Norway’s Improved Recovery Award recognizes companies that apply new methods and technology to increase oil and gas recovery on the Norwegian Continental Shelf. This year’s winner is Okea, an operator of mid- and late-life assets.Okea seeks to extend field life, explore for new resources, and unlock value from existing infrastructure.
“The end is also a good start”
Okea is using geosteering technology and real-time data integration to drill and target record length horizontal wells. As a result, the production of marginal resources has become profitable. Their systematic exploration has also increased oil and gas reserves for both Brage and Draugen. The estimated life of these platforms has thus been extended to 2040.
BragaDraugen
The Brage field in the North Sea was discovered in 1980, and production began in 1993. The Draugen field in the Norwegian Sea was discovered in 1984, and started production in 1993. Impressively, the expected recovery rate has increased from 67.3 percent in 2019 to 72.6 percent in 2026.
This is an excellent awards concept that should be considered for US offshore operations, where companies in the Gulf, Pacific, and the Beaufort Sea/Cook Inlet are making special efforts to increase ultimate recovery from mature fields.
World Bank global flaring estimates are now derived from 3 satellites carrying NOAA VIIRS detectors. The increased number of observations improves the precision and accuracy of the flare locations and volume estimates.
The World Bank (WB) Global Gas Flaring Tracker is the only worldwide flaring data source. Offshore and onshore data are segmented, so offshore flaring can be considered separately for each country.
The WB estimates that 21600.03 million cu m (762.5 bcf) of gas were flared at offshore locations worldwide in 2025. This is an increase from 2024 when the total offshore flaring volume was 21159.91 million cu m.
The flaring totals for prominent offshore producers are entered in the table below. Also included are the largest offshore flares for each country.
Unsurprisingly, Norway led the pack in minimizing offshore flaring. Their total of 36.11 million cu m (1.3 bcf) is very impressive for such a large producer. The US offshore total of 160.95 cu m (5.7 bcf) is also quite respectable relative to production.
At the other end of the scale are Iran – 3329 million cu m (118 bcf), Nigeria – 2566 (91 bcf), Angola – 2300 (81 bcf), and Mexico 2068 (73 bcf). These 4 countries accounted for nearly half of all 2025 offshore flaring. They were also massive offshore flarers in 2024: Iran – 3753 million cu m, Nigeria – 2867, Angola – 2040, and Mexico – 2223.
If both onshore and offshore flaring are considered, Iran flared 29931 million cu m in 2025. That equates to 1.057 trillion cu ft!
2025 WB flaring total million cu meters
largest flare
largest flare volume
Angola
2300.26
Lombo East
862.02
Australia
268.36
Santos
61.89
Brazil
969.16
Albacora Leste
118.93
Canada
145.12
Terra Nova
95.83
China
535.56
Weizhou 12-1
68.26
Congo, Rep.
788.98
Kitina
384.12
Gabon
368.91
Tchatamba Marin
37.46
Ghana
351.81
Sankofa East
184.97
Guyana
227.38
Yellowtail
164.06
Indonesia
292.16
Belida
30.84
Iran
3329.19
Foroozan
1360.09
Libya
313.78
Bouri
74.07
Malaysia
1459.32
Kasawari
205.8
Mexico
2067.62
Akal
386.44
Nigeria
2565.88
Oso
308.37
Norway
36.11
Balder
6.38
Qatar
688.19
Ras Laffan LNG
54.65
Russia
227.27
Yuri Korchagin
82.07
Trinidad
87.66
Atlantic LNG
53.23
UK
234.08
Penguins
22.94
US
160.95
NA*
22.77
*The WB lists the field name for the largest US flare as NA. The lat/long for the Whale deepwater platform in the Western Gulf matches the identified flare location (26.22 lat., -94.67 long.)
The WB tracker identifies the Gulf of America facilities with the highest flaring volumes. The 2025 list is pasted below. Repeat top ten Gulf flarers from 2024 were Vito (14.55 million cu m in 2024), Pompano (11.68), and Lucius (5.72).
The WB lists the field name for the largest US flare as NA. The lat/long for the Whale deepwater platform in the Western Gulf matches the identified flare location (26.22 lat., -94.67 long.)
Per the WB tracker, the Terra Nova FPSO, offshore Newfoundland, was the top North American offshore flarer by a considerable margin (data for Canada below). Terra Nova was also the top flarer in 2024 (95.56 million cu m).
The location of the only flare identified offshore California corresponds with that of the Dos Cuadras field in the Santa Barbara Channel. The estimated 2025 flaring volume was 0.10 million cu m.
The WB flaring tracker is an excellent data source, but doesn’t capture vented gas and likely understates the total volume flared. The WB estimated that 160.95 million cu m (5.68 bcf) were flared at US offshore facilities in 2025. This compares with the 9.7 bcf (flaring and venting) and 8.0 bcf (flaring only) totals derived from ONRR data (chart below). The flaring difference is not surprising given that the WB numbers are dependent on satellite imagery and the ONRR data are from mandated/audited production reports. A previous comparison also showed that the WB flaring estimates are significantly lower than the ONRR numbers. From a regulatory oversight perspective, this is rather reassuring given that the reverse (WB>ONRR) would imply serious reporting issues.
The oil and gas industry is crucial for Norway and for Europe. The government is today announcing new exploration areas in the APA (Allocations in Predefined Areas) to further develop the petroleum sector, so that it can continue to create great value for the community, lay the foundation for good jobs throughout the country, ensure our common welfare and contribute to Europe’s energy security and safety, says Prime Minister Jonas Gahr Støre.
Kudos to Norway for the strong, unequivocal announcement. Consistent acreage offerings are important in sustaining offshore production:
Allocations in Predefined Areas (APA) are an annual licensing round that covers the best-known exploration areas on the continental shelf. Through the APA scheme, oil companies gain predictability regarding access to exploration acreage, which is important for a long-term industry such as the petroleum industry. After more than 50 years of exploration activity, the APA scheme today covers the majority of the area that is opened and available on the Norwegian continental shelf.
Equinor has cut planned investments in renewable energy by roughly EUR 3.5bn for 2026–2027, while the company maintains and expects growth in oil and gas production.
Perhaps the premium for climate virtue signaling has shrunk, and Equinor, like other energy giants, is making a prudent business decision for its shareholders, which include the Norwegian govt.
Meanwhile, what are the implications for Equinor’s offshore wind investments in the US? Equinor’s embattled Empire Wind project is probably too far along to reverse course. Their Central Atlantic (Lease 0557) and California (Lease 0563, Atlas Wind) may be a different story. However, buyback negotiations would be complicated by the Empire Wind situation, and perhaps by the Norwegian government’s 2/3 ownership. On the other hand, Equinor is a significant oil and gas leaseholder in the Gulf of America, so they would have ample options for investing wind lease rebates.
Some of us remember when the UK and Norway were friendly North Sea oil and gas rivals – competing to be tops in production, technology, safety, and even promotion at conferences like OTC. Take a look at the production chart below and note the UK’s production leadership followed by the extraordinary decline.
So what happened? Norway may have better oil and gas resource potential, but that is only part of the story. While Norway was managing their offshore sector to succeed, the UK was seemingly managing theirs to fail.
Norway’s North Sea remains far more active because the government promotes exploration through predictable licensing, cost-recovery incentives, and a focus on adding resources to existing infrastructure.
The UK, by contrast, has shifted toward limited development and decommissioning. In recent years, the UK’s windfall tax on oil and gas profits was raised to 78 percent, and licences for exploratory drilling in new areas were banned.
The stark policy differences are evident in the exploration drilling numbers – sustained drilling vs. sustained decline (charts below).
Norwegian Continental Shelf Directorate dataUK NSTA data:exploration wells spudded with original wellbore intent classified as “exploration” (offshore UK includes geological sidetracks).
“Claim: Hundreds of North Sea licences have delivered only “36 days of gas”, proving new drilling does not improve energy security.
“This actually proves the opposite. In a mature basin like the North Sea, you need a constant churn of investment and new licences just to stand still. Without ongoing activity, decline accelerates and import dependence rises faster. That is why countries like Norway continue to license and develop new projects. Their approach allows them to replace what they produce and manage decline more effectively. In industry terms, this is measured through the reserves replacement ratio – how much new resource is added compared with what is produced. Norway consistently produces a higher reserves replacement ratio than the UK. Over the 5 year period 2019-2024, through exploration, Norway replaced on average 46% of the reserves that were produced, the UK however, replaced just 14%.“
“Today, the North Sea still provides over half of the UK’s oil and gas needs. With the right conditions, we can sustain production for longer, reduce exposure to imports, and manage the transition more securely. Without licensing and investment, the UK simply becomes reliant on overseas supplies sooner – regardless of demand falling.“
Claim: 93% of UK North Sea oil and gas has already been extracted, so new drilling makes little difference.
“Official projections show several billion barrels of oil and gas still expected to be produced between now and 2050. Independent analysis commissioned by OEUK shows that, with the right conditions, significantly more could be delivered from known projects and discoveries.“
“And even beyond that, the UK’s own regulator identifies large volumes of oil and gas in:
approved projects
existing discoveries
areas that haven’t yet been developed“
Pressure is mounting on the UK govt to approve the Rosebank and Jackdaw projects and ease exploration restrictions. Will it work?
Norway has always been ahead of the pack when it comes to worker accommodations. Gulfaks B (pictured) is a concrete, gravity-based platform installed nearly 40 years ago, but the living quarters and amenities are updated and first class. A Gulfaks B worker provides a tour in the video embedded below.
Ekofisk was Norway’s first commercial oil discovery in 1969, with first production in 1971. Another redevelopment phase could extend production to 2050 and beyond. This is a good example of how technology and reservoir management can extend field life indefinitely. Finite resources are not really finite.
Ekofisk production history; water injection began boosting production in 1987. The expected final recovery factor for Ekofisk is now estimated to be >50%.
ConocoPhillips and partners have approved the redevelopment of three gas and condensate fields depicted below — Albuskjell, Vest Ekofisk, and Tommeliten Gamma. Better well placement and the use of horizontal well technology will increase resource recovery.
The $1.8 billion project consists of four new subsea templates and 11 production wells tied back to the Ekofisk complex. First production is planned towards the end of 2028. Recoverable gas and condensate reserve additions are estimated at between 90 million and 120 million barrels of oil equivalent.
If you ever get to Stavanger, be sure to visit the Petroleum Museum! HIghly recommended!
The Snorre field is in 300-380m of water in the North Sea ~200 km west of Floro.
According to Reuters and others, Equinor will no longer pursue electrification of Snorre A and B, Heidrun, Aasgard B, and Kristin platforms, but still plans to proceed with projects at Grane and Balder fields.
A number of BOE posts since Jan. 2022 have questioned Norway’s electrification strategy for offshore platforms. Our reasons:
Most offshore platforms produce sufficient gas to support their power demands
Assuming gas that is not used to power a platform is marketed and consumed elsewhere, the net (global) reduction in CO2 emissions from electrifying offshore platforms is negligible. (Perhaps there is actually a small increase in net emissions given the power required to transport the gas to markets and the emissions associated with onshore power generation).
Offshore power demands are highly variable, especially when drilling operations are being conducted.
Gas turbines are reliable, and capable of responding to variable power demand. Excess generation capacity is typically provided.
Power from shore increases the cost of platform operations and could decrease ultimate recovery of oil and gas resources.
Per NPD, electrification of the shelf will increase electricity prices for onshore consumers and increase the need for onshore facility investment.
Gas turbines or diesel generators are still necessary to satisfy emergency power needs at the platforms.
Long power cables are vulnerable to damage (accidental or intentional), as are onshore power stations.
The reliability, cost, and cable vulnerability concerns have clearly been validated. The reality is that powering distant platforms from shore increases operating costs, safety risks, and onshore electricity prices with no net environmental benefit.
It also seems rather hypocritical for a major natural gas exporter to prevent offshore operators from powering their platforms with gas produced at their platforms.
Equinor (2/3 Norwegian govt owned) is increasing its position in Ørsted (50.1% Danish govt owned). Given the ownership structure, public money is at risk for both countries.
The comments below are from a DN Norway article. They were made by CEO Torgrim Reitan after Equinor announced that the company will contribute NOK 10 billion (USD 1 billion) in Ørsted’s special share offering.
“We want a closer partnership with Ørsted. We are two leading companies in offshore wind, and we believe a closer collaboration could create significant value for both Ørsted’s and our own shareholders.”
“This industry is now going through its first real crisis. That makes it quite clear what’s needed. We know a lot about this from oil and gas. What often happens in such times is consolidation.”
“We want a closer partnership with Ørsted. We are two leading companies in offshore wind, and we believe a closer collaboration could create significant value for both Ørsted’s and our own shareholders.”
“In recent weeks, we’ve had conversations with Ørsted management, and we’ve also had conversations with the Danish state. But the discussions have primarily been with Ørsted.”
“Ørsted is in a difficult situation right now. For us, as an industrial and long-term owner, it’s important to be supportive and helpful in such a situation. That’s why we’re putting in nearly a billion dollars.”
“This is a difficult decision, because clearly a lot of equity capital needs to be raised, but we have a fundamental belief in the industry, and also in the company. Ørsted’s underlying portfolio is a strong one.”
“Going forward, this will increase our debt ratio somewhat—maybe by about two percentage points. But we’re starting from a very low debt ratio. So we can manage this within our financial framework. As for capital distribution in 2026 and beyond, we will remain competitive.”
Meanwhile, Equinor is the only major oil company that remains invested in US offshore wind energy. Equinor’s Empire Wind project continues to be highly divisive.
Along with other charges, the attached complaintasserts that awarding a wind lease to Norway’s Equinor, violates the Outer Continental Shelf Lands Act (OCSLA):
As an agency or instrumentality of Norway, Equinor cannot receive a lease on the Outer Continental Shelf for offshore wind turbine development or generation of electric power.
While other elements of the complaint appear to have merit, the charge against Norway does not. Here’s why:
US subsidiaries of foreign companies have long held leases under the OCS Lands Act.
Equinor US Wind is the US subsidiary holding the wind lease.
Equinor USA E&P holds interests in OCS oil and gas leases in the Gulf of America. BOEM credits 548,389 barrels of oil production to Equinor for 2023.
Chinese state-owned CNOOC has been an oil and gas lessee in the Gulf of America.
US subsidiaries of Shell and BP, both foreign corporations, are the top 2 producers in the Gulf. Although not government owned, there is nothing in OCSLA that distinguishes between US subsidiaries of private and govt owned companies. Woodside (Australia) and Eni (Italy) are also important Gulf producers.
The plaintiffs second count (excerpt below) seems to have more merit. The bulk of the filing pertains to this count.
BOEM never completed its “necessary review”, see Stop Work Order, April 16, 2025, and, instead, reinstated the Empire Wind work permit on May 19, 2025 without any explanation or finding, stating as follows: On April 16, 2025, the Bureau of Ocean Energy Management issued a Director’s Order to Empire Offshore Wind LLC to halt all ongoing activities related to the Empire Wind Project on the outer continental shelf. That Order is hereby amended to lift the halt on activities during the ongoing review.
The complaint goes on to discuss the reasons why the plaintiffs believe the review was indeed necessary and should have been conducted.
Bud's Offshore Energy (BOE) 