GENERAL INTEREST Quick Takes
Equinor, Norwegian authorities take steps to meet European gas demand
Equinor ASA and partners, together with Norwegian authorities, are working to meet gas demand in Europe through adjusted production permits and postponed turnarounds. Increased production permits have been approved for Troll, Oseberg, and Heidrun fields offshore Norway to help maintain high gas production through the summer months.
The Ministry of Petroleum and Energy has approved a more flexible production permit for Oseberg field, to increase gas exports by about 1 billion cu m to about 7 billion cu m, to Sept. 30, 2022. This is a 15-20% increase for the current gas year. Gas production on Heidrun will increase by 400 million cu m in the current calendar year, representing an increase of up to about 30%.
The adjustments also increase exports via the Kollsnes processing plant. Production from Troll field could increase 1 billion cu m to 38 billion cu m of gas for the current gas year, an increase of slightly less than 3%, in the event of loss of production from other fields.
To further maintain supply, Equinor will postpone turnarounds on four platforms on Oseberg field to September from May, accelerating production of about 500 million cu m.
Expected to come on stream mid-May, the Hammerfest LNG plant on Melkoya Island in northern Norway will add over 6 billion cu m/year of gas from the Barents Sea. The plant has been closed since a Sept. 28, 2020 fire on the air intake of one of its five gas turbines (OGJ Online, Sept. 28, 2020; Oct. 2, 2020; Apr. 26, 2021).
Typically, 1.4 billion cu m of gas meets the gas demand of around 1.4 million European homes during a year.
bp, Eni to combine Angola assets
bp PLC and Eni SPA have signed an agreement to form a new 50-50 independent company, Azule Energy, through the combination of the two companies’ Angolan businesses. The agreement follows the memorandum of understanding between the companies agreed in May 2021 (OGJ Online, May 19, 2021).
Independently managed Azule Energy is expected to be Angola’s largest producer, holding stakes in 16 licenses, oil and gas production of over 200,000 boe/d net, resources of 2 billion boe net, and participating interest in the Angola LNG joint venture. Azule Energy also will take over Eni’s stake in Solenova, a solar company jointly held with Sonangol.
New projects to be started by the company over the next few years include the Agogo and PAJ oil projects in Blocks 15/06 and 31, respectively. It also will develop the New Gas Consortium (NGC), the first non-associated gas project in the country (OGJ Online, Jan. 16, 2020).
Creation of Azule is subject to customary governmental and other approvals. The deal is expected to close in this year’s second half. Once set up, Azule Energy will be equity accounted by bp and Eni. Hydrocarbon production and GHG emissions will continue to be reported on an equity share basis.
Currently Eni is operator of Blocks 15/06 Cabinda North, Cabinda Centro, 1/14, 28, and soon NGC. In addition, Eni has a stake in the non-operated Blocks 0 (Cabinda), 3/05, 3/05A, 14, 14 K/A-IMI, 15, and in Angola LNG.
bp is operator of Blocks 18 and 31 offshore Angola, and has non-operated stakes in Blocks 15, 17, 20, and 29. bp also has non-operated interests in NGC and Angola LNG.
CNOOC acquires additional 5% in Búzios field from Petrobras
CNOOC Petroleum Brasil Ltda. (CPBL) signed a contract for 5% of Petroleo Brasileiro SA’s (Petrobras) interest in the Production Sharing Contract of the Transfer of Rights Surplus for Búzios field, in Santos basin pre-salt area, offshore Brazil.
The agreement is the result of the option to purchase an additional share, exercised by CPBL on Sept 29, 2021 (OGJ Online, Sept. 30, 2021).
The amount, related to CPBL’s portion, to be received in cash by Petrobras at the closing of the operation will be $2.12 billion and was calculated with a base date of Sept. 1, 2021, and with an exchange rate of R$5.07/US$. This amount refers to compensation and reimbursement of the signature bonus of CPBL’s additional participation. The value will still be subject to the usual adjustments in this type of contract between the base date and the closing date.
Búzios, in water depth around 6,560 ft, began production in April 2018 and has already produced around 100 MMboe.
The transaction is subject to approvals of the Administrative Council for Economic Defense (CADE), the National Agency of Petroleum, Natural Gas, and Biofuels (ANP) and the Ministry of Mines and Energy (MME).
After the transaction becomes effective, Petrobras will hold 85% stake in the Production Sharing Contract of the Transfer of Rights Surplus of Búzios field, with CPBL holding 10% and CNODC Brasil Petróleo e Gás Ltda. holding 5%. Stakes in the Búzios Shared Deposit, including portions of the Transfer of Rights Agreement and of the BS-500 Concession Agreement (100% Petrobras) will be Petrobras (88.99%), CPBL (7.34%), and CNODC (3.67%).
OMV to review Western Siberia asset interest, end future investments in Russia
OMV will not pursue future investments in Russia and will initiate a review of its 24.99% interest in Yuzhno Russkoye gas field in Western Siberia to include potential divestment or exit with an expected value adjustment of 500-800 million euro.
The decision to remove Russia as a core business region comes on the heels of additional pivots away from Russia as the country escalates its invasion of Ukraine.
Days earlier, OMV ended negotiations with Gazprom about the potential purchase of a 24.98% stake in Blocks 4A/5A of the Achimov formation in Urengoy gas and condensate field in Western Siberia (OGJ Online, Mar. 1, 2022). The basic sale agreement from Oct. 3, 2018, has been cancelled.
In 2017, OMV established Russia as a new core region following the acquisition of Yuzhno Russkoye field interest from Uniper SE, adding 100,000 boe/d to OMV’s production (OGJ Online, Mar. 6, 2017). Gas from the field supplies the Nord Stream pipeline which transports Russian gas to Germany.
With the newest non-cash value adjustment—to impact reported operating results in first-quarter 2022—OMV reduces its net asset value in Russia (remaining Yuzhno Russkoye value) to around 2% of OMV’s total fixed assets and at-equity participation value.
In addition, OMV will recognize a value adjustment charge of 987 million euro (loan plus accrued interest as of Dec. 31, 2021) since receivables from Nord Stream 2 AG may be unrecoverable. This is a non-cash value adjustment that will impact reported earnings before taxes in first-quarter 2022.
Exploration & Development Quick Takes
Energy Resources flows gas from Lockyer Deep-1 preliminary test
Energy Resources Ltd. in the onshore North Perth basin of Western Australia has flowed gas in a preliminary test of its Lockyer Deep-1 prospect that straddled permits EP368 and EP 426.
Following perforating operations in a 25 m section of Kingia sandstone at 4,041-4,067 m, a strong continuous dry gas flow was achieved from the well through a 36/64-in. choke, partner Norwest Energy Ltd. said. Stable flowing wellhead pressure was over 4,800 psi.
Gas samples were obtained before the well was shut in with wellhead pressure of 5,122 psi.
Onsite gas sampling indicates the presence of 4-4.5% CO2 and 1-2 ppm hydrogen sulphide. Samples have been sent for independent verification and full compositional analysis.
The JV plans to run a full production test of the Kingia section when equipment arrives on site commencing in about 10 days.
Given the rapid clean-up followed by early strong flow rates, the JV anticipates the Kingia reservoir at Lockyer Deep is of good quality with potentially high gas deliverability.
If successful flows are obtained from a production test, the well will be suspended for future completion as a gas producer.
Energy Resources is operator with 80% interest. Norwest holds the remaining 20%.
OMV awards FEED contract for Iris Hades field
OMV (Norge) AS has let a front-end engineering and design (FEED) contract TechnipFMC PLC for the Iris Hades subsea production system (SPS & SURF). The operator plans to submit the plan for development and operation (PDO) to authorities at yearend.
Iris Hades field is on Haltenbanken in the Norwegian Sea close to Morvin field in production license (PL) 644, PL 644B, and PL 644C. The Iris appraisal well was drilled in 2019 and the Hades reservoir was appraised in 2020 (OGJ Online, Apr. 6, 2018; July 29, 2020). The appraisal wells confirmed the presence of hydrocarbons in both reservoirs.
The development concept for the gas-condensate discovery is a 4-slot subsea template with three producing wells tied back to the Equinor-operated Åsgard B platform.
The contract has a value of NOK 30 million and includes an option for engineering, procurement, construction, and installation (EPCI).
OMV is operator (30%). Partners are Equinor ASA (40%), DNO Norge ASA (20%), and Spirit Energy Ltd. (10%).
Equinor drills dry well near Snorre field in the North Sea
Equinor Energy AS has plugged a well near Snorre field and will move the Deepsea Stavanger rig to drill another North Sea well.
Exploration well 34/4-18 S—the 14th in production license 057—was drilled about 7 km northwest of Snorre and 160 km west of Florø to vertical and measured depths of 2,963 and 3,015 meters, respectively, subsea. It was terminated in the Raude formation from the Late Triassic. Water depth at the site is 360 m. The well is dry with no traces of hydrocarbons.
The objective of the well was to prove petroleum in reservoir rocks from the Late Triassic-Early Jurassic (the Statfjord group). The well encountered about 24 m of sandstone rocks in the Eiriksson formation (the Statfjord Group) from the Early Jurassic with good reservoir quality.
It also encountered about 25 m of sandstone rocks in the Raude formation (the Statfjord group) from the Late Triassic, with moderate to good reservoir quality.
Data acquisition was carried out.
The rig is moving on to drill wildcat well 35/10-8 S in production license 293 B, where Equinor is operator.
Drilling & Production Quick Takes
IOG starts up Blythe, Elgood fields
Independent Oil & Gas PLC (IOG) confirmed first gas from Elgood and Blythe fields in Phase 1 of its Saturn Banks project in the UK Southern North Sea.
Elgood has been developed as a subsea tieback to the Blythe normally unmanned platform, which is controlled from Bacton gas terminal on the North Sea coast of North Norfolk in the United Kingdom.
Flow rates will be assessed once stable production has been established from both fields. The company will analyze reservoir performance data over the initial months of production to form an annual production guidance range.
The first phase of the project entails development of Blythe, Elgood, and Southwark fields. Phase 2 consists of the Goddard, Nailsworth, and Elland fields
IOG is operator (50%) of Core Project Phase 1 with partner CalEnergy Resources (UK) Ltd. (50%) (OGJ Online, Nov. 3, 2020).
Eni produces first oil from GoM FPSO
Eni SPA subsidiary Eni Mexico S. de R.L. de CV achieved first oil Feb. 23 from the Miamte MV34 floating production, storage, and offloading (FPSO) vessel operating in Offshore Area 1 block in the Bay of Campeche, Gulf of Mexico, about 10 km off Mexico’s coast in 30 m of water.
Moored in a water depth of about 32 m, the FPSO will treat 90,000 b/d of crude oil and 75 MMcfd of gas. It will be able to inject 120,000 b/d of water and will store up to 700,000 bbl of oil. First production was originally planned for 2021.
Modec Inc. is responsible for engineering, procurement, construction, mobilization, and operation of Miamte, including topsides processing equipment as well as hull and marine systems. Sofec Inc., a Modec group company, designed and installed the FPSO’s disconnectable tower yoke mooring system.
Modec will own FPSO Miamte and provide operations and maintenance services for 15 years, with the option of 1-year extensions for a further 5 years.
Offshore Area 1 is estimated to contain 2.1 billion boe, of which 90% is oil, across Amoca, Tecoalli, and Miztón fields. In 2020, producing wells were linked to the Miztón production platform. Area 1 development involves building and installing three more platforms in the fields at Amoca and Tecoalli. Drilling activities are ongoing.
Eni has 100% ownership of Area 1.
Empyrean Energy to spud Jade well, offshore China
Empyrean Energy plc will spud the Jade well in Block 29/11 within Pearl River Mouth basin, offshore China, by end first-quarter 2022.
The well site survey is complete and China National Offshore Oil Corp. (CNOOC), who has a 12-month contract with rig NH9, will make the rig available to drill Jade immediately following the well currently being drilled. The company expects the Jade well to be spudded late-March or mid-April, depending on whether the current well encounters testable hydrocarbons.
The well is anticipated to take about 26 days to drill to total depth. There are no overly challenging drilling zones anticipated. If Jade intercepts a hydrocarbon zone, testing is expected to take about 2 weeks.
CNOOC EnerTech Drilling and Production Co. (CNOOC EnerTech) has been contracted to provide pre-drilling, drilling, and testing services. China Oilfield Services Ltd. (COSL) has been contracted to drill the well (OGJ Online, Nov. 11, 2021).
Empyrean is operator of the block and holds 100% working interest during the exploration phase. In the event of a commercial discovery, partner CNOOC may assume a 51% participating interest in the development and production phase.
PROCESSING Quick Takes
Shell to sever all relations with Russian oil and gas industry
In the wake of its late-February plan to exit equity partnerships held with PJSC Gazprom entities, Shell PLC says it is now undertaking a complete but phased withdrawal from all Russian-related oil and gas activities amid the war in Ukraine.
Shell now intends to withdraw from its involvement in all Russian hydrocarbons, including crude oil, petroleum products, gas, and LNG in a phased manner, aligned with new government guidance, the operator said on Mar. 8.
As an immediate first step, Shell said it will stop all spot purchases of Russian crude oil, as well as shutter its other businesses in Russia, including service stations, aviation fuels, and lubricants operations.
“We are acutely aware that our decision last week to purchase a cargo of Russian crude oil to be refined into products like petrol and diesel—despite being made with security of supplies at the forefront of our thinking—was not the right one, and we are sorry,” said Ben van Beurden, Shell’s chief executive officer.
The company “will commit profits from the limited, remaining amounts of Russian oil [Shell] will process to a dedicated fund [and] work with aid partners and humanitarian agencies over the coming days and weeks to determine where the monies from this fund are best placed to alleviate the terrible consequences that this war is having on the people of Ukraine,” van Beurden said.
Unless otherwise directed by governments, Shell said it will:
- Immediately stop buying Russian crude oil on the spot market, as well as not renew existing crude purchase term contracts.
- Change its crude supply chain as fast as possible to remove Russian volumes entirely, with the caveat the physical location and availability of alternatives means this could take weeks to complete and will lead to reduced throughput at some of its refineries.
- Immediately begin the process of safely shuttering its service stations, aviation fuels, and lubricants operations in Russia.
- Begin the complex challenge of starting its phased withdrawal from Russian petroleum products, pipeline gas, and LNG businesses in a process that will require concerted action by governments, energy suppliers, and customers. The transition to other energy supplies, however, will take much longer, the operator warned.
Currently one of the largest direct foreign investors in the Russian economy, Shell’s businesses in Russia include exploration, production and transportation of oil and gas; sale and distribution of petroleum products and petrochemicals, lubricants, motor, and industrial oils; a retail network of gas station; as well as provision of technological and consulting services to Russian enterprises, according to the operator’s Russian-language website.
While detailed information regarding Shell’s downstream holdings in Russia are not readily discoverable, the company does operate a 180,000-tonnes/year lubricants production plant in Torzhok, Tver Region, according to the website.
Petrobras warns of possible delay in proposed sale of REMAN refinery
Petróleo Brasileiro SA (Petrobras) must await completion of additional diligence works before gaining government approval to finalize the previously proposed sale of its 46,000-b/d Isaac Sabbá refinery (REMAN)—including a storage terminal—in Manaus, Amazonas, to Atem’s Distribuidora de Petróleo SA (Atem) subsidiary Ream Participações SA (OGJ Online, Aug. 26, 2021).
In a dispatch issued on Mar. 8, Brazil’s competition authority Administrative Council for Economic Defense (CADE) declaring the proposed transaction to be complex, CADE has ordered execution of unspecified diligence activities involving further analyses of REMAN’s operations, including the refinery’s effects and possibly competitive impacts on the downstream refining market, Petrobras said on Mar. 10.
Since the Mar. 8 declaration of complexity by statute allows CADE to request an extension of up to 90 days to the general 240-day diligence process, the required period of operational analyses could take up to 330 days, potentially further delaying the REMAN sale.
While Petrobras said it plans to collaborate with CADE to gain requisite approval of the REMAN sale within the legal deadline as stipulated in its agreement with Atem, the operator indicated completion of the sale still remains subject to other normal closing conditions.
If approved, the proposed sale would include Ream Participações’ purchase all of Petrobras’s ownership interest in the REMAN refinery and associated logistics assets for $189.5 million, $28.4 million of which is to be immediately paid as a security deposit, with the remaining $161.1 million to be collected a closing subject to adjustments.
Petrobras—which will continue operating REMAN and its associated assets until the transaction closes—also agreed to offer ongoing support to Atem for a transitional period following the sale as part of a service agreement to ensure the safety and uninterrupted operation of the assets.
Petrobras most recently completed the sale of its former 333,000-b/d Refinaria Landulpho Alves (RLAM) refinery—now renamed Refinaria de Mataripe—in São Francisco do Conde in the Recôncavo Baiano region of Bahia, Brazil, to Mubadala Capital (MC), an arm of Abu Dhabi-based Mubadala Investment Co. (OGJ Online, Dec. 1, 2021).
Aramco renews focus on Chinese downstream operations, relationships
Saudi Aramco has entered agreements to deepen relationships with its existing Chinese joint-venture partners to expand downstream operations in China, plans which include revival of a previously announced project involving construction of a grassroots integrated refining and petrochemical complex in northeast China.
On Mar. 10, Aramco confirmed it has taken final investment decision (FID) to participate with partners North Huajin Chemical Industries Group Corp. (NHCIG) and Panjin Xincheng Industrial Group Co. Ltd. (PXIG) to advance development of their joint venture Huajin Aramco Petrochemical Co.’s (HAPCO) proposed 300,000-b/d refining and ethylene-based steam cracking complex to be built in Panjin City, Liaoning Province.
Currently slated for startup in 2024, the planned complex would receive up to 210,000 b/d of crude oil feedstock supplied by Aramco for HAPCO to process into a variety of fuels and base petrochemicals used in manufacturing to help meet China’s growing demand for energy, chemical, and everyday products, Aramco said.
The proposed development also supports Aramco’s broader objective to further its role as a global leader in the liquids-to-chemicals business, according to Al Qahtani.
FID on the planned complex—which remains subject to finalization of transaction documentation, regulatory approvals, and closing conditions—follows formation of the HAPCO JV in December 2019, Aramco said.
Aramco previously announced its intent to form HAPCO in February 2019 as part of a $10-billion agreement with former partners China North Industries Group Corp. (Norinco) and Panjin Sincen for development of a HAPCO-operated 300,000-b/d Panjin integrated complex, which then also was to include a 1.5-million tonne/year (tpy) ethylene cracker and 1.3-million tpy paraxylene unit.
Alongside supplying up to 70% of required crude feedstock for the proposed complex, Aramco was to hold 35% interest in the newly formed company while Norinco and Panjin were to hold the remaining 36% and 29% interest, respectively.
Details regarding division of ownership under the new JV with NHCIG and PXIG have yet to be disclosed.
Aramco’s FID on the HAPCO project follows subsidiary Saudi Aramco Asia Co. Ltd.’s (SAAC) Mar. 8 entrance into a memorandum of understanding (MOU) with China Petroleum & Chemical Corp. (Sinopec) to evaluate potentially expanding the partners’ downstream collaboration in China.
Though details regarding the entire scope of proposed collaboration under the MOU were few, Aramco did reveal SAAC and Sinopec have agreed to conduct a feasibility study aimed at assessing possible optimization and capacity expansion of the Sinopec (50%)-Aramco (25%)-ExxonMobil Corp. (25%) jointly held Fujian Refining and Petrochemical Co. Ltd.’s 12-million tpy integrated refining and chemical production complex at the southern coast of Meizhou Bay in Quanzhou, Fujian Province, China.
The agreement also seems to involve additional supply of Saudi Arabian crude into China, as Mohammed Al Qahtani, senior vice-president of Aramco’s downstream unit, said the potential collaboration would help to support Aramco’s goal of becoming “a resilient and reliable supplier of one of the lowest upstream carbon-intensity oils to meet China’s growing demand.”
Additionally, Yu Baocai—president of Sinopec Corp.—said the Mar. 8 MOU with Aramco would further support Sinopec’s refinery feedstock optimization and downstream petrochemical development, as well as offer “new opportunities to deepen and expand activity amid an accelerating global energy transition.”
FREP recently commissioned a new DuPont Clean Technologies-licensed STRATCO alkylation unit designed to process a mixed-butylene FCC feedstock into 7,700-b/sd (300,000-tpy) of low-sulfur, high-octane, low-rvp alkylate to ensure fuel production at the complex complies with the current China VI-A (equivalent to Euro 6) emission standard, which limits sulfur content in gasoline to a maximum of 10 ppm to help reduce automobile-generated pollution.
TRANSPORTATION Quick Takes
Porthos tenders for subsea CCS pipeline installation
Porthos Offshore Transport and Storage CV has tendered for installation of 20 km of offshore pipeline for its Port of Rotterdam CO2 Transport Hub and Offshore Storage (Porthos) carbon capture and sequestration (CCS) project. The pipeline will move CO2 from Rotterdam to an offshore platform for storage in 3,000-4,000 m below the seabed in the depleted P18-2 North Sea natural gas field.
Scope of work includes dredging work in the nearshore zone and in the Maasgeul channel, execution of shore crossing by pipepull through a preinstalled high-density polyethylene carrier pipe, and installation of 20 km of 16-in. OD pipeline with multilayer polypropylene anticorrosion coating, thermal insulation, and concrete weight coating. Work will also include backfilling the dredged sections of pipeline, post-lay trenching and backfilling of the non-dredged pipeline sections, and precommissioning.
Tenders are due Apr. 18, 2022. The contract would start Jan. 1, 2023, and end Dec. 31, 2026.
Porthos final investment decision is expected in 2022. The greater development will include a 30-km, 42-in. OD onshore pipeline through the port to be built by Denys NV (OGJ Online, Dec. 6, 2021).
LNG Canada receives inlet module
LNG Canada has taken delivery of the 14-million tonne/year liquefaction plant’s inlet module, the part of the system that will take delivery of natural gas transported on TC Energy Corp.’s 1.7 bcfd Coastal GasLink pipeline. Receipt of the 4,618-tonne module in Kitimat, BC, puts work on the plant near 60% complete, according to the company.
The inlet module will next be transported overland via self-propelled modular transporters down a 3-km, 30-m wide purpose-built road to the plant site where it will be lifted into position on its foundation.
Petronas LNG Ltd. last year chartered three newbuild 174,000-cu m LNG carriers from shipowner Hyundai LNG Shipping for use primarily to lift cargoes from LNG Canada (OGJ Online, Apr. 29, 2021). The vessels will be delivered starting second-quarter 2024.
Partners in LNG Canada are Shell PLC, Petronas, PetroChina Co. Ltd., Mitsubishi Corp., and Korea Gas Corp.
Venture Global signs additional LNG supply agreement with Shell
Venture Global LNG signed a new 20-year long-term purchase agreement with Shell NA LNG LLC for the supply of 2 million tonnes/year (tpy) of LNG from Venture Global’s Plaquemines LNG liquefaction plant. The deal adds to Shell’s existing contract for 2 million tpy from the Calcasieu Pass LNG liquefaction plant, bringing Shell’s total long-term purchases from Venture Global to 4 million tpy (OGJ Online, Mar. 22, 2021).
Venture Global’s first plant, Calcasieu Pass, began producing LNG in January 2022. The Plaquemines LNG liquefaction plant, under construction in Plaquemines Parish, La. about 20 miles south of New Orleans, is expected to come online in 2024 (OGJ Online, Feb. 1, 2022). When fully developed, it will have an export capacity of up to 20 million tpy.