# Oil and Gas and Sulphur Operations in the Outer Continental Shelf-Blowout Preventer Systems and Well Control > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2015-08587 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** April 17, 2015 - **Citation:** 80 FR 21504 ## Text DEPARTMENT OF THE INTERIOR Bureau of Safety and Environmental Enforcement 30 CFR Part 250 [Docket ID: BSEE-2015-0002; 15XE1700DX EEEE500000 EX1SF0000.DAQ000] RIN 1014-AA11 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Blowout Preventer Systems and Well Control AGENCY: Bureau of Safety and Environmental Enforcement (BSEE), Interior. ACTION: Proposed rule. SUMMARY: The Bureau of Safety and Environmental Enforcement (BSEE) proposes new regulations in order to consolidate equipment and operational requirements that are common to other subparts pertaining to offshore oil and gas drilling, completions, workovers, and decommissioning. This proposed rule would focus, at this time, on blowout preventer (BOP) requirements, including incorporation of industry standards and revising existing regulations. The proposed rule would also include reforms in the areas of well design, well control, casing, cementing, real-time well monitoring, and subsea containment. The proposed rule would address and implement multiple recommendations resulting from various investigations of the Deepwater Horizon incident. This proposed rule would also incorporate guidance from several Notices to Lessees and Operators (NTLs) and revise provisions related to drilling, workover, completion, and decommissioning operations to enhance safety and environmental protection. DATES: Submit comments by June 16, 2015. The BSEE may not consider comments received after this date. Submit comments to the Office of Management and Budget (OMB) on the information collection burden in this proposed rule by May 18, 2015. This does not affect the deadline for the public to comment to BSEE on the proposed regulations. ADDRESSES: You may submit comments on the proposed rulemaking by any of the following methods. Please use the Regulation Identifier Number (RIN) 1014-AA11 as an identifier in your message. See also Public Availability of Comments under Procedural Matters. • Electronic comments: http://www.regulations.gov. In the Search box, enter BSEE-2015-0002 then click search. Follow the instructions to submit public comments and view supporting and related materials available for this rulemaking. We will post all comments. • Mail or hand-carry comments to the Department of the Interior (DOI); Bureau of Safety and Environmental Enforcement; Attention: Regulations and Standards Branch; 45600 Woodland Road, Sterling, Virginia 20166. Please reference Blowout Preventer Systems and Well Control, 1014-AA11 in your comments and include your name and return address. • Send comments on the information collection in this rule to: OMB, Interior Desk Officer 1014-NEW, 202-395-5806 (fax); email: OIRA_submission@omb.eop.gov. Please also send a copy to BSEE at regs@bsee.gov, fax number (703)787-1546, or by the address listed above. FOR FURTHER INFORMATION CONTACT: Kirk Malstrom, Regulations and Standards Branch, 202-258-1518, Kirk.Malstrom@bsee.gov. To see a copy of the information collection request submitted to OMB, go to http://www.reginfo.gov (select Information Collection Review, Currently Under Review). SUPPLEMENTARY INFORMATION: List of Acronyms and References ANSI American National Standards Institute APD Application for Permit to Drill API American Petroleum Institute APM Application for Permit to Modify BOP Blowout Preventer BOEM Bureau of Ocean Energy Management BSEE Bureau of Safety and Environmental Enforcement BSR Blind Shear Ram CBM Condition-based Maintenance CVA Certified Verification Agent DHS Department of Homeland Security DOI Department of the Interior DWOP Deepwater Operations Plan ECD Equivalent Circulating Density EDS Emergency Disconnect Sequence E.O. Executive Order EOR End of Operations Report F Fahrenheit FPS Floating Production System FPSO Floating Production, Storage, and Offloading Unit FSHR Free Standing Hybrid Risers GOM Gulf of Mexico GPS Global Position Systems HPHT High Pressure High Temperature JIT Joint Investigation Team LMRP Lower Marine Riser Package MASP Maximum Anticipated Surface Pressure MMS Minerals Management Service MODUs Mobile Offshore Drilling Units NAE National Academy of Engineering NAICS North American Industry Classification System NARA National Archives and Records Administration National Commission National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling NTLs Notices to Lessees and Operators OCS Outer Continental Shelf OCSLA Outer Continental Shelf Lands Act OEM Original Equipment Manufacturer OIRA Office of Information and Regulatory Affairs OMB Office of Management and Budget PE Professional Engineer psi Pounds per square inch RFA Regulatory Flexibility Act RIA Regulatory Impact Analysis RIN Regulation Identifier Number ROV Remotely Operated Vehicle RP Recommended Practice SBA Small Business Administration SBREFA Small Business Regulatory Enforcement Act of 1996 SCCE Source Control and Containment Equipment Secretary Secretary of the Interior SEM Subsea Electronic Module SEMS Safety and Environmental Management Spec. Specification TAR Technical Assessment and Research TLP Tension Leg Platform TVD True Vertical Depth USCG United States Coast Guard VSL Value of a Statistical Life WAR Well Activity Report Executive Summary Following the Deepwater Horizon incident on April 20, 2010, multiple investigations were conducted to determine the causes of the incident and to make recommendations to reduce the likelihood of a similar incident in the future. The investigative groups included: —DOI/Department of Homeland Security (DHS) Joint Investigation Team; —National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling; —Chief Counsel for the National Commission; and —National Academy of Engineering. Each investigation outlined several recommendations to improve offshore safety. The BSEE evaluated the recommendations and acted on a number of them quickly to improve offshore operations while other recommendations required additional input from industry and other stakeholders. The requirements in this proposed rule are based on recommendations made by the previously listed investigative bodies, which found a need to enhance well-control best practices to advance safety and protection of the environment. This proposed rulemaking would: (1) Incorporate the following industry standards: —American Petroleum Institute (API) Standard 53, Blowout Prevention Equipment Systems for Drilling Wells; —American National Standards Institute (ANSI)/API Specification (Spec.) 11D1, Packers and Bridge Plugs; and —API Recommended Practice (RP) 17H, Remotely Operated Tools and Interfaces on Subsea Production Systems. As related to BOP systems: —ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree Equipment; —ANSI/API Spec. 16A, Specification for Drill-through Equipment; —API Spec. 16C, Specification for Choke and Kill Systems; —API Spec. 16D, Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment; and —ANSI/API Spec. 17D, Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment. (2) Revise the requirements for Deepwater Operations Plan (DWOP) which are required to be submitted to BSEE, to include requirements on free standing hybrid risers (FSHR) for use with floating production, storage, and offloading units (FPSO). (3) Revise sections in 30 CFR part 250 Subpart D, Oil and Gas Drilling Operations, to include requirements for: —Submittal of equivalent circulating density (ECD) with the Application for Permit to Drill (APD); —Safe drilling margin; —Wellhead description; —Casing or liner centralization during cementing; and —Source control and containment. (4) Revise sections in Subparts E, Oil and Gas Well-Completion Operations, and F, Oil and Gas Well-Workover Operations, to include requirements for: —Packer and bridge plug design, and —Production packer setting depth. (5) Revise sections in Subpart Q, Decommissioning Activities, to include requirements for: —Packer and bridge plug design, —Casing bridge plugs, and —Decommissioning applications and reports. (6) Add new Subpart G, Well Operations and Equipment, and move common requirements from Subparts D, E, F, and Q into new Subpart G. Include new requirements in Subpart G for: —Rig and equipment movement reports, —Real-time monitoring, and —Revised BOP requirements, including: —Design and manufacture/quality assurance; —Accumulator system capabilities and calculations; —BOP and remotely operated vehicle (ROV) capabilities; —BOP functions ( e.g., shearing); —Improved and consistent testing frequencies; —Maintenance; —Inspections; —Failure reporting; —Third-party verification; and —Additional submittals to BSEE including up-to-date schematics. (7) Incorporate the guidance from several Notices to Lessees and Operators (NTLs) into Subpart G for: —Global Position Systems (GPS) for Mobile Offshore Drilling Units (MODUs); —Ocean Current Monitoring; —Using Alternate Compliance in Safety Systems for Subsea Production Operations; —Standard Reporting Period for the Well Activity Report (WAR); and —Information to include in the WARs and End of Operation Reports (EOR). Table of Contents I. Background BSEE Statutory and Regulatory Authority Availability of Incorporated Documents for Public Viewing Summary of Documents Incorporated by Reference Deepwater Horizon Investigations Recommendations on BOPs Stakeholder Participation BSEE Response to Recommendations and Additional Considerations II. Organization of Subpart G III. Effective Date of a Final Rule IV. Future Plans for Subpart G V. Section-By-Section Discussion Appendix VI. Derivation Tables VII. Procedural Matters I. Background BSEE In relation to oil and gas exploration, development, and production operations on the Outer Continental Shelf (OCS), the Bureau of Safety and Environmental Enforcement (BSEE) regulates offshore oil and gas operations to promote safety, protect the environment, and conserve offshore oil and gas resources. The BSEE was established on October 1, 2011, as part of a major restructuring of DOI's offshore oil and gas regulatory programs to improve the management, oversight, and accountability of activities on the OCS. The Secretary of the Interior (Secretary) announced the new division of responsibilities of the former Minerals Management Service (MMS) into two new bureaus and one office within DOI in Secretarial Order No. 3299, issued on May 19, 2010. The BSEE, one of the two new bureaus, assumed responsibility for “safety and environmental enforcement functions including, but not limited to, the authority to permit activities, inspect, investigate, summon witnesses and [require production of] evidence[;] levy penalties; cancel or suspend activities; and oversee safety, response and removal preparedness” (76 FR 64432, October 18, 2011). BSEE Statutory and Regulatory Authority The BSEE derives its authority primarily from the Outer Continental Shelf Lands Act (OCSLA), 43 U.S.C. 1331-1356a. Congress enacted OCSLA in 1953, establishing Federal control over the OCS and authorizing the Secretary to regulate oil and gas exploration, development, and production operations on the OCS. The Secretary has authorized BSEE to perform these functions under 30 CFR 250.101. To carry out its responsibilities, BSEE regulates offshore oil and gas operations to enhance the safety of offshore exploration and development of oil and gas on the OCS and to ensure that those operations protect the environment and implement advancements in technology. The BSEE also conducts onsite inspections to assure compliance with regulations, lease terms, and approved plans. Detailed information concerning BSEE's regulations and guidance to the offshore oil and gas industry may be found on BSEE's Web site at: http://www.bsee.gov/Regulations-and-Guidance/index.aspx. The BSEE regulatory program regulates a wide range of facilities and activities, including drilling, completion, workover, production, pipeline, and decommissioning operations. Drilling, completion, and workover operations are types of well operations offshore operators perform throughout the OCS from fixed and floating facilities. These well operations are the primary topic of this proposed rulemaking. Ensuring the integrity of the wellbore and maintaining control over the pressure and fluids during well operations are critical aspects of protecting worker safety and the environment. The investigations that followed the Deepwater Horizon incident documented gaps or deficiencies in the OCS regulatory programs and made recommendations for improvements. The objective of this rulemaking is to address many of these recommendations, especially those related to BOP system design, performance, and reliability. The BOP equipment and systems are critical components of many well operations. The BOP systems can be the last defense against a release of hydrocarbons into the environment, when all other forms of well control have failed ( e.g., the drilling fluid program). The BOPs may be the last line of defense in preventing release of gas that is volatile and considered to be an extreme safety hazard to rig personnel (uncontrolled gas releases can lead to explosions). The primary purpose of BOP systems is to prevent the uncontrolled release of hydrocarbons in an emergency situation by mechanically closing valves or rams that block the flow of fluid from the well. In some situations, this may require shear rams on the BOP stack to sever the drill pipe before the well can be sealed. The BOP equipment and systems have increased in complexity as the industry moves into deeper water and develops reservoirs with pressures greater than 15,000 pounds per square inch (psi) or temperatures greater than 350 degrees Fahrenheit (F). Reservoirs with these conditions are considered high pressure high temperature (HPHT). Most of the BOPs that are used in deep water operations (400 to 10,000 feet) are located on the seabed, which presents technological and operational challenges. Additionally, HPHT operations create special metallurgical and design issues. In this rulemaking, BSEE intends to: • Implement many of the recommendations related to well-control equipment and fill gaps in the regulatory program. • Increase the performance and reliability of well-control equipment, especially BOPs. • Improve regulatory oversight over the design, fabrication, maintenance, inspection, and repair of critical equipment. • Gain information on leading and lagging indicators of BOP component failures, identify trends in those failures, and help prevent accidents. • Ensure that the industry uses recognized engineering practices, as well as innovative technology and techniques to increase overall safety. Availability of Incorporated Documents for Public Viewing When a copyrighted technical industry standard is incorporated by reference into our regulations, BSEE is obligated to observe and protect that copyright. The BSEE provides members of the public with Web site addresses where these standards may be accessed for viewing—sometimes for free and sometimes for a fee. Standards-developing organizations decide whether to charge a fee. The API provides free online public access to key industry standards, including a broad range of technical standards. These free standards represent almost one-third of all API standards and include all that are safety-related or have been or are proposed to be incorporated into Federal regulations, including the standards in this rule. These standards are available for online review, and hardcopies and printable versions will continue to be available for purchase. We are proposing to incorporate certain API standards. The API Web site address is: http://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents. For the convenience of the viewing public, who may not wish to purchase or view these proposed documents online, they may be inspected at BSEE, 45600 Woodland Road, Sterling, Virginia 20166; phone: 703-787-1665; or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal-register/cfr/ibr-locations.html. These documents, if incorporated in the final rule, would continue to be made available to the public for viewing when requested. Specific information on where these documents can be inspected or obtained can be found at 30 CFR 250.198, Documents incorporated by reference. Summary of Documents Incorporated by Reference This rulemaking is substantive in terms of the content that is explicitly stated in the rule text itself, but it also incorporates by reference some very technical, detailed standards and specifications in the topic of blowout preventers and well control. In their aggregate this represents one of the most substantial rulemakings in the history of the BSEE and its predecessor organizations. A brief summary, based on the descriptions in each standard or specification, is provided in the text that follows. API Standard 53—Blowout Prevention Equipment Systems for Drilling Wells This standard is to provide requirements for the installation and testing of blowout prevention equipment systems whose primary functions are to confine well fluids to the wellbore, provide means to add fluid to the wellbore, and allow controlled volumes to be removed from the wellbore. Blowout preventer equipment systems are comprised of a combination of various components that are covered by this document. Equipment arrangements are also addressed. The components covered include: Blowout preventers (BOPs) including installations for surface and subsea BOPs; Choke and kill lines; Choke manifolds; Control systems; and Auxiliary equipment. This document provides new industry best practices related to: The use of double shear rams Maintenance and testing requirements. Failure Reporting Diverters, shut-in devices, and rotating head systems (rotating control devices) whose primary purpose is to safely divert or direct flow rather than to confine fluids to the wellbore are not addressed. Procedures and techniques for well control and extreme temperature operations are also not included in this standard. API Recommended Practice 2RD—Design of Risers for Floating Production Systems and Tension-Leg Platforms This document addresses structural analysis procedures, design guidelines, component selection criteria, and typical designs for all new riser systems used on Floating Production Systems (FPSs and Tension-Leg Platforms (TLPs). The presence of riser systems within an FPS has a direct and often significant effect on the design of all other major equipment subsystems. This RP includes recommendations on: (1) Configurations and components, (2) general design considerations based on environmental and functional requirements, and (3) materials considerations in riser design. API Specification Q1—Specification for Quality Management System Requirements for Manufacturing Organizations for the Petroleum and Natural Gas Industry This specification establishes the minimum quality management system requirements for organizations that manufacture products or provide manufacturing-related processes under a product specification for use in the petroleum and natural gas industry. This document requires that equipment be fabricated under a quality management system that provides for continual improvement, emphasizing defect prevention and the reduction of variation and waste in the supply chain and from service providers. The goal of this specification is to increase equipment reliability through better manufacturing controls. API Specification 6A—Specification for Wellhead and Christmas Tree Equipment This specification defines minimal requirements for the design of valves, wellheads and Christmas tree equipment that is used during drilling and production operations. This specification includes requirements related to dimensional and functional interchangeability, design, materials, testing, inspection, welding, marking, handling, storing, shipment, purchasing, repair and remanufacture. ANSI/API Specification 11D1—Packers and Bridge Plugs This specification provides minimum requirements and guidelines for packers and bridge plugs used downhole in oil and gas operations. The performance of this equipment is often critical to maintaining control of a well during drilling or production operations. This specification provides requirements for the functional specification and technical specification, including design, design verification and validation, materials, documentation and data control, repair, shipment, and storage. ANSI/API Specification 16A—Specification for Drill-Through Equipment This specification defines requirements for performance, design, materials, testing and inspection, welding, marking, handling, storing and shipping of BOPs and drill-through equipment used for drilling for oil and gas. It also defines service conditions in terms of pressure, temperature and wellbore fluids for which the equipment will be designed. This standard is applicable to and establishes requirements for the following specific equipment: ram blowout preventers; ram blocks, packers and top seals; annular blowout preventers; annular packing units; hydraulic connectors; drilling spools; adapters; loose connections; and clamps. Conformance to this standard is necessary to ensure that this critical safety equipment has been designed and fabricated in a manner that ensures reliable performance. API Specification 16C—Specification for Choke and Kill Systems This specification was formulated to provide for safe and functionally interchangeable surface and subsea choke and kill systems equipment utilized for drilling oil and gas wells. This equipment is used during emergencies to circulate out a “kick” and therefore, the design and fabrication of the components is extremely important. The technical content in the document provides the minimum requirements for performance, design, materials, welding, testing, inspection, storing and shipping. Equipment specific to and covered by this specification includes: Actuated valve control lines; Articulated choke & kill line; Drilling choke actuators; Drilling choke control lines, exclusive of BOP control lines; Subsurface safety valve control lines; Drilling choke controls; Drilling chokes; Flexible choke and kill lines; Union connections; Rigid choke and kill lines; and Swivel unions. API Specification 16D—Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment This specification establishes design standards for systems that are used to control BOPs and associated valves that control well pressure during drilling operations. Although diverters are not considered well control devices, their controls are often incorporated as part of the BOP control system. Thus, control systems for diverter equipment are included in the specification. Control systems for drilling well control equipment typically employ stored energy in the form of pressurized hydraulic fluid (power fluid) to operate (open and close) the BOP stack components. For deepwater operations, transmission subsea of electric/optical (rather than hydraulic) signals may be used to short response times. The failure of these controls to perform as designed can result in a major well control event. As a result, conformance to this specification is critical to ensuring that the BOPs and related equipment will operate in an emergency. ANSI/API Specification 17D—Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment This specification provides specifications for subsea wellheads, mudline wellheads, drill-through mudline wellheads and both vertical and horizontal subsea trees. These devices are located on the seafloor, and therefore, ensuring the safe and reliable performance of this equipment is extremely important. This document specifies the associated tooling necessary to handle, test and install the equipment. It also specifies the areas of design, material, welding, quality control (including factory acceptance testing), marking, storing and shipping for both individual sub-assemblies (used to build complete subsea tree assemblies) and complete subsea tree assemblies. API Recommended Practice 17H—Remotely Operated Tools and Interfaces on Subsea Production Systems This recommended practice has been prepared to provide general recommendations and overall guidance for the design and operation of remotely operated tools (ROT) comprising ROT and ROV tooling used on offshore subsea systems. ROT and ROV performance is critical to ensuring safe and reliable deepwater operations and this document provides general performance guidelines for the equipment. Deepwater Horizon Investigations This section discusses relevant investigations that have significant bearing on this proposed rulemaking. DOI/DHS Investigation The joint DOI/DHS investigation started on April 27, 2010, when the Secretaries of DOI and DHS convened a joint investigation team (JIT) comprised of staff from the MMS and the U.S. Coast Guard (USCG). The JIT held seven public hearings and heard testimony from more than 80 witnesses. The DOI JIT issued a report on September 14, 2011, entitled, REPORT REGARDING THE CAUSES OF THE APRIL 20, 2010 MACONDO WELL BLOWOUT, which included its findings, conclusions, and recommendations. National Commission On May 22, 2010, President Barack Obama announced the creation of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (National Commission), an independent, non-partisan entity. The President charged the National Commission to determine the causes of the disaster, to make recommendations for improvement to the country's ability to respond to spills, and to recommend reforms to make offshore energy production safer. The National Commission published its final report on January 11, 2011, entitled, DEEP WATER, The Gulf Oil Disaster and the Future of Offshore Drilling. Chief Counsel for the National Commission Given the factual and technical complexity of some of the underlying causes of the blowout, the National Commission's Chief Counsel issued a separate report setting forth in greater detail its findings and conclusions regarding the technical, managerial, and regulatory aspects of the blowout. The report contains findings and conclusions about the loss of well control, and also contains recommendations to industry and government to enhance well design. The Chief Counsel's report was published on February 17, 2011, and is entitled, Macondo: The Gulf Oil Disaster. National Academy of Engineering At the request of DOI, a National Academy of Engineering (NAE)/National Research Council committee examined the probable causes of the Deepwater Horizon explosion, fire, and oil spill in order to identify measures for preventing similar harm in the future. The final report was released December 14, 2011, and is entitled, Macondo Well-Deepwater Horizon Blowout. The final report provides findings about the causes of the loss of well control and the failure of the BOP to prevent release of hydrocarbons and offers recommendations to industry and government that would strengthen oversight of deepwater wells, enhance system safety, and improve cementing practices and the technical skills of industry and regulatory staff. Recommendations on BOPs Each of the previously discussed investigations resulted in reports that contained recommendations to improve offshore safety. One consistent element in each of the investigations was the recognition that additional requirements related to BOPs and well-control equipment are needed. The following list contains some of the recommendations on BOPs and related equipment from the various investigations: —The BSEE should consider promulgating regulations that require operators/contractors to have the capability to monitor the subsea electronic module (SEM) battery(ies) from the drilling rig, to ensure that there is sufficient battery power to operate the system. —The BSEE should consider requiring standardization of: Remotely Operated Vehicle (ROV) intervention panels, ROV intervention capabilities, and maximum closing times when using an ROV; ROV hot stab and receptacles per API RP 17H; and hot stab designs between drilling and production operations. —The BSEE should consider requiring a blind-shear ram design that incorporates improved pipe‐centering in the shear ram. —The BSEE should make effective use of industry standards and best practice guidelines used by other countries with the recognition that standards need to be updated and revised continually. —The BSEE should improve reporting of safety-related incidents and require the reporting of near-misses to assist in accident prevention and to improve standards. —The BSEE should develop standardized requirements for the training and certification of key industry personnel. —The BSEE should rely on independent organizations to verify and certify compliance with critical designs and required processes. —The BSEE should ensure that the general well design includes a review of fitness of the components for the intended use. —The BSEE should consider promulgating regulations that would require operators to report leaks associated with BOP control systems. —The BSEE should consider promulgating regulations that would require real‐time, remote capture of drilling data and BOP function data. —The BSEE should require improvement of the instrumentation on BOP systems so that the functionality and condition of the BOP can be monitored continuously. —The BSEE should consider regulations that address a reasonable margin of safety between the ECD and the pressure that would cause wellbore fracturing. —The BSEE should establish testing and maintenance requirements for BOPs to ensure operability and increased reliability appropriate to the environment and application. —The BSEE should require improvement of the design capabilities of the BOP systems so that they can shear and seal all combinations of pipe under all possible conditions of load from the pipe and from the well flow, and so that there would always be a shearable section of the drill pipe in front of a blind-shear ram in the BOP. —The BSEE should require demonstration of the performance of the design capabilities of BOPs and require that they be independently certified on a regular basis by test or other means. Stakeholder Participation Since the Deepwater Horizon incident, BSEE has made it a priority to participate in meetings, training, and workshops with industry, standards organizations, and other stakeholders. The BSEE recognized that it was important to collect the best ideas on the prevention of well-control incidents and blowouts to assist in the development of this proposed rule. This includes the knowledge and skillset that industry has, and BSEE wants to benefit from that experience to improve the safety of all operations on the OCS. Therefore, on May 22, 2012, BSEE hosted a public offshore energy safety forum that brought together Federal decision-makers, industry, academia, and other stakeholders to discuss additional steps that BSEE and the industry might take to continue to improve the reliability and safety of BOPs. This public forum provided industry experts, Federal decision-makers, and the public the opportunity for free and open dialogue. Discussion panels consisted of representatives from government organizations, trade associations, equipment manufacturers, offshore operators, consultants, training companies, and others. During the forum, five separate panels discussed the following BOP topics: —BOP technology needs identified by Deepwater Horizon investigations; —Real-time technologies that can aid in diagnostics and kick detection; —Design requirements needed to provide assurance that BOPs would cut casing or drill pipe and seal a well effectively; —Manufacturing, testing, maintenance, and certification requirements needed to ensure operability and reliability of BOP equipment; and —Training and certification needs for industry personnel operating or maintaining BOPs. You can find additional information about the forum, including presentations and transcripts, on the BSEE Web page at: http://www.bsee.gov/BSEE-Newsroom/BSEE-News-Briefs/2012/BSEE-Hosts-BOP-Forum-in-DC. In the year following this forum, BSEE has also received significant input and specific recommendations from industry groups, operators, equipment manufacturers, and environmental organizations on each of these items. For example, BSEE has actively participated in the following, among other events: —The API Exploration & Production Standards Conference on Oilfield Equipment and Materials; —The Ocean Energy Safety Institute risk forum; —The Offshore Well Control Equipment Forum, organized by API, January 30, 2014; —The International Regulators Forum; —Various standards committees and sub-committees for standards development ( e.g., API Committee on Standardization of Oilfield Equipment and Material Subcommittee 16 on Drilling Well Control Equipment); —The BSEE and industry assessments of current technology involving research that BSEE is funding; and —The BSEE sponsored standards workshops—November 2012 and January 2014. The BSEE has considered this input in developing this proposed rulemaking and has reviewed studies and research on this topic. BSEE Response to Recommendations and Additional Considerations The BSEE evaluated all recommendations from the investigative bodies and public input and determined that the agency needs to update regulations related to the prevention of blowouts. The prevention of blowouts, either through precautionary measures or by operation of a BOP, is a critical priority for BSEE. The BSEE therefore focused this rulemaking on updating and revising current well-control regulations. Several of the recommendations related to BSEE's regulatory programs were already implemented in rulemakings following the Deepwater Horizon incident. The following items are included in this proposed rule and arise out of the investigation reports or from other third-party recommendations. Shearing Requirements The BSEE regulations currently require that a BOP stack include a blind shear ram. A blind shear ram is designed to cut drill pipe in the well and shut in the well in an emergency well control situation. In order for a blind shear ram to shut in a well where drill pipe is across the BOP, it must be capable of shearing the drill pipe and there are known mechanical and design limitations that may prevent this from occurring. As demonstrated by the Deepwater Horizon incident, the failure of equipment to perform reliably can result in a major safety and/or environmental event. Prior to the Deepwater Horizon incident, MMS commissioned the following research on shearing capabilities: Technical Assessment & Research (TAR) Project 383, Performance of Deepwater BOP Equipment During Well-control Events; TAR Project 408, Development of a Blowout Intervention Method and Dynamic Kill Simulated for Blowouts Occurring Ultra-Deepwater; TAR Project 431, Evaluation of Secondary Intervention Methods in Well-control; TAR Project 455, Review of Shear Ram Capabilities; and TAR Project 463, Evaluation of Sheer Ram Capabilities. This research can be found at http://www.bsee.gov/Technology-and-Research/Technology-Assessment-Programs/Categories/Drilling/. The research indicated that there was a large amount of uncertainty related to the shearing capability of existing BOPs. These reports documented that there were inconsistent and inadequate testing protocols used by manufacturers to demonstrate shearing capability, a failure to share shearing data that would allow for a better understanding of shearing capability, and a concern that not all operators and drilling contractors are aware of the limitations of the equipment they are using. Following the Deepwater Horizon incident, the Agency received recommendations from multiple investigations and studies concerning the need for new and more rigorous requirements and technologies to ensure that drilling components can be severed and a well safely shut-in during an emergency. The BSEE is proposing a series of new requirements to address the gaps that were identified in these reports, incorporate recent industry standards, and assist in the adoption of improved technology through performance-based requirements. Some of the limitations of current designs are well known. Industry acknowledges that BOP equipment would not shear drill collars, heavy weight drill pipe, or drill pipe tool joints. This inability to shear all of the components in the drill string can create significant complications in an emergency situation and increase the likelihood of a catastrophic event occurring. As the industry continues to develop more technically challenging resources, shearing and sealing become more difficult for several reasons, including: —The improvements in drill pipe properties, particularly increased material strength and ductility, result in higher forces being required to shear the drill pipe in the future. —Increased water depths, in combination with drilling fluid density and shut-in pressure, contribute to a BOP having to generate additional force to successfully shear. The BSEE believes that the current testing protocols and verification procedures must be strengthened to ensure that the capabilities of shearing equipment are clearly understood and demonstrated. Furthermore, on a longer term basis, the overall performance of this equipment must improve to ensure that it can operate in an emergency situation and can successfully shear a drill stem. In this rule, BSEE is proposing to accomplish these objectives through the following: —Require operators to assure that shearing capability for existing equipment complies with BSEE requirements related to shearing by performing tests and providing detailed results to a BSEE-approved verification organization. This organization would perform an independent engineering review of the test protocols and data and ensure that the testing would provide reasonable assurances that the equipment would perform as designed on drill pipe of specific mechanical and physical properties and under the operating conditions relevant to the particular well at which the equipment will be used. The BSEE expects that the independent engineering review would be based on recognized engineering practices. To become a BSEE-approved verification organization, organizations would need to submit documentation for BSEE approval describing the applicable qualifications and experience. This engineering review process would assist in developing more standardized testing protocols, increase data sharing within the industry, and provide information for future BSEE determinations of best available and safest technologies under section 21 of OSCLA, 43 U.S.C. 1347. The BSEE anticipates that industry would play an important role in this process by developing rigorous testing procedures and protocols for organizations that perform the testing. —Require compliance with the latest industry standards contained in API Standard 53. In addition to these industry standards, BSEE would also include a requirement that operators use two shear rams in subsea BOP stacks. The use of double shear rams would increase the likelihood that a drill string can be sheared by ensuring that a shearable component is opposite a shear ram. In this proposed rulemaking, BSEE will not propose adopting the provision in API Standard 53 that operators can “opt out” of this double shear ram requirement for moored rigs. If there are unique circumstances that prevent the use of two shear rams, operators would be able to apply for the use of alternative procedures or equipment under § 250.141. —Require the use of BOP technology that provides for better shearing performance through the centering of the drill pipe in the shear rams. A number of investigations 1 have found that the shear rams did not completely cut the drill pipe in the Deepwater Horizon. This occurred because the drill pipe was not centered within the stack. The BSEE is aware of at least one BOP equipment manufacturer that currently has pipe centering technology available and proposes to require the use of pipe centering within 7 years after the publication of the final rule to encourage further technological development. 1 See DOI JIT investigation recommendation, D6. Equipment Reliability and Performance Prior to the Deepwater Horizon incident, the industry's guidance document for the operation of BOPs was API RP 53— Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells, Third Edition, March 1, 1997 (Reaffirmed September 1, 2004). The BSEE currently incorporates only specific sections of this document in existing regulations, including sections related to maintenance, inspection, and accumulator systems. Following the Deepwater Horizon incident, industry recognized the need to enhance BOP guidance and concluded that it was necessary to completely rewrite API RP 53 and upgrade the document from an RP to a standard. The BSEE participated in the development of the industry standard and is proposing to incorporate the newly published standard into its regulations. Additionally, other key industry standards concerning this type of equipment would be incorporated by reference. The BSEE concluded that incorporating new API Standard 53 provisions into its regulations would allow for better regulatory oversight and would ensure improved BOP design and operability. The BSEE believes that the incorporation of this document, and other key industry standards, such as ANSI/API Spec. 6A, ANSI/API Spec. 16A, API Spec. 16C, API Spec. 16D, ANSI/API Spec. 17D, and API Spec. Q1, would establish minimum design, manufacture, and performance baselines for this equipment and is essential to ensure the reliability and performance of this equipment. The BSEE anticipates that BOP equipment that meets these new requirements, along with several supplemental requirements (such as requiring blind-shear rams that incorporate improved pipe-centering designs), would perform in a more reliable manner. The BSEE believes that the reliability of BOP-related equipment would also increase if its inspection, maintenance, and repair are performed by highly-trained personnel. Operators are currently required by BSEE regulations to ensure that all personnel are properly trained. The BSEE proposes to add requirements that specify that these personnel be qualified and trained pursuant to original equipment manufacturer (OEM) recommendations, unless otherwise specified by BSEE. The BSEE encourages industry to develop standards and certification programs for these personnel. Third-Party Verification Regulatory oversight of the lifecycle of BOP equipment, ranging from design, installation, inspection, testing, maintenance, and repair, presents a variety of logistical and technical challenges, especially because the equipment might be used at multiple locations. In several sections of the proposed regulations, BSEE would require third-party verification of the design, maintenance, inspection, testing, and repair of BOP systems and equipment by a BSEE-approved entity. We believe that the use of third-party verification organizations would help BSEE ensure that these systems are designed and maintained during their entire service life to minimize risk. For subsea BOPs or BOPs used in HPHT applications, we are proposing that BSEE-approved verification organizations submit reports verifying compliance with these new requirements. This verification would provide BSEE with reasonable assurance that the equipment is fit for service as intended. The BSEE is also proposing an additional qualification and verification process for BOP(s) and related equipment used in HPHT wells. The verification must be specific to the conditions of the particular well at which the BOP(s) will be used. This verification process is needed because there are currently no engineering standards for the design, fabrication, and testing of equipment used in HPHT conditions. The use of a BSEE-approved verification organization would provide an additional layer of review and verification during the development and operation of the equipment. It would be the responsibility of the operator to clearly demonstrate to the BSEE-approved verification organization and BSEE that the equipment was designed for the HPHT conditions specific to the well, and will perform in a reliable manner during its service life under those conditions. To become a BSEE-approved verification organization, the organization would have to submit documentation for approval describing the organization's applicable qualifications and experience. Failure Reporting/Near-Miss Reporting Several of the standards that BSEE proposes to incorporate by reference contain failure reporting processes that ensure that operators share information with OEMs related to the performance of their equipment. This sharing of information makes it possible for the OEMs to notify users of any safety issues that arise. In 2009, the industry provided the MMS with a BOP reliability study that specifically noted the importance of ANSI/API Spec. 16A, Annex F, and referred to this requirement as “an excellent practice that assists manufacturers in identifying problems that occur in the operation and maintenance of their projects.” The BSEE agrees with this statement and is including this requirement in the proposed regulations. Because the same equipment designs are often used by multiple operators, ensuring the timely reporting of this type of data can play an important role in preventing future incidents. The need for a formalized process for disseminating information to the industry was clearly demonstrated following the December 2012 failures of certain bolts used in BOPs and wellhead connectors in the Gulf of Mexico (GOM). Subsequent investigations revealed that although these failures had occurred over a period of years, most of the industry was not aware of the safety issues. The BSEE is proposing that the operators report any significant problems with BOP or well-control equipment to BSEE to ensure that this information can be provided in a timely manner to OCS operators and the international community. In the long term, BSEE would continue to encourage industry to develop a comprehensive and formalized method of collecting, analyzing, and disseminating failure data involving critical equipment. Safe Drilling Practices The proposed regulations include new requirements related to the maintenance of safe drilling margins consistent with the recommendations arising out of Deepwater Horizon investigations. The BSEE also proposes to add requirements related to liners and other downhole equipment. We believe that these requirements would help to reduce the likelihood of a major well-control event occurring and ensure the overall integrity of the well design. The proposed rule would require that operators have the capability to monitor deepwater and HPHT drilling operations from the shore and in real time. This would allow operators to anticipate and identify issues in a timely manner and to utilize onshore resources to assist in addressing critical issues. It would allow BSEE greater visibility of operations so BSEE may focus on specific critical operations for additional oversight. The BSEE also proposes a requirement that designated operators report leaks associated with BOP control systems on the daily report, in the WAR, and directly to the District Manager. This requirement would ensure that the agency is made aware of any leaks and may determine if agency action is appropriate. The proposed regulation would include requirements concerning ROV operations, including the adoption of API RP 17H to standardize ROV hot stab activities. An ROV hot stab is a high pressure subsea connector used to connect the ROV into the BOP system. An ROV hot stab is basically comprised of two parts: —A valve; and —A tool that connects onto the valve and controls the valve. The valve is usually placed on the subsea BOP stack panel, and is accessible for an ROV to insert the tool and activate certain functions on the BOP. BOP Testing In response to public input related to the value of pressure testing in predicting future performance of a BOP and industry concerns about the operational safety issues associated with performing these tests, BSEE proposes to modify the BOP testing frequency for workover and decommissioning operations. The BSEE proposes to change the current 7 day BOP testing interval for workover (current § 250.617(b)) and decommissioning (current § 250.1707(b)) operations to 14 days, which is consistent with the testing frequency requirements (reference current § 250.447(b) and 250.517(a)) for drilling and completion operations. Some drilling, completion, workover, and decommissioning operations use the same rigs and BOP systems; therefore, to ensure consistency among different operations involving the same equipment, BSEE proposes to harmonize the requirements for that type of equipment. Harmonizing the testing frequency would streamline the BOP function-testing criteria and increase safety by reducing repetition of operations, such as pulling out of the hole and running in the hole, that pose operational safety issues, therefore limiting the exposure of potential risks to offshore personnel. This may also have a positive effect on overall equipment durability and reliability. A benefit of this provision would be a cost saving to industry. We estimated the total cost savings to industry from this provision to be $150,000,000 per year (see the economic analysis for more detailed information). Based upon existing available data and the timeframes of the economic analysis, the cost savings benefits of the proposed rule would result in benefits greater than the identified quantitative costs of the rule. The BSEE is requesting comments on whether the proposed BOP testing interval should be 7 days, 14 days (as proposed), or 21 days for all types of operations including drilling, completions, workovers, and decommissioning. The BSEE is also requesting comments on the specific cost implications of each testing interval to further its consideration of the issue. For more information on the costs and benefits of the proposed rule, refer to the economic analysis. In addition to cost savings benefits, BSEE's economic analysis also considers benefits from potential reductions in oil spills and reduced fatalities. The BSEE is requiring additional measures ( e.g. real-time monitoring and increased maintenance) that help ensure the functionality and operability of the BOP system and, therefore, will reduce the risks of spills and fatalities. The BSEE is also soliciting comments on the use of pressure and functional tests during drilling operations to verify performance, the adequacy of current and proposed testing requirements, and the identification of risks associated with increasing or decreasing the testing frequency. II. Organization of Subpart G The BSEE determined that the most effective way to communicate consistent requirements for BOPs across all well operations (drilling, completion, workover, and decommissioning) is to consolidate those common requirements in one location. The current regulations repeat similar BOP requirements in multiple locations throughout 30 CFR part 250. The BSEE is proposing to consolidate these requirements into Subpart G, which is currently reserved. This would allow better flexibility, efficiency, and consistency in future rulemaking. The proposed rule would structure proposed Subpart G—Well Operations and Equipment, under the following undesignated headings: —GENERAL REQUIREMENTS —RIG REQUIREMENTS —WELL OPERATIONS —BLOWOUT PREVENTER (BOP) SYSTEM REQUIREMENTS —RECORDS AND REPORTING The sections contained within this new subpart would apply to all drilling, completion, workover, and decommissioning activities, unless explicitly stated otherwise. III. Effective Date of a Final Rule The BSEE understands that operators may need time to comply with certain requirements proposed in this rule. The BSEE is taking into consideration the amount of time needed to meet the requirements for the installation of double shear rams and new certification requirements. Based on information provided by industry, all new drilling rigs are already being built, pursuant to the same industry standards BSEE now proposes to adopt (including API Standard 53), and many have already been retrofitted to comply with these industry standards. Furthermore, most already comply with recognized engineering practices and OEM requirements related to repair and training. The BSEE evaluated the proposed requirements in this proposed rule and seeks to set reasonable effective dates for those requirements based on information gained during, among other activities, interaction with stakeholders, involvement with development of industry standards, and evaluation of current technology. The BSEE proposes an effective date of 3 months following publication of the final rule. Operators would be required to demonstrate compliance with most of the proposed requirements at that time, with the exception of the following more extended timeframes: —Operators would be required to comply with the real-time monitoring requirements within 3 years from the publication of the final rule. —Operators would be required to install double shear rams on subsea BOPs and on surface BOPs on floating facilities within 5 years from the publication of the final rule. —Operators would be required to install shear rams that center drill pipe during shearing operations within 7 years from the publication of the final rule. The BSEE is soliciting comments about the proposed compliance dates for the requirements in this proposed rule to ensure the dates are appropriate. The BSEE is specifically soliciting comments on whether the 3-month, 3-year, 5-year, and 7-year compliance dates are appropriate and achievable. The BSEE is also specifically soliciting comments on whether the proposed requirements can be met sooner than the proposed compliance dates ( e.g., 5 years after publication of the final rule for centering drill pipe), and the anticipated costs for meeting these proposed compliance dates. Please provide justification for your responses. Note that BSEE still retains the discretion under § 250.141 to authorize alternate procedures or equipment that provide an equivalent level of safety and environmental protection. IV. Future Plans for Subpart G In future rulemaking, BSEE intends to include additional regulatory requirements for operations and equipment in Subpart G, such as: —Well-control planning, procedures, training, and certification; —Major rig equipment; —Certification requirements for personnel servicing critical equipment; —Choke and kill systems; —Mud gas separators; —Wellbore fluid safety practices, testing, and monitoring; —Diverter systems with subsea BOPs; and —Coiled tubing, snubbing, and wireline units. The BSEE is also researching other topics that would be appropriate for inclusion into this new subpart in future rulemakings. V. Section-By-Section Discussion Subpart A—General What does this part do? (§ 250.102) This section would be revised to add references for Subpart G to (b)(1), (11), (12), and (13) and also add new paragraph (b)(19) to the table. This would be added so the public will know that they can find requirements about well operations and equipment in proposed Subpart G. What must I do to protect health, safety, property, and the environment? (§ 250.107) Paragraph (a) of this section would be revised to include a general performance-based requirement that operators utilize recognized engineering practices that reduce risks to the lowest level practicable during activities covered by the regulations and conduct all activities pursuant to the applicable lease, plan, or permit terms or conditions of approval. Recognized engineering practices may be drawn from established codes, industry standards, published peer-reviewed technical reports or industry recommended practices, and similar documents applicable to engineering, design, fabrication, installation, operation, inspection, repair, and maintenance activities. This risk reduction objective is used in other regulatory programs and is consistent with BSEE's goal of taking a more risk-based approach in its regulations. This risk reduction principle has also been included in a recently published industry document (API Bulletin 97) which addresses drilling, completion, and workover activities. Proposed paragraph (e) would be added to clarify BSEE's authority to issue orders when necessary to protect health, safety, property, or the environment. The first sentence authorizes BSEE to issue orders to ensure compliance with the regulations. The second sentence clarifies that BSEE may order that operations of a component or facility be shut-in because of a threat of serious, irreparable, or immediate harm to health, safety, property, or the environment posed by those operations or because the operations violate law, including a regulation, order, or provision of a lease, plan, or permit. Service fees. (§ 250.125) This table in this section would be revised to reflect the correct citation for payment of the service fee relating to DWOPs. Documents incorporated by reference. (§ 250.198) This section would be revised to update citations of currently incorporated documents and to incorporate new documents. Changes to this section would include: —Revising paragraph (h)(51) to update cross-references to the sections incorporating API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs); —Removing the incorporation of API RP 53 in paragraph (h)(63) and in its place incorporating new API Standard 53, Blowout Prevention Equipment Systems for Drilling Wells, Fourth Edition (with the exception of the opt-out provision); —Revising paragraph (h)(68) to update cross-references to the sections incorporating API Spec. Q1, Specification for Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry; —Revising paragraph (h)(70) to update cross-references to the sections incorporating ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree Equipment; —Adding new paragraph (h)(89) to incorporate ANSI/API Spec. 11D1, Packers and Bridge Plugs; —Adding new paragraph (h)(90) to incorporate ANSI/API Spec. 16A, Specification for Drill-through Equipment; —Adding new paragraph (h)(91) to incorporate API Spec. 16C, Specification for Choke and Kill Systems; —Adding new paragraph (h)(92) to incorporate API Spec. 16D, Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment; —Adding new paragraph (h)(93) to incorporate ANSI/API Spec. 17D, Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment; —Adding new paragraph (h)(94) to incorporate ANSI/API RP 17H, Remotely Operated Vehicle Interfaces on Subsea Production Systems. Paperwork Reduction Act statements—information collection. (§ 250.199) This section would be revised by: —Changing all the OMB Control Numbers from the 1010 numbering system to BSEE's new 1014 numbering system; —Rewording for plain language the reasons that BSEE collects the information and how it is used; and —Adding paragraphs for APDs, Application for Permit to Modify (APM), and Subpart G in the table to identify the basis for the information collection. Subpart B—Plans and Information What must the Deepwater Operations Plan (DWOP) contain? (§ 250.292) The proposed rule would re-designate existing paragraph (p) to (q) and add a new paragraph (p). Proposed new paragraph (p) would specify FSHR requirements within the DWOP. The FSHRs are used in combination with FPSOs. The use of FPSOs is relatively new to the GOM. There is only one FPSO currently operating in the GOM; however, the use of FPSOs is expected to increase in the next few years. Currently, BSEE approves the use of FPSOs and associated FSHRs through the DWOP process, but has no regulations specifically addressing the use of FSHRs. Proposed paragraph (p) would outline what BSEE requires in a DWOP that proposes the use of FSHRs. The new requirements would include submission of the following: —Detailed descriptions and drawings of the FSHR buoy and tether system; —Information on the design, fabrication, and installation of the FSHR buoy and tether system, including pressure ratings, fatigue life, and yield strengths; —A description of how the operator met the design requirements, load cases, and allowable stresses for each load case according to API RP 2RD, RP for Design of Risers for FPSs and TLPs; —Detailed information regarding the tether system used to connect the FSHR to a buoyancy air can; —Descriptions of the monitoring system and a monitoring plan to monitor the pipeline FSHR and tether for fatigue, stress, and any other abnormal condition ( e.g., corrosion) that may negatively impact the riser or tether; and —Documentation that the tether system and connection accessories for the pipeline FSHR have been certified by an approved classification society or equivalent and verified by the Certified Verification Agent (CVA) as required in current Subpart I and clarified in BSEE NTL 2007-G14, Pipeline Risers Subject to the Platform Verification Program. Subpart D—Oil and Gas Drilling Operations General Requirements. (§ 250.400) The proposed rule, would revise this entire section including the section heading. The current section entitled, Who is subject to the requirements of this subpart? is not necessary because the subject matter is sufficiently covered under § 250.146, which states that lessees, operators, and the person actually performing the activity to which a requirement applies are jointly and severally responsible for complying with the regulations. The new proposed language would require drilling operations to be done in a safe manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the OCS, including any mineral deposits (in areas leased and not leased), the National security or defense, or the marine, coastal, or human environment. The new section would also clarify that for drilling operations, the operator would need to follow the requirements of this subpart and the applicable requirements of proposed Subpart G. What must I do to keep wells under control? (§ 250.401) This section would be removed and reserved. The content of this section would be moved to proposed § 250.703. When and how must I secure a well? (§ 250.402) This section would be removed and reserved. The content of this section would be moved to proposed § 250.720. What drilling unit movements must I report? (§ 250.403) This section would be removed and reserved. The content of this section would be moved to proposed § 250.712. What additional safety measures must I take when I conduct drilling operations on a platform that has producing wells or has other hydrocarbon flow? (§ 250.406) This section would be removed and reserved. The content of this section would be moved to proposed § 250.723. What information must I submit with my application? (§ 250.411) This section would be revised by separating the diverter and BOP descriptions in the table containing regulatory cross-references for descriptions of APD information, and updating the cross-references to include proposed Subpart G. What must my description of well drilling design criteria address? (§ 250.413) This section would revise paragraph (g) to include the maximum ECD on the pore pressure/fracture gradient plot. The ECD is the effective density exerted by a circulating fluid against the formation that takes into account the pressure drop in the annulus. The ECD is an important parameter in avoiding kicks and losses, particularly in wells that have a narrow window between the fracture gradient and pore pressure. This information is necessary for proper well drilling design and for BSEE to better review the drilling program. What must my drilling prognosis include? (§ 250.414) This section would revise paragraphs (c), (h), and (i) and add new paragraphs (j) and (k). Paragraph (c) of this section would be revised to better define the safe drilling margin requirements. The planned safe drilling margins would be required to be between the proposed drilling fluid weights and the estimated pore pressures and the lesser of estimated fracture gradients or casing shoe pressure integrity test. The safe drilling margins would also have to meet the following conditions: —Static downhole mud weight must be greater than estimated pore pressure; —Static downhole mud weight must be a minimum of one-half pound per gallon below the lesser of the casing shoe pressure integrity test or the lowest estimated fracture gradient; —The ECD must be below the lesser of the casing shoe pressure integrity test or the lowest estimated fracture gradient; —When determining the pore pressure and lowest estimated fracture gradient for a specific interval, related hole behavior must be considered ( e.g., pressures, influx/loss of fluids, and fluid types). Changes to better define safe drilling margins are partially based on the information revealed during investigations of the Deepwater Horizon incident. 2 Safe drilling margins are used to determine the downhole fluid program and ensure fluid densities are capable of controlling the estimated pore pressure and formation fluids while not fracturing the formations. With clearer requirements for safe drilling margins, operators would be able to better understand BSEE requirements and design fluid programs accordingly. 2 See DOI JIT investigation recommendation, A3. Paragraphs (h) and (i) would be revised with only minor wording changes. New paragraph (j) would be added to require that the drilling prognosis include the type of wellhead and liner hanger systems to be installed and a descriptive schematic. The descriptive schematic would include, among other information, pressure ratings, dimensions, valves, load shoulders, and locking mechanism, if applicable. This information would assist BSEE in its review of the APD, and assist staff in ensuring that the wellhead and liner hanger systems are adequate for the proposed use. New paragraph (k) would be added to require submittal of any additional information required by the District Manager. What must my casing and cementing programs include? (§ 250.415) Paragraph (a) of this section would be revised to include casing information for all sections of each casing interval. Operators would also need to include bit depths (including measured and true vertical depth (TVD)), and locations of any installed rupture disks and indicate either the collapse or burst ratings. Requiring this information for all sections for each casing interval would make design calculations and submittals more accurate and provide a complete representation of the well. What must I include in the diverter description? (§ 250.416) This heading and section would be revised to remove the BOP descriptions and leave the diverter descriptions. The BOP descriptions would be moved to new Subpart G in proposed §§ 250.730, 250.731, and 250.732. The diverter requirements would remain unchanged. What must I provide if I plan to use a mobile offshore drilling unit (MODU)? (§ 250.417) This section would be removed and reserved. The content of this section would be moved to proposed § 250.713. What additional information must I submit with my APD? (§ 250.418) Paragraph (g) of this section would be revised to require operators to seek approval for plans to wash out or displace cement to facilitate casing removal upon well abandonment. The request would need to include a description of how far below the mudline the operator proposes to displace cement and how the operator will visually monitor returns. This proposed change would provide information that would assist BSEE in its review of the APD. What well casing and cementing requirements must I meet? (§ 250.420) The introductory language in this section would be revised to require that applicable casing and cementing requirements in proposed Subpart G must also be followed. Existing paragraph (a)(6) would be renumbered as paragraph (a)(7). New paragraph (a)(6) would be added to require adequate centralization to help ensure proper cementation. Multiple Deepwater Horizon investigations discussed the use of centralizers, which are devices that maintain the casing or liner in the center of the wellbore to help ensure efficient placement of cement around the casing string. If an operator cements casing off-center, the wellbore may not be properly sealed. New paragraph (b)(4) would be added to specify that if casing is needed that differs from what was approved in the APD, the operator would have to contact the appropriate District Manager and receive approval before installing the different casing. This addition is necessary to ensure the casing is suitable for the well conditions and for BSEE to have the most up-to-date wellbore information. Paragraph (c) would be renumbered and revised by adding a new paragraph (c)(2). New paragraph (c)(2) would require the use of a weighted fluid to maintain an overbalanced hydrostatic pressure during the cement setting time, except when cementing casings or liners in riserless hole sections. This proposed change would enhance wellbore stability during cementing. The use of a weighted fluid is particularly important because most well-control events occur due to inadequately weighted fluids in the hole, as well as inadequate volume of fluid to hold back the pressures in the well. A weighted fluid has a greater density than seawater. As the density of the weighted fluid increases, it exerts a greater hydrostatic pressure, thereby minimizing the potential for the well to flow. What are the casing and cementing requirements by type of casing string? (§ 250.421) Paragraph (b) of the table in this section would be revised to specify that if oil, gas, or unexpected formation pressure is encountered, the operator would have to set conductor casing immediately and set it above the encountered zone, even if it is before the planned casing point. This proposed change would ensure that conductor casing is not placed across a hydrocarbon zone. Paragraph (f) of the table in this section would be revised to disallow the use of liners as conductor casing. When a liner is used as conductor casing, a portion of the drive pipe is exposed to wellbore pressure, and BSEE does not accept drive pipe as a pressure-rated component. By prohibiting the use of liners as conductor casing, BSEE would ensure that the drive pipe is not exposed to wellbore pressures. What are the requirements for casing and liner installation? (§ 250.423) This section would be revised as follows: —Change the heading to more accurately reflect corresponding changes within the section. —Remove the pressure testing and negative pressure testing requirements. The pressure testing requirements would be found in proposed § 250.721. —Add information to clarify that liner latching mechanisms, if applicable, would need to be engaged upon successfully installing and cementing the casing string or liner. This last addition would reinforce the importance that liners are properly secured in place to ensure wellbore integrity. The requirements for latching and lockdown mechanisms were also a topic of discussion in the DOI JIT Deepwater Horizon investigation. What are the requirements for prolonged drilling operations? (§ 250.424) This section would be removed and reserved. The content of this section would be moved to in proposed § 250.722. What are the requirements for pressure testing liners? (§ 250.425) This section would be removed and reserved. The content of this section would be moved to proposed § 250.721. What are the recordkeeping requirements for casing and liner pressure tests? (§ 250.426) This section would be removed and reserved. The content of this section would be moved to proposed § 250.746. What are the requirements for pressure integrity tests? (§ 250.427) Paragraph (b) would be revised to clarify that operators must maintain the drilling margins as described in § 250.414. What must I do in certain cementing and casing situations? (§ 250.428) Paragraph (b) of the table in this section would be revised to require District Manager approval for hole interval drilling depth changes greater than 100 feet TVD, and submittal of a professional engineer (PE) certification, certifying that the PE reviewed and approved the proposed changes. This requirement would assist BSEE in verifying the actual well conditions. This new requirement would also ensure proper PE review of associated changes. Paragraph (c) of the table in this section would be revised to clarify requirements concerning what actions must be taken if there is an indication of an inadequate cement job. There are many indicators of an inadequate cement job. These include lost returns, no returns to the mudline or failure to reach the expected height for the specific cement job, cement channeling, abnormal pressures, or failure of equipment. If any of these indicators, or others, are encountered during the cement job, then action must be taken to ensure the cement job is adequate. Such actions may include running a temperature survey, running a cement evaluation log (such as an ultrasonic or equivalent bond log), or a combination of these or other techniques to check cement integrity by verifying the top of cement, density, condition, bond, etc. If the cement job is determined to be adequate, the results of the cement job determination would be submitted to the District Manager in the WAR. Paragraph (d) of the table in this section would be revised to clarify that if an operator has an inadequate cement job, the District Manager would have to review and approve all proposed remedial actions, unless immediate actions must be taken to ensure the safety of the crew or to prevent a well-control event. If the operator needs to take immediate action, a description would be required to be submitted to the District Manager once the action is completed. The paragraph would also clarify that any changes to the well program would require PE certification and would need to meet any other requirements imposed by the District Manager. New paragraph (k) would be added to the table in this section and would add clarification concerning the use of valves on drive pipes during cementing operations for the conductor casing, surface casing, or liner, and require the following to assist BSEE in assessing the structural integrity of the well: —The operator would include a description in the APD of the plan to use a valve that includes a schematic of the valve and height above the water line. —The valve would be remotely operated and full opening with visual observation while taking returns. —The person in charge of observing returns would be in communication with the drill floor. —The operator would record in the daily report and in the WAR if cement returns were observed; and —If cement returns were not observed, the operator would have to contact the District Manager and obtain approval of proposed plans to locate the top of cement, before continuing with operations. These proposed additions in paragraph (k) would help BSEE assess the well's structural integrity and verify cement suitability to the mudline. The overall changes to this section would help BSEE assess actual well operations and conditions, and also would help ensure proper design with additional PE review. What are the general requirements for BOP systems and system components? (§ 250.440) This section would be removed and reserved. The content of this section would be moved to proposed § 250.730. What are the requirements for a surface BOP stack? (§ 250.441) This section would be removed and reserved. The content of this section would be moved to proposed §§ 250.733 and 250.735. What are the requirements for a subsea BOP system? (§ 250.442) This section would be removed and reserved. The content of this section would be moved to proposed § 250.734. What associated systems and related equipment must all BOP systems include? (§ 250.443) This section would be removed and reserved. The content of this section would be moved to proposed §§ 250.733, 250.734, and 250.735. What are the choke manifold requirements? (§ 250.444) This section would be removed and reserved. The content of this section would be moved to proposed § 250.736. What are the requirements for kelly valves, inside BOPs, and drill-string safety valves? (§ 250.445) This section would be removed and reserved. The content of this section would be moved to proposed § 250.736. What are the BOP maintenance and inspection requirements? (§ 250.446) This section would be removed and reserved. The content of this section would be moved to proposed § 250.739. When must I pressure test the BOP system? (§ 250.447) This section would be removed and reserved. The content of this section would be moved to proposed § 250.737. What are the BOP pressure tests requirements? (§ 250.448) This section would be removed and reserved. The content of this section would be moved to proposed § 250.737. What additional BOP testing requirements must I meet? (§ 250.449) This section would be removed and reserved. The content of this section would be moved to proposed § 250.737. What are the recordkeeping requirements for BOP tests? (§ 250.450) This section would be removed and reserved. The content of this section would be moved to proposed § 250.746. What must I do in certain situations involving BOP equipment or systems? (§ 250.451) This section would be removed and reserved. The content of this section would be moved to proposed § 250.738. What safe practices must the drilling fluid program follow? (§ 250.456) This section would remove paragraph (j) and re-designate the other paragraphs. The content of current paragraph (j) would be moved to proposed § 250.720 to clarify that this requirement applies to drilling, workover, completion, and abandonment operations. What are the source control and containment requirements? (§ 250.462) This section and heading would be entirely revised. The existing content of this section entitled, What are the requirements for well-control drills? would be moved to proposed §§ 250.710 and 250.711. This proposed new section would add requirements for the operator to demonstrate the ability to control or contain a blowout event at the sea floor. This section would apply to operations using a subsea BOP or a surface BOP on a floating facility. Paragraph (a) would require the operator to determine its source control and containment capabilities by evaluating the performance of the well design to determine if a full shut-in can be achieved without reservoir fluids broaching the sea floor. Based on this evaluation, if the well can only be partially shut-in, then the operator would be required to establish the ability to flow and capture any residual fluids to a surface production and storage system. Paragraph (b) would require that operators have access to, and the ability to deploy, Source Control and Containment Equipment (SCCE) necessary to regain control of the well. The SCCE means the capping stack, cap and flow system, containment dome, and/or other subsea and surface devices, equipment, and vessels whose collective purpose is to control a spill source and stop the flow of fluids into the environment or to contain fluids escaping into the environment. This equipment would need to include, but not be limited to: —Subsea containment and capture equipment, including containment domes and capping stacks; —Subsea utility equipment, including hydraulic power, hydrate control, and dispersant injection equipment; —Riser systems; —ROVs; —Capture vessels; —Support vessels; and —Storage facilities. Paragraph (c) would require submittal of a description of the source control and containment capabilities before BSEE would approve an APD. The submittal to the Regional Supervisor would need to include the following: —The source control and containment capabilities for controlling and containing a blowout event at the seafloor, —A discussion of the determination required by paragraph (a), and —Information showing that the operator has access to, and the ability to deploy, all equipment necessary to regain control of the well. Paragraph (d) would require that operators contact the District Manager and Regional Supervisor for reevaluation of the source control and containment capabilities if there are any well design changes or if any of the approved SCCE is out of service. Paragraph (e) would outline the maintenance, inspection, and testing requirements of certain identified containment equipment as follows: Equipment Requirements Additional information (1) Capping stacks (i) Function test all pressure holding critical components on a quarterly frequency (not to exceed 104 days), Pressure holding critical components are those components that will experience wellbore pressure during a shut-in after being functioned. (ii) Pressure test pressure holding critical components on a bi-annual basis, but not later than 210 days from the last pressure test. All pressure testing must be witnessed by BSEE and a BSEE-approved verification organization, Pressure holding critical components are those components that will experience wellbore pressure during a shut-in. These components include, but are not limited to: all blind rams, wellhead connectors, and outlet valves. (iii) Notify BSEE at least 21 days prior to commencing any pressure testing. (2) Production safety systems used for flow and capture operations (i) Meet or exceed the requirements set forth in 30 CFR 250.800 through 250.808, Subpart H. (ii) Have all equipment unique to containment operations available for inspection at all times. (3) Subsea utility equipment Have all equipment unique to containment operations available for inspection at all times, Subsea utility equipment includes, but is not limited to: hydraulic power sources, debris removal, hydrate control equipment, and dispersant injection equipment. All of these changes in this section are necessary for BSEE to properly assess an operator's ability to access and deploy appropriate equipment sufficient to control and contain a blowout subsea. The Deepwater Horizon incident demonstrated a need for the capabilities to control and contain subsea blowouts. Following the Deepwater Horizon incident, operators did not resume certain drilling operations on the OCS until successfully demonstrating their ability to control and contain a subsea blowout. Industry quickly developed the capabilities and equipment, and satisfactorily demonstrated to BSEE the equipment capabilities to ensure subsea blowout control and containment. The BSEE is considering applying the requirements of this section to other operations besides those that use a subsea BOP or surface BOP on a floating facility. Specifically, BSEE is soliciting comments on whether the source control and containment requirements should be applicable to wells drilled in shallow water. Please provide reasons for your position. If your comment addresses anticipated costs associated with such a requirement, please provide any available supporting data. When must I submit an Application for Permit to Modify (APM) or an End of Operations Report to BSEE? (§ 250.465) Paragraph (b)(3) would be revised to clarify that if there is a: —Revision to the drilling plan; —Major drilling equipment change; or —Plugback, operators would have to submit an EOR, Form BSEE-0125, as required in proposed § 250.744, within 30 days after completing the work. This would help ensure that BSEE has the current well information. What records must I keep? (§ 250.466) This section would be removed and reserved. The content of this section would be moved to proposed § 250.740. How long must I keep records? (§ 250.467) This section would be removed and reserved. The content of this section would be moved to proposed § 250.741. What well records am I required to submit? (§ 250.468) This section would be removed and reserved. The content of this section would be moved to proposed §§ 250.742 and 250.743. What other well records could I be required to submit? (§ 250.469) This section would be removed and reserved. The content of this section would be moved to proposed § 250.745. Subpart E—Oil and Gas Well-Completion Operations General requirements. (§ 250.500) This section would be revised to add a requirement to follow the applicable requirements of new Subpart G in addition to Subpart E. With the development of new Subpart G, BSEE would consolidate similar requirements regarding drilling, workover, completion, and decommissioning activities into a separate subpart. It is BSEE's intention to include additional regulations regarding similar operations and equipment in the new Subpart G in future regulations. This section would also be revised to replace the word “shall” with “must.” This change would clarify that the provision is mandatory. Equipment movement. (§ 250.502) This section would be removed and reserved. The content of this section would be moved to proposed § 250.723. Crew instructions. (§ 250.506) This section would be removed and reserved. The content of this section would be moved to proposed § 250.710. Well-control fluids, equipment, and operations. (§ 250.514) Paragraph (d) would be removed and its content would be moved to proposed § 250.720. What BOP information must I submit? (§ 250.515) This section would be removed and reserved. The content of this section would be moved to proposed §§ 250.731 and 250.732. Blowout prevention equipment. (§ 250.516) This section would be removed and reserved. The content of this section would be moved to proposed §§ 250.730, 250.733, 250.734, 250.735, and 250.736. Blowout preventer system tests, inspections, and maintenance. (§ 250.517) This section would be removed and reserved. The content of this section would be moved to proposed §§ 250.711, 250.737, 250.738, 250.739, and 250.746. Tubing and wellhead equipment. (§ 250.518) This section would be revised by removing paragraph (b), redesignating the rest of the paragraphs to reflect the removal of paragraph (b), and adding new paragraphs (e) and (f) to clarify packer and bridge plug requirements. The content of paragraph (b) would be moved to proposed § 250.722 and would clarify that these requirements apply to drilling, workover, completion, and abandonment operations. New paragraph (e) would add packer and bridge plug requirements including: —Adherence to newly incorporated API Spec. 11D1, Packers and Bridge Plugs; —Production packer setting depth to allow for a sufficient column of weighted fluid for hydrostatic control of the well; and —Production packer setting depth criteria. New paragraph (f) would require, in your APM, a description and calculations of how the production packer setting depth was determined. Subpart F—Oil and Gas Well-Workover Operations General requirements. (§ 250.600) This section would be revised to add the requirement to follow the applicable provisions of new Subpart G in addition to Subpart F. With the new development of Subpart G, BSEE is consolidating similar requirements regarding drilling, workover, completion, and decommissioning activities. It is BSEE's intention to include additional regulations regarding similar operations and equipment in new Subpart G in future regulations. This section would also be revised to replace the word “shall” with “must.” This change would clarify that the provision is mandatory. Equipment movement. (§ 250.602) This section would be removed and reserved. The content of this section would be moved to proposed § 250.723. Crew instructions. (§ 250.606) This section would be removed and reserved. The content of this section would be moved to proposed § 250.710. Well-control fluids, equipment, and operations. (§ 250.614) Paragraph (d) would be removed and its content would be moved to proposed § 250.720. What BOP information must I submit? (§ 250.615) This section would be removed and reserved. The content of this section would be moved to proposed §§ 250.731 and 250.732. Coiled tubing and snubbing operations. (§ 250.616) The section would be revised by renaming the section heading to “Coiled tubing and snubbing operations,” removing paragraphs (a) through (e), and re-designating paragraphs (f) through (h) as (a) through (c). The content of existing paragraphs (a) through (e) would be moved to proposed §§ 250.730 and 250.733 through 250.736. Blowout preventer system testing, records, and drills. (§ 250.617) This section would be removed and reserved. The content of this section would be moved to proposed §§ 250.711, 250.737, and 250.746. What are my BOP inspection and maintenance requirements? (§ 250.618) This section would be removed and reserved. The content of this section would be moved to proposed § 250.739. Tubing and wellhead equipment. (§ 250.619) This section would be revised by removing paragraph (b), redesignating the rest of the paragraphs to reflect the removal of paragraph (b), and adding new paragraphs (e) and (f) to clarify packer and bridge plug requirements. The content of paragraph (b) would be moved to proposed § 250.722. New paragraph (e) would add packer and bridge plug requirements for when operators pull and reinstall packers and bridge plugs, including: —Adherence to newly incorporated API Spec. 11D1, Packers and Bridge Plugs; —Production packer setting depth to allow for a sufficient column of weighted fluid for hydrostatic control of the well; and —Production packer setting depth criteria. This new paragraph would codify existing BSEE policy to ensure consistent permitting. The incorporation of API Spec. 11D1 would enhance packer and bridge plug reinstallation and ensure conformance to industry specifications and good industry practices not previously covered in BSEE regulations. New paragraph (f) would require, in the APM, a description and calculation of how the production packer setting depth was determined. Subpart G—Well Operations and Equipment This part of the section-by-section will not address any regulatory provisions that BSEE proposes to move without change from existing subparts to the new subpart G because the proposed moves in regulatory text are discussed above. However, this portion of the section-by-section will explain existing language that BSEE proposes to revise or add as new provisions. General Requirements What operations and equipment does this subpart cover? (§ 250.700) This proposed section explains that new Subpart G would apply to drilling, completion, workover, and decommissioning activities and equipment. New Subpart G would contain common requirements for these activities. Every section in Subpart G would be applicable to drilling, completion, workover, and decommissioning activities, unless explicitly stated otherwise. May I use alternate procedures or equipment during operations? (§ 250.701) Content in this proposed section is similar to existing § 250.408. This proposed section would explain that operators may seek approval to use alternate procedures or equipment following the process set forth in § 250.141. This section would also specify that the proposed alternate procedures and equipment must be discussed in the APD or APM. This section would make the information in § 250.408 applicable to all operations covered by this subpart. May I obtain departures from these requirements? (§ 250.702) The content of this proposed section is similar to existing § 250.409. This proposed section would explain that operators may request departures from the regulations in this subpart by using the procedure set forth in § 250.142. Also, this section would clarify what would be required for the departure request. Another addition to this section would require that the departure request be discussed in the APD or APM. What must I do to keep wells under control? (§ 250.703) The content of this proposed section was moved from existing § 250.401. Language in this section would be revised to ensure applicability to all operations covered under this subpart, and to require the use of equipment that is designed, tested, and rated for the most extreme conditions to which the equipment will be exposed while in service. This section would also require that personnel be trained according to the provisions of Subparts O and S. These subparts outline minimum training requirements. The BSEE expects personnel performing operations to be trained and knowledgeable of their required actions and duties. Rig Requirements What instructions must be given to personnel engaged in well operations? (§ 250.710) The content of this proposed section was moved from existing §§ 250.462, 250.506, and 250.606. This section would require personnel engaged in well operations to be instructed in safety requirements, possible hazards, and general safety considerations as required by Subpart S, prior to engaging in operations. This proposed section would clarify that the well-control plan must contain instructions for personnel about the use of each well-control component of the BOP system, and include procedures for shearing pipe and sealing the wellbore in the event of a well control or emergency situation before maximum anticipated surface pressure (MASP) conditions are reached. These changes would establish better proficiency for personnel using well-control equipment. What are the requirements for well-control drills? (§ 250.711) The content of this proposed section was moved from existing §§ 250.462, 250.517(f), 250.617(c), and 250.1707(c). This section would add minor revisions to make the requirement applicable to all drilling, completion, workover, and decommissioning operations covered under this subpart. This section would also clarify that the same drill may not be repeated consecutively. These proposed changes would establish better proficiency for personnel using well-control equipment. What rig unit movements must I report? (§ 250.712) The content of this proposed section was moved from existing § 250.403 with the following revisions and additions: Paragraph (a) would be revised to add rig movement reporting requirements for all rig units moving on and off locations. Rig units include MODUs, platform rigs, snubbing units, wire-line units used for non-routine operations, and coiled tubing units. This paragraph would make rig movement reporting requirements applicable to all rigs conducting operations covered under proposed Subpart G. The deadline for notifying the District Manager about rig movements, using the Rig Movement Notification Report (Form BSEE-0144), would increase from 24 to 72 hours. This proposed change would allow BSEE to better anticipate upcoming operations and coordinate applicable permitting. Paragraph (a)(2) would be revised to clarify that if operators anticipate moving off location less than 72 hours after initially moving onto location, the anticipated movement schedule may be included on Form BSEE-0144. This clarification would be necessary if you have, for example, coiled tubing and batch operations and there is not enough time to submit the rig movement 72 hours in advance. Form BSEE-0144 has been revised from its current version to reflect changes based on the proposed rule. Revised Form BSEE-0144 is included in the Appendix to this proposed rule. Existing paragraph (c) would be replaced with a new paragraph (c) requiring notifications if a MODU or platform rig is to be warm or cold stacked. The notifications for MODUs or platform rigs would include: —Where the rig is coming from; —Location where it would be positioned; —If it would be manned or unmanned; and —Any changes in the stacking location. Proposed paragraph (c) would also allow BSEE to have a better understanding of where MODUs and platform rigs are located in case of emergency situations possibly affecting surrounding infrastructure. New paragraph (d) would require notification to the appropriate District Manager of any construction, repairs, or modifications associated with the drilling package made to the MODU or platform rig, prior to resuming operations after stacking. New paragraph (e) would also require notification to the District Manager if a drilling rig enters OCS waters regarding where the drilling rig is coming from. The BSEE expects that this notification would provide information about the last location where the drilling rig was conducting operations, or the shipyard location if it is coming from a shipyard, for either a new build or repair. This notification would assist BSEE in verifying the location and movement of the rigs. This notification would also help BSEE verify rig fitness and documentation requirements to allow the rig to conduct operations on the OCS as outlined in proposed § 250.713. New paragraph (f) would clarify that if the anticipated date for initially moving on or off location changes by more than 24 hours, an updated Rig Movement Notification Report (Form BSEE-0144) would be required. This revision would clarify to operators when a revision or update would be required. What must I provide if I plan to use a mobile offshore drilling unit (MODU) or lift boat for well operations? (§ 250.713) The content of this proposed section would be moved from existing § 250.417. This section would make the requirements applicable to all operations covered under this subpart. Revised paragraph (g) would add current monitoring requirements. Current monitoring is discussed in BSEE NTL 2009-G02, Ocean Current Monitoring. These proposed changes would help provide better consistency in permits. Upon publication of the final rule, BSEE would rescind BSEE NTL 2009-G02. Do I have to develop a dropped objects plan? (§ 250.714) This section would codify some of the language from BSEE NTL 2009-G36, Using Alternate Compliance in Safety Systems for Subsea Production Operations, to help avoid prolonged damage to subsea infrastructure and aid operators' and BSEE's response to a dropped object. This proposed new section would outline the requirements for developing a dropped objects plan. This proposed section would be applicable to all floating rig units in an area with subsea infrastructure. This section would specify the requirements of a dropped objects plans. The plan would be required to include: —A description and plot of the path the rig would take while running and pulling the riser; —A plat showing the location of any subsea wells, production equipment, pipelines, and any other identified debris; —Modeling of a dropped object's path for various material forms, such as a tubular ( e.g., riser or casing) and box ( e.g., BOP or tree) with consideration given to metocean conditions; —A description of communications, procedures, and delegated authorities established with the production host facility to shut-in any active subsea wells, equipment, or pipelines in the event of a dropped object; and —Any additional information required by the District Manager. Do I need a global positioning system (GPS) for MODUs and jack-ups? (§ 250.715) This proposed new section would codify existing BSEE NTL 2013-G01, Global Positioning System (GPS) for Mobile Offshore Drilling Units (MODUs). The proposed requirements for GPSs include: —Providing a robust and reliable means of monitoring the position and tracking the path in real-time if the MODU or jack-up moves from its location during a severe storm; —Installing and protecting the tracking system's equipment to minimize the risk of the system being disabled; —Placing the GPS transponders in different locations for redundancy to minimize risk of system failure; —Capability of transmitting data for at least 7 days after a storm has passed; —Recording the GPS location data if the MODU or jack-up is moved off location in the event of a storm; and —Providing BSEE with real-time access to the MODU or jack-up location data. The BSEE would use the GPS data in emergency situations to minimize potential damage to the offshore infrastructure. Well Operations When and how must I secure a well? (§ 250.720) The content of this proposed section would be moved from existing §§ 250.402, 250.456(j), 250.514(d), 250.614(d), and 250.1709, and would contain the following revisions and additions: Paragraph (a) would add that the District Manager must be notified when operations are interrupted. This paragraph would also add an example to the list of events that would warrant interruption of operations (currently in § 250.402(a)). Specifically, if there is any observed flow outside the well's casing, operators would have to interrupt operations. The requirement to interrupt operations for the additional event of observing flow outside the well's casing would protect against a failure of the well's structural foundation and a possible environmental incident. The requirement to notify the District Manager would give BSEE awareness of interrupted operations and allow for appropriate regulatory response. This paragraph would also require a negative test in accordance with proposed § 250.721 to ensure wellbore and barrier integrity before removing a subsea BOP stack or surface BOP stack on a mudline suspension well. Paragraph (a)(2) would also clarify that if there is not enough time to install the required barriers or if special circumstances occur, the District Manager may approve alternate procedures or barriers in accordance with § 250.141. Some options that could be considered include the use of: —Blind or blind-shear rams; —Pipe rams and an inside BOP (if hydrocarbons are not exposed in the open hole); —A drill string hang-off tool; and/or —Storm packers. This section would help ensure that during the events previously discussed, the well would be properly secured. New paragraph (b) would be added to consolidate the content of existing §§ 250.456(j), 250.514(d), 250.614(d), and 250.1709. What are the requirements for pressure testing casing and liners? (§ 250.721) The content of this proposed section would be moved from existing §§ 250.423 and 250.425, and would include the following revisions and additions: Paragraph (a) would increase the minimum test pressure specification for conductor casing, excluding subsea wellheads, from 200 psi in existing regulations (§ 250.423(a)(2)) to 250 psi. Paragraph (b) would require operators to test each drilling liner and liner-lap before any further operations are continued in the well. Paragraph (c) would contain requirements for testing each production liner and liner-lap. Paragraph (d) would clarify that the District Manager may approve or require other casing test pressures. Proposed new paragraph (e) would add the requirement that operators follow additional pressure test requirements when they plan to produce a well. If a well would be fully cased and cemented, the operator would have to pressure test the well to the maximum anticipated shut-in tubing pressure before perforating the casing or liner. If a well would be an open-hole completion, the operator would have to pressure test the entire well to the maximum anticipated shut-in tubing pressure before drilling the open-hole section of the well. Proposed paragraph (f) would add a requirement for a PE certification of proposed plans to provide a proper seal if there is an unsatisfactory pressure test. Proposed paragraph (g) would require a negative pressure test on all wells that use a subsea BOP stack or wells with mudline suspension systems and outline the requirements for those tests. What are the requirements for prolonged operations in a well? (§ 250.722) The content of this proposed section would be moved from existing §§ 250.424, 250.518(b), and 250.619(b), with revisions made to clarify the requirements for well integrity for operations continuing longer than 30 days from the previous casing test. If well integrity has deteriorated to a level below minimum safety factors, this section would require repairs or installation of additional casing and subsequent pressure testing, as approved by the District Manager. To obtain approval, a PE certification must be provided showing that he or she reviewed and approved the proposed changes. The results of the pressure test would be submitted to the appropriate District Manager. These changes help ensure a proper wellbore integrity determination to allow operations to continue. What additional safety measures must I take when I conduct operations on a platform that has producing wells or has other hydrocarbon flow? (§ 250.723) This proposed section would reflect a combination of existing §§ 250.406, 250.502, and 250.602. Paragraph (b) would be modified from existing § 250.406(a) to clarify that the emergency shutdown station would be for the production system. This revision would ensure that rig units would be able to shut-in the production system of the host facility. Paragraphs (d) and (e) would make minor revisions to clarify applicability to all operations covered under proposed Subpart G and to divide the paragraphs to make them easier to read and understand. What are the real-time monitoring requirements? (§ 250.724) This proposed new section would include a requirement covering real-time monitoring by onshore personnel of the BOP system, fluid handling system of the rig, and downhole conditions. This section would be added, in part, based on multiple recommendations from various Deepwater Horizon investigation reports. Having the real-time data available to onshore personnel would increase the level of oversight throughout operations. Onshore personnel could review data and help rig personnel conduct operations in a safe manner. Also, onshore personnel would be able to assist the rig crew in identifying and evaluating abnormalities or unusual conditions while conducting operations. This section would require that BSEE be provided access to the real-time monitoring facility, upon request. Operators would also be required to record and retain the data at an onshore location for recordkeeping purposes and to make it accessible to BSEE upon request. If real-time monitoring capability is lost during operations, the operator would be required to immediately notify the District Manager, who may require other measures until the real-time monitoring capability is restored. The BSEE is considering expanding the requirements of this section to other operations, not only those conducted with a subsea BOP or a surface BOP on a floating facility or on any BOP operating in an HPHT environment. The BSEE is specifically soliciting comments on whether the real-time monitoring should be required for all well operations, including shallow water shelf operations. Please provide reasons for your position. If your comment addresses anticipated costs associated with such a requirement, please provide any available supporting data. Blowout Preventer (BOP) System Requirements What are the general requirements for BOP systems and system components? (§ 250.730) This proposed section would reflect a combination of existing §§ 250.416, 250.440, 250.516, 250.616, and 250.1706 and would also include the following revisions and additions: —Require compliance with API Standard 53, ANSI/API Spec. 6A, ANSI/API Spec. 16A, API Spec. 16C, API Spec. 16D, ANSI/API Spec. 17D, and API Spec. Q1. —Clarify that the working-pressure rating of each BOP component must exceed the MASP as defined for their operation, such as drilling, completion, or workover. For a subsea BOP, the MASP would be taken at the mudline. —Add a new performance measure for operators which would require the BOP to be able to meet anticipated wellbore conditions and still be able to perform its expected function of sealing the well. Proposed paragraph (a) would require compliance with the following API and ANSI/API documents: API Standard 53 —BOP system and components would have to be designed, installed, maintained, inspected, tested, and used according to API Standard 53. The API Standard 53 would be incorporated into the regulations; however, if there is a conflict between API Standard 53 and these regulations, operators would have to follow the requirements of these regulations ( i.e., BSEE is requiring that surface BOPs on floating facilities have the same dual shearing requirement as subsea BOPs; API Standard 53 allows for an opt out of this standard with a risk assessment that is not included in the proposed rule). Currently, BSEE regulations only incorporate select sections of API RP 53 (accumulators, maintenance, and inspections). By incorporating new API Standard 53, BSEE would greatly enhance the BOP requirements. As previously discussed in the Background section, API Standard 53 is the latest industry consensus standard to update and enhance BOP requirements. After the Deepwater Horizon incident, multiple investigations focused on the BOP stack. Every investigation made multiple recommendations to improve the performance and regulation of BOPs. Industry recognized the need to update the previous edition of API RP 53. During the process of updating API RP 53, industry determined that the document needed more substantive content and needed to be raised from an RP to an industry standard. The current API Standard 53 contains the industry consensus standards concerning engineering and operating practices regarding BOP reliability and use. Included in API Standard 53 is a list of normative references (industry standards) that are indispensable to fully utilizing API Standard 53 and to ensure safe and reliable equipment. The normative references include: —ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree Equipment; —API Spec. 16A, Specification for Drill-through Equipment; —ANSI/API Spec. 16C, Specification for Choke and Kill Systems; —API Spec. 16D, Specification for Control Systems for Drilling Well-control Equipment and Control Systems for Diverter Equipment; and —ANSI/API Spec. 17D, Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment . Sections of these industry standards apply to BOP systems. The BSEE specifically proposes to incorporate these standards into the regulations as applied to BOP systems to emphasize their significance and make clear the industry standards that must be followed. The BSEE is also requesting comments concerning whether any sections of these documents should not be incorporated by reference. For general reference, the following table shows relevant topics from each of these industry standards. This table is not a complete list of applicable sections, but is intended to show how these sections interact with API Standard 53. Industry standard Applicable topics in API standard 53 (but not limited to): ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree Equipment; Flanges and hubs, Bolting and clamps, Gaskets, Choke and kill lines, Equipment marking and storage, Equipment modifications, Maintenance and testing. API Spec. 16A, Specification for Drill-through Equipment; Flanges and hubs, Bolting and clamps, Gaskets, Choke and kill lines, Equipment marking and storage, Maintenance and testing. ANSI/API Spec. 16C, Specification for Choke and Kill Systems; Choke manifolds, Choke and kill lines. API Spec. 16D, Specification for Control Systems for Drilling Well-control Equipment and Control Systems for Diverter Equipment; Control systems, Maintenance and testing. Electro-hydraulic and multiplex control systems, Auxiliary equipment, Accumulators. ANSI/API Spec. 17D, Design and Operation of Subsea Production Systems — Subsea Wellhead and Tree Equipment; Flanges and hubs, Bolting and clamps, Choke and kill lines, Equipment marking and storage, Maintenance and testing. Paragraph (a)(3) would require that pipe and variable bore rams be capable of closing and sealing on drill pipe, workstrings, or tubing under MASP with the proposed regulator settings of the BOP control system. This new paragraph would help ensure the BOP control regulator set points are sufficient to ensure closure and sealing of the pipe rams. Paragraph (a)(4) would require a current set of approved schematics to be on the rig and at an onshore location. It would also require that if there are any modifications to the BOP or control system that will change your schematics, operations would be suspended until the operator obtains approval of the new schematics from the District Manager. Paragraph (b) would require that operators design, fabricate, maintain, and repair the BOP system pursuant to the requirements contained in this subpart, OEM recommendations unless otherwise directed by BSEE, and recognized engineering practices. Personnel performing any repair or maintenance would be required to follow any OEM training or certification recommendations unless otherwise directed by BSEE. Paragraph (c) would adopt the failure reporting procedures contained in certain API documents. The BSEE would add specific time frames for the completion of these procedures consistent with other previously incorporated API standards and add a requirement that BSEE be notified of any changes to operating or repair procedures adopted to address or in response to a failure. This would allow BSEE to notify the industry and international community of any significant safety issues related to equipment design, and potentially prevent future incidents. Paragraph (d) would require that if an operator plans to use a BOP stack manufactured after the effective date of the final rule, the operator must use one manufactured pursuant to API Spec. Q1, Specification for Quality Management System Requirements for Manufacturing Organizations for the Petroleum and Natural Gas Industry. Currently, BSEE uses API Spec. Q1 in association with the manufacture of safety and pollution prevention equipment. The API Spec. Q1 outlines the requirements for development of a quality management system that provides for continual improvement, emphasizing defect prevention and the reduction of variation. This quality management system facilitates consistent and reliable manufacture. Also added to this section is the option to seek approval to use quality assurance programs other than API Spec. Q1. The BSEE requests comments concerning whether other industry standards should be incorporated into the regulations that ensure that BOP equipment performs as designed during its service life. What information must I submit for BOP systems and system components? (§ 250.731) This proposed section would reflect a combination of existing §§ 250.416, 250.515, 250.615, and 250.1705 with the following revisions and additions: The introductory text would reflect that the requirements of BOP description submittals would apply to APDs, APMs, and other required submittals. The introductory text would also clarify that the BOP descriptions would not have to be resubmitted with any subsequent permit application or submittal after the initial application that BSEE approved or accepted when the operator moved onto location unless the operator makes changes to what was initially approved or the operator moves off location from that well. This introductory text would also clarify that if the operator is not required to resubmit the BOP information in subsequent applications, then the operator must document why the submittal is not required—in other words, the operator would need to reference the previously approved or accepted application or submittal and state that no changes have been made. The information required under this section would increase the quality of submitted documents and enhance BSEE's review and permitting process. Paragraph (a) would require submission of the following new BOP descriptions: —Pressure ratings of BOP equipment; —Both surface and corresponding subsea pressures for a subsea BOP test; —Rated capacities of the fluid-gas separator system; —Control fluid volumes needed to operate each component; —Control system pressure and regulator settings needed to achieve an effective seal of each ram BOP under MASP; —Number and volume of accumulator bottles and bottle banks (for subsea BOPs, include both surface and subsea bottles); —Accumulator pre-charge calculations (for a subsea BOP system, include both the surface and subsea calculations); —All locking devices; and —Control fluid volume calculations for the accumulator system (for a subsea BOP system, include both the surface and subsea volumes). Submission of these descriptions would enhance BSEE's review and understanding of the entire BOP system. Paragraph (b) would add the following new schematic drawing requirements: —Labeling the control system alarms and set points; —Including all locking devices; —Including control station locations; —Labeling the type of shear ram(s), size range for variable bore ram(s), size of any fixed ram(s), size of choke and kill lines, and size of subsea BOP gas bleed line(s); and —Including a cross-section of the riser for a subsea BOP system showing number size, and labeling of all control, supply, choke, and kill lines down to the BOP. Paragraph (c) would reflect content from existing § 250.416(e) and require submission of the following certifications by a BSEE-approved verification organization verifying that: —Test data clearly demonstrates the shear ram(s) will shear the drill pipe at the water depth as required in § 250.732; —The BOP was designed, tested, and maintained to perform at the most extreme anticipated conditions; and —The accumulator system has sufficient fluid to function the BOP system without assistance from the charging system. Paragraph (d) would require additional certification if an operator uses a subsea BOP, a BOP in an HPHT environment, or a surface BOP on a floating facility. The certification would include verification of the following: —The BOP stack is designed for the specific equipment on the rig and for the specific well design; —The BOP stack has not been compromised or damaged from previous service; and —The BOP stack will operate in the conditions in which it will be used. The BSEE is considering expanding the requirements of this paragraph to all BOPs. The BSEE is specifically soliciting comments on whether this certification requirement should be applied to [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2015-08587. Public record. Not legal advice.