GENERAL INTEREST Quick Takes
Suncor to record $425-million impairment on White Rose assets
Suncor Energy Inc., Calgary, will record a $425 million (Can.) non-cash after-tax impairment charge in fourth-quarter 2020 on its share of the White Rose asset and West White Rose project in the Jeanne d’Arc basin off Newfoundland and Labrador.
The project operator, Husky Energy Inc., agreed in October 2020 to merge with Cenovus Energy Inc., casting “significant doubt on the future of the project,” Suncor said Jan. 4 (OGJ Online, Oct. 26, 2020). The deal closed Jan. 1.
While the asset is currently producing, the West White Rose project was intended to access 200 million bbl (gross) of light crude oil and extend the life of White Rose field by 14 years. Construction for the project at Argentia and Marystown was suspended in March 2020 and construction workers demobilized due to COVID-19. In a September 2020 update, Husky said the project was 60% complete, but that all major construction remained on hold.
Discussions with the operator and various levels of government to determine the future of the project are ongoing. The Government of Newfoundland and Labrador agreed to provide some support for the West White Rose project in 2021, Suncor said.
The company’s 2021 guidance remains unchanged as White Rose field will remain online producing as expected and Suncor’s guidance did not include any major capital spend on the West White Rose project in 2021.
The White Rose asset joint venture owners are Cenovus (operator, 72.5%,) and Suncor (27.5%). The West White Rose Project joint venture owners are Cenovus (operator, 69%), Suncor (26%) and Nalcor (5%).
Vintage Energy books Vali gas reserves
Results of an independent review of the Vali gas discovery in southwest Queensland Cooper basin permit ATP2021 support commercialization of the field with planned connection to the Moomba gathering system in South Australia, Vintage Energy Ltd., Adelaide, said Dec. 14 (OGJ Online, Sept. 17, 2020).
Carried out by the ERC Equipoise, the reserves booking—the first for Vintage—estimated gross 1P reserves for the Permian age Patchawarra formation reservoir of 12.3 bcf, 2P reserves of 30.3 bcf, and 3P reserves of 78.9 bcf.
The Vali-1 ST1 discovery well encountered stacked gas pay in the Nappamerri, Toolachee, and Patchawarra formations, but the reserve estimates are for the Patchawarra reservoir only, Vintage said.
Vintage said it hopes gas produced from the field will be much greater than the figure estimated by ERCE, with the upside potential to come from the two shallower reservoirs.
The Vali-1 ST1 well penetrated a four-way dip closure with the Patchawarra formation comprising 22 stacked sandstone reservoirs embedded with shales and coals. Twenty of the reservoirs are interpreted to contain gas.
The well was fracture stimulated and tested in July-August and flowed over 4 days at increasing chokes and gas flow rates. A 2-day extended flow test resulted in a strong, stable gas flow rate of 4.3 MMcfd through a 36-64-in. choke at 942 psi wellhead pressure (OGJ Online, Aug. 21, 2020).
Development plans include up to nine vertical fracture-stimulated wells including the discovery well. They will be drilled at the rate of 1-2 wells/year and progressively tied into Santos-operated Beckler field via a 13 km dual 4-in. composite pipeline.
The development is now in front-end engineering design stage. First production is planned for first-half 2021.
Vintage is operator with 50%. Metgasco has 25% and Bridgeport 25%.
Earthstone adds Midland basin assets with Independence Resources acquisition
Earthstone Energy Inc. has agreed to acquire Warburg Pincus-backed Independence Resources Management LLC (IRM) for $185.9 million. The price consists of an estimated $135.2 million in cash and 12.7 million shares of Earthstone stock.
IRM’s asset base and operations include average production of 8,780 boe/d (66% oil) for third-quarter 2020. The company holds 4,900 net acres (100% HBP, 93% operated) in Midland and Ector counties, Tex., and includes inventory of 70 undeveloped horizontal locations targeting Middle Spraberry, Lower Spraberry, and Wolfcamp A zones with additional potential locations in Jo Mill, Wolfcamp B, and Wolfcamp D zones. Also included are an additional 38,500 net acres (100% HBP, 100% operated) in eastern Midland basin.
Earthstone expects a 52% increase to pro forma third-quarter 2020 production to 25,700 boe/d from 17,000 boe/d.
The transaction is expected to close in first-quarter 2021. It has been approved by the board of directors of Earthstone and by the members of IRM. No further approvals are required. Warburg will have the right to appoint one director to Earthstone’s board. EnCap Investments LP will maintain the three existing EnCap-affiliated directors, resulting in a board consisting of nine members. No changes to Earthstone management will occur in connection with the transaction.
Canadian Overseas to acquire Atomic for $54 million
Canadian Overseas Petroleum Ltd. (COPL) has agreed to acquire private company Atomic Oil & Gas LLC for $54 million in assumed debt, cash, and shares.
Atomic holds operated interests in 52,258 acres (gross) of contiguous leasehold in Wyoming’s Powder River basin.
There are two oil production units within the lease block: the Barron Flats Shannon Miscible Flood Unit (57.7% WI) and the Cole Creek Unit (66.7%), as well as one unitized exploration area—the Barron Flats Federal Unit (deep). Atomic has two affiliates: The Southwestern Production Corp., the operating entity; and PipeCo, a midstream company holding the pipeline and facility assets.
With the deal, COPL acquires 31.1 MMboe (24.7 MMboe net after royalties) of proved and probable reserves (2P). The current production rate of 1,400 b/d (gross) is expected to rise to 5,000 b/d (gross) in 2022 and around 7,000 b/d (gross) in 2026. Produced crude oil is light (40°API) and sweet.
Upon completion, expected by Jan. 31, 2021, the operative staff of Southwestern Production will join COPL.
Exploration & Development Quick Takes
Eni makes oil discovery, adds production in Egypt’s Western Desert
Eni has tied-in to production a new oil discovery in the Meleiha Concession in the Western Desert of Egypt. The discovery adds 10,000 b/d of oil to the current concession production, the company said in a release Dec. 23, 2020.
The discovery was made through the Arcadia 9 well, drilled on the Arcadia South structure, 1.5 km south of the main Arcadia field already in production. The well encountered an oil column of 85 ft in Cretaceous sandstones of the Alam El Bueib 3G formation. Drilled close to existing production facilities, the well was tied-in with a stabilized rate of 5,500 b/d of oil.
Following the discovery, two development wells, Arcadia 10 and Arcadia 11, were drilled back to back. The first encountered 25 ft of oil column and the second encountered an 80 ft oil column, both within the Alam El Bueib 3G formation. The three wells share the same oil-water contact in the discovered reservoir. Arcadia 11 also encountered 20 ft of oil pay in the overlying Alam El Bueib 3D formation.
Eni executes its exploration strategy in the Western Desert through Agiba, a joint venture with Egyptian General Petroleum Corp. (EGPC) (OGJ Online, July 29, 2020).
Eni, through its subsidiary IEOC, holds a 38% interest in the Meleiha concession. Lukoil holds a 12% and EGPC holds 50%.
Carnarvon advances Buffalo field redevelopment
Carnarvon Petroleum Ltd., Perth, has farmed out 50% of its Buffalo production sharing contract (PSC) offshore East Timor in the Timor Sea to Advance Energy PLC. Carnarvon will retain operatorship.
Advance will fund drilling of the Buffalo-10 well up to $20 million on a free-carry basis. The deal is to be finalized by Mar. 31, 2021, the due date for Advance to pay the funds into a joint venture bank account.
If Advance raises less than $20 million but more than $10 million, the transaction will proceed at a lower equity level equal to 2.5% per $1 million contributed.
A tender process to contract an international drilling management services company to assist in drilling—scheduled for late 2021—is under way.
Buffalo field was discovered by BHP Petroleum in 1996 in 25 m of water and developed from four wells and a small unmanned wellhead platform tied back to an FPSO. Production began in December 1999 at rates up to 50,000 b/d and ceased in November 2004 after a total production of 20.5 million bbl. BHP decommissioned the field and removed all existing facilities and wells.
Carnarvon was awarded the Western Australian permit WA-523-P containing Buffalo in mid-2016. Subsequent work suggested the field held remaining contingent resources of (2C) 31.1 million bbl and 1C contingent resources of 15.3 million bbl. The 3C figure was estimated at 47.8 million bbl.
The company plans to redevelop the field which is now in East Timor waters following the recent offshore maritime boundary agreement between East Timor and Australia.
Buffalo-10 is targeting attic oil and will be completed as a development well.
On completion of the Advance Energy deal, Carnarvon will retain 50- 75% interest depending on the level of Advance’s funding to the joint venture.
PGNiG makes gas discovery in Wielkopolska region
Polish Oil and Gas Co. (PGNiG) has completed drilling of the Grodzewo-1 well in the municipality of S´rem the central part of in western Poland’s Wielkopolska region. The company’s estimates the well could produce up to 20,000 cu m/year of natural gas.
The well was drilled to 2,940 m TD by PGNiG unit Exalo Drilling SA under in combined exploration and production license No. 29/2001/Ł S´rem-Jarocin under a joint operating agreement signed in 2009 with ORLEN Upstream. PGNiG is operator with 51%.
The well shows the hydrocarbon potential of the region and plans are to continue drilling in the area over the coming year, said Paweł Majewski, president of PGNiG’s management board.
Previous discoveries in the region include Zaniemys´l, S´roda Wielkopolska, Roszków, Kromolice and Kromolice Południe, Winna Góra, Lisewo, Komorze and, most recently, Miłosław.
The work is part of PGNiG’s exploration campaign targeting Rotliegend formations in the Polish Lowlands.
Drilling & Production Quick Takes
BP plugs Ironbark wildcat as duster
BP has plugged wildcat Ironbark-1 in the Carnarvon basin offshore Western Australia. The well was dry.
Ironbark-1, in exploration permit WA-359-P, intersected the primary Mungaroo formation target at a depth of 5,275 m subsea, but “no significant hydrocarbon shows were encountered in any of the target reservoir sands,” said partner Cue Energy in a release Dec. 29, 2020. Total depth reached 5,618 m.
Original license holder Cue Energy Resources Ltd. completed a farm-out of the permit in June 2019 estimating that up to 15 tcf could be found in the prospect. Its proximity to the Woodside Petroleum-operated North Rankin platform and facilities enhanced its possible development potential.
BP, which farmed in to take 42.5% and operatorship, began drilling the well at the end of October 2020 using Diamond Offshore’s semi-submersible rig Ocean Apex. Cue Energy holds 21.5%, Beach Energy Ltd. holds 21%, and New Zealand Oil and Gas Ltd. holds 15%.
CNOOC starts production from Penglai 25-6 project
CNOOC Ltd. started production from its Penglai 25-6 oilfield area 3 project in the south central Bohai Sea.
The project, in average water depth of 27 m, fully utilizes existing processing facilities of Penglai oilfields. A new wellhead platform was built, and 58 development wells are planned, including 38 production wells and 20 water injection wells.
Peak production of 11,511 b/d of crude oil is expected in 2023.
CNOOC is operator with 51% interest. ConocoPhillips holds 49%.
SNOC, Eni start up Mahani field
Sharjah National Oil Corp. (SNOC) has started production from Mahani gas and condensate field in the Area B concession of Sharjah (UAE).
The start-up is the first step in the further evaluation of the January 2020 onshore discovery (OGJ Online, Jan. 27, 2020).
Production—expected to increase progressively with the connection of additional wells planned for 2021-2022—will be sent through a new multiphase trunk line to SNOC’s Sajaa gas plant to be processed using existing facilities and infrastructure.
SNOC is operator with 50% interest. ENI holds 50%.
PROCESSING Quick Takes
Galp to permanently close one of its two refineries
Galp Energia SGPS SA is permanently ceasing crude oil refining operations in 2021 at subsidiary Petróleos de Portugal SA’s (Petrogal) 110,000-b/d refinery in Matosinhos e Leça da Palmeira, Porto, on Portugal’s northwest coast.
The decision follows negative impacts to Galp’s downstream industrial activities precipitated by structural changes in demand for finished petroleum products resulting from the COVID-19 pandemic as well as the European regulatory environment, the operator said Dec. 21, 2020.
Galp expects the planned system reconfiguration—which includes the decommissioning of an estimated €200-million ($244-million) worth of Matosinhos assets—to reduce the company’s average fixed costs and recurrent capex by more than €90 million annually, as well as reduce overall carbon dioxide emissions by about 900,000 tonnes/year (tpy).
Discontinuation of refining activities at Matosinhos will not impact fuel distribution in Portugal, however, as Galp will continue supplying the regional market by maintaining all key import, storage, and distribution installations at the site.
The operator also plans to assess unidentified alternative uses for the refining site.
Alongside its primary distillation capacity, the Matosinhos complex also houses a 440,000-tpy aromatics plant, a 1.1-million tpy base oils plant, and an 80,000-tpy lubricants plant, according to Galp’s latest annual report to investors.
Galp said it will concentrate on future developments to enhance the resilience and competitiveness of its 220,000-b/d refinery at the Port of Sines, in Setúbal. Without disclosing details, Galp confirmed it is evaluating works at Sines to improve the refinery’s energy and process efficiency, as well as potential projects to integrate the production of advanced biofuels and other cleaner products at the site.
Mostorod refinery reaches full production rates
Egyptian Refining Co. (ERC) has achieved full startup and production rates from key units at its recently commissioned hydrocracking refinery built within the existing Mostorod Petroleum Complex, 20 km northeast of Cairo in Qalyoubia governate, Egypt (OGJ Online, Nov. 11, 2019).
As of Dec. 21, the refinery’s naphtha hydrotreating unit, Axens Group-licensed Octanizing continuous catalyst regeneration (CCR) reforming unit, Prime-D diesel hydrotreating unit, and single-stage HyK hydrocracking unit were fully operational and producing at full rates, Axens said.
Alongside delivering technology licensing, the process design package, proprietary equipment, catalysts, and technical services for the major processing units, Axens is providing ongoing close monitoring of the units via implementation of its proprietary Connect’In digital technology services, according to the service provider.
While Axens disclosed neither a value of its work on the project nor unit capacity details, official project documents from ERC identified unit capacities as follows:
- Naphtha hydrotreating unit; 22,600 b/d.
- Octanizing CCR reforming unit; 15,900 b/d.
- Prime-D diesel hydrotreating unit; 32,100 b/d.
- Single-stage HyK hydrocracking unit, equipped with recycle meeting high conversion; 40,800 b/d.
In addition to its 4.7-million tonnes/year (tpy) main vacuum distillation unit, a sulfur recovery block, and hydrogen production plant, ERC’s refinery also features a 25,000-b/d delayed coking unit, which together process mainly atmospheric residue feed from Cairo Oil Refinery Co.’s adjacent 8-million tpy Mostorod refinery. ERC’s refinery produces Euro 5-quality refined products—including 2.3 million tpy of diesel, 600,000 tpy of jet fuel, 315,000 tpy of fuel oil, 860,000 tpy of naphtha and reformate, and 80,000 tpy—primarily for Cairo and surrounding areas.
Howard Energy inks deal for Javelina gas plant
Howard Midstream Energy Partners LLC (dba Howard Energy Partners, HEP) has entered an agreement with MPLX LP subsidiary MarkWest Energy Partners LP to acquire MarkWest Javelina Co. LLC’s Javelina cryogenic natural gas processing and fractionation complex in Corpus Christi, Tex.
As part of the deal, HEP will retain existing personnel currently employed at the Javelina complex, Howard said.
The transaction is expected to close in early 2021. A deal value was not disclosed.
Commissioned in the late 1990s, the Javelina complex is equipped to process between 138-142 MMcfd of off gas it receives from Corpus Christi-area refineries, which it separates into ethane, ethylene, propane, propylene, isobutane, normal butane, butylenes, pentanes, and high-purity hydrogen for distribution as feedstock to other downstream customers, according to recent documents from the US Department of Transportation and Texas Commission on Environmental Quality (TCEQ). The complex also returns residue gas recovered from its off-gas feedstock to refineries for reuse as fuel.
Alongside a 29,000-b/d C2 splitter to separate ethylene from ethane recovered at the site, TCEQ documents show the Javelina complex also houses the following major installations:
- C3 splitter.
- C4 reactor.
- C5 hydrodesulfurization unit.
- Demethanizer unit.
- Butylene conversion unit.
- Acetylene unit.
- Sulfurox unit, incinerator.
- Amine regeneration and tail gas treating areas.
- Pressure swing adsorption unit.
- Vapor recovery unit.
TRANSPORTATION Quick Takes
Permian Highway Pipeline in-service
Kinder Morgan Inc.’s Permian Highway Pipeline (PHP) began full commercial in-service operations Jan. 1, 2021. The pipeline had been flowing volumes during the commissioning process for several weeks prior.
Fully subscribed under long-term contracts, PHP is designed to transport as much as 2.1 bcfd of gas through 430 miles of 42-in. pipeline from the Waha, Tex., area to Katy, Tex., with connections to the US Gulf Coast and Mexico.
Kinder Morgan Texas Pipeline (KMTP), a subsidiary of KMI, EagleClaw Midstream and Altus Midstream each hold an ownership interest of 26.7%, and an affiliate of an anchor shipper has a 20% interest. KMTP is operator.
Nord Stream 2 pipelay resumes
Gazprom has resumed pipelay of the 55-billion cu m/year Nord Stream 2 natural gas pipeline running between Russia and Germany in the Baltic Sea. Russian pipelaying vessel Fortuna arrived in December at a construction site 70 km off the German coast, accompanied by two supply ships.
“Fortuna will lay a 2.6-km section of the pipeline in Germany’s exclusive economic zone in waters less than 30 m (100 ft) deep. All the construction work is being carried out in full compliance with the approvals obtained. We will report on further construction work in the offshore section at a later date,” Nord Stream 2 AG said.
Gazprom decided to itself finish Nord Stream 2 construction after Allseas Group SA withdrew from the project in December 2019 due to threatened US sanctions. The twin 1,230-km pipelines are 94% built.
Work in German waters was expected to continue through Dec. 31, 2020. The bulk of remaining construction is in Denmark’s exclusive economic zone near the island of Bornholm.
Pinnacle Midstream to build greenfield Midland basin gas gathering
Pinnacle Midstream II LLC will build its greenfield Dos Picos natural gas gathering system in Midland basin, underpinned by a 15-year acreage commitment from Double Point Energy LLC. Dos Picos is expected to come into service second-quarter 2021.
Dos Picos initially will service Midland, Martin, and Glasscock Counties, Tex. Expansions are planned as producer activity increases.
The initial system will consist of more than 50 miles of primarily 16-in. OD low- and high-pressure gas gathering mainlines, compression, and access to multiple in-basin gas processing options.