OGJ Newsletter
GENERAL INTEREST Quick Takes
TC Energy, Nikola to build North American hydrogen production network
TC Energy Corp. and Nikola Corp. have agreed to codevelop, build, operate, and own large-scale hydrogen production hubs in the US and Canada. Nikola’s energy business unit and TC Energy are collaborating to identify and develop projects to establish infrastructure required to deliver low-cost and low-carbon hydrogen at scale in line with each company’s core objectives. Nikola and TC Energy also seek to accelerate adoption of heavy-duty zero-emission fuel cell electric vehicles (FCEVs) and hydrogen across industrial sectors by establishing the hubs in key geographic locations.
The hubs would produce 150 tonnes/day or more of hydrogen near highly traveled truck corridors to serve Nikola’s planned need for hydrogen to fuel its Class 8 FCEVs within the next 5 years. TC Energy’s pipeline, storage, and power assets could potentially be leveraged to lower the cost and increase the speed of delivery of these hydrogen production hubs. This may include the integration of midstream assets to enable hydrogen distribution and storage via pipeline and to deliver CO2 to permanent sequestration sites to decarbonize the hydrogen production process.
INEOS Group, Repsol SA, Chevron Corp., and bp PLC are among the other major oil and gas companies to launch initiatives this month and last focused on producing hydrogen.
Senex considering takeover bid from POSCO
Senex Energy Ltd., Brisbane, is in discussions with South Korean conglomerate POSCO International Corp. regarding a revised POSCO takeover offer.
POSCO first made an approach to Senex in July with a non-binding and indicative proposal to acquire 100% of Senex for $4 (Aus.) per Senex share. A second offer came in August at $4.20/share and a third was made Sept. 2 for $4.40/share.
Upon receipt of the third offer, Senex granted POSCO an exclusivity period to complete due diligence enquiries. Following further discussions, Senex has extended POSCO’s exclusivity period to Nov. 5 to provide time for POSCO to assess a further revised proposal at a price higher than $4.40/share.
Currently, the $4.40 offer represents a 40% premium to the 30-day volume-weighted average price (VWAP) on Sept. 2 (the date prior to receipt of the revised offer). It also represents a 19% premium to the 30-day VWAP on Oct. 15, which is the last trading day prior to the extension of time announcement.
POSCO said that if a transaction proceeds it is likely to be implemented via an off-market takeover offer which would be subject to a 50.1% minimum acceptance condition as well as Australian Foreign Investment Review Board approval.
Senex believes the best interests of its shareholders will be served by continuing to engage with POSCO and assessing any forthcoming proposal on its merits. The board added that there is no certainty that ongoing discussions will result in any binding agreement.
Senex holds significant coal seam gas acreage in the Surat and Bowen basins of southeast Queensland, including the Roma North and Project Atlas developments. It has an annual production of 3 MMboe with proven and probable gas reserves of about 770 petajoules.
POSCO specializes in oil and gas exploration and production, LNG, agri-resources, and steel production with subsidiaries in 45 countries, including an office in Sydney. It has a market capitalization of more than US$2 billion.
Vitol-led consortium acquires stake in Vostok Oil from Rosneft
A consortium of commodity traders Vitol SA and Mercantile & Maritime Energy Pte. Ltd. (75% Vitol, 25% MME) closed a deal to acquire a 5% stake in Vostok Oil LLC from Rosneft.
The Vostok Oil project comprises 52 license areas with 13 oil and gas fields, including Vankor, Suzun, Tagul, and Lodochnoe, Payakhskoe, and Zapadno-Irkinskoe.
Vostok Oil production—comprised largely of low sulphur crude—currently stands at 19 million tonnes/year, Vitol said in a release Oct. 14. Rosneft plans to increase production to over 100 million tpy by 2030. Reserves are estimated to be up to 6 billion tonnes.
Rosneft signed contracts in June 2021 to construct first-priority facilities, set up the power supply system, ensure aviation support, provide services, supply equipment, materials, special-purpose vehicles, tubular products for the project. The company also launched the construction of the North Bay Port Oil Terminal.
Earlier, at end 2020, Rosneft sold a 10% stake in the project to trading company Trafigura (OGJ Online, Nov. 18, 2020).
Harbour Energy wins UK North Sea CO2 storage license
UK Oil and Gas Authority (OGA) has awarded a carbon dioxide (CO2) appraisal and storage license in the Southern North Sea to Harbour Energy. Harbour’s V Net Zero proposal would reuse depleted Rotliegend gas fields, Viking and Victor, 140 km off the Lincolnshire coast to store the CO2 9,000 ft below seabed. The project would also potentially use the Bunter Formation aquifer which could increase its future storage capacity.
Harbour plans initial injection rates of 3.6 million tonnes/year (mtpy), rising to 11 mtpy by 2030. The government’s 2030 carbon capture, usage, and storage (CCUS) target is 10 mtpy, part of its efforts to reach net-zero greenhouse gas emissions by 2050.
V Net Zero would transport CO2 along a newbuild pipeline from Immingham to Theddlethorpe, and then reuse existing 120-km Lincolnshire Offshore Gas Gathering System pipelines to move it to the offshore fields. First injection is targeted for fourth-quarter 2026.
The license requires Harbour to show progress by hitting milestones along the way, including reprocessing legacy 3D seismic data. It does not convey permission for development activities including drilling and injection testing. These require further consents from the OGA.
Exploration & Development Quick Takes
Vår Energi considers new discovery tie in to Goliat field
Vår Energi AS confirmed a Barents Sea oil and gas discovery in production license (PL) 901. Preliminary estimates place the size of the discovery at 1.4-1.9 million standard cu m recoverable oil equivalent. The licensees will assess the discovery together with other nearby prospects with a view toward a potential development tied into existing infrastructure on Goliat field.
Wildcat well 7122/6-3 S, the first exploration well in the license, was drilled by the Scarabeo 8 drilling rig about 10 km south of the 7122/6-1 (Tornerose) discovery about 100 km northwest of Hammerfest. Water depth at the site is 427 m.
The objective was to prove oil and gas in the Realgrunnen Subgroup in reservoir rocks from the Late Triassic to Middle Jurassic age.
The well was drilled to a vertical depth of 1,970 m below sea level and was terminated in the Fruholmen formation from the Late Triassic. It encountered a 28-m oil and gas column in the Stø formation from the Early to Middle Jurassic, of which 22 m were sandstone layers of moderate to good reservoir quality.
Sandstone layers totaling 36 m with moderate to good reservoir quality were also encountered in the Nordmela, Tubåen, and Fruholmen formations from the Early Jurassic to Late Triassic, but these are water-filled. Gas-oil contact and oil-water contact were encountered at 1,865 m and 1,876 m below sea level, respectively.
The well was not formation-tested, but extensive data acquisition and sampling have been performed. The well has been permanently plugged.
Vår Energi is operator at PL 901 (50%) with partners Equinor Energy AS (10%), Longboat Energy Norge AS (20%), and Concedo AS (20%).
Santos, Bengal JV to plug Legbar-1 exploration well
Following a review of well logs, Santos QNT Pty Ltd. will plug the completed Legbar-1 well in ATP 934 in the Cooper Basin, Queensland, Australia, and refine exploration targets going forward, partner Bengal Energy Ltd. said in a release Oct. 14.
The well, which lies in a 420-square-km area in the southern portion of the block, intersected good quality reservoir sands within the primary Permian Toolachee formation, but the sands contained insufficient levels of hydrocarbon pay for commercialization.
The joint venture remains focused on evaluating the Permian natural gas prospective potential of the Santos-operated farm-in block, based on the learnings from the well (OGJ Online, July 29, 2020).
Santos paid 100% of the costs to drill, plug, and abandon the well and has earned a 60% working interest in the Santos farm-in block as operator. Bengal holds a 40% working interest in the Santos farm-in block and holds 100% interest in the balance of ATP 934 and the surrounding petroleum leases PL 188, 411, 1109, and 1110.
While Legbar-1 did not indicate commercial quantities of hydrocarbons, thick, high quality reservoir sands were encountered in the primary Permian Toolachee formation with evidence of residual hydrocarbon saturation. Good fluorescence shows and elevated gas readings through the Jurassic lower Birkhead formation-Top Hutton sandstone indicate oil has passed through the reservoir, supporting the search for a valid closure to test the play, Bengal said.
Eni, partners start up Cabaça North development offshore Angola
Eni started production from the Cabaça North development project in Block 15/06 offshore Angola via the Armada Olombendo FPSO.
The development, with an expected peak production rate of 15,000 b/d of oil, will increase and sustain the plateau of the Armada Olombendo, a zero-discharge, zero-process flaring FPSO with an overall capacity of 100,000 b/d, the operator said in a release Sept. 24.
This is the second start-up by Eni Angola this year following Cuica Early Production achieved in July. A third start-up is expected within the next few months, with the Ndungu Early Production in the western area of Block 15/06.
Eni Angola operates Block 15/06 with 36.84% interest. Partners are Sonangol Pesquisa e Produção (36.84%) and SSI Fifteen Ltd. (26.32%).
BW Energy to drill offshore Gabon exploration wells
BW Energy Ltd. will drill exploration wells on Blocks G12-13 and H12-13 in offshore Southern Gabon and carry out a 3D seismic acquisition campaign on both blocks. The blocks are adjacent to BW Energy’s Dussafu license and cover an area of 2,989 sq km and 1,929 sq km, respectively.
BW Energy has been provisionally awarded operatorship of the blocks by the Direction Generale des Hydrocarbures (DGH) in the 12th offshore licensing round in Gabon. The award is subject to finalizing the production sharing contracts (PSC) with the DGH. The PSCs will have an exploration period totaling 8 years which may be extended by a further 2 years.
The blocks will be held by a consortium of BW Energy (operator, 37.5%), VAALCO Energy Inc. (37.5%), and Panoro Energy Ltd. (25%).
Drilling & Production Quick Takes
Empire Energy ramping up Beetaloo program
Empire Energy Ltd., Sydney, plans to ramp up its exploration program in its 100%-owned EP187 in the Beetaloo basin onshore Northern Territory following government approval for a broad appraisal program including drilling of the first horizontal well.
Carpentaria-2H will be drilled 11 km north of the Carpentaria-1 gas discovery. It is expected to spud before end October.
The vertical section will target the same Velkerri formation shales (A, B, Intra A/B, and C) as the first well, but is expected to be 200 m deeper. A horizontal well will then kick off into one of the target zones.
The Charlotte 2D infill seismic survey—to better define the Velkerri shale reservoir resources across the permit—will begin the first week of November. It is expected to provide a more detailed picture of the size of the resource as well as delineate future drilling locations. The survey will take 2 weeks.
The government approvals allow for the drilling of up to seven horizontal wells in the permit.
In the meantime, Empire’s re-started production testing of the fracture stimulated Carpentaria-1 has resulted in an increase in the average flow rate of 45% to 0.364 MMcfd of gas compared to the average reported flow rate reached during the first extended production test earlier in the year.
Empire’s engineers believe the increase in production rates may be due to diffusion of water into the Middle Velkerri shales during the shutdown period, providing enhanced pathways for gas production through induced fractures.
Sampling of gas and flow-back fluid at the surface has also continued and the returned hydrocarbons will be evaluated to determine the best shale to target with the horizontal section of Carpentaria-2H.
Norway production decreased in September, NPD says
Norway’s liquids production averaged 2.022 million b/d in September, the Norwegian Petroleum Directorate reported Oct. 20.
Norway’s liquids production averaged 2.092 million b/d in August.
Oil production in September is 1.1% higher than the NPD’s forecast, and 0.8% higher than the forecast so far this year.
The average daily liquids production in September consists of 1.772 million b/o, 240,000 bbl of NGL, and 10,000 bbl of condensate.
The total petroleum production for the first 9 months in 2021 is about 170.5 million standard cu m oil equivalents.
Chevron signs offshore Suriname PSC with Staatsolie
Chevron Corp. received rights for exploration, development, and production for Block 5, offshore Suriname, through a recently signed 30-year Production Sharing Contract (PSC) with state oil company Staatsolie.
Costs in the exploration phase will be carried by Chevron. The exploration period, as set out in Chevron’s PSC, will last 6 years, divided into three 2-year phases. A signing bonus of $30,875,000 will be paid by Chevron to Staatsolie after signing the PSC and a joint operating agreement (JOA). This is the first time Staatsolie will participate as a partner in offshore activities.
Block 5 is 2,235 sq km and is west of the shallow offshore area 120 km from the coast with water depth of up to 100 m.
Staatsolie retains the right to 40% participation in the block and will co-finance the possible development and production phase.
XTO drills Permian well with world’s first fully automated land rig
XTO Energy Inc., a subsidiary of ExxonMobil Corp., drilled a horizontal well in the Permian basin using Nabors PACE-R801 fully automated land rig. The rig is contracted to drill three horizontal wells on a test pad in Midland County, Tex.
The rig is the world’s first fully automated land rig and combines automated drilling software from Nabors with Canrig robotics to create an unmanned rig floor that removes crews from red zone areas, Nabors said in a release Oct. 7. The first well was drilled to a total measured depth of 19,917 ft.
Crew size on the automated rig is like other Nabors rigs but the duties change, the service provider said. One driller is required to supervise the operations of the rig while others continue to perform essential tasks, such as service, maintenance, inspections, and rig moves.
PROCESSING Quick Takes
REG breaks ground on Geismar renewable fuels expansion, site upgrades
Renewable Energy Group Inc. (REG), Ames, Iowa, has started official construction on the previously announced 250-million gal/year capacity expansion of its existing 90-million gal/year renewable diesel refinery in Geismar, Ascension Parish, La. (OGJ Online, Oct. 6, 2020).
Recently combined with an original plant improvement project, the Geismar expansion project, which broke ground on Oct. 13, will involve upgrades to the existing site as well as construction of an existing site to accommodate Geismar’s aggregate finished renewable diesel production capacity increase to 340 million gal/year, the operator said.
Planned improvements will involve works to expand the site’s marine logistics to enable global trading of feedstocks and fuel, for which International-Matex Tank Terminals LLC (IMTT) will build out storage tanks and related logistics infrastructure at its nearby Geismar bulk-liquid storage and marine terminal to accommodate REG’s increased production (OGJ Online, Aug. 27, 2021).
The Geismar improvement and expansion project comes as part of REG’s strategy to strategically grow its renewable fuels production to meet rising consumer, investor, and regulatory demand for reduced-carbon fuel options, according to Cynthia (CJ) Warner, REG’s president and chief executive officer.
Previously estimated to require a minimum $825-million capital investment, REG in early August estimated overall cost of its revised Geismar project at about $950 million.
The Geismar improvement and expansion project remains on schedule to reach mechanical completion by 2023, with full commissioning of the expanded plant to follow in 2024.
Once online, fuel produced at REG’s expanded Geismar plant will reduce carbon dioxide emissions by up to 2.8 million tonnes/year, or the equivalent to greenhouse gas emissions from 7.1 billion miles driven by an average passenger vehicle, the company said.
SIBUR lets contract for carbon-reduction study for Tyumen chemical complex
PJSC SIBUR Holding has let a contract to NOVA ENERGIES—a joint venture of Technip Energies and JSC NIPIgaspererabotka (NIPIGAS)—to provide preliminary front-end engineering and design (pre-FEED) for implementation of proposed carbon capture and reuse solutions to reduce emissions at SIBUR subsidiary LLC ZapSibNeftekhim’s more than 2-million tonnes/year (tpy) petrochemical complex—Russia’s largest— in Western Siberia’s Tyumen region, about 10 km east of Tobolsk, Russia (OGJ Online, Aug. 4, 2021).
As part of the pre-FEED study contract, NOVA ENERGIES will use best available technological and technical solutions to develop the technology as well as a cost estimate for the process of capturing, transporting, and reusing carbon dioxide (CO2) generated by operations at ZapSibNeftekhim’s complex and the nearby Tobolsk thermoelectric power station, which is the sole supplier of steam to the complex and the key supplier of heat for residential and commercial sites in the region, Technip Energies and NIPIGAS said on Oct. 12.
The service providers disclosed neither a duration nor value of the contract.
ZapSibNeftekhim’s proposed carbon-reduction project at Tyumen follows SIBUR’s environmental, social, and governance (ESG) sustainability strategy to 2025, under which the operator announced its intention to increase its investment in research and development projects aimed at reducing greenhouse gas emissions (GHG), including development of carbon capture and storage (CCS) technology to help further reduce GHGs from its operations.
The planned carbon-reduction measures would come in addition to the operator’s existing mitigation measures, which currently include recycling of CO2 emissions from burning of oil byproducts such as associated petroleum gas (APG), according to SIBUR’s October 2021 presentation to investors.
In addition to its 1.14-million tpy polypropylene production, ZapSibNeftekhim’s Tobolsk petrochemical complex produces 1.77 million tpy of polyethylene, 829,000 tpy, as well as a mix of byproducts including butadiene, butene-1, methyl tertiary butyl ether, and pyrobenzene, SIBUR said in its 2020 annual report.
TRANSPORTATION Quick Takes
Nord Stream 2 completes first-string gas fill
Nord Stream 2 AG’s natural gas pipeline has completed gas-in of its first 27.5-billion cu m/year string. In line with system-design requirements, the string is filled with 177 million cu m of so-called technical gas, reaching a pressure of 103 bar.
This pressure is sufficient to start gas transportation. But certification from a German regulator is still pending and could take several months.
Pre-commissioning of the second string is ongoing.
Nord Stream 2 began gas fill earlier this month (OGJ Online, Oct. 6, 2021). The pipeline runs more than 1,200 km along the Baltic seabed from Ust-Luga, Russia, to Greifswald, Germany.
Piñon places Delaware basin sour-gas treatment, sequestration into service
Piñon Midstream LLC has placed its 85-MMcfd Delaware basin greenfield sour-gas treating and carbon capture site (Dark Horse) and associated pipelines, compressor stations, and acid gas sequestration infrastructure into service, with the initial capacity fully subscribed. Dark Horse is in Lea County, NM, and captures and sequesters both carbon dioxide (CO2) and hydrogen sulfide (H2S).
Dark Horse infrastructure includes a centralized amine treating plant (Plant 1), an 18,000-ft deep acid gas sequestration well (Independence AGI #1), 40,000 hp of field and plant compression, and 30 miles of high-pressure gathering and redelivery pipelines. The site is expandable to treat as much as 400 MMcfd of sour gas.
Piñon expects to complete work on its second amine treating plant (Plant 2) this month. The plant will increase Dark Horse’s treating capacity to 170 MMcfd.
Independence AGI #1 is New Mexico’s deepest and largest acid gas injection well, according to Piñon, with the capacity to permanently sequester up to 175,000 tons/year of CO2 and 75,000 tons/year of H2S. Sequestration capacity will double when Independence AGI #2 well is completed and placed into service in 2022.