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.
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