OGJ Newsletter
GENERAL INTEREST Quick Takes
Equinor exits joint ventures in Russia
Equinor ASA has transferred its participating interests in four Russian joint ventures to Rosneft and is released from all future commitments and obligations, the company said in a release May 25. An agreement to exit the Kharyaga project has also been signed.
Equinor began the exit process in late February following Russia’s invasion of Ukraine. Since then, Equinor has halted all new investments into Russia, stopped trading oil and gas products from the country, and noted an impairment of $1.08 billion on the balance sheet related to its Russian activities as of Mar. 31, 2022.
Equinor had been a partner since 1996 in Kharyaga oil field development in the Timan-Pechora basin in the Nenets Autonomous District, 60 km north of the Arctic Circle. It also was involved in the AngaraOil LLC licenses, Domanik formation pilot project, and North-Komsomolskoye onshore discovery, in partnership with Rosneft.
The exit has been completed in accordance with Norwegian and EU sanctions legislation related to Russia, the company said.
BVK to buy ExxonMobil Barnett shale assets for $750 million
Subsidiaries of BKV Corp., Denver, will pay $750 million to acquire ExxonMobil’s operated and non-operated North Central Texas Barnett shale gas assets, ExxonMobil said in a release May 19. Additional payments are contingent on future natural gas prices, the oil and gas major said.
BKV currently holds about 292,600 net acres in Denton, Parker, Tarrant, and Wise counties in Texas with current production of 550 MMcfd (gross), according to the company website. The company was formed in 2015 by Thailand-based Banpu Public Co. Ltd. and acquired a large Barnett shale position through a $770-million deal with Devon Energy in 2019.
ExxonMobil said it removed the assets—operated by subsidiaries XTO Energy Inc. and Barnett Gathering LLC—from its development plan in 2020 as part of a larger strategy to prioritize investments on “advantaged assets with lowest cost of supply.”
XTO Energy had built a large position in major US shale, tight gas, and coalbed methane plays, amassing a 277,000-acre position in the Barnett specifically, before its 2009 acquisition by ExxonMobil in an all-stock deal valued at $41 billion (OGJ Online, Dec. 14, 2009; Jan. 1, 2010).
At closing, BKV will acquire some 160,000 total net acres primarily in Tarrant, Johnson, and Parker counties, with additional smaller positions in Jack, Wise, Denton, Erath, Hood, and Ellis counties, BKV said in a separate release May 20. Average working interest is 93% in over 2,100 wells with operatorship positions, the company continued. Through the deal, BKV also will acquire some 750 miles of gathering pipelines, compression, and processing infrastructure.
As part of the deal, all employees of ExxonMobil subsidiaries in the Barnett shale will receive full employment offers with BKV, according to ExxonMobil.
The sale is expected to close in this year’s second quarter.
PGNiG signs deal with Wellesley for Ørn field interest
PGNiG Upstream Norway AS agreed to purchase 40% interest in PL942 covering Ørn gas field in the Norwegian Sea, about 20 km from Skarv field, from Wellesley Petroleum AS.
PGNiG expects natural gas production attributable to its interest to average 0.25 billion cu m/yr from 2026-2035, the company said in a May 20 release.
AkerBP-operated Ørn field was discovered in 2019 (OGJ Online, Sept. 17, 2019). Development is expected to start in 2023, with production expected to begin in 2026.
According to the Norwegian Petroleum Directorate, the field’s recoverable reserves are about 6.75 billion cu m natural gas, 0.17 million tonne oil, and 0.79 million tonne NGLs.
PGNiG Upstream Norway also holds an interest in AkerBP-operated Skarv (11.92%) and may use existing production infrastructure, including the Skarv FPSO, to reduce production start-up time and cost, as well as reduce CO2 emissions associated with field development, it said.
AkerBP, as operator of Ørn, holds 30% interest. Equinor Energy also holds 30%. Acquisition of the remaining 40% from Wellesley Petroleum by PGNiG is subject to consents from, among others, the Norwegian Ministry of Petroleum and Energy.
RRC advances plan to streamline CCS injection well permits
The Railroad Commission of Texas (RRC) advanced its effort to gain primacy from the US Environmental Protection Administration (EPA) for Class VI injection wells used for underground storage of carbon dioxide (CO2) from energy production, power generation, or industrial sources.
RRC’s commissioners approved the publishing of proposed amendments to the agency’s CO2 rules for public comment. The proposed changes and other information will be sent to EPA as part of a pre-application for primacy and allow EPA a chance to start its review.
If ultimately approved by the EPA, operators would apply with the RRC for the permits rather than both agencies.
The proposed amendments would modify various sections of RRC rules, including those describing the applicability of the rules, application requirements, notice and hearing requirements, permit standards and reporting, recordkeeping, and more, RRC said.
“Clearly, there is concern today about levels of carbon dioxide in the atmosphere and its impact on the environment,” said Leslie Savage, RRC’s chief geologist. “Class VI injection wells have the potential to be part of the solution by trapping the CO2 in appropriate geologic formations. We hope our program will be able to streamline the process and allow for the timely issuing of Class VI permits.”
Primacy allows the EPA to delegate its authority to states, provided they meet the federal government’s minimum standards.
Woodside shareholders vote for BHP merger
Woodside Petroleum Ltd. shareholders voted overwhelmingly for the company’s $63 billion (Aus.) merger with BHP Group’s petroleum division at the Woodside annual general meeting in Perth May 19.
The level of support (98.66% approval) of the scrip-based deal paves the way for Woodside to join the world’s top 10 independent oil and gas producers.
Deal terms, agreed in November 2021, are expected to deliver annual synergies of at least $570 million (Aus.) beginning in 2024, according to Woodside.
Shareholders also voted to change Woodside’s name to Woodside Energy.
Exploration & Development Quick Takes
Equinor makes oil discovery near Johan Castberg
Equinor Energy AS and partners will assess a new oil discovery in Snøfonn Nord, in the Barents Sea, with a view toward a possible tie-in to Johan Castberg field.
Preliminary calculations place the size of the discovery at 6-8 million standard cu m of recoverable oil.
Exploration well 7220/8-2 S—the 12th in production license (PL) 532—was drilled by the Transocean Enabler rig 5 km south-southeast of discovery well 7220/8-1 (Skrugard) and 210 km northwest of Hammerfest to a vertical depth of 1,269 m subsea. It was terminated in the Fruholmen formation from the Late Triassic. Water depth at the site is 350 m. The well has now been permanently plugged.
The objective was to prove petroleum in reservoir rocks from the Early Jurassic and Late Triassic (Tubåen, Nordmela, Fruholmen formations). The well encountered two oil columns in the Tubåen formation of 81 m and 13 m in the upper and lower part of the formation, respectively, in sandstone totaling about 114 m with very good reservoir quality. The deepest oil-water contact was encountered 921 m subsea.
A 20-m oil column was encountered in the Nordmela formation in sandstone with medium to good reservoir quality. Oil-water contact was not encountered.
In the Fruholmen formation, the well encountered a 14-m oil column in about 81 m of sandstone with medium to good reservoir quality. Oil-water contact was encountered 1,071 m subsea.
The well was not formation-tested, but extensive data acquisition and sampling were carried out.
The rig will move 800 m west in the license to drill wildcat well 7220/8-3.
Equinor is operator of PL 532 with 50% interest. Partners are Petoro AS (20%) and Vår Energi ASA (30%).
Chevron sanctions Ballymore deepwater GoM project
Chevron Corp. has sanctioned the Ballymore project in the deepwater US Gulf of Mexico. The project, with a design capacity of 75,000 b/d of crude oil, will be developed as a three-mile subsea tieback to the existing Chevron-operated Blind Faith platform, the company said in a May 17 release.
Sanction comes 4 years after the Ballymore well, drilled to a final depth of 8,898 m, encountered 205 m of net oil pay in a high-quality Jurassic Norphlet reservoir.
Ballymore will be Chevron’s first development in the Norphlet trend of the US gulf. The project will be in the Mississippi Canyon area in about 6,600 ft (2,000 m) of water, about 160 miles (260 km) southeast of New Orleans, La.
Potentially recoverable oil-equivalent resources for Ballymore are estimated at more than 150 million bbl.
The $1.6-billion project, which involves three production wells tied back via one flowline, will transport oil and natural gas production via existing infrastructure with first oil expected in 2025.
Chevron USA Inc. is operator of the project with 60% interest. TotalEnergies E&P USA Inc. holds the remaining 40%.
CGX, Frontera confirm oil, gas condensate discovery offshore Guyana
CGX Energy Inc. and Frontera Energy Corp. said independent, third-party studies support initial interpretations from cuttings, mud gas, and annulus fluid analysis that the Kawa-1 exploration well offshore Guyana discovered light oil in the Santonian and Coniacian and gas condensate in the Maastrichtian and Campanian.
The findings also derisk the Wei-1 exploration well, expected to be spud in third-quarter 2022 subject to rig release from a third-party operator, the JV said in a May 10 release.
Kawa-1 well was drilled in water depth of 355 m (1,174 ft) to a total depth of 6,577 m (21,578 ft) in the northern portion of the block.
The JV encountered hydrocarbons in multiple zones extending from 4,638 m (15,216 ft) in the Maastrichtian to 6,568 m (21,547 ft) in the Coniacian.
A total of 69 m (228 ft) of net pay was found distributed throughout the Maastrichtian (68 ft/21 m), Campanian (66 ft/20 m), Santonian (76 ft/23 m), and Coniacian (18 ft/5 m) horizons with individual pay zones up to 11 m (35 ft) thick.
The JV is integrating detailed seismic and lithological analysis and pore pressure studies from Kawa-1 into preparations of Wei-1, which is to be drilled 14 km northwest of Kawa-1 in the same block, some 200 km offshore Georgetown, in water depth of 583 m (1,912 ft) to a targeted total depth of 6,248 m (20,500 ft). The well will target Campanian and Santonian aged stacked channels in a western channel complex in the northern section of the block.
Data from Kawa-1 and Wei-1 will inform future activities and potential development decisions. Opportunities to obtain additional drilling financing are being assessed.
Drilling & Production Quick Takes
Beach defers Bass basin Trefoil project FID in favor of Yolla West drilling
Beach Energy has deferred a final investment decision for its Trefoil development project in the Bass basin offshore Tasmania in favor of drilling an infield opportunity at nearby Yolla West field.
Recent reprocessing of existing 3D seismic data over Yolla gas field has revealed a previously unidentified fault block (Yolla West) which can be drilled from the Yolla production platform, the company said.
If successful, Yolla West could be quickly connected to the Lang Land gas plant onshore eastern Victoria, thus its potential as a lower-cost, nearer-term, and higher-returning investment opportunity, the company continued.
Deferral of Trefoil development (planned as subsea tiebacks to Yolla infrastructure 38 km to the east) will enable more time to complete interpretation of the 2021 Prion 3D seismic survey, expected in mid-financial year 2023, Beach said. It also will provide more time to refine the most cost-effective development option and benchmark the investment case against other opportunities in the portfolio, it continued.
Rig negotiations are in progress to drill a Yolla West well between December 2022 and March 2023.
The prospect has potential to return the underutilized Lang Lang gas plant to capacity production rates of 67 terajoules/day and extend the life of Yolla field, which was brought on stream in 2006 via a 147-km undersea pipeline from Yolla platform to the Victorian coast.
Hupecol begins drilling operations in Venus exploration area in Colombia
Hupecol Operating, an affiliate of Hupecol Meta LLC, started drilling operations on a well in the CPO-11 Venus exploration area in Colombia’s Llanos basin, according to interest holder Houston American Energy Corp.
Future area activities will be based on results of the first two wells, the company said in a May 24 release.
The Venus exploration area, and a 50% interest in the larger CPO-11 block, are held by Hupecol Meta. Houston American, through its ownership interest in Hupecol Meta, holds a 6.99% working interest in the subject well and Venus exploration area.
Eni spuds well offshore Cyprus
Eni has spudded the Cronos-1 well in Block 6 of the Exclusive Economic Zone of Cyprus following the arrival of Vantage Drilling’s Tungsten Explorer drillship, according to a May 23 release from the Ministry of Energy, Trade, and Industry.
In February 2018, Eni made a lean gas discovery in the offshore block with Calypso 1 NFW. The well, which was drilled in 2,074 m of water reaching a final total depth of 3,827 m, encountered an extended gas column in rocks of Miocene and Cretaceous age. The Cretaceous sequence has excellent reservoir characteristics, Eni said. Calypso 1 was described as a promising gas discovery which confirms the extension of the Zohr-like play in the Cyprus Exclusive Economic Zone.
Eni is operator in a 50-50 JV with TotalEnergies SE (50%).
Norway production down slightly
Norway’s production averaged 1.871 million b/d in April, the Norwegian Petroleum Directorate (NPD) reported.
Norway’s production averaged 1.960 million b/d in March.
Average daily liquids production in April consists of 1.660 million b/o, 203,000 bbl of NGL, and 9,000 bbl of condensate.
Oil production in April was 10.6% lower than the NPD’s forecast and 5.4% lower than the forecast so far this year.
PROCESSING Quick Takes
Flint Hills adding solar at Pine Bend refinery
Flint Hills Resources LLC (FHR), Wichita, Kan., has approved a project that will involve construction of one of the US’ largest solar installations to help power operations, lower energy costs, improve energy efficiency, and reduce emissions at subsidiary Flint Hills Resources Pine Bend LLC’s (FHR Pine Bend) 335,000-b/d Pine Bend refinery in the city of Rosemount, Dakota County, Minn., 17 miles southeast of Minneapolis.
As part of the planned $75-million project announced on May 10, FHR is building a 45-Mw solar installation that will include at least 100,000 9-14-ft panels across 200 acres of a 300-acre tract of company-owned property immediately adjacent and connecting directly to FHR Pine Bend’s refining complex, the company said in a release.
In what it anticipates will become the US’ largest single-site use of direct solar power upon completion, FHR said the planned installation will have a peak solar-energy production capacity to satisfy roughly 30% of the refinery’s 135-Mw power needs during optimal conditions, producing enough electricity to power the equivalent of more than 8,400 homes/year.
Arizona-based DEPCOM Power Inc.—a fellow subsidiary of FHR’s owner Koch Industries Inc.—has already been awarded a contract to deliver engineering, procurement, and construction services on the project, which is scheduled to be completed within a year from the start of construction, FHR confirmed.
Once operable, the solar installation will become FHR Pine Bend’s second source of on-site power generation following completion of its combined heat and power (CHP) system in 2019, which currently supplies the refinery about 50 Mw of electricity, or roughly 40% of what is required to power daily operations.
Combined and under optimal operating conditions, then, the solar installation and CHP on-site power sources could fulfill as much as 70% of the Rosemount complex’s daily power requirements, enabling the refinery to reduce energy losses associated with long-distance transmission, transformation, and distribution of utility supply, according to the operator.
Additionally, FHR said it plans to add pollinator-friendly habitat within FHR Pine Bend’s solar development, which will add several hundred acres to the complex’s overall habitat management program that currently includes property east of the refinery, near the Mississippi River. Further details on that leg of the project, however, have yet to be revealed.
Alongside supplying most of the transportation fuels used in Minnesota and a large portion of fuels used throughout the Upper Midwest, the FHR Pine Bend refinery also produces asphalt, home heating fuels, as well as raw materials used in a wide range of manufacturing processes, including fertilizers, pharmaceuticals, and plastics.
Fujian Meide Petrochemical lets contract for new PDH unit
Zhongjing Petrochemicals Group subsidiary Fujian Meide Petrochemical Co. has let a contract to Lummus Technology LLC and catalyst partner Clariant International Ltd.’s Clariant Catalysts for a project to expand propylene production at the company’s operations in Fuzhou City, Fujian Province, China.
As part of the contract, Lummus Technology will license its proprietary CATOFIN process technology for a propane dehydrogenation (PDH) unit that will use Clariant’s tailor-made catalysts and Heat Generating Material (HGM) to produce 900,000 tonnes/year (tpy) of propylene, the service providers said in separate releases on May 25.
In addition to increased production reliability, combination of Clariant’s HGM with CATOFIN technology will reduce the new unit’s energy consumption, providing Fujian Meide a low-carbon route to propylene production, said Stefan Heuser, Clariant Catalysts’ senior vice-president and general manager.
Scheduled for startup in 2023, the new unit will become the second PDH unit—and one of the world’s largest—at Fujian Meide’s Fuzhou petrochemical complex, according to McDermott and Clariant.
While McDermott and Clariant did not reveal further details of this latest joint technology-catalyst contract for Fuzhou’s Phase 2 PDH unit, Shengu Group, or Shenyang Blower Group Co. Ltd., confirmed in a release Feb. 1, 2021, its receipt of a contract award in January 2021 to supply new compressors for the Fuzhou complex’s gas, propylene, and ethylene units to support the Lummus-equipped, second-phase PDH unit.
Fujian Meide previously commissioned a 660,000-tpy PDH unit as part of the first-phase development of the Fuzhou complex. The Phase 1 PDH unit is equipped with process technology from Honeywell UOP LLC (OGJ Online, Sept. 17, 2019).
Fire breaks out at Brazilian refinery
Petróleo Brasileiro SA (Petrobras) extinguished a fire that occurred on May 17 at its 170,000-b/d Refinaria Presidente Bernardes (RPBC) refinery in Cubatão, São Paulo.
RPBC’s on-site fire brigade team immediately isolated and controlled the fire, which broke out following a diesel oil spill, Petrobras said in a release.
While the operator did not identify the specific unit impacted by the fire, Petrobras did confirm no other refining units were damaged as a result of the incident, nor were any injuries reported in the aftermath of the event.
With the incident now reported to all necessary environmental and regulatory agencies—and an investigation presumably to follow—Petrobras said there will be no interruption to production of petroleum products or risks to market supply in the fire’s wake.
Additional details were not disclosed.
Commissioned in 1955 and one of five refineries not included in operator’s ongoing downstream divestment portfolio, RPBC produces diesel, gasoline, fuel oil, and LPG for supply to São Paulo (primarily, São Paulo capital city), with a portion also for delivery to Santos as well as destinations in north, northeastern, and southern Brazilian regions.
TRANSPORTATION Quick Takes
Tellurian gets initial Driftwood pipeline environmental clearance
Tellurian Inc.’s proposed 37-mile Line 200 and Line 300 natural gas pipelines received a positive draft environmental impact statement from the US Federal Energy Regulatory Commission (FERC), advancing the project towards construction. The two pipelines would supply Tellurian’s 27.6-million tonne/year Driftwood LNG plant, which the company expects will deliver first LNG in 2026.
FERC staff determined that the project would result in some “adverse environmental impacts” but that these would not be significant if recommended mitigation measures were implemented. The review did not draw conclusions regarding the potential climate impacts of the project.
Line 200 and Line 300 would be dual 42-in. OD pipelines originating near the town of Ragley in Beauregard Parish, La., and running southward at a combined maximum capacity of 5.7 bcfd to Driftwood LNG, near Carlyss in Calcasieu Parish, La. The project will also include the new 211,200-hp Indian Bayou compressor station in Beauregard Parish, La.
Tellurian began construction of Driftwood earlier this year.
Gasunie adds FSRU to Eemshaven LNG terminal
NV Nederlandse Gasunie has agreed to charter a 170,000-cu m, 900-MMscfd floating storage and regasification unit (FSRU) from New Fortress Energy Inc. for 5 years beginning in third-quarter 2022, providing additional storage and regasification for Gasunie’s new LNG terminal in Eemshaven, the Netherlands. New Fortress says the Eems Energy Terminal—featuring the newly chartered vessel working in tandem with Exmar Groups’s S188 FSRU—will be able to import 8 billion cu m/year (bcmy), enough LNG to meet the country’s gas needs without relying on pipeline imports.
Gasunie chartered the 4.5-bcmy S188 in March 2022 for 5 years. The vessel is scheduled to leave Singapore this month and arrive in Eemshaven in early August 2022.
Gasunie plans to build a permanent shore-based terminal, also capable of storing green hydrogen, at Eemshaven in the future.
Gastrade begins work on Alexandroupolis LNG terminal, applies for second
Gastrade SA has begun construction of its 5.5-million tonne/year LNG terminal offshore Alexandroupolis, Greece, targeting an end-2023 in-service date. The terminal will use a 153,500-cu m floating storage and regasification unit (FSRU), connected to Greece’s National Natural Gas Transmission System by a 28-km, 30-in. OD pipeline.
Regasified LNG will be transmitted to markets in Greece, Bulgaria, and the wider region of southeastern Europe, with the prospect of supplying Ukraine as well, according to Gastrade. The Alexandroupolis FSRU has contracted 60% of its capacity.
The company also submitted an application to Greece’s Regulatory Authority for Energy for a new independent natural gas system (INGS) license to develop a second FSRU-based LNG terminal, Thrace INGS, to be developed near the first FSRU in the Sea of Thrace, offshore Alexandroupolis.
“Alexandroupolis is the gateway and Bulgaria is the connecting link of the supply chain that this project comes to supply, on the way to Serbia and Romania. The second FSRU…allows for the further extension of this chain to Moldova and Ukraine,” Gastrade vice-president and chief executive officer Konstantinos Sifnaios said.
Gastrade took final investment decision on the Alexandroupolis FSRU earlier this year.
Bulgarian-state Bulgartransgaz EAD owns 20% of Gastrade. Greek companies Hellenic Gas Transmission System Operator (DESFA) and DEPA Commercia, Cyprus’ GasLog Ltd., and private individual Asimina‐Eleni Copelouzou also each own 20%.
Matterhorn Express reaches FID
WhiteWater, EnLink Midstream LLC, Devon Energy, and MPLX LP reached final investment decision on construction of the Matterhorn Express Pipeline.
The pipeline, expected in service in third-quarter 2024 pending approvals, has been designed to transport up to 2.5 bcfd of natural gas through 490 miles of 42-in. pipeline from Waha, Tex., to the Katy area near Houston, Tex.
Supply will be sourced from upstream connections in the Permian basin, including direct connections to processing infrastructure in the Midland basin through a 75-mile lateral, as well as a direct connection to the 3.2 bcfd Agua Blanca pipeline, a joint venture of WhiteWater and MPLX.