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Daily Rules, Proposed Rules, and Notices of the Federal Government

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: 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 SS 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 SS 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 hasresponsibility 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) § 250.442What are the requirements for a subsea BOP system? § 250.515Blowout prevention equipment. § 250.615Blowout prevention equipment. §§ 250.1500 through 250.1510Subpart O—Well-control and Production Safety Training. Establish new fluid displacement procedures (safety report rec. II.A.2) § 250.456What safe practices must the drilling fluid program follow? Develop additional requirements or guidelines for casing installation (safety report rec. II.B.2.6) § 250.423What 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) § 250.415What 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 Registerpreamble 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 theFederal 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 atwww.regulations.govunder 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 neg