1014-AA39 Well Control Revisions - Proposed Rule published

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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
Bureau of Safety and
Environmental Enforcement, Interior.
ACTION: Proposed rule.
AGENCY:

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, realtime 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)

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SUMMARY:

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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-safetydocuments.
• 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: oira_submission@
omb.eop.gov. Please send a copy to
BSEE.
Public Availability of Comments—
Before including your address, phone
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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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: OMM_
[email protected]; for procedural
questions contact Kirk Malstrom,
Regulations and Standards Branch,
(202) 258–1518, or by email: regs@
bsee.gov.
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

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Federal Register / Vol. 83, No. 92 / Friday, May 11, 2018 / Proposed Rules
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.

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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

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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.
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
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
§ 250.105. For convenience, this preamble will refer
to all of the regulated entities as ‘‘operators’’ unless
otherwise indicated.

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Federal Register / Vol. 83, No. 92 / Friday, May 11, 2018 / Proposed Rules

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 wellcontrol 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

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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

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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-safetydocuments.
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
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.

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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
§ 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
§ 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

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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-andregulations/regulations/well-controlrule. 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-andregulations/regulations/well-controlrule/public%20forum.

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II. Section-by-Section Discussion of
Proposed Changes
BSEE is proposing to revise the
following regulations:
Subpart A—General
Documents Incorporated by Reference
(§ 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

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reference to § 250.734. The changes to
this paragraph are administrative and
merely reflect substantive changes made
to § 250.734, addressed further at the
corresponding location in the sectionby-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 § 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
§ 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
§ 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 § 250.730(d) and
the associated section-by-section
discussion.
Subpart B—Plans and Information
What must the DWOP contain?
(§ 250.292)
This rulemaking would revise
paragraph (p) by clarifying the free
standing hybrid riser (FSHR)

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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
§ 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
§ 250.910(b), and in §§ 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 § 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 § 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 § 250.911, in
connection with the PVP.
Subpart D—Oil and Gas Drilling
Operations
What must my description of well
drilling design criteria address?
(§ 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? (§ 250.414)
This proposed rule would revise
paragraph (c)(3) of this section to add

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Federal Register / Vol. 83, No. 92 / Friday, May 11, 2018 / Proposed Rules
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

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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.

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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 § 250.414(c) and its replacement
with a more performance based, caseby-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

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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 § 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? (§ 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

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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?
(§ 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? (§ 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 caseby-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? (§ 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

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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 § 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

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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.

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 diverter actuation and
testing requirements? (§ 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.

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 § 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 wellspecific 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 § 250.732(b).
For a discussion on the changes from a
BAVO to an independent third party,
see the section-by-section discussion of
§ 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.

What are the requirements for
directional and inclination surveys?
(§ 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

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What are the source control,
containment, and collocated equipment
requirements? (§ 250.462)

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Subpart E—Oil and Gas WellCompletion Operations
Tubing and Wellhead Equipment
(§ 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? (§ 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?
(§ 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? (§ 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?
(§ 250.526)
BSEE would make minimal revisions
to this section to update incorrect
citations. These revisions are

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administrative in nature and ensure that
the appropriate citations are correctly
cross referenced.
What if my casing pressure request is
denied? (§ 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 (§ 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
§ 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.

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Coiled tubing and snubbing operations
(§ 250.616)
This section would be removed and
reserved. The content of this section
would be moved to proposed § 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
(§ 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
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Subpart F requirements about
mechanical barriers similar to those
already found in § 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?
(§ 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?
(§ 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 § 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

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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 treespecific 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?
(§ 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

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be notified of the test results through the
reporting requirements of the WAR.

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What additional safety measures must
I take when I conduct operations on a
platform that has producing wells or
has other hydrocarbon flow? (§ 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? (§ 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

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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?
(§ 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-andregulations/regulations/well-controlrule. 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

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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-andregulations/regulations/well-controlrule.
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

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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.
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

sradovich on DSK3GMQ082PROD with PROPOSALS2

What information must I submit for
BOP systems and system components?
(§ 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 § 250.732(d) (see
section-by-section discussion of that
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).

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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 § 250.732(b). For a
discussion of the proposed shift from
BAVOs to independent third parties, see
the section-by-section discussion of
§ 250.732.
What are the independent third party
requirements for BOP systems and
system components? (§ 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-bysection 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

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(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
§ 250.734(a)(16) that is the subject of
this verification (see section-by-section
discussion of § 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
§ 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 § 250.804(b) rather than
§ 250.807(b), as stated in the current
regulations. This revision is
administrative in nature and ensures

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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
§ 250.731. The independent third party
verifications in § 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? (§ 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

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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 wellcompletion, 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 §§ 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 crossreferenced 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? (§ 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 § 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

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(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

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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

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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 § 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

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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 § 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
§ 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

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properly functional prior to resuming
operations after being removed.
What associated systems and related
equipment must all BOP systems
include? (§ 250.735)
This proposed rule would revise
paragraph (a) by clarifying that the
accumulator system must have the fluid
volume capacity and appropriate precharge 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 § 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.

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What are the requirements for choke
manifolds, kelly-type valves inside
BOPs, and drill string safety valves?
(§ 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? (§ 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

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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 §§ 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

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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,

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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?
(§ 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

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section-by-section discussion of
§ 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? (§ 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 § 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

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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 § 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? (§ 250.750)
The content of this proposed section
was moved from current §§ 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
(§ 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
§§ 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 § 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 § 250.737.
Subpart Q—Decommissioning
Activities
What are the general requirements for
decommissioning? (§ 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 §§ 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? (§ 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.

sradovich on DSK3GMQ082PROD with PROPOSALS2

Coiled Tubing and Snubbing
Operations (§ 250.1706)
This section would be removed and
reserved. The content of this section
would be moved to proposed § 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

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drilling, completions, workovers, and
decommissioning operations.
Must I notify BSEE before I begin well
plugging operations? (§ 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 § 250.712.
To what depth must I remove
wellheads and casings? (§ 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?
(§ 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

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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 performancebased 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:

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(1.) Underestimating the cost for
revising permits or reporting certain
operations to the District Manager
(§§ 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 (§ 250.734).
The proposed revisions to existing
ram and accumulator requirements for
subsea BOPs (§ 250.734) represent the
single largest cost savings provision in
this proposed rule, yielding cost savings
of $690 million (nominal$). The
proposed changes to § 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 § 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

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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 § 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 § 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 pre1014–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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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

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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

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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 §§ 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 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.

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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).

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.

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.

Takings Implication Assessment (E.O.
12630)

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
§ 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.

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

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

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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)

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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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Federal Register / Vol. 83, No. 92 / Friday, May 11, 2018 / Proposed Rules
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).

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The following is a brief explanation of
how the proposed regulatory changes
would affect the various subpart hour
burdens:
• APD—Proposed § 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—§ 250.423 proposes
rewording the requirement in a manner
that would reduce the number of
alternative procedure or equipment
requests under § 250.141. Reductions
will be shown during the renewal
process (see Section by Section
Discussion above).
• Subpart B—§ 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—§ 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:
§ 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).
§ 250.731 would add Independent
Third Party costs, increasing the nonhour cost burdens by $31,000 (see
Section by Section Discussion above).
§ 250.732(a) would add Independent
Third Party costs, increasing the nonhour cost burdens by $765,000 (see
Section by Section Discussion above).
§ 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).
§ 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).
§ 250.751 would be new and proposes
to include the coiled tubing testing and

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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.

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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.

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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—

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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
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
2. Amend § 250.198 by revising
paragraphs (h)(63), (h)(78), and (h)(94),
and adding new paragraph (m)(2), to
read as follows:

■

(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
4. Amend § 250.413 by revising
paragraph (g) to read as follows:

250.198 Documents incorporated by
reference.

■

*

§ 250.413 What must my description of
well drilling design criteria address?

*
*
*
*
(h) * * *
(63) API Standard 53, Blowout
Prevention Equipment Systems for
Drilling Wells, Fourth Edition,
November 2012, incorporated by
reference at §§ 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 §§ 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
§ 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 § 250.730(d).
*
*
*
*
*
Subpart B—Plans and Information
3. Amend § 250.292 by revising
paragraph (p) to read as follows:

■

§ 250.292

*

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What must the DWOP contain?

*

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*

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*

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*

*
*
*
*
(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;
*
*
*
*
*
■ 5. Amend § 250.414 by revising
paragraph (c)(3) to read as follows:
§ 250.414
include?

What must my drilling prognosis

*

*
*
*
*
(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.
*
*
*
*
*
■ 6. Amend § 250.420 by revising
paragraph (a)(6) to read as follows:
§ 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 § 250.198); and
*
*
*
*
*
■ 7. Amend § 250.421 by revising
paragraphs (c), (d), (e), and (f) to read as
follows:

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§ 250.421 What are the casing and
cementing requirements by type of casing
string?

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§ 250.423 What are the requirements for
casing and liner installation?

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(a) You must ensure that the latching
mechanisms or lock down mechanisms
are engaged upon successfully installing

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the casing string. If there is an
indication of an inadequate cement job,
you must comply with § 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

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is an indication of an inadequate cement
job, you must comply with § 250.428(c).
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■ 9. Amend § 250.428 by revising
paragraphs (c) and (d) to read as follows:
§ 250.428 What must I do in certain
cementing and casing situations?

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8. Amend § 250.423 by revising
paragraphs (a) and (b) to read as follows:

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10. Amend § 250.433 by revising
paragraph (b) to read as follows:

■

§ 250.433 What are the diverter actuation
and testing requirements?

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(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.
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■ 11. Amend § 250.461 by revising
paragraph (b) to read as follows:
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(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.
*
*
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*
■ 12. Amend § 250.462 by revising
paragraphs (b) introductory text,
(e)(1)(ii), (e)(3), and (e)(4) to read as
follows:

§ 250.461 What are the requirements for
directional and inclination surveys?

§ 250.462 What are the source control,
containment, and collocated equipment
requirements?

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(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:
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Federal Register / Vol. 83, No. 92 / Friday, May 11, 2018 / Proposed Rules

13. Amend § 250.518 by revising
paragraph (e)(1) to read as follows:

■

§ 250.518

Tubing and wellhead equipment.

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(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 § 250.198);
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■ 14. Revise § 250.519 to read as
follows:
§ 250.519 What are the requirements for
casing pressure management?

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Once you install your wellhead, you
must meet the casing pressure
management requirements of API RP 90
(as incorporated by reference in

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§ 250.198) and the requirements of
§§ 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.
■ 15. Revise § 250.522 to read as
follows:
§ 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

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complete and you must perform casing
diagnostic testing as required in
§§ 250.521 and 250.523.
■ 16. Amend § 250.525 by revising
paragraph (d) to read as follows:
§ 250.525 When am I required to take
action from my casing diagnostic test?

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(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 § 250.522;
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■ 17. Revise § 250.526 to read as
follows:
§ 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 § 250.525:

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18. Amend § 250.530 by revising
paragraph (b) to read as follows:

■

§ 250.530 What if my casing pressure
request is denied?

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(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
§ 250.523(e).
Subpart F—Oil and Gas Well-Workover
Operations
19. Amend § 250.601 by adding
paragraph (m) to the definition of
‘‘routine operations’’ to read as follows:

■

§ 250.601

Definitions.

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(m) Acid treatments
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■ 20. Remove and reserve § 250.616.
§ 250.616

[Reserved]

21. Amend § 250.619 by revising
paragraph (e)(1) to read as follows:

■

§ 250.619

Tubing and wellhead equipment.

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*
(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 § 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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*
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*
Subpart G—Well Operations and
Equipment
22. Amend § 250.712 by adding
paragraphs (g) and (h) to read as follows:

■

§ 250.712
report?

What rig unit movements must I

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(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.
■ 23. Amend § 250.720 by revising
paragraph (a)(1) and adding paragraphs
(a)(3) and (d) to read as follows:
§ 250.720
well?

When and how must I secure a

(a) * * *
(1) The events that would cause you
to interrupt operations and notify the
District Manager include, but are not
limited to, the following:

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(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.
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(3) If you unlatch the BOP or LMRP:
(i) Upon relatch of the BOP, you must
test according to § 250.734(b)(2), or
(ii) Upon relatch of the LMRP, you
must test according to § 250.734(b)(3);
and
(iii) You must receive District
Manager approval before resuming
operations.
*
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*
(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.
■ 24. Amend § 250.722 by revising
paragraph (a)(2) to read as follows:
§ 250.722 What are the requirements for
prolonged operations in a well?

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(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.
*
*
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*
■ 25. Amend § 250.723 by revising the
introductory text and paragraph (c)(3) to
read as follows:
§ 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:
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(c) * * *

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(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.
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■ 26. Revise § 250.724 to read as
follows:
§ 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 realtime 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 realtime 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 §§ 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.
■ 27. Revise § 250.730 to read as
follows:

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Federal Register / Vol. 83, No. 92 / Friday, May 11, 2018 / Proposed Rules
§ 250.730 What are the general
requirements for BOP systems and system
components?

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(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 workingpressure 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 § 250.198) and the requirements of
§§ 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 § 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

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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 § 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.

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(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 § 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 § 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.
■ 28. Amend § 250.731 by:
■ a. Removing paragraphs (d) and (f);
■ b. Redesignating existing paragraph
(e) as (d); and
■ c. Revising paragraphs (a)(5) and (c) to
read as follows:
§ 250.731 What information must I submit
for BOP systems and system components?

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Federal Register / Vol. 83, No. 92 / Friday, May 11, 2018 / Proposed Rules

§ 250.732 What are the independent third
party requirements for BOP systems and
system components?

29. Revise § 250.732 and the section
heading to read as follows:

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■

(b) The independent third-party must
be a technical classification society, or

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(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.

a licensed professional engineering firm,
or a registered professional engineer

capable of providing the required
certifications and verifications.

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(c) For wells in an HPHT
environment, as defined by § 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.

(d) You must make all documentation
that supports the requirements of this
section available to BSEE upon request.
■ 30. Amend § 250.733 by:
■ a. Revising paragraphs (a)(1) and
(b)(1); and
■ b. Adding paragraph (e) to read as
follows:

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 electricwire-, and slick-line that is in the hole
and sealing the wellbore after shearing.
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(b) * * *

(1) For BOPs installed after April 29,
2021, follow the BOP requirements in
§ 250.734(a)(1).
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*
(e) Additional requirements for
surface BOP systems used in wellcompletion, workover, and
decommissioning operations.
The minimum BOP system for wellcompletion, workover, and
decommissioning operations must meet
the appropriate standards from the
following table:

§ 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

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Federal Register / Vol. 83, No. 92 / Friday, May 11, 2018 / Proposed Rules

31. Amend § 250.734 by:
a. Removing paragraphs (a)(6)(v) and
(vi); and

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b. Revising paragraphs (a)(1)(ii), (a)(3),
(a)(4), (a)(6)(iv), (a)(16), and (b) to read
as follows:

■

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§ 250.734 What are the requirements for a
subsea BOP system?

(a) * * *

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(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 § 250.737(d)(4), including
deadman in accordance with
§ 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 § 250.737;

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(3) Upon relatch of the LMRP, you
must test according to the following:
(i) Pressure test riser connector/gasket
in accordance with § 250.737(b) and (c);
(ii) Pressure test choke and kill stabs
at LMRP/BOP interface in accordance
with § 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 § 250.737(d)(12)(vi).
(4) Receive approval from the District
Manager.
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■ 32. Amend § 250.735 by revising
paragraph (a) to read as follows:

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§ 250.735 What associated systems and
related equipment must all BOP systems
include?

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(a) An accumulator system (as
specified in API Standard 53, and
incorporated by reference in § 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;
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33. Amend § 250.736 by revising
paragraph (d)(5) to read as follows:

■

§ 250.736 What are the requirements for
choke manifolds, kelly-type valves inside
BOPs, and drill string safety valves?

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(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

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§ 250.737 What are the BOP system
testing requirements?

*

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(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 lowpressure test then transition to the highpressure 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.

(d) * * *

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stack and the rig floor prior to crossing
over to the drill pipe running string;
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■ 34. Amend § 250.737 by:
■ a. Removing paragraph (d)(4)(vi),
■ b. Adding paragraph (d)(13), and
■ 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:

Federal Register / Vol. 83, No. 92 / Friday, May 11, 2018 / Proposed Rules

You must ...

(2)

***

(3)

***

22159

Additional requirements ...
(ii) Contact the District Manager at least 72 hours prior to beginning the initial test
to allow BSEE representative(s) to witness testing.
(iii) Contact the District Manager at least 72 hours prior to beginning the stump test
to allow BSEE representative(s) to witness testing
(iv) You must verify closure of all ROV intervention functions on your subsea
BOP stack during the stump test.

(v) You must follow paragraphs (b) and (c) of this section. Pressure testing of each
ram and annular component is only required once.
(4)

***

(i) You must begin the initial subsea BOP test on the seafloor within 30 days of the
stump test.

*******
(iii) You must pressure test well-control rams and annulars according to paragraphs
(b) and (c) of this section.

*******

(5) Alternate tests between
control stations

*******
***

(v) You must test and verify closure of at least one set of rams during the initial
subsea test through a ROV hot stab. You must confirm closure of the selected ram
through the ROV hot stab with a 1,000 psi pressure test for 5 minutes.
(i) For two complete BOP control stations you must:
(A) Designate a primary and secondary station;
(B) Alternate testing between the primary and secondary control stations on a
weekly basis; and
(C) For a subsea BOP, develop an alternating testing schedule to ensure the
primary and secondary control stations will function each pod.
(ii) Remote panels where all BOP functions are not included (e.g., life boat panels)
must be function-tested upon the initial BOP tests.
(iv) Following the deadman system test on the seafloor you must document the
final remaining pressure of the subsea accumulator system.

(12)

*******
(vi) You must confirm closure of the BSR(s) with a 1,000 psi pressure test for 5
minutes.

*******

*

According to paragraph (b), except as follows:
(i) For 14 day BOP testing, test the wellbore side of the choke and kill side outlet
valves above the uppermost pipe ram to the approved annular test pressure. Choke
and kill side outlet valves below the uppermost pipe ram must be tested to MASP
plus 500 psi for the applicable hole section.
(ii) For the 30 day BSR testing, test the wellbore side of the choke and kill side
outlet valves between the upper most pipe ram and the upper most ram, to the
casing/liner test pressure or annular test pressure, whichever is greater.
(iii) For BOPs with only one choke and kill side outlet valve, you are only required
to pressure test the choke and kill side outlet valves from the wellbore side.

*
*
*
*
35. Amend § 250.738 by revising
paragraphs (b)(4), (f), (i), (m), and (o) to
read as follows:

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§ 250.738 What must I do in certain
situations involving BOP equipment or
systems?

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(13) Pressure test the choke and
kill side outlet valves

Federal Register / Vol. 83, No. 92 / Friday, May 11, 2018 / Proposed Rules

36. Amend § 250.739 by revising
paragraph (b) introductory text to read
as follows:

■

§ 250.739 What are the BOP maintenance
and inspection requirements?

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*

*
*
*
*
(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

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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 § 250.750 and undesignated
center heading to read as follows:

■

Coiled Tubing and Snubbing
Operations
§ 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:

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(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

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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 hydraulicactuating system that provides sufficient
accumulator capacity to close-openclose 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

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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 § 250.737(a), (b), and
(c).
■ 38. Add § 250.751 to read as follows:
§ 250.751 Coiled tubing testing
requirements.

Coiled tubing tests. You must test the
coiled tubing unit in accordance with
§ 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.

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Subpart Q—Decommissioning
Activities
39. Amend § 250.1703 by revising
paragraph (b) to read as follows:

■

§ 250.1703 What are the general
requirements for decommissioning?

*

*
*
*
*
(b) Permanently plug all wells.
Packers and bridge plugs used as

41. Remove and reserve § 250.1706:

§ 250.1706
■

[Reserved]

42. Remove and reserve § 250.1713:

§ 250.1713

[Reserved]

43. Amend § 250.1716 by revising
paragraph (b)(3) to read as follows:

■

§ 250.1716 To what depth must I remove
wellheads and casings?

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*

*

*

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*

■

(b) * * *
(3) The water depth is greater than
1,000 feet.
■ 44. Amend § 250.1722 by revising
paragraph (d) introductory text to read
as follows:

(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:
*
*
*
*
*

§ 250.1722 If I install a subsea protective
device, what requirements must I meet?

*

*

*

*

*

40. Amend § 250.1704 by adding
paragraph (g)(4) and revising paragraph
(h)(2) to read as follows:

§ 250.1704 What decommissioning
applications and reports must I submit and
when must I submit them?

*

*

*

*

*

[FR Doc. 2018–09305 Filed 5–10–18; 8:45 am]
BILLING CODE 4310–VH–C

*

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■

qualified mechanical barriers must
comply with ANSI/API Spec. 11D1 (as
incorporated by reference in § 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;
*
*
*
*
*