GENERAL INTEREST Quick Takes
Devon to double Eagle Ford acreage with acquisition
Devon Energy Corp., Oklahoma City, Okla., agreed to acquire Denver-based Validus Energy, an Eagle Ford operator, for total cash consideration of $1.8 billion, the company said in a release Aug. 9.
This acquisition includes 42,000 net acres (90% working interest) in Karnes County, Tex., adjacent to Devon’s existing leasehold in Dewitt County. Privately held Validus’s current production is about 35,000 boe/d (70% oil), with volumes expected to increase to an average of 40,000 boe/d over the next year. Validus is currently running two rigs in the field.
The transaction also adds 350 repeatable drilling locations in the core of the Karnes Trough oil window along with 150 refrac candidates, Devon said. Existing and acquired assets combined, Devon expects to hold 82,000 net acres (70% working interest) in the Eagle Ford with second-quarter combined production in the play of 73,000 boe/d (60% oil).
Valudis acquired the acreage in 2021 in a deal with Ovintiv Inc., Denver, for $880 million.
Devon expects to realize $50 million in average annual cash flow savings from capital efficiencies, operating improvements, and marketing synergies.
The deal, subject to customary terms and conditions, is expected to close at the end of this year’s third quarter and follows on the heels of Devon’s $865-million deal to acquire Bakken assets from RimRock in June.
The company’s second-quarter production averaged 616,000 boe/d, an increase of 7% from first-quarter 2022. Oil production accounted for the largest component of the company’s product mix at 49% of total volumes. The company reported net earnings of $1.9 billion for the quarter, with adjusted earnings of $1.7 billion. Operating cash flow totaled $2.7 billion in the quarter.
Sval Energi to acquire Norwegian Continental Shelf assets
Sval Energi AS agreed to acquire non-operated working interests in several Norwegian Continental Shelf assets held by Suncor Energy Norge for about $410 million (Canadian dollar equivalent).
The deal includes 17.5% ownership in Neptune Energy-operated Fenja field (PL 586), 30% ownership in Spirit Energy-operated Oda field (PL 405), and eight additional licenses.
The acquisition will add about 4,000 boe/d and 19 MMboe reserves to the company. Related Suncor Energy Norge employees are expected to be transferred to Sval.
The deal is expected to close before yearend, subject to approval from relevant Norwegian authorities.
Fenja lies 20 km north of Kristiansund in the Norwegian Sea, while Oda field is 13 km east of the producing Ula field in the southern part of the Norwegian North Sea.
Woodside ends Sangomar sell-down process
Woodside Energy Ltd. will halt the current sell-down process of its interest in Sangomar oil field offshore Senegal, West Africa, the company said in its second-quarter 2022 report.
Last year Woodside amassed 82% interest in the field following the acquisition of interests held by Cairn Energy and FAR Ltd. Senegal’s national company Petrosen holds the remaining 18%.
Woodside is operator of Sangomar, which is currently undergoing Phase 1 development. Work was 63% complete at the end of the reporting period, the company said.
Installation of the mooring system for the floating production, storage, and offloading (FPSO) vessel was completed in July. The FPSO is expected to move from the shipyard in China to the Keppel shipyard in Singapore in October to complete commissioning.
At Sangomar field, development drilling is progressing and a second drillship, Ocean BlackHawk, also began work in July.
The subsea installation campaign is expected to begin in this year’s third quarter.
Work on Phase 1 development began early in 2020. First oil is scheduled for 2023. It will be Senegal’s first commercial oil project.
Sangomar field was discovered in November 2014 in 1,100 m of water about 100 km south of Dakar.
Journey acquires oil-weighted Alberta assets from Enerplus
Journey Energy Inc., Calgary, has agreed to acquire producing petroleum and natural gas assets in Alberta from Enerplus Corp. for $140 million, the two companies said in separate releases July 29.
The assets are currently producing about 3,400 boe/d (60% crude oil) on a net after deduction of royalty basis (4,400 boe/d before deduction of royalties) primarily in Medicine Hat (secondary and tertiary recovery), Kaybob, Ferrier, and Ante Creek (secondary recovery) areas of Alberta. Assets include 420 net wells and 45,672 gross (15,338 net) undeveloped acres, and proprietary operated and non-operated seismic data totaling 18,666 km of 2D data and 1,847 sq km of 3D seismic data.
Pro-forma, assuming an Oct. 1 closing date, the deal is expected to increase Journey’s fourth-quarter production to 14,200-14,600 boe/d and increase the company’s liquid (oil, NGL) weighting to about 55%.
Exploration & Development Quick Takes
Wintershall Dea drills dry hole at Brage
Wintershall Dea Norge AS drilled a dry hole at Brage South exploration well 31/4-A-13 C in production license (PL) 055 in the North Sea.
The well was drilled from the Brage platform and will be plugged.
Wintershall Dea Norge AS is operator at PL 055 (35.2%) with partners Lime Petroleum AS (33.8434%), DNO Norge AS (14.2567%), Vår Energi ASA (12.2575%), And M Vest Energy AS (4.4424%).
Eni drills discovery offshore Côte d’Ivoire
Eni SPA drilled the Baleine East 1X well in Block CI-802 on the Baleine structure, about 5 km east of the Baleine 1X discovery well in adjacent Block CI-101, offshore Côte d’Ivoire. Results increased estimated volumes of hydrocarbons in place by 25% to 2.5 billion bbl of oil and 3.3 tcf of associated gas.
The well, the first exploration well and second discovery in the block, was drilled to a final measured depth of 3,165 m by the Saipem 12000 drillship in 1,150 m of water. It confirmed the presence of a continuous oil column of about 48 m in reservoir rocks with good properties.
From the vertical borehole a horizontal drain of 850 m in length was subsequently drilled into the reservoir to perform a production test that confirmed potential of at least 12,000 b/d oil and 14 MMscfd associated gas, the company said.
Eni will drill a third well and expects to start production in the block in first-half 2023.
Eni is operator with 90% interest. Petroci Holding holds the remaining 10%.
Vintage to begin Odin gas development work
The Cooper basin joint venture led by Vintage Energy Ltd. agreed to begin work on proposed development of the Odin natural gas discovery in petroleum retention lease PRL 211 in the South Australian sector of Cooper basin.
The discovery, as mapped, straddles the permit and state boundary with adjoining Queensland permit ATP 2021, containing the JV’s Vali gas field which will be brought onstream in October 2022.
Adelaide-based Vintage said the JV has agreed to begin concept engineering for connection of Odin field to the Vali-Beckler pipeline which is due to begin construction in August and will connect to the Moomba gas plant in South Australia. It has also agreed to prepare a commercial plan for marketing Odin gas.
The group anticipates that once a gas sales agreement has been made, field development work could begin early 2023 with gas from Odin brought onstream later that same year.
Vintage managing director Neil Gibbins said commitment to the Odin work program was supported by customer interest in gas supply to eastern Australia. Thus, the JV has decided to prioritize gas sales over exploration in the near-term, he added.
Concept engineering and work to commercialize Odin will be quickly followed by front-end engineering and design, detailed engineering, procurement, and construction.
The Odin gas discovery was made in May 2021 and has been independently assessed as containing a 2C contingent resource of 36.4 bcf of gas in the Permian-age Toolachee, Epsilon, Patchawarra, and Tirrawarra formation reservoirs in Cooper basin.
The discovery well was flow-tested from Epsilon and Toolachee formations at a stable rate of 6.5 MMcfd at a wellhead flowing pressure of 1,823 psi through a 7/16-in. fixed choke.
Interests in both PRL 211 and ATP 2021 are Vintage 50% and operatorship, with Metgasco Ltd. and Bridgeport Energy Ltd. each holding 25%.
Drilling & Production Quick Takes
Talos to initiate Gulf of Mexico program mid-August
Talos Energy Inc. expects to advance its US Gulf of Mexico open water program that includes six total operations between second-half 2022 and first-half 2023.
The company will take possession of the Seadrill Sevan Louisiana deepwater rig in mid-August, initiating the program, the company said as part of its second-quarter earnings report Aug. 4.
Four of the operations are exploitation wells targeting 65-100 MMboe of cumulative gross unrisked resources utilizing Talos-operated infrastructure for accelerated subsea development, the company said.
Talos will spud the Lime Rock prospect, the first of the four exploitation targets, following a deepwater recompletion. Prior to initiating the rig program, the company farmed out non-operated working interest partners in each of the Lime Rock, Venice, and Rigolets projects. Talos now owns a 60% working interest in each. If successful, the operator expects each well to produce 5,000-15,000 boe/d gross with expected timeline to first oil of 12-18 months.
The company expects the bp-operated Puma West appraisal well (Talos, 25% non-operated interest) to spud early in fourth-quarter 2022 with results expected by early 2023. The appraisal follows the successful 2021 exploration discovery well. The well has been permitted to a depth of about 26,700 ft and will be drilled with the Diamond Ocean BlackHornet rig, currently working for bp.
In Gunflint field, (Talos, 9.6% non-operated interest) Talos participated in two workovers and anticipates initiating the MC 992 #1 sidetrack well by yearend.
Lastly, Talos is working with an unnamed partner to finalize a five-block exploration unit comprising 28,800 gross acres in Walker Ridge and Green Canyon areas on which the company expects to participate in a high-impact exploration prospect in first-half 2023.
The company’s Seville exploitation well failed to discover commercial quantities of hydrocarbons in late July. The Pompano platform rig program has shifted to begin preparations for the Mount Hunter development well, with spud expected in third-quarter 2022 and first oil early 2023.
Overall, in second-quarter 2022, the company produced 65,400 boe/d (67% oil, 75% liquids).
In the second quarter, the company had revenue $519.1 million, net income of $195.1 million, and adjusted net income of $100.6 million.
Capital expenditures for the quarter totaled $85.9 million. Free cash flow (before changes in working capital) came in at $134.1 million.
Shell lets deepwater GOM contract to Worley
Shell PLC has let a 3-year contract to Worley to provide engineering and procurement services for several of its assets in the Gulf of Mexico.
Worley will provide engineering, procurement, project services, and support fabrication and construction. Shell currently operates eight oil and gas developments across the Gulf of Mexico deepwater basin, and Worley will focus on five: Appomattox, Perdido, Stones, Auger, and Enchilada-Salsa.
The contract also allows for further support of Shell’s Whale development by delivering greenfield engineering and procurement services.
Neptune Energy begins drilling Ofelia exploration well
Neptune Energy Norge AS started drilling Ofelia exploration well 35/6-3 S in production license (PL) 929, 13 km north of Gjøa field in the Norwegian sector of the North Sea.
The drilling program comprises a main-bore (35/6-3 S) with an optional sidetrack (35/6-3 A). The reservoir target is the Lower Cretaceous Agat formation and is expected to be reached at a depth of about 2,570 m.
The well is being drilled by the semisubmersible Deepsea Yantai, owned by China International Marine Containers Ltd. (CIMC) and operated by Odfjell Drilling Ltd.
In the event of a commercial discovery, the Ofelia prospect could be tied back to Neptune-operated Gjøa platform, the company said.
Neptune Energy is operator of the license with 40% interest. Partners are Wintershall Dea Norge AS (20%), Lundin Energy Norway (10%), Pandion Energy AS (20%), and DNO Norge AS (10%).
Sinopec secures gas flow in Sichuan Province
Sinopec Southwest Petroleum Administration secured high-yield industrial gas flow in the Pengzhou 5-1D well, a horizontal well in Western Sichuan Gas Field, the company said in separate social media postings Aug. 5.
Daily gas output from the well was 950,000 cu m/day with a daily open flow of 3.25 million cu m in its test production, the company said.
Western Sichuan Gas Field lies on the western edge of the Chengdu Plain, covering an area of about 139 sq km. The gas field’s proven natural gas reserves exceed 100 bcm, with the main reservoir at a depth of about 5,700-6,200 m, according to local media. The field is expected to be completed and put into production in September 2023, with an annual output of 2 bcm of natural gas, the media reported.
PROCESSING Quick Takes
bp to shed interest in Toledo refinery
Cenovus Energy Inc. has agreed to purchase partner bp PLC’s 50% ownership interest in jointly held BP-Husky Refining LLC’s 160,000-b/d refinery in Toledo, Ohio.
As part the proposed deal, Cenovus will pay $300 million in cash for bp’s stake in the refinery, plus the value of inventory, bp and Cenovus said in separate releases Aug. 8.
Upon finalizing the transaction, Cenovus—which has held the other 50% interest in the BP-Husky Refining partnership since merging with Husky Energy Inc. in 2021—will take 100% ownership of the venture, as well as assume operatorship.
The parties also signed a multi-year product supply agreement, but details of which were not revealed.
Pending customary closing conditions, the deal is expected to complete by yearend 2022.
Over 580 bp employees employed at the Toldeo refinery are expected to become Cenovus employees.
For Cenovus, the proposed acquisition will provide an additional 80,000 b/d of downstream throughput capacity, including 45,000 b/d of heavy oil refining capacity, enabling the operator to further optimize its heavy oil value chain through integration with its upstream assets, particularly the ability to run advantaged Canadian crude feedstock, the company said in an Aug. 8 presentation to investors.
“Fully owning the Toledo refinery provides a unique opportunity to further integrate our heavy oil production and refining capabilities,” said Alex Pourbaix, Cenovus’ president and chief executive officer.
“Operating the refinery will open up additional synergies and capital efficiency opportunities, including connectivity with our nearby [175,000-b/d refinery in Lima, Ohio],” Pourbaix added.
The company is also eyeing potential turnaround efficiencies via sequencing maintenance events between the Lima and Toledo refineries, the latter of which completed a major turnaround and feedstock optimization project this year to increase the site’s capacity to run high-TAN crude volumes to about 55,000 b/d from 28,000 b/d, Cenovus told investors.
Regarding divestment of its stake in the bp-Husky Toledo refinery, bp said the sale will support the operator’s strategy to instead focus investment on its remaining two US refineries—including the fully owned 152,000-b/d refinery in Whiting, Ind., and 238,450-b/d Cherry Point refinery in Blaine, Wash.—both of which are strategically positioned to serve customers in the US Midwest and Pacific Northwest.
Including the Toledo refinery, bp presently operates seven refineries that include 800,000 b/d of net capacity in the US and 1.6 million b/d internationally.
The proposed Toledo refinery sale follows bp’s June 2022 dual agreement to sell its 50% non-operated interest in the Sunrise oil sands project in Alberta, Canada, to Cenovus, as well as to acquire Cenovus’s 35% interest in the Bay du Nord project offshore Newfoundland and Labrador. Following close of that deal—also scheduled by yearend 2022—bp, which currently holds an interest in six exploration licenses offshore Eastern Newfoundland, will no longer have interests in Canadian oil sands production and will shift its focus to potential offshore growth.
Enterprise expanding Permian gas processing, pipeline capacities
Enterprise Products Partners LP (EPP) is adding fresh capacity to its existing natural gas processing and gathering systems in the Delaware and Midland subbasins of the Permian basin.
The three organic growth projects—which will include the addition of two new cryogenic natural gas processing plants, as well as the expansion of the operator’s existing Shin Oak NGL pipeline system—comes as part of EPP’s plan to support ongoing production growth of crude oil, natural gas, and NGLs in the region, EPP told investors upon release of its second-quarter 2022 earnings report.
In Delaware basin, EPP will add a third 300-MMcfd gas processing plant at its existing 300-MMcfd Mentone complex in Loving County, Tex. Supported by long-term capacity agreements and scheduled for startup by the end of first-quarter 2024, the new plant—which also will enable 40,000 b/d of incremental NGL extraction—will increase EPP’s overall Delaware basin gas processing and NGL extraction capacities to 2.2 bcfd and 300,000 b/d, respectively, the operator said.
In an effort to expand its network of Midland basin assets acquired under its purchase of Navitas Midstream Partners LLC earlier this year, EPP said it also will add a seventh gas processing plant in Midland County, Tex. Backed by long-term acreage dedication agreements and to be equipped with 40,000 b/d of NGL extraction capability, the 300-MMcfd Plant 7—also scheduled for completion by the end of first-quarter 2024—will boost the operator’s overall respective gas processing and NGL extraction capacities in Midland basin to 1.6 bcfd and 220,000 b/d.
To accommodate rising Permian NGL production, EPP also will add up to 275,000 b/d of NGL transportation capacity to the 669-mile Shin Oak pipeline, which delivers NGL from Orla, Tex., to EPP’s NGL fractionation and storage complex in Mont Belvieu, Tex., along the US Gulf Coast. The pipeline expansion—which will be executed via looping and modifications to existing pump stations—is targeted for completion during first-half 2024, the operator said.
During the Aug. 3 quarterly earnings call, EPP said it plans to commission its 300-MMcfd Plant 6 in Midland basin during second-quarter 2023 and its second 300-MMcfd Mentone plant in Delaware basin during fourth-quarter 2023.
TRANSPORTATION Quick Takes
TC Energy, Mexico to build 1.3 bcfd Southeast Gateway pipeline
TC Energy Corp. and Mexico’s state-owned Comisión Federal de Electricidad (CFE) have agreed to a strategic alliance centered on accelerating development of natural gas infrastructure in central and southeast Mexico, including construction of the 1.3 bcfd Southeast Gateway pipeline. TC Energy and CFE have agreed to consolidate previous transportation service agreements (TSA) executed between TC Energy’s Mexico-based subsidiary, Transportadora de Gas Natural de la Huasteca (TGNH), and CFE in connection with shared natural gas pipelines in central Mexico under a single, US dollar-denominated take-or-pay contract extending through 2055. This new TSA will also govern related new infrastructure projects to be developed.
TC Energy and CFE in conjunction with the alliance also took final investment decision (FID) on the 715-km Southeast Gateway. The pipeline will serve southeast Mexico, starting onshore in Tuxpan, Veracruz, then proceeding offshore, making landfall at Coatzacoalcos, Veracruz, and Dos Bocas, Tabasco. The project is expected to be in-service by mid-2025 at an estimated cost of $4.5 billion
TC Energy and the CFE also agreed to mutually terminate presently suspended international arbitration between the two related to the 886-MMcfd Tula-Villa de Reyes and Tuxpan-Tula (TXTL) pipelines, with TC Energy earning a return on and of all previous capital invested. TC Energy and CFE have also agreed to work together to complete TXTL’s central segment, subject to fourth-quarter 2022 FID.
Subject to regulatory approvals from Mexico’s economic competition commission and its Regulatory Energy Commission, CFE will have the opportunity to hold a 15% equity interest in TGNH. Regulatory approvals related to CFE’s equity participation are expected to take up to 24 months.
At the end of Southeast Gateway’s contract life in 2055 and after TC Energy has recovered full return on and of capital, CFE’s equity interest would increase to 35%, reflecting the equivalent of 49% of net value of Southeast Gateway and 15% of the other TGNH pipelines.
Beach signs LNG deal with BP Singapore
Beach Energy Ltd., Adelaide, agreed to supply LNG to BP Singapore Pte. Ltd. BP will purchase all 3.75 million tonnes of Beach’s expected LNG volumes from the Waitsia gas field Stage 2 project in the onshore North Perth basin of Western Australia.
Supply is scheduled to begin in second-half 2023 and continue for about 5 years.
The agreement contains a hybrid pricing structure that is linked to Brent and Japan Korea marker indices.
The pricing parameters support Beach’s exposure to the current commodity price cycles and put no restriction on upside price participation, the company said. In addition, the sales agreement includes a downside price protection mechanism.
Supply will be delivered on a free on board (FOB) basis from the Woodside Energy-operated North West Shelf infrastructure at Karratha. BP is a participant in the North West Shelf joint venture and has a history of four decades of lifting LNG from the Karratha plant.
Waitsia field, in production license L1, is one of the largest onshore gas fields discovered in Australia. It is operated by Mitsui E&P Australia Pty Ltd. with 50% interest. Beach holds the remaining 50%.
Stage 1 development began as an extended production test in 2016 and has since been expanded. From August 2020 Stage 1 has been producing 20-30 terajoules/day of gas via the Dampier-Bunbury trunk line.
Stage 2 development involves additional development wells and new production infrastructure capable of producing 250 terajoules/day. Final investment decision for Stage 2 was made in February 2021 and it is expected on stream in 2023.
Freeport LNG agrees to corrective measures ahead of planned liquefaction restart
Freeport LNG Development LP and the Pipeline Hazardous Materials Safety Administration (PHMSA) have entered into a Consent Agreement related to the June 8 incident at Freeport LNG’s 15-million tonne/year liquefaction plant on Quintana Island, Tex. (OGJ Online, June 9, 2022).
The obligations under the agreement are intended to ensure that Freeport LNG can safely resume initial LNG production and thereafter ultimately return to full operation of all liquefaction infrastructure, the company said in a release Aug. 3 (OGJ Online, June 14, 2022).
The agreement includes corrective measures, many of which are currently under way, that Freeport LNG is to take to obtain approval for an initial resumption of LNG production from the plant.
Freeport LNG currently expects to complete necessary corrective measures, along with applicable repair and restoration activities, and resume initial operations early October. Initial operations are expected to consist of three liquefaction trains, two LNG storage tanks, and one LNG loading dock, which are expected to enable delivery of about 2 bcfd of LNG, enough to support its existing long-term customer agreements, the company said.
In addition to the repair and replacement of physical infrastructure that was damaged, and as part of the corrective measures under the agreement, the company is evaluating and advancing initiatives related to training, process safety management, operations and maintenance procedure improvements, and plant inspections, the company said.
