BSEE regulations apply, as of their effective date(s), to all operations conducted under a lease. Operations conducted after the effective date of certain provisions of the 2019 final rule (April 30, 2021) may proceed on the basis of a previously-approved permit if those operations are conducted in accordance with both the approved permit and the applicable regulatory requirements in effect on the date the operations are conducted. BSEE does not require that an operator submit a new permit application in those circumstances simply because the new requirements have taken effect. However, if compliance with applicable regulatory requirements would require material modifications to your operations that would place them outside the terms of the approved permit, you would be required to submit a new or modified permit application that demonstrates that your operations will be completed in accordance with the newly effective regulatory requirements.

While you should always rely first and foremost on the regulatory text, and preamble language is not controlling over the text of a regulation, the preamble sets forth BSEE’s contemporaneous understanding of this rulemaking. The preamble helps explain the purposes and intent of the new regulations and provides helpful context for understanding those regulations. Thus, you may reasonably rely on the rule’s preamble in order to fully understand the regulatory text. BSEE will continue to issue interpretations and clarifications of the regulations as necessary.

Question – What is the process for obtaining confirmation of BSEE’s acceptance of clarifications provided by API to API Standards?

BSEE currently incorporates the Fourth Edition, November 2012, of API Standard 53, including the addendum.  The addendum contains clarifications to API Standard 53 4^th Edition. Future editions of or alterations to documents incorporated by reference generally need to be incorporated through a rulemaking process. Also as general rule, interpretations of the incorporated edition of API Standard 53, and other standards, that are published by the organization that published the standard, and that are developed and approved in strict conformance to the ANSI-approved interpretation procedures will be accepted by BSEE after publication of the interpretation. If there is a conflict between an interpretation of a standard and regulatory text, however, the regulation governs.

Although only standards incorporated by reference are regulatory requirements, at times compliance with such standards calls for satisfaction of other requirements. For example, API standard 53 section 5.2.7 states that “All lines, crosses, valves, and fittings in the choke manifold system and the drill string safety valve shall be constructed from materials meeting applicable requirements of API 5L and API 6A.” Thus, in order to comply with API Standard 53, as incorporated in the regulations, an operator would need to use the applicable items constructed from materials meeting applicable requirements of API 5L and API 6A.

BSEE will continue to evaluate new editions of documents incorporated by reference and, as appropriate, update the incorporated editions of those documents through the rulemaking process.

BSEE requires that your description of well drilling design criteria address both surface and downhole mud weights.  The purpose of this requirement is “to help ensure the drilling fluid weight is fully evaluated and appropriate for the estimated bottom hole pressures.”  84 FR 21932.  Satisfaction of this regulatory requirement of reporting surface and downhole mud weights constitutes the necessary comparison, and no further comparison is necessary.  If a revised permit is submitted, the permit application should include an update of the mud weights that reflect actual operations.   

On the casing information page in eWell, you should enter the downhole mud weight until that worksheet is updated to reflect both surface and downhole mud weights.  However, you are required to include both surface and downhole mud weights in all other applicable attachments in eWell.

Beginning July 15, 2019, operators have the option to submit the required justification and documentation for a proposed alternative safe drilling margin for BSEE approval at any earlier date prior to the APD.  Operators should submit to the District Operations Support all requests to approve alternate proposed safe drilling margins prior to the APD.  Regardless of the timing of the request to use an alternative drilling margin, each request must provide the supporting justifications required by 250.414(c)(2).  Any such early approval will be contingent upon confirmation in the APD that the plans and information underlying the BSEE-approved justifications have not changed. 

After July 28, 2016, you may not install a liner as a conductor casing.  Existing wells drilled prior to July 28, 2016, for which a liner was approved as conductor casing and that already have casing set, are not required to be modified. 

The preamble to the final rule states: “[I]f there are any indications of an inadequate cement job, the operator must evaluate the cement job as required in § 250.428.”  84 FR 21934-21935.  With respect to that evaluation, the preamble states: “If the operator encounters circumstances that the approved permits do not address (including PE certification), it would be required to submit a revised permit for BSEE approval that would include the PE certification.”  84 FR 21936 (”If an operator encounters circumstances that are not described in an approved permit, such as unplanned lost returns, then a new BSEE approval would be required at that time”).  Section 250.428(c) identifies examples of “indication[s] of inadequate cement job,” including “no cement returns…to expected height.”  Thus, if the cement job did not go as approved in the permit, including a discrepancy in TOC, then the job is inadequate and further action is required and may require a new PE certification.

Unless there is an indication of an inadequate cement job, requiring compliance with § 250.428(c), including any applicable notice provisions, BSEE does not require operators to provide notification or to submit information regarding engagement of the latching and lockdown mechanisms.

The final rule preamble states: “The content of [API Bulletin 92L] includes flow charts that can be used as an aid for operators to use in deciding how best to safely drill ahead when lost circulation occurs and the required criteria and procedures are met.”  84 FR 21915, 21935.  Thus, operators may utilize API Bulletin 92L and follow the associated flowcharts of 92L where the required criteria are met.  Section 250.427(b)(2) does require notification to the District Manager in connection with such action.  Further, if you cannot maintain the safe drilling margin and you take action in accordance with API Bulletin 92L, you must submit a revised permit documenting any responsive actions taken.

No.  As explained in the preamble, lift pressure analysis by itself is not a conclusive indicator of an adequate cement job.  81 Fed. Reg. 25922.  As was the case under the existing regulation, the final rule states that you must locate the top of cement by running a temperature survey, running a cement evaluation log, or using a combination of these techniques.  Alternate compliance may be requested to use lift pressure analysis with supporting data that demonstrates that a lift pressure analysis would provide a level of safety and environmental protection that equals or surpasses that provided by a temperature survey, cement evaluation log, or a combination of the two.

In line with longstanding regulations and practice, when there is an inadequate cement job, remedial actions will be approved on a case-by-case basis using sound engineering judgment based on specific well conditions. The alterations to section 250.428(d) do not impact BSEE’s existing approach to the identified situations.

If your WCST indicates you can fully shut-in the well as a cap and contain, you are not required to submit information reflecting the ability to cap and flow. BSEE will continue to use the WCST as a resource to evaluate or re-evaluate your source control capabilities. When the WCST indicates that you cannot fully shut-in, then you must determine your ability to flow and capture residual fluids to a surface production and storage system.

Section 250.462(d) requires reevaluation of the operator’s source control and containment equipment if there is a well design change. As explained in the preamble, BSEE requires notification for any well design change, which must be submitted at the time the operator submits a revised permit. 81 FR 25925. This may include, but is not limited to, changes to the pore pressures, fracture gradients, drilling fluid weights, and casing setting depths or casing materials. These parameters may affect the source control and containment capabilities for a particular well and the associated well containment screening tool (WCST).

A revised screening tool will need to be submitted in a revised permit if any of the following has changed for the primary or secondary strings analyzed in the WCST:

1. A casing or liner is set in a mud weight greater than the mud weight originally approved
2. Decrease in cement volume
3. An increase in cement volume that results with the top of cement being within 500 ft MD of the previous shoe
4. Casing shoe, liner shoe, and/or liner hanger setting depth changes by more than 100 ft TVD for strings that are analyzed in the WCST  
5. A change in the size or rating of any casing, liner, hanger, or seal assembly for strings that are analyzed in the WCST
6. A casing or Liner is added to or removed from the well program

All packers or bridge plugs designated as qualified mechanical barriers are required to be in conformance with API spec. 11D1 and there is no “grandfathering” of equipment that is currently in inventory.

Each production packer setting depth will be evaluated on a case–by-case basis. Each well and situation is unique. It is reasonably possible that BSEE will approve a setting depth for a production packer that will allow for future potential work below the packer. The provisions at §§ 250.518(e)(3) and 250.619(e)(3) do not require that BSEE only approve a setting depth that would preclude future potential work below the packer.

The new regulations are not intended to hinder the installation of production equipment by setting a fixed interval length that must be met or to hinder an operator's flexibility to intervene in or manage its well as necessary. During the permit application process, BSEE may request additional information to justify your specified production packer setting depth to ensure that the packer is set as required in these sections to help ensure long-term equipment reliability.

The final rule preamble explained that “BSEE wants to ensure that the packer is not set too high, so that, if there is a problem with the packer in the well (e.g., a leak), operators will have enough space above the packer to pump a sufficient volume of weighted fluid into the well to exert a hydrostatic force greater than the force created by the reservoir pressure below the packer.” 81 Fed. Reg. 25888, 25927 (April 29, 2016).

Requests for departure or alternate compliance to set the packer in an un-cemented casing will be reviewed on a case-by-case basis in connection with the permit.

No, there must be enough space above the packer to pump a sufficient volume of weighted fluid into the well to exert a hydrostatic force greater than or equal to the force created by the reservoir pressure below the packer.

Response

At this time, BSEE has identified the following listed sections of Subpart G as applicable to coiled tubing operations:

BSEE will continue to assess the applicability of other sections of Subpart G to coiled tubing operations as the implementation process progresses.  If you have questions regarding the applicability of a particular requirement to your specific operation, you may contact the District Manager

Yes, a rig move notification is also required.

BSEE does not require a rig move notification if the rig does not leave the safe zone.  However, BSEE requires notification and District approval when putting the well in a safe state before leaving the well, if possible.  See 30 CFR 250.720(a).   

BSEE has outlined the minimum RTM and RTM plan requirements in the regulations.  Since the 2016 Rule, the RTM planning requirements have been designed to be “flexible, performance-based measures that better reflect BSEE’s intention that operators use RTM as a tool to improve their own ability to prevent well control incidents while providing BSEE with sufficient access to RTM information to evaluate system improvements.”  2016 final rule preamble, 81 FR 25897; see also 2019 final rule preamble, 84 FR 21942 (“The 2016 WCR’s RTM requirements were themselves largely performance-based, relying primarily on the operator’s development of an RTM plan tailored to its operations but built off of core principles. The revisions implemented here do not reflect a sea change in philosophy…”).  With respect to enforcement, the final rule preamble states: “This regulation requires that operators develop and implement RTM plans, and specifically requires that those plans be made available to BSEE upon request.  If BSEE has any concerns with an operator’s RTM operations, then BSEE may undertake inspections and enforcement actions to ensure compliance with the regulations.  BSEE has additional options such as routine onsite inspections or verifications through the permitting process to ensure that RTM plans are implemented in compliance with the regulations.”  84 FR 21943.  The regulations since 2016 have required that operators both “develop and implement” RTM plans.  30 CFR 250.724(c) (emphasis added).  These principles are unchanged in this rulemaking.  

As a general principle, BSEE considers the term “significant and/or prolonged” loss of RTM capability as a period of time “that potentially could increase the risk of a well-control event.”  2016 final rule preamble, 81 FR 25938.  “BSEE did not intend that proposed requirement to apply to minor or routine interruptions in RTM capabilities that pose no significant risk to safety or of a LWC.”  2016 final rule preamble, 81 FR 25897.  This regulation is not prescriptive and thus does not establish an express time period.  An operator should use its ordinary prudence and industry expertise to establish in its RTM plan which losses of RTM capability should be characterized as “significant and/or prolonged,” taking into account the prior BSEE descriptions.  Although it is generally the operator’s responsibility to initially define in its plan which losses of RTM capability will be considered “significant and/or prolonged” based on the facts associated with the RTM system’s interruption, BSEE would typically expect that a reasonably prudent operator would take action under its plan pursuant to 250.724(c)(6) if that operator loses any real-time monitoring capabilities for a 24 hour period. 

The rig personnel should not be considered “monitoring personnel” for purposes of the RTM planning requirements at 250.724(c)(5) and (6) furthermore, rig personnel and RTM personnel should be in separate locations for a given well.  The final rule preamble clarifies: “BSEE requires the rig personnel and monitoring personnel to be separate individuals.”  84 FR 21943.  The operator is not precluded from having personnel on the rig performing real-time monitoring functions, but those individuals may not serve as the “monitoring personnel” required by regulation.  BSEE requires the operator to identify in the RTM plan how the RTM data will be transmitted and monitored, requires the rig personnel and monitoring personnel to be separate individuals, and requires certain communication capabilities among personnel, but does not prescriptively dictate the establishment of an onshore monitoring center, or even require that monitoring personnel must be onshore.  See, e.g., 84 FR 21942.  As noted in the preamble, “[w]ith currently available technology, operators are capable of using RTM remotely on computers and tablets using web based applications. This allows for subject matter experts to utilize the data anywhere and at any time as necessary, as detailed in the company’s RTM plan.”  Id. 

BSEE regulations apply, as of their effective date(s), to all operations conducted under a lease. Operations conducted after the effective date of this regulation (April 30, 2019) may proceed on the basis of a previously-approved permit if those operations are conducted in accordance with both the approved permit and the applicable regulatory requirements in effect on the date the operations are conducted. BSEE does not require that an operator submit a new permit application in those circumstances simply because the new requirements have taken effect. However, if compliance with applicable regulatory requirements would require material modifications to your operations that would place them outside the terms of the approved permit, you would be required to submit a new or modified permit application that demonstrates that your operations will be completed in accordance with the newly effective regulatory requirements

No, This requirement does not extend to hydraulic work over units or snubbing units used on the same vessel or facility.

Pursuant to the longstanding regulatory provision at 30 CFR 250.141, you may submit a request to use alternate procedures or equipment that meet the required standards.

The cited regulation does apply to such operations.  Section 250.730(a) is applicable to all BOP systems and system components, and is not specific to the type of rig unit.   A regulation’s incorporation of an industry standard extends requirements only to the subject matter covered by the incorporated standard.  250.730 applies to BOP systems and system components and incorporates Standard 53.  API Standard 53 states, “BOPs are not: gate valves, workover/ intervention control packages, subsea shut‐in devices, well control components (per API 16ST), intervention control packages, diverters, rotating heads, rotating circulating devices, capping stacks, snubbing or stripping packages, or nonsealing rams.”  This paragraph applies to intervention units which utilize BOP systems.

API standard 53 includes normative references to API Spec 17D.  Accordingly, Spec 17D should be followed as necessary to achieve compliance with API standard 53.

Question – Is it acceptable to have the ability to increase the regulated pressure if required?

Yes, the ability to increase the regulated pressure when required is acceptable under § 250.730(a)(3). The regulation does not prescribe any specific requirements for regulator settings, and BSEE requires only that the regulator settings function as designed and as specified in the approved APD. 81 Fed. Reg. 25941.

That is correct.

The regulation contains no grace period for completing training related to courses that have limited availability. The regulation states that all maintenance and repair personnel who work on a BOP system must meet or exceed any OEM training recommendations (unless otherwise directed by BSEE). Personnel who are receiving on the job training may work with trained personnel in performing specific activities. However, trained personnel must be present and be providing direct oversight over any work that is performed.

BSEE is currently working with the industry to ensure that the terminology, data, and content for failure reporting information is consistent with the existing data reporting systems that are currently being used within a large part of the industry. We believe that consistent reporting processes and formats will facilitate other sharing of data across the industry. BSEE will also be providing operators with the option of reporting information directly to the SAFEOCS reporting system through the Bureau of Transportation Statistics (BTS). BTS is currently ensuring that the systems and processes are in place to accept this type of data directly from operators. BSEE will be issuing specific guidance on these issues in the next several weeks. Until this process is fully operational, operators should use one of the following options to report failures:

Download the BOP Component Failure Form from the SafeOCS website (www.safeocs.gov) and submit it electronically directly to BSEE at BOPFailure@BSEE.gov. The form will be available on July 28, 2016.
Print the BOP Component Failure Form out and submit a paper copy directly to BSEE: Chief, Office of Offshore Regulatory Programs Bureau Safety and Environmental Enforcement 45600 Woodland Road Sterling, VA 20166
Send a faxed hard copy to Chief, Office of Offshore Regulatory Programs at 703-787-1093.
BSEE will protect all confidential and proprietary information included in these submissions in accordance with governing law

The failure reporting requirements for the BOP equipment are triggered when the rig is on site and includes all BOP stacks and any issues discovered during any testing or maintenance.

Section 250.731 requires that you submit updated information in your next submittal if a rig has moved off location from the well (due to a storm or for any other reason). For example, the information listed in § 250.731 must be updated (or confirmed still to be accurate) and submitted with an APD, APM, or other necessary submittal when the rig moves back onto the well. Also, if a rig has moved off location (due to a storm or for any other reason), you must follow the rig movement reporting requirements according to § 250.712. If operations are suspended to make repairs or changes to any part of the subsea BOP system, you must also follow the requirements of § 250.734(b).

The regulation requires the submission of schematic drawings for compliance with both paragraphs (b)(3) and (b)(8). This requirement is consistent with prior regulations (see, e.g., former §§ 250.416(d); 250.515(b); 250.615(b)), including specifically the requirement to include the location of associated valves on your BOP drawings.

The rule refers to “the maximum environmental and operational conditions anticipated to occur at the well.”  The regulations do not address the “most extreme load case.”  For purposes of identifying maximum anticipated pressures, the definitions of MASP and MAWHP set forth in API Standard 53 are sufficient.  However, the Independent third party must also take into account the specific environmental and operational conditions at the well (e.g., temperature and H2S).   As BSEE explained in the final rule preamble, in order to assess these well conditions, operators should rely on “reasonably predictable, site-specific conditions instead of hypothetical worst-case conditions.”  81 Fed. Reg. 25946 (April 29, 2016).  MASP for surface BOPs and MAWHP for subsea BOPs would ordinarily reflect reasonably predictable, site-specific conditions on which a certification pursuant to section 250.732(c)(2) may be based.

Section 250.732(a)(1)(ii) is performance-based so as to give operators the flexibility to use testing facilities that meet generally accepted quality assurance standards. BSEE believes that operators are capable of identifying such standards. These might include API standards, depending on the content of those documents.

BSEE regulations do not currently incorporate API 16A PR2.  However, BSEE will continue to evaluate this standard for future incorporation into the regulations and continue to work with OEMs for improved ways to demonstrate testing on the outermost edges of the shearing blades.  BSEE currently has no general position with respect to whether API 16A PR2 test data satisfies the regulatory requirement to submit verification and documentation that shear testing was performed on the outermost edges of the shearing blades of the shear ram, and will evaluate submitted documentation within the permit to ensure this requirement is met.  

It is the operator’s responsibility to determine how the sealing pressure calculations are applied to specific components. According to the requirements of 250.732(a)(3), it is the responsibility of the independent third party to validate and certify shearing and sealing capabilities of the BOP.

This regulation is performance-based and provides operators with the flexibility to demonstrate the sufficiency of the design. In some cases, compliance with the specification and third party requirements may be sufficient to satisfy this provision.

This paragraph sets general, performance-based requirements and is intended to be broad enough to provide flexibility in verifying the performance and reliability of the component and system designs without expressly requiring conformance to any specific standard. These might include design and testing in accordance with API standards to meet the design verification requirements of 250.732(c)(2), depending on the content of those documents.

The independent third party must conduct a comprehensive review of the BOP system and related equipment.  BSEE requires an operator to provide the independent third party access to any facility associated with the BOP system or related equipment during the review process.  The independent third party must verify that the fabrication and manufacture processes used recognized engineering practices and quality control and assurance mechanisms.  However, this does not require the independent third party to be physically present during fabrication or manufacturing.  BSEE does not specify how the independent third party must obtain the information necessary to provide the required verifications.

Section 250.732(d)(5) does not require a full SEMS audit annually.  This paragraph requires verification that the mechanical integrity provisions of the SEMS plan, related to specific equipment, have been implemented.  This is process is different than the audit of the entire management system across all operations that is typically performed every three years.

Merely repositioning a riser within the same existing floating facility, for example, from one well to another on the same facility, would not constitute the “installation” of a riser that would otherwise require use of a dual bore riser configuration under § 250.733(b)(2).

30 CFR 250.734(a)(1) requires use of dual shear rams on subsea BOPs no later than April 29, 2021. 30 CFR 250.733(b)(1) requires that surface BOPs on new floating production facilities installed after April 29, 2021, comply with the regulatory requirements in § 250.734(a)(1), including the requirement to use dual shear rams.

The 2019 final rule establishes numerous equipment and process requirements that are ancillary to the operation of dual shear rams as well as to other types of rams and other components of subsea BOPs. For example, § 250.734(a)(3)(i) requires that each subsea BOP have sufficient subsea accumulator capacity to close each required shear ram, one pipe ram, and ram locks, and to disconnect the LMRP. BSEE intended such ancillary requirements to take effect at the same time as the requirements for installation or availability of the specific equipment or component that the ancillary equipment or process is designed to operate. So, for example, the accumulator capacity closure requirement of § 250.734(a)(3)(i) must be met by April 29, 2021.

The following provisions of the final rule also fall under the dual shear rams requirements; therefore, with regard to operating the dual shear rams, you must comply with these requirements by the April 29, 2021, compliance date:

• § 250.734(a)(1)(ii) – Shear rams capable of shearing at any point along the identified pipes, tubes, and lines;
• § 250.734(a)(3)(i) – Subsea accumulator capacity to close each required shear ram;
• § 250.734(a)(3)(ii) – Have the capability to perform ROV functions within the required times outlined in API Standard 53 with ROV or flying leads;
• § 250.734(a)(6)(iv) – Emergency functioning must close, at a minimum, 2 shear rams in sequence; and
• § 250.734(a)(6)(v) – Sequencing of the dual shear rams.

No, the regulations do not require identical shear rams. 30 CFR 250.734(a)(ii) requires that both shear rams (i.e., each shear ram) be capable of performing the entire range of listed shearing operations. However, the regulation only requires that at least one shear ram be capable of closing and sealing the wellbore after shearing under MASP.

You are not required to have a second shear ram with the identified capabilities until April 29, 2021. Operators are not prohibited from meeting the dual ram shearing requirements prior to 2021, and BSEE encourages operators to pursue continual improvement toward these standards.

Do the requirements in 30 CFR 250.734(a)(1)(ii) have to be met regardless of what tubulars are being used in the well?   Example: If wireline/slick line is not going to be run, no requirement to have a shear ram that can shear/cut the wire line to be installed in the BOP.

Effective April 29, 2019, both shear rams are required be able to perform the shearing operations that may be necessary during your planned operations.  For example, if you do not plan to run wireline during your operations, then the shear rams do not need to be capable of shearing wireline.  While not required, BSEE recommends that all BOP shear rams be capable of performing the entire range of listed shearing operations in case of emergency. 

Correct, the appropriate area for the liner or casing landing string is the portion of the string that will be across the stack once landed in the wellhead which may include the running tool.

All subsea BOPs and surface BOPs on new floating production facilities will need to comply with the dual ram requirement by April 29, 2021.  All shearing components utilized within the autoshear/deadman systems must meet all required shearing capabilities, regardless of configuration.  The regulations have long provided operators the option of seeking approval of alternate procedures or equipment from those required by regulation; such proposals must demonstrate “a level of safety and environmental protection that equals or surpasses current BSEE requirements.”  30 CFR 250.141.  BSEE will consider such requests on a case-by-case basis.    

Yes, both rams in the emergency sequence must have the capability to shear under MASP independently, with one being able to seal.  There must be enough total volume for each ram to function independently.

This is defined as a simultaneous absence of hydraulic supply and control of both subsea control pods.

BSEE expects an acoustic system to comply with API standard 53.  The acoustic system is not required to undertake the operations listed in § 734(a)(3)(i).  In addition, if an operator chooses to use an acoustic control system as an additional emergency control measure (in addition to the required autoshear, deadman and EDS systems), the operator must demonstrate that the system is functional.  81 Fed. Reg. 25960.

BSEE regulations apply, as of their effective date(s), to all operations conducted under a lease. Operations conducted after the effective date of this regulation (April 30, 2019) may proceed on the basis of a previously-approved permit if those operations are conducted in accordance with both the approved permit and the applicable regulatory requirements in effect on the date the operations are conducted. BSEE does not require that an operator submit a new permit application in those circumstances simply because the new requirements have taken effect. However, if compliance with applicable regulatory requirements would require material modifications to your operations that would place them outside the terms of the approved permit, you would be required to submit a new or modified permit application that demonstrates that your operations will be completed in accordance with the newly effective regulatory requirements.

No, as stated in 250.724(a), the requirements apply when conducting well operations with a subsea BOP or with a surface BOP on a floating facility, or when operating in a high pressure high temperature (HPHT) environment. The certification requirement in 250.724(b) is separate from the substantive compliance obligations and does not narrow their scope.

BSEE does not consider equipment downstream of the choke isolation valve to be choke manifold components for purposes of 30 CFR 250.736(b). Accordingly, such equipment may have a lower pressure rating that the RWP, as described in API Standard 53.

Correct, both shear rams must meet the function testing and pressure testing requirements in 30 CFR 250.737 by April 29, 2021.

As described in the preamble to the final rule, “[this provision] is intended to give District Managers the necessary flexibility and discretion to require [BOP system tests] as needed in specific cases to fulfill the purposes of the regulation.” 81 Fed. Reg. 25966 (April 29, 2016). BSEE will evaluate the specific conditions and BOP performance on a case-by-case basis (e.g., specific well conditions, operations, or equipment) to determine whether to require more frequent testing. This approach – reflected in provisions throughout Part 250 – is essential to provide the flexibility and discretion necessary to ensure that the purposes of the regulations are fulfilled in specific cases. This language is identical to the longstanding language found at former section § 250.447(b), and BSEE is unaware of any significant concerns raised by operators in connection with the District Managers’ exercise of this authority.

These tests should be on the same chart to show that the transition from low to high happened immediately after conducting the low pressure test; however, two charts can be run simultaneously to prove the low pressure test was conducted before the high pressure test. 

This applies to the high and low pressure test.

All BOP panels must be functioned prior to deployment, as stated in API Standard 53 section 7.6.5.1.2.  The remote BOP panels that do not have full functionality are required to be function-tested upon the initial BOP tests. Furthermore, these panels do not need to be tested on a monthly basis

This regulation applies upon initial test.  For subsea BOPs (primary and secondary) this applies beginning with stump testing, and for surface BOPs this applies upon initial test once rigged up to the well.

If a failure of a component or group of components, whether critical or secondary, renders a control pod non-functional, you must suspend operations in accordance with § 250.737(d)(8).  If there are any problems or irregularities, including any leaks, you must contact the appropriate District Manager.  The need to recover BOPs for repairs will be determined on a case by case basis.

No.  Any redundant equipment failures must be reported as described in this regulation.  As BSEE explained in the preamble to the final rule:  “If redundant components are installed and planned to be used as necessary, they need to be able to fully function and operate (similarly to the required components) as intended.”  81 Fed. Reg. at 25970.  BSEE will evaluate redundant equipment failure reports it receives and evaluate the materiality of an operator’s redundant equipment failure.  Requests to operate with failed redundant components will be considered on a case- by-case basis at the time in which the component fails.

This complete breakdown and inspection must be performed every five years from the latest of the following dates: (1) The date the equipment owner accepts delivery of a new build drilling rig with a new BOP system; (2) The date the new, repaired, or remanufactured equipment is initially installed into the system; or (3) The date of the last five-year inspection conducted on the relevant component.

No, a major, detailed inspection must be completed every 5 years.  BSEE will review condition-based maintenance as a possible alternative when more data is available.