OGJ Newsletter

Feb. 27, 2023
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


EIA: US renewable diesel capacity could more than double through 2025

US production capacity for renewable diesel could more than double from current levels by end-2025, based on company reports on projects that are either under construction or could start development soon, the US Energy Information Administration (EIA) said.

Two factors behind growing US renewable diesel capacity are rising targets for state and federal renewable fuel programs and biomass-based diesel tax credits. The Inflation Reduction Act of 2022 extended the biomass-based diesel tax credits through 2024. EIA estimates US renewable diesel production capacity was 170,000 b/d, or 2.6 billion gallons per year (gal/y), at end-2022. While some projects might be delayed or canceled, if all projects begin operations as scheduled, US renewable diesel production capacity could reach 384,000 b/d, or 5.9 billion gal/y, by end-2025.

Renewable diesel is a fuel that is chemically equivalent to petroleum diesel and nearly identical in its performance characteristics. Renewable diesel has some of the highest greenhouse gas (GHG) reduction scores among existing fuel pathways in programs such as the federal Renewable Fuel Standard (RFS), the California Low-Carbon Fuel Standard (LCFS), the Oregon Clean Fuels Program, and the Washington State Clean Fuels Program.

Investment in new renewable diesel production capacity in the US has grown significantly because of renewable diesel’s interchangeability with petroleum diesel in existing petroleum infrastructure and because of government incentives. In 2022 and early 2023, the following eight renewable diesel refineries began production:

  • CVR Energy’s plant in Wynnewood, Okla.
  • Diamond Green Diesel’s plant in Port Arthur, Tex.
  • HollyFrontier’s plant in Artesia, NM. 
  • HollyFrontier’s plant in Cheyenne, Wyo.
  • Montana Renewables’ plant in Great Falls, Mont.
  • New Rise Renewables’ plant in Reno, Nev.
  • Seaboard Energy’s plant in Hugoton, Kan.
  • Shell’s plant in Norco, La.

An average of 520,000 b/d of distillate fuel oil was consumed on the West Coast in 2021. The region, which is also the largest renewable diesel importing region in the US, could soon meet the majority of its distillate fuel needs from renewable diesel by 2025 if domestic renewable diesel capacity does increase as scheduled, EIA said. 

Comstock to release two rigs in 2023 program

Comstock Resources Inc., Frisco, Tex., is releasing two of its nine operated drilling rigs in response to the current lower natural gas prices and plans to spend about $950 million to $1.15 billion this year in drilling and completion activities.

Activities for the year will be primarily focused on continued development of Haynesville-Bossier shale properties and delineation of the Western Haynesville play (2-rig program), the company said in its earnings report Feb. 14.

Under the current 2023 operating plan, the company plans to drill 67 (50.5 net) and complete 69 (49.2 net) operated horizontal wells, including eight (8.0 net) wells in the Western Haynesville area. First quarter production of 1,375-1,435 MMcfed is expected, with guidance of 1,425-1,550 MMcfed for the year.

Comstock also expects to spend $75-125 million on infrastructure, including upgrades to its Western Haynesville pipeline and processing infrastructure, and for other development costs. An additional $25-35 million is earmarked for lease acquisitions.

Reported net income for fourth-quarter 2022 included a pre-tax $302.8 million unrealized gain on hedging contracts. Excluding this and certain other items, adjusted net income for the quarter was $287.7 million.

Net cash provided by operating activities (excluding changes in working capital) generated in the quarter was $434.5 million, and net income available to common stockholders for the quarter was $516.9 million.

Production in the fourth quarter increased 7% from last year to 1,445 MMcfed.

The company drilled 73 (57.0 net) operated horizontal Haynesville/Bossier shale wells in 2022 which had an average lateral length of 10,044 ft. The company also participated in an additional 42 (3.4 net) non-operated Haynesville shale wells during the year.

Comstock turned 66 (53.6 net) operated wells and 38 (1.8 net) non-operated wells to sales in 2022 and currently expects to turn an additional 17 (10.5 net) operated wells to sales in first-quarter 2023.

Lukoil, KazMunayGaz define roles for Caspian Sea project

PJSC Lukoil and JSC NC KazMunayGas signed agreements regarding the Kalamkas-Sea, Khazar, Auezov subsoil area development project in the Kazakh sector of the Caspian Sea. The agreements define rights and obligations of the subsoil user during joint development activities in the area, Lukoil said in a release Feb. 9.

The offshore oil fields lie about 60 km from the coast at a depth of 7-9 m and could produce 3-4 million tonnes/year of oil. Commissioning is expected in 2028.

The agreements will come into force following completion of transaction between the two companies that will result in both parties holding equal shares in Kalamkas-Khazar Operating LLC, the project’s operating company.​

In November 2021, the companies had signed an agreement on principles for joint development of the Kalamkas-Sea and Khazar project. The parties met in the Republic of Kazakhstan Feb. 1 to discuss current cooperation issues and business opportunities including conditions of joint work on the Kalamkas-Sea and Khazar project and opinions on development plans for Zhenis and Al-Farabi projects.

The companies cooperate on the Karachaganak, Tengiz, Al-Farabi and Zhenis projects, take part in the Caspian Pipeline Consortium oil transportation project, and in joint ventures to develop Khvalynskoye and Tsentralnoye fields.​

Exploration & Development Quick Takes

Karoon confirms oil at Neon field

Karoon Energy Ltd., Melbourne, completed drilling the Neon-1 control well in Neon field in Santos basin offshore Brazil, confirming primary reservoir targets are present and oil-bearing.

The well, officially 9-NEO-1-SPS, reached a total depth of 2,382 m and wireline logging is under way.

Neon-2 was drilled into the down-dip southern flank of the Neon discovery to gather better data on lithologies and reservoir quality and to reduce the uncertainty of the oil-water contact. Results will assist in delineating pathways of potential future production wells, Karoon said.

The Palaeocene reservoir intervals, representing an extension of reservoirs tested in nearby Echidna-1 (which found the now renamed Neon field), were found to be present over a gross interval of 113 m. A probable oil-water contact has been identified.

Importantly, an analysis of pressure tests through the Palaeocene section indicates that oil lies on the same pressure gradient as oil in Echidna-1, which suggests communication between the two wells.

Evaluation of well data at Neon-1 is ongoing and all information will be the subject of further studies and calibration from laboratory analyses of physical samples, including the 57 m of core obtained from the well.

Karoon will proceed to drill Neon-2, which will be directionally drilled to intersect a crestal location in the northern part of Neon field with the aim of determining the quality and continuity of the Palaeocene units as well as Palaeocene pressure connectivity with the two wells drilled to date. Neon-2 also will test a deeper zone below the existing Palaeocene discovery.

Resource estimates for Neon, made in May 2018 upon discovery, are 30 million bbl of 1C contingent resources, 55 million bbl of 2C, and 92 million bbl of 3C. A revised estimate when the two control wells are completed, Karoon said.

Neon-2 is expected to spud before month’s end. 

Neon field lies in Karoon’s 100%-owned S-M-1037 license, about 210 km offshore.

Neon-1 is in 343 m of water about 2 km south of Echidna-1. Neon-2 will lie 1.3 km north northeast of Echidna-1 in 305 m of water.

Equinor drills dry hole near Johan Sverdrup

Equinor Energy AS drilled a dry hole in appraisal well 16/2-23 S and will reduce resource estimates of a discovery in North Sea production license (PL) 265, according to a release by the Norwegian Petroleum Directorate Feb. 16. The well was drilled about 7.5 km east of Edvard Grieg field and 10 km west of Johan Sverdrup field in the North Sea.

The exploration well, the 18th in the license, was drilled in 110 m of water by the Deepsea Stavanger drilling unit to a vertical depth of 2,100 m subsea and terminated in conglomerates presumably from the Jurassic-Triassic.

The objective was to delineate the 16/2-5 (P-Graben) gas discovery made in 2009 and to prove additional volumes of petroleum in a graben structure from the Jurassic-Triassic with better reservoir properties in the southern part of the Utsira High. The reservoir interval in the 16/2-5 gas discovery was cored in the appraisal well, which encountered graben-filled sediments with a thickness of about 260 m, with conglomerate rocks with poor reservoir quality. Traces of oil were encountered in an interval of around 80 m.

Well 16/2-23 S encountered traces of hydrocarbons in conglomerate rock presumably from the Jurassic-Triassic with poor reservoir quality. The well is classified as dry. Pressure points in the water zone confirm communication with the discovery in well 16/2-5.

The result of 16/2-23 S indicates that the resources have been considerably reduced compared with previous estimates. Before well 16/2-23 S was drilled, the resource estimate for the discovery was 1-2.9 billion std cu m recoverable gas. Volumetric revisions for the 16/2-5 discovery will be completed when final data from the well is available.

The well has been permanently plugged and the drilling rig will now drill wildcat well 35/10-9 in PL 827 S where Equinor is operator.

Equinor is operator at PL 265 (42.6%) with partners Petoro AS (30%) and Aker BP AS (27.4%).

Drilling & Production Quick Takes

Shell brings Vito online in Gulf of Mexico

Shell Offshore Inc., a Shell plc subsidiary, started production from the Vito platform, the operator’s 13th deepwater host in the Gulf of Mexico.

Originally discovered in 2009, Vito field spans four Outer Continental Shelf blocks in the Mississippi Canyon and lies at a depth of more than 1,220 m of water. The platform lies about 241 km southeast of New Orleans.

Vito is a four-column semi-submersible host platform with eight subsea wells (9,400 m) with deep (5,500 m) in-well, gas lift, and associated subsea flowlines and equipment.

At peak, the field is expected to produce 100,000 boe/d. Estimated recoverable resources are about 290 MMboe.

Vito will produce into Shell Midstream’s Mars Pipeline system.

Shell is operator with 63.11% interest. Equinor holds 36.89%.

Norway production down in January, NPD says

Norway’s production averaged 1.979 million bbl in January, the Norwegian Petroleum Directorate (NPD) reported. The figure is down from the 1.983 million bbl produced in December (OGJ Online, Jan. 20, 2023).

Average daily liquids production in January consists of 1.754 million b/o, 200,000 bbl of NGL, and 25,000 bbl of condensate.

Oil production in January was 3.0% lower than the NPD’s forecast.

Buru acquires Origin’s Canning basin JV interests

Buru Energy Ltd., Perth, agreed to acquire interests of Origin Energy Ltd. in the pair’s joint venture exploration permits in the onshore Canning basin of northwest Western Australia.

Origin will provide Buru with up to $4 million (Aus.) for a 3D survey over the Rafael gas-condensate discovery made in 2021. The program is timed for the mid-2023 operating season.

With Origin’s withdrawal, Buru will resume its position as the dominant net acreage holder and operator in the Canning region with participation in seven exploration permits (100% in EP 129, EP 391, EP 428, EP 431, EP 436). Buru holds 60% of EP 457 and EP 458, which it shares with Rey Resources Ltd.

The Rafael find in EP 428 has been independently assessed to contain over 1 tcf of recoverable gas and 20 million bbl of recoverable condensate.

Origin farmed into the seven permits in December 2020 to earn interests of 40-50% while Buru remained operator with 40-100% interests.

The farm-in deal required Origin to majority fund a two-well drilling program as well as a regional seismic program. Rafael-1 was the second well in the program. In June 2022, however, Origin declined to approve funding for seismic work over the discovery.

In September 2022, Origin reported its intention to withdraw from all upstream exploration activities in Australia, including the JV with Buru in EP 428, a move Buru said introduced uncertainty to the timing and form of the Rafael appraisal and commercialization program. Subsequent negotiations led to the new deal.

Buru will provide Origin future capped staged contingent reimbursements up to $34 million (Aus.), conditional on achievement of Rafael discovery-related development and production milestones. Buru said contingent payments reflect certain past costs and costs related to the transaction as incurred by Origin.

The transfer of titles back to Buru is expected to be complete by second-quarter 2023.

Following completion and interpretation of the planned Rafael seismic program, Buru expects to begin appraisal drilling in 2024.


EnLink Midstream adding gas plant in Delaware basin

EnLink Midstream LLC is proceeding with relocation of an underutilized natural gas processing plant from the Barnett shale of North Texas to the company’s operations in the Permian’s Delaware basin.

Known as Project Tiger II, the 150-MMcfd plant’s relocation is scheduled to be completed during second-quarter 2024 at a total net cost of $30 million, of which $15 million would qualify as an operating expense, EnLink told investors in its fourth-quarter 2022 earnings report.

While the operator did not reveal further details about the relocation project, the company did confirm the newly named Tiger II plant was one of three processing assets EnLink gained via its third-quarter 2022 acquisition of Crestwood Equity Partners LP Barnett shale assets.

EnLink previously completed the 240-MMcfd Tiger I gas processing plant in Culberson County, Tex., in August 2020.

In addition to the Tiger II relocation, EnLink said it completed construction of its 235-MMcfd Phantom processing plant in the Texas Midland basin, as well as agreed with partner Gulf Coast Fractionators (GFC) to the restart of their co-owned 145,000-b/d NGL fractionator in Mont Belvieu, Tex.

EnLink holds a 38.75% interest in the fractionator, with operator GCF holding the remaining 61.25% interest.

Idled to lower the partners’ operating expenses beginning in January 2021 amid reduced demand for fractionation capacity in the region, the Mont Belvieu fractionator is slated for restart during first-half 2024, EnLink said.

Denmark-based operator lets contract for electrofuels plant

Arcadia eFuels APS of Denmark has let a contract to Technip Energies to deliver front-end engineering and design (FEED) on the operator’s proposal to build what it says would be the first-ever plant to produce carbon-neutral electrofuels (eFuels)—including a sustainable aviation fuel (SAF)-equivalent—from renewable electricity, water, and biogenic CO2.

Technip Energies will engineer a plant that will produce about 55,000 tonnes/year (tpy) of eJet fuel (eKerosine), 25,000 tpy of eNaphtha, and an unidentified volume of eDiesel, all of which can respectively be blended up to 50% with conventional jet and road fuels to help the aviation and heavy transportation industries meet voluntary and regulatory carbon-reduction goals, the service provider said.

The scope of delivery also includes engineering of an associated 250-Mw electrolyzer for production of green hydrogen at the complex, which will be built at the port of Vordingborg, Denmark, in the southern part of Zeeland, 100 km south of Copenhagen.

With pre-FEED and early works recently completed, the eFuels complex is scheduled for startup in 2026.

The FEED contract award follows Arcadia eFuels’ preliminary selection of Technip Energies Italy SPA to provide both FEED and engineering, procurement, and construction (EPC) services for the project. Arcadia eFuels also confirmed its January 2022 award of a joint contract to Topsoe AS and Sasol Ltd. for delivery of preliminary engineering on the proposed eFuels plant, which will be based on the service providers’ integrated G2L eFuels technology.

While Arcadia eFuels has yet to confirm taking positive final investment decision (FID) on the project that—as of November 2022—was due by yearend 2022, the operator said the proposed e-Fuels plant’s production of net-zero carbon aviation fuel would exceed Denmark’s total requirements for eFuels established under national mandates targeting carbon-neutral domestic air travel by 2030.

Given the project’s location at Vordinborg Port, the plant’s excess production of e-Fuels—which can be transported using existing liquid-fuels infrastructure—would be available for export to markets abroad, Arcadia eFuels said.

e-Fuels production

Arcadia eFuels said production at its proposed plant will involve the following:

  • Electrolysis. Using renewable electricity to power an electrolysis process, water will be split into green hydrogen and oxygen.
  • Captured CO2. CO2 will be sourced either from biogenic carbon via carbon capture technology at a designated source, from direct air capture, or a combination of the two.
  • Electrified reverse-water gas shift. Hydrogen produced from the electrolysis process will react with captured CO2 to produce water and carbon monoxide, or syngas, as a feedstock to the Fischer Tropsch (FT) process.
  • Low-temperature FT process. A catalytic chemical reaction will convert syngas into hydrocarbons.
  • Hydroprocessing. Hydrocarbons produced in the FT process will be converted into eJet fuel, eDiesel, or a combination of both, along with smaller amounts of eNaphtha and eLPG.

Alternatively known as a Power-to-X (PtX, P2X) technology, the operator’s selected Topsoe-Sasol G2L process consists of the service providers’ following proprietary technologies:

Topsoe’s SynCor reforming technology for converting methane-rich gas and oxygen to carbon monoxide and hydrogen, the two key syngas components required by the low-temperature Fischer-Tropsch (LTFT) synthesis process.

Sasol’s LTFT synthesis process for catalytic conversion of carbon monoxide and hydrogen into long-chain molecules.

Topsoe’s hydroprocessing technology, which breaks down, isomerizes, and saturates the long-chain molecules to produce designated end-products (e.g., jet fuel, diesel, naphtha).

Topsoe’s hydrogen technology for production of low-carbon hydrogen to power associated hydroprocessing and syngas processes (see figure).


Perenco to build 0.7-million tpy LNG plant in Gabon

Perenco Oil and Gas Gabon has reached final investment decision on construction of a 0.7-million tonne/year (tpy) LNG plant at Cap Lopez oil terminal in Gabon. The plant will take 3 years to build.

In addition to LNG, the plant will produce 20,000 tpy of butane. When combined with 15,000 tpy of LPG production expected to enter production this year, the new plant will make Gabon self-sufficient in butane as soon as 2026, according to Perenco. LNG will be exported.

To ensure operational continuity throughout construction, a 2-milllion bbl crude carrier (VLCC) has been stationed at Cap Lopez to store crude coming into the terminal. Perenco acquired Cap Lopez from TotalEnergies SE in 2021.

In addition to Perenco, BW Energy Gabon SA, VAALCO Energy Inc., and China National Offshore Oil Corp. are all producing from or developing fields offshore Gabon.

Williams, Chevron to support Haynesville, GoM natural gas growth

Williams, Tulsa, Okla., signed executive agreements with Chevron USA Inc. to support natural gas development in the Haynesville basin as well as the deepwater Gulf of Mexico.

Williams will provide natural gas gathering services to Chevron’s 26,000-acre Haynesville dedication while Chevron has agreed to a long-term capacity commitment on Williams’ Louisiana Energy Gateway (LEG) project.  

As part of the Haynesville agreement, Williams plans to construct a greenfield gathering system in support of Chevron’s acreage dedication with connectivity to Williams LEG project. Williams reached a positive final investment decision on LEG in June 2022. The project is designed to gather 1.8 bcfd of Haynesville natural gas and connect it to Transco natural gas pipeline system markets and Gulf Coast LNG markets.

In the Gulf of Mexico, Williams has agreed to use existing infrastructure to serve increased production from the Blind Faith platform, which lies 160 miles southeast of New Orleans.

In May 2022, Chevron sanctioned the Ballymore project. With design capacity of 75,000 b/d of crude oil, Ballymore will be developed as a three-mile subsea tieback via one flowline to the existing Blind Faith platform.

Using existing connections to Blind Faith, Williams will provide offshore natural gas gathering and crude oil transportation services as well as onshore natural gas processing services for the production.

Chevron is the operator of the Ballymore project with a 60% interest. TotalEnergies E&P USA Inc. holds the remaining 40% interest.

Inpex revising Abadi LNG project to include CCS

Inpex Corp. is studying ways to makes its 9.5-million tonne/year Abadi LNG liquefaction project cleaner as it continues negotiations with the Indonesian government on additional revisions to its plan of development (POD), inclusive of carbon capture and storage. The company described its efforts as driven by ways to increase Abadi’s long-term competitiveness and sustainability.

Inpex plans to sequentially restart on-site Abadi project activities upon POD approval, targeting final investment decision in the latter half of 2020s to begin production in the early 2030s.

Masela block offshore Indonesia would supply the feedgas for Abadi LNG, as well as providing 150 MMcfd for local consumption. Indonesian authorities previously approved revisions to Abadi changing it from a floating LNG (FLNG) development to an onshore one.

Inpex owns 65% of Masela in partnership with Shell PLC. Shell has been seeking to sell its 35% share in the block for years, having preferred the FLNG development option. Potential buyers as of late 2022 include a consortium led by Indonesian-state energy company PT Pertamina, Malaysian-state Petroliam Nasional Berhad (Petronas), and ExxonMobil Corp.

Abadi field, part of Masela, contains an estimated 10.7 tcf of natural gas.