[Federal Register Volume 81, Number 83 (Friday, April 29, 2016)]
[Rules and Regulations]
[Pages 25888-26038]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-08921]
[[Page 25887]]
Vol. 81
Friday,
No. 83
April 29, 2016
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 Sulfur Operations in the Outer Continental Shelf--
Blowout Preventer Systems and Well Control; Final Rule
Federal Register / Vol. 81 , No. 83 / Friday, April 29, 2016 / Rules
and Regulations
[[Page 25888]]
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DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental Enforcement
30 CFR Part 250
[Docket ID: BSEE-2015-0002; 15XE1700DX EEEE500000 EX1SF0000.DAQ000]
RIN 1014-AA11
Oil and Gas and Sulfur Operations in the Outer Continental
Shelf--Blowout Preventer Systems and Well Control
AGENCY: Bureau of Safety and Environmental Enforcement, Interior.
ACTION: Final rule.
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SUMMARY: Bureau of Safety and Environmental Enforcement (BSEE) is
finalizing new regulations to consolidate into one part the equipment
and operational requirements that are found in various subparts of
BSEE's regulations pertaining to offshore oil and gas drilling,
completions, workovers, and decommissioning. This final rule focuses on
blowout preventer (BOP) and well-control requirements, including
incorporation of industry standards and revision of existing
regulations, and adopts reforms in the areas of well design, well
control, casing, cementing, real-time well monitoring, and subsea
containment. The final rule also addresses and implements multiple
recommendations resulting from various investigations of the Deepwater
Horizon incident. This final rule will also incorporate guidance from
several Notices to Lessees and Operators (NTLs) and revise provisions
related to drilling, workover, completion, and decommissioning
operations to enhance safety and environmental protection.
DATES: This final rule becomes effective on July 28, 2016. Compliance
with certain provisions of the final rule, however, will be deferred
until the times specified in those provisions and as described in Part
III of the preamble.
The incorporation by reference of certain publications listed in
the rule is approved by the Director of the Federal Register as of July
28, 2016.
FOR FURTHER INFORMATION CONTACT: Kirk Malstrom, Regulations and
Standards Branch, (202) 258-1518, or by email: [email protected].
SUPPLEMENTARY INFORMATION:
List of Acronyms and References
ANSI American National Standards Institute
APA Administrative Procedure Act
APD Application for Permit to Drill
API American Petroleum Institute
APM Application for Permit to Modify
BAST Best Available and Safest Technologies
BAVO BSEE-Approved Verification Organization
BOP Blowout Preventer
BOEM Bureau of Ocean Energy Management
BSEE Bureau of Safety and Environmental Enforcement
BSR Blind Shear Ram
CFR Code of Federal Regulations
CVA Certified Verification Agent
DHS Department of Homeland Security
DOCD Development Operations Coordination Document
DOI Department of the Interior
DPP Development and Production Plan
DWOPs Deepwater Operations Plans
ECD Equivalent Circulating Density
EDS Emergency Disconnect Sequence
E.O. Executive Order
EOR End of Operations Report
EP Exploration Plan
F Fahrenheit
FOIA Freedom of Information Act
FPSs Floating Production Systems
FPSO Floating Production, Storage, and Offloading Unit
FSHR Free Standing Hybrid Risers
GOM Gulf of Mexico
GOMR Gulf of Mexico region
GPS Global Positioning Systems
HPHT High Pressure High Temperature
IC Information Collection
IEC International Electrotechnical Commission
ISO International Organization for Standardization
JIT Joint Investigation Team
LMRP Lower Marine Riser Package
LWC Loss of Well Control
MASP Maximum Anticipated Surface Pressure
MAWHP Maximum Anticipated Wellhead Pressure
MIA Mechanical Integrity Assessment
MMS Minerals Management Service
MODUs Mobile Offshore Drilling Units
NAE National Academy of Engineering
NAICS North American Industry Classification System
NARA National Archives and Records Administration
NAS National Academy of Sciences
National Commission National Commission on the BP Deepwater Horizon
Oil Spill and Offshore Drilling
NIST National Institute of Standards and Technology
NTLs Notices to Lessees and Operators
NTTAA National Technology Transfer and Advancement Act
OCS Outer Continental Shelf
OCSLA Outer Continental Shelf Lands Act
OEM Original Equipment Manufacturer
OFR Office of Federal Register
OIRA Office of Information and Regulatory Affairs
OMB Office of Management and Budget
PEs Professional Engineers
ppg Pounds per gallon
psi Pounds per square inch
QA/QC Quality Assurance/Quality Control
RCD Regional Containment Demonstration
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
RIN Regulation Identifier Number
ROT Remotely Operated Tools
ROV Remotely-Operated Vehicle
RP Recommended Practice
RTM Real-Time Monitoring
SBA Small Business Administration
SBREFA Small Business Regulatory Enforcement Fairness Act of 1996
SCCE Source Control and Containment Equipment
Secretary Secretary of the Interior
SEM Subsea Electronic Module
SEMS Safety and Environmental Management Systems
SIMOPS Simultaneous Operations
Spec. Specification
TAR Technical Assessment and Research
TBT Agreement Technical Barriers to Trade Agreement
TIA Takings Implication Analysis
TLPs Tension Leg Platforms
TVD True Vertical Depth
USCG United States Coast Guard
VBR Variable Bore Ram
VSL Value of a Statistical Life
WAR Well Activity Report
WTO World Trade Organization
Executive Summary
Following the devastating impacts of the April 20, 2010, Deepwater
Horizon incident on the Gulf of Mexico (GOM) and the surrounding states
and local communities, multiple investigations were conducted to
determine the causes of the incident and to make recommendations to
reduce the likelihood of a similar incident in the future. The
investigative groups included:
--Department of the Interior (DOI)/Department of Homeland Security
(DHS) Joint Investigation Team;
--National Commission on the BP Deepwater Horizon Oil Spill and
Offshore Drilling;
--Chief Counsel for the National Commission; and
--National Academy of Engineering.
Each investigation outlined several recommendations to improve
offshore safety. BSEE evaluated the recommendations and acted on a
number of them quickly to improve offshore operations, while BSEE's
decision making with respect to other recommendations followed
additional input from industry and other stakeholders.
In April 2015, BSEE proposed regulations to, among other things,
incorporate industry standards and NTL guidance; consolidate into one
part the existing equipment and operational requirements that are found
in various parts of BSEE's regulations; to revise and improve existing
requirements for well design and control, casing and cementing; and to
add new requirements for real-time monitoring
[[Page 25889]]
(RTM) and subsea containment. The proposed regulations also addressed
many of the recommendations made by the previously listed investigative
bodies, which found a need to incorporate well-control best practices
to advance safety and protection of the environment. BSEE received over
176 public comments on the proposed rule, and considered those comments
in developing these final regulations.
The requirements in this final rule, including the revisions made
to the proposed regulations, reflect BSEE's consideration of the
comments and BSEE's commitment to address the recommendations made in
the Deepwater Horizon reports. This final rulemaking:
(1) Incorporates all or designated portions of the following
industry standards:
--American Petroleum Institute (API) Standard 53, Blowout Prevention
Equipment Systems for Drilling Wells, Fourth Edition, November 2012;
--API Recommended Practice (RP) 2RD--Design of Risers for Floating
Production Systems and Tension-Leg Platforms, First Edition, June 1998;
Reaffirmed May 2006, Errata June 2009;
--API Specification (Spec.) Q1--Specification for Quality Management
System Requirements for Manufacturing Organizations for the Petroleum
and Natural Gas Industry, Eighth Edition, December 2007, Effective
Date: June 15, 2008;
--American National Standards Institute (ANSI)/API Specification
(Spec.) 11D1, Packers and Bridge Plugs Second Edition, Effective Date:
January 1, 2010;
--API RP 17H, Remotely Operated Tools and Interfaces on Subsea
Production Systems, First Edition, July 2004, Reaffirmed: January 2009;
--ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree
Equipment, Nineteenth Edition, July 2004; Effective Date: February 1,
2005;
--ANSI/API Spec. 16A, Specification for Drill-through Equipment, Third
Edition, June 2004;
--API Spec. 16C, Specification for Choke and Kill Systems First
Edition, January 1993;
--API Spec. 16D, Specification for Control Systems for Drilling Well
Control Equipment and Control Systems for Diverter Equipment, Second
Edition, July 2004; and
--ANSI/API Spec. 17D, Design and Operation of Subsea Production
Systems--Subsea Wellhead and Tree Equipment, Second Edition; May 2011.
(2) Revises the requirements for Deepwater Operations Plans
(DWOPs), which are required to be submitted to BSEE under specific
circumstances, to add requirements on free standing hybrid risers
(FSHR) for use with floating production, storage, and offloading units
(FPSO).
(3) Revises 30 CFR part 250, subpart D, Oil and Gas Drilling
Operations, to include requirements for:
--Safe drilling margins;
--Wellhead descriptions;
--Casing or liner centralization during cementing; and
--Source control and containment.
(4) Revises subparts E, Oil and Gas Well-Completion Operations, and
F, Oil and Gas Well-Workover Operations, to include requirements for:
--Packer and bridge plug design; and
--Production packer setting depth.
(5) Revises Subpart Q, Decommissioning Activities, to include
requirements for:
--Packer and bridge plug design;
--Casing bridge plugs; and
--Decommissioning applications and reports.
(6) Adds new subpart G, Well Operations and Equipment, and moves
existing requirements that were duplicated in subparts D, E, F, and Q
into new subpart G including:
--Rig and equipment movement reports;
--RTM; and
--Revised BOP requirements; including:
--Design and manufacture/quality assurance;
--Accumulator system capabilities and calculations;
--BOP and remotely operated vehicle (ROV) capabilities;
--BOP functions (e.g., shearing);
--Improved and consistent testing frequencies;
--Maintenance;
--Inspections;
--Failure reporting;
--Third-party verification; and
--Additional submittals to BSEE, including up-to-date schematics.
(7) Incorporates the guidance from several NTLs into subpart G for:
--Global Positioning Systems (GPS) for Mobile Offshore Drilling Units
(MODUs);
--Ocean Current Monitoring;
--Using Alternate Compliance in Safety Systems for Subsea Production
Operations;
--Standard Reporting Period for the Well Activity Report (WAR); and
--Information to include in the WARs and End of Operations Reports
(EOR).
Based on BSEE's economic analysis of available data, this final
rule will be cost-beneficial. The estimated overall cost of the rule
(outside those costs that are part of the economic baseline) over 10
years will be exceeded by the time-savings benefits to the industry
resulting from the revisions to the former requirements for BOP
pressure testing frequency for workovers and decommissionings. In
addition, the final rule will also produce benefits to society, both
quantifiable and unquantifiable, by reducing the probability of well
control incidents involving oil spills.
Table of Contents
I. Background
A. BSEE
B. BSEE Statutory and Regulatory Authority and Responsibilities
C. Purpose and Summary of the Rulemaking
D. Availability of Incorporated Documents for Public Viewing
E. Summary of Documents Incorporated by Reference
II. Organization of Subpart G
III. Discussion of Compliance Dates for the Final Rule
IV. Issues Not Considered in this Rulemaking
V. Discussion of Final Rule Requirements
A. Summary of Key Regulatory Provisions
B. Summary of Significant Differences Between the Proposed and
Final Rules
1. Safe drilling margin
2. Accumulator systems
3. BOP 5-year major inspection
4. Real-time monitoring (RTM)
5. Potential increased severing capability
6. BOP pressure testing interval
C. Other Differences Between the Proposed and Final Rules
VI. Discussion of Public Comments on the Proposed Rule
A. Requests for Extension of the Proposed Rule Comment Period
B. Summary of General Comments on the Proposed Rule
1. Comments supporting the proposed rule
2. Legal comments
3. Arctic-related comments
4. General comments
5. Contractor/Operator/Manufacturer responsibilities
6. Economic analysis comments
7. Clarification of maximum anticipated surface pressure (MASP)
C. Section-By-Section Summary and Responses to Significant
Comments on the Proposed Rule
VII. Derivation Tables
VIII. Procedural Matters
Regulatory Planning and Review (Executive Orders (E.O.) 12866
and 13563))
Regulatory Flexibility Act
Small Business Regulatory Enforcement Fairness Act
Unfunded Mandates Reform Act of 1995
Takings Implication Assessment (E.O. 12630)
Federalism (E.O. 13132)
Civil Justice Reform (E.O. 12988)
Consultation With Indian Tribes (E.O. 13175)
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Paperwork Reduction Act (PRA) of 1995
National Environmental Policy Act of 1969 (NEPA)
Data Quality Act
Effects on the Nation's Energy Supply (E.O. 13211)
I. Background
A. BSEE
BSEE was established on October 1, 2011, as part of a major
restructuring of DOI's offshore oil and gas regulatory programs to
improve the management and oversight of, and accountability for,
activities on the Outer Continental Shelf (OCS). The Secretary of the
Interior (Secretary) announced the division of responsibilities of the
former Minerals Management Service (MMS) among two new bureaus and one
office within DOI in Secretarial Order No. 3299, issued on May 19,
2010. BSEE, one of the two new bureaus, assumed responsibility for
``safety and environmental enforcement functions including, but not
limited to, the authority to permit activities, inspect, investigate,
summon witnesses and [require production of] evidence[;] levy
penalties; cancel or suspend activities; and oversee safety, response
and removal preparedness.'' (See 76 FR 64431, October 18, 2011).
B. BSEE Statutory and Regulatory Authority and Responsibilities
BSEE derives its authority primarily from the Outer Continental
Shelf Lands Act (OCSLA), 43 U.S.C. 1331-1356a. Congress enacted OCSLA
in 1953, authorizing the Secretary of Interior to lease the OCS for
mineral development, and to regulate oil and gas exploration,
development, and production operations on the OCS. The Secretary has
delegated authority to perform certain of these functions to BSEE.
To carry out its responsibilities, BSEE regulates offshore oil and
gas operations to enhance the safety of offshore exploration and
development of oil and gas on the OCS and to ensure that those
operations protect the environment and implement advancements in
technology. BSEE also conducts onsite inspections to assure compliance
with regulations, lease terms, and approved plans. Detailed information
concerning BSEE's regulations and guidance to the offshore oil and gas
industry may be found on BSEE's website at: http://www.bsee.gov/Regulations-and-Guidance/index.
BSEE's regulatory program covers a wide range of facilities and
activities, including drilling, completion, workover, production,
pipeline, and decommissioning operations. Drilling, completion,
workover, and decommissioning operations are types of well operations
that offshore operators \1\ perform throughout the OCS. These well
operations are the primary focus of this rulemaking.
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\1\ BSEE's regulations at 30 CFR part 20 generally apply to ``a
lessee, the owner or holder of operating rights, a designated
operator or agent of the lessee(s) . . .'' covered by the definition
of ``you'' in Sec. 250.105. For convenience, this preamble will
refer to all of the regulated entities as ``operators'' unless
otherwise indicated.
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C. Purpose and Summary of the Rulemaking
A primary purpose of this rulemaking is to prevent future well-
control incidents, including major incidents like the 2010 Deepwater
Horizon catastrophe. In addition to the loss of 11 lives, that single
event resulted in the release of 134 million gallons of oil, which
spread over 43,300 square miles of the GOM and 1,300 miles of shoreline
in several states. The environmental and other damages caused by the
Deepwater Horizon incident were immense and have had long-lasting and
widespread impacts on the Gulf and the affected states. For example, as
part of a settlement agreement between BP and Federal and state
governments, BP has agreed to pay over $8 billion for natural resources
damages caused by the spill and for the restoration of natural
resources in the Gulf of Mexico region (GOMR).\2\ Those damages include
severe adverse effects on wildlife, wetlands and other wildlife
habitat, recreation and tourism, and commercial fishing. The Deepwater
Horizon Natural Resource Damage Assessment (NRDA) Trustees have
determined that ``the ecological scope of impacts from the Deepwater
Horizon incident was unprecedented, with injuries affecting a wide
array of linked resources across the northern Gulf ecosystem.'' The
released oil ``was toxic to a wide range of organisms, including fish,
invertebrates, plankton, birds, turtles, and mammals . . . [and] caused
a wide array of toxic effects, including death, disease, reduced
growth, impaired reproduction, and physiological impairments that made
it more difficult for organisms to survive and reproduce.'' \3\ In
addition, state and local government economic damage claims arising
from the Deepwater Horizon incident were significant and have been
settled for another $5.9 billion.\4\
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\2\ A summary and details of the recently approved natural
resources damages settlement between BP and Federal and state
governments are available at www.doi.gov/deepwaterhorizon and at
http://www.justice.gov/enrd/deepwater-horizon.
\3\ Deepwater Horizon NRDA Trustees, Final Programmatic Damage
Assessment and Restoration Plan and Final Programmatic Environmental
Impact Statement, at p. 1-14-1-15. On March 22, 2016, the NRDA
Trustees issued a Record of Decision setting forth the basis for the
Trustees' decision to select the comprehensive, integrated ecosystem
restoration alternative (described in Final PDARP/PEIS Sections 5.5
and 5.10). More details regarding the findings of the Federal and
state Deepwater Horizon NRDA Trustees as to natural resources
impacts from the Deepwater Horizon incident may be found at: http://www.gulfspillrestoration.noaa.gov/restoration-planning/gulf-plan/.
\4\ https://www.justice.gov/enrd/deepwater-horizon.
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In addition, despite new regulations and improvements in industry
standards and practices since the Deepwater Horizon incident, which
have resulted in progress in certain areas of safety and environmental
protection, loss of well control (LWC) incidents are happening at about
the same rate five years after that incident as they were before. In
2013 and 2014, there were 8 and 7 LWC incidents per year,
respectively--a rate on par with pre-Deepwater Horizon LWCs.\5\ Some of
these LWC incidents have resulted in blowouts, such as the 2013 Walter
Oil and Gas incident that resulted in an explosion and fire on the rig.
All 44 workers were safely evacuated, but the fire lasted over 72 hours
and the rig was completely destroyed, resulting in a financial loss
approaching $60 million. This incident occurred in part due to the
crew's inability to identify critical well control indicators and to
the failure of critical well control equipment.\6\ Blowouts such as
these can lead to much larger incidents that pose a significant risk to
human life and can cause serious environmental damage.
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\5\ See http://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/Publications_Library/Annual_Report/BSEE%202014%20Annual%20Report.pdf.
\6\ See BSEE, DOI, Investigation of Loss of Well Control and
Fire South Timbalier Area Block 220, Well. No. A-3 OCS-G24980--23
July 2013 (July 2015), at http://www.bsee.gov/uploadedFiles/BSEE/Enforcement/Accidents_and_Incidents/Panel_Investigation_Reports/ST%20220%20Panel%20Report9_8_2015.pdf.
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Ensuring the integrity of the wellbore and maintaining control over
the pressure and fluids during well operations are critical aspects of
protecting worker safety and the environment. The investigations that
followed the Deepwater Horizon incident, in particular, documented gaps
or deficiencies in the OCS regulatory programs and made numerous
recommendations for improvements. Accordingly, on April 17, 2015, BSEE
proposed to consolidate its existing well-control rules into one
subpart of the regulations, and to adopt new and revised regulatory
requirements that address many of those recommendations, including
those related to BOP system design, performance, and reliability. (See
80 FR 21504.)
[[Page 25891]]
Because BOP equipment and systems are critical components of many
well operations, BSEE recognized that it was important to collect the
best ideas on the prevention of well-control incidents and blowouts to
assist in the development of the proposed rule. This included the
knowledge, skillset, and experience possessed by the offshore oil and
gas industry. Accordingly, BSEE participated in meetings, training, and
workshops with industry, standards setting organizations, and other
stakeholders in developing the proposed rule. (See 80 FR 21508-21509.)
The proposed rule discussed in detail topics such as:
Implementing many of the recommendations related to well-
control equipment.
Increasing the performance and reliability of well-control
equipment, especially BOPs.
Improving regulatory oversight over the design,
fabrication, maintenance, inspection, and repair of critical equipment.
Gaining information on leading and lagging indicators of
BOP component failures, identifying trends in those failures, and using
that information to help prevent incidents.
Ensuring that the industry uses recognized engineering
practices, as well as innovative technology and techniques to increase
overall safety.
To help ensure the development of effective regulations, the
proposed rule used a hybrid regulatory approach incorporating
prescriptive requirements, where necessary, as well as many
performance-based requirements. BSEE recognizes the advantages and
disadvantages of both approaches and understands that each approach
could be effective and appropriate for specific circumstances.
A full discussion of these topics, along with other background and
regulatory history, is contained in the notice of proposed rulemaking
(see 80 FR 21504), which may be found on BSEE's website at http://www.bsee.gov/Regulations-and-Guidance/Regulations-In-Development/, and
in the public docket for this rulemaking at: http://www.regulations.gov
(in the Search box, enter BSEE-2015-0002, then click ``search'').
D. Availability of Incorporated Documents for Public Viewing
BSEE frequently uses standards (e.g., codes, specifications, RPs)
developed through a consensus process, facilitated by standards
development organizations and with input from the oil and gas industry,
as a means of establishing requirements for activities on the OCS. BSEE
may incorporate these standards into its regulations without
republishing the standards in their entirety in the Code of Federal
Regulations (CFR), a practice known as incorporation by reference. The
legal effect of incorporation by reference is that the incorporated
standards become regulatory requirements. This incorporated material,
like any other properly issued regulation, has the force and effect of
law, and BSEE holds operators, lessees and other regulated parties
accountable for complying with the documents incorporated by reference
in our regulations. We currently incorporate by reference over 100
consensus standards in BSEE's regulations governing offshore oil and
gas operations (see 30 CFR 250.198).
Federal regulations, at 1 CFR part 51, govern how BSEE and other
Federal agencies incorporate various documents by reference. Agencies
may only incorporate a document by reference by publishing in the
Federal Register the document title, edition, date, author, publisher,
identification number, and other specified information. The Director of
the Federal Register must approve each publication incorporated by
reference in a final rule. Incorporation by reference of a document or
publication is limited to the specific edition cited by the agency in
the final rule and approved by the Director of the Federal Register.
BSEE incorporates by reference in its regulations many oil and gas
industry standards in order to require compliance with those standards
in offshore operations. When a copyrighted publication is incorporated
by reference into BSEE regulations, BSEE is obligated to observe and
protect that copyright. BSEE provides members of the public with
website addresses where these standards may be accessed for viewing--
sometimes for free and sometimes for a fee. Standards development
organizations decide whether to charge a fee. One such organization,
API, provides free online public access to review its key industry
standards, including a broad range of technical standards. These
standards represent almost one-third of all API standards and include
all that are safety-related or are incorporated into Federal
regulations. Several of those standards are incorporated by reference
in this final rule. In addition to the free online availability of
these standards for viewing on API's website, hardcopies and printable
versions are available for purchase from API. The API website address
is: http://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents.\7\
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\7\ To review these standards online, go to the API publications
website at: http://publications.api.org. You must then log-in or
create a new account, accept API's ``Terms and Conditions,'' click
on the ``Browse Documents'' button, and then select the applicable
category (e.g., ``Exploration and Production'') for the standard(s)
you wish to review.
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For the convenience of members of the viewing public who may not
wish to purchase or view these incorporated documents online, they may
be inspected at BSEE's offices, 45600 Woodland Road, Sterling, Virginia
20166; phone: 703-787-1665; or at the National Archives and Records
Administration (NARA). For information on the availability of this
material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal-register/cfr/ibr-locations.html.
E. Summary of Documents Incorporated by Reference
This rulemaking is substantive in terms of the content that is
explicitly stated in the rule text itself, and it also incorporates by
reference certain technical standards and specifications concerning
BOPs and well control. A brief summary of each standard or
specification follows.
API Standard 53--Blowout Prevention Equipment Systems for Drilling
Wells
This standard provides requirements for the installation and
testing of blowout prevention equipment systems whose primary functions
are to confine well fluids to the wellbore, provide means to add fluid
to the wellbore, and allow controlled volumes to be removed from the
wellbore. BOP equipment systems are comprised of a combination of
various components that are covered by this document. Equipment
arrangements are also addressed. The components covered include: BOPs
including installations for surface and subsea BOPs; choke and kill
lines; choke manifolds; control systems; and auxiliary equipment.
This standard also provides new industry best practices related to
the use of dual shear rams, maintenance and testing requirements, and
failure reporting.
Diverters, shut-in devices, and rotating head systems (rotating
control devices) whose primary purpose is to safely divert or direct
flow rather than to confine fluids to the wellbore are not addressed.
Procedures and techniques for well control and extreme temperature
operations are also not included in this standard.
[[Page 25892]]
API RP 2RD--Design of Risers for Floating Production Systems and
Tension-Leg Platforms
This standard addresses structural analysis procedures, design
guidelines, component selection criteria, and typical designs for all
new riser systems used on Floating Production Systems (FPSs) and
Tension-Leg Platforms (TLPs). The presence of riser systems within an
FPS has a direct and often significant effect on the design of all
other major equipment subsystems. This RP includes recommendations on:
(1) Configurations and components; (2) general design considerations
based on environmental and functional requirements; and (3) materials
considerations in riser design.
API Spec. Q1--Specification for Quality Management System Requirements
for Manufacturing Organizations for the Petroleum and Natural Gas
Industry
This specification establishes the minimum quality management
system requirements for organizations that manufacture products or
provide manufacturing-related processes under a product specification
for use in the petroleum and natural gas industry. This standard
requires that equipment be fabricated under a quality management system
that provides for continual improvement, emphasizing defect prevention
and the reduction of variation and waste in the supply chain and from
service providers. The goal of this specification is to increase
equipment reliability through better manufacturing controls.
API Spec. 6A--Specification for Wellhead and Christmas Tree Equipment
This specification defines minimal requirements for the design of
valves, wellheads and Christmas tree equipment that is used during
drilling and production operations. This specification includes
requirements related to dimensional and functional interchangeability,
design, materials, testing, inspection, welding, marking, handling,
storing, shipment, purchasing, repair and remanufacture.
ANSI/API Spec. 11D1--Packers and Bridge Plugs
This specification provides minimum requirements and guidelines for
packers and bridge plugs used downhole in oil and gas operations. The
performance of this equipment is often critical to maintaining control
of a well during drilling or production operations. This specification
provides requirements for the functional specification and technical
specification, including design, design verification and validation,
materials, documentation and data control, repair, shipment, and
storage.
ANSI/API Spec. 16A--Specification for Drill-through Equipment
This specification defines requirements for performance, design,
materials, testing and inspection, welding, marking, handling, storing
and shipping of BOPs and drill-through equipment used for drilling for
oil and gas. It also defines service conditions in terms of pressure,
temperature and wellbore fluids for which the equipment will be
designed. This standard is applicable to, and establishes requirements
for, the following specific equipment: Ram BOPs; ram blocks, packers
and top seals; annular BOPs; annular packing units; hydraulic
connectors; drilling spools; adapters; loose connections; and clamps.
Conformance to this standard is necessary to ensure that this critical
safety equipment has been designed and fabricated in a manner that
ensures reliable performance.
API Spec. 16C--Specification for Choke and Kill Systems
This specification was formulated to provide for safe and
functionally interchangeable surface and subsea choke and kill systems
equipment utilized for drilling oil and gas wells. This equipment is
used during emergencies to circulate out a ``kick'' and, therefore, the
design and fabrication of the components is extremely important. This
document provides the minimum requirements for performance, design,
materials, welding, testing, inspection, storing and shipping.
Equipment specific to and covered by this specification includes:
Actuated valve control lines; articulated choke and kill lines;
drilling choke actuators; drilling choke control lines, exclusive of
BOP control lines; subsurface safety valve control lines; drilling
choke controls; drilling chokes; flexible choke and kill lines; union
connections; rigid choke and kill lines; and swivel unions.
API Spec. 16D--Specification for Control Systems for Drilling Well
Control Equipment and Control Systems for Diverter Equipment
This specification establishes design standards for systems that
are used to control BOPs and associated valves that control well
pressure during drilling operations. Although diverters are not
considered well-control devices, their controls are often incorporated
as part of the BOP control system. Thus, control systems for diverter
equipment are included in the specification. Control systems for
drilling well-control equipment typically employ stored energy in the
form of pressurized hydraulic fluid (power fluid) to operate (open and
close) the BOP stack components. For deepwater operations, subsea
transmission of electric/optical (rather than hydraulic) signals may be
used to shorten response times. The failure of these controls to
perform as designed can result in a major well-control event. As a
result, conformance to this specification is critical to ensuring that
the BOPs and related equipment will operate in an emergency.
ANSI/API Spec. 17D--Design and Operation of Subsea Production Systems--
Subsea Wellhead and Tree Equipment
This standard provides specifications for subsea wellheads, mudline
wellheads, drill-through mudline wellheads, and both vertical and
horizontal subsea trees. These devices are located on the seafloor,
and, therefore, ensuring the safe and reliable performance of this
equipment is extremely important. This document specifies the
associated tooling necessary to handle, test and install the equipment.
It also specifies the areas of design, material, welding, quality
control (including factory acceptance testing), marking, storing and
shipping for both individual sub-assemblies (used to build complete
subsea tree assemblies) and complete subsea tree assemblies.
API RP 17H--Remotely Operated Tools and Interfaces on Subsea Production
Systems
This RP provides general recommendations and overall guidance for
the design and operation of remotely operated tools (ROT) comprising
ROT and ROV tooling used on offshore subsea systems. ROT and ROV
performance is critical to ensuring safe and reliable deepwater
operations and this document provides general performance guidelines
for the equipment.
II. Organization of Subpart G
BSEE's former regulations repeated similar BOP requirements in
multiple locations throughout 30 CFR part 250. In this final rule, BSEE
is consolidating these requirements into subpart G (which previously
had been reserved). The final rule will structure subpart G--Well
Operations and Equipment, under the following undesignated headings:
--GENERAL REQUIREMENTS
[[Page 25893]]
--RIG REQUIREMENTS
--WELL OPERATIONS
--BLOWOUT PREVENTER (BOP) SYSTEM REQUIREMENTS
--RECORDS AND REPORTING
The sections contained within this new subpart will apply to all
drilling, completion, workover, and decommissioning activities on the
OCS, unless explicitly stated otherwise.
III. Discussion of Compliance Dates for the Final Rule
BSEE understands that operators may need time to comply with
certain new requirements in this final rule. Based on information
provided by industry, drilling rigs are now being built, or were built,
pursuant to the same industry standards BSEE is now incorporating by
reference (including API Standard 53), and many have already been
retrofitted to comply with these industry standards. Furthermore, most
drilling rigs already comply with recognized engineering practices and
original equipment manufacturer (OEM) requirements related to repair
and training.
BSEE has considered the public comments on the proposed compliance
dates, as well as relevant information gained during, among other
activities, BSEE's interactions with stakeholders, involvement in
development of industry standards, and evaluation of current
technology. Accordingly, BSEE is setting an effective date of 90 days
following publication of the final rule, by which time operators will
be required to demonstrate compliance with most of the final rule's
provisions. BSEE has determined, however, that it is appropriate to
extend the compliance dates for the following new requirements.
Detailed explanations for these extended compliance dates are provided
in parts V and VI of this document.
--As required in Sec. 250.734(a)(15), operators must install a gas
bleed line with two valves for the annular preventer no later than 2
years from publication of the final rule. BSEE is extending the
timeframe for this requirement based on the current level of
availability of the required equipment and the time needed to install
the equipment. This timeframe was selected to avoid any rig downtime.
--As required by Sec. Sec. 250.733(a)(1) and 250.734(a)(1), operators
must have the capability to shear and seal tubing with exterior control
lines no later than 2 years from the publication of the final rule.
BSEE is aware that some current technology is available to shear tubing
with exterior control lines; however, the effective date has been
extended to allow operators to acquire and install (and, if necessary,
to develop new or alternative) equipment to meet the requirements.
--As required by Sec. Sec. 250.731, 250.732, 250.734, 250.738, and
250.739, operators must begin using a BSEE-approved verification
organization (BAVO) for certain submittals, certifications, and
verifications.\8\ BSEE will develop and make available on its public
website a list of BAVOs, consisting of qualified third-party
organizations that BSEE determines are capable of performing the
functions specified in this final rule, and that will help BSEE ensure
that BOP systems are designed and maintained during their service life
to minimize risk. Industry currently uses independent third-parties to
perform verifications similar to the certifications and verifications
that a BAVO will be required to perform under this final rule. BSEE is
extending the compliance date for the use of BAVOs to no later than 1
year from the date when BSEE publishes the list of BAVOs. BSEE
anticipates that most of the independent third-parties currently used
by industry under the former regulations will become BAVOs,
significantly facilitating compliance with the requirements to use
BAVOs within the one-year timeframe.
---------------------------------------------------------------------------
\8\ For example, Sec. 250.731(c)(2) requires certification and
verifacation that all BOPs are designed and tested to maximun
anticipated condictions.
In the interim, however, final Sec. 250.732(a) requires that
operators use independent third-parties to perform the certifications,
verifications and reports that BAVOs must perform no later than 1 year
after BSEE publishes a BAVO list. This transitional measure is
necessary to ensure that there is no diminution of the safety and
environmental protection currently afforded by the use of independent
third-parties under the existing regulations or of the safety and
environmental improvements anticipated under the new BAVO requirements,
during the time required for BSEE to identify and for operators to use
---------------------------------------------------------------------------
the BAVOs.
--As required in Sec. 250.724, operators must comply with the RTM
requirements no later than 3 years from the publication of the final
rule.
--As required in Sec. 250.734(a)(3), operators are required to have
dedicated subsea accumulator capacity for autoshear and deadman
functions on subsea BOPs within 5 years from the publication of the
final rule. As explained in more detail in part VI.C, changing the
compliance date for these new accumulator requirements--from the
proposed 3 months to the final 5 years from the date of publication--
will allow sufficient lead time for industry to acquire and install
additional accumulator equipment as necessary and will correspond with
the timeframe for compliance with the final dual shear ram
requirements, which is when the additional accumulator capacity will
most likely be needed.
--As required in Sec. 250.734(a)(1), operators must install dual shear
rams on subsea BOPs no later than 5 years from the publication of the
final rule.
--As required in Sec. 250.733(b)(1), surface BOPs installed on
floating facilities 3 years after publication of the final rule must
comply with the BOP requirements of Sec. 250.734(a)(1).
--As required in Sec. 250.734(a)(16), operators must install shear
rams that center drill pipe during shearing operations no later than 7
years from the publication of the final rule.
--As required in Sec. 250.735(g), operators must install remotely-
controlled locks on surface BOP sealing rams no later than 3 years from
publication of the final rule.
--As required in Sec. 250.733(b)(2), for any risers installed 90 days
after the date of the publication of the final rule or later, operators
must use dual bore risers for surface BOPs on floating production
facilities. The final rule does not require that operators change the
riser configuration for risers that were installed on floating
facilities before 90 days after the publication date of the final rule.
--As required in Sec. Sec. 250.732(b)(1)(i) and 250.734(a)(1)(ii), the
BOP must be able to shear electric-, wire-, and slick-line no later
than 2 years after publication of the final rule.
IV. Issues Not Considered in This Rulemaking
BSEE is continuing to review and evaluate additional operational
and equipment issues that are not included in this final rulemaking,
such as:
--Well-control planning, procedures, training, and certification;
--Major rig equipment;
--Certification requirements for personnel servicing critical
equipment;
--Choke and kill systems;
--Mud gas separators;
--Wellbore fluid safety practices, testing, and monitoring;
[[Page 25894]]
--Diverter systems with subsea BOPs; and
--Additional severing requirements.
V. Discussion of Final Rule Requirements
Part V.A, which follows, summarizes and highlights some important
requirements of the final rule that were described in more detail in
the proposed rule. Some of these provisions received no comments during
the public comment period, while other provisions were supported or
criticized by certain commenters. Part V.B addresses significant
relevant comments on certain proposed provisions and summarizes changes
to those provisions that BSEE has made in the final rule based on
consideration of those comments. Part V.C summarizes other changes to
the proposed rule that BSEE has made in the final rule to avoid
ambiguity or confusion, eliminate redundancies, correct minor drafting
errors, or otherwise clarify the meaning of the new requirements.
A. Summary of Key Regulatory Provisions
After review of all the relevant public comments received on the
proposed rule, BSEE determined that the following proposed revisions
will be included in this final rule. Most of the proposed provisions
are included without change, while several of the proposed provisions
have been revised in the final rule in response to comments, as
explained in parts V.B and VI of this document.
Shearing Requirements--
Requires BOP shearing performance testing and results
reporting to a BAVO. This will ensure that shearing capability for
existing equipment complies with BSEE requirements.
Requires compliance with the latest industry standards
contained in API Standard 53.
Requires that operators use two shear rams in subsea BOP
stacks.
Requires the use of BOP technology that provides for
better shearing performance through the centering of the drill pipe in
the shear rams.
Equipment Reliability and Performance--
Requires compliance with industry standards, such as
relevant provisions of API Standard 53, ANSI/API Spec. 6A, ANSI/API
Spec. 16A, API Spec. 16C, API Spec. 16D, ANSI/API Spec. 17D, and API
Spec. Q1. BOP operability will be improved by establishing minimum
design, manufacture, and performance baselines that are essential to
ensure the reliability and performance of this equipment.
Requires inspection, maintenance, and repair of BOP-
related equipment by appropriately trained personnel; this will also
increase the reliability of BOP-related equipment.
Equipment Failure Reporting/Near-Miss Reporting--
Requires that operators share information with Original
Equipment Manufacturers (OEMs) related to the performance of their BOP
system equipment. This sharing of information makes it possible for the
OEMs to notify all users of any safety issues that arise with BOP
system equipment.
Requires that operators report any significant problems
with BOP or well-control equipment to BSEE, so BSEE can determine
whether information should be provided, in a timely manner, to OCS
operators and, if appropriate, to international offshore regulators and
operators.
Safe Drilling Practices--
Requires maintaining safe drilling margins and other
requirements related to liners and other downhole equipment to help
reduce the likelihood of a major well-control event and ensure the
overall integrity of the well design.
Requires monitoring of deepwater and High Pressure High
Temperature (HPHT) drilling operations from the shore and in real-time.
This will allow operators to anticipate and identify issues in a timely
manner and to utilize onshore resources to assist in addressing
critical issues.
Requires daily reports to BSEE concerning any leaks
associated with BOP control systems. This will ensure that the bureau
is made aware of any leaks so it can determine if further action is
appropriate.
Requires compliance with API RP 17H to standardize ROV hot
stab activities. This will allow certain functions of the BOP to be
activated remotely.
BOP Testing--
Requires same pressure testing frequency (at least once
every 14 days) for workover and decommissioning operations as for
drilling and completion operations. Pressure test results will aid in
predicting future performance of a BOP, and harmonizing testing
frequencies for all well operations will also help streamline the BOP
function-testing criteria and reduce the unnecessary repetition every 7
days of testing in workover and decommissioning operations that could
pose operational safety issues.
Requires additional measures (e.g., RTM and increased
maintenance) to help ensure the functionality and operability of the
BOP system that will help reduce the safety and environmental risks.
B. Summary of Significant Differences Between the Proposed and Final
Rules
After consideration of all relevant and significant comments, BSEE
made a number of revisions from the proposed rule in the final rule. We
are highlighting several of these changes here because they are
significant, and because numerous comments addressed these topics. A
discussion of the relevant and significant comments and BSEE's
responses are found in part VI of this document. The significant
revisions made in response to comments include:
1. Safe Drilling Margin--Sec. 250.414(c)
In response to one of the Deepwater Horizon investigation
recommendations--i.e., to better define safe drilling margins--BSEE
proposed to revise the safe drilling margin portion of the drilling
prognosis (i.e., well drilling procedures) required in an Application
for Permit to Drill (APD). Among other things, BSEE proposed that the
``static downhole mud weight must be a minimum of 0.5 pound per gallon
(ppg) below the lesser of the casing shoe pressure integrity test or
the lowest estimated fracture gradient'' (``the 0.5 ppg drilling
margin''). This proposed requirement was typically part of BSEE's
approval parameters during the permitting process. However, many
commenters expressed concerns that strict enforcement of a 0.5 ppg
drilling margin in all circumstances could cause adverse economic
consequences because it could effectively require setting additional
casing strings and smaller hole sizes and thus, in some cases, could
make it impossible to reach target depths. The commenters suggested
various alternatives to the 0.5 ppg requirement, including allowing
operators to use a risk-based approach to setting safe drilling margins
on a case-by-case basis.
Typically, 0.5 ppg is an appropriate safe drilling margin for
normal drilling scenarios and has been approved by BSEE (and thus made
a requirement) in numerous APDs. However, BSEE understands that there
are some well-specific circumstances where a lower drilling margin may
be acceptable to drill a well safely, and BSEE has approved appropriate
alternative downhole mud weights as part of a safe drilling margin in
many APDs. Accordingly, in this final rule, BSEE is keeping the 0.5 ppg
drilling margin as
[[Page 25895]]
proposed to be the default requirement, but is adding a new paragraph
(c)(2) to Sec. 250.414 that expressly allows the use of an alternative
to the 0.5 ppg drilling margin if the operator submits adequate
justification and documentation, including supplemental data (e.g.,
offset well data, analog data, seismic data, risk modeling), in the
APD. This addition is consistent with current BSEE GOMR practice to
allow alternative drilling margins when justified and documented. This
change will also provide operators some assurance that an alternative
drilling margin, other than the 0.5 ppg margin, may be used when
appropriate, while helping BSEE ensure the use of drilling mud with
properties (e.g., density, viscosity, additives) best suited for a
specific well interval and based on well-specific drilling and
geological parameters.\9\ This addition to the safe drilling margin
section will provide increased planning flexibility when drilling into
areas that could require lower safe drilling margins, such as depleted
sands or below salt (both common occurrences in the GOMR), and help
avoid the potential negative consequences of requiring a 0.5 ppg margin
in all cases.
---------------------------------------------------------------------------
\9\ Alternatives to compliance with the 0.5 ppg safe drilling
margin requirement could also be requested under existing Sec.
250.141, and approved by BSEE if the criteria of that section are
satisfied; but such separate requests would not be necessary if an
operator requests an alternative in its APD under new Sec.
250.414(c)(2).
---------------------------------------------------------------------------
BSEE is also making other minor changes to the proposed Sec.
250.414(c). Specifically, as suggested by several commenters, we are
replacing the term ``static downhole mud weight'' with ``equivalent
downhole mud weight,'' and removing the references to Equivalent
Circulating Density (ECD). Several commenters suggested replacing
static downhole mud weight with a more appropriate term to better
define and assess the mud weight because of the difficulty of achieving
and verifying static downhole mud weight during operations. BSEE agrees
with this observation. To verify a static downhole mud weight, the well
would need to be placed in a static situation. This would be done by
turning off the pumps and letting the well sit until it is static;
however, that process can result in complications, such as cuttings and
debris settling out in the bottom of the well and thermal gradients
affecting mud properties. Some of these complications may create
additional issues, such as stuck pipe or loss of wellbore integrity.
The change from ``static'' to ``equivalent'' allows the downhole mud
weight to be based on the mud properties that can be tested at the
surface and then calculated to downhole conditions. Thus, equivalent
downhole mud weight can be verified on the rig as operations are being
conducted.
BSEE also removed the references to ECD from this section based on
comments. For the reasons discussed elsewhere in this preamble (with
regard to Sec. 250.413), BSEE determined that operators do not need to
submit the estimated ECD in the APD permitting process; however, BSEE
expects operators to continue their normal practice of considering ECD
while drilling.
2. Accumulator Systems
In the proposed rule, BSEE proposed a number of significant changes
to existing BOP requirements as well as new requirements for BOPs and
associated systems, including new requirements for subsea and surface
BOP accumulator systems. (See proposed Sec. Sec. 250.734 and 250.735.)
The purpose of the accumulator system and these new requirements is to
ensure that there is sufficient volume and pressure in the accumulator
bottles to properly operate BOP components in a specified timeframe
regardless of the location of the accumulator bottles. Among other
things, we proposed increasing accumulator capacity to operate all BOP
functions; i.e., requiring all surface accumulator systems, whether
associated with surface or subsea BOPs, to meet the requirements for
accumulators servicing surface BOPS under the prior regulations
(including the requirement that the accumulator system provide 1.5
times the volume of fluid capacity necessary to hold closed all BOP
components). We also proposed requiring surface accumulator systems to
operate under MASP conditions, with the blind shear ram being last in
the BOP sequence, and still have enough accumulated pressure to allow
the BOP to shear pipe and seal the well. In addition, we proposed
defining critical functions for BOP operation, and requiring dedicated,
independent accumulator bottles for emergency functions (autoshear/
deadman/emergency disconnect sequence (EDS)).
BSEE received multiple comments on these proposed provisions.
Industry stakeholders raised concerns with (and in some cases suggested
revisions to) the proposed requirements, including the following
concerns:
That the proposed surface and subsea accumulator capacity
requirements are in conflict with API Standard 53 and API Spec. 16D;
That the terminology in the proposed rule and the current
industry standard (API Standard 53) are inconsistent, and that the
different terminology could cause ambiguity and confusion in efforts to
comply with a final rule. Industry commenters recommended using the
terminology used in the API standard; and
That the proposed requirement that accumulator systems be
able to supply pressure to operate all BOP components and shear pipe as
the last step in the BOP sequence, without assistance from a charging
unit, would increase the number of accumulator bottles needed and would
require upgraded accumulator system controls.
The commenters also stated that costs associated with the
additional bottles would be significant and that the extra weight from
additional bottles, given limited deck space availability, could cause
structural issues with the rig.
That the proposed requirements that the subsea accumulator
system be able to supply pressure to operate all critical BOP
components, and that the system have dedicated bottles for each EDS/
autoshear/deadman system(s), would greatly increase the number of
accumulator bottles on the subsea BOP. The commenters stated that the
increased number and weight of accumulator bottles could also cause
structural concerns for the BOP frame and the rig and that costs
associated with the additional bottles would also be significant.
BSEE reviewed all of the relevant comments and has made changes to
the proposed surface and subsea accumulator requirements in the final
rule. In this final rule, BSEE is deleting the ``1.5 times volume
capacity'' requirement for all surface accumulators, and instead
requiring that all accumulator systems (including those servicing
subsea BOPs) meet the sizing specifications of API Standard 53. The
final rule also extends the effective date to comply with the new
accumulator requirements (both surface and subsea) to 5 years; removes
the proposed requirement that the surface accumulator be able to
operate the blind shear ram as the last function in the BOP sequence;
defines ``critical functions;'' and requires dedicated subsea
accumulator bottles for autoshear and deadman (but not EDS) functions
and allows those dedicated bottles to be shared between the autoshear
and deadman functions.
BSEE reevaluated the relevant industry standards and determined
that API Standard 53 and API Spec. 16D provide reasonable and
appropriate methods to ensure proper volumes and pressures of
appropriate BOP components. Changing the proposed
[[Page 25896]]
volume requirements for surface accumulators to meet the specifications
of API Standard 53 will allow for more specific assessments of the
capacity necessary to address unique operating conditions, while still
ensuring that there is enough capacity to operate all specified BOP
components in an emergency. This will significantly reduce the
additional costs identified in industry comments, since it eliminates
the ``1.5 times volume'' requirement that the proposed rule would have
extended to surface accumulators servicing a subsea BOP, and since most
accumulator equipment has been designed to meet the API Standard 53
specifications since that standard was adopted in 2012.
Removing the ``1.5 times volume'' requirement and replacing it with
the volume requirements of API Standard 53 also will not decrease
safety or environmental protection as compared to the proposed
requirement. BSEE determined that the methods for calculating the
necessary fluid volumes and pressures in the API standard provide an
acceptable amount of usable fluid and pressure to operate the required
components, while still ensuring the required 200 pounds per square
inch (psi) above the pre-charge pressure. API Standard 53 also
discusses the need to have 200 psi remaining on the bottles above the
pre-charge pressure after operating the BOP components, which would
provide a sufficient margin of error to promote safety and help prevent
environmental harm from failure of pressure to the BOP.
Removing the proposed language regarding the blind shear ram being
the last in sequence will eliminate industry's misimpression that the
proposed language would have mandated that the blind shear ram always
be the last step in the BOP sequence. In addition, BSEE agrees with the
commenters that the proposed language regarding sequencing of the blind
shear ram is not necessary, as long as the accumulator is able to
provide sufficient volume of fluid to operate all the required BOP
functions under MASP.
BSEE is also making changes in the final rule to the subsea
accumulator requirements in response to comments. BSEE is requiring
subsea accumulators to have enough capacity to provide pressure for
critical functions, as defined in API Standard 53, and to have
accumulator bottles that are dedicated to autoshear and deadman
functions (but not EDS), and that may be shared between those
functions.
Subsea accumulator charge normally comes from the surface, but in
an emergency the connections to the surface may be lost and/or the
accumulator may have already operated multiple BOP components, which
may have reduced the accumulator fluid pressure needed to successfully
shear and seal. Dedicated bottles for autoshear and deadman functions
would ensure that the subsea accumulator has enough pressure available
to operate those emergency systems even if all surface connections are
lost or the volume or pressure in the accumulator system are depleted.
BSEE determined, however, that permitting those functions to share the
dedicated accumulator bottles would not result in a reduction to safety
or environmental protection so long as the shared bottles are capable
of providing enough pressure to operate the emergency functions. By
contrast, dedicated capacity in a subsea accumulator for the EDS is not
necessary, since the EDS is serviced through the main (surface)
accumulator system by rig personnel.
3. BOP 5-Year Major Inspection
In the proposed rule, BSEE included a provision to require a
complete breakdown and inspection of the BOP and every associated
component every 5 years, as documented by a BAVO, which, as proposed,
could not be performed in phased intervals. BSEE received multiple
comments on the 5-year inspection interval. Most industry commenters
did not object to a 5-year inspection requirement for each BOP
component, provided that the inspections could be staggered, or phased,
over time. Commenters expressed concern that requiring all components
to be inspected at one time would put too many rigs out of service,
potentially for long periods of time, with substantial economic
impacts.
Based on consideration of the issues raised in the comments, BSEE
has revised the final rule in order to allow a phased approach for 5-
year inspections (e.g., staggered inspection for each component), as
long as there is proper documentation and tracking to ensure that BSEE
can verify that each applicable BOP component has had the major
inspection within 5 years. BSEE is also adding, for clarification, the
applicable dates for the starting point of the 5-year cycle. BSEE is
confident that these inspection requirements maintain the necessary
level of safety and environmental protection without resulting in
unnecessary interference with scheduling or complications for
operations. Requiring operator documentation of the component
inspection dates, and requiring those records to be available on the
rig, will help BSEE to verify that the components were inspected within
the required timeframe and will also assist BSEE's review of the
documentation, when requested. The final rule requires that all of the
appropriate components be inspected during the 5-year cycle. Proper
documentation of phased inspections will improve BSEE oversight, as
compared to current practice, while a phased approach will avoid the
possibility of long rig shut downs.
4. Real-Time Monitoring
In Sec. 250.724 of the proposed rule, BSEE proposed to require RTM
of certain data for well operations that use either a subsea BOP or a
BOP on a floating facility, or are conducted in an HPHT environment.
Under the proposed rule, the RTM system would have been required to
gather and ``immediately transmit'' data on the BOP control system, the
well's fluid handling systems on the rig, and the well's downhole
conditions with the bottom hole assembly tools (if any) to an onshore
facility to be monitored by qualified personnel in ``continuous
contact'' with rig personnel during operations. In addition, BSEE
proposed that, after transmission, the RTM data must be preserved and
stored at a designated location, identified in an APD or APM, and that
the location and RTM data be made available to BSEE upon request.
Finally, the proposed rule would have required immediate notification
to the appropriate BSEE District Manager of any loss of RTM capability
during operations and would have authorized the District Manager to
require other measures pending restoration of RTM capabilities.
BSEE intends for industry to use RTM as a tool (i.e., as an
``additional pair of eyes'') to improve safety and environmental
protection during ongoing well operations, as recommended by several
reports on the Deepwater Horizon incident. See 80 FR 21520. BSEE does
not intend that onshore personnel monitoring the RTM data would have
operational control over the rig based on the data; rather, BSEE
intends that onshore personnel could use RTM data to help rig personnel
conduct their operations safely and to assist rig personnel in
identifying and evaluating abnormalities and unusual conditions before
they become critical issues. In addition, BSEE expects operators to
review stored RTM data after operations are complete in order to
improve well-control efficiency, training, and incident
[[Page 25897]]
investigation. Reviewing past data can help improve operations (e.g.,
understanding well conditions in certain geological formations assists
in the collection and use of offset well data to make drilling in
similar formations more efficient).
There are many other aspects of RTM that were not addressed in the
proposed rule, and that are not addressed in this final rule. In this
rulemaking, BSEE is laying the groundwork for further development and
use of RTM to help industry to continue improving offshore safety and
environmental protection. Industry, academia, BSEE and others are
studying and developing new RTM technology and processes, which
continues to evolve. BSEE may consider additional guidance or
regulatory requirements for use of RTM, as appropriate, in later
rulemakings.
BSEE received multiple comments on these issues, expressing
concerns with these proposed provisions and suggesting alternatives. A
more detailed discussion of the RTM comments is found in section part
VI.C of this document. However, some of the industry concerns with the
proposed requirements include:
The meaning of proposed requirements to ``immediately
transmit'' these RTM data and to maintain ``continuous contact''
between onshore personnel and rig personnel;
The proposed requirement that loss of ``any real-time
monitoring capability during operations'' requires immediate
notification of, and possible action by, the District Manager; and
The potential for an increase in rig personnel response
time and a decrease in the accountability of the offshore personnel.
In addition, several commenters suggested that BSEE require
operators to develop specific RTM plans in lieu of some or all of the
proposed requirements, or that the existence of such plans would
justify BSEE eliminating some or all of the proposed RTM requirements,
even if an RTM plan were not expressly required.
BSEE considered all of the relevant comments and made several
revisions and clarifications to the proposed RTM requirements in final
Sec. 250.724. The final rule removes or replaces several provisions
that were perceived by commenters as overly prescriptive with more
flexible, performance-based measures that better reflect BSEE's
intention that operators use RTM as a tool to improve their own ability
to prevent well control incidents while providing BSEE with sufficient
access to RTM information to evaluate system improvements. For example,
instead of requiring an operator to notify the District Manager
immediately of any loss of RTM capabilities, as proposed, the final
rule requires an operator to have an RTM plan that specifies how the
operator will notify BSEE of any significant interruption in monitoring
or RTM communications. The revisions to the final rule also clarify
that BSEE did not intend to require that direct operational
responsibility for well control be shifted from rig personnel to
onshore RTM personnel.
Specifically, the revisions to the proposed requirements, as
reflected in the final rule include the following:
The phrase ``all aspects of'' was deleted from paragraphs
(a)(1), (2), and (3).
The deletion of that phrase provides for a more performance-based
rule, pursuant to which the operator, based upon the particular rig
configuration and situation, would determine the data to be collected.
Further, the deletion of ``all aspects of'' provides more operator
flexibility so as to reduce the probability of an increase in response
time while maintaining the accountability of the offshore personnel.
This revision also clarifies that RTM is intended to be used as a
support tool for the existing rig-based chain of command and is not a
substitute for the competency or well-control responsibilities of the
rig personnel.
The word ``data'' was added to clarify the systems and
tools from which real-time data must be gathered and monitored.
BSEE also made the following revisions and clarifications in final
Sec. 250.724(b):
The phrase ``barring unforeseeable or unpreventable
interruptions in transmission'' was added to address concerns about the
interruption of the transmission of the data.
The word ``immediately'' was deleted with respect to
transferring data to shore, and the phrase ``during operations where
they must be monitored [by qualified personnel] who must be in
continuous contact with rig personnel during operations'' was deleted.
These revisions were made to address concern that mandatory onshore
monitoring would result in an erosion of authority of, or shifting
operational decision making away from, the rig-site personnel. These
revisions also address concerns that mandatory onshore monitoring and
continuous rig-to-shore contact might result in an increase in response
time and a decrease in the accountability of the offshore personnel.
They also clarify BSEE's intent that RTM involving onshore personnel
serve as a support tool for the existing rig-based chain of command.
BSEE also revised and clarified final Sec. 250.724(c) by deleting
the sentences that proposed that operators who lose any RTM capability
during operations covered by the section, you must immediately notify
the District Manager, and that the District Manager may require other
measures until RTM capability is restored.
BSEE replaced the deleted sentences with a performance-based
requirement for operators to have an RTM plan, as suggested by several
industry commenters, that addresses several of the issues that the
proposed rule would have addressed through prescriptive language. For
example, most of the commenters' concerns with proposed paragraph (c)
appear to be based on the assumption that the proposed language would
have required every interruption in RTM capabilities--no matter how
brief or inconsequential--to be reported to the District Manager, and
would have resulted in orders to suspend operations in every case.
However, BSEE did not intend that proposed requirement to apply to
minor or routine interruptions in RTM capabilities that pose no
significant risk to safety or of a LWC. Accordingly, the final rule now
requires operators to have RTM plans that include procedures for
responding to and notifying BSEE of ``significant and/or prolonged
interruptions.'' Thus, BSEE anticipates that the final rule will result
in essentially the same results regarding interruptions that the
proposed rule was intended to achieve, with no loss of safety or
environmental protection as compared to the proposal.
Specifically, the final rule requires that the RTM plan be made
available to BSEE upon request and that the plan include descriptions
of:
RTM technical and operational capabilities;
How the RTM data will be transmitted onshore, how the data
will be labeled and monitored by qualified onshore personnel, and how
the data will be stored onshore;
A description of procedures for providing BSEE access,
upon request, to the RTM data including, if applicable, the location of
any onshore data monitoring or data storage facilities;
Onshore monitoring personnel qualifications;
Methods and procedures for communications between rig and
onshore personnel;
Actions that will be taken in case of loss of RTM
capabilities or rig-to-shore communications; and
A protocol for responding to significant or prolonged
interruptions of
[[Page 25898]]
RTM capabilities or communications, including procedures for notifying
the District Manager of such interruptions.
5. Potential Increased Severing Capability
As discussed in the notice of proposed rulemaking, BSEE proposed a
variety of requirements that would increase the likelihood that a BOP
would be able to sever a drill string in an emergency situation in
order to shut-in the well and prevent a catastrophic blowout. (See 80
FR 21509-21510, 21529.) However, there are a variety of components in
the drill string (e.g., drill collars) that cannot be severed using
currently available technology. (See id. at 21509.) Accordingly, the
notice of proposed rulemaking expressly stated that BSEE was
considering including an additional provision in the final rule that
would require operators to ``install technology that is capable of
severing any components of the drill string (excluding drill bits) . .
. within 10 years from publication of the final rule.'' (See id. at
21529.) BSEE explained that this performance-based requirement would
provide additional protection against potential LWC in an emergency by
requiring installation of new technology that could sever components of
a drill string (e.g., drill collars) that cannot be severed using
current shear rams.
BSEE also explained that it was considering a 10-year timeframe for
compliance with this potential requirement in order to provide time for
manufacturers or operators to develop or select innovative or improved
technologies or equipment to meet the requirement. BSEE then invited
public comments and supporting data on a variety of key technical and
economic questions and issues that would help BSEE decide whether to
include such a requirement in the final rule. (See id. at 21529-21530.)
Only a small number of comments addressed this severing issue.
Several industry commenters opposed the idea or stated that it would be
extremely difficult and expensive to meet, and that even 10 years might
not be long enough to come into compliance. One commenter suggested
that BSEE require that shearable sections be designed into the drill
string (instead of requiring that everything be shearable), and that a
shearable section of the drill string must be across one of the
shearing rams at all times. The same commenter asserted that shearable
drill collars currently exist, but did not provide any additional
technical or economic information supporting that assertion. Another
commenter supported the requirement in general, but suggested that it
should be implemented in less than 10 years. None of the comments,
however, provided adequate relevant technical or economic data or other
information to help BSEE determine whether to include the requirement
in the final rule.
Accordingly, although BSEE still believes that such a severing
requirement could provide important additional controls to prevent
future well-control events and catastrophic blowouts, such as the
Deepwater Horizon incident, BSEE has decided that it needs more time
and more information to make a final decision about whether to adopt
such a severing requirement. Therefore, BSEE will review severing
technology on a periodic basis, with the intention of concluding the
review no later than seven years from the publication of this final
rule. BSEE will conduct a retrospective review of this rule under E.O.
13563, according to DOI's regulatory review plan. If, after obtaining
and considering additional information, BSEE decides to proceed with
adoption of such a regulation, BSEE will propose to do so in a separate
rulemaking document.
6. BOP Pressure Testing Interval
BSEE received a number of comments on proposed Sec. 250.737(a)(2),
which proposed to harmonize the pressure testing interval for BOPs used
in workovers and decommissioning operations (currently 7 days) with the
existing 14-day interval for pressure testing BOPs used in drilling and
completion operations.
In the proposed rule, BSEE explained that increasing the test
interval for workover and decommissioning BOPs from 7 days to 14 days
could decrease wear and tear on those BOPs, and thus increase their
durability and reliability in the long-term and otherwise potentially
improve safety. (See 80 FR 21511.) BSEE also explained that it expected
that BOP equipment meeting the other proposed new requirements would
perform more reliably than previous equipment, thus making 7-day
testing for workover and decommissioning BOPs less crucial. (See id. at
21524.)
In addition, BSEE requested comments on whether the pressure
testing interval for BOPs used in all types of operations should be 7
days, 14 days (as proposed), or 21 days. BSEE also requested comments
on the potential cost implications of each of those intervals. (See id.
at 21511.) In its initial economic analysis for the proposed rule, BSEE
estimated the potential savings from increasing the pressure testing
interval from 7 to 14 days for workover and decommissioning BOPs to be
about $150 million per year, and the potential cost savings that would
result from increasing the testing interval for all BOPs from 14 to 21
days to be approximately $400 million per year.
In response, one commenter suggested that BSEE require more
frequent BOP pressure tests (i.e., every 7 days for all BOPs used in
Arctic OCS operations), and claimed that BSEE had not justified
changing the 7-day testing requirement for workover and decommissioning
BOPs to 14 days. However, most commenters, primarily from industry,
supported increasing the pressure testing interval for workovers and
decommissioning and recommended increasing the testing interval for all
BOPs to 21 days. Commenters cited API Standard 53, which recommends a
21-day BOP test cycle for shear ram BOPs, as well as international
industry best practices, in support of longer pressure test intervals.
Multiple commenters also pointed out that less frequent testing would
mitigate wear and tear on the equipment from the testing itself, and
that wear and tear adversely affects long-term reliability of the
equipment and thus increases the risks of equipment failure. Some
commenters also referred to past joint industry research projects and
studies, which they suggested support test intervals longer than 14
days.
BSEE has long been involved with joint industry projects and
studies on BOP reliability and, after reviewing the comments on the
proposed rule, has concluded that increasing the test interval for
workover and decommissioning BOPs from 7 to 14 days is appropriate in
terms of decreasing wear and tear and increasing long-term reliability
of those BOPs. BSEE and the industry now have substantial experience
with the efficacy of the longstanding 14-day testing requirement for
BOPs used in drilling and completion operations, and BSEE believes that
testing decommissioning and workover BOPs every 14 days will avoid the
extra wear and tear and safety risks inherent in 7-day testing and will
not result in any diminution of safety and environmental protection as
compared to 7-day testing.
BSEE is not aware, however, of any new data that justifies
increasing the BOP pressure testing interval for all BOPs from 14 days
to 21 days. The previous studies and data on BOP testing frequency that
were submitted to MMS prior to the Deepwater Horizon incident, as
mentioned by some
[[Page 25899]]
commenters, were not deemed by MMS sufficient to justify increasing the
pressure testing interval from 14 to 21 days. In the proposed rule,
BSEE explained that it was reevaluating this issue and requested
additional data and technical analysis regarding the proposed pressure
testing frequency requirements to determine if a uniform 21-day testing
interval should be included in the final rule. Given the operational
issues that had previously been brought to BSEE's attention by the
industry, and the potential costs savings ($400 million dollars per
year) that BSEE estimated could result from moving from 14-day to 21-
day testing, BSEE anticipated that significant technical and economic
comments would be submitted on this issue. Comments in support of such
a change were submitted; however, these comments did not provide
adequate data and information to reasonably support a 21-day testing
interval at this time.
BSEE is aware of concerns that the more frequently BOPs are tested,
the more likely the equipment is to wear out prematurely; however, it
does not automatically follow that every extension of test intervals
always increases reliability, and thus safety and environmental
protection, in the long-term. The industry commenters do not dispute
that testing must occur at appropriate intervals to provide assurance
that BOPs will function as intended when needed to prevent a blowout.
BSEE's experience with 14-day pressure testing for drilling and
completion BOPs indicates that it is effective for its purpose and
that, in the absence of significant new information on longer test
intervals, it is appropriate to retain that interval for such BOPs and
to apply the same requirement to workover and decommissioning BOPs.
BSEE believes that the provisions in the final rule that increase
the exchange of data on equipment reliability, that improve the design,
manufacturing, maintenance and repair of BOP equipment, and that
require the use of BAVOs or other independent third-parties to verify
and document BOP testing, repairs and maintenance will result in
improved performance and reliability of BOPs in the future. However, in
the absence of new data demonstrating that 21-day testing would be as
protective as 14-day testing, BSEE has decided to finalize the proposed
14-day pressure testing requirement for BOPs used in all types of
operations. In response to the Deepwater Horizon incident, industry
attempted to voluntarily improve the overall reliability of well
control equipment through better designs, improved manufacturing
processes, better maintenance and repair procedures, and increased data
sharing. BSEE will consider the possibility of adopting 21-day BOP
testing when it receives adequate new (post-Deepwater Horizon) data and
analyses demonstrating that BOP reliability and capability, and
personnel safety, are not adversely affected (or are actually improved)
by pressure testing at 21-day intervals. This could include, for
example, data from BOP testing and usage in OCS or other waters. BSEE
will consider relevant data, along with any data indicating that the
other requirements contained in this rule (such as BAVO verification),
have increased overall BOP performance and reliability and decreased
the risk of failure of the systems and components. In the meantime, any
operator that believes its specific circumstances warrant a longer
pressure test interval may seek approval from the District Manager to
use alternate procedures or equipment under Sec. 250.141.
C. Other Differences Between the Proposed and Final Rules
In addition to the significant changes discussed in the preceding
section, BSEE has also made changes to the rule in response to comments
suggesting that BSEE eliminate redundancy, clarify some potentially
confusing language, streamline the regulatory text, and align certain
provisions in the proposed regulatory text more closely with relevant
terminology in API Standard 53 (where BSEE intended the proposed
provisions to be consistent with that standard). In some cases, we
agreed with and accepted specific wording changes suggested by the
commenters, and in some cases we made changes based on our agreement
with the commenters' basic suggestion, even though the commenter
provided no specific alternative language or we did not agree with the
specific wording suggested by the commenter. In still other cases, we
made minor revisions to proposed provisions in order to correct
grammatical errors, eliminate potential ambiguity, or to avoid
confusion by further clarifying the intent of the proposed language.
The revisions include the following:
In final Sec. 250.292, we clarified the proposed language
about pipeline free standing hybrid risers ``on a permanent
installation.''
In final Sec. 250.421, we clarified the proposed language
regarding cementing the liner lap and what actions are necessary when
an operator is unable to meet the cementing requirements of the liner
lap section.
In final Sec. 250.462, we revised the language from
``pressure holding'' to ``pressure containing'' critical components. We
also clarified language on excluding downhole safety valves. And we
clarified the equipment that operators must make available to BSEE for
inspection. We revised this section to clarify the differences between
collocated equipment and SCCE (e.g., collocated equipment includes
dispersant injection equipment.)
In final Sec. Sec. 250.518, 250.619, and 250.1703, we
clarified that, for the purposes of those sections, permanently
installed packers and bridge plugs must comply with the referenced
industry standard.
In final Sec. 250.703, we replaced ``the most extreme
service conditions'' with ``the maximum environmental and operational
conditions'' to which equipment may be exposed at a given well.
In final Sec. 250.711, we clarified that the same well-
control drill cannot be repeated consecutively with the same crew, in
order to avoid overly narrow training for certain personnel and to
improve proficiency in well-control procedures by a broader set of rig
personnel without unduly limiting the operator's discretion to schedule
important drills.
In final Sec. 250.712, we changed the timeframe for
informing BSEE of the rig movement from 72 hours to 24 hours' notice
before movement. BSEE agreed with commenters that requiring 72 hour
notice may have necessitated additional revisions to the submitted form
due to the constant changes of operations affecting rig movements.
Requiring a 24 hour notification provides a better indication of when a
rig will move.
In final Sec. 250.713, we deleted the reference to ``lift
boats'' and made other minor changes to improve consistency in rig-
related terminology.
In final Sec. 250.715, we also revised the language to
provide more consistency in rig-related terminology and to clarify the
requirements for access to GPS data.
In final Sec. 250.721, we clarified that operators must
test the liner-top, instead of the liner-lap, and that the pressure
testing of the entire well should not exceed 70 percent of the burst
rating limit of the weakest component.
In final Sec. 250.722, we clarified that calculations
must be included if an imaging tool or caliper is used.
In final Sec. 250.730, we:
[cir] Clarified that the lessee or operator must ensure that the
BOP systems are designed, installed, maintained, inspected, tested and
used properly (instead of the lessee or operator
[[Page 25900]]
actually performing these actions themselves), since these actions are
usually performed by contractors.
[cir] Clarified that the working pressure rating for annulars does
not need to exceed MASP.
[cir] Clarified that the BOP system (instead of each ram) must be
capable of closing and sealing the wellbore at all times and provide
reliable means to handle well-control events.
[cir] Clarified paragraph (a)(2) to provide that the BOP systems
must meet the provisions of the specified industry standards that apply
to BOP systems.
[cir] Revised the failure reporting procedures in paragraph (c) to
include submitting such reports to BSEE.
[cir] Clarified paragraph (d)(1) to remove the reference to the
alternative compliance regulations at Sec. 250.141.
In final Sec. 250.732, we:
[cir] Revised paragraph (a) by extending the compliance date for
BAVO-related requirements to 1 year from the date BSEE publishes a BAVO
list and adding new paragraphs (a)(1) and (2). Final paragraph (a)(1)
provides that, until the requirements to use BAVOs become effective,
operators must use an independent third-party to provide the
certifications, verifications, and reports that a BAVO must provide
after the BAVO requirements become effective. Final paragraph (a)(2)
clarifies the criteria for independent third-parties, based on the
longstanding criteria in use under current regulations.
[cir] Revised paragraph (b)(1)(vi), by replacing ``all testing
results'' with ``relevant testing results.''
[cir] Revised paragraph (d)(6) to clarify that training for
personnel who service, repair or maintain BOPs must cover ``any
applicable'' OEM requirements.
In final Sec. 250.733, we removed redundant requirements
that are covered in other sections.
In final Sec. 250.734, we:
[cir] Revised the ROV provisions to require opening and closing of
ram locks, one pipe ram, and the Lower Marine Riser Package (LMRP)
disconnect.
[cir] Clarified that the ROV crew must be capable of carrying out
appropriate tasks during emergency operations.
[cir] Simplified paragraph (a)(6)(vi) by deleting a phrase that
would have required a failsafe system to use ``logic'' that makes every
step independent from the previous step, and inserting instead the
words ``once activated.''
[cir] Clarified in paragraph (a)(7), that if an operator chooses to
``use'' an acoustic control system there are applicable requirements to
demonstrate that it will function in the proposed environment and
conditions.
[cir] Clarified that control panels must have ``enable'' buttons or
similar features to ensure two-handed operation.
[cir] Clarified that there must be a side outlet installed below
the lowest sealing shear ram.
[cir] Clarified that, if there are dual annulars, a gas bleed line
must be installed below the upper annular.
[cir] Revised the language regarding testing of the equipment after
making repairs, and clarified the testing requirements under certain
circumstances.
In final Sec. 250.735, we revised paragraph (e), to
clarify the required location of the kill line, and paragraph (g) to
eliminate the proposed requirement for hydraulically operated locks for
pipe rams on surface BOPs and to replace the proposed requirement for
hydraulic locks on surface BOP blind shear rams with a requirement for
remotely-operated locks.
In final Sec. 250.736, we revised the kelly valve
requirements to better reflect current practice and technology.
In final Sec. 250.737, we:
[cir] Clarified, in paragraph (d)(2), that water must be used to do
the initial test for surface BOP systems, but that drilling/completion/
workover fluids may be used to conduct subsequent tests.
[cir] Clarified the requirements for testing pods between control
stations.
[cir] Removed redundant provisions covered under other sections.
In final Sec. 250.738, we:
[cir] Revised paragraph (a) by removing the requirement to notify
the District Manager of problems or irregularities ``including leaks'';
however, these problems or irregularities must be recorded on the daily
report, which must be made available to BSEE upon request.
[cir] Revised paragraph (e) to clarify that one set of pipe rams
(instead of two) must be capable of sealing around the smaller size
pipe.
[cir] Revised paragraph (f) to clarify the required testing of the
connections if casing rams or casing shear rams are installed in a
surface BOP stack.
[cir] Revised paragraph (l) to clarify the required testing of the
wellhead/BOP connection if a test ram is to be used.
[cir] Revised paragraph (p) to clarify the requirements that apply
if the bottom hole assembly needs to be positioned across the BOP.
In final Sec. 250.739, we clarified personnel training
and records requirements.
In final Sec. 250.746, we added a reference to digital
recorders, clarified the actions required when there are leaks
associated with a BOP control system, and made minor changes to provide
consistency in rig-related terminology.
In final Sec. Sec. 250.414(k), 250.713(e), 250.714(e),
250.721(d) and (g)(3), 250.722(a)(1), 250.734(a)(7), 250.738(o),
250.740(g), 250.743(c), and 250.744(a), we clarified the purposes for
which District Managers may require additional information, testing, or
other procedures consistent with the purposes of those sections.
VI. Discussion of Public Comments on the Proposed Rule
In response to the proposed rule, BSEE received over 172 sets of
comments from individual entities (e.g., companies, industry
organizations, non-governmental organizations, and private citizens).
Some entities submitted comments multiple times. All relevant comments
are posted at the Federal eRulemaking portal: http://www.regulations.gov. (To access the comments at that website, enter
BSEE-2012-0002 in the Search box.) BSEE reviewed all comments
submitted. Each of the following sections contains a brief summary of
the relevant and significant comments as well as BSEE's responses.
A. Requests for Extension of the Proposed Rule Comment Period
Summary of comments: BSEE received requests from various
stakeholders asking BSEE to extend the comment period on the proposed
rule. The majority of those requests sought extensions of 120 days,
which would have tripled the length of the original 60-day comment
period. BSEE also received a written comment from another stakeholder
urging BSEE not to extend the comment period because the proposed rule
has been in development since the Deepwater Horizon incident, is based
on recommendations resulting from that incident, and represents a
critical regulatory improvement that should be finalized without delay.
Response: BSEE considered those requests and determined
that extending the original 60-day comment period by an additional 30
days provided sufficient additional time for review of and comment on
the proposal without unduly delaying a final rulemaking decision. The
comment extension to the notice of proposed rulemaking was published in
the Federal Register on June 3, 2015. (See 80 FR 31560.)
Summary of comments: Various commenters asserted that even the 90-
day public comment period was inadequate for a rule of this technical
complexity, and that additional time (e.g., 120 days) was needed to
properly
[[Page 25901]]
address the substantial amount of technical content and complexity in
this draft. They suggested that the comment period should be reopened
and/or that BSEE publish a revised proposed rule for comment.
Response: BSEE believes that the 90-day comment period,
which includes the 30-day extension granted by BSEE, was reasonable and
sufficient under the Administrative Procedure Act (APA). The APA
requires that agencies give ``interested persons an opportunity to
participate'' in the rule making process through submission of written
data, views or arguments. (See 5 U.S.C. 553(c).) The APA does not
prescribe the number of days that an agency must allow for written
comments, and an agency's decision on comment period length is
generally deferred to unless it is arbitrary and capricious. (See 5
U.S.C. 706(2).)
B. Summary of General Comments on the Proposed Rule
1. Comments Supporting the Proposed Rule
Summary of comments: Multiple commenters commended the efforts by
BSEE to improve safety and environmental protection and expressed their
support for many of the changes in the proposed rule.
Response: It is BSEE's continued mission to promote
safety, protect the environment, and conserve resources offshore
through vigorous regulatory oversight and enforcement. This final rule
is an important step toward better well control and improved safety and
environmental protection.
2. Legal Comments
Summary of comments: Several commenters claimed that BSEE failed to
incorporate the principles of best available and safest technologies
(BAST) reflected in OCSLA, resulting in requirements that are
arbitrary, not reasonable or practicable, not economically or
technically feasible, less safe, and more obstructive to OCS oil and
gas development, in violation of the OCSLA-mandated balance between
safety and environmental protection and expeditious and orderly
development of OCS resources.
Response: BAST requirements, as set out in OCSLA and its
implementing regulations (see 30 CFR 250.107) are the product of
specific BSEE analyses and determinations. Existing BSEE regulations
and this final rule contain numerous technology requirements, all of
which were adopted through notice and comment rulemaking. The proposed
rule explained the justifications for codifying the technological
requirements in the final rule, many of which were derived from
recommendations based on exhaustive investigations and reports on the
Deepwater Horizon incident, and on input from experts representing
equipment manufacturers, the offshore oil and gas industry, government,
academia, and environmental organizations focused on identifying
appropriate technological standards. BSEE believes that the
requirements in this regulation provide an appropriate level of safety.
BSEE may make a separate determination in the future related to the use
of BAST, pursuant to OCSLA, if supplemental requirements are necessary.
Summary of comments: Several industry commenters claimed that
certain provisions in the rule could render leases uneconomical to
operate, thereby requiring a Takings Implication Analysis (TIA) by BSEE
under Executive Order (E.O) 12360, and potentially amounting to a
breach of contract by DOI.
Response: By their own terms, OCS oil and gas leases
expressly state that they are subject to regulations promulgated after
lease issuance, including the types of regulatory action reflected in
this final rule. Accordingly, the adoption of this final rule is
consistent with lessees' rights to conduct operations on the OCS--which
are derived entirely from their lease interests--and thus do not amount
to a breach of contract or a taking under the Fifth Amendment. As a
result, a TIA is not necessary.
E.O. 12630 requires executive agencies to review agency actions,
including rulemakings, that have takings implications (i.e., actions
that, if implemented, could effect a taking) to prevent unnecessary
takings and to identify and discuss any significant takings
implications and the agency's conclusions on the takings issues. In
this case, the terms of all OCS oil and gas leases allow BSEE to
promulgate new rules, pursuant to OCSLA, without violating the rights
created by the lease contracts. Specifically, leases issued prior to
2010 state:
This lease is issued pursuant to the Outer Continental Shelf
Lands Act. . . . The lease is issued subject to the Act; all
regulations issued pursuant to the Act and in existence upon the
Effective Date of this lease; all regulations issued pursuant to the
statute in the future which provide for the prevention of waste and
conservation of the natural resources of the Outer Continental Shelf
and the protection of correlative rights therein, and all other
applicable statutes and regulations.
Leases issued since 2010 likewise provide that:
This lease is subject to [OCSLA], regulations promulgated
pursuant thereto, . . . and those . . . regulations promulgated
thereafter, except to the extent they explicitly conflict with an
express provision of this lease. It is expressly understood that
amendments to existing . . . regulations . . . as well as the . . .
promulgation of new regulations, which do not explicitly conflict
with an express provision of this lease may be made and that the
Lessee bears the risk that such may increase or decrease the
Lessee's obligations under the Lease.
None of the provisions of this rule explicitly conflict with any
express provisions of OCS oil and gas leases.
The Supreme Court and other Federal courts have interpreted the
relevant lease language to mean that ``[a] change to an OCSLA
regulation does not breach the express terms of the lease language.''
Century Exploration New Orleans, LLC v. United States, 745 F.3d 1168,
1178 (Fed. Cir. 2014), citing Mobil Oil Exploration & Production
Southeast, Inc. v. United States, 530 U.S. 604, 616 (2000); Century
Exploration New Orleans, LLC v. United States, 110 Fed. Cl. 148, 164-66
(2013) (the lease language ``allocates the risk of certain legal
changes--future regulations issued pursuant to OCSLA--to [lessees]'').
This conclusion is in no way dependent upon the impacts of such a
rulemaking on the economics of lease development.
The express language of the leases (in sections 10 and 12) likewise
requires that the lessee comply with all applicable regulations, and
OCSLA expressly provides that regulations promulgated pursuant to the
statute apply to both new and existing leases as of their effective
date. 43 U.S.C. 1334(a). Because all changes to the regulatory language
implemented through this rule are made pursuant to OCSLA, they are
expressly incorporated into the terms of the leases and thus consistent
with lessees' rights thereunder. In light of the fact that the entirety
of lessees' rights to conduct the impacted operations on the OCS are
derived from their leases, regulation that is consistent with those
lease rights likewise cannot amount to an unconstitutional taking of
those lease rights. Accordingly, promulgation of this rule does not
amount to a breach of any lease terms or a taking of any rights derived
from OCS leases.
Summary of comments: Some commenters raised issues concerning the
World Trade Organization's (WTO's) Technical Barriers to Trade
Agreement (TBT Agreement). In particular, the commenters asserted that
purported inconsistencies between the proposed rules and API Standard
53 require
[[Page 25902]]
compliance with notification procedures under the TBT Agreement.
Response: The TBT Agreement seeks to avoid unnecessary
obstacles to international trade, in part by requiring that technical
regulations and conformity assessment procedures be consistent with
international standards promulgated by international standards
developing organizations.
The proposed rule does not create a technical barrier to trade
because it is neutral as to the national origin of regulated equipment.
The proposed rule did not, and this final rule will not, discriminate
in favor of U.S.-fabricated equipment. The final rule is equally
applicable to all relevant equipment, regardless of the equipment's
country of origin. Accordingly, BSEE's proposed rule did not, and the
final rule does not, create an unnecessary technical barrier to trade.
3. Arctic-Related Comments
Summary of comments: Multiple commenters recommended extending
certain equipment, testing and monitoring requirements in the proposed
rule to all operations on the Arctic OCS, where some of those
operations would not have been covered under the terms of the proposed
requirements. For example, some commenters recommended that BSEE
require a second set of blind shear rams to be installed in the BOP
stack for all operations in the Arctic, including surface BOPs on
gravel and ice islands and bottom-founded structures in the Arctic,
even though the proposed requirement was only intended to apply to
surface BOPs on floating facilities (See Sec. 250.733(b)(1)).
Commenters also suggested that all BOPs used on the Arctic OCS
undergo independent verification by a qualified third-party
organization, and that Arctic operators submit to BSEE an annual
Mechanical Integrity Assessment (MIA) Report prepared by a BAVO, even
though BSEE proposed that the MIA Report requirement apply only to
subsea BOPs, BOPs in HPHT environments, and surface BOPs on floating
facilities. The commenters asserted that extending these requirements
would ensure that each BOP used on the Arctic OCS is fit for Arctic OCS
service. Commenters also suggested extending to all Arctic OCS
facilities: the proposed requirements in Sec. 250.724 for RTM for
subsea BOPs, BOPs in HPHT environments, and surface BOPs on floating
facilities; and the proposed Source Control and Containment
requirements in proposed Sec. 250.462 for subsea BOPs or surface BOPs
on floating facilities.
Some commenters also requested that BSEE revise the existing
regulations to strengthen equipment and operational requirements for
equipment used on the Arctic OCS. These suggestions included: Requiring
Arctic operators to submit a cementing protocol and quality assurance
plan, prepared by an experienced Arctic drilling engineer, as part of
their APD; daily well activity reporting requirements for the Arctic
OCS; and mandatory use of cement evaluation tools and temperature logs.
Some of the comments were expressly related to provisions in BSEE's
proposed rule, ``Requirements for Exploratory Drilling on the Arctic
Outer Continental Shelf.'' (See 80 FR 9916 (Feb. 24, 2015).) The
commenters stated that they submitted the same comments to BSEE in
response to that proposed rule.
Response: The requirements in this final rule apply to any
OCS facility in any BSEE region (GOM, Pacific, Alaska), including an
Arctic OCS facility, that meets the general conditions for
applicability stated in the specific regulatory provisions. For
example, some provisions (such as Sec. 250.730--What are the general
requirements for BOP systems and system components?) apply nationwide
to all BOPs on all OCS facilities, including any facility with a BOP on
the Arctic OCS. Other requirements apply only to specific types of
facilities or equipment or BOP systems (such as the requirements in
Sec. 250.733, which apply only to surface BOP stacks, and the
requirements in Sec. 250.734, which apply only to subsea BOPs). And
some provisions apply to any facility or BOP that meets specific
conditions, such as Sec. 250.732(d), which requires an operator to
submit an annual MIA report for any subsea BOP, BOP in an HPHT
environment, or surface BOP on a floating facility. In any case, all of
the provisions in this final rule apply without regard to the OCS
region in which the facility or BOP is operating.
BSEE recognizes that the Arctic OCS presents a uniquely challenging
operating environment, characterized by extreme environmental
conditions, geographic remoteness, and a relative lack of fixed
infrastructure and existing operations. However, many of the comments
submitted on the Arctic OCS issues are outside the scope of this well-
control rulemaking. BSEE has decided to address Arctic-specific issues
in separate rulemakings, guidance documents, or on a case-by-case basis
as needed. Most of the comments related to the Arctic that were
submitted under this rulemaking were also submitted in response to the
proposed Arctic OCS exploratory drilling rule proposed in February 2015
and will be considered by BSEE in that rulemaking.
4. General Comments
a. ``Grandfathering'' of Certain Equipment Requirements
Summary of comment: Multiple commenters asserted that it is not
clear whether existing facilities will be ``grandfathered in,'' (i.e.,
that the final requirements would apply only to new facilities or
equipment installed after the final rule's effective date), or whether
existing facilities will have to comply with all provisions of the
final rule, even if that requires, for example, installing new
equipment or retrofitting existing equipment, which the commenters
claimed would be very expensive and burdensome.
Similarly, some commenters asserted that it is not clear whether
existing equipment already under construction or in fabrication will
have to comply with the new regulations in the event that the new
regulations are published or become effective during or after
fabrication, but prior to startup of new facilities or actual
installation of the equipment. The commenters asserted that, under this
interpretation, compliance may not be possible to achieve without
significant delay and associated costs.
A commenter stressed that application of manufacturing
specifications (e.g., API Spec. 16A, Spec. 16C, and Spec. 16D),
incorporated by reference in certain provisions of this rule, to
existing equipment would effectively preclude the use of such
equipment. The commenter also claimed that BSEE had not considered the
cost of application of those standards in the initial economic analysis
for the proposed rule.
Response: During the rulemaking process, BSEE makes a
determination about how or whether new and revised regulations will
apply to existing operations, equipment, and facilities during the
rulemaking process. As a general matter, OCSLA provides that all
regulations promulgated thereunder (including this rule) ``shall, as of
their effective date, apply to all operations conducted under a lease
issued or maintained under'' OCSLA. (43 U.S.C. 1334(a).)
When BSEE decides to exempt existing operations, equipment, or
facilities from a specific provision, BSEE makes that clear in the
regulatory text or relevant preamble discussions for the rule. In this
rulemaking, each of the specific requirements for equipment or
facilities will apply to the equipment or facilities that are described
in that
[[Page 25903]]
provision, without regard to whether the facility or equipment already
exists, unless specifically stated otherwise. For example, (as
discussed elsewhere in this document), Sec. 250.733(b)(2) of the final
rule requires use of a dual bore riser configuration on facilities that
plan to use surface BOPs on floating production facilities, if risers
are installed 90 or more days after publication of the final rule
(e.g., at the effective date of the rule). This means that existing
surface BOPS on floating facilities using single bore risers installed
less than 90 days after the publication of the final rule (e.g., before
the effective date of the rule) are not required to be retrofitted with
dual bore risers.
BSEE notes that many of the requirements in this final rule are not
new, but are the same as or very similar to longstanding requirements
in the existing regulations. Thus, those requirements will simply
continue to apply to existing facilities or equipment. In addition,
several of the most significant new requirements in this rule do not
require compliance for several years--or longer in some cases (see part
III of this document)--so the impact of those requirements on existing
facilities or equipment will be substantially mitigated by those
extended compliance periods (e.g., some equipment potentially affected
by some new requirements may already be due for replacement or major
updates by the time such new requirements take effect). If there are
unique circumstances that indicate that use of some equipment or
procedures, other than as specified in this final rule, may be
warranted, an operator may seek approval to use alternate equipment or
procedures under existing Sec. 250.141, if the operator can
demonstrate that such equipment or procedures will provide a level of
safety and environmental protection that equals or surpasses these
requirements.
b. Requests for Additional Workshops
Summary of Comments: Numerous commenters recommended that BSEE hold
additional workshops related to this rulemaking. Most of those
commenters recommended that BSEE postpone finalizing the proposed rule,
reopen the public comment period, and hold workshops during the new
comment period before adopting a final rule. Some commenters, however,
suggested that BSEE hold workshops after adopting the final rule, in
order to further the industry's understanding of the provisions of this
rulemaking. Commenters discussed a number of issues that they asserted
warranted such workshops. One commenter stated that industry concerns
over perceived technical flaws in, and potentially significant impacts
from, the proposed rule, and the limited time provided to comment on
the proposal, warranted workshops or some other form of engagement
between BSEE and industry to make sure that the regulations are
technically viable, provide optimum risk management, and are in the
best interest of America's economy and domestic energy security.
A commenter expressed concerns that the proposed rule, as written,
would not achieve BSEE's actual goals. This commenter suggested that
BSEE should arrange workshops with industry to discuss the meanings of
the proposed rules and revise the rules to improve safety while
reducing unintended consequences.
Response: As previously discussed in this document, BSEE
actively engaged--in meetings, training, workshops and other forums--
with many stakeholders, including industry, for several years prior to
and during development of the proposed rule. In particular, BSEE
convened Federal decision-makers and stakeholders from the OCS
industry, academia, and other entities at a public forum on offshore
energy safety on May 22, 2012, to discuss ways to address well-control
concerns arising from the Deepwater Horizon incident investigations.
Those investigations and the May 2012 forum resulted in numerous
recommendations to enhance safety and environmental protection of
offshore operations by improving well control and BOP performance. BSEE
recognized the importance of collecting the best ideas, from all
perspectives, on the prevention of well-control incidents and blowouts
to assist BSEE in developing this rule. This included industry's
valuable knowledge and skillsets.
BSEE received significant input and specific recommendations from
many industry groups, operators, equipment manufacturers, academics and
environmental organizations as a result of the 2012 forum.
Subsequently, BSEE sought and received additional input on potential
means to improve well control through BSEE attendance at industry and
public conferences, industry standards committee meetings, and BSEE's
own standards workshops. BSEE also invited industry assessments of
BSEE-funded technology research projects related to well control. BSEE
conducted at least 50 meetings with various companies, trade
associations, regulators, and other stakeholders interested in well
control as part of this process.
BSEE considered all of this input in developing the proposed rule
published in April 2015. (See 80 FR 21508-21509.) Subsequently, at the
request of several commenters, including industry commenters, BSEE
extended the comment period for the proposed rule to 90 days, so
commenters would have even more time to develop and present their views
and relevant information.
Subsequently, BSEE received over 170 comments on the proposed rule,
some extremely detailed, covering almost every section of the proposed
rule, and hundreds of which related to specific technical, economic and
other issues. Many of the comments were submitted by members or
representatives of the offshore oil and gas industry, as well as
environmental groups, academics, other Federal agencies, and interested
members of the public. BSEE subject matter experts (including
experienced engineers and economists) carefully considered all of the
relevant and significant comments in developing this final rule. As
discussed elsewhere in this document, BSEE not only responded to those
comments, but made a number of revisions to the final rule to address
concerns or information described in the comments.
In light of all of these efforts, BSEE does not agree with the
commenters that urged BSEE to delay this final rule pending more
workshops. BSEE intends to stay fully engaged with the affected
industry and other stakeholders as this rule is implemented, and
expects to participate in future meetings and workshops where the
issues in this rulemaking will continue to be discussed. As experience
and additional information are gained under this rule, BSEE will both
provide guidance and clarification on this rule, as necessary.
c. Licensed Engineers
Summary of Comments: A commenter recommended that BSEE require the
use of a licensed engineer at every stage during the entire life-cycle
of OCS platforms, including design, development, construction,
commissioning, maintenance, operations and salvage. The commenter noted
that licensed professional engineers (PEs) are required by law to hold
public safety paramount.
Response: BSEE does not agree that the use of PEs should
be required more often than already provided for in this final rule and
the existing regulations. Several provisions of the final rule require
PE certifications. For example, final Sec. 250.428(b) requires
certification by a PE for changes to casing setting depth or hole
interval drilling depth and changes to the well program due to an
inadequate cement job. There are also several provisions in the
existing
[[Page 25904]]
regulations (e.g., Sec. 250.420(a)(6)(i)) that require, or allow, the
use of PEs and that are unchanged by this final rule. In addition, the
requirements in this final rule for verifications and certifications by
a BAVO or other independent third-party will help ensure that the
safety and environmental protection purposes of this rule will be
achieved without the need for additional requirements for use of PEs.
d. Requests for Shorter or Longer Compliance Periods
Summary of Comments: Some commenters observed that the proposed
rule was published more than five years after the Deepwater Horizon
incident. The commenters voiced support for the proposed effective date
of 3 months following publication of the final rule for most of the
proposed rule's requirements, since most, but not all, operators are
already using equipment and procedures consistent with a majority of
the proposed requirements. The commenters expressed concern with the
proposal for longer compliance periods for several key requirements,
including: 3 years for RTM; 5 years for shear rams on subsea BOPs and
on surface BOPs on floating facilities; and 7 years for a mechanism
coupled with each shear ram that centers drill pipe during shearing
operations. One of the commenters noted it could be more than sixteen
years after the Deepwater Horizon incident before BSEE finalizes and
the industry implements critical components of offshore drilling
safety. The commenters urged BSEE to shorten these compliance periods
to enhance safety and environmental protection in an expeditious
manner.
BSEE received other comments on the proposed rule, however, that
raised concerns that the proposed compliance periods for certain
provisions were too short. Those concerns included: Availability of
required equipment; time needed to plan and install the equipment; and
time needed to develop new or alternative equipment to meet the
requirements.
Response: BSEE agrees that it is extremely important to
move ahead with these final rules to implement many of the
recommendations from the Deepwater Horizon investigations and to help
prevent catastrophic events from occurring again. BSEE considered a
number of factors in identifying appropriate compliance periods for the
various provisions in this rule, including information from public
commenters on those requirements and information obtained, among other
activities, from prior interactions with stakeholders, involvement in
development of industry standards, and evaluation of current
technology.
BSEE considered all of the comments regarding shortening and
lengthening the compliance periods and determined that most of the
proposed compliance periods were appropriate. BSEE did, however,
determine that several requirements warranted longer compliance
periods, as discussed in part III of this document. BSEE believes that
compliance with these rules will improve well control, safety and
environmental protection in a timely manner for the near and long term.
5. Contractor/Operator/Manufacturer Responsibilities
Summary of comments: Several commenters expressed uncertainty
regarding potential responsibilities and liabilities of contractors and
individuals performing regulated activities.
Response: These final regulations do not alter BSEE's
existing position and interpretations with respect to the parties
responsible for complying with applicable regulations and related
requirements. The lessee, operator (if one has been designated), and
the person that actually performs an activity (which includes
contractors) to which a particular provision of a regulation, lease,
permit, or plan applies are jointly and severally responsible for
complying with that provision. (See Sec. 250.146(c).) Regulatory
compliance is a fact-specific and context-specific matter, dependent
upon that contractor's actual scope of activities and responsibilities
(which is typically a matter of private contract with the lessee/
operator), and is therefore not susceptible to general
characterization. BSEE's responses to specific issues regarding
responsibilities for compliance follow.
Summary of comments: Some commenters asserted that if contractors
and individuals (along with lessees, operators, et al.) are jointly and
severally responsible for compliance, proposed Sec. 250.107(a)(4)--
requiring lessees, holders of operating rights, designated operators
and certain others to comply with all lease, plan, and permit terms and
conditions--would implicitly require contractors and other individuals
to ascertain all lease, plan, and permit terms and conditions, and
potentially would make the contractor and individuals responsible for
compliance with all such terms and conditions. The commenters asked if
that is what BSEE intended.
Response: Under existing Sec. 250.146(c), the lessee,
operator (if one has been designated), and the person actually
performing an activity (including contractors or individuals) to which
a particular regulation applies are jointly and severally (i.e.,
equally) responsible for complying with that regulation. Therefore,
actual performance of an activity is one of the triggers for the
responsibility to comply with the associated requirements of lease,
permit and plan terms and conditions of approvals. (See, e.g., existing
Sec. 250.101(a).) Accordingly, under final Sec. 250.107(a)(4), any
person who actually performs an activity governed by a lease, permit or
plan term or condition will also be responsible for compliance with
that term or condition.
BSEE expects the person performing such an activity to be familiar
with all terms and conditions relevant and applicable to the activity.
However, contractors and other parties actually performing specific
activities are not responsible for complying with lease, permit or plan
terms or conditions that are outside the scope of activities that they
actually perform. Thus, it is not necessary for such persons
(contractors or individuals) to be familiar with terms or conditions of
the lease, permit or plan that are not associated with activities that
they actually perform.
Summary of comments: Some commenters asked whether, under proposed
Sec. 250.107(e)--regarding BSEE orders to ensure compliance with the
part 250 regulations--BSEE would issue orders to shut-in operations to
the ``lessee, the owner or holder of operating rights, a designated
operator or agent of the lessee(s)'' and any person actually performing
the activity.
Response: BSEE has the legal authority under OCSLA and its
implementing regulations to issue shut-in orders to the lessee,
operator (if one has been designated), and the person (which includes
contractors) actually performing an activity to which a particular
regulation, lease, permit, or plan applies. Regardless of whether BSEE
orders a contractor to shut-in operations, BSEE will typically issue
such an order to the lessee or designated operator in such cases.
Summary of comments: Some commenters asked whether, under proposed
Sec. 250.428(d)--which pertains to certain cementing and casing
situations--reports to the District Manager of immediate actions taken
to ensure the safety of the crew or to prevent a well-control event,
create an obligation for contractors to provide individual reports or
to verify that such reports have been submitted by the operator.
Response: As a general matter, BSEE looks to the
designated operator to make filings on behalf of all lessees and owners
of operating rights. More
[[Page 25905]]
specifically, new Sec. 250.428(d) describes actions a lessee (among
others included in the definition of ``you'' in Sec. 250.105) must
take when remediating inadequate cement jobs. Because existing Sec.
250.146(c) states that when a regulation requires that a lessee take an
action, the person actually performing the activity is also responsible
for complying with that requirement, it follows that the lessees'
reporting duties under Sec. 250.428(d) for immediate action to
remediate inadequate cement jobs could extend to a contractor to the
extent that contractor actually performs the activity.
Summary of comments: Some commenters asked BSEE to clarify who is
ultimately responsible for the determination that a well has been
secured, under proposed Sec. 250.703(c), which requires continuous
surveillance of the rig floor from the beginning of operations until
the well is completed or abandoned unless the well has been secured.
Response: Under Sec. 250.146(c), the lessee, operator (if
one has been designated), and the person actually performing the
activity are jointly and severally responsible for complying with the
regulation. If a contractor actually performs activities associated
with securing a well, that contractor is responsible for complying with
this regulation in performing those activities.
Summary of comments: Some commenters asked if, under proposed Sec.
250.712, which discusses rig movement reporting requirements, BSEE
expects rig movement reports to be made directly by a drilling
contractor and if the drilling contractor will be held responsible for
the report in the absence of reporting by the operator.
Response: Under existing Sec. 250.146(c) and final Sec.
250.712, the lessee, operator (if one has been designated), and the
person (including a contractor) actually performing the activity are
jointly and severally responsible for complying with this rig movement
reporting regulation. However, it does not follow that, even if a
contractor actually moves the rig, the contractor must report the
movement. When parties are jointly and severally responsible to comply
with a requirement, any of the responsible parties could satisfy that
requirement; in general, BSEE would expect the lessee or the operator
to file such a report, although there may be circumstances in which it
would be reasonable and prudent for the contractor who moved the rig to
submit the report. In all cases, at least one of the responsible
parties must fulfill the regulatory requirements.
Summary of comments: Some commenters asked whether, under proposed
Sec. 250.715(f)--which requires lessees, designated operators, holders
of operating rights (and other entities specified in the Sec. 250.105
definition of ``you'') to allow BSEE real-time access to MODU or jack-
up location data--BSEE expects that a drilling contractor will directly
provide BSEE with access to rig location data, and whether the drilling
contractor will be held responsible for providing such access only in
the absence of any action by the operator.
Response: Final Sec. 250.715(f) requires lessees,
designated operators, holders of operating rights (and other entities
specified in the existing Sec. 250.105 definition of ``you'') to allow
BSEE real-time access to MODU or jack-up location data. Under existing
Sec. 250.146(c) however, the lessee, operator (if one has been
designated), and the person actually performing the activity (including
a contractor) required by Sec. 250.715(f) are jointly and severally
responsible for providing BSEE with access to rig location data.
Summary of comments: A commenter asked whether, under proposed
Sec. 250.720 (securing of wells), a contractor would bear a residual
responsibility/liability for downhole integrity of the well or the
effectiveness of the well plugs.
Response: Final Sec. 250.720 specifies a number of well
security procedures that must be followed before moving off the well.
Some of those procedures are substantive and require physical activity
(such as installing two independent barriers) and some are
administrative (e.g., seeking approval by the BSEE District Manager for
installation of independent barriers). In some cases, certain
activities under Sec. 250.720 may be performed by a contractor or
another person acting on behalf of the lessee or operator. In
accordance with Sec. 250.146(c), the lessee, designated operator, and
the person actually performing any activity related to securing a well
under Sec. 250.720 are jointly and severally responsible for complying
with the requirements of that section. It is not possible, however, to
specify in advance how multi-party responsibility for compliance (and
liability for noncompliance) with Sec. 250.720 would be apportioned
among lessees, operators, or other persons (including contractors) who
perform any of the actions required by Sec. 250.720 because
responsibility would necessarily depend on fact-specific circumstances
associated with each case. BSEE notes, however, that Sec. 250.720 does
not expressly require the installation of plugs or address the issue of
``residual responsibility'' for long-term integrity of the well;
rather, it requires the installation of two independent barriers and
approval by the District Manager of those barriers or of alternative
procedures for securing the well if it is not possible to install the
barriers.
Summary of comments: Some commenters asked whether there is an
implicit requirement under proposed Sec. 250.724, regarding RTM, for
contractors or individuals who perform any of the actions required by
Sec. 250.724 to: Maintain duplicate records; and ascertain if the
required real-time data gathering, monitoring, recordkeeping and
transmission are being undertaken by the operator and, if they are not,
to suspend operations.
Response: As discussed in part V.B.4 of this document, the
final RTM requirements in Sec. 250.724 are somewhat different, based
on other comments received, than the proposed requirements. However,
although under existing Sec. 250.146(c) and final Sec. 250.724, the
lessee, designated operator, and the person (including a contractor)
actually performing the activity are jointly and severally responsible
for complying with the final RTM requirements, neither the proposed nor
final rule requires the contractor (or other person) to keep duplicate
records. Nor does the final regulation require a contractor to
determine whether a lessee or operator is otherwise gathering,
recording, storing or transmitting required real-time data beyond the
activities actually performed by the contractor or other person.
Summary of comments: Under proposed Sec. 250.730(c)--regarding
follow-up activities after a BOP equipment failure--a commenter
asserted that a prudent drilling contractor would conduct such follow-
up, especially since API Standard 53 covers follow-up activities. The
commenter claimed that incorporation of that standard in the rule would
make the standard's follow-up requirements mandatory. However, the
commenter questioned whether a contractor would have a regulatory
obligation to perform those follow-up activities. The commenter also
asked what, if any, regulatory obligations are created for equipment
manufacturers.
Response: To the extent that a drilling contractor
actually performs any BOP equipment follow-up activity required by
final Sec. 250.730(c), the contractor is jointly and severally
responsible, along with the lessee and designated operator, for
compliance with the specific requirement applicable to that activity.
In particular, if the
[[Page 25906]]
contractor performs any of the reporting or notification required by
Sec. 250.730(c), the contractor is responsible, along with the lessee
and designated operator, for complying with the terms of the applicable
requirement(s). If the contractor (or any other person) is not actually
performing a required activity, but believes that a lessee, operator or
other person may have failed to comply with any applicable requirement
under BSEE's regulations, the contractor may report such noncompliance
to BSEE in accordance with Sec. 250.193.
Section 250.730(c) does not impose any requirements on OEMs.
Summary of comments: With regard to the proposed recordkeeping
requirements in proposed Sec. Sec. 250.740, 250.741, and 250.746, one
commenter stated that, while a prudent drilling contractor presumably
would maintain relevant records, such prudence differs from a
regulatory obligation to do so. The commenter also asked whether BSEE's
intends that these provisions create a regulatory requirement for
contractors or individuals to maintain records duplicating those
maintained by the operator.
Response: To the degree that a contractor or any other
person actually performs any of the recordkeeping activities required
by Sec. Sec. 250.740, 250.741, and 250.746, that person is jointly and
severally responsible, with the lessee and designated operator (if
any), for complying with the applicable requirements, including record
retention, imposed by those sections. Those provisions of the final
rule do not, however, require that the lessee, designated operator, or
the person performing the recordkeeping requirements maintain duplicate
copies of the records kept by other jointly responsible parties.
6. Economic Analysis Comments
a. Analysis Period Used in the Initial Regulatory Impact Analysis (RIA)
Summary of comments: BSEE received several comments suggesting that
the analysis period used in the initial RIA \10\ for the proposed rule
was insufficient to fully assess the impacts of the rule on OCS
operations. Commenters noted, in particular, that offshore developments
and equipment have lifecycles of 20 to 30 years, making the 10-year
analysis period used in the initial RIA insufficient for estimating the
costs and benefits of the rule.
---------------------------------------------------------------------------
\10\ This document uses the terms ``initial RIA'' and ``initial
economic analysis'' interchangeably. Both terms refer to the initial
regulatory impact analysis performed for the proposed rule, as
required by E.O. 12866, which is available in the regulatory docket
for this rule at: www.regulations.gov (Enter BSEE-2015-0002).
---------------------------------------------------------------------------
Response: BSEE determined that that the 10-year analysis
period used in the initial RIA is appropriate to maintain reasonable
certainty of the estimates, given the uncertainties that exist beyond
10 years with regard to industry activities, technological change, and
energy markets.
b. Issues Associated With the Economic Baseline
Summary of comments: BSEE received several comments on the initial
RIA indicating that some of the costs assumed to be part of the
baseline (and, therefore, not considered costs of the rule) are
actually related to activities that either are not covered by current
industry standards or are not in accordance with existing regulations.
Specifically, commenters referred to costs related to requirements for
activity reporting and recordkeeping, BOP system testing, autoshear/
deadman/EDS systems, casing and cementing, maintenance and inspection,
and redundant components for well control, among others, as examples of
costs the analysis purportedly failed to consider because they were
assumed to be part of the baseline.
Response: BSEE established the baseline used in the
initial (and the final) RIA in accordance with the guidance provided by
Office of Management and Budget (OMB) Circular A-4 (``Regulatory
Analysis''). This guidance states that the ``baseline should be a best
assessment of the way the world would look absent the proposed
action[,]'' i.e., without the implementation this final rule. (OMB
Circular A-4 sec. E. 2. ``Developing a Baseline.'') Without this rule,
BSEE's best assessment of the way the world would look includes
compliance costs associated with current industry practices, existing
regulations, DWOPs, NTLs, and industry standards. Therefore, based on
the Circular A-4 guidance, BSEE has reasonably determined that the
costs listed by the commenters are appropriately included in the
baseline.
In contrast, many of the comments appeared to assume that any cost
associated with requirements of this regulation is a cost of the rule
regardless of whether that cost is already incurred based on current
standard industry practice, existing regulations, or other indicators
of state of the world in the absence of this rule. This assumption is
inconsistent with both OMB guidance and with the general principles
upon which an RIA is based. Additional discussion of BSEE's development
of the baseline scenario can be found in Section 4 and in Appendix A of
the final RIA for this rule, which is available in the regulatory
docket at www.regulations.gov (enter BSEE-2015-0002).
c. Costs Related to Equivalent Circulating Density Information
Summary of comments: One comment on the initial RIA asserted that
the requirement to include information on the ECD under proposed Sec.
250.413 would take additional time by the drilling engineer and
additional staff time to interface with BSEE personnel.
Response: BSEE notes that this information is already
included in the driller's report, which is an existing requirement, and
thus there is no additional cost as a result of this requirement.
d. Costs Related to Wellhead Systems Information
Summary of comments: One comment stated that the additional
information to be provided on wellhead systems under proposed Sec.
250.414(j) would require operators to include wellhead and liner hanger
specifications in the APD, resulting in an additional cost to
operators.
Response: This information is readily available from the
OEM, once the operator purchases the wellheads, so the additional cost
to operators due to these requirements should be minimal.
e. Tubing and Wellhead Equipment Costs
Summary of comments: Some comments asserted that BSEE failed to
adequately consider costs associated with the requirements in proposed
Sec. Sec. 250.518 and 250.619 for complying with industry standards
for tubing and wellhead equipment.
Response: BSEE notes that these costs are included in the
baseline since the only requirements in these sections that impose any
costs are those associated with meeting the existing industry standard
(i.e., API spec. 11D1) for tubing and wellhead equipment that industry
already follows.
f. Installation of Locking Devices
Summary of comments: Some comments suggested that BSEE had not
included the cost of requiring the installation of hydraulically
operated locks on surface BOP systems, under proposed Sec. 250.733
(now covered under final Sec. 250.735(g).)
Response: Although the revised final rule will not require
installation of hydraulically operated locks on surface BOP systems (as
discussed in part VI.C),
[[Page 25907]]
BSEE agrees with the comment that the costs of installing hydraulic
locks should have been included in the initial RIA. Under the revised
final Sec. 250.735(g), operators are not require to install hydraulic
locks on surface BOPs. Instead, operators must install remotely-
operated locks (which may but are not required to be hydraulic locks)
on surface BOP blind shear rams and must install either manual or
remotely-operated locks on surface BOP pipe rams or variable bore rams.
Although not required to do so, operators may choose to comply with
this revised requirement by installing hydraulic locks on some or all
of these surface BOP sealing rams. Therefore, as one of the comments
suggested, BSEE has added to the final economic analysis a one-time
cost of $50,000 for each of the estimated 50 surface BOP rigs that
could choose to install hydraulic locks this installation. Accordingly,
the final RIA includes a one-time cost to industry of $2.5 million.
g. Capping Stack Test Costs
Summary of comments: Some comments suggested that BSEE
underestimated the costs of capping stack tests in the initial RIA.
Response: BSEE analyzed these comments and agrees that the
cost estimate should be revised upward. Using information provided in
one of the comments, BSEE revised the cost estimate (to industry
overall) from $80,000 per year to $226,000 per year.
h. Costs related to Safe Drilling Margins
Summary of comments: Some comments suggested that the costs in the
initial RIA should have included a higher cost for the requirement for
safe drilling margins under proposed Sec. 250.414. The proposed
requirement specified that the static mud hole weight must be at least
0.5 ppg below the minimum of the lower of the estimated fracture
gradient or the casing shoe pressure integrity test (the 0.5 ppg safe
drilling margin).
Response: This proposed requirement was revised in the
final rule to allow for alternative drilling margins in situations
where the operator provides justification and documentation in the APD
that warrant variations, based on the specific well conditions, in
order to maintain a level of safety equivalent to the 0.5 ppg
requirement. Because the 0.5 ppg safe drilling margin is consistent
with typical margins in approved APDs under current BSEE and industry
practice, and the provision for approval of alternative margins is
consistent with existing Sec. 250.141, the costs associated with
complying with these safe drilling margin requirements (other than
minor administrative and recordkeeping costs) are part of the baseline.
Additionally, the commenters' estimated costs for complying with
the proposed safe drilling margin requirements, based on the proposed
language, would be significantly less under the final regulatory
language, which provides operators with more flexibility to set lower
drilling margins, upon providing adequate documentation with the APD
submittal and receiving approval by BSEE.
i. RTM-Related Costs
Summary of comments: BSEE received several comments suggesting that
the costs associated with RTM requirements for well operations were
underestimated in the initial RIA.
Response: These comments tended to assume greater demands
on the RTM systems (such as the exchange of more information through
RTM than was necessary, or the mandatory creation of new RTM centers)
than the proposed rule actually intended. Further, BSEE has clarified
and modified several aspects of the RTM requirements, and made them
more performance-based, in the final rule. Although the performance-
based requirements should make the RTM provisions less costly overall
than the proposed requirements (since operators presumably will use the
lowest cost means to achieve the performance goals), the final rule
retains several of the proposed RTM requirements that were the basis of
most of the RTM-related costs estimated in the initial RIA. (For
example, the final rule still requires that operators gather and
monitor RTM data, using an independent automated system, on the well's
BOP control system, the fluid handling system, and downhole
conditions.) After further review of its initial RIA, BSEE has
concluded that the initial costs estimates for the proposed RTM
requirements, as they were originally intended, are a reasonable and
conservative upper bound on the potential costs of the final rule, and
that the commenters' higher estimates were based on incorrect
assumptions about the scope and intent of the proposed requirements.
Accordingly, BSEE has retained the initial costs estimates for RTM in
the final RIA. Further discussion of the cost estimates for the final
RTM requirements are found in part VIII, ``Regulatory Planning and
Review,'' and in the final RIA.
j. BAVO-Related Costs
Summary of comments: New paragraph (a) in final Sec. 250.732
requires any organizations that want to become a BAVO to submit certain
information. Some comments suggested that this imposes additional
paperwork costs on industry.
Response: BSEE agrees and the final RIA estimates that
these costs will result in an increase of approximately $10,000
annually to industry, including BAVO applicants.
k. MIA Report Costs
Summary of comments: BSEE received a comment that included a
substantially higher estimate of the cost to operators for submitting
the MIA Report to BSEE.
Response: BSEE notes that the commenter incorrectly
calculated this cost on a per-well basis, instead of on a per-rig
basis, which is how the cost will actually be accrued. Accordingly, we
have made no change to the initial RIA cost estimate, which is included
in the final RIA.
l. Surface BOP Stacks and Drilling Risers Costs
Summary of comments: BSEE received comments asserting that the
estimated costs in the initial RIA associated with the dual bore
drilling riser requirements for surface BOP stacks were incomplete. In
particular, one comment asserted that the proposed requirement for dual
bore risers would necessitate the replacement of several existing riser
systems.
Response: The dual bore riser requirements in final Sec.
250.733(b)(2) are limited to facilities or BOPs that are installed
after the effective date for those requirements. Thus, BSEE does not
anticipate any additional replacement costs for current drilling
risers.
m. Gas Bleed Line Requirement Costs
Summary of comments: Some comments suggested that BSEE
underestimated the cost of the requirement involving the installation
of a gas bleed line under proposed Sec. 250.734(a)(15).
Response: BSEE has revised this requirement in the final
rule by clarifying that the gas bleed line must be installed below the
upper annular (not below both annulars), and the final requirement thus
costs less than the proposed requirement would have cost. Moreover,
based on BSEE's most recent analysis, the vast majority of subsea BOPs
already have a gas bleed line installed, and the ones that do not will
require only very slight modification under the final rule. Thus, the
final RIA estimates a lower cost of compliance for this provision of
the final rule.
[[Page 25908]]
n. Costs of Accumulator System Requirements
Summary of comments: BSEE received comments on the proposed
accumulator system requirements in the proposed rule at Sec. 250.735,
including estimates of industry costs to comply with these
requirements. Many of the estimated costs in these comments exceeded
the costs estimated by BSEE in the initial RIA.
Response: The final regulatory text for this requirement
has been changed to better align with API Standard 53, thereby reducing
its cost to industry. The remaining costs to comply with this final
requirement are now minimal, as described in the final RIA.
o. Costs Related To Testing of ROV Intervention Functions
Summary of comments: BSEE received a comment that the testing of
ROV intervention functions under proposed Sec. 250.737 would require
additional operational time per well, thereby imposing an additional
cost.
Response: BSEE does not estimate that there will be any
additional costs to operators in this regard since such testing is
consistent with industry standards, and is thus within the baseline of
the analysis.
p. Costs Related To Breakdown and Inspection of BOP System and
Components
Summary of comments: Several commenters asserted that the
requirement in proposed Sec. 250.739 that operators break down the
entire BOP system every 5 years for inspection, without the option to
phase or stagger inspection, would cause rigs to be out of service for
extended periods of time, at substantial opportunity costs to industry.
Response: As described in detail in parts V.B.3 and VI.C
of this document, BSEE has revised the requirement in Sec. 250.739 of
the final rule to allow for phased inspections over the course of 5
years. This change should eliminate the need for rigs to be brought out
of service for extended periods of time, and thus reduces if not
eliminates the opportunity costs of such inspections.
q. Indirect Economic Impacts of the Rule
Summary of comments: Claimed indirect costs--Some comments
suggested that BSEE should consider additional impacts of the rule. For
example, several comments asserted that the analysis did not
appropriately account for broader ``indirect'' economic costs (such as
costs arising out of job losses associated with reduced exploratory
drilling activities) that commenters asserted may occur as a result of
the rule. One of these comments also provided an economic analysis of
the broad effects of the rule on the national economy.
Response: BSEE does not agree that what the commenter has
described as ``indirect costs'' of the rule are within the scope of the
RIA as required by E.O. 12866. OMB Circular A-4 characterizes the
indirect effects of a rulemaking as ``ancillary benefits and
countervailing risks,'' but also states that these types of forecasted
consequences, if highly speculative, may not be worth further formal
analysis. Because there are a number of important and variable factors
(unrelated to the implementation of the new regulations), such as the
future price of oil, that will impact both the offshore oil and gas
labor market and the marketplace for offshore oil and gas equipment and
products, BSEE believes it is too speculative to predict whether this
rulemaking will have the types of broad and indirect effects discussed
by the comments. In addition, the indirect impacts expressed by the
comments appear to be overstated or based upon certain assumptions for
which there is no clear foundation.\11\ Moreover, many of those
estimated costs appear to be associated with requirements that are part
of the economic baseline (e.g., compliance with relevant provisions of
API Standard 53); while others are associated with requirements
discussed in the proposed rule that are not included in the final rule
(e.g., the proposed 1.5 times volume capacity accumulator requirement).
---------------------------------------------------------------------------
\11\ For example, one comment assumed that the costs of the rule
would lead to a 20 percent decrease in the number of floating units
and over 30 percent decrease in fixed platforms, but provided no
explanation for those assumptions.
---------------------------------------------------------------------------
In addition, the commenters did not take into account the potential
benefits to industry in terms of reduced costs of operation associated
with implementation of the new regulations. For example, the reduction
in costs attributable to the change in the BOP pressure testing
frequency for workovers and decommissioning will exceed the costs that
will result from the final rule.
The commenters also did not account for the indirect benefits from
the rulemaking that may accrue to entities other than offshore
operators. For example, the requirements for new equipment and for use
of BAVOs may result in an increase in the offshore labor force, which
should result in overall economic benefits. Although such indirect
benefits may also be speculative, and thus do not warrant further
analysis under OMB Circular A-4, their absence from the commenters'
estimates means that their estimates do not present a complete picture
of all of the potential indirect effects.
Summary of comments: Costs to Contractors--Several commenters
asserted that BSEE did not adequately account for the additional costs
to contractors that would result from the proposed rule.
Response: BSEE disagrees with this comment because, in
estimating costs, BSEE considered the costs of all of the equipment and
labor services that would be needed to meet new requirements,
regardless of how that equipment or labor is provided (whether by
lessees, operators, or contractors).
Summary of comments: Offshore support industries--Commenters also
stated that BSEE overlooked potential negative impacts to industries
that support offshore oil and gas exploration and development.
Response: BSEE disagrees with this comment. The economic
analysis included in the initial RIA considered the costs of all of the
equipment and labor services that would be needed to meet the new
requirements. Many of the negative impacts projected by the commenters
are speculative and outside the scope of the type of analysis required
to support this rulemaking. (For example, one comment stated that the
rule was ``unworkable as written and could effectively shut-down
drilling operations . . . similar to another drilling moratorium.'') In
addition, some commenters projected additional costs to industries that
support offshore oil and gas exploration and development, but did not
address whether there are potential benefits to other types of
industries resulting from the new requirements. Thus, even assuming
they were within the scope of this analysis, these comments do not
present a complete picture of the potential impacts on other
industries.
r. Impacts of the Regulation on National Energy Security
Summary of comments: BSEE received comments that the initial RIA
did not account for the impacts of the proposed regulation on national
energy security. These comments suggested that the rule would weaken
national energy security by reducing domestic oil production and
increasing reliance on foreign oil.
Response: BSEE does not agree with this comment. The
commenters' prediction about the weakening of national energy security
is highly speculative and thus outside of the scope of the regulatory
impact analysis
[[Page 25909]]
required by E.O. 12866 and OMB Circular A-4. For example, these
comments apparently assume that this rulemaking will cause a reduction
in domestic oil production over some period of time. As previously
discussed, the net economic effect of the final rule on the oil and gas
industry should be positive (i.e., the potential benefits exceed the
potential costs), which does not support the assumption of a reduction
in domestic oil production. Rather, future technological advancements
and variable market factors (e.g., the price of oil) unrelated to the
requirements of this final rule, are more likely to affect the future
domestic oil production.
7. Clarification of Maximum Anticipated Surface Pressure (MASP)
Summary of comments: Some commenters recommended that BSEE change
the reference to MASP in specific sections throughout the rule (e.g.,
proposed Sec. 250.734(a), requiring that the working pressure rating
of each BOP component exceed the applicable MASP) to ``maximum
anticipated wellhead pressure'' (MAWHP). They asserted that there is no
industry agreed-upon definition of MASP, but that MAWHP is defined in
API Standard 53.
Response: BSEE does not agree that the recommended change
is necessary. The MASP must be identified for the specific operation,
and for a subsea BOP, the MASP must be taken at the mudline, as
explained in Sec. 250.730(a). As a practical matter, for surface BOPs,
the MASP is the same as the MAWHP; and for subsea BOPs, the MASP, when
taken at the mudline, as required by Sec. 250.730(a), is also the same
as the MAWHP. BSEE does not agree that use of MASP will cause any
confusion. BSEE's existing regulations (e.g., former Sec. 250.448(b)),
have long used the term MASP, and BSEE does not believe that the
industry will have any difficulty understanding the meaning and use of
that term in this rule.
C. Section-By-Section Summary and Responses to Significant Comments on
the Proposed Rule
This summary discusses every section of 30 CFR part 250 covered by
the proposed rule and this final rulemaking; sections of the existing
regulations that were not addressed in the proposed or final rule are
not included in this summary. BSEE did not receive any substantive
comments on numerous sections covered by the proposed rule; those
sections are included in this final rule and are summarized here. BSEE
received substantive comments on many other sections covered by the
proposed rule, some of which have been included in this final rule
without revision and some of which have been revised in the final rule.
Those sections, and the relevant comments on those sections as well as
BSEE's responses are summarized here.
Subpart A--General
What does this part do? (Sec. 250.102)
This section of the existing regulation provides information on
where to find information about various OCS operations in 30 CFR part
250. BSEE proposed to add new information to this section so the public
will know where they can find requirements for well operations and
equipment in new subpart G. BSEE received no substantive comments on
this provision of the proposed rule and has included the proposed
language in the final rule without change.
What must I do to protect health, safety, property, and the
environment? (Sec. 250.107)
This section of the existing regulation lays out performance-based
and other requirement that operators must meet to protect safety,
health, property and the environment and requires the use of BAST
whenever practical. BSEE proposed several revisions to this existing
regulation. BSEE proposed to revise paragraph (a) of this section to
include performance-based requirements that operators utilize
recognized engineering practices that reduce risks to the lowest level
practicable during activities covered by the regulations and conduct
all activities pursuant to the applicable lease, plan, or permit terms
or conditions of approval. BSEE also proposed adding new paragraph (e)
to clarify BSEE's authority to issue orders when necessary to protect
health, safety, property, or the environment. BSEE received several
comments on the proposed changes and additions to this section but, for
the following reasons, has included the proposed language in the final
rule without change.
Comments Related to Proposed Sec. 250.107--Suggested Standards for
Incorporation
Summary of comments: Commenters expressed several concerns about
this section. One commenter focused on the performance-based intent of
this section. The commenter recommended that BSEE incorporate by
reference established and well known standards (International
Electrotechnical Commission (IEC) 61508 and 61511)) to support the
provisions. The commenter suggested that these standards, which are for
developing safety instrument systems, including programmable systems
(i.e., software), to a target level of reliability, could be adapted to
support the rule. The commenter suggested that the methodology in IEC
61508 and 61511 could be used to manage components and materials to
ensure quality, so that reliability is not degraded and can be
controlled via this process even if original parts are replaced by less
expensive versions that have the same specification.
Response: The international electrical standards referred
to by the commenter (which apply broadly to electrical and electronic
systems used to carry out safety functions and are not specifically
related to well control systems) were not proposed for incorporation in
the proposed rule and are outside the scope of this rulemaking.
However, BSEE may evaluate those standards at a later date and, if BSEE
determines that it is reasonable and appropriate to incorporate some
parts or all of those standards, BSEE may propose to do so in another
rulemaking.
Comments Related to Proposed Sec. 250.107(a)--Definition of ``You''
Summary of comments: Some commenters asserted that proposed Sec.
250.107(a)(4)--requiring lessees, designated operators, and other
persons specified in the existing definition of ``you'' in Sec.
250.105, to comply with all lease, plan and permit terms and
conditions--creates an implicit requirement for contractors or
individuals performing specific activities subject to the regulations
to ascertain all lease, plan, and permit terms and conditions.
Response: As discussed in part VI.B.5 of this document,
compliance with Sec. 250.107(a)(4) does not require a contractor or
other individual performing specific activities required by the part
250 regulations to be knowledgeable about every term in a lease, permit
or plan if those terms are unrelated to the specific activities
performed by the contractor. However, because existing Sec. 250.146(c)
makes any person who actually performs an activity jointly and
severally responsible for compliance with the applicable regulatory
provision, such persons should be familiar with the terms and
conditions of the lease, permit or plan that are relevant to that
activity.
Comments Related to Proposed Sec. 250.107(a)(3)--Concerns Related to
BAST
Summary of comments: Multiple commenters asserted that the new
[[Page 25910]]
language in proposed Sec. 250.107(a)(3) would implicitly change the
BAST provisions in former Sec. 250.107(c). In particular, multiple
comments focused on the requirement in proposed Sec. 250.107(a)(3)
that lessees, operators, and others defined as ``you'' by Sec. 250.105
use ``recognized engineering practices'' to reduce risks to the lowest
practicable level. These commenters noted that the term ``recognized
engineering practices'' is not defined in the regulations and
questioned what practices would be considered as ``recognized'' and
where the recognized practices would be referenced. Commenters also
questioned what would happen if arguably better engineering methods and
practices are developed in the future, but are not yet generally
``recognized'' by industry.
Response: It is unclear why the commenter believed the new
requirements proposed in Sec. 250.107(a)(3) would change the BAST
provisions in Sec. 250.107(c). The commenter may have assumed that the
new requirement would supersede or be inconsistent with the requirement
to use BAST whenever practical. However, Sec. 250.107(a)(3) does not
change the BAST requirement; in fact, the new requirement is intended
to complement the BAST provision by establishing a risk-based goal (to
reduce risks to the lowest practicable level), and a performance-based
requirement that lessees/operators meet that goal by using recognized
engineering practices, when conducting certain regulated activities
(i.e., design, fabrication, installation, operation, inspection,
repair, and maintenance). Such risk reduction and performance-based
approaches are used in other provisions of this final rule and other
BSEE regulations.
Regarding the specific comments on ``recognized engineering
practices,'' BSEE expects that those practices may be drawn, for
example, from established codes, industry standards, published peer-
reviewed technical reports or industry recommended practices, and
similar documents applicable to relevant engineering activities. BSEE
may issue additional guidance on such issues in the future, when and if
specific circumstances warrant such guidance.
Comments Related to Proposed Sec. 250.107(a)(3)--Suggestions for
Alternative Approaches To Reducing Risks
Summary of comments: One commenter commended BSEE for proposing the
general performance-based requirement in Sec. 250.107(a)(3) to reduce
risks to their lowest practicable levels. The commenter noted that
regulators can play a role in defining and challenging companies' risk
control measures, and that this active engagement with industry drives
down risk. The commenter also asserted that many of the other
requirements in the proposed rule are overly prescriptive. The
commenter suggested that prescriptive requirements can lead to safety
plateaus, instead of continual improvements, and that some of the
standards referenced in the proposed rule may not always reflect
current industry best practices and, thus, would not encourage
innovation. The commenter stated that it would be better for BSEE's
regulations to include provisions that adapt in real-time to industry
best practices and innovations.
Response: BSEE agrees with the commenter's suggestion that
it is often appropriate to use performance-based requirements that set
safety and environmental protection goals and encourage innovation and
continual improvement in meeting those goals, and that new Sec.
250.107(a)(3) is such a requirement. In addition, numerous other
provisions in this final rule are also performance-based. As to the
commenter's suggestion that there may be additional opportunities to
include more performance-based measures (presumably in lieu of
prescriptive requirements) in this rule, the commenter provided no
specific alternatives for BSEE to consider. In any event, as explained
elsewhere in this document, the final rule revises several provisions
of the proposed rule, as suggested by other commenters, to make them
less prescriptive and more performance-based (e.g., the revised safe
drilling margin provision in final Sec. 250.414(c)). On the whole,
BSEE believes that this final rule effectively combines prescriptive
and performance-based measures, as appropriate, to ensure and improve
well control and to prevent harm to persons and the environment.
Comments Related to Proposed Sec. 250.107(e)--Concerns About BSEE-
Issued Orders
Summary of comments: A commenter asked whether orders issued by
BSEE under proposed Sec. 250.107(e) (e.g., to ensure compliance with
30 CFR part 250 regulations, or to prevent serious, irreparable or
immediate harm, or to stop violations of the law) would be issued to
both the ``lessee, the owner or holder of operating rights, a
designated operator or agent of the lessee(s)'' and to any person
actually performing the activity. Another commenter stated that the
orders described in proposed Sec. 250.107(e) are reactive methods for
enforcing performance requirements, and that reactive methods are not
enough to reduce risks to the lowest level.
Response: Regarding the entities to whom BSEE may issue
orders under new Sec. 250.107(e), it would be premature and
speculative for BSEE to identify in advance all of the parties to whom
any specific order may be issued. Orders will be issued on a case-by-
case basis as appropriate under the particular circumstances of each
case. BSEE has legal authority to issue shut-in orders to lessees,
operators (if designated) and any person (including contractors) who
actually performs any activity to which a regulation or lease, plan or
permit term applies. Whether or not BSEE orders a contractor to shut-in
operations (suspension), BSEE typically also issues a corresponding
order to the lessee or designated operator in these cases.
BSEE agrees with the comment stating that orders issued under this
section could, at least in some cases, be `reactive'' in nature, and
that reactive measures alone may not be enough to reduce risks to the
lowest level. However, any orders issued under Sec. 250.107(e) would
be only one of many measures established by this final rule, most of
which set performance goals or prescribe specific measures to be taken
in advance of any harm, to improve safety and environmental protection.
BSEE has determined that orders authorized by paragraph (e) are an
appropriate complement to those other measures to ensure that the
regulations, as a whole, achieve their protective purpose.
Service Fees (Sec. 250.125)
The table in this section of the existing regulation lists fees
that operators must pay to BSEE for certain services. BSEE proposed to
revise this section to reflect the current citation for payment of the
service fee relating to DWOPs. BSEE received no substantive comments on
this provision of the proposed rule and has included the proposed
language in the final rule without change.
Documents Incorporated by Reference (Sec. 250.198)
This section of the existing regulation includes citations and
other information regarding all documents (e.g., industry standards)
incorporated by reference in 30 CFR part 250, including where to find
references to the incorporated documents in specific sections of the
regulations. This section also discusses BSEE's process for
incorporating documents by reference, the regulatory
[[Page 25911]]
effects of incorporation, and procedures that operators may follow to
seek BSEE's approval to comply with alternatives to an incorporated
document. BSEE proposed revising this section to add references to the
standards to be incorporated by reference in subpart G. BSEE received
several comments on the proposed additions to Sec. 250.198. BSEE
considered those comments and, for the following reasons, has retained
the proposed language, without change, in the final rule.
Comments Related to Proposed Sec. 250.198--Technical Support Documents
Summary of comments: A commenter requested that BSEE publish
``technical support documents'' summarizing its work in reviewing each
standard that it proposed to incorporate by reference in this rule,
including a determination that each standard is BAST.
Response: All of the documents proposed to be incorporated
by reference in this rulemaking were and are available for public
review. The National Technology Transfer and Advancement Act (NTTAA) of
1995 (Pub. L. 104-113) requires that BSEE rely on voluntary consensus
standards where practical, Public Law 104-113, section 12(d). BSEE
reliance on these standards is principally achieved through
incorporation by reference of industry standards into the bureau's
regulations. It is unclear what ``technical support documents'' the
commenter is referring to, but the NTTAA does not require an agency to
publish its underlying deliberations on why it is appropriate to
incorporate by reference a specific standard. BSEE has explained its
reasons for incorporating the standards referenced in this rulemaking
in both the proposed rule and this preamble.
In addition, BSEE does not make a BAST determination in connection
with the incorporation of industry standards. BSEE's authority under
the NTTAA to incorporate industry standards into BSEE regulations is
separate from the authority to require BAST under OCSLA. The NTTAA
mandates that Federal agencies use technical standards developed or
adopted by voluntary consensus standards bodies, as opposed to using
government-unique standards, when practical. BSEE follows the
requirements of the NTTAA and of OMB Circular A-119 when incorporating
standards into the regulations. These are not tied to the BAST concepts
derived from OCSLA or its implementing regulations.
Comments Related to Proposed Sec. 250.198--Concerns About the
Incorporation of Earlier Editions of Standards
Summary of comments: A number of commenters noted that some of the
standards proposed for incorporation by reference in this rule do not
reflect the current editions of those standards. Commenters requested
that BSEE update those standards to the current editions when
incorporated in the final rule. Commenters stated that the updated
standards reflect the latest knowledge and experience of industry
experts resulting from a collaborative review of the standards. They
also stated that older editions of some standards are no longer
available, and that incorporation of older editions may create
confusion. Commenters suggested that, to resolve the issue of keeping
incorporated standards up to date, BSEE should remove references to
specific editions of the standards and add language to the regulations
that refers to the ``most current edition'' of a standard.
Response: BSEE recognizes the concern related to
incorporating the most current edition of each standard. BSEE reviews
all standards incorporated by reference to ensure they are appropriate
and technically sound. BSEE can choose to keep a certain edition in the
regulations even if there is an updated edition (e.g., if BSEE does not
agree with the technical changes or options allowed in a newer edition
of an industry standard). This is done on a case-by-case basis for each
standard. The change to a new edition, or removal of a discontinued
standard, is not automatic and requires rulemaking. (In some cases,
BSEE may use a direct final rule to incorporate new editions of
standards already incorporated, if the new edition meets the
requirements of Sec. 250.198(a)(2)). BSEE is actively reviewing new
editions of many standards, although newer editions are constantly in
development.
Moreover, BSEE is prohibited, under applicable rules governing
incorporation by reference, from automatically incorporating future
amendments to or editions of a standard. (See 1 CFR 51.2(f); 30 CFR
250.198(a)(1).) However, operators may comply with a later edition of a
standard incorporated in BSEE regulations if the operator demonstrates
that compliance with the newer edition is at least as protective as the
incorporated edition, and if BSEE approves the alternative compliance.
(See 30 CFR 250.198(c).) Operators can also continue to use older
standards, other than those incorporated by reference, if they can
demonstrate an equivalent level of safety and environmental protection,
pursuant to Sec. 250.141.
Comments Related to Proposed Sec. 250.198--Effective Dates of
Standards
Summary of comments: Other commenters requested that, for standards
applicable to equipment requirements under this rule, BSEE add
provisions that allow the operator to use the standard that was in
effect at the date the specific equipment was manufactured. This would
prevent existing equipment and facilities that were manufactured and
accepted under previous standards from being rendered obsolete by
regulations incorporating newer standards. One commenter noted that
BSEE is taking that approach with another rulemaking; i.e., proposed
updating of the edition of API Spec. 2C for offshore pedestal-mounted
cranes currently incorporated in Sec. 250.108 (see 80 FR 34113 (June
15, 2015)). Commenters specifically cited the need to apply this
approach to four standards proposed for incorporation in this rule:
ANSI/API Spec. 16A, ANSI/API Spec. 16C, API Spec. 16D, and API RP 17H.
However, another commenter recommended that BSEE require operators with
existing equipment to comply with the latest industry standards
contained in API Standard 53.
Response: BSEE has addressed comments regarding the
applicability of this rule's equipment requirements to existing
equipment and facilities (e.g., requests to ``grandfather'' in existing
equipment and facilities) in part VI.B of this document. With respect
to the suggestion that BSEE require compliance with the ``latest . . .
standards'' referenced in API Standard 53, BSEE must follow the
provisions of the NTTAA and the guidelines issued by the OMB in
Circular No. A-119 for incorporation of voluntary consensus standards.
Under Circular No. A-119, the date of issuance of the standard being
incorporated must be included in the regulation. Similarly, existing
Sec. 250.198(a)(1) requires that an incorporation by reference is
limited to a specific edition of the incorporated document and does not
include future revisions to that document. Thus, BSEE may not simply
incorporate ``the latest edition'' of any standard, as suggested by the
commenter. However, as previously explained, BSEE may approve
compliance with a later (or an earlier) edition of an incorporated
standard if an operator requests and justifies such an alternative
under Sec. 250.198(c) or Sec. 250.141.
[[Page 25912]]
For the same reason, BSEE does not agree with the commenters'
suggestion that the rules allow an operator to use equipment that meets
whatever ``standard was in effect at the date the specific equipment
was manufactured.'' Under the NTTAA and implementing regulations, any
equipment standard that BSEE incorporates by reference must be
identified by date and edition number. However, BSEE has addressed the
``grandfathering'' issue for existing equipment in part VI.B.4 of this
document. And, where applicable, BSEE may approve compliance with an
earlier edition of an incorporated standard if an operator requests and
justifies such an alternative under Sec. 250.198(c) or Sec. 250.141.
Comments Related to Proposed Sec. 250.198--Normative References
Summary of comments: Several commenters suggested that BSEE should
not directly incorporate normative references (second-tier documents)
used in an incorporated standard (first-tier document), in particular,
API Standard 53.\12\ Those commenters supported the incorporation of
API Standard 53 in its entirety, and asserted that the normative
references contained in that standard would also implicitly apply. One
commenter also stated that separately incorporating the normative
references within API Standard 53 would confuse the operators. However,
other commenters suggested that concerns related to applying the
edition of an equipment standard in existence at the time the equipment
was manufactured (as previously discussed) would be minimized if the
normative references in those standards were not incorporated by
reference in BSEE's regulations.
---------------------------------------------------------------------------
\12\ ``Normative references'' are typically other documents
incorporated by reference within a standard that are considered
necessary for compliance with specific parts of the ``first-tier''
standard.
---------------------------------------------------------------------------
Commenters asked if it was BSEE's intent to require the application
of the normative references in API Standard 53 for purposes other than
their relation to the provisions of API Standard 53 to be incorporated
in the final rule. If so, they requested that BSEE should specifically
state those other purposes in the final rule.
Response: BSEE recognizes that compliance with a normative
reference in an incorporated standard is implicitly necessary at times
to ensure actual compliance with an incorporated standard. However,
BSEE has decided to expressly incorporate the normative references
within API Standard 53 (i.e., relevant provisions of API Spec. 6A, API
Spec. 16A, API Spec. 16C, API Spec. 16D, and API Spec. 17D), in the
regulations (see final Sec. 250.732(a)(2)) so that it is clear when
compliance with those documents is required. This is also consistent
with guidance from the Office of the Federal Register (OFR) related to
the incorporation of second-tier documents. (See 78FR 60,784, 60,794-95
(Oct. 2, 2013).)
Comments Related to Proposed Sec. 250.198--Additional Standards
Documents Suggested for Incorporation
Summary of comments: Commenters suggested that in addition to
updating the incorporation of API Spec. 6A, BSEE should also
incorporate API Standard 6ACRA, First Edition, (June 2015) and API Spec
6A718, First Edition (March 2004), for completeness.
Response: BSEE agrees that certain documents are more
effective if incorporated with other associated documents. However, we
did not include the suggested documents in the proposed rule, and BSEE
has not yet determined whether those standards should be incorporated
in the regulations. We may consider these documents for incorporation
in the future using the evaluation process previously described. If
BSEE decides to incorporate these documents, we will do so through a
separate rulemaking.
Comments Related to Proposed Sec. 250.198--Effective Dates of
Documents
Summary of Comments: A commenter requested that we remove the
effective dates from the citations of standards in Sec. 250.198. The
commenter suggested that the effective dates are of the monogram
licenses, not for general industry use of the documents, and including
the effective dates in the regulations could cause confusion. A
commenter recommended that BSEE use the descriptions shown in the API
Publications Catalog, which only include the standard number, title,
publication date, and any errata/addenda.
Response: BSEE disagrees. As previously stated, BSEE is
required to include certain information from the standard, including
the dates and editions of the incorporated documents, when
incorporating documents by reference. (See Sec. 250.198(a)(1); 1 CFR
51.9(b)(2).)
Comments Related to Proposed Sec. 250.198--Availability of
Incorporated Standards
Summary of comments: Two commenters asserted that BSEE acted
illegally by not providing free, unrestricted, and online access to the
standards incorporated by reference in the proposed rulemaking. The
commenters asserted that BSEE had failed to make the incorporated
materials reasonably available to the public, to discuss in the
proposed rule preamble how it worked to make those materials reasonably
available to interested parties, and to summarize in the preamble the
material it proposed to incorporate, and thus that BSEE had violated
the OFR regulations at 1 CFR 51.5(a). The commenters further asserted
that, by failing to provide access to the incorporated standards, the
proposed rule violated the APA because the proposed rule did not
include ``either the terms or substance of the proposed rule or a
description of the subjects or issues involved.'' (See 5 U.S.C.
553(a).) The commenters recommended that BSEE re-publish the proposed
rule, with the standards available freely online.
The commenters also asserted various technical obstacles to
purchasing the standards (both for print and online) from API and to
viewing them in person at BSEE's offices. The commenters also raised
numerous objections to the manner in which API presents the documents
online, including technical hurdles for visually impaired people to
view the standards online. The commenters also asserted that BSEE is in
violation of the Rehabilitation Act of 1973 because visually impaired
individuals are not able to view the standards properly on API's Web
site. They also asserted that there is no guarantee by BSEE that the
currently free online access for viewing the standards on API's Web
site will last. Another commenter requested that, if BSEE cannot make
the documents available to the general public, BSEE should, at a
minimum, grant access to certain types of organizations (e.g., local
governments).
Response: These comments do not address the substantive
merits of the proposed rule. Rather, the comments principally focus on
legal criteria relevant to BSEE's incorporation by reference of various
industry standards.
Many of the detailed assertions in the comments (e.g., complaints
about API's Web site advertisements) are outside the scope of this
rulemaking as well as unrelated to BSEE's compliance with applicable
regulations for incorporating documents by reference, and thus do not
require any further response.
In determining which industry standards to incorporate by reference
into its regulations, BSEE has carefully evaluated potentially relevant
standards, considered input from
[[Page 25913]]
various interested stakeholders, and proposed for incorporation those
standards that BSEE determined, in its judgment, would reasonably serve
the safety and environmental protection purposes of its regulations. In
developing this final rule, BSEE also considered public comments on the
proposed rule regarding which standards would best serve those
purposes, as discussed elsewhere in this document. In doing so, BSEE
has also complied with the mandate of the NTTAA (previously discussed)
to make use, where appropriate and practical, of existing consensus
standards in lieu of developing new government regulatory standards.
Moreover, BSEE disagrees with the commenters' claims that BSEE
failed to discuss the actions it took to ensure that the materials
incorporated in these rules were, and will be, reasonably available or
to actually make the materials reasonably available. In proposing
certain standards for incorporation in the final rule, and finalizing
such incorporations in this final rule, BSEE has followed the
requirements and procedures for incorporation by reference set out in
OFR's regulations. (See 1 CFR part 51.)
In order to be eligible for incorporation by reference, a document
must be ``reasonably available'' to affected persons (1 CFR 51.5,
51.7(a)(3)) and the notice of proposed rulemaking must discuss how the
incorporated document is reasonably available to interested parties or
how the agency worked to make those documents reasonably available.
(See id. at Sec. 51.5(a)(1).) The notice of final rulemaking must also
discuss the ways that the incorporated document is reasonably available
to, and how it can be obtained by, interested parties. (See id. at
Sec. 51.5(b)(2).)
The primary regulated community for these regulations is the
offshore oil and gas industry, for which the costs for purchasing a
copy of the industry standards (if they choose to do so) incorporated
by reference in this final rule are not unreasonable. For other members
of the public (including other government entities), BSEE discussed in
the preamble to the proposed rule (see 80 FR 21506), and in this
document (under ``Availability of Incorporated Documents for Public
Viewing''), the reasonable methods by which the standards incorporated
here may be reviewed, inspected, copied, or purchased.
In brief, BSEE explained in both documents how any member of the
public may review the referenced standards for free on API's Web site
or in person at BSEE's offices in Sterling, VA, or at NARA's offices in
Washington, DC. These actions are consistent with BSEE's prior
rulemakings incorporating many other standards in the part 250
regulations. Moreover, BSEE received informal approval from OFR for the
proposed incorporations by reference in the proposed rule, and formal
approval for the final incorporations in this final rule, in accordance
with OFR's regulations (1 CFR 51.3 and 51.5), which include the
requirement for making the documents reasonably available.
Similarly, we disagree with the commenters' claim that the proposed
rule violated the APA by failing to adequately describe the materials
proposed for incorporation. To the contrary, the proposed rule
adequately described the referenced standards (see 80 FR 21506-21508),
as does this document. In addition, OFR's informal approval of the
proposed incorporations, and its formal approval of the incorporations
in this final rule, means that OFR agrees that BSEE has met the
requirement in the OFR regulations for describing the incorporated
materials. (See 1 CFR 51.5(a)(2) and (b)(3).)
In addition, contrary to commenters' claims that BSEE must provide
free, downloadable copies of the standards on its Web site,
notwithstanding API's copyright claims to those standards, OFR has
expressly concluded that an agency's incorporation by reference of
copyrighted material does not result in the loss of that copyright.\13\
OFR reached this conclusion based in part on its analysis of the
decision in Veeck v. Southern Building Code Congress International,
Inc., 293 F.3d 791 (5th Cir. 2002). In the preamble to its recently
promulgated amendments to the rules for incorporation by reference, OFR
stated:
---------------------------------------------------------------------------
\13\ Contrary to some commenters' claims, OFR's regulations also
do not require BSEE to provide free, downloadable copies of the
incorporated documents online, whether or not they are copyrighted.
OFR expressly rejected that suggestion in its recent document
promulgating the current regulations governing incorporation by
reference. (See 79 FR 66267 (Nov. 7, 2014).)
that recent developments in Federal law, including the Veeck
decision and the amendments to the Freedom of Information Act
(FOIA), and the NTTAA have not eliminated the availability of
copyright protection for privately developed codes and standards
referenced in or incorporated into Federal regulations. Therefore,
we agreed with commenters who said that when the Federal government
references copyrighted works, those works should not lose their
---------------------------------------------------------------------------
copyright.
(See 79 FR 66273.)
Under the OFR regulations, BSEE is permitted to incorporate
copyrighted materials into its regulations. Implicit within that
permission is the fact that access to and presentation of certain
incorporated standards is controlled principally by the third-party
copyright holder. While BSEE works diligently to maximize the
accessibility of incorporated documents, and offers direction to where
the materials are reasonably available, it also must ultimately respect
the publisher's copyright. Accordingly, issues related to how API
structures its Web site or formats its copyrighted materials offered
for free access are outside of BSEE's control and beyond the scope of
this rulemaking.
Paperwork Reduction Act Statements--Information Collection (Sec.
250.199)
This section of the existing regulation provides the OMB control
numbers associated with information collections under each subpart of
part 250, and generally provides BSEE's reasons for collecting the
information and explains how the information is used. BSEE proposed to
revise this section by updating the OMB control numbers, by rewording
some of the explanations for BSEE's information collections, and by
adding references to proposed new information collections. After
considering comments submitted on this section, BSEE has included the
proposed language in the final rule without significant revisions.
However, in response to certain comments, BSEE has revised the
estimated burden hours for compliance with some of the information
collections in the final rule, as explained in the following responses.
Comments Related to Sec. 250.199--General Requirements for Well
Operations and Equipment
Summary of comments: Several commenters raised concerns that
additional time would be needed to account for requests for departures
from operating requirements, as provided in Sec. 250.702, and for
requests for approval to use new or alternative procedures or equipment
during operations, as provided in Sec. 250.701. For example, some
commenters asserted that the proposed requirement for use of subsea
BOPs with ``dual-pod control systems'' and kelly valves will lead to
requests for departures and for alternative procedures. The commenter
explained that such requests would be likely because API Standard 53
requires subsea stacks to ``have fully redundant control pods'' and
because kelly valves are no longer in widespread use in offshore
drilling operations.
[[Page 25914]]
Response: As discussed later in this part of the document,
we have revised the requirement for subsea BOPs with ``dual-pod control
systems'' to require only a ``redundant pod control system.'' This
change will align the pod requirement in the regulations with the
language of API Standard 53. BSEE agrees with the comment about the
limited availability of kelly valves and has revised final Sec.
250.736(d)(1) by replacing the references to kelly valves with
``applicable [k]elly-type valves'' as described in API Standard 53.
Regardless, BSEE does not agree with the commenters' assertions
regarding increased paperwork burdens. Ultimately, the requests for
alternate procedures or equipment and requests for departures
referenced in Sec. Sec. 250.701 and 250.702 are voluntary submissions
made pursuant to longstanding regulations found at Sec. Sec. 250.141
and 250.142, and thus do not reflect a new paperwork burden under this
rule.
Comments Related to Sec. 250.199--APDs
Summary of comments: Several comments requested that we include
additional burden hours to prepare required permitting information. One
commenter stated that the dual riser requirement in proposed Sec.
250.733(b) may require additional engineering time to assure existing
floating production facilities have the room to accept dual bore risers
or dual shear ram BOPs. Another commenter stated that, to meet the
requirements in Sec. 250.734(c) for drilling out the surface casing in
a new well with a subsea BOP, additional burden hours would be needed
to submit a revised APD, including the required third-party
verifications, and to obtain BSEE's approval.
One commenter stated that Sec. 250.418(g) of the proposed rule
would likely require additional engineering time to develop a well
abandonment plan that includes wash out or cement displacement to
facilitate casing removal upon well abandonment. Another commenter
stated that an additional man-day per individual well would be needed
to provide a description of the source control and containment
capabilities and receive APD approval pursuant to Sec. 250.462(c).
We also received a comment requesting that we increase the
estimated burden hours given that additional drilling prognosis
information in the APD may be required by the District Manager under
Sec. 250.414(k).
Response: BSEE agrees with several of the commenters'
assertions and has increased the burden estimate for preparing APDs and
APMs to comply with this final rule as described in part VIII
(Paperwork Reduction Act (PRA) of 1995).
Comments Related to Sec. 250.199--Tubing and Wellhead Equipment
Summary of comments: One commenter asserted that it may not be
possible to set a packer deep enough to have a column of kill weight
fluid at the packer. As a result, additional engineering time would be
required to comply with the Sec. 250.518(e) requirement for tubing and
wellhead equipment for completion operations to determine if the casing
design is suitable.
Response: BSEE agrees with the comment and has increased
the burden for APMs to account for the descriptions and calculations of
packer depths required by this rule.
Comments Related to Sec. 250.199--Well Operations
Summary of comments: We received numerous comments on the Sec.
250.724(b) proposed RTM requirements. Commenters stated that such
monitoring on all well operations, including shallow water shelf
operations, would result in significant additions to the sensor, data
integration, data telemetry band width, data reception and storage, and
data monitoring and interpretation burden for all operators. They also
expressed concern about how to comply with the new requirements to
conduct continuous RTM of the BOP control system, the well's fluid
handling systems on the rig, and the well's downhole conditions with
the bottom hole assembly tools, and provisions for storage of the data.
Response: BSEE agrees with the comment and has increased
the burden hours to account for the development and implementation of
an RTM plan, as required by the final rule, that includes all data
required by Sec. 250.724.
Comments Related to Sec. 250.199--BOP System Requirements
Summary of comments: We received comments claiming that additional
engineering time would be necessary to comply with the requirements of
Sec. 250.730(d). Since Sec. 250.730(d) requires that any BOP stack
manufactured after the effective date of the regulation comply with API
Spec. Q1, the commenter stated that additional burden hours will be
needed to design a BOP stack that complies with API Spec. Q1.
In addition, several commenters stated that there is an additional
burden involved with submittals of an MIA Report as required by Sec.
250.732(d) for a subsea BOP, a BOP used in an HPHT environment, or a
surface BOP used on a floating facility. Specifically, they asserted
that BSEE failed to account for the burden of obtaining BAVO
certification of the MIA Report, as required by proposed Sec.
250.731(f).
Response: BSEE does not agree that any additional burden
hours should be added for compliance with Sec. 250.730(d). That
provision does not create any new information collection burdens since
it requires compliance with existing industry standards, the costs of
which are included in the economic baseline.
However, BSEE has increased the burden hours for requesting
approval to use new or alternative procedures, along with supporting
documentation if applicable under Sec. 250.730, should an operator
seek to deviate from the requirements of Sec. 250.730(d). BSEE has
also increased the burden hours for complying with the Sec. 250.731(f)
MIA Report certification requirement.
Subpart B--Plans and Information
What must the DWOP contain? (Sec. 250.292)
This section of the existing regulation specifies information
(e.g., description of the typical wellbore, structural design for each
surface system) that must be included in a DWOP. BSEE proposed no
changes to existing paragraphs (a) through (o) of Sec. 250.292, and
the final rule makes no changes to those paragraphs. BSEE proposed to
add a new paragraph (p) to this section and to redesignate existing
paragraph (p) as paragraph (q). Proposed new paragraph (p) specified
information that must be included in the DWOP if the operator proposes
to use a pipeline FSHR meeting certain conditions. This information is
used in planning for production development. BSEE received several
comments on this proposed addition, and for the following reasons, has
included proposed paragraph (p) in the final rule with one revision to
the proposed language, as described in the following response and in
part V.C of this document. Former paragraph (p) is also included in the
final rule, without change, as new paragraph (q).
Comments Related to Sec. 250.292(p)--Pipeline Freestanding Hybrid
Risers (FSHRs)
Summary of comments: Commenters suggested that BSEE apply Sec.
250.292(p) only to permanent FSHRs, and not to risers used for
exploratory wells or for source control and containment. Those
commenters noted that exploration wells are not covered under the
existing DWOP regulations (Sec. Sec. 250.286 through
[[Page 25915]]
250.295), which apply to deepwater development projects, and that
risers used for source control and containment are not part of a
permanent installation.
Response: BSEE agrees that this requirement applies only
to permanent FSHRs for development projects under a DWOP. It is
incorporated into a regulation setting forth requirements for the
contents of a DWOP. Accordingly, it is inapplicable to operations that
do not require a DWOP. BSEE would permit temporary FSHRs, such as those
used with containment systems to respond to an emergency, on a case-by-
case basis. BSEE has revised this paragraph in the final rule to
clarify that it applies only to FSHRs ``on a permanent installation.''
Subpart D--Oil and Gas Drilling Operations General Requirements (Sec.
250.400)
This section of the existing regulation was entitled ``Who is
subject to the requirements of this subpart?'' BSEE proposed to revise,
this entire section, including the section heading, to require that
drilling operations be done in a safe manner to protect against harm or
damage to life (including fish and other aquatic life), property,
natural resources of the OCS (including any mineral deposits), the
National security or defense, or the marine, coastal, or human
environment. BSEE also proposed to clarify that, for drilling
operations, the operator must follow the requirements of this subpart
and the applicable requirements of proposed subpart G. BSEE received no
substantive comments on this proposed provision and made no changes to
the proposed language, which is now included in the final rule.
What must I do to keep wells under control? (Sec. 250.401)
BSEE proposed to remove and reserve this section of the existing
regulation and to move the content of this former section to proposed
Sec. 250.703. BSEE received no comments on the proposed removal and
reservation of this section and the final rule implements that action.
When and how must I secure a well? (Sec. 250.402)
BSEE proposed to remove and reserve this section of the existing
regulation and to move the content of this former section to proposed
Sec. 250.720. BSEE received no comments on the proposed removal and
reservation of this section and the final rule implements that action.
What drilling unit movements must I report? (Sec. 250.403)
BSEE proposed to remove and reserve this section of the existing
regulation and to move the content of this existing regulation to
proposed Sec. 250.712. BSEE received no comments on the proposed
removal and reservation of this section and the final rule implements
that action.
What additional safety measures must I take when I conduct drilling
operations on a platform that has producing wells or has other
hydrocarbon flow? (Sec. 250.406)
BSEE proposed to remove and reserve this section of the existing
regulation and to move the content of this former section to proposed
Sec. 250.723. BSEE received no comments on the proposed removal and
reservation of this section and the final rule implements that action.
What information must I submit with my application? (Sec. 250.411)
This section of the existing regulation specified certain
information that must be included in an APD, including descriptions of
``diverter and BOP systems.'' BSEE proposed to slightly revise this
section to separate the requirements for diverter and BOP descriptions,
and to updates the cross-reference in the section to include new
subpart G. BSEE received no substantive comments on this provision of
the proposed rule and made no changes to the proposed language, which
is included in the final rule.
What must my description of well drilling design criteria address?
(Sec. 250.413)
This section of the existing regulation specifies the type of
information that must be provided in the well drilling description
portion of an APD. BSEE did not propose any changes to paragraphs (a)
through (f) of the former Sec. 250.413, which are retained unchanged.
BSEE proposed to revise former paragraph (g) to require that the
maximum ECD be included on the pore pressure/fracture gradient plot in
the APD. BSEE received multiple comments on the proposed changes to
paragraph (g) and, for the following reasons, has decided to revise the
proposed language to require that the ``planned safe drilling margin,''
instead of the ECD, be included on the pore pressure/fracture gradient
plot under the final rule.
Comments Related to Proposed Sec. 250.413(g)--Well Drilling Design
Criteria
Summary of comments: Multiple commenters had concerns regarding the
requirement in proposed Sec. 250.413(g) that well drilling design
criteria include a plot showing maximum ECD. They stated that operators
need to manage and adjust ECD during real-time operations, and thus no
margin between ECD and fracture pressure or safety margin should be
required to be specified in advance as part of the APD. The commenters
also suggested that, since the intended use of the ECD cannot be
specified in advance, it should be deleted from Sec. 250.413(g).
Response: BSEE agrees with the commenters that, since ECD
may need to be adjusted during operations, BSEE would need to provide
more clarification about how to determine maximum ECD in order for
operators to include it within the plots. Therefore, BSEE removed the
reference to ECD from final Sec. 250.413(g) and inserted in its place
a requirement to plot the planned safe drilling margin, as required to
be included in the APD by final Sec. 250.414(c). This planned safe
drilling margin is based in part on the planned ECD and thus will
provide information essentially equivalent to what inclusion of the
maximum ECD would have provided.
What must my drilling prognosis include? (Sec. 250.414)
This section of the existing regulation describes the information
that must be included in the drilling prognosis portion of an APD. BSEE
did not propose any changes to paragraphs (a) and (b), and paragraphs
(d) through (g), of the existing regulation and they have been retained
unchanged. BSEE proposed to revise paragraphs (c), (h), and (i) of the
existing regulation and to add new paragraphs (j) and (k) to Sec.
250.414. Specifically, BSEE proposed: To revise paragraph (c) to better
define the safe drilling margin requirements; clarify paragraphs (h)
and (i) with minor wording changes; to add a new paragraph (j)
requiring that the drilling prognosis include both the type of wellhead
and liner hanger systems to be installed and a descriptive schematic;
and to add a new paragraph (k) requiring submittal of any additional
information required by the District Manager as needed to clarify or
evaluate the drilling prognosis. BSEE received some comments on
proposed paragraph (j), but has included that paragraph in the final
rule without change. BSEE received many comments on the
[[Page 25916]]
proposed changes to paragraph (c) and on proposed paragraph (k). After
considering the comments, and for the reasons stated in the following
responses to those comments, BSEE has revised the language of proposed
paragraphs (c) and (k) and included that revised language in the final
rule.
Comments Related to Proposed Sec. 250.414(c)--Safe Drilling Margin
Summary of comments: BSEE received extensive comments on the
proposed requirements in Sec. 250.414(c) regarding safe drilling
margins. The majority of these comments stated that the proposed 0.5
ppg safe drilling margin would pose operational problems, reduce the
safety of drilling operations, and lead to unintended consequences.
Commenters provided examples of concerns, such as limiting the
selection of drilling fluids; potentially requiring more casing strings
or smaller production casing sizes; economic hardships due to not being
able to reach reservoirs by setting more casing; decreased production
from the smaller hole sizes; and undue burden of submittals for
alternative compliance. Recommendations to revise proposed Sec.
250.414(c) included performance of a risk assessment and calculations
to establish safe drilling margins for each well and for each drilling
interval within the well.
BSEE also received comments on the proposed Sec. 250.414(c)(3)
requirements related to the ECD. Some commenters interpreted this
proposed language to mean that drilling must stop when any lost
circulation occurs. Clarifying language was recommended as follows:
``if lost circulation occurs, then the losses should be mitigated, and/
or ECD managed to reduce the effects of lost circulation as per API
Bulletin 92L.''
We also received a comment on the proposed requirements in Sec.
250.414(c) for determining pore pressure and lowest estimated fracture
gradients for specific intervals. The commenter emphasized that the
purpose for this paragraph is to address planning (prognosis) for
drilling operations and that it should not apply to the actual
operations. The commenter recommended the following language: ``during
planning for a specific interval, the relevant available offset hole
behavior observations must be considered.''
Response: BSEE agrees with a majority of the comments on
Sec. 250.414(c) and has not included proposed paragraph (c)(3) in the
final rule (and renumbered proposed paragraph (c)(4) as paragraph
(c)(3) in the final rule). BSEE otherwise revised paragraph (c) in the
final rule to require a planned safe drilling margin that is between
the estimated pore pressure and the lesser of estimated fracture
gradients or casing shoe pressure integrity test and based on a risk
assessment consistent with expected well conditions and operations.
Final paragraph (c) also requires that the safe drilling margin include
use of equivalent downhole mud weight that is (i) greater than the
estimated pore pressure, and (ii) except as provided in paragraph
(c)(2), a minimum of 0.5 pound per gallon below the lower of the casing
shoe pressure integrity test or the lowest estimated fracture gradient.
Final paragraph (c)(2) now clarifies that, in lieu of meeting the
criteria in paragraph (c)(1)(ii), operators may use an equivalent
downhole mud weight as specified in the applicable APD, provided that
the operators submits adequate documentation (such as risk modeling
data, off-set well data, analog data, seismic data) to justify the
alternative equivalent downhole mud weight. Finally, paragraph (c)(3)
states that, when determining the pore pressure and lowest estimated
fracture gradient for a specific interval, the operator must consider
related off-set well behavior observations.
Although 0.5 ppg is typically an appropriate safe drilling margin
for normal drilling scenarios, BSEE understands there are circumstances
where a lower drilling margin may be acceptable to drill a well safely.
The revisions made in the final rule better define safe drilling
margins, requiring the 0.5 ppg margin under most circumstances, but
providing operators with the flexibility to use a lower safe drilling
margin when appropriate.
The changes in the final rule will alleviate, if not eliminate,
much of industry's operational and economic concerns with the proposed
0.5 ppg margin, including industry's concern that a 0.5 ppg drilling
margin--with no exceptions--would effectively preclude the continued
use of dynamic pressure drilling and inhibit development of new
technology.
By requiring justification for, and prior approval by BSEE of, any
alternative to the 0.5 ppg margin, these revisions will provide BSEE
with the information needed to make appropriate case-by-case decisions
on specific drilling margins. BSEE could also use this option to
identify and focus its resources on the potentially higher risk well
sections where the safe drilling margin may be of greater concern.
These revisions will increase planning flexibility for operators when
drilling into areas that could require lower safe drilling margins,
such as depleted sands or below salt (common occurrences in the GOMR).
Industry will be able to determine and use (subject to BSEE approval)
appropriate mud properties (density, viscosity, additives, etc.) best
suited for a specific well interval based on drilling and geological
parameters.
The final rule also revised the proposed language to refer to
``off-set well''--instead of ``hole''--conditions; the final rule
language will better align the regulatory language with industry
terminology and clarify BSEE's intent. For a more in-depth discussion
of the changes to final Sec. 250.414(c), refer to part V.B.1 of this
document.
Comments Related to Proposed Sec. 250.414(j)--Wellhead System and
Liner Hanger System
Summary of comments: BSEE received comments on the proposed Sec.
250.414(j) requirements related to wellhead system and liner hanger
system information. Commenters stated that operators will not have
access to machine drawings for equipment purchased from manufacturers
since this is considered proprietary data. A commenter recommended that
the word ``descriptive'' be changed to ``detailed'' and that BSEE allow
documentation that is available to the operator to be provided to BSEE.
Response: BSEE disagrees with these comments and has made
no changes to Sec. 250.414(j) in the final rule. BSEE is aware that
operators typically receive schematics from the manufacturers, and
those schematics are sufficient to meet the requirements for describing
the wellhead and liner hanger systems. In addition, it is unclear from
the comment why a change from ``descriptive'' to ``detailed'' would
better classify the type of schematics available.
Comments Related to Proposed Sec. 250.414(k)--Additional Information
Summary of comments: BSEE received comments on the proposed Sec.
250.414(k) requirement to provide any additional information required
by the District Manager. Commenters stated that this section should be
restricted to necessary information that can be reasonably supplied by
the operator. Commenters also suggested that the District Manager
should provide justification to the operator for the requested
additional information.
Response: The District Manager may require additional
information on the drilling prognosis on a case-by-case basis, based on
unique site or well conditions. The District Managers would, of course,
take into account the potential need for such information to
[[Page 25917]]
protect personnel or the environment, given the purposes of these
regulations. Like many similar provisions throughout part 250, Sec.
250.414(k) is intended to give District Managers the necessary
flexibility and discretion to require information as needed in specific
cases to fulfill the purposes of the regulation. Nonetheless, BSEE has
slightly revised paragraph (k) in the final rule to confirm that the
District Manager may require additional information needed to clarify
or evaluate the drilling prognosis submitted under this section.
What must my casing and cementing programs include? (Sec. 250.415)
This section of the existing regulation describes the information
on casing and cementing programs that must be included in an APD. BSEE
proposed no changes to paragraphs (b) through (f) of this section,
which have been retained unchanged in the final rule. BSEE proposed to
revise former paragraph (a) of this section to require casing
information for all sections of each casing interval. BSEE proposed
that operators must include bit depths (including measured and true
vertical depth (TVD)) and locations of any installed rupture disks, and
indicate either the collapse or burst ratings, in their APDs. Requiring
this information for all sections for each casing interval will make
well design calculations and APD submittals more accurate and provide a
more complete representation of the well. BSEE received one comment on
the proposed Sec. 250.415, and as discussed in the following response,
has included proposed paragraph (a) in the final rule without change.
Comments Related to Proposed Sec. 250.415--Quality Assurance
Summary of comments: One commenter suggested that we require a
Quality Assurance/Quality Control (QA/QC) plan for cement installation
and recommended that we add the QA/QC protocol to Sec. 250.415 and
require it for each well.
Response: Section 250.420(a)(6) of the existing
regulations already requires the casing and cementing design to include
a certification signed by a registered PE. This verification of the
casing and cementing design by a PE provides the necessary QA/QC. We
have, therefore, made no changes to final Sec. 250.415 based on the
comment.
What must I include in the diverter description? (Sec. 250.416)
This section of the existing regulation specified the information
that must be included in the descriptions of diverter systems and BOP
systems contained in an APD. BSEE proposed to revise this section by
removing former paragraphs (c) through (f), which required certain
information for BOP system descriptions, which BSEE proposed to move to
new Sec. Sec. 250.703, 250.731 and 250.732, and by removing paragraph
(g), which specified criteria for independent third-parties that verify
certain BOP information. Under the proposed rule, Sec. 250.416 would
include only the former language, in paragraphs (a) and (b), regarding
diverter descriptions and would be re-titled accordingly. Based on
comments submitted on the proposed changes to this section, as
explained in the following response, BSEE has included former paragraph
(a) in the final rule without change, as proposed. BSEE also included
former paragraph (b) in the final rule, with one minor change to the
former paragraph (b)(1).
Comments Related to Proposed Sec. 250.416--Descriptions of Diverter
Systems
Summary of comments: One commenter was concerned that proposed
Sec. 250.416 did not actually require use of equipment and
instrumentation to identify hydrocarbons that have travelled above the
BOP and into the marine riser. The commenter stated that current rigs
have zero riser instrumentation (for detecting/tracking hydrocarbons
within the marine riser), and that they are equipped with a diverter
system. The commenter suggested that we completely revise Sec.
250.416(b) to require that diverters have riser instrumentation (such
as ``distributed'' pressure gauges to measure differential pressures)
that can confirm that the volume of gas does not exceed a certain limit
and impose back[hyphen]pressure to keep gas from coming out of
solution.
Response: BSEE does not agree with the suggestion that we
should transform proposed Sec. 250.416 from an informational provision
(i.e., requiring a description of the diverter system) into a
substantive equipment provision requiring specific instrumentation.
Although BSEE agrees that there may be some potential benefits from the
use of instrumentation on the riser, additional research and study
needs to be done before BSEE could determine whether such a substantive
requirement should be added to the regulations. If future research or
study reports or other information becomes available to BSEE warranting
this additional requirement, BSEE may propose revision of this section
in a future rulemaking.
Comments Related to Proposed Sec. 250.416(b)(1)--Diverter Systems
Summary of comments: Another commenter was concerned that proposed
Sec. 250.416(b)(1) would require information in the APD about annular
BOPs in diverter housings, even though not all diverters use annular
elements. The commenter stated that some diverters use ``insert
elements,'' which are not the same as annular BOPs, and recommended
that BSEE replace ``annular BOP'' in proposed Sec. 250.416(b)(1) with
``sealing element.''
Response: BSEE agrees with the commenter that not all
diverters use annular BOPs. Accordingly, BSEE has revised this section
in the final rule by replacing ``annular BOP'' with ``element,'' which
covers all of the different types of components (including annular BOPs
and sealing elements) that may be installed in the diverter housing.
What must I provide if i plan to use a mobile offshore drilling unit
(MODU)? (Sec. 250.417)
BSEE proposed to remove and reserve this section and to move the
content of this former section to proposed Sec. 250.713. BSEE received
no comments on the proposed removal and reservation of this section and
the final rule takes that action.
What additional information must I submit with my APD? (Sec. 250.418)
This section of the existing regulation specified certain
additional information (e.g., rated capacity of the drilling rig,
drilling fluids program) that must be included in an APD. BSEE did not
propose any changes to paragraphs (a) through (f) of the existing
regulation, which are therefore retained unchanged. BSEE proposed to
revise paragraph (g) of the existing regulation, which requires
operators to seek approval for plans to wash out or displace cement to
facilitate casing removal upon well abandonment, by adding a
requirement to describe how far below the mudline the operator plans to
displace cement and how the operator will visually monitor returns.
This proposed change would provide information to assist BSEE in
deciding whether to approve such plans. BSEE received no substantive
comments on this proposed addition to paragraph (g), which is included
in the final rule as proposed.
What well casing and cementing requirements must I meet? (Sec.
250.420)
This section of the existing regulation imposes specific
requirements for casing and cementing of all wells. BSEE proposed to
revise the introductory text
[[Page 25918]]
of this section, to re-designate former paragraph (a)(6) as paragraph
(a)(7), and to insert a new paragraph (a)(6) that requires adequate
centralization to help ensure proper cementation. BSEE also proposed to
add a new paragraph (b)(4), requiring approval by the District Manager
of changes to certain planned casing parameters, as well as a new
paragraph (c)(2), requiring the use of a weighted fluid during
displacement to maintain an overbalanced hydrostatic pressure during
the cement setting time and thus enhance wellbore stability during
cementing. BSEE received and considered comments on proposed paragraphs
(a) and (c) and, as explained in the following responses, has included
proposed paragraph (a) in the final rule without change. BSEE also
included proposed paragraph (c) in the final rule, but revised proposed
paragraph (c)(2) slightly in response to this section's summary of
comments and responses.
Comments Related to Proposed Sec. 250.420(a)--Centralizers
Summary of comments: One comment was submitted by multiple
commenters on the proposed requirement in Sec. 250.420(a)(6) for use
of centralization to ensure proper cementation. It stated that the
proposed requirement needs to be changed to allow for methods other
than centralizers to meet the cementing requirements of this section
because there are instances where using centralizers will actually
increase risk. The commenters provided examples of the need for
centralization, including the inability to ream down casing and the
likelihood of greater casing wear if the pipe is not centered. The
commenters also provided examples, however, of why centralizers should
not be the exclusive method for centralization, including the assertion
that centralizers may increase the chance of pack-off, increase the
number of connections in the casing string (because centralizer subs
are often the only option for centralization), and damage the wellhead
components (due to centralizer pass through). One commenter recommended
the following alternative language: ``Provide adequate centralization
and/or other methods to aid proper cementation to meet well design
objectives within the constraints imposed by hydraulic, operational,
logistical or well architecture limitations (ref. [API] Standard 65-2
2nd Edition.)''
Response: The commenter incorrectly assumes that Sec.
250.420(a)(6) provides for the use of centralizers only. That provision
does not specify or limit how centralization should be achieved. There
are many options to ensure centralization besides the use of
centralizers, and BSEE expects that multiple methods may be required to
ensure adequate centralization. BSEE relies on industry best practices
and industry standards to help determine suitable methods for
centralization while cementing. BSEE also disagrees with the
commenter's recommended inclusion of a reference to API Standard 65-2
(2nd Edition), since a written description of how the operator
evaluated the relevant practices is already required under Sec.
250.415(f) (``What must my casing and cementing programs include?'').
Therefore, no changes to proposed paragraph (a)(6) are necessary, and
BSEE has included that paragraph in the final rule as proposed.
Comments Related to Proposed Sec. 250.420(c)--Cement Compressive
Strength
Summary of comments: One commenter suggested that BSEE increase the
required compressive strength of cement (500 psi) under proposed Sec.
250.420(c)(1) in order to reduce the risk of cement failure, especially
in zones of critical cement where pressures and stresses are higher.
The commenter also recommended adding a requirement for the cement
mixture in the zone of critical cement to meet a 1,200 psi compressive
standard within 72 hours.
Response: BSEE disagrees and has retained the proposed
language requiring 500 psi compressive cement strength, which is the
same as the requirement in the former paragraph (c), in the final rule.
This requirement is also consistent with the provisions in API RP 65
part 2, already incorporated in the existing regulations, and with
industry practice.
Comments Related to Proposed Sec. 250.420(c)(2)--Cementing
Summary of comments: One comment was submitted by multiple
commenters on the requirements in proposed Sec. 250.420(c)(2) for use
of weighted fluids during cementing. The comment stated that the
proposed casing and cementing requirements increase the risk of lost
circulation, which will result in failure to achieve zonal isolation.
The commenter suggested that, if Sec. 250.420(c)(2) refers to
conditions at the center of the well, the language should be revised to
provide: ``You must use a weighted fluid during displacement.''
Response: BSEE agrees with the commenter and has revised
Sec. 250.420(c)(2) in the final rule by clarifying that a weighted
fluid must be used ``during displacement.'' This revision will help
resolve the commenter's concerns about the weighted fluid being in the
center of the well.
What are the casing and cementing requirements by type of casing
string? (Sec. 250.421)
This section of the existing regulation specifies casing and
cementing requirements applicable to certain types of casing strings
(e.g., drive or structural strings, conductor strings). BSEE did not
propose any changes to paragraphs (a) and (c) through (e) of the
existing regulation, which are therefore retained unchanged. BSEE
proposed revising former paragraph (b), however, to specify that if
oil, gas, or unexpected formation pressure is encountered, the operator
must set conductor casing immediately, above the encountered zone, even
if that is before the planned casing point. This proposed provision was
intended to ensure that conductor casing is not placed across a
hydrocarbon zone. BSEE also proposed to revise former paragraph (f) to
eliminate the potential use of liners as conductor casing. This
proposed revision would help ensure that the drive pipe is not exposed
to wellbore pressures. BSEE received and considered comments on
proposed paragraphs (b) and (f) and, as explained in the following
responses, has retained proposed paragraph (b) in the final rule
without change. However, the final rule revises the proposed language
in paragraph (f) as discussed in the following responses and in part
V.C of this document.
Comments Related to Proposed Sec. 250.421(b)--Conductors
Summary of comments: Some comments on proposed Sec. 250.421(b)
requested clarification as to whether the 22-inch and 20-inch casing
used in deepwater operations is considered surface pipe and therefore
subject to regulation under Sec. 250.421(c) (requirements for surface
casing) rather than Sec. 250.421(b) (requirements for conductor
casing). If BSEE agrees with that view, the commenter has no objection
to proposed Sec. 250.421(b) with regard to 20- and 22-inch casing.
A commenter also requested confirmation that drive pipe and jetted
pipe are considered structural pipe and therefore are subject to
regulation under former Sec. 250.421(a) (requirements for drive or
structural casing) rather than the proposed Sec. 250.421(b). If BSEE
agrees with that view, the commenter has no objection to proposed Sec.
250.421(b) with regard to drive pipe and jetted pipe.
[[Page 25919]]
One commenter suggested rewording the proposed revision to the
existing requirement for setting casing immediately upon encountering
oil, gas, or unexpected formation pressure before the planned casing
point. The language of the proposed rule would require the casing to be
set above the encountered zone. While the commenter did not object to
the proposed revision, it suggested deleting the phrase ``before the
planned casing point'' from the former and proposed regulatory text,
and adding to the end of that provision the phrase ``even if it is
before the planned casing point.''
Another commenter suggested a change to a longstanding cementing
requirement in existing (and proposed) Sec. 250.421(b) for
verification of annular fill by observation of cement returns or, when
observation is not possible, by using additional cement to ensure fill-
back to the mudline. The commenter indicated that, due to the long
distances between the platform and the mud line at deepwater locations,
excess hydrostatic cement pressure does not allow for a full column of
cement to reach the platform level, making visual observation
problematic. The commenter suggested that BSEE address this concern by
allowing use of lift pressure calculations or ``tag and circulate'' to
confirm visual evidence of cement location, and by adding language to
the cementing provisions in Sec. 250.421(b) that would require
operators to discuss the cement fill level with the District Manager
when ``drilling in deeper water on fixed structures, where it may not
be feasible to observe cement return.''
Response: BSEE agrees that 20- and 22-inch casing may be
considered surface pipe and, thus, subject to Sec. 250.421(c). BSEE
also agrees that drive pipe and jetted pipe can be considered
structural pipe and, thus, subject to Sec. 250.421(a). Accordingly, no
change to the proposed language in paragraph (b) is necessary on those
points.
BSEE does not agree that the proposed conductor casing requirement
for encounters with oil, gas or unexpected formation pressure that
occur before the planned casing point should be reworded as suggested
by the commenter. The casing requirements under former and proposed
Sec. 250.421(b) state that if oil, gas or unexpected formation
pressure is encountered before the planned casing point, casing must be
set immediately; the only change proposed by BSEE to paragraph (b) was
to clarify that, in such a case, the casing must be set above the
encountered zone. BSEE does not believe that the commenter's suggested
rephrasing would add any extra clarity or change the meaning of the
proposed language in any useful way.
Finally, BSEE did not propose any changes to the existing cementing
requirements for conductors. As described previously, the proposed
change to Sec. 250.421(b) clarifies the location where conductor
casing must be set if the operator encounters oil or gas or unexpected
formation pressure before the planned casing point; i.e., above the
encountered zone. In any case, BSEE does not agree with the suggested
revision to the cementing requirements with regard to deepwater
drilling. Current cementing requirements, as reflected in former and
proposed Sec. 250.421(b), already provide that if visual observation
of cement returns from the annular is not possible, additional cement
must be added to ensure cement returns to the mudline. To date, BSEE is
unaware of any actual problems from applying that practice reflected in
the regulation to fixed platforms drilling in deeper water; thus, there
is no need to add the language suggested by the commenter. If any
actual problems with that approach arise in the future, the operator
should consult the District Manager regarding appropriate action and,
if warranted, request approval of alternative procedures or equipment
under Sec. 250.141.
Comments Related to Proposed Sec. 250.421(f)--Casing and Liners
Summary of comments: With regard to proposed Sec. 250.421(f)--
revising existing casing requirements for liners by prohibiting use of
liners as conductor casings--commenters raised concerns about how
casing would be treated in deepwater riserless operations. One
commenter suggested that the cementing requirements should apply to
surface wellhead systems where structural casing extends back to the
surface facility, and stated that conductor liner is an effective
option for use as casing in mud line suspension completion systems. The
commenter suggested that BSEE add the following text to Sec.
250.421(f):
A casing string whose top is above the mudline and that has been
cemented back to the mudline will be not considered a liner. When
conductor liner systems are needed in special applications, such as
mud line suspension systems or drilling only applications, you must
receive approval from the District Manager. You may not use a liner
as conductor casing when surface wellhead systems are in use without
mud line suspension systems and the structural casing extends back
to the surface facility.
In support of the suggested change, the commenter stated that, for
deepwater operations, this language would allow large outside diameter
conductor hung in the supplemental wellhead adapter to be used as
intended (i.e., as a conductor) without being considered a liner
subject to the liner cementing requirements.
Response: BSEE agrees with the commenter that when the
casing string top is above the mudline and has been cemented back to
the mudline, the casing string should not be considered a liner.
Accordingly, to clarify this intent, BSEE has revised the casing
requirements in final Sec. 250.421(f) to state that ``[a] subsea well
casing string whose top is above the mudline and that has been cemented
back to the mudline will not be considered a liner.'' BSEE also agrees
with the commenter that a large outside diameter conductor hung in the
supplemental wellhead adapter should not be considered a liner. No
change to the language of paragraph (f) is necessary on this point.
Comments Related to Proposed Sec. Sec. 250.421(b) and (f)--
Centralizing Casing
Summary of comments: One commenter supported the proposed new
requirements in Sec. Sec. 250.421(b) and (f), but suggested that BSEE
add more specific instruction on how to centralize casing (e.g., by
specifying centralization requirements according to casing type). The
commenter stated that if casing inside the well is not properly
centralized, it will have thinner cement, or possibly no cement, where
the pipe is near or in contact with the earthen wall. The commenter
noted that thin areas of cement are easily cracked and damaged. The
commenter noted further that cement that is not well-bonded to the
outside of the casing or earthen hole, or that is damaged by subsequent
well activities, creates a conduit for hydrocarbon movement, which
increases the risk of losing well control. The commenter suggested
that, at a minimum, surface casing should be centralized at the shoe
and at every fourth casing joint and that intermediate and surface
casing should be centralized at the base and top and at every tenth
casing joint.
The commenter also suggested that additional centralizers should be
used in highly deviated well sections. This commenter also recommended
that BSEE change the proposed regulation to require that: (a) The
surface casing be set deep enough to provide a competent structure to
support the BOP and to contain any formation pressures that may be
encountered before the next
[[Page 25920]]
casing is run; (b) the entire surface casing annulus should be cemented
to the surface (presumably the mudline); and (c) the surface casing
must stop above any significant pressure zone or hydrocarbon zone to
ensure the BOP can be installed prior to drilling into a pressure zone
or into hydrocarbons.
Response: BSEE agrees with the comment that requiring
centralization will increase the probability of a successful and
effective cement job. However, BSEE does not agree that centralization
requirements should be included in Sec. 250.421, as suggested by the
commenter. BSEE proposed, and Sec. 250.420(a)(6) of the final rule
requires, adequate centralization (which does not mean the use of
centralizers only) to ensure proper cementing programs. In addition,
final Sec. 250.420(a)(7)--formerly Sec. 250.420(a)(6)--already
requires that operators submit certifications signed by registered PEs
that the casing and cementing design is appropriate and sufficient.
These provisions will help ensure that casing is properly centralized.
In addition, existing Sec. 250.415(f) requires that the cementing and
casing programs included in the APD describe how the operator uses API
Standard 65--part 2 to evaluate best practices, including best
practices for centralizing casing. This also helps ensure that casing
is properly centralized. Accordingly, BSEE did not propose any changes
to the surface casing provisions under former Sec. 250.421 with
respect to centralization, and no change to the former or proposed
requirements are necessary on this point.
Comments Related to Proposed Sec. 250.421(f)--Liner Lap Length
Summary of comments: A commenter did not agree with the requirement
in proposed Sec. 250.421(f) to have a liner lap length specified for
liners with liner top packers. The commenter stated that liner lap
length requirements in production wells may adversely affect the
ability to complete the well efficiently.
Response: BSEE agrees with the commenter's intent and has
revised the proposed cementing requirements for liners by adding
language to final Sec. 250.421(f) stating that as provided by (d) and
(e), if you have a liner lap and are unable to cement 500 feet above
the previous shoe, you must submit and receive approval from the
District Manager on a case-by-case basis. This revision provides
additional flexibility to ensure that production wells are completed
efficiently.
What are the requirements for casing and liner installation? (Sec.
250.423)
This section of the existing regulation was entitled ``What are the
requirements for pressure testing casing?'' BSEE proposed to change the
former title of this section to more accurately reflect proposed
changes within the section that establish requirements for installing
casings and liners. BSEE also proposed to revise paragraphs (a) through
(c) of former Sec. 250.423 to clarify that liner latching mechanisms,
if applicable, need to be engaged upon successfully installing and
cementing the casing string or liner. These proposed revisions were
intended to reinforce the importance of properly securing liners in
place to ensure wellbore integrity. BSEE received and considered
comments on the proposed revisions and the language in proposed
paragraphs (a) and (b) has been revised as discussed in the following
responses. Proposed paragraph (c), however, is included in the final
rule without change.
Comments Related to Proposed Sec. 250.423(a) and (b)--Ensuring
Lockdown Mechanism Is Engaged
Summary of comments: One commenter recommended that the
introductory sentence in proposed Sec. 250.423--regarding casing and
liner installation--be changed in order to provide greater clarity for
industry.
Multiple commenters raised the concern that the language in
proposed Sec. 250.423(a) and (b) does not define or explain how to
measure success in ensuring that latching/locking mechanisms are
engaged after ``successfully installing and cementing'' the casing
string and liner, respectively. They stated that many systems do not
have a way to ``ensure'' that the lockdown mechanism is properly
engaged; all they can do is ensure that the proper procedures to set
the lockdown mechanism are followed. The commenters recommended that
BSEE remove the word ``successfully'' from Sec. Sec. 250.423(a) and
(b) and say instead that, ``[y]ou must ensure that the latching
mechanisms or lock down mechanisms are engaged upon installation of
each casing string.''
Response: BSEE does not agree that the suggested change to
the introductory sentence in proposed Sec. 250.423 is necessary to
avoid confusion. The commenter did not explain why that sentence is
unclear or why the commenter's suggested change would make the language
clearer. In fact, the introductory sentence in the proposed rule was
exactly the same as the language in existing Sec. 250.423(b), and BSEE
is unaware of any confusion regarding the meaning of that language.
Accordingly, BSEE has not changed that sentence in the final rule.
BSEE agrees with the suggestion that more guidance is needed in
this section for operators to determine when casing strings and liners
have been successfully installed and cemented. Therefore, we have
revised proposed Sec. 250.423(a) and (b) in this final rule to include
references to the cementing requirements of Sec. 250.428(c). In
effect, the latching mechanisms or lock down mechanisms must be engaged
upon successfully installing and cementing the liner. If the operator
determines under Sec. 250.428(c) that the cement job is adequate
(i.e., successful), then the latching/locking mechanisms should be
engaged. If there are indications of an inadequate cement job, actions
should be taken in accordance with Sec. 250.428 to ensure proper
cementation before the latching or locking mechanisms are engaged.
Comments Related to Proposed Sec. 250.423(c)--Proper Casing or Liner
Installation
Summary of comments: One commenter suggested that BSEE add a new
requirement to Sec. 250.423(c) for monitoring and verification of
make-up and torqueing of casing and tubular connections. The commenter
suggested the use of torque/turn evaluation equipment when installing
production casing and tubing to confirm that thread mating has been
performed according to applicable specifications.
Response: BSEE does not agree that these suggested changes
are necessary to ensure proper installation of casing and tubing. BSEE
already requires a pressure test on the casing seal assembly under
former Sec. 250.423(b)(3)--now Sec. 250.423(c)--and submittal to BSEE
of both the test procedures and test results, in order to verify the
integrity of the casing and connections. Therefore, no additional
language is needed to help confirm casing integrity.
What are the requirements for prolonged drilling operations? (Sec.
250.424)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.722. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
What are the requirements for pressure testing liners? (Sec. 250.425)
BSEE proposed to reserve and remove this section and to move the
content of
[[Page 25921]]
this former section to proposed Sec. 250.721. BSEE received no
comments on the proposed removal and reservation of this section and
the final rule takes that action.
What are the recordkeeping requirements for casing and liner pressure
tests? (Sec. 250.426)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.746. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
What are the requirements for pressure integrity tests? (Sec. 250.427)
This section of the existing regulation requires pressure integrity
testing below the surface casing or liner and at certain drilling
intervals. BSEE proposed to revise former paragraph (b) of this section
to clarify that operators must maintain the safe drilling margins
required by proposed Sec. 250.414. Although BSEE received and
considered comments on this proposed requirement, the final rule
includes this paragraph as proposed for the reasons discussed in the
following responses.
Comments Related to Proposed Sec. 250.427(b)--Safe Drilling Margin
Summary of comments: Multiple commenters raised the concern that
changing the casing design for wells in order to maintain the safe
drilling margins specified in proposed Sec. 250.414 could make some
wells uneconomical, due to the need for smaller completions and thus,
potentially uneconomical production rates.
Although BSEE only proposed a minor change to existing Sec.
250.427 (i.e., adding a cross-reference in paragraph (b) to the new
safe drilling margin provisions in proposed Sec. 250.414), these same
commenters also raised concerns with the existing requirement in Sec.
250.427(b) that safe drilling margins must be maintained and that
drilling must be suspended and the situation remedied when the drilling
margins cannot be maintained. The commenters stated that suspending
drilling to set pipe based on the proposed 0.5 ppg safe drilling
margin--which they considered a legacy drilling margin from shallow
shelf wells--would have severe negative consequences for many deepwater
or depleted zone wells being drilled today and to be drilled in the
future. In addition, the commenters claimed that maintaining the
proposed 0.5 ppg safe drilling margin may require so many additional
casing strings that it could hinder many deeper well designs in that
they would no longer have the capability to run additional casing
strings as needed to meet the applicable containment requirements. All
commenters on this issue recommended that BSEE revise the second
sentence in Sec. 250.427(b) to state that ``[w]hen you cannot maintain
the safe margins, you must suspend drilling operations and remedy the
situation in accordance with accepted industry practices as documented
in API Bulletin 92L or as otherwise approved by the District Manager.''
Two of the commenters also suggested that BSEE require the operator to
assess risk in addition to receiving District Manager approval for the
remedial activity.
Response: As discussed elsewhere in this document (see
part V.B.1), based on other comments BSEE has revised the safe drilling
margin requirements in final Sec. 250.414 to provide operators more
flexibility in determining a proper safe drilling margin. The revisions
to that section resolve most, if not all, of the concerns raised by the
commenters in connection with proposed Sec. 250.427. In this final
rule, BSEE is not specifying how the operator must remedy the situation
when the safe drilling margin cannot be maintained. Accordingly, BSEE
has not made the changes to proposed Sec. 250.427 requested by the
commenters. However, BSEE will evaluate API Bulletin 92L and, if BSEE
determines that it is appropriate to require application of that
standard to remedial actions when safe drilling margins cannot be
maintained, BSEE may propose incorporating that standard in the
regulations in a separate rulemaking.
What must I do in certain cementing and casing situations? (Sec.
250.428)
This section of the existing regulation describes actions that must
be taken when certain situations (e.g., unexpected formation pressures)
are encountered during casing or cementing operations. BSEE did not
propose changes to paragraph (a) or paragraphs (e) though (i). BSEE
proposed to revise paragraph (b) of this section to require District
Manager approval for proposed hole interval drilling depth changes
(greater than 100 feet total vertical depth), and submittal of a
certification that a PE has reviewed and approved the proposed changes.
These proposed requirements were intended to assist BSEE in verifying
the actual well conditions.
BSEE also proposed to revise former paragraph (c), to clarify the
requirements for actions that must be taken if there is an indication
of an inadequate cement job, and former paragraph (d), clarifies that
if the cement job is inadequate, the District Manager must approve all
proposed remedial actions (except immediate action to ensure safety or
to prevent a well-control event). In addition, BSEE proposed to add
paragraph (k) (concerning the use of valves on drive pipes during
cementing operations for the conductor casing, surface casing, or
liner), to require certain actions to assist BSEE in assessing the
structural integrity of the well. After consideration of comments on
these proposed revisions, BSEE has included proposed paragraphs (b),
(c), and (d) in the final rule without change. However, as discussed in
the following responses, BSEE has revised the language of proposed
paragraph (k) in the final rule.
Comments Related to Proposed Sec. 250.428(b)--Changing Casing Setting
Depths or Hole Interval Drilling Depth
Summary of comments: One commenter raised concerns that the
proposed changes to existing Sec. 250.428(b), which specifies what
operators must do when they need to change casing setting depths or
hole interval drilling depths, would be too restrictive. The commenter
asserted that if the requirement was limited to changes that exceed 300
feet TVD--instead of 100 feet TVD as proposed--it would minimize
unnecessary resubmittals of proposed changes to District Managers for
approval and certifications of the proposed changes by PEs.
Response: BSEE does not agree with this comment. Changing
the requirement in Sec. 250.428(b) from 100 feet TVD to 300 feet TVD
would adversely affect the source control and containment capabilities
required by Sec. 250.462(a) since it could affect the performance and
integrity of the well as designed and affect the determination of
whether a full shut-in can be achieved. Accordingly, BSEE made no
changes in the final rule to the proposed language of paragraph (b) in
response to this comment.
Comments Related to Proposed Sec. 250.428(b) and (d)--PE Certification
Summary of comments: Multiple commenters raised concerns with the
requirement in proposed Sec. 250.428(b) and (d) that a PE certify that
he or she has reviewed and approved proposed changes to casing setting
depths as well as proposed changes to the well program to remedy an
inadequate cement job. The commenters asserted that PE certification of
proposed changes to casing setting depths should be required only if
those changes would
[[Page 25922]]
affect the effectiveness of a barrier or if the change in the casing
setting depth would lead to a significant change in the cementing
program (e.g., exposure of an additional hydrocarbon zone).
In case of an inadequate cement job, the commenters recommended
that BSEE require that: (1) The operator submit a remedial action plan
that includes immediate action and planned future action; (2) the
District Manager approve the remedial action, unless immediate actions
must be taken to ensure the safety of the crew or to prevent a
well[hyphen]control event; (3) if the operator completes any unapproved
immediate action to ensure the safety of the crew or to prevent a
well[hyphen]control event, the operator must submit a description of
the action to the District Manager when that action is complete; and
(4) any changes to the well program (implicitly including casing or
cement programs) that can impact the effectiveness of the barrier will
require a certification by a PE that he or she reviewed and approved
the proposed changes, and the changed well programs must meet any other
requirements of the District Manager.
One commenter also requested that BSEE clarify whether the PE
certifications required by Sec. 250.428 refer only to changes to the
casing design and primary cementing plans and not to proposed changes
included in an APM. The commenter suggested revising the PE
certification language in that paragraph to read: ``certifying that the
PE reviewed and approved the revised casing and/or cement program.''
Response: BSEE does not agree that any of the changes to
proposed Sec. 250.428 suggested in these comments are necessary. BSEE
does not agree that PE certifications for changes to casing setting
depths should only be required when such changes would degrade barrier
effectiveness. Changes to the casing setting depths could also affect
the performance and integrity of the well as designed and
determinations as to whether a full shut-in can be achieved. In
addition, PE certification provides additional QA/QC and helps ensure
that the actions are appropriate for the specific well. If an operator
has any questions about what specific changes the PE must certify, the
operator may contact the appropriate District Manager.
BSEE agrees, however, with the commenter's request that we clarify
that the PE certification requirements in proposed Sec. 250.428(b) and
(d) apply only to the changes described in those paragraphs and not to
other changes included in an APM. That is the correct interpretation of
those provisions and no change to the proposed language of those
paragraphs is necessary in the final rule.
Comments Related to Proposed Sec. 250.428(c)--Indications of
Inadequate Cement Job
Summary of comments: Several commenters recommended adding ``lift
pressure analysis'' to the list of actions (i.e., temperature survey,
cement evaluation log, or combination of both) as an alternative method
to determine the adequacy of the cement job under proposed Sec.
250.428(c)(1). The commenters stated that cement lift pressure analyses
are an industry-recognized alternative to cement evaluation logs for
determining the top of cement.
Another commenter stated that the requirements in Sec. 250.428(c)
should be revised so that when a casing shoe is not set in
hydrocarbons, only a shoe test would be required to confirm that the
cement job was successful. On the other hand, the commenter suggested
that if hydrocarbons are present, a shoe test would not be enough to
confirm cement job success, and a combination of other techniques
(including lift pressure analysis, radioactive tracers, and/or cement
bond logging) should be required to confirm job success.
One commenter supported the proposed changes to Sec. 250.428, but
recommended that the diagnostic tests should also be run for all
offshore wells to verify adequate cement placement. The commenter also
recommended that the proposed requirements in Sec. 250.428(d) for
remedying inadequate cement jobs be strengthened to require a repeat
cement evaluation log to verify that the cement repair was successful.
Response: BSEE does not agree that the changes suggested
by these comments are necessary. Lift pressure analysis and a shoe test
by themselves are not conclusive indicators of an adequate cement job,
and the additional techniques (i.e., temperature survey or cement
evaluation log or a combination of both) in Sec. 250.428(c) may be
necessary to assist in locating the top of the cement.
With regard to the comment on strengthening the requirements for
remedial actions in proposed Sec. 250.428(d), there is no need to
specify that a repeat cement evaluation is necessary if there is any
indication that the repair was inadequate. In such a case, Sec.
250.428(c) would still apply, and the actions required by that
paragraph, including a PE certification, must still be taken.
BSEE also does not agree with the suggestion that Sec. 250.428(c)
should apply to all wells, even if there is no indication of an
inadequate cement job. When there is no indication of an inadequate
cement job, the existing requirement to pressure test all casings and
liners (formerly Sec. 250.423, redesignated as Sec. 250.721 in this
final rule) provides a reasonable indication of a good cement job.
Comments Related to Proposed Sec. 250.428(d)--Immediate Action
Reporting
Summary of comments: Regarding the ``immediate action'' reporting
requirement in Sec. 250.428(d), one commenter asked whether there is
an obligation for contractors to provide individual reports or to
verify that such reports have been submitted by the operator. Regarding
the remedial action reporting, another commenter asked whether BSEE had
any expectation that a drilling contractor would submit this report.
Response: As a general matter, BSEE looks to the
designated operator to make filings on behalf of all lessees and owners
of operating rights. This issue is discussed in more detail in part
VI.B.5 of this document.
Comments Related to Proposed Sec. 250.428(k)--Valves Used on the Drive
Pipe
Summary of comments: With regard to proposed Sec. 250.428(k)--
specifying what an operator must do when it plans to use a valve on the
drive pipe during cementing for conductor or surface casings or for
liners--one commenter suggested that the reference to use of a valve
was too limiting. The commenter suggested changing the word ``valve''
to ``barrier.'' This would make the requirements in Sec. 250.428(k)
applicable to pressure caps, stabs, or other barriers in addition to
valves.
The commenter also pointed out that for subsea wells, several
valves are normally used, one for each port; therefore, the proposed
rule should not use the singular word ``valve.'' The commenter also
said that it is common practice to use a secondary barrier (such as a
pressure cap) to supplement a valve (i.e., in case the valve leaks).
Therefore, the commenter recommended that BSEE revise the proposed
requirement that ``[y]our description [of the plan to use a valve] must
include a schematic of the valve and height above the water line . .
.'' to read: ``Your description must include a schematic of the primary
and secondary barriers and height above mud-line. . . .''
Response: BSEE agrees that changing ``valve'' to
``valves'' in Sec. 250.428(k) is appropriate, and has
[[Page 25923]]
revised the final rule accordingly. However, BSEE does not agree that
the other changes suggested by the commenters are necessary. In
proposed, and now final, Sec. 250.428(k), the reference to valves is
limited to valves used to verify visible cement returns, and thus it is
expected that some cement will escape those valves. They do not serve
the same purpose as other barriers.
What are the general requirements for BOP systems and system
components? (Sec. 250.440)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.730. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
What are the requirements for a surface BOP stack? (Sec. 250.441)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. Sec. 250.733 and
250.735. BSEE received no comments on the proposed removal and
reservation of this section and the final rule takes that action.
What are the requirements for a subsea BOP system? (Sec. 250.442)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.734. BSEE received
no comments on the proposed removal and reservation, and the final rule
takes that action.
What associated systems and related equipment must all BOP systems
include? (Sec. 250.443)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. Sec. 250.733, 250.734,
and 250.735. BSEE received no comments on the proposed removal and
reservation, and the final rule takes that action.
What are the choke manifold requirements? (Sec. 250.444)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.736. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
What are the requirements for kelly valves, inside BOPs, and drill-
string safety valves? (Sec. 250.445)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.736. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
What are the BOP maintenance and inspection requirements? (Sec.
250.446)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.739. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
When must I pressure test the BOP system? (Sec. 250.447)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.737. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
What are the BOP pressure tests requirements? (Sec. 250.448)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.737. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
What additional BOP testing requirements must I meet? (Sec. 250.449)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.737. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
What are the recordkeeping requirements for BOP tests? (Sec. 250.450)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.746. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
What must I do in certain situations involving BOP equipment or
systems? (Sec. 250.451)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.738. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
What safe practices must the drilling fluid program follow? (Sec.
250.456)
This section of the existing regulation specifies safe practices
(e.g., proper conditioning of drilling fluid) that must be included in
a drilling fluid program. BSEE proposed no significant changes to
paragraphs (a) through (i) of the existing regulation. However, BSEE
proposed removing paragraph (j) of the existing regulation, re-
designating former paragraph (k) as paragraph (j), and moving the
content of former paragraph (j), which requires District Manager
approval for displacing kill-weight fluid, to proposed Sec.
250.720(b). This was intended to clarify that this requirement applies
to all drilling, workover, completion, and abandonment operations. BSEE
received no substantive comments on this provision of the proposed
rule, and the final rule takes these actions.
What are the source control, containment, and collocated equipment
requirements? (Sec. 250.462)
This section of the existing regulation was entitled ``What are the
requirements for well-control drills?'' BSEE proposed to re-title and
completely revise this section, and to move the contents of former
Sec. 250.462 to proposed Sec. Sec. 250.710 and 250.711. As proposed,
Sec. 250.462 would require the operator to demonstrate the ability to
control or contain a blowout event at the sea floor. Proposed paragraph
(a) would require the operator to determine its source control and
containment capabilities; proposed paragraph (b) would require that
operators have access to, and the ability to deploy, source control and
containment equipment (SCCE) necessary to regain control of the well;
proposed paragraph (c) would require submittal of a description of the
source control and containment capabilities before BSEE approves an
APD; proposed paragraph (d) requires reevaluation by BSEE approval if
certain events occur; and proposed paragraph (e) outlines maintenance,
inspection, and testing requirements for specified containment
equipment. After consideration of comments on the proposed section, and
as explained in the following responses, BSEE has included paragraphs
(a) through (d) in the final rule as proposed. BSEE has, however,
revised the language of proposed paragraph (e) in the final rule.
Comments Related to Proposed Sec. 250.462--Introductory Paragraph
Summary of comments: One commenter recommended that an ``alternate
contingency plan'' be added
[[Page 25924]]
at the end of the introductory paragraph to Sec. 250.462 and also to
the description of SCCE in Sec. 250.462(c)(1) and (c)(3). The
commenter asserted that this would provide an equivalent seabed source
control and containment alternative, and that the proposed rule does
not promote the development of alternative technologies that may be
more effective than traditional responses.
Response: BSEE does not agree with this comment. Companies
are free to design any type of equipment as long as they demonstrate it
has the capability to respond to a loss of well-control situation.
Therefore, no changes are needed to this proposed section in response
to this comment.
Comments Related to Proposed Sec. 250.462(a)--Determining Source
Control and Containment Capabilities
Summary of comments: Several commenters suggested revising proposed
Sec. 250.462(a)(2) to differentiate well designs that can be fully
shut-in from those that can only be partially shut-in, and to require
operators to ``verify,'' rather than to ``determine,'' that a full
shut-in can be achieved. Some of these same commenters also recommended
adding a new paragraph (a)(3) to require that an operator have the
capability to: ``flow and capture the residual fluids to a subsea
well.'' Commenters also suggested that the analyses required in
proposed Sec. 250.462(a)(1) and (2) be bolstered by stating that the
analyses should be performed using the most current version of the well
containment screening tool. Commenters stated that the BSEE-endorsed
well containment screening tool provides the necessary analysis;
operators have used this tool for over four years and submit it with
all affected APDs. Commenters suggest that this currently accepted
practice should be acknowledged and codified.
Response: BSEE disagrees with the suggestion that the rule
should require use of the well containment screening tool. Although the
rule does not require operators to use that tool, it is an acceptable
tool to use for the analyses required in final Sec. 250.462(a)(1) and
(2), and is typically included as a condition in APDs. Similarly, the
other recommended changes to paragraph (a) are not necessary, since use
of the well containment screening tool would lead to essentially the
same results that the commenters' recommendations are intended to
achieve.
Comments Related to Proposed Sec. 250.462(b)--SCCE
Summary of comments: One commenter requested BSEE add subsea device
connections or transition connections from one component to another to
the equipment listed in Sec. 250.462(b) as SCCE. The commenter
asserted that for industry to progressively address safety, efficiency,
timeliness, certainty in methods and systems to contain and capture
reservoir fluid, BOP connections and containment points should be
considered as SCCE.
Response: BSEE does not agree with the requested addition
to proposed paragraph (b). The equipment requirement that the commenter
recommends adding to this provision is already addressed in the APD and
the well containment screening tool. BSEE will not approve an APD
unless the operator ensures that it has the equipment needed. BSEE does
not specify what equipment is to be used for a given scenario under
final Sec. 250.462(b); that provision requires only that the equipment
be accessible and capable of responding to an oil spill.
Summary of comments: Some commenters requested other changes to
proposed Sec. 250.462(b), asserting that SCCE requirements should be
specific to each well and that cap and flow equipment should not be
required for wells that are specifically designed for shut-in on a full
hydrocarbon column. Among other things, the commenters requested that
BSEE clarify that SCCE means the capping stack, cap and flow system,
and ``(where applicable . . . , containment dome (i.e., localized, non-
pressurized, subsea fluids collection device),'' and that cap and flow
systems (including containment domes) are not required for wells that
are designed for shut-in on a full column of hydrocarbons.
Response: BSEE does not agree that the requested changes
are necessary. The initial screening of a well might indicate that it
can be fully shut-in, but the operator should always have the equipment
necessary and available if something happens that would change the
outcome of the situation from a full shut-in to a cap and flow
scenario. The initial screening presents a model outcome based on what
is known at the time that the APD is submitted. BSEE realizes there is
always the potential that, although the results of the initial
screening indicate that the well could be controlled through a full
shut-in (capping only), the well could actually require cap and flow if
an actual loss of well control were to occur. BSEE wants to ensure that
the operator is prepared for this situation and has all of the assets
that may be needed available to respond to a loss of well control.
Comments Related to Proposed Sec. 250.462(c)--Description of Source
Control and Containment Capabilities
Summary of comments: Regarding proposed Sec. 250.462(c),
commenters raised questions and recommended wording changes. Three
commenters stated that industry already submits the required documents
with each permit application (RP checklist) and suggested that the
Regional Containment Demonstration (RCD), once approved, would satisfy
the new requirements. Other commenters suggested retaining flexibility
for containment capabilities (i.e., pre-installed capping device for
spar and TLPs, in-situ burning and dispersants) and suggested that BSEE
revise Sec. 250.462(c)(1) to allow an ``approved alternate contingency
plan'' as an alternative to a description of containment capabilities
for controlling and containing a blowout event at the seafloor.
Commenters also suggested that BSEE change proposed Sec. 250.462(c)(3)
to allow ``other approved contingency plan equipment'' as an
alternative to information showing that the operator has access to and
ability to deploy all equipment required by paragraph (b).
Response: BSEE agrees that the RCD may indicate source
control and containment capabilities, but operators should not assume
that pre-installed containment equipment (i.e., pre-installed capping
device) will work. This equipment is located on the rig and does not
replace a capping stack, which is located elsewhere and can be used in
the event that the equipment located on the rig fails. Therefore, BSEE
requires operators to demonstrate that they are ready to respond with
additional equipment (i.e., capping stack), if necessary. Moreover,
subsea dispersant equipment are not considered source control or
containment devices, but rather equipment that is collocated and
deployed alongside SCCE operations. Accordingly, BSEE does not agree
with the recommended changes to proposed Sec. 250.462(c).
Comments Related to Proposed Sec. 250.462(d)--Notification of BSEE
Summary of comments: Some commenters requested a change to the
requirements in proposed paragraph (d) to advise BSEE of any well
design change and to suspend operations until the required out-of-
service SCCE is repaired or replaced. The commenters asserted that the
proposed requirement to advise BSEE of any well design change will pose
an undue burden on both the operator and BSEE. They also claimed that
it is important to clarify
[[Page 25925]]
that only well design changes which negatively impact the results of
the well containment screening tool require notification to BSEE. They
also suggested that a risk-based approach should be adopted, that risk
should be managed to the lowest possible level, and that if BSEE's
regional representatives are not satisfied that the risk justifies
continuing operations, then operations should be halted and the permit
withdrawn. Therefore, the commenters suggested that BSEE revise
proposed Sec. 250.462(d)(1) to set conditions on when BSEE should be
advised of well design change; i.e., that BSEE should be advised only
in the event of ``any changes in the well design or well conditions
that require a revised permit to drill to be submitted and can impact
the results of the well containment screening tool.''
One commenter also recommended that, since proposed Sec.
250.462(d)(2) would require the operator to contact the BSEE Regional
Supervisor to reevaluate source control and containment capabilities if
required SCCE is out of service, the operator should be required to
secure the well and suspend drilling operations until the SCCE
equipment is repaired or replaced and returned to full active service.
Response: BSEE does not agree that any change to proposed
paragraph (d) is warranted by these comments. BSEE will require
notification if there are any well design changes. However, BSEE is not
specifying the approach to be used for reevaluation of source control
and containment capabilities; the well containment screening tool
mentioned by the commenter would be acceptable in most circumstances.
The notifications for the well design changes must be submitted at the
time the operator submits a revised permit. BSEE will evaluate, on a
case-by-case basis, whether there is adequate equipment available if
the SCCE is out of service, and will then determine if the operator
needs to suspend drilling operations.
Comments Related to Proposed Sec. 250.462(e)--Maintaining, Testing,
and Inspecting SCCE
Summary of comments: BSEE received several comments on the cap and
flow requirements in proposed Sec. 250.462(e). In general, the
comments stated that it is not necessary to have ``cap and flow''
capacity if a capping stack is capable of achieving a complete shut-in
of the well. The commenters also stated that if an operator's
evaluation, using the BSEE-endorsed well containment screening tool,
indicates that a wellbore can be completely shut-in while maintaining
full integrity, then cap-and-flow well design and equipment should not
be required for the permit. The commenters suggested, however, that the
cap-and-flow well design and equipment should be required for permit
approval if the well containment screening tool indicates loss of
wellbore integrity when attempting a complete shut-in. Another comment
concerning the maintenance, testing, and inspection of SCCE, as
required in proposed Sec. 250.462(e), suggested that BSEE should use
the API terminology of ``pressure containing,'' rather than the
proposed ``pressure holding,'' to eliminate the possibility of
misinterpretation. It was also suggested that BSEE consider referring
to API RP 17W in paragraph (e) to provide more clarity regarding
documentation, document retention, and reporting requirements in the
proposed table of requirements.
Response: Operators should always be ready to respond to a
discharge or loss of well control requiring cap and flow response
elements, even if the initial screening suggests that the wellbore can
be fully shut-in. However, BSEE agrees that the terminology change
suggested by the commenters (replacing ``pressure holding'' with
``pressure containing'') will improve consistency with current industry
usage and provides a better description of the purpose of the
equipment. Accordingly, BSEE included that revision in final Sec.
250.462(e).
We do not agree, however, that API RP 17W should be incorporated in
the final rule at this time. BSEE did not propose to incorporate that
standard and, although we may consider this document for incorporation
in the future, using the evaluation process previously described, if we
decide it is appropriate to incorporate that standard, we will do so
through a separate rulemaking.
Comments Related to Proposed Sec. 250.462(e)--Testing SCCE
Summary of comments: Commenters provided specific comments on, and
recommended revisions to, proposed Sec. 250.462(e), suggesting that
BSEE develop alternative testing methods and frequencies that will
provide an equivalent or greater degree of verification. Some comments
also addressed how pressure testing should be witnessed. Several
commenters suggested that there should only be one witness during
pressure testing to avoid duplication and the spending of unnecessary
resources. Commenters suggested that the witness should be either BSEE
or a BAVO, but not both.
One commenter stated that the required function testing of capping
stacks should be conducted quarterly, and that pressure testing of all
critical capping stack components should be conducted on a biennial
basis.
Commenters also suggested changes to the proposed paragraph (e) to
implement their comments, including changing ``pressure holding
critical components'' to ``pressure containing critical components, and
changing the proposed witnessing requirement to allow witnessing by
BSEE ``and/or an independent third-party.''
Response: As discussed in the previous response, BSEE has
agreed to change ``pressure holding critical components'' to ``pressure
containing critical components'' in the final rule. This change
provides a better description of the purpose of the equipment. BSEE has
also addressed the concerns the commenters expressed on the use of
BAVOs elsewhere in this document, in regard to Sec. Sec. 250.731 and
250.732 and other BAVO-related provisions. BSEE disagrees with the
suggestion that the proposed requirement that both BSEE and a BAVO
witness the pressure tests be revised to require the presence of only
one or the other. It is important for BSEE and a BAVO to witness all
pressure testing, whenever it is possible for BSEE to be present.
Although BSEE may not be available to witness every test, BSEE expects
that it will witness a pressure test and a function test at least once
per year. Therefore, BSEE has determined that is necessary to require a
BAVO to witness every pressure test so that BSEE can be assured that
every test is performed correctly. BSEE has also slightly revised the
language in final Sec. 250.462(e)(1)(ii) to clarify that if a BSEE
representative is not available, the test may be witnessed by a BAVO
alone.
Comments Related to Proposed Sec. 250.462(e)(2)(i)--Production Safety
Systems Used for Flow and Capture Operations
Summary of comments: Several commenters suggested changes to the
Sec. 250.462(e)(2)(i) requirements for production safety systems used
for flow and capture operations. The commenters stated that subpart H
of part 250 (Sec. Sec. 250.800 through 250.808) includes requirements
for items below the wellhead (i.e., subsurface valves) that do not
encompass source control equipment. They recommended the following
change in the proposed text of paragraph (e)(2)(i): ``Meet the
[[Page 25926]]
requirements set forth in Sec. 250.800 through 250.808, Subpart H,
excluding equipment requirements that would be installed below the
wellhead or that are not applicable to the cap-and-flow system.''
Response: BSEE agrees with the commenter that this
provision should not apply to downhole safety systems and has revised
the final rule to exclude equipment below the wellhead.
Comments Related to Proposed Sec. 250.462(e)(3)--Inspection of Subsea
Utility Equipment
Summary of comments: Several commenters suggested BSEE should
define the expectations for inspection of subsea utility equipment in
Sec. 250.462(e)(3). They asserted that subsea utility equipment--such
as debris removal kits, hydraulic power units, coiled tubing, hydrate
control, and dispersant injection equipment,--is in common use as
provided by contractors and specific equipment is not designated in
those retainer agreements. They suggested revising the language in
proposed paragraph (e)(3) to more clearly define the scope of equipment
that needs to be available for inspection, as follows: ``Subsea utility
equipment, requirements, you must: Have all equipment utilized uniquely
for containment operations available for inspection at all times.''
Response: BSEE agrees that the nature of the equipment
that the operator needs to make available to BSEE for inspection can be
better defined. Accordingly, BSEE has decided to revise the requirement
in final Sec. 250.462(e)(3) to state, ``[h]ave all referenced
containment equipment available for inspection at all times.'' BSEE
also revised this section to include a parallel provision for
collocated equipment. If the equipment is in use for other normal
operations, BSEE expects that it would inspect similar equipment
provided by the same contractor (i.e., coiled tubing).
When must I submit an application for permit to modify (APM) or an end
of operations report to BSEE? (Sec. 250.465)
This section of the existing regulation specifies circumstances
that require an operator to submit an APM or EOR (Form BSEE-0125) and
the timeframes for doing so. BSEE did not propose any changes to this
section of the existing regulation, except former paragraph (b)(3).
Accordingly, the remainder of former Sec. 250.465 is retained in the
final rules without change. BSEE proposed to revise former paragraph
(b)(3) to clarify that, if there is a revision to the drilling plan,
major drilling equipment change, or a plugback, the operator must
submit an EOR within 30 days after completing the work. This proposed
provision was intended to help ensure that BSEE has current well
information. BSEE received no substantive comments on proposed
paragraph (b)(3), and the final rule includes that paragraph as
proposed.
Comments Related to Proposed Sec. 250.465--Timeliness and Consistency
of BSEE Action on Permit Applications
Summary of comments: Although the only revision to Sec. 250.465
that BSEE proposed was to former Sec. 250.465(b)(3), regarding
submittal of EORs (i.e., to incorporate the new EOR requirements in
proposed Sec. 250.744), one commenter raised general concerns
regarding the timeliness and consistency of BSEE action on permit
applications. The commenter stated that, although operators strive to
submit permit applications well in advance of planned operations, BSEE
engineers are not able to timely process new applications. Frequently
BSEE is reviewing new permit requests just prior to a rig arriving, or
after a rig is already on location, sometimes just before operations
would have begun. The commenter also asserted that final approval of
APDs and APMs is often received after operations begin, resulting in
updated regulatory stipulations or changes to plans which can lead to
non-compliance issues, confusion between parties, and could result in
increased operational risks.
Response: BSEE understands the concerns raised by these
comments and is making efforts to improve the timeliness of its review
and approval of APDs and APMs. With regard to this rulemaking, however,
because these comments are outside the scope of the proposed rule, BSEE
has not made any revisions concerning APM or APD submittals or
approvals. Final paragraph (b)(3) requires submission of EORs within 30
days of completing work and does not address the submission of permit
applications.
What records must I keep? (Sec. 250.466)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.740. BSEE received
no substantive comments on this provision, and the final rule takes
that action.
How long must I keep records? (Sec. 250.467)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.741. BSEE received
no comments on the proposed removal and reservation, and the final rule
takes that action.
What well records am I required to submit? (Sec. 250.468)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. Sec. 250.742 and
250.743. BSEE received no comments on the proposed removal and
reservation, and the final rule takes that action.
What other well records could I be required to submit? (Sec. 250.469)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.745. BSEE received
no comments on the proposed removal and reservation, and the final rule
takes that action.
Subpart E--Oil and Gas Well-Completion Operations
General Requirements (Sec. 250.500)
This section of the existing regulation requires that well-
completion operations be conducted in a way that protects human and
animal life, property, OCS natural resources, National security and the
environment. BSEE proposed to revise this section by adding language
requiring operators to follow the applicable requirements of proposed
new Subpart G (in addition to Subpart E). BSEE also proposed to replace
the word ``shall'' with ``must'' throughout this section in order to
clarify that the provision is mandatory. BSEE received no substantive
comments on these proposed revisions to the existing regulation and has
made no changes to the proposed language in the final rule.
Equipment Movement (Sec. 250.502)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.723. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
Crew Instructions (Sec. 250.506)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.710. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
Well-control Fluids, Equipment, and Operations (Sec. 250.514)
This section of the existing regulation requires that well-control
fluids, equipment, and operations be designed,
[[Page 25927]]
used, maintained and tested to control the well under foreseeable
conditions. BSEE did not propose any changes to this section except
proposing to remove paragraph (d) of the existing regulation and move
its content to proposed Sec. 250.720. BSEE received no substantive
comments on this proposed revision and the final rule takes that
action.
What BOP information must I submit? (Sec. 250.515)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. Sec. 250.731 and
250.732. BSEE received no comments on the proposed removal and
reservation of this section, and the final rule takes that action.
Blowout Prevention Equipment (Sec. 250.516)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. Sec. 250.730, 250.733,
250.734, 250.735, and 250.736. BSEE received no comments on the
proposed removal and reservation of this section, and the final rule
takes that action.
Blowout Preventer System Tests, Inspections, and Maintenance (Sec.
250.517)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. Sec. 250.711, 250.737,
250.738, 250.739, and 250.746. BSEE received no comments on the
proposed removal and reservation of this section, and the final rule
takes that action.
Tubing and Wellhead Equipment (Sec. Sec. 250.518--Completion
Operations and 250.619--Workover Operations)
These sections of the existing regulation provide requirements for
placement of tubing strings, periodic evaluation of casing subject to
prolonged operations, and monitoring of casing pressure for completions
and workovers, respectively. BSEE proposed to remove former paragraph
(b) from both sections (and to redesignate the remaining paragraphs
accordingly); and to add new paragraphs (e) and (f) to both sections.
Those new paragraphs would apply to packers and bridge plugs and
require adherence to newly incorporated API Spec. 11D1, Packers and
Bridge Plugs; clarify criteria production packer setting depths; and
require that an APM include a description of, and calculations for
determining, the production packer setting depths. After consideration
of comments on the proposed revisions, BSEE has removed former
paragraphs (b) from both sections in the final rule; has included
paragraph (f), as proposed, in both final sections; and has revised the
proposed language in paragraph (e) of Sec. Sec. 250.518 and 250.619,
as discussed in the following responses and in part V.C of this
document.
Comments Related to Proposed Sec. Sec. 250.518 and 250.619--Packers
and Bridge Plugs
Summary of comments: Certain commenters stated that compliance with
API Spec. 11D1 should not be required for temporary packers and bridge
plugs (i.e., those used for well servicing). Commenters stressed that
API Spec. 11D1 does not apply to temporary packers and bridge plugs.
Commenters also had concerns about the proposed requirements in
Sec. Sec. 250.518(e) and 250.619(e) for setting depth and location of
the packers. For example, the commenters were concerned that the
regulations could require setting the packers as close as possible to
the perforated interval and within the cemented interval of the casing
section.
One commenter asked BSEE to clarify whether the requirements in
proposed Sec. Sec. 250.518 and 250.619 would apply only to packers and
bridge plugs installed after the rule takes effect, or whether they
would also apply to packers and plugs already installed before the
rules take effect.
Response: BSEE agrees with the commenters that the API
standard itself does not apply to temporary plugs and packers, and thus
that these regulations should only require compliance with API Spec.
11D1 for permanent packers and bridge plugs. Accordingly, BSEE has
revised the text in paragraphs (e)(1) of final Sec. Sec. 250.518 and
250.619 to reflect that the requirement applies only to permanently
installed packers and bridge plugs.
BSEE understands the concerns about the production packer setting
requirements. However, BSEE wants to ensure that the packer is set as
required in this section in order to help ensure long term equipment
reliability. For example, setting a packer in a cemented interval will
slow down deterioration that could occur in other settings and thus
will prolong the effectiveness of the packer. Also, BSEE wants to
ensure that the packer is not set too high, so that, if there is a
problem with the packer in the well (e.g., a leak), operators will have
enough space above the packer to pump a sufficient volume of weighted
fluid into the well to exert a hydrostatic force greater than the force
created by the reservoir pressure below the packer. If there are any
concerns about the specific packer setting depth in any given case, the
operator may contact the appropriate District Manager for guidance.
Finally, BSEE agrees that final Sec. Sec. 250.518 and 250.619 are
applicable only to packers and bridge plugs installed after the
effective date of the final rule, and they do not require removal and
replacement of existing packers and bridge plugs already in use. We
slightly revised final Sec. 250.518(e) to further clarify that intent;
no change to final Sec. 250.619(e) is necessary since that language is
already clear on this point.
Subpart F--Oil and Gas Well-Workover Operations
General Requirements (Sec. 250.600)
This section of the existing regulation requires workover
operations to be conducted in a way that protects human and animal
life, property, OCS natural resources, National security and the
environment. BSEE proposed no changes to this section except proposing
to add a requirement for operators to follow the applicable provisions
of new subpart G (in addition to subpart F). BSEE received no
substantive comments on this proposed revision, and the final rule adds
the proposed language to final Sec. 250.600.
Equipment Movement (Sec. 250.602)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.723. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
Crew Instructions (Sec. 250.606)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.710. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
Well-Control Fluids, Equipment, and Operations (Sec. 250.614)
BSEE proposed to remove paragraph (d) of this former section and to
move it to proposed Sec. 250.720. BSEE received no substantive
comments on this provision of the proposed rule and the final rule
takes that action.
What BOP information must I submit? (Sec. 250.615)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. Sec. 250.731 and
250.732. BSEE received no comments on the proposed removal
[[Page 25928]]
and reservation of this section, and the final rule makes that change.
Coiled Tubing and Snubbing Operations (Sec. 250.616)
This section of the existing regulation was entitled ``Blowout
Prevention Equipment'' and provided criteria for design, use,
maintenance, and testing of BOPs and related well-control equipment.
BSEE proposed to re-title Sec. 250.616 as ``Coiled tubing and snubbing
operations,'' to remove paragraphs (a) through (e) of the former
section, and to move the content of those sections to final Sec. Sec.
250.730 and 250.733 through 250.736. BSEE also proposed to re-designate
former paragraphs (f) through (h) as paragraphs (a) through (c) without
changing the contents of those paragraphs. As proposed, redesignated
paragraph (a) sets minimum requirements for coiled tubing equipment and
operations; redesignated paragraph (b) sets certain requirements for
BOP system components for workover operations with a tree in place; and
redesignated paragraph (c) requires that an inside BOP or certain types
of safety valves be maintained on the rig floor during workovers. BSEE
received no substantive comments on this provision of the proposed rule
and final Sec. 250.616 includes the proposed changes without
additional revision.
Blowout Preventer System Testing, Records, and Drills (Sec. 250.617)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. Sec. 250.711, 250.737,
and 250.746. BSEE received no comments on the proposed removal and
reservation of this section, and the final rule takes that action.
What are my BOP inspection and maintenance requirements? (Sec.
250.618)
BSEE proposed to reserve and remove this section and to move the
content of this former section to proposed Sec. 250.739. BSEE received
no comments on the proposed removal and reservation of this section,
and the final rule takes that action.
Subpart G--Well Operations and Equipment
General Requirements
What operations and equipment does this subpart cover? (Sec. 250.700)
As provided for in the proposed rule, this new section explains
that subpart G applies to drilling, completion, workover, and
decommissioning activities and equipment. BSEE received no substantive
comments on this provision of the proposed rule and has made no changes
to the proposed language in the final rule.
May I use alternate procedures or equipment during operations? (Sec.
250.701)
May I obtain departures from these requirements? (Sec. 250.702)
As provided for in the proposed rule, Sec. Sec. 250.701 and
250.702 add provisions to new Subpart G acknowledging operators'
ability to request BSEE approval of alternative procedures or equipment
and to request departures from operating requirements in accordance
with existing Sec. Sec. 250.141 and 250.142, respectively. BSEE has
considered the comments submitted on these proposed sections, and as
explained in the following responses, the final rule includes these
sections without change.
Comments Related to Proposed Sec. Sec. 250.701 and 250.702--Alternate
Procedures or Equipment and Departures
Summary of comments: Multiple commenters raised concerns about such
requests. In particular, some commenters claimed that some of BSEE's
past decisions on alternatives and departure requests were not
consistent across all districts.
Another commenter asserted that the proposed rule is unclear about
when it would be appropriate for BSEE to allow a departure from the
well operations and equipment regulations in subpart G. The commenter
stated that the reasons for granting a departure are not specified in
existing Sec. 250.142 or proposed Sec. 250.702, and that the existing
and proposed regulatory language for departure requests does not
specify that the operator must demonstrate that it will achieve at
least the same level of safety and environmental protection as the
regulation from which it wants to depart. The commenter recommended
that BSEE remove the proposed and existing regulations for departures,
unless BSEE can explain its reasons for allowing departures from the
applicable drilling requirements, or why a departure should be allowed
without requiring an adequate substitute for the relevant requirements.
The same commenter suggested that existing Sec. 250.408 and proposed
Sec. 250.701 provide an adequate option for operators to request
approval to use alternative procedures in situations, such as technical
innovations, where there is a beneficial reason to allow such
alternatives, that must meet or exceed the requirements in the
regulations. Other commenters also raised questions regarding
contractor responsibilities.
Response: BSEE and the operators need enough flexibility
under these rules to reasonably accommodate a wide range of potential
alternative compliance methods and departures. Requests to use
alternate procedures or equipment must provide sufficient justification
for BSEE to make a determination that the proposed alternatives provide
a level of safety and environmental protection that equals or surpasses
current requirements. With respect to requests for departures from
operating requirements, BSEE does not specify the type of justification
required because doing so could unnecessarily limit the submission of
supporting documentation that could be pertinent under the various
circumstances that might arise. Moreover, even though existing Sec.
250.409 and proposed Sec. 250.702 do not expressly require an operator
seeking a departure to demonstrate that the operator can still achieve
the same level of safety and environmental protection required by the
rules, BSEE expects that any request for departure will include
appropriate measures to ensure safety and environmental protection.
Accordingly, BSEE has not made any changes to this provision in the
final rule.
BSEE is aware of operator perceptions that some past decisions made
by different Regions or Districts on alternative compliance or
departure requests appeared to lack complete consistency. However,
approval of an alternative compliance or departure request is largely
dependent upon specific site conditions and operational parameters that
can vary significantly, even for requests that otherwise seem similar
on their face. Thus, some perceived inconsistent decisions are
explainable in light of the different case-specific facts and
circumstances. BSEE strives to ensure consistency in decision-making
among all Regions and Districts, and BSEE is developing internal
procedures to improve consistency. In any event, this commenter's
concerns about consistency do not require any change to the
regulations.
Regarding the concerns raised about contractor responsibilities,
that issue is discussed in part VI.B.5 of this document.
What must I do to keep wells under control? (Sec. 250.703)
As provided for in the proposed rule, this new section is intended
to clarify certain precautions required to ensure well control at all
times. Paragraphs (a)
[[Page 25929]]
through (f) of proposed Sec. 250.703 are included in the final rule
without change for the reasons discussed in the following responses to
comments. Proposed paragraph (f) of this section would require the use
of equipment that is appropriately designed, tested, and rated.
However, as explained in the following responses to comments on this
proposed section, paragraph (f) in the final rule has been revised to
clarify that it applies to the ``maximum environmental and operational
conditions'' (rather than the proposed ``most extreme conditions'') to
which the equipment will be exposed.
Comments Related to Proposed Sec. 250.703--General Well-Control
Requirements
Summary of comments: One commenter asserted that the rules should
focus on minimizing the volume of an influx to a well and should
require better ways (such as Coriolis meters, additional sensors, and
personnel training) to determine and recognize flow. This commenter
described an alternative approach based on understanding and
recognizing well characteristics. The commenter noted that some
companies already routinely perform this type of work. The commenter
suggested the following revisions to the proposed rule: (1) Providing
more emphasis on accurately measuring flows to and from a well; (2)
remedying the current lack of control devices/instrumentation installed
with deep-water marine riser systems; (3) requiring well-specific/rig-
specific training for personnel; and (4) requiring realistic well
control modeling of the well systems.
Response: This section of the final rule provides both
specific and general performance-based parameters for keeping wells
under control that are applicable to all types of wells and conditions.
However, the listed parameters are not exclusive of other well control
measures. This section requires operators to ``take the necessary
precautions,'' not just the precautions listed in Sec. 250.703, to
control wells and to ``[u]se and maintain equipment and materials
necessary to ensure the safety and protection of personnel . . . and
the environment.'' BSEE did not prescribe specific technological
requirements, including some of the equipment recommended by the
commenter, because we do not want to limit the operators' options to
ensure and improve safety. BSEE is directly involved with numerous
research projects, and aware of others, involving technological
advancements that could improve equipment and processes, including ways
to better identify an influx to a well and to improve rig personnel
situational knowledge. As more information on such advancements becomes
available, BSEE may use that information to update the regulations, as
appropriate, in separate rulemakings. As a result, no changes were made
to the proposed rule in response to this comment.
Comments Related to Proposed Sec. 250.703--Best Available and Safest
Drilling Technology
Summary of comments: One commenter discussed concerns about the
potential change in expectations for operations that could result from
the absence of the phrase ``best available and safest drilling
technology,'' which was contained in former Sec. 250.401(a) but which
was not in proposed Sec. 250.703. Instead, proposed Sec. 250.703(a)
would require the operator to ``use recognized engineering practices
that reduce risks to the lowest level practicable.'' The commenter
recommended that BSEE include both phrases in the final, promulgated
version of Sec. 250.703.
Response: BSEE does not agree that adding the phrase
``best available and safest drilling technology'' to Sec. 250.703 is
necessary. The BSEE Director, under authority delegated by the
Secretary of the Interior, will determine when to apply BAST for
specific technologies. In applying BAST, the BSEE Director will
determine: When the failure of equipment would have a significant
effect on safety, health, or the environment; the economic feasibility
of the technology; if the incremental benefits are clearly insufficient
to justify the incremental costs of utilizing such technologies; and
whether requiring the use of BAST is practicable on existing
operations.
In this rulemaking, BSEE is not undertaking a BAST determination
with respect to any specific technology that may be utilized to satisfy
the requirements of Sec. 250.703. Moreover, the requirement to use
recognized engineering practices is one broadly associated with
processes and methods. In contrast, the BSEE's BAST authority focuses
on technologies, rather than practices.
Comments Related to Proposed Sec. 250.703(f)--Most Extreme Service
Conditions
Summary of comments: Some commenters requested revisions to
proposed Sec. 250.703(f), which would require the use of equipment
that ``has been designed, tested, and rated for the most extreme
service conditions to which it will be exposed while in service.''
Commenters asserted that multiple extreme conditions are unlikely to
occur simultaneously; thus, expected conditions based on engineering
judgment would better represent the real world. The commenters stated
that unnecessary over-design of equipment, which could result from the
proposed language, could decrease overall system reliability and
introduce additional risk. For example, the commenters noted that
increased design loads for BOPs would lead to larger material forgings,
adding to overall stresses and fatigue loads experienced by wellheads
and casing strings.
Other commenters asserted that the proposed language regarding
``most extreme conditions'' is unclear, and recommended revising the
regulation to use the term ``anticipated conditions'' instead. Some
commenters also suggested that if BSEE believes extreme load survival
is warranted for certain pieces of equipment, then BSEE should require
extreme load survivability, and justify it, as a separate provision.
Response: BSEE agrees that confusion could be created by
the term ``most extreme conditions.'' Accordingly, BSEE has revised
final Sec. 250.703(f) by replacing ``most extreme service conditions
to which it will be exposed'' with the phrase ``the maximum
environmental and operational conditions to which it may be exposed.''
The latter phrase is derived from former Sec. 250.417(a), which is now
designated as Sec. 250.713(a) in this final rule and which retains
that phrase. Thus, industry is already familiar with the meaning of
that language. BSEE intends that language to ensure that equipment used
for operations is designed, tested, and rated for the most adverse
weather and other conditions specific to the location in which it will
be used and the well conditions to which it may be exposed. For
example, equipment used in the GOM does not need to be designed,
tested, and rated for Arctic conditions unless that equipment will be
used in the Arctic. However, equipment used in the GOM does need to be
designed, tested and rated for the possibility of extreme weather
conditions, including hurricanes.
Rig Requirements
What instructions must be given to personnel engaged in well
operations? (Sec. 250.710)
As provided for in the proposed rule, this new section requires
personnel engaged in well operations to be
[[Page 25930]]
instructed in safety requirements, possible hazards, and general safety
considerations, as required by subpart S of part 250, prior to engaging
in operations. Also as provided for in the proposed rule, this section
clarifies that the well-control plan must contain instructions for
personnel about the use of each well-control component of the BOP
system, and must include procedures for shearing pipe and sealing the
wellbore in the event of a well control or emergency situation before
MASP conditions are exceeded. These changes will help establish better
proficiency for personnel using well-control equipment.
After consideration of the comments submitted on this proposed
section, BSEE included the proposed language for this new section in
the final rule without change, except that final paragraph (a) includes
minor revisions to the proposed language in order to clarify the intent
of this paragraph that personnel must be instructed in hazards and
safety requirements.
Comments Related to Proposed Sec. 250.710(b)--Well and Rig Specific
Training
Summary of comments: One commenter recommended that this section
should place more emphasis on well and rig specific training for the
crew. The commenter suggested that proposed Sec. 250.710(b)--regarding
the contents and use of well control plans--comes close to that goal.
However, the commenter suggested that BSEE should go further, including
requiring that personnel be fully informed of the characteristics of
the well.
Response: BSEE does not agree that the suggested changes
to this section are necessary. The requirements of Sec. 250.710(b) are
intended to, and should be sufficient to, help ensure that rig
personnel engaged in well operations are informed about their specific
well-control duties and capable of performing them.
Comments Related to Proposed Sec. 250.710(b)--Well-Control Plan
Summary of comments: Another commenter expressed general support
for proposed Sec. 250.710(b), but recommended that BSEE require that a
well-control expert prepare the plan. This commenter also provided
additional suggestions for what the plan should address, such as well-
control measures using the primary rig, source control and containment
equipment, and secondary relief rigs. The commenter also expressed
concerns about the proposed requirement to post a copy of the well-
control plan on the rig floor. The commenter noted that the plan can be
a complex, lengthy, technical document, and thus recommended that a
copy of the complete well control plan should be available on the rig
floor for reference, and that a shorter version of the plan (with the
key well-control steps) should be posted on the rig floor for quick
reference.
Response: BSEE does not agree that the changes suggested
by the commenter are necessary. BSEE believes it is important that the
completed well-control plan be available (i.e., ``posted'') in the
specific areas where the personnel doing the work can review and use it
to confirm any pertinent details of their and other personnel's well-
control duties. If only a summary of the plan were required to be
posted, there would be some risk that the summary would omit key
details of which rig personnel need to be aware.
In addition, BSEE does not believe that it is necessary for a well-
control expert to draft the plan, as long as it describes the specific
well-control actions that rig personnel need to take, and provides the
other essential information that the personnel need to know, as
specified in Sec. 250.710(b). Nor is it necessary to include the
additional information (e.g., availability of SCCE or a secondary
relief rig) suggested by the commenter; that information would be more
appropriate for an Oil Spill Response Plan, but is not relevant to the
well-control duties of the rig personnel.
What are the requirements for well-control drills? (Sec. 250.711)
As provided for in the proposed rule, this section consolidates
requirements for well-control drills from various sections of the
existing regulations (i.e., Sec. Sec. 250.462, 250.517, 250.617,
250.1707) and makes the requirements applicable to all drilling,
completion, workover, and decommissioning operations covered under new
subpart G. After consideration of the comments submitted on this
proposed section, BSEE has included the proposed language in the final
rule without change, except for a minor change to paragraph (a), as
explained in the following response to comments and in part V.C of this
document. This change to the proposed language of paragraph (a) will
help establish better proficiency for personnel using well-control
equipment.
Comments Related to Proposed Sec. 250.711--Well-Control Drills
Summary of comments: Some commenters asserted that the proposed
requirement is overly prescriptive. Some commenters were concerned
about the stipulation that the same drill could not be repeated
consecutively. They stated that the nature of drills is to reinforce
learning objectives and it may be appropriate to repeat a drill until a
successful outcome is achieved. They also noted that the drills should
reflect the operation being conducted; certain operations continue over
an extended period of time, and therefore it may be appropriate to
repeat the drill for the ongoing operation. Also, certain drills should
be repeated due to the criticality of upcoming operations.
One commenter recommended that the type of drills to be run should
be recommended by a well-control expert and included in the written
well-control plan. Also, this commenter stated that the operator should
document lessons learned from drills as well as any need for additional
or repeat training.
Response: BSEE wants to ensure that all personnel complete
drills involved with all relevant aspects of operations. However, BSEE
recognizes that some drills may be more critical than others and should
be done on a regular basis. Therefore, based on the comments received,
BSEE has revised final Sec. 250.711(a) to clarify that a particular
drill cannot be run consecutively with the same crew. This change will
help avoid overly narrow training for certain personnel and improve
proficiency in well-control procedures by a broader set of rig
personnel without unduly limiting the operator's discretion to schedule
important drills.
BSEE agrees that it is useful for an operator to document any
lessons learned from completed drills and that the operator should take
appropriate steps to correct any deficiencies or other problems noted
from past drills. For example, if the operator notes that certain
personnel did not perform their duties correctly during a drill, it
should consider scheduling extra drills involving those personnel and
otherwise ensure that the personnel understand and can perform their
specific duties, as described in the well-control plan. However, it is
not necessary to add such specific, prescriptive requirements to the
rule, because Sec. 250.711(a) already imposes a responsibility on the
operator to ensure that drills familiarize well operations personnel
with their roles so that they can perform their well-control duties
promptly and efficiently. BSEE believes that this performance-based
requirement, allowing operators to decide the most effective ways to
structure their drills, is appropriate given that drills may vary from
rig-to-rig
[[Page 25931]]
according to the specific rig's location and circumstances and the well
conditions. However, if, as provided by Sec. 250.711(c), BSEE orders a
drill (in consultation with the operator's onsite representative)
during an inspection, and BSEE observes any deficiencies, BSEE will
notify the operator of any deficiencies and appropriate follow-up
actions, if necessary. If appropriate, BSEE may also require additional
drills during subsequent inspections.
BSEE expects the well-control plan and drills, as required by
Sec. Sec. 250.710 and 250.711, to function together as effective tools
to help rig personnel understand and efficiently perform their well-
control responsibilities and duties. Accordingly, except with regard to
the revision described previously in Sec. 240.711(a), no further
revisions to final Sec. 250.711 are needed.
What rig unit movements must I report? (Sec. 250.712)
As described in the proposed rule, this section includes language
similar to former Sec. 250.403 and adds several new requirements for
reporting rig movements to BSEE. Paragraphs (a) and (b) of the final
rule address rig movement reporting requirements for all rig units
moving on and off locations. Paragraph (c) requires notifications to
BSEE if a MODU or platform rig is to be warm or cold stacked on a
lease, including information about where the rig is coming from, where
it would be positioned, whether it would be manned or unmanned, and any
changes in the stacking location. Paragraph (d) requires notification
to the appropriate District Manager of any construction, repairs, or
modifications associated with the drilling package made to the MODU or
platform rig prior to resuming operations after stacking. Paragraph (e)
requires notification to the District Manager if a drilling rig enters
OCS waters as to where the drilling rig is coming from. Paragraph (f)
clarifies that if the anticipated date for initially moving on or off
location changes by more than 24 hours, an updated Rig Movement
Notification Report (Form BSEE-0144) must be submitted to BSEE.
After consideration of the comments received, and as explained in
the following responses to comments and in part V.C of this document,
BSEE has made several revisions to the proposed language in this final
rule.
Comments Related to Proposed Sec. 250.712--Terminology
Summary of comments: A commenter noted that there were
inconsistencies in BSEE's use of various terms for ``rig'' in this
section and throughout the proposed rule. The commenter noted terms
used in this section include: ``Barge,'' ``coiled tubing unit,''
``drill ship,'' ``jackup,'' ``snubbing unit,'' ``semisubmersible,''
``submersible,'' ``wire-line unit,'' ``rig,'' ``rig unit,'' ``MODU,''
``platform rig,'' and ``drilling rig.'' The commenter stated that these
terms do not seem to be used consistently.
Response: Different sections of the regulations may have
different requirements for specific types of rigs, and BSEE has used
different terms to specify what rigs are covered by each specific
section. In particular, proposed and final Sec. 250.712 expressly
require reporting of movements by rig units, including MODUs, platform
rigs, snubbing units, wire-line units used for non-routine operations,
and coiled tubing units. As a result, no changes to the rig terminology
are necessary in the final rule. If any operator is unsure as to
whether a particular section of the rules applies to a particular unit,
the operator may contact the District Manager for assistance. If future
experience with these final rules indicates that further guidance is
needed on the meaning of any terms, BSEE may issue appropriate guidance
or amend the regulations at that time.
Comments Related to Proposed Sec. 250.712(a)--72-Hour Rig Movement
Notification
Summary of comments: Several commenters raised concerns that the
requirement in proposed Sec. 250.712(a)(2) to notify the District
Manager 72 hours before the planned movement of a rig--as compared to
the longstanding requirement for 24-hour advance notification under
former Sec. 250.403(a)--will result in many inaccurate estimates of
rig moves, given the potential for plans and schedules to change. Such
changes are likely to result in multiple reporting adjustments being
submitted to BSEE. Another commenter stated that the 72-hour notice
requirement would be cumbersome and expensive for wireline and coiled
tubing units.
Response: BSEE agrees with commenters that the proposed
72-hour notice requirement may result in additional revisions to the
submitted form, due to the possibility of frequent adjustments to the
rig movement schedule over that period. A 24-hour notice requirement
would provide a better, more reliable indication of when a rig will
actually move and will minimize the need for revisions to previous
notifications. Accordingly, the final rule retains the requirement of
24 hours, which was in the pre-existing regulation.
Comments Related to Proposed Sec. 250.712(c)--Stacking of Rigs
Summary of comments: A commenter recommended that BSEE should
include an ``escape clause'' under proposed Sec. 250.712(c) so that
operators who have not expressly provided permission for stacking a
MODU on their lease would not be required to provide the specified
information to BSEE.
Response: BSEE does not believe that it is necessary to
change the proposed language. BSEE intends that the responsibility for
reporting the rig movement under this provision falls on the operator
or lessee on the lease where the rig is working, not the operator or
lessee where the rig is being moved to for stacking. Thus, if a lessee
or operator has not given permission for another operator's MODU or
platform rig to be stacked on its lease, the operator/lessee who holds
the lease would not be required to provide the information to BSEE, as
the commenter suggested.
Comments Related to Proposed Sec. 250.712(d)--Notification of
Construction, Repairs, or Modifications
Summary of comments: Regarding proposed Sec. 250.712(d)--requiring
notification of repairs or modifications to the drilling package for
stacked units--a commenter suggested that BSEE should not assume an
operator has stacked a rig on the operator's location, but rather
should want to know if any stacked rig returns to operation and what
was done to it prior to the commencement of operations. The rig may not
be resuming operations for the operator who held the contract when it
was moved. Another commenter requested that BSEE define the components
of the ``drilling package'' and that, since equipment repairs are
performed to return the equipment back to specification, the
requirement to report repairs should be removed. A commenter stated
that the requirement to notify the District Manager of ``any''
construction, repairs or modifications associated with the drilling
package is ambiguous.
Response: The information required by this section is
necessary for planning and response purposes, including planning for
possible inspections. The term ``drilling package'' is a commonly
understood industry term and does not require further definition. BSEE
intends that ``any'' construction, repairs, or modifications should be
reported. If repairs or modifications were made to the drilling
package, BSEE could need that information to plan and conduct
inspections and perform additional reviews to ensure the repaired or
[[Page 25932]]
modified equipment is used as intended. Although BSEE cannot predict in
advance all potential types of repairs or modifications that may arise,
BSEE expects a rule of reason, and does not expect every trivial, de
minimis, repair (e.g., replacing a loose screw) to be reported.
Comments Related to Proposed Sec. 250.712(e)--Rig Entering OCS Waters
Summary of comments: A commenter asserted that paragraph (e)
assumes the operator has the rig under contract when it enters OCS
waters. The commenter suggested that the requirement instead be keyed
to when a rig is first utilized for well operations after coming from
an overseas location.
Response: BSEE disagrees. BSEE expects an operator that
has a contract on a rig coming from overseas to make the notification
upon entry of the rig into U.S. waters, so that BSEE has an opportunity
to inspect or otherwise determine that the rig is suitable, before the
rig is first utilized on the OCS. Operators should be aware if its
contract rig is entering OCS waters and where it is coming from.
What must I provide if I plan to use a mobile offshore drilling unit
(MODU) for well operations? (Sec. 250.713)
As provided for in the proposed rule, this section includes MODU
requirements (e.g., fitness and foundation requirements) from former
Sec. 250.417, and makes the former requirements applicable to all
operations covered under subpart G. Paragraph (g) of the final rule
also codifies certain monitoring requirements previously discussed in
BSEE NTL 2009-G02, Ocean Current Monitoring. This final section is
revised from the proposed rule as discussed in the comment responses
for this section and part V.C of this document.
Comments Related to Proposed Sec. 250.713--Platform Types and USCG
Summary of comments: One commenter suggested that this section
should also apply to other types of platforms, including multi-purpose
service vessels. Another commenter recommended that BSEE coordinate
with United States Coast Guard (USCG) regarding specific operating
criteria used to analyze structural pipe on deepwater wells and take
this opportunity to set uniform standards across the OCS. A commenter
suggested adding the USCG to the provision under proposed Sec.
250.713(d) regarding documentation of operational limits imposed by a
classification society.
Response: Although there may be some benefit to applying
these requirements to other types of platforms, BSEE does not currently
have enough data to make that determination. BSEE will need more data,
and more research needs to be conducted, to justify expanding the scope
of this section to other vessels and rigs. Similarly, BSEE does not
have enough information at this time to proceed with the commenter's
suggestion that we set specific criteria for analyzing structural pipe
on deepwater wells.
In addition, BSEE would need to gather more information and to
further consult with USCG before deciding whether to add USCG to the
Sec. 250.713(d) requirement for providing documentation on operational
limits. BSEE may consider addressing these issues in separate
rulemakings at a later date. In the meantime, BSEE will continue its
close coordination with USCG in all matters involving BSEE and USCG
responsibilities.
Comments Related to Proposed Sec. 250.713--Terminology
Summary of comments: Another commenter asserted that the use of
inconsistent terminology for ``rigs'' (e.g., unit, rig unit) in this
section may create confusion and recommended that BSEE review the Part
250 regulations for how the various terms referring to rigs are used
and then include appropriate definitions.
Response: Different sections of the regulations may have
different requirements for specific types of rigs, and BSEE has used
different terms to specify what rigs are covered by each specific
section. However, BSEE agrees with the suggestion that the uses of
various terms for rigs in this specific section could cause some
confusion. Accordingly, BSEE made minor changes to this section to
improve consistency between rig terms (e.g., we replaced ``unit'' with
``MODU'' in final Sec. 250.713(a)). The suggestion that BSEE review
all of part 250 regarding the terminology for rigs falls outside the
scope of this rulemaking. BSEE may review all of part 250 for this
purpose at a later date.
Comments Related to Proposed Sec. 250.713(a)--Fitness Requirements
Summary of comments: A commenter suggested that, under proposed
Sec. 250.713(a), the requirement to provide information demonstrating
the unit's capability to perform under the most extreme conditions
(including the minimum air gap for the hurricane season) should apply
only if appropriate. This commenter noted that dynamically positioned
rigs, MODUs and multi-purpose supply vessels typically do not stay on
location during hurricane season.
Another commenter stated that the requirement to collect and submit
environmental data to the District Manager after an APD/APM is approved
would not benefit the MODU or lift boat that is already on location
under the approved permit and that is collecting the data, and the MODU
or lift boat could be at risk if it were truly ``unsuitable'' for the
site conditions where it is gathering the data. The commenter
recommended that a metocean specialist assess the suitability of the
MODU or lift boat for the location, applying conservative environmental
criteria. If there is uncertainty in the metocean criteria that cannot
be resolved, the environmental data should be gathered before
mobilizing a MODU or lift boat to the location.
Response: BSEE agrees that the requirement to submit
information on the most extreme environmental conditions that the unit
is designed to withstand only requires information regarding the
minimum air gap where that is a relevant factor in the unit's design.
For example, not all MODUs have or require an air gap (e.g.,
drillships). However, BSEE does not believe it is necessary to
expressly add such a limitation in Sec. 250.713(a), since it is
already clearly implied by the language stating that the operator is
only required to submit information about the most extreme conditions
the ``MODU is designed to withstand.''
BSEE agrees that environmental data should be gathered before
mobilizing a MODU to location, although no change to the regulatory
text is required to make that point. The requirements in Sec.
250.713(a) have been in place--in former Sec. 250.417(a)--for years
and BSEE is not aware of any problems occurring because a unit was
onsite before the data was gathered and submitted. Nor does BSEE
believe that it is necessary to require a metocean expert to assess the
suitability of the unit for the environmental conditions under this
longstanding provision. Furthermore, the District Manager has the
authority to revoke approval of the permit if data collected during
operations shows the MODU cannot perform at the proposed location. This
will help BSEE ensure that the MODU proposed for OCS operations is
appropriate for the specific location.
[[Page 25933]]
Comments Related to Proposed Sec. 250.713(b)--Foundation Requirements
Summary of comments: One commenter asserted that Sec. 250.713(b)--
regarding foundation requirements for MODUs and lift boats--should
apply only to bottom-supported MODUs or lift boats, where a loss of
foundation is catastrophic, and that BSEE should exclude moored MODUs
from this requirement. Another commenter suggested adding text to this
section to state that the District Manager may accept lower-bound and
upper-bound soil properties, based on regional soil data and developed
by a knowledgeable geotechnical engineer, in lieu of the requirement to
submit information on site-specific soil conditions.
Response: BSEE agrees with the comment that paragraph (b)
should apply only to bottom-founded MODUs. Accordingly, BSEE revised
Sec. 250.713(b) to clarify that this provision requires submittal of
information showing that site-specific soil and oceanographic
conditions are capable of supporting the proposed bottom-founded MODUs.
(In addition, as explained later, BSEE has removed lift boats
altogether from this section of the final rule.)
However, BSEE does not agree that regional soil data should be
allowed in place of site-specific soil data. The purpose of the soil
data requirement in Sec. 250.713(b) is to ensure that the foundation
at the specific site is actually capable of supporting a bottom-founded
MODU, and regional soil data may not be sufficient to demonstrate the
suitability of the soil at that particular site.
Comments Related to Proposed Sec. 250.713(c)--Frontier Areas
Summary of comments: One commenter asserted that proposed Sec.
250.713(c) (requiring information about units in frontier areas) and
(f) (availability of units for inspection) should not apply to lift
boats. The commenter stated that lift boats are classified as offshore
support vessels and are regulated by the USCG.
Response: Commenters raised several jurisdictional and
technical concerns regarding the applicability of this section to lift
boats. For example, some of the information, or access to information,
required by this section may not be available or pertinent for some
lift boats. Accordingly, BSEE revised the final rule by deleting all
references to lift boats in Sec. 250.713.
Comments Related to Proposed Sec. 250.713(e)--Contingency Plans
Summary of comments: Another commenter recommended adding
provisions to Sec. 250.713(e), which requires contingency plans for
dynamically positioned MODUs to move offsite in emergencies, in order
to ensure that the operator has plans to secure the well during planned
suspensions.
Response: Requirements for securing a well during any
interruption, including suspensions, are adequately covered under final
Sec. 250.720. Therefore, no changes to Sec. 250.713(e) are necessary
in this regard.
Do I have to develop a dropped objects plan? (Sec. 250.714)
As provided for in the proposed rule, this new section codifies
some of the language from BSEE NTL 2009-G36, Using Alternate Compliance
in Safety Systems for Subsea Production Operations, and is intended to
help avoid prolonged damage to subsea infrastructure and to assist
operators and BSEE in responding to a dropped object. This section also
requires an operator to develop a dropped objects plan and specifies
certain information and procedures that must be included in the plan.
This final section is revised from the proposed rule as discussed in
the comment responses for this section and in part V.C of this
document.
Comments Related to Proposed Sec. 250.714(c)--Modeling a Dropped
Object's Path
Summary of comments: One comment on proposed Sec. 250.714(c)--
requiring floating rigs in areas with subsea infrastructure to model a
dropped object's path--asserted that modeling the path does not
significantly reduce the risk associated with a dropped object.
With regard to proposed Sec. 250.714(e)--requiring operators to
include in their dropped objects plan ``any additional information
required by the District Manager''--one commenter recommended that BSEE
should limit requests for additional information to ``information
needed to ensure protection of onsite personnel or the environment.''
Another commenter asserted that Sec. 250.714(e) is ambiguous and that
BSEE should clarify it. Another commenter observed that companies
should have simultaneous operations (SIMOPS) procedures in place.
Response: BSEE does not agree that there is no potential
benefit to modeling a dropped object's path. With the continuing
expansion of subsea infrastructure, BSEE determined that it is
important for operators to be aware of, and plan for, the potential
impacts of a dropped object. Having a dropped object plan helps
increase such awareness and will help operators, and BSEE, to identify
impacted infrastructure in order to improve responses to a dropped
object.
Section 250.714(e) is intended to give District Managers the
necessary flexibility and discretion to require information as needed
in specific cases to fulfill the purposes of the regulation. However,
BSEE has further clarified final Sec. 250.714(e), by stating that a
District Manager may require additional information as appropriate to
clarify, update, or evaluate a dropped objects plan. Thus, the District
Manager may require additional information regarding dropped objects on
a case-by-case basis, based on unique site or well conditions.
BSEE currently does not have enough information about SIMOPS to
warrant including such a requirement in this final rule. However, BSEE
agrees that SIMOPS may be a tool that operators should consider when
multiple operations are being conducted at the same time or in
conjunction with each other. If research or studies or other
information about SIMOPS become available in the future that warrant
further revision of this regulation, BSEE may propose such a revision
in a future rulemaking.
Do I need a global positioning system (GPS) for all MODUs? (Sec.
250.715)
As provided for in the proposed rule, this new section codifies
existing BSEE NTL 2013-G01, Global Positioning System (GPS) for Mobile
Offshore Drilling Units (MODUs). The GPS requirements for MODUs
include: Providing a reliable means to monitor and track the unit's
position and path in real-time if the unit moves from its location
during a severe storm; installing and protecting the GPS equipment to
minimize the risk of the system being disabled; having the capability
of transmitting data for at least 7 days after a storm has passed; and
providing BSEE with real-time access to the unit's GPS location data.
This final section is revised from the proposed rule as discussed in
the comment responses for this section and in part V.C of this
document.
Comments Related to Proposed Sec. 250.715--Terminology
Summary of comments: A commenter raised concern about apparent
inconsistencies in the use of terminology related to rigs in this
section. The commenter pointed out that in the proposed rule this
section referred to ``MODUs and jack-ups,'' ``jack-up and moored
MODUs,'' ``moored MODU or jack-up,'' and ``Rig/facility/platform.'' In
addition, the
[[Page 25934]]
caption for this section implies that a jack-up is not a MODU.
Response: BSEE agrees that the proposed rule's terminology
concerning rigs in this section might cause some confusion. BSEE made
some minor changes to this section in the final rule to improve
consistency between rig terms. For example, BSEE has revised the title
of this section to ``Do I need a GPS for all MODUs?'' and in final
Sec. 250.715(a), we have replaced ``jack-up and moored MODU'' with
``MODU.''
Comments Related to Proposed Sec. 250.715--Applicability
Summary of comments: A commenter suggested that this provision
should be extended to all MODUs, including dynamically positioned
MODUs, rather than just moored MODUs. All MODUs moved from the path of
a storm should be tracked for emergencies.
Response: BSEE agrees with the commenter that all MODUs
should be tracked during severe storms, as required by Sec.
250.715(e). In any event, as previously stated, BSEE has revised final
Sec. 250.715(a) by deleting the word ``moored.'' In addition, to avoid
any potential confusion, BSEE revised the title of this section to
refer to ``all MODUs.''
Comments Related to Proposed Sec. 250.715(a)--GPS Monitoring and
Tracking
Summary of comments: Another commenter recommended revising
proposed Sec. 250.715(a) by removing the phrase ``if the moored MODU
or jack[hyphen]up moves from its location during a severe storm.''
Response: BSEE does not agree with the commenter's
suggestion. The commenter provided no explanation for this
recommendation. Operators and BSEE will need the GPS data, and thus all
MODUs must possess GPS systems capable of providing such data to track
units during severe storm events. Removing the phrase suggested by the
commenter would require that the GPS systems also be able to monitor
and track the unit when making normal rig moves under routine
conditions. Although any GPS system that provides the tracking and
monitoring data during a severe storm would be able to provide such
data during a normal move, BSEE does not need access to such data and
sees no need to require operators to have such a capability. BSEE is
particularly concerned about MODUs that lose station-keeping or part
moorings during storms. Thus, BSEE slightly revised the first sentence
in this section to clarify that BSEE must have real-time access to GPS
data prior to and during each hurricane season, consistent with the
language in NTL 2013-G01 that this provision is codifying (see 80 FR
21519).
Well Operations
When and how must I secure a well? (Sec. 250.720)
As provided for in the proposed rule, this section consolidates
requirements from various provisions of the existing regulation
regarding how to secure a well whenever operations are interrupted.
Paragraph (a) requires that the District Manager be notified when
operations are interrupted and provides examples of events that would
warrant interruption of operations (e.g., any observed flow outside the
well's casing). The requirement to notify the District Manager gives
BSEE awareness of interrupted operations and an opportunity for an
appropriate response. Paragraph (a) also requires a negative pressure
test to ensure wellbore and barrier integrity before removing a subsea
BOP stack or surface BOP stack on a mudline suspension well. Paragraph
(a)(2) clarifies that if there is not enough time to install the
required barriers or other special circumstances occur, the District
Manager may approve alternate procedures in accordance with Sec.
250.141. Paragraph (b) of this section requires prior approval by the
District Manager for displacement of kill-weight fluid from a wellbore
and/or riser and specifies the information that must be included in an
APD or APM to seek such approval. This section is unchanged from the
proposed rule.
Comments Related to Proposed Sec. 250.720(a)--Testing and Verifying
Barriers
Summary of comments: Some commenters recommended that the barriers
required by proposed Sec. 250.720(a), when operations are interrupted
be tested and verified as effective by an engineer before the BOP is
removed. One commenter also recommended that the regulation clearly
require that barriers be installed prior to removing a BOP. This
commenter asserted that it appears this was intended, but that the
regulatory language would benefit from additional clarification,
including clarifying that it applies when a BOP is removed but the rig
has not yet moved off location.
Response: BSEE does not agree with the suggested changes.
It is not necessary to add a requirement to this paragraph for a PE
verification of a barrier's effectiveness, given that the barriers must
be tested, according to Sec. 250.720(b)(2), to ensure integrity before
moving off the well. Nor is any change needed to clarify that the
barriers must be installed and tested before moving off location; in
fact, Sec. 250.720(a) already expressly requires that two independent
barriers must be installed ``[b]efore moving off the well,'' and Sec.
250.720(b) effectively requires that the barriers be tested before
removing mud from the riser in preparation for moving off the well.
What are the requirements for pressure testing casing and liners?
(Sec. 250.721)
As provided for in the proposed rule, this section incorporates and
revises certain requirements from former Sec. Sec. 250.423 and 250.425
for pressure testing casing and liners. Among other things, final Sec.
250.721 increases the minimum test pressure specification for conductor
casing (excluding subsea wellheads) from 200 psi, as under the former
regulations, to 250 psi; requires operators to test each drilling liner
and liner-lap before further operations are continued in the well and
provides the parameters for such tests; clarifies that the District
Manager may approve or require other casing test pressures as
appropriate to ensure casing integrity; requires that operators follow
additional pressure test procedures when they plan to produce a well
that is fully cased and cemented or is an open-hole completion;
requires a PE certification of plans to provide a proper seal if there
is an unsatisfactory pressure test; and requires a negative pressure
test on all wells that use a subsea BOP stack or wells with mudline
suspension systems. This final section is revised from the proposed
rule as discussed in the comment responses for this section and in part
V.C of this document.
Comments Related to Proposed Sec. 250.721--Monitoring and Verification
Summary of comments: A general comment on this section asserted
that BSEE should consider improvements to the monitoring and
verification of makeup/torqueing of casing/tubular connections, under
this section and Sec. 250.423(c). Similarly, another commenter stated
that BSEE should focus on ensuring integrity of the casing string and
recommended doing so by linking minimum casing test pressure to
formation integrity pressure.
Response: BSEE does not agree that these suggested changes
are necessary to ensure proper installation of casing and tubing. BSEE
already requires a pressure test on the casing seal assembly under
former Sec. 250.423(b)(3)--now Sec. 250.423(c)--and submittal to BSEE
of both the test procedures and test results, in order to verify the
integrity of the
[[Page 25935]]
casing and connections. There is no need for additional language to
confirm these results.
Comments Related to Proposed Sec. 250.721(a) Through (c)--Liner Lap
Testing
Summary of comments: Multiple commenters asserted that testing of
the liner-lap, as specified in proposed Sec. 250.721(a) through (c),
is not possible. The commenters recommended instead that the liner-top
be tested to confirm integrity of the casing.
Response: BSEE agrees with the comment that the liner lap
cannot be tested as proposed, since the liner-lap will not actually
respond to the pressure from such a test, while the liner-top will
respond to that pressure. Accordingly, testing of the liner-top is
sufficient to demonstrate the integrity of the well, and BSEE has
revised final Sec. 250.721(b) and (c) by substituting ``liner-top''
for ``liner-laps'' with regard to the testing required to confirm
integrity.
Comments Related to Proposed Sec. 250.721(a)--Testing of Surface,
Intermediate and Production Casing
Summary of comments: Another commenter stated that under proposed
Sec. 250.721(a)(3)--regarding testing of surface, intermediate and
production casing--BSEE should allow operators to test the casing to
either 70 percent of the casing's minimum internal yield pressure (as
proposed) or to MAWHP plus 500 psi, in order to avoid putting
unnecessary loads on the casing or cement.
A commenter claimed that there is no engineering basis for the
requirement in proposed Sec. 250.721(b) to test formation integrity at
the liner shoe, if the liner will not be exposed to that amount of
pressure. The commenter claimed, for example, that casing shoes set in
salt are not exposed to such pressures.
Response: BSEE does not agree that the suggested changes
are needed or appropriate. The requirement for testing casing to 70
percent of its minimum internal yield pressure is a longstanding
requirement, formerly in Sec. 250.423(a)(3), and BSEE is not aware of
any significant problems or concerns with testing to that limit. If an
operator has any concerns with the testing procedures in a specific
case, however, the operator may request, and the District Manager may
approve, other casing test pressures on a case-by-case basis under
Sec. 250.721(d).
For the same reasons, BSEE does not agree that the suggested
changes to Sec. 250.721(b) are warranted. That testing requirement has
been in place for many years (formerly in Sec. 250.425(a) and (b)) and
BSEE is not aware of industry raising any concerns with implementing
that requirement. In any event, any operator that wants to seek
approval of an alternative test pressure under Sec. 250.721(d) in a
specific case may do so.
Comments Related to Proposed Sec. 250.721(e)
Summary of comments: A commenter raised concerns about proposed
Sec. 250.721(e)--regarding pressure testing for a well that is planned
for production--stating that the proposed language to ``pressure test
the entire well to maximum anticipated shut[hyphen]in tubing pressure''
is not clearly defined. The commenter asserted that the text is not
clear as to whether the ``anticipated shut[hyphen]in tubing pressure''
is the pressure with a full column of hydrocarbons or the pressure
after perforating with an underbalanced fluid. The commenter claimed
that this ambiguity would make implementing this requirement
problematic when the fluid in the well at the time of pressure testing
is of a different density than the planned completion fluid. The
commenter described various risks associated with this situation and
suggested that BSEE clarify that the testing pressure must not ``exceed
70 percent of the burst rating limit of the weakest component.''
Another commenter stated that the existing regulations on testing
(Sec. 250.423) are fit-for purpose, and that industry's long standing
practice to test casing to maximum values only with a technical reason
for doing so is sufficient. The commenter stated that testing to
maximum anticipated shut-in tubing pressure may do unnecessary harm to
the cement integrity.
Response: BSEE agrees that continually pressure testing to
the maximum anticipated shut-in tubing pressure may put additional
stresses on the cement and thus potentially affect cement integrity.
Therefore, as suggested by one of the commenters, BSEE has revised
final Sec. 250.721(e) by inserting the phrase ``but not to exceed 70
percent of the burst rating limit of the weakest component'' to help
ensure long term cement integrity. In addition, as provided by final
Sec. 250.721(d), if an operator has other concerns about casing test
pressures, it may seek approval from the District Manager or Regional
Supervisor for alternative test pressures on a case-by-case basis.
Comments Related to Proposed Sec. 250.721(f)--Pressure Testing Before
Resuming Operations
Summary of comments: One commenter recommended that BSEE should
revise Sec. 250.721(f)--requiring pressure testing of a well before
resuming operations--to require operators to run pressure tests long
enough to stabilize the pressure and to hold a constant pressure for 30
minutes.
Response: BSEE does not agree that holding a constant
pressure for 30 minutes is necessary to demonstrate sufficient
stability to resume operations. Due to well parameters such as, but not
limited to, thermal effects, fluid compressibility, fluid
characteristics, and environmental conditions, holding a constant
pressure for 30 minutes may not be possible. The proposed requirement
that--if the pressure declines more than 10 percent in 30 minutes--the
District Manager must approve a PE-certified plan to resolve the
pressure issue is sufficient to ensure that the well is fit to be
operated.
Comments Related to Proposed Sec. 250.721(g)--Negative Pressure Test
Summary of comments: BSEE received multiple comments on proposed
Sec. 250.721(g), which addressed negative pressure testing of wells
with subsea BOP stacks or mudline suspension systems. Commenters
asserted that the negative pressure tests under Sec. 250.721(g)(1) and
(3), should only be required if hydrocarbons are present. Commenters
also recommended that Sec. 250.721(g) require two barriers only if
hydrocarbons are present.
Response: BSEE disagrees with the comments about testing
the barriers only if there are hydrocarbons present. BSEE determined
that ensuring barrier integrity and well stability by performing the
required tests is important, even if hydrocarbons are not present at
the time, because geological conditions (e.g., fluid migration) may
exist that could subsequently result in hydrocarbons entering the well
if the barriers are not effective. Thus, testing the barriers'
effectiveness under such conditions will help ensure that hydrocarbons
will not enter the well at a later date.
What are the requirements for prolonged operations in a well? (Sec.
250.722)
As provided for in the proposed rule, this section consolidates and
clarifies various sections of the existing regulations that established
requirements for well integrity for operations continuing longer than
30 days from a previous casing or liner test. If well integrity has
deteriorated to a level below minimum safety factors, this section
requires repairs or installation of additional casing and subsequent
pressure testing, as approved by the District Manager. As discussed in
the
[[Page 25936]]
comment responses for this section and in part V.C. of this document,
BSEE has revised the language of proposed paragraph (a) in the final
rule.
Comments Related to Proposed Sec. 250.722--Introductory Paragraph
Summary of comments: BSEE received a comment on the introductory
paragraph of Sec. 250.722, which specifies actions that must be taken
if wellbore operations continue more than 30 days after the previous
pressure test. The commenter suggested that the introductory text be
revised to include ``or independent third-party review of the well's
casing or liner'' as a condition of timing for performing the
requirements in this section.
Response: BSEE did not revise this section based on the
comment. It is not clear from the comment how the independent third-
party would review the well's casing or liner.
Comments Related to Proposed Sec. 250.722(a)--Prolonged Well
Operations
Summary of comments: Other commenters raised concerns with proposed
Sec. 250.722(a), which requires that operations stop as soon as
practicable, and that the operator must: Evaluate the effects of
prolonged operations using a pressure test, caliper or imaging tool;
and report the results, including calculations showing the well's
integrity is above minimal safety factors, to the District Manager.
Commenters asserted that calculations that show a well's integrity is
above the minimum safety factors cannot be performed for a casing
pressure test, and thus recommended revisions to Sec. 250.722(a)(2) to
clarify that the report must include calculations showing that the
well's integrity is above the minimum safety factors only if an imaging
tool or caliper is used.
Response: BSEE agrees with the comment that calculations
that show a well's integrity cannot be performed for a casing pressure
test. Accordingly, BSEE has revised final Sec. 250.722(a)(2) to say
that the report must include calculations that show the well's
integrity is above the minimum safety factors if an imaging tool or
caliper is used.
What additional safety measures must I take when I conduct operations
on a platform that has producing wells or has other hydrocarbon flow?
(Sec. 250.723)
As provided for in the proposed rule, this section consolidates and
revises requirements from several former sections (i.e., Sec. Sec.
250.406, 250.518(b), 250.619(b)) regarding additional safety measures
for operations on a platform that has a producing well or other
hydrocarbon flow. Among other requirements, this section requires the
installation of an emergency shutdown station, for the production
system, near the rig operator's console. This provision helps ensure
that rig units would be able to shut-in the production system of the
host facility. For the reasons discussed in the following comment
responses, the final rule makes no changes to the proposed rule in
regard to this section.
Comments Related to Proposed Sec. 250.723--Terminology
Summary of comments: A commenter noted that there are apparent
inconsistencies in BSEE's use of terms for ``rig'' in this section. The
commenter noted terms used in this section include: ``coiled tubing
unit,'' ``lift boat,'' ``drill ship,'' ``jackup,'' ``snubbing unit,''
``wire-line unit,'' ``rig unit,'' and ``MODU.'' However, the commenter
provided no specific suggestions for addressing this issue.
Response: For the reasons stated in response to similar
comments on proposed Sec. 250.712, BSEE has determined that no changes
to the terminology in this section are necessary.
Comments Related to Proposed Sec. 250.723--Definition of ``Platform''
Summary of comments: Another commenter stated that the term
``platform,'' which is mentioned in this section's heading, is not
defined in part 250, and that facilities or rigs may be built and
operated on gravel islands or installed on bottom-founded offshore
structures. The commenter recommended that BSEE develop and add a new
definition of ``platform,'' including facilities on gravel islands or
bottom-founded structures, to Sec. 250.105.
Response: This comment recommends adding a new provision
that was not in the proposed rule, and the commenter did not suggest a
specific definition for BSEE to consider. BSEE has decided that it is
not appropriate to include such a new definition in this final rule.
Various sections of BSEE's current regulations have long used the term
``platform'' (or similar terms), including former Sec. 250.406, on
which final Sec. 250.723 is partially based, and BSEE is unaware of
any significant difficulties by regulated entities in understanding
that term in connection with that former section. Moreover, since that
term is used in somewhat different contexts in different provisions, a
single definition of that term might not be suitable for use in every
context.\14\
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\14\ 14 For example, BSEE has already proposed adding a
definition of ``fixed platform'' to Sec. 250.105, for use in
connection with proposed amendments to Sec. 250.108. (See 80 FR
34113 (June 15, 2015).) While that proposed definition would be
appropriate for use under the specific circumstances applicable to
the proposed amendments to Sec. 250.108 (see id. at 31446), it
might not be as appropriate for defining similar terms in other
sections.
---------------------------------------------------------------------------
Comments Related to Proposed Sec. 250.723(c)--Lift Boats
Summary of comments: A commenter suggested that BSEE not include
lift boats in Sec. 250.723(c)(3), which requires shut-in of producible
wells when a MODU or lift boat moves within 500 feet of the platform.
The commenter observed that lift boats are self-powered motor vessels,
which are more maneuverable than, and not comparable to, a MODU that is
towed on location.
Response: BSEE disagrees with the comment about removing
lift boats from paragraph (c)(3). Even though a lift boat may be more
maneuverable than a MODU, care must still be taken when any large
object, such as a lift boat, undertakes any movement near a well with
producing hydrocarbons. The risk of a collision or other incident that
could trigger a well-control event cannot be eliminated simply because
the moving object may be relatively maneuverable.
What are the real-time monitoring requirements? (Sec. 250.724)
As described in the proposed rule, this new section includes
requirements for gathering and monitoring real-time well data. The
proposed section has been revised in the final rule as discussed in the
comment responses for this section and in part V.B.4 of this document.
Proposed paragraph (a) has been revised to clarify that it requires
using an independent, automatic, and continuous monitoring system
capable of recording, storing, and transmitting data regarding the BOP
control system, the well's fluid handling system on the rig, and the
well's downhole conditions. Proposed paragraph (b) has been revised to
describe some of the required RTM operational capabilities and
procedures. Proposed paragraph (c) has been revised to require that an
operator develop and implement an RTM plan, to specify certain
information that must be included in the plan, and to require that BSEE
be provided with access to the plan, and to RTM data, upon request.
[[Page 25937]]
Comments Related to Proposed Sec. 250.724--Claims That the RTM
Requirements are Premature
Summary of comments: Some comments asserted that any RTM rule would
be premature until after studies and research on the application of
such monitoring and analysis to offshore oil and gas operations is
complete. Specifically, some comments suggested that BSEE take no final
action on the RTM regulation until after the National Academy of
Sciences (NAS) Transportation Research Board completes a study on RTM,
commissioned by BSEE, and releases its final report.
Response: RTM is not a novel concept or technology, and it
is currently widely used in many industrial applications, including
offshore oil and gas development. Several of the industry commenters
stated that they already have RTM plans and use RTM systems in their
offshore operations, and acknowledged the value of such programs. In
addition, based on regular interaction with operators, BSEE is aware
that many other operators already use RTM capabilities to monitor
certain aspects of their operations. Thus, BSEE does not agree that it
is appropriate to delay promulgation of the RTM requirements in this
final rule until after the completion of the NAS Report, especially
since compliance with the RTM requirements will not be required until
three years after publication of the final rule, and the NAS report is
currently scheduled to be completed in May 2016. (More information on
the NAS study is available at: http://www.bsee.gov/Technology-and-Research/Technology-Assessment-Programs/Projects/Project-740/.) BSEE
will carefully consider the NAS report when it is issued, and if BSEE
concludes that the report warrants any revisions to these final
regulations, BSEE may propose such changes in a separate rulemaking.
Comments Related to Proposed Sec. 250.724--Concerns About RTM
Transmission
Summary of comments: Some comments raised concerns regarding the
possibility that the transmittal of RTM to an onshore location could
provide another opportunity for data system attacks, and that this
increases the need for more cyber security. In addition, some comments
asserted that the proposal would increase problems with data retention
and data quality (e.g., availability of bandwidth and upload time),
although no specifics were provided in those comments.
Response: Concerns about cyber security, data retention,
and data quality have been and will continue to be an issue for all
regulatory programs that require electronic transmission or storage of
data. However, much rig-based data has long been, and will continue to
be, transferred to shore without regard to the proposed RTM
requirements and, in many cases, without being required by any
regulation. Many effective measures to address cyber security (e.g.,
access controls, encryption, firewalls, intrusion detection), data
retention, and data quality issues are available, and BSEE is confident
that the offshore oil and gas industry is aware of and frequently uses
such measures. Accordingly, such concerns do not justify foregoing the
expected benefits of the RTM requirements of this final rule.
Comments Related to Proposed Sec. 250.724--Concerns About Compliance
Timing
Summary of comments: Some comments requested that, in lieu of the
proposed requirements, BSEE give operators 5 years from publication of
the final rule to address BOPs in RTM plans.
Response: Those comments did not include any specific
explanation or support for the requested 5-year period for
incorporating BOP RTM data in such RTM plans. BSEE has reviewed the
relevant comments and supporting information, and determined that 3
years will provide sufficient time to implement the final RTM
requirements for all of the specified data, including data regarding
the BOP control system, as proposed. Based upon public comments and
prior consultation with industry, BSEE believes that many operators
have already implemented some form of RTM for at least some rig
equipment and operations (e.g., drilling and fluid handling systems);
thus, modifying (if necessary) such existing RTM programs to include
the data specified in Sec. 250.724(a), including BOP data, can be
reasonably accomplished within 3 years.
Comments Related to Proposed Sec. 250.724(a)--Scope of Data To Be
Monitored
Summary of comments: Some comments questioned what was meant by the
proposed requirement that the operator's RTM system must be capable of
monitoring ``all aspects of'' the BOP control system, the well's fluid
handling system, and the well's downhole conditions with any installed
bottom hole assembly tools.
Response: For clarity and to avoid any potential
confusion, BSEE deleted the phrase ``all aspects of'' from final Sec.
250.724(a), which now requires that the RTM system be capable of
``recording, storing, labeling, and transmitting data regarding'' the
``BOP control system data . . .,'' the ``well's fluid handling system .
. .,'' and the ``well's downhole conditions . . . .''
Comments Related to Proposed Sec. 250.724(b)--Concerns About RTM and
Decision-Making
Summary of comments: Many commenters asserted that the proposed RTM
requirements would lead to an erosion of authority of, or shifting
operational decision-making away from, the rig-site personnel. In
particular, some commenters claimed that the requirement in proposed
Sec. 250.724(b)(4) that RTM data be ``immediately transmitted'' to
onshore personnel who must be in ``continuous contact'' with rig
personnel implied that BSEE expected onshore personnel to be able to
override rig personnel in making key operational decisions based on the
RTM data. The commenters asserted that such intervention could be
detrimental to the rig personnel's performance of their operational
duties, as well as their sense of accountability, and thus could
actually inhibit their responses to unusual data and otherwise degrade
safety and environmental protection.
Response: The proposed rule did not intend to, and the
final rule does not, contribute to an erosion of authority of, or
shifting of operational decision-making away from, the rig-site
personnel. The proposed requirement was intended only to ensure that
RTM data is transmitted onshore and that onshore personnel who have the
ability to monitor the data and contact rig personnel in the event that
unusual data warrants discussion with and potential evaluation by rig
personnel. (See 80 FR 21520.) BSEE intended the proposed rule to ensure
that onshore personnel could serve as ``another set of eyes'' to
monitor the data and potentially to assist rig personnel in performing
their duties, but not to override the key onsite decision makers or
interfere with rig personnel performing their onsite duties.
However, to avoid any confusion in this regard, BSEE has revised
final Sec. 250.724(b) to address the commenters' concerns, while
staying true to BSEE's original intent. In particular, we have replaced
the proposed requirement to ``immediately transmit'' the RTM data to
the onshore location with a requirement to transmit these data as they
are gathered, barring unforeseeable or
[[Page 25938]]
unpreventable interruptions in transmission. In addition, we have
replaced the proposed reference to onshore personnel ``who must be in
continuous contact with rig personnel'' with a new sentence requiring
that ``[o]nshore personnel who monitor real-time data must have the
capability to contact rig personnel during operations.''
Comments Related to Proposed Sec. 250.724(b)--Concerns About RTM
Interruptions
Summary of comments: A commenter suggested that the proposed
requirement in Sec. 250.724(b) regarding communications (continuous
contact) between rig personnel and onshore personnel would result in a
shutdown of operations at the rig in the event of any interruption, no
matter how brief or inconsequential, to onshore-rig communications. The
commenter asserted that such shutdowns, and subsequent restarting of
operations, would be extremely costly and would create additional risks
of malfunction during the shutdowns without any corresponding benefits.
Another commenter also suggested that loss of RTM transmission to
onshore should not result in a shutdown under proposed Sec.
250.724(c).
Response: Nothing in the proposed rule suggested that an
operator must automatically shutdown, or that BSEE would necessarily
order a shutdown of operations due to any break, no matter how minor,
in transmittal of RTM data onshore or in communications between onshore
and rig personnel. However, although these concerns were not supported
by the proposed regulatory text, they are addressed by the revisions in
this final rule to Sec. Sec. 250.724(b) and 250.724(c). As already
discussed, BSEE has revised final Sec. 250.724(b) to require that
operators transmit the RTM data as they are gathered, barring
unforeseeable or unpreventable interruptions in transmission, and that
operators have the capability to monitor the data onshore, using
qualified personnel in accordance with an RTM plan, as provided in
final paragraph (c). Finally, onshore personnel who monitor real-time
data must have the capability to contact rig personnel during
operations.
In addition, as discussed elsewhere in this document, BSEE has
revised final Sec. 250.724(c) and removed the language that would have
authorized the District Manager to require other measures during a loss
of RTM capabilities. These revisions eliminate the language that the
commenters perceived could have required shutdowns.
Comments Related to Proposed Sec. 250.724(c)--Concerns About Notifying
BSEE
Summary of comments: Various commenters raised concerns about the
practicality of the requirement in proposed Sec. 250.724(c) to
immediately notify the District Manager if RTM capability is lost.
Commenters pointed out that there will be brief losses in monitoring
capability from time-to-time, which are expected and unavoidable.
However, the operators and the District Managers could be inundated
with notifications for very short interruptions that are insignificant
and have no potential consequences.
Response: BSEE did not intend the proposed rule to require
notifications for every loss of RTM capability, no matter how brief or
insignificant the interruption might be. BSEE agrees with the
commenters that it would be impractical and an unnecessary burden for
operators and the District Managers if immediate notifications were
required for every minor interruption. Accordingly, BSEE has removed
the proposed requirement to immediately notify the District Manager
every time RTM is interrupted from the final rule. However, BSEE still
expects to be informed when there is a significant or prolonged loss of
RTM capability as outlined in the RTM plan, that potentially could
increase the risk of a well-control event. Thus, as described in more
detail elsewhere, BSEE has added a provision to the final rule, at
Sec. 250.724(c), requiring operators to develop an RTM plan that
includes a description of how the operator will notify the District
Manager when such a loss occurs.
Comments Related to Proposed Sec. 250.724(c)--Requests To Delete RTM
Requirements and/or Require RTM Plans
Summary of comments: Several commenters requested that BSEE delete
the proposed RTM requirements from the final rule. Some of those
commenters also suggested that, if BSEE did not delete RTM altogether,
it should replace at least some of the prescriptive RTM requirements
with a performance-based requirement for operators to develop their own
RTM plans (similar to the safety and environmental management system--
SEMS--plans required by BSEE regulations), which would be available to
BSEE upon request. Some other commenters, who did not expressly urge
BSEE to require RTM plans, nonetheless relied on the existence of their
own RTM plans to justify their recommendation that BSEE eliminate RTM
requirements from the final rule. Some of the commenters who suggested
that BSEE require RTM plans also suggested specific issues that should
be covered in such RTM plans (e.g., qualifications for onshore
personnel; protocols for communications between rig and onshore
personnel; protocols for handling interruptions in such communications
and in RTM capabilities; location of onshore monitoring facilities),
although each plan could be tailored to fit the circumstances
applicable to each rig operator.
Response: BSEE agrees with many of the commenters'
suggestions regarding the potential advantages of a performance-based
RTM plan requirement. In particular, BSEE agrees that requiring rig-
specific RTM plans could allow operators to optimize their resources to
better focus on areas or issues that need the most attention. Further,
the availability of the RTM plans to BSEE would provide extra insight
into ways in which RTM can be used to improve safety and environmental
protection. In addition, such plans would provide operators with a more
flexible, performance-based opportunity to address issues such as what
to do when RTM capabilities and communications are interrupted.
Accordingly, BSEE revised the final rule, as requested by some
commenters, to include a requirement, in final Sec. 250.724(c), that
operators develop and implement RTM plans and make the plans available
to BSEE upon request. That provision requires that the RTM plans
include certain information, such as:
[cir] Descriptions of how RTM data will be transmitted onshore, and
the onshore location(s) where the data will be monitored and stored;
[cir] Procedures for communications between onshore and rig
personnel;
[cir] Actions to be taken if such communications or RTM
capabilities are lost;
[cir] Procedures for responding to any significant or prolonged
interruptions of monitoring or communications; and
[cir] A protocol for notifying BSEE of any significant or prolonged
interruptions.
These RTM plan requirements will complement the other RTM
requirements in Sec. 250.724(a) and (b).
Comments Related to Proposed Sec. 250.724--Miscellaneous Concerns
Summary of comments: Several comments did not fit into the
summaries already discussed. These miscellaneous comments include
[[Page 25939]]
assertions: (a) That the RTM requirements will not result in increased
functionality, reliability and operability of BOPs and that no RTM
centers are known to reduce incidents and increase safety; (b) that rig
alarms and visual inspection are more effective than RTM; and (c) that
the rule requires the gathering of a huge amount of information.
Response: Some of these miscellaneous comments express
opinions (e.g., that rig alarms and visual inspection are better than
RTM; the RTM requirement will not result in increased functionality,
reliability and operability of BOPs), with no supporting facts or
explanations and some are largely irrelevant (i.e., this rulemaking
does not require operators to establish RTM centers). For the reasons
stated in the proposed rule and elsewhere in this document, BSEE
expects the use of RTM to improve safety and environmental protection
significantly and that such improvements will be seen over time. BSEE
understands that the RTM provisions of this final rule will result in
more information being gathered, and BSEE took that into account in
assessing the potential costs and benefits of this rule under E.O.
12866 and the Paperwork Reduction Act, as discussed in part VIII and in
the final RIA. For all of the reasons stated in this document and in
the final RIA, BSEE has determined that the benefits of the final RTM
requirements, including the value of the RTM information to be
collected, are appropriate in relation to the potential costs,
including the burdens associated with collecting RTM information.
Blowout Preventer (BOP) System Requirements
What are the general requirements for BOP systems and system
components? (Sec. 250.730)
As provided for in the proposed rule, this section consolidates and
revises requirements from several sections of the existing regulations
for design, fabrication, installation, maintenance, inspection, repair,
testing and use of BOP systems and BOP components. Among other things,
paragraph (a) of final Sec. 250.730 requires compliance with relevant
provisions of API Standard 53 and several related industry standards
and adds a performance-based requirement that the BOP system be able to
meet anticipated well conditions and still be able to seal the well.
Paragraph (b) requires that operators ensure that design, fabrication,
maintenance, and repair of the BOP system is done pursuant to the
requirements contained in part 250, OEM recommendations (unless
otherwise directed by BSEE), and recognized engineering practices.
Paragraph (c) requires operators to use failure reporting procedures
consistent with specified industry standards and to report failures to
BSEE. Paragraph (d) requires that if an operator uses a BOP stack
manufactured after the effective date of this rule, that BOP stack must
have been manufactured in accordance with API Spec. Q1. Proposed Sec.
250.730 has been revised in the final rule as discussed in the comment
responses for this section and in part V.C of this document.
Comments Related to Proposed Sec. 250.730(a)--BOP Design,
Installation, and Maintenance
Summary of comments: In response to the language in proposed Sec.
250.730(a) that operators ``must design, install, maintain, inspect and
use'' BOP system components, several commenters pointed out that
operators do not design, install, or maintain BOP systems. Typically,
drilling contractors select and obtain the equipment from OEMs and have
the BOP stack built to order in accordance with API Standard 53. These
commenters recommended revising this section to replace ``design'' with
``ensure'' or ``select.''
Response: Although the requirements in Sec. 250.730(a)
have long been in place under existing regulations (former Sec.
250.440), BSEE agrees with the comment that operators do not usually
design, install, or maintain the BOP systems. Therefore, BSEE has
revised final Sec. 250.730(a), as suggested by commenters, to state
that lessees/operators must ensure that the BOP system and system
components are designed, installed, maintained, inspected, tested, and
used properly to ensure well control. This change addresses the
commenters' concern, while clarifying that the lessee or operator
retains overall responsibility for ensuring the BOP system's proper,
design, installation, maintenance, inspection, testing and use.
Comments Related to Proposed Sec. 250.730(a)--BOP Design
Responsibility
Summary of Comments: Some comments asserted that the requirements
in proposed Sec. 250.730(a) would implicitly impose QA/QC and
oversight responsibilities for BOP equipment on lessees/operators that
are infeasible, given that the design, manufacturing and testing of
such equipment are completed before the contracts between the lessees/
operators and drilling contractors are in place.
Response: As explained in the previous response, BSEE has
revised final Sec. 250.730(a) to require that the operators ``ensure''
that the equipment is designed, installed, maintained, etc., to ensure
well control. To the extent that drilling contractors actually perform
those activities, the contractors will be jointly and severally
responsible for compliance with this provision.
Comments Related to Proposed Sec. 250.730(a)--MASP
Summary of comments: Some commenters recommended that BSEE change
the reference to ``MASP'' in proposed Sec. 250.730(a) (i.e., that the
working pressure rating of each BOP component exceed the applicable
MASP) to ``maximum anticipated wellhead pressure'' (``MAWHP''). They
asserted that there is no industry agreed-upon definition of ``MASP,''
but that MAWHP is defined in API Standard 53.
Response: BSEE does not agree that the recommended change
is necessary. As a practical matter, for surface BOPs, the MASP is the
same as the MAWHP; and for subsea BOPs, the MASP, when taken at the
mudline as required by Sec. 250.730(a), is also the same as the MAWHP.
BSEE does not agree that use of ``MASP'' will cause any confusion.
BSEE's existing regulations (e.g., former Sec. 250.448(b)), have long
used the term ``MASP,'' and BSEE does not believe that the industry
will have any difficulty in understanding the meaning and use of that
term in this rule.
Comments Related to Proposed Sec. 250.730(a)--Annular BOPs
Summary of comments: Several commenters also stressed that annular
BOPs capable of meeting the specified pressure rating for ``each BOP
component'' under proposed Sec. 250.730(a) are not currently available
and are not considered technologically feasible in the near term. They
suggested that BSEE clarify that this proposed requirement applies only
to lower stack components (including and below the uppermost ram) and
that components above the uppermost ram (e.g., annular and LMRP or
riser connect) should be excluded. Another commenter suggested
excluding annular BOPs that comply with Sec. 250.738(g), which sets
procedural requirements for annular BOPs with rated working pressures
(RWPs) lower than anticipated surface pressure.
Response: BSEE agrees that annulars may not be able to
meet the MASP requirements. BSEE is aware that the current design for
annulars does not match the pressure rating for large ram preventers
greater than 10,000 psi.
[[Page 25940]]
Annulars are typically used with wellbore pressures less than MASP. An
annular does not have any locking mechanisms to keep it closed, as do
pipe rams and blind shear rams, and it will relax and not seal if the
hydraulic pressure is lost. Thus, a single annular is not commonly used
for well-control purposes; rather, annulars are commonly used in
conjunction with other MASP-rated components, such as pipe rams or
blind shear rams, that can seal the well under MASP. Therefore,
excluding annulars from the MASP pressure rating requirement will not
decrease safety. Accordingly, we have revised final Sec. 250.730(a) to
exclude annulars from the requirement that working pressure rating
exceed MASP.
Comments Related to Proposed Sec. 250.730(a)--Flowing Conditions
Summary of comments: Various commenters raised issues regarding the
requirement in proposed Sec. 250.730(a) that each ram (except casing
shears/supershears) must be capable of closing and sealing the wellbore
at all times, including under flowing conditions. Some commenters
viewed the proposed language as requiring each ram to be assessed
against an absolute worst-case event (i.e., any conceivable flowing
conditions), and that it is not realistic to expect a drilling BOP ram
to close and seal on a high flow-rate well stream. Some comments
asserted that the ability to test to such extreme worst-case conditions
does not exist. Various comments asserted that the actual goal of the
regulation should be for the BOP system as a whole (including both
annulars and rams) to reliably shut-in the well under ``reasonably
anticipated'' or ``anticipated'' flowing conditions. Multiple
commenters emphasized that the industry has demonstrated the capability
to successfully seal the wellbore under a variety of anticipated
flowing conditions (with flow checks using an annular BOP). Some
commenters, however, claimed there are currently no criteria for
determining anticipated flowing conditions; while other comments
suggested that anticipated flowing conditions should be defined by the
OEM.
Multiple commenters, therefore, asked BSEE to clarify the
conditions that the equipment must be designed to meet, while other
commenters specifically asked BSEE to require that the anticipated
flowing conditions be defined in the APD for the specific operation and
well conditions.
Response: BSEE recognizes that a single ram may not be
capable of closing and sealing the wellbore at all times under all
possible flowing conditions. BSEE is also aware that testing an
individual ram component under all possible well conditions is not
feasible with current testing mechanisms. Accordingly, BSEE has revised
final Sec. 250.730(a) to clarify that the BOP system, not each ram,
must be capable of closing and sealing the wellbore at all times under
``. . . anticipated flowing conditions for the specific well conditions
. . . .'' If an operator has any questions about the anticipated
flowing conditions in any specific case, it may request assistance from
the District Manager.
Comments Related to Proposed Sec. 250.730(a)--Concerns About
Compliance Date
Summary of comments: Commenters also raised concerns that
implementation of proposed Sec. 250.730 would be required within 90
days of publication of the final rule. They asserted that BOPs
available today are not designed to close and seal under the worst-case
flowing conditions that the commenters assumed the rule would require.
Similarly, various commenters stated that BSEE has not defined testing
parameters and protocols necessary to meet such scenarios. Thus,
multiple commenters requested that BSEE significantly extend the
proposed 90-day implementation period in order to provide time for
manufacturers to develop new BOPs and for drillers to purchase and
install such new designs.
Response: In light of the revisions to final Sec.
250.730(a) previously described (i.e, the deletion of the requirement
for each ram to close and seal, and the insertion of ``anticipated''
before ``flowing conditions''), BSEE is not changing the compliance
date for requiring that BOP systems have the capability to close and
seal the well. BSEE is aware, and several industry commenters have
stated, that industry has already demonstrated that reasonably
available existing BOP systems are capable of successfully closing and
sealing the wellbore under a variety of flowing conditions under the
existing BOP regulations (former Sec. 250.440). Given the changes to
the final rule language, and industry commenters' acknowledgment of
their ability to comply with the similar requirements under the
existing regulations, BSEE does not anticipate that industry will need
to make any significant changes to its current or planned BOP systems
to comply with the final rule.
Comments Related to Proposed Sec. 250.730(a)(2)--Normative References
Summary of comments: In general, some industry commenters did not
support the incorporation by reference of the additional standards
associated with API Standard 53, as listed in proposed Sec.
250.730(a)(2), since those listed standards are merely normative
references in API Standard 53. These associated documents are
manufacturing specifications, and since they are already referenced in
API Standard 53, the commenters stated that it is redundant to also
reference them in the regulations. Several major industry commenters
requested that, if BSEE does reference these documents in the
regulations, then it should clarify that only the relevant provisions
of those documents are required to be complied with.
Response: BSEE recognizes that the industry standards
listed in Sec. 250.730(a)(2) are normative references within API
Standard 53. BSEE is including the standards in the regulations,
however, because they provide certain relevant specifications for BOP
system components, and are important to compliance with API Standard 53
itself. As requested by industry commenters, however, BSEE has revised
final Sec. 250.730(a)(2) to clarify that the BOP system must meet
those provisions of the listed industry standards that apply to BOP
systems.
Comments Related to Proposed Sec. 250.730(a)(2)--Standards--Current
Editions
Summary of comments: Other commenters stated that the additional
standards listed in proposed Sec. 250.730(a)(2) are outdated equipment
manufacturing standards, and that incorporating a specific outdated
edition renders equipment manufactured prior to the standard, or
manufactured to earlier versions of the standard, obsolete. They
asserted that incorporating only API Standard 53, which includes
updated normative references, and deleting the outdated standards
listed in paragraph (a)(2), would resolve this issue. Alternatively,
some commenters suggested that the regulation should allow equipment to
be used if it complies with the editions of API Standard 53 and the
associated standards that were in effect at the time the equipment was
manufactured.
A commenter also noted that there are significant misalignments
between API Standard 53 and the current versions of most of these
associated standards (e.g., accumulator capacity requirements), which
would make it impossible to
[[Page 25941]]
comply with API Standard 53 and these associated standards. The
commenter also noted that API Standard 53 and these associated
standards are currently being revised, and that the API committees
working on the new editions are aware of these misalignment issues.
Response: Whenever BSEE incorporates a standard by
reference in the regulations, it must incorporate a specific edition of
the standard (see 1 CFR part 51), and compliance is then required with
the incorporated standard. BSEE proposed to incorporate the most recent
(Fourth) edition of API Standard 53, which refers to the other
standards but which--in contrast to Federal regulations--does not
specify the edition of those other standards to which it refers. Some
of the associated standards incorporated by reference in Sec.
250.730(a)(2) are the current versions (e.g., API Spec. 16A and API
Spec. 16D); other standards have been updated and new editions adopted
by industry since BSEE developed and issued the proposed rule. BSEE
understands the industry is also working to update some of the current
standards. BSEE will evaluate any new editions of the standards as they
are finalized by industry. If BSEE determines that any such revised
standards are appropriate for incorporation in this regulation, BSEE
may do so in a separate rulemaking. In addition, as previously
discussed, an operator that wishes to use equipment manufactured to a
more recent edition of the incorporated standard, may ask for approval
to do so in accordance with Sec. 250.198(c) and Sec. 250.141 or Sec.
250.142.
Comments Related to Proposed Sec. 250.730(a)(3)--Pipe and Variable
Bore Rams (VBRs)
Summary of comments: Commenters raised concerns that the proposed
requirement in Sec. 250.730(a)(3) (i.e., that pipe rams and VBRs be
able to close and seal any drill pipe, workstring and tubing) is not
achievable for tubing with control lines, electric cable, and flat
packs. Commenters asserted that the interstices between the tubular and
these ancillary lines become leak paths when the pipe or VBRs are
closed around the tubing arrangement. In addition, some commenters
stated that the proposed requirement would be redundant with existing
dual barrier systems (including annulars), and thus would provide
negligible additional improvements to safe operations. Commenters
recommended that tubing with such exterior lines be excluded from the
proposed requirement. If the requested exclusion from the proposed
requirement is not adopted, some commenters suggested that BSEE revise
the rule to allow alternative control measures based on risk
assessments.
Response: BSEE agrees with the comments about pipe rams
and VBRs not being able to close and seal around tubing with exterior
control lines and flat packs. An annular is the only BOP component
currently able to seal around tubing with exterior control lines and is
only used for a low pressure situation, which is usually the case when
running tubing with exterior control lines. Accordingly, BSEE has
revised final Sec. 250.730(a)(3) to clarify that pipe rams and VBRs
are not required to be able to close and seal around tubing with
exterior control lines and flat packs. In addition, BSEE has determined
that this exclusion will not have significant safety or environmental
consequences since Sec. Sec. 250.733(a) and 250.734(a)(1)(ii) will
require that the shear rams be able to cut and seal tubing with
exterior control lines in the hole.
Comments Related to Proposed Sec. 250.730(a)(3)--Claimed Conflicts
With API Standard 53
Summary of comments: Commenters requested clarification regarding
the requirement in proposed Sec. 250.730(a)(3) that the pipe rams and
VBRs be able to close and seal the tubing using the ``proposed
regulator settings'' of the BOP system. The commenters claimed that
this language potentially conflicts with API Standard 53. The
commenters also suggested that the reference to ``regulator settings''
should be removed from this provision because such settings are part of
the BOP control system described in Sec. 250.730(a).
Response: This regulation does not prescribe any specific
requirements for regulator settings. BSEE requires only that the
regulator settings function as designed or as specified in the APD
submitted to and approved by BSEE. Therefore, BSEE does not believe
that this provision will cause any conflict or confusion for operators,
including with respect to API Standard 53, and thus no change or
further clarification is necessary.
Comments Related to Proposed Sec. 250.730(a)(4)--Approval of BOP
Changes
Summary of comments: With regard to proposed Sec. 250.730(a)(4),
requiring that operations be suspended pending BSEE approval of any
changes to the BOP or control systems that would alter previously
approved schematic drawings--some commenters observed that any changes
to the BOP stack or control system would be made between wells. Thus,
any changes to the drawings and equipment would be included in the APD
for the next well. Those commenters recommended deleting that portion
of Sec. 250.730(a)(4) that would require such suspensions.
Response: BSEE disagrees with the comment's suggestion
that changes would always be made between wells. BSEE understands that
this is usually the case; however, there are circumstances where
repairs and modifications to the BOP or control system are made at
other times and not necessarily between wells. Thus, there is no reason
to revise this provision.
Comments Related to Proposed Sec. 250.730(a)(4)--Schematic Drawings
Summary of comments: A commenter recommended that BSEE clarify
Sec. 250.730(a)(4) to specify that the schematic drawings required for
the BOP and its control system be the same drawings listed in Sec.
250.731(b)(1) through (10).
Response: No changes to the proposed paragraph (a)(4) are
necessary. Under final Sec. 250.730(a)(4), schematic drawings may
include other schematics (such as those required under Sec.
250.737(d)(12)) that are not listed in Sec. 250.731(b)(1) through
(10).
Comments Related to Proposed Sec. 250.730(b)--Lowest Level Practicable
Summary of comments: A commenter recommended that BSEE revise the
first sentence in proposed Sec. 250.730(b) to require that the design,
fabrication, maintenance, and repair of BOP systems reduce risks to the
lowest level practicable instead of ``according to the requirements of
this subpart, OEM recommendations, . . . and recognized engineering
practices'' as proposed by BSEE.
Response: The requested changes are not necessary. BSEE
expects these types of activities to utilize recognized engineering
practices that reduce risks to the lowest level practicable, as already
required by existing Sec. 250.107(a)(3).
Comments Related to Proposed Sec. 250.730(b)--BOP Design and
Fabrication
Summary of comments: Other comments stated that operators do not
design and fabricate the BOP systems; they select the equipment based
upon their specifications and capabilities. Accordingly, commenters
suggested that BSEE should revise the text, replacing ``design,
fabricate, maintain, and repair'' with ``select, maintain, and
repair.''
Response: BSEE agrees with the comments that operators do
not usually
[[Page 25942]]
design and fabricate the BOP systems. Therefore, BSEE revised this
paragraph in the final rule to state that an operator must ensure that
the design, fabrication, maintenance, and repair of its BOP system is
in accordance with the requirements contained in the part. This change
will help clarify that the lessee or operator is responsible for
ensuring the BOP system's proper, design, installation, maintenance,
inspection, testing and use even if it does not design and fabricate
the BOP system.
Comments Related to Proposed Sec. 250.730(b)--BOP Repair and
Maintenance
Summary of comments: A commenter suggested that repair and
maintenance should be carried out in accordance with OEM specifications
and maintenance manuals and the equipment owner's planned maintenance
procedures. Additionally, a commenter advised that the OEM's
recommendations for repair and maintenance should include the quantity
and quality of parts that the owner or operator subsequently uses.
Response: The suggested changes are unnecessary. As
previously discussed, the lessee or operator is responsible for
ensuring that the BOP system is designed, repaired and maintained in
accordance with the requirements of this final rule, which includes
ensuring that the BOP equipment is suitable for the conditions under
which it will be used (see, e.g., Sec. 250.731), as well as with any
OEM recommendations, which would include OEM specifications and
maintenance.
As to the second comment, BSEE expects the equipment to operate as
designed and to be used under the conditions for which it was designed.
However, the commenter's suggestion that OEMs should include the
quantity and quality of parts subsequently used by the operator in the
OEMs' recommendations for repair and maintenance is beyond the scope of
this rulemaking, which addresses requirements that must be met by
operators.
Comments Related to Proposed Sec. 250.730(b)--Recognized Engineering
Practices
Summary of comments: Commenters recommended that the phrase
``recognized engineering practices'' be removed since the phrase is
vague and undefined.
Response: The recommended deletion is neither necessary
nor appropriate. Recognized engineering practices are commonly
understood to be found in established codes, industry standards,
published peer-reviewed technical reports or industry RPs, and similar
documents applicable to engineering, design, fabrication, installation,
operation, inspection, repair, and maintenance activities.
Comments Related to Proposed Sec. 250.730(b)--Training of Personnel
Summary of comments: Commenters recommended that BSEE remove the
proposed requirements for training of repair and maintenance personnel.
Some commenters observed that OEMs do not publish training,
qualification, and maintenance recommendations. Others stated that OEM
maintenance recommendations are one `size fits all', since OEMs do not
have a clear understanding of how the equipment will be used,
maintained or preserved. Commenters emphasized that the equipment
owners are responsible for the condition of the equipment and that they
should be responsible for defining the skills and training for their
maintenance personnel. They also noted that operators are already
required to address training as part of their SEMS program under BSEE's
SEMS regulations (see Sec. 250.1915), and that the equipment owners
(e.g., rig contractors) are also establishing training standards for
their personnel. One commenter recommended that BSEE should implement
an accredited/licensed training program, to be developed by the
industry, instead of relying solely on OEMs and recognized engineering
practices.
Response: None of the suggested changes are necessary.
BSEE agrees that the SEMS training requirements are pertinent to
personnel maintaining, inspecting or repairing BOPs, and BSEE added an
express reference to those requirements in final Sec. 250.739(d), as
discussed elsewhere in this document. However, BSEE does not see any
inconsistency between the requirements in Sec. 250.730(b), for
training based on OEM recommendations and recognized engineering
practices, and BOP-related training as part of the SEMS program and
under Sec. 250.739(d). There is no reason why operators' SEMS training
programs should not incorporate OEM recommendations and other
recognized practices.
In addition, BSEE does not agree that it should require a new
training program, whether developed by industry, as suggested by the
commenter, or not. Contrary to the commenter's assumption, BSEE is not
relying solely on OEM recommendations and recognized engineering
practices. As explained previously, the SEMS training requirements
apply to BOP-related training, and those requirements should be
sufficient without BSEE creating yet another training program.
Comments Related to Proposed Sec. 250.730(b)--Meaning of OEM
Summary of comments: Some comments questioned the meaning of OEM in
this provision. They asked if the OEM is the BOP component manufacturer
or the suppliers of parts used by the component manufacturer.
Commenters suggested that, if the proposed rule implies that service
and maintenance personnel must receive training from subcontractors of
the OEM, it would not be a workable rule. One commenter suggested that
there would be a severe impact on the availability of personnel
permitted to carry out maintenance, depending on the definition of OEM.
Response: BSEE does not agree that any definition of OEM
is necessary at this time. BSEE expects that where operators have
relevant recommendations from manufacturers of individual parts of the
BOP system, as well as recommendations from the BOP component
manufacturer, they are able to implement both sets of recommendations.
Conversely, this regulation does not require operators to follow the
recommendations of OEMs, whether manufacturers of BOP components or
individual pieces of equipment, if no such recommendations exist. In
the event an operator has any questions as to the applicability of any
specific OEM recommendation, it may ask the District Manager for
assistance.
Comments Related to Sec. 250.730(c)--BOP Failure Reporting Procedures
Summary of comments: A commenter recommended that BSEE add near-
miss reporting to failure reporting requirements. Commenters also
suggested that BSEE define ``failure'' and specify the types of failure
covered by this provision.
Response: The comment regarding near-miss reporting is
outside the scope of this rulemaking and the suggested changes are not
necessary or appropriate at this time.\15\
---------------------------------------------------------------------------
\15\ BSEE notes, however, that the U.S. Bureau of Transportation
Statistics has developed (with BSEE's assistance) a voluntary near-
miss reporting system for OCS facilities and operations. More
information is available at www.SafeOCS.gov.
---------------------------------------------------------------------------
BSEE agrees, however, with the suggestion that a definition of
``failure'' would clarify the scope and applicability of this
provision. Since there are no definitions of ``failure'' in any of the
industry standards (i.e., API Spec. 6A, API Spec. 16A, or API
[[Page 25943]]
Standard 53) referenced in this provision, BSEE added a general
definition of ``failure'' in final Sec. 250.730(c)(1).
Comments Related to Proposed Sec. 250.730(c)--Failure Reporting Under
API Standard 53
Summary of comments: A commenter asserted that since API Standard
53 covers failure reporting by the owner of the equipment, regulations
on this point are not necessary. Since it is covered in API Standard
53, the commenter presumed that a prudent drilling contractor would
conduct such follow-up.
Response: BSEE understands that failure reporting
requirements are found throughout various voluntary industry standards,
several of which are incorporated in this provision. As with any
voluntary standard incorporated into BSEE's rules, that incorporation
has the intended benefit of making compliance with the standard a
regulatory requirement, which promotes consistency across the regulated
community. BSEE is also including additional failure reporting
requirements in this rule. Such reporting can lead to improved and more
reliable equipment.
Comments Related to Proposed Sec. 250.730(c)--Manufacturing Standards
Summary of comments: Some commenters suggested that BSEE only needs
to reference API Standard 53 in this section, and that BSEE should
remove the references to API Spec. 6A and Spec. 16A. API Standard 53 is
an operational document, while API Spec. 6A and API Spec. 16A are
manufacturing-related failure reporting methods. Alternatively, BSEE
needs to provide guidelines on the intended use for referencing Spec.
6A and Spec. 16A.
Response: No changes to this proposed paragraph related to
this comment are necessary. BSEE incorporated the failure reporting
requirements from all three of the industry standards in the proposed
provision because each standard contains useful reporting procedures
that the others do not. In addition, the incorporation of the failure
reporting procedures of API Spec. 6A and API Spec. 16C adds value to
this provision because those standards apply specifically to equipment
that is part of a BOP system. BSEE expects that the failure reporting
procedures of all three standards will complement each other. On the
other hand, BSEE sees no need to provide guidance on the potential use
of API Specs. 6A and 16A at this time. As experience and additional
information are gained under this rule, BSEE will both provide guidance
and clarification on this rule as necessary, and consider any new
information it learns in considering whether any adjustments to the
rule may be warranted.
Comments Related to Proposed Sec. 250.730(c)--Failure Database
Summary of comments: Some commenters advised BSEE that a group of
drilling contractors have developed a database for reporting BOP
failures. These failures are automatically copied to the OEM by the
database. According to the commenters, this group plans to implement
the failure reporting database industrywide. Within a year or so,
according to the commenter, this group may have sufficient data to
identify problem areas, to collectively focus on these areas until
design and procedure changes are implemented that will make well-
control equipment even more reliable.
Response: The commenters recommended no specific changes
to the rule or other action by BSEE. In any case, it would not be
appropriate for BSEE to take any action now based on a program that may
or may not exist in the future. However, BSEE encourages continued
proactive evaluation by industry of potential failure mechanisms to
enhance safety and environmental protection offshore.
Comments Related to Proposed Sec. 250.730(c)--Written Failure Report
Summary of comments: With regard to proposed Sec. 250.730(c)(1), a
commenter suggested replacing the requirement for a ``written report''
of equipment failure to the manufacturer with ``written notification.''
Response: BSEE agrees that such a change is appropriate.
This requirement is only the first step in the failure reporting
process, and a notice at this step is sufficient. A more detailed
analysis report of the failure will be provided to the manufacturer, as
well as to BSEE, under final Sec. 250.730(c)(2). Accordingly, BSEE has
revised final Sec. 250.730(c)(1) to require only a written notice.
Comments Related to Proposed Sec. 250.730(c)--Concerns About Who
Should Submit Failure Reports
Summary of comments: Some commenters stated that, since operators
do not own the BOP equipment, and are not the primary source of failure
data, failure reports should come from the drilling contractors.
Therefore, the commenters recommended revising this section to state
that the operator must ``ensure'' that a failure report is provided to
the manufacturer.
Response: BSEE does not agree that these suggested changes
are necessary. In paragraph (c), BSEE is requiring the operator to
provide the notifications and handle the interactions with the
manufacturer because operators are responsible for all activities under
a lease.
Comments Related to Proposed Sec. 250.730(c)--Failure Investigation
and Analysis
Summary of comments: A commenter noted that not every failure
warrants a full investigation and suggested replacing ``investigation
and a failure analysis'' in the proposed rule with ``investigation and,
when required, a failure analysis.'' According to the commenter, major
failures should be discussed with the OEM and an investigation
initiated; however, the system would be unsustainable if every
(including a minor) failure required investigation by the OEM, a third-
party or a combination of both.
Response: BSEE disagrees with the assertion that the
failure reporting system would break down if every minor failure
required investigation. It is possible that even a so-called ``minor''
failure could indicate a potentially more serious problem that warrants
correction, which would otherwise escape attention, if not for the
investigation of the ``minor'' failure. Since it is not possible to
know in advance which seemingly minor failures may lead to a ``major''
problem, BSEE does not believe that it is appropriate to limit the
requirement as suggested.
Comments Related to Proposed Sec. 250.730(c)--Timing of Failure
Analysis
Summary of comments: A commenter also suggested that a 60-day
window to complete and submit failure analysis findings is not
realistic. It often takes 6 months or more for these findings to be
obtained and approved. Reporting of the analysis results within 60 days
will potentially lead to narrowing the scope or lessening the intensity
of the investigation and diminishing its potential value.
Response: The commenter apparently misinterpreted the
proposed rule as requiring that the findings of the failure analysis be
produced within 60 days, when the proposed requirement actually
provided that the investigation and analysis must be initiated within
60 days. Nonetheless, BSEE agrees with the commenter that 60 days may
not be sufficient for an effective failure analysis to be performed.
However,
[[Page 25944]]
BSEE does not agree with the commenter's suggestion that 6 months or
more may be necessary to produce the findings of such analysis. There
is value to concluding the analysis, and providing the results to the
manufacturer at a reasonably early date after the failure, so that any
necessary follow up actions can be taken sooner, and thus potentially
prevent additional related failures from occurring. Accordingly, BSEE
has revised final Sec. 250.730(c)(2) by modifying the time for
performing a failure analysis to 120 days.
Comments Related to Proposed Sec. 250.730(c)--Failure Occurrence
Summary of comments: A commenter suggested that BSEE revise this
section to reflect only failures that occur when the BOP system is in
service and not during maintenance periods.
Response: BSEE does not agree that these suggested changes
are necessary. In Sec. 250.730(c), BSEE incorporated the failure
reporting requirements of 3 industry standards, and those standards
provide enough specificity as to when a failure triggers the need for
reporting. In any event, a failure may be an indicator of a serious
problem requiring investigation and potential follow-up action whenever
the failure occurs.
Comments Related to Proposed Sec. 250.730(c)(2)--Analysis Report
Summary of comments: Another commenter recommended that BSEE revise
proposed paragraph (c)(2) by changing ``copy of the analysis'' to
``results of the investigation.''
Response: BSEE agrees with the substance of this comment
and has revised final Sec. 250.730(c)(2) by changing ``copy of the
analysis'' to ``copy of the analysis report.'' This revision will
ensure that the results of the analysis, including any recommendations
for corrective action, are documented and provided to the manufacturer.
BSEE expects that the analysis report will describe the analysis as
well as the results, since it is frequently useful to review the
analysis to determine the adequacy of the results. For the same reason,
BSEE has revised final Sec. 250.730(c)(2) to require that a copy of
the analysis report also be provided to BSEE, since it is important
that BSEE be aware of the results of failure analyses in order to help
BSEE identify potential trends and, if appropriate, make others aware
of a potential problem that may require action to prevent similar
failures or to improve equipment reliability.
Comments Related to Proposed Sec. 250.730(c)(3)--Questions Concerning
Who Must Notify BSEE of Failures
Summary of comments: A commenter requested that BSEE clarify
paragraph (c)(3) regarding who is required to notify BSEE of an
equipment design change or change in operating or repair procedures;
i.e., whether it should be the operator or the contractor (the owner of
the equipment involved in the failure.)
Response: Paragraph (c)(3) clearly requires the operator
to report the design changes or modified procedures, unless another
person covered by the regulatory definition of ``you'' informs the
operator it has done so.
Comments Related to Proposed Sec. 250.730(c)(3)--Submittal of Failure
Report to BSEE
Summary of comments: Some comments questioned why the report of
equipment changes or procedural changes must be sent to BSEE's
headquarters office instead of the District Manager.
Response: BSEE will require that these reports be sent to
BSEE headquarters in order to ensure that emerging trends occurring
across various Districts and Regions are recognized early and that
potentially serious concerns can be addressed in a coordinated and
uniform way nationwide.
Comments Related to Proposed Sec. 250.730(d)--Scope of API Spec. Q1
(Quality Control)
Summary of comments: One commenter asserted that the proposed
regulation at Sec. 250.730(d) does not clearly define the scope of the
requirement to implement API Spec. Q1. The commenter requested that
BSEE clarify whether this requirement only applies to complete BOP
stacks, or if it also includes any BOP component that is manufactured
after the implementation of the rule (e.g., a single BOP ram).
Response: The intent of the provision is that the complete
BOP stack must be manufactured pursuant to API Spec. Q1, not the
individual components of the BOP system.
Comments Related to Proposed Sec. 250.730(d)--Reference to ISO 17011
Summary of comments: Some commenters suggested that the reference
to ISO 17011 is incorrect and that the actual reference should be to
ISO 17021. In addition, they suggested that BSEE add ISO 29001 as an
optional alternative standard. They also noted that ANSI/API Spec. Q1
8th edition is no longer available from ANSI, and that BSEE should
incorporate API Spec. Q1 9th edition, as it is the correct edition. In
addition, other commenters asserted that there is no API standard for a
BOP stack, and that API Spec. Q1 would apply only to the individual
components.
Response: BSEE already incorporates ISO 17011 under
Sec. Sec. 250.1900, 250.1903, 250.1904, and 250.1922 for
qualifications of accreditation bodies under SEMS. Incorporating that
standard here ensures consistency with the SEMS requirements for
quality management systems. Regarding incorporation of ISO 29001 as an
optional alternative standard, BSEE generally expects that operators
are following the industry developed standards, regardless of whether
the standard is incorporated in the regulations. However, when BSEE
incorporates a standard in the regulations, compliance with that
standard is not optional. An operator may request approval from BSEE to
comply with an alternative standard under Sec. 250.141. BSEE
recognizes the concerns related to incorporating the most current
edition of each standard. The issue of incorporation of a newer edition
was addressed in comment-responses under Sec. 250.198. The change to a
new edition or removal of a discontinued standard is not automatic and
requires rulemaking. Operators may request approval from BSEE to follow
a later edition of a standard under Sec. 250.198(a)(1). BSEE
recognizes that API Spec. Q1 applies to the manufacture of individual
components, however, as previously stated, the intent of the provision
is that the complete BOP stack must be manufactured pursuant to API
Spec. Q1, not the individual components of the BOP system.
Comments Related to Proposed Sec. 250.730(d)--Applicability of API
Spec. Q1 (Quality Control)
Summary of comments: Some comments requested that BSEE clarify this
provision since ``BOP stacks'' are not ``manufactured;'' i.e., only the
components are manufactured. In addition, compliance with the API
standard incorporated by reference should be sufficient; there is no
need for BSEE to add ISO requirements.
Response: BSEE recognizes that API Spec. Q1 applies to the
manufacture of individual components, however, as previously stated,
the intent of the provision is that the complete BOP stack must be
manufactured pursuant to API Spec. Q1, not the individual components of
the BOP system. The incorporation of ISO 17011 ensures the
[[Page 25945]]
manufacturers of the BOP systems follow the quality management system
required by API Spec. Q1.
Comments Related to Proposed Sec. 250.730(d)(1)--Approval of Other
Quality Programs
Summary of comments: With regard to the proposed option under Sec.
250.730(d)(1) for seeking BSEE approval for BOP equipment manufactured
under some quality program other than API Spec. Q1, a commenter stated
that operators are not typically in the business of manufacturing BOPs
for their operations. Instead, they typically select a MODU/Rig with a
BOP as part of the equipment package. Therefore, these requirements
should be placed upon the drilling contractor when applying for their
license to operate in the U.S.
Another commenter asserted that proposed Sec. 250.730(d)(1) would
allow for potential approval of an alternative quality program (instead
of API Spec. Q1) for the manufacture of BOP equipment, but that the
path for obtaining such approval does not appear to be available to
contractors (unless sponsored by an operator).
Response: Section 250.730(d) is applicable to operators/
lessees in the same way that most of the requirements in existing part
250 are applicable. Ultimately, the operator/lessee is responsible for
compliance with these requirements. As is common practice under the
regulations, however, operators may contract with others for the
performance of many of the required actions. In that case, the
operator/lessee and the person (contractor) actually performing that
activity are jointly and severally responsible for compliance with the
applicable requirement. (See Sec. 250.146(c).) The actions required by
Sec. 250.730(d) are no different.
Comments Related to Proposed Sec. 250.730(d)(1)--Request for
Alternative Quality Programs
Summary of comments: Commenters also noted the proposed rule refers
to approval of alternatives under Sec. 250.141, which is granted by
District Managers and Regional Supervisors, but requires that the
request be submitted to the Chief, Office of Offshore Regulatory
Programs (OORP). The commenter noted that, even if approval by the
Chief of OORP is obtained, the accepted alternative would not appear to
be binding on other District Managers or Regional Supervisors.
Response: BSEE agrees with the comment and revised final
Sec. 250.730(d) to require operators to send the requests to use an
alternative quality assurance program to the Chief of OORP and not to
submit the request under Sec. 250.141.
What information must I submit for BOP systems and system components?
(Sec. 250.731)
As provided for in the proposed rule, this section consolidates and
revises requirements from various former sections for including BOP
information in APDs, APMs or other submittals to BSEE. Among other
things, paragraphs (a) and (b) require submission of a complete
description and schematic drawings of the BOP system. Paragraph (c)
requires submission of a certification by a BAVO: That test data
demonstrates the BOP shear ram(s) will shear the drill pipe as
required; that the BOP was designed, tested, and maintained to perform
under the anticipated maximum environmental and operational conditions;
and that the accumulator system has sufficient fluid to operate the BOP
system without assistance from the charging system. Paragraph (d)
requires additional certification by a BAVO regarding the design and
functionality of BOPs used in certain circumstances (e.g., subsea
BOPs); while paragraph (e) requires descriptions of the autoshear,
deadman, and EDS systems on subsea BOPs. Paragraph (f) requires a
certification that the required MIA Report has been submitted within
the preceding 12 months. BSEE has revised proposed paragraphs (c) and
(d) of this section in the final rule as discussed in the comment
responses for this section.\16\
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\16\ Any information submitted to BSEE should identify any
confidential commercial or proprietary information. Any confidential
or proprietary information will be protected consistent with the
Freedom of Information Act (5 U.S.C. 552) and DOI's implementing
regulations (43 CFR part 2); section 26 of OCSLA (43 U.S.C. 1352);
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.
---------------------------------------------------------------------------
Comments Related to Proposed Sec. 250.731--Concerns About Prescriptive
Requirements
Summary of comments: BSEE received a comment stating that this
section is overly prescriptive on certain issues, including accumulator
sizing, testing, BOP configurations, and QA/QC oversight.
Another commenter claimed that this section would be unnecessary
given that effective verification processes are already in place, and
that the additional verifications required by this rule would not
increase the safety of operations or the reliability of equipment.
Response: BSEE disagrees with the comment that this
section is overly prescriptive. The specific information required to be
submitted with APDs, APMs and other submissions is necessary to help
BSEE make informed decisions in the approval process by providing a
clear understanding of the BOP system, equipment and operations. These
provisions essentially set performance-based goals for the operators
and verifiers, and several of the descriptions of processes and
equipment that must be verified are broad enough to allow the persons
doing the verification some flexibility to decide whether, under the
specific circumstances, it is the equipment or process that should be
verified.
BSEE also disagrees with the comment indicating that these
verification requirements are unnecessary. BSEE believes that these
certification and verification provisions will serve as a useful tool
for BSEE and the industry to better ensure--as compared to the current
rules and industry practices--that equipment and processes function as
intended to protect safety and the environment.
Comments Related to Proposed Sec. 250.731(a)--BOP System Connections
Summary of comments: A commenter noted that Sec. 250.731(a)--
requiring descriptions of BOP systems--does not address how the devices
along the BOP stack are connected, and that there is no mention of
capping or containment points along the BOP stack. The commenter
suggests that the BOP system description should address technology that
enables better containment and is integrated with that system.
Locations along those devices at which containment and capture
equipment may be attached should also be included in the system
description.
Response: BSEE disagrees with the commenter that capping
or containment points should be included in this provision. It is
unclear from the comment what devices, technology, and shortcomings the
commenter would propose including in Sec. 250.731(a). In any case,
source control and containment requirements are adequately covered
under final Sec. 250.462, as described elsewhere in this document.
Comments Related to Proposed Sec. 250.731(a)(7) Through (9)--
Calculations
Summary of comments: Another commenter observed that the
calculations required in paragraphs Sec. 250.731(a)(7) through (9)
should demonstrate that there is adequate pressure available to operate
each item, especially shear rams. The commenter suggested adding
information to the rule
[[Page 25946]]
that confirms this is the purpose for conducting the calculations, and
suggests that the calculations should take into account the actual
planned sequence of BOP operation for deadman, autoshear, and any
emergency disconnect programmed operations.
Response: BSEE disagrees with the suggestion that we
include the purpose for conducting the calculations, and specifying
that the calculations must take into account the planned sequence. BSEE
will review the volume and pre-charge accumulator calculations required
by paragraphs Sec. 250.731(a)(7) and (9), regardless of sequence, to
determine that they are adequate to operate all of the required BOP
functions specified in Sec. Sec. 250.734(a)(3) and 250.735(a) without
assistance from the charging system.
Comments Related to Proposed Sec. 250.731(c)--Verification of Shearing
Test Data
Summary of comments: Commenters questioned the requirement in
proposed paragraph Sec. 250.731(c)(1) for verification of test data on
shearing capabilities. Since a test facility to simulate subsea
conditions for shear testing does not exist, the requirement for shear
testing at water depth implies the BOP is in an environment that
simulates the required water depth (instead of on the surface, where
shear tests are currently performed). The commenters asserted that
there is a risk of damaging equipment when carrying out shearing tests
under these conditions. The current industry practice is to apply
proven calculation methods to surface shear test data and relevant
maximum allowable working pressure conditions. The commenters claimed
that if shear tests must be performed under subsea conditions, all of
the past shear test data will be irrelevant, and that the time and
effort to re-test will likely shut down the GOM for a considerable
time. The commenters requested that BSEE revise this requirement to
allow supporting engineering calculations instead of test data for
shear capability.
Another commenter recommended that the equipment manufacturers
should demonstrate shearing capability and provide shearing data
instead of operators having to do so.
Response: BSEE agrees that there are technological
limitations with testing facilities to simulate subsea conditions. BSEE
currently allows, and will continue to allow, operators to use
calculations to help verify shearing at water depth. In fact, this
provision expressly references final Sec. 250.732, which clearly
provides that calculations are used in conjunction with testing to
demonstrate that the pipe can be sheared at the well. Therefore, no
revision to paragraph Sec. 250.731(c)(1) is warranted.
Comments Related to Proposed Sec. 250.731(c)(2)--Most Extreme
Anticipated Conditions
Summary of comments: Most of the comments concerning paragraph
Sec. 250.731(c)(2) were related to the requirement for verification
that the BOP has been designed, tested and maintained to perform under
the ``most extreme anticipated conditions.'' Commenters expressed
concerns that the term is undefined and asked whether this phrase
refers, for example, to the worst-case discharge or a kick. Commenters
also stated that shearing and sealing on flowing wells at worst-case
discharge rates is not a typical drilling BOP testing scenario, and the
commenters described how testing to verify BOP capabilities is commonly
performed. Commenters also pointed out potential hazards from testing
for worst-case discharges. Commenters suggested that BSEE's emphasis
should be on early detection and correct shut in procedures. A
commenter asserted that none of the BOPs currently in use would meet
the ``most extreme anticipated conditions'' requirement, and that OEMs
do not qualify BOP components under flowing conditions. Commenters
recommended that the requirement should be to ``ensure the BOP is
designed, tested, and maintained to perform under the anticipated
conditions of the well.''
Response: As previously discussed, BSEE has revised
paragraph Sec. 250.731(c)(2) by replacing ``to perform at the most
extreme anticipated conditions'' with ``to perform under the maximum
conditions anticipated to occur at the well.'' This change clarifies
this requirement by relying on reasonably predictable, site-specific
conditions instead of hypothetical worst-case conditions. In any event,
if an operator has any questions about the maximum anticipated
conditions in any specific case, it may request assistance from the
District Manager.
Comments Related to Proposed Sec. 250.731(c)(3)--Accumulator Systems
Summary of comments: The primary concern raised by commenters
regarding paragraph Sec. 250.731(c)(3) was that there appeared to a
conflict between the requirement for the accumulator systems, on the
one hand, and API Standard 53, as well as the current work industry is
undertaking to update the specifications, on the other. Commenters were
also concerned that this requirement may impact compliance with API
Specs. 16A and 16D. Commenters suggested that BSEE revise this section
to require the accumulator system to have sufficient fluid, as defined
by Sec. 250.734(a)(3) for subsea accumulators and Sec. 250.735(a) for
surface accumulators, to function the BOP system without assistance
from the charging system. Other commenters suggested that BSEE revise
this provision to refer to the accumulator volume test in API Standard
53.
Response: BSEE does not agree that the suggested changes
to paragraph Sec. 250.731(c)(3) are necessary given that, as discussed
elsewhere, BSEE has revised the final accumulator requirements of Sec.
250.734(a)(3) for subsea accumulators and Sec. 250.735(a) for surface
accumulators to more closely align with API Standard 53. Those
revisions are consistent with recommendations made by some of these
commenters.
Comments Related to Proposed Sec. 250.731(d)(1)--Verification of BOP
Design
Summary of comments: Several of the comments on proposed paragraph
Sec. 250.731(d)(1) raised concerns with the requirement for
verification that the BOP stack is designed for the specific equipment
on the rig and for the specific well design. Commenters asserted that
the BOP stacks are not designed for specific equipment; they are
selected in consideration of such equipment, which is designed to meet
the RWP conditions for the site. Also, BOP stacks are not moved from
rig to rig, they are part of the rig equipment and selected to suit the
rig design and capabilities. Commenters suggested that BSEE revise this
provision to require the BOP stack be suitable for use with the
specific equipment on the rig, instead of designed for the equipment.
Response: BSEE does not agree that it is appropriate to
remove the reference to ``designing'' the BOP stack. The commenters
appear to be interpreting that term unnecessarily restrictively. BSEE
believes that the process described by the commenters for how BOP
stacks are put together with regard to the equipment on the rig is
effectively what BSEE intended by ``designed.'' BSEE does agree,
however, with the commenters that the BOP stack must be suitable for
use with the specific equipment on the rig. Accordingly, BSEE has
revised final Sec. 250.731(d)(1) by inserting ``and suitable'' after
the word ``designed.''
[[Page 25947]]
Comments Related to Proposed Sec. 250.731(d)--Independent Verification
Summary of comments: A commenter recommended that BSEE revise
proposed Sec. 250.731(d) in order to require independent verification
of all OCS operations requiring a BOP (rather than just the operations
specified in the proposed rule), since the purposes of independent
verification are not unique to subsea BOPs, surface BOPs on a floating
facility, or BOPs operating in a HPHT environment. The commenter
recommended that BSEE revise the rule in this way and then reconsider,
after several years, whether the program is working effectively and
delivering results, or whether it should be scaled back.
Response: BSEE does not agree that the requested change is
appropriate at this time. The verifications required in paragraphs
Sec. 250.731(a) through (c) are already applicable to all BOPs.
Paragraphs Sec. 250.731(d) through (f) only apply to BOPs used in
certain situations because BSEE determined that those situations
present higher risks than the other situations in which BOPs are used.
The certification and/or verification requirements in paragraphs Sec.
250.731(d) through (f) are specific to the equipment, systems or
procedures that are related to such risks. BSEE does not believe those
same concerns apply equally to the BOP situations described in
paragraphsSec. 250.731(a) through (c).
Comments Related to Proposed Sec. 250.731(e)--Subsea BOP Descriptions
Summary of comments: Regarding the proposed requirement in
paragraph Sec. 250.731(e) that subsea BOP descriptions include a
description of the EDS, commenters recommended that BSEE add ``if
installed'' after ``EDS systems.''
Response: BSEE does not agree that this change is
appropriate. BSEE already recognizes that an EDS system is not
installed or necessary on every rig with a subsea BOP, and Sec.
250.731(e) is not intended to require descriptions for EDS systems that
are not present and not otherwise required by the regulations (see
Sec. 250.734(a)(6)).
Comments Related to Proposed Sec. 250.731(f)--MIA Report
Summary of comments: A commenter suggested that the MIA report
certification required by Sec. 250.731(f) is equivalent to the
certification in the APD. The commenter suggested that the regulation
be revised to consider either an MIA or an APD certification submitted
within the past 12 months as sufficient. The commenter also asserted
that the regulation does not identify who issues the certification.
Response: This comment is vague and unclear. The MIA
certification required in paragraph (f) must be included in the
applicable APD or APM, but BSEE is not aware of any duplication between
this requirement and any other certification requirement. BSEE does not
specify who must provide the certification in paragraph Sec.
250.731(f); so any appropriate person acting on behalf of the operator/
lessee may do so.
Summary of comments: Many commenters recommended that BSEE revise
or delete Sec. 250.731(f) as duplicative or unnecessary and
burdensome. Some commenters requested that BSEE clarify whether this
certification is required only if an APD has not been submitted in the
previous 12 months. Commenters suggest that, if it is in addition to an
APD submitted within the prior 12 months, it appears to be an
unnecessary time and expense burden.
Other commenters stated that this report is unnecessary, asserting
that all of the requested information is already reported in the APD/
APM and the BOP and Well Compatibility Certificate.
Response: BSEE does not agree that paragraph Sec.
250.731(f) should be deleted or revised for any of the reasons
suggested by the commenters. As required by Sec. 250.731, a
certification statement as described in paragraph (f) must be included
each time an APD or APM is submitted. Therefore, if multiple APDs/APMs
are submitted within a 12 month period, each one must include a
certification statement that an MIA Report was completed within the 12
months preceding that APD/APM. However, the regulation does not require
that a certification be submitted every 12 months separately from an
APD/APM. Nor does it require that an MIA Report be completed or
submitted every time an APD or APM is submitted.
In addition, BSEE disagrees that the requested information (i.e., a
certification statement regarding completion of an MIA Report) is
already required to be submitted with an APD. Section 250.731(f) itself
establishes that requirement. BSEE is unaware of any BOP and Well
Compatibility certificate, as mentioned by the commenter, that is
currently applicable and duplicative of Sec. 250.731(f).
Comments Related to Proposed Sec. 250.731(c) and (d)--BAVOs
Summary of comments: Several commenters highlighted the fact that
BAVOs do not currently exist and that BAVOs cannot be ``approved'' by
BSEE until after the effective date of the final rule (i.e., 3 months
after publication); therefore, compliance with the proposed Sec.
250.731(c) and (d) certification requirements within 3 months, as
proposed, would not be possible. Some commenters claimed this could
result in a bottleneck that would effectively become a moratorium on
OCS drilling. Given the other demands of the proposed rule, some
commenters asserted that 3 years is a more feasible timeline for
implementation of this requirement. Other commenters, however,
requested that the BAVO certification requirements should not go into
effect until 12 months after the initial BAVO list is published.
Response: As previously discussed in part V.C of this
document, BSEE has revised the final rule to extend the compliance
dates for certain provisions, including those that require the use of a
BAVO. Under the final rule, operators' APD will not be required to
submit BAVO certifications under Sec. 250.731 until one year from the
date when BSEE publishes a list of approved organizations. BSEE
anticipates that most of the current independent third-parties
currently used by industry could become BAVOs; thus, one year will be
sufficient for operators to make use of a BSEE-developed list of BAVOs
suitable for this rulemaking.
Summary of comments: A commenter asked if BSEE approval as a
verification organization is open for any company that applies.
Response: Any verification organization that seeks
approval and submits the information specified in Sec. 250.732(a) to
BSEE may be considered by BSEE for approval as a BAVO.
Summary of comments: A commenter suggested that BSEE should allow
use of current verification companies whenever a BAVO is not available.
Response: Under Sec. 250.732, BSEE will not require the
use of BAVOs until one year after BSEE establishes a BAVO list. After
that occurs, there will not be any need to use other verification
companies. BSEE expects many existing independent third-parties and
verification companies to become BAVOs.
Summary of comments: Some commenters asserted that the requirements
to use BAVOs for certification could create conflicts of interest and
render the third-party neutrality concept ineffective. That is, if BSEE
approves the verification organization, and the operators/contractors
are required to hire them, neither BSEE nor the BAVO nor the
[[Page 25948]]
operators would be independent of each other.
A commenter asserted that BAVOs provide BSEE with selective powers
not generally associated with a regulatory organization in a free
market system. Commenters recommended that BSEE remove/delete all
references to BAVOs due to potential legal implications and restriction
of trade.
Response: BSEE disagrees with the suggestion that the BAVO
approach will compromise third-party neutrality or effectiveness or is
otherwise impermissible. To the contrary, approval of verification
organizations by BSEE will ensure that the BAVOs are independent of the
parties whose crucial equipment and processes the BAVO will review and
evaluate. Other regulatory regimes throughout the world use similar
systems.
Summary of comments: Some commenters also asked how BAVOs will work
and what specific factual situations BAVOs would or would not be able
to certify or verify under Sec. Sec. 250.731(c) and (d) and 250.732
(e.g., how will a BAVO be able to verify that a stack has not been
compromised from previous service?).
Response: These comments seek answers to hypothetical
questions about how the rules may be implemented in very specific
factual situations. It would be premature and speculative for BSEE to
attempt to do so. A BAVO will need to certify or verify the matters
specified in Sec. Sec. 250.731 and 250.732, but those rules do not
prescribe exactly how the BAVO must perform those tasks. Rather, the
purpose of BSEE evaluating and approving verification organizations to
serve as BAVOs is to ensure that they are knowledgeable and capable
enough to perform these tasks without BSEE needing to prescribe in
great detail how to do so under a very specific factual scenario.
What are the BSEE-approved verification organization (BAVO)
requirements for BOP systems and system components? (Sec. 250.732)
As provided for in the proposed rule, this new section creates a
process for BSEE to identify BAVOs and sets out various situations that
require verification or a report by a BAVO. Paragraph (a) clarifies
that BSEE will develop and maintain a list of BAVOs on its public
website, and that compliance with the BAVO-related provisions of the
rule will not be required until 1 year after BSEE issues that list.
Paragraph (a) also specifies the information (regarding qualifications)
that applicants for inclusion on the BAVO list must submit; while
paragraph (b) lists the types of actions (e.g., shear testing) for
which an operator must submit BAVO verification. Paragraph (c) of this
section requires additional BAVO verifications for BOPs and related
equipment associated with wells in an HPHT environment. Paragraph (d)
requires an operator to submit to BSEE an annual MIA report prepared by
a BAVO. These BAVO actions will help BSEE ensure that BOPs will perform
as necessary to protect safety and the environment from losses of well
control. BSEE has revised certain provisions of the proposed rule in
final Sec. 250.732 as discussed in the comment responses for this
section and in part V.C of this document.
Comments Related to Proposed Sec. 250.732--Existing Quality Control
Systems
Summary of Comments: Many comments asserted that operators already
have adequate systems in place for quality control (e.g., voluntary
compliance with API Spec. Q1 or similar standards), to verify
repeatability of testing, and/or to comply with existing requirements
under BSEE's regulations for SEMS programs (including a requirement for
SEMS program audits). Commenters suggested that these systems
adequately address many of the same items subject to BAVO verification
under proposed Sec. 250.732, and thus, that BAVO verification of
similar issues is unnecessary and overly burdensome.
Response: BSEE does not agree that the BAVO-related
requirements of Sec. 250.732 are unnecessary; nor does BSEE agree that
those requirements will not provide additional value, to justify the
burdens on the operators, compared to existing voluntary industry
practices and BSEE's other regulatory requirements. Third-party
consultants hired by the operator for quality control, to confirm
equipment testing repeatability, or for a SEMS audit do not address the
specific BOP and well-control issues required by the present rule.
Quality control and equipment testing repeatability are, as stated in
the comments, addressed by several voluntary industry standards. While
compliance with industry standards that are not incorporated in the
regulations is voluntary, the BAVO verifications required by the final
rule will document compliance with key regulatory requirements for
ensuring that BOPs will perform as needed to protect safety and the
environment. For example, the final rule requires verification of shear
testing, pressure integrity testing, and related calculations for
verifying that the equipment is suitable for the conditions under which
it will operate.
In addition, while BSEE appreciates the value of operators'
existing quality control programs, including those based on API Spec.
Q1 or similar standards, BSEE cannot rely on such voluntary programs to
provide the information or assurances that BSEE needs. As explained in
the proposed rule, Sec. 250.732 is necessary to ensure that BSEE
receives accurate information regarding BOP systems so that BSEE may
ensure the system is appropriate for the proposed use. In particular,
the verification and documentation of such information by a BAVO would
enhance BSEE's review of the information in APDs and APMs. (See 80 FR
21509, 21522.) BSEE believes that the importance and complexity of BOP
systems warrant a thorough and regular assessment of the systems and
verification that design, installation, maintenance, inspection, and
repair activities for such systems are documented and traceable. The
BAVO-related provisions in Sec. 250.732 will serve this purpose,
through independent engineering reviews to ensure that required testing
is effective at ensuring the equipment will perform as designed under
the conditions to which it will be exposed. (See 80 FR 21509.)
Voluntary compliance with industry standards alone cannot provide BSEE
with such assurances.
Similarly, BSEE believes the SEMS regulations are an important step
toward building an offshore safety culture that includes oil and gas
companies as well as their employees and contractors, and the SEMS
rules will result in substantial safety and environmental protection
improvements over time. However, the SEMS requirements are very
different from, and serve different purposes than, the BAVO-related
requirements. The SEMS regulations focus on creating internal safety
and environmental management systems that will foster safety and
environmental protection by ensuring that offshore personnel comply
with policy and procedures identified in a facility's SEMS plan. The
SEMS rules lay out largely performance-based elements that the SEMS
plan must address in areas such as hazards management, inspections and
maintenance, training, and quality assurance and mechanical integrity
of critical equipment. (See Sec. 250.1901.) However, the SEMS rules do
not prescribe specific technical requirements that the plans must
ensure are met. Nor is BSEE routinely informed of the specific results
from actual implementation of the SEMS plan at a rig.
[[Page 25949]]
By contrast, BAVO verifications or reports under Sec. 250.732 will
provide BSEE with important information regarding, among other things:
Actual shearing capabilities (through recognized testing protocols and
analyses), and pressure integrity testing (see Sec. 250.732(b));
comprehensive review of the BOP system demonstrating the performance
and reliability of the equipment; and annual reports by the BAVO on
mechanical integrity for BOPs used in certain high risk environments.
BSEE needs the information that BAVOs will verify or create in order to
ensure that effective and appropriate well-control equipment and
procedures are actually in place to prevent or minimize future well-
control events. BSEE cannot get that kind of information through
operators' voluntary compliance with either industry standards or the
SEMS regulations.
However, in response to commenters' suggestions that BSEE allow the
continued use of independent third-parties to perform verifications (as
required under provisions of the existing regulations that are being
replaced by these final rules),\17\ and to comments requesting
additional time to comply with the BAVO requirements, BSEE has revised
Sec. 250.732(a) of the final rule. The revised paragraph will require
that an independent third-party, meeting the same criteria as specified
in former Sec. 250.416(g)(1), perform the same functions that a BAVO
must perform until such time as the operator uses a BAVO to perform
those functions (i.e., no later than 1 year after BSEE publishes a list
of BAVOs).
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\17\ Former Sec. Sec. 250.416(e) and (f), 250.515(c) and (d),
250.615(c) and (d), and 250.1705(c) and (d) require verifications of
various aspects of drilling, completion, workover and
decommissioning operations, respectively. Those requirements are
superseded and replaced by the requirements of final Sec.
250.731(c) and (d).
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Comments Related to Proposed Sec. 250.732(a)--Timing of Compliance
With BAVO Requirements
Summary of Comments: Many comments asserted a need for sufficient
time to comply with the BAVO-related requirements after BSEE issues a
list of BAVOs. Specifically, multiple comments addressed the need for
time to select a BAVO and to have the BAVO implement the required
verifications. These comments raised essentially the same concerns
previously discussed with regard to BAVO certifications as required by
Sec. 250.731.
Response: BSEE, as previously explained, has revised the
final rule to extend the time required to comply with the requirements
to utilize a BAVO until one year after BSEE publishes a list of BAVOs.
BSEE has determined that this will provide enough time for operators to
select a BAVO and for the BAVO to perform the required verifications.
In the interim, for the reasons previously discussed, BSEE has revised
final Sec. 250.732(a) to require operators to use an independent
third-party to provide the certifications, verifications, and reports
that a BAVO must provide after the requirements to use a BAVO become
effective.
Comments Related to Proposed Sec. 250.732(a)--General Comments on
BAVOs
Summary of Comments: Multiple comments raised the following issues:
(a) BSEE is restricting industry's choice of third-parties by requiring
use of a BAVO; BSEE should provide industry with the opportunity to
comment on the intended detailed work scope for a BAVO; (b) industry
must be provided with a means of recourse to BSEE on decisions made by
BAVOs where there is a difference of opinion regarding the application
or interpretation of a rule or standard; and (c) some of the proposed
requirements imply that the BAVO may make recommendations on how to
improve the fabrication, installation, operation, maintenance,
inspection, and repair of operator equipment.
Response: Concerning the comments on BSEE restricting
industry's choice of third-parties by requiring use of a BAVO, BSEE is
aware that the requirement to use BAVOs will impose some limits on the
choices of third-parties. However, that is an unavoidable feature of
any requirement that depends on the use of a third-party having
relevant qualifications necessary to perform specific tasks, whether
BSEE determines who meets those qualifications or the operators make
those decisions themselves. In addition, for the reasons stated in the
proposed rule, BSEE determined that it is necessary for each BAVO
performing the important safety and environmental tasks specified in
Sec. Sec. 250.731 and 250.732 to be technically qualified, experienced
and capable of performing the functions necessary for BSEE and the
public, as well as the operators, to be sure that the BOP systems and
equipment will function as intended. Therefore, in its oversight role,
it is necessary that BSEE make the first decisions as to which third-
parties are eligible to be used for these purposes, rather than leaving
that decision entirely to the operators whose equipment and processes
must be evaluated and verified to be suitable and capable of performing
their intended functions.
In any case, BSEE will publish a list of BAVOs so that choices will
be available to operators. BSEE expects that there will also be enough
listed BAVOs that operators will be able to base their choices between
BAVOs on various factors, such as experience, price, availability, and
access to appropriate technology. After the initial BAVO list is
published, BSEE will continue to evaluate other verification
organizations that apply for approval as BAVOs and will refresh or
supplement the list from time to time as necessary to ensure that
choices continue to be available to operators.
Concerning the suggestion that BSEE should provide industry with
the opportunity to comment on the detailed scope of the work that BSEE
intends BAVOs to perform, the final rule, in Sec. Sec. 250.731 and
250.732, provides the scope of the certifications and verifications
that BAVOs must perform. As to how a BAVO will perform each specific
task for a specific facility, the BAVO and the operator employing the
BAVO will work together to determine the precise nature and execution
of the work. BSEE expects that the BAVOs and operators will establish
these parameters through the contracting process.
Concerning the comments that industry should have a means of
recourse to BSEE on decisions made by BAVOs where there is a difference
of opinion regarding application or interpretation of a rule or
standard, several means exist for BSEE to resolve such differences of
opinion. In the first place, BSEE expects the BAVO and the operator to
communicate with each other and attempt to resolve any differences of
opinion in a mutually acceptable way. However, if necessary, the
operator may refer requests for an interpretation of a specific
regulation, or a standard incorporated in the regulations, to BSEE for
assistance. In addition, if it appears that there is a broader need for
an interpretation to guide BAVOs and operators, BSEE will consider
issuing a NTL, an Information to Lessees and Operators, or a similar
notice of interpretation or guidance, as appropriate.
BSEE disagrees with the comments suggesting that the proposed
requirements imply that the BAVO may make recommendations on how to
improve the fabrication, installation, repair, etc., of operator
equipment. The rule does not state or imply that a BAVO must or should
make recommendations to an operator with respect to the equipment.
However, BSEE does expect
[[Page 25950]]
the BAVO process to help, over time, the industry to improve the
performance of the equipment and to develop more and better testing
protocols. (See 80 FR 21509.)
Comments Related to Proposed Sec. 250.732(a)(1) Through (7)--Criteria
for BAVOs
Summary of Comments: Multiple comments asserted that the criteria
used to evaluate the technical knowledge of the BAVOs must be
established in advance and be more detailed than the proposed criteria.
A commenter also suggested that industry should be consulted in helping
to identify qualified candidates. However, other commenters recommended
that the regulation expressly require BAVOs to be independent of
equipment manufacturers and operators.
Response: BSEE disagrees with the comments calling for
more detailed BAVO criteria. Proposed Sec. 250.732(a)(1) through (6)
(renumbered as Sec. 250.732(a)(3)(i) through (vi) in the final rule)
specified the criteria that BSEE would apply in evaluating the
qualifications, caliber, and technical knowledge of each verification
organization before deciding whether it should be approved. The
commenters on this issue provided no additional detailed criteria for
BSEE to apply in evaluating verification organizations, and BSEE sees
no reason to add more criteria at this time.
In addition, BSEE disagrees with the suggestion that industry
should be consulted in helping to identify BAVO candidates. As
explained in the proposal, the purpose of the BAVO concept is to ensure
that BOP equipment is monitored during its lifecycle by an
``independent third-party'' to verify compliance with the regulations,
OEM recommendations, and recognized engineering practices. (See 80 FR
21522.) As explained in the proposed rule, a potential BAVO must apply
to BSEE for approval, and must submit specific information and
documentation demonstrating its qualifications and experience, as
provided in Sec. 250.732(a)(1) through (7). (See id. at 21510, 21522.)
BSEE will then evaluate that specific information to determine whether
the verification organization is qualified to carry out the BAVO-
related tasks listed in Sec. 250.732(b) through (d) and in other
sections. If BSEE determines, based on the information submitted and
BSEE's understanding of the specific tasks BAVOs must perform, that an
organization is qualified to perform those task, BSEE will add that
organization's name to the BAVO list.
Comments Related to Proposed Sec. 250.732(b)(1)(i)--BOP Shearing Tests
Summary of Comments: Multiple commenters raised concerns with the
proposed requirement in Sec. 250.732(b)(1)(i) for shearing tests that
demonstrate the BOP will shear the drill pipe and any electric-, wire-,
and slick-line to be used in the well. They asserted that many rigs do
not currently have shearing capability that would conform to that
requirement and cannot obtain such equipment within the 3 months
provided by the proposed rule for compliance. As a result, many
drilling operations could be shutdown. They requested that BSEE extend
the requirement for shearing the exterior control lines (e.g., wire-
line) to 5 years.