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.
Thursday, 30 November 2023
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.
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.
Tuesday, 28 November 2023
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.
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.
Monday, 27 November 2023
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%.
"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."
Sunday, 26 November 2023
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
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.
Saturday, 25 November 2023
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:
"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.
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
"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%.
Tuesday, 21 November 2023
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.”
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.”
Wednesday, 15 November 2023
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.
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.
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.
Tuesday, 14 November 2023
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.
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.
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.
Friday, 10 November 2023
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.
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.
Thursday, 9 November 2023
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.
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.
Tuesday, 7 November 2023
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.”
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.”
Thursday, 2 November 2023
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.
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.
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