# Oil and Gas and Sulphur Operations on the Outer Continental Shelf-Increased Safety Measures for Energy Development on the Outer Continental Shelf > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2012-20090 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** August 22, 2012 - **Citation:** 77 FR 50856 ## Text 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 § 250.423(c) to require the operator to perform a negative pressure test only on wells that use a subsea blowout preventer (BOP) stack or wells with a mudline suspension system instead of on all wells, as was provided in the Interim Final Rule. • Adds new § 250.451(j) stating that an operator must have two barriers in place before removing the BOP, and that the BSEE District Manager may require additional barriers. • Extends the requirements for BOPs and well-control fluids to 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 § 250.443 stating that all BOP systems must include a wellhead assembly with a rated working pressure that exceeds the maximum anticipated wellhead pressure instead of the maximum anticipated surface pressure as was previously provided. • In § 250.1500 revising the definition of well-control to clarify that persons performing well monitoring and maintaining well-control must be trained. This new definition encompasses anyone who has responsibility for monitoring the well and/or maintaining the well-control equipment. This Final Rule is promulgated for the prevention of waste and for the conservation of natural resources of the Outer Continental Shelf (OCS), under the rulemaking authority of the Outer Continental Shelf Lands Act (the Act), 43 U.S.C. 1334. This rule is based on certain recommendations in the May 27, 2010, report from the Secretary of the Interior to the President entitled, “Increased Safety Measures for Energy Development on the Outer Continental Shelf” (Safety Measures Report). The President directed that the Department of the Interior (DOI) develop this report as a result of the Deepwater Horizon event on April 20, 2010. This event, which involved a blowout of the BP Macondo well and an explosion on the Transocean Deepwater Horizon mobile offshore drilling unit (MODU), resulted in the deaths of 11 workers, an oil spill of national significance, and the sinking of the Deepwater Horizon MODU. On June 2, 2010, the Secretary of the Interior directed BOEMRE to adopt the recommendations contained in the Safety Measures Report and to implement them as soon as possible. As noted in the regulatory impact analysis accompanying this rule, other recommendations will be addressed in other future rulemakings and will be available for public comment. Final Regulatory Impact Analysis for the Final Rule on Increased Safety Measures for Energy Development on the Outer Continental Shelf, RIN 1014-AA02, at 9 (BSEE; March 7, 2012). Similarly, BSEE's actions here are not intended to supplant any actions by BSEE or other authorized government authorities warranted by fact finding or other factual development in other proceedings, including but not limited to those in Multi-District Litigation No. 2179, In Re: Oil Spill by the OIL RIG DEEPWATER HORIZON in the GULF OF MEXICO, on April 2010 (E.D. La.). II. Source of Specific Provisions Addressed in the Interim Final Rule The Safety Measures Report recommended a series of steps designed to improve the safety of offshore oil and gas drilling operations in Federal waters. It outlined a number of specific measures designed to ensure sufficient redundancy in BOPs, promote well integrity, enhance well-control, and facilitate a culture of safety through operational and personnel management. The IFR addressed both new well bore integrity requirements and well-control equipment requirements. The well bore integrity provisions impose requirements for casing and cementing design and installation, tighter cementing practices, the displacement of kill-weight fluids, and testing of independent well barriers. These new requirements were intended to ensure that additional physical barriers exist in wells to prevent oil and gas from escaping into the environment. These new requirements related to well bore integrity were intended to decrease the likelihood of a loss of well-control. The well-control equipment requirements in the IFR help ensure the BOPs will operate in the event of an emergency and that the Remotely Operated Vehicles (ROVs) are capable of activating the BOPs. The following provisions in the IFR were identified in the Safety Measures Report as being appropriate to implement through an emergency rulemaking: Safety measures report provision Interim final rule citations Establish deepwater well-control procedure guidelines (safety report rec. II.A.1) § 250.442 What are the requirements for a subsea BOP system? § 250.515 Blowout prevention equipment. § 250.615 Blowout prevention equipment. §§ 250.1500 through 250.1510 Subpart O—Well-control and Production Safety Training. Establish new fluid displacement procedures (safety report rec. II.A.2) § 250.456 What safe practices must the drilling fluid program follow? Develop additional requirements or guidelines for casing installation (safety report rec. II.B.2.6) § 250.423 What are the requirements for pressure testing casing? BOEMRE also included the following provision in the IFR from the Safety Measures Report: Safety measures report provision Interim final rule Enforce tighter primary cementing practices (safety report rec.II.B.3.7) § 250.415 What must my casing and cementing programs include? BOEMRE determined that it was appropriate for inclusion in the IFR because it is consistent with the intent of the recommendations in the Safety Measures Report. Tighter requirements for cementing practices increase the safety of offshore oil and gas drilling operations. Much of the October 14, 2010, Federal Register preamble supporting the need for emergency rulemaking procedures also supports retaining these provisions permanently. III. Overview of the Interim Final Rule as Amended by This Rule The primary purpose of this Final Rule is to address comments received, make appropriate revisions, and bring to closure the rulemaking begun by the IFR. Together, the two rules clarify and incorporate safeguards that will decrease the likelihood of a blowout during drilling, completion, workover, and abandonment operations on the OCS. For example, the safeguards address well bore integrity and 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; (6) Establish new requirements for subsea secondary BOP intervention; (7) Require function testing for subsea secondary BOP intervention; (8) Require documentation for BOP inspections and maintenance; (9) Require a Registered Professional Engineer to certify casing and cementing requirements; and (10) Establish new requirements for specific well-control training to include deepwater operations. IV. Comments Received on the Interim Final Rule Although the IFR was effective immediately upon publication in the Federal Register , the IFR included a request for public comments. BSEE received 38 comments on the IFR. The following table categorizes the commenters: Commenter type Number of comments Oil and Gas Industry/Organizations 21 Other Non-Government Organizations 6 Individuals 8 Government Federal/State 3 Total 38 A number of comments included topics that were outside the scope of this rulemaking. Some provided suggestions for future rulemakings; other comments related to the Deepwater Horizon event, speculating on the causes of the event and suggesting additional changes based on their understanding of that event. While we requested comments on future rulemakings, we are not specifically addressing those comments in this rule; we will however, consider those suggestions in related future rulemakings. To the degree that comments assert that compliance with current rules or standards incorporated by reference may be infeasible in certain situations, and that such provisions need to be revised, BSEE will examine the need to revise its rules. Pending any future revisions of such provisions, persons subject to compliance may seek BSEE approval of either alternative procedures or equipment under § 250.141 or departures from such requirements under § 250.142. In this Final Rule, BSEE only responds to comments that relate directly to this rulemaking. All comments BSEE received on the IFR are available at www.regulations.gov under Docket ID: BSEE-2012-0002. BSEE received a number of comments asserting that in making the IFR effective immediately upon publication, we did not follow the appropriate rulemaking process as required by the Administrative Procedure Act (APA). BSEE disagrees with these comments. In issuing the IFR, BOEMRE followed procedures authorized under the APA at 5 U.S.C. 553(b) and (d). BOEMRE provided justification in the IFR for not seeking public comment in advance, and for the immediate effective date. BSEE believes that the justification provided at that time was sufficient and will not repeat that justification here. In this Final Rule, BSEE is publishing revisions to the IFR based on the comments we received. Analysis of the comments also confirms the agency's earlier conclusions regarding those portions of the IFR that are not modified in this Final Rule. To help organize and present the comments received and the BSEE response to the comments, BSEE has developed 3 separate tables. Except for one issue, the following three tables summarize the comments received, and contain BSEE's response to those comments. (Comments pertaining to the “should/must” issue related to § 250.198(a) are addressed in the section-by-section discussion with specific comments being addressed in a separate document included in the Administrative Record.) The first table relates to comments received on specific sections. The second table relates to broader topics and general questions not connected to a specific section. The third table addresses comments regarding the Regulatory Impact Analysis. Following the comment discussions, we include a section-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 § 250.198(h)(79)—API Standard 65 2nd edition API Standard 65—Part 2, Isolating Potential Flow Zones During Well Construction, Second Edition was published on December 10, 2010. The Second Edition incorporates learnings from the Macondo well incident, enhances the description and classification of well-control barriers, and defines testing requirements for cement to be considered a barrier. The Second Edition also revises Annex D into a checklist based on the requirements of the document. BOEMRE should update the IFR to incorporate the 2nd Edition by reference BSEE has reviewed API Standard 65—Part 2 2nd edition and has determined that it is appropriate to incorporate the latest edition in our regulations. § 250.198(h)(79)—API Standard 65 2nd edition Provide clarification on how API RP 65-2 will be used; will a minimum pre-cementing score be required for each cement job and then evaluated after the job also? (or checklist if using the Second Edition) BSEE developed a compliance table, based on API Standard 65—Part 2 (see Table 4) for guidance. This Final Rule does not require operators to use this table; however, the operator may answer the questions in the table, along with the written descriptions where needed, or the operator may supply a written description in an alternate format as required in § 250.415(f) which is submitted with the APD. If the operator does not supply enough information to confirm compliance, then BSEE may return the permit application for clarification. BSEE does not plan to use a scoring system; the operator must submit how it evaluated API Standard 65 part 2 when designing its cement program. The operator is not required to submit a post-cement job evaluation. § 250.415(f), § 250.416(e) Will the submittal be with each APD, or once for each rig per year unless changed? The operator is required to submit the written description of how the best practices in API Standard 65—Part 2 were evaluated and the qualifications of the independent third-party with each APD. § 250.416(d) Confirm that the schematic of the control system includes location, control system pressure for BOP functions, BOP functions at each control station, and emergency sequence logic. Specifications on other requirements should be clear BSEE agrees that the schematics of the control systems should include these items. The location of control stations are not required to be submitted. While it is critical to have control stations, the actual location of the control stations is not critical. § 250.416(e) Will there be a standard way to perform shearing calculations for the drill pipe? BSEE does not require a standard method to perform shearing calculations; different manufacturers have different methods of calculating shearing requirements. The documentation the operator provides, however, needs to explain and support the methodology used in performing the calculations and arriving at the test results. § 250.416(e) Will there be a standard of calculation for the Maximum Anticipated Surface Pressure (MASP)? BSEE does not require a standard procedure for MASP or shearing calculations. In § 250.413(f), MASP for drilling is defined along with the considerations for calculations. § 250.416(e) Will the maximum MASP be the rating of the annulars? The MASP for shearing calculations will not be based on the annular rating. There are multiple methods to calculate the MASP. It is the responsibility of the operator to select the appropriate method, depending upon the situation. § 250.416(e) Is it a requirement of the deadman to also shear at MASP? Yes, the shear rams installed in the BOP must be able to shear drill pipe at MASP. § 250.416(e) If there is a requirement of the deadman to also shear at MASP, what usable volume and pressure should remain after actuation? BSEE is researching this issue and may address it in future rulemaking. § 250.416(e) Please confirm that operators will only be required to demonstrate shearing capacity for drill pipe (which includes workstring and tubing) that is run across the BOP stack and that BHA components, drill collars, HWDP, casing, concentric strings, and lower completion assemblies are excluded from this requirement BSEE agrees with this comment. We revised § 250.416 to specifically include workstring and tubing. § 250.416(e) A better requirement would be to demonstrate shearing capacity for drill pipe which includes work-strings and tubing which is run across the BOP stack BSEE revised this section in this Final Rule to include workstring and tubing as drill pipe. § 250.416(e) Shearing capacity with MASP should be modified to shearing capacity with mud hydrostatic pressure plus a conservative shut-in pressure limit set by the operator and contractor where shut-in is transferred from the annular BOP to Ram BOP. At this point increased pressure in the cavity between the pipe rams and annular preventer should be eliminated. BOEMRE should request the internal bore pressure shear capacity calculation to be provided at the limit of the BOP system and approval contingent upon MASP being less than internal bore pressure limit BSEE requires the operator to design for the case in which blind-shear rams will be exposed to the MASP. BSEE does not agree that we need to request operators to provide the internal bore pressure shear capacity calculation. Designing the BOP for the well design and the conditions in which it will be used will ensure that this concern is addressed. § 250.416(e) Modify the requirement for blind-shear rams to reflect the 2,500 psi maximum pressure limit when placed above all pipe rams and immediately below the annular on the subsea BOP stack BSEE disagrees. The operator is required to design for the case in which blind-shear rams are exposed to the MASP. It is possible that this situation may occur and this requirement addresses that possibility. The proposed new API RP-53 4th Edition states pipe rams must be used when shut-in pressure exceeds 2,500 psi. When the blind-shear rams are above all pipe rams in the stack, the well-control sequence would be to shut the annular first and then switch to a pipe ram if the shut-in pressure approaches 2,500 psi. With the blind-shear ram above all pipe rams, it would be nearly impossible for the blind-shear rams to ever experience shut-in pressures approaching MASP § 250.416(e) 30 CFR 250.416(e) requires independent third-party verification of pipe shearing calculations at MASP for the blind-shear rams in the BOP stack. Prior to the IFR, this item didn't require the independent third-party verification of shear calculations. Prudent operators always do those calculations to (1) comply with the law as it was written and (2) feel comfortable that pipe can be sheared in an emergency. The requirement for independent third-party verification does not make things safer in the GoM. Why cannot BOEMRE regulators just have the operators do what was already in the regs? Shear calculations are very straight forward and tend to be conservative by 30 percent when it comes to predicting the hydraulic pressure needed to shear tubulars with MASP at the BOP BSEE disagrees with this comment and the Final Rule continues to require independent third-party verification. This requirement ensures that everyone will perform the calculations, not just prudent operators. Third-party verification provides additional and necessary assurance that the blind-shear rams will be able to shear the drill pipe at MASP. The additional requirements in this rulemaking are intended to support existing requirements and not replace them. § 250.416(f) The reliability and operability of the BOP can be confirmed without bringing the entire BOP and Lower Marine Riser Package (LMRP) to surface after each well, by visual inspection of a subsea BOP with an ROV and through a thorough function and pressure testing process. Any regulation that would require the operator to pull the stack to surface, handle the riser, and re-run it introduces more risk to personnel, well bore, and equipment. The proposed new API RP-53, 4th Edition, states: “Section 18.2 Types of Tests. This section addresses the types of tests to be performed and the frequency of when those tests are to be performed, realizing that the BOP can be moved from well-to-well without returning to surface for inspections and testing. For those cases, a visual inspection (by ROV) should be performed. Operability and integrity can be confirmed by function and pressure testing. In these instances, subsequent testing criteria shall apply for testing parameters.” This approach is safer and the regulation must be amended BSEE disagrees. The operator must pull the BOP stack to surface and complete a between-well inspection. The required inspection is more thorough than a visual inspection by an ROV and will help ensure the integrity of the BOP stack. As required in § 250.446(a), a between well inspection must be performed according to currently incorporated API RP 53, sections 17.10 and 18.10, Inspections. The stump test of the subsea BOP before installation was already required under § 250.449(b) as it existed before promulgation of the IFR. To conduct a stump test, the BOP must be located on the surface. The BOP inspection was a recommendation in the Safety Measures Report. § 250.416(f) 30 CFR 250.416(f) requires that an independent third-party verify that a subsea BOP stack is fit for purpose. Section 250.416(f)(2) further requires that the subsea BOP stack has not been compromised or damaged from previous service—no guidance is given on how one is to determine that the subsea BOP hasn't been compromised or damaged For multi-well projects where it makes senses to hop the BOP stack from well to well, would a successful subsea function test and pressure test be sufficient evidence that the requirement has been met? BSEE does not specify how the third-party verifies that the BOP has not been compromised or damaged from previous service. As required in § 250.446(a), a between-well inspection must be performed according to API RP 53, sections 17.10 and 18.10, Inspections. The requirement to conduct a stump test of the subsea BOP before installation existed before promulgation of the IFR, under § 250.449(b). The operator may not hop the BOP stack from well to well and be in compliance with the new provisions of this section or the previously existing requirements under § 250.449(b). § 250.416(f)(2) This requirement infers that an inspection of the BOP system is required to ensure the system has not been compromised or damaged from previous service. Please confirm that the agency agrees that a subsea BOP system is not compromised or damaged provided it can be function tested and pressure tested in the subsea environment where it will be in operation. Standardized pressure testing in the subsea environment without visual inspection fulfills the requirements of § 250.416(f)(2) In § 250.416(f)(2), BSEE does not specify how the third-party verifies that the BOP has not been compromised or damaged from previous service. However, BSEE has requirements for between-well inspections in § 250.446(a), and stump testing prior to installation in § 250.449(b). § 250.416(f)(2) If it is mandated that a visual inspection between wells is required then the cost to implement of $1.2 MM is grossly understated. The cost to pull a BOP for a visual inspection is underestimated. The cost of pulling a subsea BOP for a visual inspection would result in a $5-$15 million opportunity cost The full cost to pull a subsea BOP to the surface following an activation of a shear ram or lower marine riser package (LMRP) disconnect (under § 250.451(i)) in the benefit-cost analysis is estimated to be $11.9 million dollars. This amount is within the range suggested by the commenter. However, the requirement to conduct a visual inspection and test the subsea BOP between wells predated the IFR and was in the previously existing regulation at § 250.446(a). Because this requirement is not a new provision, no compliance costs are assigned in the economic analysis. § 250.416(f)(2) Third-party verification that the BOP stack has not been compromised or damaged from previous service can be accomplished by successful subsea function and pressure tests without visual inspection. Between well visual inspections of the BOP internal components is not required An independent third-party must confirm that the BOP stack matches the drawings and will operate according to the design. The third-party verification must include verification that: (1) The BOP stack is designed for the specific equipment on the rig and for the specific well design; (2) The BOP stack has not been compromised or damaged from previous service; (3) The BOP stack will operate in the conditions in which it will be used. BSEE does not specify how the third-party verifies that the BOP has not been compromised or damaged from previous service. However, BSEE has requirements for between-well inspections in § 250.446(a), and stump testing prior to installation in § 250.449(b). § 250.416(g) Qualification for Independent Third Parties The requirements for independent third parties to conduct BOP inspections fail to provide globally consistent standards necessary for the lifecycle use of Mobile Offshore Drilling Units (MODUs) on a global basis. The Interim Rule allows for an API licensed manufacturing, inspection, certification firm; or licensed engineering firm to carry out independent third-party verification of the BOP system, as well as technical classification societies. We recommend that the Interim Rule be amended to only enable organizations with the necessary breadth and depth of engineering knowledge, and experience and global reach, and demonstrable freedom from any conflict of interest, such as classification societies, can qualify as `independent third parties'. We believe that owing to the global employment of MODUs, where rigs could be engaged anywhere around the world, only independent technical classification societies have the global reach to ensure consistency in inspection and verification of safety critical equipment necessary to ensure the safe operation of an asset throughout its lifecycle In response to comments, BSEE removed the option for the independent third-party to be an API-licensed manufacturing, inspection, or certification firm in § 250.416(g)(1) because API does not license such firms. Section 250.416(g)(1) allows registered professional engineers, or a technical classification society, or licensed professional engineering firms to provide the independent third-party verification. Section 250.416(g)(2)(i) requires the operator to submit evidence that the registered professional engineers, or a technical classification society, or licensed professional engineering firms or its employees hold appropriate licenses to perform the verification in the appropriate jurisdiction, and evidence to demonstrate that the individual, society, or firm has the expertise and experience necessary to perform verifications. BSEE may accept the verification from any firm or person that meets these requirements. We will not require the exclusive use of technical classification societies at this time. § 250.420(a)(6) Certification by a professional engineer that there are two independent tested barriers and that the casing and cementing design are appropriate The comment supports the requirements in the IFR. However, BSEE clarified the requirement for the two independent barriers, based on other comments. §§ 250.420(a)(6), 250.1712(g), and 250.1721(h) What is the definition of well-completion activities? This is the first time it has been mentioned that barriers had to be certified by a professional engineer, only casing design and cementing were mentioned in the past BSEE clarified the certification requirement in § 250.420(a)(6) by removing the term “well-completion activities,” because it was redundant in the context of that provision. The two required barriers are part of the casing and cementing design. §§ 250.420(a)(6), 250.1712(g), and 250.1721(h) Will BOEMRE still check casing designs based on load cases that are not published? If so, will certified plans be rejected due to design reviews within the agency? Will Agency design reviews be done by Registered Professional Engineers (RPE)? If not, what will be the process for approval when an RPE approved design conflicts with the Agency? Will the Agency mandate a change and take the responsibility for that change? There are multiple ways to calculate the load cases. The operator must ensure the well design and calculations are appropriate for the purpose for which it is intended under expected wellbore conditions. BSEE engineers will conduct the design reviews. Any issues will be resolved with the operator on a case-by-case basis. §§ 250.420(a)(6), 250.1712(g), and 250.1721(h) Professional Engineer Liabilities that will be placed onto a “Professional Engineer” are an issue. The PE approach demands that the PE is intimately involved in all aspects of the design and also in primary communication as the well is drilled and small variations in the plan are made or happen. All liability for the well must remain with the operator without any “dilution” to a PE, although review by a PE or other “independent and reputable” third-party is totally appropriate The intent of the PE certification is to ensure that all plans are consistent with standard engineering practices. To add to safety assurances, BSEE included language in § 250.420(a)(6) that the Professional Engineer be involved in the design process. Such person must be included in the design process so that he or she is familiar enough with the final design to make the required certification. Under § 250.146(c), persons actually performing an activity on a lease to which a regulatory obligation applies are jointly and severally responsible for compliance. Such third person responsibility does not eliminate or dilute the operator's responsibilities for a well. §§ 250.420(a)(6), 250.1712(g), and 250.1721(h) Professional Engineer Can the required “registered professional engineer” be a company employee? Yes, the registered professional engineer can be a company employee. §§ 250.420(a)(6), 250.1712(g), and 250.1721(h) Professional Engineer Require that all certifications needed by a Registered Professional Engineer be done by a Registered Professional Petroleum Engineer. It makes no sense at all to utilize any PE. If so, at least require a BS in Petroleum Engineering. There is no specification to determine how any Registered Professional Engineer is “capable of reviewing and certifying that the * * * is appropriate for the purpose for which it is intended under expected wellbore conditions.” BSEE disagrees that the professional engineer must be a petroleum engineer; a professional engineer with another background who has expertise and experience in well design will be capable of certifying these plans. The expectation is that a licensed professional engineer will NOT certify anything outside of their area of expertise. However, in response to the commenter's concern, this Final Rule adds an expertise and experience requirement for the person performing the certification. §§ 250.420(a)(6), 250.1712(g), and 250.1721(h) The intent of Congress and the Act does not appear to be complied with by the proposed rule. The use of a registered Professional Engineer to certify casing and cementing programs when “The Registered Professional Engineer must be registered in a State of the United States but does not have to be a specific discipline” does not appear to comply with the allowance for coordination with local Coastal Affected Zone States to have input. Two deficiencies are apparent. One is a licensed professional engineer should not be certifying anything that he is not competent to certify due to his education, training and experience. The second is that the engineer should be licensed in the Coastal Zone Affected State due to the differences that occur in licensing requirements. Some states are more liberal than others in the exemptions allowed and the requirements for discipline specific engineering licensure. If Texas wants to allow a higher risk then Texas offshore Coastal Affected Zones should be the only zones that are allowed to have such higher risk to be taken. If Louisiana or Mississippi want to be more restrictive then their offshore waters should be more restrictive. This seems to be the intent of the Coastal Zone Affected State language in the federal statutes. As currently proposed a licensed engineer from the state of minimum requirements can be selected The certification requirement is intended to ensure that all operators meet basic standards for their cement and casing. This requirement for PE certification is a substantial improvement compared to previous rules in which a certification was not mandatory. The final rule has added a provision to assure that a licensed professional will NOT certify anything outside of his or her area of expertise and experience. Because OCS projects occur offshore from several states, a company may want to use the same PE regardless of the location of any given well. Furthermore, the certification requirement applies uniformly to any project in Federal waters. Under these conditions, the certification standard combined with the liabilities associated with certification of a plan effectively address certification concerns. Also, States with approved coastal management programs have adequate opportunities to express their concerns about specific projects under other provisions of the regulations. §§ 250.420(a)(6), 250.1712(g), and 250.1721(h) BOEMRE now requires a Registered Professional Engineer to certify a number of well design aspects including: casing and cementing design, independent well barriers, and abandonment design. This is a new, important requirement. BOEMRE does not, however, require that the engineer be certified as a Registered Professional Engineer in any particular engineering discipline. This creates the possibility that a Professional Engineer, with little or no experience with oil and gas well design, drilling operations or well pressure control could be certifying these designs. For example, BOEMRE's rule would allow an electrical engineer to certify a well design that may have no expertise or experience on offshore well construction design. We recommend that the Registered Professional Engineer requirement be limited to the discipline of Petroleum Engineering, and/or a Registered Professional Engineer in any engineering discipline that has more years of experience designing and drilling offshore wells. We agree that Registered Professional Engineers have the technical capability to assimilate the knowledge to certify well construction methods over a period of time, but only the Registered Professional Petroleum Engineer is actually tested on well casing, cementing, barriers and other well construction design and safety issues. Other engineering disciplines require on-the-job training and experience to expand their expertise and apply their engineering credentials to offshore well construction design certification BSEE disagrees that the professional engineer must be a petroleum engineer; a professional engineer with another background who has experience in well design will be capable of certifying these plans. In response to commenters' concerns, we have added an expertise and experience requirement for the certifying person. It is the operator's responsibility to ensure that the Registered Professional Engineer is qualified and competent to perform the work and has the necessary expertise and experience. The expectation is that a licensed professional engineer will NOT certify anything outside of his or her area of expertise. The operator certainly has a strong incentive to assure that the professional engineer is competent because the operator is responsible for the activities on the lease and the consequences thereof. § 250.420(a)(6) 30 CFR 250.420(a)(6) requires that a Registered Professional Engineer certify barriers across each flow path and that a well's casing and cementing design is fit for its intended purpose under expected wellbore conditions. There are RPE's whose area of expertise isn't well design or construction. There are very few drilling and completion engineers with both sufficient expertise to make the required assessment and a PE license. What in this requirement makes operations in the GoM safer? Does BOEMRE plan to consider changing this requirement to expand the number of truly qualified people who can accurately assess this situation? What will eventually be the right standard for the certifying authority? Requiring a Registered Professional Engineer's certification helps to ensure that the casing and cementing design meets accepted industry design standards. The expectation is that licensed professional engineers will NOT certify anything outside of their area of expertise. In response to this comment, this Final Rule does expand the persons who can make the required certification if they are registered and have the requisite expertise and experience. §§ 250.420(a)(6), 250.1712(g) and 250.1721(h) The description of “flow path” would be improved by commenting on examples and/or by providing a definition and not including potential paths, i.e., previously verified or tested mechanical barriers are accepted without retest. Flow paths in the broadest terms would include annular seal assemblies which may not be accessible on existing wells. The assumption that all casing strings can be cut and pulled would result in exceptions in the majority of cases and would introduce a health and safety risk to operating personnel and equipment currently not present BSEE revised the regulatory text in § 250.420(b)(3) to include an example of barriers for the annular flow path and for the final casing string or liner. Once an operator performs a negative test on a barrier, the operator does not have to retest it unless that barrier is altered or modified. Also, see the subsequent comment responses that address the flow paths to which the barrier requirements apply. § 250.420(a)(6) Will BOEMRE still check casing designs based on load cases that are not published? If so, will certified plans be rejected due to design reviews within the agency? BSEE engineers will check casing designs. BSEE will resolve any differences with the operator on a case-by-case basis. § 250.420(a)(6) BOEMRE has not provided specific guidance on what aspects of casing and cementing designs must be initially certified or guidance on triggers which would cause a plan to be recertified for continuance of operations. The Offshore Operators' Committee OOC provided those triggers to BOEMRE on October 12, 2010, and requests they be accepted as the only triggers for plan certification. Currently, the BOEMRE is inconsistent in their requests for recertification and fearful of approving minor changes that have no effect on safety. Further, delays to operations resulting in additional operational exposure and safety risk are to be expected when the Agency requires arbitrary recertification when simple changes are required. The requirement for an RPE review for OCS operations may become a bottleneck if this requirement becomes a standard for all U.S. operations While the list provided by the commenter contained some good examples, it is not comprehensive. If an activity triggers the need for a revised permit or an APM, then the Registered Professional Engineer must recertify the design. BSEE is working to improve consistency among the District Offices. § 250.420(b)(3) Add clarification to the dual mechanical barrier requirement to ensure the barriers are installed within the casing string and does not apply to mechanical barriers that seal the annulus between casings or between casing and wellhead. Acceptable barriers for annuli shall include at least one mechanical barrier in the wellhead and cement across and above hydrocarbon zones. Placement of cement can be validated by return volume, hydrostatic lift pressure or cased hole logging methods Industry best practices do not consider dual float valves to be two separate mechanical barriers because they cannot be tested independently and because they are not designed to be gas-tight barriers. This regulation does not achieve the safety objectives of the Drilling Safety Rule In response, this Final Rule revises § 250.420(b)(3) to provide that for the final casing string (or liner if it is the final string), an operator must install one mechanical barrier, in addition to cement, to prevent flow in the event of a failure in the cement. In response to the comment, we also clarify that a dual float valve, by itself, is not considered a mechanical barrier. The appropriate BSEE District Manager may approve alternatives. § 250.420(b)(3) Does the dual mechanical barrier requirement apply to just the inside of the casing or to both the inside and annulus flow paths? Our interpretation is the inside of the casing. It is also not clear when these dual barriers are required BSEE revised the regulatory text at § 250.420(b)(3) to clarify the requirement that two independent barriers are required in each annular flow path (examples include, but are not limited to, primary cement job and seal assembly) and for the final casing string or liner. The appropriate BSEE District Manager may approve alternatives. §§ 250.420(b)(3), 250.1712(g) and 250.1721(h) The incorporation by reference of API RP 65-2 in § 250.415(f) includes a definition of a mechanical barrier. This either confuses or contradicts the use of the phrase “mechanical barrier” in sections §§ 250.420(b)(3), 250.1712(g) and 250.1712(h). The description of a “seal achieved by mechanical means between two casing strings or a casing string and the borehole” would not be possible regarding an existing well, specifically for the temporary or permanent abandonment, and does not include seals that are not in an annulus. Question: Do cast iron bridge plugs and retainers/packers without tubing installed meet the requirement for mechanical barriers? BSEE revised the language in § 250.420(b)(3) to clarify that the operator must install two independent barriers to prevent flow in the event of a failure in the cement, and clarified that a dual float valve is not considered a barrier. The appropriate BSEE District Manager may approve alternative options. BSEE revised the language in §§ 250.1712 and 250.1721 to clarify the requirements. For wells being permanently abandoned and wellhead removed, the PE needs to certify that there are two independent barriers in the center wellbore and the annuli are isolated per the regulations at § 250.1715. If the wellhead is being left in place for the production string, the registered PE must certify two independent barriers in the center wellbore and the annuli. The registered PE may not certify work that was previously performed; the registered PE must only certify the work to be performed under the permit submitted. A cast iron bridge plug is an option as a mechanical barrier. With regard to the question of using retainers/packers to meet the requirement for mechanical barriers, evaluation will be conducted on a case-by-case basis. § 250.420(b)(3) The rules seem to encourage use of devices described in Section 3 of RP 65, some of which have never been used in deepwater and are in fact of dubious utility. It is agreed that more stringent cementing practices are in order, but these proposed rules are too confusing to serve this purpose. This section needs to be revisited and specific, practical, recommended practices set out BSEE revised this section in the Final Rule to clarify the requirement of two independent barriers, and also clarified that a dual float valve is not considered a mechanical barrier. The BSEE District Manager may approve alternatives. § 250.420(c) 30 CFR 250.420(c) requires that cement attain 500 psi compressive strength prior to drill out. What drives the CS requirement? It's not API RP 65-2 This is a previously existing requirement and therefore not within the scope of this rulemaking. §§ 250.420, 250.1712, and 250.1721 Previous guidance/interpretation issued by BOEMRE said that deviation from certified procedures required contact with the appropriate BSEE District Manager. This is documented only in the guidance and is not implicit in this part of the rule. We request that BOEMRE specify the kinds of variances that require this contact If an activity triggers the need for a revised permit or an APM, then the Registered Professional Engineer must recertify the design and the revised permit or Application for Permit Modification (APM) must receive approval from the appropriate BSEE District Manager. § 250.423(b) Need definition or clarity around the term—lock down and the requirement for locking down a drilling liner. Must all liner hangers have hold down slips? Normally conventional line hangers only have hang off slips to transfer the weight of the liner to the previous casing string. Once the seal is energized for a Liner Top Packer, it will hold pressure from below and above, but not all seals have slips to prevent uplift should the pressure-area effect exceed the weight of the liner. Requiring hold down slips on a conventional liner hanger increases the difficulty to fish the liner out of the hole, in fact it will lead to a milling operation BSEE has revised the language in § 250.423(b), to clarify that the Final Rule does not require the use of a latching or lock down mechanism for a liner. However, if a liner is used that has a latching or lock down mechanism, then that mechanism must be engaged. § 250.423(b) As currently drafted, § 250.423(b) requires negative testing to be set to either 70 percent of system collapse resistance pressure, saltwater gradient, or 500 psi less than formation pressure, whichever is less. The rule implies that operators are required to perform a test on the casing seal; however, the industry has had several examples of where testing to a salt water gradient to sea floor has caused casing collapse in deep wells with casing across the salt. This regulation does not clearly state whether it applies to casing shoe extensions, such as expandable casing or 18” (which is a surface casing shoe extension). Since not all casing sizes (e.g. 16” and 18”) have lockdown mechanisms at this time, the rule should allow for waivers to this requirement until such time that lockdown mechanisms are available BSEE revised the language for the requirements for a negative test under § 250.423(c). The operator must perform a negative pressure test on all wells that use a subsea BOP stack or wells with mudline suspension systems to ensure proper casing or liner installation. You must perform the negative test to the same degree of the expected pressure once the BOP is disconnected. BSEE also revised the language for the requirement to ensure proper installation of the casing in the subsea wellhead and liner in the liner hanger in § 250.423(b). Regarding lockdown mechanisms, see previous comment. § 250.423(b) The operator must perform a pressure test on the casing seal assembly to ensure proper installation of casing or liner. The operator must ensure that the latching mechanisms or lock down mechanisms are engaged upon installation of each casing string or liner BSEE agrees with this comment. Section 250.423(b) requires performance of a pressure test on the casing seal assembly and further requires the operator to maintain the necessary documentation. Performance and documentation of a pressure test on the casing seal assembly to ensure proper installation of the casing and the liner are essential. Documentation that the latching mechanisms or lock down mechanisms are fully engaged upon installation of each casing string or liner must be mandatory § 250.423(b)(1) Not clear if integral latching capability of casing hanger/seal assembly is acceptable or if a separate mechanism is required Under § 250.423(b)(1), the operator must ensure proper installation of casing in the subsea wellhead by ensuring that the latching mechanisms or lock down mechanisms are engaged upon installation of each casing string. The rule does not require a specific type of latching mechanism. Integral latching capability of the casing hanger or seal assembly is acceptable. § 250.423(c) What is the design basis and acceptance criteria required for negative testing? The regulations do not specify a particular design basis for the negative pressure test. Under § 250.423(c)(3) operators must submit negative test procedures and provide their criteria for a successful test to BSEE for approval. BSEE revised the language of § 250.423(c)(5) to include examples of indications of failure. § 250.423(c) It is imperative that the operator establish what is “normal” for this type of testing event, such that the rig crew is in no doubt as to what to look for and whether or not there is an event going on which is “not normal” Operators are required to submit the procedures of these tests and provide their criteria for a successful test with their APD. BSEE revised the regulatory text to include examples of indications of a failed negative pressure test. § 250.423(c) What is the definition of intermediate casing? The rule states a negative pressure test is required for intermediate and production casing. If drilling liners are set below intermediate casing is additional negative testing required? The intent of this requirement is not clear. The magnitude of the negative test is also not apparent. Is the intent to test the entire casing, wellhead, liner top, or the shoe? Surface wellheads are negative tested for each BOP test when the stack is drained and water is used for a test. If a negative test of an intermediate shoe is intended, then, what is the purpose since the casing shoe will be drilled out. In general, negative testing should not apply to all wells and should apply if the load is anticipated and then not until such time it is needed BSEE revised § 250.423(c) to clarify the requirements for the negative pressure test. Intermediate casing is any casing string between the surface casing string and production casing string. We revised the Final Rule to require negative pressure tests only on subsea BOP stack and wells with mudline suspension systems. We specifically require the operator to perform a negative pressure test on the final casing string or liner, and prior to unlatching the BOP at any point in the well (if the operator has not already performed the negative test on its final casing string or liner). At a minimum, the negative test must be conducted on those components that will be exposed to the negative differential pressure that will occur when the BOP is disconnected. The intent of the requirement is to ensure that the casing can withstand the wellbore conditions. The Final Rule addresses indicators of failed pressure tests and specifies what the operator must do in the event of a failed test. § 250.423(c) Wells with surface wellheads should be exempt from negative tests unless the well is to be displaced to a fluid less than pore pressure and in that case the shoe, productive intervals, and liner tops can be negative tested to the amount anticipated prior to or during the displacement. The requirement to negative test wells with surface wellheads should not be mandated since the well can be displaced to a fluid less than pore pressure under controlled conditions without risk of an influx getting in a riser We agree that as a general matter wells with surface well heads should be exempt from negative pressure tests and we revised the Final Rule to require the negative pressure test only for wells that use a subsea BOP stack or wells with mudline suspension systems. We did, however, provide that if circumstances warrant, the BSEE District Manager may require an operator to perform additional negative pressure tests on other casing strings or liners (e.g. intermediate casing string or liner) or on wells with a surface BOP stack. § 250.423(c) Additional guidance given by BOEMRE has indicated a desire to negative test all liner tops exposed in either the intermediate or production annulus on all wells with surface BOP equipment. This requirement is not consistent with the desire to improve safety since many liner tops are never exposed to negative pressures during the life of the well. Thus performing the test exposes personnel to additional exposure while tripping pipe to perform the test, risks the well by installing non-drillable test packers above the liner top during the test, and will expose personnel to additional material handling requirements All liner tops, exposed below the intermediate casing (wells with mudline suspension systems) must be tested, but only for wells with subsea BOP stacks or wells with mudline suspension systems. The test must be performed before displacing kill weight fluids in preparation for disconnecting the BOP stack. § 250.423(c) The Agency has not provided guidance on when the test is to be performed. Testing upon installation is not advisable due to additional pressure cycles applied to the cement early in the development of its strength that could result in premature cement failure. Additionally, if a negative load is anticipated during operations, it is best to defer the negative test to assure well integrity is validated just prior to the intended operation This Final Rule revises § 250.423(c) to state that the negative pressure test must be performed on the final casing string or liner, and prior to unlatching the BOP at any point in the well. The negative test must be conducted on those components, at a minimum, that will be exposed to the negative differential pressure that will be seen when the BOP is disconnected. § 250.423(c) Negative testing should be performed on subsea wells and wells with mudline suspension systems where it is important to validate barriers prior to removal of mud hydrostatic pressure during an abandonment or suspension activity such as hurricane evacuation or BOP repair. Drilling or production liner tops should not require negative testing upon installation. Testing should be deferred until just prior to performing an operation where a negative load is anticipated on a liner top or wellhead hanger BSEE agrees with the comment. We revised § 250.423(c) to require the negative pressure tests only on wells that use a subsea BOP stack or wells with mudline suspension systems. See the response to the previous comment. § 250.423(c) The magnitude and duration of an acceptable negative test should be provided for consistency. Recommend negative tests on subsea wells to be equal to SWHP at the wellhead We revised the Final Rule to require the negative test be performed to the same degree of the expected pressure once the BOP is disconnected. § 250.423(c) 30 CFR 250.423(c) requires negative testing of intermediate casing and liner tops, but offers no guidance as to the magnitude of the required negative test. As an experienced deepwater driller, I've assumed that BOEMRE meant for this testing to apply to intermediate casing string seal assemblies on subsea wells. That mimics what the well would see in a BOP stack disconnect situation. I see no valid reason to be negatively testing intermediate casing shoes that will be subsequently drilled out. I'd also like to understand the rationale behind a negative test on all liner tops. Just because a liner top tests negatively doesn't mean it won't fail if the well is exposed to a differential as a result of a blow out. I see a negative test on production liner tops as a prudent thing, but this type testing of drilling liners that will ultimately be covered up can increase risk in certain situations (small platform rig on a floating facility with limited pit space could get into an unintended well-control situation dealing with the fluid handling/movements required by a negative test) BSEE agrees. We revised this requirement to require the negative pressure tests only on wells that use a subsea BOP stack or wells with mudline suspension systems. See the response to the previous comments. § 250.442 Must heavy weight drill pipe be shearable with blind shear rams? Blind-shear rams must be capable of shearing any drill pipe in the hole under maximum anticipated surface pressure, including heavyweight drillpipe. This Final Rule revises § 250.416(e) to include workstring and tubing to clarify that these are also considered drill pipe and need to be shearable by the blind-shear rams. § 250.442 What does “operable” mean for dual pod controls? Does it mean 100 percent functional and redundant? The provision under § 250.442(b), for an “operable dual-pod control system” was an existing requirement and was included in the IFR because that section was rearranged into a table to accommodate the new provisions. The meaning of “operable dual-pod control system” has not changed. The commenter is correct in that these are redundant systems. Each pod has to be independent of the other and 100 percent functional. § 250.442 In § 250.442(c), what does “fast” mean for subsea closure and what are the “critical” functions? As specified in § 250.442(c), the accumulator system must meet or exceed the requirements in API RP 53, section 13.3, Accumulator Volumetric Capacity. § 250.442 What will be competency basis for qualification of an individual to operate the BOP's? The operator must ensure that all employees and contract personnel can properly perform their duties, as required under § 250.1501. Section 250.442(j) prescribes training and knowledge requirements for persons authorized to operate critical BOP equipment. §§ 250.442(d), § 250.515(e), and § 250.615(e) While the verified ability to close one set of pipe rams, close one set of blind-shear rams, and unlatch the lower marine riser package using a Remotely Operated Underwater Vehicle (ROV) is critical, the time delay associated with launch and subsea deployment of an ROV will likely have enabled the full force of a major blowout to already clear the well bore and result in excessive pressures and a debris stream at the BOP that can complicate efforts to shut in the well. Preventive and precautionary measures are a priority, and immediate shut-in capability will always be more critical than after-the-fact ROV response; thus this initiative should go further toward ensuring more immediate wild well shut-in capabilities, either in the current rulemaking, or in a future rulemaking We agree that there is a time delay associated with the launch and deployment of an ROV and that preventative and precautionary measures are a priority and immediate shut-in capability is critical. The intent of the provision is to ensure that an ROV is available in the unlikely event that all other measures fail. This regulation is intended to address broad issues related to well-control; BSEE is planning future regulations that will focus on preventative measures and improving immediate response capabilities. §§ 250.442(e), 250.515(e), and 250.615(e) The ROV crews should not be required on a continuous basis, this item needs to be revised to reflect the need for having a trained ROV crew on board only when the BOP is deployed BSEE agrees with the substance of this comment and has revised § 250.442(e) accordingly. § 250.442(j) What is meant by operate critical BOP equipment, maintenance, or activation of equipment? Section 250.442(j) establishes minimum requirements for personnel who operate any BOP equipment. The paragraph expressly refers to BOP hardware and control systems. In addition, other paragraphs of § 250.442 refer to specific features of the BOP and associated equipment. Any person authorized to operate or maintain any of the BOP components or systems must satisfy the requisite training and knowledge requirements. §§ 250.446(a), 250.516(h), 250.516(g), and 250.617 (Section numbers refer to the IFR.) The recordkeeping requested should be a responsibility of the drilling contractor. Many operations are short lived contracts and once the rig is released, the contractor has no obligation to ensure the records remain on the rig. Drilling contractors should be required to have a BOPE certification program complete with a certificate of compliance that is renewed every 3 to 5 years by a certification agency or class society. This will assure drilling contractors maintain their equipment to a higher standard on a routine basis Under § 250.146(c), lessees, operators, and persons performing an activity subject to regulatory requirements are jointly and severally responsible for complying with regulatory requirements. This includes contractors maintaining and inspecting BOP systems. See the discussion in the section-by-section portion of this preamble. Certification documents for rental BOPE would also be used by the operator or contractor depending upon who is renting the equipment §§ 250.446(a), 250.516(h), 250.516(g), and 250.617 (Section numbers refer to the IFR.) We believe that API-recommended practices have not proven to be a standard that has generated full and verifiable compliance by all. Require documentation of BOP inspections and maintenance according to API RP 53. The codification of API-recommended practices via Federal regulations will be needed to ensure reliable compliance going forward. This should take place in the current rule, or, at a minimum, in a future rule BSEE already requires operators to follow Sections 17.10 and 18.10, Inspections; Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, Quality Management, described in API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells. We continually review standards and our use of these standards. We may consider additional documentation from operators in future rulemaking. § 250.449(h) Are the requirements for function test for normal or high pressure function or both? In § 250.449(h), request change from the required duration from 7 days to 14 days. The basis for this is to mitigate the risk and exposure due to the additional tripping of pipe out of hole in order to function test blind/shear rams Section 250.449(h) is a previously existing requirement that was included in the IFR only to make editorial changes to accommodate new requirements in subsequent paragraphs. The requested revision is outside the scope of this rulemaking. §§ 250.449(j), 250.516(d)(8) (Section numbers refer to the IFR.) Stump test ROV intervention functions This does not go far enough. This is insufficient. It is necessary that the BOP ROV functions be regularly tested at the seabed with the ROV that would be used in an emergency. The only requirement of the stump test should be to test the plumbing. The BOP ROV functions should be tested at each BOP test when at operating hydrostatic pressures and temperatures Section 250.449(j) requires the operator must test one set of rams during the initial test on the seafloor. In this Final Rule, we added that the test of the one set of rams on the seafloor must be done through an ROV hot stab to ensure the functioning of the hot stab. BSEE may consider additional requirements in future rulemaking. § 250.449(k) Section 250.449(k) explains: “[f]unction test auto shear and deadman systems on your subsea BOP stack during the stump test. You must also test the deadman system during the initial test on the seafloor.” We do not recommend testing the deadman system when the stack is attached to a subsea wellhead. If the rig experiences a dynamic positioning incident, i.e., a drive-off or drift-off during the test, the only alternative system available to disconnect from the wellhead is the ROV intervention system. Failure to disconnect in time could result in serious damage to the rig equipment, the well head, or the well casing. As an alternative, we believe it would be more appropriate to test the autoshear system subsea. Such a requirement will test the same hydraulic system as the deadman, however, the autoshear function does not disable the control system and create the same well and equipment hazards as testing the deadman system BSEE believes that not testing the deadman system is a greater risk than conducting the test. Testing the deadman system on the seafloor is necessary to ensure that the deadman system will function in the event of a loss of power/hydraulics between the rig and the BOP. To help mitigate risk for the function test of the deadman system during the initial test on the seafloor, we added that there must be an ROV on bottom, so it would be available to disconnect the LMRP should the rig experience a loss of stationkeeping event. We also added clarifications for the required submittals of procedures for the autoshear and deadman function testing, including procedures on how the ROV will be utilized during testing. § 250.449(k) Modify deadman system testing requirements to increase safety As drafted, operators must test the deadman system during the initial test on the seafloor. Intentionally disabling the deadman system increases the risk to personnel, well bore and equipment should a “power management” or “loss of station keeping” incident occur during a deadman system test. Testing of the deadman system requires shutting down of power and hydraulic systems to the BOP thereby eliminating the ability to disconnect in a controlled manner should a “power management” or “loss of station keeping” incident occur. As a result, rig personnel could be exposed to the consequences of a violent release of tension if a riser component fails and seafloor architecture will be exposed to released/dropped riser components. Revise the deadman system testing requirement, bringing it in line with the proposed new API RP-53, 4th Edition recommendations. Specifically, testing should be completed during commissioning, rig acceptance and if any modifications or maintenance has been performed on the system, not to exceed 5 years BSEE believes that not testing the deadman system is a greater risk than conducting the test. Testing the deadman system on the seafloor is necessary to ensure that the deadman system will function in the event of a loss power/hydraulics between the rig and the BOP. To help mitigate risk for the function test of the deadman system during the initial test on the seafloor, we added that there must be an ROV on bottom, so it would be available to disconnect the LMRP should the rig experience a loss of stationkeeping event. We also added clarifications for the required submittals of procedures for the autoshear and deadman function testing, including procedures on how the ROV will be utilized during testing. BSEE will review API RP-53, 4th Edition, and decide if it is appropriate for incorporation, after it is finalized. §§ 250.449(k), 250.516(d)(9), 250.616(h)(2) (Section numbers refer to the IFR.) We recommend testing the deadman system when attached to a well subsea upon commissioning or within 5 years of previous test but not at every well. If during the testing time the rig experiences a dynamic position incident, i.e., a drive off or drift off, the only options to disconnect from the well are acoustically (if acoustic system fitted), or with an ROV. Failure to disconnect in time could result in serious equipment damage, and/or damage to the well head BSEE believes that not testing the deadman system is a greater risk than conducting the test. Testing the deadman system on the seafloor is necessary to ensure that the deadman system will function in the event of a loss power/hydraulics between the rig and the BOP. To help mitigate risk for the function test of the deadman system during the initial test on the seafloor, we added that there must be an ROV on bottom, so it would be available to disconnect the LMRP should the rig experience a loss of stationkeeping event. We also added clarifications for the required submittals of procedures for the autoshear and deadman function testing, including procedures on how the ROV will be utilized during testing. §§ 250.449(k) and 250.516(d)(9) (Section numbers refer to the IFR.) Stump test the autoshear and deadman. Test the deadman after initial landing Both the deadman and autoshear should be tested on the seabed. Moreover the Deadman should include a disconnect function. However, the LMRP connector should not be unlocked during this test. Rather, the LMRP disconnect function should be plumbed in such a way that during the test the fluid can be vented to sea rather than to the unlatch side On the initial test on the seafloor, the operator is required only to test the deadman system. The rule requires operators to submit their test procedures with the APD or APM for approval. BSEE may develop specific test procedures at a later time. § 250.451(i) A successful seafloor pressure and function test of the BOP following a well-control event also is an acceptable means of verifying integrity. Ram sealing elements would be compromised before damage to the rams themselves would be extensive enough to prevent successful shearing of pipe. Additionally, plugging an open hole that may be experiencing ballooning and gas following a well-control event and pulling the BOP and riser present safety and operational risks that are likely much greater than proceeding with the drilling program using a fully tested BOP stack After a well-control event where pipe or casing was sheared, a full inspection and pressure test assures that the BOP stack is fully operable. The rule requires the operator to do this only after the situation is fully controlled. § 250.451(i) We believe § 250.451(i) is best read to only require a subsea BOP stack to surface when pipe is sheared, rather than actuated on an empty cavity. We request that the agency clarify that the requirement to pull a subsea BOP stack to surface after actuating the blind shear rams does not apply when the blind shear rams are actuated on an empty cavity, but applies when pipe is sheared BSEE agrees with the comment that § 250.451(i) does not apply to actuation of shear rams on an empty cavity. Section 250.451(i) states that an operator must retrieve the BOP if: “You activate the blind-shear rams or casing shear rams during a well-control situation, in which pipe or casing is sheared.” § 250.456(j) Does this requirement only refer to the end of well during abandonment or at any time during the drilling of a well? There are times when mud weight is cut prior to drilling out a casing shoe due to exposure of weak formations or anticipated lost circulation. Would approval be required to cut mud weight in these circumstances? Consider that mud weight is cut just prior to drilling out the shoe in a controlled environment at which time the entire system is negative tested with pipe in the hole at TD and BOPs are capable of shutting in the well if and when needed This Final Rule revises § 250.456(j) to clarify that this requirement applies any time kill-weight mud is displaced, putting the wellbore in an underbalanced state. If the mud weight is cut, but the wellbore will remain in an overbalanced state, then approval is not required. §§ 250.515 and 250.616 It appears that some of the requirements of NTL 2010-N05 which applied to workover BOPs have been omitted in the revision to 30 CFR 250.5XX and 250.6XX. Specifically, verification that the blind/shear is capable of shearing all pipe in the well at MASP has been omitted for workover and coiled tubing operations. Verification of this capability is as important in workover as it is in drilling, for both surface BOPs and subsurface BOPs. API RP 16ST, “Coiled Tubing Well-control Equipment Systems”, Section 12, “Well-control Equipment Testing”, should be referenced in 30 CFR 250.6XX in addition to the reference to API RP 53 BSEE agrees that it is important for BOP requirements to be consistent, regardless of the application or stage of a well. These requirements should also apply to well-completion and well-workover activities. We changed the regulatory text in §§ 250.515 and 250.615 to reflect this. In addition, in response to the concern raised by the commenter, this Final Rule adds these requirements to subpart Q, since the same equipment used in drilling and workovers may be used in decommissioning operations, and similar safety risks also exist. BSEE may consider incorporating by reference API RP 16ST, “Coiled Tubing Well-control Equipment Systems” in future rulemaking. § 250.1503 What is the definition of enhanced deepwater well-control training? Will this require a new certification of well-control schools? The rule does not use the phrase, “enhanced deepwater well-control training.” It does require deepwater well-control training for operations with a subsea BOP stack. The operator must ensure that all employees are properly trained for their duties as required in § 250.1501. BSEE expects that operators will integrate the deepwater well-control training requirement into their current subpart O well-control program. §§ 250.1712(g), 250.1721(h), and 250.1715 Liabilities that will be placed onto a “Professional Engineer (PE)” are an issue. The PE approach demands that the PE is intimately involved in all aspects of the design and also in primary communication as the well is drilled and small variations in the plan are made or happen All liability for the well must remain with the operator without any “dilution” to a PE, although review by a PE or other “independent and reputable” third-party is totally appropriate The operator is responsible for all activities on its lease, regardless of requirements for various persons to certify or verify various aspects of operations. Although persons performing certifications and verifications have responsibility for their actions, such responsibility will not eliminate or diminish the operator's responsibilities for compliance with applicable requirements. Table 2—Topics and General Questions Comments and Responses Topic Comment BSEE response Participate in Standard Development BOEMRE should participate in API's open process for adopting industry standards on an on-going basis BSEE agrees that its involvement in the standard development process with API and other standards organizations is important. We are already active in API's industry standard process and we are committed to continuing and increasing this involvement. Participate in Standard Development BOEMRE should participate in revising American Welding Society's (AWS) standards. AWS's standards committees comply with ANSI-approved procedures for standards development, which, among other things, guarantee public and open participation by any materially affected entity, committee interest group balance, fair voting, and written technical issue resolution. AWS solicits ongoing input and comments for these revisions from any interested party, including BOEMRE. BOEMRE's input to the standards committees would be invaluable to help understand the goals of the government and to apply AWS's experts' thoughtful consideration to ongoing regulatory issues. Moreover, participation in AWS standards-setting would provide BOEMRE with access to valuable scientific and technical expertise BSEE agrees that its involvement in the standard development process with AWS and other standards organizations is important. BSEE accepts this and other offers to participate in the development of standards that support the mission of BSEE. Subsea BOP Requirements More work should be carried out in this area before final requirements are identified. In particular, the findings of the post-mortem on the Horizon BOP should be carefully looked at prior to a “final rule'' BSEE reviewed the findings of various DWH investigations before developing the Final Rule. Findings from the DWH investigation that are within the scope of this rulemaking were incorporated. BSEE will address other findings in future rules. Blind-Shear Ram Redundancy Requirements With this rule, BOEMRE has made the important first step of requiring independent third-party verification of blind shear ram capability, but deferred one of the most critical safety improvements, the requirement to install redundant blind-shear rams in each OCS BOP, to a later rulemaking process. We recommend that redundant blind-shear rams be required for all OCS drilling operations as of June 1, 2011 BSEE is considering this requirement for future regulations. We do recognize the importance of having redundant safety features on BOP stacks. However, we need to consider all the impacts of such a requirement before requiring it by regulation. BSEE has concluded that the requirements of the IFR, as modified by this Final Rule, have enhanced operational safety sufficiently until such time that BSEE determines whether to add a requirement for additional blind-shear rams. Accident Event Reporting Also missing from the IFR is a requirement that OCS operators and their contractors report to BOEMRE any accidental event that could significantly impact well integrity or blowout prevention. This proposed reporting requirement includes, but is not limited to, any event where blowout preventer seal material may be compromised BSEE's incident reporting requirements are covered in §§ 250.187 through 250.190. Specifically, § 250.188(a)(3) requires the reporting of all losses of well-control, including uncontrolled flow of formation or other fluids; flow through a diverter; or uncontrolled flow resulting from a failure of surface equipment or procedures. We are looking into expanding the reporting requirements in future rulemaking. Third-party Certifications The rule makes repeated references to third-party “verification” of certain matters related to well-control equipment, including BOPs. The appropriate functional terminology should be “certification,” rather than “verification.” In industry practice, “certification” and “verification” are different functions. A party that “certifies” a process is different from the party that “verifies” the certified process is being followed. This is more than a definitional difference We disagree with the commenter's suggestion. The repeated use of the concept of independent third-party “verification” in § 250.416 and conforming provisions of the other subparts derives directly from various recommendations of the Department's May 10, 2010 Safety Measures Report, e.g., Safety Measures Report Recommendations I.A.2 and I.C.7 (pp. 20-21) that use the term “verification.” The preparers of that report appear to have understood the distinction between “certification” and “verification” because in other recommendations the term “certification” is used, e.g., Recommendation I.A.1, recommending a written and signed third-party “certification” of certain things. Although a distinction may exist between certification and verification, the provisions of the Final Rule requiring third-party verification of certain features use that term correctly and, together with the other provisions of the Final Rule, establish an adequate basis to reduce safety risks associated with BOP stacks. These rules provide a substantial upgrade over the previous rules that did not contain such provisions. Table 3—Regulatory Impact Analysis Comments and Responses Topic Comment BSEE response Regulatory Impact Analysis The increased costs will negatively impact future OCS development. The IFR itself estimated the baseline risk of a catastrophic blowout at once every 26 years. 75 FR at 63365. This estimate for a blowout in the Gulf of Mexico is even lower, as it appears the estimate used by BOEMRE is based on worldwide catastrophic blowout data BSEE will continue to evaluate regulatory changes that could result in offsetting cost savings for OCS operators as directed by the President in his January 18, 2011 executive order, “Improving Regulation and Regulatory Review.” The estimate for the risk of a catastrophic blowout event is based upon one recorded GOM catastrophic blowout event and the historical number of deepwater GOM wells drilled, not world-wide blowout data. Going forward, we estimated the drilling of 160 deepwater wells annually for cost estimation purposes. The 160 deepwater wells per year may be more than will be drilled when considering all of the factors influencing GOM deepwater activity outside of this specific regulation. At the time of this analysis (during the summer of 2010), this number was estimated to be a reasonable baseline for the regulatory benefit-cost analysis. If on average fewer than 160 deepwater wells are drilled annually, the baseline activity scenario provides an upper bound regulatory cost estimate. If an estimate of 120 deepwater wells per year is used in the benefit-cost calculation, both the cost and the benefit i.e., interval between blowouts will decrease by approximately the same factor. The historical risk of a catastrophic blowout event will be reduced from once in 26 years to once in 34 years. Regulatory Impact Analysis The costs for compliance prepared by the Agency are not reflective of the total cost of compliance and thus will negatively affect both small and large businesses more than alleged by the Agency Multiple commenters suggested that the costs of this rulemaking were not fully captured in the Regulatory Impact Analysis. BSSE and BOEMRE used the best available information to determine the compliance cost estimates for this rulemaking. The commenters do not identify specific regulatory provision where costs are claimed to be underestimated. Several of the compliance costs commenters associated with this rulemaking reflect provisions in existing regulations. Additionally, no alternative cost estimates are provided by this commenter. External factors influencing the cost of operating on the OCS are not considered to be compliance costs of this rulemaking. As explained in other portions of this preamble, BSEE has both decreased and increased some cost estimates for provisions in this rulemaking. However, the net estimated compliance cost has decreased from the estimate contained in the IFR. Regulatory Impact Analysis The benefit-cost analysis implies that a blowout may pose more problems in deepwater where drilling a relief well is likely to take longer. I find this statement troubling. It could be considered to imply, that it takes longer to penetrate seawater than hard rock. As an example, two drilling targets are at 20,000 feet total vertical depth (TVD). One is in 500 feet of water and the other is in 5,000 feet of water. For a well drilled in 500 feet of water an additional 4,500 feet of hard rock drilling must be completed to reach the target. From public well data on the BOEMRE website, I found the following pair of wells: API Number TVD Water Depth Time to Reach Total Depth 608124001700 28497 6959 ft 200 days 427084062600 28382 100 ft 390 days It is possible that the statement is true, that is due to a different distribution of TVD in shallow and deep water drilling targets. BOEMRE needs to be rigorous to see if its conjectures are supported by the data. This is part of a pattern of the claim that deep water activities are more risky than shallow water. This assumption is being made by BOEMRE as a result of the Deepwater Horizon incident The typical GOM exploratory well in shallow water takes less than 30 days to reach TVD. The typical GOM deepwater exploratory well takes nearly 90 days to reach TVD. This is primarily because, on average, shallow water wells are not drilled to depths as deep as deepwater wells. Well-completions for “wet” wells and abandonment for “dry” wells take additional time. While exceptions can be found, we maintain that in most cases our assumption will hold that a deepwater relief well will take longer than a shallow water relief well. Regulatory Impact Analysis The agency estimates 160 deepwater wells annually for the next 20 years. This is a very important estimate, since it drives the estimates of both the costs and benefits. Granted projections of the future in the oil and gas industry have been notoriously wrong. I see that 160 wells annually as overly optimistic. My reasons are: —Historical data show a declining trend of the most recent years with all observations below 160 —Deepwater Horizon incident will lead to less favorable conditions for drilling in the Gulf —Natural Gas from shale is a major disruption coming to North American energy markets. This is analogous to the cellular phone technology replacing land line phones in the last 20 years A better way of presenting the future benefits and costs is with a range of scenarios such as 160, 120 and 80 wells a year. The Deepwater Horizon incident will lead to less favorable conditions for drilling in the Gulf of Mexico A reduction in the number of wells drilled per year will reduce the estimated annual compliance costs as well as the corresponding likelihood of a catastrophic blowout and hence the potential gains from any improvements in reliability. How much the new regulatory environment will affect future OCS drilling is unknown at this time. BSEE estimates the drilling of 160 deepwater wells annually for cost estimation purposes. The 160 deepwater wells per year may be more than will be drilled when considering all of the factors influencing GOM deepwater activity outside of this specific regulation. At the time this analysis was prepared for the IFR during the summer of 2010, it was estimated to be a reasonable baseline for the regulatory benefit-cost analysis. One hundred sixty deepwater wells per year can serve as an upper bound cost estimate for the regulation. If an estimate of 120 deepwater wells per year is used in the benefit-cost calculation, both the cost and the benefit will decrease by approximately the same factor. The historical risk applied to future drilling estimates for 120 wells per year will reduce the estimated risk from once in 26 years to once in 34 years. For only 80 deepwater wells a year, the risk will be reduced to once each 52 years. A scenario analysis for 120 deepwater wells per year has been added to the benefit-cost analysis. Regulatory Impact Analysis BOEMRE estimates an equal likelihood of serious damage or sinking of a MODU drilling rig from a catastrophic blowout event. Press reports indicate the sinking of Deepwater Horizon was due to bad fire fighting procedures. That is, pouring seawater on the floating vessel causing it to sink. When the accident report is completed, new standard practices should emerge for fire fighting with the byproduct of great reduction in the probability of sinking BOEMRE's estimate, in the IFR, of an equal likelihood of loss or damage, is based on the two recorded events for severe damage or destruction of deepwater MODUs in the GOM. This rulemaking requires additional the testing of LMRP disconnect functionality. A disconnect of a deepwater MODU during a catastrophic event will likely protect the MODU from total loss. BSEE maintains that our baseline cost estimate for deepwater MODU damage is reasonable for purposes of this benefit cost analysis. Regulatory Impact Analysis The benefit-cost sensitivity analysis provided no basis for the assumption that reservoirs at depths of 3,000 feet are generally more prolific than their shallow water counterparts. That statement is contradicted by most recent Reserves Report ( http://www.gomr.boemre.gov/homepg/offshore/fldresv/2006-able4.pdf ) which shows of the 20 largest fields in the Gulf of Mexico, only five are located in depth greater than 3,000 feet The report referenced by the commenter does indicate that only 5 of the 20 largest GOM fields are in water depths greater than 3,000 feet. If the top 20 fields are further analyzed, 6 of the top 20 fields are in water depths of 2,860 feet or greater and discovered since 1989. Fourteen of the fields are in water depths 247 feet or less and discovered in 1971 or earlier. The GOM shelf is in decline and few large fields are likely to be discovered in the GOM shallow water. Over the last 40 years the largest fields with booked reserves have all been in deepwater. BSEE maintains that the basis for the sensitivity analysis that future discovered reservoirs at water depths of 3,000 feet or greater will be more prolific is a reasonable assumption for the benefit-cost scenario analysis for this rule. Regulatory Impact Analysis The agency's estimation of costs is not consistent with our own estimates and we strongly encourage the agency to carefully review the assumptions that went into your analysis. Moreover, to potentially assist you with your examination of the socio-economic costs and consequences of the regulation, we have enclosed a report we commissioned by IHS-Global Insight entitled, “The Economic Impact of the Gulf of Mexico Offshore Oil and Natural Gas Industry and the Role of the Independents,” which determined that more than $106 billion in Federal, state, and local revenues would be lost over a 10-year period if independents were excluded from deepwater. Obviously, this report examined broader policy impacts than were encompassed in the particular regulation, but we believe it provides a useful data set to examine these regulations within a broader context of impacts We have reviewed the report by IHS-Global Insight and found nothing that will substantiate, contradict or otherwise provide compliance cost figures for this rulemaking. Since the commenter's own estimates were not provided, we cannot evaluate alternative cost estimates suggested by the commenter. The Final Rule does not exclude independents from deepwater drilling. Regulatory Impact Analysis—Small Business Impacts In its notice, BOEMRE included certain information regarding the composition of the oil and gas industry and the small business entities—lessees, operators, and drilling contractors—that will be most affected by this interim rule. BOEMRE estimates that $29 million dollars or 15.8 percent of the IFR's total cost of $183 million will be borne by small businesses. This cost would comprise about 0.36 percent of these small businesses' fiscal year 2009 revenue BOEMRE does not discuss how the regulation's costs would be distributed among small businesses. Advocacy is concerned that these costs will impact certain small businesses more heavily than others. We encourage BOEMRE to include additional information regarding how the industry functions and which small entities are most likely to incur increased costs as a result of this IFR. We also recommend that BOEMRE include a more detailed discussion of the distribution of costs among the small entities identified in the IRFA (Initial Regulatory Flexibility Analysis) in order to accurately determine whether some small entities will incur disproportionate impacts as a result of this rule BOEMRE published a separate IRFA on December 23, 2010 (75 FR 80717) with a 30 day comment period. The IRFA and the FRFA published with the final RIA provide the analysis required in the Regulatory Flexibility Act. This includes an estimate of the number of small entities affected, a description of reporting, recordkeeping requirements and evaluation of significant alternatives that could minimize the impacts on small entities while accomplishing the objectives of this rulemaking. The RFA requires agencies to include in their IRFA a description of any significant alternatives to the proposed rule that minimize significant economic impacts on small entities while still accomplishing the agency's objectives. While BOEMRE did note a few alternatives in the interim rule, we recommend that BOEMRE include a more detailed discussion of the alternatives and their effects on small business and the reasons for or against adopting those alternatives. We further recommend that BOEMRE continue to conduct outreach with small entities affected by this rule and any future safety rules to develop alternatives that minimize disproportionate impacts on small entities Regulatory Impact Analysis—Small Business Impacts A commenter estimated that the rulemaking will increase costs by $17.3 million for each deepwater well drilled with a MODU. This cost increase is attributed to required modification of the well plan and associated casing design that results in the addition of a liner and associated work The compliance costs for the IFR were estimated using the best available information at the time of publication. Neither the IFR nor this Final Rule requires operators to conform to a specific casing design, nor do they require new designs for well plans. The additional requirements of the IFR are intended to increase the safety of operating on the OCS considering the best available and safest technology. The commenter does not identify which elements increase either the time to drill a well by 15 rig days, or the cost by $17.3 million. Absent new and well-defined information, BSEE is unable to evaluate or adjust the compliance cost estimates for a deepwater well. Regulatory Impact Analysis—Small Business Impacts § 250.449(h) A commenter identified $10.45 million in BOP inspection cost savings per deepwater well. The proposal is to function test the blind-shear rams every 14 days instead of every 7 days as required by § 250.449(h). The commenter claims “prior to the Macondo incident, all the rams on the BOP were function tested once a week except for the blind-shear rams.” Another commenter claims that “ * * * frequent function testing of blind/shears will exacerbate this stack body wear and introduce further exposure to leakage within the BOP” The Final Rule does not change the existing regulation at § 250.449(h) which requires a function test every 7 days including the blind-shear rams. The 7-day testing requirement existed before the Macondo event and is not being made more stringent with this rulemaking. The commenter's assertion that “prior to the Macondo incident, all the rams on the BOP were function tested once a week except for the blind-shear rams” is incorrect. The $10.45 million figure does not represent an additional compliance cost due to this rule, but an estimated cost savings to the company on a per-well basis if their recommendation for a once-every-two weeks function test requirement is accepted. A Joint Industry Project study completed in 2009 analyzed BOP equipment reliability. The results of this study suggest that up to $193 million per year could be saved through less frequent testing while achieving the same reliability for BOP performance. However, at this time BSEE believes increasing the duration between tests poses a greater risk than conducting the test on the current schedule. BOP testing frequency is a topic that merits further study. Regulatory Impact Analysis—Small Business Impacts Several commenters claim that the compliance costs are significantly higher than BOEMRE's estimate. One comment suggests that the “Final Rule will add three to five times the amount the BOEMRE has published.” Another comment claims that the new regulation will cost as much as $28 million per deepwater well for compliance, compared to the $1.42 million estimated by BOEMRE BSEE has considered the limited cost information provided by commenters and new time and cost estimates obtained by the bureau since the publication of the IFR. The commenter's $28 million compliance cost estimate includes a $10.45 million cost from additional BOP tests. However, these additional BOP tests do not represent additional costs, but a cost savings if the company's recommendation to function test the blind shear rams every 7 days instead of every 14 days (with regard to the previously existing regulation) is accepted. If the recommendation is not accepted, there is no increased compliance cost for this rulemaking. This proposal on function test intervals is outside the scope of this rulemaking as previously stated in the response to comments for § 250.449(h). The additional $17.3 million of compliance costs are claimed to result from “modified casing design” and “associated work.” The lack of specific data or citations result in a vague and indeterminate interpretation of these cost estimates. BSEE does not specify well designs. If a new well design used by the operator is the result of industry best practices, it is not a compliance cost of the regulation. As such, BSEE cannot comment on the presumed cost impact for modified casing design and associated work. IRFA The IRFA published by BOEMRE does not satisfy the agency`s statutory obligation under the Regulatory Flexibility Act of 1980, as amended. The commenter believes that, since there is not a good cause exception to the Administrative Procedure Act`s notice and comment rulemaking requirement, BOEMRE was required to publish an IRFA at the time of the proposed rulemaking. Further, the IRFA BOEMRE eventually published did not account for the significant costs likely to be imposed by BOEMRE`s new interpretation of 14,000 discretionary provisions found in API standards as mandatory permitting requirements The BSEE published an IRFA pursuant to the Regulatory Flexibility Act. While it was not published with the IFR, it was published shortly thereafter and made available for public comment. The SBA Office of Advocacy stated in its comments that “Advocacy appreciates BOEMRE's decision to publish a supplemental IRFA.” The comments on the IRFA were considered along with all comments on the rulemaking. Regarding the 14,000 discretionary provisions from API standards, BSEE disagrees with the commenter's assertion that § 250.198(a)(3) will have resulted in significant additional costs. See the section-by-section discussion for further elaboration of this issue. V. Section-by-Section Discussion of the Requirements in Final Rule As of October 1, 2011, BOEMRE was officially reorganized into the separate agencies of BSEE and BOEM. This Final Rule reflects the appropriate name changes, based on the reorganization. Nomenclature change. BSEE is revising all references to the term glory hole in the regulations at 30 CFR 250 to the term well cellar. This revision will amend text at two locations in the regulations (§§ 250.421(b) and 250.451(h)). Both terms refer to a depression deep enough to protect subsea equipment from ice-scour, when drilling in an ice-scour area. However, the term well cellar is more commonly used. Service Fees (§ 250.125) This Final Rule updates § 250.125(a)(8) and (9) in the chart to reflect accurate numbering redesignation. Documents Incorporated by Reference (§ 250.198) Final § 250.198(a)(3) has been modified from the IFR in response to many comments received on one important issue. Section 250.198(a)(3) pertains to how BSEE ensures compliance with documents incorporated by reference in its regulations. The provision in the IFR read as follows: The effect of incorporation by reference of a document into the regulations in this part is that the incorporated document is a requirement. When a section in this part incorporates all of a document, you are responsible for complying with the provisions of that entire document, except to the extent that section provides otherwise. When a section in this part incorporates part of a document, you are responsible for complying with that part of the document as provided in that section. If any incorporated document uses the word should, it means must for purposes of these regulations. (75 FR 63372) This provision was intended to clarify BSEE's existing policy on compliance with documents incorporated by reference in regulations. A number of commenters from the offshore oil and gas industry objected to this provision. The commenters were particularly concerned about the statement in the last sentence of the paragraph that for the documents incorporated by reference in 30 CFR part 250, the word “ should” means “ must.” Commenters asserted that there are 14,000 occurrences of the word “ should” just in documents incorporated from the American Petroleum Institute (API). These commenters provided a number of examples in which they asserted that the last sentence of paragraph (a)(3) could cause conflicts; undermine safety, instead of improving safety on the Outer Continental Shelf (OCS); and, in certain circumstances, establish requirements with which compliance may be impossible. Accordingly, such commenters specifically requested that the agency remove the last sentence from paragraph (a)(3). While some of the examples provided by commenters were overstated or did not account for alternatives or for the specifics in the operative language of the incorporated documents, we have removed the last sentence of paragraph (a)(3) as set forth in the IFR because it could have appeared to be overly broad and may not have provided the intended clarification. The last sentence is not needed as a means of emphasizing the agency's interpretation of the binding effect of documents incorporated by reference, i.e., BSEE relies on the specific regulatory provisions that incorporate a document by reference for the intended effects of each incorporation. The other portions of paragraph (a)(3) make it clear that operators are required to comply with documents incorporated by reference, unless the specific sections performing the incorporation provide otherwise. Moreover, many, but not all, of the individual sections of BSEE regulations that incorporate documents by reference are written in terms that make it clear that compliance is mandatory, even where the incorporated consensus standards were written as recommendations, not obligations. This position is not a new one and was the agency's interpretation of documents incorporated by reference long before the adoption of the IFR. For instance, in a 1988 Federal Register preamble to the final rule converting agency orders into regulations, the MMS, a predecessor agency to BSEE and BOEM, responded to public comments on the effect of incorporating documents by reference in its rules as follows: Comment —Objection was raised to the incorporation by reference of “recommended practice” documents which are intended only as recommendations, not as rules. Response —When MMS adopts the specific provisions of a document through the rulemaking process, that incorporation by reference establishes the recommended practice as a minimum standard which must be observed. Comment —A number of commenters expressed the view that with respect to documents incorporated by reference, it should be clear to what extent references within such incorporated documents are also binding. It was pointed out that documents proposed to be incorporated by reference in turn reference other documents, which reference other documents, down through numerous tiers. Response —Under the final rule, the material that is incorporated by reference is specifically identified. Adherence to documents referenced within an incorporated document is mandatory if such adherence is necessary for compliance with the document referenced in the rule. (53 FR 10600) We reaffirm our position stated in the agency's April 1, 1988, (53 FR 10600) rule that when BSEE adopts the specific provisions of a document through the rulemaking process, that incorporation by reference establishes the recommended practice as a minimum standard which must be observed. We recognize, however, that certain regulations incorporating documents by reference either do not make compliance mandatory with the incorporated provisions, or provide operators some flexibility in achieving compliance. For instance, regulations at § 250.415(f) incorporate by reference API RP 65—Part 2, Isolating Potential Flow Zones During Well Construction. The requirement in § 250.415(f) specifies that operators must submit a written description of how they evaluated the best practices included in API RP 65—Part 2, not that they must comply with each of the best practices. This Final Rule is not intended to upset that interpretation or to modify the meaning of any particular regulatory provision that incorporates documents by reference. To the extent that the commenters were correct in asserting that the last sentence of § 250.198(a)(3) in the IFR (or other regulations that establish mandatory compliance with incorporated documents) will lead to unintended consequences, BSEE's rules already provide the means for operators to seek relief in situations where they need an alternative means to comply. One provision, § 250.141, allows operators to use alternative procedures or equipment that provides a level of safety and environmental protection that equals or surpasses that required by BSEE rules. Another, § 250.142, provides for departures from operating requirements. Other provisions throughout BSEE regulations allow for departures related to specific circumstances ( e.g., plans, drilling operations, and structure removal). It should be noted that all of these departures require advance BSEE approval. This approach was clarified in a March 28, 2011, Supplemental Information document that appears on the BSEE Web site. That document made it clear that the rules require operators to seek BOEMRE approval to deviate from a practice or procedure when the document incorporated by reference requires a particular practice or procedure. Incorporation of API Standard 65—Part 2, Second Edition In this Final Rule, we have modified § 250.198(h)(79) by incorporating the second edition of API Standard 65—Part 2 that was issued in December 2010. This change was made in response to comments. Previously, the first edition was incorporated. API also designated this recommended practice into a standard. What must my casing and cementing programs include? (§ 250.415) In the IFR, BOEMRE added a new § 250.415 (f) requiring the operator to include in its APD an evaluation of the best practices identified in API RP 65—Part 2, Isolating Potential Flow Zones During Well Construction. In the IFR, we also revised paragraphs (c), (d), and (e) to accommodate the new paragraph. The text of paragraph (f) was changed in this Final Rule to update the cross reference to sections 4 and 5 of the second edition of API Standard 65—Part 2. These sections correspond to sections 3 and 4 of the earlier edition that were previously cross-referenced. The basis and purpose for this section was set forth in the preamble of the IFR (75 FR 63346). In response to comments, BSEE developed a table, set forth below, based on API Standard 65—Part 2 Annex D which outlines the process summary for isolating potential flow zones during well construction. For example, the operator may use Annex D or the following Table 4 as a guide for complying with the written description of how an operator evaluated the best practices included in API Standard 65—Part 2 required by § 250.415(f). Table 4—Example of How To Evaluate the Best Practices in API Standard 65—Part 2 GENERAL QUESTIONS 1 Have you considered the following in your well planning and drilling plan determinations: evaluation for flow potential, site selection, shallow hazards, deeper hazard contingency planning, well-control planning for fluid influxes, planning for lost circulation control, regulatory issues and communications plans, planning the well, pore pressure, fracture gradient, mud weight, casing plan, cementing plan, drilling plan, wellbore hydraulics, wellbore cleaning, barrier design, and contingency planning? [API 65-2 1.5] Yes/No. 2 Have you considered the general well practices while drilling, monitoring and maintaining wellbore stability, curing and preventing lost circulation, and planning and operational considerations? [API 65-2 1.6] Yes/No. FLOW POTENTIAL 3 Will a pre-spud hazard assessment be conducted for the proposed well site? Yes/No. 4 List all potential flow zones within the well section to be cemented Describe below. 5 Has the information concerning the type, location, and likelihood of potential flow zones been communicated to key parties (cementing service provider, rig contractor, or third parties)? Yes/No. CRITICAL DRILLING FLUID PARAMETERS 6 Are fluid densities sufficient to maintain well-control without inducing lost circulation? Yes/No. CRITICAL WELL DESIGN PARAMETERS 7 Will you use a cementing simulation model in the design of this well? Yes/No. 7a If yes, how is the output of this simulation model used in your decision-making process? Describe below. 7b If no, include discussion of why a model is not being used Describe below. 7c Either way, include the number and placement of centralizers being used Describe below. 8 Will you ensure the planned top of cement will be 500 feet above the shallowest potential flow zone? Yes/No. 9 Have you confirmed that the hole diameter is sufficient to provide adequate centralization? Yes/No. 10 If there are any isolated annuli, how have you mitigated thermal casing pressure build-up? NA or Describe below. 11 Will you ensure the well will be stable (no volume gain or losses, drilling fluid density equal in vs. out) before commencing cementing operations? Yes/No. 12 List all annular mechanical barriers in your design Describe below. 13 Has the rathole length been minimized or filled with drilling fluid with a density greater than the cement density? Yes/No. 14a If you have any liner top packers exposed to the production or intermediate annulus, what is the rating for differential pressure across this packer? NA or Describe below. 14b If you have any liner top packers exposed to the production or intermediate annulus, have you confirmed that your negative test will not exceed this rating? Yes/No/NA. 15 What type of casing hanger lock-down mechanisms will be used? Describe below. 16 For all intermediate and production casing hangers set in subsea, HP wellhead housing, will you immediately set/energize the lock-down ring prior to performing any negative test? Yes/No. 17 For all production casing hangers set in subsea, HP wellhead housing, will you set/energize the lock-down sleeve immediately after running the casing and prior to performing any negative test? Yes/No. CRITICAL OPERATIONAL PARAMETERS 18 Will you have 1 mechanical barrier in addition to cement in your final casing string (or liner if it is your final string)? Yes/No. 19 Do you plan to nipple down BOP in accordance with the WOC requirements in 30 CFR 250.422? Yes/No. 20 Do you plan on running a cement bond log on the production and intermediate casing/liner prior to conducting the negative test on that string? Yes/No. Are contingency plans in place for the following: 21 Lost circulation? Yes/No. 22 Unplanned shut-down? Yes/No. 23 Unplanned rate change? Yes/No. 24 Float equipment does not hold differential pressures? Yes/No. 25 Surface Equipment issues? Yes/No. 26 Will you monitor the annulus during cementing and WOC time? Yes/No. 27 If using foam cement, is a risk assessment being conducted and incorporated into cementing plan? Yes/No. 28 If using foam cement, will the foamer, stabilizer, and nitrogen injection be controlled by an automated process system? Yes/No. CRITICAL MUD REMOVAL PARAMETERS 28 Have you tested your drilling fluid and cementing fluid programs for compatibility to reduce possible contamination? Yes/No. 29 Have you considered actual well conditions when determining appropriate cement volumes? Yes/No. 30 Has the spacer been modeled or designed to achieve the best possible mud removal? Yes/No. CRITICAL CEMENT SLURRY PARAMETERS 31 Have all appropriate cement slurry parameters been considered to ensure the highest probability of isolating all potential flow zones? Yes/No. 32 Do you plan on circulating bottom up prior to the start of the cement job? Yes/No. What must I include in the diverter and BOP descriptions? (§ 250.416) The IFR revised § 250.416(d) to include the submission of a schematic drawing of all control systems, including primary control systems, secondary control systems, and pods for the BOP system. We did not revise this paragraph in the Final Rule. The IFR revised § 250.416(e) to require the operator to submit independent third-party verification and supporting documentation that shows the blind-shear rams installed in the BOP stack are capable of shearing any drill pipe in the hole under maximum anticipated surface pressure, as recommended in the Safety Measures Report. In response to comments received, we emphasize that the blind-shear rams must be capable of shearing heavy weight drill pipe. The Final Rule also revises § 250.416(e) to clarify that drill pipe includes workstring and tubing. The IFR provided that the supporting documentation has to include test results, but did not specify which tests are required. The Final Rule clarifies that the documentation must include actual shearing and subsequent pressure integrity test results for the most rigid pipe to be used and calculations of shearing capacity of all pipe to be used in the well, including correction for MASP. The IFR added § 250.416(f) to require independent third-party verification that a subsea BOP stack is designed for the specific equipment used on the rig. In the Final Rule, we revised this paragraph to also include surface BOP stacks on floating facilities to clarify the intent that this verification is required for all floating drilling operations. This section also includes the requirements for verification that the BOP stack has not been compromised or damaged from previous service. BSEE realizes that an APD may be submitted prior to the third-party verification. Under such circumstances, BSEE may issue a condition of approval in the APD contingent on the third-party verification. The verification must be completed prior to BOP latch-up onto the associated well. The third-party verification will be submitted to BSEE in an APD or a revised sidetrack permit. The IFR added § 250.416(g) to describe the criteria and documentation for an independent third-party that must be submitted with the APD to BSEE for review. In the IFR, § 250.416(g)(1) of this section referenced the independent party in § 250.416(e). This Final Rule removes this reference, since the requirements for the independent third-party in paragraph (g) apply to any use of the independent third-party in § 250.416. We revised paragraph (g)(1) to specify that a registered professional engineer, or a technical classification society, or a licensed professional engineering firm, could qualify as the independent 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 questi [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2012-20090. Public record. Not legal advice.