GENERAL INTEREST Quick Takes
Equinor completes full Russian exit with final deal close
Equinor has completed a full exit from Russia with completion of a deal signed in May to leave the Kharyaga project, the company said in a release Sept. 2. The company held a 30% interest in the onshore Zarubezhneft-operated oil field, which lies in the Timan-Pechora basin in the Nenets Autonomous District, 60 km north of the Arctic Circle. Equinor had been a partner in the development since 1996.
Kharyaga produces about 29,000 b/d of oil. In 2018, Russia extended the production sharing agreement to 2031 (OGJ Online, July 25, 2018).
Equinor began the exit process in late February following Russia’s invasion of Ukraine. Since that time, the company stopped new investments into Russia, stopped trading oil and gas products from Russia, wrote down $1.08 billion in related assets, and transferred its participating interests in four Russian joint ventures to Rosneft (OGJ Online, Feb. 28, 2022; Mar. 15, 2022; May 25, 2022)
In addition to the Kharyaga project, Equinor had been involved in the AngaraOil LLC licenses, Domanik formation pilot project, and North-Komsomolskoye onshore discovery, in partnership with Rosneft.
After 30 years in Russia, Equinor has now exited all joint ventures in the country—all completed in accordance with Norwegian and EU sanctions legislation related to Russia, the company said.
TotalEnergies, another previous partner in the project, finalized the sale of its 20% interest in Kharyaga to state-controlled operator Zarubezhneft on Aug. 3, 2022. Nenets Oil Co. is the remaining partner.
QatarEnergy to build 1.2-million tpy blue ammonia plant
QatarEnergy affiliates QatarEnergy Renewable Solutions and Qatar Fertiliser Co. (QAFCO) have agreed to build the 1.2-million tonne/year (tpy) Ammonia-7 blue ammonia project, targeting first-quarter 2026 startup. QAFCO will run the plant as part of its integrated operations in Mesaieed Industrial City (MIC).
A consortium of thyssenkrupp Uhde GMBH and Consolidated Contractors Co. (CCC) won the project’s $1-billion engineering, procurement, and construction contract.
QatarEnergy described the project as building on its expertise in making conventional ammonia for the sake of fertilizer production. Blue ammonia is produced by capturing and storing the CO2 created, with the ammonia
itself transportable by ship for use in low-carbon electricity generation.
Under terms of the agreement QatarEnergy Renewable Solutions will:
- Develop and manage 1.5 million tpy of integrated carbon capture and storage (CCS) for use with the Ammonia-7 plant.
- Supply more than 35 Mw of renewable electricity to Ammonia-7 from its photovoltaic solar powerplant in MIC, currently under construction.
- Develop and lead the process for certifying the product produced by Ammonia-7 as blue ammonia, with the involvement of industry experts and independent bodies.
- Be the sole off-taker and marketer of Ammonia-7’s production.
QatarEnergy has a goal of developing 11 million tpy of domestic CCS by 2035. It describes QAFCO as the world’s largest integrated single-site producer of ammonia, with current capacity of 4 million tpy.
German LNG Terminal GMBH is building an 8-million tpy LNG terminal in Brunsbüttel, Germany, designed to import ammonia as well (OGJ Online, Aug. 1, 2022).
Permian Resources updates guidance post Centennial-Colgate deal close
Permian Resources Corp., Midland, Tex., the combine of the now-closed merger of Centennial Resource Development Inc. and Colgate Energy Partners III LLC, expects to deliver total equivalent production of 140,000-150,000 boe/d (52% oil) in this year’s fourth quarter.
Assuming 38-42 gross wells spudded and completed, total capital expenditures are estimated at $300-325 million during the quarter, the company said in a release Sept. 1.
The company updated guidance following closing of the $7-billion deal signed in May to create the largest pure-play exploration and production company in the Permian Delaware basin (OGJ Online, May 19, 2022). Assets are concentrated in Reeves and Ward Counties, Texas, and Eddy and Lea Counties, New Mexico, consisting of about 180,000 net leasehold acres and 40,000 net royalty acres.
Permian Resources is operating an eight-rig drilling program and expects to reduce to a seven-rig program in November.
For full-year 2023, the company plans to spud and complete about 145 and 150 gross wells, respectively, with an average working interest of 80% and 8/8ths net revenue interest of about 78%. Total daily production for 2023 of 150,000-165,000 boe/d (52% oil; 71% liquids) is expected with total capital expenditures of $1.15-1.35 billion.
The company will start 2023 with a seven-rig drilling program with the potential to reduce the rig count during the year, assuming expected operational efficiencies are achieved, the company said. Crude oil production growth of about 10% is planned in fourth-quarter 2023 compared with fourth-quarter 2022.
Operating activity is expected to be split relatively evenly between New Mexico and Texas. In New Mexico, activity will focus on second and third Bone Spring sand intervals, while Texas development will concentrate on the third Bone Spring sand and Wolfcamp intervals.
Exploration & Development Quick Takes
Wintershall to submit PDO for Dvalin North tieback
Wintershall Dea Norge AS plans to submit its plan for development and operation (PDO) for the Norwegian Sea Dvalin North field later this year. The gas field will be developed as a tie-back to Dvalin field.
Dvalin was the largest discovery on the shelf in 2021. Last year, Wintershall drilled two exploration wells at Dvalin North. The first contained 10-16 million std cu m total recoverable oil equivalent. The second contained a total estimated recoverable oil equivalent of 3-9 million std cu m (OGJ Online, May 31, 2021).
Wintershall is operator at Dvalin with 55% interest. Partners are Petoro AS (35%) and Sval Energi AS (10%).
LLOG lets contract for Salamanca project, Gulf of Mexico
LLOG Exploration Offshore LLC has let a contract to Audubon Engineering Co. LP to support its Salamanca floating production system (FPS) project in the US Gulf of Mexico. LLOG is acting as project manager for the Salamanca FPS Infra LLC (OGJ Online, May 4, 2022).
Work scope includes detailed design services as well as procurement, vendor equipment management, construction, pre-commissioning, and offshore commissioning support.
LLOG will repurpose the decommissioned Independence Hub semisubmersible production unit, aiming for a positive impact on environmental, social, and governance (ESG) and emissions avoidance when compared to new unit construction.
The hull, topside truss, cranes, and lifeboats will be reused with minor modifications. All other topside equipment, including piping, instrumentation, and electrical systems, will be new and fit for purpose.
In July, LLOG let a contract to Exterran Corp. for technology to support the Salamanca project floating production unit.
The column-stabilized Salamanca FPS will sit in Keathley Canyon block 689 in 6,400 ft of water to tap the Lower Tertiary Leon and Castile discoveries. The platform will have processing capacity of 60,000 b/d of oil, 25,000 b/d of water, and 40 MMscfd of natural gas. Three initial development wells are planned, two on Leon field and one on Castile field. Initial production from the joint development is expected mid-2025.
LLOG will obtain ABS A1 notation for the platform to comply with CG-ENG Policy Letter No. 01-13, Alternate Design and Equipment Standard for Floating Offshore Installations.
LLOG is operator. Partners include Repsol and Beacon Offshore Energy.
ExxonMobil to explore India deepwater
Oil and Natural Gas Corp. (ONGC) has signed a heads of agreement with ExxonMobil Corp. for deepwater exploration offshore India.
Collaboration areas focus on the eastern offshore Krishna Godavari and Cauvery basins and the western offshore Kutch-Mumbai region. In recent years, the companies have exchanged exploration data, leading to the partnership, ONGC said in a release.
Cauvery basin is an established hydrocarbon province with a resource base of 700 million metric tonnes, with 430 million metric tonnes on land and 270 million metric tonnes offshore. Structural and combination traps are in Early Cretaceous to Paleocene sequences. Stratigraphic traps such as pinch-outs, wedge-outs, and lenticular sand bodies are in early to late Cretaceous sequences.
Krishna Godavari basin is an established hydrocarbon province with a resource base of 1,130 million metric tonnes, of which 555 million metric tonnes are assessed offshore. Commercial hydrocarbons are in the oldest Permo-Triassic Mandapeta sandstone on land to the youngest Pleistocene channel levee complexes in deep water offshore. The basin has four petroleum systems classified broadly into Pre-Trappean and Post-Trappean due to their distinct tectonic and sedimentary characteristics.
Touchstone receives environmental clearance for Ortoire block work
Touchstone Exploration Inc. received a Certificate of Environmental Clearance (CEC) to develop Ortoire block Cascadura area, onshore the Republic of Trinidad and Tobago, from the Trinidad and Tobago Environmental Management Authority.
The CEC approves construction of a multi-well surface production unit with designed production capacity of 200 MMcfd natural gas, 5,000 b/d of associated liquids, and 200 b/d of produced water, with a storage capacity of 8,800 bbl of liquids on the Cascadura A wellsite.
The CEC also includes drilling eight wells at two well pads (Cascadura B and C) and establishment of associated pipelines and infrastructure within the block. Construction of the Cascadura surface unit and associated infrastructure needed to bring on production from two existing Cascadura wells will begin immediately following required notifications and conditions set out in the approval.
The National Gas Co. of Trinidad and Tobago Ltd. has started field activity to begin construction of the 1.7 km, 20-in. pipeline.
Touchstone is operator of the license with 80% working interest. Heritage Petroleum Co. Ltd. holds the remaining 20%.
Drilling & Production Quick Takes
CNOOC starts gas production from projects offshore China
CNOOC started production from two gas projects in the western South China Sea. The projects lie in the Yinggehai region in average water depth of 90 m.
Dongfang 1-1 gas field southeast zone and Ledong 22-1 gas field south block are connected to processing infrastructure at the Dongfang 1-1 and Ledong 22-1 platforms, respectively.
CNOOC plans four development wells, two subsea production systems, two oil and gas transportation pipelines and two umbilicals, with peak production of about 44 MMcfd of gas.
The company holds 100% interest in both projects.
Neptune Energy begins work on tenth Cygnus gas well
Neptune Energy started an infill drilling campaign at Cygnus gas field in the southern UK North Sea. Completion of the tenth well on the field is expected in this year’s fourth quarter.
Drilling is being carried out by Borr Drilling’s Prospector 1 jack up rig.
Cygnus is the largest natural gas discovery in the southern North Sea in over 30 years and is the largest single producing gas field in the UK, typically exporting over 250 MMscfd of gas. Part of the existing Cygnus field development plan, the tenth well holds the potential to provide enough additional gas to heat 200,000 UK homes this winter. Upon completion of the well, Cygnus will be capable of producing enough gas for about 2 million UK households, the company said.
Two drilling centers target 10 wells. Cygnus Alpha consists of three bridge-linked platforms: a wellhead drilling center, a processing-utilities unit, and living quarters-central control room. Cygnus Bravo, an unmanned satellite platform, is about 7 km northwest of Cygnus Alpha.
Gas is exported via a 55-km pipeline. Cygnus connects via the Esmond Transmission System (ETS) pipeline to the gas-treatment terminal at Bacton, Norfolk. Neptune holds a 25% minority interest in ETS.
Neptune Energy is operator at Cygnus with 38.75% interest. Spirit Energy holds 61.25%.
Aker BP drills dry hole near Skarv
Aker BP ASA plugged a Norwegian Sea well after acquiring data. Well 6507/3-16, the second exploration well in production license 941, about 12 km northeast of Skarv field and 220 km west of Sandnessjøen, was dry.
The well was drilled by the Deepsea Nordkapp drilling rig to a vertical depth of 2,205 m subsea. It was terminated in the Grey Beds from the Triassic. Water depth at the site is 374 m. The primary exploration target was to prove petroleum in reservoir rocks in the Lower Jurassic and Upper Triassic (the Båt Group and Grey Beds). The secondary exploration target was to prove petroleum in reservoir rocks in the Palaeocene (the Tang formation).
In the primary exploration target, the well encountered sandstone layers totaling about 200 m with good reservoir quality. The preliminary interpretation is that this is part of the Båt Group in the Lower Jurassic and Grey Beds in the Upper Triassic. Up to 2-3 m of sandstone were encountered in the secondary exploration target in the Tang formation.
The rig will now drill production well 6507/5-A-3 AH on Skarv field for operator Aker BP.
Earlier this month, Aker BP discovered oil in exploration well 6507/3-15, the first in the license (OGJ Online, Aug. 12, 2022).
Aker BP operates production license 941 with 80% interest. PGNiG Upstream Norway AS holds the remaining 20%.
PROCESSING Quick Takes
Shell takes FID on Malaysian gas project
Shell PLC subsidiary Sarawak Shell Bhd. (SSB) and partner PETRONAS Carigali Sdn Bhd have reached final investment decision (FID) to move forward with their Rosmari-Marjoram gas project, including an onshore gas plant (OGP) in Bintulu, Sarawak, Malaysia, to process natural gas produced from the Rosmari-Marjoram project in Block SK318, about 220 km offshore Sarawak (OGJ Online, Aug. 26, 2014).
To be primarily powered by renewable energy in line with Shell’s Powering Progress strategy as part of the broader energy transition, the Rosmari-Marjoram development is scheduled to begin producing 800 MMcfd of gas in 2026, Shell said upon announcing the Sept. 5 FID.
Part of the first phase of the Sarawak Integrated Sour Gas Evacuation System (SISGES) project, the Rosmari-Marjoram development will consist of a subsea tie-back, an unmanned well head platform, a 207-km sour wet gas pipeline to shore, and the OGP at Bintulu.
The offshore platform will use power from 240 solar panels, while the OGP will receive power from the Sarawak grid system, which is supplied mainly from hydroelectric plants.
The development will use diesel generators and batteries as backup, according to Shell.
Confirmation of FID follows the partnership’s award of a $680-million contract to Samsung Engineering Co. Ltd. in July for delivery of engineering, procurement, construction, and commissioning (EPCC) for the proposed OGP, which will have a nameplate processing capacity of 800 MMcfd (OGJ Online, July 13, 2022).
With 80% equity in the SK318 production sharing contract (PSC), SSB serves as operator alongside partner PETRONAS Carigali Sdn Bhd (20%).
bp progresses work to restart Whiting refinery
bp PLC said it is working to resume operations at subsidiary bp Products North America Inc.’s 440,000-b/d refinery in Whiting, Ind., following its sitewide shutdown in the wake of an Aug. 24 electrical fire.
“bp has deployed all available resources and is working around the clock to bring the Whiting refinery back to normal operations as soon as safely possible,” bp America Inc. told OGJ via e-mail on Aug. 30.
The Whiting team continues to make progress in “restoring the utilities needed to bring the plant back to normal operations” and is “working toward a phased restart of the refinery” in the coming days, bp said at the time.
While the Aug. 24 incident did not result in any injuries, bp confirmed the electrical fire—though limited to a single electrical system and quickly extinguished—did cause a loss of utilities in other parts of the refinery, presumably prompting the site’s safe and orderly shutdown.
A cause of the incident has yet to be revealed.
bp’s Whiting refinery—the largest in the US Midwest—produces about 10 million gal/day of gasoline, 4 million gal/day of diesel, and 2 million gal/day of jet fuel for distribution into the region’s transportation network, according to the operator’s website.
During the ongoing shutdown period, bp said it is continuing to work with local, state, and federal agencies to help ease regional supply constraints, and with partners on steps to secure fuel supplies.
As part of the US federal government’s response to the Whiting shutdown, both the US Department of Transportation’s (UDOT) Federal Motor Carrier Safety Administration (FMCSA) and the US Environmental Protection Agency (EPA) have issued temporary emergency orders to expedite supply and distribution of gasoline, diesel, jet fuel, and other petroleum products in Illinois, Indiana, Michigan, and Wisconsin, the four states most impacted by the refinery’s outage.
On Aug. 26, USDOT’s FMCSA issued an emergency declaration providing a temporary hours-of-service exemption that—subject to restrictions—allows motor carriers and drivers transporting gasoline, diesel, jet fuel, and other refined products in the affected areas to exceed the maximum driving time for property-carrying vehicles as stipulated under US federal law. The FMCSA exemption was to remain valid through Sept. 10, or until the emergency ended, whichever came first, USDOT said at the time.
On Aug. 27, US EPA Administrator Michael Regan issued an emergency fuel waiver to help alleviate fuel shortages in the same four states whose supply of gasoline has been interrupted by the refinery shutdown. To remain in effect through Sept. 15, the temporary waiver will lift federal regulations as well as federally enforceable state requirements for fuel volatility on gasoline sold in the impacted states.
TRANSPORTATION Quick Takes
Gazprom suspends Nord Stream 1 gas shipments indefinitely
PJSC Gazprom has stopped natural gas shipments via its Nord Stream 1 natural gas pipeline to Germany indefinitely. The company said that during scheduled maintenance on Nord Stream pipeline’s gas compressor unit (GCU) No. 24 at Portovaya compressor station it discovered an oil leak that had reached terminal connections serving the 66-Mw Siemens Trent 60 turbine’s rotor-speed sensors. Gazprom indicated that it was conducting the maintenance jointly with Siemens.
The company also said that Russia’s environmental supervisory agency (Rostekhnadzor) had issued a safety warning that required the GCU be idled until its safe operations could be ensured. It further described the leak as similar to issues that have forced other GCU to be taken offline and returned to Siemens for repair. The absence of these units has had Nord Stream 1 operating at just 20% of its designed 55-billion cu m/year capacity since June.
Gazprom had planned to complete maintenance and restart the compressor in the early days of September, saying via Twitter in August that shipments would be resumed at a rate of 33 million cu m/day (OGJ Online, Aug. 22, 2022).
Initial reaction from consumers of Russian gas was skeptical. European Commission spokesman Eric Manner wrote on Twitter that “Gazprom’s announcement this afternoon that it is once again shutting down Nord Stream 1 under fallacious pretenses is another confirmation of its unreliability as a supplier. It’s also proof of Russia’s cynicism, as it prefers to flare gas instead of honoring contracts.”
The shutdown announcement came just hours after G7 finance ministers agreed to impose a cap on Russian oil aimed at both avoiding prices spikes and slashing the country’s revenue, undermining its ability to continue the war in Ukraine (OGJ Online, Sept. 2, 2022). Russia said it would stop selling oil to countries implementing the policy.
Cheniere requests NEPA prefiling for Corpus Christi LNG expansion
Cheniere Energy Inc. has requested that the US Federal Energy Regulatory Commission (FERC) begin its National Environmental Policy Act (NEPA) prefiling review for two additional midscale trains at the company’s 15-million tonne/year (tpy) Corpus Christi Liquefaction (CCL) plant in Corpus Christi, Tex. FERC had previously approved CCL Stage 3, consisting of as many as seven midscale trains which would add 10 million tpy to the plant’s capacity. The most recent request would add an eighth and ninth train to the expansion.
Newly proposed work would also include a 220,000-cu m storage tank, adding to the three 160,000-cu m tanks already operating at CCL. Feed gas for the new trains would be supplied in part by Cheniere’s 2.75-bcfd, 48-in. OD Corpus Christi Pipeline.
CCL uses two berths for loading LNG carriers, with a current combined authorized loading rate of 12,000-cu m/hr. The new prefiling request proposes increasing this rate to 22,500 cu m/hr, which would allow for simultaneous loading at both jetties. CCL also proposed increasing the maximum single-jetty rate to 14,000 cu m/hr.
The company anticipates filing a formal project application with FERC in February 2023, beginning construction in August 2024 (pending FERC approval), and placing the 1.64-million tonne/year Trains 8 and 9 in service second-half 2031. Cheniere describes the two new trains as “near replicates” of those approved by FERC as part of CCL Stage 3.
Cheniere took final investment decision on CCL Stage 3 earlier this year, issuing full notice to proceed with construction to Bechtel Corp., which had already begun work under a limited notice (OGJ Online, June 22, 2022).
Petronas, YPF to develop Argentina LNG project
Petroliam Nasional Berhad (Petronas) and YPF SA have signed an MOU for joint development of a 5-million tonne/year (tpy) LNG plant in Argentina and collaboration in other areas, including upstream oil, petrochemicals, and clean energy. The companies anticipate LNG production to ultimately reach 25 million tpy.
Petronas said that the LNG project would leverage Vaca Muerta shale’s gas resources. The company has worked with YPF since 2014 in developing Vaca Muerta crude oil (OGJ Online, Aug. 28, 2014).
YPF and Petronas’s operating entity in Argentina, Petronas E&P Argentina SA, also executed a joint study and development agreement towards the Argentina Integrated LNG project which will encompass dedicated upstream natural gas production, pipeline and infrastructure development, the LNG plant, and marketing and shipping.
Final investment decision for the projects will follow technical and commercial assessment and is dependent on conducive financial and regulatory terms.
As of July 2019, Vaca Muerta held an estimated 308 tcf of dry, wet, and associated technically recoverable shale gas resources, according to the US Energy Information Agency. Argentina’s proved natural gas reserves are 14 tcf.
Magellan Midstream to expand refined products pipeline system
Magellan Midstream Partners LP, Tulsa, plans to expand its refined petroleum products pipeline system from the Houston area to El Paso, Tex., to a new capacity of about 100,000 b/d.
Expansion includes construction of a new 16-in., 30-mile pipeline along its existing route between Odessa and Crane, Tex., and additional operational storage to facilitate incremental shipments, the company said in a release Aug. 29.
Magellan currently expects to spend about $125 million on the project and expects the extra capacity to be available early 2024, subject to permits and approvals.
The company currently can transport about 70,000 b/d of refined petroleum products (gasoline and diesel fuel) from Gulf Coast and mid-continent refineries to El Paso, with further shipper optionality to access markets in New Mexico through its pipeline system, as well as Arizona and Mexico via connections to third-party pipelines.