ExxonMobil made a final investment decision for the Uaru development offshore Guyana after receiving required government and regulatory approvals. The company expects Uaru, the fifth project on Guyana’s offshore Stabroek block, to add approximately 250,000 barrels of daily capacity after a targeted startup in 2026.
“Our fifth, multi-billion-dollar investment in Guyana exemplifies ExxonMobil’s long-term commitment to the country’s sustained economic growth,” said Liam Mallon, president of the ExxonMobil Upstream Company. “Our Guyana investments and unrivalled development success continue to contribute to secure, reliable global energy supplies at this critical time.”
The $12.7 billion Uaru project plans to include up to 10 drill centers and 44 production and injection wells aimed at developing an estimated resource of more than 800 million barrels of oil.
MODEC is constructing the Floating Production Storage and Offloading (FPSO) vessel for the Uaru project, which will be called the Errea Wittu. ExxonMobil is utilizing its diversified supplier base to help reduce costs and safely accelerate development in its Guyana operations. The company’s diverse supplier base includes nearly 1,000 unique local Guyanese suppliers, exemplifying Guyana’s growing in-country supply chain capabilities.
Two FPSOs, the Liza Destiny and Liza Unity, are currently operating offshore Guyana and safely produced an average of 375,000 barrels of oil per day in the first quarter. A third FPSO, the Prosperity, is expected to be operational later this year, adding 220,000 barrels of daily capacity from the Payara development. ExxonMobil made a final investment decision on the fourth offshore project, Yellowtail, last year. The company is targeting to have six FPSOs online by the end of 2027, bringing Guyana’s production capacity to more than 1.2 million barrels per day.
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 world with respect to emissions intensity, outpacing 75% of global oil and gas producing assets.
ExxonMobil affiliate Esso Exploration and Production Guyana Limited is operator and holds 45% interest in the Stabroek Block. Hess Guyana Exploration Ltd. holds 30% interest and CNOOC Petroleum Guyana Limited holds 25% interest.
Friday 28 April 2023
Thursday 27 April 2023
Suncor Energy to Acquire TotalEnergies' Canadian Operations for $5.5 Billion, Plus Additional Potential Payments up to an Aggregate Maximum of $600 Million
Suncor Energy (TSX: SU) (NYSE: SU) today announced that it has agreed to purchase TotalEnergies' Canadian operations through the acquisition of TotalEnergies EP Canada Ltd., which holds a 31.23% working interest in the Fort Hills oil sands mining project (Fort Hills) and a 50% working interest in the Surmont in situ asset. This will add 135,000 barrels per day of net bitumen production capacity and 2.1 billion barrels of proved and probable reserves to Suncor's oil sands portfolio. The acquisition is for cash consideration of $5.5 billion, with the potential for additional payments of up to an aggregate maximum of $600 million, conditional upon Western Canadian Select benchmark pricing and certain production targets. Subject to closing, the transaction will have an effective date of April 1, 2023.
"This transaction represents a major step in securing long-term bitumen supply to our Base Plant upgraders at a competitive supply cost," said Rich Kruger, President and Chief Executive Officer. "These are valuable oil sands assets that are a strategic fit for us and add long-term shareholder value. The acquisition also introduces flexibility and optionality into our long-range capital plan, providing us with further discretion in respect of the timing and scope of future oil sands developments."
With the transaction Suncor will have 100% ownership of Fort Hills, which along with the Firebag and MacKay River in situ assets, provides the company with sufficient long-life, physically-integrated bitumen supply in the Fort McMurray region to fully utilize the Base Plant upgraders post the end of the Base Mine life in the mid 2030s.
Surmont is a high-quality, producing asset which adds long-life production to Suncor's oil sands portfolio that is competitive with the company's organic development options. The asset also has the potential for growth through cost-competitive expansion. When the Base Mine life ends in the mid 2030s the bitumen production from the combination of the Fort Hills and Surmont interests will effectively replace half of the current Base Mine bitumen production. Replacement of the remaining Base Plant Mine bitumen production will involve economic decisions assessing the highest value use of capital in the future.
With Suncor's strong balance sheet the acquisition will be funded by debt. As a result, it is expected that net debt levels will temporarily exceed the company's $12-15 billion target range. The company will maintain the current allocation of funds flow after dividends, capital and non-operational benefits of 50% to debt reduction and 50% to share buybacks in line with the capital allocation framework. Suncor expects to return to within its target net debt range in 2024 based on current expected commodity prices. The acquisition is expected to strengthen the underlying business, result in increasing funds flow and be accretive to funds flow per share. Assuming the acquisition closes as contemplated, the Board currently intends to increase the quarterly dividend by approximately 10% following closing.
The Surmont in situ project is operated by ConocoPhillips Canada and upon closing, each of Suncor and ConocoPhillips Canada will hold a 50% working interest. Under the terms of the Surmont joint venture arrangements ConocoPhillips Canada has certain preemptive rights including a right of first refusal on the 50% Surmont working interest. Closing of the transaction is anticipated to occur in the third quarter of 2023 and is subject to waiver of the right of first refusal on the Surmont working interest and other customary closing conditions, including receipt of all required regulatory approvals.
The addition of these assets to Suncor's portfolio will be subject to our net zero by 2050 emissions reduction objective.
Suncor engaged J.P. Morgan Securities Canada to act as its exclusive financial advisor and Blake Cassels and Graydon LLP and Paul, Weiss, Rifkind, Wharton & Garrison LLP as its legal advisors on the transaction.
"This transaction represents a major step in securing long-term bitumen supply to our Base Plant upgraders at a competitive supply cost," said Rich Kruger, President and Chief Executive Officer. "These are valuable oil sands assets that are a strategic fit for us and add long-term shareholder value. The acquisition also introduces flexibility and optionality into our long-range capital plan, providing us with further discretion in respect of the timing and scope of future oil sands developments."
With the transaction Suncor will have 100% ownership of Fort Hills, which along with the Firebag and MacKay River in situ assets, provides the company with sufficient long-life, physically-integrated bitumen supply in the Fort McMurray region to fully utilize the Base Plant upgraders post the end of the Base Mine life in the mid 2030s.
Surmont is a high-quality, producing asset which adds long-life production to Suncor's oil sands portfolio that is competitive with the company's organic development options. The asset also has the potential for growth through cost-competitive expansion. When the Base Mine life ends in the mid 2030s the bitumen production from the combination of the Fort Hills and Surmont interests will effectively replace half of the current Base Mine bitumen production. Replacement of the remaining Base Plant Mine bitumen production will involve economic decisions assessing the highest value use of capital in the future.
With Suncor's strong balance sheet the acquisition will be funded by debt. As a result, it is expected that net debt levels will temporarily exceed the company's $12-15 billion target range. The company will maintain the current allocation of funds flow after dividends, capital and non-operational benefits of 50% to debt reduction and 50% to share buybacks in line with the capital allocation framework. Suncor expects to return to within its target net debt range in 2024 based on current expected commodity prices. The acquisition is expected to strengthen the underlying business, result in increasing funds flow and be accretive to funds flow per share. Assuming the acquisition closes as contemplated, the Board currently intends to increase the quarterly dividend by approximately 10% following closing.
The Surmont in situ project is operated by ConocoPhillips Canada and upon closing, each of Suncor and ConocoPhillips Canada will hold a 50% working interest. Under the terms of the Surmont joint venture arrangements ConocoPhillips Canada has certain preemptive rights including a right of first refusal on the 50% Surmont working interest. Closing of the transaction is anticipated to occur in the third quarter of 2023 and is subject to waiver of the right of first refusal on the Surmont working interest and other customary closing conditions, including receipt of all required regulatory approvals.
The addition of these assets to Suncor's portfolio will be subject to our net zero by 2050 emissions reduction objective.
Suncor engaged J.P. Morgan Securities Canada to act as its exclusive financial advisor and Blake Cassels and Graydon LLP and Paul, Weiss, Rifkind, Wharton & Garrison LLP as its legal advisors on the transaction.
Monday 17 April 2023
The Bauge field on stream
On 8 April production started from the Bauge subsea field in the Norwegian Sea. Bauge is tied back to the recently upgraded Njord platform. Recoverable reserves in Bauge are estimated at 50 million barrels of oil equivalent, mainly oil.
Bauge consists of two oil producers in a subsea template, in addition to pipelines and an umbilical connecting the wells to the Njord A platform. The Bauge licensees are Equinor (operator), Wintershall Dea, Vår Energi and Neptune Energy.
“The subsea facility was built and installed without a single HSE incident. I am very proud of this, and I would like to thank our suppliers, particularly the main suppliers Randaberg Industries, Ocean Installer and OneSubsea. This shows that the zero-harm vision is possible. Capital expenditures totalling NOK 4.6 billion (2023) the project was delivered within budget," says Trond Bokn, Equinor's senior vice president for project development.
The Norwegian content of the Bauge project is well over 90 percent. The wells were delivered faster than planned by Transocean and Schlumberger.
The project has been run in parallel with the extensive upgrading of Njord A (Aker Solutions) and the Njord Bravo FSO (Aibel).
“The Njord upgrading enables us to tie in new, valuable discoveries such as Bauge. By utilising existing infrastructure, we can realise profitable development of small-size discoveries in line with the company's strategy. We are planning further exploration activity in the area," says Grete B. Haaland, senior vice president for Exploration & Production North.
The Njord field came on stream in 1997. In 2016, the installations were brought ashore for extensive upgrading and in December 2022 the field came on stream again.
The field will now produce for another 20 years, and the ambition is to produce about the same volume from Njord and Hyme as the fields have produced so far, some 250 million barrels of oil equivalent.
Bauge consists of two oil producers in a subsea template, in addition to pipelines and an umbilical connecting the wells to the Njord A platform. The Bauge licensees are Equinor (operator), Wintershall Dea, Vår Energi and Neptune Energy.
“The subsea facility was built and installed without a single HSE incident. I am very proud of this, and I would like to thank our suppliers, particularly the main suppliers Randaberg Industries, Ocean Installer and OneSubsea. This shows that the zero-harm vision is possible. Capital expenditures totalling NOK 4.6 billion (2023) the project was delivered within budget," says Trond Bokn, Equinor's senior vice president for project development.
The Norwegian content of the Bauge project is well over 90 percent. The wells were delivered faster than planned by Transocean and Schlumberger.
The project has been run in parallel with the extensive upgrading of Njord A (Aker Solutions) and the Njord Bravo FSO (Aibel).
“The Njord upgrading enables us to tie in new, valuable discoveries such as Bauge. By utilising existing infrastructure, we can realise profitable development of small-size discoveries in line with the company's strategy. We are planning further exploration activity in the area," says Grete B. Haaland, senior vice president for Exploration & Production North.
The Njord field came on stream in 1997. In 2016, the installations were brought ashore for extensive upgrading and in December 2022 the field came on stream again.
The field will now produce for another 20 years, and the ambition is to produce about the same volume from Njord and Hyme as the fields have produced so far, some 250 million barrels of oil equivalent.
Sunday 16 April 2023
FPSO Prosperity arrives at the Stabroek Block offshore Guyana
SBM Offshore announces the arrival of FPSO Prosperity at the Payara Field in the Stabroek Block offshore Guyana.
The vessel travelled just over 11,000 nautical miles – or just over 20,000 kilometers - from Singapore in just under 50 days.
On track for first oil later this year, Prosperity becomes Guyana’s third FPSO joining Liza Destiny and Liza Unity.
The vessel travelled just over 11,000 nautical miles – or just over 20,000 kilometers - from Singapore in just under 50 days.
On track for first oil later this year, Prosperity becomes Guyana’s third FPSO joining Liza Destiny and Liza Unity.
Friday 14 April 2023
bp starts oil production at Argos platform in the Gulf of Mexico
bp has successfully started oil production at its Argos offshore platform, delivering more energy at a critical time and strengthening bp’s position as a leading producer in the deepwater US Gulf of Mexico.
With a gross production capacity of up to 140,000 barrels of oil per day, Argos is bp’s fifth platform in the Gulf of Mexico and the first new bp-operated production facility in the region since 2008. The semi-submersible platform ultimately will increase bp’s gross operated production capacity in the Gulf of Mexico by an estimated 20%. bp expects to safely and systematically ramp up production from Argos through 2023.
bp chief executive Bernard Looney said: “The start-up of Argos is a fantastic achievement that helps deliver our integrated energy strategy – investing in today’s energy system and, at the same time, investing in the energy transition. As bp’s most digital facility worldwide, applying our latest technologies, Argos will strengthen our key position in the Gulf of Mexico for years to come.”
Argos is the centerpiece of bp’s Mad Dog Phase 2 project, which extends the life of the super-giant oil field discovered in 1998. It is one of nine high-margin major projects that bp plans start up by the end of 2025 globally.
Starlee Sykes, bp senior vice president, Gulf of Mexico and Canada, said: “Safely starting up the Argos platform is an incredible milestone for bp and a proud moment for our team who delivered the project with an impeccable safety record. Producing some of bp’s highest value, lowest operational emissions barrels, our Gulf of Mexico business has an important role to play in delivering the energy the world needs. I am grateful to everyone who worked on Argos over the years – from discovery to start-up.”
David Lawler, chairman and president bp America: “Argos demonstrates bp’s continued commitment to investing in the US. We’re one of the largest energy producers in the country and are adding more resilient hydrocarbons at a critical moment.”
Operating in 4,500 feet of water about 190 miles south of New Orleans, Argos will support 250 permanent jobs. Standing 27 stories tall, the platform has a deck the length and width of an American football field and weighs more than 60,000 tons.
Ewan Drummond, senior vice president, projects, production and operations, said: “Projects like Argos don’t just happen. They take years of careful planning, execution excellence, and brilliant teamwork. Argos is key to our strategy of increasing our Gulf of Mexico production to around 400,000 barrels of oil equivalent per day by the middle of this decade.”
Argos is bp’s most digitally advanced platform operating in the Gulf of Mexico, featuring bp’s proprietary LoSal® Enhanced Oil Recovery (EOR) and Dynamic Digital Twin technologies. Argos has a waterflood injection capacity of more than 140,000 barrels of low-salinity water per day to help increase oil recovery from the Mad Dog field. The platform also has a Dynamic Digital Twin, a bp patent-pending software that links complex data from Argos to 3D digital models of those systems, allowing remote operators wearing Virtual Reality headsets to access data in real time to improve decision-making, efficiency and safety.
bp is the operator with 60.5% working interest. Co-owners include Woodside Energy (23.9%) and Union Oil Company of California, an affiliate of Chevron U.S.A. Inc. (15.6%).
With a gross production capacity of up to 140,000 barrels of oil per day, Argos is bp’s fifth platform in the Gulf of Mexico and the first new bp-operated production facility in the region since 2008. The semi-submersible platform ultimately will increase bp’s gross operated production capacity in the Gulf of Mexico by an estimated 20%. bp expects to safely and systematically ramp up production from Argos through 2023.
bp chief executive Bernard Looney said: “The start-up of Argos is a fantastic achievement that helps deliver our integrated energy strategy – investing in today’s energy system and, at the same time, investing in the energy transition. As bp’s most digital facility worldwide, applying our latest technologies, Argos will strengthen our key position in the Gulf of Mexico for years to come.”
Argos is the centerpiece of bp’s Mad Dog Phase 2 project, which extends the life of the super-giant oil field discovered in 1998. It is one of nine high-margin major projects that bp plans start up by the end of 2025 globally.
Starlee Sykes, bp senior vice president, Gulf of Mexico and Canada, said: “Safely starting up the Argos platform is an incredible milestone for bp and a proud moment for our team who delivered the project with an impeccable safety record. Producing some of bp’s highest value, lowest operational emissions barrels, our Gulf of Mexico business has an important role to play in delivering the energy the world needs. I am grateful to everyone who worked on Argos over the years – from discovery to start-up.”
David Lawler, chairman and president bp America: “Argos demonstrates bp’s continued commitment to investing in the US. We’re one of the largest energy producers in the country and are adding more resilient hydrocarbons at a critical moment.”
Operating in 4,500 feet of water about 190 miles south of New Orleans, Argos will support 250 permanent jobs. Standing 27 stories tall, the platform has a deck the length and width of an American football field and weighs more than 60,000 tons.
Ewan Drummond, senior vice president, projects, production and operations, said: “Projects like Argos don’t just happen. They take years of careful planning, execution excellence, and brilliant teamwork. Argos is key to our strategy of increasing our Gulf of Mexico production to around 400,000 barrels of oil equivalent per day by the middle of this decade.”
Argos is bp’s most digitally advanced platform operating in the Gulf of Mexico, featuring bp’s proprietary LoSal® Enhanced Oil Recovery (EOR) and Dynamic Digital Twin technologies. Argos has a waterflood injection capacity of more than 140,000 barrels of low-salinity water per day to help increase oil recovery from the Mad Dog field. The platform also has a Dynamic Digital Twin, a bp patent-pending software that links complex data from Argos to 3D digital models of those systems, allowing remote operators wearing Virtual Reality headsets to access data in real time to improve decision-making, efficiency and safety.
bp is the operator with 60.5% working interest. Co-owners include Woodside Energy (23.9%) and Union Oil Company of California, an affiliate of Chevron U.S.A. Inc. (15.6%).
Monday 10 April 2023
Saipem: awarded new offshore EPCI contracts and competitive FEED contracts totalling approximately 650 million USD
Saipem has been awarded three new offshore contracts and two competitive FEED contracts totalling approximately 650 million USD.
The first contract has been assigned by Azule Energy for the Agogo Full Field Development project, a deepwater greenfield development, approximately 180 kilometres offshore Angola, about 20 kilometres west of the N’Goma FPSO (West Hub), which has been in operation since November 2014. The contract encompasses the Engineering, Procurement, Construction and Installation (EPCI) of rigid Pipe-In-Pipe flowlines with associated subsea structures. Saipem will mobilize its state-of-art offshore installation vessel FDS2.
The second contract has been awarded by EnQuest for the decommissioning of existing infrastructures in the Heather oil field, located in the UK sector of the North Sea, around 460 kilometres northeast of Aberdeen. Saipem’s activities entail the engineering, preparation, removal and disposal of the upper jacket of the Heather platform, utilising the semisubmersible crane vessel Saipem 7000.
The third contract has been awarded under the Aramco LTA program in Saudi Arabia. Saipem will execute the offshore EPCI of one platform topside and the associated subsea flexible, umbilical and cable system.
Furthermore, Saipem has been awarded two Front-End Engineering Design (FEED) Competition contracts for gas development projects. The first one, assigned by Shell Trinidad & Tobago Ltd., is related to the development of the Manatee natural gas field. The second contract has been assigned to Saipem, in partnership with PT Tripatra Engineers and Constructors and Daewoo Engineering & Construction Co. Ltd., by PAPUA LNG Development Pte. Ltd. It concerns the development of the upstream facilities to feed the natural gas PAPUA LNG project in Papua New Guinea.
These important contracts further consolidate the positioning of Saipem both geographically and in key segments for the offshore business, in particular in decommissioning where the company boasts an important track record. In addition, these awards leverage on Saipem’s combination of its unique assets and expertise in competitive FEEDs that allow for the presentation of effective offers and safe and innovative solutions.
The first contract has been assigned by Azule Energy for the Agogo Full Field Development project, a deepwater greenfield development, approximately 180 kilometres offshore Angola, about 20 kilometres west of the N’Goma FPSO (West Hub), which has been in operation since November 2014. The contract encompasses the Engineering, Procurement, Construction and Installation (EPCI) of rigid Pipe-In-Pipe flowlines with associated subsea structures. Saipem will mobilize its state-of-art offshore installation vessel FDS2.
The second contract has been awarded by EnQuest for the decommissioning of existing infrastructures in the Heather oil field, located in the UK sector of the North Sea, around 460 kilometres northeast of Aberdeen. Saipem’s activities entail the engineering, preparation, removal and disposal of the upper jacket of the Heather platform, utilising the semisubmersible crane vessel Saipem 7000.
The third contract has been awarded under the Aramco LTA program in Saudi Arabia. Saipem will execute the offshore EPCI of one platform topside and the associated subsea flexible, umbilical and cable system.
Furthermore, Saipem has been awarded two Front-End Engineering Design (FEED) Competition contracts for gas development projects. The first one, assigned by Shell Trinidad & Tobago Ltd., is related to the development of the Manatee natural gas field. The second contract has been assigned to Saipem, in partnership with PT Tripatra Engineers and Constructors and Daewoo Engineering & Construction Co. Ltd., by PAPUA LNG Development Pte. Ltd. It concerns the development of the upstream facilities to feed the natural gas PAPUA LNG project in Papua New Guinea.
These important contracts further consolidate the positioning of Saipem both geographically and in key segments for the offshore business, in particular in decommissioning where the company boasts an important track record. In addition, these awards leverage on Saipem’s combination of its unique assets and expertise in competitive FEEDs that allow for the presentation of effective offers and safe and innovative solutions.
Eni Celebrates Sail Away of FPSO Firenze to Baleine Field Offshore Côte d'Ivoire
Eni, in partnership with PetroCi, celebrated the sail away of the FPSO Firenze to the Baleine field offshore Côte d'Ivoire in Dubai. The event was attended by Mamadou Sangafowa-Coulibaly, Minister of Mines, Petroleum and Energy Côte of d'Ivoire, and other dignitaries.
The FPSO Firenze will allow production start-up of the Baleine field, which is the largest hydrocarbon discovery in Côte d'Ivoire to date, with an estimated oil in place of 2.5 billion barrels and 3.3 trillion cubic feet of associated gas. The development of Baleine will also be Africa's first net-zero emission project (Scope 1 and 2).
The FPSO Firenze, that will be renamed Baleine after its arrival in Cote d’Ivoire, has been refurbished and upgraded in order to allow it to treat up to 15,000 bbl/d of oil and around 25 Mcfd/d of associated gas. The entire gas production will be delivered onshore via a newly built export pipeline. The installation of the subsea production system and well completion campaign are underway and will ensure an accelerated start-up of production by June 2023.
Eni's phased development model and fast track have proven to be effective, as the project is set to start production less than 2 years from the Baleine 1X discovery well and one and a half years after the FID. Eni is already progressing swiftly on the second phase of the project forecasting a start-up of production by December 2024 after having taken the FID in December 2022.
Eni is committed to sustainable development, and the Baleine field's net-zero emission project is a significant step towards achieving this goal. The company looks forward to contributing to the development of Côte d'Ivoire's hydrocarbon industry with the Baleine field and its other projects in the Ivorian deep water.
The Baleine field extends over blocks CI-101 and CI-802. Eni also owns interests in four other blocks in the Ivorian deep water: CI-205, CI-501, CI-401, and CI-801, all with the same partner, PetroCi Holding.
The FPSO Firenze will allow production start-up of the Baleine field, which is the largest hydrocarbon discovery in Côte d'Ivoire to date, with an estimated oil in place of 2.5 billion barrels and 3.3 trillion cubic feet of associated gas. The development of Baleine will also be Africa's first net-zero emission project (Scope 1 and 2).
The FPSO Firenze, that will be renamed Baleine after its arrival in Cote d’Ivoire, has been refurbished and upgraded in order to allow it to treat up to 15,000 bbl/d of oil and around 25 Mcfd/d of associated gas. The entire gas production will be delivered onshore via a newly built export pipeline. The installation of the subsea production system and well completion campaign are underway and will ensure an accelerated start-up of production by June 2023.
Eni's phased development model and fast track have proven to be effective, as the project is set to start production less than 2 years from the Baleine 1X discovery well and one and a half years after the FID. Eni is already progressing swiftly on the second phase of the project forecasting a start-up of production by December 2024 after having taken the FID in December 2022.
Eni is committed to sustainable development, and the Baleine field's net-zero emission project is a significant step towards achieving this goal. The company looks forward to contributing to the development of Côte d'Ivoire's hydrocarbon industry with the Baleine field and its other projects in the Ivorian deep water.
The Baleine field extends over blocks CI-101 and CI-802. Eni also owns interests in four other blocks in the Ivorian deep water: CI-205, CI-501, CI-401, and CI-801, all with the same partner, PetroCi Holding.
Monday 3 April 2023
KBR Awarded Front End Engineering Design Contract for Equinor Bay du Nord FPSO Project
KBR (NYSE: KBR) announced today that its Canadian entity, KBR Industrial Canada Co., has received a Letter of Intent (LOI) from Equinor Canada for the front-end engineering design (FEED) of the topside facilities of the new Bay Du Nord floating production, storage, and offloading facility (FPSO) to be located offshore Newfoundland, Canada.
The agreement also includes an option for continuation of detailed design and procurement management services through to final completion of the FPSO. The FEED scope comes on the back of the pre-FEED engineering carried out by KBR in 2022 and will further mature the engineering and execution planning, working towards a final investment decision with first production expected to be in the late 2020s.
During the FEED engineering, KBR will continue to help Equinor develop one of the lowest carbon emitting FPSO’s in the world, using an onboard combined cycle power system and the latest technology to minimize the number of crew onboard and maximize digital solutions. All these elements will produce energy safely and securely while minimizing carbon emissions.
KBR will execute the work scope jointly with Canadian sub-contractor Hatch Ltd., an employee-owned multidisciplinary engineering, project management, and professional services firm with a local office in St. John’s, Canada, and will provide Equinor with an integrated team across Canada and London.
The Bay du Nord FPSO is a deep-water facility utilizing industry leading technology and digital solutions to ensure safe and reliable production. This award builds upon KBR’s unrivalled knowledge and expertise in this arena.
“We are excited to be a part of this significant project with Equinor,” said Jay Ibrahim, president of KBR’s Sustainable Technology Solutions business. “This win is indicative of KBR’s strategic commitment to work with clients not only to secure energy supply for the world but to do it in a safe, responsible, and sustainable way. KBR adds maximum value to clients such as Equinor, by drawing on our extensive global engineering expertise and applying the latest technology and processes to deliver extraordinary outcomes.”
The agreement also includes an option for continuation of detailed design and procurement management services through to final completion of the FPSO. The FEED scope comes on the back of the pre-FEED engineering carried out by KBR in 2022 and will further mature the engineering and execution planning, working towards a final investment decision with first production expected to be in the late 2020s.
During the FEED engineering, KBR will continue to help Equinor develop one of the lowest carbon emitting FPSO’s in the world, using an onboard combined cycle power system and the latest technology to minimize the number of crew onboard and maximize digital solutions. All these elements will produce energy safely and securely while minimizing carbon emissions.
KBR will execute the work scope jointly with Canadian sub-contractor Hatch Ltd., an employee-owned multidisciplinary engineering, project management, and professional services firm with a local office in St. John’s, Canada, and will provide Equinor with an integrated team across Canada and London.
The Bay du Nord FPSO is a deep-water facility utilizing industry leading technology and digital solutions to ensure safe and reliable production. This award builds upon KBR’s unrivalled knowledge and expertise in this arena.
“We are excited to be a part of this significant project with Equinor,” said Jay Ibrahim, president of KBR’s Sustainable Technology Solutions business. “This win is indicative of KBR’s strategic commitment to work with clients not only to secure energy supply for the world but to do it in a safe, responsible, and sustainable way. KBR adds maximum value to clients such as Equinor, by drawing on our extensive global engineering expertise and applying the latest technology and processes to deliver extraordinary outcomes.”
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