Case studies

Spotlight

Eni’s Enilive Gela plant produces HVO diesel and SAF from renewable feedstocks

Eni has been investing in biofuels for over a decade. Since 2014, Eni has been producing hydrotreated vegetable oil (HVO) from renewable feedstocks, mainly waste (such as used cooking oil, animal fat) and agro-food industry residues. Since 2022, Eni has integrated these with agri feedstock produced through a model of vertical integration that valorizes sustainable agricultural projects that do not compete with the food value chain.

In 2019 Eni converted a petrochemical plant in Gela, Sicily into a biorefinery that, in January 2025, started producing sustainable aviation fuel (SAF). This SAF can be blended with traditional aviation fuel in proportions of up to 50%, and it is produced using the hydroprocessed esters and fatty acids (HEFA) technology.

The Gela biorefinery has a processing capacity of 736,000 tonnes per year, and the SAF plant has a capacity of 400,000 tonnes per year, almost a third of the expected European SAF demand in 2025,* following the implementation of the ReFuelEU Aviation regulation.

Eni’s subsidiary Enilive is dedicated to mobility products and services. It owns and manages several industrial assets, including biorefineries in Italy and abroad. With a current processing capacity of 1.65 million tonnes per year, Enilive is one of the biggest HVO producers globally and the only one in Italy.

In addition to the facility in Gela, Enilive has a biorefinery in Venice, located in Porto Marghera, which was the world’s first conversion of an oil refinery into a biorefinery to produce HVO diesel. The biorefinery in Venice has a processing capacity of 400,000 tonnes/year. Enilive’s biorefining assets also include St. Bernard Renewables LLC (50% joint venture with PBF Energy) in the US state of Louisiana.

Enilive’s biorefineries can process waste and residues thanks to the Ecofining™ technology, which was developed by Eni in cooperation with Honeywell-UOP. Ecofining™ enables the transformation of renewable feedstocks into HVO biofuels, that are currently the only available solution to support the decarbonization of the hard-to-abate transport industry such as heavy-duty, aviation and maritime.

Enilive manages more than 5,000 Enilive Stations in Europe. HVO diesel is available in about 1,400 of them, enabling all light and heavy-duty drivers to refuel their vehicles with a 100% HVO biofuel.

*Source: Wood Mackenzie

Eni’s Enilive Gela plant produces HVO diesel and SAF from renewable feedstocks Credit: Eni

Spotlight

bp’s Cherry Point refinery turns waste into renewable diesel

bp’s Cherry Point refinery in Washington State is turning what were once considered waste products into a low-carbon fuel that is helping to decarbonize road transportation.

Cherry Point refinery produces renewable diesel using co-processing. This is when biomass-based feedstocks, such as beef tallow, cooking oil and byproducts from the ethanol industry, are refined alongside conventional crude oil to create a blended fuel.

As it is chemically identical to diesel derived solely from fossil fuels, truck drivers can use co-processed fuel without any changes to their engines.

This renewable diesel only has (up to) 30%¹of the Lifecycle Greenhouse Emissions compared to fossil diesel fuel as measured by the California Air Resources Board GREET model.

Biofuels such as renewable diesel have the potential to be one of the most cost-effective decarbonization options for the transportation sector, particularly in hard-to-abate areas such as long-haul trucking.

Cherry Point is currently able to co-process more than 7,000 barrels of renewable diesel fuel daily, or 2.6 million barrels each year.

1 Based on California Air Resources Board life cycle analysis (LCA) of renewable diesel produced via co-processing animal fat at bp’s Cherry Point refinery versus conventional US diesel.

Co-processing facility for bio-diesel at bp’s Cherry Point refinery. Credit: bp

Spotlight

Petrobras developing CCUS pilot project

Petrobras is developing a pilot project designed to generate technical insights that will inform the potential implementation of Brazil’s first commercial CCUS. This initiative is part of the company’s broader strategy to support industrial decarbonization and advance carbon management solutions.

The demonstration pilot, with final investment decision already approved, will capture up to 100,000 tonnes of CO₂ per year from the Petrobras-owned Cabiúnas natural gas processing facility. The CO₂ will be injected into an onshore saline acquifer where it will be monitored long term.

The pilot is designed to test injection, pressure management, monitoring, and plume migration in an onshore hypersaline aquifer that has similar characteristics to the potential offshore storage site for the hub.

Petrobras plans to develop a commercial hub for a range of industrial emitters in Rio de Janeiro state, home to several large industrial clusters.

Petrobras is exploring options to re-use existing pipelines and build new ones out to an offshore saline aquifer with a potential storage resource capacity of 20 Mt of CO₂ per year.

Petrobras has years of experience in natural gas processing CCUS, re-injecting large amounts of carbon dioxide back into pre-salt fields as it develops oil and gas resources.

Alongside the pilot project, Petrobras is assessing the technical and economic viability of potential CCUS hubs in several Brazilian states, in alignment with its Strategic Plan 2025–2029. The company is advancing feasibility studies that may lead to the development of its first full-scale CCUS project.

Petrobras’s 2025–2029 strategic plan includes $5.7 billion in investments in low-carbon energy initiatives, including carbon capture activities. Part of these resources are earmarked for projects and research and development investments specifically related to the pilot plant.

“There’s significant potential to develop CCUS hubs in Brazil. The opportunity is more than just reducing emissions from heavy industry, CCUS hubs also create economic value and jobs and help to grow carbon markets as we transition to a net-zero emissions future.”

Ana Paula Santana Musse, Petrobras CCUS senior advisor and OGCI CCUS workstream member

Spotlight

Shell’s bio-LNG plant in Germany supplies trucks

In April 2024, Shell opened its bio-LNG plant at the Energy and Chemicals Park Rheinland, part of its ambition to decarbonize heavy-duty trucks.

Biomethane is obtained from agricultural waste (manure or organic residues). At the new plant in Rhineland, the gas is liquefied and delivered to Shell’s LNG truck stations, where customers refuel.

The plant is the largest facility of its kind in Germany. It has the capacity to produce up to 100,000 tonnes of low-carbon bio-LNG every year. This is enough to fuel 5,000 LNG-powered trucks – a major boost for the energy transition in commercial transportation.

Shell believes bio-LNG, along with other low-carbon fuels, is crucial to decarbonizing hard-to-abate sectors such as aviation, shipping and commercial road transport.

Shell is one of the largest producers, traders and marketers of biomethane in Europe. This includes the acquisition of Nature Energy in 2023, which added to an already established European biomethane portfolio.

According to the IEA, the world’s biogas and biomethane resources could meet up to 20% of global gas demand while reducing greenhouse gas emissions.¹

Initiatives such as REPowerEU, the EU’s plan to increase local energy sourcing by accelerating the energy transition, and the associated Biomethane Action Plan aim to spur a ten-fold rise in biomethane production to 35 billion cubic meters by 2030.

1 IEA: Outlook for Biogas and Biomethane – Analysis – IEA

Employee observing the hydro cracker unit (HCU) at Shell Energy and Chemicals Park Rhineland, Wesseling, Germany. Credit: Shell

Spotlight

Northern Lights JV successfully stores first CO2

Northern Lights, the world’s first cross-border carbon transport and storage facility, is now receiving and injecting CO₂. The first volumes were transported through the 100-kilometre pipeline and injected into the Aurora reservoir below the seabed of the Norwegian North Sea earlier this summer.

Northern Lights is developing an open and flexible infrastructure to transport CO₂ by ship from capture sites across Europe to a receiving terminal in western Norway for intermediate storage, before being transported by pipeline for safe and permanent storage in a reservoir 2,600 metres under the seabed.

With a storage capacity of 1.5 Mt of CO₂ per year, this first phase of Northern Lights is establishing a commercial CCS market and supporting the decarbonization of European industry.

Joint venture partners Equinor, Shell and TotalEnergies completed the CO₂ receiving and storage facilities for Phase 1 of the Northern Lights Project in 2024. The first phase of the project is fully booked including by cement company Heidelberg Materials, fertilizer company Yara and waste-to-energy plant Hafslund Celsio.

In March 2025, the partners gave the green light to the second phase of the Northern Lights project. The Phase 2 expansion, due to become operational by the second half of 2028, will more than triple capacity to at least 5 Mt per year. Phase 2 of the project will include nine additional onshore storage tanks, larger pumps, a new jetty and new electrical substation and
two new injection wells.

The investment decision to expand capacity followed a commercial agreement with the Swedish energy provider, Stockholm Exergi, for cross-border transport and storage of up to 0.9 Mt of biogenic CO₂ per year.

Support from the Norwegian government has been an important contributing factor to successfully completing Phase 1. Phase 2 was made possible by investments from the Northern Lights joint venture owners as well as a grant from the Connecting Europe Facility for Energy funding scheme.

Northern Lights facilities. Photo by Torstein Lund Eik, Equinor

Spotlight

Petrobras launches forest restoration initiative to help catalyze further projects

In 2025, Petrobras and Brazil’s National Bank for Economic and Social Development (BNDES) launched ProFloresta+, a large-scale forest restoration and carbon credit initiative in the Amazon.

The program aims to restore up to 50,000 hectares of degraded land, capturing an estimated 15 million tonnes of CO₂ equivalent, while delivering biodiversity and community benefits.

ProFloresta+ combines Petrobras’s demand for highintegrity carbon credits with BNDES’s capacity to finance restoration projects.

By committing to long-term purchase agreements for high-integrity carbon credits, Petrobras provides the market certainty needed to attract serious project developers.

Petrobras also brings technical expertise in large-scale project management, transparency practices, and the capacity to integrate carbon credits into broader corporate decarbonization plans.

The first phase will restore around 15,000 hectares, generating about 5 million carbon credits through a public tender. Petrobras has committed to long-term purchase agreements, ensuring financial stability for project developers. BNDES complements this with dedicated credit lines to lower upfront barriers.

The initiative is expected to create around 4,500 local jobs, prioritize native species, and require adherence to social and environmental safeguards. Public consultations on the first tender and contract design aim to enhance transparency and ensure alignment with international best practices.

The project’s ambition and structured design position it as one of the largest corporate-backed restoration efforts in Brazil.

The goal is for ProFloresta+ to provide a model that can be replicated to scale restoration-based carbon markets in Brazil by linking corporate offtake with public finance.

Petrobras CEO Magda Chambriard, BNDES President Aloizio Mercadante, BNDES Socioenvironmental Director Tereza Campello at MOU signing for the ProFloresta+ program. Credit: Marcelo Gonzalez

“This initiative is critically important for Petrobras and Brazil. It will allow us to meet our climate commitments with high-quality, high-integrity carbon credits while fostering the development of NCS in Brazil.”

Maria Izabel Ramos, Petrobras Nature Based Solutions Manager, and OGCI Natural Climate Solutions workstream lead.

Spotlight

Repsol invests in advanced biofuels

In early 2025, Repsol approved an investment of more than €800 million in the Ecoplanta project – a pioneering facility to turn waste into advanced biofuels, such as renewable methanol, that will help decarbonize transport.

Ecoplanta, located in Tarragona, Spain, will use cutting-edge gasification technology to process up to 400,000 tonnes of waste per year into 240,000 tonnes of renewable fuels and circular products. The plant is expected to begin operations in 2029.

According to IRENA and the Methanol Institute, global methanol demand is expected to quintuple by 2050, driven by the use of renewable methanol in shipping, road transport and aviation.

The renewable methanol produced at Ecoplanta can be used for road transport, as a material to produce renewable gasoline and diesel, for shipping as well as for the production of sustainable aviation fuel.

In its first 10 years of operation, Ecoplanta will help avoid 3.4 Mt of CO₂e, and Repsol is looking to replicate the model in other regions as part of its plans to increase renewable fuels production.

Repsol is targeting annual production in 2027 of 1.5-1.7 Mt of renewable fuels, including renewable hydrogen and biomethane, and up to 2.7 Mt per year in 2030.

The company is already producing renewable fuels at its industrial complex in Cartagena, Spain, which has a capacity of 250,000 tonnes per year.

The plant can produce renewable diesel and sustainable aviation fuels which can be used in any transport, including cars, trucks, buses, ships or airplanes and with existing refueling infrastructure.

The production of 100% renewable fuels at the plant in Cartagena will avoid the emissions of 0.9 Mt of CO₂ per year.

Credit: Repsol

“The Ecoplanta is one of our flagship projects and a pioneer in Europe for the coming years. By converting municipal solid waste into renewable fuels and circular products, it offers a tangible solution to reduce GHG emissions in transport while maximizing waste valorization. This project is a clear example of how industrial companies can contribute through strategic investments to continue generating employment, creating economic value, developing technology, and building a better future for society.”

Josu Jon Imaz, CEO, Repsol

Spotlight

CNPC sees Junggar CCUS hub capacity at 3 Mt per year by 2030

CNPC is developing a CCUS hub in the Junggar basin in northwest China, an area with a high concentration of large emitters.

Also at the Junggar hub, CNPC has started construction of a coal-fired power plant carbon capture project, and pipelines and systems for geological storage and enhanced recovery technology applications.

In the second phase, CNPC expects to capture 1 Mt of CO₂ per year from its own refineries and coal-fired power plants and 2 Mt of CO₂ per year until 2030 from nearby coal power stations, steel mills, cement plants, and hydrogen production facilities.

CNPC aims to expand the hub’s capacity to 10 Mt of CO₂ per year by 2040.

CNPC plans to further develop and expand its CCUS hubs in other parts of China by 2030. These include the Daqing and Dagang hubs in the northeast, the Changqing hub in northern China, and the Hainan hub in the south.

Credit: CNPC

“CCUS hubs like Junggar, along with others we are developing in China, will be pivotal in helping the country achieve its goal of carbon neutrality before 2060. The technology can significantly reduce emissions across a number of hard-to-abate sectors, including power generation, cement, steel, chemicals and refining.”

Dai Houliang, CEO, CNPC

Spotlight

Aramco uses cogeneration to reduce CO2 intensity

Aramco is using cogeneration at many of its operating sites to help lower its upstream carbon intensity by
making its operations more energy efficient.

Cogeneration plants typically utilize waste heat from gas turbines to generate steam, meeting both the heat and power requirements of the facility. This process reduces emissions – in Aramco’s case over 7 Mt of CO2 per year have been saved by Aramco’s cogeneration program.

Aramco is working to improve the energy efficiency of its upstream and downstream assets – an ambition that could mitigate 7 million tonnes of CO₂e by 2035.

Support provided by Aramco for cogeneration has to date generated 5.3 gigawatts (GW) of power, 4.3 GW of which was used to power operations, with the remainder funneled into Saudi Arabia’s national grid. And there are more to come.

In 2024, Aramco and TotalEnergies’ joint venture Saudi Aramco Total Refining and Petrochemical Company reached a deal with Abu Dhabi National Energy Company PJSC and Japanese power company JERA to develop a state-of-the-art cogeneration plant for the Amiral petrochemical complex due to be built in Jubail in Saudi Arabia’s Eastern Province.

The plant, due to start operating in 2027, will generate up to 475 megawatts of power and approximately 452 tonnes per hour of steam using advanced cogeneration gas-fired technology.

Along with ongoing and planned reductions to flaring and methane emissions, growth in carbon capture, utilization and storage, renewable energy capacity and natural climate solutions, increasing operational efficiency will help Aramco as it continues on its ambition to achieve net zero Scope 1 and Scope 2 GHG emissions across all wholly owned operated assets by 2050.

Aramco’s upstream carbon intensity is one of the lowest among its peers. In 2024 it was 9.7 kilograms of CO₂ equivalent per barrel of oil equivalent.¹

1 This compares to an average of 22.2 kg CO₂e/boe from other international oil companies, based on public disclosures in 2023. www.aramco.
com/-/media/publications/corporate-reports/reports-and-presentations/2024/fy/saudi-aramco-fy-2024-webcast-presentation-english.pdf p.11

Credit: Aramco

“As a founding member of OGCI, Aramco values the sharing of best practices and working alongside peers across the industry to help develop solutions to support emissions reduction. Our innovative lower-emissions solutions, such as cogeneration, reinforce both efficiency gains and our ambition to achieve net-zero Scope 1 and 2 GHG emissions across our wholly-owned operated assets by 2050.”

Amin Nasser, President & CEO, Aramco

Spotlight

CNPC develops 10 biodiversity conservation areas

CNPC has established 10 biodiversity conservation areas across its operational regions, reflecting its commitment to sustainable development and ecological protection.

The biodiversity conservation areas form part of CNPC’s Intended National Determined Contributions (INDC) under the Paris Agreement.

The 10 areas are located in diverse ecosystems such as wetlands, forests, grasslands, and desert margins and serve as key zones for protecting endangered species, restoring habitats, and balancing industrial development with environmental stewardship.

Each conservation area is designed around local ecological priorities. For example, the Daqing Wetland Reserve focuses on waterbird protection, while the Tarim Basin area safeguards rare desert flora and fauna. In Qinghai, CNPC supports high-altitude grassland restoration, ensuring the preservation of native species such as the Tibetan antelope.

CNPC integrates scientific research, community participation, and continuous monitoring into its management approach. Partnerships with universities and local environmental agencies enable data-driven strategies, such as habitat mapping, biodiversity surveys, and ecological impact assessments.

The company also implements offset programs and ecological compensation to mitigate industrial impacts, aligning with international standards like the Convention on Biological Diversity.

Through these initiatives, CNPC’s ten biodiversity areas not only conserve critical ecosystems but also demonstrate how energy companies can integrate biodiversity protection into corporate environmental responsibility frameworks aligned with INDC goals.

Qinghai-Tibet Plateau grasslands Credit: Adobe Stock

Spotlight

Aramco works to protect and restore mangrove forests

For decades, Aramco has been at the forefront of mangrove restoration and conservation efforts in Saudi Arabia, pioneering the large-scale plantation of millions of mangroves across the Red Sea and Arabian Gulf coastlines.

These ecosystems are vitally important for capturing and storing carbon, while supporting marine biodiversity and strengthening coastal ecosystems.

At the end of 2024, Aramco had planted over 43 million mangroves in Saudi Arabia, with a goal of reaching 300 million by 2035.

This large-scale program contributes directly to carbon removal and aligns with the Kingdom’s broader targets under the Saudi Green Initiative.

Aramco is accelerating the scaling of its mangrove restoration initiatives through pioneering research and the deployment of cutting-edge technology and digital tools. These efforts are designed to enhance restoration outcomes. Mangrove restoration represents one part of Aramco’s broader biodiversity efforts.

Since 2012, Aramco has been protecting biodiversity on its land and sea holdings, establishing a network of Biodiversity Protection Areas (BPAs).

At the end of 2024, these totaled 28 BPAs, covering over 1,900 km², and encompassing numerous ecosystems, from seagrass meadows and coral reefs, to montane grasslands and dramatic desert landscapes.

Collectively, these BPAs host an array of flora and fauna, with over 800 species recorded, including numerous IUCN Red List species, such as striped hyena, steppe eagle, and the critically endangered hawksbill turtle.

As well as supporting a plethora of species, these BPAs provide a wide range of ‘ecosystem services’ (the benefits human societies and economies derive from nature), including coastal protection, erosion control, and air quality maintenance.

Many of the benefits accrue from the protection of native vegetation, such as shrublands and seagrass. This also has carbon sequestration benefits, with seagrass and old-growth mangrove stands in particular contributing to blue carbon stocks.

Augmenting these initiatives, Aramco is developing and applying innovative technology solutions to enhance biodiversity protection, including satellite tracking of marine species and mapping and monitoring tools for management of its BPAs. These efforts align with the company’s aspiration to achieving a net positive impact on biodiversity and ecosystem services across its operations.

Aramco EPD Mangrove Eco-Park. Credit: Aramco

Spotlight

Aramco pursuing lower-carbon aviation fuel certification

Aramco recognizes that an energy transition plan has to consider the needs of all of society, especially developing and emerging economies. Lower carbon aviation fuel (LCAF) supports transition plans at an acceptable cost, facilitating energy security and affordability in the aviation industry that is integral to the global economy, and to connecting societies and families.

Aramco is advancing its goal to become a certified producer of LCAF. It has already achieved ISO certification for lower-carbon intensity at four facilities in Saudi Arabia. As the aviation industry increases sustainable aviation fuel (SAF) production, LCAF serves as a complementary, fossil-based solution that utilizes existing infrastructure to help the aviation industry meet its carbon neutrality goals.

Global trends indicate a gradual increase in SAF production. Aramco’s LCAF provides a cost-effective, sustainable solution to help the aviation industry, a hard-to-abate sector, reduce carbon emissions and advance toward its net-zero goals. LCAF is a drop-in fuel that reduces overall emissions and requires no modifications to existing fueling infrastructure. Aramco’s refineries produce CORSIA-compliant fuel, and the company is working with independent third-parties for audits and
certifications to ensure products meet ISO standards for lower-carbon emissions.

The demand for air travel is expected to double by 2040, growing at an annual average rate of 3.4%. LCAF stands out as a viable solution because it is positioned to satisfy this growing demand and simultaneously achieve reductions in carbon emissions within the aviation sector.

For instance, converting five billion liters of LCAF at 80g CO₂/MJ could provide the equivalent GHG emissions reduction of about 1 billion liters of SAF at 45g CO₂/MJ.

Spotlight

ExxonMobil eyes expansion at LaBarge CCS facility

ExxonMobil’s estimated $400 million expansion of its carbon capture facility in LaBarge, Wyoming has the potential to come onstream this year [2025, pending regulatory approvals], increasing the plant’s capture capacity by 1.2 Mt of CO₂ per year.

The facility, which currently has capacity of 6-7 Mt per year, has captured more CO₂ than any other carbon capture operation globally.

The expansion at LaBarge is part of the company’s 2030 emissions reduction plans and supports ExxonMobil’s ambition to achieve net zero GHG emissions (Scopes 1 and 2) for its operated assets by 2050.

By capturing an additional 1.2 Mt of CO₂ each year, ExxonMobil can reduce GHG emissions from its upstream operated emissions by 3%.

To date, operations under ExxonMobil’s control have captured approximately 150 Mt of carbon¹ – more than a third of all anthropogenic carbon ever captured.²

ExxonMobil’s current capture capacity is 9 Mt per year.

With the integration of Denbury, ExxonMobil now owns and operates a 1,500-mile network of CO₂ pipelines: the most extensive in the US.

This, coupled with an array of locations across the Gulf Coast that allow for secure and permanent storage hundreds of metres underground, means it can help heavy industries such as chemicals, refining, cement and steel production reduce their emissions.

1 Global CCS Institute 2022 Cumulative CO₂ Capture Facilities Analysis conducted for ExxonMobil
2 GCCSI Historical Carbon Capture Volumes 2023

Credit: ExxonMobil

“Carbon capture projects like LaBarge are essential to meeting society’s emission-reduction goals. These technologies offer one of the most practical, scalable pathways available today, and ExxonMobil has more than 40 years of experience in carbon capture with the ability to deliver results at global scale.”

Darren Woods, Chairman & CEO, ExxonMobil

Spotlight

bp reduces flaring and emissions at Permian Basin facility

Since acquiring assets in the Permian Basin, bpx – bp’s US onshore business – has taken a leadership role in advancing technology to reduce emissions and unlock long-term value.

At the center of this effort is bp’s redesign of acquired well site facilities into “hydra” sites, a next-generation infrastructure model that flows production to centralized facilities.

Hydra sites are engineered by bpx to eliminate storage tanks, flares, and onsite compression at new well sites.This enables industry-leading emissions performance.

For legacy well sites, bpx upgraded key equipment, replacing gas-driven pneumatics with air systems to eliminate intermittent methane emissions and expanded vapor recovery to capture more gas that would otherwise be lost.

This integrated and efficient design has delivered measurable impact. Flaring has been reduced by 99%, and bpx eliminated routine flaring. The company has set a strict standard: no new bpx well is brought online unless it’s connected to a gas pipeline from startup.

Through ongoing innovation in site design, equipment, and operating standards, bpx is building a scalable model for low-carbon growth in the Permian Basin, delivering operational excellence while significantly reducing its environmental footprint.

bpx’s Grand Slam facility in the Permian Basin, near Orla, Texas. Copyright: bp

“In the Permian, our bpx team has achieved its accelerated goal of zero routine flaring by 2025 and significantly reduced emissions through next-gen Hydra sites—an innovation that’s reshaping how we design and operate. It’s a powerful step towards our aim to reach net zero operations by 2050 or sooner.”

Murray Auchincloss, CEO, bp

Spotlight

Occidental’s DAC facility to start up this year

STRATOS, Occidental’s first direct air capture (DAC) facility is planned to start commercial operations this year. The Texas facility is designed to remove up to 0.5 Mt tonnes of atmospheric CO₂ per year.

The facility represents the culmination of a multi-year journey to deploy innovation and leverage Occidental’s 50-year history managing CO₂ to provide a solution to address emissions and meet demand for low-carbon fuels.

STRATOS is expected to start capturing CO₂ by the end of 2025, with the full capacity planned to be online as soon as mid-2026.

This phased approach allows Occidental to implement advances to optimize the DAC process. These advances will help improve efficiency, reliability and reduce capital expenditures – critical factors in bringing first-of-a-kind technologies to market.

By developing DAC technology, Occidental is creating a pathway to produce low-carbon fuels through enhanced oil recovery (EOR) and provide carbon dioxide removal credits (CDRs) generated from sequestration.

Microsoft, Amazon, Airbus and other large companies have entered into agreements to purchase CDR credits from STRATOS where the captured CO₂ is stored in saline reservoirs as a durable solution to address their emissions.

Occidental’s ability to use CO₂ captured from DAC for EOR can create a carbon neutral barrel of oil, in which the volume of CO₂ injected to produce that barrel of oil is equal to the emissions it creates over its lifecycle from production to refining to use.

This provides an opportunity to power hard-todecarbonize sectors like aviation, maritime and heavy transportation with carbon neutral fuels.

Occidental is also working on the South Texas DAC Hub located on the US Gulf Coast. The hub has acreage with the potential to store up to 3 billion tonnes of CO₂.

The first DAC facility at the hub is designed to capture 0.5 Mt of CO₂ per year and is currently in front-end engineering and design. The hub can also accept point source CO₂ volumes due to its proximity to industrial facilities.

Credit: Occidental

“We believe that carbon capture and DAC, in particular, will be instrumental in shaping the future energy landscape. First, captured CO2 can be used for enhanced oil recovery in conventional and shale reservoirs. Second, CO2 removed from the atmosphere via DAC can be used today to address emissions related to products or services.”

Vicki Hollub, President & CEO, Occidental

Spotlight

Aramco’s Jubail CCUS hub plays a key role in GHG reduction strategy

Aramco’s CCUS hub in Jubail, in the Kingdom’s eastern province will take CO₂ from natural gas processing and other industrial sources, with around 6 Mt of CO₂ per year coming from Aramco’s gas plants and 3 Mt of CO₂ per year from other non-Aramco industrial sources.

The captured CO₂ will be transported for storage below ground in a saline aquifer.

The hub supports Aramco’s ambition to achieve net zero Scope 1 and Scope 2 GHG emissions across its wholly owned operated assets by 2050.

The Jubail CCUS hub plays a key role in Aramco’s GHG reduction roadmap articulated around five key levers: improving energy efficiency across upstream and downstream facilities, reducing methane emissions and flaring, advancing carbon capture, expanding renewable energy production capacity, and implementing nature-based solutions as well as purchasing carbon offset credits.

Two engineers working at a Saudi Aramco Facility. Credit: Aramco

“Aramco’s CCUS hub in Jubail is indicative of our company-wide efforts to deliver innovative lower-carbon solutions designed to lower emissions today, and into the future. Aramco is proud to support OGCI’s valuable role as a leading platform for sharing best practices, and for supporting the OGCI members’ ambitions to reduce emissions and deploy lower-carbon technologies.”

Musaab Al-Mulla, Vice President of Market Analysis & Sustainability, Aramco and OGCI ExCom member

Spotlight

Eni’s Ravenna CCS project paves the way for CCS in Southern Europe

In September 2024, Eni and joint venture partner Snam started up Phase 1 of the Ravenna carbon capture and storage project, the first of its kind in Italy with a capture capacity of 0.25 Mt per year.

Carbon captured at Eni’s Casalborsetti natural gas treatment plant is now being injected and permanently stored in the depleted Porto Corsini Mare Ovest gas field in the Adriatic Sea. The initiative is already cutting the Casalborsetti plant’s CO₂emissions by up to 96% during peaks. The actual volumes correspond to those captured due to the system’s efficiency,
where the power supply is ensured by the recovery of self-produced thermal energy and electricity from renewable sources.

Phase 2 of the project, due to start by 2030, will allow annual storage of up to 4 Mt of CO₂. A significant portion of this is expected to be used by hard-to-abate industries such as cement, steel, fertilizer and chemicals in the Ravenna industrial zone as well as power plants.

Given high market demand and potential annual CO₂ injection capacity of up to 16 Mt per year after 2030, Ravenna is on track to become a strategic CCUS hub for the decarbonization of heavy industries across Southern Europe.

Eni’s Ravenna CCS project capturing CO₂ from the Casalborsetti gas plant in Italy. Credit: Eni

“CCUS is a mature and safe technological process, and is one of the key levers for the energy transition, being an efficient and effective tool to support hard-to-abate industries in reducing their emissions. was launched in 2024 and has achieved, and it is a key project in Eni’s commitment to reduce emissions of large industrial clusters.”

Claudio Descalzi, CEO, Eni

Spotlight

TotalEnergies shares AUSEA methane detection across industry

To help accelerate the oil and gas industry’s action to reduce methane emissions to near zero by 2030, TotalEnergies is sharing its cutting-edge drone-based methane emissions detection and measurement system AUSEA (Airborne Ultralight Spectrometer for Environmental Applications) with companies on three continents.

To date, TotalEnergies has signed cooperation agreements with the Nigerian National Petroleum Company, India’s Oil and Natural Gas Corporation, Oil India Ltd, Petrobras in Brazil, SOCAR in Azerbaijan and Sonangol in Angola that allow them to use AUSEA to better understand and abate methane emissions at their operations.

The AUSEA gas analyzer, developed by TotalEnergies and its research and development partners,¹ consists of a dual sensor that can pinpoint the presence and the source of both methane and CO₂emissions.

The sensor features a diode laser spectrometer and can detect and quantify methane emissions with a high level of accuracy of more than 1 kilogram per hour.

AUSEA’s ability to detect both CO₂ and methane emissions at onshore and offshore facilities of all types and to reach even the most difficult-to-access areas have made it one of the industry’s most accurate methods for finding and tracking methane emissions.

1 Reims Champagne Ardennes University, GSMA and CNRS

TotalEnergies AUSEA drone demonstration in France. Credit: TotalEnergies

“Cutting methane emissions from operations is a priority as technologies are available. The first step is to measure emissions, asset by asset. By making our AUSEA technology available to our partners, TotalEnergies is taking a concrete step to encourage the whole industry, including national companies, to aim for zero methane emissions.”

Patrick Pouyanné, Chairman & CEO, TotalEnergies

Spotlight

Equinor’s electrification drive reduces emissions

A key pillar of Equinor’s Energy Transition Plan is the ambition to halve net operated GHG emissions from its operations by 2030, compared with 2015.

Electrification of key oil and gas installations with low-carbon power is an efficient way to address emissions while reducing operating expenses and CO2 costs.

Oil and gas production on the Norwegian continental shelf accounts for approximately 25% of Norway’s total CO₂ emissions. To reduce emissions from its oil and gas production, Equinor is replacing offshore gas turbines with electricity from the mainland where the energy mix is predominantly renewable.

The Troll A platform was electrified in 1996. Johan Sverdrup, which accounts for around one-third of Norway’s oil production, has been powered from shore since its startup in 2019. At 0.67 kg CO₂ per barrel, it has some of the lowest upstream CO₂ emissions of any oil field in the world.

Hywind Tampen, developed by Equinor, is the world’s first floating offshore wind farm to power offshore oil and gas installations, has supplied electricity to Gullfaks and Snorre fields since 2023.

Between 2018 and 2024, six other fields and installations have been electrified, and more are planned, cutting emissions and creating low-carbon hubs for tie-in of potential future discoveries nearby.

Hywind Tampen, offshore in the Norwegian North Sea. Copyright: Ole Jørgen Bratland / Equinor

“Electrifying oil and gas installations is an effective and efficient method for lowering operational CO₂ emissions. Replacing gas turbines offshore – either fully or partially – with electric power from the Norwegian grid enhances energy efficiency and reduces emissions.”

Anders Opedal, President & CEO, Equinor

Spotlight

TotalEnergies deploys continuous methane monitoring

In 2024, TotalEnergies announced a plan to deploy continuous, real-time methane monitoring detection equipment across all its upstream operations – the largest project of its kind in the industry.

The equipment is expected to be installed at every facility TotalEnergies operates, including those under development, by the end of 2025. It includes the use of existing and proven technologies such as Internet of Things sensors, InfraRed
cameras, flow meters, pyrometers and Predictive Emissions Monitoring Systems.

This builds on other initiatives, including TotalEnergies’ successful deployment of Airborne Ultralight Spectrometer for Environment Applications (AUSEA) technology, starting in 2022.

AUSEA comprises a drone-mounted ultralight CO₂ and methane sensor and ensures access to hard-to-reach emissions points while delivering readings with high precision.

The successful deployment of TotalEnergies’ AUSEA drone campaign, alongside strategic abatement projects, have helped the company meet its target to reduce its operated methane emissions by more than 50% versus 2020 levels in 2024 – a year earlier than planned.

This puts the company on track to meet its ambition to reduce methane emissions by 80% by 2030 to achieve near zero methane emissions.

Credit: TotalEnergies

“Continuous, real-time detection will enable our operators to act in an even more decisive manner in order to reduce our methane emissions and to repair leaks to achieve our near-zero methane emissions ambition.”

Patrick Pouyanné, Chairman & CEO, TotalEnergies

Spotlight

Shell achieves methane and flaring targets

Shell QGC (Shell operated), which produces natural gas, has long used advanced technology such as sensors, drones and satellites to detect potential methane leaks from its extensive infrastructure and improve emissions reporting.

This has helped QGC reduce reported methane emissions by 70% compared with 2016.

Shell aims to maintain methane emissions intensity for global operated oil and gas assets below 0.20% (continued to be met in 2024), and achieve near-zero methane emissions intensity by 2030. As of January 1, 2025, Shell no longer routinely flares from its operated oil and gas assets.

LNG facility, Curtis Island, Australia Credit: Shell

“Shell remains a leader in reducing emissions of methane. By the end of 2024, we had reduced total methane emissions from assets under our operational control by 76% compared with 2016. We have also met our target to eliminate routine flaring from our upstream-operated assets, five years ahead of the World Bank Zero Routine Flaring Initiative deadline, as we continue on our journey to deliver more value with less emissions.”

Wael Sawan, CEO, Shell

Spotlight

Chevron’s approach to reducing its methane intensity

From 2016 to 2024, Chevron has reduced its methane intensity by over 50%.

To manage methane intensity, Chevron has a threepronged approach that includes facility design, operating practices and advancing technology.

In 2024, Chevron completed its largest methane emissions reduction project in Colorado executing more than 250 facility retrofits to reduce methane emissions.

The facilities were converted to operate pneumatic devices with nitrogen, instead of field natural gas, which helps keep methane in the pipe.

This project started as a pilot to trial technology on three facilities and was quickly scaled up.

Chevron shares lessons across the company, and the same technology is being considered for a pilot in the Permian Basin.

Chevron believes an important first step in mitigating emissions is improving methane detection.

Since 2016, Chevron has trialed over 20 methane detection technologies and incorporates solutions into its methane detection campaign.

Chevron believes that combining operational data with detection information enhances its understanding of methane emissions and recently published its findings in the SPE Journal.

Credit: Chevron

“Chevron remains focused on lowering the carbon intensity of our operations through energy efficiency, methane management, and flaring reduction. Our Colorado facility retrofits exemplify these efforts. We collaborate with organizations like OGCI to advance understanding and share best practices across the industry.”

Mike Wirth, Chairman & CEO, Chevron