Top dollar oil & gas FID plays in 2024 with offshore development epilogues to come

Shifting power dynamics not only in the political arena but also in the energy industry have led to many changes across the globe and spurred new sets of challenges, including geopolitical headaches arising from trade wars and further tariff threats that are putting at stake the progress and final investment decisions (FIDs) for many energy projects, given the expected rise in supply chain costs, among other things, as a result of tariff restrictions. Since 2024 saw many projects green-lighted, Offshore Energy has delved into some of the biggest steps taken last year to move forward with these developments.

TotalEnergies took a final investment decision to develop a deepwater oil project in Block 20, which is said to be the first large deepwater development in the Kwanza basin off the coast of Angola. Following the FID, the French oil major handed out three deals to Saipem, adding $3.7 billion to the firm’s backlog and enabling the Italian player to work on various aspects of this project in Angola.

With a planned investment of more than $1 billion, Equinor laid the groundwork to further develop gas infrastructure at a field in the North Sea, strengthening Europe’s energy security in the process. Given the resource base at the Troll field, the Norwegian state-owned energy giant opted to split its development and production into three phases.

While Phase 1 entailed the gas resources in Troll East, which resulted in the Troll A platform, the Kollsnes gas plant, and associated infrastructure with gas exported to Europe via the Zeepipe pipelines, the oil from Phase 2, which covered resources in Troll West, leading to the Troll B and C platforms and associated infrastructure, is sent to the oil terminal at Mongstad.

Furthermore, the first part of Phase 3 revolved around producing the gas cap overlying the oil column in Troll West, while continuing to produce oil, with the produced gas going to Troll A and onward to existing infrastructure. The second stage of the Troll Phase 3 (TP3 II) project is made up of eight new wells from two new templates with subsea controls extended from existing templates, while a new gas flowline will be laid as a tie-back to the Troll A platform.

As this project will require modification work on Troll A, the first wells are scheduled to come online at the end of 2026, adding production from the reservoir equivalent to about 55 billion standard cubic meters of gas to enable the annual contribution from the new development to amount to around 7 billion standard cubic meters of gas at its peak.

According to Equinor, the second stage will prolong the plateau production by around four years and curtail the production decline over the next 10-12 years. Some of the players that will work on bringing this project to life include OneSubsea, Allseas, and Odfjell Drilling’s Deepsea Aberdeen rig, with drilling activities slated for late 2025 or early 2026.

The partners in the Troll field are Equinor Energy (30.58%, operator), Petoro (56%), Norske Shell (8.10%), TotalEnergies EP Norge (3.69%), and ConocoPhillips Skandinavia (1.62%). Given substantial reserves still underground, this field is said to be Norway’s largest gas producer, which has an annual export volume corresponding to an estimated 10% of Europe’s gas consumption.

After taking a final investment decision to develop the second phase of two oil fields in the pre-salt Santos Basin, Petrobras employed Seatrium to construct an FPSO pair, which will be deployed at Atapu and Sepia, thanks to a deal valued at more than $8 billion at the time. The FPSOs P-84 and P-85 will be used in the eastern part of the Santos Basin, approximately 200 kilometers offshore of Rio de Janeiro in Brazil.

With a production capacity of 225,000 barrels of oil per day (bopd) and a gas processing capacity of 10 million cubic meters per day, both FPSOs will come with technologies like zero routine flaring and venting, variable speed drives, and measures to control emissions and capture CO2, including an all-electric concept, to bolster energy efficiency and reach a 30% reduction in greenhouse gas (GHG) emissions.

Seatrium also got a deal with SBM Offshore for the topside fabrication and integration of the FPSO Jaguar, which will work at ExxonMobil’s Whiptail oil development on the Stabroek block off the coast of Guyana. This is one of the most significant hydrocarbon projects, which reached a final investment decision last year.

This is the U.S. player’s sixth project in the Stabroek block offshore Guyana. SBM Offshore was put in charge of front-end engineering and design (FEED) work for the FPSO Jaguar. With an expected field life of at least 20 years, the project is scheduled to be up and running in 2027. The development concept for the Whiptail project entails the Whiptail, Pinktail, and Tilapia fields, along with potential additional resources, if they end up being feasible and economically viable.

TotalEnergies, Staatsolie Maatschappij Suriname, and Apache Corporation made an oil project FID-ready and tapped SBM Offshore to supply a hull for an FPSO destined to work on their oil project offshore Suriname.

Shell‘s final investment decision for a gas development project offshore Trinidad and Tobago was set to bolster the firm’s LNG arsenal. The Manatee undeveloped gas field in the East Coast Marine Area (ECMA) in Trinidad and Tobago is interpreted to enable the UK-headquartered firm to competitively grow its Integrated Gas business by building on development efforts in the ECMA, which is perceived to be one of the country’s most prolific gas-producing areas.

The operator’s plan entails eight new development wells drilled from a new, normally unmanned offshore platform from which gas and condensate would be delivered to shore via a new gas pipeline. The Manatee field is part of the giant Loran-Manatee field that straddles Trinidad and Tobago’s maritime boundary with Venezuela.

McDermott was put in charge of the project’s engineering, procurement, construction, and installation (EPCI) activities, covering the design, procurement, fabrication, transportation, installation, and commissioning of a wellhead platform, along with offshore and onshore gas pipelines. The project was set to provide backfill for Trinidad’s Atlantic LNG facility, as Shell sees the ramp-up of utilization at existing LNG plants as an important lever to maximize the potential of its existing assets.

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The company’s plan up to 2030 includes a boost in its LNG business by 20-30%, compared to 2022, with LNG liquefaction volumes up by 25-30%, relative to 2022. The expansion of the UK firm’s LNG portion is aligned with its ‘LNG Outlook 2024,’ forecasting a rise in global demand for LNG of more than 50% by 2040.

One of Shell’s permits was recently revoked by the U.S. government’s Office of Foreign Assets Control (OFAC) for a gas field straddling the maritime boundary between Venezuela and Trinidad and Tobago, as part of America’s sanctions on Venezuela’s government, giving Trinidad and Tobago a wind-down period until May 27, 2025.

Energean‘s final investment decision for the Katlan/Tanin area envisions a phased development offshore Israel, bringing gas discoveries online by tying them back to an existing FPSO. The project’s field development plan was approved in December 2023.

After the Israeli Ministry of Energy and Infrastructure granted the associated 30-year lease for the Katlan area, including a 20-year extension option, the firm made the FID for the project, targeting a phased approach through a subsea tie-back to the existing FPSO Energean Power.

BP‘s FID for the development of its Kaskida deepwater oil project in the Gulf of America, formerly the U.S. Gulf of Mexico, has the potential to unlock 10 billion barrels of discovered resources in place. This will be the firm’s sixth hub in the Gulf of Mexico, featuring a new FPU with a capacity to produce 80,000 barrels of crude oil per day from six wells in the first phase.

Singapore’s Seatrium was hired to handle early engineering works for this newbuild FPU. Located approximately 250 miles (around 402 kilometers) southwest of New Orleans in the Keathley Canyon area of the Gulf of America, formerly the U.S. Gulf of Mexico, the Kaskida greenfield development project comprises a single topside module supported by a four-column semi-submersible hull.

The project will be BP’s first development in the U.S. Gulf to produce from reservoirs requiring well equipment with a pressure rating of up to 20,000 pounds per square inch (20K). TechnipFMC will handle the integrated engineering, procurement, construction, and installation (iEPCI) work. 

After TotalEnergies reached a final investment decision for a giant oil project in Block 58 offshore Suriname, the construction and installation phases are estimated to take approximately four years, thus, the first oil is anticipated in 2028. The FPSO hull for the project was reserved a few months ago with SBM Offshore.

The existing market prices indicate that the development will cost around $10.5 billion. The French player and its partners, Apache Corporation and Staatsolie, have confirmed more offshore drilling is on the horizon with 32 wells planned in the development plan, along with two rigs likely to be hired for the drilling job. During the lifetime of the project, up to $26 billion is on the cards to flow into Suriname’s economy.

Patrick Pouyanné, Chairman and CEO of TotalEnergies, highlighted: “Building on TotalEnergies’ pioneering spirit, this landmark project marks the first offshore development in the country and capitalizes on our extensive expertise in deep offshore innovation.

“Launched only a year after the end of appraisal, GranMorgu fits with our strategy to accelerate time-to-market and develop low-cost and low emission oil projects. We look forward to continuing our fruitful collaboration with Staatsolie to deliver a transformative project for Suriname’s economy.”

BP decided to move forward with the development of a project entailing offshore enhanced gas recovery (EGR) through carbon capture, utilization, and storage (CCUS) in Indonesia.

Shell, which gave the go-ahead for its multi-well development project to expand oil production from an asset in a water depth of about 2,450 meters in the U.S. Gulf, also approved the development of a deepwater oil and gas project offshore Nigeria. The multibillion-dollar project will be brought online as a subsea tie-back to an existing FPSO.