GENERAL INTEREST Quick Takes
EOG signs deal for Oman Block 49 farm-in
EOG Resources Inc. subsidiary EOG Resources Oman Block 49 Ltd. agreed to acquire a 50% interest in the exploration and production sharing agreement (EPSA) covering Block 49 onshore Oman from Tethys Oil subsidiary Tethys Oil Montasar Ltd.
EOG also will have the option to assume operatorship of the block and increase its interest to 85% for any operation relating to unconventional hydrocarbon resources. The agreement is subject to government approval.
EOG will acquire access to the data from several thousand line-km of 2D seismic grids, two recently acquired seismic surveys (2D and 3D), nine exploration wells, plus additional geotechnical studies and reports. As consideration for both the 50% interest and access to data, EOG will refund all costs incurred on the block and fund the Thameen-1 exploration well, up to a combined amount of $15 million.
Tethys will continue as operator for the first exploration period including the drilling of the Thameen-1 well. Should EOG exercise its option to become operator and increase its interest to 85%, Tethys would retain 15%. The agreement includes consideration if the option is exercised and in the case of commercial development of unconventional hydrocarbon resources. The parties would each retain 50% of any operations relating to conventional hydrocarbon resources.
Tethys Oil acquired the 15,439-sq-km block in 2017 (OGJ Online, Nov. 13, 2017). After 3 years of seismic work, including reprocessing of older seismic data and processing and interpretation of seismic data from two new campaigns, Tethys is ready to drill Thameen-1. The well, to be drilled to 4,000 m depth to evaluate three portential reservoir targets, is expected to spud in mid-December 2020.
The block’s exploration phase has been extended by 1 year and runs until December 2021. EPSA holders can elect to enter into a second exploration phase of an additional 3 years.
Ilwella group to acquire Australian assets, operations from Tag Oil
Luco Energy Pty. Ltd., owned by Ilwella Pty Ltd. and AJ Lucas Services, agreed to acquire Australian assets and operations from Tag Oil Ltd.
The arm’s length transaction involves the sale by TAG Oil of the shares of its Australian subsidiary, Cypress Petroleum Pty Ltd., which holds the company’s 100% working interests in PL 17, ATP 2037, and ATP 2038 in the Surat basin of Queensland, Australia, to Luco. In the Surat basin, Tag holds production and exploration permits in acreage containing two undeveloped light oil fields and a deeper Permian play with unconventional tight gas-condensate play opportunities.
Closing of the deal is expected in this year’s fourth quarter, subject to certain customary conditions, including approval of the TSX Venture Exchange.
The deal includes a cash payment to TAG Oil of $2,500,000 (Aus.) at closing. TAG Oil will receive a 3% gross overriding royalty on future production from all liquids produced from the permits.
Zimmerman to succeed Fowler as LLOG COO
LLOG Exploration Co. LLC, Covington, La., has named Eric Zimmerman to succeed Rick Fowler, who will retire as chief operating officer effective Dec. 1, 2020.
Fowler joined LLOG in 2007 and has served as the company’s chief operating officer since 2018 (OGJ Online, July 26, 2018).
Zimmermann joined LLOG in 2007 and currently serves as vice-president of geology and business development. Prior to joining the company, his 20-year career included work for BP and Dominion.
Exploration & Development Quick Takes
Woodside awarded licenses over Scarborough field
Woodside Petroleum Ltd. has been granted two production licenses covering Scarborough gas field area on the Exmouth Plateau offshore Western Australia.
The licenses are a step forward in the delayed $17 (Aus.)-billion development project which proposes to pipe gas from Scarborough and surrounding fields to an expanded Pluto LNG plant on the Burrup Peninsula near Karratha in the state’s Pilbara region.
Woodside is operator with a 73.5% interest. BHP holds the remaining 26.5%.
A final investment decision, delayed by this year’s market volatility and the COVID-19 pandemic, is now expected during second-half 2021.
Acceptance of the new production licenses is a strong sign that the JV is committed to advancing the project, said Woodside Chief Executive Peter Coleman.
Together with the project’s recent environmental approval, Woodside has obtained key Commonwealth approvals required to support a final investment decision, he said.
The production licenses, about 375 km west-northwest of the Burrup, account for an estimated 11 tcf of gas resources.
Mosman discovers hydrocarbons in Falcon-1, East Texas
Mosman Oil and Gas Ltd. found hydrocarbons at the Falcon-1 well on the Champion Project in East Texas.
Wireline logs indicate good porosity and hydrocarbons in the primary and secondary Frio sandstone target zones interbedded with shale between about 7100-7550 ft TVD. The primary zone is about 90 ft thick. Mud logs also showed hydrocarbons in these zones with an increase in mud gas readings from a background of about 30 units to over 3000 units in the primary zone.
Casing will be run, and the well will be flow tested once the drilling rig is released and production testing equipment is on site.
Falcon-1 well is the first well that Mosman has participated in at Champion. Mossman has 60% working interest in the well and it is required to pay 80% to complete its acquisition, according to an August 2020 company presentation.
Equinor to drill Barents Sea well following minor Norwegian Sea discovery
Equinor Energy AS and PL 263 D license partners will plug and assess a minor Norwegian Sea discovery along with other discoveries and prospects in the vicinity to determine further follow-up. Preliminary estimates place the size of the discovery at 0.5-1.6 million std cu m recoverable oil equivalent.
Well 6407/1-8 S—the first in the license—was drilled by the West Hercules drilling rig in 295 m of water about 9 km east of Maria field and 210 km north of Kristiansund to a vertical depth of 3,518 m. It was terminated in the Ile formation from the Middle Jurassic age. The objective of the well was to prove petroleum in Garn and Ile formations.
The well was not formation-tested, but data acquisition was undertaken. About 85 m of reservoir rocks were encountered in Garn of moderate to very good reservoir quality, but the well is dry in Garn and Ile. The well encountered a 9-m gas column in the Lange formation from the Late Cretaceous age, in which there were three thin sandstone layers totaling 4 m with poor-to-moderate reservoir properties.
West Hercules will move to drill well 7018/5-1 for Equinor in PL 960 in the Barents Sea.
Equinor is operator of PL 263 D (60%) with partners Lime Petroleum AS (20%) and Pandion Energy (20%).
Central restarts Queensland Range gas project
Central Petroleum Ltd., Brisbane, has restarted its Range gas project in the Surat basin of southeast Queensland with its 50-50 joint venture partner Incitec Pivot Ltd.
Activities required to reach a final investment decision for the coal seam gas development include a 3-well appraisal pilot program with drilling scheduled to take place in first-half 2021 as well as approvals and permits for the development program. FID is targeted for end-2021 with development expected to immediately follow leading to first commercial gas production in 2023 for supply to Australia’s east coast markets.
The Range project will develop and produce 270 petajoules of 2C resources. Subject to pilot test results, conversion into 2P reserves is expected before FID.
Gas exploration in 2019 exceeded expectations, but the operational and financial uncertainty caused by the COVID-19 pandemic and a severe downturn in global energy markets prompted a pause in pre-FEED activities in March 2020.
The outlook has stabilized, and Central Petroleum has strengthened its financial flexibility with an extension of its debt facility and the signing of a new gas sale agreement, the company said.
The Range project covers 77 sq km and could see more than 140 producing wells over the life of the field, with gas processed on site and transported to market via a new pipeline connecting to the Roma-Brisbane trunkline or a tie-in to other nearby pipeline facilities.
Drilling & Production Quick Takes
Wintershall starts Nova field drilling
Wintershall Dea has begun drilling the first of six wells on Nova field in the Norwegian North Sea.
With most of the subsea work already complete and a dedicated module installed on the host platform, Gjøa, the start of drilling represents the beginning of the final major packet of work in the development of Nova field.
Scheduled to be on site for around 400 days, the Seadrill-operated West Mira rig will drill three production wells through one of two subsea templates, and three water injection wells, through the second.
Installation season began in March. In May, the manifolds were installed ahead of schedule. The topside module was installed on to the Neptune Energy-operated Gjøa platform in preparation for receiving oil and associated gas from the field (OGJ Online, May 11, 2020). This summer the risers, which connect the pipelines to the platform, were also put in place.
When it comes on stream in 2022, Nova will be the company’s fourth subsea field in production. First oil is unlikely in 2021, as earlier forecasted, due to the impact of COVID-19 on the topside part of the project.
Nova lies 120 km northwest of Bergen and 17 km southwest of the Gjøa platform in water depth of 370 m. The reservoir lies 2,570 m subsea.. Wintershall has a 28% interest in the Gjøa license. Gjøa will receive the production fluids and provide injection water and lift gas to Nova field. Oil from Nova will be transported from Gjøa through the Troll Oil Pipeline II to Mongstad, associated gas will be exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus in the UK, supplying the European energy market.
Wintershall is operator of Nova with 45%. Partners are Spirit Energy Norge AS 20%, Edison Norge AS 15%, Sval Energi AS 10%, and ONE-Dyas Norge AS 10%.
CNOOC begins Liuhua 29-1 gas field production
CNOOC Ltd. commenced production from Liuhua 29-1 gas field in the eastern South China Sea, 86 km northeast of Liwan 3-1 gas field, with water depth of 640-785 m. It is expected to reach a peak production of 62 MMcfd of natural gas in 2022.
A new subsea wellhead has been built, with seven development wells planned in total. The gas field will fully utilize existing production facilities of Liuhua 34-2 gas field and Liwan 3-1 gas field.
CNOOC Ltd. holds a 25% working interest in Liuhua 29-1 and acts as operator in shallow water. Husky Oil China Ltd. holds the remaining 75% interest and acts as operator in deep water.
Field startup is part of a plan announced in January 2020 by CNOOC to steadily increase its oil and gas reserves and production through 2022 (OGJ Online, Jan. 13, 2020).
DNO increases Kurdistan output
DNO ASA has increased Kurdistan output to 113,700 b/d in this year’s third quarter, resulting in 12% uplift in DNO-operated Tawke and Peshkabir fields from the prior quarter. The increase—the result of quick turnaround, low cost well interventions, and startup of the first enhanced oil recovery project in Iraq’s Kurdistan region—is reversing production declines triggered by oil market volatility in the wake of COVID-19, the company said Oct. 29 (OGJ Online, Mar. 19, 2020; May 27, 2020).
Both fields have outperformed expectations, and DNO projects replacement of a significant share of its reserves produced this year in Kurdistan, even as it scaled back drilling of new wells to meet a one-third budget reduction in response to lower oil prices and a 4-month payment hiatus in Kurdistan, the company said.
Across the portfolio, company working interest production in the third quarter increased 9% over the second quarter to 97,900 boe/d, of which Kurdistan contributed 80,200 b/d and the North Sea added 17,700 boe/d. DNO expects to exit the year with Kurdistan and North Sea production at third-quarter levels.
The Peshkabir-to-Tawke gas capture and reinjection project, in operation since mid-year, is continuing to cut gas flaring and greenhouse emissions by half at Peshkabir to 7 kg CO2 equivalent for each boe produced, while unlocking additional oil at Tawke, the company said (OGJ Online, July 30, 2020). To date, 2 billion cu ft of otherwise flared gas have been reinjected with positive reservoir response, adding up to 5,000 b/d.
Two exploration wells are scheduled for fourth-quarter 2020 with Polmak currently drilling in the Barents Sea (DNO 20%) and Røver Nord to spud shortly in the Northern North Sea (DNO 20%), the company said. The wells will be followed by an exploration program in 2021 that includes wildcat wells at Gomez in the Southern North Sea (DNO 85%) and Edinburgh cross-border (UK-Norway) in the North Sea (DNO 45%).
PROCESSING Quick Takes
BCC lets contract for Ust-Luga cracker complex
JSC RusGazDobycha subsidiary Baltic Chemical Complex LLC (BCC), through its contractor, has let a contract to McDermott International Ltd. to provide additional services for BCC’s $13-billion ethane cracking project under construction on the Gulf of Finland near Ust-Luga, in Russia’s Leningrad region (OGJ Online, June 10, 2020; Apr. 2, 2019).
As part of the contract—awarded directly by project contractor China National Chemical Engineering & Construction Corporation Seven Ltd. (CC7)—McDermott will deliver the engineering and procurement early works package for all schedule critical equipment for the project, the service provider said on Nov. 9.
While it disclosed neither a value nor timeframe for its work under the agreement, McDermott did confirm it will execute the early works package from the company’s offices in The Hague and Brno, Czech Republic.
This latest contract follows and expands CC7’s earlier award to McDermott in 2019 for extended basic engineering on the BCC project (OGJ Online, Nov. 18, 2019).
BCC, through CC7, most recently awarded a contract to McDermott partner Lummus Technology LLC to deliver engineering design and supply of 14 of its proprietary Short Residence Time (SRT) VI cracking furnaces for the complex’s two ethylene crackers that, combined, will produce up to 3 million tonnes/year of ethylene product (OGJ Online, Nov. 2, 2020).
First announced in 2019 and slated to become the largest ethylene integration project in the world once completed, the natural gas processing chemical plant will include two ethylene cracking sites—each with a capacity of 1.4 million tpy—six polyethylene trains with a combined processing capacity of 480,000 tpy, and two linear alpha olefin plants with a combined capacity of 137,000 tpy.
Construction work on the integrated complex—which will process ethane-containing gas from PJSC Gazprom’s production fields—currently is proceeding according to schedule, RusGazDobycha said in September.
The complex is due to be completed in two phases, with Phase 1 commissioning planned for fourth-quarter 2023 and Phase 2 startup to follow in fourth-quarter 2024.
DRPIC lets contract for Duqm integrated complex
Duqm Refinery & Petrochemical Industries Co. LLC (DRPIC), Muscat—a joint venture of state-owned OQ SAOC (OQ) and Kuwait Petroleum Corp. subsidiary Kuwait Petroleum International Ltd. (Q8)—has let a contract to Univation Technologies LLC to license technology for a new polyethylene (PE) unit at the petrochemical portion of DRPIC’s long-planned 230,000-b/d integrated refining complex under construction in the Duqm Special Economic Zone (SEZAD) in Duqm, Al Wusta Governate, on Oman’s southeastern coast along the Arabian Sea, about 600 km south of Muscat (OGJ Online, Oct. 2, 2019; Oct. 8, 2018).
As part of the contract, Univation Technologies will license its proprietary UNIPOL PE process and associated ACCLAIM High-Density PE (HDPE) catalyst technology for a 480,000-tonne/year line with the flexibility to shift between production of high-performance unimodal HDPE resins and linear low-density PE (LLDPE), the service provider said.
The flexible production capabilities of the UNIPOL PE process line comes as a key component of DRPIC realizing its objective to become a major player in the region by satisfying evolving customer demand for PE products in both domestic and key international markets, said Dr. Salim Al Huthaili, DRPIC’s chief executive officer.
Univation Technologies disclosed neither a value of the contract nor a timeframe for its work on the project.
This latest contract follows DRPIC’s recent award to Lummus Technology LLC to deliver proprietary licensing technology and the process design package for the complex’s 1.6-million tpy ethylene unit, NGL extraction units, a butadiene extraction unit, and a combined methyl tertiary butyl ether (MTBE)-1-Butene separation unit (OGJ Online, Sept. 23, 2020).
Primarily designed to produce and recover naphtha, jet fuel, diesel, and LPG, the Duqm refinery will include units for hydrocracking, hydrotreating, delayed coking, sulfur recovery, hydrogen generation, and Merox treating.
As of Sept. 25, 2020, the nearly $6-billion refinery project was 70.5% completed, DRPIC said in an Oct. 19 video post to its official YouTube account.
DRPIC most recently said it hopes to launch preliminary test runs at the refinery site by yearend 2021.
TRANSPORTATION Quick Takes
Topsides shipment sails for Eni’s Area 1 GoM FPSO
Eni SPA contractor McDermott International Ltd. has shipped its second and final group of topsides modules to Modec Inc. for the Miamte MV34 floating production, storage, and offloading (FPSO) vessel. Miamte will be stationed at Eni’s Area 1 development in the Bay of Campeche, 10 km off the coast of Mexico in 105 ft of water.
The modules will travel from McDermott’s Altamira, Mexico, fabrication yard to Singapore where integration will be performed at Dyna-Mac Engineering Services Pte. Ltd.’s fabrication yard. The shipment comes just weeks after the first modules sailed from Altamira.
The FPSO will treat 90,000 b/d of crude oil and 75 MMcfd of gas. It will be able to inject 120,000 b/d of water and will store up to 900,000 bbl of oil. First production is planned for 2021.
Modec is responsible for engineering, procurement, construction, mobilization, and operation of FPSO Miamte, including topsides processing equipment as well as hull and marine systems. This most recent topsides shipment includes modules that will provide inlet separators, oil separation, a flare knockout drum, and sand cleanup materials for the FPSO. Sofec Inc., a Modec group company, will design and install the FPSO’s disconnectable tower yoke mooring system.
Modec will own FPSO Miamte and provide operations and maintenance services for 15 years, with the option of 1-year extensions for a further 5 years.
Adelphia Gateway pipeline receives FERC clearance
Adelphia Gateway LLC has received US Federal Energy Regulatory Commission (FERC) partial notice to proceed with Phase 1 construction of its natural gas pipeline project and has begun preconstruction mobilization.
Phase 1 work in portions of Delaware, Chester, Bucks, and Montgomery Counties, Pa., includes conversion of the southern 50 miles of Adelphia Gateway’s existing 84-mile pipeline from oil to natural gas service. Upon completion of the conversion and enhancements, the southern portion of the pipeline will be able to transport 250 MMcfd. The northern 34 miles of the pipeline, from western Bucks County to the Martins Creek terminal in Northampton County, have delivered natural gas since 1996.
In 2019, FERC issued its certificate of public convenience and necessity and completed environmental assessment of the Adelphia Gateway project (OGJ Online, Dec. 20, 2019). Recently, the Pennsylvania Department of Environmental Protection issued the necessary permits and approvals for Phase 1 construction.
Adelphia Gateway expects the southern portion of the Adelphia Gateway pipeline to be placed into service in 2021 to the greater Philadelphia area.
Double E natural gas pipeline approved by FERC
Summit Midstream Partners LP’s (SMLP) Double E Pipeline LLC, a joint venture in which SMLP owns a 70% operating interest, has received US Federal Energy Regulatory Commission (FERC) approval to build and operate its 1.35-bcfd Double E Pipeline. Double E will deliver natural gas from Delaware basin in southeast New Mexico and west Texas to delivery points near Waha in Reeves and Pecos Counties, Tex.
Upon fulfilling certain remaining requirements, including finalizing a right-of-way grant from the Bureau of Land Management and filing an implementation plan with FERC, Double E expects to receive FERC’s notice to proceed with construction. This notice is expected within the next 90 days.