Shell invests in water injection at Gulf of Mexico field

Shell Offshore Inc. (Shell), a subsidiary of Shell plc, has taken a Final Investment Decision (FID) on a ‘waterflood’ project at its Vito asset in the US Gulf of Mexico. Water will be injected into the reservoir formation to displace additional oil.

The process is due to begin in 2027 and is expected to significantly enhance volume capacity at the Vito field.

“Over time, we’ve seen the benefits of waterflood as we look to fill our hubs in the Gulf of Mexico,” said Zoë Yujnovich, Shell Integrated Gas and Upstream Director. “This investment will deliver additional high-margin, lower-carbon barrels from our advantaged Upstream business while maximizing our potential from Vito.”

Waterflood is a method of secondary recovery where the injected water physically sweeps the displaced oil to adjacent production wells, while re-pressurizing the reservoir. The three water injection wells were all drilled as pre-producers.

Shell is the leading deep-water operator in the U.S. Gulf of Mexico, where our production has among the lowest greenhouse gas (GHG) intensity in the world for producing oil.

Notes to editors

• In July 2009, the Vito field was discovered in more than 4,000 feet of water approximately 75 miles south of Venice, LA, 150 miles southeast of New Orleans and 10 miles south of the Shell-operated Mars TLP.
• In 2015, the original Vito host design was simplified and rescoped, resulting in a reduction of approximately 80% in CO2 emissions over the lifetime of the facility as well as a cost reduction of more than 70% from the original host design concept.
• Shell (Operator 63.11%) and Equinor (36.89%) announced FID for the Vito development in April 2018, with first oil achieved in February 2023.
• Given the properties of the Vito reservoir, energy is required to maximize the producing rate of existing wells and thus ultimate recovery.
• The Vito waterflood project will increase recoverable resource volume by 60 million boe. The estimate of resources volumes is currently classified as 2P and 2C under the Society of Petroleum Engineers’ Resource Classification System.
• The reference to our U.S. Gulf of Mexico production having among the lowest GHG intensity in the world is a comparison among other IOGP oil-and gas-producing members.
• As communicated at Shell’s Capital Markets Day in 2023, we plan to see production stabilise at 1.4 million barrels per day of liquids to 2030.

McDermott Secures EPCI Contract for Gas Project Offshore Trinidad and Tobago

McDermott has been awarded an engineering, procurement, construction, installation (EPCI), hook up and commissioning contract by Shell Trinidad and Tobago Limited for the Manatee gas field development project, located 60 miles (100 kilometers) off the southeast coast of Trinidad and Tobago.

The award follows the successful delivery of the front-end engineering design, detailed engineering and long lead procurement service contracts for the project's initial design and execution planning.

Under the contract scope, McDermott will design, procure, fabricate, hook up and commission a platform and jacket. The company will also provide design, installation, and commissioning services for a 32-inch gas pipeline that will connect the platform to a gas processing facility operated by Shell. The contract scope also includes design, procurement, installation, and testing services for a fiber optic cable.

"This award leverages our unique, integrated EPCI capabilities and legacy of engineering excellence and innovation to successfully deliver large offshore platforms and complex subsea infrastructure worldwide," said Mahesh Swaminathan, McDermott's Senior Vice President, Subsea and Floating Facilities. "The Manatee project builds on our track record of successful project execution for Shell and exemplifies our commitment to building energy infrastructure required to meet demand."

This contract award also demonstrates our continued commitment to working in Trinidad and Tobago to support the future supply of gas to its domestic and export market.

SBM Offshore awarded FSO contract for Woodside’s Trion development

SBM Offshore is pleased to announce that it has signed a contract with Woodside Petróleo Operaciones de México, S. de R.L. de C.V. (“Woodside”), operator of the Trion deepwater oil field development located in the Perdido Belt of the western Gulf of Mexico. Under this contract, SBM Offshore will construct and thereafter lease to Woodside a Floating Storage and Offloading (“FSO”) unit for a period of 20 years. This award complements the Transportation & Installation contract for the FSO and the FPU awarded to SBM Offshore in 2023.

The new build FSO, based on a Suezmax-type hull, will be equipped with a Disconnectable Turret Mooring (“DTM”) system designed by SBM Offshore. The FSO will be moored in water depth of about 2,500 meters and will be able to store around 950,000 barrels of crude oil.

The Trion field is located 180 km off the Mexican coastline and 30 km south of the US/Mexico maritime border. The Trion project is an alliance between Woodside (60%, Operator) and PEMEX Exploración y Producción (40%, non-Operator).

Viaro Energy signs agreement to take over Shell & ExxonMobil’s UK Southern North Sea assets

Viaro Energy (“Viaro”), the independent British energy company operating in the UKCS and the Netherlands North Sea, is pleased to announce that its main operating subsidiary RockRose Energy Limited signed an agreement with Shell U.K. Limited, a subsidiary of Shell plc (“Shell”), and Esso Exploration and Production UK Limited, a subsidiary of ExxonMobil Corporation (“ExxonMobil”), to acquire a full ownership interest in their Shell-operated UK Southern North Sea assets.

Pending regulatory approval, Viaro will acquire a portfolio consisting of 11 operated offshore assets and one exploration field (Shamrock; Caravel; Corvette; Brigantine; Leman; Galleon; Skiff; Carrack Main, Cutter, Carrack East; Barque; and Clipper), all tying back to the Shell-operated onshore Bacton Gas Processing Terminal via the Leman and Clipper fields. In 2023, production was around 28,000 boepd (c. 5% of UK total gas production) and the assets possess strong growth potential through identified near field exploration opportunities.

With a strong record of reliable production and around 90% production efficiency reported, the natural gas fields of the Southern North Sea and the Bacton gas terminal have been part of the UK’s energy foundation for 56 years. The tight gas development ongoing in the Galleon and Barque fields and strong potential for tight gas opportunities and near field exploration already identified in the Greater Sole Pit area are both indicative of the fields’ lasting importance for the UK’s energy security.

Viaro estimates place the 2P volumes of these assets at 58 million barrels of oil equivalent (“boe”), with a projected potential to extract over 120 million boe of net 2C resources. Viaro intends to maximise the economic return of these assets and, by working to ensure the extraction is conducted to reach their fullest potential, to increase low-emissions production of gas in the area through a redevelopment with an existing infrastructure.

The Bacton Gas Processing Terminal provides a direct route for natural gas produced from the Southern and Central North Sea to the UK National Transmission system, operated by the National Grid, enabling gas to flow between the UK and the Netherlands. In recent years, it received the Bacton Rejuvenation Investment of around £300 million to upgrade and extend the life of the terminal for future use. Bacton gas is used to generate around 40% of Britain’s electricity and it constitutes the main supply of gas for East Anglia and North London’s homes and businesses, whose terminal optimisation potential has been recognised by the North Sea Transition Authority (“NSTA”).







With a well-established value chain, the Bacton gas terminal complex also holds immense potential to become an energy transition hub. According to the NSTA, the Bacton terminal is ideally positioned to become a significant hydrogen production site for London and the Southeast, with strong potential to play a role with carbon capture storage and offshore wind developments that can supply renewable power to Bacton. In addition, Viaro intends to conduct feasibility studies on the best ways to decarbonise this asset through the deployment of clean technology.







Francesco Mazzagatti, CEO of Viaro Energy, commented: “We are immensely grateful to the Shell and ExxonMobil teams for an exemplary collaboration on this major deal, which represents a crowning achievement of Viaro’s strategic vision in the North Sea to date. We have long emphasised our commitment to the UKCS North Sea, and while we have certainly encountered more than a few challenges to realise our initial strategy, it is deals like this that make it evident why it is a worthwhile long-term investment.







Shell and ExxonMobil’s Southern North Sea portfolio is not only the backbone of the UK’s energy production and security, but it also represents one of the best strategically placed solutions that have the potential to play an important role in the energy transition. With strong potential for wind farm synergies, electrification of upstream assets, CCS and hydrogen supply, this acquisition fits Viaro’s ongoing and planned activities across the energy sector perfectly.”

Subsea Integration Alliance awarded EPCI contract offshore UK

Subsea7 today announced the award of a sizeable(1) contract by bp to Subsea Integration Alliance(2), for the Murlach development (formerly Skua field), 240 kilometres east of Aberdeen in the UK North Sea.

The project work scope covers the engineering, procurement, construction and installation of the subsea pipelines (SURF) and production systems (SPS). It includes the first deployment of OneSubsea’s standard, configurable, vertical monobore tree systems in the UK North Sea, which will be deployed via vessel to reduce drill rig days. OneSubsea will deliver two vertical monobore trees, a 2-slot manifold, and associated topside controls. The Alliance worked with bp to develop a technology solution leveraging OneSubsea’s field-proven standard equipment, which is simpler to design and quicker to install when compared with traditional configured-to-order subsea systems.

Subsea7 will install eight kilometres of rigid flowline and two flexible jumpers, along with associated subsea infrastructure. The new flowline will be tied-back to the Eastern Trough Area Project (ETAP) facility. Fabrication of the pipelines will take place at Subsea7’s spoolbase at Vigra, Norway and offshore operations are expected to be executed in 2025.

Olivier Blaringhem, Chief Executive Officer of Subsea Integration Alliance said: “This is bp’s third fully integrated EPCI project with Subsea Integration Alliance marking an important milestone as we extend our support to the UK North Sea market.”

Hani El Kurd, Senior Vice President for Subsea7 UK & Global Inspection, Repair and Maintenance, said: “We are delighted to be awarded this contract by bp, as it recognises Subsea Integration Alliance’s global reputation for seamless, full subsea system delivery. Subsea7 has a long relationship with bp and we look forward to supporting their Murlach development.”

bp gives go-ahead for sixth operated hub, Kaskida, in the US Gulf of Mexico

bp has taken a final investment decision on the Kaskida project in the US Gulf of Mexico. This demonstrates bp’s long-term commitment to deliver secure, affordable and reliable energy.

Kaskida will be bp’s sixth hub in the Gulf of Mexico, featuring a new floating production platform with the capacity to produce 80,000 barrels of crude oil per day from six wells in the first phase. Production is expected to start in 2029.

"Developing Kaskida will unlock the potential of the Paleogene in the Gulf of Mexico for bp, building on our decades of experience in the region," said Gordon Birrell, bp’s executive vice president of production and operations.

"Technology has and will continue to play a pivotal role in propelling Kaskida from discovery to production. Together with the other resources we have in the Paleogene, we expect it to prove to be a world-class development. Today is a critical step in realizing its potential."

Owned 100% by bp, the Kaskida field has discovered recoverable resources currently estimated at around 275 million barrels of oil equivalent from the initial phase. Additional wells could be drilled in future phases, subject to further evaluation.

The project is fully accommodated within bp’s disciplined financial framework, reflecting bp’s drive to focus on value and returns.

Located in the Keathley Canyon area about 250 miles southwest off the coast of New Orleans, the Kaskida project unlocks the potential future development of 10 billion barrels of discovered resources in place across the Kaskida and Tiber catchment areas.

bp plans to leverage existing platform and subsea equipment designs that can be replicated in future projects to drive cost efficiencies across Kaskida’s construction, commissioning and operations.

"By employing an industry-led design solution, Kaskida will be simpler to construct and simpler to operate, enhancing safety and delivering greater value for bp," said Andy Krieger, bp’s senior vice president, Gulf of Mexico and Canada.

Kaskida is in a prime location, with a stable fiscal regime and access to market. It will also be bp’s first development in the Gulf of Mexico to produce from reservoirs that will require well equipment with a pressure rating of up to 20,000 pounds per square inch (20K).

Advancements in 20K drilling technology coupled with updated seismic imaging are enabling bp to safely develop Kaskida and to progress plans to develop other fields such as Tiber, which is expected to advance to a final investment decision next year.

Today’s announcement demonstrates bp’s near-term priorities in action – moving forward a key high-value growth project and supporting its drive to deliver as a simpler, more focused, higher value company.

• bp discovered the Kaskida field in 2006 and has since worked closely with the offshore industry to help develop 20K rig technology necessary to complete high-pressure wells.
• Kaskida, Tiber and nearby discoveries combined have an estimated 10 billion barrels of discovered resources in place.
• bp is one of the leading producers in the Gulf of Mexico with more than 60 years of experience operating in the basin.
• bp operates five platforms in the Gulf of Mexico: Argos, Atlantis, Mad Dog, Na Kika and Thunder Horse.
• bp produced circa 300,000 barrels of oil equivalent per day from the Gulf of Mexico in 2023.