Global E&P

Feb. 1, 2021
Equinor and partner BP have discovered two new oil fields offshore Newfoundland.


Equinor and partner BP have discovered two new oil fields offshore Newfoundland. Cambriol and Cappahayden are 500 km (310 mi) offshore in the Flemish basin, in water depths of 1,000 m and 600 m (3,281 ft and 1,968 ft). Both are also west of Equinor’s planned Bay du Nord oil field development.

BP was the sole bidder for the Canada-Newfoundland and Labrador Offshore Petroleum Board’s recent licensing round over the eastern Newfoundland region. The company secured Parcel 9, which extends partly beyond Canada’s 200-nautical mile zone.


Heerema’s crane lift vessel Thialf has completed an extensive decommissioning campaign for ExxonMobil at the Sable field offshore Nova Scotia. This involved removal of seven platform topsides, seven jackets and 22 conductors, subsequently transported across the Atlantic to Able UK’s decommissioning yard in northeast England.


LLOG Exploration expects to complete two wells this year on its sub-salt Spruance oil discovery in Ewing Bank blocks 877/921 in the US Gulf of Mexico. The second well, drilled last October, logged more than 200 net ft of oil pay. Spruance will be tied back to the EnVen-operated Lobster platform, 209 km (130 mi) south of New Orleans in 236 m (775 ft) of water.


BHP has commissioned McDermott International to manage the pre-FEED extension phase for the Trion field development offshore Mexico, in 2,500 m (8,200 ft) water depth. McDermott, which was awarded the original pre-FEED contract last March, is now focused on optimization of the design and construction execution for the field’s floating production unit, including risers and moorings. Houston Offshore Engineering and Wood are supporting this program.


Suriname is emerging as the latest hotspot off the northern coast of South America. Total and Apache have made a fourth oil discovery in offshore block 58, Keskesi East, drilled by the drillship Noble Sam Croft in 725 m (2,378 ft) of water. Total, which recently took over as operator, said the well encountered oil in Campano-Maastrichtian and Santonian reservoirs. The company has since contracted Maersk Drilling to provide two deepwater rigs for further exploration/appraisal drilling.

Earlier, Petronas and partner ExxonMobil proved oil in the Sloanea prospect in block 52, 121 km (75 mi) north of Paramaribo. The semisub Maersk Developer drilled the well, which intersected various hydrocarbon-bearing intervals in Campanian sandstones.


Petrobras, Shell and Petrogal, the partners in the BM-S-11 concession in the Santos basin off Brazil, have committed to purchase the 150,000-b/d FPSO P-71, which is nearing completion at Jurong Shipyard in Espírito Santo. The vessel will be allocated to the Itapu field. In addition, the trio will work on a new development plan for the Tupi field, which had been the FPSO’s original destination. According to Petrobras, the new plan, due to be submitted to the ANP, will focus on improving recovery from Tupi.


TGS expects to complete its Malvinas 3D seismic survey offshore Argentina during the current quarter. The BGP Prospector vessel has been acquiring data over a 5,000-sq km (1,931-sq mi) area, raising total coverage in the region to 18,000 sq km (6,950 sq mi).

Shell has agreed to farm into 30% of the CAN 100 block in Argentina’s offshore North Argentinian basin. Equinor is the current operator, in partnership with YPF. The block, which extends across 15,000 sq km (5,791 sq mi), is the largest in the basin.


Chariot Oil & Gas expects Morocco’s government to rubber-stamp the award of the new Rissana Offshore license later this year. Chariot will operate, in partnership with state-owned ONHYM. The 8,467-sq km (3,273-sq mi) permit will surround Chariot’s existing Lixus Offshore license, which contains the potential Anchois gas field development, and prospective northern sections of the previously held Mohammedia and Kenitra permits. Chariot plans to target the Mio-Pliocene gas play, thought to be on trend with Anchois.


TG-Geopartners may have started shooting a new 3D multi-client seismic survey over Ghana’s offshore Keta basin. The 10-month program, supported by the country’s Petroleum Commission, will cover 14,000 sq km (5,405 sq mi) over open blocks: processing of the data should be completed by spring 2022. Intervals of special interest are late Cretaceous turbidite channels present in the producing Jubilee field, and late Cretaceous/Tertiary basin floor fans that could hold large volumes of hydrocarbons.


BW Energy has agreed to pay Borr Drilling $14.5 million for the jackups Balder and Atla, both built in 2003. The company plans to convert the rigs to offshore production facilities for the Hibiscus/Ruche development in the Dussafu license offshore Gabon.


Nigerian state oil company NNPC and First E&P have produced first oil from the Anyala West development in shallow-water leases OML 83 and 85 in the Niger Delta. They aim to produce 142 MMbbl of oil and 98 bcf from the Anyala West and Madu fields via two unmanned, conductor-supported platforms connected to the FPSO Abigail-Joseph. The latter is a former Suezmax tanker with oil processing capacity of 60,000 b/d, gas handling capacity of 39 MMcf/d, and storage for 700,000 bbl of oil.


Total and its partners have made a second large gas-condensate discovery on block 11B/12B in the Outeniqua basin, 175 km (109 mi) off the southern coast of South Africa. The Luiperd-1X well, drilled by the semisub Deepsea Stavanger in 1,800 m (5,905 ft) of water, delivered 73 m (239 ft) of net pay in lower Cretaceous reservoirs. Rather than appraise this and the play-opening Brulpadda find, the partners have opted to engage with the South African authorities on advancing commercialization options.


ConocoPhillips was the most consistently successful explorer offshore Norway last year, achieving four potentially commercial discoveries. The latest, and possibly the largest find throughout the shelf in 2020, was Slagugle, 23 km (14 mi) northeast of the Heidrun field in the Norwegian Sea, in 355 m (1,165 ft) water depth. Early analysis suggested 75-200 MMboe recoverable. Previously, the company found gas with its first well on license 1009 in the central Norwegian Sea, 27 km (16.8 mi) west of the Skarv field.

In the southern Norwegian North Sea, the company has started production from Tor II, thought to be the first redevelopment of a previously shut-down field in the Norwegian sector. The facilities, 1 km (0.6 mi) west of the platform used for the original Tor development, comprise two four-slot subsea production systems with eight wells, connected via a multiphase/gas-lift pipelines to the Ekofisk 2/4 M wellhead platform. ConocoPhillips is aiming to recover up to 70 MMboe.


Equinor and its partners plan to spend $350 million on new facilities to improve recovery from Statfjord Ost in the North Sea, which came onstream in 1994. Production is exported through pipelines to the Statfjord C platform, 5 km (3.1 mi) to the southwest. Four new wells will be drilled from the existing subsea templates to extract a further 23 MMboe, boosting the recovery factor from the present 56% to 62%.


Denmark’s government has cancelled a planned eighth offshore licensing round and has pledged to issue no further licenses. The government has pledged to end all fossil fuel extraction by 2050.


Energean has committed to the Karish North subsea tieback in the Israeli sector. The discovery, containing 32 bcm of gas and 34 MMbbl of liquids, will be connected to the FPSO Energean Power, 5.4 km (3.36 mi) distant, at an estimated cost of around $150 million. Start-up should follow during the second half of 2023.

The company has also strengthened its position offshore western Greece through acquiring Total’s 50% operated stake in exploration block 2, lifting its interest to 75%. Work to date on the block has identified a prospect that could be analogous to the producing Vega field off southeast Italy.


First gas has flowed through the TAP pipeline across the Adriatic Sea from western Albania to eastern Italy, after BP started commercial deliveries from the Shah Deniz II development in the Caspian Sea. The full Southern Gas Corridor pipeline system that terminates with TAP will eventually export 16 bcm/yr from Shah Deniz to countries across the Caucasus region and southeast Europe.

Offshore northern Egypt BP, via the Pharaonic Petroleum Company joint venture, has produced first gas from the Qattameya field in the North Damietta concession. Qattameya, proven in 2017, is tied back 50 km (31 mi) to the Ha’py and Tuart field facilities via a new pipeline and subsea umbilical.


Eni has been awarded operatorship of the largest concession offered under Abu Dhabi’s second competitive bid round. The company will operate the 11,660-sq km (4,502-sq mi) block 3 off northwest Abu Dhabi with a 70% interest, the remainder held by a subsidiary of PTTEP. Terms include both exploration drilling (planned to start this year, according to PTTEP), and appraisal of existing discoveries.

ADNOC and ExxonMobil have signed a strategic framework agreement covering joint upstream R&D. Technologies of mutual interest are said to include smart reservoir management and well monitoring systems. The companies are partners in the ongoing development of the giant offshore Upper Zakum oil field.


Reliance Industries and BP have produced first gas from the R Cluster subsea field development in block KG D6 offshore eastern India. According to BP, the water depth of more than 2,000 m (6,252 ft) is the deepest of any project offshore Asia to date. R Cluster’s production, due to peak this year at close to 13 MMcm/d, is sent 60 km (37 mi) via a pipeline to the KG D6 Control & Riser platform off the Kakinada coast. 


Myanmar’s government has awarded PTTEP an exclusive development right for the country’s Integrated Domestic Gas to Power project. This will harness gas from PTTEP’s fields in the Gulf of Moattama, starting with the Zawtika and Myanmar M3 projects, to generate electrical power for Myanmar’s domestic market. The $2 billion of associated investments will include upstream development facilities and a new 370-km (230-mi) offshore/onshore gas pipeline between Lanbauk, Daw Nyein and Kyaiklat, where a 600-MW combined cycle power plant will be located. PTTEP expects to take a final investment decision in 2022.


KrisEnergy has started production from Cambodia’s first offshore field development, Apsara in Block A in the Khmer basin. The Singapore-based operator expects the jackup PV Drilling III to have completed all five wells for the Mini Phase 1A project by mid-February, pushing output to around 7,500 b/d. Facilities for this initial phase include a three-deck wellhead support platform, a production barge (Ingenium II) for processing the wellstream, and the crude storage vessel MT Strovolos, moored nearby.


Petronas Carigali has assumed operatorship of the E11 gas hub, 130 km (81 mi) offshore Sarawak, from Sarawak Shell. The facility has been in operation since 1982, under the MLNG PSC.

Petronas has contracted the PGS/TGS/WesternGeco consortium to acquire and process up to 105,000 sq km (40,541 sq mi) of multi-sensor 3D seismic data over the Sarawak basin. This is a follow-on to the consortium’s ongoing campaign in the Sabah offshore region, awarded in 2016.


CNOOC has brought onstream two new projects offshore China. The Penglai 25-6 oilfield area 3 development in the south central Bohai Sea, in 27 m (88.6 ft) of water, involved the addition of a new wellhead platform linked to processing facilities at the Penglai oil fields. CNOOC and partner ConocoPhillips plan to drill 38 producer and 20 water injector wells and to hit peak crude production of 11,511 b/d by 2023.

Earlier, the company started up the Liuhua 29-1 gas field in the eastern South China Sea, in water depths ranging from 640-785 m (2,100-2,575 ft). This is connected to facilities serving the Liuhua 34-2 and Liwan 3-1 gas fields, with peak production of 62 MMcf/d anticipated in 2022.


Carnarvon Petroleum has struck an agreement under which Advance Energy will farm into up to 50% of the Buffalo oil field redevelopment project in the Timor Sea. BHP originally produced the field via four wells from an unmanned wellhead platform, connected to an FPSO. Carnarvon, which was awarded the surrounding permit in 2016, has been tendering for a drilling management services contractor for the Buffalo-10 well, which it aims to spud in late 2021. It estimates remaining resources at the field at around 31 MMbbl.


Santos and its partners have sanctioned the $235-million, Phase 3C infill drilling program at the Bayu-Undan gas-condensate field in the Timor Sea, targeting over 20 MMboe gross reserves. The jackup Noble Tom Prosser will start drilling the three production wells (one subsea and two platform wells) in 2Q.