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:

•  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 Mr. Saad Sherida Al-Kaabi, the Minister of State for Energy Affairs, the President and CEO of QatarEnergy, welcomed the award of the contract packages as an important milestone in the development of the State of Qatar’s largest oil field. His Excellency said: “By awarding these contracts, we are taking an important step towards realizing the full potential of Al-Shaheen filed, which produces around half of Qatar’s crude oil today.”

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.

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.”

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.

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.

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:

• 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."

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.

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

• 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.

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.

• 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.

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).

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 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.

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.

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.

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).

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.

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