OGJ Newsletter

June 26, 2023
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


WoodMac: “plenty of running room” in shallow-water Niger Delta

Regarding TotalEnergies SE’s discovery at Ntokon in the shallow-water Niger Delta, Gail Anderson, Wood Mackenzie’s director of upstream research, stated, “Ntokon is likely to be Nigeria’s biggest shallow water discovery in a decade. Despite the lack of exploration in recent times, this discovery shows that there is still plenty of running room in the shallow-water Niger Delta.”

Drawing parallels with similar net pay in shallow-water discoveries in the Niger Delta’s Tertiary Agbada formation, and accounting for above-average recovery from high-quality reservoirs, Wood Mackenzie estimates the field could hold resources in the range of 300-400 MMboe.

The discovery was made in shallow-water block OML 102, part of a joint venture between operator TotalEnergies (40%) and NNPC Ltd. (60%). Ntokon will be developed by integrating it with the Ofon field, 20 km to the northeast, within the same block.

“Assuming 320 MMboe of reserves, a wellhead platform development of 60-70 m water depth with up to 30 wells and a multi-phase pipeline to Ofon could achieve first oil in 2029. This would generate a healthy internal rate of return of 24%, based on the current concession terms, with the understanding that the JV will not convert to the Petroleum Industry Act fiscal terms,” said Anderson.

Wood Mackenzie analysis notes that filling the Ofon infrastructure and the oil terminal will significantly cut emissions intensity, while a ready-made gas export route will make Ntokon a zero-flare development.

“This demonstrates the advantages of shorter-cycle tie backs over more expensive stand-alone developments for both cost savings and lower emissions,” said Anderson. “However, there are challenges. Nigeria is not known for short lead-times, particularly where JV projects are concerned. Ntokon will provide a test in the face of stiff global competition to see if all interested parties could quickly progress lower-cost, lower-carbon projects and allow Nigeria to kick-start desperately needed investment and recover its declining production.”

Project Greensand CCS receives DNV safety approval

Project Greensand, carbon capture and storage (CCS) in the Danish North Sea, has received official safety approval from DNV. The project aims to store up to 1.5 million tonnes/year (tpy) of CO2 per year in 2025-26, and as much as 8 million tpy by 2030.

DNV’s safety verification covers everything from fabrication by individual subcontractors to the actual offshore installation. Its work involved extensive analyses of plans, the suitability of the underground sites, and the practicability of the storage and designs, along with physical presence during a stress test of the individual sub-elements and approval of the connection and installation of offshore systems throughout the value chain and across national borders.

Wintershall Dea Norge AS and INEOS E&P AS earlier this year received the first CO2 storage licenses for Project Greensand from the Danish Ministry of Climate, Energy, and Utilities. Captured CO2 will be stored in depleted oil reservoirs in Nini West and Nini Main fields.

Project Greensand’s pilot stage used Nini West. The storage area has been extended to Nini Main field to start commercial operations. CO2 is transported on ships, transferred to the Nini platform, then pumped into the sandstone reservoirs through injection wells. Expansion to 8 million tpy will use depleted fields in the Siri Fairway.

The consortium behind Project Greenway consists of 23 companies and includes Noble Corp., Aker Carbon Capture ASA, and Blue Water Shipping Inc. in addition to Wintershall and INEOS.  

Earthstone acquires Novo Oil & Gas

Earthstone Energy Inc. has agreed to acquire Novo Oil & Gas Holdings LLC, a privately held Delaware basin-focused exploration and production company backed by EnCap Investments LP, for $1.5 billion. Concurrently, Northern Oil and Gas Inc. will acquire working interests equal to a pro-rata 331/3% of the oil and gas assets of Novo for $500 million from Earthstone, resulting in a $1.0 billion purchase price net to Earthstone for the retained 662/3% interest.

The company added 11,300 net acres (99% operated, 57% working interest, 86% held by production) in the core of Delaware basin in Eddy County, NM, and Culberson County, Tex. It will increase production by 38,000 boe/d from 114 wells, bringing its total output to more than 135,000 boe/d. Total proved developed and PV10 reserves acquired are roughly 73.9 MMboe.

Closing is anticipated in third-quarter 2023.

Woodside awards decommissioning contracts

Woodside Energy has awarded all major contracts involved in the decommissioning of subsea infrastructure at Enfield, Griffin, Stybarrow, and Echo/Yodel oil and gas fields on the North West Shelf offshore Western Australia.

Subject to regulatory approvals, Woodside expects to begin the decommissioning campaign in this year’s fourth quarter. It will follow decommissioning activities that began at Enfield and Balnaves field in first-quarter 2022.

The new campaign includes removal and disposal of the Nganhurra riser turret mooring (RTM) with associated umbilicals, flowlines, and other subsea equipment at Enfield as well as the Griffin RTM and the Stybarrow disconnectable turret mooring system.

Contractors engaged include TechnipFMC, Heerema, McDermott, Fugro, DOF, and McMahon. The contract to permanently plug wells at Stybarrow has been awarded to Transcocean.

Integrated engineering, preparation, removal, and transport of the Nganhurra RTM from Enfield was awarded to Heerema Marine Contractors in 2022.

The full decommissioning project will be the largest of its kind so far undertaken offshore Western Australia.

Exploration & Development Quick Takes

Woodside to develop Trion in Gulf of Mexico

Woodside Energy made a final investment decision to develop the Trion resource in Mexico, 19 miles south of the US-Mexico border and 112 miles from the Mexican coastline in 8,200 ft of water. First oil is targeted for 2028.

The project will target an estimated 479 MMboe of best estimate (2C) contingent resource of oil and gas. The subsurface has been extensively appraised with six well penetrations across the field.

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 with will connect to a floating storage and offloading vessel with a capacity of 950,000 bbl of oil (OGJ Online, Dec. 10, 2020).

The development is subject to joint venture approval and regulatory approval of the field development plan, expected in fourth-quarter 2023. Forecasted total capital expenditure is $7.2 billion.

Woodside is operator at Trion (60%) with partner PEMEX Exploración y Producción (40%).

Equinor shelves Bay du Nord development offshore Canada

Equinor ASA shelved its Bay du Nord deepwater oil project for 3 years “following changing market conditions and subsequent high cost-inflation.” The company said it will continue to assess exploration drilling around the field in 2024.

Bay du Nord consists of several oil discoveries in Flemish Pass basin, 500 km northeast of St. John’s, Newfoundland and Labrador, Canada. Bay du Nord itself lies in waters about 1,170 m deep, while the later discoveries in adjacent exploration license EL1156 (Cappahayden and Cambriol) are in 650-m water depths and are potential tie-ins to a joint project development.

Equinor earlier this year issued a letter of intent to KBR Industrial Canada Co. for front-end engineering and design of topside infrastructure for the floating, production, storage, and offloading vessel it plans to develop the project through. Its partner in the project is bp PLC (35%).

TotalEnergies lets contract for Uganda project

TotalEnergies EP Uganda has let a 5-year well intervention and integrity contract to Expro Group Holdings NV for the multi-well, onshore Tilenga oil development project.

The Tilenga project covers six fields, with over 400 wells planned across multiple pads. Drilling will start this year and continue for 5 years.

Work begins in this year’s second quarter, with Expro initially supporting drilling activity followed by production optimization, integrity and well workover support, the service provider said. Final investment decision on the project was made in February 2022.

Expro has designed four well intervention units to deliver a single operational solution for slickline and braided line in a cased hole environment across the life of the well. The solution is designed to reduce equipment footprint and equivalent CO2 emissions, while delivering improved efficiency, it said.

The service provider places the value of the contract over $30 million.

Drilling & Production Quick Takes

Trillion Energy spuds Alapli-2 gas well offshore Turkey

Trillion Energy International Inc. has spudded the Alapli-2 natural gas well at SASB gas field, offshore Turkey, the sixth well in its multi-well program. Alapli-2 was drilled by GSP Offshore SRL’s Uranus jack-up rig.

Alapli-2 is a long-reach directional well being drilled from the Akkaya tripod and will twin the Alapli-1 exploration well. Alapli-1 well was never put on production but was perforated and tested at a combined rate of over 7 MMcfd, indicating the gas pool is economic.

Trillion’s Bayhanli-2 gas well, which began producing June 2, 2023, averaged 8 MMcfd (100%) of natural gas production in its first 6 full days of operation.

Eight intervals of gas pay with a true thickness of about 21 m were perforated and tested at Bayhanli-2 and now are producing gas to the sales pipeline (OGJ Online, June 2, 2023).

BlueNord begins Halfdan Tor NE Danish North Sea infill drilling

BlueNord ASA has begun drilling operations on HBA-27B, successfully spudding the first well from jackup rig Shelf Drilling Winner. This is the first of two infill wells to be drilled during 2023 in the Cretaceous chalk Tor formation, Halfdan North East field, Danish North Sea.

Following the spudding, drilling activities will continue, with a total of seven infill wells planned. HBA-27B is scheduled to be on stream fourth-quarter 2023 at an expected initial peak production rate 3,000 boe/d net to BlueNord, 75% natural gas.

Shelf Drilling Winner is under contract through March 2025.

The Halfdan Tor NE development targets oil and gas northeast of Halfdan Main oil development and below Halfdan North East gas development. Tor NE development potential was confirmed by drilling HBB-10 in 2017. Its 1P-P90 reserves at end-2022 were 3 MMboe gross.

DUC is a joint venture with three partners: TotalEnergies SE (43.2%, operator), BlueNord (36.8%, except for Lulita where equity is 28.4%), and state Nordsøfonden (20%).

Vår Energi partners with Halliburton to reach production growth target

Vår Energi has formed a long-term partnership with Halliburton for drilling services related to the operator’s exploration and production drilling across the Norwegian Continental Shelf.

The contract has a duration of 5 years with options for an additional 4 years in total.

The partnership is expected to help Vår Energi reach its end-2025 target of a more than 50% increase in production from today’s level.

Vår Energi’s activities span the entire NCS with a portfolio of 158 licenses and 39 producing fields. Drilling activities are focused around four hubs in the Balder/Grane area, the North Sea, the Norwegian Sea, and the Barents Sea.

Equinor drills dry well on PL923 in North Sea west of Troll

Equinor Energy AS has completed drilling wildcat well 31/2-24 on production license (PL) 923, about 3 km west of Troll field in the North Sea and about 115 km northwest of Bergen. Acquired data indicated the well is dry.

The primary exploration target for the well was to prove petroleum in Upper and Middle Jurassic reservoir rocks in Sognefjord formation in the Viking group and Tarbert, Ness, and Etive formations in the Brent group. The secondary exploration target for the well was to prove petroleum in Middle Jurassic reservoir rocks in Fensfjord formation in the Viking group and Oseberg formation in the Brent group.

Well 31/2-24 encountered Sognefjord and Fensfjord formations in the Viking group, with a total thickness of 514 m, of which 197 m were sandstone reservoir of moderate to good quality. Tarbert, Ness, Etive, and Oseberg formations were encountered in the Brent group. Tarbert, Ness, and Etive have a thickness of about 106 m, of which 41 m were sandstone reservoir with poor to good quality. Oseberg formation is about 31 m thick, of which 25 m were sandstone reservoir of moderate to good quality.

This was the sixth exploration well in PL 923 and was drilled to a vertical depth of 2,558 m subsea and terminated in Drake formation in Lower Jurassic.

Water depth was 330 m. The well has been permanently plugged.

Well 31/2-24 was drilled by Odfjell Drilling Ltd.’s Deepsea Stavanger jack-up, which will now drill wildcat well 30/11-15 for Equinor in PL 035.


TotalEnergies, VNG partner on green hydrogen to decarbonize Leuna refinery

TotalEnergies and VNG, a German natural gas distribution company, signed an agreement to initiate the future supply of green hydrogen to the 227,000-b/d Leuna refinery in central Germany operated by TotalEnergies.

Under the agreement, green hydrogen will be produced from renewable electricity with a 30 Mw electrolyzer in Bad Lauchstädt, built and operated by VNG with its partner Uniper. VNG and partners have made a positive final investment decision on the Bad Lauchstädt Energy Park, the company said in a release June 21.

The energy park is designed as a production-scale laboratory to produce green hydrogen and its storage, transport, marketing, and use. It will use renewable electricity from a nearby windfarm to produce green hydrogen. Temporarily stored in a salt cavern specially created for this purpose, the green hydrogen can be fed into the hydrogen network of the chemical industry in central Germany via a converted gas pipeline.

With the agreement between TotalEnergies and VNG, TotalEnergies becomes the first anchor customer for green hydrogen from the project. The agreement contributes to the decarbonization of the Leuna refinery and will reduce the site’s annual CO2 emissions by up to 80,000 tons by 2030, TotalEnergies said in a separate June 21 release.

Work on the electrolyser—which will take about 2 years, VNG said—and on a gas transport pipeline that is to be converted—including construction of a new airlock for introducing pigs to the network—will begin shortly, VNG continued. In 2024, the Leuna refinery will be hooked up by pipeline to the future ONTRAS hydrogen network, giving the refinery access to the European hydrogen infrastructure and the international markets for green hydrogen.

Trial operation will start in early 2025, and from third-quarter 2025 the pipeline is scheduled to transport green hydrogen from the Bad Lauchstädt Energy Park for use in the refinery.

TotalEnergies plans to decarbonize all hydrogen used in its European refineries by 2030. The goal is to replace gray hydrogen with low-carbon hydrogen, representing a reduction of 3 million tons/year of CO2 by 2030, said Jean-Marc Durand, senior vice-president, TotalEnergies Refining Base Chemicals Europe.

Elsewhere in Europe, in November 2022, TotalEnergies and Air Liquide signed a partnership agreement to build a circular system at the Grandpuits biorefinery to produce and harness renewable hydrogen. At La Mède, the Masshylia project to produce hydrogen in partnership with Engie is moving forward.

Angola inks preliminary deal for Lobito construction

Angola’s state-owned Sonangol EP signed an MOU with China National Chemical Engineering Co. Ltd. (CNCEC) that could potentially advance its previously delayed

plan to build a new 200,000-b/d refinery in Lobito, Benguela Province.

The MOU may lead to signing of an official contract with CNCEC for construction, Angola’s Ministry of Mineral Resources, Oil and Gas (MIREMPET) said in a release.

Sonangol’s entrance into the MOU falls within the scope of its responsibility to implement and seek financing for the proposed Lobito refinery project, over which the state-owned company resumed sole control in 2022 following delays to a July 2021-launched tender seeking a financial partner, according to MIREMPET and Sonangol’s 2022 annual consolidated statements made available in June 2023.

The refinery project was restarted for development in 2017 following election of President João Lourenço after its 2016 suspension under the previous administration.

In its 2022 consolidated statements, Sonangol said it completed an update to an earlier-executed front-end engineering design (FEED) study for the refinery, which will be built on 3,800 hectares about 8 km northwest of Lobito. Ongoing FEED update works include:

  • Preparation of technical deliverables and definition of the proposed refinery’s 3D model.
  • Preparation of the project’s early-FEED book.
  • Preparation of an official preliminary project cost estimate.
  • Preparation of the invitation-to-bid package for a main EPC contractor.
  • Analysis, approval of unidentified technical documents prepared by KBR Inc.
  • Completion, issuance of a final FEED update package.

During 2022, Sonangol also confirmed it began unidentified structural works at the proposed refinery’s site, as well as signed contracts with OECI SA (formerly Odebrecht Engenharia e Construção Internacional SA) and Dar Al-Handasah Consultants Shair and Partners Holdings Ltd. for preliminary engineering, procurement, and construction (EPC) works.

Sonangol said in its 2022 consolidated report that it remains open to evaluating possible participation in the project by third-party investors. MIREMPET indicated in a June 2022 release that the operator would continue development of the refinery with or without a partner. 


Enbridge sells idle North Dakota crude line to MHA Nation

Enbridge Inc. has sold the idle 15,000-b/d Plaza-Wabek crude pipeline in North Dakota to the Mandan, Hidatsa, and Arikara (MHA) Nation, which plans within 1 year to begin shipping oil on it to an interconnection with Enbridge’s pipeline network. The pipeline will be operated by Thunder Butte Petroleum Services Inc., a wholly owned subsidiary of MHA Nation.

Plaza-Wabek runs 6-in. OD pipe 31 miles from Plaza-Wabek field’s gathering system to Enbridge’s Stanley, ND, terminal.

North Dakota’s Department of Mineral Resources lists more than 2,600 active wells on MHA Nation land, producing an average of more than 144,000 b/d.

MHA Nation paid $5 million for the pipeline.  

QatarEnergy, CNPC reach North Field supply, partnership agreements

QatarEnergy has agreed to supply China National Petroleum Corp. (CNPC) 4 million tonnes/year (tpy) of LNG from its North Field East (NFE) expansion project for a 27-year term. The two companies also signed a share sale and purchase agreement under which QatarEnergy will transfer to CNPC a 5% interest in the equivalent of one 8-million tpy NFE train (1.25% of the overall project).

QatarEnergy earlier this year made China Petrochemical Corp. (Sinopec) a project partner under similar terms (OGJ Online, Apr. 12, 2023). The two companies reached a 4-million tpy, 27-year supply agreement in 2022.

NFE will increase Qatar’s annual LNG export volume to 110 million tpy from 77 million tpy by 2025. A second phase, North Field South, will further increase capacity to 126 million tpy by 2027. 

The two stages combined will add six liquefaction trains.

Tamboran secures Darwin development precinct for proposed LNG project

Tamboran Resources Ltd., Sydney, secured an exclusive right over a 170-hectare (420 acres) site at the Middle Arm Development Precinct in Darwin Harbour, Northern territory, for a proposed LNG development.

The project, Northern Territory LNG (NTLNG), is expected to be supported by low CO2 gas from the onshore Beetaloo basin.

The acreage has been allocated by the Northern Territory Government on a ‘do not deal’ basis for 12 months which enables the company to progress a concept select phase for a proposed LNG development, the company said.

The plan is to use the site to host an LNG development with an initial capacity of 6.6 million tonnes/year (tpy) of LNG with expansion potential. The project is subject to completion of the concept study as well as successful Beetaloo appraisal drilling and flow testing in the company’s operated permits, as well as government approvals.

Tamboran holds interests in permits EPs 161, 136, 98, 117, and 76 with potential resources held in Velkerri A, B, and C shale reservoirs.

Tamboran says NTLNG represents the first fully integrated onshore LNG development in Australia’s north where upstream, midstream, and downstream production and processing will be based in the Northern Territory.

Tamboran is targeting first LNG production by 2030, with a near-term commitment to ensure supply to the Northern Territory and east coast markets.

Currently, front-end engineering and development (FEED) studies are continuing for the company’s proposed 100 MMcfd domestic pilot plant development in its Beetaloo permits with volumes contracted to Origin Energy for 10 years.

Middle Arm Sustainable Development Precinct is sited on a peninsula south of Darwin that already hosts Ichthys LNG and Darwin LNG production plants.

Novatek signs cooperation agreement for small-scale LNG in Tula region

PAO Novatek plans to build a small-scale LNG plant in Russia’s Tula region.

A cooperation agreement signed by Leonid Mikhelson, chairman of the management board of Novatek, and Alexei Dyumin, governor of the Tula Region, at the St. Petersburg International Economic Forums in mid-June, provides for construction of a 126,000 tonnes/year LNG plant on the territory of the special economic zone Uzlovaya.

The LNG plant, the largest in the Central Federal District of the Russian Federation, will supply LNG as motor fuel through an LNG fueling network and as an off-grid energy solution, Novatek said in a release June 15.