reference at 
Sec. 250.108(a);
    (49) API RP 2FPS, RP for Planning, Designing, and Constructing 
Floating Production Systems; First Edition, March 2001, Order No. 
G2FPS1; incorporated by reference at Sec. 250.901(a), (d);
    (50) API RP 2I, In-Service Inspection of Mooring Hardware for 
Floating Structures; Third Edition, April 2008, Product No. G02I03; 
incorporated by reference at Sec. 250.901(a), (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; Order 
No. G02RD1; incorporated by reference at Sec. 250.800(b)(2); Sec. 
250.901(a), (d); Sec. 250.1002(b)(5);
    (52) API RP 2SK, Design and Analysis of Stationkeeping Systems for 
Floating Structures, Third Edition, October 2005, Addendum, May 2008, 
Product No. G2SK03; incorporated by reference at Sec. 250.800(b)(3); 
Sec. 250.901(a), (d);
    (53) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, First Edition, March 2001, Addendum, May 2007, Product No. 
G02SM1; incorporated by reference at Sec. 250.901(a), (d);
    (54) API RP 2T, Recommended Practice for Planning, Designing, and 
Constructing Tension Leg Platforms, Second Edition, August 1997, Order 
No. G02T02; incorporated by reference at Sec. 250.901(a), (d);
    (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, Product No. GX14B05; incorporated 
by reference at Sec. 250.801(e)(4); Sec. 250.804(a)(1)(i);
    (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; Product No. C14C07; incorporated by reference at Sec. 250.125(a); 
Sec. 250.292(j); Sec. 250.802(b), (e)(2); Sec. 250.803(a), (b)(2)(i), 
(b)(4), (b)(5)(i), (b)(7), (b)(9)(v), (c)(2); Sec. 250.804(a), (a)(6); 
Sec. 250.1002(d); Sec. 250.1004(b)(9); Sec. 250.1628(c), (d)(2); 
Sec. 250.1629(b)(2), (b)(4)(v); Sec. 250.1630(a);
    (57) API RP 14E, Recommended Practice for Design and Installation of 
Offshore Production Platform Piping Systems, Fifth Edition, October 
1991; reaffirmed, March 2007, Order No. 811-07185; incorporated by 
reference at Sec. 250.802(e)(3); Sec. 250.1628(b)(2), (d)(3);
    (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, Product No. G14F05; incorporated by reference at 
Sec. 250.114(c); Sec. 250.803(b)(9)(v); Sec. 250.1629(b)(4)(v);
    (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; 
Product No. G14FZ1; incorporated by reference at Sec. 250.114(c); Sec. 
250.803(b)(9)(v); Sec. 250.1629(b)(4)(v);

[[Page 92]]

    (60) API RP 14G, Recommended Practice for Fire Prevention and 
Control on Fixed Open-type Offshore Production Platforms, Fourth 
Edition, April 2007; Product No. G14G04; incorporated by reference at 
Sec. 250.803(b)(8), (b)(9)(v); Sec. 250.1629(b)(3), (b)(4)(v);
    (61) API RP 14H, Recommended Practice for Installation, Maintenance 
and Repair of Surface Safety Valves and Underwater Safety Valves 
Offshore, Fifth Edition, August 2007, Product No. G14H05; incorporated 
by reference at Sec. 250.802(d); Sec. 250.804(a)(5);
    (62) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, Second Edition, May 2001; 
reaffirmed: March 2007; Product No. G14J02; incorporated by reference at 
Sec. 250.800(b)(1); Sec. 250.901(a)(14);
    (63) API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells, Third Edition, March 1997; 
reaffirmed September 2004, Order No. G53003; incorporated by reference 
at Sec. 250.442(c); Sec. 250.446(a); Sec. 250.516(g)(1); Sec. 
250.516(h); and Sec. 250.617(a)(1), and (b);
    (64) API RP 65, Recommended Practice for Cementing Shallow Water 
Flow Zones in Deepwater Wells, First Edition, September 2002, Product 
No. G56001; incorporated by reference at Sec. 250.415(e);
    (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, Product No. C50002; 
incorporated by reference at Sec. 250.114(a); Sec. 250.459; Sec. 
250.802(e)(4)(i); Sec. 250.803(b)(9)(i); Sec. 250.1628(b)(3), 
(d)(4)(i); Sec. 250.1629(b)(4)(i);
    (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, Order No. C50501; incorporated 
by reference at Sec. 250.114(a); Sec. 250.459; Sec. 250.802(e)(4)(i); 
Sec. 250.803(b)(9)(i); Sec. 250.1628(b)(3), (d)(4)(i); Sec. 
250.1629(b)(4)(i);
    (67) API RP 2556, Recommended Practice for Correcting Gauge Tables 
for Incrustation, Second Edition, August 1993; reaffirmed November 2003, 
Order No. H25560; incorporated by reference at Sec. 250.1202(l)(4);
    (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, Product No. GXQ108; incorporated by reference at Sec. 
250.806(a)(2)(ii);
    (69) API Spec. 2C, Specification for Offshore Pedestal Mounted 
Cranes, Sixth Edition, March 2004, Effective Date: September 2004, 
Product No. G02C06; incorporated by reference at Sec. 250.108(c), (d);
    (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; Product No. GX06A19; 
incorporated by reference at Sec. 250.806(a)(3); Sec. 250.1002(b)(1), 
(b)(2);
    (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, Order No. 
G06AV1; incorporated by reference at Sec. 250.806(a)(3);
    (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; Product 
No. GX6D23; incorporated by reference at Sec. 250.1002(b)(1);

[[Page 93]]

    (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, Product No. GX14A11; incorporated by 
reference at Sec. 250.806(a)(3);
    (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; Product No. GX17J03; incorporated by 
reference at Sec. 250.803(b)(2)(iii); Sec. 250.1002(b)(4); Sec. 
250.1007(a)(4);
    (75) API Standard 2551, Measurement and Calibration of Horizontal 
Tanks, First Edition, 1965; reaffirmed March 2002, API Stock No. H25510; 
incorporated by reference at Sec. 250.1202(l)(4);
    (76) API Standard 2552, USA Standard Method for Measurement and 
Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed, 
October 2007 (ASTM designation: D 1408-65; date of joint API/ASTM 
approval, 1965); incorporated by reference at Sec. 250.1202(l)(4);
    (77) API Standard 2555, Method for Liquid Calibration of Tanks, 
First Edition, September 1966; reaffirmed March 2002; Order No. 852-
25550; incorporated by reference at Sec. 250.1202(l)(4).
    (78) API RP 90, Annular Casing Pressure Management for Offshore 
Wells, First Edition, August 2006, Product No. G09001, incorporated by 
reference at Sec. 250.518.
    (79) API RP 65-Part 2, Isolating Potential Flow Zones During Well 
Construction; First Edition, May 2010; Product No. G65201; incorporated 
by reference at Sec. 250.415(f).
    (80) 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, Product No. G07503; 
incorporated by reference at Sec. Sec. 250.1900, 250.1900(c), 
250.1902(c), 250.1903, 250.1909, 250.1920(a) and (b).
    (i) American Society for Testing and Materials (ASTM), ASTM 
Standards, 100 Bar Harbor Drive, P. O. Box C700, West Conshohocken, PA 
19428-2959; http://www.astm.org; phone: 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(a), (d);
    (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(a), (d);
    (3) ASTM Standard C 150-07, approved May 1, 2007, Standard 
Specification for Portland Cement; incorporated by reference at Sec. 
250.901(a), (d);
    (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(a), (d);
    (5) ASTM Standard C 595-08, approved January 1, 2008, Standard 
Specification for Blended Hydraulic Cements; incorporated by reference 
at Sec. 250.901(a), (d);
    (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; incorporated by 
reference at Sec. 250.901(a), (d);
    (2) AWS D1.4-98, Structural Welding Code--Reinforcing Steel; 
incorporated by reference at Sec. 250.901(a), (d);
    (3) AWS D3.6M:1999, Specification for Underwater Welding; 
incorporated by reference at Sec. 250.901(a), (d).
    (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, Item No. 21302, Standard Material 
Requirements, Metals for Sulfide Stress Cracking and Stress Corrosion 
Cracking Resistance in Sour Oilfield Environments; incorporated by 
reference at Sec. 250.901(a), Sec. 250.490(p)(2);
    (2) NACE Standard RP0176-2003, Item No. 21018, Standard Recommended 
Practice, Corrosion Control of Steel Fixed Offshore Structures 
Associated with Petroleum Production; incorporated by reference at Sec. 
250.901(a), (d).

[75 FR 22222, Apr. 28, 2010, as amended at 75 FR 23584, May 4, 2010; 75 
FR 63372, Oct. 14, 2010; 75 FR 63649, Oct. 15, 2010]

[[Page 94]]



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 MMS uses the information. The 
associated MMS 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; parts 251 and 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, Minerals 
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 
20240.
    (e) MMS is collecting this information for the reasons given in the 
following table:

------------------------------------------------------------------------
 30 CFR subpart, title and/or MMS Form        Reasons for collecting
           (OMB Control No.)                 information and how used
------------------------------------------------------------------------
(1) Subpart A, General (1010-0114),      To inform MMS of actions taken
 including Forms MMS-132, Evacuation      to comply with general
 Statistics; MMS-143, Facility/           operational requirements on
 Equipment Damage Report; MMS-1123,       the OCS. To ensure that
 Designation of Operator; MMS-1832,       operations on the OCS meet
 Notification of Incidents of             statutory and regulatory
 Noncompliance.                           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 MMS 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 MMS, States, and the
 Development and Production Plans (1010-  public of planned exploration,
 0151), including Forms MMS-137, OCS      development, and production
 Plan Information Form; MMS-139, EP Air   operations on the OCS. To
 Quality Screening Checklist; MMS-138,    ensure that operations on the
 DOCD Air Quality Screening Checklist,    OCS are planned to comply with
 MMS-141, ROV Survey Report Form; MMS-    statutory and regulatory
 142, Environmental Impact Analysis       requirements, will be safe and
 Worksheet.                               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 MMS of measures to be
 Control (1010-0057).                     taken to prevent water and air
                                          pollution. To ensure that
                                          appropriate measures are taken
                                          to prevent water and air
                                          pollution.
(4) Subpart D, Oil and Gas and Drilling  To inform MMS of the equipment
 Operations (1010-0141), including        and procedures to be used in
 Forms MMS-123, Application for Permit    drilling operations on the
 to Drill; MMS-123S, Supplemental APD     OCS. To ensure that drilling
 Information Sheet; MMS-124,              operations are safe and
 Application for Permit to Modify; MMS-   protect the human, marine, and
 125, End of Operations Report; MMS-      coastal environment.
 133, Well Activity Report; MMS-133S,
 Open Hole Data Report.
(5) Subpart E, Oil and Gas Well-         To inform MMS 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 MMS 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 MMS 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 MMS with information
 (1010-0149).                             regarding the design,
                                          fabrication, and installation
                                          of platforms on the OCS. To
                                          ensure the structural
                                          integrity of platforms
                                          installed on the OCS.

[[Page 95]]

 
(9) Subpart J, Pipelines and Pipeline    To provide MMS with information
 Rights-of-Way (1010-0050).               regarding the design,
                                          installation, and 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 MMS of production
 Rates (1010-0041), including Forms MMS-  rates for hydrocarbons
 126, Well Potential Test Report; MMS-    produced on the OCS. To ensure
 127, Sensitive Reservoir Information     economic maximization of
 Report; MMS-128, Semiannual Well Test    ultimate hydrocarbon recovery.
 Report; MMS-140 Bottomhole Pressure
 Survey Report.
(11) Subpart L, Oil and Gas Production   To inform MMS 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 MMS 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 MMS 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 MMS 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.
(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 MMS-131,           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.
(18) Form MMS-144, Rig Movement          The rig notification
 Notification Report (form used in the    requirement is essential for
 GOM OCS Region), Subparts D, E, F,       MMS inspection scheduling and
 (1010-0150).                             to verify that the equipment
                                          being used complies with
                                          approved permits.
------------------------------------------------------------------------


[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 35405, May 17, 2002; 68 
FR 8422, Feb. 20, 2003; 71 FR 23863, Apr. 25, 2006; 72 FR 25200, May 4, 
2007; 73 FR 64546, Oct. 30, 2008; 74 FR 46908, Sept. 14, 2009; 75 FR 
20289, Apr. 19, 2010; 75 FR 63649, Oct. 15, 2010]



                     Subpart B_Plans and Information

    Source: 70 FR 51501, Aug. 30, 2005, unless otherwise noted.

                           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:
    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
    MMS means Minerals Management Service
    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:

[[Page 96]]

    Amendment means a change you make to an EP, DPP, or DOCD that is 
pending before MMS for a decision (see Sec. Sec. 250.232(d) and 
250.267(d)).
    Modification means a change required by the Regional Supervisor to 
an EP, DPP, or DOCD (see Sec. 250.233(b)(2) and Sec. 250.270(b)(2)) 
that is pending before MMS 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 an MMS 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 MMS has disapproved (see Sec. Sec. 
250.234(b), 250.272(a), and 250.273(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 Sec. 250.283(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 Sec. 250.283(b)).



Sec. 250.201  What plans and information must I submit before I conduct any 

activities on my lease or unit?

    (a) Plans and documents. Before you conduct the activities on your 
lease or unit listed in the following table, you must submit, and MMS 
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) Exploration Plan (EP)....  Conduct any exploration activities on a
                                lease or unit.
(2) Development and            Conduct any development and production
 Production Plan (DPP).         activities on a lease or unit in any OCS
                                area other than the Western Gulf of
                                Mexico.
(3) Development Operations     Conduct any development and production
 Coordination Document (DOCD).  activities on a lease or unit in the
                                Western GOM.
(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) Conservation Information   Commence production from development
 Document (CID).                projects in water depths greater than
                                1,312 feet (400 meters).
(6) EP, DPP, or DOCD.........  Conduct geological or geophysical (G&G)
                                exploration or a development G&G
                                activity (see definitions under Sec.
                                250.105) on your lease or unit when:
                               (i) It will result in a physical
                                penetration of the seabed greater than
                                500 feet (152 meters);
                               (ii) It will involve the use of
                                explosives;
                               (iii) The Regional Director determines
                                that it might have a significant adverse
                                effect on the human, marine, or coastal
                                environment; or
                               (iv) The Regional Supervisor, after
                                reviewing a notice under Sec.  250.209,
                                determines that an EP, DPP, or DOCD is
                                necessary.
------------------------------------------------------------------------

    (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:

[[Page 97]]

    (1) Sufficient applicable information or analysis is readily 
available to MMS;
    (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 MMS.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]



Sec. 250.202  What criteria must the Exploration Plan (EP), Development and Production

Plan (DPP), or Development Operations Coordination Document (DOCD) meet?

    Your EP, DPP, or DOCD must demonstrate that you have planned and are 
prepared to conduct the proposed activities in a manner that:
    (a) Conforms to the Outer Continental Shelf Lands Act as amended 
(Act), applicable implementing regulations, lease provisions and 
stipulations, and other Federal laws;
    (b) Is safe;
    (c) Conforms to sound conservation practices and protects the rights 
of the lessor;
    (d) Does not unreasonably interfere with other uses of the OCS, 
including those involved with national security or defense; and
    (e) Does not cause undue or serious harm or damage to the human, 
marine, or coastal environment.



Sec. 250.203  Where can wells be located under an EP, DPP, or DOCD?

    The Regional Supervisor reviews and approves proposed well location 
and spacing under an EP, DPP, or DOCD. In deciding whether to approve a 
proposed well location and spacing, the Regional Supervisor will 
consider factors including, but not limited to, the following:
    (a) Protecting correlative rights;
    (b) Protecting Federal royalty interests;
    (c) Recovering optimum resources;
    (d) Number of wells that can be economically drilled for proper 
reservoir management;
    (e) Location of drilling units and platforms;
    (f) Extent and thickness of the reservoir;
    (g) Geologic and other reservoir characteristics;
    (h) Minimizing environmental risk;
    (i) Preventing unreasonable interference with other uses of the OCS; 
and
    (j) Drilling of unnecessary wells.



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.



Sec. 250.206  How do I submit the EP, DPP, or DOCD?

    (a) Number of copies. When you submit an EP, DPP, or DOCD to MMS, 
you must provide:

[[Page 98]]

    (1) Four copies that contain all required information (proprietary 
copies);
    (2) Eight copies for public distribution (public information copies) 
that omit information that you assert is exempt from disclosure under 
the Freedom of Information Act (FOIA) (5 U.S.C. 552) and the 
implementing regulations (43 CFR part 2); and
    (3) Any additional copies that may be necessary to facilitate review 
of the EP, DPP, or DOCD by certain affected States and other reviewing 
entities.
    (b) Electronic submission. You may submit part or all of your EP, 
DPP, or DOCD and its accompanying information electronically. If you 
prefer to submit your EP, DPP, or DOCD electronically, ask the Regional 
Supervisor for further guidance.
    (c) Withdrawal after submission. You may withdraw your proposed EP, 
DPP, or DOCD at any time for any reason. Notify the appropriate MMS OCS 
Region if you do.

                          Ancillary Activities



Sec. 250.207  What ancillary activities may I conduct?

    Before or after you submit an EP, DPP, or DOCD to MMS, you may 
elect, the regulations in this part may require, or the Regional 
Supervisor may direct you to conduct ancillary activities. Ancillary 
activities include:
    (a) Geological and geophysical (G&G) explorations and development 
G&G activities;
    (b) Geological and high-resolution geophysical, geotechnical, 
archaeological, biological, physical oceanographic, meteorological, 
socioeconomic, or other surveys; or
    (c) Studies that model potential oil and hazardous substance spills, 
drilling muds and cuttings discharges, projected air emissions, or 
potential hydrogen sulfide (H2S) releases.



Sec. 250.208  If I conduct ancillary activities, what notices must I provide?

    At least 30 calendar days before you conduct any G&G exploration or 
development G&G activity (see Sec. 250.207(a)), you must notify the 
Regional Supervisor in writing.
    (a) When you prepare the notice, you must:
    (1) Sign and date the notice;
    (2) Provide the names of the vessel, its operator, and the person(s) 
in charge; the specific type(s) of operations you will conduct; and the 
instrumentation/techniques and vessel navigation system you will use;
    (3) Provide expected start and completion dates and the location of 
the activity; and
    (4) Describe the potential adverse environmental effects of the 
proposed activity and any mitigation to eliminate or minimize these 
effects on the marine, coastal, and human environment.
    (b) The Regional Supervisor may require you to:
    (1) Give written notice to MMS at least 15 calendar days before you 
conduct any other ancillary activity (see Sec. 250.207(b) and (c)) in 
addition to those listed in Sec. 250.207(a); and
    (2) Notify other users of the OCS before you conduct any ancillary 
activity.



Sec. 250.209  What is the MMS review process for the notice?

    The Regional Supervisor will review any notice required under Sec. 
250.208(a) and (b)(1) to ensure that your ancillary activity complies 
with the performance standards listed in Sec. 250.202(a), (b), (d), and 
(e). The Regional Supervisor may notify you that your ancillary activity 
does not comply with those standards. In such a case, the Regional 
Supervisor will require you to submit an EP, DPP, or DOCD and you may 
not start your ancillary activity until the Regional Supervisor approves 
the EP, DPP, or DOCD.



Sec. 250.210  If I conduct ancillary activities, what reporting and 

data/information retention requirements must I satisfy?

    (a) Reporting. The Regional Supervisor may require you to prepare 
and submit reports that summarize and analyze data or information 
obtained or derived from your ancillary activities. When applicable, MMS 
will protect and disclose the data and information in these reports in 
accordance with Sec. 250.197(b).

[[Page 99]]

    (b) Data and information retention. You must retain copies of all 
original data and information, including navigation data, obtained or 
derived from your G&G explorations and development G&G activities (see 
Sec. 250.207(a)), including any such data and information you obtained 
from previous leaseholders or unit operators. You must submit such data 
and information to MMS for inspection and possible retention upon 
request at any time before lease or unit termination. When applicable, 
MMS will protect and disclose such submitted data and information in 
accordance with Sec. 250.197(b).

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]

                   Contents of Exploration Plans (EP)



Sec. 250.211  What must the EP include?

    Your EP must include the following:
    (a) Description, objectives, and schedule. A description, discussion 
of the objectives, and tentative schedule (from start to completion) of 
the exploration activities that you propose to undertake. Examples of 
exploration activities include exploration drilling, well test flaring, 
installing a well protection structure, and temporary well abandonment.
    (b) Location. A map showing the surface location and water depth of 
each proposed well and the locations of all associated drilling unit 
anchors.
    (c) Drilling unit. A description of the drilling unit and associated 
equipment you will use to conduct your proposed exploration activities, 
including a brief description of its important safety and pollution 
prevention features, and a table indicating the type and the estimated 
maximum quantity of fuels, oil, and lubricants that will be stored on 
the facility (see third definition of ``facility'' under Sec. 250.105).
    (d) Service fee. You must include payment of the service fee listed 
in Sec. 250.125.

[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.212  What information must accompany the EP?

    The following information must accompany your EP:
    (a) General information required by Sec. 250.213;
    (b) Geological and geophysical (G&G) information required by Sec. 
250.214;
    (c) Hydrogen sulfide information required by Sec. 250.215;
    (d) Biological, physical, and socioeconomic information required by 
Sec. 250.216;
    (e) Solid and liquid wastes and discharges information and cooling 
water intake information required by Sec. 250.217;
    (f) Air emissions information required by Sec. 250.218;
    (g) Oil and hazardous substance spills information required by Sec. 
250.219;
    (h) Alaska planning information required by Sec. 250.220;
    (i) Environmental monitoring information required by Sec. 250.221;
    (j) Lease stipulations information required by Sec. 250.222;
    (k) Mitigation measures information required by Sec. 250.223;
    (l) Support vessels and aircraft information required by Sec. 
250.224;
    (m) Onshore support facilities information required by Sec. 
250.225;
    (n) Coastal zone management information required by Sec. 250.226;
    (o) Environmental impact analysis information required by Sec. 
250.227; and
    (p) Administrative information required by Sec. 250.228.



Sec. 250.213  What general information must accompany the EP?

    The following general information must accompany your EP:
    (a) Applications and permits. A listing, including filing or 
approval status, of the Federal, State, and local application approvals 
or permits you must obtain to conduct your proposed exploration 
activities.
    (b) Drilling fluids. A table showing the projected amount, discharge 
rate, and chemical constituents for each type (i.e., water-based, oil-
based, synthetic-based) of drilling fluid you plan to use to drill your 
proposed exploration wells.
    (c) Chemical products. A table showing the name and brief 
description, quantities to be stored, storage method, and rates of usage 
of the chemical products you will use to conduct your proposed 
exploration activities. List only those

[[Page 100]]

chemical products you will store or use in quantities greater than the 
amounts defined as Reportable Quantities in 40 CFR part 302, or amounts 
specified by the Regional Supervisor.
    (d) New or unusual technology. A description and discussion of any 
new or unusual technology (see definition under Sec. 250.200) you will 
use to carry out your proposed exploration activities. In the public 
information copies of your EP, you may exclude any proprietary 
information from this description. In that case, include a brief 
discussion of the general subject matter of the omitted information. If 
you will not use any new or unusual technology to carry out your 
proposed exploration activities, include a statement so indicating.
    (e) Bonds, oil spill financial responsibility, and well control 
statements. Statements attesting that:
    (1) The activities and facilities proposed in your EP are or will be 
covered by an appropriate bond under 30 CFR part 256, subpart I;
    (2) You have demonstrated or will demonstrate oil spill financial 
responsibility for facilities proposed in your EP according to 30 CFR 
part 253; and
    (3) You have or will have the financial capability to drill a relief 
well and conduct other emergency well control operations.
    (f) Suspensions of operations. A brief discussion of any suspensions 
of operations that you anticipate may be necessary in the course of 
conducting your activities under the EP.
    (g) Blowout scenario. A scenario for the potential blowout of the 
proposed well in your EP that you expect will have the highest volume of 
liquid hydrocarbons. Include the estimated flow rate, total volume, and 
maximum duration of the potential blowout. Also, discuss the potential 
for the well to bridge over, the likelihood for surface intervention to 
stop the blowout, the availability of a rig to drill a relief well, and 
rig package constraints. Estimate the time it would take to drill a 
relief well.
    (h) Contact. The name, address (e-mail address, if available), and 
telephone number of the person with whom the Regional Supervisor and any 
affected State(s) can communicate about your EP.



Sec. 250.214  What geological and geophysical (G&G) information must accompany the EP?

    The following G&G information must accompany your EP:
    (a) Geological description. A geological description of the 
prospect(s).
    (b) Structure contour maps. Current structure contour maps (depth-
based, expressed in feet subsea) drawn on the top of each prospective 
hydrocarbon-bearing reservoir showing the locations of proposed wells.
    (c) Two-dimensional (2-D) or three-dimensional (3-D) seismic lines. 
Copies of migrated and annotated 2-D or 3-D seismic lines (with depth 
scale) intersecting at or near your proposed well locations. You are not 
required to conduct both 2-D and 3-D seismic surveys if you choose to 
conduct only one type of survey. If you have conducted both types of 
surveys, the Regional Supervisor may instruct you to submit the results 
of both surveys. You must interpret and display this information. 
Because of its volume, provide this information as an enclosure to only 
one proprietary copy of your EP.
    (d) Geological cross-sections. Interpreted geological cross-sections 
showing the location and depth of each proposed well.
    (e) Shallow hazards report. A shallow hazards report based on 
information obtained from a high-resolution geophysical survey, or a 
reference to such report if you have already submitted it to the 
Regional Supervisor.
    (f) Shallow hazards assessment. For each proposed well, an 
assessment of any seafloor and subsurface geological and manmade 
features and conditions that may adversely affect your proposed drilling 
operations.
    (g) High-resolution seismic lines. A copy of the high-resolution 
survey line closest to each of your proposed well locations. Because of 
its volume, provide this information as an enclosure to only one 
proprietary copy of your EP. You are not required to provide this 
information if the surface location of your proposed well has been 
approved in a previously submitted EP, DPP, or DOCD.
    (h) Stratigraphic column. A generalized biostratigraphic/
lithostratigraphic

[[Page 101]]

column from the surface to the total depth of the prospect.
    (i) Time-versus-depth chart. A seismic travel time-versus-depth 
chart based on the appropriate velocity analysis in the area of 
interpretation and specifying the geodetic datum.
    (j) Geochemical information. A copy of any geochemical reports you 
used or generated.
    (k) Future G&G activities. A brief description of the types of G&G 
explorations and development G&G activities you may conduct for lease or 
unit purposes after your EP is approved.



Sec. 250.215  What hydrogen sulfide (H[bdi2]S) information must accompany the EP?

    The following H2S information, as applicable, must 
accompany your EP:
    (a) Concentration. The estimated concentration of any H2S 
you might encounter while you conduct your proposed exploration 
activities.
    (b) Classification. Under Sec. 250.490(c), a request that the 
Regional Supervisor classify the area of your proposed exploration 
activities as either H2S absent, H2S present, or 
H2S unknown. Provide sufficient information to justify your 
request.
    (c) H2S Contingency Plan. If you ask the Regional 
Supervisor to classify the area of your proposed exploration activities 
as either H2S present or H2S unknown, an 
H2S Contingency Plan prepared under Sec. 250.490(f), or a 
reference to an approved or submitted H2S Contingency Plan 
that covers the proposed exploration activities.
    (d) Modeling report. If you modeled a potential H2S 
release when developing your EP, modeling report or the modeling 
results, or a reference to such report or results if you have already 
submitted it to the Regional Supervisor.
    (1) The analysis in the modeling report must be specific to the 
particular site of your proposed exploration activities, and must 
consider any nearby human-occupied OCS facilities, shipping lanes, 
fishery areas, and other points where humans may be subject to potential 
exposure from an H2S release from your proposed exploration 
activities.
    (2) If any H2S emissions are projected to affect an 
onshore location in concentrations greater than 10 parts per million, 
the modeling analysis must be consistent with the Environmental 
Protection Agency's (EPA) risk management plan methodologies outlined in 
40 CFR part 68.



Sec. 250.216  What biological, physical, and socioeconomic information must accompany the EP?

    If you obtain the following information in developing your EP, or if 
the Regional Supervisor requires you to obtain it, you must include a 
report, or the information obtained, or a reference to such a report or 
information if you have already submitted it to the Regional Supervisor, 
as accompanying information:
    (a) Biological environment reports. Site-specific information on 
chemosynthetic communities, federally listed threatened or endangered 
species, marine mammals protected under the Marine Mammal Protection Act 
(MMPA), sensitive underwater features, marine sanctuaries, critical 
habitat designated under the Endangered Species Act (ESA), or other 
areas of biological concern.
    (b) Physical environment reports. Site-specific meteorological, 
physical oceanographic, geotechnical reports, or archaeological reports 
(if required under Sec. 250.194).
    (c) Socioeconomic study reports. Socioeconomic information regarding 
your proposed exploration activities.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18584, Apr. 13, 2007]



Sec. 250.217  What solid and liquid wastes and discharges

information and cooling water intake information must accompany the EP?

    The following solid and liquid wastes and discharges information and 
cooling water intake information must accompany your EP:
    (a) Projected wastes. A table providing the name, brief description, 
projected quantity, and composition of solid and liquid wastes (such as 
spent drilling fluids, drill cuttings, trash, sanitary and domestic 
wastes, and chemical product wastes) likely to be generated by your 
proposed exploration activities. Describe:

[[Page 102]]

    (1) The methods you used for determining this information; and
    (2) Your plans for treating, storing, and downhole disposal of these 
wastes at your drilling location(s).
    (b) Projected ocean discharges. If any of your solid and liquid 
wastes will be discharged overboard, or are planned discharges from 
manmade islands:
    (1) A table showing the name, projected amount, and rate of 
discharge for each waste type; and
    (2) A description of the discharge method (such as shunting through 
a downpipe, etc.) you will use.
    (c) National Pollutant Discharge Elimination System (NPDES) permit. 
(1) A discussion of how you will comply with the provisions of the 
applicable general NPDES permit that covers your proposed exploration 
activities; or
    (2) A copy of your application for an individual NPDES permit. 
Briefly describe the major discharges and methods you will use for 
compliance.
    (d) Modeling report. The modeling report or the modeling results (if 
you modeled the discharges of your projected solid or liquid wastes when 
developing your EP), or a reference to such report or results if you 
have already submitted it to the Regional Supervisor.
    (e) Projected cooling water intake. A table for each cooling water 
intake structure likely to be used by your proposed exploration 
activities that includes a brief description of the cooling water intake 
structure, daily water intake rate, water intake through screen 
velocity, percentage of water intake used for cooling water, mitigation 
measures for reducing impingement and entrainment of aquatic organisms, 
and biofouling prevention measures.



Sec. 250.218  What air emissions information must accompany the EP?

    The following air emissions information, as applicable, must 
accompany your EP:
    (a) Projected emissions. Tables showing the projected emissions of 
sulphur dioxide (SO2), particulate matter in the form of 
PM10 and PM2.5 when applicable, nitrogen oxides 
(NOX), carbon monoxide (CO), and volatile organic compounds 
(VOC) that will be generated by your proposed exploration activities.
    (1) For each source on or associated with the drilling unit 
(including well test flaring and well protection structure 
installation), you must list:
    (i) The projected peak hourly emissions;
    (ii) The total annual emissions in tons per year;
    (iii) Emissions over the duration of the proposed exploration 
activities;
    (iv) The frequency and duration of emissions; and
    (v) The total of all emissions listed in paragraphs (a)(1)(i) 
through (iv) of this section.
    (2) You must provide the basis for all calculations, including 
engine size and rating, and applicable operational information.
    (3) You must base the projected emissions on the maximum rated 
capacity of the equipment on the proposed drilling unit under its 
physical and operational design.
    (4) If the specific drilling unit has not yet been determined, you 
must use the maximum emission estimates for the type of drilling unit 
you will use.
    (b) Emission reduction measures. A description of any proposed 
emission reduction measures, including the affected source(s), the 
emission reduction control technologies or procedures, the quantity of 
reductions to be achieved, and any monitoring system you propose to use 
to measure emissions.
    (c) Processes, equipment, fuels, and combustibles. A description of 
processes, processing equipment, combustion equipment, fuels, and 
storage units. You must include the characteristics and the frequency, 
duration, and maximum burn rate of any well test fluids to be burned.
    (d) Distance to shore. Identification of the distance of your 
drilling unit from the mean high water mark (mean higher high water mark 
on the Pacific coast) of the adjacent State.
    (e) Non-exempt drilling units. A description of how you will comply 
with Sec. 250.303 when the projected emissions of SO2, PM, 
NOX, CO, or VOC, that will be generated by your proposed 
exploration activities, are greater than the respective emission 
exemption

[[Page 103]]

amounts ``E'' calculated using the formulas in Sec. 250.303(d). When 
MMS requires air quality modeling, you must use the guidelines in 
Appendix W of 40 CFR part 51 with a model approved by the Director. 
Submit the best available meteorological information and data consistent 
with the model(s) used.
    (f) Modeling report. A modeling report or the modeling results (if 
Sec. 250.303 requires you to use an approved air quality model to model 
projected air emissions in developing your EP), or a reference to such a 
report or results if you have already submitted it to the Regional 
Supervisor.



Sec. 250.219  What oil and hazardous substance spills information must accompany the EP?

    The following information regarding potential spills of oil (see 
definition under 30 CFR 254.6) and hazardous substances (see definition 
under 40 CFR part 116) as applicable, must accompany your EP:
    (a) Oil spill response planning. The material required under 
paragraph (a)(1) or (a)(2) of this section:
    (1) An Oil Spill Response Plan (OSRP) for the facilities you will 
use to conduct your exploration activities prepared according to the 
requirements of 30 CFR part 254, subpart B; or
    (2) Reference to your approved regional OSRP (see 30 CFR 254.3) to 
include:
    (i) A discussion of your regional OSRP;
    (ii) The location of your primary oil spill equipment base and 
staging area;
    (iii) The name(s) of your oil spill removal organization(s) for both 
equipment and personnel;
    (iv) The calculated volume of your worst case discharge scenario 
(see 30 CFR 254.26(a)), and a comparison of the appropriate worst case 
discharge scenario in your approved regional OSRP with the worst case 
discharge scenario that could result from your proposed exploration 
activities; and
    (v) A description of the worst case discharge scenario that could 
result from your proposed exploration activities (see 30 CFR 254.26(b), 
(c), (d), and (e)).
    (b) Modeling report. If you model a potential oil or hazardous 
substance spill in developing your EP, a modeling report or the modeling 
results, or a reference to such report or results if you have already 
submitted it to the Regional Supervisor.



Sec. 250.220  If I propose activities in the Alaska OCS Region, what 

planning information must accompany the EP?

    If you propose exploration activities in the Alaska OCS Region, the 
following planning information must accompany your EP:
    (a) Emergency plans. A description of your emergency plans to 
respond to a blowout, loss or disablement of a drilling unit, and loss 
of or damage to support craft.
    (b) Critical operations and curtailment procedures. Critical 
operations and curtailment procedures for your exploration activities. 
The procedures must identify ice conditions, weather, and other 
constraints under which the exploration activities will either be 
curtailed or not proceed.



Sec. 250.221  What environmental monitoring information must accompany the EP?

    The following environmental monitoring information, as applicable, 
must accompany your EP:
    (a) Monitoring systems. A description of any existing and planned 
monitoring systems that are measuring, or will measure, environmental 
conditions or will provide project-specific data or information on the 
impacts of your exploration activities.
    (b) Incidental takes. If there is reason to believe that protected 
species may be incidentally taken by planned exploration activities, you 
must describe how you will monitor for incidental take of:
    (1) Threatened and endangered species listed under the ESA and
    (2) Marine mammals, as appropriate, if you have not already received 
authorization for incidental take as may be necessary under the MMPA.
    (c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you 
propose to conduct exploration activities within the protective zones of 
the FGBNMS, a description of your provisions for monitoring the impacts 
of an

[[Page 104]]

oil spill on the environmentally sensitive resources at the FGBNMS.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18584, Apr. 13, 2007]



Sec. 250.222  What lease stipulations information must accompany the EP?

    A description of the measures you took, or will take, to satisfy the 
conditions of lease stipulations related to your proposed exploration 
activities must accompany your EP.



Sec. 250.223  What mitigation measures information must accompany the EP?

    (a) If you propose to use any measures beyond those required by the 
regulations in this part to minimize or mitigate environmental impacts 
from your proposed exploration activities, a description of the measures 
you will use must accompany your EP.
    (b) If there is reason to believe that protected species may be 
incidentally taken by planned exploration activities, you must include 
mitigation measures designed to avoid or minimize the incidental take 
of:
    (1) Threatened and endangered species listed under the ESA and
    (2) Marine mammals, as appropriate, if you have not already received 
authorization for incidental take as may be necessary under the MMPA.

[72 FR 18585, Apr. 13, 2007]



Sec. 250.224  What information on support vessels, offshore vehicles,

and aircraft you will use must accompany the EP?

    The following information on the support vessels, offshore vehicles, 
and aircraft you will use must accompany your EP:
    (a) General. A description of the crew boats, supply boats, anchor 
handling vessels, tug boats, barges, ice management vessels, other 
vessels, offshore vehicles, and aircraft you will use to support your 
exploration activities. The description of vessels and offshore vehicles 
must estimate the storage capacity of their fuel tanks and the frequency 
of their visits to your drilling unit.
    (b) Air emissions. A table showing the source, composition, 
frequency, and duration of the air emissions likely to be generated by 
the support vessels, offshore vehicles, and aircraft you will use that 
will operate within 25 miles of your drilling unit.
    (c) Drilling fluids and chemical products transportation. A 
description of the transportation method and quantities of drilling 
fluids and chemical products (see Sec. 250.213(b) and (c)) you will 
transport from the onshore support facilities you will use to your 
drilling unit.
    (d) Solid and liquid wastes transportation. A description of the 
transportation method and a brief description of the composition, 
quantities, and destination(s) of solid and liquid wastes (see Sec. 
250.217(a)) you will transport from your drilling unit.
    (e) Vicinity map. A map showing the location of your proposed 
exploration activities relative to the shoreline. The map must depict 
the primary route(s) the support vessels and aircraft will use when 
traveling between the onshore support facilities you will use and your 
drilling unit.



Sec. 250.225  What information on the onshore support facilities you will use must accompany the EP?

    The following information on the onshore support facilities you will 
use must accompany your EP:
    (a) General. A description of the onshore facilities you will use to 
provide supply and service support for your proposed exploration 
activities (e.g., service bases and mud company docks).
    (1) Indicate whether the onshore support facilities are existing, to 
be constructed, or to be expanded.
    (2) If the onshore support facilities are, or will be, located in 
areas not adjacent to the Western GOM, provide a timetable for acquiring 
lands (including rights-of-way and easements) and constructing or 
expanding the facilities. Describe any State or Federal permits or 
approvals (dredging, filling, etc.) that would be required for 
constructing or expanding them.
    (b) Air emissions. A description of the source, composition, 
frequency, and duration of the air emissions (attributable to your 
proposed exploration activities) likely to be generated by the onshore 
support facilities you will use.

[[Page 105]]

    (c) Unusual solid and liquid wastes. A description of the quantity, 
composition, and method of disposal of any unusual solid and liquid 
wastes (attributable to your proposed exploration activities) likely to 
be generated by the onshore support facilities you will use. Unusual 
wastes are those wastes not specifically addressed in the relevant 
National Pollution Discharge Elimination System (NPDES) permit.
    (d) Waste disposal. A description of the onshore facilities you will 
use to store and dispose of solid and liquid wastes generated by your 
proposed exploration activities (see Sec. 250.217) and the types and 
quantities of such wastes.



Sec. 250.226  What Coastal Zone Management Act (CZMA) information must accompany the EP?

    The following CZMA information must accompany your EP:
    (a) Consistency certification. A copy of your consistency 
certification under section 307(c)(3)(B) of the CZMA (16 U.S.C. 
1456(c)(3)(B)) and 15 CFR 930.76(d) stating that the proposed 
exploration activities described in detail in this EP comply with (name 
of State(s)) approved coastal management program(s) and will be 
conducted in a manner that is consistent with such program(s); and
    (b) Other information. ``Information'' as required by 15 CFR 
930.76(a) and 15 CFR 930.58(a)(2)) and ``Analysis'' as required by 15 
CFR 930.58(a)(3).



Sec. 250.227  What environmental impact analysis (EIA) information must accompany the EP?

    The following EIA information must accompany your EP:
    (a) General requirements. Your EIA must:
    (1) Assess the potential environmental impacts of your proposed 
exploration activities;
    (2) Be project specific; and
    (3) Be as detailed as necessary to assist the Regional Supervisor in 
complying with the National Environmental Policy Act (NEPA) of 1969 (42 
U.S.C. 4321 et seq.) and other relevant Federal laws such as the ESA and 
the MMPA.
    (b) Resources, conditions, and activities. Your EIA must describe 
those resources, conditions, and activities listed below that could be 
affected by your proposed exploration activities, or that could affect 
the construction and operation of facilities or structures, or the 
activities proposed in your EP.
    (1) Meteorology, oceanography, geology, and shallow geological or 
manmade hazards;
    (2) Air and water quality;
    (3) Benthic communities, marine mammals, sea turtles, coastal and 
marine birds, fish and shellfish, and plant life;
    (4) Threatened or endangered species and their critical habitat as 
defined by the Endangered Species Act of 1973;
    (5) Sensitive biological resources or habitats such as essential 
fish habitat, refuges, preserves, special management areas identified in 
coastal management programs, sanctuaries, rookeries, and calving 
grounds;
    (6) Archaeological resources;
    (7) Socioeconomic resources including employment, existing offshore 
and coastal infrastructure (including major sources of supplies, 
services, energy, and water), land use, subsistence resources and 
harvest practices, recreation, recreational and commercial fishing 
(including typical fishing seasons, location, and type), minority and 
lower income groups, and coastal zone management programs;
    (8) Coastal and marine uses such as military activities, shipping, 
and mineral exploration or development; and
    (9) Other resources, conditions, and activities identified by the 
Regional Supervisor.
    (c) Environmental impacts. Your EIA must:
    (1) Analyze the potential direct and indirect impacts (including 
those from accidents, cooling water intake structures, and those 
identified in relevant ESA biological opinions such as, but not limited 
to, those from noise, vessel collisions, and marine trash and debris) 
that your proposed exploration activities will have on the identified 
resources, conditions, and activities;
    (2) Analyze any potential cumulative impacts from other activities 
to those identified resources, conditions, and

[[Page 106]]

activities potentially impacted by your proposed exploration activities;
    (3) Describe the type, severity, and duration of these potential 
impacts and their biological, physical, and other consequences and 
implications;
    (4) Describe potential measures to minimize or mitigate these 
potential impacts; and
    (5) Summarize the information you incorporate by reference.
    (d) Consultation. Your EIA must include a list of agencies and 
persons with whom you consulted, or with whom you will be consulting, 
regarding potential impacts associated with your proposed exploration 
activities.
    (e) References cited. Your EIA must include a list of the references 
that you cite in the EIA.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.228  What administrative information must accompany the EP?

    The following administrative information must accompany your EP:
    (a) Exempted information description (public information copies 
only). A description of the general subject matter of the proprietary 
information that is included in the proprietary copies of your EP or its 
accompanying information.
    (b) Bibliography. (1) If you reference a previously submitted EP, 
DPP, DOCD, study report, survey report, or other material in your EP or 
its accompanying information, a list of the referenced material; and
    (2) The location(s) where the Regional Supervisor can inspect the 
cited referenced material if you have not submitted it.

                 Review and Decision Process for the EP



Sec. 250.231  After receiving the EP, what will MMS do?

    (a) Determine whether deemed submitted. Within 15 working days after 
receiving your proposed EP and its accompanying information, the 
Regional Supervisor will review your submission and deem your EP 
submitted if:
    (1) The submitted information, including the information that must 
accompany the EP (refer to the list in Sec. 250.212), fulfills 
requirements and is sufficiently accurate;
    (2) You have provided all needed additional information (see Sec. 
250.201(b)); and
    (3) You have provided the required number of copies (see Sec. 
250.206(a)).
    (b) Identify problems and deficiencies. If the Regional Supervisor 
determines that you have not met one or more of the conditions in 
paragraph (a) of this section, the Regional Supervisor will notify you 
of the problem or deficiency within 15 working days after the Regional 
Supervisor receives your EP and its accompanying information. The 
Regional Supervisor will not deem your EP submitted until you have 
corrected all problems or deficiencies identified in the notice.
    (c) Deemed submitted notification. The Regional Supervisor will 
notify you when the EP is deemed submitted.



Sec. 250.232  What actions will MMS take after the EP is deemed submitted?

    (a) State and CZMA consistency reviews. Within 2 working days after 
deeming your EP submitted under Sec. 250.231, the Regional Supervisor 
will use receipted mail or alternative method to send a public 
information copy of the EP and its accompanying information to the 
following:
    (1) The Governor of each affected State. The Governor has 21 
calendar days after receiving your deemed-submitted EP to submit 
comments. The Regional Supervisor will not consider comments received 
after the deadline.
    (2) The CZMA agency of each affected State. The CZMA consistency 
review period under section 307(c)(3)(B)(ii) of the CZMA (16 U.S.C. 
1456(c)(3)(B)(ii)) and 15 CFR 930.78 begins when the State's CZMA agency 
receives a copy of your deemed-submitted EP, consistency certification, 
and required necessary data and information (see 15 CFR 930.77(a)(1)).
    (b) MMS compliance review. The Regional Supervisor will review the 
exploration activities described in your proposed EP to ensure that they 
conform to the performance standards in Sec. 250.202.
    (c) MMS environmental impact evaluation. The Regional Supervisor 
will evaluate the environmental impacts of

[[Page 107]]

the activities described in your proposed EP and prepare environmental 
documentation under the National Environmental Policy Act (NEPA) (42 
U.S.C. 4321 et seq.) and the implementing regulations (40 CFR parts 1500 
through 1508).
    (d) Amendments. During the review of your proposed EP, the Regional 
Supervisor may require you, or you may elect, to change your EP. If you 
elect to amend your EP, the Regional Supervisor may determine that your 
EP, as amended, is subject to the requirements of Sec. 250.231.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]



Sec. 250.233  What decisions will MMS make on the EP and within what timeframe?

    (a) Timeframe. The Regional Supervisor will take one of the actions 
shown in the table in paragraph (b) of this section within 30 calendar 
days after the Regional Supervisor deems your EP submitted under Sec. 
250.231, or receives the last amendment to your proposed EP, whichever 
occurs later.
    (b) MMS decision. By the deadline in paragraph (a) of this section, 
the Regional Supervisor will take one of the following actions:

------------------------------------------------------------------------
  The regional  supervisor
         will . . .                 If . . .           And then . . .
------------------------------------------------------------------------
(1) Approve your EP.........  It complies with all  The Regional
                               applicable            Supervisor will
                               requirements.         notify you in
                                                     writing of the
                                                     decision and may
                                                     require you to meet
                                                     certain conditions,
                                                     including those to
                                                     provide monitoring
                                                     information.
(2) Require you to modify     The Regional          The Regional
 your proposed EP.             Supervisor finds      Supervisor will
                               that it is            notify you in
                               inconsistent with     writing of the
                               the lease, the Act,   decision and
                               the regulations       describe the
                               prescribed under      modifications you
                               the Act, or other     must make to your
                               Federal laws.         proposed EP to
                                                     ensure it complies
                                                     with all applicable
                                                     requirements.
(3) Disapprove your EP......  Your proposed         (i) The Regional
                               activities would      Supervisor will
                               probably cause        notify you in
                               serious harm or       writing of the
                               damage to life        decision and
                               (including fish or    describe the
                               other aquatic         reason(s) for
                               life); property;      disapproving your
                               any mineral (in       EP.
                               areas leased or not  (ii) MMS may cancel
                               leased); the          your lease and
                               national security     compensate you
                               or defense; or the    under 43 U.S.C.
                               marine, coastal, or   1334(a)(2)(C) and
                               human environment;    the implementing
                               and you cannot        regulations in Sec.
                               modify your            Sec.  250.182,
                               proposed activities   250.184, and
                               to avoid such         250.185 and 30 CFR
                               condition(s).         256.77.
------------------------------------------------------------------------


[70 FR 51501, Aug. 30, 2005, as amended at 74 FR 46908, Sept. 14, 2009]



Sec. 250.234  How do I submit a modified EP or resubmit a disapproved EP, and when will MMS make a decision?

    (a) Modified EP. If the Regional Supervisor requires you to modify 
your proposed EP under Sec. 250.233(b)(2), you must submit the 
modification(s) to the Regional Supervisor in the same manner as for a 
new EP. You need submit only information related to the proposed 
modification(s).
    (b) Resubmitted EP. If the Regional Supervisor disapproves your EP 
under Sec. 250.233(b)(3), you may resubmit the disapproved EP if there 
is a change in the conditions that were the basis of its disapproval.
    (c) MMS review and timeframe. The Regional Supervisor will use the 
performance standards in Sec. 250.202 to either approve, require you to 
further modify, or disapprove your modified or resubmitted EP. The 
Regional Supervisor will make a decision within 30 calendar days after 
the Regional Supervisor deems your modified or resubmitted EP to be 
submitted, or receives the last amendment to your modified or 
resubmitted EP, whichever occurs later.



Sec. 250.235  If a State objects to the EP's coastal zone consistency certification, what can I do?

    If an affected State objects to the coastal zone consistency 
certification accompanying your proposed EP within the timeframe 
prescribed in Sec. 250.233(a) or Sec. 250.234(c), you may do one of 
the following:
    (a) Amend your EP. Amend your EP to accommodate the State's 
objection and submit the amendment to the Regional Supervisor for 
approval. The

[[Page 108]]

amendment needs to only address information related to the State's 
objection.
    (b) Appeal. Appeal the State's objection to the Secretary of 
Commerce using the procedures in 15 CFR part 930, subpart H. The 
Secretary of Commerce will either:
    (1) Grant your appeal by finding, under section 307(c)(3)(B)(iii) of 
the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), that each activity described in 
detail in your EP is consistent with the objectives of the CZMA, or is 
otherwise necessary in the interest of national security; or
    (2) Deny your appeal, in which case you may amend your EP as 
described in paragraph (a) of this section.
    (c) Withdraw your EP. Withdraw your EP if you decide not to conduct 
your proposed exploration activities.

[70 FR 51501, Aug. 30, 2005; 71 FR 12438, Mar. 10, 2006]

   Contents of Development and Production Plans (DPP) and Development 
                Operations Coordination Documents (DOCD)



Sec. 250.241  What must the DPP or DOCD include?

    Your DPP or DOCD must include the following:
    (a) Description, objectives, and schedule. A description, discussion 
of the objectives, and tentative schedule (from start to completion) of 
the development and production activities you propose to undertake. 
Examples of development and production activities include:
    (1) Development drilling;
    (2) Well test flaring;
    (3) Installation of production platforms, satellite structures, 
subsea wellheads and manifolds, and lease term pipelines (see definition 
at Sec. 250.105); and
    (4) Installation of production facilities and conduct of production 
operations.
    (b) Location. The location and water depth of each of your proposed 
wells and production facilities. Include a map showing the surface and 
bottom-hole location and water depth of each proposed well, the surface 
location of each production facility, and the locations of all 
associated drilling unit and construction barge anchors.
    (c) Drilling unit. A description of the drilling unit and associated 
equipment you will use to conduct your proposed development drilling 
activities. Include a brief description of its important safety and 
pollution prevention features, and a table indicating the type and the 
estimated maximum quantity of fuels and oil that will be stored on the 
facility (see third definition of ``facility'' under Sec. 250.105).
    (d) Production facilities. A description of the production 
platforms, satellite structures, subsea wellheads and manifolds, lease 
term pipelines (see definition at Sec. 250.105), production facilities, 
umbilicals, and other facilities you will use to conduct your proposed 
development and production activities. Include a brief description of 
their important safety and pollution prevention features, and a table 
indicating the type and the estimated maximum quantity of fuels and oil 
that will be stored on the facility (see third definition of 
``facility'' under Sec. 250.105).
    (e) Service fee. You must include payment of the service fee listed 
in Sec. 250.125.

[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.242  What information must accompany the DPP or DOCD?

    The following information must accompany your DPP or DOCD.
    (a) General information required by Sec. 250.243;
    (b) G&G information required by Sec. 250.244;
    (c) Hydrogen sulfide information required by Sec. 250.245;
    (d) Mineral resource conservation information required by Sec. 
250.246;
    (e) Biological, physical, and socioeconomic information required by 
Sec. 250.247;
    (f) Solid and liquid wastes and discharges information and cooling 
water intake information required by Sec. 250.248;
    (g) Air emissions information required by Sec. 250.249;
    (h) Oil and hazardous substance spills information required by Sec. 
250.250;
    (i) Alaska planning information required by Sec. 250.251;

[[Page 109]]

    (j) Environmental monitoring information required by Sec. 250.252;
    (k) Lease stipulations information required by Sec. 250.253;
    (l) Mitigation measures information required by Sec. 250.254;
    (m) Decommissioning information required by Sec. 250.255;
    (n) Related facilities and operations information required by Sec. 
250.256;
    (o) Support vessels and aircraft information required by Sec. 
250.257;
    (p) Onshore support facilities information required by Sec. 
250.258;
    (q) Sulphur operations information required by Sec. 250.259;
    (r) Coastal zone management information required by Sec. 250.260;
    (s) Environmental impact analysis information required by Sec. 
250.261; and
    (t) Administrative information required by Sec. 250.262.



Sec. 250.243  What general information must accompany the DPP or DOCD?

    The following general information must accompany your DPP or DOCD:
    (a) Applications and permits. A listing, including filing or 
approval status, of the Federal, State, and local application approvals 
or permits you must obtain to carry out your proposed development and 
production activities.
    (b) Drilling fluids. A table showing the projected amount, discharge 
rate, and chemical constituents for each type (i.e., water based, oil 
based, synthetic based) of drilling fluid you plan to use to drill your 
proposed development wells.
    (c) Production. The following production information:
    (1) Estimates of the average and peak rates of production for each 
type of production and the life of the reservoir(s) you intend to 
produce; and
    (2) The chemical and physical characteristics of the produced oil 
(see definition under 30 CFR 254.6) that you will handle or store at the 
facilities you will use to conduct your proposed development and 
production activities.
    (d) Chemical products. A table showing the name and brief 
description, quantities to be stored, storage method, and rates of usage 
of the chemical products you will use to conduct your proposed 
development and production activities. You need list only those chemical 
products you will store or use in quantities greater than the amounts 
defined as Reportable Quantities in 40 CFR part 302, or amounts 
specified by the Regional Supervisor.
    (e) New or unusual technology. A description and discussion of any 
new or unusual technology (see definition under Sec. 250.200) you will 
use to carry out your proposed development and production activities. In 
the public information copies of your DPP or DOCD, you may exclude any 
proprietary information from this description. In that case, include a 
brief discussion of the general subject matter of the omitted 
information. If you will not use any new or unusual technology to carry 
out your proposed development and production activities, include a 
statement so indicating.
    (f) Bonds, oil spill financial responsibility, and well control 
statements. Statements attesting that:
    (1) The activities and facilities proposed in your DPP or DOCD are 
or will be covered by an appropriate bond under 30 CFR part 256, subpart 
I;
    (2) You have demonstrated or will demonstrate oil spill financial 
responsibility for facilities proposed in your DPP or DOCD, according to 
30 CFR Part 253; and
    (3) You have or will have the financial capability to drill a relief 
well and conduct other emergency well control operations.
    (g) Suspensions of production or operations. A brief discussion of 
any suspensions of production or suspensions of operations that you 
anticipate may be necessary in the course of conducting your activities 
under the DPP or DOCD.
    (h) Blowout scenario. A scenario for a potential blowout of the 
proposed well in your DPP or DOCD that you expect will have the highest 
volume of liquid hydrocarbons. Include the estimated flow rate, total 
volume, and maximum duration of the potential blowout. Also, discuss the 
potential for the well to bridge over, the likelihood for surface 
intervention to stop the blowout, the availability of a rig to drill a 
relief well, and rig package constraints. Estimate the time it would 
take to drill a relief well.

[[Page 110]]

    (i) Contact. The name, mailing address, (e-mail address if 
available), and telephone number of the person with whom the Regional 
Supervisor and the affected State(s) can communicate about your DPP or 
DOCD.



Sec. 250.244  What geological and geophysical (G&G) information must accompany the DPP or DOCD?

    The following G&G information must accompany your DPP or DOCD:
    (a) Geological description. A geological description of the 
prospect(s).
    (b) Structure contour maps. Current structure contour maps (depth-
based, expressed in feet subsea) showing depths of expected productive 
formations and the locations of proposed wells.
    (c) Two dimensional (2-D) or three-dimensional (3-D) seismic lines. 
Copies of migrated and annotated 2-D or 3-D seismic lines (with depth 
scale) intersecting at or near your proposed well locations. You are not 
required to conduct both 2-D and 3-D seismic surveys if you choose to 
conduct only one type of survey. If you have conducted both types of 
surveys, the Regional Supervisor may instruct you to submit the results 
of both surveys. You must interpret and display this information. 
Provide this information as an enclosure to only one proprietary copy of 
your DPP or DOCD.
    (d) Geological cross-sections. Interpreted geological cross-sections 
showing the depths of expected productive formations.
    (e) Shallow hazards report. A shallow hazards report based on 
information obtained from a high-resolution geophysical survey, or a 
reference to such report if you have already submitted it to the 
Regional Supervisor.
    (f) Shallow hazards assessment. For each proposed well, an 
assessment of any seafloor and subsurface geologic and manmade features 
and conditions that may adversely affect your proposed drilling 
operations.
    (g) High resolution seismic lines. A copy of the high-resolution 
survey line closest to each of your proposed well locations. Because of 
its volume, provide this information as an enclosure to only one 
proprietary copy of your DPP or DOCD. You are not required to provide 
this information if the surface location of your proposed well has been 
approved in a previously submitted EP, DPP, or DOCD.
    (h) Stratigraphic column. A generalized biostratigraphic/
lithostratigraphic column from the surface to the total depth of each 
proposed well.
    (i) Time-versus-depth chart. A seismic travel time-versus-depth 
chart based on the appropriate velocity analysis in the area of 
interpretation and specifying the geodetic datum.
    (j) Geochemical information. A copy of any geochemical reports you 
used or generated.
    (k) Future G&G activities. A brief description of the G&G 
explorations and development G&G activities that you may conduct for 
lease or unit purposes after your DPP or DOCD is approved.



Sec. 250.245  What hydrogen sulfide (H[bdi2]S) information must accompany the DPP or DOCD?

    The following H2S information, as applicable, must 
accompany your DPP or DOCD:
    (a) Concentration. The estimated concentration of any H2S 
you might encounter or handle while you conduct your proposed 
development and production activities.
    (b) Classification. Under Sec. 250.490(c), a request that the 
Regional Supervisor classify the area of your proposed development and 
production activities as either H2S absent, H2S 
present, or H2S unknown. Provide sufficient information to 
justify your request.
    (c) H2S Contingency Plan. If you request that the 
Regional Supervisor classify the area of your proposed development and 
production activities as either H2S present or H2S 
unknown, an H2S Contingency Plan prepared under Sec. 
250.490(f), or a reference to an approved or submitted H2S 
Contingency Plan that covers the proposed development and production 
activities.
    (d) Modeling report. (1) If you have determined or estimated that 
the concentration of any H2S you may encounter or handle 
while you conduct your development and production activities will be 
greater than 500 parts per million (ppm), you must:
    (i) Model a potential worst case H2S release from the 
facilities you will use

[[Page 111]]

to conduct your proposed development and production activities; and
    (ii) Include a modeling report or modeling results, or a reference 
to such report or results if you have already submitted it to the 
Regional Supervisor.
    (2) The analysis in the modeling report must be specific to the 
particular site of your development and production activities, and must 
consider any nearby human-occupied OCS facilities, shipping lanes, 
fishery areas, and other points where humans may be subject to potential 
exposure from an H2S release from your proposed activities.
    (3) If any H2S emissions are projected to affect an 
onshore location in concentrations greater than 10 ppm, the modeling 
analysis must be consistent with the EPA's risk management plan 
methodologies outlined in 40 CFR part 68.



Sec. 250.246  What mineral resource conservation information must accompany the DPP or DOCD?

    The following mineral resource conservation information, as 
applicable, must accompany your DPP or DOCD:
    (a) Technology and reservoir engineering practices and procedures. A 
description of the technology and reservoir engineering practices and 
procedures you will use to increase the ultimate recovery of oil and gas 
(e.g., secondary, tertiary, or other enhanced recovery practices). If 
you will not use enhanced recovery practices initially, provide an 
explanation of the methods you considered and the reasons why you are 
not using them.
    (b) Technology and recovery practices and procedures. A description 
of the technology and recovery practices and procedures you will use to 
ensure optimum recovery of oil and gas or sulphur.
    (c) Reservoir development. A discussion of exploratory well results, 
other reservoir data, proposed well spacing, completion methods, and 
other relevant well plan information.



Sec. 250.247  What biological, physical, and socioeconomic information must accompany the DPP or DOCD?

    If you obtain the following information in developing your DPP or 
DOCD, or if the Regional Supervisor requires you to obtain it, you must 
include a report, or the information obtained, or a reference to such a 
report or information if you have already submitted it to the Regional 
Supervisor, as accompanying information:
    (a) Biological environment reports. Site-specific information on 
chemosynthetic communities, federally listed threatened or endangered 
species, marine mammals protected under the MMPA, sensitive underwater 
features, marine sanctuaries, critical habitat designated under the ESA, 
or other areas of biological concern.
    (b) Physical environment reports. Site-specific meteorological, 
physical oceanographic, geotechnical reports, or archaeological reports 
(if required under Sec. 250.194).
    (c) Socioeconomic study reports. Socioeconomic information related 
to your proposed development and production activities.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.248  What solid and liquid wastes and discharges information

and cooling water intake information must accompany the DPP or DOCD?

    The following solid and liquid wastes and discharges information and 
cooling water intake information must accompany your DPP or DOCD:
    (a) Projected wastes. A table providing the name, brief description, 
projected quantity, and composition of solid and liquid wastes (such as 
spent drilling fluids, drill cuttings, trash, sanitary and domestic 
wastes, produced waters, and chemical product wastes) likely to be 
generated by your proposed development and production activities. 
Describe:
    (1) The methods you used for determining this information; and
    (2) Your plans for treating, storing, and downhole disposal of these 
wastes at your facility location(s).
    (b) Projected ocean discharges. If any of your solid and liquid 
wastes will be discharged overboard or are planned discharges from 
manmade islands:
    (1) A table showing the name, projected amount, and rate of 
discharge for each waste type; and

[[Page 112]]

    (2) A description of the discharge method (such as shunting through 
a downpipe, adding to a produced water stream, etc.) you will use.
    (c) National Pollutant Discharge Elimination System (NPDES) permit. 
(1) A discussion of how you will comply with the provisions of the 
applicable general NPDES permit that covers your proposed development 
and production activities; or
    (2) A copy of your application for an individual NPDES permit. 
Briefly describe the major discharges and methods you will use for 
compliance.
    (d) Modeling report. A modeling report or the modeling results (if 
you modeled the discharges of your projected solid or liquid wastes in 
developing your DPP or DOCD), or a reference to such report or results 
if you have already submitted it to the Regional Supervisor.
    (e) Projected cooling water intake. A table for each cooling water 
intake structure likely to be used by your proposed development and 
production activities that includes a brief description of the cooling 
water intake structure, daily water intake rate, water intake through-
screen velocity, percentage of water intake used for cooling water, 
mitigation measures for reducing impingement and entrainment of aquatic 
organisms, and biofouling prevention measures.



Sec. 250.249  What air emissions information must accompany the DPP or DOCD?

    The following air emissions information, as applicable, must 
accompany your DPP or DOCD:
    (a) Projected emissions. Tables showing the projected emissions of 
sulphur dioxide (SO2), particulate matter in the form of 
PM10 and PM2.5 when applicable, nitrogen oxides 
(NOX), carbon monoxide (CO), and volatile organic compounds 
(VOC) that will be generated by your proposed development and production 
activities.
    (1) For each source on or associated with the facility you will use 
to conduct your proposed development and production activities, you must 
list:
    (i) The projected peak hourly emissions;
    (ii) The total annual emissions in tons per year;
    (iii) Emissions over the duration of the proposed development and 
production activities;
    (iv) The frequency and duration of emissions; and
    (v) The total of all emissions listed in paragraph (a)(1)(i) through 
(iv) of this section.
    (2) If your proposed production and development activities would 
result in an increase in the emissions of an air pollutant from your 
facility to an amount greater than the amount specified in your 
previously approved DPP or DOCD, you must show the revised emission 
rates for each source as well as the incremental change for each source.
    (3) You must provide the basis for all calculations, including 
engine size and rating, and applicable operational information.
    (4) You must base the projected emissions on the maximum rated 
capacity of the equipment and the maximum throughput of the facility you 
will use to conduct your proposed development and production activities 
under its physical and operational design.
    (5) If the specific drilling unit has not yet been determined, you 
must use the maximum emission estimates for the type of drilling unit 
you will use.
    (b) Emission reduction measures. A description of any proposed 
emission reduction measures, including the affected source(s), the 
emission reduction control technologies or procedures, the quantity of 
reductions to be achieved, and any monitoring system you propose to use 
to measure emissions.
    (c) Processes, equipment, fuels, and combustibles. A description of 
processes, processing equipment, combustion equipment, fuels, and 
storage units. You must include the frequency, duration, and maximum 
burn rate of any flaring activity.
    (d) Distance to shore. Identification of the distance of the site of 
your proposed development and production activities from the mean high 
water mark (mean higher high water mark on the Pacific coast) of the 
adjacent State.

[[Page 113]]

    (e) Non-exempt facilities. A description of how you will comply with 
Sec. 250.303 when the projected emissions of SO2, PM, 
NOX, CO, or VOC that will be generated by your proposed 
development and production activities are greater than the respective 
emission exemption amounts ``E'' calculated using the formulas in Sec. 
250.303(d). When MMS requires air quality modeling, you must use the 
guidelines in Appendix W of 40 CFR part 51 with a model approved by the 
Director. Submit the best available meteorological information and data 
consistent with the model(s) used.
    (f) Modeling report. A modeling report or the modeling results (if 
Sec. 250.303 requires you to use an approved air quality model to model 
projected air emissions in developing your DPP or DOCD), or a reference 
to such report or results if you have already submitted it to the 
Regional Supervisor.



Sec. 250.250  What oil and hazardous substance spills information must accompany the DPP or DOCD?

    The following information regarding potential spills of oil (see 
definition under 30 CFR 254.6) and hazardous substances (see definition 
under 40 CFR part 116), as applicable, must accompany your DPP or DOCD:
    (a) Oil spill response planning. The material required under 
paragraph (a)(1) or (a)(2) of this section:
    (1) An Oil Spill Response Plan (OSRP) for the facilities you will 
use to conduct your proposed development and production activities 
prepared according to the requirements of 30 CFR part 254, subpart B; or
    (2) Reference to your approved regional OSRP (see 30 CFR 254.3) to 
include:
    (i) A discussion of your regional OSRP;
    (ii) The location of your primary oil spill equipment base and 
staging area;
    (iii) The name(s) of your oil spill removal organization(s) for both 
equipment and personnel;
    (iv) The calculated volume of your worst case discharge scenario 
(see 30 CFR 254.26(a)), and a comparison of the appropriate worst case 
discharge scenario in your approved regional OSRP with the worst case 
discharge scenario that could result from your proposed development and 
production activities; and
    (v) A description of the worst case oil spill scenario that could 
result from your proposed development and production activities (see 30 
CFR 254.26(b), (c), (d), and (e)).
    (b) Modeling report. If you model a potential oil or hazardous 
substance spill in developing your DPP or DOCD, a modeling report or the 
modeling results, or a reference to such report or results if you have 
already submitted it to the Regional Supervisor.



Sec. 250.251  If I propose activities in the Alaska OCS Region, what 

planning information must accompany the DPP?

    If you propose development and production activities in the Alaska 
OCS Region, the following planning information must accompany your DPP:
    (a) Emergency plans. A description of your emergency plans to 
respond to a blowout, loss or disablement of a drilling unit, and loss 
of or damage to support craft; and
    (b) Critical operations and curtailment procedures. Critical 
operations and curtailment procedures for your development and 
production activities. The procedures must identify ice conditions, 
weather, and other constraints under which the development and 
production activities will either be curtailed or not proceed.



Sec. 250.252  What environmental monitoring information must accompany the DPP or DOCD?

    The following environmental monitoring information, as applicable, 
must accompany your DPP or DOCD:
    (a) Monitoring systems. A description of any existing and planned 
monitoring systems that are measuring, or will measure, environmental 
conditions or will provide project-specific data or information on the 
impacts of your development and production activities.
    (b) Incidental takes. If there is reason to believe that protected 
species may be incidentally taken by planned development and production 
activities, you must describe how you will monitor for incidental take 
of:
    (1) Threatened and endangered species listed under the ESA and

[[Page 114]]

    (2) Marine mammals, as appropriate, if you have not already received 
authorization for incidental take of marine mammals as may be necessary 
under the MMPA.
    (c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you 
propose to conduct development and production activities within the 
protective zones of the FGBNMS, a description of your provisions for 
monitoring the impacts of an oil spill on the environmentally sensitive 
resources of the FGBNMS.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.253  What lease stipulations information must accompany the DPP or DOCD?

    A description of the measures you took, or will take, to satisfy the 
conditions of lease stipulations related to your proposed development 
and production activities must accompany your DPP or DOCD.



Sec. 250.254  What mitigation measures information must accompany the DPP or DOCD?

    (a) If you propose to use any measures beyond those required by the 
regulations in this part to minimize or mitigate environmental impacts 
from your proposed development and production activities, a description 
of the measures you will use must accompany your DPP or DOCD.
    (b) If there is reason to believe that protected species may be 
incidentally taken by planned development and production activities, you 
must include mitigation measures designed to avoid or minimize that 
incidental take of:
    (1) Threatened and endangered species listed under the ESA and
    (2) Marine mammals, as appropriate, if you have not already received 
authorization for incidental take as may be necessary under the MMPA.

[72 FR 18585, Apr. 13, 2007]



Sec. 250.255  What decommissioning information must accompany the DPP or DOCD?

    A brief description of how you intend to decommission your wells, 
platforms, pipelines, and other facilities, and clear your site(s) must 
accompany your DPP or DOCD.



Sec. 250.256  What related facilities and operations information must accompany the DPP or DOCD?

    The following information regarding facilities and operations 
directly related to your proposed development and production activities 
must accompany your DPP or DOCD.
    (a) OCS facilities and operations. A description and location of any 
of the following that directly relate to your proposed development and 
production activities:
    (1) Drilling units;
    (2) Production platforms;
    (3) Right-of-way pipelines (including those that transport chemical 
products and produced water); and
    (4) Other facilities and operations located on the OCS (regardless 
of ownership).
    (b) Transportation system. A discussion of the transportation system 
that you will use to transport your production to shore, including:
    (1) Routes of any new pipelines;
    (2) Information concerning barges and shuttle tankers, including the 
storage capacity of the transport vessel(s), and the number of transfers 
that will take place per year;
    (3) Information concerning any intermediate storage or processing 
facilities;
    (4) An estimate of the quantities of oil, gas, or sulphur to be 
transported from your production facilities; and
    (5) A description and location of the primary onshore terminal.



Sec. 250.257  What information on the support vessels, 

offshore vehicles, and aircraft you will use must accompany the DPP or DOCD?

    The following information on the support vessels, offshore vehicles, 
and aircraft you will use must accompany your DPP or DOCD:
    (a) General. A description of the crew boats, supply boats, anchor 
handling vessels, tug boats, barges, ice management vessels, other 
vessels, offshore vehicles, and aircraft you will use to support your 
development and production activities. The description of vessels and 
offshore vehicles must estimate the storage capacity of their fuel tanks

[[Page 115]]

and the frequency of their visits to the facilities you will use to 
conduct your proposed development and production activities.
    (b) Air emissions. A table showing the source, composition, 
frequency, and duration of the air emissions likely to be generated by 
the support vessels, offshore vehicles, and aircraft you will use that 
will operate within 25 miles of the facilities you will use to conduct 
your proposed development and production activities.
    (c) Drilling fluids and chemical products transportation. A 
description of the transportation method and quantities of drilling 
fluids and chemical products (see Sec. 250.243(b) and (d)) you will 
transport from the onshore support facilities you will use to the 
facilities you will use to conduct your proposed development and 
production activities.
    (d) Solid and liquid wastes transportation. A description of the 
transportation method and a brief description of the composition, 
quantities, and destination(s) of solid and liquid wastes (see Sec. 
250.248(a)) you will transport from the facilities you will use to 
conduct your proposed development and production activities.
    (e) Vicinity map. A map showing the location of your proposed 
development and production activities relative to the shoreline. The map 
must depict the primary route(s) the support vessels and aircraft will 
use when traveling between the onshore support facilities you will use 
and the facilities you will use to conduct your proposed development and 
production activities.



Sec. 250.258  What information on the onshore support facilities you will use

must accompany the DPP or DOCD?

    The following information on the onshore support facilities you will 
use must accompany your DPP or DOCD:
    (a) General. A description of the onshore facilities you will use to 
provide supply and service support for your proposed development and 
production activities (e.g., service bases and mud company docks).
    (1) Indicate whether the onshore support facilities are existing, to 
be constructed, or to be expanded; and
    (2) For DPPs only, provide a timetable for acquiring lands 
(including rights-of-way and easements) and constructing or expanding 
any of the onshore support facilities.
    (b) Air emissions. A description of the source, composition, 
frequency, and duration of the air emissions (attributable to your 
proposed development and production activities) likely to be generated 
by the onshore support facilities you will use.
    (c) Unusual solid and liquid wastes. A description of the quantity, 
composition, and method of disposal of any unusual solid and liquid 
wastes (attributable to your proposed development and production 
activities) likely to be generated by the onshore support facilities you 
will use. Unusual wastes are those wastes not specifically addressed in 
the relevant National Pollution Discharge Elimination System (NPDES) 
permit.
    (d) Waste disposal. A description of the onshore facilities you will 
use to store and dispose of solid and liquid wastes generated by your 
proposed development and production activities (see Sec. 250.248(a)) 
and the types and quantities of such wastes.



Sec. 250.259  What sulphur operations information must accompany the DPP or DOCD?

    If you are proposing to conduct sulphur development and production 
activities, the following information must accompany your DPP or DOCD:
    (a) Bleedwater. A discussion of the bleedwater that will be 
generated by your proposed sulphur activities, including the measures 
you will take to mitigate the potential toxic or thermal impacts on the 
environment caused by the discharge of bleedwater.
    (b) Subsidence. An estimate of the degree of subsidence expected at 
various stages of your sulphur development and production activities, 
and a description of the measures you will take to mitigate the effects 
of subsidence on existing or potential oil and gas production, 
production platforms, and production facilities, and to protect the 
environment.

[[Page 116]]



Sec. 250.260  What Coastal Zone Management Act (CZMA) information must 

accompany the DPP or DOCD?

    The following CZMA information must accompany your DPP or DOCD:
    (a) Consistency certification. A copy of your consistency 
certification under section 307(c)(3)(B) of the CZMA (16 U.S.C. 
1456(c)(3)(B)) and 15 CFR 930.76(c) stating that the proposed 
development and production activities described in detail in this DPP or 
DOCD comply with (name of State(s)) approved coastal management 
program(s) and will be conducted in a manner that is consistent with 
such program(s); and
    (b) Other information. ``Information'' as required by 15 CFR 
930.76(a) and 15 CFR 930.58(a)(2)) and ``Analysis'' as required by 15 
CFR 930.58(a)(3).

[70 FR 51501, Aug. 30, 2005, as amended at 73 FR 20171, Apr. 15, 2008]



Sec. 250.261  What environmental impact analysis (EIA) information must 

accompany the DPP or DOCD?

    The following EIA information must accompany your DPP or DOCD:
    (a) General requirements. Your EIA must:
    (1) Assess the potential environmental impacts of your proposed 
development and production activities;
    (2) Be project specific; and
    (3) Be as detailed as necessary to assist the Regional Supervisor in 
complying with the NEPA of 1969 (42 U.S.C. 4321 et seq.) and other 
relevant Federal laws such as the ESA and the MMPA.
    (b) Resources, conditions, and activities. Your EIA must describe 
those resources, conditions, and activities listed below that could be 
affected by your proposed development and production activities, or that 
could affect the construction and operation of facilities or structures 
or the activities proposed in your DPP or DOCD.
    (1) Meteorology, oceanography, geology, and shallow geological or 
manmade hazards;
    (2) Air and water quality;
    (3) Benthic communities, marine mammals, sea turtles, coastal and 
marine birds, fish and shellfish, and plant life;
    (4) Threatened or endangered species and their critical habitat;
    (5) Sensitive biological resources or habitats such as essential 
fish habitat, refuges, preserves, special management areas identified in 
coastal management programs, sanctuaries, rookeries, and calving 
grounds;
    (6) Archaeological resources;
    (7) Socioeconomic resources (including the approximate number, 
timing, and duration of employment of persons engaged in onshore support 
and construction activities), population (including the approximate 
number of people and families added to local onshore areas), existing 
offshore and onshore infrastructure (including major sources of 
supplies, services, energy, and water), types of contractors or vendors 
that may place a demand on local goods and services, land use, 
subsistence resources and harvest practices, recreation, recreational 
and commercial fishing (including seasons, location, and type), minority 
and lower income groups, and CZMA programs;
    (8) Coastal and marine uses such as military activities, shipping, 
and mineral exploration or development; and
    (9) Other resources, conditions, and activities identified by the 
Regional Supervisor.
    (c) Environmental impacts. Your EIA must:
    (1) Analyze the potential direct and indirect impacts (including 
those from accidents, cooling water intake structures, and those 
identified in relevant ESA biological opinions such as, but not limited 
to, those from noise, vessel collisions, and marine trash and debris) 
that your proposed development and production activities will have on 
the identified resources, conditions, and activities;
    (2) Describe the type, severity, and duration of these potential 
impacts and their biological, physical, and other consequences and 
implications;
    (3) Describe potential measures to minimize or mitigate these 
potential impacts;
    (4) Describe any alternatives to your proposed development and 
production activities that you considered while developing your DPP or 
DOCD, and compare the potential environmental impacts; and
    (5) Summarize the information you incorporate by reference.

[[Page 117]]

    (d) Consultation. Your EIA must include a list of agencies and 
persons with whom you consulted, or with whom you will be consulting, 
regarding potential impacts associated with your proposed development 
and production activities.
    (e) References cited. Your EIA must include a list of the references 
that you cite in the EIA.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.262  What administrative information must accompany the DPP or DOCD?

    The following administrative information must accompany your DPP or 
DOCD:
    (a) Exempted information description (public information copies 
only). A description of the general subject matter of the proprietary 
information that is included in the proprietary copies of your DPP or 
DOCD or its accompanying information.
    (b) Bibliography. (1) If you reference a previously submitted EP, 
DPP, DOCD, study report, survey report, or other material in your DPP or 
DOCD or its accompanying information, a list of the referenced material; 
and
    (2) The location(s) where the Regional Supervisor can inspect the 
cited referenced material if you have not submitted it.

             Review and Decision Process for the DPP or DOCD



Sec. 250.266  After receiving the DPP or DOCD, what will MMS do?

    (a) Determine whether deemed submitted. Within 25 working days after 
receiving your proposed DPP or DOCD and its accompanying information, 
the Regional Supervisor will deem your DPP or DOCD submitted if:
    (1) The submitted information, including the information that must 
accompany the DPP or DOCD (refer to the list in Sec. 250.242), fulfills 
requirements and is sufficiently accurate;
    (2) You have provided all needed additional information (see Sec. 
250.201(b)); and
    (3) You have provided the required number of copies (see Sec. 
250.206(a)).
    (b) Identify problems and deficiencies. If the Regional Supervisor 
determines that you have not met one or more of the conditions in 
paragraph (a) of this section, the Regional Supervisor will notify you 
of the problem or deficiency within 25 working days after the Regional 
Supervisor receives your DPP or DOCD and its accompanying information. 
The Regional Supervisor will not deem your DPP or DOCD submitted until 
you have corrected all problems or deficiencies identified in the 
notice.
    (c) Deemed submitted notification. The Regional Supervisor will 
notify you when your DPP or DOCD is deemed submitted.



Sec. 250.267  What actions will MMS take after the DPP or DOCD is deemed submitted?

    (a) State, local government, CZMA consistency, and other reviews. 
Within 2 working days after the Regional Supervisor deems your DPP or 
DOCD submitted under Sec. 250.266, the Regional Supervisor will use 
receipted mail or alternative method to send a public information copy 
of the DPP or DOCD and its accompanying information to the following:
    (1) The Governor of each affected State. The Governor has 60 
calendar days after receiving your deemed-submitted DPP or DOCD to 
submit comments and recommendations. The Regional Supervisor will not 
consider comments and recommendations received after the deadline.
    (2) The executive of any affected local government who requests a 
copy. The executive of any affected local government has 60 calendar 
days after receipt of your deemed-submitted DPP or DOCD to submit 
comments and recommendations. The Regional Supervisor will not consider 
comments and recommendations received after the deadline. The executive 
of any affected local government must forward all comments and 
recommendations to the respective Governor before submitting them to the 
Regional Supervisor.
    (3) The CZMA agency of each affected State. The CZMA consistency 
review period under section 307(c)(3)(B)(ii) of the CZMA (16 
U.S.C.1456(c)(3)(B)(ii)) and 15 CFR 930.78 begins when the States CZMA 
agency receives a copy of

[[Page 118]]

your deemed-submitted DPP or DOCD, consistency certification, and 
required necessary data/information (see 15 CFR 930.77(a)(1)).
    (b) General public. Within 2 working days after the Regional 
Supervisor deems your DPP or DOCD submitted under Sec. 250.266, the 
Regional Supervisor will make a public information copy of the DPP or 
DOCD and its accompanying information available for review to any 
appropriate interstate regional entity and the public at the appropriate 
MMS Regional Public Information Office. Any interested Federal agency or 
person may submit comments and recommendations to the Regional 
Supervisor. Comments and recommendations must be received by the 
Regional Supervisor within 60 calendar days after the DPP or DOCD 
including its accompanying information is made available.
    (c) MMS compliance review. The Regional Supervisor will review the 
development and production activities in your proposed DPP or DOCD to 
ensure that they conform to the performance standards in Sec. 250.202.
    (d) Amendments. During the review of your proposed DPP or DOCD, the 
Regional Supervisor may require you, or you may elect, to change your 
DPP or DOCD. If you elect to amend your DPP or DOCD, the Regional 
Supervisor may determine that your DPP or DOCD, as amended, is subject 
to the requirements of Sec. 250.266.



Sec. 250.268  How does MMS respond to recommendations?

    (a) Governor. The Regional Supervisor will accept those 
recommendations from the Governor that provide a reasonable balance 
between the national interest and the well-being of the citizens of each 
affected State. The Regional Supervisor will explain in writing to the 
Governor the reasons for rejecting any of his or her recommendations.
    (b) Local governments and the public. The Regional Supervisor may 
accept recommendations from the executive of any affected local 
government or the public.
    (c) Availability. The Regional Supervisor will make all comments and 
recommendations available to the public upon request.



Sec. 250.269  How will MMS evaluate the environmental impacts of the DPP or DOCD?

    The Regional Supervisor will evaluate the environmental impacts of 
the activities described in your proposed DPP or DOCD and prepare 
environmental documentation under the National Environmental Policy Act 
(NEPA) (42 U.S.C.4321 et seq.) and the implementing regulations (40 CFR 
parts 1500 through 1508).
    (a) Environmental impact statement (EIS) declaration. At least once 
in each OCS planning area (other than the Western and Central GOM 
Planning Areas), the Director will declare that the approval of a 
proposed DPP is a major Federal action, and MMS will prepare an EIS.
    (b) Leases or units in the vicinity. Before or immediately after the 
Director determines that preparation of an EIS is required, the Regional 
Supervisor may require lessees and operators of leases or units in the 
vicinity of the proposed development and production activities for which 
DPPs have not been approved to submit information about preliminary 
plans for their leases or units.
    (c) Draft EIS. The Regional Supervisor will send copies of the draft 
EIS to the Governor of each affected State and to the executive of each 
affected local government who requests a copy. Additionally, when MMS 
prepares a DPP EIS, and the Federally-approved CZMA program for an 
affected State requires a DPP NEPA document for use in determining 
consistency, the Regional Supervisor will forward a copy of the draft 
EIS to the State's CZMA agency. The Regional Supervisor will also make 
copies of the draft EIS available to any appropriate Federal agency, 
interstate regional entity, and the public.



Sec. 250.270  What decisions will MMS make on the DPP or DOCD and within what timeframe?

    (a) Timeframe. The Regional Supervisor will act on your deemed-
submitted DPP or DOCD as follows:

[[Page 119]]

    (1) The Regional Supervisor will make a decision within 60 calendar 
days after the latest of the day that:
    (i) The comment period provided in Sec. 250.267(a)(1), (a)(2), and 
(b) closes;
    (ii) The final EIS for a DPP is released or adopted; or
    (iii) The last amendment to your proposed DOCD is received by the 
Regional Supervisor.
    (2) Notwithstanding paragraph (a)(1) of this section, MMS will not 
approve your DPP or DOCD until either:
    (i) All affected States with approved CZMA programs concur, or have 
been conclusively presumed to concur, with your DPP or DOCD consistency 
certification under section 307(c)(3)(B)(i) and (ii) of the CZMA (16 
U.S.C. 1456(c)(3)(B)(i) and (ii)); or
    (ii) The Secretary of Commerce has made a finding authorized by 
section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) 
that each activity described in the DPP or DOCD is consistent with the 
objectives of the CZMA, or is otherwise necessary in the interest of 
national security.
    (b) MMS decision. By the deadline in paragraph (a) of this section, 
the Regional Supervisor will take one of the following actions:

------------------------------------------------------------------------
   The regional supervisor
         will . . .                 If . . .           And then . . .
------------------------------------------------------------------------
(1) Approve your DPP or DOCD  It complies with all  The Regional
                               applicable            Supervisor will
                               requirements.         notify you in
                                                     writing of the
                                                     decision and may
                                                     require you to meet
                                                     certain conditions,
                                                     including those to
                                                     provide monitoring
                                                     information.
(2) Require you to modify     It fails to make      The Regional
 your proposed DPP or DOCD.    adequate provisions   Supervisor will
                               for safety,           notify you in
                               environmental         writing of the
                               protection, or        decision and
                               conservation of       describe the
                               natural resources     modifications you
                               or otherwise does     must make to your
                               not comply with the   proposed DPP or
                               lease, the Act, the   DOCD to ensure it
                               regulations           complies with all
                               prescribed under      applicable
                               the Act, or other     requirements.
                               Federal laws.
(3) Disapprove your DPP or    Any of the reasons    (i) The Regional
 DOCD.                         in Sec.  250.271     Supervisor will
                               apply.                notify you in
                                                     writing of the
                                                     decision and
                                                     describe the
                                                     reason(s) for
                                                     disapproving your
                                                     DPP or DOCD; and
                                                    (ii) MMS may cancel
                                                     your lease and
                                                     compensate you
                                                     under 43 U.S.C.
                                                     1351(h)(2)(C) and
                                                     the implementing
                                                     regulations in Sec.
                                                      Sec.  250.183,
                                                     250.184, and
                                                     250.185 and 30 CFR
                                                     256.77.
------------------------------------------------------------------------


[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.271  For what reasons will MMS disapprove the DPP or DOCD?

    The Regional Supervisor will disapprove your proposed DPP or DOCD if 
one of the four reasons in this section applies:
    (a) Non-compliance. The Regional Supervisor determines that you have 
failed to demonstrate that you can comply with the requirements of the 
Outer Continental Shelf Lands Act, as amended (Act), implementing 
regulations, or other applicable Federal laws.
    (b) No consistency concurrence. (1) An affected State has not yet 
issued a final decision on your coastal zone consistency certification 
(see 15 CFR 930.78(a)); or
    (2) An affected State objects to your coastal zone consistency 
certification, and the Secretary of Commerce, under section 
307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), has not 
found that each activity described in the DPP or DOCD is consistent with 
the objectives of the CZMA or is otherwise necessary in the interest of 
national security.
    (3) If the Regional Supervisor disapproved your DPP or DOCD for the 
sole reason that an affected State either has not yet issued a final 
decision on, or has objected to, your coastal zone consistency 
certification (see paragraphs (b)(1) and (2) in this section), the 
Regional Supervisor will approve your DPP or DOCD upon receipt of 
concurrence by the affected State, at the time concurrence of the 
affected State is conclusively presumed, or when the Secretary of 
Commerce makes a finding authorized by section 307(c)(3)(B)(iii) of the 
CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) that each activity described in your 
DPP or DOCD is consistent with the objectives of the CZMA, or is 
otherwise necessary in the

[[Page 120]]

interest of national security. In that event, you do not need to 
resubmit your DPP or DOCD for approval under Sec. 250.273(b).
    (c) National security or defense conflicts. Your proposed activities 
would threaten national security or defense.
    (d) Exceptional circumstances. The Regional Supervisor determines 
because of exceptional geological conditions, exceptional resource 
values in the marine or coastal environment, or other exceptional 
circumstances that all of the following apply:
    (1) Implementing your DPP or DOCD would cause serious harm or damage 
to life (including fish and other aquatic life), property, any mineral 
deposits (in areas leased or not leased), the national security or 
defense, or the marine, coastal, or human environment;
    (2) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and
    (3) The advantages of disapproving your DPP or DOCD outweigh the 
advantages of development and production.



Sec. 250.272  If a State objects to the DPP's or DOCD's coastal zone consistency 

certification, what can I do?

    If an affected State objects to the coastal zone consistency 
certification accompanying your proposed or disapproved DPP or DOCD, you 
may do one of the following:
    (a) Amend or resubmit your DPP or DOCD. Amend or resubmit your DPP 
or DOCD to accommodate the State's objection and submit the amendment or 
resubmittal to the Regional Supervisor for approval. The amendment or 
resubmittal needs to only address information related to the State's 
objections.
    (b) Appeal. Appeal the State's objection to the Secretary of 
Commerce using the procedures in 15 CFR part 930, subpart H. The 
Secretary of Commerce will either:
    (1) Grant your appeal by finding under section 307(c)(3)(B)(iii) of 
the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity described in 
detail in your DPP or DOCD is consistent with the objectives of the 
CZMA, or is otherwise necessary in the interest of national security; or
    (2) Deny your appeal, in which case you may amend or resubmit your 
DPP or DOCD, as described in paragraph (a) of this section.
    (c) Withdraw your DPP or DOCD. Withdraw your DPP or DOCD if you 
decide not to conduct your proposed development and production 
activities.



Sec. 250.273  How do I submit a modified DPP or DOCD or resubmit a disapproved DPP or DOCD?

    (a) Modified DPP or DOCD. If the Regional Supervisor requires you to 
modify your proposed DPP or DOCD under Sec. 250.270(b)(2), you must 
submit the modification(s) to the Regional Supervisor in the same manner 
as for a new DPP or DOCD. You need submit only information related to 
the proposed modification(s).
    (b) Resubmitted DPP or DOCD. If the Regional Supervisor disapproves 
your DPP or DOCD under Sec. 250.270(b)(3), and except as provided in 
Sec. 250.271(b)(3), you may resubmit the disapproved DPP or DOCD if 
there is a change in the conditions that were the basis of its 
disapproval.
    (c) MMS review and timeframe. The Regional Supervisor will use the 
performance standards in Sec. 250.202 to either approve, require you to 
further modify, or disapprove your modified or resubmitted DPP or DOCD. 
The Regional Supervisor will make a decision within 60 calendar days 
after the Regional Supervisor deems your modified or resubmitted DPP or 
DOCD to be submitted, or receives the last amendment to your modified or 
resubmitted DPP or DOCD, whichever occurs later.

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



Sec. 250.280  How must I conduct activities under the approved EP, DPP, or DOCD?

    (a) Compliance. You must conduct all of your lease and unit 
activities according to your approved EP, DPP, or DOCD and any approval 
conditions. If you fail to comply with your approved EP, DPP, or DOCD:
    (1) You may be subject to MMS enforcement action, including civil 
penalties; and

[[Page 121]]

    (2) The lease(s) involved in your EP, DPP, or DOCD may be forfeited 
or cancelled under 43 U.S.C. 1334(c) or (d). If this happens, you will 
not be entitled to compensation under Sec. 250.185(b) and 30 CFR 
256.77.
    (b) Emergencies. Nothing in this subpart or in your approved EP, 
DPP, or DOCD relieves you of, or limits your responsibility to take 
appropriate measures to meet emergency situations. In an emergency 
situation, the Regional Supervisor may approve or require departures 
from your approved EP, DPP, or DOCD.



Sec. 250.281  What must I do to conduct activities under the approved EP, DPP, or DOCD?

    (a) Approvals and permits. Before you conduct activities under your 
approved EP, DPP, or DOCD you must obtain the following approvals and or 
permits, as applicable, from the District Manager or Regional 
Supervisor:
    (1) Approval of applications for permits to drill (APDs) (see Sec. 
250.410);
    (2) Approval of production safety systems (see Sec. 250.800);
    (3) Approval of new platforms and other structures (or major 
modifications to platforms and other structures) (see Sec. 250.905);
    (4) Approval of applications to install lease term pipelines (see 
Sec. 250.1007); and
    (5) Other permits, as required by applicable law.
    (b) Conformance. The activities proposed in these applications and 
permits must conform to the activities described in detail in your 
approved EP, DPP, or DOCD.
    (c) Separate State CZMA consistency review. APDs, and other 
applications for licenses, approvals, or permits to conduct activities 
under your approved EP, DPP, or DOCD including those identified in 
paragraph (a) of this section, are not subject to separate State CZMA 
consistency review.
    (d) Approval restrictions for permits for activities conducted under 
EPs. The District Manager or Regional Supervisor will not approve any 
APDs or other applications for licenses, approvals, or permits under 
your approved EP until either:
    (1) All affected States with approved coastal zone management 
programs concur, or are conclusively presumed to concur, with the 
coastal zone consistency certification accompanying your EP under 
section 307(c)(3)(B)(i) and (ii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(i) 
and (ii)); or
    (2) The Secretary of Commerce finds, under section 307(c)(3)(B)(iii) 
of the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity covered by 
the EP is consistent with the objectives of the CZMA or is otherwise 
necessary in the interest of national security;
    (3) If an affected State objects to the coastal zone consistency 
certification accompanying your approved EP after MMS has approved your 
EP, you may either:
    (i) Revise your EP to accommodate the State's objection and submit 
the revision to the Regional Supervisor for approval; or
    (ii) Appeal the State's objection to the Secretary of Commerce using 
the procedures in 15 CFR part 930 subpart H. The Secretary of Commerce 
will either:
    (A) Grant your appeal by making the finding described in paragraph 
(d)(2) of this section; or
    (B) Deny your appeal, in which case you may revise your EP as 
described in paragraph (d)(3)(i) of this section.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]



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

    After approving your EP, DPP, or DOCD, the Regional Supervisor may 
direct you to conduct monitoring programs, including monitoring in 
accordance with the ESA and the MMPA. You must retain copies of all 
monitoring data obtained or derived from your monitoring programs and 
make them available to the MMS upon request. The Regional Supervisor may 
require you to:
    (a) Monitoring plans. Submit monitoring plans for approval before 
you begin the work; and
    (b) Monitoring reports. Prepare and submit reports that summarize 
and analyze data and information obtained or derived from your 
monitoring programs. The Regional Supervisor will

[[Page 122]]

specify requirements for preparing and submitting these reports.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]



Sec. 250.283  When must I revise or supplement the approved EP, DPP, or DOCD?

    (a) Revised OCS plans. You must revise your approved EP, DPP, or 
DOCD when you propose to:
    (1) Change the type of drilling rig (e.g., jack-up, platform rig, 
barge, submersible, semisubmersible, or drillship), production facility 
(e.g., caisson, fixed platform with piles, tension leg platform), or 
transportation mode (e.g., pipeline, barge);
    (2) Change the surface location of a well or production platform by 
a distance more than that specified by the Regional Supervisor;
    (3) Change the type of production or significantly increase the 
volume of production or storage capacity;
    (4) Increase the emissions of an air pollutant to an amount that 
exceeds the amount specified in your approved EP, DPP, or DOCD;
    (5) Significantly increase the amount of solid or liquid wastes to 
be handled or discharged;
    (6) Request a new H2S area classification, or increase the 
concentration of H2S to a concentration greater than that specified by 
the Regional Supervisor;
    (7) Change the location of your onshore support base either from one 
State to another or to a new base or a base requiring expansion; or
    (8) Change any other activity specified by the Regional Supervisor.
    (b) Supplemental OCS plans. You must supplement your approved EP, 
DPP, or DOCD when you propose to conduct activities on your lease(s) or 
unit that require approval of a license or permit which is not described 
in your approved EP, DPP, or DOCD. These types of changes are called 
supplemental OCS plans.



Sec. 250.284  How will MMS require revisions to the approved EP, DPP, or DOCD?

    (a) Periodic review. The Regional Supervisor will periodically 
review the activities you conduct under your approved EP, DPP, or DOCD 
and may require you to submit updated information on your activities. 
The frequency and extent of this review will be based on the 
significance of any changes in available information and onshore or 
offshore conditions affecting, or affected by, the activities in your 
approved EP, DPP, or DOCD.
    (b) Results of review. The Regional Supervisor may require you to 
revise your approved EP, DPP, or DOCD based on this review. In such 
cases, the Regional Supervisor will inform you of the reasons for the 
decision.



Sec. 250.285  How do I submit revised and supplemental EPs, DPPs, and DOCDs?

    (a) Submittal. You must submit to the Regional Supervisor any 
revisions and supplements to approved EPs, DPPs, or DOCDs for approval, 
whether you initiate them or the Regional Supervisor orders them.
    (b) Information. Revised and supplemental EPs, DPPs, and DOCDs need 
include only information related to or affected by the proposed changes, 
including information on changes in expected environmental impacts.
    (c) Procedures. All supplemental EPs, DPPs, and DOCDs, and those 
revised EPs, DPPs, and DOCDs that the Regional Supervisor determines are 
likely to result in a significant change in the impacts previously 
identified and evaluated, are subject to all of the procedures under 
Sec. 250.231 through Sec. 250.235 for EPs and Sec. 250.266 through 
Sec. 250.273 for DPPs and DOCDs.

[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25201, May 4, 2007]

                    Deepwater Operations Plans (DWOP)



Sec. 250.286  What is a DWOP?

    (a) A DWOP is a plan that provides sufficient information for MMS 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 Exploration Plans, 
Development and Production Plans, and Development Operations 
Coordination Documents. MMS

[[Page 123]]

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 MMS 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 
MMS 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;
    (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;

[[Page 124]]

    (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.

[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.293  What operations require approval of the DWOP?

    You may not begin production until MMS 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.

                Conservation Information Documents (CID)



Sec. 250.296  When and how must I submit a CID or a revision to a CID?

    (a) You must submit one original and two copies of a CID to the 
appropriate OCS Region at the same time you first submit your DOCD or 
DPP for any development of a lease or leases located in water depths 
greater than 400 meters (1,312 feet). You must also submit a CID for a 
Supplemental DOCD or DPP when requested by the Regional Supervisor. The 
submission of your CID must be accompanied by payment of the service fee 
listed in Sec. 250.125.
    (b) If you decide not to develop a reservoir you committed to 
develop in your CID, you must submit one original and two copies of a 
revision to the CID to the appropriate OCS Region. The revision to the 
CID must be submitted within 14 calendar days after making your decision 
not to develop the reservoir and before the reservoir is bypassed. The 
Regional Supervisor will approve or disapprove any such revision to the 
original CID. If the Regional Supervisor disapproves the revision, you 
must develop the reservoir as described in the original CID.

[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]



Sec. 250.297  What information must a CID contain?

    (a) You must base the CID on wells drilled before your CID 
submittal, that define the extent of the reservoirs. You must notify MMS 
of any well that is drilled to total depth during the CID evaluation 
period and you may be required to update your CID.
    (b) You must include all of the following information if available. 
Information must be provided for each hydrocarbon-bearing reservoir that 
is penetrated by a well that would meet the producibility requirements 
of Sec. 250.115 or Sec. 250.116:
    (1) General discussion of the overall development of the reservoir;
    (2) Summary spreadsheets of well log data and reservoir parameters 
(i.e., sand tops and bases, fluid contacts, net pay, porosity, water 
saturations, pressures, formation volume factor);

[[Page 125]]

    (3) Appropriate well logs, including digital well log (i.e., gamma 
ray, resistivity, neutron, density, sonic, caliper curves) curves in an 
acceptable digital format;
    (4) Sidewall core/whole core and pressure-volume-temperature 
analysis;
    (5) Structure maps, with the existing and proposed penetration 
points and subsea depths for all wells penetrating the reservoirs, fluid 
contacts (or the lowest or highest known levels in the absence of actual 
contacts), reservoir boundaries, and the scale of the map;
    (6) Interpreted structural cross sections and corresponding 
interpreted seismic lines or block diagrams, as necessary, that include 
all current wellbores and planned wellbores on the leases or units to be 
developed, the reservoir boundaries, fluid contacts, depth scale, 
stratigraphic positions, and relative biostratigraphic ages;
    (7) Isopach maps of each reservoir showing the net feet of pay for 
each well within the reservoir identified at the penetration point, 
along with the well name, labeled contours, and scale;
    (8) Estimates of original oil and gas in-place and anticipated 
recoverable oil and gas reserves, all reservoir parameters, and risk 
factors and assumptions;
    (9) Plat map at the same scale as the structure maps with existing 
and proposed well paths, as well as existing and proposed penetrations;
    (10) Wellbore schematics indicating proposed perforations;
    (11) Proposed wellbore utility chart showing all existing and 
proposed wells, with proposed completion intervals indicated for each 
borehole;
    (12) Appropriate pressure data, specified by date, and whether 
estimated or measured;
    (13) Description of reservoir development strategies;
    (14) Description of the enhanced recovery practices you will use or, 
if you do not plan to use such practices, an explanation of the methods 
you considered and reasons you do not intend to use them;
    (15) For each reservoir you do not intend to develop:
    (i) A statement explaining the reason(s) you will not develop the 
reservoir, and
    (ii) Economic justification, including costs, recoverable reserve 
estimate, production profiles, and pricing assumptions; and
    (16) Any other appropriate data you used in performing your 
reservoir evaluations and preparing your reservoir development 
strategies.



Sec. 250.298  How long will MMS take to evaluate and make a decision on the CID?

    (a) The Regional Supervisor will make a decision within 150 calendar 
days of receiving your CID. If MMS does not act within 150 calendar 
days, your CID is considered approved.
    (b) MMS may suspend the 150-calendar-day evaluation period if there 
is missing, inconclusive, or inaccurate data, or when a well reaches 
total depth during the evaluation period. MMS may also suspend the 
evaluation period when a well penetrating a hydrocarbon-bearing 
structure reaches total depth during the evaluation period and the data 
from that well is needed for the CID. You will receive written 
notification from the Regional Supervisor describing the additional 
information that is needed, and the evaluation period will resume once 
MMS receives the requested information.
    (c) The Regional Supervisor will approve or deny your CID request 
based on your commitment to develop economically producible reservoirs 
according to sound conservation, engineering, and economic practices.



Sec. 250.299  What operations require approval of the CID?

    You may not begin production before you receive MMS approval of the 
CID.



               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,

[[Page 126]]

property, aquatic life, wildlife, recreation, navigation, commercial 
fishing, or other uses of the ocean.
    (1) When pollution occurs as a result of operations conducted by or 
on behalf of the lessee and the pollution damages or threatens to damage 
life (including fish and other aquatic life), property, any mineral 
deposits (in areas leased or not leased), or the marine, coastal, or 
human environment, the control and removal of the pollution to the 
satisfaction of the District Manager shall be at the expense of the 
lessee. Immediate corrective action shall be taken in all cases where 
pollution has occurred. Corrective action shall be subject to 
modification when directed by the District Manager.
    (2) If the lessee fails to control and remove the pollution, the 
Director, in cooperation with other appropriate Agencies of Federal, 
State, and local governments, or in cooperation with the lessee, or 
both, shall have the right to control and remove the pollution at the 
lessee's expense. Such action shall not relieve the lessee of any 
responsibility provided for by law.
    (b)(1) The District Manager may restrict the rate of drilling fluid 
discharges or prescribe alternative discharge methods. The District 
Manager may also restrict the use of components 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

[[Page 127]]

facility's daily operations report, as appropriate, and reported to the 
District Manager.

[53 FR 10690, Apr. 1, 1988, as amended at 56 FR 32099, July 15, 1991. 
Redesignated at 63 FR 29479, May 29, 1998]



Sec. 250.301  Inspection of facilities.

    (a) 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.

[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 13996, Mar. 25, 1997. 
Redesignated at 63 FR 29479, May 29, 1998]



Sec. 250.302  Definitions concerning air quality.

    For purposes of Sec. Sec. 250.303 and 250.304 of this part:
    Air pollutant means any combination of agents for which the 
Environmental Protection Agency (EPA) has established, pursuant to 
section 109 of the Clean Air Act, national primary or secondary ambient 
air quality standards.
    Attainment area means, for any air pollutant, an area which is shown 
by monitored data or which 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 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 BACT shall be 
verified on a case-by-case basis by the Regional Supervisor and may 
include reductions achieved through the application of processes, 
systems, and techniques for the control of each air pollutant.
    Emission offsets means emission reductions obtained from facilities, 
either onshore or offshore, other than the facility or facilities 
covered by the proposed Exploration Plan or Development and Production 
Plan.
    Existing facility is an OCS facility described in an Exploration 
Plan or a Development and Production Plan submitted or approved prior to 
June 2, 1980.
    Facility means any installation or device permanently or temporarily 
attached to the seabed which is used for exploration, development, and 
production activities for oil, gas, or sulphur and which emits or has 
the potential to emit any air pollutant from one or more sources. All 
equipment directly associated with the installation or device shall be 
considered part of a single facility if the equipment is dependent on, 
or affects the processes of, the installation or device. During 
production, multiple installations or devices will be considered to be a 
single facility if the installations or devices are directly related to 
the production of oil, gas, or sulphur at a single site. Any vessel used 
to transfer production from an offshore facility shall be considered 
part of the facility while physically attached to it.
    Nonattainment area means, for any air pollutant, an area which is 
shown by monitored data or which 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.
    Projected emissions means emissions, either controlled or 
uncontrolled, from a source(s).
    Source means an emission point. Several sources may be included 
within a single facility.
    Temporary facility means activities associated with the construction 
of platforms offshore or with facilities related to exploration for or 
development of offshore oil and gas resources which are conducted in one 
location for less than 3 years.
    Volatile organic compound (VOC) means any organic compound which is 
emitted to the atmosphere as a vapor. The unreactive compounds are 
exempt from the above definition.

[53 FR 10690, Apr. 1, 1988, as amended at 56 FR 32100, July 15, 1991. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998]

[[Page 128]]



Sec. 250.303  Facilities described in a new or revised Exploration Plan or 

Development and Production Plan.

    (a) New plans. All Exploration Plans and Development and Production 
Plans shall include the information required to make the necessary 
findings under paragraphs (d) through (i) of this section, and the 
lessee shall comply with the requirements of this section as necessary.
    (b) Applicability of Sec. 250.303 to existing facilities. (1) The 
Regional Supervisor may review any Exploration Plan or Development and 
Production Plan to determine whether any facility described in the plan 
should be subject to review under this section and has the potential to 
significantly affect the air quality of an onshore area. To make these 
decisions, the Regional Supervisor shall consider the distance of the 
facility from shore, the size of the facility, the number of sources 
planned for the facility and their operational status, and the air 
quality status of the onshore area.
    (2) For a facility identified by the Regional Supervisor in 
paragraph (b)(1) of this section, the Regional Supervisor shall require 
the lessee to refer to the information required in Sec. 250.218 or 
Sec. 250.249 of this part and to submit only that information required 
to make the necessary findings under paragraphs (d) through (i) of this 
section. The lessee shall submit this information within 120 days of the 
Regional Supervisor's determination or within a longer period of time at 
the discretion of the Regional Supervisor. The lessee shall comply with 
the requirements of this section as necessary.
    (c) Revised facilities. All revised Exploration Plans and 
Development and Production Plans shall include the information required 
to make the necessary findings under paragraphs (d) through (i) of this 
section. The lessee shall comply with the requirements of this section 
as necessary.
    (d) Exemption formulas. To determine whether a facility described in 
a new, modified, or revised Exploration Plan or Development and 
Production Plan is exempt from further air quality review, the lessee 
shall use the highest annual-total amount of emissions from the facility 
for each air pollutant calculated in Sec. 250.249(a) or Sec. 
250.218(a) of this part and compare these emissions to the emission 
exemption amount ``E'' for each air pollutant calculated using the 
following formulas: E=3400D2/3 for carbon monoxide (CO); and 
E=33.3D for total suspended particulates (TSP), sulphur dioxide 
(SO2), nitrogen oxides (NOX), and VOC (where E is 
the emission exemption amount expressed in tons per year, and D is the 
distance of the proposed facility from the closest onshore area of a 
State expressed in statute miles). If the amount of these projected 
emissions is less than or equal to the emission exemption amount ``E'' 
for the air pollutant, the facility is exempt from further air quality 
review required under paragraphs (e) through (i) of this section.
    (e) Significance levels. For a facility not exempt under paragraph 
(d) of this section for air pollutants other than VOC, the lessee shall 
use an approved air quality model to determine whether the projected 
emissions of those air pollutants from the facility result in an onshore 
ambient air concentration above the following significance levels:

    Significance Levels: Air pollutant concentrations ([micro]g/m\3\)
------------------------------------------------------------------------
                                               Averaging time (hours)
               Air pollutant               -----------------------------
                                             Annual  24   8    3     1
------------------------------------------------------------------------
SO2.......................................        1   5  ...  25  ......
TSP.......................................        1   5  ...  ..  ......
NO2.......................................        1  ..  ...  ..  ......
CO........................................  .......  ..  500  ..   2,000
------------------------------------------------------------------------

    (f) Significance determinations. (1) The projected emissions of any 
air pollutant other than VOC from any facility which result in an 
onshore ambient air concentration above the significance level 
determined under paragraph (e) of this section for that air pollutant, 
shall be deemed to significantly affect the air quality of the onshore 
area for that air pollutant.
    (2) The projected emissions of VOC from any facility which is not 
exempt under paragraph (d) of this section for that air pollutant shall 
be deemed to significantly affect the air quality of the onshore area 
for VOC.
    (g) Controls required. (1) The projected emissions of any air 
pollutant other than VOC from any facility, except a temporary facility, 
which significantly

[[Page 129]]

affect the quality of a nonattainment area, shall be fully reduced. This 
shall be done through the application of BACT and, if additional 
reductions are necessary, through the application of additional emission 
controls or through the acquisition of offshore or onshore offsets.
    (2) The projected emissions of any air pollutant other than VOC from 
any facility which significantly affect the air quality of an attainment 
or unclassifiable area shall be reduced through the application of BACT.
    (i) Except for temporary facilities, the lessee also shall use an 
approved air quality model to determine whether the emissions of TSP or 
SO2 that remain after the application of BACT cause the 
following maximum allowable increases over the baseline concentrations 
established in 40 CFR 52.21 to be exceeded in the attainment or 
unclassifiable area:

        Maximum allowable concentration increases ([micro]g/m\3\)
------------------------------------------------------------------------
                                                    Averaging times
                                              --------------------------
                Air pollutant                   Annual
                                                 mean   24-hour   3-hour
                                                 \1\    maximum  maximum
------------------------------------------------------------------------
Class I:
  TSP........................................        5       10  .......
  SO2........................................        2        5       25
Class II:
  TSP........................................       19       37  .......
  SO2........................................       20       91      512
Class III:
  TSP........................................       37       75  .......
  SO2........................................       40      182     700
------------------------------------------------------------------------
\1\ For TSP--geometric; For SO2--arithmetric.


No concentration of an air pollutant shall exceed the concentration 
permitted under the national secondary ambient air quality standard or 
the concentration permitted under the national primary air quality 
standard, whichever concentration is lowest for the air pollutant for 
the period of exposure. For any period other than the annual period, the 
applicable maximum allowable increase may be exceeded during one such 
period per year at any one onshore location.
    (ii) If the maximum allowable increases are exceeded, the lessee 
shall apply whatever additional emission controls are necessary to 
reduce or offset the remaining emissions of TSP or SO2 so 
that concentrations in the onshore ambient air of an attainment or 
unclassifiable area do not exceed the maximum allowable increases.
    (3)(i) The projected emissions of VOC from any facility, except a 
temporary facility, which significantly affect the onshore air quality 
of a nonattainment area shall be fully reduced. This shall be done 
through the application of BACT and, if additional reductions are 
necessary, through the application of additional emission controls or 
through the acquisition of offshore or onshore offsets.
    (ii) The projected emissions of VOC from any facility which 
significantly affect the onshore air quality of an attainment area shall 
be reduced through the application of BACT.
    (4)(i) If projected emissions from a facility significantly affect 
the onshore air quality of both a nonattainment and an attainment or 
unclassifiable area, the regulatory requirements applicable to projected 
emissions significantly affecting a nonattainment area shall apply.
    (ii) If projected emissions from a facility significantly affect the 
onshore air quality of more than one class of attainment area, the 
lessee must reduce projected emissions to meet the maximum allowable 
increases specified for each class in paragraph (g)(2)(i) of this 
section.
    (h) Controls required on temporary facilities. The lessee shall 
apply BACT to reduce projected emissions of any air pollutant from a 
temporary facility which significantly affect the air quality of an 
onshore area of a State.
    (i) Emission offsets. When emission offsets are to be obtained, the 
lessee must demonstrate that the offsets are equivalent in nature and 
quantity to the projected emissions that must be reduced after the 
application of BACT; a binding commitment exists between the lessee and 
the owner or owners of the source or sources; the appropriate air 
quality control jurisdiction has been notified of the need to revise the 
State Implementation Plan to include the information regarding the 
offsets; and the required offsets come from sources which affect the air 
quality of the area significantly affected by the lessee's offshore 
operations.

[[Page 130]]

    (j) Review of facilities with emissions below the exemption amount. 
If, during the review of a new, modified, or revised Exploration Plan or 
Development and Production Plan, the Regional Supervisor determines or 
an affected State submits information to the Regional Supervisor which 
demonstrates, in the judgment of the Regional Supervisor, that projected 
emissions from an otherwise exempt facility will, either individually or 
in combination with other facilities in the area, significantly affect 
the air quality of an onshore area, then the Regional Supervisor shall 
require the lessee to submit additional information to determine whether 
emission control measures are necessary. The lessee shall be given the 
opportunity to present information to the Regional Supervisor which 
demonstrates that the exempt facility is not significantly affecting the 
air quality of an onshore area of the State.
    (k) Emission monitoring requirements. The lessee shall monitor, in a 
manner approved or prescribed by the Regional Supervisor, emissions from 
the facility. The lessee shall submit this information monthly in a 
manner and form approved or prescribed by the Regional Supervisor.
    (l) Collection of meteorological data. The Regional Supervisor may 
require the lessee to collect, for a period of time and in a manner 
approved or prescribed by the Regional Supervisor, and submit 
meteorological data from a facility.

[53 FR 10690, Apr. 1, 1988; 53 FR 19856, May 31, 1988; 53 FR 26067, July 
11, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 
70 FR 51518, Aug. 30, 2005]



Sec. 250.304  Existing facilities.

    (a) Process leading to review of an existing facility. (1) An 
affected State may request that the Regional Supervisor supply basic 
emission data from existing facilities when such data are needed for the 
updating of the State's emission inventory. In submitting the request, 
the State must demonstrate that similar offshore and onshore facilities 
in areas under the State's jurisdiction are also included in the 
emission inventory.
    (2) The Regional Supervisor may require lessees of existing 
facilities to submit basic emission data to a State submitting a request 
under paragraph (a)(1) of this section.
    (3) The State submitting a request under paragraph (a)(1) of this 
section may submit information from its emission inventory which 
indicates that emissions from existing facilities may be significantly 
affecting the air quality of the onshore area of the State. The lessee 
shall be given the opportunity to present information to the Regional 
Supervisor which demonstrates that the facility is not significantly 
affecting the air quality of the State.
    (4) The Regional Supervisor shall evaluate the information submitted 
under paragraph (a)(3) of this section and shall determine, based on the 
basic emission data, available meteorological data, and the distance of 
the facility or facilities from the onshore area, whether any existing 
facility has the potential to significantly affect the air quality of 
the onshore area of the State.
    (5) If the Regional Supervisor determines that no existing facility 
has the potential to significantly affect the air quality of the onshore 
area of the State submitting information under paragraph (a)(3) of this 
section, the Regional Supervisor shall notify the State of and explain 
the reasons for this finding.
    (6) If the Regional Supervisor determines that an existing facility 
has the potential to significantly affect the air quality of an onshore 
area of the State submitting information under paragraph (a)(3) of this 
section, the Regional Supervisor shall require the lessee to refer to 
the information requirements under Sec. 250.218 or 250.249 of this part 
and submit only that information required to make the necessary findings 
under paragraphs (b) through (e) of this section. The lessee shall 
submit this information within 120 days of the Regional Supervisor's 
determination or within a longer period of time at the discretion of the 
Regional Supervisor. The lessee shall comply with the requirements of 
this section as necessary.
    (b) Exemption formulas. To determine whether an existing facility is 
exempt from further air quality review, the

[[Page 131]]

lessee shall use the highest annual total amount of emissions from the 
facility for each air pollutant calculated in Sec. 250.218(a) or 
250.249(a) of this part and compare these emissions to the emission 
exemption amount ``E'' for each air pollutant calculated using the 
following formulas: E=3400D2/3 for CO; and E=33.3D for TSP, 
SO2, NOX, and VOC (where E is the emission 
exemption amount expressed in tons per year, and D is the distance of 
the facility from the closest onshore area of the State expressed in 
statute miles). If the amount of projected emissions is less than or 
equal to the emission exemption amount ``E'' for the air pollutant, the 
facility is exempt for that air pollutant from further air quality 
review required under paragraphs (c) through (e) of this section.
    (c) Significance levels. For a facility not exempt under paragraph 
(b) of this section for air pollutants other than VOC, the lessee shall 
use an approved air quality model to determine whether projected 
emissions of those air pollutants from the facility result in an onshore 
ambient air concentration above the following significance levels:

    Significance Levels: Air Pollutant Concentrations ([micro]G/M\3\)
------------------------------------------------------------------------
                                               Averaging time (hours)
               Air pollutant               -----------------------------
                                             Annual  24   8    3     1
------------------------------------------------------------------------
SO2.......................................        1   5  ...  25  ......
TSP.......................................        1   5  ...  ..  ......
NO2.......................................        1  ..  ...  ..  ......
CO........................................  .......  ..  500  ..   2,000
------------------------------------------------------------------------

    (d) Significance determinations. (1) The projected emissions of any 
air pollutant other than VOC from any facility which result in an 
onshore ambient air concentration above the significance levels 
determined under paragraph (c) of this section for that air pollutant 
shall be deemed to significantly affect the air quality of the onshore 
area for that air pollutant.
    (2) The projected emissions of VOC from any facility which is not 
exempt under paragraph (b) of this section for that air pollutant shall 
be deemed to significantly affect the air quality of the onshore area 
for VOC.
    (e) Controls required. (1) The projected emissions of any air 
pollutant which significantly affect the air quality of an onshore area 
shall be reduced through the application of BACT.
    (2) The lessee shall submit a compliance schedule for the 
application of BACT. If it is necessary to cease operations to allow for 
the installation of emission controls, the lessee may apply for a 
suspension of operations under the provisions of Sec. 250.174 of this 
part.
    (f) Review of facilities with emissions below the exemption amount. 
If, during the review of the information required under paragraph (a)(6) 
of this section, the Regional Supervisor determines or an affected State 
submits information to the Regional Supervisor which demonstrates, in 
the judgment of the Regional Supervisor, that projected emissions from 
an otherwise exempt facility will, either individually or in combination 
with other facilities in the area, significantly affect the air quality 
of an onshore area, then the Regional Supervisor shall require the 
lessee to submit additional information to determine whether control 
measures are necessary. The lessee shall be given the opportunity to 
present information to the Regional Supervisor which demonstrates that 
the exempt facility is not significantly affecting the air quality of an 
onshore area of the State.
    (g) Emission monitoring requirements. The lessee shall monitor, in a 
manner approved or prescribed by the Regional Supervisor, emissions from 
the facility following the installation of emission controls. The lessee 
shall submit this information monthly in a manner and form approved or 
prescribed by the Regional Supervisor.
    (h) Collection of meteorological data. The Regional Supervisor may 
require the lessee to collect, for a period of time and in a manner 
approved or prescribed by the Regional Supervisor, and submit 
meteorological data from a facility.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988. Redesignated and 
amended at 63 FR 29479, 29485, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 
70 FR 51519, Aug. 30, 2005]

[[Page 132]]



                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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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 MMS-144, Rig Movement Notification Report.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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

[[Page 133]]

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

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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 MMS-123) (see Sec. 
250.414(h)). Procedures for obtaining approval are described in section 
250.141 of this part.

[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 25201, May 4, 2007]



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)).

[68 FR 8423, Feb. 20, 2003]

                     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. 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);

[[Page 134]]

    (c) Meet the oil spill financial responsibility requirements for 
offshore facilities as required by 30 CFR part 253; and
    (d) Submit the following to the District Manager:
    (1) An original and two complete copies of Form MMS-123, Application 
for Permit to Drill (APD), and Form MMS-123S, Supplemental APD 
Information Sheet;
    (2) A separate public information copy of forms MMS-123 and MMS-123S 
that meets the requirements of Sec. 250.186; and
    (3) Payment of the service fee listed in Sec. 250.125.

[68 FR 8423, Feb. 20, 2003, as amended at 71 FR 40911, July 19, 2006; 72 
FR 25201, May 4, 2007]



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

    In addition to forms MMS-123 and MMS-123S, you must include the 
information described in the following table.

------------------------------------------------------------------------
 Information that you must include with an         Where to find a
                    APD                              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
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.414  What must my drilling prognosis include?

    Your drilling prognosis must include a brief description of the 
procedures

[[Page 135]]

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).

[68 FR 8423, Feb. 20, 2003]



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 (incorporated by reference as specified 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 RP 65-Part 2, Isolating Potential Flow Zones During Well 
Construction (incorporated by reference as specified in Sec. 250.198). 
Your written description must identify the mechanical barriers and 
cementing practices you will use for each casing string (reference API 
RP 65-Part 2, Sections 3 and 4).

[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 8903, Feb. 28, 2007; 75 
FR 63372, Oct. 14, 2010; 75 FR 76632, Dec. 9, 2010]



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;

[[Page 136]]

    (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 in the hole under maximum 
anticipated surface pressure. The documentation must include test 
results 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, 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 paragraph (e) in this section 
must be a technical classification society; an API-licensed 
manufacturing, inspection, or certification firm; or a licensed 
professional engineering firm capable of providing the verifications 
required under this part. The independent third party must not be the 
original equipment manufacturer (OEM).
    (2) You must:
    (i) Include evidence that the firm you are using is reputable, the 
firm or its employees hold appropriate licenses to perform the 
verification in the appropriate jurisdiction, the firm carries industry-
standard levels of professional liability insurance, and the firm has no 
record of violations of applicable law.
    (ii) Ensure that an official representative of BOEMRE will have 
access to the location to witness any testing or inspections, and verify 
information submitted to BOEMRE. Prior to any shearing ram tests or 
inspections, you must notify the District Manager at least 24 hours in 
advance.

[68 FR 8423, Feb. 20, 2003, as amended at 75 FR 63372, Oct. 14, 2010]



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, 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. 250.915 through Sec. 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

[[Page 137]]

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.

[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 25201, May 4, 2007]



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 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) Description of qualifications required by Sec. 250.416(f) of 
any independent third party; and
    (j) Such other information as the District Manager may require.

[68 FR 8423, Feb. 20, 2003, as amended at 75 FR 63372, Oct. 14, 2010]

                    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) Include certification signed by a Registered Professional 
Engineer that there will be at least two independent tested barriers, 
including one mechanical barrier, across each flow path during well 
completion activities and that the casing and cementing design is 
appropriate for the purpose for which it is intended under expected 
wellbore conditions. The Registered Professional Engineer must be 
registered in a State in the United States. Submit this certification 
with your APD (Form MMS-123).

[[Page 138]]

    (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) For the final casing string (or liner if it is your final 
string), you must install dual mechanical barriers in addition to 
cement, to prevent flow in the event of a failure in the cement. These 
may include dual float valves, or one float valve and a mechanical 
barrier. You must submit documentation to BOEMRE 30 days after 
installation of the dual mechanical barriers.
    (c) Cementing requirements. You must design and conduct your 
cementing jobs so that cement composition, placement techniques, and 
waiting times ensure that the cement placed behind the bottom 500 feet 
of casing attains a minimum compressive strength of 500 psi before 
drilling out of the casing or before commencing completion operations.

[68 FR 8423, Feb. 20, 2003, as amended at 75 FR 63373, Oct. 14, 2010]



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.

------------------------------------------------------------------------
                                        Casing             Cementing
           Casing type               requirements        requirements
------------------------------------------------------------------------
(a) Drive or Structural.........  Set by driving,     If you drilled a
                                   jetting, or         portion of this
                                   drilling to the     hole, you must
                                   minimum depth as    use enough cement
                                   approved or         to fill the
                                   prescribed by the   annular space
                                   District Manager.   back to the
                                                       mudline.
(b) Conductor...................  Design casing and   Use enough cement
                                   select setting      to fill the
                                   depths based on     calculated
                                   relevant            annular space
                                   engineering and     back to the
                                   geologic factors.   mudline.
                                   These factors      Verify annular
                                   include the         fill by observing
                                   presence or         cement returns.
                                   absence of          If you cannot
                                   hydrocarbons,       observe cement
                                   potential           returns, use
                                   hazards, and        additional cement
                                   water depths.       to ensure fill-
                                  Set casing           back to the
                                   immediately         mudline.
                                   before drilling    For drilling on an
                                   into formations     artificial island
                                   known to contain    or when using a
                                   oil or gas. If      glory hole, you
                                   you encounter oil   must discuss the
                                   or gas or           cement fill level
                                   unexpected          with the District
                                   formation           Manager.
                                   pressure before
                                   the planned
                                   casing point, you
                                   must set casing
                                   immediately.
(c) Surface.....................  Design casing and   Use enough cement
                                   select setting      to fill the
                                   depths based on     calculated
                                   relevant            annular space to
                                   engineering and     at least 200 feet
                                   geologic factors.   inside the
                                   These factors       conductor casing.
                                   include the        When geologic
                                   presence or         conditions such
                                   absence of          as near-surface
                                   hydrocarbons,       fractures and
                                   potential           faulting exist,
                                   hazards, and        you must use
                                   water depths.       enough cement to
                                                       fill the
                                                       calculated
                                                       annular space to
                                                       the mudline.
(d) Intermediate................  Design casing and   Use enough cement
                                   select setting      to cover and
                                   depth based on      isolate all
                                   anticipated or      hydrocarbon-
                                   encountered         bearing zones and
                                   geologic            isolate abnormal
                                   characteristics     pressure
                                   or wellbore         intervals from
                                   conditions.         normal 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
                                   select setting      to cover or
                                   depth based on      isolate all
                                   anticipated or      hydrocarbon-
                                   encountered         bearing zones
                                   geologic            above the shoe.
                                   characteristics    As a minimum, you
                                   or wellbore         must cement the
                                   conditions.         annular space at
                                                       least 500 feet
                                                       above the casing
                                                       shoe and 500 feet
                                                       above the
                                                       uppermost
                                                       hydrocarbon-
                                                       bearing zone.

[[Page 139]]

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


[68 FR 8423, Feb. 20, 2003]



Sec. 250.422  When may I resume drilling after cementing?

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

[68 FR 8423, Feb. 20, 2003]



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 re-cement, repair the casing, 
or run additional casing to provide a proper seal. The 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       70 percent of its minimum internal
 Production.                           yield.
------------------------------------------------------------------------

    (b) You must ensure proper installation of casing or liner in the 
subsea wellhead or liner hanger.
    (1) You must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon installation of each casing string or liner.
    (2) 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.
    (3) You must submit for approval with your APD, test procedures and 
criteria for a successful test.
    (4) You must document all your test results and make them available 
to BOEMRE upon request.
    (c) You must perform a negative pressure test on all wells to ensure 
proper casing installation. You must perform this test for the 
intermediate and production casing strings.
    (1) You must submit for approval with your APD, test procedures and 
criteria for a successful test.
    (2) You must document all your test results and make them available 
to BOEMRE upon request.

[75 FR 63373, Oct. 14, 2010]



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

[[Page 140]]

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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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     Submit a revised casing program to the
 pressures or conditions that      District Manager for approval.
 warrant revising your casing
 design.

[[Page 141]]

 
(b) Need to increase casing       Submit those changes to the District
 setting depths more than 100      Manager for approval.
 feet true vertical depth (TVD)
 from the approved APD due to
 conditions encountered during
 drilling operations.
(c) Have indication of            (1) Pressure test the casing shoe; (2)
 inadequate cement job (such as    Run a temperature survey; (3) Run a
 lost returns, cement              cement bond log; or (4) Use a
 channeling, or failure of         combination of these techniques.
 equipment).
(d) Inadequate cement job.......  Re-cement or take other remedial
                                   actions as approved by the District
                                   Manager.
(e) Primary cement job that did   Isolate those intervals from normal
 not isolate abnormal pressure     pressures by squeeze cementing before
 intervals.                        you complete; suspend operations; or
                                   abandon the well, whichever occurs
                                   first.
(f) Decide to produce a well      Have at least two cemented casing
 that was not originally           strings (does not include liners) in
 contemplated for production.      the well. Note: All producing wells
                                   must have at least two cemented
                                   casing strings.
(g) Want to drill a well without  Submit geologic data and information
 setting conductor casing.         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         Submit information to the District
 required cement for the surface   Manager that demonstrates the use of
 casing during floating drilling   less cement is necessary.
 operations to provide
 protection from burst and
 collapse pressures.
(i) Cement across a permafrost    Use cement that sets before it freezes
 zone.                             and has a low heat of hydration.
(j) Leave the annulus opposite a  Fill the annulus with a liquid that
 permafrost zone uncemented.       has a freezing point below the
                                   minimum permafrost temperature and
                                   minimizes opposite a corrosion.
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]

                      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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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 142]]



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


[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]

               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.

[68 FR 8423, Feb. 20, 2003]



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.

[[Page 143]]

    (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 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.

[68 FR 8423, Feb. 20, 2003, as amended at 74 FR 46908, Sept. 14, 2009]



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 annular
 controlled, hydraulically operated   BOP, two BOPs equipped with pipe
 BOPs.                                rams, and one BOP equipped with
                                      blind-shear rams. The blind-shear
                                      rams must be capable of shearing
                                      any drill pipe 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 meet or
 provide fast closure of the BOP      exceed the provisions of Section
 components and to operate all        13.3, Accumulator Volumetric
 critical functions in case of a      Capacity, in API RP 53,
 loss of the power fluid connection   Recommended Practices for Blowout
 to the surface.                      Prevention Equipment Systems for
                                      Drilling Wells (incorporated by
                                      reference as specified in Sec.
                                      250.198). The District Manager may
                                      approve a suitable alternate
                                      method.
(d) Have a subsea BOP stack          At a minimum, the ROV must be
 equipped with remotely operated      capable of closing one set of pipe
 vehicle (ROV) intervention           rams, closing one set of blind-
 capability.                          shear rams and unlatching the
                                      LMRP.
(e) Maintain an ROV and have a       The crew must be trained in the
 trained ROV crew on each floating    operation of the ROV. The training
 drilling rig on a continuous         must include simulator training on
 basis. The crew must examine all     stabbing into an ROV intervention
 ROV related well control equipment   panel on a subsea BOP stack.
 (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 safety
 systems for dynamically positioned   system that is designed to
 rigs.                                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 the shear rams. This is
                                      considered a ``rapid discharge''
                                      system.
                                     (2) Deadman System means a safety
                                      system that is designed to
                                      automatically close the wellbore
                                      in the event of a simultaneous
                                      absence of hydraulic supply and
                                      signal transmission capacity in
                                      both subsea control pods. This is
                                      considered a ``rapid discharge''
                                      system.
                                     (3) You may also have an acoustic
                                      system.
(g) Have operational or physical     Incorporate enable buttons on
 barrier(s) on BOP control panels     control panels to ensure two-
 to prevent accidental disconnect     handed operation for all critical
 functions.                           functions.
(h) Clearly label all control        Label other BOP control panels such
 panels for the subsea BOP system.    as hydraulic control panel.
(i) Develop and use a management     The management system must include
 system for operating the BOP         written procedures for operating
 system, including the prevention     the BOP stack and LMRP (including
 of accidental or unplanned           proper techniques to prevent
 disconnects of the system.           accidental disconnection of these
                                      components) and minimum knowledge
                                      requirements for personnel
                                      authorized to operate and maintain
                                      BOP components.
(j) Establish minimum requirements   Personnel must have:
 for 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       You must maintain sufficient
 riser, displace the fluid in the     hydrostatic pressure or take other
 riser with seawater.                 suitable precautions to compensate
                                      for the reduction in pressure and
                                      to maintain a safe and controlled
                                      well condition.

[[Page 144]]

 
(l) Install the BOP stack in a       Your glory hole must be deep enough
 glory hole when in ice-scour area.   to ensure that the top of the
                                      stack is below the deepest
                                      probable ice-scour depth.
------------------------------------------------------------------------


[75 FR 63373, Oct. 14, 2010]



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 surface pressure.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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

[[Page 145]]

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 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.

[68 FR 8423, Feb. 20, 2003]



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 the 
procedures used, record the results of your BOP inspections and 
maintenance actions, and make available to BOEMRE upon request. You must 
maintain your records on the rig for 2 years or from the date of your 
last major inspection, whichever is longer;
    (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.

[68 FR 8423, Feb. 20, 2003, as amended at 75 FR 63374, Oct. 14, 2010]



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.

[68 FR 8423, Feb. 20, 2003]



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

[[Page 146]]

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 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).

[68 FR 8423, Feb. 20, 2003]



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;
    (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. You must also test at least one set of rams 
during the initial test on the seafloor. You must submit test procedures 
with your APD or APM for 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 and one set of 
blind-shear rams and unlatching the LMRP; and
    (2) document all your test results and make them available to BOEMRE 
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 
during the initial test on the seafloor.
    (1) You must submit test procedures with your APD or APM for 
District Manager approval.
    (2) You must document all your test results and make them available 
to BOEMRE upon request.

[68 FR 8423, Feb. 20, 2003, as amended at 75 FR 63374, Oct. 14, 2010]



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 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

[[Page 147]]

tests, actuations, and inspections at the facility for the duration of 
drilling.

[68 FR 8423, Feb. 20, 2003]



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.                                 glory hole. The glory hole
                                             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.
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003, as amended at 75 FR 63374, Oct. 14, 2010]

                       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.

[68 FR 8423, Feb. 20, 2003]



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.
    (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;

[[Page 148]]

    (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 displacing kill-weight drilling fluid from the wellbore, 
you must obtain prior approval from the District Manager. To obtain 
approval, you must submit with your APD or APM your reasons for 
displacing the kill-weight drilling 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 that are in place for 
each flow path,
    (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 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.

[68 FR 8423, Feb. 20, 2003; 68 FR 14274, Mar. 24, 2003, as amended at 75 
FR 63374, Oct. 14, 2010]



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

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

[[Page 149]]

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.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]



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 (incorporated by reference as specified 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 (incorporated by 
reference as specified 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.

[68 FR 8423, Feb. 20, 2003]

                       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 MMS-123) or in an 
Application for Permit to Modify (APM) (form MMS-124). 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;

[[Page 150]]

    (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.

[68 FR 8423, Feb. 20, 2003]



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

    For this subpart, MMS 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.

[68 FR 8423, Feb. 20, 2003]



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.
    (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) MMS ordered drill. An MMS authorized representative may require 
you to conduct a well control drill during an MMS inspection. The MMS 
representative will consult with your onsite representative before 
requiring the drill.

[68 FR 8423, Feb. 20, 2003]



Sec. 250.463  Who establishes field drilling rules?

    (a) The District Manager may establish field drilling rules 
different from

[[Page 151]]

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.

[68 FR 8423, Feb. 20, 2003]

            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 MMS?

    (a) You must submit an APM (form MMS-124) or an End of Operations 
Report (form MMS-125) 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 your       Submit form MMS-   Receive written or
 drilling plan, change major     124 or request     oral approval from
 drilling equipment, or          oral approval.     the District Manager
 plugback.                                          before you begin the
                                                    intended operation.
                                                    If you get an
                                                    approval, you must
                                                    submit form MMS-124
                                                    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 final    Immediately        Submit a plat
 surface location, water         Submit a form      certified by a
 depth, and the rotary kelly     MMS-124.           registered land
 bushing elevation.                                 surveyor that meets
                                                    the requirements of
                                                    Sec.  250.412.
(3) Move a drilling unit from   Submit forms MMS-  Submit appropriate
 a wellbore before completing    124 and MMS-125    copies of the well
 a well.                         within 30 days     records.
                                 after 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 MMS-124) 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 MMS-124 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 
MMS-124 with detailed information about the work to the District 
Manager, unless you have already provided sufficient information in a 
Well Activity Report, form MMS-133 (Sec. 250.468(b)).

[68 FR 8423, Feb. 20, 2003, as amended at 71 FR 40911, July 19, 2006]



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;
    (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

[[Page 152]]

the protection of correlative rights, safety, and environment.

[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 25201, May 4, 2007]



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 completion
 diverter tests, and BOP tests.           of drilling operations.
(c) Completion of a well or of any       You permanently plug and
 workover activity that materially        abandon the well or until you
 alters the completion configuration or   forward the records with a
 affects a hydrocarbon-bearing zone.      lease assignment.
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]



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 MMS. 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 MMS-133, 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 MMS-133, Well Activity Report, to the District 
Manager on a daily basis.

[68 FR 8423, Feb. 20, 2003]



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.

[68 FR 8423, Feb. 20, 2003]

                            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:

[[Page 153]]

    (1) Drilling, logging, coring, testing, or producing operations have 
confirmed the absence of H2S in concentrations that could 
potentially result in atmospheric concentrations of 20 ppm or more of 
H2S; or
    (2) Drilling in the surrounding areas and correlation of geological 
and seismic data with equivalent stratigraphic units have confirmed an 
absence of H2S throughout the area to be drilled.
    H2S present means that drilling, logging, coring, 
testing, or producing operations have confirmed the presence 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 MMS 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;

[[Page 154]]

    (10) The agencies and facilities you will notify in case of a 
release of H2S (that constitutes an emergency), how you will 
notify them, and their telephone numbers. Include all facilities that 
might be exposed to atmospheric concentrations of 20 ppm or more of 
H2S;
    (11) The medical personnel and facilities you will use if needed, 
their addresses, and telephone numbers;
    (12) H2S detector locations in production facilities 
producing gas containing 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,

[[Page 155]]

warning systems, evacuation procedures, and the direction of prevailing 
winds;
    (iv) Restrictions and corrective measures concerning beards, 
spectacles, and contact lenses in conformance with ANSI Z88.2, American 
National Standard for Respiratory Protection (incorporated by reference 
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

[[Page 156]]

responsible persons must inform personnel of the level of danger and 
issue instructions on the initiation of appropriate protective measures.
    (j) H2S-detection and H2S monitoring 
equipment--(1) What are the requirements for an H2S detection 
system? An H2S detection system must:
    (i) Be capable of sensing a minimum of 10 ppm of H2S in 
the atmosphere; and
    (ii) Activate audible and visual alarms when the concentration of 
H2S in the atmosphere reaches 20 ppm.
    (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.

[[Page 157]]

    (ii) When conducting production operations, test all detectors at 
least every 14 days between tests.
    (iii) If equipment requires calibration as a result of two 
consecutive functional tests, the District Manager may require that 
H2S-detection and H2S-monitoring equipment be 
functionally tested and calibrated more frequently.
    (8) What documentation must I keep?--(i) You must maintain records 
of testing and calibrations (in the drilling or production operations 
report, as applicable) at the facility to show the present status and 
history of each device, including dates and details concerning:
    (A) Installation;
    (B) Removal;
    (C) Inspection;
    (D) Repairs;
    (E) Adjustments; and
    (F) Reinstallation.
    (ii) Records must be available for inspection by MMS 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 SO2 concentration 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 (incorporated by reference 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.

[[Page 158]]

    (ix) As appropriate to the particular operation(s), (production, 
drilling, well-completion or well-workover operations, or any 
combination of them), provide a system of breathing-air manifolds, 
hoses, and masks at the facility and the briefing areas. You must 
provide a cascade air-bottle system for the breathing-air manifolds to 
refill individual protective-breathing apparatus bottles. The cascade 
air-bottle system may be recharged by a high-pressure compressor 
suitable for providing breathing-quality air, provided the compressor 
suction is located in an uncontaminated atmosphere.
    (k) Personnel safety equipment--(1) What additional personnel-safety 
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 MMS in the event of an H2S release? You must 
notify MMS 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

[[Page 159]]

burn them in a closed flare system conforming to paragraph (q)(6) of 
this section.
    (n) What must I do in the event of a kick? In the event of a kick, 
you must use one of the following alternatives to dispose of the well-
influx fluids giving consideration to personnel safety, possible 
environmental damage, and possible facility well-equipment damage:
    (1) Contain the well-fluid influx by shutting in the well and 
pumping the fluids back into the formation.
    (2) Control the kick by using appropriate well-control techniques to 
prevent formation fracturing in an open hole within the pressure limits 
of the 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 H\2\S-bearing fluids in conformance 
with NACE Standard MR0175-03 (incorporated by reference 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.

[[Page 160]]

    (q) General requirements when operating in an H2S zone--
(1) Coring operations. When you conduct coring operations in 
H2S-bearing zones, all personnel in the working area must 
wear protective-breathing equipment at least 10 stands in advance of 
retrieving the core barrel. Cores to be transported must be sealed and 
marked for the presence of H2S.
    (2) Logging operations. You must treat and condition well-control 
fluid in use for logging operations to minimize the effects of 
H2S on the logging equipment.
    (3) Stripping operations. Personnel must monitor displaced well-
control fluid returns and wear protective-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

[[Page 161]]

by atomic hydrogen when H2S is present.

[62 FR 3795, Jan. 27, 1997. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 65 FR 15864, Mar. 24, 2000. Redesignated and 
amended at 68 FR 8423, 8434, Feb. 20, 2003; 71 FR 19645, Apr. 17, 2006; 
72 FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007; 75 FR 20289, Apr. 
19, 2010]



            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 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.

[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 47752, Nov. 15, 1990. 
Redesignated at 63 FR 29479, May 29, 1998]



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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 68 FR 8434, Feb. 20, 2003]



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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998]



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

[[Page 162]]

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 MMS 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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989. 
Redesignated at 63 FR 29479, May 29, 1998]



Sec. 250.510  Diesel engine air intakes.

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

[74 FR 46908, Sept. 14, 2009]



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.

[74 FR 46908, Sept. 14, 2009]



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 MMS-123 and MMS-
123S), 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 MMS-124) for approval of such operations.
    (b) You must submit the following with Form MMS-124 (or with Form 
MMS-123; Form MMS-123S):
    (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) When the well-completion is in a zone known to contain 
H2S or a zone where the presence of H2S is 
unknown,

[[Page 163]]

information pursuant to Sec. 250.490 of this part; and
    (5) 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 MMS-125), including a 
schematic of the tubing and subsurface equipment.
    (d) You must submit public information copies of Form MMS-125 
according to Sec. 250.186.

[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 64 FR 
72794, Dec. 28, 1999; 68 FR 8434, Feb. 20, 2003; 71 FR 19646, Apr. 17, 
2006; 71 FR 40911, July 19, 2006; 72 FR 25201, May 4, 2007]



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

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



Sec. 250.515  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 MMS-124 or Form 
MMS-123, 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      Three BOPs consisting of an
 than 5,000 psi,.                       annular, one set of pipe rams,
                                        and one set of blind-shear rams.
(2) The expected pressure is 5,000     Four BOPs consisting of an
 psi or greater or you use multiple     annular, two sets of pipe rams,
 tubing strings,.                       and one set of blind-shear rams.
(3) You handle multiple tubing         Four BOPs consisting of an
 strings 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.
------------------------------------------------------------------------


[[Page 164]]

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

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989; 58 
FR 49928, Sept. 24, 1993. Redesignated at 62 29479, May 29, 1998, as 
amended at 68 FR 8434, Feb. 20, 2003; 74 FR 46908, Sept. 14, 2009; 75 FR 
63375, Oct. 14, 2010]



Sec. 250.516  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

[[Page 165]]

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 subsurface BOP system before installation. You must 
use water to stump test a subsea BOP system. You may use drilling or 
completion fluids to conduct subsequent tests of a subsea BOP system;
    (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. You must also test at least one set of rams 
during the initial test on the seafloor. You must submit test procedures 
with your APM for 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 
BOEMRE upon request; and
    (9) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system 
during the initial test on the seafloor.
    (i) You must submit test procedures with your APM for District 
Manager approval.
    (ii) You must document all your test results and make them available 
to BOEMRE 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 the procedures used, 
record the results, and make them available to BOEMRE upon request. You 
must maintain your records on the rig for 2 years or from the date of 
your last major inspection, whichever is longer.
    (2) You must visually inspect your BOP system and marine riser at 
least once each day if weather and sea conditions permit. You may use 
television cameras to inspect this equipment. The 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 the procedures used, record the results, and 
make available to BOEMRE upon request. You must maintain your records on 
the rig for 2 years or from the date of your last major inspection, 
whichever is longer.
    (i) BOP test records. You must record the time, date, and results of 
all pressure tests, actuations, crew drills, and

[[Page 166]]

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
    (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.

[63 FR 29607, June 1, 1998, as amended at 75 FR 63375, Oct. 14, 2010]



Sec. 250.517  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:

------------------------------------------------------------------------
                                 you must equip *   so you can monitor *
       If you have * * *               * *                  * *
------------------------------------------------------------------------
(1) fixed platform wells,.....  the wellhead,....  all annuli (A, B, C,
                                                    D, etc., annuli).
(2) subsea wells,.............  the tubing head,.  the production casing
                                                    annulus (A annulus).
(3) hybrid* wells,............  the surface        all annuli at the
                                 wellhead,.         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.

[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 47753 Nov. 15, 1990. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 75 FR 
23584, May 4, 2010]

                       Casing Pressure Management

    Source: 75 FR 23584, May 4, 2010, unless otherwise noted.

[[Page 167]]



Sec. 250.518  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 (incorporated by reference as 
specified 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.



Sec. 250.519  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
       If you have * * *         you must monitor   pressure data 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     daily,...........  day for each casing.
 casing pressure request on a
 manned fixed platform,
(e) wells operating under a     weekly,..........  week for each casing.
 casing pressure request on an
 unmanned fixed platform,
------------------------------------------------------------------------



Sec. 250.520  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 diagnostic
        If you have a * * *                     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.



Sec. 250.521  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.



Sec. 250.522  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         immediately.
 approved term has expired,.
(b) your well, previously on gas lift,   immediately on the production
 has been shut-in or returned to          casing (A annulus). The
 flowing status without gas lift for      production casing (A annulus)
 more than 180 days,                      of wells on active gas lift
                                          are exempt from diagnostic
                                          testing.
(c) your casing pressure request         within 30 days.
 becomes invalid,.
(d) a casing or riser has an increase    within 30 days.
 in pressure greater than 200 psig over
 the previous casing diagnostic test,
(e) after any corrective action has      within 30 days.
 been taken to remediate undesirable
 casing pressure, either as a result of
 a casing pressure request denial or
 any other action,

[[Page 168]]

 
(f) your fixed platform well production  once per year, not to exceed 12
 casing (A annulus) has pressure          months between tests.
 exceeding 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,
------------------------------------------------------------------------



Sec. 250.523  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.



Sec. 250.524  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.



Sec. 250.525  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:           to the appropriate:      and it must include:        You must also:
----------------------------------------------------------------------------------------------------------------
(a) a notification of corrective       District Manager and     requirements under Sec. submit an Application
 action; or,                            copy the Regional          250.526.               for Permit to Modify
                                        Supervisor, Field                                 or Corrective Action
                                        Operations,                                       Plan within 30 days of
                                                                                          the diagnostic test.
(b) a casing pressure request,.......  Regional Supervisor,     requirements under Sec.
                                        Field Operations,          250.527.
----------------------------------------------------------------------------------------------------------------



Sec. 250.526  What must I include in my notification of corrective action?

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



Sec. 250.527  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);

[[Page 169]]

    (l) Well status (shut-in, temporarily abandoned, producing, 
injecting, or gas lift);
    (m) Well type (dry tree, hybrid, or subsea);
    (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.



Sec. 250.528  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.



Sec. 250.529  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).



Sec. 250.530  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.



             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:
    (a) Cutting paraffin;
    (b) Removing and setting pump-through-type tubing plugs, gas-lift

[[Page 170]]

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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 71 FR 11313, Mar. 7, 2006]



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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 64 FR 9065, Feb. 24, 1999; 68 FR 8435, Feb. 20, 
2003]



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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998]



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

[[Page 171]]

meetings shall be recorded and available at the facility for review by a 
Minerals Management Service representative.



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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989. 
Redesignated at 63 FR 29479, May 29, 1998]



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 MMS-124, Application for Permit to 
Modify.
    (b) You must submit the following with Form MMS-124:
    (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) 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
    (4) Payment of the service fee listed in Sec. 250.125.
    (c) The following additional information shall be submitted with 
Form MMS-124 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.

[[Page 172]]

    (d) Within 30 days after completing the well-workover operation, 
except routine operations, Form MMS-124, 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 MMS-125, 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.

[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 65 FR 
35824, June 6, 2000; 68 FR 8435, Feb. 20, 2003; 71 FR 40912, July 19, 
2006; 72 FR 25201, May 4, 2007]



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.



Sec. 250.615  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 MMS-124, 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      Three BOPs consisting of an
 than 5,000 psi,.                       annular, one set of pipe rams,
                                        and one set of blind-shear rams.
(2) The expected pressure is 5,000     Four BOPs consisting of an
 psi or greater or you use multiple     annular, two sets of pipe rams,
 tubing strings,.                       and one set of blind-shear rams.
(3) You handle multiple tubing         Four BOPs consisting of an
 strings simultaneously,.               annular, one set of pipe rams,
                                        one set of dual pipe rams, and
                                        one set of blind-shear rams.

[[Page 173]]

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


[[Page 174]]

    (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 MMS-124, Application for Permit to Modify and have 
it approved by the District Manager.
    (5) You must have a kill line and a separate choke line. You must 
equip each line with two full-opening valves and at least one of the 
valves must be remotely controlled. You may use a manual valve instead 
of the remotely controlled valve on the kill line if you install a check 
valve between the two full-opening manual valves and the pump or 
manifold. The valves must have a working pressure rating equal to or 
greater than the working pressure rating of the connection to which they 
are attached, and you must install them between the well control stack 
and the choke or kill line. For operations with expected surface 
pressures greater than 3,500 psi, the kill line must be connected to a 
pump or manifold. You must not use the kill line inlet on the BOP stack 
for taking fluid returns from the wellbore.
    (6) You must have a hydraulic-actuating system that provides 
sufficient accumulator capacity to close-open-close each component in 
the BOP stack. This cycle must be completed with at least 200 psi above 
the pre-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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989; 58 
FR 49928, Sept. 24, 1993. Redesignated at 63 FR 29479, May 29, 1998, as 
amended at 68 FR 8435, Feb. 20, 2003; 71 FR 11313, Mar. 7, 2006; 71 FR 
29710, May 23, 2006; 74 FR 46908, Sept. 14, 2009; 75 FR 63375, Oct. 14, 
2010]



Sec. 250.616  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.

[[Page 175]]

    (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) 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.
    (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-workover operations shall 
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 Form 
MMS-124, Application for Permit to Modify, and must be approved by the 
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 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 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 MMS 
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

[[Page 176]]

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:
    (1) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. You must also test at least one set of rams 
during the initial test on the seafloor. You must submit test procedures 
with your APM for 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 
BOEMRE 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 
during the initial test on the seafloor. You must:
    (i) Submit test procedures with your APM for District Manager 
approval.
    (ii) Document the results of each test and make them available to 
BOEMRE upon request.
    (3) Use water to stump test a subsea BOP system. You may use 
drilling or completion fluids to conduct subsequent tests of a subsea 
BOP system.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 56 
FR 1915, Jan. 18, 1991. Redesignated at 63 FR 29479, May 29, 1998; 71 FR 
11313, Mar. 7, 2006; 75 FR 63376, Oct. 14, 2010]



Sec. 250.617  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 the procedures used, 
record the results, and make them available to BOEMRE upon request. You 
must maintain your records on the rig for 2 years or from the date of 
your last major inspection, whichever is longer.
    (2) You must visually inspect your BOP system and marine riser at 
least once each day if weather and sea conditions permit. You may use 
television cameras to inspect this equipment. The 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 the procedures used, record the results, and 
make them available to BOEMRE upon request. You must maintain your 
records on the rig for 2 years or from the date of your last major 
inspection, whichever is longer.

[75 FR 63376, Oct. 14, 2010]



Sec. 250.618  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:

[[Page 177]]



------------------------------------------------------------------------
                                 you must equip *   so you can monitor *
       If you have * * *               * *                  * *
------------------------------------------------------------------------
(i) fixed platform wells,.....  the wellhead,....  all annuli (A, B, C,
                                                    D, etc., annuli).
(ii) subsea wells,............  the tubing head,.  the production casing
                                                    annulus (A annulus).
(iii) hybrid* wells,..........  the surface        all annuli at the
                                 wellhead,.         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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990. Redesignated and amended at 63 FR 29479, 29485, 
May 29, 1998; 75 FR 23586, May 4, 2010. Further redesignated at 75 FR 
63376, Oct. 14, 2010]



Sec. 250.619  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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998. Further redesignated at 75 FR 63376, Oct. 14, 2010]

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 (incorporated by reference as specified 
in 30 CFR 250.198);
    (2) Meet the drilling and production riser standards of API RP 2RD 
(incorporated by reference as specified in 30 CFR 250.198);
    (3) Design all stationkeeping systems for floating facilities to 
meet the standards of API RP 2SK (incorporated by reference as specified 
in 30 CFR

[[Page 178]]

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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 70 FR 41574, July 19, 2005]



Sec. 250.801  Subsurface safety devices.

    (a) General. All tubing installations open to hydrocarbon-bearing 
zones 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 SSSV's. Surface-controlled and subsurface-
controlled SSSV's 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 SSSV's. 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 SSSV's. Wells may be equipped with 
subsurface-controlled SSSV's 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 SSSV's 
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 SSSV's. The SSSV's 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 SSSV's 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 (incorporated by reference 
as specified in Sec. 250.198).
    (f) Subsurface safety devices in shut-in wells. New completions 
(perforated but not placed on production) and completions shut in for a 
period of 6 months shall be equipped with either (1) a pump-through-type 
tubing plug; (2) a surface-controlled SSSV, provided the surface control 
has been rendered inoperative; or (3) an injection valve capable of 
preventing backflow. The setting

[[Page 179]]

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 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 MMS-124, 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 SSSV's 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 SSSV's 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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 58 
FR 49928, Sept. 24, 1993. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 72 FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 
2007]



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 (incorporated by reference as specified in Sec. 
250.198). If you use processing components other than those for which 
Safety Analysis Checklists are included in API RP 14C you must utilize 
the analysis technique and documentation specified 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 SSV's, USV's, and their actuators 
which are

[[Page 180]]

installed in the OCS shall conform to the requirements in Sec. 250.806 
of this part.
    (d) Use of SSV's 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 
(incorporated by reference as specified 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.
    (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, 
incorporated by reference as specified in Sec. 250.198) and the related 
Safety analysis Function Evaluation chart (API RP 14C, subsection 4.3c, 
incorporated by reference as specified 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 
(incorporated by reference as specified 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 (incorporated by reference as specified 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

[[Page 181]]

involved in the review and approval process.

[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60024, Nov. 26, 1996. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 65 FR 219, 
Jan. 4, 2000; 67 FR 51759, Aug. 9, 2002; 71 FR 40912, July 19, 2006; 72 
FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007]



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 
(incorporated by reference as specified in 30 CFR 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 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) (incorporated by reference as specified 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 (incorporated by reference as specified 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

[[Page 182]]

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 
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 
(incorporated by reference as specified in 30 CFR 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 MMS District Manager the manufacturer's design 
specifications for the unbonded flexible pipe; and
    (D) Submit to the MMS District Manager a statement certifying that 
the pipe is suitable for its intended use and that the manufacturer has 
complied with the IVA requirements of API Spec 17J (incorporated by 
reference as specified in 30 CFR 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 (incorporated by reference as specified 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) (incorporated by reference as specified 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

[[Page 183]]

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 (incorporated by reference as specified 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 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 (incorporated by reference as specified 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

[[Page 184]]

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 (incorporated by reference as specified in 
Sec. 250.198), or any area classified Class I, Zone 0, Zone 1, or Zone 
2, following the guidelines of API RP 505 (incorporated by reference as 
specified in Sec. 250.198).
    (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.
    (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 incorporated by 
reference as specified 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 MMS 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 (incorporated by reference as specified 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.

[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13, 1988. Redesignated at 
63 FR 29479, 29485, May 29, 1998]

    Editorial Note: For Federal Register citations affecting Sec. 
250.803, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.fdsys.gov.



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

[[Page 185]]

with API RP 14C, Appendix D (incorporated by reference as specified 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 
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.
    (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 
(incorporated by reference as specified 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 (incorporated by reference as 
specified 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.

[[Page 186]]

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 MMS. The records shall show the present status and 
history of each device, including dates and details of installation, 
removal, inspection, testing, repairing, adjustments, and 
reinstallation.

[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 47753, Nov. 15, 1990; 62 
FR 5331, Feb. 5, 1997. Redesignated at 63 FR 29479, May 29, 1998, as 
amended at 65 FR 35824, June 6, 2000; 67 FR 51760, Aug. 9, 2002; 68 FR 
47, Jan. 2, 2003]



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 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 MMS recognizes. MMS 
considers all other SPPE as noncertified. MMS 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; and
    (ii) API Spec Q1, Specification for Quality Programs for the 
Petroleum, Petrochemical and Natural Gas Industry (incorporated by 
reference as specified 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 (incorporated by reference as specified 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 MMS 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

[[Page 187]]

such as welding, you must replace it with certified SPPE.
    (c) Recognizing other quality assurance programs. The MMS will 
consider recognizing other quality assurance programs covering the 
manufacture of SPPE. If you want MMS to evaluate other quality assurance 
programs, submit relevant information about the program and reasons for 
recognition by MMS to the Chief, Office of Offshore Regulatory Programs; 
Minerals Management Service; MS-4020; 381 Elden Street, Herndon, 
Virginia 20170-4817.

[62 FR 42671, Aug. 8, 1997. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 63 FR 37068, July 9, 1998; 65 FR 76935, Dec. 8, 2000; 72 
FR 12096, Mar. 15, 2007; 73 FR 20171, Apr. 15, 2008; 75 FR 1279, Jan. 
11, 2010; 75 FR 22226, Apr. 28, 2010]



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.
    (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.

[75 FR 1280, Jan. 11, 2010]



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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 68 FR 8435, Feb. 20, 2003. Further redesignated at 
75 FR 1280, Jan. 11, 2010]



                   Subpart I_Platforms and Structures

    Source: 70 FR 41575, July 19, 2005, unless otherwise noted.

                   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

[[Page 188]]

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           (i) You must adhere to the
 platform. This includes any             requirements of this subpart,
 structural changes that materially      including the industry
 alter the approved plan or cause a      standards in Sec.  250.901.
 major deviation from approved          (ii) Before you make a major
 operations and any modification that    modification to a floating
 increases loading on a platform by 10   platform, you must obtain
 percent or more.                        approval from both the MMS and
                                         the USCG for the modification.
(3) Major repair of damage to any       (i) You must adhere to the
 platform. This includes any             requirements of this subpart,
 corrective operations involving         including the industry
 structural members affecting the        standards in Sec.  250.901.
 structural integrity of a portion or   (ii) Before you make a major
 all of the platform.                    repair to a floating platform,
                                         you must obtain approval from
                                         both the MMS and the USCG for
                                         the repair.
(4) Convert an existing platform at     (i) The Regional Supervisor will
 the current location for a new          determine on a case-by-case
 purpose.                                basis the requirements for an
                                         application for conversion of
                                         an existing platform at the
                                         current location.
                                        (ii) At a minimum, your
                                         application must include: the
                                         converted platform's intended
                                         use; and a demonstration of the
                                         adequacy of the design and
                                         structural condition of the
                                         converted platform.
                                        (iii) If a floating platform,
                                         you must also adhere to USCG
                                         regulations for the
                                         fabrication, installation, and
                                         inspection of floating OCS
                                         facilities.
(5) Convert an existing mobile          (i) The Regional Supervisor will
 offshore drilling unit (MODU) for a     determine on a case-by-case
 new purpose.                            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 MMS 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. 
250.909-250.918 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), MMS will cancel the approved platform application 1 year after 
the approval has been granted if the platform has not been installed. If 
MMS cancels the approval, you must resubmit your platform application 
and receive MMS 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, MMS will 
identify the date when the installation approval will be cancelled (if 
installation has not occurred) during the application and approval 
process. If MMS cancels your installation approval, you must resubmit 
your platform application and receive

[[Page 189]]

MMS approval if you still plan to install the platform.

[70 FR 41575, July 19, 2005; 71 FR 16859, Apr. 4, 2006, as amended at 73 
FR 20171, Apr. 15, 2008; 73 FR 64546, Oct. 30, 2008]



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, 
(incorporated by reference as specified in Sec. 250.198);
    (4) American Petroleum Institute (API) Bulletin 2INT-DG, Interim 
Guidance for Design of Offshore Structures for Hurricane Conditions, 
(incorporated by reference as specified in Sec. 250.198);
    (5) API Bulletin 2INT-EX, Interim Guidance for Assessment of 
Existing Offshore Structures for Hurricane Conditions, (incorporated by 
reference as specified in Sec. 250.198);
    (6) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions 
in the Gulf of Mexico, (incorporated by reference as specified in Sec. 
250.198);
    (7) API Recommend Practice (RP) 2A-WSD, RP for Planning, Designing, 
and Constructing Fixed Offshore Platforms--Working Stress Design 
(incorporated by reference as specified in Sec. 250.198);
    (8) API RP 2FPS, Recommended Practice for Planning, Designing, and 
Constructing Floating Production Systems, (incorporated by reference as 
specified in Sec. 250.198);
    (9) API RP 2I, In-Service Inspection of Mooring Hardware for 
Floating Drilling Units (incorporated by reference as specified in Sec. 
250.198);
    (10) API RP 2RD, Design of Risers for Floating Production Systems 
(FPSs) and Tension-Leg Platforms (TLPs), (incorporated by reference as 
specified in Sec. 250.198);
    (11) API RP 2SK, Recommended Practice for Design and Analysis of 
Station Keeping Systems for Floating Structures, (incorporated by 
reference as specified in Sec. 250.198);
    (12) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, (incorporated by reference as specified in Sec. 250.198);
    (13) API RP 2T, Recommended Practice for Planning, Designing and 
Constructing Tension Leg Platforms, (incorporated by reference as 
specified in Sec. 250.198);
    (14) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, (incorporated by reference 
as specified 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 (incorporated by reference as specified in Sec. 250.198);
    (16) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard 
Specification for Ready-Mixed Concrete (incorporated by reference as 
specified in Sec. 250.198);
    (17) ASTM Standard C 150-07, approved May 1, 2007, Standard 
Specification for Portland Cement (incorporated by reference as 
specified in Sec. 250.198);
    (18) ASTM Standard C 330-05, approved December 15, 2005, Standard 
Specification for Lightweight Aggregates for Structural Concrete 
(incorporated by reference as specified in Sec. 250.198);
    (19) ASTM Standard C 595-08, approved January 1, 2008, Standard 
Specification for Blended Hydraulic Cements (incorporated by reference 
as specified in Sec. 250.198);
    (20) AWS D1.1, Structural Welding Code--Steel, including Commentary, 
(incorporated by reference as specified in Sec. 250.198);
    (21) AWS D1.4, Structural Welding Code--Reinforcing Steel, 
(incorporated by reference as specified in Sec. 250.198);

[[Page 190]]

    (22) AWS D3.6M, Specification for Underwater Welding, (incorporated 
by reference as specified in Sec. 250.198);
    (23) NACE Standard MR0175, Sulfide Stress Cracking Resistant 
Metallic Materials for Oilfield Equipment, (incorporated by reference as 
specified 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:

------------------------------------------------------------------------
            Industry standard                   Applicable to * * *
------------------------------------------------------------------------
(1) ACI Standard 318-95, Building Code     Fixed and floating platform,
 Requirements for Reinforced Concrete       as appropriate.
 (ACI 318-95) and Commentary (ACI 318R-
 95).
(2) ANSI/AISC 360-05, Specification for
 Structural Steel Buildings;.
(3) API Bulletin 2INT-DG, Interim
 Guidance for Design of Offshore
 Structures for Hurricane Conditions;.
(4) API Bulletin 2INT-EX, Interim
 Guidance for Assessment of Existing
 Offshore Structures for Hurricane
 Conditions;.
(5) API Bulletin 2INT-MET, Interim
 Guidance on Hurricane Conditions in the
 Gulf of Mexico;.
(6) API RP 2A-WSD, RP for Planning,
 Designing, and Constructing Fixed
 Offshore Platforms--Working Stress
 Design;.
(7) ASTM Standard C 33-07, approved
 December 15, 2007, Standard
 Specification for Concrete Aggregates;.
(8) ASTM Standard C 94/C 94M-07, approved
 January 1, 2007, Standard Specification
 for Ready-Mixed Concrete;.
(9) ASTM Standard C 150-07, approved May
 1, 2007, Standard Specification for
 Portland Cement;.
(10) ASTM Standard C 330-05, approved
 December 15, 2005, Standard
 Specification for Lightweight Aggregates
 for Structural Concrete;.
(11) ASTM Standard C 595-08, approved
 January 1, 2008, Standard Specification
 for Blended Hydraulic Cements;.
(12) AWS D1.1, Structural Welding Code--
 Steel;.
(13) AWS D1.4, Structural Welding Code--
 Reinforcing Steel;.
(14) AWS D3.6M, Specification for
 Underwater Welding;.
(15) NACE Standard RP 0176-2003, Standard
 Recommended Practice (RP), Corrosion
 Control of Steel Fixed Offshore
 Platforms Associated with Petroleum
 Production;.
(16) ACI 357R-84, Guide for the Design     Fixed platforms
 and Construction of Fixed Offshore
 Concrete Structures, 1984; reapproved
 1997.
(17) API RP 14J, RP for Design and         Floating platforms.
 Hazards Analysis for Offshore Production
 Facilities;.
(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..
------------------------------------------------------------------------


[70 FR 41575, July 19, 2005, as amended at 72 FR 12096, Mar. 15, 2007; 
73 FR 20169, Apr. 15, 2008; 73 FR 64546, Oct. 30, 2008; 75 FR 22226, 
Apr. 28, 2010]



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 MMS 
representatives for the functional life of all platforms:
    (1) The as-built drawings;

[[Page 191]]

    (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 MMS 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 MMS 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 MMS criteria for 
approval of fixed platforms of a proven design that will be placed in 
the shallow water areas (<= 400 ft.) of the Gulf of Mexico OCS.
    (b) The requirements of the Platform Approval Program must be met by 
all platforms on the OCS. Additionally, if you want approval for a 
floating platform; a platform of unique design; or a platform being 
installed in deepwater ( 400 ft.) or a frontier area, you 
must also meet the requirements of the Platform Verification Program. 
The requirements of the Platform Verification Program are described in 
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,        three copies. If,
                                   lease number,       your facility is
                                   area, name, and     subject to the
                                   block number, and   Platform
                                   the type of         Verficiation
                                   facility your       Program (PVP),
                                   facility (e.g.,     you must submit
                                   drilling,           four copies.
                                   production,
                                   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
                                   coordinates,        of 1 inch equals
                                   Universal           2,000 feet and
                                   Mercator grid-      include the
                                   system              coordinates of
                                   coordinates,        the lease block
                                   state plane         boundary lines.
                                   coordinates in      You must submit
                                   the Lambert or      three
                                   Transverse
                                   Mercator
                                   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 View    Platform            Your drawing sizes
 drawings.                         dimensions and      must not exceed
                                   orientation,        11 x
                                   elevations          17.
                                   relative to         You must submit
                                   M.L.L.W. (Mean      three copies
                                   Lower Low Water),   (four copies for
                                   and pile sizes      PVP
                                   and penetration.    applications).

[[Page 192]]

 
(d) Complete set of structural    The approved for    Your drawing sizes
 drawings.                         construction        must not exceed
                                   fabrication         11 x
                                   drawings should     17.
                                   be submitted        You must submit
                                   including; e.g.,    one copy.
                                   cathodic
                                   protection
                                   systems; jacket
                                   design; pile
                                   foundations;
                                   drilling,
                                   production, and
                                   pipeline risers
                                   and riser
                                   tensioning
                                   systems; turrets
                                   and turret-and-
                                   hull interfaces;
                                   mooring and
                                   tethering
                                   systems;
                                   foundations and
                                   anchoring systems.
(e) Summary of environmental      A summary of the    You must submit
 data.                             environmental       one copy.
                                   data described in
                                   the applicable
                                   standards
                                   referenced under
                                   Sec.  250.901(a)
                                   of this subpart
                                   and in Sec.
                                   250.198 of
                                   Subpart A, where
                                   the data is used
                                   in the design or
                                   analysis of the
                                   platform.
                                   Examples of
                                   relevant data
                                   include
                                   information on
                                   waves, wind,
                                   current, tides,
                                   temperature, snow
                                   and ice effects,
                                   marine growth,
                                   and water depth.
(f) Summary of the engineering    Loading             You must submit
 design data.                      information         one copy.
                                   (e.g., live,
                                   dead,
                                   environmental),
                                   structural
                                   information
                                   (e.g., design-
                                   life; material
                                   types; cathodic
                                   protection
                                   systems; design
                                   criteria; fatigue
                                   life; jacket
                                   design; deck
                                   design;
                                   production
                                   component design;
                                   pile foundations;
                                   drilling,
                                   production, and
                                   pipeline risers
                                   and riser
                                   tensioning
                                   systems; turrets
                                   and turret-and-
                                   hull interfaces;
                                   foundations,
                                   foundation
                                   pilings and
                                   templates, and
                                   anchoring
                                   systems; mooring
                                   or tethering
                                   systems;
                                   fabrication and
                                   installation
                                   guidelines), and
                                   foundation
                                   information
                                   (e.g., soil
                                   stability, design
                                   criteria).
(g) Project-specific studies      All studies         You must submit
 used in the platform design or    pertinent to        one copy of each
 installation.                     platform design     study.
                                   or installation,
                                   e.g.,
                                   oceanographic and/
                                   or soil reports
                                   including the
                                   overall site
                                   investigative
                                   report required
                                   in section
                                   250.906.
(h) Description of the loads      Loads imposed by    You must submit
 imposed on the facility.          jacket; decks;      one copy.
                                   production
                                   components;
                                   drilling,
                                   production, and
                                   pipeline risers,
                                   and riser
                                   tensioning
                                   systems; turrets
                                   and turret-and-
                                   hull interfaces;
                                   foundations,
                                   foundation
                                   pilings and
                                   templates, and
                                   anchoring
                                   systems; and
                                   mooring or
                                   tethering systems.
(i) Summary of safety factors     A summary of        You must submit
 utilized.                         pertinent derived   one copy.
                                   factors of safety
                                   against failure
                                   for major
                                   structural
                                   members, e.g.,
                                   unity check
                                   ratios exceeding
                                   0.85 for steel-
                                   jacket platform
                                   members,
                                   indicated on
                                   ``line'' sketches
                                   of jacket
                                   sections.
(j) A copy of the in-service      This plan is        You must submit
 inspection plan.                  described in Sec.  one copy.
                                     250.919..
(k) Certification statement.....  The following       An authorized
                                   statement: ``The    company
                                   design of this      representative
                                   structure has       must sign the
                                   been certified by   statement. You
                                   a recognized        must submit one
                                   classification      copy.
                                   society, or a
                                   registered civil
                                   or structural
                                   engineer or
                                   equivalent, or a
                                   naval architect
                                   or marine
                                   engineer or
                                   equivalent,
                                   specializing in
                                   the design of
                                   offshore
                                   structures. The
                                   certified design
                                   and as-built
                                   plans and
                                   specifications
                                   will be on file
                                   at (give
                                   location)''.
(l) Payment of the service fee    ..................  ..................
 listed in Sec.  250.125.
------------------------------------------------------------------------


[70 FR 41575, July 19, 2005, as amended at 71 FR 40912, July 19, 2006; 
73 FR 64546, Oct. 30, 2008]



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:

[[Page 193]]

    (1) Seismic activity at your proposed site;
    (2) Fault zones, the extent and geometry of faulting, and 
attenuation effects of geologic conditions near your site; and
    (3) For platforms located in producing areas, the possibility and 
effects of seafloor subsidence.
    (c) Subsurface surveys. Depending upon the design and location of 
your proposed platform and the results of the shallow hazard and 
geologic surveys, the Regional Supervisor may require you to perform a 
subsurface survey. This survey will include a testing program for 
investigating the stratigraphic and engineering properties of the soil 
that may affect the foundations or anchoring systems for your facility. 
The testing program must include adequate in situ testing, boring, and 
sampling to examine all important soil and rock strata to determine its 
strength classification, deformation properties, and dynamic 
characteristics. If required to perform a subsurface survey, you must 
prepare and submit to the Regional Supervisor a summary report to 
briefly describe the results of your soil testing program, the various 
field and laboratory test methods employed, and the applicability of 
these methods as they pertain to the quality of the samples, the type of 
soil, and the anticipated design application. You must explain how the 
engineering properties of each soil stratum affect the design of your 
platform. In your explanation you must describe the uncertainties 
inherent in your overall testing program, and the reliability and 
applicability of each test method.
    (d) Overall site investigation report. You must prepare and submit 
to the Regional Supervisor an overall site investigation report for your 
platform that integrates the findings of your shallow hazards surveys 
and geologic surveys, and, if required, your subsurface surveys. Your 
overall site investigation report must include analyses of the potential 
for:
    (1) Scouring of the seafloor;
    (2) Hydraulic instability;
    (3) The occurrence of sand waves;
    (4) Instability of slopes at the platform location;
    (5) Liquifaction, 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 (incorporated by reference as 
specified in 30 CFR 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 must
 redundancy to prevent catastrophic   indicate a maximum calculated life
 failure of the platform or           of twice the design life of the
 structure under consideration.       platform.

[[Page 194]]

 
(2) There is not sufficient          The results of a fatigue analysis
 structural redundancy to prevent     must indicate a minimum calculated
 catastrophic failure of the          life or three times the design
 platform or structure.               life of the platform.
(3) The desirable degree of          The results of a fatigue analysis
 redundancy is significantly          must indicate a minimum calculated
 reduced as a result of fatigue       life of three times the design
 damage.                              life of the platform.
------------------------------------------------------------------------

    (b) The documents incorporated by reference in Sec. 250.901 may 
require larger safety factors than indicated in paragraph (a) of this 
section for some key components. When the documents incorporated by 
reference require a larger safety factor than the chart in paragraph (a) 
of this section, the requirements of the incorporated document will 
prevail.

                      Platform Verification Program



Sec. 250.909  What is the Platform Verification Program?

    The Platform Verification Program is the MMS 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 subject to
 buoyant offshore facility that       the Platform Verification Program
 does not have a ship-shaped hull.    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 structures that
 buoyant offshore facility with a     may be associated with a floating
 ship-shaped hull.                    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

[[Page 195]]

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 MMS and the 
USCG.
    (d) The applicability of Platform Verification Program requirements 
to other types of facilities will be determined by MMS on a case-by-case 
basis.

[70 FR 41575, July 19, 2005; 71 FR 28080, May 15, 2006]



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.

[70 FR 41575, July 19, 2005, as amended at 73 FR 64547, Oct. 30, 2008]



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 with or subsequent to the submittal of your 
Development and Production Plan (DPP) or Development Operations 
Coordination Document (DOCD). 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

[[Page 196]]

structures and major members of concrete-gravity and steel-gravity 
structures;
    (2) For jacket and floating structures, all the primary load-bearing 
members included in the space-frame analysis; and
    (3) A summary description of the following:
    (i) Structural tolerances;
    (ii) Welding procedures;
    (iii) Material (concrete, gravel, or silt) placement methods;
    (iv) Fabrication standards;
    (v) Material quality-control procedures;
    (vi) Methods and extent of nondestructive examinations for welds and 
materials; and
    (vii) Quality assurance procedures.
    (c) Installation verification plan. The Regional Supervisor must 
approve your installation verification plan before you may initiate any 
related operations. Your installation verification plan must include:
    (1) A summary description of the planned marine operations;
    (2) Contingencies considered;
    (3) Alternative courses of action; and
    (4) An identification of the areas to be inspected. You must specify 
the acceptance and rejection criteria to be used for any inspections 
conducted during installation, and for the post-installation 
verification inspection.
    (d) You must combine fabrication verification and installation 
verification plans for manmade islands or platforms fabricated and 
installed in place.



Sec. 250.913  When must I resubmit Platform Verification Program plans?

    (a) You must resubmit any design verification, fabrication 
verification, or installation verification plan to the Regional 
Supervisor for approval if:
    (1) The CVA changes;
    (2) The CVA's or assigned personnel's qualifications change; or
    (3) The level of work to be performed changes.
    (b) If only part of a verification plan is affected by one of the 
changes described in paragraph (a) of this section, you can resubmit 
only the affected part. You do not have to resubmit the summary of 
technical details unless you make changes in the technical details.



Sec. 250.914  How do I nominate a CVA?

    (a) As part of your design verification, fabrication verification, 
or installation verification plan, you must nominate a CVA for the 
Regional Supervisor's approval. You must specify whether the nomination 
is for the design, fabrication, or installation phase of verification, 
or for any combination of these phases.
    (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 MMS 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 250.901(b); and the requirements of this subpart.

[[Page 197]]

    (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 judgement and practices in 
conducting an independent assessment of the design of the platform, 
major modification, or repair. The CVA must ensure that the platform, 
major modification, or repair is designed to withstand the environmental 
and functional load conditions appropriate for the intended service life 
at the proposed location.
    (b) Primary duties of the CVA during the design phase include the 
following:

------------------------------------------------------------------------
       Type of facility . . .                 The CVA must . . .
------------------------------------------------------------------------
(1) For fixed platforms and non-     Conduct an independent assessment
 ship-shaped floating facilities.     of all proposed:
                                     (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.

[70 FR 41575, July 19, 2005, as amended at 73 FR 64547, Oct. 30, 2008]



Sec. 250.917  What are the CVA's primary duties during the fabrication phase?

    (a) The CVA must use good engineering judgement 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:

[[Page 198]]



------------------------------------------------------------------------
       Type of facility . . .                 The CVA must . . .
------------------------------------------------------------------------
(1) For all fixed platforms and non- Make periodic onsite inspections
 ship-shaped floating facilities.     while fabrication is in 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 tolerences
                                      specified and adherence to those
                                      tolerances;
                                     (vii) The nondestructive
                                      examination requirements, and
                                      evaluation results of the
                                      specified examinations;
                                     (viii) Destructive testing
                                      requirements and results;
                                     (ix) Repair procedures;
                                     (x) Installation of corrosion-
                                      protection systems and splash-zone
                                      protection;
                                     (xi) Erection procedures to ensure
                                      that overstressing of structural
                                      members does not occur;
                                     (xii) Alignment procedures;
                                     (xiii) Dimensional check of the
                                      overall structure, including any
                                      turrets, turret-and-hull
                                      interfaces, any mooring line and
                                      chain and riser tensioning line
                                      segments; and
                                     (xiv) Status of quality-control
                                      records at various stages of
                                      fabrication.
(2) For all floating facilities....  Ensure that the requirements of the
                                      U.S. Coast Guard floating for
                                      structural integrity and
                                      stability, e.g., verification of
                                      center of gravity, etc., have been
                                      met. The CVA must also consider:
                                     (i) Drilling, production, and
                                      pipeline risers, and riser
                                      tensioning systems (at least for
                                      the initial fabrication of these
                                      elements);
                                     (ii) Turrets and turret-and-hull
                                      interfaces;
                                     (iii) Foundation pilings and
                                      templates, and anchoring systems;
                                      and
                                     (iv) Mooring or tethering systems.
------------------------------------------------------------------------

    (c) The CVA must submit interim reports and a final report to the 
Regional Supervisor, and to you, during the fabrication phase in 
accordance with the approved schedule required by Sec. 250.911(d). In 
each interim and final report the CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Describe the CVA's activities during the verification process;
    (3) Summarize the CVA's findings;
    (4) Confirm or deny compliance with the design specifications and 
the approved fabrication plan;
    (5) In the final CVA report, make a recommendation to accept or 
reject the fabrication unless such a recommendation has been previously 
made in an interim report; and
    (6) Provide any additional comments that the CVA deems necessary.

[70 FR 41575, July 19, 2005, as amended at 73 FR 64547, Oct. 30, 2008]



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:

------------------------------------------------------------------------
                                         Operation or equipment to be
         The CVA must . . .                    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;

[[Page 199]]

 
                                     (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          (i) The loadout of the jacket,
 floating platform).                  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          (i) The loadout of the platform;
 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       (i) Equipment;
 determine compliance with the       (ii) Procedures; and
 applicable documents listed in      (iii) Recordkeeping.
 Sec.  250.901(a); the alternative
 codes, rules and standards
 approved under 250.901(b); the
 requirements listed in Sec.
 250.903 and 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 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.

[70 FR 41575, July 19, 2005, as amended at 73 FR 64547, Oct. 30, 2008]

          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 (incorporated by reference as specified 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

[[Page 200]]

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 MMS before you make major repairs of any damage 
unless you meet the requirements of Sec. 250.900(c).

[73 FR 64547, Oct. 30, 2008]



Sec. 250.920  What are the MMS 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. If MMS 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 for a description of assessment initiators).
    (c) You must initiate mitigation actions for platforms that do not 
pass the assessment process of API RP 2A-WSD. You must submit 
applications for your mitigation actions (e.g., repair, modification, 
decommissioning) to the Regional Supervisor for approval before you 
conduct the work.
    (d) The MMS 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.

[73 FR 64548, Oct. 30, 2008]



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.

[[Page 201]]

    (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 MMS upon request.
    (iv) If adjoining producing and transporting operators cannot agree 
on a transfer point by April 14, 1999, the MMS 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 MMS 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.
    (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, MMS 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 MMS Regional Supervisor recognize that valve as the last point 
MMS will exercise its regulatory authority.
    (9) A pipeline segment is not subject to MMS 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 MMS 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 MMS 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

[[Page 202]]

of Pipeline Safety (OPS) Regional Director.
    (13) A transporter who operates a pipeline regulated by DOT may 
request to operate under MMS regulations governing pipeline operation 
and maintenance. Any subsequent repairs or modifications will also be 
subject to MMS 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 MMS Regional Supervisor.
    (ii) The MMS 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).

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 63 FR 34597, June 25, 1998; 63 FR 43880, Aug. 17, 
1998; 65 FR 46095, July 27, 2000; 71 FR 40912, July 19, 2006]



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

[[Page 203]]

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).

[53 FR 10690, Apr. 1, 1998. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 63 FR 43881, Aug. 17, 1998; 65 FR 46096, July 27, 2000; 67 
FR 35405, May 17, 2002; 72 FR 25201, May 4, 2007]



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] TC15NO91.019


For limitations see section 841.121 of American National Standards 
Institute (ANSI) B31.8 (incorporated by reference as specified in 30 CFR 
250.198) where--

P=Internal design pressure in pounds per square inch (psi).
S=Specified minimum yield strength, in psi, stipulated in the 
specification under which the pipe was purchased from the manufacturer 
or determined in accordance with section 811.253(h) of ANSI B31.8.
D=Nominal outside diameter of pipe, in inches.
t=Nominal wall thickness, in inches.
F=Construction design factor of 0.72 for the submerged component and 
0.60 for the riser component.
E=Longitudinal joint factor obtained from Table 841.1B of ANSI B31.8. 
(See also section 811.253(d)).
T=Temperature derating factor obtained from Table 841.1C of ANSI B31.8.

    (b)(1) Pipeline valves shall meet the minimum design requirements of 
American Petroleum Institute (API) Spec 6A, API Spec 6D, 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 
(incorporated by reference as specified 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, incorporated by reference as specified 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), incorporated by reference as specified in 30 CFR 
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

[[Page 204]]

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 (incorporated by reference as 
specified 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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 67 FR 51760, Aug. 9, 2002; 70 FR 41583, July 19, 2005; 72 
FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007]



Sec. 250.1003  Installation, testing, and repair requirements for DOI pipelines.

    (a)(1) Pipelines greater than 8-5/8 inches in diameter and installed 
in water depths of less than 200 feet shall be buried to a depth of at 
least 3 feet unless they are located in pipeline congested areas or 
seismically active areas as determined by the Regional Supervisor. 
Nevertheless, the Regional Supervisor may require burial of any pipeline 
if the Regional Supervisor determines that such burial will reduce the 
likelihood of environmental degradation or that the pipeline may 
constitute a hazard to trawling operations or other uses. A trawl test 
or diver survey may be required to determine whether or not pipeline 
burial is necessary or to determine whether a pipeline has been properly 
buried.
    (2) Pipeline valves, taps, tie-ins, capped lines, and repaired 
sections that could be obstructive shall be provided with at least 3 
feet of cover unless the Regional Supervisor determines that such items 
present no hazard to trawling or other operations. A protective device 
may be used to cover an obstruction in lieu of burial if it is approved 
by the Regional Supervisor prior to installation.
    (3) Pipelines shall be installed with a minimum separation of 18 
inches at pipeline crossings and from obstructions.
    (4) Pipeline risers installed after April 1, 1988, shall be 
protected from physical damage that could result from contact with 
floating vessels. Riser protection on pipelines installed on or before 
April 1, 1988, may be required when the Regional Supervisor determines 
that significant damage potential exists.
    (b)(1) Pipelines shall be pressure tested with water at a stabilized 
pressure of at least 1.25 times the MAOP for at least 8 hours when 
installed, relocated, uprated, or reactivated after being out-of-service 
for more than 1 year.
    (2) Prior to returning a pipeline to service after a repair, the 
pipeline shall be pressure tested with water or processed natural gas at 
a minimum stabilized pressure of at least 1.25 times the MAOP for at 
least 2 hours.
    (3) Pipelines shall not be pressure tested at a pressure which 
produces a stress in the pipeline in excess of 95 percent of the 
specified minimum-yield strength of the pipeline. A temperature recorder 
measuring test fluid temperature synchronized with a pressure recorder 
along with deadweight test readings shall be employed for all pressure 
testing. When a pipeline is pressure tested, no observable leakage shall 
be allowed. Pressure gauges and recorders shall be of sufficient 
accuracy to verify that leakage is not occurring.
    (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

[[Page 205]]

encirclement clamp able to withstand the anticipated pipeline pressure.

[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13, 1988; 57 FR 26997, 
June 17, 1992. Redesignated at 63 FR 29479, May 29, 1998, as amended at 
72 FR 25201, May 4, 2007]



Sec. 250.1004  Safety equipment requirements for DOI pipelines.

    (a) The lessee shall ensure the proper installation, operation, and 
maintenance of safety devices required by this section on all incoming, 
departing, and crossing pipelines on platforms.
    (b)(1)(i) Incoming pipelines to a platform shall be equipped with a 
flow safety valve (FSV).
    (ii) For sulphur operations, incoming pipelines delivering gas to 
the power plant platform may be equipped with high- and low-pressure 
sensors (PSHL), which activate audible and visual alarms in lieu of 
requirements in paragraph (b)(1)(i) of this section. The PSHL shall be 
set at 15 percent or 5 psi, whichever is greater, above and below the 
normal operating pressure range.
    (2) Incoming pipelines boarding a production platform shall be 
equipped with an automatic shutdown valve (SDV) immediately upon 
boarding the platform. The SDV shall be connected to the automatic- and 
remote-emergency shut-in systems.
    (3) Departing pipelines receiving production from production 
facilities shall be protected by high- and low-pressure sensors (PSHL) 
to directly or indirectly shut in all production facilities. The PSHL 
shall be set not to exceed 15 percent above and below the normal 
operating pressure range. However, high pilots shall not be set above 
the pipeline's MAOP.
    (4) Crossing pipelines on production or manned nonproduction 
platforms which do not receive production from the platform shall be 
equipped with an SDV immediately upon boarding the platform. The SDV 
shall be operated by a PSHL on the departing pipelines and connected to 
the platform automatic- and remote-emergency shut-in systems.
    (5) The Regional Supervisor may require that oil pipelines be 
equipped with a metering system to provide a continuous volumetric 
comparison between the input to the line at the structure(s) and the 
deliveries onshore. The system shall include an alarm system and shall 
be of adequate sensitivity to detect variations between input and 
discharge volumes. In lieu of the foregoing, a system capable of 
detecting leaks in the pipeline may be substituted with the approval of 
the Regional Supervisor.
    (6) Pipelines incoming to a subsea tie-in shall be equipped with a 
block valve and an FSV. Bidirectional pipelines connected to a subsea 
tie-in shall be equipped with only a block valve.
    (7) Gas-lift or water-injection pipelines on unmanned platforms need 
only be equipped with an FSV installed immediately upstream of each 
casing annulus or the first inlet valve on the christmas tree.
    (8) Bidirectional pipelines shall be equipped with a PSHL and an SDV 
immediately upon boarding each platform.
    (9) Pipeline pumps must comply with section A7 of API RP 14C 
(incorporated by reference as specified 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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 56 
FR 32100, July 15, 1991. Redesignated at 63 FR 29479, May 29, 1998; 67 
FR 51760, Aug. 9, 2002; 72 FR 25201, May 4, 2007]



Sec. 250.1005  Inspection requirements for DOI pipelines.

    (a) Pipeline routes shall be inspected at time intervals and methods 
prescribed by the Regional Supervisor for indication of pipeline 
leakage. The results of these inspections shall be retained for at least 
2 years and be made available to the Regional Supervisor upon request.

[[Page 206]]

    (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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, 
as amended at 72 FR 25201, May 4, 2007]



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


[67 FR 35405, May 17, 2002]



Sec. 250.1007  What to include in applications.

    (a) Applications to install a lease term pipeline or for a pipeline 
right-of-way grant must be submitted in quadruplicate to the Regional 
Supervisor. Right-of-way grant applications must include an 
identification of the operator of the pipeline. Each application must 
include the following:
    (1) Plat(s) drawn to a scale specified by the Regional Supervisor 
showing major features and other pertinent data including area, lease, 
and block designations; water depths; route; length in Federal waters; 
width of right-of-way, if applicable; connecting facilities; size; 
product(s) to be transported with anticipated gravity or density; burial 
depth; direction of flow; X-Y coordinates of key points; and the 
location of other pipelines that will be connected to or crossed by the 
proposed pipeline(s). The initial and terminal points of the pipeline 
and any continuation into State jurisdiction shall be accurately located 
even if the pipeline is to have an onshore terminal point. A plat(s) 
submitted for a pipeline right-of-way shall bear a signed certificate 
upon its face by the engineer who made the map that certifies that the 
right-of-way is accurately represented upon the map and that the design 
characteristics of the associated pipeline are in accordance with 
applicable regulations.
    (2) A schematic drawing showing the size, weight, grade, wall 
thickness, and type of line pipe and risers; pressure-regulating devices 
(including back-pressure regulators); sensing devices with associated 
pressure-control lines; PSV's and settings; SDV's, FSV's, and block 
valves; and manifolds. This schematic drawing shall also show input 
source(s), e.g., wells, pumps, compressors, and vessels; maximum input 
pressure(s); the rated working pressure, as specified by ANSI or API, of 
all valves, flanges, and fittings; the initial receiving equipment and 
its rated working pressure; and associated safety equipment and pig 
launchers and receivers. The schematic must indicate the point on the 
OCS at which operating responsibility transfers between a producing 
operator and a transporting operator.
    (3) General information as follows:
    (i) Description of cathodic protection system. If pipeline anodes 
are to be used, specify the type, size, weight, number, spacing, and 
anticipated life;
    (ii) Description of external pipeline coating system;
    (iii) Description of internal protective measures;
    (iv) Specific gravity of the empty pipe;
    (v) MSP;
    (vi) MAOP and calculations used in its determination;
    (vii) Hydrostatic test pressure, medium, and period of time that the 
line will be tested;
    (viii) MAOP of the receiving pipeline or facility,
    (ix) Proposed date for commencing installation and estimated time 
for construction; and
    (x) Type of protection to be afforded crossing pipelines, subsea 
valves, taps, and manifold assemblies, if applicable.

[[Page 207]]

    (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 (incorporated by reference as specified 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.

[53 FR 10690, Apr. 1, 1988, as amended at 59 FR 53094, Oct. 21, 1994. 
Redesignated at 63 FR 29479, May 29, 1998, as amended at 63 FR 43881, 
Aug. 17, 1998; 67 FR 35406, May 17, 2002; 70 FR 41583, July 19, 2005; 72 
FR 25201, May 4, 2007; 73 FR 64548, Oct. 30, 2008]



Sec. 250.1008  Reports.

    (a) The lessee, or right-of-way holder, shall notify the Regional 
Supervisor at least 48 hours prior to commencing the installation or 
relocation of a pipeline or conducting a pressure test on a pipeline.
    (b) The lessee or right-of-way holder shall submit a report to the 
Regional Supervisor within 90 days after completion of any pipeline 
construction. The report, submitted in triplicate, shall include an 
``as-built'' location plat drawn to a scale specified by the Regional 
Supervisor showing the location, length in Federal waters, and X-Y 
coordinates of key points; the completion date; the proposed date of 
first operation; and the HPT data. Pipeline right-of-way ``as-built'' 
location plats shall be certified by a registered engineer or land 
surveyor and show the boundaries of the right-of-way as granted. If 
there is a substantial deviation of the pipeline route as granted in the 
right-of-way, the report shall include a discussion of the reasons for 
such deviation.
    (c) The lessee or right-of-way holder shall report to the Regional 
Supervisor any pipeline taken out of service. If the period of time in 
which the pipeline is out of service is greater than 60 days, written 
confirmation is also required.
    (d) The lessee or right-of-way holder shall report to the Regional 
Supervisor when any required pipeline safety equipment is taken out of 
service for more than 12 hours. The Regional Supervisor shall be 
notified when the equipment is returned to service.
    (e) The lessee or right-of-way holder must notify the Regional 
Supervisor before the repair of any pipeline or as soon as practicable. 
Your notification must be accompanied by payment of the service fee 
listed in Sec. 250.125. You must submit a detailed report of the repair 
of a pipeline or pipeline component to the Regional Supervisor within

[[Page 208]]

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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 71 FR 40912, July 19, 2006]



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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]



Sec. 250.1010  General requirements for pipeline right-of-way holders.

    An applicant, by accepting a right-of-way grant, agrees to comply 
with the following requirements:
    (a) The right-of-way holder shall comply with applicable laws and 
regulations and the terms of the grant.
    (b) The granting of the right-of-way shall be subject to the express 
condition that the rights granted shall not prevent or interfere in any 
way with the management, administration, or the granting of other rights 
by the United States, either prior or subsequent to the granting of the 
right-of-way. Moreover, the holder agrees to allow the occupancy and use 
by the United States, its lessees, or other right-of-way holders, of any 
part of the right-of-way grant not actually occupied or necessarily 
incident to its use for any necessary operations involved in the 
management, administration, or the enjoyment of such other granted 
rights.
    (c) If the right-of-way holder discovers any archaeological resource 
while conducting operations within the right-of-way, the right-of-way 
holder shall immediately halt operations

[[Page 209]]

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 
Minerals Management Service (MMS). 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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 
25201, May 4, 2007]



Sec. 250.1011  Bond requirements for pipeline right-of-way holders.

    (a) When you apply for, or are the holder of, a right-of-way, you 
must:
    (1) Provide and maintain a $300,000 bond (in addition to the bond 
coverage required in part 256) that guarantees compliance with all the 
terms and conditions of the rights-of-way you hold in an OCS area; and
    (2) Provide additional security if the Regional Director determines 
that a bond in excess of $300,000 is needed.
    (b) For the purpose of this paragraph, there are three areas:
    (1) The Gulf of Mexico and the area offshore the Atlantic Coast;
    (2) The areas offshore the Pacific Coast States of California, 
Oregon, Washington, and Hawaii; and
    (3) The area offshore the Coast of Alaska.

[[Page 210]]

    (c) If, as the result of a default, the surety on a right-of-way 
grant bond makes payment to the Government of any indebtedness under a 
grant secured by the bond, the face amount of such bond and the surety's 
liability shall be reduced by the amount of such payment.
    (d) After a default, a new bond in the amount of $300,000 shall be 
posted within 6 months or such shorter period as the Regional Supervisor 
may direct. Failure to post a new bond shall be grounds for forfeiture 
of all grants covered by the defaulted bond.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 
25201, May 4, 2007]



Sec. 250.1012  Required payments for pipeline right-of-way holders.

    (a) You must pay MMS an annual rental of $15 for each statute mile, 
or part of a statute mile, of the OCS that your pipeline right-of-way 
crosses.
    (b) This paragraph applies to you if you obtain a pipeline right-of-
way that includes a site for an accessory to the pipeline, including but 
not limited to a platform. This paragraph also applies if you apply to 
modify a right-of-way to change the site footprint. In either case, you 
must pay the amounts shown in the following table.

------------------------------------------------------------------------
               If...                               Then...
------------------------------------------------------------------------
(1) Your accessory site is located   You must pay a rental of $5 per
 in water depths of less than 200     acre per year with a minimum of
 meters;                              $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   You must pay a rental of $7.50 per
 in water depths of 200 meters or     acre per year with a minimum of
 greater;                             $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 MMS 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 218.54. If you fail to make a payment 
that is late after written notice from MMS, MMS may initiate 
cancellation of the right-of-use grant and easement under 30 CFR 
250.1013.

[68 FR 69312, Dec. 12, 2003, as amended at 69 FR 29433, May 24, 2004]



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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]

[[Page 211]]



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.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 
FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 
22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 
63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]



Sec. 250.1015  Applications for pipeline right-of-way grants.

    (a) You must submit an original and three copies of an application 
for a new or modified pipeline ROW grant to the Regional Supervisor. The 
application must address those items required by Sec. 250.1007(a) or 
(b) of this subpart, as applicable. It must also state the primary 
purpose for which you will use the ROW grant. If the ROW has been used 
before the application is made, the application must state the date such 
use began, by whom, and the date the applicant obtained control of the 
improvement. When you file your application, you must pay the rental 
required under Sec. 250.1012 of this subpart, as well as the service 
fees listed in Sec. 250.125 of this part for a pipeline ROW grant to 
install a new pipeline, or to convert an existing lease term pipeline 
into a ROW pipeline. An application to modify an approved ROW grant must 
be accompanied by the additional rental required under Sec. 250.1012 if 
applicable. You must file a separate application for each ROW.
    (b)(1) An individual applicant shall submit a statement of 
citizenship or nationality with the application. An applicant who is an 
alien lawfully admitted for permanent residence in the United States 
shall also submit evidence of such status with the application.
    (2) If the applicant is an association (including a partnership), 
the application shall also be accompanied by a certified copy of the 
articles of association or appropriate reference to a copy of such 
articles already filed with MMS 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 MMS (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 MMS 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.

[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 39775, July 24, 1997. 
Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 64 FR 
42598, Aug. 5, 1999. Further redesignated and amended at 68 FR 69311, 
69312, Dec. 12, 2003; 70 FR 49876, Aug. 25, 2005; 70 FR 61893, Oct. 27, 
2005]



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,

[[Page 212]]

marine, and coastal environments, life (including aquatic life), 
property, and mineral resources in the entire area during construction 
and operational phases. The Regional Supervisor shall prepare an 
environmental analysis in accordance with applicable policies and 
guidelines. To aid in the evaluation and determinations, the Regional 
Supervisor may request and consider views and recommendations of 
appropriate Federal Agencies, hold public meetings after appropriate 
notice, and consult, as appropriate, with State agencies, organizations, 
industries, and individuals. Before granting a pipeline right-of-way, 
the Regional Supervisor shall give consideration to any recommendation 
by the intergovernmental planning program, or similar process, for the 
assessment and management of OCS oil and gas transportation.
    (b) Should the proposed route of a right-of-way adjoin and 
subsequently cross any State submerged lands, the applicant shall submit 
evidence to the Regional Supervisor that the State(s) so affected has 
reviewed the application. The applicant shall also submit any comment 
received as a result of that review. In the event of a State 
recommendation to relocate the proposed route, the Regional Supervisor 
may consult with the appropriate State officials.
    (c)(1) The applicant shall submit photocopies of return receipts to 
the Regional Supervisor that indicate the date that each lessee or 
right-of-way holder referenced in Sec. 250.1015(c) of this part has 
received a copy of the application. Letters of no objection may be 
submitted in lieu of the return receipts.
    (2) The Regional Supervisor shall not take final action on a right-
of-way application until the Regional Supervisor is satisfied that each 
such lessee or right-of-way holder has been afforded at least 30 days 
from the date determined in paragraph (c)(1) of this section in which to 
submit comments.
    (d) If a proposed right-of-way crosses any lands not subject to 
disposition by mineral leasing or restricted from oil and gas 
activities, it shall be rejected by the Regional Supervisor unless the 
Federal Agency with jurisdiction over such excluded or restricted area 
gives its consent to the granting of the right-of-way. In such case, the 
applicant, upon a request filed within 30 days after receipt of the 
notification of such rejection, shall be allowed an opportunity to 
eliminate the conflict.
    (e)(1) If the application and other required information are found 
to be in compliance with applicable laws and regulations, the right-of-
way may be granted. The Regional Supervisor may prescribe, as conditions 
to the right-of-way grant, stipulations necessary to protect human, 
marine, and coastal environments, life (including aquatic life), 
property, and mineral resources located on or adjacent to the right-of-
way.
    (2) If the Regional Supervisor determines that a change in the 
application should be made, the Regional Supervisor shall notify the 
applicant that an amended application shall be filed subject to 
stipulated changes. The Regional Supervisor shall determine whether the 
applicant shall deliver copies of the amended application to other 
parties for comment.
    (3) A decision to reject an application shall be in writing and 
shall state the reasons for the rejection.

[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1988. 
Redesignated and amended at 63 FR 29479, 29486, May 29, 1998. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 
25201, May 4, 2007]



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

[[Page 213]]

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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998. 
Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]



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 Sec. 250.1011 of this 
subpart. 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 that paragraph is suspended 
until January 3, 2006.

[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 39775, July 24, 1997. 
Redesignated and amended at 63 FR 29479, 29486, May 29, 1998. Further 
redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 70 FR 
49876, Aug. 25, 2005; 70 FR 61893, Oct. 27, 2005]



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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 67 FR 35406, May 17, 2002. Further redesignated and 
amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 25201, May 4, 2007]



              Subpart K_Oil and Gas Production Requirements

    Source: 75 FR 20289, Apr. 19, 2010, unless otherwise noted.

                                 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:

[[Page 214]]



------------------------------------------------------------------------
                                            And you must submit to the
           You must conduct:                   Regional Supervisor:
------------------------------------------------------------------------
(1) A well-flow potential test on all    Form MMS-126, Well Potential
 new, recompleted, or reworked well       Test Report, along with the
 completions within 30 days of the date   supporting data as listed in
 of first continuous production.          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 MMS-128,
 calendar half-year for each producing    Semiannual Well Test Report,
 completion.                              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 MMS-126.



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) An MMS 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.



Sec. 250.1153  When must I conduct a static bottomhole pressure survey?

    (a) You must conduct a static bottomhole pressure survey under the 
following conditions:

------------------------------------------------------------------------
           If you have . . .               Then you must conduct . . .
------------------------------------------------------------------------
(1) A new producing reservoir..........  A static bottomhole pressure
                                          survey within 90 days after
                                          the date of first continuous
                                          production.
(2) A reservoir with three or more       Annual static bottomhole
 producing completions.                   pressure surveys in a
                                          sufficient number of key wells
                                          to establish an average
                                          reservoir pressure. The
                                          Regional Supervisor may
                                          require that bottomhole
                                          pressure surveys be performed
                                          on specific wells.
------------------------------------------------------------------------

    (b) Your bottomhole pressure survey must meet the following 
requirements:
    (1) You must shut-in the well for a minimum period of 4 hours to 
ensure stabilized conditions; and
    (2) The bottomhole pressure survey must consist of a pressure 
measurement at mid-perforation, and pressure measurements and gradient 
information for at least four gradient stops coming out of the hole.
    (c) You must submit to the Regional Supervisor the results of all 
static bottomhole pressure surveys on Form

[[Page 215]]

MMS-140, Bottomhole Pressure Survey Report, within 60 days after the 
date of the survey.
    (d) The Regional Supervisor may grant a departure from the 
requirement to run a static bottomhole pressure survey. To request a 
departure, you must submit a justification, along with Form MMS-140, 
Bottomhole Pressure Survey Report, showing a calculated bottomhole 
pressure or any measured data.

                         Classifying Reservoirs



Sec. 250.1154  How do I determine if my reservoir is sensitive?

    (a) You must determine whether each reservoir is sensitive. You must 
classify the reservoir as sensitive if:
    (1) Under initial conditions it is an oil reservoir with an 
associated gas cap;
    (2) At any time there are near-critical fluids; or
    (3) The reservoir is undergoing enhanced recovery.
    (b) For the purposes of this subpart, near-critical fluids are:
    (1) Those fluids that occur in high temperature, high-pressure 
reservoirs where it is not possible to define the liquid-gas contact; or
    (2) Fluids in reservoirs that are near bubble point or dew point 
conditions.
    (c) The Regional Supervisor may reclassify a reservoir when 
available information warrants reclassification.
    (d) If available information indicates that a reservoir previously 
classified as non-sensitive is now sensitive, you must submit a request 
to the Regional Supervisor to reclassify the reservoir. You must include 
supporting information, as listed in the table in Sec. 250.1167, with 
your request.
    (e) If information indicates that a reservoir previously classified 
as sensitive is now non-sensitive, you may submit a request to the 
Regional Supervisor to reclassify the reservoir. You must include 
supporting information, as listed in the table in Sec. 250.1167, with 
your request.



Sec. 250.1155  What information must I submit for sensitive reservoirs?

    You must submit to the Regional Supervisor an original and two 
copies of Form MMS-127; one of the copies must be a public information 
copy in accordance with Sec. Sec. 250.186 and 250.197, and marked 
``Public Information.'' You must also submit two copies of the 
supporting information, as listed in the table in Sec. 250.1167. You 
must submit this information:
    (a) Within 45 days after beginning production from the reservoir or 
discovering that it is sensitive;
    (b) At least once during the calendar year, but you do not need to 
resubmit unrevised structure maps (Sec. 250.1167(a)(2)) or previously 
submitted well logs (Sec. 250.1167(c)(1));
    (c) Within 45 days after you revise reservoir parameters; and
    (d) Within 45 days after the Regional Supervisor classifies the 
reservoir as sensitive under Sec. 250.1154(c).

                      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 MMS 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

[[Page 216]]

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 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:

[[Page 217]]



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

    (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).
    (c) The Regional Supervisor may establish alternative approval 
procedures to cover situations when you cannot contact the MMS 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 part 202 of this title. You must value any gas or liquid 
hydrocarbons avoidably lost or wasted under the provisions of part 206 
of this title.
    (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

[[Page 218]]

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 part 202 of this title. You must value any liquid 
hydrocarbons avoidably lost or wasted under the provisions of part 206 
of this title.



Sec. 250.1163  How must I measure gas flaring or venting volumes and 

liquid hydrocarbon burning volumes, and what records must I maintain?

    (a) If your facility processes more than an average of 2,000 bopd 
during May 2010, you must install flare/vent meters within 180 days 
after May 2010. If your facility processes more than an average of 2,000 
bopd during a calendar month after May 2010, you must install flare/vent 
meters within 120 days after the end of the month in which the average 
amount of oil processed exceeds 2,000 bopd.
    (1) You must notify the Regional Supervisor when your facility 
begins to process more than an average of 2,000 bopd in a calendar 
month;
    (2) The flare/vent meters must measure all flared and vented gas 
within 5 percent accuracy;
    (3) You must calibrate the meters regularly, in accordance with the 
manufacturer's recommendation, or at least once every year, whichever is 
shorter; and
    (4) You must use and maintain the flare/vent meters for the life of 
the facility.
    (b) You must report all hydrocarbons produced from a well 
completion, including all gas flared, gas vented, and liquid 
hydrocarbons burned, to Minerals Revenue Management on Form MMS-4054 
(Oil and Gas Operations Report), in accordance with Sec. 210.102 of 
this title.
    (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

[[Page 219]]

years and have them available for inspection by MMS representatives.
    (2) After 2 years, you must maintain the records, allow MMS 
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 MMS representatives.
    (ii) After 2 years, you must maintain the recordings, allow MMS 
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:
    (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, 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 Sec. 250.303, to determine the 
potential effect of facility emissions. The Regional Supervisor may 
require monitoring and reporting, or may restrict or prohibit flaring, 
under Sec. Sec. 250.303 and 250.304.
    (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.

[[Page 220]]

    (b) Before initiating enhanced recovery operations, you must submit 
a proposed plan to the 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 MMS-
127 and supporting data as required in Sec. 250.1167, and any 
additional information required by the Regional Supervisor.
    (c) You must report to Minerals Revenue Management the volumes of 
oil, gas, or other substances injected, produced, or produced for a 
second time under Sec. 210.102 of this title.



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 MMS and the State of 
Alaska, MMS and the Alaska Oil and Gas Conservation Commission will 
jointly determine appropriate reporting requirements to minimize or 
eliminate duplicate reporting requirements.
    (c) Every time you are required to submit Form MMS-127 under Sec. 
250.1155, you must request an MER for each producing sensitive reservoir 
in the Alaska OCS Region, unless otherwise instructed by the Regional 
Supervisor.



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 forms identified in columns 1 and 2 and for the approvals 
required under this subpart identified in columns 3 through 6:

----------------------------------------------------------------------------------------------------------------
                                                                                                      Production
                                    WPT MMS-    SRI MMS-                                              within 500-
                                     126 (2      127 (2      Gas cap     Downhole       Reservoir       ft of a
                                     copies)     copies)   production  commingling  reclassification    unit or
                                                                                                      lease line
----------------------------------------------------------------------------------------------------------------
(a) Maps:
    (1) Base map with surface,     ..........  ..........    [radic]      [radic]   ................    [radic]
     bottomhole, and completion
     locations with respect to
     the unit or lease line and
     the orientation of
     representative seismic lines
     or cross-sections...........
    (2) Structure maps with          [radic]     [radic]     [radic]      [radic]        [radic]        [radic]
     penetration point and subsea
     depth for each well
     penetrating the reservoirs,
     highlighting subject wells;
     reservoir boundaries; and
     original and current fluid
     levels......................
    (3) Net sand isopach with      ..........          *     [radic]      [radic]
     total net sand penetrated
     for each well, identified at
     the penetration point.......
    (4) Net hydrocarbon isopach    ..........          *     [radic]      [radic]
     with net feet of pay for
     each well, identified at the
     penetration point...........
(b) Seismic data:
    (1) Representative seismic     ..........  ..........    [radic]      [radic]   ................    [radic]
     lines, including strike and
     dip lines that confirm the
     structure; indicate polarity
    (2) Amplitude extraction of    ..........  ..........    [radic]      [radic]        [radic]        [radic]
     seismic horizon, if
     applicable..................
(c) Logs:
    (1) Well log sections with       [radic]     [radic]     [radic]      [radic]        [radic]        [radic]
     tops and bottoms of the
     reservoir(s) and proposed or
     existing perforations.......
    (2) Structural cross-sections  ..........  ..........    [radic]      [radic]        [radic]              *
     showing the subject well and
     nearby wells................
(d) Engineering data:

[[Page 221]]

 
    (1) Estimated recoverable      ..........    [radic]    [dagger]     [dagger]   ................    [radic]
     reserves for each well
     completion in the reservoir;
     total recoverable reserves
     for each reservoir; method
     of calculation; reservoir
     parameters used in
     volumetric and decline curve
     analysis....................
    (2) Well schematics showing    ..........  ..........    [radic]      [radic]   ................    [radic]
     current and proposed
     conditions..................
    (3) The drive mechanism of     ..........    [radic]     [radic]      [radic]        [radic]        [radic]
     each reservoir..............
    (4) Pressure data, by date,    ..........  ..........    [radic]      [radic]        [radic]
     and whether they are
     estimated or measured.......
    (5) Production data and        ..........  ..........    [radic]      [radic]        [radic]
     decline curve analysis
     indicative of the reservoir
     performance.................
    (6) Reservoir simulation with  ..........  ..........          *            *              *              *
     the reservoir parameters
     used, history matches, and
     prediction runs (include
     proposed development
     scenario)...................
(e) General information:
    (1) Detailed economic          ..........  ..........          *            *
     analysis....................
    (2) Reservoir name and         ..........    [radic]     [radic]      [radic]        [radic]        [radic]
     whether or not it is
     competitive as defined under
     Sec.  250.105..............
    (3) Operator name, lessee      ..........  ..........    [radic]      [radic]   ................    [radic]
     name(s), block, lease
     number, royalty rate, and
     unit number (if applicable)
     of all relevant leases......
    (4) Geologic overview of       ..........  ..........    [radic]      [radic]        [radic]        [radic]
     project.....................
    (5) Explanation of why the     ..........  ..........    [radic]      [radic]   ................    [radic]
     proposed completion scenario
     will maximize ultimate
     recovery....................
    (6) List of all wells in       ..........  ..........    [radic]      [radic]        [radic]        [radic]
     subject reservoirs that have
     ever produced or been used
     for injection...............
----------------------------------------------------------------------------------------------------------------
[radic] 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

    Source: 63 FR 26370, May 12, 1998, unless otherwise noted. 
Redesignated at 63 FR 29479, May 29, 1998.



Sec. 250.1200  Question index table.

    The table in this section lists questions concerning Oil and Gas 
Production Measurement, Surface Commingling, and Security.

------------------------------------------------------------------------
        Frequently asked questions                  CFR citation
------------------------------------------------------------------------
 1. What are the requirements for           Sec.  250.1202(a)
 measuring liquid hydrocarbons?.
 2. What are the requirements for liquid    Sec.  250.1202(b)
 hydrocarbon royalty meters?.
 3. What are the requirements for run       Sec.  250.1202(c)
 tickets?.
 4. What are the requirements for liquid    Sec.  250.1202(d)
 hydrocarbon royalty meter provings?.
 5. What are the requirements for           Sec.  250.1202(e)
 calibrating a master meter used in
 royalty meter provings?.
 6. What are the requirements for           Sec.  250.1202(f)
 calibrating mechanical-displacement
 provers and tank provers?.
 7. What correction factors must a lessee   Sec.  250.1202(g)
 use when proving meters with a mechanical
 displacement prover, tank prover, or
 master meter?............................

[[Page 222]]

 
 8. What are the requirements for           Sec.  250.1202(h)
 establishing and 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   Sec.  250.1202(l)
 and inventory tank facilities?.
13. To which meters do MMS requirements     Sec.  250.1203(a)
 for gas measurement apply?.
14. What are the requirements for           Sec.  250.1203(b)
 measuring gas?.
15. What are the requirements for gas       Sec.  250.1203(c)
 meter calibrations?.
16. What must a lessee do if a gas meter    Sec.  250.1203(d)
 is out of calibration or malfunctioning?.
17. What are the requirements when natural  Sec.  250.1203(e)
 gas from a Federal lease is transferred
 to a gas plant before royalty
 determination?...........................
18. What are the requirements for           Sec.  250.1203(f)
 measuring gas lost or used on a lease?.
19. What are the requirements for the       Sec.  250.1204(a)
 surface commingling of production?.
20. What are the requirements for a         Sec.  250.1204(b)
 periodic well test used for allocation?.
21. What are the requirements for site      Sec.  250.1205(a)
 security?.
22. What are the requirements for using     Sec.  250.1205(b)
 seals?.
------------------------------------------------------------------------


[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



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 30 CFR 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.
    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.

[[Page 223]]

    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.
    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.
    Pipeline (retrograde) condensate--liquid hydrocarbons which drop out 
of the separated gas stream at any point in a pipeline during 
transmission to shore.
    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).

[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 73 FR 20171, Apr. 15, 
2008; 74 FR 40073, Aug. 11, 2009]



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 that will accurately measure the 
liquid hydrocarbons produced from a lease or unit;
    (3) Use procedures and correction factors according to the 
applicable chapters of the API MPMS as incorporated by reference in 30 
CFR 250.198, when obtaining net standard volume and associated 
measurement parameters; and

[[Page 224]]

    (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 MMS-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 30 CFR 250.198);
    (ii) The sample container is vapor-tight and includes a power mixing 
device to allow complete mixing of the sample before removal from the 
container; and
    (iii) The sample probe is in the center half of the pipe diameter in 
a vertical run and is located at least three pipe diameters downstream 
of any pipe fitting within a region of turbulent flow. The sample probe 
can be located in a horizontal pipe if adequate stream conditioning such 
as power mixers or static mixers are installed upstream of the probe 
according to the manufacturer's instructions.
    (c) What are the requirements for run tickets? You must:
    (1) For royalty 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 MMS 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

[[Page 225]]

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; and
    (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 referenced in 30 
CFR 250.198:
    (1) The change in prover volume due to the effect of temperature on 
steel (Cts);
    (2) The change in prover volume due to the effect of pressure on 
steel (Cps);
    (3) The change in liquid volume due to the effect of temperature on 
a liquid (Ctl); and
    (4) The change in liquid volume due to the effect of pressure on a 
liquid (Cpl).
    (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:

[[Page 226]]

    (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 30 CFR 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
    (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 MMS 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 
correction factors and procedures in the API MPMS as incorporated by 
reference in 30 CFR 250.198.

[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 63 FR 33853, June 22, 1998; 64 FR 72794, Dec. 28 
1999; 71 FR 40912, July 19, 2006; 72 FR 25201, May 4, 2007; 73 FR 20171, 
Apr. 15, 2008; 74 FR 40073, Aug. 11, 2009]



Sec. 250.1203  Gas measurement.

    (a) To which meters do MMS requirements for gas measurement apply? 
MMS 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

[[Page 227]]

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 
to ensure accurate and verifiable measurement. You must follow the 
recommendations in API MPMS as incorporated by reference in 30 CFR 
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 as referenced in 30 CFR 250.198.
    (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 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 MMS 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 MMS 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.

[[Page 228]]

    (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 212.
    (5) Upon the request of the Regional Supervisor, you must provide 
copies of the records.

[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 63 FR 33853, June 22, 1998; 64 FR 72794, Dec. 28, 
1999; 71 FR 40912, July 19, 2006; 74 FR 40073, Aug. 11, 2009]



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.
    (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.

[63 FR 26370, May 12, 1998. Redesignated at 63 FR 29479, May 29, 1998; 
63 FR 33853, June 22, 1998; 71 FR 40913, July 19, 2006; 73 FR 20171, 
Apr. 15, 2008; 74 FR 40073, Aug. 11, 2009]



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 MMS-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

[[Page 229]]

    (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 MMS inspection.



                          Subpart M_Unitization

    Source: 62 FR 5331, Feb. 5, 1997, unless otherwise noted. 
Redesignated at 63 FR 29479, May 29, 1998.



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
    (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) MMS orders or approves a suspension of production or operations 
for your lease.

[[Page 230]]

    (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 
MMS 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) MMS orders or approves a suspension of operations under Sec. 
250.170.

[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 73 FR 20172, Apr. 15, 
2008]



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 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 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 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), MMS 
will initiate unitization under Sec. 250.1304.

[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998]



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.

[[Page 231]]

    (b) The unit agreement must comply with the requirements of this 
part. MMS will maintain and provide a model unit agreement for you to 
follow. If MMS revises the model, MMS 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.

[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998; 70 FR 49876, Aug. 25, 2005]



Sec. 250.1304  How will MMS 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 MMS 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:
    (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, MMS 
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 MMS 
provides all lessees of the proposed unit area written notice and an 
opportunity for a hearing. If you want MMS 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) MMS will not hold a hearing under this paragraph until at least 
30 days after MMS 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

[[Page 232]]

Regional Supervisor under 30 CFR part 290.

[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



            Subpart N_Outer Continental Shelf Civil Penalties

    Source: 62 FR 42668, Aug. 8, 1997, unless otherwise noted. 
Redesignated at 63 FR 29479, May 29, 1998.

            Outer Continental Shelf Lands Act Civil Penalties



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

    This subpart explains MMS's 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 MMS determines, 
on the basis of available evidence, that a violation occurred and a 
civil penalty review is appropriate, it will prepare a case file. MMS 
will appoint a Reviewing Officer.



Sec. 250.1401  Index table.

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

                          Sec.  250.1401 Table
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Definitions...............................  Sec.  250.1402
What is the maximum civil penalty?........  Sec.  250.1403
Which violations will MMS review for        Sec.  250.1404
 potential civil penalties?.
When is a case file developed?............  Sec.  250.1405
When will MMS 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
------------------------------------------------------------------------


[62 FR 42668, Aug. 8, 1997. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



Sec. 250.1402  Definitions.

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