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Posts Tagged ‘BOEM’

Just as I was lamenting the absence of scientific surveying in the Atlantic, my former colleague Renee Orr brought this NOAA announcement to my attention. Researchers from the University of Texas Institute of Geophysics and Lamont-Doherty Earth Observatory, with funding from the National Science Foundation, propose to conduct seismic surveys in the Blake Plateau area of the South Atlantic (map below).

The proposed study would acquire two-dimensional (2-D) seismic reflection and seismic refraction data to examine the structure and evolution of the rifted margins of the southeastern United States, including the rift dynamics during the formation of the Carolina Trough and Blake Plateau.

The survey will lead to a better understanding of “the interaction between tectonic and magmatic processes that led to continental breakup and the onset of seafloor spreading in the central Atlantic Ocean 200 million years ago.” The investigators are particularly interested in the “stratigraphy of sediments that formed during and after rifting, the degree of crustal stretching at the continental margins, crustal faults that formed during extension of the margin, and the geometry of lava flows that were placed on the crust before the start of seafloor spreading.”

While not a primary purpose, the research should improve our understanding of the relationship between productive oil and gas fields offshore Africa and US analogs. Paul Post and his BOEM team estimated that the US Atlantic could contain >20 billion BOE (link to the latest report).

NOAA has conducted a detailed review of the proposal and made a “preliminary determination that the impacts resulting from this activity are not expected to adversely affect any of the species or stocks through effects on annual rates of recruitment or survival.”

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Linking an interesting academic paper on regulatory fragmentation:

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.

Regulatory Fragmentation

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.

Decades later, DOT and DOI pipeline regulations and oversight practices are still inconsistent. Note the confusion regarding the applicable regulations following the Huntington Beach pipeline spill in 2021. As posted following that spill:

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 factorjurisdiction
flow not automatically diverted overboardDOI/USCG (also concerns about EPA discharge violations)
some gas detectors were inoperableDOI/USCG
generators did not automatically shutdown when gas was detectedUSCG/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 functionUSCG/DOI
hazardous area classification shortcomingsUSCG/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.

The contributing factors listed in the Macondo table are not clearly or effectively addressed in the current MOAs for MODUs and floating production facilities.

Helicopter safety is another example of MOA inadequacy. Three offshore workers and a pilot died in December when a helicopter crashed onto the helideck of a GoM platform during takeoff. The most recent Coast Guard – BSEE MOA for fixed platforms added to helideck regulatory uncertainty by assigning decks and fuel handling to BSEE and railings and perimeter netting to the Coast Guard. This is the antithesis of holistic, systems-based regulation.

 

 

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Industry consultancy Rystad Energy estimates Guyana will be pumping 1.7 million barrels per day by 2035, which is higher than other major offshore basins including the Gulf of Mexico, ranking the country as the world’s fourth largest offshore oil producer. 

OilPrice.com

The GoM is currently producing >1.8 million bopd. If Rystad/OilPrice intended to say that Guyana production will exceed GoM production in 2035, that could be the case. However, sustained GoM production in 2035 could easily be >1.7 million bopd with proper resource management by government and industry. In fact, BOEM’s latest forecast (table below) calls for production >1.8 million bopd in 2031, the last year in their forecast.

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BSEE will continue to evaluate the process for issuing decommissioning orders and will continue to issue decommissioning orders to jointly and severally liable parties on a case-by-case basis.

Final decommissioning rule (preamble). 4/18/2023

Although the news release for BSEE’s final decommissioning rule asserts that the regulations “provide the certainty requested by industry,” that does not seem to be the case. The main change in the final rule was to delete the reverse chronological order (RCO) provision which called for issuing decommissioning orders to the most recent predecessor first. Instead, BSEE may continue to issue decommissioning orders arbitrarily.

While deleting the RCO provision may be advantageous for the regulator, and in some cases for the public, claiming that the decision provides certainty for industry is quite a stretch. BSEE may continue to issue a decommissioning order to anyone in the ownership chain, whether the company was a recent lessee or one that had owned the lease decades ago. Original or early lessees may be held liable for decommissioning old facilities regardless of subsequent damage, modifications, or neglected maintenance.

The absence of a defined procedure for issuing decommissioning orders may also expose BSEE to new legal challenges, particularly in cases where a company has not held the lease for decades. A 1988 letter from the Director of the Minerals Management Service to Amoco (attached below) explicitly relieves the assignor (predecessor) of decommissioning liability after the lease has been assigned. A revised bonding rule published on May 22, 1997 reversed that policy, but decommissioning liability for leases assigned prior to the 1997 rule may still be very much in question.

Another concern is the split jurisdiction for decommissioning between BSEE and BOEM. The financial, land management, operational, and environmental aspects of decommissioning are inextricably intertwined and attempts to divide these responsibilities between two bureaus with separate regulations is a prescription for gaps, overlap, inconsistency, inefficiency, disputes, and confusion. Decommissioning should be regulated holistically, not with separate “BOEM-only” and “BSEE-only” regulations.

Finally, wind facility decommissioning may prove to be even more challenging given the higher facility density and economic uncertainties. The regulatory regime needs to be clearly established early in the development phase.

Related posts:

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This comment from Save LBI (Long Beach Island, NJ) on BOEM’s Renewable Energy Modernization Rule (proposed) highlights an important regulatory policy consideration:

Promoting the offshore wind program is a very high BOEM priority. The bureau is charged with deploying 30 gigawatts of offshore wind energy capacity by 2030, which requires extensive advocacy. However, BOEM is also a core regulator for offshore wind projects, and the concern is that their regulatory role could be compromised by their advocacy priorities.

Per Notice to Lessees 2023 N-01, which arguably should have been published for public comment given its regulatory significance, BOEM has retained important responsibilities for wind project development and operations. These include review and approval of construction and operations plans, site assessment plans, and general activities plans. BOEM may also exercise enforcement authority through the issuance of violation notices and the assessment of civil penalties.

BOEM exists because in 2010 the Administration wanted to separate the OCS program’s leasing (sales/advocacy) and safety (regulatory/enforcement) functions. The intent was to avoid conflicting missions (or the appearance thereof) in the post-Macondo era. (More on this in an upcoming post.)

Ironically, the Save LBI comment describes BSEE as “a distinct unit within BOEM.” That may seem to be the case, but BSEE is actually a separate bureau in the Department of the Interior.

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An interesting study published in the Proceedings of the National Academy of Sciences (PNAS) was brought to my attention by leading offshore energy historian Tyler Priest. The study used airborne observations and emissions reports to measure the carbon intensity (CI) of Gulf of Mexico oil and gas production. Their CI measure is grams of CO2 equivalent of greenhouse gas emissions per megajoule of energy produced.

The authors conclude that inventory emissions of CO2 (as reported to BOEM) “are generally consistent with observations from our aircraft survey, suggesting that combustion is well represented in the federal inventory.

However, that is not the case for methane (CH4) emissions which are underestimated by the Federal inventories. As summarized in the chart below, deepwater facility methane emissions are consistent with the reported inventories, but shelf emissions in State and Federal waters differ significantly.

Comments:

  • As previously discussed, the lower CI for deepwater production is entirely consistent with expectations. When the most modern 5% (57) of GoM platforms are producing 93% of the oil and 76% of the gas, their CI should be impressive (which indeed it is).
  • As summarized using ONRR data, more gas-well gas was vented from 2015-2021 than was flared, which is not what you want from a GHG standpoint. Gas wells are predominantly at shallow water facilities, many of which are not equipped with flare booms.
  • Oil-well gas, most of which is produced at deepwater platforms, is flared rather than vented by a ratio of approximately 4 to 1.
  • About 15 years ago, the Federal government (MMS) considered requiring that older production platforms be retrofitted with flare booms, but safety, space limitations, and cost considerations precluded such a regulation. Instead, additional flaring/venting limits, and measurement and reporting requirements were imposed.
  • One bad actor may have been a major contributor to the shelf methane emissions observed during the study’s observational flights. That company entered into bankruptcy proceedings. Presumably those issues have been resolved and more rigorous monitoring and enforcement practices have been implemented. I’ll be looking at the 2022 ONRR flaring and venting data for evidence of such improvement. The remainder of the 2022 data should be available in May.
  • The subject study’s only observational measurements were in August 2020. Followup airborne measurements would be helpful.
  • The study only considered production emissions. Shelf facilities are primarily natural gas producers and would thus have a lower relative CI when consumed.
  • When will updated BOEM GOADS flaring and venting data be available? The latest data are for 2017 (cover below)? Are GOADS data being compared with ONRR and World Bank data?

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  • Deepwater (>1000′) activity continues to dominate, accounting for 61% of the well starts.
  • Not a single company drilled both shelf and deepwater wells.
  • While shelf facilities currently account for only about 7% of GoM oil production, 1122 of the 1179 remaining platforms are on the shelf and they account for 24% of GoM gas production, most of which is environmentally favorable nonassociated gas.
  • Two companies, Arena and Cantium, accounted for 75% of the shelf well starts. Excluding the CCS bids, Arena and Cantium were the most active shelf bidders in Sale 279. Arena bid alone on 7 blocks. Cantium was the high bidder on 5 blocks. (Focus Exploration was high bidder on 4 shelf blocks and was “outbid” by Exxon for High Island 177.)
  • One company, Shell, accounted for 39% of the deepwater well starts
  • One of BP’s exploratory wells (drilled subsequent to Sale 257) was in Green Canyon 821, immediately south of GC 777, the block that BP/Talos bid $1.8 million for in Sale 257. That bid was rejected by BOEM. In sale 259, BP was the sole bidder for GC 777, and their bid was only $583,000, less than 1/3 of their Sale 257 bid. Perhaps the GC 821 exploratory well reduced the value of GC 777? Will this lower bid now be accepted?
DW explDW devshelf explshelf dev
Anadarko51
Arena22
BOE14
BP23
Byron2
Cantium20
Chevron3
Contango2
Cox2
Eni25
EnVen5
Greyhound2
Hess2
Kosmos1
LLOG31
Murphy4
QuarterNorth2
Shell259
Talos28
Walter1
Woodside31
Gulf of Mexico well starts during 2022 and the first quarter of 2023

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  • 313 blocks receiving bids
  • 353 bids
  • 32 companies submitting bids
  • High bids totaled $263.8 million

Exxon doubled down on their strategic CCS bidding; their only bids (69 in total) again appeared to be solely for carbon sequestration purposes. As previously noted, acquiring tracts for CCS purposes is not authorized in an oil and gas sale. Arguably, these bids should be rejected.

The other super-majors, BP, Chevron, and Shell, were active participants as were many independents.

It was good to see BOEM Director Liz Klein announcing bids. This shows respect for the OCS oil and gas program.

It was also good to hear that Red Willow, a native American corporation, was again an active participant.

More to follow.

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Comments on 2022 oil production:

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BOEM’s new procedures, which have been published for public comment, seem reasonable. However, it would be helpful to learn more about the testing of the new methodology. (See the quote below). Further, would the rejected Sale 257 bid have been accepted? What was the LBCI for that tract? Would any accepted Sale 257 bids have been rejected? Would the outcome of other sales have been affected?

After a 2-year comprehensive technical review of the delayed valuation methodology, BOEM intends to replace the delayed valuation methodology with a statistical lower bound confidence interval (LBCI) at a 90 percent confidence level as a decision criterion for accepting or rejecting qualified high bids on tracts offered in OCS oil and gas lease sales. Following extensive testing of the alternative approaches using both historical and current lease sale tract data and existing BOEM cash flow simulation models, BOEM determined that the LBCI approach would be the most appropriate substitute for the delayed valuation methodology. The LBCI is a statistical concept that captures the lower bound of a range of values encompassing the true unknown mean of the risked present worth of the resources at the time of the lease sale. The LBCI incorporates the uncertainty of parameters unique to the valuation of each OCS oil and gas lease sale tract. These parameters may include, but are not limited to, subsurface characterization of reservoir properties, cost and timing of the development, and projected revenues. Unlike the delayed valuation methodology, the LBCI approach would not require that BOEM estimate the time delay period between the current OCS oil and gas lease sale and the projected next lease sale. As such, BOEM finds the LBCI to be a better approach going forward.

Federal Register

Below is the flow chart for the new procedures. It’s interesting that high bids on nonviable tracts are automatically (and gratefully) accepted! 😉

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