[Federal Register Volume 83, Number 92 (Friday, May 11, 2018)]
[Proposed Rules]
[Pages 22128-22162]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-09305]



[[Page 22127]]

Vol. 83

Friday,

No. 92

May 11, 2018

Part II





Department of the Interior





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Bureau of Safety and Environmental Enforcement





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30 CFR Part 250





Oil and Gas and Sulfur Operations in the Outer Continental Shelf--
Blowout Preventer Systems and Well Control Revisions; Proposed Rule

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

[[Page 22128]]


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DEPARTMENT OF THE INTERIOR

Bureau of Safety and Environmental Enforcement

30 CFR Part 250

[Docket ID: BSEE-2018-0002; 189E1700D2 ET1SF0000.PSB000 EEEE500000]
RIN 1014-AA39


Oil and Gas and Sulfur Operations in the Outer Continental 
Shelf--Blowout Preventer Systems and Well Control Revisions

AGENCY: Bureau of Safety and Environmental Enforcement, Interior.

ACTION: Proposed rule.

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SUMMARY: The Bureau of Safety and Environmental Enforcement (BSEE) is 
proposing to revise existing regulations for well control and blowout 
preventer systems. This proposed rule would revise requirements for 
well design, well control, casing, cementing, real-time monitoring 
(RTM), and subsea containment. These revisions modify regulations 
pertaining to offshore oil and gas drilling, completions, workovers, 
and decommissioning in accordance with Executive and Secretary of the 
Interior's Orders to ensure safety and environmental protection, while 
correcting errors and reducing certain unnecessary regulatory burdens 
imposed under the existing regulations. Accordingly, after thoroughly 
reexamining the original Blowout Preventer Systems and Well Control 
final rule (WCR), experiences from the implementation process, and BSEE 
policy, BSEE proposes to amend, revise, or remove current regulatory 
provisions that create unnecessary burdens on stakeholders while 
ensuring safety and environmental protection. The proposed regulations 
would also address various issues and errors that were identified 
during the implementation of the recent rulemaking on these issues.

DATES: Submit comments by July 10, 2018. BSEE may not fully consider 
comments received after this date. You may submit comments to the 
Office of Management and Budget (OMB) on the information collection 
burden in this proposed rule by June 11, 2018. The deadline for 
comments on the information collection burden does not affect the 
deadline for the public to comment to BSEE on the proposed regulations.

ADDRESSES: You may submit comments on the rulemaking by any of the 
following methods. Please use the Regulation Identifier Number (RIN) 
1014-AA39 as an identifier in your message. See also Public 
Availability of Comments under Procedural Matters.
     Federal eRulemaking Portal: http://www.regulations.gov. In 
the entry titled Enter Keyword or ID, enter BSEE-2018-0002 then click 
search. Follow the instructions to submit public comments and view 
supporting and related materials available for this rulemaking. BSEE 
may post all submitted comments.
     The American Petroleum Institute (API) provides free 
online public access to view read only copies of its key industry 
standards, including a broad range of technical standards. All API 
standards that are safety-related and that are incorporated into 
Federal regulations are available to the public for free viewing online 
in the Incorporation by Reference Reading Room on API's website at: 
http://publications.api.org.\1\ In addition to the free online 
availability of these standards for viewing on API's website, 
hardcopies and printable versions are available for purchase from API. 
The API website address to purchase standards is: http://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents.
---------------------------------------------------------------------------

    \1\ To view these standards online, go to the API publications 
website at: http://publications.api.org. You must then log-in or 
create a new account, accept API's ``Terms and Conditions,'' click 
on the ``Browse Documents'' button, and then select the applicable 
category (e.g., ``Exploration and Production'') for the standard(s) 
you wish to review.
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     The International Organization for Standardization (ISO) 
creates documents that provide requirements, specifications/government-
cited-safety documents. ISO creates documents that provide 
requirements, specifications, guidelines or characteristics that can be 
used consistently to ensure that materials, products, processes and 
services are fit for their purposes. All ISO International Standards 
are available at the ISO Store for purchase, https://www.iso.org/store.html.
     For the convenience of members of the viewing public who 
may not wish to purchase copies or view these incorporated documents 
online, they may be inspected at BSEE's office, 45600 Woodland Road, 
Sterling, Virginia 20166, or by sending a request by email to 
[email protected].
     Send comments on the information collection in this rule 
to: Interior Desk Officer 1014-0028, Office of Management and Budget; 
202-395-5806 (fax); email: [email protected]. Please send a 
copy to BSEE.
    Public Availability of Comments--Before including your address, 
phone number, email address, or other personal identifying information 
in your comment, you should be aware that your entire comment--
including your personal identifying information--may be made publicly 
available at any time. In order for BSEE to withhold from disclosure 
your personal identifying information, you must identify any 
information contained in the submittal of your comments that, if 
released, would constitute a clearly unwarranted invasion of your 
personal privacy. You must also briefly describe any possible harmful 
consequence(s) of the disclosure of information, such as embarrassment, 
injury, or other harm. While you can ask us in your comment to withhold 
your personal identifying information from public review, we cannot 
guarantee that we will be able to do so.

FOR FURTHER INFORMATION CONTACT: For technical questions contact Fred 
Brink, GOMR District Operations Support, (504) 736-2400, or by email: 
[email protected]; for procedural questions contact Kirk Malstrom, 
Regulations and Standards Branch, (202) 258-1518, or by email: 
[email protected].

SUPPLEMENTARY INFORMATION: 

Executive Summary

    In the immediate aftermath of the Deepwater Horizon incident in 
2010, BSEE adopted several recommendations from multiple investigation 
teams in order to improve the safety of offshore operations. 
Subsequently, BSEE published the Blowout Preventer Systems and Well 
Control final rule (WCR) on April 29, 2016. The WCR consolidated the 
equipment and operational requirements for well control into one part 
of BSEE's regulations; enhanced blowout preventer (BOP), well design, 
and modified well-control requirements; and incorporated certain 
industry technical standards. Most of the original WCR provisions 
became effective on July 28, 2016.
    Although the WCR addressed a significant number of issues that were 
identified during the analysis of the Deepwater Horizon incident, BSEE 
recognized that BOP equipment and systems continue to improve 
technologically and well control processes also evolve. Therefore, 
since the WCR became effective in 2016, BSEE has continued to engage 
with the offshore oil and gas industry, Standards Development 
Organizations (SDOs), and other stakeholders. During the course of 
these engagements, BSEE identified issues and stakeholders expressed a

[[Page 22129]]

variety of concerns regarding the implementation of the WCR. For 
instance, oil and natural gas operators raised concerns about certain 
regulatory provisions that impose undue burdens on their industry, but 
do not significantly enhance worker safety or environmental protection 
(e.g., how RTM is monitored and utilized onshore, a strictly enforced 
0.5ppg drilling margin, having requirements inconsistent with API 
Standard 53--an American National Standards Institute (ANSI) 
accredited, voluntary consensus standards development organization, and 
delays waiting for certain BSEE approvals during cementing operations). 
Other stakeholders suggested that certain regulatory requirements do 
not properly account for advances or limitations in technology and 
processes. Further, BSEE received numerous questions regarding the 
proper interpretation and application of provisions viewed to be 
unclear or ambiguous, requiring BSEE to provide substantial informal 
guidance regarding the terms of the WCR.
    Accordingly, after thoroughly reexamining the original WCR, 
experiences from the implementation process, and BSEE policy, BSEE 
proposes to amend, revise, or remove current regulatory provisions that 
create unnecessary burdens on stakeholders while ensuring safety and 
environmental protection. The proposed regulatory changes also reflect 
BSEE's consideration of the public comments and stakeholders' 
recommendations pertaining to the requirements applicable to offshore 
oil and gas drilling, completions, workovers, and decommissioning. This 
proposed rulemaking would revise regulatory provisions in Subparts A, 
B, D, E, F, G, and Q on topics such as, but not limited to:

Notifications and submittals to BSEE;
Drilling margins;
Lift boats;
Real-time monitoring;
BSEE Approved Verification Organizations (BAVOs);
Accumulator systems;
BOP and control station testing;
Coiled tubing; and
Mechanical barriers (packers and bridge plugs).

    BSEE utilized the best available and most pertinent data to analyze 
the economic impact of the proposed changes. That analysis indicates 
that the estimated overall economic impact will benefit the industry 
over the next 10 years because of the substantial reduction in 
compliance costs while ensuring safety and environmental protection.
    In keeping with the Executive and Secretary's Orders, BSEE 
undertook a review of the 2016 Well Control Final Rule with a view 
toward the policy direction of encouraging energy exploration and 
production on the OCS and reducing unnecessary regulatory burdens while 
ensuring that any such activity is safe and environmentally 
responsible. BSEE carefully analyzed all 342 provisions of the 2016 
Well Control Final Rule, and determined that only 59 of those 
provisions--or less than 18% of the 2016 Rule--were appropriate for 
revision. In the process, BSEE compared each of the proposed changes to 
the 424 recommendations arising from 26 separate reports from 14 
different organizations developed in the wake of and response to the 
Deepwater Horizon disaster, and determined that none of the proposed 
changes ignores or contradicts any of those recommendations, or would 
alter any provision of the 2016 Well Control Final Rule in a way that 
would make the result inconsistent with those recommendations. Further, 
nothing in this proposed rule would alter any elements of other rules 
promulgated since Deepwater Horizon, including the Drilling Safety Rule 
(Oct. 2010), SEMS I (Oct. 2010), and SEMS II (April 2013). BSEE's 
review has been thorough, careful, and tailored to the task of reducing 
unnecessary regulatory burdens while ensuring that OCS activity is safe 
and environmentally responsible.

Table of Contents

I. Background
    A. BSEE Statutory and Regulatory Authority and Responsibilities
    B. Purpose and Summary of the Rulemaking
    C. Summary of Documents Incorporated by Reference
    D. New Executive and Secretary's Orders
    E. Stakeholder Engagement
II. Section-by-Section Discussion of Proposed Changes
III. Additional Comments Solicited
    A. BOP Testing Frequency
    B. Economic Data
IV. Procedural Matters

I. Background

A. BSEE Statutory and Regulatory Authority and Responsibilities

    BSEE derives its authority primarily from the Outer Continental 
Shelf Lands Act (OCSLA), 43 U.S.C. 1331-1356a. Congress enacted OCSLA 
in 1953, authorizing the Secretary of the Interior (Secretary) to lease 
the Outer Continental Shelf (OCS) for mineral development, and to 
regulate oil and gas exploration, development, and production 
operations on the OCS. The Secretary has delegated authority to perform 
certain of these functions to BSEE.
    To carry out its responsibilities, BSEE regulates offshore oil and 
gas operations to enhance the safety of exploration for and development 
of oil and gas on the OCS, to ensure that those operations protect the 
environment, and to implement advancements in technology. BSEE also 
conducts onsite inspections to assure compliance with regulations, 
lease terms, and approved plans and permits. Detailed information 
concerning BSEE's regulations and guidance to the offshore oil and gas 
industry may be found on BSEE's website at: http://www.bsee.gov/Regulations-and-Guidance/index.
    BSEE's regulatory program covers a wide range of facilities and 
activities, including drilling, completion, workover, production, 
pipeline, and decommissioning operations. Drilling, completion, 
workover, and decommissioning operations are types of well operations 
that offshore operators \2\ perform throughout the OCS. These well 
operations are the primary focus of this rulemaking.
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    \2\ BSEE's regulations at 30 CFR part 250 generally apply to ``a 
lessee, the owner or holder of operating rights, a designated 
operator or agent of the lessee(s) . . . ,'' covered by the 
definition of ``you'' in Sec.  250.105. For convenience, this 
preamble will refer to all of the regulated entities as 
``operators'' unless otherwise indicated.
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B. Purpose and Summary of the Rulemaking

    This proposed rule would amend and update certain provision of the 
Blowout Preventer Systems and Well Control regulations and update the 
regulations to better implement BSEE policy. This proposed rule would 
fortify the Administration's position towards facilitating energy 
dominance leading to increased domestic oil and gas production, and 
reduce unnecessary burdens on stakeholders while ensuring safety and 
environmental protection. Since 2010, BSEE has promulgated many 
rulemakings (e.g., Safety and Environmental Management Systems (SEMS) I 
and II, the final safety measures rule, and the production safety 
systems final rule) to improve worker safety and environmental 
protection. Additionally, on April 29, 2016, BSEE published a final 
rule to consolidate into one part the equipment and operational 
requirements that were found in various parts of BSEE's regulations 
pertaining to well control for offshore oil and gas drilling, 
completions, workovers, and decommissioning (81 FR 25888). That final 
rule addressed issues relating to

[[Page 22130]]

BOP and well-control requirements. More specifically, the final rule 
incorporated industry standards; adopted reforms to well design, well 
control, casing, cementing, real-time well monitoring, and subsea 
containment requirements; and implemented many of the recommendations 
resulting from various investigations of the Deepwater Horizon 
incident. Most of the provisions of that rulemaking became effective on 
July 28, 2016.
    Since the time the Blowout Preventer Systems and Well Control 
regulations took effect, oil and natural gas operators have raised 
various concerns, and BSEE has identified issues during the 
implementation of the recent rulemaking. The concerns and issues 
involve certain regulatory provisions that impose undue burdens on oil 
and natural gas operators, but do not significantly enhance worker 
safety or environmental protection. BSEE understands the concerns that 
have been raised, but BSEE also fully recognizes that the BOP and other 
well-control requirements are critical components in ensuring safety 
and environmental protection. After thoroughly reexamining the Blowout 
Preventer Systems and Well Control regulations, BSEE has identified 
those provisions that can be amended, revised, or removed to reduce 
significant burdens on oil and natural gas operators on the OCS while 
ensuring safety and environmental protection. In keeping with the 
Executive and Secretary's Orders, BSEE undertook a review of the 2016 
Well Control Final Rule with a view toward the policy direction of 
encouraging energy exploration and production on the OCS and reducing 
unnecessary regulatory burdens while ensuring that any such activity is 
safe and environmentally responsible. BSEE carefully analyzed all 342 
provisions of the 2016 Well Control Final Rule, and determined that 
only 59 of those provisions--or less than 18% of the 2016 Rule--were 
appropriate for revision. In the process, BSEE compared each of the 
proposed changes to the 424 recommendations arising from 26 separate 
reports from 14 different organizations developed in the wake of and 
response to the Deepwater Horizon disaster, and determined that none of 
the proposed changes ignores or contradicts any of those 
recommendations, or would alter any provision of the 2016 Well Control 
Final Rule in a way that would make the result inconsistent with those 
recommendations. Further, nothing in this proposed rule would alter any 
elements of other rules promulgated since Deepwater Horizon, including 
the Drilling Safety Rule (Oct. 2010), SEMS I (Oct. 2010), and SEMS II 
(April 2013). BSEE's review has been thorough, careful, and tailored to 
the task of reducing unnecessary regulatory burdens while ensuring that 
OCS activity is safe and environmentally responsible.
    This rulemaking would revise current regulations that impact 
offshore oil and gas drilling, completions, workovers, and 
decommissioning activities. The proposed regulations would also address 
various issues that were identified during the implementation of the 
current Blowout Preventer Systems and Well Control regulations, as well 
as numerous questions that have required substantial informal guidance 
from BSEE regarding the interpretation and application of the 
provisions. For example, this proposed rulemaking would:

     Clarify the rig movement reporting requirements.
     Clarify and revise the requirements for certain 
submittals to BSEE to eliminate redundant and unnecessary reporting.
     Clarify the drilling margin requirements.
     Revise section 250.723 by removing references to lift 
boats from the section.
     Remove certain prescriptive requirements for real time 
monitoring.
     Replace the use of a BSEE approved verification 
organization (BAVO) with the use of an independent third party for 
certain certifications and verifications of BOP systems and 
components, and remove the requirement to have a BAVO submit a 
Mechanical Integrity Assessment report for the BOP stack and system.
     Revise the accumulator system requirements and 
accumulator bottle requirements to better align with API Standard 
53.
     Revise the control station and pod testing schedules to 
ensure component functionality without inadvertently requiring 
duplicative testing.
     Include coiled tubing and snubbing requirements in 
Subpart G.
     Revise the text to ensure consistency and conformity 
across the applicable sections of the regulations.

C. Summary of Documents Incorporated by Reference

    This rulemaking would update a document currently incorporated by 
reference to a newer edition, and add a new standard for incorporation. 
A brief summary of the proposed changes, based on the descriptions in 
each standard or specification is provided in the text that follows.
API Standard 53--Blowout Prevention Equipment Systems for Drilling 
Wells
    This standard provides requirements for the installation and 
testing of blowout prevention equipment systems whose primary functions 
are to confine well fluids to the wellbore, provide means to add fluid 
to the wellbore, and allow controlled volumes to be removed from the 
wellbore. BOP equipment systems are comprised of a combination of 
various components that are covered by this document. Equipment 
arrangements are also addressed. The components covered include: BOPs 
including installations for surface and subsea BOPs; choke and kill 
lines; choke manifolds; control systems; and auxiliary equipment.
    This standard also provides new industry best practices related to 
the use of dual shear rams, maintenance and testing requirements, and 
failure reporting. Diverters, shut-in devices, and rotating head 
systems (rotating control devices) whose primary purpose is to safely 
divert or direct flow rather than to confine fluids to the wellbore are 
not addressed. Procedures and techniques for well control and extreme 
temperature operations are also not included in this standard.
    API Standard 65-part 2, which was issued December 2010. This 
standard outlines the process for isolating potential flow zones during 
well construction. The new Standard 65-part 2 enhances the description 
and classification of well-control barriers, and defines testing 
requirements for cement to be considered a barrier.
API Recommended Practice 17H--Remotely Operated Tools and Interfaces on 
Subsea Production Systems
    The proposed rule would update the incorporated version of this 
document from the First Edition (dated 2004, reaffirmed 2009) to the 
Second Edition (dated 2013). This recommended practice provides general 
recommendations and overall guidance for the design and operation of 
remotely operated tools (ROT) and remotely operated vehicle (ROV) 
tooling used on offshore subsea systems. ROT and ROV performance is 
critical to ensuring safe and reliable deepwater operations, and this 
document provides general performance guidelines for the equipment. One 
of the main differences between the first edition and second edition of 
this recommended practice is that the second edition includes 
provisions on high flow Type D hot stabs.
ISO ISO/IEC 17021-1--Conformity Assessment--Requirements for Bodies 
Providing Audit and Certification of Management Systems
    The proposed rule would incorporate this standard into the 
regulations by

[[Page 22131]]

reference for the first time, for purposes of the quality management 
system certification requirements of section 250.730(d). This standard 
contains principles and requirements for the competence, consistency, 
and impartiality of bodies providing audit and certification of all 
types of management systems. It provides generic requirements for such 
bodies performing audit and certification in the fields of quality, the 
environment, and other types of management systems. Incorporation of 
this standard would provide clarity and consistency surrounding the 
critical qualifications of entities responsible for certifying quality 
management systems for the manufacture of BOP stacks.
    When a copyrighted publication is incorporated by reference into 
BSEE regulations, BSEE is obligated to observe and protect that 
copyright. BSEE provides members of the public with website addresses 
where these standards may be accessed for viewing--sometimes for free 
and sometimes for a fee. Standards development organizations decide 
whether to charge a fee. One such organization, the American Petroleum 
Institute (API), provides free online public access to view read only 
copies of its key industry standards, including a broad range of 
technical standards. All API standards that are safety-related and that 
are incorporated into Federal regulations are available to the public 
for free viewing online in the Incorporation by Reference Reading Room 
on API's website at: http://publications.api.org.\3\ In addition to the 
free online availability of these standards for viewing on API's 
website, hardcopies and printable versions are available for purchase 
from API. The API website address to purchase standards is: http://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents.
---------------------------------------------------------------------------

    \3\ To view these standards online, go to the API publications 
website at: http://publications.api.org. You must then log-in or 
create a new account, accept API's ``Terms and Conditions,'' click 
on the ``Browse Documents'' button, and then select the applicable 
category (e.g., ``Exploration and Production'') for the standard(s) 
you wish to review.
---------------------------------------------------------------------------

    The International Organization for Standardization (ISO) creates 
documents that provide requirements, specifications/government-cited-
safety documents. ISO creates documents that provide requirements, 
specifications, guidelines or characteristics that can be used 
consistently to ensure that materials, products, processes and services 
are fit for their purposes. All ISO International Standards are 
available at the ISO Store for purchase, https://www.iso.org/store.html.
    For the convenience of members of the viewing public who may not 
wish to purchase copies or view these incorporated documents online, 
they may be inspected at BSEE's office, 45600 Woodland Road, Sterling, 
Virginia 20166, or by sending a request by email to [email protected].
    In addition, BSEE is aware of a published addendum to API Standard 
53, and a new Standard 53 edition currently under development by API, 
consistent with international standards. BSEE will continue to evaluate 
the API addendum and the new edition. At this time, BSEE does not 
propose to incorporate the API Standard 53 addendum into this proposed 
rule. However, BSEE is considering incorporating the API Standard 53 
addendum in the final rule. BSEE is specifically soliciting comments on 
whether the API Standard 53 addendum should be included within the 
documents incorporated by reference. Please provide reasons for your 
position. If your comment addresses anticipated monetary or operational 
benefits associated with using the API Standard 53 addendum, please 
provide any available supporting data. When the new edition of API 
Standard 53 is finalized by API, BSEE would consider incorporating that 
edition into future rulemaking as appropriate.
    BSEE is also considering potential, technical (non-substantive) 
revisions to Sec.  250.198 for the purposes of reorganizing and 
revising that section to make it clearer, more user-friendly, and more 
consistent with the Office of the Federal Register's (OFR) 
recommendations for incorporations by reference in Federal regulations. 
BSEE will continue to consult with OFR regarding its suggestions for 
specific organizational and language changes to Sec.  250.198 and 
expects to address such technical revisions in a final rule as soon as 
possible. BSEE does not anticipate that those potential revisions would 
have any substantive impact on the proposed incorporations by reference 
of industry standards discussed in this rule.

D. New Executive and Secretary's Orders

    On March 28, 2017, the President issued Executive Order (E.O.) 
13783--Promoting Energy Independence and Economic Growth (82 FR 16093). 
The E.O. directed Federal agencies to review all existing regulations 
and other agency actions and, ultimately, to suspend, revise, or 
rescind any such regulations or actions that unnecessarily burden the 
development of domestic energy resources beyond the degree necessary to 
protect the public interest or otherwise comply with the law.
    On April 28, 2017, the President issued E.O. 13795--Implementing an 
America-First Offshore Energy Strategy (82 FR 20815), which directed 
the Secretary to review the WCR for consistency with the policy set 
forth in section 2 of E.O. 13795, and to ``publish for notice and 
comment a proposed rule revising that rule, if appropriate and as 
consistent with law.'' To further implement E.O. 13795, the Secretary 
issued Secretary's Order No. 3350 on May 1, 2017, directing BSEE to 
review the WCR for consistency with E.O. 13795, including preparation 
of a report ``providing recommendations on whether to suspend, revise, 
or rescind the rule'' in response to concerns raised by stakeholders 
that the WCR ``unnecessarily include[s] prescriptive measures that are 
not needed to ensure safe and responsible development of our OCS 
resources.''
    As part of its response to E.O.s 13783 and 13795, and Secretary's 
Order No. 3350, and in light of the requests received for clarification 
and revision of various provisions, BSEE reviewed the WCR and is 
proposing revisions to the WCR that could reduce unnecessary burdens on 
industry without impacting key provisions in the rule that have a 
significant impact on improving safety and equipment reliability.

E. Stakeholder Engagement

Implementation of the Original WCR--BSEE Questions and Answers (Q's and 
A's)
    The Department promulgated the original ``Blowout Preventer Systems 
and Well Control'' final rule (WCR) in April 2016. Subsequently, during 
the implementation of the revised regulations, BSEE received numerous 
questions from stakeholders seeking clarification and guidance 
concerning the WCR's provisions. The questions covered a vast array of 
issues and spanned multiple subparts of the regulations.
    BSEE reviewed each question it received and decided whether the 
question presented an issue that was appropriate for Bureau guidance. 
To the extent a question required guidance or clarification, BSEE 
provided a response to clarify any potentially confusing language. In 
addition to deciding on the appropriateness of a question for guidance, 
BSEE determined whether a question posed was of sufficient public 
interest to merit broader publication of a response. After finalizing 
regulatory

[[Page 22132]]

guidance in response to a stakeholder's question, BSEE typically 
publishes both the question and BSEE's answer on its web page. The 
information, which reflects BSEE's guidance of the current regulations, 
may be found at: https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule. BSEE has posted approximately 100 
responses on the web page.
    BSEE has reexamined the questions and answers pertaining to the 
original WCR. After careful consideration of all relevant information 
in the questions and answers, BSEE has determined that certain 
provisions of the original rule should be revised to support the goals 
of the regulatory reform initiative while ensuring safety and 
environmental protection. Additionally, BSEE's proposed revisions seek 
to clarify any ambiguity in the regulatory language, eliminate 
redundancies in the provisions, and align specific requirements more 
closely with relevant technical standards.
BSEE Public Forum on Well Control and Blowout Preventer Rule
    To ensure a complete and thorough review of the WCR, BSEE has 
solicited input from interested parties to identify potential revisions 
to the rule that would significantly reduce regulatory burdens without 
significantly reducing safety and environmental protection on the OCS. 
BSEE held a public forum on September 20, 2017, in Houston, Texas. More 
than 110 participants attended and provided comments and suggestions. A 
summary of registrants included:
     Federal agencies;
     Media;
     Oil and gas companies;
     Classification societies;
     Trade associations;
     Environmental groups; and
     Equipment manufacturers.
    Additionally, there were eight presentations made at the forum. 
These presentations are available at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule/public%20forum.

II. Section-by-Section Discussion of Proposed Changes

    BSEE is proposing to revise the following regulations:

Subpart A--General

Documents Incorporated by Reference (Sec.  250.198)

    BSEE would revise paragraph (h)(63), which incorporates API 
Standard 53, Blowout Prevention Equipment Systems for Drilling Wells, 
Fourth Edition, November 2012, to add a new cross reference to Sec.  
250.734. The changes to this paragraph are administrative and merely 
reflect substantive changes made to Sec.  250.734, addressed further at 
the corresponding location in the section-by-section discussion.
    BSEE would revise paragraph (h)(78), which incorporates API 
Standard 65--Part 2, Isolating Potential Flow Zones During Well 
Construction; Second Edition, December 2010, to add a new cross 
reference to Sec.  250.420(a)(6). The changes to this paragraph are 
administrative. For discussion of the effects on the regulatory 
requirements of incorporating this document, refer to Sec.  
250.420(a)(6).
    BSEE would also revise paragraph (h)(94) to update the 
incorporation of API RP 17H to the second edition. The changes to this 
paragraph are administrative. For discussion of the effects on the 
regulatory requirements of incorporating this document, refer to Sec.  
250.734(a)(4). BSEE has reviewed the differences between the first and 
second editions of API RP 17H. The API RP 17H second edition was mostly 
rearranged to clarify and consolidate similar topics covered in the 
first edition. The second edition now includes the following sections: 
Subsea intervention concepts, subsea intervention systems design 
recommendations, ROV interfaces, materials, subsea markings, and 
validation and verification. These sections are mostly a reorganization 
of the content of the first edition with minor changes to the design 
recommendations. The most significant change from the first edition to 
the second edition was the addition of the Type D connection to the ROV 
interface section. The Type D connection is intended for large bore, 
high circulation capabilities and is limited to the maximum rated 
pressure of 5,000 psi. This Type D connection allows the ROV hot stab 
to meet the API Standard 53 closing timing requirements, which API RP 
17H first edition did not accomplish.
    BSEE would add new paragraph (m)(2) for the International 
Organization for Standardization (ISO) 17021 to update the erroneous 
standard incorporated in the original WCR. For discussion of the 
effects on the regulatory requirements of incorporating this document, 
refer to Sec.  250.730(d) and the associated section-by-section 
discussion.

Subpart B--Plans and Information

What must the DWOP contain? (Sec.  250.292)

    This rulemaking would revise paragraph (p) by clarifying the free 
standing hybrid riser (FSHR) requirements and removing the requirement 
for certification of the tether system and connection accessories by an 
approved classification society or equivalent. Based on BSEE experience 
during the implementation of the original WCR, these revisions to 
paragraph (p) would clarify the focus of the requirements for FSHR 
systems that involve a buoyancy air can suspended from the top of the 
riser, regardless of the manner of connection, to avoid confusion over 
whether a specific component type would be considered `critical' or 
not. The requirements in existing Sec.  250.292(p)(2) and (p)(3) would 
be removed because the detailed information specified on the FSHR 
design, fabrication, installation, and load cases is already required 
by the relevant portions of the platform verification program (PVP) in 
Sec.  250.910(b), and in Sec. Sec.  250.1002(b)(5) and 
250.1007(a)(4)(ii). This would reduce the burden on operators by 
eliminating the requirement to submit the same or very similar 
information on an FSHR system through more than one regulatory 
permitting process. Section 250.292 paragraphs (p)(4) and (p)(5) would 
be redesignated as Sec.  250.292 paragraphs (p)(2) and (p)(3), and 
their language would be revised to align with the clarification in 
paragraph (p). The requirements in Sec.  250.292(p)(6) would be removed 
altogether, because they are duplicative of the certification that any 
permanent pipeline riser installation and its tensioning systems will 
undergo via the Certified Verification Agent (CVA) requirements of 
Sec.  250.911, in connection with the PVP.

Subpart D--Oil and Gas Drilling Operations

What must my description of well drilling design criteria address? 
(Sec.  250.413)

    This rulemaking would add in paragraph (g) a parenthetical 
clarification of ``surface and downhole'' after ``proposed drilling 
fluid weights'', to ensure the operator includes the weight of the 
drilling fluid in both places. This clarifies the information the 
operator has previously been required to provide, without adding a new 
burden, and improves the safety of the drilling operation by ensuring 
the drilling fluid weight is fully evaluated and appropriate for the 
estimated bottom hole pressures.

What must my drilling prognosis include? (Sec.  250.414)

    This proposed rule would revise paragraph (c)(3) of this section to 
add

[[Page 22133]]

the words ``and analogous'' before ``well behavior observations'' and 
``, if available'' at the end of paragraph (c)(3) of this section. This 
minor wording change would ensure that operators use available data 
from wells with similar conditions as the well being drilled when 
determining the pore pressure and fracture gradient to ensure accuracy 
and safety when establishing the drilling margin. BSEE is specifically 
soliciting comments about the effectiveness of the use of related 
analogous data and how the pore pressure and fracture gradient are 
determined without related analogous data. Please provide reasons for 
your position.
    In the proposed rule text, the drilling margin requirements are 
mostly unchanged. The current regulations allow for a deviation from 
the default 0.5 pound per gallon (ppg) drilling margin. The deviation 
does not have to be submitted as an alternate procedure or departure 
request; rather, it may be submitted with the Application for Permit to 
Drill (APD) along with the supporting justifications. BSEE is currently 
approving margins other than 0.5 ppg based on specific well conditions. 
BSEE is working to provide consistent approval throughout the regions 
and districts, and, as described more fully below, BSEE is specifically 
soliciting comments about the process to deviate from the 0.5 ppg 
drilling margin.
    The purpose of the drilling margin is to ensure that the drilling 
fluid weight used allows for some variability in the pore pressure and 
fracture gradient, ensuring the safety of drilling operations. In 2011, 
the National Academy of Engineering and National Research Council of 
the National Academies recommended that ``[d]uring drilling, rig 
personnel should maintain a reasonable margin of safety between the 
equivalent circulating density and the density that will cause wellbore 
fracturing.'' Macondo Well Deepwater Horizon Blowout--Lessons for 
Improving Offshore Drilling Safety (NAE Report), Recommendation 2.2 (p. 
43). The NAE Report stated further that ``until a reasonable standard 
is established, industry should design the ECD [equivalent circulating 
density] so that the difference between the ECD and the fracture mud 
weight is a minimum of 0.5 ppg . . . Additional evaluations and 
analyses should be performed to establish an appropriate standard for 
this margin of safety.'' Id. The Department's 2011 joint investigation 
team report (DOI JIT Report) regarding the causes of the April 20, 
2010, Macondo Well blowout recommended that BSEE define the term ``safe 
drilling margin(s)'' and that such a definition should ``encompass pore 
pressure, fracture gradient and mud weight.'' The Bureau of Ocean 
Energy Management, Regulation and Enforcement Report Regarding the 
Causes of the April 20, 2010, Macondo Well Blowout (DOI JIT Report), 
Recommendation 3 (p. 202). Thus, the NAE Report and the DOI JIT Report 
recommended additional evaluations, analyses, and definition of what a 
safe drilling margin is. In the 2016 final well control rule preamble, 
BSEE cited this JIT Report recommendation and the bureau's prior 
typical reliance on a minimum of 0.5 ppg below the lower casing shoe 
pressure integrity test or the lowest estimated fracture gradient as an 
appropriate safe drilling margin and as the basis for including this as 
the default requirement in the current section 250.414(c). 81 FR 25888, 
25894 (April 29, 2016). Section 250.414(c) also allows for using an 
equivalent downhole mud weight, provided that the operator submitted 
adequate documentation justifying the use of an alternative equivalent 
downhole mud weight.
    Since the WCR became effective, BSEE's records show that there have 
been 305 wells drilled. Of those wells, BSEE has approved operators' 
use of drilling margins that are less than 0.5 ppg for 32 wells, 31 of 
which were in deep water. Even though these 32 wells represent only 10 
percent of the total wells drilled in that time frame, the number is 
significant enough for BSEE to consider whether it should further 
refine the approach it is taking in the current regulations or whether 
it should adhere to its practice of identifying a specific drilling 
margin with an avenue for allowing operators to submit adequate 
documentation justifying the use of a different drilling margin, such 
as risk modeling data, off-set well data, analog data, and seismic 
data.
    The Explanatory Statement for the 2017 Consolidated Appropriations 
Act, Public Law 115-31 (May 5, 2017), also recommended that BSEE 
consider revising the 2016 WCR. It stated:

    Blowout Preventer Systems and Well Control Rule.--The Committees 
encourage the Bureau to evaluate information learned from additional 
stakeholder input and ongoing technical conversations to inform 
implementation of this rule. To the extent additional information 
warrants revisions to the rule that require public notice and 
comment, the Bureau is encouraged to follow that process to ensure 
that offshore operations promote safety and protect the environment 
in a technically feasible manner.

163 Cong. Rec. H3881 (daily ed. May 3, 2017).
    For these reasons, BSEE is requesting comment and further 
statistical analysis from stakeholders about whether the 0.5 ppg 
drilling margin in this proposed rule should be revised or removed. 
BSEE solicits comments on alternatives to the current set 0.5 ppg 
drilling margin. Specifically, BSEE requests comment on replacing it 
with a more performance-based standard under which the approved safe 
drilling margin is established on a case-by-case basis for each well, 
based on data and analysis particular to that well, through the 
permitting process. BSEE also requests comment on potentially providing 
for a different drilling margin or multiple drilling margins that are 
specific to the conditions in which the wells are drilled, such as if 
the well is drilled in deep water or shallow water. BSEE further 
requests comment on whether removal of a specific reference to a 0.5 
ppg standard from the regulation may be appropriate. For example, the 
standard establishes a prescriptive margin without an in-depth analysis 
of appropriate margins for potential hole sections, which must take 
into account factors, such as cutting loads, equivalent downhole mud 
weight, and fluid temperatures and pressures. Further, enforcing a 
prescriptive minimum margin can force operators to encroach on pore 
pressure, which might result in unintended kicks. These types of 
considerations may suggest that a more case-by-case approach toward the 
establishment of appropriate safe drilling margins for particular wells 
through the permitting process would be preferable. Consequently, BSEE 
specifically solicits comments regarding the potential removal of the 
specific reference to a 0.5 ppg drilling margin from Sec.  250.414(c) 
and its replacement with a more performance based, case-by-case 
standard for the establishment of appropriate safe drilling margins 
through the well permitting process.
    BSEE also requests comment on the criteria that BSEE could use to 
apply alternative approaches, such as an operator demonstrating that a 
well is a development well as opposed to an exploratory well. To 
utilize this alternative option, the rulemaking could specify what 
documentation operators would need to submit with the APD in order to 
provide adequate justification. BSEE requests comment on what 
supplemental data would provide an adequate level of justification for 
deviating from the 0.5 ppg drilling margin under identified 
circumstances, such as requiring the submission of

[[Page 22134]]

offset well data, analog data, seismic data, and decision modeling.
    BSEE also requests comment on whether there are situations where 
drilling can continue prior to receiving alternative safe drilling 
margin approval from BSEE. BSEE requests comment on (1) whether there 
are situations where, despite not being able to maintain the approved 
safe drilling margin, an operator's continued drilling with an 
alternative drilling margin creates little risk; (2) the criteria that 
BSEE should use to define those situations and the available 
alternative drilling margins; and (3) what level of follow-up reporting 
(e.g. submitting a follow-up notice to BSEE within a specified time 
frame) would be appropriate. Such an approach could provide assurance 
that an operator, with the appropriate level of justification, could 
continue to drill as real time data is evaluated, and would largely be 
designed to add more clarity to the existing option(s) provided by 
Sec.  250.414(c)(2). This would provide a proactive approach to 
managing risk and ensuring safe operations, while also providing 
increased investment certainty for the regulated community.
    In addition, BSEE could add the words ``and analogous'' before 
``well behavior observations'' and ``, if available'' at the end of 
paragraph (c)(3) of this section. This minor wording change could 
ensure that operators use available data from wells with similar 
conditions as the well being drilled when determining the pore pressure 
and fracture gradient to ensure accuracy and safety when establishing 
the drilling margin. BSEE is specifically soliciting comments about the 
effectiveness of the use of related analogous data and how the pore 
pressure and fracture gradient are determined without related analogous 
data. Please provide reasons for your position.

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

    BSEE is proposing to incorporate by reference API Standard 65-Part 
2 in paragraph (a)(6) of this section for purposes of defining the 
standards governing centralization. This would clarify the intent of 
the current centralization requirements by adopting the methods 
described in API Standard 65-Part 2 to ensure proper centralization 
during cementing. BSEE would add the reference to API Standard 65-Part 
2 based upon its evaluation of the original WCR implementation and 
industry's recent questions concerning the applicability of this 
standard. Centralization is important for cement jobs, as it ensures 
the casing is centered in the hole and that there is enough space 
between the casing and the wellbore for the cement to form a uniform 
barrier to help minimize the risk of cement failure. BSEE has 
determined that the standards set forth in API Standard 65-Part 2 
properly ensure adequate centralization and provide clearer guidelines 
for operators than the current regulatory language.

What are the casing and cementing requirements by type of casing 
string? (Sec.  250.421)

    BSEE proposes to make minor revisions in paragraphs (c), (d), (e), 
and (f) clarifying that all length requirements are to be taken from 
measured depth. This clarification of the existing regulatory 
requirements would provide consistency for planning and permitting 
purposes.
    Paragraph (f) would also be revised by removing the specifics of 
the listed example regarding when a liner is used as intermediate 
casing. The example is redundant because it restates the same 
information already contained in this section. This deletion would not 
change the applicability or substance of the requirements.

What are the requirements for casing and liner installation? (Sec.  
250.423)

    This rulemaking would revise paragraphs (a) and (b) by removing the 
words ``and cementing'' after ``upon successfully installing''. 
Revisions to this section are necessary because there are many 
situations in the design of the casing or liner string running tool 
where the latching or lock down mechanism is automatically engaged upon 
installing the string. BSEE has received many alternate procedure 
requests to accommodate these situations since publication of the 
original WCR. This change would not impact safety because BSEE is still 
requiring these mechanisms to be engaged upon successful installation 
of the casing or liner. The proposed change would allow more 
flexibility on an operational case-by-case basis in determining the 
appropriate time to engage these mechanisms and would also reduce the 
number of alternate procedure requests submitted to BSEE for approval.

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

    BSEE is proposing to revise paragraph (c) to include the term 
``unplanned'' when describing the lost returns that provide indications 
of an inadequate cement job. This revision would minimize the number of 
unnecessary revised permits submitted to BSEE for approval. Current 
cementing practices utilize improved well modelling to identify and 
account for zones that may have anticipated losses. It is unnecessary 
to submit a revised APD to address lost returns for a well cementing 
program that has been designed for those occurrences. Any unexpected 
losses would require locating top of cement and determining whether the 
cement job is adequate.
    Existing paragraph (c)(iii) would be redesignated as paragraph 
(c)(iv). A new paragraph (c)(iii) would be added to allow the use of 
tracers in the cement, and logging the tracers' location prior to drill 
out, as an alternative approach for locating the top of cement. The 
original WCR did not address this approach, however based upon BSEE 
experience this addition would provide more viable options and 
flexibility for locating top of cement to help minimize rig down time 
running in and out of the hole multiple times, without compromising 
safety.
    Paragraph (d) would be revised to clarify that, if there is an 
inadequate cement job, operators are required to comply with Sec.  
250.428(c)(1). The original WCR did not address this provision, however 
based upon BSEE experience this revision would help assess the overall 
cement job to allow for improved planning of remedial actions.
    This rulemaking would also revise paragraph (d) to allow the 
preapproval of remedial cementing actions through a contingency plan 
within the original approved permit; however, if the remedial actions 
have not already been approved by BSEE, clarification was added 
directing submittal of the remedial actions in a revised permit for 
BSEE review and approval. The original WCR did not address this 
provision, however based upon BSEE experience, BSEE is proposing to 
allow the remedial actions to be included as contingency plans in the 
original permit to minimize the time necessary for operators to 
commence approved remedial cementing actions, and to reduce burdens on 
operators and BSEE from multiple submissions. If BSEE has already 
approved the remedial cementing actions in the original permit, 
additional BSEE approval is not required unless they deviate from the 
approved actions. BSEE will still receive information regarding any 
remedial cementing actions taken in Well Activity Reports.
    Based upon BSEE experience with the implementation of the original 
WCR, BSEE has determined that allowing the professional engineer (PE) 
to certify the remedial cementing actions in the contingency plan 
within the original permit would help streamline the

[[Page 22135]]

permitting process and reduce delays to remedial actions without 
compromising safety. The proposed revision to this paragraph would 
eliminate the requirement for a PE certification for any changes to the 
well program so long as the changes were already approved in the 
permit. This would result in less rig down time waiting for PE 
certifications before beginning initial remedial actions. In 
conjunction with the approval of the remedial actions BSEE requires a 
PE certification for any changes to the well program. These proposed 
revisions would minimize the number of revised permits submitted to 
BSEE for approval, reducing burdens on operators and BSEE.

What are the diverter actuation and testing requirements? (Sec.  
250.433)

    This rulemaking would revise paragraph (b) to modify requirements 
for subsequent diverter testing by allowing partial activation of the 
diverter element and not requiring a flow test. The original WCR did 
not address this provision, however based upon BSEE experience these 
changes would codify longstanding BSEE policy and minimize the number 
of alternate procedure requests submitted to BSEE. Full actuation of 
the diverter element and flow tests are unnecessary with subsequent 
testing because partial actuation of the element sufficiently 
demonstrates functionality of the element, and a full flow test would 
be originally verified on the initial test. These changes would also 
help minimize the possibility of accidental discharge of mud overboard.

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

    This proposed rule would revise paragraph (b) by extending the 
maximum permitted survey intervals during angle-changing portions of 
directional wells from 100 feet to 180 feet. This would account for the 
majority of the pipe stand lengths and would address developments that 
BSEE has needed to accommodate through alternative approvals since 
before the original WCR. Most rigs have upgraded the derrick height to 
account for the increase in pipe stand lengths to improve drilling 
efficiency. The pipe stands have routinely become greater than 100 
feet, with some pipe stands being as high as 180 feet. Increasing the 
survey interval to correlate with the now common pipe stand lengths 
would help improve rig efficiency while drilling. This revision would 
also minimize the number of alternate procedure requests submitted to 
BSEE in APDs. BSEE does not expect these revisions to reduce safety 
because of the rationale previously stated. BSEE currently, when 
appropriate, approves survey intervals based on the use of such pipe 
stand lengths through the alternate procedure request and approval 
process. These revisions would not result in any real changes in 
current survey operations, only removing the added process of operators 
submitting for approval an alternate procedure to use surveys 
associated with 180 foot pipe stand lengths.

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

    Paragraph (b) of this section would be revised to clarify that the 
source control and containment equipment (SCCE) to which operators need 
to have access is based on the determinations regarding source control 
and containment capabilities required in Sec.  250.462(a), and that the 
identified list of equipment represents examples of the types of SCCE 
that may be determined appropriate rather than universal requirements. 
Based upon BSEE experience with the implementation of the original WCR, 
this revision would help ensure that appropriate SCCE is available for 
the specific corresponding well rather than requiring every possible 
type of SCCE regardless of the well-specific determinations.
    Paragraph (e)(1)(ii) would be revised to remove ``a BSEE approved 
verification organization'' and replace it with ``an independent third 
party'' that meets the requirements of Sec.  250.732(b). For a 
discussion on the changes from a BAVO to an independent third party, 
see the section-by-section discussion of Sec.  250.732.
    Proposed revisions to paragraph (e)(3) would clarify that subsea 
utility equipment utilized solely for containment operations must be 
available for inspection at all times. Paragraph (e)(4) would also be 
revised to clarify that it is applicable only to collocated equipment 
identified in the Regional Containment Demonstration (RCD) or Well 
Containment Plan and not all collocated equipment. The proposed 
revisions to both paragraphs (e)(3) and (e)(4) would help ensure that 
the applicable respective equipment is available for inspection. BSEE 
recognizes that some of the equipment used for containment is used for 
other types of operations on the OCS and would be available for 
inspection when in use during other well operations.

Subpart E--Oil and Gas Well-Completion Operations

Tubing and Wellhead Equipment (Sec.  250.518)

    This rulemaking would revise paragraph (e)(1) by clarifying that 
only permanently installed packers or bridge plugs that are qualified 
as mechanical barriers are required to comply with ANSI/API Spec. 11D1. 
Based upon BSEE experience with the implementation of the original WCR, 
including questions BSEE received from operators, this revision would 
codify BSEE's policy to ensure that the required mechanical barriers in 
a well are held to a higher standard than other common packers or 
bridge plugs used for various other well-specific conditions and 
completions design. Furthermore, BSEE is aware that certain packers and 
bridge plugs cannot meet the specifications of ANSI/API Spec. 11D1. 
BSEE does not expect these revisions to reduce safety. The proposed 
change would ensure that the packers and bridge plugs utilized as 
required mechanical barriers are ANSI/API Spec. 11D1 compliant, while 
eliminating the need for packers and plugs used for other, non-
critical, purposes to meet the standard.

 What are the requirements for casing pressure management? (Sec.  250. 
519)

    BSEE would make minimal revisions to this section to update 
incorrect citations. These revisions are administrative in nature and 
ensure that the appropriate citations are correctly cross referenced.

How do I manage the thermal effects caused by initial production on a 
newly completed or recompleted well? (Sec.  250.522)

    BSEE would make minimal revisions to this section to update 
incorrect citations. These revisions are administrative in nature and 
ensure that the appropriate citations are correctly cross referenced.

When am I required to take action from my casing diagnostic test? 
(Sec.  250.525)

    BSEE would make minimal revisions to paragraph (d) of this section 
to update incorrect citations. These revisions are administrative in 
nature and ensure that the appropriate citations are correctly cross 
referenced.

What do I submit if my casing diagnostic test requires action? (Sec.  
250.526)

    BSEE would make minimal revisions to this section to update 
incorrect citations. These revisions are

[[Page 22136]]

administrative in nature and ensure that the appropriate citations are 
correctly cross referenced.

What if my casing pressure request is denied? (Sec.  250.530)

    BSEE would make minimal revisions to paragraph (b) of this section 
to update incorrect citations. These revisions are administrative in 
nature and ensure that the appropriate citations are correctly cross 
referenced.

Subpart F--Oil and Gas Well-Workover Operations

Definitions (Sec.  250.601)

    This rulemaking would revise the definition of routine operations 
in this section to make it consistent with the definition of routine 
operations in Sec.  250.105 by adding paragraph (m) ``acid 
treatments.'' The original WCR did not address this provision, however 
based upon BSEE experience, this revision is necessary to help minimize 
confusion about the definition of routine operations.

Coiled tubing and snubbing operations (Sec.  250.616)

    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.750, with minor revisions 
discussed in connection with that provision. These revisions would help 
BSEE eliminate inconsistencies between similar requirements throughout 
different BSEE subparts by consolidating those requirements into 
Subpart G which is applicable to drilling, completions, workovers, and 
decommissioning operations.

Tubing and wellhead equipment (Sec.  250.619)

    This rulemaking would revise paragraph (e)(1) by clarifying that 
only permanently installed packers or bridge plugs that are qualified 
as mechanical barriers are required to comply with ANSI/API Spec. 11D1. 
This revision would codify BSEE's policy developed since the WCR, to 
ensure that the required mechanical barriers in a well are held to a 
higher standard than other common packers or bridge plugs used for 
various well specific conditions and completions design. Furthermore, 
BSEE is aware that certain packers and bridge plugs cannot meet the 
specifications of ANSI/API Spec. 11D1. BSEE would also add that 
operators must have two independent barriers, one being mechanical, in 
the exposed center wellbore prior to removing the tree or well control 
equipment. This addition would codify existing BSEE policy and add into 
the workover regulations in Subpart F requirements about mechanical 
barriers similar to those already found in Sec.  250.720(a). This 
addition would help ensure the well is properly secured before removal 
of the tree or well control equipment.

Subpart G--Well Operations and Equipment

What rig unit movements must I report? (Sec.  250.712)

    BSEE proposes to revise this section by adding new paragraphs (g) 
and (h). BSEE would add paragraph (g) to clarify that reporting is not 
necessary for rig movements to and from the safe zone during permitted 
operations. BSEE would also add paragraph (h) to clarify that, if a rig 
unit is already on a well, BSEE would not require a notification for 
any additional rig unit movements on that well. This change would not 
impact safety because BSEE would still receive initial rig movement 
notifications and would be aware of rig unit locations. The original 
WCR did not address this provision, however based upon BSEE experience, 
BSEE determined that these clarifications would minimize the number of 
duplicative rig movement notifications submitted to BSEE under these 
particular circumstances.

When and how must I secure a well? (Sec.  250.720)

    BSEE proposes to revise paragraph (a)(1) to add an impending 
National Weather Service-named tropical storm or hurricane to the list 
of example events that would interrupt operations and require 
notification. Furthermore, BSEE also proposes to add new paragraph 
(a)(3) to include provisions for testing the applicable BOP or lower 
marine riser package (LMRP) upon relatch according to Sec.  250.734 
paragraphs (b)(2) or (b)(3), respectively, and obtaining BSEE approval 
before resuming operations. Based upon BSEE experience with the 
implementation of the original WCR and longstanding policy, these 
revisions would codify the BSEE storm policy reflected in longstanding 
guidance and provide clarity for testing when an operator has returned 
to the location and relatched the BOP or LMRP. These tests help confirm 
that the BOP or LMRP is properly functional prior to resuming 
operations after being unlatched due to a storm or other interruption.
    This rulemaking would also add new paragraph (d) requiring 
equipment and capabilities for well intervention. This addition would 
specify that equipment used solely for well intervention must be 
readily available for use, maintained in accordance with applicable 
original equipment manufacturer (OEM) recommendations, and available 
for inspection by BSEE upon request. BSEE would add this paragraph to 
ensure that when intervention is necessary on a well, the applicable 
tools (such as the tree interface tools) are available and ready for 
their intended use. BSEE is aware of recent instances where 
intervention was necessary on a particular subsea tree, and the tree-
specific unique interface tools were not available to perform the work 
on that well, delaying the operations.

What are the requirements for prolonged operations in a well? (Sec.  
250.722)

    BSEE is proposing to revise the prolonged operations well casing 
reporting requirements in paragraph (a)(2) of this section to clarify 
that District Manager approval is not required to resume operations if 
a successful pressure test was conducted as already approved in the 
applicable permit. BSEE would also clarify that the successful pressure 
test results must be documented in the Well Activity Report (WAR). The 
original WCR did not address the issue of District Manager approval, 
however based upon BSEE experience, these revisions would minimize the 
amount of unnecessary rig operational time waiting for separate BSEE 
approval of the successful pressure test where BSEE has already 
approved the relevant testing and streamline BSEE approval of 
associated operations. These revisions would be applicable only if the 
actions are appropriately planned for and already approved in the 
associated permit. The pressure tests are conducted to help verify 
casing integrity. BSEE would also make a minor revision to this 
paragraph to provide that the calculations are used to ``indicate'' not 
``show'' that the well's integrity is above the minimum safety factors. 
This change is necessary because the calculations do not guarantee or 
``show'' integrity; they are used as a way to help determine well 
integrity. Using the word ``indicate'' removes the definitive statement 
or assumption that the calculations demonstrate well integrity. BSEE 
does not expect these revisions to decrease safety because, by 
approving the test pressure described in the APD, BSEE has determined 
that any test that successfully meets the pre-approved test pressure 
for that casing design is sufficient. Therefore, requiring an 
additional, subsequent approval of the test results before operations 
may be resumed is redundant and unnecessary and does not improve 
safety. BSEE will

[[Page 22137]]

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

What additional safety measures must I take when I conduct operations 
on a platform that has producing wells or has other hydrocarbon flow? 
(Sec.  250.723)

    This rulemaking would revise this section by removing the phrase 
``or lift boat.'' This revision would mostly impact paragraph (c)(3) 
which requires a shut-in of all producible wells located in the 
affected wellbay when a lift boat moves within 500 feet of the platform 
until the lift boat is secured in place and ready to begin operations. 
Removing the references to lift boats from these requirements would 
minimize the number of unnecessary well shut-ins and delayed 
production. Since the original WCR, BSEE reevaluated the lift boat 
activities, and determined that the vast majority of lift boats used on 
the OCS are relatively small when compared to the size of a mobile 
offshore drilling unit (MODU) and would not have the same operational 
impacts and potential risks as a MODU. BSEE is considering the effects 
of the size of lift boats for potential future rulemakings, and may 
gather additional information and provide guidance on a case-by-case 
basis for any lift boats comparable in size to a MODU.

What are the real-time monitoring requirements? (Sec.  250.724)

    This rulemaking would revise this section by removing many of the 
prescriptive real-time monitoring requirements and moving towards a 
more performance-based approach. BSEE would still require the ability 
to gather and monitor real-time well data using an independent, 
automatic, and continuous monitoring system capable of recording, 
storing, and transmitting data for the BOP control system, the well's 
fluid handling system on the rig, and the well's downhole conditions 
with the bottom hole assembly tools (if any tools are installed). Based 
upon BSEE's evaluation of RTM since the publication of the original 
WCR, BSEE determined that the prescriptive requirements for how the 
data is handled may be revised to allow company-specific approaches to 
handling the data while still receiving the benefits of RTM. BSEE is 
specifically soliciting comments if there are alternative ways to meet 
RTM provisions or if there are alternative means to meet the purposes 
of RTM. BSEE would completely remove existing paragraph (b) with its 
associated prescriptive requirements, and redesignate existing 
paragraph (c) as paragraph (b), with minor revisions to shift certain 
prescriptive elements to be more performance-based. BSEE would continue 
to require the items discussed in existing paragraph (c) in an RTM 
plan. BSEE expects operators to explain how they would carry out the 
requirements of the RTM plan on an individual company basis. BSEE 
revised this section to outline the RTM requirements and allow the 
operators to determine how they would fulfill those requirements.
    BSEE is specifically soliciting comments about the appropriateness 
of utilizing RTM for workover, completion, and decommissioning 
operations, or whether RTM requirements should be limited to drilling 
operations. Please provide reasons for your position and any applicable 
associated data.

What are the general requirements for BOP systems and system 
components? (Sec.  250.730)

    BSEE proposes to revise paragraph (a) by removing ``excluding 
casing shear'' and replacing ``at all times'' with ``in the event of 
flow due to a kick.'' Based upon BSEE experience with the 
implementation of the original WCR, BSEE is removing the phrase 
``excluding casing shear'' because it is not necessary in this context. 
The requirements of this sentence are applicable to the entire BOP 
system, including the casing shear. BSEE expects the BOP system as a 
whole to be capable of closing and sealing the wellbore. BSEE also 
proposes to clarify that the BOP system must be able to close and seal 
the wellbore in the event of flow due to a kick. BSEE would make this 
change to codify BSEE guidance on the original WCR posted on the BSEE 
website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule. BSEE understands mechanical and operational design 
limits of equipment and expects operators to ensure ram closure time 
and sealing integrity before exceeding those operational and mechanical 
limits.
    Paragraph (b) would be revised to clarify that BSEE expects the use 
of ``applicable'' OEM recommendations for the design, fabrication, 
maintenance, and repair of BOP systems, as well as personnel training 
in their use. The proposed revision to include ``applicable'' is 
necessary because some OEMs may not have specific recommendations for 
every item required by this paragraph. BSEE expects operators to follow 
OEM recommendations to the extent relevant recommendations exist.
    This rulemaking would also revise the failure reporting 
requirements in paragraph (c) to codify BSEE guidance and current 
practice. The failure reporting references to American National 
Standards Institute (ANSI)/API Specs 6A and 16A would be removed 
because the failure reporting process outlined in those standards is 
redundant to API Standard 53 and the remaining requirements of this 
section. Revisions to this paragraph would include clarification on 
submitting failure data and reports to BSEE, unless BSEE has designated 
a third party to collect the data and reports, and ensuring that an 
investigation and failure analysis are started within 120 days. BSEE 
reevaluated the timeframes set forth in the original WCR regarding 
performing the investigation and failure analysis and determined that 
certain operations would not be able to meet the original timeframes. 
Accordingly, BSEE proposes to require that the investigation and 
failure analysis be started within 120 days of the failure. BSEE would 
then provide a 120 day timeframe to complete the investigation and 
failure analysis once they have started.
    Based upon the unknown situations that could arise around the 
completion of the failure analysis and availability of the equipment, 
BSEE is specifically soliciting comments about whether specifying a 
completion date for the failure analysis is appropriate and if so 
whether 120 days from the commencement of the analysis is appropriate. 
Please provide reasons for your position and any applicable associated 
data.
    BSEE proposes to add new paragraph (c)(4) to explain that BSEE may 
designate a third party to collect failure data and reports on behalf 
of BSEE, and failure data and reports must be sent to the designated 
third party. The changes regarding submittal of the reports to BSEE or 
designated third party would codify BSEE guidance on the original WCR 
posted on the BSEE website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
    BSEE is currently using www.SafeOCS.gov as the designated third 
party. Reporting instructions are on the SafeOCS website at: 
www.SafeOCS.gov. Reports submitted through www.SafeOCS.gov are 
collected and analyzed by the Bureau of Transportation Statistics (BTS) 
and protected from release under the Confidential Information 
Protection and Statistical Efficiency Act (CIPSEA), which permits BTS 
to confidentially

[[Page 22138]]

handle and store reported information.\4\ Information submitted under 
this statute also is protected from release to other government 
agencies, Freedom of Information Act (FOIA) requests, and certain 
records requests.
---------------------------------------------------------------------------

    \4\ OMB defines BTS as one of 14 CIPSEA statistical agencies; 
BSEE is not a CIPSEA statistical agency. (``Implementation Guidance 
for [CIPSEA]''); 72 FR 33362 at 33368 (June 15, 2007).
---------------------------------------------------------------------------

    BSEE also proposes to revise paragraph (d) by removing the 
reference to an incorrect document incorporated by reference and 
replacing it with the correct document incorporated by reference. The 
original WCR requires that BOP stacks must be manufactured pursuant to 
a quality management system certified by an entity that meets the 
requirements of ISO 17011. The correct reference is ISO 17021. This was 
an error in the original WCR, and BSEE would make this correction in 
keeping with the WCR guidance posted on the BSEE website at https://
www.bsee.gov/guidance-and-regulations/regulations/well-control-rule

What information must I submit for BOP systems and system components? 
(Sec.  250.731)

    This rulemaking would revise the information submitted to BSEE 
pursuant to paragraph (a)(5) by replacing ``to achieve an effective 
seal of each ram BOP'' with ``to close each ram BOP.'' This revision 
would affect information submitted to BSEE and, based upon BSEE 
experience with the implementation of the original WCR, would more 
accurately reflect the control system and regulator control setting 
requirements of API Standard 53. BSEE does not expect these revisions 
to decrease safety. BSEE has determined that these revisions would be 
adequate to meet the API Standard 53 requirements for control systems 
to ensure that each ram BOP can be effectively sealed, as the original 
WCR language intended.
    This section would also be revised by removing the BAVO 
verification requirements in existing paragraphs (d) and (f). The BAVO 
verifications required by existing paragraphs (d)(1) and (d)(3) were 
redundant to the verifications required by paragraph (c); however, the 
verifications required by current paragraph (d)(2) are still necessary 
and BSEE therefore proposes to add them to revised paragraph (c). BSEE 
proposes to remove paragraph (f) because the Report that is the subject 
of that paragraph is proposed for elimination in connection with 
proposed revisions to Sec.  250.732(d) (see section-by-section 
discussion of that provision for further explanation). The independent 
third party verifications under paragraph (c) help ensure that the BOP 
is fit for service at each specific well. BSEE proposes to revise this 
section by replacing references to a BAVO with references to an 
independent third party that meets the requirements of Sec.  
250.732(b). For a discussion of the proposed shift from BAVOs to 
independent third parties, see the section-by-section discussion of 
Sec.  250.732.

What are the independent third party requirements for BOP systems and 
system components? (Sec.  250.732)

    BSEE proposes to completely revise this section by removing all 
references to a BAVO and, where appropriate, replacing those references 
with an independent third party. This change would also be made in 
appropriate locations throughout subpart G where BAVOs are referenced, 
as noted throughout the applicable section-by-section discussions. This 
change would not impact safety because independent third parties have 
been utilized as a long-standing industry practice to carry out 
certifications and verifications similar to those which a BAVO would 
do. BSEE expected most of the companies or individuals currently being 
used as independent third parties to apply to become a BAVO. Since the 
publication of the original WCR, BSEE has increased its interaction 
with the independent third parties to better understand how they 
operate and carry out certifications and verifications. BSEE has 
determined that, if as expected the majority of BAVOs would be drawn 
from the existing independent third parties who would continue to 
conduct the same verifications, additional BSEE oversight and submittal 
to become a BAVO would be unnecessary and the BAVO system implemented 
by the WCR would increase procedural burdens and costs without giving 
rise to meaningful improvements to safety or environmental protection. 
If BSEE becomes aware of any performance issues with an independent 
third party, there are still options for BSEE to address the issues 
(e.g., through a SEMS audit, or verifications through the permitting 
process). Based upon the BSEE determination to remove the BAVOs, BSEE 
would revise the section heading to reflect the change from a BAVO to 
an independent third party, remove paragraphs (a)(1) and (a)(3), and 
replace all remaining BAVO references with references to an independent 
third party. The independent third party qualifications in existing 
paragraph (a)(2) would remain in this section as new paragraph (b).
    This proposed rule would remove the requirements to verify that 
testing was performed on the outermost edges of the shearing blades of 
the shear ram positioning mechanism, found in current paragraph 
(b)(1)(iv). This would align the verification requirements with BSEE's 
proposal to remove the centering mechanism required in existing Sec.  
250.734(a)(16) that is the subject of this verification (see section-
by-section discussion of Sec.  250.734 for discussion of those 
changes). BSEE does not expect this revision to decrease safety since 
it simply aligns this testing requirement with the proposed change to 
Sec.  250.734(a)(16). As explained in connection with that proposed 
change, BSEE believes that, since newer shearing blades can center 
pipe, it is unnecessary to require a pipe centering mechanism. In 
addition, the shear rams are capable of shearing along the entire blade 
surface area without specifically requiring testing on the outermost 
edges. BSEE also proposes to remove from existing paragraph (b)(1)(i) a 
vestigial reference to a compliance deadline that has already passed. 
This is merely an administrative revision.
    BSEE would also revise existing paragraph (b)(2)(ii) to proposed 
paragraph (a)(2)(ii) by changing the testing facilities' verification 
pressure testing hold time demonstration from 30 minutes to 5 minutes. 
This revision would allow the continued use of the established 
historical data to help verify the pressure holding time. BSEE is 
proposing to revise this paragraph after consideration and reevaluation 
of the original WCR and historical data along with the longstanding 
successful practical application of that data. BSEE does not expect 
this revision to decrease safety because the shear ram testing 
timeframes of five minutes in a lab have been well established, and 
BSEE believes the historical data indicates that five minutes is 
adequate to demonstrate effective sealing. BSEE has increased its 
interaction with testing facilities and is continuing to evaluate any 
additional testing protocols. BSEE will continue to interact with 
testing facilities to ensure that new protocols or test data do not 
show a need for a longer test period.
    BSEE also proposes to make a minor revision to paragraph (c) to 
update an incorrect citation--the referenced definition of High 
Pressure High Temperature (HPHT) environments is found in Sec.  
250.804(b) rather than Sec.  250.807(b), as stated in the current 
regulations. This revision is administrative in nature and ensures

[[Page 22139]]

that the appropriate citations are correctly cross referenced.
    With the removal of the BAVO references, BSEE is also proposing to 
remove the mechanical integrity assessment (MIA) report requirements 
from paragraph (d). This MIA report was a function of the BAVO. Based 
on discussions regarding the MIA report after publication of the 
original WCR, BSEE determined that the information contained within the 
MIA report was redundant with the BOP equipment capability 
verifications required by Sec.  250.731. The independent third party 
verifications in Sec.  250.731 help ensure that the BOP systems have 
the appropriate capabilities and are fit for service for a specific 
well and location.

What are the requirements for a surface BOP stack? (Sec.  250.733)

    This rulemaking would revise paragraph (a)(1) by removing the 
reference to an extended time for compliance with exterior control line 
shearing requirements under the original WCR, which BSEE anticipates 
will have run and no longer warrant reference in the regulations by the 
time a final rule is promulgated. BSEE also proposes to remove the 
requirement to have an alternative cutting device used for shearing 
electric-, wire-, or slick-line if your blind shear rams are unable to 
cut and seal under maximum anticipated surface pressure (MASP). The 
alternative cutting device is no longer necessary because the currently 
commercially available shear rams have increased design capabilities, 
which are capable of shearing these types of lines. BSEE is aware of 
concerns regarding the removal of the alternative cutting device 
option. Therefore, BSEE is considering other options in the final rule, 
such as keeping the alternative cutting device provisions in the 
regulations or extending the compliance date to allow the use of the 
alternative cutting devices until a more appropriate date when the 
surface stack shear rams can be upgraded to shear electric-, wire-, or 
slick-line.
    BSEE is specifically soliciting comments about the effectiveness of 
using an alternative cutting device and whether BSEE should continue to 
allow its use. Additionally, BSEE is also specifically soliciting 
comments on how long it would take for surface stack shear rams to be 
upgraded to shear electric-, wire-, or slick-line. Please provide 
reasons for your position and any applicable associated data.
    BSEE is also proposing to revise paragraph (b)(1) to extend the 
compliance date from April 29, 2019 to April 29, 2021, to correspond 
with the same requirements for subsea BOP stacks. This revision would 
align the dual shear ram requirements for surface BOPs installed on 
floating facilities and subsea BOPs. Aligning these dates would help 
minimize confusion between the conflicting effective dates of the 
parallel requirements for surface BOPs used on floating facilities and 
subsea BOPs. This revision would also allow more time to install the 
dual shear rams in a surface BOP on a new floating facility and 
potentially minimize the technical and economic challenges prior to 
installation.
    New paragraph (e) would be added to clarify the minimum surface BOP 
system requirements for well-completion, workover, and decommissioning 
operations where estimated well pressures are low. The provisions in 
this proposed paragraph were inadvertently removed from the regulations 
through the original WCR and are consolidated from Sec. Sec.  250.516, 
250.616, and 250.1706 of the regulations as they existed before the 
original WCR. BSEE is proposing minor revisions to the original 
language to conform to the applicable operations covered under revised 
Subpart G and to update cross-referenced citations. When BSEE developed 
the original WCR, it attempted to consolidate all of the BOP 
requirements from Subparts D, E, F, and Q, but in doing so 
inadvertently removed the requirements of this paragraph. The 
provisions in this paragraph would provide flexibility to utilize 
appropriate configurations and capabilities for surface BOP stacks 
where estimated well pressures are low (e.g., an end of life well).

What are the requirements for a subsea BOP system? (Sec.  250.734)

    BSEE proposes to revise paragraph (a)(1)(ii) by clarifying that a 
``combination of the'' shear rams must be capable of shearing all the 
items specified in the paragraph. This revision would better align the 
functionality of the BOP system with API Standard 53 and proposed Sec.  
250.730(a). Based upon BSEE experience with the implementation of the 
original WCR, BSEE is aware that certain casing shears still have 
difficulty shearing electric-, wire-, or slick-line, while certain 
blind shear rams have difficulties shearing larger casing sizes. This 
proposed revision would provide the operators flexibility for how they 
utilize the BOP system and components for operations while still 
ensuring all critical shearing capabilities. This would not impact 
safety because BSEE would still require the capability to shear at any 
point along the tubular body of any drill pipe (excluding tool joints, 
bottom-hole tools, and bottom hole assemblies such as heavy-weight pipe 
or collars), workstring, tubing and associated exterior control lines, 
appropriate area for the liner or casing landing string, shear sub on 
subsea test tree, and any electric-, wire-, slick-line in the hole. 
BSEE expects the operators to better evaluate how the BOP system, 
including both shear rams, would function together to comply with the 
required shearing capabilities. The proposed rule would also revise 
paragraph (a)(1)(ii) by removing references to extended times for 
compliance with certain shearing requirements under the original WCR, 
which BSEE anticipates will have run and no longer warrant reference in 
the regulations by the time a final rule is promulgated.
    This rulemaking would revise the accumulator requirements in 
paragraph (a)(3) to better align with API Standard 53. BSEE would 
remove the reference to the subsea location of the accumulator 
capacity. BSEE understands that the accumulator system works together 
with the surface and subsea accumulator capacity to achieve full 
functionality, and BSEE determined that it was unnecessary to 
specifically identify only subsea requirements when the entire system 
is covered within API Standard 53. BSEE does not expect these revisions 
to reduce safety. The requirements to operate the key components of the 
BOP subsea will remain the same. This revision helps reduce the non-
critical accumulator capacity on the BOP stack subsea, but would not 
affect safety of the critical components. Adding subsea accumulator 
bottles increases weight and size, which could have a negative impact 
on the stability and functionality of existing facilities by exceeding 
the operational or mechanical design limits of the wellhead and BOP 
systems.
    Paragraph (a)(3)(i) would be revised by clarifying that the 
accumulator capacity must be sufficient to close each required shear 
ram, ram locks, one pipe ram, and disconnect the LMRP. During a well 
control event, the most critical functions would be to close the BOP 
components and seal the well. This revision would also align the 
requirements with the intent of the API Standard 53 request for 
information finalized after the original WCR.
    Paragraph (a)(3)(ii) would be revised to clarify that the 
accumulator capacity must have the capability to perform the ROV 
functions within the required times outlined in API Standard 53 with 
ROVs or flying leads. Based upon BSEE experience with the 
implementation of the original WCR, BSEE is proposing to

[[Page 22140]]

revise this paragraph not only to better align with API Standard 53, 
but also to account for the technological advancements in ROV 
capabilities and ROV standardization to meet the appropriate BOP 
closing times via an ROV. Many of these advancements have taken place 
after publication of the original WCR. BSEE is aware of operators 
currently using high flow rate ROVs to meet the BOP component closing 
times of API Standard 53.
    Paragraph (a)(3)(iii) would be revised by removing the mention of 
``dedicated'' bottles and allowing bottles to be shared among emergency 
and secondary control system functions to secure the wellbore. This 
revision would further align the accumulator capacity requirements with 
API Standard 53 and account for the appropriate number of accumulator 
bottles on the subsea BOP stack. This revision would increase operator 
flexibility to utilize the appropriate accumulator capacity to perform 
the necessary emergency functions. Through the implementation of the 
original WCR, BSEE was able to better evaluate the effects of the 
original WCR accumulator requirements impacting subsea BOP space and 
weight limitations. This revision would help ensure that the regulatory 
requirements do not exceed the operational or mechanical design limits 
of the wellhead and BOP systems, and would help minimize risks 
associated with approaching those design limits.
    This rulemaking would revise paragraph (a)(4) by removing the term 
``opening'' and adding reference to the ROV function response times 
outlined in API Standard 53. After publication of the original WCR, the 
API Standard 53 committee clarified the definition of ``operate'' 
critical functions to include ``close'' only and not to include 
``open.'' Removal of the ROV open function would limit the ability for 
well intervention after the well has already been secured; however, it 
would not affect or decrease the ability for the ROV to close the 
required components for well control purposes. During a well control 
event, the most critical functions would be to close the BOP components 
and seal the well. This revision would minimize the required number of 
equipment alterations to the subsea ROV panel and associated control 
systems and improve consistency with similar requirements in API 
Standard 53. The open function on the ROV panel may also be unnecessary 
due to technological advancements in well intervention capabilities 
once the well has already been secured. This paragraph would also be 
revised by requiring the ROV to function the appropriate BOP component 
within the required response time outlined in API Standard 53. BSEE is 
proposing to revise this paragraph not only to better align with API 
Standard 53, but also to account for the recent technological 
advancements in ROV capabilities and ROV standardization to meet the 
appropriate BOP closing times via an ROV. BSEE is aware that operators 
currently use high flow rate ROVs to meet the BOP component closing 
times of API Standard 53.
    BSEE would also update the incorporated reference to API RP 17H to 
a newer edition in Sec.  250.198(h)(94). There is a conflict between 
the API RP 17H first edition referenced in the original WCR and the API 
Standard 53 ROV requirements. The second edition of API RP 17H 
eliminates the conflict between the first edition and API Standard 53. 
BSEE would incorporate by reference the second edition of API RP 17H to 
ensure the appropriate methods are utilized to comply with the API 
Standard 53 ROV closure timeframes of 45 seconds. One of the main 
differences between the first edition and second edition of this 
recommended practice is that the second edition includes provisions on 
high flow Type D 17H hot stabs.
    This rulemaking would also revise paragraph (a)(6)(iv) by 
clarifying that the autoshear/deadman functions must close at a minimum 
two shear rams in sequence, not every emergency function. Closing two 
shear rams in sequence may not be advantageous for certain emergency 
disconnect system (EDS) functions. Depending upon the rig operations, 
operators develop different EDS modes that would function different BOP 
components at appropriate times. The selection of the EDS mode and the 
specific sequencing of emergency functions should be developed by the 
operator based on safety considerations and an operational risk 
assessment. BSEE would make this change to codify BSEE guidance on the 
original WCR posted on the BSEE website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
    BSEE would revise paragraph (a)(16) by removing references to the 
centering mechanism and the ability to mitigate compression of the pipe 
between the shear rams in paragraphs (i) and (ii), respectively. Based 
upon BSEE experience with the implementation of the original WCR and 
increased interactions with OEMs of shearing components, BSEE would 
remove these paragraphs based upon a better understanding of the 
technological advancements of available shearing capabilities to 
accomplish the same goals outlined in these paragraphs. Many of the 
shear ram designs have improved the shearing capabilities to help 
ensure the shearing is conducted on the appropriate shearing area of 
the shear blades. This is commonly done by shaping the shear ram 
cutting blades in a ``V'' or ``W'' pattern to help center the pipe as 
it shears, as well as to increase the blade face surface area to ensure 
there are no areas that cannot shear the pipe in the well. BSEE is also 
proposing to remove paragraphs (a)(6)(v) and (a)(6)(vi) based upon a 
better understanding of the third party verifications and documentation 
of the shearing requirements as outlined in current Sec.  250.732(b). 
BSEE does not expect these revisions to decrease safety because these 
newer designed shear rams are off the shelf available components that 
can be swapped with current components. BSEE believes that operators 
will continue to substitute new components for old ones to comply with 
the still-required increased shearing capability provisions of the 
original WCR. BSEE is aware of many technological advancements in 
shearing ram designs and capabilities. BSEE expects the shear rams to 
shear pipe or wire in any position within the wellbore; however, BSEE 
is specifically soliciting comments about the effectiveness of 
requiring shear rams to center pipe or wire while shearing, or 
requiring shear rams to have the capability to shear any pipe or wire 
in the hole without a separate centering mechanism. Another option BSEE 
is considering is retaining the centering mechanism requirements, but 
expressly providing that the shear rams with these capabilities satisfy 
the requirements. Please provide reasons for your position and any 
applicable associated data.
    This rulemaking would revise paragraph (b)(1) by replacing the BAVO 
references with references to an independent third party. For a 
discussion of the general shift from BAVOs to independent third 
parties, see the section-by-section discussion of Sec.  250.732.
    BSEE would also revise paragraph (b)(2), redesignate existing 
paragraph (b)(3) as (b)(4), and add new paragraph (b)(3) to include 
provisions for testing the applicable BOP or LMRP upon relatch to the 
well. The original WCR did not address this provision, however based 
upon BSEE experience, these revisions would codify longstanding BSEE 
policy and provide clarity for testing when an operator has returned to 
the location and relatched the BOP or LMRP to the well. These tests 
help confirm that the BOP or LMRP is

[[Page 22141]]

properly functional prior to resuming operations after being removed.

What associated systems and related equipment must all BOP systems 
include? (Sec.  250.735)

    This proposed rule would revise paragraph (a) by clarifying that 
the accumulator system must have the fluid volume capacity and 
appropriate pre-charge pressures in accordance with API Standard 53. 
BSEE would revise this section to provide consistency with the API 
Standard 53 and conform to the other proposed accumulator system 
revisions in Sec.  250.734. This revision would not materially alter 
the requirements of this section, which are already based upon API 
Standard 53. An accumulator system is necessary to provide the fluid 
and pressure to operate desired BOP functions. API Standard 53 outlines 
the pre-charge pressure calculations in Annex C and additional 
requirements for the accumulator system pressures in the drawdown 
tests.

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

    This rulemaking would revise paragraph (d)(5) by including 
equipment requirements for the safety valve when running casing with a 
subsea BOP. This revision would specify that the safety valve must be 
available on the rig floor if the length of casing being run exceeds 
the water depth, which would result in the casing being across the BOP 
stack and the rig floor prior to crossing over to the drill pipe 
running string. Based upon BSEE experience with the implementation of 
the original WCR, the substance of this revision is currently 
incorporated into every subsea well permit approval as a standard 
condition. This revision would provide clarity and consistency 
throughout BSEE permitting and minimize the number of alternate 
procedure or equipment requests submitted to BSEE.

What are the BOP system testing requirements? (Sec.  250.737)

    This rulemaking would revise paragraph (b) to clarify the BOP 
system pressure testing requirements. These revisions would include 
clarification that the test rams and non-sealing shear rams do not need 
to be pressure tested, and this would not impact safety because the 
non-sealing shear rams are not pressure holding components and the test 
ram is an inverted ram that is not utilized for well control purposes. 
Paragraph (b)(2) would be revised to add in the current BSEE policy for 
conducting the high-pressure test for specific components. For example, 
some of the revisions would include specific procedures and testing 
parameters for initial equipment pressure testing and also include the 
provisions for subsequent pressure testing on the same equipment. Since 
the publication of the original WCR, BSEE received many questions from 
operators regarding the operational application of the current pressure 
testing requirements. This proposed revision would codify BSEE policy 
and provide clarity and consistency for permitting throughout the 
Regions and Districts.
    In this proposed rule, BSEE would also revise paragraphs (d)(2) and 
(d)(3) by removing the requirement to submit test results to BSEE where 
BSEE is unable to witness testing. Based upon BSEE experience with the 
implementation of the original WCR, these revisions would significantly 
reduce the number of submittals to BSEE and minimize the associated 
burden for BSEE to review those submittals. If BSEE is unable to 
witness the testing, BSEE still has access to the testing documentation 
upon request in accordance with Sec. Sec.  250.740, 250.741, and 
250.746.
    Paragraph (d)(3)(iv) would be revised by removing ``test and[.]'' 
BSEE would remove this term to minimize confusion regarding 
verification and testing. In this instance, verification of closure 
qualifies as testing the ROV functions. The purpose of the stump test 
is to help ensure the BOP components and control systems can function 
properly before being utilized on a well.
    BSEE would revise paragraph (d)(3)(v) to clarify that pressure 
testing of each ram and annular on the stump test is only required 
once. This revision would help ensure that the testing of BOP 
components during stump testing would limit unnecessarily duplicative 
pressure testing on each ram or annular. BSEE would also make this 
change to codify BSEE guidance on the original WCR. The purpose of the 
stump test is to help ensure the BOP components and control systems can 
function properly before being utilized on a well. It is unnecessary to 
pressure test a ram or annular multiple times during stump testing if 
that component has already been successfully pressure tested, verifying 
proper functionality. This revision would help limit the risk 
associated with component wear.
    Paragraph (d)(4)(i) would be revised to clarify that the initial 
subsea BOP test on the sea floor would need to ``begin'' within 30 days 
of the stump test. BSEE receives many questions about the timing of the 
initial subsea test and, as written, the regulation was ambiguous 
regarding exactly what needed to occur within the 30 days. Based upon 
its experience with the implementation of the original WCR, BSEE 
proposes this revision to clarify that the testing has to begin within 
30 days. BSEE wants to ensure that the time between the stump testing 
and the initial subsea test is minimal to help ensure that all of the 
BOP components can properly function upon installation on the well.
    Paragraph (d)(4)(iii) would be revised to include annulars in the 
pressure testing requirements of paragraphs (b) and (c) of this 
section. This revision would not alter the current testing requirements 
for annulars, but based upon BSEE experience with the implementation of 
the original WCR, would provide clarity for where to find them.
    Paragraph (d)(4)(v) would be revised to clarify the initial subsea 
pressure testing requirements to confirm closure of the selected ram 
through an ROV hot stab. This revision would require the operator to 
confirm closure through a 1,000 psi pressure test held for 5 minutes. 
This revision would codify BSEE policy for pressure testing the 
selected ram through the ROV hot stabs. Based on BSEE experience during 
the implementation of the original WCR, BSEE has concluded that testing 
to higher pressures is not necessary for this circumstance because the 
intended purpose of this test is to verify operability of the ROV hot 
stab to close the selected ram. Selected rams will be pressure tested 
according to other regularly required pressure testing intervals. This 
revision would save rig operational time by reducing the amount of time 
required to conduct the pressure test, minimize the risk associated 
with wear of the BOP components, and eliminate associated alternate 
procedure requests.
    Existing paragraph (d)(4)(vi) would be removed because the testing 
requirements of the selected ram would now be covered under proposed 
paragraph (d)(4)(v).
    BSEE would revise paragraph (d)(5) by clarifying the alternating 
testing schedules of control stations and pods. These revisions would 
ensure that operators develop a testing schedule that allows for 
alternating testing between the control stations, and also between the 
pods for subsea BOPs. The intended result of alternating the testing is 
to ensure that each control station, and each pod for subsea, can 
properly function all required BOP components. Based on BSEE experience 
during the implementation of the original WCR,

[[Page 22142]]

BSEE has concluded that these revisions would help ensure BOP 
functionality while not inadvertently requiring unnecessarily 
duplicative testing. This revision would save rig operational time by 
reducing the number of unnecessary duplicate tests, and minimize the 
risk associated with wear of the BOP components functioned during 
testing.
    Paragraph (d)(12)(iv) would be revised by clarifying that, during 
the deadman test on the seafloor, operators are not required to 
indicate the discharge pressure of the subsea accumulator throughout 
the entire test. These revisions would require that the remaining 
pressure be documented at the end of the test, to help verify the 
proper accumulator settings required to function the specific critical 
BOP components.
    Paragraph (d)(12)(vi) would be revised to clarify the pressure 
testing requirements of the original WCR, to confirm closure of the 
BSR(s) during the autoshear/deadman and EDS testing. This revision 
would require confirmation of closure through a 1,000 psi pressure test 
held for 5 minutes. Based upon BSEE experience with the implementation 
of the original WCR, this revision would codify BSEE policy for 
autoshear/deadman and EDS pressure testing of the BSR(s). Testing to 
higher pressures is not necessary for this circumstance because the 
BSR(s) will be pressure tested according to other regularly required 
pressure testing intervals. This revision would save rig operational 
time by reducing the amount of time required to conduct the pressure 
test, and minimize the risk associated with wear of the BOP components.
    BSEE proposes to add paragraph (d)(13) setting forth exceptions for 
pressure testing the choke and kill side outlet valves. Since 
publication of the original WCR, BSEE has received many questions from 
operators regarding the operational application of the current pressure 
testing requirements. This addition would codify BSEE policy and 
provide consistency for permitting throughout the Regions and Districts 
without meaningfully reducing safety or environmental protection.

What must I do in certain situations involving BOP equipment or 
systems? (Sec.  250.738)

    This rulemaking would revise paragraphs (b), (i), (m), and (o) by 
replacing the references to BAVOs with references to an independent 
third party throughout. For a discussion of the proposed shift from 
BAVOs to independent third parties, see the section-by-section 
discussion of Sec.  250.732.
    Paragraph (f) would be revised to clarify the testing requirements 
implemented by the original WCR necessary to verify the integrity of 
the affected casing ram or casing shear ram and connections. Based upon 
BSEE experience with the implementation of the original WCR, this 
revision would codify BSEE policy to allow the pressure testing to the 
test pressure of the BOP component above this ram as specified in the 
approved permit.
    Paragraph (m) would be revised to replace the term ``well-control 
equipment'' with ``circulating or ancillary equipment.'' This revision 
would eliminate confusion arising from the use of conflicting terms 
that may have different meanings throughout the regulations.

What are the BOP maintenance and inspection requirements? (Sec.  
250.739)

    BSEE proposes to revise paragraph (b) by replacing ``complete 
breakdown and detailed physical inspection'' with a ``major, detailed 
inspection,'' identifying examples of well control system components, 
replacing references to the BAVO with references to an independent 
third party, and replacing the requirement to have a BAVO present 
during each inspection with a requirement for an independent third 
party to review inspection results.
    Replacing ``complete breakdown and detailed physical inspection'' 
with a ``major, detailed inspection'' would correct the industry 
misconception, prevalent since the promulgation of the original WCR, 
that each component must be dismantled to its smallest possible part. 
This was never the intent behind this provision of the WCR, and these 
revisions would clarify BSEE's positions on the WCR requirement and 
resolve perceived ambiguities, without substantively altering the 
inspection requirement. BSEE would make this change to codify BSEE 
guidance on the original WCR posted on the BSEE website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule. 
BSEE also proposes to add references to examples of the well control 
system components requiring inspection to clarify the general reference 
in the original WCR.
    For a discussion of the proposed shift from BAVOs to independent 
third parties, see the section-by-section discussion of Sec.  250.732.
    BSEE would also remove the requirement for the BAVO to be present 
during each inspection and replace it with a requirement that an 
independent third party review the inspections results. BSEE expects 
the independent third party to review the documentation of the 
inspections to help ensure that the appropriate entities accurately and 
appropriately complete the activities. These reports would also help 
facilitate other required verifications that the BOP is fit for 
service, such as those required by Sec.  250.731. These revisions would 
ease the original WCR logistical and economic burdens of having the 
BAVO onsite at all times during all inspections.

What are the coiled tubing and snubbing requirements? (Sec.  250.750)

    The content of this proposed section was moved from current 
Sec. Sec.  250.616 and 250.1706. This section would consolidate some of 
the minimum BOP system component requirements for coiled tubing and 
snubbing operations. BSEE is proposing minor revisions to the original 
language to conform to the applicable operations covered under Subpart 
G. BSEE is also proposing to add paragraph (d) to conform snubbing unit 
testing with updated requirements.

Coiled Tubing Testing Requirements (Sec.  250.751)

    BSEE proposes to add this section to codify current BSEE policy 
regarding the coiled tubing testing and recording requirements. This 
addition would a reintroduce similar provisions that were inadvertently 
removed in the original WCR, consolidating elements from Sec. Sec.  
250.617 and 250.1707 of the regulations as they existed before the 
original WCR. Both sections are currently reserved. BSEE is proposing 
revisions to the original language to conform to the applicable 
requirements of Subpart G. For example, BSEE would not include in this 
section the provisions regarding testing of the coiled tubing 
connector, because the proposal would require that operators ``must 
test the coiled tubing unit in accordance with Sec.  250.737 paragraphs 
(a), (b), (c), (d)(9), and (d)(10)''. Section 250.737 requires testing 
of the system when installed and provides testing criteria. Identifying 
the connector testing in this section is not necessary because it is 
already covered by the testing requirements of Sec.  250.737.

Subpart Q--Decommissioning Activities

What are the general requirements for decommissioning? (Sec.  250.1703)

    This rulemaking would revise paragraph (b) to clarify that only 
packers or bridge plugs used as mechanical barriers are required to 
comply with ANSI/API Spec. 11D1. Based upon BSEE experience with the

[[Page 22143]]

implementation of the original WCR, this revision would codify BSEE's 
policy to ensure that the required mechanical barriers in a well are 
held to a higher standard than other common packers or bridge plugs 
used for various well specific conditions and completions design. 
Furthermore, BSEE is aware that certain packers and bridge plugs cannot 
meet the specifications of ANSI/API Spec. 11D1. This revision would 
minimize the number of alternate equipment requests submitted to BSEE. 
BSEE would also add that operators must have two independent barriers, 
one being mechanical, in the exposed center wellbore (e.g., this could 
be the tubing or casing depending on the well configuration) prior to 
removing the tree or well control equipment. This addition would codify 
BSEE policy and align the well decommissioning requirements with 
similar requirements from Sec. Sec.  250.720(a) and 250.1712(g). This 
addition would help ensure the well is properly secured before removal 
of the tree or well control equipment.

What decommissioning applications and reports must I submit and when 
must I submit them? (Sec.  250.1704)

    BSEE proposes to revise paragraph (g) by adding the requirements 
for submittal of the site clearance verification activity information 
in an Application for Permit to Modify (APM). The site clearance 
verification activity information would be removed from the end of 
operations report (EOR). Based on BSEE experience during the 
implementation of the original WCR, BSEE became aware of dual reporting 
of the same information and confusion about which permit or report 
should include the information. These revisions would better reflect 
current practice and limit redundant reporting.
    Paragraph (h) would be revised by adding the submittal of the 
decommissioning activity information, upon completion, in the EOR. 
Based upon BSEE experience with the implementation of the original WCR, 
these revisions would better reflect current practice and limit 
redundant reporting.

Coiled Tubing and Snubbing Operations (Sec.  250.1706)

    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.750. These revisions would 
help BSEE eliminate inconsistencies between similar requirements 
throughout different BSEE subparts by consolidating those requirements 
into Subpart G, which is applicable to drilling, completions, 
workovers, and decommissioning operations.

Must I notify BSEE before I begin well plugging operations? (Sec.  
250.1713)

    This section would be removed and reserved. Based upon BSEE 
experience with the implementation of the original WCR, BSEE determined 
that the submittal of the information required by this section is 
redundant with similar rig movement notification information required 
under Sec.  250.712.

To what depth must I remove wellheads and casings? (Sec.  250.1716)

    This rulemaking would revise paragraph (b)(3) by changing the water 
depth criteria for when BSEE may approve an alternate depth for removal 
of the wellhead or casing from 800 meters to 1000 feet. BSEE would 
include this new regulatory revision in order to codify longstanding 
BSEE policy established before the original WCR. At depths below 1,000 
feet, there is little risk of obstruction to other users of the OCS or 
its waters or contact with other equipment, and little risk of safety 
or environmental issues from removal to an alternate depth.

If I install a subsea protective device, what requirements must I meet? 
(Sec.  250.1722)

    BSEE proposes to revise paragraph (d) to direct the submittal of 
the trawl test report to the EOR rather than an APM. This revision 
would reflect current BSEE practice established before publication of 
the original WCR and help minimize redundant reporting. It would not 
affect the substance of the reporting requirement or the information 
BSEE receives, only the mechanism through which it is received.

III. Additional Comments Solicited

A. BOP Testing Frequency

    BSEE is requesting comments on whether the BOP testing interval 
should be 7 days, 14 days, or 21 days for all types of operations 
including drilling, completions, workovers, and decommissioning. BSEE 
is also requesting comments on the specific cost and operational 
implications of each testing interval to further its consideration of 
the issue.
    The industry and BSEE currently rely on function and hydrostatic 
tests to verify the performance of BOP equipment in the field. These 
tests have traditionally been the primary method of verifying the 
capability of in-service equipment.
    In recent years, the industry has raised concerns related to the 
benefits of pressure and functional testing of subsea BOPs when 
compared to the costs and potential operational issues. BSEE requests 
comments on the adequacy of the current functional and pressure test 
requirements in predicting the performance of this equipment in 
subsequent drilling operations. Under what circumstances or 
environments should the testing frequency be increased or decreased? 
BSEE is aware of potential technologies that may improve the 
operability and reliability of BOP systems. Are there additional 
technologies, processes, or procedures that can be used to supplement 
existing requirements and provide additional assurances related to the 
performance of this equipment?
    Please provide supporting reasons and data for your responses.

B. Economic Data

    The compliance costs and savings in the regulatory impact analysis 
(RIA) are BSEE's best estimates based on experience with the previous 
WCR, stakeholder comments, and communication with industry. BSEE is 
requesting comments related to the appropriateness and accuracy of the 
compliance costs and benefits identified in the RIA. Please provide 
supporting reasons and data for your responses.

IV. Procedural Matters

Regulatory Planning and Review (Executive Orders (E.O.) 12866, 13563, 
and 13771)

    Executive Order 12866 provides that the Office of Information and 
Regulatory Affairs within the OMB will review all significant rules. 
BSEE coordinated development of an economic analysis to assess the 
anticipated costs and potential benefits of the proposed rulemaking. 
OIRA has determined that it would have a positive annual effect on the 
economy of $100 million or more. The significant positive economic 
effect on the economy is the result of the proposed cost savings in 
this rule. BSEE estimates the amendments in this rulemaking would save 
the regulated industry $98.6 million annually over ten years 
(discounted at 7 percent).
    Executive Order 13563 reaffirms the principles of E.O. 12866 while 
calling for improvements in the Nation's regulatory system to promote 
predictability, to reduce uncertainty, and to use the best, most 
innovative, and least burdensome tools for achieving regulatory ends. 
The E.O. directs agencies to consider regulatory approaches that reduce 
burdens and maintain flexibility and freedom of choice for the public 
where these

[[Page 22144]]

approaches are relevant, feasible, and consistent with regulatory 
objectives. Executive Order 13563 emphasizes further that regulations 
must be based on the best available science and that the rulemaking 
process must allow for public participation and an open exchange of 
ideas. We have developed this rule in a manner consistent with these 
requirements.
    Executive Order 13771 requires Federal agencies to take proactive 
measures to reduce the costs associated with complying with Federal 
regulations. This proposed rule is expected to be an E.O. 13771 
deregulatory action. Details on the estimated cost savings of this 
proposed rule can be found in the rule's economic analysis. The cost 
savings for the regulatory clarifications, reduction in paperwork 
burdens, adoption of industry standards, and migration to performance-
based standards for select provisions constitute an E.O. 13771 
deregulatory action. BSEE also finds that the reduced regulated entity 
compliance burden would not increase the safety or environmental risks 
for offshore drilling operations.
    This rulemaking proposes to revise regulatory provisions in 30 CFR 
part 250, subparts D, E, F, G, and Q. BSEE has reassessed a number of 
the provisions in the original (1014-AA11) WCR rulemaking and proposes 
to rewrite some provisions as performance-based standards rather than 
prescriptive requirements. Other proposed revisions would reduce or 
eliminate parts of the paperwork burden, while providing the same 
levels of safety and environmental protection. BSEE sought the best 
available data and information to analyze the economic impact of the 
proposed changes. The Initial RIA (IRIA) for this rulemaking can be 
found in the https://www.regulations.gov/ docket (Docket ID: BSEE-2018-
0002). The IRIA indicates that the estimated overall cost savings to 
the industry over the next 10 years would exceed $900 million in 
nominal dollars.
    BSEE proposes to revise certain provisions of the original rule to 
support the goals of the regulatory reform initiatives while ensuring 
safety and environmental protection. BSEE has received additional 
information since the publication of 1014-AA11 and revisited several of 
the compliance cost assumptions in the economic analysis for the 2016 
1014-AA11 final rule. The proposed modifications to the BSEE compliance 
cost estimates in the 1014-AA11 analysis are primarily related to:
    (1.) Underestimating the cost for revising permits or reporting 
certain operations to the District Manager (Sec. Sec.  250.428 and 
250.722), and
    (2.) Underestimating both the number of subsea BOPs that would 
require modifications and the cost of those modifications under the 
1014-AA11 regulations (Sec.  250.734).
    The proposed revisions to existing ram and accumulator requirements 
for subsea BOPs (Sec.  250.734) represent the single largest cost 
savings provision in this proposed rule, yielding cost savings of $690 
million (nominal$). The proposed changes to Sec.  250.734 would better 
align the shear ram provisions with API Standard 53, revise the 
accumulator capacity requirements for subsea BOP stacks, and redefine 
shearing requirements.
    BSEE expects the proposed rule would reduce the regulatory burden 
on industry, and the proposed amendments would not negatively impact 
worker safety or the environment. BSEE proposes to provide industry 
flexibility, when practical, to meet the safety or equipment standards, 
rather than specifying the compliance method. For example, BSEE is 
proposing to eliminate the requirement that operators resubmit an 
Application for Permit to Drill (APD) in the event of planned mud 
losses or inadequate cement jobs. Instead, BSEE proposes to allow the 
operator to outline remedial actions to these scenarios in contingency 
plans included in the original approved APD. This revision would not 
change the operational responses to these events, and therefore will 
reduce the paperwork burden and expensive operational downtime without 
increasing drilling risks. Other changes would remove BOP stack 
certification requirements regarding design specifications and 
equipment conditions and replace the BAVO requirements for BOP systems 
and system components with independent third party requirements. The 
existing provisions are either duplicative or provide a more burdensome 
certification process than necessary. The proposed changes to the 
certification processes will continue to protect worker safety and the 
environment.
    The proposed Sec.  250.734 amendments would better define the BOP 
components functionality requirements, revise the requirements for ROV 
capability and functionality, and amend accumulator capacity 
requirements for subsea BOP stacks. This revision to the accumulator 
requirements would increase operator flexibility to utilize the 
appropriate accumulator capacity to perform the necessary emergency 
functions. Through the implementation of the original WCR, BSEE was 
able to better evaluate the effects of the original WCR accumulator 
requirements on subsea BOP space and weight limitations. After 
reevaluating the API 53 standards, BSEE agrees that certain 
prescriptive requirements in the current regulations are unnecessary 
and the proposed regulatory text revisions would align BSEE regulations 
with the performance standards in API Standard 53. The proposed Sec.  
250.734 revisions would also remove the prescriptive requirement that 
EDS emergency functions must close at a minimum two shear rams in 
sequence. This would allow the operator to select the appropriate EDS 
emergency function shearing sequence for the circumstances and would 
adopt the performance standard that the BOP system must be able to seal 
the wellbore. Furthermore, the accumulator capacity required in API 53 
is sufficient to actuate the BOP ram functions necessary to seal the 
well. This performance standard meets the intent of the 1014-AA11 well 
control rule without the prescriptive and unnecessarily burdensome 
requirements. The alignment of the accumulator volume requirements with 
industry standards would also provide additional safety benefits. The 
weight of the combined BOP and accumulator bottle package required by 
the original rule would be reduced with these proposed revisions. This 
reduction would avoid increased strain on rig handling systems and 
potentially avoid modifications on some rigs to accommodate the 
additional space and BOP handling requirements.
    The proposed Sec.  250.737 paragraph (d)(5) amendments would allow 
the operator to alternate tests between the two control stations rather 
than testing from both control stations on each test. Testing from both 
control stations on a weekly basis has been proven to wear the BOP 
components out at a faster rate than was expected when the original WCR 
was written. The proposed rule would return the regulations to pre-
1014-AA11 regulatory language in order to prevent the additional wear 
and tear on the BOP components. This change would align BSEE 
regulations with the industry testing standards.
    BSEE's estimate of the net total, annualized and discounted 
regulatory cost savings can be found in the following table.

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[GRAPHIC] [TIFF OMITTED] TP11MY18.008

    This rulemaking would reduce the burden imposed on society while 
ensuring continued safety and environmental protection. Additional 
information on the compliance costs, savings, and benefits can be found 
in the IRIA posted in the docket.
    BSEE has developed this proposed rule consistent with the 
requirements of E.O. 12866, E.O. 13563, and E.O. 13771. This proposed 
rule would revise multiple provisions in the current regulations with 
performance-based provisions based upon the best reasonably obtainable 
safety, technical, economic, and other information. Other redundant or 
unnecessary reporting requirements are proposed for elimination. BSEE 
proposes to provide industry flexibility, when practical, to meet the 
safety or equipment standards, rather than specifying the compliance 
method. Based on a consideration of the qualitative and quantitative 
safety and environmental factors related to the proposed rule, BSEE's 
assessment is that its promulgation would be consistent with the 
requirements of the applicable Executive Orders and the OCSLA.

Regulatory Flexibility Act and Small Business Regulatory Enforcement 
Fairness Act

    The Regulatory Flexibility Act, 5 U.S.C. 601-612, requires agencies 
to analyze the economic impact of proposed regulations when a 
significant economic impact on a substantial number of small entities 
is likely and to consider regulatory alternatives that will achieve the 
agency's goals while minimizing the burden on small entities. In 
addition, the Small Business Regulatory Enforcement Fairness Act of 
1996, 5 U.S.C. 601 note, requires agencies to produce compliance 
guidance for small entities if the rule has a significant economic 
impact. For the reasons explained in this analysis, BSEE believes the 
proposed rule may have a significant economic impact and, therefore, a 
regulatory flexibility analysis for the Proposed Rule is required by 
the RFA. The Initial Regulatory Flexibility Analysis (IRFA), which 
assesses the impact of this proposed rule on small entities, can be 
found in the Regulatory Impact Analysis (RIA) within the docket for 
this rulemaking.
    As defined by the Small Business Administration (SBA), a small 
entity is one that is ``independently owned and operated and which is 
not dominant in its field of operation.'' What characterizes a small 
business varies from industry to industry in order to properly reflect 
industry size differences. This proposed rule would affect lease 
operators that are conducting OCS drilling or well operations. BSEE's 
analysis shows this could include about 69 companies with active 
drilling or well operations. Of the 69 companies, 21 (30 percent) are 
large and 48 (70 percent) are small. Entities that would operate under 
this proposed rule are classified primarily under North American 
Industry Classification System (NAICS) codes 211120 (Crude Petroleum 
Extraction), 211130 (Natural Gas Extraction), and 213111 (Drilling Oil 
and Gas Wells). The proposed rule would indirectly impact OCS drilling 
companies that are the regulated entities classified under NAICS code 
21311 and this analysis focuses on the OCS oil and gas lessees and 
operators. For NAICS codes 211120, SBA defines a small company as 
having fewer than 1,251 employees.
    BSEE considers that a rule will have an impact on a ``substantial 
number of small entities'' when the total number of small entities 
impacted by the rule is equal to or exceeds 10 percent of the relevant 
universe of small entities in a given industry. BSEE's analysis shows 
that there are 48 small companies with active operations on the OCS, 
and all of these companies could be impacted by the proposed rule if 
conducting drilling or well operations. Therefore, BSEE expects that 
the proposed rule would affect a substantial number of small entities.
    Large companies are responsible for the majority of activity in 
deepwater, where subsea BOPs are used with floating MODUs. BSEE's 
first-order estimate for the rulemaking's small entity cost savings is 
proportional to the number of drilling rigs being operated or 
contracted by small companies (circa October 2017).
    This proposed rule is a deregulatory action; however, BSEE has 
evaluated possible costs and benefits and has estimated that there is 
an overall associated cost savings. BSEE has estimated the annualized 
cost savings by regulatory provision and then allocated those savings 
to small or large entities based on drilling/well activity (circa 
October, 2017; activity breakouts can be found in the IRFA). The 
proposed changes to Sec. Sec.  250.423, 250.734, and 250.737 paragraph 
(d)(5) would only apply to subsea BOPs and would yield cost savings 
that sum to $70,250,336. All remaining proposed changes would apply to 
all well operations or subsea/surface BOPs, and would yield cost 
savings that sum to $24,367,256. Using the share of small and large 
companies subject to each suite of provisions, we estimate that small 
companies would realize 15 percent of the cost savings from this 
rulemaking and large companies 85 percent. The allocation is displayed 
in the following table.

[[Page 22146]]

[GRAPHIC] [TIFF OMITTED] TP11MY18.009

    This proposed rule:
    a. Would have a positive economic effect on the economy of $100 
million or more. The cost savings will not materially affect the 
economy nationally or in any local area.
    b. Would not cause a major increase in costs or prices for 
consumers; individual industries; Federal, State, Tribal, or local 
governments; or regions of the nation. This proposed rule would have 
positive effects on OCS operators and is not anticipated to negatively 
impact oil, gas, and sulfur production or the cost of fuels for 
consumers.
    c. Would not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of 
U.S.-based enterprises to compete with foreign-based enterprises.
    BSEE has determined that this proposed rule is a major rule because 
it would have an annual effect on the economy of $100 million or more 
in at least one year of the 10-year period analyzed. The requirements 
apply to all entities operating on the OCS regardless of company 
designation as a small business. For more information on the small 
business impacts, see the IRFA in the RIA. Small businesses may send 
comments on the actions of Federal employees who enforce, or otherwise 
determine compliance with, Federal regulations to the Small Business 
and Agriculture Regulatory Enforcement Ombudsman, and to the Regional 
Small Business Regulatory Fairness Board. The Ombudsman evaluates these 
actions annually and rates each agency's responsiveness to small 
business. If you wish to comment on actions by employees of BSEE, call 
1-888-REG-FAIR (1-888-734-3247).

Unfunded Mandates Reform Act of 1995

    This proposed rule would not impose an unfunded mandate on State, 
local, or tribal governments or the private sector of more than $100 
million per year. The proposed rule would not have a significant or 
unique effect on State, local, or tribal governments or the private 
sector. A statement containing the information required by Unfunded 
Mandates Reform Act (2 U.S.C. 1531 et seq.) is not required.

Takings Implication Assessment (E.O. 12630)

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

Federalism (E.O. 13132)

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

Civil Justice Reform (E.O. 12988)

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

Consultation With Indian Tribes (E.O. 13175)

    BSEE is committed to regular and meaningful consultation and 
collaboration with tribes on policy decisions that have tribal 
implications. Under the criteria in E.O. 13175 and DOI's Policy on 
Consultation with Indian Tribes (Secretarial Order 3317, Amendment 2, 
dated December 31, 2013), we have evaluated this proposed rule and 
determined that it has no substantial direct effects on federally 
recognized Indian tribes.

National Technology Transfer and Advancement Act (NTTAA)

    BSEE complies with the National Technology Transfer and Advancement 
Act (NTTAA) (15 U.S.C. 3701 et seq.) requirement that an agency ``use 
standards developed or adopted by voluntary consensus standards bodies 
rather than government-unique standards, except where inconsistent with 
applicable law or otherwise impractical.'' (OMB Circular A-119 at p. 
13). BSEE also complies with the OFR regulations governing 
incorporation by reference. (See, 1 CFR part 51.) Those regulations 
also specify the process for updating an incorporated standard at Sec.  
51.11(a), and BSEE complies with those requirements, including seeking 
approval by OFR for a change to a standard incorporated by reference in 
a final rule.

Paperwork Reduction Act (PRA) of 1995

    This proposed rule contains collections of information that will be 
submitted to OMB for review and approval under the PRA, 44 U.S.C. 3501 
et seq. As part of its continuing effort to reduce paperwork and 
burdens on respondents, BSEE invites the public and other Federal 
agencies to comment on any aspect of the reporting and recordkeeping 
burden. If you wish to comment on the information collection (IC) 
aspects of this proposed rule, you may send your comments directly to 
OMB and send a copy of your comments to the Regulations and Standards 
Branch (see the ADDRESSES section of this proposed rule). Please 
reference 30 CFR part 250, subpart G, Blowout Preventer Systems and 
Well Control, 1014-0028, in your comments. To see a

[[Page 22147]]

copy of the information collection request submitted to OMB, go to 
http://www.reginfo.gov (select Information Collection Review, Currently 
Under Review); or you may obtain a copy of the supporting statement for 
the new collection of information by contacting the Bureau's 
Information Collection Clearance Officer at (703) 787-1607.
    The PRA provides that an agency may not conduct or sponsor, and a 
person is not required to respond to, a collection of information 
unless it displays a currently valid OMB control number. The OMB is 
required to make a decision concerning the collection of information 
contained in these proposed regulations 30-60 days after publication of 
this document in the Federal Register. Therefore, a comment to OMB is 
best assured of being fully considered if OMB receives it by June 11, 
2018. This does not affect the deadline for the public to comment to 
BSEE on the proposed regulations.
    The title of the collection of information for this rule is 30 CFR 
part 250, Blowout Preventer Systems and Well Control Revisions 
(Proposed Rulemaking). The proposed regulations concern BOP system 
requirements and maintaining well control, among others, and the 
information is used in BSEE's efforts to regulate oil and gas 
operations on the OCS to protect life and the environment, conserve 
natural resources, and prevent waste.
    Potential respondents comprise Federal OCS oil, gas, and sulfur 
operators and lessees. Responses to this collection of information are 
mandatory, or are required to obtain or retain a benefit; they are also 
submitted on occasion, daily and weekly (during drilling operations), 
monthly, quarterly, biennially, and as a result of situations 
encountered, depending upon the requirement. The IC does not include 
questions of a sensitive nature. The BSEE will protect proprietary 
information according to the Freedom of Information Act (5 U.S.C. 552) 
and DOI implementing regulations (43 CFR part 2), 30 CFR part 252, OCS 
Oil and Gas Information Program, and 30 CFR 250.197, Data and 
information to be made available to the public or for limited 
inspection.
    This proposed rule affects Applications for Permits to Drill (1014-
0025, expiration 4/30/20); Applications for Permits to Modify (1014-
0026, expiration 7/31/20); Subpart B (1014-0024, expiration 11/30/18); 
Subpart D (1014-0018, expiration 3/31/2021); Subpart E, (1014-0004, 
expiration 1/31/20); Subpart G (1014-0028, expiration 07/31/19); and 
Subpart Q, (1014-0010, expiration 1/31/20).
    The following is a brief explanation of how the proposed regulatory 
changes would affect the various subpart hour burdens:
     APD--Proposed Sec.  250.428 removes the requirement to 
resubmit an application for permit to drill (APD) in the event of 
planned mud losses, or remedial actions for inadequate cement jobs, if 
these circumstances are addressed in the original approved APD. 
Reductions will be shown during the renewal process (see Section by 
Section Discussion above).
    250.724(b): BSEE is proposing to eliminate the requirement to 
submit certification that you have a real-time monitoring plan that 
meets the criteria listed. This would decrease the hour burden by 109 
hours (see Section by Section Discussion above).
     Subpart A--Sec.  250.423 proposes rewording the 
requirement in a manner that would reduce the number of alternative 
procedure or equipment requests under Sec.  250.141. Reductions will be 
shown during the renewal process (see Section by Section Discussion 
above).
     Subpart B--Sec.  250.292(p) proposes to require less 
information to be submitted in the DWOP. Reductions will be shown 
during the renewal process (see Section by Section Discussion above).
     Subpart D--Sec.  250.462(e)(1) would add Independent Third 
Party costs increasing the non-hour cost burdens by $16,000 (see 
Section by Section Discussion above).
     Subpart G:
    Sec.  250.720(a)(3) would be new and would require operators to 
request and receive District Manager approval before resuming 
operations after unlatching the BOP or LMRP, and would add 13 burden 
hours (see Section by Section Discussion above).
    Sec.  250.731 would add Independent Third Party costs, increasing 
the non-hour cost burdens by $31,000 (see Section by Section Discussion 
above).
    Sec.  250.732(a) would add Independent Third Party costs, 
increasing the non-hour cost burdens by $765,000 (see Section by 
Section Discussion above).
    Sec.  250.732(d) would eliminate the requirement to request and 
submit for approval all relevant information to become a BAVO. This 
would decrease the hour burden by 700 hours (see Section by Section 
Discussion above).
    Sec.  250.737(d)(5) would be new and proposes to allow for 
alternating tests between two control stations; adding 25 burden hours 
(see Section by Section Discussion above).
    Sec.  250.751 would be new and proposes to include the coiled 
tubing testing and recording requirements that were inadvertently 
removed in the original Well Control Rule; adding 3,630 burden hours 
(see Section by Section Discussion above).
    BSEE-Approved Verification Organization = BAVO; is being replaced 
with Independent Third Party (ITP). In connection with the original 
WCR, BSEE assumed hour burdens in place of non-hour costs associated 
with BAVO submissions; however, in this proposed rule, we are capturing 
non-hour costs associated with hiring ITPs totaling $812,000 (+$16,000 
would be added to the information collection associated with OMB 
Control number 1014-0018 and +$796,000 would be added to the 
information collection associated with OMB Control number 1014-0028). 
1014-0018 and +$796,000 in 1014-0028).
    If this proposed rule becomes effective, BSEE will use the current 
OMB control numbers for the affected subparts discussed and will have 
their information collection burdens adjusted accordingly through the 
renewal process.

National Environmental Policy Act of 1969 (NEPA)

    BSEE has prepared a draft environmental assessment (EA) to 
determine whether this proposed rule would have a significant impact on 
the quality of the human environment under the National Environmental 
Policy Act of 1969 (NEPA) (42 U.S.C. 4321 et seq.). If the final EA 
supports the issuance of a Finding of No Significant Impact for the 
rule, the preparation of an environmental impact statement pursuant to 
the NEPA would not be required. A copy of the draft EA can be viewed at 
www.regulations.gov (use the keyword/ID ``BSEE-2018-0002'').

Data Quality Act

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

Effects on the Nation's Energy Supply (E.O. 13211)

    This proposed rule is not a significant energy action under the 
definition in E.O. 13211. Although the rule is a significant regulatory 
action under E.O. 12866, it is not likely to have a significant adverse 
effect on the supply, distribution, or use of energy. A Statement of 
Energy Effects is not required.

[[Page 22148]]

Clarity of This Regulation

    We are required by E.O. 12866, E.O. 12988, and by the Presidential 
Memorandum of June 1, 1998, to write all rules in plain language. This 
means that each rule we publish must:
    (1) Be logically organized;
    (2) Use the active voice to address readers directly;
    (3) Use clear language rather than jargon;
    (4) Be divided into short sections and sentences; and
    (5) Use lists and tables wherever possible.
    If you feel that we have not met these requirements, send us 
comments by one of the methods listed in the ADDRESSES section. To 
better help us revise the rule, your comments should be as specific as 
possible. For example, you should tell us the numbers of the sections 
or paragraphs that you find unclear, which sections or sentences are 
too long, the sections where you feel lists or tables would be useful, 
etc.

Public Availability of Comments

    Before including your address, phone number, email address, or 
other personal identifying information in your comment, you should be 
aware that your entire comment--including your personal identifying 
information--may be made publicly available at any time. In order for 
BSEE to withhold from disclosure your personal identifying information, 
you must identify any information contained in the submittal of your 
comments that, if released, would constitute a clearly unwarranted 
invasion of your personal privacy. You must also briefly describe any 
possible harmful consequence(s) of the disclosure of information, such 
as embarrassment, injury, or other harm. While you can ask us in your 
comment to withhold your personal identifying information from public 
review, we cannot guarantee that we will be able to do so.

Severability

    If a court holds any provisions of a subsequent final rule or their 
applicability to any persons or circumstances invalid, the remainder of 
the provisions and their applicability to other people or circumstances 
will not be affected.

List of Subjects in 30 CFR Part 250

    Administrative practice and procedure, Continental shelf, 
Environmental impact statements, Environmental protection, 
Incorporation by reference, Oil and gas exploration, Outer Continental 
Shelf--mineral resources, Outer Continental Shelf--rights-of-way, 
Penalties, Reporting and recordkeeping requirements, Sulfur.

Joseph R. Balash,
Assistant Secretary--Land and Minerals Management, U.S. Department of 
the Interior.

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

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

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

    Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, 33 U.S.C. 
1321(j)(1)(C), 43 U.S.C. 1334.

Subpart A--General

0
2. Amend Sec.  250.198 by revising paragraphs (h)(63), (h)(78), and 
(h)(94), and adding new paragraph (m)(2), to read as follows:


250.198   Documents incorporated by reference.

* * * * *
    (h) * * *
    (63) API Standard 53, Blowout Prevention Equipment Systems for 
Drilling Wells, Fourth Edition, November 2012, incorporated by 
reference at Sec. Sec.  250.730, 250.734, 250.735, 250.737, and 
250.739;
* * * * *
    (78) API Standard 65--Part 2, Isolating Potential Flow Zones During 
Well Construction; Second Edition, December 2010; incorporated by 
reference at Sec. Sec.  250.415(f) and 250.420(a)(6);
* * * * *
    (94) API Recommended Practice 17H, Remotely Operated Tool and 
Interfaces on Subsea Production Systems, Second Edition, June 2013, 
Errata January 2014, incorporated by reference at Sec.  250.734(a)(4);
* * * * *
    (m) * * *
    (2) ISO/IEC 17021-1--Conformity assessment--Requirements for bodies 
providing audit and certification of management systems--Part 1, First 
Edition, June 2015, incorporated by reference at Sec.  250.730(d).
* * * * *

Subpart B--Plans and Information

0
3. Amend Sec.  250.292 by revising paragraph (p) to read as follows:


Sec.  250.292   What must the DWOP contain?

* * * * *
    (p) If you propose to use a pipeline free standing hybrid riser 
(FSHR) on a permanent installation that utilizes a buoyancy air can 
suspended from the top of the riser, you must provide the following 
information in your DWOP in the discussions required by paragraphs (f) 
and (g) of this section:
    (1) A detailed description and drawings of the FSHR, buoy, and the 
associated connection system;
    (2) Detailed information regarding the system used to connect the 
FSHR to the buoyancy air can, and associated redundancies; and
    (3) Descriptions of your monitoring system and monitoring plan to 
monitor the pipeline FSHR and the associated connection system for 
fatigue, stress, and any other abnormal condition (e.g., corrosion) 
that may negatively impact the riser system's integrity.
* * * * *

Subpart D--Oil and Gas Drilling Operations

0
4. Amend Sec.  250.413 by revising paragraph (g) to read as follows:


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

* * * * *
    (g) A single plot containing curves for estimated pore pressures, 
formation fracture gradients, proposed drilling fluid weights (surface 
and downhole), planned safe drilling margin, and casing setting depths 
in true vertical measurements;
* * * * *
0
5. Amend Sec.  250.414 by revising paragraph (c)(3) to read as follows:


Sec.  250.414   What must my drilling prognosis include?

* * * * *
    (c) * * *
    (3) When determining the pore pressure and lowest estimated 
fracture gradient for a specific interval, you must consider related 
off-set and analogous well behavior observations, if available.
* * * * *
0
6. Amend Sec.  250.420 by revising paragraph (a)(6) to read as follows:


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

* * * * *
    (a) * * *
    (6) Provide adequate centralization consistent with the guidelines 
of API Standard 65--Part 2 (as incorporated by reference in Sec.  
250.198); and
* * * * *
0
7. Amend Sec.  250.421 by revising paragraphs (c), (d), (e), and (f) to 
read as follows:

[[Page 22149]]

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

* * * * *
BILLING CODE 4310-VH-P
[GRAPHIC] [TIFF OMITTED] TP11MY18.010

0
8. Amend Sec.  250.423 by revising paragraphs (a) and (b) to read as 
follows:


Sec.  250.423   What are the requirements for casing and liner 
installation?

* * * * *
    (a) You must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon successfully installing the casing string. 
If there is an indication of an inadequate cement job, you must comply 
with Sec.  250.428(c).
    (b) If you run a liner that has a latching mechanism or lock down 
mechanism, you must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon successfully installing the liner. If there 
is an indication of an inadequate cement job, you must comply with 
Sec.  250.428(c).
* * * * *
0
9. Amend Sec.  250.428 by revising paragraphs (c) and (d) to read as 
follows:


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

* * * * *

[[Page 22150]]

[GRAPHIC] [TIFF OMITTED] TP11MY18.011

BILLING CODE 4310-VH-C
0
10. Amend Sec.  250.433 by revising paragraph (b) to read as follows:


Sec.  250.433   What are the diverter actuation and testing 
requirements?

* * * * *
    (b) For floating drilling operations with a subsea BOP stack, you 
must actuate the diverter system within 7 days after the previous 
actuation. For subsequent testing, you may partially actuate the 
diverter element and a flow test is not required.
* * * * *
0
11. Amend Sec.  250.461 by revising paragraph (b) to read as follows:


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

* * * * *
    (b) Survey requirements for directional well. You must conduct 
directional surveys on each directional well and digitally record the 
results. Surveys must give both inclination and azimuth at intervals 
not to exceed 500 feet during the normal course of drilling. Intervals 
during angle-changing portions of the hole may not exceed 180 feet.
* * * * *
0
12. Amend Sec.  250.462 by revising paragraphs (b) introductory text, 
(e)(1)(ii), (e)(3), and (e)(4) to read as follows:


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

* * * * *
    (b) You must have access to and the ability to deploy Source 
Control and Containment Equipment (SCCE) and all other necessary 
supporting and collocated equipment to regain control of the well. SCCE 
means the capping stack, cap-and-flow system, containment dome, and/or 
other subsea and surface devices, equipment, and vessels, which have 
the collective purpose to control a spill source and stop the flow of 
fluids into the environment or to contain fluids escaping into the 
environment based on the determinations outlined in paragraph (a) of 
this section. This SCCE, supporting equipment, and collocated equipment 
may include, but is not limited to, the following:
* * * * *
    (e) * * *

[[Page 22151]]

[GRAPHIC] [TIFF OMITTED] TP11MY18.012

Subpart E--Oil and Gas Well-Completion Operations

0
13. Amend Sec.  250.518 by revising paragraph (e)(1) to read as 
follows:


Sec.  250.518   Tubing and wellhead equipment.

* * * * *
    (e) * * *
    (1) All permanently installed packers and bridge plugs qualified as 
mechanical barriers must comply with ANSI/API Spec. 11D1 (as 
incorporated by reference in Sec.  250.198);
* * * * *
0
14. Revise Sec.  250.519 to read as follows:


Sec.  250.519   What are the requirements for casing pressure 
management?

    Once you install your wellhead, you must meet the casing pressure 
management requirements of API RP 90 (as incorporated by reference in 
Sec.  250.198) and the requirements of Sec. Sec.  250.519 through 
250.531. If there is a conflict between API RP 90 and the casing 
pressure requirements of this subpart, you must follow the requirements 
of this subpart.
0
15. Revise Sec.  250.522 to read as follows:


Sec.  250.522   How do I manage the thermal effects caused by initial 
production on a newly completed or recompleted well?

    A newly completed or recompleted well often has thermal casing 
pressure during initial startup. Bleeding casing pressure during the 
startup process is considered a normal and necessary operation to 
manage thermal casing pressure; therefore, you do not need to evaluate 
these operations as a casing diagnostic test. After 30 days of 
continuous production, the initial production startup operation is 
complete and you must perform casing diagnostic testing as required in 
Sec. Sec.  250.521 and 250.523.
0
16. Amend Sec.  250.525 by revising paragraph (d) to read as follows:


Sec.  250.525   When am I required to take action from my casing 
diagnostic test?

* * * * *
    (d) Any well that has sustained casing pressure (SCP) and is bled 
down to prevent it from exceeding its MAWOP, except during initial 
startup operations described in Sec.  250.522;
* * * * *
0
17. Revise Sec.  250.526 to read as follows:


Sec.  250.526   What do I submit if my casing diagnostic test requires 
action?

    Within 14 days after you perform a casing diagnostic test requiring 
action under Sec.  250.525:
[GRAPHIC] [TIFF OMITTED] TP11MY18.013


[[Page 22152]]


0
18. Amend Sec.  250.530 by revising paragraph (b) to read as follows:


Sec.  250.530   What if my casing pressure request is denied?

* * * * *
    (b) You must submit the casing diagnostic test data to the 
appropriate Regional Supervisor, Field Operations, within 14 days of 
completion of the diagnostic test required under Sec.  250.523(e).

Subpart F--Oil and Gas Well-Workover Operations

0
19. Amend Sec.  250.601 by adding paragraph (m) to the definition of 
``routine operations'' to read as follows:


Sec.  250.601   Definitions.

* * * * *
    (m) Acid treatments
* * * * *
0
20. Remove and reserve Sec.  250.616.


Sec.  250.616   [Reserved]

0
21. Amend Sec.  250.619 by revising paragraph (e)(1) to read as 
follows:


Sec.  250.619   Tubing and wellhead equipment.

* * * * *
    (e) * * *
    (1) All permanently installed packers and bridge plugs qualified as 
mechanical barriers must comply with ANSI/API Spec. 11D1 (as 
incorporated by reference in Sec.  250.198). You must have two 
independent barriers, one being mechanical, in the exposed center 
wellbore prior to removing the tree and/or well control equipment;
* * * * *

Subpart G--Well Operations and Equipment

0
22. Amend Sec.  250.712 by adding paragraphs (g) and (h) to read as 
follows:


Sec.  250.712   What rig unit movements must I report?

* * * * *
    (g) You are not required to report rig unit movements to and from 
the safe zone during the course of permitted operations.
    (h) If a rig unit is already on a well, you are not required to 
report any additional rig unit movements on that well.
0
23. Amend Sec.  250.720 by revising paragraph (a)(1) and adding 
paragraphs (a)(3) and (d) to read as follows:


Sec.  250.720   When and how must I secure a well?

    (a) * * *
    (1) The events that would cause you to interrupt operations and 
notify the District Manager include, but are not limited to, the 
following:
    (i) Evacuation of the rig crew;
    (ii) Inability to keep the rig on location;
    (iii) Repair to major rig or well-control equipment;
    (iv) Observed flow outside the well's casing (e.g., shallow water 
flow or bubbling); or
    (v) Impending National Weather Service-named tropical storm or 
hurricane.
* * * * *
    (3) If you unlatch the BOP or LMRP:
    (i) Upon relatch of the BOP, you must test according to Sec.  
250.734(b)(2), or
    (ii) Upon relatch of the LMRP, you must test according to Sec.  
250.734(b)(3); and
    (iii) You must receive District Manager approval before resuming 
operations.
* * * * *
    (d) For subsea completed wells with a tree installed, you must have 
the equipment and capabilities for intervention on those wells. All 
equipment utilized solely for intervention operations (e.g., tree 
interface tools) must be readily available, maintained in accordance 
with OEM recommendations, and available for inspection by BSEE upon 
request.
0
24. Amend Sec.  250.722 by revising paragraph (a)(2) to read as 
follows:


Sec.  250.722   What are the requirements for prolonged operations in a 
well?

* * * * *
    (a) * * *
    (2) Report the results of your evaluation to the District Manager 
and obtain approval of those results before resuming operations. Your 
report must include calculations that indicate the well's integrity is 
above the minimum safety factors, if an imaging tool or caliper is 
used. District Manager approval is not required to resume operations if 
you conducted a successful pressure test as approved in your permit. 
You must document the successful pressure test in the WAR.
* * * * *
0
25. Amend Sec.  250.723 by revising the introductory text and paragraph 
(c)(3) to read as follows:


Sec.  250.723   What additional safety measures must I take when I 
conduct operations on a platform that has producing wells or has other 
hydrocarbon flow?

    You must take the following safety measures when you conduct 
operations with a rig unit on or jacked-up over a platform with 
producing wells or that has other hydrocarbon flow:
* * * * *
    (c) * * *
    (3) A MODU moves within 500 feet of a platform. You may resume 
production once the MODU is in place, secured, and ready to begin 
operations.
* * * * *
0
26. Revise Sec.  250.724 to read as follows:


Sec.  250.724   What are the real-time monitoring requirements?

    (a) No later than April 29, 2019, when conducting well operations 
with a subsea BOP or with a surface BOP on a floating facility, or when 
operating in an high pressure high temperature (HPHT) environment, you 
must gather and monitor real-time well data using an independent, 
automatic, and continuous monitoring system capable of recording, 
storing, and transmitting data regarding the following:
    (1) The BOP control system;
    (2) The well's fluid handling system on the rig; and
    (3) The well's downhole conditions with the bottom hole assembly 
tools (if any tools are installed).
    (b) You must develop and implement a real-time monitoring plan. 
Your real-time monitoring plan, and all real-time monitoring data, must 
be made available to BSEE upon request. Your real-time monitoring plan 
must include the following:
    (1) A description of your real-time monitoring capabilities, 
including the types of the data collected;
    (2) A description of how your real-time monitoring data will be 
transmitted during operations, how the data will be labeled and 
monitored by qualified personnel, and how the data will be stored as 
required in Sec. Sec.  250.740 and 250.741;
    (3) A description of your procedures for providing BSEE access, 
upon request, to your real-time monitoring data;
    (4) The qualifications of the personnel monitoring the data;
    (5) Your procedures for, and methods of, communication between rig 
personnel and the monitoring personnel; and
    (6) Actions to be taken if you lose any real-time monitoring 
capabilities or communications between rig personnel and monitoring 
personnel, and a protocol for how you will respond to any significant 
and/or prolonged interruption of monitoring capabilities or 
communications, including your protocol for notifying BSEE of any 
significant and/or prolonged interruptions.
0
27. Revise Sec.  250.730 to read as follows:

[[Page 22153]]

Sec.  250.730   What are the general requirements for BOP systems and 
system components?

    (a) You must ensure that the BOP system and system components are 
designed, installed, maintained, inspected, tested, and used properly 
to ensure well control. The working-pressure rating of each BOP 
component (excluding annular(s)) must exceed MASP as defined for the 
operation. For a subsea BOP, the MASP must be taken at the mudline. The 
BOP system includes the BOP stack, control system, and any other 
associated system(s) and equipment. The BOP system and individual 
components must be able to perform their expected functions and be 
compatible with each other. Your BOP system must be capable of closing 
and sealing the wellbore in the event of flow due to a kick, including 
under anticipated flowing conditions for the specific well conditions, 
without losing ram closure time and sealing integrity due to the 
corrosiveness, volume, and abrasiveness of any fluids in the wellbore 
that the BOP system may encounter. Your BOP system must meet the 
following requirements:
    (1) The BOP requirements of API Standard 53 (incorporated by 
reference in Sec.  250.198) and the requirements of Sec. Sec.  250.733 
through 250.739. If there is a conflict between API Standard 53 and the 
requirements of this subpart, you must follow the requirements of this 
subpart.
    (2) The provisions of the following industry standards (all 
incorporated by reference in Sec.  250.198) that apply to BOP systems:
    (i) ANSI/API Spec. 6A;
    (ii) ANSI/API Spec. 16A;
    (iii) ANSI/API Spec. 16C;
    (iv) API Spec. 16D; and
    (v) ANSI/API Spec. 17D.
    (3) For surface and subsea BOPs, the pipe and variable bore rams 
installed in the BOP stack must be capable of effectively closing and 
sealing on the tubular body of any drill pipe, workstring, and tubing 
(excluding tubing with exterior control lines and flat packs) in the 
hole under MASP, as defined for the operation, with the proposed 
regulator settings of the BOP control system.
    (4) The current set of approved schematic drawings must be 
available on the rig and at an onshore location. If you make any 
modifications to the BOP or control system that will change your BSEE-
approved schematic drawings, you must suspend operations until you 
obtain approval from the District Manager.
    (b) You must ensure that the design, fabrication, maintenance, and 
repair of your BOP system is in accordance with the requirements 
contained in this part, applicable Original Equipment Manufacturers 
(OEM) recommendations unless otherwise directed by BSEE, and recognized 
engineering practices. The training and qualification of repair and 
maintenance personnel must meet or exceed applicable OEM training 
recommendations unless otherwise directed by BSEE.
    (c) You must follow the failure reporting procedures contained in 
API Standard 53, (incorporated by reference in Sec.  250.198), and:
    (1) You must provide a written notice of equipment failure to BSEE, 
unless BSEE has designated a third party as provided in paragraph (d) 
of this section, and the manufacturer of such equipment within 30 days 
after the discovery and identification of the failure. A failure is any 
condition that prevents the equipment from meeting the functional 
specification.
    (2) You must ensure that an investigation and a failure analysis 
are started within 120 days of the failure to determine the cause of 
the failure, and are completed within 120 days upon starting the 
investigation and failure analysis. You must also ensure that the 
results and any corrective action are documented. You must ensure that 
the analysis report is submitted to BSEE, unless BSEE has designated a 
third party as provided in paragraph (c)(4) of this section, as well as 
the manufacturer.
    (3) If the equipment manufacturer notifies you that it has changed 
the design of the equipment that failed or if you have changed 
operating or repair procedures as a result of a failure, then you must, 
within 30 days of such changes, report the design change or modified 
procedures in writing to BSEE, unless BSEE has designated a third party 
as provided in paragraph (c)(4) of this section.
    (4) BSEE may designate a third party to receive the data and 
reports on behalf of BSEE. If BSEE designates a third party, you must 
submit the data and reports to the designated third party.
    (d) If you plan to use a BOP stack manufactured after the effective 
date of this regulation, you must use one manufactured pursuant to an 
ANSI/API Spec. Q1 (as incorporated by reference in Sec.  250.198) 
quality management system. Such quality management system must be 
certified by an entity that meets the requirements of ISO/IEC 17021-1 
(as incorporated by reference in Sec.  250.198).
    (1) BSEE may consider accepting equipment manufactured under 
quality assurance programs other than ANSI/API Spec. Q1, provided you 
submit a request to the Chief, Office of Offshore Regulatory Programs 
for approval, containing relevant information about the alternative 
program.
    (2) You must submit this request to the Chief, Office of Offshore 
Regulatory Programs; Bureau of Safety and Environmental Enforcement; 
45600 Woodland Road, Sterling, Virginia 20166.
0
28. Amend Sec.  250.731 by:
0
a. Removing paragraphs (d) and (f);
0
b. Redesignating existing paragraph (e) as (d); and
0
c. Revising paragraphs (a)(5) and (c) to read as follows:


Sec.  250.731   What information must I submit for BOP systems and 
system components?

* * * * *
BILLING CODE 4310-VH-P

[[Page 22154]]

[GRAPHIC] [TIFF OMITTED] TP11MY18.014

0
29. Revise Sec.  250.732 and the section heading to read as follows:


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

    (a) Prior to beginning any operation requiring the use of any BOP, 
you must submit verification by an independent third party and 
supporting documentation as required by this paragraph to the 
appropriate District Manager and Regional Supervisor.
[GRAPHIC] [TIFF OMITTED] TP11MY18.015

    (b) The independent third-party must be a technical classification 
society, or a licensed professional engineering firm, or a registered 
professional engineer capable of providing the required certifications 
and verifications.

[[Page 22155]]

    (c) For wells in an HPHT environment, as defined by Sec.  
250.804(b), you must submit verification by an independent third party 
that the independent third party conducted a comprehensive review of 
the BOP system and related equipment you propose to use. You must 
provide the independent third party access to any facility associated 
with the BOP system or related equipment during the review process. You 
must submit the verifications required by this paragraph (c) to the 
appropriate District Manager and Regional Supervisor before you begin 
any operations in an HPHT environment with the proposed equipment.
[GRAPHIC] [TIFF OMITTED] TP11MY18.016

    (d) You must make all documentation that supports the requirements 
of this section available to BSEE upon request.
0
30. Amend Sec.  250.733 by:
0
a. Revising paragraphs (a)(1) and (b)(1); and
0
b. Adding paragraph (e) to read as follows:


Sec.  250.733   What are the requirements for a surface BOP stack?

    (a) * * *
    (1) The blind shear rams must be capable of shearing at any point 
along the tubular body of any drill pipe (excluding tool joints, 
bottom-hole tools, and bottom hole assemblies that include heavy-weight 
pipe or collars), workstring, tubing and associated exterior control 
lines, and any electric-wire-, and slick-line that is in the hole and 
sealing the wellbore after shearing.
* * * * *
    (b) * * *
    (1) For BOPs installed after April 29, 2021, follow the BOP 
requirements in Sec.  250.734(a)(1).
* * * * *
    (e) Additional requirements for surface BOP systems used in well-
completion, workover, and decommissioning operations.
    The minimum BOP system for well-completion, workover, and 
decommissioning operations must meet the appropriate standards from the 
following table:

[[Page 22156]]

[GRAPHIC] [TIFF OMITTED] TP11MY18.017

0
31. Amend Sec.  250.734 by:
0
a. Removing paragraphs (a)(6)(v) and (vi); and
0
b. Revising paragraphs (a)(1)(ii), (a)(3), (a)(4), (a)(6)(iv), (a)(16), 
and (b) to read as follows:


Sec.  250.734   What are the requirements for a subsea BOP system?

    (a) * * *

[[Page 22157]]

[GRAPHIC] [TIFF OMITTED] TP11MY18.018

    (b) If you suspend operations to make repairs to any part of the 
subsea BOP system, you must stop operations at a safe downhole 
location. Before resuming operations you must:
    (1) Submit a revised permit with a verification report from an 
independent third party documenting the repairs and that the BOP is fit 
for service;
    (2) Upon relatch of the BOP, perform an initial subsea BOP test in 
accordance with Sec.  250.737(d)(4), including deadman in accordance 
with Sec.  250.737(d)(12)(vi). If repairs take longer than 30 days, 
once the BOP is on deck, you must test in accordance with the 
requirements of Sec.  250.737;
    (3) Upon relatch of the LMRP, you must test according to the 
following:
    (i) Pressure test riser connector/gasket in accordance with Sec.  
250.737(b) and (c);
    (ii) Pressure test choke and kill stabs at LMRP/BOP interface in 
accordance with Sec.  250.737(b) and (c);
    (iii) Full function test of both pods and both control panels;
    (iv) Verify acoustic pod communication (if equipped); and
    (v) Deadman test with pressure test in accordance with Sec.  
250.737(d)(12)(vi).
    (4) Receive approval from the District Manager.
* * * * *
0
32. Amend Sec.  250.735 by revising paragraph (a) to read as follows:


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

* * * * *
    (a) An accumulator system (as specified in API Standard 53, and 
incorporated by reference in Sec.  250.198). Your accumulator system 
must have the fluid volume capacity and appropriate pre-charge 
pressures in accordance with API Standard 53. If you supply the 
accumulator regulators by rig air and do not have a secondary source of 
pneumatic supply, you must equip the regulators with manual overrides 
or other devices to ensure capability of hydraulic operations if rig 
air is lost;
* * * * *

[[Page 22158]]

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33. Amend Sec.  250.736 by revising paragraph (d)(5) to read as 
follows:


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

* * * * *
    (d) * * *
    (5) When running casing, a safety valve in the open position 
available on the rig floor to fit the casing string being run in the 
hole. For subsea BOPs, the safety valve must be available on the rig 
floor if the length of casing being run exceeds the water depth, which 
would result in the casing being across the BOP stack and the rig floor 
prior to crossing over to the drill pipe running string;
* * * * *
0
34. Amend Sec.  250.737 by:
0
a. Removing paragraph (d)(4)(vi),
0
b. Adding paragraph (d)(13), and
0
c. Revising paragraphs (b) introductory text, (b)(2), (d)(2)(ii), 
(d)(3)(iii), (d)(3)(iv), (d)(3)(v), (d)(4)(i), (d)(4)(iii), (d)(4)(v), 
(d)(5), (d)(12)(iv) and (d)(12)(vi) to read as follows:


Sec.  250.737   What are the BOP system testing requirements?

* * * * *
    (b) Pressure test procedures. When you pressure test the BOP 
system, you must conduct a low-pressure test and a high-pressure test 
for each BOP component (excluding test rams and non-sealing shear 
rams). You must begin each test by conducting the low-pressure test 
then transition to the high-pressure test. Each individual pressure 
test must hold pressure long enough to demonstrate the tested 
component(s) holds the required pressure. The table in this paragraph 
(b) outlines your pressure test requirements.
[GRAPHIC] [TIFF OMITTED] TP11MY18.019

* * * * *
    (d) * * *

[[Page 22159]]

[GRAPHIC] [TIFF OMITTED] TP11MY18.020

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


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

* * * * *

[[Page 22160]]

[GRAPHIC] [TIFF OMITTED] TP11MY18.021

0
36. Amend Sec.  250.739 by revising paragraph (b) introductory text to 
read as follows:


Sec.  250.739   What are the BOP maintenance and inspection 
requirements?

* * * * *
    (b) A major, detailed inspection of the well control system 
components (including but not limited to riser, BOP, LMRP, and control 
pods) must be performed every 5 years. This major inspection may be 
performed in phased intervals. You must track and document all system 
and component inspection dates. These records must be available on the 
rig. An independent third party is required to review the inspection 
results and must compile a detailed report of the inspection results, 
including descriptions of any problems and how they were corrected. You 
must make these reports available to BSEE upon request. This major 
inspection must be performed every 5 years from the following 
applicable dates, whichever is later:
* * * * *
0
37. Add Sec.  250.750 and undesignated center heading to read as 
follows:

Coiled Tubing and Snubbing Operations


Sec.  250.750   What are the coiled tubing and snubbing requirements?

    (a) For coiled tubing operations with the production tree in place, 
you must meet the following minimum requirements for the BOP system:
    (1) BOP system components must be in the following order from the 
top down:

[[Page 22161]]

[GRAPHIC] [TIFF OMITTED] TP11MY18.022

    (2) You may use a set of hydraulically-operated combination rams 
for the blind rams and shear rams.
    (3) You may use a set of hydraulically-operated combination rams 
for the hydraulic two-way slip rams and the hydraulically-operated pipe 
rams.
    (4) You must attach a dual check valve assembly to the coiled 
tubing connector at the downhole end of the coiled tubing string for 
all coiled tubing operations. If you plan to conduct operations without 
downhole check valves, you must describe alternate procedures and 
equipment in Form BSEE-0124, Application for Permit to Modify and have 
it approved by the District Manager.
    (5) You must have a kill line and a separate choke line. You must 
equip each line with two full-opening valves and at least one of the 
valves must be remotely controlled. You may use a manual valve instead 
of the remotely controlled valve on the kill line if you install a 
check valve between the two full-opening manual valves and the pump or 
manifold. The valves must have a working pressure rating equal to or 
greater than the working pressure rating of the connection to which 
they are attached, and you must install them between the well control 
stack and the choke or kill line. For operations with expected surface 
pressures greater than 3,500 psi, the kill line must be connected to a 
pump or manifold. You must not use the kill line inlet on the BOP stack 
for taking fluid returns from the wellbore.
    (6) You must have a hydraulic-actuating system that provides 
sufficient accumulator capacity to close-open-close each component in 
the BOP stack. This cycle must be completed with at least 200 psi above 
the pre-charge pressure, without assistance from a charging system.
    (7) All connections used in the surface BOP system from the tree to 
the uppermost required ram must be flanged, including the connections 
between the well control stack and the first full-opening valve on the 
choke line and the kill line.
    (b) The minimum BOP-system components for operations with the tree 
in place and performed by moving tubing or drill pipe in or out of a 
well under pressure utilizing equipment specifically designed for that 
purpose, i.e., snubbing operations, shall include the following:
    (1) One set of pipe rams hydraulically operated, and
    (2) Two sets of stripper-type pipe rams hydraulically operated with 
spacer spool.
    (c) An inside BOP or a spring-loaded, back-pressure safety valve 
and an essentially full-opening, work-string safety valve in the open 
position must be maintained on the rig floor at all times during 
operations when the tree is removed or during operations with the tree 
installed and using small tubing as the work string. A wrench to fit 
the work-string safety valve must be readily available. Proper 
connections must be readily available for inserting valves in the work 
string. The full-opening safety valve is not required for coiled tubing 
or snubbing operations.
    (d) Test the snubbing unit in accordance with Sec.  250.737(a), 
(b), and (c).
0
38. Add Sec.  250.751 to read as follows:


Sec.  250.751   Coiled tubing testing requirements.

    Coiled tubing tests. You must test the coiled tubing unit in 
accordance with Sec.  250.737(a), (b), (c), (d)(9), and (d)(10). You 
must successfully pressure test the dual check valves to the rated 
working pressure of the connector, the rated working pressure of the 
dual check valve, expected surface pressure, or the collapse pressure 
of the coiled tubing, whichever is less. The test interval for coiled 
tubing operations must include a 10 minute high-pressure test for the 
coiled tubing string.

[[Page 22162]]

Subpart Q--Decommissioning Activities

0
39. Amend Sec.  250.1703 by revising paragraph (b) to read as follows:


Sec.  250.1703   What are the general requirements for decommissioning?

* * * * *
    (b) Permanently plug all wells. Packers and bridge plugs used as 
qualified mechanical barriers must comply with ANSI/API Spec. 11D1 (as 
incorporated by reference in Sec.  250.198). You must have two 
independent barriers, one being mechanical, in the exposed center 
wellbore prior to removing the tree and/or well control equipment;
* * * * *
0
40. Amend Sec.  250.1704 by adding paragraph (g)(4) and revising 
paragraph (h)(2) to read as follows:


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

* * * * *
[GRAPHIC] [TIFF OMITTED] TP11MY18.023

0
41. Remove and reserve Sec.  250.1706:


Sec.  250.1706   [Reserved]

0
42. Remove and reserve Sec.  250.1713:


Sec.  250.1713   [Reserved]

0
43. Amend Sec.  250.1716 by revising paragraph (b)(3) to read as 
follows:


Sec.  250.1716   To what depth must I remove wellheads and casings?

* * * * *
    (b) * * *
    (3) The water depth is greater than 1,000 feet.
0
44. Amend Sec.  250.1722 by revising paragraph (d) introductory text to 
read as follows:


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

* * * * *
    (d) Within 30 days after you complete the trawling test described 
in paragraph (c) of this section, submit a report to the appropriate 
District Manager using form BSEE-0125, End of Operations Report (EOR) 
that includes the following:
* * * * *
[FR Doc. 2018-09305 Filed 5-10-18; 8:45 am]
 BILLING CODE 4310-VH-C