Advertise your business here! 🚀

Contact us now and get more customers.

Smiling woman thumbs up

Oil Production: Nigeria Exits 2024 On A High, But It’S Still A Struggle

oil-gas
Jan 13, 2025
Article Source LogoAfrica oil + gas report
Africa oil + gas report

By Macson Obojemuinmoin

Nigeria’s crude oil output in December 2024 was 1,484,585Barrels of oil per day (BOPD), a slight drop from the November 2024 by ~1,000Barrels of Oil per Day. The figure is higher than the October 2024 production by over 150,000BOPD, signaling a continuing end of year uptick. Crude and condensate output for December 2024, was 1,667,560BOPD, compared with 1,690,485BPD in November 2024; condensate output dipped by 22,905BPD from November to December.

What’s noteworthy about the November and December 2024 output, either as oil or both oil and condensate is that they were the highest liquid hydrocarbon production since April 2021.

Still this is a low in historical context; the 2024 (January to December) crude oil and condensate average turns out to be 1, 548,538BPD (or 1.59MMBPD), but the country’s crude oil output alone  in 2020 was 1.828MMBPD and in 2019 it was 2.1MMBPD. Between 1999 and 2020 it had ranged from as ‘low’ as 1.89MMBPD and as high as 2.53MMBPD.

Some of the clearest indications that the country is on a course to bolster hydrocarbon output  include Seplat’s takeover of the assets of Mobil Producing Nigeria, which had not drilled a single well for the last three years, and the finalisation of  the sale of Shell Petroleum Development Company’s operated Oil Mining Leases to Renaissance Africa. But the “surge” that is expected from these events will not happen in a hurry. Shell’s Final Investment Decision to develop Bonga North field as a tie back to the Bonga Main’s FPSO will only bring in the liquids (anticipated peak output of 110,000BOPD) from 2028 at the earliest.

For the second consecutive month, the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) published, in its footnote, what it calls the highest and the lowest output in the course of the month. In the footnote for December 2024, it says that “the Lowest and Peak Production in December were 1.57MMBOPD and 1.79MMBOPD respectively”. That footnote is clearly a reference to the argument that erupted in November 2024 over NNPC’s claims that the country produced 1.8MMBPD of crude and condensate and the official figure from the NUPRC turned out to be 1.69MMBPD for that month. The NUPRC doesn’t have to help NNPC clean its act: Simple statistics would indicate that if the average output over the course of 31 days is 1.667MMBPD, a 1.79MMBPD data point would be an extreme outlier, if the lowest figure is 1.57MMBPD. This is, using NUPRC’s own figures.

 

Share Your Insights!

Publish your articles, reach a global audience, and make an impact.

4
Recent Comments
JD
JD
John Doe1 week ago
Lorem ipsum, dolor sit amet consectetur adipisicing elit. Repudiandae, exercitationem earum hic numquam assumenda voluptatem velit nemo consequatur sed, ullam, iste porro vitae eius placeat dolorum dolore dolor! Inventore, eius! Lorem ipsum, dolor sit amet consectetur adipisicing elit. Repudiandae, exercitationem earum hic numquam assumenda voluptatem velit nemo consequatur sed, ullam, iste porro vitae eius placeat dolorum dolore dolor! Inventore, eius! Lorem ipsum, dolor sit amet consectetur adipisicing elit. Repudiandae, exercitationem earum hic numquam assumenda voluptatem velit nemo consequatur sed, ullam, iste porro vitae eius placeat dolorum dolore dolor! Inventore, eius! Lorem ipsum, dolor sit amet consectetur adipisicing elit. Repudiandae, exercitationem earum hic numquam assumenda voluptatem velit nemo consequatur sed, ullam, iste porro vitae eius placeat dolorum dolore dolor! Inventore, eius!
100
JD
John Doe1 week ago
Lorem ipsum, dolor sit amet consectetur adipisicing elit. Repudiandae, exercitationem earum hic numquam assumenda voluptatem velit nemo consequatur sed, ullam, iste porro vitae eius placeat dolorum dolore dolor! Inventore, eius! Lorem ipsum, dolor sit amet consectetur adipisicing elit. Repudiandae, exercitationem earum hic numquam assumenda voluptatem velit nemo consequatur sed, ullam, iste porro vitae eius placeat dolorum dolore dolor! Inventore, eius! Lorem ipsum, dolor sit amet consectetur adipisicing elit. Repudiandae, exercitationem earum hic numquam assumenda voluptatem velit nemo consequatur sed, ullam, iste porro vitae eius placeat dolorum dolore dolor! Inventore, eius! Lorem ipsum, dolor sit amet consectetur adipisicing elit. Repudiandae, exercitationem earum hic numquam assumenda voluptatem velit nemo consequatur sed, ullam, iste porro vitae eius placeat dolorum dolore dolor! Inventore, eius!
100
JD
John Doe1 week ago
Lorem ipsum, dolor sit amet consectetur adipisicing elit. Repudiandae, exercitationem earum hic numquam assumenda voluptatem velit nemo consequatur sed, ullam, iste porro vitae eius placeat dolorum dolore dolor! Inventore, eius! Lorem ipsum, dolor sit amet consectetur adipisicing elit. Repudiandae, exercitationem earum hic numquam assumenda voluptatem velit nemo consequatur sed, ullam, iste porro vitae eius placeat dolorum dolore dolor! Inventore, eius! Lorem ipsum, dolor sit amet consectetur adipisicing elit. Repudiandae, exercitationem earum hic numquam assumenda voluptatem velit nemo consequatur sed, ullam, iste porro vitae eius placeat dolorum dolore dolor! Inventore, eius! Lorem ipsum, dolor sit amet consectetur adipisicing elit. Repudiandae, exercitationem earum hic numquam assumenda voluptatem velit nemo consequatur sed, ullam, iste porro vitae eius placeat dolorum dolore dolor! Inventore, eius!
100

Related News You might want to check out

Output At Iraq’S Largest Gas Field Up 75% Since 2017
ARABIAN GULF BUSINESS INSIGHT
Output At Iraq’S Largest Gas Field Up 75% Since 2017Production from Khor Mor, Iraq’s largest non-associated gas field, has reached 500 million barrels of oil equivalent, according to a joint statement issued by Abu Dhabi-listed Dana Gas and Sharjah-based Crescent Petroleum. The two companies, each owning a 35 percent stake in Pearl Petroleum consortium, the operator of the gas field in the Kurdistan Region of Iraq (KRI), said daily production hit 525 million standard cubic feet per day of natural gas in early March. This is a rise of 75 percent since 2017, in addition to 15,200 barrels per day of condensate, and 1,070 tonnes per day of liquefied petroleum gas. The Khor Mor plant provides the fuel for 75 percent of KRI power generation, enabling power for more than six million Iraqis in the KRI and other governorates. Total investment in the project exceeds $3.5 billion, leading to the creation of 20,000 direct and indirect jobs. The companies said that work on KM-250 project, which will boost capacity by a further 50 percent, has accelerated with expected completion in the first quarter of 2026. Moreover, progress on the $1 billion expansion project, which includes $250 million in financing from the US Development Finance Corporation, is in the advanced stage, with completion expected ahead of time. The consortium has also commenced work to unlock Khor Mor’s additional hydrocarbon potential and plan the new phases of the field’s development. The consortium partners will inveset $160 million to drill three wells, install an extended well test facility and construct associated enabling infrastructure. Pearl Petroleum is considering new financing options and has enlisted DNB Markets, part of DNB Bank ASA, and Pareto Securities AS as joint lead managers and bookrunners to arrange fixed-income investor meetings. New senior secured bond issue with a five-year tenor may follow, subject to market conditions. The proceeds will be used to finance near-term growth opportunities and general corporate purposes. Pearl Petroleum was founded in 2009 as a consortium with Dana Gas and Crescent Petroleum as joint operators with a 35 percent equity share each, and with Austria’s OMV, Hungary’s MOL and Germany’s RWE subsequently joining the consortium with a 10 percent share each. AGBI registered members can access even more of our unique analysis and perspective on business and economics in the Middle East. Register For Free Already registered? Sign in I’ll register later
oil-gas
03 April 2025
Kenya To Launch Oil & Gas Licensing Round In September
EnergyCapitalPower
Kenya To Launch Oil & Gas Licensing Round In SeptemberKenya is set to initiate its first oil and gas licensing round in September 2025, offering ten exploration blocks to investors, according to a recent announcement from Energy and Petroleum Cabinet Secretary Opiyo Wandayi. The ten blocks were selected using geoscientific data to ensure a transparent allocation process, with the government providing comprehensive seismic surveys, geological reports and well data. This follows a restructuring of Kenya‘s petroleum exploration blocks to align with global standards, offering flexible Production Sharing Contract terms and tax incentives. In addition to the licensing round, Kenya is investing in key infrastructure projects to bolster oil and gas exploration and development. Notable projects include the expansion of Lamu Port under the LAPSSET Corridor Program and the Lamu-Lokichar pipeline.
oil-gas
03 April 2025
Hungary-Serbia Oil Pipeline Could Meet Needs By 2028
Pipeline Technology Journal
Hungary-Serbia Oil Pipeline Could Meet Needs By 2028A planned oil pipeline from Hungary to Serbia could meet all of Serbia's crude oil needs by 2028, Hungarian Foreign Minister Peter Szijjarto said Wednesday. Construction of the pipeline, with an annual capacity of 4-5 million tons, could begin late this year or early in 2026, Szijjarto said at a news conference with Serbian Energy Minister Dubravka Dedovic Handanovic. Ties between Serbia and Hungary have strengthened in recent years, and their leaders, Hungarian Prime Minister Viktor Orban and Serbian President Aleksandar Vucic, maintain strong relations with Russia. The two countries agreed in 2022 to build a pipeline to supply Serbia with Russian Urals crude via the Soviet-era Druzhba oil pipeline despite the ongoing efforts by the European Union (EU) member states to wean themselves off Russian energy supplies. While the European Union has sought to reduce reliance on Russian energy supplies since Russia's 2022 invasion of Ukraine, landlocked Hungary still receives about 80% of its natural gas and most of its crude oil from Russia. Hungarian oil company MOL, which has refineries in Hungary and Slovakia, presented a feasibility study for the pipeline Wednesday, Szijjarto said, which was approved by both countries. "Currently, Hungary's entire natural gas import needs can be met through Serbia. And with this new investment, Serbia's entire crude oil import needs will be met through Hungary," Szijjarto said, adding that the project would provide “a significant” energy security to both countries. The pipeline project includes Hungary increasing the capacity of oil flow between the Ukraine border and its Danube refinery and building a new 190-kilometer (118-mile) pipeline from the refinery to the Serbian border. Szijjarto said the cost of the capacity expansion and the construction of the new pipeline to the border would be about 130 billion forints ($350.33 million). Serbia, which is not a member of the EU, also relies on Russian crude supplies and has been working to find a solution to end Russian ownership in its NIS oil company since the United States imposed sanctions on the Russian oil sector in January.
oil-gas
03 April 2025
Opec+ Shocks Market With Plans To Boost Oil Supply, Driving Down Prices
World Oil
Opec+ Shocks Market With Plans To Boost Oil Supply, Driving Down Prices(Bloomberg) – For most of this decade, the OPEC+ alliance has been the world’s most stalwart defender of high oil prices. In just a few moments this week, that role reversed dramatically. In a video conference on Thursday, the coalition of crude producers led by Saudi Arabia and Russia was expected to simply remind errant members to respect their output limits, ahead of rubber stamping its existing plan to gradually raise production. Instead they delivered a major shock — increasing supply by three times the planned amount in May in what delegates described as a deliberate effort to drive down prices to punish the group’s cheats.  After many months of excess production from Kazakhstan and Iraq, Saudi Energy Minister Prince Abdulaziz bin Salman reached the limit of his patience, delegates said, asking not to be identified because the talks were private. The larger-than-expected May output hike would just be an “aperitif” if those countries didn’t improve their performance, the prince said on the call.  Prince Abdulaziz’s gambit — a marked break from years of urging OPEC+ to remain cautious in adding supplies — illustrates the toll taken on the alliance as its effort to balance global oil markets drags on far longer than initially envisioned. For some observers, it stirs echoes of the price war that briefly erupted between OPEC+’s leaders during the 2020 pandemic. Crude was already reeling from the onslaught of trade tariffs announced by U.S. President Donald Trump the previous day, and the surprise addition of 411,000 barrels a day by OPEC+ in May turbo-charged the rout. Brent futures sank as much as 7.3%, the most in two years, to below $70 a barrel.  The timing of the announcement by the Organization of the Petroleum Exporting Countries and its allies seemed unlikely to be a coincidence, and group delegates and crude traders alike speculated that Riyadh deliberately sought to maximize the bearish effect. Astana has infuriated Riyadh by ramping up output at a new project to expand its giant Tengiz oil field, in partnership with international majors like Chevron Corp. Even as the country pledged to conform better with its OPEC+ limits, in February its output was a hefty 300,000 bpd above target.  Iraq, another habitual quota cheat, has reduced output closer in line with its quota in recent months, but has shown little sign of making the compensation cuts it promised to atone for past over-production.  While delegates said they were surprised at the outcome of what was supposed to be a routine conference call, they were supportive of measures to end cheating and everyone backed the proposal from Saudi Arabia and Russia to make a larger supply hike in May.  “This is about coaxing Kazakhstan and Iraq to improve their compliance in a balanced way,” said Bob McNally, president and founder of Rapidan Energy Advisers LLC and a former White House energy official.
oil-gas
03 April 2025
African Oil Giants Advance Ipo Plans To Attract Investment
World Oil
African Oil Giants Advance Ipo Plans To Attract InvestmentIn a bid to bolster investment and competitiveness within Africa's oil and gas sector, national oil companies (NOCs) in Nigeria and Angola are progressing with long-anticipated initial public offerings (IPOs). These IPOs are poised to attract significant global investment, providing much-needed capital to enhance production capabilities, improve infrastructure and foster long-term growth. This move reflects a broader trend of African nations seeking to modernize and diversify their energy sectors, signaling a shift toward greater transparency and accountability in state-owned enterprises, while also positioning the continent as a more attractive investment destination in the global energy market.The Nigerian National Petroleum Company (NNPC) has announced it is in the final stages of preparing for its IPO, as mandated by the Petroleum Industry Act of 2021. Chief Finance and Investor Relations Officer, Olugbenga Oluwaniyi, stated that the company is engaging with prospective investor relations executives and investment banks to facilitate the process. This initiative aims to transition NNPC into a fully commercial entity capable of independently raising capital without reliance on state funds. The IPO is expected to enhance transparency, improve corporate governance and attract both domestic and international investors to Nigeria's oil and gas industry.Similarly, Angola's NOC Sonangol has reaffirmed its intention to proceed with an IPO, offering up to 30% of its shares to the public. This partial privatization is designed to generate capital to support exploration and production projects, positioning Sonangol as a more competitive player in the global upstream market. CEO Sebastião Gaspar Martins emphasized that the company is undertaking necessary internal preparations to initiate this process, aligning with Angola's broader strategy to diversify its economy and attract foreign investment.The planned IPOs of NNPC and Sonangol represent a transformative shift in Africa's oil and gas industry. By opening up to public investment, these companies aim to enhance operational efficiency, foster transparency and stimulate economic growth. The influx of capital from these IPOs is anticipated to fund critical infrastructure projects, advance technological innovation and expand exploration activities across the continent. While historically NOCs have been primarily state-controlled entities with limited outside investment, this move signals a growing recognition of the need for private sector involvement to drive sustainable development and foster more dynamic, competitive markets.Moreover, these developments assure global investors that African nations are committed to creating conducive environments for investment, characterized by improved regulatory frameworks and corporate governance standards. This shift is expected to increase the continent's competitiveness in the global energy market, attracting further investments into Africa's rich hydrocarbon resources.
oil-gas
03 April 2025
Bp Starts Production From Cypre Gas Field, Trinidad And Tobago
World Oil
Bp Starts Production From Cypre Gas Field, Trinidad And Tobagobp Trinidad and Tobago (bpTT) today confirms its Cypre development has safely delivered its first gas. Cypre is one of bp’s 10 major projects expected to start up worldwide between 2025 and 2027, announced as part of bp’s reset strategy to grow the upstream. Production from Cypre will make a significant contribution towards the 250,000 barrels of oil equivalent per day (boed) combined peak net production expected from these 10 projects.  Cypre is bpTT’s third subsea development. It will comprise seven wells tied back into bpTT’s existing Juniper platform. At peak, it is projected to deliver around 45,000 boed (approximately 250 million standard cubic feet of gas a day). The first phase of the development – four wells – was completed at the end of 2024. The second phase is expected to commence in the second half of this year. “Our focus is on consistent execution and safe delivery of major projects like Cypre. The second of 10 major projects across our global portfolio that we expect to start up by 2027, Cypre is also the first of a series of projects we will be bringing online in Trinidad to deliver gas to the nation and add value for bp.” “Our focus is on consistent execution and safe delivery of major projects like Cypre," said William Lin, EVP gas and low carbon energy. "The second of 10 major projects across our global portfolio that we expect to start up by 2027, Cypre is also the first of a series of projects we will be bringing online in Trinidad to deliver gas to the nation and add value for bp,” said William Lin, EVP gas and low carbon energy. “Cypre is another key milestone in bpTT's strategy to maximize production from our shallow water acreage using existing infrastructure," said bpTT president David Campbell. "The project not only reinforces our commitment to maintaining production but also plays a crucial role in satisfying our existing gas supply commitments. Cypre represents a significant investment in the country's energy sector. We are proud to be part of this journey and look forward to continuing our collaboration with Government and other stakeholders to unlock Trinidad and Tobago's energy future." Cypre is bp’s second major start-up of 2025, following the start of production from the second development phase of the Raven field, offshore Egypt. The project meets bp's expected returns from upstream projects and is fully accommodated within bp’s capital expenditure plans.
oil-gas
03 April 2025
Poland To Expand Gas Pipeline Capacity To Ukraine By 2026
Pipeline Gas Journal
Poland To Expand Gas Pipeline Capacity To Ukraine By 2026(Reuters) — Poland's Gaz-System will upgrade a metering station on the gas pipeline to Ukraine to boost gas transit capacity towards its eastern neighbor, the company said on Thursday. The upgrade of the Hermanowice station will be ready at the end of 2025 or early 2026, the company told Reuters. The upgrade, set to cost 8 million zloty ($2.12 million), follows talks with Ukraine's gas transmission network operator. Ukraine wants to import large volumes of U.S. LNG via Germany, Greece, Lithuania and Poland ahead of the heating season, after Russian shelling left the country with storage almost empty. Kyiv also wants to expand gas transport corridors. The Polish link allows shipment of up to 7 million cubic meters a day, a fraction of Ukraine's needs. Naftogaz, Ukraine's state gas producer, and Polish refiner Orlen last month agreed to cooperate in the LNG sector. Naftogaz bought 200 million cubic meters (mcm) of LNG from Orlen, including one cargo of U.S. LNG. The available capacity on the upgraded pipeline will depend on supply directions, the use of other export routes and the demand of power plants and storage facilities in southern and south-eastern Poland, Gaz-System said. ($1 = 3.7820 zlotys)
oil-gas
03 April 2025
Tariff Fight Could Rattle U.S. Lng Exports, Push Gas Prices Higher
Pipeline Gas Journal
Tariff Fight Could Rattle U.S. Lng Exports, Push Gas Prices Higher(Reuters) — U.S. natural gas prices are already up by around 80% from a year ago, but are due for a fresh jolt from the knock-on effects of the latest round of trade tariffs imposed by the U.S. government on goods entering the country. Regardless of how and when the new tariffs kick in, the U.S. gas market stands to be impacted as exports of gas in the form of LNG look set to become a bargaining chip in any ensuing trade maneuvers. For those nations looking to narrow their trade surplus with the U.S. or avoid being hit with future tariffs, commitments to scale up purchases of U.S. LNG are an effective means of speedily rebalancing the trade ledger in favor of the U.S. At the same time, countries impacted by new tariffs that are already regular buyers of U.S. LNG may threaten to cut those purchases as part of possible reprisals. That means that in any event, the U.S. gas market looks set to be buffeted by the impending trade turbulence, with gas exporters, utilities, households and businesses all likely to be impacted by the upcoming swings in gas trade volumes and prices. Big Stakes The U.S. shipped out nearly 12 billion cubic feet of LNG per day in 2024, according to the U.S. Energy Information Administration, which cemented the U.S.' position as the top exporter of the fuel for the second year running. The LNG shipments brought in more than $30 billion, and so represented significant earnings for both the firms that shipped the gas and for the U.S. Treasury. The largest single market for U.S. LNG exports in 2024 was the Netherlands, which accounted for around 11% of total volumes, according to ship tracking data from Kpler. France, Japan, South Korea and India were the next largest buyers of U.S. LNG, while China, Turkey, Spain and the United Kingdom were also notable buyers. Tipping the Balance As the U.S. has run up trade deficits with nearly all of those countries, the administration of U.S. President Donald Trump is threatening to impose steep tariffs on the goods they sell to the U.S. And as all those countries are already notable buyers of U.S. LNG, it is likely that they will consider stepping up those purchases as part of any trade tactics designed at easing relations with the Trump administration. Other countries with steep trade surpluses with the U.S., including Vietnam, are also likely to mull increasing U.S. LNG imports as part of tariff negotiating efforts. Plan B LNG is also likely to feature as part of any countermeasures deployed by nations who want to hit back at the U.S. for raising tariffs in the first place. China and several European nations including Germany have vowed to respond to the planned tariff hikes, and are likely to view LNG as a means to inflict revenue damage on the U.S. without risking too much self-harm in the process. Qatar, Australia and Malaysia all also supply LNG to global customers, and so will likely be able to replace any lost U.S. volumes at relatively short notice while U.S. LNG exporters may struggle to quickly find alternate buyers. Gas Flow Impact Regardless of which way LNG export volumes trend in the wake of the latest U.S. tariff moves, the domestic natural gas market will feel the effects. If most U.S. trade partners opt to dial up LNG imports in an effort to close trade gaps, that will trigger more gas demand at LNG export terminals and tighter supplies for other gas users. That in turn will likely put fresh pressure on U.S. utilities which rely on natural gas for roughly 40% of electricity production. Several utilities have already cut gas use in favor of higher coal-fired power generation this year in response to the higher domestic gas prices. If gas prices climb further on the back of renewed strength in LNG exports, that may accelerate the uptake of coal instead of gas, and result in a swell in U.S. power emissions that could accelerate climate change. On the other hand, if most trade partners opt to cut U.S. LNG purchases as part of tariff reprisals, demand from LNG export terminals could drop and result in greater gas supplies for domestic users, and lower gas prices. Most likely, there will be a mixed response among trade partners in the LNG arena, with some nations dropping their LNG purchases while others increase them. Over time, those volume swings could offset each other and result in total LNG volumes being largely unaffected by the end of the year. But over the near term, sudden changes to LNG order flows will feed back into the domestic gas market and trigger potentially wild swings in available supplies and prices. For gas market participants, the trick will be to position themselves to exploit any advantageous price moves, and take cover during bouts of potentially damaging market action. The opinions expressed here are those of the author, a market analyst for Reuters.
oil-gas
03 April 2025
Abb Digitizes Indianoil’S 12,400-Mile Pipeline Network With Nationwide Scada System
Pipeline Gas Journal
Abb Digitizes Indianoil’S 12,400-Mile Pipeline Network With Nationwide Scada System(P&GJ) — ABB has delivered a full suite of automation and digital solutions to support Indian Oil Corporation Ltd.’s (IndianOil) vast cross-country pipeline network, one of the largest in the world. Spanning more than 20,000 kilometers (12,427 miles), IndianOil’s pipeline network transports around 125 million metric tons of oil and 49 million metric standard cubic meters of gas annually, playing a critical role in India’s energy infrastructure. At the center of the upgrade is ABB’s SCADAvantage digital platform, part of the company’s ABB Ability suite. The platform will power IndianOil’s Centralized Pipeline Information Management System (CPIMS), designed to monitor and manage the nationwide network in real time. The project scope included the design, engineering, and commissioning of cloud-hosted SCADA systems with built-in cybersecurity and disaster recovery capabilities. ABB will also provide a 10-year service contract to help unify IndianOil’s entire pipeline system under CPIMS and ensure long-term support. “CPIMS has been envisioned to address the complexities associated with the maintenance and operation of cross-country pipeline networks,” said Senthil Kumar N, Director (Pipelines) at IndianOil. “By leveraging technology, this project aims to eliminate manual operations and enhance the efficiency, productivity and availability of the pipeline networks. At IndianOil, we value our enduring partnership with ABB, which spans over a decade.” ABB was awarded the project contract in February 2024 and delivered its integrated solutions within a year. Commissioning of the system is currently underway.
oil-gas
03 April 2025
Permian Oil Growth Slows As U.S. Shale Hits Geological Limits
Pipeline Gas Journal
Permian Oil Growth Slows As U.S. Shale Hits Geological Limits(Reuters) — U.S. oil producers are grappling with geological limits to production growth as the country's top oilfield ages and produces more water and gas and less oil - and may be nearing peak output. The Permian basin was the centerpiece of the shale revolution that began nearly two decades ago and spurred the U.S. to become the world's top oil producer, stealing market share from the Organization of the Petroleum Exporting Countries (OPEC) and other top producers. Slowing output growth and rising costs would make it difficult for oil producers to pump more and bring down oil prices to consumers, as envisioned by U.S. President Donald Trump in his "drill, baby, drill" mantra. The Permian is pumping 6.5 million barrels per day (bpd), a record level and nearly half the all-time high 13.5 million bpd of crude that the U.S. produced in December. But the Permian is flagging. Since the widespread introduction of hydraulic fracturing, the technique that enabled the shale revolution in the mid-2000s, thousands of wells have perforated the Permian and fractured the rock to extract oil and gas. Relentless drilling to reach record production has exhausted the core of the Permian's two largest sub-basins: nearly two-thirds of the Midland formation's core has been drilled, and slightly more than half in the Delaware formation, according to data from analytics software company Novi Labs. "We've never been in a position before where we were on the back-half of the inventory story of the Permian basin," Novi Labs head of research Brandon Myers said. That has rung alarm bells across the industry, as drilling in the fringes of the basin, on lower-quality prospects, means less oil output and more water and gas. At conferences and on earnings calls, analysts and executives are discussing the issue with a growing sense of urgency. "We think that between 2027 and 2030 it's likely that the U.S. will see peak production, and after that some decline," Occidental CEO Vicki Hollub said earlier this month at an industry conference in Houston. Harold Hamm, founder of shale producer Continental Resources and a key figure in the U.S. shale boom, agrees. He said at the same conference that U.S. oil production is already beginning to plateau. For now, output is still rising. Shale executives expect oil output growth from the Permian to slow by around 25% this year to 250,000 to 300,000 bpd. The government estimates higher growth, of about 350,000 bpd, but even that would be the smallest increase in the basin's oil output since the COVID-19 pandemic. Tapped Out? Producers are dealing with rising levels of water and gas per barrel produced, which is slowing growth and driving up costs. In the past decade, gas output in the Permian has increased eight-fold, while crude production rose six-fold, according to a review by the U.S. Energy Information Administration. The gas-to-oil ratio (GOR) has risen steadily from around 3,100 cubic feet of natural gas per barrel of oil produced (cf/b), or 34% of total production in 2014, to 4,000 cf/b, or 40%, in 2024, the EIA said. The EIA classifies wells with a GOR of more than 6,000 cf/b as gas wells, not oil wells. Energy companies market the gas. But that raises costs - they must treat it, and build or lease space on pipelines to deliver it. The Permian's geology adds another layer of complexity: drilling in the basin on average produces four barrels of water for each barrel of oil, while in other basins the ratio is closer to one-to-one, oilfield water analytics firm B3 Insight data showed. The water-to-oil ratio can rise to as high as twelve-to-one from wells drilled in the fringes of an oilfield, said Christine Guerrero, a veteran petroleum engineer who is a strategic advisor to asset manager Octane Investments. "The Permian is much of a water and gas business with oil as a secondary product there," Chris Doyle, CEO of Civitas Resources, one of the newest entrants to the Permian basin, said on the company's fourth-quarter earnings conference in February. Producers dispose of the water by pumping it back into the ground, but regulators in recent years have cracked down on reinjection due to its links to increased seismic activity. The issue has not yet forced producers to abandon drilling plans, but will ultimately drive costs higher, said Shannon Flowers, director of crude and water marketing at producer Coterra Energy. "There are only so many places to drill, inject and frac, and as that goes down, you still have to find a home for the rest of your produced water," he said. At a four-to-one water-to-oil ratio, that translates to water disposal costs of about $2 for each barrel of oil produced in the basin. At 12-to-1, it would be nearly $8 a barrel. Breakevens to drill a new well in the Permian averaged $65 a barrel in 2024, up $4 on the year, according to the Federal Reserve Bank of Dallas. Less desirable acreage breakevens can hit $96, per Novi Labs, some $26 above where a barrel of crude is trading. Never Bet Against The Permian The shale revolution has beaten expectations for growth again and again as new techniques and technologies allowed producers to wring more oil out of the same rock. Now, executives are talking about the potential for artificial intelligence to cut drilling costs further and fuel new gains in production. The Permian has produced more than could ever have been imagined when the first well was drilled more than a century ago. Conventional production peaked in the 1970s, nearly 30 years before the shale revival. Even as producers face higher gas and water output, the sheer volume of oil they can pump justifies production, said Clint Barnette, director of geology at Indigo Energy Advisors, a unit of advisory firm Efficient Markets. "It's how the Delaware basin stays economic even though those wells produce six to seven times the amount of water as they do oil," he said, referring to the Permian's second biggest sub-basin. Producers such as Chevron and Coterra have been recycling their produced water for future fracking, helping to reduce transportation and other disposal costs. And in mid-March, the Environmental Protection Agency (EPA) said it will look into ways to ease recycling of produced water for artificial intelligence data center cooling, irrigation, fire control, and other needs. "I would never bet against the Permian," Barnette said.
oil-gas
03 April 2025
Processing Raw Biogas Into Renewable Natural Gas Suitable For Pipeline Blending
Pipeline Gas Journal
Processing Raw Biogas Into Renewable Natural Gas Suitable For Pipeline BlendingBy: Alice Fu, Senior Global Product Manager, Emerson In these days of growing efforts to reduce the effects of climate change, the agriculture sector is often cited as a major source of greenhouse gases (GHGs), including methane (CH4) and nitrous oxide (N2O), with those two sources combined accounting for about 10% of global non-carbon dioxide (CO2) emissions. Much of this comes from manure, but also from crop waste if left to deteriorate in the open. Using anerobic digestion in an enclosed system to process crop waste (Figure 1) allows collection of the resulting biogas, and its use of CH4, as a fuel source, while preventing its release to atmosphere. Capturing biogas is not a new concept and has been used extensively by large agricultural sites as a means to deliver essentially free fuel as a byproduct of normal waste processing. Generally, this biogas has been used within a given facility to power equipment suited to handling minimally processed gas, such as boilers or engine-generator sets. But this raw biogas right out of the digester gas can be refined to the extent necessary for it to be used as renewable natural gas (RNG, aka biomethane in some regions) such that it can be added to pipelines interchangeably with the traditional fossil product, reducing consumption of fossil sources. Let’s take a closer look at what this requires. Understanding Biogas Composition Anerobic digestion is fermentation of organic matter by bacteria. It is similar to natural biodegradation but happens more quickly in a reactor in the absence of oxygen, and this process allows for capturing the gaseous products. This is neither a clean nor precise reaction due to the wide range of variabilities, but still fairly predictable. Biogas normally contains: Obviously, raw biogas is a long way from qualifying as sales gas carried by pipelines and utilities. Moreover, a pipeline company accepting gas from a source such as a biogas producer will insist on having it fall within normal compositional limitations to avoid contaminants or ballast gases that reduce overall BTU value. So how much does it need to be cleaned up to meet basic requirements for sales gas? Regulatory agencies and pipeline companies around the world define natural gas quality by limits on components other than CH4. While there is some minor variability, most regions include specification ranges for: Regulations are tight as variability in sales gas can create a variety of problems for large-scale users, particularly when used as a fuel for gas turbines or sophisticated fired heaters, where the BTU rating is critical. For gas turbines, the Wobbe Index indicates additional characteristics affecting its suitability as a fuel. And for some users, contaminants can be just as important. For most, the least desirable contaminants relate to sulfur, which influences the price and quality of gas being transferred. Pipeline operators must test sales gas at various points in the distribution chain to ensure it has correct composition. Various testing methods are available, as we will discuss in a moment. Having said all that, what is the practicality of converting biogas into RNG, within all the limitations of pipeline regulations? Cleaning Up Biogas Undertaking such a project must be driven by a desire to reduce fossil fuel use. RNG is considered carbon-neutral because the CO2 released when burned comes from the CO2 that was originally absorbed by the plants during photosynthesis, essentially creating a closed carbon cycle where no net new carbon is added to the atmosphere. Conventional natural gas is not considered carbon neutral because, despite producing less CO2 than other fossil fuels when burned, it is primarily composed of CH4, a potent GHG. Throughout natural gas production fields, CH4 leaks significantly throughout its extraction, transportation, and distribution processes, negating some of its climate benefit. CH4 leaks contribute significantly to overall GHG effects from natural gas, at rates more than CO2. The process of converting biogas into RNG, also known as biogas upgrading, requires the removal of unwanted components—including CO2, H2S, and H2O—from raw biogas, leaving behind a much higher concentration of CH4 that can be injected into the natural gas grid. Common upgrading technologies include: The selection of each technology depends on the desired purity level and project volume requirements, and in some circumstances may require more than one removal technique, depending on the gas composition. The aim of upgrading technologies is to achieve the highest practical CH4 purity with minimum energy consumption and overall volume loss. Examining the pros and cons of various options is beyond the scope of this article, but all options require a method to measure final gas composition, and possibly at additional intermediate points. Gas Chromatography for Composition Analysis Gas chromatography (GC) technology is firmly established as a recognized method for composition analysis of natural gas at production and custody transfer points due to its high reliability, measurement accuracy, and minimal downtime. Tens of thousands of GC analyzers are installed worldwide along natural gas pipelines, and due to the similarity of biogas measurement with natural gas measurement, GC analyzers are also trusted by biogas producers, transporters, and users. A GC analyzer functions by separating and detecting chemical components within a sample. Inside the analytical oven, a column facilitates separation of various components, while valves inject the sample and direct it through different flow paths. Finally, detectors are employed to identify and quantify the separated sample components. A GC analyzer utilizes different types of detection technologies depending on the gas composition. The most common techniques are thermal conductivity detector (TCD), flame ionization detector (FID), and flame photometric detector (FPD). TCDs are for universal detection, mainly to measure inert gases and most hydrocarbons, while FIDs are adept at quantifying trace hydrocarbons, and FPDs specialize in measuring low-level sulfur species. With speciated composition measurement, GC software can calculate many critical physical properties of the gas according to the latest industry standards, such as BTU value, Wobbe index, specific gravity, compressibility, etc. For characterizing biogas and monitoring upgrading operations, TCD detectors are generally sufficient since there are relatively few sulfur compounds present and few higher hydrocarbons. GC Analyzer Operation The gas sample under test is mixed with an inert carrier gas and passes through a packed column (Figure 2). During the stationary phase in the column, the components separate and exit the column in a prescribed order, allowing them to be identified and quantified using TCD. The column and TCD are inside an oven to maintain the required temperature (Figure 3). Signal processing by specialized software embedded in the GC analyzer determines which individual chemical components are present and in what proportions. These are indicated by peaks on the graph (Figure 4). GC analyzer suppliers design their instruments to fit the list of components that end users demand for their routine applications. Some instruments cover a longer list of components than others, and this becomes a key specification, driving price and operational complexity. For biogas or conventional natural gas analysis, a basic GC analyzer can typically handle hydrocarbons through hexanes, although hydrocarbons higher than CH4 in biogas are usually only present in trace amounts. Selecting a GC Analyzer RNG measurement standards, where it is used as a stand-alone fuel, are still being developed in the different world areas and can vary from country to country, and even from contract to contract. However, where RNG must be interchangeable with conventional pipeline natural gas, the measurement requirements are the same as with sales gas analysis. Whichever the case, sites that produce biogas generally do it as a sideline, with their main operations focused on dairy products or meat production. Consequently, biogas is decidedly secondary, so selecting an analyzer technology will hinge on minimizing long-term operational cost and providing overall ease of use. Fortunately, today’s GC analyzers aren’t the complex, fragile, bulky, and expensive devices of yesteryear. The need for consumables is much lower, and improved operator interfaces allow automated processing, remote connectivity, and audit checks—while reducing the need for specialized operator training. The smaller size and greater ruggedness of internal valves and sensors makes it possible to reduce the footprint of a GC analyzer, while eliminating the need for specialized enclosures (Figure 5). Most biogas producers choose a GC analyzer with a single TCD, such as Emerson’s Rosemount™ 470XA Gas Chromatograph, due to its cost effectiveness. Others may prefer a GC analyzer with two TCDs, such as Emerson’s Rosemount 770XA Gas Chromatograph, to achieve expanded measurement into higher hydrocarbons, along with low ppm-level H2S. The latter unit also delivers a shorter cycle time. Both designs are explosion-proof and NEC/ ATEX/IECEX safety rated—so they are field installable without an enclosure—even in Class 1, Division 1 areas, eliminating the need for costly air-purged enclosures. RNG Implementation Drivers The processing steps necessary to turn raw biogas into RNG results in a production cost between five and 10 times the cost of conventional natural gas. The primary factor is the cost of purification via removal of CO2 and sulfur compounds, as these are expensive and complex processes. The analyzer itself is no different than would be necessary for a conventional natural gas production site delivering product to a pipeline operator. Therefore, the fundamental drivers behind RNG production are government mandates and initiatives aimed at lowering GHG emissions. For the producers to be profitable, or at least minimize required subsidies, there is a strong need for cost effective measurement solutions. For dirty raw gas, a robust analyzer solution capable of measuring H2S as well as BTU content in one single-analyzer solution is thus highly desired. Emerson’s GC analyzer offerings are ideal for these applications, delivering accurate measurements with simple operation and low lifetime costs. Biogas producers, pipeline companies, and end users get the measurements they need without the complications, expense, and maintenance requirements of older technologies and solutions. About the Author Alice Fu is a Senior Global Product Manager at Emerson, supporting the Rosemount Gas Chromatograph product line. She has been with Emerson for the past 20 years in multiple roles, including customer support, analytical system integration, project management, business leadership, and currently product management. Fu holds a bachelor’s degree in biomedical engineering from Zhejiang University, and MBA from Shanghai Jiao Tong University, both in China.
oil-gas
03 April 2025
Mosman Oil And Gas Limited Announces Mello Investor Presentation
Gulf Oil and Gas
Mosman Oil And Gas Limited Announces Mello Investor PresentationMosman Oil and Gas Limited the helium, hydrogen and hydrocarbon exploration, development and production company, is presenting at Mello Monday's virtual investor event on Monday 7 April 2025. Andy Carroll, Chief Executive Officer, will be presenting at 17:30 (BST) and taking questions afterwards. If you would like to attend, you can?register here?for a free ticket for the event using code SHFREE.
oil-gas
03 April 2025
Bptt Announces Start Of Production From New Cypre Gas Project
Gulf Oil and Gas
Bptt Announces Start Of Production From New Cypre Gas ProjectCypre subsea trees arriving at the Tembladora facility, Trinidad bp Trinidad and Tobago (bpTT) today confirms its Cypre development has safely delivered its first gas. Cypre is one of bp’s 10 major projects expected to start up worldwide between 2025 and 2027, announced as part of bp’s reset strategy to grow the upstream.?Production from Cypre will make a significant contribution towards the 250,000 barrels of oil equivalent per day (boed) combined peak net production expected from these 10 projects. Cypre is bpTT’s third subsea development. It will comprise seven wells tied back into bpTT’s existing Juniper platform. At peak, it is projected to deliver around 45,000 boed (approximately 250 million standard cubic feet of gas a day). The first phase of the development – four wells – was completed at the end of 2024. The second phase is expected to commence in the second half of this year. “Our focus is on consistent execution and safe delivery of major projects like Cypre. The second of 10 major projects across our global portfolio that we expect to start up by 2027, Cypre is also the first of a series of projects we will be bringing online in Trinidad to deliver gas to the nation and add value for bp.” William Lin, EVP gas and low carbon energy “Our focus is on consistent execution and safe delivery of major projects like Cypre. The second of 10 major projects across our global portfolio that we expect to start up by 2027, Cypre is also the first of a series of projects we will be bringing online in Trinidad to deliver gas to the nation and add value for bp,” said William Lin, EVP gas and low carbon energy. bpTT president David Campbell said: “Cypre is another key milestone in bpTT's strategy to maximize production from our shallow water acreage using existing infrastructure. The project not only reinforces our commitment to maintaining production but also plays a crucial role in satisfying our existing gas supply commitments. Cypre represents a significant investment in the country's energy sector. We are proud to be part of this journey and look forward to continuing our collaboration with Government and other stakeholders to unlock Trinidad and Tobago's energy future." Cypre is bp’s second major start-up of 2025, following the start of production from the second development phase of the Raven field, offshore Egypt. The project meets bp's expected returns from upstream projects and is fully accommodated within bp’s capital expenditure plans. More on Cypre The Cypre gas field is located 78 kilometers off the southeast coast of Trinidad within the East Mayaro Block, in water depth of approximately 80 metres. Cypre is 100% owned by bp Trinidad and Tobago which is owned by bp (70%) and Repsol (30%)
oil-gas
03 April 2025
Wärtsilä To Supply Biolng Plants For Two Large-Scale Biogas Projects In Finland
Gulf Oil and Gas
Wärtsilä To Supply Biolng Plants For Two Large-Scale Biogas Projects In FinlandWärtsilä Gas Solutions, part of technology group Wärtsilä, will supply and install the bioLNG production solutions for two large-scale biogas projects in Finland. The plants have been ordered by Suomen Lantakaasu Oy, a joint venture between the biomethane company St1 Biokraft and dairy and food company, Valio. The two projects will each have the capacity to produce 25 tons of bioLNG per day. The orders with Wärtsilä were booked in Q1. The feedstock for the biogas will be mainly manure and food processing waste. The residue product is an odour-free biofertilizer to be used by the farmers that supply the manure. When operational, the plants will enable more widespread use of a biogas-powered transport fleet. By utilising manure in biogas production, the carbon footprint of milk production is significantly reduced, when the emissions reduction of both agriculture and transport is taken into account. "Suomen Lantakaasu has strong ambitions in building a biogas production network in Finland and enabling wider use of biogas fuel in transport applications. Wärtsilä’s deep experience and successful track record for high-capacity biogas upgrading and liquefaction plants is highly valuable to our projects”, says Leena Helminen, CEO of Suomen Lantakaasu. These biogas plants are greenfield projects and will be built in Nurmo and Kiuruvesi, located in western and central parts of Finland respectively. Both plants are expected to be in operation by the second half of 2026. “Wärtsilä’s focus is very much on shaping decarbonisation. Our bioLNG plants are a central pillar of this strategy. These biogas upgrading and liquefaction plants will have the capacity to produce significant levels of green fuel and thus support Suomen Lantakaasu in their journey,” comments Magnus Folkelid, Sales Manager, Wärtsilä Gas Solutions, Biogas. In addition to the biogas upgrading and liquefaction plants, Wärtsilä will also supply 300m3 capacity storage tanks, as well as an export station. Earlier, Wärtsilä has only supplied biogas upgrading and biogas upgrading plus liquefaction plants to St1 Biokraft in Sweden and Norway.
oil-gas
03 April 2025
Ogdcl Announces 3Rd Gas And Condensate Discovery At Spinwam-1 Well
Gulf Oil and Gas
Ogdcl Announces 3Rd Gas And Condensate Discovery At Spinwam-1 WellWith reference to our announcement dated March 18, 2025, regarding the discovery at Spinwam-1 well in the Waziristan Block, Khyber Pakhtunkhwa from the Kawagarh Formation, we are pleased to report third gas and condensate discovery in the Hangu Formation at the Spinwam-1 Well. OGDCL holds a 35% working interest in the Waziristan Block, with Mari Energies Limited as Operator (55%) and Orient Petroleum Inc. (10%). The well has flowed 23.85 MMSCFD of gas and approximately 122 barrels per day of condensate at a 32/64" choke, with a Well Head Flowing Pressure (WHFP) of 4,042 psig. Testing of additional formations is in progress. The above information is submitted in compliance of Section 96 of the Securities Act, 2015 and Clause 5.6.1(a) of PSX Regulations, for dissemination amongst your members please.
oil-gas
03 April 2025
Goil Ceo To Speak At Accra Investor Briefing As Ghana Targets Enhanced Fuel Security
Gulf Oil and Gas
Goil Ceo To Speak At Accra Investor Briefing As Ghana Targets Enhanced Fuel SecurityInvest in African Energies: Accra Investor Briefing takes place on April 14 at the Kempinsky Hotel. Targeting enhanced fuel security, Ghana is driving the development of its downstream oil and gas industry, with advancements in liquefied petroleum gas (LPG), distributed fuel products and aviation fuels. The country’s state-owned oil and gas marketing company Ghana Oil Company (GOIL) plays an instrumental part in strengthening the downstream sector. Edward Abambire Bawa, Group CEO and Managing Director of GOIL, is speaking at the Invest in African Energies: Accra Investor Briefing on April 14 at the Kempinsky Hotel. The event is a prelude to the African Energy Week (AEW): Invest in African Energies 2025 conference – taking place in Cape Town from September 29 to October 3 – and will showcase Ghana’s extensive oil and gas opportunities, from upstream exploration to midstream infrastructure to downstream distribution and investment opportunities. With ambitions to increase oil production through the expansion of upstream fields, Ghana also strives to enhance its downstream industry, with aims to reduce petroleum imports by scaling-up domestic infrastructure and distribution. At the helm of this ambition is GOIL, which is already renowned for its diverse product offerings and extensive distribution network. This includes a vast network of fuel stations across the country; strong partnerships with global and local stakeholders in the energy sector; and ongoing investment in infrastructure, innovation and sustainable solutions. The company is also one of the leading suppliers of jet fuel at Ghana’s Kotoka International Airport, Takoradi Airforce Base and Kumasi Airport. In collaboration with partners, the company also offers jet fuel for export worldwide. Recent developments underscore GOIL’s commitment to expanding its distribution infrastructure. In February 2025, the company opened its third service station in Berekum in the Upper Middle Belt Zone; in August 2024, it reintroduced super XP onto the market; and in February 2024, it opened Autogas stations in five regions nationwide. Additionally, in partnership with Ivory Coast’s Societé Multinationale de Bitumes, GOIL inaugurated a bitumen terminal and production plant in Tema in September 2024. The $40 million facility has a production capacity of 7,500 metric tons and will produce polymer modified bitumen and bitumen emulsions. The facility also features a laboratory for testing the quality of products as well as storage options. The facility is expected to meet the demand of the country’s road construction sector, reducing the import of bitumen products in Ghana. These developments highlight the company’s commitment to expanding infrastructure to support the growing demand for petroleum products in Ghana. Stepping into this picture, the Invest in African Energies: Accra Investor Briefing offers an opportunity for the country’s state-owned enterprises such as GOIL to share updates on major projects, upcoming investment opportunities and strategic areas of collaboration. During the event, Bawa will share insights on GOIL’s strategic initiatives to enhance the nation’s oil and gas infrastructure, underscoring the critical need for increased investments across the entire energy value chain to bolster Ghana’s economic growth and energy security. “GOIL continues to make significant strides toward strengthening the entire oil and gas value chain in Ghana. With a commitment to enhancing domestic fuel security and reducing imports, the company is looking at working more closely with international partners to modernize energy infrastructure, boost petroleum product distribution and scale-up capacity building across the downstream sector. GOIL’s projects and forward-looking development strategy exemplify the proactive steps needed across the country to attract investment and enhance the value chain,” stated NJ Ayuk, Executive Chairman, African Energy Chamber.
oil-gas
03 April 2025
Traverse Pipeline Reaches Final Investment Decision To Transport Natural Gas Between Agua Dulce And The Katy Area
Gas Processing and LNG
Traverse Pipeline Reaches Final Investment Decision To Transport Natural Gas Between Agua Dulce And The Katy AreaWhiteWater announced that WhiteWater, MPLX LP, and Enbridge Inc., through the WPC joint venture, have partnered with an affiliate of Targa Resources Corp. and have reached the final investment decision to move forward with the construction of the Traverse Pipeline, having secured sufficient firm transportation agreements with investment grade shippers. The bi-directional Traverse Pipeline is designed to transport up to 1.75 billion cubic feet per day (Bcf/d) of natural gas through approximately 160 miles of 36-inch pipeline along the Gulf Coast between Agua Dulce in South Texas and the Katy area. Supply for the Traverse Pipeline will be sourced from multiple connections, including, but not limited to, the Whistler, Blackcomb, and Matterhorn Express Pipelines. The Traverse Pipeline enhances optionality for shippers to access multiple premium markets. The Traverse Pipeline will be wholly owned by the Blackcomb Pipeline joint venture, which is owned 70.0% by WPC, 17.5% by Targa, and 12.5% by MPLX, which is incremental to MPLX's ownership interest in WPC. The Traverse Pipeline will be constructed and operated by WhiteWater and is expected to be in service in 2027, pending the receipt of customary regulatory and other approvals.
oil-gas
03 April 2025
Wm Announces New, Modernized High-Tech Recycling And Renewable Gas Facilities Across U.S.
Gas Processing and LNG
Wm Announces New, Modernized High-Tech Recycling And Renewable Gas Facilities Across U.S.WM, North America's leading environmental solutions provider and largest recycler, announced the company will celebrate the official grand openings for four recycling and renewable natural gas (RNG) projects across the U.S. The facilities are part of WM's plans to invest about $3 billion in its sustainability growth strategy from 2022-2026, expected to result in 39 new or upgraded recycling facilities and 20 new WM-owned RNG facilities. "We are meeting our customers' needs today and investing in communities for the long term through our planned growth in recycling and renewable energy infrastructure," said Jim Fish, president and chief executive officer, WM. "As demand for recycling and renewable energy rises, WM is leading the industry in leveraging technology and automation to deliver solutions to our customers and help drive a more sustainable future." During Earth Month, WM will have grand opening events for newly upgraded recycling facilities near Baltimore and in Central Texas, as well as new RNG facilities in the Chicago and Philadelphia areas, totaling more than $323 million in executed investments. Among these upgrades is the Mesquite Creek Recycling Facility in New Braunfels, Texas — one of the fastest-growing markets in America. Additionally, the Elkridge Recycling Facility near Baltimore is now WM's largest recycling facility by hourly processing capacity, and the Fairless RNG Facility outside Philadelphia is now the largest of its kind owned by WM. So far, WM has completed eight out of 20 planned RNG facilities and 27 out of 39 planned recycling facilities and intends to open additional sites in 2025 as part of its enterprise-wide investment plans. Once all planned recycling and RNG facilities are complete, the expanded network is expected to add more than 2.8 million incremental tons of annual recycling capacity and 25 million MMBtu of renewable natural gas each year. The new and upgraded recycling facilities leverage state-of-the-art technology that uses artificial intelligence and automation in an effort to increase the amount of material that can be captured for potential reuse. The RNG facilities process captured landfill gas into pipeline-quality renewable natural gas, positioning WM's landfill assets as a community energy partner. WM also continues to invest in innovative capabilities to monitor and mitigate landfill air emissions. WM recently acquired Blue Sky Resources and AirLogic analytics platform, providing WM a comprehensive tool to track and compare data from various detection technologies to help better locate and mitigate potential emissions. "Technology and innovation underpin our sustainability strategy, and we are adding optical sorters, intelligent sorting equipment and more at our recycling sites to help capture more material, including in areas that lack recycling access today," said Tara Hemmer, chief sustainability officer, WM. "We're also proud to turn landfill gas captured at WM landfill sites into a renewable energy source, which could power up to 1.7 million homes by 2026 and support our objective of maximizing the allocation of RNG to WM's natural gas collection fleet."
oil-gas
03 April 2025
Poland To Upgrade Gas Link To Ukraine To Boost Transit Capacity
Gas Processing and LNG
Poland To Upgrade Gas Link To Ukraine To Boost Transit CapacityPoland's Gaz-System will upgrade a metering station on the gas pipeline to Ukraine to boost gas transit capacity towards its eastern neighbor. The upgrade of the Hermanowice station will be ready at the end of 2025 or early 2026. The upgrade, set to cost 8 million zloty ($2.12 million), follows talks with Ukraine's gas transmission network operator. Ukraine wants to import large volumes of U.S. LNG via Germany, Greece, Lithuania and Poland ahead of the heating season, after Russian shelling left the country with storage almost empty. Kyiv also wants to expand gas transport corridors. The Polish link allows shipment of up to 7 million cubic meters a day, a fraction of Ukraine's needs. Naftogaz, Ukraine's state gas producer, and Polish refiner Orlen PKNWA> last month agreed to cooperate in the LNG sector. Naftogaz bought 200 million cubic metres (mcm) of LNG from Orlen, including one cargo of U.S. LNG. The available capacity on the upgraded pipeline will depend on supply directions, the use of other export routes and the demand of power plants and storage facilities in southern and south-eastern Poland, Gaz-System said.
oil-gas
03 April 2025
Argentina Commences Vaca Muerta Gas Exports To Brazil Through Bolivian Pipelines
Offshore Technology
Argentina Commences Vaca Muerta Gas Exports To Brazil Through Bolivian PipelinesArgentina has initiated gas exports from its Vaca Muerta shale formation to Brazil, utilising Bolivian pipelines. This strategic deal involves TotalEnergies, Bolivia’s YPFB and Matrix Energia, and marks a significant step in establishing a long-term route for Argentina’s gas to markets in Brazil. The gold standard of business intelligence. Find out more Approximately 500,000m³ of gas was exported through the Bolivian pipeline, reported Reuters, citing sources. “The objective of the unprecedented operation is to ensure the technical viability of the logistics network,” Matrix Energia said in a statement. Matrix Energia has entered into agreements with both Total’s Argentine division and Bolivia’s YPFB, establishing a tripartite operational agreement. Initially, Bolivia was reluctant to charge a tolling fee for its infrastructure as the country preferred to buy gas from Argentina and resell it to Brazil. However, negotiations have progressed after several potential supply contracts were identified, the report said. The pipeline in Bolivia, historically carrying Bolivian gas to Brazil and Argentina, faces declining volumes due to Bolivia’s reduced gas output, necessitating new suppliers and solutions. For Brazil, the arrival of Vaca Muerta gas aligns with President Luiz Inacio Lula da Silva’s goal of providing cheaper gas to the country’s industry. Sustained exports could also benefit Argentina, whose gas output is increasing under President Javier Milei’s policies, potentially improving the country’s energy trade balance. The tripartite agreement includes a spot contract allowing supply interruptions to Brazil during Argentina’s higher winter demand. While Bolivia’s YPFB did not comment, Brazil’s Petrobras is exploring contracts to import liquefied natural gas and negotiating pipeline supplies from Argentina. Petrobras’ former chief of energy transition, Mauricio Tolmasquim, was quoted as saying: “I think that there is a real possibility to make some deal.” In a related development, CB&I has secured a contract for the engineering, procurement, fabrication and construction of new storage facilities at the Vaca Muerta crude oil exportation facility in Punta Colorada, Argentina. Awarded by VMOS, the project involves building storage with a total capacity of 630,000m³, equivalent to four million barrels.
oil-gas
02 April 2025