For all the oil and gas industry haters and doubters out there, some interesting news surfaced recently. According to a new analysis by S&P Global Commodity insights, the methane intensity of oil and gas production in the Permian basin—an area responsible for about half of U.S. oil production and one-fifth of natural gas output—declined more than 50% during the 2022-2024 period, Fig. 1. That’s right—by more than half.
The improvement, said S&P, can be attributed to more efficient operations, better equipment and the utilization of A.I. and other advanced technologies. Implementation of these items led to reductions across all observable plume rates (large and small).
The latest data for the year 2024 show the methane emissions intensity of upstream oil and gas operations in the Permian to be 0.44% per boe—a 29% reduction from the previous year. Absolute annual 2024 methane emissions decreased by 21.3 Bcf, a 22% decline from the previous year. Given that methane is a potent greenhouse gas, the reduction was equivalent to 11.1 million tons (MMT) of carbon dioxide emissions avoided (100-year equivalency factor of 28*).
Since the end of 2022, absolute emissions have declined by 55.2 Bcf, equivalent to 28.8 MMT of carbon dioxide emissions avoided. To put the numbers into perspective, the 28.8-MMt CO2e reduction in absolute methane emissions over a two-year period was:
Roughly equivalent to emissions from the nation of Lithuania;
15% greater than the emissions avoided by all electric vehicles sold in the United States and the European Union;
50% greater than the total emissions reductions in the UK power sector;
Equal to 2.2 billion trash bags recycled, instead of landfilled;
Greater than the greenhouse gas emissions from cooling and heating all the homes in California. (This editor likes how S&P framed that last factoid.)
The findings of the latest “analysis for Permian upstream methane,” produced in partnership with methane management firm Insight M, are based on high-frequency observation data that include more than 500 high-resolution aerial surveys, covering 90% of the basin's production to provide the most accurate, basin-wide estimate of methane emissions.
"Access to reliable methane data is crucial to provide critical context to benchmark and allow companies to differentiate themselves and truly compete on carbon," said Kevin Birn, Head of the Center for Emissions Excellence, S&P Global Commodity Insights. "Whereas data quality still varies globally, improvements in access to reliable observation data in places like the Permian are leading the way and allow us to more credibly measure the impact of emissions mitigation efforts."
The overflight data to which S&P has access showed reductions across all observable plume rates, from large (1,000+kg/hr) to small (10kg/hr) emissions. The continued emissions reductions occurred despite the relatively low commercial value of gas in the region, where the annual average price for those selling gas on the spot market was just $0.02 in 2024, due to oversupply and a lack of takeaway capacity. Consequently, the lost economic value (i.e. had the gas been captured and sold) from fugitive emissions equated to just 0.002% of total 2024 hydrocarbon revenues, the analysis reveals.
The analysis attributes the continued breadth and depth of the emissions decline to ongoing improvements in equipment, as well as increasing deployment of new technologies—from A.I.-driven analysis of operational data to on-the-ground sensors, aircraft overflights and satellites—that make it possible to detect leaks with greater speed and accuracy.
"Methane emissions management is being increasingly normalized as part of field operations. It's becoming a standard and accepted part of the field staff's responsibilities," said Raoul LeBlanc, Vice President, Global Upstream, S&P Global Commodity Insights. "At the same time, oilfield service manufacturers are now producing equipment that includes emissions reduction as an important feature, and operators are increasingly utilizing A.I. and machine learning to not only 'find and fix' but 'predict and prevent' emissions."
Challenging the herd mentality on LNG. Argent LNG Chairman and CEO Jonathan Bass got people’s attention with an Aug. 9 blog on his firm’s website that also was mentioned on his LinkedIn page. Entitled “Egypt’s Summer LNG Rush: Why ‘Abundant Supply’ Is an Illusion,” Bass’ blog basically says that while the industry may be congratulating itself that global LNG supply is bountiful on paper, the reality may be noticeably different, with shortages either occurring or possible in a number of places worldwide.
Bass says that for years, energy analysts have promised that LNG would be plentiful in 2024 and beyond. He cites firms like Wood Mackenzie and Poten & Partners painting a picture of strong supply, softer prices, and a market “where utilities could buy gas without breaking a sweat.” However, he says that Egypt’s “frantic summer scramble” shows a very different reality, which he believes is something that “the rest of the world may soon be forced to live through.”
In June, notes Bass, a sudden halt in gas flows from Israel put Egypt’s electricity supply on edge. The Egyptian General Petroleum Corporation (EGPC) reacted quickly, issuing a tender for 14 fuel oil shipments—or about 700,000 tons—to keep the country’s power plants running through August. Obviously, fuel oil is dirtier and more expensive than natural gas, but it’s reliable when one has a problem. The order, analyzed by Bass, looked like a prudent backup plan.
Then came a total switch. Weeks later, Egypt canceled about half of those fuel oil cargoes—more than 2.2 MMbbl—after accessing large LNG volumes from trading firms like Trafigura Group and Vitol Group. As Bass notes, “from the outside, it might have looked like a confident switch in strategy. Inside, it was a high-stakes race to find cargoes before the summer heat pushed power demand beyond the grid’s limits.”
In a section entitled, “The Realities Behind ‘Abundance,’” Bass says Egypt has frequently turned to LNG when domestic output falls short, Fig. 2. But until this summer, the country had just one operational floating storage and regasification unit (FSRU): the Hoegh Galleon in Ain Sokhna.
The situation changed in July, when the Energos Eskimo and Energos Power were added, tripling the country’s import capacity almost overnight. “Without that expansion,” says Bass, “Egypt might have been stuck with its fuel oil plan—and a much dirtier, costlier summer energy mix. But even then, timing was critical. “Cargoes had to be negotiated fast, with shipping schedules and port logistics lining up perfectly,” explained Bass. “This was not a slow, calculated shift; it was a scramble that happened to succeed.”
Fuel oil still lingers, notes Bass, as “it remains an insurance policy for Egypt’s power sector,” but unloading it isn’t simple. He says the ports of Alexandria, Suez and Ain Sokhna “have limited infrastructure for large-scale unloading and storage.” As evidence, he points to earlier this summer, when three tankers—Clean Sanctuary, Seasalvia, and Dhan Laxmi—sat offshore for weeks, unable to gain permission to unload their cargoes. “Delays like that mean fuel oil can’t always step in quickly, and LNG needs to arrive at just the right moment to fill the gap,” explains Bass.
And while, on paper, global LNG production is rising, Bass says Egypt’s experience is “a warning written in summer heat,” and it shows how delicate “abundance” can be in the real world. “Supply only matters if it’s in the right place, at the right time, with the infrastructure to handle it,” he says quite accurately.
“Egypt went from net LNG exporter to net importer in less than a year,” continues Bass. “And while its scramble was triggered by regional gas disruptions, the same pressures—extreme weather, shipping bottlenecks, competing bids from other countries—could hit anywhere.”
As for why this might matter beyond Egypt, Bass says that for now, wealthier nations with long-term contracts and strong port facilities may feel “insulated.” But with LNG demand rising fast, thanks to Europe shifting away from Russian supplies, Asia’s surging power needs, and electrification of new industries, that scenario may not last.
In the future, says Bass, “even the best-prepared buyers will face moments when cargoes are scarce, prices spike, and delivery windows close overnight. Egypt’s summer isn’t an anomaly — it’s an early signal of how quickly a ‘plentiful’ market can turn tight.”
The lesson to learn, according to Bass, is that “LNG abundance on spreadsheets doesn’t guarantee energy security at the shoreline—not for Egypt, and not for anyone else.”
Trump administration commissions first U.S. Arctic Icebreaker in more than 25 years. On Aug. 11, the U.S. Coast Guard officially commissioned the USCGC Storis (WAGB 21) in Juneau, Alaska. The commissioning of this polar icebreaker marks a crucial step in President Donald Trump’s directive to rebuild the Coast Guard, which will include historic investments through the One Big Beautiful Bill Act.
This vessel is the Coast Guard’s first polar icebreaker acquired in over 25 years. As a medium polar icebreaker, Storis expands the U.S. operational presence in the Arctic and will support Coast Guard missions while awaiting delivery of the new Polar Security Cutter class.
The Coast Guard operates the nation’s fleet of icebreakers to assure access to, and protect, U.S. sovereign interests in the polar regions. As the nation’s third polar icebreaker, Storis was acquired to bolster these operations, providing near-term operational presence and supporting national security in the Arctic as a bridging strategy for Arctic surface presence. Additional Coast Guard icebreakers will be acquired through investments in the One Big Beautiful Bill Act, which is the largest single funding commitment in Coast Guard history.
From an oil and gas perspective, acquisition of this icebreaker will help to safeguard potential U.S. reserves in the Arctic, as well as serve as a deterrent to other nations encroaching on U.S. territory. It is no secret that Russia continues to invest in Arctic oil and gas projects, particularly in the Barents Sea and on the Yamal Peninsula. In addition, Norway continues to award exploration licenses in the Arctic. So, the new U.S. icebreaker will help to remind these nations that the U.S. has a stake in the Arctic, too. WO
IN THIS ISSUE
Special focus: Offshore Operations. Our cup runneth over with seven articles in this issue. Three of these features are deepwater-oriented, including two from our Deepwater Development Conference earlier this year. One of these two is an adaptation by HMH’s Brian Piccolo of that firm’s presentation on a full-scale test rig validating the benefits of an electric BOP. Also adapted from a Deepwater Development presentation is the article on “Strategies for improved topsides weight management for offshore facilities” by Wood plc’s Angelique Spies. The third article oriented to deepwater activity is from Siemens Energy, as three company authors look at the technology advancements inside one of the world’s largest FPSOs, the Mero-3, operated by TotalEnergies offshore Brazil. Other features include a piece from Aize on contextual digital twins for FPSOs; an interview with Armoda Vice President Tim Murphy on modular construction for offshore facilities; an Opensealog article on embedding efficiency in offshore support vessels; and a piece by ABS about the role safety advances are playing in the rebound of offshore activity.
Exploration technology: Transforming the seismic interpretation landscape. As explained by CMG Group’s executive vice president, seismic interpretation is about to get faster, smarter, and more connected. CMG Seismic Solutions is uniting Bluware, Sharp Reflections, and SeisWare into an open ecosystem that removes workflow bottlenecks, enables real-time collaboration, and transforms seismic insight into faster, more confident drilling and development decisions.
ESG/CCS: Repurposing offshore wells for carbon capture. As detailed by an Oil States author, oil and gas operators continue to seek ways to reduce their carbon footprint, and carbon capture and storage (CCS) is gaining traction. With CCS, carbon dioxide emissions are captured, transported to CO2 storage sites, and injected into geological formations deep underground, where they remain indefinitely. Repurposing mature offshore wells could significantly boost the scale and cost-effectiveness of CCS.
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