A consortium comprised of McDermott and Petrovietnam Technical Services Corporation (PTSC) has received a limited letter of award from Phu Quoc Petroleum Operating Company for engineering, procurement, construction, installation (EPCI), and hook-up and commissioning (HUC) services.
Under the full project scope, the consortium will provide EPCI and HUC services for a central production platform, living quarters platform, flare tower, and bridges for the Block B gas development project off the southwest coast of Vietnam.
"This award combines our 50 years of experience executing complex EPCI projects in the region with PTSC's technical strengths," said Mahesh Swaminathan, McDermott's Senior Vice President, Subsea and Floating Facilities. "Together, we will initiate this important groundwork as we finalize the full project scope and ultimately deliver another world-class project for Vietnam."
The full project contract is expected to be executed between the parties in early 2024 with an award value of more than $1 billion.
Tuesday 31 October 2023
Wednesday 25 October 2023
TechnipFMC Awarded Flexible Pipe Contract for Woodside Energy’s Trion Project
TechnipFMC (NYSE: FTI) has been awarded a contract to manufacture flexible pipe by Woodside Energy (LON: WDS).
The Company will supply infield flowlines and jumpers for the Trion project in deepwater Mexico.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “We worked with Woodside to formulate the best technical solution for this milestone project. This contract is our largest flexible pipe award in the Gulf of Mexico to date, and builds upon the trust we have established with Woodside over many years of successful execution and delivery.”
The Company will supply infield flowlines and jumpers for the Trion project in deepwater Mexico.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “We worked with Woodside to formulate the best technical solution for this milestone project. This contract is our largest flexible pipe award in the Gulf of Mexico to date, and builds upon the trust we have established with Woodside over many years of successful execution and delivery.”
Tuesday 24 October 2023
Peyto Announces Closing Of Repsol Acquisition
Peyto Exploration & Development Corp. ("Peyto" or the "Company") is pleased to announce that it has completed its previously announced acquisition of Repsol Canada Energy Partnership, which holds the Canadian upstream oil and gas business of Repsol Exploración, S.A.U. ("Repsol"), including all related midstream facilities and infrastructure located predominantly in the Deep Basin area of Alberta, for cash consideration of US$468 million (CDN$636 million) (the "Acquisition") prior to closing adjustments. The Acquisition increases Peyto’s current production to 123,000 boe/d (86% natural gas, 14% NGLs), adds over 800 highimpact gross drilling locations1 and includes extensive gas processing and pipeline infrastructure that complement Peyto’s legacy assets in the Edson area. Peyto has plans to begin drilling operations on the Repsol lands, immediately.
Shell completes sale of interest in Indonesia’s Masela block
Shell Upstream Overseas Services (I) Limited (“SUOS”), a subsidiary of Shell plc, has completed the
previously announced sale of its 35% participating interest in Indonesia’s Masela Production Sharing Contract (“Masela PSC”) to Indonesia’s PT Pertamina Hulu Energi and PETRONAS Masela Sdn. Bhd (“Petronas Masela”).
The sale includes the Abadi gas project. Completion of the sale follows regulatory approval from Indonesia’s Ministry of Energy and Mineral Resources for the transfer of SUOS’ stake to PT Pertamina Hulu Energi Masela and Petronas Masela.
This divestment is in line with Shell’s focus on disciplined capital allocation. Shell remains active in Indonesia’s downstream and low-carbon fuel sectors.
Notes to editors
previously announced sale of its 35% participating interest in Indonesia’s Masela Production Sharing Contract (“Masela PSC”) to Indonesia’s PT Pertamina Hulu Energi and PETRONAS Masela Sdn. Bhd (“Petronas Masela”).
The sale includes the Abadi gas project. Completion of the sale follows regulatory approval from Indonesia’s Ministry of Energy and Mineral Resources for the transfer of SUOS’ stake to PT Pertamina Hulu Energi Masela and Petronas Masela.
This divestment is in line with Shell’s focus on disciplined capital allocation. Shell remains active in Indonesia’s downstream and low-carbon fuel sectors.
Notes to editors
- INPEX Corporation (“INPEX”) holds a 65% operating interest in Masela PSC and is the operator of the Abadi gas project. This is located in the Masela block, 150 kilometers offshore Saumlaki in Maluku province, Indonesia.
- SUOS acquired its interest in the Masela PSC in 2011.
Monday 23 October 2023
Chevron announces agreement to acquire Hess
Chevron Corporation (NYSE: CVX) announced today that it has entered into a definitive agreement with Hess Corporation (NYSE: HES) to acquire all of the outstanding shares of Hess in an all-stock transaction valued at $53 billion, or $171 per share based on Chevron’s closing price on October 20, 2023. Under the terms of the agreement, Hess shareholders will receive 1.0250 shares of Chevron for each Hess share. The total enterprise value, including debt, of the transaction is $60 billion.
The acquisition of Hess upgrades and diversifies Chevron’s already advantaged portfolio. The Stabroek block in Guyana is an extraordinary asset with industry leading cash margins and low carbon intensity that is expected to deliver production growth into the next decade. Hess’ Bakken assets add another leading U.S. shale position to Chevron’s DJ and Permian basin operations and further strengthen domestic energy security. The combined company is expected to grow production and free cash flow faster and for longer than Chevron’s current five-year guidance. In addition, John Hess is expected to join Chevron’s Board of Directors.
“This combination positions Chevron to strengthen our long-term performance and further enhance our advantaged portfolio by adding world-class assets,” said Chevron Chairman and CEO Mike Wirth. “Importantly, our two companies have similar values and cultures, with a focus on operating safely and with integrity, attracting and developing the best people, making positive contributions to our communities and delivering higher returns and lower carbon.”
“Building on our track record of successful transactions, the addition of Hess is expected to extend further Chevron’s free cash flow growth,” said Pierre Breber, Chevron’s CFO. “With greater confidence in projected long-term cash generation, Chevron intends to return more cash to shareholders with higher dividend per share growth and higher share repurchases.”
“This strategic combination brings together two strong companies to create a premier integrated energy company,” CEO John Hess said. “I am proud of our people and what we have achieved as a company, which has one of the industry’s best growth portfolios including Guyana, the world’s largest oil discovery in the last 10 years, and the Bakken shale, where we are a leading oil and gas producer. Chevron has a world-class diversified portfolio of assets and one of the industry’s strongest balance sheets and cash return profiles. I believe our strategic combination creates a company that is stronger in every respect, with the leadership, asset portfolio and financial resources to lead us through the energy transition and deliver significant shareholder value for years to come.”
Transaction Benefits
The acquisition of Hess upgrades and diversifies Chevron’s already advantaged portfolio. The Stabroek block in Guyana is an extraordinary asset with industry leading cash margins and low carbon intensity that is expected to deliver production growth into the next decade. Hess’ Bakken assets add another leading U.S. shale position to Chevron’s DJ and Permian basin operations and further strengthen domestic energy security. The combined company is expected to grow production and free cash flow faster and for longer than Chevron’s current five-year guidance. In addition, John Hess is expected to join Chevron’s Board of Directors.
“This combination positions Chevron to strengthen our long-term performance and further enhance our advantaged portfolio by adding world-class assets,” said Chevron Chairman and CEO Mike Wirth. “Importantly, our two companies have similar values and cultures, with a focus on operating safely and with integrity, attracting and developing the best people, making positive contributions to our communities and delivering higher returns and lower carbon.”
“Building on our track record of successful transactions, the addition of Hess is expected to extend further Chevron’s free cash flow growth,” said Pierre Breber, Chevron’s CFO. “With greater confidence in projected long-term cash generation, Chevron intends to return more cash to shareholders with higher dividend per share growth and higher share repurchases.”
“This strategic combination brings together two strong companies to create a premier integrated energy company,” CEO John Hess said. “I am proud of our people and what we have achieved as a company, which has one of the industry’s best growth portfolios including Guyana, the world’s largest oil discovery in the last 10 years, and the Bakken shale, where we are a leading oil and gas producer. Chevron has a world-class diversified portfolio of assets and one of the industry’s strongest balance sheets and cash return profiles. I believe our strategic combination creates a company that is stronger in every respect, with the leadership, asset portfolio and financial resources to lead us through the energy transition and deliver significant shareholder value for years to come.”
Transaction Benefits
- Strong strategic fit:
- Guyana – 30% ownership in more than 11 billion barrels of oil equivalent discovered recoverable resource with high cash margins per barrel, strong production growth outlook and potential exploration upside.
- Bakken – 465,000 net acres of high-quality, long-duration inventory supported by the integrated assets of Hess Midstream.
- Complementary Gulf of Mexico assets and steady free cash flow from Southeast Asia natural gas business.
- Accretive to cash flow per share and extends growth into 2030s:
- Expected to be accretive to cash flow per share in 2025 after achieving synergies and start-up of the fourth floating production storage and offloading (FPSO) vessel in Guyana.
- Increases Chevron’s estimated five-year production and free cash flow growth rates and expected to extend such growth into the next decade.
- Increases cash returned to shareholders:
- In January, Chevron expects to recommend an increase to its first quarter dividend per share of 8% to $1.63, which will be subject to the approval of the Chevron Board of Directors.
- Post closing, Chevron intends to increase share repurchases by $2.5 billion to the top end of its guidance range of $20 billion per year in a continued upside oil price scenario.
- Capital and cost efficient:
- The combined company’s capital expenditures budget is expected to be between $19 and $22 billion.
- With a stronger portfolio after closing, Chevron expects to increase asset sales and generate $10 to $15 billion in before-tax proceeds through 2028.
- The transaction is expected to achieve run-rate cost synergies around $1 billion before tax within a year of closing.
Hess Assets:
- Block A 18 Gas Fields - A Barrel Full
- Baldpate Oil and Gas Field - A Barrel Full
- Liza Oil Field - A Barrel Full
- Llano Oil and Gas Field - A Barrel Full
- North Malay Basin Gas Fields - A Barrel Full
- Payara Oil Field - A Barrel Full
- Stampede TLP Oil and Gas Fields Development - A Barrel Full
- Tubular Bells Oil and Gas Field - A Barrel Full
- Uaru Oil Field - A Barrel Full
- Yellowtail Oil Field - A Barrel Full
Thursday 19 October 2023
Acquisition of shares in the Reggane Nord gas project closed
Wintershall Dea is expanding its presence in Algeria. Following the completion of the transaction and regulatory approvals, the company is increasing its participating interest in the Reggane Nord natural gas project by 4.5 per cent through the acquisition of interest from former project partner Edison. The Groupement Reggane Nord, operator of the project, will thus consist of Sonatrach (40%), Repsol (36%), and Wintershall Dea (24%).
For Wintershall Dea, all signs point to growth in Algeria. The company has been active in the North African country since 2002. Since production began in Reggane Nord in December 2017, around 13 billion cubic meters of gas have been produced in the consortium. Its business in Algeria is an important part of the company's portfolio and is to be expanded in the future. To this end, in February 2022 Wintershall Dea and partner Sonatrach extended an existing Memorandum of Understanding to consider new business opportunities in Algeria, not just in natural gas but also in hydrogen and Carbon Capture and Storage (CCS).
Dawn Summers, Chief Operating Officer and the responsible Board Member for Algeria, says: "We see great potential for the future of the Algerian energy sector; both for the expansion of natural gas production, and for carbon management and hydrogen projects. Areas in which Wintershall Dea intends to become active in Algeria in the future. With the acquisition of further interest in Reggane Nord, we are now consolidating our presence in Algeria and setting the course for growth."
Thomas Ruttmann, Senior Vice President and Managing Director Wintershall Dea Algeria says: "Reggane Nord has been producing natural gas reliably and cost-efficiently since 2017. Wintershall Dea is not just an investor, our team is actively contributing experience and know-how and effectively contributes to the efficiency of the project – especially our drilling and reservoir expertise is in demand here. We are pleased to now increase our participating interest in the project and continue to actively advance Reggane Nord in the future."
Algeria is the largest producer of natural gas in Africa and the third largest exporter of natural gas to Europe. The North African country therefore makes a decisive contribution to Europe's energy supply and is the ideal partner for Europe to secure its energy supply and at the same time advance the energy transition.
For Wintershall Dea, all signs point to growth in Algeria. The company has been active in the North African country since 2002. Since production began in Reggane Nord in December 2017, around 13 billion cubic meters of gas have been produced in the consortium. Its business in Algeria is an important part of the company's portfolio and is to be expanded in the future. To this end, in February 2022 Wintershall Dea and partner Sonatrach extended an existing Memorandum of Understanding to consider new business opportunities in Algeria, not just in natural gas but also in hydrogen and Carbon Capture and Storage (CCS).
Dawn Summers, Chief Operating Officer and the responsible Board Member for Algeria, says: "We see great potential for the future of the Algerian energy sector; both for the expansion of natural gas production, and for carbon management and hydrogen projects. Areas in which Wintershall Dea intends to become active in Algeria in the future. With the acquisition of further interest in Reggane Nord, we are now consolidating our presence in Algeria and setting the course for growth."
Thomas Ruttmann, Senior Vice President and Managing Director Wintershall Dea Algeria says: "Reggane Nord has been producing natural gas reliably and cost-efficiently since 2017. Wintershall Dea is not just an investor, our team is actively contributing experience and know-how and effectively contributes to the efficiency of the project – especially our drilling and reservoir expertise is in demand here. We are pleased to now increase our participating interest in the project and continue to actively advance Reggane Nord in the future."
Algeria is the largest producer of natural gas in Africa and the third largest exporter of natural gas to Europe. The North African country therefore makes a decisive contribution to Europe's energy supply and is the ideal partner for Europe to secure its energy supply and at the same time advance the energy transition.
Saturday 14 October 2023
Green light for Breidablikk
The Norwegian Petroleum Directorate (NPD) has granted consent for start-up of the Breidablikk field in the North Sea. Production is expected to start in October.
Breidablikk is an oil field situated ten kilometres northeast of the Grane field, west of Haugesund. Equinor is the operator, while Vår, ConocoPhillips and Petoro are licensees.
The field is a subsea development with four subsea templates, each with six well slots.
Breidablikk contains around 30 million standard cubic metres of recoverable oil (approx. 190 million barrels of oil). Total investments are around NOK 19 billion.
Breidablikk is an oil field situated ten kilometres northeast of the Grane field, west of Haugesund. Equinor is the operator, while Vår, ConocoPhillips and Petoro are licensees.
The field is a subsea development with four subsea templates, each with six well slots.
Breidablikk contains around 30 million standard cubic metres of recoverable oil (approx. 190 million barrels of oil). Total investments are around NOK 19 billion.
Ready for Tommeliten A start-up
The authorities have granted consent for start-up of the Tommeliten A field in the North Sea.
Operator Conoco Phillips estimates that around 24 million standard cubic metres (150 million barrels) of oil equivalent can be recovered from Tommeliten A.
The operator estimates investments for developing Tommeliten A at ca NOK 13 billion . Conoco Phillips expects the field to come on stream this month. The plan for development and operation (PDO) was approved in 2022, and the discovery was made as early as 1977.
The field, which mainly contains gas and condensate, is located in production licence 044. It is a transboundary field, with a marginal share on the UK shelf. The licensees on the Norwegian and UK sides have unitised the activity. Tommeliten A is a gas and condensate field southwest of the Ekofisk field in the southern part of the Norwegian sector.
Tommeliten A is a subsea development with two subsea templates, with enough space to accommodate a total of twelve wells. The wellstream will be routed to the Ekofisk field for further processing and export. The gas will be exported to Emden in Germany, while oil and wet gas will be routed via pipeline to Teesside in the United Kingdom.
Tommeliten A will include eleven development wells, seven of which will be completed as of start-up. The operator expects to complete the four remaining wells during the first quarter of 2024.
The twelfth well slot will be reserved as a potential future replacement well.
“The Tommeliten A development is a good example of sound utilisation of existing infrastructure in the area”, says Tomas Mørch, assistant director of Licence Management in the Norwegian Petroleum Directorate.
“It’s gratifying to see that an older discovery from 1977 has now been matured into a profitable and robust field development that’s ready to come on stream. It’s also gratifying that the project has been completed ahead of schedule and within the cost framework.”
“We also note that the same type of subsea technology used on Tommeliten A could potentially be applied for other development projects in the area.”
Several attempts to mature Tommeliten A have been made in the past. Insufficient processing capacity on Ekofisk was one of the roadblocks encountered. This is no longer an issue.
Operator Conoco Phillips estimates that around 24 million standard cubic metres (150 million barrels) of oil equivalent can be recovered from Tommeliten A.
The operator estimates investments for developing Tommeliten A at ca NOK 13 billion . Conoco Phillips expects the field to come on stream this month. The plan for development and operation (PDO) was approved in 2022, and the discovery was made as early as 1977.
The field, which mainly contains gas and condensate, is located in production licence 044. It is a transboundary field, with a marginal share on the UK shelf. The licensees on the Norwegian and UK sides have unitised the activity. Tommeliten A is a gas and condensate field southwest of the Ekofisk field in the southern part of the Norwegian sector.
Tommeliten A is a subsea development with two subsea templates, with enough space to accommodate a total of twelve wells. The wellstream will be routed to the Ekofisk field for further processing and export. The gas will be exported to Emden in Germany, while oil and wet gas will be routed via pipeline to Teesside in the United Kingdom.
Tommeliten A will include eleven development wells, seven of which will be completed as of start-up. The operator expects to complete the four remaining wells during the first quarter of 2024.
The twelfth well slot will be reserved as a potential future replacement well.
“The Tommeliten A development is a good example of sound utilisation of existing infrastructure in the area”, says Tomas Mørch, assistant director of Licence Management in the Norwegian Petroleum Directorate.
“It’s gratifying to see that an older discovery from 1977 has now been matured into a profitable and robust field development that’s ready to come on stream. It’s also gratifying that the project has been completed ahead of schedule and within the cost framework.”
“We also note that the same type of subsea technology used on Tommeliten A could potentially be applied for other development projects in the area.”
Several attempts to mature Tommeliten A have been made in the past. Insufficient processing capacity on Ekofisk was one of the roadblocks encountered. This is no longer an issue.
Friday 13 October 2023
Saipem awarded new contract by ADNOC in the United Arab Emirates worth around 4.1 billion USD
Saipem, in consortium with National Petroleum Construction Company (NPCC), has signed today a letter of award with ADNOC for a new contract related to the Hail and Ghasha Development Project – Package 1 in the United Arab Emirates. Saipem's share of the contract amounts to around 4.1 billion USD.
The project is aimed at developing the resources of the Hail and Ghasha natural gas fields, located offshore Abu Dhabi, UAE. The project scope of work encompasses the Engineering, Procurement and Construction (EPC) of four drilling centres and one processing plant to be built on artificial islands, as well as various offshore structures and more than 300 km of subsea pipelines.
The award is in line with Saipem’s unique capability to deliver integrated onshore and offshore projects, providing its clients with a single and reliable interface for complex full-field developments. Saipem will leverage on its state-of-the-art shallow water offshore vessels, its advanced welding technology for corrosion resistant materials, as well as its renowned engineering expertise. Furthermore, Saipem will work with ADNOC to continue the project's focus on biodiversity and responsible environmental stewardship.
This award reinforces Saipem’s long-standing relationship with ADNOC and further consolidates the company’s presence in Abu Dhabi, which includes an Engineering and Project Execution Centre, as well as a new Offshore Logistic base in Zayed Port.
The project is aimed at developing the resources of the Hail and Ghasha natural gas fields, located offshore Abu Dhabi, UAE. The project scope of work encompasses the Engineering, Procurement and Construction (EPC) of four drilling centres and one processing plant to be built on artificial islands, as well as various offshore structures and more than 300 km of subsea pipelines.
The award is in line with Saipem’s unique capability to deliver integrated onshore and offshore projects, providing its clients with a single and reliable interface for complex full-field developments. Saipem will leverage on its state-of-the-art shallow water offshore vessels, its advanced welding technology for corrosion resistant materials, as well as its renowned engineering expertise. Furthermore, Saipem will work with ADNOC to continue the project's focus on biodiversity and responsible environmental stewardship.
This award reinforces Saipem’s long-standing relationship with ADNOC and further consolidates the company’s presence in Abu Dhabi, which includes an Engineering and Project Execution Centre, as well as a new Offshore Logistic base in Zayed Port.
SBM Offshore awarded FEED contracts for Whiptail project in Guyana
SBM Offshore is pleased to announce it has been awarded contracts to perform Front End Engineering and Design (FEED) for a Floating Production, Storage and Offloading vessel (FPSO) for the Whiptail development project in Guyana.
Following FEED and subject to government approvals in Guyana of the development plan, project sanction including final investment decision by ExxonMobil Guyana Limited, an affiliate of ExxonMobil Corporation, to release the second phase of work, SBM Offshore will construct and install the FPSO. The FEED contract award triggers the initial release of funds by ExxonMobil Guyana Limited to begin FEED activities, and commits a Fast4Ward® hull for the execution of the Whiptail development project in Guyana.
Under the contracts, the FPSO’s ownership is expected to be transferred to the client at the end of the construction period and before start of operations in Guyana. The construction costs are expected to be partially funded by senior loans which will be repaid at the time of the FPSO’s transfer to the client.
SBM Offshore is expected to operate the FPSO through its integrated operations and maintenance model combining SBM Offshore and ExxonMobil’s expertise and experience, leveraging key learnings and the operational excellence of the units currently deployed in Guyana.
SBM Offshore will design and construct the FPSO using its industry-leading Fast4Ward® program using the Company’s seventh new build, Multi-Purpose Floater hull, combined with several standardized topsides modules. The FPSO will be designed to produce 250,000 barrels of oil per day, will have associated gas treatment capacity of 540 million cubic feet per day and water injection capacity of 300,000 barrels per day. The FPSO will be spread moored in water depth of about 1,630 meters and will be able to store around 2 million barrels of crude oil.
Building on the experience to date of FPSOs Liza Destiny, Liza Unity, Prosperity and ONE GUYANA, SBM Offshore continues to commit to local content development in Guyana by sourcing fabrication scope locally and integrating Guyanese engineers into the execution and operational teams.
Bruno Chabas, SBM Offshore’s Chief Executive Officer:
“We are proud to announce ExxonMobil Guyana has awarded the contracts for a fifth FPSO from SBM Offshore in Guyana. This project demonstrates once more the value that our industry-leading Fast4Ward® program brings to our clients and other stakeholders while delivering carbon efficient energy to the world.”
Following FEED and subject to government approvals in Guyana of the development plan, project sanction including final investment decision by ExxonMobil Guyana Limited, an affiliate of ExxonMobil Corporation, to release the second phase of work, SBM Offshore will construct and install the FPSO. The FEED contract award triggers the initial release of funds by ExxonMobil Guyana Limited to begin FEED activities, and commits a Fast4Ward® hull for the execution of the Whiptail development project in Guyana.
Under the contracts, the FPSO’s ownership is expected to be transferred to the client at the end of the construction period and before start of operations in Guyana. The construction costs are expected to be partially funded by senior loans which will be repaid at the time of the FPSO’s transfer to the client.
SBM Offshore is expected to operate the FPSO through its integrated operations and maintenance model combining SBM Offshore and ExxonMobil’s expertise and experience, leveraging key learnings and the operational excellence of the units currently deployed in Guyana.
SBM Offshore will design and construct the FPSO using its industry-leading Fast4Ward® program using the Company’s seventh new build, Multi-Purpose Floater hull, combined with several standardized topsides modules. The FPSO will be designed to produce 250,000 barrels of oil per day, will have associated gas treatment capacity of 540 million cubic feet per day and water injection capacity of 300,000 barrels per day. The FPSO will be spread moored in water depth of about 1,630 meters and will be able to store around 2 million barrels of crude oil.
Building on the experience to date of FPSOs Liza Destiny, Liza Unity, Prosperity and ONE GUYANA, SBM Offshore continues to commit to local content development in Guyana by sourcing fabrication scope locally and integrating Guyanese engineers into the execution and operational teams.
Bruno Chabas, SBM Offshore’s Chief Executive Officer:
“We are proud to announce ExxonMobil Guyana has awarded the contracts for a fifth FPSO from SBM Offshore in Guyana. This project demonstrates once more the value that our industry-leading Fast4Ward® program brings to our clients and other stakeholders while delivering carbon efficient energy to the world.”
MAIRE awarded USD 8.7 billion contract by ADNOC for the onshore portion of the HAIL and GHASHA development project in Abu Dhabi. The largest award ever for the Group
MAIRE announces that Tecnimont, part of the Integrated E&C Solutions business unit, today signed a Letter of Award with ADNOC for the onshore processing plant of the Hail and Ghasha Development Project. The award was signed at ADIPEC, the world’s largest energy summit.
The Hail and Ghasha project is aimed to operate with net zero CO2 emissions, in part due to the facility’s CO2 carbon capture and recovery units, which will allow the capture and storage of CO2.
The overall EPC contract value is approximately USD 8.7 billion and project completion is expected during 2028. The scope of work includes two gas processing units, three sulphur recovery sections, the associated utilities and offsites as well as export pipelines. Tecnimont will also leverage the competences of MAIRE’s Sustainable Technology Solutions division to develop innovative digital solutions aimed at reducing emissions and optimizing energy consumption, allowing a significant efficiency of the plant in terms of opex and capex.
The engineering and procurement activities will be executed by several dedicated teams in Europe, India and the UAE, under the central coordination of MAIRE’s Milan headquarters. In particular, MAIRE’s UAE procurement hub will ensure the maximization of the local suppliers’ involvement, aimed at providing significant value to the local economy.
MAIRE has been active in the UAE since the late ‘90s, with several strategic projects in the Country for an overall total value of approximately USD 17 billion, starting from the first polyolefin plant completed in 2001 (Borouge 1). Additionally, the Group can leverage on a world class track record and experience in delivering large gas treatment plants and sulphur recovery projects.
Alessandro Bernini, MAIRE Group CEO, commented: “Today we have been awarded the largest contract ever for the MAIRE Group, a multi-billion-dollar project which will significantly boost the delivery of our 10-year strategic plan. We are honored to have achieved this great result with a leading global player such as ADNOC, as it represents further evidence of the strength of our long-lasting and fruitful relationship. This award, a landmark recognition of Made in Italy Engineering, is a demonstration not only of our leadership in sulphur recovery and in gas treatment plants but, more broadly, of our undisputed execution capabilities as well as our technological expertise in designing carbon-free industrial solutions.”
The Hail and Ghasha project is aimed to operate with net zero CO2 emissions, in part due to the facility’s CO2 carbon capture and recovery units, which will allow the capture and storage of CO2.
The overall EPC contract value is approximately USD 8.7 billion and project completion is expected during 2028. The scope of work includes two gas processing units, three sulphur recovery sections, the associated utilities and offsites as well as export pipelines. Tecnimont will also leverage the competences of MAIRE’s Sustainable Technology Solutions division to develop innovative digital solutions aimed at reducing emissions and optimizing energy consumption, allowing a significant efficiency of the plant in terms of opex and capex.
The engineering and procurement activities will be executed by several dedicated teams in Europe, India and the UAE, under the central coordination of MAIRE’s Milan headquarters. In particular, MAIRE’s UAE procurement hub will ensure the maximization of the local suppliers’ involvement, aimed at providing significant value to the local economy.
MAIRE has been active in the UAE since the late ‘90s, with several strategic projects in the Country for an overall total value of approximately USD 17 billion, starting from the first polyolefin plant completed in 2001 (Borouge 1). Additionally, the Group can leverage on a world class track record and experience in delivering large gas treatment plants and sulphur recovery projects.
Alessandro Bernini, MAIRE Group CEO, commented: “Today we have been awarded the largest contract ever for the MAIRE Group, a multi-billion-dollar project which will significantly boost the delivery of our 10-year strategic plan. We are honored to have achieved this great result with a leading global player such as ADNOC, as it represents further evidence of the strength of our long-lasting and fruitful relationship. This award, a landmark recognition of Made in Italy Engineering, is a demonstration not only of our leadership in sulphur recovery and in gas treatment plants but, more broadly, of our undisputed execution capabilities as well as our technological expertise in designing carbon-free industrial solutions.”
Wednesday 4 October 2023
Keyera celebrates the completion of the KAPS pipeline
Keyera Corp. (TSX: KEY) ("Keyera"), one of Canada's largest independent midstream energy infrastructure businesses, recently completed the KAPS pipeline – Alberta's newest natural gas liquids (NGLs) and condensate pipeline spanning 575 kilometres, and supporting Canada's role on the global energy stage. KAPS is operated by Keyera and 50% owned by Stonepeak, a leading alternative investment firm specializing in infrastructure and real assets.
"KAPS is more than a pipeline, it's truly an energy infrastructure solution that is helping to unlock partnership and prosperity through a purposeful approach," says Dean Setoguchi, President & CEO of Keyera. "The support KAPS has received is a testament to both commercial need and the listen-first approach Keyera takes with external stakeholders and Indigenous communities. KAPS has been years in the making, and it is the platform that propels us forward and lets us focus on what we do best – supply responsibly produced Canadian energy."
The KAPS pipeline will safely transport 350,000 barrels per day of NGLs and condensate from the liquids-rich Montney and Duvernay basins to Keyera's liquids processing and storage hub in Alberta's Industrial Heartland, located in Fort Saskatchewan. By providing a competitive transportation alternative that allows producers to grow natural gas production, KAPS is advancing Alberta's energy industry. This highly desired industry pipeline solution is designed to integrate services, generate more volumes, and expand commercial opportunities; all of which drives benefit for Alberta and fuels greater domestic economic growth.
"The completion of the KAPS pipeline represents a significant milestone in the expansion of natural gas production in Western Canada. As natural gas continues to be a key contributor to the global energy mix and energy transition, especially in East Asia, we believe that KAPS has a critical role to play," says Anthony Borreca, Senior Managing Director at Stonepeak. "KAPS has the ability to support decarbonization and energy security goals on a local and global level and we look forward to continuing to partner with Keyera as responsible stewards of this asset as production gets underway."
Integral to the successful construction and completion of KAPS was Keyera's engagement and partnerships with communities along the pipeline route, including 10 municipalities, 22 Indigenous communities and 60 Indigenous-owned or affiliated businesses. Determining the pipeline route was a collaborative effort that extended well beyond regulatory, environmental, safety and land factors. It included input from traditional land use studies from each Indigenous community, approximately 400 site visits with Rights holders, and the approval of nearly 600 landowners and occupants.
"This is such great news for Keyera, its partners, and for Alberta," says the Honourable, Danielle Smith, Premier of Alberta. "KAPS is furthering economic opportunity and prosperity for Indigenous partners and communities as well as for the entire province. I'm excited to see the positive impacts this project will have and the economic growth we'll see in the years to come."
During construction, KAPS generated more than $650 million in labour income and 7.7 million people hours. Now in service, KAPS plays a key role in positioning Alberta as an integral conduit for petrochemical and upgrading feedstock in the region and a competitive world class destination for growth and investment today and tomorrow.
"This year Keyera celebrated our 25th anniversary, and we look forward to continuing to collaborate with the communities along the KAPS pipeline route for the next 25," says Setoguchi. "In recognition of today's celebration and in commitment to these communities, we are investing $300,000 from our Keyera Connects Social Investment Program into partnerships focused on capacity building and sustainability."
"KAPS is more than a pipeline, it's truly an energy infrastructure solution that is helping to unlock partnership and prosperity through a purposeful approach," says Dean Setoguchi, President & CEO of Keyera. "The support KAPS has received is a testament to both commercial need and the listen-first approach Keyera takes with external stakeholders and Indigenous communities. KAPS has been years in the making, and it is the platform that propels us forward and lets us focus on what we do best – supply responsibly produced Canadian energy."
The KAPS pipeline will safely transport 350,000 barrels per day of NGLs and condensate from the liquids-rich Montney and Duvernay basins to Keyera's liquids processing and storage hub in Alberta's Industrial Heartland, located in Fort Saskatchewan. By providing a competitive transportation alternative that allows producers to grow natural gas production, KAPS is advancing Alberta's energy industry. This highly desired industry pipeline solution is designed to integrate services, generate more volumes, and expand commercial opportunities; all of which drives benefit for Alberta and fuels greater domestic economic growth.
"The completion of the KAPS pipeline represents a significant milestone in the expansion of natural gas production in Western Canada. As natural gas continues to be a key contributor to the global energy mix and energy transition, especially in East Asia, we believe that KAPS has a critical role to play," says Anthony Borreca, Senior Managing Director at Stonepeak. "KAPS has the ability to support decarbonization and energy security goals on a local and global level and we look forward to continuing to partner with Keyera as responsible stewards of this asset as production gets underway."
Integral to the successful construction and completion of KAPS was Keyera's engagement and partnerships with communities along the pipeline route, including 10 municipalities, 22 Indigenous communities and 60 Indigenous-owned or affiliated businesses. Determining the pipeline route was a collaborative effort that extended well beyond regulatory, environmental, safety and land factors. It included input from traditional land use studies from each Indigenous community, approximately 400 site visits with Rights holders, and the approval of nearly 600 landowners and occupants.
"This is such great news for Keyera, its partners, and for Alberta," says the Honourable, Danielle Smith, Premier of Alberta. "KAPS is furthering economic opportunity and prosperity for Indigenous partners and communities as well as for the entire province. I'm excited to see the positive impacts this project will have and the economic growth we'll see in the years to come."
During construction, KAPS generated more than $650 million in labour income and 7.7 million people hours. Now in service, KAPS plays a key role in positioning Alberta as an integral conduit for petrochemical and upgrading feedstock in the region and a competitive world class destination for growth and investment today and tomorrow.
"This year Keyera celebrated our 25th anniversary, and we look forward to continuing to collaborate with the communities along the KAPS pipeline route for the next 25," says Setoguchi. "In recognition of today's celebration and in commitment to these communities, we are investing $300,000 from our Keyera Connects Social Investment Program into partnerships focused on capacity building and sustainability."
Monday 2 October 2023
Eni announces a significant gas discovery in the Kutei Basin in Indonesia
Eni announces a significant gas discovery from the Geng North-1 exploration well drilled in North Ganal PSC, about 85 km off the cost of East Kalimantan in Indonesia. Preliminary estimates indicate a total structure discovered volume of 5 trillion cubic feet (Tcf) of gas in place with a content of condensate estimated up to 400 Mbbls; the acquired data will allow to study the options for a fast-track development.
Geng North-1 was drilled to a depth of 5,025 meters in 1,947 meters water depth, encountered a gas column about 50m thick in a Miocene sandstone reservoir with excellent petrophysical properties that has been subject of an extensive data acquisition campaign. A well production test (DST) has been successfully performed for a full assessment of the gas discovery and although limited by the test facilities, it has allowed to estimate a well capacity of up to 80-100 mmscfd and about 5-6 kbbld of condensate.
The discovery confirms the effectiveness of Eni’s strategy aimed at creating value through its deep knowledge of geological plays and the application of advanced geophysical technologies. The ongoing exploration campaign, along with the recent acquisitions, is in line with Eni’s energy transition strategy to progressively shift its portfolio mix towards gas and LNG, targeting 60% in 2030, and to increase its LNG equity portfolio. Indonesia, and South-East Asia in general, play a relevant role in this strategy.
Thanks to its location and significant size, the discovery has the potential to contribute substantially to the creation of a new production hub, in the Northern part of the Kutei Basin, to be connected to the Bontang LNG facilities on the coast of East Kalimantan, further exploiting its available ullage capacity. It is estimated that, in addition to Geng North, more than 5 Tcf of gas in place are present in undeveloped discoveries within the area of interest, while a significant multi-Tcf exploration potential is under maturation through the ongoing studies.
The Geng North discovery is adjacent to the Indonesia Deepwater Development (IDD) area that includes several stranded discoveries located within the Rapak and Ganal PSC blocks, for which Eni recently announced the acquisition of Chevron interests, increasing its participating interest and acquiring the operatorship. Significant synergies between the two areas are envisaged in terms of gas development options. The acquisition also provides the opportunity to fast track the development of the Gendalo and Gandang gas project (around 2 Tcf of gas reserves) through Eni’s operated Jangkrik facilities.
The Geng North discovery comes shortly after the announcement of Eni’s agreement to acquire Neptune Energy, whose completion will allow to further strengthen Eni’s position in the North Ganal Block.
Eni North Ganal Limited, holding 50.22% participating interest, operate the Block, with Neptune Energy North Ganal BV and Agra Energi I Pte Ltd as partners, holding the remaining 38.04% and 11.74% respectively.
Eni has been operating in Indonesia since 2001 and currently has a large portfolio of assets in exploration, development, and production phases with a current equity production of approximately 80,000 barrels of oil equivalent per day from the Jangkrik and Merakes fields in East Kalimantan.
Geng North-1 was drilled to a depth of 5,025 meters in 1,947 meters water depth, encountered a gas column about 50m thick in a Miocene sandstone reservoir with excellent petrophysical properties that has been subject of an extensive data acquisition campaign. A well production test (DST) has been successfully performed for a full assessment of the gas discovery and although limited by the test facilities, it has allowed to estimate a well capacity of up to 80-100 mmscfd and about 5-6 kbbld of condensate.
The discovery confirms the effectiveness of Eni’s strategy aimed at creating value through its deep knowledge of geological plays and the application of advanced geophysical technologies. The ongoing exploration campaign, along with the recent acquisitions, is in line with Eni’s energy transition strategy to progressively shift its portfolio mix towards gas and LNG, targeting 60% in 2030, and to increase its LNG equity portfolio. Indonesia, and South-East Asia in general, play a relevant role in this strategy.
Thanks to its location and significant size, the discovery has the potential to contribute substantially to the creation of a new production hub, in the Northern part of the Kutei Basin, to be connected to the Bontang LNG facilities on the coast of East Kalimantan, further exploiting its available ullage capacity. It is estimated that, in addition to Geng North, more than 5 Tcf of gas in place are present in undeveloped discoveries within the area of interest, while a significant multi-Tcf exploration potential is under maturation through the ongoing studies.
The Geng North discovery is adjacent to the Indonesia Deepwater Development (IDD) area that includes several stranded discoveries located within the Rapak and Ganal PSC blocks, for which Eni recently announced the acquisition of Chevron interests, increasing its participating interest and acquiring the operatorship. Significant synergies between the two areas are envisaged in terms of gas development options. The acquisition also provides the opportunity to fast track the development of the Gendalo and Gandang gas project (around 2 Tcf of gas reserves) through Eni’s operated Jangkrik facilities.
The Geng North discovery comes shortly after the announcement of Eni’s agreement to acquire Neptune Energy, whose completion will allow to further strengthen Eni’s position in the North Ganal Block.
Eni North Ganal Limited, holding 50.22% participating interest, operate the Block, with Neptune Energy North Ganal BV and Agra Energi I Pte Ltd as partners, holding the remaining 38.04% and 11.74% respectively.
Eni has been operating in Indonesia since 2001 and currently has a large portfolio of assets in exploration, development, and production phases with a current equity production of approximately 80,000 barrels of oil equivalent per day from the Jangkrik and Merakes fields in East Kalimantan.
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