Global E&P

NORTH AMERICA

Suncor and its partners in the Terra Nova field off Newfoundland and Labrador are aiming to sanction their asset life extension project during the fall. This would allow the FPSO, currently off-station, to resume operations. In addition, ownership will likely be restructured, with Suncor increasing its operated interest from 38% to 48%.

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PGS’ Ramform Titan has been acquiring a long-offset 3D survey over the Orphan basin offshore Newfoundland. The 10,000-sq km (3,861-sq mi) program, managed by PGS and TGS, is designed to cover existing lease blocks and open acreage.

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Williams has struck a deal with Beacon Offshore Energy Development and ShenHai to take gas from the Shenandoah development through the Discovery infrastructure in the central US Gulf of Mexico. Shenandoah is 257 km (160 mi) from the Louisiana coast in the Walker Ridge area. An 8-km (5-mi) pipeline will be laid from the field’s platform to Discovery’s Keathley Canyon Connector pipeline, with the gas transported to the Larose onshore complex for processing.

Production from bp’s Manuel project has started flowing to the Na Kika platform via a two-well subsea tieback, with combined production set to peak at 20,100 boe/d. The location is 225 km (140 mi) offshore New Orleans.

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Mexico’s Ministry of Energy (SENER) has surprised Talos Energy and its partners in block 7 in the Sureste basin by awarding Pemex operatorship of the unitized shallow-water Zama oilfield. Talos discovered Zama in 2017, with subsequent delineation proving an extension into a neighboring block operated by Pemex.

SOUTH AMERICA

ExxonMobil sees potential for a fifth FPSO on the deepwater Stabroek block off Guyana, east of the Liza complex. This could incorporate reserves proven by the recent Mako-2 appraisal well and the earlier Uaru-2 discovery. The drillship Stena DrillMAX was due to test another prospect, Whiptail, having earlier found 70 m (230 ft) of net oil pay via the Longtail-3 well.

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Yinson’s Olso office is performing pre-FEED for TotalEnergies for an FPSO in block 58, offshore Suriname, where the company and co-venturer APA have made four oil discoveries. The location is 150 km (93 mi) from the capital Paramaribo, in 2,000 m (6,562 ft) water depth. TotalEnergies recently extended its position in the area by winning operatorship of shallow-water blocks 6 and 8, immediately south of block 58.

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Petrobras expects to start production this month from the ultra-deepwater Sépia field in the presalt Santos basin, 250 km (155 mi) offshore Rio de Janeiro. The FPSO Carioca, owned by MODEC, is chartered to operate at the field for 21 years, with capacity to process 180,000 b/d of oil and 6 MMcm/d of gas, and storage for up to 1.4 MMbbl.

A joint venture between Saipem and DSME will construct the eighth FPSO for Petrobras’ Búzios field in the same basin, under a $2.3-billion contract. The P-79 will be connected to eight producer and six injector wells via rigid production/injection pipelines and flexible service lines, and will be designed to process 180,000 b/d of oil and 7.2 MMcf/d of gas, with 2 MMbbl oil storage capacity. The completed vessel is due to be delivered in 2025.

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Australian independent Karoon Energy will develop the Patola field in 300 m (984 ft) of water in the Santos basin via two subsea production wells connected to spare riser slots on the FPSO Cidade de Itajai, which serves the Baúna field. The semisubmersible Maersk Developer will drill the wells and TechnipFMC will supply the subsea facilities. Karoon estimates the project cost at $175-195 million.

The Stena DrillMAX will drill the Bambo-1 exploration well this fall offshore The Gambia for operator FAR. The well will target three prospects – Soloo, Bambo, and Solo Deep – with potential combined resources of 1,118 MMbbl, in a water depth of 993 m (3,258 ft). Drilling should take around 30 days to complete. The location is 85 km (53 mi) offshore and 500 m (1,640 ft) south of the border with Senegal and the nearby Sangomar oilfield project.

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TechnipFMC has an integrated EPCI contract to supply and install all main subsea equipment for Tullow Oil’s Jubilee South East development, offshore Ghana. The project is an extension to the deepwater Jubilee development.

Eni has proven a second large field in Ghana’s offshore CTP block. The drillship Saipem 10000 drilled the Eban-1X well in 545 m (1,788 ft) of water, 8 km (5 mi) north of the Sankofa production hub, served by the FPSO John Agyekum Kufuor. The well encountered light oil in a thick Cenomanian sandstone reservoir. Eni estimates the potential resource from Eban and the earlier Akoma find at 1.1 Bboe, with potential for a fast-track subsea tieback through the FPSO, extending its production plateau.

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Nigeria has moved closer to revitalizing its petroleum sector after the National Assembly passed the country’s Petroleum Industry Bill. If various outstanding issues can be resolved before year-end, leading to presidential assent for a new petroleum law, this would reduce the fiscal uncertainty that has deterred upstream investments in recent years. Proposed changes include lower royalty and tax rates and better terms for marginal fields and indigenous producers.

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TotalEnergies has commissioned Yinson for a preliminary FEED study for an FPSO in 1,400 m (4,593 ft) of water in Angolan offshore block 20/21. Off neighboring South Africa, the company is assessing the feasibility of an early gas-condensate production system for a phased development of its deepwater discoveries in the Outeniqua basin, starting with last October’s Luiperd.

NORTHWEST EUROPE

Equinor and its partners have agreed on a new development in the Kristin area of the Norwegian Sea. Phase 1 of the 58.2-MMboe Kristin South project, with an estimated cost of $750 million, would involve tiebacks of the Lavrans and Kristin-Q discoveries to the Kristin semisubmersible production platform. A new subsea template would be installed at Lavrans while Kristin Q would be connected to an existing template, with a future phase potentially tying in the Erlend and Ragnfrid accumulations. Equinor has awarded contracts to Aker Solutions for the subsea production systems and TechnipFMC for the pipeline and subsea installations.

Another dual-field tie-in is in prospect in the northern North Sea. Aker BP has submitted plans to produce around 40 MMboe from the Kobra East and Gekko fields, including four multi-branch wells drilled from Gekko South and Gekko North, connected via subsea facilities to the Alvheim FPSO. The projected price is around $1 billion.

Elsewhere in the North Sea, Equinor has started oil and gas production from the Martin Linge field, 42 km (26 mi) west of the Oseberg field center in 115 m (377 ft) of water. The integrated fixed wellhead, production and accommodation platform can produce up to 115,000 boe/d: oil is processed on a nearby storage vessel for transfer to shuttle tankers. One feature of the development is the platform’s power supply, a 163-km (101-mi) AC subsea cable from the substation onshore in Kollsnes, western Norway.

Offshore pipelay has finished of the first string of the Nord Stream 2 gas trunkline system through the Baltic Sea from Russia to Germany. Pipelay works continue for the second string.

Saipem’s Castorone has been laying the 275-km (171-mi) Baltic Pipe gas trunkline between Denmark and Poland, starting operations close to the mid-point of the offshore route, near the Danish island of Bornholm. Construction could be completed this year, depending on weather conditions.

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Romanian gas distributor Romgaz has been negotiating to acquire ExxonMobil Exploration and Production Romania, a 50% partner in the XIX Neptun Deep block in the Romanian sector of the Black Sea. The concession includes the deepwater Domino gas discovery.

TPAO estimates in-place volumes at Amasra-1, its latest gas discovery in the Turkish sector of the Black Sea at 135 bcm. The find, drilled by the drillship Fatih-1, follows TPAO’s play-opening Sakarya discovery in 2020.

MIDDLE EAST

Energean has booked the drillship Stena IceMAX for up to five wells in the Israeli sector of the Mediterranean Sea during 2022-23. The line-up includes the Karish Main-04 appraisal well, targeting a further 166 MMboe recoverable from the Karish Main block, and including a possible oil rim; and a wildcat on the 700-bcf Athena prospect in block 12.

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The ADNOC/CNPC joint venture Al Yasat Petroleum Operations Co. has awarded NPCC a $744-million EPCI contract for the full-field development of the Belbazem offshore block, 120 km (75 mi) from Abu Dhabi city. Facilities will include three offshore wellhead towers, one on each of the Belbazem, Umm Al Dholou and Umm Al Salsal fields, and interconnecting subsea pipelines and cables from the Belbazem field to Zirku Island. Combined production capacity will be 45,000 b/d of 35° API crude, with first oil expected in 2023.

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DSME will build a fixed jacket platform for the Al-Shaheen oilfield offshore Qatar, under a $635-million contract awarded by North Oil Co. Al-Shaheen is the country’s largest offshore oilfield, currently served by 33 platforms and over 300 wells, in a water depth of 60 m (197 ft). DSME expects to complete the platform and interconnecting bridge with other facilities by the second half of 2023.

ASIA/PACIFIC

Crown LNG has contracted Aker Solutions to manage the FEED for the Kakinada LNG regasification project, 19 km (11.8 mi) northeast of Kakinada off eastern India. Aker Solutions will supply a concrete gravity-based structure (GBS) for the offshore terminal, with Siemens responsible for the power generation and electrical distributions equipment, and Wärtsilä providing the re-gasification system. The GBS will measure 40 m (131 ft) high, 60 m (197 ft) wide, and over 200 m (656 ft) long, with the topsides also supporting living quarters. Crown LNG is targeting year-round operations, including during the monsoon season.

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CNOOC has started gas-condensate production from the Lingshui 17-2 field in the northern part of the Qiongdongnan basin in the South China Sea. Water depth is around 1,500 m (4,921 ft). Linghsui 17-2 was China’s first large deepwater discovery, with a proven resource of over 100 bcm. Facilities comprise an 11-well subsea production system connected to a moored semisubmersible production platform with condensate storage. Gas heads through subsea pipelines to the Guangdong-Hong Kong-Hainan area. Output should peak next year at 328 MMcf/d and 6,751 b/d then level off over a 10-year period.

Chevron and its partners in the Gorgon venture off Western Australia have committed to the $4-billion Jansz-Io compression project. The Jansz-Io gas field, 200 km (124 m) offshore, in 1,340 m (4,429 ft) of water, came onstream in late 2015.  Aker Solutions will supply the subsea compression technology for the project, which involves construction and installation of a 27,000-metric ton (29,762-ton), normally unattended floating field control station; 6,500 metric tons (7,165 tons) of subsea compression infrastructure; and a 135-km (84-mi) subsea power link to Barrow Island, where Jansz-Io’s gas is converted to LNG. Under the current Gorgon Stage 2, Chevron is adding four new wells at the field and seven more at Gorgon.