Chevron Corporation (NYSE: CVX) announced today that its 50 percent owned affiliate Tengizchevroil LLP (TCO) has safely commenced operations at its Wellhead Pressure Management Project (WPMP) at the Tengiz oil field in Kazakhstan.
TCO achieved this milestone by converting its first metering station at Tengiz to low pressure and activating the associated Pressure Boost Facility (PBF). This marks important progress for TCO’s overall expansion project at Tengiz.
The WPMP is designed to maintain the existing processing plants’ full capacity (approx. 28 million tonnes per annum), by lowering the flowing pressure at the wellheads and then boosting the pressure to the existing plants.
“This is a significant step towards completion of the Future Growth Project (FGP). It is also important progress for the modernization of the existing base business at Tengiz and demonstrates TCO’s commitment to safely and reliably manage operations, while maximizing the ultimate recovery of resources critical to global energy security,” said Clay Neff, President of Chevron International Exploration and Production.
The start-up of additional PBF compressors and the conversion of the remaining metering stations in the oil gathering system at Tengiz, from high pressure to low pressure, is scheduled for completion through the remainder of the year.
The final phase of TCO’s expansion project, FGP, is on track to conclude in the first half of 2025. This will enable TCO to expand Tengiz crude oil production by an incremental 12 million tons per annum (260,000 barrels a day).
“This accomplishment highlights the vital role of partnership. Together with the Republic of Kazakhstan and our other partners, we have safely started operations at the WPMP, which is a positive development as we continue our focus on the FGP-WPMP expansion project,” said Derek Magness, Managing Director of Chevron’s Eurasia Business Unit.
Sunday 28 April 2024
Thursday 25 April 2024
Transformational combination of substantially all of Eni’s UK upstream operations with Ithaca Energy, creating a leading United Kingdom Continental Shelf production and growth company
Eni S.p.A. (“Eni”) is pleased to announce today that it has reached an agreement on the combination of substantially all of its upstream assets in the UK, excluding East Irish Sea assets and CCUS activities (“Eni UK Business”) with Ithaca Energy plc, (“Ithaca”), marking a strategic move to significantly strengthen its presence on the UK Continental Shelf (the "UKCS") (the “Combination”).
Under the terms of the business combination agreement Eni and Ithaca will combine the Eni UK Business with the existing Ithaca business. The Combination is being funded through the issue to Eni UK of such number of new ordinary shares that represents 38.5% of the enlarged issued share capital of Ithaca. The economic effective date for the Combination will be 30 June 2024, with Completion expected in Q3 2024, subject to the satisfaction of certain regulatory and other customary conditions precedent. Certain customary cash adjustments will be made for, amongst other things, cash, financial debt and working capital, each as at the economic effective date.
Ithaca is one of the largest independent oil and gas companies on the UKCS, with a substantial resource base and playing a key role in energy supply security in the region, with stakes in six of the ten largest fields and the top two largest development fields on the UKCS.
The Combination will immediately create an enlarged and stronger Combined Group with 2024 production greater than 100,000 boepd and the underlying potential to organically grow to 150,0001 boepd by the early 2030s. The Combination is aimed at replicating the previous successful execution of upstream combinations that Eni has formed using its distinctive Satellite Model (including Vår Energi in Norway and Azule Energy in Angola). The Satellite Model is a strategic response to the challenges and opportunities of energy markets, creating focussed and lean companies able to attract new capital to create value through operating and financial synergies and the acceleration of growth. The Combination will allow Eni to continue pursuing its successful growth on the UKCS, thereby strengthening its commitment to the UK post the Neptune Energy acquisition. Eni will be a fully committed, long-term and supportive shareholder of Ithaca, and will bring its world class technical capabilities and operational support to benefit the Combination.
Commenting on the Combination, Eni’s CEO, Claudio Descalzi, said: “This agreement represents a further example of Eni adapting to the demands of the changing energy market and in this case deploying our successful Satellite Model. It affords the opportunity to build scale, realising efficient upstream growth and maximising value under a dedicated and focused management structure supported by Eni resources and expertise. The combination with Ithaca represents an exciting opportunity for us to bring together complementary portfolios establishing a material position on the UKCS with significant growth and optimisation opportunities. We have moved quickly after the acquisition by Eni of Neptune Energy to transform our competitive position in the UK and we see the opportunity for Eni and Ithaca to realise material long-term value in helping to address the key challenges of security, affordability and sustainability of energy supply. Indeed, establishing a leading position in the UK upstream market will mirror our equally strong position in CCS with our Hynet and Bacton Thames projects which together with 3 other CO2 storage licences gives us around 1Giga Tonn of gross storage capacity and will see us become a key player in the decarbonisation of the UK’s hard-to-abate industries. With our significant investment as a partner in the giant Dogger Bank offshore wind farm, Eni is pleased to be a major player across key activities in the UK’s energy sector.”
Combination Highlights
The Combination will result in Eni becoming a significant minority shareholder in the leading independent UKCS operator, with:
Immediately accretive to CFFO, providing enhanced flexibility and optionality for shareholder returns and growthComplementary portfolio unlocks potential for material long-term organic growth with significant value to be unlocked through operational and financial synergies
Organic growth potential to increase the Combined Group’s production to potentially over 150,000 boepd by the early 2030s
Strong cash flow generation and scale of operations create optionality for future shareholder returns as well as inorganic investment to deliver further growth
The Combination is expected to improve Ithaca’s credit rating with a pathway towards investment grade
Committed 2024 and 2025 dividend of 30% post-tax CFFO with an ambition for special dividends to increase total shareholder distributions to up to $500 million per annum, including through special dividends as required. All dividends are subject to operational performance and commodity prices as well as Combined Group refinancing
Tangible benefits to be derived from Eni as a long-term supportive shareholder of the Combined GroupAs part of the transaction, the Combined Group to enter into a technical services agreement with Eni, enabling it to leverage Eni’s leading operational capabilities and leadership to support future growth plans, all areas where Eni has a strong track-record
Potential for the Combined Group to benefit from (i) Eni’s operational support, including access to subsurface technical expertise and Eni’s innovation centre as well as suite of digital tools, and (ii) Eni’s world class exploration capabilities, including access to proprietary supercomputer and rigorous screening process
Relationship Agreement and Corporate Governance
At Completion, Eni will enter into a relationship agreement with Ithaca on substantially similar terms to the relationship between Delek and Ithaca Energy. This will entitle Eni, for so long as it directly or indirectly holds greater than 20% of the Combined Group’s issued share capital, the right to appoint two non-executive directors to the Ithaca Board and for so long as it holds greater than 25% of the Combined Group’s issued share capital, to appoint one observer to the Remuneration Committee and the Audit and Risk Committee; and appoint one director to the Nomination and Governance Committee.
From Completion, it is anticipated that Eni will be entitled to recommend the nomination of the next proposed CEO of the Combined Group in accordance with the policies and processes of Ithaca’s Nomination and Governance Committee.
Further information on the composition of the board of directors of the Combined Group, and other senior management appointments, will be announced in due course.
Free Float
As a consequence of the issue of shares to Eni UK, and Ithaca’s existing shareholder structure, the Combination would result in the number of ordinary shares in public hands being 7%, and below the minimum 10% as required by the Financial Conduct Authority listing rules. Therefore, in order to ensure that the number of ordinary shares in public hands remains at or above 10%, Delek has undertaken to sell-down approximately 3% of the enlarged issued share capital of Ithaca prior to Completion.
Delek will also enter into a call option arrangement with Eni UK, pursuant to which it will have the option to require Eni UK to transfer to Delek such shares in Ithaca as represents approximately 1% of the enlarged issued share capital. Once the sell down is complete and if this call option is exercised, Delek will hold 52.7% and Eni will hold 37.3% of Ithaca’s ordinary shares, with 10% of Ithaca’s ordinary shares being held in public hands.
Under the terms of the business combination agreement Eni and Ithaca will combine the Eni UK Business with the existing Ithaca business. The Combination is being funded through the issue to Eni UK of such number of new ordinary shares that represents 38.5% of the enlarged issued share capital of Ithaca. The economic effective date for the Combination will be 30 June 2024, with Completion expected in Q3 2024, subject to the satisfaction of certain regulatory and other customary conditions precedent. Certain customary cash adjustments will be made for, amongst other things, cash, financial debt and working capital, each as at the economic effective date.
Ithaca is one of the largest independent oil and gas companies on the UKCS, with a substantial resource base and playing a key role in energy supply security in the region, with stakes in six of the ten largest fields and the top two largest development fields on the UKCS.
The Combination will immediately create an enlarged and stronger Combined Group with 2024 production greater than 100,000 boepd and the underlying potential to organically grow to 150,0001 boepd by the early 2030s. The Combination is aimed at replicating the previous successful execution of upstream combinations that Eni has formed using its distinctive Satellite Model (including Vår Energi in Norway and Azule Energy in Angola). The Satellite Model is a strategic response to the challenges and opportunities of energy markets, creating focussed and lean companies able to attract new capital to create value through operating and financial synergies and the acceleration of growth. The Combination will allow Eni to continue pursuing its successful growth on the UKCS, thereby strengthening its commitment to the UK post the Neptune Energy acquisition. Eni will be a fully committed, long-term and supportive shareholder of Ithaca, and will bring its world class technical capabilities and operational support to benefit the Combination.
Commenting on the Combination, Eni’s CEO, Claudio Descalzi, said: “This agreement represents a further example of Eni adapting to the demands of the changing energy market and in this case deploying our successful Satellite Model. It affords the opportunity to build scale, realising efficient upstream growth and maximising value under a dedicated and focused management structure supported by Eni resources and expertise. The combination with Ithaca represents an exciting opportunity for us to bring together complementary portfolios establishing a material position on the UKCS with significant growth and optimisation opportunities. We have moved quickly after the acquisition by Eni of Neptune Energy to transform our competitive position in the UK and we see the opportunity for Eni and Ithaca to realise material long-term value in helping to address the key challenges of security, affordability and sustainability of energy supply. Indeed, establishing a leading position in the UK upstream market will mirror our equally strong position in CCS with our Hynet and Bacton Thames projects which together with 3 other CO2 storage licences gives us around 1Giga Tonn of gross storage capacity and will see us become a key player in the decarbonisation of the UK’s hard-to-abate industries. With our significant investment as a partner in the giant Dogger Bank offshore wind farm, Eni is pleased to be a major player across key activities in the UK’s energy sector.”
Combination Highlights
The Combination will result in Eni becoming a significant minority shareholder in the leading independent UKCS operator, with:
- Increased scale and asset diversification, with strategic interests in key assets on the UKCS Proforma 2024 production of 100,000 to 110,000 boepd with potential to become the largest operator on the UKCS by production in 2030
- Material combined long-life 2P reserves and 2C resources base of 658[3] mmboe, with resource life in excess of 15 years based on 2023 pro-forma production, with interest in 37 producing assets, and stakes in 6 of the 10 largest fields on the UKCS (including Rosebank, Cambo, Schiehallion, Mariner Area, Elgin/Franklin and J-Area)
- The Combination to create a diversified and balanced portfolio, with 49% gas weighting based on 2023 pro-forma production
Immediately accretive to CFFO, providing enhanced flexibility and optionality for shareholder returns and growthComplementary portfolio unlocks potential for material long-term organic growth with significant value to be unlocked through operational and financial synergies
Organic growth potential to increase the Combined Group’s production to potentially over 150,000 boepd by the early 2030s
Strong cash flow generation and scale of operations create optionality for future shareholder returns as well as inorganic investment to deliver further growth
The Combination is expected to improve Ithaca’s credit rating with a pathway towards investment grade
Committed 2024 and 2025 dividend of 30% post-tax CFFO with an ambition for special dividends to increase total shareholder distributions to up to $500 million per annum, including through special dividends as required. All dividends are subject to operational performance and commodity prices as well as Combined Group refinancing
Tangible benefits to be derived from Eni as a long-term supportive shareholder of the Combined GroupAs part of the transaction, the Combined Group to enter into a technical services agreement with Eni, enabling it to leverage Eni’s leading operational capabilities and leadership to support future growth plans, all areas where Eni has a strong track-record
Potential for the Combined Group to benefit from (i) Eni’s operational support, including access to subsurface technical expertise and Eni’s innovation centre as well as suite of digital tools, and (ii) Eni’s world class exploration capabilities, including access to proprietary supercomputer and rigorous screening process
Relationship Agreement and Corporate Governance
At Completion, Eni will enter into a relationship agreement with Ithaca on substantially similar terms to the relationship between Delek and Ithaca Energy. This will entitle Eni, for so long as it directly or indirectly holds greater than 20% of the Combined Group’s issued share capital, the right to appoint two non-executive directors to the Ithaca Board and for so long as it holds greater than 25% of the Combined Group’s issued share capital, to appoint one observer to the Remuneration Committee and the Audit and Risk Committee; and appoint one director to the Nomination and Governance Committee.
From Completion, it is anticipated that Eni will be entitled to recommend the nomination of the next proposed CEO of the Combined Group in accordance with the policies and processes of Ithaca’s Nomination and Governance Committee.
Further information on the composition of the board of directors of the Combined Group, and other senior management appointments, will be announced in due course.
Free Float
As a consequence of the issue of shares to Eni UK, and Ithaca’s existing shareholder structure, the Combination would result in the number of ordinary shares in public hands being 7%, and below the minimum 10% as required by the Financial Conduct Authority listing rules. Therefore, in order to ensure that the number of ordinary shares in public hands remains at or above 10%, Delek has undertaken to sell-down approximately 3% of the enlarged issued share capital of Ithaca prior to Completion.
Delek will also enter into a call option arrangement with Eni UK, pursuant to which it will have the option to require Eni UK to transfer to Delek such shares in Ithaca as represents approximately 1% of the enlarged issued share capital. Once the sell down is complete and if this call option is exercised, Delek will hold 52.7% and Eni will hold 37.3% of Ithaca’s ordinary shares, with 10% of Ithaca’s ordinary shares being held in public hands.
Thursday 18 April 2024
TechnipFMC Awarded Large Subsea Contract for ExxonMobil Guyana’s Whiptail Project
TechnipFMC (NYSE: FTI) (the “Company”) has been awarded a large1 contract in Guyana’s Stabroek Block by Exxon Mobil Corporation (NYSE: XOM) affiliate ExxonMobil Guyana Limited to supply subsea production systems for the Whiptail project.
TechnipFMC will provide project management, engineering, and manufacturing to deliver 48 subsea trees and associated tooling, as well as 12 manifolds and associated controls and tie-in equipment.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “ExxonMobil Guyana will utilize our Subsea 2.0® systems and manifolds, which help provide schedule certainty. We have already delivered more than 100 subsea trees for ExxonMobil Guyana – the location of one of the world’s fastest developing basins – and we look forward to deepening our relationship with them through Whiptail.”
TechnipFMC currently employs nearly 140 Guyanese, and expects to continue to hire and train additional local staff in support of this award.
Whiptail is TechnipFMC’s most recent award from ExxonMobil Guyana, where the Company has been awarded subsea production system contracts since the first contract award in 2017 for Liza Phase 1.
TechnipFMC will provide project management, engineering, and manufacturing to deliver 48 subsea trees and associated tooling, as well as 12 manifolds and associated controls and tie-in equipment.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “ExxonMobil Guyana will utilize our Subsea 2.0® systems and manifolds, which help provide schedule certainty. We have already delivered more than 100 subsea trees for ExxonMobil Guyana – the location of one of the world’s fastest developing basins – and we look forward to deepening our relationship with them through Whiptail.”
TechnipFMC currently employs nearly 140 Guyanese, and expects to continue to hire and train additional local staff in support of this award.
Whiptail is TechnipFMC’s most recent award from ExxonMobil Guyana, where the Company has been awarded subsea production system contracts since the first contract award in 2017 for Liza Phase 1.
Friday 12 April 2024
SBM Offshore Awarded Contracts for ExxonMobil Guyana’s FPSO Jaguar
SBM Offshore is pleased to announce that ExxonMobil Guyana Limited (“EMGL”) has confirmed the award of contracts for the Whiptail development project located in the Stabroek Block in Guyana. Under these contracts, SBM Offshore will construct and install FPSO Jaguar. Ownership will transfer to EMGL prior to the FPSO’s installation in Guyana, and SBM Offshore expects to operate the FPSO for 10 years under the Operations and Maintenance Enabling Agreement signed in 2023. The award follows completion of front-end engineering and design studies, receipt of requisite government approvals and the final investment decision on the project by ExxonMobil and block co-venturers.
The Whiptail development is the sixth development within the Stabroek block, circa 200 kilometers offshore Guyana. EMGL is the operator and holds a 45 percent interest in the Stabroek block, Hess Guyana Exploration Ltd. holds a 30 percent interest and CNOOC Petroleum Guyana Limited, holds a 25 percent interest.
The FPSO Jaguar’s design is based on SBM Offshore’s industry leading Fast4Ward® program that incorporates the Company’s 7th 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.
SBM Offshore remains committed to working with Guyanese companies and will continue to expand these activities. More Guyanese engineers will be recruited and employed as part of the FPSO Jaguar project team.
The Whiptail development is the sixth development within the Stabroek block, circa 200 kilometers offshore Guyana. EMGL is the operator and holds a 45 percent interest in the Stabroek block, Hess Guyana Exploration Ltd. holds a 30 percent interest and CNOOC Petroleum Guyana Limited, holds a 25 percent interest.
The FPSO Jaguar’s design is based on SBM Offshore’s industry leading Fast4Ward® program that incorporates the Company’s 7th 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.
SBM Offshore remains committed to working with Guyanese companies and will continue to expand these activities. More Guyanese engineers will be recruited and employed as part of the FPSO Jaguar project team.
Tuesday 2 April 2024
MODEC secures FEED for Shell’s Gato do Mato FPSO project in Brazil
MODEC Inc. (“MODEC”) is pleased to announce that it has been successful in securing the Front-End Engineering and Design (FEED) for a Floating Production, Storage and Offloading (FPSO) system for Shell do Brasil Ltda (“Shell”) on the Gato do Mato development, offshore Brazil.
Gato do Mato FPSO will be moored at a water depth of approximately 2,000m, some 250km off the coast of Brazil. MODEC will be responsible for the design of the hull and all related topsides facilities for the FPSO, which is projected to be moored by a SOFEC Spread Mooring system. The produced stabilized crude will be stored in the FPSO tanks and the oil will be offloaded to shuttle tankers to go to market.
MODEC has previously delivered sixteen (16) FPSOs to Brazil and has two (2) more under construction currently. The FPSO Gato do Mato would be the second unit to be delivered directly to Shell by MODEC for operation in Brazil.
MODEC President and CEO, Hirohiko Miyata, expressed his delight in securing the FEED project. “MODEC is proud to be working on its nineteenth (19th) FPSO for Brazil and our second for Shell in Brazil. This milestone indicates the strong relationship between the two companies which now spans more than 20 years. We are excited about performing this FEED study for Shell.”
Gato do Mato FPSO will be moored at a water depth of approximately 2,000m, some 250km off the coast of Brazil. MODEC will be responsible for the design of the hull and all related topsides facilities for the FPSO, which is projected to be moored by a SOFEC Spread Mooring system. The produced stabilized crude will be stored in the FPSO tanks and the oil will be offloaded to shuttle tankers to go to market.
MODEC has previously delivered sixteen (16) FPSOs to Brazil and has two (2) more under construction currently. The FPSO Gato do Mato would be the second unit to be delivered directly to Shell by MODEC for operation in Brazil.
MODEC President and CEO, Hirohiko Miyata, expressed his delight in securing the FEED project. “MODEC is proud to be working on its nineteenth (19th) FPSO for Brazil and our second for Shell in Brazil. This milestone indicates the strong relationship between the two companies which now spans more than 20 years. We are excited about performing this FEED study for Shell.”
Aramco awards $7.7 billion contracts to add 1.5 bscfd of raw gas to Fadhili Gas Plant
Aramco, one of the world’s leading integrated energy and chemicals companies, today awarded engineering, procurement and construction (EPC) contracts worth $7.7 billion for a major expansion of its Fadhili Gas Plant in the Eastern Province of Saudi Arabia. The project is expected to increase the plant’s processing capacity from 2.5 to up to 4 billion standard cubic feet per day (bscfd).
This additional 1.5 bscfd of processing capacity is expected to contribute to the company’s strategy to raise gas production by more than 60% by 2030, compared to 2021 levels. The Fadhili Gas Plant expansion, which is expected to be completed by November 2027, is also expected to add an additional 2,300 metric tons per day to sulphur production.
Wail Al Jaafari, Aramco Executive Vice President of Technical Services, said: “The award of these contracts reflects Aramco’s goal to increase supplies of natural gas, help efforts to reduce greenhouse gas emissions, and free up more crude oil for value-added refining and export. Together with leading international companies, we are advancing our goal to increase gas production. The expansion also supports our ambitions to develop a lower-carbon hydrogen business, while associated liquids from gas are an important feedstock for the petrochemical industry.”
Aramco awarded EPC contracts for the Fadhili Gas Plant increment project to SAMSUNG Engineering Company, GS Engineering & Construction Corporation, and Nesma & Partners.
This additional 1.5 bscfd of processing capacity is expected to contribute to the company’s strategy to raise gas production by more than 60% by 2030, compared to 2021 levels. The Fadhili Gas Plant expansion, which is expected to be completed by November 2027, is also expected to add an additional 2,300 metric tons per day to sulphur production.
Wail Al Jaafari, Aramco Executive Vice President of Technical Services, said: “The award of these contracts reflects Aramco’s goal to increase supplies of natural gas, help efforts to reduce greenhouse gas emissions, and free up more crude oil for value-added refining and export. Together with leading international companies, we are advancing our goal to increase gas production. The expansion also supports our ambitions to develop a lower-carbon hydrogen business, while associated liquids from gas are an important feedstock for the petrochemical industry.”
Aramco awarded EPC contracts for the Fadhili Gas Plant increment project to SAMSUNG Engineering Company, GS Engineering & Construction Corporation, and Nesma & Partners.
Thursday 28 March 2024
McDermott Awarded Offshore Contract from PTTEP
McDermott has been awarded a sizeable* offshore transportation, installation and commissioning contract from PTTEP Sabah Oil Limited (PTTEP) for the Kikeh subsea gas lift project, located 75 miles (120 kilometers) northwest of the island of Labuan, offshore Sabah in East Malaysia.
Under the scope of the contract, McDermott will remove the existing flexible gas lift riser and perform the installation and commissioning of a new dynamic riser section and flowline comprised of two thermoplastic composite pipe jumpers. This will enable gas delivery to a subsea production system tied back to the Kikeh floating production, storage and offloading (FPSO) vessel.
"McDermott is uniquely positioned to deliver this project, having performed the installation of subsea infrastructure in the Kikeh field between 2011 and 2012, and again in 2014, in the nearby Siakap North-Petai field," said Mahesh Swaminathan, McDermott's Senior Vice President, Subsea and Floating Facilities. "We pioneered reel-lay installation for pipe-in-pipe production and water injection flowlines in the region, underscoring our commitment to engineering innovation. Returning to the Kikeh field not only reaffirms our expertise, but also presents another opportunity to deliver exceptional results through our unmatched experience in offshore transportation, subsea installations, and commissioning."
Project management and engineering will be executed from Kuala Lumpur, Malaysia, with support from other McDermott offices.
Operated by PTTEP on behalf of partner Petronas Carigali and PT Pertamina Malaysia Exploration Production, the Kikeh field has been producing from the existing Kikeh FPSO since 2007. The Kikeh FPSO is the first and largest deepwater FPSO in Malaysia.
*McDermott defines a sizeable contract as between USD $1 million and USD $50 million.
Under the scope of the contract, McDermott will remove the existing flexible gas lift riser and perform the installation and commissioning of a new dynamic riser section and flowline comprised of two thermoplastic composite pipe jumpers. This will enable gas delivery to a subsea production system tied back to the Kikeh floating production, storage and offloading (FPSO) vessel.
"McDermott is uniquely positioned to deliver this project, having performed the installation of subsea infrastructure in the Kikeh field between 2011 and 2012, and again in 2014, in the nearby Siakap North-Petai field," said Mahesh Swaminathan, McDermott's Senior Vice President, Subsea and Floating Facilities. "We pioneered reel-lay installation for pipe-in-pipe production and water injection flowlines in the region, underscoring our commitment to engineering innovation. Returning to the Kikeh field not only reaffirms our expertise, but also presents another opportunity to deliver exceptional results through our unmatched experience in offshore transportation, subsea installations, and commissioning."
Project management and engineering will be executed from Kuala Lumpur, Malaysia, with support from other McDermott offices.
Operated by PTTEP on behalf of partner Petronas Carigali and PT Pertamina Malaysia Exploration Production, the Kikeh field has been producing from the existing Kikeh FPSO since 2007. The Kikeh FPSO is the first and largest deepwater FPSO in Malaysia.
*McDermott defines a sizeable contract as between USD $1 million and USD $50 million.
Tuesday 26 March 2024
Successful installation of Fénix Platform off the coast of Argentina
Wintershall Dea and its partners TotalEnergies (operator) and Pan American Energy have successfully completed the installation of the Fénix platform, around 60 kilometer off the coast of Tierra del Fuego, in 70 meter water depth.
“The successful installation of the production platform marks another significant milestone for the Fénix field development, which keeps the project on track for the planned first gas in Q4 2024”, says Manfred Boeckmann, Managing Director of Wintershall Dea Argentina. “Fénix represents a material pillar for the growing domestic gas production and will support Argentina to meet the increasing demand and to offset imports, by contributing significant natural gas volumes for more than 15 years to the country’s long-term energy supply”, Boeckmann adds.
Given the size of the project, the logistics and the installation of the 4,800 ton platform were carried out in two phases: first the installation of the jacket with four piles in January, followed by the successful lift and setting of the 1,500 ton deck topside.
Starting on January 8, the deck was transported from the Rosetti Marino shipyard in Italy to Tierra del Fuego within a month on board the heavy transport ship HTV Interocean II. Four vessels were involved in the installation of both parts of the platform, led by Heerema’s heavy lift vessel Aegir. All work was completed safely and without incident.
The deck of the Fénix platform covers a surface area of 2,500 square meter and consists of five levels: the helipad, the upper deck, the main deck with the wellheads and instrument room, and the lower deck. The platform is designed to be operated from shore without the need for a permanent crew.
“With the installation of the platform we have completed the surface facilities part of the Fénix development project within the targeted schedule”, underlines Mariano Cancelo, Vice President Production and Development at Wintershall Dea in Argentina. “Our focus will now switch to the next step, which is the drilling of three production wells”, he says.
The drilling of the wells will be executed with a jack-up drilling rig which will be temporarily located next to the Fénix platform. First gas production is envisaged in November 2024.
Fénix is part of the world’s southernmost gas production concession CMA-1 in which Wintershall Dea and TotalEnergies (operator) each hold a 37.5 per cent share while Pan American Energy holds the remaining 25 per cent.
“The successful installation of the production platform marks another significant milestone for the Fénix field development, which keeps the project on track for the planned first gas in Q4 2024”, says Manfred Boeckmann, Managing Director of Wintershall Dea Argentina. “Fénix represents a material pillar for the growing domestic gas production and will support Argentina to meet the increasing demand and to offset imports, by contributing significant natural gas volumes for more than 15 years to the country’s long-term energy supply”, Boeckmann adds.
Given the size of the project, the logistics and the installation of the 4,800 ton platform were carried out in two phases: first the installation of the jacket with four piles in January, followed by the successful lift and setting of the 1,500 ton deck topside.
Starting on January 8, the deck was transported from the Rosetti Marino shipyard in Italy to Tierra del Fuego within a month on board the heavy transport ship HTV Interocean II. Four vessels were involved in the installation of both parts of the platform, led by Heerema’s heavy lift vessel Aegir. All work was completed safely and without incident.
The deck of the Fénix platform covers a surface area of 2,500 square meter and consists of five levels: the helipad, the upper deck, the main deck with the wellheads and instrument room, and the lower deck. The platform is designed to be operated from shore without the need for a permanent crew.
“With the installation of the platform we have completed the surface facilities part of the Fénix development project within the targeted schedule”, underlines Mariano Cancelo, Vice President Production and Development at Wintershall Dea in Argentina. “Our focus will now switch to the next step, which is the drilling of three production wells”, he says.
The drilling of the wells will be executed with a jack-up drilling rig which will be temporarily located next to the Fénix platform. First gas production is envisaged in November 2024.
Fénix is part of the world’s southernmost gas production concession CMA-1 in which Wintershall Dea and TotalEnergies (operator) each hold a 37.5 per cent share while Pan American Energy holds the remaining 25 per cent.
Friday 22 March 2024
BlueNord: Tyra II Production Successfully Restarted
BlueNord ASA ("BlueNord" or the "Company") is pleased to announce that the Tyra Redevelopment Project ("Tyra" or "Tyra II") in the late hours on 21 March 2024 successfully reached an important milestone with the safe restart of production.
Since the acquisition of Shell’s upstream assets in Denmark in 2019, the Tyra Redevelopment Project has been the key focus for the Company and its partners in the Danish Underground Consortium (the “DUC”), and first production from Tyra II marks a true inflection-point for BlueNord and its stakeholders.
The Tyra Redevelopment Project is, to date, the largest project carried out on Danish Continental Shelf with the fabrication and installation of eight new platform topsides. With production from Tyra, Denmark will not only be self-sufficient but also a net-exporter of natural gas to Europe. The production from the new Tyra facilities is expected to more than double BlueNord’s net production to over 50 mboepd by the end of 2024 and unlock gross reserves of more than 200 mmboe. In addition, redeveloped Tyra will significantly decrease field opex and emissions intensity, and at the same time extend its field life by 25 years, only constrained by the 2042 license expiry.
“With restart of production today, the most important Tyra Redevelopment milestone has been achieved. I would like to thank TotalEnergies and the Tyra Project team for their commitment to the project and for safely restarting the production on Tyra. Focus is now on bringing the Tyra fields and satellites Valdemar, Roar, Harald and Svend on production through one of the most advanced and efficient offshore gas installations in the world,” said Marianne Eide, Chief Operating Officer of BlueNord.
“We are delighted to announce the restart of production from Tyra, marking a significant milestone in a journey that began for us nearly five years ago when we became a partner in the DUC. The successful delivery of this project is a monumental accomplishment that is a testament to the commitment, resilience, and perseverance of all parties involved, not only at BlueNord but also at TotalEnergies and Nordsøfonden. With a ramp-up that is expected to last four months, Tyra will shortly be a key supporter of energy security in the region, transforming Denmark from a net importer to a net exporter of natural gas and supporting the European Union in a manner that compares favourably to imported LNG. For BlueNord, this moment represents the beginning of a new journey: one that will see us more than double our production and, with the benefit of significantly increased free cash flow generation, fulfil our longstanding commitment to shareholder distributions. Today we celebrate not only a major accomplishment but also the bright future that Tyra will help us deliver for all our stakeholders,” said Euan Shirlaw, Chief Executive Officer of BlueNord
This information is subject to disclosure requirements pursuant to section 5-12 of the Norwegian Securities Trading Act.
Since the acquisition of Shell’s upstream assets in Denmark in 2019, the Tyra Redevelopment Project has been the key focus for the Company and its partners in the Danish Underground Consortium (the “DUC”), and first production from Tyra II marks a true inflection-point for BlueNord and its stakeholders.
The Tyra Redevelopment Project is, to date, the largest project carried out on Danish Continental Shelf with the fabrication and installation of eight new platform topsides. With production from Tyra, Denmark will not only be self-sufficient but also a net-exporter of natural gas to Europe. The production from the new Tyra facilities is expected to more than double BlueNord’s net production to over 50 mboepd by the end of 2024 and unlock gross reserves of more than 200 mmboe. In addition, redeveloped Tyra will significantly decrease field opex and emissions intensity, and at the same time extend its field life by 25 years, only constrained by the 2042 license expiry.
“With restart of production today, the most important Tyra Redevelopment milestone has been achieved. I would like to thank TotalEnergies and the Tyra Project team for their commitment to the project and for safely restarting the production on Tyra. Focus is now on bringing the Tyra fields and satellites Valdemar, Roar, Harald and Svend on production through one of the most advanced and efficient offshore gas installations in the world,” said Marianne Eide, Chief Operating Officer of BlueNord.
“We are delighted to announce the restart of production from Tyra, marking a significant milestone in a journey that began for us nearly five years ago when we became a partner in the DUC. The successful delivery of this project is a monumental accomplishment that is a testament to the commitment, resilience, and perseverance of all parties involved, not only at BlueNord but also at TotalEnergies and Nordsøfonden. With a ramp-up that is expected to last four months, Tyra will shortly be a key supporter of energy security in the region, transforming Denmark from a net importer to a net exporter of natural gas and supporting the European Union in a manner that compares favourably to imported LNG. For BlueNord, this moment represents the beginning of a new journey: one that will see us more than double our production and, with the benefit of significantly increased free cash flow generation, fulfil our longstanding commitment to shareholder distributions. Today we celebrate not only a major accomplishment but also the bright future that Tyra will help us deliver for all our stakeholders,” said Euan Shirlaw, Chief Executive Officer of BlueNord
This information is subject to disclosure requirements pursuant to section 5-12 of the Norwegian Securities Trading Act.
Wednesday 6 March 2024
Aramco adds significant volumes to proven gas and condensate reserves at Jafurah unconventional field
Aramco, one of the world’s leading integrated energy and chemicals companies, has added significant volumes to the proven gas and condensate reserves at the Jafurah unconventional field in the Kingdom of Saudi Arabia.
The Company has booked 15 trillion standard cubic feet (scf) of raw gas and two billion stock tank barrels (STB) of condensate as proven reserves at Jafurah. It now estimates that Jafurah contains a total resource of 229 trillion scf of raw gas, alongside an estimated 75 billion STB of condensate. These new estimates were calculated using a novel approach to shale reserves booking, which was applied to unconventional resources for the first time in the industry and has potential to be deployed at scale.
Reserve booking practices were assessed through establishing continuity of resources and consistency of performance. These new estimates were technically validated by respected industry reserves certification consultancy DeGolyer and MacNaughton, which reviewed the statistical booking mechanism and provided a fully independent assessment.
Amin H. Nasser, Aramco President & CEO, said: “This achievement enhances the Kingdom’s hydrocarbon wealth through proven reserves of gas, which is a vital resource for the energy and chemicals industries. Aramco’s upstream business is deploying state-of-the-art technologies including advanced modelling and artificial intelligence to make tangible progress in developing Jafurah, which is one of the company’s growth engines and an important economic resource for the Kingdom. The field represents a key element in our ambitious strategy to increase Aramco’s gas production.”
Work is currently underway to deliver production at Jafurah, with plans to ramp up to reach a sustainable sales gas rate of two billion scfd by 2030, in addition to significant volumes of ethane, Natural Gas Liquids (NGL) and condensate.
The Company has booked 15 trillion standard cubic feet (scf) of raw gas and two billion stock tank barrels (STB) of condensate as proven reserves at Jafurah. It now estimates that Jafurah contains a total resource of 229 trillion scf of raw gas, alongside an estimated 75 billion STB of condensate. These new estimates were calculated using a novel approach to shale reserves booking, which was applied to unconventional resources for the first time in the industry and has potential to be deployed at scale.
Reserve booking practices were assessed through establishing continuity of resources and consistency of performance. These new estimates were technically validated by respected industry reserves certification consultancy DeGolyer and MacNaughton, which reviewed the statistical booking mechanism and provided a fully independent assessment.
Amin H. Nasser, Aramco President & CEO, said: “This achievement enhances the Kingdom’s hydrocarbon wealth through proven reserves of gas, which is a vital resource for the energy and chemicals industries. Aramco’s upstream business is deploying state-of-the-art technologies including advanced modelling and artificial intelligence to make tangible progress in developing Jafurah, which is one of the company’s growth engines and an important economic resource for the Kingdom. The field represents a key element in our ambitious strategy to increase Aramco’s gas production.”
Work is currently underway to deliver production at Jafurah, with plans to ramp up to reach a sustainable sales gas rate of two billion scfd by 2030, in addition to significant volumes of ethane, Natural Gas Liquids (NGL) and condensate.
Thursday 22 February 2024
First Modules Arrive For Scarborough Energy Project
The first three Pluto Train 2 modules for the Scarborough Energy Project have arrived in Karratha, Western Australia, marking a significant milestone for the project. The modules, fabricated by Bechtel in Indonesia, weigh a combined total of more than 4,000 metric tonnes. The modules are three of a total of 51 that will be shipped to site from the module yard to form Pluto Train 2.
Pluto Train 2 will be the second Liquefied Natural Gas (LNG) production train at the existing Pluto LNG onshore facility and will process gas from the offshore Scarborough development. The Scarborough Energy Project will contribute significantly to the Australian economy and create thousands of job opportunities during its construction phase.
Bechtel was selected by Woodside Energy to execute the engineering, procurement and construction of Pluto Train 2, with construction activities beginning in November 2021. Pluto Train 2 will have an LNG processing capacity of approximately 5 million tonnes per annum (Mtpa). Additional domestic gas infrastructure will be installed at the Pluto LNG facility to increase domestic gas capacity to approximately 225 Terajoules per day. Up to 3 Mtpa of LNG will be processed at the existing Pluto Train 1 following modifications to accommodate Scarborough’s lean gas.
Woodside CEO Meg O’Neill said the delivery of the first Pluto Train 2 module was a key milestone towards the delivery of the Scarborough Energy Project, which will help meet the growing demand for the low-cost, lower-carbon, reliable energy the world needs today and into the future. “The safe and timely arrival of the module is testament to the hard work and dedication of the Woodside team and our lead contractor Bechtel. “With the Scarborough Energy Project sitting at more than 55% complete, we are making significant progress across all scopes of work and look forward to receiving the remaining modules on site throughout 2024,” she said.
"This achievement exemplifies our unwavering commitment to safety, quality and collaboration," said Paul Marsden, President of Bechtel Energy. "Fuelled by the passion to deliver excellence and foster sustainable practices, we are creating a lasting impact on the communities where we live and work. Our teams of extraordinary people, leveraging our global experience in delivering LNG projects, are instrumental in supporting the quality execution of the work on Pluto Train 2.”
The Scarborough Energy Project is targeting first LNG cargo in 2026.
Friday 16 February 2024
TechnipFMC Awarded Substantial iEPCI™ Contract for Sparta Project
TechnipFMC (NYSE: FTI) has been awarded a substantial(1) contract by Shell plc (FTSE: SHEL) (AMS: SHELL) (NYSE: SHEL) for the first integrated Engineering, Procurement, Construction, and Installation (iEPCI™) project to use high-pressure subsea production systems rated up to 20,000 psi (20K).
The Company will manufacture and install subsea production systems, umbilicals, risers, and flowlines for Shell’s Sparta development in the Gulf of Mexico. The tree systems will be Shell’s first to be qualified for 20K applications and are engineered to meet the high-pressure requirements of this greenfield development.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “Sparta will combine our leading-edge subsea technology with our proven integrated execution model, iEPCI™, providing improved project economics. We are excited to be working with Shell on 20K technology.”
The Company will manufacture and install subsea production systems, umbilicals, risers, and flowlines for Shell’s Sparta development in the Gulf of Mexico. The tree systems will be Shell’s first to be qualified for 20K applications and are engineered to meet the high-pressure requirements of this greenfield development.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “Sparta will combine our leading-edge subsea technology with our proven integrated execution model, iEPCI™, providing improved project economics. We are excited to be working with Shell on 20K technology.”
Friday 9 February 2024
Nigeria: Production commences at the Akpo West field
TotalEnergies and its partners announce the start of production from the Akpo West field on the PML2 license in Nigeria.
Located 135 kilometers off the coast, Akpo West is tied back to the existing Akpo Floating Production Storage and Offloading (FPSO) facility, which started-up in 2009 and produced 124,000 barrels of oil equivalent per day in 2023. By mid-2024, Akpo West will add 14,000 barrels of condensate production per day, to be followed by up to 4 million cubic meters of gas per day by 2028.
The Akpo West development leverages the existing Akpo facilities to keep costs low and minimize greenhouse gas emissions. The project’s carbon intensity is expected to be below 5 kg CO2e/boe and will contribute to reduce the average carbon intensity of TotalEnergies’ portfolio.
“After Ikike in 2022, TotalEnergies is pleased to start production of another tie-back project in Nigeria, Akpo West, which will contribute to maintaining the production of the existing Akpo facilities by developing additional nearby resources. This project fits the Company’s strategy of developing low-cost and low-emission projects”, said Mike Sangster, Senior Vice President Africa, Exploration and Production at TotalEnergies. “This project leverages TotalEnergies’ solid footprint in Nigeria and will quickly bring value to the country, TotalEnergies and its partners.”
TotalEnergies is the operator of PML2 with a 24% interest, in partnership with CNOOC (45%), Sapetro (15%), Prime 130 (16%) and the Nigerian National Petroleum Company Ltd as the concessionaire of the PSC.
Located 135 kilometers off the coast, Akpo West is tied back to the existing Akpo Floating Production Storage and Offloading (FPSO) facility, which started-up in 2009 and produced 124,000 barrels of oil equivalent per day in 2023. By mid-2024, Akpo West will add 14,000 barrels of condensate production per day, to be followed by up to 4 million cubic meters of gas per day by 2028.
The Akpo West development leverages the existing Akpo facilities to keep costs low and minimize greenhouse gas emissions. The project’s carbon intensity is expected to be below 5 kg CO2e/boe and will contribute to reduce the average carbon intensity of TotalEnergies’ portfolio.
“After Ikike in 2022, TotalEnergies is pleased to start production of another tie-back project in Nigeria, Akpo West, which will contribute to maintaining the production of the existing Akpo facilities by developing additional nearby resources. This project fits the Company’s strategy of developing low-cost and low-emission projects”, said Mike Sangster, Senior Vice President Africa, Exploration and Production at TotalEnergies. “This project leverages TotalEnergies’ solid footprint in Nigeria and will quickly bring value to the country, TotalEnergies and its partners.”
TotalEnergies is the operator of PML2 with a 24% interest, in partnership with CNOOC (45%), Sapetro (15%), Prime 130 (16%) and the Nigerian National Petroleum Company Ltd as the concessionaire of the PSC.
Wednesday 31 January 2024
Qatarenergy Announces The Award Of $6 Billion EPC Contracts To Increase Oil Production By About 100,000 Bpd From Al-Shaheen Oil Field
QatarEnergy has announced the award of the four main Engineering, Procurement, Construction, and Installation (EPCI) contract packages related to the next development phase of the offshore Al-Shaheen field (Qatar’s largest oil field) to increase production by about 100,000 barrels of oil per day (BPD).
The award is part of Project Ru’ya (vision in Arabic), which is the third phase of Al-Shaheen’s development since North Oil Company, a joint venture between QatarEnergy (70%) and TotalEnergies (30%), took over the field’s operation in July 2017.
Project Ru’ya, which will develop more than 550 million barrels of oil, will be executed over a period of 5 years with first oil expected in 2027. The project includes the drilling of more than 200 wells and the installation of a new centralized process complex, nine remote wellhead platforms, and associated pipelines.
The four EPC packages, with varying scopes of work, valued in total at more than six billion dollars, comprise of:
His Excellency Minister Al-Kaabi added: “I would like to thank North Oil Company and our longtime strategic partner TotalEnergies for their great efforts towards unlocking the true potential of Qatar’s hydrocarbon resources and maximizing value from Al-Shaheen field through the implementation of world-class development and operational excellence programs.”
Al-Shaheen field is located 80 kilometres offshore Qatar and is among the world’s largest in terms of “oil in place”. The field commenced commercial production in 1994 and underwent significant development to reach an oil production rate of 300,000 bpd in 2007.
The award is part of Project Ru’ya (vision in Arabic), which is the third phase of Al-Shaheen’s development since North Oil Company, a joint venture between QatarEnergy (70%) and TotalEnergies (30%), took over the field’s operation in July 2017.
Project Ru’ya, which will develop more than 550 million barrels of oil, will be executed over a period of 5 years with first oil expected in 2027. The project includes the drilling of more than 200 wells and the installation of a new centralized process complex, nine remote wellhead platforms, and associated pipelines.
The four EPC packages, with varying scopes of work, valued in total at more than six billion dollars, comprise of:
- the EPC package for 9 wellhead platforms valued at about $2.1 billion and awarded to a consortium of McDermott Middle East Inc. and Qingdao McDermott Wuchuan Offshore Engineering Co.;
- the EPC package for a Central Processing Platform valued at about $1.9 billion and awarded to a consortium of McDermott Middle East Inc. and Hyundai Heavy Industries;
- the EPC package for a riser platform valued at about $1.3 billion and awarded to Larsen & Toubro Limited; and
- the EPC package for subsea pipelines and cables valued at about $900 million and awarded to China Offshore Oil Engineering Co (COOEC).
His Excellency Minister Al-Kaabi added: “I would like to thank North Oil Company and our longtime strategic partner TotalEnergies for their great efforts towards unlocking the true potential of Qatar’s hydrocarbon resources and maximizing value from Al-Shaheen field through the implementation of world-class development and operational excellence programs.”
Al-Shaheen field is located 80 kilometres offshore Qatar and is among the world’s largest in terms of “oil in place”. The field commenced commercial production in 1994 and underwent significant development to reach an oil production rate of 300,000 bpd in 2007.
Friday 26 January 2024
McDermott and Baker Hughes Safely Complete Subsea Infrastructure in Northern Australia
McDermott, a premier engineering and construction company, and Baker Hughes, an energy technology company, today announced the safe completion of the installation of subsea infrastructure at the Ichthys field in northern Australia.
Awarded to the McDermott and Baker Hughes consortium in 2019 by INPEX Operations Australia P/L (INPEX), the subsea infrastructure development project included engineering, procurement, construction and installation (EPCI) of umbilicals, risers and flowlines (URF), a subsea production system comprised of a new 7-inch (approximately 18 centimeters) vertical Christmas tree (VXT) system, all forming a subsea well gathering system (GS4) tied back to the existing Ichthys Explorer central processing facility. The consortium’s scope of work also included an in-fill URF EPCI involving the development of new subsea wells tied in to the existing gathering systems.
“The McDermott and Baker Hughes partnership has been marked by resilience and adaptability, guided by our firm commitment to deliver for the INPEX-operated Ichthys LNG and Australia,” said Mahesh Swaminathan, McDermott’s Senior Vice President, Subsea and Floating Facilities. “Together, leveraging McDermott’s unique end-to-end EPCI capabilities and Baker Hughes’ subsea development solutions, we navigated project complexities and overcame the unique challenges posed by the pandemic. Our hard work paid off, and I would like to thank our teams in Perth, Batam, and beyond, whose collective efforts enabled the safe completion of this important work scope.”
“This milestone has been achieved through the successful partnership between Baker Hughes and McDermott to execute for INPEX,” said Romain Chambault, Baker Hughes Senior Vice President, Subsea Projects and Services. “The amount of collaboration shown between the consortium has been truly unique and serves as an industry benchmark for the successful execution of large, complex EPCI subsea projects. Manufacturing the highly complex 7-inch VXT from our dedicated SP&S facility in Batam has expanded the global capability for Baker Hughes in the Asia Pacific region where we are well-positioned to support customers with a strong regional capability, complemented by a strong McDermott presence in Batam and the region as a whole.”
Awarded to the McDermott and Baker Hughes consortium in 2019 by INPEX Operations Australia P/L (INPEX), the subsea infrastructure development project included engineering, procurement, construction and installation (EPCI) of umbilicals, risers and flowlines (URF), a subsea production system comprised of a new 7-inch (approximately 18 centimeters) vertical Christmas tree (VXT) system, all forming a subsea well gathering system (GS4) tied back to the existing Ichthys Explorer central processing facility. The consortium’s scope of work also included an in-fill URF EPCI involving the development of new subsea wells tied in to the existing gathering systems.
“The McDermott and Baker Hughes partnership has been marked by resilience and adaptability, guided by our firm commitment to deliver for the INPEX-operated Ichthys LNG and Australia,” said Mahesh Swaminathan, McDermott’s Senior Vice President, Subsea and Floating Facilities. “Together, leveraging McDermott’s unique end-to-end EPCI capabilities and Baker Hughes’ subsea development solutions, we navigated project complexities and overcame the unique challenges posed by the pandemic. Our hard work paid off, and I would like to thank our teams in Perth, Batam, and beyond, whose collective efforts enabled the safe completion of this important work scope.”
“This milestone has been achieved through the successful partnership between Baker Hughes and McDermott to execute for INPEX,” said Romain Chambault, Baker Hughes Senior Vice President, Subsea Projects and Services. “The amount of collaboration shown between the consortium has been truly unique and serves as an industry benchmark for the successful execution of large, complex EPCI subsea projects. Manufacturing the highly complex 7-inch VXT from our dedicated SP&S facility in Batam has expanded the global capability for Baker Hughes in the Asia Pacific region where we are well-positioned to support customers with a strong regional capability, complemented by a strong McDermott presence in Batam and the region as a whole.”
Monday 22 January 2024
Técnicas Reunidas and Sinopec awarded two contracts by Saudi Aramco for more than 3,3 billion USD
Saudi Aramco, one of the world’s largest energy companies, has awarded a joint venture formed by the Spanish company Técnicas Reunidas and the Chinese Sinopec Engineering Group the development of new Natural Gas Liquids (NGL) fractionation facilities in Saudi Arabia. The works will be developed on the basis of two EPC (engineering, procurement and construction) contracts for the execution of Riyas NGL Fractionation Trains (Package 1) and Riyas NGL Common Facilities (Package 2), which includes utilities, storage and export facilities. Total investment arising from these two contracts amounts to more than 3.3 billion USD. Since the joint venture is 65% owned by Técnicas Reunidas and 35% by Sinopec Engineering Group, the Spanish company is entitled to more than 2.15 billion USD of this total amount.
Function of the new facilities
The primary objective of the project is to enable the fractionation of NGLs, thus producing ethane, propane, butane and pentane.
Scope of the contracts
The new facilities to be developed by Técnicas Reunidas and Sinopec Engineering Group will fractionate 510 thousand barrels per day (MBD) of NGLs. The two trains of the Package 1 will process 255 MBD each, and will include fractionation, treatment, dehydration and refrigeration units. The common facilities of Package 2 will provide feed and product surge storage, chemicals storage and utilities including, although not limited to, steam and condensate recovery systems, utility water, plant, instrument air and nitrogen systems, machinery cooling water, drainage and flare systems. The expected duration of the project is about 46 months for Package 1 and about 41 months for Package 2, with a total maximum level of 575 engineers, of which more than 70% will be from Técnicas Reunidas.
Function of the new facilities
The primary objective of the project is to enable the fractionation of NGLs, thus producing ethane, propane, butane and pentane.
Scope of the contracts
The new facilities to be developed by Técnicas Reunidas and Sinopec Engineering Group will fractionate 510 thousand barrels per day (MBD) of NGLs. The two trains of the Package 1 will process 255 MBD each, and will include fractionation, treatment, dehydration and refrigeration units. The common facilities of Package 2 will provide feed and product surge storage, chemicals storage and utilities including, although not limited to, steam and condensate recovery systems, utility water, plant, instrument air and nitrogen systems, machinery cooling water, drainage and flare systems. The expected duration of the project is about 46 months for Package 1 and about 41 months for Package 2, with a total maximum level of 575 engineers, of which more than 70% will be from Técnicas Reunidas.
Discovery near the Munin field in the North Sea
Equinor Energy AS has discovered oil in exploration well 30/12-3 S in the North Sea. The well also included a sidetrack, 30/12-3 A, which was dry.
The wells were drilled about 40 kilometres south of Oseberg and 150 kilometres west of Bergen. The drilling was conducted by the Deepsea Stavanger drilling rig.
Equinor drilled the well on behalf of Aker BP, which is the operator of production licence 272 B. This is the first well in the production licence.
Aker BP and Equinor each have ownership interests of 50 per cent in the production licence, which was awarded in APA 2018. The production licence is part of the Munin field, which was discovered in 2011. The authorities approved the plan for development and operation (PDO) for Munin in June 2023.
Between 0.15 and 0.55 million standard cubic metres (Sm3) of recoverable oil equivalent (o.e.) was proven in well 30/12-3 S.
Preliminary calculations show that the discovery is not profitable with current price assumptions.
Geological information
The objective of wildcat wells 30/12-3 S and 30/12-3 A was to prove petroleum in Middle Jurassic reservoir rocks in the Tarbert Formation.
Well 30/12-3 S encountered a 3.5-metre oil column in the Tarbert Formation, in a sandstone reservoir with moderate reservoir quality. The Tarbert Formation was about 195 metres thick, 97 metres of which was sandstone rocks with moderate-good reservoir quality. The oil/water contact was encountered 3110 meters below sea level.
The Ness Formation was about 163 metres thick in total, 19 metres of which was a sandstone reservoir with moderate reservoir quality.
Well 30/12-3 A encountered the Tarbert Formation with a thickness of about 216 meters, 19 meters of which was sandstone rocks with poor reservoir quality. The Ness Formation was about 50 metres thick in total, 11 metres of which was a sandstone reservoir with moderate reservoir quality. The well was dry.
The wells were not formation-tested, but data acquisition was undertaken.
Well 30/12-3 S was drilled to measured and vertical depths of 3663 metres and 3465 metres below sea level, respectively, and was terminated in the Drake Formation. Well 30/12-3 A was drilled to measured and vertical depths of 4520 and 3718 metres below sea level, respectively, and was terminated in the Ness Formation. Water depth in the area is 106 metres. The well has now been permanently plugged and abandoned.
The wells were drilled about 40 kilometres south of Oseberg and 150 kilometres west of Bergen. The drilling was conducted by the Deepsea Stavanger drilling rig.
Equinor drilled the well on behalf of Aker BP, which is the operator of production licence 272 B. This is the first well in the production licence.
Aker BP and Equinor each have ownership interests of 50 per cent in the production licence, which was awarded in APA 2018. The production licence is part of the Munin field, which was discovered in 2011. The authorities approved the plan for development and operation (PDO) for Munin in June 2023.
Between 0.15 and 0.55 million standard cubic metres (Sm3) of recoverable oil equivalent (o.e.) was proven in well 30/12-3 S.
Preliminary calculations show that the discovery is not profitable with current price assumptions.
Geological information
The objective of wildcat wells 30/12-3 S and 30/12-3 A was to prove petroleum in Middle Jurassic reservoir rocks in the Tarbert Formation.
Well 30/12-3 S encountered a 3.5-metre oil column in the Tarbert Formation, in a sandstone reservoir with moderate reservoir quality. The Tarbert Formation was about 195 metres thick, 97 metres of which was sandstone rocks with moderate-good reservoir quality. The oil/water contact was encountered 3110 meters below sea level.
The Ness Formation was about 163 metres thick in total, 19 metres of which was a sandstone reservoir with moderate reservoir quality.
Well 30/12-3 A encountered the Tarbert Formation with a thickness of about 216 meters, 19 meters of which was sandstone rocks with poor reservoir quality. The Ness Formation was about 50 metres thick in total, 11 metres of which was a sandstone reservoir with moderate reservoir quality. The well was dry.
The wells were not formation-tested, but data acquisition was undertaken.
Well 30/12-3 S was drilled to measured and vertical depths of 3663 metres and 3465 metres below sea level, respectively, and was terminated in the Drake Formation. Well 30/12-3 A was drilled to measured and vertical depths of 4520 and 3718 metres below sea level, respectively, and was terminated in the Ness Formation. Water depth in the area is 106 metres. The well has now been permanently plugged and abandoned.
Sunday 21 January 2024
Talos Energy Announces Strategic Acquisition of QuarterNorth Energy
Talos Energy Inc. ("Talos" or the "Company") (NYSE: TALO) today announced the execution of definitive agreements to acquire QuarterNorth Energy Inc. ("QuarterNorth") for $1.29 billion (the "Transaction"). QuarterNorth is a privately-held U.S. Gulf of Mexico exploration and production company with ownership in several prolific offshore fields. QuarterNorth's assets will provide additional scale from high quality deepwater assets with a favorable base decline profile along with attractive future development opportunities. The Transaction is immediately accretive to Talos shareholders on key metrics and is expected to accelerate de-leveraging of Talos's balance sheet.
Consideration for the Transaction consists of 24.8 million shares of Talos's common stock and approximately $965 million in cash. The board of directors of both Talos and QuarterNorth have unanimously approved the Transaction. The Transaction is expected to close by the end of the first quarter of 2024, subject to certain customary closing conditions and regulatory approvals.
Key Transaction Highlights:
Talos President and Chief Executive Officer Timothy S. Duncan commented: "Today's announcement marks one of Talos's most significant milestones as we build a large-scale offshore exploration and production company. The addition of QuarterNorth's overlapping deepwater portfolio with valuable operated infrastructure will increase Talos's operational breadth and production profile while enhancing our margins and cash flow. This Transaction aligns with Talos's overall strategy of leveraging existing infrastructure and complementary acreage to accelerate shareholder value creation. The pro forma footprint in the U.S. Gulf of Mexico should allow us to capture meaningful operating synergies. The expected financing structure of the Transaction accelerates de-leveraging, immediately improves our credit profile, is accretive on key metrics, and positions us to consider additional capital return initiatives following deleveraging in the near term. We look forward to completing this Transaction in the next few months and continuing our strategy of building a large-scale, diverse energy company."
STRATEGIC AND FINANCIAL DETAILS
Immediately Accretive to Key Metrics
The Transaction is accretive to key financial metrics based on management's 2024 and 2025 estimates3. This approach is consistent with Talos's disciplined acquisition strategy to execute transactions that create shareholder value. This Transaction is accretive on the following metrics at current strip pricing4:>65% accretive on 2024E and 2025E Free Cash Flow Per Share3,5.
>15% accretive on 2024E and 2025E Cash Flow Per Share.
Accretive on Net Asset Value Per Share.
Accretive on Proved Reserves Per Share.
Accretive on 2024E and 2025E Production Per Share.
High Quality Asset Base with Low Production Decline
Talos estimates QuarterNorth average daily production for the full year 2024 of approximately 30 MBoe/d (75% oil), inclusive of planned downtime. QuarterNorth's producing assets include six major fields and are approximately 95% operated and 95% in deepwater. The Transaction is expected to improve Talos's base decline rate by approximately 20%, providing increased production stability and lower reinvestment rates.
QuarterNorth's assets bring significant reserves upside beyond current production from both producing probable zones and near-term development opportunities in 2024 and 2025. The Transaction also brings a high-quality inventory of drilling opportunities that will high-grade Talos's already robust inventory and will immediately compete for capital.
QuarterNorth operates and holds a 50% working interest in the Katmai discovery in the Green Canyon region, producing an estimated combined 27 MBoe/d gross from two early-life wells. Talos expects the Katmai field to produce over 34 MBoe/d gross on average with minimal decline over the next several years based on a successful field development plan including two future well locations and a facilities upgrade project in early 2025. QuarterNorth's interest in the Big Bend, Galapagos, Genovesa, and Gunflint fields represent attractive assets, each with strong production histories with nominal declines, and future development potential.
Material and Tangible Synergies
Talos expects to realize annual run-rate synergies of approximately $50 million, consisting of both operational and general and administrative cost reductions. Talos expects to realize approximately half of the synergies throughout 2024 and expects full run-rate savings can be achieved by year-end 2024.
Additional asset management and drilling & completions optimizations are also expected to create meaningful synergies in the combined business, which will be incremental to the expected $50 million annual synergies.
Reduction of Asset Retirement Obligations per Barrel
QuarterNorth's assets have no meaningful near-term ARO obligations. On a pro forma basis, future ARO obligations will represent a reduction of Talos's average ARO per barrel of oil equivalent ("Boe") of reserves and ARO per Boe of production, representing another "accretive" metric for Talos's shareholders.
Fully Committed Financing
Talos has secured $650 million in bridge financing from a syndicate of banks representing most of the Company's reserves-based loan ("RBL") lender group. All required RBL approvals and waivers have been received. Talos also expects to fund a portion of the cash consideration with availability under the RBL, and opportunistically to the extent market conditions warrant, debt or equity financings. Talos thereafter expects to repay the majority of the RBL funding for the Transaction in the next 12 months. The initial bridge financing structure provides flexibility to Talos with respect to the timing and structure of permanent financing of the Transaction.
GOVERNANCE, TIMING AND APPROVALS
Leadership, Governance, and Equity Holders
The Talos senior management team will remain unchanged. Talos's Board of Directors will be expanded to include one additional independent director.
QuarterNorth's top equity holders, representing approximately 68% of the total ownership group of QuarterNorth, have entered into a support agreement pursuant to which they will vote in favor of the Transaction and exercise a drag-along right in connection therewith. These holders will also be subject to a customary lock-up arrangement, subject to certain exceptions, for a 60-day period following closing, implying a lock-up into mid-2024 based on Talos's estimated closing timing. Following the closing, Talos expects that no single QuarterNorth shareholder will hold 5% or more of Talos's outstanding shares of common stock.
Timing And Approvals
The Transaction, which is expected to close by the end of the first quarter of 2024, is subject to customary closing conditions, including the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Both the Talos and QuarterNorth boards of directors have unanimously approved the Transaction.
Consideration for the Transaction consists of 24.8 million shares of Talos's common stock and approximately $965 million in cash. The board of directors of both Talos and QuarterNorth have unanimously approved the Transaction. The Transaction is expected to close by the end of the first quarter of 2024, subject to certain customary closing conditions and regulatory approvals.
Key Transaction Highlights:
- Adds production of approximately 30 thousand barrels of oil equivalent per day ("MBoe/d") expected for the full year 2024, averaging about 75% oil from approximately 95% operated assets.
- Adds proved reserves1 of approximately 69 million barrels of oil equivalent ("MMBoe") with a PV-10 of $1.7 billion.
- High margin, low decline production, with low reinvestment rate requirements to sustain production and no meaningful near-term asset retirement obligations ("ARO") conducive to long-term high free cash flow generation.
- Accretive to key financial metrics, including Cash Flow Per Share, Free Cash Flow Per Share, and Net Asset Value Per Share.
- Annual run-rate synergies of approximately $50 million are expected to be achieved by year-end 2024.
- Improves balance sheet strength with expected year-end 2024 leverage ratio2 of 1.0x or less.
Talos President and Chief Executive Officer Timothy S. Duncan commented: "Today's announcement marks one of Talos's most significant milestones as we build a large-scale offshore exploration and production company. The addition of QuarterNorth's overlapping deepwater portfolio with valuable operated infrastructure will increase Talos's operational breadth and production profile while enhancing our margins and cash flow. This Transaction aligns with Talos's overall strategy of leveraging existing infrastructure and complementary acreage to accelerate shareholder value creation. The pro forma footprint in the U.S. Gulf of Mexico should allow us to capture meaningful operating synergies. The expected financing structure of the Transaction accelerates de-leveraging, immediately improves our credit profile, is accretive on key metrics, and positions us to consider additional capital return initiatives following deleveraging in the near term. We look forward to completing this Transaction in the next few months and continuing our strategy of building a large-scale, diverse energy company."
STRATEGIC AND FINANCIAL DETAILS
Immediately Accretive to Key Metrics
The Transaction is accretive to key financial metrics based on management's 2024 and 2025 estimates3. This approach is consistent with Talos's disciplined acquisition strategy to execute transactions that create shareholder value. This Transaction is accretive on the following metrics at current strip pricing4:>65% accretive on 2024E and 2025E Free Cash Flow Per Share3,5.
>15% accretive on 2024E and 2025E Cash Flow Per Share.
Accretive on Net Asset Value Per Share.
Accretive on Proved Reserves Per Share.
Accretive on 2024E and 2025E Production Per Share.
High Quality Asset Base with Low Production Decline
Talos estimates QuarterNorth average daily production for the full year 2024 of approximately 30 MBoe/d (75% oil), inclusive of planned downtime. QuarterNorth's producing assets include six major fields and are approximately 95% operated and 95% in deepwater. The Transaction is expected to improve Talos's base decline rate by approximately 20%, providing increased production stability and lower reinvestment rates.
QuarterNorth's assets bring significant reserves upside beyond current production from both producing probable zones and near-term development opportunities in 2024 and 2025. The Transaction also brings a high-quality inventory of drilling opportunities that will high-grade Talos's already robust inventory and will immediately compete for capital.
QuarterNorth operates and holds a 50% working interest in the Katmai discovery in the Green Canyon region, producing an estimated combined 27 MBoe/d gross from two early-life wells. Talos expects the Katmai field to produce over 34 MBoe/d gross on average with minimal decline over the next several years based on a successful field development plan including two future well locations and a facilities upgrade project in early 2025. QuarterNorth's interest in the Big Bend, Galapagos, Genovesa, and Gunflint fields represent attractive assets, each with strong production histories with nominal declines, and future development potential.
Material and Tangible Synergies
Talos expects to realize annual run-rate synergies of approximately $50 million, consisting of both operational and general and administrative cost reductions. Talos expects to realize approximately half of the synergies throughout 2024 and expects full run-rate savings can be achieved by year-end 2024.
Additional asset management and drilling & completions optimizations are also expected to create meaningful synergies in the combined business, which will be incremental to the expected $50 million annual synergies.
Reduction of Asset Retirement Obligations per Barrel
QuarterNorth's assets have no meaningful near-term ARO obligations. On a pro forma basis, future ARO obligations will represent a reduction of Talos's average ARO per barrel of oil equivalent ("Boe") of reserves and ARO per Boe of production, representing another "accretive" metric for Talos's shareholders.
Fully Committed Financing
Talos has secured $650 million in bridge financing from a syndicate of banks representing most of the Company's reserves-based loan ("RBL") lender group. All required RBL approvals and waivers have been received. Talos also expects to fund a portion of the cash consideration with availability under the RBL, and opportunistically to the extent market conditions warrant, debt or equity financings. Talos thereafter expects to repay the majority of the RBL funding for the Transaction in the next 12 months. The initial bridge financing structure provides flexibility to Talos with respect to the timing and structure of permanent financing of the Transaction.
GOVERNANCE, TIMING AND APPROVALS
Leadership, Governance, and Equity Holders
The Talos senior management team will remain unchanged. Talos's Board of Directors will be expanded to include one additional independent director.
QuarterNorth's top equity holders, representing approximately 68% of the total ownership group of QuarterNorth, have entered into a support agreement pursuant to which they will vote in favor of the Transaction and exercise a drag-along right in connection therewith. These holders will also be subject to a customary lock-up arrangement, subject to certain exceptions, for a 60-day period following closing, implying a lock-up into mid-2024 based on Talos's estimated closing timing. Following the closing, Talos expects that no single QuarterNorth shareholder will hold 5% or more of Talos's outstanding shares of common stock.
Timing And Approvals
The Transaction, which is expected to close by the end of the first quarter of 2024, is subject to customary closing conditions, including the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Both the Talos and QuarterNorth boards of directors have unanimously approved the Transaction.
Reabold Resources plc - Notification of final tranche of payment from Shell
Reabold Resources plc, the oil & gas investing company with a diversified portfolio of exploration, appraisal and development projects, announces that, further to its announcement on 5 December 2023, it has been informed that the final tranche of the payment from Shell U.K. Limited ("Shell") for the sale of the entire issued share capital of Corallian Energy Limited ("Corallian"), as announced on 1 November 2022, will be distributed to former Corallian shareholders over the coming days, following receipt of Development and Production Consent for the Victory gas field from the North Sea Transition Authority on 17 January 2024.
Reabold will receive £4.4 million for the final tranche, which follows the £8.3 million already received by the Company. Reabold intends to use the proceeds received to advance the development of assets across its portfolio, as well as distributing excess cash to shareholders.
Reabold aims to replicate its success with the Victory project across the other key assets in its portfolio, most notably, West Newton and Colle Santo. Both assets are significant gas resources, which, like Victory, can make a meaningful contribution to improve energy security in Western Europe.
Stephen Williams, Co-CEO of Reabold, said:
"We are pleased to see development approval granted for the Victory gas field, which triggers the final tranche of the payment from Shell to Corallian's shareholders. This represents a significant moment in the delivery of the Reabold strategy to identify, fund and monetise underappreciated, but strategically important assets. We remain focused on progressing other key projects in the Reabold portfolio in 2024 and realising further value to reward shareholders for their ongoing support of the Company."
Reabold will receive £4.4 million for the final tranche, which follows the £8.3 million already received by the Company. Reabold intends to use the proceeds received to advance the development of assets across its portfolio, as well as distributing excess cash to shareholders.
Reabold aims to replicate its success with the Victory project across the other key assets in its portfolio, most notably, West Newton and Colle Santo. Both assets are significant gas resources, which, like Victory, can make a meaningful contribution to improve energy security in Western Europe.
Stephen Williams, Co-CEO of Reabold, said:
"We are pleased to see development approval granted for the Victory gas field, which triggers the final tranche of the payment from Shell to Corallian's shareholders. This represents a significant moment in the delivery of the Reabold strategy to identify, fund and monetise underappreciated, but strategically important assets. We remain focused on progressing other key projects in the Reabold portfolio in 2024 and realising further value to reward shareholders for their ongoing support of the Company."
Thursday 18 January 2024
TechnipFMC Awarded Significant Subsea Contract by BP in the Gulf of Mexico
TechnipFMC (NYSE: FTI) has been awarded a significant contract by bp (LON: BP) for its Argos Southwest Extension project in the Mad Dog field.
TechnipFMC will install pipe and an umbilical, tying back three new wells to the Argos platform in the Gulf of Mexico.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “We have a long-standing relationship with bp, underpinned by close collaboration. This partnership, combined with our robust installation and execution capabilities, enables us to meet bp’s schedule to extend the production in the Mad Dog field.”
Under the contract, TechnipFMC will also manufacture and install pipeline end terminations.
TechnipFMC will install pipe and an umbilical, tying back three new wells to the Argos platform in the Gulf of Mexico.
Jonathan Landes, President, Subsea at TechnipFMC, commented: “We have a long-standing relationship with bp, underpinned by close collaboration. This partnership, combined with our robust installation and execution capabilities, enables us to meet bp’s schedule to extend the production in the Mad Dog field.”
Under the contract, TechnipFMC will also manufacture and install pipeline end terminations.
Shell invests in the Victory gas field in the UK North Sea
Shell U.K. Limited (Shell UK) has taken a final investment decision (FID) on the Victory gas field in the UK North Sea, approximately 47 km north-west of the Shetland Islands. Once onstream, the field will help to maintain domestically produced gas for Britain’s homes, businesses and power generation.
The development will feature a single subsea well which will be tied back to existing infrastructure of the Greater Laggan Area system, using a new 16 km pipeline.
“The UK North Sea is a critical national resource, providing a steady supply of the fuels people rely on today and strengthening the country’s energy security and resilience,” said Shell UK Upstream Senior Vice President, Simon Roddy. “Continued investment is required to sustain domestic production, which is declining faster than the UK’s demand for oil and gas.”
According to the regulator, the North Sea Transition Authority, only 38% of the UK’s 2022 gas consumption was domestically produced – the rest was imported.
It is anticipated the Victory field will come online in the middle of the decade and at its peak, produce enough gas to heat almost 900,000 homes per year. This is around 150 million standard cubic feet per day of gas (approximately 25,000 barrels of oil equivalent per day). Most of the field’s recoverable gas is expected to be extracted by the end of the decade.
Victory’s gas will be processed onshore at the Shetland Gas Plant before being piped to the UK mainland to enter the National Grid at St Fergus, where Shell UK is also helping develop the Acorn Carbon Capture and Storage project.
Because Victory will tie back to existing infrastructure, its operational emissions will be lower than for many current UK North Sea gas fields. The project supports Shell’s Powering Progress strategy to deliver more value with less emissions, providing the energy people need today while developing the low-carbon energy system of the future.
Notes to editors
The development will feature a single subsea well which will be tied back to existing infrastructure of the Greater Laggan Area system, using a new 16 km pipeline.
“The UK North Sea is a critical national resource, providing a steady supply of the fuels people rely on today and strengthening the country’s energy security and resilience,” said Shell UK Upstream Senior Vice President, Simon Roddy. “Continued investment is required to sustain domestic production, which is declining faster than the UK’s demand for oil and gas.”
According to the regulator, the North Sea Transition Authority, only 38% of the UK’s 2022 gas consumption was domestically produced – the rest was imported.
It is anticipated the Victory field will come online in the middle of the decade and at its peak, produce enough gas to heat almost 900,000 homes per year. This is around 150 million standard cubic feet per day of gas (approximately 25,000 barrels of oil equivalent per day). Most of the field’s recoverable gas is expected to be extracted by the end of the decade.
Victory’s gas will be processed onshore at the Shetland Gas Plant before being piped to the UK mainland to enter the National Grid at St Fergus, where Shell UK is also helping develop the Acorn Carbon Capture and Storage project.
Because Victory will tie back to existing infrastructure, its operational emissions will be lower than for many current UK North Sea gas fields. The project supports Shell’s Powering Progress strategy to deliver more value with less emissions, providing the energy people need today while developing the low-carbon energy system of the future.
Notes to editors
- Shell UK completed the acquisition of a 100% interest in Corallian Energy Ltd in November 2022. The acquisition exclusively comprised the P2596 Victory license to develop gas West of Shetland.
- Victory is part of Shell UK’s aim to be a major investor in the UK energy system, sitting alongside our low-carbon and renewable projects including electric vehicle charging, floating offshore wind and carbon capture and storage.
Tuesday 16 January 2024
Shell agrees to sell Nigerian onshore subsidiary, SPDC
Shell has reached an agreement to sell its Nigerian onshore subsidiary The Shell Petroleum Development Company of Nigeria Limited (SPDC) to Renaissance, a consortium of five companies comprising four exploration and production companies based in Nigeria and an international energy group.
Completion of the transaction is subject to approvals by the Federal Government of Nigeria and other conditions.
Transaction will preserve SPDC’s operating capabilities for benefit of joint venture
The transaction has been designed to preserve the full range of SPDC's operating capabilities following the change of ownership. This includes the technical expertise, management systems and processes that SPDC implements on behalf of all the companies in the SPDC Joint Venture (SPDC JV)*. SPDC’s staff will continue to be employed by the company as it transitions to new ownership.
Following completion, Shell will retain a role in supporting the management of SPDC JV facilities that supply a major portion of the feed gas to Nigeria LNG (NLNG), to help Nigeria achieve maximum value from NLNG.
Shell to focus investment on Deepwater and Integrated Gas positions
“This agreement marks an important milestone for Shell in Nigeria, aligning with our previously announced intent to exit onshore oil production in the Niger Delta, simplifying our portfolio and focusing future disciplined investment in Nigeria on our Deepwater and Integrated Gas positions” said Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director.
“It is a significant moment for SPDC, whose people have built it into a high-quality business over many years. Now, after decades as a pioneer in Nigeria’s energy sector, SPDC will move to its next chapter under the ownership of an experienced, ambitious Nigerian-led consortium.
“Shell sees a bright future in Nigeria with a positive investment outlook for its energy sector. We will continue to support the country’s growing energy needs and export ambitions in areas aligned with our strategy.”
* The SPDC JV is an unincorporated joint venture comprised of SPDC Ltd (30%), the government owned Nigerian National Petroleum Corporation (55%), Total Exploration and Production Nigeria Ltd (10%) and Nigeria Agip Oil Company Ltd (5%).
Notes to editors.
Completion of the transaction is subject to approvals by the Federal Government of Nigeria and other conditions.
Transaction will preserve SPDC’s operating capabilities for benefit of joint venture
The transaction has been designed to preserve the full range of SPDC's operating capabilities following the change of ownership. This includes the technical expertise, management systems and processes that SPDC implements on behalf of all the companies in the SPDC Joint Venture (SPDC JV)*. SPDC’s staff will continue to be employed by the company as it transitions to new ownership.
Following completion, Shell will retain a role in supporting the management of SPDC JV facilities that supply a major portion of the feed gas to Nigeria LNG (NLNG), to help Nigeria achieve maximum value from NLNG.
Shell to focus investment on Deepwater and Integrated Gas positions
“This agreement marks an important milestone for Shell in Nigeria, aligning with our previously announced intent to exit onshore oil production in the Niger Delta, simplifying our portfolio and focusing future disciplined investment in Nigeria on our Deepwater and Integrated Gas positions” said Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director.
“It is a significant moment for SPDC, whose people have built it into a high-quality business over many years. Now, after decades as a pioneer in Nigeria’s energy sector, SPDC will move to its next chapter under the ownership of an experienced, ambitious Nigerian-led consortium.
“Shell sees a bright future in Nigeria with a positive investment outlook for its energy sector. We will continue to support the country’s growing energy needs and export ambitions in areas aligned with our strategy.”
* The SPDC JV is an unincorporated joint venture comprised of SPDC Ltd (30%), the government owned Nigerian National Petroleum Corporation (55%), Total Exploration and Production Nigeria Ltd (10%) and Nigeria Agip Oil Company Ltd (5%).
Notes to editors.
- The SPDC JV holds 15 oil mining leases for petroleum operations onshore and 3 for petroleum operations in shallow water in Nigeria. It is operated by SPDC.
- Renaissance is formed of ND Western, Aradel Energy, First E&P, Waltersmith and Petrolin.
- On December 31, 2022, SEC proved reserves that are the subject of this transaction were approximately 458 MMboe.
- The consideration payable to Shell as part of the transaction is US$1.3bln.
- The buyer will make additional cash payments to Shell of up to US$1.1bln, primarily relating to prior receivables and cash balances in the business, with the majority expected to be paid at completion of the transaction.
- The amounts above will be adjusted to reflect any shareholder distributions, above US$200 million, made prior to completion. Other contingent payments, including those related to gas supply to NLNG, may become payable depending on business performance and fluctuation of product prices.
- The net book value of the entity subject to this transaction is approximately US$2.8bln as at December 31, 2023. Under the agreed deal structure, economic performance accrues to the buyer with effect from December 31, 2021 (the effective date). However, Shell will continue to consolidate SPDC until control transfers at completion. Although any amounts will depend on the future financial performance of the business, we expect to recognise impairments in respect of the business up to the date of completion, including to the extent that the net book value of SPDC exceeds the expected consideration at completion.
- At closing, Shell will provide secured term loans of up to US$1.2bln, to cover a variety of funding requirements.
- Shell is providing additional financing of up to US$1.3bln over future years to fund SPDC’s share of the development of the SPDC JV’s gas resources to supply feedgas to NLNG, and its share of specific decommissioning and restoration costs. This additional financing will only be drawn down when these costs are approved and incurred by the SPDC JV.
- Shell has three other main businesses in Nigeria that are outside the scope of this transaction:Shell Nigeria Exploration and Production Company Limited (SNEPCo), which produces oil and gas in the deepwater Gulf of Guinea;
- Shell Nigeria Gas Limited (SNG), which provides gas to domestic industrial and commercial customers; and
- Daystar Power Group, which provides integrated solar power to commercial and industrial business across West Africa.
- In addition, Shell holds a 25.6% interest in NLNG, which produces and exports LNG to global markets. Shell’s interest in NLNG is also outside the scope of this transaction.
Monday 15 January 2024
Barossa Gas Project Update
Santos welcomes the decision of the Federal Court of Australia today in the case of Munkara v Santos NA Barossa Pty Ltd (No.3).
The decision was in favour of Santos, with the Court dismissing the application and discharging the injunction that prevented pipelay activities south of the kilometre 86 (KP86) point along the Barossa Gas Export Pipeline.
As per the ruling and in accordance with the Environment Plan in force for the activity, Santos will continue pipelaying activity for the Barossa Gas Project (Barossa).
The decision was in favour of Santos, with the Court dismissing the application and discharging the injunction that prevented pipelay activities south of the kilometre 86 (KP86) point along the Barossa Gas Export Pipeline.
As per the ruling and in accordance with the Environment Plan in force for the activity, Santos will continue pipelaying activity for the Barossa Gas Project (Barossa).
Friday 12 January 2024
Wood secures major topside modifications contract with bp in the North Sea
Wood has been awarded a major contract to deliver topside modifications supporting bp’s latest subsea tieback in the UK North Sea.
Wood’s Operations business will deliver engineering, procurement, construction and commissioning (EPCC) services to enhance the central processing facility of bp’s Eastern Trough Area Project (ETAP) production hub in the central North Sea. Repurposing of existing equipment on ETAP will be a key focus under the two-year contract to enable the platform’s connection to Murlach, bp’s two production well subsea tieback development.
Steve Nicol, Executive President, Operations at Wood said: “Working with bp for over 30 years, this contract builds on our global relationship, and we are proud to support this important project on one of their critical North Sea assets.’
“Wood will deliver this under our multi-region engineering services contract, with our teams supporting efficient and safe delivery of asset repair, modifications and enhancements on ETAP to enable production from Murlach.”
The cost reimbursable contract follows Wood’s delivery of pre-FEED and FEED work on the Murlach field, and the recent successful completion of brownfield scopes on bp’s Seagull field, another subsea tieback to ETAP that commenced production in 2023.
The Murlach project will be delivered by Wood’s teams in Aberdeen, where over 300 employees support bp contracts.
Wood’s Operations business will deliver engineering, procurement, construction and commissioning (EPCC) services to enhance the central processing facility of bp’s Eastern Trough Area Project (ETAP) production hub in the central North Sea. Repurposing of existing equipment on ETAP will be a key focus under the two-year contract to enable the platform’s connection to Murlach, bp’s two production well subsea tieback development.
Steve Nicol, Executive President, Operations at Wood said: “Working with bp for over 30 years, this contract builds on our global relationship, and we are proud to support this important project on one of their critical North Sea assets.’
“Wood will deliver this under our multi-region engineering services contract, with our teams supporting efficient and safe delivery of asset repair, modifications and enhancements on ETAP to enable production from Murlach.”
The cost reimbursable contract follows Wood’s delivery of pre-FEED and FEED work on the Murlach field, and the recent successful completion of brownfield scopes on bp’s Seagull field, another subsea tieback to ETAP that commenced production in 2023.
The Murlach project will be delivered by Wood’s teams in Aberdeen, where over 300 employees support bp contracts.
Monday 8 January 2024
Wood wins detailed engineering design for Trion project in Gulf of Mexico
Wood has secured a contract from HD Hyundai Heavy Industries for detailed engineering of the topsides facilities on Woodside Energy's Trion Floating Production Unit (FPU) in Mexican waters of the Gulf of Mexico. When complete, Trion will have a production capacity of 100,000 barrels per day and connect to a 950,000 barrel capacity floating storage and offloading vessel.
This greenfield development will represent the first deepwater development in Mexico at a water depth of 2,500 meters. HD Hyundai Heavy Industries is the engineering, procurement and construction (EPC) provider for the FPU and Wood's latest award follows the delivery of the Trion pre-FEED and FEED design.
John Day, President of Oil, Gas and Power at Wood commented, "We are pleased to have been selected as the topsides engineering provider for Trion by Woodside Energy and the project's EPC Contractor, HD Hyundai Heavy Industries. Wood's innovative design process on the pre-FEED and FEED work positioned us well for the detailed engineering scope on Trion.
"Applying a practical approach to decarbonisation in the design process has been an important part of this project, whilst ensuring safety and quality. Our team has a proven history with Woodside, having worked together for two decades, and our experience designing and delivering solutions for Trion will improve productivity, reduce emissions and maximize the return on investment for our client."
SeonMook Lim, Engineering Vice President of Offshore Engineering Division as HD Hyundai Heavy Industries commented, "We are very pleased to reunite with Wood through the Trion FPU Project for the first time since we worked on the East Area Natural Gas Liquids Offshore Project in West Africa in 2005. We are greatly enthusiastic about creating another EPC success story that will leave a lasting mark in the history of offshore oil and gas development. We look forward to continuing our relationship with Woodside as we embark on Trion FPU project."
Wood's teams in Houston (US) and Bogota (Colombia) will deliver the detailed topsides design work for the FPU project over the next three years. In the last decade, Wood has designed more than 50% of topside facilities in the Gulf of Mexico today.
This greenfield development will represent the first deepwater development in Mexico at a water depth of 2,500 meters. HD Hyundai Heavy Industries is the engineering, procurement and construction (EPC) provider for the FPU and Wood's latest award follows the delivery of the Trion pre-FEED and FEED design.
John Day, President of Oil, Gas and Power at Wood commented, "We are pleased to have been selected as the topsides engineering provider for Trion by Woodside Energy and the project's EPC Contractor, HD Hyundai Heavy Industries. Wood's innovative design process on the pre-FEED and FEED work positioned us well for the detailed engineering scope on Trion.
"Applying a practical approach to decarbonisation in the design process has been an important part of this project, whilst ensuring safety and quality. Our team has a proven history with Woodside, having worked together for two decades, and our experience designing and delivering solutions for Trion will improve productivity, reduce emissions and maximize the return on investment for our client."
SeonMook Lim, Engineering Vice President of Offshore Engineering Division as HD Hyundai Heavy Industries commented, "We are very pleased to reunite with Wood through the Trion FPU Project for the first time since we worked on the East Area Natural Gas Liquids Offshore Project in West Africa in 2005. We are greatly enthusiastic about creating another EPC success story that will leave a lasting mark in the history of offshore oil and gas development. We look forward to continuing our relationship with Woodside as we embark on Trion FPU project."
Wood's teams in Houston (US) and Bogota (Colombia) will deliver the detailed topsides design work for the FPU project over the next three years. In the last decade, Wood has designed more than 50% of topside facilities in the Gulf of Mexico today.
ONGC announces “First Oil” from the deep-water KG-DWN-98/2 Block
ONGC announces the successful commencement of “First Oil” from the deep-water KG-DWN-98/2 Block, situated off the coast of Bay of Bengal. This 98/2 project is likely to increase ONGC’s total Oil and Gas production by 11 percent and 15 percent respectively.
Valiantly combating various technological and Covid-related challenges, ONGC had successfully executed Phase 1 of the project in March 2020, achieving the commencement of gas production from U field of the KG-DWN-98/2 Block in record time of 10 months.
With commencement of this First Oil on 7 January 2024, ONGC is nearing completion of Phase 2, culminating into commencement of oil production from the ‘M’ field of KG-DWN-98/2.
The development of this field faced unique technical challenges due to the waxy nature of the crude. To overcome those, ONGC employed innovative Pipe in Pipe technology, a first-of-its-kind initiative in India. While some subsea hardware involved in this development has been sourced internationally to meet specific requirements, the majority of fabrication works were carried out at Modular Fabrication Facility at Kattupalli which highlights ONGC's commitment to promote ‘Make in India’, contributing towards a self-reliant energy sector in India.
The flagship project is on track with Final phase of project with the balance oil & gas fields of the block scheduled to be put on production by mid 2024. Peak production of field is expected to be 45,000 barrels of oil per day (bopd) and over 10 MMSCMD of gas, which will contribute significantly towards the vision of Hon’ble PM of an energy Aatmanirbhar Bharat.
Valiantly combating various technological and Covid-related challenges, ONGC had successfully executed Phase 1 of the project in March 2020, achieving the commencement of gas production from U field of the KG-DWN-98/2 Block in record time of 10 months.
With commencement of this First Oil on 7 January 2024, ONGC is nearing completion of Phase 2, culminating into commencement of oil production from the ‘M’ field of KG-DWN-98/2.
The development of this field faced unique technical challenges due to the waxy nature of the crude. To overcome those, ONGC employed innovative Pipe in Pipe technology, a first-of-its-kind initiative in India. While some subsea hardware involved in this development has been sourced internationally to meet specific requirements, the majority of fabrication works were carried out at Modular Fabrication Facility at Kattupalli which highlights ONGC's commitment to promote ‘Make in India’, contributing towards a self-reliant energy sector in India.
The flagship project is on track with Final phase of project with the balance oil & gas fields of the block scheduled to be put on production by mid 2024. Peak production of field is expected to be 45,000 barrels of oil per day (bopd) and over 10 MMSCMD of gas, which will contribute significantly towards the vision of Hon’ble PM of an energy Aatmanirbhar Bharat.
Friday 5 January 2024
First Gas Reached In Rozhkovskoye Field, Kazakhstan
MOL, as part of an international joint venture Ural Oil and Gas LLP., reached first gas from U-21 well in the Rozhkovskoye field, Kazakhstan, as a result of the close cooperation between the Hungarian, Kazakh and Chinese partners.
MOL, as part of an international joint venture Ural Oil and Gas LLP., reached first gas from U-21 well in the Rozhkovskoye field, Kazakhstan, as a result of the close cooperation between the Hungarian, Kazakh and Chinese partners. The Rozhkovskoye gas and condensate project is operated by Ural Oil and Gas LLP, a joint venture owned by KazMunayGas, Kazakhstan (50%), MOL Group, Hungary (27.5%), and FIOC, China (22.5%).
The Rozhkovskoye gas and condensate field was discovered in 2008, and after a thorough appraisal and engineering phase, it has been commissioned. The field is located in the West-Kazakhstan Region, 60 kilometers North-East of the town of Uralsk.
The gas and condensate recoverable from the reservoir currently targeted amounts to 158.8 MMboe, of which gas is 101.5 MMboe and condensate is 57.3 MMboe, based on the Kazakhstan State Balance Reserves Report. Out of nine wells drilled as part of exploration and appraisal, five were successfully re-completed for production in 2021. An Engineering, Procurement and Construction contract was signed in April 2022, covering all elements of the gathering infrastructure.
“It’s a long-awaited success for MOL in the Caspian region, I am pleased that our Kazakh asset has joined our diverse international production portfolio and represents further potential to MOL’s Exploration and Production. A large number of our subsurface experts, engineers and project managers worked tirelessly together with our Kazakh and Chinese partners in the last 15 years to make it happen. I am especially proud that MOL team was an active partner and our experts contributed in all technical aspects of the project,” said Zsombor Marton, Executive Vice President of MOL Group Exploration and Production.
The first well commenced production with a rate of 300,000 cubic meters of raw gas per day. Production will be transferred to Chinarevskoye Gas Plant for processing. MOL expects that in the initial pilot phase with one well in production, the Rozhkovskoye field will contribute approximately 1,300 boepd to the Group’s production.
Four additional wells will be put into production in the third quarter of 2024 to further boost production to 1.5 MM cubic meters of gas per day. In parallel with completion of Phase 1, the project is moving ahead to ensure timely delivery of planned Phase 2, in accordance with Field Development Plan endorsed by Central Commission for Exploration and Development in 2022. It includes additional recompletions, drilling new wells and expanding infrastructure to handle 2.5 MM cubic meters per day of gas by the end of 2027.
Wednesday 3 January 2024
TechnipFMC Awarded Major iEPCI™ Contract by Petrobras for Mero 3 HISEP® Project
TechnipFMC (NYSE: FTI) has been awarded a major(1) integrated Engineering, Procurement, Construction, and Installation (iEPCI™) contract by Petrobras to deliver the Mero 3 HISEP® project, which uses subsea processing to capture carbon dioxide-rich dense gases and then inject them into the reservoir.
TechnipFMC, in partnership with Petrobras, has advanced the qualification of some of the core technologies needed to deliver the HISEP® (High Pressure Separation) process entirely subsea, several of which are proprietary and will be used in other subsea applications. These include gas separation systems and dense gas pumps which enable the injection of CO2-rich dense gas.
The Mero 3 project in Brazil’s pre-salt field will be the first to utilize Petrobras’s patented HISEP® process subsea. HISEP® technologies enable the capture of CO2-rich dense gases directly from the well stream, moving part of the separation process from the topside platform to the sea floor. In addition to reducing greenhouse gas emission intensity, HISEP® technologies increase production capacity by debottlenecking the topside gas processing plant. These technologies are supported by Petrobras and its partners in the Libra Consortium(2).
Luana Duffé, Executive Vice President, New Energy at TechnipFMC, commented: “This is an important moment for our Company. With the HISEP® project, we will again demonstrate how our leadership in subsea processing, technology innovation, and integrated solutions can deliver real and sustainable benefits to our partners. We are honored to be trusted by Petrobras and its partners in the Libra Consortium to deliver this transformational project.”
The contract covers the design, engineering, manufacture, and installation of subsea equipment, including manifolds, flexible and rigid pipes, umbilicals, power distribution, as well as life of field services. The contract follows a tender process and aligns with research and development guidance established by the Brazilian National Petroleum Agency (ANP).
TechnipFMC, in partnership with Petrobras, has advanced the qualification of some of the core technologies needed to deliver the HISEP® (High Pressure Separation) process entirely subsea, several of which are proprietary and will be used in other subsea applications. These include gas separation systems and dense gas pumps which enable the injection of CO2-rich dense gas.
The Mero 3 project in Brazil’s pre-salt field will be the first to utilize Petrobras’s patented HISEP® process subsea. HISEP® technologies enable the capture of CO2-rich dense gases directly from the well stream, moving part of the separation process from the topside platform to the sea floor. In addition to reducing greenhouse gas emission intensity, HISEP® technologies increase production capacity by debottlenecking the topside gas processing plant. These technologies are supported by Petrobras and its partners in the Libra Consortium(2).
Luana Duffé, Executive Vice President, New Energy at TechnipFMC, commented: “This is an important moment for our Company. With the HISEP® project, we will again demonstrate how our leadership in subsea processing, technology innovation, and integrated solutions can deliver real and sustainable benefits to our partners. We are honored to be trusted by Petrobras and its partners in the Libra Consortium to deliver this transformational project.”
The contract covers the design, engineering, manufacture, and installation of subsea equipment, including manifolds, flexible and rigid pipes, umbilicals, power distribution, as well as life of field services. The contract follows a tender process and aligns with research and development guidance established by the Brazilian National Petroleum Agency (ANP).
Seatrium Secures Contract to Construct and Integrate Deep-Water Newbuild Project for Shell’s Semi-Submersible FPU
Seatrium Limited (Seatrium, or the Group), has been awarded a contract by Shell Offshore Inc. (Shell) to construct and integrate the hull, topsides and living quarters of the Sparta semi-submersible Floating Production Unit (FPU).
The contract includes the installation of Shell-furnished equipment and follows the Letter of Intent sealed by both parties on 28 August 2023. The Sparta FPU will be situated in the Garden Banks area of the US Gulf of Mexico, approximately 275 kilometres (171 miles) off the coast of Louisiana. It will feature a single topside bolstered by a four-column, semi-submersible floating hull and is designed to produce 90,000 barrels of oil equivalent per day (boe/d).
Seatrium, a leading global provider of engineering solutions to the marine, offshore and energy sectors, is known for its industry-leading approach in assembling topsides safely and efficiently at ground level, which minimises work-at-height risks for workers. The two-level topside for Sparta will be integrated and lifted to the hull using Seatrium’s game-changing Goliath twin cranes capable of lifting up to 30,000 tonnes.
Mr William Gu, Executive Vice President and Head of Oil & Gas International of Seatrium, said, “We are deeply honoured that Shell has awarded Sparta, the third FPU newbuild, to Seatrium, following the successful deliveries of the Vito and Whale FPUs. It is a strong affirmation of our team’s capabilities and the long-standing partnership between both parties. We are fully committed to executing the project well, including the single lift operation and fabrication of the FPU to meet its 20,000-psi design for use in harsh weather conditions, and delivering the unit to Shell safely and efficiently.”
The Sparta FPU is conceived as a replicable project between Shell and Seatrium to leverage the Group’s topsides single lift integration methodology, following the Vito and Whale newbuilds, and benefitting from operational synergies. With an extensive experience in complex offshore projects, Seatrium is well-positioned and equipped with cutting-edge technology to deliver high-quality engineering, procurement, installation and commissioning (EPIC) services for fixed and floating production platforms and subsea developments.
Tuesday 2 January 2024
Petrobras puts platform vessel into pre-salt production
Petrobras informs that it put into production today the Sepetiba platform vessel, in the Mero field, Libra block, in the pre-salt Santos Basin.
This is Mero's third production system, with the capacity to produce up to 180 thousand barrels of oil a day and compress up to 12 million cubic meters of gas. The platform is an FPSO, or floating production, storage, and offloading unit.
FPSO Sepetiba is part of a production system that includes drilling and preparing the well for production (completion) of eight producer wells and eight water and gas injection wells that are being interconnected to the unit.
The unit has innovative technologies to increase production efficiency and also enable the CCUS (Carbon Capture, Utilization and Storage) activity, where CO2-rich gas is reinjected into the reservoir and reduces greenhouse gas emissions into the atmosphere.
Petrobras chartered the FPSO Sepetiba from SBM, which also built it, to be the third production unit in the Mero field, out of a total of five, since two are yet to be installed.
Mero produces around 230 thousand barrels of oil and 15 million m3 of gas every day. It is a unitized field, operated by Petrobras (38.6%), in partnership with Shell Brasil (19.3%), TotalEnergies (19.3%), CNPC (9.65%), CNOOC (9.65%) and Pré-Sal Petróleo S.A (PPSA) (3.5%), as the Federal Government's representative in the non-contracted area
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