[Federal Register Volume 83, Number 92 (Friday, May 11, 2018)]
[Proposed Rules]
[Pages 22128-22162]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-09305]
[[Page 22127]]
Vol. 83
Friday,
No. 92
May 11, 2018
Part II
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 Revisions; Proposed Rule
Federal Register / Vol. 83 , No. 92 / Friday, May 11, 2018 / Proposed
Rules
[[Page 22128]]
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DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental Enforcement
30 CFR Part 250
[Docket ID: BSEE-2018-0002; 189E1700D2 ET1SF0000.PSB000 EEEE500000]
RIN 1014-AA39
Oil and Gas and Sulfur Operations in the Outer Continental
Shelf--Blowout Preventer Systems and Well Control Revisions
AGENCY: Bureau of Safety and Environmental Enforcement, Interior.
ACTION: Proposed rule.
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SUMMARY: The Bureau of Safety and Environmental Enforcement (BSEE) is
proposing to revise existing regulations for well control and blowout
preventer systems. This proposed rule would revise requirements for
well design, well control, casing, cementing, real-time monitoring
(RTM), and subsea containment. These revisions modify regulations
pertaining to offshore oil and gas drilling, completions, workovers,
and decommissioning in accordance with Executive and Secretary of the
Interior's Orders to ensure safety and environmental protection, while
correcting errors and reducing certain unnecessary regulatory burdens
imposed under the existing regulations. Accordingly, after thoroughly
reexamining the original Blowout Preventer Systems and Well Control
final rule (WCR), experiences from the implementation process, and BSEE
policy, BSEE proposes to amend, revise, or remove current regulatory
provisions that create unnecessary burdens on stakeholders while
ensuring safety and environmental protection. The proposed regulations
would also address various issues and errors that were identified
during the implementation of the recent rulemaking on these issues.
DATES: Submit comments by July 10, 2018. BSEE may not fully consider
comments received after this date. You may submit comments to the
Office of Management and Budget (OMB) on the information collection
burden in this proposed rule by June 11, 2018. The deadline for
comments on the information collection burden does not affect the
deadline for the public to comment to BSEE on the proposed regulations.
ADDRESSES: You may submit comments on the rulemaking by any of the
following methods. Please use the Regulation Identifier Number (RIN)
1014-AA39 as an identifier in your message. See also Public
Availability of Comments under Procedural Matters.
Federal eRulemaking Portal: http://www.regulations.gov. In
the entry titled Enter Keyword or ID, enter BSEE-2018-0002 then click
search. Follow the instructions to submit public comments and view
supporting and related materials available for this rulemaking. BSEE
may post all submitted comments.
The American Petroleum Institute (API) provides free
online public access to view read only copies of its key industry
standards, including a broad range of technical standards. All API
standards that are safety-related and that are incorporated into
Federal regulations are available to the public for free viewing online
in the Incorporation by Reference Reading Room on API's website at:
http://publications.api.org.\1\ 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 to purchase standards is: http://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents.
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\1\ To view 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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The International Organization for Standardization (ISO)
creates documents that provide requirements, specifications/government-
cited-safety documents. ISO creates documents that provide
requirements, specifications, guidelines or characteristics that can be
used consistently to ensure that materials, products, processes and
services are fit for their purposes. All ISO International Standards
are available at the ISO Store for purchase, https://www.iso.org/store.html.
For the convenience of members of the viewing public who
may not wish to purchase copies or view these incorporated documents
online, they may be inspected at BSEE's office, 45600 Woodland Road,
Sterling, Virginia 20166, or by sending a request by email to
[email protected].
Send comments on the information collection in this rule
to: Interior Desk Officer 1014-0028, Office of Management and Budget;
202-395-5806 (fax); email: [email protected]. Please send a
copy to BSEE.
Public Availability of Comments--Before including your address,
phone number, email address, or other personal identifying information
in your comment, you should be aware that your entire comment--
including your personal identifying information--may be made publicly
available at any time. In order for BSEE to withhold from disclosure
your personal identifying information, you must identify any
information contained in the submittal of your comments that, if
released, would constitute a clearly unwarranted invasion of your
personal privacy. You must also briefly describe any possible harmful
consequence(s) of the disclosure of information, such as embarrassment,
injury, or other harm. While you can ask us in your comment to withhold
your personal identifying information from public review, we cannot
guarantee that we will be able to do so.
FOR FURTHER INFORMATION CONTACT: For technical questions contact Fred
Brink, GOMR District Operations Support, (504) 736-2400, or by email:
[email protected]; for procedural questions contact Kirk Malstrom,
Regulations and Standards Branch, (202) 258-1518, or by email:
[email protected].
SUPPLEMENTARY INFORMATION:
Executive Summary
In the immediate aftermath of the Deepwater Horizon incident in
2010, BSEE adopted several recommendations from multiple investigation
teams in order to improve the safety of offshore operations.
Subsequently, BSEE published the Blowout Preventer Systems and Well
Control final rule (WCR) on April 29, 2016. The WCR consolidated the
equipment and operational requirements for well control into one part
of BSEE's regulations; enhanced blowout preventer (BOP), well design,
and modified well-control requirements; and incorporated certain
industry technical standards. Most of the original WCR provisions
became effective on July 28, 2016.
Although the WCR addressed a significant number of issues that were
identified during the analysis of the Deepwater Horizon incident, BSEE
recognized that BOP equipment and systems continue to improve
technologically and well control processes also evolve. Therefore,
since the WCR became effective in 2016, BSEE has continued to engage
with the offshore oil and gas industry, Standards Development
Organizations (SDOs), and other stakeholders. During the course of
these engagements, BSEE identified issues and stakeholders expressed a
[[Page 22129]]
variety of concerns regarding the implementation of the WCR. For
instance, oil and natural gas operators raised concerns about certain
regulatory provisions that impose undue burdens on their industry, but
do not significantly enhance worker safety or environmental protection
(e.g., how RTM is monitored and utilized onshore, a strictly enforced
0.5ppg drilling margin, having requirements inconsistent with API
Standard 53--an American National Standards Institute (ANSI)
accredited, voluntary consensus standards development organization, and
delays waiting for certain BSEE approvals during cementing operations).
Other stakeholders suggested that certain regulatory requirements do
not properly account for advances or limitations in technology and
processes. Further, BSEE received numerous questions regarding the
proper interpretation and application of provisions viewed to be
unclear or ambiguous, requiring BSEE to provide substantial informal
guidance regarding the terms of the WCR.
Accordingly, after thoroughly reexamining the original WCR,
experiences from the implementation process, and BSEE policy, BSEE
proposes to amend, revise, or remove current regulatory provisions that
create unnecessary burdens on stakeholders while ensuring safety and
environmental protection. The proposed regulatory changes also reflect
BSEE's consideration of the public comments and stakeholders'
recommendations pertaining to the requirements applicable to offshore
oil and gas drilling, completions, workovers, and decommissioning. This
proposed rulemaking would revise regulatory provisions in Subparts A,
B, D, E, F, G, and Q on topics such as, but not limited to:
Notifications and submittals to BSEE;
Drilling margins;
Lift boats;
Real-time monitoring;
BSEE Approved Verification Organizations (BAVOs);
Accumulator systems;
BOP and control station testing;
Coiled tubing; and
Mechanical barriers (packers and bridge plugs).
BSEE utilized the best available and most pertinent data to analyze
the economic impact of the proposed changes. That analysis indicates
that the estimated overall economic impact will benefit the industry
over the next 10 years because of the substantial reduction in
compliance costs while ensuring safety and environmental protection.
In keeping with the Executive and Secretary's Orders, BSEE
undertook a review of the 2016 Well Control Final Rule with a view
toward the policy direction of encouraging energy exploration and
production on the OCS and reducing unnecessary regulatory burdens while
ensuring that any such activity is safe and environmentally
responsible. BSEE carefully analyzed all 342 provisions of the 2016
Well Control Final Rule, and determined that only 59 of those
provisions--or less than 18% of the 2016 Rule--were appropriate for
revision. In the process, BSEE compared each of the proposed changes to
the 424 recommendations arising from 26 separate reports from 14
different organizations developed in the wake of and response to the
Deepwater Horizon disaster, and determined that none of the proposed
changes ignores or contradicts any of those recommendations, or would
alter any provision of the 2016 Well Control Final Rule in a way that
would make the result inconsistent with those recommendations. Further,
nothing in this proposed rule would alter any elements of other rules
promulgated since Deepwater Horizon, including the Drilling Safety Rule
(Oct. 2010), SEMS I (Oct. 2010), and SEMS II (April 2013). BSEE's
review has been thorough, careful, and tailored to the task of reducing
unnecessary regulatory burdens while ensuring that OCS activity is safe
and environmentally responsible.
Table of Contents
I. Background
A. BSEE Statutory and Regulatory Authority and Responsibilities
B. Purpose and Summary of the Rulemaking
C. Summary of Documents Incorporated by Reference
D. New Executive and Secretary's Orders
E. Stakeholder Engagement
II. Section-by-Section Discussion of Proposed Changes
III. Additional Comments Solicited
A. BOP Testing Frequency
B. Economic Data
IV. Procedural Matters
I. Background
A. 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 the Interior (Secretary) to lease
the Outer Continental Shelf (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 exploration for and development
of oil and gas on the OCS, to ensure that those operations protect the
environment, and to implement advancements in technology. BSEE also
conducts onsite inspections to assure compliance with regulations,
lease terms, and approved plans and permits. 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 \2\ perform throughout the OCS. These well
operations are the primary focus of this rulemaking.
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\2\ BSEE's regulations at 30 CFR part 250 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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B. Purpose and Summary of the Rulemaking
This proposed rule would amend and update certain provision of the
Blowout Preventer Systems and Well Control regulations and update the
regulations to better implement BSEE policy. This proposed rule would
fortify the Administration's position towards facilitating energy
dominance leading to increased domestic oil and gas production, and
reduce unnecessary burdens on stakeholders while ensuring safety and
environmental protection. Since 2010, BSEE has promulgated many
rulemakings (e.g., Safety and Environmental Management Systems (SEMS) I
and II, the final safety measures rule, and the production safety
systems final rule) to improve worker safety and environmental
protection. Additionally, on April 29, 2016, BSEE published a final
rule to consolidate into one part the equipment and operational
requirements that were found in various parts of BSEE's regulations
pertaining to well control for offshore oil and gas drilling,
completions, workovers, and decommissioning (81 FR 25888). That final
rule addressed issues relating to
[[Page 22130]]
BOP and well-control requirements. More specifically, the final rule
incorporated industry standards; adopted reforms to well design, well
control, casing, cementing, real-time well monitoring, and subsea
containment requirements; and implemented many of the recommendations
resulting from various investigations of the Deepwater Horizon
incident. Most of the provisions of that rulemaking became effective on
July 28, 2016.
Since the time the Blowout Preventer Systems and Well Control
regulations took effect, oil and natural gas operators have raised
various concerns, and BSEE has identified issues during the
implementation of the recent rulemaking. The concerns and issues
involve certain regulatory provisions that impose undue burdens on oil
and natural gas operators, but do not significantly enhance worker
safety or environmental protection. BSEE understands the concerns that
have been raised, but BSEE also fully recognizes that the BOP and other
well-control requirements are critical components in ensuring safety
and environmental protection. After thoroughly reexamining the Blowout
Preventer Systems and Well Control regulations, BSEE has identified
those provisions that can be amended, revised, or removed to reduce
significant burdens on oil and natural gas operators on the OCS while
ensuring safety and environmental protection. In keeping with the
Executive and Secretary's Orders, BSEE undertook a review of the 2016
Well Control Final Rule with a view toward the policy direction of
encouraging energy exploration and production on the OCS and reducing
unnecessary regulatory burdens while ensuring that any such activity is
safe and environmentally responsible. BSEE carefully analyzed all 342
provisions of the 2016 Well Control Final Rule, and determined that
only 59 of those provisions--or less than 18% of the 2016 Rule--were
appropriate for revision. In the process, BSEE compared each of the
proposed changes to the 424 recommendations arising from 26 separate
reports from 14 different organizations developed in the wake of and
response to the Deepwater Horizon disaster, and determined that none of
the proposed changes ignores or contradicts any of those
recommendations, or would alter any provision of the 2016 Well Control
Final Rule in a way that would make the result inconsistent with those
recommendations. Further, nothing in this proposed rule would alter any
elements of other rules promulgated since Deepwater Horizon, including
the Drilling Safety Rule (Oct. 2010), SEMS I (Oct. 2010), and SEMS II
(April 2013). BSEE's review has been thorough, careful, and tailored to
the task of reducing unnecessary regulatory burdens while ensuring that
OCS activity is safe and environmentally responsible.
This rulemaking would revise current regulations that impact
offshore oil and gas drilling, completions, workovers, and
decommissioning activities. The proposed regulations would also address
various issues that were identified during the implementation of the
current Blowout Preventer Systems and Well Control regulations, as well
as numerous questions that have required substantial informal guidance
from BSEE regarding the interpretation and application of the
provisions. For example, this proposed rulemaking would:
Clarify the rig movement reporting requirements.
Clarify and revise the requirements for certain
submittals to BSEE to eliminate redundant and unnecessary reporting.
Clarify the drilling margin requirements.
Revise section 250.723 by removing references to lift
boats from the section.
Remove certain prescriptive requirements for real time
monitoring.
Replace the use of a BSEE approved verification
organization (BAVO) with the use of an independent third party for
certain certifications and verifications of BOP systems and
components, and remove the requirement to have a BAVO submit a
Mechanical Integrity Assessment report for the BOP stack and system.
Revise the accumulator system requirements and
accumulator bottle requirements to better align with API Standard
53.
Revise the control station and pod testing schedules to
ensure component functionality without inadvertently requiring
duplicative testing.
Include coiled tubing and snubbing requirements in
Subpart G.
Revise the text to ensure consistency and conformity
across the applicable sections of the regulations.
C. Summary of Documents Incorporated by Reference
This rulemaking would update a document currently incorporated by
reference to a newer edition, and add a new standard for incorporation.
A brief summary of the proposed changes, based on the descriptions in
each standard or specification is provided in the text that 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.
API Standard 65-part 2, which was issued December 2010. This
standard outlines the process for isolating potential flow zones during
well construction. The new Standard 65-part 2 enhances the description
and classification of well-control barriers, and defines testing
requirements for cement to be considered a barrier.
API Recommended Practice 17H--Remotely Operated Tools and Interfaces on
Subsea Production Systems
The proposed rule would update the incorporated version of this
document from the First Edition (dated 2004, reaffirmed 2009) to the
Second Edition (dated 2013). This recommended practice provides general
recommendations and overall guidance for the design and operation of
remotely operated tools (ROT) and remotely operated vehicle (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. One
of the main differences between the first edition and second edition of
this recommended practice is that the second edition includes
provisions on high flow Type D hot stabs.
ISO ISO/IEC 17021-1--Conformity Assessment--Requirements for Bodies
Providing Audit and Certification of Management Systems
The proposed rule would incorporate this standard into the
regulations by
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reference for the first time, for purposes of the quality management
system certification requirements of section 250.730(d). This standard
contains principles and requirements for the competence, consistency,
and impartiality of bodies providing audit and certification of all
types of management systems. It provides generic requirements for such
bodies performing audit and certification in the fields of quality, the
environment, and other types of management systems. Incorporation of
this standard would provide clarity and consistency surrounding the
critical qualifications of entities responsible for certifying quality
management systems for the manufacture of BOP stacks.
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, the American Petroleum
Institute (API), provides free online public access to view read only
copies of its key industry standards, including a broad range of
technical standards. All API standards that are safety-related and that
are incorporated into Federal regulations are available to the public
for free viewing online in the Incorporation by Reference Reading Room
on API's website at: http://publications.api.org.\3\ 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 to purchase standards is: http://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents.
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\3\ To view 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.
---------------------------------------------------------------------------
The International Organization for Standardization (ISO) creates
documents that provide requirements, specifications/government-cited-
safety documents. ISO creates documents that provide requirements,
specifications, guidelines or characteristics that can be used
consistently to ensure that materials, products, processes and services
are fit for their purposes. All ISO International Standards are
available at the ISO Store for purchase, https://www.iso.org/store.html.
For the convenience of members of the viewing public who may not
wish to purchase copies or view these incorporated documents online,
they may be inspected at BSEE's office, 45600 Woodland Road, Sterling,
Virginia 20166, or by sending a request by email to [email protected].
In addition, BSEE is aware of a published addendum to API Standard
53, and a new Standard 53 edition currently under development by API,
consistent with international standards. BSEE will continue to evaluate
the API addendum and the new edition. At this time, BSEE does not
propose to incorporate the API Standard 53 addendum into this proposed
rule. However, BSEE is considering incorporating the API Standard 53
addendum in the final rule. BSEE is specifically soliciting comments on
whether the API Standard 53 addendum should be included within the
documents incorporated by reference. Please provide reasons for your
position. If your comment addresses anticipated monetary or operational
benefits associated with using the API Standard 53 addendum, please
provide any available supporting data. When the new edition of API
Standard 53 is finalized by API, BSEE would consider incorporating that
edition into future rulemaking as appropriate.
BSEE is also considering potential, technical (non-substantive)
revisions to Sec. 250.198 for the purposes of reorganizing and
revising that section to make it clearer, more user-friendly, and more
consistent with the Office of the Federal Register's (OFR)
recommendations for incorporations by reference in Federal regulations.
BSEE will continue to consult with OFR regarding its suggestions for
specific organizational and language changes to Sec. 250.198 and
expects to address such technical revisions in a final rule as soon as
possible. BSEE does not anticipate that those potential revisions would
have any substantive impact on the proposed incorporations by reference
of industry standards discussed in this rule.
D. New Executive and Secretary's Orders
On March 28, 2017, the President issued Executive Order (E.O.)
13783--Promoting Energy Independence and Economic Growth (82 FR 16093).
The E.O. directed Federal agencies to review all existing regulations
and other agency actions and, ultimately, to suspend, revise, or
rescind any such regulations or actions that unnecessarily burden the
development of domestic energy resources beyond the degree necessary to
protect the public interest or otherwise comply with the law.
On April 28, 2017, the President issued E.O. 13795--Implementing an
America-First Offshore Energy Strategy (82 FR 20815), which directed
the Secretary to review the WCR for consistency with the policy set
forth in section 2 of E.O. 13795, and to ``publish for notice and
comment a proposed rule revising that rule, if appropriate and as
consistent with law.'' To further implement E.O. 13795, the Secretary
issued Secretary's Order No. 3350 on May 1, 2017, directing BSEE to
review the WCR for consistency with E.O. 13795, including preparation
of a report ``providing recommendations on whether to suspend, revise,
or rescind the rule'' in response to concerns raised by stakeholders
that the WCR ``unnecessarily include[s] prescriptive measures that are
not needed to ensure safe and responsible development of our OCS
resources.''
As part of its response to E.O.s 13783 and 13795, and Secretary's
Order No. 3350, and in light of the requests received for clarification
and revision of various provisions, BSEE reviewed the WCR and is
proposing revisions to the WCR that could reduce unnecessary burdens on
industry without impacting key provisions in the rule that have a
significant impact on improving safety and equipment reliability.
E. Stakeholder Engagement
Implementation of the Original WCR--BSEE Questions and Answers (Q's and
A's)
The Department promulgated the original ``Blowout Preventer Systems
and Well Control'' final rule (WCR) in April 2016. Subsequently, during
the implementation of the revised regulations, BSEE received numerous
questions from stakeholders seeking clarification and guidance
concerning the WCR's provisions. The questions covered a vast array of
issues and spanned multiple subparts of the regulations.
BSEE reviewed each question it received and decided whether the
question presented an issue that was appropriate for Bureau guidance.
To the extent a question required guidance or clarification, BSEE
provided a response to clarify any potentially confusing language. In
addition to deciding on the appropriateness of a question for guidance,
BSEE determined whether a question posed was of sufficient public
interest to merit broader publication of a response. After finalizing
regulatory
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guidance in response to a stakeholder's question, BSEE typically
publishes both the question and BSEE's answer on its web page. The
information, which reflects BSEE's guidance of the current regulations,
may be found at: https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule. BSEE has posted approximately 100
responses on the web page.
BSEE has reexamined the questions and answers pertaining to the
original WCR. After careful consideration of all relevant information
in the questions and answers, BSEE has determined that certain
provisions of the original rule should be revised to support the goals
of the regulatory reform initiative while ensuring safety and
environmental protection. Additionally, BSEE's proposed revisions seek
to clarify any ambiguity in the regulatory language, eliminate
redundancies in the provisions, and align specific requirements more
closely with relevant technical standards.
BSEE Public Forum on Well Control and Blowout Preventer Rule
To ensure a complete and thorough review of the WCR, BSEE has
solicited input from interested parties to identify potential revisions
to the rule that would significantly reduce regulatory burdens without
significantly reducing safety and environmental protection on the OCS.
BSEE held a public forum on September 20, 2017, in Houston, Texas. More
than 110 participants attended and provided comments and suggestions. A
summary of registrants included:
Federal agencies;
Media;
Oil and gas companies;
Classification societies;
Trade associations;
Environmental groups; and
Equipment manufacturers.
Additionally, there were eight presentations made at the forum.
These presentations are available at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule/public%20forum.
II. Section-by-Section Discussion of Proposed Changes
BSEE is proposing to revise the following regulations:
Subpart A--General
Documents Incorporated by Reference (Sec. 250.198)
BSEE would revise paragraph (h)(63), which incorporates API
Standard 53, Blowout Prevention Equipment Systems for Drilling Wells,
Fourth Edition, November 2012, to add a new cross reference to Sec.
250.734. The changes to this paragraph are administrative and merely
reflect substantive changes made to Sec. 250.734, addressed further at
the corresponding location in the section-by-section discussion.
BSEE would revise paragraph (h)(78), which incorporates API
Standard 65--Part 2, Isolating Potential Flow Zones During Well
Construction; Second Edition, December 2010, to add a new cross
reference to Sec. 250.420(a)(6). The changes to this paragraph are
administrative. For discussion of the effects on the regulatory
requirements of incorporating this document, refer to Sec.
250.420(a)(6).
BSEE would also revise paragraph (h)(94) to update the
incorporation of API RP 17H to the second edition. The changes to this
paragraph are administrative. For discussion of the effects on the
regulatory requirements of incorporating this document, refer to Sec.
250.734(a)(4). BSEE has reviewed the differences between the first and
second editions of API RP 17H. The API RP 17H second edition was mostly
rearranged to clarify and consolidate similar topics covered in the
first edition. The second edition now includes the following sections:
Subsea intervention concepts, subsea intervention systems design
recommendations, ROV interfaces, materials, subsea markings, and
validation and verification. These sections are mostly a reorganization
of the content of the first edition with minor changes to the design
recommendations. The most significant change from the first edition to
the second edition was the addition of the Type D connection to the ROV
interface section. The Type D connection is intended for large bore,
high circulation capabilities and is limited to the maximum rated
pressure of 5,000 psi. This Type D connection allows the ROV hot stab
to meet the API Standard 53 closing timing requirements, which API RP
17H first edition did not accomplish.
BSEE would add new paragraph (m)(2) for the International
Organization for Standardization (ISO) 17021 to update the erroneous
standard incorporated in the original WCR. For discussion of the
effects on the regulatory requirements of incorporating this document,
refer to Sec. 250.730(d) and the associated section-by-section
discussion.
Subpart B--Plans and Information
What must the DWOP contain? (Sec. 250.292)
This rulemaking would revise paragraph (p) by clarifying the free
standing hybrid riser (FSHR) requirements and removing the requirement
for certification of the tether system and connection accessories by an
approved classification society or equivalent. Based on BSEE experience
during the implementation of the original WCR, these revisions to
paragraph (p) would clarify the focus of the requirements for FSHR
systems that involve a buoyancy air can suspended from the top of the
riser, regardless of the manner of connection, to avoid confusion over
whether a specific component type would be considered `critical' or
not. The requirements in existing Sec. 250.292(p)(2) and (p)(3) would
be removed because the detailed information specified on the FSHR
design, fabrication, installation, and load cases is already required
by the relevant portions of the platform verification program (PVP) in
Sec. 250.910(b), and in Sec. Sec. 250.1002(b)(5) and
250.1007(a)(4)(ii). This would reduce the burden on operators by
eliminating the requirement to submit the same or very similar
information on an FSHR system through more than one regulatory
permitting process. Section 250.292 paragraphs (p)(4) and (p)(5) would
be redesignated as Sec. 250.292 paragraphs (p)(2) and (p)(3), and
their language would be revised to align with the clarification in
paragraph (p). The requirements in Sec. 250.292(p)(6) would be removed
altogether, because they are duplicative of the certification that any
permanent pipeline riser installation and its tensioning systems will
undergo via the Certified Verification Agent (CVA) requirements of
Sec. 250.911, in connection with the PVP.
Subpart D--Oil and Gas Drilling Operations
What must my description of well drilling design criteria address?
(Sec. 250.413)
This rulemaking would add in paragraph (g) a parenthetical
clarification of ``surface and downhole'' after ``proposed drilling
fluid weights'', to ensure the operator includes the weight of the
drilling fluid in both places. This clarifies the information the
operator has previously been required to provide, without adding a new
burden, and improves the safety of the drilling operation by ensuring
the drilling fluid weight is fully evaluated and appropriate for the
estimated bottom hole pressures.
What must my drilling prognosis include? (Sec. 250.414)
This proposed rule would revise paragraph (c)(3) of this section to
add
[[Page 22133]]
the words ``and analogous'' before ``well behavior observations'' and
``, if available'' at the end of paragraph (c)(3) of this section. This
minor wording change would ensure that operators use available data
from wells with similar conditions as the well being drilled when
determining the pore pressure and fracture gradient to ensure accuracy
and safety when establishing the drilling margin. BSEE is specifically
soliciting comments about the effectiveness of the use of related
analogous data and how the pore pressure and fracture gradient are
determined without related analogous data. Please provide reasons for
your position.
In the proposed rule text, the drilling margin requirements are
mostly unchanged. The current regulations allow for a deviation from
the default 0.5 pound per gallon (ppg) drilling margin. The deviation
does not have to be submitted as an alternate procedure or departure
request; rather, it may be submitted with the Application for Permit to
Drill (APD) along with the supporting justifications. BSEE is currently
approving margins other than 0.5 ppg based on specific well conditions.
BSEE is working to provide consistent approval throughout the regions
and districts, and, as described more fully below, BSEE is specifically
soliciting comments about the process to deviate from the 0.5 ppg
drilling margin.
The purpose of the drilling margin is to ensure that the drilling
fluid weight used allows for some variability in the pore pressure and
fracture gradient, ensuring the safety of drilling operations. In 2011,
the National Academy of Engineering and National Research Council of
the National Academies recommended that ``[d]uring drilling, rig
personnel should maintain a reasonable margin of safety between the
equivalent circulating density and the density that will cause wellbore
fracturing.'' Macondo Well Deepwater Horizon Blowout--Lessons for
Improving Offshore Drilling Safety (NAE Report), Recommendation 2.2 (p.
43). The NAE Report stated further that ``until a reasonable standard
is established, industry should design the ECD [equivalent circulating
density] so that the difference between the ECD and the fracture mud
weight is a minimum of 0.5 ppg . . . Additional evaluations and
analyses should be performed to establish an appropriate standard for
this margin of safety.'' Id. The Department's 2011 joint investigation
team report (DOI JIT Report) regarding the causes of the April 20,
2010, Macondo Well blowout recommended that BSEE define the term ``safe
drilling margin(s)'' and that such a definition should ``encompass pore
pressure, fracture gradient and mud weight.'' The Bureau of Ocean
Energy Management, Regulation and Enforcement Report Regarding the
Causes of the April 20, 2010, Macondo Well Blowout (DOI JIT Report),
Recommendation 3 (p. 202). Thus, the NAE Report and the DOI JIT Report
recommended additional evaluations, analyses, and definition of what a
safe drilling margin is. In the 2016 final well control rule preamble,
BSEE cited this JIT Report recommendation and the bureau's prior
typical reliance on a minimum of 0.5 ppg below the lower casing shoe
pressure integrity test or the lowest estimated fracture gradient as an
appropriate safe drilling margin and as the basis for including this as
the default requirement in the current section 250.414(c). 81 FR 25888,
25894 (April 29, 2016). Section 250.414(c) also allows for using an
equivalent downhole mud weight, provided that the operator submitted
adequate documentation justifying the use of an alternative equivalent
downhole mud weight.
Since the WCR became effective, BSEE's records show that there have
been 305 wells drilled. Of those wells, BSEE has approved operators'
use of drilling margins that are less than 0.5 ppg for 32 wells, 31 of
which were in deep water. Even though these 32 wells represent only 10
percent of the total wells drilled in that time frame, the number is
significant enough for BSEE to consider whether it should further
refine the approach it is taking in the current regulations or whether
it should adhere to its practice of identifying a specific drilling
margin with an avenue for allowing operators to submit adequate
documentation justifying the use of a different drilling margin, such
as risk modeling data, off-set well data, analog data, and seismic
data.
The Explanatory Statement for the 2017 Consolidated Appropriations
Act, Public Law 115-31 (May 5, 2017), also recommended that BSEE
consider revising the 2016 WCR. It stated:
Blowout Preventer Systems and Well Control Rule.--The Committees
encourage the Bureau to evaluate information learned from additional
stakeholder input and ongoing technical conversations to inform
implementation of this rule. To the extent additional information
warrants revisions to the rule that require public notice and
comment, the Bureau is encouraged to follow that process to ensure
that offshore operations promote safety and protect the environment
in a technically feasible manner.
163 Cong. Rec. H3881 (daily ed. May 3, 2017).
For these reasons, BSEE is requesting comment and further
statistical analysis from stakeholders about whether the 0.5 ppg
drilling margin in this proposed rule should be revised or removed.
BSEE solicits comments on alternatives to the current set 0.5 ppg
drilling margin. Specifically, BSEE requests comment on replacing it
with a more performance-based standard under which the approved safe
drilling margin is established on a case-by-case basis for each well,
based on data and analysis particular to that well, through the
permitting process. BSEE also requests comment on potentially providing
for a different drilling margin or multiple drilling margins that are
specific to the conditions in which the wells are drilled, such as if
the well is drilled in deep water or shallow water. BSEE further
requests comment on whether removal of a specific reference to a 0.5
ppg standard from the regulation may be appropriate. For example, the
standard establishes a prescriptive margin without an in-depth analysis
of appropriate margins for potential hole sections, which must take
into account factors, such as cutting loads, equivalent downhole mud
weight, and fluid temperatures and pressures. Further, enforcing a
prescriptive minimum margin can force operators to encroach on pore
pressure, which might result in unintended kicks. These types of
considerations may suggest that a more case-by-case approach toward the
establishment of appropriate safe drilling margins for particular wells
through the permitting process would be preferable. Consequently, BSEE
specifically solicits comments regarding the potential removal of the
specific reference to a 0.5 ppg drilling margin from Sec. 250.414(c)
and its replacement with a more performance based, case-by-case
standard for the establishment of appropriate safe drilling margins
through the well permitting process.
BSEE also requests comment on the criteria that BSEE could use to
apply alternative approaches, such as an operator demonstrating that a
well is a development well as opposed to an exploratory well. To
utilize this alternative option, the rulemaking could specify what
documentation operators would need to submit with the APD in order to
provide adequate justification. BSEE requests comment on what
supplemental data would provide an adequate level of justification for
deviating from the 0.5 ppg drilling margin under identified
circumstances, such as requiring the submission of
[[Page 22134]]
offset well data, analog data, seismic data, and decision modeling.
BSEE also requests comment on whether there are situations where
drilling can continue prior to receiving alternative safe drilling
margin approval from BSEE. BSEE requests comment on (1) whether there
are situations where, despite not being able to maintain the approved
safe drilling margin, an operator's continued drilling with an
alternative drilling margin creates little risk; (2) the criteria that
BSEE should use to define those situations and the available
alternative drilling margins; and (3) what level of follow-up reporting
(e.g. submitting a follow-up notice to BSEE within a specified time
frame) would be appropriate. Such an approach could provide assurance
that an operator, with the appropriate level of justification, could
continue to drill as real time data is evaluated, and would largely be
designed to add more clarity to the existing option(s) provided by
Sec. 250.414(c)(2). This would provide a proactive approach to
managing risk and ensuring safe operations, while also providing
increased investment certainty for the regulated community.
In addition, BSEE could add the words ``and analogous'' before
``well behavior observations'' and ``, if available'' at the end of
paragraph (c)(3) of this section. This minor wording change could
ensure that operators use available data from wells with similar
conditions as the well being drilled when determining the pore pressure
and fracture gradient to ensure accuracy and safety when establishing
the drilling margin. BSEE is specifically soliciting comments about the
effectiveness of the use of related analogous data and how the pore
pressure and fracture gradient are determined without related analogous
data. Please provide reasons for your position.
What well casing and cementing requirements must I meet? (Sec.
250.420)
BSEE is proposing to incorporate by reference API Standard 65-Part
2 in paragraph (a)(6) of this section for purposes of defining the
standards governing centralization. This would clarify the intent of
the current centralization requirements by adopting the methods
described in API Standard 65-Part 2 to ensure proper centralization
during cementing. BSEE would add the reference to API Standard 65-Part
2 based upon its evaluation of the original WCR implementation and
industry's recent questions concerning the applicability of this
standard. Centralization is important for cement jobs, as it ensures
the casing is centered in the hole and that there is enough space
between the casing and the wellbore for the cement to form a uniform
barrier to help minimize the risk of cement failure. BSEE has
determined that the standards set forth in API Standard 65-Part 2
properly ensure adequate centralization and provide clearer guidelines
for operators than the current regulatory language.
What are the casing and cementing requirements by type of casing
string? (Sec. 250.421)
BSEE proposes to make minor revisions in paragraphs (c), (d), (e),
and (f) clarifying that all length requirements are to be taken from
measured depth. This clarification of the existing regulatory
requirements would provide consistency for planning and permitting
purposes.
Paragraph (f) would also be revised by removing the specifics of
the listed example regarding when a liner is used as intermediate
casing. The example is redundant because it restates the same
information already contained in this section. This deletion would not
change the applicability or substance of the requirements.
What are the requirements for casing and liner installation? (Sec.
250.423)
This rulemaking would revise paragraphs (a) and (b) by removing the
words ``and cementing'' after ``upon successfully installing''.
Revisions to this section are necessary because there are many
situations in the design of the casing or liner string running tool
where the latching or lock down mechanism is automatically engaged upon
installing the string. BSEE has received many alternate procedure
requests to accommodate these situations since publication of the
original WCR. This change would not impact safety because BSEE is still
requiring these mechanisms to be engaged upon successful installation
of the casing or liner. The proposed change would allow more
flexibility on an operational case-by-case basis in determining the
appropriate time to engage these mechanisms and would also reduce the
number of alternate procedure requests submitted to BSEE for approval.
What must I do in certain cementing and casing situations? (Sec.
250.428)
BSEE is proposing to revise paragraph (c) to include the term
``unplanned'' when describing the lost returns that provide indications
of an inadequate cement job. This revision would minimize the number of
unnecessary revised permits submitted to BSEE for approval. Current
cementing practices utilize improved well modelling to identify and
account for zones that may have anticipated losses. It is unnecessary
to submit a revised APD to address lost returns for a well cementing
program that has been designed for those occurrences. Any unexpected
losses would require locating top of cement and determining whether the
cement job is adequate.
Existing paragraph (c)(iii) would be redesignated as paragraph
(c)(iv). A new paragraph (c)(iii) would be added to allow the use of
tracers in the cement, and logging the tracers' location prior to drill
out, as an alternative approach for locating the top of cement. The
original WCR did not address this approach, however based upon BSEE
experience this addition would provide more viable options and
flexibility for locating top of cement to help minimize rig down time
running in and out of the hole multiple times, without compromising
safety.
Paragraph (d) would be revised to clarify that, if there is an
inadequate cement job, operators are required to comply with Sec.
250.428(c)(1). The original WCR did not address this provision, however
based upon BSEE experience this revision would help assess the overall
cement job to allow for improved planning of remedial actions.
This rulemaking would also revise paragraph (d) to allow the
preapproval of remedial cementing actions through a contingency plan
within the original approved permit; however, if the remedial actions
have not already been approved by BSEE, clarification was added
directing submittal of the remedial actions in a revised permit for
BSEE review and approval. The original WCR did not address this
provision, however based upon BSEE experience, BSEE is proposing to
allow the remedial actions to be included as contingency plans in the
original permit to minimize the time necessary for operators to
commence approved remedial cementing actions, and to reduce burdens on
operators and BSEE from multiple submissions. If BSEE has already
approved the remedial cementing actions in the original permit,
additional BSEE approval is not required unless they deviate from the
approved actions. BSEE will still receive information regarding any
remedial cementing actions taken in Well Activity Reports.
Based upon BSEE experience with the implementation of the original
WCR, BSEE has determined that allowing the professional engineer (PE)
to certify the remedial cementing actions in the contingency plan
within the original permit would help streamline the
[[Page 22135]]
permitting process and reduce delays to remedial actions without
compromising safety. The proposed revision to this paragraph would
eliminate the requirement for a PE certification for any changes to the
well program so long as the changes were already approved in the
permit. This would result in less rig down time waiting for PE
certifications before beginning initial remedial actions. In
conjunction with the approval of the remedial actions BSEE requires a
PE certification for any changes to the well program. These proposed
revisions would minimize the number of revised permits submitted to
BSEE for approval, reducing burdens on operators and BSEE.
What are the diverter actuation and testing requirements? (Sec.
250.433)
This rulemaking would revise paragraph (b) to modify requirements
for subsequent diverter testing by allowing partial activation of the
diverter element and not requiring a flow test. The original WCR did
not address this provision, however based upon BSEE experience these
changes would codify longstanding BSEE policy and minimize the number
of alternate procedure requests submitted to BSEE. Full actuation of
the diverter element and flow tests are unnecessary with subsequent
testing because partial actuation of the element sufficiently
demonstrates functionality of the element, and a full flow test would
be originally verified on the initial test. These changes would also
help minimize the possibility of accidental discharge of mud overboard.
What are the requirements for directional and inclination surveys?
(Sec. 250.461)
This proposed rule would revise paragraph (b) by extending the
maximum permitted survey intervals during angle-changing portions of
directional wells from 100 feet to 180 feet. This would account for the
majority of the pipe stand lengths and would address developments that
BSEE has needed to accommodate through alternative approvals since
before the original WCR. Most rigs have upgraded the derrick height to
account for the increase in pipe stand lengths to improve drilling
efficiency. The pipe stands have routinely become greater than 100
feet, with some pipe stands being as high as 180 feet. Increasing the
survey interval to correlate with the now common pipe stand lengths
would help improve rig efficiency while drilling. This revision would
also minimize the number of alternate procedure requests submitted to
BSEE in APDs. BSEE does not expect these revisions to reduce safety
because of the rationale previously stated. BSEE currently, when
appropriate, approves survey intervals based on the use of such pipe
stand lengths through the alternate procedure request and approval
process. These revisions would not result in any real changes in
current survey operations, only removing the added process of operators
submitting for approval an alternate procedure to use surveys
associated with 180 foot pipe stand lengths.
What are the source control, containment, and collocated equipment
requirements? (Sec. 250.462)
Paragraph (b) of this section would be revised to clarify that the
source control and containment equipment (SCCE) to which operators need
to have access is based on the determinations regarding source control
and containment capabilities required in Sec. 250.462(a), and that the
identified list of equipment represents examples of the types of SCCE
that may be determined appropriate rather than universal requirements.
Based upon BSEE experience with the implementation of the original WCR,
this revision would help ensure that appropriate SCCE is available for
the specific corresponding well rather than requiring every possible
type of SCCE regardless of the well-specific determinations.
Paragraph (e)(1)(ii) would be revised to remove ``a BSEE approved
verification organization'' and replace it with ``an independent third
party'' that meets the requirements of Sec. 250.732(b). For a
discussion on the changes from a BAVO to an independent third party,
see the section-by-section discussion of Sec. 250.732.
Proposed revisions to paragraph (e)(3) would clarify that subsea
utility equipment utilized solely for containment operations must be
available for inspection at all times. Paragraph (e)(4) would also be
revised to clarify that it is applicable only to collocated equipment
identified in the Regional Containment Demonstration (RCD) or Well
Containment Plan and not all collocated equipment. The proposed
revisions to both paragraphs (e)(3) and (e)(4) would help ensure that
the applicable respective equipment is available for inspection. BSEE
recognizes that some of the equipment used for containment is used for
other types of operations on the OCS and would be available for
inspection when in use during other well operations.
Subpart E--Oil and Gas Well-Completion Operations
Tubing and Wellhead Equipment (Sec. 250.518)
This rulemaking would revise paragraph (e)(1) by clarifying that
only permanently installed packers or bridge plugs that are qualified
as mechanical barriers are required to comply with ANSI/API Spec. 11D1.
Based upon BSEE experience with the implementation of the original WCR,
including questions BSEE received from operators, this revision would
codify BSEE's policy to ensure that the required mechanical barriers in
a well are held to a higher standard than other common packers or
bridge plugs used for various other well-specific conditions and
completions design. Furthermore, BSEE is aware that certain packers and
bridge plugs cannot meet the specifications of ANSI/API Spec. 11D1.
BSEE does not expect these revisions to reduce safety. The proposed
change would ensure that the packers and bridge plugs utilized as
required mechanical barriers are ANSI/API Spec. 11D1 compliant, while
eliminating the need for packers and plugs used for other, non-
critical, purposes to meet the standard.
What are the requirements for casing pressure management? (Sec. 250.
519)
BSEE would make minimal revisions to this section to update
incorrect citations. These revisions are administrative in nature and
ensure that the appropriate citations are correctly cross referenced.
How do I manage the thermal effects caused by initial production on a
newly completed or recompleted well? (Sec. 250.522)
BSEE would make minimal revisions to this section to update
incorrect citations. These revisions are administrative in nature and
ensure that the appropriate citations are correctly cross referenced.
When am I required to take action from my casing diagnostic test?
(Sec. 250.525)
BSEE would make minimal revisions to paragraph (d) of this section
to update incorrect citations. These revisions are administrative in
nature and ensure that the appropriate citations are correctly cross
referenced.
What do I submit if my casing diagnostic test requires action? (Sec.
250.526)
BSEE would make minimal revisions to this section to update
incorrect citations. These revisions are
[[Page 22136]]
administrative in nature and ensure that the appropriate citations are
correctly cross referenced.
What if my casing pressure request is denied? (Sec. 250.530)
BSEE would make minimal revisions to paragraph (b) of this section
to update incorrect citations. These revisions are administrative in
nature and ensure that the appropriate citations are correctly cross
referenced.
Subpart F--Oil and Gas Well-Workover Operations
Definitions (Sec. 250.601)
This rulemaking would revise the definition of routine operations
in this section to make it consistent with the definition of routine
operations in Sec. 250.105 by adding paragraph (m) ``acid
treatments.'' The original WCR did not address this provision, however
based upon BSEE experience, this revision is necessary to help minimize
confusion about the definition of routine operations.
Coiled tubing and snubbing operations (Sec. 250.616)
This section would be removed and reserved. The content of this
section would be moved to proposed Sec. 250.750, with minor revisions
discussed in connection with that provision. These revisions would help
BSEE eliminate inconsistencies between similar requirements throughout
different BSEE subparts by consolidating those requirements into
Subpart G which is applicable to drilling, completions, workovers, and
decommissioning operations.
Tubing and wellhead equipment (Sec. 250.619)
This rulemaking would revise paragraph (e)(1) by clarifying that
only permanently installed packers or bridge plugs that are qualified
as mechanical barriers are required to comply with ANSI/API Spec. 11D1.
This revision would codify BSEE's policy developed since the WCR, to
ensure that the required mechanical barriers in a well are held to a
higher standard than other common packers or bridge plugs used for
various well specific conditions and completions design. Furthermore,
BSEE is aware that certain packers and bridge plugs cannot meet the
specifications of ANSI/API Spec. 11D1. BSEE would also add that
operators must have two independent barriers, one being mechanical, in
the exposed center wellbore prior to removing the tree or well control
equipment. This addition would codify existing BSEE policy and add into
the workover regulations in Subpart F requirements about mechanical
barriers similar to those already found in Sec. 250.720(a). This
addition would help ensure the well is properly secured before removal
of the tree or well control equipment.
Subpart G--Well Operations and Equipment
What rig unit movements must I report? (Sec. 250.712)
BSEE proposes to revise this section by adding new paragraphs (g)
and (h). BSEE would add paragraph (g) to clarify that reporting is not
necessary for rig movements to and from the safe zone during permitted
operations. BSEE would also add paragraph (h) to clarify that, if a rig
unit is already on a well, BSEE would not require a notification for
any additional rig unit movements on that well. This change would not
impact safety because BSEE would still receive initial rig movement
notifications and would be aware of rig unit locations. The original
WCR did not address this provision, however based upon BSEE experience,
BSEE determined that these clarifications would minimize the number of
duplicative rig movement notifications submitted to BSEE under these
particular circumstances.
When and how must I secure a well? (Sec. 250.720)
BSEE proposes to revise paragraph (a)(1) to add an impending
National Weather Service-named tropical storm or hurricane to the list
of example events that would interrupt operations and require
notification. Furthermore, BSEE also proposes to add new paragraph
(a)(3) to include provisions for testing the applicable BOP or lower
marine riser package (LMRP) upon relatch according to Sec. 250.734
paragraphs (b)(2) or (b)(3), respectively, and obtaining BSEE approval
before resuming operations. Based upon BSEE experience with the
implementation of the original WCR and longstanding policy, these
revisions would codify the BSEE storm policy reflected in longstanding
guidance and provide clarity for testing when an operator has returned
to the location and relatched the BOP or LMRP. These tests help confirm
that the BOP or LMRP is properly functional prior to resuming
operations after being unlatched due to a storm or other interruption.
This rulemaking would also add new paragraph (d) requiring
equipment and capabilities for well intervention. This addition would
specify that equipment used solely for well intervention must be
readily available for use, maintained in accordance with applicable
original equipment manufacturer (OEM) recommendations, and available
for inspection by BSEE upon request. BSEE would add this paragraph to
ensure that when intervention is necessary on a well, the applicable
tools (such as the tree interface tools) are available and ready for
their intended use. BSEE is aware of recent instances where
intervention was necessary on a particular subsea tree, and the tree-
specific unique interface tools were not available to perform the work
on that well, delaying the operations.
What are the requirements for prolonged operations in a well? (Sec.
250.722)
BSEE is proposing to revise the prolonged operations well casing
reporting requirements in paragraph (a)(2) of this section to clarify
that District Manager approval is not required to resume operations if
a successful pressure test was conducted as already approved in the
applicable permit. BSEE would also clarify that the successful pressure
test results must be documented in the Well Activity Report (WAR). The
original WCR did not address the issue of District Manager approval,
however based upon BSEE experience, these revisions would minimize the
amount of unnecessary rig operational time waiting for separate BSEE
approval of the successful pressure test where BSEE has already
approved the relevant testing and streamline BSEE approval of
associated operations. These revisions would be applicable only if the
actions are appropriately planned for and already approved in the
associated permit. The pressure tests are conducted to help verify
casing integrity. BSEE would also make a minor revision to this
paragraph to provide that the calculations are used to ``indicate'' not
``show'' that the well's integrity is above the minimum safety factors.
This change is necessary because the calculations do not guarantee or
``show'' integrity; they are used as a way to help determine well
integrity. Using the word ``indicate'' removes the definitive statement
or assumption that the calculations demonstrate well integrity. BSEE
does not expect these revisions to decrease safety because, by
approving the test pressure described in the APD, BSEE has determined
that any test that successfully meets the pre-approved test pressure
for that casing design is sufficient. Therefore, requiring an
additional, subsequent approval of the test results before operations
may be resumed is redundant and unnecessary and does not improve
safety. BSEE will
[[Page 22137]]
be notified of the test results through the reporting requirements of
the WAR.
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)
This rulemaking would revise this section by removing the phrase
``or lift boat.'' This revision would mostly impact paragraph (c)(3)
which requires a shut-in of all producible wells located in the
affected wellbay when a lift boat moves within 500 feet of the platform
until the lift boat is secured in place and ready to begin operations.
Removing the references to lift boats from these requirements would
minimize the number of unnecessary well shut-ins and delayed
production. Since the original WCR, BSEE reevaluated the lift boat
activities, and determined that the vast majority of lift boats used on
the OCS are relatively small when compared to the size of a mobile
offshore drilling unit (MODU) and would not have the same operational
impacts and potential risks as a MODU. BSEE is considering the effects
of the size of lift boats for potential future rulemakings, and may
gather additional information and provide guidance on a case-by-case
basis for any lift boats comparable in size to a MODU.
What are the real-time monitoring requirements? (Sec. 250.724)
This rulemaking would revise this section by removing many of the
prescriptive real-time monitoring requirements and moving towards a
more performance-based approach. BSEE would still require the ability
to gather and monitor real-time well data using an independent,
automatic, and continuous monitoring system capable of recording,
storing, and transmitting data for the BOP control system, the well's
fluid handling system on the rig, and the well's downhole conditions
with the bottom hole assembly tools (if any tools are installed). Based
upon BSEE's evaluation of RTM since the publication of the original
WCR, BSEE determined that the prescriptive requirements for how the
data is handled may be revised to allow company-specific approaches to
handling the data while still receiving the benefits of RTM. BSEE is
specifically soliciting comments if there are alternative ways to meet
RTM provisions or if there are alternative means to meet the purposes
of RTM. BSEE would completely remove existing paragraph (b) with its
associated prescriptive requirements, and redesignate existing
paragraph (c) as paragraph (b), with minor revisions to shift certain
prescriptive elements to be more performance-based. BSEE would continue
to require the items discussed in existing paragraph (c) in an RTM
plan. BSEE expects operators to explain how they would carry out the
requirements of the RTM plan on an individual company basis. BSEE
revised this section to outline the RTM requirements and allow the
operators to determine how they would fulfill those requirements.
BSEE is specifically soliciting comments about the appropriateness
of utilizing RTM for workover, completion, and decommissioning
operations, or whether RTM requirements should be limited to drilling
operations. Please provide reasons for your position and any applicable
associated data.
What are the general requirements for BOP systems and system
components? (Sec. 250.730)
BSEE proposes to revise paragraph (a) by removing ``excluding
casing shear'' and replacing ``at all times'' with ``in the event of
flow due to a kick.'' Based upon BSEE experience with the
implementation of the original WCR, BSEE is removing the phrase
``excluding casing shear'' because it is not necessary in this context.
The requirements of this sentence are applicable to the entire BOP
system, including the casing shear. BSEE expects the BOP system as a
whole to be capable of closing and sealing the wellbore. BSEE also
proposes to clarify that the BOP system must be able to close and seal
the wellbore in the event of flow due to a kick. BSEE would make this
change to codify BSEE guidance on the original WCR posted on the BSEE
website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule. BSEE understands mechanical and operational design
limits of equipment and expects operators to ensure ram closure time
and sealing integrity before exceeding those operational and mechanical
limits.
Paragraph (b) would be revised to clarify that BSEE expects the use
of ``applicable'' OEM recommendations for the design, fabrication,
maintenance, and repair of BOP systems, as well as personnel training
in their use. The proposed revision to include ``applicable'' is
necessary because some OEMs may not have specific recommendations for
every item required by this paragraph. BSEE expects operators to follow
OEM recommendations to the extent relevant recommendations exist.
This rulemaking would also revise the failure reporting
requirements in paragraph (c) to codify BSEE guidance and current
practice. The failure reporting references to American National
Standards Institute (ANSI)/API Specs 6A and 16A would be removed
because the failure reporting process outlined in those standards is
redundant to API Standard 53 and the remaining requirements of this
section. Revisions to this paragraph would include clarification on
submitting failure data and reports to BSEE, unless BSEE has designated
a third party to collect the data and reports, and ensuring that an
investigation and failure analysis are started within 120 days. BSEE
reevaluated the timeframes set forth in the original WCR regarding
performing the investigation and failure analysis and determined that
certain operations would not be able to meet the original timeframes.
Accordingly, BSEE proposes to require that the investigation and
failure analysis be started within 120 days of the failure. BSEE would
then provide a 120 day timeframe to complete the investigation and
failure analysis once they have started.
Based upon the unknown situations that could arise around the
completion of the failure analysis and availability of the equipment,
BSEE is specifically soliciting comments about whether specifying a
completion date for the failure analysis is appropriate and if so
whether 120 days from the commencement of the analysis is appropriate.
Please provide reasons for your position and any applicable associated
data.
BSEE proposes to add new paragraph (c)(4) to explain that BSEE may
designate a third party to collect failure data and reports on behalf
of BSEE, and failure data and reports must be sent to the designated
third party. The changes regarding submittal of the reports to BSEE or
designated third party would codify BSEE guidance on the original WCR
posted on the BSEE website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
BSEE is currently using www.SafeOCS.gov as the designated third
party. Reporting instructions are on the SafeOCS website at:
www.SafeOCS.gov. Reports submitted through www.SafeOCS.gov are
collected and analyzed by the Bureau of Transportation Statistics (BTS)
and protected from release under the Confidential Information
Protection and Statistical Efficiency Act (CIPSEA), which permits BTS
to confidentially
[[Page 22138]]
handle and store reported information.\4\ Information submitted under
this statute also is protected from release to other government
agencies, Freedom of Information Act (FOIA) requests, and certain
records requests.
---------------------------------------------------------------------------
\4\ OMB defines BTS as one of 14 CIPSEA statistical agencies;
BSEE is not a CIPSEA statistical agency. (``Implementation Guidance
for [CIPSEA]''); 72 FR 33362 at 33368 (June 15, 2007).
---------------------------------------------------------------------------
BSEE also proposes to revise paragraph (d) by removing the
reference to an incorrect document incorporated by reference and
replacing it with the correct document incorporated by reference. The
original WCR requires that BOP stacks must be manufactured pursuant to
a quality management system certified by an entity that meets the
requirements of ISO 17011. The correct reference is ISO 17021. This was
an error in the original WCR, and BSEE would make this correction in
keeping with the WCR guidance posted on the BSEE website at https://
www.bsee.gov/guidance-and-regulations/regulations/well-control-rule
What information must I submit for BOP systems and system components?
(Sec. 250.731)
This rulemaking would revise the information submitted to BSEE
pursuant to paragraph (a)(5) by replacing ``to achieve an effective
seal of each ram BOP'' with ``to close each ram BOP.'' This revision
would affect information submitted to BSEE and, based upon BSEE
experience with the implementation of the original WCR, would more
accurately reflect the control system and regulator control setting
requirements of API Standard 53. BSEE does not expect these revisions
to decrease safety. BSEE has determined that these revisions would be
adequate to meet the API Standard 53 requirements for control systems
to ensure that each ram BOP can be effectively sealed, as the original
WCR language intended.
This section would also be revised by removing the BAVO
verification requirements in existing paragraphs (d) and (f). The BAVO
verifications required by existing paragraphs (d)(1) and (d)(3) were
redundant to the verifications required by paragraph (c); however, the
verifications required by current paragraph (d)(2) are still necessary
and BSEE therefore proposes to add them to revised paragraph (c). BSEE
proposes to remove paragraph (f) because the Report that is the subject
of that paragraph is proposed for elimination in connection with
proposed revisions to Sec. 250.732(d) (see section-by-section
discussion of that provision for further explanation). The independent
third party verifications under paragraph (c) help ensure that the BOP
is fit for service at each specific well. BSEE proposes to revise this
section by replacing references to a BAVO with references to an
independent third party that meets the requirements of Sec.
250.732(b). For a discussion of the proposed shift from BAVOs to
independent third parties, see the section-by-section discussion of
Sec. 250.732.
What are the independent third party requirements for BOP systems and
system components? (Sec. 250.732)
BSEE proposes to completely revise this section by removing all
references to a BAVO and, where appropriate, replacing those references
with an independent third party. This change would also be made in
appropriate locations throughout subpart G where BAVOs are referenced,
as noted throughout the applicable section-by-section discussions. This
change would not impact safety because independent third parties have
been utilized as a long-standing industry practice to carry out
certifications and verifications similar to those which a BAVO would
do. BSEE expected most of the companies or individuals currently being
used as independent third parties to apply to become a BAVO. Since the
publication of the original WCR, BSEE has increased its interaction
with the independent third parties to better understand how they
operate and carry out certifications and verifications. BSEE has
determined that, if as expected the majority of BAVOs would be drawn
from the existing independent third parties who would continue to
conduct the same verifications, additional BSEE oversight and submittal
to become a BAVO would be unnecessary and the BAVO system implemented
by the WCR would increase procedural burdens and costs without giving
rise to meaningful improvements to safety or environmental protection.
If BSEE becomes aware of any performance issues with an independent
third party, there are still options for BSEE to address the issues
(e.g., through a SEMS audit, or verifications through the permitting
process). Based upon the BSEE determination to remove the BAVOs, BSEE
would revise the section heading to reflect the change from a BAVO to
an independent third party, remove paragraphs (a)(1) and (a)(3), and
replace all remaining BAVO references with references to an independent
third party. The independent third party qualifications in existing
paragraph (a)(2) would remain in this section as new paragraph (b).
This proposed rule would remove the requirements to verify that
testing was performed on the outermost edges of the shearing blades of
the shear ram positioning mechanism, found in current paragraph
(b)(1)(iv). This would align the verification requirements with BSEE's
proposal to remove the centering mechanism required in existing Sec.
250.734(a)(16) that is the subject of this verification (see section-
by-section discussion of Sec. 250.734 for discussion of those
changes). BSEE does not expect this revision to decrease safety since
it simply aligns this testing requirement with the proposed change to
Sec. 250.734(a)(16). As explained in connection with that proposed
change, BSEE believes that, since newer shearing blades can center
pipe, it is unnecessary to require a pipe centering mechanism. In
addition, the shear rams are capable of shearing along the entire blade
surface area without specifically requiring testing on the outermost
edges. BSEE also proposes to remove from existing paragraph (b)(1)(i) a
vestigial reference to a compliance deadline that has already passed.
This is merely an administrative revision.
BSEE would also revise existing paragraph (b)(2)(ii) to proposed
paragraph (a)(2)(ii) by changing the testing facilities' verification
pressure testing hold time demonstration from 30 minutes to 5 minutes.
This revision would allow the continued use of the established
historical data to help verify the pressure holding time. BSEE is
proposing to revise this paragraph after consideration and reevaluation
of the original WCR and historical data along with the longstanding
successful practical application of that data. BSEE does not expect
this revision to decrease safety because the shear ram testing
timeframes of five minutes in a lab have been well established, and
BSEE believes the historical data indicates that five minutes is
adequate to demonstrate effective sealing. BSEE has increased its
interaction with testing facilities and is continuing to evaluate any
additional testing protocols. BSEE will continue to interact with
testing facilities to ensure that new protocols or test data do not
show a need for a longer test period.
BSEE also proposes to make a minor revision to paragraph (c) to
update an incorrect citation--the referenced definition of High
Pressure High Temperature (HPHT) environments is found in Sec.
250.804(b) rather than Sec. 250.807(b), as stated in the current
regulations. This revision is administrative in nature and ensures
[[Page 22139]]
that the appropriate citations are correctly cross referenced.
With the removal of the BAVO references, BSEE is also proposing to
remove the mechanical integrity assessment (MIA) report requirements
from paragraph (d). This MIA report was a function of the BAVO. Based
on discussions regarding the MIA report after publication of the
original WCR, BSEE determined that the information contained within the
MIA report was redundant with the BOP equipment capability
verifications required by Sec. 250.731. The independent third party
verifications in Sec. 250.731 help ensure that the BOP systems have
the appropriate capabilities and are fit for service for a specific
well and location.
What are the requirements for a surface BOP stack? (Sec. 250.733)
This rulemaking would revise paragraph (a)(1) by removing the
reference to an extended time for compliance with exterior control line
shearing requirements under the original WCR, which BSEE anticipates
will have run and no longer warrant reference in the regulations by the
time a final rule is promulgated. BSEE also proposes to remove the
requirement to have an alternative cutting device used for shearing
electric-, wire-, or slick-line if your blind shear rams are unable to
cut and seal under maximum anticipated surface pressure (MASP). The
alternative cutting device is no longer necessary because the currently
commercially available shear rams have increased design capabilities,
which are capable of shearing these types of lines. BSEE is aware of
concerns regarding the removal of the alternative cutting device
option. Therefore, BSEE is considering other options in the final rule,
such as keeping the alternative cutting device provisions in the
regulations or extending the compliance date to allow the use of the
alternative cutting devices until a more appropriate date when the
surface stack shear rams can be upgraded to shear electric-, wire-, or
slick-line.
BSEE is specifically soliciting comments about the effectiveness of
using an alternative cutting device and whether BSEE should continue to
allow its use. Additionally, BSEE is also specifically soliciting
comments on how long it would take for surface stack shear rams to be
upgraded to shear electric-, wire-, or slick-line. Please provide
reasons for your position and any applicable associated data.
BSEE is also proposing to revise paragraph (b)(1) to extend the
compliance date from April 29, 2019 to April 29, 2021, to correspond
with the same requirements for subsea BOP stacks. This revision would
align the dual shear ram requirements for surface BOPs installed on
floating facilities and subsea BOPs. Aligning these dates would help
minimize confusion between the conflicting effective dates of the
parallel requirements for surface BOPs used on floating facilities and
subsea BOPs. This revision would also allow more time to install the
dual shear rams in a surface BOP on a new floating facility and
potentially minimize the technical and economic challenges prior to
installation.
New paragraph (e) would be added to clarify the minimum surface BOP
system requirements for well-completion, workover, and decommissioning
operations where estimated well pressures are low. The provisions in
this proposed paragraph were inadvertently removed from the regulations
through the original WCR and are consolidated from Sec. Sec. 250.516,
250.616, and 250.1706 of the regulations as they existed before the
original WCR. BSEE is proposing minor revisions to the original
language to conform to the applicable operations covered under revised
Subpart G and to update cross-referenced citations. When BSEE developed
the original WCR, it attempted to consolidate all of the BOP
requirements from Subparts D, E, F, and Q, but in doing so
inadvertently removed the requirements of this paragraph. The
provisions in this paragraph would provide flexibility to utilize
appropriate configurations and capabilities for surface BOP stacks
where estimated well pressures are low (e.g., an end of life well).
What are the requirements for a subsea BOP system? (Sec. 250.734)
BSEE proposes to revise paragraph (a)(1)(ii) by clarifying that a
``combination of the'' shear rams must be capable of shearing all the
items specified in the paragraph. This revision would better align the
functionality of the BOP system with API Standard 53 and proposed Sec.
250.730(a). Based upon BSEE experience with the implementation of the
original WCR, BSEE is aware that certain casing shears still have
difficulty shearing electric-, wire-, or slick-line, while certain
blind shear rams have difficulties shearing larger casing sizes. This
proposed revision would provide the operators flexibility for how they
utilize the BOP system and components for operations while still
ensuring all critical shearing capabilities. This would not impact
safety because BSEE would still require the capability to shear at any
point along the tubular body of any drill pipe (excluding tool joints,
bottom-hole tools, and bottom hole assemblies such as heavy-weight pipe
or collars), workstring, tubing and associated exterior control lines,
appropriate area for the liner or casing landing string, shear sub on
subsea test tree, and any electric-, wire-, slick-line in the hole.
BSEE expects the operators to better evaluate how the BOP system,
including both shear rams, would function together to comply with the
required shearing capabilities. The proposed rule would also revise
paragraph (a)(1)(ii) by removing references to extended times for
compliance with certain shearing requirements under the original WCR,
which BSEE anticipates will have run and no longer warrant reference in
the regulations by the time a final rule is promulgated.
This rulemaking would revise the accumulator requirements in
paragraph (a)(3) to better align with API Standard 53. BSEE would
remove the reference to the subsea location of the accumulator
capacity. BSEE understands that the accumulator system works together
with the surface and subsea accumulator capacity to achieve full
functionality, and BSEE determined that it was unnecessary to
specifically identify only subsea requirements when the entire system
is covered within API Standard 53. BSEE does not expect these revisions
to reduce safety. The requirements to operate the key components of the
BOP subsea will remain the same. This revision helps reduce the non-
critical accumulator capacity on the BOP stack subsea, but would not
affect safety of the critical components. Adding subsea accumulator
bottles increases weight and size, which could have a negative impact
on the stability and functionality of existing facilities by exceeding
the operational or mechanical design limits of the wellhead and BOP
systems.
Paragraph (a)(3)(i) would be revised by clarifying that the
accumulator capacity must be sufficient to close each required shear
ram, ram locks, one pipe ram, and disconnect the LMRP. During a well
control event, the most critical functions would be to close the BOP
components and seal the well. This revision would also align the
requirements with the intent of the API Standard 53 request for
information finalized after the original WCR.
Paragraph (a)(3)(ii) would be revised to clarify that the
accumulator capacity must have the capability to perform the ROV
functions within the required times outlined in API Standard 53 with
ROVs or flying leads. Based upon BSEE experience with the
implementation of the original WCR, BSEE is proposing to
[[Page 22140]]
revise this paragraph not only to better align with API Standard 53,
but also to account for the technological advancements in ROV
capabilities and ROV standardization to meet the appropriate BOP
closing times via an ROV. Many of these advancements have taken place
after publication of the original WCR. BSEE is aware of operators
currently using high flow rate ROVs to meet the BOP component closing
times of API Standard 53.
Paragraph (a)(3)(iii) would be revised by removing the mention of
``dedicated'' bottles and allowing bottles to be shared among emergency
and secondary control system functions to secure the wellbore. This
revision would further align the accumulator capacity requirements with
API Standard 53 and account for the appropriate number of accumulator
bottles on the subsea BOP stack. This revision would increase operator
flexibility to utilize the appropriate accumulator capacity to perform
the necessary emergency functions. Through the implementation of the
original WCR, BSEE was able to better evaluate the effects of the
original WCR accumulator requirements impacting subsea BOP space and
weight limitations. This revision would help ensure that the regulatory
requirements do not exceed the operational or mechanical design limits
of the wellhead and BOP systems, and would help minimize risks
associated with approaching those design limits.
This rulemaking would revise paragraph (a)(4) by removing the term
``opening'' and adding reference to the ROV function response times
outlined in API Standard 53. After publication of the original WCR, the
API Standard 53 committee clarified the definition of ``operate''
critical functions to include ``close'' only and not to include
``open.'' Removal of the ROV open function would limit the ability for
well intervention after the well has already been secured; however, it
would not affect or decrease the ability for the ROV to close the
required components for well control purposes. During a well control
event, the most critical functions would be to close the BOP components
and seal the well. This revision would minimize the required number of
equipment alterations to the subsea ROV panel and associated control
systems and improve consistency with similar requirements in API
Standard 53. The open function on the ROV panel may also be unnecessary
due to technological advancements in well intervention capabilities
once the well has already been secured. This paragraph would also be
revised by requiring the ROV to function the appropriate BOP component
within the required response time outlined in API Standard 53. BSEE is
proposing to revise this paragraph not only to better align with API
Standard 53, but also to account for the recent technological
advancements in ROV capabilities and ROV standardization to meet the
appropriate BOP closing times via an ROV. BSEE is aware that operators
currently use high flow rate ROVs to meet the BOP component closing
times of API Standard 53.
BSEE would also update the incorporated reference to API RP 17H to
a newer edition in Sec. 250.198(h)(94). There is a conflict between
the API RP 17H first edition referenced in the original WCR and the API
Standard 53 ROV requirements. The second edition of API RP 17H
eliminates the conflict between the first edition and API Standard 53.
BSEE would incorporate by reference the second edition of API RP 17H to
ensure the appropriate methods are utilized to comply with the API
Standard 53 ROV closure timeframes of 45 seconds. One of the main
differences between the first edition and second edition of this
recommended practice is that the second edition includes provisions on
high flow Type D 17H hot stabs.
This rulemaking would also revise paragraph (a)(6)(iv) by
clarifying that the autoshear/deadman functions must close at a minimum
two shear rams in sequence, not every emergency function. Closing two
shear rams in sequence may not be advantageous for certain emergency
disconnect system (EDS) functions. Depending upon the rig operations,
operators develop different EDS modes that would function different BOP
components at appropriate times. The selection of the EDS mode and the
specific sequencing of emergency functions should be developed by the
operator based on safety considerations and an operational risk
assessment. BSEE would make this change to codify BSEE guidance on the
original WCR posted on the BSEE website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
BSEE would revise paragraph (a)(16) by removing references to the
centering mechanism and the ability to mitigate compression of the pipe
between the shear rams in paragraphs (i) and (ii), respectively. Based
upon BSEE experience with the implementation of the original WCR and
increased interactions with OEMs of shearing components, BSEE would
remove these paragraphs based upon a better understanding of the
technological advancements of available shearing capabilities to
accomplish the same goals outlined in these paragraphs. Many of the
shear ram designs have improved the shearing capabilities to help
ensure the shearing is conducted on the appropriate shearing area of
the shear blades. This is commonly done by shaping the shear ram
cutting blades in a ``V'' or ``W'' pattern to help center the pipe as
it shears, as well as to increase the blade face surface area to ensure
there are no areas that cannot shear the pipe in the well. BSEE is also
proposing to remove paragraphs (a)(6)(v) and (a)(6)(vi) based upon a
better understanding of the third party verifications and documentation
of the shearing requirements as outlined in current Sec. 250.732(b).
BSEE does not expect these revisions to decrease safety because these
newer designed shear rams are off the shelf available components that
can be swapped with current components. BSEE believes that operators
will continue to substitute new components for old ones to comply with
the still-required increased shearing capability provisions of the
original WCR. BSEE is aware of many technological advancements in
shearing ram designs and capabilities. BSEE expects the shear rams to
shear pipe or wire in any position within the wellbore; however, BSEE
is specifically soliciting comments about the effectiveness of
requiring shear rams to center pipe or wire while shearing, or
requiring shear rams to have the capability to shear any pipe or wire
in the hole without a separate centering mechanism. Another option BSEE
is considering is retaining the centering mechanism requirements, but
expressly providing that the shear rams with these capabilities satisfy
the requirements. Please provide reasons for your position and any
applicable associated data.
This rulemaking would revise paragraph (b)(1) by replacing the BAVO
references with references to an independent third party. For a
discussion of the general shift from BAVOs to independent third
parties, see the section-by-section discussion of Sec. 250.732.
BSEE would also revise paragraph (b)(2), redesignate existing
paragraph (b)(3) as (b)(4), and add new paragraph (b)(3) to include
provisions for testing the applicable BOP or LMRP upon relatch to the
well. The original WCR did not address this provision, however based
upon BSEE experience, these revisions would codify longstanding BSEE
policy and provide clarity for testing when an operator has returned to
the location and relatched the BOP or LMRP to the well. These tests
help confirm that the BOP or LMRP is
[[Page 22141]]
properly functional prior to resuming operations after being removed.
What associated systems and related equipment must all BOP systems
include? (Sec. 250.735)
This proposed rule would revise paragraph (a) by clarifying that
the accumulator system must have the fluid volume capacity and
appropriate pre-charge pressures in accordance with API Standard 53.
BSEE would revise this section to provide consistency with the API
Standard 53 and conform to the other proposed accumulator system
revisions in Sec. 250.734. This revision would not materially alter
the requirements of this section, which are already based upon API
Standard 53. An accumulator system is necessary to provide the fluid
and pressure to operate desired BOP functions. API Standard 53 outlines
the pre-charge pressure calculations in Annex C and additional
requirements for the accumulator system pressures in the drawdown
tests.
What are the requirements for choke manifolds, kelly-type valves inside
BOPs, and drill string safety valves? (Sec. 250.736)
This rulemaking would revise paragraph (d)(5) by including
equipment requirements for the safety valve when running casing with a
subsea BOP. This revision would specify that the safety valve must be
available on the rig floor if the length of casing being run exceeds
the water depth, which would result in the casing being across the BOP
stack and the rig floor prior to crossing over to the drill pipe
running string. Based upon BSEE experience with the implementation of
the original WCR, the substance of this revision is currently
incorporated into every subsea well permit approval as a standard
condition. This revision would provide clarity and consistency
throughout BSEE permitting and minimize the number of alternate
procedure or equipment requests submitted to BSEE.
What are the BOP system testing requirements? (Sec. 250.737)
This rulemaking would revise paragraph (b) to clarify the BOP
system pressure testing requirements. These revisions would include
clarification that the test rams and non-sealing shear rams do not need
to be pressure tested, and this would not impact safety because the
non-sealing shear rams are not pressure holding components and the test
ram is an inverted ram that is not utilized for well control purposes.
Paragraph (b)(2) would be revised to add in the current BSEE policy for
conducting the high-pressure test for specific components. For example,
some of the revisions would include specific procedures and testing
parameters for initial equipment pressure testing and also include the
provisions for subsequent pressure testing on the same equipment. Since
the publication of the original WCR, BSEE received many questions from
operators regarding the operational application of the current pressure
testing requirements. This proposed revision would codify BSEE policy
and provide clarity and consistency for permitting throughout the
Regions and Districts.
In this proposed rule, BSEE would also revise paragraphs (d)(2) and
(d)(3) by removing the requirement to submit test results to BSEE where
BSEE is unable to witness testing. Based upon BSEE experience with the
implementation of the original WCR, these revisions would significantly
reduce the number of submittals to BSEE and minimize the associated
burden for BSEE to review those submittals. If BSEE is unable to
witness the testing, BSEE still has access to the testing documentation
upon request in accordance with Sec. Sec. 250.740, 250.741, and
250.746.
Paragraph (d)(3)(iv) would be revised by removing ``test and[.]''
BSEE would remove this term to minimize confusion regarding
verification and testing. In this instance, verification of closure
qualifies as testing the ROV functions. The purpose of the stump test
is to help ensure the BOP components and control systems can function
properly before being utilized on a well.
BSEE would revise paragraph (d)(3)(v) to clarify that pressure
testing of each ram and annular on the stump test is only required
once. This revision would help ensure that the testing of BOP
components during stump testing would limit unnecessarily duplicative
pressure testing on each ram or annular. BSEE would also make this
change to codify BSEE guidance on the original WCR. The purpose of the
stump test is to help ensure the BOP components and control systems can
function properly before being utilized on a well. It is unnecessary to
pressure test a ram or annular multiple times during stump testing if
that component has already been successfully pressure tested, verifying
proper functionality. This revision would help limit the risk
associated with component wear.
Paragraph (d)(4)(i) would be revised to clarify that the initial
subsea BOP test on the sea floor would need to ``begin'' within 30 days
of the stump test. BSEE receives many questions about the timing of the
initial subsea test and, as written, the regulation was ambiguous
regarding exactly what needed to occur within the 30 days. Based upon
its experience with the implementation of the original WCR, BSEE
proposes this revision to clarify that the testing has to begin within
30 days. BSEE wants to ensure that the time between the stump testing
and the initial subsea test is minimal to help ensure that all of the
BOP components can properly function upon installation on the well.
Paragraph (d)(4)(iii) would be revised to include annulars in the
pressure testing requirements of paragraphs (b) and (c) of this
section. This revision would not alter the current testing requirements
for annulars, but based upon BSEE experience with the implementation of
the original WCR, would provide clarity for where to find them.
Paragraph (d)(4)(v) would be revised to clarify the initial subsea
pressure testing requirements to confirm closure of the selected ram
through an ROV hot stab. This revision would require the operator to
confirm closure through a 1,000 psi pressure test held for 5 minutes.
This revision would codify BSEE policy for pressure testing the
selected ram through the ROV hot stabs. Based on BSEE experience during
the implementation of the original WCR, BSEE has concluded that testing
to higher pressures is not necessary for this circumstance because the
intended purpose of this test is to verify operability of the ROV hot
stab to close the selected ram. Selected rams will be pressure tested
according to other regularly required pressure testing intervals. This
revision would save rig operational time by reducing the amount of time
required to conduct the pressure test, minimize the risk associated
with wear of the BOP components, and eliminate associated alternate
procedure requests.
Existing paragraph (d)(4)(vi) would be removed because the testing
requirements of the selected ram would now be covered under proposed
paragraph (d)(4)(v).
BSEE would revise paragraph (d)(5) by clarifying the alternating
testing schedules of control stations and pods. These revisions would
ensure that operators develop a testing schedule that allows for
alternating testing between the control stations, and also between the
pods for subsea BOPs. The intended result of alternating the testing is
to ensure that each control station, and each pod for subsea, can
properly function all required BOP components. Based on BSEE experience
during the implementation of the original WCR,
[[Page 22142]]
BSEE has concluded that these revisions would help ensure BOP
functionality while not inadvertently requiring unnecessarily
duplicative testing. This revision would save rig operational time by
reducing the number of unnecessary duplicate tests, and minimize the
risk associated with wear of the BOP components functioned during
testing.
Paragraph (d)(12)(iv) would be revised by clarifying that, during
the deadman test on the seafloor, operators are not required to
indicate the discharge pressure of the subsea accumulator throughout
the entire test. These revisions would require that the remaining
pressure be documented at the end of the test, to help verify the
proper accumulator settings required to function the specific critical
BOP components.
Paragraph (d)(12)(vi) would be revised to clarify the pressure
testing requirements of the original WCR, to confirm closure of the
BSR(s) during the autoshear/deadman and EDS testing. This revision
would require confirmation of closure through a 1,000 psi pressure test
held for 5 minutes. Based upon BSEE experience with the implementation
of the original WCR, this revision would codify BSEE policy for
autoshear/deadman and EDS pressure testing of the BSR(s). Testing to
higher pressures is not necessary for this circumstance because the
BSR(s) will be pressure tested according to other regularly required
pressure testing intervals. This revision would save rig operational
time by reducing the amount of time required to conduct the pressure
test, and minimize the risk associated with wear of the BOP components.
BSEE proposes to add paragraph (d)(13) setting forth exceptions for
pressure testing the choke and kill side outlet valves. Since
publication of the original WCR, BSEE has received many questions from
operators regarding the operational application of the current pressure
testing requirements. This addition would codify BSEE policy and
provide consistency for permitting throughout the Regions and Districts
without meaningfully reducing safety or environmental protection.
What must I do in certain situations involving BOP equipment or
systems? (Sec. 250.738)
This rulemaking would revise paragraphs (b), (i), (m), and (o) by
replacing the references to BAVOs with references to an independent
third party throughout. For a discussion of the proposed shift from
BAVOs to independent third parties, see the section-by-section
discussion of Sec. 250.732.
Paragraph (f) would be revised to clarify the testing requirements
implemented by the original WCR necessary to verify the integrity of
the affected casing ram or casing shear ram and connections. Based upon
BSEE experience with the implementation of the original WCR, this
revision would codify BSEE policy to allow the pressure testing to the
test pressure of the BOP component above this ram as specified in the
approved permit.
Paragraph (m) would be revised to replace the term ``well-control
equipment'' with ``circulating or ancillary equipment.'' This revision
would eliminate confusion arising from the use of conflicting terms
that may have different meanings throughout the regulations.
What are the BOP maintenance and inspection requirements? (Sec.
250.739)
BSEE proposes to revise paragraph (b) by replacing ``complete
breakdown and detailed physical inspection'' with a ``major, detailed
inspection,'' identifying examples of well control system components,
replacing references to the BAVO with references to an independent
third party, and replacing the requirement to have a BAVO present
during each inspection with a requirement for an independent third
party to review inspection results.
Replacing ``complete breakdown and detailed physical inspection''
with a ``major, detailed inspection'' would correct the industry
misconception, prevalent since the promulgation of the original WCR,
that each component must be dismantled to its smallest possible part.
This was never the intent behind this provision of the WCR, and these
revisions would clarify BSEE's positions on the WCR requirement and
resolve perceived ambiguities, without substantively altering the
inspection requirement. BSEE would make this change to codify BSEE
guidance on the original WCR posted on the BSEE website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
BSEE also proposes to add references to examples of the well control
system components requiring inspection to clarify the general reference
in the original WCR.
For a discussion of the proposed shift from BAVOs to independent
third parties, see the section-by-section discussion of Sec. 250.732.
BSEE would also remove the requirement for the BAVO to be present
during each inspection and replace it with a requirement that an
independent third party review the inspections results. BSEE expects
the independent third party to review the documentation of the
inspections to help ensure that the appropriate entities accurately and
appropriately complete the activities. These reports would also help
facilitate other required verifications that the BOP is fit for
service, such as those required by Sec. 250.731. These revisions would
ease the original WCR logistical and economic burdens of having the
BAVO onsite at all times during all inspections.
What are the coiled tubing and snubbing requirements? (Sec. 250.750)
The content of this proposed section was moved from current
Sec. Sec. 250.616 and 250.1706. This section would consolidate some of
the minimum BOP system component requirements for coiled tubing and
snubbing operations. BSEE is proposing minor revisions to the original
language to conform to the applicable operations covered under Subpart
G. BSEE is also proposing to add paragraph (d) to conform snubbing unit
testing with updated requirements.
Coiled Tubing Testing Requirements (Sec. 250.751)
BSEE proposes to add this section to codify current BSEE policy
regarding the coiled tubing testing and recording requirements. This
addition would a reintroduce similar provisions that were inadvertently
removed in the original WCR, consolidating elements from Sec. Sec.
250.617 and 250.1707 of the regulations as they existed before the
original WCR. Both sections are currently reserved. BSEE is proposing
revisions to the original language to conform to the applicable
requirements of Subpart G. For example, BSEE would not include in this
section the provisions regarding testing of the coiled tubing
connector, because the proposal would require that operators ``must
test the coiled tubing unit in accordance with Sec. 250.737 paragraphs
(a), (b), (c), (d)(9), and (d)(10)''. Section 250.737 requires testing
of the system when installed and provides testing criteria. Identifying
the connector testing in this section is not necessary because it is
already covered by the testing requirements of Sec. 250.737.
Subpart Q--Decommissioning Activities
What are the general requirements for decommissioning? (Sec. 250.1703)
This rulemaking would revise paragraph (b) to clarify that only
packers or bridge plugs used as mechanical barriers are required to
comply with ANSI/API Spec. 11D1. Based upon BSEE experience with the
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implementation of the original WCR, this revision would codify BSEE's
policy to ensure that the required mechanical barriers in a well are
held to a higher standard than other common packers or bridge plugs
used for various well specific conditions and completions design.
Furthermore, BSEE is aware that certain packers and bridge plugs cannot
meet the specifications of ANSI/API Spec. 11D1. This revision would
minimize the number of alternate equipment requests submitted to BSEE.
BSEE would also add that operators must have two independent barriers,
one being mechanical, in the exposed center wellbore (e.g., this could
be the tubing or casing depending on the well configuration) prior to
removing the tree or well control equipment. This addition would codify
BSEE policy and align the well decommissioning requirements with
similar requirements from Sec. Sec. 250.720(a) and 250.1712(g). This
addition would help ensure the well is properly secured before removal
of the tree or well control equipment.
What decommissioning applications and reports must I submit and when
must I submit them? (Sec. 250.1704)
BSEE proposes to revise paragraph (g) by adding the requirements
for submittal of the site clearance verification activity information
in an Application for Permit to Modify (APM). The site clearance
verification activity information would be removed from the end of
operations report (EOR). Based on BSEE experience during the
implementation of the original WCR, BSEE became aware of dual reporting
of the same information and confusion about which permit or report
should include the information. These revisions would better reflect
current practice and limit redundant reporting.
Paragraph (h) would be revised by adding the submittal of the
decommissioning activity information, upon completion, in the EOR.
Based upon BSEE experience with the implementation of the original WCR,
these revisions would better reflect current practice and limit
redundant reporting.
Coiled Tubing and Snubbing Operations (Sec. 250.1706)
This section would be removed and reserved. The content of this
section would be moved to proposed Sec. 250.750. These revisions would
help BSEE eliminate inconsistencies between similar requirements
throughout different BSEE subparts by consolidating those requirements
into Subpart G, which is applicable to drilling, completions,
workovers, and decommissioning operations.
Must I notify BSEE before I begin well plugging operations? (Sec.
250.1713)
This section would be removed and reserved. Based upon BSEE
experience with the implementation of the original WCR, BSEE determined
that the submittal of the information required by this section is
redundant with similar rig movement notification information required
under Sec. 250.712.
To what depth must I remove wellheads and casings? (Sec. 250.1716)
This rulemaking would revise paragraph (b)(3) by changing the water
depth criteria for when BSEE may approve an alternate depth for removal
of the wellhead or casing from 800 meters to 1000 feet. BSEE would
include this new regulatory revision in order to codify longstanding
BSEE policy established before the original WCR. At depths below 1,000
feet, there is little risk of obstruction to other users of the OCS or
its waters or contact with other equipment, and little risk of safety
or environmental issues from removal to an alternate depth.
If I install a subsea protective device, what requirements must I meet?
(Sec. 250.1722)
BSEE proposes to revise paragraph (d) to direct the submittal of
the trawl test report to the EOR rather than an APM. This revision
would reflect current BSEE practice established before publication of
the original WCR and help minimize redundant reporting. It would not
affect the substance of the reporting requirement or the information
BSEE receives, only the mechanism through which it is received.
III. Additional Comments Solicited
A. BOP Testing Frequency
BSEE is requesting comments on whether the BOP testing interval
should be 7 days, 14 days, or 21 days for all types of operations
including drilling, completions, workovers, and decommissioning. BSEE
is also requesting comments on the specific cost and operational
implications of each testing interval to further its consideration of
the issue.
The industry and BSEE currently rely on function and hydrostatic
tests to verify the performance of BOP equipment in the field. These
tests have traditionally been the primary method of verifying the
capability of in-service equipment.
In recent years, the industry has raised concerns related to the
benefits of pressure and functional testing of subsea BOPs when
compared to the costs and potential operational issues. BSEE requests
comments on the adequacy of the current functional and pressure test
requirements in predicting the performance of this equipment in
subsequent drilling operations. Under what circumstances or
environments should the testing frequency be increased or decreased?
BSEE is aware of potential technologies that may improve the
operability and reliability of BOP systems. Are there additional
technologies, processes, or procedures that can be used to supplement
existing requirements and provide additional assurances related to the
performance of this equipment?
Please provide supporting reasons and data for your responses.
B. Economic Data
The compliance costs and savings in the regulatory impact analysis
(RIA) are BSEE's best estimates based on experience with the previous
WCR, stakeholder comments, and communication with industry. BSEE is
requesting comments related to the appropriateness and accuracy of the
compliance costs and benefits identified in the RIA. Please provide
supporting reasons and data for your responses.
IV. Procedural Matters
Regulatory Planning and Review (Executive Orders (E.O.) 12866, 13563,
and 13771)
Executive Order 12866 provides that the Office of Information and
Regulatory Affairs within the OMB will review all significant rules.
BSEE coordinated development of an economic analysis to assess the
anticipated costs and potential benefits of the proposed rulemaking.
OIRA has determined that it would have a positive annual effect on the
economy of $100 million or more. The significant positive economic
effect on the economy is the result of the proposed cost savings in
this rule. BSEE estimates the amendments in this rulemaking would save
the regulated industry $98.6 million annually over ten years
(discounted at 7 percent).
Executive Order 13563 reaffirms the principles of E.O. 12866 while
calling for improvements in the Nation's regulatory system to promote
predictability, to reduce uncertainty, and to use the best, most
innovative, and least burdensome tools for achieving regulatory ends.
The E.O. directs agencies to consider regulatory approaches that reduce
burdens and maintain flexibility and freedom of choice for the public
where these
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approaches are relevant, feasible, and consistent with regulatory
objectives. Executive Order 13563 emphasizes further that regulations
must be based on the best available science and that the rulemaking
process must allow for public participation and an open exchange of
ideas. We have developed this rule in a manner consistent with these
requirements.
Executive Order 13771 requires Federal agencies to take proactive
measures to reduce the costs associated with complying with Federal
regulations. This proposed rule is expected to be an E.O. 13771
deregulatory action. Details on the estimated cost savings of this
proposed rule can be found in the rule's economic analysis. The cost
savings for the regulatory clarifications, reduction in paperwork
burdens, adoption of industry standards, and migration to performance-
based standards for select provisions constitute an E.O. 13771
deregulatory action. BSEE also finds that the reduced regulated entity
compliance burden would not increase the safety or environmental risks
for offshore drilling operations.
This rulemaking proposes to revise regulatory provisions in 30 CFR
part 250, subparts D, E, F, G, and Q. BSEE has reassessed a number of
the provisions in the original (1014-AA11) WCR rulemaking and proposes
to rewrite some provisions as performance-based standards rather than
prescriptive requirements. Other proposed revisions would reduce or
eliminate parts of the paperwork burden, while providing the same
levels of safety and environmental protection. BSEE sought the best
available data and information to analyze the economic impact of the
proposed changes. The Initial RIA (IRIA) for this rulemaking can be
found in the https://www.regulations.gov/ docket (Docket ID: BSEE-2018-
0002). The IRIA indicates that the estimated overall cost savings to
the industry over the next 10 years would exceed $900 million in
nominal dollars.
BSEE proposes to revise certain provisions of the original rule to
support the goals of the regulatory reform initiatives while ensuring
safety and environmental protection. BSEE has received additional
information since the publication of 1014-AA11 and revisited several of
the compliance cost assumptions in the economic analysis for the 2016
1014-AA11 final rule. The proposed modifications to the BSEE compliance
cost estimates in the 1014-AA11 analysis are primarily related to:
(1.) Underestimating the cost for revising permits or reporting
certain operations to the District Manager (Sec. Sec. 250.428 and
250.722), and
(2.) Underestimating both the number of subsea BOPs that would
require modifications and the cost of those modifications under the
1014-AA11 regulations (Sec. 250.734).
The proposed revisions to existing ram and accumulator requirements
for subsea BOPs (Sec. 250.734) represent the single largest cost
savings provision in this proposed rule, yielding cost savings of $690
million (nominal$). The proposed changes to Sec. 250.734 would better
align the shear ram provisions with API Standard 53, revise the
accumulator capacity requirements for subsea BOP stacks, and redefine
shearing requirements.
BSEE expects the proposed rule would reduce the regulatory burden
on industry, and the proposed amendments would not negatively impact
worker safety or the environment. BSEE proposes to provide industry
flexibility, when practical, to meet the safety or equipment standards,
rather than specifying the compliance method. For example, BSEE is
proposing to eliminate the requirement that operators resubmit an
Application for Permit to Drill (APD) in the event of planned mud
losses or inadequate cement jobs. Instead, BSEE proposes to allow the
operator to outline remedial actions to these scenarios in contingency
plans included in the original approved APD. This revision would not
change the operational responses to these events, and therefore will
reduce the paperwork burden and expensive operational downtime without
increasing drilling risks. Other changes would remove BOP stack
certification requirements regarding design specifications and
equipment conditions and replace the BAVO requirements for BOP systems
and system components with independent third party requirements. The
existing provisions are either duplicative or provide a more burdensome
certification process than necessary. The proposed changes to the
certification processes will continue to protect worker safety and the
environment.
The proposed Sec. 250.734 amendments would better define the BOP
components functionality requirements, revise the requirements for ROV
capability and functionality, and amend accumulator capacity
requirements for subsea BOP stacks. This revision to the accumulator
requirements would increase operator flexibility to utilize the
appropriate accumulator capacity to perform the necessary emergency
functions. Through the implementation of the original WCR, BSEE was
able to better evaluate the effects of the original WCR accumulator
requirements on subsea BOP space and weight limitations. After
reevaluating the API 53 standards, BSEE agrees that certain
prescriptive requirements in the current regulations are unnecessary
and the proposed regulatory text revisions would align BSEE regulations
with the performance standards in API Standard 53. The proposed Sec.
250.734 revisions would also remove the prescriptive requirement that
EDS emergency functions must close at a minimum two shear rams in
sequence. This would allow the operator to select the appropriate EDS
emergency function shearing sequence for the circumstances and would
adopt the performance standard that the BOP system must be able to seal
the wellbore. Furthermore, the accumulator capacity required in API 53
is sufficient to actuate the BOP ram functions necessary to seal the
well. This performance standard meets the intent of the 1014-AA11 well
control rule without the prescriptive and unnecessarily burdensome
requirements. The alignment of the accumulator volume requirements with
industry standards would also provide additional safety benefits. The
weight of the combined BOP and accumulator bottle package required by
the original rule would be reduced with these proposed revisions. This
reduction would avoid increased strain on rig handling systems and
potentially avoid modifications on some rigs to accommodate the
additional space and BOP handling requirements.
The proposed Sec. 250.737 paragraph (d)(5) amendments would allow
the operator to alternate tests between the two control stations rather
than testing from both control stations on each test. Testing from both
control stations on a weekly basis has been proven to wear the BOP
components out at a faster rate than was expected when the original WCR
was written. The proposed rule would return the regulations to pre-
1014-AA11 regulatory language in order to prevent the additional wear
and tear on the BOP components. This change would align BSEE
regulations with the industry testing standards.
BSEE's estimate of the net total, annualized and discounted
regulatory cost savings can be found in the following table.
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This rulemaking would reduce the burden imposed on society while
ensuring continued safety and environmental protection. Additional
information on the compliance costs, savings, and benefits can be found
in the IRIA posted in the docket.
BSEE has developed this proposed rule consistent with the
requirements of E.O. 12866, E.O. 13563, and E.O. 13771. This proposed
rule would revise multiple provisions in the current regulations with
performance-based provisions based upon the best reasonably obtainable
safety, technical, economic, and other information. Other redundant or
unnecessary reporting requirements are proposed for elimination. BSEE
proposes to provide industry flexibility, when practical, to meet the
safety or equipment standards, rather than specifying the compliance
method. Based on a consideration of the qualitative and quantitative
safety and environmental factors related to the proposed rule, BSEE's
assessment is that its promulgation would be consistent with the
requirements of the applicable Executive Orders and the OCSLA.
Regulatory Flexibility Act and Small Business Regulatory Enforcement
Fairness Act
The Regulatory Flexibility Act, 5 U.S.C. 601-612, requires agencies
to analyze the economic impact of proposed regulations when a
significant economic impact on a substantial number of small entities
is likely and to consider regulatory alternatives that will achieve the
agency's goals while minimizing the burden on small entities. In
addition, the Small Business Regulatory Enforcement Fairness Act of
1996, 5 U.S.C. 601 note, requires agencies to produce compliance
guidance for small entities if the rule has a significant economic
impact. For the reasons explained in this analysis, BSEE believes the
proposed rule may have a significant economic impact and, therefore, a
regulatory flexibility analysis for the Proposed Rule is required by
the RFA. The Initial Regulatory Flexibility Analysis (IRFA), which
assesses the impact of this proposed rule on small entities, can be
found in the Regulatory Impact Analysis (RIA) within the docket for
this rulemaking.
As defined by the Small Business Administration (SBA), a small
entity is one that is ``independently owned and operated and which is
not dominant in its field of operation.'' What characterizes a small
business varies from industry to industry in order to properly reflect
industry size differences. This proposed rule would affect lease
operators that are conducting OCS drilling or well operations. BSEE's
analysis shows this could include about 69 companies with active
drilling or well operations. Of the 69 companies, 21 (30 percent) are
large and 48 (70 percent) are small. Entities that would operate under
this proposed rule are classified primarily under North American
Industry Classification System (NAICS) codes 211120 (Crude Petroleum
Extraction), 211130 (Natural Gas Extraction), and 213111 (Drilling Oil
and Gas Wells). The proposed rule would indirectly impact OCS drilling
companies that are the regulated entities classified under NAICS code
21311 and this analysis focuses on the OCS oil and gas lessees and
operators. For NAICS codes 211120, SBA defines a small company as
having fewer than 1,251 employees.
BSEE considers that a rule will have an impact on a ``substantial
number of small entities'' when the total number of small entities
impacted by the rule is equal to or exceeds 10 percent of the relevant
universe of small entities in a given industry. BSEE's analysis shows
that there are 48 small companies with active operations on the OCS,
and all of these companies could be impacted by the proposed rule if
conducting drilling or well operations. Therefore, BSEE expects that
the proposed rule would affect a substantial number of small entities.
Large companies are responsible for the majority of activity in
deepwater, where subsea BOPs are used with floating MODUs. BSEE's
first-order estimate for the rulemaking's small entity cost savings is
proportional to the number of drilling rigs being operated or
contracted by small companies (circa October 2017).
This proposed rule is a deregulatory action; however, BSEE has
evaluated possible costs and benefits and has estimated that there is
an overall associated cost savings. BSEE has estimated the annualized
cost savings by regulatory provision and then allocated those savings
to small or large entities based on drilling/well activity (circa
October, 2017; activity breakouts can be found in the IRFA). The
proposed changes to Sec. Sec. 250.423, 250.734, and 250.737 paragraph
(d)(5) would only apply to subsea BOPs and would yield cost savings
that sum to $70,250,336. All remaining proposed changes would apply to
all well operations or subsea/surface BOPs, and would yield cost
savings that sum to $24,367,256. Using the share of small and large
companies subject to each suite of provisions, we estimate that small
companies would realize 15 percent of the cost savings from this
rulemaking and large companies 85 percent. The allocation is displayed
in the following table.
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This proposed rule:
a. Would have a positive economic effect on the economy of $100
million or more. The cost savings will not materially affect the
economy nationally or in any local area.
b. Would not cause a major increase in costs or prices for
consumers; individual industries; Federal, State, Tribal, or local
governments; or regions of the nation. This proposed rule would have
positive effects on OCS operators and is not anticipated to negatively
impact oil, gas, and sulfur production or the cost of fuels for
consumers.
c. Would not have significant adverse effects on competition,
employment, investment, productivity, innovation, or the ability of
U.S.-based enterprises to compete with foreign-based enterprises.
BSEE has determined that this proposed rule is a major rule because
it would have an annual effect on the economy of $100 million or more
in at least one year of the 10-year period analyzed. The requirements
apply to all entities operating on the OCS regardless of company
designation as a small business. For more information on the small
business impacts, see the IRFA in the RIA. Small businesses may send
comments on the actions of Federal employees who enforce, or otherwise
determine compliance with, Federal regulations to the Small Business
and Agriculture Regulatory Enforcement Ombudsman, and to the Regional
Small Business Regulatory Fairness Board. The Ombudsman evaluates these
actions annually and rates each agency's responsiveness to small
business. If you wish to comment on actions by employees of BSEE, call
1-888-REG-FAIR (1-888-734-3247).
Unfunded Mandates Reform Act of 1995
This proposed rule would not impose an unfunded mandate on State,
local, or tribal governments or the private sector of more than $100
million per year. The proposed rule would not have a significant or
unique effect on State, local, or tribal governments or the private
sector. A statement containing the information required by Unfunded
Mandates Reform Act (2 U.S.C. 1531 et seq.) is not required.
Takings Implication Assessment (E.O. 12630)
Under the criteria in E.O. 12630, this proposed rule does not have
significant takings implications. The rule is not a governmental action
capable of interference with constitutionally protected property
rights. A Takings Implication Assessment is not required.
Federalism (E.O. 13132)
Under the criteria in E.O. 13132, this proposed rule does not have
federalism implications. This proposed rule would not substantially and
directly affect the relationship between the Federal and State
governments. To the extent that State and local governments have a role
in OCS activities, this proposed rule would not affect that role. A
federalism assessment is not required.
Civil Justice Reform (E.O. 12988)
This proposed rule complies with the requirements of E.O. 12988.
Specifically, this rule:
(1) Meets the criteria of section 3(a) requiring that all
regulations be reviewed to eliminate errors and ambiguity and be
written to minimize litigation; and
(2) Meets the criteria of section 3(b)(2) requiring that all
regulations be written in clear language and contain clear legal
standards.
Consultation With Indian Tribes (E.O. 13175)
BSEE is committed to regular and meaningful consultation and
collaboration with tribes on policy decisions that have tribal
implications. Under the criteria in E.O. 13175 and DOI's Policy on
Consultation with Indian Tribes (Secretarial Order 3317, Amendment 2,
dated December 31, 2013), we have evaluated this proposed rule and
determined that it has no substantial direct effects on federally
recognized Indian tribes.
National Technology Transfer and Advancement Act (NTTAA)
BSEE complies with the National Technology Transfer and Advancement
Act (NTTAA) (15 U.S.C. 3701 et seq.) requirement that an agency ``use
standards developed or adopted by voluntary consensus standards bodies
rather than government-unique standards, except where inconsistent with
applicable law or otherwise impractical.'' (OMB Circular A-119 at p.
13). BSEE also complies with the OFR regulations governing
incorporation by reference. (See, 1 CFR part 51.) Those regulations
also specify the process for updating an incorporated standard at Sec.
51.11(a), and BSEE complies with those requirements, including seeking
approval by OFR for a change to a standard incorporated by reference in
a final rule.
Paperwork Reduction Act (PRA) of 1995
This proposed rule contains collections of information that will be
submitted to OMB for review and approval under the PRA, 44 U.S.C. 3501
et seq. As part of its continuing effort to reduce paperwork and
burdens on respondents, BSEE invites the public and other Federal
agencies to comment on any aspect of the reporting and recordkeeping
burden. If you wish to comment on the information collection (IC)
aspects of this proposed rule, you may send your comments directly to
OMB and send a copy of your comments to the Regulations and Standards
Branch (see the ADDRESSES section of this proposed rule). Please
reference 30 CFR part 250, subpart G, Blowout Preventer Systems and
Well Control, 1014-0028, in your comments. To see a
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copy of the information collection request submitted to OMB, go to
http://www.reginfo.gov (select Information Collection Review, Currently
Under Review); or you may obtain a copy of the supporting statement for
the new collection of information by contacting the Bureau's
Information Collection Clearance Officer at (703) 787-1607.
The PRA provides that an agency may not conduct or sponsor, and a
person is not required to respond to, a collection of information
unless it displays a currently valid OMB control number. The OMB is
required to make a decision concerning the collection of information
contained in these proposed regulations 30-60 days after publication of
this document in the Federal Register. Therefore, a comment to OMB is
best assured of being fully considered if OMB receives it by June 11,
2018. This does not affect the deadline for the public to comment to
BSEE on the proposed regulations.
The title of the collection of information for this rule is 30 CFR
part 250, Blowout Preventer Systems and Well Control Revisions
(Proposed Rulemaking). The proposed regulations concern BOP system
requirements and maintaining well control, among others, and the
information is used in BSEE's efforts to regulate oil and gas
operations on the OCS to protect life and the environment, conserve
natural resources, and prevent waste.
Potential respondents comprise Federal OCS oil, gas, and sulfur
operators and lessees. Responses to this collection of information are
mandatory, or are required to obtain or retain a benefit; they are also
submitted on occasion, daily and weekly (during drilling operations),
monthly, quarterly, biennially, and as a result of situations
encountered, depending upon the requirement. The IC does not include
questions of a sensitive nature. The BSEE will protect proprietary
information according to the Freedom of Information Act (5 U.S.C. 552)
and DOI implementing regulations (43 CFR part 2), 30 CFR part 252, OCS
Oil and Gas Information Program, and 30 CFR 250.197, Data and
information to be made available to the public or for limited
inspection.
This proposed rule affects Applications for Permits to Drill (1014-
0025, expiration 4/30/20); Applications for Permits to Modify (1014-
0026, expiration 7/31/20); Subpart B (1014-0024, expiration 11/30/18);
Subpart D (1014-0018, expiration 3/31/2021); Subpart E, (1014-0004,
expiration 1/31/20); Subpart G (1014-0028, expiration 07/31/19); and
Subpart Q, (1014-0010, expiration 1/31/20).
The following is a brief explanation of how the proposed regulatory
changes would affect the various subpart hour burdens:
APD--Proposed Sec. 250.428 removes the requirement to
resubmit an application for permit to drill (APD) in the event of
planned mud losses, or remedial actions for inadequate cement jobs, if
these circumstances are addressed in the original approved APD.
Reductions will be shown during the renewal process (see Section by
Section Discussion above).
250.724(b): BSEE is proposing to eliminate the requirement to
submit certification that you have a real-time monitoring plan that
meets the criteria listed. This would decrease the hour burden by 109
hours (see Section by Section Discussion above).
Subpart A--Sec. 250.423 proposes rewording the
requirement in a manner that would reduce the number of alternative
procedure or equipment requests under Sec. 250.141. Reductions will be
shown during the renewal process (see Section by Section Discussion
above).
Subpart B--Sec. 250.292(p) proposes to require less
information to be submitted in the DWOP. Reductions will be shown
during the renewal process (see Section by Section Discussion above).
Subpart D--Sec. 250.462(e)(1) would add Independent Third
Party costs increasing the non-hour cost burdens by $16,000 (see
Section by Section Discussion above).
Subpart G:
Sec. 250.720(a)(3) would be new and would require operators to
request and receive District Manager approval before resuming
operations after unlatching the BOP or LMRP, and would add 13 burden
hours (see Section by Section Discussion above).
Sec. 250.731 would add Independent Third Party costs, increasing
the non-hour cost burdens by $31,000 (see Section by Section Discussion
above).
Sec. 250.732(a) would add Independent Third Party costs,
increasing the non-hour cost burdens by $765,000 (see Section by
Section Discussion above).
Sec. 250.732(d) would eliminate the requirement to request and
submit for approval all relevant information to become a BAVO. This
would decrease the hour burden by 700 hours (see Section by Section
Discussion above).
Sec. 250.737(d)(5) would be new and proposes to allow for
alternating tests between two control stations; adding 25 burden hours
(see Section by Section Discussion above).
Sec. 250.751 would be new and proposes to include the coiled
tubing testing and recording requirements that were inadvertently
removed in the original Well Control Rule; adding 3,630 burden hours
(see Section by Section Discussion above).
BSEE-Approved Verification Organization = BAVO; is being replaced
with Independent Third Party (ITP). In connection with the original
WCR, BSEE assumed hour burdens in place of non-hour costs associated
with BAVO submissions; however, in this proposed rule, we are capturing
non-hour costs associated with hiring ITPs totaling $812,000 (+$16,000
would be added to the information collection associated with OMB
Control number 1014-0018 and +$796,000 would be added to the
information collection associated with OMB Control number 1014-0028).
1014-0018 and +$796,000 in 1014-0028).
If this proposed rule becomes effective, BSEE will use the current
OMB control numbers for the affected subparts discussed and will have
their information collection burdens adjusted accordingly through the
renewal process.
National Environmental Policy Act of 1969 (NEPA)
BSEE has prepared a draft environmental assessment (EA) to
determine whether this proposed rule would have a significant impact on
the quality of the human environment under the National Environmental
Policy Act of 1969 (NEPA) (42 U.S.C. 4321 et seq.). If the final EA
supports the issuance of a Finding of No Significant Impact for the
rule, the preparation of an environmental impact statement pursuant to
the NEPA would not be required. A copy of the draft EA can be viewed at
www.regulations.gov (use the keyword/ID ``BSEE-2018-0002'').
Data Quality Act
In developing this rule, we did not conduct or use a study,
experiment, or survey requiring peer review under the Data Quality Act
(Pub. L. 106-554, app. C, sec. 515, 114 Stat. 2763, 2763A-153-154).
Effects on the Nation's Energy Supply (E.O. 13211)
This proposed rule is not a significant energy action under the
definition in E.O. 13211. Although the rule is a significant regulatory
action under E.O. 12866, it is not likely to have a significant adverse
effect on the supply, distribution, or use of energy. A Statement of
Energy Effects is not required.
[[Page 22148]]
Clarity of This Regulation
We are required by E.O. 12866, E.O. 12988, and by the Presidential
Memorandum of June 1, 1998, to write all rules in plain language. This
means that each rule we publish must:
(1) Be logically organized;
(2) Use the active voice to address readers directly;
(3) Use clear language rather than jargon;
(4) Be divided into short sections and sentences; and
(5) Use lists and tables wherever possible.
If you feel that we have not met these requirements, send us
comments by one of the methods listed in the ADDRESSES section. To
better help us revise the rule, your comments should be as specific as
possible. For example, you should tell us the numbers of the sections
or paragraphs that you find unclear, which sections or sentences are
too long, the sections where you feel lists or tables would be useful,
etc.
Public Availability of Comments
Before including your address, phone number, email address, or
other personal identifying information in your comment, you should be
aware that your entire comment--including your personal identifying
information--may be made publicly available at any time. In order for
BSEE to withhold from disclosure your personal identifying information,
you must identify any information contained in the submittal of your
comments that, if released, would constitute a clearly unwarranted
invasion of your personal privacy. You must also briefly describe any
possible harmful consequence(s) of the disclosure of information, such
as embarrassment, injury, or other harm. While you can ask us in your
comment to withhold your personal identifying information from public
review, we cannot guarantee that we will be able to do so.
Severability
If a court holds any provisions of a subsequent final rule or their
applicability to any persons or circumstances invalid, the remainder of
the provisions and their applicability to other people or circumstances
will not be affected.
List of Subjects in 30 CFR Part 250
Administrative practice and procedure, Continental shelf,
Environmental impact statements, Environmental protection,
Incorporation by reference, Oil and gas exploration, Outer Continental
Shelf--mineral resources, Outer Continental Shelf--rights-of-way,
Penalties, Reporting and recordkeeping requirements, Sulfur.
Joseph R. Balash,
Assistant Secretary--Land and Minerals Management, U.S. Department of
the Interior.
For the reasons stated in the preamble, the Bureau of Safety and
Environmental Enforcement (BSEE) proposes to amend 30 CFR part 250 as
follows:
PART 250--OIL AND GAS AND SULFUR OPERATIONS IN THE OUTER
CONTINENTAL SHELF
0
1. The authority citation for part 250 continues to read as follows:
Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, 33 U.S.C.
1321(j)(1)(C), 43 U.S.C. 1334.
Subpart A--General
0
2. Amend Sec. 250.198 by revising paragraphs (h)(63), (h)(78), and
(h)(94), and adding new paragraph (m)(2), to read as follows:
250.198 Documents incorporated by reference.
* * * * *
(h) * * *
(63) API Standard 53, Blowout Prevention Equipment Systems for
Drilling Wells, Fourth Edition, November 2012, incorporated by
reference at Sec. Sec. 250.730, 250.734, 250.735, 250.737, and
250.739;
* * * * *
(78) API Standard 65--Part 2, Isolating Potential Flow Zones During
Well Construction; Second Edition, December 2010; incorporated by
reference at Sec. Sec. 250.415(f) and 250.420(a)(6);
* * * * *
(94) API Recommended Practice 17H, Remotely Operated Tool and
Interfaces on Subsea Production Systems, Second Edition, June 2013,
Errata January 2014, incorporated by reference at Sec. 250.734(a)(4);
* * * * *
(m) * * *
(2) ISO/IEC 17021-1--Conformity assessment--Requirements for bodies
providing audit and certification of management systems--Part 1, First
Edition, June 2015, incorporated by reference at Sec. 250.730(d).
* * * * *
Subpart B--Plans and Information
0
3. Amend Sec. 250.292 by revising paragraph (p) to read as follows:
Sec. 250.292 What must the DWOP contain?
* * * * *
(p) If you propose to use a pipeline free standing hybrid riser
(FSHR) on a permanent installation that utilizes a buoyancy air can
suspended from the top of the riser, you must provide the following
information in your DWOP in the discussions required by paragraphs (f)
and (g) of this section:
(1) A detailed description and drawings of the FSHR, buoy, and the
associated connection system;
(2) Detailed information regarding the system used to connect the
FSHR to the buoyancy air can, and associated redundancies; and
(3) Descriptions of your monitoring system and monitoring plan to
monitor the pipeline FSHR and the associated connection system for
fatigue, stress, and any other abnormal condition (e.g., corrosion)
that may negatively impact the riser system's integrity.
* * * * *
Subpart D--Oil and Gas Drilling Operations
0
4. Amend Sec. 250.413 by revising paragraph (g) to read as follows:
Sec. 250.413 What must my description of well drilling design
criteria address?
* * * * *
(g) A single plot containing curves for estimated pore pressures,
formation fracture gradients, proposed drilling fluid weights (surface
and downhole), planned safe drilling margin, and casing setting depths
in true vertical measurements;
* * * * *
0
5. Amend Sec. 250.414 by revising paragraph (c)(3) to read as follows:
Sec. 250.414 What must my drilling prognosis include?
* * * * *
(c) * * *
(3) When determining the pore pressure and lowest estimated
fracture gradient for a specific interval, you must consider related
off-set and analogous well behavior observations, if available.
* * * * *
0
6. Amend Sec. 250.420 by revising paragraph (a)(6) to read as follows:
Sec. 250.420 What well casing and cementing requirements must I
meet?
* * * * *
(a) * * *
(6) Provide adequate centralization consistent with the guidelines
of API Standard 65--Part 2 (as incorporated by reference in Sec.
250.198); and
* * * * *
0
7. Amend Sec. 250.421 by revising paragraphs (c), (d), (e), and (f) to
read as follows:
[[Page 22149]]
Sec. 250.421 What are the casing and cementing requirements by type
of casing string?
* * * * *
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0
8. Amend Sec. 250.423 by revising paragraphs (a) and (b) to read as
follows:
Sec. 250.423 What are the requirements for casing and liner
installation?
* * * * *
(a) You must ensure that the latching mechanisms or lock down
mechanisms are engaged upon successfully installing the casing string.
If there is an indication of an inadequate cement job, you must comply
with Sec. 250.428(c).
(b) If you run a liner that has a latching mechanism or lock down
mechanism, you must ensure that the latching mechanisms or lock down
mechanisms are engaged upon successfully installing the liner. If there
is an indication of an inadequate cement job, you must comply with
Sec. 250.428(c).
* * * * *
0
9. Amend Sec. 250.428 by revising paragraphs (c) and (d) to read as
follows:
Sec. 250.428 What must I do in certain cementing and casing
situations?
* * * * *
[[Page 22150]]
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BILLING CODE 4310-VH-C
0
10. Amend Sec. 250.433 by revising paragraph (b) to read as follows:
Sec. 250.433 What are the diverter actuation and testing
requirements?
* * * * *
(b) For floating drilling operations with a subsea BOP stack, you
must actuate the diverter system within 7 days after the previous
actuation. For subsequent testing, you may partially actuate the
diverter element and a flow test is not required.
* * * * *
0
11. Amend Sec. 250.461 by revising paragraph (b) to read as follows:
Sec. 250.461 What are the requirements for directional and
inclination surveys?
* * * * *
(b) Survey requirements for directional well. You must conduct
directional surveys on each directional well and digitally record the
results. Surveys must give both inclination and azimuth at intervals
not to exceed 500 feet during the normal course of drilling. Intervals
during angle-changing portions of the hole may not exceed 180 feet.
* * * * *
0
12. Amend Sec. 250.462 by revising paragraphs (b) introductory text,
(e)(1)(ii), (e)(3), and (e)(4) to read as follows:
Sec. 250.462 What are the source control, containment, and
collocated equipment requirements?
* * * * *
(b) You must have access to and the ability to deploy Source
Control and Containment Equipment (SCCE) and all other necessary
supporting and collocated equipment to regain control of the well. SCCE
means the capping stack, cap-and-flow system, containment dome, and/or
other subsea and surface devices, equipment, and vessels, which have
the collective purpose to control a spill source and stop the flow of
fluids into the environment or to contain fluids escaping into the
environment based on the determinations outlined in paragraph (a) of
this section. This SCCE, supporting equipment, and collocated equipment
may include, but is not limited to, the following:
* * * * *
(e) * * *
[[Page 22151]]
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Subpart E--Oil and Gas Well-Completion Operations
0
13. Amend Sec. 250.518 by revising paragraph (e)(1) to read as
follows:
Sec. 250.518 Tubing and wellhead equipment.
* * * * *
(e) * * *
(1) All permanently installed packers and bridge plugs qualified as
mechanical barriers must comply with ANSI/API Spec. 11D1 (as
incorporated by reference in Sec. 250.198);
* * * * *
0
14. Revise Sec. 250.519 to read as follows:
Sec. 250.519 What are the requirements for casing pressure
management?
Once you install your wellhead, you must meet the casing pressure
management requirements of API RP 90 (as incorporated by reference in
Sec. 250.198) and the requirements of Sec. Sec. 250.519 through
250.531. If there is a conflict between API RP 90 and the casing
pressure requirements of this subpart, you must follow the requirements
of this subpart.
0
15. Revise Sec. 250.522 to read as follows:
Sec. 250.522 How do I manage the thermal effects caused by initial
production on a newly completed or recompleted well?
A newly completed or recompleted well often has thermal casing
pressure during initial startup. Bleeding casing pressure during the
startup process is considered a normal and necessary operation to
manage thermal casing pressure; therefore, you do not need to evaluate
these operations as a casing diagnostic test. After 30 days of
continuous production, the initial production startup operation is
complete and you must perform casing diagnostic testing as required in
Sec. Sec. 250.521 and 250.523.
0
16. Amend Sec. 250.525 by revising paragraph (d) to read as follows:
Sec. 250.525 When am I required to take action from my casing
diagnostic test?
* * * * *
(d) Any well that has sustained casing pressure (SCP) and is bled
down to prevent it from exceeding its MAWOP, except during initial
startup operations described in Sec. 250.522;
* * * * *
0
17. Revise Sec. 250.526 to read as follows:
Sec. 250.526 What do I submit if my casing diagnostic test requires
action?
Within 14 days after you perform a casing diagnostic test requiring
action under Sec. 250.525:
[GRAPHIC] [TIFF OMITTED] TP11MY18.013
[[Page 22152]]
0
18. Amend Sec. 250.530 by revising paragraph (b) to read as follows:
Sec. 250.530 What if my casing pressure request is denied?
* * * * *
(b) You must submit the casing diagnostic test data to the
appropriate Regional Supervisor, Field Operations, within 14 days of
completion of the diagnostic test required under Sec. 250.523(e).
Subpart F--Oil and Gas Well-Workover Operations
0
19. Amend Sec. 250.601 by adding paragraph (m) to the definition of
``routine operations'' to read as follows:
Sec. 250.601 Definitions.
* * * * *
(m) Acid treatments
* * * * *
0
20. Remove and reserve Sec. 250.616.
Sec. 250.616 [Reserved]
0
21. Amend Sec. 250.619 by revising paragraph (e)(1) to read as
follows:
Sec. 250.619 Tubing and wellhead equipment.
* * * * *
(e) * * *
(1) All permanently installed packers and bridge plugs qualified as
mechanical barriers must comply with ANSI/API Spec. 11D1 (as
incorporated by reference in Sec. 250.198). You must have two
independent barriers, one being mechanical, in the exposed center
wellbore prior to removing the tree and/or well control equipment;
* * * * *
Subpart G--Well Operations and Equipment
0
22. Amend Sec. 250.712 by adding paragraphs (g) and (h) to read as
follows:
Sec. 250.712 What rig unit movements must I report?
* * * * *
(g) You are not required to report rig unit movements to and from
the safe zone during the course of permitted operations.
(h) If a rig unit is already on a well, you are not required to
report any additional rig unit movements on that well.
0
23. Amend Sec. 250.720 by revising paragraph (a)(1) and adding
paragraphs (a)(3) and (d) to read as follows:
Sec. 250.720 When and how must I secure a well?
(a) * * *
(1) The events that would cause you to interrupt operations and
notify the District Manager include, but are not limited to, the
following:
(i) Evacuation of the rig crew;
(ii) Inability to keep the rig on location;
(iii) Repair to major rig or well-control equipment;
(iv) Observed flow outside the well's casing (e.g., shallow water
flow or bubbling); or
(v) Impending National Weather Service-named tropical storm or
hurricane.
* * * * *
(3) If you unlatch the BOP or LMRP:
(i) Upon relatch of the BOP, you must test according to Sec.
250.734(b)(2), or
(ii) Upon relatch of the LMRP, you must test according to Sec.
250.734(b)(3); and
(iii) You must receive District Manager approval before resuming
operations.
* * * * *
(d) For subsea completed wells with a tree installed, you must have
the equipment and capabilities for intervention on those wells. All
equipment utilized solely for intervention operations (e.g., tree
interface tools) must be readily available, maintained in accordance
with OEM recommendations, and available for inspection by BSEE upon
request.
0
24. Amend Sec. 250.722 by revising paragraph (a)(2) to read as
follows:
Sec. 250.722 What are the requirements for prolonged operations in a
well?
* * * * *
(a) * * *
(2) Report the results of your evaluation to the District Manager
and obtain approval of those results before resuming operations. Your
report must include calculations that indicate the well's integrity is
above the minimum safety factors, if an imaging tool or caliper is
used. District Manager approval is not required to resume operations if
you conducted a successful pressure test as approved in your permit.
You must document the successful pressure test in the WAR.
* * * * *
0
25. Amend Sec. 250.723 by revising the introductory text and paragraph
(c)(3) to read as follows:
Sec. 250.723 What additional safety measures must I take when I
conduct operations on a platform that has producing wells or has other
hydrocarbon flow?
You must take the following safety measures when you conduct
operations with a rig unit on or jacked-up over a platform with
producing wells or that has other hydrocarbon flow:
* * * * *
(c) * * *
(3) A MODU moves within 500 feet of a platform. You may resume
production once the MODU is in place, secured, and ready to begin
operations.
* * * * *
0
26. Revise Sec. 250.724 to read as follows:
Sec. 250.724 What are the real-time monitoring requirements?
(a) No later than April 29, 2019, when conducting well operations
with a subsea BOP or with a surface BOP on a floating facility, or when
operating in an high pressure high temperature (HPHT) environment, you
must gather and monitor real-time well data using an independent,
automatic, and continuous monitoring system capable of recording,
storing, and transmitting data regarding the following:
(1) The BOP control system;
(2) The well's fluid handling system on the rig; and
(3) The well's downhole conditions with the bottom hole assembly
tools (if any tools are installed).
(b) You must develop and implement a real-time monitoring plan.
Your real-time monitoring plan, and all real-time monitoring data, must
be made available to BSEE upon request. Your real-time monitoring plan
must include the following:
(1) A description of your real-time monitoring capabilities,
including the types of the data collected;
(2) A description of how your real-time monitoring data will be
transmitted during operations, how the data will be labeled and
monitored by qualified personnel, and how the data will be stored as
required in Sec. Sec. 250.740 and 250.741;
(3) A description of your procedures for providing BSEE access,
upon request, to your real-time monitoring data;
(4) The qualifications of the personnel monitoring the data;
(5) Your procedures for, and methods of, communication between rig
personnel and the monitoring personnel; and
(6) Actions to be taken if you lose any real-time monitoring
capabilities or communications between rig personnel and monitoring
personnel, and a protocol for how you will respond to any significant
and/or prolonged interruption of monitoring capabilities or
communications, including your protocol for notifying BSEE of any
significant and/or prolonged interruptions.
0
27. Revise Sec. 250.730 to read as follows:
[[Page 22153]]
Sec. 250.730 What are the general requirements for BOP systems and
system components?
(a) You must ensure that the BOP system and system components are
designed, installed, maintained, inspected, tested, and used properly
to ensure well control. The working-pressure rating of each BOP
component (excluding annular(s)) must exceed MASP as defined for the
operation. For a subsea BOP, the MASP must be taken at the mudline. The
BOP system includes the BOP stack, control system, and any other
associated system(s) and equipment. The BOP system and individual
components must be able to perform their expected functions and be
compatible with each other. Your BOP system must be capable of closing
and sealing the wellbore in the event of flow due to a kick, including
under anticipated flowing conditions for the specific well conditions,
without losing ram closure time and sealing integrity due to the
corrosiveness, volume, and abrasiveness of any fluids in the wellbore
that the BOP system may encounter. Your BOP system must meet the
following requirements:
(1) The BOP requirements of API Standard 53 (incorporated by
reference in Sec. 250.198) and the requirements of Sec. Sec. 250.733
through 250.739. If there is a conflict between API Standard 53 and the
requirements of this subpart, you must follow the requirements of this
subpart.
(2) The provisions of the following industry standards (all
incorporated by reference in Sec. 250.198) that apply to BOP systems:
(i) ANSI/API Spec. 6A;
(ii) ANSI/API Spec. 16A;
(iii) ANSI/API Spec. 16C;
(iv) API Spec. 16D; and
(v) ANSI/API Spec. 17D.
(3) For surface and subsea BOPs, the pipe and variable bore rams
installed in the BOP stack must be capable of effectively closing and
sealing on the tubular body of any drill pipe, workstring, and tubing
(excluding tubing with exterior control lines and flat packs) in the
hole under MASP, as defined for the operation, with the proposed
regulator settings of the BOP control system.
(4) The current set of approved schematic drawings must be
available on the rig and at an onshore location. If you make any
modifications to the BOP or control system that will change your BSEE-
approved schematic drawings, you must suspend operations until you
obtain approval from the District Manager.
(b) You must ensure that the design, fabrication, maintenance, and
repair of your BOP system is in accordance with the requirements
contained in this part, applicable Original Equipment Manufacturers
(OEM) recommendations unless otherwise directed by BSEE, and recognized
engineering practices. The training and qualification of repair and
maintenance personnel must meet or exceed applicable OEM training
recommendations unless otherwise directed by BSEE.
(c) You must follow the failure reporting procedures contained in
API Standard 53, (incorporated by reference in Sec. 250.198), and:
(1) You must provide a written notice of equipment failure to BSEE,
unless BSEE has designated a third party as provided in paragraph (d)
of this section, and the manufacturer of such equipment within 30 days
after the discovery and identification of the failure. A failure is any
condition that prevents the equipment from meeting the functional
specification.
(2) You must ensure that an investigation and a failure analysis
are started within 120 days of the failure to determine the cause of
the failure, and are completed within 120 days upon starting the
investigation and failure analysis. You must also ensure that the
results and any corrective action are documented. You must ensure that
the analysis report is submitted to BSEE, unless BSEE has designated a
third party as provided in paragraph (c)(4) of this section, as well as
the manufacturer.
(3) If the equipment manufacturer notifies you that it has changed
the design of the equipment that failed or if you have changed
operating or repair procedures as a result of a failure, then you must,
within 30 days of such changes, report the design change or modified
procedures in writing to BSEE, unless BSEE has designated a third party
as provided in paragraph (c)(4) of this section.
(4) BSEE may designate a third party to receive the data and
reports on behalf of BSEE. If BSEE designates a third party, you must
submit the data and reports to the designated third party.
(d) If you plan to use a BOP stack manufactured after the effective
date of this regulation, you must use one manufactured pursuant to an
ANSI/API Spec. Q1 (as incorporated by reference in Sec. 250.198)
quality management system. Such quality management system must be
certified by an entity that meets the requirements of ISO/IEC 17021-1
(as incorporated by reference in Sec. 250.198).
(1) BSEE may consider accepting equipment manufactured under
quality assurance programs other than ANSI/API Spec. Q1, provided you
submit a request to the Chief, Office of Offshore Regulatory Programs
for approval, containing relevant information about the alternative
program.
(2) You must submit this request to the Chief, Office of Offshore
Regulatory Programs; Bureau of Safety and Environmental Enforcement;
45600 Woodland Road, Sterling, Virginia 20166.
0
28. Amend Sec. 250.731 by:
0
a. Removing paragraphs (d) and (f);
0
b. Redesignating existing paragraph (e) as (d); and
0
c. Revising paragraphs (a)(5) and (c) to read as follows:
Sec. 250.731 What information must I submit for BOP systems and
system components?
* * * * *
BILLING CODE 4310-VH-P
[[Page 22154]]
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0
29. Revise Sec. 250.732 and the section heading to read as follows:
Sec. 250.732 What are the independent third party requirements for
BOP systems and system components?
(a) Prior to beginning any operation requiring the use of any BOP,
you must submit verification by an independent third party and
supporting documentation as required by this paragraph to the
appropriate District Manager and Regional Supervisor.
[GRAPHIC] [TIFF OMITTED] TP11MY18.015
(b) The independent third-party must be a technical classification
society, or a licensed professional engineering firm, or a registered
professional engineer capable of providing the required certifications
and verifications.
[[Page 22155]]
(c) For wells in an HPHT environment, as defined by Sec.
250.804(b), you must submit verification by an independent third party
that the independent third party conducted a comprehensive review of
the BOP system and related equipment you propose to use. You must
provide the independent third party access to any facility associated
with the BOP system or related equipment during the review process. You
must submit the verifications required by this paragraph (c) to the
appropriate District Manager and Regional Supervisor before you begin
any operations in an HPHT environment with the proposed equipment.
[GRAPHIC] [TIFF OMITTED] TP11MY18.016
(d) You must make all documentation that supports the requirements
of this section available to BSEE upon request.
0
30. Amend Sec. 250.733 by:
0
a. Revising paragraphs (a)(1) and (b)(1); and
0
b. Adding paragraph (e) to read as follows:
Sec. 250.733 What are the requirements for a surface BOP stack?
(a) * * *
(1) The blind shear rams must be capable of shearing at any point
along the tubular body of any drill pipe (excluding tool joints,
bottom-hole tools, and bottom hole assemblies that include heavy-weight
pipe or collars), workstring, tubing and associated exterior control
lines, and any electric-wire-, and slick-line that is in the hole and
sealing the wellbore after shearing.
* * * * *
(b) * * *
(1) For BOPs installed after April 29, 2021, follow the BOP
requirements in Sec. 250.734(a)(1).
* * * * *
(e) Additional requirements for surface BOP systems used in well-
completion, workover, and decommissioning operations.
The minimum BOP system for well-completion, workover, and
decommissioning operations must meet the appropriate standards from the
following table:
[[Page 22156]]
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0
31. Amend Sec. 250.734 by:
0
a. Removing paragraphs (a)(6)(v) and (vi); and
0
b. Revising paragraphs (a)(1)(ii), (a)(3), (a)(4), (a)(6)(iv), (a)(16),
and (b) to read as follows:
Sec. 250.734 What are the requirements for a subsea BOP system?
(a) * * *
[[Page 22157]]
[GRAPHIC] [TIFF OMITTED] TP11MY18.018
(b) If you suspend operations to make repairs to any part of the
subsea BOP system, you must stop operations at a safe downhole
location. Before resuming operations you must:
(1) Submit a revised permit with a verification report from an
independent third party documenting the repairs and that the BOP is fit
for service;
(2) Upon relatch of the BOP, perform an initial subsea BOP test in
accordance with Sec. 250.737(d)(4), including deadman in accordance
with Sec. 250.737(d)(12)(vi). If repairs take longer than 30 days,
once the BOP is on deck, you must test in accordance with the
requirements of Sec. 250.737;
(3) Upon relatch of the LMRP, you must test according to the
following:
(i) Pressure test riser connector/gasket in accordance with Sec.
250.737(b) and (c);
(ii) Pressure test choke and kill stabs at LMRP/BOP interface in
accordance with Sec. 250.737(b) and (c);
(iii) Full function test of both pods and both control panels;
(iv) Verify acoustic pod communication (if equipped); and
(v) Deadman test with pressure test in accordance with Sec.
250.737(d)(12)(vi).
(4) Receive approval from the District Manager.
* * * * *
0
32. Amend Sec. 250.735 by revising paragraph (a) to read as follows:
Sec. 250.735 What associated systems and related equipment must all
BOP systems include?
* * * * *
(a) An accumulator system (as specified in API Standard 53, and
incorporated by reference in Sec. 250.198). Your accumulator system
must have the fluid volume capacity and appropriate pre-charge
pressures in accordance with API Standard 53. If you supply the
accumulator regulators by rig air and do not have a secondary source of
pneumatic supply, you must equip the regulators with manual overrides
or other devices to ensure capability of hydraulic operations if rig
air is lost;
* * * * *
[[Page 22158]]
0
33. Amend Sec. 250.736 by revising paragraph (d)(5) to read as
follows:
Sec. 250.736 What are the requirements for choke manifolds, kelly-
type valves inside BOPs, and drill string safety valves?
* * * * *
(d) * * *
(5) When running casing, a safety valve in the open position
available on the rig floor to fit the casing string being run in the
hole. For subsea BOPs, the safety valve must be available on the rig
floor if the length of casing being run exceeds the water depth, which
would result in the casing being across the BOP stack and the rig floor
prior to crossing over to the drill pipe running string;
* * * * *
0
34. Amend Sec. 250.737 by:
0
a. Removing paragraph (d)(4)(vi),
0
b. Adding paragraph (d)(13), and
0
c. Revising paragraphs (b) introductory text, (b)(2), (d)(2)(ii),
(d)(3)(iii), (d)(3)(iv), (d)(3)(v), (d)(4)(i), (d)(4)(iii), (d)(4)(v),
(d)(5), (d)(12)(iv) and (d)(12)(vi) to read as follows:
Sec. 250.737 What are the BOP system testing requirements?
* * * * *
(b) Pressure test procedures. When you pressure test the BOP
system, you must conduct a low-pressure test and a high-pressure test
for each BOP component (excluding test rams and non-sealing shear
rams). You must begin each test by conducting the low-pressure test
then transition to the high-pressure test. Each individual pressure
test must hold pressure long enough to demonstrate the tested
component(s) holds the required pressure. The table in this paragraph
(b) outlines your pressure test requirements.
[GRAPHIC] [TIFF OMITTED] TP11MY18.019
* * * * *
(d) * * *
[[Page 22159]]
[GRAPHIC] [TIFF OMITTED] TP11MY18.020
* * * * *
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35. Amend Sec. 250.738 by revising paragraphs (b)(4), (f), (i), (m),
and (o) to read as follows:
Sec. 250.738 What must I do in certain situations involving BOP
equipment or systems?
* * * * *
[[Page 22160]]
[GRAPHIC] [TIFF OMITTED] TP11MY18.021
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36. Amend Sec. 250.739 by revising paragraph (b) introductory text to
read as follows:
Sec. 250.739 What are the BOP maintenance and inspection
requirements?
* * * * *
(b) A major, detailed inspection of the well control system
components (including but not limited to riser, BOP, LMRP, and control
pods) must be performed every 5 years. This major inspection may be
performed in phased intervals. You must track and document all system
and component inspection dates. These records must be available on the
rig. An independent third party is required to review the inspection
results and must compile a detailed report of the inspection results,
including descriptions of any problems and how they were corrected. You
must make these reports available to BSEE upon request. This major
inspection must be performed every 5 years from the following
applicable dates, whichever is later:
* * * * *
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37. Add Sec. 250.750 and undesignated center heading to read as
follows:
Coiled Tubing and Snubbing Operations
Sec. 250.750 What are the coiled tubing and snubbing requirements?
(a) For coiled tubing operations with the production tree in place,
you must meet the following minimum requirements for the BOP system:
(1) BOP system components must be in the following order from the
top down:
[[Page 22161]]
[GRAPHIC] [TIFF OMITTED] TP11MY18.022
(2) You may use a set of hydraulically-operated combination rams
for the blind rams and shear rams.
(3) You may use a set of hydraulically-operated combination rams
for the hydraulic two-way slip rams and the hydraulically-operated pipe
rams.
(4) You must attach a dual check valve assembly to the coiled
tubing connector at the downhole end of the coiled tubing string for
all coiled tubing operations. If you plan to conduct operations without
downhole check valves, you must describe alternate procedures and
equipment in Form BSEE-0124, Application for Permit to Modify and have
it approved by the District Manager.
(5) You must have a kill line and a separate choke line. You must
equip each line with two full-opening valves and at least one of the
valves must be remotely controlled. You may use a manual valve instead
of the remotely controlled valve on the kill line if you install a
check valve between the two full-opening manual valves and the pump or
manifold. The valves must have a working pressure rating equal to or
greater than the working pressure rating of the connection to which
they are attached, and you must install them between the well control
stack and the choke or kill line. For operations with expected surface
pressures greater than 3,500 psi, the kill line must be connected to a
pump or manifold. You must not use the kill line inlet on the BOP stack
for taking fluid returns from the wellbore.
(6) You must have a hydraulic-actuating system that provides
sufficient accumulator capacity to close-open-close each component in
the BOP stack. This cycle must be completed with at least 200 psi above
the pre-charge pressure, without assistance from a charging system.
(7) All connections used in the surface BOP system from the tree to
the uppermost required ram must be flanged, including the connections
between the well control stack and the first full-opening valve on the
choke line and the kill line.
(b) The minimum BOP-system components for operations with the tree
in place and performed by moving tubing or drill pipe in or out of a
well under pressure utilizing equipment specifically designed for that
purpose, i.e., snubbing operations, shall include the following:
(1) One set of pipe rams hydraulically operated, and
(2) Two sets of stripper-type pipe rams hydraulically operated with
spacer spool.
(c) An inside BOP or a spring-loaded, back-pressure safety valve
and an essentially full-opening, work-string safety valve in the open
position must be maintained on the rig floor at all times during
operations when the tree is removed or during operations with the tree
installed and using small tubing as the work string. A wrench to fit
the work-string safety valve must be readily available. Proper
connections must be readily available for inserting valves in the work
string. The full-opening safety valve is not required for coiled tubing
or snubbing operations.
(d) Test the snubbing unit in accordance with Sec. 250.737(a),
(b), and (c).
0
38. Add Sec. 250.751 to read as follows:
Sec. 250.751 Coiled tubing testing requirements.
Coiled tubing tests. You must test the coiled tubing unit in
accordance with Sec. 250.737(a), (b), (c), (d)(9), and (d)(10). You
must successfully pressure test the dual check valves to the rated
working pressure of the connector, the rated working pressure of the
dual check valve, expected surface pressure, or the collapse pressure
of the coiled tubing, whichever is less. The test interval for coiled
tubing operations must include a 10 minute high-pressure test for the
coiled tubing string.
[[Page 22162]]
Subpart Q--Decommissioning Activities
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39. Amend Sec. 250.1703 by revising paragraph (b) to read as follows:
Sec. 250.1703 What are the general requirements for decommissioning?
* * * * *
(b) Permanently plug all wells. Packers and bridge plugs used as
qualified mechanical barriers must comply with ANSI/API Spec. 11D1 (as
incorporated by reference in Sec. 250.198). You must have two
independent barriers, one being mechanical, in the exposed center
wellbore prior to removing the tree and/or well control equipment;
* * * * *
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40. Amend Sec. 250.1704 by adding paragraph (g)(4) and revising
paragraph (h)(2) to read as follows:
Sec. 250.1704 What decommissioning applications and reports must I
submit and when must I submit them?
* * * * *
[GRAPHIC] [TIFF OMITTED] TP11MY18.023
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41. Remove and reserve Sec. 250.1706:
Sec. 250.1706 [Reserved]
0
42. Remove and reserve Sec. 250.1713:
Sec. 250.1713 [Reserved]
0
43. Amend Sec. 250.1716 by revising paragraph (b)(3) to read as
follows:
Sec. 250.1716 To what depth must I remove wellheads and casings?
* * * * *
(b) * * *
(3) The water depth is greater than 1,000 feet.
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44. Amend Sec. 250.1722 by revising paragraph (d) introductory text to
read as follows:
Sec. 250.1722 If I install a subsea protective device, what
requirements must I meet?
* * * * *
(d) Within 30 days after you complete the trawling test described
in paragraph (c) of this section, submit a report to the appropriate
District Manager using form BSEE-0125, End of Operations Report (EOR)
that includes the following:
* * * * *
[FR Doc. 2018-09305 Filed 5-10-18; 8:45 am]
BILLING CODE 4310-VH-C