Per the DOI regulatory agenda published on 7/27/2023 (excerpt below), the final BSEE well control rule was published in June. Of course, that did not happen, but the update tells us that the final rule should be published soon. The delay is probably in the internal review process which moves at the pace of continental drift 😉.
BOE comments on the proposed rule are attached here.
12. Oil and Gas and Sulfur Operations in the Outer Continental Shelf-Blowout Preventer Systems and Well Control Revisions [1014–AA52]
Legal Authority: Not Yet Determined [BOE note: This is rather comical since the OCSLA authority was specified in the preamble to the proposed rule and you would never publicly imply that you didn’t know the authority for a final rule. 😉]
Abstract: This rulemaking revises the Bureau of Safety and Environmental Enforcement (BSEE) regulations published in the 2019 final rule entitled “Oil and Gas and Sulfur Operations in the Outer Continental Shelf-Blowout Preventer Systems and Well Control Revisions,” 84 FR 21908 (May 15, 2019), for drilling, workover, completion and decommissioning operations. In accordance with Executive Order (E.O.) 13990 (Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis) and the E.O.’s accompanying “President’s Fact Sheet: List of Agency Actions for Review,” BSEE reviewed the 2019 final rule and is updating to subpart G of 30 CFR part 250 to ensure operations are conducted safely and in an environmentally responsible manner.
Attached is a settlement agreement between NOAA and 4 NGOs that could have major implications for deepwater oil and gas operations in the Gulf of Mexico.
As background, the Rice’s Whale (formerly Bryde’s whale) area has been expanded (see map above) such that it fences off deepwater leases by creating a barrier to vessel transportation. The expansion is based on a single study that concluded that Rice’s whales were “the most plausible explanation” for moan calls observed in the northwest GOM shelf break area. No Brice’s whales were sighted in the expanded area during this study. The authors do point to a 2017 sighting offshore Corpus Christi, which is apparently the only actual sighting of a Brice’s whale along the NW GoM shelf break.
The settlement agreement commits BOEM, presumably with their concurrence, to exclude the expanded area from future leasing, to issue a Notice to Lessees and Operators (exhibit 1 below) and to attach stipulations to new leases (exhibit 2). Because BOEM’s authority to impose major new requirements without proposing a regulation for public review and comment is questionable, the Notice (NTL) describes the restrictions as “recommended measures.” However, the liability risks associated with the failure to comply with this “guidance” would be unacceptable to most companies. Adding to the muddle, the language in the lease stipulation differs by making it perfectly clear that compliance is required.
The most troubling restriction from an operational standpoint:
“To the maximum extent practicable, lessees and operators should avoid transit through the Expanded Rice’s Whale Area after dusk and before dawn, and during other times of low visibility to further reduce the risk of vessel strike of Rice’s whales.“
Comments:
Deepwater facilities are typically far from shore, and a requirement to transit only between dusk and dawn, particularly in the winter, is unrealistic and onerous. This is further complicated by the speed limit provision.
Those who have worked offshore know that periods of low visibility are unpredictable and can extend for days. The low visibility transit restriction is thus highly punitive and increases operational risks on the vessels and at the facilities they serve.
The vague “to the maximum extent practicable” caveat provides little comfort for planners, managers, and crews, and is a de facto acknowledgement that the requirement is unreasonable.
These restrictions, coupled with the required Automatic Identification System data, open the door to endless challenges, especially given the keen interest of the litigious organizations that are parties in the settlement agreement.
Deepwater GoM operations are few in number and highly dispersed, which is a more important mitigating factor than those included in the agreement. More on this tomorrow.
In addition to the deepwater operations that will be much more difficult to supply, there are currently 81 production platforms within the expanded Rice’s whale area (100 to 400 m water depth).These include important facilities like Amberjack, Cognac, Cerveza, and Lobster. What are the implications for these platforms? Will they be required to have full-time whale observers? Can they only be supplied during daylight hours with good visibility? Why not consider using these platforms as bases for more definitive studies?
Further to the previous point, there are 103 existing leases in the 100-400 m depth zone that is now excluded from leasing? 90 of these leases are still in their primary term, and 21 were issued in the past 2 years. How will the contractual rights of these leaseholders be protected? (In fact, the value of all 1550 active leases in >100 m water depth is affected by this agreement.)
Have BSEE and Coast Guard been consulted on the practicality and safety implications of these requirements?
Deepwater operations have been ongoing in the GoM for 50 years, and there is no apparent evidence of impacts to this species. Why can’t the consultation process and any necessary followup studies be completed before decisions are made regarding operating restrictions?
Finally, BOEM’s third footnote in the NTL (pasted below), doesn’t demonstrate great confidence in the need for the onerous requirements that are being imposed.
“This is not meant to be construed as a blanket determination as to whether BOEM, at present, has determined that there is a “reason to believe” that incidental take may occur, within the meaning of the ESA, the consultation regulations, or BOEM’s regulations. Those decisions will be made on a case-by-case basis in accordance with BOEM regulations referenced below.” Comment: Huh??? How are these blanket restrictions case-by-case, and how are they being imposed without public review?
ENERGYWIRE has reported that the Department of the Interior will publish the legislatively mandated carbon sequestration rule later this year. Given that even close followers of the OCS program were completely unaware of the enabling legislative provisions prior to their enactment, the proposed DOI rule will provide the first opportunity to formally comment.
Within the oil and gas industry and the environmental community, there are considerable differences of opinion about carbon sequestration in general, and more specifically, offshore sequestration. All interested parties are encouraged to submit comments on these important regulations.
Some background information on the sequestration legislation and subsequent actions:
amend the OCS Lands act to authorize “the injection of a carbon dioxide stream to sub-seabed geologic formations for the purpose of long-term carbon sequestration.”
exempt CO2 injection from the restrictions on ocean dumping by stipulating that such injection “shall not be considered to be material (as defined in section 3 of the Marine Protection, Research, and Sanctuaries Act of 1972.” Without this exemption, CO2 streams would clearly be “material,” as defined in 33 U.S.C. 1402, and would be subject to the stringent requirements of that act.
direct that “not later than 1 year after the date of enactment of this Act, the Secretary of the Interior shall promulgate regulations to carry out the amendments made by this section.” (This deadline has been missed, which is rather common for such directives.)
3/29/23: Exxon bid at Sale 259 on 69 nearshore tracts with little oil and gas potential. Once again, this was strictly an oil and gas lease sale and Exxon’s CCS intentions were clear. Nonetheless, the leases were awarded.
Exxon and other companies intend to commercialize carbon sequestration, and Exxon projects an astounding $4 trillion CCS market by 2050. Such a market will of course be dependent on mandates and subsidies, and the costs will ultimately be borne by taxpayers and consumers.
Is it not a bit unsavory and hypocritical for hydrocarbon producers to capitalize on the capture and disposal of emissions associated with the consumption of their products? Perhaps companies that believe oil and gas production is harmful to society should exit the industry, rather than engage in enterprises that sustain it.
The Jones Act, protectionism at its finest, was enacted 113 years ago, and stipulates that vessels which transport merchandise or people between two US points must be US built, flagged, owned, and crewed. Congress tightened the screws further by ordaining that offshore energy facilities, including wind farms, are US points. That precludes the transportation of wind turbine components from US ports to offshore wind farms.
The Jones Act has thus provided an opportunity for the Port of Argentia, a former US Navy base in southeast Newfoundland, and the port is set to become a key node in the offshore wind supply chain. Monopiles constructed in Europe will be stored in Argentia, until they are delivered to US wind farms in the North Atlantic. Kudos to the folks at the Port of Argentia for taking advantage of this opportunity.
Dutch company Boskalis will be transporting the monopiles, which are expected to land in the Port of Argentia in a few weeks. (Boskalis)
BOEM has rather surprisingly proposed to eliminate consideration of a company’s compliance record in determining the need for supplemental financial assurance.An opposing view will be posted tomorrow.
If a lease has proved reserves with a value of at least three times that of the estimated decommissioning cost, no supplemental financial assurance would be required. Comparing two imprecise and variable estimates is neither a simple nor reliable method for determining the need for supplemental financial assurance. BOEM should look at the history of the Carpenteria field (Santa Barbara Channel) and the reserve estimates that were provided to discount decommissioning risks. More on this at a later date.
Transferor liability applies only to those obligations existing at the time of transfer; new facilities, or additions to existing facilities, that were not in existence at the time of any lease transfer are not obligations of a predecessor company and are considered obligations of the party that built such new facilities and its co- and successor lessees. This is a good policy, but is difficult to implement. Some of the complexities may need to be addressed.More later.
The “reverse chronological order” provision was withdrawn in April, so there is no defined process for issuing decommissioning orders to predecessor lessees. Is it good policy to first issue such orders to companies who may have owned leases decades ago, in some cases prior to the establishment of transferor liability in the 1997 MMS “bonding rule?”
The proposed rule would clarify that BOEM will not approve the transfer of a lease interest until the transferee complies with all applicable regulations and orders, including the financial assurance requirements. BOEM needs to be firmly enforce this policy. See tomorrow’s post.
The proposed rule would not allow BOEM to rely upon the financial strength of predecessor lessees when determining whether, or how much, supplemental financial assurance should be provided. This is a good provision.
BOEM proposes to use the P70 probabilistic value to set the amount of any required supplemental financial assurance. These estimates do not seem sufficiently conservative to protect other parties and the public in the event of default. This is particularly true after storm damage which can increase plugging costs more than tenfold.
The probabilistic cost estimates were updated in 2020 and are based on data submitted subsequent to 2016 and 2017 NTLs. How often will these estimates be updated?
The final rule should specify that funds may not be withdrawn from decommissioning accounts for operational purposes, and that BOEM approval is required for such withdrawals.
The Piper Alpha fire was the worst disaster in the history of offshore oil and gas operations and sent shock waves around the world. Eight months later another interactive pipeline-platform fire killed 7 workers at the South Pass 60 “B” facility in the Gulf of Mexico. A US Minerals Management Service task group reviewed the investigation reports for both fires and recommended regulatory changes with regard to:
the identification and notification procedures for out-of-service safety devices and systems,
location and protection of pipeline risers,
diesel and helicopter fuel storage areas and tanks,
Lord Cullen’s comprehensive inquiry into the Piper Alpha tragedy challenged traditional thinking about regulation and how safety objectives could best be achieved, and was perhaps the most important report in the history of offshore oil and gas operations. Per Cullen:
“Many current safety regulations are unduly restrictive because they impose solutions rather than objectives. They also are out of date in relation to technological advances. Guidance notes lend themselves to interpretations that discourage alternatives.There is a danger that compliance takes precedence over wider safety considerations and that sound innovations are discouraged.“
Cullen advocated management systems that describe the safety objectives, the system by which those objectives were to be achieved, the performance standards to be met, and the means by which adherence to those standards was to be monitored. He called for safety cases that describe major hazards on an installation and provide appropriate safety measures. Per Cullen, each operator should be required in the safety case to demonstrate that the safety management systems of the company and the installation are adequate to assure that design and operation of the platform and its equipment are safe.
Interestingly, none of Exxon’s 69 high bids for shelf leases have been accepted to date. Given that the Exxon bids were for tracts that are presumably considered “nonviable” from an oil and gas production standpoint, those bids should have been accepted by now were they deemed to be valid.
Perhaps BOEM, to their credit, is planning to reject the CCS bids as they may when an unusual bidding pattern has been identified. It is now quire clear (unlike in the immediate aftermath of Sale 257) that Exxon was seeking to acquire these leases for carbon sequestration purposes. That is not allowed given that both Sales 257 and 259 were oil and gas lease sales. As similarly noted for Sale 257:
Sale 259 was an oil and gas lease sale. The Notice of Sale said nothing about carbon sequestration and did not offer the opportunity to acquire leases for that purpose. Therefore, the public notice requirements for CCS leasing (30 CFR § 556.308) were not fulfilled.
Because there was no draft or final Notice of Sale for CCS leases, interested parties and the public did not have the opportunity to consider and comment on CCS leasing, tract exclusions, bidding parameters, and other factors.
30 CFR § 556.308 requires publication of a lease form. No CCS lease form was posted or published for comment.
CCS operations were not considered in the environmental assessments conducted prior to the sale.
No evaluation criteria for CCS bids have been published.
Regulatory fragmentation occurs when multiple federal agencies oversee a single issue. Using the full text of the Federal Register, the government’s official daily publication, we provide the first systematic evidence on the extent and costs of regulatory fragmentation. We find that fragmentation increases the firm’s costs while lowering its productivity, profitability, and growth. Moreover, it deters entry into an industry. These effects arise from regulatory redundancy and, more prominently, regulatory inconsistency between agencies. Our results uncover a new source of regulatory burden: companies pay a substantial economic price when regulatory oversight is fragmented across multiple government agencies.
The US has a highly fragmented offshore regulatory regime that has become even more fragmented with the complex division of responsibilities between BOEM and BSEE. The slide below is from a presentation on this topic.
While the linked paper focuses on costs and productivity, fragmentation may also be a significant safety risk factor. A UK colleague once asseted that “overlap is underlap,” and I believe there is something to that. If multiple agencies have jurisdiction over a facility, system, or procedure, the resulting redundancy, inconsistency, and ambiguity may create significant gaps in industry and governmental oversight.
For example, regulatory fragmentation was arguably a significant factor in the most fatal US offshore fire/explosion incidents in the past 35 years – the South Pass B fire in 1989 and the Macondo blowout in 2010. More specifically:
South Pass 60 B: The investigation of the 1989 South Pass 60 B platform explosion that killed 7 workers noted the inconsistency in regulatory practices for the platform, regulated by DOI, and the pipeline regulated by DOT. Cutting into the 18-inch pipeline riser did not require an approved procedure, and the risks associated with hydrocarbon pockets in the undulating pipeline were not carefully assessed. Oversight by the pipeline operator was minimal, and the contractor began cutting into the riser without first determining its contents. A massive explosion occurred and 7 lives were lost.
One would hope that this major spill will lead to an independent review of the regulatory regime for offshore pipelines. Consideration should be given to designating a single regulator that is responsible and accountable for offshore pipeline safety (a joint authority approach might also merit consideration) and developing a single set of clear and consistent regulations.
Macondo: While the root causes of the Macondo blowout involved well planning and construction decisions regarding the casing point, cementing of the production casing, and well suspension procedure, the blowout would likely have been at least partially mitigated (and lives saved) if the gas detection system was fully operable, the emergency disconnect sequence was activated in a timely manner, flow was automatically diverted overboard, or engine overspeed devices functioned properly. Indeed, regulatory overlap led to underlap as summarized below:
Macondo contributing factor
jurisdiction
flow not automatically diverted overboard
DOI/USCG (also concerns about EPA discharge violations)
some gas detectors were inoperable
DOI/USCG
generators did not automatically shutdown when gas was detected
USCG/DOI
failure to activate emergency disconnect sequence in a timely manner (training deficiencies and chain-of-command complications)
USCG/DOI
engine overspeed devices did not function
USCG/DOI
hazardous area classification shortcomings
USCG/DOI
MOUs and MOAs are seldom effective regulatory solutions as they are often unclear or inconclusive, and tend to be more about the interests of the regulator and protecting turf. They also do nothing to ensure a consistent commitment among the regulators. In the case of the US OCS program, BOEM-BSEE have a greater stake in the safety and environmental outcomes given that offshore energy is the reason for their existence. That is not the case for any of the other regulators identified in the graphic above.
Oil and Energy Minister Terje Aasland takes over the constitutional responsibility for the Petroleum Safety Authority with effect from 11 May 2023. Labor and Inclusion Minister Marte Mjøs Persen previously held responsibility. With this, the government wishes to strengthen comprehensive and good management of HSE, safety and preparedness on the Norwegian continental shelf.
The transfer of responsibility to the Ministry of Oil and Energy (OED) is in line with the main principle in Norwegian administration that one ministry and one cabinet minister have the constitutional responsibility for the sector as a whole.
The Petroleum Safety Authority and the Norwegian Petroleum Directorate, the resource management agency, now report to the same ministry. Prior to a December 2003 decree that established the PSA, both the safety and resource functions were administered by the NPD.
Could this be the start of a trend toward better coordination of regulatory and resource management functions? If so, that would be a positive development. Fragmented oversight is neither in the best interest of safety nor resource management. (More on this in an upcoming post.)
Bud's Offshore Energy (BOE) 