OGJ Newsletter

Nov. 7, 2023
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


JX Nippon restarts Petra Nova carbon capture plant in Texas

JX Nippon Oil & Gas Exploration Corp. restarted operations at the Petra Nova CCUS plant in Texas on Sept. 5, 2023.

The project, owned 100% by JX Nippon subsidiary Petra Nova Parish Holdings LLC since September 2022, had been shut down since May 2020 by NRG Energy Inc. due to a combination of low oil prices and mechanical problems. The company later sold its 50% interest in Petra Nova Holdings to partner JX Nippon for $3.6 million.  

NRG Energy Inc. placed the Petra Nova project in Thompson, Tex., into service in 2017. It was designed to capture at least 90% of the CO2 emissions from a 240-Mw equivalent flue-gas slipstream at the NRG Energy Inc.-owned W.A. Parish Electric Generating Station and to store up to 1.4 million tpy of CO2. Captured CO2 was compressed and transported through an 80-mile pipeline for enhanced oil recovery (EOR).

Vista Energy increases profits 54% year-over-year

Vista Energy S.A.B. de C.V. increased its adjusted net income 54% from the year-ago level to $122.5 million in this year’s third quarter. The company, Argentina’s second-largest shale oil producer, attributed the increase to higher Vaca Muerta production and a decrease in operating costs.

During this year’s third quarter, Vista increased production to 49,450 boe/d, an increase of 6% compared with second-quarter 2023. Oil production for the quarter was 41,490 b/d, largely driven by production from 12 new wells in the Bajada del Palo Oeste block in Vaca Muerta.

Growth continued in September with production of 53,000 boe/d. The company expects to produce 70,000 boe/d in 2024.

Vista’s operating costs in third-quarter 2023 were reduced to $4.80/boe, a decrease of 35% year-on-year, due to the company’s unconventional oil-focused operating model. In this year’s first quarter, to increase its focus on its shale operations in Vaca Muerta, the company made a deal to transfer all of its production from conventional assets (Entre Lomas Río Negro, Entre Lomas Neuquén, Jarilla Quemada, Charco del Palenque, 25 de Mayo Medanito SE, and Jagüel de los Machos) to Petrolera Aconcagua Energía S.A.

Since that time Vista has recovered production to levels prior to the divestiture.

Earlier this year, the company noted plans to increase its daily production by 25% to 100,000 boe/d by 2026  compared with a goal set in 2021. At the same time, the company said it plans to invest $2.5 billion in Vaca Muerta over the next 3 years.

Comstock Resources forms midstream partnership for Haynesville build-out

Comstock Resources Inc. has formed a partnership to fund its midstream build-out to support Western Haynesville acreage development.

As part of a deal with Quantum Capital Solutions (QCS), an affiliate of Quantum Capital Group, Comstock will contribute its Pinnacle gathering and treating system—comprised of a 145-mile high pressure pipeline and the Bethel natural gas processing plant—to the partnership in exchange for 100% of the capital required (up to $300 million) to fund the future build-out of the Western Haynesville midstream system over the next 5 years, Comstock said as part of its third-quarter earnings.

Comstock will operate the midstream system and direct its activities and said the partnership will reduce capital outlays that would be required in 2024 to support expected production growth from the area. In this year’s fourth quarter, Comstock expects its production to come in at 1,450-1,550 MMcfed.

For the quarter, Comstock had adjusted net income of $11.7 million compared with $326 million for the same quarter in 2022. Continued weak natural gas prices weighed heavily on the third quarter results, the operator said.

Comstock drilled 13 (10.2 net) operated horizontal Haynesville-Bossier wells in the quarter with 11,644 ft average lateral length and turned 21 (18.1 net) operated wells to sales with initial daily production rates that averaged 29 MMcfd.  

Exploration & Development   Quick Takes

OKEA discovers oil near North Sea Brage field

OKEA ASA discovered oil near Brage oil field in production license (PL) 055 in the North Sea, the Norwegian Petroleum Directorate said Oct. 26. About 0.2-0.5 million std cu m of recoverable oil reserves were proven.

Two wells were drilled from the platform on Brage field in 137 m of water. Well 31/4-A 13 E was drilled as a horizontal sidetrack based on data collected during the drilling operation. The well encountered the Sognefjord formation 2,147 m subsea and proved oil in a sandstone layer of about 10 m in reservoir rocks with moderate to good reservoir quality. The oil-water contact was not encountered.

Production well 31/4-A-13 D was drilled in the southern part of Brage field and was extended to reach two exploration targets in a separate structure south of the field. The targets were in Sognefjord and Fensfjord formations, and both were dry. The well was not formation-tested, but data acquisition has been carried out. The well has been plugged.

Brage field was proven in 1980 in reservoir rocks in the Statfjord and Brent Group and in the Fensfjord and Sognefjord formations. 

The field started production in 1993 and with oil transportation via the Oseberg Transport System-Sture Terminal and gas offtake through Gassco AS’s Gassled pipeline system on the Norwegian Continental Shelf (OGJ Online, Oct. 9, 2023).

OKEA is operator at PL 055 (35.2%) with partners Lime Petroleum AS (33.8434%), DNA Norge AS (14.2567%), Petrolia (12.2575%), and M Vest Energy AS (4.4423%).

ExxonMobil to carry out comprehensive appraisal of latest Guyana discovery

ExxonMobil will carry out a comprehensive appraisal process of the newly discovered reservoir encountered by the Lancetfish-2 appraisal well in the Liza petroleum production license area, the country’s Ministry of Natural Resources said last week.  

The Ministry’s release comes following partner Hess Corp.’s third-quarter 2023 earnings statement in which it detailed Lancetfish-2 (OGJ Online, Oct. 25, 2023). Hess said the appraisal well encountered about 125 ft of net oil pay in appraisal reservoirs and about 65 ft of net oil pay in a new discovery interval.

The well was drilled in 5,649 ft of water and lies about 4 miles southeast of the Lancetfish-1 discovery well, which—drilled by the Noble Don Taylor—encountered about 92 ft of high-quality oil-bearing sandstone. That well was drilled in 5,843 ft of water and is about 4 miles southeast of the Fangtooth discovery.

ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. is operator and holds 45% interest in Stabroek block. Hess Guyana Exploration Ltd. holds 30% interest and CNOOC Petroleum Guyana Ltd. holds 25% interest.

Woodside progresses Gulf of Mexico projects

Woodside Energy has let a flexible pipe contract to TechnipFMC and installed subsea equipment from Trendsetter Engineering Inc. for Trion and Shenzi North projects in the Gulf of Mexico, respectively.

TechnipFMC will supply infield flowlines and jumpers for the Trion project 180 km off the coastline and 30 km south of the US-Mexico border in 8,200 ft of water. Trion will be developed with 18 wells (nine producers, seven water injectors, and two gas injectors) drilled in the initial phase and a total of 24 wells drilled over the life of the project.

A 100,000 b/d capacity floating production unit (FPU) will connect to a floating storage and offloading (FSO) vessel with a capacity of 950,000 bbl of oil.

In August, Woodside received field development plan approval from Mexican regulator Comision Nacional de Hidrocarburos (CNH). First oil is targeted for 2028.

Trendsetter Engineering delivered two subsea manifolds, two high integrity pressure protection Systems (HIPPS), and TCS clamps for Shenzi North about 195 km off the coast of Louisiana in the Green Canyon area. Trendsetter partnered with Proserv for the HIPPS control system and ATV for provision of the HIPPS shutdown valves.

By using HIPPS modules, existing flowlines, risers, and topsides, Shenzi North can tie‐in to the existing Shenzi tension leg platform (TLP). Delivery and subsequent start‐up of the two well‐based HIPPS modules represent the first fully sanctioned and operational subsea HIPPS units in the region, the service provider said in a release.

Woodside started production at Shenzi North in September.

Woodside is operator at Trion (60%) with partner PEMEX Exploración y Producción (40%) and operator of Shenzi (72%) with Repsol holding the remaining 28% interest.

Drilling & Production   Quick Takes

Wintershall produces first gas at East Damanhur

Wintershall Dea produced first gas at the ED2-X well at East Damanhur block in the onshore Nile Delta in Egypt. The well’s proximity to existing infrastructure at Disouq enabled a rapid tie-back and production start, the company said in a release Oct. 30.

Wintershall Dea (operator, 40%) and partners Cheiron Energy (40%) and INA (20%), as well as the Egyptian Gas Holding Co. (EGAS), began exploring at East Damanhur in 2021 and noted a gas discovery at the ED-2X ST1 well in January 2023.

ED-2X ST1 lies about 3 km from Disouq field, where Wintershall Dea and EGAS are producing natural gas in the DISOUCO joint venture. The well—tied-back to Disouq infrastructure within 2 months—is currently producing around 10 MMscfd.

Aker BP starts production at Kobra East, Gekko fields offshore Norway

Aker BP started production from Kobra East and Gekko (KEG) oil and gas fields in production license (PL) 203 in the Alvheim area offshore Norway. The original startup target was first-quarter 2024.The project has been delivered under the original budget of NOK 8 billion.

KEG has been developed in the Norwegian part of the central North Sea near the UK border with subsea installations connected to the Alvheim FPSO on Aker BP-operated Alvheim field. Four multi-branch wells have been drilled in the reservoir (the Heimdal formation, a high-quality turbidite reservoir similar to the reservoir developed on Alvheim field) with about 42 km combined measured depth.

KEG will extend the Alvheim FPSO lifetime up to 2040. The ongoing Tyrving project—estimated to come on stream in 2025—will add further production to the FPSO, the operator said. Recoverable resources at Tyrving are estimated at about 25 MMboe. (OGJ Online, June 8, 2023).

Recoverable reserves as noted in KEG’s plan for operation and development, submitted to the Ministry of Petroleum and Energy in June 2021, are estimated at about 40 MMboe.

Since the start of production from Alvheim in 2008, nearly 600 MMboe have been produced from the area.

Aker BP is operator at PL 203 with 80% interest. ConocoPhillips Skandinavia AS holds the remaining 20%.

Equinor advances plan for Svalin drilling

Equinor Energy AS has been granted approval by the Petroleum Safety Authority Norway (PSA) for use of Odfjell Drilling Ltd.’s Deepsea Aberdeen semi-submersible drilling rig for production drilling, completion, and exploration drilling at Svalin oil field in the central part of the North Sea.

In May, Equinor added to the rig’s work scope with new wells to be drilled at Svalin field starting in this year’s fourth quarter for an estimated 174 days, extending the rig’s firm backlog into second-quarter 2025.

Svalin lies 6 km southwest of Grane field in water depth of 120 m. The field was discovered in 1992, and the plan for development and operation (PDO) was approved in 2012.

The field is developed with a multilateral well drilled from the Grane platform (Svalin M), and with a subsea template tied-in to Grane (Svalin C) via pipeline. Production started in 2014.

Svalin produces oil and associated gas from massive sandstone of Paleocene to early Eocene age in the Heimdal and Balder formations. The reservoirs are in marine fan deposits and have excellent quality. They lie at a depth of 1,750 m.

Equinor is operator of the field with 57% interest. Partners are Petoro AS (30%) and Var Energi ASA (13%).

CNOOC starts production at Enping 18-6

CNOOC Ltd. started production from two projects, the Enping 18-6 development project in the Pearl River Mouth Basin of the South China Sea, and the Penglai 19-3 area 5/10 project in south-central Bohai Sea.

For Enping 18-6, production infrastructure lies in about 99 m of water and includes one wellhead platform with 15 development wells planned to be put into production. Peak production of about 9,300 b/d is expected in 2024. CNOOC is operator with 100% interest.

At Penglai 19-3, the main production infrastructure lies in about 30 m of water and includes two wellhead platforms. A total of 130 development wells are planned, including 87 production wells and 43 water-injection wells. The area is expected to achieve a peak production of about 29,800 b/d in 2027. CNOOC is operator with 51% interest. ConocoPhillips China holds 49%.

PROCESSING   Quick Takes

Satorp’s Jubail complex producing SAF via co-processing of used cooking oil

Saudi Aramco TotalEnergies Refinery & Petrochemicals Co. (Satorp)—a joint venture of Saudi Aramco (62.5%) and TotalEnergies SE (37.5%)—has completed production of sustainable aviation fuel (SAF) from co-processing of used cooking oil (UCO) at the operator’s 460,000 b/d full-conversion refinery complex at Jubail, on Saudi Arabia’s eastern coast.

Satorp’s Jubail platform produced the Middle East and North Africa (MENA) region’s first International Sustainability and Carbon Certification (ISCC+)-certified SAF from UCO in August 2023 via co-processing in the refinery’s low-pressure hydrodesulfurization unit, meeting all product-quality parameters of SAF specifications, TotalEnergies said on Oct. 30.

“This project at Satorp is part of TotalEnergies’ aim to produce 1.5 million tonnes/year (tpy) of SAF by 2030 [in line] with the company’s ambition to get to net zero by 2050,” said Francois Good, senior-vice president of TotalEnergies’ refining and petrochemicals for the company’s Africa, Middle East, and Asia-Pacific division.

With first production now completed and ISCC+ certification in hand, Satorp’s Jubail platform is now equipped to respond to Saudi Arabia’s anticipated increased demand for UCO-based SAF, which reduces carbon dioxide (CO2) emissions by at least 80% on average across the entire lifecycle compared with the fossil-based fuel equivalent, TotalEnergies said.

Satorp’s production of ISCC+ certified SAF at Jubail follows the operator’s first production of ISCC+ certified circular polymers from plastic pyrolysis oil, or plastic waste derived oil (PDO), in the MENA region earlier this year, paving the way for Saudi Arabia’s creation of a domestic value chain for the advanced recycling of non-sorted plastics to circular polymers to help solve the challenge of end-of-life plastics, according to a July 17 release from TotalEnergies.

Aramco and TotalEnegies also recently let contracts for construction of the proposed $11-billion Amiral grassroots petrochemical complex to be integrated into Satorp’s existing Jubail platform (OGJ Online, June 26, 2023).

To feature a mixed-feed cracker capable of producing 1.65 million tpy of ethylene and related industrial gases, as well as two polyethylene units—each with a capacity of 500,000 tpy—the proposed Amiral complex would enable Satorp to convert internally produced refinery offgases and naphtha—in addition to ethane and natural gasoline supplied by Aramco—into high-demand chemicals by 2027 in support of Aramco’s plan to advance its liquids-to-chemicals strategy.

Indian Oil contracts Linde for industrial gases supply to Panipat refinery 

Indian Oil Corp. (IOC) has let a contract to Linde entities in India for the supply of industrial gases to IOC’s Panipat refinery in Haryana, India, north of New Delhi.

Linde’s entities will build, own, and operate new on-site infrastructure to supply hydrogen, nitrogen, and compressed dry air to IOC on a job work basis, the service provider said in a release Oct. 25.

The on-site will support the expansion of the refinery to 25 million metric tons/year (tpy) from 15 million tpy.

Industrial gases play several roles in refining, including removing sulfur to make clean fuels, cracking crude oil into various products, or purging and cleaning process equipment and control instruments, Linde said.

Panipat will be the second large-scale hydrogen plant which is built, owned, and operated by Linde entities for IOC. It will also be one of Linde’s largest on-site plants in India, with a total combined industrial gas production capacity of 142,200 cu m/hr. The plant is expected to start up in 2025.

In addition to supplying IOC, the new on-site complex will cater for demand for nitrogen from companies across end markets including chemicals, energy, and manufacturing, Linde said.


Calcasieu Pass LNG granted modified Phase 3 in-service plan

Venture Global LNG Inc. has been granted authorization by the US Federal Energy Regulatory Commission (FERC) to place Blocks 7-9 of its 10-million tonne/year (tpy) Calcasieu Pass LNG plant in service, using a modified commissioning plan that will allow individual systems or equipment to be placed in service as ready (OGJ Online, Oct. 12, 2023).

Venture Global’s previously authorized commissioning and in-service plan included three phases: Phase 1 included Blocks 1-4, Phase 2 Blocks 5-6, and Phase 3 the remainder of the plant, including liquefaction Blocks 7-9, both 200,000-cu m LNG storage tanks, both marine transfer systems, all pretreatment systems, and power generation. FERC said, however, that commissioning demonstration tests and commissioning operations over the last several months have shown that liquefaction equipment can operate above authorized nameplate capacity and near authorized maximum capacity, despite reliability issues associated with the heat-recovery steam generator tube leaks and with other individual units or pieces of equipment that may not be meeting commissioning demonstration tests or have failed to operate reliably after such tests.

The commission therefore agreed with a modified commissioning plan that no longer bundles Phase 3 when individual systems or equipment can be demonstrated to operate safely and reliably on their own. The plant, sited in Cameron Parish, La., uses 18 modular liquefaction trains configured in nine two-train blocks.

Contract customers including Shell PLC, bp PLC, Repsol SA, and Edison SPA welcomed the FERC ruling, suggesting that it clears the way for them to begin loading cargoes. The companies are in arbitration with Venture Global seeking either the ability to begin loading or monetary compensation. Calcasieu Pass has loaded numerous “pre-commissioning cargoes” since it began operations in 2022 but has yet to supply its foundational contract customers.

Navigator cancels US Midwest CCUS pipeline project

Navigator CO2 Ventures LLC has cancelled its 15-million tonne/year (tpy) Heartland Greenway carbon capture, utilization, and sequestration (CCUS) pipeline project, citing “the unpredictable nature of the regulatory and government processes involved, particularly in South Dakota and Iowa.” Heartland Greenway was being developed to collect carbon from Midwest ethanol plants—including 18 operated by POET LLC in Iowa, Nebraska, and South Dakota—for sequestration in Illinois.

The cancellation follows a Sept. 29, 2023, request by Navigator to pause the Iowa permitting process and its Oct. 10, 2023, withdrawal of the 1,300-mile project’s sequestration permit application in Illinois. South Dakota had denied permits for Heartland Greenway earlier in September.

Summit Carbon Solutions LLC and Wolf Carbon Solutions US LLC are still developing multistate projects in the Upper Midwest. The North Dakota Public Service Commission in August 2023 denied a siting permit for Summit’s 18-million tpy Midwest Carbon Express CO2 pipeline, feeling that the company had not taken steps to address outstanding legitimate concerns expressed by landowners (OGJ Online, Sept. 4, 2023).

Summit now expects Midwest Carbon Express to begin operations in 2026 instead of 2024. It is partnering with 34 Midwest ethanol plants in building the 2,000-mile system.

WBI Energy gets FERC approval for Wahpeton Expansion North Dakota gas pipeline

WBI Energy Inc. has received US Federal Energy Regulatory Commission (FERC) approval of its 20.6-MMcfd Wahpeton Expansion natural gas pipeline project. The 60.5-mile, 12-in. OD pipeline will increase natural gas deliveries to Wahpeton and Kindred, both in eastern North Dakota.

Wahpeton Expansion will run from an existing 3,000-hp compressor station at Mapleton, ND to Wahpeton. WBI expects to begin construction in 2024 for a late 2024 in service.

About 10 MMcfd of the expansion will be used by Montana-Dakota Utilities Co. to serve industrial and commercial customers in Wahpeton with contracts for firm natural gas service. The remainder will be sent to additional residential and commercial end users, including bringing natural gas utility service to Kindred.

Both Montana-Dakota and WBI are subsidiaries of MDU Resources Group Inc. The project is expected to cost $75 million. FERC last year issued Wahpeton Expansion’s draft environmental impact statement (OGJ Online, Nov. 7, 2022).