GENERAL INTEREST Quick Takes
Occidental to build large-scale DAC plant in Ector County
Occidental and subsidiary 1PointFive will begin detailed engineering and early site construction for their first large-scale direct air capture (DAC) plant in Ector County, Tex., near certain of Occidental’s Permian basin acreage and infrastructure conducive to safe and secure CO2 storage, the operator said in a release Aug. 25.
The first stage, which includes site preparation and road work, is scheduled to begin in this year’s third quarter. Start-up is expected in late 2024. Once operational, the plant is expected to capture up to 500,000 tonnes/year (tpy) of CO2 with the capability to scale up to 1 million tpy.
Construction start follows completion of a front-end engineering and design (FEED) study and extensive testing and validation, the company said. 1PointFive partnered with Carbon Engineering, a climate solutions company, to commercialize and deploy DAC technology at scale. Oxy formed 1PointFive, a development company, to finance and deploy Carbon Engineering’s large-scale DAC technology for the project.
The subsidiary also has agreed on substantive terms with Worley for engineering, procurement, and construction (EPC) services, and expects to work toward a definitive agreement for the EPC contract by yearend.
1PointFive has advanced product sales for the plant, including carbon removal credit purchases from Airbus, Shopify, and ThermoFisher. Oxy reached an offtake agreement with SK Trading International for an opportunity to purchase net-zero oil. Oxy also entered into an agreement with Origis Energy to provide zero-emission solar power for the DAC plant and other projects in the Permian basin.
FAR takes 100% interest in permits offshore Gambia
FAR Ltd. has acquired the remaining 50% interest it didn’t own in two exploration blocks (A2, A5) offshore Republic of Gambia in West Africa, from Petronas.
FAR negotiated with the Gambian government to remove an obligation to drill an exploration well in the next 2-year license term which begins Oct. 1, 2022, thus reducing immediate expenditure and enabling FAR to conduct a detailed geoscience review incorporating results of Samo-1 and Bambo-1 wildcats, FAR said.
The company is seeking joint venture partners to undertake the review and ultimately drill exploration wells in the permits.Subject to conditions, including government approval, the incoming party may assume operatorship.
Full assessment from Bambo-1 drilling is ongoing. Oil shows were detected during drilling and the subsequent Bambo-1ST1 sidetrack. Laboratory work, based on analysis of rock cuttings recovered during the drilling program, confirmed oil at multiple levels, including immediately beneath the S390 secondary objective.
The S390 reservoir updip from Bambo-1 lies within a structural closure which forms the Panthera prospect. There were also oil shows down-dip of the Panthera closure in Samo-1 which presents evidence of an oil charge at both ends of the prospect, the company said, noting it is possible Bambo-1ST1 caught the edge of an oil column.
The S390 reservoir and seal would be the primary objective in the Panthera prospect. This reservoir was penetrated by the nearby Jammah-1 well which contains several sandstone units and a sound top seal.
FAR is emerging from years of financial turmoil during which it was forced to sell its interest in Sangomar oil field immediately to the north across the international border in Senegal to Woodside Energy Ltd. in July 2021.
Amplify reaches deal related to oil pipeline spill
Amplify Energy Corp., Houston, reached an agreement with the US government to resolve all federal criminal matters involving the company and its subsidiaries stemming from the October 2021 southern California pipeline incident (OGJ Online, Oct. 4, 2021).
A broken pipeline off the coast of Huntington Beach caused an oil spill. Amplify Energy subsidiary Beta Offshore Operating Co. LLC notified the US Coast Guard of the oil sheen Oct. 2. Beta’s holdings include San Pedro Bay Pipeline Co., which owns and operates a 16-in. OD subsea pipeline extending 17.5 miles from one of its platforms to an onshore pump station, metering, and tankage at the Port of Long Beach.
As part of the resolution, which is subject to court review and approval, Amplify agreed to plead guilty to one count of misdemeanor negligent discharge of oil in violation of the Clean Water Act. If approved by the court, Amplify will pay a fine of about $7.1 million over a period of 3 years, serve a term of 4 years’ probation, and reimburse governmental agencies about $5.8 million for their response to the incident.
Amplify also agreed to implement compliance measures including installation of a new leak detection system and increased remote operated vehicle inspections of the pipeline.
Separately, the company noted an agreement in principle reached with plaintiffs in a class action to resolve all civil claims against Amplify and its subsidiaries. The settlement, the value of which was not disclosed, will be funded under the company’s insurance policies if approved by the court.
In February, Amplify filed a complaint against two shipping companies whose anchors struck the San Pedro Bay pipeline, damaging it and causing the oil release, the company said. Claims were also filed against the Marine Exhange of Southern California, which failed to notify Amplify of the anchor strikes, the company said in March.
Cleanup operations in all impacted counties were concluded in late December 2021.
Exploration & Development Quick Takes
Neptune Energy discovers oil near Gjøa field
Neptune Energy Norge AS discovered oil in the North Sea about 14 km north of Gjøa field in 344 m of water.
The operator and license partners will assess the discovery along with other area discoveries and prospects with a view toward a possible development through existing infrastructure on Gjøa field. Preliminary estimates place the size of the discovery at 2.5-6.2 million std cu m of recoverable oil equivalent.
Exploration well 35/6-3 S, the first in production license (PL) 929, was drilled by the Deepsea Yantai drilling rig to a vertical depth of 2,742 m and a measured depth of 2,966 m subsea. It was terminated in presumed basement rock.
The objective was to prove petroleum in Lower Cretaceous reservoir rocks in the Agat formation. The well encountered a 73-m oil column with 140 m total thickness comprising sandstone layers totaling 80 m with moderate reservoir quality. The oil-water contact was encountered at 2,639 m. The well was not formation-tested, but data acquisition and sampling were carried out. The well will be plugged.
Neptune Energy is operator at PL 929 with 40% interest. Partners are ABP Norway AS (10%), DNO Norge AS (10%), Pandion Energy AS (20%), and Wintershall Dea Norge AS (20%).
Dorado FID delayed past 2022
Santos Ltd. has delayed a final investment decision (FID) for Dorado oil development in the Bedout subbasin offshore Western Australia in license WA-64-L due to the current inflationary cost environment and supply uncertainties.
Project partner Carnarvon Energy Ltd. said front-end engineering and design is nearing completion and the project is technically robust. Nevertheless, FID will not be made in 2022 as planned.
The main outstanding matter is finalization of the engineering procurement and construction contract for the floating production, storage and offtake (FPSO) vessel, Carnarvon said. The FPSO represents more than 50% of the expected project cost and must be carefully contracted and managed.
Engineering work for the 16 well-slot wellhead platform and FPSO is essentially complete and will enable further tie-back opportunities such as the recent Pavo discovery, the company said.
The FPSO will have a process capacity of 100,000 b/d of oil plus 215 MMcfd of gas for reinjection into the Dorado reservoir. Storage capacity will be 1 million bbl.
At Pavo, pre-development work has begun, with a discovery assessment report filed with the National Offshore Petroleum Safety and Environmental Management Authority and studies being undertaken for potential development.
Pavo-1 is estimated to contain 43 million bbl of 2C resource (Pavo North). The plan is to tie the oil pool back to the Dorado FPSO.
Pavo South is estimated to contain 55 million bbl of 2P resource. Drilling is in the planning stage.
Carnarvon plans to farm out a portion of its 20% Dorado interest and associated acreage before moving to FID to help fund development.
Angola consortium lets development contracts to Saipem
A consortium led by Azule Energy let three contracts (one onshore, two offshore) to Saipem for development of Quiluma and Maboqueiro fields off the northwest coast of Angola, the service provider said in a release Aug. 11.
Angola’s first non-associated gas development project, sanctioned in July, includes two offshore wellhead platforms, an onshore gas processing plant, and a connection to the Angola LNG plant for the marketing of condensates and gas via LNG cargoes (OGJ Online, July 27, 2022). Project execution activities will start in 2022 with first gas planned in 2026 and an expected production of 330 MMscfd at plateau (about 4 bcf/year).
With an overall value of around $900 million, Saipem will provide engineering, procurement, and construction activities, including hook-up and commissioning assistance of the Quiluma platform and related onshore natural gas processing plant.
The New Gas Consortium partners are Eni (25.6%, operator), Chevron affiliate CABGOC (31%), Sonangol P&P (19.8%), bp (11.8%), and TotalEnergies (11.8%).
Aker BP lets contract for Valhall hub modules construction
Aker BP ASA let a letter of intent to Rosenberg Worley for construction of two modules for a new central platform on Valhall field in the North Sea.
The operator and partners plan to establish Valhall as a gas hub to provide gas deliveries to Europe and extend the life of the area to 2060. The project, Valhall PWP–Fenris (previously NCP/King Lear), is being delivered by a fixed infrastructure alliance between Aker BP, Aker Solutions, and ABB.
Valhall PWP consists of three large modules totaling more than 15,000 tonnes. The process module will be built by Aker Solutions on Stord. Rosenberg Worley will deliver the wellbay module and the utility module. The platform also will be assembled on Stord.
The letter of intent presumes approval of plan for development and operation (PDO) and is valued at about NOK 1.6 billion. Construction is scheduled to start in autumn 2023.
Aker BP and Valhall PWP–Fenris partners Pandion Energy AS and PGNiG Upstream Norway AS plan to invest NOK 40-50 billion in the project and expect to submit the PDO near yearend.
Aker BP is operator at Valhall (90%) with partner Pandion Energy (10%).
Drilling & Production Quick Takes
PGNiG spuds Copernicus exploration well offshore Norway
PGNiG Upstream Norway AS has begun drilling operations on the Copernicus exploration well offshore Norway.
Copernicus is the primary prospect in license PL1017, which lies on the Utgard High in the Vøring basin region of the Norwegian Sea. The prospect is a combination trap with mapped stratigraphic pinch out down-dip and a small structural component at the apex, said partner Longboat Energy.
The prospective interval is identified as the Pliocene-Pleistocene Naust formation. Based on seismic features, the interval is interpreted as representing distal fan lobes sourced from erosion of coastal plain sediments in the Lofoten area, according to Longboat’s website. Petrophysical analysis of nearby wells show the Naust sands are good quality, with porosities of 25-35% and 100s to 1000s mD permeability.
Drilling of well 6608/1-1S by the Deepsea Yantai drilling rig began Aug. 30 and is expected to take up to 8 weeks to drill.
PGNiG is operator. Partners are Equinor and Longboat Energy.
TotalEnergies advances delayed Nigeria drilling campaign
TotalEnergies SE will start a drilling campaign on Egina and Akpo fields in oil mining lease (OML) 130, offshore Nigeria, in December, according to local media reports.
The prospective 11-well drilling program was expected to begin earlier in the year but was postponed due to rig availability and water depth challenges, the media reported. Egina is 130 km off the coast of Nigeria in 1,600 m of water.
Akpo field is expected to increase Nigeria’s oil production by about 150,000-175,000 b/d. Egina produces 200,000 b/d through a subsea production system connected to an FPSO designed to hold 2.3 million bbl of oil.
Total Upstream Nigeria Ltd. operates OML 130 with 24% interest. Partners include Nigerian National Petroleum Corp., South Atlantic Petroleum Ltd., CNOOC E&P Nigeria Ltd., and Petrobras Oil & Gas BV.
Senex Energy to triple Queensland gas output by 2025
Senex Energy, recently acquired by South Korean company Posco International and Hancock Energy, Perth, plans to invest over $1 billion (Aus.) to triple the company’s Queensland gas output by 2025.
Senex began Queensland production in 2019 and plans to produce up to 60 petajoules/year by 2025.
More than two thirds of the promised funds are to be invested during the next 2 years on gas infrastructure and the drilling of wells in Surat basin coal seam gas fields of southeast Queensland.
The company currently supplies gas to manufacturers in Queensland and supplies feedstock for the Santos-operated Gladstone LNG plant on Curtis Island.
PROCESSING Quick Takes
PetroChina refinery starts up Ionikylation unit
PetroChina Dagang Petrochemical Co., a subsidiary of PetroChina Co. Ltd.—the publicly listed arm of state-owned China National Petroleum Corp. (CNPC)—has commissioned a new unit based on composite ionic liquid alkylation technology for production of high-octane alkylate at its 5-million tonnes/year (tpy) refinery in Dagang, Tianjin, at northeastern China’s Dagang field.
Operational as of Aug. 14 and located on a plot space of 159 m by 71 m at the site of the refinery’s previously dismantled catalytic reforming unit, the new 150,000-tpy Ionikylation unit is producing high-octane alkylate with a RON of 98 to help the operator ensure the site’s 1.5-million tpy production of gasoline meets China’s current National VI (equivalent to Euro 6) emission standard, Well Resources Inc.—the technology’s global licensor—said on Aug. 23.
Estimated at total project cost of 330 million yuan, the new Dagang alkylation unit is the third unit in PetroChina’s portfolio based on Beijing-based China University of Petroleum’s Ionikylation process, which uses a proprietary composite ionic liquid catalyst that eliminates reliance on more dangerous, corrosive, and hazardous chemicals—such as hydrofluoric and sulfuric acids—to safely and more efficiently produce low-sulfur, high-octane alkylate free of sulfur, benzene, olefins, and aromatics that complies with increasingly more stringent clean-fuel standards (OGJ Online, Apr. 1, 2022; July 8, 2019).
PetroChina previously completed startup of a revamped 3,000-b/d brownfield alkylation unit retrofitted with Ionikylation technology in November 2018 at subsidiary Harbin Petrochemical Co. Ltd.’s refinery in Harbin City, Heilongjiang Province, as well as the January 2019 commissioning of a 1,000-b/d Ionikylation unit at subsidiary Golmud Petroleum Refinery’s 20,000-b/d refinery in the Qinghai-Tibet Plateau of Golmud City, Qinghai Province (OGJ Online, Apr. 16, 2020).
Commissioning of the Dagang refinery’s new unit marks the seventh commercial Ionikylation project entering operation to date, Well Resources confirmed.
ExxonMobil gets BLM approval for Wyoming CCS project
ExxonMobil Corp. has received US Bureau of Land Management (BLM) approval to sequester carbon dioxide (CO2) under federal land in Lincoln and Sweetwater counties, Wyoming. The project, capable of sequestering 60 MMcfd, will include a CO2 disposal well 18,000 ft underground in the water leg of the Madison formation and a pipeline connecting the disposal site to ExxonMobil’s Shute Creek natural gas plant near Kemmerer, Wyo.
Shute Creek receives gas from La Barge field in Sublette County, Wyo. Composition of the gas from La Barge is 66% CO2, 21% methane, 7% nitrogen, 5% hydrogen sulfide, and 0.6% helium. The plant was expanded in 2010 to capture 365 MMcfd of CO2.
ExxonMobil in February 2022 made final investment decision to further expand carbon capture and storage (CCS) at LaBarge, which it says has captured more CO2 than any other CCS project in the world to date. The new expansion will add as much as 1.2 million tonnes/year (tpy) of CO2 to the 6-7 million tpy already captured from LaBarge operations.
The company completed front-end engineering and design work for the project in December 2021. Pending regulatory approvals, startup is estimated for 2025.
ExxonMobil currently sells much of the CO2 for EOR use by other operators, with excess vented into the atmosphere under a permit approved by the Wyoming Department of Environmental Quality.
The project with ExxonMobil is the first time BLM has issued a permit to allow for permanent underground storage of CO2.
TRANSPORTATION Quick Takes
Santos takes FID on Darwin pipeline duplication project
Santos Ltd., operator of the proposed Barossa gas project in the Timor Sea, made a final investment decision (FID) to proceed with the Darwin Pipeline Duplication Project in the Timor Sea offshore Northern Territory.
The project aims to extend Barossa field gas export pipeline to the Santos-operated Darwin LNG plant and enable repurposing of the existing Bayu-Undan to Darwin pipeline for use in carbon capture storage (CCS) programs.
The decision is expected to increase Santos’ share of capital expenditure for Barossa by about $311 million.
Gas from the field, which lies 300 km north of Darwin, is slated to replace current supply from Bayu-Undan in East Timor jurisdiction with first gas targeted for early- to mid-2025.
The CCS project could capture and store up to 10 million tonnes/year of CO2, the company said.
The Barossa joint venture agreed with Darwin LNG joint venture partners to terminate toll arrangement for utilizing the original Bayu-Undan to Darwin LNG pipeline, thus reducing operating expenses for Barossa. FID on Bayu-Undan CCS is targeted for 2023.
Santos is operator of Bayu-Undan and Darwin LNG with 43.4% interest. Partners are SK E&S (25%), INPEX (11.4%), ENI (11%), JERA (6.1%), and Tokyo Gas (3.1%).
Energy Transfer signs LNG deal with Shell
Energy Transfer LP has executed a 20-year agreement to supply Shell NA LNG LLC with LNG from Energy Transfer LNG Export LLC’s Lake Charles liquefaction plant in Louisiana.
Shell will purchase 2.1 million tpy of LNG on a free-on-board basis with the purchase price indexed to Henry Hub, plus a fixed liquefaction charge.
The agreement will become effective upon satisfaction of conditions precedent, including Energy Transfer taking final investment decision (FID), expected by yearend. First deliveries are expected to begin as early as 2026.
The Lake Charles LNG project is fully permitted, having received authorizations from the Federal Energy Regulatory Commission as well as export authorizations from the Department of Energy. Liquefaction would be adjacent to Lake Charles LNG’s existing LNG terminal in Calcasieu Parish, La. and will capitalize on four existing LNG storage tanks, two deep water berths, and other LNG infrastructure.
The liquefaction plant will directly connect to Energy Transfer’s existing trunkline pipeline system that in turn provides connections to multiple intrastate and interstate pipelines. These pipelines allow access to multiple natural gas producing basins, including Haynesville, Permian, and Marcellus shale.
Energy Transfer LNG has signed six LNG agreements in the last 5 months, bringing the total amount of LNG contracted from its Lake Charles LNG plant to nearly 8 million tpy.
TC Energy awards Shawcor coating contract for Mexico gas pipeline
Transportadora de Gas Natural de la Huasteca S de RL de CV (TGNH), the Mexican subsidiary of TC Energy Corp., awarded Shawcor Ltd. a contract to supply pipe coating services for the Southeast Gateway natural gas pipeline project offshore southeast Mexico.
Shawcor will apply concrete weight coating to 706 km of 36-in. OD pipe that will connect TGNH pipeline in Tuxpan, Veracruz, with Coatzacoalcos, Veracruz, and Dos Bocas, Tabasco. Coating is expected to begin early 2023 at a plant in Altamira, Mexico, and take 1 year.
The contract is valued at $500 million (Can.).
TC Energy in early August took final investment decision on Southeast Gateway and expects to put the pipeline in service by mid-2025 (OGJ Online, Aug. 8, 2022).
