GENERAL INTEREST Quick Takes
Bids sought for sales of crude oil to Strategic Petroleum Reserve
The US Department of Energy (DOE) is seeking offers to sell crude oil to replenish the Strategic Petroleum Reserve (SPR) for its Big Hill site in southeastern Texas.
The Office of Petroleum Reserve will post monthly solicitations to purchase the oil through at least May 2024, beginning with a solicitation for up to 6 million bbl of oil for delivery in December 2023 and January 2024.
DOE will purchase oil in those months for $79/bbl or below, less than the average $95/bbl DOE received for 2022 emergency SPR sales, it said.
Bids for the first solicitation for the purchase of up to 3 million bbl of crude oil, for December receipt, were due Oct. 24, 2023. Bids for the second solicitation for the purchase of up to 3 million bbl of crude oil, for January receipt, are due no later than 10:00 a.m. Central Time on Nov. 1, 2023.
DOE said it has already purchased 4.8 million bbl for SPR replenishment for an average less than $73/bbl.
The administration’s three-part SPR replenishment strategy includes direct purchases with revenues from emergency sales; exchange returns that include a premium to volume delivered; and securing legislative solutions that avoid unnecessary sales unrelated to supply disruptions. DOE said it has already secured cancellation of 140 million bbl in congressionally mandated sales scheduled for fiscal years 2024-27, marking progress toward replenishment.
Gasunie, partners make FID on first CO2 storage project in the Netherlands
Gasunie, through a joint venture with Energie Beheer Nederland (EBN) and the Port of Rotterdam Authority, made positive final investment decision (FID) to develop the first major CO2 transport and storage system in the Netherlands (the Porthos project).
Final contracts will be awarded, and construction of the €1.3 billion project is expected to begin in 2024. The Porthos system is expected to be operational in 2026.
Porthos will store about 2.5 million tonnes/year of CO2 for 15 years from Rotterdam-based companies Air Liquide, Air Products, ExxonMobil, and Royal Dutch Shell, equal to about 10% of Rotterdam industry’s emissions.
The companies will invest in their own capture installations to supply CO2 to a collective pipeline that runs through the Rotterdam port area. A compressor station will pressurize the CO2.
The CO2 will be transported through an offshore pipeline to the P18A platform in the North Sea, about 20 km off the coast. From there, the CO2 will be pumped into depleted gas fields P18-2, P18-4, and P18-6 in a sealed reservoir of porous sandstone at a depth of 3-4 km under the seabed.
Porthos has partnerships with TAQA Energy, the present operator of the P18A platform and P18 gas fields, and contractors and suppliers Denys NV, Allseas, LMR Drilling GmbH, Mannesmann Grossrohr GmbH, Corinth Pipeworks, Equans, Ensco Offshore, Van der Ven, and Bonatti.
The European Union, through the Connecting Europe Facility (CEF) for Energy, declared Porthos a project of common interest and awarded €102 million in subsidy.
Operator plans CCS expansion in Texas Permian
San Antonio-based Ozona CCS LLC entered a deal to expand its carbon capture sequestration (CCS) capabilities for oil and gas operators in the Permian basin of West Texas.
Ozona signed a definitive agreement with a private landowner in Loving County, Tex., to lease about 5,723 contiguous acres of pore space for the purpose of drilling multiple commercial CO2 sequestration wells to increase its Permian lease position to more than 10,000 contiguous acres with estimated pore space capacity of 120 million tonnes.
Ozona will begin the federal and state permitting process to drill and operate multiple CO2 disposal wells across its acreage position, with each to have an initial injection rate of 25,000 b/d.
Rich Adams, Ozona’s co-chief executive and chief operating officer, said initial anchor customers will include existing Permian natural gas processing plants, regional oil and gas operators, as well as industrial and power generation under development in the area.
Pending EPA permitting approvals, Ozona plans a target in-service date for its Class VI wells during first-quarter 2026.
This land-lease agreement follows Ozona’s previous deal signed earlier this year with Texas Pacific Land Corp. (TPL) to lease about 5,173 contiguous acres of land in the Permian for drilling one of the first commercial CO2 sequestration wells in the region.
The proposed CO2 disposal well on TPL land—scheduled to be in-service during third-quarter 2024—is to have an estimated initial injection rate of up to 25,000 b/d and an estimated total storage capacity of at least 40,000,000 metric tons of CO2.
Exploration & Development Quick Takes
Pan American Energy gains contract approval for Vaca Muerta blocks
Pan American Energy SL Sucursal Argentina and state-owned Gas y Petróleo del Neuquén Sociedad Anónima (GyP) gained approval from Argentina’s Neuquén provincial government for an exploration, development, and production contract.
The contract, for Aguada de Castro Oeste Blocks I and II to be operated by Pan American Energy, was approved Oct. 12.
Preliminary work scope for the initial 4-year exploration period includes drilling an exploration well in Block I and a second in Block II, to be drilled horizontally for about 3,000 m at a vertical depth of 2,800 m and including completion of 45 fracturing stages.
Aguada de Castro Oeste Blocks I and II lie in central Neuquén Province, central Neuquén basin, in the dry gas window of the Vaca Muerta formation.
Currently, Pan American Energy operates six areas in Argentina, two in partnership with GyP. The company is a non-operating partner in two additional areas.
With the new contract, along with neighboring concessions of Aguada de Castro (ACAS) and Aguada Pichana Oeste (APO), Pan American forms a dry gas hub.
Eni awarded exploration block offshore Egypt
Eni SPA has been awarded a new exploration block offshore Egypt as part of the 2022 EGAS International Bid Round, partner QatarEnergy said Oct. 4.
Egypt’s Ministry of Petroleum and Mineral Resources awarded exploration and production rights for Block EGY-MED-E8 (East Port Said) to the consortium comprised of Eni (operator, 34%) QatarEnergy (33%), and bp (33%).
The 2,600-sq km block, offshore Egypt’s northeastern Mediterranean coast, lies in water depths up to 800 m.
Shell verifies gas in deepwater Colombian Caribbean
Shell plc verified natural gas in the Glaucus-1 well in deepwater southern Colombian Caribbean, project partner Ecopetrol SA said in a release Oct 19.
The well, the fifth in the area, was drilled 75 km off the coast in Block COL-5 by the Noble drillship Noble Voyager in about 2,340 m of water.
Earlier discoveries were made with the Kronos-1, Gorgon-1, Purple Angel-1, and Gorgon-2 prospects (OGJ Online, Aug. 11, 2022).
Block COL-5 partners are set to spud the Orca Norte-1 exploration in Tayrona block next month using the Noble semi-submersible rig Noble Discoverer.
Shell is operator of the South Caribbean blocks (Col-5, Fuerte Sur, Purple Angel) in a 50-50 partnership with Ecopetrol.
Drilling & Production Quick Takes
Petrobras breaks operated production records
Petróleo Brasileiro SA (Petrobras) produced 3.98 MMboe/d in third-quarter 2023, a quarterly record for operated oil and gas production that came in 7.8% above second-quarter 2023 production, the company said in a release Oct. 16.
The company also achieved a monthly record for operated production in September, with 4.1 MMboe/d, 6.8% higher than in August.
The increase is mainly due to the ramp-up of the Almirante Barroso FPSO, which operates in Búzios field, and the P-71 FPSO, in Itapu field—both in the presalt Santos basin offshore Brazil—and the Anna Nery and Anita Garibaldi FPSOs in Marlim and Voador fields in Campos basin offshore Brazil, Petrobras said.
Another factor was the lower number of platform maintenance stoppages in the period, it continued.
The monthly operated production record was also accompanied by the monthly record for presalt operated production in September, when Petrobras reached 3.43 MMboe/d in the layer.
Petrobras will provide a revised oil and gas production guidance to the market on Nov. 9, 2023, together with its third-quarter results.
EOG plans Beehive prospect drilling offshore Australia
EOG Resources Australia Block WA-488 Pty Ltd. will drill the Beehive-1 exploration well in permit WA-488-P in Commonwealth waters of the Joseph Bonaparte Gulf off the northern Western Australian (WA) coastline according to a release from The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA), Australia’s offshore energy regulator.
The well will be drilled 80 km off the WA coastline and 300 km southwest of Darwin in the Northern Territory in 40 m of water. The well will be vertical and will target the Sunbird and Tanmurra formations, with a planned total depth of 5,090 m.
Well evaluation involving DST (and associated flaring) is planned if the well successfully finds hydrocarbon pay in the target formation(s) which warrants such testing. At the completion of drilling, Beehive-1 will be plugged with no equipment remaining on the seabed.
Drilling is scheduled to start no earlier than Jan. 1, 2024, and will be completed no later than Dec. 31, 2025. Exact timing is dependent on receipt of environmental approvals and availability of a mobile offshore drilling unit [MODU] and is expected to take 55-100 days.
EOG holds a 100% interest in the WA-488-P block.
Equinor places Breidablikk field on stream
Equinor Energy AS started production from Breidablikk field in the North Sea on Oct. 20.
Tied back to the Grane platform, the subsea field holds almost 200 million bbl of recoverable oil, partner Vår Energi said in a release.
The field is expected to produce at plateau level in 2024 to 2026. Plateau production is estimated at 55,000-60,000 boe/d gross.
Discovered in 1992, Breidablikk lies in the central part of the North Sea, 10 km northeast of Grane, in 130 m water depth.
The project has taken just over 3 years to complete, following the plan for development and operation (PDO) submission in September 2020. The original plan was to begin production from five wells in first-quarter 2024. The project is on stream ahead of schedule and the number of wells drilled has increased to eight. The remaining wells will be drilled and completed by end-2025.
Breidablikk is being developed with 22 subsea wells drilled from four templates. Pipelines and cables have been installed between the subsea infrastructure and the Grane platform, which has been modified to receive the well stream.
Oil from Breidablikk is processed on Grane and sent ashore by pipeline to the Sture terminal in Øygarden.
Equinor is operator of the field with 39% interest. Partners are Vår Energi ASA (34.4%), Petoro (22.2%), and ConocoPhillips Skandinavia AS (4.4%).
Norway production down in September, NPD says
Norway’s production averaged 1.797 million bbl in September, the Norwegian Petroleum Directorate (NPD) reported. The figure is down from the 2.006 million bbl produced in August.
Average daily liquids production in September consists of 1.644 million b/o, 138,000 bbl of NGL, and 15,000 bbl of condensate.
Oil production in September is 4.7% less than the NPD’s forecast and 0.7% lower than the forecast so far this year.
PROCESSING Quick Takes
Repsol’s Petronor refinery producing renewable hydrogen
Repsol SA has started producing renewable hydrogen at subsidiary Petróleos del Norte SA’s (Petronor) 220,000-b/d refinery and industrial complex at Múskiz, near Bilbao, Biscay Province, in Spain’s northern autonomous Basque Country.
Entered into operation in early October, the 2.5-Mw electrolyzer—Repsol’s first—is equipped to generate 350 tonnes/year (tpy) of renewable hydrogen, most of which will be used by Petronor’s refinery as a raw material for production of products with a reduced-carbon footprint, Repsol said.
Renewable hydrogen produced by the electrolyzer also will be transported via pipeline to be used for powering buses and heavy transport in the logistics platform at Abanto Zierbana Technology Park, 1.5 km from Muskiz, where Repsol and the Basque Energy Agency have sited the region’s first hydrogen refueling station, the operator said.
Part of the first-phase development of Basque Hydrogen Corridor (BH2C), a joint initiative launched by Petronor and Repsol to decarbonize the region’s energy, industrial, residential, and transportation sectors, the Bilbao refinery’s electrolyzer produces renewable hydrogen using renewable electricity to separate water molecules into hydrogen and oxygen based on a process and sources entirely free of CO2 emissions.
Petronor will also host two additional hydrogen plants that will include electrolyzers with capacities of 10 Mw and 100 Mw, respectively, the latter of which has been recognized by the European Commission (EC) as an Important Project of Common European Interest (IPCEI), Repsol said.
The operator said it also plans to install electrolyzers nearby its remaining four refining and petrochemical industrial centers in Spain, including:
- A 100-Mw unit at its 220,000-b/d Cartagena refinery in the Spain’s southeastern province of Murcia, also qualified as an IPCEI.
- A 150-Mw unit near the 186,000-b/d Tarragona integrated refining and petrochemicals complex along northeastern Spain’s Costa Daurada along the Mediterranean Sea, which has been selected by the EC as an innovative project to receive funds under the Innovation Fund program.
- A 30-Mw unit near the 150,000-b/d Puertollano refinery in Spain’s province of Ciudad Real, Castile-La Mancha.
- A 30-Mw unit near the 120,000-b/d A Coruña refinery in northern Spain.
Repsol’s industrial sites in Spain currently produce a total of about 360,000 tpy of hydrogen, representing nearly 60% of the country’s overall demand, the operator said.
Montana Renewables advances turnaround at Great Falls biorefinery
Calumet Specialty Products Partners LP subsidiary Montana Renewables LLC (MRL) is bringing forward planned maintenance following a decision to replace equipment at the operator’s renewable fuels manufacturing plant in Great Falls, Mont.
Following discovery and inspection of a leak in the steam-recovery system of its renewable hydrogen plant during third-quarter 2023, MRL has decided to replace the steam drum in lieu of repairing it, Calumet said on Oct. 20.
With the steam-drum replacement anticipated for completion sometime in November, Calumet said MRL will use the ongoing downtime to pull forward its a regularly scheduled turnaround previously planned for early 2024 into November.
While MRL will continue to operate the Great Falls renewables plant at reduced throughput until the turnaround begins, the operator plans to process more than 12,000 b/d of predominantly untreated feed upon completion of work in December, according to Calumet.
As of late August, MRL estimated 8,000-8,500 b/d of renewable product sales for third-quarter 2023, as ongoing debottlenecking of the plant’s pretreating unit enabled the site to process 11,000 b/d of untreated renewable feedstock.
Petrobras sets presalt gas processing record
Petrobras achieved a record-high rate during September for its processing of natural gas volumes produced from the presalt Santos basin offshore Brazil.
The operator’s 20-million cu m/day Caraguatatuba (UTGCA) in Caraguatatuba, São Paulo, and 25.16-million cu m/day Cabiúnas (UTGCAB) in Macaé, Rio de Janeiro, in September processed a combined 28.96 million cu m/day of presalt gas, surpassing the previous monthly record of 27.27 million cu m/day hit in March 2022, Petrobras said.
The UTGCA plant processed an average 9.8 million cu m/day of presalt gas volumes during the month, which in turn contributed to record utilization of the pipeline connecting the presalt region to the Mexilhão platform, installed about 145 km offshore Caraguatatuba, according to the operator.
Noting the difficulty processing presalt gas poses for the company, William França—Petrobras’ director of industrial processes and products—said improved utilization of the UTGCA and UTGCAB plants during September decisively contributed to the operator’s overall higher oil and gas production and supply to the market.
Presalt gas currently accounts for 77% of total volumes processed by the onshore UTGCA and UTGCAB plants, which receive both presalt and post-salt volumes from offshore fields via flow lines, Petrobras said.
TRANSPORTATION Quick Takes
Equitrans delays MVP startup to Q1 2024, costs rise
Equitrans Midstream has delayed expected startup for its 303-mile Mountain Valley natural gas pipeline (MVP) to first-quarter 2024 from end-2023, citing unforeseen factors that slow construction pace and increase costs.
“The ramp up of MVP’s contractor workforce has been slower and more challenging than expected, due to multiple crews electing not to work on the project based on the history of court-related construction stops, and the inability to recruit crews with required and sufficient experience,” the company stated in a filing with the US Securities Exchange Commission. Equitrans also cited “challenging terrain and geology” in explaining the delay and costs increase.
Project costs have increased to $7.2 billion from $6.6 billion. Work began on the 2-bcfd pipeline in 2018 and is more than 94% complete, but the project has faced multiple legal delays related to its potential environmental impact since construction started.
The US Supreme Court earlier this year ordered that appellate court stays blocking work on the pipeline be vacated, following passage of the Fiscal Responsibility Act which approved all needed permits. And earlier this month, Equitrans reached agreement with the Pipeline and Hazardous Materials Safety Administration under which inline inspections and cathodic protection surveys would be accelerated.
Equitrans owns 47% of MVP in a joint venture with NextEra Capital Holdings Inc., Con Edison Transmission Inc., WGL Midstream MVP LLC, and RGC Midstream LLC. The pipeline will transport gas from West Virginia to Mid-Atlantic US markets.
Novatek to proceed with Murmansk LNG project
PAO Novatek will proceed with development of the 20-million tonnes/year (tpy) Murmansk LNG plant, Russia’s Interfax news agency said, citing Deputy Russian Prime Minister Alexander Novak’s interview with RT Arabic.
Russia is currently producing 33 million tonnes of LNG, the news agency reported, and Arctic LNG 2 is in final stages of construction. In late August, Novatek said it was preparing to hook up Train 1 of its 19.8-million tpy Arctic LNG 2 liquefaction plant on Russia’s Gydan Peninsula to complete commissioning activities and begin liquefaction operations.
The Murmansk LNG project in Murmansk Oblast, Russia, is envisaged as a three-train plant, each with capacity of 6.8 million tonnes, Interfax said, reporting that “surplus electricity generated by the Kola Nuclear Power Plant will power the LNG plant compressors and a 1,300 km pipeline will have to be built to supply gas to Murmansk.”
In September, Novatek and PAO Rosseti signed a partnership agreement to supply power to the project, to “enable timely start of power supply to the company’s prospective large-scale Murmansk LNG project, whose distinctive feature is the use of electric drives for process compressors instead of gas turbines,” the operator said in a release at the time.
INPEX to lead Houston area ammonia plant development
INPEX Corp., Air Liquide Group, LSB Industries Inc., and Vopak Moda Houston LLC will collaborate on pre-front-end engineering and design (FEED) for a 1.1-million tonne/year (tpy), low-carbon ammonia production and export project on the Houston Ship Channel (HSC). The developers are targeting end-2027 startup, with options for future expansions.
Vopak Moda already operates an HSC ammonia terminal that includes storage tanks and a newbuild dock with multiple deepwater berths capable of accommodating very large gas carriers. HSC siting also provides access to utilities and pipelines for supply of raw materials. Vopak Moda will build additional storage to handle the new production.
Air Liquide and INPEX will collaborate on low-carbon hydrogen production, using the former’s AutoThermal reforming (ATR) technology and proprietary carbon capture technology. The combination of ATR technology with carbon capture aims to capture at least 95% of direct CO2 emissions from hydrogen production, resulting in the capture and permanent sequestration (CCS) of at least 1.6-million tpy of CO2, according to the companies.
LSB and INPEX will collaborate on low-carbon ammonia production. LSB would lead the selection of the ammonia loop technology provider, the pre-FEED, and the plant’s engineering, procurement, and construction. LSB would also be responsible for the day-to-day operation of the ammonia loop.
INPEX and LSB will sell the ammonia and finalize off-take and potential additional partnership agreements. Most of the product would be used for power generation in Asia with some volumes going to Europe and the US, the companies said. INPEX, with stakes in both hydrogen and ammonia production, is expected to be the largest investor in the overall project.