GENERAL INTEREST Quick Takes
Vista Energy to invest $2.5 billion in Vaca Muerta by end-2026
Vista Energy SAB de CV, the second-largest shale oil producer in Argentina, aims to increase daily production by 25% by 2026 compared with a target set in 2021, with a goal to reach 100,000 boe/d.
President and chief executive officer Miguel Galuccio, during an investor day presentation, said the company plans to invest $2.5 billion in Vaca Muerta over the next 3 years, a 60% increase from the amount presented in the previous plan.
Galuccio said the company holds more than 200,000 acres “in the productive heart of the formation,” and that Vista’s goal is “to continue increasing investment to boost greater activity, aiming for production of 100,000 boe/d by 2026 and 150,000 boe/d by 2030.”
In first-half 2023, Vaca Muerta accounted for nearly half of Argentina’s oil production and 70% of its crude oil exports, he said.
In a July meeting with investors, Vista said it added 150 wells to its inventory in parts of its shale blocks. Between 2024 and 2026, the company expects to place 138 new oil wells into production, a 33% increase from its previous plan.
The production growth is expected to lead to greater operational efficiency, reducing extraction cost to $4.00/boe in 2026 from $5.50/boe in 2023, a 33% improvement compared with the previous target of $6.00/boe.
The projections would lead to a doubling of revenue, reaching $2.35 billion in 2026 assuming a realized oil price of $65/bbl in real terms. This represents a 42% increase from the previous target of $1.65 billion.
Occidental, ADNOC to fund UAE direct air capture project study
Occidental subsidiary 1PointFive and ADNOC will jointly fund a preliminary engineering study for a 1 million tonne/year (tpy) direct air capture (DAC) plant in the United Arab Emirates (UAE).
The agreement is the first project to reach the technical feasibility stage since the companies signed a collaboration agreement in August to explore carbon capture, utilization, and storage (CCUS) projects in the UAE and the US and to incorporate climate technologies in energy projects such as emissions-free power and sustainable fuels.
The study will assess the feasibility of building the first megaton-scale DAC plant outside the US. The project is envisioned to be connected to ADNOC’s CO2 infrastructure for injection and permanent storage into saline reservoirs not used for oil and gas production, ADNOC said in a release Oct. 3. Financial details were not disclosed.
Use of CO2 extraction technology developed by Carbon Engineering for 1PointFive’s DAC plant being developed in Ector County, Tex., is expected, Occidental said in a separate release Oct. 3.
A $1.1-billion August deal by Occidental’s 1PointFive to acquire the Canada-based engineering company’s outstanding equity gives the operator opportunity to “rapidly advance DAC technology,” the company said at the time.
The Permian basin-area plant, Stratos, is expected to capture up to 500,000 tpy of CO2 from the atmosphere when fully operational.
As part of its carbon management strategy, ADNOC is currently testing the world’s first full sequestered CO2 injection well in a carbonate saline aquifer in Abu Dhabi, and in August made a final investment decision to proceed with the Habshan carbon capture project in Abu Dhabi for which it recently let an engineering, procurement, and construction contract to Petrofac.
Santos to farm down Alaska North Slope asset interest
Santos Ltd. will farm down half of its working interest in 148 exploration leases in the Lagniappe area of the Alaska North Slope in an agreement with APA Alaska LLC, a subsidiary of APA Corp., and Lagniappe Alaska LLC, a subsidiary of Armstrong Oil & Gas.
The leases cover more than 270,000 acres and are on the eastern North Slope with multiple prospects in the late Cretaceous Brookian and Schrader Bluff formations, Santos said in a release Sept. 20.
Farm-down of the acreage, which was acquired as part of its merger with Oil Search in 2021, is consistent with the operator’s Alaska strategy to focus on the Pikka conventional development. The company took final investment decision on Pikka Phase 1 oil development in 2022 and drilling began in June. The $2.6 billion project is expected to produce 80,000 b/d of oil when it comes on stream in 2026.
Following execution of the agreement, subject to customary government approvals, Santos’s working interest will be 25%.
Under the terms of the agreement, initial activities during the exploration phase will be undertaken without cost to Santos.
Exploration & Development Quick Takes
Eni makes discovery offshore Indonesia
Eni North Ganal Ltd. discovered gas in the Geng North-1 exploration well in North Ganal PSC about 85 km off the cost of East Kalimantan, Indonesia.
Geng North-1 was drilled to a depth of 5,025 m in 1,947 m of water. It encountered a gas column about 50 m thick in a Miocene sandstone reservoir with excellent petrophysical properties that has been the subject of a data acquisition campaign. A drill stem test was limited by the test facilities but has resulted in estimated well capacity of up to 80-100 MMscfd and about 5,000-6,000 b/d of condensate, the company said in a release Oct. 2.
Preliminary estimates indicate a total structure discovered volume of 5 tcf of gas in place with condensate content estimated up to 400 million bbl. The acquired data will help fast track options for development, Eni said.
The Geng North discovery is adjacent to the Indonesia Deepwater Development area that includes stranded discoveries within the Rapak and Ganal PSC blocks, which Eni recently acquired from Chevron Corp. The acquisition could fast track development of the Gendalo and Gandang gas project (about 2 tcf of gas reserves) through Eni’s operated Jangkrik infrastructure.
Due to its location and size, the discovery could contribute to development of a new production hub in the northern part of Kutei basin connected to Bontang LNG infrastructure on the coast of East Kalimantan, Eni said. It is estimated that, in addition to Geng North, more than 5 tcf of gas in place are present in undeveloped discoveries within the area of interest, while multi-tcf exploration potential is under maturation through ongoing studies.
Eni is operator of the North Ganal PSC (50.22%) with partners Neptune Energy North Ganal BV (38.04%) and Agra Energi I Pte Ltd. (11.74%).
OMV discovers gas in Norwegian Sea
OMV made a gas discovery in Velocette exploration well 6607/3-1 S, 225 km west of Sandnessjøen and 45 km southeast of Equinor Energy-operated Aasta Hansteen field in the Norwegian Sea. Preliminary estimates indicate 0.2-1.8 million cu m of recoverable oil equivalent.
The well, the first to be drilled in production license (PL) 1016, was drilled by the Transocean Norge rig in 475 m of water to vertical and measured depths of 3,645 and 3,770 m subsea, respectively. It was terminated in the Nise formation in the Upper Cretaceous.
The objective was to prove petroleum in reservoir rocks in the Nise formation in the Upper Cretaceous.
The well encountered a gas-condensate column of about 9 m in the Nise formation, about 5 m of which is in a sandstone reservoir with quality varying from moderate to very good. The Nise formation has a total thickness of 55 m. The gas-water contact was encountered in the well.
While not formation-tested, data acquisition and sampling have been performed. The well will be permanently plugged.
The Transocean Norge drilling rig will now move to PL 836 S, where Wintershall Dea is the operator.
OMV is operator at PL 1016 (40%) with partners INPEX Idemitsu Norge AS (40%) and Longboat Energy Norge AS (20%).
Equinor granted consent to begin Breidablikk production
Equinor Energy AS has been granted consent by the Norwegian Petroleum Directorate for start-up of North Sea Breidablikk field, which lies 10 km northeast of Equinor-operated Grane field and west of Haugesund, Norway. Production is expected to begin in October, ahead of the original first-quarter 2024 plan.
The field is a subsea development in 130 m of water with four subsea templates, each with six well slots, and tied back to the Grane platform. It includes two discoveries, D-structure and F-structure, discovered in 1992 and 2013, respectively. The main reservoirs contain oil in Paleocene sandstone in the Heimdal formation at a depth of 1,700 m. The reservoirs are of good quality, with little variation in reservoir properties.
Breidablikk contains around 30 million std cu m of recoverable oil (about 190 million bbl). Total investments are around NOK 19 billion.
Equinor is operator at Breidablikk (39%) with partners Vår Energi ASA (34.4%), Petoro AS (22.2%), and ConocoPhillips Skandinavia AS (4.4%).
Drilling & Production Quick Takes
Neptune Energy spuds Ofelia appraisal well
Neptune Energy has started drilling the Ofelia appraisal well in the Norwegian sector of the North Sea.
The Ofelia discovery, in production license (PL) 929 about 14 km north of Neptune-operated Gjøa field, was made in August 2022. Preliminary estimates of recoverable volume are 2.5-6.2 million standard cu m (16-39 MMboe).
The new well (35/6-4 S) is being drilled by the Deepsea Yantai semi-submersible rig. The aim is to fully evaluate the hydrocarbon discovery in the Ofelia Agat formation, the company said in a release Oct. 3.
A secondary target is to evaluate an upside of gas charged reservoir in the shallower Kyrre formation.
The main reservoir target is the Lower Cretaceous Agat formation. It is expected to be reached at a depth of about 2,530 m.
Neptune Energy is operator of the license with 40% interest. Partners are Wintershall Dea (20%), Pandion Energy (20%), Aker BP (10%), and DNO (10%).
Strike granted South Erregulla permit, begins appraisal drilling
Strike Energy Ltd. is drilling the South Erregulla-2 (SE-2) appraisal well and has been awarded production license L24 in South Erregulla gas field in Perth basin, Australia.
Issuance of the license award by the Department of Mines, Industry, Regulation, and Safety prior to the field’s final investment decision will allow Strike to control and forecast the completion and start-up for the South Erregulla Phase 1 development, the company said.
Strike spudded SE-2 on Aug. 22. The primary objective is to prove continuity of South Erregulla gas field to the west and to expand the existing 128 petajoules (PJ) of independently certified 2P reserves prior to sanctioning development.
Drilling, casing, and pressure testing of the top-hole section has been completed down to about 2,100 m measured depth (MD). Subsequently, Strike has drilled the intermediate section down to 4,259 m MD and is conducting a bit change before reaching section depth and casing and cementing with 9 5/8-in. casing. The company will then run in to drill the well to total depth which will pass through the principal target in the Kingia sandstone.
With the production license, Strike can now submit the facility safety case and environmental plan required to begin construction of the proposed Phase 1 development following an investment decision.
Strike Energy is operator at South Erregulla (100%).
Equinor, Aker BP drill dry hole southwest of Oseberg field
Equinor Energy AS, drilling on behalf of North Sea production license PL 035 operator Aker BP ASA, encountered a dry hole in exploration well 30/11-15, the Norwegian Petroleum Directorate said in a release Sept. 22.
The primary exploration target was to prove petroleum in Lower Jurassic reservoir rocks in the Statfjord group. The secondary target was sampling and logging previously proven petroleum deposits from the Middle Jurassic Brent group.
The exploration well, the 14th in the license, was drilled about 25 km southwest of Equinor-operated Oseberg field and 150 km west of Bergen by the Deepsea Stavanger drilling rig to a vertical depth of 4,620 m subsea in water depth of 106 m. It was terminated in the Eiriksson formation in the Lower Jurassic.
The well encountered the Statfjord group at about 382 m with reservoir rocks totaling 58 m with poor reservoir quality. Data acquisition was carried out. The well also encountered the Brent group with reservoir properties and hydrocarbon columns as expected. The discovery in well 30/11-8 S was proven in 2011. Data acquisition was also carried out in the Brent group.
The well has been permanently plugged.
Aker BP is operator of PL 035 in a 50-50 joint venture with Equinor.
PROCESSING Quick Takes
TotalEnergies-OMV JV starts up long-planned Texas petrochemicals unit
Bayport Polymers LLC (Baystar)—a 50-50 joint venture of OMV AG subsidiary Borealis AG and TotalEnergies SE—has commissioned a new polyethylene unit to more than double production capacity at the operator’s existing Bayport PE site in Pasadena, Tex.
Known as Bay 3, the new 625,000-tonne/year (tpy) PE unit joins the site’s two legacy production PE units with a combined production of 400,000 tpy to increase overall PE output at the site to more than 1 million tpy, TotalEnergies and OMV said in separate Oct. 3 releases.
Equipped with Borealis’ proprietary Borstar PE process technology, the newly commissioned Bay 3 PE unit receives its ethylene feedstock from the JV’s nearly $2-billion, 1-million tpy ethane steam cracker started up in July 2022 at TotalEnergies Petrochemical & Refining USA’s nearby 200,000-b/d integrated refining complex in Port Arthur, Tex.
Commissioning of the $1.4-billion Bay 3 PE unit completes the partners’ integrated petrochemicals venture—including the expanded Bayport PE site and the Port Arthur ethane cracker—fulfilling strategic objectives of both companies, according to OMV and TotalEnergies.
Alongside establishing Baystar as a fully integrated US petrochemical operator, startup of the Bay 3 unit also advances TotalEnergies’ ambition to grow its US operations.
First announced in 2018, the Bayport Polymers JV was formed to help meet growing global demand for PE by taking advantage of abundant, competitively priced US ethane feedstock supplies and easy export access to markets abroad, as well to expand the companies’ respective businesses in the US.
ADNOC’s Ruwais refinery to produce sustainable aviation fuel
Abu Dhabi National Oil Co. (ADNOC) subsidiary ADNOC Refining has received ISCC System GmbH’s International Sustainability Carbon Certification (ISCC) to produce sustainable aviation fuel (SAF) at the operator’s more than 920,000-b/d Ruwais refining complex on the coast of the Arabian Gulf, about 245 km west of Abu Dhabi City, UAE.
Awarded on Oct. 3, the ISCC certification includes the ISCC European Union (EU) and ISCC Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA) PLUS co-processing certifications, which allows the Ruwais refinery to produce SAF from a feedstock of used cooking oil that is blended with jet fuel, ADNOC said.
With the certification now in hand, ADNOC said it will now be able to supply its SAF from Ruwais to international airlines at Abu Dhabi Airport via the operator’s 1,600-km pipeline network.
Marking the first ISCC certification award to a refinery in the Middle East, the accreditation supports ADNOC’s internal sustainability journey under the UAE’s Net Zero by 2050 Strategic Initiative, which ADNOC has brought forward internally by 5 years to 2045, the company said.
In addition to becoming responsible for sourcing suitable biofeedstocks from the market into ADNOC Refining’s Ruwais operations, fellow subsidiary ADNOC Global Trading will be able to ramp up distribution activities to supply global and domestic customers with lower-carbon and more sustainable alternative fuels, products, and feedstocks, according to ADNOC.
Without disclosing specific production or capacity details, ADNOC did confirm the Ruwais refinery’s first batch of SAF—which will be enough to fuel a return 787-10 Dreamliner flight from Abu Dhabi to Paris—would become available later in October.
Alujain lets contract for new petrochemical project at Yanbu
Alujain Corp. subsidiary Alujain National Industrial Co. (LNIC) has let a contract to Samsung Engineering Co. Ltd. to provide front-end engineering and design (FEED) for new units to be installed as part of integrated propane dehydrogenation (PDH) and polypropylene (PP) project at Yanbu Industrial City in western Saudi Arabia’s Medina province.
Under the contract, Samsung Engineering will deliver FEED on a 600,000-tonne/year (tpy) PDH plant and 500,000-tpy PP plant, the service provider said.
Samsung Engineering’s scope of delivery also covers FEED services for related utilities and offsites required for the project. Valued at $19.428 million, the newly awarded contract follows Samsung Engineering’s previous completion of preliminary FEED work for the PDH-PP project.
Upon completing the FEED phase in May 2024, Samsung Engineering said it plans to secure the main engineering, procurement, and construction (EPC) contract for the integrated plant.
In early May, LNIC let a contract to Lummus Technology LLC for licensing of its proprietary C3 CATOFIN process technology for the planned PDH unit, which will produce propylene as feedstock, according to a May 10 release.
On May 30, LyondellBasell Industries Holdings BV confirmed it received a contract to deliver licensing of its proprietary Spherizone process technology, as well as supply of its proprietary Avant ZN catalyst, for the project’s new PP unit.
LyondellBasell said LNIC’s PDH-PP project will be built adjacent to fellow Alujain subsidiary National Petrochemical Industrial Co.’s (NatPet) existing 400,000-tpy PDH-PP plant at Yanbu, which is equipped with the service provider’s proprietary Spheripol PP process technology.
Alujain said the new PDH-PP project, once completed, will produce more than 600,000 tpy of PP, PP compounds, and specialized construction materials from PP derivatives, as well as about 25,000 tpy salable hydrogen.
Alujain, which estimated total cost of the LNIC project at about $2 billion, said it expects the new PDH-PP plant to enter operation during first-half 2026.
TRANSPORTATION Quick Takes
Canada approves Trans Mountain pipeline route change
The Canada Energy Regulator’s (CER) Commission has approved Trans Mountain pipeline’s application for a route deviation of its Trans Mountain expansion project (TMEP) in the Pípsell (Jacko Lake) area near Kamloops, BC. The decision averted a potential months-long delay in completing the project, owned by the Canadian government which is targeting a first-quarter 2024 start of operations.
Trans Mountain Corp. in August applied to revise the route and method of construction for a 1.3-km section of the crude pipeline, indicating that it had encountered technical problems while attempting to complete micro-tunnelling along the previously approved route. In response to these issues, Trans Mountain proposed a combined approach of horizontal directional drilling and conventional open trenching along the revised route.
Stk’emlúpsemc te Secwépemc Nation responded to the application, as the area holds “profound spiritual and cultural significance to the Nation and Peoples,” CER said. An oral hearing was held Sept. 18-20 in Calgary to hear submissions from both parties.
TMEP will increase the 615-mile pipeline’s capacity to 890,000 b/d from 300,000 b/d.
CER’s Commission will release its reasons for the decision in the coming weeks. The body occasionally issues an expedited decision with reasons to follow in order to accommodate the need for a timely verdict. It is responsible for adjudicative decisions, operating as a quasi-judicial body that is arm’s length from other parts of the CER governance structure and the federal government, according to CER.
Woodside awards contract for Pluto LNG Train 1 modification project
Woodside Energy has let an engineering, procurement, and construction management contract to KBR for work on Woodside-operated Pluto LNG plant near Karratha, Western Australia.
KBR will undertake modifications to the existing Train 1 which will enable it to process up to 3 million tonnes/year (tpy) of Scarborough gas. Pluto LNG currently processes gas from Pluto and Xena gas fields offshore Western Australia.
Scarborough gas field lies about 375 km off the coast of Western Australia. The project includes installation of a floating production unit with eight wells drilled in the initial phase and 13 wells drilled over the life of the field.
Gas will be transported for processing at Pluto LNG through a new 430-km trunkline. About 5 million tpy of Scarborough gas will be processed through Pluto Train 2, with up to 3 million tpy processed through Pluto Train 1. First LNG cargo is targeted for 2026.
QatarEnergy signs LNG ship-building deal valued at $3.9 billion
QatarEnergy signed an agreement with Korea’s HD Hyundai Heavy Industries (HHI) for the construction of 17 ultra-modern LNG carriers.
The deal, valued at 14.2 billion Qatari Riyals (US$3.9 billion), marks the start of the second phase of QatarEnergy’s LNG ship acquisition program, which will support its expanding LNG production capacity from the North Field LNG expansion and Golden Pass LNG export projects as well as long-term fleet replacement requirements, the company said.
Together with the 60 ships contracted for by QatarEnergy in the first phase of the program, which will be built at Korean and Chinese shipyards, the agreement with HHI brings the total number of confirmed new LNG vessels to be delivered to QatarEnergy and its affiliates to 77, with more to follow, the company said.
