GENERAL INTEREST Quick Takes
Baytex adds operated Eagle Ford assets in $2.5-billion deal to acquire Ranger Oil
Baytex Energy Corp., Calgary, has agreed to acquire Ranger Oil Corp., Houston, a pure play Eagle Ford company, in a cash and stock transaction totaling about $2.5 billion including debt assumption of about of $650 million.
The deal sees Baytex acquire operating capability in the Eagle Ford, on-trend with its non-operated position in the Karnes Trough, building a diversified oil-weighted portfolio when combined with its Western Canadian Sedimentary basin assets, said Eric T. Greager, president and chief executive officer of Baytex, in a release Feb. 28.
The Ranger inventory immediately competes for capital, with about 741 net undrilled locations representing 12-15 years of oil-weighted drilling opportunities, according to Baytex. Inventory includes 523 quality Lower Eagle Ford opportunities and 218 additional Upper Eagle Ford and Austin Chalk opportunities, Baytex said. The company believes it can grow production modestly from the acquired assets with two rigs and about 50-55 net wells/year.
In all, Ranger brings 162,000 net acres in the crude oil window of the Eagle Ford shale, highly concentrated in Gonzales, Lavaca, Fayette, and Dewitt counties in Texas, and production of 67,000-70,000 boe/d (working interest) that is 96% operated (72% light oil, 15% NGLs, 13% natural gas).
Baytex’s production is forecast to average 155,000-160,000 boe/d (52% light oil, 22% heavy oil, 11% NGLs, 14% natural gas) for the 12-month period following closing, which is expected late in this year’s second quarter. Prior to the deal, Baytex reported full year 2022 average production of 83,519 boe/d (84% oil and NGL), a 4% increase over 2021.
Shell Petroleum acquires Europe’s largest RNG producer
Shell Petroleum NV, a wholly owned subsidiary of Shell plc, closed a deal to acquire Nature Energy Biogas A/S, the largest producer of renewable natural gas (RNG) in Europe, for a total enterprise value of nearly $2 billion.
Nature Energy established its first biogas plant in Denmark in 2015 and now has 14 operating plants with associated infrastructure, feedstock arrangements, and 2022 production of about 3,000 boe/d.
The company also has a pipeline of around 30 new plant projects in Europe and North America. Over one-third are in medium to late development stage in Denmark, the Netherlands, and France and could deliver up to 4,400 boe/d by 2030, subject to future final investment decisions and relevant regulatory approvals, Shell said.
RNG, also known as biomethane, is chemically identical to conventional natural gas and can be used in existing transmission and distribution infrastructure, making it a competitive option to help decarbonize multiple hard to abate sectors, Shell said.
Shell has an existing RNG production business in North America, with one operational site and three under construction. Shell also has an existing RNG trading portfolio in Europe.
Nature Energy will operate as a wholly owned subsidiary of Shell, initially under its existing brand.
New Sunrise concept study may lead to development
Woodside Energy Ltd. will begin a new concept selection study related to potential development of the Sunrise-Troubadour gas-condensate fields that lie primarily in East Timor waters.
The fields, discovered in the mid-1970s, lie 450 km northwest of Darwin and 150 km south of East Timor. They contain 2C contingent resources of about 5.3 tcf of gas and about 225 million bbl of condensate.
The study will include the potential for siting a gas processing plant in East Timor, a move long opposed by Woodside due to the perceived economic and technical challenges of constructing a pipeline crossing the Timor Trench and building a grassroots LNG plant in East Timor.
Woodside said recently, however, that it will consider elements for delivering and processing the gas in East Timor compared with sending the gas to Darwin for processing.
The advent of new technologies, including the potential for modular LNG, along with the increasing demand for LNG, has prompted the new study.
The study will incorporate and update previous technical work and cost estimates while also evaluating the socio-economic, safety, environmental, and capacity factors as well as strategic and security benefits of the various options.
While no timetable has been disclosed, Woodside said the study will be carried out expeditiously.
Woodside is operator of the Greater Sunrise joint venture with 33.44% interest. East Timor national petroleum company Timor GAP holds 56.56% and Osaka Gas Australia holds the remaining 10%.
Exploration & Development Quick Takes
Equinor lets contracts for work offshore Norway
Equinor Energy has let contract to Subsea7 SA for Irpa and Verdande field developments in the Norwegian Sea.
The two projects will be executed via consortium of Subsea7 and DeepOcean.
The Irpa project, in the Aasta Hansteen area at 1,350 m water depth, involves a subsea tieback of about 80 km to the Aasta Hansteen FPSO. Contract scope includes engineering, transportation, and installation of a MEG pipeline, a production riser, umbilical, subsea structures, and tie-ins.
The Verdande project, in the Nordland Ridge area, involves a subsea tieback to existing Skuld field and Norne FPSO infrastructure. Contract scope includes engineering, transportation, and installation of a 7.5-km pipe-in-pipe production pipeline, umbilical, flexibles, subsea structures, and tie-ins.
Project management and engineering will begin immediately at Subsea7’s offices in Stavanger, Norway. Fabrication of the pipelines will take place at Subsea7’s spoolbase at Vigra, Norway, and offshore operations are expected to take place in 2024, 2025, and 2026 using both Subsea7’s and DeepOcean’s fleet of vessels.
Subsea7 puts its share of the contract somewhere between $50-150 million.
Cooper slows Otway gas project FID
Cooper Energy Ltd., Adelaide, delayed a final investment decision (FID) on a new phase of gas development and exploration in the offshore Otway basin off Western Victoria.
The proposed $400 million (Aus.) Otway Phase 3 Development (OP3D) revolves around work in the Casino-Henry operations and the Athena onshore gas plant near Port Campbell.
Cooper said FID timing, originally set for April or May, with first production targeted for 2025, is now subject to finalization of proposed Federal Government changes to gas pricing surrounding a regulated $12 (Aus.) per gigajoule price cap legislated in mid-December 2022.
A gas sales agreement for OP3D was signed with AGL Energy Ltd. in November to supply AGL with up to 10 petajoules/year of gas for up to 6 years. The agreement includes supplying an initial 8 petajoules/year of the contracted volumes from the new Annie gas field for the first 3 years and then moving into the field’s declining tail.
The government is consulting the industry on the ‘reasonable price’ provision in the mandatory code of conduct that will require gas producers to contract at a reasonable rate.
Although Cooper has signed the agreement with AGL for gas from OP3D, the government’s proposed code allows a customer to challenge the terms with any resulting arbitration settled on the ‘reasonable pricing’ basis.
Cooper said it decided to await the changes so that it can reconfirm the project economics and ensure alignment with its joint venture partner Mitsui.
Cooper is operator and 50% interest holder in Casino-Henry operations and the Athena plant. Mitsui holds the remaining 50%.
Equinor lets Snøhvit Future EPCI contract
Equinor Energy AS has let an engineering, procurement, construction, and installation (EPCI) contract to Aibel for Hammerfest LNG modifications in connection with the Snøhvit Future project.
The contract, an option in the FEED contract awarded to Aibel in September 2020, is for two new processing modules related to the onshore compression and electrification of the Melkøya plant. Aibel will also build a new receiving station for power from shore, carry out integration work at the plant, and carry out further upgrades of existing systems at Hammerfest LNG to make the plant more resilient for extended life until 2050. The contract is subject to governmental approval of the project.
Snøhvit field lies in Hammerfest basin, southern Barents Sea, in 310-340 m of water. Snøhvit Future consists of online compression and electrification of Hammerfest LNG at Melkøya. As the pressure drops in the reservoirs, compression is required to ensure sufficient flow of the gas to the plant. The project will extend plateau production while reducing CO2 emissions from the plant by 850,000 tonnes/year.
Equinor is operator (36.79%) with partners Petoro AS (30.00%), TotalEnergies EP Norge AS (18.40%), Neptune Energy Norge AS (12.00%), and Wintershall Dea Norge AS (2.81%).
Drilling & Production Quick Takes
TotalEnergies to drill appraisals offshore Namibia
TotalEnergies SE will start a multi-well drilling program offshore Namibia following the Venus light oil discovery in Block 2913B (PEL 56), according to a Feb. 22 release by Impact Oil & Gas Ltd.
The Venus discovery is in Orange basin, about 290 km off the coast of southern Namibia in about 3,000 m of water. The Venus-1X discovery well was drilled to 6,296 m TD by the Maersk Voyager drillship and encountered a high-quality light oil-bearing sandstone reservoir of Lower Cretaceous age.
Drilling of Venus-1A, the first discovery appraisal well, will be drilled by the Tungsten Explorer drillship about 13 km north of Venus-1X. Deepsea Mira will then be used to conduct a drill stem test.
Deepsea Mira will then re-enter and side-track Venus-1X and conduct a flow test. The objective is to further evaluate the Venus reservoir and deliver dynamic data.
TotalEnergies and partners will also explore the Venus accumulation into Block 2912 (PEL 91) to provide an understanding of the structure and reservoir quality. The block is offshore southern Namibia adjacent to, but outboard of, PEL 56 and covers about 7,884 sq km in water depths of 3,000-3,900 m.
Drilling operations will begin mid-2023 with exploration well Nara-1X. The well will be drilled and flow tested by the Tungsten Explorer and, if successful, appraisal well Nara-1A will be drilled and flow tested.
TotalEnergies EP Namibia BV is operator of PEL 56 (40%) with partners Impact Oil and Gas Namibia (Pty) Ltd. (20%), QatarEnergy (30%), and NAMCOR (10%).
TotalEnergies is operator of PEL 91 (37.78%) with partners Impact (18.89%), QatarEnergy (28.33%), and NAMCOR (15%).
Santos given environmental go-ahead for Queensland CSG drilling
Santos Ltd., Adelaide, has received environmental approval from the Australian Government to drill development wells in its Towrie coal seam gas (CSG) project in central east Queensland.
The project will consist of 116 CSG wells in an area of 87,000 hectares in the Surat basin about 50 km north of Injune and 350 km southeast of Gladstone.
The project will supply gas feedstock to Santos’s Gladstone LNG plant on Curtis Island.
The project is expected to have a life of around 30 years.
TMK Energy to drill for Mongolian coal seam gas
TMK Energy Co. has let a drilling contract to the Mongolian operating subsidiary of Major Drilling Group International Inc. for TMK’s pilot well program at the Gurvantes XXXV coal seam gas (CSG) project in Mongolia.
The program proposes three production wells near the Snow Leopard-02 (SL-02) exploration well. Results from SL-02 have been integrated into modeling work undertaken by SLB which has shown positive indications on both early gas breakthrough and production rates, the company said in a release Feb. 15. The modeling work suggests a high degree of confidence that the upcoming program will deliver a proof of concept and gas flow to surface at relatively high production rates compared to CSG wells globally, the company continued.
The program is expected to take about 8 weeks for drilling completion and pumps installation. The wells will be tied into the surface infrastructure, which includes metering skids, a flare stack, and water disposal system. The pumps will then start pressure drawdown prior to gas breakout. Once commissioned, the pilot wells will be operated for about 6 months to gain understanding of water and gas production profiles.
Work is under way to determine if there is an economical and environmentally sensible way to utilize gas produced to surface during early stages of the production test rather than flaring, TMK said.
Drilling operations are to begin in April, with preparation of drilling locations, site works, and purchase of long lead items (currently in transit to site) already under way.
PROCESSING Quick Takes
CNOOC-Shell JV lets contract for Huizhou Phase 3 ethylene expansion
Shell PLC subsidiary Shell Nanhai BV and China National Offshore Oil Corp. (CNOOC) have let a contract to Shell Catalyst & Technologies (SC&T) to deliver process technology for a third major expansion of ethylene production capacity at the operators’ 50-50 joint venture CNOOC & Shell Petrochemicals Co. Ltd.’s (CSPC) petrochemical complex in Daya Bay Economic & Technological Development Zone, Huizhou City, Guangdong Province, China.
As part of the Feb. 27 contract, SC&T will license a suite of technologies for CSPC’s Phase 3 expansion, including its proprietary production process for styrene monomer and propylene oxide (SMPO) and OMEGA catalytic process for manufacturing of ethylene-oxide-ethylene glycol (EO-EG), as well as its technology for production of linear alpha olefins (LAO) for a grassroots LAO plant to be built as part of the project, the service provider said.
SC&T said its scope of delivery under contract also includes provision of associated catalysts for the Phase 3 growth project, which will add a new 1.6-million tonne/year (tpy) ethylene cracker.
The contract for CSPC’s Phase 3 expansion follows the partners’ May 2020 confirmation that they would proceed with project development that was then only to include construction of a new 1.5-million tpy cracker (OGJ Online, May 18, 2020).
Preceded by commissioning of a 1.2-million tpy ethylene cracker—the site’s second—in 2018, CSPC most recently completed startup of remaining derivatives units included under complex’s Phase 2 expansion in April 2021.
Targa updates gas processing, fractionation growth plans
Targa Resources Corp. is progressing with projects to expand cryogenic natural gas processing and fractionation capabilities as part of the operator’s broader strategy to further extend its Permian basin gathering and processing position amid heightened demand from producers.
Construction continues on Targa’s 275 MMcfd Legacy II plant and 275 MMcfd Greenwood plant in Midland basin, as well as on the 275 MMcfd Midway plant and 275 MMcfd Wildcat II plant in Delaware basin, the operator told investors on Feb. 22 in its fourth-quarter 2022 earnings report.
In response to rising production in the region, Targa also confirmed it is relocating an existing natural gas processing plant in the Eagle Ford shale region of South Texas to the Delaware basin to meet increased producer demand. Acquired as part of its 2022 purchase of Southcross Energy Operating LLC, the plant will be installed as the new 230-MMcfd Roadrunner II plant (OGJ Online, Mar. 18, 2022).
The five new plants will collectively add more than 1.2 bcfd of gas processing capacity to Targa’s Permian operations upon their targeted in-service dates of:
- Legacy II (Midland), second-quarter 2023.
- Midway (Delaware), second-quarter 2023.
- Greenwood (Midland), fourth-quarter 2023.
- Wildcat II (Delaware), first-quarter 2024.
- Roadrunner II (Delaware), second-quarter 2024.
Targa said construction also remained ongoing during fourth-quarter 2022 on its 120,000-b/d Train 9 fractionator in Mont Belvieu, Tex., and its Daytona NGL pipeline, which will transport NGLs from the Permian basin to the 30-in. OD Grand Prix segment of the common-carrier 550,000-b/d Grand Prix NGL pipeline system in North Texas for further delivery to the operator’s Mont Belvieu fractionation and storage complex (OGJ Online, Nov. 7, 2022).
The Train 9 fractionator remains on schedule for startup in second-quarter 2024, with the Daytona NGL pipeline due to be in service by yearend 2024, Targa said.
Pembina adding fractionator at Alberta complex
Pembina Pipeline Corp. is expanding NGL fractionating capacity to its existing Redwater fractionation and storage complex in Redwater, Alta. (OGJ Online, Dec. 12, 2022).
To be known as RFS IV, the 55,000-b/d propane-plus fractionator will enable the Redwater complex meet increased demand from Northeast British Columbia producers under existing as well as recently signed long-term, take-or-pay and incremental contracts, Pembina told investors in its fourth-quarter 2022 earnings report.
The proposed $460-million (Can.) RFS IV project investment—including construction of new rail-loading capacity at the complex—will lift the site’s total fractionation capacity to 256,000 b/d following planned startup in first-half 2026, the operator said in its yearend-2022 filing released on Feb. 23.
Designed for importing, exporting, treating, and storing NGL products, the Redwater complex currently consists of:
- 73,000-b/d RFS I ethane-plus fractionator.
- 73,000-b/d RFS I ethane-plus fractionator.
- 55,000-b/d RFS III fractionator.
- 12.1 million bbl of cavern storage.
- Existing truck and rail terminals with unit train capability.
TRANSPORTATION Quick Takes
Greater Tortue Ahmeyim partners select gravity-based Phase 2 concept
bp PLC and partners have confirmed use of a gravity-based structure (GBS) for developing Greater Tortue Ahmeyim (GTA) LNG’s 2.5-3.0 million tonne/year (tpy) Phase 2 expansion offshore Mauritania and Senegal. The partnership is now working with contractors towards pre-front end engineering and development.
GTA is 120 km offshore in water depth of 2,850 m and holds estimated gas resources of 15 tcf. Phase 1, currently under development, will export gas from four subsea wells to a floating production, storage, and offloading (FPSO) vessel about 40 km offshore at which the gas will be processed for export to a 2.3-million tpy floating LNG plant (FLNG Gimi) 10 km offshore. The FPSO left COSCO Shipping Heavy Industry Co. Ltd.’s Qidong, China, yard in January en route to West Africa, with Phase-1 first gas expected by end 2023.
GBS LNG developments have a static connection to the seabed with the structure providing LNG storage and a foundation for the liquefication plant. Concept design will also include new wells and subsea equipment, integrating with and expanding existing GTA infrastructure.
The partnership said it will consider powering LNG liquefication using electricity to help lower emissions.
In October 2022, bp signed an exploration and production sharing contract for the nearby 13-tcf BirAllah gas resource in Mauritania. bp also continues to work with partners on development of a gas-to-power project in Senegal based on the Yakaar Teranga resource (20 tcf), also near GTA. Most recently, bp signed an MoU with the Government of Mauritania to explore the potential for large-scale production of green hydrogen in the country.
The GTA partnership consists of bp 61%, Petrosen SA 5%, Société Mauritanienne des Hydrocarbures 5%, and Kosmos Energy Ltd. 29%.
Venture Global signs long-term LNG supply agreements with China Gas
Venture Global LNG Inc. and China Gas Hongda Energy Trading Co. Ltd., a subsidiary of China Gas Holdings Ltd. have executed two 20-year agreements for China Gas to purchase 1 million tonnes/year (tpy) of LNG a free on board (FOB) basis from Venture Global’s 20-million tpy Plaquemines LNG plant and another 1 million tpy from the CP2 LNG plant, both in Louisiana.
Venture Global is developing Plaquemines LNG on a 630-acre site in Plaquemines Parish, La., about 20 miles south of New Orleans. The plant will use as many as 36 0.626-million tpy trains configured in 18 two-train blocks and will include up to three berths capable of handling LNG carriers as big as 185,000 cu m.
The 20-milllion tpy nameplate capacity CP2 LNG plant will be built in Cameron Parish, La. The plant and 4-bcfd CP Express natural gas pipeline project received its draft environmental impact statement (EIS) from the US Federal Energy Regulatory Commission (FERC) in January (OGJ Online, Jan. 23, 2023). The company hopes to begin construction in 2023 to meet a second-quarter 2026 in-service date.
