One of Brian’s Favorite Quotes
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Oil and Gas and Sulphur Operations on the Outer Continental Shelf-Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf
This portion of the preamble provides an explanation of the specific regulatory changes proposed in this rule and why they are necessary. At the outset, this discussion addresses the proposed definitions of the terms Arctic OCS and Arctic OCS Conditions for use in both BOEM’s and BSEE’s regulations in order to provide context for the rest of the proposed provisions. Since this is a joint BOEM and BSEE proposed rule, the remainder of the Section-by-Section discussion is organized according to how operators would seek to comply with the proposed regulations, rather than the order in which they would appear in the Code of Federal Regulations. After introducing the definitions of Arctic OCS (for purposes of proposed §§ 250.105, 254.6, and 550.105) and Arctic OCS Conditions (for purposes of proposed §§ 250.105 and 550.105), the Section-by-Section discussion provides an explanation of the remainder of BOEM’s proposed regulations (i.e., proposed §§ 550.105, 550.200, 550.204, 550.206, and 550.220), and then follows with the remainder of BSEE’s proposed regulations (i.e., proposed §§ 250.105, 250.188, 250.198, 250.300, 250.402, 250.418, 250.447, 250.452, 250.470, 250.471, 250.472, 250.473, and 250.1920; proposed §§ 254.6, 254.55, 254.65, 254.70, 254.80, and 254.90).
Although BSEE permitting and operational requirements appear earlier in Title 30 of the CFR at Part 250, with the BOEM requirements following in 30 CFR part 550, in practice the IOP and EP phases governed by the 30 CFR part 550 regulations would precede the drilling approval and oversight phases governed by 30 CFR part 250 (operations). Requirements to prepare for an oil spill, which are contained in 30 CFR part 254, may be met at any time before handling, storing, or transporting oil in operations BSEE permits under Part 250. Finally, the Section-by-Section discussion includes a process flowchart of BOEM’s and BSEE’s current regulatory framework for Arctic OCS exploratory drilling and how the proposed requirements would be integrated into that framework.
A. Definitions (§§ 250.105, 254.6, and 550.105)
For the purposes of this proposed rulemaking, Arctic OCS is defined as the Beaufort Sea and Chukchi Sea Planning Areas, as described in the Proposed Final OCS Oil and Gas Leasing Program for 2012-2017 (June 2012), available at www.boem.gov/uploadedFiles/BOEM/Oil_and_Gas_Energy_Program/Leasing/Five_Year_Program/2012-2017_Five_Year_Program/PFP%2012-17.pdf (see pp.21-24). This definition would appear in §§ 250.105, 254.6, and 550.105. As described previously, BOEM and BSEE have determined that these areas are both the subject of current exploration and development interest and subject to conditions that present significant challenges to such operations.
Arctic OCS Conditions
Sections 250.105 and 550.105 would be revised to add a definition for Arctic OCS Conditions. The definition is necessary because these proposed regulations are designed largely around the particular challenges presented by Arctic OCS Conditions. The term Arctic OCS Conditions would be defined to describe both the environmental conditions and functional characteristics (e.g., geographic remoteness, limited infrastructure, subsistence hunting areas) that oil and gas operators can reasonably expect to encounter during exploratory drilling operations and when responding to a loss of well control on the Arctic OCS. Depending on the time of year, relevant environmental conditions and the proposed definition include, but are not limited to, the following: “extreme cold, freezing spray, snow, extended periods of low light, strong winds, dense fog, sea ice, strong currents, and dangerous sea states.” This definition would not affect or alter any other existing Federal regulatory requirements.
It is crucial for OCS oil and gas operators to have a clear understanding of the conditions they would likely encounter during exploratory drilling operations and when responding to a loss of well control on the Arctic OCS. Offshore oil and gas exploration involves inherent risks to human safety and the environment. If not effectively addressed, Arctic OCS Conditions could multiply these risks. Thus, the proposed definition also recognizes that “the Arctic’s remote location, limited infrastructure, and existence of subsistence hunting and fishing areas are also characteristic of the Arctic region” and must be considered to ensure safe operations and minimize impacts to the environment and to other users of the area. Addressing these factors would enable industry to proactively safeguard people, facilities, equipment, and the environment.
B. Additional Regulations Proposed by BOEM
Definitions (§ 550.200)
The acronym “IOP”—meaning Integrated Operations Plan—would be inserted into the proper alphabetical location within existing § 550.200, for purposes of the IOP provisions at proposed § 550.204, as discussed next.
When must I submit my IOP for proposed Arctic exploratory drilling operations and what must the IOP include? (§ 550.204)
This proposed rule would require the operator to develop an IOP for each proposed exploratory drilling program on the Arctic OCS, and to submit the IOP to DOI, through its designee, BOEM, at least 90 days in advance of filing its EP. The IOP would need to describe how the proposed exploratory drilling program would be designed and conducted in an integrated manner suitable for Arctic OCS Conditions and would address each of the information requirements identified in proposed § 550.204. Operators may also choose to address the requirements in §§ 550.211 through 550.228, which could facilitate the later formal review of the operator’s EP. The IOP should be detailed enough to allow DOI, other relevant Federal agencies, and the State of Alaska to:
1. Familiarize themselves with the proposed operations as an integrated project from start to finish; and
2. Provide constructive feedback to the operator concerning the conceptual plans reflected in its IOP.
DOI recognizes that when the IOP is submitted, operators might not possess all the detailed and specific information that may be more readily available later in the planning process; e.g., contracts for vessels may not be finalized, precise dates of drilling may be uncertain, or the exact staging location of assets, such as the relief rig or SCCE, may be unknown. For BOEM’s and BSEE’s purposes, operators would submit more detailed information through the EPs and APDs, as appropriate.
Though BOEM would review the IOP to ensure that the operator’s submission addresses each of the elements listed in § 550.204, the IOP would not require approval by DOI or the other relevant agencies. Instead, the IOP would be an informational document intended to facilitate early review of important concepts related to an operator’s proposed exploratory drilling program. This review would assist DOI and other relevant agencies in developing an understanding of, and familiarity with, the operator’s overall proposed exploratory drilling program early in the planning process.
DOI recognizes that the information requirements of § 550.204 could implicate other Federal agencies’ and the State of Alaska’s statutory and regulatory mandates. For example, the USCG administers laws and regulations governing maritime safety, security, and environmental protection and is also responsible for inspecting the vessels to which those laws and regulations apply. In acknowledging the USCG’s principal jurisdiction over vessel safety and security, DOI has determined that information, early in the process, pertaining to the safety of operations, vessel mobilization, demobilization, and tow plans, is also essential to DOI’s statutory and regulatory responsibilities related to Arctic OCS oil and gas activities. The IOP process is intended to facilitate the sharing of information among the relevant Federal agencies and the State of Alaska and to provide the relevant agencies an early opportunity to engage in a meaningful and constructive dialogue with operators, consistent with the policies articulated in E.O. 13580 (Interagency Working Group on Coordination of Domestic Energy Development and Permitting in Alaska, discussed earlier).
Upon receipt, DOI would engage fellow members of the Working Group and distribute the IOP to other Federal government agencies involved in the review, approval, or oversight of aspects of OCS operations (e.g., BOEM, BSEE, USFWS, USCG, NOAA, and EPA), as well as the State of Alaska. Early engagement by these entities would allow them to become familiar with the operator’s overall proposed exploratory drilling program and could provide a meaningful opportunity to offer early feedback to the operator concerning its proposed activities and any identifiable issues that might affect future permitting decisions. DOI would also encourage the assembly of an interagency coordination team to facilitate and coordinate agency review and feedback. Any feedback could be provided individually by the relevant Federal agencies or the State of Alaska, or collectively through DOI.
BOEM also plans to promptly post each IOP on its Web site. BOEM would not solicit public input on the IOP; instead, the IOP would be informational only, affording the public an early opportunity to view key concepts of a proposed exploratory program. This effort responds to stakeholder concerns that BOEM does not provide the public with sufficient time to participate meaningfully in BOEM’s administrative process for proposed exploratory drilling activities on the Arctic OCS. Typically, the public first becomes aware of an operator’s plans for exploratory drilling when the operator submits its EP. BOEM acknowledges that public review periods for EPs are relatively short in duration. However, this is a result of the OCSLA provision that requires BOEM to approve, disapprove, or require modifications to an EP within 30 days of BOEM deeming the EP submitted (43 U.S.C. 1340(c)(1)), thus placing modification of the length of the review period outside the discretion or authority of the agency absent Congressional action. An early opportunity to view the IOP and the key concepts of the proposed exploratory drilling program, however, will enhance existing public engagement opportunities.
Paragraph (a), Vessels and Equipment
Operators must plan to adapt their exploratory drilling operations to Arctic OCS Conditions. Although generally the equipment for extracting oil and gas from the OCS is the same for the offshore Arctic as anywhere else on the OCS, the equipment might need to be modified, procedures might need to be adjusted, or personnel might need to be specifically trained for work conditions on the Arctic OCS. For example, cranes might need to be modified for operations under ice loading that could be anticipated during Arctic OCS operations, and be de-rated to account for reduced strength in extreme cold temperatures. Accordingly, this provision would require that operators submit, “[i]nformation describing how all vessels and equipment will be designed, built, and/or modified to account for Arctic OCS Conditions” and is designed to ensure that the operator is planning to deploy vessels and equipment capable of operating safely on the Arctic OCS. Operators would need to submit information sufficient to allow DOI and other relevant agencies (e.g., the USCG) to understand the function of each vessel within the proposed fleet of vessels and how the vessels would be capable of performing their identified roles in the proposed exploratory drilling program safely and effectively.
Paragraph (b), Exploratory Drilling Program Schedule
The proposed rule would require the IOP to include an exploratory drilling program schedule of operations including importantly, contractor work on critical components of the program (e.g., inspection and testing of critical equipment such as BOPs or SCCE). Thorough advanced planning regarding the proposed schedule for operations is an important component of the IOP, particularly in light of the limits that returning sea ice can place on the drilling season on the Arctic OCS, and for elements of operations for which operators are relying upon outside contractor deliverables. Furthermore, it is important for BOEM and other relevant agencies to have information regarding how the timing of proposed operations aligns with expected seasonal ice encroachment, as well as how the timing of proposed operations may interact with seasonal marine mammal migrations and subsistence activities, for purposes of understanding the potential environmental impacts. This will help BOEM and other relevant agencies develop an understanding of how the operator proposes to conduct operations safely.
The proposed schedule would need to include, for example, when an operator intends to enter waters overlying the Alaska OCS (including transit time to the proposed drilling site), when drilling is expected to commence and conclude, dates of operations, and when the operator plans to leave the vicinity of drilling operations. The schedule would also need to include the critical dates for completion or activation of components under construction, repair, or storage by outside contractors. This provision would help assure DOI and other relevant agencies that the operator and its contractors have developed a reasonable schedule for executing each phase of the exploration program and are capable of conducting exploratory drilling activities safely in Arctic OCS Conditions.
Paragraph (c), Mobilization and Demobilization
This provision would require operators to include in their IOP a description of their mobilization and demobilization operations, including tow plans suitable for Arctic OCS Conditions, as well as their general maintenance schedules for vessels and equipment. This element is designed to help DOI and other relevant agencies understand the extent to which operators:
1. Have accounted for the conditions likely to be encountered on the Arctic OCS; and
2. Are prepared to handle the substantial environmental challenges and associated operational risks present throughout the mobilization and demobilization of personnel and equipment.
The requested information would facilitate coordination between DOI and the USCG. Similarly, having information about where vessels would come from and go to before and after entering the waters overlying the Alaska OCS would aid, for example, DOI’s and other relevant agencies’ early understanding of potential environmental issues, such as aquatic invasive species that might be carried on vessels.
This provision would also require consideration of how repairs to, and maintenance of, vessels and equipment might affect the larger exploratory drilling program. This information could facilitate DOI’s and other relevant agencies’ understanding of potential environmental considerations and safety aspects of the projected operational schedules.
Paragraph (d), Exploratory Drilling Program Objectives, Timelines, and Contingency Plans
This provision would require operators to include in their IOP a description of their “exploratory drilling program objectives and timelines for each objective, including general plans for abandonment of the well(s)” under a variety of circumstances. This description would help DOI and other relevant agencies familiarize themselves with the operator’s plans for a well-designed, safe operation with clear objectives for employees and contractors that would allow ample flexibility in light of the difficult and variable conditions on the Arctic OCS.
A fully developed exploration program includes, among other things: the operator’s general plan of how many wells it plans to drill in a particular season; the timing and sequence of those operations; locations of the wells; necessary equipment and resources, including information on support vessels; and the operator’s contingency plans in the event that temporary abandonment would become necessary. To the extent that relevant information submitted with the IOP has not changed, the operator could later incorporate that information into its EP. Thorough advanced planning of the operator’s objectives, as well as clear timelines for the accomplishment of each objective, are essential, particularly in light of the limited seasonal drilling window on the Arctic OCS.
Given the uncertainties created by the challenging Arctic OCS Conditions, it is equally essential for an operator to acknowledge and plan for contingencies and delays that might arise. For example, an operator would need to provide general information regarding how it would safely respond to unanticipated ice encroachment at the drill site, including safe and secure temporary abandonment of the well and relocation of the drilling rig, as necessary. DOI would need to be provided with information that explains how the operator has considered these elements of its exploration program, well in advance of operations. Also, if an operator plans to drill multiple wells, DOI must be provided with information regarding the anticipated objectives and timelines for each well. Similarly, an operator would be expected to indicate whether it intends to abandon the well(s) at the end of the season and, if the operator intends to abandon the well, whether such abandonment would be temporary or permanent.
Paragraph (e), Weather and Ice Forecasting and Management
One of the key drivers of this proposed rule is DOI’s need to understand how operators would account for the variable conditions on the Arctic OCS and how those conditions might affect drilling activities. One important component of an operator’s overall program is accounting for adverse weather and ice conditions and developing a plan to respond to those conditions. Consequently, this provision would require operators to describe their weather and ice forecasting capabilities for all phases of the exploration program, including a description of how they would respond to and manage ice hazards and weather events. The challenges presented by Arctic OCS Conditions are not limited to the period of active drilling operations, but would create difficulties throughout all phases of an exploratory drilling program, including mobilization and demobilization. Accordingly, it is important for DOI and other relevant agencies to understand the operator’s plans for implementing ice and weather forecasting and management systems that would be operational around the clock from start to finish.
Paragraph (f), Contractors
This provision would require operators to provide in their IOP a description of work to be performed by contractors supporting their exploratory drilling program (including mobilization and demobilization), how such work would be designed or modified to account for Arctic OCS Conditions, and operators’ strategy for contractor management, oversight, and risk management. This information is designed to help DOI and other relevant agencies understand the operator’s strategies for developing, early in the planning process, a rigorous and effective operational management and oversight system for its contractors that is specifically tailored for operations on the Arctic OCS. Information regarding the nature and timeline of operational elements for which the operator would rely on contractors would aid in a full understanding of the various inputs and contingencies that might affect the planned execution of the proposed operations.
The IOP would need to describe, for example, what types of operations the operator would contract out and how the operator would oversee the contractor to ensure the contractor’s work product would be suitable for Arctic OCS operations. At the IOP stage, the specific names of contractors would not be necessary but could be provided, if known. The focus of this proposed requirement is to facilitate DOI’s and other relevant agencies’ understanding of how the operator plans to rely on contractors and how it plans to manage its contractor relationships in order to ensure safe and responsible drilling operations.
Paragraph (g), Safety
BOEM proposes to require that operators include in their IOP a description of how they “will ensure operational safety while working in Arctic OCS Conditions,” including but not limited to, the safety principles applicable to operators and their contractors, the accountability structure within operators’ organizations for implementing these principles, how operators would communicate these principles to their employees and contractors, and how operators would determine successful implementation of these principles.
The OCSLA provides that all operations taking place on the OCS “should be conducted in a safe manner by well-trained personnel using technology, precautions, and techniques sufficient to prevent or minimize the likelihood of blowouts, loss of well control, fires, spillages, physical obstruction to other users of the waters or subsoil and seabed, or other occurrences which may cause damage to the environment or to property, or endanger life or health” (43 U.S.C. 1332(6)). Also, operators are required to demonstrate through their EPs and APDs that they have planned and are prepared to conduct activities in a manner that conforms to the OCSLA and applicable implementing regulations, and that their activities will be conducted safely (see 43 U.S.C. 1340(c)(1); 30 CFR 250.106, 250.107, 550.202 paragraphs (a) and (b)). The proposed safety information requirement would help DOI and other relevant agencies (e.g., USCG) familiarize themselves with the operator’s early consideration of how its proposed exploratory drilling program would proceed in a safe manner with appropriate caution and respect for the extreme and unpredictable conditions found offshore in the Arctic and would be consistent with DOI’s and other relevant agencies’ safety requirements.
This proposed safety information element is also intended to complement BSEE’s SEMS program by requiring operators to identify and assess, early in the planning stages of their proposed exploratory drilling program, their guiding principles for safe Arctic OCS operations, and optimal strategies for implementing those principles throughout their workforce.
Proposed 30 CFR 550.204(g) would not require an operator to provide the same level of detail, if not available, concerning safety of operations as would be available at the time of the EP and APD, or to duplicate the detail provided in its USCG Safety Management System program or its BSEE SEMS program. Instead, the IOP would need to provide a general understanding of the principles that operators would follow to manage risks to ensure safety of all exploratory drilling activities and personnel vis-à-vis the conditions likely to be encountered on the Arctic OCS. For example, it is reasonably expected that operators would experience freezing spray, extended periods of low light, strong winds, and dense fog during operations. Operators would need to provide a general description of how they would account for these conditions, and any guiding principles they would follow to minimize risk to operations, personnel, vessels, and other equipment.
Paragraph (h), Staging of Oil Spill Response Assets
BOEM proposes to require that operators include in their IOP information regarding their “preparations and plans for staging of oil spill response assets.” This provision would facilitate DOI’s, and other relevant agencies’ (e.g., USCG), early understanding of the potential effects on local communities from staging spill response assets near coastal communities, the safety and environmental implications of plans for mobilization and demobilization of related vessels and equipment, the potential environmental impacts of the vessels staged in the area for response, and anticipated response times based on where the equipment will be located. This information would be especially relevant to the USCG, which is the Federal On Scene Coordinator responsible for developing the North Slope Sub-Area Contingency Plan for Oil and Hazardous Substances Discharges/Releases. The USCG and all appropriate governmental entities at the State and local levels would have an early understanding of the proposed activities.
Paragraph (i), Impact of Exploratory Drilling on Local Community Infrastructure
BOEM proposes to require that operators include in their IOP, a description of their “efforts to minimize impacts of [their] exploratory drilling operations on local community infrastructure, including but not limited to housing, energy supplies, and services.” This provision would facilitate DOI’s and other relevant agencies’ early understanding of the potential socioeconomic implications of the proposed exploratory drilling program, including the extent to which the proposed activities might strain the limited infrastructure of coastal communities in the Arctic, or reduce the availability of housing, energy, food, and health care to local communities through increased demand and higher costs caused by the presence of persons supporting the exploratory drilling program.
Paragraph (j), Local Community Workforce and Response Capacity
BOEM proposes to require that operators include in their IOP “[a] description of whether and to what extent your project will rely on local community workforce and spill cleanup response capacity.” This provision would encourage operators to engage in early planning toward providing local communities, which would incur the greatest risk of offshore exploration activities, with the capacity—both in terms of training and resources—to protect their communities and important subsistence use areas. It is intended to provide DOI and other relevant agencies with early insight into whether the proposed operations are being planned safely, with appropriate environmental safeguards and respect for the other users of area resources. This provision would also allow DOI to develop an early understanding of industry’s efforts to promote local communities’ ability to participate in and obtain benefit from future Arctic OCS oil and gas development.
How do I submit the IOP, EP, DPP, or DOCD? (§ 550.206)
DOI recognizes that operators may consider some of the information required by proposed § 550.204 to be proprietary or commercial in nature. Pursuant to the proposed revisions to § 550.206, operators would be able to request the nondisclosure of this information using established DOI processes. As is currently the case with EPs, Development and Production Plans (DPPs), and Development Operations Coordination Documents (DOCDs), operators requesting the nondisclosure of portions of an IOP should provide BOEM with two separate versions of the IOP; a public version from which potentially exempt information is redacted, and a
If I propose activities in the Alaska OCS Region, what planning information must accompany the EP? (§ 550.220)
As described previously, drilling operations, especially on the Arctic OCS, can be complex, and operators may face substantial environmental challenges and operational risks throughout every phase of the endeavor. One of the main goals of this rulemaking is to ensure, through thorough advanced planning, that operators are capable of operating safely in the extreme and challenging Arctic OCS Conditions.
BOEM first proposes to amend the existing “Emergency Plans” provision at § 550.220(a) to add fire, explosion, and personnel evacuation to the events for which emergency plans are required, and to replace the terms “blowout” with “loss of well control” and “craft” with “vessel, offshore vehicle, or aircraft” for clarification purposes.
BOEM next proposes to create a new § 550.220(c), which would set forth additional information requirements for EPs that are proposing exploration activities on the Arctic OCS. BOEM proposes to add a new performance-based provision at § 550.220(c)(1) that would require an operator to describe how its proposed activities would be designed and conducted in a manner suitable for Arctic OCS Conditions and how these activities would be managed and overseen as an integrated endeavor. This description may be summarized from the operator’s IOP or, if appropriate, updated with any information not available at the time of the IOP.
BOEM also proposes to add § 550.220(c)(2), which would require operators to include, as part of their EP submissions, more detailed and updated information concerning their weather and ice forecasting and management plans for all phases of their exploratory drilling activities, including: a description of how they would respond to and manage ice hazards and weather events; their ice and weather alert procedures; their procedures and thresholds for activating their ice and weather management systems; and confirmation that their ice and weather management and alert systems would be operated continuously throughout the planned operations. As described previously, DOI needs to be certain that adequate forecasting equipment and procedures are in place to predict and follow developing weather and ice conditions that might pose a risk to operations. Also, it is essential that operators develop and describe their pre-established thresholds for triggering varying levels of responsive actions in the face of weather and ice threats, as well as the procedures and equipment necessary to respond to these hazards. Furthermore, operators need to demonstrate that they would be capable of responding to and managing these conditions to prevent or minimize the risks associated with ice and adverse weather.
BOEM next proposes to require preliminary information concerning SCCE capabilities, deployment of a relief well rig, and sharing of SCCE and spill response and cleanup assets. The proposed informational requirements concerning SCCE and relief well rigs relate to the operator’s preliminary plans for complying with BSEE’s proposed regulations at 30 CFR 250.471 and 250.472, which will be described later.
Requiring information about how an operator intends to satisfy the proposed BSEE regulations at proposed 30 CFR 250.471 and 250.472 would allow consideration of these issues at an early planning stage, and would further inform BOEM’s review of proposed EPs under § 550.202, and other applicable laws. It would likewise reduce the risk of discrepancy between reviews and approvals conducted at the EP stage and an operator’s later-submitted APD. While BOEM anticipates that elements of the SCCE description required by proposed § 550.220(c)(3) and the relief well rig description required by proposed § 550.220(c)(4) may be general at the EP stage, they must be detailed enough for BOEM to confirm that the operator would have plans in place for how it would conduct its operations safely, in conformance with applicable regulations. The description would also need to be detailed enough to enable BOEM to evaluate the potential environmental implications of proposed SCCE and relief well rig staging and operations. Proposed § 550.220(c)(4) would set forth some of the information expected to be available about the relief well rig when the EP is submitted.
The proposed § 550.220(c)(5) provision would add an informational requirement concerning any agreements the operator might have with third parties for the sharing of assets (e.g., SCCE, relief rigs, and oil spill response resources) and/or any agreements to assist each other in response and cleanup efforts in the event of a loss of well control or other emergency. A cooperative, consortium-based model should offer:
1. Logistical, operational, and commercial efficiencies;
2. Less duplication of personnel and equipment;
3. Reduced monetary cost of exploration;
4. Reduced environmental footprint;
5. Reduced social costs and interference with other users of the OCS; and
6. A coordinated response and cleanup effort in the event of a loss of well control.
BOEM’s environmental impact analyses have repeatedly shown that the presence of vessels, aircraft, and other equipment within the Arctic region could result in adverse impacts to subsistence activities and to environmental resources (e.g., noise impacts on marine mammals, increased risk of bird or marine mammal collisions, increased risk of fuel spills, and increased air emissions). The potential effects would be compounded if multiple operators—each fielding its own fleet of drilling, resupply, and emergency response vessels—were to engage in activities simultaneously. Avoiding duplication of relief well rigs, oil spill response assets, and other emergency response vessels and equipment would be an effective means to minimize environmental and social impacts.
BOEM and BSEE strongly encourage operators proposing exploratory drilling activities on the Arctic OCS to enter into mutual aid agreements for the sharing of vessels, relief well rigs, and other assets or services associated with responding to an oil spill or other emergency. Notice of these arrangements would inform BOEM’s and BSEE’s safety and environmental review of proposed activities to ensure operators are fully prepared to respond to a loss of well control. Also, BOEM and BSEE expect that operators, when planning a response to a loss of well control, would ensure that an effective and immediate removal, mitigation, or prevention of a discharge could be achieved, to the greatest extent practicable, using private sector capability.
Finally, proposed § 550.220(c)(6) would add an informational requirement concerning the conclusion of on-site operations at the end of the season. An operator would include a projected date, and information used to determine the date, when on-site operations would be completed based on ice conditions that will likely exist in the relevant operational area (using current Federal ice and weather forecasts or other reliable forecasting systems). An operator would also provide a projected date, and supporting information, on when the operator would stop drilling operations into zones capable of flowing liquid hydrocarbons to the surface. That date would need to be consistent with the relief rig planning requirements under proposed 30 CFR 250.472 and with the estimated timeframe for deployment of a relief rig under proposed § 550.220(c)(4).
There is no single, definitive “end of drilling season” in the Arctic OCS. The projected end-of-season dates in any specific EP should be based on a variety of factors, including the operator’s equipment, procedures, and capability to effective ly manage and mitigate risk that are reasonably likely to occur. Other factors include, but are not limited to, the prevailing meteorologic and oceanic conditions, which vary from year to year, and the location of proposed drilling. For example, in a year when the encroachment of sea ice is projected to occur later, an operator may be able to justify a later end of season and avoid the need to cease drilling operations earlier than necessary. By contrast, in a year when the onset of sea ice is projected to occur earlier, the operator would need to plan to conclude on-site operations earlier.
In projecting when to conclude on-site operations, BOEM and BSEE expect operators to be flexible and fully responsive to the latest ice and weather forecasts and the best available information for ensuring optimal timing for the end of on-site operations. Of course, after an EP is approved, an operator may request approval to revise its EP if available information regarding its operations and anticipated meteorologic and oceanic conditions change.
For example, BOEM’s approval for Shell’s 2012 Arctic operations required drilling operations in zones where measurable quantities of liquid hydrocarbons were capable of flowing into the well to be concluded 38 days prior to November 1, based on satellite imagery showing the five-year historical average of earliest sea ice encroachment over Shell’s drill site and estimates of the time needed to drill a relief well. The purpose of this drilling hiatus was to reduce project risk by assuring a greater opportunity for response and cleanup in the unlikely event of a late season oil spill.
BOEM and BSEE invite comments on what kinds of Arctic weather and ice forecasting options are currently (or expected to be) available for use by operators. In addition, comments may address other factors that should be considered in determining when on-site operations are expected to be completed, or when drilling into certain hydrocarbon zones should cease each year, given an operator’s response and cleanup capabilities.
C. Additional Regulations Proposed by BSEE
The authority citation for 30 CFR part 250 would be amended to add reference to 33 U.S.C. 1321(j)(1)(C). This statutory provision, in addition to section 5 of the OCSLA (43 U.S.C. 1334), provides authority to DOI for the portions of the proposed revisions to § 250.300 related to preventing discharge of petroleum-based mud and cuttings from operations that use petroleum-based mud. For further explanation of those provisions, see the discussion under that section.
Definitions (§ 250.105)
This section would be revised to add definitions for Arctic OCS, Arctic OCS Conditions,
Cap and Flow System, Capping Stack, Containment Dome, and Source Control and Containment Equipment. For an explanation of the definitions of Arctic OCS and Arctic OCS Conditions, see the discussion of definitions at the beginning of the Section-by-Section analysis. The remaining definitions are necessary because these proposed regulations would require the defined systems and equipment under identified circumstances. In addition, the definition of District Manager would be revised for activities on the Alaska OCS such that District Manager would mean Regional Supervisor, because the Regional Supervisor in BSEE’s Alaska OCS region performs the District Manager’s duties.
Cap and Flow System—this term would be defined to mean an integrated suite of equipment and vessels, including a capping stack and associated flow lines, that, when installed or positioned, is used to control the flow of fluids escaping from the well by conveying the fluids to the surface to a vessel or facility equipped to process the flow of oil, gas, and water. A cap and flow system is a high pressure system that includes the capping stack and piping necessary to convey the flowing fluids through the choke manifold to the surface equipment. When a responsible party has been able to successfully cap a well, but conditions will not allow the well to be shut in (e.g., due to damage, equipment failure or pressure constraints), the cap and flow system allows the well cap to be used as a connection for the flow lines that transport well fluids to the surface for capture and disposition. In some circumstances, this can relieve the pressure on the capping device or tubulars at the well head or in the well while maintaining or reestablishing control of the produced fluids, or a portion thereof.
Capping Stack—this term would be defined to mean a mechanical device that can be installed on top of a subsea or surface wellhead or BOP to stop the flow of fluids into the environment. A capping stack’s primary function is to stop the uncontrolled flow of fluids from a well to the environment in the event that other intervention methods, such as a BOP, would fail. The capping stack is attached to a connector or pipe stub located on or in the well to achieve a pressure-tight seal that would either stop the flow or direct it into a conduit that would transmit the fluids to a surface facility that is able to store, process, or properly dispose of the fluids. Capping stacks may be deployed from the surface to the well head, as needed, or prepositioned below the riser system when the BOP is located on the deck of a MODU. The pre-positioned capping stack may be created by adapting an auxiliary subsea intervention device to meet the requirements of this proposed rule.
Containment Dome—this term would be defined to mean a non-pressurized container that can be used to collect fluids escaping from the well or equipment below the sea surface or from seeps by suspending the device over the discharge or seep location. A containment dome, also known as a “sombrero,” “cofferdam,” or “hat,” captures fluids after they have escaped the well, subsea equipment, or a seep, but before they have reached the surface. It consists of a structure that has the ability to capture fluids rising through the water column and to convey the fluids to a surface vessel or facility for processing or disposal. If a cap and flow system is unable to stop or control the flow of fluids to the environment, or the well system is so damaged that a capping stack cannot make a successful connection, the containment dome system would be needed to capture the hydrocarbons flowing to the environment.
Source Control and Containment Equipment (SCCE)—SCCE would be defined to mean 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 being discharged into the environment for proper processing or disposal. This definition is useful for referring collectively to the various independent elements of an operator’s SCCE in portions of the proposed rule that would apply to any such equipment and its capabilities as a unified system, rather than a specific type of SCCE (see, e.g., proposed § 250.470(f)). The SCCE serves the purpose of stopping or minimizing the flow of hydrocarbons into the environment after a loss of well control event has occurred. The term “surface devices” within the definition of SCCE refers to equipment mounted or staged on a barge, vessel, or facility. The purpose of this equipment is to separate, treat, store and/or dispose of fluids conveyed to the surface by the cap and flow system or the containment dome. The SCCE, however, does not include a BOP or similar equipment that is used in ordinary operations and functions to maintain well control under normal operational conditions or to prevent a loss of well control. Finally, “subsea devices” includes, but is not limited to, remotely operated vehicles (ROV), anchors, buoyancy equipment, connectors, cameras, controls and other subsea equipment necessary to facilitate the deployment, operation and retrieval of the SCCE.
What incidents must I report to BSEE and when must I report them? (§ 250.188)
The current regulation requires operators to provide oral and written notification to the BSEE District Manager (who in the Alaska OCS region is the Regional Supervisor) of, among other things, any injuries, fatalities, losses of well control, fires and explosions, and incidents affecting operations. BSEE proposes to add a new paragraph (c) to this section that would require operators on the Arctic OCS to provide an immediate oral report to the BSEE onsite inspector, if one is present, or to the Regional Supervisor of any sea ice movement or condition that has the potential to affect operations or trigger ice management activities, as well as the start and termination of these activities, and any “kicks” or operational issues that are unexpected and could result in the loss of well control.
Sea ice, if not properly managed, can have a major effect on exploratory drilling operations. Spring and summer thawing can produce large ice masses on the waters overlying the Arctic OCS, which could cause substantial damage to exploratory drilling equipment and render operations unsafe, leading to injury, loss of life, or environmental harm. For example, if the well is not properly protected, sea ice that is moving through the surrounding water could cause a loss of well control by damaging the well head and triggering the discharge of hydrocarbons into the marine environment. Ice management activities, as described in an operator’s ice management plan, could include physically changing the direction of an ice floe or using ice breaking techniques in order to minimize the likelihood of damage to the exploratory drilling equipment.
It is essential for operators to remain in close communication with BSEE about sea ice in the area that has the potential to affect operations. Just as the operator needs to have sufficient time to act in the event that ice poses an operational hazard, BSEE would need sufficient time to oversee the safety of an operator’s reactions and prepare to respond if a response is necessary due to a safety or environmental incident resulting from an ice event.
The proposed paragraph (c) would require the operator to immediately notify the BSEE inspector on location or the Regional Supervisor of any event that, pursuant to the hazard thresholds identified in its EP, would trigger a heightened observation requirement, or could potentially result in the need to physically manage ice, initiate operations to secure the well, or move the drilling rig to avoid a threat caused by floating ice. This provision would also require immediate oral notification of the commencement and completion of any ice management activities.
The oral report required by this provision could be a simple direct oral notification of the basic facts surrounding the relevant circumstances, and would not need to contain all of the detail required of oral reports pursuant to § 250.189. The proposed provision would also require a follow-up written report regarding any ice management activities undertaken by the operator that must be submitted within 24 hours following completion of those activities.
BSEE proposes this tighter 24-hour timeline (as opposed to, and in lieu of, the standard 15 day window under § 250.190) due to the immediacy of the threats and concerns presented by circumstances requiring ice management activities, and the need for BSEE to remain abreast of those events in its regulatory and safety oversight role. The written report may be submitted via email or other electronic means to the inspector or Regional Supervisor and must conform to the content requirements set forth in § 250.190.
Finally, BSEE proposes to require that operators submit an immediate oral report of any “kicks” or operational issues that are unexpected and could result in the loss of well control. Operators on the Alaska OCS currently have to report kicks at the end of every day on the well activity report Form BSEE-0133, as required by § 250.468. However, the proposed requirements of this section mean operators would not be allowed to wait until the end of the day or some time later to fill out a form. If a kick occurred, they would have to provide an immediate oral report. The nature of Arctic OCS Conditions, as defined in this proposed rule, demonstrates that responding to a spill in the Arctic region would be a difficult task. Reporting kicks right away is a safety measure that can improve the ability of both inspectors and operators to potentially prevent a loss of well control.
Documents incorporated by reference. (§ 250.198)
The proposed rule would add subsection (h)(89) to existing § 250.198 as a reference to the American Petroleum Institute (API) proposed draft Recommended Practice (RP) 2N, Recommended Practice for Planning, Designing, and Constructing Structures and Pipelines for Arctic Conditions, Third Edition. This document will be a voluntary consensus standard addressing the unique Arctic OCS Conditions that affect the planning, design, and construction of systems used in Arctic and sub-Arctic environments. This API document—which is virtually identical to a standard previously issued by the International Organization for Standardization (ISO), “Petroleum and Natural Gas Industries Arctic Offshore Structures,” First Edition (2010) (ISO 19906)—would be appropriate for certain aspects of drilling operations, such as accounting for the severe weather and thermal effects on structures, maintenance procedures, and safety. Since this proposed rule is focused on the exploratory drilling phase of operations on the Arctic OCS, certain portions of API RP 2N, Third Edition (such as those related to issues regarding structural and pipeline integrity) would not be relevant to the exploration stage. However, many elements of that document, when published, could be effectively applied to equipment used in exploratory drilling operations on the Arctic OCS. Therefore, proposed §§ 250.198(h)(89) and 250.470(g) would incorporate appropriate elements of API RP 2N, Third Edition, for purposes of APD information requirements.
A voluntary consensus standard indicates acceptance and recognition across the industry that certain technology is feasible. For example, API standards are created with input from oil and gas operators, drilling contractors, service companies, consultants, and regulators. Even though the development of a consensus standard does not necessarily represent a unanimous agreement by the developing body’s members, the API process provides a means for industry and regulatory bodies to provide input into the development of protocols for the highly specialized equipment and procedures used in oil and gas operations. In the National Technology Transfer and Advancement Act of 1995 (Pub. L. 104-113, 15 U.S.C. 3701 note), Congress directed Federal agencies to use technical standards that are developed or adopted by voluntary consensus standards bodies in lieu of government-unique standards, unless inconsistent with applicable law or otherwise impractical (see OMB Circular A-119 (Revised), February 1998, available at www.standards.gov/standards_gov/nttaa.cfm).
BSEE frequently uses standards (e.g., codes, specifications, RPs) developed through a consensus process, facilitated by standards development organizations and with input from the oil and gas industry, as a means of establishing requirements for activities on the OCS. BSEE may incorporate these standards into its final regulations without publishing the standards in their entirety in the Code of Federal Regulations, a practice known as incorporation by reference. The legal effect of incorporation by reference is that the incorporated standards become regulatory requirements. Material incorporated in a final rule, like any other properly issued regulation, has the force and effect of law, and BSEE holds operators, lessees and other regulated parties accountable for complying with the documents incorporated by reference in its final regulations. BSEE currently incorporates by reference over 100 consensus standards in its offshore regulations governing oil and gas operations (see 30 CFR 250.198).
Federal regulations at 1 CFR part 51 govern how BSEE and other Federal agencies incorporate various documents by reference. Agencies may only incorporate a document by reference in a final rule by publishing the document title, edition, date, author, publisher, identification number and other specified information in the Federal Register. The Director of the Federal Register must approve each publication incorporated by reference in a final rule. Incorporation by reference of a document or publication in a final rule is limited to the specific edition approved by the Director of the Federal Register.
Availability of Incorporated Documents for Public Viewing
When a copyrighted industry standard is incorporated by reference into our regulations, BSEE is obligated to observe and protect that copyright. We typically provide members of the public with Web site addresses where these standards may be accessed for viewing—sometimes for free and sometimes for a fee. The decision to charge a fee is made by each standards development organization. The API provides free online public access to at least 160 key industry standards, including a broad range of technical standards. Those standards represent almost one-third of all API standards and include all that are safety-related or are incorporated into Federal regulations. These standards are available for review, and hard copies and printable versions will continue to be available for purchase through API. BSEE proposes to incorporate, with certain exclusions discussed later in this proposed rule, draft proposed API RP 2N, Third Edition, which is available for free public viewing during the API balloting process on API’s Web site at http://mycommittees.api.org/standards/ecs/sc2/default.aspx (click on the title of the document to open). When finalized by API, that standard will be available for free public viewing on API’s Web site at: http://publications.api.org.
In addition, as explained later in this proposed rule, BSEE is considering incorporating by reference ISO 19906 in lieu of API RP 2N, Third Edition. ISO standards are available for purchase from ISO at ISO’s publications Web site at: http://www.iso.org/iso/home/store/catalogue_ics.htm or from commercial vendors.
For the convenience of the viewing public who may not wish to purchase or view incorporated documents online, they may be inspected, upon request, at our office, 381 Elden Street, Room 3313, Herndon, Virginia 20170 (phone: 703-787-1587); or at the National Archives and Records Administration (NARA). For information on the availability of materials at NARA, call 202-741-6030, or go to: www.archives.gov/federal-register/cfr/ibr-locations.html.
If API RP 2N, Third Edition, is incorporated into the final rule, it would continue to be made available for public viewing, when requested, at the addresses indicated in the prior paragraph. Specific information on where incorporated documents can be inspected or obtained is also found at § 250.198, Documents incorporated by reference.
Pollution prevention. (§ 250.300)
This section would revise BSEE’s pollution prevention regulation as it pertains to Arctic OCS exploratory drilling operations. Spent mud and cuttings are generated during exploratory drilling. Drilling mud may be entirely water-based or may include petroleum (i.e., oil) as a component. Cuttings generated using petroleum-based mud would be oil-contaminated, and the discharge of the mud or cuttings into the environment would result in discharge of that oil into the environment. The proposed rule would add provisions in paragraphs (b)(1) and (b)(2) requiring that, during exploratory drilling operations on the Arctic OCS, the operator must capture all petroleum-based mud, and associated cuttings from operations that use petroleum-based mud, to prevent their discharge into the marine environment. These subparagraphs would also clarify the Regional Supervisor’s discretionary authority to require operators to also capture all water-based mud and associated cuttings from Arctic OCS exploratory drilling operations (after completion of the hole for the conductor casing) to prevent their discharge into the marine environment, based on factors including, but not limited to:
1. The proximity of the exploratory drilling operations to subsistence hunting and fishing locations;
2. The extent to which discharged mud or cuttings may cause marine mammals to alter their migratory patterns in a manner that interferes with subsistence activities; or
3. The extent to which discharged mud or cuttings may adversely affect marine mammals, fish, or their habitat.
BSEE regulates discharges of mud and cuttings from OCS facilities under the OCSLA, which contemplates the imposition of environmental safeguards for oil and gas activities on the OCS and mandates that they be conducted in a manner that prevents or minimizes the likelihood of damage to the environment. The President has also delegated authority to the Secretary (further delegated to BSEE) to regulate discharges of oil under Section 311 of the CWA, 33 U.S.C. 1321, which calls for the issuance of regulations establishing procedures, methods, and equipment to prevent discharges of oil and hazardous substances from offshore facilities, and to contain such discharges. BSEE’s pollution prevention regulations are intended to complement requirements imposed by the EPA under the CWA. For example, in November 2012, the EPA issued general National Pollutant Discharge Elimination System (NPDES) permits authorizing certain discharges from oil and gas exploratory facilities to Federal waters in the Beaufort Sea and the Chukchi Sea, including certain discharges of water-based drilling fluids and drill cuttings, subject to effluent limitations and other requirements. Of note, the EPA NPDES permits do not allow the discharge of oil-based drilling fluids, or the discharge of water-based drilling fluids and drill cuttings during the fall bowhead whale hunt in the Beaufort Sea. BSEE’s proposed regulations clarify the Regional Supervisor’s authority to impose operational measures that complement EPA’s discharge limitations by considering potential impacts to specific components of the Arctic environment, such as subsistence activities, marine resources, and coastal areas.
The discharge of mud and cuttings has the potential to affect marine mammals, fish, and their habitat, as well as subsistence activities present in the Arctic region. As noted earlier, subsistence hunting is central to the food supply and cultural traditions of many Alaska Natives. BSEE proposes to clarify its authority to limit discharges of any mud and cuttings having the potential to adversely impact marine wildlife or to disrupt subsistence hunting activities.
For example, existing environmental analyses show that the release of drill cuttings and drilling mud would result in increased turbidity and concentrations of total suspended solids in the water column, which could displace marine mammals from the drill sites and could adversely affect habitat and prey within and around the drill site (see Shell Gulf of Mexico, Inc.’s Revised Chukchi Sea Exploration Plan Burger Prospect Environmental Assessment (2011)). In addition, subsistence hunters, who rely on traditional ecological knowledge, have expressed concern to BOEM and BSEE that whales are capable of detecting the odors from mud and cuttings and will avoid areas where these discharges occur, resulting in similar effects. Hunting farther away from shore to find displaced whales can increase transit time, reduce the likelihood of successful harvests, increase exposure to adverse weather and dangerous sea states, and increase safety concerns for subsistence hunters. Finally, the farther away whales are harvested from a community, the greater the length of towing time necessary to bring the animals back to shore for processing. This increased tow time could negatively affect the viability of the meat and blubber for food because of spoilage.
Marine mammal migrations and subsistence hunting patterns vary greatly in different areas of the Arctic region and at different times of the year. These proposed rules would therefore clarify the Regional Supervisor’s discretion to require the capture of water-based mud and cuttings, taking into account location- and season-specific circumstances (such as subsistence hunting). In addition, other relevant circumstances, such as applicable provisions of a NPDES general permit, can be considered when exercising that discretionary authority. BSEE invites comments on the potential costs to the industry of limiting or prohibiting the discharge of mud and cuttings that otherwise would not be prohibited by the NPDES general permits.
When and how must I secure a well? (§ 250.402)
The current regulation requires, among other things, that operators install a downhole safety device at an appropriate depth whenever there is an interruption in drilling operations. BSEE proposes to add a new paragraph (c)(1), which would require exploratory drilling operators on the Arctic OCS to ensure that any equipment left on, near, or in a temporarily abandoned well that has penetrated below the surface casing be secured in a way that would protect the well head and prevent or minimize the likelihood of the integrity of the well or plugs being compromised. The primary concern this proposed language is designed to address is the possibility that ice floes could sever, dislodge, or drag any exploration-related equipment, obstructions or protrusions left on the well or the adjacent seafloor. The proposed language, however, is drafted to encompass damage from any foreseeable source. The provision in paragraph (c)(1) is designed to be performance-based, would allow operators to devise optimal strategies for identifying and accounting for threats to the integrity of equipment left on the OCS, and would be limited only to exploration wells that have penetrated below the surface casing. However, for exploration wells located in an area subject to ice scour, based on a shallow hazards survey, proposed paragraph (c)(2) would require a mudline cellar or equivalent means of protection. The BSEE Regional Supervisor will evaluate, during the APD process, whether a proposed equivalent approach is sufficiently protective.
There are a number of problems that could occur if operators did not adhere to this proposed requirement. For example, if an ice floe were to contact equipment left on, near, or in a well that had penetrated hydrocarbons, the impact could damage the well and potentially compromise the cement, casing, or safety valves and plugs inside the well and could result in the discharge of hydrocarbons.
What additional information must I submit with my APD? (§ 250.418)
BSEE proposes to add a new paragraph (k) to this section, providing that the information identified in proposed § 250.470 must be submitted with an APD for exploratory drilling on the Arctic OCS. The information required in the proposed section would be necessary to inform BSEE’s evaluation of APDs for Arctic OCS exploratory drilling operations (see discussion of proposed § 250.470).
When must I pressure test the BOP system? (§ 250.447)
The current regulation requires operators to pressure test a BOP system when it is installed, at specified time intervals, and prior to drilling out each string of casing or a liner. BSEE proposes to revise paragraph (b) of this section to require a BOP pressure test frequency of one test every 7 days for Arctic OCS exploratory drilling operations. However, there is some debate over whether more frequent testing, beyond the 14-day test frequency prescribed by existing regulations, would be necessary or advisable.
The effectiveness of hydrostatic pressure testing of BOPs has been questioned in the past. The industry has argued that increasing the number of pressure tests: (1) may reduce the reliability of the equipment by degrading the sealing capability of the elements within the BOP stack; and (2) does not necessarily demonstrate the future performance of the equipment. Furthermore, the industry has claimed that the requirement for operators to stop drilling operations to perform a pressure test could ultimately increase the likelihood of an incident occurring. Due to these safety and cost concerns, the industry has sought to reduce the current testing frequency for this equipment (i.e., to longer than every 14 days).
Ensuring the proper functioning of a BOP, which is a critical line of defense against loss of well control, is essential to Arctic OCS drilling operations. BSEE is concerned that the integrity of BOPs could be compromised by Arctic conditions; in particular, BSEE is concerned about the possible effects of extreme weather conditions on BOPs maintained on surface vessels or facilities (such as jackup rigs). At this time, pressure tests and functional tests are the primary methods for ensuring the performance of BOPs. A 7-day BOP testing cycle was proposed by Shell in 2012, and ultimately approved by BSEE, and we propose to require a similar testing frequency for all Arctic OCS exploratory drilling operations. BSEE specifically requests comments on the appropriateness of the proposed 7-day testing frequency to demonstrate the reliability of the equipment under Arctic conditions. BSEE also requests that commenters identify any additional safety issues that might arise from this increased testing and that would be unique to Arctic operations. In addition, BSEE invites comments on all potential drilling impacts related to the proposed 7-day testing frequency.
Note that the only proposed changes to the existing BOP testing regulation are the phrases specific to exploratory drilling on the Arctic OCS. The remaining language is identical to the wording currently at § 250.447(b) and is duplicated in this proposed rule for readability.
What are the real-time monitoring requirements for Arctic OCS exploratory drilling operations? (§ 250.452)
BSEE proposes to add a new performance-based section in Part 250 that would require real-time data gathering on the BOP control system, the fluid handling systems on the rig, and, if a downhole sensing system is installed, the well’s downhole conditions during Arctic OCS exploratory drilling operations. In addition, this section would require operators to transmit immediately the data during operations to an onshore location, identified to BSEE prior to well operations, where it must be stored and monitored by personnel who would be capable of interpreting the data and have the authority, in consultation with rig personnel, to initiate any necessary action in response to abnormal events or data. Such personnel must also have the capability for continuous and reliable contact with rig personnel, to ensure the ability to communicate information or instructions between the rig and onshore facility in real-time, while operations are underway.
This section would be added, in part, based on multiple recommendations from various Deepwater Horizon investigation reports. Having the real-time, well-related data available to onshore personnel would increase the level of oversight of well conditions during 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 that might arise during operations. This section would also require that the real-time monitoring data be available to BSEE upon request, to enable BSEE to perform its oversight role and to monitor responses to events as they unfold. Finally, this section would, consistent with §§ 250.466 and 250.467, require that the data gathered be stored at a designated location for recordkeeping purposes after operations have concluded, to enable BSEE to perform audits, investigations, or other types of analyses, as part of its regulatory oversight functions.
The following undesignated centered heading would be inserted above proposed § 250.470:
Additional Arctic OCS Requirements
What additional information must I submit with my APD for Arctic OCS exploratory drilling operations? (§ 250.470)
BSEE proposes to add § 250.470, which would require operators to provide Arctic OCS-specific information with their APDs for exploratory drilling. The proposed informational requirements in the new section would be necessary to inform BSEE’s evaluation of APDs for Arctic OCS exploratory drilling operations.
Paragraph (a), Fitness for Service
This provision would require operators to submit a detailed description of the environmental, meteorologic and oceanic conditions expected at the well site(s); how their equipment, materials, and drilling unit will be prepared for service in the conditions, and how the drilling unit will be in compliance with the requirements of § 250.417. For this proposed requirement, BSEE would expect the operator to identify the specific drilling units proposed for use during its operations, verify that the identified equipment and materials are fit for service, and that the drilling units conform to the fitness for service requirements of § 250.417. It is important that operators provide this level of detail to ensure that the equipment, materials, and drilling units proposed for use in Arctic OCS exploratory drilling are capable of performing their respective tasks under Arctic OCS Conditions.
The information requested by this proposed section for drilling units is not in addition to the requirements of § 250.417, but rather is designed to make clear that, to satisfy the fitness requirements of § 250.417, operators would need to provide details regarding Alaska OCS Conditions. Further, BSEE does not currently have an existing provision for drilling equipment and materials that requires the same level of detail found in § 250.417 for drilling units.
BSEE’s current regulations concerning fitness for other types of equipment and material are more general and performance-based than the requirements proposed in this rule for Arctic OCS operations. Additionally, since SCCE is a new suite of equipment and materials proposed by this rule, there are no existing fitness for service regulations covering these items. Therefore, the information required under proposed paragraph (a) for equipment and materials would be new.
Paragraph (b), Well-specific Transition Operations
This provision would require operators to submit “[a] detailed description of all operations necessary in Arctic OCS Conditions to transition the rig from being under way to conducting drilling operations and from ending drilling operations to being under way, as well as any anticipated repair and maintenance plans for the drilling unit and equipment.” BSEE does not intend for this provision to require operators to resubmit any information already submitted to BOEM. Rather, BSEE would expect operators to have a fairly detailed plan when they submit their APD, including information such as the identity of equipment and vessels to be used, dates of planned operations, and a description of how the equipment and vessels would be designed for and be capable of performing in Arctic OCS Conditions. For transition operations, BSEE would need details about all of the activities necessary to begin and end drilling operations, and to move from one drilling location to the next. Examples of the types of activities BSEE would expect an operator to describe include, but are not limited to: recovering the subsea equipment, including the marine riser and the lower marine riser package; recovering the BOP; recovering the auxiliary sub-sea controls and template; laying down the drill pipe and securing the drill pipe and marine riser; securing the drilling equipment; transferring the fluids for transport or disposal; securing ancillary equipment like the draw works and lines; refueling or transferring fuel; offloading waste; recovering the ROVs; picking up the oil spill prevention booms and equipment; and offloading the drilling crew.
Finally, BSEE would require information regarding any specific repair and maintenance plans for the drilling unit and equipment associated with commencement or completion of drilling operations. All of the required information would facilitate BSEE’s understanding of an operator’s program and ensure that the operator complies with lease stipulations, EP conditions, and other permitting requirements.
Paragraph (c), Well-specific Drilling Objectives and Contingency Plans
This provision would require operators to submit “[w]ell-specific drilling objectives, timelines, and updated contingency plans for temporary abandonment of the well.” Whereas the corresponding provisions of the proposed IOP and current EP regulations (e.g., § 550.211) relate more broadly to the objectives and timelines of the overall proposed exploratory drilling activities, this provision would require an operator to provide “well-specific” information at the APD stage. This information would include the operator’s detailed schedule of the following:
1. When they will spud the particular well (i.e., begin drilling operations at the well site) identified in the APD;
2. How long will it take to drill the well;
3. Anticipated depths and geologic targets, with timelines;
4. When the operator expects to set and cement each string of casing;
5. When and how the operator would log the well;
6. The operator’s plans to test the well;
7. When and how the operator would abandon the well, including specifically addressing plans for how to move the rig off location and how the operator would meet the requirements of proposed § 250.402(c);
8. A description of what equipment and vessels would be involved in the process of temporarily abandoning the well due to ice; and
9. An explanation of how these elements would be integrated into the operator’s overall program.
Examples of the information the operator would be required to provide include, but are not limited to: the location(s) to which the rig would be moved; the operator’s plans for safely securing the well prior to leaving the drill site; how temporary abandonment would affect the operator’s seasonal drilling plans, including its remaining schedule of operations at each well; and how crew logistics, such as transportation to and from a drilling rig, would be affected.
It should be noted that the contingency plans proposed in this section of the rule are different from the contingency plans required for “icing or ice-loading” under existing § 250.417(c)(2). That phrase refers to ice build-up on the vessel or equipment itself, whereas the focus of proposed § 250.470(c) is on ice management, meaning the contingency plans for response to the presence of ice in the water, such as temporary abandonment of a well until the ice in the water passes, or management through some other technique. For oil and gas exploration, ice management is an Arctic OCS-specific issue that does not occur elsewhere on the OCS. However, icing and ice-loading can occur during operations on other parts of the OCS, outside of the Arctic.
Paragraph (d), Weather and Ice Forecasting and Management
This performance-based provision would require an operator to submit: a detailed description of its “weather and ice forecasting capability for all phases of the drilling operation, including how [it] will ensure continuous awareness of potential weather and ice hazards at, and during transition between, wells;” its “plans for managing ice hazards and responding to weather events;” and verification that it has the capabilities described in its EP. Verification could be provided, for example, by providing appropriate supporting documents (e.g., contracts) for the forecasting and ice management capabilities.
BSEE needs to know the details for how the operator would implement the policies and/or plans for managing ice and weather events, identified to BOEM, for the drilling operations proposed in the APD. It is anticipated that the operator may not know the specific details about each vessel and piece of equipment that contributes to its weather and ice forecasting and management capabilities when describing those capabilities to BOEM, in connection with the IOP and the EP. Also, more detailed plans for managing ice hazards or weather events may be necessary and appropriate given the timing and location of the specific well at issue than may have been available or appropriate for the IOP and EP. Further, BSEE anticipates that weather and ice monitoring and forecasting capabilities may evolve between the approval of the EP and the submittal of the APD, which could yield better data, especially when operations commence. Therefore, this proposed provision would require the operator to submit the specific detailed information to BSEE in connection with its APD and also to describe, in more detail and closer in time to commencement of drilling, how it would implement its weather and ice forecasting and management plan.
BSEE would expect operators to identify the specific weather and ice forecasting equipment and vessels that they intend to utilize, including the name of the contractor that would deliver satellite imagery, if applicable. Such information should also be specific to the location and operations associated with the well that is the subject of the particular APD.
Finally, BSEE would require that an operator’s weather and ice management capabilities would be uninterrupted for the entirety of their operations while on the Arctic OCS. This provision proposes that there would be no gap in weather and ice monitoring activities, including during transit between wells. This is to ensure that, upon arrival at a new well location, there are no unexpected weather or ice hazards that would interfere with drilling operations at the new location, or would pose a threat to the safety or integrity of the drilling equipment or personnel. The purpose of this proposed requirement is to ensure that hazards to drilling operations are avoided or managed before they could become a danger or an interruption to operations.
Paragraph (e), Relief Rig Plan
Paragraph (e) would require operators to provide, with their APD, information concerning how they would comply with the relief rig requirements of proposed § 250.472. See the discussion of that provision for an explanation of the nature of, and need for, those requirements.
Paragraph (f), SCCE Capabilities
Paragraph (f) would require operators who propose to use a MODU to conduct exploratory drilling operations on the Arctic OCS to provide with their APD information concerning their required SCCE capabilities when they are drilling below or working below the surface casing, including a statement that the operator owns, or has a contract with a provider for, SCCE capable of controlling and/or containing its identified WCD. Ensuring that an operator would be capable of responding to a loss of well control is one of the key goals of this proposed rule. In other parts of the OCS (e.g., the Gulf of Mexico), there are several well-established contractors readily available to operators and extensive operations and infrastructure within the region from which resources could be drawn to respond to an event. However, resources are limited in the Arctic region due to the remote location and relative lack of infrastructure and operations. Therefore, operators proposing to conduct exploratory drilling on the Arctic OCS must demonstrate that they would have access to, and be capable of promptly deploying, adequate SCCE. Operators must also describe how they would inspect, test, and maintain this equipment in order to ensure that it would remain fully functional and ready for use. These proposed requirements would help assure BSEE that operators conducting exploratory drilling under Arctic OCS Conditions are capable of: (1) Regaining control after a loss of well control event or (2) containing escaping fluids from a loss of well control event. The information requirements of paragraph (f) would include:
1. A detailed description of the operator’s or its contractor’s SCCE capabilities. The description must include operating assumptions and limitations and information demonstrating that the operator would have access to and the ability to deploy such equipment necessary to regain control of the well. This description would allow BSEE to verify the location and availability of this equipment for compliance with proposed § 250.471.
2. An inventory of the equipment, supplies, and services the operator owns or has a contract for locally and regionally, including the identification of each supplier. This information is important because BSEE would need to verify the existence, condition, and location of the equipment that the operator describes in its plans.
3. Where SCCE capabilities are obtained through contracting, proof of contracts or membership agreements with cooperatives, service providers, or other contractors, including information demonstrating the availability of the personnel and/or equipment on a 24-hour per day basis during operations below the surface casing. In an effort to minimize the environmental and social footprint of, and economic impediments to, Arctic OCS operations, BSEE is encouraging operators to share resources, especially standby equipment. This provision would facilitate the identification of those assets, and would allow BSEE to verify the contractual basis of any agreements necessary to provide the services required.
4. A description of the procedures for inspecting, testing, and maintaining SCCE. SCCE is intended to be standby equipment. However, BSEE needs to be assured that the equipment would remain able to function if it were needed. This provision would allow BSEE to verify that the operator, or contractor, has procedures in place for inspecting, testing, and maintaining the equipment so that it would be ready for use, if necessary. Operators are already required under existing regulations at § 250.1916 to retain the information requested by this proposed new paragraph. The proposed provision would require that operators who propose to conduct exploratory drilling on the Arctic OCS submit this information in conjunction with their APD.
5. A description of the operator’s plan to ensure that personnel are trained to deploy and operate the equipment and that they would maintain ongoing proficiency in source control operations. Standby crews who are not used regularly to perform their dedicated functions would not develop the necessary skills unless they are properly trained, and would not maintain those skills unless that training is reinforced by practice. It is therefore imperative that the operator demonstrate that these personnel have a plan for acquiring, and the ability to maintain, the proficiency necessary to respond when called upon. This requirement would allow BSEE to review those plans and verify that the proficiencies have been acquired and would be maintained.
Paragraph (g), API RP 2N, Third Edition
Paragraph (g) would require that operators explain how they utilized API RP 2N, Third Edition, in planning their Arctic OCS exploratory drilling operations. The API is updating this RP by adopting the entirety of ISO standard “ Petroleum and natural gas industries Arctic offshore structures,” First Edition (2010) (ISO 19906). Since the requirements of this proposed rule are limited only to exploratory drilling operations, operators would not be expected to provide an explanation of how they utilized the entire API RP 2N, Third Edition. This performance-based requirement would be limited to those portions of that document that are specifically relevant for exploratory drilling operations. BSEE proposes to exclude the following sections of API RP 2N, Third Edition, from incorporation:
1. sections 6.6.3 through 6.6.4;
2. the foundation recommendations in section 8.4;
3. section 9.6;
4. the recommendations for permanently moored systems in section 9.7;
5. the seismic analysis recommendations for pile foundations in section 9.10;
6. section 12;
7. section 13.2.1;
8. sections 220.127.116.11, 18.104.22.168, 22.214.171.124, 126.96.36.199 through 188.8.131.52;
9. sections 13.9.1, 13.9.2, 13.9.4 through 13.9.8;
10. sections 14 through 16; and
11. section 18.
Sections 6.6.3 and 6.6.4 would be excluded because they address different types of conditions for ice gouging and/or scouring than are anticipated to occur during the Alaska Arctic open water drilling season. The foundation criteria of section 8.4, the piled structure criteria of section 9.6, the requirements for permanently moored systems in section 9.7, and the requirements for seismic analysis of pile foundations in section 9.10 would be excluded because this rule only applies to MODUs drilling on a temporary basis, as opposed to the more permanent types of structures addressed in those provisions. Similarly, section 12 would be excluded because it applies only to fixed concrete structures and is outside the scope of this proposed rule. Section 13.2.1 (design philosophy for floating structures) would be excluded because similar ice forecasting and management issues are covered separately under proposed § 250.470(d). Sections 184.108.40.206, 220.127.116.11, 18.104.22.168, 22.214.171.124 through 126.96.36.199, 13.9.1, 13.9.2, and 13.9.4 through 13.9.5, would be excluded because they cover vessel design and procedures requirements under USCG jurisdiction. Sections 13.9.6 (inspection and maintenance), 13.9.7 (operations and planning for safety of personnel, the environment, and equipment), and 13.9.8 (ice management plans) would be excluded because similar requirements are addressed by other provisions of this proposed rule. Section 14 would be excluded because it relates only to subsea production systems while this proposed rule applies to MODUs engaged in exploratory drilling activities and because this rule proposes a different set of requirements for BOPs from that set forth in section 14.3.3. Section 15 (topsides design and operation) would be excluded because it does not generally apply to MODUs, and any parts that could be utilized for MODUs fall under USCG jurisdiction. Section 16 (ice engineering topics) would be excluded because it applies to structures that will remain in the ice and does not apply to MODUs. Section 18 (escape, evacuation and rescue) would be excluded because its provisions are already addressed under existing 30 CFR part 250 Subpart S and USCG rules.
BSEE recognizes that, when applied to MODUs, many of the structural criteria of API RP 2N, Third Edition, are regulated by the USCG and may be covered by Class requirements for marine structures. Classification is a determination made by private organizations (in accordance with USCG requirements) that a vessel has been constructed and maintained in compliance with industry standards to be fit for a particular service, in this case Ice Class 3. Therefore, application of API RP 2N, Third Edition, for the purposes of this proposed rule would be limited to the non-marine structural components of MODUs. For example, Class requirements do not cover the derrick, plumbing, pipes, tubing, and pumps that are all also structural components of a MODU and that fall under BSEE jurisdiction. If incorporated in the final rule, BSEE would expect operators to comply with API RP 2N, Third Edition, for MODU components within BSEE jurisdiction. BSEE and the USCG have signed a Memorandum of Agreement for MODUs outlining the allocation of responsibilities between the agencies for fixed offshore facilities available at: www.bsee.gov/BSEE-Newsroom/Publications-Library/Interagency-Agreements/; click on the link for 2013 BSEE/USCG MOA: OCS-08.
BSEE specifically requests comment on proposed draft API RP 2N, Third Edition, and on the extent to which BSEE should incorporate its provisions when finalized into the regulations. As an alternative to incorporation of API RP 2N, Third Edition, BSEE is considering incorporation by reference of ISO 19906, the ISO Arctic standard on which API RP 2N, Third Edition, is based. If BSEE incorporates the ISO standard in lieu of the API standard, the final rule would exclude the sections of the ISO standard corresponding to the excluded sections of API RP 2N previously discussed. BSEE requests comments on whether and to what extent BSEE should incorporate ISO 19906 in lieu of proposed draft API RP 2N, Third Edition.
BSEE is also considering incorporating the ISO standard “Petroleum and natural gas industries—Site-specific assessment of mobile offshore units—Part 1: Jack-ups,” First Edition (2012) (ISO 19905-1), into the final rule, with application limited only to Arctic OCS exploratory drilling operations. ISO 19905-1 may be better suited than API RP 2N (or ISO 19906) to guide structural components for jack-up rigs. The API RP 2N (or ISO 19906) and ISO 19905-1 documents together would provide the most comprehensive structural requirements for the use of a jack-up rig in Arctic conditions. BSEE requests comments on the extent to which ISO 19905-1 should be incorporated into these proposed Arctic regulations.
What are the requirements for Arctic OCS source control and containment? (§ 250.471)
BSEE proposes to require operators to continue to adhere to all applicable source control and containment requirements in the current regulations, and to meet additional SCCE requirements for Arctic OCS exploratory drilling operations. BSEE is required to ensure that offshore oil and gas operations are conducted safely and in a manner that protects the environment from harm as a result of those operations. As stated earlier, the waters and surrounding environment of the Arctic region support a wide variety of marine mammals and other wildlife, including several Endangered Species Act (ESA) listed species and designated critical habitat. Furthermore, U.S. obligations under Article 4 of the Arctic Council’s Agreement on Cooperation on Marine Oil Pollution Preparedness and Response in the Arctic, require that, for “areas of special ecological significance,” each party “shall establish a minimum level of pre-positioned oil spill combating equipment, commensurate with the risk involved, and programs for its use[.]” The Arctic contains areas of ecological significance to the Nation as a whole, and especially to Alaska Native communities.
Therefore, it is imperative that any loss of well control during oil and gas exploratory drilling operations is corrected and/or contained as quickly as possible to minimize the impact of oil pollution on the environment. To accomplish this task, it would be necessary to have all equipment needed to cap and/or contain the release of fluids readily available in the event of a loss of well control during Arctic OCS exploratory drilling operations. Further, operations on the Arctic OCS are distinct from operations on any other part of the OCS. The logistics and the transit times necessary to respond to a well control event on the Arctic OCS, coupled with the difficulties associated with oil spill response operations in Arctic OCS Conditions, require the operator to plan for and be prepared for contingencies that would be more straightforward to address in other theaters. There is limited ability in the Arctic region to summon additional source control and containment resources. Accordingly, operators working there must plan for response redundancies and planning complexities not required elsewhere.
The proposed requirements would apply to all exploratory drilling operations using a MODU on the Arctic OCS, regardless of the BOP configuration employed by the operation. These provisions are designed to ensure that each operator using a MODU would have access to, and could promptly and effectively deploy and operate, surface and subsea control and containment equipment in the event of a loss of well control. In particular, BSEE would require each operator to have the ability, in the event of a loss of well control, to cap the well and to capture, contain, and process or properly dispose of any fluids escaping from the well. All SCCE must be mobilized (i.e., begin transit) to the well immediately upon a loss of well control. The rule would specifically provide that the SCCE is only necessary when drilling below or working below the surface casing.
This new section would require compliance with the following source control and containment requirements for all exploration wells drilled on the Arctic OCS.
Paragraph (a), Drilling Below or Working Below the Surface Casing
Paragraph (a) would require that the operator, when using a MODU to drill below or work below the surface casing, have access to a capping stack positioned to arrive at the well within 24 hours after a loss of well control, and a cap and flow system and a containment dome positioned to arrive at the well within 7 days after a loss of well control. These technologies are important because they have, either individually or in sequence, been proven to be effective at reacquiring control of wells and/or containing the flow of hydrocarbons after primary well control measures (such as well design and a BOP) have failed to prevent a well control event. The SCCE is intended to provide redundancy in the event of a loss of well control. Some of the well control events for which this equipment would be deployed could require a relief well to permanently plug and abandon the uncontrolled well.
On the Arctic OCS, the exploratory drilling operator would not be considered to have the required SCCE unless it is secured in advance and has the capability of arriving at the well within the required timeframes. In the event that a BOP or other prevention mechanism fails to stop the flow of fluids, capping stacks would be necessary to provide an additional means to control flow from the well, where a stub or connector is accessible. Capping stacks are the preferred immediate first level redundancy, with the goal of controlling the well and stopping the discharge of fluids, and should be positioned so that they will arrive at the well within 24 hours after a loss of well control. Incidents in which the connectors or tubulars are not damaged would lend themselves to the use of a capping stack.
If the tubulars are damaged and the pressure cannot be managed with the capping stack, the remainder of the cap and flow system must be used as a secondary response. It must be positioned so that it will arrive at the well within 7 days of a loss of well control and designed to capture the WCD identified in the EP. If the cap and flow system were unable to stop or control the flow of fluids to the environment, or the well system were damaged to the point that the capping stack could not make a connection, the containment dome system, which also must be positioned to arrive at the well within 7 days of a loss of well control, would need to be used to capture the hydrocarbons flowing to the environment, as a tertiary response. Thus, the SCCE system, as a whole, would provide a level of redundancy and flexibility necessary to operate on the Arctic OCS.
BSEE specifically requests comment on all of the proposed timeframes for arrival of SCCE at the well in the event of a loss of well control. In particular, BSEE invites comments on whether such timeframes are appropriate, from a logistical and feasibility perspective, to address a loss of well control. BSEE also requests comment on whether the cap and flow system and containment dome could be available and positioned to arrive at the well within 3 days, or some shorter amount of time than 7 days.
Paragraph (b), Stump Test
Paragraph (b) would require monthly stump tests of dry-stored capping stacks, and stump tests prior to installation for pre-positioned capping stacks. The presence of the equipment alone is not sufficient to ensure the reliability of the system. Testing of the equipment must be done on a regular basis. This proposed rule would impose a requirement that any capping stack that is dry stored must be stump tested (function and pressure tested to prescribed minimum and maximum pressures on the deck in a stand or stump where it could be visually observed) monthly. The rule would also require that pre-positioned capping stacks be tested prior to each installation on a well to assure BSEE that no damage was done during the prior deployment or transit.
Paragraph (c), Reevaluating SCCE for Well Design Changes
Paragraph (c) would require a reevaluation of the SCCE capabilities if the well design changes because some well design changes may impact the WCD rate. If the operator proposes a change to a well design that impacts the WCD rate, the operator must provide the new WCD rate through an Application for Permit to Modify (APM), as required by § 250.465(a). The operator must then verify that the SCCE would either be modified to address the new rate or that the previously proposed system would be adequate to handle the new WCD to demonstrate ongoing compliance with the SCCE capability requirements previously addressed.
Paragraph (d), SCCE Tests or Exercises
Paragraph (d) would require the operator to conduct tests or exercises of the SCCE when directed by the Regional Supervisor. Similar to the requirement that equipment be tested periodically, BSEE has concluded that there is a need to ensure that personnel are prepared and that they, and the SCCE, would be capable of performing as intended. Therefore, BSEE proposes to require that operators conduct tests and exercises (including deployment), at the direction of the Regional Supervisor, to verify the functionality of the systems and the training of the personnel.
Paragraphs (e) and (f), SCCE Records Maintenance
Paragraph (e) would require the operator to maintain records pertaining to testing, inspection, and maintenance of the SCCE for at least 10 years, and make them available to BSEE upon request. This information would facilitate a review of the effectiveness of the operator’s inspection and maintenance procedures and provide a basis of review for performance during any drill, test, or necessary deployment. Because of the limited drilling season on the Arctic OCS, the 10-year record retention requirement is necessary in order to ensure the availability of a meaningful longitudinal data set. Additionally, the limited drilling season means that this equipment would be infrequently used and might be stored for long periods of time between seasons. Thus, a 10-year record retention requirement is necessary to ensure enough cumulative data is gathered to assess overall equipment performance and trends.
Paragraph (f) would require the operator to maintain records pertaining to use of the SCCE during testing, training, and deployment activities for at least 3 years and to make them available to BSEE upon request. The use of the equipment during testing and training activities and actual operations must be recorded, along with any deficiencies or failures. These records would allow BSEE to address any issues arising during the usage and to document any trends or time-dependent problems that would develop over the record retention period. In the event that the equipment is used in a well control incident, the records are necessary to document the effectiveness of the response and functioning of the equipment.
Paragraphs (g) and (h), Mobilizing and Deploying SCCE
Paragraph (g) would require operators to mobilize (i.e., initiate transit of) SCCE to a well immediately upon a loss of well control and deploy (i.e., position for use) and use SCCE. Paragraph (h) would give the Regional Supervisor the authority to require the operator to deploy and use SCCE independent of an operator’s determination of whether or not to deploy and use SCCE. Requiring immediate mobilization would prevent operators from delaying the transit of SCCE equipment to the well in the hope that other source control or containment methods will be successful. This provision would ensure that all SCCE is available and ready for use. Also, this provision is being proposed to clarify the Regional Supervisor’s discretion to require the deployment and use of SCCE in the event of a loss of well control or for purposes of SCCE training and exercises. The Regional Supervisor’s authority is specifically addressed here to allow the Regional Supervisor to act in a timely manner should a loss of well control occur.
What are the relief rig requirements for the Arctic OCS? (§ 250.472)
As demonstrated by past loss of well control events around the globe, in some cases it may be necessary to drill a relief well to permanently plug an uncontrolled well. The SCCE is an interim solution designed to minimize environmental harm from well control events, but the ultimate solution may need to be accomplished by a relief well. Arctic OCS exploratory drilling operations would take place in a region that has little or no infrastructure, that is subject to variable and sometimes extreme weather, and in which transportation systems could be interrupted for significant periods of time. Also, Arctic OCS exploratory drilling operations are complicated by the fact that they currently take place only during the “open water season,” or that period of time in the summer and early fall when ice hazards can be physically managed and there is no continuous ice layer over the water. Outside of that window, ice encroachment may complicate or prevent drilling and transit operations, and for that reason it is critical to ensure that drilling (including relief well drilling if necessary) and other operations affected by sea ice are concluded before ice encroachment. Furthermore, if there is a loss of well control during the drilling season, it is also important to ensure that, if a relief rig is necessary to stop the uncontrolled flow of oil, the relief rig is available and able to complete all necessary operations in as short a time as possible. Thus, while conducting exploratory drilling operations below the surface casing on the Arctic OCS, it is essential to position or designate a relief rig in a location that would enable it to transit to the well site, drill a relief well, plug the original well, plug the relief well, and demobilize from the site prior to expected seasonal ice encroachment. This would require the cessation of exploratory drilling or other work below the surface casing far enough in advance of the expected return of seasonal ice to allow for completion and abandonment of a relief well.
The proposed rule would establish a 45-day maximum limit on the time necessary to complete relief well operations. This timeframe is necessary to acknowledge the relative lack of infrastructure and active operations from which response resources could be drawn in the region, as well as the grave threats of a prolonged loss of well control to the Arctic environment. If an operator were to use a pure standby rig (i.e., a rig that is not otherwise operating in the Arctic), Dutch Harbor is the nearest deep-water port where the standby rig could be stationed. BSEE estimates that it would take 20 days to get the rig ready and to transit from the nearest U.S. deep-water port (Dutch Harbor) to the farthest well location (Beaufort leases), 20 days to drill the relief well, and 5 days to plug the uncontrolled well, test it, and move off the well site. If, on the other hand, an operator were to use a second drilling rig to serve as a relief rig for another drilling rig, the time required to complete relief well operations could be much shorter than 45 days because the second rig would already be operating in the Arctic OCS and would require shorter transit time than a standby relief rig staged in Dutch Harbor or at another location.
BSEE considered imposing prescriptive geographic limitations on the staging of relief rigs in proximity to exploratory drilling operations, but chose instead to propose a performance-based requirement to provide operators the flexibility to choose how best to comply with the relief rig obligations. Operators would need to demonstrate their ability to complete relief well operations within a maximum of 45 days, subject to BSEE’s review in the APD process (see proposed § 250.470(e)). The proposed rule would also authorize the Regional Supervisor to direct an operator to begin drilling the relief well.
The relief rig could be stored in harbor, staged idle offshore, or actively working, as long as it would be capable of physically and contractually meeting the proposed 45-day maximum timeframe. However, any relief rig must be a separate and distinct rig from the primary drilling rig to account for the possibility that the primary rig could be destroyed or incapacitated during the loss of well control incident.
Of course, an operator’s actual timeframe to drill a relief well would be based on consideration of the distance between anticipated exploratory drilling sites, the availability of adequate staging locations for relief rigs, the length and complexity of rig transit under Arctic OCS Conditions, and the time necessary to complete the requisite operations once on-site. Thus, BSEE specifically requests comment on whether the maximum time limit for deploying a relief rig and drilling a relief well should be more or less than 45 days.
The proposed rule expressly provides that the relief rig would only be necessary when drilling below or working below the surface casing (i.e., where contact with hydrocarbons capable of flowing into the well could occur). BSEE recognizes that the proposed relief rig requirement may effectively limit the number of days an operator can work below the surface casing at the end of each drilling season. The actual length of this limitation would depend on the operator’s plans for staging and deploying a relief rig and could extend up to 45 days before the end of the drilling season (e.g., the projected return of sea ice). During this period, however, an operator may be able to conduct a number of different operations at the well site that do not involve work below the surface casing. Such work can significantly advance an exploratory drilling project and can help an operator prepare to conduct work below the surface casing during the following drilling season. BSEE requests comments on the different types of work (above the surface casing) that could be performed during the time period set aside for a relief well to be drilled, if needed, as well as the economic benefits and costs associated with this work.
While a relief well is the most reliable, and in some circumstances the only available, solution to kill and permanently plug an out-of-control well, there could be circumstances in which control could be regained without intervention by a relief well. Accordingly, BSEE also requests comment on whether there are any alternative technological methods, in addition to a relief well, to kill and permanently plug an out-of-control well before seasonal ice encroachment. Comments should include, where possible, specific technological solutions, descriptions of the conditions under which an alternative method could successfully kill and permanently plug a well, and any research that would demonstrate the effectiveness of such an alternative.
For example, some stakeholders have proposed that the use of subsea shut-in devices (SIDs) located on the seafloor could help significantly reduce the risk of a release of hydrocarbons if the BOP system fails. SID equipment is specifically designed to act as a redundant safety system and ensure the safe and timely shut-in of a well in an emergency. Although BSEE believes that timely access to a relief rig is the surest way to permanently resolve a WCD event in the Arctic, the use of SIDs could reduce the risk of a release of hydrocarbons and potentially justify giving operators more flexibility in the staging of relief rigs.
Thus, BSEE requests comments on alternative compliance approaches and specifically requests data on the performance of SIDs, including operational issues (such as timeframes needed to activate such alternatives). In particular, BSEE requests comments on appropriate staging requirements for a relief rig assuming that an SID has been installed at the exploration well. Comments are also requested on the need for an operator to have an in-season relief well drilling capability if an SID is used at a location that is not subject to ice scouring.
BSEE also requests information or data comparing the relative safety and environmental risk levels, as well as the costs, of the equipment and procedures that would be required under the proposed regulations to the risks and costs of equipment and procedures under any suggested alternative approach.
In any case, BSEE’s existing regulations allow operators the flexibility to develop new technological solutions and to seek approval for the use of those solutions to fulfill their regulatory obligations. Under 30 CFR 250.141, operators may request approval to use alternative equipment or procedures for any specified requirement, provided that the operator is able to demonstrate an equivalent or improved level of safety and environmental protection. This performance-based provision is a key part of BSEE’s regulatory program, which is a combination of prescriptive and performance-based requirements, because it gives operators the ability to comply with regulatory requirements through a variety of methods if they can make the necessary demonstrations to BSEE. It also serves to encourage the development and utilization of alternative technologies to satisfy the specific requirements contained in the regulations.
What must I do to protect health, safety, property, and the environment while operating on the Arctic OCS? (§ 250.473)
BSEE proposes to add a new § 250.473 that would require performance-based measures in addition to those listed in § 250.107 to protect health, safety, property, and the environment during exploratory drilling operations on the Arctic OCS.
Paragraph (a) would require that all equipment and materials proposed for use in exploratory drilling operations on the Arctic OCS be rated or de-rated for service under conditions that could be reasonably expected during operations. Arctic OCS Conditions place strains on operating equipment not experienced elsewhere on the OCS. This necessitates that such equipment be rated or de-rated for use under such conditions in order to ensure that it could operate safely and effectively.
For example, cranes must be designed to withstand ice loads that can be anticipated to build up during Arctic OCS operations and operational limitations of components under extreme cold temperatures (e.g., reduced tensile strength) must be understood and accounted for. Also, capping and containment equipment must be specifically designed to withstand the demands of regional conditions. The Arctic Council made similar recommendations for equipment and materials in its 2009 report on Arctic oil and gas operations (see Arctic Council—Arctic Offshore Oil and Gas Guidelines (2009)).
BSEE’s existing regulation at § 250.418(f) requires that operators include in their APD “evidence that the drilling equipment, BOP systems and components, diverter systems, and other associated equipment and materials are suitable for operating” in areas subject to subfreezing conditions, while proposed § 250.473(a) would establish a requirement for use of appropriately rated or de-rated equipment and materials. Operators may ensure that proposed materials and equipment are rated or de-rated appropriately by referencing manufacturer specifications and would not need to obtain equipment or material rating by an independent third-party rating entity. Upon finalization of this provision, failure to use appropriately rated or de-rated equipment and materials could subject an operator or its contractor to enforcement action by BSEE.
Paragraph (b) would require operators to employ measures to address human factors associated with weather conditions that can be reasonably expected during Arctic OCS exploratory drilling operations. This provision is designed to ensure safety of the workforce and protection of the environment by requiring operators to account for weather conditions that might impact decision-making and personnel health and safety. On the Arctic OCS, the workforce would encounter harsh environmental conditions, including extreme cold, snow, ice, and freezing spray, which could cause, among other medical conditions, frost bite and breathing difficulties that can impair performance and judgment. Measures that operators would be required to use to address human factors include, but are not limited to, provision of proper attire and equipment, construction of protected work spaces, and management of shifts.
What are the auditing requirements for my SEMS program? (§ 250.1920)
In 2013, BSEE published an update to Subpart S, which established additional measures operators must take to manage safety and to protect the environment during their OCS operations. The requirements under this subpart are designed to be performance-based to allow operators to tailor their management systems to their particular operations, including operations on the Arctic OCS. For example, a hazards analysis for a facility on the Arctic OCS would account for the types of hazards expected on the Arctic OCS, like ice floe. Similarly, Job Safety Analyses must account for Arctic OCS Conditions, such as ice, extreme cold, snow, and freezing spray. BSEE would not consider an operator’s SEMS to be effective under § 250.1924 if it were not specifically tailored to the Arctic OCS Conditions reasonably anticipated at the facility in question.
Similarly, existing §§ 250.1914 and 250.1924 give BSEE broad authority to require that operators on the Arctic OCS provide BSEE with information such as the names of contractors and the specific scope of their duties and timelines for performance in support of an operator’s drilling activities. For example, if an operator planned to use a contractor for waste disposal, cementing, or logging, BSEE would expect the operator to inform BSEE of this intent, along with any other operations contracted out, and the names of those contractors. Because the existing performance-based SEMS regulations are adequate to cover Arctic OCS operations when properly implemented, no major modifications are needed to Subpart S for the Arctic OCS. However, additional provisions are necessary to bolster auditing expectations for Arctic OCS exploratory drilling operations.
This rule proposes to increase the audit frequency and facility coverage for intermittent Arctic OCS exploratory drilling operations. While operators are generally required to conduct their SEMS audit every 3 years after their initial audit, BSEE believes it would be critical to perform a SEMS audit of Arctic OCS exploratory drilling operations and all related infrastructure each year in which drilling is conducted, because of the particularly challenging conditions and high-risk nature of those activities. This Arctic OCS audit would require operators to ensure that all safety systems are in place and functional prior to commencing or resuming, activities for a new drilling season, as well as to conduct the offshore portion of the audit while drilling is under way. An operator conducting Arctic OCS exploratory drilling operations may not combine its Arctic OCS facility audit(s) with audits of its non-Arctic OCS facilities to satisfy the facility sampling requirements incorporated into Subpart S.
As with SEMS audits in other OCS regions, there would be an onshore and offshore portion. However, for Arctic OCS exploratory drilling operations, an operator would be required to submit a separate audit report and corrective action plan (CAP) for the onshore and offshore portions of its audit. To provide an opportunity for BSEE to review the onshore portion of the audit report and CAP prior to commencement of drilling, they must be submitted no later than March 1st in any year in which drilling is planned. The operator would also be required to start and close the offshore portion of the audit within 30 days after first spudding of the well or entry into an existing wellbore for any purpose from that facility. The operator would be required to submit the audit report and CAP from the offshore portion of the audit within 30 days of the close of that portion of the audit. This is designed to enable the auditors to analyze offshore operations while they are actively underway, and to ensure that BSEE is made aware of any issues surrounding those operations as soon as practicable. To ensure that any critical problems that are revealed by the audit are addressed, BSEE would be able to order all or part of the operations to be shut down, if necessary.