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Oil and Gas and Sulphur Operations in the Outer Continental Shelf (OCS)-Minimum Blowout Prevention (BOP) System Requirements for Well-Workover Operations Performed Using Coiled Tubing With the Production Tree in Place

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Information about this document as published in the Federal Register.

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Start Preamble

AGENCY:

Minerals Management Service (MMS), Interior.

ACTION:

Final rule.

SUMMARY:

This rule upgrades minimum blowout prevention and well control requirements for well-workover operations on the OCS performed using coiled tubing with the production tree in place. Since 1997, there have been eight coiled tubing-related incidents on OCS facilities. The rule helps prevent losses of well control, and provides for increased safety and environmental protection.

dates:

Effective Date: This rule becomes effective on April 6, 2006.

Start Further Info

FOR FURTHER INFORMATION CONTACT:

Joseph R. Levine, Offshore Regulatory Programs, at (703) 787-1033, Fax: (703) 787-1555, or e-mail at joseph.levine@mms.gov.

End Further Info End Preamble Start Supplemental Information

SUPPLEMENTARY INFORMATION:

On June 22, 2004, MMS published a Notice of Proposed Rulemaking (69 FR 34625), titled “Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Minimum Blowout Prevention (BOP) System Requirements for Well-Workover Operations Performed Using Coiled Tubing with the Production Tree in Place.” The proposed rule had a 60-day comment period that closed on August 23, 2004.

Comments on the Rule

MMS received two sets of comments on the proposed rule. The comments came from the Offshore Operators Committee (OOC) and Halliburton, an oilfield service company and are posted at: http://www.mms.gov/​federalregister/​PublicComments/​rulecomm.htm. Both sets of comments addressed specific technical issues related to coiled tubing operations.

I. OOC Comments on Specific Sections

Comment on section 250.615(e)(1): OOC suggested that the “Kill line outlet” reference should be the “Kill line inlet.” This line is used for pumping kill fluid into the well and is not commonly used to flow out of the well.

Response: MMS agrees with the suggestion, and revised the requirement.

Comment on section 250.615(e)(5): OOC commented that the requirement for hydraulically controlled valves on both lines could be onerous for some situations, such as [plugged and abandoned] operations on dead or depleted wells with less than 3,500 expected pounds per square inch (psi) surface pressure.” They suggested wording should be added to allow exceptions in special situations that would allow leaving the hydraulic actuation requirement off and using manual valves. “Some circumstances require the ability to flow back from both sides of the flow cross unit.” An operator should be allowed to comply by using dual full-opening valves on the kill line inlet. They asked, “Would this BOP rig up configuration comply with this clause?” Also, the commenter questioned the “* * * need to require one valve to be remotely controlled in all BOP rig up cases.” The commenter further suggested, “Possibly for wells with no H2 S, or for those wells which have lower wellhead pressures, the use of dual manual valves could be sufficient.”

Response: MMS agrees that two manual valves can be used on the kill line for all situations provided that a check valve is placed between the manual valves and the pump or manifold. However, the choke line needs to be equipped with two full-opening valves with at least one of these valves being remotely controlled for all operations.

MMS does not consider it a safe practice to use the kill line to flow back fluids through the flow cross because the purpose of the kill line is to pump clean fluids into the wellbore. If the kill line is used to flow back fluids from the well, these well fluids may contain well debris that could erode critical safety equipment.

Comment on section 250.615(e)(5): The proposed provision states, “For operations with expected surface pressure of 3,500 psi or greater, the kill line must be connected to a pump.” OOC recommended that this statement be amended to read: “For operations with expected surface pressure of 3,500 psi or greater, the kill line must be connected to a pump or manifold.”

Response: MMS agrees with the suggestion and revised the requirement. In a well control situation, having the kill line connected to a manifold provides an equivalent degree of protection to both personnel and the environment as having the kill line connected to a pump.

Comment on section 250.615(e)(7): The proposed provision states, “All connections used in the surface BOP system must be flanged.” OOC asked MMS to clarify that the statement means the equipment shown in the table and does not include kill or flow lines. OOC recommended that all riser connections from wellhead to below the stripper must be flanged when expected surface pressures are greater than 3,500 psi. OOC also recommended that if the expected surface pressure is less than 3,500 psi, the BOP kill inlet valves can be full-opening manual plug (hammer union type) valves.

Response: MMS has modified 30 CFR 250.615 (e)(7) to clarify the flanging requirement for the BOP system. All connections in the surface BOP system from the tree to the uppermost required ram, as included in the table at § 250.615(e)(1), need to be flanged, including the connections between the well control stack and the first full-opening valve on the choke line and kill line. This configuration needs to be adhered to for all expected surface pressures. Flanged connections provide better pressure integrity than hammer union type connections. Hammer union type connections are not allowed between the well control stack and the first full-opening valve on either the choke line or the kill line.

Comment on section 250.616(a)(2): The proposed provision states, “Ram-type BOPs, related control equipment, including the choke and kill manifolds, and safety valves must be successfully tested to the rated working pressure of the BOP equipment or as otherwise approved by the District Manager.” OOC recommended that this clause be changed to state, “Ram-type BOPs, related control equipment, including the choke and kill manifolds, and safety valves must be successfully tested to 1,500 psi above the maximum expected Start Printed Page 11311shut in wellhead pressure (not to exceed the wellhead working pressure), or as otherwise approved by the District Manager.”

Response: MMS did not make the suggested change. The requirement to test the rams, related control equipment, manifolds, and safety valves to the equipments' rated working pressure is viewed as an industry best practice by the offshore oil and gas community. If operators want to test this equipment to a lower pressure than its rated working pressure, they must provide the MMS District Manager with appropriate justification.

Comment on section 250.616(a)(2): The proposed provision states, “Variable bore rams must be pressure tested against all sizes of drill pipe in the well, excluding drill collars.” The commenter stated that this should not apply to coiled tubing functions and is a holdover from the source document used in writing this rule. OOC recommended that this be deleted.

Response: MMS agrees with the comment and changed the variable bore pipe rams requirement to provide for pressure testing on tubulars including jointed and seamless pipe.

Comment on section 250.616(f): OOC requested “* * * that the required pressure test duration on coiled tubing BOP tests be changed from 10 minutes to 5 minutes. The American Petroleum Institute (API) Coiled Tubing Committee originally agreed on the 10-minute duration and then, after further discussion, agreed that it should be changed back to 5 minutes. The recommended change to 5 minutes would save approximately 1/2 hour of testing each week.”

Response: MMS did not make the suggested change. MMS believes that a 10-minute pressure test of the coiled tubing string more accurately shows string integrity than a 5-minute test. In such a test, it may take longer then 5 minutes to pressurize the entire string, depending on the length of the coiled tubing string, to accurately evaluate its integrity. MMS is aware of the discussions that the API Well Intervention Well Control Task Group had concerning this topic. Though the Task Group agreed to return to a 5-minute testing requirement, it was clear during the discussions that not every representative agreed with the change.

II. Halliburton Comments on Specific Sections

Comment on section 250.615(e)(1): “According to the proposed text, the blind-shear rams are required to be the lowermost rams.” If an operator places “* * * a set of dual combination rams below a flow cross, it would be a preference to have the pipe-slip combination ram as the lowermost ram to enable holding the cut coiled tubing. From the provided text, it may stand to reason that the primary objective is to have a blind-shear ram configuration as part of the BOP system and the sequential order is of less importance.”

Response: MMS agrees with the suggestion and modified the table to reflect this change. Operators will have the option to place either the pipe rams or the blind-shear rams as the lowermost rams.

Comment on section 250.615(e)(5): “The placement of the two full-opening valves is vague and left to interpretation. Connecting the valves to the well control stack could be accomplished by either directly to the stack or with 30 feet of connection line. A check valve in the kill line might need to be considered as a component requirement.”

Response: MMS agrees with the comment that the placement of the two full-opening valves on both the choke line and the kill line is vague. We modified the wording to require that the kill line and choke line valves be installed between the well control stack and the respective line.

If a check valve is used on the kill line of the BOP stack, it needs to be placed between two manual valves and the pump. If the check valve is used, it is considered a component of the BOP system and should be treated accordingly with regard to testing.

Comment on section 250.615(e)(7): “Lubricator sections are normally acceptable pressure containment devices and employ quick connections as end connections. Is the placement of the lubricator below the stripper well control component and above the Quad Ram function an acceptable configuration?”

Response: Yes, placement of the lubricator below the stripper well control component and above the uppermost required ram is an appropriate and common configuration.

Comment on section 250.616(a): “There could be some confusion regarding the pressure test amount for the stripper well components. Are stripper well components classified as related control equipment?”

Response: MMS agrees that the proposed rule could be confusing concerning the pressure testing requirements for the stripper. Therefore, we changed the wording in this section to reflect that strippers need to be tested like other BOP components.

Comment on section 250.616(f): “There could be some confusion regarding the test period. Is the coiled tubing pipe the only 10-minute test interval, and the rest of the BOP system components a 5-minute test interval requirement?”

Response: MMS agrees that the proposed rule could be confusing in regards to the required pressure test period for the coiled tubing string. We changed the regulation to indicate that the 10-minute pressure test is just for the coiled tubing string.

Differences Between Proposed and Final Rules Not Directly Related to Comments

In addition to changes we made in the rule in response to public comments, MMS has reworded several sections in the final rule to further clarify the requirements. The following are the changes by section:

Section 250.615(e)(1)— We expanded the title of the first column in the table to reflect a pressure range of less than or equal to 3,500 psi. This change more accurately reflects our intentions.

Section 250.615(e)(1)— We removed the requirement to have two sets of hydraulically-operated pipe rams for BOP configurations when expected surface pressures are greater than 3,500 psi. This change corrects an oversight.

Section 250.616(a)— We removed the word “sequentially” from the last sentence of this section so that the testing of the choke and kill manifold valves does not need to be conducted in any predetermined order.

Procedural Matters

Regulatory Planning and Review (Executive Order 12866)

This is not a significant rule under Executive Order 12866, and does not require review by the Office of Management and Budget (OMB).

a. The final rule will not have an annual effect on the economy of $100 million or more, or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or state, local, or tribal governments or communities. The final rule will not create an adverse effect upon the ability of the United States offshore oil and gas industry to compete in the world marketplace, nor will the final rule adversely affect investment or employment factors locally. The economic effects of the rule will not be significant. This rule will not add significant dollar amounts to the cost of each well-workover operation involving the use of coiled tubing with the production tree in place. During February 2003, MMS surveyed, by Start Printed Page 11312phone, five of the eight coiled tubing operating companies working on the OCS to collect information on the impact this rule would have on their operations. All data indicates that these offshore coiled tubing companies have upgraded their field procedures and equipment to the same or a similar process as that required under the final rule. None of the companies in this survey could provide dollar values for the implementation of this rule because they had incorporated most of the suggested measures into their work processes in 1999. Some of the coiled tubing operating companies contacted are already using dual check valves in the bottom of their coiled tubing string. According to these companies, this practice was put into place several years ago for OCS operations. For these reasons, MMS concluded that direct annual costs to industry for the final rule will have a minor economic effect on the offshore oil and gas industry.

b. This rule will not create inconsistencies with other agencies' actions. The rule does not change the relationships of the OCS oil and gas leasing program with other agencies. These relationships are all encompassed in agreements and memoranda of understanding that will not change with this final rule.

c. This final rule will not affect entitlements, grants, loan programs, or the rights and obligations of their recipients. The rule includes specific well-workover process standards to prevent accidents and environmental pollution on the OCS.

d. This rule will not raise novel legal or policy issues. There is a precedent for actions of this type under regulations dealing with the Outer Continental Shelf Lands Act and the Oil Pollution Act of 1990.

Regulatory Flexibility Act (RFA)

MMS has determined that this final rule will not have a significant economic effect on a substantial number of small entities. While the rule will affect some small entities, the economic effects of the rule will not be significant.

The regulated community for this rule consists of about eight companies specializing in offshore oil and gas coiled tubing technologies. Of these companies, three are considered to be “small.” The small companies to be affected by this rule are all represented by the North American Industry Classification System (NAICS) Code 211111 (crude petroleum and natural gas extraction).

MMS's analysis of the economic impacts of this final rule indicates that direct implementation costs to both large and small companies cannot be accurately assessed because the industry has already implemented most of the technological requirements required in this final rule. Regardless of company size, the final rule will have a minor economic effect on some oil and gas offshore platform operators on the OCS. In the overwhelming majority of cases, operators choose to perform improved and safer well-workover procedures involving coiled tubing operations on their own initiative, not because of an MMS safety inspection or regulation. The final rule will add relatively little to the cost of a well-workover operation. Thus, there will not be a significant impact on a substantial number of small entities under the RFA (5 U.S.C. 601 et seq.). The rule will not cause the business practices of the majority of these companies to change.

Your comments are important. The Small Business and Agriculture Regulatory Enforcement Ombudsman and 10 Regional Fairness boards were established to receive comments from small businesses about federal agency enforcement actions. The Ombudsman will annually evaluate the enforcement activities and rate each agency's responsiveness to small business. If you wish to comment on the enforcement actions of MMS, call toll-free at (888) 734-3247.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

This final rule is not a major rule under 5 U.S.C. 804(2), the SBREFA. The rule will not significantly increase the cost of well-workovers. If there is an increase, it is not a large cost compared to the overall cost of a well-workover. Moreover, it may significantly reduce the possibility of a fatal or environmentally damaging accident during the course of a well-workover. Such an accident could be economically disastrous for a small entity. Based on economic analysis:

a. This rule does not have an annual effect on the economy of $100 million or more. As indicated in MMS's cost analysis, direct annual costs to industry for the rule could not be assessed adequately. The final rule will have a minor economic effect on the offshore oil and gas industries.

b. This rule will not cause a major increase in costs or prices for consumers, individual industries, federal, state, or local government agencies, or geographic regions.

c. This rule does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises.

Paperwork Reduction Act (PRA) of 1995

The final revisions to 30 CFR part 250, subpart F, Oil and Gas Well-Workover Operations, do not change the information collection requirements in current regulations.

OMB has approved the referenced information collection requirements under OMB control numbers 1010-0043 (expiration date October 31, 2007) for 30 CFR 250 subpart F and 1010-0141 (expiration date August 31, 2008) for subpart D Drilling, Form MMS-124, Application for Permit to Modify. The revised sections in the final rule do not affect the currently approved burdens (19,459 approved hours for 1010-0043 and 163,714 for 1010-0141). Therefore, an information collection request (form OMB 83-I) has not been submitted to OMB for review and approval under section 3507(d) of the PRA.

Unfunded Mandates Reform Act (UMRA) of 1995

This rule does not contain any unfunded mandates to state, local, or tribal governments; nor would it impose significant regulatory costs on the private sector. Anticipated costs to the private sector will be far below the $100 million threshold for any year that was established by UMRA.

Takings Implications Assessment (Executive Order 12630)

The Department of the Interior (DOI) certifies that this rule does not represent a governmental action capable of interference with constitutionally protected property rights.

Civil Justice Reform (Executive Order 12988)

DOI has certified to OMB that this regulation meets the applicable civil justice reform standards provided in sections 3(a) and 3(b) (2) of Executive Order 12988.

Federalism (Executive Order 13132)

According to Executive Order 13132, this rule does not have significant Federalism effects. This rule does not change the role or responsibilities of federal, state, and local governmental entities. The rule does not relate to the structure and role of states, and will not have direct, substantive, or significant effects on states.

National Environmental Policy Act (NEPA) of 1969

MMS has analyzed this rule according to the criteria of NEPA and 516 Departmental Manual 6, Appendix Start Printed Page 1131310.4C. MMS reviewed the criteria of the Categorical Exclusion Review (CER) for this action during February 2003, and concluded that this rulemaking does not represent an exception to the established criteria for categorical exclusion, and that its impacts are limited to administrative, economic, or technological effects. Therefore, preparation of an environmental document is not required, and further documentation of this CER is not required.

Consultation and Coordination With Indian Tribal Governments (Executive Order 13175)

In accordance with Executive Order 13175, this final rule does not have tribal implications that impose substantial direct compliance costs on Indian tribal governments.

Start List of Subjects

List of Subjects in 30 CFR Part 250

End List of Subjects Start Signature

Dated: February 17, 2006.

R. M. “Johnnie” Burton,

Acting Assistant Secretary, Land and Minerals Management.

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For the reasons stated in the preamble, MMS amends

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PART 250—OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF

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

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Authority: 43 U.S.C. 1331, et seq., 31 U.S.C. 9701.

End Authority Start Amendment Part

2. In § 250.601, add the following definition for expected surface pressure in alphabetical order:

End Amendment Part
Definitions.

Expected surface pressure means the highest pressure predicted to be exerted upon the surface of a well. In calculating expected surface pressure, you must consider reservoir pressure as well as applied surface pressure.

* * * * *
Start Amendment Part

3. In § 250.615, revise paragraph (e) of the section to read as follows:

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Blowout prevention equipment.
* * * * *

(e) 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 psiBOP system when expected surface pressures are greater than 3,500 psiBOP system for wells with returns taken through an outlet on the BOP stack
Stripper or annular-type well control componentStripper or annular-type well control componentStripper or annular-type well control component.
Hydraulically-operated blind ramsHydraulically-operated blind ramsHydraulically-operated blind rams.
Hydraulically-operated shear ramsHydraulically-operated shear ramsHydraulically-operated shear rams.
Kill line inletKill line inletKill line inlet.
Hydraulically-operated two-way slip ramsHydraulically-operated two-way slip ramsHydraulically-operated two-way slip rams.
Hydraulically-operated pipe ramsHydraulically-operated pipe rams. Hydraulically-operated blind-shear rams. These rams should be located as close to the tree as practicalA 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-workover operations. If you plan to conduct operations without downhole check valves, you must describe alternate procedures and equipment in Form MMS-124, Application for Permit to Modify and have it approved by the District Manager.

(5) You must have a kill line and a separate choke line. You must equip each line with two full-opening valves and at least one of the valves must be remotely controlled. You may use a manual valve instead of the remotely controlled valve on the kill line if you install a check valve between the two full-opening manual valves and the pump or manifold. The valves must have a working pressure rating equal to or greater than the working pressure rating of the connection to which they are attached, and you must install them between the well control stack and the choke or kill line. For operations with expected surface pressures greater than 3,500 psi, the kill line must be connected to a pump or manifold. You must not use the kill line inlet on the BOP stack for taking fluid returns from the wellbore.

(6) You must have a hydraulic-actuating system that provides sufficient accumulator capacity to close-open-close each component in the BOP stack. This cycle must be completed with at least 200 psi above the pre-charge pressure, without assistance from a charging system.

(7) All connections used in the surface BOP system from the tree to the uppermost required ram must be flanged, including the connections between the well control stack and the first full-opening valve on the choke line and the kill line.

* * * * *
Start Amendment Part

4. Amend § 250.616 by revising paragraph (a); redesignating paragraphs (d) and (e) as paragraphs (f) and (g); adding new paragraphs (d) and (e); and revising redesignated paragraph (f) to read as follows:

End Amendment Part
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 high-pressure 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 Start Printed Page 11314BOP systems must be pressure tested with water.

(1) Low Pressure Tests. All BOP system components must be successfully tested 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. All BOP system components must be successfully tested to the rated working pressure of the BOP equipment, or as otherwise approved by the District Manager. The annular-type BOP must be successfully tested at 70 percent of its rated working pressure or as otherwise approved by the District Manager.

(3) Other Testing Requirements. Variable bore pipe rams must be pressure tested against the largest and smallest sizes of tubulars in use (jointed pipe, seamless pipe) in the well.

* * * * *

(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 Form MMS-124, Application for Permit to Modify, and must be approved by the 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 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.

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End Supplemental Information

[FR Doc. 06-2101 Filed 3-6-06; 8:45 am]

BILLING CODE 4310-MR-P