Subsea7 today announced the award of a sizeable(1) contract by bp to Subsea Integration Alliance(2), for the Murlach development (formerly Skua field), 240 kilometres east of Aberdeen in the UK North Sea.
The project work scope covers the engineering, procurement, construction and installation of the subsea pipelines (SURF) and production systems (SPS). It includes the first deployment of OneSubsea’s standard, configurable, vertical monobore tree systems in the UK North Sea, which will be deployed via vessel to reduce drill rig days. OneSubsea will deliver two vertical monobore trees, a 2-slot manifold, and associated topside controls. The Alliance worked with bp to develop a technology solution leveraging OneSubsea’s field-proven standard equipment, which is simpler to design and quicker to install when compared with traditional configured-to-order subsea systems.
Subsea7 will install eight kilometres of rigid flowline and two flexible jumpers, along with associated subsea infrastructure. The new flowline will be tied-back to the Eastern Trough Area Project (ETAP) facility. Fabrication of the pipelines will take place at Subsea7’s spoolbase at Vigra, Norway and offshore operations are expected to be executed in 2025.
Olivier Blaringhem, Chief Executive Officer of Subsea Integration Alliance said: “This is bp’s third fully integrated EPCI project with Subsea Integration Alliance marking an important milestone as we extend our support to the UK North Sea market.”
Hani El Kurd, Senior Vice President for Subsea7 UK & Global Inspection, Repair and Maintenance, said: “We are delighted to be awarded this contract by bp, as it recognises Subsea Integration Alliance’s global reputation for seamless, full subsea system delivery. Subsea7 has a long relationship with bp and we look forward to supporting their Murlach development.”
Tuesday, 6 August 2024
bp gives go-ahead for sixth operated hub, Kaskida, in the US Gulf of Mexico
bp has taken a final investment decision on the Kaskida project in the US Gulf of Mexico. This demonstrates bp’s long-term commitment to deliver secure, affordable and reliable energy.
Kaskida will be bp’s sixth hub in the Gulf of Mexico, featuring a new floating production platform with the capacity to produce 80,000 barrels of crude oil per day from six wells in the first phase. Production is expected to start in 2029.
"Developing Kaskida will unlock the potential of the Paleogene in the Gulf of Mexico for bp, building on our decades of experience in the region," said Gordon Birrell, bp’s executive vice president of production and operations.
"Technology has and will continue to play a pivotal role in propelling Kaskida from discovery to production. Together with the other resources we have in the Paleogene, we expect it to prove to be a world-class development. Today is a critical step in realizing its potential."
Owned 100% by bp, the Kaskida field has discovered recoverable resources currently estimated at around 275 million barrels of oil equivalent from the initial phase. Additional wells could be drilled in future phases, subject to further evaluation.
The project is fully accommodated within bp’s disciplined financial framework, reflecting bp’s drive to focus on value and returns.
Located in the Keathley Canyon area about 250 miles southwest off the coast of New Orleans, the Kaskida project unlocks the potential future development of 10 billion barrels of discovered resources in place across the Kaskida and Tiber catchment areas.
bp plans to leverage existing platform and subsea equipment designs that can be replicated in future projects to drive cost efficiencies across Kaskida’s construction, commissioning and operations.
"By employing an industry-led design solution, Kaskida will be simpler to construct and simpler to operate, enhancing safety and delivering greater value for bp," said Andy Krieger, bp’s senior vice president, Gulf of Mexico and Canada.
Kaskida is in a prime location, with a stable fiscal regime and access to market. It will also be bp’s first development in the Gulf of Mexico to produce from reservoirs that will require well equipment with a pressure rating of up to 20,000 pounds per square inch (20K).
Advancements in 20K drilling technology coupled with updated seismic imaging are enabling bp to safely develop Kaskida and to progress plans to develop other fields such as Tiber, which is expected to advance to a final investment decision next year.
Today’s announcement demonstrates bp’s near-term priorities in action – moving forward a key high-value growth project and supporting its drive to deliver as a simpler, more focused, higher value company.
- bp discovered the Kaskida field in 2006 and has since worked closely with the offshore industry to help develop 20K rig technology necessary to complete high-pressure wells.
- Kaskida, Tiber and nearby discoveries combined have an estimated 10 billion barrels of discovered resources in place.
- bp is one of the leading producers in the Gulf of Mexico with more than 60 years of experience operating in the basin.
- bp operates five platforms in the Gulf of Mexico: Argos, Atlantis, Mad Dog, Na Kika and Thunder Horse.
- bp produced circa 300,000 barrels of oil equivalent per day from the Gulf of Mexico in 2023.
Tuesday, 30 July 2024
Eni: FPSO Petrojarl Kong and FSO Yamoussoukro ready to leave for Côte d'Ivoire for phase 2 of Baleine project
Eni announces that the naming ceremony of the Floating Production, Storage and Offloading Unit (FPSO) Petrojarl Kong and the Floating Storage and Offloading Unit (FSO) Yamoussoukro was held today in Dubai. The two vessels will significantly increase production from the Baleine field, located offshore Côte d'Ivoire, the largest discovery ever made in the country.
The ceremony was attended by Côte d'Ivoire's Minister of Petroleum, Mines and Energy Mamadou Sangafowa Coulibaly, Petroci CEO Fatoumata Sanogo, and Eni's Chief Operating Officer Natural Resources Guido Brusco.
With the christening of the vessels, phase 2 of the Baleine project is now in full swing, in line with the record timing of phase 1. After just 12 months on site in a challenging market environment, the refurbished units are preparing to set sail for the Ivory Coast, where they will be anchored about 50km from the coast, alongside the FPSO Baleine that entered operation in August 2023.
With the startup of Phase 2, scheduled for December 2024, total production from the Baleine field will rise to 60,000 barrels of oil per day and 70 million cubic feet of associated gas (equivalent to 2 million cubic meters of associated gas), significantly increasing current production.
The Baleine project strengthens Côte d'Ivoire's role in the regional and international energy market. In addition, through the adoption of cutting-edge technologies and industry-leading initiatives designed in collaboration with institutions and already underway, it will be the first net zero-emission Upstream (Scope 1 and 2) development on the African continent.
Eni has been operating in Côte d'Ivoire since 2015 where it has an equity production of about 22,000 barrels of oil equivalent per day and participates in six blocks in Ivorian deepwater: CI-101, CI-205, CI-401, CI-501, CI-801 and CI- 802, all with the same partner Petroci Holding. The company is active in the country with initiatives ranging from hydrocarbon production to vegetable oil production for biorefining, as well as projects to improve access to health, education and training, contributing to the country's economic, social and energy development.
The ceremony was attended by Côte d'Ivoire's Minister of Petroleum, Mines and Energy Mamadou Sangafowa Coulibaly, Petroci CEO Fatoumata Sanogo, and Eni's Chief Operating Officer Natural Resources Guido Brusco.
With the christening of the vessels, phase 2 of the Baleine project is now in full swing, in line with the record timing of phase 1. After just 12 months on site in a challenging market environment, the refurbished units are preparing to set sail for the Ivory Coast, where they will be anchored about 50km from the coast, alongside the FPSO Baleine that entered operation in August 2023.
With the startup of Phase 2, scheduled for December 2024, total production from the Baleine field will rise to 60,000 barrels of oil per day and 70 million cubic feet of associated gas (equivalent to 2 million cubic meters of associated gas), significantly increasing current production.
The Baleine project strengthens Côte d'Ivoire's role in the regional and international energy market. In addition, through the adoption of cutting-edge technologies and industry-leading initiatives designed in collaboration with institutions and already underway, it will be the first net zero-emission Upstream (Scope 1 and 2) development on the African continent.
Eni has been operating in Côte d'Ivoire since 2015 where it has an equity production of about 22,000 barrels of oil equivalent per day and participates in six blocks in Ivorian deepwater: CI-101, CI-205, CI-401, CI-501, CI-801 and CI- 802, all with the same partner Petroci Holding. The company is active in the country with initiatives ranging from hydrocarbon production to vegetable oil production for biorefining, as well as projects to improve access to health, education and training, contributing to the country's economic, social and energy development.
Monday, 15 July 2024
First gas achieved at Jerun gas field in Malaysia
The operator of the Jerun field in Malaysia, SapuraOMV Upstream Sdn Bhd, has announced that first gas has been achieved. Shell plc has a 30% equity stake in the field, through its Malaysian subsidiary, Sarawak Shell Berhad, and made a final investment decision on the development in 2021.
The field is located around 160 kilometres (km) north-west of Bintulu in Sarawak, and 190 km north-west of Miri, Sarawak, Malaysia. Comprising an integrated central processing platform, Jerun will export gas through a new 80-km pipeline into the E11RB production hub, for onward delivery to Bintulu based customers including Malaysia LNG. The Jerun platform is designed to produce up to 550 million cubic feet of gas per day, with condensate production of 15,000 barrels per day during peak production.
“Jerun was a highly attractive investment for Shell, building on our interests in this important region off the coast of Sarawak, offshore Malaysia, where Shell operates the Timi platform and has the Rosmari-Marjoram project under construction,” said Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director. “Gas is an important fuel for Malaysia and the world, providing a secure form of energy for heating, cooling and power generation. We are delighted the venture has reached this milestone.”
Shell is proud of its long and successful history in Malaysia. Under the stewardship of Malaysia Petroleum Management, PETRONAS, Shell remains committed to supporting the country’s economic progress and energy transition efforts with competitive and resilient investments.
Jerun is operated by SapuraOMV Upstream (40%) in partnership with Sarawak Shell Berhad (30%) and PETRONAS Carigali Sdn Bhd (30%).
Notes to editors
The Jerun gas field was discovered in 2015, under the SK408 production sharing contract.
On Shell’s Capital Market Day in 2023, Shell committed to deliver upstream and integrated gas projects coming on stream between 2023 to 2025, with a total peak production of greater than 500,000 barrels of oil equivalent per day. Jerun is expected to contribute to this commitment.
The field is located around 160 kilometres (km) north-west of Bintulu in Sarawak, and 190 km north-west of Miri, Sarawak, Malaysia. Comprising an integrated central processing platform, Jerun will export gas through a new 80-km pipeline into the E11RB production hub, for onward delivery to Bintulu based customers including Malaysia LNG. The Jerun platform is designed to produce up to 550 million cubic feet of gas per day, with condensate production of 15,000 barrels per day during peak production.
“Jerun was a highly attractive investment for Shell, building on our interests in this important region off the coast of Sarawak, offshore Malaysia, where Shell operates the Timi platform and has the Rosmari-Marjoram project under construction,” said Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director. “Gas is an important fuel for Malaysia and the world, providing a secure form of energy for heating, cooling and power generation. We are delighted the venture has reached this milestone.”
Shell is proud of its long and successful history in Malaysia. Under the stewardship of Malaysia Petroleum Management, PETRONAS, Shell remains committed to supporting the country’s economic progress and energy transition efforts with competitive and resilient investments.
Jerun is operated by SapuraOMV Upstream (40%) in partnership with Sarawak Shell Berhad (30%) and PETRONAS Carigali Sdn Bhd (30%).
Notes to editors
The Jerun gas field was discovered in 2015, under the SK408 production sharing contract.
On Shell’s Capital Market Day in 2023, Shell committed to deliver upstream and integrated gas projects coming on stream between 2023 to 2025, with a total peak production of greater than 500,000 barrels of oil equivalent per day. Jerun is expected to contribute to this commitment.
Thursday, 11 July 2024
Eni announces a new discovery offshore Mexico
Eni announces a new discovery on the Yopaat-1 EXP exploration well in Block 9, approximately 63 kilometers off the coast in the mid-deep water of the Cuenca Salina in the Sureste Basin, offshore Mexico. The preliminary estimates indicate a discovered potential of around 300-400 million barrels equivalents (Mboe) of oil and associated gas in place.
The well has been drilled in a water depth of 525 meters and reached a total depth of 2,931 meters, finding about 200meter net pay of hydrocarbon bearing sands in the Pliocene and Miocene sequences, subject to an intense subsurface data acquisition campaign.
Block 9 Joint venture consists of Eni as Operator with a 50% participating interest and Repsol with the remaining 50%.
This successful result, alongside the discoveries in Eni-operated Blocks 7 and 10, confirms the value of Eni’s asset portfolio in the Sureste Basin. The overall estimate of resources in place currently exceeds 1.3 billion barrels of oil equivalent (Bboe) which allows Eni to advance with the studies towards a potential future “Hub” development, including the discoveries and other prospects present in the area, in synergy with the infrastructures located nearby.
Eni has been present in Mexico since 2006 and established its wholly owned subsidiary Eni Mexico S. de R. L. de C.V. in 2015. Currently, Eni is the main foreign operator in the country and holds rights in eight exploration and production blocks, of which seven as Operator, in the Sureste Basin in the Gulf of Mexico.
The well has been drilled in a water depth of 525 meters and reached a total depth of 2,931 meters, finding about 200meter net pay of hydrocarbon bearing sands in the Pliocene and Miocene sequences, subject to an intense subsurface data acquisition campaign.
Block 9 Joint venture consists of Eni as Operator with a 50% participating interest and Repsol with the remaining 50%.
This successful result, alongside the discoveries in Eni-operated Blocks 7 and 10, confirms the value of Eni’s asset portfolio in the Sureste Basin. The overall estimate of resources in place currently exceeds 1.3 billion barrels of oil equivalent (Bboe) which allows Eni to advance with the studies towards a potential future “Hub” development, including the discoveries and other prospects present in the area, in synergy with the infrastructures located nearby.
Eni has been present in Mexico since 2006 and established its wholly owned subsidiary Eni Mexico S. de R. L. de C.V. in 2015. Currently, Eni is the main foreign operator in the country and holds rights in eight exploration and production blocks, of which seven as Operator, in the Sureste Basin in the Gulf of Mexico.
Vallourec wins a major order from TotalEnergies in Angola
Following a call for tender, Vallourec, a world leader in premium tubular solutions, announces that it has been awarded a contract by TotalEnergies to supply almost 5,000 tonnes of OCTG solutions and associated services for the Kaminho deepwater project on Block 20, 100 km off the coast of Angola.
On this project, Vallourec will supply its world-renowned range of VAM® connections and use CLEANWELL® , its more environmentally-friendly, dope-free solution. The Group will also provide its offshore expertise via VAM® Field Service as well as its Tubular Management Services (TMS) offering, which involves managing the inspection and preparation of tubes before they leave for the drilling platform, and on their return to the storage area.
The products will be manufactured at Vallourec plants in France, Brazil, and Indonesia, taking advantage of the Group’s strategic premium production hubs.
More broadly in Africa, Vallourec is supporting its customer with a complete range of premium products and services, including its CLEANWELL® solution in Nigeria, Gabon, Congo, and Mozambique.
The Group has also worked with TotalEnergies in its exploration and appraisal campaigns, such as in Namibia, a region with strong development potential, where the Group has already supplied almost 5,000 tonnes of tubes and connections.
Philippe Guillemot, Chairman of the Board of Directors and Chief Executive Officer, commented: “We are proud to support TotalEnergies in its developments and exploration projects. I would like to thank the Vallourec teams for their commitment.”
Wednesday, 10 July 2024
Shell to invest in Ruwais LNG project in Abu Dhabi
Shell Overseas Holdings Limited, a subsidiary of Shell plc (Shell), has signed an agreement to invest in the Abu Dhabi National Oil Company’s (ADNOC) Ruwais liquefied natural gas (LNG) project in Abu Dhabi through a 10% participating interest.
“This investment decision builds on our long-standing partnership with ADNOC," said Shell's Chief Executive Officer Wael Sawan. "In line with our strategy to create more value with less emissions, we are investing in additional LNG capacity and further growing our world-leading LNG portfolio, with energy-efficient and carbon-competitive projects."
The Ruwais LNG project will consist of two 4.8 million metric tonnes per annum (mmtpa) LNG liquefaction trains with a total capacity of 9.6 mmtpa. Shell, through its subsidiary Shell International Trading Middle East Limited FZE, has also signed an agreement to offtake 1 mmtpa of LNG produced by the project. The Ruwais LNG facility is set to have an electric-powered liquefaction system and will utilise access to a renewable power supply. This design supports lower operational emissions compared to traditional gas-powered LNG facilities.
ADNOC will hold a majority 60% share in the project and serve as the lead developer and operator of the facility, while Shell, BP, Mitsui and TotalEnergies will each hold 10%.
ADNOC has awarded an engineering, procurement and construction (EPC) contract to a Technip-led joint venture and will soon start construction in Al Ruwais Industrial City, Abu Dhabi. LNG deliveries are expected to start in 2028.
Notes to editors
The Ruwais LNG project is located some 240 kilometres west of Abu Dhabi, United Arab Emirates.
Shell has a proud history of more than 80 years in the United Arab Emirates. Shell’s current activities with ADNOC include a 15% interest in ADNOC Gas Processing (AGP) with associated technical and manpower support services.
The capital investment related to Shell’s 10% participating interest in the Ruwais LNG project will be absorbed within Shell’s cash capital expenditure guidance, which remains unchanged. The deal is in excess of the internal rate of return (IRR) hurdle rate for Shell’s Integrated Gas business, delivering on its 25-30% growth ambition in liquefaction volumes, relative to 2022, as outlined during the 2023 Capital Markets Day.
Global demand for LNG is estimated to rise by more than 50% by 2040, as industrial coal-to-gas switching gathers pace in China, South Asian and South-east Asian countries. These countries are expected to use more LNG to support their economic growth, according to Shell’s LNG Outlook 2024 (PDF)
.
Shell believes LNG will play a critical role in the energy transition, replacing coal in heavy industry. It also has a continued role in displacing coal in power generation, helping to reduce local air pollution and carbon emissions. LNG helps to provide the flexibility the power system needs, at a time when renewable generation is growing rapidly. Find out more in Shell’s Energy Transition Strategy 2024 (PDF)
.
“This investment decision builds on our long-standing partnership with ADNOC," said Shell's Chief Executive Officer Wael Sawan. "In line with our strategy to create more value with less emissions, we are investing in additional LNG capacity and further growing our world-leading LNG portfolio, with energy-efficient and carbon-competitive projects."
The Ruwais LNG project will consist of two 4.8 million metric tonnes per annum (mmtpa) LNG liquefaction trains with a total capacity of 9.6 mmtpa. Shell, through its subsidiary Shell International Trading Middle East Limited FZE, has also signed an agreement to offtake 1 mmtpa of LNG produced by the project. The Ruwais LNG facility is set to have an electric-powered liquefaction system and will utilise access to a renewable power supply. This design supports lower operational emissions compared to traditional gas-powered LNG facilities.
ADNOC will hold a majority 60% share in the project and serve as the lead developer and operator of the facility, while Shell, BP, Mitsui and TotalEnergies will each hold 10%.
ADNOC has awarded an engineering, procurement and construction (EPC) contract to a Technip-led joint venture and will soon start construction in Al Ruwais Industrial City, Abu Dhabi. LNG deliveries are expected to start in 2028.
Notes to editors
The Ruwais LNG project is located some 240 kilometres west of Abu Dhabi, United Arab Emirates.
Shell has a proud history of more than 80 years in the United Arab Emirates. Shell’s current activities with ADNOC include a 15% interest in ADNOC Gas Processing (AGP) with associated technical and manpower support services.
The capital investment related to Shell’s 10% participating interest in the Ruwais LNG project will be absorbed within Shell’s cash capital expenditure guidance, which remains unchanged. The deal is in excess of the internal rate of return (IRR) hurdle rate for Shell’s Integrated Gas business, delivering on its 25-30% growth ambition in liquefaction volumes, relative to 2022, as outlined during the 2023 Capital Markets Day.
Global demand for LNG is estimated to rise by more than 50% by 2040, as industrial coal-to-gas switching gathers pace in China, South Asian and South-east Asian countries. These countries are expected to use more LNG to support their economic growth, according to Shell’s LNG Outlook 2024 (PDF)
.
Shell believes LNG will play a critical role in the energy transition, replacing coal in heavy industry. It also has a continued role in displacing coal in power generation, helping to reduce local air pollution and carbon emissions. LNG helps to provide the flexibility the power system needs, at a time when renewable generation is growing rapidly. Find out more in Shell’s Energy Transition Strategy 2024 (PDF)
.
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