Global E&P Briefs

Aug. 9, 2023
A compilation of the latest offshore exploration and production updates and projects from around the world

Editor's note: This Data section first appeared in the July-August issue of Offshore magazine. Click here to view the full issue.


Chevron’s new Anchor production platform has sailed from Kiewit Offshore Services in Ingleside, Texas to the mooring location in Green Canyon Block 87, 140 mi from the Louisiana coast. Stage 1 of the $5.7-billion Anchor development, in 5,000 ft of water, comprises seven wells tied back to the platform which can handle pressures up to 20,000 psi. The facility is designed to produce 75,000 b/d of crude oil and 28 MMcf/d of gas, and should start operations in 2024.

Shell has awarded TechnipFMC an integrated EPCI contract to supply the subsea tree systems for the Dover-Appomattox tieback. In addition, TechnipFMC has EPCI responsibility for the umbilical, riser and flowline systems. Dover should enter production by early 2024, with estimated peak rates of 21,000 boe/d.


Woodside Energy has taken FID on the deepwater Trion oilfield development in 2,500 m of water, 180 km offshore Mexico and 30 km south of the US GoM boundary.  Assuming sanction from partner Pemex and regulatory approval, expected during the fall, first oil could flow in 2028. The host facility will be a 100,000-b/d floating production unit linked to a 950,000-bbl capacity FSO, and connected to nine producer wells, seven water injectors and two gas injectors in the initial phase. Six more wells should follow later, with the project targeting 479 MMboe of resources at a capital cost of $7.2 billion.

Grupo Carso has agreed to take a controlling 49.9% stake in Talos Mexico for $124.75 million, pending approval from COFECE, the Mexican Federal Economic Competition Commission. Talos Mexico has a 17.4% stake in the shallow-water Zama oilfield project, operated by Pemex, and the initial purchase price could rise to $262.5 million if certain milestones are reached. Pemex submitted a development plan for the Zama Unit in March, under which Talos would co-lead work on the wells and execution/delivery of the offshore infrastructure.


Trinity Exploration & Production has awarded Petrofac a screening study for further development of the Galeota block offshore eastern Trinidad, where all production comes currently from the Trintes field. Petrofac will develop a concept, drawing on its experience with marginal fields, that could be advanced to the FEED and project sanction phases, with flexibility to re-deploy any recommended equipment on other accumulations elsewhere on the block.


Canadian independents CGX Energy and Frontera Energy have confirmed an oil discovery in the Wei prospect in the Corentyne block, 200 km offshore Georgetown, Guyana. The Wei-1 well encountered light and sweet medium crude in Maastrichtian and Campanian reservoirs, with a subsequent bypass well (Wei-1BP1) intersecting hydrocarbon-bearing sands in the Santonian interval.


Petrobras has produced first oil through Almirante Barroso, the fifth FPSO on the giant Búzios field in the pre-salt Santos basin off Brazil. The facility, constructed in China, is operating under charter from MODEC, with capacity to produce up to 150,000 b/d of oil and 6 MMcm/d of gas and to inject 220,000 b/d of water. The location is 180 km from the Rio de Janeiro coast in 1,900 m water depth.

Another newbuild floater Sepetiba, based on SBM Offshore’s Fast4-Ward design, has sailed from the BOMESC shipyard in China to the Mero field on the Libra block in the same basin. SBM will operate the platform for Petrobras under a 20-year contract, with first oil expected later this year.

In the Campos basin, Brazil’s GERDAU/ECOVIX shipyard joint venture will decommission and dismantle the P-32 platform after winning Petrobras’ first decommissioning auction. The platform was one of 10 that operated on the original Marlim/Voador fields development, with two new FPSOs now in service.


Uruguay’s ANCAP agency has awarded the country’s final unassigned offshore block to UK-based Challenger Energy Group. AREA OFF-3 covers a 13,252-sq km area, 100 km offshore and in up to 1,000 m of water, and has 2D and 3D seismic data which PGS acquired for bp in 2012. Challenger, which also operates AREA OFF-1, has identified gas and oil potential in multiple plays. Both concessions are in the Punta del Este and Pelotas sedimentary basins.


TotalEnergies has discovered more oil and gas in the OML 102 permit, 60 km offshore south-east Nigeria. The Ntokon-1AX well and the sidetrack that followed encountered a total of 111 m of oil and 15 m of gas in around 60-70 m water depth: according to Wood Mackenzie, it could be the country’s largest offshore find in a decade with a potential resource of 300-400 Mboe. This would justify a wellhead platform-based development with up to 30 wells and a multiphase oil pipeline running 20 km to the Ofon field complex.

And following a 20-year renewal of a PSC for deepwater block in the Niger Delta offshore Nigeria with NNPC and CNOOC, TotalEnergies is now clear to proceed with FEED studies for a tieback here of the Preowei oil discovery. Other fields in production on the concession, which will be converted from Oil Mining Lease130 to a petroleum mining license, under a new Nigerian law, are Akpo and Egina.


Azule Energy, the Angolan joint venture between bp and Eni, has commissioned TechnipFMC to provide subsea production systems, flowlines, umbilicals and topside controls for the offshore Block 18 Infills development. This will require a reconfiguration of the existing field layout to accommodate the new equipment, which is designed to increase production.


Wellesley Petroleum has made potentially its first breakthrough discovery as an operator on the Norwegian shelf, finding gas-condensate in the Carmen prospect in license PL1148, close to the Equinor-led Troll-Gjøa area. Initial analysis suggests 120-230 MMboe recoverable, according to partner DNO.

Equinor has provisionally asked Aker Solutions to supply a two-tree subsea production system and control umbilical for the tieback of the Eirin field to the Gina Krog platform to the south. Eirin was discovered in 1978.


OMV Petrom and Romgaz have committed to Romania’s first deepwater gas development in the Neptun Deep block. They aim to recover close to 100 bcm from the Domino and Pelican South fields, both discovered by former operator ExxonMobil, at a cost of around EUR4 billion. The project will involve drilling 10 wells and three subsea production systems on the two fields connected by flowlines to a platform, with a gas export pipeline to Tuzla and an onshore gas measurement station. Production should reach 140,000 boe/d at peak, with the entire infrastructure operated remotely.


Turkish Petroleum has commissioned the Subsea Integration Alliance to provide all main equipment for the second-phase Sakarya gasfield subsea-beach development in the Turkish sector, in water depths of up to 2,000 m. OneSubsea will supply the subsea production systems while Subsea 7 will engineer and install 37 km of flowlines and 47 km of control umbilicals, with offshore work scheduled for 2025. Saipem has the EPCI responsibility for the 175-km, 16-in. pipeline, with the Castorone construction vessel due to start laying operations next year.


TotalEnergies and SOCAR have started production from the Absheron field development offshore Azerbaijan, 100 km south-east of Baku. A single subsea well, connected to a new gas processing platform linked to SOCAR’s Oil Rocks complex, is producing up to 4 MMcf/d of gas for domestic use and 12,000 b/d of condensate.


Chevron has submitted an updated development plan for the 129-bcm Aphrodite gas field in offshore Block 12 in the EEZ of the Republic of Cyprus, 160 km south of Limassol. According to Israeli partner NewMed Energy, the new proposal involves constructing a subsea gas transport pipeline with connections to existing offshore/onshore infrastructure in Egypt to the south.

To the south-east offshore Israel, the same two companies and partner Ratio Energies have taken FID on a third long-distance subsea pipeline for the Leviathan field, with an estimated cost of $568 million. This will be laid between the field’s deepwater production wells and the fixed platform close to the shore, and will expand supplies of gas to INGL’s transmission system to around 1.4 bcf/d from mid-2025.


Reliance Industries and bp have started gas production from the MJ field, the third development on block KG D6 offshore eastern India. MJ is a high pressure, high temperature field in up to 1,200 m of water and 30 km from the onshore terminal at Gadimoga. It will eventually produce around 12 MMcf/d and 25,000 b/d. The development included installation of the FPSO Ruby to process and separate the wellstream, water and impurities before sending the gas ashore.


Sarawak Shell has commissioned McDermott to support the F22, F27 and Selasik fields (FaS) development offshore eastern Malaysia. The work scope covers

 transport and installation of three jackets and topsides, laying of two subsea pipelines and one section of flexible pipelay. The DLV2000 vessel will perform all installations.


Chevron Australia and its partners have delivered first gas from the Gorgon Stage Two development off Western Australia. The project involved drilling 11 new wells on the Gorgon and Jansz-Io fields and installing extra offshore production pipelines and subsea structures to sustain gas supplies to the processing complex onshore Barrow Island.


Woodside Energy has awarded all main contracts for what it claims is one of Western Australia’s largest ever offshore decommissioning campaigns. The awards cover removal and disposal of subsea infrastructure at the Echo Yodel, Enfield, Griffin and Stybarrow fields to groups including DOF, Fugro, Heerema, McDermott, McMahon and Technip FMC, while Transocean will P&A wells at Stybarrow.

In the Gippsland basin offshore Victoria, Esso Australia is inviting heavy-lift contracts to submit proposals for completing an offshore removal, transportation and onshore recycling/disposal program concerning some of Australia’s longest-producing offshore oil and gas fields.


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