Vol. 77 Wednesday, 

No. 163 August 22, 2012 

Part III 

Department of the Interior 

Bureau of Safety and Environmental Enforcement 

30 CFR Part 250 

Oil and Gas and Sulphur Operations on the Outer Continental Shelf— 

Increased Safety Measures for Energy Development on the Outer 

Continental Shelf; Final Rule 


TKELLEY on DSK3SPTVN1PROD with RULES2
50856 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

DEPARTMENT OF THE INTERIOR 

Bureau of Safety and Environmental 

Enforcement 

30 CFR Part 250 

[Docket ID BSEE–2012–0002] 

RIN 1014–AA02 

Oil and Gas and Sulphur Operations 

on the Outer Continental Shelf— 

Increased Safety Measures for Energy 

Development on the Outer Continental 

Shelf 

AGENCY: Bureau of Safety and 

Environmental Enforcement (BSEE), 

Interior. 

ACTION: Final rule. 

SUMMARY: This Final Rule implements 

certain safety measures recommended 

in the report entitled, ‘‘Increased Safety 

Measures for Energy Development on 

the Outer Continental Shelf.’’ To 

implement the appropriate 

recommendations in the Safety 

Measures Report and DWH JIT report, 

BSEE is amending drilling, wellcompletion, well-workover, and 

decommissioning regulations related to 

well-control, including: subsea and 

surface blowout preventers, well casing 

and cementing, secondary intervention, 

unplanned disconnects, recordkeeping, 

and well plugging. 

DATES: Effective Date: This rule becomes 

effective on October 22, 2012. The 

incorporation by reference of certain 

publications listed in the rule is 

approved by the Director of the Federal 

Register as of October 22, 2012. 

FOR FURTHER INFORMATION CONTACT: Kirk 

Malstrom, Bureau of Safety and 

Environmental Enforcement (BSEE), 

Office of Offshore Regulatory Programs, 

Regulations Development Branch, 703– 

787–1751, kirk.malstrom@bsee.gov. 

Executive Summary 

On October 14, 2010, the Bureau of 

Offshore Energy Management, 

Regulation, and Enforcement (BOEMRE) 

published the Interim Final Rule (75 FR 

63346), ‘‘Increased Safety Measures for 

Energy Development on the Outer 

Continental Shelf.’’ The Interim Final 

Rule (IFR) addressed certain 

recommendations 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 

Bureau of Safety and Environmental 

Enforcement (BSEE) is publishing this 

Final Rule in response to comments on 

the requirements implemented in the 

IFR. This rulemaking: 

• Establishes new casing installation 

requirements; 

• Establishes new cementing 

requirements; 

• Requires independent third party 

verification of blind-shear ram 

capability; 

• Requires independent third party 

verification of subsea BOP stack 

compatibility; 

• Requires new casing and cementing 

integrity tests; 

• Establishes new requirements for 

subsea secondary BOP intervention; 

• Requires function testing for subsea 

secondary BOP intervention; 

• Requires documentation for BOP 

inspections and maintenance; 

• Requires a Registered Professional 

Engineer to certify casing and cementing 

requirements; and 

• Establishes new requirements for 

specific well control training to include 

deepwater operations. 

This Final Rule changes the Interim 

Final Rule (IFR) in the following ways: 

• Updates the incorporation by 

reference to the second edition of API 

Standard 65—Part 2, which was issued 

December 2010. This standard outlines 

the process for isolating potential flow 

zones during well construction. The 

new Standard 65—Part 2 enhances the 

description and classification of wellcontrol barriers, and defines testing 

requirements for cement to be 

considered a barrier. 

• Revises requirements from the IFR 

on the installation of 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. The Final 

Rule provides that, for the final casing 

string (or liner if it is the final string), 

an operator must install one mechanical 

barrier in addition to cement, to prevent 

flow in the event of a failure in the 

cement. The final rule also clarifies that 

float valves are not mechanical barriers. 

• Revises § 250.423(c) to require the 

operator to perform a negative pressure 

test only on wells that use a subsea 

blowout preventer (BOP) stack or wells 

with a mudline suspension system 

instead of on all wells, as was provided 

in the Interim Final Rule. 

• Adds new § 250.451(j) stating that 

an operator must have two barriers in 

place before removing the BOP, and that 

the BSEE District Manager may require 

additional barriers. 

• Extends the requirements for BOPs 

and well-control fluids to wellcompletion, well-workover, and 

decommissioning operations under 

Subpart E—Oil and Gas WellCompletion Operations, Subpart F—Oil 

and Gas Well-Workover Operations, and 

Subpart Q—Decommissioning Activities 

to promote consistency in the 

regulations. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

I. Background 

II. Source of Specific Provisions Addressed 

in the Final Rule 

III. Overview of the Interim Final Rule as 

Amended by This Rule 

IV. Comments Received on the Interim Final 

Rule 

V. Section-by-Section Discussion of the 

Requirements in Final Rule 

VI. Compliance Costs 

VII. Procedural Matters 

I. Background 

This Final Rule was initiated as an 

IFR published by the BOEMRE on 

October 14, 2010 (75 FR 63346). The IFR 

was effective immediately, with a 60- 

day comment period. On October 1, 

2011, the BOEMRE, formerly the 

Minerals Management Service, was 

replaced by the Bureau of Ocean Energy 

Management (BOEM) and the Bureau of 

Safety and Environmental Enforcement 

(BSEE) as part of the reorganization. 

This Final Rule falls under the authority 

of BSEE and as such, a new Regulation 

Identifier Number (RIN) has been 

assigned to this rulemaking. The new 

RIN for this Final Rule is 1014–AA02, 

and replaces RIN 1010–AD68 from the 

IFR. This Final Rule modifies, in part, 

provisions of the IFR based on 

comments received. After reviewing the 

comments, however, BSEE retained 

many of the provisions adopted on 

October 14, 2010 without change. 

Some revisions to the IFR herein are 

additionally noteworthy in that they 

respond to comments we received and/ 

or are consistent as possible with 

recommendations in the Deepwater 

Horizon Joint Investigation Team (DWH 

JIT) report, to the degree that those 

recommendations are within the scope 

of the IFR or can be considered a logical 

outgrowth of the IFR. These changes 

include the following: 

• Clarification that the use of a dual 

float valve is not considered a sufficient 

mechanical barrier. 

• Clarification in § 250.443 stating 

that all BOP systems must include a 

wellhead assembly with a rated working 

pressure that exceeds the maximum 

anticipated wellhead pressure instead of 

the maximum anticipated surface 

pressure as was previously provided. 

• In § 250.1500 revising the definition 

of well-control to clarify that persons 

performing well monitoring and 

maintaining well-control must be 

trained. This new definition 

encompasses anyone who has 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50857 

responsibility for monitoring the well 

and/or maintaining the well-control 

equipment. 

This Final Rule is promulgated for the 

prevention of waste and for the 

conservation of natural resources of the 

Outer Continental Shelf (OCS), under 

the rulemaking authority of the Outer 

Continental Shelf Lands Act (the Act), 

43 U.S.C. 1334. 

This rule is 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 BOEMRE to adopt the 

recommendations contained in the 

Safety Measures Report and to 

implement them as soon as possible. As 

noted in the regulatory impact analysis 

accompanying this rule, other 

recommendations will be addressed in 

other future rulemakings and will be 

available for public comment. Final 

Regulatory Impact Analysis for the Final 

Rule on Increased Safety Measures for 

Energy Development on the Outer 

Continental Shelf, RIN 1014–AA02, at 9 

(BSEE; March 7, 2012). Similarly, 

BSEE’s actions here are not intended to 

supplant any actions by BSEE or other 

authorized government authorities 

warranted by fact finding or other 

factual development in other 

proceedings, including but not limited 

to those in Multi-District Litigation No. 

2179, In Re: Oil Spill by the OIL RIG 

DEEPWATER HORIZON in the GULF 

OF MEXICO, on April 2010 (E.D. La.). 

II. Source of Specific Provisions 

Addressed in the Interim Final Rule 

The Safety Measures Report 

recommended a series of steps designed 

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 BOPs, promote well 

integrity, enhance well-control, and 

facilitate a culture of safety through 

operational and personnel management. 

The IFR addressed 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 were intended to ensure 

that additional physical barriers exist in 

wells to prevent oil and gas from 

escaping into the environment. These 

new requirements related to well bore 

integrity were intended to decrease the 

likelihood of a loss of well-control. The 

well-control equipment requirements in 

the IFR help ensure the BOPs will 

operate in the event of an emergency 

and that the Remotely Operated 

Vehicles (ROVs) are capable of 

activating the BOPs. 

The following provisions in the IFR 

were identified in the Safety Measures 

Report as being appropriate to 

implement 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 also included the following 

provision in the IFR 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? 

BOEMRE determined that it was 

appropriate for inclusion in the IFR 

because it is consistent with the intent 

of the recommendations in the Safety 

Measures Report. Tighter requirements 

for cementing practices increase the 

safety of offshore oil and gas drilling 

operations. 

Much of the October 14, 2010, 

Federal Register preamble supporting 

the need for emergency rulemaking 

procedures also supports retaining these 

provisions permanently. 

III. Overview of the Interim Final Rule 

as Amended by This Rule 

The primary purpose of this Final 

Rule is to address comments received, 

make appropriate revisions, and bring to 

closure the rulemaking begun by the 

IFR. Together, the two rules clarify and 

incorporate safeguards that will 

decrease the likelihood of a blowout 

during drilling, completion, workover, 

and abandonment operations on the 

OCS. For example, the safeguards 

address well bore integrity and wellcontrol equipment. In sum, the two 

rules: 

(1) Establish new casing installation 

requirements; 

(2) Establish new cementing 

requirements; 

(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; 


TKELLEY on DSK3SPTVN1PROD with RULES2
50858 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

(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. 

IV. Comments Received on the Interim 

Final Rule 

Although the IFR was effective 

immediately upon publication in the 

Federal Register, the IFR included a 

request for public comments. BSEE 

received 38 comments on the IFR. The 

following table categorizes the 

commenters: 

Commenter type Number of 

comments 

Oil and Gas Industry/Organizations ....................................... 21 

Other Non-Government Organizations ................................... 6 

Individuals ................................. 8 

Government Federal/State ....... 3 

Total ................................... 38 

A number of comments included 

topics that were outside the scope of 

this rulemaking. Some provided 

suggestions for future rulemakings; 

other comments related to the 

Deepwater Horizon event, speculating 

on the causes of the event and 

suggesting additional changes based on 

their understanding of that event. While 

we requested comments on future 

rulemakings, we are not specifically 

addressing those comments in this rule; 

we will however, consider those 

suggestions in related future 

rulemakings. To the degree that 

comments assert that compliance with 

current rules or standards incorporated 

by reference may be infeasible in certain 

situations, and that such provisions 

need to be revised, BSEE will examine 

the need to revise its rules. Pending any 

future revisions of such provisions, 

persons subject to compliance may seek 

BSEE approval of either alternative 

procedures or equipment under 

§ 250.141 or departures from such 

requirements under § 250.142. In this 

Final Rule, BSEE only responds to 

comments that relate directly to this 

rulemaking. All comments BSEE 

received on the IFR are available at 

www.regulations.gov under Docket ID: 

BSEE–2012–0002. 

BSEE received a number of comments 

asserting that in making the IFR 

effective immediately upon publication, 

we did not follow the appropriate 

rulemaking process as required by the 

Administrative Procedure Act (APA). 

BSEE disagrees with these comments. In 

issuing the IFR, BOEMRE followed 

procedures authorized under the APA at 

5 U.S.C. 553(b) and (d). BOEMRE 

provided justification in the IFR for not 

seeking public comment in advance, 

and for the immediate effective date. 

BSEE believes that the justification 

provided at that time was sufficient and 

will not repeat that justification here. 

In this Final Rule, BSEE is publishing 

revisions to the IFR based on the 

comments we received. Analysis of the 

comments also confirms the agency’s 

earlier conclusions regarding those 

portions of the IFR that are not modified 

in this Final Rule. To help organize and 

present the comments received and the 

BSEE response to the comments, BSEE 

has developed 3 separate tables. Except 

for one issue, the following three tables 

summarize the comments received, and 

contain BSEE’s response to those 

comments. (Comments pertaining to the 

‘‘should/must’’ issue related to 

§ 250.198(a) are addressed in the 

section-by-section discussion with 

specific comments being addressed in a 

separate document included in the 

Administrative Record.) The first table 

relates to comments received on specific 

sections. The second table relates to 

broader topics and general questions not 

connected to a specific section. The 

third table addresses comments 

regarding the Regulatory Impact 

Analysis. Following the comment 

discussions, we include a section-bysection analysis of the Final Rule 

describing changes we made from the 

IFR. We do not repeat here the basis and 

purpose for each of the provisions of the 

sections retained from the IFR. 

TABLE 1—SPECIFIC SECTIONS COMMENTS AND RESPONSES

Section—topic Comment BSEE response 

§ 250.198(h)(79)—API Standard 65 2nd edition.API Standard 65—Part 2, Isolating Potential Flow Zones 

During Well Construction, Second Edition was published on December 10, 2010. The Second Edition incorporates learnings from the Macondo well incident, 

enhances the description and classification of well-control barriers, and defines testing requirements for cement to be considered a barrier. The Second Edition 

also revises Annex D into a checklist based on the requirements of the document. BOEMRE should update 

the IFR to incorporate the 2nd Edition by reference.

BSEE has reviewed API Standard 65—Part 2 2nd edition 

and has determined that it is appropriate to incorporate 

the latest edition in our regulations. 

§ 250.198(h)(79)—API Standard 65 2nd edition.Provide clarification on how API RP 65–2 will be used; 

will a minimum pre-cementing score be required for 

each cement job and then evaluated after the job 

also? (or checklist if using the Second Edition).

BSEE developed a compliance table, based on API 

Standard 65—Part 2 (see Table 4) for guidance. This 

Final Rule does not require operators to use this table; 

however, the operator may answer the questions in the 

table, along with the written descriptions where needed, or the operator may supply a written description in 

an alternate format as required in § 250.415(f) which is 

submitted with the APD. If the operator does not supply enough information to confirm compliance, then 

BSEE may return the permit application for clarification. BSEE does not plan to use a scoring system; the 

operator must submit how it evaluated API Standard 

65 part 2 when designing its cement program. The operator is not required to submit a post-cement job evaluation. 

§ 250.415(f), § 250.416(e) ................................ Will the submittal be with each APD, or once for each rig 

per year unless changed? 

The operator is required to submit the written description 

of how the best practices in API Standard 65—Part 2 

were evaluated and the qualifications of the independent third-party with each APD. 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50859 

TABLE 1—SPECIFIC SECTIONS COMMENTS AND RESPONSES—Continued 

Section—topic Comment BSEE response 

§ 250.416(d) ..................................................... Confirm that the schematic of the control system includes 

location, control system pressure for BOP functions, 

BOP functions at each control station, and emergency 

sequence logic. Specifications on other requirements 

should be clear.

BSEE agrees that the schematics of the control systems 

should include these items. The location of control stations are not required to be submitted. While it is critical to have control stations, the actual location of the 

control stations is not critical. 

§ 250.416(e) ..................................................... Will there be a standard way to perform shearing calculations for the drill pipe? BSEE does not require a standard method to perform 

shearing calculations; different manufacturers have different methods of calculating shearing requirements. 

The documentation the operator provides, however, 

needs to explain and support the methodology used in 

performing the calculations and arriving at the test results. 

§ 250.416(e) ..................................................... Will there be a standard of calculation for the Maximum 

Anticipated Surface Pressure (MASP)? 

BSEE does not require a standard procedure for MASP 

or shearing calculations. In § 250.413(f), MASP for 

drilling is defined along with the considerations for calculations. 

§ 250.416(e) ..................................................... Will the maximum MASP be the rating of the annulars? The MASP for shearing calculations will not be based on 

the annular rating. There are multiple methods to calculate the MASP. It is the responsibility of the operator 

to select the appropriate method, depending upon the 

situation. 

§ 250.416(e) ..................................................... Is it a requirement of the deadman to also shear at 

MASP? 

Yes, the shear rams installed in the BOP must be able to 

shear drill pipe at MASP. 

§ 250.416(e) ..................................................... If there is a requirement of the deadman to also shear at 

MASP, what usable volume and pressure should remain after actuation? 

BSEE is researching this issue and may address it in future rulemaking. 

§ 250.416(e) ..................................................... Please confirm that operators will only be required to 

demonstrate shearing capacity for drill pipe (which includes workstring and tubing) that is run across the 

BOP stack and that BHA components, drill collars, 

HWDP, casing, concentric strings, and lower completion assemblies are excluded from this requirement.

BSEE agrees with this comment. We revised § 250.416 

to specifically include workstring and tubing. 

§ 250.416(e) ..................................................... A better requirement would be to demonstrate shearing 

capacity for drill pipe which includes work-strings and 

tubing which is run across the BOP stack.

BSEE revised this section in this Final Rule to include 

workstring and tubing as drill pipe. 

§ 250.416(e) ..................................................... Shearing capacity with MASP should be modified to 

shearing capacity with mud hydrostatic pressure plus a 

conservative shut-in pressure limit set by the operator 

and contractor where shut-in is transferred from the 

annular BOP to Ram BOP. At this point increased 

pressure in the cavity between the pipe rams and annular preventer should be eliminated. BOEMRE should 

request the internal bore pressure shear capacity calculation to be provided at the limit of the BOP system 

and approval contingent upon MASP being less than 

internal bore pressure limit.

BSEE requires the operator to design for the case in 

which blind-shear rams will be exposed to the MASP. 

BSEE does not agree that we need to request operators to provide the internal bore pressure shear capacity calculation. Designing the BOP for the well design 

and the conditions in which it will be used will ensure 

that this concern is addressed. 

§ 250.416(e) ..................................................... Modify the requirement for blind-shear rams to reflect the 

2,500 psi maximum pressure limit when placed above 

all pipe rams and immediately below the annular on 

the subsea BOP stack.

BSEE disagrees. The operator is required to design for 

the case in which blind-shear rams are exposed to the 

MASP. It is possible that this situation may occur and 

this requirement addresses that possibility. 

The proposed new API RP–53 4th Edition states pipe 

rams must be used when shut-in pressure exceeds 

2,500 psi. When the blind-shear rams are above all 

pipe rams in the stack, the well-control sequence 

would be to shut the annular first and then switch to a 

pipe ram if the shut-in pressure approaches 2,500 psi. 

With the blind-shear ram above all pipe rams, it would 

be nearly impossible for the blind-shear rams to ever 

experience shut-in pressures approaching MASP.


TKELLEY on DSK3SPTVN1PROD with RULES2
50860 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

TABLE 1—SPECIFIC SECTIONS COMMENTS AND RESPONSES—Continued 

Section—topic Comment BSEE response 

§ 250.416(e) ..................................................... 30 CFR 250.416(e) requires independent third-party 

verification of pipe shearing calculations at MASP for 

the blind-shear rams in the BOP stack. Prior to the 

IFR, this item didn’t require the independent third-party 

verification of shear calculations. Prudent operators always do those calculations to (1) comply with the law 

as it was written and (2) feel comfortable that pipe can 

be sheared in an emergency. The requirement for 

independent third-party verification does not make 

things safer in the GoM. Why cannot BOEMRE regulators just have the operators do what was already in 

the regs? Shear calculations are very straight forward 

and tend to be conservative by 30 percent when it 

comes to predicting the hydraulic pressure needed to 

shear tubulars with MASP at the BOP.

BSEE disagrees with this comment and the Final Rule 

continues to require independent third-party 

verification. This requirement ensures that everyone 

will perform the calculations, not just prudent operators. Third-party verification provides additional and 

necessary assurance that the blind-shear rams will be 

able to shear the drill pipe at MASP. The additional requirements in this rulemaking are intended to support 

existing requirements and not replace them. 

§ 250.416(f) ...................................................... The reliability and operability of the BOP can be confirmed without bringing the entire BOP and Lower Marine Riser Package (LMRP) to surface after each well, 

by visual inspection of a subsea BOP with an ROV 

and through a thorough function and pressure testing 

process. Any regulation that would require the operator 

to pull the stack to surface, handle the riser, and re-run 

it introduces more risk to personnel, well bore, and 

equipment. The proposed new API RP–53, 4th Edition, 

states: ‘‘Section 18.2 Types of Tests. This section addresses the types of tests to be performed and the frequency of when those tests are to be performed, realizing that the BOP can be moved from well-to-well 

without returning to surface for inspections and testing. 

For those cases, a visual inspection (by ROV) should 

be performed. Operability and integrity can be confirmed by function and pressure testing. In these instances, subsequent testing criteria shall apply for testing parameters.’’ This approach is safer and the regulation must be amended.

BSEE disagrees. The operator must pull the BOP stack 

to surface and complete a between-well inspection. 

The required inspection is more thorough than a visual 

inspection by an ROV and will help ensure the integrity 

of the BOP stack. As required in § 250.446(a), a between well inspection must be performed according to 

currently incorporated API RP 53, sections 17.10 and 

18.10, Inspections. The stump test of the subsea BOP 

before installation was already required under 

§ 250.449(b) as it existed before promulgation of the 

IFR. To conduct a stump test, the BOP must be located on the surface. The BOP inspection was a recommendation in the Safety Measures Report. 

§ 250.416(f) ...................................................... 30 CFR 250.416(f) requires that an independent thirdparty verify that a subsea BOP stack is fit for purpose. 

Section 250.416(f)(2) further requires that the subsea 

BOP stack has not been compromised or damaged 

from previous service—no guidance is given on how 

one is to determine that the subsea BOP hasn’t been 

compromised or damaged.

For multi-well projects where it makes senses to hop the 

BOP stack from well to well, would a successful 

subsea function test and pressure test be sufficient 

evidence that the requirement has been met?.

BSEE does not specify how the third-party verifies that 

the BOP has not been compromised or damaged from 

previous service. As required in § 250.446(a), a between-well inspection must be performed according to 

API RP 53, sections 17.10 and 18.10, Inspections. The 

requirement to conduct a stump test of the subsea 

BOP before installation existed before promulgation of 

the IFR, under § 250.449(b). The operator may not hop 

the BOP stack from well to well and be in compliance 

with the new provisions of this section or the previously existing requirements under § 250.449(b). 

§ 250.416(f)(2) .................................................. This requirement infers that an inspection of the BOP 

system is required to ensure the system has not been 

compromised or damaged from previous service. 

Please confirm that the agency agrees that a subsea 

BOP system is not compromised or damaged provided 

it can be function tested and pressure tested in the 

subsea environment where it will be in operation. 

Standardized pressure testing in the subsea environment without visual inspection fulfills the requirements 

of § 250.416(f)(2).

In § 250.416(f)(2), BSEE does not specify how the thirdparty verifies that the BOP has not been compromised 

or damaged from previous service. However, BSEE 

has requirements for between-well inspections in 

§ 250.446(a), and stump testing prior to installation in 

§ 250.449(b). 

§ 250.416(f)(2) .................................................. If it is mandated that a visual inspection between wells is 

required then the cost to implement of $1.2 MM is 

grossly understated. The cost to pull a BOP for a visual inspection is underestimated. The cost of pulling a 

subsea BOP for a visual inspection would result in a 

$5–$15 million opportunity cost.

The full cost to pull a subsea BOP to the surface following an activation of a shear ram or lower marine 

riser package (LMRP) disconnect (under § 250.451(i)) 

in the benefit-cost analysis is estimated to be $11.9 

million dollars. This amount is within the range suggested by the commenter. However, the requirement 

to conduct a visual inspection and test the subsea 

BOP between wells predated the IFR and was in the 

previously existing regulation at § 250.446(a). Because 

this requirement is not a new provision, no compliance 

costs are assigned in the economic analysis. 

§ 250.416(f)(2) .................................................. Third-party verification that the BOP stack has not been 

compromised or damaged from previous service can 

be accomplished by successful subsea function and 

pressure tests without visual inspection. Between well 

visual inspections of the BOP internal components is 

not required.

An independent third-party must confirm that the BOP 

stack matches the drawings and will operate according 

to the design. The third-party verification must include 

verification that: 

(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; 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50861 

TABLE 1—SPECIFIC SECTIONS COMMENTS AND RESPONSES—Continued 

Section—topic Comment BSEE response 

(3) The BOP stack will operate in the conditions in which 

it will be used. 

BSEE does not specify how the third-party verifies that 

the BOP has not been compromised or damaged from 

previous service. However, BSEE has requirements for 

between-well inspections in § 250.446(a), and stump 

testing prior to installation in § 250.449(b). 

§ 250.416(g) Qualification for Independent 

Third Parties.

The requirements for independent third parties to conduct BOP inspections fail to provide globally consistent 

standards necessary for the lifecycle use of Mobile Offshore Drilling Units (MODUs) on a global basis. The 

Interim Rule allows for an API licensed manufacturing, 

inspection, certification firm; or licensed engineering 

firm to carry out independent third-party verification of 

the BOP system, as well as technical classification societies. We recommend that the Interim Rule be 

amended to only enable organizations with the necessary breadth and depth of engineering knowledge, 

and experience and global reach, and demonstrable 

freedom from any conflict of interest, such as classification societies, can qualify as ‘independent third parties’. We believe that owing to the global employment 

of MODUs, where rigs could be engaged anywhere 

around the world, only independent technical classification societies have the global reach to ensure consistency in inspection and verification of safety critical 

equipment necessary to ensure the safe operation of 

an asset throughout its lifecycle.

In response to comments, BSEE removed the option for 

the independent third-party to be an API-licensed manufacturing, inspection, or certification firm in 

§ 250.416(g)(1) because API does not license such 

firms. 

Section 250.416(g)(1) allows registered professional engineers, or a technical classification society, or licensed professional engineering firms to provide the 

independent third-party verification. 

Section 250.416(g)(2)(i) requires the operator to submit 

evidence that the registered professional engineers, or 

a technical classification society, or licensed professional engineering firms or its employees hold appropriate licenses to perform the verification in the appropriate jurisdiction, and evidence to demonstrate that 

the individual, society, or firm has the expertise and 

experience necessary to perform verifications. BSEE 

may accept the verification from any firm or person 

that meets these requirements. We will not require the 

exclusive use of technical classification societies at this 

time. 

§ 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.

The comment supports the requirements in the IFR. 

However, BSEE clarified the requirement for the two 

independent barriers, based on other comments. 

§§ 250.420(a)(6), 250.1712(g), and 

250.1721(h).

What is the definition of well-completion activities? This 

is the first time it has been mentioned that barriers had 

to be certified by a professional engineer, only casing 

design and cementing were mentioned in the past.

BSEE clarified the certification requirement in 

§ 250.420(a)(6) by removing the term ‘‘well-completion 

activities,’’ because it was redundant in the context of 

that provision. The two required barriers are part of the 

casing and cementing design. 

§§ 250.420(a)(6), 250.1712(g), and 

250.1721(h).

Will BOEMRE still check casing designs based on load 

cases that are not published? If so, will certified plans 

be rejected due to design reviews within the agency? 

Will Agency design reviews be done by Registered 

Professional Engineers (RPE)? If not, what will be the 

process for approval when an RPE approved design 

conflicts with the Agency? Will the Agency mandate a 

change and take the responsibility for that change? 

There are multiple ways to calculate the load cases. The 

operator must ensure the well design and calculations 

are appropriate for the purpose for which it is intended 

under expected wellbore conditions. BSEE engineers 

will conduct the design reviews. Any issues will be resolved with the operator on a case-by-case basis. 

§§ 250.420(a)(6), 250.1712(g), and 

250.1721(h) Professional Engineer.

Liabilities that will be placed onto a ‘‘Professional Engineer’’ are an issue. The PE approach demands that 

the PE is intimately involved in all aspects of the design and also in primary communication as the well is 

drilled and small variations in the plan are made or 

happen. All liability for the well must remain with the 

operator without any ‘‘dilution’’ to a PE, although review by a PE or other ‘‘independent and reputable’’ 

third-party is totally appropriate.

The intent of the PE certification is to ensure that all 

plans are consistent with standard engineering practices. To add to safety assurances, BSEE included language in § 250.420(a)(6) that the Professional Engineer be involved in the design process. Such person 

must be included in the design process so that he or 

she is familiar enough with the final design to make 

the required certification. Under § 250.146(c), persons 

actually performing an activity on a lease to which a 

regulatory obligation applies are jointly and severally 

responsible for compliance. Such third person responsibility does not eliminate or dilute the operator’s responsibilities for a well. 

§§ 250.420(a)(6), 250.1712(g), and 

250.1721(h) Professional Engineer.

Can the required ‘‘registered professional engineer’’ be a 

company employee? 

Yes, the registered professional engineer can be a company employee. 

§§ 250.420(a)(6), 250.1712(g), and 

250.1721(h) Professional Engineer.

Require that all certifications needed by a Registered 

Professional Engineer be done by a Registered Professional Petroleum Engineer. It makes no sense at all 

to utilize any PE. If so, at least require a BS in Petroleum Engineering. There is no specification to determine how any Registered Professional Engineer is 

‘‘capable of reviewing and certifying that the * * * is 

appropriate for the purpose for which it is intended 

under expected wellbore conditions.’’ 

BSEE disagrees that the professional engineer must be 

a petroleum engineer; a professional engineer with another background who has expertise and experience in 

well design will be capable of certifying these plans. 

The expectation is that a licensed professional engineer will NOT certify anything outside of their area of 

expertise. However, in response to the commenter’s 

concern, this Final Rule adds an expertise and experience requirement for the person performing the certification. 


TKELLEY on DSK3SPTVN1PROD with RULES2
50862 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

TABLE 1—SPECIFIC SECTIONS COMMENTS AND RESPONSES—Continued 

Section—topic Comment BSEE response 

§§ 250.420(a)(6), 250.1712(g), and 

250.1721(h).

The intent of Congress and the Act does not appear to 

be complied with by the proposed rule. The use of a 

registered Professional Engineer to certify casing and 

cementing programs when ‘‘The Registered Professional Engineer must be registered in a State of the 

United States but does not have to be a specific discipline’’ does not appear to comply with the allowance 

for coordination with local Coastal Affected Zone 

States to have input. Two deficiencies are apparent. 

One is a licensed professional engineer should not be 

certifying anything that he is not competent to certify 

due to his education, training and experience. The second is that the engineer should be licensed in the 

Coastal Zone Affected State due to the differences that 

occur in licensing requirements. Some states are more 

liberal than others in the exemptions allowed and the 

requirements for discipline specific engineering licensure. If Texas wants to allow a higher risk then Texas 

offshore Coastal Affected Zones should be the only 

zones that are allowed to have such higher risk to be 

taken. If Louisiana or Mississippi want to be more restrictive then their offshore waters should be more restrictive. This seems to be the intent of the Coastal 

Zone Affected State language in the federal statutes. 

As currently proposed a licensed engineer from the 

state of minimum requirements can be selected.

The certification requirement is intended to ensure that 

all operators meet basic standards for their cement 

and casing. This requirement for PE certification is a 

substantial improvement compared to previous rules in 

which a certification was not mandatory. The final rule 

has added a provision to assure that a licensed professional will NOT certify anything outside of his or her 

area of expertise and experience. Because OCS 

projects occur offshore from several states, a company 

may want to use the same PE regardless of the location of any given well. Furthermore, the certification requirement applies uniformly to any project in Federal 

waters. Under these conditions, the certification standard combined with the liabilities associated with certification of a plan effectively address certification concerns. Also, States with approved coastal management 

programs have adequate opportunities to express their 

concerns about specific projects under other provisions 

of the regulations. 

§§ 250.420(a)(6), 250.1712(g), and 

250.1721(h).

BOEMRE now requires a Registered Professional Engineer to certify a number of well design aspects including: casing and cementing design, independent well 

barriers, and abandonment design. This is a new, important requirement. BOEMRE does not, however, require that the engineer be certified as a Registered 

Professional Engineer in any particular engineering 

discipline. This creates the possibility that a Professional Engineer, with little or no experience with oil and 

gas well design, drilling operations or well pressure 

control could be certifying these designs. For example, 

BOEMRE’s rule would allow an electrical engineer to 

certify a well design that may have no expertise or experience on offshore well construction design. We recommend that the Registered Professional Engineer requirement be limited to the discipline of Petroleum Engineering, and/or a Registered Professional Engineer 

in any engineering discipline that has more years of 

experience designing and drilling offshore wells. We 

agree that Registered Professional Engineers have the 

technical capability to assimilate the knowledge to certify well construction methods over a period of time, 

but only the Registered Professional Petroleum Engineer is actually tested on well casing, cementing, barriers and other well construction design and safety 

issues. Other engineering disciplines require on-the-job 

training and experience to expand their expertise and 

apply their engineering credentials to offshore well 

construction design certification.

BSEE disagrees that the professional engineer must be 

a petroleum engineer; a professional engineer with another background who has experience in well design 

will be capable of certifying these plans. In response to 

commenters’ concerns, we have added an expertise 

and experience requirement for the certifying person. It 

is the operator’s responsibility to ensure that the Registered Professional Engineer is qualified and competent to perform the work and has the necessary expertise and experience. The expectation is that a licensed professional engineer will NOT certify anything 

outside of his or her area of expertise. The operator 

certainly has a strong incentive to assure that the professional engineer is competent because the operator 

is responsible for the activities on the lease and the 

consequences thereof. 

§ 250.420(a)(6) ................................................. 30 CFR 250.420(a)(6) requires that a Registered Professional Engineer certify barriers across each flow path 

and that a well’s casing and cementing design is fit for 

its intended purpose under expected wellbore conditions. There are RPE’s whose area of expertise isn’t 

well design or construction. There are very few drilling 

and completion engineers with both sufficient expertise 

to make the required assessment and a PE license. 

What in this requirement makes operations in the GoM 

safer? Does BOEMRE plan to consider changing this 

requirement to expand the number of truly qualified 

people who can accurately assess this situation? What 

will eventually be the right standard for the certifying 

authority? 

Requiring a Registered Professional Engineer’s certification helps to ensure that the casing and cementing 

design meets accepted industry design standards. The 

expectation is that licensed professional engineers will 

NOT certify anything outside of their area of expertise. 

In response to this comment, this Final Rule does expand the persons who can make the required certification if they are registered and have the requisite expertise and experience. 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50863 

TABLE 1—SPECIFIC SECTIONS COMMENTS AND RESPONSES—Continued 

Section—topic Comment BSEE response 

§§ 250.420(a)(6), 250.1712(g) and 

250.1721(h).

The description of ‘‘flow path’’ would be improved by 

commenting on examples and/or by providing a definition and not including potential paths, i.e., previously 

verified or tested mechanical barriers are accepted 

without retest. Flow paths in the broadest terms would 

include annular seal assemblies which may not be accessible on existing wells. The assumption that all casing strings can be cut and pulled would result in exceptions in the majority of cases and would introduce a 

health and safety risk to operating personnel and 

equipment currently not present.

BSEE revised the regulatory text in § 250.420(b)(3) to include an example of barriers for the annular flow path 

and for the final casing string or liner. Once an operator performs a negative test on a barrier, the operator 

does not have to retest it unless that barrier is altered 

or modified. Also, see the subsequent comment responses that address the flow paths to which the barrier requirements apply. 

§ 250.420(a)(6) ................................................. Will BOEMRE still check casing designs based on load 

cases that are not published? If so, will certified plans 

be rejected due to design reviews within the agency? 

BSEE engineers will check casing designs. BSEE will resolve any differences with the operator on a case-bycase basis. 

§ 250.420(a)(6) ................................................. BOEMRE has not provided specific guidance on what 

aspects of casing and cementing designs must be initially certified or guidance on triggers which would 

cause a plan to be recertified for continuance of operations. The Offshore Operators’ Committee OOC provided those triggers to BOEMRE on October 12, 2010, 

and requests they be accepted as the only triggers for 

plan certification. Currently, the BOEMRE is inconsistent in their requests for recertification and fearful of 

approving minor changes that have no effect on safety. 

Further, delays to operations resulting in additional 

operational exposure and safety risk are to be expected when the Agency requires arbitrary recertification when simple changes are required. The requirement for an RPE review for OCS operations may become a bottleneck if this requirement becomes a 

standard for all U.S. operations.

While the list provided by the commenter contained 

some good examples, it is not comprehensive. If an 

activity triggers the need for a revised permit or an 

APM, then the Registered Professional Engineer must 

recertify the design. BSEE is working to improve consistency among the District Offices. 

§ 250.420(b)(3) ................................................. Add clarification to the dual mechanical barrier requirement to ensure the barriers are installed within the 

casing string and does not apply to mechanical barriers that seal the annulus between casings or between casing and wellhead. Acceptable barriers for 

annuli shall include at least one mechanical barrier in 

the wellhead and cement across and above hydrocarbon zones. Placement of cement can be validated 

by return volume, hydrostatic lift pressure or cased 

hole logging methods.

Industry best practices do not consider dual float valves 

to be two separate mechanical barriers because they 

cannot be tested independently and because they are 

not designed to be gas-tight barriers. This regulation 

does not achieve the safety objectives of the Drilling 

Safety Rule 

In response, this Final Rule revises § 250.420(b)(3) to 

provide that for the final casing string (or liner if it is 

the final string), an operator must install one mechanical barrier, in addition to cement, to prevent flow in the 

event of a failure in the cement. In response to the 

comment, we also clarify that a dual float valve, by 

itself, is not considered a mechanical barrier. The appropriate BSEE District Manager may approve alternatives. 

§ 250.420(b)(3) ................................................. Does the dual mechanical barrier requirement apply to 

just the inside of the casing or to both the inside and 

annulus flow paths? Our interpretation is the inside of 

the casing. It is also not clear when these dual barriers 

are required.

BSEE revised the regulatory text at § 250.420(b)(3) to 

clarify the requirement that two independent barriers 

are required in each annular flow path (examples include, but are not limited to, primary cement job and 

seal assembly) and for the final casing string or liner. 

The appropriate BSEE District Manager may approve 

alternatives. 

§§ 250.420(b)(3), 250.1712(g) and 

250.1721(h).

The incorporation by reference of API RP 65–2 in 

§ 250.415(f) includes a definition of a mechanical barrier. This either confuses or contradicts the use of the 

phrase ‘‘mechanical barrier’’ in sections 

§§ 250.420(b)(3), 250.1712(g) and 250.1712(h). The 

description of a ‘‘seal achieved by mechanical means 

between two casing strings or a casing string and the 

borehole’’ would not be possible regarding an existing 

well, specifically for the temporary or permanent abandonment, and does not include seals that are not in an 

annulus. Question: Do cast iron bridge plugs and retainers/packers without tubing installed meet the requirement for mechanical barriers? 

BSEE revised the language in § 250.420(b)(3) to clarify 

that the operator must install two independent barriers 

to prevent flow in the event of a failure in the cement, 

and clarified that a dual float valve is not considered a 

barrier. The appropriate BSEE District Manager may 

approve alternative options. BSEE revised the language in §§ 250.1712 and 250.1721 to clarify the requirements. For wells being permanently abandoned 

and wellhead removed, the PE needs to certify that 

there are two independent barriers in the center 

wellbore and the annuli are isolated per the regulations 

at § 250.1715. If the wellhead is being left in place for 

the production string, the registered PE must certify 

two independent barriers in the center wellbore and 

the annuli. The registered PE may not certify work that 

was previously performed; the registered PE must only 

certify the work to be performed under the permit submitted. A cast iron bridge plug is an option as a mechanical barrier. With regard to the question of using 

retainers/packers to meet the requirement for mechanical barriers, evaluation will be conducted on a caseby-case basis. 


TKELLEY on DSK3SPTVN1PROD with RULES2
50864 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

TABLE 1—SPECIFIC SECTIONS COMMENTS AND RESPONSES—Continued 

Section—topic Comment BSEE response 

§ 250.420(b)(3) ................................................. The rules seem to encourage use of devices described 

in Section 3 of RP 65, some of which have never been 

used in deepwater and are in fact of dubious utility. It 

is agreed that more stringent cementing practices are 

in order, but these proposed rules are too confusing to 

serve this purpose. This section needs to be revisited 

and specific, practical, recommended practices set out.

BSEE revised this section in the Final Rule to clarify the 

requirement of two independent barriers, and also 

clarified that a dual float valve is not considered a mechanical barrier. The BSEE District Manager may approve alternatives. 

§ 250.420(c) ...................................................... 30 CFR 250.420(c) requires that cement attain 500 psi 

compressive strength prior to drill out. What drives the 

CS requirement? It’s not API RP 65–2.

This is a previously existing requirement and therefore 

not within the scope of this rulemaking. 

§§ 250.420, 250.1712, and 250.1721 .............. Previous guidance/interpretation issued by BOEMRE 

said that deviation from certified procedures required 

contact with the appropriate BSEE District Manager. 

This is documented only in the guidance and is not implicit in this part of the rule. We request that BOEMRE 

specify the kinds of variances that require this contact.

If an activity triggers the need for a revised permit or an 

APM, then the Registered Professional Engineer must 

recertify the design and the revised permit or Application for Permit Modification (APM) must receive approval from the appropriate BSEE District Manager. 

§ 250.423(b) ..................................................... Need definition or clarity around the term—lock down 

and the requirement for locking down a drilling liner. 

Must all liner hangers have hold down slips? Normally 

conventional line hangers only have hang off slips to 

transfer the weight of the liner to the previous casing 

string. Once the seal is energized for a Liner Top 

Packer, it will hold pressure from below and above, but 

not all seals have slips to prevent uplift should the 

pressure-area effect exceed the weight of the liner. 

Requiring hold down slips on a conventional liner 

hanger increases the difficulty to fish the liner out of 

the hole, in fact it will lead to a milling operation.

BSEE has revised the language in § 250.423(b), to clarify 

that the Final Rule does not require the use of a latching or lock down mechanism for a liner. However, if a 

liner is used that has a latching or lock down mechanism, then that mechanism must be engaged. 

§ 250.423(b) ..................................................... As currently drafted, § 250.423(b) requires negative testing to be set to either 70 percent of system collapse 

resistance pressure, saltwater gradient, or 500 psi less 

than formation pressure, whichever is less. The rule 

implies that operators are required to perform a test on 

the casing seal; however, the industry has had several 

examples of where testing to a salt water gradient to 

sea floor has caused casing collapse in deep wells 

with casing across the salt. This regulation does not 

clearly state whether it applies to casing shoe extensions, such as expandable casing or 18’’ (which is a 

surface casing shoe extension). Since not all casing 

sizes (e.g. 16’’ and 18’’) have lockdown mechanisms 

at this time, the rule should allow for waivers to this requirement until such time that lockdown mechanisms 

are available.

BSEE revised the language for the requirements for a 

negative test under § 250.423(c). The operator must 

perform a negative pressure test on all wells that use a 

subsea BOP stack or wells with mudline suspension 

systems to ensure proper casing or liner installation. 

You must perform the negative test to the same degree of the expected pressure once the BOP is disconnected. BSEE also revised the language for the requirement to ensure proper installation of the casing in 

the subsea wellhead and liner in the liner hanger in 

§ 250.423(b). Regarding lockdown mechanisms, see 

previous comment. 

§ 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.

BSEE agrees with this comment. Section 250.423(b) requires performance of a pressure test on the casing 

seal assembly and further requires the operator to 

maintain the necessary documentation. 

Performance and documentation of a pressure test on 

the casing seal assembly to ensure proper installation 

of the casing and the liner are essential. Documentation that the latching mechanisms or lock down mechanisms are fully engaged upon installation of each casing string or liner must be mandatory.

§ 250.423(b)(1) ................................................. Not clear if integral latching capability of casing hanger/ 

seal assembly is acceptable or if a separate mechanism is required.

Under § 250.423(b)(1), the operator must ensure proper 

installation of casing in the subsea wellhead by ensuring that the latching mechanisms or lock down mechanisms are engaged upon installation of each casing 

string. The rule does not require a specific type of 

latching mechanism. Integral latching capability of the 

casing hanger or seal assembly is acceptable. 

§ 250.423(c) ...................................................... What is the design basis and acceptance criteria required for negative testing? The regulations do not specify a particular design basis 

for the negative pressure test. Under § 250.423(c)(3) 

operators must submit negative test procedures and 

provide their criteria for a successful test to BSEE for 

approval. BSEE revised the language of 

§ 250.423(c)(5) to include examples of indications of 

failure. 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50865 

TABLE 1—SPECIFIC SECTIONS COMMENTS AND RESPONSES—Continued 

Section—topic Comment BSEE response 

§ 250.423(c) ...................................................... It is imperative that the operator establish what is ‘‘normal’’ for this type of testing event, such that the rig 

crew is in no doubt as to what to look for and whether 

or not there is an event going on which is ‘‘not normal’’.

Operators are required to submit the procedures of these 

tests and provide their criteria for a successful test with 

their APD. BSEE revised the regulatory text to include 

examples of indications of a failed negative pressure 

test. 

§ 250.423(c) ...................................................... What is the definition of intermediate casing? The rule 

states a negative pressure test is required for intermediate and production casing. If drilling liners are set 

below intermediate casing is additional negative testing 

required? 

The intent of this requirement is not clear. The magnitude of the negative test is also not apparent. Is the 

intent to test the entire casing, wellhead, liner top, or 

the shoe? Surface wellheads are negative tested for 

each BOP test when the stack is drained and water is 

used for a test. If a negative test of an intermediate 

shoe is intended, then, what is the purpose since the 

casing shoe will be drilled out. In general, negative 

testing should not apply to all wells and should apply if 

the load is anticipated and then not until such time it is 

needed.

BSEE revised § 250.423(c) to clarify the requirements for 

the negative pressure test. Intermediate casing is any 

casing string between the surface casing string and 

production casing string. We revised the Final Rule to 

require negative pressure tests only on subsea BOP 

stack and wells with mudline suspension systems. We 

specifically require the operator to perform a negative 

pressure test on the final casing string or liner, and 

prior to unlatching the BOP at any point in the well (if 

the operator has not already performed the negative 

test on its final casing string or liner). At a minimum, 

the negative test must be conducted on those components that will be exposed to the negative differential 

pressure that will occur when the BOP is disconnected. The intent of the requirement is to ensure that 

the casing can withstand the wellbore conditions. The 

Final Rule addresses indicators of failed pressure tests 

and specifies what the operator must do in the event 

of a failed test. 

§ 250.423(c) ...................................................... Wells with surface wellheads should be exempt from 

negative tests unless the well is to be displaced to a 

fluid less than pore pressure and in that case the 

shoe, productive intervals, and liner tops can be negative tested to the amount anticipated prior to or during 

the displacement. The requirement to negative test 

wells with surface wellheads should not be mandated 

since the well can be displaced to a fluid less than 

pore pressure under controlled conditions without risk 

of an influx getting in a riser.

We agree that as a general matter wells with surface 

well heads should be exempt from negative pressure 

tests and we revised the Final Rule to require the negative pressure test only for wells that use a subsea 

BOP stack or wells with mudline suspension systems. 

We did, however, provide that if circumstances warrant, the BSEE District Manager may require an operator to perform additional negative pressure tests on 

other casing strings or liners (e.g. intermediate casing 

string or liner) or on wells with a surface BOP stack. 

§ 250.423(c) ...................................................... Additional guidance given by BOEMRE has indicated a 

desire to negative test all liner tops exposed in either 

the intermediate or production annulus on all wells with 

surface BOP equipment. This requirement is not consistent with the desire to improve safety since many 

liner tops are never exposed to negative pressures 

during the life of the well. Thus performing the test exposes personnel to additional exposure while tripping 

pipe to perform the test, risks the well by installing 

non-drillable test packers above the liner top during the 

test, and will expose personnel to additional material 

handling requirements.

All liner tops, exposed below the intermediate casing 

(wells with mudline suspension systems) must be tested, but only for wells with subsea BOP stacks or wells 

with mudline suspension systems. The test must be 

performed before displacing kill weight fluids in preparation for disconnecting the BOP stack. 

§ 250.423(c) ...................................................... The Agency has not provided guidance on when the test 

is to be performed. Testing upon installation is not advisable due to additional pressure cycles applied to the 

cement early in the development of its strength that 

could result in premature cement failure. Additionally, if 

a negative load is anticipated during operations, it is 

best to defer the negative test to assure well integrity 

is validated just prior to the intended operation.

This Final Rule revises § 250.423(c) to state that the 

negative pressure test must be performed on the final 

casing string or liner, and prior to unlatching the BOP 

at any point in the well. The negative test must be conducted on those components, at a minimum, that will 

be exposed to the negative differential pressure that 

will be seen when the BOP is disconnected. 

§ 250.423(c) ...................................................... Negative testing should be performed on subsea wells 

and wells with mudline suspension systems where it is 

important to validate barriers prior to removal of mud 

hydrostatic pressure during an abandonment or suspension activity such as hurricane evacuation or BOP 

repair. Drilling or production liner tops should not require negative testing upon installation. Testing should 

be deferred until just prior to performing an operation 

where a negative load is anticipated on a liner top or 

wellhead hanger.

BSEE agrees with the comment. We revised 

§ 250.423(c) to require the negative pressure tests only 

on wells that use a subsea BOP stack or wells with 

mudline suspension systems. See the response to the 

previous comment. 

§ 250.423(c) ...................................................... The magnitude and duration of an acceptable negative 

test should be provided for consistency. Recommend 

negative tests on subsea wells to be equal to SWHP 

at the wellhead.

We revised the Final Rule to require the negative test be 

performed to the same degree of the expected pressure once the BOP is disconnected. 


TKELLEY on DSK3SPTVN1PROD with RULES2
50866 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

TABLE 1—SPECIFIC SECTIONS COMMENTS AND RESPONSES—Continued 

Section—topic Comment BSEE response 

§ 250.423(c) ...................................................... 30 CFR 250.423(c) requires negative testing of intermediate casing and liner tops, but offers no guidance 

as to the magnitude of the required negative test. As 

an experienced deepwater driller, I’ve assumed that 

BOEMRE meant for this testing to apply to intermediate casing string seal assemblies on subsea 

wells. That mimics what the well would see in a BOP 

stack disconnect situation. I see no valid reason to be 

negatively testing intermediate casing shoes that will 

be subsequently drilled out. I’d also like to understand 

the rationale behind a negative test on all liner tops. 

Just because a liner top tests negatively doesn’t mean 

it won’t fail if the well is exposed to a differential as a 

result of a blow out. I see a negative test on production liner tops as a prudent thing, but this type testing 

of drilling liners that will ultimately be covered up can 

increase risk in certain situations (small platform rig on 

a floating facility with limited pit space could get into an 

unintended well-control situation dealing with the fluid 

handling/movements required by a negative test).

BSEE agrees. We revised this requirement to require the 

negative pressure tests only on wells that use a 

subsea BOP stack or wells with mudline suspension 

systems. See the response to the previous comments. 

§ 250.442 .......................................................... Must heavy weight drill pipe be shearable with blind 

shear rams? 

Blind-shear rams must be capable of shearing any drill 

pipe in the hole under maximum anticipated surface 

pressure, including heavyweight drillpipe. This Final 

Rule revises § 250.416(e) to include workstring and 

tubing to clarify that these are also considered drill 

pipe and need to be shearable by the blind-shear 

rams. 

§ 250.442 .......................................................... What does ‘‘operable’’ mean for dual pod controls? Does 

it mean 100 percent functional and redundant? 

The provision under § 250.442(b), for an ‘‘operable dualpod control system’’ was an existing requirement and 

was included in the IFR because that section was rearranged into a table to accommodate the new provisions. The meaning of ‘‘operable dual-pod control system’’ has not changed. The commenter is correct in 

that these are redundant systems. Each pod has to be 

independent of the other and 100 percent functional. 

§ 250.442 .......................................................... In § 250.442(c), what does ‘‘fast’’ mean for subsea closure and what are the ‘‘critical’’ functions? As specified in § 250.442(c), the accumulator system 

must meet or exceed the requirements in API RP 53, 

section 13.3, Accumulator Volumetric Capacity. 

§ 250.442 .......................................................... What will be competency basis for qualification of an individual to operate the BOP’s? The operator must ensure that all employees and contract personnel can properly perform their duties, as 

required under § 250.1501. Section 250.442(j) prescribes training and knowledge requirements for persons authorized to operate critical BOP equipment. 

§§ 250.442(d), § 250.515(e), and § 250.615(e) While the verified ability to close one set of pipe rams, 

close one set of blind-shear rams, and unlatch the 

lower marine riser package using a Remotely Operated Underwater Vehicle (ROV) is critical, the time 

delay associated with launch and subsea deployment 

of an ROV will likely have enabled the full force of a 

major blowout to already clear the well bore and result 

in excessive pressures and a debris stream at the 

BOP that can complicate efforts to shut in the well. 

Preventive and precautionary measures are a priority, 

and immediate shut-in capability will always be more 

critical than after-the-fact ROV response; thus this initiative should go further toward ensuring more immediate wild well shut-in capabilities, either in the current 

rulemaking, or in a future rulemaking.

We agree that there is a time delay associated with the 

launch and deployment of an ROV and that preventative and precautionary measures are a priority and immediate shut-in capability is critical. The intent of the 

provision is to ensure that an ROV is available in the 

unlikely event that all other measures fail. This regulation is intended to address broad issues related to 

well-control; BSEE is planning future regulations that 

will focus on preventative measures and improving immediate response capabilities. 

§§ 250.442(e), 250.515(e), and 250.615(e) ..... The ROV crews should not be required on a continuous 

basis, this item needs to be revised to reflect the need 

for having a trained ROV crew on board only when the 

BOP is deployed.

BSEE agrees with the substance of this comment and 

has revised § 250.442(e) accordingly. 

§ 250.442(j) ....................................................... What is meant by operate critical BOP equipment, maintenance, or activation of equipment? Section 250.442(j) establishes minimum requirements for 

personnel who operate any BOP equipment. The paragraph expressly refers to BOP hardware and control 

systems. In addition, other paragraphs of § 250.442 

refer to specific features of the BOP and associated 

equipment. Any person authorized to operate or maintain any of the BOP components or systems must satisfy the requisite training and knowledge requirements. 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50867 

TABLE 1—SPECIFIC SECTIONS COMMENTS AND RESPONSES—Continued 

Section—topic Comment BSEE response 

§§ 250.446(a), 250.516(h), 250.516(g), and 

250.617 (Section numbers refer to the IFR.).

The recordkeeping requested should be a responsibility 

of the drilling contractor. Many operations are short 

lived contracts and once the rig is released, the contractor has no obligation to ensure the records remain 

on the rig. Drilling contractors should be required to 

have a BOPE certification program complete with a 

certificate of compliance that is renewed every 3 to 5 

years by a certification agency or class society. This 

will assure drilling contractors maintain their equipment 

to a higher standard on a routine basis.

Under § 250.146(c), lessees, operators, and persons performing an activity subject to regulatory requirements 

are jointly and severally responsible for complying with 

regulatory requirements. This includes contractors 

maintaining and inspecting BOP systems. See the discussion in the section-by-section portion of this preamble. 

Certification documents for rental BOPE would also be 

used by the operator or contractor depending upon 

who is renting the equipment.

§§ 250.446(a), 250.516(h), 250.516(g), and 

250.617 (Section numbers refer to the IFR.).

We believe that API-recommended practices have not 

proven to be a standard that has generated full and 

verifiable compliance by all. Require documentation of 

BOP inspections and maintenance according to API 

RP 53. The codification of API-recommended practices 

via Federal regulations will be needed to ensure reliable compliance going forward. This should take place 

in the current rule, or, at a minimum, in a future rule.

BSEE already requires operators to follow 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. We continually review 

standards and our use of these standards. We may 

consider additional documentation from operators in future rulemaking. 

§ 250.449(h) ..................................................... Are the requirements for function test for normal or high 

pressure function or both? 

In § 250.449(h), request change from the required duration from 7 days to 14 days. The basis for this is to 

mitigate the risk and exposure due to the additional 

tripping of pipe out of hole in order to function test 

blind/shear rams.

Section 250.449(h) is a previously existing requirement 

that was included in the IFR only to make editorial 

changes to accommodate new requirements in subsequent paragraphs. The requested revision is outside 

the scope of this rulemaking. 

§§ 250.449(j), 250.516(d)(8) (Section numbers 

refer to the IFR.).

Stump test ROV intervention functions .............................

This does not go far enough. This is insufficient. It is 

necessary that the BOP ROV functions be regularly 

tested at the seabed with the ROV that would be used 

in an emergency. The only requirement of the stump 

test should be to test the plumbing. The BOP ROV 

functions should be tested at each BOP test when at 

operating hydrostatic pressures and temperatures.

Section 250.449(j) requires the operator must test one 

set of rams during the initial test on the seafloor. In 

this Final Rule, we added that the test of the one set 

of rams on the seafloor must be done through an ROV 

hot stab to ensure the functioning of the hot stab. 

BSEE may consider additional requirements in future 

rulemaking. 

§ 250.449(k) ...................................................... Section 250.449(k) explains: ‘‘[f]unction test auto shear 

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.’’ We do 

not recommend testing the deadman system when the 

stack is attached to a subsea wellhead. If the rig experiences a dynamic positioning incident, i.e., a drive-off 

or drift-off during the test, the only alternative system 

available to disconnect from the wellhead is the ROV 

intervention system. Failure to disconnect in time could 

result in serious damage to the rig equipment, the well 

head, or the well casing. As an alternative, we believe 

it would be more appropriate to test the autoshear system subsea. Such a requirement will test the same hydraulic system as the deadman, however, the 

autoshear function does not disable the control system 

and create the same well and equipment hazards as 

testing the deadman system.

BSEE believes that not testing the deadman system is a 

greater risk than conducting the test. Testing the 

deadman system on the seafloor is necessary to ensure that the deadman system will function in the 

event of a loss of power/hydraulics between the rig 

and the BOP. To help mitigate risk for the function test 

of the deadman system during the initial test on the 

seafloor, we added that there must be an ROV on bottom, so it would be available to disconnect the LMRP 

should the rig experience a loss of stationkeeping 

event. We also added clarifications for the required 

submittals of procedures for the autoshear and 

deadman function testing, including procedures on how 

the ROV will be utilized during testing. 


TKELLEY on DSK3SPTVN1PROD with RULES2
50868 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

TABLE 1—SPECIFIC SECTIONS COMMENTS AND RESPONSES—Continued 

Section—topic Comment BSEE response 

§ 250.449(k) ...................................................... Modify deadman system testing requirements to increase 

safety.

As drafted, operators must test the deadman system during the initial test on the seafloor. Intentionally disabling the deadman system increases the risk to personnel, well bore and equipment should a ‘‘power 

management’’ or ‘‘loss of station keeping’’ incident 

occur during a deadman system test. Testing of the 

deadman system requires shutting down of power and 

hydraulic systems to the BOP thereby eliminating the 

ability to disconnect in a controlled manner should a 

‘‘power management’’ or ‘‘loss of station keeping’’ incident occur. As a result, rig personnel could be exposed to the consequences of a violent release of tension if a riser component fails and seafloor architecture 

will be exposed to released/dropped riser components. 

Revise the deadman system testing requirement, 

bringing it in line with the proposed new API RP–53, 

4th Edition recommendations. Specifically, testing 

should be completed during commissioning, rig acceptance and if any modifications or maintenance has 

been performed on the system, not to exceed 5 years.

BSEE believes that not testing the deadman system is a 

greater risk than conducting the test. Testing the 

deadman system on the seafloor is necessary to ensure that the deadman system will function in the 

event of a loss power/hydraulics between the rig and 

the BOP. To help mitigate risk for the function test of 

the deadman system during the initial test on the 

seafloor, we added that there must be an ROV on bottom, so it would be available to disconnect the LMRP 

should the rig experience a loss of stationkeeping 

event. We also added clarifications for the required 

submittals of procedures for the autoshear and 

deadman function testing, including procedures on how 

the ROV will be utilized during testing. 

BSEE will review API RP–53, 4th Edition, and decide if it 

is appropriate for incorporation, after it is finalized. 

§§ 250.449(k), 250.516(d)(9), 250.616(h)(2) 

(Section numbers refer to the IFR.).

We recommend testing the deadman system when attached to a well subsea upon commissioning or within 

5 years of previous test but not at every well. If during 

the testing time the rig experiences a dynamic position 

incident, i.e., a drive off or drift off, the only options to 

disconnect from the well are acoustically (if acoustic 

system fitted), or with an ROV. Failure to disconnect in 

time could result in serious equipment damage, and/or 

damage to the well head.

BSEE believes that not testing the deadman system is a 

greater risk than conducting the test. Testing the 

deadman system on the seafloor is necessary to ensure that the deadman system will function in the 

event of a loss power/hydraulics between the rig and 

the BOP. To help mitigate risk for the function test of 

the deadman system during the initial test on the 

seafloor, we added that there must be an ROV on bottom, so it would be available to disconnect the LMRP 

should the rig experience a loss of stationkeeping 

event. We also added clarifications for the required 

submittals of procedures for the autoshear and 

deadman function testing, including procedures on how 

the ROV will be utilized during testing. 

§§ 250.449(k) and 250.516(d)(9) (Section 

numbers refer to the IFR.).

Stump test the autoshear and deadman. Test the 

deadman after initial landing.

Both the deadman and autoshear should be tested on 

the seabed. Moreover the Deadman should include a 

disconnect function. However, the LMRP connector 

should not be unlocked during this test. Rather, the 

LMRP disconnect function should be plumbed in such 

a way that during the test the fluid can be vented to 

sea rather than to the unlatch side.

On the initial test on the seafloor, the operator is required 

only to test the deadman system. The rule requires operators to submit their test procedures with the APD or 

APM for approval. BSEE may develop specific test 

procedures at a later time. 

§ 250.451(i) ....................................................... A successful seafloor pressure and function test of the 

BOP following a well-control event also is an acceptable means of verifying integrity. Ram sealing elements would be compromised before damage to the 

rams themselves would be extensive enough to prevent successful shearing of pipe. Additionally, plugging 

an open hole that may be experiencing ballooning and 

gas following a well-control event and pulling the BOP 

and riser present safety and operational risks that are 

likely much greater than proceeding with the drilling 

program using a fully tested BOP stack.

After a well-control event where pipe or casing was 

sheared, a full inspection and pressure test assures 

that the BOP stack is fully operable. The rule requires 

the operator to do this only after the situation is fully 

controlled. 

§ 250.451(i) ....................................................... We believe § 250.451(i) is best read to only require a 

subsea BOP stack to surface when pipe is sheared, 

rather than actuated on an empty cavity. We request 

that the agency clarify that the requirement to pull a 

subsea BOP stack to surface after actuating the blind 

shear rams does not apply when the blind shear rams 

are actuated on an empty cavity, but applies when 

pipe is sheared.

BSEE agrees with the comment that § 250.451(i) does 

not apply to actuation of shear rams on an empty cavity. Section 250.451(i) states that an operator must retrieve the BOP if: ‘‘You activate the blind-shear rams 

or casing shear rams during a well-control situation, in 

which pipe or casing is sheared.’’ 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50869 

TABLE 1—SPECIFIC SECTIONS COMMENTS AND RESPONSES—Continued 

Section—topic Comment BSEE response 

§ 250.456(j) ....................................................... Does this requirement only refer to the end of well during 

abandonment or at any time during the drilling of a 

well? There are times when mud weight is cut prior to 

drilling out a casing shoe due to exposure of weak formations or anticipated lost circulation. Would approval 

be required to cut mud weight in these circumstances? 

Consider that mud weight is cut just prior to drilling out 

the shoe in a controlled environment at which time the 

entire system is negative tested with pipe in the hole at 

TD and BOPs are capable of shutting in the well if and 

when needed.

This Final Rule revises § 250.456(j) to clarify that this requirement applies any time kill-weight mud is displaced, putting the wellbore in an underbalanced state. 

If the mud weight is cut, but the wellbore will remain in 

an overbalanced state, then approval is not required. 

§§ 250.515 and 250.616 .................................. It appears that some of the requirements of NTL 2010– 

N05 which applied to workover BOPs have been omitted in the revision to 30 CFR 250.5XX and 250.6XX. 

Specifically, verification that the blind/shear is capable 

of shearing all pipe in the well at MASP has been 

omitted for workover and coiled tubing operations. 

Verification of this capability is as important in 

workover as it is in drilling, for both surface BOPs and 

subsurface BOPs. API RP 16ST, ‘‘Coiled Tubing Wellcontrol Equipment Systems’’, Section 12, ‘‘Well-control 

Equipment Testing’’, should be referenced in 30 CFR 

250.6XX in addition to the reference to API RP 53.

BSEE agrees that it is important for BOP requirements to 

be consistent, regardless of the application or stage of 

a well. These requirements should also apply to wellcompletion and well-workover activities. We changed 

the regulatory text in §§ 250.515 and 250.615 to reflect 

this. In addition, in response to the concern raised by 

the commenter, this Final Rule adds these requirements to subpart Q, since the same equipment used in 

drilling and workovers may be used in decommissioning operations, and similar safety risks also exist. 

BSEE may consider incorporating by reference API RP 

16ST, ‘‘Coiled Tubing Well-control Equipment Systems’’ in future rulemaking. 

§ 250.1503 ........................................................ What is the definition of enhanced deepwater well-control 

training? Will this require a new certification of wellcontrol schools? 

The rule does not use the phrase, ‘‘enhanced deepwater 

well-control training.’’ It does require deepwater wellcontrol training for operations with a subsea BOP 

stack. The operator must ensure that all employees 

are properly trained for their duties as required in 

§ 250.1501. BSEE expects that operators will integrate 

the deepwater well-control training requirement into 

their current subpart O well-control program. 

§§ 250.1712(g), 250.1721(h), and 250.1715 ... Liabilities that will be placed onto a ‘‘Professional Engineer (PE)’’ are an issue. The PE approach demands 

that the PE is intimately involved in all aspects of the 

design and also in primary communication as the well 

is drilled and small variations in the plan are made or 

happen.

All liability for the well must remain with the operator 

without any ‘‘dilution’’ to a PE, although review by a 

PE or other ‘‘independent and reputable’’ third-party is 

totally appropriate.

The operator is responsible for all activities on its lease, 

regardless of requirements for various persons to certify or verify various aspects of operations. Although 

persons performing certifications and verifications have 

responsibility for their actions, such responsibility will 

not eliminate or diminish the operator’s responsibilities 

for compliance with applicable requirements. 

TABLE 2—TOPICS AND GENERAL QUESTIONS COMMENTS AND RESPONSES

Topic Comment BSEE response 

Participate in Standard Development .............. BOEMRE should participate in API’s open process for 

adopting industry standards on an on-going basis.

BSEE agrees that its involvement in the standard development process with API and other standards organizations is important. We are already active in API’s industry standard process and we are committed to continuing and increasing this involvement. 

Participate in Standard Development .............. BOEMRE should participate in revising American Welding Society’s (AWS) standards. AWS’s standards committees comply with ANSI-approved procedures for 

standards development, which, among other things, 

guarantee public and open participation by any materially affected entity, committee interest group balance, 

fair voting, and written technical issue resolution. AWS 

solicits ongoing input and comments for these revisions from any interested party, including BOEMRE. 

BOEMRE’s input to the standards committees would 

be invaluable to help understand the goals of the government and to apply AWS’s experts’ thoughtful consideration to ongoing regulatory issues. Moreover, participation in AWS standards-setting would provide 

BOEMRE with access to valuable scientific and technical expertise.

BSEE agrees that its involvement in the standard development process with AWS and other standards organizations is important. BSEE accepts this and other offers to participate in the development of standards that 

support the mission of BSEE. 


TKELLEY on DSK3SPTVN1PROD with RULES2
50870 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

TABLE 2—TOPICS AND GENERAL QUESTIONS COMMENTS AND RESPONSES—Continued 

Topic Comment BSEE response 

Subsea BOP Requirements ............................. More work should be carried out in this area before final 

requirements are identified. In particular, the findings of 

the post-mortem on the Horizon BOP should be carefully looked at prior to a ‘‘final rule’’.

BSEE reviewed the findings of various DWH investigations before developing the Final Rule. Findings from 

the DWH investigation that are within the scope of this 

rulemaking were incorporated. BSEE will address other 

findings in future rules. 

Blind-Shear Ram Redundancy Requirements With this rule, BOEMRE has made the important first 

step of requiring independent third-party verification of 

blind shear ram capability, but deferred one of the 

most critical safety improvements, the requirement to 

install redundant blind-shear rams in each OCS BOP, 

to a later rulemaking process. We recommend that redundant blind-shear rams be required for all OCS drilling operations as of June 1, 2011.

BSEE is considering this requirement for future regulations. We do recognize the importance of having redundant safety features on BOP stacks. However, we 

need to consider all the impacts of such a requirement 

before requiring it by regulation. BSEE has concluded 

that the requirements of the IFR, as modified by this 

Final Rule, have enhanced operational safety sufficiently until such time that BSEE determines whether 

to add a requirement for additional blind-shear rams. 

Accident Event Reporting ................................ Also missing from the IFR is a requirement that OCS operators and their contractors report to BOEMRE any 

accidental event that could significantly impact well integrity or blowout prevention. This proposed reporting 

requirement includes, but is not limited to, any event 

where blowout preventer seal material may be compromised.

BSEE’s incident reporting requirements are covered in 

§§ 250.187 through 250.190. Specifically, 

§ 250.188(a)(3) requires the reporting of all losses of 

well-control, including uncontrolled flow of formation or 

other fluids; flow through a diverter; or uncontrolled 

flow resulting from a failure of surface equipment or 

procedures. We are looking into expanding the reporting requirements in future rulemaking. 

Third-party Certifications .................................. The rule makes repeated references to third-party 

‘‘verification’’ of certain matters related to well-control 

equipment, including BOPs. The appropriate functional 

terminology should be ‘‘certification,’’ rather than 

‘‘verification.’’ In industry practice, ‘‘certification’’ and 

‘‘verification’’ are different functions. A party that ‘‘certifies’’ a process is different from the party that 

‘‘verifies’’ the certified process is being followed. This 

is more than a definitional difference.

We disagree with the commenter’s suggestion. The repeated use of the concept of independent third-party 

‘‘verification’’ in § 250.416 and conforming provisions of 

the other subparts derives directly from various recommendations of the Department’s May 10, 2010 

Safety Measures Report, e.g., Safety Measures Report 

Recommendations I.A.2 and I.C.7 (pp. 20–21) that use 

the term ‘‘verification.’’ The preparers of that report appear to have understood the distinction between ‘‘certification’’ and ‘‘verification’’ because in other recommendations the term ‘‘certification’’ is used, e.g., 

Recommendation I.A.1, recommending a written and 

signed third-party ‘‘certification’’ of certain things. 

Although a distinction may exist between certification and 

verification, the provisions of the Final Rule requiring 

third-party verification of certain features use that term 

correctly and, together with the other provisions of the 

Final Rule, establish an adequate basis to reduce 

safety risks associated with BOP stacks. These rules 

provide a substantial upgrade over the previous rules 

that did not contain such provisions. 

TABLE 3—REGULATORY IMPACT ANALYSIS COMMENTS AND RESPONSES

Topic Comment BSEE response 

Regulatory Impact Analysis ............................. The increased costs will negatively impact future OCS 

development. The IFR itself estimated the baseline risk 

of a catastrophic blowout at once every 26 years. 75 

FR at 63365. This estimate for a blowout in the Gulf of 

Mexico is even lower, as it appears the estimate used 

by BOEMRE is based on worldwide catastrophic blowout data.

BSEE will continue to evaluate regulatory changes that 

could result in offsetting cost savings for OCS operators as directed by the President in his January 18, 

2011 executive order, ‘‘Improving Regulation and Regulatory Review.’’ 

The estimate for the risk of a catastrophic blowout event 

is based upon one recorded GOM catastrophic blowout event and the historical number of deepwater GOM 

wells drilled, not world-wide blowout data. Going forward, we estimated the drilling of 160 deepwater wells 

annually for cost estimation purposes. The 160 deepwater wells per year may be more than will be drilled 

when considering all of the factors influencing GOM 

deepwater activity outside of this specific regulation. At 

the time of this analysis (during the summer of 2010), 

this number was estimated to be a reasonable baseline for the regulatory benefit-cost analysis. If on average fewer than 160 deepwater wells are drilled annually, the baseline activity scenario provides an upper 

bound regulatory cost estimate. If an estimate of 120 

deepwater wells per year is used in the benefit-cost 

calculation, both the cost and the benefit i.e., interval 

between blowouts will decrease by approximately the 

same factor. The historical risk of a catastrophic blowout event will be reduced from once in 26 years to 

once in 34 years. 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50871 

TABLE 3—REGULATORY IMPACT ANALYSIS COMMENTS AND RESPONSES—Continued 

Topic Comment BSEE response 

Regulatory Impact Analysis ............................. The costs for compliance prepared by the Agency are 

not reflective of the total cost of compliance and thus 

will negatively affect both small and large businesses 

more than alleged by the Agency.

Multiple commenters suggested that the costs of this 

rulemaking were not fully captured in the Regulatory 

Impact Analysis. BSSE and BOEMRE used the best 

available information to determine the compliance cost 

estimates for this rulemaking. The commenters do not 

identify specific regulatory provision where costs are 

claimed to be underestimated. Several of the compliance costs commenters associated with this rulemaking reflect provisions in existing regulations. Additionally, no alternative cost estimates are provided by 

this commenter. External factors influencing the cost of 

operating on the OCS are not considered to be compliance costs of this rulemaking. As explained in other 

portions of this preamble, BSEE has both decreased 

and increased some cost estimates for provisions in 

this rulemaking. However, the net estimated compliance cost has decreased from the estimate contained 

in the IFR. 

Regulatory Impact Analysis ............................. The benefit-cost analysis implies that a blowout may 

pose more problems in deepwater where drilling a relief well is likely to take longer. I find this statement 

troubling. It could be considered to imply, that it takes 

longer to penetrate seawater than hard rock. As an example, two drilling targets are at 20,000 feet total 

vertical depth (TVD). One is in 500 feet of water and 

the other is in 5,000 feet of water. For a well drilled in 

500 feet of water an additional 4,500 feet of hard rock 

drilling must be completed to reach the target. From 

public well data on the BOEMRE website, I found the 

following pair of wells: 

API Number TVD Water Depth Time to Reach Total 

Depth 608124001700 28497 6959 ft 200 days 

427084062600 28382 100 ft 390 days It is possible that 

the statement is true, that is due to a different distribution of TVD in shallow and deep water drilling targets. 

BOEMRE needs to be rigorous to see if its conjectures 

are supported by the data. This is part of a pattern of 

the claim that deep water activities are more risky than 

shallow water. This assumption is being made by 

BOEMRE as a result of the Deepwater Horizon incident 

The typical GOM exploratory well in shallow water takes 

less than 30 days to reach TVD. The typical GOM 

deepwater exploratory well takes nearly 90 days to 

reach TVD. This is primarily because, on average, 

shallow water wells are not drilled to depths as deep 

as deepwater wells. Well-completions for ‘‘wet’’ wells 

and abandonment for ‘‘dry’’ wells take additional time. 

While exceptions can be found, we maintain that in 

most cases our assumption will hold that a deepwater 

relief well will take longer than a shallow water relief 

well. 

Regulatory Impact Analysis ............................. The agency estimates 160 deepwater wells annually for 

the next 20 years. This is a very important estimate, 

since it drives the estimates of both the costs and benefits. Granted projections of the future in the oil and 

gas industry have been notoriously wrong. I see that 

160 wells annually as overly optimistic. My reasons 

are: 

—Historical data show a declining trend of the most recent years with all observations below 160.

—Deepwater Horizon incident will lead to less favorable conditions for drilling in the Gulf.

—Natural Gas from shale is a major disruption coming 

to North American energy markets. This is analogous to 

the cellular phone technology replacing land line phones 

in the last 20 years.

A better way of presenting the future benefits and costs 

is with a range of scenarios such as 160, 120 and 80 

wells a year. The Deepwater Horizon incident will lead 

to less favorable conditions for drilling in the Gulf of 

Mexico.

A reduction in the number of wells drilled per year will reduce the estimated annual compliance costs as well as 

the corresponding likelihood of a catastrophic blowout 

and hence the potential gains from any improvements 

in reliability. How much the new regulatory environment will affect future OCS drilling is unknown at this 

time. 

BSEE estimates the drilling of 160 deepwater wells annually for cost estimation purposes. The 160 deepwater wells per year may be more than will be drilled 

when considering all of the factors influencing GOM 

deepwater activity outside of this specific regulation. At 

the time this analysis was prepared for the IFR during 

the summer of 2010, it was estimated to be a reasonable baseline for the regulatory benefit-cost analysis. 

One hundred sixty deepwater wells per year can serve 

as an upper bound cost estimate for the regulation. If 

an estimate of 120 deepwater wells per year is used in 

the benefit-cost calculation, both the cost and the benefit will decrease by approximately the same factor. 

The historical risk applied to future drilling estimates 

for 120 wells per year will reduce the estimated risk 

from once in 26 years to once in 34 years. For only 80 

deepwater wells a year, the risk will be reduced to 

once each 52 years. A scenario analysis for 120 deepwater wells per year has been added to the benefitcost analysis. 

Regulatory Impact Analysis ............................. BOEMRE estimates an equal likelihood of serious damage or sinking of a MODU drilling rig from a catastrophic blowout event. Press reports indicate the sinking of Deepwater Horizon was due to bad fire fighting 

procedures. That is, pouring seawater on the floating 

vessel causing it to sink. When the accident report is 

completed, new standard practices should emerge for 

fire fighting with the byproduct of great reduction in the 

probability of sinking.

BOEMRE’s estimate, in the IFR, of an equal likelihood of 

loss or damage, is based on the two recorded events 

for severe damage or destruction of deepwater 

MODUs in the GOM. This rulemaking requires additional the testing of LMRP disconnect functionality. A 

disconnect of a deepwater MODU during a catastrophic event will likely protect the MODU from total 

loss. BSEE maintains that our baseline cost estimate 

for deepwater MODU damage is reasonable for purposes of this benefit cost analysis. 


TKELLEY on DSK3SPTVN1PROD with RULES2
50872 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

TABLE 3—REGULATORY IMPACT ANALYSIS COMMENTS AND RESPONSES—Continued 

Topic Comment BSEE response 

Regulatory Impact Analysis ............................. The benefit-cost sensitivity analysis provided no basis for 

the assumption that reservoirs at depths of 3,000 feet 

are generally more prolific than their shallow water 

counterparts. That statement is contradicted by most 

recent Reserves Report (http://www.gomr.boemre.gov/

homepg/offshore/fldresv/2006-able4.pdf) which shows 

of the 20 largest fields in the Gulf of Mexico, only five 

are located in depth greater than 3,000 feet.

The report referenced by the commenter does indicate 

that only 5 of the 20 largest GOM fields are in water 

depths greater than 3,000 feet. If the top 20 fields are 

further analyzed, 6 of the top 20 fields are in water 

depths of 2,860 feet or greater and discovered since 

1989. Fourteen of the fields are in water depths 247 

feet or less and discovered in 1971 or earlier. The 

GOM shelf is in decline and few large fields are likely 

to be discovered in the GOM shallow water. Over the 

last 40 years the largest fields with booked reserves 

have all been in deepwater. BSEE maintains that the 

basis for the sensitivity analysis that future discovered 

reservoirs at water depths of 3,000 feet or greater will 

be more prolific is a reasonable assumption for the 

benefit-cost scenario analysis for this rule. 

Regulatory Impact Analysis ............................. The agency’s estimation of costs is not consistent with 

our own estimates and we strongly encourage the 

agency to carefully review the assumptions that went 

into your analysis. Moreover, to potentially assist you 

with your examination of the socio-economic costs and 

consequences of the regulation, we have enclosed a 

report we commissioned by IHS-Global Insight entitled, 

‘‘The Economic Impact of the Gulf of Mexico Offshore 

Oil and Natural Gas Industry and the Role of the Independents,’’ which determined that more than $106 billion in Federal, state, and local revenues would be lost 

over a 10-year period if independents were excluded 

from deepwater. Obviously, this report examined 

broader policy impacts than were encompassed in the 

particular regulation, but we believe it provides a useful 

data set to examine these regulations within a broader 

context of impacts.

We have reviewed the report by IHS-Global Insight and 

found nothing that will substantiate, contradict or otherwise provide compliance cost figures for this rulemaking. Since the commenter’s own estimates were 

not provided, we cannot evaluate alternative cost estimates suggested by the commenter. The Final Rule 

does not exclude independents from deepwater drilling. 

Regulatory Impact Analysis—Small Business 

Impacts.

In its notice, BOEMRE included certain information regarding the composition of the oil and gas industry and 

the small business entities—lessees, operators, and 

drilling contractors—that will be most affected by this 

interim rule. BOEMRE estimates that $29 million dollars or 15.8 percent of the IFR’s total cost of $183 million will be borne by small businesses. This cost would 

comprise about 0.36 percent of these small businesses’ fiscal year 2009 revenue.

BOEMRE does not discuss how the regulation’s costs 

would be distributed among small businesses. Advocacy is concerned that these costs will impact certain 

small businesses more heavily than others. We encourage BOEMRE to include additional information regarding how the industry functions and which small entities are most likely to incur increased costs as a result of this IFR. We also recommend that BOEMRE include a more detailed discussion of the distribution of 

costs among the small entities identified in the IRFA 

(Initial Regulatory Flexibility Analysis) in order to accurately determine whether some small entities will incur 

disproportionate impacts as a result of this rule.

BOEMRE published a separate IRFA on December 23, 

2010 (75 FR 80717) with a 30 day comment period. 

The IRFA and the FRFA published with the final RIA 

provide the analysis required in the Regulatory Flexibility Act. This includes an estimate of the number of 

small entities affected, a description of reporting, recordkeeping requirements and evaluation of significant 

alternatives that could minimize the impacts on small 

entities while accomplishing the objectives of this rulemaking. 

The RFA requires agencies to include in their IRFA a description of any significant alternatives to the proposed 

rule that minimize significant economic impacts on 

small entities while still accomplishing the agency’s objectives. While BOEMRE did note a few alternatives in 

the interim rule, we recommend that BOEMRE include 

a more detailed discussion of the alternatives and their 

effects on small business and the reasons for or 

against adopting those alternatives. We further recommend that BOEMRE continue to conduct outreach 

with small entities affected by this rule and any future 

safety rules to develop alternatives that minimize disproportionate impacts on small entities.


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50873 

TABLE 3—REGULATORY IMPACT ANALYSIS COMMENTS AND RESPONSES—Continued 

Topic Comment BSEE response 

Regulatory Impact Analysis—Small Business 

Impacts.

A commenter estimated that the rulemaking will increase 

costs by $17.3 million for each deepwater well drilled 

with a MODU. This cost increase is attributed to required modification of the well plan and associated 

casing design that results in the addition of a liner and 

associated work.

The compliance costs for the IFR were estimated using 

the best available information at the time of publication. Neither the IFR nor this Final Rule requires operators to conform to a specific casing design, nor do 

they require new designs for well plans. The additional 

requirements of the IFR are intended to increase the 

safety of operating on the OCS considering the best 

available and safest technology. The commenter does 

not identify which elements increase either the time to 

drill a well by 15 rig days, or the cost by $17.3 million. 

Absent new and well-defined information, BSEE is unable to evaluate or adjust the compliance cost estimates for a deepwater well. 

Regulatory Impact Analysis—Small Business 

Impacts § 250.449(h).

A commenter identified $10.45 million in BOP inspection 

cost savings per deepwater well. The proposal is to 

function test the blind-shear rams every 14 days instead of every 7 days as required by § 250.449(h). The 

commenter claims ‘‘prior to the Macondo incident, all 

the rams on the BOP were function tested once a 

week except for the blind-shear rams.’’ Another commenter claims that ‘‘ * * * frequent function testing of 

blind/shears will exacerbate this stack body wear and 

introduce further exposure to leakage within the BOP’’.

The Final Rule does not change the existing regulation at 

§ 250.449(h) which requires a function test every 7 

days including the blind-shear rams. The 7-day testing 

requirement existed before the Macondo event and is 

not being made more stringent with this rulemaking. 

The commenter’s assertion that ‘‘prior to the Macondo 

incident, all the rams on the BOP were function tested 

once a week except for the blind-shear rams’’ is incorrect. The $10.45 million figure does not represent an 

additional compliance cost due to this rule, but an estimated cost savings to the company on a per-well basis 

if their recommendation for a once-every-two weeks 

function test requirement is accepted. 

A Joint Industry Project study completed in 2009 analyzed BOP equipment reliability. The results of this 

study suggest that up to $193 million per year could be 

saved through less frequent testing while achieving the 

same reliability for BOP performance. However, at this 

time BSEE believes increasing the duration between 

tests poses a greater risk than conducting the test on 

the current schedule. BOP testing frequency is a topic 

that merits further study. 

Regulatory Impact Analysis—Small Business 

Impacts.

Several commenters claim that the compliance costs are 

significantly higher than BOEMRE’s estimate. One 

comment suggests that the ‘‘Final Rule will add three 

to five times the amount the BOEMRE has published.’’ 

Another comment claims that the new regulation will 

cost as much as $28 million per deepwater well for 

compliance, compared to the $1.42 million estimated 

by BOEMRE.

BSEE has considered the limited cost information provided by commenters and new time and cost estimates 

obtained by the bureau since the publication of the 

IFR. 

The commenter’s $28 million compliance cost estimate 

includes a $10.45 million cost from additional BOP 

tests. However, these additional BOP tests do not represent additional costs, but a cost savings if the company’s recommendation to function test the blind shear 

rams every 7 days instead of every 14 days (with regard to the previously existing regulation) is accepted. 

If the recommendation is not accepted, there is no increased compliance cost for this rulemaking. This proposal on function test intervals is outside the scope of 

this rulemaking as previously stated in the response to 

comments for § 250.449(h). 

The additional $17.3 million of compliance costs are 

claimed to result from ‘‘modified casing design’’ and 

‘‘associated work.’’ The lack of specific data or citations result in a vague and indeterminate interpretation 

of these cost estimates. BSEE does not specify well 

designs. If a new well design used by the operator is 

the result of industry best practices, it is not a compliance cost of the regulation. As such, BSEE cannot 

comment on the presumed cost impact for modified 

casing design and associated work. 

IRFA ................................................................. The IRFA published by BOEMRE does not satisfy the 

agency‘s statutory obligation under the Regulatory 

Flexibility Act of 1980, as amended. The commenter 

believes that, since there is not a good cause exception to the Administrative Procedure Act‘s notice and 

comment rulemaking requirement, BOEMRE was required to publish an IRFA at the time of the proposed 

rulemaking. Further, the IRFA BOEMRE eventually 

published did not account for the significant costs likely 

to be imposed by BOEMRE‘s new interpretation of 

14,000 discretionary provisions found in API standards 

as mandatory permitting requirements.

The BSEE published an IRFA pursuant to the Regulatory 

Flexibility Act. While it was not published with the IFR, 

it was published shortly thereafter and made available 

for public comment. The SBA Office of Advocacy stated in its comments that ‘‘Advocacy appreciates 

BOEMRE’s decision to publish a supplemental IRFA.’’ 

The comments on the IRFA were considered along 

with all comments on the rulemaking. 


TKELLEY on DSK3SPTVN1PROD with RULES2
50874 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

TABLE 3—REGULATORY IMPACT ANALYSIS COMMENTS AND RESPONSES—Continued 

Topic Comment BSEE response 

Regarding the 14,000 discretionary provisions from API 

standards, BSEE disagrees with the commenter’s assertion that § 250.198(a)(3) will have resulted in significant additional costs. See the section-by-section discussion for further elaboration of this issue. 

V. Section-by-Section Discussion of the 

Requirements in Final Rule 

As of October 1, 2011, BOEMRE was 

officially reorganized into the separate 

agencies of BSEE and BOEM. This Final 

Rule reflects the appropriate name 

changes, based on the reorganization. 

Nomenclature change. BSEE is 

revising all references to the term glory 

hole in the regulations at 30 CFR 250 to 

the term well cellar. This revision will 

amend text at two locations in the 

regulations (§§ 250.421(b) and 

250.451(h)). Both terms refer to a 

depression deep enough to protect 

subsea equipment from ice-scour, when 

drilling in an ice-scour area. However, 

the term well cellar is more commonly 

used. 

Service Fees (§ 250.125) 

This Final Rule updates 

§ 250.125(a)(8) and (9) in the chart to 

reflect accurate numbering 

redesignation. 

Documents Incorporated by Reference 

(§ 250.198) 

Final § 250.198(a)(3) has been 

modified from the IFR in response to 

many comments received on one 

important issue. Section 250.198(a)(3) 

pertains to how BSEE ensures 

compliance with documents 

incorporated by reference in its 

regulations. The provision in the IFR 

read as follows: 

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. (75 

FR 63372) 

This provision was intended to clarify 

BSEE’s existing policy on compliance 

with documents incorporated by 

reference in regulations. A number of 

commenters from the offshore oil and 

gas industry objected to this provision. 

The commenters were particularly 

concerned about the statement in the 

last sentence of the paragraph that for 

the documents incorporated by 

reference in 30 CFR part 250, the word 

‘‘should’’ means ‘‘must.’’ Commenters 

asserted that there are 14,000 

occurrences of the word ‘‘should’’ just 

in documents incorporated from the 

American Petroleum Institute (API). 

These commenters provided a number 

of examples in which they asserted that 

the last sentence of paragraph (a)(3) 

could cause conflicts; undermine safety, 

instead of improving safety on the Outer 

Continental Shelf (OCS); and, in certain 

circumstances, establish requirements 

with which compliance may be 

impossible. Accordingly, such 

commenters specifically requested that 

the agency remove the last sentence 

from paragraph (a)(3). 

While some of the examples provided 

by commenters were overstated or did 

not account for alternatives or for the 

specifics in the operative language of 

the incorporated documents, we have 

removed the last sentence of paragraph 

(a)(3) as set forth in the IFR because it 

could have appeared to be overly broad 

and may not have provided the 

intended clarification. 

The last sentence is not needed as a 

means of emphasizing the agency’s 

interpretation of the binding effect of 

documents incorporated by reference, 

i.e., BSEE relies on the specific 

regulatory provisions that incorporate a 

document by reference for the intended 

effects of each incorporation. The other 

portions of paragraph (a)(3) make it 

clear that operators are required to 

comply with documents incorporated 

by reference, unless the specific sections 

performing the incorporation provide 

otherwise. Moreover, many, but not all, 

of the individual sections of BSEE 

regulations that incorporate documents 

by reference are written in terms that 

make it clear that compliance is 

mandatory, even where the incorporated 

consensus standards were written as 

recommendations, not obligations. 

This position is not a new one and 

was the agency’s interpretation of 

documents incorporated by reference 

long before the adoption of the IFR. For 

instance, in a 1988 Federal Register 

preamble to the final rule converting 

agency orders into regulations, the 

MMS, a predecessor agency to BSEE and 

BOEM, responded to public comments 

on the effect of incorporating documents 

by reference in its rules as follows: 

Comment—Objection was raised to the 

incorporation by reference of ‘‘recommended 

practice’’ documents which are intended 

only as recommendations, not as rules. 

Response—When MMS adopts the specific 

provisions of a document through the 

rulemaking process, that incorporation by 

reference establishes the recommended 

practice as a minimum standard which must 

be observed. 

Comment—A number of commenters 

expressed the view that with respect to 

documents incorporated by reference, it 

should be clear to what extent references 

within such incorporated documents are also 

binding. It was pointed out that documents 

proposed to be incorporated by reference in 

turn reference other documents, which 

reference other documents, down through 

numerous tiers. 

Response—Under the final rule, the 

material that is incorporated by reference is 

specifically identified. Adherence to 

documents referenced within an 

incorporated document is mandatory if such 

adherence is necessary for compliance with 

the document referenced in the rule. (53 FR 

10600) 

We reaffirm our position stated in the 

agency’s April 1, 1988, (53 FR 10600) 

rule that when BSEE adopts the specific 

provisions of a document through the 

rulemaking process, that incorporation 

by reference establishes the 

recommended practice as a minimum 

standard which must be observed. 

We recognize, however, that certain 

regulations incorporating documents by 

reference either do not make 

compliance mandatory with the 

incorporated provisions, or provide 

operators some flexibility in achieving 

compliance. For instance, regulations at 

§ 250.415(f) incorporate by reference 

API RP 65—Part 2, Isolating Potential 

Flow Zones During Well Construction. 

The requirement in § 250.415(f) 

specifies that operators must submit a 

written description of how they 

evaluated the best practices included in 

API RP 65—Part 2, not that they must 

comply with each of the best practices. 

This Final Rule is not intended to upset 

that interpretation or to modify the 

meaning of any particular regulatory 

provision that incorporates documents 

by reference. 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50875 

To the extent that the commenters 

were correct in asserting that the last 

sentence of § 250.198(a)(3) in the IFR (or 

other regulations that establish 

mandatory compliance with 

incorporated documents) will lead to 

unintended consequences, BSEE’s rules 

already provide the means for operators 

to seek relief in situations where they 

need an alternative means to comply. 

One provision, § 250.141, allows 

operators to use alternative procedures 

or equipment that provides a level of 

safety and environmental protection 

that equals or surpasses that required by 

BSEE rules. Another, § 250.142, 

provides for departures from operating 

requirements. Other provisions 

throughout BSEE regulations allow for 

departures related to specific 

circumstances (e.g., plans, drilling 

operations, and structure removal). It 

should be noted that all of these 

departures require advance BSEE 

approval. 

This approach was clarified in a 

March 28, 2011, Supplemental 

Information document that appears on 

the BSEE Web site. That document 

made it clear that the rules require 

operators to seek BOEMRE approval to 

deviate from a practice or procedure 

when the document incorporated by 

reference requires a particular practice 

or procedure. 

Incorporation of API Standard 65—Part 

2, Second Edition 

In this Final Rule, we have modified 

§ 250.198(h)(79) by incorporating the 

second edition of API Standard 65—Part 

2 that was issued in December 2010. 

This change was made in response to 

comments. Previously, the first edition 

was incorporated. API also designated 

this recommended practice into a 

standard. 

What must my casing and cementing 

programs include? (§ 250.415) 

In the IFR, BOEMRE added a new 

§ 250.415 (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. In the IFR, 

we also revised paragraphs (c), (d), and 

(e) to accommodate the new paragraph. 

The text of paragraph (f) was changed in 

this Final Rule to update the cross 

reference to sections 4 and 5 of the 

second edition of API Standard 65—Part 

2. These sections correspond to sections 

3 and 4 of the earlier edition that were 

previously cross-referenced. The basis 

and purpose for this section was set 

forth in the preamble of the IFR (75 FR 

63346). 

In response to comments, BSEE 

developed a table, set forth below, based 

on API Standard 65—Part 2 Annex D 

which outlines the process summary for 

isolating potential flow zones during 

well construction. For example, the 

operator may use Annex D or the 

following Table 4 as a guide for 

complying with the written description 

of how an operator evaluated the best 

practices included in API Standard 65— 

Part 2 required by § 250.415(f). 

TABLE 4—EXAMPLE OF HOW TO EVALUATE THE BEST PRACTICES IN API STANDARD 65—PART 2 

GENERAL QUESTIONS 

1 Have you considered the following in your well planning and drilling plan determinations: evaluation for flow potential, 

site selection, shallow hazards, deeper hazard contingency planning, well-control planning for fluid influxes, planning for lost circulation control, regulatory issues and communications plans, planning the well, pore pressure, fracture gradient, mud weight, casing plan, cementing plan, drilling plan, wellbore hydraulics, wellbore cleaning, barrier 

design, and contingency planning? [API 65–2 1.5].

Yes/No. 

2 Have you considered the general well practices while drilling, monitoring and maintaining wellbore stability, curing 

and preventing lost circulation, and planning and operational considerations? [API 65–2 1.6].

Yes/No. 

FLOW POTENTIAL 

3 Will a pre-spud hazard assessment be conducted for the proposed well site? ............................................................... Yes/No. 

4 List all potential flow zones within the well section to be cemented ................................................................................. Describe below. 

5 Has the information concerning the type, location, and likelihood of potential flow zones been communicated to key 

parties (cementing service provider, rig contractor, or third parties)? 

Yes/No. 

CRITICAL DRILLING FLUID PARAMETERS 

6 Are fluid densities sufficient to maintain well-control without inducing lost circulation? ................................................... Yes/No. 

CRITICAL WELL DESIGN PARAMETERS 

7 Will you use a cementing simulation model in the design of this well? ............................................................................ Yes/No. 

7a If yes, how is the output of this simulation model used in your decision-making process? ............................................. Describe below. 

7b If no, include discussion of why a model is not being used .............................................................................................. Describe below. 

7c Either way, include the number and placement of centralizers being used ..................................................................... Describe below. 

8 Will you ensure the planned top of cement will be 500 feet above the shallowest potential flow zone? ........................ Yes/No. 

9 Have you confirmed that the hole diameter is sufficient to provide adequate centralization? ......................................... Yes/No. 

10 If there are any isolated annuli, how have you mitigated thermal casing pressure build-up? .......................................... NA or Describe 

below. 

11 Will you ensure the well will be stable (no volume gain or losses, drilling fluid density equal in vs. out) before commencing cementing operations? Yes/No. 

12 List all annular mechanical barriers in your design ........................................................................................................... Describe below. 

13 Has the rathole length been minimized or filled with drilling fluid with a density greater than the cement density? ....... Yes/No. 

14a If you have any liner top packers exposed to the production or intermediate annulus, what is the rating for differential 

pressure across this packer? 

NA or Describe 

below. 

14b If you have any liner top packers exposed to the production or intermediate annulus, have you confirmed that your 

negative test will not exceed this rating? 

Yes/No/NA. 

15 What type of casing hanger lock-down mechanisms will be used? .................................................................................. Describe below. 

16 For all intermediate and production casing hangers set in subsea, HP wellhead housing, will you immediately set/energize the lock-down ring prior to performing any negative test? Yes/No. 


TKELLEY on DSK3SPTVN1PROD with RULES2
50876 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

TABLE 4—EXAMPLE OF HOW TO EVALUATE THE BEST PRACTICES IN API STANDARD 65—PART 2—Continued 

17 For all production casing hangers set in subsea, HP wellhead housing, will you set/energize the lock-down sleeve 

immediately after running the casing and prior to performing any negative test? 

Yes/No. 

CRITICAL OPERATIONAL PARAMETERS 

18 Will you have 1 mechanical barrier in addition to cement in your final casing string (or liner if it is your final string)? .. Yes/No. 

19 Do you plan to nipple down BOP in accordance with the WOC requirements in 30 CFR 250.422? .............................. Yes/No. 

20 Do you plan on running a cement bond log on the production and intermediate casing/liner prior to conducting the 

negative test on that string? 

Yes/No. 

Are contingency plans in place for the following: 

21 Lost circulation? ................................................................................................................................................................. Yes/No. 

22 Unplanned shut-down? ...................................................................................................................................................... Yes/No. 

23 Unplanned rate change? .................................................................................................................................................... Yes/No. 

24 Float equipment does not hold differential pressures? ..................................................................................................... Yes/No. 

25 Surface Equipment issues? ............................................................................................................................................... Yes/No. 

26 Will you monitor the annulus during cementing and WOC time? ..................................................................................... Yes/No. 

27 If using foam cement, is a risk assessment being conducted and incorporated into cementing plan? ........................... Yes/No. 

28 If using foam cement, will the foamer, stabilizer, and nitrogen injection be controlled by an automated process system? Yes/No. 

CRITICAL MUD REMOVAL PARAMETERS 

28 Have you tested your drilling fluid and cementing fluid programs for compatibility to reduce possible contamination? Yes/No. 

29 Have you considered actual well conditions when determining appropriate cement volumes? ....................................... Yes/No. 

30 Has the spacer been modeled or designed to achieve the best possible mud removal? ................................................ Yes/No. 

CRITICAL CEMENT SLURRY PARAMETERS 

31 Have all appropriate cement slurry parameters been considered to ensure the highest probability of isolating all potential flow zones? Yes/No. 

32 Do you plan on circulating bottom up prior to the start of the cement job? ..................................................................... Yes/No. 

What must I include in the diverter and 

BOP descriptions? (§ 250.416) 

The IFR revised § 250.416(d) to 

include the submission of a schematic 

drawing of all control systems, 

including primary control systems, 

secondary control systems, and pods for 

the BOP system. We did not revise this 

paragraph in the Final Rule. 

The IFR revised § 250.416(e) 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. In response to comments 

received, we emphasize that the blindshear rams must be capable of shearing 

heavy weight drill pipe. The Final Rule 

also revises § 250.416(e) to clarify that 

drill pipe includes workstring and 

tubing. The IFR provided that the 

supporting documentation has to 

include test results, but did not specify 

which tests are required. The Final Rule 

clarifies that the documentation must 

include actual shearing and subsequent 

pressure integrity test results for the 

most rigid pipe to be used and 

calculations of shearing capacity of all 

pipe to be used in the well, including 

correction for MASP. 

The IFR added § 250.416(f) to require 

independent third-party verification 

that a subsea BOP stack is designed for 

the specific equipment used on the rig. 

In the Final Rule, we revised this 

paragraph to also include surface BOP 

stacks on floating facilities to clarify the 

intent that this verification is required 

for all floating drilling operations. This 

section also includes the requirements 

for verification that the BOP stack has 

not been compromised or damaged from 

previous service. BSEE realizes that an 

APD may be submitted prior to the 

third-party verification. Under such 

circumstances, BSEE may issue a 

condition of approval in the APD 

contingent on the third-party 

verification. The verification must be 

completed prior to BOP latch-up onto 

the associated well. The third-party 

verification will be submitted to BSEE 

in an APD or a revised sidetrack permit. 

The IFR added § 250.416(g) to 

describe the criteria and documentation 

for an independent third-party that must 

be submitted with the APD to BSEE for 

review. 

In the IFR, § 250.416(g)(1) of this 

section referenced the independent 

party in § 250.416(e). This Final Rule 

removes this reference, since the 

requirements for the independent thirdparty in paragraph (g) apply to any use 

of the independent third-party in 

§ 250.416. 

We revised paragraph (g)(1) to specify 

that a registered professional engineer, 

or a technical classification society, or a 

licensed professional engineering firm, 

could qualify as the independent thirdparty under this section. We also 

removed the reference that the original 

equipment manufacturer (OEM) cannot 

be the independent third-party. We 

removed this prohibition so that the 

OEM, who has the expertise with the 

equipment, may function as the 

independent third-party under this 

section as long as it meets the 

requirements of the independent thirdparty outlined in this section. 

Based on comments received, we have 

also revised qualifications for 

independent third parties to remove 

various standards that were not 

sufficiently objective or certain. We 

removed the provision from the IFR that 

the firm can be an API-licensed 

manufacturing, inspection, or 

certification firm, since API does not 

license such firms. We also removed the 

requirement that the firm must carry 

industry-standard levels of professional 

liability insurance, based on comments 

questioning how to determine ‘‘industry 

standard levels of professional liability 

insurance.’’ BSEE has not devised an 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50877 

approach to make this determination. 

We removed the requirement that the 

firm provide evidence that it is 

‘‘reputable’’ because such a standard is 

too vague. Similarly, we removed the 

requirement that a firm have no record 

of violations of applicable law because 

it is not clear what ‘‘applicable law’’ 

refers to and how far back the 

requirement applies, and because state 

licensure or registration will assure 

current compliance. In place of the 

requirements that were removed, in 

response to comments discussed earlier, 

we added that evidence be provided to 

demonstrate that the person or entity 

performing the third-party verification 

has the expertise and experience 

necessary to perform the required 

verifications. Thus, the Final Rule 

requires evidence of appropriate 

licenses and evidence of expertise and 

experience to perform the verifications. 

We also revised paragraph (g)(2)(ii) to 

change the notification of the 

appropriate BSEE District Manager from 

24 hours in advance of any shearing ram 

tests or shearing ram inspections to 72 

hours in advance. This amount of time 

will facilitate having a BSEE 

representative present to witness at least 

one of these tests. See the discussion of 

§ 250.416 in the IFR (75 FR 63357 

through 63358) for additional 

information on this section. 

What additional information must I 

submit with my APD? (§ 250.418) 

This Final Rule revises § 250.418(g) 

by adding the phrase ‘‘below the 

mudline’’. The revision is made to 

clarify the intent that the operator must 

submit a request for approval to wash 

out if the operator is washing out below 

the mudline, not for washing out the 

cement in all situations, as was 

previously provided. 

The IFR added § 250.418(h), which 

requires operators to submit 

certifications of their casing and 

cementing program required by 

§ 250.420(a)(6). Paragraph (h) is not 

revised in this Final Rule. 

The IFR added § 250.418(i), requiring 

the operator to submit a description of 

qualifications of any independent thirdparty. Paragraph (i) is revised in this 

Final Rule by changing the cross 

reference in that paragraph to 

§ 250.416(g), the paragraph that 

specifies the qualifications referred to 

instead of paragraph (f) as was provided 

in the IFR. 

What well casing and cementing 

requirements must I meet? (§ 250.420) 

The IFR added § 250.420(a)(6) that 

requires the operators to submit 

certification of their casing and 

cementing program signed by a 

Registered Professional Engineer. In the 

IFR, § 250.420(a)(6) also included 

certification requirements pertaining to 

two independent tested barriers. This 

Final Rule reorganizes § 250.420(a)(6) to 

focus solely on the required certification 

and the role of the persons making the 

certification. This Final Rule moves the 

requirements pertaining to two 

independent barriers to § 250.420(b)(3), 

discussed below. 

The Registered Professional Engineer 

signing the certification must be 

registered in a State of the United States. 

In response to comments about the 

qualifications of the person performing 

the certification, this Final Rule 

specifies that the person signing the 

certification must have sufficient 

expertise and experience to perform the 

certification. During the review process, 

BSEE may disallow a certification if it 

concludes that the certifier’s expertise 

and experience to perform the 

certification are inadequate. Although 

the regulation does not require that 

every certification be accompanied by 

documentation of the qualifications of 

the person performing the certification, 

BSEE may, on a case-by-case basis, 

request that such material be provided. 

As was provided in the IFR, this Final 

Rule states that the Registered 

Professional Engineer reviewing the 

casing and cementing design must 

certify that the design is appropriate for 

the purpose for which it is intended, 

under expected wellbore conditions. We 

have also added that the certification 

must specify that the casing and 

cementing design is sufficient to satisfy 

the tests and requirements of §§ 250.420 

and 250.423. In that manner, the 

certification ties into the substantive 

requirements of the regulations. Final 

§ 250.420(a)(6) also provides that the 

Registered Professional Engineer must 

be involved in the casing and cementing 

design process. This requirement will 

assure that the Registered Professional 

Engineer will be familiar enough with 

the design process and the final design 

to make the required certification. 

As mentioned above, this Final Rule 

moves the requirement pertaining to 

two independent barriers from 

§ 250.420(a)(6) to final § 250.420(b)(3). 

In response to comments, this Final 

Rule revises this requirement to clarify 

the meaning of ‘‘two independent tested 

barriers.’’ We retained the requirement 

for two independent barriers, but 

removed the word ‘‘tested,’’ based on 

comments. The term ‘‘two independent 

tested barriers’’ was confusing. In 

response to comments inquiring as to 

which flow paths must have 

independent barriers, we clarify that on 

all wells that use subsea BOP stacks, the 

well must include two independent 

barriers, including one mechanical 

barrier, in each of the annular flow 

paths. We also added examples of 

acceptable types of barriers, including 

primary cement job and seal assembly. 

In the IFR, § 250.420(b)(3) required 

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. This Final 

Rule provides, instead, that for the final 

casing string (or liner if it is the final 

string), an operator must install one 

mechanical barrier in addition to 

cement, to prevent flow in the event of 

a failure in the cement. We have 

clarified that this requirement applies to 

the final casing string or liner, since that 

is the string of casing that will be 

exposed to wellbore conditions. Final 

§ 250.420(b)(3) states that an operator 

must submit documentation of this 

installation to BSEE in the End-ofOperations Report (Form BSEE–0125) 

instead of 30 days after installation, as 

was provided in the IFR. This Final 

Rule also adds that these barriers cannot 

be modified prior to or during 

completion or abandonment operations. 

The IFR stated that dual mechanical 

barriers may include dual float valves. 

In response to comments, we clarify that 

a dual float valve, by itself, is not 

considered a mechanical barrier. 

We also added a provision that 

clarifies that the BSEE District Manager 

may approve alternative options. 

Although operators may apply for 

approval for use of alternative producers 

of equipment under existing BSEE 

regulations at § 250.141, we mention it 

specifically in this provision because we 

recognize that there are other 

approaches to prevent flow in the event 

of a failure in the cement. 

What are the requirements for pressure 

testing casing? (§ 250.423) 

The IFR reorganized § 250.423 to 

accommodate new requirements, 

redesignated the previous regulation as 

§ 250.423(a) and added new § 250.423(b) 

and (c). Paragraph (b) was added to 

require 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. Paragraph (c) was added to 

require the operator to perform a 

negative pressure test on all wells to 

ensure proper installation of casing for 

the intermediate and production casing 

strings. 

This Final Rule revises § 250.423(a) to 

clarify that if pressure declines more 

than 10 percent in a 30-minute test, or 


TKELLEY on DSK3SPTVN1PROD with RULES2
50878 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

there is an indication of a leak, the 

operator must investigate the cause and 

receive approval from the appropriate 

BSEE District Manager for the repair 

(e.g., re-cement, casing repair, or 

additional casing). BSEE revised the 

language to state that BSEE approval is 

needed. 

This Final Rule, slightly rearranges 

§ 250.423(b) for clarification to state, 

‘‘You must ensure proper installation of 

casing in the subsea wellhead or liner in 

the liner hanger.’’ This Final Rule also 

revises §§ 250.423(b)(1) from the IFR by 

separating the requirements for casing 

strings and liners into paragraphs (b)(1) 

and a new paragraph (b)(2), 

respectively. 

New § 250.423(b)(2) provides that if 

the liner has a latching or lock down 

mechanism, the operator must ensure 

that the mechanism is engaged upon 

installation of the liner. This new 

provision clarifies that BSEE does not 

require the use of a latching or lock 

down mechanism, but if the 

mechanisms are used, they must be 

engaged upon installation. 

The subsequent paragraphs, 

numbered as §§ 250.423(b)(2), (b)(3), 

and (b)(4) in the IFR, are renumbered as 

§§ 250.423(b)(3), (b)(3)(i), and (b)(3(ii)) 

in this Final Rule. 

In response to comments, this Final 

Rule revises § 250.423(c) to require a 

negative pressure test be performed only 

on wells that use a subsea BOP stack or 

wells with a mudline suspension system 

instead of on all wells, as was provided 

in the IFR. Requiring the performance of 

negative pressure tests on wells that use 

a surface BOP stack is not necessary; it 

is more important to test the barriers in 

subsea wells and wells with a mudline 

suspension. 

In response to comments, this Final 

Rule adds new §§ 250.423(c)(1) and 

(c)(2) to clarify when the negative 

pressure test must be performed. We 

specifically require the operator to 

perform a negative pressure test on the 

final casing string or liner. We also 

require a negative pressure test prior to 

unlatching the BOP. The negative 

pressure test is to be conducted on those 

components, at a minimum, that will be 

exposed to the negative differential 

pressure that will occur when the BOP 

is disconnected. The Final Rule 

provides that the BSEE District Manager 

may require performance of additional 

negative pressure tests on other casing 

strings or liners (e.g., intermediate 

casing string or liner) or on wells with 

a surface BOP stack in situations where 

it is appropriate. BSEE is requiring the 

negative pressure test on the final casing 

string or liner because the operator may 

decide to continue other operations on 

the well before the BOP is disconnected. 

The subsequent paragraphs that were 

numbered §§ 250.423(c)(1) and (c)(2) in 

the IFR have been redesignated as 

§§ 250.423(c)(3) and (c)(4). The 

redesignated § 250.423(c)(3) is revised to 

clarify that if any of the test procedures 

or criteria for a successful test change, 

the operator must submit for approval 

the changes in an Revised APD or APM. 

In response to comments, we added 

new paragraph (c)(5) to this section, 

which addresses what the operator must 

do in the event of an indication of a 

failed negative pressure test and 

includes examples of an indication of 

failure (pressure buildup or observed 

flow). The operator must investigate the 

cause of the possible failure, correct the 

problem, contact the appropriate BSEE 

District Manager, submit a description 

of the corrective action taken, and 

receive approval from the appropriate 

BSEE District Manager for the retest. 

Although a prudent operator would 

likely follow these steps in the absence 

of a regulatory provision, inclusion of 

paragraph (c)(5) is intended to provide 

assurance that these steps will occur, 

and also ensure that BSEE will be 

involved in these situations. 

This Final Rule also adds 

§ 250.423(c)(6), clarifying that operators 

must have two barriers in place prior to 

performing the negative pressure test. 

This safeguard is necessary to protect 

against well failure. 

This Final Rule also adds 

§ 250.423(c)(7), requiring 

documentation of the successful 

negative pressure test in the End-ofOperations Report (Form BSEE–0125). 

What must I do in certain cementing 

and casing situations? (§ 250.428) 

This Final Rule revises § 250.428(c) 

by removing § 250.428(c)(1) which 

allowed an operator to pressure test the 

casing shoe when the operator has an 

indication of an inadequate cement job. 

This section was removed because the 

pressure test of the casing shoe does not 

provide sufficient information to 

evaluate the integrity of the cement job. 

This change is consistent with other 

revisions in the IFR and this Final Rule 

and necessary to ensure the integrity of 

the cement job. This Final Rule revises 

§ 250.428(c) to include ‘‘gas cut mud’’ as 

an indication of an inadequate cement 

job. The option to perform a cement 

‘‘bond’’ log in paragraph (c)(3) is revised 

to allow operators to perform a cement 

‘‘evaluation’’ log instead. This option 

was changed in the Final Rule to allow 

operators more flexibility to incorporate 

the use of newer technology to assess 

the cement job other than a bond log; 

however, an operator may still use a 

bond log as an evaluation tool. With 

previous § 250.428(c)(1) removed, the 

Final Rule renumbers the remaining 

paragraphs as § 250.428(c)(1), (c)(2), and 

(c)(3). 

What are the requirements for a subsea 

BOP system? (§ 250.442) 

Section 250.442 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 specific 

BOP requirements. 

Paragraph (a) was revised in the IFR 

to clarify that the blind-shear rams must 

be capable of shearing any drill pipe in 

the hole under maximum anticipated 

surface pressures. In response to 

comments, this Final Rule revises 

§ 250.442(a) to clarify that drill pipe 

includes workstring and tubing. 

The IFR redesignated the requirement 

in previous § 250.442(d) to have an 

operable dual-pod control system as 

new § 250.442(b), without substantive 

change. This Final Rule does not modify 

the redesignated paragraph. 

The IFR added § 250.442(d), 

containing requirements related to ROV 

intervention capability. This Final rule 

does not modify these requirements. 

The IFR added § 250.442(e), requiring 

operators to maintain an ROV and have 

a trained ROV crew on each floating 

drilling rig on a continuous basis. This 

Final Rule modifies § 250.442(e) by 

removing the word ‘‘floating’’, which 

conflicted with the table heading ‘‘when 

drilling with a subsea BOP system’’ and 

created confusion as to the agency’s 

intent. This Final Rule clarifies that 

when drilling with a subsea BOP 

system, the operator must maintain an 

ROV and have a trained ROV crew on 

each drilling rig (floating or not) on a 

continuous basis once BOP deployment 

has been initiated from the rig (the stack 

has been splashed) until the BOP is 

recovered to the surface. 

The IFR added § 250.442(f), 

containing requirements related to 

autoshear and deadman systems. This 

Final Rule revises §§ 250.442(f)(1) and 

(2) in the IFR to specify that the 

autoshear system and deadman system 

must each be able to close, at a 

minimum, one set of blind-shear rams, 

instead of one set of shear rams. We 

revised the language to ensure that the 

shearing rams, when activated, will be 

capable of sealing the wellbore. We also 

revised § 250.442(f)(3) to clarify that the 

acoustic system will be a secondary 

control system, and cannot supplant a 

required control system. This Final Rule 

provides that if an operator intends to 

install an acoustic control system, it 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50879 

must demonstrate to BSEE, as part of the 

information submitted under § 250.416, 

that the acoustic system will function in 

the anticipated environment and 

conditions. 

The following paragraphs were added 

in the IFR: § 250.442(g), requiring the 

operator to have operational or physical 

barrier(s) on BOP control panels to 

prevent accidental use of disconnect 

functions; § 250.442(h), requiring the 

operator to clearly label all control 

panels for the subsea BOP system; 

§ 250.442(i), requiring the operator to 

develop and use a management system 

for operating the BOP system (the 

operator may include this with its SEMS 

program as described in 30 CFR 250 

subpart S); and § 250.442(j), requiring 

the operator to establish minimum 

requirements for personnel authorized 

to operate critical BOP equipment. This 

Final Rule does not revise these 

paragraphs. 

This Final Rule removes § 250.442(l), 

addressing the use of BOP systems in 

ice-scour areas. This paragraph 

duplicated § 250.451(h), and does not 

need to appear in two places in the CFR. 

What associated systems and related 

equipment must all BOP systems 

include? (§ 250.443) 

This Final rule revises § 250.443(g) to 

clarify that all BOP systems must 

include a wellhead assembly with a 

rated working pressure that exceeds the 

maximum anticipated wellhead 

pressure instead of the maximum 

anticipated surface pressure as was 

previously provided. This revision 

clarifies what is required when using 

subsea systems and is made to be as 

consistent as possible with a 

recommendation in the DWH JIT report. 

What are the BOP maintenance and 

inspection requirements? (§ 250.446) 

The IFR revised § 250.446(a) to 

require the operator to document the 

procedures used and to record the 

results of BOP system maintenance and 

inspection actions, and make the 

records available to BSEE upon request. 

This Final Rule further revises 

§ 250.446(a) to clarify that the 

documentation requirements pertain to 

how the BOP system maintenance and 

inspections met or exceeded the specific 

API RP 53 provisions referenced earlier 

in that section. 

The IFR specified that the documents 

required in § 250.446(a) must be 

maintained on the rig for two years or 

from the date of the last major 

inspection, whichever is longer. The 

rule did not state how long from the 

date of the last major inspection the 

records must be kept. To clarify and 

simplify the timeframe for keeping 

records, the Final Rule provides that 

records must be maintained on the rig 

for two years from the date the records 

are created or for longer if directed by 

BSEE. 

The requirement for the BOP system 

maintenance and inspection records to 

be maintained on the rig for a minimum 

of two years will assure that the records 

will be kept at the location of, and 

follow, the BOP system if and when the 

rig changes locations. This requirement 

will help ensure that persons 

responsible for using a BOP system in 

the future will be able to identify any 

earlier problems with the BOP system 

and will be able to take necessary steps 

to try to prevent recurrence of such 

problems. 

As with other activities they perform, 

drilling contractors who control the 

drilling rig and perform BOP system 

maintenance and inspections are 

responsible for the documentation and 

recordkeeping requirements of 

§ 250.446(a), see § 250.146(c). Failure to 

satisfy these obligations will subject all 

responsible persons, including 

contractors, to BSEE enforcement. 

Once the two year obligation for 

maintaining records begins, a contractor 

controlling the rig will continue to have 

the record-keeping responsibility even if 

the rig subsequently moves and is used 

for drilling on different leases with 

different operators. To satisfy their 

obligations, the original lessee and 

operator will need to obtain assurance 

from a contractor in possession of the 

BOP system maintenance and 

inspection records for the wells on its 

lease that the records will be kept and 

made available to BSEE for the required 

period. 

What additional BOP testing 

requirements must I meet? (§ 250.449) 

In conjunction with the changes from 

the IFR regarding stump test 

requirements, this Final Rule revises 

§ 250.449(b) to clarify that the time 

lapse between the stump test of a subsea 

BOP system and the initial test of a 

subsea BOP system on the seafloor must 

not exceed 30 days. This practice is 

already common in industry and BSEE 

policy. The IFR added § 250.449(j) 

requiring certain testing during the 

stump test and during the initial testing 

on the seafloor, but did not specify the 

temporal relationship between the two 

sets of tests. This Final Rule clarifies the 

timing. 

This revision is intended to help 

ensure that the condition of a BOP has 

not deteriorated between the stump test 

and the actual use of the BOP. The 

previous rules did not have a timeframe 

between the BOP system stump test and 

the initial BOP system test on the 

seafloor. In response to operator 

inquiries, BSEE’s Gulf of Mexico region 

established a policy that BOP system 

stump tests are to be performed within 

30 days of the initial BOP system test on 

the seafloor, to preclude reliance upon 

stump tests that do not accurately reflect 

the condition of the BOP system at the 

time of installation. This Final Rule 

codifies that policy, and will ensure that 

operators will not rely upon older 

stump tests to satisfy § 250.449(b). This 

provision is not expected to impact 

operations to any great degree because 

stump tests of subsea BOP systems 

typically occur shortly before BOP 

systems are initially installed. 

The IFR made slight editorial changes 

to §§ 250.449(h) and (i) to account for 

the new paragraphs following those 

sections. This Final Rule makes no 

further changes to §§ 250.449(h) and (i). 

The IFR added §§ 250.449(j) and (k). 

In response to comments that the BOP 

tests are insufficient, we revised 

§ 250.449(j) to require the operator to 

test and verify closure of at least one set 

of rams during the initial test on the 

seafloor through an ROV hot stab and to 

clarify that each ROV must be fully 

compatible with the BOP stack 

intervention panels. The Final Rule also 

clarifies that when an operator submits 

the test procedures to BSEE for 

approval, the operator must include 

how it will test each ROV intervention 

function. 

This Final Rule also adds a new 

paragraph, § 250.449(j)(2), which 

requires a 72-hour notification prior to 

the initiation of a stump test and initial 

test on the seafloor. Operators must 

notify BSEE at least 72 hours prior to all 

BOP stump tests and initial BOP tests 

on the seafloor to facilitate having a 

BSEE representative present to witness 

at least one of these tests. The 

subsequent paragraph, § 250.449(j)(2) in 

the IFR, has been redesignated as 

§ 250.449(j)(3) in this Final Rule. 

In response to comments, this Final 

Rule revises § 250.449(k) to require the 

operator to test the deadman system and 

verify closure of a set of blind-shear 

rams during the initial test on the 

seafloor. The Final rule also adds new 

clarification to ensure that the well is 

secure and that hydrocarbon flow would 

be isolated during the initial deadman 

test on the seafloor. For example if 

hydrocarbons are present in the well, 

the hydrocarbon flow could be isolated 

by closing appropriate production safety 

devices, required in subpart H of this 

part, installing plugs, and/or cementing. 

Also to help mitigate risk for the 

function test of the deadman system 


TKELLEY on DSK3SPTVN1PROD with RULES2
50880 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

during the initial test on the seafloor, we 

added a provision that there must be an 

ROV on bottom. The ROV is located on 

bottom to assist in the testing, as 

needed, and as a back-up to disconnect 

the LMRP should the rig experience a 

loss of station event. 

In response to comments BSEE also 

revised final § 250.449(k)(1) to clarify 

that the required submittals of 

procedures for the autoshear and 

deadman function testing must include 

documentation of the controls and 

circuitry of the system utilized during 

each test. This documentation is 

necessary to verify that the same 

deadman controls are used in testing 

and emergency activation. This Final 

Rule also specifies that the submittals 

include procedures on how the ROV 

will be utilized during testing. 

For the same reasons, BSEE made 

corresponding changes in final 

§§ 250.517(d)(9), 250.617(h)(2), and 

250.1707(h)(2). 

What must I do in certain situations 

involving BOP equipment or systems? 

(§ 250.451) 

As described above, this Final Rule 

revises § 250.451(h), to replace the term 

‘‘glory hole’’ with the term ‘‘well 

cellar.’’ This Final Rule also adds new 

§ 250.451(j) stating that before an 

operator removes the BOP it must have 

two barriers in place, and that the BSEE 

District Manager may require additional 

barriers. This provision was added to 

provide clarification for barrier 

requirements prior to removing the BOP 

stack, and is a safeguard necessary to 

protect against well failure. This 

regulation is intended to apply to 

normal, planned operations; however, if 

the operator encounters an unexpected 

situation as outlined in § 250.402, the 

operator should still follow those 

guidelines as appropriate. 

What safe practices must the drilling 

fluid program follow? (§ 250.456) 

The IFR redesignated then existing 

§ 250.456(j) as § 250.456(k) and added a 

new § 250.456(j) to require approval 

from the BSEE District Manager before 

displacing kill-weight fluid from the 

wellbore. 

This Final Rule revises § 250.456(j) to 

clarify that the operator must receive 

prior approval before displacing killweight fluid from the wellbore and/or 

riser to an underbalanced state. The IFR 

required prior approval whenever killweight fluid would be displaced from 

the wellbore, even if the wellbore would 

not be underbalanced. It is not 

necessary to receive approval if the 

wellbore will remain in an overbalanced 

state. 

This Final Rule also revises 

§ 250.456(j)(1) to conform the flow path 

description to that contained in 

§ 250.420(b)(3), and § 250.456(j)(4) to 

clarify that the monitoring procedures 

are required for monitoring the volumes 

and rates of fluids entering and leaving 

the wellbore. 

Approval and Reporting of WellCompletion Operations (§ 250.513) 

In this Final Rule, we added a new 

§ 250.513(b)(4) as a conforming 

procedural amendment requiring the 

operator to submit with the APD or 

APM the BOP descriptions for wellcompletion operations required in the 

new § 250.515. This new paragraph does 

not require information in addition to 

that already required, but will ensure 

information required under the new 

§ 250.515 is submitted with the APD or 

APM. To accommodate the new 

paragraph (b)(4), this Final Rule 

redesignates previous §§ 250.513(b)(4) 

and (b)(5) as §§ 250.513(b)(5) and (b)(6). 

Well-Control Fluids, Equipment, and 

Operations (§ 250.514) 

In response to comments that 

requirements for well-completion and 

drilling should be consistent, this Final 

Rule adds § 250.514(d). This new 

paragraph makes the requirements for 

well-control fluids for well-completions 

consistent with the requirements for 

drilling (§ 250.456(j)). As with the 

drilling requirements, before displacing 

kill-weight fluid from the wellbore and/ 

or riser to an underbalanced state, the 

operator must obtain approval from the 

appropriate BSEE District Manager. To 

obtain this approval, the operator must 

submit with the APD or APM the 

reasons for displacing the kill-weight 

fluid and provide detailed step-by-step 

written procedures describing how this 

will be done. 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 that requires such barriers, 

(2) Tests the operator will conduct to 

ensure integrity of independent barriers, 

(3) BOP procedures the operator will 

use while displacing kill-weight fluids, 

and 

(4) Procedures the operator will use to 

monitor the volumes and rates of fluids 

entering and leaving the wellbore. 

What BOP information must I submit? 

(§ 250.515) 

In response to comments, this Final 

Rule adds a new § 250.515 which 

conforms well-completion BOP 

information requirements to those of the 

drilling and workover subparts, where 

the same type of equipment may be 

used, and similar safety risks exist. To 

accommodate the new section, this 

Final Rule redesignates §§ 250.515 

through 250.530 as §§ 250.516 through 

250.531. 

New § 250.515 requires operators to 

include BOP descriptions in the APM 

for well-completion operations. The 

operator must include a description of 

the BOP system and system components 

and a schematic drawing of the BOP 

system. The operator must also include 

independent third-party verification and 

supporting documentation that show 

the blind-shear rams installed in the 

BOP stack are capable of shearing any 

drill pipe (including workstring and 

tubing) in the hole under maximum 

anticipated surface pressure. The 

documentation must include actual test 

results and calculations of shearing 

capacity of all pipe that will be used in 

the well including correction for MASP. 

The operator must also include, when 

using a subsea BOP stack, independent 

third-party verification that shows: The 

BOP stack is designed for the specific 

equipment on the rig and for the 

specific well design; 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. 

Final § 250.515(e) requires operators 

to include the qualifications of the 

independent third-party performing the 

verifications. The independent thirdparty must be a registered professional 

engineer, or from a technical 

classification society, or a licensed 

professional engineering firm capable of 

providing the verifications required 

under this part. In the qualifications, the 

operator must include evidence that the 

registered professional engineer, or a 

technical classification society, or 

engineering firm the operator is using to 

perform the verification or its 

employees hold appropriate licenses to 

perform the verification in the 

appropriate jurisdiction and evidence to 

demonstrate that the individual, society, 

or firm has the expertise and experience 

necessary to perform the required 

verifications. The operator must ensure 

that an official representative of BSEE 

will have access to the location to 

witness any testing or inspections, and 

verify information submitted to BSEE. 

Prior to any shearing ram tests or 

inspections, the operator must notify the 

BSEE District Manager at least 72 hours 

in advance. This new section makes the 

requirements for submission of BOP 

information for well-completions 

consistent with the requirements in 

subpart D (§§ 250.416(c) through (g)). 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50881 

Blowout Prevention Equipment 

(§ 250.515 in the Interim Final Rule, 

Redesignated as § 250.516 in This Final 

Rule) 

The IFR added the requirements of 

§ 250.442 in subpart D, Oil and Gas 

Drilling Operations, to the requirements 

in § 250.515 for well-completion 

operations using a subsea BOP stack. 

This Final Rule redesignates § 250.515 

in the IFR as § 250.516, but makes no 

further changes to that section. 

Blowout Preventer System Tests, 

Inspections, and Maintenance 

(§ 250.516 in the Interim Final Rule, 

Redesignated as § 250.517 in This Final 

Rule) 

The IFR added § 250.516(d)(8) to 

require tests for ROV intervention 

functions during the stump test and 

§ 250.516(d)(9) to require a function test 

of the autoshear and deadman system. 

This Final Rule redesignates § 250.516 

as § 250.517. 

This Final Rule revises redesignated 

§ 250.517(d)(2) to specify that the time 

lapse between the stump test of a subsea 

BOP system and initial BOP system test 

on the seafloor must not exceed 30 days; 

see the discussion of § 250.449(b) earlier 

in this preamble concerning inclusion of 

the same timeframe in subpart D. 

This Final Rule revises redesignated 

§ 250.517(d)(8) to require the operator to 

test and verify closure of at least one set 

of rams during the initial test on the 

seafloor through an ROV hot stab, and 

that each ROV must be fully compatible 

with the BOP stack intervention panels. 

This Final Rule also adds a requirement 

that when an operator submits the test 

procedures, it must include how it will 

test each ROV function. This Final Rule 

adds a 72-hour notification requirement 

in § 250.517(d)(8)(ii). Operators are 

required to notify BSEE at least 72 hours 

prior to all BOP stump tests and initial 

BOP tests on the seafloor to facilitate 

having a BSEE representative present to 

witness at least one of these tests. 

Changes to redesignated § 250.517(d)(8) 

are consistent with changes to final 

§ 250.449(j) as discussed earlier. 

This Final Rule revises redesignated 

§ 250.517(d)(9) to require the operator to 

test the deadman system and verify 

closure of a set of blind-shear rams 

during the initial test on the seafloor. 

The verification requirement is new and 

is consistent with revised § 250.449(k). 

The IFR revised previous 

§§ 250.516(g) and (h) to expand and 

clarify the requirements for BOP 

inspections and maintenance. This 

Final Rule revises redesignated 

§§ 250.517(g) and (h) to clarify the 

documentation requirements include 

showing how an operator met or 

exceeded specific API RP 53 sections. 

This Final Rule also revises 

redesignated §§ 250.517(g) and (h) to 

clarify the recordkeeping timeframe to 

require that an operator must maintain 

records on the rig for two years from the 

date of creation or for longer if directed 

by BSEE. 

This Final Rule revises redesignated 

§ 250.517(g)(2) to be consistent with the 

subsea BOP system and marine riser 

inspection requirements in subpart D, 

§ 250.446(b). It requires the visual 

inspection of surface BOP systems on a 

daily basis. It requires the visual 

inspection of subsea BOP systems and 

marine risers at least once every three 

days, instead of every day as was 

provided in the IFR. This revision 

reduces the number of required 

inspections of subsea BOP systems and 

marine risers. 

Approval and Reporting of WellWorkover Operations (§ 250.613) 

This Final Rule adds a new 

§ 250.613(b)(3) that requires an operator 

to submit, with its APM, the 

information required in the new 

§ 250.615. This new paragraph was 

added to ensure that BOP descriptions 

for well-workover operations, required 

under the new § 250.615, will be 

submitted with the APM. To 

accommodate the new § 250.613(b)(3), 

this Final Rule redesignates 

§§ 250.613(b)(3) and (b)(4) as 

§§ 250.613(b)(4) and (b)(5). 

Well-Control Fluids, Equipment, and 

Operations (§ 250.614) 

In response to comments, this Final 

Rule adds a new § 250.614(d). This new 

paragraph makes the requirements for 

well-control fluids for well-workover 

operations consistent with the 

requirements in subpart D (§ 250.456(j)). 

As with the drilling requirements, 

before displacing kill-weight fluid from 

the wellbore to an underbalanced state, 

the operator must obtain approval from 

the appropriate BSEE District Manager. 

To obtain this approval, the operator 

must submit, with the APM, the reasons 

for displacing the kill-weight fluid, and 

provide detailed step-by-step written 

procedures describing how this will be 

accomplished. 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 the operator will conduct to 

ensure integrity of independent barriers, 

(3) BOP procedures the operator will 

use while displacing kill-weight fluids, 

and 

(4) Procedures the operator will use to 

monitor the volumes and rates of fluids 

entering and leaving the wellbore. 

What BOP information must I submit? 

(§ 250.615) 

In response to comments, this Final 

Rule adds a new section, § 250.615. This 

new section makes the requirements for 

submission of BOP information for wellcompletions consistent with the 

requirements in subpart D (§§ 250.416(c) 

through (g)). This section requires 

operators to include BOP descriptions 

in the APM for well-completion 

operations. The operator must include a 

description of the BOP system and 

system components, and a schematic 

drawing of the BOP system. The 

operator must also include independent 

third-party verification and supporting 

documentation that show the blindshear rams installed in the BOP stack 

are capable of shearing any drill pipe 

(including workstring and tubing) in the 

hole under maximum anticipated 

surface pressure. The documentation 

must include actual test results and 

calculations of shearing capacity of all 

pipes to be used in the well, including 

correcting for MASP. Operators must 

also include, when using a subsea BOP 

stack, independent third-party 

verification that shows: The BOP stack 

is designed for the specific equipment 

on the rig and for the specific well 

design; the BOP stack has not been 

compromised or damaged from previous 

service; and the BOP stack will operate 

properly in the conditions in which it 

will be used. 

The operators must include 

qualifications of the independent thirdparty. The independent third-party in 

this section must be a registered 

professional engineer, or a technical 

classification society, or a licensed 

professional engineering firm capable of 

providing the verifications required 

under this part. In the qualifications, the 

operator must include evidence that the 

registered professional engineer, or a 

technical classification society, or 

engineering firm the operator is using to 

perform the verification or its 

employees holds appropriate licenses to 

perform the verification in the 

appropriate jurisdiction, and evidence 

to demonstrate that the individual, 

society, or firm has the expertise and 

experience necessary to perform the 

required verifications. The operator 

must ensure that an official 

representative of BSEE will have access 

to the location to witness any testing or 

inspections, and verify information 

submitted to BSEE. Prior to any shearing 

ram tests or inspections, the operator 

must notify the BSEE District Manager 


TKELLEY on DSK3SPTVN1PROD with RULES2
50882 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

at least 72 hours in advance to facilitate 

having a BSEE representative present to 

witness at least one of these tests. 

To accommodate the new section, this 

Final Rule redesignates previous 

§§ 250.615 through 250.619 as 

§§ 250.616 through 250.620. 

Blowout Prevention Equipment 

(§ 250.615 in the Interim Final Rule, 

Redesignated as § 250.616 in Final Rule) 

The IFR added new §§ 250.615(b)(5) 

and (e) that applied the requirements of 

§ 250.442 in subpart D, Oil and Gas 

Drilling Operations, to well-workover 

operations using a subsea BOP stack. 

This Final Rule redesignates this section 

as § 250.616, but does not substantively 

change the IFR. 

Blowout Preventer System Testing, 

Records, and Drills (§ 250.616 in the 

Interim Final Rule IFR, Redesignated as 

§ 250.617 in This Final Rule) 

The IFR added § 250.616(h) to require 

an operator to stump test a subsea BOP 

system before installation. It added 

§ 250.616(h)(1) to require tests for ROV 

intervention functions during the stump 

test, § 250.616(h)(2) to require a function 

test of the autoshear and deadman 

system, and § 250.616(h)(3) to require 

the use of water to stump test a subsea 

BOP system. This Final Rule 

redesignates this section as § 250.617. 

This Final Rule revises redesignated 

§ 250.617(h) to be consistent with final 

§§ 250.449 and 250.517. It requires that 

the initial test on the seafloor must be 

conducted within 30 days of the stump 

test of the subsea BOP stack. This 

subsection does not add a new 

requirement; it just specifies the timing 

of the test. This Final Rule revises 

redesignated § 250.617(h)(1) to require 

the operator to test and verify closure of 

at least one set of rams during the initial 

test on the seafloor through an ROV hot 

stab and that each ROV must be fully 

compatible with the BOP stack 

intervention panels. It also adds that 

when an operator submits the test 

procedures it must include how it will 

test each ROV function. 

The Final Rule also adds 

§ 250.617(h)(1)(ii) which includes a 

notification provision requiring 

operators to notify BSEE at least 72 

hours prior to all BOP stump tests and 

initial BOP tests on the seafloor to 

facilitate having a BSEE representative 

present to witness at least one of these 

tests. This Final Rule revises 

redesignated § 250.617(h)(2) to require 

the operator to test the deadman system 

and verify closure of a set of blind-shear 

rams during the initial test on the 

seafloor. This Final Rule moves the 

contents of redesignated 

§ 250.617(h)(2)(iii) into the general text 

of § 250.617(h). 

What are my BOP inspection and 

maintenance requirements? (§ 250.617 

in the Interim Final Rule, § 250.618 in 

the Final Rule) 

The IFR added § 250.617 to apply the 

requirements of § 250.446 in subpart D, 

Oil and Gas Drilling Operations, to the 

inspections and maintenance 

requirements for well-workover 

operations using a subsea BOP stack. 

This Final Rule redesignates § 250.617 

as § 250.618. This Final Rule revises 

redesignated § 250.618(a) to clarify that 

the documentation requirements 

include showing how an operator met or 

exceeded specific API RP 53 sections. It 

also clarifies the recordkeeping 

timeframe to require records to be 

maintained on the rig for 2 years from 

the date the records are created or for 

longer if directed by BSEE. The previous 

text was confusing. 

This Final Rule also revises 

redesignated §§ 250.618(a)(2) be 

consistent with the subsea BOP system 

and marine riser inspection 

requirements in subpart D, § 250.446(b). 

It requires the visual inspection of 

surface BOP systems on a daily basis. It 

requires the visual inspection of subsea 

BOP systems and marine risers at least 

once every 3 days, instead of every day. 

This revision reduces the number of 

required inspections of the subsea BOP 

system and marine riser. 

Definitions (§ 250.1500) 

In the IFR, BOEMRE added separate 

definitions for the terms deepwater wellcontrol, well servicing and wellcompletion/well-workover. This Final 

Rule makes no further changes to those 

definitions. 

We have clarified the definition of 

well-control to be as consistent as 

possible with recommendations in the 

DWH JIT report. In the Final Rule we 

also clarify that well-control applies to 

abandonment operations. The Final 

Rule provides that 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. Well-control applies to 

drilling, well-completion, wellworkover, abandonment, and wellservicing operations. It includes 

measures, practices, procedures and 

equipment, such as fluid flow 

monitoring, to ensure safe and 

environmentally protective drilling, 

completion, abandonment, and 

workover operations as well as the 

installation, repair, maintenance, and 

operation of surface and subsea wellcontrol equipment. 

Inclusion of this revised definition in 

subpart O will facilitate the 

establishment of minimum training 

standards for persons monitoring and 

maintaining well-control. This new 

definition encompasses anyone who has 

the responsibility for monitoring the 

well and/or maintaining the wellcontrol equipment for well control 

purposes. 

What are my general responsibilities for 

training? (§ 250.1503) 

In the IFR, the operator is required to 

ensure that employees and contract 

personnel are trained in deepwater wellcontrol when conducting operations 

with a subsea BOP stack. They must 

have a comprehensive knowledge of 

deepwater well-control equipment, 

practices, and theory. We did not make 

any changes to this section in the Final 

Rule. 

When must I submit decommissioning 

applications and reports? (§ 250.1704) 

This Final Rule revises § 250.1704(g) 

by adding § 250.1704(g)(1)(ii) to provide 

clarification that when an operator uses 

a BOP for abandonment operations, it 

must include the information required 

under § 250.1705, discussed below. 

What BOP information must I submit? 

(§ 250.1705) 

In response to comment, this Final 

Rule adds § 250.1705. BSEE received a 

comment stating that some BOP 

requirements were omitted in subparts E 

and F that should be included to ensure 

consistency of BOP requirements with 

subpart D. We agree with this comment 

and have made the appropriate changes 

in those subparts. This reasoning has 

also led us to conclude these 

requirements should also be extended to 

subpart Q. The same BOP equipment 

may be used in abandonment operations 

as is used in operations under the other 

subparts. Attendant safety risks are also 

similar and justify imposition of the 

same regulatory oversight in subpart Q 

as that contained in the other subparts. 

Final Rule § 250.1705 requires 

operators to include BOP descriptions 

in the APM for well-completion 

operations. The operator must include a 

description of the BOP system and 

system components and a schematic 

drawing of the BOP system. The 

operator must also include independent 

third-party verification and supporting 

documentation that show the blindshear rams installed in the BOP stack 

are capable of shearing any drill pipe 

(including workstring and tubing) in the 

hole under maximum anticipated 

surface pressure. The documentation 

must include test results and 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50883 

calculations of shearing capacity of all 

pipe to be used in the well, including 

correction for MASP. The operator must 

also include, when using a subsea BOP 

stack, independent third-party 

verification that shows: the BOP stack is 

designed for the specific equipment on 

the rig and for the specific well design; 

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. 

The operators must include 

qualifications of the independent thirdparty. The independent third-party in 

this section must be a registered 

professional engineer, or technical 

classification society, or a licensed 

professional engineering firm capable of 

providing the verifications required 

under this part. In the qualifications, the 

operator must include evidence that the 

registered professional engineer, or a 

technical classification society, or 

engineering firm it is using to perform 

the verifications or its employees hold 

appropriate licenses to perform the 

verification in the appropriate 

jurisdiction, and evidence to 

demonstrate that the individual, society, 

or firm has the expertise and experience 

necessary to perform the required 

verifications. The operator must ensure 

that an official representative of BSEE 

will have access to the location to 

witness any testing or inspections, and 

verify information submitted to BSEE. 

Prior to any shearing ram tests or 

inspections, the operator must notify the 

BSEE District Manager at least 72 hours 

in advance. This new section makes the 

requirements for submission of BOP 

information for well-completions 

consistent with the requirements in 

subpart D (§ 250.416(c) through (g)). 

What are the requirements for blowout 

prevention equipment? (§ 250.1706) 

BSEE received a comment stating that 

BOP requirements were omitted in 

subparts E and F. We agree with this 

comment; it is important for BOP 

requirements to be consistent, regardless 

of the application. We have made the 

appropriate changes in those subparts 

and also have included these 

requirements in subpart Q for 

abandonment operations that use a BOP 

system. In response to the comment, 

this Final Rule adds § 250.1706, which 

also adds consistency for BOP 

requirements between subparts. If the 

operator plans to use a BOP for any well 

abandonment operations, the BOP must 

meet the same requirements as those in 

subpart F, § 250.616. 

What are the requirements for blowout 

preventer system testing, records, and 

drills? (§ 250.1707) 

BSEE received a comment stating that 

BOP requirements were omitted in 

subparts E and F. We agree with this 

comment; it is important for BOP 

requirements to be consistent, regardless 

of the application. We have made the 

appropriate changes in those subparts 

and also have included these 

requirements in subpart Q for 

abandonment operations that use a BOP 

system. Since the new sections are 

added for BOP requirements in subpart 

Q, this Final Rule also adds § 250.1707 

to ensure operators meet the same 

testing and recordkeeping requirements 

as those in subparts D, E, and F. 

What are my BOP inspection and 

maintenance requirements? (§ 250.1708) 

BSEE received a comment stating that 

BOP requirements were omitted in 

subparts E and F. We agree with this 

comment; it is important for BOP 

requirements to be consistent, regardless 

of the application. We have made the 

appropriate changes in those subparts 

and also have included these 

requirements in subpart Q for 

abandonment operations that use a BOP 

system. Since the new sections are 

added for BOP requirements in subpart 

Q, this new section is added to the Final 

Rule to ensure operators maintain and 

inspect the BOP equipment as required 

in subparts D, E, and F. 

What are my well-control fluid 

requirements? (§ 250.1709) 

In response to comments, we added a 

new section in the Final Rule. This new 

section makes the requirements for wellcontrol fluids for well abandonment 

consistent with the requirements for 

drilling (§ 250.456(j)). As with the 

drilling requirements, before displacing 

kill-weight fluid from the wellbore to an 

underbalanced state, the operator must 

obtain approval from the appropriate 

BSEE District Manager. To obtain this 

approval, the operator must submit with 

the APM the reasons for displacing the 

kill-weight fluid and provide detailed 

step-by-step written procedures 

describing how the displacement will be 

accomplished. 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 

the volumes and rates of fluids entering 

and leaving the wellbore. 

What information must I submit before 

I permanently plug a well or zone? 

(§ 250.1712) 

In the IFR, a 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 of 

the United States and have sufficient 

expertise and experience to perform the 

certification. The Registered 

Professional Engineer does not have to 

be licensed for 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 IFR provided that the 

Registered Professional Engineer 

certifies that there will be at least two 

independent tested barriers, including 

one mechanical barrier, across each flow 

path during well abandonment 

activities. The IFR also provided that 

the Registered Professional Engineer 

certify that the plug meets the 

requirements in the table in § 250.1715. 

In response to comments, the 

language in the Final Rule paragraph (g) 

was clarified that the Registered 

Professional Engineer must certify the 

well abandonment design and that all 

applicable plugs meet the requirements 

in the table in § 250.1715. In response 

to comments related to § 250.420(b)(3) 

discussed earlier, the Registered 

Professional Engineer must also certify 

that the design will include two 

independent barriers, one of which 

must be a mechanical barrier, in the 

center wellbore, as described in 

§ 250.420(b)(3). 

How must I permanently plug a well? 

(§ 250.1715) 

The Final Rule adopts a conforming 

change to § 250.1715 by adding 

paragraph (a)(11) which ensures that 

two independent barriers, as described 

in § 250.420(b)(3), will be put in place 

for abandonment if the barriers have 

been removed for production. Both the 

IFR and this Final Rule already require 

certification of the design of such 

barriers in § 250.1712(g), and the 

amendment to § 250.1715 is necessary 

to accompany the certification. 


TKELLEY on DSK3SPTVN1PROD with RULES2
50884 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

If I temporarily abandon a well that I 

plan to re-enter, what must I do? 

(§ 250.1721) 

In the IFR, new paragraph (h) was 

added to require operators to submit 

certification by a Registered Professional 

Engineer of the well abandonment 

design and procedures. 

In response to comments, language in 

paragraph (h) in the Final Rule was 

clarified that the Registered Professional 

Engineer must certify the well 

abandonment design and procedures. 

The Registered Professional Engineer 

must also certify that the design 

includes two independent barriers in 

the center wellbore and all annuli, one 

of which must be a mechanical barrier. 

The text has been modified from the IFR 

to be consistent with the requirements 

of § 250.420(b)(3). 

VI. Compliance Costs 

The IFR contained a table estimating 

compliance costs on a section-bysection basis. Since the IFR was 

published, we have reanalyzed 

compliance costs based on actual 

experience under the rule. In addition, 

this Final Rule modifies various 

provisions of the IFR. The following 

table provides a summary comparison 

between the compliance costs of the IFR 

and this Final Rule. The following table 

demonstrates that the estimated 

compliance costs have decreased by 

approximately 52 million dollars. 

ESTIMATED COMPLIANCE COSTS COMPARISON BETWEEN THE INTERIM FINAL RULE AND THE FINAL RULE

Annual recurring costs IFR 

($ millions) 

Final Rule 

($ millions) Compliance cost change between IFR and Final Rule 

Subsea ROV function testing (drilling) ......................... 102.7 17.1 Estimated time was reduced. BSEE over estimated 

the time required for the subsea tests. 

Subsea ROV function testing (completions/workover/ 

abandonments).

15.5 5.5 Estimated time was reduced. BSEE over estimated 

the time required for the subsea tests. Count of 

abandonment operations added to revised count of 

workover/completions. 

Test casing strings for proper installation (negative 

pressure test).

45.1 12.8 Regulation was changed and the count of actions is 

reduced. BSEE no longer requires a negative pressure test on all intermediate casing strings, only the 

final casing before the subsea BOP is removed. 

Installation of two independent barriers, one of which 

must be a mechanical barrier.

10.3 83.0 Regulation was changed from dual mechanical barriers. A dual float valve no longer meets the definition of a mechanical barrier. The estimated time to 

install the mechanical barrier increased to 12 hours. 

PE certification for well design ..................................... 6.0 3.9 Cost estimate reduced because the large companies 

drilling in shallow water are now assumed to have 

Professional PE available for in-house certification. 

Emergency cost of activated shear rams or LMRP 

disconnect.

2.6 2.6 No change. 

Independent third-party shear certification ................... 1.2 1.2 No change. 

Paperwork Costs taken from PRA tables in IFR & 

Final Rule.

0.0 4.6 Paperwork costs were not included in the IFR benefitcost analysis, but are added to the compliance cost 

for the final rule. 

Total ....................................................................... 183.4 130.7 

VII. Procedural Matters 

Regulatory Planning and Review 

(Executive Orders 12866 and 13563) 

This rulemaking constitutes a 

significant rule as determined by the 

Office of Management and Budget 

(OMB) and is subject to review under 

E.O. 12866. For purposes of this 

analysis, we deem the rulemaking to 

consist of the IFR as modified by this 

Final Rule. 

(1) This rulemaking will have an 

annual effect of $100 million or more on 

the economy. The following discussion 

summarizes a Regulatory Impact 

Analysis (RIA) that is available on 

www.Regulations.gov. Use the keyword/ 

ID ‘‘BSEE–2012–0002’’ to locate the 

docket for this rule. 

BSEE estimates the annual cost of this 

rulemaking to be approximately $131 

million per year. Because of regulatory 

changes in this Final Rule and revised 

cost assumptions, the annual 

compliance cost is reduced from $183 

million estimated in the IFR to $131 

million for the final regulatory impact 

analysis. The quantification of benefits 

is uncertain, but is estimated to be 

represented by the avoided costs of a 

catastrophic spill, which are estimated 

under the stipulated scenario as being 

$16.3 billion per spill avoided and 

annualized at $631 million per year. 

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), we estimate 

the baseline risk of a catastrophic 

blowout to be about once every 26 years. 

Combining the baseline likelihood of 

occurrence with the cost of a 

representative spill implies that the 

expected annualized damage cost absent 

this regulation is $631 million ($16.3 

billion once in 26 years, equally likely 

in any 1 year). To balance the $131 

million annual cost imposed by this 

rulemaking with the expected benefits, 

the reliability of the well-control system 

needs to improve by 21 percent ($131 

million/$631 million). We have found 

no studies that evaluate the degree of 

actual improvement that could be 

expected from dual barriers, negative 

pressure tests, and a seafloor ROV 

function test and no additional 

information was provided during the 

public comment period. However, based 

upon the plausible scenarios that have 

been developed, it is reasonable to 

conclude that this rulemaking will 

reduce the risk of a catastrophic 

blowout spill event such that benefits 

will justify the costs estimated to be 

imposed by the regulation. 

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 rulemaking was 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50885 

conducted using a scenario analysis. 

The benefit-cost 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 DWH event. 

Three new requirements account for 

most of the compliance costs imposed 

by this rulemaking. These are: (1) Use of 

two independent barriers in each 

annular flow path; and in the final 

casing string or liner to prevent 

hydrocarbon flow in the event of cement 

failure; (2) Application of negative 

pressure tests to the production casing 

string for wells drilled with a subsea 

BOP; and (3) Testing time for the ROV 

to close BOP rams after the BOP has 

been installed on the sea floor. BSEE 

estimates that these three requirements 

will impose compliance costs of 

approximately $118 million per year, 

representing 91 percent of the total 

annual compliance costs of $131 million 

associated with this rulemaking. These 

cost estimates were developed based on 

public data sources, BSEE experience, 

and confidential information provided 

by several offshore operators and 

drilling companies. The $131 million 

estimated annual compliance costs are 

29 percent less than the $183 million 

cost estimated previously for the IFR, 

largely reflecting a reduced estimate of 

the time it takes to conduct an ROV 

function test when the BOP is on the 

seafloor and lower negative pressure test 

costs resulting from relaxed testing 

requirements in the IFR. These reduced 

costs are partly offset by the 

requirement that a dual float valve no 

longer meets the criteria for a 

mechanical barrier and inclusion of 

paperwork costs omitted from the 

estimates in the IFR. See table 4 earlier 

in this preamble comparing the IFR 

estimated compliance costs with those 

estimated in this Final Rule. 

On the benefit side, the avoided costs 

for a representative 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 cleanup and restoration 

estimates developed by the Department 

of the Interior, Office of Policy Analysis, 

using damage costs per barrel measures 

found in historical spill data (from all 

sources including pipeline, tanker, and 

shallow water, as well as from 

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 

this 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. 

We believe the compliance cost 

estimate of $131 million is closer to the 

actual cost than the figure used in the 

IFR because of improved information 

gathered since deepwater drilling 

resumed in the GOM in the spring of 

2011. 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) has not been 

revised. The true magnitude of an 

avoided 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 blowout 

leading to a catastrophic oil spill is 

difficult to quantify because of limited 

historical data on catastrophic offshore 

blowouts. 

(2) This final rule will not adversely 

affect competition or State, local, or 

tribal governments or communities. 

(3) This final rule will not create a 

serious inconsistency or otherwise 

interfere with an action taken or 

planned by another agency. 

(4) This 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 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. 

Executive Order 13563 reaffirms the 

principles of E.O. 12866 while calling 

for improvements in the nation’s 

regulatory system to promote 

predictability, to reduce uncertainty, 

and to use the best, most innovative, 

and least burdensome tools for 

achieving regulatory ends. The 

executive order directs agencies to 

consider regulatory approaches that 

reduce burdens and maintain flexibility 

and freedom of choice for the public 

where these approaches are relevant, 

feasible, and consistent with regulatory 

objectives. E.O. 13563 emphasizes 

further that regulations must be based 

on the best available science and that 

the rulemaking process must allow for 

public participation and an open 

exchange of ideas. This final rule has 

been developed in a manner consistent 

with these requirements. 

Regulatory Flexibility Act: Final 

Regulatory Flexibility Analysis 

BSEE has prepared a Final Regulatory 

Flexibility Analysis (FRFA) in 

conjunction with this Final Rule. The 

FRFA is found in Appendix A of the 

Regulatory Impact Analysis (RIA). As 

with the analysis under E.O. 12866, the 

FRFA analyzes the rulemaking, 

consisting of the IFR as modified by this 

Final Rule. The Bureau’s publication of 

the IFR did not include a full Initial 

Regulatory Flexibility Analysis (IRFA) 

pursuant to the Regulatory Flexibility 

Act (5 U.S.C. 603). A supplemental 

IRFA was published on December 23, 

2010 (75 FR 80717) with a 30-day 

comment period which closed on 

January 24, 2011. The changes from the 

IRFA are minor and relate to lower total 

compliance cost estimates for the 

regulation. The revised cost estimates 

are the result of changes to the 

regulatory language from the IFR to this 

Final Rule and improved estimates of 

the costs and the operational timeframes 

required to comply with the regulatory 

provisions. 

This final rule 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. 


TKELLEY on DSK3SPTVN1PROD with RULES2
50886 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

For these NAICS code classifications, a 

small company is one with fewer than 

500 employees. Based on these criteria, 

approximately 65 percent of companies 

operating on the OCS are considered 

small companies. Therefore, BSEE has 

determined that this rulemaking will 

have an impact on a substantial number 

of small entities. 

We estimate that the rulemaking will 

impose a recurring operational cost of 

$131 million each year on operators 

drilling OCS wells. The rulemaking 

affects every new well drilled after 

October 14, 2010; some requirements 

also apply to wells undergoing 

completion, workover, or abandonment 

operations on the OCS. Every operator, 

both large and small, must meet the 

same criteria for these operations 

regardless of company size. However, 

the overwhelming share of the cost 

imposed by the rulemaking will fall on 

the operating companies drilling 

deepwater wells, which are 

predominately the larger companies. We 

estimate that about 81 percent of the 

total costs will be imposed on 

deepwater lessees and operators where 

small businesses only hold 8 percent of 

the leases and drill 12 percent of the 

wells. About 19 percent of the total 

costs will apply to shallow water leases 

where small companies hold 45 percent 

of OCS leases and also drill 45 percent 

of the wells. 

Nonetheless, small companies, as 

both operators and lease-holders, will 

bear meaningful costs under the 

rulemaking. Of the annual $131 million 

in annual cost imposed by the 

rulemaking, we estimate that $12.7 

million will apply to small businesses 

operating in deepwater and $11.2 

million to those operating in shallow 

water. In total, we estimate that $23.9 

million or 18 percent of the 

rulemaking’s cost will be borne by small 

businesses. 

Alternatives to ease impacts on small 

business were considered and are 

discussed in the FRFA. The alternatives 

considered include: different 

compliance requirements for small 

entities, alternative BOP testing 

requirements and periods, performance 

rather than design standards, and 

exemption from regulatory 

requirements. These alternatives are 

being rejected by BSEE for this 

rulemaking because of the overriding 

need to reduce the chance of a 

catastrophic blowout event. It would not 

be 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 final rule is a major rule under 

the Small Business Regulatory 

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

et seq.). As with the preceding analyses, 

this discussion deems the rulemaking to 

consist of the IFR as modified by this 

Final Rule. This rulemaking: 

(a) Will have an annual effect on the 

economy of $100 million or more. This 

rulemaking 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, as 

discussed in the FRFA. 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 $850 thousand to 

each new deepwater well drilled and 

completed with a MODU, $230 

thousand for each new deepwater well 

drilled with a platform rig, and $130 

thousand for each new shallow water 

well. While not an insignificant amount, 

we note this extra recurring cost is 

around 1 percent for most deep and 

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 marginally 

negative, but the size of the impact is 

not expected to materially impact world 

oil markets. The deepwater GOM is an 

oil province and the domestic crude oil 

prices are set by the world oil markets. 

Currently, domestic onshore production 

is increasing and there is sufficient 

spare capacity in OPEC to offset any 

GOM deepwater production decline that 

could occur as a result of this 

rulemaking. 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. 

(c) Will not have significant adverse 

effects on competition, innovation, or 

the ability of U.S.-based enterprises to 

compete with foreign-based enterprises. 

The requirements will apply to all 

entities operating on the OCS. 

(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 offshore domestic energy 

resources from what it otherwise will 

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 this rulemaking for 

offshore wells is expected to yield about 

a 1 percent decrease in productivity. 

(e) Does not make accommodations 

for small business. Not making such 

accommodations avoids 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, and 45 percent of 

shallow water leases. This rulemaking 

will make it more expensive for all 

interest holders in OCS leases, and we 

do not expect a disproportionate impact 

on small businesses. However, the costs 

in this rulemaking 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) May affect small businesses that 

support offshore oil and gas drilling 

operations including service, supply, 

and consulting companies. Because 

there may be a marginal decrease in 

offshore drilling activity due to the 

increased cost and regulatory burden, 

some businesses that support drilling 

operations may experience reduced 

business activity. Some small business 

may therefore decide to focus more on 

shallow water or other oil and gas 

offshore provinces overseas. 

(g) May benefit some small 

businesses. Companies that are involved 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50887 

with inspecting and certifying 

equipment covered by this rulemaking, 

as well as consulting companies 

specializing in safety and offshore 

drilling, could see long-term growth. 

Unfunded Mandates Reform Act of 1995 

This Final Rule will not impose an 

unfunded mandate on State, local, or 

tribal governments or the private sector 

of more than $100 million per year. The 

Final 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 

rulemaking does not have significant 

takings implications. The Final 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 

final rule does not have federalism 

implications. This rulemaking 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 rulemaking will 

not affect that role. A Federalism 

Assessment is not required. 

Civil Justice Reform (E.O. 12988) 

This rulemaking complies with the 

requirements of E.O. 12988. 

Specifically, this rulemaking: 

(a) Meets the criteria of section 3(a) 

requiring that all regulations be 

reviewed to eliminate errors and 

ambiguity and be written to minimize 

litigation; and 

(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 rulemaking and 

determined that it has no substantial 

effects on Federally recognized Indian 

tribes. 

Paperwork Reduction Act (PRA) 

This Final 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.). This rule expands 

existing and adds new regulatory 

requirements under in 30 CFR 250, 

subparts D, E, F, and Q based on 

comments received from the IFR (75 FR 

63346). The OMB approved these 

requirements and assigned OMB Control 

Number 1014–0020, 5,347 hours 

(expiration August 31, 2015). The title 

of the collection of information for this 

Final Rule is 30 CFR 250, Increased 

Safety Measures for Energy 

Development on the Outer Continental 

Shelf. 

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. 

BSEE will protect proprietary 

information according to the Freedom of 

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

implementing regulations (43 CFR 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. 

As discussed earlier in the preamble, 

this final rulemaking is a revision to 

various sections of the 30 CFR 250 

regulations that will amend drilling 

regulations in subparts D, E, F, and Q. 

This includes requirements that will 

implement various safety measures that 

pertain to drilling, well-completion, 

well-workovers, and abandoning/ 

decommissioning 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 Final 

Rule will promote human safety and 

environmental protection. 

Based on comments received from the 

IFR (1010–AD68), this rulemaking adds 

new regulatory requirements and/or 

expands requirements to those already 

approved under 30 CFR 250, subparts D, 

E, F, and Q, as explained in the 

following paragraphs. 

A commenter stated that, where 

applicable, requirements for drilling, 

well work-overs, completions, 

abandonment and/or decommissioning 

should be consistent. We agreed with 

the comment, and to be consistent, 

added new requirements and expanded 

others in subparts D, E, F, and Q. 

For example, in § 250.449(j), when 

operators submit their test procedures 

for approval, they must now include 

how they will test each ROV. We 

consider the currently approved burden 

for this requirement to be adequate to 

include this expanded new information 

collection (IC) because an operator 

doing due diligence will have already 

addressed this requirement in 

developing its test procedures; the 

burden will be to submit the procedures 

to BSEE. 

Also, as a logical outgrowth of the IFR 

and to respond to the comment to make 

the BOP requirements consistent across 

various subparts of the BSEE 

regulations, we added the BOP 

requirements to subpart Q. 

Please note that between the IFR and 

the Final Rule, as discussed previously, 

the BSEE was created. Upon creation of 

the new agency, the OMB-approved 

collections of information that related to 

BSEE were transferred from the 1010 to 

the 1014 numbering system. Also the 

collection of information pertaining to 

30 CFR 250, subpart D, came up for 

OMB renewal. As per the PRA process, 

we revised the estimated burdens, per 

consultations with industry, which 

included the new requirements of the 

IFR. Therefore, the subpart D collection 

that was submitted to, and approved by, 

OMB included the hour burdens that 

pertained to the IFR. Accordingly, this 

analysis only addresses the IC burden of 

the new and/or expanded regulatory 

requirements imposed by this final rule. 

The current regulations on Oil and 

Gas Drilling Operations and associated 

IC are located in 30 CFR 250, subpart D. 

The OMB approved the IC burden of the 

current subpart D regulations under 

control number 1014–0018 (expiration 

10/31/2014). This Final Rule adds 

additional regulatory requirements that 

pertain to subsea and surface BOPs, well 

casing and cementing, secondary 

intervention, unplanned disconnects, 

recordkeeping, well-completion, and 

well plugging (+363 burden hours). 

The current regulations on Oil and 

Gas Well-Completion Operations and 

associated IC are located in 30 CFR 250, 

subpart E. The OMB approved the IC 

burden of the current subpart E 

regulations under control number 1014– 

0004 (expiration 1/31/2014). This Final 

Rule adds new regulatory requirements 

to this subpart that pertain to subsea 

and surface BOPs, secondary 

intervention, and well-completions 

(+311 burden hours). 

The current regulations on Oil and 

Gas Well-Workover Operations and 

associated IC are located in 30 CFR 250, 

subpart F. The OMB approved the IC 

burden of the current subpart F 

regulations under control number 1014– 

0001 (expiration 1/31/2014). This Final 

Rule adds new regulatory requirements 

to this subpart that pertain to subsea 

and surface BOPs, secondary 

intervention, unplanned disconnects, 

and well-workers (+776 burden hours). 

The current regulations on 

Decommissioning Activities and 

associated IC are located in 30 CFR 250, 


TKELLEY on DSK3SPTVN1PROD with RULES2
50888 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

subpart Q. The OMB approved the IC 

burden of the current subpart Q 

regulations under control number 1014– 

0010 (expiration 12/31/2013). This Final 

Rule adds new regulatory requirements 

that refer to information collection 

requirements that pertain to subsea and 

surface BOPs, secondary intervention, 

unplanned disconnects and well 

workers during the abandonment 

decommissioning process (+3,897 

burden hours). 

We note that while Form BSEE–0124, 

Application for Permit to Modify is 

housed in 30 CFR 250, subpart D (1014– 

0018), this form is used in multiple 

subparts for multiple purposes. The 

form is also used in 30 CFR 250, 

subparts E, F, P, and Q—WellCompletions, Well-Workovers, Sulphur 

Operations, and for Abandonment/ 

Decommissioning functions. While the 

requirement may be stated as ‘submit 

with your APM’, the paperwork burden 

to fill out the form is in subpart D, while 

the actual APM submittal of 

supplementary and supporting 

documents and/or information that 

pertains to the job function is in the 

specific subpart. 

When this rule becomes effective, 

BSEE will incorporate the 30 CFR 250, 

subparts D, E, F, and Q paperwork 

burdens into their respective primary 

collections: 1014–0018, 1014–0004, 

1014–0001, and 1014–0010 respectively. 

The following table provides a 

breakdown of the new burdens. 

BURDEN TABLE

Citation 

30 CFR 250 Reporting & recordkeeping requirement Hour burden 

Average number of annual 

responses 

Annual burden 

hours 

(rounded) 

Subpart D 

410–418; 420(a)(6); 423(b)(3), (c)(3); 

449(j), (k)(1); 456(j) plus various 

references in subparts A, B, D, E, 

H, P, Q.

Apply for permit to drill APD (Form BSEE–0123) that includes any/all 

supporting documentation/evidence [including, but not limited to, test 

results, calculations, pressure integrity, verifications, procedures, criteria, qualifications, etc.] and requests for various approvals required 

in subpart D (including §§ 250.424, 425, 427, 428, 432, 442(c), 447, 

448(c), 451(g), 456(a)(3), (f), 460, 490(c)) and submitted via the form; 

upon request, make available to BSEE.

Burden covered under 1014– 

0018 

0 

449(j); 460; 465; 514(d); 515; 

517(d)(8–9); 614(d); 615; 617(h)(1– 

2); 1704(g); 1707(d), (h)(1–2); 

1709; 1712; 1721(h).

Provide revised plans and the additional supporting information required 

by the cited regulations [test results, calculations, verifications, procedures, criteria, qualifications, etc.] when you submit an Application for 

Permit to Modify (APM) (Form BSEE–0124) to BSEE for approval.

Burden covered under 1014– 

0018 

0 

416(g)(2) ............................................. Provide 72 hour advance notice of location of shearing ram tests or inspections; allow BSEE access to witness testing, inspections and information verification.Burden covered under 1014– 

0018 

0 

416(g)(2) ............................................. Submit evidence that demonstrates that the Registered Professional Engineer/firm has the expertise and experience necessary to perform the 

verification(s); allow BSEE access to witness testing; verify info submitted to BSEE.

0.25 700 submittals 175 

420(b)(3) ............................................. Submit documentation of two independent barriers after installation with 

your EOR.

Burden covered under 1014– 

0018 

0 

420(b)(3) ............................................. Request approval for alternative options to installing barriers ................... 0.25 25 requests 7 

423(a) ................................................. Request alternative approval for other pressure casing test pressures .... Burden covered under 1010– 

0114 

0 

423(a) ................................................. Request and receive approval from BSEE District Manager for repair ..... 0.5 88 requests 44 

423(b)(3), (c)(4) .................................. Document pressure casing test results and make available to BSEE 

upon request.

Burden covered under 1014– 

0018 

0 

423(c)(5) ............................................. Immediately contact BSEE District Manager when problem corrected 

due to failed negative pressure test; submit a description of corrected 

action taken; and receive approval from BSEE District Manager to 

retest.

1 14 notifications 14 

423(c)(8) ............................................. Submit documentation of successful negative pressure test in the EOR 

(Form BSEE–0125).

2 45 submittals 90 

442(f)(3) .............................................. Demonstrate that your secondary control system will function properly ... 5 1 validation 5 

446(a) ................................................. Document BOP maintenance and inspection procedures used; record 

results of BOP inspections and maintenance actions; maintain records 

for 2 years or longer if directed by BSEE; make available to BSEE 

upon request.

Burden covered under 1014– 

0018 

0 

449(j)(2) .............................................. Notify BSEE District Manager at least 72 hours prior to stump/initial test 

on seafloor.

0.25 110 notifications 28 

449(j)(3) * ............................................ Document all ROV intervention function test results including how you 

test each ROV functions; make available to BSEE upon request.

Burden covered under 1014– 

0018 

0 

456(j) ................................................... Request approval from the BSEE District Manager to displace kill-weight 

fluids to an underbalanced state; submit detailed written procedures 

with your APD/APM.

Burden covered under 1014– 

0018 

0 

Subtotal D .................................... ..................................................................................................................... 983 responses 363 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50889 

BURDEN TABLE—Continued 

Citation 

30 CFR 250 Reporting & recordkeeping requirement Hour burden 

Average number of annual 

responses 

Annual burden 

hours 

(rounded) 

Subpart E 

514(d) ................................................. Request approval from the BSEE District Manager to displace kill-weight 

fluids to an underbalanced state; submit detailed written procedures 

with your APM.

2 60 requests 120 

515 ...................................................... Submit a description of your BOP and its components; schematic drawings; independent third-party verification and all supporting information 

(evidence showing appropriate licenses, has expertise/experience 

necessary to perform required verifications, etc) with your APM.

15 12 submittals 180 

515(e)(2)(ii) ......................................... Allow BSEE access to witness testing, inspections, and information 

verification. Notify BSEE District Manager at least 72 hours prior to 

shearing ram tests.

0.25 12 notifications 3 

517(d)(8)* ............................................ Function test ROV interventions on your subsea BOP stack; document 

all test results, including how you test each ROV function; submit procedures with your APM for BSEE District Manager approval; make 

available to BSEE upon request.

Burden covered under 1014– 

0004 

0 

517(d)(8)(ii) ......................................... Notify BSEE District Manager at least 72 hours prior to stump/initial test 

on seafloor.

0.25 32 notifications 8 

517(d)(9) ............................................. Document all autoshear and deadman test results and submit test procedures with your APM for BSEE Manager approval; make available 

to BSEE upon request.

Burden covered under 1014– 

0004 

0 

517(g)(l) .............................................. Document BOP inspection procedures used; record results of BOP inspection actions; maintain records for 2 years or longer if directed by 

BSEE; make available to BSEE upon request.

Burden covered under 1014– 

0004 

0 

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

0114 

0 

517(h) ................................................. Document the procedures used for BOP maintenance/quality management; record results; maintain records for 2 years or longer if directed 

by BSEE; make available to BSEE upon request.

Burden covered under 1014– 

0004 

0 

Subtotal E .................................... ..................................................................................................................... 116 responses 311 

Subpart F 

614(d) ................................................. Request approval from the BSEE District Manager to displace kill-weight 

fluids to an underbalanced state; submit detailed written procedures 

with your APM.

2 80 requests 160 

615 ...................................................... Submit a description of your BOP and its components; schematic drawings; independent third-party verification and all supporting information 

(evidence showing appropriate licenses, has expertise/experience 

necessary to perform required verifications, etc) with your APM.

15 40 submittals 600 

615(e)(2)(ii) ......................................... Allow BSEE access to witness testing, inspections, and information 

verification. Notify BSEE District Manager at least 72 hours prior to 

shearing ram tests.

0.25 12 notifications 5 

617(h)(l) * ............................................ Document all test results of your ROV intervention functions including 

how you test each ROV function; submit test procedures with your 

APM for BSEE District Manager approval; make available to BSEE 

upon request.

Burden covered under 1014– 

0001 

0 

617(h)(1)(ii) ......................................... Notify BSEE District Manager at least 72 hours prior to stump/initial test 

on seafloor.

0.25 44 notifications 11 

617(h)(2) * ........................................... Document all autoshear and deadman test results; submit test procedures with your APM for BSEE District Manager approval; make available to BSEE upon request.Burden covered under 1014– 

0001 

0 

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

maintain records for 2 years or longer if directed by BSEE; make 

available to BSEE upon request.

Burden covered under 1014– 

0001 

0 

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

0114 

0 

618(b) ................................................. Document the procedures used for BOP maintenance; record results; 

maintain records for 2 years or longer if directed by BSEE; make 

available to BSEE upon request.

Burden covered under 1014– 

0001 

0 

Subtotal F .................................... ..................................................................................................................... 176 responses 776 

Subpart Q 

1705 .................................................... Submit a description of your BOP and its components; schematic drawings; independent third-party verification and all supporting information 

(evidence showing appropriate licenses, has expertise/experience 

necessary to perform required verifications, etc) with your APM.

15 200 submittals 3,000 

1705(e)(2)(ii) ....................................... Allow BSEE access to witness testing, inspections, and information 

verification. Notify BSEE District Manager at least 72 hours prior to 

shearing ram tests.

0.25 12 submittals 3 


TKELLEY on DSK3SPTVN1PROD with RULES2
50890 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

BURDEN TABLE—Continued 

Citation 

30 CFR 250 Reporting & recordkeeping requirement Hour burden 

Average number of annual 

responses 

Annual burden 

hours 

(rounded) 

1706(a) ............................................... Request approval of well abandonment operations; procedures indicating how the annular preventer will be utilized and how pressure 

limitations will be applied during each mode of pressure control, with 

your APM.

0.25 200 requests 50 

1706(f)(4) ............................................ Request approval of the BSEE District Manager to conduct operations 

without downhole check values; describe procedures/equipment in 

APM.

1 50 requests 50 

1707(a)(2) ........................................... Request approval from BSEE District Manager to test annular BOP less 

than 70 percent.

0.25 6 requests 2 

1707(b)(2) ........................................... State reason for postponing test in operations logs .................................. 0.25 30 reasons 8 

1707(b)(2) ........................................... Request approval from BSEE District Manager for alternate test frequencies if condition/BOP warrant.0.25 5 requests 2 

1707(f) ................................................ Request alternative method to record test pressures ................................ 0.25 25 requests 7 

1707(f) ................................................ Record test pressures during BOP and coiled tubing on a pressure chart 

or w/digital recorder; certify charts are correct.

1 200 records/ 

certifications 

200 

1707(g) ............................................... Record or reference in operations log all pertinent information listed in

this requirement; make all documents pertaining to BOP tests, actuations and inspections available for BSEE review at facility for duration of well abandonment activity; retain all records for 2 years at a location conveniently available for the BSEE District Manager.

0.5 200 records 100 

1707(h)(1) ........................................... Submit test procedures with your APM for BSEE District Manager approval.1 50 submittals 50 

1707(h)(1)(ii) ....................................... Document all ROV intervention test results; make available to BSEE 

upon request.

0.5 50 records 25 

1707(h)(2)(ii) ....................................... Document all autoshear and deadman function test results; make available to BSEE upon request.0.25 50 records 13 

1708(a), (b) ......................................... Document BOP inspection and maintenance procedures used; record 

results of BOP inspections and maintenance actions; maintain records 

for 2 years or longer if directed by BSEE; make available to BSEE 

upon request.

1 25 records 25 

1708(a) ............................................... Request alternative method to inspect marine risers ................................ 0.25 5 requests 2 

1709 .................................................... Request approval from the BSEE District Manager to displace kill-weight

fluids in an unbalanced state; submit detailed written procedures with 

your APM.

2 80 requests 160 

1712(g); 1721(h) ................................. Submit with your APM, Registered Professional Engineer certification .... Burden covered under 1014– 

0018 

0 

1712(g)*; 1721(h) * ............................. Submit evidence from the Registered Professional Engineer/firm of the 

well abandonment design and procedures; plugs in the annuli meet 

requirements of § 250.1715; 2 independent barriers etc; has the expertise and experience necessary to perform the verification(s), submit 

with the APM.

1 200 200 

Total Q ......................................... ..................................................................................................................... 1,388 responses 3,897 

Grand Total .......................... ..................................................................................................................... 2,663 Responses 5,347 

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 Safety and 

Environmental Enforcement; 

Regulations Development Branch; Mail 

Stop HE–3314; 381 Elden Street; 

Herndon, Virginia 20170–4817. 

National Environmental Policy Act of 

1969 

We have prepared a supplemental 

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 (FONSI). A 

copy of the FONSI and Supplemental 

Environmental Assessment can be 

viewed at www.Regulations.gov (use the 

keyword/ID ‘‘BSEE–2012–0002’’). 

Data Quality Act 

In developing this rulemaking, 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 rulemaking is a significant rule 

and is subject to review by the Office of 

Management and Budget under E.O. 

12866. This rulemaking 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 marginally slow 

exploration and development 

operations. We estimate an average 

delay of 1 day and cost of $820 

thousand 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 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50891 

imposed on new drilling by this 

rulemaking are very small (1 percent) 

relative to the cost of drilling an OCS 

well. In view of the high risk-reward 

associated with deepwater exploration 

in general, we do not expect this small 

regulatory surcharge from this 

rulemaking to result in meaningful 

reduction in discoveries. Thus, we 

expect the net change in supply 

associated with this rulemaking will 

cause only a very 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. 

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: August 9, 2012. 

Ned Farquhar, 

Deputy Assistant Secretary—Land and 

Minerals Management. 

For the reasons stated in the 

preamble, the Bureau of Safety and 

Environmental Enforcement (BSEE) is 

amending 30 CFR part 250 as follows: 

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: 30 U.S.C. 1751, 31 U.S.C. 9701, 

43 U.S.C. 1334. 

■ 2. In part 250, revise all references to 

‘‘glory hole’’ to read ‘‘well cellar’’. 

■ 3. Amend § 250.125(a), by revising 

entries (8) and (9) in the table to read 

as follows: 

§ 250.125 Service fees. 

(a) * * * 

Service—processing of the following Fee amount 30 CFR citation 

*******

(8) Application for Permit to Drill (APD; Form 

BSEE–0123).

$1,959 for initial applications only; no fee for 

revisions.

§ 250.410(d); § 250.513(b); § 250.1617(a). 

(9) Application for Permit to Modify (APM; 

Form BSEE–0124).

$116 .................................................................. § 250.465(b); § 250.513(b); § 250.613(b); 

§ 250.1618(a); § 250.1704(g). 

* * * * * * * 

* * * * * 

■ 4. Amend § 250.198 by revising 

paragraphs (a)(3), (h)(63), and (h)(78) 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 the section 

which incorporates the document by 

reference 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. 

* * * * * 

(h) * * * 

(63) API RP 53, Recommended 

Practices for Blowout Prevention 

Equipment Systems for Drilling Wells, 

Third Edition, March 1997; reaffirmed 

September 2004; incorporated by 

reference at §§ 250.442, 250.446, 

250.517, 250.618, and 250.1708, 

* * * * * 

(78) API Standard 65—Part 2, 

Isolating Potential Flow Zones During 

Well Construction; Second Edition, 

December 2010; incorporated by 

reference at § 250.415(f). 

* * * * * 

■ 5. Amend § 250.415 by revising 

paragraphs (f) to read as follows: 

§ 250.415 What must my casing and 

cementing programs include? 

* * * * * 

(f) A written description of how you 

evaluated the best practices included in 

API Standard 65—Part 2, Isolating 

Potential Flow Zones During Well 

Construction, Second Edition (as 

incorporated by reference in § 250.198). 

Your written description must identify 

the mechanical barriers and cementing 

practices you will use for each casing 

string (reference API Standard 65—Part 

2, Sections 4 and 5). 

■ 6. Amend § 250.416 by revising 

paragraphs (e), (f), and (g) to read as 

follows: 

§ 250.416 What must I include in the 

diverter and BOP descriptions? 

* * * * * 

(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 

(including workstring and tubing) in the 

hole under maximum anticipated 

surface pressure. The documentation 

must include actual shearing and 

subsequent pressure integrity test 

results for the most rigid pipe to be used 

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 

or surface BOP stack on a floating 

facility, 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 

this section must be a technical 

classification society, or a licensed 

professional engineering firm, or a 

registered professional engineer capable 

of providing the verifications required 

under this part. 

(2) You must: 

(i) Include evidence that the 

registered professional engineer, or a 

technical classification society, or 

engineering firm you are using or its 

employees hold appropriate licenses to 

perform the verification in the 

appropriate jurisdiction, and evidence 

to demonstrate that the individual, 

society, or firm has the expertise and 

experience necessary to perform the 

required verifications. 


TKELLEY on DSK3SPTVN1PROD with RULES2
50892 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

(ii) Ensure that an official 

representative of BSEE will have access 

to the location to witness any testing or 

inspections, and verify information 

submitted to BSEE. Prior to any shearing 

ram tests or inspections, you must 

notify the BSEE District Manager at least 

72 hours in advance. 

■ 7. Amend § 250.418 by revising 

paragraphs (g) 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 below the mudline or 

displace some cement to facilitate 

casing removal upon well abandonment; 

* * * * * 

(i) Descriptions of qualifications 

required by § 250.416(g) of the 

independent third-party; and 

* * * * * 

■ 8. Amend § 250.420 by revising 

paragraphs (a)(6) and (b)(3) to read as 

follows: 

§ 250.420 What well casing and cementing 

requirements must I meet? 

* * * * * 

(a) * * * 

(6)(i) Include a certification signed by 

a registered professional engineer that 

the casing and cementing design is 

appropriate for the purpose for which it 

is intended under expected wellbore 

conditions, and is sufficient to satisfy 

the tests and requirements of this 

section and § 250.423. Submit this 

certification with your APD (Form 

BSEE–0123). 

(ii) You must have the registered 

professional engineer involved in the 

casing and cementing design process. 

(iii) The registered professional 

engineer must be registered in a state of 

the United States and have sufficient 

expertise and experience to perform the 

certification. 

(b) * * * 

(3) On all wells that use subsea BOP 

stacks, you must include two 

independent barriers, including one 

mechanical barrier, in each annular flow 

path (examples of barriers include, but 

are not limited to, primary cement job 

and seal assembly). For the final casing 

string (or liner if it is your final string), 

you must install one mechanical barrier 

in addition to cement to prevent flow in 

the event of a failure in the cement. A 

dual float valve, by itself, is not 

considered a mechanical barrier. These 

barriers cannot be modified prior to or 

during completion or abandonment 

operations. The BSEE District Manager 

may approve alternative options under 

§ 250.141. You must submit 

documentation of this installation to 

BSEE in the End-of-Operations Report 

(Form BSEE–0125). 

* * * * * 

■ 9. 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 investigate the cause and receive 

approval from the appropriate BSEE 

District Manager for the repair to resolve 

the problem ensuring that the casing 

will provide a proper seal. The BSEE 

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 in the subsea 

wellhead or liner in the liner hanger. 

(1) You must ensure that the latching 

mechanisms or lock down mechanisms 

are engaged upon installation of each 

casing string. 

(2) If you run a liner that has a 

latching mechanism or lock down 

mechanism, you must ensure that the 

latching mechanisms or lock down 

mechanisms are engaged upon 

installation of the liner. 

(3) 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. 

(i) You must submit for approval with 

your APD, test procedures and criteria 

for a successful test. 

(ii) You must document all your test 

results and make them available to 

BSEE upon request. 

(c) You must perform a negative 

pressure test on all wells that use a 

subsea BOP stack or wells with mudline 

suspension systems. The BSEE District 

Manager may require you to perform 

additional negative pressure tests on 

other casing strings or liners (e.g., 

intermediate casing string or liner) or on 

wells with a surface BOP stack. 

(1) You must perform a negative 

pressure test on your final casing string 

or liner. 

(2) You must perform a negative test 

prior to unlatching the BOP at any point 

in the well. The negative test must be 

performed on those components, at a 

minimum, that will be exposed to the 

negative differential pressure that will 

occur when the BOP is disconnected. 

(3) You must submit for approval with 

your APD, test procedures and criteria 

for a successful test. If any of your test 

procedures or criteria for a successful 

test change, you must submit for 

approval the changes in a revised APD 

or APM. 

(4) You must document all your test 

results and make them available to 

BSEE upon request. 

(5) If you have any indication of a 

failed negative pressure test, such as, 

but not limited to pressure buildup or 

observed flow, you must immediately 

investigate the cause. If your 

investigation confirms that a failure 

occurred during the negative pressure 

test, you must: 

(i) Correct the problem and 

immediately contact the appropriate 

BSEE District Manager. 

(ii) Submit a description of the 

corrective action taken and you must 

receive approval from the appropriate 

BSEE District Manager for the retest. 

(6) You must have two barriers in 

place, as required in § 250.420(b)(3), 

prior to performing the negative 

pressure test. 

(7) You must include documentation 

of the successful negative pressure test 

in the End-of-Operations Report (Form 

BSEE–0125). 

■ 10. Amend § 250.428 by revising 

paragraph (c) to read as follows: 

§ 250.428 What must I do in certain 

cementing and casing situations? 

* * * * * 

If you encounter the following situation . . . Then you must . . . 

*******

(c) Have indication of inadequate cement job (such as, but not limited 

to, lost returns, cement channeling, gas cut mud, or failure of equipment).

(1) Run a temperature survey; 

(2) Run a cement evaluation log; or 

(3) Use a combination of these techniques. 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50893 

If you encounter the following situation . . . Then you must . . . 

*******

■ 11. Amend § 250.442 by removing 

paragraph (l) and revising paragraphs 

(a), (e), and (f) to read as follows: 

§ 250.442 What are the requirements for a 

subsea BOP system? 

* * * * * 

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 (including 

workstring and tubing) in the hole under maximum anticipated surface pressures. 

* * * * * * * 

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

on a continuous basis once BOP deployment has been initiated from 

the rig until recovered to the surface. 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. 

(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, at a minimum, one set of blind-shear rams. This is considered a ‘‘rapid discharge’’ system. 

(2) Deadman System means a safety system that is designed to automatically close, at a minimum, one set of blind-shear rams 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 as a secondary control system. If you intend to install an acoustic control system, you must 

demonstrate to BSEE as part of the information submitted under 

§ 250.416 that the acoustic system will function in the proposed environment and conditions. 

*******

■ 12. Amend § 250.443 by revising 

paragraph (g) to read as follows: 

§ 250.443 What associated systems and 

related equipment must all BOP systems 

include? 

* * * * * 

(g) A wellhead assembly with a rated 

working pressure that exceeds the 

maximum anticipated wellhead 

pressure. 

■ 13. 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 how you met or 

exceeded 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, 

record the results of your BOP 

inspections and maintenance actions, 

and make the records available to BSEE 

upon request. You must maintain your 

records on the rig for 2 years from the 

date the records are created, or for a 

longer period if directed by BSEE; 

* * * * * 

■ 14. Amend § 250.449 by revising 

paragraphs (b), (j), and (k) to read as 

follows: 

§ 250.449 What additional BOP testing 

requirements must I meet? 

* * * * * 

(b) Stump test a subsea BOP system 

before installation. You must use water 

to conduct this test. You may use 

drilling fluids to conduct subsequent 

tests of a subsea BOP system. You must 

perform the initial subsea BOP test on 

the seafloor within 30 days of the stump 

test. 

* * * * * 

(j) Test all ROV intervention functions 

on your subsea BOP stack during the 

stump test. Each ROV must be fully 

compatible with the BOP stack ROV 

intervention panels. You must also test 

and verify closure of at least one set of 

rams during the initial test on the 

seafloor through an ROV hot stab. You 

must submit test procedures, including 

how you will test each ROV 

intervention function, with your APD or 

APM for BSEE 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, one set of blind-shear rams, and 

unlatching the Lower Marine Riser 

Package (LMRP); 

(2) Notify the appropriate BSEE 

District Manager a minimum of 72 hours 

prior to the stump test and initial test on 

the seafloor; and 


TKELLEY on DSK3SPTVN1PROD with RULES2
50894 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

(3) Document all your test results and 

make them available to BSEE 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 and verify 

closure of at least one set of blind-shear 

rams during the initial test on the 

seafloor. When you conduct the initial 

deadman system test on the seafloor you 

must ensure the well is secure and, if 

hydrocarbons have been present, 

appropriate barriers are in place to 

isolate hydrocarbons from the wellhead. 

You must also have an ROV on bottom 

during the test. 

(1) You must submit test procedures 

with your APD or APM for District 

Manager approval. The procedures for 

these function tests must include 

documentation of the controls and 

circuitry of the system utilized during 

each test. The procedure must also 

describe how the ROV will be utilized 

during this operation. 

(2) You must document all your test 

results and make them available to 

BSEE upon request. 

■ 15. Amend § 250.451 by adding 

paragraph (j) 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 . . . 

*******

(j) Need to remove the BOP stack ........................................................... Have a minimum of two barriers in place prior to BOP removal. The 

BSEE District Manager may require additional barriers. 

■ 16. Amend § 250.456 by revising 

paragraph (j) to read as follows: 

§ 250.456 What safe practices must the 

drilling fluid program follow? 

* * * * * 

(j) Before you displace kill-weight 

fluid from the wellbore and/or riser to 

an underbalanced state, you must obtain 

approval from the BSEE District 

Manager. To obtain approval, you must 

submit with your APD or APM your 

reasons for displacing the kill-weight 

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, as described in § 250.420(b)(3), 

that are in place for each flow path that 

requires such barriers, 

(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 

the volumes and rates of fluids entering 

and leaving the wellbore; and 

* * * * * 

■ 17. Amend § 250.513 by: 

■ a. Redesignating paragraphs (b)(4) 

through (b)(5) as (b)(5) through (b)(6), 

and 

■ b. Adding a new paragraph (b)(4) to 

read as follows: 

§ 250.513 Approval and reporting of wellcompletion operations. 

* * * * * 

(b) * * * 

(4) All applicable information 

required in § 250.515. 

* * * * * 

■ 18. Amend § 250.514 by adding 

paragraph (d) to read as follows: 

§ 250.514 Well-control fluids, equipment, 

and operations. 

* * * * * 

(d) Before you displace kill-weight 

fluid from the wellbore and/or riser to 

an underbalanced state, you must obtain 

approval from the BSEE District 

Manager. To obtain approval, you must 

submit with your APM your reasons for 

displacing the kill-weight fluid and 

provide detailed step-by-step written 

procedures describing how you will 

safely displace these fluids. The step-bystep displacement procedures must 

address the following: 

(1) Number and type of independent 

barriers, as described in § 250.420(b)(3), 

that are in place for each flow path that 

requires such barriers, 

(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 

the volumes and rates of fluids entering 

and leaving the wellbore. 

■ 19. Redesignate §§ 250.515 through 

250.530 as §§ 250.516 through 250.531. 

■ 20. Add new § 250.515 to read as 

follows: 

§ 250.515 What BOP information must I 

submit? 

For completion operations, your APM 

must include the following BOP 

descriptions: 

(a) A description of the BOP system 

and system components, including 

pressure ratings of BOP equipment and 

proposed BOP test pressures; 

(b) 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; 

(c) Independent third-party 

verification and supporting 

documentation that show the blindshear rams installed in the BOP stack 

are capable of shearing any drill pipe 

(including workstring and tubing) in the 

hole under maximum anticipated 

surface pressure. The documentation 

must include actual shearing and 

subsequent pressure integrity test 

results for the most rigid pipe to be 

used, and calculations of shearing 

capacity of all pipe to be used in the 

well including correction for maximum 

anticipated surface pressure; 

(d) 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 

(e) The qualifications of the 

independent third-party referenced in 

paragraphs (c) and (d) of this section: 

(1) The independent third-party in 

this section must be a technical 

classification society, or a licensed 

professional engineering firm, or a 

registered professional engineer capable 

of providing the verifications required 

under this part. 

(2) You must: 

(i) Include evidence that the 

registered professional engineer, or a 

technical classification society, or 

engineering firm you are using or its 

employees hold appropriate licenses to 

perform the verification in the 

appropriate jurisdiction, and evidence 

to demonstrate that the individual, 

society, or firm has the expertise and 

experience necessary to perform the 

required verifications; and 

(ii) Ensure that an official 

representative of BSEE will have access 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50895 

to the location to witness any testing or 

inspections, and verify information 

submitted to BSEE. Prior to any shearing 

ram tests or inspections, you must 

notify the BSEE District Manager at least 

72 hours in advance. 

■ 21. Amend newly redesignated 

§ 250.517 by revising paragraphs (d)(2), 

(d)(8), (d)(9), (g), and (h) to read as 

follows: 

§ 250.517 Blowout preventer system tests, 

inspections, and maintenance. 

* * * * * 

(d) * * * 

(2) Stump test a subsea BOP system 

before installation. You must use water 

to conduct this test. You may use 

drilling or completion fluids to conduct 

subsequent tests of a subsea BOP 

system. You must perform the initial 

subsea BOP test on the seafloor within 

30 days of the stump test. 

* * * * * 

(8) Test all ROV intervention 

functions on your subsea BOP stack 

during the stump test. Each ROV must 

be fully compatible with the BOP stack 

ROV intervention panels. You must also 

test and verify closure of at least one set 

of rams during the initial test on the 

seafloor through an ROV hot stab. You 

must submit test procedures, including 

how you will test each ROV function, 

with your APM for BSEE 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, one set of blind-shear rams, and 

unlatching the LMRP; 

(ii) Notify the appropriate BSEE 

District Manager a minimum of 72 hours 

prior to the stump test and initial test on 

the seafloor; 

(iii) Document all your test results 

and make them available to BSEE 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 and verify 

closure of at least one set of blind-shear 

rams during the initial test on the 

seafloor. When you conduct the initial 

deadman system test on the seafloor you 

must ensure the well is secure and, if 

hydrocarbons have been present, 

appropriate barriers are in place to 

isolate hydrocarbons from the wellhead. 

You must also have an ROV on bottom 

during the test. You must: 

(i) Submit test procedures with your 

APM for BSEE District Manager 

approval. The procedures for these 

function tests must include 

documentation of the controls and 

circuitry of the system utilized during 

each test. The procedure must also 

describe how the ROV will be utilized 

during this operation. 

(ii) Document all your test results and 

make them available to BSEE 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 how you met or 

exceeded the provisions of Sections 

17.10 and 18.10 described in API RP 53, 

the procedures used, record the results, 

and make the records available to BSEE 

upon request. You must maintain your 

records on the rig for 2 years from the 

date the records are created, or for a 

longer period if directed by BSEE. 

(2) You must visually inspect your 

surface BOP system on a daily basis. 

You must visually inspect your subsea 

BOP system and marine riser at least 

once every 3 days if weather and sea 

conditions permit. You may use 

television cameras to inspect subsea 

equipment. The BSEE 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 how 

you met or exceeded the provisions of 

Sections 17.11 and 18.11, Maintenance; 

and Sections 17.12 and 18.12, Quality 

Management, described in API RP 53, 

the procedures used, record the results, 

and make the records available to BSEE 

upon request. You must maintain your 

records on the rig for 2 years from the 

date the records are created, or for a 

longer period if directed by BSEE. 

* * * * * 

■ 22. Amend § 250.613 by: 

a. Redesignating paragraphs (b)(3) 

through (b)(4) as (b)(4) through (b)(5), 

and 

b. Adding a new paragraph (b)(3) to 

read as follows: 

§ 250.613 Approval and reporting of wellworkover operations. 

* * * * * 

(b) * * * 

(3) All information required in 

§ 250.615. 

* * * * * 

■ 23. Amend § 250.614 by adding new 

paragraph (d) to read as follows: 

§ 250.614 Well-control fluids, equipment, 

and operations. 

* * * * * 

(d) Before you displace kill-weight 

fluid from the wellbore and/or riser to 

an underbalanced state, you must obtain 

approval from the BSEE District 

Manager. To obtain approval, you must 

submit with your APM your reasons for 

displacing the kill-weight fluid and 

provide detailed step-by-step written 

procedures describing how you will 

safely displace these fluids. The step-bystep displacement procedures must 

address the following: 

(1) Number and type of independent 

barriers, as described in § 250.420(b)(3), 

that are in place for each flow path that 

requires such barriers, 

(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 

the volumes and rates of fluids entering 

and leaving the wellbore. 

■ 24. Redesignate §§ 250.615 through 

250.619 as §§ 250.616 through 250.620. 

■ 25. Add new § 250.615 to read as 

follows: 

§ 250.615 What BOP information must I 

submit? 

For well-workover operations, your 

APM must include the following BOP 

descriptions: 

(a) A description of the BOP system 

and system components, including 

pressure ratings of BOP equipment and 

proposed BOP test pressures; 

(b) 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; 

(c) Independent third-party 

verification and supporting 

documentation that show the blindshear rams installed in the BOP stack 

are capable of shearing any drill pipe 

(including workstring and tubing) in the 

hole under maximum anticipated 

surface pressure. The documentation 

must include actual shearing and 

subsequent pressure integrity test 

results for the most rigid pipe to be used 

and calculations of shearing capacity of 


TKELLEY on DSK3SPTVN1PROD with RULES2
50896 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

all pipe to be used in the well, including 

correction for under maximum 

anticipated surface pressure; 

(d) 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 

(e) The qualifications of the 

independent third-party referenced in 

paragraphs (c) and (d) of this section: 

(1) The independent third-party in 

this section must be a technical 

classification society, or a licensed 

professional engineering firm, or a 

registered professional engineer capable 

of providing the verifications required 

under this part. 

(2) You must: 

(i) Include evidence that the 

registered professional engineer, or a 

technical classification society, or 

engineering firm you are using or its 

employees hold appropriate licenses to 

perform the verification in the 

appropriate jurisdiction, and evidence 

to demonstrate that the individual, 

society, or firm has the expertise and 

experience necessary to perform the 

required verifications. 

(ii) Ensure that an official 

representative of BSEE will have access 

to the location to witness any testing or 

inspections, and verify information 

submitted to BSEE. Prior to any shearing 

ram tests or inspections, you must 

notify the BSEE District Manager at least 

72 hours in advance. 

* * * * * 

■ 26. Amend newly redesignated 

§ 250.617 by revising paragraph (h) to 

read as follows: 

§ 250.617 Blowout preventer system 

testing, records, and drills. 

* * * * * 

(h) Stump test a subsea BOP system 

before installation. You must use water 

to conduct this test. You may use 

drilling or completion fluids to conduct 

subsequent tests of a subsea BOP 

system. You must perform the initial 

subsea BOP test on the seafloor within 

30 days of the stump test. You must: 

(1) Test all ROV intervention 

functions on your subsea BOP stack 

during the stump test. Each ROV must 

be fully compatible with the BOP stack 

ROV intervention panels. You must also 

test and verify closure of at least one set 

of rams during the initial test on the 

seafloor through an ROV hot stab. You 

must submit test procedures, including 

how you will test each ROV function, 

with your APM for BSEE 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, one set of blind-shear rams, and 

unlatching the LMRP; 

(ii) Notify the appropriate BSEE 

District Manager a minimum of 72 hours 

prior to the stump test and initial test on 

the seafloor; 

(iii) Document all your test results 

and make them available to BSEE 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 and verify 

closure of at least one set of blind-shear 

rams during the initial test on the 

seafloor. When you conduct the initial 

deadman system test on the seafloor you 

must ensure the well is secure and, if 

hydrocarbons have been present, 

appropriate barriers are in place to 

isolate hydrocarbons from the wellhead. 

You must also have an ROV on bottom 

during the test. You must: 

(i) Submit test procedures with your 

APM for BSEE District Manager 

approval. The procedures for these 

function tests must include 

documentation of the controls and 

circuitry of the system utilized during 

each test. The procedure must also 

describe how the ROV will be utilized 

during this operation. 

(ii) Document the results of each test 

and make them available to BSEE upon 

request. 

■ 27. Revise § 250.618 to read as 

follows: 

§ 250.618 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 how you met or 

exceeded the provisions of Sections 

17.10 and 18.10 described in API RP 53, 

the procedures used, record the results, 

and make the records available to BSEE 

upon request. You must maintain your 

records on the rig for 2 years from the 

date the records are created, or for a 

longer period if directed by BSEE. 

(2) You must visually inspect your 

surface BOP system on a daily basis. 

You must visually inspect your subsea 

BOP system and marine riser at least 

once every 3 days if weather and sea 

conditions permit. You may use 

television cameras to inspect subsea 

equipment. The BSEE 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 how 

you met or exceeded the provisions of 

Sections 17.11 and 18.11, Maintenance; 

and Sections 17.12 and 18.12, Quality 

Management, described in API RP 53, 

the procedures used, record the results, 

and make the records available to BSEE 

upon request. You must maintain your 

records on the rig for 2 years from the 

date the records are created, or for a 

longer period if directed by BSEE. 

■ 28. Amend § 250.1500 by revising the 

definition for ‘‘Well-control’’ to read as 

follows: 

§ 250.1500 Definitions 

* * * * * 

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. 

Well-control applies to drilling, wellcompletion, well-workover, 

abandonment, and well-servicing 

operations. It includes measures, 

practices, procedures and equipment, 

such as fluid flow monitoring, to ensure 

safe and environmentally protective 

drilling, completion, abandonment, and 

workover operations as well as the 

installation, repair, maintenance, and 

operation of surface and subsea wellcontrol equipment. 

* * * * * 

■ 29. Amend § 250.1704 by revising 

paragraph (g) to read as follows: 

§ 250.1704 When must I submit 

decommissioning applications and reports? 

* * * * * 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50897 

Decommissioning applications and reports When to submit Instructions 

*******

(g) Form BSEE–0124, Application for Permit to 

Modify (APM). The submission of your APM 

must be accompanied by payment of the 

service fee listed in § 250.125.

(1) Before you temporarily abandon or permanently plug a well or zone (i) Include information required under 

§§ 250.1712 and 250.1721. 

(ii) When using a BOP for abandonment operations include information required under 

§ 250.1705. 

(2) Within 30 days after you plug a well .......... Include information required under § 250.1717. 

(3) Before you install a subsea protective device.Refer to § 250.1722(a). 

(4) Within 30 days after you complete a protective device trawl test Include information required under 

§ 250.1722(d). 

(5) Before you remove any casing stub or mud 

line suspension equipment and any subsea 

protective device.

Refer to § 250.1723. 

(6) Within 30 days after you complete site 

clearance verification activities 

Include information required under 

§ 250.1743(a). 

■ 30. Add § 250.1705 to read as follows: 

§ 250.1705 What BOP information must I 

submit? 

If you plan to use a BOP for 

abandonment operations, your 

decommissioning application must 

include the following BOP descriptions: 

(a) A description of the BOP system 

and system components, including 

pressure ratings of BOP equipment and 

proposed BOP test pressures; 

(b) 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; 

(c) Independent third-party 

verification and supporting 

documentation that show the blindshear rams installed in the BOP stack 

are capable of shearing any drill pipe 

(including workstring and tubing) in the 

hole under maximum anticipated 

surface pressure. The documentation 

must include actual shearing and 

subsequent pressure integrity test 

results for the most rigid pipe to be used 

and calculations of shearing capacity of 

all pipe to be used in the well, including 

correction for Maximum Anticipated 

Surface Pressure (MASP); 

(d) 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 

(e) The qualifications of the 

independent third-party referenced in 

paragraphs (c) and (d) of this section 

including evidence that: 

(1) The independent third-party in 

this section is a technical classification 

society, or a licensed professional 

engineering firm, or a registered 

professional engineer capable of 

providing the verifications required 

under this part. 

(2) You must: 

(i) Include evidence that the 

registered professional engineer, or a 

technical classification society, or 

engineering firm you are using or its 

employees hold appropriate licenses to 

perform the verification in the 

appropriate jurisdiction, and evidence 

to demonstrate that the individual, 

society, or firm has the expertise and 

experience necessary to perform the 

required verifications. 

(ii) Ensure that an official 

representative of BSEE will have access 

to the location to witness any testing or 

inspections, and verify information 

submitted to BSEE. Prior to any shearing 

ram tests or inspections, you must 

notify the BSEE District Manager at least 

72 hours in advance. 

■ 31. Add § 250.1706 to read as follows: 

§ 250.1706 What are the requirements for 

blowout prevention equipment? 

If you use a BOP for any well 

abandonment operations, your BOP 

must meet the following requirements: 

(a) The BOP system, system 

components, and related well-control 

equipment must be designed, used, 

maintained, and tested in a manner 

necessary to assure well-control in 

foreseeable conditions and 

circumstances, including subfreezing 

conditions. The working pressure rating 

of the BOP system and system 

components must exceed the expected 

surface pressure to which they may be 

subjected. If the expected surface 

pressure exceeds the rated working 

pressure of the annular preventer, you 

must submit with Form BSEE–0124, 

requesting approval of the well 

abandonment operations, a well-control 

procedure that indicates how the 

annular preventer will be utilized, and 

the pressure limitations that will be 

applied during each mode of pressure 

control. 

(b) The minimum BOP system for 

well abandonment operations with the 

tree removed must meet the appropriate 

standards from the following table: 

When . . . The minimum BOP stack must include . . . 

(1) The expected pressure is less than 5,000 

psi, 

Three BOPs consisting of an annular, one set of pipe rams, and one set of blind-shear rams. 

(2) The expected pressure is 5,000 psi or greater or you use multiple tubing strings, Four BOPs consisting of an annular, two sets of pipe rams, and one set of blind-shear rams. 

(3) You handle multiple tubing strings simultaneously, Four BOPs consisting of an annular, one set of pipe rams, one set of dual pipe rams, and one 

set of blind-shear rams. 

(4) You use a tapered drill string, (i) At least one set of pipe rams that are capable of sealing around each size of drill string. 


TKELLEY on DSK3SPTVN1PROD with RULES2
50898 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

When . . . The minimum BOP stack must include . . . 

(ii) If the expected pressure is greater than 5,000 psi, then you must have at least two sets of 

pipe rams that are capable of sealing around the larger size drill string. 

(iii) You may substitute one set of variable bore rams for two sets of pipe rams. 

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

(c) The BOP systems for well 

abandonment operations with the tree 

removed must be equipped with the 

following: 

(1) A hydraulic-actuating system that 

provides sufficient accumulator 

capacity to supply 1.5 times the volume 

necessary to close all BOP equipment 

units with a minimum pressure of 200 

psi above the precharge pressure 

without assistance from a charging 

system. Accumulator regulators 

supplied by rig air and without a 

secondary source of pneumatic supply, 

must be equipped with manual 

overrides, or alternately, other devices 

provided to ensure capability of 

hydraulic operations if rig air is lost; 

(2) A secondary power source, 

independent from the primary power 

source, with sufficient capacity to close 

all BOP system components and hold 

them closed; 

(3) Locking devices for the pipe-ram 

preventers; 

(4) At least one remote BOP-control 

station and one BOP-control station on 

the rig floor; and 

(5) A choke line and a kill line each 

equipped with two full opening valves 

and a choke manifold. At least one of 

the valves on the choke-line must be 

remotely controlled. At least one of the 

valves on the kill line must be remotely 

controlled, except that a check valve on 

the kill line in lieu of the remotely 

controlled valve may be installed, 

provided two readily accessible manual 

valves are in place and the check valve 

is placed between the manual valves 

and the pump. This equipment must 

have a pressure rating at least equivalent 

to the ram preventers. You must install 

the choke line above the bottom ram 

and may install the kill line below the 

bottom ram. 

(d) The minimum BOP system 

components for well abandonment 

operations with the tree in place and 

performed through the wellhead inside 

of conventional tubing using smalldiameter jointed pipe (usually 3⁄4 inch to 

11⁄4 inch) as a work string, i.e., smalltubing operations, must include the 

following: 

(1) Two sets of pipe rams, and 

(2) One set of blind rams. 

(e) The subsea BOP system for well 

abandonment operations must meet the 

requirements in § 250.442 of this part. 

(f) For coiled tubing operations with 

the production tree in place, you must 

meet the following minimum 

requirements for the BOP system: 

(1) BOP system components must be 

in the following order from the top 

down: 

BOP system when expected 

surface pressures are less than or 

equal to 3,500 psi 

BOP system when expected 

surface pressures are greater than 

3,500 psi 

BOP system for wells with returns taken through an outlet on the 

BOP stack 

(i) Stripper or annular-type wellcontrol component, Stripper or annular-type well-control component, Stripper or annular-type well-control component. 

(ii) Hydraulically-operated blind 

rams, 

Hydraulically-operated blind rams, Hydraulically-operated blind rams. 

(iii) Hydraulically-operated shear 

rams, 

Hydraulically-operated shear rams, Hydraulically-operated shear rams. 

(iv) Kill line inlet, Kill line inlet, Kill line inlet. 

(v) Hydraulically-operated two-way 

slip rams, 

Hydraulically-operated two-way 

slip rams, 

Hydraulically-operated two-way slip rams. 

Hydraulically-operated pipe rams. 

(vi) Hydraulically-operated pipe 

rams, 

Hydraulically-operated pipe rams. 

Hydraulically-operated blind-shear 

rams. These rams should be located as close to the tree as 

practical, 

A flow tee or cross. 

Hydraulically-operated pipe rams. 

Hydraulically-operated blind-shear rams on wells with surface pressures >3,500 psi. As an option, the pipe rams can be placed below 

the blind-shear rams. The blind-shear rams should be located as 

close to the tree as practical. 

(2) You may use a set of 

hydraulically-operated combination 

rams for the blind rams and shear rams. 

(3) You may use a set of 

hydraulically-operated combination 

rams for the hydraulic two-way slip 

rams and the hydraulically-operated 

pipe rams. 

(4) You must attach a dual check 

valve assembly to the coiled tubing 

connector at the downhole end of the 

coiled tubing string for all coiled tubing 

well abandonment operations. If you 

plan to conduct operations without 

downhole check valves, you must 

describe alternate procedures and 

equipment in Form BSEE–0124, 

Application for Permit to Modify, and 

have it approved by the BSEE District 

Manager. 

(5) You must have a kill line and a 

separate choke line. You must equip 

each line with two full-opening valves 

and at least one of the valves must be 

remotely controlled. You may use a 

manual valve instead of the remotely 

controlled valve on the kill line if you 

install a check valve between the two 

full-opening manual valves and the 

pump or manifold. The valves must 

have a working pressure rating equal to 

or greater than the working pressure 

rating of the connection to which they 

are attached, and you must install them 

between the well-control stack and the 

choke or kill line. For operations with 

expected surface pressures greater than 

3,500 psi, the kill line must be 

connected to a pump or manifold. You 

must not use the kill line inlet on the 

BOP stack for taking fluid returns from 

the wellbore. 

(6) You must have a hydraulicactuating system that provides sufficient 

accumulator capacity to close-openclose each component in the BOP stack. 

This cycle must be completed with at 

least 200 psi above the pre-charge 

pressure, without assistance from a 

charging system. 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50899 

(7) All connections used in the 

surface BOP system from the tree to the 

uppermost required ram must be 

flanged, including the connections 

between the well-control stack and the 

first full-opening valve on the choke 

line and the kill line. 

(g) The minimum BOP system 

components for well abandonment 

operations with the tree in place and 

performed by moving tubing or drill 

pipe in or out of a well under pressure 

utilizing equipment specifically 

designed for that purpose, i.e., snubbing 

operations, must include the following: 

(1) One set of pipe rams hydraulically 

operated, and 

(2) Two sets of stripper-type pipe 

rams hydraulically operated with spacer 

spool. 

(h) An inside BOP or a spring-loaded, 

back-pressure safety valve, and an 

essentially full-opening, work-string 

safety valve in the open position must 

be maintained on the rig floor at all 

times during well abandonment 

operations when the tree is removed or 

during well abandonment operations 

with the tree installed and using small 

tubing as the work string. A wrench to 

fit the work-string safety valve must be 

readily available. Proper connections 

must be readily available for inserting 

valves in the work string. The fullopening safety valve is not required for 

coiled tubing or snubbing operations. 

■ 32. Add § 250.1707 to read as follows: 

§ 250.1707 What are the requirements for 

blowout preventer system testing, records, 

and drills? 

(a) BOP pressure tests. When you 

pressure test the BOP system, you must 

conduct a low-pressure test and a highpressure test for each component. You 

must conduct the low-pressure test 

before the high-pressure test. For 

purposes of this section, BOP system 

components include ram-type BOP’s, 

related control equipment, choke and 

kill lines, and valves, manifolds, 

strippers, and safety valves. Surface 

BOP systems must be pressure tested 

with water. 

(1) Low pressure tests. You must 

successfully test all BOP system 

components to a low pressure between 

200 and 300 psi. Any initial pressure 

equal to or greater than 300 psi must be 

bled back to a pressure between 200 and 

300 psi before starting the test. If the 

initial pressure exceeds 500 psi, you 

must bleed back to zero before starting 

the test. 

(2) High pressure tests. You must 

successfully test all BOP system 

components to the rated working 

pressure of the BOP equipment, or as 

otherwise approved by the BSEE District 

Manager. You must successfully test the 

annular-type BOP at 70 percent of its 

rated working pressure or as otherwise 

approved by the BSEE District Manager. 

(3) Other testing requirements. You 

must test variable bore pipe rams 

against the largest and smallest sizes of 

tubulars in use (jointed pipe, seamless 

pipe) in the well. 

(b) You must test the BOP systems at 

the following times: 

(1) When installed; 

(2) At least every 7 days, alternating 

between control stations and at 

staggered intervals to allow each crew to 

operate the equipment. If either control 

system is not functional, further 

operations must be suspended until the 

nonfunctional system is operable. The 

test every 7 days is not required for 

blind or blind-shear rams. The blind or 

blind-shear rams must be tested at least 

once every 30 days during operation. A 

longer period between blowout 

preventer tests is allowed when there is 

a stuck pipe or pressure-control 

operation and remedial efforts are being 

performed. The tests must be conducted 

as soon as possible and before normal 

operations resume. The reason for 

postponing testing must be entered into 

the operations log. The BSEE District 

Manager may require alternate test 

frequencies if conditions or BOP 

performance warrant. 

(3) Following repairs that require 

disconnecting a pressure seal in the 

assembly, the affected seal will be 

pressure tested. 

(c) All personnel engaged in well 

abandonment operations must 

participate in a weekly BOP drill to 

familiarize crew members with 

appropriate safety measures. 

(d) You may conduct a stump test for 

the BOP system on location. A plan 

describing the stump test procedures 

must be included in your Application 

for Permit to Modify, Form BSEE–0124, 

and must be approved by the BSEE 

District Manager. 

(e) You must test the coiled tubing 

connector to a low pressure of 200 to 

300 psi, followed by a high pressure test 

to the rated working pressure of the 

connector or the expected surface 

pressure, whichever is less. You must 

successfully pressure test the dual check 

valves to the rated working pressure of 

the connector, the rated working 

pressure of the dual check valve, 

expected surface pressure, or the 

collapse pressure of the coiled tubing, 

whichever is less. 

(f) You must record test pressures 

during BOP and coiled tubing tests on 

a pressure chart, or with a digital 

recorder, unless otherwise approved by 

the BSEE District Manager. The test 

interval for each BOP system 

component must be 5 minutes, except 

for coiled tubing operations, which 

must include a 10 minute high-pressure 

test for the coiled tubing string. Your 

representative at the facility must certify 

that the charts are correct. 

(g) The time, date, and results of all 

pressure tests, actuations, inspections, 

and crew drills of the BOP system, 

system components, and marine risers 

must be recorded in the operations log. 

The BOP tests must be documented in 

accordance with the following: 

(1) The documentation must indicate 

the sequential order of BOP and 

auxiliary equipment testing, the 

pressure, and duration of each test. As 

an alternate, the documentation in the 

operations log may reference a BOP test 

plan that contains the required 

information and is retained on file at the 

facility. 

(2) The control station used during 

the test must be identified in the 

operations log. For a subsea system, the 

pod used during the test must be 

identified in the operations log. 

(3) Any problems or irregularities 

observed during BOP and auxiliary 

equipment testing and any actions taken 

to remedy such problems or 

irregularities, must be noted in the 

operations log. 

(4) Documentation required to be 

entered in the operations log may 

instead be referenced in the operations 

log. You must make all records 

including pressure charts, operations 

log, and referenced documents 

pertaining to BOP tests, actuations, and 

inspections, available for BSEE review 

at the facility for the duration of well 

abandonment activity. Following 

completion of the well abandonment 

activity, you must retain all such 

records for a period of two years at the 

facility, at the lessee’s field office 

nearest the OCS facility, or at another 

location conveniently available to the 

BSEE District Manager. 

(h) Stump test a subsea BOP system 

before installation. You must use water 

to conduct this test. You may use 

drilling fluids to conduct subsequent 

tests of a subsea BOP system. You must 

stump test the subsea BOP within 30 

days of the initial test on the seafloor. 

You must: 

(1) Test all ROV intervention 

functions on your subsea BOP stack 

during the stump test. Each ROV must 

be fully compatible with the BOP stack 

ROV intervention panels. You must also 

test and verify closure of at least one set 

of rams during the initial test on the 

seafloor. You must submit test 

procedures, including how you will test 

each ROV function, with your APM for 


TKELLEY on DSK3SPTVN1PROD with RULES2
50900 Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 

BSEE 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 BSEE 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 and verify 

closure of at least one set of blind-shear 

rams during the initial test on the 

seafloor. When you conduct the initial 

deadman system test on the seafloor you 

must ensure the well is secure and, if 

hydrocarbons have been present, 

appropriate barriers are in place to 

isolate hydrocarbons from the wellhead. 

You must also have an ROV on bottom 

during the test. You must: 

(i) Submit test procedures with your 

APM for BSEE District Manager 

approval. The procedures for these 

function tests must include 

documentation of the controls and 

circuitry of the system utilized during 

each test. The procedure must also 

describe how the ROV will be utilized 

during this operation. 

(ii) Document the results of each test 

and make them available to BSEE upon 

request. 

■ 33. Add § 250.1708 to read as follows: 

§ 250.1708 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 how you met or 

exceeded the provisions of Sections 

17.10 and 18.10 described in API RP 53, 

document the procedures used, record 

the results, and make the records 

available to BSEE upon request. You 

must maintain your records on the rig 

for 2 years from the date the records are 

created, or for a longer period if directed 

by BSEE. 

(2) You must visually inspect your 

BOP system and marine riser at least 

once every 3 days if weather and sea 

conditions permit. You may use 

television cameras to inspect this 

equipment. The BSEE 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 how 

you met or exceeded the provisions of 

Sections 17.11 and 18.11, Maintenance; 

and Sections 17.12 and 18.12, Quality 

Management, described in API RP 53, 

document the procedures used, record 

the results, and make the records 

available to BSEE upon request. You 

must maintain your records on the rig 

for 2 years from the date the records are 

created, or for a longer period if directed 

by BSEE. 

■ 34. Add § 250.1709 to read as follows: 

§ 250.1709 What are my well-control fluid 

requirements? 

Before you displace kill-weight fluid 

from the wellbore and/or riser to an 

underbalanced state, you must obtain 

approval from the BSEE District 

Manager. To obtain approval, you must 

submit with your APM, your reasons for 

displacing the kill-weight fluid and 

provide detailed step-by-step written 

procedures describing how you will 

safely displace these fluids. The step-bystep displacement procedures must 

address the following: 

(a) Number and type of independent 

barriers, as described in § 250.420(b)(3), 

that are in place for each flow path that 

requires such barriers, 

(b) Tests you will conduct to ensure 

integrity of independent barriers, 

(c) BOP procedures you will use 

while displacing kill weight fluids, and 

(d) Procedures you will use to 

monitor the volumes and rates of fluids 

entering and leaving the wellbore. 

■ 35. Amend § 250.1712 by revising 

paragraph (g) to read as follows: 

§ 250.1712 What information must I submit 

before I permanently plug a well or zone? 

* * * * * 

(g) Certification by a Registered 

Professional Engineer of the well 

abandonment design and procedures 

and that all plugs meet the requirements 

in the table in § 250.1715. In addition to 

the requirements of § 250.1715, the 

Registered Professional Engineer must 

also certify the design will include two 

independent barriers, one of which 

must be a mechanical barrier, in the 

center wellbore as described in 

§ 250.420(b)(3). The Registered 

Professional Engineer must be registered 

in a State of the United States and have 

sufficient expertise and experience to 

perform the certification. You must 

submit this certification with your APM 

(Form BSEE–0124). 

■ 36. Amend § 250.1715 by adding 

paragraph (a)(11) to read as follows: 

§ 250.1715 How must I permanently plug a 

well? 

(a) * * * 

If you have . . . Then you must use . . . 

*******

(11) Removed the barriers required in § 250.420(b)(3) for the well to be 

completed.

Two independent barriers, one of which must be a mechanical barrier, 

in the center wellbore as described in § 250.420(b)(3) once the well 

is to be placed in a permanent or temporary abandonment. 

* * * * * 

■ 37. Amend § 250.1721 by revising 

paragraph (h) to read as follows: 

§ 250.1721 If I temporarily abandon a well 

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

* * * * * 

(h) Submit certification by a 

Registered Professional Engineer of the 

well abandonment design and 

procedures and that all plugs meet the 

requirements of paragraph (b) of this 

section. In addition to the requirements 

of paragraph (b) of this section, the 

Registered Professional Engineer must 

also certify the design will include two 

independent barriers, one of which 

must be a mechanical barrier, in the 

center wellbore as described in 

§ 250.420(b)(3). The Registered 

Professional Engineer must be registered 

in a State of the United States and have 

sufficient expertise and experience to 

perform the certification. You must 

submit this certification with your APM 


TKELLEY on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 77, No. 163 / Wednesday, August 22, 2012 / Rules and Regulations 50901 

(Form BSEE–0124) required by 

§ 250.1712 of this part. 

[FR Doc. 2012–20090 Filed 8–16–12; 4:15 pm] 

BILLING CODE 4310–VH–P 


TKELLEY on DSK3SPTVN1PROD with RULES2