GENERAL INTEREST Quick Takes
ExxonMobil increases participation in Scotland CCS project
ExxonMobil has increased its participation in the proposed Acorn carbon capture project in Scotland by signing an expression of interest to capture, transport, and store CO2 from its Fife ethylene plant.
The agreement to include the ethylene plant, in Mossmorran, Scotland, is in addition to a memorandum of understanding to capture and store emissions from gas terminals at the St Fergus complex at Peterhead, Scotland, which includes ExxonMobil’s joint venture gas terminal (OGJ Online, July 16, 2021).
Acorn CCS repurposes existing gas pipelines to take CO2 directly to the offshore Acorn CO2 storage site. The project plans to capture and store some 5-6 million tons/year (tpy) of CO2 by 2030.
Acorn can potentially store more than half of the UK government’s targeted 10 million tpy CO2 storage, and when expanded has the potential to store more than 20 million tpy by mid-2030.
The Acorn project recently announced plans to capture and store CO2 from the Grangemouth refinery, and the addition of Mossmorran infrastructure will help Scotland reduce emissions in its industrial sector (OGJ Online, Sept. 23, 2021).
The Fife Ethylene plant recently completed a $170 million investment program to upgrade key infrastructure and introduce new technologies to improve operational reliability and performance (OGJ Online, Sept. 25, 2019). A further project is under way to install an enclosed ground flare. On schedule to be operational by end 2022, the unit is designed to reduce noise, light, and vibration, and it is estimated the investment will reduce the use of the plant’s elevated flare by at least 98%.
QatarEnergy enters offshore Atlantic exploration in Canada
QatarEnergy signed an agreement with ExxonMobil Canada to farm into an exploration license offshore the province of Newfoundland and Labrador in Canada.
QatarEnergy will hold a 40% participating interest in license EL 1165A, where the Hampden exploration well activities are planned. The remaining interest is held by ExxonMobil Canada. The block covered by the license lies about 450 km east of St. John’s in Newfoundland and Labrador, in water depths of about 1,100 m.
The transaction has received all necessary consents from the Canada- Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB).
Viaro closes deal for UK North Sea producing assets
Viaro Energy, through its wholly owned subsidiary RockRose Energy, closed an acquisition of producing assets in the UK North Sea from SSE for $164 million with an additional contingent payment of $54 million.
The portfolio comprises non-operated interests in over 16 producing gas fields in three regions: the Easington Catchment area, the Bacton Catchment area, and the Greater Laggan area. The assets are expected to produce over 15,000 boe/d in 2021.
SSE will continue to provide decommissioning security for the assets and will retain an obligation to pay 60% of the decommissioning costs when they are incurred.
Viaro acquired RockRose for $330 million in 2020 and later acquired HALO’s interest in the Netherlands in May 2021.
Viaro produces about 33,000 boe/d from more than 36 producing oil and gas fields on the UK Continental Shelf and the Netherlands and is targeting 100,000 boe/d, the company said in a release Oct. 15.
Exploration & Development Quick Takes
Equinor discovers oil at Egyptian Vulture in the Norwegian Sea
Equinor Energy AS discovered oil at Egyptian Vulture exploration well 6407/1-9 in production license (PL) 939, 20 km from Åsgard field and 23 km from Kristin field in the Norwegian Sea (OGJ Online, June 16, 2021).
The well is the second in a seven-well exploration program. It was drilled to 3,936 m total vertical depth, and the top of the reservoir was reached close to prognosis at 3,684 m vertical depth below sea level with 13 m net sand in a 37 m oil filled gross interval. The well encountered light oil in the primary target in the Lower Cretaceous (Cenomanian) Intra-Lange formation.
The upper part of the Lange sand interval has a high net to gross ratio and porosity of about 16%. Data acquisition and sampling have been carried out and the preliminary analysis of the oil sample indicates a very light oil. The oil-water contact was not encountered. The well will be plugged.
Egyptian Vulture recoverable resource preliminary estimate is 19-63 MMboe (gross), and the oil-in-place volume has been estimated at 220-440 MMboe (gross). Further appraisal will be required to understand the flow potential of the reservoir and future development wells.
Equinor is operator at PL 939 (55%) with partners Longboat Energy Norge AS (15%), and PGNiG Upstream Norway AS (30%).
Santos plans Ashmore Cartier exploration drilling
The Santos Ltd.-SapuraOMV joint venture received approval from Australia’s National Offshore Petroleum Safety and Environmental management Authority (NOPSEMA) to begin preliminary survey work surrounding its proposed Stairway-1 wildcat location in Ashmore Cartier permit AC/P50 in the western sector of the Timor Sea.
The work program includes geophysical and hydrographic surveys to determine seabed and environmental conditions in the general area around the proposed well site.
The location is 650 km west of Darwin and about 200 km from the closest shoreline. AC/P50 adjoins Jadestone’s producing Montara group oil fields to the southwest.
Water depths are 80-100 m.
Survey work is expected to take place before end 2022 with the Stairway-1 wildcat to be drilled in 2023-2024 depending on rig availability.
OGDCL discovers gas in Jandran exploration, Pakistan
Oil and Gas Development Co. Ltd. (OGDCL) discovered gas in the Mughalkot formation at the Jandran West X-1 exploration well in District Kohlu, Balochistan province, Pakistan.
The well was spudded May 19 and was drilled to a depth of 1,627 m into the Parh formation. Based on good gas shows during drilling and interpretation of open hole log data, a drill stem test was performed in the Mughalkot formation. The well tested 2.391 MMscfd gas with traces of condensate with well head flowing pressure of 455 psi on a 32/64-in. choke.
OGDCL previously discovered gas with Jandran X-04 in the license (OGJ Online, May 17, 2021).
OGDCL is operator of the license with 100% ownership.
Lundin drills dry well southwest of Stavanger
Lundin Energy Norway AS drilled a dry hole in production license (PL) 976, about 70 km southeast of Johan Sverdrup field in the North Sea and 140 km southwest of Stavanger in 119 m of water. Data acquisition was carried out, and the well will be permanently plugged.
Well 17/8-1 was drilled by the Deepsea Stavanger drilling rig to a vertical depth of 2,891 m below sea level. It was terminated in rocks from the Paleozoic Era.
The primary exploration target was to prove petroleum in sandstone in the Sandnes formation from the Middle Jurassic. The secondary exploration target was to prove petroleum in carbonate rocks in the Zechstein Group and possible sandstone in the Rotliegend Group, both from the Permian.
The well encountered 18 m of the Sandnes and Bryne formation from the Middle Jurassic, 10 m of which were sandstone with good reservoir quality. In the secondary exploration target, the well encountered about 70 m of tight carbonate rocks in the Zechstein Group. The Rotliegend Group is most likely not present in the well, but it did encounter about 60 m of tight clastic rocks from the Paleozoic Era.
The well also encountered about 200 m of the Skagerrak and Smith Bank formation (Triassic), a total of about 120 m of which were sandstone with poor to moderate reservoir quality.
Deepsea Stavanger will now drill wildcat well 24/12-7 in production license 1041 in the North Sea, where Aker BP ASA is operator.
Lundin is operator at PL 976 (40%) with partners ONE-Dyas Norge AS (10%), Petoro AS (20%), and Repsol Norge AS (30%).
Drilling & Production Quick Takes
Repsol Norge achieves first oil from Yme field restart
Repsol Norge has achieved first oil from the Yme field restart after it was shut down in 2001 in response to low oil prices (OGJ Online, Aug. 11, 2021).
Yme includes production license (PL) 316 and PL 316 B in the southeastern part of the Norwegian North Sea in Block 9/2 and 9/5 in Egersund basin, 130 km from the Norwegian coastline. Expected recoverable reserves in Yme are estimated to about 10 million std cu m oil (63 million bbl). At plateau, the field will produce around 56,000 boe/d.
Earlier this year, the Yme license entered into an agreement to acquire the Mærsk Inspirer jack up through a bareboat charter agreement with Havila Sirius AS and takeover of day-to-day operations of the rig from Maersk Drilling. The handover process has begun and is expected to close in the fourth quarter.
Repsol is operator (55%) with partners Lotos Exploration and Production Norge AS (20%), OKEA ASA (15%), and Kufpec Norway AS (10%).
BW Energy concludes Tortue Phase 2 project in Gabon
BW Energy Ltd. hooked up the final two production wells, DTM-6H and DTM-7H, in the Dussafu Marin license offshore Gabon and has completed handover of production operations, concluding the Tortue Phase 2 project.
Gambia eell DTM-7H was brought online on Oct. 19. DTM-6H, in the Dentale formation, was scheduled to come onstream days after. Production prior to the two new wells is around 11,500 b/d.
The Tortue development consists of six production wells tied back to the BW Adolo FPSO (OGJ Online, May 10, 2021). Completion of DTM-6H and DTM-7H was suspended last year due to the COVID-19 pandemic.
Gross production from Tortue field averaged about 9,000 b/d in third-quarter 2021, amounting to a total gross production of 800,000 b/o for the period. The decrease in production compared to second-quarter 2021 was mainly due to plant shutdowns and temporary operational issues, the company said. A shortage of gas lifting capacity also impacted production. A nitrogen generation unit has been installed on BW Adolo to improve production efficiency, the company said.
BW Energy had a cash balance of $170 million at Sept. 30 compared to $216 million at June 30. The decrease is mainly due to investment activities related to Tortue Phase 2, progress on the Hibiscus-Ruche project, as well as completing the exploration drilling campaign in Dussafu.
BW Energy is operator of the 850-sq km Dussafu block with 73.5% interest. Panoro Energy holds 17.5% and the Gabonese Oil Co. holds 9%.
Matador operating fifth drilling rig in New Mexico
Dallas-based Matador Resources Co. and San Mateo Midstream LLC—the company’s 51%-owned midstream joint venture with Houston private equity firm Five Point Energy LLC (49%)—began operating a fifth drilling rig in August to drill an additional salt water disposal well in the Greater Stebbins area in Eddy County, NM.
The well and associated facilities are needed and expected to handle additional produced water volumes anticipated from Matador’s increased drilling and completions activity in the area this year, the company said in a release Oct. 20. Matador expects to turn to sales nine wells in the area during this year’s fourth quarter.
Drilling operations were completed in late September. The well is currently undergoing completion operations.
Matador’s portion of San Mateo’s capital expenditures was about $15 million for third-quarter 2021, including the drilling costs associated with the new salt water disposal well, about 6% below the company’s estimate of $16 million for the third quarter.
Matador contracted the fifth operated drilling rig for 6 months. As a result, in early October, following the conclusion of drilling operations on the salt water disposal well, Matador moved the rig to its Rodney Robinson leasehold in the western portion of the Antelope Ridge asset area in Lea County, NM. The company is currently running two rigs on the leasehold and expects to drill nine new wells there during fourth-quarter 2021. These nine Rodney Robinson wells are expected to be completed in January and February 2022 and turned to sales before the end of first-quarter 2022.
Matador incurred capital expenditures for drilling, completing, and equipping wells of about $121 million, about 14% below the company’s estimate of $140 million for these expenditures for third-quarter 2021.
Equinor to drill four wells on Statfjord Øst
Equinor Energy AS and partners have agreed to drill four new wells on Statfjord Øst in the Tampen area in the North Sea, 7 km northeast of Statfjord field in 150-190 m of water.
The field has been developed with two subsea production templates and one water injection template, tied back to the Statfjord C platform. In addition, two production wells have been drilled from Statfjord C.
Startup is planned for spring 2023, and the COSLPromoter rig has been contracted. In addition to the four wells on Statfjord Øst, the rig also has options for drilling five wells for Statfjord satellite fields. The contract value is about $56 million for the fixed part of the agreement, estimated to last for 220 days.
Equinor is operator (31.6875%) with partners Petoro AS (30%), Vår Energi AS (20.55%), Spirit Energy Norway AS (11.5625%), Idemitsu Petroleum Norge AS (4.8%), and Wintershall Dea Norge AS (1.4%).
PROCESSING Quick Takes
RusGazDobycha’s Baltic Chemical lets additional contract for Ust-Luga complex
JSC RusGazDobycha subsidiary Baltic Chemical Complex LLC (BCC), through its contractor, has let a contract to McDermott International Ltd. to provide additional works for BCC’s $13-billion ethane-cracking complex, or gas chemical complex (GCC) portion, of the larger PJSC Gazprom-RusGazDobycha combined gas processing, liquefaction, and chemical complex for processing ethane-containing gas (CPECG) under construction at the Gulf of Finland near the seaport of Ust-Luga, Leningrad Oblast, Russia.
As part of a letter of guarantee for the Oct. 18 contract—awarded directly by CPECG’s main project contractor China National Chemical Engineering & Construction Corp. Seven Ltd. (CC7)—McDermott will provide complete project management as well as engineering and procurement services, including field engineering, author supervision, and supply of equipment and materials for the two-train 2.8-million tonnes/year ethane cracker unit featuring ethylene steam-cracking process technology licensed by Lummus Technology LLC, McDermott said.
This latest agreement follows McDermott’s delivery of the front-end engineering design and early works phases of the project, the service provider said.
Alongside BCC’s GCC, the CPECG—which officially began construction in May—also includes RusKhimAlyans’—a 50-50 special-purpose venture of Gazprom and RusGazDobycha—integrated natural gas processing and liquefaction complex (GPC of the CPECG), which will have 13-million tpy liquefaction capacity and initially process 45 billion cu m/year (bcmy) of wet natural gas feedstock it receives from Gazprom’s Achimov and Valanginian deposits in the Nadym-Pur-Taz region of the Yamal Peninsula.
The GPC will produce as much as 4 million tpy of ethane, and more than 2.2 million tpy of LPG, with ethane from the complex to feed nearby BCC’s $13-billion ethane cracking project that—once in operation—will produce more than 3 million tpy of polymers. About 18 bcmy of gas remaining after processing at GPC—including ethane extraction, LPG, and 13 million tpy of LNG—will be exported from the site via Gazprom’s gas transmission lines.
In September, RusKhimAlyans also let a contract to a consortium of Linde PLC’s Linde Engineering and Rönesans Holding’s Renaissance Heavy Industries to deliver engineering, procurement, and construction services on the GPC of the CPECG.
RusGazDobycha said it expects to complete first-phase construction of the GCC during fourth-quarter 2023, with second-stage construction to wrap in fourth-quarter 2024.
Morgan Stanley: Downstream recovery begins
With commodity prices rising, downstream margins improving, and spending holding steady, free cash flow (FCF) is set to rise sharply off a strong base for US majors and Canadian energy, according to research from Morgan Stanley.
In first-half 2021, the North American integrated oil sector generated the highest FCF in over a decade, even eclipsing years in the early 2010s when oil was above $100/bbl. These results, aided by cost reductions and spending discipline, were delivered despite continued weakness in downstream margins. Now, downstream margins have begun to recover as well, supporting strong third-quarter results, and underpinning further upside into 2022, Morgan Stanley continued.
On the back of continued inventory draws and improving mobility statistics, Brent finished the third quarter at an average $73/bbl, up 6% quarter-on-quarter (q-o-q). In Canada, WTI-WCS differentials were roughly flat q-o-q at $13/bbl, supporting realizations.
On the downstream side, jet fuel demand continues to lag but the crack spreads are improving. In the US, jet fuel demand continues to lag at around 90% of 5-year average levels, vs. gasoline and distillate which have fully recovered. That said, cracks have continued higher. In the US Gulf Coast, cracks were up about 11% q-o-q, while cracks in Europe were up 16%. In the midcontinent—generally more indicative of profitability for Canadian refineries—cracks were up 5%. Together, Morgan Stanley expects this to drive an improvement in downstream earnings before interest, taxes, depreciation, and amortization of 60% for its covered group.
For chemicals, polyethylene-ethylene margins in the US were up 10% q-o-q, compared to an 18% decline q-o-q in Europe and an 80% decline in Asia.
TRANSPORTATION Quick Takes
EIG to acquire 10% stake in Australia Pacific LNG
EIG has agreed to acquire a 10% interest in Australia Pacific LNG Pty Ltd. (APLNG) from Origin Energy Ltd. for an equity purchase price of $1.592 billion.
Australia Pacific LNG is the largest LNG project by liquefaction capacity on Australia’s eastern seaboard and a major supplier of LNG to Asia and gas to Australia’s domestic market, EIG said in a release Oct. 25.
The project, in Gladstone, Queensland, holds nameplate capacity of 9 million tonnes/year and holds a large acreage position spanning the Surat and Bowen basins, providing long-life reserves, the institutional investor continued.
Australia Pacific LNG is operated by ConocoPhillips (downstream) and Origin Energy (upstream) and maintains long-dated LNG contracts with Sinopec and Kansai Electric.
As part of the transaction, EIG will have the right to nominate one member to Australia Pacific LNG’s board of directors.
The transaction has received approval from the Australian Foreign Investment Review Board and is subject to the waiving of pre-emptive rights by ConocoPhillips and Sinopec, as well as other customary completion conditions.
Cheniere enters Corpus Christi Stage 3 offtake agreement with Glencore
Cheniere Energy Inc. subsidiary Cheniere Marketing LLC has entered into a binding 13-year agreement to sell 0.8 million tonnes/year (tpy) of LNG to a subsidiary of Glencore PLC. Glencore will buy the LNG on a free-on-board Henry Hub-indexed basis starting in April 2023.
Cheniere is in the process of contracting capacity in advance of a 2022 final investment decision (FID) on its 10-million tpy Corpus Christi Stage 3 project. Corpus Christi Stage 3 will include as many as seven midscale liquefaction trains and has received all necessary regulatory approvals.
Assuming Cheniere takes FID on Stage 3, it plans to build a new bidirectional natural gas pipeline to deliver feed gas to it.
The company put the third train of its initial Corpus Christi LNG development stages into service earlier this year, bringing the plant’s total capacity to 15 million tpy (OGJ Online, Mar. 29, 2021).
Petrobras lets contract for pipelay support vessel
Petrobras has let a long-term charter and services contract to TechnipFMC for the Coral do Atlântico pipelay support vessel.
The Brazilian-registered vessel has been secured on a 3-year contract, with an option to extend. Operations offshore Brazil are expected to begin in second-quarter 2022.
Coral do Atlântico—the third TechnipFMC pipelay support vessel to be contracted via a long-term charter by Petrobras this year—will mainly be deployed in ultra-deepwater of up to 3,000 m, but can work in deep or shallow water, the service provider said.
The contract is valued by TechnipFMC at $250-500 million.