63346 Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 

DEPARTMENT OF THE INTERIOR 

Bureau of Ocean Energy Management, 

Regulation and Enforcement 

30 CFR Part 250 

[Docket ID BOEM–2010–0034] 

RIN 1010–AD68 

Oil and Gas and Sulphur Operations in 

the Outer Continental Shelf—Increased 

Safety Measures for Energy 

Development on the Outer Continental 

Shelf 

AGENCY: Bureau of Ocean Energy 

Management, Regulation and 

Enforcement (BOEMRE), Interior. 

ACTION: Interim final rule with request 

for comments. 

SUMMARY: This interim final rule 

implements certain safety measures 

recommended in the report entitled, 

‘‘Increased Safety Measures for Energy 

Development on the Outer Continental 

Shelf’’ (Safety Measures Report), dated 

May 27, 2010. The President directed 

the Department of the Interior to 

develop the Safety Measures Report to 

identify measures necessary to improve 

the safety of oil and gas exploration and 

development on the Outer Continental 

Shelf in light of the Deepwater Horizon 

event on April 20, 2010, and resulting 

oil spill. To implement the practices 

recommended in the Safety Measures 

Report, the Bureau of Ocean Energy 

Management, Regulation and 

Enforcement is amending drilling 

regulations related to well control, 

including: subsea and surface blowout 

preventers, well casing and cementing, 

secondary intervention, unplanned 

disconnects, recordkeeping, well 

completion, and well plugging. 

DATES: Effective Date: This rule becomes 

effective on October 14, 2010. The 

incorporation by reference of the 

publication listed in the regulations is 

approved by the Director of the Federal 

Register as of October 14, 2010. Submit 

comments on the interim final rule by 

December 13, 2010. BOEMRE may not 

fully consider comments received after 

this date. Submit comments to the 

Office of Management and Budget on 

the information collection burden in 

this rule by December 13, 2010. 

ADDRESSES: You may submit comments 

on the interim final rulemaking by any 

of the following methods. Please use the 

Regulation Identifier Number (RIN) 

1010–AD68 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 BOEM2010-0034 then click search. Follow the 

instructions to submit public comments 

and view supporting and related 

materials available for this rulemaking. 

BOEMRE will post all comments. 

• Mail or hand-carry comments to the 

Department of the Interior; Bureau of 

Ocean Energy Management, Regulation 

and Enforcement; Attention: 

Regulations and Standards Branch 

(RSB); 381 Elden Street, MS–4024, 

Herndon, Virginia 20170–4817. Please 

reference ‘‘Increased Safety Measures for 

Energy Development on the Outer 

Continental Shelf, 1010–AD68’’ in your 

comments and include your name and 

return address. 

• Send comments on the information 

collection in this rule to: Department of 

the Interior; Bureau of Ocean Energy 

Management, Regulation and 

Enforcement; Attention: Cheryl 

Blundon; 381 Elden Street, MS–4024; 

Herndon, Virginia 20170–4817. Please 

reference Information Collection 1010– 

0185 in your comment and include your 

name and address. 

FOR FURTHER INFORMATION CONTACT: 

Amy C. White, Office of Offshore 

Regulatory Programs, Regulations and 

Standards Branch, Bureau of Ocean 

Energy Management, Regulation and 

Enforcement, 703–787–1665, 

amy.white@boemre.gov. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

I. Background 

II. Request for Comments on Interim Final 

Rule and Effective Date 

III. Overview of Requirements in the Interim 

Final Rule 

IV. Source of Specific Provisions Addressed 

in the Interim Final Rule 

V. Justification for Interim Final Rulemaking 

VI. Section-By-Section Discussion of 

Requirements in the Interim Final Rule 

VII. Additional Recommendations in the 

Safety Measures Report Not Covered in 

This Interim Final Rule 

I. Background 

This interim final rule promulgated 

for the prevention of waste and 

conservation of natural resources of the 

Outer Continental Shelf, establishes 

regulations based on certain 

recommendations in the May 27, 2010, 

report from the Secretary of the Interior 

to the President entitled, ‘‘Increased 

Safety Measures for Energy 

Development on the Outer Continental 

Shelf’’ (Safety Measures Report). The 

President directed that the Department 

of the Interior (DOI) develop this report 

as a result of the Deepwater Horizon 

event on April 20, 2010. This event, 

which involved a blowout of the BP 

Macondo well and an explosion on the 

Transocean Deepwater Horizon mobile 

offshore drilling unit (MODU), resulted 

in the deaths of 11 workers, an oil spill 

of national significance, and the sinking 

of the Deepwater Horizon MODU. On 

June 2, 2010, the Secretary of the 

Interior directed the Bureau of Ocean 

Energy Management, Regulation and 

Enforcement (BOEMRE) (formerly the 

Minerals Management Service) to adopt 

the recommendations contained in the 

Safety Measures Report and to 

implement them as soon as possible. 

The Safety Measures Report 

recommended a series of steps to 

improve the safety of offshore oil and 

gas drilling operations in Federal 

waters. It outlined a number of specific 

measures designed to ensure sufficient 

redundancy in blowout preventers 

(BOPs), promote well integrity, enhance 

well control, and facilitate a culture of 

safety through operational and 

personnel management. 

The Safety Measures Report 

recommended that certain measures be 

implemented immediately through a 

Notice to Lessees and Operators (NTL). 

It identified other measures as being 

appropriate to address through an 

emergency rulemaking process. The 

Safety Measures Report recognized that 

other recommendations would require 

additional review and refinement 

through technical reviews by the DOI, 

through information supplied as a result 

of the numerous investigations into the 

root causes of the Deepwater Horizon 

explosion, and through the longer-term 

recommendations of DOI strike teams 

and inter-agency work groups. The 

Safety Measures Report recommended 

that these other measures be addressed 

through notice and comment 

rulemaking, as appropriate. 

On June 8, 2010, BOEMRE issued an 

NTL addressing those recommendations 

identified in the Safety Measures Report 

as warranting immediate 

implementation (NTL No. 2010–N05— 

Increased Safety Measures for Energy 

Development on the OCS). This interim 

final rule clarifies existing regulatory 

requirements that were addressed by 

certain portions of NTL No. 2010–N05. 

This rule incorporates specific details 

included in 2010–N05 by codifying 

these into regulations. The rule does not 

codify the one-time requirements from 

NTL No. 2010–N05, such as the onetime requirement for recertification of 

all BOP equipment used in new floating 

operations, which will be evaluated and 

considered for future rulemakings as 

appropriate. 

This interim final rule also addresses 

measures identified in the Safety 

Measures Report as appropriate for 


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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 63347 

implementation through emergency 

rulemaking, with certain exceptions 

discussed later. It also includes other 

provisions from the Safety Measures 

Report that BOEMRE considers 

appropriate for immediate 

implementation in this interim final 

rule. 

As provided for in the Safety 

Measures Report, BOEMRE will 

continue to review other safety 

measures. These include items that may 

be appropriate for rulemaking in the 

near future, as well as measures that 

will require further study, whether 

through DOI-led strike teams, interagency workgroups, or other means. 

The following table provides a 

summary of the interim final rule 

requirements, estimated annual costs to 

implement the requirements, and the 

operator’s ability to comply with the 

requirements. Additional discussion on 

all the requirements follows in the 

remainder of the preamble. 

SUMMARY OF INTERIM FINAL RULE COMPLIANCE

Citation and requirement Recommendation Applies to 

Operator cost to 

implement per 

year * 

Operator ability to comply 

with requirement 

§ 250.198(a)(3), All documents incorporated by reference ‘‘should’’ and ‘‘shall’’ 

mean ‘‘must’’.

Based on NTL No. 2010 N05 All operators .......................... .............................. Administrative provision 

that does not impose 

compliance times beyond 

the substantive provisions involved. 

§ 250.198(h)(79), Incorporation by Reference of API 

RP 65—Part 2 Isolating 

Potential Flow Zones During Well Construction.

Safety Measures Report: 

II.B.3.7: Enforce Tighter 

Primary Cementing Practices.

All applications for permit to 

drill (APDs) **.

.............................. Additional information provision does not impose 

compliance times beyond 

the substantive provisions involved. 

§ 250.415(f), Written description of how the operator 

evaluated the best practices included in API RP 

65–Part 2. The description 

must identify mechanical 

barriers and cementing 

practices to be used for 

each casing string.

Safety Measures Report: 

II.B.3.7: Enforce Tighter 

Primary Cementing Practices.

Submitted with APD. Applies 

to all APDs.

.............................. New engineering requirement. BOEMRE believes 

that most operators will 

be able to comply with 

this requirement with no 

significant delays * * * 

because this can be 

completed concurrently 

with other tasks. 

§ 250.416(d), Include schematics of all control systems and control pods.Safety Measures Report: 

I.B.5: Secondary Control 

System Requirement and 

Guidelines.

Submitted with APD. Applies 

to all APDs.

.............................. Information is readily available. Should not delay 

submission of the APD. 

§ 250.416(e), Independent 

third party verification that 

the blind-shear rams installed are capable of 

shearing any drill pipe in 

the hole.

Safety Measures Report: 

I.C.7: Develop New Testing Requirements. Also in 

NTL No. N05.

Submitted with APD. Applies 

to all APDs.

$1,200,000 Because there are multiple 

engineering firms available to do this work, and 

because operators have 

had advance notice of 

this requirement in both 

the Safety Measures Report and NTL No. N05, 

BOEMRE believes that 

most operators will be 

able to comply with this 

requirement with no significant delay and provide 

information in the APD. 

§ 250.416(f), Independent 

third party verification that 

subsea BOP is designed 

for specific equipment on 

rig and specific well design.

Safety Measures Report: 

I.B.2: Order BOP Equipment Compatibility 

Verification for Each Floating Vessel and for Each 

New Well. Also in NTL No. 

N05.

Submitted with APD. All 

APDs for well with subsea 

BOP stack. Subsea BOP 

stacks are usually employed in deepwater.

§ 250.416(g), Qualification for 

independent third parties.

Based on NTL No. 2010 N– 

05.

All APDs ................................ .............................. Related to requirements for 

independent third party 

certifications. 


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63348 Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 

SUMMARY OF INTERIM FINAL RULE COMPLIANCE—Continued 

Citation and requirement Recommendation Applies to 

Operator cost to 

implement per 

year * 

Operator ability to comply 

with requirement 

§ 250.420(a)(6), Certification 

by a professional engineer 

that there are two independent tested barriers and 

that the casing and cementing design are appropriate.

Safety Measure Report: 

II.B.1.3: New Casing and 

Cement Design Requirements: Two Independent 

Barriers. This requirement 

was also addressed in NTL 

No. N05.

Submitted with APD. Applies 

to all APDs.

6,000,000 Because there are multiple 

engineering firms available to do this work and 

because operators have 

had advance notice of 

this requirement in both 

the Safety Measures Report and NTL No. N05, 

BOEMRE believes operators will be able to comply with this requirement 

with no significant delays 

and provide information 

in the APD. 

§ 250.420(b)(3), Installation of 

dual mechanical barriers in 

addition to cement for final 

casing string.

Safety Measure Report: 

II.B.1.3: New Casing and 

Cement Design Requirements: Two Independent 

Barriers. This requirement 

was also addressed in NTL 

No. N05.

Completed during the casing 

and cementing of the well. 

It applies to all wells drilled.

10,300,000 Completed during the casing and cementing of the 

well. Compliance with 

this requirement may 

minimally increase the 

time to drill each well. 

§ 250.423(b), The operator 

must perform a pressure 

test on the casing seal assembly to ensure proper installation of casing or liner. 

The operator must ensure 

that the latching mechanisms or lock down mechanisms are engaged upon 

installation of each casing 

string or liner.

Safety Measure Report: 

II.B.2.5: New Casing Installation Procedures. This requirement was also addressed in NTL No. N05.

Complied with after the installation of each casing 

string or liner for all wells 

drilled with a subsea BOP 

stack. It is tested after the 

installation of the casing or 

liner.

.............................. Because operators had advance notice of this requirement in both the 

Safety Measures Report 

and NTL No. N05, 

BOEMRE believes operators should be complying 

with this requirement. 

§ 250.423(c), The operator 

must perform a negative 

pressure test to ensure 

proper casing installation. 

This test must be performed for the intermediate 

and production casing 

strings.

Safety Measure Report: 

II.B.2.6: Develop Additional 

Requirements or Guidelines for Casing.

Tested after running the casing. All wells, involves all 

rigs with surface and subsurface BOPs in all water 

depths.

45,100,000 Compliance with this requirement will increase 

the time to drill each 

subsea well resulting in 

additional costs. 

BOEMRE estimates several hours of additional 

drilling time for each well. 

§ 250.442(c), § 250.515(e), 

§ 250.615(e). Have a 

subsea BOP stack 

equipped with remotely operated vehicle (ROV) intervention capability. At a minimum, the ROV must be 

capable of closing one set 

of pipe rams, closing one 

set of blind-shear rams, 

and unlatching the lower 

marine riser package.

Safety Measure Report: 

I.B.5: Secondary Control 

System Requirements and 

Guidelines. This requirement was also addressed 

in NTL No. N05.

Applies to all subsea BOP 

stacks.

.............................. All rigs should be able to 

comply with requirement. 

All rigs currently have 

ROV intervention capability; approximately 80% 

of subsea BOP stacks 

currently have all the 

specified capabilities. 

Other 20% are expected 

to be able to comply 

promptly. 

§ 250.442(c), § 250.515(e), 

§ 250.615(e). Maintain an 

ROV and have a trained 

ROV crew on each floating 

drilling rig on a continuous 

basis.

Safety Measure Report: 

I.B.6: New ROV Operating 

Capabilities; II.A.1: Establish Deepwater Well-Control Procedure Guidelines.

Ongoing requirement. All 

subsea BOP stacks regardless of water depth.

.............................. BOEMRE believes all rigs 

operating on OCS are already in compliance. 

§ 250.442(f), § 250.515(e), 

§ 250.615(e). Provide 

autoshear and deadman 

systems for dynamically 

positioned (DP) rigs.

Safety Measure Report: 

I.B.5: Secondary Control 

System Requirements and 

Guidelines.

Anytime drilling occurs with 

subsea BOP stacks on DP 

rigs.

.............................. BOEMRE believes all DP 

rigs operating on OCS 

currently comply with this 

requirement. 


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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 63349 

SUMMARY OF INTERIM FINAL RULE COMPLIANCE—Continued 

Citation and requirement Recommendation Applies to 

Operator cost to 

implement per 

year * 

Operator ability to comply 

with requirement 

§ 250.442(e), § 250.515(e), 

§ 250.615(e). Establish 

minimum requirements for 

personnel authorized to operate critical BOP equipment.

Safety Measure Report: 

II.A.1: Establish Deepwater 

Well-Control Procedure 

Guidelines.

Ongoing requirement. Applies to all personnel that 

operate subsea BOP 

stacks. Majority of drilling 

rigs that use subsea BOP 

stacks operate in deepwater.

.............................. Requires trained ROV 

crew; for rigs not already 

in compliance, additional 

training or hiring of new 

crew may be necessary. 

Additional training could 

take days to weeks, depending upon how well 

existing crews are 

trained. However, 

BOEMRE believes no 

rigs should be operating 

without adequately 

trained personnel. 

§ 250.446(a), § 250.516(h), 

§ 250.516(g), § 250.617. 

Require documentation of 

BOP inspections and maintenance according to API 

RP 53.

Safety Measure Report: 

I.B.5: Secondary Control 

System Requirements and 

Guidelines.

Ongoing requirement. All 

BOP stacks. All water 

depths.

.............................. All rigs should be able to 

comply with requirement. 

§ 250.449(j), § 250.516(d)(8), 

§ 250.616(h)(1). Test all 

ROV intervention functions 

on the subsea BOP stack 

during the stump test. Test 

at least one set of rams 

during the initial test on the 

seafloor.

Safety Measure Report: 

I.B.5: Secondary Control 

System Requirements and 

Guidelines; I.C.7: Develop 

New Testing Requirements.

During the stump test and 

initial test on the seafloor. 

All subsea BOP stacks. All 

water depths.

118,200,000 All rigs should be able to 

comply with requirement. 

This requirement not expected to result in significant delay. Compliance 

with this requirement will 

slightly increase the time 

to drill each deepwater 

well drilled with a subsea 

BOP, resulting in additional costs. 

§ 250.449(k), § 250.516(d)(9), 

§ 250.616(h)(2). Function 

test autoshear and 

deadman systems on the 

subsea BOP stack during 

the stump test. Test the 

deadman system during 

the initial test on the 

seafloor.

Safety Measure Report: 

I.B.5: Secondary Control 

System Requirements and 

Guidelines; I.C.7: Develop 

New Testing Requirements.

§ 250.451(i), If the blind-shear 

or casing shear rams are 

activated in a well control 

situation, the BOP must be 

retrieved and fully inspected and tested.

Safety Measure Report: 

I.C.7: Develop New Testing Requirements. This requirement was also addressed in NTL No. N05.

Emergency activation of blind 

or casing shear rams.

2,600,000 Compliance with this requirement will increase 

drilling costs when such 

an emergency occurs. 

§ 250.456(j), Before displacing kill-weight drilling 

fluid from the wellbore, the 

operator must receive approval from the District 

Manager. The operator 

must submit the reasons 

for displacing the kill-weight 

drilling fluid and provide detailed step-by-step procedures describing how the 

operator will safely displace 

these fluids.

Safety Measure Report: 

II.A.2: New Fluid Displacement Procedures.

Submit with APD or application for permit to modify 

(APM). All wells where the 

operator wants to displace 

kill-weight fluids. This could 

occur on all rigs that use 

either a surface or subsurface BOP stack. Could 

occur with all water depths.

.............................. New requirement. Operator 

should be able to provide 

this information in APD or 

APM without significant 

delay. 

Subpart O, §§ 250.1500– 

250.1510, Requires that rig 

personnel are trained in 

deepwater well control and 

the specific duties, equipment, and techniques associated with deepwater drilling.

Safety Measure Report: 

II.A.1: Establish Deepwater 

Well-Control Procedure 

Guidelines.

All wells drilled with subsea 

BOP stack.

.............................. BOEMRE believes that the 

majority of operators 

have addressed this requirement. There should 

not be any delay for this 

requirement. 


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63350 Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 

SUMMARY OF INTERIM FINAL RULE COMPLIANCE—Continued 

Citation and requirement Recommendation Applies to 

Operator cost to 

implement per 

year * 

Operator ability to comply 

with requirement 

§ 250.1712(g), § 250.1721(h). 

Certification by a professional engineer of the well 

abandonment design and 

procedures; that there will 

be at least two independent 

tested barriers, including 

one mechanical barrier, 

across each flow path during abandonment activities; 

and that the plug meets the 

requirements in the table in 

§ 250.1715.

Safety Measure Report: 

II.B.1.3: New Casing and 

Cement Design Requirements: Two Independent 

Tested Barriers.

Submitted with APM. All 

abandonment operations 

regardless of BOP type or 

water depth.

.............................. Operator should be able to 

comply with no significant 

delay and provide information in application for 

permit to modify (APM). 

Estimate that this could 

take an operator as much 

as several days to comply with new requirement. 

Depends on operator’s 

internal review process. 

* Costs that were not provided did not add a meaningful value in comparison of the cost of drilling a well. 

** All APDs means all wells drilled with a surface BOP and all wells drilled with a subsurface BOP. Includes all water depths. 

*** Requirements noted as ‘‘no significant delay’’ are anticipated to require no more than 1 week to achieve compliance. While individually each 

activity could take a day and possibly up to 5 days to complete, it is anticipated that companies will build this into their schedules with no resulting overall delay. 

TOTAL ESTIMATES OF COSTS AND BENEFITS

Total Estimated Annual Compliance Costs ........................................................................................................................ $183.1 million. 

Total Estimated Annual Avoided Social Costs (Benefits) ................................................................................................... $631.4 million—B *. 

* DOI estimated the cost of a hypothetical spill in the future at $16.3 billion, and also estimated the baseline likelihood of a catastrophic blowout 

event and spill occurring, based on historical trends and the number of expected future wells, to be once every 26 years. These estimates are 

necessarily uncertain, and are discussed in more detail in the RIA. Combining the baseline likelihood of occurrence with the cost of a hypothetical spill implies that the expected annualized spill cost is about $631 million. This rulemaking will not reduce the probability of a future spill to 

zero; therefore, ‘‘B’’ in the table above represents the adjustment in annual avoided social costs expected from this rulemaking based on the nonzero remaining probability of a spill after this rule is put into place. Thus, the difference between the avoided costs with and without their rule represents its expected benefits. This remaining probability is uncertain. For example, to balance the $183 million annual cost imposed by these 

regulations with the expected benefits, the reliability of the well control system needs to improve by about 29 percent ($183 million/$631 million). 

Although we have found no studies that evaluate the degree of actual improvement that could be expected from dual mechanical barriers, negative pressure tests, and a seafloor ROV function test, we believe it reasonable to anticipate that such measures will increase the reliability of the 

well control systems, and therefore that the benefits of this rulemaking justify the costs. 

II. Request for Comments on Interim 

Final Rule and Effective Date 

This is an interim final rulemaking 

with request for comments; it is 

effective immediately upon publication. 

The Administrative Procedure Act 

(APA) requires that an agency publish a 

proposed rule in the Federal Register 

with notice and an opportunity for 

public comment, unless the agency, for 

good cause, finds that providing notice 

and soliciting comments in advance of 

promulgating the rule would be 

impracticable, unnecessary, or contrary 

to the public interest (5 U.S.C. 553(b)). 

BOEMRE determined that there is good 

cause for publishing this interim final 

rule without prior notice and comment 

based on its findings, consistent with 

preliminary information that is available 

as a result of investigations into the 

Deepwater Horizon event, that certain 

equipment, systems, and improved 

practices are immediately necessary for 

the safety of offshore oil and gas drilling 

operations on the Outer Continental 

Shelf (OCS), and that these improved 

drilling practices are either not 

addressed or not sufficiently detailed by 

current regulations. Immediate 

imposition of the requirements 

contained in this interim final rule is 

necessary because BOEMRE views strict 

adherence to improved safety practices 

set forth herein as necessary to 

achieving safer conditions that, together 

with other wild well control and oil 

spill response capabilities, will allow it 

to permit future OCS drilling 

operations. Following notice and 

comment procedures would be 

impracticable in these circumstances. 

Furthermore, following notice and 

comment procedures would be contrary 

to the public interest because the delay 

in implementation of this interim final 

rule could result in harm to public 

safety and the environment. Failure to 

adhere to the safety practices required 

by this interim final rule increases the 

risk of a blowout and subsequent oil 

spill, with serious consequences to the 

health and safety of workers and the 

environment. 

As discussed in Section 5, 

‘‘Justification for the Interim Final 

Rulemaking,’’ while investigation and 

information-gathering into the 

Deepwater Horizon blowout and spill 

continues, preliminary evidence 

suggests problems with the Macondo 

well’s line of defense, which could 

include blowout preventer (BOP) 

systems, casing and cementing 

programs, and fluid displacement 

procedures. Evidence further suggests 

that it is unlikely that these problems 

are unique to the Deepwater Horizon 

event; for example, most BOPs used in 

drilling on the OCS are of similar design 

and are produced by a limited number 

of manufacturers. The interim final 

rule’s provisions thus incorporate 

targeted measures to promote the 

integrity of the well and enhance well 

control, including provisions 

specifically identified by the Safety 

Measures Report as warranting 

immediate implementation. For 

example, the requirement that operators 

have all well casing designs and 

cementing systems/procedures certified 

by a Professional Engineer. 

Similarly, BOEMRE determined that 

the immediate necessity for improved 

equipment, systems, and practices also 

provides good cause to impose an 

immediate effective date. The APA 

requires an agency to publish a rule not 

less than 30 days before its effective 


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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 63351 

date, except as otherwise provided by 

the agency for good cause found and 

published with the rule (5 U.S.C. 

553(d)(3)). Just as BOEMRE found that 

providing notice and an opportunity to 

comment is impracticable and contrary 

to the public interest, BOEMRE finds 

that a 30-day delay after publication of 

this interim final rule compromises the 

safety of offshore oil and gas drilling. To 

the extent that the 30-day period is 

intended to allow regulated parties to 

adjust to new requirements, information 

gathered by BOEMRE in advance of this 

rulemaking indicates that the oil and gas 

industry is well aware of the general 

provisions in this interim final rule. 

Most of the provisions in the rule were 

identified in the Safety Measures 

Report, and industry is already working 

to implement them. 

We note that in developing the Safety 

Measures Report on which this interim 

final rule is based, the Department 

consulted with a wide range of experts 

in state and Federal governments, 

academic institutions, and industry and 

advocacy organizations. In addition, the 

draft recommendations of the Safety 

Measure Report were peer reviewed by 

seven experts identified by the National 

Academy of Engineering (NAE). Further 

explanation of the justification for this 

interim final rulemaking is provided in 

section V, ‘‘Justification for Interim Final 

Rulemaking.’’ 

While BOEMRE will not solicit 

comments before the effective date, 

BOEMRE will accept and consider 

public comments on this rule that are 

submitted within 60 days of its 

publication in the Federal Register. 

After reviewing the public comments, 

BOEMRE will publish a notice in the 

Federal Register that will respond to 

comments and will either: 

1. Confirm this rule as a final rule 

with no additional changes, or 

2. Issue a revised final rule with 

modifications, based on public 

comments. 

III. Overview of Requirements in the 

Interim Final Rule 

As recommended in the Safety 

Measures Report, this interim final rule 

imposes a number of prescriptive, nearterm requirements. Other longer-term 

safety measures and performance-based 

standards recommended in the Safety 

Measures Report will be analyzed for 

implementation in future rulemakings. 

Information from the many 

investigations and other information 

sources will also be analyzed and 

considered in future rulemakings. In 

developing the Safety Measures Report 

on which this interim final rule is 

based, the Department consulted with 

experts in state and Federal government, 

academic institutions, and industry and 

advocacy organizations. In addition, 

draft recommendations were peer 

reviewed by seven experts identified by 

the NAE. 

The primary purpose of this interim 

final rule is to clarify and incorporate 

safeguards that will decrease the 

likelihood of a blowout during drilling 

operations on the OCS. The safeguards 

address well bore integrity and well 

control equipment, and this interim 

final rule focuses on those two 

overarching issues. This rule will 

therefore promulgate OCS-wide 

provisions that will: 

1. Establish new casing installation 

requirements, 

2. Establish new cementing 

requirements (incorporate American 

Petroleum Institute (API) Recommended 

Practice (RP) 65—Part 2, Isolating 

Potential Flow Zones During Well 

Construction), 

3. Require independent third party 

verification of blind-shear ram 

capability, 

4. Require independent third party 

verification of subsea BOP stack 

compatibility, 

5. Require new casing and cementing 

integrity tests, 

6. Establish new requirements for 

subsea secondary BOP intervention, 

7. Require function testing for subsea 

secondary BOP intervention, 

8. Require documentation for BOP 

inspections and maintenance, 

9. Require a Registered Professional 

Engineer to certify casing and cementing 

requirements, and 

10. Establish new requirements for 

specific well control training to include 

deepwater operations. 

As stated, the intent of this interim 

final rule is to improve safety related to 

both well bore integrity and well control 

equipment. 

Well bore integrity provides the first 

line of defense against a blowout by 

preventing a loss of well control. Well 

bore integrity includes appropriate use 

of drilling fluids and the casing and 

cementing program. Drilling fluids and 

the casing and cementing program are 

used to balance the pressure in the 

borehole against the fluid pressure of 

the formation, preventing an 

uncontrolled influx of fluid into the 

wellbore. The specific provisions in this 

rule that address well bore integrity are: 

1. Incorporating by reference API RP 

65—Part 2, Isolating Potential Flow 

Zones During Well Construction; 

2. Submission of certification by a 

Registered Professional Engineer that 

the casing and cementing program is 

appropriate for the purpose for which it 

is intended under expected wellbore 

pressure; 

3. Requirements for two independent 

test barriers across each flow path 

during well completion activities (also 

certified by a Registered Professional 

Engineer); 

4. Ensuring proper installation of the 

casing or liner in the subsea wellhead or 

liner hanger; 

5. Approval from the District Manager 

before displacing kill-weight drilling 

fluid; and 

6. Deepwater well control training for 

rig personnel. 

Well control equipment is the general 

term for the technologies used to control 

a well by mechanical means in the event 

that other well control mechanisms fail. 

Well control equipment includes 

control systems that activate the BOPs, 

either through a control panel on the 

drilling rig or through Remotely 

Operated Vehicles (ROVs) that directly 

interface with the subsea BOP to 

activate the appropriate rams. The 

provisions in this rule that address well 

control equipment include: 

1. Submission of documentation and 

schematics for all control systems; 

2. A requirement for independent 

third party verification that the blindshear rams are capable of cutting any 

drill pipe in the hole under maximum 

anticipated surface pressure (MASP); 

3. A requirement for a subsea BOP 

stack equipped with ROV intervention 

capability. At a minimum, the ROV 

must be capable of closing one set of 

pipe rams, closing one set of blind-shear 

rams, and unlatching the Lower Marine 

Riser Package (LMRP); 

4. A requirement for maintaining an 

ROV and having a trained ROV crew on 

each floating drilling rig on a 

continuous basis; 

5. A requirement for autoshear and 

deadman systems for dynamically 

positioned rigs; 

6. Establishment of minimum 

requirements for personnel authorized 

to operate critical BOP equipment; 

7. A requirement for documentation 

of subsea BOP inspections and 

maintenance according to API RP 53, 

Recommended Practices for Blowout 

Prevention Equipment Systems for 

Drilling Wells; 

8. Required testing of all ROV 

intervention functions on the subsea 

BOP stack during the stump test and 

testing at least one set of rams during 

the initial test on the seafloor; 

9. Required function testing of 

autoshear and deadman systems on the 

subsea BOP stack during the stump test 

and testing the deadman system during 

the initial test on the seafloor; and 


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10. Required pressure testing if any 

shear rams are used in an emergency. 

The following table shows where 

recommendations from the Safety 

Measures Report are implemented in the 

interim final rule. 

Safety measures report recommendation Interim final rule citation 

Subpart A—General 

II.B.3.7: Enforce Tighter Primary Cementing Practices ......................................... § 250.198 Documents incorporated by reference. 

Subpart D—Oil and Gas Drilling Operations 

II.B.3.7: Enforce Tighter Primary Cementing Practices ......................................... § 250.415 What must my casing and cementing programs include? 

I.A.2: Order BOP Equipment Compatibility Verification for Each Floating Vessel 

and for Each New Well.

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

I.B.5: Secondary Control System Requirement and Guidelines 

I.C.7: Develop New Testing Requirements 

II.B.1.3: New Casing and Cement Design Requirements: Two Independent Barriers.§ 250.418 What additional information must I submit with my 

APD? 

I.C.7: Develop New Testing Requirements 

II.B.1.3: New Casing and Cement Design Requirements: Two Independent Barriers.§ 250.420 What well casing and cementing requirements 

must I meet? 

II.B.1.3: New Casing and Cement Design Requirements: Two Independent Barriers.§ 250.423 What are the requirements for pressure testing 

casing? 

II.B.2.5: New Casing Installation Procedures 

II.B.2.6: Develop Additional Requirements or Guidelines for Casing Installation 

I.B.5: Secondary Control System Requirements and Guidelines .......................... § 250.442 What are the requirements for a subsea BOP system? 

I.B.6: New ROV Operating Capabilities 

II.A.1: Establish Deepwater Well-Control Procedure Guidelines 

I.B.5: Secondary Control System Requirements and Guidelines .......................... § 250.446 What are the BOP maintenance and inspection requirements? 

I.B.5: Secondary Control System Requirements and Guidelines .......................... § 250.449 What additional BOP testing requirements must I 

meet? 

I.C.7: Develop New Testing Requirements 

I.C.7: Develop New Testing Requirements § 250.451 What must I do in certain situations involving BOP 

equipment or systems? 

II.A.2: New Fluid Displacement Procedures .......................................................... § 250.456 What safe practices must the drilling fluid program 

follow? 

Subpart E—Oil and Gas Well-Completion Operations 

I.B.5: Secondary Control System Requirements and Guidelines .......................... § 250.515 Blowout prevention equipment. 

I.B.6: New ROV Operating Capabilities 

II.A.1: Establish Deepwater Well-Control Procedure Guidelines 

I.B.5: Secondary Control System Requirements and Guidelines and recommendation.

I.C.7: Develop New Testing Requirements 

Subpart F—Oil and Gas Well-Workover Operations 

I.B.5: Secondary Control System Requirements and Guidelines .......................... § 250.615 Blowout prevention equipment. 

I.B.6: New ROV Operating Capabilities 

II.A.1: Establish Deepwater Well-Control Procedure Guidelines 

I.B.5: Secondary Control System Requirements and Guidelines and recommendation.§ 250.616 Blowout preventer system testing, records, and 

drills. 

I.C.7: Develop New Testing Requirements 

I.B.5: Secondary Control System Requirements and Guidelines and recommendation.§ 250.617 What are my BOP inspection and maintenance requirements? 

I.C.7: Develop New Testing Requirements 

Subpart O—Well Control and Production Safety Training 

II.A.1: Establish Deepwater Well-Control Procedure Guidelines ........................... §§ 250.1500–250.1510. 

§ 250.1503 What are my general responsibilities for training? 

Subpart Q—Decommissioning Activities 

II.B.1.3: New Casing and Cement Design Requirements: Two Independent 

Tested Barriers.

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

II.B.1.3: New Casing and Cement Design Requirements: Two Independent 

Tested Barriers.

§ 250.1721 If I temporarily abandon a well that I plan to reenter, what must I do? 

IV. Source of Specific Provisions 

Addressed in the Interim Final Rule 

This interim final rule clarifies 

existing regulatory requirements that 

were addressed by certain portions of 

NTL No. 2010–N05 by codifying the 

specific details into regulations. It also 

addresses items in the Safety Measures 

Report either identified as appropriate 

for implementation through emergency 

rulemaking, or which BOEMRE has 

determined will significantly increase 

OCS drilling safety and with which 

operators can readily comply. The 

following provides an explanation of 

each of these sources and provisions. 

Emergency Rulemaking 

Recommendations From Safety 

Measures Report 

The Safety Measures Report identified 

four items for emergency rulemaking: 

1. Develop secondary control system 

requirements; 


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2. Establish new blind-shear ram 

redundancy requirements; 

3. Establish new deepwater well 

control procedure requirements; and 

4. Adopt safety case requirements for 

floating drilling operations on the OCS. 

Of these four items, this interim final 

rule addresses: 1. Secondary control 

system requirements; and 3. deepwater 

well control procedure requirements. 

This interim final rule does not include: 

2. New blind-shear ram redundancy 

requirements; and 4. safety case 

requirements for floating drilling 

operations on the OCS. 

BOEMRE determined that, while new 

blind-shear ram redundancy 

requirements are important to offshore 

drilling safety, they are not appropriate 

for inclusion in this interim final rule. 

Installation of a second set of blindshear rams will require major 

modifications to the BOP stack for most 

rigs on the OCS. Compliance with such 

a requirement is likely to take operators 

from 1 year to 18 months. Inclusion of 

a requirement that will necessitate a 

period of 1 year or more to comply is 

not appropriate for an interim final rule, 

the purpose of which is to have 

immediate effect. Given the necessary 

compliance periods, BOEMRE believes 

there will be sufficient opportunity to 

proceed through a notice and comment 

rulemaking. Operators should be aware, 

however, that BOEMRE intends to 

promptly initiate a notice and comment 

rulemaking process to address this 

issue. Specifically, operators should be 

aware that BOEMRE is considering 

regulations to require the installation of 

a second set of blind-shear rams, 

appropriately spaced to ensure that at 

least one blind-shear ram cuts any drill 

pipe in the hole and seals the wellbore 

at any time. Operators should also be 

aware that BOEMRE is likewise 

considering requiring, through a notice 

and comment rulemaking, a set of 

casing shear rams capable of shearing 

any casing in the hole. 

This interim final rule addresses both 

new well bore integrity requirements 

and well control equipment 

requirements. The well bore integrity 

provisions impose requirements for 

casing and cementing design and 

installation, tighter cementing practices, 

the displacement of kill-weight fluids, 

and testing of independent well barriers. 

These new requirements ensure that 

there are additional physical barriers in 

the well to prevent oil and gas from 

escaping into the environment. These 

new requirements related to well bore 

integrity will considerably decrease the 

likelihood of a loss of well control. The 

well control equipment requirements in 

this interim final rule will help ensure 

the BOPs will operate in the event of an 

emergency and that the ROVs are 

capable of activating the BOPs. 

Together, these new requirements will 

help decrease the urgency of 

immediately requiring blind-shear ram 

redundancy on BOPs, and have factored 

into BOEMRE’s decision to address such 

requirements through a standard 

rulemaking process. 

BOEMRE also determined not to 

include safety case requirements for 

floating drilling operations in this 

interim final rule. A safety case is a 

comprehensive, structured 

documentation system to reduce 

operating risks for offshore drilling. A 

drilling safety case would establish risk 

assessment and mitigation processes to 

manage a drilling contractor’s controls 

related to health, safety, and 

environmental aspects of operations. 

BOEMRE is evaluating how a drilling 

safety case should be most appropriately 

integrated with an overall Safety and 

Environmental Management System 

(SEMS) approach, which BOEMRE may 

implement through a separate 

rulemaking process. As directed in the 

Safety Measures Report, BOEMRE will 

work with offshore operators and 

drilling contractors, appropriate 

government agencies, and other 

appropriate stakeholders to consider the 

type of well construction interfacing 

document that will best connect the 

requirements of a safety case to existing 

well design and construction 

documents. BOEMRE therefore intends 

to pursue adoption of appropriate safety 

case requirements through a separate 

rulemaking process once the necessary 

analyses have been completed. 

Requirements From NTL No. 2010–N05 

Of the requirements in this interim 

final rule, the following table clarifies 

existing regulations by codifying 

provisions of NTL No. 2010–N05: 

NTL No. 2010–N05 provision Interim final rule citations 

Documentation that the BOP has been maintained according to the regulations 

at § 250.446(a), maintain these records and make them available upon request (safety report rec. I.A.1).

§ 250.446 What are the BOP maintenance and inspection requirements? 

§ 250.516 Blowout preventer system tests, inspections, and 

maintenance. 

§ 250.617 What are my BOP inspection and maintenance requirements? 

Independent third party verification that the BOP stack is designed for the specific equipment on the rig and compatible with the specific well location, well 

design, and well execution plan; that the BOP stack has not been compromised or damaged from previous service; and that the BOP stack will operate in the conditions in which it will be used (safety report rec. I.A.2).

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

Secondary control system with ROV intervention capabilities, including the ability to close one set of blind-shear rams and one set of pipe rams and unlatch 

the LMRP (safety report rec. I.B.5).

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

§ 250.515 Blowout prevention equipment. 

§ 250.615 Blowout prevention equipment. 

Emergency shut-in system in the event that you lose power to the BOP stack, 

have an unplanned disconnection of the riser from the BOP stack, or experience another emergency situation (safety report rec. I.B.5).

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

§ 250.515 Blowout prevention equipment. 

§ 250.615 Blowout prevention equipment. 

Function test the hot stabs that would be used to interface with the ROV intervention panel during the stump test (safety report rec. I.B.6).§ 250.449 What additional BOP testing requirements must I 

meet? 

§ 250.516 Blowout preventer system tests, inspections, and 

maintenance. 

§ 250.616 Blowout preventer system testing, records, and 

drills. 

Independent third party verification that provides sufficient information showing 

that the blind-shear rams installed in the BOP stack are capable of shearing 

the drill pipe in the hole under maximum anticipated surface pressures (safety 

report rec. I.C.7).

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


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NTL No. 2010–N05 provision Interim final rule citations 

If the blind-shear rams or casing shear rams are activated in a well control situation in which pipe or casing was sheared, operators must inspect and test 

the BOP stack and its components, after the situation is fully controlled (safety report rec. I.C.7).

§ 250.451 What must I do in certain situations involving BOP 

equipment or systems? 

Have all well casing designs and cementing program/procedures certified by a 

Registered Professional Engineer, verifying the casing design is appropriate 

for the purpose for which it is intended under expected wellbore conditions 

(safety report rec. II.B.3).

§ 250.420 What well casing and cementing requirements 

must I meet? 

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

§ 250.1721 If I temporarily abandon a well that I plan to reenter, what must I do? 

Certain measures in NTL No. 2010– 

N05 are not included in this interim 

final rule. These are: 

1. Verify compliance with existing 

BOEMRE regulations and with the 

BOEMRE/U.S. Coast Guard National 

Safety Alert (safety report rec. III.A.1). 

2. Submit BOP and well control 

system configuration information for a 

drilling rig that was being used on May 

27, 2010 (safety report rec. I.C.8). 

3. Operator must submit the relevant 

information required in NTL No. 2010– 

N05 prior to commencing operations if 

the operator had an Application for 

Permit to Drill (APD) or Application for 

Permit to Modify (APM) that was 

previously approved but drilling had 

not commenced as of May 27, 2010, and 

operator may not commence drilling 

without BOEMRE approval (general 

requirement for NTL not specified in 

Safety Measures Report). 

Other Provisions From the Safety 

Measures Report in This Interim Final 

Rule 

The following provisions in this 

interim final rule are not covered in 

existing NTL No. 2010–N05 but are 

identified in the Safety Measures Report 

as being appropriate to implement 

either immediately or through an 

emergency rulemaking: 

Safety measures report provision Interim final rule citations 

Establish deepwater well control procedure guidelines (safety report rec. II.A.1) § 250.442 What are the requirements for a subsea BOP system? 

§ 250.515 Blowout prevention equipment. 

§ 250.615 Blowout prevention equipment. 

§§ 250.1500 through 250.1510 Subpart O—Well Control 

and Production Safety Training. 

Establish new fluid displacement procedures (safety report rec. II.A.2) ............... § 250.456 What safe practices must the drilling fluid program 

follow? 

Develop additional requirements or guidelines for casing installation (safety report rec. II.B.2.6).§ 250.423 What are the requirements for pressure testing 

casing? 

BOEMRE has also included the 

following provision in this interim final 

rule from the Safety Measures Report: 

Safety measures report provision Interim final rule 

Enforce tighter primary cementing practices (safety report rec. II.B.3.7) .............. § 250.415 What must my casing and cementing programs include? 

This provision is recommended in the 

Safety Measures Report, although it is 

not specifically identified as requiring 

implementation immediately or through 

emergency rulemaking (this provision 

was also not addressed in NTL No. 

2010–N05). BOEMRE has nonetheless 

determined that it is appropriate for 

inclusion in this interim final rule 

because it is consistent with the intent 

of the recommendations in the Safety 

Measures Report. Tighter cementing 

practices will increase the safety of 

offshore oil and gas drilling operations 

by improving cementing practices; they 

also will support the other requirements 

in this interim final rule. 

V. Justification for Interim Final 

Rulemaking 

Pursuant to the Outer Continental 

Shelf Lands Act (OCSLA), the Secretary 

has an affirmative obligation to ensure 

that drilling operations undertaken on 

the OCS are conducted in a manner that 

is safe for the human, marine, and 

coastal environment (43 U.S.C. 1332(6), 

1334(a), 1347, and 1348; and 30 CFR 

250.106). The April 20, 2010, blowout of 

the BP Macondo well and the explosion 

on the Deepwater Horizon killed 11 

workers and resulted in the Nation’s 

largest oil spill ever, with substantial 

environmental and economic impacts. 

On May 28, 2010, the Secretary 

ordered the suspension of certain oil 

and gas drilling operations in deepwater 

(greater than 500 feet). On July 12, 2010, 

the Secretary rescinded that order and 

replaced it with a new decision ordering 

the suspension in the Gulf of Mexico 

(GOM) and Pacific regions of the 

drilling of wells using subsea BOPs or 

surface BOPs on a floating facility, with 

certain exceptions for intervention 

wells, injection and disposal wells, 

abandonments, completions, and 

workovers. This suspension order 

applies by its terms until November 30, 

2010, although the order notes that it 

could be lifted earlier than that date. 

As mentioned previously, on April 

30, 2010, the President also directed the 

Secretary to conduct a thorough review 

of the Deepwater Horizon event and to 

report within 30 days on additional 


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measures needed to improve the safety 

of oil and gas operations on the OCS. On 

May 27, 2010, the Secretary delivered 

the Safety Measures Report to the 

President. This Safety Measures Report 

incorporated recommendations from 

BOEMRE, as well as from a wide range 

of experts from government, academia, 

and industry. In developing the Safety 

Measures Report on which this interim 

final rule is based, the Department 

consulted with a wide range of experts 

in state and Federal government, 

academic institutions, and industry and 

advocacy organizations. In addition, 

draft recommendations were peer 

reviewed by seven experts identified by 

the NAE. 

Numerous investigations are ongoing, 

and the precise causes of the well 

blowout and explosion are not fully 

known; however, the fact that a blowout 

occurred clearly indicates problems 

with the well’s line of defense, which 

could include BOP systems, casing and 

cementing programs, and fluid 

displacement procedures. Accordingly, 

it is not necessary to await certainty 

regarding the cause of the blowout 

before promulgating this interim final 

rule. 

Circumstances suggest that, while a 

blowout and spill of this magnitude 

have not occurred before on the OCS, it 

is unlikely that the problems are unique 

to the Deepwater Horizon and BP’s 

Macondo well. As noted in the July 12, 

2010, decision of the Secretary to 

suspend certain offshore permitting and 

drilling activities, most BOPs used in 

drilling on the OCS are of similar design 

and are produced by a limited number 

of manufacturers. Furthermore, the 

BOPs for the relief wells drilled to 

intercept the Macondo well encountered 

unexpected performance problems, 

initially failing to pass new testing 

procedures developed in response to the 

Safety Measures Report, including 

failure of the deadman and autoshear 

functions. These multiple failures raise 

red flags as to the reliability of BOPs to 

adequately safeguard the lives of 

workers and protect the environment 

from oil spills in response to a large 

blowout. They also suggest the need to 

review regulations pertaining to well 

casing and design, the other area of 

likely failure in the Deepwater Horizon 

event. 

Even without the full results of the 

pending investigations, the obvious 

failures of well intervention and 

blowout containment systems 

demonstrate that previous regulatory 

assumptions concerning their reliability 

are inaccurate. The importance of these 

systems in preventing catastrophic 

blowouts and oil spills indicate that 

genuine harm could result from delay 

and lead BOEMRE to conclude that 

immediate regulations are needed to 

better ensure the reliability of these 

systems, and to protect the lives of 

workers, human health, and the 

environment. 

This interim final rule therefore, 

specifically addresses measures that 

will increase the safety of these systems. 

It imposes requirements to give greater 

certainty that casing and cement design 

and fluid displacement are adequate for 

well bore integrity, and to enhance the 

reliability of well control equipment. 

The casing and cementing program 

and fluid displacement procedures are 

the first line of defense in preventing a 

loss of well control that could lead to a 

blowout. Casing and cement and 

drilling fluids are used to ensure the 

fluids in a formation do not enter the 

wellbore during drilling and completion 

operations. When a well is completed 

and production begins, the casing and 

cement continue to prevent 

uncontrolled flow of fluids into the 

wellbore. The integrity of the casing and 

cement are critical to proper well 

control. While the extent to which 

cementing and casing failures 

contributed to the Macondo blowout is 

not yet fully known, preliminary 

information suggests that the operator 

may have failed to follow best industry 

cementing and casing installation 

practices. The current regulations 

contain general cementing and casing 

requirements, but they do not 

specifically address best cementing and 

casing installation practices. This 

rulemaking will provide greater 

assurance that all operators will follow 

these safer practices, reducing the risk 

of a loss of well control. 

This interim final rule also 

strengthens requirements for BOPs. In 

the event of a loss of well control, rig 

operators use the BOPs to regain control 

of the well. This is done by closing the 

various rams on the BOP stack, which 

shut off the flow of formation fluids to 

the surface. Secondary well control 

system requirements (i.e., ROV 

intervention capabilities and emergency 

back-up BOP control systems) ensure 

that rig operators are able to activate 

various BOP rams in the event the 

control system on the rig fails (e.g., loss 

of power). Requirements in this interim 

final rule impose new standards to 

enhance BOP reliability, thereby 

lessening the possibility of failures that 

could lead to an uncontrolled blowout 

and spill with potentially catastrophic 

consequences for workers and the 

environment. 

Given the Deepwater Horizon blowout 

and resulting spill, and because of the 

potential for grave harm to workers and 

the human, marine, and coastal 

environment from any additional 

events, BOEMRE concludes that existing 

regulations must be strengthened to 

more fully protect offshore workers, the 

environment, and the public, and that 

this situation justifies immediate 

imposition of the requirements of this 

interim final rule. 

This interim final rule applies to 

ongoing operations not covered by the 

Secretary’s July 12, 2010, suspension 

decision in addition to those operations 

that were suspended by that decision. 

Immediate imposition of the 

requirements of this rule is necessary for 

both ongoing and suspended operations 

to ensure that all operations proceed in 

a more safe and reliable fashion in 

protection of human health and the 

environment. The July 12, 2010, 

suspension expires by its terms on 

November 30, 2010, and it could be 

lifted earlier. A standard APA notice 

and comment rulemaking process 

would place the effective date of these 

measures beyond the expiration date of 

the suspension, which would mean that 

these operations could resume without 

the benefit of the new safety measures 

being in place. Therefore, BOEMRE 

believes that the delay associated with 

notice and comment has the potential to 

harm worker and public health and 

safety and the environment, and further 

justifies the immediate implementation 

of this interim final rule to all OCS 

drilling operations. To act otherwise has 

the potential to risk worker and 

environmental protection with 

inadequate regulatory coverage. 

BOEMRE is cognizant of the fact that 

the Secretary has the ability to extend 

the suspension of operations covered by 

his July 12, 2010, decision, or to apply 

the suspension to additional operations 

on the OCS. Immediate application of 

the safety measures in this interim final 

rule, however, will improve the 

reliability of well control systems, 

thereby allowing all oil and gas 

operations on the OCS to proceed in a 

more safe and environmentally sound 

manner. 

BOEMRE believes that much of the oil 

and gas industry is already well 

informed of the general provisions in 

this interim final rule, most of which 

were identified in the Safety Measures 

Report. Information gathered by 

BOEMRE in advance of this rulemaking 

indicates that BOP equipment 

manufacturers, drilling contractors, and 

operators are already working to address 

the recommendations. Establishing 

these requirements via an interim final 

rule will allow these entities to make 


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informed financial and operational 

decisions earlier. 

As previously noted, these regulations 

were developed without the benefit of 

the conclusive findings from the 

ongoing investigations into the root 

causes of the explosions and fire on the 

Deepwater Horizon. In the future, based 

on the comments we receive on this rule 

and the additional findings of ongoing 

investigations, BOEMRE may issue 

additional regulations or amendments to 

these regulations that will be intended 

to further increase the safety of offshore 

oil and gas operations. 

VI. Section-By-Section Discussion of 

Requirements in the Interim Final Rule 

Documents Incorporated by Reference 

(§ 250.198) 

Code of Federal Regulations, Title 30— 

MINERAL RESOURCES 

BOEMRE is revising the title of 

Chapter II to, ‘‘CHAPTER II—BUREAU 

OF OCEAN ENERGY MANAGEMENT, 

REGULATION AND ENFORCEMENT, 

DEPARTMENT OF THE INTERIOR.’’ On 

June 18, 2010, the Secretary of the 

Interior changed the name of the 

Minerals Management Service (MMS) to 

the Bureau of Ocean Energy 

Management, Regulation and 

Enforcement (BOEMRE). This rule 

updates the heading of Chapter II in 

Title 30, Volume 2, of the Code of 

Federal Regulations to reflect this 

change. 

Paragraph (a)(3) was added to clarify 

that the documents incorporated by 

reference into the regulations are 

requirements. In the National 

Technology Transfer and Advancement 

Act of 1995, Congress directed Federal 

agencies to use technical standards that 

are developed or adopted by voluntary 

consensus standards bodies. In 

§ 250.198, BOEMRE incorporates by 

reference many consensus technical 

standards including recommended 

practices, code requirements, and 

specifications. The effect of 

incorporating these standards into 

Federal regulations is confirmed in 

regulations issued by the Office of the 

Federal Register (1 CFR 51.9(b)), which 

requires agencies to inform the user that 

an incorporated publication is a 

requirement. 

When BOEMRE incorporates a 

document by reference, any 

recommendations in the document will 

be interpreted as requirements, unless 

otherwise specified. For example, this 

section incorporates API documents that 

recommend certain actions using the 

word should. In the Foreword to its 

recommended practices, API explains 

that the word shall indicates that the 

recommended practice has universal 

applicability to the specific activity, 

while the word should denotes a 

recommended practice where a safe 

comparable alternative practice is 

available. Despite this explanation, for 

API documents incorporated by 

reference into this part, the terms should 

and shall mean must. For example, API 

RP 53, sections 17.10, 17.11, 17.12, 

18.10, 18.11, and 18.12, are currently 

incorporated by reference in 

§ 250.446(a). By adding paragraph (a)(3) 

to this interim final rule, which explains 

that the words should and shall both 

mean must, BOEMRE clarifies to the 

operators that they must follow all of 

the provisions of these API RP 53 

sections. 

Paragraph (h)(79) was added to this 

section and incorporates by reference 

API RP 65—Part 2, Isolating Potential 

Flow Zones During Well Construction, 

First Edition, May 2010. This document 

contains best practices for zone isolation 

in wells to prevent annular pressure 

and/or flow through or past pressurecontainment barriers that are installed 

and verified during well construction. 

Barriers that seal wellbore and 

formation pressures or flows may 

include temporary pressure 

containment barriers like hydrostatic 

head pressure during cement curing, 

and permanent ones such as mechanical 

seals, shoe formations, and cement. 

Other well construction (well design, 

drilling, leak-off tests, etc.,) practices 

that may affect barrier sealing 

performance are addressed along with 

methods to help ensure positive effects 

or to minimize any negative ones. The 

incorporation by reference of API RP 

65—Part 2 addresses the Safety 

Measures Report recommendation 

II.B.3.7: Enforce Tighter Primary 

Cementing Practices. 

The citations for API RP 53 in 

§ 250.198(h)(63) were updated to 

include the requirements in § 250.516 

and new § 250.617. 

A consensus standard indicates 

acceptance and recognition across the 

industry that this technology is feasible. 

For example, in its recommended 

practice publications, including API RP 

65—Part 2 and API RP 53, API explains 

that its publications are intended to 

facilitate the broad availability of 

proven, sound engineering, and 

operating practices. The recommended 

practices are created with input from oil 

and gas operators, drilling contractors, 

service companies, consultants, and 

regulators; therefore, the recommended 

practices reflect an agreement that the 

specified practices and technologies are 

available and appropriate. Even though 

the development of a standard does not 

represent a 100% agreement by the task 

group members, the process provides a 

means for industry and regulatory 

bodies to develop protocols for the 

highly specialized equipment and 

procedures used in offshore oil and gas 

work. BOEMRE would not have the 

proper resources to develop information 

included in standards on its own (e.g. 

deepwater, High Pressure, High 

Temperature). BOEMRE regulatory 

program benefits from using the 

expertise in industry on offshore 

operations through the standards 

development process. Furthermore, in 

the National Technology Transfer and 

Advancement Act of 1995, Congress 

directed Federal agencies to use 

technical standards that are developed 

or adopted by voluntary consensus 

standards bodies (http://standards.gov/ 

standards_gov/nttaa.cfm). 

When a copyrighted technical 

industry standard is incorporated by 

reference into our regulations, BOEMRE 

is obligated to observe and protect that 

copyright. BOEMRE provides members 

of the public with Web site addresses 

where these standards may be accessed 

for viewing—sometimes for free and 

sometimes for a fee. The decision to 

charge a fee is decided by organizations 

developing the standard. 

For the convenience of the viewing 

public who may not wish to purchase 

these documents, they may be inspected 

at the Bureau of Ocean Energy 

Management, Regulation and 

Enforcement, 381 Elden Street, Room 

3313, Herndon, Virginia 20170; phone: 

703–787–1587; or at the National 

Archives and Records Administration. 

For information on the availability of 

this material, call 202–741–6030, or go 

to: http://www.archives.gov/ 

federal_register/ 

code_of_federal_regulations/ 

ibr_locations.html. 

These documents will continue to be 

made available to the public for viewing 

when requested. Specific information 

on where these documents can be 

inspected or purchased can be found at 

§ 250.198, Documents incorporated by 

reference. 

In addition, the API has decided to 

provide free online public access to 160 

key industry standards, including a 

broad range of safety standards once 

changes to the API website are 

complete. The standards represent 

almost one-third of all API standards 

and will include all that are safetyrelated or have been incorporated into 

Federal regulations. The API will make 

these standards will be available online 

for review and hardcopies and printable 

versions will continue to be available 

for purchase. You may view or purchase 


emcdonald on DSK2BSOYB1PROD with RULES2
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these API documents at: http:// 

www.api.org/. 

What must my casing and cementing 

programs include? (§ 250.415) 

In this section, BOEMRE added a new 

paragraph (f) requiring the operator to 

include in its APD an evaluation of the 

best practices identified in API RP 65— 

Part 2, Isolating Potential Flow Zones 

During Well Construction. We revised 

paragraphs (c), (d), and (e) to 

accommodate the new paragraph. 

Incorporating this document by 

reference will help ensure operators use 

best practices when designing their 

casing and cementing programs and will 

help ensure the integrity of the well, 

decreasing the risk of a loss of well 

control. Operators must submit a 

written description of their evaluation 

to BOEMRE that includes the 

mechanical barriers and cementing 

practices the operators will use for each 

casing string. Operators must exercise 

due diligence in understanding the 

variables involved when planning the 

casing and cementing program. 

The API RP 65—Part 2 addresses 

mechanical barriers in section 3. A 

mechanical barrier, as defined by this 

document, is a verifiable seal achieved 

by mechanical means between two 

casing strings or a casing string and the 

borehole that isolates all potential 

flowing zones at or below the wellhead, 

BOP, or diverter. The use of downhole 

mechanical barriers is complementary 

to properly executed cementing and not 

a replacement. The applications of 

subsurface mechanical barriers must be 

chosen with care. 

The API RP 65—Part 2, section 4, 

addresses cementing practices and 

factors affecting cementing. This section 

requires that casing and cementing 

programs address many of the key 

drilling issues that affect the quality of 

a primary cementing operation. Section 

4 includes the best practices for the 

factors that must be considered and 

addresses the interrelationship between 

drilling operations and cementing 

success. BOEMRE is requiring operators 

to document how they evaluated these 

best practices, to ensure operators 

consider them while developing their 

casing and cementing programs. 

BOEMRE believes that this is an 

appropriate document to incorporate by 

reference. The key to successful use of 

this document for OCS cementing 

operations is implementation. The 

regulations will require that the operator 

address the document during the 

preparation of the APD and describe the 

cementing practices and barriers used 

for casing string. Including this 

information on the APD will help assure 

best practices are used for a particular 

operation. Incorporating this document 

will not address all issues associated 

with cementing practices; however, 

doing so gives the agency the ability to 

evaluate best cementing practices on a 

case by case basis. Additional 

cementing requirements may be 

identified as results of the many 

investigations of the Deepwater Horizon 

event but until then BOEMRE believes 

this is the best approach to requiring 

best cementing practices. These 

additions will allow BOEMRE to 

confirm that well construction is based 

on a complete evaluation of all critical 

factors (including mechanical barriers 

and cementing practices) involved in a 

casing and cementing program. This 

new requirement addresses Safety 

Measures Report recommendation 

II.B.3.7: Enforce Tighter Primary 

Cementing Practices. 

What must I include in the diverter and 

BOP descriptions? (§ 250.416) 

In this section, paragraph (d) was 

revised to include the submission of a 

schematic of all control systems, 

including primary control systems, 

secondary control systems, and pods for 

the BOP system. This requirement 

applies to both surface and subsea BOP 

systems. This will provide 

documentation for all control systems to 

BOEMRE. The location of the controls 

must be included. Secondary control 

systems include, but are not limited to, 

the following: ROV intervention panels 

located on the BOP, autoshear and 

deadman systems, power sources of 

each system, back up power sources, 

and acoustic systems. 

In this section, paragraph (e) was 

revised to require the operator to submit 

independent third party verification and 

supporting documentation that shows 

the blind-shear rams installed in the 

BOP stack are capable of shearing any 

drill pipe in the hole under maximum 

anticipated surface pressure, as 

recommended in the Safety Measures 

Report and included in NTL No. 2010– 

N05. This requirement applies to both 

surface and subsea BOP systems. The 

benefit of an independent third party is 

that it provides an objective and 

technically-informed review to properly 

verify capabilities of the blind-shear 

rams. Requiring independent third party 

verification and information about the 

blind-shear rams will help ensure that 

the appropriate shear rams are installed 

in the BOP. The documentation must 

include test results and calculations of 

shearing capacity of all pipe to be used 

in the well including correction for 

maximum anticipated surface pressure. 

Shearing capability tests can be 

performed on the drill pipe that requires 

the highest shear pressure. The operator 

must include a discussion on how the 

drill pipe used during the shear test 

required the highest shear pressure and 

was the most difficult to shear. The 

interim final rule will codify the 

section, ‘‘Verification that Blind-shear 

Rams Will Shear Pipe in the Hole’’ in 

NTL No. 2010–N05. 

Paragraph (f) was added to require 

independent third party verification that 

a subsea BOP stack is designed for the 

specific equipment used on the rig. The 

independent third party must verify that 

the subsea BOP stack is compatible with 

the specific well location, well design, 

and well execution plan. Information 

showing that the shear rams are 

appropriate for the project must be 

included. The independent third party 

must also verify that the subsea BOP 

stack has not been damaged or 

compromised from previous service. 

Last, the independent third party must 

verify that a subsea BOP stack will 

operate in the conditions in which it 

will be used. This will ensure that all 

factors of drilling with subsea BOPs are 

considered when choosing well control 

equipment. This requirement applies to 

all APDs that request to use a subsea 

BOP stack. It applies to completion, 

workover, or abandonment operations. 

The interim final rule will codify the 

section, ‘‘BOP Compatibility Verification 

for All Wells’’ in NTL No. 2010–N05. 

Paragraph (g) was added and 

describes the criteria and 

documentation for an independent third 

party that must be submitted with the 

APD to BOEMRE for review. This is to 

ensure that the independent third party 

is capable of providing both an objective 

and a technically informed validation of 

the subjects being reviewed. The 

independent third party must be a 

technical classification society; an API 

licensed manufacturing, inspection, 

certification firm; or licensed 

professional engineering firm capable of 

providing the verifications required 

under this part. The independent third 

party must not be the original 

equipment manufacturer. The original 

equipment manufacturer is excluded 

because it has a financial interest in 

equipment being evaluated. Equipment 

manufacturers that do not have a 

financial interest in the equipment 

being evaluated may serve as an 

independent third party certifier if 

otherwise qualified. The operator must 

provide evidence to BOEMRE that the 

firm it is using is reputable; specifically, 

the firm or its employees hold 

appropriate licenses to perform the 

verification in the appropriate 

jurisdiction, the firm carries industryVerDate Mar<15>2010 17:55 Oct 13, 2010 Jkt 223001 PO 00000 Frm 00013 Fmt 4701 Sfmt 4700 E:\FR\FM\14OCR2.SGM 14OCR2

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63358 Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 

standard levels of professional liability 

insurance, and the firm has no record of 

violations of applicable law. Prior to any 

shearing ram tests or inspections, the 

operator must also notify the District 

Manager 24 hours in advance. The 

operator must ensure an official 

representative of BOEMRE access to the 

location to potentially witness any 

testing or inspections, or to verify 

information submitted to BOEMRE. This 

approach to document the qualifications 

of the independent third party is the 

same approach being followed for the 

documenting the independent third 

party required by NTL No. 2010–N05. 

The revised requirements in 

paragraph (d) address Safety Measures 

Report recommendation I.B.5: 

Secondary Control System 

Requirements and Guidelines. The 

requirements in paragraph (e) address 

Safety Measures Report 

recommendation I.C.7: Develop New 

Testing Requirements. The new 

requirements in paragraph (f) address 

Safety Measures Report 

recommendation I.A.2: Order BOP 

Equipment Compatibility Verification 

for Each Floating Vessel and for Each 

New Well. The criteria required for the 

independent third party are also 

addressed in NTL No. 2010–N05. These 

requirements will help ensure that the 

rig operator has the appropriate control 

systems in place, aiding the rig 

operator’s ability to regain control of a 

well in the event of a loss of well 

control. 

What additional information must I 

submit with my APD? (§ 250.418) 

In this section, new paragraph (h) was 

added that requires the operator to 

submit certifications of their casing and 

cementing program signed by a 

Registered Professional Engineer. The 

Registered Professional Engineer must 

be registered in a State in the United 

States but does not have to be a specific 

discipline. Certification by a Registered 

Professional Engineer will increase the 

likelihood that the casing and 

cementing program has been properly 

designed and implemented, and will 

provide adequate well control. The 

Registered Professional Engineer will 

certify that there will be at least two 

independent tested barriers across each 

flow path during well completion 

activities. The Registered Professional 

Engineer will also certify that the casing 

and cementing design is appropriate for 

the purpose for which it is intended 

under expected wellbore conditions. 

The operator must submit this 

certification to BOEMRE along with the 

APD. Paragraph (g) was revised to 

accommodate new paragraph (h). The 

interim final rule will codify 

requirements addressed under the 

section, ‘‘Well Design and Construction 

for All Wells’’ in NTL No. 2010–N05. 

These requirements for additional 

barriers, and the certification of the 

cement design, will decrease the 

likelihood of a blowout. These 

requirements apply to new wells, 

sidetracks, bypasses, or deepened wells. 

In this section, a new paragraph (i) 

was added requiring the operator to 

submit a description of qualifications of 

any independent third party. Operators 

must formally notify BOEMRE of their 

independent third parties. The 

description must be submitted with the 

APD and may include the following: 

1. Name and address of the individual 

or organization; 

2. Size and type of the organization or 

corporation; 

3. Previous experience as a Certified 

Entity, Certified Verification Agent 

(CVA), or similar third-party 

representative; 

4. Experience in design, fabrication, 

or installation of BOPs and related 

equipment; 

5. Technical capabilities (including 

professional certifications and 

organizational memberships) of the 

third party or the primary staff to be 

associated with the certifying functions 

for the specific project; 

6. In-house availability of, or access 

to, appropriate technology (i.e., 

computer modeling programs and 

hardware, testing materials, and 

equipment); 

7. Ability to perform and effectively 

manage certifying functions, 

inspections, and tests for the specific 

project considering current resource 

availability; 

8. Previous experience with 

regulatory requirements and procedures; 

9. Evidence that the third party is not 

owned or controlled by the designer, 

manufacturer, or supplier of the system 

or its subsystems to be inspected or 

tested under regulations applicable to 

this device or any manufacturer of 

similar equipment or material; 

10. The level of work to be performed 

by the third party; and 

11. A list of documents and 

certifications expected to be furnished 

to BOEMRE by the third party. 

The new requirements address the 

Safety Measures Report 

recommendation II.B.1.3: New Casing 

and Cement Design Requirements: Two 

Independent Tested Barriers and 

recommendation I.C.7: Develop New 

Testing Requirements. 

What well casing and cementing 

requirements must I meet? (§ 250.420) 

In this section, new paragraph (a)(6) 

was added that requires the operators to 

submit certification of their casing and 

cementing program signed by a 

Registered Professional Engineer (see 

discussion under section 250.418, 

above). The Registered Professional 

Engineer must be registered in a State in 

the United States. As mentioned 

previously, the Registered Professional 

Engineer does not have to be from a 

specific discipline, but must be capable 

of reviewing and certifying that the 

casing design is appropriate for the 

purpose for which it is intended under 

expected wellbore conditions. The 

Registered Professional Engineer will 

certify that there will be at least two 

independent tested barriers, including 

one mechanical barrier, across each flow 

path during well completion activities. 

The Registered Professional Engineer 

will also certify the casing and 

cementing design is appropriate for the 

purpose for which it is intended under 

expected wellbore conditions. The 

operator must submit this certification 

to BOEMRE along with the APD. The 

operator should not deviate from the 

certified procedure; if the operator 

deviates from the certified procedures, 

they must contact the appropriate 

District Manager. Paragraphs (a)(4) and 

(a)(5) were revised to accommodate the 

new paragraph (a)(6). The interim final 

rule will codify the section, ‘‘Well 

Design and Construction for All Wells’’ 

in NTL No. 2010–N05. The certification 

of the casing and cementing program 

will help ensure that the appropriate 

program is used for the well and 

decrease the likelihood of a blowout. 

A new paragraph (b)(3) was also 

added, requiring the operator to install 

dual mechanical barriers in addition to 

cement for the final casing string (or 

liner if it is the final string), to prevent 

flow in the event of a failure in the 

cement. These may include dual float 

valves, or one float valve and a 

mechanical barrier. The operator must 

document the installation of the dual 

mechanical barriers and submit this 

documentation to BOEMRE 30 days 

after installation. References to days in 

this rule are always in calendar days. 

The interim final rule will codify the 

section, ‘‘Well Design and Construction 

for All Wells’’ in NTL No. 2010–N05. 

These new requirements will help 

ensure that the best casing and 

cementing design will be used for a 

specific well. The new requirements in 

paragraphs (a)(6) and (b)(3) address the 

Safety Measures Report 

recommendation II.B.1.3: New Casing 


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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 63359 

and Cement Design Requirements: Two 

Independent Tested Barriers. 

What are the requirements for pressure 

testing casing? (§ 250.423) 

This section was reorganized to 

accommodate new requirements: the 

current regulations were redesignated as 

paragraph (a) and new paragraphs (b) 

and (c) were added. Paragraph (b) 

requires the operator to perform a 

pressure test on the casing seal assembly 

to ensure proper installation of casing or 

liner in the subsea wellhead or liner 

hanger. This must be done for 

intermediate and production casing 

strings or liner. To install casing in the 

subsea wellhead, the operator runs and 

lands the casing hanger tool, cements 

the casing, latches the casing hanger in 

place, and finally pressure sets and tests 

the seal. This test ensures that the 

casing hanger latching mechanism, or 

lockdown mechanism, is engaged, 

ensuring the integrity of the casing. The 

operator must submit the test 

procedures and criteria used for a 

successful test with the APD to 

BOEMRE for approval. The operator 

must record the test results and make 

the results available to BOEMRE upon 

request. As required in § 250.466, 

records for well operations must be kept 

onsite while drilling activities continue. 

The interim final rule will codify 

requirements addressed under the 

section, ‘‘Well Design and Construction 

for All Wells’’ in NTL No. 2010–N05. 

Paragraph (c) requires the operator to 

perform a negative pressure test on all 

wells to ensure proper installation of 

casing for the intermediate and 

production casing strings. The operator 

must submit the procedures and criteria 

for a successful test with the APD for 

approval. The operator must record the 

test results and make available to 

BOEMRE upon request. A negative 

pressure test will help ensure that the 

casing, along with the cement, provides 

a seal. 

The new requirements in this section 

will help ensure proper casing 

installation and evaluate the integrity of 

the casing and cement. The new 

requirements in this section address the 

Safety Measures Report 

recommendations II.B.1.3: New Casing 

and Cement Design Requirements: Two 

Independent Tested Barriers; II.B.2.5: 

New Casing Installation Procedures; and 

II.B.2.6: Develop Additional 

Requirements or Guidelines for Casing 

Installation. 

What are the requirements for a subsea 

BOP system? (§ 250.442) 

This section requires that when 

drilling with a subsea BOP system, the 

BOP system must be installed before 

drilling below the surface casing. The 

table in this section outlines the 

requirements, including: 

a. The minimum number of each type 

of BOP, 

b. dual-pod control systems, 

c. accumulator operations, 

d. ROV intervention, 

e. maintaining an ROV and ROV crew 

training, 

f. autoshear and deadman capability 

and optional acoustic system for 

dynamically positioned rigs, 

g. accidental disconnect avoidance, 

h. BOP control panel labels, 

i. BOP management system, 

j. personnel training for BOP 

equipment, 

k. marine riser removal, and 

l. avoiding ice scour. 

Paragraph (a) was revised to clarify 

that the blind-shear rams must be 

capable of shearing any drill pipe in the 

hole under maximum anticipated 

surface pressures. When drilling with a 

subsea BOP stack, the operator must 

have a minimum of four remote 

controlled hydraulically operated BOPs. 

The BOPs must include one annular 

preventer, two sets of pipe rams, and 

one set of blind-shear rams. 

The requirement in paragraph (b) to 

have an operable dual-pod control 

system and the requirement in 

paragraph (c) to follow API RP 53, 

Section 13.3, Accumulator Volumetric 

Capacity, were not revised. The operator 

must meet the volume capacities for all 

subsea accumulators and must meet the 

closing times specified in API RP 53, 

Section 13.3.5, Accumulator Response 

Time: The BOP control system must be 

capable of closing each ram BOP in 45 

seconds or less; closing time must not 

exceed 60 seconds for annular BOPs; 

operating response time for choke and 

kill valves must not exceed the 

minimum observed ram BOP close 

response time; and time to unlatch the 

LMRP must not exceed 45 seconds. 

Requirements related to ROV 

intervention in paragraph (d) were 

added. The subsea BOP stack must be 

equipped with ROV intervention 

capability to operate one set of pipe 

rams and one set of blind-shear rams as 

well as unlatch the LMRP. The BOP– 

ROV interface must allow sufficient 

volume to actuate all required functions. 

This requirement will ensure that the 

dedicated ROV has the capacity to close 

the BOP functions and secure the well 

in sufficient time during a well control 

event. The interim final rule will codify 

the section, ‘‘ROV Hot Stab Function 

Testing of the ROV Intervention Panel’’ 

in NTL No. 2010–N05. 

In paragraph (e), the operator is 

required to maintain an ROV and have 

a trained ROV crew on each floating 

drilling rig on a continuous basis. The 

crew must be trained in the operation of 

the ROV. The training must include 

simulator training on stabbing into an 

ROV intervention panel on a subsea 

BOP stack. This requirement will help 

provide assurance that a properly 

trained crew is available for use during 

an emergency situation. 

Requirements related to autoshear and 

deadman systems in paragraph (f) were 

added. Autoshear, deadman, and 

acoustic systems are all emergency 

systems. Dynamically positioned rigs 

must have autoshear and deadman 

systems. Autoshear system is defined as 

a safety system that is designed to 

automatically shut in the wellbore in 

the event of an unplanned disconnect of 

the LMRP. When the autoshear is 

armed, a disconnect of the LMRP closes 

the shear rams. Deadman system is 

defined as a safety system that is 

designed to automatically close the 

wellbore in the event of a simultaneous 

absence of hydraulic supply and signal 

transmission capacity in both subsea 

control pods. Both autoshear and 

deadman are considered ‘‘rapid 

discharge’’ systems. Dynamically 

positioned rigs may also use an acoustic 

system. An acoustic signal transmission 

may be used as an emergency backup 

that controls critical BOP functions. 

However, BOEMRE believes additional 

evaluation is necessary to determine the 

reliability of acoustic signal 

transmission as a mandatory backup 

control system. Industry, academics and 

other stakeholders have raised concerns 

about how the differences in water 

temperatures between water layers 

(deepwater thermocline) will affect the 

transmission of the acoustic signal to 

the BOP stack when installed in 

deepwater. Similar concerns were raised 

about how different salinities between 

water layers, noise from a wild well, or 

other subsea noise may interfere with 

the successful transmission of the 

acoustic signals to the BOP stack. 

Further investigation of these concerns 

is needed before deciding to require the 

installation of an acoustic backup 

control system. The interim final rule 

will codify the section, ‘‘Secondary 

Control System Requirements and 

Guidelines for Subsea BOP Stacks’’ in 

NTL No. 2010–N05. 

In paragraph (g), the operator is 

required to have operational or physical 

barrier(s) on BOP control panels to 

prevent accidental use of disconnect 

functions. The operator must 

incorporate enable buttons on control 

panels to ensure two-handed operation 

for all critical functions. The new 

requirements in this paragraph will 


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63360 Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 

reduce the chances of an accidental 

disconnect by requiring two separate 

actions to activate all critical functions. 

In paragraph (h), the operator is 

required to clearly label all control 

panels for the subsea BOP system. The 

operator must include all BOP controls 

such as hydraulic control panels and 

ROV interface on the BOP. The new 

requirements in this paragraph will help 

to ensure that the correct function is 

executed. The labeling of all functions 

will also assist in proper usage in an 

emergency situation. 

In paragraph (i), the operator is 

required to develop and use a 

management system for operating the 

BOP system. This includes guidance to 

prevent accidental or unplanned 

disconnects of the system. This 

management system must include 

written procedures for operating the 

BOP stack and LMRP, and minimum 

knowledge requirements for personnel 

authorized to operate and maintain BOP 

components. A copy of these written 

procedures should be maintained on the 

drilling rig and in other readily 

accessible locations. These procedures 

must be made available to all relevant 

personnel. The new requirements in this 

paragraph will help to ensure that the 

correct function is executed in an 

emergency situation. 

Paragraph (j) requires the operator to 

establish minimum requirements for 

personnel authorized to operate critical 

BOP equipment. This training must 

include deepwater well control theory 

and practice in accordance with 30 CFR 

part 250, subpart O, and a 

comprehensive knowledge of BOP 

hardware and control systems. 

Paragraphs (k) and (l) are currently 

required, but were reformatted into the 

table. Paragraph (k) requires the 

operator to displace the fluid in the riser 

with seawater before removing the 

marine riser; while conducting this 

operation, the operator must maintain 

sufficient hydrostatic pressure on the 

well or take other suitable precautions 

to compensate for the reduction in 

pressure to maintain well control. 

Paragraph (l) requires that when drilling 

in an ice-scour area, the BOP stack must 

be installed in a glory hole (a depression 

deep enough that the equipment is 

protected). 

These requirements help ensure 

enhanced operability of subsea BOP 

systems. These requirements will also 

help to ensure that the proper personnel 

are trained to have a comprehensive 

knowledge of well control equipment, 

maintain well control equipment, 

operate essential well control 

equipment, and manage a well control 

situation. 

The ROV intervention capability and 

autoshear and deadman requirements in 

this section address Safety Measures 

Report recommendation I.B.5: 

Secondary Control System 

Requirements and Guidelines, and 

recommendation I.B.6: New ROV 

Operating Capabilities. The new 

requirements also meet Safety Measures 

Report recommendation II.A.1: Establish 

Deepwater Well-Control Procedure 

Guidelines. 

What are the BOP maintenance and 

inspection requirements? (§ 250.446) 

Paragraph (a) of this section was 

changed to require the operator to 

document the maintenance and 

inspections of their BOP system. The 

requirement that BOP maintenance and 

inspections must meet or exceed the 

provisions of Sections 17.10 and 18.10, 

Inspections; Sections 17.11 and 18.11, 

Maintenance; and Sections 17.12 and 

18.12, Quality Management; described 

in API RP 53, Recommended Practices 

for Blowout Prevention Equipment 

Systems for Drilling Wells (incorporated 

by reference as specified in § 250.198) 

was not changed. The operator must 

document the procedures used, record 

the results, and make the results 

available to BOEMRE upon request. The 

operator must maintain the records on 

the rig for 2 years or from the date of 

the last major inspection, whichever is 

longer. 

The BOP maintenance, inspections, 

and quality management are essential 

components to ensuring BOP integrity 

and operability. According to API RP 

53, Section 17.10 (surface BOPs) and 

Section 18.10 (subsea BOPs), operators 

must perform a between-well 

inspection, a visual inspection of 

flexible choke and kill lines, and a 

major 3–5 year inspection. According to 

API RP 53, Section 17.11 (surface BOPs) 

and Section 18.11 (subsea BOPs), 

operators are required to maintain BOP 

manuals, connections, replacement 

parts, torque requirements, equipment 

storage, lubricants and hydraulic fluids, 

weld repairs, and mud/gas separators. 

According to API RP 53, Section 17.12 

(surface BOPs) and Section 18.12 

(subsea BOPs), operators are required to 

have a planned maintenance system, 

with equipment identified, tasks 

specified, and the time intervals 

between tasks stated. Records of 

maintenance performed and repairs 

made must be retained on file at the rig 

site or readily available. 

The interim final rule will codify the 

section, ‘‘BOP Inspection, Maintenance, 

and Repair for All Wells’’ in NTL No. 

2010–N05. The documentation for BOP 

maintenance, repairs, and inspections 

meet the Safety Measures Report 

recommendation I.B.5: Secondary 

Control System Requirements and 

Guidelines. 

What additional BOP testing 

requirements must I meet? (§ 250.449) 

New paragraphs (j) and (k) were 

added and paragraphs (h) and (i) were 

revised to accommodate the new 

paragraphs. New paragraph (j) requires 

the testing of ROV intervention 

functions on a subsea BOP stack. The 

ROV intervention functions must be 

tested during the stump test. This test 

must include ensuring that the hot stabs 

are function tested and are capable of 

actuating one set of pipe rams and one 

set of blind-shear rams, as well as 

unlatching the LMRP. The operator 

must also test at least one set of rams 

during the initial test on the seafloor. 

The BOP–ROV interface must allow 

sufficient volume to actuate all required 

functions. The operator must document 

the test results and make them available 

to BOEMRE upon request. This will 

help to ensure that the ROV and hot 

stabs are capable of actuating the BOP 

rams and LMRP disconnect. The interim 

final rule will codify requirements 

addressed under the section, ‘‘ROV Hot 

Stab Function Testing of the ROV 

Intervention Panel’’ in NTL No. 2010– 

N05; which required testing of ROV 

intervention functions during the stump 

test. The interim final rule will also 

require function testing during the 

initial test on the seafloor. A successful 

test will help ensure that the ROV and 

BOP are capable of operating as 

designed under conditions at water 

depth. 

New paragraph (k) requires function 

testing of the autoshear and deadman 

systems on the BOP stack during the 

stump test. The operator must submit 

the testing procedures for these 

requirements with the APD or APM for 

BOEMRE approval. This should include 

the sequence of BOP functions that will 

activate when the autoshear and 

deadman systems are triggered. These 

requirements will help to ensure that a 

well is secured in an emergency 

situation, loss of power, or accidental 

disconnect, preventing the possible loss 

of well control. The ROV intervention 

capability and autoshear and deadman 

requirements in this section address 

Safety Measures Report 

recommendation I.B.5: Secondary 

Control System Requirements and 

Guidelines and recommendation I.C.7: 

Develop New Testing Requirements. 


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What must I do in certain situations 

involving BOP equipment or systems? 

(§ 250.451) 

A new item was added to the table, 

requiring the operator to perform a full 

pressure test when the blind-shear rams 

or casing shear rams are used in an 

emergency. Following activation of the 

blind-shear rams or casing shear rams, 

in which pipe or casing is sheared 

during a well control situation, the 

operator must retrieve and physically 

inspect the BOP and conduct a full 

pressure test of the BOP stack, after the 

situation is fully controlled. This will 

help ensure the integrity of the BOP and 

that the BOP will fully function and 

hold pressure after the event. If rams, 

sealing elements, or other equipment are 

damaged, they must be replaced or 

repaired. 

The interim final rule will codify the 

section, ‘‘BOP Inspection Testing after 

Well Control Event for All Wells’’ in 

NTL No. 2010–N05. The tests required 

after a well control event in this section 

addresses Safety Measures Report 

recommendation I.C.7: Develop New 

Testing Requirements. 

What safe practices must the drilling 

fluid program follow? (§ 250.456) 

A new paragraph (j) was added, the 

current (j) was redesignated to 

paragraph (k) and paragraph (i) was 

revised to accommodate the new 

paragraph. The new paragraph (j) 

requires approval from the District 

Manager before displacing kill-weight 

drilling fluid from the wellbore. The 

operator must submit with the APD or 

APM the reasons for displacing the killweight drilling fluid and provide 

detailed step-by-step written procedures 

describing how the operator will safely 

displace these fluids. The step-by-step 

displacement procedures must address 

the following: 

1. Number and type of independent 

barriers that are in place for each flow 

path; 

2. Tests to ensure integrity of 

independent barriers; 

3. BOP procedures used while 

displacing kill weight fluids; and 

4. Procedures to monitor fluids 

entering and leaving the wellbore. 

These new requirements better ensure 

that well control is not compromised 

when displacing kill-weight fluid out of 

the wellbore. The requirement to submit 

procedures for kill-weight drilling fluid 

displacement in this section addresses 

Safety Measures Report 

recommendation II.A.2: New Fluid 

Displacement Procedures. 

Blowout prevention equipment. 

(§ 250.515) 

This section added requirements of 

§ 250.442 in subpart D, Oil and Gas 

Drilling Operations, to the requirements 

for well completion operations using a 

subsea BOP stack. 

Blowout preventer system tests, 

inspections, and maintenance. 

(§ 250.516) 

Paragraph (d)(8) was added to require 

tests for ROV intervention functions 

during the stump test. Paragraph (d)(9) 

was added to require a function test of 

the autoshear and deadman system. 

Paragraph (d)(6) was revised to 

accommodate the new paragraphs. This 

section adds the requirements of 

§ 250.449 in subpart D, Oil and Gas 

Drilling Operations, to the requirements 

for well completion operations using a 

subsea BOP stack. The interim final rule 

will require successful testing of both 

systems during the stump test. 

Successful tests will ensure the 

autoshear and deadman system are 

operating as designed. A function test of 

the deadman system is also required 

during the initial test on the seafloor. 

Successful testing the deadman system 

during the initial test on the seafloor 

will ensure the system is capable of 

operating as designed under conditions 

at water depth. 

Paragraphs (g) and (h) were revised to 

expand and clarify the requirements for 

inspections and maintenance. The BOP 

maintenance, inspections, and quality 

management are essential to BOP 

operability. This section adds 

requirements of § 250.446 in subpart D, 

Oil and Gas Drilling Operations, to the 

requirements for well completion 

operations using a subsea BOP stack. 

The operator must maintain the records 

on the rig for 2 years or from the date 

of the last major inspection, whichever 

is longer. 

The documentation for BOP 

maintenance, repairs, and inspections 

meets the Safety Measures Report 

recommendation I.B.5: Secondary 

Control System Requirements and 

Guidelines and recommendation I.C.7: 

Develop New Testing Requirements. 

Blowout prevention equipment. 

(§ 250.615) 

This section added requirements of 

§ 250.442 in subpart D, Oil and Gas 

Drilling Operations, to the requirements 

for well workover operations using a 

subsea BOP stack. 

Blowout preventer system testing, 

records, and drills. (§ 250.616) 

Paragraph (h)(1) was added to require 

tests for ROV intervention functions 

during the stump test. Paragraph (h)(2) 

was added to require a function test of 

the autoshear and deadman systems. 

Paragraph (h)(3) was added to require 

the use of water to stump test a subsea 

BOP system. This section adds the 

requirements of § 250.449 in subpart D, 

Oil and Gas Drilling Operations, to the 

requirements for well workover 

operations using a subsea BOP stack. 

The interim final rule will require 

testing of both systems during the stump 

test. Successful tests will ensure the 

autoshear and deadman systems are 

operating as designed. A function test of 

the deadman system is also required 

during the initial test on the seafloor. 

Testing the deadman system during the 

initial test on the seafloor will help 

ensure the system is capable of 

operating as designed under conditions 

at water depth. 

What are my BOP inspection and 

maintenance requirements? (§ 250.617) 

This section was added to apply the 

requirements of § 250.446 in subpart D, 

Oil and Gas Drilling Operations, to the 

requirements for well workover 

operations using a subsea BOP stack. 

Definitions. (§ 250.1500) 

BOEMRE revised the definition of 

well control by creating separate 

definitions for the terms well servicing 

and well completion/well workover. 

A new definition for deepwater well 

control was added. The rule adds 

deepwater well control throughout 

subpart O as one of the subjects for 

employee and contract personnel 

training. This clarification helps ensure 

that rig personnel are trained in 

deepwater well control and the specific 

duties, equipment, and techniques 

associated with deepwater drilling. 

What are my general responsibilities for 

training? (§ 250.1503) 

In this section, new paragraph (b) was 

added and current paragraphs (b) and 

(c) were redesignated as (c) and (d). The 

operator is required to ensure that 

employees and contract personnel are 

trained in deepwater well control when 

conducting operations with a subsea 

BOP stack. They must have a 

comprehensive knowledge of deepwater 

well control equipment, practices, and 

theory. This clarification of existing 

requirements addresses Safety Measures 

Report recommendation II.A.1: Establish 

Deepwater Well-Control Procedure 

Guidelines. 


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What information must I submit before 

I permanently plug a well or zone? 

(§ 250.1712) 

In this section, new paragraph (g) was 

added and paragraphs (e) and (f)(14) 

were revised to accommodate the new 

paragraph. New paragraph (g) requires 

operators to submit certification by a 

Registered Professional Engineer of the 

well abandonment design and 

procedures. The Registered Professional 

Engineer must be registered in a State in 

the United States. The Registered 

Professional Engineer does not have to 

be a specific discipline, but must be 

capable of reviewing and certifying that 

the casing design is appropriate for the 

purpose for which it is intended under 

expected wellbore conditions. The 

Registered Professional Engineer will 

certify that there will be at least two 

independent tested barriers, including 

one mechanical barrier, across each flow 

path during well abandonment 

activities. The Registered Professional 

Engineer will also certify that the plug 

meets the requirements in the table in 

§ 250.1715. This will help ensure the 

integrity of the well. The operator must 

submit this certification along with the 

APM. The operator should not deviate 

from the certified procedure; if the 

operator deviates from the certified 

procedures, they must contact the 

appropriate District Manager. The 

interim final rule will codify the 

section, ‘‘Well Design and Construction 

for All Wells’’ in NTL No. 2010–N05. 

This new requirement addresses Safety 

Measures Report recommendation 

II.B.1.3: New Casing and Cement Design 

Requirements: Two Independent Tested 

Barriers. 

If I temporarily abandon a well that I 

plan to re-enter, what must I do? 

(§ 250.1721) 

In this section, new paragraph (h) was 

added to require operators to submit 

certification by a Registered Professional 

Engineer of the well abandonment 

design and procedures. The Registered 

Professional Engineer does not have to 

be a specific discipline. The Registered 

Professional Engineer must be registered 

in a State in the United States. As 

mentioned previously, the Registered 

Professional Engineer does not have to 

be a specific discipline, but must be 

capable of reviewing and certifying that 

the casing design is appropriate for the 

purpose for which it is intended under 

expected wellbore conditions. The 

Registered Professional Engineer will 

certify that there will be at least two 

independent tested barriers, including 

one mechanical barrier, across each flow 

path during well abandonment 

activities. This will help ensure the 

integrity of the well. The operator must 

submit this certification to BOEMRE 

along with the APM, as required in 

§ 250.1712 and is responsible for 

ensuring that the approved well 

abandonment design and procedures are 

followed. The operator should not 

deviate from the certified procedure, if 

the operator deviates from the certified 

procedures they must contact the 

appropriate District Manager. 

Paragraphs (e) and (g)(3) were revised to 

accommodate the new paragraph. The 

interim final rule will codify 

requirements addressed under the 

section, ‘‘Well Design and Construction 

for All Wells’’ in NTL No. 2010–N05. 

This new requirement addresses Safety 

Measures Report recommendation 

II.B.1.3: New Casing and Cement Design 

Requirements: Two Independent Tested 

Barriers. 

VII. Additional Recommendations in 

the Safety Measures Report Not 

Covered in This Interim Final Rule 

As discussed previously, this interim 

final rule incorporates some, but not all 

items from the Safety Measures Report. 

The following tables specifically 

identify which measures from the Safety 

Measures Report are not covered in the 

interim final rule. BOEMRE anticipates 

it will be able to address these measures 

in notice and comment rulemakings in 

the future. 

Items in the Safety Measures Report 

that are not covered in this interim final 

rule, and which BOEMRE anticipates 

addressing either in the near future, or 

at a later time after further review and 

analysis, are as follows: 

ITEMS FOR FUTURE RULEMAKING

Number Recommendation 

I.A.3 ......... Develop Formal Equipment Certification Requirements. 

I.B.4 ......... New Blind Shear Ram Redundancy Requirement. 

II.B.3.8 ..... Develop Additional Requirements or Guidelines for Evaluation of Cement Integrity. 

II.C.9 ........ Increase Federal Government 

Wild-Well Intervention Capabilities. 

II.C.10 ...... Study Innovative Wild-Well Intervention, Response Techniques, and Response Planning. 

III.C.2 ....... Adopt Safety Case Requirements for Floating Drilling Operations on the OCS. 

III.C.4 ....... Study Additional Safety Training 

and Certification Requirements. 

There are also certain items which, 

although they are included in this 

interim final rule, BOEMRE anticipates 

expanding upon in the future. BOEMRE 

is specifically considering additional 

rulemaking activity concerning the 

following: 

ITEMS INCLUDED IN THIS RULE UNDER

CONSIDERATION FOR EXPANSION

Number Recommendation 

I.B.5 ......... Secondary Control System Requirements and Guidelines. 

I.B.6 ......... New ROV Operating Capabilities. 

II.A.1 ........ Establish Deepwater Well-Control Procedure Guidelines. 

II.B.1.4 ..... Study Formal Personnel Training 

Requirements for Casing and 

Cementing Operations. 

II.B.2.6 ..... Develop Additional Requirements or Guidelines for Casing Installation. 

II.B.3.7 ..... Enforce Tighter Primary Cementing Practices. 

Additionally, as discussed further, 

BOEMRE is examining a variety of other 

well control issues related to OCS 

drilling to determine how to improve 

future safety on the OCS in light of the 

Deepwater Horizon event. 

BOEMRE recognizes that this interim 

final rule does not fully address all 

issues associated with OCS drilling 

operations, although it is a critical step. 

We anticipate future rulemakings as we 

learn more about the causes of the 

Deepwater Horizon event and other 

issues associated with deepwater 

drilling operations. Future rulemakings 

will be based on recommendations in 

the Safety Measures Report that require 

further development, the results of the 

joint USCG–BOEMRE investigation, 

other investigations and inquiries, and 

findings from technology-focused 

research led by DOI strike teams and 

interagency workgroups. Some of the 

issues that are addressed by this 

rulemaking, such as cementing and 

casing design, will be considered for 

additional rulemaking in the future. We 

will consider additional measures, after 

we have more thoroughly studied these 

issues and assessed the best approaches. 

BOEMRE has identified the following 

issues as likely topics for both near-term 

and future rulemakings: 

Well Control Issues 

While the content of these future 

rulemakings will depend in part on the 

findings of the various investigations, 

BOEMRE anticipates that future rules 

will focus on well control issues. More 

specifically this will include: 

1. Cementing and casing—BOEMRE 

anticipates examining the need for 

additional cement evaluation 


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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 63363 

procedures and training needs for 

personnel involved in cementing and 

casing operations, and intends to 

incorporate findings as appropriate from 

the investigations related to the 

Deepwater Horizon event. 

2. Fluid displacement—BOEMRE 

intends to further evaluate the 

effectiveness of new fluid displacement 

requirements to determine if it needs to 

establish different or enhanced fluid 

displacement procedures. 

3. BOPs—BOEMRE anticipates 

rulemaking to address BOP 

recommendations resulting from the 

joint BOEMRE and United States Coast 

Guard investigation of the Deepwater 

Horizon event. Rulemaking will also 

likely address the requirement to have 

two sets of blind shear rams as 

recommended in the Safety Measures 

Report and discussed previously. 

Rulemakings will also likely consider 

requirements for casing shear rams, 

minimum number of pipe rams, second 

annular preventer for subsea BOP 

stacks, and electronic BOP logs. Another 

area mentioned in the Safety Measures 

Report is the need for periodic 

certification of the BOP stack or specific 

BOP components. BOEMRE wishes to 

undertake additional research on how 

these certifications should be done and 

how often they should occur. 

4. Secondary control systems and 

ROVs—Future rulemaking may address 

autoshear and deadman requirements 

for all rigs with subsea BOP stacks, 

enhanced ROV intervention capability, 

and subsea accumulator volumes to 

ensure fast closure of BOPs and choke 

and kill lines. The need for effective 

tertiary control systems, such as an 

acoustic system, will also be examined 

and addressed as appropriate. 

5. Wild-well intervention 

techniques—BOEMRE will conduct 

research on this topic and evaluate the 

progress industry has made to establish 

deepwater wild-well intervention as it 

moves forward with rulemaking on wild 

well intervention. 

6. Industry training—BOEMRE will 

investigate safety training requirements 

for deepwater drilling operations and 

determine the appropriate manner to 

regulate the training of personnel. 

7. Oil spill response—BOEMRE 

anticipates future rulemaking to address 

the capture and disposition of oil 

released from a deepwater well blowout 

at the seafloor. 

8. Organization and safety 

management—The Safety Measures 

Report recommended that the DOI 

evaluate the need to require all or part 

of the International Association of 

Drilling Contractors’ Health, Safety, and 

Environmental Case Guidelines for 

Mobile Drilling Units. BOEMRE will 

evaluate the guidelines and determine 

how they will best fit with SEMS 

regulations that are being considered by 

BOEMRE for final publication in a 

separate rulemaking. BOEMRE 

published a notice of proposed 

rulemaking on SEMS requirements on 

June 17, 2009 (74 FR 28639). 

Technical Consensus Standards 

BOEMRE is aware that various 

organizations which support the 

offshore oil and gas industry are also 

studying the possible causes of the 

Deepwater Horizon event. Based on 

their findings, these organizations may 

make recommendations to their 

members on practices to increase the 

safety of offshore oil and gas operations 

in general with specific 

recommendations related to deepwater 

drilling operations. BOEMRE is 

reviewing the following subjects: 

1. API Documents Concerning 

Cementing Practices 

In § 250.198 of this interim final rule, 

BOEMRE incorporates API RP 65—Part 

2, Isolating Potential Flow Zones During 

Well Construction, which summarizes 

best practices and addresses basic issues 

associated with cementing practices. 

The API has additional documents that 

address cementing practices in more 

detail. 

2. Discussion of Additional 

Specifications and Recommended 

Practices 

API Spec 16A: Specification for DrillThrough Equipment 

This standard specifies requirements 

for performance, design, materials, 

testing and inspection, welding, 

marking, handling, storing, and 

shipping of drill-through equipment 

used for drilling for oil and gas. It also 

defines service conditions in terms of 

pressure, temperature, and wellbore 

fluids for which the equipment will be 

designed. This standard is applicable to, 

and establishes requirements for, the 

following specific equipment: ram 

BOPs; ram blocks, packers, and top 

seals; annular BOPs; annular packing 

units; hydraulic connectors; drilling 

spools; adapters; loose connectors; and 

clamps. 

API Spec 16D: Specification for Control 

Systems for Drilling Well Control 

Equipment and Control Systems for 

Diverter Equipment 

This specification provides design 

standards for systems used to control 

the BOP and associated valves that 

control well pressure during drilling 

operations. Diverter control systems are 

included in this specification because 

they are included in the BOP control 

system. This specification addresses the 

following categories: control systems for 

surface BOP stacks, control systems for 

subsea BOP stacks, discrete hydraulic 

control systems for subsea BOP stacks, 

electro-hydraulic/multiplex control 

systems for subsea BOP stacks, control 

systems for diverter equipment, 

auxiliary equipment control systems 

and interfaces, emergency disconnect 

sequenced systems (EDS), backup 

systems, and special deepwater/harsh 

environment features. 

Certain standards in API Spec. 16D 

are of particular interest. These include 

optional sections—5.7 Emergency 

Disconnect Sequenced Systems (EDS), 

5.8 Backup Control Systems, and 5.9 

Special Deepwater/Harsh Environment 

Features. The EDS systems are required 

for floating drilling rigs in order to 

quickly disconnect the riser in the event 

of an inability to maintain rig position 

within a prescribed watch circle. 

Backup Control Systems include 

standards on acoustic systems, ROV 

control systems, LMRP recovery 

systems, and backup power supply. The 

Deepwater/Harsh Environment features 

give specifications for autoshear and 

deadman systems. 

API Spec 17D: Specification for Subsea 

Wellhead and Christmas Tree 

Equipment 

This specification was formulated to 

provide for the availability of safe, 

dimensionally, and functionally 

interchangeable subsea wellhead, 

mudline, and tree equipment. The 

technical content provides requirements 

for performance, design, materials, 

testing, inspection, welding, marking, 

handling, storing, and shipping. Critical 

components are those parts having a 

requirement specified in this document. 

Rework and repair of used equipment 

are beyond the scope of this 

specification. 

API Recommended Practice 17H; ISO 

13628–8: Remotely Operated Vehicle 

(ROV) Interfaces on Subsea Production 

Systems 

This recommended practice gives 

functional requirements and guidelines 

for ROV interfaces on subsea production 

systems for the petroleum and natural 

gas industries. It is applicable to both 

the selection and use of ROV interfaces 

on subsea production equipment, and 

provides guidance on design as well as 

the operational requirements for 

maximizing the potential of standard 

equipment and design principles. The 

auditable information for subsea 

systems this document offers allows 


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63364 Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 

interfacing and actuation by ROVoperated systems, while it identifies 

issues that have to be considered when 

designing interfaces on subsea 

production systems. The framework and 

detailed specifications set out enable the 

user to select the correct interface for a 

specific application. 

API Recommended Practice 53: 

Recommended Practices for Blowout 

Prevention Equipment Systems for 

Drilling Wells 

This recommended practice provides 

guidance for installation and testing of 

surface and subsea BOP equipment 

systems. This equipment system 

consists of a BOP, choke and kill lines, 

marine riser, and auxiliary equipment. 

The primary function of a BOP 

equipment system is to confine wellbore 

fluids, provide a means to add fluids, 

and allow controlled volumes to be 

withdrawn from the wellbore. This 

recommended practice also addresses 

diverter systems. 

Other Items for Consideration 

BOEMRE is also studying the 

following issues: 

1. Following the certification of the 

BOP to meet the one-time requirement 

of NTL No. 2010–N05, frequency and 

conditions for recertification 

requirements. 

2. Requirements for BOP equipment 

and other components of the BOP stack 

such as control panels, communication 

pods, accumulator systems, and choke 

and kill lines and the adequacy of API 

Spec 16A. 

3. Standardization of the BOP–ROV 

interface to improve intervention 

capabilities. 

4. Issues related to requiring a subsea 

isolation device that is independent of 

the BOP stack that is capable of 

operating critical functions that will 

shut in a well in emergency situations. 

Procedural Matters 

Regulatory Planning and Review 

(Executive Order (E.O.) 12866) 

This interim final rule is a significant 

rule as determined by the Office of 

Management and Budget (OMB) and is 

subject to review under E.O. 12866. 

1. This rule will have an annual effect 

of $100 million or more on the 

economy. The following discussion 

summarizes a detailed cost-benefit 

analysis that is available on http:// 

www.Regulations.gov. Use the keyword/ 

ID ‘‘BOEM–2010–0034’’ to locate the 

docket for this rule. 

Various events around the world as 

well as the US over the years 

demonstrate that catastrophic oil spills 

can and do occur. The costs associated 

with such spills can be tremendous. As 

a matter of policy, BOEMRE has decided 

that any reasonable measures to reduce 

the risks of another catastrophic spill 

occurring on the OCS should be put in 

place and enforced. The requirements 

included in this rulemaking are such 

measures. They were identified in the 

May 27, 2010 report, Increased Safety 

Measures for Energy Development on 

the Outer Continental Shelf, for which 

the draft recommendations were peerreviewed by seven experts identified by 

the National Academy of Engineering., 

or identified by industry or academic 

experts in materials presented to 

BOEMRE. While the estimated costs of 

this rulemaking, as reflected in the 

compliance costs of the enumerated 

requirements of approximately $180 

million per year, have a strong 

foundation and are based on surveys of 

public and industry sources, 

quantification of the benefits is 

uncertain. The benefits are represented 

by the avoided costs of a catastrophic 

spill, which are estimated under the 

stipulated scenario as being $16.3 

billion per spill avoided. These 

regulations will reduce the likelihood of 

another blowout and associated spill, 

but the risk reduction associated with 

the specific provisions of this 

rulemaking cannot be quantified 

because there are many complex factors 

that affect the risk of a blowout event. 

As noted by the Secretary of the Interior 

in his July 12 decision memo 

suspending certain drilling activities, 

drilling accidents can have a profound, 

devastating impact on the economic and 

environmental health of a region. The 

measures codified in this rule will 

reduce the likelihood of such an event 

in the future, at a cost that is not 

prohibitive, and therefore this 

rulemaking is justified. 

The purpose of a benefit-cost analysis 

is to provide policy makers and others 

with detailed information on the 

economic consequences of the 

regulatory requirements. The benefitcost analysis for this rule was conducted 

using a scenario analysis. The benefitcost analysis considers a regulation 

designed to reduce the likelihood of a 

catastrophic oil spill. The costs are the 

compliance costs of imposed regulation. 

If another catastrophic oil spill is 

prevented, the benefits are the avoided 

costs associated with a catastrophic oil 

spill (e.g., reduction in expected natural 

resource damages owing to the 

reduction in likelihood of failure). 

Avoided cost is an approximation of 

the ‘‘true’’ benefits of avoiding a 

catastrophic oil spill. A benefits transfer 

approach is used to estimate the 

avoided costs. The benefits transfer 

method estimates economic values by 

transferring existing benefit calculations 

from studies already completed for 

another location or issue to the case at 

hand. Accordingly, none of the avoided 

costs used for a hypothetical 

catastrophic spill rely upon, or should 

be taken to represent, our estimate for 

the BPDH event commencing on April 

20, 2010. 

Three new requirements account for 

virtually all of the compliance costs 

imposed by this regulation (1) use of 

dual mechanical barriers in addition to 

cement barriers in the final casing string 

to prevent hydrocarbon flow in the 

event of cement failure, (2) application 

of negative pressure tests to all 

intermediate and the production casing 

strings to ensure their proper 

installation, and (3) maintenance of 

standby ROV capability to close BOP 

rams and testing that capability after the 

BOP has been installed on the sea floor. 

BOEMRE estimates that these three 

requirements will impose compliance 

costs of approximately $174 million per 

year, representing 95 percent of the total 

annual compliance costs of $183 million 

associated with this rulemaking. These 

cost estimates were developed by 

BOEMRE based on public data sources 

and confidential information provided 

by several offshore operators and 

drilling companies. 

On the benefit side, the avoided costs 

for a hypothetical deepwater blowout 

resulting in a catastrophic oil spill are 

estimated to be about $16.3 billion (in 

2010 dollars). Most of this amount 

derives from detailed cleanup estimates 

developed using damage costs per barrel 

measures found in historical spill data 

(from all sources including pipeline, 

tanker, and shallow water as well as 

deepwater wells) and from aggregate 

damage measures contained in the legal 

settlement documents for past spills 

applied to a catastrophic deepwater 

spill of hypothetical size. The rest of the 

avoided cost amount represents the 

private costs for blowout containment 

operations. In sum, three components 

account for nearly the entire avoided 

spill cost total: (1) Natural resource 

damage to habitat and creatures, (2) 

infrastructure salvage and cleanup 

operations of areas soiled by oil, and (3) 

containment and well-plugging actions 

plus lost hydrocarbons. 

The estimate of compliance costs is 

somewhat uncertain. This is the case 

primarily because the $183 million 

annual estimate is perhaps higher than 

the actual costs that will be incurred by 

society from this rule because industry 

is voluntarily undertaking some steps 

following the BPDH event that overlap 


emcdonald on DSK2BSOYB1PROD with RULES2
Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 63365 

those in this regulation. The Joint 

Industry Task Force draft 

recommendations include use of 

mechanical barriers and negative 

pressure tests. Voluntary action, 

perhaps spurred on as well by revised 

liability expectations and increased 

insurance prospects, means the 

incremental costs associated with these 

overlapping measures are not truly 

imposed solely by the new regulations. 

Less incremental required costs reduce 

the improvement in reliability necessary 

for expected benefits to cover the cost of 

complying with the new regulations. On 

the benefit side, the total avoided cost 

estimate of $16.3 billion (representing a 

measure of expected benefits for 

avoiding a future catastrophic oil spill) 

is highly uncertain because of the 

limited historical data upon which to 

judge the cost of failure, the disparity 

between the damages associated with 

spills of different sizes, locations, and 

season of occurrence, and owing to the 

fact that the measure employed reflects 

only those outlays that we have been 

able to calculate based primarily upon 

factors derived from past oil spills. 

Possible losses from human health 

effects or reduced property values have 

not been quantified in this analysis. 

Moreover, the likelihood of a future 

blow out leading to a catastrophic oil 

spill is difficult to quantify because of 

limited historical data on catastrophic 

offshore blowouts. 

Benefit-Cost Result: Based on the 

occurrence of only a single catastrophic 

blowout, the number of GOM deepwater 

wells drilled historically (4,123), and 

the forecasted future drilling activity in 

the GOM (160 deepwater wells per 

year), the baseline risk of a catastrophic 

blowout is estimated to be about once 

every 26 years. Combining the baseline 

likelihood of occurrence with the cost of 

a hypothetical spill implies that the 

expected annualized spill cost is about 

$631 million ($16.3 billion once in 26 

years, equally likely in any 1 year). To 

balance the $183 million annual cost 

imposed by these regulations with the 

expected benefits, the reliability of the 

well control system needs to improve by 

about 29 percent ($183 million/$631 

million). We have found no studies that 

evaluate the degree of actual 

improvement that could be expected 

from dual mechanical barriers, negative 

pressure tests, and a seafloor ROV 

function test. We request comment with 

supporting evidence on the reliability 

improvement likely from these new 

provisions. 

2. This interim final rule will not 

adversely affect competition or State, 

local, or tribal governments or 

communities. 

3. This interim final rule will not 

create a serious inconsistency or 

otherwise interfere with an action taken 

or planned by another agency. 

4. This interim final rule will not alter 

the budgetary effects of entitlements, 

grants, user fees, or loan programs or the 

rights or obligations of their recipients. 

5. This interim final rule will not raise 

novel legal or policy issues arising out 

of legal mandates, the President’s 

priorities, or the principles set forth in 

E.O. 12866. 

Regulatory Flexibility Act: Initial 

Regulatory Flexibility Analysis 

Given the emergency nature of these 

rules, BOEMRE has not yet prepared a 

detailed Initial Regulatory Flexibility 

Analysis for this rule; however, 

BOEMRE intends to publish a 

supplemental Initial Regulatory 

Flexibility Analysis in the near future 

which will examine the impact of this 

regulation on small entities in greater 

detail than provided below. BOEMRE 

continues to be interested in all 

potential impacts of the interim final 

rule on small entities and welcomes 

comments on issues related to such 

impacts. These comments will assist 

BOEMRE in conducting further analysis 

than provided below regarding the 

economic impact of these regulations on 

small entities, as well as an opportunity 

to examine regulatory alternatives that 

can accomplish BOEMRE’s safety goals 

at a lower cost to small entities. 

This rulemaking affects lessees, 

operators of leases and drilling 

contractors on the OCS; thus this rule 

directly impacts small entities. This 

could include about 130 active Federal 

oil and gas lessees and more than a 

dozen drilling contractors and their 

suppliers. Small entities that operate 

under this rule are coded under the 

Small Business Administration’s North 

American Industry Classification 

System (NAICS) codes 211111, Crude 

Petroleum and Natural Gas Extraction, 

and 213111, Drilling Oil and Gas Wells. 

For these NAICS code classifications, a 

small company is one with fewer than 

500 employees. Based on these criteria, 

approximately 70 percent of companies 

operating on the OCS (91) are 

considered small companies. Therefore, 

BOEMRE has determined that this 

proposed rule will have an impact on a 

substantial number of small entities. 

The ownership share of deepwater 

leases for small entities is estimated to 

only be 12 percent. While a larger 

percentage of the oil service industry 

supporting the deepwater operators are 

small businesses, the lessees that hire 

and direct these support businesses will 

bear the burden of this rule. Small 

companies hold 55 percent of shallow 

water leases but a smaller portion of the 

costs of these regulations will affect 

drilling operations in shallow water. 

This rule will affect every new well 

on the OCS. Tighter regulatory 

standards for drilling operations and the 

increased cost of meeting these 

requirements as a result of regulations 

for extra tests and well standards will 

now be required. We estimate that this 

rulemaking will impose a recurring cost 

of $183 million each year for drilling 

OCS wells. Every operator and drilling 

contractor both large and small must 

meet the same criteria for drilling 

operations regardless of company size. 

However, the overwhelming share of the 

cost imposed by these regulations will 

fall on companies drilling deepwater 

wells, which are predominately the 

larger companies. In fact, 90 percent of 

the total costs will be imposed on 

deepwater lessees and operators where 

small businesses only hold 12 percent of 

the leases. Less than 10 percent of the 

total costs will apply to shallow water 

leases where a 55 percent lease 

ownership share is held by small 

companies. Furthermore, these 

compliance costs only impact drilling 

operations. Drilling costs are only a 

share of the total costs incurred by a 

company operating on the OCS. 

Nonetheless, small companies as both 

lease-holders, and contractors serving 

lease-holders, will bear meaningful 

costs under these regulations. Of the 

annual $183 million in annual cost 

imposed by the rule, we estimate that 

the $20 million will apply to small 

businesses in deepwater and $9 million 

in shallow water. In total we estimate 

that $29 million or 15.8 percent of these 

regulations’ cost will be borne by small 

businesses. 

Fiscal year 2009 aggregate annual Gulf 

of Mexico OCS oil and gas revenues 

were $31.3 billion. Using the same 

percentages of leases held as a proxy for 

production value in deep and shallow 

water, we estimate that 74 percent 

($23.3 billion) of the OCS revenues are 

ultimately received by large companies 

and 26 percent ($8.1 billion) by small 

companies. As a share of fiscal year 

2009 revenues this interim final rule 

would cost approximately 0.67 percent 

of OCS revenue for large companies and 

only 0.36 ($0.029/$8.1) percent for small 

companies. 

Even though this rule may not have a 

significant economic impact on small 

businesses, alternatives to ease impacts 

on small business were considered. One 

alternative is to exempt small 

businesses from the requirements of this 

interim final rule. A second alternative 

is to delay the implementation timelines 


emcdonald on DSK2BSOYB1PROD with RULES2
63366 Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 

to comply with the regulation. Both of 

these alternatives are being rejected by 

BOEMRE for this interim final rule 

because of the overriding need to reduce 

the chance of a catastrophic blowout 

event. We do not believe it is 

responsible for a regulator to 

compromise the safety of offshore 

personnel and the environment for any 

entity including small businesses. 

Offshore drilling is highly technical and 

can be hazardous, any delay may 

increase the interim risk of OCS drilling 

operations. 

Small Business Regulatory Enforcement 

Fairness Act 

This interim final rule is a major rule 

under the Small Business Regulatory 

Enforcement Fairness Act (5 U.S.C. 801 

et seq.). This interim final rule: 

a. Will have an annual effect on the 

economy of $100 million or more. This 

rule will affect every new well on the 

OCS, and every operator, both large and 

small must meet the same criteria for 

well construction regardless of company 

size. This rulemaking may have a 

significant economic effect on a 

substantial number of small entities and 

the impact on small businesses will be 

analyzed more thoroughly in an Initial 

Regulatory Flexibility Analysis. While 

large companies will bear the majority 

of these costs, small companies as both 

leaseholders and contractors supporting 

OCS drilling operations will be affected. 

Considering the new requirements for 

redundant barriers and new tests, we 

estimate that this rulemaking will add 

an average of about $1.42 million to 

each new deepwater well drilled and 

completed with a MODU, $170 

thousand for each new deepwater well 

drilled with a platform rig, and $90 

thousand for each new shallow water 

well. While not an insignificant amount, 

we note this extra recurring cost is less 

than 2 percent of the cost of drilling a 

well in deepwater and around 1 percent 

for most shallow water wells. 

b. Will not cause a major increase in 

costs or prices for consumers, 

individual industries, Federal, State, or 

local government agencies, or 

geographic regions. The impact on 

domestic deepwater hydrocarbon 

production as a result of these 

regulations is expected to be negative, 

but the size of the impact is not 

expected to materially impact the world 

oil markets. The deepwater GOM is an 

oil province and the domestic crude oil 

prices are set by the world oil markets. 

Currently there is sufficient spare 

capacity in OPEC to offset a decrease in 

GOM deepwater production that could 

occur as a result of this rule. Therefore, 

the increase in the price of hydrocarbon 

products to consumers from the 

increased cost to drill and operate on 

the OCS is expected to be minimal. 

However, more of the oil for domestic 

consumption may be purchased from 

overseas markets because the cost of 

OCS oil and gas production will rise 

relative to other sources of supply. This 

shift would contribute negatively to our 

balance of trade. 

c. Will not have significant adverse 

effects on competition, innovation, or 

the ability of U.S.-based enterprises to 

compete with foreign-based enterprises. 

d. May have adverse effects on 

employment, investment, and 

productivity. A meaningful increase in 

costs as a result of more stringent 

regulations and increased drilling costs 

may result in a reduction in the pace of 

deepwater drilling activity on marginal 

offshore fields, and reduce investment 

in our domestic energy resources from 

what it otherwise would be, thereby 

reducing employment in OCS and 

related support industries. The 

additional regulatory requirements in 

this rulemaking will increase drilling 

costs and add to the time it takes to drill 

deepwater wells. The resulting 

reduction in profitability of drilling 

operations may cause some declines in 

related investment and employment. A 

typical deepwater well drilled by a 

MODU may cost $90–$100 million. The 

added cost of these regulations for a 

deepwater well is expected to be about 

$1.42 million; this is less than a 2 

percent decrease in productivity for 

drilling a deepwater well as a result of 

these regulations. 

e. Accommodations for small business 

have not been made to avoid the risk of 

compromising the safety and 

environmental protections addressed in 

this rulemaking. Small businesses 

actively invest in offshore operations, 

owning a 12 percent interest in 

deepwater leases, most often as a 

minority partner. These regulations will 

make it more expensive for all interest 

holders in OCS leases, and we do not 

expect a disproportionate impact on 

small businesses. However, we 

anticipate that the costs in this rule may 

contribute to one or more of the 

following: 

1. Reduce the small business 

ownership share in individual 

deepwater leases. 

2. Cause small businesses to target 

their investments more in shallow water 

leases. 

3. Cause small businesses to target 

their investments more in onshore oil 

and gas operations or other natural 

resources. 

4. Small businesses may choose to 

invest or partner in overseas natural 

resource operations. 

f. There are many small businesses 

that support offshore oil and gas drilling 

operations including service, supply, 

and consulting companies. They will 

also be affected by this rule. Because we 

can reasonably anticipate an overall 

decrease in deepwater drilling activity 

due to the increased cost and regulatory 

burden, some businesses that support 

drilling operations may experience 

reduced business activity. Some small 

businesses may therefore decide to 

focus more on shallow water or other oil 

and gas offshore provinces overseas. 

g. There are some small businesses 

that may benefit from this rulemaking. 

Companies that are involved with 

inspecting and certifying this 

equipment, as well as consulting 

companies specializing in safety and 

offshore drilling, could see long-term 

growth. 

Unfunded Mandates Reform Act of 1995 

This rule will impose an unfunded 

mandate on State, local, or tribal 

governments or the private sector of 

more than $100 million per year. The 

rule will not have a significant or 

unique effect on State, local, or tribal 

governments or the private sector. A 

statement containing the information 

required by the Unfunded Mandates 

Reform Act (2 U.S.C. 1501 et seq.) is not 

required. 

Takings Implication Assessment (E.O. 

12630) 

Under the criteria in E.O. 12630, this 

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 

rule does not have federalism 

implications. This rule will not 

substantially and directly affect the 

relationship between the Federal and 

State governments. To the extent that 

State and local governments have a role 

in OCS activities, this rule will not 

affect that role. A Federalism 

Assessment is not required. 

Civil Justice Reform (E.O. 12988) 

This rule complies with the 

requirements of E.O. 12988. 

Specifically, this rule: 

a. Meets the criteria of section 3(a) 

requiring that all regulations be 

reviewed to eliminate errors and 


emcdonald on DSK2BSOYB1PROD with RULES2
Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 63367 

ambiguity and be written to minimize 

litigation; and 

b. Meets the criteria of section 3(b)(2) 

requiring that all regulations be written 

in clear language and contain clear legal 

standards. 

Consultation With Indian Tribes (E.O. 

13175) 

Under the criteria in E.O. 13175, we 

have evaluated this rule and determined 

that it has no substantial effects on 

federally recognized Indian tribes. 

Paperwork Reduction Act (PRA) 

This rule contains a collection of 

information that was submitted to and 

approved by OMB under the Paperwork 

Reduction Act of 1995 (44 U.S.C. 3501 

et seq.). The rule expands existing 

requirements, as well as adds new 

requirements in 30 CFR part 250, 

subparts D, E, and F. The OMB 

approved these requirements and their 

respective burden hours under an 

emergency request, OMB Control 

Number 1010–0185, 44,731 hours 

(expiration 04/30/2011). We will be 

accepting comments on the information 

collection (IC) aspects and burdens of 

this rulemaking until 60 days after 

October 14, 2010. 

The title of the collection of 

information for this rule is 30 CFR part 

250, Increased Safety Measures for Oil 

and Gas Drilling, Well-Completion, and 

Well-Workover Operations. 

Respondents primarily are the Federal 

OCS lessees and operators. The 

frequency of response varies depending 

upon the requirement. Responses to this 

collection of information are mandatory. 

BOEMRE will protect proprietary 

information according to the Freedom of 

Information Act (5 U.S.C. 552), its 

implementing regulations (43 CFR part 

2), 30 CFR 250.197, Data and 

information to be made available to the 

public or for limited inspection, and 30 

CFR part 252, OCS Oil and Gas 

Information Program. Even though this 

rulemaking becomes effective 

immediately, BOEMRE will be 

accepting comments, see the DATES

section, including the IC aspects of the 

rulemaking. See the ADDRESSES section 

for how to submit comments. 

As discussed earlier in the preamble, 

this interim final rulemaking is a 

revision to various sections of the 30 

CFR part 250 regulations that will 

amend drilling regulations in subparts 

D, E, F, O, and Q. This includes 

requirements that will implement 

various safety measures that pertain to 

drilling operations. The information 

collected will ensure sufficient 

redundancy in the BOPs; promote the 

integrity of the well and enhance well 

control; and facilitate a culture of safety 

through operational and personnel 

management. This rule will promote 

human safety and environmental 

protection. 

Under § 250.198, this section lists all 

of the documents incorporated by 

reference in the 30 CFR part 250 

regulations. This rulemaking revises this 

section to include the new 30 CFR part 

250 document we are incorporating and 

the document already incorporated that 

we are updating. Under the PRA (5 CFR 

part 1320), information and 

recordkeeping produced during 

customary and usual business activities 

are excluded from agency IC burdens. 

Information submitted or reported to the 

Federal Government that goes beyond 

these practices does count as burdens 

and is required to have OMB approval 

under the PRA. We consider all of the 

activities and operations performed in 

accordance with the documents 

incorporated by reference involved in 

this rulemaking to be customary and 

usual business activities because they 

are consensus standards developed by 

working task force groups. These groups 

are comprised of subject matter experts 

from the industry and government in 

the following fields: Blowout preventer 

equipment, cementing, and well design. 

Any information and recordkeeping 

produced during the conduct of 

operations or activities performed under 

those standards, therefore, do not count 

as new or additional IC burdens. 

The rulemaking clarifies 

requirements, but does not change the 

hour burdens in 30 CFR part 250, 

subpart O (1010–0128, expiration 11/30/ 

2012). This rulemaking also references, 

but does not change, the requirements 

and burdens in 30 CFR part 250, subpart 

Q (1010–0142, expiration 11/30/2010). 

However, the rule does change and add 

new requirements to those already 

approved for 30 CFR part 250, subparts 

D, E, and F, as explained in the 

following paragraphs. 

The current regulations on Oil and 

Gas Drilling Operations and associated 

IC are located in 30 CFR part 250, 

subpart D. The OMB approved the IC 

burden of the current subpart D 

regulations under control number 1010– 

0141 (expiration 11/30/2011). This 

interim final rule expands the current 

regulatory requirements and adds new 

requirements that pertain to subsea and 

surface BOPs, well casing and 

cementing, secondary intervention, 

unplanned disconnects, recordkeeping, 

well completion, and well plugging 

(+24,144 burden hours). 

The current regulations on Oil and 

Gas Well-Completion Operations and 

associated IC are located in 30 CFR part 

250, subpart E. The OMB approved the 

IC burden of the current subpart E 

regulations under control number 1010– 

0067 (expiration 12/31/2010). This 

interim final rule adds new regulatory 

requirements to this subpart that pertain 

to subsea and surface BOPs, secondary 

intervention, and well-completions 

(+4,669 burden hours). 

The current regulations on Oil and 

Gas Well-Workover Operations and 

associated IC are located in 30 CFR part 

250, subpart F. The OMB approved the 

IC burden of the current subpart F 

regulations under control number 1010– 

0043 (expiration 12/31/2010). This 

interim final rule adds new regulatory 

requirements to this subpart that pertain 

to subsea and surface BOPs, secondary 

intervention, unplanned disconnects, 

and well-workers (+15,918 burden 

hours). 

When this rulemaking becomes 

effective, the additional 30 CFR part 

250, subparts D, E, and F paperwork 

burdens will be incorporated into their 

respective primary collections; 1010– 

0141, 1010–0067, and 1010–0043, 

respectively. 

The following table provides a 

breakdown of the new burdens. 


emcdonald on DSK2BSOYB1PROD with RULES2
63368 Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 

Citation 

30 CFR 250 

Reporting and recordkeeping 

requirement Hour burden 

Average number 

of annual 

responses 

Annual 

burden 

hours 

Subpart D 

408, 409; 410–418; 420(a)(6); 

423(b)(3), (c)(1); 449(j), 

(k)(1); plus various references in subparts A, B, D, 

E, H, P, Q.

Apply for permit to drill/revised APD that includes any/all 

supporting documentation/evidence [test results, calculations, verifications, procedures, criteria, qualifications, etc.] 

and requests for various approvals required in subpart D 

(including §§ 250.423, 424, 427, 432, 442(c), 447, 448(c), 

449(j), (k), 451(g), 456(a)(3), (f), 460, 490(c)(1), (2)) and 

submitted via Form MMS–123 (Application for Permit to 

Drill).

6 ..................... MMS–123 .........

700 

4,200 

416(g)(2) ................................. Provide 24 hour advance notice of location of shearing ram 

tests or inspections; allow BOEMRE access to witness 

testing, inspections and information verification.

10 mins .......... 6 notifications ... 1 

420(b)(3) ................................. Submit dual mechanical barrier documentation after installation.30 mins .......... 700 submissions.350 

423(a) ..................................... Request approval of other pressure casing test pressures 

per District Manager.

Burden covered under 1010– 

0141. 

0 

423(b)(4), (c)(2) ...................... Perform pressure casing test; document results and make 

available to BOEMRE upon request.

30 mins .......... 700 drilling ops 

× 5 tests per 

ops = 3,500 

tests.

1,750 

442(c) ...................................... Request alternative method for the accumulator system ....... Burden covered under 1010– 

0141. 

0 

442(h) ..................................... Label all functions on all panels .............................................. 30 mins .......... 30 panels ......... 15 

442(i) ....................................... Develop written procedures for management system for operating the BOP stack and LMRP.4 ..................... 30 procedures .. 120 

442(j) ....................................... Establish minimum requirements for authorized personnel to 

operate BOP equipment; require training.

Burden covered under 1010– 

0128. 

0 

446(a) ..................................... Document BOP maintenance and inspection procedures 

used; record results of BOP inspections and maintenance 

actions; maintain records for 2 years; make available to 

BOEMRE upon request.

1 ..................... 105 rigs ............ 105 

449; 450; 467 ......................... Function test annular and rams; document results every 7 

days between BOP tests (biweekly). Note: part of BOP 

test.

Burden covered under 1010– 

0141. 

0 

449(j)(2) .................................. Test all ROV intervention functions on your subsea BOP 

stack; document all test results; make available to 

BOEMRE upon request.

10 ................... 110 wells .......... 1,100 

449(k)(2) ................................. Function test autoshear and deadman on your subsea BOP 

stack during stump test; document all test results; make 

available to BOEMRE upon request.

30 mins .......... 110 wells .......... 55 

456(i) ....................................... Record results of drilling fluid tests in drilling report ............... Burden covered under 1010– 

0141. 

0 

456(j) ....................................... Submit detailed step by step procedures describing displacement of fluids with your APD/APM [this submission 

obtains District Manager approval].

2 ..................... 110 wells .......... 220 

460; 465; 449(j), (k)(1); 

516(d)(8), (d)(9); 616(h)(1), 

(2); plus various references 

in subparts A, D, E, F, H, P, 

and Q.

Submit revised plans, changes, well/drilling records, procedures, certifications that include any/all supporting documentation etc., submitted on Form MMS–124 (Application 

for Permit to Modify).

4 ..................... MMS–124 .........

4,057 

16,228 

Subtotal ........................... .................................................................................................. ........................ 9,458 responses 24,144 

Subpart E 

516(d)(8) ................................. Submit test procedures with your APM for approval .............. Burden covered under 1010– 

0141. 

0 

516(d)(8) ................................. Function test ROV interventions on your subsea BOP stack; 

document all test results; make available to BOEMRE 

upon request.

10 ................... 110 wells .......... 1,100 


emcdonald on DSK2BSOYB1PROD with RULES2
Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 63369 

Citation 

30 CFR 250 

Reporting and recordkeeping 

requirement Hour burden 

Average number 

of annual 

responses 

Annual 

burden 

hours 

516(d)(9) ................................. Function test autoshear and deadman on your subsea BOP 

stack during stump test; document all test results; make 

available to BOEMRE upon request.

30 mins .......... 1,048 completions.524 

516(g)(l) .................................. Document the procedures used for BOP inspections; record 

results; maintain records for 2 years; make available to 

BOEMRE upon request.

7 days × 12 

hrs/day = 84.

105 rigs/once 

every 3 years 

= 35 per year.

2,940 

516(g)(2) ................................. Request alternative method to inspect a marine riser ............ Burden covered under 1010– 

0067. 

0 

516(h) ..................................... Document the procedures used for BOP maintenance; 

record results; maintain records for 2 years; make available to BOEMRE upon request.

1 ..................... 105 rigs ............ 105 

Subtotal ........................... .................................................................................................. ........................ 1,298 responses 4,669 

Subpart F 

616(h)(l) .................................. Test all ROV intervention functions on your subsea BOP 

stack; document all test results; make available to 

BOEMRE upon request.

10 hours ......... 1,226 workovers 12,260 

616(h)(2) ................................. Function test autoshear and deadman on your subsea BOP 

stack during stump test; document all test results; make 

available to BOEMRE upon request.

30 mins .......... 1,226 workovers 613 

617(a)(l) .................................. Document the procedures used for BOP inspections; record 

results; maintain records for 2 years; make available to 

BOEMRE upon request.

7 days × 12 

hrs/day = 84.

105 rigs/once 

every 3 years 

= 35 per year.

2,940 

617(a)(2) ................................. Request approval to use alternative method to inspect a marine riser.Burden covered under 1010– 

0067. 

0 

617(b) ..................................... Document the procedures used for BOP maintenance; 

record results; maintain records for 2 years; make available to BOEMRE upon request.

1 ..................... 105 rigs ............ 105 

Subtotal ........................... .................................................................................................. ........................ 2,592 responses 15,918 

Subpart Q 

1712(f), (g); 1721(h) ............... Submit with your APM, archaeological and sensitive biological features; Registered Professional Engineer certification.Burden covered under 1010– 

0141. 

0 

1721(e) ................................... Identify and report subsea wellheads, casing stubs, or other 

obstructions.

USCG requirements. 0 

Total ................................. .................................................................................................. ........................ 13,348 responses.44,731 

BOEMRE plans to follow this interim 

final rule with a request for a standard, 

3-year approval by OMB. The request 

will be processed under OMB’s normal 

clearance procedures in accordance 

with the provisions of OMB regulation 

5 CFR 1320.10. To facilitate processing 

of the normal clearance submission to 

OMB, BOEMRE invites the general 

public to comment on: (1) Whether this 

collection of information is necessary 

for the proper performance of 

BOEMRE’s functions, including whether 

the information has practical utility; (2) 

the accuracy of the estimates of the 

burden of the information collection, 

including the validity of the 

methodologies and assumptions used; 

(3) ways to enhance the quality, utility, 

and clarity of the information to be 

collected; (4) ways to minimize the 

burden of the information collection on 

respondents, including through the use 

of automated collection techniques or 

other forms of information technology; 

and (5) estimates of capital or start up 

costs, and costs of operation, 

maintenance and purchase of services to 

provide the information. 

An agency may not conduct or 

sponsor, and you are not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The public may 

comment, at any time, on the accuracy 

of the IC burden in this rule and may 

submit any comments to the Department 

of the Interior; Bureau of Ocean Energy 

Management, Regulation and 

Enforcement; Attention: Regulations 

and Standards Branch; Mail Stop 4024; 

381 Elden Street; Herndon, Virginia 

20170–4817. 

National Environmental Policy Act of 

1969 

We have prepared an environmental 

assessment to determine whether this 

rule will have a significant impact on 

the quality of the human environment 

under the National Environmental 

Policy Act of 1969. This rule does not 

constitute a major Federal action 

significantly affecting the quality of the 

human environment. A detailed 

statement under the National 

Environmental Policy Act of 1969 is not 

required because we reached a Finding 

of No Significant Impact. A copy of the 

Environmental Assessment can be 

viewed at http://www.Regulations.gov 

(type in ‘‘environmental assessment’’ for 


emcdonald on DSK2BSOYB1PROD with RULES2
63370 Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 

the document type and use the 

keyword/ID ‘‘BOEM–2010–0034’’). 

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 § 515, 114 Stat. 2763, 2763A–153– 

154). 

Effects on the Energy Supply (E.O. 

13211) 

This rule is a significant rule and is 

subject to review by the Office of 

Management and Budget under E.O. 

12866. The rule does have an effect on 

energy supply, distribution, or use 

because its provisions may delay 

development of some OCS oil and gas 

resources. The delay stems from the 

extra drill time and cost imposed on 

new wells which will somewhat slow 

exploration and development 

operations. We estimate an average 

delay of 2 days and cost of $1.42 million 

for most deepwater wells in the GOM. 

Increased imports or inventory 

drawdowns should compensate for most 

of the delay or reduction in domestic 

production. The recurring costs 

imposed on new drilling by this rule are 

very small (2 percent) relative to the 

cost of drilling a well in deepwater. In 

view of the high risk-reward associated 

with deepwater exploration in general, 

we do not expect this small regulatory 

surcharge from this rule to result in 

meaningful reduction in discoveries. 

Thus, we expect the net change in 

supply associated with this rule will 

cause only a slight increase in oil and 

gas prices relative to what they 

otherwise would have been. Normal 

volatility in both oil and gas market 

prices overshadow these rule related 

price effects, so we consider this an 

insignificant effect on energy supply 

and price. 

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: 

a. Be logically organized; 

b. Use the active voice to address 

readers directly; 

c. Use clear language rather than 

jargon; 

d. Be divided into short sections and 

sentences; and 

e. 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. 

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. 

Appendix A 

BOEMRE Response to the Deepwater 

Horizon Event and Resulting Oil Spill 

I. Description 

On April 20, 2010, the crew of the 

Transocean drilling rig Deepwater Horizon 

was preparing to temporarily abandon BP’s 

discovery well at the Macondo prospect, 52 

miles from shore in 4,992 feet of water in the 

GOM. An explosion and subsequent fire on 

the rig caused 11 fatalities and several 

injuries. The rig sank 2 days later, resulting 

in an uncontrolled release of oil that was 

declared a spill of national significance. 

II. Status of BOEMRE/USCG Joint 

Investigation 

The DOI and USCG are undertaking a joint 

investigation into the causes of the 

explosions and fire on the Deepwater 

Horizon. This joint investigation includes 

members of BOEMRE and the USCG and 

involves issuing subpoenas for documents 

and testimony, obtaining expert analyses of 

data and reports, holding public hearings, 

calling witnesses, and taking any other steps 

necessary to determine the cause of the spill. 

The purpose of this joint investigation is to 

develop conclusions about the cause and 

recommendations for preventing a similar 

event. The facts collected at the public 

hearings, along with the lead investigators’ 

conclusions and recommendations, will be 

forwarded to USCG Headquarters and 

BOEMRE for approval. Once approved, the 

final investigative report will be made 

available to the public and the media. The 

team has been given 9 months, from the date 

of the convening order (April 27, 2010), to 

submit the final report. 

III. DOI and BOEMRE actions 

In response to the Deepwater Horizon 

event, DOI and BOEMRE have taken several 

actions, as outlined below. Numerous other 

investigations and reviews have been 

commenced, including an investigation by 

the DOI Safety Oversight Board; an 

investigation by the President’s National 

Commission on the BP Deepwater Horizon 

Oil Spill and Offshore Drilling; the USCG 

incident Specific Preparedness Review; a 

review by the National Academy of 

Engineering; a review by the U.S. Chemical 

Safety Board; and others. This Appendix 

addresses only BOEMRE actions. These are 

as follows: 

1. Issued a Joint Safety Alert with USCG on 

April 30, 2010. 

2. Published the Safety Measures Report on 

May 27, 2010, at the request of the President. 

3. Issued National NTL No. 2010–N05, 

‘‘Increased Safety Measures for Energy 

Development on the OCS,’’ to implement the 

immediate recommendations from the Safety 

Measures Report. 

4. Issued National NTL No. 2010–N06, 

‘‘Information Requirements for Exploration 

Plans, Development and Production Plans, 

and Development Operations Coordination 

Documents on the OCS.’’ 

5. Implemented Secretarial Decision dated 

July 12, 2010, ordering the suspensions of 

drilling activities that use a subsea BOP stack 

and drilling from floating facilities with a 

surface BOP stack. 

6. Held public meetings to collect 

information and views about deepwater 

drilling safety reforms, blowout containment, 

and oil spill response. 

1. Joint USCG–BOEMRE Safety Alert 

On April 30, 2010, USCG and BOEMRE 

issued a National Safety Alert No. 2 

concerning the Deepwater Horizon event and 

resulting oil spill. BOEMRE and the USCG 

included the following safety 

recommendations to operators and drilling 

contractors: 

(1) Examine all well control equipment 

(both surface and subsea) currently being 

used to ensure that it has been properly 

maintained and is capable of shutting in the 

well during emergency operations. Ensure 

that the ROV hot-stabs are function-tested 

and are capable of actuating the BOP. 

(2) Review all rig drilling/casing/ 

completion practices to ensure that well 

control contingencies are not compromised at 

any point while the BOP is installed on the 

wellhead. 

(3) Review all emergency shutdown and 

dynamic positioning procedures that 

interface with emergency well control 

operations. 

(4) Inspect lifesaving and firefighting 

equipment for compliance with Federal 

requirements. 

(5) Ensure that all crew members are 

familiar with emergency/firefighting 

equipment, as well as participate in an 

abandon ship drill. Operators are reminded 

that the review of emergency equipment and 

drills should be conducted after each crew 

change out. 

(6) Exercise emergency power equipment 

to ensure proper operation. 

(7) Ensure that all personnel involved in 

well operations are properly trained and 

capable of performing their tasks under both 

normal drilling and emergency well control 

operations. 

2. Safety Measures Report 

a. Summary 

On April 30, 2010, the President ordered 

the Secretary of the Interior to conduct a 


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thorough review of this event and to report, 

within 30 days, on what, if any, additional 

precautions and technologies should be 

required to improve the safety of oil and gas 

exploration and production operations on the 

OCS. The Safety Measures Report was 

presented to the President on May 27, 2010. 

A copy of the report is available at: http:// 

www.doi.gov/news/pressreleases/ 

loader.cfm?csModule=security/ 

getfile&PageID=33646. 

The Safety Measures Report was developed 

without the benefit of the findings from the 

ongoing investigations into the root causes of 

the explosions and fire on the Deepwater 

Horizon and the resulting oil spill. In the 

coming months, those investigations will 

likely suggest refinements to some of this 

report’s recommendations, as well as 

additional safety measures. 

The Safety Measures Report includes a 

history of OCS production, spills, and 

blowouts; a review of the existing U.S. 

regulatory and enforcement structure; a 

survey of other countries’ regulatory 

approaches; and a summary of existing 

BOEMRE-sponsored studies on technologies 

that could reduce the risk of blowouts. The 

report examines all aspects of drilling 

operations, including equipment, procedures, 

personnel management, and inspections and 

verification in an effort to identify safety and 

environmental protection measures that 

would reduce the risk of a catastrophic event. 

In particular, this report examines several 

issues highlighted by the Deepwater Horizon 

event regarding operational and personnel 

safety while conducting drilling operations 

in deepwater environments. 

The Safety Measures Report includes a 

number of recommendations to improve the 

safety of oil and gas drilling operations on 

the OCS. These recommendations address: 

• Well-control and well abandonment 

operations; 

• Specific requirements for devices, such 

as BOPs and their testing; 

• Industry practices; 

• Worker training; 

• Inspection protocol and operator 

oversight; and 

• The responsibility of the Department for 

safety and enforcement. 

The draft recommendations were peer 

reviewed by seven experts identified by the 

National Academy of Engineering. 

b. Implementation teams. To inform the 

efforts related to implementation of some of 

the recommendations from the Safety 

Measures Report, the DOI Safety Oversight 

Board Report, the recommendations to be 

developed by the President’s bipartisan 

National Commission and other investigative 

and reviewing bodies, DOI is establishing 

Department-led implementation teams. These 

teams, initially described as ‘‘strike teams’’ in 

the Safety Measures Report, will evaluate 

various issues, both highly technical and 

non-technical. 

The implementation teams will seek input 

as appropriate from academia, industry, and 

other technical experts and stakeholders. 

They will develop and present their 

recommendations for further actions to 

address additional environmental protection 

and safety measures. The Department may 

use the recommendations from these 

implementation teams to: 

(1) Inform future rulemaking, 

(2) Develop internal policy for inspections 

and enforcement of regulations, 

(3) Identify future research needs. 

3. NTL No. 2010–N05—Increased Safety 

Measures for Energy Development on the 

OCS 

The NTL No. 2010–N05, ‘‘Increased Safety 

Measures for Energy Development on the 

OCS,’’ addressed the recommendations from 

the Safety Measures Report that warranted 

immediate implementation. The link to this 

NTL is: http://www.gomr.boemre.gov/ 

homepg/regulate/regs/ntls/2010NTLs/10- 

n05.pdf. 

BOEMRE issued this NTL on June 8, 2010, 

as a result of the Deepwater Horizon event. 

The NTL addresses the recommendations in 

the report to the President entitled, 

‘‘Increased Safety Measures for Energy 

Development on the Outer Continental Shelf’’ 

dated May 27, 2010, and details under thenexisting regulations the requirements lessees 

and operators must meet to operate on the 

OCS. Following are the specific items 

included in the NTL: 

Operators are required to: 

• Verify compliance with existing 

regulations and Safety Alert issued on April 

30, 2010. 

• Submit BOP and well control system 

configuration information for the drilling rig 

that was being used. 

• Recertify all BOP equipment before 

resuming drilling. 

• Have documentation showing that the 

BOP has been maintained according to the 

regulations at 30 CFR 250.446(a). The 

operators are required to maintain records 

and make them available upon request. 

• Obtain independent third party 

verification that the BOP stack is designed for 

the specific equipment on the rig and 

compatible with the specific well location, 

well design, and well execution plan; the 

BOP stack has not been compromised or 

damaged from previous service; and the BOP 

stack will operate in the conditions in which 

it will be used. 

• Have a secondary control system with 

ROV intervention capabilities, including the 

ability to close one set of blind-shear rams 

and one set of pipe rams and unlatch the 

LMRP. 

• Have an emergency shut-in system in the 

event that you lose power to the BOP stack, 

have an unplanned disconnection of the riser 

from the BOP stack, or experience another 

emergency situation. 

• Function test the hot stabs that would be 

used to interface with the ROV intervention 

panel during the stump test. 

• Obtain an independent third party 

verification that provides sufficient 

information showing that the blind-shear 

rams installed in the BOP stack are capable 

of shearing the drill pipe in the hole under 

maximum anticipated surface pressures. 

• If the blind-shear rams or casing shear 

rams are activated in a well control situation 

in which pipe or casing was sheared, 

operators must inspect and test the BOP stack 

and its components, after the situation is 

fully controlled. 

• Have all well casing designs and 

cementing program/procedures certified by a 

Professional Engineer, verifying the casing 

design is appropriate for the purpose for 

which it is intended under expected wellbore 

conditions. 

• Submit the relevant information 

discussed in the NTL prior to commencing 

those operations, and drilling may not 

commence without BOEMRE approval. 

4. NTL No. 2010–N06—Information 

Requirements for Exploration Plans, 

Development and Production Plans, and 

Development Operations Coordination 

Documents on the OCS 

The link to this NTL is: http:// 

www.gomr.boemre.gov/homepg/regulate/ 

regs/ntls/2010NTLs/10-n06.pdf. 

BOEMRE issued this NTL on June 18, 

2010. This NTL provides guidance to lessees 

and operators regarding the blowout and oil 

spill information required in the exploration 

and development plan documents submitted 

to BOEMRE, including: 

A blowout scenario as required by 30 CFR 

250.213(g) and 250.243(h), including: 

Highest volume of liquid hydrocarbons; 

Estimated flow rate, total volume, and 

maximum duration; 

Potential for the well to bridge over; 

Likelihood for surface intervention to stop 

the blowout; 

Availability of a rig to drill a relief well; 

Time frame to drill a relief well. 

A description of the assumptions and 

calculations used to determine the volume of 

the worst case discharge scenario, including: 

Well design; 

Reservoir characteristics; 

Fluid characteristics; 

Pressure, volume, and temperature 

characteristics; 

Analog reservoir assumptions; 

Supporting calculations and models used 

in determining worst case scenario. 

5. Secretarial Decision Suspending Drilling 

Activities That Use Subsea BOP Stacks and 

Drilling From Floating Facilities With a 

Surface BOP Stack 

On July 12, 2010, the Secretary issued a 

decision directing BOEMRE to suspend the 

drilling of wells using subsea BOPs or surface 

BOPs on floating facilities, and to cease 

approval of pending and future applications 

for permits to drill using subsea BOPs or 

surface BOPs on floating facilities. These 

directives apply in the GOM and Pacific 

regions through November 30, 2010, subject 

to modification if the Secretary determines 

that the significant threats to life, property, 

and the environment set forth in his decision 

have been sufficiently addressed. This 

includes additional information about the 

causes of the Deepwater Horizon Oil Spill. 

Several investigations and reviews are being 

undertaken to identify the root causes of the 

disaster, including a joint BOEMRE–USCG 

investigation, a review by the NAE, on-going 

Congressional inquiries, and the National 

Commission on the BP Deepwater Horizon 

Oil Spill and Offshore Drilling (Presidential 

Commission). The results of these will better 

inform DOI decision-making and longer-term 

rulemaking. 

Following this decision, on July 12, 2010, 

BOEMRE issued suspension orders of most 


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deepwater drilling operations on the OCS 

through November 30, 2010. BOEMRE 

stopped approval of pending and future 

deepwater drilling applications in the GOM 

and Pacific regions. 

6. Held Public Meetings to Collect 

Information and Views About Deepwater 

Drilling Safety Reforms, Blowout 

Containment, and Oil Spill Response 

As directed by the Secretary in the 

Decision of July 12, 2010, the BOEMRE 

Director led a series of public meetings to 

collect information and views about 

deepwater drilling safety reforms, blowout 

containment, and oil spill response. The 

Director solicited input from the general 

public, state, and local leaders, experts from 

academia, the environmental community, 

and the oil and gas industry. The link to the 

Public Forums on Offshore Drilling is: 

http://www.boemre.gov/forums/. The 

webpage provides information and 

presentations from each meeting. The 

meetings were held in August and September 

in the following cities: New Orleans, 

Louisiana; Mobile, Alabama; Pensacola, 

Florida; Santa Barbara, California; 

Anchorage, Alaska; Houston, Texas; Biloxi, 

Mississippi; Lafayette, Louisiana. 

List of Subjects in 30 CFR Part 250 

Administrative practice and 

procedure, Continental shelf, 

Incorporation by reference, Oil and gas 

exploration, Public lands—mineral 

resources, Public lands—rights-of-way, 

Reporting and recordkeeping 

requirements. 

Dated: October 1, 2010. 

Wilma A. Lewis, 

Assistant Secretary—Land and Minerals 

Management. 

■ For the reasons stated in the preamble, 

under the authority of 43 U.S.C. 1334 

and Section 2 or Reorganization Plan 

No. 3 of 1950, 64 Stat. 1262, as 

amended, the Bureau of Ocean Energy 

Management, Regulation and 

Enforcement (BOEMRE) is amending 30 

CFR chapter II as follows: 

Title 30—Mineral Resources 

CHAPTER II—BUREAU OF OCEAN ENERGY 

MANAGEMENT, REGULATION AND 

ENFORCEMENT, DEPARTMENT OF THE 

INTERIOR 

PART 250—OIL AND GAS AND 

SULPHUR OPERATIONS IN THE 

OUTER CONTINENTAL SHELF 

■ 1. The authority citation for part 250 

continues to read as follows: 

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

■ 2. Amend § 250.198 by: 

■ a. Adding a new paragraph (a)(3), 

■ b. Revising paragraph (h)(63), and 

■ c. Adding new paragraph (h)(79) to 

read as follows: 

§ 250.198 Documents incorporated by 

reference. 

(a) * * * 

(3) The effect of incorporation by 

reference of a document into the 

regulations in this part is that the 

incorporated document is a 

requirement. When a section in this part 

incorporates all of a document, you are 

responsible for complying with the 

provisions of that entire document, 

except to the extent that section 

provides otherwise. When a section in 

this part incorporates part of a 

document, you are responsible for 

complying with that part of the 

document as provided in that section. If 

any incorporated document uses the 

word should, it means must for 

purposes of these regulations. 

* * * * * 

(h) * * * 

(63) API RP 53, Recommended 

Practices for Blowout Prevention 

Equipment Systems for Drilling Wells, 

Third Edition, March 1997; reaffirmed 

September 2004, Order No. G53003; 

incorporated by reference at 

§ 250.442(c); § 250.446(a); 

§ 250.516(g)(1); § 250.516(h); and 

§ 250.617(a)(1), and (b); 

* * * * * 

(79) API RP 65–Part 2, Isolating 

Potential Flow Zones During Well 

Construction; First Edition, May 2010; 

Product No. G65201; incorporated by 

reference at § 250.415(f). 

* * * * * 

■ 3. Amend § 250.415 as follows: 

■ a. Revise paragraphs (c), (d), and 

(e)(2), and 

■ b. Add new paragraph (f) to read as 

follows: 

§ 250.415 What must my casing and 

cementing programs include? 

* * * * * 

(c) Type and amount of cement (in 

cubic feet) planned for each casing 

string; 

(d) * * * Your program must provide 

protection from thaw subsidence and 

freezeback effect, proper anchorage, and 

well control; 

(e) * * * 

(2) An ‘‘area known to contain a 

shallow water flow hazard’’ is a zone or 

geologic formation for which drilling 

has confirmed the presence of shallow 

water flow; and 

(f) A written description of how you 

evaluated the best practices included in 

API RP 65–Part 2, Isolating Potential 

Flow Zones During Well Construction 

(incorporated by reference as specified 

in § 250.198). Your written description 

must identify the mechanical barriers 

and cementing practices you will use for 

each casing string (reference API RP 65– 

Part 2, Sections 3 and 4). 

■ 4. Amend § 250.416 by revising 

paragraphs (d) and (e) and adding new 

paragraphs (f) and (g) to read as follows: 

§ 250.416 What must I include in the 

diverter and BOP descriptions? 

* * * * * 

(d) A schematic drawing of the BOP 

system that shows the inside diameter 

of the BOP stack, number and type of 

preventers, all control systems and 

pods, location of choke and kill lines, 

and associated valves; 

(e) Independent third party 

verification and supporting 

documentation that show the blindshear rams installed in the BOP stack 

are capable of shearing any drill pipe in 

the hole under maximum anticipated 

surface pressure. The documentation 

must include test results and 

calculations of shearing capacity of all 

pipe to be used in the well including 

correction for MASP; 

(f) When you use a subsea BOP stack, 

independent third party verification that 

shows: 

(1) the BOP stack is designed for the 

specific equipment on the rig and for 

the specific well design; 

(2) The BOP stack has not been 

compromised or damaged from previous 

service; 

(3) The BOP stack will operate in the 

conditions in which it will be used; and 

(g) The qualifications of the 

independent third party referenced in 

paragraphs (e) and (f) of this section: 

(1) The independent third party in 

paragraph (e) in this section must be a 

technical classification society; an APIlicensed manufacturing, inspection, or 

certification firm; or a licensed 

professional engineering firm capable of 

providing the verifications required 

under this part. The independent third 

party must not be the original 

equipment manufacturer (OEM). 

(2) You must: 

(i) Include evidence that the firm you 

are using is reputable, the firm or its 

employees hold appropriate licenses to 

perform the verification in the 

appropriate jurisdiction, the firm carries 

industry-standard levels of professional 

liability insurance, and the firm has no 

record of violations of applicable law. 

(ii) Ensure that an official 

representative of BOEMRE will have 

access to the location to witness any 

testing or inspections, and verify 

information submitted to BOEMRE. 

Prior to any shearing ram tests or 

inspections, you must notify the District 

Manager at least 24 hours in advance. 

■ 5. Amend § 250.418 as follows: 

■ a. Revise paragraph (g), 


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■ b. Redesignate paragraph (h) as 

paragraph (j), and 

■ c. Add new paragraphs (h) and (i) to 

read as follows: 

§ 250.418 What additional information 

must I submit with my APD? 

* * * * * 

(g) A request for approval if you plan 

to wash out or displace some cement to 

facilitate casing removal upon well 

abandonment; 

(h) Certification of your casing and 

cementing program as required in 

§ 250.420(a)(6); 

(i) Description of qualifications 

required by § 250.416(f) of any 

independent third party; and 

* * * * * 

■ 6. Amend § 250.420 as follows: 

■ a. Revise paragraphs (a)(4) and (a)(5), 

■ b. Add new paragraph (a)(6), 

■ c. Add new paragraph (b)(3) to read as 

follows: 

§ 250.420 What well casing and cementing 

requirements must I meet? 

* * * * * 

(a) * * * 

(4) Protect freshwater aquifers from 

contamination; 

(5) Support unconsolidated 

sediments; and 

(6) Include certification signed by a 

Registered Professional Engineer that 

there will be at least two independent 

tested barriers, including one 

mechanical barrier, across each flow 

path during well completion activities 

and that the casing and cementing 

design is appropriate for the purpose for 

which it is intended under expected 

wellbore conditions. The Registered 

Professional Engineer must be registered 

in a State in the United States. Submit 

this certification with your APD (Form 

MMS–123). 

(b) * * * 

(3) For the final casing string (or liner 

if it is your final string), you must install 

dual mechanical barriers in addition to 

cement, to prevent flow in the event of 

a failure in the cement. These may 

include dual float valves, or one float 

valve and a mechanical barrier. You 

must submit documentation to BOEMRE 

30 days after installation of the dual 

mechanical barriers. 

* * * * * 

■ 7. Revise § 250.423 to read as follows: 

§ 250.423 What are the requirements for 

pressure testing casing? 

(a) The table in this section describes 

the minimum test pressures for each 

string of casing. You may not resume 

drilling or other down-hole operations 

until you obtain a satisfactory pressure 

test. If the pressure declines more than 

10 percent in a 30-minute test, or if 

there is another indication of a leak, you 

must re-cement, repair the casing, or run 

additional casing to provide a proper 

seal. The District Manager may approve 

or require other casing test pressures. 

Casing type Minimum test pressure 

(1) Drive or Structural ................................................................................................................. Not required. 

(2) Conductor .............................................................................................................................. 200 psi. 

(3) Surface, Intermediate, and Production ................................................................................. 70 percent of its minimum internal yield. 

(b) You must ensure proper 

installation of casing or liner in the 

subsea wellhead or liner hanger. 

(1) You must ensure that the latching 

mechanisms or lock down mechanisms 

are engaged upon installation of each 

casing string or liner. 

(2) You must perform a pressure test 

on the casing seal assembly to ensure 

proper installation of casing or liner. 

You must perform this test for the 

intermediate and production casing 

strings or liner. 

(3) You must submit for approval with 

your APD, test procedures and criteria 

for a successful test. 

(4) You must document all your test 

results and make them available to 

BOEMRE upon request. 

(c) You must perform a negative 

pressure test on all wells to ensure 

proper casing installation. You must 

perform this test for the intermediate 

and production casing strings. 

(1) You must submit for approval with 

your APD, test procedures and criteria 

for a successful test. 

(2) You must document all your test 

results and make them available to 

BOEMRE upon request. 

■ 8. Amend § 250.442 by revising the 

section heading and the section to read 

as follows: 

§ 250.442 What are the requirements for a 

subsea BOP system? 

When you drill with a subsea BOP 

system, you must install the BOP system 

before drilling below the surface casing. 

The District Manager may require you to 

install a subsea BOP system before 

drilling below the conductor casing if 

proposed casing setting depths or local 

geology indicate the need. The table in 

this paragraph outlines your 

requirements. 

When drilling with a subsea BOP system, you must: Additional requirements 

(a) Have at least four remote-controlled, hydraulically operated BOPs. You must have at least one annular BOP, two BOPs equipped with 

pipe rams, and one BOP equipped with blind-shear rams. The blindshear rams must be capable of shearing any drill pipe in the hole 

under maximum anticipated surface pressures. 

(b) Have an operable dual-pod control system to ensure proper and 

independent operation of the BOP system. 

(c) Have an accumulator system to provide fast closure of the BOP 

components and to operate all critical functions in case of a loss of 

the power fluid connection to the surface. 

The accumulator system must meet or exceed the provisions of Section 13.3, Accumulator Volumetric Capacity, in API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for 

Drilling Wells (incorporated by reference as specified in § 250.198). 

The District Manager may approve a suitable alternate method. 

(d) Have a subsea BOP stack equipped with remotely operated vehicle 

(ROV) intervention capability. 

At a minimum, the ROV must be capable of closing one set of pipe 

rams, closing one set of blind-shear rams and unlatching the LMRP. 

(e) Maintain an ROV and have a trained ROV crew on each floating 

drilling rig on a continuous basis. The crew must examine all ROV 

related well control equipment (both surface and subsea) to ensure 

that it is properly maintained and capable of shutting in the well during emergency operations. 

The crew must be trained in the operation of the ROV. The training 

must include simulator training on stabbing into an ROV intervention 

panel on a subsea BOP stack. 


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When drilling with a subsea BOP system, you must: Additional requirements 

(f) Provide autoshear and deadman systems for dynamically positioned 

rigs. 

(1) Autoshear system means a safety system that is designed to automatically shut in the wellbore in the event of a disconnect of the 

LMRP. When the autoshear is armed, a disconnect of the LMRP 

closes the shear rams. This is considered a ‘‘rapid discharge’’ system. 

(2) Deadman System means a safety system that is designed to automatically close the wellbore in the event of a simultaneous absence 

of hydraulic supply and signal transmission capacity in both subsea 

control pods. This is considered a ‘‘rapid discharge’’ system. 

(3) You may also have an acoustic system. 

(g) Have operational or physical barrier(s) on BOP control panels to 

prevent accidental disconnect functions. 

Incorporate enable buttons on control panels to ensure two-handed operation for all critical functions. 

(h) Clearly label all control panels for the subsea BOP system. Label other BOP control panels such as hydraulic control panel.

(i) Develop and use a management system for operating the BOP system, including the prevention of accidental or unplanned disconnects 

of the system. 

The management system must include written procedures for operating 

the BOP stack and LMRP (including proper techniques to prevent 

accidental disconnection of these components) and minimum knowledge requirements for personnel authorized to operate and maintain 

BOP components. 

(j) Establish minimum requirements for personnel authorized to operate 

critical BOP equipment. 

Personnel must have: 

(1) Training in deepwater well control theory and practice according to the requirements of 30 CFR 250, subpart O; and 

(2) A comprehensive knowledge of BOP hardware and control systems. 

(k) Before removing the marine riser, displace the fluid in the riser with 

seawater. 

You must maintain sufficient hydrostatic pressure or take other suitable 

precautions to compensate for the reduction in pressure and to 

maintain a safe and controlled well condition. 

(l) Install the BOP stack in a glory hole when in ice-scour area. Your glory hole must be deep enough to ensure that the top of the 

stack is below the deepest probable ice-scour depth. 

■ 9. Amend § 250.446 by revising 

paragraph (a) to read as follows: 

§ 250.446 What are the BOP maintenance 

and inspection requirements? 

(a) You must maintain and inspect 

your BOP system to ensure that the 

equipment functions properly. The BOP 

maintenance and inspections must meet 

or exceed the provisions of Sections 

17.10 and 18.10, Inspections; Sections 

17.11 and 18.11, Maintenance; and 

Sections 17.12 and 18.12, Quality 

Management, described in API RP 53, 

Recommended Practices for Blowout 

Prevention Equipment Systems for 

Drilling Wells (incorporated by 

reference as specified in § 250.198). You 

must document the procedures used, 

record the results of your BOP 

inspections and maintenance actions, 

and make available to BOEMRE upon 

request. You must maintain your 

records on the rig for 2 years or from the 

date of your last major inspection, 

whichever is longer; 

* * * * * 

■ 10. Amend § 250.449, by revising 

paragraphs (h) and (i) and adding new 

paragraphs (j) and (k) to read as follows: 

§ 250.449 What additional BOP testing 

requirements must I meet? 

* * * * * 

(h) Function test annular and ram 

BOPs every 7 days between pressure 

tests; 

(i) Actuate safety valves assembled 

with proper casing connections before 

running casing; 

(j) Test all ROV intervention functions 

on your subsea BOP stack during the 

stump test. You must also test at least 

one set of rams during the initial test on 

the seafloor. You must submit test 

procedures with your APD or APM for 

District Manager approval. You must: 

(1) ensure that the ROV hot stabs are 

function tested and are capable of 

actuating, at a minimum, one set of pipe 

rams and one set of blind-shear rams 

and unlatching the LMRP; and 

(2) document all your test results and 

make them available to BOEMRE upon 

request; 

(k) Function test autoshear and 

deadman systems on your subsea BOP 

stack during the stump test. You must 

also test the deadman system during the 

initial test on the seafloor. 

(1) You must submit test procedures 

with your APD or APM for District 

Manager approval. 

(2) You must document all your test 

results and make them available to 

BOEMRE upon request. 

■ 11. Amend § 250.451 by adding new 

paragraph (i) to the table to read as 

follows: 

§ 250.451 What must I do in certain 

situations involving BOP equipment or 

systems? 

* * * * * 

If you encounter the following situation: Then you must * * *

*******

(i) You activate blind-shear rams or casing shear rams during a well 

control situation, in which pipe or casing is sheared.

Retrieve, physically inspect, and conduct a full pressure test of the 

BOP stack after the situation is fully controlled. 

* * * * * * * 

■ 12. Amend § 250.456 by: ■ a. Revising the last sentence in 

paragraph (i), 

■ b. Redesignating paragraph (j) as (k), 

and 


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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 63375 

■ c. Adding a new paragraph (j) to read 

as follows: 

§ 250.456 What safe practices must the 

drilling fluid program follow? 

* * * * * 

(i) * * * You must record the results 

of these tests in the drilling fluid report; 

(j) Before displacing kill-weight 

drilling fluid from the wellbore, you 

must obtain prior approval from the 

District Manager. To obtain approval, 

you must submit with your APD or 

APM your reasons for displacing the 

kill-weight drilling fluid and provide 

detailed step-by-step written procedures 

describing how you will safely displace 

these fluids. The step-by-step 

displacement procedures must address 

the following: 

(1) number and type of independent 

barriers that are in place for each flow 

path, 

(2) tests you will conduct to ensure 

integrity of independent barriers, 

(3) BOP procedures you will use 

while displacing kill weight fluids, and 

(4) procedures you will use to monitor 

fluids entering and leaving the wellbore; 

and 

* * * * * 

■ 13. Amend § 250.515 by adding new 

paragraphs (b)(5) and (e) to read as 

follows: 

§ 250.515 Blowout prevention equipment. 

* * * * * 

(b) * * * 

When The minimum BOP stack must include 

*******

(5) You use a subsea BOP stack ............................................................. The requirements in § 250.442(a) of this part. 

* * * * * * * 

* * * * * 

(e) The subsea BOP system for wellcompletions must meet the 

requirements in § 250.442 of this part. 

■ 14. Amend § 250.516 by: 

■ a. Revising (d)(6); 

■ b. Adding new paragraphs (d)(8) and 

(d)(9); and 

■ c. Revising paragraphs (g) and (h) to 

read as follows: 

§ 250.516 Blowout preventer system tests, 

inspections, and maintenance. 

* * * * * 

(d) * * * 

(6) Pressure-test variable bore-pipe 

rams against all sizes of pipe in use, 

excluding drill collars and bottom-hole 

tools; 

* * * * * 

(8) Test all ROV intervention 

functions on your subsea BOP stack 

during the stump test. You must also 

test at least one set of rams during the 

initial test on the seafloor. You must 

submit test procedures with your APM 

for District Manager approval. You 

must: 

(i) Ensure that the ROV hot stabs are 

function tested and are capable of 

actuating, at a minimum, one set of pipe 

rams and one set of blind-shear rams 

and unlatching the LMRP; 

(ii) Document all your test results and 

make them available to BOEMRE upon 

request; and 

(9) Function test autoshear and 

deadman systems on your subsea BOP 

stack during the stump test. You must 

also test the deadman system during the 

initial test on the seafloor. 

(i) You must submit test procedures 

with your APM for District Manager 

approval. 

(ii) You must document all your test 

results and make them available to 

BOEMRE upon request. 

* * * * * 

(g) BOP inspections. (1) You must 

inspect your BOP system to ensure that 

the equipment functions properly. The 

BOP inspections must meet or exceed 

the provisions of Sections 17.10 and 

18.10, Inspections, described in API RP 

53, Recommended Practices for Blowout 

Prevention Equipment Systems for 

Drilling Wells (incorporated by 

reference as specified in § 250.198). You 

must document the procedures used, 

record the results, and make them 

available to BOEMRE upon request. You 

must maintain your records on the rig 

for 2 years or from the date of your last 

major inspection, whichever is longer. 

(2) You must visually inspect your 

BOP system and marine riser at least 

once each day if weather and sea 

conditions permit. You may use 

television cameras to inspect this 

equipment. The District Manager may 

approve alternate methods and 

frequencies to inspect a marine riser. 

(h) BOP maintenance. You must 

maintain your BOP system to ensure 

that the equipment functions properly. 

The BOP maintenance must meet or 

exceed the provisions of Sections 17.11 

and 18.11, Maintenance; and Sections 

17.12 and 18.12, Quality Management, 

described in API RP 53, Recommended 

Practices for Blowout Prevention 

Equipment Systems for Drilling Wells 

(incorporated by reference as specified 

in § 250.198). You must document the 

procedures used, record the results, and 

make available to BOEMRE upon 

request. You must maintain your 

records on the rig for 2 years or from the 

date of your last major inspection, 

whichever is longer. 

* * * * * 

■ 15. Amend § 250.615 by: 

■ a. Adding new paragraph (b)(5), 

■ b. Redesignating paragraphs (e) 

through (g) as (f) through (h), and 

■ c. Adding new paragraph (e) to read 

as follows: 

§ 250.615 Blowout prevention equipment. 

* * * * * 

(b) * * * 

When The minimum BOP stack must include 

*******

(5) You use a subsea BOP stack ............................................................. The requirements in § 250.442(a) of this part. 

*******


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63376 Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 

(e) The subsea BOP system for wellworkover operations must meet the 

requirements in § 250.442 of this part. 

* * * * * 

■ 16. Amend § 250.616 by adding new 

paragraph (h) to read as follows: 

§ 250.616 Blowout preventer system 

testing, records, and drills. 

* * * * * 

(h) Stump test a subsea BOP system 

before installation. You must: 

(1) Test all ROV intervention 

functions on your subsea BOP stack 

during the stump test. You must also 

test at least one set of rams during the 

initial test on the seafloor. You must 

submit test procedures with your APM 

for District Manager approval. You 

must: 

(i) Ensure that the ROV hot stabs are 

function tested and are capable of 

actuating, at a minimum, one set of pipe 

rams and one set of blind-shear rams 

and unlatching the LMRP; 

(ii) Document all your test results and 

make them available to BOEMRE upon 

request; and 

(2) Function test autoshear and 

deadman systems on your subsea BOP 

stack during the stump test. You must 

also test the deadman system during the 

initial test on the seafloor. You must: 

(i) Submit test procedures with your 

APM for District Manager approval. 

(ii) Document the results of each test 

and make them available to BOEMRE 

upon request. 

(3) Use water to stump test a subsea 

BOP system. You may use drilling or 

completion fluids to conduct 

subsequent tests of a subsea BOP 

system. 

§§ 250.617 and 250.618 [Redesignated as 

§§ 250.618 and 250.619] 

■ 17. Redesignate §§ 250.617 and 

250.618 to §§ 250.618 and 250.619, 

respectively. 

■ 18. Add new § 250.617 to read as 

follows: 

§ 250.617 What are my BOP inspection 

and maintenance requirements? 

(a) BOP inspections. 

(1) You must inspect your BOP 

system to ensure that the equipment 

functions properly. The BOP 

inspections must meet or exceed the 

provisions of Sections 17.10 and 18.10, 

Inspections, described in API RP 53, 

Recommended Practices for Blowout 

Prevention Equipment Systems for 

Drilling Wells (incorporated by 

reference as specified in § 250.198). You 

must document the procedures used, 

record the results, and make them 

available to BOEMRE upon request. You 

must maintain your records on the rig 

for 2 years or from the date of your last 

major inspection, whichever is longer. 

(2) You must visually inspect your 

BOP system and marine riser at least 

once each day if weather and sea 

conditions permit. You may use 

television cameras to inspect this 

equipment. The District Manager may 

approve alternate methods and 

frequencies to inspect a marine riser. 

(b) BOP maintenance. You must 

maintain your BOP system to ensure 

that the equipment functions properly. 

The BOP maintenance must meet or 

exceed the provisions of Sections 17.11 

and 18.11, Maintenance; and Sections 

17.12 and 18.12, Quality Management, 

described in API RP 53, Recommended 

Practices for Blowout Prevention 

Equipment Systems for Drilling Wells 

(incorporated by reference as specified 

in § 250.198). You must document the 

procedures used, record the results, and 

make them available to BOEMRE upon 

request. You must maintain your 

records on the rig for 2 years or from the 

date of your last major inspection, 

whichever is longer. 

■ 19. In §§ 250.1500: 

■ a. Amend the definition of ‘‘Contractor 

and contract personnel’’ and the 

definition of ‘‘Employee’’ by removing 

the phrase ‘‘well control or production 

safety’’, and in its place add the phrase 

‘‘well control, deepwater well control, or 

production safety’’; and 

■ b. Add definitions for ‘‘Deepwater 

well control’’, ‘‘Well completion/well 

workover’’, Well control’’, and ‘‘Well 

servicing’’ in alphabetical order to read 

as follows: 

§ 250.1500 Definitions. 

* * * * * 

Deepwater well control means well 

control when you are using a subsea 

BOP system. 

* * * * * 

Well completion/well workover means 

those operations following the drilling 

of a well that are intended to establish 

or restore production. 

Well control means methods used to 

minimize the potential for the well to 

flow or kick and to maintain control of 

the well in the event of flow or a kick 

during drilling, well completion, well 

workover, and well servicing 

operations. 

Well servicing means snubbing, coiled 

tubing, and wireline operations. 

§ 250.1501 [Amended] 

■ 20. In §§ 250.1501, remove the phrase 

‘‘well control or production safety’’, and 

in its place add the phrase ‘‘well control, 

deepwater well control, or production 

safety’’. 

§ 250.1503 [Amended] 

■ 21. In §§ 250.1503: 

■ a. Redesignating paragraphs (b) and 

(c) as paragraphs (c) and (d); 

■ b. Amending paragraphs (a), (c)(1), 

(c)(3) and (d)(1) by removing the phrase 

‘‘well control or production safety’’, and 

in its place adding the phrase ‘‘well 

control, deepwater well control, or 

production safety’’; 

■ c. Amend paragraph (a) by removing 

the phrase ‘‘well control and production 

safety’’, and in its place adding the 

phrase ‘‘well control, deepwater well 

control, and production safety’’; and 

■ d. Adding new paragraph (b) to read 

as follows: 

§ 250.1503 What are my general 

responsibilities for training? 

* * * * * 

(b) If you conduct operations with a 

subsea BOP stack, your employees and 

contract personnel must be trained in 

deepwater well control. The trained 

employees and contract personnel must 

have a comprehensive knowledge of 

deepwater well control equipment, 

practices, and theory. 

§ 250.1506 [Amended] 

■ 22. In §§ 250.1506, amend paragraphs 

(a), (b), and (c) by removing the phrase 

‘‘well control or production safety’’, and 

in its place adding the phrase ‘‘well 

control, deepwater well control, or 

production safety’’. 

§ 250.1507 [Amended] 

■ 23. In §§ 250.1507, amend paragraphs 

(c) and (d) by removing the phrase ‘‘well 

control and production safety’’, and in 

its place adding the phrase ‘‘well 

control, deepwater well control, and 

production safety’’. 

■ 24. Amend § 250.1712 by, 

■ a. Revising paragraph (e) and (f)(14); 

and 

■ b. Adding new paragraph (g) to read 

as follows: 

§ 250.1712 What information must I submit 

before I permanently plug a well or zone? 

* * * * * 

(e) A description of the work; 

(f) * * * 

(14) Your plans to protect 

archaeological and sensitive biological 

features, including anchor damage 

during plugging operations, a brief 

assessment of the environmental 

impacts of the plugging operations, and 

the procedures and mitigation measures 

you will take to minimize such impacts; 

and 

(g) Certification by a Registered 

Professional Engineer of the well 

abandonment design and procedures; 

that there will be at least two 


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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations 63377 

independent tested barriers, including 

one mechanical barrier, across each flow 

path during abandonment activities; and 

that the plug meets the requirements in 

the table in § 250.1715. The Registered 

Professional Engineer must be registered 

in a State in the United States. You must 

submit this certification with your APM 

(Form MMS–124). 

■ 25. Amend § 250.1721 by: 

■ a. Revising paragraphs (e) and (g)(3), 

and 

■ b. Adding new paragraph (h) to read 

as follows: 

§ 250.1721 If I temporarily abandon a well 

that I plan to re-enter, what must I do? 

* * * * * 

(e) Identify and report subsea 

wellheads, casing stubs, or other 

obstructions that extend above the mud 

line according to U.S. Coast Guard 

(USCG) requirements; 

* * * * * 

(g) * * * 

(3) A description of any remaining 

subsea wellheads, casing stubs, mudline 

suspension equipment, or other 

obstructions that extend above the 

seafloor; and 

(h) Submit certification by a 

Registered Professional Engineer of the 

well abandonment design and 

procedures; that there will be at least 

two independent tested barriers, 

including one mechanical barrier, across 

each flow path during abandonment 

activities; and that the plug meets the 

requirements in the table in § 250.1715. 

The Registered Professional Engineer 

must be registered in a State in the 

United States. You must submit this 

certification with your APM (Form 

MMS–124) required by § 250.1712. 

[FR Doc. 2010–25256 Filed 10–7–10; 11:15 am] 

BILLING CODE 4310–MR–P 


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