Oil and Gas and Sulphur Operations on the Outer Continental Shelf-Increased Safety Measures for Energy Development on the Outer Continental Shelf, 50855-50901 [2012-20090]
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[Federal Register Volume 77, Number 163 (Wednesday, August 22, 2012)] [Rules and Regulations] [Pages 50855-50901] From the Federal Register Online via the Government Printing Office [www.gpo.gov] [FR Doc No: 2012-20090] [[Page 50855]] 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 Federal Register / Vol. 77 , No. 163 / Wednesday, August 22, 2012 / Rules and Regulations [[Page 50856]] ----------------------------------------------------------------------- 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, well-completion, 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 well-control 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 Sec. 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 Sec. 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 well-completion, well-workover, and decommissioning operations under Subpart E--Oil and Gas Well-Completion 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 Sec. 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 Sec. 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 [[Page 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 Sec. 250.442 What are the procedure guidelines (safety report requirements for a subsea BOP rec. II.A.1). system? Sec. 250.515 Blowout prevention equipment. Sec. 250.615 Blowout prevention equipment. Sec. Sec. 250.1500 through 250.1510 Subpart O--Well- control and Production Safety Training. Establish new fluid displacement Sec. 250.456 What safe procedures (safety report rec. II.A.2). practices must the drilling fluid program follow? Develop additional requirements or Sec. 250.423 What are the guidelines for casing installation requirements for pressure (safety report rec. II.B.2.6). 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 Sec. 250.415 What must my practices (safety report rec.II.B.3.7). 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 well-control 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; [[Page 50858]] (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: ------------------------------------------------------------------------ Number of Commenter type 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 Sec. 250.141 or departures from such requirements under Sec. 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 Sec. 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-by-section 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 ---------------------------------------------------------------------------------------------------------------- Sec. 250.198(h)(79)--API Standard 65 API Standard 65--Part 2, Isolating BSEE has reviewed API Standard 65-- 2nd edition. Potential Flow Zones During Well Part 2 2nd edition and has Construction, Second Edition was determined that it is appropriate published on December 10, 2010. to incorporate the latest edition The Second Edition incorporates in our regulations. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.198(h)(79)--API Standard 65 Provide clarification on how API RP BSEE developed a compliance table, 2nd edition. 65-2 will be used; will a minimum based on API Standard 65--Part 2 pre-cementing score be required (see Table 4) for guidance. This for each cement job and then Final Rule does not require evaluated after the job also? (or operators to use this table; checklist if using the Second however, the operator may answer Edition). 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 Sec. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.415(f), Sec. 250.416(e).. Will the submittal be with each The operator is required to submit APD, or once for each rig per year the written description of how the unless changed? best practices in API Standard 65-- Part 2 were evaluated and the qualifications of the independent third-party with each APD. ---------------------------------------------------------------------------------------------------------------- [[Page 50859]] Sec. 250.416(d)..................... Confirm that the schematic of the BSEE agrees that the schematics of control system includes location, the control systems should include control system pressure for BOP these items. The location of functions, BOP functions at each control stations are not required control station, and emergency to be submitted. While it is sequence logic. Specifications on critical to have control stations, other requirements should be clear. the actual location of the control stations is not critical. ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(e)..................... Will there be a standard way to BSEE does not require a standard perform shearing calculations for method to perform shearing the drill pipe? 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(e)..................... Will there be a standard of BSEE does not require a standard calculation for the Maximum procedure for MASP or shearing Anticipated Surface Pressure calculations. In Sec. (MASP)? 250.413(f), MASP for drilling is defined along with the considerations for calculations. ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(e)..................... Will the maximum MASP be the rating The MASP for shearing calculations of the annulars? 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(e)..................... Is it a requirement of the deadman Yes, the shear rams installed in to also shear at MASP? the BOP must be able to shear drill pipe at MASP. ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(e)..................... If there is a requirement of the BSEE is researching this issue and deadman to also shear at MASP, may address it in future what usable volume and pressure rulemaking. should remain after actuation? ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(e)..................... Please confirm that operators will BSEE agrees with this comment. We only be required to demonstrate revised Sec. 250.416 to shearing capacity for drill pipe specifically include workstring (which includes workstring and and tubing. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(e)..................... A better requirement would be to BSEE revised this section in this demonstrate shearing capacity for Final Rule to include workstring drill pipe which includes work- and tubing as drill pipe. strings and tubing which is run across the BOP stack. ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(e)..................... Shearing capacity with MASP should BSEE requires the operator to be modified to shearing capacity design for the case in which blind- with mud hydrostatic pressure plus shear rams will be exposed to the a conservative shut-in pressure MASP. BSEE does not agree that we limit set by the operator and need to request operators to contractor where shut-in is provide the internal bore pressure transferred from the annular BOP shear capacity calculation. to Ram BOP. At this point Designing the BOP for the well increased pressure in the cavity design and the conditions in which between the pipe rams and annular it will be used will ensure that preventer should be eliminated. this concern is addressed. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(e)..................... Modify the requirement for blind- BSEE disagrees. The operator is shear rams to reflect the 2,500 required to design for the case in psi maximum pressure limit when which blind-shear rams are exposed placed above all pipe rams and to the MASP. It is possible that immediately below the annular on this situation may occur and this the subsea BOP stack. 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. ---------------------------------------------------------------------------------------------------------------- [[Page 50860]] Sec. 250.416(e)..................... 30 CFR 250.416(e) requires BSEE disagrees with this comment independent third-party and the Final Rule continues to verification of pipe shearing require independent third-party calculations at MASP for the blind- verification. This requirement shear rams in the BOP stack. Prior ensures that everyone will perform to the IFR, this item didn't the calculations, not just prudent require the independent third- operators. Third-party party verification of shear verification provides additional calculations. Prudent operators and necessary assurance that the always do those calculations to blind-shear rams will be able to (1) comply with the law as it was shear the drill pipe at MASP. The written and (2) feel comfortable additional requirements in this that pipe can be sheared in an rulemaking are intended to support emergency. The requirement for existing requirements and not independent third-party replace them. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(f)..................... The reliability and operability of BSEE disagrees. The operator must the BOP can be confirmed without pull the BOP stack to surface and bringing the entire BOP and Lower complete a between-well Marine Riser Package (LMRP) to inspection. The required surface after each well, by visual inspection is more thorough than a inspection of a subsea BOP with an visual inspection by an ROV and ROV and through a thorough will help ensure the integrity of function and pressure testing the BOP stack. As required in Sec. process. Any regulation that would 250.446(a), a between well require the operator to pull the inspection must be performed stack to surface, handle the according to currently riser, and re-run it introduces incorporated API RP 53, sections more risk to personnel, well bore, 17.10 and 18.10, Inspections. The and equipment. The proposed new stump test of the subsea BOP API RP-53, 4th Edition, states: before installation was already ``Section 18.2 Types of Tests. required under Sec. 250.449(b) This section addresses the types as it existed before promulgation of tests to be performed and the of the IFR. To conduct a stump frequency of when those tests are test, the BOP must be located on to be performed, realizing that the surface. The BOP inspection the BOP can be moved from well-to- was a recommendation in the Safety well without returning to surface Measures Report. 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. Sec. 250.416(f)..................... 30 CFR 250.416(f) requires that an BSEE does not specify how the third- independent third-party verify party verifies that the BOP has that a subsea BOP stack is fit for not been compromised or damaged purpose. Section 250.416(f)(2) from previous service. As required further requires that the subsea in Sec. 250.446(a), a between- BOP stack has not been compromised well inspection must be performed or damaged from previous service-- according to API RP 53, sections no guidance is given on how one is 17.10 and 18.10, Inspections. The to determine that the subsea BOP requirement to conduct a stump hasn't been compromised or damaged. test of the subsea BOP before For multi-well projects where it installation existed before makes senses to hop the BOP stack promulgation of the IFR, under from well to well, would a Sec. 250.449(b). The operator successful subsea function test may not hop the BOP stack from and pressure test be sufficient well to well and be in compliance evidence that the requirement has with the new provisions of this been met?. section or the previously existing requirements under Sec. 250.449(b). Sec. 250.416(f)(2).................. This requirement infers that an In Sec. 250.416(f)(2), BSEE does inspection of the BOP system is not specify how the third-party required to ensure the system has verifies that the BOP has not been not been compromised or damaged compromised or damaged from from previous service. Please previous service. However, BSEE confirm that the agency agrees has requirements for between-well that a subsea BOP system is not inspections in Sec. 250.446(a), compromised or damaged provided it and stump testing prior to can be function tested and installation in Sec. 250.449(b). 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 Sec. 250.416(f)(2). ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(f)(2).................. If it is mandated that a visual The full cost to pull a subsea BOP inspection between wells is to the surface following an required then the cost to activation of a shear ram or lower implement of $1.2 MM is grossly marine riser package (LMRP) understated. The cost to pull a disconnect (under Sec. BOP for a visual inspection is 250.451(i)) in the benefit-cost underestimated. The cost of analysis is estimated to be $11.9 pulling a subsea BOP for a visual million dollars. This amount is inspection would result in a $5- within the range suggested by the $15 million opportunity cost. 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 Sec. 250.446(a). Because this requirement is not a new provision, no compliance costs are assigned in the economic analysis. ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(f)(2).................. Third-party verification that the An independent third-party must BOP stack has not been compromised confirm that the BOP stack matches or damaged from previous service the drawings and will operate can be accomplished by successful according to the design. The third- subsea function and pressure tests party verification must include without visual inspection. Between verification that: well visual inspections of the BOP internal components is not required. (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; [[Page 50861]] (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 Sec. 250.446(a), and stump testing prior to installation in Sec. 250.449(b). ---------------------------------------------------------------------------------------------------------------- Sec. 250.416(g) Qualification for The requirements for independent In response to comments, BSEE Independent Third Parties. third parties to conduct BOP removed the option for the inspections fail to provide independent third-party to be an globally consistent standards API-licensed manufacturing, necessary for the lifecycle use of inspection, or certification firm Mobile Offshore Drilling Units in Sec. 250.416(g)(1) because (MODUs) on a global basis. The API does not license such firms. Interim Rule allows for an API Section 250.416(g)(1) allows licensed manufacturing, registered professional engineers, inspection, certification firm; or or a technical classification licensed engineering firm to carry society, or licensed professional out independent third-party engineering firms to provide the verification of the BOP system, as independent third-party well as technical classification verification. societies. We recommend that the Section 250.416(g)(2)(i) requires Interim Rule be amended to only the operator to submit evidence enable organizations with the that the registered professional necessary breadth and depth of engineers, or a technical engineering knowledge, and classification society, or experience and global reach, and licensed professional engineering demonstrable freedom from any firms or its employees hold conflict of interest, such as appropriate licenses to perform classification societies, can the verification in the qualify as `independent third appropriate jurisdiction, and parties'. We believe that owing to evidence to demonstrate that the the global employment of MODUs, individual, society, or firm has where rigs could be engaged the expertise and experience anywhere around the world, only necessary to perform independent technical verifications. BSEE may accept the classification societies have the verification from any firm or global reach to ensure consistency person that meets these in inspection and verification of requirements. We will not require safety critical equipment the exclusive use of technical necessary to ensure the safe classification societies at this operation of an asset throughout time. its lifecycle. ---------------------------------------------------------------------------------------------------------------- Sec. 250.420(a)(6).................. Certification by a professional The comment supports the engineer that there are two requirements in the IFR. However, independent tested barriers and BSEE clarified the requirement for that the casing and cementing the two independent barriers, design are appropriate. based on other comments. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.420(a)(6), What is the definition of well- BSEE clarified the certification 250.1712(g), and 250.1721(h). completion activities? This is the requirement in Sec. first time it has been mentioned 250.420(a)(6) by removing the term that barriers had to be certified ``well-completion activities,'' by a professional engineer, only because it was redundant in the casing design and cementing were context of that provision. The two mentioned in the past. required barriers are part of the casing and cementing design. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.420(a)(6), Will BOEMRE still check casing There are multiple ways to 250.1712(g), and 250.1721(h). designs based on load cases that calculate the load cases. The are not published? If so, will operator must ensure the well certified plans be rejected due to design and calculations are design reviews within the agency? appropriate for the purpose for Will Agency design reviews be done which it is intended under by Registered Professional expected wellbore conditions. BSEE Engineers (RPE)? If not, what will engineers will conduct the design be the process for approval when reviews. Any issues will be an RPE approved design conflicts resolved with the operator on a with the Agency? Will the Agency case-by-case basis. mandate a change and take the responsibility for that change? Sec. Sec. 250.420(a)(6), Liabilities that will be placed The intent of the PE certification 250.1712(g), and 250.1721(h) onto a ``Professional Engineer'' is to ensure that all plans are Professional Engineer. are an issue. The PE approach consistent with standard demands that the PE is intimately engineering practices. To add to involved in all aspects of the safety assurances, BSEE included design and also in primary language in Sec. 250.420(a)(6) communication as the well is that the Professional Engineer be drilled and small variations in involved in the design process. the plan are made or happen. All Such person must be included in liability for the well must remain the design process so that he or with the operator without any she is familiar enough with the ``dilution'' to a PE, although final design to make the required review by a PE or other certification. Under Sec. ``independent and reputable'' 250.146(c), persons actually third-party is totally appropriate. 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. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.420(a)(6), Can the required ``registered Yes, the registered professional 250.1712(g), and 250.1721(h) professional engineer'' be a engineer can be a company Professional Engineer. company employee? employee. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.420(a)(6), Require that all certifications BSEE disagrees that the 250.1712(g), and 250.1721(h) needed by a Registered professional engineer must be a Professional Engineer. Professional Engineer be done by a petroleum engineer; a professional Registered Professional Petroleum engineer with another background Engineer. It makes no sense at all who has expertise and experience to utilize any PE. If so, at least in well design will be capable of require a BS in Petroleum certifying these plans. The Engineering. There is no expectation is that a licensed specification to determine how any professional engineer will NOT Registered Professional Engineer certify anything outside of their is ``capable of reviewing and area of expertise. However, in certifying that the * * * is response to the commenter's appropriate for the purpose for concern, this Final Rule adds an which it is intended under expertise and experience expected wellbore conditions.'' requirement for the person performing the certification. ---------------------------------------------------------------------------------------------------------------- [[Page 50862]] Sec. Sec. 250.420(a)(6), The intent of Congress and the Act The certification requirement is 250.1712(g), and 250.1721(h). does not appear to be complied intended to ensure that all with by the proposed rule. The use operators meet basic standards for of a registered Professional their cement and casing. This Engineer to certify casing and requirement for PE certification cementing programs when ``The is a substantial improvement Registered Professional Engineer compared to previous rules in must be registered in a State of which a certification was not the United States but does not mandatory. The final rule has have to be a specific discipline'' added a provision to assure that a does not appear to comply with the licensed professional will NOT allowance for coordination with certify anything outside of his or local Coastal Affected Zone States her area of expertise and to have input. Two deficiencies experience. Because OCS projects are apparent. One is a licensed occur offshore from several professional engineer should not states, a company may want to use be certifying anything that he is the same PE regardless of the not competent to certify due to location of any given well. his education, training and Furthermore, the certification experience. The second is that the requirement applies uniformly to engineer should be licensed in the any project in Federal waters. Coastal Zone Affected State due to Under these conditions, the the differences that occur in certification standard combined licensing requirements. Some with the liabilities associated states are more liberal than with certification of a plan others in the exemptions allowed effectively address certification and the requirements for concerns. Also, States with discipline specific engineering approved coastal management licensure. If Texas wants to allow programs have adequate a higher risk then Texas offshore opportunities to express their Coastal Affected Zones should be concerns about specific projects the only zones that are allowed to under other provisions of the have such higher risk to be taken. regulations. 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. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.420(a)(6), BOEMRE now requires a Registered BSEE disagrees that the 250.1712(g), and 250.1721(h). Professional Engineer to certify a professional engineer must be a number of well design aspects petroleum engineer; a professional including: casing and cementing engineer with another background design, independent well barriers, who has experience in well design and abandonment design. This is a will be capable of certifying new, important requirement. BOEMRE these plans. In response to does not, however, require that commenters' concerns, we have the engineer be certified as a added an expertise and experience Registered Professional Engineer requirement for the certifying in any particular engineering person. It is the operator's discipline. This creates the responsibility to ensure that the possibility that a Professional Registered Professional Engineer Engineer, with little or no is qualified and competent to experience with oil and gas well perform the work and has the design, drilling operations or necessary expertise and well pressure control could be experience. The expectation is certifying these designs. For that a licensed professional example, BOEMRE's rule would allow engineer will NOT certify anything an electrical engineer to certify outside of his or her area of a well design that may have no expertise. The operator certainly expertise or experience on has a strong incentive to assure offshore well construction design. that the professional engineer is We recommend that the Registered competent because the operator is Professional Engineer requirement responsible for the activities on be limited to the discipline of the lease and the consequences Petroleum Engineering, and/or a thereof. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.420(a)(6).................. 30 CFR 250.420(a)(6) requires that Requiring a Registered Professional a Registered Professional Engineer Engineer's certification helps to certify barriers across each flow ensure that the casing and path and that a well's casing and cementing design meets accepted cementing design is fit for its industry design standards. The intended purpose under expected expectation is that licensed wellbore conditions. There are professional engineers will NOT RPE's whose area of expertise certify anything outside of their isn't well design or construction. area of expertise. In response to There are very few drilling and this comment, this Final Rule does completion engineers with both expand the persons who can make sufficient expertise to make the the required certification if they required assessment and a PE are registered and have the license. What in this requirement requisite expertise and makes operations in the GoM safer? experience. 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? ---------------------------------------------------------------------------------------------------------------- [[Page 50863]] Sec. Sec. 250.420(a)(6), The description of ``flow path'' BSEE revised the regulatory text in 250.1712(g) and 250.1721(h). would be improved by commenting on Sec. 250.420(b)(3) to include an examples and/or by providing a example of barriers for the definition and not including annular flow path and for the potential paths, i.e., previously final casing string or liner. Once verified or tested mechanical an operator performs a negative barriers are accepted without test on a barrier, the operator retest. Flow paths in the broadest does not have to retest it unless terms would include annular seal that barrier is altered or assemblies which may not be modified. Also, see the subsequent accessible on existing wells. The comment responses that address the assumption that all casing strings flow paths to which the barrier can be cut and pulled would result requirements apply. in exceptions in the majority of cases and would introduce a health and safety risk to operating personnel and equipment currently not present. ---------------------------------------------------------------------------------------------------------------- Sec. 250.420(a)(6).................. Will BOEMRE still check casing BSEE engineers will check casing designs based on load cases that designs. BSEE will resolve any are not published? If so, will differences with the operator on a certified plans be rejected due to case-by-case basis. design reviews within the agency? ---------------------------------------------------------------------------------------------------------------- Sec. 250.420(a)(6).................. BOEMRE has not provided specific While the list provided by the guidance on what aspects of casing commenter contained some good and cementing designs must be examples, it is not comprehensive. initially certified or guidance on If an activity triggers the need triggers which would cause a plan for a revised permit or an APM, to be recertified for continuance then the Registered Professional of operations. The Offshore Engineer must recertify the Operators' Committee OOC provided design. BSEE is working to improve those triggers to BOEMRE on consistency among the District October 12, 2010, and requests Offices. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.420(b)(3).................. Add clarification to the dual In response, this Final Rule mechanical barrier requirement to revises Sec. 250.420(b)(3) to ensure the barriers are installed provide that for the final casing within the casing string and does string (or liner if it is the not apply to mechanical barriers final string), an operator must that seal the annulus between install one mechanical barrier, in casings or between casing and addition to cement, to prevent wellhead. Acceptable barriers for flow in the event of a failure in annuli shall include at least one the cement. In response to the mechanical barrier in the wellhead comment, we also clarify that a and cement across and above dual float valve, by itself, is hydrocarbon zones. Placement of not considered a mechanical cement can be validated by return barrier. The appropriate BSEE volume, hydrostatic lift pressure District Manager may approve or cased hole logging methods. alternatives. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.420(b)(3).................. Does the dual mechanical barrier BSEE revised the regulatory text at requirement apply to just the Sec. 250.420(b)(3) to clarify inside of the casing or to both the requirement that two the inside and annulus flow paths? independent barriers are required Our interpretation is the inside in each annular flow path of the casing. It is also not (examples include, but are not clear when these dual barriers are limited to, primary cement job and required. seal assembly) and for the final casing string or liner. The appropriate BSEE District Manager may approve alternatives. Sec. Sec. 250.420(b)(3), The incorporation by reference of BSEE revised the language in Sec. 250.1712(g) and 250.1721(h). API RP 65-2 in Sec. 250.415(f) 250.420(b)(3) to clarify that the includes a definition of a operator must install two mechanical barrier. This either independent barriers to prevent confuses or contradicts the use of flow in the event of a failure in the phrase ``mechanical barrier'' the cement, and clarified that a in sections Sec. Sec. dual float valve is not considered 250.420(b)(3), 250.1712(g) and a barrier. The appropriate BSEE 250.1712(h). The description of a District Manager may approve ``seal achieved by mechanical alternative options. BSEE revised means between two casing strings the language in Sec. Sec. or a casing string and the 250.1712 and 250.1721 to clarify borehole'' would not be possible the requirements. For wells being regarding an existing well, permanently abandoned and wellhead specifically for the temporary or removed, the PE needs to certify permanent abandonment, and does that there are two independent not include seals that are not in barriers in the center wellbore an annulus. Question: Do cast iron and the annuli are isolated per bridge plugs and retainers/packers the regulations at Sec. without tubing installed meet the 250.1715. If the wellhead is being requirement for mechanical left in place for the production barriers? 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 case-by-case basis. ---------------------------------------------------------------------------------------------------------------- [[Page 50864]] Sec. 250.420(b)(3).................. The rules seem to encourage use of BSEE revised this section in the devices described in Section 3 of Final Rule to clarify the RP 65, some of which have never requirement of two independent been used in deepwater and are in barriers, and also clarified that fact of dubious utility. It is a dual float valve is not agreed that more stringent considered a mechanical barrier. cementing practices are in order, The BSEE District Manager may but these proposed rules are too approve alternatives. confusing to serve this purpose. This section needs to be revisited and specific, practical, recommended practices set out. ---------------------------------------------------------------------------------------------------------------- Sec. 250.420(c)..................... 30 CFR 250.420(c) requires that This is a previously existing cement attain 500 psi compressive requirement and therefore not strength prior to drill out. What within the scope of this drives the CS requirement? It's rulemaking. not API RP 65-2. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.420, 250.1712, and Previous guidance/interpretation If an activity triggers the need 250.1721. issued by BOEMRE said that for a revised permit or an APM, deviation from certified then the Registered Professional procedures required contact with Engineer must recertify the design the appropriate BSEE District and the revised permit or Manager. This is documented only Application for Permit in the guidance and is not Modification (APM) must receive implicit in this part of the rule. approval from the appropriate BSEE We request that BOEMRE specify the District Manager. kinds of variances that require this contact. ---------------------------------------------------------------------------------------------------------------- Sec. 250.423(b)..................... Need definition or clarity around BSEE has revised the language in the term--lock down and the Sec. 250.423(b), to clarify that requirement for locking down a the Final Rule does not require drilling liner. Must all liner the use of a latching or lock down hangers have hold down slips? mechanism for a liner. However, if Normally conventional line hangers a liner is used that has a only have hang off slips to latching or lock down mechanism, transfer the weight of the liner then that mechanism must be to the previous casing string. engaged. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.423(b)..................... As currently drafted, Sec. BSEE revised the language for the 250.423(b) requires negative requirements for a negative test testing to be set to either 70 under Sec. 250.423(c). The percent of system collapse operator must perform a negative resistance pressure, saltwater pressure test on all wells that gradient, or 500 psi less than use a subsea BOP stack or wells formation pressure, whichever is with mudline suspension systems to less. The rule implies that ensure proper casing or liner operators are required to perform installation. You must perform the a test on the casing seal; negative test to the same degree however, the industry has had of the expected pressure once the several examples of where testing BOP is disconnected. BSEE also to a salt water gradient to sea revised the language for the floor has caused casing collapse requirement to ensure proper in deep wells with casing across installation of the casing in the the salt. This regulation does not subsea wellhead and liner in the clearly state whether it applies liner hanger in Sec. 250.423(b). to casing shoe extensions, such as Regarding lockdown mechanisms, see expandable casing or 18'' (which previous comment. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.423(b)..................... The operator must perform a BSEE agrees with this comment. pressure test on the casing seal Section 250.423(b) requires assembly to ensure proper performance of a pressure test on installation of casing or liner. the casing seal assembly and The operator must ensure that the further requires the operator to latching mechanisms or lock down maintain the necessary mechanisms are engaged upon documentation. installation of each casing string or liner. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.423(b)(1).................. Not clear if integral latching Under Sec. 250.423(b)(1), the capability of casing hanger/seal operator must ensure proper assembly is acceptable or if a installation of casing in the separate mechanism is required. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.423(c)..................... What is the design basis and The regulations do not specify a acceptance criteria required for particular design basis for the negative testing? negative pressure test. Under Sec. 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 Sec. 250.423(c)(5) to include examples of indications of failure. ---------------------------------------------------------------------------------------------------------------- [[Page 50865]] Sec. 250.423(c)..................... It is imperative that the operator Operators are required to submit establish what is ``normal'' for the procedures of these tests and this type of testing event, such provide their criteria for a that the rig crew is in no doubt successful test with their APD. as to what to look for and whether BSEE revised the regulatory text or not there is an event going on to include examples of indications which is ``not normal''. of a failed negative pressure test. ---------------------------------------------------------------------------------------------------------------- Sec. 250.423(c)..................... What is the definition of BSEE revised Sec. 250.423(c) to intermediate casing? The rule clarify the requirements for the states a negative pressure test is negative pressure test. required for intermediate and Intermediate casing is any casing production casing. If drilling string between the surface casing liners are set below intermediate string and production casing casing is additional negative string. We revised the Final Rule testing required? to require negative pressure tests The intent of this requirement is only on subsea BOP stack and wells not clear. The magnitude of the with mudline suspension systems. negative test is also not We specifically require the apparent. Is the intent to test operator to perform a negative the entire casing, wellhead, liner pressure test on the final casing top, or the shoe? Surface string or liner, and prior to wellheads are negative tested for unlatching the BOP at any point in each BOP test when the stack is the well (if the operator has not drained and water is used for a already performed the negative test. If a negative test of an test on its final casing string or intermediate shoe is intended, liner). At a minimum, the negative then, what is the purpose since test must be conducted on those the casing shoe will be drilled components that will be exposed to out. In general, negative testing the negative differential pressure should not apply to all wells and that will occur when the BOP is should apply if the load is disconnected. The intent of the anticipated and then not until requirement is to ensure that the such time it is needed. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.423(c)..................... Wells with surface wellheads should We agree that as a general matter be exempt from negative tests wells with surface well heads unless the well is to be displaced should be exempt from negative to a fluid less than pore pressure pressure tests and we revised the and in that case the shoe, Final Rule to require the negative productive intervals, and liner pressure test only for wells that tops can be negative tested to the use a subsea BOP stack or wells amount anticipated prior to or with mudline suspension systems. during the displacement. The We did, however, provide that if requirement to negative test wells circumstances warrant, the BSEE with surface wellheads should not District Manager may require an be mandated since the well can be operator to perform additional displaced to a fluid less than negative pressure tests on other pore pressure under controlled casing strings or liners (e.g. conditions without risk of an intermediate casing string or influx getting in a riser. liner) or on wells with a surface BOP stack. ---------------------------------------------------------------------------------------------------------------- Sec. 250.423(c)..................... Additional guidance given by BOEMRE All liner tops, exposed below the has indicated a desire to negative intermediate casing (wells with test all liner tops exposed in mudline suspension systems) must either the intermediate or be tested, but only for wells with production annulus on all wells subsea BOP stacks or wells with with surface BOP equipment. This mudline suspension systems. The requirement is not consistent with test must be performed before the desire to improve safety since displacing kill weight fluids in many liner tops are never exposed preparation for disconnecting the to negative pressures during the BOP stack. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.423(c)..................... The Agency has not provided This Final Rule revises Sec. guidance on when the test is to be 250.423(c) to state that the performed. Testing upon negative pressure test must be installation is not advisable due performed on the final casing to additional pressure cycles string or liner, and prior to applied to the cement early in the unlatching the BOP at any point in development of its strength that the well. The negative test must could result in premature cement be conducted on those components, failure. Additionally, if a at a minimum, that will be exposed negative load is anticipated to the negative differential during operations, it is best to pressure that will be seen when defer the negative test to assure the BOP is disconnected. well integrity is validated just prior to the intended operation. ---------------------------------------------------------------------------------------------------------------- Sec. 250.423(c)..................... Negative testing should be BSEE agrees with the comment. We performed on subsea wells and revised Sec. 250.423(c) to wells with mudline suspension require the negative pressure systems where it is important to tests only on wells that use a validate barriers prior to removal subsea BOP stack or wells with of mud hydrostatic pressure during mudline suspension systems. See an abandonment or suspension the response to the previous activity such as hurricane comment. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.423(c)..................... The magnitude and duration of an We revised the Final Rule to acceptable negative test should be require the negative test be provided for consistency. performed to the same degree of Recommend negative tests on subsea the expected pressure once the BOP wells to be equal to SWHP at the is disconnected. wellhead. ---------------------------------------------------------------------------------------------------------------- [[Page 50866]] Sec. 250.423(c)..................... 30 CFR 250.423(c) requires negative BSEE agrees. We revised this testing of intermediate casing and requirement to require the liner tops, but offers no guidance negative pressure tests only on as to the magnitude of the wells that use a subsea BOP stack required negative test. As an or wells with mudline suspension experienced deepwater driller, systems. See the response to the I've assumed that BOEMRE meant for previous comments. 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). ---------------------------------------------------------------------------------------------------------------- Sec. 250.442........................ Must heavy weight drill pipe be Blind-shear rams must be capable of shearable with blind shear rams? shearing any drill pipe in the hole under maximum anticipated surface pressure, including heavyweight drillpipe. This Final Rule revises Sec. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.442........................ What does ``operable'' mean for The provision under Sec. dual pod controls? Does it mean 250.442(b), for an ``operable dual- 100 percent functional and pod control system'' was an redundant? 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.442........................ In Sec. 250.442(c), what does As specified in Sec. 250.442(c), ``fast'' mean for subsea closure the accumulator system must meet and what are the ``critical'' or exceed the requirements in API functions? RP 53, section 13.3, Accumulator Volumetric Capacity. ---------------------------------------------------------------------------------------------------------------- Sec. 250.442........................ What will be competency basis for The operator must ensure that all qualification of an individual to employees and contract personnel operate the BOP's? can properly perform their duties, as required under Sec. 250.1501. Section 250.442(j) prescribes training and knowledge requirements for persons authorized to operate critical BOP equipment. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.442(d), Sec. While the verified ability to close We agree that there is a time delay 250.515(e), and Sec. 250.615(e). one set of pipe rams, close one associated with the launch and set of blind-shear rams, and deployment of an ROV and that unlatch the lower marine riser preventative and precautionary package using a Remotely Operated measures are a priority and Underwater Vehicle (ROV) is immediate shut-in capability is critical, the time delay critical. The intent of the associated with launch and subsea provision is to ensure that an ROV deployment of an ROV will likely is available in the unlikely event have enabled the full force of a that all other measures fail. This major blowout to already clear the regulation is intended to address well bore and result in excessive broad issues related to well- pressures and a debris stream at control; BSEE is planning future the BOP that can complicate regulations that will focus on efforts to shut in the well. preventative measures and Preventive and precautionary improving immediate response measures are a priority, and capabilities. 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. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.442(e), 250.515(e), The ROV crews should not be BSEE agrees with the substance of and 250.615(e). required on a continuous basis, this comment and has revised Sec. this item needs to be revised to 250.442(e) accordingly. reflect the need for having a trained ROV crew on board only when the BOP is deployed. ---------------------------------------------------------------------------------------------------------------- Sec. 250.442(j)..................... What is meant by operate critical Section 250.442(j) establishes BOP equipment, maintenance, or minimum requirements for personnel activation of equipment? who operate any BOP equipment. The paragraph expressly refers to BOP hardware and control systems. In addition, other paragraphs of Sec. 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. ---------------------------------------------------------------------------------------------------------------- [[Page 50867]] Sec. Sec. 250.446(a), 250.516(h), The recordkeeping requested should Under Sec. 250.146(c), lessees, 250.516(g), and 250.617 (Section be a responsibility of the operators, and persons performing numbers refer to the IFR.). drilling contractor. Many an activity subject to regulatory operations are short lived requirements are jointly and contracts and once the rig is severally responsible for released, the contractor has no complying with regulatory obligation to ensure the records requirements. This includes remain on the rig. Drilling contractors maintaining and contractors should be required to inspecting BOP systems. See the have a BOPE certification program discussion in the section-by- complete with a certificate of section portion of this preamble. 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. Certification documents for rental BOPE would also be used by the operator or contractor depending upon who is renting the equipment. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.446(a), 250.516(h), We believe that API-recommended BSEE already requires operators to 250.516(g), and 250.617 (Section practices have not proven to be a follow Sections 17.10 and 18.10, numbers refer to the IFR.). standard that has generated full Inspections; Sections 17.11 and and verifiable compliance by all. 18.11, Maintenance; and Sections Require documentation of BOP 17.12 and 18.12, Quality inspections and maintenance Management, described in API RP according to API RP 53. The 53, Recommended Practices for codification of API-recommended Blowout Prevention Equipment practices via Federal regulations Systems for Drilling Wells. We will be needed to ensure reliable continually review standards and compliance going forward. This our use of these standards. We may should take place in the current consider additional documentation rule, or, at a minimum, in a from operators in future future rule. rulemaking. ---------------------------------------------------------------------------------------------------------------- Sec. 250.449(h)..................... Are the requirements for function Section 250.449(h) is a previously test for normal or high pressure existing requirement that was function or both? included in the IFR only to make In Sec. 250.449(h), request editorial changes to accommodate change from the required duration new requirements in subsequent from 7 days to 14 days. The basis paragraphs. The requested revision for this is to mitigate the risk is outside the scope of this and exposure due to the additional rulemaking. tripping of pipe out of hole in order to function test blind/shear rams. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.449(j), 250.516(d)(8) Stump test ROV intervention Section 250.449(j) requires the (Section numbers refer to the IFR.). functions. operator must test one set of rams This does not go far enough. This during the initial test on the is insufficient. It is necessary seafloor. In this Final Rule, we that the BOP ROV functions be added that the test of the one set regularly tested at the seabed of rams on the seafloor must be with the ROV that would be used in done through an ROV hot stab to an emergency. The only requirement ensure the functioning of the hot of the stump test should be to stab. BSEE may consider additional test the plumbing. The BOP ROV requirements in future rulemaking. functions should be tested at each BOP test when at operating hydrostatic pressures and temperatures. ---------------------------------------------------------------------------------------------------------------- Sec. 250.449(k)..................... Section 250.449(k) explains: BSEE believes that not testing the ``[f]unction test auto shear and deadman system is a greater risk deadman systems on your subsea BOP than conducting the test. Testing stack during the stump test. You the deadman system on the seafloor must also test the deadman system is necessary to ensure that the during the initial test on the deadman system will function in seafloor.'' We do not recommend the event of a loss of power/ testing the deadman system when hydraulics between the rig and the the stack is attached to a subsea BOP. To help mitigate risk for the wellhead. If the rig experiences a function test of the deadman dynamic positioning incident, system during the initial test on i.e., a drive-off or drift-off the seafloor, we added that there during the test, the only must be an ROV on bottom, so it alternative system available to would be available to disconnect disconnect from the wellhead is the LMRP should the rig experience the ROV intervention system. a loss of stationkeeping event. We Failure to disconnect in time also added clarifications for the could result in serious damage to required submittals of procedures the rig equipment, the well head, for the autoshear and deadman or the well casing. As an function testing, including alternative, we believe it would procedures on how the ROV will be be more appropriate to test the utilized during testing. 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. ---------------------------------------------------------------------------------------------------------------- [[Page 50868]] Sec. 250.449(k)..................... Modify deadman system testing BSEE believes that not testing the requirements to increase safety. deadman system is a greater risk As drafted, operators must test the than conducting the test. Testing deadman system during the initial the deadman system on the seafloor test on the seafloor. is necessary to ensure that the Intentionally disabling the deadman system will function in deadman system increases the risk the event of a loss power/ to personnel, well bore and hydraulics between the rig and the equipment should a ``power BOP. To help mitigate risk for the management'' or ``loss of station function test of the deadman keeping'' incident occur during a system during the initial test on deadman system test. Testing of the seafloor, we added that there the deadman system requires must be an ROV on bottom, so it shutting down of power and would be available to disconnect hydraulic systems to the BOP the LMRP should the rig experience thereby eliminating the ability to a loss of stationkeeping event. We disconnect in a controlled manner also added clarifications for the should a ``power management'' or required submittals of procedures ``loss of station keeping'' for the autoshear and deadman incident occur. As a result, rig function testing, including personnel could be exposed to the procedures on how the ROV will be consequences of a violent release utilized during testing. 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 will review API RP-53, 4th Edition, and decide if it is appropriate for incorporation, after it is finalized. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.449(k), We recommend testing the deadman BSEE believes that not testing the 250.516(d)(9), 250.616(h)(2) (Section system when attached to a well deadman system is a greater risk numbers refer to the IFR.). subsea upon commissioning or than conducting the test. Testing within 5 years of previous test the deadman system on the seafloor but not at every well. If during is necessary to ensure that the the testing time the rig deadman system will function in experiences a dynamic position the event of a loss power/ incident, i.e., a drive off or hydraulics between the rig and the drift off, the only options to BOP. To help mitigate risk for the disconnect from the well are function test of the deadman acoustically (if acoustic system system during the initial test on fitted), or with an ROV. Failure the seafloor, we added that there to disconnect in time could result must be an ROV on bottom, so it in serious equipment damage, and/ would be available to disconnect or damage to the well head. 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. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.449(k) and Stump test the autoshear and On the initial test on the 250.516(d)(9) (Section numbers refer deadman. Test the deadman after seafloor, the operator is required to the IFR.). initial landing. only to test the deadman system. Both the deadman and autoshear The rule requires operators to should be tested on the seabed. submit their test procedures with Moreover the Deadman should the APD or APM for approval. BSEE include a disconnect function. may develop specific test However, the LMRP connector should procedures at a later time. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.451(i)..................... A successful seafloor pressure and After a well-control event where function test of the BOP following pipe or casing was sheared, a full a well-control event also is an inspection and pressure test acceptable means of verifying assures that the BOP stack is integrity. Ram sealing elements fully operable. The rule requires would be compromised before damage the operator to do this only after to the rams themselves would be the situation is fully controlled. 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. ---------------------------------------------------------------------------------------------------------------- Sec. 250.451(i)..................... We believe Sec. 250.451(i) is BSEE agrees with the comment that best read to only require a subsea Sec. 250.451(i) does not apply BOP stack to surface when pipe is to actuation of shear rams on an sheared, rather than actuated on empty cavity. Section 250.451(i) an empty cavity. We request that states that an operator must the agency clarify that the retrieve the BOP if: ``You requirement to pull a subsea BOP activate the blind-shear rams or stack to surface after actuating casing shear rams during a well- the blind shear rams does not control situation, in which pipe apply when the blind shear rams or casing is sheared.'' are actuated on an empty cavity, but applies when pipe is sheared. ---------------------------------------------------------------------------------------------------------------- [[Page 50869]] Sec. 250.456(j)..................... Does this requirement only refer to This Final Rule revises Sec. the end of well during abandonment 250.456(j) to clarify that this or at any time during the drilling requirement applies any time kill- of a well? There are times when weight mud is displaced, putting mud weight is cut prior to the wellbore in an underbalanced drilling out a casing shoe due to state. If the mud weight is cut, exposure of weak formations or but the wellbore will remain in an anticipated lost circulation. overbalanced state, then approval Would approval be required to cut is not required. 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. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.515 and 250.616...... It appears that some of the BSEE agrees that it is important requirements of NTL 2010-N05 which for BOP requirements to be applied to workover BOPs have been consistent, regardless of the omitted in the revision to 30 CFR application or stage of a well. 250.5XX and 250.6XX. Specifically, These requirements should also verification that the blind/shear apply to well-completion and well- is capable of shearing all pipe in workover activities. We changed the well at MASP has been omitted the regulatory text in Sec. Sec. for workover and coiled tubing 250.515 and 250.615 to reflect operations. Verification of this this. In addition, in response to capability is as important in the concern raised by the workover as it is in drilling, for commenter, this Final Rule adds both surface BOPs and subsurface these requirements to subpart Q, BOPs. API RP 16ST, ``Coiled Tubing since the same equipment used in Well-control Equipment Systems'', drilling and workovers may be used Section 12, ``Well-control in decommissioning operations, and Equipment Testing'', should be similar safety risks also exist. referenced in 30 CFR 250.6XX in addition to the reference to API RP 53. BSEE may consider incorporating by reference API RP 16ST, ``Coiled Tubing Well-control Equipment Systems'' in future rulemaking. ---------------------------------------------------------------------------------------------------------------- Sec. 250.1503....................... What is the definition of enhanced The rule does not use the phrase, deepwater well-control training? ``enhanced deepwater well-control Will this require a new training.'' It does require certification of well-control deepwater well-control training schools? for operations with a subsea BOP stack. The operator must ensure that all employees are properly trained for their duties as required in Sec. 250.1501. BSEE expects that operators will integrate the deepwater well- control training requirement into their current subpart O well- control program. ---------------------------------------------------------------------------------------------------------------- Sec. Sec. 250.1712(g), 250.1721(h), Liabilities that will be placed The operator is responsible for all and 250.1715. onto a ``Professional Engineer activities on its lease, (PE)'' are an issue. The PE regardless of requirements for approach demands that the PE is various persons to certify or intimately involved in all aspects verify various aspects of of the design and also in primary operations. Although persons communication as the well is performing certifications and drilled and small variations in verifications have responsibility the plan are made or happen. for their actions, such All liability for the well must responsibility will not eliminate remain with the operator without or diminish the operator's any ``dilution'' to a PE, although responsibilities for compliance review by a PE or other with applicable requirements. ``independent and reputable'' third-party is totally appropriate. ---------------------------------------------------------------------------------------------------------------- Table 2--Topics and General Questions Comments and Responses ---------------------------------------------------------------------------------------------------------------- Topic Comment BSEE response ---------------------------------------------------------------------------------------------------------------- Participate in Standard Development... BOEMRE should participate in API's BSEE agrees that its involvement in open process for adopting industry the standard development process standards on an on-going basis. 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 BSEE agrees that its involvement in revising American Welding the standard development process Society's (AWS) standards. AWS's with AWS and other standards standards committees comply with organizations is important. BSEE ANSI-approved procedures for accepts this and other offers to standards development, which, participate in the development of among other things, guarantee standards that support the mission public and open participation by of BSEE. 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. ---------------------------------------------------------------------------------------------------------------- [[Page 50870]] Subsea BOP Requirements............... More work should be carried out in BSEE reviewed the findings of this area before final various DWH investigations before requirements are identified. In developing the Final Rule. particular, the findings of the Findings from the DWH post-mortem on the Horizon BOP investigation that are within the should be carefully looked at scope of this rulemaking were prior to a ``final rule''. incorporated. BSEE will address other findings in future rules. ---------------------------------------------------------------------------------------------------------------- Blind-Shear Ram Redundancy With this rule, BOEMRE has made the BSEE is considering this Requirements. important first step of requiring requirement for future independent third-party regulations. We do recognize the verification of blind shear ram importance of having redundant capability, but deferred one of safety features on BOP stacks. the most critical safety However, we need to consider all improvements, the requirement to the impacts of such a requirement install redundant blind-shear rams before requiring it by regulation. in each OCS BOP, to a later BSEE has concluded that the rulemaking process. We recommend requirements of the IFR, as that redundant blind-shear rams be modified by this Final Rule, have required for all OCS drilling enhanced operational safety operations as of June 1, 2011. 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 BSEE's incident reporting requirement that OCS operators and requirements are covered in Sec. their contractors report to BOEMRE Sec. 250.187 through 250.190. any accidental event that could Specifically, Sec. 250.188(a)(3) significantly impact well requires the reporting of all integrity or blowout prevention. losses of well-control, including This proposed reporting uncontrolled flow of formation or requirement includes, but is not other fluids; flow through a limited to, any event where diverter; or uncontrolled flow blowout preventer seal material resulting from a failure of may be compromised. surface equipment or procedures. We are looking into expanding the reporting requirements in future rulemaking. ---------------------------------------------------------------------------------------------------------------- Third-party Certifications............ The rule makes repeated references We disagree with the commenter's to third-party ``verification'' of suggestion. The repeated use of certain matters related to well- the concept of independent third- control equipment, including BOPs. party ``verification'' in Sec. The appropriate functional 250.416 and conforming provisions terminology should be of the other subparts derives ``certification,'' rather than directly from various ``verification.'' In industry recommendations of the practice, ``certification'' and Department's May 10, 2010 Safety ``verification'' are different Measures Report, e.g., Safety functions. A party that Measures Report Recommendations ``certifies'' a process is I.A.2 and I.C.7 (pp. 20-21) that different from the party that use the term ``verification.'' The ``verifies'' the certified process preparers of that report appear to is being followed. This is more have understood the distinction than a definitional difference. 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 BSEE will continue to evaluate impact future OCS development. The regulatory changes that could IFR itself estimated the baseline result in offsetting cost savings risk of a catastrophic blowout at for OCS operators as directed by once every 26 years. 75 FR at the President in his January 18, 63365. This estimate for a blowout 2011 executive order, ``Improving in the Gulf of Mexico is even Regulation and Regulatory lower, as it appears the estimate Review.'' used by BOEMRE is based on worldwide catastrophic blowout data. 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. ---------------------------------------------------------------------------------------------------------------- [[Page 50871]] Regulatory Impact Analysis............ The costs for compliance prepared Multiple commenters suggested that by the Agency are not reflective the costs of this rulemaking were of the total cost of compliance not fully captured in the and thus will negatively affect Regulatory Impact Analysis. BSSE both small and large businesses and BOEMRE used the best available more than alleged by the Agency. 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 API Number TVD Water Depth Time to that a blowout may pose more Reach Total Depth 608124001700 problems in deepwater where 28497 6959 ft 200 days drilling a relief well is likely 427084062600 28382 100 ft 390 days to take longer. I find this It is possible that the statement statement troubling. It could be is true, that is due to a considered to imply, that it takes different distribution of TVD in longer to penetrate seawater than shallow and deep water drilling hard rock. As an example, two targets. BOEMRE needs to be drilling targets are at 20,000 rigorous to see if its conjectures feet total vertical depth (TVD). are supported by the data. This is One is in 500 feet of water and part of a pattern of the claim the other is in 5,000 feet of that deep water activities are water. For a well drilled in 500 more risky than shallow water. feet of water an additional 4,500 This assumption is being made by feet of hard rock drilling must be BOEMRE as a result of the completed to reach the target. Deepwater Horizon incident From public well data on the The typical GOM exploratory well in BOEMRE website, I found the shallow water takes less than 30 following pair of wells: 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 A reduction in the number of wells wells annually for the next 20 drilled per year will reduce the years. This is a very important estimated annual compliance costs estimate, since it drives the as well as the corresponding estimates of both the costs and likelihood of a catastrophic benefits. Granted projections of blowout and hence the potential the future in the oil and gas gains from any improvements in industry have been notoriously reliability. How much the new wrong. I see that 160 wells regulatory environment will affect annually as overly optimistic. My future OCS drilling is unknown at reasons are: this time. --Historical data show a declining BSEE estimates the drilling of 160 trend of the most recent years deepwater wells annually for cost with all observations below 160. estimation purposes. The 160 --Deepwater Horizon incident will deepwater wells per year may be lead to less favorable conditions more than will be drilled when for drilling in the Gulf. considering all of the factors --Natural Gas from shale is a major influencing GOM deepwater activity disruption coming to North outside of this specific American energy markets. This is regulation. At the time this analogous to the cellular phone analysis was prepared for the IFR technology replacing land line during the summer of 2010, it was phones in the last 20 years. estimated to be a reasonable A better way of presenting the baseline for the regulatory future benefits and costs is with benefit-cost analysis. One hundred a range of scenarios such as 160, sixty deepwater wells per year can 120 and 80 wells a year. The serve as an upper bound cost Deepwater Horizon incident will estimate for the regulation. If an lead to less favorable conditions estimate of 120 deepwater wells for drilling in the Gulf of Mexico. 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 benefit-cost analysis. ---------------------------------------------------------------------------------------------------------------- Regulatory Impact Analysis............ BOEMRE estimates an equal BOEMRE's estimate, in the IFR, of likelihood of serious damage or an equal likelihood of loss or sinking of a MODU drilling rig damage, is based on the two from a catastrophic blowout event. recorded events for severe damage Press reports indicate the sinking or destruction of deepwater MODUs of Deepwater Horizon was due to in the GOM. This rulemaking bad fire fighting procedures. That requires additional the testing of is, pouring seawater on the LMRP disconnect functionality. A floating vessel causing it to disconnect of a deepwater MODU sink. When the accident report is during a catastrophic event will completed, new standard practices likely protect the MODU from total should emerge for fire fighting loss. BSEE maintains that our with the byproduct of great baseline cost estimate for reduction in the probability of deepwater MODU damage is sinking. reasonable for purposes of this benefit cost analysis. ---------------------------------------------------------------------------------------------------------------- [[Page 50872]] Regulatory Impact Analysis............ The benefit-cost sensitivity The report referenced by the analysis provided no basis for the commenter does indicate that only assumption that reservoirs at 5 of the 20 largest GOM fields are depths of 3,000 feet are generally in water depths greater than 3,000 more prolific than their shallow feet. If the top 20 fields are water counterparts. That statement further analyzed, 6 of the top 20 is contradicted by most recent fields are in water depths of Reserves Report (https:// 2,860 feet or greater and www.gomr.boemre.gov/homepg/ discovered since 1989. Fourteen of offshore/fldresv/2006-able4.pdf) the fields are in water depths 247 which shows of the 20 largest feet or less and discovered in fields in the Gulf of Mexico, only 1971 or earlier. The GOM shelf is five are located in depth greater in decline and few large fields than 3,000 feet. 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 We have reviewed the report by IHS- not consistent with our own Global Insight and found nothing estimates and we strongly that will substantiate, contradict encourage the agency to carefully or otherwise provide compliance review the assumptions that went cost figures for this rulemaking. into your analysis. Moreover, to Since the commenter's own potentially assist you with your estimates were not provided, we examination of the socio-economic cannot evaluate alternative cost costs and consequences of the estimates suggested by the regulation, we have enclosed a commenter. The Final Rule does not report we commissioned by IHS- exclude independents from Global Insight entitled, ``The deepwater drilling. 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. ---------------------------------------------------------------------------------------------------------------- Regulatory Impact Analysis--Small In its notice, BOEMRE included BOEMRE published a separate IRFA on Business Impacts. certain information regarding the December 23, 2010 (75 FR 80717) composition of the oil and gas with a 30 day comment period. The industry and the small business IRFA and the FRFA published with entities--lessees, operators, and the final RIA provide the analysis drilling contractors--that will be required in the Regulatory most affected by this interim Flexibility Act. This includes an rule. BOEMRE estimates that $29 estimate of the number of small million dollars or 15.8 percent of entities affected, a description the IFR's total cost of $183 of reporting, recordkeeping million will be borne by small requirements and evaluation of businesses. This cost would significant alternatives that comprise about 0.36 percent of could minimize the impacts on these small businesses' fiscal small entities while accomplishing year 2009 revenue. the objectives of this rulemaking. 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. 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. ---------------------------------------------------------------------------------------------------------------- [[Page 50873]] Regulatory Impact Analysis--Small A commenter estimated that the The compliance costs for the IFR Business Impacts. rulemaking will increase costs by were estimated using the best $17.3 million for each deepwater available information at the time well drilled with a MODU. This of publication. Neither the IFR cost increase is attributed to nor this Final Rule requires required modification of the well operators to conform to a specific plan and associated casing design casing design, nor do they require that results in the addition of a new designs for well plans. The liner and associated work. 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 A commenter identified $10.45 The Final Rule does not change the Business Impacts Sec. 250.449(h). million in BOP inspection cost existing regulation at Sec. savings per deepwater well. The 250.449(h) which requires a proposal is to function test the function test every 7 days blind-shear rams every 14 days including the blind-shear rams. instead of every 7 days as The 7-day testing requirement required by Sec. 250.449(h). The existed before the Macondo event commenter claims ``prior to the and is not being made more Macondo incident, all the rams on stringent with this rulemaking. the BOP were function tested once The commenter's assertion that a week except for the blind-shear ``prior to the Macondo incident, rams.'' Another commenter claims all the rams on the BOP were that `` * * * frequent function function tested once a week except testing of blind/shears will for the blind-shear rams'' is exacerbate this stack body wear incorrect. The $10.45 million and introduce further exposure to figure does not represent an leakage within the BOP''. 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 Several commenters claim that the BSEE has considered the limited Business Impacts. compliance costs are significantly cost information provided by higher than BOEMRE's estimate. One commenters and new time and cost comment suggests that the ``Final estimates obtained by the bureau Rule will add three to five times since the publication of the IFR. 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. 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 Sec. 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 The BSEE published an IRFA pursuant not satisfy the agency`s statutory to the Regulatory Flexibility Act. obligation under the Regulatory While it was not published with Flexibility Act of 1980, as the IFR, it was published shortly amended. The commenter believes thereafter and made available for that, since there is not a good public comment. The SBA Office of cause exception to the Advocacy stated in its comments Administrative Procedure Act`s that ``Advocacy appreciates notice and comment rulemaking BOEMRE's decision to publish a requirement, BOEMRE was required supplemental IRFA.'' The comments to publish an IRFA at the time of on the IRFA were considered along the proposed rulemaking. Further, with all comments on the the IRFA BOEMRE eventually rulemaking. 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. [[Page 50874]] Regarding the 14,000 discretionary provisions from API standards, BSEE disagrees with the commenter's assertion that Sec. 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 (Sec. Sec. 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 (Sec. 250.125) This Final Rule updates Sec. 250.125(a)(8) and (9) in the chart to reflect accurate numbering redesignation. Documents Incorporated by Reference (Sec. 250.198) Final Sec. 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 Sec. 250.415(f) incorporate by reference API RP 65--Part 2, Isolating Potential Flow Zones During Well Construction. The requirement in Sec. 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. [[Page 50875]] To the extent that the commenters were correct in asserting that the last sentence of Sec. 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, Sec. 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, Sec. 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 Sec. 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? (Sec. 250.415) In the IFR, BOEMRE added a new Sec. 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 Sec. 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 Yes/No. 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]. 2 Have you considered the general well Yes/No. practices while drilling, monitoring and maintaining wellbore stability, curing and preventing lost circulation, and planning and operational considerations? [API 65-2 1.6]. ------------------------------------------------------------------------ FLOW POTENTIAL ------------------------------------------------------------------------ 3 Will a pre-spud hazard assessment be Yes/No. conducted for the proposed well site?. 4 List all potential flow zones within the Describe below. well section to be cemented. 5 Has the information concerning the type, Yes/No. location, and likelihood of potential flow zones been communicated to key parties (cementing service provider, rig contractor, or third parties)? ------------------------------------------------------------------------ CRITICAL DRILLING FLUID PARAMETERS ------------------------------------------------------------------------ 6 Are fluid densities sufficient to Yes/No. maintain well-control without inducing lost circulation?. ------------------------------------------------------------------------ CRITICAL WELL DESIGN PARAMETERS ------------------------------------------------------------------------ 7 Will you use a cementing simulation model Yes/No. in the design of this well?. 7a If yes, how is the output of this Describe below. simulation model used in your decision- making process?. 7b If no, include discussion of why a model Describe below. is not being used. 7c Either way, include the number and Describe below. placement of centralizers being used. 8 Will you ensure the planned top of cement Yes/No. will be 500 feet above the shallowest potential flow zone?. 9 Have you confirmed that the hole diameter Yes/No. is sufficient to provide adequate centralization?. 10 If there are any isolated annuli, how NA or Describe have you mitigated thermal casing below. pressure build-up?. 11 Will you ensure the well will be stable Yes/No. (no volume gain or losses, drilling fluid density equal in vs. out) before commencing cementing operations? 12 List all annular mechanical barriers in Describe below. your design. 13 Has the rathole length been minimized or Yes/No. filled with drilling fluid with a density greater than the cement density?. 14a If you have any liner top packers exposed NA or Describe to the production or intermediate below. annulus, what is the rating for differential pressure across this packer? 14b If you have any liner top packers exposed Yes/No/NA. to the production or intermediate annulus, have you confirmed that your negative test will not exceed this rating? 15 What type of casing hanger lock-down Describe below. mechanisms will be used?. 16 For all intermediate and production Yes/No. casing hangers set in subsea, HP wellhead housing, will you immediately set/energize the lock-down ring prior to performing any negative test? [[Page 50876]] 17 For all production casing hangers set in Yes/No. subsea, HP wellhead housing, will you set/energize the lock-down sleeve immediately after running the casing and prior to performing any negative test? ------------------------------------------------------------------------ CRITICAL OPERATIONAL PARAMETERS ------------------------------------------------------------------------ 18 Will you have 1 mechanical barrier in Yes/No. addition to cement in your final casing string (or liner if it is your final string)?. 19 Do you plan to nipple down BOP in Yes/No. accordance with the WOC requirements in 30 CFR 250.422?. 20 Do you plan on running a cement bond log Yes/No. on the production and intermediate casing/liner prior to conducting the negative test on that string? ------------------------------------------------------------------------ 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 Yes/No. differential pressures?. 25 Surface Equipment issues?................ Yes/No. 26 Will you monitor the annulus during Yes/No. cementing and WOC time?. 27 If using foam cement, is a risk Yes/No. assessment being conducted and incorporated into cementing plan?. 28 If using foam cement, will the foamer, Yes/No. stabilizer, and nitrogen injection be controlled by an automated process system? ------------------------------------------------------------------------ CRITICAL MUD REMOVAL PARAMETERS ------------------------------------------------------------------------ 28 Have you tested your drilling fluid and Yes/No. cementing fluid programs for compatibility to reduce possible contamination?. 29 Have you considered actual well Yes/No. conditions when determining appropriate cement volumes?. 30 Has the spacer been modeled or designed Yes/No. to achieve the best possible mud removal?. ------------------------------------------------------------------------ CRITICAL CEMENT SLURRY PARAMETERS ------------------------------------------------------------------------ 31 Have all appropriate cement slurry Yes/No. parameters been considered to ensure the highest probability of isolating all potential flow zones? 32 Do you plan on circulating bottom up Yes/No. prior to the start of the cement job?. ------------------------------------------------------------------------ What must I include in the diverter and BOP descriptions? (Sec. 250.416) The IFR revised Sec. 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 Sec. 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 blind-shear rams must be capable of shearing heavy weight drill pipe. The Final Rule also revises Sec. 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 Sec. 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 Sec. 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, Sec. 250.416(g)(1) of this section referenced the independent party in Sec. 250.416(e). This Final Rule removes this reference, since the requirements for the independent third-party in paragraph (g) apply to any use of the independent third-party in Sec. 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 third-party 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 third-party 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 [[Page 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 Sec. 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? (Sec. 250.418) This Final Rule revises Sec. 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 Sec. 250.418(h), which requires operators to submit certifications of their casing and cementing program required by Sec. 250.420(a)(6). Paragraph (h) is not revised in this Final Rule. The IFR added Sec. 250.418(i), requiring the operator to submit a description of qualifications of any independent third-party. Paragraph (i) is revised in this Final Rule by changing the cross reference in that paragraph to Sec. 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? (Sec. 250.420) The IFR added Sec. 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, Sec. 250.420(a)(6) also included certification requirements pertaining to two independent tested barriers. This Final Rule reorganizes Sec. 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 Sec. 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 Sec. Sec. 250.420 and 250.423. In that manner, the certification ties into the substantive requirements of the regulations. Final Sec. 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 Sec. 250.420(a)(6) to final Sec. 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, Sec. 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 Sec. 250.420(b)(3) states that an operator must submit documentation of this installation to BSEE in the End-of- Operations 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 Sec. 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? (Sec. 250.423) The IFR reorganized Sec. 250.423 to accommodate new requirements, redesignated the previous regulation as Sec. 250.423(a) and added new Sec. 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 Sec. 250.423(a) to clarify that if pressure declines more than 10 percent in a 30-minute test, or [[Page 50878]] 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 Sec. 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 Sec. Sec. 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 Sec. 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 Sec. Sec. 250.423(b)(2), (b)(3), and (b)(4) in the IFR, are renumbered as Sec. Sec. 250.423(b)(3), (b)(3)(i), and (b)(3(ii)) in this Final Rule. In response to comments, this Final Rule revises Sec. 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 Sec. Sec. 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 Sec. Sec. 250.423(c)(1) and (c)(2) in the IFR have been redesignated as Sec. Sec. 250.423(c)(3) and (c)(4). The redesignated Sec. 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 Sec. 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 Sec. 250.423(c)(7), requiring documentation of the successful negative pressure test in the End-of- Operations Report (Form BSEE-0125). What must I do in certain cementing and casing situations? (Sec. 250.428) This Final Rule revises Sec. 250.428(c) by removing Sec. 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 Sec. 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 Sec. 250.428(c)(1) removed, the Final Rule renumbers the remaining paragraphs as Sec. 250.428(c)(1), (c)(2), and (c)(3). What are the requirements for a subsea BOP system? (Sec. 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 Sec. 250.442(a) to clarify that drill pipe includes workstring and tubing. The IFR redesignated the requirement in previous Sec. 250.442(d) to have an operable dual-pod control system as new Sec. 250.442(b), without substantive change. This Final Rule does not modify the redesignated paragraph. The IFR added Sec. 250.442(d), containing requirements related to ROV intervention capability. This Final rule does not modify these requirements. The IFR added Sec. 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 Sec. 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 Sec. 250.442(f), containing requirements related to autoshear and deadman systems. This Final Rule revises Sec. Sec. 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 Sec. 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 [[Page 50879]] must demonstrate to BSEE, as part of the information submitted under Sec. 250.416, that the acoustic system will function in the anticipated environment and conditions. The following paragraphs were added in the IFR: Sec. 250.442(g), requiring the operator to have operational or physical barrier(s) on BOP control panels to prevent accidental use of disconnect functions; Sec. 250.442(h), requiring the operator to clearly label all control panels for the subsea BOP system; Sec. 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 Sec. 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 Sec. 250.442(l), addressing the use of BOP systems in ice-scour areas. This paragraph duplicated Sec. 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? (Sec. 250.443) This Final rule revises Sec. 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? (Sec. 250.446) The IFR revised Sec. 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 Sec. 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 Sec. 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 Sec. 250.446(a), see Sec. 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? (Sec. 250.449) In conjunction with the changes from the IFR regarding stump test requirements, this Final Rule revises Sec. 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 Sec. 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 Sec. 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 Sec. Sec. 250.449(h) and (i) to account for the new paragraphs following those sections. This Final Rule makes no further changes to Sec. Sec. 250.449(h) and (i). The IFR added Sec. Sec. 250.449(j) and (k). In response to comments that the BOP tests are insufficient, we revised Sec. 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, Sec. 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, Sec. 250.449(j)(2) in the IFR, has been redesignated as Sec. 250.449(j)(3) in this Final Rule. In response to comments, this Final Rule revises Sec. 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 [[Page 50880]] 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 Sec. 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 Sec. Sec. 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? (Sec. 250.451) As described above, this Final Rule revises Sec. 250.451(h), to replace the term ``glory hole'' with the term ``well cellar.'' This Final Rule also adds new Sec. 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 Sec. 250.402, the operator should still follow those guidelines as appropriate. What safe practices must the drilling fluid program follow? (Sec. 250.456) The IFR redesignated then existing Sec. 250.456(j) as Sec. 250.456(k) and added a new Sec. 250.456(j) to require approval from the BSEE District Manager before displacing kill-weight fluid from the wellbore. This Final Rule revises Sec. 250.456(j) to clarify that the operator must receive prior approval before displacing kill-weight fluid from the wellbore and/or riser to an underbalanced state. The IFR required prior approval whenever kill-weight 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 Sec. 250.456(j)(1) to conform the flow path description to that contained in Sec. 250.420(b)(3), and Sec. 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 Well-Completion Operations (Sec. 250.513) In this Final Rule, we added a new Sec. 250.513(b)(4) as a conforming procedural amendment requiring the operator to submit with the APD or APM the BOP descriptions for well-completion operations required in the new Sec. 250.515. This new paragraph does not require information in addition to that already required, but will ensure information required under the new Sec. 250.515 is submitted with the APD or APM. To accommodate the new paragraph (b)(4), this Final Rule redesignates previous Sec. Sec. 250.513(b)(4) and (b)(5) as Sec. Sec. 250.513(b)(5) and (b)(6). Well-Control Fluids, Equipment, and Operations (Sec. 250.514) In response to comments that requirements for well-completion and drilling should be consistent, this Final Rule adds Sec. 250.514(d). This new paragraph makes the requirements for well-control fluids for well-completions consistent with the requirements for drilling (Sec. 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? (Sec. 250.515) In response to comments, this Final Rule adds a new Sec. 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 Sec. Sec. 250.515 through 250.530 as Sec. Sec. 250.516 through 250.531. New Sec. 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 Sec. 250.515(e) requires operators to include the qualifications of the independent third-party performing the verifications. The independent third-party 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 (Sec. Sec. 250.416(c) through (g)). [[Page 50881]] Blowout Prevention Equipment (Sec. 250.515 in the Interim Final Rule, Redesignated as Sec. 250.516 in This Final Rule) The IFR added the requirements of Sec. 250.442 in subpart D, Oil and Gas Drilling Operations, to the requirements in Sec. 250.515 for well-completion operations using a subsea BOP stack. This Final Rule redesignates Sec. 250.515 in the IFR as Sec. 250.516, but makes no further changes to that section. Blowout Preventer System Tests, Inspections, and Maintenance (Sec. 250.516 in the Interim Final Rule, Redesignated as Sec. 250.517 in This Final Rule) The IFR added Sec. 250.516(d)(8) to require tests for ROV intervention functions during the stump test and Sec. 250.516(d)(9) to require a function test of the autoshear and deadman system. This Final Rule redesignates Sec. 250.516 as Sec. 250.517. This Final Rule revises redesignated Sec. 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 Sec. 250.449(b) earlier in this preamble concerning inclusion of the same timeframe in subpart D. This Final Rule revises redesignated Sec. 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 Sec. 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 Sec. 250.517(d)(8) are consistent with changes to final Sec. 250.449(j) as discussed earlier. This Final Rule revises redesignated Sec. 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 Sec. 250.449(k). The IFR revised previous Sec. Sec. 250.516(g) and (h) to expand and clarify the requirements for BOP inspections and maintenance. This Final Rule revises redesignated Sec. Sec. 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 Sec. Sec. 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 Sec. 250.517(g)(2) to be consistent with the subsea BOP system and marine riser inspection requirements in subpart D, Sec. 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 Well-Workover Operations (Sec. 250.613) This Final Rule adds a new Sec. 250.613(b)(3) that requires an operator to submit, with its APM, the information required in the new Sec. 250.615. This new paragraph was added to ensure that BOP descriptions for well-workover operations, required under the new Sec. 250.615, will be submitted with the APM. To accommodate the new Sec. 250.613(b)(3), this Final Rule redesignates Sec. Sec. 250.613(b)(3) and (b)(4) as Sec. Sec. 250.613(b)(4) and (b)(5). Well-Control Fluids, Equipment, and Operations (Sec. 250.614) In response to comments, this Final Rule adds a new Sec. 250.614(d). This new paragraph makes the requirements for well-control fluids for well-workover operations consistent with the requirements in subpart D (Sec. 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? (Sec. 250.615) In response to comments, this Final Rule adds a new section, Sec. 250.615. This new section makes the requirements for submission of BOP information for well-completions consistent with the requirements in subpart D (Sec. Sec. 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 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 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 third- party. 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 [[Page 50882]] 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 Sec. Sec. 250.615 through 250.619 as Sec. Sec. 250.616 through 250.620. Blowout Prevention Equipment (Sec. 250.615 in the Interim Final Rule, Redesignated as Sec. 250.616 in Final Rule) The IFR added new Sec. Sec. 250.615(b)(5) and (e) that applied the requirements of Sec. 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 Sec. 250.616, but does not substantively change the IFR. Blowout Preventer System Testing, Records, and Drills (Sec. 250.616 in the Interim Final Rule IFR, Redesignated as Sec. 250.617 in This Final Rule) The IFR added Sec. 250.616(h) to require an operator to stump test a subsea BOP system before installation. It added Sec. 250.616(h)(1) to require tests for ROV intervention functions during the stump test, Sec. 250.616(h)(2) to require a function test of the autoshear and deadman system, and Sec. 250.616(h)(3) to require the use of water to stump test a subsea BOP system. This Final Rule redesignates this section as Sec. 250.617. This Final Rule revises redesignated Sec. 250.617(h) to be consistent with final Sec. Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 250.617(h)(2)(iii) into the general text of Sec. 250.617(h). What are my BOP inspection and maintenance requirements? (Sec. 250.617 in the Interim Final Rule, Sec. 250.618 in the Final Rule) The IFR added Sec. 250.617 to apply the requirements of Sec. 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 Sec. 250.617 as Sec. 250.618. This Final Rule revises redesignated Sec. 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 Sec. Sec. 250.618(a)(2) be consistent with the subsea BOP system and marine riser inspection requirements in subpart D, Sec. 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 (Sec. 250.1500) In the IFR, BOEMRE added separate definitions for the terms deepwater well-control, well servicing and well-completion/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, 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 well-control 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 well-control equipment for well control purposes. What are my general responsibilities for training? (Sec. 250.1503) In the IFR, the operator is required to ensure that employees and contract personnel are trained in deepwater well-control when conducting operations with a subsea BOP stack. They must have a comprehensive knowledge of deepwater well-control equipment, practices, and theory. We did not make any changes to this section in the Final Rule. When must I submit decommissioning applications and reports? (Sec. 250.1704) This Final Rule revises Sec. 250.1704(g) by adding Sec. 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 Sec. 250.1705, discussed below. What BOP information must I submit? (Sec. 250.1705) In response to comment, this Final Rule adds Sec. 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 Sec. 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 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 test results and [[Page 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 third- party. 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 (Sec. 250.416(c) through (g)). What are the requirements for blowout prevention equipment? (Sec. 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 Sec. 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, Sec. 250.616. What are the requirements for blowout preventer system testing, records, and drills? (Sec. 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 Sec. 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? (Sec. 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? (Sec. 250.1709) In response to comments, we added a new section in the Final Rule. This new section makes the requirements for well-control fluids for well abandonment consistent with the requirements for drilling (Sec. 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? (Sec. 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 Sec. 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 Sec. 250.1715. In response to comments related to Sec. 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 Sec. 250.420(b)(3). How must I permanently plug a well? (Sec. 250.1715) The Final Rule adopts a conforming change to Sec. 250.1715 by adding paragraph (a)(11) which ensures that two independent barriers, as described in Sec. 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 Sec. 250.1712(g), and the amendment to Sec. 250.1715 is necessary to accompany the certification. [[Page 50884]] If I temporarily abandon a well that I plan to re-enter, what must I do? (Sec. 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 Sec. 250.420(b)(3). VI. Compliance Costs The IFR contained a table estimating compliance costs on a section- by-section 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 ---------------------------------------------------------------------------------------------------------------- IFR ($ Final Rule ($ Compliance cost change between IFR Annual recurring costs millions) millions) 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/ 15.5 5.5 Estimated time was reduced. BSEE workover/abandonments). 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 45.1 12.8 Regulation was changed and the (negative pressure test). 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, 10.3 83.0 Regulation was changed from dual one of which must be a mechanical barrier. 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 2.6 2.6 No change. LMRP disconnect. Independent third-party shear certification 1.2 1.2 No change. Paperwork Costs taken from PRA tables in 0.0 4.6 Paperwork costs were not included IFR & Final Rule. in the IFR benefit-cost 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 benefit-cost analysis for this rulemaking was [[Page 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. [[Page 50886]] 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 [[Page 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 Sec. 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, [[Page 50888]] 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--Well-Completions, 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 -------------------------------------------------------------------------------------------------------------------------------------------------------- Annual burden Citation 30 CFR 250 Reporting & recordkeeping requirement Hour burden Average number of hours annual responses (rounded) -------------------------------------------------------------------------------------------------------------------------------------------------------- Subpart D -------------------------------------------------------------------------------------------------------------------------------------------------------- 410-418; 420(a)(6); 423(b)(3), Apply for permit to drill APD (Form BSEE-0123) Burden covered under 1014-0018 0 (c)(3); 449(j), (k)(1); 456(j) plus that includes any/all supporting documentation/ various references in subparts A, evidence [including, but not limited to, test B, D, E, H, P, Q. results, calculations, pressure integrity, verifications, procedures, criteria, qualifications, etc.] and requests for various approvals required in subpart D (including Sec. Sec. 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. -------------------------------------------------- 449(j); 460; 465; 514(d); 515; Provide revised plans and the additional Burden covered under 1014-0018 0 517(d)(8-9); 614(d); 615; 617(h)(1- supporting information required by the cited 2); 1704(g); 1707(d), (h)(1-2); regulations [test results, calculations, 1709; 1712; 1721(h). verifications, procedures, criteria, qualifications, etc.] when you submit an Application for Permit to Modify (APM) (Form BSEE-0124) to BSEE for approval. 416(g)(2)........................... Provide 72 hour advance notice of location of Burden covered under 1014-0018 0 shearing ram tests or inspections; allow BSEE access to witness testing, inspections and information verification. -------------------------------------------------- 416(g)(2)........................... Submit evidence that demonstrates that the 0.25 700 submittals 175 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. -------------------------------------------------- 420(b)(3)........................... Submit documentation of two independent barriers Burden covered under 1014-0018 0 after installation with your EOR. -------------------------------------------------- 420(b)(3)........................... Request approval for alternative options to 0.25 25 requests 7 installing barriers. -------------------------------------------------- 423(a).............................. Request alternative approval for other pressure Burden covered under 1010-0114 0 casing test pressures. -------------------------------------------------- 423(a).............................. Request and receive approval from BSEE District 0.5 88 requests 44 Manager for repair. -------------------------------------------------- 423(b)(3), (c)(4)................... Document pressure casing test results and make Burden covered under 1014-0018 0 available to BSEE upon request. -------------------------------------------------- 423(c)(5)........................... Immediately contact BSEE District Manager when 1 14 notifications 14 problem corrected due to failed negative pressure test; submit a description of corrected action taken; and receive approval from BSEE District Manager to retest. 423(c)(8)........................... Submit documentation of successful negative 2 45 submittals 90 pressure test in the EOR (Form BSEE-0125). 442(f)(3)........................... Demonstrate that your secondary control system 5 1 validation 5 will function properly. -------------------------------------------------- 446(a).............................. Document BOP maintenance and inspection Burden covered under 1014-0018 0 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. -------------------------------------------------- 449(j)(2)........................... Notify BSEE District Manager at least 72 hours 0.25 110 notifications 28 prior to stump/initial test on seafloor. -------------------------------------------------- 449(j)(3) *......................... Document all ROV intervention function test Burden covered under 1014-0018 0 results including how you test each ROV functions; make available to BSEE upon request. 456(j).............................. Request approval from the BSEE District Manager Burden covered under 1014-0018 0 to displace kill-weight fluids to an underbalanced state; submit detailed written procedures with your APD/APM. ---------------------------------------- Subtotal D...................... ................................................ ....................... 983 responses 363 -------------------------------------------------------------------------------------------------------------------------------------------------------- [[Page 50889]] Subpart E -------------------------------------------------------------------------------------------------------------------------------------------------------- 514(d).............................. Request approval from the BSEE District Manager 2 60 requests 120 to displace kill-weight fluids to an underbalanced state; submit detailed written procedures with your APM. 515................................. Submit a description of your BOP and its 15 12 submittals 180 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. 515(e)(2)(ii)....................... Allow BSEE access to witness testing, 0.25 12 notifications 3 inspections, and information verification. Notify BSEE District Manager at least 72 hours prior to shearing ram tests. -------------------------------------------------- 517(d)(8)*.......................... Function test ROV interventions on your subsea Burden covered under 1014-0004 0 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. -------------------------------------------------- 517(d)(8)(ii)....................... Notify BSEE District Manager at least 72 hours 0.25 32 notifications 8 prior to stump/initial test on seafloor. -------------------------------------------------- 517(d)(9)........................... Document all autoshear and deadman test results Burden covered under 1014-0004 0 and submit test procedures with your APM for BSEE Manager approval; make available to BSEE upon request. 517(g)(l)........................... Document BOP inspection procedures used; record Burden covered under 1014-0004 0 results of BOP inspection actions; maintain records for 2 years or longer if directed by BSEE; make available to BSEE upon request. 517(g)(2)........................... Request alternative method/frequency to inspect Burden covered under 1010-0114 0 a marine riser. 517(h).............................. Document the procedures used for BOP maintenance/ Burden covered under 1014-0004 0 quality management; record results; maintain records for 2 years or longer if directed by BSEE; make available to BSEE upon request. ---------------------------------------- Subtotal E...................... ................................................ ....................... 116 responses 311 -------------------------------------------------------------------------------------------------------------------------------------------------------- Subpart F -------------------------------------------------------------------------------------------------------------------------------------------------------- 614(d).............................. Request approval from the BSEE District Manager 2 80 requests 160 to displace kill-weight fluids to an underbalanced state; submit detailed written procedures with your APM. 615................................. Submit a description of your BOP and its 15 40 submittals 600 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. 615(e)(2)(ii)....................... Allow BSEE access to witness testing, 0.25 12 notifications 5 inspections, and information verification. Notify BSEE District Manager at least 72 hours prior to shearing ram tests. -------------------------------------------------- 617(h)(l) *......................... Document all test results of your ROV Burden covered under 1014-0001 0 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. -------------------------------------------------- 617(h)(1)(ii)....................... Notify BSEE District Manager at least 72 hours 0.25 44 notifications 11 prior to stump/initial test on seafloor. -------------------------------------------------- 617(h)(2) *......................... Document all autoshear and deadman test results; Burden covered under 1014-0001 0 submit test procedures with your APM for BSEE District Manager approval; make available to BSEE upon request. 618(a)(l)........................... Document the procedures used for BOP Burden covered under 1014-0001 0 inspections; record results; maintain records for 2 years or longer if directed by BSEE; make available to BSEE upon request. 618(a)(2)........................... Request approval to use alternative method to Burden covered under 1010-0114 0 inspect a marine riser. 618(b).............................. Document the procedures used for BOP Burden covered under 1014-0001 0 maintenance; record results; maintain records for 2 years or longer if directed by BSEE; make available to BSEE upon request. ----------------------------------------------------------------- Subtotal F...................... ................................................ ....................... 176 responses 776 -------------------------------------------------------------------------------------------------------------------------------------------------------- Subpart Q -------------------------------------------------------------------------------------------------------------------------------------------------------- 1705................................ Submit a description of your BOP and its 15 200 submittals 3,000 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. 1705(e)(2)(ii)...................... Allow BSEE access to witness testing, 0.25 12 submittals 3 inspections, and information verification. Notify BSEE District Manager at least 72 hours prior to shearing ram tests. [[Page 50890]] 1706(a)............................. Request approval of well abandonment operations; 0.25 200 requests 50 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. 1706(f)(4).......................... Request approval of the BSEE District Manager to 1 50 requests 50 conduct operations without downhole check values; describe procedures/equipment in APM. 1707(a)(2).......................... Request approval from BSEE District Manager to 0.25 6 requests 2 test annular BOP less than 70 percent. 1707(b)(2).......................... State reason for postponing test in operations 0.25 30 reasons 8 logs. 1707(b)(2).......................... Request approval from BSEE District Manager for 0.25 5 requests 2 alternate test frequencies if condition/BOP warrant. 1707(f)............................. Request alternative method to record test 0.25 25 requests 7 pressures. 1707(f)............................. Record test pressures during BOP and coiled 1 200 records/ 200 tubing on a pressure chart or w/digital certifications recorder; certify charts are correct. 1707(g)............................. Record or reference in operations log all 0.5 200 records 100 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. 1707(h)(1).......................... Submit test procedures with your APM for BSEE 1 50 submittals 50 District Manager approval. 1707(h)(1)(ii)...................... Document all ROV intervention test results; make 0.5 50 records 25 available to BSEE upon request. 1707(h)(2)(ii)...................... Document all autoshear and deadman function test 0.25 50 records 13 results; make available to BSEE upon request. 1708(a), (b)........................ Document BOP inspection and maintenance 1 25 records 25 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. 1708(a)............................. Request alternative method to inspect marine 0.25 5 requests 2 risers. 1709................................ Request approval from the BSEE District Manager 2 80 requests 160 to displace kill-weight fluids in an unbalanced state; submit detailed written procedures with your APM. -------------------------------------------------- 1712(g); 1721(h).................... Submit with your APM, Registered Professional Burden covered under 1014-0018 0 Engineer certification. -------------------------------------------------- 1712(g)*; 1721(h) *................. Submit evidence from the Registered Professional 1 200 200 Engineer/firm of the well abandonment design and procedures; plugs in the annuli meet requirements of Sec. 250.1715; 2 independent barriers etc; has the expertise and experience necessary to perform the verification(s), submit with the APM. -------------------------------------------------------------------------------------------------------------------------------------------------------- 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 Sec. 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 [[Page 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 0 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. 0 2. In part 250, revise all references to ``glory hole'' to read ``well cellar''. 0 3. Amend Sec. 250.125(a), by revising entries (8) and (9) in the table to read as follows: Sec. 250.125 Service fees. (a) * * * ------------------------------------------------------------------------ Service--processing of the following Fee amount 30 CFR citation ------------------------------------------------------------------------ * * * * * * * (8) Application for Permit to $1,959 for initial Sec. 250.410(d); Drill (APD; Form BSEE-0123). applications Sec. only; no fee for 250.513(b); Sec. revisions. 250.1617(a). (9) Application for Permit to $116.............. Sec. 250.465(b); Modify (APM; Form BSEE-0124). Sec. 250.513(b); Sec. 250.613(b); Sec. 250.1618(a); Sec. 250.1704(g). * * * * * * * ------------------------------------------------------------------------ * * * * * 0 4. Amend Sec. 250.198 by revising paragraphs (a)(3), (h)(63), and (h)(78) to read as follows: Sec. 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 Sec. Sec. 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 Sec. 250.415(f). * * * * * 0 5. Amend Sec. 250.415 by revising paragraphs (f) to read as follows: Sec. 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 Sec. 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). 0 6. Amend Sec. 250.416 by revising paragraphs (e), (f), and (g) to read as follows: Sec. 250.416 What must I include in the diverter and BOP descriptions? * * * * * (e) 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 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. [[Page 50892]] (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. 0 7. Amend Sec. 250.418 by revising paragraphs (g) and (i) to read as follows: Sec. 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 Sec. 250.416(g) of the independent third-party; and * * * * * 0 8. Amend Sec. 250.420 by revising paragraphs (a)(6) and (b)(3) to read as follows: Sec. 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 Sec. 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 Sec. 250.141. You must submit documentation of this installation to BSEE in the End-of-Operations Report (Form BSEE-0125). * * * * * 0 9. Revise Sec. 250.423 to read as follows: Sec. 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 Sec. 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). 0 10. Amend Sec. 250.428 by revising paragraph (c) to read as follows: Sec. 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 (1) Run a temperature survey; cement job (such as, but not limited (2) Run a cement evaluation to, lost returns, cement channeling, log; or gas cut mud, or failure of equipment). (3) Use a combination of these techniques. [[Page 50893]] * * * * * * * ------------------------------------------------------------------------ 0 11. Amend Sec. 250.442 by removing paragraph (l) and revising paragraphs (a), (e), and (f) to read as follows: Sec. 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- You must have at least one controlled, hydraulically operated annular BOP, two BOPs equipped BOPs. with pipe rams, and one BOP equipped with blind-shear rams. The blind-shear 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 The crew must be trained in the ROV crew on each drilling rig on a operation of the ROV. The continuous basis once BOP deployment training must include has been initiated from the rig until simulator training on stabbing recovered to the surface. The crew into an ROV intervention panel must examine all ROV related well- on a subsea BOP stack. control equipment (both surface and subsea) to ensure that it is properly maintained and capable of shutting in the well during emergency operations. (f) Provide autoshear and deadman (1) Autoshear system means a systems for dynamically positioned safety system that is designed rigs. 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 Sec. 250.416 that the acoustic system will function in the proposed environment and conditions. * * * * * * * ------------------------------------------------------------------------ 0 12. Amend Sec. 250.443 by revising paragraph (g) to read as follows: Sec. 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. 0 13. Amend Sec. 250.446 by revising paragraph (a) to read as follows: Sec. 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 Sec. 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; * * * * * 0 14. Amend Sec. 250.449 by revising paragraphs (b), (j), and (k) to read as follows: Sec. 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 [[Page 50894]] (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. 0 15. Amend Sec. 250.451 by adding paragraph (j) to read as follows: Sec. 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. ------------------------------------------------------------------------ 0 16. Amend Sec. 250.456 by revising paragraph (j) to read as follows: Sec. 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 Sec. 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 * * * * * 0 17. Amend Sec. 250.513 by: 0 a. Redesignating paragraphs (b)(4) through (b)(5) as (b)(5) through (b)(6), and 0 b. Adding a new paragraph (b)(4) to read as follows: Sec. 250.513 Approval and reporting of well-completion operations. * * * * * (b) * * * (4) All applicable information required in Sec. 250.515. * * * * * 0 18. Amend Sec. 250.514 by adding paragraph (d) to read as follows: Sec. 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-by-step displacement procedures must address the following: (1) Number and type of independent barriers, as described in Sec. 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. 0 19. Redesignate Sec. Sec. 250.515 through 250.530 as Sec. Sec. 250.516 through 250.531. 0 20. Add new Sec. 250.515 to read as follows: Sec. 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 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 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 [[Page 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. 0 21. Amend newly redesignated Sec. 250.517 by revising paragraphs (d)(2), (d)(8), (d)(9), (g), and (h) to read as follows: Sec. 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 Sec. 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 Sec. 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. * * * * * 0 22. Amend Sec. 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: Sec. 250.613 Approval and reporting of well-workover operations. * * * * * (b) * * * (3) All information required in Sec. 250.615. * * * * * 0 23. Amend Sec. 250.614 by adding new paragraph (d) to read as follows: Sec. 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-by-step displacement procedures must address the following: (1) Number and type of independent barriers, as described in Sec. 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. 0 24. Redesignate Sec. Sec. 250.615 through 250.619 as Sec. Sec. 250.616 through 250.620. 0 25. Add new Sec. 250.615 to read as follows: Sec. 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 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 shearing and subsequent pressure integrity test results for the most rigid pipe to be used and calculations of shearing capacity of [[Page 50896]] 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. * * * * * 0 26. Amend newly redesignated Sec. 250.617 by revising paragraph (h) to read as follows: Sec. 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. 0 27. Revise Sec. 250.618 to read as follows: Sec. 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 Sec. 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 Sec. 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. 0 28. Amend Sec. 250.1500 by revising the definition for ``Well- control'' to read as follows: Sec. 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, well-completion, 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 well-control equipment. * * * * * 0 29. Amend Sec. 250.1704 by revising paragraph (g) to read as follows: Sec. 250.1704 When must I submit decommissioning applications and reports? * * * * * [[Page 50897]] ------------------------------------------------------------------------ Decommissioning applications and reports When to submit Instructions ------------------------------------------------------------------------ * * * * * * * (g) Form BSEE-0124, Application (1) Before you (i) Include for Permit to Modify (APM). The temporarily information submission of your APM must be abandon or required under accompanied by payment of the permanently plug Sec. Sec. service fee listed in Sec. a well or zone 250.1712 and 250.125. 250.1721. (ii) When using a BOP for abandonment operations include information required under Sec. 250.1705. (2) Within 30 days Include after you plug a information well. required under Sec. 250.1717. (3) Before you Refer to Sec. install a subsea 250.1722(a). protective device. (4) Within 30 days Include after you information complete a required under protective device Sec. trawl test 250.1722(d). (5) Before you Refer to Sec. remove any casing 250.1723. stub or mud line suspension equipment and any subsea protective device. (6) Within 30 days Include after you information complete site required under clearance Sec. verification 250.1743(a). activities ------------------------------------------------------------------------ 0 30. Add Sec. 250.1705 to read as follows: Sec. 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 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 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. 0 31. Add Sec. 250.1706 to read as follows: Sec. 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 Three BOPs consisting of an annular, one less than 5,000 psi, set of pipe rams, and one set of blind- shear rams. (2) The expected pressure is Four BOPs consisting of an annular, two 5,000 psi or greater or you sets of pipe rams, and one set of blind- use multiple tubing strings, shear rams. (3) You handle multiple Four BOPs consisting of an annular, one tubing strings set of pipe rams, one set of dual pipe simultaneously, rams, and one set of blind-shear rams. (4) You use a tapered drill (i) At least one set of pipe rams that string, are capable of sealing around each size of drill string. [[Page 50898]] (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 The requirements in Sec. 250.442(a) of stack, 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 small-diameter jointed pipe (usually \3/4\ inch to 1\1/4\ inch) as a work string, i.e., small- tubing 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 Sec. 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 BOP system when expected expected surface BOP system for wells surface pressures are less pressures are with returns taken than or equal to 3,500 psi greater than through an outlet on 3,500 psi the BOP stack ------------------------------------------------------------------------ (i) Stripper or annular-type Stripper or Stripper or annular- well-control component, annular-type type well-control well-control component. component, (ii) Hydraulically-operated Hydraulically- Hydraulically- blind rams, operated blind operated blind rams. rams,. (iii) Hydraulically-operated Hydraulically- Hydraulically- shear rams, operated shear operated shear rams. rams,. (iv) Kill line inlet, Kill line inlet, Kill line inlet. (v) Hydraulically-operated two- Hydraulically- Hydraulically- way slip rams, operated two-way operated two-way slip rams, slip rams. Hydraulically- operated pipe rams. (vi) Hydraulically-operated Hydraulically- A flow tee or cross. pipe rams, operated pipe Hydraulically- rams. operated pipe rams. Hydraulically- Hydraulically- operated blind- operated blind-shear shear rams. rams on wells with These rams surface pressures should be >3,500 psi. As an located as close option, the pipe to the tree as rams can be placed practical,. 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 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. [[Page 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 full-opening safety valve is not required for coiled tubing or snubbing operations. 0 32. Add Sec. 250.1707 to read as follows: Sec. 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 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 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 [[Page 50900]] 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. 0 33. Add Sec. 250.1708 to read as follows: Sec. 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 Sec. 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 Sec. 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. 0 34. Add Sec. 250.1709 to read as follows: Sec. 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-by-step displacement procedures must address the following: (a) Number and type of independent barriers, as described in Sec. 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. 0 35. Amend Sec. 250.1712 by revising paragraph (g) to read as follows: Sec. 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 Sec. 250.1715. In addition to the requirements of Sec. 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 Sec. 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). 0 36. Amend Sec. 250.1715 by adding paragraph (a)(11) to read as follows: Sec. 250.1715 How must I permanently plug a well? (a) * * * ------------------------------------------------------------------------ If you have . . . Then you must use . . . ------------------------------------------------------------------------ * * * * * * * (11) Removed the barriers required in Two independent barriers, one Sec. 250.420(b)(3) for the well to of which must be a mechanical be completed. barrier, in the center wellbore as described in Sec. 250.420(b)(3) once the well is to be placed in a permanent or temporary abandonment. ------------------------------------------------------------------------ * * * * * 0 37. Amend Sec. 250.1721 by revising paragraph (h) to read as follows: Sec. 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 Sec. 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 [[Page 50901]] (Form BSEE-0124) required by Sec. 250.1712 of this part. [FR Doc. 2012-20090 Filed 8-16-12; 4:15 pm] BILLING CODE 4310-VH-P
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