TechnipFMC (NYSE: FTI) (PARIS: FTI) has been awarded an integrated Engineering, Procurement, Construction and Installation (iEPCI™) contract(1) for Equinor’s Smørbukk Nord development.
The contract covers a high-pressure, high-temperature subsea production system and associated equipment for a brownfield tieback in the Åsgard field in the Norwegian Continental Shelf, where TechnipFMC has a large installed base. The award follows front end engineering and design work on the project in 2021.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “Our ability to deliver this optimized solution for Equinor is possible due to our close collaboration with the client, portfolio of subsea equipment, and integrated execution model. We’re delighted to be once again delivering an iEPCI™ project for Equinor.”
The installation campaign will use TechnipFMC’s battery hybrid vessel, which will reduce greenhouse gas emissions through reduced fuel consumption.
Friday, 21 January 2022
Tuesday, 11 January 2022
Eni awarded five Exploration Licenses in Egypt
Eni has been awarded five new exploration licenses by the Egyptian Ministry of Petroleum. The licenses, four of which as Operator, are in the Egyptian offshore and onshore, and follow the successful participation to the 2021 competitive “Egypt International Bid Round for Petroleum Exploration and Exploitation” which was previously announced by the Egyptian General Petroleum Corporation and the Egyptian Natural Gas Holding Company through the Egypt Exploration and Production Gateway.
The licenses are located in the Eastern Mediterranean Sea (Block “EGY-MED-E5” in partnership with BP 50%-50% and Block “EGY-MED-E6” IEOC 100%), in the Gulf of Suez (Block “EGY-GOS-13” IEOC 100%) and in the Western Desert (Blocks “Egy-WD- 7” in partnership with APEX 50%-50% and “EGY-WD-9” IEOC 100%) with a total acreage of about 8,410 sqkm. The licenses are placed within prolific basins with proved petroleum systems able to generate liquid and gaseous hydrocarbons and can also rely on nearby existing producing and processing facilities and on a demanding market that will allow a quick valorization of the potential exploration discoveries.
The bid results are aligned with Eni’s strategy to keep exploring and producing gas to sustain the Egyptian domestic market and contribute to LNG export, thanks to the recent restart of the Damietta LNG plant.
Eni has been present in Egypt since 1954 and is currently the country's main producer with equity hydrocarbon production of around 350,000 barrels of oil equivalent per day.
The licenses are located in the Eastern Mediterranean Sea (Block “EGY-MED-E5” in partnership with BP 50%-50% and Block “EGY-MED-E6” IEOC 100%), in the Gulf of Suez (Block “EGY-GOS-13” IEOC 100%) and in the Western Desert (Blocks “Egy-WD- 7” in partnership with APEX 50%-50% and “EGY-WD-9” IEOC 100%) with a total acreage of about 8,410 sqkm. The licenses are placed within prolific basins with proved petroleum systems able to generate liquid and gaseous hydrocarbons and can also rely on nearby existing producing and processing facilities and on a demanding market that will allow a quick valorization of the potential exploration discoveries.
The bid results are aligned with Eni’s strategy to keep exploring and producing gas to sustain the Egyptian domestic market and contribute to LNG export, thanks to the recent restart of the Damietta LNG plant.
Eni has been present in Egypt since 1954 and is currently the country's main producer with equity hydrocarbon production of around 350,000 barrels of oil equivalent per day.
Monday, 10 January 2022
McDermott Wins Scarborough EPCIC Contract
After successfully completing the Front-End Engineering Design (FEED) for the Scarborough Project, McDermott International has been awarded a contract by Woodside, as Operator for and on behalf of the Scarborough Joint Venture, for the engineering, procurement, construction, installation and commissioning (EPCIC) services for its Floating Production Unit (FPU) offshore Western Australia. The integrated scope also includes the design, fabrication, integration, transportation and installation of the hull and topsides.
"McDermott brings the engineering and execution expertise to deliver integrated deepwater subsea projects and offshore FPUs to the highest standards," said Samik Mukherjee, Executive Vice President and Chief Operating Officer. "After a long engagement on the project, the collaborative execution model with Woodside—from pre-FEED through to EPCIC—de-risks execution. Further, the facilities incorporate energy efficiency in design to reduce Scarborough's offshore emissions."
The topside, which will be approximately 30,000 tons, will be fabricated by McDermott's joint venture fabrication yard, Qingdao McDermott Wuchuan, in China. The project scope includes a battery energy storage system to reduce emissions on the topsides and support Woodside's net emissions reduction targets.
"McDermott will apply our long history of successful integrated project delivery for the Scarborough Project, along with our deepwater expertise and industry-leading health and safety standards to drive this incredible project to completion," said Mahesh Swaminathan, Senior Vice President, Asia Pacific.
Engineering expertise will be leveraged from McDermott's Kuala Lumpur and Gurgaon offices, with McDermott's long-established subsea team in Perth supporting transport, installation, hook up and commissioning activities.
The FPU processes natural gas, which includes gas separation, dehydration and compression as well as mono ethylene glycol regeneration and produced-water handling. Designed for a production capacity of up to 1.8 billion standard cubic feet per day, the topside will be connected to the semi-submersible hull and pre-commissioned prior to transportation and installation in a water depth of 3,100 feet (950 meters), approximately 248 miles (400 kilometers) offshore Western Australia. The FPU will be capable of being remotely operated and minimally staffed during normal production operations.
"McDermott brings the engineering and execution expertise to deliver integrated deepwater subsea projects and offshore FPUs to the highest standards," said Samik Mukherjee, Executive Vice President and Chief Operating Officer. "After a long engagement on the project, the collaborative execution model with Woodside—from pre-FEED through to EPCIC—de-risks execution. Further, the facilities incorporate energy efficiency in design to reduce Scarborough's offshore emissions."
The topside, which will be approximately 30,000 tons, will be fabricated by McDermott's joint venture fabrication yard, Qingdao McDermott Wuchuan, in China. The project scope includes a battery energy storage system to reduce emissions on the topsides and support Woodside's net emissions reduction targets.
"McDermott will apply our long history of successful integrated project delivery for the Scarborough Project, along with our deepwater expertise and industry-leading health and safety standards to drive this incredible project to completion," said Mahesh Swaminathan, Senior Vice President, Asia Pacific.
Engineering expertise will be leveraged from McDermott's Kuala Lumpur and Gurgaon offices, with McDermott's long-established subsea team in Perth supporting transport, installation, hook up and commissioning activities.
The FPU processes natural gas, which includes gas separation, dehydration and compression as well as mono ethylene glycol regeneration and produced-water handling. Designed for a production capacity of up to 1.8 billion standard cubic feet per day, the topside will be connected to the semi-submersible hull and pre-commissioned prior to transportation and installation in a water depth of 3,100 feet (950 meters), approximately 248 miles (400 kilometers) offshore Western Australia. The FPU will be capable of being remotely operated and minimally staffed during normal production operations.
Tuesday, 21 December 2021
PETRONAS Wins Sépia Field In Brazil Bid Round
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.
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.
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.”
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