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.
Tuesday 30 July 2024
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)
.
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.
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