INEOS Energy has today announced the acquisition of the Gulf of Mexico business held by CNOOC Energy Holdings U.S.A. Inc., a U.S. subsidiary of CNOOC International Limited (“CNOOC”).
The deal increases INEOS Energy’s production globally to over 90 thousand barrels of oil equivalent per day. These assets in the Gulf of Mexico are the third major investment by INEOS Energy in the USA, in the past three years, following the 1.4 mtpa LNG deal completed with Sempra in December 2022 and the acquisition of Chesapeake Energy’s oil and gas assets in South Texas in May 2023.
The deal includes a portfolio of non operated assets built around two deep water early production assets (Appomattox and Stampede) in the Gulf of Mexico. In addition, INEOS acquires several mature assets and supporting business.
Brian Gilvary Chairman of INEOS Energy said: “This is a major step for us into the deepwater Gulf of Mexico, which builds on our growing energy business. INEOS Energy is all about competing in the energy transition to provide reliable, affordable energy to meet world demand as the population continues to grow. And progressing carbon storage projects.”
The CNOOC Gulf of Mexico assets and strategic partnerships in major U.S. energy projects, will further complement INEOS’ existing onshore portfolio.
David Bucknall CEO INEOS Energy said, "The USA is a very attractive place for INEOS Energy to invest. This is our third deal in three years following the 1.4 mtpa LNG deal with Sempra and the acquisition of Chesapeake Energy’s oil and gas assets in South Texas. Total capital spend on energy assets in the USA now exceeds $3billion, providing a strong platform for future growth.”
INEOS Energy is committed to a dual track approach, to meet society's energy needs through the current energy transition and to investment in carbon storage. The business is actively producing and trading oil, gas, power and carbon credits, as well as investing in LNG, and Carbon Capture and Storage.
In a world first, INEOS demonstrated the feasibility of CO2 storage on the 8th March 2023. The company captured CO2 from INEOS Oxide in Belgium; transported this cross-border then safely and permanently stored it in the INEOS-operated Nini field in the Danish North Sea. On the 10th September this year world-leading provider of risk, verification and standardization services, DNV, verified that the stored CO2 remains safely and permanently sealed in the Nini West reservoir 1,800 metres below the North Sea seabed. Their verification moves the project closer towards commercialisation, expected next year.
Last week, (10th December) INEOS, the day-to-day operator, with its partners Harbour Energy and Nordsøfonden, announced it had made a Final Investment Decision (FID) on the first commercial phase ‘Greensand Future’ with storage operations set to begin at the end of 2025/early 2026. This decision paves the way for expected investments of more than $150 million across the Greensand CCS value chain.
The acquisition of the Gulf of Mexico business held by CNOOC Energy Holdings U.S.A. is subject to the receipt of regulatory approvals and satisfaction of other customary closing conditions.
Tuesday, 31 December 2024
Monday, 30 December 2024
Eni kicks off Baleine Phase 2, increasing production in the offshore of Côte d'Ivoire
Today, Eni successfully started production of Phase 2 from the Baleine field, marking a crucial step in the development of the Côte d'Ivoire’s offshore. Thanks to this milestone, production will reach 60,000 barrels of oil per day and 70 million cubic feet of associated gas (equivalent to 2 million cubic metres).
Phase 2 will see the Floating Production, Storage and Offloading Unit (FPSO) Petrojarl Kong deployed alongside the Floating Storage and Offloading Unit (FSO) Yamoussoukro for the export of oil, while 100% of the processed gas will supply the local energy demand through the connection with the pipeline built during the project’s Phase 1. This achievement further consolidates Côte d'Ivoire's role as a producing country on the global energy scenario, strengthening access to energy on a national scale.
The rapid development of Baleine Phase 2 confirms Eni's excellent time-to-market, enhanced also by the renovation and reuse of the 2 units.
The Final Investment Decision for the project was taken in December 2022; Phase 1 was started in August 2023; in parallel, activities for Phase 2 had been carried and completed in full safety.
Baleine is the first net zero emission Upstream project (Scope 1 and 2) in Africa, made possible through the adoption of advanced technologies, which minimize the operations’ carbon footprint, and innovative initiatives developed in close collaboration with the Ivorian ministries. These include the improved cookstoves’ distribution program (i.g. clean cooking program), which leverages the local production and has already benefited over 575,000 people in vulnerable conditions, and the initiative to protect and restore 14 classified forests, both contributing to the project’s carbon neutrality. In addition, a wide range of initiatives in the areas of vocational training, education, health and economic diversification enrich Eni's collaboration with the country.
Eni has been present in Côte d'Ivoire since 2015 with a current equity production of around 22,000 barrels of oil equivalent per day. The company operates 10 blocks in the Ivorian deepwaters (CI-101, CI-205, CI-401, CI-501, CI-801, CI-802, CI-504, CI-526, CI-706 and CI-708) in partnership with Petroci Holding.
With the start-up of Baleine's Phase 2 and the development of Phase 3, currently under study, total production is set to reach 150,000 barrels of oil per day and 200 million cubic feet of associated gas, further consolidating Côte d'Ivoire's role as a regional energy hub and strengthening strategic collaboration with the local partner.
Phase 2 will see the Floating Production, Storage and Offloading Unit (FPSO) Petrojarl Kong deployed alongside the Floating Storage and Offloading Unit (FSO) Yamoussoukro for the export of oil, while 100% of the processed gas will supply the local energy demand through the connection with the pipeline built during the project’s Phase 1. This achievement further consolidates Côte d'Ivoire's role as a producing country on the global energy scenario, strengthening access to energy on a national scale.
The rapid development of Baleine Phase 2 confirms Eni's excellent time-to-market, enhanced also by the renovation and reuse of the 2 units.
The Final Investment Decision for the project was taken in December 2022; Phase 1 was started in August 2023; in parallel, activities for Phase 2 had been carried and completed in full safety.
Baleine is the first net zero emission Upstream project (Scope 1 and 2) in Africa, made possible through the adoption of advanced technologies, which minimize the operations’ carbon footprint, and innovative initiatives developed in close collaboration with the Ivorian ministries. These include the improved cookstoves’ distribution program (i.g. clean cooking program), which leverages the local production and has already benefited over 575,000 people in vulnerable conditions, and the initiative to protect and restore 14 classified forests, both contributing to the project’s carbon neutrality. In addition, a wide range of initiatives in the areas of vocational training, education, health and economic diversification enrich Eni's collaboration with the country.
Eni has been present in Côte d'Ivoire since 2015 with a current equity production of around 22,000 barrels of oil equivalent per day. The company operates 10 blocks in the Ivorian deepwaters (CI-101, CI-205, CI-401, CI-501, CI-801, CI-802, CI-504, CI-526, CI-706 and CI-708) in partnership with Petroci Holding.
With the start-up of Baleine's Phase 2 and the development of Phase 3, currently under study, total production is set to reach 150,000 barrels of oil per day and 200 million cubic feet of associated gas, further consolidating Côte d'Ivoire's role as a regional energy hub and strengthening strategic collaboration with the local partner.
Saturday, 28 December 2024
TechnipFMC Awarded Substantial Subsea Contract for Shell’s Bonga North Development in Nigeria
TechnipFMC (NYSE: FTI) has been awarded a substantial contract by Shell Nigeria Exploration and Production Company Limited to supply Subsea 2.0® production systems for the Bonga North development in Nigeria.
The contract covers the design and manufacture of subsea tree systems, manifolds, jumpers, controls, and services.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “Shell was the first to adopt our Subsea 2.0® configure-to-order solution, and continues to deploy it across multiple basins—underscoring its commitment to the technology globally. This award further positions us for future deepwater opportunities in the region.”
The contract covers the design and manufacture of subsea tree systems, manifolds, jumpers, controls, and services.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “Shell was the first to adopt our Subsea 2.0® configure-to-order solution, and continues to deploy it across multiple basins—underscoring its commitment to the technology globally. This award further positions us for future deepwater opportunities in the region.”
Shell invests in Bonga North deep-water project, Nigeria
Shell Nigeria Exploration and Production Company Limited (SNEPCo), a subsidiary of Shell plc, has announced a final investment decision (FID) on Bonga North, a deep-water project off the coast of Nigeria.
Bonga North will be a subsea tie-back to the Shell-operated Bonga Floating Production Storage and Offloading (FPSO) facility which Shell operates with a 55% interest.
The Bonga North project involves drilling, completing, and starting up 16 wells (8 production and 8 water injection wells), modifications to the existing Bonga Main FPSO and the installation of new subsea hardware tied back to the FPSO.
The project will sustain oil and gas production at the Bonga facility. Bonga North currently has an estimated recoverable resource volume of more than 300 million barrels of oil equivalent (boe) and will reach a peak production of 110,000 barrels of oil a day, with first oil anticipated by the end of the decade.
“This is another significant investment, which will help us to maintain stable liquids production from our advantaged Upstream portfolio,” said Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director.
Bonga North will help ensure Shell’s leading Integrated Gas and Upstream business continues to drive cash generation into the next decade.
Notes to editors:
Bonga North will be a subsea tie-back to the Shell-operated Bonga Floating Production Storage and Offloading (FPSO) facility which Shell operates with a 55% interest.
The Bonga North project involves drilling, completing, and starting up 16 wells (8 production and 8 water injection wells), modifications to the existing Bonga Main FPSO and the installation of new subsea hardware tied back to the FPSO.
The project will sustain oil and gas production at the Bonga facility. Bonga North currently has an estimated recoverable resource volume of more than 300 million barrels of oil equivalent (boe) and will reach a peak production of 110,000 barrels of oil a day, with first oil anticipated by the end of the decade.
“This is another significant investment, which will help us to maintain stable liquids production from our advantaged Upstream portfolio,” said Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director.
Bonga North will help ensure Shell’s leading Integrated Gas and Upstream business continues to drive cash generation into the next decade.
Notes to editors:
- SNEPCo (55%) operates the Bonga field in partnership with Esso Exploration and Production Nigeria Ltd. (20%), Nigerian Agip Exploration Ltd. (12.5%), and TotalEnergies Exploration and Production Nigeria Ltd. (12.5%), on behalf of the Nigerian National Petroleum Company Limited (NNPC).
- Bonga is a deep-water development located in OML 118, at water depths exceeding 1,000 meters. Production at the Bonga FPSO began in 2005, with a capacity to produce 225,000 barrels of oil per day. The project produced its one-billionth barrel of crude oil in 2023.
- The Bonga North development holds estimated recoverable resource volumes of more than 300 million barrels of oil equivalent (boe). These volumes are currently classified as 2P (proven and probable) under the Society of Petroleum Engineers’ Petroleum Resources Management System.
- The estimated peak production and recoverable resources mentioned above are 100% total gross figures.
- The investment in Bonga North is expected to generate an internal rate of return (IRR) in excess of the hurdle rate for Shell’s Upstream business.
- Shell’s Upstream business continues to set new benchmarks in performance through near-field opportunities like Bonga North, leveraging technical expertise, strong partnerships, and a model built on simplification and replication.
Phillips 66 announces agreement to sell interest in Gulf Coast Express
Phillips 66 (NYSE: PSX) announced today that it has entered into a definitive agreement to sell DCP GCX Pipeline LLC, which owns a 25% non-operated equity interest in Gulf Coast Express Pipeline LLC, to an affiliate of ArcLight Capital Partners, LLC for pre-tax total cash proceeds of $865 million, subject to purchase price adjustments.
“With this transaction, we have exceeded our $3 billion asset divestiture target established in our strategic priorities. We intend to continue to optimize the portfolio and rationalize non-core assets going forward,” said Mark Lashier, chairman and CEO of Phillips 66. “The evolution of our portfolio underscores our position as a leading integrated downstream energy provider, enhancing shareholder value and positioning the company for the future.”
Gulf Coast Express Pipeline is an approximately 500-mile pipeline system that transports about 2 billion cubic feet per day of natural gas from the Permian Basin to the Agua Dulce, Texas area. Following the transaction, Gulf Coast Express Pipeline LLC will be jointly owned by subsidiaries of Kinder Morgan, Inc. (NYSE: KMI) and affiliates of ArcLight Capital Partners, LLC.
The sales price represents an implied Enterprise Value/EBITDA multiple of 10.6x based on expected 2025 EBITDA. Proceeds from the sale will support the strategic priorities of Phillips 66, including returns to shareholders and debt reduction.
The sale is expected to close in January 2025.
“With this transaction, we have exceeded our $3 billion asset divestiture target established in our strategic priorities. We intend to continue to optimize the portfolio and rationalize non-core assets going forward,” said Mark Lashier, chairman and CEO of Phillips 66. “The evolution of our portfolio underscores our position as a leading integrated downstream energy provider, enhancing shareholder value and positioning the company for the future.”
Gulf Coast Express Pipeline is an approximately 500-mile pipeline system that transports about 2 billion cubic feet per day of natural gas from the Permian Basin to the Agua Dulce, Texas area. Following the transaction, Gulf Coast Express Pipeline LLC will be jointly owned by subsidiaries of Kinder Morgan, Inc. (NYSE: KMI) and affiliates of ArcLight Capital Partners, LLC.
The sales price represents an implied Enterprise Value/EBITDA multiple of 10.6x based on expected 2025 EBITDA. Proceeds from the sale will support the strategic priorities of Phillips 66, including returns to shareholders and debt reduction.
The sale is expected to close in January 2025.
Tennessee Gas Pipeline Announces Final Investment Decision on Mississippi Crossing Project
Tennessee Gas Pipeline, L.L.C. (TGP), a subsidiary of Kinder Morgan, Inc. (NYSE: KMI), today announced its decision to proceed with its Mississippi Crossing Project (MSX Project) after securing long-term, binding transportation agreements with customers for all the capacity.
“This transformative project will benefit the Southeast region as it will provide incremental access to diverse sources of supply,” said Natural Gas Pipelines President Sital Mody. “The additional supply will help satisfy growing energy demand and lower energy costs, allowing power generators and other energy suppliers in the region to attract new residential, commercial and industrial opportunities. We are in final discussions with customers for up to an additional 0.4 Bcf/d of long-term commitments, which would require additional capital for incremental horsepower.”
The approximately $1.4 billion MSX Project is designed to transport up to 1.5 Bcf/d of natural gas and primarily involves the construction of nearly 206 miles of 42-inch and 36-inch pipeline and two new compressor stations. The project will originate near Greenville, Mississippi, and conclude near Butler, Alabama, with connections to the existing TGP system and third-party pipelines to provide critical supply access sourced from multiple supply basins. Pending the receipt of all required permits and clearances, the project is expected to be placed in service November 2028.
“The fundamentals in the natural gas market are robust, with significant growth expected over the next five years from LNG exports, exports to Mexico and power generation,” said KMI CEO Kim Dang. “With today’s announcement, KMI has sanctioned approximately $3.1 billion (KMI share) in expansion capital between the SNG South System 4 Expansion and TGP’s Mississippi Crossing Project. We expect to announce additional projects in the coming months.
“This transformative project will benefit the Southeast region as it will provide incremental access to diverse sources of supply,” said Natural Gas Pipelines President Sital Mody. “The additional supply will help satisfy growing energy demand and lower energy costs, allowing power generators and other energy suppliers in the region to attract new residential, commercial and industrial opportunities. We are in final discussions with customers for up to an additional 0.4 Bcf/d of long-term commitments, which would require additional capital for incremental horsepower.”
The approximately $1.4 billion MSX Project is designed to transport up to 1.5 Bcf/d of natural gas and primarily involves the construction of nearly 206 miles of 42-inch and 36-inch pipeline and two new compressor stations. The project will originate near Greenville, Mississippi, and conclude near Butler, Alabama, with connections to the existing TGP system and third-party pipelines to provide critical supply access sourced from multiple supply basins. Pending the receipt of all required permits and clearances, the project is expected to be placed in service November 2028.
“The fundamentals in the natural gas market are robust, with significant growth expected over the next five years from LNG exports, exports to Mexico and power generation,” said KMI CEO Kim Dang. “With today’s announcement, KMI has sanctioned approximately $3.1 billion (KMI share) in expansion capital between the SNG South System 4 Expansion and TGP’s Mississippi Crossing Project. We expect to announce additional projects in the coming months.
Thursday, 14 November 2024
SBM Offshore awarded contracts for the GranMorgu field development
SBM Offshore announces that it has been awarded contracts for the GranMorgu field development project located in Block 58 in Suriname by the Operator, TotalEnergies EP Suriname B.V., an affiliate of TotalEnergies. Under these contracts, SBM Offshore will, in partnership with Technip Energies, construct and install a Floating Production, Storage and Offloading vessel (FPSO). The award follows completion of front-end engineering and design studies, and the final investment decision on the project by the Joint Venture operated by TotalEnergies EP Suriname B.V. SBM Offshore is expected to operate the unit under an operations and maintenance agreement.
The GranMorgu project is the first development within Block 58, circa 150 kilometers offshore Suriname. TotalEnergies is the operator holding a 50 percent interest in Block 58, alongside APA Corporation. Staatsolie has announced its intent to exercise its option to enter the development project with up to 20% interest.
The FPSO will be the first large deepwater project development in Suriname with an expected production capacity of up to 220,000 barrels of oil per day and associated gas treatment capacity of up to 500 million cubic feet per day. The FPSO will be spread moored in water depth of about 400 meters and will be able to store around 2 million barrels of crude oil. First oil is expected in 2028.
Thanks to the joint expertise of Technip Energies and SBM Offshore, this all-electric drive FPSO will also be designed to eliminate routine flaring, in line with TotalEnergies objectives and SBM Offshore’s goal to deliver carbon efficient units.
The GranMorgu project is the first development within Block 58, circa 150 kilometers offshore Suriname. TotalEnergies is the operator holding a 50 percent interest in Block 58, alongside APA Corporation. Staatsolie has announced its intent to exercise its option to enter the development project with up to 20% interest.
The FPSO will be the first large deepwater project development in Suriname with an expected production capacity of up to 220,000 barrels of oil per day and associated gas treatment capacity of up to 500 million cubic feet per day. The FPSO will be spread moored in water depth of about 400 meters and will be able to store around 2 million barrels of crude oil. First oil is expected in 2028.
Thanks to the joint expertise of Technip Energies and SBM Offshore, this all-electric drive FPSO will also be designed to eliminate routine flaring, in line with TotalEnergies objectives and SBM Offshore’s goal to deliver carbon efficient units.
Thursday, 31 October 2024
FPSO Maria Quitéria starts operating in the pre-salt Campos Basin
The Maria Quitéria platform ship produced its first oil on Tuesday (10/15) in the Jubarte field, pre-salt in the Espírito Santo portion of the Campos Basin. The unit can produce up to 100,000 barrels of oil a day and process up to 5 million cubic meters of gas. It will be interconnected to a total of eight producing wells and eight injectors.
FPSO Maria Quitéria's entry was brought forward; it was initially scheduled for 2025, according to the 2024-2028 Strategic Plan. Petrobras is the sole holder of the production rights for the Jubarte field, located in the area known as Parque das Baleias in Espírito Santo.
The platform is FPSO (floating production, storage, and transfer system). It is equipped with technologies to reduce emissions with greater operational efficiency and a reduction of around 24% in operational greenhouse gas emissions.
With a height of 156 meters and a length of 333 meters, the FPSO is installed at a water depth of 1,385 meters. It will also have the capacity to generate 100 MW of energy to supply a city of 230,000 inhabitants.
Parque das Baleias Integrated Project
The Parque das Baleias area is made up of the Jubarte, Baleia Anã, Cachalote, Caxaréu, Pirambú and Mangangá fields. The first field, Jubarte, was discovered in 2001. In 2019, Petrobras and the National Agency of Petroleum, Natural Gas and Biofuels (ANP) signed an agreement to extend the concession period until 2056 for the new unified Jubarte field, which enabled the implementation of FPSO Maria Quitéria, the latest production system for the Parque das Baleias Integrated Project, as well as complementary projects in the area.
Three other platforms operate in Parque das Baleias: P-57, P-58, and FPSO Cidade de Anchieta. When Maria Quitéria starts operating at full load, this unit will account for around 40% of the field's production.
FPSO Maria Quitéria's entry was brought forward; it was initially scheduled for 2025, according to the 2024-2028 Strategic Plan. Petrobras is the sole holder of the production rights for the Jubarte field, located in the area known as Parque das Baleias in Espírito Santo.
The platform is FPSO (floating production, storage, and transfer system). It is equipped with technologies to reduce emissions with greater operational efficiency and a reduction of around 24% in operational greenhouse gas emissions.
With a height of 156 meters and a length of 333 meters, the FPSO is installed at a water depth of 1,385 meters. It will also have the capacity to generate 100 MW of energy to supply a city of 230,000 inhabitants.
Parque das Baleias Integrated Project
The Parque das Baleias area is made up of the Jubarte, Baleia Anã, Cachalote, Caxaréu, Pirambú and Mangangá fields. The first field, Jubarte, was discovered in 2001. In 2019, Petrobras and the National Agency of Petroleum, Natural Gas and Biofuels (ANP) signed an agreement to extend the concession period until 2056 for the new unified Jubarte field, which enabled the implementation of FPSO Maria Quitéria, the latest production system for the Parque das Baleias Integrated Project, as well as complementary projects in the area.
Three other platforms operate in Parque das Baleias: P-57, P-58, and FPSO Cidade de Anchieta. When Maria Quitéria starts operating at full load, this unit will account for around 40% of the field's production.
TechnipFMC Awarded iEPCI™ Contract for bp’s Greenfield 20K Development in the Paleogene
TechnipFMC (NYSE: FTI) has been awarded an integrated Engineering, Procurement, Construction, and Installation (iEPCI™) contract(1) by bp for its greenfield Kaskida development in the Gulf of Mexico.
The contract covers the design and manufacture of subsea production systems, including 20,000 psi (20K) standardized subsea trees and manifolds. The scope also includes the design, manufacture, and installation of subsea umbilicals, risers, and flowlines.
The award follows an integrated Front End Engineering and Design (iFEED®) study by TechnipFMC.
Jonathan Landes, President, Subsea for TechnipFMC, commented: “Our innovative high-pressure solutions are key to helping unlock the most economically attractive opportunities in the Paleogene. Kaskida is our latest iEPCI™ project with bp and is emblematic of our longstanding collaboration. Through early engagement, we’re leveraging the breadth of our technological and integration capabilities to help bp successfully deliver Kaskida.”
The contract covers the design and manufacture of subsea production systems, including 20,000 psi (20K) standardized subsea trees and manifolds. The scope also includes the design, manufacture, and installation of subsea umbilicals, risers, and flowlines.
The award follows an integrated Front End Engineering and Design (iFEED®) study by TechnipFMC.
Jonathan Landes, President, Subsea for TechnipFMC, commented: “Our innovative high-pressure solutions are key to helping unlock the most economically attractive opportunities in the Paleogene. Kaskida is our latest iEPCI™ project with bp and is emblematic of our longstanding collaboration. Through early engagement, we’re leveraging the breadth of our technological and integration capabilities to help bp successfully deliver Kaskida.”
Thursday, 15 August 2024
Shell invests in water injection at Gulf of Mexico field
Shell Offshore Inc. (Shell), a subsidiary of Shell plc, has taken a Final Investment Decision (FID) on a ‘waterflood’ project at its Vito asset in the US Gulf of Mexico. Water will be injected into the reservoir formation to displace additional oil.
The process is due to begin in 2027 and is expected to significantly enhance volume capacity at the Vito field.
“Over time, we’ve seen the benefits of waterflood as we look to fill our hubs in the Gulf of Mexico,” said Zoë Yujnovich, Shell Integrated Gas and Upstream Director. “This investment will deliver additional high-margin, lower-carbon barrels from our advantaged Upstream business while maximizing our potential from Vito.”
Waterflood is a method of secondary recovery where the injected water physically sweeps the displaced oil to adjacent production wells, while re-pressurizing the reservoir. The three water injection wells were all drilled as pre-producers.
Shell is the leading deep-water operator in the U.S. Gulf of Mexico, where our production has among the lowest greenhouse gas (GHG) intensity in the world for producing oil.
Notes to editors
The process is due to begin in 2027 and is expected to significantly enhance volume capacity at the Vito field.
“Over time, we’ve seen the benefits of waterflood as we look to fill our hubs in the Gulf of Mexico,” said Zoë Yujnovich, Shell Integrated Gas and Upstream Director. “This investment will deliver additional high-margin, lower-carbon barrels from our advantaged Upstream business while maximizing our potential from Vito.”
Waterflood is a method of secondary recovery where the injected water physically sweeps the displaced oil to adjacent production wells, while re-pressurizing the reservoir. The three water injection wells were all drilled as pre-producers.
Shell is the leading deep-water operator in the U.S. Gulf of Mexico, where our production has among the lowest greenhouse gas (GHG) intensity in the world for producing oil.
Notes to editors
- In July 2009, the Vito field was discovered in more than 4,000 feet of water approximately 75 miles south of Venice, LA, 150 miles southeast of New Orleans and 10 miles south of the Shell-operated Mars TLP.
- In 2015, the original Vito host design was simplified and rescoped, resulting in a reduction of approximately 80% in CO2 emissions over the lifetime of the facility as well as a cost reduction of more than 70% from the original host design concept.
- Shell (Operator 63.11%) and Equinor (36.89%) announced FID for the Vito development in April 2018, with first oil achieved in February 2023.
- Given the properties of the Vito reservoir, energy is required to maximize the producing rate of existing wells and thus ultimate recovery.
- The Vito waterflood project will increase recoverable resource volume by 60 million boe. The estimate of resources volumes is currently classified as 2P and 2C under the Society of Petroleum Engineers’ Resource Classification System.
- The reference to our U.S. Gulf of Mexico production having among the lowest GHG intensity in the world is a comparison among other IOGP oil-and gas-producing members.
- As communicated at Shell’s Capital Markets Day in 2023, we plan to see production stabilise at 1.4 million barrels per day of liquids to 2030.
Tuesday, 13 August 2024
McDermott Secures EPCI Contract for Gas Project Offshore Trinidad and Tobago
McDermott has been awarded an engineering, procurement, construction, installation (EPCI), hook up and commissioning contract by Shell Trinidad and Tobago Limited for the Manatee gas field development project, located 60 miles (100 kilometers) off the southeast coast of Trinidad and Tobago.
The award follows the successful delivery of the front-end engineering design, detailed engineering and long lead procurement service contracts for the project's initial design and execution planning.
Under the contract scope, McDermott will design, procure, fabricate, hook up and commission a platform and jacket. The company will also provide design, installation, and commissioning services for a 32-inch gas pipeline that will connect the platform to a gas processing facility operated by Shell. The contract scope also includes design, procurement, installation, and testing services for a fiber optic cable.
"This award leverages our unique, integrated EPCI capabilities and legacy of engineering excellence and innovation to successfully deliver large offshore platforms and complex subsea infrastructure worldwide," said Mahesh Swaminathan, McDermott's Senior Vice President, Subsea and Floating Facilities. "The Manatee project builds on our track record of successful project execution for Shell and exemplifies our commitment to building energy infrastructure required to meet demand."
This contract award also demonstrates our continued commitment to working in Trinidad and Tobago to support the future supply of gas to its domestic and export market.
The award follows the successful delivery of the front-end engineering design, detailed engineering and long lead procurement service contracts for the project's initial design and execution planning.
Under the contract scope, McDermott will design, procure, fabricate, hook up and commission a platform and jacket. The company will also provide design, installation, and commissioning services for a 32-inch gas pipeline that will connect the platform to a gas processing facility operated by Shell. The contract scope also includes design, procurement, installation, and testing services for a fiber optic cable.
"This award leverages our unique, integrated EPCI capabilities and legacy of engineering excellence and innovation to successfully deliver large offshore platforms and complex subsea infrastructure worldwide," said Mahesh Swaminathan, McDermott's Senior Vice President, Subsea and Floating Facilities. "The Manatee project builds on our track record of successful project execution for Shell and exemplifies our commitment to building energy infrastructure required to meet demand."
This contract award also demonstrates our continued commitment to working in Trinidad and Tobago to support the future supply of gas to its domestic and export market.
Thursday, 8 August 2024
SBM Offshore awarded FSO contract for Woodside’s Trion development
SBM Offshore is pleased to announce that it has signed a contract with Woodside Petróleo Operaciones de México, S. de R.L. de C.V. (“Woodside”), operator of the Trion deepwater oil field development located in the Perdido Belt of the western Gulf of Mexico. Under this contract, SBM Offshore will construct and thereafter lease to Woodside a Floating Storage and Offloading (“FSO”) unit for a period of 20 years. This award complements the Transportation & Installation contract for the FSO and the FPU awarded to SBM Offshore in 2023.
The new build FSO, based on a Suezmax-type hull, will be equipped with a Disconnectable Turret Mooring (“DTM”) system designed by SBM Offshore. The FSO will be moored in water depth of about 2,500 meters and will be able to store around 950,000 barrels of crude oil.
The Trion field is located 180 km off the Mexican coastline and 30 km south of the US/Mexico maritime border. The Trion project is an alliance between Woodside (60%, Operator) and PEMEX Exploración y Producción (40%, non-Operator).
The new build FSO, based on a Suezmax-type hull, will be equipped with a Disconnectable Turret Mooring (“DTM”) system designed by SBM Offshore. The FSO will be moored in water depth of about 2,500 meters and will be able to store around 950,000 barrels of crude oil.
The Trion field is located 180 km off the Mexican coastline and 30 km south of the US/Mexico maritime border. The Trion project is an alliance between Woodside (60%, Operator) and PEMEX Exploración y Producción (40%, non-Operator).
Tuesday, 6 August 2024
Viaro Energy signs agreement to take over Shell & ExxonMobil’s UK Southern North Sea assets
Viaro Energy (“Viaro”), the independent British energy company operating in the UKCS and the Netherlands North Sea, is pleased to announce that its main operating subsidiary RockRose Energy Limited signed an agreement with Shell U.K. Limited, a subsidiary of Shell plc (“Shell”), and Esso Exploration and Production UK Limited, a subsidiary of ExxonMobil Corporation (“ExxonMobil”), to acquire a full ownership interest in their Shell-operated UK Southern North Sea assets.
Pending regulatory approval, Viaro will acquire a portfolio consisting of 11 operated offshore assets and one exploration field (Shamrock; Caravel; Corvette; Brigantine; Leman; Galleon; Skiff; Carrack Main, Cutter, Carrack East; Barque; and Clipper), all tying back to the Shell-operated onshore Bacton Gas Processing Terminal via the Leman and Clipper fields. In 2023, production was around 28,000 boepd (c. 5% of UK total gas production) and the assets possess strong growth potential through identified near field exploration opportunities.
With a strong record of reliable production and around 90% production efficiency reported, the natural gas fields of the Southern North Sea and the Bacton gas terminal have been part of the UK’s energy foundation for 56 years. The tight gas development ongoing in the Galleon and Barque fields and strong potential for tight gas opportunities and near field exploration already identified in the Greater Sole Pit area are both indicative of the fields’ lasting importance for the UK’s energy security.
Viaro estimates place the 2P volumes of these assets at 58 million barrels of oil equivalent (“boe”), with a projected potential to extract over 120 million boe of net 2C resources. Viaro intends to maximise the economic return of these assets and, by working to ensure the extraction is conducted to reach their fullest potential, to increase low-emissions production of gas in the area through a redevelopment with an existing infrastructure.
The Bacton Gas Processing Terminal provides a direct route for natural gas produced from the Southern and Central North Sea to the UK National Transmission system, operated by the National Grid, enabling gas to flow between the UK and the Netherlands. In recent years, it received the Bacton Rejuvenation Investment of around £300 million to upgrade and extend the life of the terminal for future use. Bacton gas is used to generate around 40% of Britain’s electricity and it constitutes the main supply of gas for East Anglia and North London’s homes and businesses, whose terminal optimisation potential has been recognised by the North Sea Transition Authority (“NSTA”).
With a well-established value chain, the Bacton gas terminal complex also holds immense potential to become an energy transition hub. According to the NSTA, the Bacton terminal is ideally positioned to become a significant hydrogen production site for London and the Southeast, with strong potential to play a role with carbon capture storage and offshore wind developments that can supply renewable power to Bacton. In addition, Viaro intends to conduct feasibility studies on the best ways to decarbonise this asset through the deployment of clean technology.
Francesco Mazzagatti, CEO of Viaro Energy, commented: “We are immensely grateful to the Shell and ExxonMobil teams for an exemplary collaboration on this major deal, which represents a crowning achievement of Viaro’s strategic vision in the North Sea to date. We have long emphasised our commitment to the UKCS North Sea, and while we have certainly encountered more than a few challenges to realise our initial strategy, it is deals like this that make it evident why it is a worthwhile long-term investment.
Shell and ExxonMobil’s Southern North Sea portfolio is not only the backbone of the UK’s energy production and security, but it also represents one of the best strategically placed solutions that have the potential to play an important role in the energy transition. With strong potential for wind farm synergies, electrification of upstream assets, CCS and hydrogen supply, this acquisition fits Viaro’s ongoing and planned activities across the energy sector perfectly.”
Pending regulatory approval, Viaro will acquire a portfolio consisting of 11 operated offshore assets and one exploration field (Shamrock; Caravel; Corvette; Brigantine; Leman; Galleon; Skiff; Carrack Main, Cutter, Carrack East; Barque; and Clipper), all tying back to the Shell-operated onshore Bacton Gas Processing Terminal via the Leman and Clipper fields. In 2023, production was around 28,000 boepd (c. 5% of UK total gas production) and the assets possess strong growth potential through identified near field exploration opportunities.
With a strong record of reliable production and around 90% production efficiency reported, the natural gas fields of the Southern North Sea and the Bacton gas terminal have been part of the UK’s energy foundation for 56 years. The tight gas development ongoing in the Galleon and Barque fields and strong potential for tight gas opportunities and near field exploration already identified in the Greater Sole Pit area are both indicative of the fields’ lasting importance for the UK’s energy security.
Viaro estimates place the 2P volumes of these assets at 58 million barrels of oil equivalent (“boe”), with a projected potential to extract over 120 million boe of net 2C resources. Viaro intends to maximise the economic return of these assets and, by working to ensure the extraction is conducted to reach their fullest potential, to increase low-emissions production of gas in the area through a redevelopment with an existing infrastructure.
The Bacton Gas Processing Terminal provides a direct route for natural gas produced from the Southern and Central North Sea to the UK National Transmission system, operated by the National Grid, enabling gas to flow between the UK and the Netherlands. In recent years, it received the Bacton Rejuvenation Investment of around £300 million to upgrade and extend the life of the terminal for future use. Bacton gas is used to generate around 40% of Britain’s electricity and it constitutes the main supply of gas for East Anglia and North London’s homes and businesses, whose terminal optimisation potential has been recognised by the North Sea Transition Authority (“NSTA”).
With a well-established value chain, the Bacton gas terminal complex also holds immense potential to become an energy transition hub. According to the NSTA, the Bacton terminal is ideally positioned to become a significant hydrogen production site for London and the Southeast, with strong potential to play a role with carbon capture storage and offshore wind developments that can supply renewable power to Bacton. In addition, Viaro intends to conduct feasibility studies on the best ways to decarbonise this asset through the deployment of clean technology.
Francesco Mazzagatti, CEO of Viaro Energy, commented: “We are immensely grateful to the Shell and ExxonMobil teams for an exemplary collaboration on this major deal, which represents a crowning achievement of Viaro’s strategic vision in the North Sea to date. We have long emphasised our commitment to the UKCS North Sea, and while we have certainly encountered more than a few challenges to realise our initial strategy, it is deals like this that make it evident why it is a worthwhile long-term investment.
Shell and ExxonMobil’s Southern North Sea portfolio is not only the backbone of the UK’s energy production and security, but it also represents one of the best strategically placed solutions that have the potential to play an important role in the energy transition. With strong potential for wind farm synergies, electrification of upstream assets, CCS and hydrogen supply, this acquisition fits Viaro’s ongoing and planned activities across the energy sector perfectly.”
Subsea Integration Alliance awarded EPCI contract offshore UK
Subsea7 today announced the award of a sizeable(1) contract by bp to Subsea Integration Alliance(2), for the Murlach development (formerly Skua field), 240 kilometres east of Aberdeen in the UK North Sea.
The project work scope covers the engineering, procurement, construction and installation of the subsea pipelines (SURF) and production systems (SPS). It includes the first deployment of OneSubsea’s standard, configurable, vertical monobore tree systems in the UK North Sea, which will be deployed via vessel to reduce drill rig days. OneSubsea will deliver two vertical monobore trees, a 2-slot manifold, and associated topside controls. The Alliance worked with bp to develop a technology solution leveraging OneSubsea’s field-proven standard equipment, which is simpler to design and quicker to install when compared with traditional configured-to-order subsea systems.
Subsea7 will install eight kilometres of rigid flowline and two flexible jumpers, along with associated subsea infrastructure. The new flowline will be tied-back to the Eastern Trough Area Project (ETAP) facility. Fabrication of the pipelines will take place at Subsea7’s spoolbase at Vigra, Norway and offshore operations are expected to be executed in 2025.
Olivier Blaringhem, Chief Executive Officer of Subsea Integration Alliance said: “This is bp’s third fully integrated EPCI project with Subsea Integration Alliance marking an important milestone as we extend our support to the UK North Sea market.”
Hani El Kurd, Senior Vice President for Subsea7 UK & Global Inspection, Repair and Maintenance, said: “We are delighted to be awarded this contract by bp, as it recognises Subsea Integration Alliance’s global reputation for seamless, full subsea system delivery. Subsea7 has a long relationship with bp and we look forward to supporting their Murlach development.”
The project work scope covers the engineering, procurement, construction and installation of the subsea pipelines (SURF) and production systems (SPS). It includes the first deployment of OneSubsea’s standard, configurable, vertical monobore tree systems in the UK North Sea, which will be deployed via vessel to reduce drill rig days. OneSubsea will deliver two vertical monobore trees, a 2-slot manifold, and associated topside controls. The Alliance worked with bp to develop a technology solution leveraging OneSubsea’s field-proven standard equipment, which is simpler to design and quicker to install when compared with traditional configured-to-order subsea systems.
Subsea7 will install eight kilometres of rigid flowline and two flexible jumpers, along with associated subsea infrastructure. The new flowline will be tied-back to the Eastern Trough Area Project (ETAP) facility. Fabrication of the pipelines will take place at Subsea7’s spoolbase at Vigra, Norway and offshore operations are expected to be executed in 2025.
Olivier Blaringhem, Chief Executive Officer of Subsea Integration Alliance said: “This is bp’s third fully integrated EPCI project with Subsea Integration Alliance marking an important milestone as we extend our support to the UK North Sea market.”
Hani El Kurd, Senior Vice President for Subsea7 UK & Global Inspection, Repair and Maintenance, said: “We are delighted to be awarded this contract by bp, as it recognises Subsea Integration Alliance’s global reputation for seamless, full subsea system delivery. Subsea7 has a long relationship with bp and we look forward to supporting their Murlach development.”
bp gives go-ahead for sixth operated hub, Kaskida, in the US Gulf of Mexico
bp has taken a final investment decision on the Kaskida project in the US Gulf of Mexico. This demonstrates bp’s long-term commitment to deliver secure, affordable and reliable energy.
Kaskida will be bp’s sixth hub in the Gulf of Mexico, featuring a new floating production platform with the capacity to produce 80,000 barrels of crude oil per day from six wells in the first phase. Production is expected to start in 2029.
"Developing Kaskida will unlock the potential of the Paleogene in the Gulf of Mexico for bp, building on our decades of experience in the region," said Gordon Birrell, bp’s executive vice president of production and operations.
"Technology has and will continue to play a pivotal role in propelling Kaskida from discovery to production. Together with the other resources we have in the Paleogene, we expect it to prove to be a world-class development. Today is a critical step in realizing its potential."
Owned 100% by bp, the Kaskida field has discovered recoverable resources currently estimated at around 275 million barrels of oil equivalent from the initial phase. Additional wells could be drilled in future phases, subject to further evaluation.
The project is fully accommodated within bp’s disciplined financial framework, reflecting bp’s drive to focus on value and returns.
Located in the Keathley Canyon area about 250 miles southwest off the coast of New Orleans, the Kaskida project unlocks the potential future development of 10 billion barrels of discovered resources in place across the Kaskida and Tiber catchment areas.
bp plans to leverage existing platform and subsea equipment designs that can be replicated in future projects to drive cost efficiencies across Kaskida’s construction, commissioning and operations.
"By employing an industry-led design solution, Kaskida will be simpler to construct and simpler to operate, enhancing safety and delivering greater value for bp," said Andy Krieger, bp’s senior vice president, Gulf of Mexico and Canada.
Kaskida is in a prime location, with a stable fiscal regime and access to market. It will also be bp’s first development in the Gulf of Mexico to produce from reservoirs that will require well equipment with a pressure rating of up to 20,000 pounds per square inch (20K).
Advancements in 20K drilling technology coupled with updated seismic imaging are enabling bp to safely develop Kaskida and to progress plans to develop other fields such as Tiber, which is expected to advance to a final investment decision next year.
Today’s announcement demonstrates bp’s near-term priorities in action – moving forward a key high-value growth project and supporting its drive to deliver as a simpler, more focused, higher value company.
- bp discovered the Kaskida field in 2006 and has since worked closely with the offshore industry to help develop 20K rig technology necessary to complete high-pressure wells.
- Kaskida, Tiber and nearby discoveries combined have an estimated 10 billion barrels of discovered resources in place.
- bp is one of the leading producers in the Gulf of Mexico with more than 60 years of experience operating in the basin.
- bp operates five platforms in the Gulf of Mexico: Argos, Atlantis, Mad Dog, Na Kika and Thunder Horse.
- bp produced circa 300,000 barrels of oil equivalent per day from the Gulf of Mexico in 2023.
Tuesday, 30 July 2024
Eni: FPSO Petrojarl Kong and FSO Yamoussoukro ready to leave for Côte d'Ivoire for phase 2 of Baleine project
Eni announces that the naming ceremony of the Floating Production, Storage and Offloading Unit (FPSO) Petrojarl Kong and the Floating Storage and Offloading Unit (FSO) Yamoussoukro was held today in Dubai. The two vessels will significantly increase production from the Baleine field, located offshore Côte d'Ivoire, the largest discovery ever made in the country.
The ceremony was attended by Côte d'Ivoire's Minister of Petroleum, Mines and Energy Mamadou Sangafowa Coulibaly, Petroci CEO Fatoumata Sanogo, and Eni's Chief Operating Officer Natural Resources Guido Brusco.
With the christening of the vessels, phase 2 of the Baleine project is now in full swing, in line with the record timing of phase 1. After just 12 months on site in a challenging market environment, the refurbished units are preparing to set sail for the Ivory Coast, where they will be anchored about 50km from the coast, alongside the FPSO Baleine that entered operation in August 2023.
With the startup of Phase 2, scheduled for December 2024, total production from the Baleine field will rise to 60,000 barrels of oil per day and 70 million cubic feet of associated gas (equivalent to 2 million cubic meters of associated gas), significantly increasing current production.
The Baleine project strengthens Côte d'Ivoire's role in the regional and international energy market. In addition, through the adoption of cutting-edge technologies and industry-leading initiatives designed in collaboration with institutions and already underway, it will be the first net zero-emission Upstream (Scope 1 and 2) development on the African continent.
Eni has been operating in Côte d'Ivoire since 2015 where it has an equity production of about 22,000 barrels of oil equivalent per day and participates in six blocks in Ivorian deepwater: CI-101, CI-205, CI-401, CI-501, CI-801 and CI- 802, all with the same partner Petroci Holding. The company is active in the country with initiatives ranging from hydrocarbon production to vegetable oil production for biorefining, as well as projects to improve access to health, education and training, contributing to the country's economic, social and energy development.
The ceremony was attended by Côte d'Ivoire's Minister of Petroleum, Mines and Energy Mamadou Sangafowa Coulibaly, Petroci CEO Fatoumata Sanogo, and Eni's Chief Operating Officer Natural Resources Guido Brusco.
With the christening of the vessels, phase 2 of the Baleine project is now in full swing, in line with the record timing of phase 1. After just 12 months on site in a challenging market environment, the refurbished units are preparing to set sail for the Ivory Coast, where they will be anchored about 50km from the coast, alongside the FPSO Baleine that entered operation in August 2023.
With the startup of Phase 2, scheduled for December 2024, total production from the Baleine field will rise to 60,000 barrels of oil per day and 70 million cubic feet of associated gas (equivalent to 2 million cubic meters of associated gas), significantly increasing current production.
The Baleine project strengthens Côte d'Ivoire's role in the regional and international energy market. In addition, through the adoption of cutting-edge technologies and industry-leading initiatives designed in collaboration with institutions and already underway, it will be the first net zero-emission Upstream (Scope 1 and 2) development on the African continent.
Eni has been operating in Côte d'Ivoire since 2015 where it has an equity production of about 22,000 barrels of oil equivalent per day and participates in six blocks in Ivorian deepwater: CI-101, CI-205, CI-401, CI-501, CI-801 and CI- 802, all with the same partner Petroci Holding. The company is active in the country with initiatives ranging from hydrocarbon production to vegetable oil production for biorefining, as well as projects to improve access to health, education and training, contributing to the country's economic, social and energy development.
Monday, 15 July 2024
First gas achieved at Jerun gas field in Malaysia
The operator of the Jerun field in Malaysia, SapuraOMV Upstream Sdn Bhd, has announced that first gas has been achieved. Shell plc has a 30% equity stake in the field, through its Malaysian subsidiary, Sarawak Shell Berhad, and made a final investment decision on the development in 2021.
The field is located around 160 kilometres (km) north-west of Bintulu in Sarawak, and 190 km north-west of Miri, Sarawak, Malaysia. Comprising an integrated central processing platform, Jerun will export gas through a new 80-km pipeline into the E11RB production hub, for onward delivery to Bintulu based customers including Malaysia LNG. The Jerun platform is designed to produce up to 550 million cubic feet of gas per day, with condensate production of 15,000 barrels per day during peak production.
“Jerun was a highly attractive investment for Shell, building on our interests in this important region off the coast of Sarawak, offshore Malaysia, where Shell operates the Timi platform and has the Rosmari-Marjoram project under construction,” said Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director. “Gas is an important fuel for Malaysia and the world, providing a secure form of energy for heating, cooling and power generation. We are delighted the venture has reached this milestone.”
Shell is proud of its long and successful history in Malaysia. Under the stewardship of Malaysia Petroleum Management, PETRONAS, Shell remains committed to supporting the country’s economic progress and energy transition efforts with competitive and resilient investments.
Jerun is operated by SapuraOMV Upstream (40%) in partnership with Sarawak Shell Berhad (30%) and PETRONAS Carigali Sdn Bhd (30%).
Notes to editors
The Jerun gas field was discovered in 2015, under the SK408 production sharing contract.
On Shell’s Capital Market Day in 2023, Shell committed to deliver upstream and integrated gas projects coming on stream between 2023 to 2025, with a total peak production of greater than 500,000 barrels of oil equivalent per day. Jerun is expected to contribute to this commitment.
The field is located around 160 kilometres (km) north-west of Bintulu in Sarawak, and 190 km north-west of Miri, Sarawak, Malaysia. Comprising an integrated central processing platform, Jerun will export gas through a new 80-km pipeline into the E11RB production hub, for onward delivery to Bintulu based customers including Malaysia LNG. The Jerun platform is designed to produce up to 550 million cubic feet of gas per day, with condensate production of 15,000 barrels per day during peak production.
“Jerun was a highly attractive investment for Shell, building on our interests in this important region off the coast of Sarawak, offshore Malaysia, where Shell operates the Timi platform and has the Rosmari-Marjoram project under construction,” said Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director. “Gas is an important fuel for Malaysia and the world, providing a secure form of energy for heating, cooling and power generation. We are delighted the venture has reached this milestone.”
Shell is proud of its long and successful history in Malaysia. Under the stewardship of Malaysia Petroleum Management, PETRONAS, Shell remains committed to supporting the country’s economic progress and energy transition efforts with competitive and resilient investments.
Jerun is operated by SapuraOMV Upstream (40%) in partnership with Sarawak Shell Berhad (30%) and PETRONAS Carigali Sdn Bhd (30%).
Notes to editors
The Jerun gas field was discovered in 2015, under the SK408 production sharing contract.
On Shell’s Capital Market Day in 2023, Shell committed to deliver upstream and integrated gas projects coming on stream between 2023 to 2025, with a total peak production of greater than 500,000 barrels of oil equivalent per day. Jerun is expected to contribute to this commitment.
Thursday, 11 July 2024
Eni announces a new discovery offshore Mexico
Eni announces a new discovery on the Yopaat-1 EXP exploration well in Block 9, approximately 63 kilometers off the coast in the mid-deep water of the Cuenca Salina in the Sureste Basin, offshore Mexico. The preliminary estimates indicate a discovered potential of around 300-400 million barrels equivalents (Mboe) of oil and associated gas in place.
The well has been drilled in a water depth of 525 meters and reached a total depth of 2,931 meters, finding about 200meter net pay of hydrocarbon bearing sands in the Pliocene and Miocene sequences, subject to an intense subsurface data acquisition campaign.
Block 9 Joint venture consists of Eni as Operator with a 50% participating interest and Repsol with the remaining 50%.
This successful result, alongside the discoveries in Eni-operated Blocks 7 and 10, confirms the value of Eni’s asset portfolio in the Sureste Basin. The overall estimate of resources in place currently exceeds 1.3 billion barrels of oil equivalent (Bboe) which allows Eni to advance with the studies towards a potential future “Hub” development, including the discoveries and other prospects present in the area, in synergy with the infrastructures located nearby.
Eni has been present in Mexico since 2006 and established its wholly owned subsidiary Eni Mexico S. de R. L. de C.V. in 2015. Currently, Eni is the main foreign operator in the country and holds rights in eight exploration and production blocks, of which seven as Operator, in the Sureste Basin in the Gulf of Mexico.
The well has been drilled in a water depth of 525 meters and reached a total depth of 2,931 meters, finding about 200meter net pay of hydrocarbon bearing sands in the Pliocene and Miocene sequences, subject to an intense subsurface data acquisition campaign.
Block 9 Joint venture consists of Eni as Operator with a 50% participating interest and Repsol with the remaining 50%.
This successful result, alongside the discoveries in Eni-operated Blocks 7 and 10, confirms the value of Eni’s asset portfolio in the Sureste Basin. The overall estimate of resources in place currently exceeds 1.3 billion barrels of oil equivalent (Bboe) which allows Eni to advance with the studies towards a potential future “Hub” development, including the discoveries and other prospects present in the area, in synergy with the infrastructures located nearby.
Eni has been present in Mexico since 2006 and established its wholly owned subsidiary Eni Mexico S. de R. L. de C.V. in 2015. Currently, Eni is the main foreign operator in the country and holds rights in eight exploration and production blocks, of which seven as Operator, in the Sureste Basin in the Gulf of Mexico.
Vallourec wins a major order from TotalEnergies in Angola
Following a call for tender, Vallourec, a world leader in premium tubular solutions, announces that it has been awarded a contract by TotalEnergies to supply almost 5,000 tonnes of OCTG solutions and associated services for the Kaminho deepwater project on Block 20, 100 km off the coast of Angola.
On this project, Vallourec will supply its world-renowned range of VAM® connections and use CLEANWELL® , its more environmentally-friendly, dope-free solution. The Group will also provide its offshore expertise via VAM® Field Service as well as its Tubular Management Services (TMS) offering, which involves managing the inspection and preparation of tubes before they leave for the drilling platform, and on their return to the storage area.
The products will be manufactured at Vallourec plants in France, Brazil, and Indonesia, taking advantage of the Group’s strategic premium production hubs.
More broadly in Africa, Vallourec is supporting its customer with a complete range of premium products and services, including its CLEANWELL® solution in Nigeria, Gabon, Congo, and Mozambique.
The Group has also worked with TotalEnergies in its exploration and appraisal campaigns, such as in Namibia, a region with strong development potential, where the Group has already supplied almost 5,000 tonnes of tubes and connections.
Philippe Guillemot, Chairman of the Board of Directors and Chief Executive Officer, commented: “We are proud to support TotalEnergies in its developments and exploration projects. I would like to thank the Vallourec teams for their commitment.”
Wednesday, 10 July 2024
Shell to invest in Ruwais LNG project in Abu Dhabi
Shell Overseas Holdings Limited, a subsidiary of Shell plc (Shell), has signed an agreement to invest in the Abu Dhabi National Oil Company’s (ADNOC) Ruwais liquefied natural gas (LNG) project in Abu Dhabi through a 10% participating interest.
“This investment decision builds on our long-standing partnership with ADNOC," said Shell's Chief Executive Officer Wael Sawan. "In line with our strategy to create more value with less emissions, we are investing in additional LNG capacity and further growing our world-leading LNG portfolio, with energy-efficient and carbon-competitive projects."
The Ruwais LNG project will consist of two 4.8 million metric tonnes per annum (mmtpa) LNG liquefaction trains with a total capacity of 9.6 mmtpa. Shell, through its subsidiary Shell International Trading Middle East Limited FZE, has also signed an agreement to offtake 1 mmtpa of LNG produced by the project. The Ruwais LNG facility is set to have an electric-powered liquefaction system and will utilise access to a renewable power supply. This design supports lower operational emissions compared to traditional gas-powered LNG facilities.
ADNOC will hold a majority 60% share in the project and serve as the lead developer and operator of the facility, while Shell, BP, Mitsui and TotalEnergies will each hold 10%.
ADNOC has awarded an engineering, procurement and construction (EPC) contract to a Technip-led joint venture and will soon start construction in Al Ruwais Industrial City, Abu Dhabi. LNG deliveries are expected to start in 2028.
Notes to editors
The Ruwais LNG project is located some 240 kilometres west of Abu Dhabi, United Arab Emirates.
Shell has a proud history of more than 80 years in the United Arab Emirates. Shell’s current activities with ADNOC include a 15% interest in ADNOC Gas Processing (AGP) with associated technical and manpower support services.
The capital investment related to Shell’s 10% participating interest in the Ruwais LNG project will be absorbed within Shell’s cash capital expenditure guidance, which remains unchanged. The deal is in excess of the internal rate of return (IRR) hurdle rate for Shell’s Integrated Gas business, delivering on its 25-30% growth ambition in liquefaction volumes, relative to 2022, as outlined during the 2023 Capital Markets Day.
Global demand for LNG is estimated to rise by more than 50% by 2040, as industrial coal-to-gas switching gathers pace in China, South Asian and South-east Asian countries. These countries are expected to use more LNG to support their economic growth, according to Shell’s LNG Outlook 2024 (PDF)
.
Shell believes LNG will play a critical role in the energy transition, replacing coal in heavy industry. It also has a continued role in displacing coal in power generation, helping to reduce local air pollution and carbon emissions. LNG helps to provide the flexibility the power system needs, at a time when renewable generation is growing rapidly. Find out more in Shell’s Energy Transition Strategy 2024 (PDF)
.
“This investment decision builds on our long-standing partnership with ADNOC," said Shell's Chief Executive Officer Wael Sawan. "In line with our strategy to create more value with less emissions, we are investing in additional LNG capacity and further growing our world-leading LNG portfolio, with energy-efficient and carbon-competitive projects."
The Ruwais LNG project will consist of two 4.8 million metric tonnes per annum (mmtpa) LNG liquefaction trains with a total capacity of 9.6 mmtpa. Shell, through its subsidiary Shell International Trading Middle East Limited FZE, has also signed an agreement to offtake 1 mmtpa of LNG produced by the project. The Ruwais LNG facility is set to have an electric-powered liquefaction system and will utilise access to a renewable power supply. This design supports lower operational emissions compared to traditional gas-powered LNG facilities.
ADNOC will hold a majority 60% share in the project and serve as the lead developer and operator of the facility, while Shell, BP, Mitsui and TotalEnergies will each hold 10%.
ADNOC has awarded an engineering, procurement and construction (EPC) contract to a Technip-led joint venture and will soon start construction in Al Ruwais Industrial City, Abu Dhabi. LNG deliveries are expected to start in 2028.
Notes to editors
The Ruwais LNG project is located some 240 kilometres west of Abu Dhabi, United Arab Emirates.
Shell has a proud history of more than 80 years in the United Arab Emirates. Shell’s current activities with ADNOC include a 15% interest in ADNOC Gas Processing (AGP) with associated technical and manpower support services.
The capital investment related to Shell’s 10% participating interest in the Ruwais LNG project will be absorbed within Shell’s cash capital expenditure guidance, which remains unchanged. The deal is in excess of the internal rate of return (IRR) hurdle rate for Shell’s Integrated Gas business, delivering on its 25-30% growth ambition in liquefaction volumes, relative to 2022, as outlined during the 2023 Capital Markets Day.
Global demand for LNG is estimated to rise by more than 50% by 2040, as industrial coal-to-gas switching gathers pace in China, South Asian and South-east Asian countries. These countries are expected to use more LNG to support their economic growth, according to Shell’s LNG Outlook 2024 (PDF)
.
Shell believes LNG will play a critical role in the energy transition, replacing coal in heavy industry. It also has a continued role in displacing coal in power generation, helping to reduce local air pollution and carbon emissions. LNG helps to provide the flexibility the power system needs, at a time when renewable generation is growing rapidly. Find out more in Shell’s Energy Transition Strategy 2024 (PDF)
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Equinor starts production from Kristin South
Equinor and its partners Petoro, Vår Energi, and TotalEnergies EP Norge started production from the first Lavrans well in the Kristin South area on 7 July.
The partnership submitted the plan for development and operation (PDO) of the Lavrans and Kristin Q discoveries as satellites to the Kristin field in 2021. This is the first phase of the Kristin South project. The PDO was approved by the authorities in 2022.
“The Kristin South project demonstrates our strategy to create value by developing existing infrastructure on the Norwegian Continental Shelf. Together with our partners and suppliers, we have developed the project and started the production from Lavrans in a safe and good way,” says Trond Bokn, senior vice president for project development in Equinor.
A new subsea template has been installed and tied into the Kristin platform, now processing oil and gas from the first well at the Lavrans field. The gas will be exported through the pipeline system to the European market, while the oil will be transported to the market by ship via the Åsgard C storage vessel.
Four additional wells are planned as part of the first phase of the Kristin South project, three at the Lavrans field and one in the Q-segment at the Kristin field. The latter will be drilled from an existing subsea template that has been tied back to the Kristin SEMI.
The expected production in phase one of the Kristin South project is in the PDO estimated at 6.2 GSm3 of gas and 1.9 MSm3 of oil (a total of 58.2 million barrels of oil equivalent).
“This is a key milestone in our plan to continue to develop new resources in a mature area in the Norwegian Sea. Tying in additional resources to our producing hubs is a cost-efficient way to add production and extend the lifespan of our fields in operation. This approach contributes to energy security and job creation in Norway,” says Grete B. Haaland, senior vice president for Exploration & Production North.
The CO2 intensity for extraction and production of Kristin South phase 1 is very low - less than 1 kg of CO2 per barrel of oil equivalent. The emissions will mainly be generated from the project’s drilling activities.
Norwegian suppliers have been awarded over 60% of the contract values in the development phase creating ripple effects along the coast. The project is estimated to have created 4,000 person-years across Norway, with 800 in the Mid-Norway region, over the 2020-2025 period.
Lavrans was discovered in 1995, while the Kristin field was put on stream in 2005. The technical lifetime of the Kristin platform is currently estimated to be 2043 with potential for further extensions.
Partners (Haltenbanken Vest Unit): Equinor Energy AS (54.82 %, operator), Petoro AS (22.52 %), Vår Energi ASA (16.66 %), TotalEnergies EP Norge AS (6 %).
Contracts:
- Aker Solutions/OneSubsea and subcontractors: Subsea production facilities
- TechnipFMC and subcontractors: Pipeline fabrication, pipelaying, and subsea installation
- Aibel and subcontractors: Engineering, procurement, construction, and installation for Kristin platform modification
- Transocean Spitsbergen: Rig contractor
Shell boosts LNG business with Manatee FID in Trinidad and Tobago
Shell Trinidad and Tobago Ltd. (Shell), a subsidiary of Shell plc, today announced that it has taken Final Investment Decision (FID) on the Manatee project, an undeveloped gas field in the East Coast Marine Area (ECMA) in Trinidad and Tobago.
Manatee will allow Shell to competitively grow its Integrated Gas business by building on development efforts in the ECMA, one of the country’s most prolific gas-producing areas. The ECMA is currently home to Shell’s largest gas-producing fields in the country including Dolphin, Starfish, Bounty and Endeavour.
The Manatee gas field will provide backfill for the country’s Atlantic LNG facility. Increasing utilization at existing LNG plants is an important lever to maximize potential from Shell’s existing assets.
“This project will help meet the increasing demand for natural gas globally while also addressing the energy needs of our customers domestically in Trinidad and Tobago,” said Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director. “The investment bolsters our world-leading LNG portfolio in line with our commitment to invest in competitive projects that deliver more value with less emissions,” she added.
Shell plans to grow its LNG business by 20-30% by 2030, compared with 2022, and LNG liquefaction volumes are planned to grow by 25-30%, relative to 2022, as outlined at Shell’s Capital Markets Day in 2023.
Manatee is slated to start production in 2027. Once online, Manatee is expected to reach peak production of approximately 104,000 barrels of oil equivalent per day (boe/d) (604 MMscf/d).
Notes to editors
Manatee will allow Shell to competitively grow its Integrated Gas business by building on development efforts in the ECMA, one of the country’s most prolific gas-producing areas. The ECMA is currently home to Shell’s largest gas-producing fields in the country including Dolphin, Starfish, Bounty and Endeavour.
The Manatee gas field will provide backfill for the country’s Atlantic LNG facility. Increasing utilization at existing LNG plants is an important lever to maximize potential from Shell’s existing assets.
“This project will help meet the increasing demand for natural gas globally while also addressing the energy needs of our customers domestically in Trinidad and Tobago,” said Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director. “The investment bolsters our world-leading LNG portfolio in line with our commitment to invest in competitive projects that deliver more value with less emissions,” she added.
Shell plans to grow its LNG business by 20-30% by 2030, compared with 2022, and LNG liquefaction volumes are planned to grow by 25-30%, relative to 2022, as outlined at Shell’s Capital Markets Day in 2023.
Manatee is slated to start production in 2027. Once online, Manatee is expected to reach peak production of approximately 104,000 barrels of oil equivalent per day (boe/d) (604 MMscf/d).
Notes to editors
- Shell is the operator of Manatee with a 100% working interest under the sub-Block 6D Production Sharing Contract.
- The Loran-Manatee field was discovered in 1983 and subsequently appraised via four wells. Loran represents the portion of the field in Venezuelan waters and Manatee represents the portion of the field in Trinidad and Tobago waters.
- In 2007 the Government of Trinidad and Tobago (GORTT) and the Government of Venezuela (GOVEN) signed a Framework Treaty covering all cross-border fields and in 2010 signed a Unitization Agreement specifically covering Loran-Manatee.
- In 2019, GORTT and GOVEN terminated the Unitization Agreement and entered into another government-to-government agreement, allowing each country to independently develop its respective share of the Loran-Manatee field.
- The project will involve a Normally Unattended Installation platform located in the ECMA acreage with eight development wells via a 110 km 32” pipeline to the Shell-operated onshore Beachfield gas processing facility, for onward export to the Atlantic LNG facility, and to the National Gas Company of Trinidad and Tobago for the domestic gas market.
- Shell believes LNG will play a critical role in the energy transition, replacing coal in heavy industry. It also has a continued role in displacing coal in power generation, helping to reduce local air pollution and carbon emissions. LNG helps to provide the flexibility the power system needs, at a time when renewable generation is growing rapidly. Find out more in Shell’s Energy Transition Strategy 2024.
- Global demand for LNG is estimated to rise by more than 50% by 2040, as industrial coal-to-gas switching gathers pace in China, South Asian and South-east Asian countries. These countries are expected to use more LNG to support their economic growth, according to Shell’s LNG Outlook 2024.
Monday, 8 July 2024
Wood awarded concept study for Greater Sunrise Development
Wood, a global leader in consulting and engineering,has been selected as the lead specialist consultant for an independent study for the Sunrise Joint Venture’s (SJV) Greater Sunrise Development.
Wood will deliver a comprehensive concept study for the Greater Sunrise Development, considering engineering, technology, financing, commercial structures, fiscal, environmental, health & safety and socioeconomic drivers including local content. The study, on target for completion by no later than Q4 2024, will support the SJV to advance the development to the next stage.
Azad Hessamodini, President of Consulting at Wood, said: “This is an important concept study for the Greater Sunrise Development. We are delighted to support and deliver the work at pace to ensure the SJV has the impartial insights to advance this regionally significant project.”
SJV comprises TIMOR GAP (56.56%), Woodside Energy (33.44% and Operator) and Osaka Gas (10.00%). The development project is located between Timor-Leste and Australia’s Northern Territory and comprises the Sunrise and Troubadour gas and condensate fields.
Wood has completed over 100 LNG feasibility studies globally, providing technical consulting and advisory services at the earliest stages to support clients in making informed and independent decisions.
Wood will deliver a comprehensive concept study for the Greater Sunrise Development, considering engineering, technology, financing, commercial structures, fiscal, environmental, health & safety and socioeconomic drivers including local content. The study, on target for completion by no later than Q4 2024, will support the SJV to advance the development to the next stage.
Azad Hessamodini, President of Consulting at Wood, said: “This is an important concept study for the Greater Sunrise Development. We are delighted to support and deliver the work at pace to ensure the SJV has the impartial insights to advance this regionally significant project.”
SJV comprises TIMOR GAP (56.56%), Woodside Energy (33.44% and Operator) and Osaka Gas (10.00%). The development project is located between Timor-Leste and Australia’s Northern Territory and comprises the Sunrise and Troubadour gas and condensate fields.
Wood has completed over 100 LNG feasibility studies globally, providing technical consulting and advisory services at the earliest stages to support clients in making informed and independent decisions.
Thursday, 4 July 2024
Wood teams up with Rosetti Marino to deliver FEED for North Sea platform
Wood has been selected by EPCI contractor Rosetti Marino to deliver a front-end engineering design (FEED) study for the INEOS Hejre development project in the Danish sector of the North Sea.
Wood has a proud heritage in offshore design, delivery and operations, having engineered over one million tons of topsides facilities globally including support for the majority of facilities in the North Sea. Building on that track record, Wood will deliver the engineering design for the facility as well as support Rosetti Marino to develop the execute phase tender for the project, providing a clear roadmap to project completion.
"Often the greatest success factor for new offshore projects comes down to the quality of execution, which is why we emphasise the importance of coupling innovative solutions with predictable delivery at Wood,” said Simon Harris, Senior Vice President of Oil & Gas and New Energies Europe at Wood.
“Combining Wood’s proven track-record in offshore engineering with Rosetti Marino’s topside EPCI expertise will deliver a fabrication and construction-ready design during the initial stages of the project, ensuring there are no surprises in later phases."
Together Wood and Rosetti Marino will provide INEOS with a cost effective and executable design to help the Hejre Development Project deliver planned first oil in 2027.
Hejre will provide critical energy supply to Europe upon completion. The project includes a greenfield topside installation and brownfield modifications and tie ins to the existing wellhead and processing platforms.
Wood has a proud heritage in offshore design, delivery and operations, having engineered over one million tons of topsides facilities globally including support for the majority of facilities in the North Sea. Building on that track record, Wood will deliver the engineering design for the facility as well as support Rosetti Marino to develop the execute phase tender for the project, providing a clear roadmap to project completion.
"Often the greatest success factor for new offshore projects comes down to the quality of execution, which is why we emphasise the importance of coupling innovative solutions with predictable delivery at Wood,” said Simon Harris, Senior Vice President of Oil & Gas and New Energies Europe at Wood.
“Combining Wood’s proven track-record in offshore engineering with Rosetti Marino’s topside EPCI expertise will deliver a fabrication and construction-ready design during the initial stages of the project, ensuring there are no surprises in later phases."
Together Wood and Rosetti Marino will provide INEOS with a cost effective and executable design to help the Hejre Development Project deliver planned first oil in 2027.
Hejre will provide critical energy supply to Europe upon completion. The project includes a greenfield topside installation and brownfield modifications and tie ins to the existing wellhead and processing platforms.
The Prax Group Signs An Agreement To Acquire TotalEnergies’ Upstream Assets In The West Of Shetland
The Prax Group announces the signing of an agreement to acquire TotalEnergies’ interests in the Greater Laggan Area fields and the onshore Shetland Gas Plant, as well as its interests in several nearby exploration licenses. The transaction is subject to approval from the relevant authorities.
The Greater Laggan Area fields include Laggan, Tormore, Glenlivet, Edradour and Glendronach, located around 140 kilometres west of the Shetland Islands. Current production (for FY 2023) for TotalEnergies’ interests is at about 7,500 barrels of oil equivalent per day, made up of around 90% of gas.
Having acquired Hurricane Energy last year – a UK-based oil and gas exploration and production company with a 100 per cent operated interest in the Lancaster offshore oil field in the West of Shetland basin – this is a major acquisition transaction for the Prax Group, to further develop its E&P portfolio. This acquisition would see TotalEnergies’ interests become integrated within the Prax Group’s existing businesses, as part of the Group’s larger, long-term strategy.
Sanjeev Kumar Soosaipillai, Chairman and CEO of the Prax Group, commented: “With a strong track record of integrating acquisitions and managing assets in the oil and gas value chain, the Prax Group is a long-standing and trusted partner of TotalEnergies. The announcement of the signing of this agreement is the culmination of many months of solid co-operation between our respective companies.
Our strong balance sheet has enabled the Group to execute its growth strategy having successfully completed two major acquisitions last year, and with two other transactions in the pipeline, I am delighted that the Prax Group is able to announce its proposed expansion in West of Shetland, as part of our long-term plan to strengthen our position across the whole oil and gas value chain.
Following a period of consolidation, we now have a clear path to achieve our vision and future-proof our company and are ready to continue implementing our strategy. The acquisition of TotalEnergies’ West of Shetland interests is the beginning of the next exciting chapter in our history.”
Discussing TotalEnergies’ reasoning behind the sale, Jean-Luc Guiziou, Senior Vice President Europe for Exploration & Production at TotalEnergies said: “This transaction is in line with TotalEnergies’ strategy to continuously adapt its portfolio by divesting mature non-core assets. TotalEnergies remains committed to the UK through both its upstream portfolio in the North Sea (Elgin-Franklin, Culzean and Alwyn fields) and its Integrated Power and Renewables portfolio.”
The Greater Laggan Area fields include Laggan, Tormore, Glenlivet, Edradour and Glendronach, located around 140 kilometres west of the Shetland Islands. Current production (for FY 2023) for TotalEnergies’ interests is at about 7,500 barrels of oil equivalent per day, made up of around 90% of gas.
Having acquired Hurricane Energy last year – a UK-based oil and gas exploration and production company with a 100 per cent operated interest in the Lancaster offshore oil field in the West of Shetland basin – this is a major acquisition transaction for the Prax Group, to further develop its E&P portfolio. This acquisition would see TotalEnergies’ interests become integrated within the Prax Group’s existing businesses, as part of the Group’s larger, long-term strategy.
Sanjeev Kumar Soosaipillai, Chairman and CEO of the Prax Group, commented: “With a strong track record of integrating acquisitions and managing assets in the oil and gas value chain, the Prax Group is a long-standing and trusted partner of TotalEnergies. The announcement of the signing of this agreement is the culmination of many months of solid co-operation between our respective companies.
Our strong balance sheet has enabled the Group to execute its growth strategy having successfully completed two major acquisitions last year, and with two other transactions in the pipeline, I am delighted that the Prax Group is able to announce its proposed expansion in West of Shetland, as part of our long-term plan to strengthen our position across the whole oil and gas value chain.
Following a period of consolidation, we now have a clear path to achieve our vision and future-proof our company and are ready to continue implementing our strategy. The acquisition of TotalEnergies’ West of Shetland interests is the beginning of the next exciting chapter in our history.”
Discussing TotalEnergies’ reasoning behind the sale, Jean-Luc Guiziou, Senior Vice President Europe for Exploration & Production at TotalEnergies said: “This transaction is in line with TotalEnergies’ strategy to continuously adapt its portfolio by divesting mature non-core assets. TotalEnergies remains committed to the UK through both its upstream portfolio in the North Sea (Elgin-Franklin, Culzean and Alwyn fields) and its Integrated Power and Renewables portfolio.”
Technip Energies and KPSP sign a long-term services agreement with KPO for the development of the Karachaganak field in Kazakhstan
Technip Energies, through its joint-venture TKJV LLP with KPSP, announces the signing of a long-term services frame agreement with Karachaganak Petroleum Operating B.V. (KPO) for the development of the Karachaganak Field, located in northwest Kazakhstan near Aksai.
This five-year agreement covers a comprehensive range of services, from consulting and concept to detailed engineering, aimed at optimizing and expanding the existing facilities and infrastructure of one of the largest oil and gas condensate fields in the world. The project will be executed through TKJV LLP, Technip Energies’ locally incorporated joint venture established in 2019 to serve the Kazakh market by leveraging its engineering and technology capabilities.
Charles Cessot, SVP of T.EN X Consulting and Products, commented: "We are delighted to strengthen our relationship with KPO through this engagement. The trust placed in us for this project demonstrates our expertise and operational quality for many years in Kazakhstan. This project aligns perfectly with our ambition to provide cutting-edge and efficient consulting services.”
Nour Abou Jaoudé, CEO & Chairman of TKJV LLP, declared: “This is a collaboration for success. We are deeply honored and humbled by the trust that KPO's CEO, Mr. Marco Marsili, and H.E. the Minister of Energy of the Republic of Kazakhstan, Almassadam Satkaliyev, have bestowed upon us. We are fully committed to supporting the localization of complex engineering services as part of the country’s ambitious local content development plans and specially on such an important project for the Kazakh energy sector and economy.”
This five-year agreement covers a comprehensive range of services, from consulting and concept to detailed engineering, aimed at optimizing and expanding the existing facilities and infrastructure of one of the largest oil and gas condensate fields in the world. The project will be executed through TKJV LLP, Technip Energies’ locally incorporated joint venture established in 2019 to serve the Kazakh market by leveraging its engineering and technology capabilities.
Charles Cessot, SVP of T.EN X Consulting and Products, commented: "We are delighted to strengthen our relationship with KPO through this engagement. The trust placed in us for this project demonstrates our expertise and operational quality for many years in Kazakhstan. This project aligns perfectly with our ambition to provide cutting-edge and efficient consulting services.”
Nour Abou Jaoudé, CEO & Chairman of TKJV LLP, declared: “This is a collaboration for success. We are deeply honored and humbled by the trust that KPO's CEO, Mr. Marco Marsili, and H.E. the Minister of Energy of the Republic of Kazakhstan, Almassadam Satkaliyev, have bestowed upon us. We are fully committed to supporting the localization of complex engineering services as part of the country’s ambitious local content development plans and specially on such an important project for the Kazakh energy sector and economy.”
Aramco’s strategic gas expansion progresses with $25bn contract awards
Aramco, one of the world’s leading integrated energy and chemicals companies, has awarded contracts worth more than $25 billion to progress its strategic gas expansion, which targets sales gas production growth of more than 60% by 2030, compared to 2021 levels.
The contracts relate to phase two development of the vast Jafurah unconventional gas field, phase three expansion of Aramco’s Master Gas System, new gas rigs and ongoing capacity maintenance.
Amin H. Nasser, Aramco President & CEO, said: “These contract awards demonstrate our firm belief in the future of gas as an important energy source, as well as a vital feedstock for downstream industries. The scale of our ongoing investment at Jafurah and the expansion of our Master Gas System underscores our intention to further integrate and grow our gas business to meet anticipated rising demand. This complements the diversification of our portfolio, creates new employment opportunities, and supports the Kingdom’s transition towards a lower-emission power grid, in which gas and renewables gradually displace liquids-based power generation. To get where we are today, a lot of hard work, innovation and a strong ‘can do’ spirit has been demonstrated by teams across our vast network of suppliers and service providers, who have joined Aramco on this journey to build and expand our world-class energy infrastructure.”
Contract awards
The Company has awarded 16 contracts, worth a combined total of around $12.4 billion, for phase two development at Jafurah. The work will involve construction of gas compression facilities and associated pipelines, expansion of the Jafurah Gas Plant including construction of gas processing trains, and utilities, sulfur and export facilities. It will also involve construction of the Company’s new Riyas Natural Gas Liquids (NGL) fractionation facilities in Jubail — including NGL fractionation trains, and utilities, storage and export facilities — to process NGL received from Jafurah.
Another 15 lump sum turnkey contracts, worth a combined total of around $8.8 billion, have been awarded to commence the phase three expansion of the Master Gas System, which delivers natural gas to customers across the Kingdom of Saudi Arabia. The expansion, being conducted in collaboration with the Ministry of Energy, will increase the size of the network and raise its total capacity by an additional 3.15 billion standard cubic feet per day (bscfd) by 2028, through the installation of around 4,000km of pipelines and 17 new gas compression trains.
An additional 23 gas rig contracts worth $2.4bn have also been awarded, along with two directional drilling contracts worth $612 million. Meanwhile, 13 well tie-in contracts at Jafurah, worth a total of $1.63bn, have been awarded between December 2022 and May 2024.
Progress at Jafurah
The Jafurah unconventional gas field is estimated to contain 229 trillion standard cubic feet of raw gas and 75 billion Stock Tank Barrels of condensate. Phase one of the Jafurah development program, which commenced in November 2021, is progressing on schedule with initial start-up anticipated in the third quarter of 2025. Aramco expects total overall lifecycle investment at Jafurah to exceed $100 billion and production to reach a sustainable sales gas rate of two billion standard cubic feet per day by 2030, in addition to significant volumes of ethane, NGL and condensate.
Master Gas System expansion
Aramco’s Master Gas System is an extensive network of pipelines that connects Aramco’s key gas production and processing sites throughout the Kingdom of Saudi Arabia. Its expansion will increase access to domestic gas supplies for customers in the industrial, utility and other sectors — providing a lower greenhouse gas emission alternative to oil for power generation. From 1982, the network transported associated gas, also known as “waste gas” released during oil production, instead of being flared — illustrating Aramco’s innovation and early adoption of solutions that help mitigate emissions. This pioneering network, which now transports associated gas and sales gas, has helped Aramco achieve near-zero routine gas flaring and maintain a flare volume of less than 1% of total raw gas production since 2012, contributing to the Company having one of the lowest upstream carbon intensities in the industry.
The contracts relate to phase two development of the vast Jafurah unconventional gas field, phase three expansion of Aramco’s Master Gas System, new gas rigs and ongoing capacity maintenance.
Amin H. Nasser, Aramco President & CEO, said: “These contract awards demonstrate our firm belief in the future of gas as an important energy source, as well as a vital feedstock for downstream industries. The scale of our ongoing investment at Jafurah and the expansion of our Master Gas System underscores our intention to further integrate and grow our gas business to meet anticipated rising demand. This complements the diversification of our portfolio, creates new employment opportunities, and supports the Kingdom’s transition towards a lower-emission power grid, in which gas and renewables gradually displace liquids-based power generation. To get where we are today, a lot of hard work, innovation and a strong ‘can do’ spirit has been demonstrated by teams across our vast network of suppliers and service providers, who have joined Aramco on this journey to build and expand our world-class energy infrastructure.”
Contract awards
The Company has awarded 16 contracts, worth a combined total of around $12.4 billion, for phase two development at Jafurah. The work will involve construction of gas compression facilities and associated pipelines, expansion of the Jafurah Gas Plant including construction of gas processing trains, and utilities, sulfur and export facilities. It will also involve construction of the Company’s new Riyas Natural Gas Liquids (NGL) fractionation facilities in Jubail — including NGL fractionation trains, and utilities, storage and export facilities — to process NGL received from Jafurah.
Another 15 lump sum turnkey contracts, worth a combined total of around $8.8 billion, have been awarded to commence the phase three expansion of the Master Gas System, which delivers natural gas to customers across the Kingdom of Saudi Arabia. The expansion, being conducted in collaboration with the Ministry of Energy, will increase the size of the network and raise its total capacity by an additional 3.15 billion standard cubic feet per day (bscfd) by 2028, through the installation of around 4,000km of pipelines and 17 new gas compression trains.
An additional 23 gas rig contracts worth $2.4bn have also been awarded, along with two directional drilling contracts worth $612 million. Meanwhile, 13 well tie-in contracts at Jafurah, worth a total of $1.63bn, have been awarded between December 2022 and May 2024.
Progress at Jafurah
The Jafurah unconventional gas field is estimated to contain 229 trillion standard cubic feet of raw gas and 75 billion Stock Tank Barrels of condensate. Phase one of the Jafurah development program, which commenced in November 2021, is progressing on schedule with initial start-up anticipated in the third quarter of 2025. Aramco expects total overall lifecycle investment at Jafurah to exceed $100 billion and production to reach a sustainable sales gas rate of two billion standard cubic feet per day by 2030, in addition to significant volumes of ethane, NGL and condensate.
Master Gas System expansion
Aramco’s Master Gas System is an extensive network of pipelines that connects Aramco’s key gas production and processing sites throughout the Kingdom of Saudi Arabia. Its expansion will increase access to domestic gas supplies for customers in the industrial, utility and other sectors — providing a lower greenhouse gas emission alternative to oil for power generation. From 1982, the network transported associated gas, also known as “waste gas” released during oil production, instead of being flared — illustrating Aramco’s innovation and early adoption of solutions that help mitigate emissions. This pioneering network, which now transports associated gas and sales gas, has helped Aramco achieve near-zero routine gas flaring and maintain a flare volume of less than 1% of total raw gas production since 2012, contributing to the Company having one of the lowest upstream carbon intensities in the industry.
Sunday, 23 June 2024
Strategic sale of Egypt, Italy and Croatia portfolio
Energean plc (LSE: ENOG, TASE: אנאג (is pleased to announce that it has entered into a binding agreement for the sale of its portfolio in Egypt, Italy and Croatia to an entity controlled by Carlyle International Energy Partners (“Carlyle”) for an enterprise value (“EV”) of up to $945 million, of which $820 million is firm (the “Transaction”). Completion is expected by year-end 2024, subject to customary regulatory and antitrust approvals.
Energean assets being sold include:
Monday, 17 June 2024
Subsea7 awarded a contract for the Bittern field in the UK North Sea.
Subsea7 today announced the award of a sizeable1 contract by Dana Petroleum (E&P) Limited, for the Bittern field development, located approximately 190km east of Aberdeen in the UK Central North Sea, at a water depth of 90 metres.
The contract scope includes project management, engineering, procurement, construction and installation (EPCI) of a 22km 12” water injection pipeline. Subsea7’s scope also includes associated subsea structures and tie-ins at the Triton Floating Production Storage & Offloading (FPSO) vessel and the Bittern field.
Project management and engineering work will commence immediately in Aberdeen. The offshore activities are scheduled for Q3 2025.
Steve Wisely, Senior Vice President of UK and Global Inspection, Repair and Maintenance, Subsea7, said: "We are pleased that Dana Petroleum has chosen Subsea7 to provide project management expertise and engineering technical knowledge for this important field development. We look forward to supporting Dana in meeting their project objectives and for the opportunity to play a key role in the safe and successful completion of Bittern."
The contract scope includes project management, engineering, procurement, construction and installation (EPCI) of a 22km 12” water injection pipeline. Subsea7’s scope also includes associated subsea structures and tie-ins at the Triton Floating Production Storage & Offloading (FPSO) vessel and the Bittern field.
Project management and engineering work will commence immediately in Aberdeen. The offshore activities are scheduled for Q3 2025.
Steve Wisely, Senior Vice President of UK and Global Inspection, Repair and Maintenance, Subsea7, said: "We are pleased that Dana Petroleum has chosen Subsea7 to provide project management expertise and engineering technical knowledge for this important field development. We look forward to supporting Dana in meeting their project objectives and for the opportunity to play a key role in the safe and successful completion of Bittern."
Woodside Achieves First Oil at Sangomar In Senegal
Woodside has achieved first oil from the Sangomar field offshore Senegal, marking the safe delivery of the country’s first offshore oil project.
The Sangomar Field Development Phase 1 is a deepwater project including a stand-alone floating production storage and offloading (FPSO) facility with a nameplate capacity of 100,000 barrels/day, and subsea infrastructure that is designed to allow subsequent development phases.
The Sangomar Field Development Phase 1 is a deepwater project including a stand-alone floating production storage and offloading (FPSO) facility with a nameplate capacity of 100,000 barrels/day, and subsea infrastructure that is designed to allow subsequent development phases.
“This is an historic day for Senegal and for Woodside,” said Woodside CEO Meg O’Neill. “First oil from the Sangomar field is a key milestone and reflects delivery against our strategy. The Sangomar project is expected to generate shareholder value within the terms of the production sharing contract.
“Delivering Senegal’s first offshore oil project safely, through a period of unprecedented global challenge, demonstrates Woodside’s world-class project execution capability.
We are proud of the relationships we have formed with PETROSEN, the Government of Senegal and our key international and local contractors to develop this nationally significant resource.”
General Manager of PETROSEN E&P Thierno Ly said he was pleased to reach this milestone.
“First oil from the Sangomar field marks a new era not only for our country's industry and economy, but most importantly for our people. “This achievement is the result of the unwavering commitment of our teams, who have worked diligently to overcome challenges and meet our strategic objectives in a complex and demanding environment. We have never been so well positioned for opportunities for growth, innovation, and success in the economic and social development of our nation.
About Sangomar Field Development Phase 1
The Sangomar Field Development Phase 1 features the Léopold Sédar Senghor FPSO, named after the first president of Senegal, which is moored approximately 100 kilometres offshore Senegal. The vessel has a storage capacity of 1,300,000 barrels.
About Sangomar Field Development Phase 1
The Sangomar Field Development Phase 1 features the Léopold Sédar Senghor FPSO, named after the first president of Senegal, which is moored approximately 100 kilometres offshore Senegal. The vessel has a storage capacity of 1,300,000 barrels.
The Phase 1 development includes 23 wells (11 production wells, 10 water injection wells and 2 gas injection wells). 21 of the 23 wells have been drilled and completed including 9 production wells. The RSSD joint venture has also approved a 24th well (production well) that will be completed in the current campaign.
The Sangomar Project is being progressed by the Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore (RSSD) joint venture, comprising Woodside (Operator and 82% participating interest) and Societé des Petroles du Sénégal (PETROSEN) (18% participating interest).
The Sangomar Field Development Phase 1 project cost estimate remains within the provided range of US$4.9-$5.2 billion. The drilling campaign at Sangomar is ongoing and Woodside expects to continue commissioning activities and safely ramping up production through 2024.
Crude quality is expected to be ~31 degrees API which is in demand in European and Asian markets.
Woodside’s historical acquisition of participating interests in the RSSD joint venture from both Capricorn Energy and FAR included certain contingent payments. Given current timing of first oil and oil prices Woodside anticipates making both these payments. The final payments are subject to ongoing production performance and oil price.
Thursday, 6 June 2024
Suriname: TotalEnergies, APA Corporation and Staatsolie progress towards Final Investment Decision on Block 58
On the occasion of the 2024 Suriname Energy Oil and Gas Summit, Javier Rielo, Senior Vice President Americas, Exploration & Production for TotalEnergies, and Annand Jagesar, CEO of Staatsolie Maatschappij Suriname N.V, the Suriname National Oil Company, announced several significant steps towards the Final Investment Decision (FID) of the development of offshore Block 58. This decision is expected in the fourth quarter of 2024, for a production start-up in 2028.
TotalEnergies is the operator of Block 58 with a 50% interest, alongside APA Corporation (50%). Staatsolie has the option to enter the development project with up to 20% interest upon FID.
Engineering studies (FEED) are progressing for the development of the Sapakara and Krabdagu fields, with combined recoverable resources estimated above 700 million barrels thanks to the integration of Water Alternating Gas (WAG) injection technology to maximize recovery. Ocean Bottom Node (OBN) seismic technology will also play a key role in maximizing resources and the placement of the development wells, as well as identifying resource upsides. A first OBN campaign covering 900 km2 will be carried out in second half of 2024.
Some key milestones have been recently reached in the path towards FID. An agreement was concluded between Staatsolie and TotalEnergies on the field development area, maximizing the value for Suriname and the Block 58 co-venturers over the 25 years Production Period. In addition, the hull for the 200,000 barrels of oil per day (bopd) Floating Production Storage and Offloading (FPSO) unit has been secured.
TotalEnergies is committed to developing this project responsibly using the best technologies to minimize greenhouse gas emissions. In particular, the facilities will be designed for zero routine flaring, with all associated gas reinjected into the reservoirs. During the development and production phases, TotalEnergies will work closely with Staatsolie to enhance local content, as already demonstrated during the exploration and appraisal phases, with over 80 people trained for logistics operations in Paramaribo.
“We are glad to progress together with Staatsolie and APA towards the FID of Block 58, which will be the next milestone in the partnership between Suriname and TotalEnergies. Our Company is deploying advanced technologies to minimize the environmental impact and maximize resource recovery, while focusing on ensuring economic benefits for the country,” said Javier Rielo, Senior Vice President Americas, Exploration & Production at TotalEnergies.
“Staatsolie is happy to progress towards the development of this project with a world-renowned partner in such a way that Suriname optimally benefits not only from large financial streams but as well from a design and execution that will safeguard safe and clean operations,” said Annand Jagesar, CEO of Staatsolie.
TotalEnergies is the operator of Block 58 with a 50% interest, alongside APA Corporation (50%). Staatsolie has the option to enter the development project with up to 20% interest upon FID.
Engineering studies (FEED) are progressing for the development of the Sapakara and Krabdagu fields, with combined recoverable resources estimated above 700 million barrels thanks to the integration of Water Alternating Gas (WAG) injection technology to maximize recovery. Ocean Bottom Node (OBN) seismic technology will also play a key role in maximizing resources and the placement of the development wells, as well as identifying resource upsides. A first OBN campaign covering 900 km2 will be carried out in second half of 2024.
Some key milestones have been recently reached in the path towards FID. An agreement was concluded between Staatsolie and TotalEnergies on the field development area, maximizing the value for Suriname and the Block 58 co-venturers over the 25 years Production Period. In addition, the hull for the 200,000 barrels of oil per day (bopd) Floating Production Storage and Offloading (FPSO) unit has been secured.
TotalEnergies is committed to developing this project responsibly using the best technologies to minimize greenhouse gas emissions. In particular, the facilities will be designed for zero routine flaring, with all associated gas reinjected into the reservoirs. During the development and production phases, TotalEnergies will work closely with Staatsolie to enhance local content, as already demonstrated during the exploration and appraisal phases, with over 80 people trained for logistics operations in Paramaribo.
“We are glad to progress together with Staatsolie and APA towards the FID of Block 58, which will be the next milestone in the partnership between Suriname and TotalEnergies. Our Company is deploying advanced technologies to minimize the environmental impact and maximize resource recovery, while focusing on ensuring economic benefits for the country,” said Javier Rielo, Senior Vice President Americas, Exploration & Production at TotalEnergies.
“Staatsolie is happy to progress towards the development of this project with a world-renowned partner in such a way that Suriname optimally benefits not only from large financial streams but as well from a design and execution that will safeguard safe and clean operations,” said Annand Jagesar, CEO of Staatsolie.
GTA LNG project reaches significant milestone with arrival of FPSO vessel
The floating production storage and offloading (FPSO) vessel, a key component of the Greater Tortue Ahmeyim (GTA) Phase 1 LNG development, has arrived at its final location offshore on the maritime border of Mauritania and Senegal.
The FPSO vessel is currently being moored at the site 40km offshore in a water depth of 120m. It will be operated by bp, on behalf of the project’s partners: bp, Kosmos Energy, PETROSEN and SMH. The project will produce gas from reservoirs in deep water, approximately 120km offshore, through a subsea system.
Following completion of its construction at the COSCO Qidong Shipyard, China, the FPSO has travelled more than 12,000 nautical miles to the GTA site.
Dave Campbell, bp’s senior vice president, Mauritania and Senegal said: “bp is investing in today’s energy system - and tomorrow’s too, and GTA Phase 1 represents this investment in action.
“And this is a huge landmark step for the project, an innovative LNG development that is leading the way in unlocking gas resources for Mauritania and Senegal. The FPSO vessel has travelled halfway around the globe and its safe arrival and installation is testament to the resilience, skills, teamwork and huge effort of all the partners involved. We are now entirely focused on safe completion of the project as we continue to work towards first gas.”
The GTA Phase 1 development is expected to produce around 2.3 million tonnes of LNG annually for more than 20 years. It is the first gas development in this new basin offshore Mauritania and Senegal. With wells located in water depths of up to 2,850m, the GTA Phase 1 development has the deepest subsea infrastructure in Africa. The multibillion-dollar investment has been granted the status of National Project of Strategic Importance by the Presidents of both Mauritania and Senegal.
The FPSO will have up to 140 people on board during normal operation. With an area equivalent to two football fields and 10-storeys in height, the FPSO is made of more than 81,000 tonnes of steel, 37,000m of pipe spools and 1.52 million meters of cable.
The FPSO is expected to process over 500 million standard cubic feet of gas per day. It will remove water, condensate and impurities from the gas before transferring it via pipeline to the Floating Liquified Natural Gas (FLNG) vessel at the Hub Terminal approximately 10km offshore. At the FLNG vessel, the gas will be cryogenically cooled, liquefied and stored before being transferred to LNG carriers for export, while some is allocated to help meet growing demand in the two host countries.
The FPSO vessel is currently being moored at the site 40km offshore in a water depth of 120m. It will be operated by bp, on behalf of the project’s partners: bp, Kosmos Energy, PETROSEN and SMH. The project will produce gas from reservoirs in deep water, approximately 120km offshore, through a subsea system.
Following completion of its construction at the COSCO Qidong Shipyard, China, the FPSO has travelled more than 12,000 nautical miles to the GTA site.
Dave Campbell, bp’s senior vice president, Mauritania and Senegal said: “bp is investing in today’s energy system - and tomorrow’s too, and GTA Phase 1 represents this investment in action.
“And this is a huge landmark step for the project, an innovative LNG development that is leading the way in unlocking gas resources for Mauritania and Senegal. The FPSO vessel has travelled halfway around the globe and its safe arrival and installation is testament to the resilience, skills, teamwork and huge effort of all the partners involved. We are now entirely focused on safe completion of the project as we continue to work towards first gas.”
The GTA Phase 1 development is expected to produce around 2.3 million tonnes of LNG annually for more than 20 years. It is the first gas development in this new basin offshore Mauritania and Senegal. With wells located in water depths of up to 2,850m, the GTA Phase 1 development has the deepest subsea infrastructure in Africa. The multibillion-dollar investment has been granted the status of National Project of Strategic Importance by the Presidents of both Mauritania and Senegal.
The FPSO will have up to 140 people on board during normal operation. With an area equivalent to two football fields and 10-storeys in height, the FPSO is made of more than 81,000 tonnes of steel, 37,000m of pipe spools and 1.52 million meters of cable.
The FPSO is expected to process over 500 million standard cubic feet of gas per day. It will remove water, condensate and impurities from the gas before transferring it via pipeline to the Floating Liquified Natural Gas (FLNG) vessel at the Hub Terminal approximately 10km offshore. At the FLNG vessel, the gas will be cryogenically cooled, liquefied and stored before being transferred to LNG carriers for export, while some is allocated to help meet growing demand in the two host countries.
Seatrium Awarded Letter of Intent for a Deepwater New-build Production Unit in the US Gulf of Mexico
Seatrium Limited (Seatrium, or the Group) is pleased to announce that it has been awarded a Letter of Intent (LOI) by BP Exploration & Production Inc. (bp) to provide services to carry out certain early engineering works pending the finalisation of a definitive contract for engineering, procurement, construction and commissioning work for bp’s Kaskida Floating Production Unit (FPU) project in the US Gulf of Mexico.
The Kaskida project is a greenfield development located approximately 250 miles southwest of New Orleans, in the Keathley Canyon area of the Gulf of Mexico. Comprising a single topside module supported by a four-column semi-submersible hull, the Kaskida FPU is supported by subsea production wells located in a water depth of approximately 6,000 feet.
The EPC contract award is subject to mutually agreed terms and conditions and management approval, and the final investment decision by bp.
Mr William Gu, Executive Vice President, Oil & Gas (International) of Seatrium, said, “We are pleased to secure the Letter of Intent with bp for the Kaskida development. This award reflects our expertise and successful track record of delivering complex FPUs. Over the years, Seatrium has established itself as the market leader in EPC projects for FPUs. We look forward to the opportunity to contribute to the success of the Kaskida project."
The LOI is not expected to have any material impact on the net tangible assets and earnings per share of the Group for the financial year ending 31 December 2024.
ADNOC Awards 3% Interest in SARB and Umm Lulu Concession to SOCAR
ADNOC announced today it has signed an agreement to award a 3% participating interest in the SARB and Umm Lulu offshore concession to SOCAR. This award builds on the strategic energy partnership between the United Arab Emirates (UAE) and Azerbaijan and deepens ADNOC’s growing partnership with SOCAR across the energy value chain.
The SARB and Umm Lulu concession deploys cutting-edge digitalization and AI technologies for remote monitoring, smart well operations and production management to optimize production efficiency, reduce emissions, enhance safety and increase production capacity.
Abdulmunim Saif Al Kindy, ADNOC Upstream Executive Director, said: "We are very pleased to welcome SOCAR to the SARB and Umm Lulu concession. This award supports ADNOC’s strategy to leverage strategic partnerships and advanced technologies to maximize value from Abu Dhabi’s energy resources to ensure a secure, reliable and responsible supply of energy.”
This agreement builds upon previous collaborations between the two companies, including ADNOC's acquisition of a 30% equity stake in Absheron gas and condensate field in the Caspian Sea and a Strategic Collaboration Agreement on the potential development of low carbon energy technologies, including hydrogen and geothermal.
Rovshan Najaf, President of SOCAR said: “This is our first international upstream investment and we are particularly delighted to make this investment in Abu Dhabi, building upon our bilateral strategic relationships. We are committed to advance our energy partnership with ADNOC even further and continue cooperating in many more projects of mutual interest."
Both fields at the SARB and Umm Lulu concession use Intelligent Well Surveillance (IWS) technology, allowing them to operate wells at an optimum rate to drive operational efficiency.
The SARB and Umm Lulu concession deploys cutting-edge digitalization and AI technologies for remote monitoring, smart well operations and production management to optimize production efficiency, reduce emissions, enhance safety and increase production capacity.
Abdulmunim Saif Al Kindy, ADNOC Upstream Executive Director, said: "We are very pleased to welcome SOCAR to the SARB and Umm Lulu concession. This award supports ADNOC’s strategy to leverage strategic partnerships and advanced technologies to maximize value from Abu Dhabi’s energy resources to ensure a secure, reliable and responsible supply of energy.”
This agreement builds upon previous collaborations between the two companies, including ADNOC's acquisition of a 30% equity stake in Absheron gas and condensate field in the Caspian Sea and a Strategic Collaboration Agreement on the potential development of low carbon energy technologies, including hydrogen and geothermal.
Rovshan Najaf, President of SOCAR said: “This is our first international upstream investment and we are particularly delighted to make this investment in Abu Dhabi, building upon our bilateral strategic relationships. We are committed to advance our energy partnership with ADNOC even further and continue cooperating in many more projects of mutual interest."
Both fields at the SARB and Umm Lulu concession use Intelligent Well Surveillance (IWS) technology, allowing them to operate wells at an optimum rate to drive operational efficiency.
Friday, 31 May 2024
Subsea7 awarded ‘super-major’ contract offshore Brazil
Subsea7 announce the award of a super-major contract by Petrobras, after winning a competitive tender, for the development of the Búzios 9 field located approximately 180 kilometres off the coast of the state of Rio de Janeiro, Brazil, at 2,000 metres water depth in the pre-salt Santos basin.
The contract scope includes engineering, procurement, fabrication, installation, and pre-commissioning of 102 kilometres of rigid risers and flowlines for the steel lazy wave production system.
Project management and engineering will commence immediately at Subsea7’s offices in Rio de Janeiro and Paris. Fabrication of the pipelines will take place at Subsea7’s spoolbase at Ubu in the state of Espirito Santo, Brazil, and offshore operations are scheduled to be executed in 2026 and 2027.
Yann Cottart, Vice-President Brazil said: “This new award strengthens our diverse portfolio of projects in Brazil and affirms our position as a trusted contractor of Petrobras. Subsea7 looks forward to continuing this strong, collaborative relationship as we work together to successfully deliver the Búzios 9 project.”
The contract scope includes engineering, procurement, fabrication, installation, and pre-commissioning of 102 kilometres of rigid risers and flowlines for the steel lazy wave production system.
Project management and engineering will commence immediately at Subsea7’s offices in Rio de Janeiro and Paris. Fabrication of the pipelines will take place at Subsea7’s spoolbase at Ubu in the state of Espirito Santo, Brazil, and offshore operations are scheduled to be executed in 2026 and 2027.
Yann Cottart, Vice-President Brazil said: “This new award strengthens our diverse portfolio of projects in Brazil and affirms our position as a trusted contractor of Petrobras. Subsea7 looks forward to continuing this strong, collaborative relationship as we work together to successfully deliver the Búzios 9 project.”
Tuesday, 28 May 2024
Subsea7 awarded a contract for the Belinda field in the UK North Sea
Subsea7 today announced the award of a sizeable contract by Serica Energy, for the Belinda field development south-east of the Triton FPSO. The Belinda field is operated by Serica Energy and located approximately 190 kilometres east of Aberdeen in the UK Central North Sea, with a water depth of 95 metres.
The contract scope includes project management, engineering, procurement, construction and installation (EPCI) of a 5-kilometre 8” production pipeline with a 3” piggy-backed gas lift line and an electro-hydraulic controls (EHC) umbilical. Subsea7’s scope also includes associated subsea structures and tie-ins to the Triton Floating Production Storage & Offloading (FPSO) vessel operated by Dana Petroleum, via an existing production manifold near the Triton riser base and for controls at the Evelyn valve skid.
Project management and engineering work will commence immediately in Aberdeen. The offshore activities are scheduled for Q3 2025.
Steve Wisely, Senior Vice President of UK and Global Inspection, Repair and Maintenance, Subsea7, said: “We are pleased to have this opportunity to supply Serica Energy with EPCI knowledge and demonstrate the extensive North Sea expertise we have amassed over 50 years. We look forward to supporting the safe, efficient and timely execution of this project.”
The contract scope includes project management, engineering, procurement, construction and installation (EPCI) of a 5-kilometre 8” production pipeline with a 3” piggy-backed gas lift line and an electro-hydraulic controls (EHC) umbilical. Subsea7’s scope also includes associated subsea structures and tie-ins to the Triton Floating Production Storage & Offloading (FPSO) vessel operated by Dana Petroleum, via an existing production manifold near the Triton riser base and for controls at the Evelyn valve skid.
Project management and engineering work will commence immediately in Aberdeen. The offshore activities are scheduled for Q3 2025.
Steve Wisely, Senior Vice President of UK and Global Inspection, Repair and Maintenance, Subsea7, said: “We are pleased to have this opportunity to supply Serica Energy with EPCI knowledge and demonstrate the extensive North Sea expertise we have amassed over 50 years. We look forward to supporting the safe, efficient and timely execution of this project.”
Monday, 27 May 2024
Seatrium Secures FPSO Newbuild Contracts P-84 And P-85 From Petrobras
Seatrium Limited (Seatrium, or the Group), a global provider of engineering solutions to the offshore, marine, and energy industries, has won an international tender from Brazil’s National Oil Company, Petróleo Brasileiro S.A. (Petrobras), acting as operator of Atapu1 and Sepia2 consortiums, for the newbuild supply of Floating Production Storage and Offloading vessels (FPSO) platforms P-84 and P-85. With the contracts valued at approximately S$11 billion, these high throughput FPSOs will be deployed in the Atapu and Sépia fields, located in the eastern part of the Santos Basin, approximately 200 kilometres offshore of Rio de Janeiro in Brazil.
The P-84 and P-85 platforms are part of Petrobras' new generation of FPSO platforms, characterised by a high production capacity that prioritise sustainable practices with innovative technologies. The P-84 and P-85 FPSOs will each have a production capacity of 225,000 barrels of oil per day (bopd) and gas processing capacity of 10 million cubic meters per day (Sm3 /d). Both FPSOs will incorporate advanced technologies such as zero routine flaring and venting, variable speed drives and measures to control emissions and capture CO2, including an all-electric concept, which focuses on efficient power generation and increased energy efficiency to achieve a 30% reduction in greenhouse gas emissions intensity. These features will enhance operational efficiency and reduce environmental impact, showcasing Seatrium's commitment to responsible and sustainable operations.
Construction for the P-84 and P-85 FPSOs will commence in first quarter of 2025 with the final delivery expected to be in 2029.
Supply of the FPSO platforms will leverage the Group’s “One Seatrium Delivery Model”, where operations and engineering support are integrated across different yards globally. Seatrium’s facilities in Brazil, China, and Singapore will manufacture the modules, weighing an impressive 60,000 metric tonnes, with the outsourced hull and accommodation transported to Singapore for topside module integration and commissioning. After successful integration and commissioning in Singapore, the FPSO platforms will be towed to the Atapu and Sépia fields for offshore commissioning.
Qatarenergy Announces FID In the Second Development Phase For Brazil’s Sépia Field
QatarEnergy announces that the consortium partners in the Sepia joint venture have taken the final investment decision (FID) for the second development phase of the Sépia field, located in the prolific pre-salt Santos Basin, offshore Brazil.
The Sepia joint venture is a partnership between QatarEnergy, TotalEnergies, Petronas, Petrogal Brazil, and Petrobras (the operator).
The FID was marked by the signing of a contract with Seatrium O&G Americas Limited to construct a floating production storage and offloading (FPSO) unit to operate in the ultra-deep waters of the Sepia field. The FPSO will have a crude oil production capacity of 225,000 barrels of oil per day, and a gas processing capacity of ten million cubic meters per day.
His Excellency Mr. Saad Sherida Al-Kaabi, the Minister of State for Energy Affairs, the President and CEO of QatarEnergy, welcomed the award of the contract as an important landmark in QatarEnergy’s activities in Brazil.
The FPSO is expected to result in reducing greenhouse gas emission intensity per barrel of oil equivalent by 30%. The reduction is due to the benefits of an all-electric configuration and optimizations in the processing plant to increase energy efficiency. The FPSO also incorporates several environmental technologies, such as: zero routine ventilation (recovery of ventilated gases from cargo tanks and the processing), deep seawater capture, use of speed variators in pumps and compressors, cogeneration (Waste Heat Recovery Unit), routine zero burning (torch gas recovery – closed flare), valves with requirements for low fugitive emissions and the capture, use and geological storage of CO2 from the gas produced.
The FPSO’s construction will be carried out in shipyards in Brazil, China, and Singapore. It will be the second FPSO in the Sepia field (in addition to the already operating Carioca FPSO) and will target the northern part of the Sépia field.
The Sepia joint venture is a partnership between QatarEnergy, TotalEnergies, Petronas, Petrogal Brazil, and Petrobras (the operator).
The FID was marked by the signing of a contract with Seatrium O&G Americas Limited to construct a floating production storage and offloading (FPSO) unit to operate in the ultra-deep waters of the Sepia field. The FPSO will have a crude oil production capacity of 225,000 barrels of oil per day, and a gas processing capacity of ten million cubic meters per day.
His Excellency Mr. Saad Sherida Al-Kaabi, the Minister of State for Energy Affairs, the President and CEO of QatarEnergy, welcomed the award of the contract as an important landmark in QatarEnergy’s activities in Brazil.
The FPSO is expected to result in reducing greenhouse gas emission intensity per barrel of oil equivalent by 30%. The reduction is due to the benefits of an all-electric configuration and optimizations in the processing plant to increase energy efficiency. The FPSO also incorporates several environmental technologies, such as: zero routine ventilation (recovery of ventilated gases from cargo tanks and the processing), deep seawater capture, use of speed variators in pumps and compressors, cogeneration (Waste Heat Recovery Unit), routine zero burning (torch gas recovery – closed flare), valves with requirements for low fugitive emissions and the capture, use and geological storage of CO2 from the gas produced.
The FPSO’s construction will be carried out in shipyards in Brazil, China, and Singapore. It will be the second FPSO in the Sepia field (in addition to the already operating Carioca FPSO) and will target the northern part of the Sépia field.
Friday, 24 May 2024
Consortium led by Tecnimont (MAIRE) awarded a USD 2.3 billion gas project by SONATRACH in Algeria aimed at bolstering Europe’s energy security
MAIRE (MAIRE.MI) announces that a consortium composed by its subsidiary Tecnimont (Integrated E&C Solutions) and Baker Hughes has been awarded by SONATRACH an Engineering, Procurement and Construction (EPC) contract for the implementation of three gas boosting stations and the upgrading of the gathering system, located at the Hassi R’mel gas field, 550 kilometers south of Algiers. The gas field is the largest in Algeria and one of the largest in the world. The overall contract value is about USD 2.3 billion, of which USD 1.7 billion relates to Tecnimont.
The scope of the project entails the implementation of three gas boosting stations, including turbo-compressors that will compress about 188 million standard cubic meters per day of natural gas. Additionally, the project entails the upgrading of the existing gas gathering system, which includes more than 300 km of flowlines connecting the wells. Completion of the project is scheduled within 39 months from the contract’s effective date.
The boosting stations, along with the gathering system, will maintain the pressure of the gas as it travels through the pipelines, allowing it to continue flowing more efficiently and ensuring a reliable and uninterrupted supply of natural gas to Italy, and subsequently to Europe as a whole. With this contract, MAIRE confirms its standing as a key engineering player in strategic energy projects, significantly contributing to the optimization of the gas supply from Algeria, thus diversifying Italy and Europe’s energy sources. This initiative consolidates the relationships between the two sides of the Mediterranean, reinforcing EU-Africa cooperation.
Alessandro Bernini, Chief Executive Officer of MAIRE group, commented: “After the award of the linear alkyl benzene (LAB) plant in the industrial zone of Skikda last March, SONATRACH once again relies on our Group’s execution capabilities. The development of this new crucial project strengthens our relationship with SONATRACH and, most importantly, the bilateral relations between Italy and Algeria. This award, in fact, represents a strong recognition of the entire Italian value chain, having Baker Hughes as partner and, more broadly, an important economic impact on our country”.
The scope of the project entails the implementation of three gas boosting stations, including turbo-compressors that will compress about 188 million standard cubic meters per day of natural gas. Additionally, the project entails the upgrading of the existing gas gathering system, which includes more than 300 km of flowlines connecting the wells. Completion of the project is scheduled within 39 months from the contract’s effective date.
The boosting stations, along with the gathering system, will maintain the pressure of the gas as it travels through the pipelines, allowing it to continue flowing more efficiently and ensuring a reliable and uninterrupted supply of natural gas to Italy, and subsequently to Europe as a whole. With this contract, MAIRE confirms its standing as a key engineering player in strategic energy projects, significantly contributing to the optimization of the gas supply from Algeria, thus diversifying Italy and Europe’s energy sources. This initiative consolidates the relationships between the two sides of the Mediterranean, reinforcing EU-Africa cooperation.
Alessandro Bernini, Chief Executive Officer of MAIRE group, commented: “After the award of the linear alkyl benzene (LAB) plant in the industrial zone of Skikda last March, SONATRACH once again relies on our Group’s execution capabilities. The development of this new crucial project strengthens our relationship with SONATRACH and, most importantly, the bilateral relations between Italy and Algeria. This award, in fact, represents a strong recognition of the entire Italian value chain, having Baker Hughes as partner and, more broadly, an important economic impact on our country”.
Baker Hughes to Support Strategic Gas Project in Algeria to Enhance Italy, Europe’s Energy Security
Baker Hughes (NASDAQ: BKR), an energy technology company, announced Thursday it was awarded a major contract from SONATRACH for a gas-boosting project for the Hassi R’Mel gas field in Algeria. The contract is part of a broader order awarded to a consortium between Baker Hughes and Tecnimont, part of technology and engineering group MAIRE. The signing ceremony took place in Algiers in the presence of the three company CEOs: Rachid Hachichi of SONATRACH, Lorenzo Simonelli of Baker Hughes, and Alessandro Bernini of MAIRE, as well as H.E. Mohamed Arkab, Minister of Energy & Mines.
Baker Hughes’ awarded scope includes the supply of 20 compression trains based on Frame 5 gas turbine and BCL compressor technology, which will be installed across three gas boosting stations within the Hassi R’ Mel gas field. Located 550 km south of Algiers, Hassi R’ Mel is the largest gas field in Algeria and one of the largest in the world, representing a key source of energy supply for Algeria and Europe. Baker Hughes’ proven technology solutions are expected to play a central role in the project by boosting and stabilizing the pressure of natural gas and increasing production at site, which will enhance Algeria’s domestic energy system and economy as well as Europe’s energy security.
“Today’s announcement marks a notable milestone in our historical collaboration with SONATRACH for key energy projects in Algeria that have played a crucial role in supplying reliable energy to Europe,” said Lorenzo Simonelli, chairman and CEO of Baker Hughes. “We have long believed that it is critical to increase gas within the overall global energy mix to help achieve a lower-carbon economy. This project helps to solve for energy producers’ multi-faceted challenge of driving sustainable energy development as energy demand increases. We are proud to support such a critical energy project in partnership with Tecnimont.”
The new gas-boosting stations are part of Algeria’s ambitious plan to strengthen its role in the global energy market and its commitment to natural gas as a key energy source for socio-economic development. According to Bloomberg NEF, Algeria became the second-largest gas supplier to Europe in 2023, further strengthening the country’s role in enhancing the energy security of the continent, particularly in Italy where Algeria represents the biggest single source of import. The Hassi R’ Mel Project is part of a broader strategic collaboration between Algeria and Italy, which includes recently signed agreements to foster bilateral cooperation and provide financial support for Algeria’s gas production as part of the Mattei Plan. The Mattei Plan seeks to promote cooperation between Africa and Italy along five main policy pillars: education and training, agriculture, health, water and energy.
Baker Hughes’ awarded scope includes the supply of 20 compression trains based on Frame 5 gas turbine and BCL compressor technology, which will be installed across three gas boosting stations within the Hassi R’ Mel gas field. Located 550 km south of Algiers, Hassi R’ Mel is the largest gas field in Algeria and one of the largest in the world, representing a key source of energy supply for Algeria and Europe. Baker Hughes’ proven technology solutions are expected to play a central role in the project by boosting and stabilizing the pressure of natural gas and increasing production at site, which will enhance Algeria’s domestic energy system and economy as well as Europe’s energy security.
“Today’s announcement marks a notable milestone in our historical collaboration with SONATRACH for key energy projects in Algeria that have played a crucial role in supplying reliable energy to Europe,” said Lorenzo Simonelli, chairman and CEO of Baker Hughes. “We have long believed that it is critical to increase gas within the overall global energy mix to help achieve a lower-carbon economy. This project helps to solve for energy producers’ multi-faceted challenge of driving sustainable energy development as energy demand increases. We are proud to support such a critical energy project in partnership with Tecnimont.”
The new gas-boosting stations are part of Algeria’s ambitious plan to strengthen its role in the global energy market and its commitment to natural gas as a key energy source for socio-economic development. According to Bloomberg NEF, Algeria became the second-largest gas supplier to Europe in 2023, further strengthening the country’s role in enhancing the energy security of the continent, particularly in Italy where Algeria represents the biggest single source of import. The Hassi R’ Mel Project is part of a broader strategic collaboration between Algeria and Italy, which includes recently signed agreements to foster bilateral cooperation and provide financial support for Algeria’s gas production as part of the Mattei Plan. The Mattei Plan seeks to promote cooperation between Africa and Italy along five main policy pillars: education and training, agriculture, health, water and energy.
Wednesday, 22 May 2024
Saipem: three new contracts awarded by TotalEnergies E&P Angola Block 20 for the Kaminho project for an overall amount of 3.7 billion USD
Saipem has been awarded three new contracts by TotalEnergies EP Angola Block 20, a subsidiary of TotalEnergies, for the Kaminho project relating to the development of Cameia and Golfinho oil fields, located approximately 100 km off the coast of Angola. The overall amount of the contracts is 3.7 billion USD.
The first contract refers to the Engineering, Procurement, Construction, Transportation and Commissioning of the Kaminho Floating Production Storage and Offloading (FPSO) vessel.
The second contract entails the Operation and Maintenance (O&M) of the same vessel FPSO for a firm period of 12 years with a potential 8-year extension, leveraging on the expertise acquired from three other FPSOs currently operating in Angola.
The third contract involves the Engineering, Procurement, Supply, Construction, Installation, Pre-Commissioning and Assistance for the commissioning and start-up of a Subsea, Umbilicals, Risers and Flowlines (SURF) package which includes approximately 30 km of 8” and 10" subsea flowlines and risers, and umbilicals. The associated structures will be fabricated in Saipem’s local yard in Ambriz.
For the offshore campaign, and specifically for the J-lay vessel, Saipem will deploy its FDS and will widely involve the local supply chain for logistics and fabrication activities.
The joint award of the SURF, FPSO and O&M contracts confirms the competitiveness of Saipem’s integrated business model, in particular the company's unique capability to provide offshore and plant project management and engineering services, combined with a state-of-the-art fleet and local fabrication capacity.
The first contract refers to the Engineering, Procurement, Construction, Transportation and Commissioning of the Kaminho Floating Production Storage and Offloading (FPSO) vessel.
The second contract entails the Operation and Maintenance (O&M) of the same vessel FPSO for a firm period of 12 years with a potential 8-year extension, leveraging on the expertise acquired from three other FPSOs currently operating in Angola.
The third contract involves the Engineering, Procurement, Supply, Construction, Installation, Pre-Commissioning and Assistance for the commissioning and start-up of a Subsea, Umbilicals, Risers and Flowlines (SURF) package which includes approximately 30 km of 8” and 10" subsea flowlines and risers, and umbilicals. The associated structures will be fabricated in Saipem’s local yard in Ambriz.
For the offshore campaign, and specifically for the J-lay vessel, Saipem will deploy its FDS and will widely involve the local supply chain for logistics and fabrication activities.
The joint award of the SURF, FPSO and O&M contracts confirms the competitiveness of Saipem’s integrated business model, in particular the company's unique capability to provide offshore and plant project management and engineering services, combined with a state-of-the-art fleet and local fabrication capacity.
Angola: TotalEnergies launches the Kaminho deepwater project
Patrick Pouyanné, Chairman and CEO of TotalEnergies, met on May 20 in Luanda with João Lourenço, President of Angola, Diamantino Azevedo, Minister of Mineral Resources, Oil & Gas (MIREMPET), Paulino Jerónimo, Chairman and CEO of ANPG and Gaspar Martins, Chairman and CEO of Sonangol, to announce the Final Investment Decision of the Kaminho deepwater project.
TotalEnergies (40%), along with its Block 20/11 partners, Petronas (40%) and Sonangol (20%), announced the Final Investment Decision (FID) of the Kaminho project to develop the Cameia and Golfinho fields, located 100 km off the coast of Angola, by 1,700 m water-depth. This FID has been made possible thanks to a close collaboration with the concessionaire Agencia Nacional de Petroleo e Gas (ANPG).
The Kaminho project which is the first large deepwater development in the Kwanza basin comprises the conversion of a Very Large Crude Carrier (VLCC) to a Floating Production Storage and Offloading (FPSO) unit, which will be connected to a subsea production network. Designed to minimize greenhouse gas emissions and eliminate routine flaring, this FPSO is all-electric and associated gas will be fully reinjected into the reservoirs. Production start-up is expected in 2028, with a plateau of 70,000 barrels of oil per day.
The Kaminho project will involve over 10 million man-hours in Angola, mainly with offshore operations and construction at local yards.
On this occasion, TotalEnergies and Sonangol EP also signed a Memorandum of Understanding to share expertise on Research & Technology, notably in decarbonization of the Oil & Gas industry, with a strong focus on methane emissions reduction and renewable energies. TotalEnergies’ teams will provide support to Sonangol EP for the start-up and operation of its new Sumbe R&D center and for the development of the skills of the Sonangol research and technology teams, with a focus on reservoir geology, process electrification and photovoltaics.
TotalEnergies (40%), along with its Block 20/11 partners, Petronas (40%) and Sonangol (20%), announced the Final Investment Decision (FID) of the Kaminho project to develop the Cameia and Golfinho fields, located 100 km off the coast of Angola, by 1,700 m water-depth. This FID has been made possible thanks to a close collaboration with the concessionaire Agencia Nacional de Petroleo e Gas (ANPG).
The Kaminho project which is the first large deepwater development in the Kwanza basin comprises the conversion of a Very Large Crude Carrier (VLCC) to a Floating Production Storage and Offloading (FPSO) unit, which will be connected to a subsea production network. Designed to minimize greenhouse gas emissions and eliminate routine flaring, this FPSO is all-electric and associated gas will be fully reinjected into the reservoirs. Production start-up is expected in 2028, with a plateau of 70,000 barrels of oil per day.
The Kaminho project will involve over 10 million man-hours in Angola, mainly with offshore operations and construction at local yards.
On this occasion, TotalEnergies and Sonangol EP also signed a Memorandum of Understanding to share expertise on Research & Technology, notably in decarbonization of the Oil & Gas industry, with a strong focus on methane emissions reduction and renewable energies. TotalEnergies’ teams will provide support to Sonangol EP for the start-up and operation of its new Sumbe R&D center and for the development of the skills of the Sonangol research and technology teams, with a focus on reservoir geology, process electrification and photovoltaics.
Tuesday, 21 May 2024
Saipem awarded a new offshore contract by Azule Energy for Ndungu Field Project in Angola for a total amount of around 850 million USD
Saipem has been awarded a new offshore contract by Azule Energy Angola S.p.A., subsidiary of Azule Energy Holdings Limited, an incorporated joint venture between Eni and bp, for the development of the Ndungu Field as part of Agogo Integrated West Hub ProjectIntegrated West Hub Project, located approximately 180 km off the coast of Angola. The value of the contract is around 850 million USD.
Saipem’s scope of work entails the engineering, fabrication, transportation and installation of approximately 60 km of rigid pipelines and of the subsea facilities at a depth of around 1,100 meters, and the transportation and installation of flexible flowlines, jumpers and 17 km of umbilicals. Fabrication activities will be executed at Saipem’s Ambriz yard, in Angola. For the offshore installation campaign Saipem expects to deploy its FDS vessel, for the transportation and laying activities of the rigid pipelines.
The award of this important project further consolidates Saipem’s positioning in Angola, both in deep waters and in shallow waters, through the provision of innovative and efficient solutions to reduce installation times.
Saipem’s scope of work entails the engineering, fabrication, transportation and installation of approximately 60 km of rigid pipelines and of the subsea facilities at a depth of around 1,100 meters, and the transportation and installation of flexible flowlines, jumpers and 17 km of umbilicals. Fabrication activities will be executed at Saipem’s Ambriz yard, in Angola. For the offshore installation campaign Saipem expects to deploy its FDS vessel, for the transportation and laying activities of the rigid pipelines.
The award of this important project further consolidates Saipem’s positioning in Angola, both in deep waters and in shallow waters, through the provision of innovative and efficient solutions to reduce installation times.
Approval of Belinda Development
Serica Energy plc (AIM: SQZ), a British independent upstream oil and gas company, announces that it has received final approval from the NSTA to develop the 100% owned and operated Belinda field. The field will be tied back to the Triton FPSO following the drilling of the development well which is scheduled to take place in the first half of 2025. The Belinda well is the 5th well in Serica’s Triton area drilling campaign, which commenced in April this year using the COSLInnovator drilling rig. All these wells are designed to enhance production via the Triton FPSO.
Proven and probable reserves in the Belinda field are estimated at about 5 million barrels of oil equivalent (80% oil). Production is scheduled to commence in 1Q2026 following the tie-back work to the Triton FPSO.
David Latin, Chairman and Interim CEO of Serica commented:
“We are delighted to have received approval to develop Belinda. This will build on our strong track record of delivering growth and adding value through investment in our assets. We have further potential projects in our portfolio which we continue to assess, including the possible re-development of the Kyle field, which could, like Belinda, be another low emissions tie-back candidate to the Triton FPSO. We look to the UK government to implement tax and licensing arrangements that support investments like Belinda, thereby creating UK jobs, earnings and tax receipts instead of increasing reliance on energy imports.”
Tuesday, 14 May 2024
TechnipFMC Awarded Significant iEPCI™ Contract by Woodside Energy for Xena Phase 3 Development
TechnipFMC (NYSE: FTI) has been awarded a significant integrated Engineering, Procurement, Construction, and Installation (iEPCI™) contract by Woodside Energy (LON: WDS) in Australia.
TechnipFMC will design, manufacture, and install the subsea production system, flexible pipe, and umbilicals for the Xena Infill well (XNA03) to support ongoing production from the Pluto LNG Project. The award follows an integrated front end engineering design (iFEED™) study.
The project will use the Company’s Subsea 2.0 production system. Xena Phase 3 will be tied back to existing subsea infrastructure previously supplied by TechnipFMC.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “We are proud to be delivering a fully integrated project from concept to execution. This project will help our long-term client meet their objectives, demonstrating the favorable impact iFEED™, iEPCI™, and Subsea 2.0® can have on project economics.”
The contract is the latest call-off on the framework agreement between Woodside Energy and TechnipFMC.
TechnipFMC will design, manufacture, and install the subsea production system, flexible pipe, and umbilicals for the Xena Infill well (XNA03) to support ongoing production from the Pluto LNG Project. The award follows an integrated front end engineering design (iFEED™) study.
The project will use the Company’s Subsea 2.0 production system. Xena Phase 3 will be tied back to existing subsea infrastructure previously supplied by TechnipFMC.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “We are proud to be delivering a fully integrated project from concept to execution. This project will help our long-term client meet their objectives, demonstrating the favorable impact iFEED™, iEPCI™, and Subsea 2.0® can have on project economics.”
The contract is the latest call-off on the framework agreement between Woodside Energy and TechnipFMC.
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