Petrobras on natural gas flow and processing

Petróleo Brasileiro S.A. – Petrobras informs that together with Equinor Energy do Brasil Ltda. (Equinor) signed the contracts for the Campos Basin Integrated Natural Gas Flow System (SIE-BC) and access to the Cabiúnas Gas Treatment Unit (UTGCAB). 

With the signing of these contracts, Equinor will be able to transport natural gas from the Roncador field, located in the Campos Basin, from January 1, 2024. Equinor has a 25% stake in Roncador, while Petrobras is the operator of the field and holds the other 75%. 

The SIE-BC is made up of sea and land pipelines owned by Petrobras, which connect to the UTGCAB, also owned by Petrobras, located in Cabiúnas, Rio de Janeiro. 

In this way, Petrobras complies with the provisions of the Gas Law, negotiating access to infrastructure and enabling the diversification of agents in all links of the natural gas chain. Petrobras currently has contracts to share the infrastructure in the Santos Basin (SIE BS and SIP), the Catu Cluster (BA) and the Cacimbas Cluster (ES)

ConocoPhillips Makes Final Investment Decision to Develop the Willow Project

ConocoPhillips (NYSE: COP) announced today that it will move forward with development of the Willow project in Alaska. This Final Investment Decision approves the project and funds construction needed to reach first oil. The decision follows the Department of the Interior March 2023 Record of Decision and recent positive court orders, including this week’s Ninth Circuit Court of Appeals denial of plaintiffs’ request for an injunction.

“We are excited to reach this significant milestone,” said Ryan Lance, chairman and chief executive officer. “With this project authorization, we’ve begun winter construction and Alaskans have started to receive the benefits from responsible energy development.”

According to the Bureau of Land Management, the Willow project is projected to deliver $8 billion to $17 billion in new revenue for the federal government, the state of Alaska and Alaska Native communities. When completed, Willow is estimated to produce approximately 600 million barrels across the lifetime of the project, decreasing American dependence on foreign energy supplies. Designed to support and coexist with subsistence activities on Alaska’s North Slope, the Willow project underwent five years of rigorous regulatory and environmental review. Willow will be built using materials primarily made and sourced in the U.S. and has the potential to create over 2,500 construction jobs and approximately 300 long-term jobs.

“We are grateful for the many supporters who advocated for Willow. Alaska Native communities and groups, especially those closest to the project on the North Slope, continually provided input that helped shape this project. We also appreciate the unwavering support from Alaska’s bipartisan Congressional Delegation – Senators Lisa Murkowski and Dan Sullivan and Representative Mary Peltola – the state legislature and organized labor groups,” Lance added. “Our employees and the contractor community have dedicated years to designing a project that will provide reliable energy while adhering to the highest environmental standards.”

Transformational acquisition of Wintershall Dea asset portfolio

Harbour is pleased to announce that it has reached an agreement with BASF and LetterOne, the shareholders of Wintershall Dea AG ("Wintershall Dea"), for the acquisition of substantially all of Wintershall Dea’s upstream assets (the "Target Portfolio") for $11.2 billion (the "Acquisition").

The Target Portfolio includes all of Wintershall Dea’s upstream assets in Norway, Germany, Denmark1, Argentina, Mexico, Egypt, Libya2 and Algeria as well as Wintershall Dea’s CO2 Capture and Storage ("CCS") licences in Europe. Wintershall Dea's Russian assets are excluded. The Acquisition will add 1.1 bnboe of 2P reserves at c.$10/boe and more than 300 kboepd of production at c.$35,000/boepd3.

The Acquisition is expected to transform Harbour into one of the world’s largest and most geographically diverse independent oil and gas companies, adding material gas-weighted portfolios in Norway and Argentina and complementary growth projects in Mexico. Harbour will also benefit from an increased reserve life and improved margins with lower operating costs and greenhouse gas ("GHG") intensity.

Harbour is expected to receive investment grade credit ratings and to benefit from a significantly lower cost of financing resulting from the porting of existing euro denominated Wintershall Dea bonds with a nominal value of c.$4.9 billion4 (the "Wintershall Dea Bonds") and a weighted average coupon of c.1.8 per cent. The Acquisition is also accretive to Harbour’s free cash flow, supporting enhanced and sustainable shareholder returns.

Wintershall Dea Assets

• Algeria
• North Reggane Gas Fields 
• Argentina
• Vega Pleyade Offshore Gas Field 
• Denmark
• Cecilie Oil Field 
• Nini Oil Field 
• Germany
• Mittelplate Oil Field 
• Libya
• Al Jurf Oil Field 
• Norway
• Dvalin Gas Field 
• Maria Oil Field 
• United Arab Emirates
• Ghasha and Hail Sour Gas Fields
• United Kingdom
• Wingate Gas Field 

Shell Invests in the Sparta Development in the Gulf of Mexico

Shell Offshore Inc., a subsidiary of Shell plc, today announced the Final Investment Decision (FID) for Sparta, a deep-water development in the U.S. Gulf of Mexico that represents our competitive approach to simplifying and replicating projects.

Owned by Shell Offshore Inc. (51% operator) and Equinor Gulf of Mexico LLC (49%), Sparta is expected to reach a peak production of approximately 90,000 barrels of oil equivalent per day (boe/d) and currently has an estimated, discovered recoverable resource volume of 244 million boe. Sparta will be Shell's 15th deep-water host in the Gulf of Mexico and is currently scheduled to begin production in 2028.

Sparta showcases Shell's cost-efficient development approach through standardized, simplified host designs, first utilized at the Vito development and later replicated at the Whale development. An enhanced replication of Vito and Whale, Sparta replicates about 95% of Whale's hull and 85% of Whale's topsides.

"Shell's latest deep-water development demonstrates the power of replication, driving greater value from our advantaged positions," said Zoë Yujnovich, Shell's Integrated Gas & Upstream Director. "This investment decision is aligned with our commitment to pursue the most energy-efficient and competitive projects while supplying safe, secure energy supplies today and for decades to come."

Building on more than 40 years of deep-water expertise, Sparta also marks Shell's first development in the Gulf of Mexico to produce from reservoirs with pressures up to 20,000 pounds per square inch.

The Sparta development will be the first of Shell's replicable projects to feature all-electric topside compression equipment, significantly reducing greenhouse gas intensity and emissions from our own operations.

Notes to editors

• The Sparta development spans four Outer Continental Shelf (OCS) blocks in the Garden Banks area of the U.S. Gulf of Mexico.
• Sparta will feature a semi-submersible production host in a depth of more than 1,400m/4,700ft of water, initially with eight oil and gas producing wells.
• Sparta's design closely replicates the 100,000 barrel per day Vito and Whale designs, both of which are four-column semi-submersible host facilities. Vito is located in the greater Mars Corridor and began production in February 2023. Whale will be located in the Perdido corridor and is scheduled to come online in 2024.
• Current estimated recoverable resource volumes of the primary Sparta development are 244 million boe. The estimate of resource volumes is currently classified as 2P under the Society of Petroleum Engineers' Resource Classification System.
• The estimated peak production and current estimated recoverable resources presented above are 100% total gross figures.
• Shell is the leading operator in the U.S. Gulf of Mexico.

Barossa Development Drilling and Completions Environment Plan (EP) accepted

The Barossa Development Drilling and Completions Environment Plan (EP) was accepted by the regulator, the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) on Friday 15 December 2023.

Following the setting aside of NOPSEMA’s March 2022 approval of the EP in September 2022, Santos has conducted further extensive consultation with Tiwi Island people and other relevant persons consistent with the applicable regulations, NOPSEMA’s guidelines, and guidance provided by the decision of the Full Federal Court in the Tipakalippa proceedings.

Santos is proceeding with applications for all remaining approvals for the Barossa Gas Project.

Shell Takes Investment Decision For Phased Wells Campaign At Perdido In US Gulf Of Mexico

Shell Offshore Inc., a subsidiary of Shell plc (Shell), announced the Final Investment Decision (FID) for a phased campaign to deliver three wells in the Great White unit designed to boost production at the Shell-operated Perdido spar in the US Gulf of Mexico (GoM).

After completion of this campaign in April 2025, these wells collectively are expected to produce up to 22,000 barrels of oil equivalent per day (boe/d) at peak rates.

“Shell is the leading operator in the US Gulf of Mexico, and we continue to find ways to build on that position,” said Rich Howe, Shell’s Executive Vice President for Deep Water. “By expanding our Perdido development, we continue to unlock the greatest value from this exceptional resource.”

This investment underscores Shell’s long-term commitment to the US Gulf of Mexico, where production is essential to ensuring a reliable and secure supply of energy. Additionally, production in the US Gulf of Mexico has among the lowest greenhouse gas (GHG) intensity in the world for producing oil.

Notes to editors

• Perdido, a production spar in the US Gulf of Mexico, began production in 2010. It is located approximately 200 miles south of Galveston, Texas in about 8,000 feet of water.
• The wells will be drilled in the Great White unit, where Shell Offshore Inc. is operator with 33.34% WI, with Chevron U.S.A. Inc. holding 33.33% WI, BP Exploration & Production Inc. holding 33.33% WI.
• This phased campaign includes three wells which combined are expected to produce up to 22 kboe/d at peak rates.
• Shell Offshore Inc. is operator of the Perdido Regional Host with 35% Working Interest (WI) in Perdido, with Chevron U.S.A. Inc. holding 37.5% WI, 3C Perdido Holdings LLC holding 26.5% and BP Exploration & Production Inc. holding 1% WI.
• Perdido’s production capacity is 125 kboe/d at peak rates.
• The reference to our U.S. Gulf of Mexico production being among the lowest GHG intensity in the world is a comparison among other IOGP oil-and gas-producing members.
• Shell is the leading operator in the U.S. Gulf of Mexico for oil and gas production.

Shell Assumes 100% Working Interest In Us Gulf Of Mexico Kaikias Field

Shell Offshore Inc., a subsidiary of Shell plc (Shell), has acquired the 20% Working Interest (WI) of MOEX North America LLC (MOEX), a 100% subsidiary of Mitsui & Co., Ltd., in the Kaikias field in the US Gulf of Mexico. Shell now has 100% WI and remains the operator.

“Since its discovery, the Kaikias field has been a productive investment,” said Rich Howe, Shell’s Executive Vice President for Deep Water. “By increasing Shell’s working interest in the field, we are creating options for our future as the leading producer in the US Gulf of Mexico.”

This investment underscores Shell’s long-term commitment to the US Gulf of Mexico, where production is essential to ensuring a reliable and secure supply of energy. Additionally, production in the US Gulf of Mexico has among the lowest greenhouse gas (GHG) intensity for scope 1 and 2 in the world.

Shell and MOEX will submit for federal regulatory approval.

Notes to editors

• The Kaikias field in the US Gulf of Mexico is a deep-water project that uses a subsea tieback to the nearby Ursa production hub.
• Shell discovered the Kaikias field in 2014. The field is located in the prolific Mars-Ursa basin, approximately 130 miles from the Louisiana coast. Production began in May 2018.
• The reference to Shell’s US Gulf of Mexico production being among the lowest GHG intensity in the world is a comparison among other IOGP oil-and gas-producing members.
• Shell is the leading operator in the US Gulf of Mexico for oil and gas production.

Transocean Ltd. Announces $251 Million Harsh Environment Semisubmersible Contract

Transocean Ltd. (NYSE: RIG) (“Transocean”) today announced a minimum 540-day contract for the Transocean Barents with OMV Petrom S.A. in the Romanian Black Sea at a rate of $465,000 per day, excluding additional services. The program is expected to commence in the first quarter of 2025 and is estimated to contribute approximately $251 million in backlog, excluding full compensation for mobilization and a demobilization fee. For each day over 540 days, including the two option periods, the operating dayrate will be $480,000.

The rig will be utilised on the Neptun Deep Gas Fields project

Saipem awarded two offshore contracts worth approximately 1.9 billion USD

Saipem has been awarded two offshore contracts, one in Guyana and the other in Brazil, worth approximately 1.9 billion USD.

The first contract has been awarded by ExxonMobil’s subsidiary ExxonMobil Guyana Limited for the proposed Whiptail oilfield development located in the Stabroek block offshore Guyana, at a water depth of approximately 2,000 meters. Saipem’s scope of work includes the design, fabrication and installation of subsea structures, risers, flowlines, and umbilicals for a large subsea production facility.

Saipem will perform operations using its state-of-the art vessels FDS2, Constellation, and Castorone, and will deploy as key fabrication site for its execution model Saipem’s Guyana Offshore Construction Facility located at the Port of Georgetown, enhancing a sustainable steady growth in the country. Subject to the necessary government approvals, the project sanction by ExxonMobil Guyana Limited and its Stabroek block coventurers and an authorization to proceed with the final phase, the award will allow Saipem to begin some limited activities, namely detailed engineering, and procurement.

The second contract has been awarded by Equinor for the Raia project, the development of a pre-salt gas and condensate field in the Campos Basin, located about 200 km offshore the state of Rio de Janeiro in Brazil.

Saipem’s scope of work encompasses the offshore transport and installation of a subsea gas export line and associated equipment in water depths of around 2,900 meters, as well as the horizontal drilling activities for the shore approach. Saipem will deploy its state-of-the-art pipelaying vessel Castorone for the installation works.

With this project, Saipem will contribute to the realization of one of the most important gas development projects in Brazil, which could represent 15% of the total domestic demand of the Country. The extracted gas will be transported through pipelines installed by Saipem for approximately 200 km from the field to a gas receiving facility to be built in Cabiúnas, in the city of Macaé in the State of Rio de Janeiro.

The two awards confirm, once again, the competitiveness of Saipem’s offer in bidding processes and the ability to build long term partnerships based on consistent performances. Moreover, they further strengthen the visibility on Saipem’s key assets utilization throughout 2027.

Coastal GasLink achieves mechanical completion, ahead of 2023 year-end target

Today, TC Energy shared that the Coastal GasLink project safely reached mechanical completion on November 6, 2023, ahead of schedule. Mechanical completion represents another major milestone following the recent achievement of 100 per cent pipeline installation.

This major milestone is a testament to the power of collaboration between industry, Indigenous and local communities, and government, all of whom have played a significant role in shaping the future of Canada’s energy sector.

Coastal GasLink is Canada's first direct path for sustainably produced Canadian natural gas and a critical component to support global emissions reduction.

Together with LNG Canada, Coastal GasLink has the potential to reduce global GHG emissions by 60 to 90 million tonnes of CO2 each year, displacing global GHG emissions from higher emitting forms of energy such as coal.

Through the remainder of 2023, TC Energy will complete commission activities to be ready to deliver commissioning gas to the LNG Canada facility by year end.

McDermott Receives Limited Notice to Proceed for Manatee Gas Development Project Offshore Trinidad and Tobago

McDermott has received a limited notice to proceed for an engineering, procurement, construction and installation (EPCI) contract from Shell Trinidad and Tobago Limited for the Manatee gas field development project, located off the east coast of Trinidad and Tobago.

Subject to Shell taking a final investment decision, the Manatee project scope is for the design, procurement, fabrication, transportation, installation, and commissioning of a wellhead platform, offshore and onshore gas pipelines.

"This award follows our successful delivery of the front-end engineering design for the Manatee gas field," said Mahesh Swaminathan, McDermott's Senior Vice President, Subsea and Floating Facilities. "It is testament to McDermott's integrated EPCI capabilities built over the last 100 years around the world including many successful projects in Trinidad and Tobago. We will again deliver for Shell, building on a partnership marked by trust, collaboration, and shared success, to execute this important project."

The Manatee field is a conventional gas development and once commissioned, gas will supply both domestic and export markets from Trinidad and Tobago.

Suncor Energy Announces Restart of Production at Terra Nova

Suncor Energy (TSX: SU) (NYSE: SU) today announced that the Terra Nova Floating, Production, Storage and Offloading vessel has safely restarted following the completion of the Terra Nova Asset Life Extension project. Production is expected to ramp up over the coming months.

"Focusing on safety and operational integrity, we have brought this key offshore project online, providing additional cash flow for our shareholders as well as many benefits to the Newfoundland and Labrador and Canadian economies," said Rich Kruger, Suncor President and Chief Executive Officer. "We appreciate the collaboration and support from the provincial and federal governments regarding this project."

Terra Nova is an oil field located offshore Newfoundland and Labrador approximately 350 kilometres southeast of St. John's. The Terra Nova Partners are Suncor - 48%, Cenovus - 34%, and Murphy Oil Corporation - 18%.

Seatrium Successfully Delivers Floating Production Unit For Gulf of Mexico Project

Seatrium Limited (Seatrium) announced today the successful delivery of the Floating Production Unit (FPU), Whale, for deployment in the Gulf of Mexico, in accordance with the contract secured in November 2019 with Shell Offshore Inc. 

The completed Whale FPU, which comprises a topside module and a four-column semi-submersible floating hull (of over 22,000 tonnes) delivered on-time and within budget, underscores Seatrium’s strong track record and leadership as a global player with deep engineering expertise. 

Enabled by Seatrium’s game-changing Goliath twin cranes with a combined 30,000-tonne lifting capacity and a 100-metre hook height, the integration of the Whale FPU topside and hull in one single lift is a major milestone achievement for Seatrium, resulting in greater productivity and safety for the assembly of such mega-blocks before integration. 

Leveraging Seatrium’s extensive experience in designing and building world-class FPUs, the Whale project demonstrates Seatrium's continuous efforts for improvement and innovation which has brought about tangible contributions of over two million man-hours saved and 30% reduction in hull and topside integration time. The project scores 96% on international standards for health, safety, and environment and complies with the International Association of Oil & Gas Producers1 (IOGP) 577 standards as well as the US Coast Guards statutory requirements. 

In addition to strong engineering capabilities and timely project delivery, Seatrium adopts Environmental, Social and Governance (ESG) practices in its operations. The hull structure of Whale was fabricated in Seatrium’s state-of-the-art steel fabrication facility, powered by renewable solar energy, resulting in reduced carbon emissions during the construction process. 

Mr Chris Ong, CEO of Seatrium said, "We are delighted to have successfully delivered the Whale FPU project, which marks a significant milestone in our journey as we continue to expand our footprint in the offshore market. We are committed to providing innovative and comprehensive solutions for a diverse range of offshore and marine applications. Our successful delivery of the Whale FPU project is a testament to our capabilities and expertise."

Production begins from bp-operated Seagull field in North Sea

bp has successfully started production from the Seagull oil and gas field in the UK North Sea, boosting energy supplies, supporting the supply chain and jobs, and underpinning continued production from an offshore facility that’s been operating for 25 years.

Seagull has been developed by Neptune Energy as a subsea tieback to the bp-operated central processing facility (CPF) of the Eastern Trough Area Project (ETAP) in the central North Sea, around 140 miles east of Aberdeen.

The project supported 800 jobs through the development phase.

“bp has been safely operating in the North Sea for nearly 60 years, delivering a reliable flow of energy, supporting thousands of jobs and a world-class supply chain. We plan to keep doing this by investing in our existing oil and gas infrastructure, like at ETAP, which has been a cornerstone of our North Sea portfolio for a quarter of a century. The start-up of Seagull is a fantastic milestone that demonstrates how bp is investing in today’s energy system and, at the same time, investing in the energy transition.”

Doris Reiter, senior vice president, bp North Sea

Seagull is the first tieback to the ETAP hub in 20 years. The field is located 10 miles south of the ETAP CPF and is a four-well development. Production is delivered via a new three-mile subsea pipeline which connects to an existing pipeline system. A new 10-mile umbilical has been installed, linking the ETAP CPF to the Seagull field, providing control, power and communications services between surface and seafloor.

Seagull sustains continued production through the ETAP CPF, which supports 350 full-time jobs, 270 offshore and 80 onshore. Oil from Seagull is exported through the Forties Pipeline System to Grangemouth in central Scotland and gas to Teesside via the Central Area Transmission System.

The new field is expected to produce around 50,000 barrels of oil equivalent gross per day at peak production.

Doris Reiter, senior vice president, bp North Sea, said: “bp has been safely operating in the North Sea for nearly 60 years, delivering a reliable flow of energy, supporting thousands of jobs and a world-class supply chain. We plan to keep doing this by investing in our existing oil and gas infrastructure, like at ETAP, which has been a cornerstone of our North Sea portfolio for a quarter of a century. The start-up of Seagull is a fantastic milestone that demonstrates how bp is investing in today’s energy system and, at the same time, investing in the energy transition.

“A key focus for bp in the North Sea is to identify projects which can be developed efficiently using existing infrastructure. Seagull is a great example of this, and my thanks go to the committed teams at bp, our joint venture partners and supply chain colleagues who worked so hard to safely deliver this important project.”

Alan Muirhead, UK Country Director, Neptune Energy, added: “As the operator of the project, Seagull is an excellent example of what can be achieved through close collaboration. From the beginning, the partners have taken an innovative approach to ensure we can collectively maximise the recovery of domestic energy resources while extending the life of existing subsea infrastructure to reduce development costs.”

Tomomi Yamada, Managing Executive Officer, JAPEX said: “JAPEX is truly delighted with the safe and successful start-up of the Seagull field. We believe this commencement in production will benefit our business expansion strategy in the North Sea and realise the significant potential of the UK Continental Shelf. It is our pleasure to strengthen our partnership with bp and Neptune through the project.”

Notes to editors

• Neptune Energy holds a 35% stake in Seagull and operated the field through the development phase, drilling wells and installing subsea equipment. bp, with a 50% stake in Seagull, operates the production phase of the development. JAPEX holds the remaining 15% interest in the field. The ETAP hub came online in July 1998. It was initially estimated to have a production life of 20-25 years, with decommissioning predicted to begin in 2023. A $1 billion investment in 2015 secured its future into the 2030s. bp operates all the ETAP fields; Machar, Madoes, Mirren, Monan, Marnock, Mungo and Seagull. They produce through the ETAP CPF. Murlach, a future tieback to the ETAP CPF, received government and regulatory approval in September 2023 with production expected in 2025.

FPSO Acquisition

Jersey Oil & Gas (AIM: JOG), an independent upstream oil and gas company ‎focused on the UK Continental Shelf region of the North Sea, is pleased to announce that the owners of the Buchan field licences, JOG and NEO Energy ("NEO"), have executed agreements to acquire the "Western Isles" floating production, storage and offloading ("FPSO") vessel. The FPSO will be used as the processing facility for the planned redevelopment of the Buchan field.

Highlights:

• Western Isles FPSO, which has been operational since 2017, acquired for planned redevelopment of the Buchan field - high-quality vessel that is currently operating in the UK North Sea
• JOG to receive a $9.4 million cash payment from NEO pursuant to the terms of the farm-out transaction announced on 6 April 2023 - the milestone payment in respect of finalisation of the Greater Buchan Area ("GBA") development solution
• Work progressing at pace on Front-End Engineering and Design ("FEED") activities in order to facilitate Field Development Plan ("FDP") approval in 2024

Andrew Benitz, CEO of Jersey Oil & Gas, commented:

"Finalising the terms for the joint venture partners to acquire the FPSO, which is less than eight years old and requires relatively modest adaptation for our planned GBA redevelopment, is a tremendous milestone for the project.

"Re-using existing high-quality infrastructure and modifying it to be electrification-ready is exactly in line with our stated low carbon strategy and the net zero related objectives of the industry. The vessel is the cornerstone to completing the engineering work required to facilitate FDP approval for the Buchan redevelopment next year."

GBA Development Solution

In July 2023, it was announced that the preferred solution for the redevelopment of the Greater Buchan Area ("GBA") was via the redeployment of an FPSO. This solution benefits from being both the lowest cost development option and the one that results in the lowest full-cycle carbon footprint of all the potential options evaluated. This conclusion was driven by the ability to re-use existing infrastructure that can be located directly at the Buchan field and, with limited modifications, make the FPSO "electrification-ready" upon its redeployment. This will enable the vessel to have the potential to be connected to one of the anticipated third-party floating wind power developments that are intended to be located in close proximity to the GBA following the recent Innovation and Targeted Oil & Gas ("INTOG") licence awards made by Crown Estate Scotland.

Importantly, the preferred development solution aligns with the North Sea Transition Authority's ("NSTA") obligations to maximise the economic recovery of reserves and assist with achieving the UK government's net zero target. Consequently, the NSTA issued a letter confirming it had no objections to the Concept Select Report submitted in support of the Buchan re-development programme utilising the redeployment of the Western Isles FPSO.

FPSO Acquisition

The Western Isles FPSO that is being acquired by NEO on behalf of the Buchan field partners is currently operating in the UK North Sea and is owned by Dana Petroleum (E&P) Limited (76.9188%), as operator, and NEO (23.0812%). The FPSO is a high-quality vessel that has been in operation since early 2017 and is scheduled to come off-station as part of the planned cessation of production of the Western Isles fields around the second half of 2024. The operational capabilities of the vessel, along with its relatively limited service-life to date, make the FPSO an excellent fit for use on the planned redevelopment of the Buchan field.

Following handover of the vessel to NEO, as the Buchan field operator, it is planned for a relatively modest work programme to be undertaken in order to prepare the FPSO for redeployment on Buchan. The works will essentially involve the installation of water injection booster pumps, produced water injection modifications and preparation of the vessel for future electrification. These modifications are expected to be completed by early 2026, such that the vessel can be deployed to the field location and hooked up ready for the anticipated start-up of production in late 2026.

Agreements have been executed to acquire the 76.9188% interest in the vessel not currently owned by NEO. The main terms of the acquisition commit the Buchan field partners to acquire the vessel upon the approval of the Buchan FDP. Prior to this milestone being achieved, the Buchan partners are responsible for the costs of storing the vessel from the date of handover, which is anticipated to be in the second half of 2024. The FPSO acquisition and associated costs forms part of the previously announced farm-out carry arrangements agreed between NEO and JOG.

NEO Farm-out Transaction

As a result of executing the FPSO acquisition agreement, the Company is now due to receive a further cash payment from NEO of $9.4 million associated with finalisation of the GBA development solution.

Further to the farm-out transaction completed with NEO earlier this year, the Company has a 50% working interest in the GBA licences. Through the expenditure carry arrangements agreed with NEO, the Company is being fully carried for its 50% share of the estimated $25 million cost to take the Buchan field through to FDP approval. The Company will also be carried for 12.5% of the Buchan field re-development costs (equivalent to a 1.25 carry ratio).

In line with JOG's stated strategy to farm-out a further interest in the GBA licences, it is targeted for the Company to ultimately retain a fully carried 20-25% interest in the Buchan re-development.

Buchan Development Activities

Work is currently progressing well on the FEED studies that require completion ahead of FDP approval and the development moving into the execution phase of activities. This work primarily involves specification of the planned drilling programme, the design of the subsea infrastructure connecting the wells to the FPSO, and finalisation of the modifications programme that is required to prepare the FPSO for redeployment. Additionally, preparation of the Environmental Statement for the Buchan redevelopment is on-going and it is expected that this will be submitted to the regulator prior to the end of the year, along with the draft FDP.

The first phase of the planned GBA work programme involves re-development of the Buchan field, with the start-up of production targeted for late 2026. Subsequent phases are expected to involve the tie-back of the Verbier and J2 discoveries that lie within the GBA licence area and the potential for regional third-party discoveries to be tied back to the FPSO.

Acquisition of Interest in Greater Buchan Area

Serica Energy plc (AIM: SQZ) is pleased to announce the execution of agreements for the acquisition by its wholly owned subsidiary, Serica Energy (UK) Limited, of 30% non-operated interests in the P2498 and P2170 licences (together the Greater Buchan Area (“GBA”)) from Jersey Oil & Gas (“JOG”) (the “Transaction”). Completion is subject to regulatory, partner and interested party approvals and is expected to occur early in 2024. Following completion, the partners in the GBA will be Serica Energy (UK) Limited (30%), NEO Energy (50% and operator) and JOG (20%). As a result of the Transaction, Serica will have the option of participating in the re-development of the Buchan field and other potential developments in the GBA.

Greater Buchan Area 

The GBA encompasses several oil and gas accumulations some 150 km north-east of Aberdeen, in the Outer Moray Firth. The largest of these accumulations is the Buchan field which produced for over thirty years, ceasing production in 2017 owing to the end of the useable life of the floating production facility. The Concept Select Report submitted to the NSTA for the re-development of Buchan is based on a new production hub located at the Buchan field utilising the floating production, storage and offloading (“FPSO”) vessel currently operating on the UK Western Isles fields and planned to come off-station in the second half of 2024. The acquisition of the FPSO by NEO on behalf of the participants in the Buchan joint venture was announced on 17 November 2023. 

 A phased development is envisaged involving the re-development of the Buchan field in Phase 1 and the possible development of the J2 and Verbier discoveries in Phase 2. Mid-case contingent resources from the Buchan field alone are estimated to be in region of 70 million barrels of oil equivalent, making it the third largest pre-development field in the UKCS. There are other discoveries and prospects in close proximity which might provide additional tie-back opportunities to the FPSO. 

 The NSTA has issued a no objection letter following the submission of the Concept Select Report in support of the Buchan re-development programme. A proposed Field Development Plan (“FDP”) for Buchan is expected to be submitted to the NSTA shortly, with approval of the FDP potentially in the second half of 2024. 

 The development concept includes limited works on the FPSO in order to prepare it for re-deployment. These works involve the installation of water injection booster pumps, produced water injection modifications and preparation of the vessel for future electrification. Following the recent Innovation and Targeted Oil & Gas (“INTOG”) licence awards, there is the possibility of third-party floating wind power developments located close to the GBA. It is anticipated that the FPSO will be connected to one of these, should they become available. Oil export is planned to be via shuttle tankers. 

Subject to project sanction and regulatory approval, the target for first production is late 2026. Peak production rates are expected to be around 35,000 barrels per day. Gross development costs are estimated to be in the order of £850-950 million, which under the current fiscal terms, are expected to qualify for tax relief at a rate of approximately 91%. 

Subsea7 awarded decommissioning contract in Brazil

Subsea 7 S.A. (Oslo Børs: SUBC, ADR: SUBCY) today announced the award of a sizeable contract by Shell for the decommissioning of subsea infrastructure associated with the FPSO Fluminense in the Bijupirá and Salema fields of the Campos Basin, at 700m water depth.

Subsea7’s scope includes the disconnection, recovery, and disposal of 10 flexible risers, three umbilicals and nine mooring lines. Offshore works are planned to start in December 2023.

Yann Cottart, Subsea7 Brazil Vice-President, said: “Twenty years ago, Subsea7 installed the flexibles and umbilicals for Shell’s Bijupirá and Salema fields and, two decades later, we’re proud to be one of Shell’s chosen contractors to take part in the completion of this field’s life cycle.”

CNOOC Limited announced that the Penglai 19-3 oilfield area 5/10 development project has commenced

CNOOC Limited (the "Company", SEHK stock code: 27 (HKD counter) and 00883 (RMB counter), Shanghai Stock Exchange stock code: 80883) today announced that the Penglai 600938-19 oilfield area 3/5 development project has commenced production.

The project is located in the south-central part of the Bohai Sea, with an average water depth of about 30 meters, and the main production facilities include two wellhead platforms, and it is planned to put into operation 130 development wells, including 87 oil production wells and 43 water injection wells, and is expected to achieve peak production of about 2027,29 barrels of crude oil per day in 800.

CNOOC Limited has a 51% interest in the project and is the operator, and ConocoPhillips China has a 49% interest.

Corinth Pipeworks is awarded a contract to manufacture and supply the pipeline for OMV Petrom’s Neptun Deep Project in the Black Sea

Corinth Pipeworks, as subcontractor of Sumitomo Corporation Europe Limited, will manufacture and supply approximately 160km of longitudinally submerged arc-welded steel pipes (LSAW) for the development of an offshore natural gas pipeline for OMV Petrom’s Neptun Deep project in the Black Sea. A major contract valued between EUR 100 and 150 million.

The Neptun Deep Block in the Black Sea has an area of 7,500 square km and is located at a distance of about 160 km from the shore of Romania, in water depths up to 1,000 meters. Neptun Deep is the largest natural gas project in the Romanian Black Sea and the first deepwater offshore project in Romania.

The 30-inch pipeline will be manufactured at Corinth Pipeworks’ facilities and will include external anticorrosion coating and internal flow efficiency lining, applied at the same location as pipe manufacturing at Thisvi, Greece.

Corinth Pipeworks has a comprehensive portfolio of products and solutions to supply and deliver challenging, current and future offshore development projects, using the latest welded linepipe technology.

“We are particularly delighted to be awarded this major project by Sumitomo Corporation Europe Limited, a trusted partner of OMV Petrom, the largest integrated energy company in Southern and Eastern Europe”, stated Ilias Bekiros, General Manager of Corinth Pipeworks.

CNOOC Limited Announces Bozhong 19-6 Condensate Gas Field Phase I Development Project Commences Production

CNOOC Limited (the “Company”, SEHK: 00883 (HKD Counter) and 80883 (RMB Counter), SSE: 600938) announces today that Bozhong 19-6 Condensate Gas Field Phase I Development Project has commenced production.

The project is located in central Bohai Sea, with an average water depth of approximately 20 meters. The main production facilities include 1 newly built central processing platform, 3 unmanned wellhead platforms and 1 gas process terminal. 65 development wells are planned to be commissioned, including 42 production wells, 20 gas injection wells and 3 water source wells. It is expected to achieve a peak production of approximately 37,000 barrels of oil equivalent per day in 2024.

Mr. Zhou Xinhuai, CEO and President of the Company, said, “The project is the first condensate gas field with a proved in-place volume of over 200 billion cubic meters natural gas that has been put into operation in Bohai Bay, relying on the Bozhong-Kenli Oilfields Onshore Power Project. The gas field will supply stable clean energy to the Beijing-Tianjin-Hebei region and the Bohai Rim region, and contribute to the low-carbon and high-quality development of the Company.”

CNOOC Limited holds 100% interest in this project and acts as the operator.

ExxonMobil starts production at third offshore Guyana project

ExxonMobil started production today at Payara, Guyana’s third offshore oil development on the Stabroek Block, bringing total production capacity in Guyana to approximately 620,000 barrels per day.

The Prosperity floating, production, storage and offloading (FPSO) vessel is expected to reach initial production of approximately 220,000 barrels per day over the first half of next year as new wells come online. This additional capacity will be the third major milestone towards reaching a combined production capacity of more than 1.2 million barrels per day on the Stabroek Block by year-end 2027.

“Each new project supports economic development and access to resources that will benefit Guyanese communities while also helping to meet the world’s energy demand,” said Liam Mallon, president of ExxonMobil Upstream Company. “We’re pleased to work in partnership with the Guyanese government to make reliable energy accessible and sustainable.”

ExxonMobil Guyana anticipates six FPSOs will be in operation on the Stabroek Block by year-end 2027. Yellowtail and Uaru, the fourth and fifth projects, are in progress and will each produce approximately 250,000 barrels of oil per day. The company is working with the government of Guyana to secure regulatory approvals for a sixth project at Whiptail.

Prosperity joins the Liza Unity as two of the world’s first FPSOs to be awarded the SUSTAIN-1 notation by the American Bureau of Shipping in recognition of the sustainability of its design, documentation and operational procedures. ExxonMobil’s Guyana developments are generating around 30% lower greenhouse gas intensity than the average of ExxonMobil’s upstream portfolio. According to the independent research firm Rystad Energy, they are also among the best performing in the world with respect to emissions intensity, outpacing 75% of global oil and gas producing assets.

Some 6,000 Guyanese are now supporting ExxonMobil Guyana’s activities in the country, representing more than two-thirds of the local oil and gas workforce. The company and its direct contractors have spent more than $1.2 billion with more than 1,500 Guyanese suppliers since operations began in 2015. Production started in December 2019.

ExxonMobil Guyana Limited operates the Stabroek Block and holds 45% interest. Hess Guyana Exploration Ltd. holds 30% interest, and CNOOC Petroleum Guyana Limited holds 25% interest.

FPSO Liza Unity Purchase by ExxonMobil Completed

SBM Offshore and ExxonMobil Guyana Limited, an affiliate of ExxonMobil Corporation, have completed the transaction related to the purchase of FPSO Liza Unity, a few months ahead of the end of the maximum lease term, in February 2024. The purchase allows ExxonMobil Guyana to assume ownership of the unit while SBM Offshore will continue to operate and maintain the FPSO up to 2033.

The transaction comprises a total cash consideration of c. US$1.26 billion. The net cash proceeds will primarily be used for the full repayment of the US$1.14 billion project financing and as such will decrease SBM Offshore’s net debt position.

The FPSO Liza Unity has been on hire since February 2022 and since 2023 was operated through the integrated operations and maintenance model combining SBM Offshore and ExxonMobil’s expertise and experience delivering outstanding operational performance.

Equinor has made a commercially viable gas discovery by the Gina Krog field in the North Sea. The discovery is small, but gas production can start as early as 2023.

The recoverable volumes are estimated to be between5 og 16 million barrels of oil equivalent. The well was drilled by the Noble Lloyd Noble rig. Equinor is the operator with KUFPEC and PGNiG as partners.

The discovery is considered commercially viable, partly because it can make use of existing infrastructure by the Gina Krog platform. The well has been drilled as a development well with exploration target, and the plan is to put the well into production during the fourth quarter of 2023.

Preparations have already been carried out on Gina Krog so that the well can quickly start production.

"The discovery will help extend the lifetime and strengthen the profitability of Gina Krog and is important for the entire Sleipner area. It will quickly bring new gas to Europe with good profitability and low CO2 emissions from production. Gina Krog is already electrified and has spare capacity. This shows how important it is to explore in mature areas on the Norwegian continental shelf," says Camilla Salthe, senior vice president for field life extension in Equinor.

When the energy crisis hit in 2021, there was close collaboration with Norwegian authorities to deliver the maximum amount of gas to Europe. The Gina Krog partnership significantly increased its gas export by exporting gas previously used for injection for oil extraction. At the same time, it triggered a need to accelerate projects that can extend the lifetime of the field. Together with the Eirin development, the discovery is an important part of this work.

Equinor is the operator (58.7%) with KUFPEC Norway AS (30%) and PGNiG Upstream Norway AS (11.3%) as partners.

This is the first commercial discovery in the Gina Krog license since 2011.

Commercial Discovery at the Veliki Rastovac-1 well in the Drava-03 exploration block

INA reached Commercial Discovery at the Veliki Rastovac-1 well, near Grubišno polje in the Drava-03 exploration block. Well testing confirmed commerciality of the well and excellent reservoir properties, with maximum daily inflow of around 145,000 m³ reached during testing. This is the first of five exploration wells planned to be drilled in first exploration phase of DRAVA-03 exploration block. After completion of exploitation field determination procedure, INA plans to drill an additional development well, build a connecting pipeline and put both wells into production by the end of 2027 according to the current permitting timeline for hydrocarbon production in Croatia.

McDermott Awarded Transportation and Installation Contract by ONGC

McDermott has been awarded a large* transportation and installation contract by the Oil and Natural Gas Corporation (ONGC) for the KG-DWN-98/2 development project, located off the east coast of India.

Under the scope of the contract, McDermott will perform the transportation and installation of a central processing platform (CPP) and living quarters. Once installed, the CPP will be used to process wet gas which will then be transferred from the platform to an onshore terminal.

The CPP award is an expansion of McDermott's current scope of work under the KG-DWN-98/2 project — one of the largest subsea projects in India. Originally awarded in 2018, and nearing completion, the integrated subsea package includes the supply of all subsea production systems (SPS), including 26 deepwater trees, and the installation of subsea umbilicals, risers and flowlines (SURF) at a water depth of between zero to 4,265 feet (1,300 meters).

"This award demonstrates McDermott's track record of executing fast track projects of this nature," said Mahesh Swaminathan, McDermott's Senior Vice President, Subsea and Floating Facilities. "It not only builds on the successes of our ongoing work for the KG-DWN-98/2 project but stands as a testament to our strong working relationship with ONGC. We are confident that our collaborative approach will continue to position us well for the successful delivery of this next stage of this important project for India."

Project management and engineering will be executed from Kuala Lumpur, Malaysia, with support from other McDermott offices.

*McDermott defines a large contract as between USD $50 million and USD $250 million.

Azerbaijan: Inauguration of the Absheron gas field

On the occasion of the inauguration ceremony of the Absheron gas field, whose first development phase started production in early July 2023 and is currently producing 1.5 BCMA (billions of cubic meters per year), Patrick Pouyanné, Chairman and CEO of TotalEnergies, met on Thursday in Baku His Excellency Mr. Ilham Aliyev, President of the Republic of Azerbaijan, as well as Mr. Mikayil Jabbarov, Minister of Economy and Chairman of SOCAR’s Supervisory Board, Mr. Parviz Shahbazov, Minister of Energy, and Mr. Rovshan Najaf, President of SOCAR.

Together they discussed TotalEnergies' projects in Azerbaijan, notably the launch of the second phase of the Absheron development, which will increase the field's production to 5.5 BCMA, in line with Azerbaijan's ambition to supply the European market. TotalEnergies also plans to participate in the development of the country’s renewable energy potential under the Memorandum of Understanding signed in June 2023 to assess and develop 500 MW of renewable wind and solar energies and energy storage systems for the national grid.

“I am very pleased to inaugurate Absheron, alongside the national company SOCAR and our new partner ADNOC. Discovered by our exploration team, this gas field provides additional gas resources to contribute to diversifying gas supply for Europe”, said Patrick Pouyanné, Chairman and CEO of TotalEnergies. “In line with our multi-energy strategy, we also look forward to supporting Azerbaijan in implementing its own energy transition strategy, through an agreement to develop renewable energy combined with electricity storage.”

L&T Wins another (Ultra-Mega*) Contract for its Hydrocarbon Business

The Hydrocarbon Business (L&T Energy Hydrocarbon – LTEH) of Larsen & Toubro (L&T) has secured Letter of Intent for yet another Ultra-Mega Onshore project from a prestigious client in the Middle East further to the recent Ultra-Mega project award for a Gas Compression plant.

The scope of work comprises engineering, procurement, & construction for Gas Processing Plant consisting of Inlet Separation Facilities, Booster Compression System, Amine Gas Recovery Unit, Dehydration Unit, Mercury Removal Unit, NGL Recovery Unit and Sales Gas Compression System in new onshore facilities and its integration with existing Gas Processing Plants.

Upbeat by the ultra-mega order win, L&T Chairman & Managing Director Mr S N Subrahmanyan said: “This is a huge order that will not only strengthen our balance sheet but also provide impetus to our demonstrated credentials in the Hydrocarbon EPC space. We are proud of our LTEH team.”

Commenting on the recent ultra-mega award, Mr Subramanian Sarma, Whole-time Director and Senior Executive Vice President (Energy), said, “In the ever-evolving landscape of the oil and gas sector, this twin win for LTEH demonstrates our execution and delivering capabilities of ultra-mega projects. It drives us to constantly strive for excellence, to innovate, and to deliver solutions that exceed customer expectations.”

Organised under Offshore, Onshore, Construction Services, Modular Fabrication and Advanced Value Engineering & Technology (AdVENT) verticals, LTEH offers integrated design-to-build solutions across the hydrocarbon sector to domestic and international customers. With over three decades of rich experience, LTEH has been setting global benchmarks in all aspects of project management, corporate governance, quality, HSE and operational excellence.

McDermott, PTSC Consortium Receives Limited Letter of Award for Block B Gas Development Project Offshore Vietnam

A consortium comprised of McDermott and Petrovietnam Technical Services Corporation (PTSC) has received a limited letter of award from Phu Quoc Petroleum Operating Company for engineering, procurement, construction, installation (EPCI), and hook-up and commissioning (HUC) services.

Under the full project scope, the consortium will provide EPCI and HUC services for a central production platform, living quarters platform, flare tower, and bridges for the Block B gas development project off the southwest coast of Vietnam.

"This award combines our 50 years of experience executing complex EPCI projects in the region with PTSC's technical strengths," said Mahesh Swaminathan, McDermott's Senior Vice President, Subsea and Floating Facilities. "Together, we will initiate this important groundwork as we finalize the full project scope and ultimately deliver another world-class project for Vietnam."

The full project contract is expected to be executed between the parties in early 2024 with an award value of more than $1 billion.

TechnipFMC Awarded Flexible Pipe Contract for Woodside Energy’s Trion Project

TechnipFMC (NYSE: FTI) has been awarded a contract to manufacture flexible pipe by Woodside Energy (LON: WDS).

The Company will supply infield flowlines and jumpers for the Trion project in deepwater Mexico.

Jonathan Landes, President, Subsea at TechnipFMC, commented: “We worked with Woodside to formulate the best technical solution for this milestone project. This contract is our largest flexible pipe award in the Gulf of Mexico to date, and builds upon the trust we have established with Woodside over many years of successful execution and delivery.”

Peyto Announces Closing Of Repsol Acquisition

Peyto Exploration & Development Corp. ("Peyto" or the "Company") is pleased to announce that it has completed its previously announced acquisition of Repsol Canada Energy Partnership, which holds the Canadian upstream oil and gas business of Repsol Exploración, S.A.U. ("Repsol"), including all related midstream facilities and infrastructure located predominantly in the Deep Basin area of Alberta, for cash consideration of US$468 million (CDN$636 million) (the "Acquisition") prior to closing adjustments. The Acquisition increases Peyto’s current production to 123,000 boe/d (86% natural gas, 14% NGLs), adds over 800 highimpact gross drilling locations1 and includes extensive gas processing and pipeline infrastructure that complement Peyto’s legacy assets in the Edson area. Peyto has plans to begin drilling operations on the Repsol lands, immediately. 

Shell completes sale of interest in Indonesia’s Masela block

Shell Upstream Overseas Services (I) Limited (“SUOS”), a subsidiary of Shell plc, has completed the
previously announced sale of its 35% participating interest in Indonesia’s Masela Production Sharing Contract (“Masela PSC”) to Indonesia’s PT Pertamina Hulu Energi and PETRONAS Masela Sdn. Bhd (“Petronas Masela”).

The sale includes the Abadi gas project. Completion of the sale follows regulatory approval from Indonesia’s Ministry of Energy and Mineral Resources for the transfer of SUOS’ stake to PT Pertamina Hulu Energi Masela and Petronas Masela.

This divestment is in line with Shell’s focus on disciplined capital allocation. Shell remains active in Indonesia’s downstream and low-carbon fuel sectors.

Notes to editors

• INPEX Corporation (“INPEX”) holds a 65% operating interest in Masela PSC and is the operator of the Abadi gas project. This is located in the Masela block, 150 kilometers offshore Saumlaki in Maluku province, Indonesia.
• SUOS acquired its interest in the Masela PSC in 2011.

Chevron announces agreement to acquire Hess

Chevron Corporation (NYSE: CVX) announced today that it has entered into a definitive agreement with Hess Corporation (NYSE: HES) to acquire all of the outstanding shares of Hess in an all-stock transaction valued at $53 billion, or $171 per share based on Chevron’s closing price on October 20, 2023. Under the terms of the agreement, Hess shareholders will receive 1.0250 shares of Chevron for each Hess share. The total enterprise value, including debt, of the transaction is $60 billion.

The acquisition of Hess upgrades and diversifies Chevron’s already advantaged portfolio. The Stabroek block in Guyana is an extraordinary asset with industry leading cash margins and low carbon intensity that is expected to deliver production growth into the next decade. Hess’ Bakken assets add another leading U.S. shale position to Chevron’s DJ and Permian basin operations and further strengthen domestic energy security. The combined company is expected to grow production and free cash flow faster and for longer than Chevron’s current five-year guidance. In addition, John Hess is expected to join Chevron’s Board of Directors.

“This combination positions Chevron to strengthen our long-term performance and further enhance our advantaged portfolio by adding world-class assets,” said Chevron Chairman and CEO Mike Wirth. “Importantly, our two companies have similar values and cultures, with a focus on operating safely and with integrity, attracting and developing the best people, making positive contributions to our communities and delivering higher returns and lower carbon.”

“Building on our track record of successful transactions, the addition of Hess is expected to extend further Chevron’s free cash flow growth,” said Pierre Breber, Chevron’s CFO. “With greater confidence in projected long-term cash generation, Chevron intends to return more cash to shareholders with higher dividend per share growth and higher share repurchases.”

“This strategic combination brings together two strong companies to create a premier integrated energy company,” CEO John Hess said. “I am proud of our people and what we have achieved as a company, which has one of the industry’s best growth portfolios including Guyana, the world’s largest oil discovery in the last 10 years, and the Bakken shale, where we are a leading oil and gas producer. Chevron has a world-class diversified portfolio of assets and one of the industry’s strongest balance sheets and cash return profiles. I believe our strategic combination creates a company that is stronger in every respect, with the leadership, asset portfolio and financial resources to lead us through the energy transition and deliver significant shareholder value for years to come.”

Transaction Benefits

• Strong strategic fit:
• Guyana – 30% ownership in more than 11 billion barrels of oil equivalent discovered recoverable resource with high cash margins per barrel, strong production growth outlook and potential exploration upside.
• Bakken – 465,000 net acres of high-quality, long-duration inventory supported by the integrated assets of Hess Midstream.
• Complementary Gulf of Mexico assets and steady free cash flow from Southeast Asia natural gas business.
• Accretive to cash flow per share and extends growth into 2030s:
• Expected to be accretive to cash flow per share in 2025 after achieving synergies and start-up of the fourth floating production storage and offloading (FPSO) vessel in Guyana.
• Increases Chevron’s estimated five-year production and free cash flow growth rates and expected to extend such growth into the next decade.
• Increases cash returned to shareholders:
• In January, Chevron expects to recommend an increase to its first quarter dividend per share of 8% to $1.63, which will be subject to the approval of the Chevron Board of Directors.
• Post closing, Chevron intends to increase share repurchases by $2.5 billion to the top end of its guidance range of $20 billion per year in a continued upside oil price scenario.
• Capital and cost efficient:
• The combined company’s capital expenditures budget is expected to be between $19 and $22 billion.
• With a stronger portfolio after closing, Chevron expects to increase asset sales and generate $10 to $15 billion in before-tax proceeds through 2028.
• The transaction is expected to achieve run-rate cost synergies around $1 billion before tax within a year of closing.

Hess Assets:

• Block A 18 Gas Fields - A Barrel Full
• Baldpate Oil and Gas Field - A Barrel Full
• Liza Oil Field - A Barrel Full
• Llano Oil and Gas Field - A Barrel Full
• North Malay Basin Gas Fields - A Barrel Full
• Payara Oil Field - A Barrel Full
• Stampede TLP Oil and Gas Fields Development - A Barrel Full
• Tubular Bells Oil and Gas Field - A Barrel Full
• Uaru Oil Field - A Barrel Full
• Yellowtail Oil Field - A Barrel Full

Acquisition of shares in the Reggane Nord gas project closed

Wintershall Dea is expanding its presence in Algeria. Following the completion of the transaction and regulatory approvals, the company is increasing its participating interest in the Reggane Nord natural gas project by 4.5 per cent through the acquisition of interest from former project partner Edison. The Groupement Reggane Nord, operator of the project, will thus consist of Sonatrach (40%), Repsol (36%), and Wintershall Dea (24%).

For Wintershall Dea, all signs point to growth in Algeria. The company has been active in the North African country since 2002. Since production began in Reggane Nord in December 2017, around 13 billion cubic meters of gas have been produced in the consortium. Its business in Algeria is an important part of the company's portfolio and is to be expanded in the future. To this end, in February 2022 Wintershall Dea and partner Sonatrach extended an existing Memorandum of Understanding to consider new business opportunities in Algeria, not just in natural gas but also in hydrogen and Carbon Capture and Storage (CCS).

Dawn Summers, Chief Operating Officer and the responsible Board Member for Algeria, says: "We see great potential for the future of the Algerian energy sector; both for the expansion of natural gas production, and for carbon management and hydrogen projects. Areas in which Wintershall Dea intends to become active in Algeria in the future. With the acquisition of further interest in Reggane Nord, we are now consolidating our presence in Algeria and setting the course for growth."

Thomas Ruttmann, Senior Vice President and Managing Director Wintershall Dea Algeria says: "Reggane Nord has been producing natural gas reliably and cost-efficiently since 2017. Wintershall Dea is not just an investor, our team is actively contributing experience and know-how and effectively contributes to the efficiency of the project – especially our drilling and reservoir expertise is in demand here. We are pleased to now increase our participating interest in the project and continue to actively advance Reggane Nord in the future."

Algeria is the largest producer of natural gas in Africa and the third largest exporter of natural gas to Europe. The North African country therefore makes a decisive contribution to Europe's energy supply and is the ideal partner for Europe to secure its energy supply and at the same time advance the energy transition.

Green light for Breidablikk

The Norwegian Petroleum Directorate (NPD) has granted consent for start-up of the Breidablikk field in the North Sea. Production is expected to start in October.

Breidablikk is an oil field situated ten kilometres northeast of the Grane field, west of Haugesund. Equinor is the operator, while Vår, ConocoPhillips and Petoro are licensees.

The field is a subsea development with four subsea templates, each with six well slots.

Breidablikk contains around 30 million standard cubic metres of recoverable oil (approx. 190 million barrels of oil). Total investments are around NOK 19 billion.

Ready for Tommeliten A start-up

The authorities have granted consent for start-up of the Tommeliten A field in the North Sea.

Operator Conoco Phillips estimates that around 24 million standard cubic metres (150 million barrels) of oil equivalent can be recovered from Tommeliten A. 

The operator estimates investments for developing Tommeliten A at ca NOK 13 billion . Conoco Phillips expects the field to come on stream this month. The plan for development and operation (PDO) was approved in 2022, and the discovery was made as early as 1977.

The field, which mainly contains gas and condensate, is located in production licence 044. It is a transboundary field, with a marginal share on the UK shelf. The licensees on the Norwegian and UK sides have unitised the activity. Tommeliten A is a gas and condensate field southwest of the Ekofisk field in the southern part of the Norwegian sector.

Tommeliten A is a subsea development with two subsea templates, with enough space to accommodate a total of twelve wells. The wellstream will be routed to the Ekofisk field for further processing and export. The gas will be exported to Emden in Germany, while oil and wet gas will be routed via pipeline to Teesside in the United Kingdom.  

Tommeliten A will include eleven development wells, seven of which will be completed as of start-up. The operator expects to complete the four remaining wells during the first quarter of 2024.

The twelfth well slot will be reserved as a potential future replacement well. 

“The Tommeliten A development is a good example of sound utilisation of existing infrastructure in the area”, says Tomas Mørch, assistant director of Licence Management in the Norwegian Petroleum Directorate. 

“It’s gratifying to see that an older discovery from 1977 has now been matured into a profitable and robust field development that’s ready to come on stream. It’s also gratifying that the project has been completed ahead of schedule and within the cost framework.”
“We also note that the same type of subsea technology used on Tommeliten A could potentially be applied for other development projects in the area.”
 
Several attempts to mature Tommeliten A have been made in the past. Insufficient processing capacity on Ekofisk was one of the roadblocks encountered. This is no longer an issue.

Saipem awarded new contract by ADNOC in the United Arab Emirates worth around 4.1 billion USD

Saipem, in consortium with National Petroleum Construction Company (NPCC), has signed today a letter of award with ADNOC for a new contract related to the Hail and Ghasha Development Project – Package 1 in the United Arab Emirates. Saipem's share of the contract amounts to around 4.1 billion USD.

The project is aimed at developing the resources of the Hail and Ghasha natural gas fields, located offshore Abu Dhabi, UAE. The project scope of work encompasses the Engineering, Procurement and Construction (EPC) of four drilling centres and one processing plant to be built on artificial islands, as well as various offshore structures and more than 300 km of subsea pipelines.

The award is in line with Saipem’s unique capability to deliver integrated onshore and offshore projects, providing its clients with a single and reliable interface for complex full-field developments. Saipem will leverage on its state-of-the-art shallow water offshore vessels, its advanced welding technology for corrosion resistant materials, as well as its renowned engineering expertise. Furthermore, Saipem will work with ADNOC to continue the project's focus on biodiversity and responsible environmental stewardship.

This award reinforces Saipem’s long-standing relationship with ADNOC and further consolidates the company’s presence in Abu Dhabi, which includes an Engineering and Project Execution Centre, as well as a new Offshore Logistic base in Zayed Port.

SBM Offshore awarded FEED contracts for Whiptail project in Guyana

SBM Offshore is pleased to announce it has been awarded contracts to perform Front End Engineering and Design (FEED) for a Floating Production, Storage and Offloading vessel (FPSO) for the Whiptail development project in Guyana.

Following FEED and subject to government approvals in Guyana of the development plan, project sanction including final investment decision by ExxonMobil Guyana Limited, an affiliate of ExxonMobil Corporation, to release the second phase of work, SBM Offshore will construct and install the FPSO. The FEED contract award triggers the initial release of funds by ExxonMobil Guyana Limited to begin FEED activities, and commits a Fast4Ward® hull for the execution of the Whiptail development project in Guyana.

Under the contracts, the FPSO’s ownership is expected to be transferred to the client at the end of the construction period and before start of operations in Guyana. The construction costs are expected to be partially funded by senior loans which will be repaid at the time of the FPSO’s transfer to the client.

SBM Offshore is expected to operate the FPSO through its integrated operations and maintenance model combining SBM Offshore and ExxonMobil’s expertise and experience, leveraging key learnings and the operational excellence of the units currently deployed in Guyana.

SBM Offshore will design and construct the FPSO using its industry-leading Fast4Ward® program using the Company’s seventh new build, Multi-Purpose Floater hull, combined with several standardized topsides modules. The FPSO will be designed to produce 250,000 barrels of oil per day, will have associated gas treatment capacity of 540 million cubic feet per day and water injection capacity of 300,000 barrels per day. The FPSO will be spread moored in water depth of about 1,630 meters and will be able to store around 2 million barrels of crude oil.

Building on the experience to date of FPSOs Liza Destiny, Liza Unity, Prosperity and ONE GUYANA, SBM Offshore continues to commit to local content development in Guyana by sourcing fabrication scope locally and integrating Guyanese engineers into the execution and operational teams.

Bruno Chabas, SBM Offshore’s Chief Executive Officer:

“We are proud to announce ExxonMobil Guyana has awarded the contracts for a fifth FPSO from SBM Offshore in Guyana. This project demonstrates once more the value that our industry-leading Fast4Ward® program brings to our clients and other stakeholders while delivering carbon efficient energy to the world.”

MAIRE awarded USD 8.7 billion contract by ADNOC for the onshore portion of the HAIL and GHASHA development project in Abu Dhabi. The largest award ever for the Group

MAIRE announces that Tecnimont, part of the Integrated E&C Solutions business unit, today signed a Letter of Award with ADNOC for the onshore processing plant of the Hail and Ghasha Development Project. The award was signed at ADIPEC, the world’s largest energy summit.

The Hail and Ghasha project is aimed to operate with net zero CO2 emissions, in part due to the facility’s CO2 carbon capture and recovery units, which will allow the capture and storage of CO2.

The overall EPC contract value is approximately USD 8.7 billion and project completion is expected during 2028. The scope of work includes two gas processing units, three sulphur recovery sections, the associated utilities and offsites as well as export pipelines. Tecnimont will also leverage the competences of MAIRE’s Sustainable Technology Solutions division to develop innovative digital solutions aimed at reducing emissions and optimizing energy consumption, allowing a significant efficiency of the plant in terms of opex and capex.

The engineering and procurement activities will be executed by several dedicated teams in Europe, India and the UAE, under the central coordination of MAIRE’s Milan headquarters. In particular, MAIRE’s UAE procurement hub will ensure the maximization of the local suppliers’ involvement, aimed at providing significant value to the local economy.

MAIRE has been active in the UAE since the late ‘90s, with several strategic projects in the Country for an overall total value of approximately USD 17 billion, starting from the first polyolefin plant completed in 2001 (Borouge 1). Additionally, the Group can leverage on a world class track record and experience in delivering large gas treatment plants and sulphur recovery projects.

Alessandro Bernini, MAIRE Group CEO, commented: “Today we have been awarded the largest contract ever for the MAIRE Group, a multi-billion-dollar project which will significantly boost the delivery of our 10-year strategic plan. We are honored to have achieved this great result with a leading global player such as ADNOC, as it represents further evidence of the strength of our long-lasting and fruitful relationship. This award, a landmark recognition of Made in Italy Engineering, is a demonstration not only of our leadership in sulphur recovery and in gas treatment plants but, more broadly, of our undisputed execution capabilities as well as our technological expertise in designing carbon-free industrial solutions.”

Keyera celebrates the completion of the KAPS pipeline

Keyera Corp. (TSX: KEY) ("Keyera"), one of Canada's largest independent midstream energy infrastructure businesses, recently completed the KAPS pipeline – Alberta's newest natural gas liquids (NGLs) and condensate pipeline spanning 575 kilometres, and supporting Canada's role on the global energy stage. KAPS is operated by Keyera and 50% owned by Stonepeak, a leading alternative investment firm specializing in infrastructure and real assets.

"KAPS is more than a pipeline, it's truly an energy infrastructure solution that is helping to unlock partnership and prosperity through a purposeful approach," says Dean Setoguchi, President & CEO of Keyera. "The support KAPS has received is a testament to both commercial need and the listen-first approach Keyera takes with external stakeholders and Indigenous communities. KAPS has been years in the making, and it is the platform that propels us forward and lets us focus on what we do best – supply responsibly produced Canadian energy."

The KAPS pipeline will safely transport 350,000 barrels per day of NGLs and condensate from the liquids-rich Montney and Duvernay basins to Keyera's liquids processing and storage hub in Alberta's Industrial Heartland, located in Fort Saskatchewan. By providing a competitive transportation alternative that allows producers to grow natural gas production, KAPS is advancing Alberta's energy industry. This highly desired industry pipeline solution is designed to integrate services, generate more volumes, and expand commercial opportunities; all of which drives benefit for Alberta and fuels greater domestic economic growth.

"The completion of the KAPS pipeline represents a significant milestone in the expansion of natural gas production in Western Canada. As natural gas continues to be a key contributor to the global energy mix and energy transition, especially in East Asia, we believe that KAPS has a critical role to play," says Anthony Borreca, Senior Managing Director at Stonepeak. "KAPS has the ability to support decarbonization and energy security goals on a local and global level and we look forward to continuing to partner with Keyera as responsible stewards of this asset as production gets underway."

Integral to the successful construction and completion of KAPS was Keyera's engagement and partnerships with communities along the pipeline route, including 10 municipalities, 22 Indigenous communities and 60 Indigenous-owned or affiliated businesses. Determining the pipeline route was a collaborative effort that extended well beyond regulatory, environmental, safety and land factors. It included input from traditional land use studies from each Indigenous community, approximately 400 site visits with Rights holders, and the approval of nearly 600 landowners and occupants.

"This is such great news for Keyera, its partners, and for Alberta," says the Honourable, Danielle Smith, Premier of Alberta. "KAPS is furthering economic opportunity and prosperity for Indigenous partners and communities as well as for the entire province. I'm excited to see the positive impacts this project will have and the economic growth we'll see in the years to come."

During construction, KAPS generated more than $650 million in labour income and 7.7 million people hours. Now in service, KAPS plays a key role in positioning Alberta as an integral conduit for petrochemical and upgrading feedstock in the region and a competitive world class destination for growth and investment today and tomorrow.

"This year Keyera celebrated our 25th anniversary, and we look forward to continuing to collaborate with the communities along the KAPS pipeline route for the next 25," says Setoguchi. "In recognition of today's celebration and in commitment to these communities, we are investing $300,000 from our Keyera Connects Social Investment Program into partnerships focused on capacity building and sustainability."

Eni announces a significant gas discovery in the Kutei Basin in Indonesia

Eni announces a significant gas discovery from the Geng North-1 exploration well drilled in North Ganal PSC, about 85 km off the cost of East Kalimantan in Indonesia. Preliminary estimates indicate a total structure discovered volume of 5 trillion cubic feet (Tcf) of gas in place with a content of condensate estimated up to 400 Mbbls; the acquired data will allow to study the options for a fast-track development.

Geng North-1 was drilled to a depth of 5,025 meters in 1,947 meters water depth, encountered a gas column about 50m thick in a Miocene sandstone reservoir with excellent petrophysical properties that has been subject of an extensive data acquisition campaign. A well production test (DST) has been successfully performed for a full assessment of the gas discovery and although limited by the test facilities, it has allowed to estimate a well capacity of up to 80-100 mmscfd and about 5-6 kbbld of condensate.

The discovery confirms the effectiveness of Eni’s strategy aimed at creating value through its deep knowledge of geological plays and the application of advanced geophysical technologies. The ongoing exploration campaign, along with the recent acquisitions, is in line with Eni’s energy transition strategy to progressively shift its portfolio mix towards gas and LNG, targeting 60% in 2030, and to increase its LNG equity portfolio. Indonesia, and South-East Asia in general, play a relevant role in this strategy.

Thanks to its location and significant size, the discovery has the potential to contribute substantially to the creation of a new production hub, in the Northern part of the Kutei Basin, to be connected to the Bontang LNG facilities on the coast of East Kalimantan, further exploiting its available ullage capacity. It is estimated that, in addition to Geng North, more than 5 Tcf of gas in place are present in undeveloped discoveries within the area of interest, while a significant multi-Tcf exploration potential is under maturation through the ongoing studies.

The Geng North discovery is adjacent to the Indonesia Deepwater Development (IDD) area that includes several stranded discoveries located within the Rapak and Ganal PSC blocks, for which Eni recently announced the acquisition of Chevron interests, increasing its participating interest and acquiring the operatorship. Significant synergies between the two areas are envisaged in terms of gas development options. The acquisition also provides the opportunity to fast track the development of the Gendalo and Gandang gas project (around 2 Tcf of gas reserves) through Eni’s operated Jangkrik facilities.

The Geng North discovery comes shortly after the announcement of Eni’s agreement to acquire Neptune Energy, whose completion will allow to further strengthen Eni’s position in the North Ganal Block.

Eni North Ganal Limited, holding 50.22% participating interest, operate the Block, with Neptune Energy North Ganal BV and Agra Energi I Pte Ltd as partners, holding the remaining 38.04% and 11.74% respectively.

Eni has been operating in Indonesia since 2001 and currently has a large portfolio of assets in exploration, development, and production phases with a current equity production of approximately 80,000 barrels of oil equivalent per day from the Jangkrik and Merakes fields in East Kalimantan.

Baker Hughes Strengthens Norway Presence with 2 Major Contracts from Vår Energi

Baker Hughes (NASDAQ: BKR), an energy technology company, announced Friday two awards from Vår Energi that expand its regional presence in the North Sea for exploration logging, well intervention technology and subsea production systems.

The first contract, a nine-year engagement, is a testament to Baker Hughes’ heightened well intervention capabilities gained through the strategic acquisition of Altus Intervention completed in April 2023. In addition to the interventions scope, Baker Hughes will supply all exploration logging solutions to help Vår Energi further develop their prospects in the Norwegian Continental Shelf. The agreement enables a seamless integration of Baker Hughes’ market-leading technologies into the wider operations of Vår Energi, enabling a powerful impact to their carbon reduction efforts.

The second contract with Vår Energi is to deliver a bespoke Balder field vertical tree system, a Baker Hughes technology selected for the complexities of this field.

This agreement spans 15 years, signifying a trusted long-term Future Agreement (FA) in one of Vår Energi’s core focus areas, the Balder field. The contract includes the support for existing Balder legacy wells and any future developments in the Balder area. This pivotal engagement is anchored by Baker Hughes’ distinct Norway delivery model, a multimodal site in Dusavik, Stavanger, that ensures a forward-looking local future for Norway’s oil and gas industry.

“Baker Hughes has an extensive and successful history of creating value for customers in Norway and the North Sea,” said Maria Claudia Borras, executive vice president, Oilfield Services & Equipment at Baker Hughes. “The two long-term contract awards from Vår Energi enable us to deploy our superior portfolio not only in well intervention, but also in exploration logging and subsea production. Combining our technology, our exceptional regional expertise, and our dedication to a world-class customer experience ensures successful outcomes for both companies.”

TechnipFMC Awarded Large iEPCI™ Contract for Equinor’s Rosebank Development

TechnipFMC (NYSE: FTI) has been awarded a large integrated Engineering, Procurement, Construction, and Installation (iEPCI™) contract by Equinor for its Rosebank project, west of the Shetland Isles in the United Kingdom.

The contract covers the manufacture and installation of subsea production systems, flexible and rigid pipe, and umbilicals, as well as connection to the host facility. The project will use pre-qualified equipment, which will accelerate the delivery schedule.

Jonathan Landes, President, Subsea at TechnipFMC, commented: “We have collaborated with Equinor on Rosebank since the concept stage in 2019. Using a single interface, we tied together all the work scopes, leveraging our iEPCI™ model to reduce project complexity. We are proud that our track record and proven technology have earned Equinor’s confidence that we will deliver this significant project.”

Umbilicals, rigid pipe, and the majority of the subsea production systems will be designed, engineered and manufactured in-country using TechnipFMC’s facilities and network of trusted local suppliers, then installed by TechnipFMC. Together, these activities will contribute significantly to value and job creation across the United Kingdom, which was an important factor in Equinor’s selection of the Company for this award. TechnipFMC has committed approximately $500 million of the total award to local value creation.

Rosebank field to progress in the UK

Equinor and Ithaca Energy have taken the final investment decision to progress Phase 1 of the Rosebank development on the UK Continental Shelf (UKCS), investing USD 3.8 billion.

The North Sea Transition Authority (NSTA) granted consent for the development of the field on 27 September.

“Developing the Rosebank field will allow us to grow our position as a broad energy partner to the UK, while optimising our oil and gas portfolio, and increasing energy supply in Europe. Rosebank provides an opportunity to develop a field within the UK Continental Shelf which will bring significant benefits to Scotland and the wider UK,” says Geir Tungesvik, executive vice president Projects, Drilling and Procurement at Equinor.

The Rosebank field is located around 130 kilometres north-west of Shetland in approximately 1,100 metres of water depth. Total recoverable resources are estimated at around 300 million barrels of oil, with Phase 1 targeting estimated 245 million barrels of oil.

The field will be developed with subsea wells tied back to a redeployed Floating Production Storage and Offloading vessel (FPSO), with start-up planned in 2026-2027. Oil will be transported to refineries by shuttle tankers, while gas will be exported through the West of Shetland Pipeline system to mainland Scotland.

“We are pleased to move forward with the Rosebank field together with Ithaca Energy,” says Philippe Mathieu, executive vice president for Exploration and Production International.

“This development further strengthens our international business, and we look forward to collaborating closely with our partner and suppliers to develop and operate Rosebank with the lowest possible carbon footprint while bringing the maximum value to society in the shape of UK investment, local jobs and energy security,” says Mathieu.

The Rosebank oil and gas field is being developed in compliance with the North Sea Transition Deal, an agreement between the UK government and the offshore industry. It acknowledges that whilst there is a continued, though over time reducing need for oil and gas, the remaining demand for oil and gas must be met with the lowest emissions possible.

The FPSO has been designed to be electrification-ready and Equinor is collaborating with government and industry to pursue a regional solution for power from shore to Rosebank and nearby fields to minimise carbon emissions from production.

According to an independent socioeconomic report by Wood Mackenzie and Voar Energy, Rosebank is estimated to create £8.1 billion of total direct investment over the lifetime of the field, of which 78% is likely to be invested in UK-based businesses. It is expected to support around 1,600 jobs during the height of the construction phase of the project, and it will continue to support approx. 450 UK-based jobs during the lifetime of the field.

"We know that the world needs to transition to new, cleaner energy systems and our broad energy investments into the UK support this. And while we do this there is going to be a continued need for oil and gas, which currently meets 76% of the UK’s energy needs. Our decision to progress the Rosebank development is the result of work and collaboration by our employees, partners, government, regulators, and other stakeholders to ensure that this development is able to help meet this ongoing need, with the lowest carbon footprint possible,” says Arne Gürtner, senior vice president Upstream at Equinor in the UK.

TechnipFMC has been awarded an integrated engineering, procurement, construction and installation (iEPCI™) contract for subsea production systems, umbilicals, risers and flowlines with an estimated value of around USD 500 million for the local content part. TechnipFMC has estimated that more than half of the contract value will be generated from local activities across the UK, with a large portion in Scotland.

Project management and engineering activities will be performed mainly from Aberdeen and tree systems will be manufactured in Dunfermline. Umbilicals will be produced in Newcastle, pipelines will be fabricated in Evanton and the main vessel mobilisation site will also be in the UK. In addition, several other fabrication sites in the UK will contribute to the project.

Odfjell Drilling has been awarded a rig contract, with an estimated value of USD 328 million including integrated services, modifications and options. The Deepsea Atlantic mobile rig is scheduled to start a seven-well drilling campaign in the second quarter of 2025, and in addition four single well options are included.

Altera has been awarded a bareboat charter and an operations and maintenance contract related to the Petrojarl Knarr FPSO which is set to be deployed on the Rosebank field on a firm contract for nine years, and options up to a total of 25 years.

Equinor has been a reliable energy partner to the UK for 40 years, providing a stable supply of oil and gas, developing the UK’s offshore wind industry, and pioneering solutions to decarbonise the UK economy.

Today, Equinor supplies 29% of the UK’s gas, and 15% of the UK’s oil. Equinor is currently working with government in developing plans to invest over £10 billion in the UK by 2030, in total creating over 5,000 high-quality jobs. For every £1 we plan to invest in the UK in oil and gas we aim to spend over £2 in renewables, CO2 capture and storage, and hydrogen.

Ithaca Energy To Acquire Remaining 30% Working Interest In Cambo

Ithaca Energy (LON: ITH) is pleased to announce that the Group has agreed, subject to regulatory approval, to acquire the remaining 30% stake in Cambo from Shell U.K. Limited (“Shell”) taking Ithaca Energy’s stake in Cambo to 100%.

The acquisition, which has minimal near-term cost exposure, will provide Ithaca Energy with full control over the progression of the future development of Cambo, the second largest undeveloped oil and gas discovery in the UK North Sea.

The consideration, in accordance with the previously announced terms dated 5 May, is payable on the earlier of (i) first oil; and (ii) the receipt of proceeds of any subsequent sale of a working interest in Cambo by Ithaca Energy; and is subject to Ithaca Energy proceeding with FID and/or the NSTA providing development consent.

Alan Bruce, Chief Executive Officer, Ithaca Energy, commented: “We are pleased to conclude the marketing process with Shell and to take full ownership of the Cambo development. Our primary focus continues to be the delivery of our BUY, BUILD and BOOST strategy, including the future development of Cambo, subject to fiscal conditions. We believe that Cambo has an important role to play in providing energy security and economic benefit to the UK, while reducing overall emissions intensity.”

Notes:

The Cambo field is the second largest undeveloped oil and gas discovery in the UK North Sea, located in the West of Shetland region. The development provides Ithaca Energy with long term production growth at a low expected unit operating cost per barrel. With its modern, energy efficient design and potential for electrification, Cambo could be one of the lowest-emission intensity assets in the North Sea. The field is expected to produce at less than half the CO2 intensity than the average UK field, enabled by the FPSO design which includes features such as being fully electrification ready (subject to grid connection availability), zero routine flaring and the Sevan FPSO hull design reducing power demand.

Shenzi North Production Start-Up

The Woodside-operated Shenzi North project has commenced production in the deepwater US Gulf of Mexico. 

Shenzi North is a two-well subsea tieback that takes advantage of the existing Shenzi infrastructure to increase production capacity of the asset. The project, on which a final investment decision (FID) was taken in July 2021, achieved production ahead of targeted first oil in 2024. 

Woodside CEO Meg O’Neill said the start-up of Shenzi North further demonstrated the value of Woodside’s US Gulf of Mexico assets, acquired as part of the merger with BHP’s petroleum business in 2022. 

“First production from Shenzi North shows how we are leveraging existing infrastructure to increase production and provide attractive returns from our Gulf of Mexico business. 

“Taking the project from FID to first oil in 26 months is a great achievement. I commend the project team on safely bringing this resource into production well ahead of schedule,” she said. 

Woodside holds a 72% interest in the Shenzi conventional oil and gas field as operator and Repsol holds the remaining 28% interest. The field is located approximately 195 km off the coast of Louisiana in the Green Canyon protraction area. Shenzi was discovered in 2002 and first production of oil and natural gas occurred in 2009. 

The Shenzi platform produces both oil and gas with a production capacity of 100,000 bbl/d and 50 MMscf/d. Crude oil and natural gas produced from the field is transported to connecting pipelines for onward sale to Gulf Coast customers.

ACE platform topsides unit sails away for offshore installation

bp as operator of the Azeri-Chirag-Deepwater Gunashli (ACG) field development project announces that today the Azeri Central East (ACE) platform topsides unit sailed away from the Bayil fabrication yard where it was built. Prior to its sail away the topsides unit was mostly commissioned and operationally tested onshore to minimise activities required for offshore installation and start-up.


On 4 April, the President of Azerbaijan Ilham Aliyev visited the topsides fabrication yard and toured the almost completed topsides unit before it had sailed away to its permanent location. Since then, the team have successfully completed the key commissioning activities planned to be performed onshore. These activities mainly included the successful completion of the rig access period, the integrated assurance test and the blowdown safety testing.


Following these completions, the topsides unit was safely jacked-up and lowered onto the load-out frame in preparation for skidding onto the transportation barge.


On 30 May, the transportation barge STB-1 arrived at the Bibi-Heybat yard and preparations for load out activities commenced. On 2 July, the topsides unit was transferred onto the STB-1 barge, sea-fastened and prepared for sail away to the ACG field.


The topsides transportation, float-over and installation activities have been carefully planned and are expected to take around four days to complete. The unit will be installed on top of the ACE platform jacket which has been at its offshore location since March installed in a water depth of 137 metres.



Gary Jones, bp’s regional president for Azerbaijan, Georgia and Türkiye, said:


“Today we sailed away the final section of the ACE platform which we believe is an amazing feat of innovative engineering with its state-of-the-art design that will make it possible to extensively use system and process automations and digital innovations. This platform will be controlled remotely from the Sangachal terminal and this is the first time in our experience in the Caspian that we will control an offshore platform from onshore.



As operator we are extremely pleased to have completed all onshore construction and commissioning activities of such a complex project safely. I would like to say a huge thank you to all people involved in the construction and commissioning works. My special thanks are to our fabrication contractors, construction, commissioning, operations, safety and engineering teams and all the workforce for their excellent performance and delivery.



We expect the topsides unit to be safely installed onto the jacket over the next week. We will then need a few months to complete offshore hook up and commissioning works to allow us to commence drilling the first platform production well and deliver ACE first oil in early 2024.”

The construction of the 19,600-tonne topsides unit started in 2019 and was completed with outstanding safety achievements of over 21 million hours worked injury free.

The ACE topsides unit consists of oil and gas processing facilities, an integrated drilling rig, a gas compressor and living quarters.

The topsides unit was constructed by Azfen in the Bayil fabrication yard using local infrastructure and resources.


Notes to editors

• The $6 billion ACE project is the next stage of development of the giant ACG field in the Caspian Sea.
• ACE is centred on a new 48-slot production, drilling and quarters platform located mid-way between the existing Central Azeri and East Azeri platforms in a water depth of approximately 140 metres. The project also includes new infield pipelines to transfer oil and gas from the ACE platform to the existing ACG Phase 2 oil and gas export pipelines for transportation to the onshore Sangachal terminal. 
• In addition, there is a water injection pipeline between the East Azeri and ACE platforms to supply injection water from the Central Azeri compression and water injection platform to the ACE facilities. 
• The ACE platform and facilities are designed to process up to 100,000 barrels of oil per day. The project is expected to produce up to 300 million barrels over its lifetime.
• At peak, over 8,500 people were involved in the ACE project construction works in Azerbaijan.