GENERAL INTEREST Quick Takes
Vår Energi adds $1.2 billion to Balder X development cost, delays first oil
Vår Energi ASA has increased the cost estimate for Balder X development by $1.2 billion (gross) and pushed first oil to third-quarter 2024 from late-2023, citing increased workscope and continued impacts from global supply chain challenges and COVID-19, the company said Sept. 19. The new total estimated gross project cost is $4.3 billion. The 350,000 boe/d production target by end 2025 is unaffected.
Balder X, on the Norwegian Continental Shelf comprising Balder Future and Ringhorne Phase IV drilling projects, is set to extend production from Balder Hub to 2045 and support development of new nearby discoveries by upgrading existing infrastructure and drilling new wells. The new cost estimate and schedule change are mainly related to Balder Future, with increased scope and additional engineering and construction work on the Jotun FPSO lifetime extension, the company said.
Balder X is expected to unlock an estimated 143 million bbl of recoverable reserves and to increase Balder Hub gross production to over 70,000 boe/d at peak, said Torger Rød, chief executive officer.
Once the Jotun FPSO is re-installed and connected to Balder Future production wells, it will tie in the new Ringhorne wells. The King and Prince discoveries, estimated to hold additional 60-135 million bbl of oil, are being considered for tie-in.
Federal Court of Australia rules against Santos-led Barossa drilling
The Federal Court of Australia has set aside acceptance by the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) of an environmental plan covering drilling and completion activities on the Santos-operated Barossa gas project in the Timor Sea north of Darwin.
Drilling activities, comprising eight new development wells in Barossa field, are suspended pending a favorable appeal or approval of a new environment plan.
The Federal Court judge found that Santos failed to adequately consult local indigenous people in Tiwi Island.
The Munupi elder, Dennis Tipakalippa, in the Tiwi Islands filed the case to challenge NOPSEMA’s decision to allow Santos to drill, arguing that the company had not considered his people’s connection to the sea country despite its requirement for NOPSEMA approval.
Santos claimed it had engaged with the Tiwi Land Council and the Northern Land Council about the proposed drilling and that NOPSEMA had accepted Santos’ efforts in accordance with regulations.
Santos had paused the drilling program in late August pending the Federal Court decision. The Federal Court judge ordered an injunction preventing drilling restart be extended until Oct. 6.
The $3.6-billion Barossa development, expected to pipe gas to the Darwin LNG plant to backfill waning supplies from Bayu-Undan field, is 46% complete.
Sawan appointed new Shell CEO
Shell plc has named Wael Sawan to succeed Ben van Beurden as the company’s chief executive officer, effective Jan. 1, 2023.
At yearend, Van Beurden will step down after 39 years with Shell and 9 years as chief executive. He will work as an adviser to the board until June 30, 2023.
Sawan, who will also join Shell’s board of directors, is currently director of integrated gas, renewables, and energy solutions, and was previously the upstream director. He has been a member of Shell’s executive committee (EC) for 3 years.
Prior to joining EC, he was the executive vice-president, deepwater, and a member of the upstream leadership team, and executive vice-president, Qatar, and a member of the integrated gas leadership team. He has worked with Shell for 25 years.
INPEX divests US Gulf of Mexico assets
INPEX Americas Inc., a subsidiary of Japan’s INPEX Corp., has transferred its 10.11% interest in Occidental Petroleum-operated deepwater Gulf of Mexico fields Lucius and Hadrian North to project partners Anadarko US Offshore LLC (an Occidental subsidiary), Murphy Exploration & Production Co., and Eni Petroleum US LLC.
Lucius lies 380 km offshore Louisiana in Keathley Canyon Blocks 874, 875, 918, and 919 in water depth of 2,200 m. The field lies 240 miles south of Louisiana’s coast and contains thick reservoir sands with good porosity and permeability and is estimated to contain more than 300 MMboe reserves. INPEX joined the project in June 2012.
Subsea tieback drilling at Lucius #10 and Lucius #4 (Keathley Canyon 918, 919) is planned for this year’s third quarter and expected online in the fourth quarter, according to an Aug. 4 investor presentation released by Murphy. In it, the partner noted a signed agreement to acquire an additional 3.4% working interest in Lucius field for $77 million after adjustments.
Hadrian North, in the vicinity of Lucius in Keathley Canyon Blocks 918 and 919, was unitized with Lucius in 2017. The field has been developed as a subsea tieback. Production began in April 2019.
Crude oil and natural gas from the two fields are processed at an offshore floating production platform with capacity to process over 80,000 bo/d and 450 MMscfd of natural gas, and shipped to a plant onshore Louisiana via subsea pipelines.
Santos awarded CO2 offshore storage permits
Santos has been awarded two permits offshore Western Australia (G-9-AP in Carnarvon basin, G-11-AP in Bonaparte basin) to evaluate CO2 storage potential.
The Carnarvon basin covers 3,589 sq km and provides potential new acreage for carbon capture storage (CCS) beyond the company’s Reindeer fields which plays into plans to establish a CCS hub at Reindeer and Devil Creek, Santos said.
The 26,000-sq km Bonaparte permit lies close to the Santos Bayu-Undan CCS project.
The company’s first CCS project at Moomba in South Australia is 20% complete with 100 million tonnes of CO2 capacity and contingent resources booked. The Bayu-Undan CCS project entered front-end engineering and design stage earlier this year.
Santos is operator of G-9-AP with 50% interest. Chevron Australia Pty Ltd. holds the remaining 50%. Santos is operator of G-11-AP with 40%. Partners are Chevron Australia (30%) and SK E&S (30%).
Exploration & Development Quick Takes
TotalEnergies takes FID on Fenix gas development
TotalEnergies SE has taken final investment decision (FID) to develop the $706-million Fenix gas project 60 km offshore Tierra del Fuego, southern Argentina, the operator said in a release Sept. 19.
First phase of Fenix field development—in the CMA-1 concession—will comprise three horizontal wells drilled from a new, unmanned platform in 70 m of water. Gas will be transported through a 24-in. OD, 35-km subsea, multiphase pipeline to the TotalEnergies-operated Véga Pleyade platform and treated onshore at Rio Cullen and Cañadon Alfa plants, also operated by the company.
At production start-up, expected early 2025, Fenix will produce 10 million cu m/d of natural gas (70,000 boe/d).
Four gas field in the concession—Cañadón Alfa, Aries, Carina and Vega Pléyade—are on production, supplying 16% of Argentina’s natural gas demand. The Fenix project will help maintain production in Tierra del Fuego province and guarantee gas supply to the Argentine market, partner Wintershall said in a separate release Sept. 19.
TotalEnergies is operator of the project (37.5%) with partners WintershallDea AG (37.5%) and Pan American Sur (25%).
Shell signs Oman block exploration, production agreement
Shell Integrated Gas Oman BV, a subsidiary of Shell plc, signed an agreement with Oman’s Ministry of Energy and Minerals to explore, appraise, and develop natural gas and condensate resources onshore Block 11 on the western side of the sultanate.
Shell will advance exploration activities including seismic acquisition of 1,400 sq km later this year and drilling of exploration wells beginning in 2023, the company said in a release Sept. 16.
Shell will serve as operator of the onshore block with 67.5% interest. Partners are state-owned OQ (10%) and TotalEnergies SE (22.5%).
Santos increases Beetaloo contingent gas resources by 164%
The Santos Ltd.-Tamboran Resources Ltd. joint venture in Beetaloo basin permit EP161 onshore Northern Territory, Australia, has increased its estimated 2C contingent gas resource by 164% following a review of extended production test data from the Tanumbirini-2H and 3H appraisal wells.
The upgrade of unrisked 2C contingent gas resources has risen to 1.617 tcf while the unrisked 1C contingent resource has increased by 73% to 330 bcf.
The upgrade also incorporates additional data supporting the reservoir continuity of the Mid-Velkerri C Shale reservoir and an updated development strategy that includes drilling 3,000 m horizontal wells, Tamboran said.
The upgrade has been evaluated and certified by Netherland, Sewell & Associates Inc.
The area over which the 2C resources have been booked covers less than 4% of the prospective acreage within the permit, the company said.
Santos is operator of the license with 75% interest. Tamboran holds 25% interest.
Drilling & Production Quick Takes
Tailwind Energy starts production at Evelyn
Tailwind Energy Ltd. started production at the Evelyn oil and gas discovery in license P.1792, Block 21/30f, in UK Central North Sea via subsea tieback to the Triton FPSO.
The subsea execution phase was led by Dana Petroleum (E&P) Ltd. and TechnipFMC, which tied back the EV-01z horizontal development well (drilled in 2021) to the Triton FPSO about 6 km to the northeast of Evelyn via subsea production line and umbilical services line. Dana Petroleum is operator of the vessel.
In the same campaign, the project team installed a second subsea production line from Gannet-E field, which already produces via Triton. The flowline was commissioned and brought into production Sept. 11, allowing for increased production from the existing three Gannet E wells and debottlenecking for a fourth well, which is expected to be drilled in this year’s fourth quarter and brought into production via the new line in first-quarter 2023.
Evelyn and the Gannet-E expansion projects are expected to add over 10,000 boe/d to Tailwind net production.
Tailwind has 100% equity in Evelyn.
Serinus Energy spuds Moftinu Nord exploration well
Serinus Energy PLC spudded the Moftinu Nord-1 exploration well on the Satu Mare concession onshore Romania Sept. 19, 2022, with the aim to connect the well to the Moftinu gas processing plant, utilizing existing capacity, the company said in a release Sept. 20.
Moftinu Nord prospect is on the northern flank of Carei basin, about 5 km northwest of the 15-MMcf/d gas plant.
The well will be drilled to a depth of 1,000 m, targeting four prospective hydrocarbon zones and seeking to discover further hydrocarbons on the migration path from Carei basin source kitchen, testing a different structure type than the recently completed Canar-1 exploration well (OGJ Online, Sept. 2, 2022).
Serinus is operator of the concession with 100% working interest.
Norway production up in August, NPD says
Norway’s production averaged 1.998 million in August, the Norwegian Petroleum Directorate (NPD) reported. The figure is up from the 1.876 million b/d produced in July.
Average daily liquids production in August consists of 1.774 million b/o, 205,000 bbl of NGL, and 19,000 bbl of condensate.
Oil production in August was 3.1% lower than the NPD’s forecast and 4.7% lower than the forecast so far this year.
Parkmead advances Skerryvore prospect drilling
Parkmead agreed to increase its stake in the Skerryvore project in the UK Central North Sea to 50% from 30% and has received approval from the North Sea Transition Authority to enter the next phase of the P.2400 license agreement to drill the Skerryvore prospects.
Geotechnical work has confirmed the multi-interval potential of Skerryvore, Parkmead said in a release Sept. 15. The planned well will target the main stacked exploration prospects, at Mey and Chalk level, which studies indicate could contain 157 MMboe in the P50, most likely case, the operator continued.
The license also contains additional prospectivity at Ekofisk and Jurassic levels, the company said, noting a successful discovery could be tied into existing and planned infrastructure in the area.
The area around Skerryvore is seeing activity, with Harbour Energy having reached an investment decision on the adjacent Talbot discovery and NEO Energy continuing with redevelopment of Affleck, the company said. Development activity is also taking place in the Norwegian sector close to Skerryvore at ConocoPhillips-operated Tommeliten A, Parkmead continued.
Skerryvore will be Parkmead’s first operated exploration well. Joint venture partners in the license are Serica Energy (UK) Ltd. (20%) and CalEnergy (Gas) Ltd. (30%).
PGNiG drills dry hole at Copernicus
PGNiG Upstream Norway AS drilled a dry hole at Copernicus exploration well 6608/1-1S in production license (PL) 1017 in the Norwegian Sea, partner Longboat Energy Norge AS said in a release Sept. 14. The well will be plugged.
The well was drilled to a total vertical depth of 2,400 m subsea and targeted Plio-Pleistocene formations in Vøring basin. Background gas readings were recorded, but the well failed to encounter any effective reservoir. Analysis remains ongoing to understand the observed bright seismic amplitude anomaly and any remaining prospectivity in the area.
PGNiG Upstream Norway AS is operator with 50% interest. Partners are Equinor Energy AS (40%) and Longboat Energy (10%).
PROCESSING Quick Takes
Germany assumes control of Rosneft Deutschland refineries
The German government has placed German Rosneft subsidiaries—Rosneft Deutschland GmbH (RDG) and RN Refining & Marketing GmbH (RNRM)—under fiduciary management. The Bundesnetzagentur (Federal Network Agency), the country’s gas and electricity industry regulator, is assuming control of RDG’s respective shares PCK Schwedt, MiRo (Karlsruhe), and Bayernoil (Vohburg) refineries.
The government announced the news Sept. 16, citing section 17 of the Energy Security of Supply Act. Rosneft Deutschland holds about 12% of German oil refining capacity, making it one of the largest oil-processing companies in Germany, the government said, noting the fiduciary management “counters the impending risk to the security of the energy supply, and lays a key foundation stone for the maintenance and future of the Schwedt operation.”
The subsidiaries import several hundred million euros worth of crude oil from Russia to Germany each month and maintenance of the refineries’ business operations was in jeopardy as central service providers are no longer willing to work with Rosneft—neither with refineries in which Rosneft held a stake, nor with Germany’s Rosneft subsidiaries, RDG and RNRM, the economy ministry said.
The order imposing the fiduciary management was issued by the Federal Ministry for Economic Affairs and Climate Action. It took effect on Sept. 16, and is initially effective for 6 months, according to the release. The RDG and the RNRM must bear the costs of the fiduciary management themselves.
PCK Schwedt, Brandenburg, enables direct delivery of crude oil via the Druzhba pipeline, which connects Russia with Germany. The refinery’s capacity is 11.6 million tonnes/year (tpy).
The MiRo refinery is the largest oil refinery in Germany with total processing capacity of 14.9 million tpy.
The Bayernoil refinery, the largest in the Bavarian region, supplies fuel to Bavaria and northern Austria. Total processing capacity is 10.3 million tpy.
Steel Reef Infrastructure acquires North Dakota gas gathering system from Summit Midstream
Summit Midstream Holdings LLC signed and closed a sale of Bison Midstream LLC, its gas gathering system in northwestern North Dakota, to Steel Reef Infrastructure Corp., an integrated owner and operator of associated gas capture, gathering, and processing assets in North Dakota and Saskatchewan, for $40 million cash.
The Bison Midstream system, in Mountrail and Burke Counties, ND, gathers, compresses, and treats associated natural gas that exists in the crude oil stream produced from the Bakken and Three Forks shale formations in the Williston basin.
Gathering agreements for the system include long-term, fee-based, or percent-of-proceeds contracts, Summit Midstream said. Natural gas gathered on the Bison Midstream system is delivered to Aux Sable Midstream LLC’s 80 MMcfd Palermo Conditioning Plant in Palermo, ND, and then delivered to downstream pipelines serving Aux Sable’s 2.1 bcfd natural gas processing plant in Channahon, Ill.
Combined with the previous sale of the Lane gas gathering and processing system in Eddy County, NM, the sale of Bison Midstream advances Summit Midstream’s scale-building strategy, said Heath Deneke, president, chief executive officer, and chairman, in a release Sept. 19. In late June, Summit Midstream Permian LLC sold the Lane system in the Delaware basin to a subsidiary of Matador Resources Co. for $75 million cash.
OMV updates timeline for Schwechat refinery restart
OMV Aktiengesellschaft, Vienna, is progressing with repairs required to restart its 9.6-million tonne/year refinery at its integrated complex in Schwechat, Austria, following an early June mechanical upset impacting the site’s main crude oil distillation unit (CDU) at the end of its 2022 turnaround.
With repair works proceeding well and on schedule, OMV plans to start the commissioning and ramp-up phase of the refinery’s restart during the first half of October, after which the site will progressively resume supply of products to the markets it serves, the operator said on Sept. 15.
In the meantime, OMV said it will maintain the alternative supply system established in the wake of the June incident for as long as necessary to continue reliable product deliveries to customers during the repair period.
Alongside securing temporary supplies of downstream feedstock and products from other OMV refineries and cooperating with partners and logistics affiliates to purchase products to replace supply shortfalls during repairs on Schwechat’s main CDU, OMV also maximized distillation capacity of a smaller available CDU covering about 20% of the site’s pre-incident capacity.
In the aftermath of the incident, the Austrian government released fuel from the country’s strategic oil reserves to help supply product to the market.
In its second-quarter 2022 earnings presentation, OMV told investors it anticipated the refinery to be running at full-utilization rates in a September-October timeframe. As of the late-July presentation, the operator said financial impact of the refinery incident and subsequent CDU outage stood at about €90 million.
TRANSPORTATION Quick Takes
Whistler Pipeline, Cheniere form natural gas pipeline JV in Texas
WhiteWater Midstream LLC and subsidiaries of Whistler Pipeline LLC and Cheniere Energy Inc. signed agreements to move forward with construction of the ADCC pipeline, a new joint venture 42-in. OD pipeline expected to extend 43 miles from the terminus of Whistler pipeline to Cheniere’s Corpus Christi liquefaction plant.
The ADCC pipeline—designed to transport up to 1.7 bcfd of natural gas, expandable to 2.5 bcfd—is expected to be in service in 2024, pending receipt of customary regulatory and other approvals.
The Whistler natural gas pipeline is owned by a consortium including MPLX LP, WhiteWater, and a joint venture between Stonepeak and West Texas Gas Inc.
The 450-mile, 42-in OD Whistler pipeline transports natural gas from Waha in the Permian basin to Agua Dulce, Tex., providing access to South Texas and export markets. An 85-mile, 36-in. OD lateral provides connectivity to the Midland basin.
ADNOC lets offshore gas pipeline EPC contract
Abu Dhabi National Oil Co. (ADNOC) affiliate ADNOC Offshore awarded an engineering, procurement, and construction contract to National Petroleum Construction Co. for construction of a new natural gas transmission line at its Lower Zakum field offshore of Abu Dhabi. The project is intended to accommodate an expected increase in Lower Zakum’s associated gas production to 700 MMscfd from 430 MMscfd as the company increases the field’s oil production to 450,000 b/d by 2025.
Construction will include a new 85-km subsea pipeline from Zakum West Super Complex to Das Island, Abu Dhabi, a new platform at Zakum West, and a new gas receiving terminal at Das Island.
The contract is worth $548 million.
Commonwealth LNG receives FERC environmental impact statement
Commonwealth LNG LLC has received a final environmental impact statement (EIS) from the US Federal Energy Regulatory Commission (FERC) for its proposed 8.4-million tonne/year LNG plant in Cameron Parish, La.
FERC staff concluded that approval of the project with the mitigation measures recommended would result in some adverse environmental impacts, most of which would be reduced to less than significant levels. But FERC also concluded that there would be significant impacts on visual resources and that impacts on environmental justice communities would be disproportionately high and adverse.
In addition to the plant, the project would include six gas pretreatment trains and two flare systems (consisting of four total flares), six 50,000-cu m LNG storage tanks, one LNG carrier berth capable of accommodating vessels up to 216,000 cu m, a barge dock, and a 3-mile, 42-in. OD pipeline capable of delivering 1.44 bcfd.
Commonwealth expects to begin site preparation in early 2023 and take final investment decision in third-quarter 2023, targeting operations in third-quarter 2026.
This EIS did not characterize Commonwealth LNG’s greenhouse gas emissions as significant or insignificant because FERC is conducting a generic proceeding to determine whether and how it will conduct such significance determinations going forward.