04-13943. 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

AGENCY:

Minerals Management Service (MMS), Interior.

ACTION:

Proposed rule.

SUMMARY:

This proposed rule would upgrade BOP and well control requirements for well-workover operations performed using coiled tubing with the production tree in place. Since 1997 there have been eight incidents on Outer Continental Shelf (OCS) facilities in the Gulf of Mexico OCS Region while coiled tubing operations were being conducted. The proposed rule would contribute to preventing losses of well control, and lead to increased OCS safety and environmental protection.

DATES:

MMS will consider all comments received by August 23, 2004. MMS will begin reviewing comments then and may not fully consider comments received after August 23, 2004.

ADDRESSES:

Mail or hand-carry comments to the Department of the Interior; Minerals Management Service; Mail Stop 4024; 381 Elden Street; Herndon, Virginia 20170-4817; Attention: Rules Processing Team (RPT). If you wish to e-mail comments, the RPT's e-mail address is: [e-mail]. Reference 1010-AC96 Coiled Tubing Safety Measures in your e-mail subject line. Include your name and return address in your e-mail message and mark your message for return receipt. Materials submitted as part of comments will not be returned.

FOR FURTHER INFORMATION CONTACT:

Joseph R. Levine, Engineering and Operations Division, at [phone], FAX: [phone], or e-mail at [e-mail].

SUPPLEMENTARY INFORMATION:

Background

MMS is authorized to issue and enforce rules to promote safe operations, environmental protection, and resource conservation on the OCS by the Outer Continental Shelf Lands Act (OCSLA), 43 U.S.C. 1331 et seq. Under this authority, MMS regulates all safety aspects of oil and gas drilling, production, and well-workover operations on the OCS.

A search of MMS's Technical Information Management System (TIMS) database shows that eight coiled tubing related incidents occurred on the OCS from 1997 through March 2003. One of these incidents resulted in a personal injury. Six coiled tubing incidents resulted in losses of well control. Two coiled tubing incidents resulted in fires that caused extensive damage to the facilities. No fatalities were reported to MMS as a result of these incidents.

Based on these eight coiled tubing incidents, MMS has determined that the regulations under 30 CFR 250 subpart F—Oil and Gas Well-Workover Operations, do not adequately address coiled tubing operations with the production tree in place. As such, MMS proposes to amend its rules. These incidents might have been prevented if the proposed rule had been in effect.

One example was the September 9, 1999, loss of well control and fire resulting from coiled tubing operations on Newfield Exploration Inc.'s Ship Shoal Block 354, (OCS-G 15312, Well A-2). An MMS investigation team published OCS Report MMS 2001-009: “Investigation of Blowout and Fire—Ship Shoal Block 354 OCS-G 15312 Well A-2 September 9, 1999,” concerning this incident in January 2001. This report is available from the Gulf of Mexico OCS Regional Office, New Orleans, Louisiana at the following Web address: http://www.gomr.mms.gov/​homepg/​offshore/​safety/​acc_​repo/​accindex.html.

In the Newfield Exploration, Inc., Ship Shoal Block 354 incident, coiled tubing was being snubbed into Well A-2 when it encountered an unidentified obstruction. This obstruction caused it to stop abruptly at about 915 feet. Simultaneously, the coiled tubing buckled, split open between the stripper and the injector head, ultimately resulting in a loss of well control. The coiled tubing contractor closed the pipe and shear rams in the BOP unit, and spooled the coiled tubing string on to the reel. The buckled and parted section of the coiled tubing remained stuck between the stripper assembly and the injector head, preventing the blind rams from completely sealing the well. The contractor then attempted to close the bottom manual valve on the BOP riser assembly, the crown (swab) valve, the surface safety valve, the bottom master valve, and the subsurface safety valve. None of the valves fully closed because coiled tubing remained below the shear rams and across the valve assemblies, resulting in an uncontrolled flow. The operator activated the platform emergency shutdown system (ESD) and all personnel were evacuated. The well ignited on September 12, 1999, and burned intermittently until September 17, 1999. Newfield Exploration, Inc., succeeded in killing the well on September 20, 1999.

In OCS Report MMS 2001-009, the MMS investigation panel found that “The immediate cause of the accident, which led to the uncontrolled flow, was the parting of the coiled tubing above the stripper assembly and the subsequent inability to contain the wellbore fluids.” The panel also found that a contributing cause of the accident was that back pressure valves (BPVs), also referred to as “check valves,” were not installed in the coiled tubing string. BPVs allow the flow of fluids inside the coiled tubing only in the downhole direction, and close immediately if the flow direction reverses. In this example, when the fluid flow reversed its direction there were no BPVs installed to block the flow. BPVs may have prevented the flow of hydrocarbons from the well through the coiled tubing. The uncontrolled flow quickly eroded the coiled tubing string, the BOP stack, and the production tree, creating an unrestricted flow path to the atmosphere that subsequently allowed the well to ignite.

OCS Report MMS-2001-009 further found that Newfield Exploration, Inc., and the coiled tubing contractor had inadequately provided for well control procedures prior to commencing the workover operations. The MMS panel noted that industry-recognized well control practices outlined in American Petroleum Institute (API) Recommended Practice 5C7 “Recommended Practice for Coiled Tubing Operations in Oil and Gas Well Services” (API RP 5C7, First Edition, December 1996) were not followed by Newfield Exploration, Inc. The report stated that:

“Specifically, the slip rams were not set, pipe rams were not manually locked, and the kill line was not installed. Although not currently referenced by the Code of Federal Regulations, the industry guidelines provide safe and prudent practices that should be followed.”

As a result of this statement, MMS reviewed the API RP 5C7 standard for possible incorporation by reference into 30 CFR 250 subpart F—Oil and Gas Well-Workover Operations. The review found that Appendix C—Emergency Responses and Contingency Planning was adequate. However, the main body of the document did not reflect current coiled tubing technologies. Therefore, MMS decided not to incorporate this industry standard into the regulations.

MMS also reviewed the Department of Energy Coiled Tubing Guide for possible incorporation into MMS regulations. After completing its review, MMS concluded that this guide should not be incorporated into the regulations because it addressed only onshore coiled tubing procedures and did not include those used in the offshore oil and gas industry.

As a result of the eight incidents, and after consultations with MMS, API formed a Well Intervention/Well Control Task Group, which is in the process of developing a new industry standard for coiled tubing, hydraulic workover, and wireline operations. The group assisted MMS in understanding the technological aspects of coiled tubing operations and provided the agency with valuable information on this subject, which was used in preparing this proposed rule. MMS has a representative on the Task Group.

The Purpose of This Rule

This proposed rule would update subpart F—Oil and Gas Well-Workover Operations, BOP, and well control requirements for coiled tubing operations with the production tree in place. It would amend 30 CFR 250.601, 250.615(e), and 250.616(a), and add new §§ 250.616(d) and (e). The proposed changes include adding a new definition for expected surface pressures, adding more specific requirements for BOP system components, and updating BOP pressure testing procedures. Some of the key points of this proposal include the following:

• The use of a flow tee or cross, and one set of hydraulically-operated pipe rams placed directly below the flow tee or cross when returns are taken through an outlet on the BOP stack;
• The use of additional BOP equipment for expected surface pressures above 3,500 psi;
• The use of a dual check valve (also known as a back pressure valve or BPV) assembly attached to the coiled tubing connector at the downhole end of the coiled tubing string;
• The use of a kill line and a separate choke line, each equipped with two full-opening valves;
• A pressure test of the coiled tubing connector and dual check valves;
• The use of a hydraulic-actuating system with sufficient accumulator capacity to close-open-close each component in the BOP stack;
• A recording of pressure conditions during BOP tests on a pressure chart or with a digital recorder, unless otherwise approved by the District Manager;
• The ability to hold the required pressure on coil tubing BOP tests for 10 minutes;
• A certification of pressure charts as correct by the operator's representative at the facility;
• A submittal of a stump test plan for approval by the District Manager if such a test is conducted; and
• A definition for expected surface pressure to more clearly articulate what factors should be considered in designing and operating the coil tubing BOP system, and to make the coil tubing section of this subpart consistent with the other types of well-workover operations addressed in the regulations (tree removed).

Procedural Matters

Public Comment

MMS's practice is to make comments, including the names and home addresses of respondents, available for public review during regular business hours. Individual respondents may request that we withhold their home address from the rulemaking record, which will be honored to the extent allowable by law. If you wish your name and/or address to be withheld, you must state this prominently at the beginning of your comment. However, MMS will not consider anonymous comments. All submissions from organizations or businesses, and from individuals identifying themselves as representatives or officials of organizations or businesses, will be made available for public inspection in their entirety.

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 proposed 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 proposed 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 proposal 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 phone, five of the eight coiled tubing operating companies working on the OCS to collect information on the impact this proposed rule would have on their operations. All data indicate that, since the September 9, 1999, Newfield Exploration, Inc., loss of well control incident, these offshore coiled tubing companies have upgraded their field procedures and equipment to the same or a similar process as required by proposed rule. None of the companies in this survey could provide dollar values for the implementation of this proposed rule because they incorporated most of the suggested measures into their work processes in 1999. Some of the coiled tubing operating companies contacted stated that they are already using dual check valves (BPVs) 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, the MMS survey conclusion was that direct annual costs to industry for the entire proposed rule cannot be assessed in dollar value and will have a minor economic effect on the offshore oil and gas industry.

b. This proposed 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 proposed rule.

c. This proposed 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 OCSLA and the Oil Pollution Act of 1990.

Regulatory Flexibility (RF) Act

MMS has determined that this proposed 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 proposal consists of about eight companies specializing in offshore oil and gas coiled tubing technologies. Of these companies, three are considered to be “small.” Of the small companies to be affected by the proposed rule, almost all are represented by the North American Industry Classification System (NAICS) code 211111 (crude petroleum and natural gas extraction). None of these small companies is represented primarily by NAICS codes 486110 (crude petroleum pipelines) and 486210 (natural gas transmission pipelines).

MMS's analysis of the economic impacts of this proposed rule indicates that direct implementation costs to both large and small companies cannot be accurately assessed because the industry has already implemented a majority of the technological requirements required in this proposed rule. The proposed rule will have a minor economic effect on some oil and gas offshore platform operators on the OCS, regardless of company size. This is because, 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 proposed rule would add relatively little to the cost of a well-workover operation. Thus, there would not be a significant impact on a substantial number of small entities under the RF Act (5 U.S.C. 601 et seq.). The proposed rule will not cause the business practices of any 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 [phone].

Small Business Regulatory Enforcement Fairness Act (SBREFA)

This proposed rule is not a major rule under 5 U.S.C. 804(2), the SBREFA. The proposed rule would not increase significantly 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 reduce significantly 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 entire proposed rule could not be assessed adequately. The proposed 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 United States-based enterprises to compete with foreign-based enterprises.

Paperwork Reduction Act (PRA) of 1995

The proposed 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 August 31, 2004) for 30 CFR 250 subpart F and 1010-0045 (expiration date October 31, 2005) for Form MMS-124, Application for Permit to Modify. The revised sections in the proposed rule do not affect the currently approved burdens (19,205 approved hours for 1010-0043 and 16,963 for 1010-0045). 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.

Federalism (Executive Order 13132)

According to Executive Order 13132, the rule does not have significant Federalism effects. The proposed 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.

Takings (Executive Order 12630)

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.

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.

National Environmental Policy Act (NEPA) of 1969

MMS has analyzed this rule according to the criteria of NEPA and 516 Departmental Manual 6, Appendix 10.4C, “issuance and/or modification of regulations.” MMS has reviewed the criteria of the Categorical Exclusion Review (CER) for this action during February 2003, and concluded: “The proposed rulemaking does not represent an exception to the established criteria for categorical exclusion, and its impacts are limited to administrative, economic, or technological effects. Therefore, preparation of an environmental document will not be required, and further documentation of this CER is not required.”

Clarity of This Regulation

Executive Order 12866 requires each agency to write regulations that are easy to understand. MMS invites your comments on how to make this proposed rule easier to understand, including answers to questions such as the following:

(1) Are the requirements in the rule clearly stated?

(2) Does the rule contain technical language or jargon that interferes with its clarity?

(3) Does the format of the rule (grouping and order of sections, use of headings, paragraphing, etc.) aid or reduce its clarity?

(4) Is the description of the rule in the “Supplementary Information” section of this preamble helpful in understanding the rule? What else can be done to make the rule easier to understand?

Send a copy of any comments on how this rule could be made easier to understand to: Office of Regulatory Affairs, Department of the Interior, Room 7229, 1849 C Street, NW., Washington, DC 20240. You may also e-mail the comments to this address: [e-mail]

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

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

List of Subjects in 30 CFR Part 250

• Continental shelf
• Environmental impact statements
• Environmental protection
• Government contracts
• Investigations
• Mineral royalties
• Oil and gas development and production
• Oil and gas exploration
• Oil and gas reserves
• Penalties
• Pipelines
• Public lands-mineral resources
• Public lands-rights-of-way
• Reporting and recordkeeping requirements
• Sulphur development and production
• Sulphur exploration
• Surety bonds

Dated: April 21, 2004.

Rebecca W. Watson,

Assistant Secretary—Land and Minerals Management.

For the reasons stated in the preamble, MMS proposes to amend 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: 43 U.S.C. 1331, et seq.

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

§ 250.601

Definitions.

* * * * *

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

* * * * *

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

§ 250.615

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) Surface BOP system components must be in the following order from the top down:

BOP system when expected surface pressures are less than 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
Stripper or annular-type well control component	Stripper or annular-type well control component	Stripper or annular-type well control component.
Hydraulically operated blind rams	Hydraulically operated blind rams	Hydraulically operated blind rams.
Hydraulically operated shear rams	Hydraulically operated shear rams	Hydraulically operated shear rams.
Kill line outlet	Kill line outlet	Kill line outlet.
Hydraulically operated two-way slip rams	Hydraulically operated two-way slip rams	Hydraulically operated two-way slip rams.
Hydraulically operated pipe rams	Two sets of hydraulically operated pipe rams Hydraulically operated blind-shear rams. These rams should be located as close to the tree as practical	Hydraulically operated pipe rams. A flow tee or cross. Hydraulically operated pipe rams. Hydraulically operated blind-shear rams (on wells with surface pressures > 3,500 psi). These 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.

(5) You must have a kill line and a separate choke line. You must equip each line with two full-opening valves. One of the full-opening valves on each line must be a remotely controlled valve, and the other valve must be a manual valve. 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 connect them to the well control stack. For operations with expected surface pressure of 3,500 psi or greater, the kill line must be connected to a pump. You must not use the kill line outlet 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 must be flanged.

* * * * *

4. Amend §250.616 by:

A: Revising paragraph (a);

B: Redesignating paragraphs (d) and (e) as paragraphs (f) and (g); and

C. Revising redesignated paragraph (f); and

D. Adding new paragraphs (d) and (e).

The revised and added paragraphs read as follows:

§ 250.616

Blowout preventer system testing, records, and drills.

(a)(1) Before conducting high pressure tests, all BOP system components must be successfully tested to a low pressure between 200 and 300 psi.

If . . .	Then . . .
Initial pressure on the BOP system is < 300 psi * * *	You may initiate the BOP test.
Initial pressure on the BOP system is > 300 psi but < 500 psi * * *	You must bleed the pressure back to a value between 200 and 300 psi before you begin the test.
Initial pressure on the BOP system is > 500 psi * * *	You must bleed the pressure to zero before you begin the test.

(2) 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. Variable bore rams must be pressure-tested against all sizes of drill pipe in the well excluding drill collars. Surface BOP systems must be pressure tested with water. The annular-type BOP must be successfully tested at 70 percent of its rated working pressure or as otherwise approved by the District Manager. Each valve in the choke and kill manifolds must be successfully, sequentially pressure tested to the ram-type BOP test pressure.

* * * * *

(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. There must be no leaks during the test. 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 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, which must be for 10 minutes. Your representative at the facility must certify the charts as correct.

* * * * *