[Federal Register Volume 77, Number 163 (Wednesday, August 22, 2012)]
[Rules and Regulations]
[Pages 50855-50901]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-20090]



[[Page 50855]]

Vol. 77

Wednesday,

No. 163

August 22, 2012

Part III





Department of the Interior





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Bureau of Safety and Environmental Enforcement





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30 CFR Part 250





Oil and Gas and Sulphur Operations on the Outer Continental Shelf--
Increased Safety Measures for Energy Development on the Outer 
Continental Shelf; Final Rule

Federal Register / Vol. 77 , No. 163 / Wednesday, August 22, 2012 / 
Rules and Regulations

[[Page 50856]]


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DEPARTMENT OF THE INTERIOR

Bureau of Safety and Environmental Enforcement

30 CFR Part 250

[Docket ID BSEE-2012-0002]
RIN 1014-AA02


Oil and Gas and Sulphur Operations on the Outer Continental 
Shelf--Increased Safety Measures for Energy Development on the Outer 
Continental Shelf

AGENCY: Bureau of Safety and Environmental Enforcement (BSEE), 
Interior.

ACTION: Final rule.

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SUMMARY: This Final Rule implements certain safety measures recommended 
in the report entitled, ``Increased Safety Measures for Energy 
Development on the Outer Continental Shelf.'' To implement the 
appropriate recommendations in the Safety Measures Report and DWH JIT 
report, BSEE is amending drilling, well-completion, well-workover, and 
decommissioning regulations related to well-control, including: subsea 
and surface blowout preventers, well casing and cementing, secondary 
intervention, unplanned disconnects, recordkeeping, and well plugging.

DATES: Effective Date: This rule becomes effective on October 22, 2012. 
The incorporation by reference of certain publications listed in the 
rule is approved by the Director of the Federal Register as of October 
22, 2012.

FOR FURTHER INFORMATION CONTACT: Kirk Malstrom, Bureau of Safety and 
Environmental Enforcement (BSEE), Office of Offshore Regulatory 
Programs, Regulations Development Branch, 703-787-1751, 
kirk.malstrom@bsee.gov.

Executive Summary

    On October 14, 2010, the Bureau of Offshore Energy Management, 
Regulation, and Enforcement (BOEMRE) published the Interim Final Rule 
(75 FR 63346), ``Increased Safety Measures for Energy Development on 
the Outer Continental Shelf.'' The Interim Final Rule (IFR) addressed 
certain recommendations from the Secretary of the Interior to the 
President entitled, ``Increased Safety Measures for Energy Development 
on the Outer Continental Shelf '' (Safety Measures Report). The Bureau 
of Safety and Environmental Enforcement (BSEE) is publishing this Final 
Rule in response to comments on the requirements implemented in the 
IFR. This rulemaking:
     Establishes new casing installation requirements;
     Establishes new cementing requirements;
     Requires independent third party verification of blind-
shear ram capability;
     Requires independent third party verification of subsea 
BOP stack compatibility;
     Requires new casing and cementing integrity tests;
     Establishes new requirements for subsea secondary BOP 
intervention;
     Requires function testing for subsea secondary BOP 
intervention;
     Requires documentation for BOP inspections and 
maintenance;
     Requires a Registered Professional Engineer to certify 
casing and cementing requirements; and
     Establishes new requirements for specific well control 
training to include deepwater operations.
    This Final Rule changes the Interim Final Rule (IFR) in the 
following ways:
     Updates the incorporation by reference to the second 
edition of API Standard 65--Part 2, which was issued December 2010. 
This standard outlines the process for isolating potential flow zones 
during well construction. The new Standard 65--Part 2 enhances the 
description and classification of well-control barriers, and defines 
testing requirements for cement to be considered a barrier.
     Revises requirements from the IFR on the installation of 
dual mechanical barriers in addition to cement for the final casing 
string (or liner if it is the final string), to prevent flow in the 
event of a failure in the cement. The Final Rule provides that, for the 
final casing string (or liner if it is the final string), an operator 
must install one mechanical barrier in addition to cement, to prevent 
flow in the event of a failure in the cement. The final rule also 
clarifies that float valves are not mechanical barriers.
     Revises Sec.  250.423(c) to require the operator to 
perform a negative pressure test only on wells that use a subsea 
blowout preventer (BOP) stack or wells with a mudline suspension system 
instead of on all wells, as was provided in the Interim Final Rule.
     Adds new Sec.  250.451(j) stating that an operator must 
have two barriers in place before removing the BOP, and that the BSEE 
District Manager may require additional barriers.
     Extends the requirements for BOPs and well-control fluids 
to well-completion, well-workover, and decommissioning operations under 
Subpart E--Oil and Gas Well-Completion Operations, Subpart F--Oil and 
Gas Well-Workover Operations, and Subpart Q--Decommissioning Activities 
to promote consistency in the regulations.

SUPPLEMENTARY INFORMATION: 

Table of Contents

I. Background
II. Source of Specific Provisions Addressed in the Final Rule
III. Overview of the Interim Final Rule as Amended by This Rule
IV. Comments Received on the Interim Final Rule
V. Section-by-Section Discussion of the Requirements in Final Rule
VI. Compliance Costs
VII. Procedural Matters

I. Background

    This Final Rule was initiated as an IFR published by the BOEMRE on 
October 14, 2010 (75 FR 63346). The IFR was effective immediately, with 
a 60-day comment period. On October 1, 2011, the BOEMRE, formerly the 
Minerals Management Service, was replaced by the Bureau of Ocean Energy 
Management (BOEM) and the Bureau of Safety and Environmental 
Enforcement (BSEE) as part of the reorganization. This Final Rule falls 
under the authority of BSEE and as such, a new Regulation Identifier 
Number (RIN) has been assigned to this rulemaking. The new RIN for this 
Final Rule is 1014-AA02, and replaces RIN 1010-AD68 from the IFR. This 
Final Rule modifies, in part, provisions of the IFR based on comments 
received. After reviewing the comments, however, BSEE retained many of 
the provisions adopted on October 14, 2010 without change.
    Some revisions to the IFR herein are additionally noteworthy in 
that they respond to comments we received and/or are consistent as 
possible with recommendations in the Deepwater Horizon Joint 
Investigation Team (DWH JIT) report, to the degree that those 
recommendations are within the scope of the IFR or can be considered a 
logical outgrowth of the IFR. These changes include the following:
     Clarification that the use of a dual float valve is not 
considered a sufficient mechanical barrier.
     Clarification in Sec.  250.443 stating that all BOP 
systems must include a wellhead assembly with a rated working pressure 
that exceeds the maximum anticipated wellhead pressure instead of the 
maximum anticipated surface pressure as was previously provided.
     In Sec.  250.1500 revising the definition of well-control 
to clarify that persons performing well monitoring and maintaining 
well-control must be trained. This new definition encompasses anyone 
who has

[[Page 50857]]

responsibility for monitoring the well and/or maintaining the well-
control equipment.
    This Final Rule is promulgated for the prevention of waste and for 
the conservation of natural resources of the Outer Continental Shelf 
(OCS), under the rulemaking authority of the Outer Continental Shelf 
Lands Act (the Act), 43 U.S.C. 1334.
    This rule is based on certain recommendations in the May 27, 2010, 
report from the Secretary of the Interior to the President entitled, 
``Increased Safety Measures for Energy Development on the Outer 
Continental Shelf'' (Safety Measures Report). The President directed 
that the Department of the Interior (DOI) develop this report as a 
result of the Deepwater Horizon event on April 20, 2010. This event, 
which involved a blowout of the BP Macondo well and an explosion on the 
Transocean Deepwater Horizon mobile offshore drilling unit (MODU), 
resulted in the deaths of 11 workers, an oil spill of national 
significance, and the sinking of the Deepwater Horizon MODU. On June 2, 
2010, the Secretary of the Interior directed BOEMRE to adopt the 
recommendations contained in the Safety Measures Report and to 
implement them as soon as possible. As noted in the regulatory impact 
analysis accompanying this rule, other recommendations will be 
addressed in other future rulemakings and will be available for public 
comment. Final Regulatory Impact Analysis for the Final Rule on 
Increased Safety Measures for Energy Development on the Outer 
Continental Shelf, RIN 1014-AA02, at 9 (BSEE; March 7, 2012). 
Similarly, BSEE's actions here are not intended to supplant any actions 
by BSEE or other authorized government authorities warranted by fact 
finding or other factual development in other proceedings, including 
but not limited to those in Multi-District Litigation No. 2179, In Re: 
Oil Spill by the OIL RIG DEEPWATER HORIZON in the GULF OF MEXICO, on 
April 2010 (E.D. La.).

II. Source of Specific Provisions Addressed in the Interim Final Rule

    The Safety Measures Report recommended a series of steps designed 
to improve the safety of offshore oil and gas drilling operations in 
Federal waters. It outlined a number of specific measures designed to 
ensure sufficient redundancy in BOPs, promote well integrity, enhance 
well-control, and facilitate a culture of safety through operational 
and personnel management. The IFR addressed both new well bore 
integrity requirements and well-control equipment requirements. The 
well bore integrity provisions impose requirements for casing and 
cementing design and installation, tighter cementing practices, the 
displacement of kill-weight fluids, and testing of independent well 
barriers. These new requirements were intended to ensure that 
additional physical barriers exist in wells to prevent oil and gas from 
escaping into the environment. These new requirements related to well 
bore integrity were intended to decrease the likelihood of a loss of 
well-control. The well-control equipment requirements in the IFR help 
ensure the BOPs will operate in the event of an emergency and that the 
Remotely Operated Vehicles (ROVs) are capable of activating the BOPs.
    The following provisions in the IFR were identified in the Safety 
Measures Report as being appropriate to implement through an emergency 
rulemaking:

------------------------------------------------------------------------
    Safety measures report provision       Interim final rule citations
------------------------------------------------------------------------
Establish deepwater well-control         Sec.   250.442 What are the
 procedure guidelines (safety report      requirements for a subsea BOP
 rec. II.A.1).                            system?
                                         Sec.   250.515 Blowout
                                          prevention equipment.
                                         Sec.   250.615 Blowout
                                          prevention equipment.
                                         Sec.  Sec.   250.1500 through
                                          250.1510 Subpart O--Well-
                                          control and Production Safety
                                          Training.
Establish new fluid displacement         Sec.   250.456 What safe
 procedures (safety report rec. II.A.2).  practices must the drilling
                                          fluid program follow?
Develop additional requirements or       Sec.   250.423 What are the
 guidelines for casing installation       requirements for pressure
 (safety report rec. II.B.2.6).           testing casing?
------------------------------------------------------------------------

    BOEMRE also included the following provision in the IFR from the 
Safety Measures Report:

------------------------------------------------------------------------
    Safety measures report provision            Interim final rule
------------------------------------------------------------------------
Enforce tighter primary cementing        Sec.   250.415 What must my
 practices (safety report rec.II.B.3.7).  casing and cementing programs
                                          include?
------------------------------------------------------------------------

    BOEMRE determined that it was appropriate for inclusion in the IFR 
because it is consistent with the intent of the recommendations in the 
Safety Measures Report. Tighter requirements for cementing practices 
increase the safety of offshore oil and gas drilling operations.
    Much of the October 14, 2010, Federal Register preamble supporting 
the need for emergency rulemaking procedures also supports retaining 
these provisions permanently.

III. Overview of the Interim Final Rule as Amended by This Rule

    The primary purpose of this Final Rule is to address comments 
received, make appropriate revisions, and bring to closure the 
rulemaking begun by the IFR. Together, the two rules clarify and 
incorporate safeguards that will decrease the likelihood of a blowout 
during drilling, completion, workover, and abandonment operations on 
the OCS. For example, the safeguards address well bore integrity and 
well-control equipment. In sum, the two rules:
    (1) Establish new casing installation requirements;
    (2) Establish new cementing requirements;
    (3) Require independent third-party verification of blind-shear ram 
capability;
    (4) Require independent third-party verification of subsea BOP 
stack compatibility;
    (5) Require new casing and cementing integrity tests;

[[Page 50858]]

    (6) Establish new requirements for subsea secondary BOP 
intervention;
    (7) Require function testing for subsea secondary BOP intervention;
    (8) Require documentation for BOP inspections and maintenance;
    (9) Require a Registered Professional Engineer to certify casing 
and cementing requirements; and
    (10) Establish new requirements for specific well-control training 
to include deepwater operations.

IV. Comments Received on the Interim Final Rule

    Although the IFR was effective immediately upon publication in the 
Federal Register, the IFR included a request for public comments. BSEE 
received 38 comments on the IFR. The following table categorizes the 
commenters:

------------------------------------------------------------------------
                                                              Number of
                       Commenter type                          comments
------------------------------------------------------------------------
Oil and Gas Industry/Organizations.........................           21
Other Non-Government Organizations.........................            6
Individuals................................................            8
Government Federal/State...................................            3
                                                            ------------
    Total..................................................           38
------------------------------------------------------------------------

    A number of comments included topics that were outside the scope of 
this rulemaking. Some provided suggestions for future rulemakings; 
other comments related to the Deepwater Horizon event, speculating on 
the causes of the event and suggesting additional changes based on 
their understanding of that event. While we requested comments on 
future rulemakings, we are not specifically addressing those comments 
in this rule; we will however, consider those suggestions in related 
future rulemakings. To the degree that comments assert that compliance 
with current rules or standards incorporated by reference may be 
infeasible in certain situations, and that such provisions need to be 
revised, BSEE will examine the need to revise its rules. Pending any 
future revisions of such provisions, persons subject to compliance may 
seek BSEE approval of either alternative procedures or equipment under 
Sec.  250.141 or departures from such requirements under Sec.  250.142. 
In this Final Rule, BSEE only responds to comments that relate directly 
to this rulemaking. All comments BSEE received on the IFR are available 
at www.regulations.gov under Docket ID: BSEE-2012-0002.
    BSEE received a number of comments asserting that in making the IFR 
effective immediately upon publication, we did not follow the 
appropriate rulemaking process as required by the Administrative 
Procedure Act (APA). BSEE disagrees with these comments. In issuing the 
IFR, BOEMRE followed procedures authorized under the APA at 5 U.S.C. 
553(b) and (d). BOEMRE provided justification in the IFR for not 
seeking public comment in advance, and for the immediate effective 
date. BSEE believes that the justification provided at that time was 
sufficient and will not repeat that justification here.
    In this Final Rule, BSEE is publishing revisions to the IFR based 
on the comments we received. Analysis of the comments also confirms the 
agency's earlier conclusions regarding those portions of the IFR that 
are not modified in this Final Rule. To help organize and present the 
comments received and the BSEE response to the comments, BSEE has 
developed 3 separate tables. Except for one issue, the following three 
tables summarize the comments received, and contain BSEE's response to 
those comments. (Comments pertaining to the ``should/must'' issue 
related to Sec.  250.198(a) are addressed in the section-by-section 
discussion with specific comments being addressed in a separate 
document included in the Administrative Record.) The first table 
relates to comments received on specific sections. The second table 
relates to broader topics and general questions not connected to a 
specific section. The third table addresses comments regarding the 
Regulatory Impact Analysis. Following the comment discussions, we 
include a section-by-section analysis of the Final Rule describing 
changes we made from the IFR. We do not repeat here the basis and 
purpose for each of the provisions of the sections retained from the 
IFR.

                                Table 1--Specific Sections Comments and Responses
----------------------------------------------------------------------------------------------------------------
            Section--topic                            Comment                           BSEE response
----------------------------------------------------------------------------------------------------------------
Sec.   250.198(h)(79)--API Standard 65  API Standard 65--Part 2, Isolating   BSEE has reviewed API Standard 65--
 2nd edition.                            Potential Flow Zones During Well     Part 2 2nd edition and has
                                         Construction, Second Edition was     determined that it is appropriate
                                         published on December 10, 2010.      to incorporate the latest edition
                                         The Second Edition incorporates      in our regulations.
                                         learnings from the Macondo well
                                         incident, enhances the description
                                         and classification of well-control
                                         barriers, and defines testing
                                         requirements for cement to be
                                         considered a barrier. The Second
                                         Edition also revises Annex D into
                                         a checklist based on the
                                         requirements of the document.
                                         BOEMRE should update the IFR to
                                         incorporate the 2nd Edition by
                                         reference.
----------------------------------------------------------------------------------------------------------------
Sec.   250.198(h)(79)--API Standard 65  Provide clarification on how API RP  BSEE developed a compliance table,
 2nd edition.                            65-2 will be used; will a minimum    based on API Standard 65--Part 2
                                         pre-cementing score be required      (see Table 4) for guidance. This
                                         for each cement job and then         Final Rule does not require
                                         evaluated after the job also? (or    operators to use this table;
                                         checklist if using the Second        however, the operator may answer
                                         Edition).                            the questions in the table, along
                                                                              with the written descriptions
                                                                              where needed, or the operator may
                                                                              supply a written description in an
                                                                              alternate format as required in
                                                                              Sec.   250.415(f) which is
                                                                              submitted with the APD. If the
                                                                              operator does not supply enough
                                                                              information to confirm compliance,
                                                                              then BSEE may return the permit
                                                                              application for clarification.
                                                                              BSEE does not plan to use a
                                                                              scoring system; the operator must
                                                                              submit how it evaluated API
                                                                              Standard 65 part 2 when designing
                                                                              its cement program. The operator
                                                                              is not required to submit a post-
                                                                              cement job evaluation.
----------------------------------------------------------------------------------------------------------------
Sec.   250.415(f), Sec.   250.416(e)..  Will the submittal be with each      The operator is required to submit
                                         APD, or once for each rig per year   the written description of how the
                                         unless changed?                      best practices in API Standard 65--
                                                                              Part 2 were evaluated and the
                                                                              qualifications of the independent
                                                                              third-party with each APD.
----------------------------------------------------------------------------------------------------------------

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Sec.   250.416(d).....................  Confirm that the schematic of the    BSEE agrees that the schematics of
                                         control system includes location,    the control systems should include
                                         control system pressure for BOP      these items. The location of
                                         functions, BOP functions at each     control stations are not required
                                         control station, and emergency       to be submitted. While it is
                                         sequence logic. Specifications on    critical to have control stations,
                                         other requirements should be clear.  the actual location of the control
                                                                              stations is not critical.
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(e).....................  Will there be a standard way to      BSEE does not require a standard
                                         perform shearing calculations for    method to perform shearing
                                         the drill pipe?                      calculations; different
                                                                              manufacturers have different
                                                                              methods of calculating shearing
                                                                              requirements. The documentation
                                                                              the operator provides, however,
                                                                              needs to explain and support the
                                                                              methodology used in performing the
                                                                              calculations and arriving at the
                                                                              test results.
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(e).....................  Will there be a standard of          BSEE does not require a standard
                                         calculation for the Maximum          procedure for MASP or shearing
                                         Anticipated Surface Pressure         calculations. In Sec.
                                         (MASP)?                              250.413(f), MASP for drilling is
                                                                              defined along with the
                                                                              considerations for calculations.
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(e).....................  Will the maximum MASP be the rating  The MASP for shearing calculations
                                         of the annulars?                     will not be based on the annular
                                                                              rating. There are multiple methods
                                                                              to calculate the MASP. It is the
                                                                              responsibility of the operator to
                                                                              select the appropriate method,
                                                                              depending upon the situation.
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(e).....................  Is it a requirement of the deadman   Yes, the shear rams installed in
                                         to also shear at MASP?               the BOP must be able to shear
                                                                              drill pipe at MASP.
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(e).....................  If there is a requirement of the     BSEE is researching this issue and
                                         deadman to also shear at MASP,       may address it in future
                                         what usable volume and pressure      rulemaking.
                                         should remain after actuation?
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(e).....................  Please confirm that operators will   BSEE agrees with this comment. We
                                         only be required to demonstrate      revised Sec.   250.416 to
                                         shearing capacity for drill pipe     specifically include workstring
                                         (which includes workstring and       and tubing.
                                         tubing) that is run across the BOP
                                         stack and that BHA components,
                                         drill collars, HWDP, casing,
                                         concentric strings, and lower
                                         completion assemblies are excluded
                                         from this requirement.
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(e).....................  A better requirement would be to     BSEE revised this section in this
                                         demonstrate shearing capacity for    Final Rule to include workstring
                                         drill pipe which includes work-      and tubing as drill pipe.
                                         strings and tubing which is run
                                         across the BOP stack.
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(e).....................  Shearing capacity with MASP should   BSEE requires the operator to
                                         be modified to shearing capacity     design for the case in which blind-
                                         with mud hydrostatic pressure plus   shear rams will be exposed to the
                                         a conservative shut-in pressure      MASP. BSEE does not agree that we
                                         limit set by the operator and        need to request operators to
                                         contractor where shut-in is          provide the internal bore pressure
                                         transferred from the annular BOP     shear capacity calculation.
                                         to Ram BOP. At this point            Designing the BOP for the well
                                         increased pressure in the cavity     design and the conditions in which
                                         between the pipe rams and annular    it will be used will ensure that
                                         preventer should be eliminated.      this concern is addressed.
                                         BOEMRE should request the internal
                                         bore pressure shear capacity
                                         calculation to be provided at the
                                         limit of the BOP system and
                                         approval contingent upon MASP
                                         being less than internal bore
                                         pressure limit.
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(e).....................  Modify the requirement for blind-    BSEE disagrees. The operator is
                                         shear rams to reflect the 2,500      required to design for the case in
                                         psi maximum pressure limit when      which blind-shear rams are exposed
                                         placed above all pipe rams and       to the MASP. It is possible that
                                         immediately below the annular on     this situation may occur and this
                                         the subsea BOP stack.                requirement addresses that
                                                                              possibility.
                                        The proposed new API RP-53 4th
                                         Edition states pipe rams must be
                                         used when shut-in pressure exceeds
                                         2,500 psi. When the blind-shear
                                         rams are above all pipe rams in
                                         the stack, the well-control
                                         sequence would be to shut the
                                         annular first and then switch to a
                                         pipe ram if the shut-in pressure
                                         approaches 2,500 psi. With the
                                         blind-shear ram above all pipe
                                         rams, it would be nearly
                                         impossible for the blind-shear
                                         rams to ever experience shut-in
                                         pressures approaching MASP.
----------------------------------------------------------------------------------------------------------------

[[Page 50860]]

 
Sec.   250.416(e).....................  30 CFR 250.416(e) requires           BSEE disagrees with this comment
                                         independent third-party              and the Final Rule continues to
                                         verification of pipe shearing        require independent third-party
                                         calculations at MASP for the blind-  verification. This requirement
                                         shear rams in the BOP stack. Prior   ensures that everyone will perform
                                         to the IFR, this item didn't         the calculations, not just prudent
                                         require the independent third-       operators. Third-party
                                         party verification of shear          verification provides additional
                                         calculations. Prudent operators      and necessary assurance that the
                                         always do those calculations to      blind-shear rams will be able to
                                         (1) comply with the law as it was    shear the drill pipe at MASP. The
                                         written and (2) feel comfortable     additional requirements in this
                                         that pipe can be sheared in an       rulemaking are intended to support
                                         emergency. The requirement for       existing requirements and not
                                         independent third-party              replace them.
                                         verification does not make things
                                         safer in the GoM. Why cannot
                                         BOEMRE regulators just have the
                                         operators do what was already in
                                         the regs? Shear calculations are
                                         very straight forward and tend to
                                         be conservative by 30 percent when
                                         it comes to predicting the
                                         hydraulic pressure needed to shear
                                         tubulars with MASP at the BOP.
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(f).....................  The reliability and operability of   BSEE disagrees. The operator must
                                         the BOP can be confirmed without     pull the BOP stack to surface and
                                         bringing the entire BOP and Lower    complete a between-well
                                         Marine Riser Package (LMRP) to       inspection. The required
                                         surface after each well, by visual   inspection is more thorough than a
                                         inspection of a subsea BOP with an   visual inspection by an ROV and
                                         ROV and through a thorough           will help ensure the integrity of
                                         function and pressure testing        the BOP stack. As required in Sec.
                                         process. Any regulation that would     250.446(a), a between well
                                         require the operator to pull the     inspection must be performed
                                         stack to surface, handle the         according to currently
                                         riser, and re-run it introduces      incorporated API RP 53, sections
                                         more risk to personnel, well bore,   17.10 and 18.10, Inspections. The
                                         and equipment. The proposed new      stump test of the subsea BOP
                                         API RP-53, 4th Edition, states:      before installation was already
                                         ``Section 18.2 Types of Tests.       required under Sec.   250.449(b)
                                         This section addresses the types     as it existed before promulgation
                                         of tests to be performed and the     of the IFR. To conduct a stump
                                         frequency of when those tests are    test, the BOP must be located on
                                         to be performed, realizing that      the surface. The BOP inspection
                                         the BOP can be moved from well-to-   was a recommendation in the Safety
                                         well without returning to surface    Measures Report.
                                         for inspections and testing. For
                                         those cases, a visual inspection
                                         (by ROV) should be performed.
                                         Operability and integrity can be
                                         confirmed by function and pressure
                                         testing. In these instances,
                                         subsequent testing criteria shall
                                         apply for testing parameters.''
                                         This approach is safer and the
                                         regulation must be amended.
Sec.   250.416(f).....................  30 CFR 250.416(f) requires that an   BSEE does not specify how the third-
                                         independent third-party verify       party verifies that the BOP has
                                         that a subsea BOP stack is fit for   not been compromised or damaged
                                         purpose. Section 250.416(f)(2)       from previous service. As required
                                         further requires that the subsea     in Sec.   250.446(a), a between-
                                         BOP stack has not been compromised   well inspection must be performed
                                         or damaged from previous service--   according to API RP 53, sections
                                         no guidance is given on how one is   17.10 and 18.10, Inspections. The
                                         to determine that the subsea BOP     requirement to conduct a stump
                                         hasn't been compromised or damaged.  test of the subsea BOP before
                                        For multi-well projects where it      installation existed before
                                         makes senses to hop the BOP stack    promulgation of the IFR, under
                                         from well to well, would a           Sec.   250.449(b). The operator
                                         successful subsea function test      may not hop the BOP stack from
                                         and pressure test be sufficient      well to well and be in compliance
                                         evidence that the requirement has    with the new provisions of this
                                         been met?.                           section or the previously existing
                                                                              requirements under Sec.
                                                                              250.449(b).
Sec.   250.416(f)(2)..................  This requirement infers that an      In Sec.   250.416(f)(2), BSEE does
                                         inspection of the BOP system is      not specify how the third-party
                                         required to ensure the system has    verifies that the BOP has not been
                                         not been compromised or damaged      compromised or damaged from
                                         from previous service. Please        previous service. However, BSEE
                                         confirm that the agency agrees       has requirements for between-well
                                         that a subsea BOP system is not      inspections in Sec.   250.446(a),
                                         compromised or damaged provided it   and stump testing prior to
                                         can be function tested and           installation in Sec.   250.449(b).
                                         pressure tested in the subsea
                                         environment where it will be in
                                         operation. Standardized pressure
                                         testing in the subsea environment
                                         without visual inspection fulfills
                                         the requirements of Sec.
                                         250.416(f)(2).
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(f)(2)..................  If it is mandated that a visual      The full cost to pull a subsea BOP
                                         inspection between wells is          to the surface following an
                                         required then the cost to            activation of a shear ram or lower
                                         implement of $1.2 MM is grossly      marine riser package (LMRP)
                                         understated. The cost to pull a      disconnect (under Sec.
                                         BOP for a visual inspection is       250.451(i)) in the benefit-cost
                                         underestimated. The cost of          analysis is estimated to be $11.9
                                         pulling a subsea BOP for a visual    million dollars. This amount is
                                         inspection would result in a $5-     within the range suggested by the
                                         $15 million opportunity cost.        commenter. However, the
                                                                              requirement to conduct a visual
                                                                              inspection and test the subsea BOP
                                                                              between wells predated the IFR and
                                                                              was in the previously existing
                                                                              regulation at Sec.   250.446(a).
                                                                              Because this requirement is not a
                                                                              new provision, no compliance costs
                                                                              are assigned in the economic
                                                                              analysis.
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(f)(2)..................  Third-party verification that the    An independent third-party must
                                         BOP stack has not been compromised   confirm that the BOP stack matches
                                         or damaged from previous service     the drawings and will operate
                                         can be accomplished by successful    according to the design. The third-
                                         subsea function and pressure tests   party verification must include
                                         without visual inspection. Between   verification that:
                                         well visual inspections of the BOP
                                         internal components is not
                                         required.
                                                                             (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;

[[Page 50861]]

 
                                                                             (3) The BOP stack will operate in
                                                                              the conditions in which it will be
                                                                              used.
                                                                             BSEE does not specify how the third-
                                                                              party verifies that the BOP has
                                                                              not been compromised or damaged
                                                                              from previous service. However,
                                                                              BSEE has requirements for between-
                                                                              well inspections in Sec.
                                                                              250.446(a), and stump testing
                                                                              prior to installation in Sec.
                                                                              250.449(b).
----------------------------------------------------------------------------------------------------------------
Sec.   250.416(g) Qualification for     The requirements for independent     In response to comments, BSEE
 Independent Third Parties.              third parties to conduct BOP         removed the option for the
                                         inspections fail to provide          independent third-party to be an
                                         globally consistent standards        API-licensed manufacturing,
                                         necessary for the lifecycle use of   inspection, or certification firm
                                         Mobile Offshore Drilling Units       in Sec.   250.416(g)(1) because
                                         (MODUs) on a global basis. The       API does not license such firms.
                                         Interim Rule allows for an API      Section 250.416(g)(1) allows
                                         licensed manufacturing,              registered professional engineers,
                                         inspection, certification firm; or   or a technical classification
                                         licensed engineering firm to carry   society, or licensed professional
                                         out independent third-party          engineering firms to provide the
                                         verification of the BOP system, as   independent third-party
                                         well as technical classification     verification.
                                         societies. We recommend that the    Section 250.416(g)(2)(i) requires
                                         Interim Rule be amended to only      the operator to submit evidence
                                         enable organizations with the        that the registered professional
                                         necessary breadth and depth of       engineers, or a technical
                                         engineering knowledge, and           classification society, or
                                         experience and global reach, and     licensed professional engineering
                                         demonstrable freedom from any        firms or its employees hold
                                         conflict of interest, such as        appropriate licenses to perform
                                         classification societies, can        the verification in the
                                         qualify as `independent third        appropriate jurisdiction, and
                                         parties'. We believe that owing to   evidence to demonstrate that the
                                         the global employment of MODUs,      individual, society, or firm has
                                         where rigs could be engaged          the expertise and experience
                                         anywhere around the world, only      necessary to perform
                                         independent technical                verifications. BSEE may accept the
                                         classification societies have the    verification from any firm or
                                         global reach to ensure consistency   person that meets these
                                         in inspection and verification of    requirements. We will not require
                                         safety critical equipment            the exclusive use of technical
                                         necessary to ensure the safe         classification societies at this
                                         operation of an asset throughout     time.
                                         its lifecycle.
----------------------------------------------------------------------------------------------------------------
Sec.   250.420(a)(6)..................  Certification by a professional      The comment supports the
                                         engineer that there are two          requirements in the IFR. However,
                                         independent tested barriers and      BSEE clarified the requirement for
                                         that the casing and cementing        the two independent barriers,
                                         design are appropriate.              based on other comments.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.420(a)(6),             What is the definition of well-      BSEE clarified the certification
 250.1712(g), and 250.1721(h).           completion activities? This is the   requirement in Sec.
                                         first time it has been mentioned     250.420(a)(6) by removing the term
                                         that barriers had to be certified    ``well-completion activities,''
                                         by a professional engineer, only     because it was redundant in the
                                         casing design and cementing were     context of that provision. The two
                                         mentioned in the past.               required barriers are part of the
                                                                              casing and cementing design.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.420(a)(6),             Will BOEMRE still check casing       There are multiple ways to
 250.1712(g), and 250.1721(h).           designs based on load cases that     calculate the load cases. The
                                         are not published? If so, will       operator must ensure the well
                                         certified plans be rejected due to   design and calculations are
                                         design reviews within the agency?    appropriate for the purpose for
                                         Will Agency design reviews be done   which it is intended under
                                         by Registered Professional           expected wellbore conditions. BSEE
                                         Engineers (RPE)? If not, what will   engineers will conduct the design
                                         be the process for approval when     reviews. Any issues will be
                                         an RPE approved design conflicts     resolved with the operator on a
                                         with the Agency? Will the Agency     case-by-case basis.
                                         mandate a change and take the
                                         responsibility for that change?
Sec.  Sec.   250.420(a)(6),             Liabilities that will be placed      The intent of the PE certification
 250.1712(g), and 250.1721(h)            onto a ``Professional Engineer''     is to ensure that all plans are
 Professional Engineer.                  are an issue. The PE approach        consistent with standard
                                         demands that the PE is intimately    engineering practices. To add to
                                         involved in all aspects of the       safety assurances, BSEE included
                                         design and also in primary           language in Sec.   250.420(a)(6)
                                         communication as the well is         that the Professional Engineer be
                                         drilled and small variations in      involved in the design process.
                                         the plan are made or happen. All     Such person must be included in
                                         liability for the well must remain   the design process so that he or
                                         with the operator without any        she is familiar enough with the
                                         ``dilution'' to a PE, although       final design to make the required
                                         review by a PE or other              certification. Under Sec.
                                         ``independent and reputable''        250.146(c), persons actually
                                         third-party is totally appropriate.  performing an activity on a lease
                                                                              to which a regulatory obligation
                                                                              applies are jointly and severally
                                                                              responsible for compliance. Such
                                                                              third person responsibility does
                                                                              not eliminate or dilute the
                                                                              operator's responsibilities for a
                                                                              well.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.420(a)(6),             Can the required ``registered        Yes, the registered professional
 250.1712(g), and 250.1721(h)            professional engineer'' be a         engineer can be a company
 Professional Engineer.                  company employee?                    employee.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.420(a)(6),             Require that all certifications      BSEE disagrees that the
 250.1712(g), and 250.1721(h)            needed by a Registered               professional engineer must be a
 Professional Engineer.                  Professional Engineer be done by a   petroleum engineer; a professional
                                         Registered Professional Petroleum    engineer with another background
                                         Engineer. It makes no sense at all   who has expertise and experience
                                         to utilize any PE. If so, at least   in well design will be capable of
                                         require a BS in Petroleum            certifying these plans. The
                                         Engineering. There is no             expectation is that a licensed
                                         specification to determine how any   professional engineer will NOT
                                         Registered Professional Engineer     certify anything outside of their
                                         is ``capable of reviewing and        area of expertise. However, in
                                         certifying that the * * * is         response to the commenter's
                                         appropriate for the purpose for      concern, this Final Rule adds an
                                         which it is intended under           expertise and experience
                                         expected wellbore conditions.''      requirement for the person
                                                                              performing the certification.
----------------------------------------------------------------------------------------------------------------

[[Page 50862]]

 
Sec.  Sec.   250.420(a)(6),             The intent of Congress and the Act   The certification requirement is
 250.1712(g), and 250.1721(h).           does not appear to be complied       intended to ensure that all
                                         with by the proposed rule. The use   operators meet basic standards for
                                         of a registered Professional         their cement and casing. This
                                         Engineer to certify casing and       requirement for PE certification
                                         cementing programs when ``The        is a substantial improvement
                                         Registered Professional Engineer     compared to previous rules in
                                         must be registered in a State of     which a certification was not
                                         the United States but does not       mandatory. The final rule has
                                         have to be a specific discipline''   added a provision to assure that a
                                         does not appear to comply with the   licensed professional will NOT
                                         allowance for coordination with      certify anything outside of his or
                                         local Coastal Affected Zone States   her area of expertise and
                                         to have input. Two deficiencies      experience. Because OCS projects
                                         are apparent. One is a licensed      occur offshore from several
                                         professional engineer should not     states, a company may want to use
                                         be certifying anything that he is    the same PE regardless of the
                                         not competent to certify due to      location of any given well.
                                         his education, training and          Furthermore, the certification
                                         experience. The second is that the   requirement applies uniformly to
                                         engineer should be licensed in the   any project in Federal waters.
                                         Coastal Zone Affected State due to   Under these conditions, the
                                         the differences that occur in        certification standard combined
                                         licensing requirements. Some         with the liabilities associated
                                         states are more liberal than         with certification of a plan
                                         others in the exemptions allowed     effectively address certification
                                         and the requirements for             concerns. Also, States with
                                         discipline specific engineering      approved coastal management
                                         licensure. If Texas wants to allow   programs have adequate
                                         a higher risk then Texas offshore    opportunities to express their
                                         Coastal Affected Zones should be     concerns about specific projects
                                         the only zones that are allowed to   under other provisions of the
                                         have such higher risk to be taken.   regulations.
                                         If Louisiana or Mississippi want
                                         to be more restrictive then their
                                         offshore waters should be more
                                         restrictive. This seems to be the
                                         intent of the Coastal Zone
                                         Affected State language in the
                                         federal statutes. As currently
                                         proposed a licensed engineer from
                                         the state of minimum requirements
                                         can be selected.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.420(a)(6),             BOEMRE now requires a Registered     BSEE disagrees that the
 250.1712(g), and 250.1721(h).           Professional Engineer to certify a   professional engineer must be a
                                         number of well design aspects        petroleum engineer; a professional
                                         including: casing and cementing      engineer with another background
                                         design, independent well barriers,   who has experience in well design
                                         and abandonment design. This is a    will be capable of certifying
                                         new, important requirement. BOEMRE   these plans. In response to
                                         does not, however, require that      commenters' concerns, we have
                                         the engineer be certified as a       added an expertise and experience
                                         Registered Professional Engineer     requirement for the certifying
                                         in any particular engineering        person. It is the operator's
                                         discipline. This creates the         responsibility to ensure that the
                                         possibility that a Professional      Registered Professional Engineer
                                         Engineer, with little or no          is qualified and competent to
                                         experience with oil and gas well     perform the work and has the
                                         design, drilling operations or       necessary expertise and
                                         well pressure control could be       experience. The expectation is
                                         certifying these designs. For        that a licensed professional
                                         example, BOEMRE's rule would allow   engineer will NOT certify anything
                                         an electrical engineer to certify    outside of his or her area of
                                         a well design that may have no       expertise. The operator certainly
                                         expertise or experience on           has a strong incentive to assure
                                         offshore well construction design.   that the professional engineer is
                                         We recommend that the Registered     competent because the operator is
                                         Professional Engineer requirement    responsible for the activities on
                                         be limited to the discipline of      the lease and the consequences
                                         Petroleum Engineering, and/or a      thereof.
                                         Registered Professional Engineer
                                         in any engineering discipline that
                                         has more years of experience
                                         designing and drilling offshore
                                         wells. We agree that Registered
                                         Professional Engineers have the
                                         technical capability to assimilate
                                         the knowledge to certify well
                                         construction methods over a period
                                         of time, but only the Registered
                                         Professional Petroleum Engineer is
                                         actually tested on well casing,
                                         cementing, barriers and other well
                                         construction design and safety
                                         issues. Other engineering
                                         disciplines require on-the-job
                                         training and experience to expand
                                         their expertise and apply their
                                         engineering credentials to
                                         offshore well construction design
                                         certification.
----------------------------------------------------------------------------------------------------------------
Sec.   250.420(a)(6)..................  30 CFR 250.420(a)(6) requires that   Requiring a Registered Professional
                                         a Registered Professional Engineer   Engineer's certification helps to
                                         certify barriers across each flow    ensure that the casing and
                                         path and that a well's casing and    cementing design meets accepted
                                         cementing design is fit for its      industry design standards. The
                                         intended purpose under expected      expectation is that licensed
                                         wellbore conditions. There are       professional engineers will NOT
                                         RPE's whose area of expertise        certify anything outside of their
                                         isn't well design or construction.   area of expertise. In response to
                                         There are very few drilling and      this comment, this Final Rule does
                                         completion engineers with both       expand the persons who can make
                                         sufficient expertise to make the     the required certification if they
                                         required assessment and a PE         are registered and have the
                                         license. What in this requirement    requisite expertise and
                                         makes operations in the GoM safer?   experience.
                                         Does BOEMRE plan to consider
                                         changing this requirement to
                                         expand the number of truly
                                         qualified people who can
                                         accurately assess this situation?
                                         What will eventually be the right
                                         standard for the certifying
                                         authority?
----------------------------------------------------------------------------------------------------------------

[[Page 50863]]

 
Sec.  Sec.   250.420(a)(6),             The description of ``flow path''     BSEE revised the regulatory text in
 250.1712(g) and 250.1721(h).            would be improved by commenting on   Sec.   250.420(b)(3) to include an
                                         examples and/or by providing a       example of barriers for the
                                         definition and not including         annular flow path and for the
                                         potential paths, i.e., previously    final casing string or liner. Once
                                         verified or tested mechanical        an operator performs a negative
                                         barriers are accepted without        test on a barrier, the operator
                                         retest. Flow paths in the broadest   does not have to retest it unless
                                         terms would include annular seal     that barrier is altered or
                                         assemblies which may not be          modified. Also, see the subsequent
                                         accessible on existing wells. The    comment responses that address the
                                         assumption that all casing strings   flow paths to which the barrier
                                         can be cut and pulled would result   requirements apply.
                                         in exceptions in the majority of
                                         cases and would introduce a health
                                         and safety risk to operating
                                         personnel and equipment currently
                                         not present.
----------------------------------------------------------------------------------------------------------------
Sec.   250.420(a)(6)..................  Will BOEMRE still check casing       BSEE engineers will check casing
                                         designs based on load cases that     designs. BSEE will resolve any
                                         are not published? If so, will       differences with the operator on a
                                         certified plans be rejected due to   case-by-case basis.
                                         design reviews within the agency?
----------------------------------------------------------------------------------------------------------------
Sec.   250.420(a)(6)..................  BOEMRE has not provided specific     While the list provided by the
                                         guidance on what aspects of casing   commenter contained some good
                                         and cementing designs must be        examples, it is not comprehensive.
                                         initially certified or guidance on   If an activity triggers the need
                                         triggers which would cause a plan    for a revised permit or an APM,
                                         to be recertified for continuance    then the Registered Professional
                                         of operations. The Offshore          Engineer must recertify the
                                         Operators' Committee OOC provided    design. BSEE is working to improve
                                         those triggers to BOEMRE on          consistency among the District
                                         October 12, 2010, and requests       Offices.
                                         they be accepted as the only
                                         triggers for plan certification.
                                         Currently, the BOEMRE is
                                         inconsistent in their requests for
                                         recertification and fearful of
                                         approving minor changes that have
                                         no effect on safety. Further,
                                         delays to operations resulting in
                                         additional operational exposure
                                         and safety risk are to be expected
                                         when the Agency requires arbitrary
                                         recertification when simple
                                         changes are required. The
                                         requirement for an RPE review for
                                         OCS operations may become a
                                         bottleneck if this requirement
                                         becomes a standard for all U.S.
                                         operations.
----------------------------------------------------------------------------------------------------------------
Sec.   250.420(b)(3)..................  Add clarification to the dual        In response, this Final Rule
                                         mechanical barrier requirement to    revises Sec.   250.420(b)(3) to
                                         ensure the barriers are installed    provide that for the final casing
                                         within the casing string and does    string (or liner if it is the
                                         not apply to mechanical barriers     final string), an operator must
                                         that seal the annulus between        install one mechanical barrier, in
                                         casings or between casing and        addition to cement, to prevent
                                         wellhead. Acceptable barriers for    flow in the event of a failure in
                                         annuli shall include at least one    the cement. In response to the
                                         mechanical barrier in the wellhead   comment, we also clarify that a
                                         and cement across and above          dual float valve, by itself, is
                                         hydrocarbon zones. Placement of      not considered a mechanical
                                         cement can be validated by return    barrier. The appropriate BSEE
                                         volume, hydrostatic lift pressure    District Manager may approve
                                         or cased hole logging methods.       alternatives.
                                        Industry best practices do not
                                         consider dual float valves to be
                                         two separate mechanical barriers
                                         because they cannot be tested
                                         independently and because they are
                                         not designed to be gas-tight
                                         barriers. This regulation does not
                                         achieve the safety objectives of
                                         the Drilling Safety Rule.
----------------------------------------------------------------------------------------------------------------
Sec.   250.420(b)(3)..................  Does the dual mechanical barrier     BSEE revised the regulatory text at
                                         requirement apply to just the        Sec.   250.420(b)(3) to clarify
                                         inside of the casing or to both      the requirement that two
                                         the inside and annulus flow paths?   independent barriers are required
                                         Our interpretation is the inside     in each annular flow path
                                         of the casing. It is also not        (examples include, but are not
                                         clear when these dual barriers are   limited to, primary cement job and
                                         required.                            seal assembly) and for the final
                                                                              casing string or liner. The
                                                                              appropriate BSEE District Manager
                                                                              may approve alternatives.
Sec.  Sec.   250.420(b)(3),             The incorporation by reference of    BSEE revised the language in Sec.
 250.1712(g) and 250.1721(h).            API RP 65-2 in Sec.   250.415(f)     250.420(b)(3) to clarify that the
                                         includes a definition of a           operator must install two
                                         mechanical barrier. This either      independent barriers to prevent
                                         confuses or contradicts the use of   flow in the event of a failure in
                                         the phrase ``mechanical barrier''    the cement, and clarified that a
                                         in sections Sec.  Sec.               dual float valve is not considered
                                         250.420(b)(3), 250.1712(g) and       a barrier. The appropriate BSEE
                                         250.1712(h). The description of a    District Manager may approve
                                         ``seal achieved by mechanical        alternative options. BSEE revised
                                         means between two casing strings     the language in Sec.  Sec.
                                         or a casing string and the           250.1712 and 250.1721 to clarify
                                         borehole'' would not be possible     the requirements. For wells being
                                         regarding an existing well,          permanently abandoned and wellhead
                                         specifically for the temporary or    removed, the PE needs to certify
                                         permanent abandonment, and does      that there are two independent
                                         not include seals that are not in    barriers in the center wellbore
                                         an annulus. Question: Do cast iron   and the annuli are isolated per
                                         bridge plugs and retainers/packers   the regulations at Sec.
                                         without tubing installed meet the    250.1715. If the wellhead is being
                                         requirement for mechanical           left in place for the production
                                         barriers?                            string, the registered PE must
                                                                              certify two independent barriers
                                                                              in the center wellbore and the
                                                                              annuli. The registered PE may not
                                                                              certify work that was previously
                                                                              performed; the registered PE must
                                                                              only certify the work to be
                                                                              performed under the permit
                                                                              submitted. A cast iron bridge plug
                                                                              is an option as a mechanical
                                                                              barrier. With regard to the
                                                                              question of using retainers/
                                                                              packers to meet the requirement
                                                                              for mechanical barriers,
                                                                              evaluation will be conducted on a
                                                                              case-by-case basis.
----------------------------------------------------------------------------------------------------------------

[[Page 50864]]

 
Sec.   250.420(b)(3)..................  The rules seem to encourage use of   BSEE revised this section in the
                                         devices described in Section 3 of    Final Rule to clarify the
                                         RP 65, some of which have never      requirement of two independent
                                         been used in deepwater and are in    barriers, and also clarified that
                                         fact of dubious utility. It is       a dual float valve is not
                                         agreed that more stringent           considered a mechanical barrier.
                                         cementing practices are in order,    The BSEE District Manager may
                                         but these proposed rules are too     approve alternatives.
                                         confusing to serve this purpose.
                                         This section needs to be revisited
                                         and specific, practical,
                                         recommended practices set out.
----------------------------------------------------------------------------------------------------------------
Sec.   250.420(c).....................  30 CFR 250.420(c) requires that      This is a previously existing
                                         cement attain 500 psi compressive    requirement and therefore not
                                         strength prior to drill out. What    within the scope of this
                                         drives the CS requirement? It's      rulemaking.
                                         not API RP 65-2.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.420, 250.1712, and     Previous guidance/interpretation     If an activity triggers the need
 250.1721.                               issued by BOEMRE said that           for a revised permit or an APM,
                                         deviation from certified             then the Registered Professional
                                         procedures required contact with     Engineer must recertify the design
                                         the appropriate BSEE District        and the revised permit or
                                         Manager. This is documented only     Application for Permit
                                         in the guidance and is not           Modification (APM) must receive
                                         implicit in this part of the rule.   approval from the appropriate BSEE
                                         We request that BOEMRE specify the   District Manager.
                                         kinds of variances that require
                                         this contact.
----------------------------------------------------------------------------------------------------------------
Sec.   250.423(b).....................  Need definition or clarity around    BSEE has revised the language in
                                         the term--lock down and the          Sec.   250.423(b), to clarify that
                                         requirement for locking down a       the Final Rule does not require
                                         drilling liner. Must all liner       the use of a latching or lock down
                                         hangers have hold down slips?        mechanism for a liner. However, if
                                         Normally conventional line hangers   a liner is used that has a
                                         only have hang off slips to          latching or lock down mechanism,
                                         transfer the weight of the liner     then that mechanism must be
                                         to the previous casing string.       engaged.
                                         Once the seal is energized for a
                                         Liner Top Packer, it will hold
                                         pressure from below and above, but
                                         not all seals have slips to
                                         prevent uplift should the pressure-
                                         area effect exceed the weight of
                                         the liner. Requiring hold down
                                         slips on a conventional liner
                                         hanger increases the difficulty to
                                         fish the liner out of the hole, in
                                         fact it will lead to a milling
                                         operation.
----------------------------------------------------------------------------------------------------------------
Sec.   250.423(b).....................  As currently drafted, Sec.           BSEE revised the language for the
                                         250.423(b) requires negative         requirements for a negative test
                                         testing to be set to either 70       under Sec.   250.423(c). The
                                         percent of system collapse           operator must perform a negative
                                         resistance pressure, saltwater       pressure test on all wells that
                                         gradient, or 500 psi less than       use a subsea BOP stack or wells
                                         formation pressure, whichever is     with mudline suspension systems to
                                         less. The rule implies that          ensure proper casing or liner
                                         operators are required to perform    installation. You must perform the
                                         a test on the casing seal;           negative test to the same degree
                                         however, the industry has had        of the expected pressure once the
                                         several examples of where testing    BOP is disconnected. BSEE also
                                         to a salt water gradient to sea      revised the language for the
                                         floor has caused casing collapse     requirement to ensure proper
                                         in deep wells with casing across     installation of the casing in the
                                         the salt. This regulation does not   subsea wellhead and liner in the
                                         clearly state whether it applies     liner hanger in Sec.   250.423(b).
                                         to casing shoe extensions, such as   Regarding lockdown mechanisms, see
                                         expandable casing or 18'' (which     previous comment.
                                         is a surface casing shoe
                                         extension). Since not all casing
                                         sizes (e.g. 16'' and 18'') have
                                         lockdown mechanisms at this time,
                                         the rule should allow for waivers
                                         to this requirement until such
                                         time that lockdown mechanisms are
                                         available.
----------------------------------------------------------------------------------------------------------------
Sec.   250.423(b).....................  The operator must perform a          BSEE agrees with this comment.
                                         pressure test on the casing seal     Section 250.423(b) requires
                                         assembly to ensure proper            performance of a pressure test on
                                         installation of casing or liner.     the casing seal assembly and
                                         The operator must ensure that the    further requires the operator to
                                         latching mechanisms or lock down     maintain the necessary
                                         mechanisms are engaged upon          documentation.
                                         installation of each casing string
                                         or liner.
                                        Performance and documentation of a
                                         pressure test on the casing seal
                                         assembly to ensure proper
                                         installation of the casing and the
                                         liner are essential. Documentation
                                         that the latching mechanisms or
                                         lock down mechanisms are fully
                                         engaged upon installation of each
                                         casing string or liner must be
                                         mandatory.
----------------------------------------------------------------------------------------------------------------
Sec.   250.423(b)(1)..................  Not clear if integral latching       Under Sec.   250.423(b)(1), the
                                         capability of casing hanger/seal     operator must ensure proper
                                         assembly is acceptable or if a       installation of casing in the
                                         separate mechanism is required.      subsea wellhead by ensuring that
                                                                              the latching mechanisms or lock
                                                                              down mechanisms are engaged upon
                                                                              installation of each casing
                                                                              string. The rule does not require
                                                                              a specific type of latching
                                                                              mechanism. Integral latching
                                                                              capability of the casing hanger or
                                                                              seal assembly is acceptable.
----------------------------------------------------------------------------------------------------------------
Sec.   250.423(c).....................  What is the design basis and         The regulations do not specify a
                                         acceptance criteria required for     particular design basis for the
                                         negative testing?                    negative pressure test. Under Sec.
                                                                                250.423(c)(3) operators must
                                                                              submit negative test procedures
                                                                              and provide their criteria for a
                                                                              successful test to BSEE for
                                                                              approval. BSEE revised the
                                                                              language of Sec.   250.423(c)(5)
                                                                              to include examples of indications
                                                                              of failure.
----------------------------------------------------------------------------------------------------------------

[[Page 50865]]

 
Sec.   250.423(c).....................  It is imperative that the operator   Operators are required to submit
                                         establish what is ``normal'' for     the procedures of these tests and
                                         this type of testing event, such     provide their criteria for a
                                         that the rig crew is in no doubt     successful test with their APD.
                                         as to what to look for and whether   BSEE revised the regulatory text
                                         or not there is an event going on    to include examples of indications
                                         which is ``not normal''.             of a failed negative pressure
                                                                              test.
----------------------------------------------------------------------------------------------------------------
Sec.   250.423(c).....................  What is the definition of            BSEE revised Sec.   250.423(c) to
                                         intermediate casing? The rule        clarify the requirements for the
                                         states a negative pressure test is   negative pressure test.
                                         required for intermediate and        Intermediate casing is any casing
                                         production casing. If drilling       string between the surface casing
                                         liners are set below intermediate    string and production casing
                                         casing is additional negative        string. We revised the Final Rule
                                         testing required?                    to require negative pressure tests
                                        The intent of this requirement is     only on subsea BOP stack and wells
                                         not clear. The magnitude of the      with mudline suspension systems.
                                         negative test is also not            We specifically require the
                                         apparent. Is the intent to test      operator to perform a negative
                                         the entire casing, wellhead, liner   pressure test on the final casing
                                         top, or the shoe? Surface            string or liner, and prior to
                                         wellheads are negative tested for    unlatching the BOP at any point in
                                         each BOP test when the stack is      the well (if the operator has not
                                         drained and water is used for a      already performed the negative
                                         test. If a negative test of an       test on its final casing string or
                                         intermediate shoe is intended,       liner). At a minimum, the negative
                                         then, what is the purpose since      test must be conducted on those
                                         the casing shoe will be drilled      components that will be exposed to
                                         out. In general, negative testing    the negative differential pressure
                                         should not apply to all wells and    that will occur when the BOP is
                                         should apply if the load is          disconnected. The intent of the
                                         anticipated and then not until       requirement is to ensure that the
                                         such time it is needed.              casing can withstand the wellbore
                                                                              conditions. The Final Rule
                                                                              addresses indicators of failed
                                                                              pressure tests and specifies what
                                                                              the operator must do in the event
                                                                              of a failed test.
----------------------------------------------------------------------------------------------------------------
Sec.   250.423(c).....................  Wells with surface wellheads should  We agree that as a general matter
                                         be exempt from negative tests        wells with surface well heads
                                         unless the well is to be displaced   should be exempt from negative
                                         to a fluid less than pore pressure   pressure tests and we revised the
                                         and in that case the shoe,           Final Rule to require the negative
                                         productive intervals, and liner      pressure test only for wells that
                                         tops can be negative tested to the   use a subsea BOP stack or wells
                                         amount anticipated prior to or       with mudline suspension systems.
                                         during the displacement. The         We did, however, provide that if
                                         requirement to negative test wells   circumstances warrant, the BSEE
                                         with surface wellheads should not    District Manager may require an
                                         be mandated since the well can be    operator to perform additional
                                         displaced to a fluid less than       negative pressure tests on other
                                         pore pressure under controlled       casing strings or liners (e.g.
                                         conditions without risk of an        intermediate casing string or
                                         influx getting in a riser.           liner) or on wells with a surface
                                                                              BOP stack.
----------------------------------------------------------------------------------------------------------------
Sec.   250.423(c).....................  Additional guidance given by BOEMRE  All liner tops, exposed below the
                                         has indicated a desire to negative   intermediate casing (wells with
                                         test all liner tops exposed in       mudline suspension systems) must
                                         either the intermediate or           be tested, but only for wells with
                                         production annulus on all wells      subsea BOP stacks or wells with
                                         with surface BOP equipment. This     mudline suspension systems. The
                                         requirement is not consistent with   test must be performed before
                                         the desire to improve safety since   displacing kill weight fluids in
                                         many liner tops are never exposed    preparation for disconnecting the
                                         to negative pressures during the     BOP stack.
                                         life of the well. Thus performing
                                         the test exposes personnel to
                                         additional exposure while tripping
                                         pipe to perform the test, risks
                                         the well by installing non-
                                         drillable test packers above the
                                         liner top during the test, and
                                         will expose personnel to
                                         additional material handling
                                         requirements.
----------------------------------------------------------------------------------------------------------------
Sec.   250.423(c).....................  The Agency has not provided          This Final Rule revises Sec.
                                         guidance on when the test is to be   250.423(c) to state that the
                                         performed. Testing upon              negative pressure test must be
                                         installation is not advisable due    performed on the final casing
                                         to additional pressure cycles        string or liner, and prior to
                                         applied to the cement early in the   unlatching the BOP at any point in
                                         development of its strength that     the well. The negative test must
                                         could result in premature cement     be conducted on those components,
                                         failure. Additionally, if a          at a minimum, that will be exposed
                                         negative load is anticipated         to the negative differential
                                         during operations, it is best to     pressure that will be seen when
                                         defer the negative test to assure    the BOP is disconnected.
                                         well integrity is validated just
                                         prior to the intended operation.
----------------------------------------------------------------------------------------------------------------
Sec.   250.423(c).....................  Negative testing should be           BSEE agrees with the comment. We
                                         performed on subsea wells and        revised Sec.   250.423(c) to
                                         wells with mudline suspension        require the negative pressure
                                         systems where it is important to     tests only on wells that use a
                                         validate barriers prior to removal   subsea BOP stack or wells with
                                         of mud hydrostatic pressure during   mudline suspension systems. See
                                         an abandonment or suspension         the response to the previous
                                         activity such as hurricane           comment.
                                         evacuation or BOP repair. Drilling
                                         or production liner tops should
                                         not require negative testing upon
                                         installation. Testing should be
                                         deferred until just prior to
                                         performing an operation where a
                                         negative load is anticipated on a
                                         liner top or wellhead hanger.
----------------------------------------------------------------------------------------------------------------
Sec.   250.423(c).....................  The magnitude and duration of an     We revised the Final Rule to
                                         acceptable negative test should be   require the negative test be
                                         provided for consistency.            performed to the same degree of
                                         Recommend negative tests on subsea   the expected pressure once the BOP
                                         wells to be equal to SWHP at the     is disconnected.
                                         wellhead.
----------------------------------------------------------------------------------------------------------------

[[Page 50866]]

 
Sec.   250.423(c).....................  30 CFR 250.423(c) requires negative  BSEE agrees. We revised this
                                         testing of intermediate casing and   requirement to require the
                                         liner tops, but offers no guidance   negative pressure tests only on
                                         as to the magnitude of the           wells that use a subsea BOP stack
                                         required negative test. As an        or wells with mudline suspension
                                         experienced deepwater driller,       systems. See the response to the
                                         I've assumed that BOEMRE meant for   previous comments.
                                         this testing to apply to
                                         intermediate casing string seal
                                         assemblies on subsea wells. That
                                         mimics what the well would see in
                                         a BOP stack disconnect situation.
                                         I see no valid reason to be
                                         negatively testing intermediate
                                         casing shoes that will be
                                         subsequently drilled out. I'd also
                                         like to understand the rationale
                                         behind a negative test on all
                                         liner tops. Just because a liner
                                         top tests negatively doesn't mean
                                         it won't fail if the well is
                                         exposed to a differential as a
                                         result of a blow out. I see a
                                         negative test on production liner
                                         tops as a prudent thing, but this
                                         type testing of drilling liners
                                         that will ultimately be covered up
                                         can increase risk in certain
                                         situations (small platform rig on
                                         a floating facility with limited
                                         pit space could get into an
                                         unintended well-control situation
                                         dealing with the fluid handling/
                                         movements required by a negative
                                         test).
----------------------------------------------------------------------------------------------------------------
Sec.   250.442........................  Must heavy weight drill pipe be      Blind-shear rams must be capable of
                                         shearable with blind shear rams?     shearing any drill pipe in the
                                                                              hole under maximum anticipated
                                                                              surface pressure, including
                                                                              heavyweight drillpipe. This Final
                                                                              Rule revises Sec.   250.416(e) to
                                                                              include workstring and tubing to
                                                                              clarify that these are also
                                                                              considered drill pipe and need to
                                                                              be shearable by the blind-shear
                                                                              rams.
----------------------------------------------------------------------------------------------------------------
Sec.   250.442........................  What does ``operable'' mean for      The provision under Sec.
                                         dual pod controls? Does it mean      250.442(b), for an ``operable dual-
                                         100 percent functional and           pod control system'' was an
                                         redundant?                           existing requirement and was
                                                                              included in the IFR because that
                                                                              section was rearranged into a
                                                                              table to accommodate the new
                                                                              provisions. The meaning of
                                                                              ``operable dual-pod control
                                                                              system'' has not changed. The
                                                                              commenter is correct in that these
                                                                              are redundant systems. Each pod
                                                                              has to be independent of the other
                                                                              and 100 percent functional.
----------------------------------------------------------------------------------------------------------------
Sec.   250.442........................  In Sec.   250.442(c), what does      As specified in Sec.   250.442(c),
                                         ``fast'' mean for subsea closure     the accumulator system must meet
                                         and what are the ``critical''        or exceed the requirements in API
                                         functions?                           RP 53, section 13.3, Accumulator
                                                                              Volumetric Capacity.
----------------------------------------------------------------------------------------------------------------
Sec.   250.442........................  What will be competency basis for    The operator must ensure that all
                                         qualification of an individual to    employees and contract personnel
                                         operate the BOP's?                   can properly perform their duties,
                                                                              as required under Sec.   250.1501.
                                                                              Section 250.442(j) prescribes
                                                                              training and knowledge
                                                                              requirements for persons
                                                                              authorized to operate critical BOP
                                                                              equipment.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.442(d), Sec.           While the verified ability to close  We agree that there is a time delay
 250.515(e), and Sec.   250.615(e).      one set of pipe rams, close one      associated with the launch and
                                         set of blind-shear rams, and         deployment of an ROV and that
                                         unlatch the lower marine riser       preventative and precautionary
                                         package using a Remotely Operated    measures are a priority and
                                         Underwater Vehicle (ROV) is          immediate shut-in capability is
                                         critical, the time delay             critical. The intent of the
                                         associated with launch and subsea    provision is to ensure that an ROV
                                         deployment of an ROV will likely     is available in the unlikely event
                                         have enabled the full force of a     that all other measures fail. This
                                         major blowout to already clear the   regulation is intended to address
                                         well bore and result in excessive    broad issues related to well-
                                         pressures and a debris stream at     control; BSEE is planning future
                                         the BOP that can complicate          regulations that will focus on
                                         efforts to shut in the well.         preventative measures and
                                         Preventive and precautionary         improving immediate response
                                         measures are a priority, and         capabilities.
                                         immediate shut-in capability will
                                         always be more critical than after-
                                         the-fact ROV response; thus this
                                         initiative should go further
                                         toward ensuring more immediate
                                         wild well shut-in capabilities,
                                         either in the current rulemaking,
                                         or in a future rulemaking.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.442(e), 250.515(e),    The ROV crews should not be          BSEE agrees with the substance of
 and 250.615(e).                         required on a continuous basis,      this comment and has revised Sec.
                                         this item needs to be revised to      250.442(e) accordingly.
                                         reflect the need for having a
                                         trained ROV crew on board only
                                         when the BOP is deployed.
----------------------------------------------------------------------------------------------------------------
Sec.   250.442(j).....................  What is meant by operate critical    Section 250.442(j) establishes
                                         BOP equipment, maintenance, or       minimum requirements for personnel
                                         activation of equipment?             who operate any BOP equipment. The
                                                                              paragraph expressly refers to BOP
                                                                              hardware and control systems. In
                                                                              addition, other paragraphs of Sec.
                                                                                250.442 refer to specific
                                                                              features of the BOP and associated
                                                                              equipment. Any person authorized
                                                                              to operate or maintain any of the
                                                                              BOP components or systems must
                                                                              satisfy the requisite training and
                                                                              knowledge requirements.
----------------------------------------------------------------------------------------------------------------

[[Page 50867]]

 
Sec.  Sec.   250.446(a), 250.516(h),    The recordkeeping requested should   Under Sec.   250.146(c), lessees,
 250.516(g), and 250.617 (Section        be a responsibility of the           operators, and persons performing
 numbers refer to the IFR.).             drilling contractor. Many            an activity subject to regulatory
                                         operations are short lived           requirements are jointly and
                                         contracts and once the rig is        severally responsible for
                                         released, the contractor has no      complying with regulatory
                                         obligation to ensure the records     requirements. This includes
                                         remain on the rig. Drilling          contractors maintaining and
                                         contractors should be required to    inspecting BOP systems. See the
                                         have a BOPE certification program    discussion in the section-by-
                                         complete with a certificate of       section portion of this preamble.
                                         compliance that is renewed every 3
                                         to 5 years by a certification
                                         agency or class society. This will
                                         assure drilling contractors
                                         maintain their equipment to a
                                         higher standard on a routine basis.
                                        Certification documents for rental
                                         BOPE would also be used by the
                                         operator or contractor depending
                                         upon who is renting the equipment.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.446(a), 250.516(h),    We believe that API-recommended      BSEE already requires operators to
 250.516(g), and 250.617 (Section        practices have not proven to be a    follow Sections 17.10 and 18.10,
 numbers refer to the IFR.).             standard that has generated full     Inspections; Sections 17.11 and
                                         and verifiable compliance by all.    18.11, Maintenance; and Sections
                                         Require documentation of BOP         17.12 and 18.12, Quality
                                         inspections and maintenance          Management, described in API RP
                                         according to API RP 53. The          53, Recommended Practices for
                                         codification of API-recommended      Blowout Prevention Equipment
                                         practices via Federal regulations    Systems for Drilling Wells. We
                                         will be needed to ensure reliable    continually review standards and
                                         compliance going forward. This       our use of these standards. We may
                                         should take place in the current     consider additional documentation
                                         rule, or, at a minimum, in a         from operators in future
                                         future rule.                         rulemaking.
----------------------------------------------------------------------------------------------------------------
Sec.   250.449(h).....................  Are the requirements for function    Section 250.449(h) is a previously
                                         test for normal or high pressure     existing requirement that was
                                         function or both?                    included in the IFR only to make
                                        In Sec.   250.449(h), request         editorial changes to accommodate
                                         change from the required duration    new requirements in subsequent
                                         from 7 days to 14 days. The basis    paragraphs. The requested revision
                                         for this is to mitigate the risk     is outside the scope of this
                                         and exposure due to the additional   rulemaking.
                                         tripping of pipe out of hole in
                                         order to function test blind/shear
                                         rams.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.449(j), 250.516(d)(8)  Stump test ROV intervention          Section 250.449(j) requires the
 (Section numbers refer to the IFR.).    functions.                           operator must test one set of rams
                                        This does not go far enough. This     during the initial test on the
                                         is insufficient. It is necessary     seafloor. In this Final Rule, we
                                         that the BOP ROV functions be        added that the test of the one set
                                         regularly tested at the seabed       of rams on the seafloor must be
                                         with the ROV that would be used in   done through an ROV hot stab to
                                         an emergency. The only requirement   ensure the functioning of the hot
                                         of the stump test should be to       stab. BSEE may consider additional
                                         test the plumbing. The BOP ROV       requirements in future rulemaking.
                                         functions should be tested at each
                                         BOP test when at operating
                                         hydrostatic pressures and
                                         temperatures.
----------------------------------------------------------------------------------------------------------------
Sec.   250.449(k).....................  Section 250.449(k) explains:         BSEE believes that not testing the
                                         ``[f]unction test auto shear and     deadman system is a greater risk
                                         deadman systems on your subsea BOP   than conducting the test. Testing
                                         stack during the stump test. You     the deadman system on the seafloor
                                         must also test the deadman system    is necessary to ensure that the
                                         during the initial test on the       deadman system will function in
                                         seafloor.'' We do not recommend      the event of a loss of power/
                                         testing the deadman system when      hydraulics between the rig and the
                                         the stack is attached to a subsea    BOP. To help mitigate risk for the
                                         wellhead. If the rig experiences a   function test of the deadman
                                         dynamic positioning incident,        system during the initial test on
                                         i.e., a drive-off or drift-off       the seafloor, we added that there
                                         during the test, the only            must be an ROV on bottom, so it
                                         alternative system available to      would be available to disconnect
                                         disconnect from the wellhead is      the LMRP should the rig experience
                                         the ROV intervention system.         a loss of stationkeeping event. We
                                         Failure to disconnect in time        also added clarifications for the
                                         could result in serious damage to    required submittals of procedures
                                         the rig equipment, the well head,    for the autoshear and deadman
                                         or the well casing. As an            function testing, including
                                         alternative, we believe it would     procedures on how the ROV will be
                                         be more appropriate to test the      utilized during testing.
                                         autoshear system subsea. Such a
                                         requirement will test the same
                                         hydraulic system as the deadman,
                                         however, the autoshear function
                                         does not disable the control
                                         system and create the same well
                                         and equipment hazards as testing
                                         the deadman system.
----------------------------------------------------------------------------------------------------------------

[[Page 50868]]

 
Sec.   250.449(k).....................  Modify deadman system testing        BSEE believes that not testing the
                                         requirements to increase safety.     deadman system is a greater risk
                                        As drafted, operators must test the   than conducting the test. Testing
                                         deadman system during the initial    the deadman system on the seafloor
                                         test on the seafloor.                is necessary to ensure that the
                                         Intentionally disabling the          deadman system will function in
                                         deadman system increases the risk    the event of a loss power/
                                         to personnel, well bore and          hydraulics between the rig and the
                                         equipment should a ``power           BOP. To help mitigate risk for the
                                         management'' or ``loss of station    function test of the deadman
                                         keeping'' incident occur during a    system during the initial test on
                                         deadman system test. Testing of      the seafloor, we added that there
                                         the deadman system requires          must be an ROV on bottom, so it
                                         shutting down of power and           would be available to disconnect
                                         hydraulic systems to the BOP         the LMRP should the rig experience
                                         thereby eliminating the ability to   a loss of stationkeeping event. We
                                         disconnect in a controlled manner    also added clarifications for the
                                         should a ``power management'' or     required submittals of procedures
                                         ``loss of station keeping''          for the autoshear and deadman
                                         incident occur. As a result, rig     function testing, including
                                         personnel could be exposed to the    procedures on how the ROV will be
                                         consequences of a violent release    utilized during testing.
                                         of tension if a riser component
                                         fails and seafloor architecture
                                         will be exposed to released/
                                         dropped riser components. Revise
                                         the deadman system testing
                                         requirement, bringing it in line
                                         with the proposed new API RP-53,
                                         4th Edition recommendations.
                                         Specifically, testing should be
                                         completed during commissioning,
                                         rig acceptance and if any
                                         modifications or maintenance has
                                         been performed on the system, not
                                         to exceed 5 years.
                                                                             BSEE will review API RP-53, 4th
                                                                              Edition, and decide if it is
                                                                              appropriate for incorporation,
                                                                              after it is finalized.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.449(k),                We recommend testing the deadman     BSEE believes that not testing the
 250.516(d)(9), 250.616(h)(2) (Section   system when attached to a well       deadman system is a greater risk
 numbers refer to the IFR.).             subsea upon commissioning or         than conducting the test. Testing
                                         within 5 years of previous test      the deadman system on the seafloor
                                         but not at every well. If during     is necessary to ensure that the
                                         the testing time the rig             deadman system will function in
                                         experiences a dynamic position       the event of a loss power/
                                         incident, i.e., a drive off or       hydraulics between the rig and the
                                         drift off, the only options to       BOP. To help mitigate risk for the
                                         disconnect from the well are         function test of the deadman
                                         acoustically (if acoustic system     system during the initial test on
                                         fitted), or with an ROV. Failure     the seafloor, we added that there
                                         to disconnect in time could result   must be an ROV on bottom, so it
                                         in serious equipment damage, and/    would be available to disconnect
                                         or damage to the well head.          the LMRP should the rig experience
                                                                              a loss of stationkeeping event. We
                                                                              also added clarifications for the
                                                                              required submittals of procedures
                                                                              for the autoshear and deadman
                                                                              function testing, including
                                                                              procedures on how the ROV will be
                                                                              utilized during testing.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.449(k) and             Stump test the autoshear and         On the initial test on the
 250.516(d)(9) (Section numbers refer    deadman. Test the deadman after      seafloor, the operator is required
 to the IFR.).                           initial landing.                     only to test the deadman system.
                                        Both the deadman and autoshear        The rule requires operators to
                                         should be tested on the seabed.      submit their test procedures with
                                         Moreover the Deadman should          the APD or APM for approval. BSEE
                                         include a disconnect function.       may develop specific test
                                         However, the LMRP connector should   procedures at a later time.
                                         not be unlocked during this test.
                                         Rather, the LMRP disconnect
                                         function should be plumbed in such
                                         a way that during the test the
                                         fluid can be vented to sea rather
                                         than to the unlatch side.
----------------------------------------------------------------------------------------------------------------
Sec.   250.451(i).....................  A successful seafloor pressure and   After a well-control event where
                                         function test of the BOP following   pipe or casing was sheared, a full
                                         a well-control event also is an      inspection and pressure test
                                         acceptable means of verifying        assures that the BOP stack is
                                         integrity. Ram sealing elements      fully operable. The rule requires
                                         would be compromised before damage   the operator to do this only after
                                         to the rams themselves would be      the situation is fully controlled.
                                         extensive enough to prevent
                                         successful shearing of pipe.
                                         Additionally, plugging an open
                                         hole that may be experiencing
                                         ballooning and gas following a
                                         well-control event and pulling the
                                         BOP and riser present safety and
                                         operational risks that are likely
                                         much greater than proceeding with
                                         the drilling program using a fully
                                         tested BOP stack.
----------------------------------------------------------------------------------------------------------------
Sec.   250.451(i).....................  We believe Sec.   250.451(i) is      BSEE agrees with the comment that
                                         best read to only require a subsea   Sec.   250.451(i) does not apply
                                         BOP stack to surface when pipe is    to actuation of shear rams on an
                                         sheared, rather than actuated on     empty cavity. Section 250.451(i)
                                         an empty cavity. We request that     states that an operator must
                                         the agency clarify that the          retrieve the BOP if: ``You
                                         requirement to pull a subsea BOP     activate the blind-shear rams or
                                         stack to surface after actuating     casing shear rams during a well-
                                         the blind shear rams does not        control situation, in which pipe
                                         apply when the blind shear rams      or casing is sheared.''
                                         are actuated on an empty cavity,
                                         but applies when pipe is sheared.
----------------------------------------------------------------------------------------------------------------

[[Page 50869]]

 
Sec.   250.456(j).....................  Does this requirement only refer to  This Final Rule revises Sec.
                                         the end of well during abandonment   250.456(j) to clarify that this
                                         or at any time during the drilling   requirement applies any time kill-
                                         of a well? There are times when      weight mud is displaced, putting
                                         mud weight is cut prior to           the wellbore in an underbalanced
                                         drilling out a casing shoe due to    state. If the mud weight is cut,
                                         exposure of weak formations or       but the wellbore will remain in an
                                         anticipated lost circulation.        overbalanced state, then approval
                                         Would approval be required to cut    is not required.
                                         mud weight in these circumstances?
                                         Consider that mud weight is cut
                                         just prior to drilling out the
                                         shoe in a controlled environment
                                         at which time the entire system is
                                         negative tested with pipe in the
                                         hole at TD and BOPs are capable of
                                         shutting in the well if and when
                                         needed.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.515 and 250.616......  It appears that some of the          BSEE agrees that it is important
                                         requirements of NTL 2010-N05 which   for BOP requirements to be
                                         applied to workover BOPs have been   consistent, regardless of the
                                         omitted in the revision to 30 CFR    application or stage of a well.
                                         250.5XX and 250.6XX. Specifically,   These requirements should also
                                         verification that the blind/shear    apply to well-completion and well-
                                         is capable of shearing all pipe in   workover activities. We changed
                                         the well at MASP has been omitted    the regulatory text in Sec.  Sec.
                                         for workover and coiled tubing        250.515 and 250.615 to reflect
                                         operations. Verification of this     this. In addition, in response to
                                         capability is as important in        the concern raised by the
                                         workover as it is in drilling, for   commenter, this Final Rule adds
                                         both surface BOPs and subsurface     these requirements to subpart Q,
                                         BOPs. API RP 16ST, ``Coiled Tubing   since the same equipment used in
                                         Well-control Equipment Systems'',    drilling and workovers may be used
                                         Section 12, ``Well-control           in decommissioning operations, and
                                         Equipment Testing'', should be       similar safety risks also exist.
                                         referenced in 30 CFR 250.6XX in
                                         addition to the reference to API
                                         RP 53.
                                                                             BSEE may consider incorporating by
                                                                              reference API RP 16ST, ``Coiled
                                                                              Tubing Well-control Equipment
                                                                              Systems'' in future rulemaking.
----------------------------------------------------------------------------------------------------------------
Sec.   250.1503.......................  What is the definition of enhanced   The rule does not use the phrase,
                                         deepwater well-control training?     ``enhanced deepwater well-control
                                         Will this require a new              training.'' It does require
                                         certification of well-control        deepwater well-control training
                                         schools?                             for operations with a subsea BOP
                                                                              stack. The operator must ensure
                                                                              that all employees are properly
                                                                              trained for their duties as
                                                                              required in Sec.   250.1501. BSEE
                                                                              expects that operators will
                                                                              integrate the deepwater well-
                                                                              control training requirement into
                                                                              their current subpart O well-
                                                                              control program.
----------------------------------------------------------------------------------------------------------------
Sec.  Sec.   250.1712(g), 250.1721(h),  Liabilities that will be placed      The operator is responsible for all
 and 250.1715.                           onto a ``Professional Engineer       activities on its lease,
                                         (PE)'' are an issue. The PE          regardless of requirements for
                                         approach demands that the PE is      various persons to certify or
                                         intimately involved in all aspects   verify various aspects of
                                         of the design and also in primary    operations. Although persons
                                         communication as the well is         performing certifications and
                                         drilled and small variations in      verifications have responsibility
                                         the plan are made or happen.         for their actions, such
                                        All liability for the well must       responsibility will not eliminate
                                         remain with the operator without     or diminish the operator's
                                         any ``dilution'' to a PE, although   responsibilities for compliance
                                         review by a PE or other              with applicable requirements.
                                         ``independent and reputable''
                                         third-party is totally appropriate.
----------------------------------------------------------------------------------------------------------------


                          Table 2--Topics and General Questions Comments and Responses
----------------------------------------------------------------------------------------------------------------
                 Topic                                Comment                           BSEE response
----------------------------------------------------------------------------------------------------------------
Participate in Standard Development...  BOEMRE should participate in API's   BSEE agrees that its involvement in
                                         open process for adopting industry   the standard development process
                                         standards on an on-going basis.      with API and other standards
                                                                              organizations is important. We are
                                                                              already active in API's industry
                                                                              standard process and we are
                                                                              committed to continuing and
                                                                              increasing this involvement.
----------------------------------------------------------------------------------------------------------------
Participate in Standard Development...  BOEMRE should participate in         BSEE agrees that its involvement in
                                         revising American Welding            the standard development process
                                         Society's (AWS) standards. AWS's     with AWS and other standards
                                         standards committees comply with     organizations is important. BSEE
                                         ANSI-approved procedures for         accepts this and other offers to
                                         standards development, which,        participate in the development of
                                         among other things, guarantee        standards that support the mission
                                         public and open participation by     of BSEE.
                                         any materially affected entity,
                                         committee interest group balance,
                                         fair voting, and written technical
                                         issue resolution. AWS solicits
                                         ongoing input and comments for
                                         these revisions from any
                                         interested party, including
                                         BOEMRE. BOEMRE's input to the
                                         standards committees would be
                                         invaluable to help understand the
                                         goals of the government and to
                                         apply AWS's experts' thoughtful
                                         consideration to ongoing
                                         regulatory issues. Moreover,
                                         participation in AWS standards-
                                         setting would provide BOEMRE with
                                         access to valuable scientific and
                                         technical expertise.
----------------------------------------------------------------------------------------------------------------

[[Page 50870]]

 
Subsea BOP Requirements...............  More work should be carried out in   BSEE reviewed the findings of
                                         this area before final               various DWH investigations before
                                         requirements are identified. In      developing the Final Rule.
                                         particular, the findings of the      Findings from the DWH
                                         post-mortem on the Horizon BOP       investigation that are within the
                                         should be carefully looked at        scope of this rulemaking were
                                         prior to a ``final rule''.           incorporated. BSEE will address
                                                                              other findings in future rules.
----------------------------------------------------------------------------------------------------------------
Blind-Shear Ram Redundancy              With this rule, BOEMRE has made the  BSEE is considering this
 Requirements.                           important first step of requiring    requirement for future
                                         independent third-party              regulations. We do recognize the
                                         verification of blind shear ram      importance of having redundant
                                         capability, but deferred one of      safety features on BOP stacks.
                                         the most critical safety             However, we need to consider all
                                         improvements, the requirement to     the impacts of such a requirement
                                         install redundant blind-shear rams   before requiring it by regulation.
                                         in each OCS BOP, to a later          BSEE has concluded that the
                                         rulemaking process. We recommend     requirements of the IFR, as
                                         that redundant blind-shear rams be   modified by this Final Rule, have
                                         required for all OCS drilling        enhanced operational safety
                                         operations as of June 1, 2011.       sufficiently until such time that
                                                                              BSEE determines whether to add a
                                                                              requirement for additional blind-
                                                                              shear rams.
----------------------------------------------------------------------------------------------------------------
Accident Event Reporting..............  Also missing from the IFR is a       BSEE's incident reporting
                                         requirement that OCS operators and   requirements are covered in Sec.
                                         their contractors report to BOEMRE   Sec.   250.187 through 250.190.
                                         any accidental event that could      Specifically, Sec.   250.188(a)(3)
                                         significantly impact well            requires the reporting of all
                                         integrity or blowout prevention.     losses of well-control, including
                                         This proposed reporting              uncontrolled flow of formation or
                                         requirement includes, but is not     other fluids; flow through a
                                         limited to, any event where          diverter; or uncontrolled flow
                                         blowout preventer seal material      resulting from a failure of
                                         may be compromised.                  surface equipment or procedures.
                                                                              We are looking into expanding the
                                                                              reporting requirements in future
                                                                              rulemaking.
----------------------------------------------------------------------------------------------------------------
Third-party Certifications............  The rule makes repeated references   We disagree with the commenter's
                                         to third-party ``verification'' of   suggestion. The repeated use of
                                         certain matters related to well-     the concept of independent third-
                                         control equipment, including BOPs.   party ``verification'' in Sec.
                                         The appropriate functional           250.416 and conforming provisions
                                         terminology should be                of the other subparts derives
                                         ``certification,'' rather than       directly from various
                                         ``verification.'' In industry        recommendations of the
                                         practice, ``certification'' and      Department's May 10, 2010 Safety
                                         ``verification'' are different       Measures Report, e.g., Safety
                                         functions. A party that              Measures Report Recommendations
                                         ``certifies'' a process is           I.A.2 and I.C.7 (pp. 20-21) that
                                         different from the party that        use the term ``verification.'' The
                                         ``verifies'' the certified process   preparers of that report appear to
                                         is being followed. This is more      have understood the distinction
                                         than a definitional difference.      between ``certification'' and
                                                                              ``verification'' because in other
                                                                              recommendations the term
                                                                              ``certification'' is used, e.g.,
                                                                              Recommendation I.A.1, recommending
                                                                              a written and signed third-party
                                                                              ``certification'' of certain
                                                                              things.
                                                                             Although a distinction may exist
                                                                              between certification and
                                                                              verification, the provisions of
                                                                              the Final Rule requiring third-
                                                                              party verification of certain
                                                                              features use that term correctly
                                                                              and, together with the other
                                                                              provisions of the Final Rule,
                                                                              establish an adequate basis to
                                                                              reduce safety risks associated
                                                                              with BOP stacks. These rules
                                                                              provide a substantial upgrade over
                                                                              the previous rules that did not
                                                                              contain such provisions.
----------------------------------------------------------------------------------------------------------------


                           Table 3--Regulatory Impact Analysis Comments and Responses
----------------------------------------------------------------------------------------------------------------
                 Topic                                Comment                           BSEE response
----------------------------------------------------------------------------------------------------------------
Regulatory Impact Analysis............  The increased costs will negatively  BSEE will continue to evaluate
                                         impact future OCS development. The   regulatory changes that could
                                         IFR itself estimated the baseline    result in offsetting cost savings
                                         risk of a catastrophic blowout at    for OCS operators as directed by
                                         once every 26 years. 75 FR at        the President in his January 18,
                                         63365. This estimate for a blowout   2011 executive order, ``Improving
                                         in the Gulf of Mexico is even        Regulation and Regulatory
                                         lower, as it appears the estimate    Review.''
                                         used by BOEMRE is based on
                                         worldwide catastrophic blowout
                                         data.
                                                                             The estimate for the risk of a
                                                                              catastrophic blowout event is
                                                                              based upon one recorded GOM
                                                                              catastrophic blowout event and the
                                                                              historical number of deepwater GOM
                                                                              wells drilled, not world-wide
                                                                              blowout data. Going forward, we
                                                                              estimated the drilling of 160
                                                                              deepwater wells annually for cost
                                                                              estimation purposes. The 160
                                                                              deepwater wells per year may be
                                                                              more than will be drilled when
                                                                              considering all of the factors
                                                                              influencing GOM deepwater activity
                                                                              outside of this specific
                                                                              regulation. At the time of this
                                                                              analysis (during the summer of
                                                                              2010), this number was estimated
                                                                              to be a reasonable baseline for
                                                                              the regulatory benefit-cost
                                                                              analysis. If on average fewer than
                                                                              160 deepwater wells are drilled
                                                                              annually, the baseline activity
                                                                              scenario provides an upper bound
                                                                              regulatory cost estimate. If an
                                                                              estimate of 120 deepwater wells
                                                                              per year is used in the benefit-
                                                                              cost calculation, both the cost
                                                                              and the benefit i.e., interval
                                                                              between blowouts will decrease by
                                                                              approximately the same factor. The
                                                                              historical risk of a catastrophic
                                                                              blowout event will be reduced from
                                                                              once in 26 years to once in 34
                                                                              years.
----------------------------------------------------------------------------------------------------------------

[[Page 50871]]

 
Regulatory Impact Analysis............  The costs for compliance prepared    Multiple commenters suggested that
                                         by the Agency are not reflective     the costs of this rulemaking were
                                         of the total cost of compliance      not fully captured in the
                                         and thus will negatively affect      Regulatory Impact Analysis. BSSE
                                         both small and large businesses      and BOEMRE used the best available
                                         more than alleged by the Agency.     information to determine the
                                                                              compliance cost estimates for this
                                                                              rulemaking. The commenters do not
                                                                              identify specific regulatory
                                                                              provision where costs are claimed
                                                                              to be underestimated. Several of
                                                                              the compliance costs commenters
                                                                              associated with this rulemaking
                                                                              reflect provisions in existing
                                                                              regulations. Additionally, no
                                                                              alternative cost estimates are
                                                                              provided by this commenter.
                                                                              External factors influencing the
                                                                              cost of operating on the OCS are
                                                                              not considered to be compliance
                                                                              costs of this rulemaking. As
                                                                              explained in other portions of
                                                                              this preamble, BSEE has both
                                                                              decreased and increased some cost
                                                                              estimates for provisions in this
                                                                              rulemaking. However, the net
                                                                              estimated compliance cost has
                                                                              decreased from the estimate
                                                                              contained in the IFR.
----------------------------------------------------------------------------------------------------------------
Regulatory Impact Analysis............  The benefit-cost analysis implies    API Number TVD Water Depth Time to
                                         that a blowout may pose more         Reach Total Depth 608124001700
                                         problems in deepwater where          28497 6959 ft 200 days
                                         drilling a relief well is likely    427084062600 28382 100 ft 390 days
                                         to take longer. I find this          It is possible that the statement
                                         statement troubling. It could be     is true, that is due to a
                                         considered to imply, that it takes   different distribution of TVD in
                                         longer to penetrate seawater than    shallow and deep water drilling
                                         hard rock. As an example, two        targets. BOEMRE needs to be
                                         drilling targets are at 20,000       rigorous to see if its conjectures
                                         feet total vertical depth (TVD).     are supported by the data. This is
                                         One is in 500 feet of water and      part of a pattern of the claim
                                         the other is in 5,000 feet of        that deep water activities are
                                         water. For a well drilled in 500     more risky than shallow water.
                                         feet of water an additional 4,500    This assumption is being made by
                                         feet of hard rock drilling must be   BOEMRE as a result of the
                                         completed to reach the target.       Deepwater Horizon incident
                                         From public well data on the        The typical GOM exploratory well in
                                         BOEMRE website, I found the          shallow water takes less than 30
                                         following pair of wells:             days to reach TVD. The typical GOM
                                                                              deepwater exploratory well takes
                                                                              nearly 90 days to reach TVD. This
                                                                              is primarily because, on average,
                                                                              shallow water wells are not
                                                                              drilled to depths as deep as
                                                                              deepwater wells. Well-completions
                                                                              for ``wet'' wells and abandonment
                                                                              for ``dry'' wells take additional
                                                                              time. While exceptions can be
                                                                              found, we maintain that in most
                                                                              cases our assumption will hold
                                                                              that a deepwater relief well will
                                                                              take longer than a shallow water
                                                                              relief well.
----------------------------------------------------------------------------------------------------------------
Regulatory Impact Analysis............  The agency estimates 160 deepwater   A reduction in the number of wells
                                         wells annually for the next 20       drilled per year will reduce the
                                         years. This is a very important      estimated annual compliance costs
                                         estimate, since it drives the        as well as the corresponding
                                         estimates of both the costs and      likelihood of a catastrophic
                                         benefits. Granted projections of     blowout and hence the potential
                                         the future in the oil and gas        gains from any improvements in
                                         industry have been notoriously       reliability. How much the new
                                         wrong. I see that 160 wells          regulatory environment will affect
                                         annually as overly optimistic. My    future OCS drilling is unknown at
                                         reasons are:                         this time.
                                        --Historical data show a declining   BSEE estimates the drilling of 160
                                         trend of the most recent years       deepwater wells annually for cost
                                         with all observations below 160.     estimation purposes. The 160
                                        --Deepwater Horizon incident will     deepwater wells per year may be
                                         lead to less favorable conditions    more than will be drilled when
                                         for drilling in the Gulf.            considering all of the factors
                                        --Natural Gas from shale is a major   influencing GOM deepwater activity
                                         disruption coming to North           outside of this specific
                                         American energy markets. This is     regulation. At the time this
                                         analogous to the cellular phone      analysis was prepared for the IFR
                                         technology replacing land line       during the summer of 2010, it was
                                         phones in the last 20 years.         estimated to be a reasonable
                                        A better way of presenting the        baseline for the regulatory
                                         future benefits and costs is with    benefit-cost analysis. One hundred
                                         a range of scenarios such as 160,    sixty deepwater wells per year can
                                         120 and 80 wells a year. The         serve as an upper bound cost
                                         Deepwater Horizon incident will      estimate for the regulation. If an
                                         lead to less favorable conditions    estimate of 120 deepwater wells
                                         for drilling in the Gulf of Mexico.  per year is used in the benefit-
                                                                              cost calculation, both the cost
                                                                              and the benefit will decrease by
                                                                              approximately the same factor. The
                                                                              historical risk applied to future
                                                                              drilling estimates for 120 wells
                                                                              per year will reduce the estimated
                                                                              risk from once in 26 years to once
                                                                              in 34 years. For only 80 deepwater
                                                                              wells a year, the risk will be
                                                                              reduced to once each 52 years. A
                                                                              scenario analysis for 120
                                                                              deepwater wells per year has been
                                                                              added to the benefit-cost
                                                                              analysis.
----------------------------------------------------------------------------------------------------------------
Regulatory Impact Analysis............  BOEMRE estimates an equal            BOEMRE's estimate, in the IFR, of
                                         likelihood of serious damage or      an equal likelihood of loss or
                                         sinking of a MODU drilling rig       damage, is based on the two
                                         from a catastrophic blowout event.   recorded events for severe damage
                                         Press reports indicate the sinking   or destruction of deepwater MODUs
                                         of Deepwater Horizon was due to      in the GOM. This rulemaking
                                         bad fire fighting procedures. That   requires additional the testing of
                                         is, pouring seawater on the          LMRP disconnect functionality. A
                                         floating vessel causing it to        disconnect of a deepwater MODU
                                         sink. When the accident report is    during a catastrophic event will
                                         completed, new standard practices    likely protect the MODU from total
                                         should emerge for fire fighting      loss. BSEE maintains that our
                                         with the byproduct of great          baseline cost estimate for
                                         reduction in the probability of      deepwater MODU damage is
                                         sinking.                             reasonable for purposes of this
                                                                              benefit cost analysis.
----------------------------------------------------------------------------------------------------------------

[[Page 50872]]

 
Regulatory Impact Analysis............  The benefit-cost sensitivity         The report referenced by the
                                         analysis provided no basis for the   commenter does indicate that only
                                         assumption that reservoirs at        5 of the 20 largest GOM fields are
                                         depths of 3,000 feet are generally   in water depths greater than 3,000
                                         more prolific than their shallow     feet. If the top 20 fields are
                                         water counterparts. That statement   further analyzed, 6 of the top 20
                                         is contradicted by most recent       fields are in water depths of
                                         Reserves Report (http://             2,860 feet or greater and
                                         www.gomr.boemre.gov/homepg/          discovered since 1989. Fourteen of
                                         offshore/fldresv/2006-able4.pdf)     the fields are in water depths 247
                                         which shows of the 20 largest        feet or less and discovered in
                                         fields in the Gulf of Mexico, only   1971 or earlier. The GOM shelf is
                                         five are located in depth greater    in decline and few large fields
                                         than 3,000 feet.                     are likely to be discovered in the
                                                                              GOM shallow water. Over the last
                                                                              40 years the largest fields with
                                                                              booked reserves have all been in
                                                                              deepwater. BSEE maintains that the
                                                                              basis for the sensitivity analysis
                                                                              that future discovered reservoirs
                                                                              at water depths of 3,000 feet or
                                                                              greater will be more prolific is a
                                                                              reasonable assumption for the
                                                                              benefit-cost scenario analysis for
                                                                              this rule.
----------------------------------------------------------------------------------------------------------------
Regulatory Impact Analysis............  The agency's estimation of costs is  We have reviewed the report by IHS-
                                         not consistent with our own          Global Insight and found nothing
                                         estimates and we strongly            that will substantiate, contradict
                                         encourage the agency to carefully    or otherwise provide compliance
                                         review the assumptions that went     cost figures for this rulemaking.
                                         into your analysis. Moreover, to     Since the commenter's own
                                         potentially assist you with your     estimates were not provided, we
                                         examination of the socio-economic    cannot evaluate alternative cost
                                         costs and consequences of the        estimates suggested by the
                                         regulation, we have enclosed a       commenter. The Final Rule does not
                                         report we commissioned by IHS-       exclude independents from
                                         Global Insight entitled, ``The       deepwater drilling.
                                         Economic Impact of the Gulf of
                                         Mexico Offshore Oil and Natural
                                         Gas Industry and the Role of the
                                         Independents,'' which determined
                                         that more than $106 billion in
                                         Federal, state, and local revenues
                                         would be lost over a 10-year
                                         period if independents were
                                         excluded from deepwater.
                                         Obviously, this report examined
                                         broader policy impacts than were
                                         encompassed in the particular
                                         regulation, but we believe it
                                         provides a useful data set to
                                         examine these regulations within a
                                         broader context of impacts.
----------------------------------------------------------------------------------------------------------------
Regulatory Impact Analysis--Small       In its notice, BOEMRE included       BOEMRE published a separate IRFA on
 Business Impacts.                       certain information regarding the    December 23, 2010 (75 FR 80717)
                                         composition of the oil and gas       with a 30 day comment period. The
                                         industry and the small business      IRFA and the FRFA published with
                                         entities--lessees, operators, and    the final RIA provide the analysis
                                         drilling contractors--that will be   required in the Regulatory
                                         most affected by this interim        Flexibility Act. This includes an
                                         rule. BOEMRE estimates that $29      estimate of the number of small
                                         million dollars or 15.8 percent of   entities affected, a description
                                         the IFR's total cost of $183         of reporting, recordkeeping
                                         million will be borne by small       requirements and evaluation of
                                         businesses. This cost would          significant alternatives that
                                         comprise about 0.36 percent of       could minimize the impacts on
                                         these small businesses' fiscal       small entities while accomplishing
                                         year 2009 revenue.                   the objectives of this rulemaking.
                                        BOEMRE does not discuss how the
                                         regulation's costs would be
                                         distributed among small
                                         businesses. Advocacy is concerned
                                         that these costs will impact
                                         certain small businesses more
                                         heavily than others. We encourage
                                         BOEMRE to include additional
                                         information regarding how the
                                         industry functions and which small
                                         entities are most likely to incur
                                         increased costs as a result of
                                         this IFR. We also recommend that
                                         BOEMRE include a more detailed
                                         discussion of the distribution of
                                         costs among the small entities
                                         identified in the IRFA (Initial
                                         Regulatory Flexibility Analysis)
                                         in order to accurately determine
                                         whether some small entities will
                                         incur disproportionate impacts as
                                         a result of this rule.
                                        The RFA requires agencies to         ...................................
                                         include in their IRFA a
                                         description of any significant
                                         alternatives to the proposed rule
                                         that minimize significant economic
                                         impacts on small entities while
                                         still accomplishing the agency's
                                         objectives. While BOEMRE did note
                                         a few alternatives in the interim
                                         rule, we recommend that BOEMRE
                                         include a more detailed discussion
                                         of the alternatives and their
                                         effects on small business and the
                                         reasons for or against adopting
                                         those alternatives. We further
                                         recommend that BOEMRE continue to
                                         conduct outreach with small
                                         entities affected by this rule and
                                         any future safety rules to develop
                                         alternatives that minimize
                                         disproportionate impacts on small
                                         entities.
----------------------------------------------------------------------------------------------------------------

[[Page 50873]]

 
Regulatory Impact Analysis--Small       A commenter estimated that the       The compliance costs for the IFR
 Business Impacts.                       rulemaking will increase costs by    were estimated using the best
                                         $17.3 million for each deepwater     available information at the time
                                         well drilled with a MODU. This       of publication. Neither the IFR
                                         cost increase is attributed to       nor this Final Rule requires
                                         required modification of the well    operators to conform to a specific
                                         plan and associated casing design    casing design, nor do they require
                                         that results in the addition of a    new designs for well plans. The
                                         liner and associated work.           additional requirements of the IFR
                                                                              are intended to increase the
                                                                              safety of operating on the OCS
                                                                              considering the best available and
                                                                              safest technology. The commenter
                                                                              does not identify which elements
                                                                              increase either the time to drill
                                                                              a well by 15 rig days, or the cost
                                                                              by $17.3 million. Absent new and
                                                                              well-defined information, BSEE is
                                                                              unable to evaluate or adjust the
                                                                              compliance cost estimates for a
                                                                              deepwater well.
----------------------------------------------------------------------------------------------------------------
Regulatory Impact Analysis--Small       A commenter identified $10.45        The Final Rule does not change the
 Business Impacts Sec.   250.449(h).     million in BOP inspection cost       existing regulation at Sec.
                                         savings per deepwater well. The      250.449(h) which requires a
                                         proposal is to function test the     function test every 7 days
                                         blind-shear rams every 14 days       including the blind-shear rams.
                                         instead of every 7 days as           The 7-day testing requirement
                                         required by Sec.   250.449(h). The   existed before the Macondo event
                                         commenter claims ``prior to the      and is not being made more
                                         Macondo incident, all the rams on    stringent with this rulemaking.
                                         the BOP were function tested once    The commenter's assertion that
                                         a week except for the blind-shear    ``prior to the Macondo incident,
                                         rams.'' Another commenter claims     all the rams on the BOP were
                                         that `` * * * frequent function      function tested once a week except
                                         testing of blind/shears will         for the blind-shear rams'' is
                                         exacerbate this stack body wear      incorrect. The $10.45 million
                                         and introduce further exposure to    figure does not represent an
                                         leakage within the BOP''.            additional compliance cost due to
                                                                              this rule, but an estimated cost
                                                                              savings to the company on a per-
                                                                              well basis if their recommendation
                                                                              for a once-every-two weeks
                                                                              function test requirement is
                                                                              accepted.
                                                                             A Joint Industry Project study
                                                                              completed in 2009 analyzed BOP
                                                                              equipment reliability. The results
                                                                              of this study suggest that up to
                                                                              $193 million per year could be
                                                                              saved through less frequent
                                                                              testing while achieving the same
                                                                              reliability for BOP performance.
                                                                              However, at this time BSEE
                                                                              believes increasing the duration
                                                                              between tests poses a greater risk
                                                                              than conducting the test on the
                                                                              current schedule. BOP testing
                                                                              frequency is a topic that merits
                                                                              further study.
----------------------------------------------------------------------------------------------------------------
Regulatory Impact Analysis--Small       Several commenters claim that the    BSEE has considered the limited
 Business Impacts.                       compliance costs are significantly   cost information provided by
                                         higher than BOEMRE's estimate. One   commenters and new time and cost
                                         comment suggests that the ``Final    estimates obtained by the bureau
                                         Rule will add three to five times    since the publication of the IFR.
                                         the amount the BOEMRE has
                                         published.'' Another comment
                                         claims that the new regulation
                                         will cost as much as $28 million
                                         per deepwater well for compliance,
                                         compared to the $1.42 million
                                         estimated by BOEMRE.
                                                                             The commenter's $28 million
                                                                              compliance cost estimate includes
                                                                              a $10.45 million cost from
                                                                              additional BOP tests. However,
                                                                              these additional BOP tests do not
                                                                              represent additional costs, but a
                                                                              cost savings if the company's
                                                                              recommendation to function test
                                                                              the blind shear rams every 7 days
                                                                              instead of every 14 days (with
                                                                              regard to the previously existing
                                                                              regulation) is accepted. If the
                                                                              recommendation is not accepted,
                                                                              there is no increased compliance
                                                                              cost for this rulemaking. This
                                                                              proposal on function test
                                                                              intervals is outside the scope of
                                                                              this rulemaking as previously
                                                                              stated in the response to comments
                                                                              for Sec.   250.449(h).
                                                                             The additional $17.3 million of
                                                                              compliance costs are claimed to
                                                                              result from ``modified casing
                                                                              design'' and ``associated work.''
                                                                              The lack of specific data or
                                                                              citations result in a vague and
                                                                              indeterminate interpretation of
                                                                              these cost estimates. BSEE does
                                                                              not specify well designs. If a new
                                                                              well design used by the operator
                                                                              is the result of industry best
                                                                              practices, it is not a compliance
                                                                              cost of the regulation. As such,
                                                                              BSEE cannot comment on the
                                                                              presumed cost impact for modified
                                                                              casing design and associated work.
----------------------------------------------------------------------------------------------------------------
IRFA..................................  The IRFA published by BOEMRE does    The BSEE published an IRFA pursuant
                                         not satisfy the agency`s statutory   to the Regulatory Flexibility Act.
                                         obligation under the Regulatory      While it was not published with
                                         Flexibility Act of 1980, as          the IFR, it was published shortly
                                         amended. The commenter believes      thereafter and made available for
                                         that, since there is not a good      public comment. The SBA Office of
                                         cause exception to the               Advocacy stated in its comments
                                         Administrative Procedure Act`s       that ``Advocacy appreciates
                                         notice and comment rulemaking        BOEMRE's decision to publish a
                                         requirement, BOEMRE was required     supplemental IRFA.'' The comments
                                         to publish an IRFA at the time of    on the IRFA were considered along
                                         the proposed rulemaking. Further,    with all comments on the
                                         the IRFA BOEMRE eventually           rulemaking.
                                         published did not account for the
                                         significant costs likely to be
                                         imposed by BOEMRE`s new
                                         interpretation of 14,000
                                         discretionary provisions found in
                                         API standards as mandatory
                                         permitting requirements.

[[Page 50874]]

 
                                                                             Regarding the 14,000 discretionary
                                                                              provisions from API standards,
                                                                              BSEE disagrees with the
                                                                              commenter's assertion that Sec.
                                                                              250.198(a)(3) will have resulted
                                                                              in significant additional costs.
                                                                              See the section-by-section
                                                                              discussion for further elaboration
                                                                              of this issue.
----------------------------------------------------------------------------------------------------------------

V. Section-by-Section Discussion of the Requirements in Final Rule

    As of October 1, 2011, BOEMRE was officially reorganized into the 
separate agencies of BSEE and BOEM. This Final Rule reflects the 
appropriate name changes, based on the reorganization.
    Nomenclature change. BSEE is revising all references to the term 
glory hole in the regulations at 30 CFR 250 to the term well cellar. 
This revision will amend text at two locations in the regulations 
(Sec. Sec.  250.421(b) and 250.451(h)). Both terms refer to a 
depression deep enough to protect subsea equipment from ice-scour, when 
drilling in an ice-scour area. However, the term well cellar is more 
commonly used.

Service Fees (Sec.  250.125)

    This Final Rule updates Sec.  250.125(a)(8) and (9) in the chart to 
reflect accurate numbering redesignation.

Documents Incorporated by Reference (Sec.  250.198)

    Final Sec.  250.198(a)(3) has been modified from the IFR in 
response to many comments received on one important issue. Section 
250.198(a)(3) pertains to how BSEE ensures compliance with documents 
incorporated by reference in its regulations. The provision in the IFR 
read as follows:

    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. (75 FR 63372)

    This provision was intended to clarify BSEE's existing policy on 
compliance with documents incorporated by reference in regulations. A 
number of commenters from the offshore oil and gas industry objected to 
this provision. The commenters were particularly concerned about the 
statement in the last sentence of the paragraph that for the documents 
incorporated by reference in 30 CFR part 250, the word ``should'' means 
``must.'' Commenters asserted that there are 14,000 occurrences of the 
word ``should'' just in documents incorporated from the American 
Petroleum Institute (API). These commenters provided a number of 
examples in which they asserted that the last sentence of paragraph 
(a)(3) could cause conflicts; undermine safety, instead of improving 
safety on the Outer Continental Shelf (OCS); and, in certain 
circumstances, establish requirements with which compliance may be 
impossible. Accordingly, such commenters specifically requested that 
the agency remove the last sentence from paragraph (a)(3).
    While some of the examples provided by commenters were overstated 
or did not account for alternatives or for the specifics in the 
operative language of the incorporated documents, we have removed the 
last sentence of paragraph (a)(3) as set forth in the IFR because it 
could have appeared to be overly broad and may not have provided the 
intended clarification.
    The last sentence is not needed as a means of emphasizing the 
agency's interpretation of the binding effect of documents incorporated 
by reference, i.e., BSEE relies on the specific regulatory provisions 
that incorporate a document by reference for the intended effects of 
each incorporation. The other portions of paragraph (a)(3) make it 
clear that operators are required to comply with documents incorporated 
by reference, unless the specific sections performing the incorporation 
provide otherwise. Moreover, many, but not all, of the individual 
sections of BSEE regulations that incorporate documents by reference 
are written in terms that make it clear that compliance is mandatory, 
even where the incorporated consensus standards were written as 
recommendations, not obligations.
    This position is not a new one and was the agency's interpretation 
of documents incorporated by reference long before the adoption of the 
IFR. For instance, in a 1988 Federal Register preamble to the final 
rule converting agency orders into regulations, the MMS, a predecessor 
agency to BSEE and BOEM, responded to public comments on the effect of 
incorporating documents by reference in its rules as follows:

    Comment--Objection was raised to the incorporation by reference 
of ``recommended practice'' documents which are intended only as 
recommendations, not as rules.
    Response--When MMS adopts the specific provisions of a document 
through the rulemaking process, that incorporation by reference 
establishes the recommended practice as a minimum standard which 
must be observed.
    Comment--A number of commenters expressed the view that with 
respect to documents incorporated by reference, it should be clear 
to what extent references within such incorporated documents are 
also binding. It was pointed out that documents proposed to be 
incorporated by reference in turn reference other documents, which 
reference other documents, down through numerous tiers.
    Response--Under the final rule, the material that is 
incorporated by reference is specifically identified. Adherence to 
documents referenced within an incorporated document is mandatory if 
such adherence is necessary for compliance with the document 
referenced in the rule. (53 FR 10600)

    We reaffirm our position stated in the agency's April 1, 1988, (53 
FR 10600) rule that when BSEE adopts the specific provisions of a 
document through the rulemaking process, that incorporation by 
reference establishes the recommended practice as a minimum standard 
which must be observed.
    We recognize, however, that certain regulations incorporating 
documents by reference either do not make compliance mandatory with the 
incorporated provisions, or provide operators some flexibility in 
achieving compliance. For instance, regulations at Sec.  250.415(f) 
incorporate by reference API RP 65--Part 2, Isolating Potential Flow 
Zones During Well Construction. The requirement in Sec.  250.415(f) 
specifies that operators must submit a written description of how they 
evaluated the best practices included in API RP 65--Part 2, not that 
they must comply with each of the best practices. This Final Rule is 
not intended to upset that interpretation or to modify the meaning of 
any particular regulatory provision that incorporates documents by 
reference.

[[Page 50875]]

    To the extent that the commenters were correct in asserting that 
the last sentence of Sec.  250.198(a)(3) in the IFR (or other 
regulations that establish mandatory compliance with incorporated 
documents) will lead to unintended consequences, BSEE's rules already 
provide the means for operators to seek relief in situations where they 
need an alternative means to comply. One provision, Sec.  250.141, 
allows operators to use alternative procedures or equipment that 
provides a level of safety and environmental protection that equals or 
surpasses that required by BSEE rules. Another, Sec.  250.142, provides 
for departures from operating requirements. Other provisions throughout 
BSEE regulations allow for departures related to specific circumstances 
(e.g., plans, drilling operations, and structure removal). It should be 
noted that all of these departures require advance BSEE approval.
    This approach was clarified in a March 28, 2011, Supplemental 
Information document that appears on the BSEE Web site. That document 
made it clear that the rules require operators to seek BOEMRE approval 
to deviate from a practice or procedure when the document incorporated 
by reference requires a particular practice or procedure.

Incorporation of API Standard 65--Part 2, Second Edition

    In this Final Rule, we have modified Sec.  250.198(h)(79) by 
incorporating the second edition of API Standard 65--Part 2 that was 
issued in December 2010. This change was made in response to comments. 
Previously, the first edition was incorporated. API also designated 
this recommended practice into a standard.

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

    In the IFR, BOEMRE added a new Sec.  250.415 (f) requiring the 
operator to include in its APD an evaluation of the best practices 
identified in API RP 65--Part 2, Isolating Potential Flow Zones During 
Well Construction. In the IFR, we also revised paragraphs (c), (d), and 
(e) to accommodate the new paragraph. The text of paragraph (f) was 
changed in this Final Rule to update the cross reference to sections 4 
and 5 of the second edition of API Standard 65--Part 2. These sections 
correspond to sections 3 and 4 of the earlier edition that were 
previously cross-referenced. The basis and purpose for this section was 
set forth in the preamble of the IFR (75 FR 63346).
    In response to comments, BSEE developed a table, set forth below, 
based on API Standard 65--Part 2 Annex D which outlines the process 
summary for isolating potential flow zones during well construction. 
For example, the operator may use Annex D or the following Table 4 as a 
guide for complying with the written description of how an operator 
evaluated the best practices included in API Standard 65--Part 2 
required by Sec.  250.415(f).

 Table 4--Example of How To Evaluate the Best Practices in API Standard
                               65--Part 2
------------------------------------------------------------------------
 
------------------------------------------------------------------------
                            GENERAL QUESTIONS
------------------------------------------------------------------------
1        Have you considered the following in your  Yes/No.
          well planning and drilling plan
          determinations: evaluation for flow
          potential, site selection, shallow
          hazards, deeper hazard contingency
          planning, well-control planning for
          fluid influxes, planning for lost
          circulation control, regulatory issues
          and communications plans, planning the
          well, pore pressure, fracture gradient,
          mud weight, casing plan, cementing plan,
          drilling plan, wellbore hydraulics,
          wellbore cleaning, barrier design, and
          contingency planning? [API 65-2 1.5].
2        Have you considered the general well       Yes/No.
          practices while drilling, monitoring and
          maintaining wellbore stability, curing
          and preventing lost circulation, and
          planning and operational considerations?
          [API 65-2 1.6].
------------------------------------------------------------------------
                             FLOW POTENTIAL
------------------------------------------------------------------------
3        Will a pre-spud hazard assessment be       Yes/No.
          conducted for the proposed well site?.
4        List all potential flow zones within the   Describe below.
          well section to be cemented.
5        Has the information concerning the type,   Yes/No.
          location, and likelihood of potential
          flow zones been communicated to key
          parties (cementing service provider, rig
          contractor, or third parties)?
------------------------------------------------------------------------
                   CRITICAL DRILLING FLUID PARAMETERS
------------------------------------------------------------------------
6        Are fluid densities sufficient to          Yes/No.
          maintain well-control without inducing
          lost circulation?.
------------------------------------------------------------------------
                     CRITICAL WELL DESIGN PARAMETERS
------------------------------------------------------------------------
7        Will you use a cementing simulation model  Yes/No.
          in the design of this well?.
7a       If yes, how is the output of this          Describe below.
          simulation model used in your decision-
          making process?.
7b       If no, include discussion of why a model   Describe below.
          is not being used.
7c       Either way, include the number and         Describe below.
          placement of centralizers being used.
8        Will you ensure the planned top of cement  Yes/No.
          will be 500 feet above the shallowest
          potential flow zone?.
9        Have you confirmed that the hole diameter  Yes/No.
          is sufficient to provide adequate
          centralization?.
10       If there are any isolated annuli, how      NA or Describe
          have you mitigated thermal casing          below.
          pressure build-up?.
11       Will you ensure the well will be stable    Yes/No.
          (no volume gain or losses, drilling
          fluid density equal in vs. out) before
          commencing cementing operations?
12       List all annular mechanical barriers in    Describe below.
          your design.
13       Has the rathole length been minimized or   Yes/No.
          filled with drilling fluid with a
          density greater than the cement density?.
14a      If you have any liner top packers exposed  NA or Describe
          to the production or intermediate          below.
          annulus, what is the rating for
          differential pressure across this
          packer?
14b      If you have any liner top packers exposed  Yes/No/NA.
          to the production or intermediate
          annulus, have you confirmed that your
          negative test will not exceed this
          rating?
15       What type of casing hanger lock-down       Describe below.
          mechanisms will be used?.
16       For all intermediate and production        Yes/No.
          casing hangers set in subsea, HP
          wellhead housing, will you immediately
          set/energize the lock-down ring prior to
          performing any negative test?

[[Page 50876]]

 
17       For all production casing hangers set in   Yes/No.
          subsea, HP wellhead housing, will you
          set/energize the lock-down sleeve
          immediately after running the casing and
          prior to performing any negative test?
------------------------------------------------------------------------
                     CRITICAL OPERATIONAL PARAMETERS
------------------------------------------------------------------------
18       Will you have 1 mechanical barrier in      Yes/No.
          addition to cement in your final casing
          string (or liner if it is your final
          string)?.
19       Do you plan to nipple down BOP in          Yes/No.
          accordance with the WOC requirements in
          30 CFR 250.422?.
20       Do you plan on running a cement bond log   Yes/No.
          on the production and intermediate
          casing/liner prior to conducting the
          negative test on that string?
------------------------------------------------------------------------
            Are contingency plans in place for the following:
------------------------------------------------------------------------
21       Lost circulation?........................  Yes/No.
22       Unplanned shut-down?.....................  Yes/No.
23       Unplanned rate change?...................  Yes/No.
24       Float equipment does not hold              Yes/No.
          differential pressures?.
25       Surface Equipment issues?................  Yes/No.
26       Will you monitor the annulus during        Yes/No.
          cementing and WOC time?.
27       If using foam cement, is a risk            Yes/No.
          assessment being conducted and
          incorporated into cementing plan?.
28       If using foam cement, will the foamer,     Yes/No.
          stabilizer, and nitrogen injection be
          controlled by an automated process
          system?
------------------------------------------------------------------------
                     CRITICAL MUD REMOVAL PARAMETERS
------------------------------------------------------------------------
28       Have you tested your drilling fluid and    Yes/No.
          cementing fluid programs for
          compatibility to reduce possible
          contamination?.
29       Have you considered actual well            Yes/No.
          conditions when determining appropriate
          cement volumes?.
30       Has the spacer been modeled or designed    Yes/No.
          to achieve the best possible mud
          removal?.
------------------------------------------------------------------------
                    CRITICAL CEMENT SLURRY PARAMETERS
------------------------------------------------------------------------
31       Have all appropriate cement slurry         Yes/No.
          parameters been considered to ensure the
          highest probability of isolating all
          potential flow zones?
32       Do you plan on circulating bottom up       Yes/No.
          prior to the start of the cement job?.
------------------------------------------------------------------------

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

    The IFR revised Sec.  250.416(d) to include the submission of a 
schematic drawing of all control systems, including primary control 
systems, secondary control systems, and pods for the BOP system. We did 
not revise this paragraph in the Final Rule.
    The IFR revised Sec.  250.416(e) to require the operator to submit 
independent third-party verification and supporting documentation that 
shows the blind-shear rams installed in the BOP stack are capable of 
shearing any drill pipe in the hole under maximum anticipated surface 
pressure, as recommended in the Safety Measures Report. In response to 
comments received, we emphasize that the blind-shear rams must be 
capable of shearing heavy weight drill pipe. The Final Rule also 
revises Sec.  250.416(e) to clarify that drill pipe includes workstring 
and tubing. The IFR provided that the supporting documentation has to 
include test results, but did not specify which tests are required. The 
Final Rule clarifies that the documentation must include actual 
shearing and subsequent pressure integrity test results for the most 
rigid pipe to be used and calculations of shearing capacity of all pipe 
to be used in the well, including correction for MASP.
    The IFR added Sec.  250.416(f) to require independent third-party 
verification that a subsea BOP stack is designed for the specific 
equipment used on the rig. In the Final Rule, we revised this paragraph 
to also include surface BOP stacks on floating facilities to clarify 
the intent that this verification is required for all floating drilling 
operations. This section also includes the requirements for 
verification that the BOP stack has not been compromised or damaged 
from previous service. BSEE realizes that an APD may be submitted prior 
to the third-party verification. Under such circumstances, BSEE may 
issue a condition of approval in the APD contingent on the third-party 
verification. The verification must be completed prior to BOP latch-up 
onto the associated well. The third-party verification will be 
submitted to BSEE in an APD or a revised sidetrack permit.
    The IFR added Sec.  250.416(g) to describe the criteria and 
documentation for an independent third-party that must be submitted 
with the APD to BSEE for review.
    In the IFR, Sec.  250.416(g)(1) of this section referenced the 
independent party in Sec.  250.416(e). This Final Rule removes this 
reference, since the requirements for the independent third-party in 
paragraph (g) apply to any use of the independent third-party in Sec.  
250.416.
    We revised paragraph (g)(1) to specify that a registered 
professional engineer, or a technical classification society, or a 
licensed professional engineering firm, could qualify as the 
independent third-party under this section. We also removed the 
reference that the original equipment manufacturer (OEM) cannot be the 
independent third-party. We removed this prohibition so that the OEM, 
who has the expertise with the equipment, may function as the 
independent third-party under this section as long as it meets the 
requirements of the independent third-party outlined in this section.
    Based on comments received, we have also revised qualifications for 
independent third parties to remove various standards that were not 
sufficiently objective or certain. We removed the provision from the 
IFR that the firm can be an API-licensed manufacturing, inspection, or 
certification firm, since API does not license such firms. We also 
removed the requirement that the firm must carry industry-standard 
levels of professional liability insurance, based on comments 
questioning how to determine ``industry standard levels of professional 
liability insurance.'' BSEE has not devised an

[[Page 50877]]

approach to make this determination. We removed the requirement that 
the firm provide evidence that it is ``reputable'' because such a 
standard is too vague. Similarly, we removed the requirement that a 
firm have no record of violations of applicable law because it is not 
clear what ``applicable law'' refers to and how far back the 
requirement applies, and because state licensure or registration will 
assure current compliance. In place of the requirements that were 
removed, in response to comments discussed earlier, we added that 
evidence be provided to demonstrate that the person or entity 
performing the third-party verification has the expertise and 
experience necessary to perform the required verifications. Thus, the 
Final Rule requires evidence of appropriate licenses and evidence of 
expertise and experience to perform the verifications.
    We also revised paragraph (g)(2)(ii) to change the notification of 
the appropriate BSEE District Manager from 24 hours in advance of any 
shearing ram tests or shearing ram inspections to 72 hours in advance. 
This amount of time will facilitate having a BSEE representative 
present to witness at least one of these tests. See the discussion of 
Sec.  250.416 in the IFR (75 FR 63357 through 63358) for additional 
information on this section.

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

    This Final Rule revises Sec.  250.418(g) by adding the phrase 
``below the mudline''. The revision is made to clarify the intent that 
the operator must submit a request for approval to wash out if the 
operator is washing out below the mudline, not for washing out the 
cement in all situations, as was previously provided.
    The IFR added Sec.  250.418(h), which requires operators to submit 
certifications of their casing and cementing program required by Sec.  
250.420(a)(6). Paragraph (h) is not revised in this Final Rule.
    The IFR added Sec.  250.418(i), requiring the operator to submit a 
description of qualifications of any independent third-party. Paragraph 
(i) is revised in this Final Rule by changing the cross reference in 
that paragraph to Sec.  250.416(g), the paragraph that specifies the 
qualifications referred to instead of paragraph (f) as was provided in 
the IFR.

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

    The IFR added Sec.  250.420(a)(6) that requires the operators to 
submit certification of their casing and cementing program signed by a 
Registered Professional Engineer. In the IFR, Sec.  250.420(a)(6) also 
included certification requirements pertaining to two independent 
tested barriers. This Final Rule reorganizes Sec.  250.420(a)(6) to 
focus solely on the required certification and the role of the persons 
making the certification. This Final Rule moves the requirements 
pertaining to two independent barriers to Sec.  250.420(b)(3), 
discussed below.
    The Registered Professional Engineer signing the certification must 
be registered in a State of the United States. In response to comments 
about the qualifications of the person performing the certification, 
this Final Rule specifies that the person signing the certification 
must have sufficient expertise and experience to perform the 
certification. During the review process, BSEE may disallow a 
certification if it concludes that the certifier's expertise and 
experience to perform the certification are inadequate. Although the 
regulation does not require that every certification be accompanied by 
documentation of the qualifications of the person performing the 
certification, BSEE may, on a case-by-case basis, request that such 
material be provided.
    As was provided in the IFR, this Final Rule states that the 
Registered Professional Engineer reviewing the casing and cementing 
design must certify that the design is appropriate for the purpose for 
which it is intended, under expected wellbore conditions. We have also 
added that the certification must specify that the casing and cementing 
design is sufficient to satisfy the tests and requirements of 
Sec. Sec.  250.420 and 250.423. In that manner, the certification ties 
into the substantive requirements of the regulations. Final Sec.  
250.420(a)(6) also provides that the Registered Professional Engineer 
must be involved in the casing and cementing design process. This 
requirement will assure that the Registered Professional Engineer will 
be familiar enough with the design process and the final design to make 
the required certification.
    As mentioned above, this Final Rule moves the requirement 
pertaining to two independent barriers from Sec.  250.420(a)(6) to 
final Sec.  250.420(b)(3). In response to comments, this Final Rule 
revises this requirement to clarify the meaning of ``two independent 
tested barriers.'' We retained the requirement for two independent 
barriers, but removed the word ``tested,'' based on comments. The term 
``two independent tested barriers'' was confusing. In response to 
comments inquiring as to which flow paths must have independent 
barriers, we clarify that on all wells that use subsea BOP stacks, the 
well must include two independent barriers, including one mechanical 
barrier, in each of the annular flow paths. We also added examples of 
acceptable types of barriers, including primary cement job and seal 
assembly.
    In the IFR, Sec.  250.420(b)(3) required the operator to install 
dual mechanical barriers in addition to cement for the final casing 
string (or liner if it is the final string), to prevent flow in the 
event of a failure in the cement. This Final Rule provides, instead, 
that for the final casing string (or liner if it is the final string), 
an operator must install one mechanical barrier in addition to cement, 
to prevent flow in the event of a failure in the cement. We have 
clarified that this requirement applies to the final casing string or 
liner, since that is the string of casing that will be exposed to 
wellbore conditions. Final Sec.  250.420(b)(3) states that an operator 
must submit documentation of this installation to BSEE in the End-of-
Operations Report (Form BSEE-0125) instead of 30 days after 
installation, as was provided in the IFR. This Final Rule also adds 
that these barriers cannot be modified prior to or during completion or 
abandonment operations.
    The IFR stated that dual mechanical barriers may include dual float 
valves. In response to comments, we clarify that a dual float valve, by 
itself, is not considered a mechanical barrier.
    We also added a provision that clarifies that the BSEE District 
Manager may approve alternative options. Although operators may apply 
for approval for use of alternative producers of equipment under 
existing BSEE regulations at Sec.  250.141, we mention it specifically 
in this provision because we recognize that there are other approaches 
to prevent flow in the event of a failure in the cement.

What are the requirements for pressure testing casing? (Sec.  250.423)

    The IFR reorganized Sec.  250.423 to accommodate new requirements, 
redesignated the previous regulation as Sec.  250.423(a) and added new 
Sec.  250.423(b) and (c). Paragraph (b) was added to require the 
operator to perform a pressure test on the casing seal assembly to 
ensure proper installation of casing or liner in the subsea wellhead or 
liner hanger. Paragraph (c) was added to require the operator to 
perform a negative pressure test on all wells to ensure proper 
installation of casing for the intermediate and production casing 
strings.
    This Final Rule revises Sec.  250.423(a) to clarify that if 
pressure declines more than 10 percent in a 30-minute test, or

[[Page 50878]]

there is an indication of a leak, the operator must investigate the 
cause and receive approval from the appropriate BSEE District Manager 
for the repair (e.g., re-cement, casing repair, or additional casing). 
BSEE revised the language to state that BSEE approval is needed.
    This Final Rule, slightly rearranges Sec.  250.423(b) for 
clarification to state, ``You must ensure proper installation of casing 
in the subsea wellhead or liner in the liner hanger.'' This Final Rule 
also revises Sec. Sec.  250.423(b)(1) from the IFR by separating the 
requirements for casing strings and liners into paragraphs (b)(1) and a 
new paragraph (b)(2), respectively.
    New Sec.  250.423(b)(2) provides that if the liner has a latching 
or lock down mechanism, the operator must ensure that the mechanism is 
engaged upon installation of the liner. This new provision clarifies 
that BSEE does not require the use of a latching or lock down 
mechanism, but if the mechanisms are used, they must be engaged upon 
installation.
    The subsequent paragraphs, numbered as Sec. Sec.  250.423(b)(2), 
(b)(3), and (b)(4) in the IFR, are renumbered as Sec. Sec.  
250.423(b)(3), (b)(3)(i), and (b)(3(ii)) in this Final Rule.
    In response to comments, this Final Rule revises Sec.  250.423(c) 
to require a negative pressure test be performed only on wells that use 
a subsea BOP stack or wells with a mudline suspension system instead of 
on all wells, as was provided in the IFR. Requiring the performance of 
negative pressure tests on wells that use a surface BOP stack is not 
necessary; it is more important to test the barriers in subsea wells 
and wells with a mudline suspension.
    In response to comments, this Final Rule adds new Sec. Sec.  
250.423(c)(1) and (c)(2) to clarify when the negative pressure test 
must be performed. We specifically require the operator to perform a 
negative pressure test on the final casing string or liner. We also 
require a negative pressure test prior to unlatching the BOP. The 
negative pressure test is to be conducted on those components, at a 
minimum, that will be exposed to the negative differential pressure 
that will occur when the BOP is disconnected. The Final Rule provides 
that the BSEE District Manager may require performance of additional 
negative pressure tests on other casing strings or liners (e.g., 
intermediate casing string or liner) or on wells with a surface BOP 
stack in situations where it is appropriate. BSEE is requiring the 
negative pressure test on the final casing string or liner because the 
operator may decide to continue other operations on the well before the 
BOP is disconnected.
    The subsequent paragraphs that were numbered Sec. Sec.  
250.423(c)(1) and (c)(2) in the IFR have been redesignated as 
Sec. Sec.  250.423(c)(3) and (c)(4). The redesignated Sec.  
250.423(c)(3) is revised to clarify that if any of the test procedures 
or criteria for a successful test change, the operator must submit for 
approval the changes in an Revised APD or APM.
    In response to comments, we added new paragraph (c)(5) to this 
section, which addresses what the operator must do in the event of an 
indication of a failed negative pressure test and includes examples of 
an indication of failure (pressure buildup or observed flow). The 
operator must investigate the cause of the possible failure, correct 
the problem, contact the appropriate BSEE District Manager, submit a 
description of the corrective action taken, and receive approval from 
the appropriate BSEE District Manager for the retest. Although a 
prudent operator would likely follow these steps in the absence of a 
regulatory provision, inclusion of paragraph (c)(5) is intended to 
provide assurance that these steps will occur, and also ensure that 
BSEE will be involved in these situations.
    This Final Rule also adds Sec.  250.423(c)(6), clarifying that 
operators must have two barriers in place prior to performing the 
negative pressure test. This safeguard is necessary to protect against 
well failure.
    This Final Rule also adds Sec.  250.423(c)(7), requiring 
documentation of the successful negative pressure test in the End-of-
Operations Report (Form BSEE-0125).

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

    This Final Rule revises Sec.  250.428(c) by removing Sec.  
250.428(c)(1) which allowed an operator to pressure test the casing 
shoe when the operator has an indication of an inadequate cement job. 
This section was removed because the pressure test of the casing shoe 
does not provide sufficient information to evaluate the integrity of 
the cement job. This change is consistent with other revisions in the 
IFR and this Final Rule and necessary to ensure the integrity of the 
cement job. This Final Rule revises Sec.  250.428(c) to include ``gas 
cut mud'' as an indication of an inadequate cement job. The option to 
perform a cement ``bond'' log in paragraph (c)(3) is revised to allow 
operators to perform a cement ``evaluation'' log instead. This option 
was changed in the Final Rule to allow operators more flexibility to 
incorporate the use of newer technology to assess the cement job other 
than a bond log; however, an operator may still use a bond log as an 
evaluation tool. With previous Sec.  250.428(c)(1) removed, the Final 
Rule renumbers the remaining paragraphs as Sec.  250.428(c)(1), (c)(2), 
and (c)(3).

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

    Section 250.442 requires that when drilling with a subsea BOP 
system, the BOP system must be installed before drilling below the 
surface casing. The table in this section outlines specific BOP 
requirements.
    Paragraph (a) was revised in the IFR to clarify that the blind-
shear rams must be capable of shearing any drill pipe in the hole under 
maximum anticipated surface pressures. In response to comments, this 
Final Rule revises Sec.  250.442(a) to clarify that drill pipe includes 
workstring and tubing.
    The IFR redesignated the requirement in previous Sec.  250.442(d) 
to have an operable dual-pod control system as new Sec.  250.442(b), 
without substantive change. This Final Rule does not modify the 
redesignated paragraph.
    The IFR added Sec.  250.442(d), containing requirements related to 
ROV intervention capability. This Final rule does not modify these 
requirements.
    The IFR added Sec.  250.442(e), requiring operators to maintain an 
ROV and have a trained ROV crew on each floating drilling rig on a 
continuous basis. This Final Rule modifies Sec.  250.442(e) by removing 
the word ``floating'', which conflicted with the table heading ``when 
drilling with a subsea BOP system'' and created confusion as to the 
agency's intent. This Final Rule clarifies that when drilling with a 
subsea BOP system, the operator must maintain an ROV and have a trained 
ROV crew on each drilling rig (floating or not) on a continuous basis 
once BOP deployment has been initiated from the rig (the stack has been 
splashed) until the BOP is recovered to the surface.
    The IFR added Sec.  250.442(f), containing requirements related to 
autoshear and deadman systems. This Final Rule revises Sec. Sec.  
250.442(f)(1) and (2) in the IFR to specify that the autoshear system 
and deadman system must each be able to close, at a minimum, one set of 
blind-shear rams, instead of one set of shear rams. We revised the 
language to ensure that the shearing rams, when activated, will be 
capable of sealing the wellbore. We also revised Sec.  250.442(f)(3) to 
clarify that the acoustic system will be a secondary control system, 
and cannot supplant a required control system. This Final Rule provides 
that if an operator intends to install an acoustic control system, it

[[Page 50879]]

must demonstrate to BSEE, as part of the information submitted under 
Sec.  250.416, that the acoustic system will function in the 
anticipated environment and conditions.
    The following paragraphs were added in the IFR: Sec.  250.442(g), 
requiring the operator to have operational or physical barrier(s) on 
BOP control panels to prevent accidental use of disconnect functions; 
Sec.  250.442(h), requiring the operator to clearly label all control 
panels for the subsea BOP system; Sec.  250.442(i), requiring the 
operator to develop and use a management system for operating the BOP 
system (the operator may include this with its SEMS program as 
described in 30 CFR 250 subpart S); and Sec.  250.442(j), requiring the 
operator to establish minimum requirements for personnel authorized to 
operate critical BOP equipment. This Final Rule does not revise these 
paragraphs.
    This Final Rule removes Sec.  250.442(l), addressing the use of BOP 
systems in ice-scour areas. This paragraph duplicated Sec.  250.451(h), 
and does not need to appear in two places in the CFR.

What associated systems and related equipment must all BOP systems 
include? (Sec.  250.443)

    This Final rule revises Sec.  250.443(g) to clarify that all BOP 
systems must include a wellhead assembly with a rated working pressure 
that exceeds the maximum anticipated wellhead pressure instead of the 
maximum anticipated surface pressure as was previously provided. This 
revision clarifies what is required when using subsea systems and is 
made to be as consistent as possible with a recommendation in the DWH 
JIT report.

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

    The IFR revised Sec.  250.446(a) to require the operator to 
document the procedures used and to record the results of BOP system 
maintenance and inspection actions, and make the records available to 
BSEE upon request. This Final Rule further revises Sec.  250.446(a) to 
clarify that the documentation requirements pertain to how the BOP 
system maintenance and inspections met or exceeded the specific API RP 
53 provisions referenced earlier in that section.
    The IFR specified that the documents required in Sec.  250.446(a) 
must be maintained on the rig for two years or from the date of the 
last major inspection, whichever is longer. The rule did not state how 
long from the date of the last major inspection the records must be 
kept. To clarify and simplify the timeframe for keeping records, the 
Final Rule provides that records must be maintained on the rig for two 
years from the date the records are created or for longer if directed 
by BSEE.
    The requirement for the BOP system maintenance and inspection 
records to be maintained on the rig for a minimum of two years will 
assure that the records will be kept at the location of, and follow, 
the BOP system if and when the rig changes locations. This requirement 
will help ensure that persons responsible for using a BOP system in the 
future will be able to identify any earlier problems with the BOP 
system and will be able to take necessary steps to try to prevent 
recurrence of such problems.
    As with other activities they perform, drilling contractors who 
control the drilling rig and perform BOP system maintenance and 
inspections are responsible for the documentation and recordkeeping 
requirements of Sec.  250.446(a), see Sec.  250.146(c). Failure to 
satisfy these obligations will subject all responsible persons, 
including contractors, to BSEE enforcement.
    Once the two year obligation for maintaining records begins, a 
contractor controlling the rig will continue to have the record-keeping 
responsibility even if the rig subsequently moves and is used for 
drilling on different leases with different operators. To satisfy their 
obligations, the original lessee and operator will need to obtain 
assurance from a contractor in possession of the BOP system maintenance 
and inspection records for the wells on its lease that the records will 
be kept and made available to BSEE for the required period.

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

    In conjunction with the changes from the IFR regarding stump test 
requirements, this Final Rule revises Sec.  250.449(b) to clarify that 
the time lapse between the stump test of a subsea BOP system and the 
initial test of a subsea BOP system on the seafloor must not exceed 30 
days. This practice is already common in industry and BSEE policy. The 
IFR added Sec.  250.449(j) requiring certain testing during the stump 
test and during the initial testing on the seafloor, but did not 
specify the temporal relationship between the two sets of tests. This 
Final Rule clarifies the timing.
    This revision is intended to help ensure that the condition of a 
BOP has not deteriorated between the stump test and the actual use of 
the BOP. The previous rules did not have a timeframe between the BOP 
system stump test and the initial BOP system test on the seafloor. In 
response to operator inquiries, BSEE's Gulf of Mexico region 
established a policy that BOP system stump tests are to be performed 
within 30 days of the initial BOP system test on the seafloor, to 
preclude reliance upon stump tests that do not accurately reflect the 
condition of the BOP system at the time of installation. This Final 
Rule codifies that policy, and will ensure that operators will not rely 
upon older stump tests to satisfy Sec.  250.449(b). This provision is 
not expected to impact operations to any great degree because stump 
tests of subsea BOP systems typically occur shortly before BOP systems 
are initially installed.
    The IFR made slight editorial changes to Sec. Sec.  250.449(h) and 
(i) to account for the new paragraphs following those sections. This 
Final Rule makes no further changes to Sec. Sec.  250.449(h) and (i).
    The IFR added Sec. Sec.  250.449(j) and (k). In response to 
comments that the BOP tests are insufficient, we revised Sec.  
250.449(j) to require the operator to test and verify closure of at 
least one set of rams during the initial test on the seafloor through 
an ROV hot stab and to clarify that each ROV must be fully compatible 
with the BOP stack intervention panels. The Final Rule also clarifies 
that when an operator submits the test procedures to BSEE for approval, 
the operator must include how it will test each ROV intervention 
function.
    This Final Rule also adds a new paragraph, Sec.  250.449(j)(2), 
which requires a 72-hour notification prior to the initiation of a 
stump test and initial test on the seafloor. Operators must notify BSEE 
at least 72 hours prior to all BOP stump tests and initial BOP tests on 
the seafloor to facilitate having a BSEE representative present to 
witness at least one of these tests. The subsequent paragraph, Sec.  
250.449(j)(2) in the IFR, has been redesignated as Sec.  250.449(j)(3) 
in this Final Rule.
    In response to comments, this Final Rule revises Sec.  250.449(k) 
to require the operator to test the deadman system and verify closure 
of a set of blind-shear rams during the initial test on the seafloor. 
The Final rule also adds new clarification to ensure that the well is 
secure and that hydrocarbon flow would be isolated during the initial 
deadman test on the seafloor. For example if hydrocarbons are present 
in the well, the hydrocarbon flow could be isolated by closing 
appropriate production safety devices, required in subpart H of this 
part, installing plugs, and/or cementing. Also to help mitigate risk 
for the function test of the deadman system

[[Page 50880]]

during the initial test on the seafloor, we added a provision that 
there must be an ROV on bottom. The ROV is located on bottom to assist 
in the testing, as needed, and as a back-up to disconnect the LMRP 
should the rig experience a loss of station event.
    In response to comments BSEE also revised final Sec.  250.449(k)(1) 
to clarify that the required submittals of procedures for the autoshear 
and deadman function testing must include documentation of the controls 
and circuitry of the system utilized during each test. This 
documentation is necessary to verify that the same deadman controls are 
used in testing and emergency activation. This Final Rule also 
specifies that the submittals include procedures on how the ROV will be 
utilized during testing.
    For the same reasons, BSEE made corresponding changes in final 
Sec. Sec.  250.517(d)(9), 250.617(h)(2), and 250.1707(h)(2).

What must I do in certain situations involving BOP equipment or 
systems? (Sec.  250.451)

    As described above, this Final Rule revises Sec.  250.451(h), to 
replace the term ``glory hole'' with the term ``well cellar.'' This 
Final Rule also adds new Sec.  250.451(j) stating that before an 
operator removes the BOP it must have two barriers in place, and that 
the BSEE District Manager may require additional barriers. This 
provision was added to provide clarification for barrier requirements 
prior to removing the BOP stack, and is a safeguard necessary to 
protect against well failure. This regulation is intended to apply to 
normal, planned operations; however, if the operator encounters an 
unexpected situation as outlined in Sec.  250.402, the operator should 
still follow those guidelines as appropriate.

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

    The IFR redesignated then existing Sec.  250.456(j) as Sec.  
250.456(k) and added a new Sec.  250.456(j) to require approval from 
the BSEE District Manager before displacing kill-weight fluid from the 
wellbore.
    This Final Rule revises Sec.  250.456(j) to clarify that the 
operator must receive prior approval before displacing kill-weight 
fluid from the wellbore and/or riser to an underbalanced state. The IFR 
required prior approval whenever kill-weight fluid would be displaced 
from the wellbore, even if the wellbore would not be underbalanced. It 
is not necessary to receive approval if the wellbore will remain in an 
overbalanced state.
    This Final Rule also revises Sec.  250.456(j)(1) to conform the 
flow path description to that contained in Sec.  250.420(b)(3), and 
Sec.  250.456(j)(4) to clarify that the monitoring procedures are 
required for monitoring the volumes and rates of fluids entering and 
leaving the wellbore.

Approval and Reporting of Well-Completion Operations (Sec.  250.513)

    In this Final Rule, we added a new Sec.  250.513(b)(4) as a 
conforming procedural amendment requiring the operator to submit with 
the APD or APM the BOP descriptions for well-completion operations 
required in the new Sec.  250.515. This new paragraph does not require 
information in addition to that already required, but will ensure 
information required under the new Sec.  250.515 is submitted with the 
APD or APM. To accommodate the new paragraph (b)(4), this Final Rule 
redesignates previous Sec. Sec.  250.513(b)(4) and (b)(5) as Sec. Sec.  
250.513(b)(5) and (b)(6).

Well-Control Fluids, Equipment, and Operations (Sec.  250.514)

    In response to comments that requirements for well-completion and 
drilling should be consistent, this Final Rule adds Sec.  250.514(d). 
This new paragraph makes the requirements for well-control fluids for 
well-completions consistent with the requirements for drilling (Sec.  
250.456(j)). As with the drilling requirements, before displacing kill-
weight fluid from the wellbore and/or riser to an underbalanced state, 
the operator must obtain approval from the appropriate BSEE District 
Manager. To obtain this approval, the operator must submit with the APD 
or APM the reasons for displacing the kill-weight fluid and provide 
detailed step-by-step written procedures describing how this will be 
done. 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 that requires such barriers,
    (2) Tests the operator will conduct to ensure integrity of 
independent barriers,
    (3) BOP procedures the operator will use while displacing kill-
weight fluids, and
    (4) Procedures the operator will use to monitor the volumes and 
rates of fluids entering and leaving the wellbore.

What BOP information must I submit? (Sec.  250.515)

    In response to comments, this Final Rule adds a new Sec.  250.515 
which conforms well-completion BOP information requirements to those of 
the drilling and workover subparts, where the same type of equipment 
may be used, and similar safety risks exist. To accommodate the new 
section, this Final Rule redesignates Sec. Sec.  250.515 through 
250.530 as Sec. Sec.  250.516 through 250.531.
    New Sec.  250.515 requires operators to include BOP descriptions in 
the APM for well-completion operations. The operator must include a 
description of the BOP system and system components and a schematic 
drawing of the BOP system. The operator must also include independent 
third-party verification and supporting documentation that show the 
blind-shear rams installed in the BOP stack are capable of shearing any 
drill pipe (including workstring and tubing) in the hole under maximum 
anticipated surface pressure. The documentation must include actual 
test results and calculations of shearing capacity of all pipe that 
will be used in the well including correction for MASP. The operator 
must also include, when using a subsea BOP stack, independent third-
party verification that shows: The BOP stack is designed for the 
specific equipment on the rig and for the specific well design; the BOP 
stack has not been compromised or damaged from previous service; and 
the BOP stack will operate in the conditions in which it will be used.
    Final Sec.  250.515(e) requires operators to include the 
qualifications of the independent third-party performing the 
verifications. The independent third-party must be a registered 
professional engineer, or from a technical classification society, or a 
licensed professional engineering firm capable of providing the 
verifications required under this part. In the qualifications, the 
operator must include evidence that the registered professional 
engineer, or a technical classification society, or engineering firm 
the operator is using to perform the verification or its employees hold 
appropriate licenses to perform the verification in the appropriate 
jurisdiction and evidence to demonstrate that the individual, society, 
or firm has the expertise and experience necessary to perform the 
required verifications. The operator must ensure that an official 
representative of BSEE will have access to the location to witness any 
testing or inspections, and verify information submitted to BSEE. Prior 
to any shearing ram tests or inspections, the operator must notify the 
BSEE District Manager at least 72 hours in advance. This new section 
makes the requirements for submission of BOP information for well-
completions consistent with the requirements in subpart D (Sec. Sec.  
250.416(c) through (g)).

[[Page 50881]]

Blowout Prevention Equipment (Sec.  250.515 in the Interim Final Rule, 
Redesignated as Sec.  250.516 in This Final Rule)

    The IFR added the requirements of Sec.  250.442 in subpart D, Oil 
and Gas Drilling Operations, to the requirements in Sec.  250.515 for 
well-completion operations using a subsea BOP stack. This Final Rule 
redesignates Sec.  250.515 in the IFR as Sec.  250.516, but makes no 
further changes to that section.

Blowout Preventer System Tests, Inspections, and Maintenance (Sec.  
250.516 in the Interim Final Rule, Redesignated as Sec.  250.517 in 
This Final Rule)

    The IFR added Sec.  250.516(d)(8) to require tests for ROV 
intervention functions during the stump test and Sec.  250.516(d)(9) to 
require a function test of the autoshear and deadman system. This Final 
Rule redesignates Sec.  250.516 as Sec.  250.517.
    This Final Rule revises redesignated Sec.  250.517(d)(2) to specify 
that the time lapse between the stump test of a subsea BOP system and 
initial BOP system test on the seafloor must not exceed 30 days; see 
the discussion of Sec.  250.449(b) earlier in this preamble concerning 
inclusion of the same timeframe in subpart D.
    This Final Rule revises redesignated Sec.  250.517(d)(8) to require 
the operator to test and verify closure of at least one set of rams 
during the initial test on the seafloor through an ROV hot stab, and 
that each ROV must be fully compatible with the BOP stack intervention 
panels. This Final Rule also adds a requirement that when an operator 
submits the test procedures, it must include how it will test each ROV 
function. This Final Rule adds a 72-hour notification requirement in 
Sec.  250.517(d)(8)(ii). Operators are required to notify BSEE at least 
72 hours prior to all BOP stump tests and initial BOP tests on the 
seafloor to facilitate having a BSEE representative present to witness 
at least one of these tests. Changes to redesignated Sec.  
250.517(d)(8) are consistent with changes to final Sec.  250.449(j) as 
discussed earlier.
    This Final Rule revises redesignated Sec.  250.517(d)(9) to require 
the operator to test the deadman system and verify closure of a set of 
blind-shear rams during the initial test on the seafloor. The 
verification requirement is new and is consistent with revised Sec.  
250.449(k).
    The IFR revised previous Sec. Sec.  250.516(g) and (h) to expand 
and clarify the requirements for BOP inspections and maintenance. This 
Final Rule revises redesignated Sec. Sec.  250.517(g) and (h) to 
clarify the documentation requirements include showing how an operator 
met or exceeded specific API RP 53 sections. This Final Rule also 
revises redesignated Sec. Sec.  250.517(g) and (h) to clarify the 
recordkeeping timeframe to require that an operator must maintain 
records on the rig for two years from the date of creation or for 
longer if directed by BSEE.
    This Final Rule revises redesignated Sec.  250.517(g)(2) to be 
consistent with the subsea BOP system and marine riser inspection 
requirements in subpart D, Sec.  250.446(b). It requires the visual 
inspection of surface BOP systems on a daily basis. It requires the 
visual inspection of subsea BOP systems and marine risers at least once 
every three days, instead of every day as was provided in the IFR. This 
revision reduces the number of required inspections of subsea BOP 
systems and marine risers.

Approval and Reporting of Well-Workover Operations (Sec.  250.613)

    This Final Rule adds a new Sec.  250.613(b)(3) that requires an 
operator to submit, with its APM, the information required in the new 
Sec.  250.615. This new paragraph was added to ensure that BOP 
descriptions for well-workover operations, required under the new Sec.  
250.615, will be submitted with the APM. To accommodate the new Sec.  
250.613(b)(3), this Final Rule redesignates Sec. Sec.  250.613(b)(3) 
and (b)(4) as Sec. Sec.  250.613(b)(4) and (b)(5).

Well-Control Fluids, Equipment, and Operations (Sec.  250.614)

    In response to comments, this Final Rule adds a new Sec.  
250.614(d). This new paragraph makes the requirements for well-control 
fluids for well-workover operations consistent with the requirements in 
subpart D (Sec.  250.456(j)). As with the drilling requirements, before 
displacing kill-weight fluid from the wellbore to an underbalanced 
state, the operator must obtain approval from the appropriate BSEE 
District Manager. To obtain this approval, the operator must submit, 
with the APM, the reasons for displacing the kill-weight fluid, and 
provide detailed step-by-step written procedures describing how this 
will be accomplished. 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 the operator will conduct to ensure integrity of 
independent barriers,
    (3) BOP procedures the operator will use while displacing kill-
weight fluids, and
    (4) Procedures the operator will use to monitor the volumes and 
rates of fluids entering and leaving the wellbore.

What BOP information must I submit? (Sec.  250.615)

    In response to comments, this Final Rule adds a new section, Sec.  
250.615. This new section makes the requirements for submission of BOP 
information for well-completions consistent with the requirements in 
subpart D (Sec. Sec.  250.416(c) through (g)). This section requires 
operators to include BOP descriptions in the APM for well-completion 
operations. The operator must include a description of the BOP system 
and system components, and a schematic drawing of the BOP system. The 
operator must also include independent third-party verification and 
supporting documentation that show the blind-shear rams installed in 
the BOP stack are capable of shearing any drill pipe (including 
workstring and tubing) in the hole under maximum anticipated surface 
pressure. The documentation must include actual test results and 
calculations of shearing capacity of all pipes to be used in the well, 
including correcting for MASP. Operators must also include, when using 
a subsea BOP stack, independent third-party verification that shows: 
The BOP stack is designed for the specific equipment on the rig and for 
the specific well design; the BOP stack has not been compromised or 
damaged from previous service; and the BOP stack will operate properly 
in the conditions in which it will be used.
    The operators must include qualifications of the independent third-
party. The independent third-party in this section must be a registered 
professional engineer, or a technical classification society, or a 
licensed professional engineering firm capable of providing the 
verifications required under this part. In the qualifications, the 
operator must include evidence that the registered professional 
engineer, or a technical classification society, or engineering firm 
the operator is using to perform the verification or its employees 
holds appropriate licenses to perform the verification in the 
appropriate jurisdiction, and evidence to demonstrate that the 
individual, society, or firm has the expertise and experience necessary 
to perform the required verifications. The operator must ensure that an 
official representative of BSEE will have access to the location to 
witness any testing or inspections, and verify information submitted to 
BSEE. Prior to any shearing ram tests or inspections, the operator must 
notify the BSEE District Manager

[[Page 50882]]

at least 72 hours in advance to facilitate having a BSEE representative 
present to witness at least one of these tests.
    To accommodate the new section, this Final Rule redesignates 
previous Sec. Sec.  250.615 through 250.619 as Sec. Sec.  250.616 
through 250.620.

Blowout Prevention Equipment (Sec.  250.615 in the Interim Final Rule, 
Redesignated as Sec.  250.616 in Final Rule)

    The IFR added new Sec. Sec.  250.615(b)(5) and (e) that applied the 
requirements of Sec.  250.442 in subpart D, Oil and Gas Drilling 
Operations, to well-workover operations using a subsea BOP stack. This 
Final Rule redesignates this section as Sec.  250.616, but does not 
substantively change the IFR.

Blowout Preventer System Testing, Records, and Drills (Sec.  250.616 in 
the Interim Final Rule IFR, Redesignated as Sec.  250.617 in This Final 
Rule)

    The IFR added Sec.  250.616(h) to require an operator to stump test 
a subsea BOP system before installation. It added Sec.  250.616(h)(1) 
to require tests for ROV intervention functions during the stump test, 
Sec.  250.616(h)(2) to require a function test of the autoshear and 
deadman system, and Sec.  250.616(h)(3) to require the use of water to 
stump test a subsea BOP system. This Final Rule redesignates this 
section as Sec.  250.617.
    This Final Rule revises redesignated Sec.  250.617(h) to be 
consistent with final Sec. Sec.  250.449 and 250.517. It requires that 
the initial test on the seafloor must be conducted within 30 days of 
the stump test of the subsea BOP stack. This subsection does not add a 
new requirement; it just specifies the timing of the test. This Final 
Rule revises redesignated Sec.  250.617(h)(1) to require the operator 
to test and verify closure of at least one set of rams during the 
initial test on the seafloor through an ROV hot stab and that each ROV 
must be fully compatible with the BOP stack intervention panels. It 
also adds that when an operator submits the test procedures it must 
include how it will test each ROV function.
    The Final Rule also adds Sec.  250.617(h)(1)(ii) which includes a 
notification provision requiring operators to notify BSEE at least 72 
hours prior to all BOP stump tests and initial BOP tests on the 
seafloor to facilitate having a BSEE representative present to witness 
at least one of these tests. This Final Rule revises redesignated Sec.  
250.617(h)(2) to require the operator to test the deadman system and 
verify closure of a set of blind-shear rams during the initial test on 
the seafloor. This Final Rule moves the contents of redesignated Sec.  
250.617(h)(2)(iii) into the general text of Sec.  250.617(h).

What are my BOP inspection and maintenance requirements? (Sec.  250.617 
in the Interim Final Rule, Sec.  250.618 in the Final Rule)

    The IFR added Sec.  250.617 to apply the requirements of Sec.  
250.446 in subpart D, Oil and Gas Drilling Operations, to the 
inspections and maintenance requirements for well-workover operations 
using a subsea BOP stack. This Final Rule redesignates Sec.  250.617 as 
Sec.  250.618. This Final Rule revises redesignated Sec.  250.618(a) to 
clarify that the documentation requirements include showing how an 
operator met or exceeded specific API RP 53 sections. It also clarifies 
the recordkeeping timeframe to require records to be maintained on the 
rig for 2 years from the date the records are created or for longer if 
directed by BSEE. The previous text was confusing.
    This Final Rule also revises redesignated Sec. Sec.  250.618(a)(2) 
be consistent with the subsea BOP system and marine riser inspection 
requirements in subpart D, Sec.  250.446(b). It requires the visual 
inspection of surface BOP systems on a daily basis. It requires the 
visual inspection of subsea BOP systems and marine risers at least once 
every 3 days, instead of every day. This revision reduces the number of 
required inspections of the subsea BOP system and marine riser.

Definitions (Sec.  250.1500)

    In the IFR, BOEMRE added separate definitions for the terms 
deepwater well-control, well servicing and well-completion/well-
workover. This Final Rule makes no further changes to those 
definitions.
    We have clarified the definition of well-control to be as 
consistent as possible with recommendations in the DWH JIT report. In 
the Final Rule we also clarify that well-control applies to abandonment 
operations. The Final Rule provides that well-control means methods 
used to minimize the potential for the well to flow or kick and to 
maintain control of the well in the event of flow or a kick. Well-
control applies to drilling, well-completion, well-workover, 
abandonment, and well-servicing operations. It includes measures, 
practices, procedures and equipment, such as fluid flow monitoring, to 
ensure safe and environmentally protective drilling, completion, 
abandonment, and workover operations as well as the installation, 
repair, maintenance, and operation of surface and subsea well-control 
equipment.
    Inclusion of this revised definition in subpart O will facilitate 
the establishment of minimum training standards for persons monitoring 
and maintaining well-control. This new definition encompasses anyone 
who has the responsibility for monitoring the well and/or maintaining 
the well-control equipment for well control purposes.

What are my general responsibilities for training? (Sec.  250.1503)

    In the IFR, the operator is required to ensure that employees and 
contract personnel are trained in deepwater well-control when 
conducting operations with a subsea BOP stack. They must have a 
comprehensive knowledge of deepwater well-control equipment, practices, 
and theory. We did not make any changes to this section in the Final 
Rule.

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

    This Final Rule revises Sec.  250.1704(g) by adding Sec.  
250.1704(g)(1)(ii) to provide clarification that when an operator uses 
a BOP for abandonment operations, it must include the information 
required under Sec.  250.1705, discussed below.

What BOP information must I submit? (Sec.  250.1705)

    In response to comment, this Final Rule adds Sec.  250.1705. BSEE 
received a comment stating that some BOP requirements were omitted in 
subparts E and F that should be included to ensure consistency of BOP 
requirements with subpart D. We agree with this comment and have made 
the appropriate changes in those subparts. This reasoning has also led 
us to conclude these requirements should also be extended to subpart Q. 
The same BOP equipment may be used in abandonment operations as is used 
in operations under the other subparts. Attendant safety risks are also 
similar and justify imposition of the same regulatory oversight in 
subpart Q as that contained in the other subparts.
    Final Rule Sec.  250.1705 requires operators to include BOP 
descriptions in the APM for well-completion operations. The operator 
must include a description of the BOP system and system components and 
a schematic drawing of the BOP system. The operator must also include 
independent third-party verification and supporting documentation that 
show the blind-shear rams installed in the BOP stack are capable of 
shearing any drill pipe (including workstring and tubing) in the hole 
under maximum anticipated surface pressure. The documentation must 
include test results and

[[Page 50883]]

calculations of shearing capacity of all pipe to be used in the well, 
including correction for MASP. The operator must also include, when 
using a subsea BOP stack, independent third-party verification that 
shows: the BOP stack is designed for the specific equipment on the rig 
and for the specific well design; the BOP stack has not been 
compromised or damaged from previous service; and the BOP stack will 
operate in the conditions in which it will be used.
    The operators must include qualifications of the independent third-
party. The independent third-party in this section must be a registered 
professional engineer, or technical classification society, or a 
licensed professional engineering firm capable of providing the 
verifications required under this part. In the qualifications, the 
operator must include evidence that the registered professional 
engineer, or a technical classification society, or engineering firm it 
is using to perform the verifications or its employees hold appropriate 
licenses to perform the verification in the appropriate jurisdiction, 
and evidence to demonstrate that the individual, society, or firm has 
the expertise and experience necessary to perform the required 
verifications. The operator must ensure that an official representative 
of BSEE will have access to the location to witness any testing or 
inspections, and verify information submitted to BSEE. Prior to any 
shearing ram tests or inspections, the operator must notify the BSEE 
District Manager at least 72 hours in advance. This new section makes 
the requirements for submission of BOP information for well-completions 
consistent with the requirements in subpart D (Sec.  250.416(c) through 
(g)).

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

    BSEE received a comment stating that BOP requirements were omitted 
in subparts E and F. We agree with this comment; it is important for 
BOP requirements to be consistent, regardless of the application. We 
have made the appropriate changes in those subparts and also have 
included these requirements in subpart Q for abandonment operations 
that use a BOP system. In response to the comment, this Final Rule adds 
Sec.  250.1706, which also adds consistency for BOP requirements 
between subparts. If the operator plans to use a BOP for any well 
abandonment operations, the BOP must meet the same requirements as 
those in subpart F, Sec.  250.616.

What are the requirements for blowout preventer system testing, 
records, and drills? (Sec.  250.1707)

    BSEE received a comment stating that BOP requirements were omitted 
in subparts E and F. We agree with this comment; it is important for 
BOP requirements to be consistent, regardless of the application. We 
have made the appropriate changes in those subparts and also have 
included these requirements in subpart Q for abandonment operations 
that use a BOP system. Since the new sections are added for BOP 
requirements in subpart Q, this Final Rule also adds Sec.  250.1707 to 
ensure operators meet the same testing and recordkeeping requirements 
as those in subparts D, E, and F.

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

    BSEE received a comment stating that BOP requirements were omitted 
in subparts E and F. We agree with this comment; it is important for 
BOP requirements to be consistent, regardless of the application. We 
have made the appropriate changes in those subparts and also have 
included these requirements in subpart Q for abandonment operations 
that use a BOP system. Since the new sections are added for BOP 
requirements in subpart Q, this new section is added to the Final Rule 
to ensure operators maintain and inspect the BOP equipment as required 
in subparts D, E, and F.

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

    In response to comments, we added a new section in the Final Rule. 
This new section makes the requirements for well-control fluids for 
well abandonment consistent with the requirements for drilling (Sec.  
250.456(j)). As with the drilling requirements, before displacing kill-
weight fluid from the wellbore to an underbalanced state, the operator 
must obtain approval from the appropriate BSEE District Manager. To 
obtain this approval, the operator must submit with the APM the reasons 
for displacing the kill-weight fluid and provide detailed step-by-step 
written procedures describing how the displacement will be 
accomplished. 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 the volumes and rates of 
fluids entering and leaving the wellbore.

What information must I submit before I permanently plug a well or 
zone? (Sec.  250.1712)

    In the IFR, a new paragraph (g) was added and paragraphs (e) and 
(f)(14) were revised to accommodate the new paragraph. New paragraph 
(g) requires operators to submit certification by a Registered 
Professional Engineer of the well abandonment design and procedures. 
The Registered Professional Engineer must be registered in a state of 
the United States and have sufficient expertise and experience to 
perform the certification. The Registered Professional Engineer does 
not have to be licensed for a specific discipline, but must be capable 
of reviewing and certifying that the casing design is appropriate for 
the purpose for which it is intended under expected wellbore 
conditions. The IFR provided that the Registered Professional Engineer 
certifies that there will be at least two independent tested barriers, 
including one mechanical barrier, across each flow path during well 
abandonment activities. The IFR also provided that the Registered 
Professional Engineer certify that the plug meets the requirements in 
the table in Sec.  250.1715.
    In response to comments, the language in the Final Rule paragraph 
(g) was clarified that the Registered Professional Engineer must 
certify the well abandonment design and that all applicable plugs meet 
the requirements in the table in Sec.  250.1715. In response to 
comments related to Sec.  250.420(b)(3) discussed earlier, the 
Registered Professional Engineer must also certify that the design will 
include two independent barriers, one of which must be a mechanical 
barrier, in the center wellbore, as described in Sec.  250.420(b)(3).

How must I permanently plug a well? (Sec.  250.1715)

    The Final Rule adopts a conforming change to Sec.  250.1715 by 
adding paragraph (a)(11) which ensures that two independent barriers, 
as described in Sec.  250.420(b)(3), will be put in place for 
abandonment if the barriers have been removed for production. Both the 
IFR and this Final Rule already require certification of the design of 
such barriers in Sec.  250.1712(g), and the amendment to Sec.  250.1715 
is necessary to accompany the certification.

[[Page 50884]]

If I temporarily abandon a well that I plan to re-enter, what must I 
do? (Sec.  250.1721)

    In the IFR, new paragraph (h) was added to require operators to 
submit certification by a Registered Professional Engineer of the well 
abandonment design and procedures.
    In response to comments, language in paragraph (h) in the Final 
Rule was clarified that the Registered Professional Engineer must 
certify the well abandonment design and procedures. The Registered 
Professional Engineer must also certify that the design includes two 
independent barriers in the center wellbore and all annuli, one of 
which must be a mechanical barrier. The text has been modified from the 
IFR to be consistent with the requirements of Sec.  250.420(b)(3).

VI. Compliance Costs

    The IFR contained a table estimating compliance costs on a section-
by-section basis. Since the IFR was published, we have reanalyzed 
compliance costs based on actual experience under the rule. In 
addition, this Final Rule modifies various provisions of the IFR. The 
following table provides a summary comparison between the compliance 
costs of the IFR and this Final Rule. The following table demonstrates 
that the estimated compliance costs have decreased by approximately 52 
million dollars.

             Estimated Compliance Costs Comparison Between the Interim Final Rule and the Final Rule
----------------------------------------------------------------------------------------------------------------
                                                 IFR  ($     Final Rule  ($   Compliance cost change between IFR
           Annual recurring costs               millions)       millions)               and Final Rule
----------------------------------------------------------------------------------------------------------------
Subsea ROV function testing (drilling).....           102.7            17.1  Estimated time was reduced. BSEE
                                                                              over estimated the time required
                                                                              for the subsea tests.
Subsea ROV function testing (completions/              15.5             5.5  Estimated time was reduced. BSEE
 workover/abandonments).                                                      over estimated the time required
                                                                              for the subsea tests. Count of
                                                                              abandonment operations added to
                                                                              revised count of workover/
                                                                              completions.
Test casing strings for proper installation            45.1            12.8  Regulation was changed and the
 (negative pressure test).                                                    count of actions is reduced. BSEE
                                                                              no longer requires a negative
                                                                              pressure test on all intermediate
                                                                              casing strings, only the final
                                                                              casing before the subsea BOP is
                                                                              removed.
Installation of two independent barriers,              10.3            83.0  Regulation was changed from dual
 one of which must be a mechanical barrier.                                   mechanical barriers. A dual float
                                                                              valve no longer meets the
                                                                              definition of a mechanical
                                                                              barrier. The estimated time to
                                                                              install the mechanical barrier
                                                                              increased to 12 hours.
PE certification for well design...........             6.0             3.9  Cost estimate reduced because the
                                                                              large companies drilling in
                                                                              shallow water are now assumed to
                                                                              have Professional PE available for
                                                                              in-house certification.
Emergency cost of activated shear rams or               2.6             2.6  No change.
 LMRP disconnect.
Independent third-party shear certification             1.2             1.2  No change.
Paperwork Costs taken from PRA tables in                0.0             4.6  Paperwork costs were not included
 IFR & Final Rule.                                                            in the IFR benefit-cost analysis,
                                                                              but are added to the compliance
                                                                              cost for the final rule.
                                            --------------------------------------------------------------------
    Total..................................           183.4           130.7  ...................................
----------------------------------------------------------------------------------------------------------------

VII. Procedural Matters

Regulatory Planning and Review (Executive Orders 12866 and 13563)

    This rulemaking constitutes a significant rule as determined by the 
Office of Management and Budget (OMB) and is subject to review under 
E.O. 12866. For purposes of this analysis, we deem the rulemaking to 
consist of the IFR as modified by this Final Rule.
    (1) This rulemaking will have an annual effect of $100 million or 
more on the economy. The following discussion summarizes a Regulatory 
Impact Analysis (RIA) that is available on www.Regulations.gov. Use the 
keyword/ID ``BSEE-2012-0002'' to locate the docket for this rule.
    BSEE estimates the annual cost of this rulemaking to be 
approximately $131 million per year. Because of regulatory changes in 
this Final Rule and revised cost assumptions, the annual compliance 
cost is reduced from $183 million estimated in the IFR to $131 million 
for the final regulatory impact analysis. The quantification of 
benefits is uncertain, but is estimated to be represented by the 
avoided costs of a catastrophic spill, which are estimated under the 
stipulated scenario as being $16.3 billion per spill avoided and 
annualized at $631 million per year.
    Based on the occurrence of only a single catastrophic blowout, the 
number of GOM deepwater wells drilled historically (4,123), and the 
forecasted future drilling activity in the GOM (160 deepwater wells per 
year), we estimate the baseline risk of a catastrophic blowout to be 
about once every 26 years. Combining the baseline likelihood of 
occurrence with the cost of a representative spill implies that the 
expected annualized damage cost absent this regulation is $631 million 
($16.3 billion once in 26 years, equally likely in any 1 year). To 
balance the $131 million annual cost imposed by this rulemaking with 
the expected benefits, the reliability of the well-control system needs 
to improve by 21 percent ($131 million/$631 million). We have found no 
studies that evaluate the degree of actual improvement that could be 
expected from dual barriers, negative pressure tests, and a seafloor 
ROV function test and no additional information was provided during the 
public comment period. However, based upon the plausible scenarios that 
have been developed, it is reasonable to conclude that this rulemaking 
will reduce the risk of a catastrophic blowout spill event such that 
benefits will justify the costs estimated to be imposed by the 
regulation.
    The purpose of a benefit-cost analysis is to provide policy makers 
and others with detailed information on the economic consequences of 
the regulatory requirements. The benefit-cost analysis for this 
rulemaking was

[[Page 50885]]

conducted using a scenario analysis. The benefit-cost analysis 
considers a regulation designed to reduce the likelihood of a 
catastrophic oil spill. The costs are the compliance costs of imposed 
regulation. If another catastrophic oil spill is prevented, the 
benefits are the avoided costs associated with a catastrophic oil spill 
(e.g., reduction in expected natural resource damages owing to the 
reduction in likelihood of failure).
    Avoided cost is an approximation of the ``true'' benefits of 
avoiding a catastrophic oil spill. A benefits transfer approach is used 
to estimate the avoided costs. The benefits transfer method estimates 
economic values by transferring existing benefit calculations from 
studies already completed for another location or issue to the case at 
hand. Accordingly, none of the avoided costs used for a hypothetical 
catastrophic spill rely upon, or should be taken to represent, our 
estimate for the DWH event.
    Three new requirements account for most of the compliance costs 
imposed by this rulemaking. These are: (1) Use of two independent 
barriers in each annular flow path; and in the final casing string or 
liner to prevent hydrocarbon flow in the event of cement failure; (2) 
Application of negative pressure tests to the production casing string 
for wells drilled with a subsea BOP; and (3) Testing time for the ROV 
to close BOP rams after the BOP has been installed on the sea floor. 
BSEE estimates that these three requirements will impose compliance 
costs of approximately $118 million per year, representing 91 percent 
of the total annual compliance costs of $131 million associated with 
this rulemaking. These cost estimates were developed based on public 
data sources, BSEE experience, and confidential information provided by 
several offshore operators and drilling companies. The $131 million 
estimated annual compliance costs are 29 percent less than the $183 
million cost estimated previously for the IFR, largely reflecting a 
reduced estimate of the time it takes to conduct an ROV function test 
when the BOP is on the seafloor and lower negative pressure test costs 
resulting from relaxed testing requirements in the IFR. These reduced 
costs are partly offset by the requirement that a dual float valve no 
longer meets the criteria for a mechanical barrier and inclusion of 
paperwork costs omitted from the estimates in the IFR. See table 4 
earlier in this preamble comparing the IFR estimated compliance costs 
with those estimated in this Final Rule.
    On the benefit side, the avoided costs for a representative 
deepwater blowout resulting in a catastrophic oil spill are estimated 
to be about $16.3 billion (in 2010 dollars). Most of this amount 
derives from cleanup and restoration estimates developed by the 
Department of the Interior, Office of Policy Analysis, using damage 
costs per barrel measures found in historical spill data (from all 
sources including pipeline, tanker, and shallow water, as well as from 
deepwater wells) and from aggregate damage measures contained in the 
legal settlement documents for past spills applied to a catastrophic 
deepwater spill of hypothetical size. The rest of this avoided cost 
amount represents the private costs for blowout containment operations. 
In sum, three components account for nearly the entire avoided spill 
cost total: (1) Natural resource damage to habitat and creatures; (2) 
Infrastructure salvage and cleanup operations of areas soiled by oil; 
and (3) Containment and well-plugging actions, plus lost hydrocarbons.
    We believe the compliance cost estimate of $131 million is closer 
to the actual cost than the figure used in the IFR because of improved 
information gathered since deepwater drilling resumed in the GOM in the 
spring of 2011. On the benefit side, the total avoided cost estimate of 
$16.3 billion (representing a measure of expected benefits for avoiding 
a future catastrophic oil spill) has not been revised. The true 
magnitude of an avoided spill is highly uncertain because of the 
limited historical data upon which to judge the cost of failure, the 
disparity between the damages associated with spills of different 
sizes, locations, and season of occurrence, and owing to the fact that 
the measure employed reflects only those outlays that we have been able 
to calculate based primarily upon factors derived from past oil spills. 
Possible losses from human health effects or reduced property values 
have not been quantified in this analysis. Moreover, the likelihood of 
a future blowout leading to a catastrophic oil spill is difficult to 
quantify because of limited historical data on catastrophic offshore 
blowouts.
    (2) This final rule will not adversely affect competition or State, 
local, or tribal governments or communities.
    (3) This final rule will not create a serious inconsistency or 
otherwise interfere with an action taken or planned by another agency.
    (4) This final rule will not alter the budgetary effects of 
entitlements, grants, user fees, or loan programs or the rights or 
obligations of their recipients.
    (5) This final rule will not raise novel legal or policy issues 
arising out of legal mandates, the President's priorities, or the 
principles set forth in E.O. 12866.
    Executive Order 13563 reaffirms the principles of E.O. 12866 while 
calling for improvements in the nation's regulatory system to promote 
predictability, to reduce uncertainty, and to use the best, most 
innovative, and least burdensome tools for achieving regulatory ends. 
The executive order directs agencies to consider regulatory approaches 
that reduce burdens and maintain flexibility and freedom of choice for 
the public where these approaches are relevant, feasible, and 
consistent with regulatory objectives. E.O. 13563 emphasizes further 
that regulations must be based on the best available science and that 
the rulemaking process must allow for public participation and an open 
exchange of ideas. This final rule has been developed in a manner 
consistent with these requirements.

Regulatory Flexibility Act: Final Regulatory Flexibility Analysis

    BSEE has prepared a Final Regulatory Flexibility Analysis (FRFA) in 
conjunction with this Final Rule. The FRFA is found in Appendix A of 
the Regulatory Impact Analysis (RIA). As with the analysis under E.O. 
12866, the FRFA analyzes the rulemaking, consisting of the IFR as 
modified by this Final Rule. The Bureau's publication of the IFR did 
not include a full Initial Regulatory Flexibility Analysis (IRFA) 
pursuant to the Regulatory Flexibility Act (5 U.S.C. 603). A 
supplemental IRFA was published on December 23, 2010 (75 FR 80717) with 
a 30-day comment period which closed on January 24, 2011. The changes 
from the IRFA are minor and relate to lower total compliance cost 
estimates for the regulation. The revised cost estimates are the result 
of changes to the regulatory language from the IFR to this Final Rule 
and improved estimates of the costs and the operational timeframes 
required to comply with the regulatory provisions.
    This final rule affects lessees, operators of leases, and drilling 
contractors on the OCS; thus this rule directly impacts small entities. 
This could include about 130 active Federal oil and gas lessees and 
more than a dozen drilling contractors and their suppliers. Small 
entities that operate under this rule are coded under the Small 
Business Administration's North American Industry Classification System 
(NAICS) codes 211111, Crude Petroleum and Natural Gas Extraction, and 
213111, Drilling Oil and Gas Wells.

[[Page 50886]]

For these NAICS code classifications, a small company is one with fewer 
than 500 employees. Based on these criteria, approximately 65 percent 
of companies operating on the OCS are considered small companies. 
Therefore, BSEE has determined that this rulemaking will have an impact 
on a substantial number of small entities.
    We estimate that the rulemaking will impose a recurring operational 
cost of $131 million each year on operators drilling OCS wells. The 
rulemaking affects every new well drilled after October 14, 2010; some 
requirements also apply to wells undergoing completion, workover, or 
abandonment operations on the OCS. Every operator, both large and 
small, must meet the same criteria for these operations regardless of 
company size. However, the overwhelming share of the cost imposed by 
the rulemaking will fall on the operating companies drilling deepwater 
wells, which are predominately the larger companies. We estimate that 
about 81 percent of the total costs will be imposed on deepwater 
lessees and operators where small businesses only hold 8 percent of the 
leases and drill 12 percent of the wells. About 19 percent of the total 
costs will apply to shallow water leases where small companies hold 45 
percent of OCS leases and also drill 45 percent of the wells.
    Nonetheless, small companies, as both operators and lease-holders, 
will bear meaningful costs under the rulemaking. Of the annual $131 
million in annual cost imposed by the rulemaking, we estimate that 
$12.7 million will apply to small businesses operating in deepwater and 
$11.2 million to those operating in shallow water. In total, we 
estimate that $23.9 million or 18 percent of the rulemaking's cost will 
be borne by small businesses.
    Alternatives to ease impacts on small business were considered and 
are discussed in the FRFA. The alternatives considered include: 
different compliance requirements for small entities, alternative BOP 
testing requirements and periods, performance rather than design 
standards, and exemption from regulatory requirements. These 
alternatives are being rejected by BSEE for this rulemaking because of 
the overriding need to reduce the chance of a catastrophic blowout 
event. It would not be responsible for a regulator to compromise the 
safety of offshore personnel and the environment for any entity, 
including small businesses. Offshore drilling is highly technical and 
can be hazardous; any delay may increase the interim risk of OCS 
drilling operations.

Small Business Regulatory Enforcement Fairness Act

    This final rule is a major rule under the Small Business Regulatory 
Enforcement Fairness Act (5 U.S.C. 801 et seq.). As with the preceding 
analyses, this discussion deems the rulemaking to consist of the IFR as 
modified by this Final Rule. This rulemaking:
    (a) Will have an annual effect on the economy of $100 million or 
more. This rulemaking will affect every new well on the OCS, and every 
operator, both large and small must meet the same criteria for well 
construction regardless of company size. This rulemaking may have a 
significant economic effect on a substantial number of small entities, 
as discussed in the FRFA. While large companies will bear the majority 
of these costs, small companies as both leaseholders and contractors 
supporting OCS drilling operations will be affected.
    Considering the new requirements for redundant barriers and new 
tests, we estimate that this rulemaking will add an average of about 
$850 thousand to each new deepwater well drilled and completed with a 
MODU, $230 thousand for each new deepwater well drilled with a platform 
rig, and $130 thousand for each new shallow water well. While not an 
insignificant amount, we note this extra recurring cost is around 1 
percent for most deep and shallow water wells.
    (b) Will not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, or local government 
agencies, or geographic regions. The impact on domestic deepwater 
hydrocarbon production as a result of these regulations is expected to 
be marginally negative, but the size of the impact is not expected to 
materially impact world oil markets. The deepwater GOM is an oil 
province and the domestic crude oil prices are set by the world oil 
markets. Currently, domestic onshore production is increasing and there 
is sufficient spare capacity in OPEC to offset any GOM deepwater 
production decline that could occur as a result of this rulemaking. 
Therefore, the increase in the price of hydrocarbon products to 
consumers from the increased cost to drill and operate on the OCS is 
expected to be minimal.
    (c) Will not have significant adverse effects on competition, 
innovation, or the ability of U.S.-based enterprises to compete with 
foreign-based enterprises. The requirements will apply to all entities 
operating on the OCS.
    (d) May have adverse effects on employment, investment, and 
productivity. A meaningful increase in costs as a result of more 
stringent regulations and increased drilling costs may result in a 
reduction in the pace of deepwater drilling activity on marginal 
offshore fields, and reduce investment in our offshore domestic energy 
resources from what it otherwise will be, thereby reducing employment 
in OCS and related support industries. The additional regulatory 
requirements in this rulemaking will increase drilling costs and add to 
the time it takes to drill deepwater wells. The resulting reduction in 
profitability of drilling operations may cause some declines in related 
investment and employment. A typical deepwater well drilled by a MODU 
may cost $90-$100 million. The added cost of this rulemaking for 
offshore wells is expected to yield about a 1 percent decrease in 
productivity.
    (e) Does not make accommodations for small business. Not making 
such accommodations avoids the risk of compromising the safety and 
environmental protections addressed in this rulemaking. Small 
businesses actively invest in offshore operations, owning a 12 percent 
interest in deepwater leases, most often as a minority partner, and 45 
percent of shallow water leases. This rulemaking will make it more 
expensive for all interest holders in OCS leases, and we do not expect 
a disproportionate impact on small businesses. However, the costs in 
this rulemaking may contribute to one or more of the following:
    (1) Reduce the small business ownership share in individual 
deepwater leases.
    (2) Cause small businesses to target their investments more in 
shallow water leases.
    (3) Cause small businesses to target their investments more in 
onshore oil and gas operations or other natural resources.
    (4) Small businesses may choose to invest or partner in overseas 
natural resource operations.
    (f) May affect small businesses that support offshore oil and gas 
drilling operations including service, supply, and consulting 
companies. Because there may be a marginal decrease in offshore 
drilling activity due to the increased cost and regulatory burden, some 
businesses that support drilling operations may experience reduced 
business activity. Some small business may therefore decide to focus 
more on shallow water or other oil and gas offshore provinces overseas.
    (g) May benefit some small businesses. Companies that are involved

[[Page 50887]]

with inspecting and certifying equipment covered by this rulemaking, as 
well as consulting companies specializing in safety and offshore 
drilling, could see long-term growth.

Unfunded Mandates Reform Act of 1995

    This Final Rule will not impose an unfunded mandate on State, 
local, or tribal governments or the private sector of more than $100 
million per year. The Final Rule will not have a significant or unique 
effect on State, local, or tribal governments or the private sector. A 
statement containing the information required by the Unfunded Mandates 
Reform Act (2 U.S.C. 1501 et seq.) is not required.

Takings Implication Assessment (E.O. 12630)

    Under the criteria in E.O. 12630, this rulemaking does not have 
significant takings implications. The Final Rule is not a governmental 
action capable of interference with constitutionally protected property 
rights. A Takings Implication Assessment is not required.

Federalism (E.O. 13132)

    Under the criteria in E.O. 13132, this final rule does not have 
federalism implications. This rulemaking will not substantially and 
directly affect the relationship between the Federal and State 
governments. To the extent that State and local governments have a role 
in OCS activities, this rulemaking will not affect that role. A 
Federalism Assessment is not required.

Civil Justice Reform (E.O. 12988)

    This rulemaking complies with the requirements of E.O. 12988. 
Specifically, this rulemaking:
    (a) Meets the criteria of section 3(a) requiring that all 
regulations be reviewed to eliminate errors and ambiguity and be 
written to minimize litigation; and
    (b) Meets the criteria of section 3(b)(2) requiring that all 
regulations be written in clear language and contain clear legal 
standards.

Consultation With Indian Tribes (E.O. 13175)

    Under the criteria in E.O. 13175, we have evaluated this rulemaking 
and determined that it has no substantial effects on Federally 
recognized Indian tribes.

Paperwork Reduction Act (PRA)

    This Final Rule contains a collection of information that was 
submitted to and approved by OMB under the Paperwork Reduction Act of 
1995 (44 U.S.C. 3501 et seq.). This rule expands existing and adds new 
regulatory requirements under in 30 CFR 250, subparts D, E, F, and Q 
based on comments received from the IFR (75 FR 63346). The OMB approved 
these requirements and assigned OMB Control Number 1014-0020, 5,347 
hours (expiration August 31, 2015). The title of the collection of 
information for this Final Rule is 30 CFR 250, Increased Safety 
Measures for Energy Development on the Outer Continental Shelf.
    Respondents primarily are the Federal OCS lessees and operators. 
The frequency of response varies depending upon the requirement. 
Responses to this collection of information are mandatory. BSEE will 
protect proprietary information according to the Freedom of Information 
Act (5 U.S.C. 552), its implementing regulations (43 CFR 2), 30 CFR 
250.197, Data and information to be made available to the public or for 
limited inspection, and 30 CFR part 252, OCS Oil and Gas Information 
Program.
    As discussed earlier in the preamble, this final rulemaking is a 
revision to various sections of the 30 CFR 250 regulations that will 
amend drilling regulations in subparts D, E, F, and Q. This includes 
requirements that will implement various safety measures that pertain 
to drilling, well-completion, well-workovers, and abandoning/
decommissioning operations. The information collected will ensure 
sufficient redundancy in the BOPs; promote the integrity of the well 
and enhance well-control; and facilitate a culture of safety through 
operational and personnel management. This Final Rule will promote 
human safety and environmental protection.
    Based on comments received from the IFR (1010-AD68), this 
rulemaking adds new regulatory requirements and/or expands requirements 
to those already approved under 30 CFR 250, subparts D, E, F, and Q, as 
explained in the following paragraphs.
    A commenter stated that, where applicable, requirements for 
drilling, well work-overs, completions, abandonment and/or 
decommissioning should be consistent. We agreed with the comment, and 
to be consistent, added new requirements and expanded others in 
subparts D, E, F, and Q.
    For example, in Sec.  250.449(j), when operators submit their test 
procedures for approval, they must now include how they will test each 
ROV. We consider the currently approved burden for this requirement to 
be adequate to include this expanded new information collection (IC) 
because an operator doing due diligence will have already addressed 
this requirement in developing its test procedures; the burden will be 
to submit the procedures to BSEE.
    Also, as a logical outgrowth of the IFR and to respond to the 
comment to make the BOP requirements consistent across various subparts 
of the BSEE regulations, we added the BOP requirements to subpart Q.
    Please note that between the IFR and the Final Rule, as discussed 
previously, the BSEE was created. Upon creation of the new agency, the 
OMB-approved collections of information that related to BSEE were 
transferred from the 1010 to the 1014 numbering system. Also the 
collection of information pertaining to 30 CFR 250, subpart D, came up 
for OMB renewal. As per the PRA process, we revised the estimated 
burdens, per consultations with industry, which included the new 
requirements of the IFR. Therefore, the subpart D collection that was 
submitted to, and approved by, OMB included the hour burdens that 
pertained to the IFR. Accordingly, this analysis only addresses the IC 
burden of the new and/or expanded regulatory requirements imposed by 
this final rule.
    The current regulations on Oil and Gas Drilling Operations and 
associated IC are located in 30 CFR 250, subpart D. The OMB approved 
the IC burden of the current subpart D regulations under control number 
1014-0018 (expiration 10/31/2014). This Final Rule adds additional 
regulatory requirements that pertain to subsea and surface BOPs, well 
casing and cementing, secondary intervention, unplanned disconnects, 
recordkeeping, well-completion, and well plugging (+363 burden hours).
    The current regulations on Oil and Gas Well-Completion Operations 
and associated IC are located in 30 CFR 250, subpart E. The OMB 
approved the IC burden of the current subpart E regulations under 
control number 1014-0004 (expiration 1/31/2014). This Final Rule adds 
new regulatory requirements to this subpart that pertain to subsea and 
surface BOPs, secondary intervention, and well-completions (+311 burden 
hours).
    The current regulations on Oil and Gas Well-Workover Operations and 
associated IC are located in 30 CFR 250, subpart F. The OMB approved 
the IC burden of the current subpart F regulations under control number 
1014-0001 (expiration 1/31/2014). This Final Rule adds new regulatory 
requirements to this subpart that pertain to subsea and surface BOPs, 
secondary intervention, unplanned disconnects, and well-workers (+776 
burden hours).
    The current regulations on Decommissioning Activities and 
associated IC are located in 30 CFR 250,

[[Page 50888]]

subpart Q. The OMB approved the IC burden of the current subpart Q 
regulations under control number 1014-0010 (expiration 12/31/2013). 
This Final Rule adds new regulatory requirements that refer to 
information collection requirements that pertain to subsea and surface 
BOPs, secondary intervention, unplanned disconnects and well workers 
during the abandonment decommissioning process (+3,897 burden hours).
    We note that while Form BSEE-0124, Application for Permit to Modify 
is housed in 30 CFR 250, subpart D (1014-0018), this form is used in 
multiple subparts for multiple purposes. The form is also used in 30 
CFR 250, subparts E, F, P, and Q--Well-Completions, Well-Workovers, 
Sulphur Operations, and for Abandonment/Decommissioning functions. 
While the requirement may be stated as `submit with your APM', the 
paperwork burden to fill out the form is in subpart D, while the actual 
APM submittal of supplementary and supporting documents and/or 
information that pertains to the job function is in the specific 
subpart.
    When this rule becomes effective, BSEE will incorporate the 30 CFR 
250, subparts D, E, F, and Q paperwork burdens into their respective 
primary collections: 1014-0018, 1014-0004, 1014-0001, and 1014-0010 
respectively.
    The following table provides a breakdown of the new burdens.

                                                                      Burden Table
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                           Annual burden
         Citation 30 CFR 250                Reporting & recordkeeping requirement             Hour burden           Average number of          hours
                                                                                                                    annual  responses        (rounded)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Subpart D
--------------------------------------------------------------------------------------------------------------------------------------------------------
410-418; 420(a)(6); 423(b)(3),        Apply for permit to drill APD (Form BSEE-0123)    Burden covered under 1014-0018                                 0
 (c)(3); 449(j), (k)(1); 456(j) plus   that includes any/all supporting documentation/
 various references in subparts A,     evidence [including, but not limited to, test
 B, D, E, H, P, Q.                     results, calculations, pressure integrity,
                                       verifications, procedures, criteria,
                                       qualifications, etc.] and requests for various
                                       approvals required in subpart D (including Sec.
                                        Sec.   250.424, 425, 427, 428, 432, 442(c),
                                       447, 448(c), 451(g), 456(a)(3), (f), 460,
                                       490(c)) and submitted via the form; upon
                                       request, make available to BSEE.
                                                                                       --------------------------------------------------
449(j); 460; 465; 514(d); 515;        Provide revised plans and the additional          Burden covered under 1014-0018                                 0
 517(d)(8-9); 614(d); 615; 617(h)(1-   supporting information required by the cited
 2); 1704(g); 1707(d), (h)(1-2);       regulations [test results, calculations,
 1709; 1712; 1721(h).                  verifications, procedures, criteria,
                                       qualifications, etc.] when you submit an
                                       Application for Permit to Modify (APM) (Form
                                       BSEE-0124) to BSEE for approval.
416(g)(2)...........................  Provide 72 hour advance notice of location of     Burden covered under 1014-0018                                 0
                                       shearing ram tests or inspections; allow BSEE
                                       access to witness testing, inspections and
                                       information verification.
                                                                                       --------------------------------------------------
416(g)(2)...........................  Submit evidence that demonstrates that the        0.25                     700 submittals                      175
                                       Registered Professional Engineer/firm has the
                                       expertise and experience necessary to perform
                                       the verification(s); allow BSEE access to
                                       witness testing; verify info submitted to BSEE.
                                                                                       --------------------------------------------------
420(b)(3)...........................  Submit documentation of two independent barriers  Burden covered under 1014-0018                                 0
                                       after installation with your EOR.
                                                                                       --------------------------------------------------
420(b)(3)...........................  Request approval for alternative options to       0.25                     25 requests                           7
                                       installing barriers.
                                                                                       --------------------------------------------------
423(a)..............................  Request alternative approval for other pressure   Burden covered under 1010-0114                                 0
                                       casing test pressures.
                                                                                       --------------------------------------------------
423(a)..............................  Request and receive approval from BSEE District   0.5                      88 requests                          44
                                       Manager for repair.
                                                                                       --------------------------------------------------
423(b)(3), (c)(4)...................  Document pressure casing test results and make    Burden covered under 1014-0018                                 0
                                       available to BSEE upon request.
                                                                                       --------------------------------------------------
423(c)(5)...........................  Immediately contact BSEE District Manager when    1                        14 notifications                     14
                                       problem corrected due to failed negative
                                       pressure test; submit a description of
                                       corrected action taken; and receive approval
                                       from BSEE District Manager to retest.
423(c)(8)...........................  Submit documentation of successful negative       2                        45 submittals                        90
                                       pressure test in the EOR (Form BSEE-0125).
442(f)(3)...........................  Demonstrate that your secondary control system    5                        1 validation                          5
                                       will function properly.
                                                                                       --------------------------------------------------
446(a)..............................  Document BOP maintenance and inspection           Burden covered under 1014-0018                                 0
                                       procedures used; record results of BOP
                                       inspections and maintenance actions; maintain
                                       records for 2 years or longer if directed by
                                       BSEE; make available to BSEE upon request.
                                                                                       --------------------------------------------------
449(j)(2)...........................  Notify BSEE District Manager at least 72 hours    0.25                     110 notifications                    28
                                       prior to stump/initial test on seafloor.
                                                                                       --------------------------------------------------
449(j)(3) *.........................  Document all ROV intervention function test       Burden covered under 1014-0018                                 0
                                       results including how you test each ROV
                                       functions; make available to BSEE upon request.
456(j)..............................  Request approval from the BSEE District Manager   Burden covered under 1014-0018                                 0
                                       to displace kill-weight fluids to an
                                       underbalanced state; submit detailed written
                                       procedures with your APD/APM.
                                                                                                                ----------------------------------------
    Subtotal D......................  ................................................  .......................  983 responses                       363
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 50889]]

 
                                                                        Subpart E
--------------------------------------------------------------------------------------------------------------------------------------------------------
514(d)..............................  Request approval from the BSEE District Manager   2                        60 requests                         120
                                       to displace kill-weight fluids to an
                                       underbalanced state; submit detailed written
                                       procedures with your APM.
515.................................  Submit a description of your BOP and its          15                       12 submittals                       180
                                       components; schematic drawings; independent
                                       third-party verification and all supporting
                                       information (evidence showing appropriate
                                       licenses, has expertise/experience necessary to
                                       perform required verifications, etc) with your
                                       APM.
515(e)(2)(ii).......................  Allow BSEE access to witness testing,             0.25                     12 notifications                      3
                                       inspections, and information verification.
                                       Notify BSEE District Manager at least 72 hours
                                       prior to shearing ram tests.
                                                                                       --------------------------------------------------
517(d)(8)*..........................  Function test ROV interventions on your subsea    Burden covered under 1014-0004                                 0
                                       BOP stack; document all test results, including
                                       how you test each ROV function; submit
                                       procedures with your APM for BSEE District
                                       Manager approval; make available to BSEE upon
                                       request.
                                                                                       --------------------------------------------------
517(d)(8)(ii).......................  Notify BSEE District Manager at least 72 hours    0.25                     32 notifications                      8
                                       prior to stump/initial test on seafloor.
                                                                                       --------------------------------------------------
517(d)(9)...........................  Document all autoshear and deadman test results   Burden covered under 1014-0004                                 0
                                       and submit test procedures with your APM for
                                       BSEE Manager approval; make available to BSEE
                                       upon request.
517(g)(l)...........................  Document BOP inspection procedures used; record   Burden covered under 1014-0004                                 0
                                       results of BOP inspection actions; maintain
                                       records for 2 years or longer if directed by
                                       BSEE; make available to BSEE upon request.
517(g)(2)...........................  Request alternative method/frequency to inspect   Burden covered under 1010-0114                                 0
                                       a marine riser.
517(h)..............................  Document the procedures used for BOP maintenance/ Burden covered under 1014-0004                                 0
                                       quality management; record results; maintain
                                       records for 2 years or longer if directed by
                                       BSEE; make available to BSEE upon request.
                                                                                                                ----------------------------------------
    Subtotal E......................  ................................................  .......................  116 responses                       311
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Subpart F
--------------------------------------------------------------------------------------------------------------------------------------------------------
614(d)..............................  Request approval from the BSEE District Manager   2                        80 requests                         160
                                       to displace kill-weight fluids to an
                                       underbalanced state; submit detailed written
                                       procedures with your APM.
615.................................  Submit a description of your BOP and its          15                       40 submittals                       600
                                       components; schematic drawings; independent
                                       third-party verification and all supporting
                                       information (evidence showing appropriate
                                       licenses, has expertise/experience necessary to
                                       perform required verifications, etc) with your
                                       APM.
615(e)(2)(ii).......................  Allow BSEE access to witness testing,             0.25                     12 notifications                      5
                                       inspections, and information verification.
                                       Notify BSEE District Manager at least 72 hours
                                       prior to shearing ram tests.
                                                                                       --------------------------------------------------
617(h)(l) *.........................  Document all test results of your ROV             Burden covered under 1014-0001                                 0
                                       intervention functions including how you test
                                       each ROV function; submit test procedures with
                                       your APM for BSEE District Manager approval;
                                       make available to BSEE upon request.
                                                                                       --------------------------------------------------
617(h)(1)(ii).......................  Notify BSEE District Manager at least 72 hours    0.25                     44 notifications                     11
                                       prior to stump/initial test on seafloor.
                                                                                       --------------------------------------------------
617(h)(2) *.........................  Document all autoshear and deadman test results;  Burden covered under 1014-0001                                 0
                                       submit test procedures with your APM for BSEE
                                       District Manager approval; make available to
                                       BSEE upon request.
618(a)(l)...........................  Document the procedures used for BOP              Burden covered under 1014-0001                                 0
                                       inspections; record results; maintain records
                                       for 2 years or longer if directed by BSEE; make
                                       available to BSEE upon request.
618(a)(2)...........................  Request approval to use alternative method to     Burden covered under 1010-0114                                 0
                                       inspect a marine riser.
618(b)..............................  Document the procedures used for BOP              Burden covered under 1014-0001                                 0
                                       maintenance; record results; maintain records
                                       for 2 years or longer if directed by BSEE; make
                                       available to BSEE upon request.
                                                                                       -----------------------------------------------------------------
    Subtotal F......................  ................................................  .......................  176 responses                       776
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Subpart Q
--------------------------------------------------------------------------------------------------------------------------------------------------------
1705................................  Submit a description of your BOP and its          15                       200 submittals                    3,000
                                       components; schematic drawings; independent
                                       third-party verification and all supporting
                                       information (evidence showing appropriate
                                       licenses, has expertise/experience necessary to
                                       perform required verifications, etc) with your
                                       APM.
1705(e)(2)(ii)......................  Allow BSEE access to witness testing,             0.25                     12 submittals                         3
                                       inspections, and information verification.
                                       Notify BSEE District Manager at least 72 hours
                                       prior to shearing ram tests.

[[Page 50890]]

 
1706(a).............................  Request approval of well abandonment operations;  0.25                     200 requests                         50
                                       procedures indicating how the annular preventer
                                       will be utilized and how pressure limitations
                                       will be applied during each mode of pressure
                                       control, with your APM.
1706(f)(4)..........................  Request approval of the BSEE District Manager to  1                        50 requests                          50
                                       conduct operations without downhole check
                                       values; describe procedures/equipment in APM.
1707(a)(2)..........................  Request approval from BSEE District Manager to    0.25                     6 requests                            2
                                       test annular BOP less than 70 percent.
1707(b)(2)..........................  State reason for postponing test in operations    0.25                     30 reasons                            8
                                       logs.
1707(b)(2)..........................  Request approval from BSEE District Manager for   0.25                     5 requests                            2
                                       alternate test frequencies if condition/BOP
                                       warrant.
1707(f).............................  Request alternative method to record test         0.25                     25 requests                           7
                                       pressures.
1707(f).............................  Record test pressures during BOP and coiled       1                        200 records/                        200
                                       tubing on a pressure chart or w/digital                                    certifications
                                       recorder; certify charts are correct.
1707(g).............................  Record or reference in operations log all         0.5                      200 records                         100
                                       pertinent information listed in this
                                       requirement; make all documents pertaining to
                                       BOP tests, actuations and inspections available
                                       for BSEE review at facility for duration of
                                       well abandonment activity; retain all records
                                       for 2 years at a location conveniently
                                       available for the BSEE District Manager.
1707(h)(1)..........................  Submit test procedures with your APM for BSEE     1                        50 submittals                        50
                                       District Manager approval.
1707(h)(1)(ii)......................  Document all ROV intervention test results; make  0.5                      50 records                           25
                                       available to BSEE upon request.
1707(h)(2)(ii)......................  Document all autoshear and deadman function test  0.25                     50 records                           13
                                       results; make available to BSEE upon request.
1708(a), (b)........................  Document BOP inspection and maintenance           1                        25 records                           25
                                       procedures used; record results of BOP
                                       inspections and maintenance actions; maintain
                                       records for 2 years or longer if directed by
                                       BSEE; make available to BSEE upon request.
1708(a).............................  Request alternative method to inspect marine      0.25                     5 requests                            2
                                       risers.
1709................................  Request approval from the BSEE District Manager   2                        80 requests                         160
                                       to displace kill-weight fluids in an unbalanced
                                       state; submit detailed written procedures with
                                       your APM.
                                                                                       --------------------------------------------------
1712(g); 1721(h)....................  Submit with your APM, Registered Professional     Burden covered under 1014-0018                                 0
                                       Engineer certification.
                                                                                       --------------------------------------------------
1712(g)*; 1721(h) *.................  Submit evidence from the Registered Professional  1                        200                                 200
                                       Engineer/firm of the well abandonment design
                                       and procedures; plugs in the annuli meet
                                       requirements of Sec.   250.1715; 2 independent
                                       barriers etc; has the expertise and experience
                                       necessary to perform the verification(s),
                                       submit with the APM.
--------------------------------------------------------------------------------------------------------------------------------------------------------
    Total Q.........................  ................................................  .......................  1,388 responses                   3,897
                                                                                       -----------------------------------------------------------------
        Grand Total.................  ................................................  .......................  2,663 Responses                   5,347
--------------------------------------------------------------------------------------------------------------------------------------------------------

    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. The public may comment, at any time, on the 
accuracy of the IC burden in this rule and may submit any comments to 
the Department of the Interior; Bureau of Safety and Environmental 
Enforcement; Regulations Development Branch; Mail Stop HE-3314; 381 
Elden Street; Herndon, Virginia 20170-4817.

National Environmental Policy Act of 1969

    We have prepared a supplemental environmental assessment to 
determine whether this rule will have a significant impact on the 
quality of the human environment under the National Environmental 
Policy Act of 1969. This rule does not constitute a major Federal 
action significantly affecting the quality of the human environment. A 
detailed statement under the National Environmental Policy Act of 1969 
is not required because we reached a Finding of No Significant Impact 
(FONSI). A copy of the FONSI and Supplemental Environmental Assessment 
can be viewed at www.Regulations.gov (use the keyword/ID ``BSEE-2012-
0002'').

Data Quality Act

    In developing this rulemaking, we did not conduct or use a study, 
experiment, or survey requiring peer review under the Data Quality Act 
(Pub. L. 106-554, app. C Sec.  515, 114 Stat. 2763, 2763A-153-154).

Effects on the Energy Supply (E.O. 13211)

    This rulemaking is a significant rule and is subject to review by 
the Office of Management and Budget under E.O. 12866. This rulemaking 
does have an effect on energy supply, distribution, or use because its 
provisions may delay development of some OCS oil and gas resources. The 
delay stems from the extra drill time and cost imposed on new wells 
which will marginally slow exploration and development operations. We 
estimate an average delay of 1 day and cost of $820 thousand for most 
deepwater wells in the GOM.
    Increased imports or inventory drawdowns should compensate for most 
of the delay or reduction in domestic production. The recurring costs

[[Page 50891]]

imposed on new drilling by this rulemaking are very small (1 percent) 
relative to the cost of drilling an OCS well. In view of the high risk-
reward associated with deepwater exploration in general, we do not 
expect this small regulatory surcharge from this rulemaking to result 
in meaningful reduction in discoveries. Thus, we expect the net change 
in supply associated with this rulemaking will cause only a very slight 
increase in oil and gas prices relative to what they otherwise would 
have been. Normal volatility in both oil and gas market prices 
overshadow these rule-related price effects, so we consider this an 
insignificant effect on energy supply and price.

List of Subjects in 30 CFR Part 250

    Administrative practice and procedure, Continental shelf, 
Incorporation by reference, Oil and gas exploration, Public lands--
mineral resources, Public lands--rights-of-way, Reporting and 
recordkeeping requirements.

    Dated: August 9, 2012.
Ned Farquhar,
Deputy Assistant Secretary--Land and Minerals Management.

    For the reasons stated in the preamble, the Bureau of Safety and 
Environmental Enforcement (BSEE) is amending 30 CFR part 250 as 
follows:

PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER 
CONTINENTAL SHELF

0
1. The authority citation for part 250 continues to read as follows:

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


0
2. In part 250, revise all references to ``glory hole'' to read ``well 
cellar''.

0
3. Amend Sec.  250.125(a), by revising entries (8) and (9) in the table 
to read as follows:


Sec.  250.125  Service fees.

    (a) * * *

------------------------------------------------------------------------
   Service--processing of the
            following                 Fee amount        30 CFR citation
------------------------------------------------------------------------
 
                              * * * * * * *
(8) Application for Permit to     $1,959 for initial  Sec.   250.410(d);
 Drill (APD; Form BSEE-0123).      applications        Sec.
                                   only; no fee for    250.513(b); Sec.
                                   revisions.           250.1617(a).
(9) Application for Permit to     $116..............  Sec.   250.465(b);
 Modify (APM; Form BSEE-0124).                         Sec.
                                                       250.513(b); Sec.
                                                        250.613(b); Sec.
                                                         250.1618(a);
                                                       Sec.
                                                       250.1704(g).
 
                              * * * * * * *
------------------------------------------------------------------------

* * * * *

0
4. Amend Sec.  250.198 by revising paragraphs (a)(3), (h)(63), and 
(h)(78) to read as follows:


Sec.  250.198  Documents incorporated by reference.

    (a) * * *
    (3) The effect of incorporation by reference of a document into the 
regulations in this part is that the incorporated document is a 
requirement. When a section in this part incorporates all of a 
document, you are responsible for complying with the provisions of that 
entire document, except to the extent that the section which 
incorporates the document by reference provides otherwise. When a 
section in this part incorporates part of a document, you are 
responsible for complying with that part of the document as provided in 
that section.
* * * * *
    (h) * * *
    (63) API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells, Third Edition, March 1997; 
reaffirmed September 2004; incorporated by reference at Sec. Sec.  
250.442, 250.446, 250.517, 250.618, and 250.1708,
* * * * *
    (78) API Standard 65--Part 2, Isolating Potential Flow Zones During 
Well Construction; Second Edition, December 2010; incorporated by 
reference at Sec.  250.415(f).
* * * * *

0
5. Amend Sec.  250.415 by revising paragraphs (f) to read as follows:


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

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

0
6. Amend Sec.  250.416 by revising paragraphs (e), (f), and (g) to read 
as follows:


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

* * * * *
    (e) Independent third-party verification and supporting 
documentation that show the blind-shear rams installed in the BOP stack 
are capable of shearing any drill pipe (including workstring and 
tubing) in the hole under maximum anticipated surface pressure. The 
documentation must include actual shearing and subsequent pressure 
integrity test results for the most rigid pipe to be used and 
calculations of shearing capacity of all pipe to be used in the well, 
including correction for MASP;
    (f) When you use a subsea BOP stack or surface BOP stack on a 
floating facility, independent third-party verification that shows:
    (1) The BOP stack is designed for the specific equipment on the rig 
and for the specific well design;
    (2) The BOP stack has not been compromised or damaged from previous 
service;
    (3) The BOP stack will operate in the conditions in which it will 
be used; and
    (g) The qualifications of the independent third-party referenced in 
paragraphs (e) and (f) of this section:
    (1) The independent third-party in this section must be a technical 
classification society, or a licensed professional engineering firm, or 
a registered professional engineer capable of providing the 
verifications required under this part.
    (2) You must:
    (i) Include evidence that the registered professional engineer, or 
a technical classification society, or engineering firm you are using 
or its employees hold appropriate licenses to perform the verification 
in the appropriate jurisdiction, and evidence to demonstrate that the 
individual, society, or firm has the expertise and experience necessary 
to perform the required verifications.

[[Page 50892]]

    (ii) Ensure that an official representative of BSEE will have 
access to the location to witness any testing or inspections, and 
verify information submitted to BSEE. Prior to any shearing ram tests 
or inspections, you must notify the BSEE District Manager at least 72 
hours in advance.

0
7. Amend Sec.  250.418 by revising paragraphs (g) and (i) to read as 
follows:


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

* * * * *
    (g) A request for approval if you plan to wash out below the 
mudline or displace some cement to facilitate casing removal upon well 
abandonment;
* * * * *
    (i) Descriptions of qualifications required by Sec.  250.416(g) of 
the independent third-party; and
* * * * *

0
8. Amend Sec.  250.420 by revising paragraphs (a)(6) and (b)(3) to read 
as follows:


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

* * * * *
    (a) * * *
    (6)(i) Include a certification signed by a registered professional 
engineer that the casing and cementing design is appropriate for the 
purpose for which it is intended under expected wellbore conditions, 
and is sufficient to satisfy the tests and requirements of this section 
and Sec.  250.423. Submit this certification with your APD (Form BSEE-
0123).
    (ii) You must have the registered professional engineer involved in 
the casing and cementing design process.
    (iii) The registered professional engineer must be registered in a 
state of the United States and have sufficient expertise and experience 
to perform the certification.
    (b) * * *
    (3) On all wells that use subsea BOP stacks, you must include two 
independent barriers, including one mechanical barrier, in each annular 
flow path (examples of barriers include, but are not limited to, 
primary cement job and seal assembly). For the final casing string (or 
liner if it is your final string), you must install one mechanical 
barrier in addition to cement to prevent flow in the event of a failure 
in the cement. A dual float valve, by itself, is not considered a 
mechanical barrier. These barriers cannot be modified prior to or 
during completion or abandonment operations. The BSEE District Manager 
may approve alternative options under Sec.  250.141. You must submit 
documentation of this installation to BSEE in the End-of-Operations 
Report (Form BSEE-0125).
* * * * *

0
9. Revise Sec.  250.423 to read as follows:


Sec.  250.423  What are the requirements for pressure testing casing?

    (a) The table in this section describes the minimum test pressures 
for each string of casing. You may not resume drilling or other down-
hole operations until you obtain a satisfactory pressure test. If the 
pressure declines more than 10 percent in a 30-minute test, or if there 
is another indication of a leak, you must investigate the cause and 
receive approval from the appropriate BSEE District Manager for the 
repair to resolve the problem ensuring that the casing will provide a 
proper seal. The BSEE District Manager may approve or require other 
casing test pressures.

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

     (b) You must ensure proper installation of casing in the subsea 
wellhead or liner in the liner hanger.
    (1) You must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon installation of each casing string.
    (2) If you run a liner that has a latching mechanism or lock down 
mechanism, you must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon installation of the liner.
    (3) You must perform a pressure test on the casing seal assembly to 
ensure proper installation of casing or liner. You must perform this 
test for the intermediate and production casing strings or liner.
    (i) You must submit for approval with your APD, test procedures and 
criteria for a successful test.
    (ii) You must document all your test results and make them 
available to BSEE upon request.
    (c) You must perform a negative pressure test on all wells that use 
a subsea BOP stack or wells with mudline suspension systems. The BSEE 
District Manager may require you to perform additional negative 
pressure tests on other casing strings or liners (e.g., intermediate 
casing string or liner) or on wells with a surface BOP stack.
    (1) You must perform a negative pressure test on your final casing 
string or liner.
    (2) You must perform a negative test prior to unlatching the BOP at 
any point in the well. The negative test must be performed on those 
components, at a minimum, that will be exposed to the negative 
differential pressure that will occur when the BOP is disconnected.
    (3) You must submit for approval with your APD, test procedures and 
criteria for a successful test. If any of your test procedures or 
criteria for a successful test change, you must submit for approval the 
changes in a revised APD or APM.
    (4) You must document all your test results and make them available 
to BSEE upon request.
    (5) If you have any indication of a failed negative pressure test, 
such as, but not limited to pressure buildup or observed flow, you must 
immediately investigate the cause. If your investigation confirms that 
a failure occurred during the negative pressure test, you must:
    (i) Correct the problem and immediately contact the appropriate 
BSEE District Manager.
    (ii) Submit a description of the corrective action taken and you 
must receive approval from the appropriate BSEE District Manager for 
the retest.
    (6) You must have two barriers in place, as required in Sec.  
250.420(b)(3), prior to performing the negative pressure test.
    (7) You must include documentation of the successful negative 
pressure test in the End-of-Operations Report (Form BSEE-0125).

0
10. Amend Sec.  250.428 by revising paragraph (c) to read as follows:


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

* * * * *

------------------------------------------------------------------------
     If you encounter the following
            situation . . .                    Then you must . . .
------------------------------------------------------------------------
 
                              * * * * * * *
(c) Have indication of inadequate        (1) Run a temperature survey;
 cement job (such as, but not limited    (2) Run a cement evaluation
 to, lost returns, cement channeling,     log; or
 gas cut mud, or failure of equipment).  (3) Use a combination of these
                                          techniques.

[[Page 50893]]

 
 
                              * * * * * * *
------------------------------------------------------------------------


0
11. Amend Sec.  250.442 by removing paragraph (l) and revising 
paragraphs (a), (e), and (f) to read as follows:


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

* * * * *

------------------------------------------------------------------------
When drilling with a subsea BOP system,
             you must . . .               Additional requirements . . .
------------------------------------------------------------------------
(a) Have at least four remote-           You must have at least one
 controlled, hydraulically operated       annular BOP, two BOPs equipped
 BOPs.                                    with pipe rams, and one BOP
                                          equipped with blind-shear
                                          rams. The blind-shear rams
                                          must be capable of shearing
                                          any drill pipe (including
                                          workstring and tubing) in the
                                          hole under maximum anticipated
                                          surface pressures.
 
                              * * * * * * *
(e) Maintain an ROV and have a trained   The crew must be trained in the
 ROV crew on each drilling rig on a       operation of the ROV. The
 continuous basis once BOP deployment     training must include
 has been initiated from the rig until    simulator training on stabbing
 recovered to the surface. The crew       into an ROV intervention panel
 must examine all ROV related well-       on a subsea BOP stack.
 control equipment (both surface and
 subsea) to ensure that it is properly
 maintained and capable of shutting in
 the well during emergency operations.
(f) Provide autoshear and deadman        (1) Autoshear system means a
 systems for dynamically positioned       safety system that is designed
 rigs.                                    to automatically shut in the
                                          wellbore in the event of a
                                          disconnect of the LMRP. When
                                          the autoshear is armed, a
                                          disconnect of the LMRP closes,
                                          at a minimum, one set of blind-
                                          shear rams. This is considered
                                          a ``rapid discharge'' system.
                                         (2) Deadman System means a
                                          safety system that is designed
                                          to automatically close, at a
                                          minimum, one set of blind-
                                          shear rams in the event of a
                                          simultaneous absence of
                                          hydraulic supply and signal
                                          transmission capacity in both
                                          subsea control pods. This is
                                          considered a ``rapid
                                          discharge'' system.
                                         (3) You may also have an
                                          acoustic system as a secondary
                                          control system. If you intend
                                          to install an acoustic control
                                          system, you must demonstrate
                                          to BSEE as part of the
                                          information submitted under
                                          Sec.   250.416 that the
                                          acoustic system will function
                                          in the proposed environment
                                          and conditions.
 
                              * * * * * * *
------------------------------------------------------------------------


0
12. Amend Sec.  250.443 by revising paragraph (g) to read as follows:


Sec.  250.443  What associated systems and related equipment must all 
BOP systems include?

* * * * *
    (g) A wellhead assembly with a rated working pressure that exceeds 
the maximum anticipated wellhead pressure.

0
13. Amend Sec.  250.446 by revising paragraph (a) to read as follows:


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

    (a) You must maintain and inspect your BOP system to ensure that 
the equipment functions properly. The BOP maintenance and inspections 
must meet or exceed the provisions of Sections 17.10 and 18.10, 
Inspections; Sections 17.11 and 18.11, Maintenance; and Sections 17.12 
and 18.12, Quality Management, described in API RP 53, Recommended 
Practices for Blowout Prevention Equipment Systems for Drilling Wells 
(incorporated by reference as specified in Sec.  250.198). You must 
document how you met or exceeded the provisions of Sections 17.10 and 
18.10, Inspections; Sections 17.11 and 18.11, Maintenance; and Sections 
17.12 and 18.12, Quality Management, described in API RP 53, record the 
results of your BOP inspections and maintenance actions, and make the 
records available to BSEE upon request. You must maintain your records 
on the rig for 2 years from the date the records are created, or for a 
longer period if directed by BSEE;
* * * * *

0
14. Amend Sec.  250.449 by revising paragraphs (b), (j), and (k) to 
read as follows:


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

* * * * *
    (b) Stump test a subsea BOP system before installation. You must 
use water to conduct this test. You may use drilling fluids to conduct 
subsequent tests of a subsea BOP system. You must perform the initial 
subsea BOP test on the seafloor within 30 days of the stump test.
* * * * *
    (j) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. Each ROV must be fully compatible with the BOP 
stack ROV intervention panels. You must also test and verify closure of 
at least one set of rams during the initial test on the seafloor 
through an ROV hot stab. You must submit test procedures, including how 
you will test each ROV intervention function, with your APD or APM for 
BSEE District Manager approval. You must:
    (1) Ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams, one set of 
blind-shear rams, and unlatching the Lower Marine Riser Package (LMRP);
    (2) Notify the appropriate BSEE District Manager a minimum of 72 
hours prior to the stump test and initial test on the seafloor; and

[[Page 50894]]

    (3) Document all your test results and make them available to BSEE 
upon request;
    (k) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system and 
verify closure of at least one set of blind-shear rams during the 
initial test on the seafloor. When you conduct the initial deadman 
system test on the seafloor you must ensure the well is secure and, if 
hydrocarbons have been present, appropriate barriers are in place to 
isolate hydrocarbons from the wellhead. You must also have an ROV on 
bottom during the test.
    (1) You must submit test procedures with your APD or APM for 
District Manager approval. The procedures for these function tests must 
include documentation of the controls and circuitry of the system 
utilized during each test. The procedure must also describe how the ROV 
will be utilized during this operation.
    (2) You must document all your test results and make them available 
to BSEE upon request.

0
15. Amend Sec.  250.451 by adding paragraph (j) to read as follows:


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

* * * * *

------------------------------------------------------------------------
     If you encounter the following
            situation . . .                    Then you must . . .
------------------------------------------------------------------------
 
                              * * * * * * *
(j) Need to remove the BOP stack.......  Have a minimum of two barriers
                                          in place prior to BOP removal.
                                          The BSEE District Manager may
                                          require additional barriers.
------------------------------------------------------------------------


0
16. Amend Sec.  250.456 by revising paragraph (j) to read as follows:


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

* * * * *
    (j) Before you displace kill-weight fluid from the wellbore and/or 
riser to an underbalanced state, you must obtain approval from the BSEE 
District Manager. To obtain approval, you must submit with your APD or 
APM your reasons for displacing the kill-weight fluid and provide 
detailed step-by-step written procedures describing how you will safely 
displace these fluids. The step-by-step displacement procedures must 
address the following:
    (1) Number and type of independent barriers, as described in Sec.  
250.420(b)(3), that are in place for each flow path that requires such 
barriers,
    (2) Tests you will conduct to ensure integrity of independent 
barriers,
    (3) BOP procedures you will use while displacing kill-weight 
fluids, and
    (4) Procedures you will use to monitor the volumes and rates of 
fluids entering and leaving the wellbore; and
* * * * *

0
17. Amend Sec.  250.513 by:
0
a. Redesignating paragraphs (b)(4) through (b)(5) as (b)(5) through 
(b)(6), and
0
b. Adding a new paragraph (b)(4) to read as follows:


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

* * * * *
    (b) * * *
    (4) All applicable information required in Sec.  250.515.
* * * * *

0
18. Amend Sec.  250.514 by adding paragraph (d) to read as follows:


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

* * * * *
    (d) Before you displace kill-weight fluid from the wellbore and/or 
riser to an underbalanced state, you must obtain approval from the BSEE 
District Manager. To obtain approval, you must submit with your APM 
your reasons for displacing the kill-weight fluid and provide detailed 
step-by-step written procedures describing how you will safely displace 
these fluids. The step-by-step displacement procedures must address the 
following:
    (1) Number and type of independent barriers, as described in Sec.  
250.420(b)(3), that are in place for each flow path that requires such 
barriers,
    (2) Tests you will conduct to ensure integrity of independent 
barriers,
    (3) BOP procedures you will use while displacing kill-weight 
fluids, and
    (4) Procedures you will use to monitor the volumes and rates of 
fluids entering and leaving the wellbore.

0
19. Redesignate Sec. Sec.  250.515 through 250.530 as Sec. Sec.  
250.516 through 250.531.

0
20. Add new Sec.  250.515 to read as follows:


Sec.  250.515  What BOP information must I submit?

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

[[Page 50895]]

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

0
21. Amend newly redesignated Sec.  250.517 by revising paragraphs 
(d)(2), (d)(8), (d)(9), (g), and (h) to read as follows:


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

* * * * *
    (d) * * *
    (2) Stump test a subsea BOP system before installation. You must 
use water to conduct this test. You may use drilling or completion 
fluids to conduct subsequent tests of a subsea BOP system. You must 
perform the initial subsea BOP test on the seafloor within 30 days of 
the stump test.
* * * * *
    (8) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. Each ROV must be fully compatible with the BOP 
stack ROV intervention panels. You must also test and verify closure of 
at least one set of rams during the initial test on the seafloor 
through an ROV hot stab. You must submit test procedures, including how 
you will test each ROV function, with your APM for BSEE District 
Manager approval. You must:
    (i) Ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams, one set of 
blind-shear rams, and unlatching the LMRP;
    (ii) Notify the appropriate BSEE District Manager a minimum of 72 
hours prior to the stump test and initial test on the seafloor;
    (iii) Document all your test results and make them available to 
BSEE upon request; and
    (9) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system and 
verify closure of at least one set of blind-shear rams during the 
initial test on the seafloor. When you conduct the initial deadman 
system test on the seafloor you must ensure the well is secure and, if 
hydrocarbons have been present, appropriate barriers are in place to 
isolate hydrocarbons from the wellhead. You must also have an ROV on 
bottom during the test. You must:
    (i) Submit test procedures with your APM for BSEE District Manager 
approval. The procedures for these function tests must include 
documentation of the controls and circuitry of the system utilized 
during each test. The procedure must also describe how the ROV will be 
utilized during this operation.
    (ii) Document all your test results and make them available to BSEE 
upon request.
* * * * *
    (g) BOP inspections. (1) You must inspect your BOP system to ensure 
that the equipment functions properly. The BOP inspections must meet or 
exceed the provisions of Sections 17.10 and 18.10, Inspections, 
described in API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells (incorporated by reference as 
specified in Sec.  250.198). You must document how you met or exceeded 
the provisions of Sections 17.10 and 18.10 described in API RP 53, the 
procedures used, record the results, and make the records available to 
BSEE upon request. You must maintain your records on the rig for 2 
years from the date the records are created, or for a longer period if 
directed by BSEE.
    (2) You must visually inspect your surface BOP system on a daily 
basis. You must visually inspect your subsea BOP system and marine 
riser at least once every 3 days if weather and sea conditions permit. 
You may use television cameras to inspect subsea equipment. The BSEE 
District Manager may approve alternate methods and frequencies to 
inspect a marine riser.
* * * * *
    (h) BOP maintenance. You must maintain your BOP system to ensure 
that the equipment functions properly. The BOP maintenance must meet or 
exceed the provisions of Sections 17.11 and 18.11, Maintenance; and 
Sections 17.12 and 18.12, Quality Management, described in API RP 53, 
Recommended Practices for Blowout Prevention Equipment Systems for 
Drilling Wells (incorporated by reference as specified in Sec.  
250.198). You must document how you met or exceeded the provisions of 
Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, 
Quality Management, described in API RP 53, the procedures used, record 
the results, and make the records available to BSEE upon request. You 
must maintain your records on the rig for 2 years from the date the 
records are created, or for a longer period if directed by BSEE.
* * * * *

0
22. Amend Sec.  250.613 by:
    a. Redesignating paragraphs (b)(3) through (b)(4) as (b)(4) through 
(b)(5), and
    b. Adding a new paragraph (b)(3) to read as follows:


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

* * * * *
    (b) * * *
    (3) All information required in Sec.  250.615.
* * * * *

0
23. Amend Sec.  250.614 by adding new paragraph (d) to read as follows:


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

* * * * *
    (d) Before you displace kill-weight fluid from the wellbore and/or 
riser to an underbalanced state, you must obtain approval from the BSEE 
District Manager. To obtain approval, you must submit with your APM 
your reasons for displacing the kill-weight fluid and provide detailed 
step-by-step written procedures describing how you will safely displace 
these fluids. The step-by-step displacement procedures must address the 
following:
    (1) Number and type of independent barriers, as described in Sec.  
250.420(b)(3), that are in place for each flow path that requires such 
barriers,
    (2) Tests you will conduct to ensure integrity of independent 
barriers,
    (3) BOP procedures you will use while displacing kill weight 
fluids, and
    (4) Procedures you will use to monitor the volumes and rates of 
fluids entering and leaving the wellbore.

0
24. Redesignate Sec. Sec.  250.615 through 250.619 as Sec. Sec.  
250.616 through 250.620.

0
25. Add new Sec.  250.615 to read as follows:


Sec.  250.615  What BOP information must I submit?

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

[[Page 50896]]

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

0
26. Amend newly redesignated Sec.  250.617 by revising paragraph (h) to 
read as follows:


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

* * * * *
    (h) Stump test a subsea BOP system before installation. You must 
use water to conduct this test. You may use drilling or completion 
fluids to conduct subsequent tests of a subsea BOP system. You must 
perform the initial subsea BOP test on the seafloor within 30 days of 
the stump test. You must:
    (1) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. Each ROV must be fully compatible with the BOP 
stack ROV intervention panels. You must also test and verify closure of 
at least one set of rams during the initial test on the seafloor 
through an ROV hot stab. You must submit test procedures, including how 
you will test each ROV function, with your APM for BSEE District 
Manager approval. You must:
    (i) Ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams, one set of 
blind-shear rams, and unlatching the LMRP;
    (ii) Notify the appropriate BSEE District Manager a minimum of 72 
hours prior to the stump test and initial test on the seafloor;
    (iii) Document all your test results and make them available to 
BSEE upon request; and
    (2) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system and 
verify closure of at least one set of blind-shear rams during the 
initial test on the seafloor. When you conduct the initial deadman 
system test on the seafloor you must ensure the well is secure and, if 
hydrocarbons have been present, appropriate barriers are in place to 
isolate hydrocarbons from the wellhead. You must also have an ROV on 
bottom during the test. You must:
    (i) Submit test procedures with your APM for BSEE District Manager 
approval. The procedures for these function tests must include 
documentation of the controls and circuitry of the system utilized 
during each test. The procedure must also describe how the ROV will be 
utilized during this operation.
    (ii) Document the results of each test and make them available to 
BSEE upon request.

0
27. Revise Sec.  250.618 to read as follows:


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

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

0
28. Amend Sec.  250.1500 by revising the definition for ``Well-
control'' to read as follows:


Sec.  250.1500  Definitions

* * * * *
    Well-control means methods used to minimize the potential for the 
well to flow or kick and to maintain control of the well in the event 
of flow or a kick. Well-control applies to drilling, well-completion, 
well-workover, abandonment, and well-servicing operations. It includes 
measures, practices, procedures and equipment, such as fluid flow 
monitoring, to ensure safe and environmentally protective drilling, 
completion, abandonment, and workover operations as well as the 
installation, repair, maintenance, and operation of surface and subsea 
well-control equipment.
* * * * *

0
29. Amend Sec.  250.1704 by revising paragraph (g) to read as follows:


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

* * * * *

[[Page 50897]]



------------------------------------------------------------------------
Decommissioning applications and
             reports                When to submit       Instructions
------------------------------------------------------------------------
 
                              * * * * * * *
(g) Form BSEE-0124, Application   (1) Before you      (i) Include
 for Permit to Modify (APM). The   temporarily         information
 submission of your APM must be    abandon or          required under
 accompanied by payment of the     permanently plug    Sec.  Sec.
 service fee listed in Sec.        a well or zone      250.1712 and
 250.125.                                              250.1721.
                                                      (ii) When using a
                                                       BOP for
                                                       abandonment
                                                       operations
                                                       include
                                                       information
                                                       required under
                                                       Sec.   250.1705.
                                  (2) Within 30 days  Include
                                   after you plug a    information
                                   well.               required under
                                                       Sec.   250.1717.
                                  (3) Before you      Refer to Sec.
                                   install a subsea    250.1722(a).
                                   protective device.
                                  (4) Within 30 days  Include
                                   after you           information
                                   complete a          required under
                                   protective device   Sec.
                                   trawl test          250.1722(d).
                                  (5) Before you      Refer to Sec.
                                   remove any casing   250.1723.
                                   stub or mud line
                                   suspension
                                   equipment and any
                                   subsea protective
                                   device.
                                  (6) Within 30 days  Include
                                   after you           information
                                   complete site       required under
                                   clearance           Sec.
                                   verification        250.1743(a).
                                   activities
------------------------------------------------------------------------


0
30. Add Sec.  250.1705 to read as follows:


Sec.  250.1705  What BOP information must I submit?

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

0
31. Add Sec.  250.1706 to read as follows:


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

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

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

[[Page 50898]]

 
                               (ii) If the expected pressure is greater
                                than 5,000 psi, then you must have at
                                least two sets of pipe rams that are
                                capable of sealing around the larger
                                size drill string.
                               (iii) You may substitute one set of
                                variable bore rams for two sets of pipe
                                rams.
(5) You use a subsea BOP       The requirements in Sec.   250.442(a) of
 stack,                         this part.
------------------------------------------------------------------------

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

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

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

[[Page 50899]]

    (7) All connections used in the surface BOP system from the tree to 
the uppermost required ram must be flanged, including the connections 
between the well-control stack and the first full-opening valve on the 
choke line and the kill line.
    (g) The minimum BOP system components for well abandonment 
operations with the tree in place and performed by moving tubing or 
drill pipe in or out of a well under pressure utilizing equipment 
specifically designed for that purpose, i.e., snubbing operations, must 
include the following:
    (1) One set of pipe rams hydraulically operated, and
    (2) Two sets of stripper-type pipe rams hydraulically operated with 
spacer spool.
    (h) An inside BOP or a spring-loaded, back-pressure safety valve, 
and an essentially full-opening, work-string safety valve in the open 
position must be maintained on the rig floor at all times during well 
abandonment operations when the tree is removed or during well 
abandonment operations with the tree installed and using small tubing 
as the work string. A wrench to fit the work-string safety valve must 
be readily available. Proper connections must be readily available for 
inserting valves in the work string. The full-opening safety valve is 
not required for coiled tubing or snubbing operations.

0
32. Add Sec.  250.1707 to read as follows:


Sec.  250.1707  What are the requirements for blowout preventer system 
testing, records, and drills?

    (a) BOP pressure tests. When you pressure test the BOP system, you 
must conduct a low-pressure test and a high-pressure test for each 
component. You must conduct the low-pressure test before the high-
pressure test. For purposes of this section, BOP system components 
include ram-type BOP's, related control equipment, choke and kill 
lines, and valves, manifolds, strippers, and safety valves. Surface BOP 
systems must be pressure tested with water.
    (1) Low pressure tests. You must successfully test all BOP system 
components to a low pressure between 200 and 300 psi. Any initial 
pressure equal to or greater than 300 psi must be bled back to a 
pressure between 200 and 300 psi before starting the test. If the 
initial pressure exceeds 500 psi, you must bleed back to zero before 
starting the test.
    (2) High pressure tests. You must successfully test all BOP system 
components to the rated working pressure of the BOP equipment, or as 
otherwise approved by the BSEE District Manager. You must successfully 
test the annular-type BOP at 70 percent of its rated working pressure 
or as otherwise approved by the BSEE District Manager.
    (3) Other testing requirements. You must test variable bore pipe 
rams against the largest and smallest sizes of tubulars in use (jointed 
pipe, seamless pipe) in the well.
    (b) You must test the BOP systems at the following times:
    (1) When installed;
    (2) At least every 7 days, alternating between control stations and 
at staggered intervals to allow each crew to operate the equipment. If 
either control system is not functional, further operations must be 
suspended until the nonfunctional system is operable. The test every 7 
days is not required for blind or blind-shear rams. The blind or blind-
shear rams must be tested at least once every 30 days during operation. 
A longer period between blowout preventer tests is allowed when there 
is a stuck pipe or pressure-control operation and remedial efforts are 
being performed. The tests must be conducted as soon as possible and 
before normal operations resume. The reason for postponing testing must 
be entered into the operations log. The BSEE District Manager may 
require alternate test frequencies if conditions or BOP performance 
warrant.
    (3) Following repairs that require disconnecting a pressure seal in 
the assembly, the affected seal will be pressure tested.
    (c) All personnel engaged in well abandonment operations must 
participate in a weekly BOP drill to familiarize crew members with 
appropriate safety measures.
    (d) You may conduct a stump test for the BOP system on location. A 
plan describing the stump test procedures must be included in your 
Application for Permit to Modify, Form BSEE-0124, and must be approved 
by the BSEE District Manager.
    (e) You must test the coiled tubing connector to a low pressure of 
200 to 300 psi, followed by a high pressure test to the rated working 
pressure of the connector or the expected surface pressure, whichever 
is less. You must successfully pressure test the dual check valves to 
the rated working pressure of the connector, the rated working pressure 
of the dual check valve, expected surface pressure, or the collapse 
pressure of the coiled tubing, whichever is less.
    (f) You must record test pressures during BOP and coiled tubing 
tests on a pressure chart, or with a digital recorder, unless otherwise 
approved by the BSEE District Manager. The test interval for each BOP 
system component must be 5 minutes, except for coiled tubing 
operations, which must include a 10 minute high-pressure test for the 
coiled tubing string. Your representative at the facility must certify 
that the charts are correct.
    (g) The time, date, and results of all pressure tests, actuations, 
inspections, and crew drills of the BOP system, system components, and 
marine risers must be recorded in the operations log. The BOP tests 
must be documented in accordance with the following:
    (1) The documentation must indicate the sequential order of BOP and 
auxiliary equipment testing, the pressure, and duration of each test. 
As an alternate, the documentation in the operations log may reference 
a BOP test plan that contains the required information and is retained 
on file at the facility.
    (2) The control station used during the test must be identified in 
the operations log. For a subsea system, the pod used during the test 
must be identified in the operations log.
    (3) Any problems or irregularities observed during BOP and 
auxiliary equipment testing and any actions taken to remedy such 
problems or irregularities, must be noted in the operations log.
    (4) Documentation required to be entered in the operations log may 
instead be referenced in the operations log. You must make all records 
including pressure charts, operations log, and referenced documents 
pertaining to BOP tests, actuations, and inspections, available for 
BSEE review at the facility for the duration of well abandonment 
activity. Following completion of the well abandonment activity, you 
must retain all such records for a period of two years at the facility, 
at the lessee's field office nearest the OCS facility, or at another 
location conveniently available to the BSEE District Manager.
    (h) Stump test a subsea BOP system before installation. You must 
use water to conduct this test. You may use drilling fluids to conduct 
subsequent tests of a subsea BOP system. You must stump test the subsea 
BOP within 30 days of the initial test on the seafloor. You must:
    (1) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. Each ROV must be fully compatible with the BOP 
stack ROV intervention panels. You must also test and verify closure of 
at least one set of rams during the initial test on the seafloor. You 
must submit test procedures, including how you will test each ROV 
function, with your APM for

[[Page 50900]]

BSEE District Manager approval. You must:
    (i) Ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams and one set of 
blind-shear rams and unlatching the LMRP;
    (ii) Document all your test results and make them available to BSEE 
upon request; and
    (2) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system and 
verify closure of at least one set of blind-shear rams during the 
initial test on the seafloor. When you conduct the initial deadman 
system test on the seafloor you must ensure the well is secure and, if 
hydrocarbons have been present, appropriate barriers are in place to 
isolate hydrocarbons from the wellhead. You must also have an ROV on 
bottom during the test. You must:
    (i) Submit test procedures with your APM for BSEE District Manager 
approval. The procedures for these function tests must include 
documentation of the controls and circuitry of the system utilized 
during each test. The procedure must also describe how the ROV will be 
utilized during this operation.
    (ii) Document the results of each test and make them available to 
BSEE upon request.

0
33. Add Sec.  250.1708 to read as follows:


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

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

0
34. Add Sec.  250.1709 to read as follows:


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

    Before you displace kill-weight fluid from the wellbore and/or 
riser to an underbalanced state, you must obtain approval from the BSEE 
District Manager. To obtain approval, you must submit with your APM, 
your reasons for displacing the kill-weight fluid and provide detailed 
step-by-step written procedures describing how you will safely displace 
these fluids. The step-by-step displacement procedures must address the 
following:
    (a) Number and type of independent barriers, as described in Sec.  
250.420(b)(3), that are in place for each flow path that requires such 
barriers,
    (b) Tests you will conduct to ensure integrity of independent 
barriers,
    (c) BOP procedures you will use while displacing kill weight 
fluids, and
    (d) Procedures you will use to monitor the volumes and rates of 
fluids entering and leaving the wellbore.

0
35. Amend Sec.  250.1712 by revising paragraph (g) to read as follows:


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

* * * * *
    (g) Certification by a Registered Professional Engineer of the well 
abandonment design and procedures and that all plugs meet the 
requirements in the table in Sec.  250.1715. In addition to the 
requirements of Sec.  250.1715, the Registered Professional Engineer 
must also certify the design will include two independent barriers, one 
of which must be a mechanical barrier, in the center wellbore as 
described in Sec.  250.420(b)(3). The Registered Professional Engineer 
must be registered in a State of the United States and have sufficient 
expertise and experience to perform the certification. You must submit 
this certification with your APM (Form BSEE-0124).

0
36. Amend Sec.  250.1715 by adding paragraph (a)(11) to read as 
follows:


Sec.  250.1715  How must I permanently plug a well?

    (a) * * *

------------------------------------------------------------------------
           If you have . . .                 Then you must use . . .
------------------------------------------------------------------------
 
                              * * * * * * *
(11) Removed the barriers required in    Two independent barriers, one
 Sec.   250.420(b)(3) for the well to     of which must be a mechanical
 be completed.                            barrier, in the center
                                          wellbore as described in Sec.
                                           250.420(b)(3) once the well
                                          is to be placed in a permanent
                                          or temporary abandonment.
------------------------------------------------------------------------

* * * * *

0
37. Amend Sec.  250.1721 by revising paragraph (h) to read as follows:


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

* * * * *
    (h) Submit certification by a Registered Professional Engineer of 
the well abandonment design and procedures and that all plugs meet the 
requirements of paragraph (b) of this section. In addition to the 
requirements of paragraph (b) of this section, the Registered 
Professional Engineer must also certify the design will include two 
independent barriers, one of which must be a mechanical barrier, in the 
center wellbore as described in Sec.  250.420(b)(3). The Registered 
Professional Engineer must be registered in a State of the United 
States and have sufficient expertise and experience to perform the 
certification. You must submit this certification with your APM

[[Page 50901]]

(Form BSEE-0124) required by Sec.  250.1712 of this part.

[FR Doc. 2012-20090 Filed 8-16-12; 4:15 pm]
BILLING CODE 4310-VH-P