OGJ Newsletter

Jan. 17, 2022


CNR sets 2022 budget, eyes conventional growth

Canadian Natural Resources Ltd., Calgary, expects its 2022 budget to target base capital of about $3.6 billion that delivers targeted production of 1.27-1.32 MMboe/d, with year-over-year near-term growth of about 60,000 boe/d primarily from production growth in conventional exploration and production operations.

In 2022, growth capital of about $700 million will be allocated to long-life, low decline thermal in situ and oil sands mining and upgrading assets which targets incremental annual production in 2023 and beyond, resulting in total production increases of 63,000 b/d by 2025.

Thermal in situ production is targeted to add about 22,000 b/d in 2024, increasing to about 49,000 b/d in 2025. Growth capital being allocated to oil sands mining and upgrading in 2022 is targeted to reduce required turnaround times in the future, increasing the capacity of zero decline, high value production by about 5,000 b/d of synthetic crude oil in 2023, increasing to about 14,000 b/d in 2025.

Planned turnarounds at our Oil Sands Mining and Upgrading assets, which are incorporated in the above 2022 production target, are expected to impact yearly production volumes by about 35,000 b/d.

The product mix is targeted at 46% light and synthetic crude oil, 28% heavy crude oil, and 26% natural gas.

Liquids production, including synthetic crude oil, is targeted at 940,000-982,000 b/d, of which long life low decline production is targeted to be some 78% of total liquids production.

Conventional E&P liquids production is targeted at 250,000-267,000 b/d.

Natural gas production is targeted at 1,980-2,030 MMcfd, representing growth of about 18% from targeted 2021 levels.

Eight blocks awarded in Egypt digital bid round

Eight blocks were awarded in the first international digital bid round for oil and gas exploration and production in the Mediterranean, Western Desert, and the Gulf of Suez, according to an announcement from Egypt’s Minister of Petroleum and Mineral Resources Tarek El Molla.

The round, which concluded Aug. 1, 2021, included nine blocks in the Mediterranean Sea, 12 in the Western Desert, and three in the Gulf of Suez.

In total, two blocks in the Mediterranean, four in the Western Desert, and two in the Gulf of Suez were awarded to Eni, BP, Apex International, Energean Egypt, Ina Nafta, ENAP Sipetrol Egypt, and United Energy.

The minimum investment cost is about $250 million during the exploration phases to drill a minimum of 33 wells, in addition to the $23.7 million in signature grants.

Sipetrol Egypt ENAP was awarded exploration and development of the 875 sq km West Amer Block in the central part of the Gulf of Suez, an area characterized by high oil productivity and numerous exploitation concessions.

Eni SPA was awarded five new exploration licenses offshore and onshore in blocks EGY-MED-E5 and EGY-MED-E6, Eastern Mediterranean Sea, Block EGY-GOS-13, Gulf of Suez, and Blocks Egy-WD- 7 and EGY-WD-9, Western Desert. Total acreage is about 8,410 sq km.

ENI is operator at four licenses. ENI has 50% interest in block EGY-MED-E5ENI with partner bp (50%). ENI subsidiary IEOC Production BV has 100% interest in blocks EGY-MED-E6, EGY-GOS-13, and EGY-WD-9. ENI has 50% interest in Block Egy-WD- 7 with partner APEX International Energy (50%).

The Egyptian General Petroleum Corp. (EGPC) and Egyptian Natural Gas Holding Co. (EGAS) offered the first digital international bid round in 2021 for petroleum E&P operations in 24 blocks. Schlumberger’s Egypt Upstream Gateway (EUG) provided virtual access to all data including information of the offered blocks on an interactive map, data room viewing, seismic surveys, subsurface insights, and data packages.

Chevron completes Suriname Block 5 farmout

Chevron Corp completed farmout of 20% of its 60% interest in offshore Suriname Block 5 to Royal Dutch Shell. The block is 2,235 sq km and is west of the shallow offshore area 120 km from the coast with water depth of up to 100 m.

Paradise Oil Comp., a subsidiary of Suriname’s state-run Staatsolie, retains 40% stake in the block as a non-executive partner, according to the farmout contract.

Staatsolie and Chevron signed a 30-year production sharing contract in October for Block 5 (OGJ Online, Oct. 14, 2021). It is the first time that Staatsolie is participating in offshore activities as a partner.

Exploration & Development Quick Takes

ExxonMobil discovers more oil offshore Guyana

ExxonMobil Corp. made oil discoveries at Fangtooth-1 and Lau Lau-1 in Stabroek block, offshore Guyana.

Fangtooth-1 was drilled by the Stena DrillMAX, about 11 miles (18 km) northwest of Liza field in 6,030 ft (1,838 m) of water and encountered about 164 ft (50 m) of high-quality oil-bearing sandstone reservoirs.

Lau Lau-1 was drilled by the Noble Don Taylor in 4,793 ft (1,461 m) of water and is about 42 miles (68 km) southeast of Liza field. The well encountered about 315 ft (96 m) of high-quality hydrocarbon-bearing sandstone reservoirs.

Fangtooth and Lau Lau will add to previous recoverable resource estimate of 10 billion boe for the block, which covers 6.6 million acres (26,800 sq km).

In other progress, the Liza Unity floating production storage and offloading (FPSO) vessel is undergoing hookup and commissioning after arriving in Guyanese waters in October 2021. The Unity is on track to start production in first-quarter 2022 and has a target of 220,000 b/d at peak production.

The hull for the Prosperity FPSO, the third project on Stabroek block at Payara field, is complete and topside construction activities are ongoing in Singapore for planned production start-up in 2024 (OGJ Online, Oct. 12, 2020). The field development plan and environmental impact assessment for the fourth potential project, Yellowtail, have been submitted for government and regulatory review (OGJ Online Nov. 17, 2021).

ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. is operator at Stabroek block (45%) with partners Hess Guyana Exploration Ltd. (30%) and CNOOC Petroleum Guyana Ltd. (25%).

ADNOC invests $946 million for Umm Shaif field development

Abu Dhabi National Oil Co. (ADNOC) let a $946 million engineering, procurement, and construction (EPC) contract for development of Umm Shaif field.

Umm Shaif field is in the Arabian Gulf about 85 miles northwest of Abu Dhabi. It produces both crude oil and natural gas.

The Long-Term Development Plan – Phase 1 (LTDP-1) EPC contract was awarded by ADNOC Offshore to National Petroleum Construction Co. (NPCC). The scope of the award covers engineering, procurement, fabrication, installation, and commissioning activities required to maintain the offshore field’s 275,000 b/d crude oil production capacity, increase efficiencies, and enhance the field’s long-term potential, ADNOC said in a release Jan. 5.

The EPC contract, which is due to be completed in 2025, comprises two packages for network expansion and new well-head towers. The first package includes modifications and extension of existing infrastructure with installation of new subsea cables and pipelines for debottlenecking. The second package includes the design of three lean well-head towers with associated new pipelines.

The contract incorporates rigless electrical submersible pumps and other digital field technologies.

Abu Dhabi targets self-sufficiency in natural gas and expansion of oil-production capacity to 5 million b/d by 2030 under an expanded budget approved in 2018 by the Supreme Petroleum Council (OGJ Online, Nov. 5, 2018).

Petronas makes third gas discovery in Balingian Province

Petronas Carigali Sdn Bhd (PCSB), a subsidiary of Petronas, has made a gas discovery in Block SK411 in the shallow waters of Balingian Province about 170 km northwest off the coast of Sarawak, Malaysia.

The Hadrah-1 well was drilled to a total depth of 1,850 m in November 2021 and encountered gas within a 200-m thick sequence of high-quality sandstone and carbonate reservoirs.

The discovery supports prospectivity in the underexplored Cycle I, II & III plays within the Balingian province, said Emeliana Rice-Oxley, vice-president of exploration, upstream.

“The excellent quality of reservoirs encountered augurs the remaining potential in the surrounding areas, with PCSB well positioned to pursue the untapped similar plays in Blocks SK411 and SK306,” Rice-Oxley said.

PCSB is operator with 90% participating interest. E&P Malaysia Venture Sdn Bhd. holds the remaining 10%.

Hadrah-1 is Petronas’ third gas discovery in this province in 2021, after Sirung-1 and Kulintang-1 in March and May, respectively. In 2019, oil and gas were also discovered within the same play at D18 field.

Drilling & Production Quick Takes

Santos JV to drill Dorado satellite prospects in January

The Santos Ltd.-Carnarvon Petroleum Ltd. joint venture in Dorado oil discovery permits WA-437-P and WA-438-P, Bedout sub-basin, offshore Western Australia plans to drill two satellite prospects. The Pavo-1 wildcat is scheduled to spud mid-late January and the Apus-1 well will follow. The JV has contracted jack up rig Noble Tom Prosser for the two-well program.

Pavo-1, 42 km east of Dorado in 88 m of water, will target the primary Caley to Crespin interval, similar to that intersected in the Dorado discovery. The prospect has estimated potential to hold around 82 million bbl of recoverable liquids and 100 bcf of gas. Following initial drilling, the well will be deepened to acquire geological information on two underlying intervals to provide data regarding Bedout sub-basin’s broader potential.

Pavo-1 drilling is expected to take 2 months before the rig is moved to Apius-1 about 20 km to the southwest. Apus-1, in 84 m of water, will target the Caley and Milne intervals which are similar to those intersected at Dorado. This well is expected to have a drilling time of 1 month. The Apus prospect is estimated to have potential to hold 235 million bbl of recoverable liquids and 400 bcfd of gas.

Santos has 80% interest and operatorship. Carnarvon has 20%.

Kuwait Energy to bring Abu Sennan well on production

Kuwait Energy Egypt will bring the Al Jahraa-13 development well onstream in the Abu Sennan license, 7 km north of producing Al Jahraa field in Egypt’s Western Desert, partner United Oil & Gas PLC said in a Dec. 29 release.

The well encountered 17.5 m net pay in the oil-bearing Upper and Lower Bahariya reservoir targets and reached total depth several days ahead of schedule and under budget. The well will be tested and completed and will be brought immediately onstream through the existing Al Jahraa infrastructure.

Al Jahraa-13 is the final well in the Abu Sennan 2021 drilling program.

Abu Sennan is operated by Kuwait Energy Egypt (25%). Joint venture partners are United Oil & Gas (22%), Global Connect Ltd. (25%), and Dover Investments (28%).

Santos flows gas to surface after fracturing Beetaloo wells

The Santos Ltd.-led joint venture in Northern Territory Beetaloo subbasin permit EP161 has flowed gas to surface following a fracture stimulation program in the Tanumbirni-2H and -3H horizontal wells.

The wells are being dewatered and are undergoing cleanup activities.

Both wells were successfully fracture stimulated late 2021 across 11 and 10 stages, respectively, within the main mid-Velkerri B target shale formation.

Once stabilized flow conditions have been established, the JV plans a 30-day flow test with flow performance noted at regular intervals to provide information on steady-state production, the potential well deliverability, and estimated ultimate gas recovery.

Partner Tamboran Resources Ltd. said estimated steady production commerciality threshold for wells within the subbasin is 3 MMcfd per 1,000 m horizontal length.

In line with other unconventional gas basins, the expected horizontal sections in development wells in the Beetaloo are expected to be up to 3,000 m.

Tamboran has commissioned Netherland Sewell and Associates Inc. to provide a revised independent resource report. Publication is expected in this year’s first half.

Santos has a 75% interest and operatorship of the Tanumbirini wells. Tamboran has 25%.

Gazprom Neft establishes new production center

Gazprom Neft commissioned oil production infrastructure at its Pestsovoye and En-Yakhinskoye fields in the Yamalo-Nenets Autonomous Okrug, Russia. Production volumes are expected to exceed 6.3 million tonnes of oil equivalent as early as this year. Oil-rim deposits at the two fields from part of the company’s new oil production center in the Arctic.

A central gathering plant has been commissioned at Pestsovoye field. The complex, which will also include a compressor station and gas-treatment unit, will allow all types of crude and feedstocks—oil, gas, and condensate—to be processed and shipped.

Gazprom Neft subsidiary Gazpromneft-Zapolyarye is developing oil-rim deposits at Pestsovoye and En-Yakhinskoye fields under long-term risk-operatorship agreements held by license owner Gazprom Dobycha Urengoy LLC.

Gazprom Neft expects to produce 2.8 million tonnes of liquid hydrocarbons and 4.3 cu m of gas at these fields in 2022. Production of hydrocarbons at Achimovsky deposits at the Pestsovoye field will be considered, the company said.

Aerial monitoring of construction, as well as mobile modular oil production and treatment systems have been installed at the field from readymade modules, bringing field development forward by 2 years, Gazprom said. Multilateral wells with horizontal shafts running more than 2 km have been drilled to produce oil and gas from narrow oil rims.


Indian Oil lets contract for Barauni refinery expansion

Indian Oil Corp. Ltd. (IOC) has let a contract to Larsen & Toubro Ltd. subsidiary L&T Hydrocarbon Engineering (LTHE) to revamp a major processing unit as part of IOC’s project to increase crude oil processing capacity at its 6-million tonne/year (tpy) Barauni refinery in Begusarai District, Bihar (OGJ Online, Aug. 6, 2021).

As part of the Jan. 5 contract, LTHE will deliver detailed engineering as well as supply critical equipment and components for the modification, revamp, and upgrade of the refinery’s existing residue fluid catalytic cracking (RFCC) unit, Larsen & Toubro said in a release to investors.

Alongside increasing capacity of the unit, LTHE’s scope of work on the project will include conversion of the RFCC into an INDMAX FCC unit that will process a feedstock of hydrotreated and straight-run residue into propylene, which in turn will be used for production of polypropylene in a downstream petrochemical unit at the refinery, according to the service provider.

While Larsen & Toubro—which valued the contract at between 10-25 billion rupees—did not reveal a post-revamp capacity of converted INDMAX FCC, IOC previously told the government of India the Barauni expansion would involve expanding capacity of the refinery’s existing 1.4-million tpy RFCC to 1.7 million tpy (OGJ Online, Apr. 8, 2020).

The entirety of the Barauni crude processing capacity expansion currently remains on schedule for commissioning by April 2023 at an overall cost of 148 billion rupees, IOC most recently told investors.

Lucid advances plan to develop Permian CCS project

Lucid Energy Group is moving forward with plans to develop what will become the Permian basin’s largest carbon capture and sequestration (CCS) project at the operator’s northern Delaware basin Red Hills natural gas processing complex in Lea County, NM, about 15 miles northwest of Jal.

The US Environmental Protection Agency (EPA) has approved Lucid’s previously submitted monitoring, reporting, and verification (MRV) plan for the project, which aims to safely ensure permanent CCS of carbon dioxide (CO2) from natural gas volumes the operator processes and treats for customers at the complex, Lucid said on Jan. 11.

Scalable and designed for future growth capacity, the CCS project will allow for sequestration and permanent storage of CO2 in Lucid’s existing and permitted disposal wells, according to the operator.

Alongside enabling Lucid to offer a lower carbon-intensity (CI) service to customers and reduced operational carbon footprint to stakeholders, the Red Hills MVP plan—pending subsequent approval by the US Internal Revenue Service—also will provide Lucid certain CCS-related tax credits, the company said.

Lucid—which currently removes more CO2 from Permian basin shale production than any other midstream operator—will develop the CCS project by simply modifying and expanding existing operations at the Red Hills complex, said Mike Latchem, Lucid’s chief executive officer.

While Lucid did not directly confirm a definitive timeline for the planned CCS project, the operator informed EPA officials that it intended to immediately implement the MVR plan upon its approval by the agency, according to official EPA documents published in December 2021.

As the Delaware basin’s largest gas processing complex, Lucid’s Red Hills site consists of five plants with a combined processing capacity of 920 MMcfd (OGJ Online, Mar. 23, 2021).

Individual plant capacities include:

  • Red Hills I, 60 MMcfd.
  • Red Hills II, 200 MMcfd.
  • Red Hills III, 200 MMcfd.
  • Red Hills IV, 230 MMcfd.
  • Red Hills V, 230 MMcfd.

Development of a sixth plant at the site—the 230-MMcfd Red Hills VI plant—was also under way during 2021, according to the operator’s latest sustainability report.

Baltic Chemical lets contract for Ust-Luga complex

JSC RusGazDobycha subsidiary Baltic Chemical Complex LLC (BCC) has let a contract to DL E&C Co. Ltd. to provide design and equipment procurement services for BCC’s $13-billion ethane-cracking complex, or gas chemical complex (GCC) portion, of the larger PJSC Gazprom-RusGazDobycha combined gas processing, liquefaction, and chemical complex for processing ethane-containing gas (CPECG) under construction at the Gulf of Finland near the seaport of Ust-Luga, Leningrad Oblast, Russia, about 110 km southwest of St. Petersburg.

Valued at €1.17 billion, the contract award follows DL E&C’s participation since December 2019 in basic project design of BCC’s GCC, the service provider said on Jan. 3.

DL E&C said it expects its scope of work under the contract—which will help manage overall project risks as well as enable completion of optimal detailed design to maximize efficiency and profitability of the complex—will pave the way for a future contract award to participate in the project’s main construction.

Further details regarding DL E&C’s contract award were not revealed.

This latest contract for the GCC portion of the CPECG follows BCC’s earlier awards to McDermott International Ltd. and Lummus Technology LLC for a series of engineering services and technologies at the ethane-cracking complex, that once in operation, will produce 3 million tonnes/year (tpy) of polyethylene, 120,000 tpy of butane, and 50,000 tpy of hexane.

Alongside BCC’s GCC, the CPECG—which officially began construction in May 2021—also includes RusKhimAlyans’—a 50-50 special-purpose venture of Gazprom and RusGazDobycha—integrated natural gas processing and liquefaction complex (GPC of the CPECG), which will have 13-million tpy liquefaction capacity and initially process 45 billion cu m/year (bcmy) of wet natural gas feedstock it receives from Gazprom’s Achimov and Valanginian deposits in the Nadym-Pur-Taz region of the Yamal Peninsula.

The GPC will produce as much as 4 million tpy of ethane, and more than 2.2 million tpy of LPG, with ethane from the complex to feed nearby BCC’s ethane cracking project that—once in operation—will produce more than 3 million tpy of polymers (OGJ Online, Nov. 9, 2020). About 18 bcmy of gas remaining after processing at GPC—including ethane extraction, LPG, and 13 million tpy of LNG—will be exported from the site via Gazprom’s gas transmission lines.

RusGazDobycha most recently said it expects to complete first-phase construction of the GCC during fourth-quarter 2023, with second-stage construction to wrap in fourth-quarter 2024.


Novatek reaches 1.6-million tpy Arctic LNG 2 sales agreements

PAO Novatek subsidiary Novatek Gas & Power Asia Pte. Ltd. has signed long-term sales agreements for production from its 19.8-million tonne/year (tpy) Arctic LNG 2 project with Zhejiang Energy Gas Group, a subsidiary of the Zhejiang Provincial Energy Group, and ENN LNG (Singapore) Pte. Ltd., a subsidiary of ENN Natural Gas Co. Ltd.

The Zhejiang contract is for 1-million tpy over 15 years, delivered ex-ship (DES) to Zhejiang Energy’s LNG terminals in China, and follows a heads-of-agreement reached between the parties last year. The 11-year contract with ENN is for 600,000 tpy sent DES to its 6-million tpy Zhoushan LNG terminal.

Arctic LNG 2 will use three 6.6-million tpy liquefaction trains. The plant will also produce 1.6-million tpy of

gas condensate.

Natural gas feedstock will be supplied from Utrenneye field, with 2P reserves under the Petroleum Resources Management System of 1.434 billion cu m and 90 million tons of liquids.

Project participants include: Novatek (60%), TotalEnergies SE (10%), China National Petroleum Corp. (10%), China National Offshore Oil Corp. (10%), and Japan Arctic LNG, a consortium of Mitsui & Co Ltd. and Japan Oil, Gas and Metals National Corp. (10%).

Mountain Valley pipeline gets water-crossing permits

Equitrans Midstream Corp.’s 303-mile, 2-bcfd Mountain Valley natural gas pipeline has received permission from Virginia’s State Water Control Board to cross roughly 150 stream and wetlands.

Earlier in December 2021, Virginia’s Air Pollution Control Board denied approval of the pipeline’s Lambert compressor station. The station, part of the line’s Southgate extension, was to be sited in Pittsylvania, Va.

The pipeline also received its federal Clean Water Act Section 401 stream-crossing permit from the West Virginia Department of Environmental Protection (WV DEP).

The pipeline continues to face legal challenges from Sierra Club and other environmental groups in the US Court of Appeals for the Fourth Circuit regarding its water permits.

Mountain Valley construction is about 94% complete with much of the remaining work including water crossings in both West Virginia and Virginia. The pipeline is expected to transport gas from the Marcellus and Utica shales to Mid-Atlantic and southeast US consumers.

Equitrans expects Mountain Valley to enter service third-quarter 2022. The company began work on the pipeline in February 2018.

UGI to acquire natural gas gathering system

UGI Corp. subsidiary UGI Energy Services LLC has agreed to acquire Stonehenge Appalachia LLC from Stonehenge Energy Holdings LLC for about $190 million.

The Stonehenge natural gas system, in Butler County Pennsylvania, includes more than 47 miles of pipeline and associated compression assets, and has gathering capacity of 130 MMcfd.

Also in the Appalachian basin, UGI acquired the assets of Columbia Midstream Group in 2019 and purchased an ownership stake in the Pine Run gathering system in 2021.

The transaction is subject to customary regulatory and other closing conditions. Assuming fulfillment of all conditions, the transaction is expected to close by Jan. 31, 2022.

FERC investigates Rover and Midship gas pipelines

The US Federal Energy Regulatory Commission (FERC) is gathering information on two natural gas pipelines to determine whether they should be hit with civil penalties for improper construction methods. Both the Rover Pipeline, running from West Virginia to Michigan, and Midship Pipeline in Oklahoma are operating and expected to stay in operation. But FERC Chairman Richard Glick said both cases should remind companies that significant penalties are possible if they do not live up to the stipulations in their federal authorizations.

FERC is trying to determine whether Rover Pipeline LLC, a unit of Energy Transfer LP, should be hit with a $40 million civil penalty for improper construction work when the line was built under the Tuscarawas River in Stark County, Ohio. FERC’s Office of Enforcement concluded that Rover used diesel and other unapproved substances in drilling mud, and that the company improperly disposed of contaminated drilling mud.

The commissioners have asked Energy Transfer to respond before making their own determinations.

Rover is a 711-mile line, 42-in. OD pipeline that carries up to 3.25 bcfd to supply regional gas markets with Marcellus shale production.

FERC also has received reports that Midship Pipeline Co. LLC was built incorrectly. An earlier order required the company, indirectly owned by Cheniere Energy Inc. and EIG Global Energy Partners, to adequately restore land along its route and negotiate settlements with landowners. The company has not yet resolved all landowner claims.

The FERC chairman said there also is evidence that rock and construction debris were buried instead of removed. Potentially significant civil penalties could be levied, Glick said.

Midship Pipeline runs about 200 miles through Oklahoma to connect the STACK and SCOOP gas fields to pipelines that can take gas to the Gulf Coast and the East. It is a 36-in. OD line that can carry up to 1.44 bcfd of gas.

At its monthly meeting, FERC also put to rest two proposed pipelines the owners of which had given up on winning permits. The commission vacated its authorization of the PennEast Pipeline, which would have run from Pennsylvania to New Jersey. The agency also vacated its authorizations of the Pacific Connector Gas Pipeline and Jordan Cove LNG projects, which would have allowed export of LNG from Coos Bay, Ore.

Both PennEast and Pacific Connector were stymied by state and local opposition. Pembina Pipeline Corp. announced its decision to give up 2 weeks before the FERC meeting.

Equinor, Wellesly find oil near North Sea Fram field

Equinor Energy AS discovered oil in the Troll and Fram area in production license 630 in the North Sea. Preliminary calculations of the expected size indicate 3.3-5.2 million standard cu m of recoverable oil equivalent (21–33MMboe). The partners believe the discovery to be commercially viable and will consider tying it to the Troll B or Troll C platform.

Exploration wells 35/10-7 S and 35/10-7 A in the Toppand prospect—the second and third in the license—were drilled by the West Hercules drilling about 8 km west of Fram field and 140 km northwest of Bergen.

Well 35/10-7 S encountered an oil column of around 75 m in the lower part of the Ness formation and in the Etive formation. There were also traces of hydrocarbons in the shale and coal dominated upper part of the Brent Group. A total of around 68 m of effective sandstone reservoir of good to very good reservoir quality was encountered in the Ness and Etive formations combined.

The Oseberg formation was around 48 m thick and filled with water. It mainly consisted of sandstone of moderate reservoir quality. The oil-water contact was not proven in the well, but by aid of pressure data it is estimated to be located at around 3,303 m. Sandstone of moderate to poor reservoir quality was encountered in the Cook formation, but the reservoir was filled with water.

Exploration well 35/10-7 A encountered a 60-m oil-filled sandstone-dominated interval in the lower part of the Ness formation and in the Etive formation. A total of around 67 m of effective sandstone reservoir of good to moderate quality were encountered in the Ness and Etive formations combined.

The Oseberg formation was around 48 m thick and mainly consisted of oil-filled sandstone of moderate reservoir quality. An oil-water contact was proven at around 3,290 m, accounting for a 30 m oil column.

Well 35/10-7 S was drilled to a vertical depth of 3,509 m below sea level and a measured depth of 3,563 m below sea level and was completed in the Dunlin Group of early Jurassic rock. Well 30/10-7 A was drilled to a vertical depth of 3,370 m below sea level and a measured depth of 3,574 m below sea level and was completed in the upper part of the Dunlin Group.

Water depth in the area is 354 m. The wells have been permanently plugged.

The rig has moved to drill exploration well 6407/9-13 in Equinor-operated production license 1060 in the Norwegian Sea.

Equinor is operator with 50% interest. Wellesley holds the remaining 50%.