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Archive for the ‘Offshore Energy – General’ Category

Newfoundland: Hibernia keeps on chugging!

Posted in Canada, Offshore Energy - General, tagged , , , , , on June 11, 2026| Leave a Comment »

I had the pleasure of visiting the Hibernia gravity-based structure while it was still under construction in Bull Arm, Newfoundland (photo). This pioneering facility, where Newfoundland’s offshore production began in Nov. 1997, continues to impress.

In April, Hibernia posted its highest monthly production since August 2021 – 3.1 million barrels or 103,000 bopd. Exxon attributes the production growth to a recent 6-well drilling program. The Hibernia field has produced more than double the original resource estimate of 520 million barrels.

Offshore Newfoundland’s total April production, increased to 9.4 million barrels, with a sharp increase in the value of production (see figure below). This is the highest monthly production level for the province since March 2020, and the second highest monthly production value on record, only behind July 2008.

Meanwhile, production at Hebron, another Exxon GBS structure, has reached record levels this year (chart below). The facility is producing more than 5 million bbls/month.

Finally, Suncor’s decision to refurbish the Terra Nova FPSO and resume production may be paying off given production levels of ~1 million bbls/month.

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AI to geophysicists: “You’re fired!”😉

Posted in Offshore Energy - General, drilling, tagged , , , , , , , on June 10, 2026| Leave a Comment »

Offshore Guyana seismic line

Oil Now Guyana reports that an Exxon artificial intelligence model built using Guyana’s offshore seismic data was able to identify already-discovered crude oil accumulations with a 90% success rate.

Neil Chapman, Exxon: “…in Guyana, we have built an agent, a model…which if we give it the seismic data that we’ve run and we say, go find the crude oil, it can find all the crude oil that we’ve already found with a 90% success rate.”

(Note: Humans are also great at identifying discoveries after the fact 😉. How many false positives were there?)

Chapman said the company has also used artificial intelligence to review well data from across the industry.

“We have analyzed the well data from 50,000 wells that have been drilled in the industry all over the world, 50,000,” Chapman said. “It would have taken us 15 years to do that analysis. We’ve done it in a matter of weeks.” 

Despite the many advances in exploration technology over the years, one caveat remains unchanged: “We don’t know if they’re going to be successful or not until you drill a hole, you can never be sure,” Chapman said. 

AI should enhance not just geophysical interpretations, but all aspects of offshore exploration and production including site surveys, well planning and construction, drilling, well control, structure designs, production and pipeline monitoring, and safety management. Hopefully, the net result will be increased production at lower cost with improved safety and environmental performance, and that the workforce will not be reduced, but will become more efficient.

Stunning picture taken offshore Guyana

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West of Shetland – let’s go!

Posted in energy policy, Offshore Energy - General, UK, tagged , , , , , , , , on June 9, 2026| Leave a Comment »

North Sea pioneer JL Daeschler is among those lamenting the sad state of UK exploration and development, commenting that he is “green” with envy of Norway’s long term management of their oil and gas resources.

Researchers at the University of Aberdeen may be showing the way for exploitation of the West of Shetland area’s estimated 4.7 billion bbls of oil equivalent (boe). They are advocating a tailored management regime for this challenging area. Per the researchers:

“West of Shetland is not a depleted frontier – it is a technically demanding but strategically important energy province,” said Nick Schofield, Professor of Igneous & Petroleum Geology at the University of Aberdeen. “Our study highlights the remaining oil and gas potential in the area, which could extend the life of the UK’s oil and gas sector.”

John Underhill, Aberdeen University’s Director for Energy Transition said: “Failing to develop these domestic resources risks increasing the UK’s dependence on imports, with implications for emissions, costs, jobs, tax revenues and energy security.” 

The researchers argue that a “one-size-fits-all” approach to UKCS taxation fails to reflect the unique risks and costs associated with West of Shetland exploration, appraisal and development. As a result, they say projects that are technically viable may remain economically marginal under current conditions.

The University of Aberdeen paper (linked) advocates a tailored regime that would:

  • Recognize higher exploration and development costs
  • Account for increased geological and operational risk
  • Encourage investment in challenging projects
  • Enable tie-backs to existing infrastructure that would provide energy security, tax revenues, retain jobs and be better for the global climate than importing liquified natural gas (LNG), which carries a higher carbon footprint.
  • Support the development of already identified prospects within licensed areas

Rosebank update:

The West of Shetland area includes the controversial Rosebank project (map above), which has yet to receive environmental consent from the UK govt. Following a court ruling, Equinor (operator) was given permission to proceed with the project, including preparatory engineering and construction work, but no production is allowed pending final govt approval.

The PetoJarl Rosebank Floating Production Storage and Offloading (PFSO) vessel recently left its dry dock in Norway and has arrived in the West of Shetland basin. The vessel will undergo commissioning to be ready for production by the end of the year.

PetroJari Rosebank FPSO

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Lackluster ANWR sale. Implications for Arctic offshore leasing?

Posted in Alaska, energy policy, Offshore Energy - General, tagged , , , , , on June 6, 2026| Leave a Comment »

The Canning River, seen here in 2018, flows from the Brooks Range into the Beaufort Sea along the western edge of the Arctic National Wildlife Refuge. The river marks the boundary between the refuge, which is managed by the U.S. Bureau of Land Management, and state land on the North Slope. Results of an oil lease sale that offered 58 tracts in the refuge’s coastal plan drew bids on five tracts. The highest-dollar bid was for a tract right at the Canning River edge of the refuge’s border with state land. (Photo by Lisa Hupp/U.S. Fish and Wildlife Service)

Yesterday’s mandated One Big Beautiful Bill sale in the Arctic National Wildlife Refuge turned out to be a one-on-one competition between an Alaskan independent and a State agency! Only 5 of the 58 tracts received bids, and the high bid was $1.7 million.

The competitors:

  • HEX Energy, an Alaskan independent: 4 bids, 2 high bids
  • Alaska Industrial Development and Export Authority (AIDEA), the state government’s economic development agency: 5 bids, 1 high bid

Full sale results

The implications for Arctic offshore sales are not good, but oil companies can be fickle, and opinions and investment strategies are subject to change, especially in the Arctic.

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As expected, Secretaries Burgum and Wright visited Sable’s onshore facilities today

Posted in California, energy policy, Offshore Energy - General, tagged , , , , , on June 5, 2026| Leave a Comment »

Sable posts

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The events that led to the Strategic Petroleum Reserve also drove the rapid expansion of the offshore program

Posted in Alaska, California, energy policy, Georges Bank, Gulf of Mexico, Offshore Energy - General, tagged , , , , , , , , , on June 5, 2026| 2 Comments »

Nothing tilts public opinion more than high gasoline prices, or worse yet shortages! Hence the 1975 legislation establishing the SPR, the massive SPR drawdown in 2022, and this year’s withdrawals.

Looking back to the halcyon days of the US offshore program, it was the gas lines in the 1970s that drove the remarkable and rather unlikely growth in the program during the Carter Administration (1977-1981). A few highlights from those four years:

  • 15 lease sales including 3 offshore Alaska, 3 in the Atlantic, and 1 offshore California
  • Drilling activity in all 4 regions: GoM, Pacific, Alaska, and Atlantic
  • Natural gas discovery in the Mid Atlantic (Hudson Canyon Unit)
  • North, Mid, and South Atlantic District offices for permitting and inspections
  • 5300 well starts including 97 in water depths > 1000′
  • 314 new platforms including Cognac, the world’s first platform in > 1000′ of water

Perhaps unthinkable today, the Governor of Massachusetts from 1979-1983, Ed King, was a strong supporter of offshore drilling. Absent that support, the exploratory drilling on Georges Bank would probably have never occurred. /s/ Nostalgic Old Man 😉

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Informative Sable update; Burgum and Wright to visit

Posted in California, energy policy, Offshore Energy - General, Regulation, tagged , , , , , , , , on June 4, 2026| Leave a Comment »

SYU near-term workover plan; estimated reserve additions exceed production.

Those who have been following the Santa Ynez Unit saga should take a look at Sable’s informative PowerPoint update (attached). The presentation includes reserve data, well operation plans, production forecasts, financial and legal updates, and regional energy supply information.

Also, Sable CEO Jim Flores has announced that Energy Secretary Wright and Interior Secretary Burgum will be visiting the project this week. Transportation Secretary Duffy was also expected, but he will not be attending.

Sable-Offshore-Corp-Investor-Presentation_2026-06-01Download

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USCG: Monetizing the Benefits of Avoided Oil Spills in the Maritime Environment

Posted in energy policy, Offshore Energy - General, oil spill response, Regulation, tagged , , , , on June 3, 2026| Leave a Comment »

The subject IEc report for the US Coast Guard may be of interest to BOE followers. The Coast Guard is requesting comments by July 28, 2026. You can download the full report (129 pages) here.

The report is intended to update the Coast Guard’s methodology for estimating the cost savings resulting from spill prevention regulations. The paragraph pasted below is a good summary of the objective.

The offshore industry could benefit from this report, because the estimated cost of spills >100 gallons is reduced, dramatically so when the DWH/Macondo blowout is excluded (see the second table below). That reduction would support regulatory reform initiatives, and could thus generate some controversy.

My main concern is that there is only a single distance-from-shore category for offshore spills (see text below). The natural resources damage from a spill 3 miles from shore will almost always be much greater than from an equivalent volume spill 100 miles from shore.

The single-offshore-category issue is illustrated in the 2 tables pasted below. The first table presents a summary of expert opinions on the smallest spill size that is likely to result in measurable natural resource damages. The mean response to Question 3 (offshore) is 7782 gallons. A spill of that size occurring 3 miles from shore is much more likely to result in resource damage than a spill originating 50 or 100 miles from shore.

In the second table, note the new methodology results in the same cost estimates for large nearshore/coastal spills as for offshore spills. Again, this is presumably because there is only a single offshore category.

The public comments on this report should be interesting.

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2025 was not a record year for OCS oil production; however Jan. 2026 set a monthly record

Posted in Gulf of Mexico, Offshore Energy - General, tagged , , , , on June 1, 2026| Leave a Comment »

BOEM Press Release: “The Bureau of Ocean Energy Management announced today the critical role of offshore leasing, resource assessment and long-term planning in supporting record oil production on the U.S. Outer Continental Shelf, which reached more than 714 million barrels in 2025.”

Was 2025 a record OCS oil production year? No, 2025 came very close, but barring belated revisions, 2019 retains the record.

Did 2025 oil production exceed 714 million barrels? Not even close according to the US Energy Information Administration (EIA), which reported a final OCS production total of 692.6 million barrels for 2025. The Office of Natural Resources Revenue (ONRR), to whom all production data must be reported, has yet to post their final 2025 numbers, but they are normally very close to the EIA totals. Also, ONRR’s fiscal year totals do not suggest calendar year production in excess of 700 million barrels. BOEM’s announced 714 million barrel CY 2025 total is more than 60,000 bopd higher than the actual EIA CY or ONRR FY daily averages, and even exceeds the total posted in BOEM’s data center.

See the 2019 and 2025 oil production totals in the table below. The BOEM 2025 numbers appear to be erroneous.

Oil Production (includes condensate in all cases)20192025
Gulf of America OCS
ONRR692,681,303not yet posted; fiscal year total was
681,760,441
EIA692,831,000692,634,000
BOEM693,004,577707,847,938
All OCS including Pacific & Alaska
ONRR697,610,350not yet posted; fiscal year total was
686,544,402
EIA697,217,000697,020,000
BOEM697,933,210712,543,491

On the plus side, per EIA’s latest update, Jan. 2026 was a record production month for the Gulf. January’s ave. production of 2.060 million bopd surpassed the Aug. 2019 ave. of 2.044 million bopd.

Barring significant tropical storm shut-ins over the next 6 months (hurricane season starts today!), a production record in 2026 seems like a good possibility.

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57 years after the Santa Barbara blowout, production continues at Platform A

Posted in California, decommissioning, Gulf of Mexico, Offshore Energy - General, Regulation, well control incidents, tagged , , , , , on May 29, 2026| Leave a Comment »

Santa Barbara Channel, Dos Cuadras Field platforms (L to R): Hillhouse, A, B, and C; Antandrus Wiki photo

As part of the recent focus on decommissioning and financial assurance requirements, I looked at borehole data for platforms A, B, and C on Lease OCS-P 0241 in the Santa Barbara Channel. Platform “A” is where a well blew out in 1969, permanently scarring the US offshore program. Observations:

  • There are 140 completed and unplugged wells on the 3 platforms. None of the wells on these platforms have been permanently plugged and only one is temporarily abandoned.
  • The latest available production information (2024 data) indicates ave. daily oil production of 3791 bopd for the lease, including 1901 bopd from Platform A, the highest production for any platform in the region in 2024.
  • 41 of the lease’s completed (unplugged) wells are on Platform A.
    • The number of these wells that are currently producing is not publicly available.
    • 30 of the completed Platform A wells were drilled prior to 1985.
    • The blowout well was the 5th well drilled from platform A. All 4 of the wells drilled prior to the 1/28/1969 blowout are still unplugged:
      • well A-20: spudded on 11/19/1968, reached total depth on 12/2/1968
      • well A-41: spudded on 11/27/1968, TD on 12/19/1968
      • well A-25: spudded on 12/18/1968, TD on 12/28/1969
      • well A-38: spudded on 1/12/1969, TD on 1/24/1969
      • Note how quickly the wells were drilled. The wells were shallow (2299-4051′ true vertical depth), and the operator (Union Oil) saved time by omitting a casing string. (This decision was a root cause of the blowout and thus changed history 😡)

Lease documents and regulations at 30 CFR § 250.1710 require that all wells be permanently plugged within one year of lease termination. For leases like 0241 that are still active, 30 CFR § 250.1711 stipulates that BSEE will order a well to be permanently plugged if the well poses a hazard to safety or the environment, or is not useful for lease operations and is not capable of oil, gas, or sulphur production in paying quantities. In the Gulf of America Region, the policy is to require wells that have not been used in the past 5 years to be permanently plugged. Allowing old wells to remain unplugged is neither prudent nor consistent with the regulations.

Platform A during 1969 blowout

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