PETRONAS Petróleo Brasil Ltda. (PPBL), a subsidiary of PETRONAS, and its consortium partners have won the Sépia field, located in the Santos Basin, during Brazil’s Second Transfer of Rights Surplus Volume Bidding Round held in Rio de Janeiro.
Following this successful bid, PETRONAS will hold a 21% interest alongside operator Petrobras (30%), TotalEnergies (28%) and QatarEnergy (21%). The results were publicly announced by the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (ANP) in a live broadcast.
PETRONAS President and Group CEO, Datuk Tengku Muhammad Taufik said, “PETRONAS is extremely encouraged with the outcome of the bid round which marks our entry into the Santos Basin. This signals our commitment to strengthen our ventures in Brazil which offers the world’s most prolific basins. Establishing our presence in the Americas is in line with our global growth strategy.
“Even as we work closely with our partners, together with the support of the Host Government, PETRONAS will remain focused on pursuing value creation while continuing our decarbonizing efforts in order to sustainably develop and monetise the Sépia field.”
Sépia is a pre-salt oil field in the Santos Basin, located in water depths about 2,000 meters off the coast of Rio de Janerio and has started its production in August 2021 through a dedicated 180,000 bpd floating production, storage and offloading unit (FPSO). The second FPSO is expected to be sanctioned soon which would increase the overall production capacity of the field.
PPBL currently has a participating interest in the Tartaruga Verde (BM-C-36 Concession) and Module III of the Espadarte (Espadarte Concession) deepwater fields located in the Campos Basin, offshore Brazil. PPBL also holds participating interests in three other deepwater exploration blocks in the Campos Basin, (C-M-661, C-M-715 and C-M-541) which were awarded during Brazil’s Concession Exploration Bid Round 16 in 2019.
Tuesday 21 December 2021
Monday 20 December 2021
Subsea 7 awarded contract offshore Australia
Subsea 7 today announced the award of a large1 contract to Subsea Integration Alliance2 by Woodside, as Operator for and on behalf of the Scarborough Joint Venture3, for the Scarborough project, located approximately 380km offshore North West Australia.
The project work scope covers the engineering, procurement, construction, and installation (EPCI) of subsea pipelines and production systems. The development will include 45 kilometres of rigid flowlines, six flexible flowline risers, 42 kilometres of umbilicals and eight trees, as well as associated subsea equipment, in water depths of approximately 950 metres.
The Subsea Integration Alliance team established during the initial front-end engineering and design (“FEED”) phase, awarded in January 2019, will now transition into the full EPCI phase. Project management and engineering will take place in Perth, Australia, with support from Subsea 7’s Global Project Centre’s offices in Malaysia, UK and France and various OneSubsea® offices.
Offshore activities are targeted to take place from 2023 to 2025 using Subsea 7's reel-lay and flex- lay vessels.
Olivier Blaringhem, CEO Subsea Integration Alliance said: “This award is the result of a strong and collaborative early engagement process with Woodside, working with a high level of transparency and cooperation during the pre-tender and FEED phases. It demonstrates the potential value of Subsea Integration Alliance and its optimised and integrated offering capacity. We look forward to working with Woodside to deliver the project successfully and safely while maximising the client’s production objectives.”
David Bertin, Vice President for Subsea 7 Global Projects Centre and Asia Pacific said: “We are proud to be awarded this contract by Woodside. This builds on our long-standing relationship with the client and our successful track record of projects executed offshore Australia. Our local office in Perth will be supported by Subsea 7’s Global Projects Centre, underlining the strength and breadth of our project management capabilities and the capacity to deliver complex projects worldwide.”
The Hanz development sanctioned
Aker BP (operator) and licence partners Equinor and Spirit Energy have affirmed the investment decision (DG3) for development of the Hanz discovery in the North Sea. The project has matured a solution involving reuse of existing infrastructure, which both strengthens project economics and minimises the environmental footprint.
Hanz is an oil and gas discovery that will be tied into the Ivar Aasen platform about twelve kilometres further south.
Total investments are estimated at NOK 3.3 billion. Expected start-up is in the first half of 2024. Total reserves are around 20 million barrels of oil equivalent (mmboe).
Lower cost, lower emissions
Development and operation of the Ivar Aasen field, including Hanz, was subject to a full impact assessment in 2012. The concept for development of Hanz was also described in the Plan for Development and Operation (PDO) for the Ivar Aasen field.
“Over the last few years, we have matured an optimised development solution, in part through re-use of subsea production systems (SPS) from the Jette field. This development solution will be more cost-efficient and have a smaller environmental footprint than the original concept that was described when the PDO was first delivered,” says SVP Operations & Asset Development in Aker BP, Ine Dolve.
In addition to reusing existing infrastructure, the strategy for how the oil and gas is to be recovered has been changed to include use of a cross-stream well for water injection. This results in a substantial reduction of power consumption, less use of chemicals and less equipment on the seabed.
“The selected development solution provides both better project economy and significantly lower emissions and environmental footprint than we previously assumed. This is in line with Aker BP’s continuous search for improvements, where the goal is to produce with low costs and low emissions,” Dolve adds.
The change in the development solution for Hanz since the PDO was submitted means that the partnership will send a formal statement regarding the investment decision and the selected concept to the authorities.
Maintaining production level
The Ivar Aasen field is located on the Utsira High in the northern part of the North Sea, around 175 km west of Karmøy. The field was discovered in 2008, and was joined with other discoveries in the area, including Hanz, which was proven in 1997. The first oil from Ivar Aasen was produced on 24 December 2016.
“Development of the Hanz discovery is important for the development of the Ivar Aasen area. Production start from Hanz in 2024 will help us maintain good production from the Ivar Aasen platform for several more years,” says Ivar Aasen asset manager, Gudmund Evju.
“At the same time, we are searching for new oil and gas resources in the area, both through improved recovery measures and exploration, with the objective of tying additional volumes into the field centre,” Evju adds.
Ivar Aasen receives power from the Edvard Grieg platform ten kilometres to the southeast. From 2022, the field will receive power from shore via the Johan Sverdrup field, thereby minimising CO2 emissions.
About Hanz:
Lisence 028 B
Partners: Aker BP (35%, operator), Equinor (50%), Spirit Energy (15%)
Hanz is an oil and gas discovery that will be tied into the Ivar Aasen platform about twelve kilometres further south.
Total investments are estimated at NOK 3.3 billion. Expected start-up is in the first half of 2024. Total reserves are around 20 million barrels of oil equivalent (mmboe).
Lower cost, lower emissions
Development and operation of the Ivar Aasen field, including Hanz, was subject to a full impact assessment in 2012. The concept for development of Hanz was also described in the Plan for Development and Operation (PDO) for the Ivar Aasen field.
“Over the last few years, we have matured an optimised development solution, in part through re-use of subsea production systems (SPS) from the Jette field. This development solution will be more cost-efficient and have a smaller environmental footprint than the original concept that was described when the PDO was first delivered,” says SVP Operations & Asset Development in Aker BP, Ine Dolve.
In addition to reusing existing infrastructure, the strategy for how the oil and gas is to be recovered has been changed to include use of a cross-stream well for water injection. This results in a substantial reduction of power consumption, less use of chemicals and less equipment on the seabed.
“The selected development solution provides both better project economy and significantly lower emissions and environmental footprint than we previously assumed. This is in line with Aker BP’s continuous search for improvements, where the goal is to produce with low costs and low emissions,” Dolve adds.
The change in the development solution for Hanz since the PDO was submitted means that the partnership will send a formal statement regarding the investment decision and the selected concept to the authorities.
Maintaining production level
The Ivar Aasen field is located on the Utsira High in the northern part of the North Sea, around 175 km west of Karmøy. The field was discovered in 2008, and was joined with other discoveries in the area, including Hanz, which was proven in 1997. The first oil from Ivar Aasen was produced on 24 December 2016.
“Development of the Hanz discovery is important for the development of the Ivar Aasen area. Production start from Hanz in 2024 will help us maintain good production from the Ivar Aasen platform for several more years,” says Ivar Aasen asset manager, Gudmund Evju.
“At the same time, we are searching for new oil and gas resources in the area, both through improved recovery measures and exploration, with the objective of tying additional volumes into the field centre,” Evju adds.
Ivar Aasen receives power from the Edvard Grieg platform ten kilometres to the southeast. From 2022, the field will receive power from shore via the Johan Sverdrup field, thereby minimising CO2 emissions.
About Hanz:
Lisence 028 B
Partners: Aker BP (35%, operator), Equinor (50%), Spirit Energy (15%)
Subsea 7 awarded contract offshore Norway
Subsea 7 today announced the award of a sizeable1 contract by Aker BP for the Hanz field development located in the North Sea.
The project involves a subsea tie-back of approximately 15 kilometres to the Ivar Aasen platform. The contract scope includes engineering, procurement, construction and installation (EPCI) of the gas lift and production pipelines, and associated subsea infrastructure, using vessels from Subsea 7’s fleet. The production pipeline is a pipe-in-pipe design.
Project management and engineering will commence immediately at Subsea 7’s offices in Stavanger, Norway. Fabrication of the pipelines will take place at Subsea 7’s spool base at Vigra, Norway and offshore operations are expected to be carried out in 2023.
Monica Bjørkmann, Vice President for Subsea 7 Norway said: “This award continues our long-standing collaboration with Aker BP, through the Aker BP Subsea Alliance2. The partnership enables Subsea 7 to engage early in the field development process, optimising design solutions and contributing to a positive final investment decision. Subsea 7 looks forward to continuing our alliance with Aker BP for the Hanz field development, with a focus on safe, efficient and reliable operations.”
Project management and engineering will commence immediately at Subsea 7’s offices in Stavanger, Norway. Fabrication of the pipelines will take place at Subsea 7’s spool base at Vigra, Norway and offshore operations are expected to be carried out in 2023.
Monica Bjørkmann, Vice President for Subsea 7 Norway said: “This award continues our long-standing collaboration with Aker BP, through the Aker BP Subsea Alliance2. The partnership enables Subsea 7 to engage early in the field development process, optimising design solutions and contributing to a positive final investment decision. Subsea 7 looks forward to continuing our alliance with Aker BP for the Hanz field development, with a focus on safe, efficient and reliable operations.”
Thursday 16 December 2021
ConocoPhillips Alaska’s Greater Mooses Tooth #2 Produces First Oil
December 14, 2021
ConocoPhillips (NYSE: COP) Alaska today announced that the Greater Mooses Tooth #2 (GMT2) drill site in the National Petroleum Reserve-Alaska (NPR-A) has achieved first oil production under budget and on schedule on Dec. 12. GMT2 is the second project in the Greater Mooses Tooth Unit, in the northeast NPR-A on Alaska’s North Slope and is located about eight miles southwest of GMT1. GMT2 is a satellite development of the Alpine field and is connected to the existing Alpine production center in the Colville River Unit (CRU) for processing via GMT1 and CD5 infrastructure.
Permit applications for drilling at GMT2 were submitted to the Bureau of Land Management (BLM) in August 2015. The BLM completed a Supplemental Environmental Impact Statement with a Record of Decision issued on Oct. 16, 2018. The BLM, ASRC and Kuukpik Corporation share land and mineral rights for the project.
GMT2 has a 14-acre drilling pad, an 8-mile gravel road, and pipeline facilities connected to the existing CRU infrastructure. The pad is planned to have 36 wells initially, with capacity for up to 48 wells. Peak production is estimated at approximately 30,000 barrels of oil equivalent per day (BOEPD) and the project costs approximately $1.4 billion gross, including construction and drilling expenses. At peak construction during the past three winter seasons, the project created about 700 jobs resulting in more than 600,000 direct construction manhours.
“The GMT2 team safely executed this project in an environmentally responsible manner marking another successful milestone for development in the NPR-A,” said Erec Isaacson, president of ConocoPhillips Alaska. “Projects like these continue to create hundreds of jobs in Alaska and contribute to a stable Alaska economy. We appreciate the collaboration with stakeholders from Kuukpik Corporation, the community of Nuiqsut, the North Slope Borough and ASRC that made it possible. Our continuous investment in projects on the North Slope benefits Alaska’s future.”
In addition to completing GMT2, ConocoPhillips Alaska continues making substantial investments in long-term projects on the North Slope.
The Greater Mooses Tooth and Colville River Units are approximately 100 percent owned and operated by ConocoPhillips Alaska, Inc.
ConocoPhillips (NYSE: COP) Alaska today announced that the Greater Mooses Tooth #2 (GMT2) drill site in the National Petroleum Reserve-Alaska (NPR-A) has achieved first oil production under budget and on schedule on Dec. 12. GMT2 is the second project in the Greater Mooses Tooth Unit, in the northeast NPR-A on Alaska’s North Slope and is located about eight miles southwest of GMT1. GMT2 is a satellite development of the Alpine field and is connected to the existing Alpine production center in the Colville River Unit (CRU) for processing via GMT1 and CD5 infrastructure.
Permit applications for drilling at GMT2 were submitted to the Bureau of Land Management (BLM) in August 2015. The BLM completed a Supplemental Environmental Impact Statement with a Record of Decision issued on Oct. 16, 2018. The BLM, ASRC and Kuukpik Corporation share land and mineral rights for the project.
GMT2 has a 14-acre drilling pad, an 8-mile gravel road, and pipeline facilities connected to the existing CRU infrastructure. The pad is planned to have 36 wells initially, with capacity for up to 48 wells. Peak production is estimated at approximately 30,000 barrels of oil equivalent per day (BOEPD) and the project costs approximately $1.4 billion gross, including construction and drilling expenses. At peak construction during the past three winter seasons, the project created about 700 jobs resulting in more than 600,000 direct construction manhours.
“The GMT2 team safely executed this project in an environmentally responsible manner marking another successful milestone for development in the NPR-A,” said Erec Isaacson, president of ConocoPhillips Alaska. “Projects like these continue to create hundreds of jobs in Alaska and contribute to a stable Alaska economy. We appreciate the collaboration with stakeholders from Kuukpik Corporation, the community of Nuiqsut, the North Slope Borough and ASRC that made it possible. Our continuous investment in projects on the North Slope benefits Alaska’s future.”
In addition to completing GMT2, ConocoPhillips Alaska continues making substantial investments in long-term projects on the North Slope.
The Greater Mooses Tooth and Colville River Units are approximately 100 percent owned and operated by ConocoPhillips Alaska, Inc.
Wednesday 8 December 2021
JERA to Invest in the Barossa Gas Field in Australia to Secure a Stable LNG Supply
JERA Co., Inc. (“JERA”) has decided to invest, through its subsidiary JERA Australia Pty Ltd., in the Barossa/Caldita gas field in Australia and has today concluded an equity purchase agreement with a subsidiary of Santos Ltd., a major resource development company in Australia, to acquire a 12.5% stake in the gas field. The acquisition is expected to be finalized after the necessary approval and authorization procedures.
As a result of this acquisition, JERA will participate in the project to develop a successor gas field for the Darwin LNG project in Australia (the "Project").
JERA participated in the Darwin LNG project in 2003. That project has produced LNG at the Darwin liquefaction plant using natural gas supplied from the Bayu-Undan gas field, located in waters off Timor-Leste, and contributed to the stable supply of LNG for approximately 15 years since production began in 2006.
Production at the Bayu-Undan gas field is expected to end within a few years. Development of the Barossa gas field as a successor to supply feed gas to the Darwin LNG liquefaction plant is now underway.
The Barossa gas field is located in Australian waters off the Northern Territory of Australia. The Project will develop the Barossa gas field and link it by pipeline to the Darwin liquefaction plant for LNG production, which is expected to start around 2025. JERA will receive about 0.425mtpa of LNG from the Project which is equivalent to its equity stake in the Barossa gas field.
In Asia, there is demand both for decarbonization and for a stable energy supply to support economic growth. Gas-fired power generation—which emits less CO2 than power generation using other fossil fuels—can be a flexible supplement to intermittent renewable energy, and demand for it as an energy source indispensable to promoting the energy transition is expected to continue to grow. Securing a stable supply of competitive LNG, therefore, is becoming increasingly important.
Because the Barossa gas field is medium-sized, and existing facilities such as the Darwin LNG project’s liquefaction plant, an LNG storage tank, and jetty can be utilized, the Project enables JERA to secure highly competitive LNG with extremely low development risk. By leveraging the knowledge and expertise it has accumulated through its global LNG value chain business, JERA will work together with its partners to develop the Project and ensure a stable supply of LNG to the global market, including to Japan and to gas-to-power projects in Asia.
In addition, JERA will also work with its partners to study the development of zero-emission projects and to evaluate CCS projects. Through these initiatives, JERA will evaluate opportunities for the reduction of CO2 emissions from the Project with the partners.
Under its “JERA Zero CO2 Emissions 2050” objective, JERA has been working to reduce CO2 emissions from its domestic and overseas businesses to zero by 2050, to promote the adoption of greener fuels, and to pursue thermal power that does not emit CO2 during power generation. JERA also plans to establish decarbonization roadmaps optimized for each country and region and to promote zero-emission initiatives that follow these roadmaps.
Leveraging its long experience in the LNG value chain businesses, JERA will follow the decarbonization roadmaps it is drawing up for each country and region as it strives to expand the adoption of LNG—a transitional fuel indispensable for achieving decarbonization—and to contribute to global decarbonization and energy solutions.
As a result of this acquisition, JERA will participate in the project to develop a successor gas field for the Darwin LNG project in Australia (the "Project").
JERA participated in the Darwin LNG project in 2003. That project has produced LNG at the Darwin liquefaction plant using natural gas supplied from the Bayu-Undan gas field, located in waters off Timor-Leste, and contributed to the stable supply of LNG for approximately 15 years since production began in 2006.
Production at the Bayu-Undan gas field is expected to end within a few years. Development of the Barossa gas field as a successor to supply feed gas to the Darwin LNG liquefaction plant is now underway.
The Barossa gas field is located in Australian waters off the Northern Territory of Australia. The Project will develop the Barossa gas field and link it by pipeline to the Darwin liquefaction plant for LNG production, which is expected to start around 2025. JERA will receive about 0.425mtpa of LNG from the Project which is equivalent to its equity stake in the Barossa gas field.
In Asia, there is demand both for decarbonization and for a stable energy supply to support economic growth. Gas-fired power generation—which emits less CO2 than power generation using other fossil fuels—can be a flexible supplement to intermittent renewable energy, and demand for it as an energy source indispensable to promoting the energy transition is expected to continue to grow. Securing a stable supply of competitive LNG, therefore, is becoming increasingly important.
Because the Barossa gas field is medium-sized, and existing facilities such as the Darwin LNG project’s liquefaction plant, an LNG storage tank, and jetty can be utilized, the Project enables JERA to secure highly competitive LNG with extremely low development risk. By leveraging the knowledge and expertise it has accumulated through its global LNG value chain business, JERA will work together with its partners to develop the Project and ensure a stable supply of LNG to the global market, including to Japan and to gas-to-power projects in Asia.
In addition, JERA will also work with its partners to study the development of zero-emission projects and to evaluate CCS projects. Through these initiatives, JERA will evaluate opportunities for the reduction of CO2 emissions from the Project with the partners.
Under its “JERA Zero CO2 Emissions 2050” objective, JERA has been working to reduce CO2 emissions from its domestic and overseas businesses to zero by 2050, to promote the adoption of greener fuels, and to pursue thermal power that does not emit CO2 during power generation. JERA also plans to establish decarbonization roadmaps optimized for each country and region and to promote zero-emission initiatives that follow these roadmaps.
Leveraging its long experience in the LNG value chain businesses, JERA will follow the decarbonization roadmaps it is drawing up for each country and region as it strives to expand the adoption of LNG—a transitional fuel indispensable for achieving decarbonization—and to contribute to global decarbonization and energy solutions.
Thursday 2 December 2021
Start-up of CLOV Phase 2 project
TotalEnergies, operator of Block 17 in Angola, together with the Angolan National Oil, Gas and Biofuels Agency (ANPG) announce the start of production of CLOV Phase 2, a project connected to the existing CLOV FPSO (Floating Production, Storage and Offloading unit). This tie-back project will reach a production of 40,000 barrels of oil equivalent per day in mid-2022.
Located about 140 kilometers from the Angolan coast, in water depths from 1,100 to 1,400 meters, the CLOV Phase 2 resources are estimated at around 55 million barrels of oil equivalent.
Launched in 2018, this project was carried out within budget and planned execution duration, despite the challenges associated with the Covid-19 pandemic.
“The start of the production of CLOV Phase 2, a few months after Zinia Phase 2, demonstrates our continuous efforts to ensure a sustainable output on Block 17. This project fits within the company’s strategy to focus its upstream investments on low-cost projects which contribute to lower the average GHG emissions intensity of its production”, said Henri-Max Ndong-Nzue, Senior Vice-President Africa, Exploration and Production at TotalEnergies. “CLOV Phase 2 start-up also highlights the performance of our teams despite the health crisis “.
Belarmino Chitangueleca, acting President of the ANPG, commented that “CLOV Phase 2 start-up comes at the right time to sustain the national oil production. We value the performance of the operator and the contractor group to keep executing projects despite this crisis period.”
Block 17 is operated by TotalEnergies with a 38% stake, alongside Equinor (22.16%), ExxonMobil (19%), BP Exploration Angola Ltd (15.84%) and Sonangol P&P (5%). The Contractor Group operates four FPSOs in the main production areas of the block, namely Girassol, Dalia, Pazflor and CLOV.
***
TotalEnergies in Angola
TotalEnergies has been present in Angola since 1953, where it today employs around 1,500 people in the business segments of Exploration & Production, Marketing & Services, Trading & Shipping and iGRP.
TotalEnergies’s equity production in Angola averaged 212,000 barrels of oil equivalent per day in 2020 from operated blocks 17 and 32, and from non-operated assets 0, 14, 14K, and Angola LNG. TotalEnergies is the country's leading oil operator with close to 45% of Angola’s operated oil production.
TotalEnergies also operates Block 17/06 in the Lower Congo Basin, Block 16, location of the Chissonga discovery — both in development phase —, and Block 48 in the emerging ultra-deep offshore play and still in exploration phase.
In the gas sector, TotalEnergies holds a 13.6% stake in the 5.2-million-ton-per-year Angola LNG liquefaction plant, which is supplied with associated gas from the country’s producing offshore oil fields. TotalEnergies also recently entered the New Gas Consortium, a key player in developing Angola’s natural gas resource.
Located about 140 kilometers from the Angolan coast, in water depths from 1,100 to 1,400 meters, the CLOV Phase 2 resources are estimated at around 55 million barrels of oil equivalent.
Launched in 2018, this project was carried out within budget and planned execution duration, despite the challenges associated with the Covid-19 pandemic.
“The start of the production of CLOV Phase 2, a few months after Zinia Phase 2, demonstrates our continuous efforts to ensure a sustainable output on Block 17. This project fits within the company’s strategy to focus its upstream investments on low-cost projects which contribute to lower the average GHG emissions intensity of its production”, said Henri-Max Ndong-Nzue, Senior Vice-President Africa, Exploration and Production at TotalEnergies. “CLOV Phase 2 start-up also highlights the performance of our teams despite the health crisis “.
Belarmino Chitangueleca, acting President of the ANPG, commented that “CLOV Phase 2 start-up comes at the right time to sustain the national oil production. We value the performance of the operator and the contractor group to keep executing projects despite this crisis period.”
Block 17 is operated by TotalEnergies with a 38% stake, alongside Equinor (22.16%), ExxonMobil (19%), BP Exploration Angola Ltd (15.84%) and Sonangol P&P (5%). The Contractor Group operates four FPSOs in the main production areas of the block, namely Girassol, Dalia, Pazflor and CLOV.
***
TotalEnergies in Angola
TotalEnergies has been present in Angola since 1953, where it today employs around 1,500 people in the business segments of Exploration & Production, Marketing & Services, Trading & Shipping and iGRP.
TotalEnergies’s equity production in Angola averaged 212,000 barrels of oil equivalent per day in 2020 from operated blocks 17 and 32, and from non-operated assets 0, 14, 14K, and Angola LNG. TotalEnergies is the country's leading oil operator with close to 45% of Angola’s operated oil production.
TotalEnergies also operates Block 17/06 in the Lower Congo Basin, Block 16, location of the Chissonga discovery — both in development phase —, and Block 48 in the emerging ultra-deep offshore play and still in exploration phase.
In the gas sector, TotalEnergies holds a 13.6% stake in the 5.2-million-ton-per-year Angola LNG liquefaction plant, which is supplied with associated gas from the country’s producing offshore oil fields. TotalEnergies also recently entered the New Gas Consortium, a key player in developing Angola’s natural gas resource.
Wednesday 1 December 2021
Neptune Energy uses innovative technology for decommissioning work
Neptune Energy today announced the award of a decommissioning contract to Maersk Supply Service (MSS) for the Juliet field in the UK Southern North Sea, which will deploy innovative technology to reduce the time and costs associated with the removal of the subsea infrastructure.
Piping spools and umbilicals will be removed using the Utility ROV Services system (UTROV), a remotely-operated tool carrier equipped with multiple attachments for the recovery of subsea equipment, reducing the necessity for multiple vessels and equipment providers to carry out the complex work.
The UTROV system was previously used for work on the Juliet field in 2019 and will be deployed from the Maersk Forza Subsea Support Vessel.
Neptune Energy’s UK Managing Director, Alexandra Thomas, said: “Work on decommissioning Juliet is progressing well and the activities undertaken by MSS will finalise the work on the pipelines and enable us to move forward with plugging and abandonment operations.
”The use of such innovative technologies is enabling operators to reduce the time, costs and environmental impacts associated with such operations, and ensures the safe and efficient removal of decommissioned subsea infrastructure.”
Maersk Supply Service’s Head of Integrated Solutions, Olivier Trouvé, said: “We are looking forward to mobilizing our engineering capabilities and specialised assets to provide safe and efficient operations.”
The Juliet subsea assets were installed in 2013. Production ceased in 2017 and formal cessation of production was approved in December 2018 by the OGA. The Juliet Subsea completion is located in block 47/14b of the UK Southern North Sea. The Juliet facilities comprise two subsea wells tied back to the Pickerill ‘A’ Platform, which is owned and operated by Perenco (PUK).
The decommissioning work will be carried out in early 2022.
Tuesday 30 November 2021
Aramco awards contracts worth $10bn for vast Jafurah field development, as unconventional resources program reaches commercial stage
The Saudi Arabian Oil Company (“Aramco” or “the Company”) today announced the start of development of the vast Jafurah unconventional gas field, the largest non-associated gas field in the Kingdom of Saudi Arabia. The Company has awarded subsurface and Engineering, Procurement and Construction (EPC) contracts worth $10 billion, with capital expenditure at Jafurah expected to reach $68 billion over the first 10 years of development.
It is a significant milestone both for the commercialization of unconventional resources in Saudi Arabia and the expansion of Aramco’s integrated gas portfolio, which will provide additional feedstock to support growth of the Company’s high-value chemicals business, complement its focus on low-carbon hydrogen production and help reduce emissions in the domestic power sector by providing a cleaner-burning alternative to liquid fuel.
With an estimated 200 trillion standard cubic feet of gas in place, the Jafurah basin hosts the largest liquid-rich shale gas play in the Middle East. This shale play covers an area measuring 17,000 square kilometers and production of natural gas at Jafurah is expected to ramp up from 200 million standard cubic feet per day (scfd) in 2025 to reach a sustainable gas rate of two billion scfd of sales gas by 2030, with 418 million scfd of ethane and around 630,000 barrels per day of gas liquids and condensates, which are essential feedstock for the growing petrochemical industry. It will make Saudi Arabia one of the world’s largest natural gas producers.
HRH Prince Abdulaziz bin Salman Al Saud, Minister of Energy for the Kingdom of Saudi Arabia, said: “I would like to thank the Custodian of the Two Holy Mosques, King Salman bin Abdulaziz Al Saud, and HRH Prince Mohammed bin Salman bin Abdulaziz Al Saud, Crown Prince, Deputy Prime Minister and Minister of Defense, for their ongoing support of the Kingdom’s energy sector. The development of Jafurah will positively contribute to the Kingdom’s energy mix and it has been made possible thanks to close co-operation between more than 17 different agencies. The government is committed to the empowerment of national companies such as Aramco and no other energy company in the world is empowered to the same extent by the state, or by the Ministry of Energy which oversees the concession to develop the Kingdom’s hydrocarbon resources.”
The project is a key component of the Company’s long-term strategy and Aramco expects total overall lifecycle investment at Jafurah to exceed $100 billion. Through its unconventional gas program at the Jafurah, North Arabia and South Ghawar fields, the Company expects to create more than 200,000 direct and indirect jobs.
Amin H. Nasser, Aramco President and CEO, said: “This is a pivotal moment in the commercialization of Saudi Arabia’s vast unconventional resources program. It is a breakthrough that few outside the Kingdom thought was possible, and which has positive implications for energy security, economic development and climate protection. Gas has a critical role to play in the energy transition and it will help significantly reduce emissions in the domestic energy sector, while providing a feedstock for low-carbon hydrogen and ammonia. It will also allow Aramco to tap into high-value feedstocks for use in the expanding Downstream petrochemicals industry and our aim is to significantly increase our gas production capacity over the next decade to meet demand growth.”
Aramco recently announced its ambition to achieve net-zero Scope 1 and Scope 2 greenhouse gas emissions across its wholly-owned operated assets by 2050. Jafurah is expected to contribute to Saudi Arabia’s goal of producing half of its electricity from gas and half from renewables as the Kingdom pursues its own 2060 net-zero target.
At peak production, Aramco’s unconventional gas program is expected to replace around half a million barrels of crude oil per day that would otherwise have been used for domestic consumption. The Jafurah gas development alone is expected to replace more than 300,000 barrels of crude oil per day at peak production.
Nasir K. Al-Naimi, Aramco’s Upstream Senior Vice President, said: “The development of Jafurah is a game-changer for our Unconventional Resources program. It will be one of the most modern, cost-efficient shale development schemes in the industry and observe the highest environmental and safety standards. Jafurah will be a key enabler of our ambitions moving forward, and we continue to explore new fields, re-evaluate existing ones and evaluate potential joint investment opportunities in both natural gas and natural gas liquids as we pursue our goal of developing an integrated global gas portfolio to meet long-term energy and petrochemicals demand.”
Aramco has awarded 16 subsurface and EPC contracts valued at $10bn for the Jafurah Gas Plant and gas compression facilities, as well as infrastructure and related surface facilities. These contracts were awarded to domestic and international service companies and involve several projects to enable development of subsurface and surface components of the Jafurah program.
This will allow for the reliable delivery of gas and condensates through a dedicated surface network that includes a gas processing plant, a gas compression system and network of around 1,500 kilometers of main transfer pipelines, flow lines and gas gathering pipelines. The program also includes construction of the Jafurah Bulk Supply Point, transmission lines, power interconnection for Jafurah Gas Plant and new cogeneration plant facilities.
In line with Aramco’s Digital Transformation Program, development of Jafurah will incorporate advanced Fourth Industrial Revolution (4IR) technologies, including Industrial Internet of Things (IIoT) and video analytics, to enhance construction, operation and safety.
Aramco has awarded the majority of Jafurah subsurface contracts, in addition to engineering, material procurement and construction contracts, to contractors based in Saudi Arabia, in association with reputed international contractors and service providers. This is in line with the Company’s efforts to support development of the domestic energy sector and local supply chain partners. In addition, to drive domestic value creation and maximize long-term economic growth and diversification, the Jafurah development program will include an In-Kingdom Total Value Add (iktva) component. Aramco launched the iktva program in 2015 to facilitate development of a diverse, sustainable, and a globally competitive energy sector.
It is a significant milestone both for the commercialization of unconventional resources in Saudi Arabia and the expansion of Aramco’s integrated gas portfolio, which will provide additional feedstock to support growth of the Company’s high-value chemicals business, complement its focus on low-carbon hydrogen production and help reduce emissions in the domestic power sector by providing a cleaner-burning alternative to liquid fuel.
With an estimated 200 trillion standard cubic feet of gas in place, the Jafurah basin hosts the largest liquid-rich shale gas play in the Middle East. This shale play covers an area measuring 17,000 square kilometers and production of natural gas at Jafurah is expected to ramp up from 200 million standard cubic feet per day (scfd) in 2025 to reach a sustainable gas rate of two billion scfd of sales gas by 2030, with 418 million scfd of ethane and around 630,000 barrels per day of gas liquids and condensates, which are essential feedstock for the growing petrochemical industry. It will make Saudi Arabia one of the world’s largest natural gas producers.
HRH Prince Abdulaziz bin Salman Al Saud, Minister of Energy for the Kingdom of Saudi Arabia, said: “I would like to thank the Custodian of the Two Holy Mosques, King Salman bin Abdulaziz Al Saud, and HRH Prince Mohammed bin Salman bin Abdulaziz Al Saud, Crown Prince, Deputy Prime Minister and Minister of Defense, for their ongoing support of the Kingdom’s energy sector. The development of Jafurah will positively contribute to the Kingdom’s energy mix and it has been made possible thanks to close co-operation between more than 17 different agencies. The government is committed to the empowerment of national companies such as Aramco and no other energy company in the world is empowered to the same extent by the state, or by the Ministry of Energy which oversees the concession to develop the Kingdom’s hydrocarbon resources.”
The project is a key component of the Company’s long-term strategy and Aramco expects total overall lifecycle investment at Jafurah to exceed $100 billion. Through its unconventional gas program at the Jafurah, North Arabia and South Ghawar fields, the Company expects to create more than 200,000 direct and indirect jobs.
Amin H. Nasser, Aramco President and CEO, said: “This is a pivotal moment in the commercialization of Saudi Arabia’s vast unconventional resources program. It is a breakthrough that few outside the Kingdom thought was possible, and which has positive implications for energy security, economic development and climate protection. Gas has a critical role to play in the energy transition and it will help significantly reduce emissions in the domestic energy sector, while providing a feedstock for low-carbon hydrogen and ammonia. It will also allow Aramco to tap into high-value feedstocks for use in the expanding Downstream petrochemicals industry and our aim is to significantly increase our gas production capacity over the next decade to meet demand growth.”
Aramco recently announced its ambition to achieve net-zero Scope 1 and Scope 2 greenhouse gas emissions across its wholly-owned operated assets by 2050. Jafurah is expected to contribute to Saudi Arabia’s goal of producing half of its electricity from gas and half from renewables as the Kingdom pursues its own 2060 net-zero target.
At peak production, Aramco’s unconventional gas program is expected to replace around half a million barrels of crude oil per day that would otherwise have been used for domestic consumption. The Jafurah gas development alone is expected to replace more than 300,000 barrels of crude oil per day at peak production.
Nasir K. Al-Naimi, Aramco’s Upstream Senior Vice President, said: “The development of Jafurah is a game-changer for our Unconventional Resources program. It will be one of the most modern, cost-efficient shale development schemes in the industry and observe the highest environmental and safety standards. Jafurah will be a key enabler of our ambitions moving forward, and we continue to explore new fields, re-evaluate existing ones and evaluate potential joint investment opportunities in both natural gas and natural gas liquids as we pursue our goal of developing an integrated global gas portfolio to meet long-term energy and petrochemicals demand.”
Aramco has awarded 16 subsurface and EPC contracts valued at $10bn for the Jafurah Gas Plant and gas compression facilities, as well as infrastructure and related surface facilities. These contracts were awarded to domestic and international service companies and involve several projects to enable development of subsurface and surface components of the Jafurah program.
This will allow for the reliable delivery of gas and condensates through a dedicated surface network that includes a gas processing plant, a gas compression system and network of around 1,500 kilometers of main transfer pipelines, flow lines and gas gathering pipelines. The program also includes construction of the Jafurah Bulk Supply Point, transmission lines, power interconnection for Jafurah Gas Plant and new cogeneration plant facilities.
In line with Aramco’s Digital Transformation Program, development of Jafurah will incorporate advanced Fourth Industrial Revolution (4IR) technologies, including Industrial Internet of Things (IIoT) and video analytics, to enhance construction, operation and safety.
Aramco has awarded the majority of Jafurah subsurface contracts, in addition to engineering, material procurement and construction contracts, to contractors based in Saudi Arabia, in association with reputed international contractors and service providers. This is in line with the Company’s efforts to support development of the domestic energy sector and local supply chain partners. In addition, to drive domestic value creation and maximize long-term economic growth and diversification, the Jafurah development program will include an In-Kingdom Total Value Add (iktva) component. Aramco launched the iktva program in 2015 to facilitate development of a diverse, sustainable, and a globally competitive energy sector.
Monday 22 November 2021
TechnipFMC Awarded Large Subsea Contract for Additional Stabroek Block project
TechnipFMC (NYSE: FTI) (PARIS: FTI) has been awarded a large(1) contract by Exxon Mobil Corporation (NYSE: XOM) affiliate, Esso Exploration and Production Guyana Limited, to supply the subsea production system for the Yellowtail development.
Subject to government approvals and final project sanction, TechnipFMC will provide project management, engineering, manufacturing and testing capabilities to deliver the overall subsea production system. The scope of the project includes 51 enhanced vertical deepwater trees (EVDT) and associated tooling, as well as 12 manifolds and associated controls and tie-in equipment.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “We are very excited to continue our relationship with ExxonMobil through this award, which is our fourth within the Stabroek block. We are proud of our dedicated Guyanese employees and are committed to the continued development and expansion of local capabilities.”
TechnipFMC currently employs more than 60 Guyanese, and expects to continue to hire and train additional local staff in support of this award.
Subject to government approvals and final project sanction, TechnipFMC will provide project management, engineering, manufacturing and testing capabilities to deliver the overall subsea production system. The scope of the project includes 51 enhanced vertical deepwater trees (EVDT) and associated tooling, as well as 12 manifolds and associated controls and tie-in equipment.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “We are very excited to continue our relationship with ExxonMobil through this award, which is our fourth within the Stabroek block. We are proud of our dedicated Guyanese employees and are committed to the continued development and expansion of local capabilities.”
TechnipFMC currently employs more than 60 Guyanese, and expects to continue to hire and train additional local staff in support of this award.
Friday 19 November 2021
McDermott Completes FEED and Wins Ichthys Booster Compression Platform EPC Contract
Nov. 18, 2021
McDermott has won an engineering, procurement and construction (EPC) project after successfully completing FEED services for a booster compression module for the INPEX-operated Ichthys LNG development. The module will be added to the Ichthys Explorer central processing facility, located off the northwest coast of Western Australia.
"Ichthys LNG is ranked among the most significant and complex energy developments in the world. We've been there since 2012, and we are very familiar with the Ichthys gas field," said Mahesh Swaminathan, McDermott's Senior Vice President, Asia Pacific. "McDermott's integrated, end-to-end solution minimizes project risks by enhancing delivery certainty and managing COVID-19 impacts."
This is the third contract McDermott has been awarded for the project after successfully completing FEED services and converting contracts to EPCI.
McDermott's EPC scope involves a booster compression module which will extend the production from the gas reservoir to the central processing facility. McDermott is currently undertaking umbilicals, risers and flowlines as part of an expansion of the existing offshore facilities.
The work will be executed from McDermott's Engineering Centers of Excellence in Perth, Kuala Lumpur and Chennai. Fabrication will be completed at McDermott's yard in Batam which has been delivering complex offshore and onshore structures for over 50 years.
Wednesday 14 April 2021
Uganda And Tanzania: Final Agreements For The Lake Albert Resources Development Project
During a signing ceremony held yesterday in Entebbe, in the presence of Yoweri Museveni, President of the Republic of Uganda, Samia Suluhu Hassan, President of the United Republic of Tanzania, Patrick Pouyanné, Chairman and CEO of Total, as well as representatives of China National Offshore Oil Corporation (CNOOC), Uganda National Oil Company (UNOC) and Tanzania Petroleum Development Corporation (TPDC), the partners of the Lake Albert development project have concluded the final agreements required to launch this major project.
The Lake Albert development encompasses Tilenga and Kingfisher upstream oil projects in Uganda and the construction of the East African Crude Oil Pipeline (EACOP) in Uganda and Tanzania. The Tilenga project, operated by Total, and the Kingfisher project, operated by CNOOC, are expected to deliver a combined production of 230,000 barrels per day at plateau. The upstream partners are Total (56.67%), CNOOC (28.33%) and UNOC (15%). The production will be transported from the oilfields in Uganda to the port of Tanga in Tanzania via EACOP cross-border pipeline, with Total, UNOC, TPDC and CNOOC as shareholders.
The agreements concluded yesterday include the Shareholders Agreement of EACOP and the Tariff and Transportation Agreement between EACOP and the Lake Albert oil shippers.
These agreements open the way for the commencement of the Lake Albert development project. The main engineering, procurement and construction contracts will be awarded shortly, and construction will start. First oil export is planned in early 2025.
All the partners are committed to implement these projects in an exemplary manner and taking into highest consideration the biodiversity and environmental stakes as well as the local communities’ rights and within the stringent environmental and social performance standards of the International Finance Corporation (IFC).
“The Tilenga development and EACOP pipeline project are major projects for Total and are consistent with our strategy to focus on low breakeven oil projects while lowering the average carbon intensity of the Group’s upstream portfolio. These projects will create significant in-country value for both Uganda and Tanzania” said Patrick Pouyanné, Chairman and Chief Executive Officer of Total. “Total is also taking into the highest consideration the sensitive environmental context and social stakes of these onshore projects. Our commitment is to implement these projects in an exemplary and fully transparent manner”.
“The Tilenga development and EACOP pipeline project are major projects for Total and are consistent with our strategy to focus on low breakeven oil projects while lowering the average carbon intensity of the Group’s upstream portfolio. These projects will create significant in-country value for both Uganda and Tanzania” said Patrick Pouyanné, Chairman and Chief Executive Officer of Total. “Total is also taking into the highest consideration the sensitive environmental context and social stakes of these onshore projects. Our commitment is to implement these projects in an exemplary and fully transparent manner”.
Thursday 25 March 2021
INEOS Energy to sell its Norwegian oil and gas business to PGNiG for $615m
INEOS Energy has today announced an agreement to sell its Oil and Gas business in Norway to PGNiG Upstream Norway AS for a consideration of $615 million. The deal includes all INEOS Oil & Gas interests in production, licenses, fields, facilities and pipelines, on the Norwegian continental shelf.
INEOS E&P Norge AS produces around 33,000 BOE per day from the Norwegian Sea. A 93% gas ratio, from 3 non-operated fields, Ormen Lange (14%), Alve (15%) and Marulk (30%). The business also holds 22 offshore licenses, of which 6 are operated, and has equity in the Nyhamna Terminal (8%).
The deal announced today continues to rebalance our portfolio in terms of oil and gas and moves INEOS Energy towards a more operated position.
The sale, which has an effective date of 1 January 2021, is subject to approval by the Norwegian Ministry of Petroleum and Energy and the Norwegian Ministry of Finance. It is expected to complete later this year.
All 52 employees of INEOS E&P Norge AS will transfer to PGNiG Upstream Norway AS following completion of the deal.
The PGNiG Group is the largest Polish oil and gas company employing 25,000 people worldwide. PGNiG Upstream Norway AS is an integrated exploration and production company established in Norway in 2007 and plays an important role in the supply of gas to Poland.
Brian Gilvary, Executive Chairman of INEOS Energy said, “This represents another positive step in the INEOS Energy journey. The deal allows us to monetise a non-operated, predominantly gas portfolio at an attractive price compared to our hold value. This will further balance our portfolio of oil and gas and open up new opportunities to reinvest further into the energy transition. These assets are a very strong strategic fit for PGNiG and significantly extends their position in Norway."
Today’s deal quickly follows the announcement of the acquisition of the HESS business in Denmark, which consists of operated assets. These deals begin reshaping INEOS Energy as it progresses a strategy to position the businesses strongly in the coming energy transition.
Friday 5 March 2021
ExxonMobil to sell U.K. upstream central and northern North Sea assets
ExxonMobil has signed an agreement with HitecVision, through its wholly owned portfolio company NEO Energy, for the sale of most of ExxonMobil’s non-operated upstream assets in the United Kingdom central and northern North Sea. The sale price of more than $1 billion is subject to closing adjustments, and has additional upside of approximately $300 million in contingent payments based on potential for increase in commodity prices.
Sale price of more than $1 billion advances divestment plans, further focusing portfolio on advantaged assets
ExxonMobil retains extensive refining and fuels marketing, lubricants, petrochemicals production and natural gas marketing business in the U.K.
“We continue to high-grade our portfolio by divesting assets that are less strategic and focusing our investments on our advantaged projects that are among the best in the industry,” said Neil Chapman, senior vice president of ExxonMobil. “Our development plans that prioritize Guyana, the U.S. Permian Basin, Brazil and LNG are focused on increasing earnings potential and generating strong cash flow to fund future capital investments, reduce debt and maintain a reliable dividend.”
The agreement includes ownership interests in 14 producing fields operated primarily by Shell, including Penguins, Starling, Fram, the Gannet Cluster and Shearwater; Elgin Franklin fields operated by Total; and interests in the associated infrastructure. ExxonMobil’s share of production from these fields was approximately 38,000 oil-equivalent barrels per day in 2019.
ExxonMobil will retain its non-operated share in upstream assets in the southern North Sea, and its share in the Shell Esso gas and liquids (SEGAL) infrastructure that supplies ethane to the company’s Fife ethylene plant.
The transaction is expected to close by the middle of 2021, subject to regulatory and third-party approvals.
ExxonMobil has operated in the U.K. for more than 135 years and continues natural gas sales, refining and chemical operations, the marketing of lubricants and petrochemicals, and the marketing of fuels through a network of more than 1,300 independently owned Esso-branded retail sites.
https://corporate.exxonmobil.com/News/Newsroom/News-releases/2021/0224_ExxonMobil-to-sell-UK-Upstream-Central-and-Northern-North-Sea-assets
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