GENERAL INTERESTQuick Takes
PennEnergy Resources to acquire Rex Energy assets
PennEnergy Resources, Pittsburgh, Pa., will acquire substantially all the assets of Rex Energy Corp., State College, Pa., for $600.5 million in a cash deal. Nearly all the combined assets are in the core of the Marcellus shale area with 20 years of drilling inventory, the company said. Rex Energy filed for voluntary bankruptcy and announced plans to sell its Appalachian basin-focused assets in May (OGJ Online, May 18, 2018).
On a combined basis, PennEnergy Resources will operate 329 horizontal producing shale wells and will control 203,500 gross leasehold acres, primarily in the Pennsylvania counties of Butler, Beaver, and Armstrong, north of Pittsburgh. Independent petroleum consultants Wright & Co. Inc. estimated total combined net proved reserves of 8.5 tcf of natural gas equivalent, of which 1.7 tcfe are proved developed producing.
With combined gross production of 700 MMcfed and net production of 450 MMcfed, PennEnergy Resources believes it will be the 10th largest gas producer in Pennsylvania and the third largest headquartered in the state.
Most of the acquired assets are contiguous to PennEnergy Resources’ existing operations, said Pres. and COO Greg Muse. The firm plans to operate 2 horizontal rigs on the combined properties, he said. The assets acquired include cash accounts of $29.5 million held by Rex used to collateralize firm transportation contracts that will be released at close.
Talos Energy acquires Whistler Energy II
Talos Energy Inc., Houston, has entered into and completed a transaction to acquire Whistler Energy II LLC. The bolt-on acquisition includes production facilities with unused capacity and seismic data to be used in a field study to potentially identify additional drilling locations on the producing asset.
The acquired assets include a 100% working interest in three blocks in the central Gulf of Mexico—Green Canyon Block 18, GC Block 60, and Ewing Bank Block 988—collectively known as GC 18 field and comprising 16,494 acres—and a fixed production platform on GC Block 18 (GC18 Production Facility) in 750 ft of water. All leases are held-by-production.
Green Canyon 18 field was originally developed by ExxonMobil Corp. and sold to Whistler in 2012. To date, it has cumulative production of more than 117 million boe. The GC18 Production Facility—18 miles north of Talos-operated Phoenix field and Tornado discovery—has a nameplate production capacity of 30,000 bo/d and 30 MMcfd of gas, or 35,000 boe/d of total capacity, with potential for expansions. Year-to-date gross production from Whistler’s assets is 1,900 boe/d, or net production after royalties of 1,500 boe/d, 82% of which is oil.
Talos holds license to recent vintage-wide azimuth seismic data in the area that will be reprocessed to assist in the remapping of the producing reservoirs and potentially generate additional drilling prospects. Additionally, in the latest federal lease sale in the gulf, the company was the high bidder on new leases containing at least three drilling prospects that could be tied back to the GC18 Production Facility.
The purchase price was $52 million. Also, Talos negotiated the release of $77 million collateral that had secured Whistler’s surety bonds that it will not need to replace. Of the total collateral released, Talos received $31 million, with the seller entitled to the remaining $46 million. Whistler held $7 million in cash at closing, resulting in a net of $14 million to Talos.
Bryska to lead refocused Crescent Point
Craig Bryska has been named president and chief executive officer of Crescent Point Energy Corp., Calgary, as the company focuses on key assets and cuts costs. Robert Heinemann has been named chairman, succeeding Peter Bannister.
Bryska has been interim president and CEO since earlier this year, when he succeeded Scott Saxberg, a company founder (OGJ Online, May 29, 2018).
Crescent Point plans to divest upstream assets, cut debt by more than $1 billion by the end of next year, identify midstream assets for potential monetization, and save more than $50 million/year through a 17% workforce reduction.
It has identified its Viewfield, Shaunavon, and Flat Lake resource plays in southern Saskatchewan as “key focus areas,” based on returns, scalability, potential free cash flow, and ability to improve market access. Crescent Point produced 102,000 boe/d of oil and gas from those areas in the second quarter.
It also will continue work on emerging resource plays in the Uinta basin in Utah and East Shale Duvernay play of southeastern Alberta, where second quarter production was 23,000 boe/d.
Production from other assets was 50,000 boe/d.
Exploration & DevelopmentQuick Takes
Latest New Mexico lease sale broke records, BLM reports
The US Bureau of Land Management’s third-quarter oil and gas lease sale in New Mexico broke records by grossing nearly $1 billion in bonus bids for 142 parcels, the US Department of the Interior agency said on Sept. 6. Revenue from the sale totaled nearly $972.5 million, surpassing revenue for all BLM oil and gas sales in 2017 as well as the agency’s previous best sales year.
BLM said the 2-day, online sale in its Carlsbad Field Office outpaced what previously was its largest sales year ever in 2008, which generated $408,631,537 of revenue. Seventy-one parcels covering 28,036 acres were sold on the first day for nearly $386 million of total receipts, more than the $358 million of revenue from all of BLM oil and gas leases sales in 2017, BLM said.
In addition to the record total bonus bids, the first day of the sale also resulted in a national record for the highest bid for a single parcel, and the highest per-acre bid ever placed, BLM said.
The winning bid for a 1,240-acre parcel in Eddy County was $81,889/acre, bringing in $101.5 million. The previous record for a single parcel in New Mexico was $76.68 million, set in September 2016. The previous per-acre bid record for a federal lease in the state was $40,001 set in December 2017.
Gazprom Neft plans Neptune appraisal well
Gazprom Neft is preparing to drill a second well to appraise its Neptune discovery in the Okhotsk Sea in far eastern Russia after increasing the resource assessment by 60% (OGJ Online, Oct. 4, 2017). The company calls Neptune, on the Ayashsky license block in 60-70 m of water 55 km northeast of Sakhalin Island, its “most important discovery of 2017.”
Its new estimate of C1+C2 reserves, which under the Russian system includes “preliminary reserves,” at 415.8 million tonnes of oil equivalent.
Gazprom Neft said its subsidiaries have cored and logged the discovery well, studied fluids, and built a geologic model.
The Ayashsky block is part of the Sakhalin III project.
Estimates raised for offshore NL resources
Assessed exploration and development potential offshore Newfoundland and Labrador has jumped with new resource estimates for parcels offered in a current license round.
New resource totals are 49.2 billion bbl of oil and 193.8 tcf of natural gas, reflecting increases of 11.7 billion bbl of oil and 60.2 tcf of gas. The assessments come from the provincial government, provincially owned Nalcor Energy-Oil & Gas, and Beicip Franlab. The license round will offer 16 parcels on offer in the Orphan and East Jeanne d’Arc basins.
In that round, covering the Eastern Newfoundland Region, the Canada-Newfoundland and Labrador Offshore Petroleum Board is accepting sealed bids until midday Nov. 7.
The resource increases come from recent geoscientific studies of nine of the parcels on offer.
Petronas confirmed as partner to FAR blocks off Gambia
The government of Gambia has granted approval for the farmout by FAR Ltd., Perth, of two offshore exploration blocks to Malaysian state firm Petronas.
Petronas will take a 40% interest in contiguous offshore petroleum licences A2 and A5 in return for funding 80% of the exploration well costs of the forthcoming Samo-1 wildcat on Block A2 up to a maximum of $45 million.
Petronas also will pay FAR $6 million plus 80% of nonwell back costs. The proceeds are subject to reconciliation and were estimated to be $19 million (Aus.) at June 30.
FAR will retain 40% interest and operatorship status. The company originally had an 80% interest in the blocks.
FAR said last week that it had finalised a location for Samo-1 in 1,017 m of water and 112 km from the coast in the Mauritania-Senegal-Guinea-Bissau-Conakry basin.
The Samo structure has been assessed as having potential to hold a resource up to 825 million bbl of oil. It lies on trend and south of Cairn Energy Group’s SNE oil discovery in which FAR is a joint venture partner.
The well is to be drilled by the dynamic positioning drillship Stena DrillMAX.
FAR says it has also identified and mapped a second prospect called Bambo which lies in Block A2 northeast of Samo.
Exploration of this prospect will be influenced by the results of Samo-1.
Drilling & ProductionQuick Takes
Lukoil adds steam capacity at Yarega field
Lukoil has commissioned a steam-generation complex at Yarega heavy-oil field in the Republic of Komi in Russia, where first-half production was up 77% over the comparable 2017 period.
The company said output in the first 6 months totaled 761,000 tonnes of highly viscous oil.
Yarega field, where production exceeded 1 million tonnes for the first time last year, has two main producing areas. It produces via thermally enhanced mining, which Lukoil calls “thermoshaft,” in the Yarega area and via steam-assisted gravity drainage in the Lyayel area.
The new facility has five boilers with combined capacity of 125 tonnes/hr of steam.
Last year, Lukoil added steam-generation capacity of 300 tonnes/hr at Yarega. Hydrocarbons at Yarega occur under low pressure at depths of 165-200 m.
Sound Energy reports concession onshore Morocco
Sound Energy PLC reported that the Moroccan Ministry of Energy has awarded it a production concession for the Tendrara natural gas discovery. The concession covers 133½ sq km.
Plans call for as many as five horizontal development wells in addition to recompletion of the existing TE-6 and TE-7 wells.
Sound Energy announced plans in June to build a gas-treatment plant and compression station (CPF) and a 120-km, 20-in. Tendrara Gas Export Pipeline connecting the CPF and the delivery point to the Gazoduc Maghreb Europe pipeline.
Sound Energy said it signed heads of terms with a consortium comprising Enagas, Elecnor, and Fomento for conditional construction and financing of the infrastructure required, including the TGEP and CPF. An FID has yet to be made.
Gas production is expected in about 2 years with an anticipated midcase production rate of around 60 MMscfd over at least 10 years. Sound Energy said 10-13 wells could be drilled to maintain this production rate.
Ohio reports increased Utica shale production
Oil and gas production from Ohio’s Utica shale grew year-to-year during the second quarter, the Oil & Gas Division in the state’s Department of Natural Resources reported on Aug. 28.
During the 3 months ended June 30, crude oil production totaled 4,488,104 bbl, 10.98% more than the 4,044,072 bbl reported for the comparable 2017 quarter, it said. Gas production during 2018’s second quarter totaled 554,306.9 MMcf, a 42.25% jump from the 389,662.5 MMcf reported during the comparable period a year earlier, ODNR’s Natural Resources Department division said.
Ohio law does not require the separate reporting of natural gas liquids or condensate, it noted. Oil and gas reporting totals list on the report include NGLs and condensate, it said.
The division noted that its latest ODNR quarterly report lists 2,035 horizontal shale wells, 2,002 of which reported oil and gas production during the quarter. It said that of the wells reporting oil and gas results: The average amount of crude produced was 2,242 bbl; the average amount of gas produced was 276.9 MMcf; and the average number of days in production during 2018’s second quarter was 85.
Woodside ties Goodwyn A platform to Lady Nora
McDermott International has finished laying pipe for Woodside Petroleum Inc.’s Greater Western Flank Phase 2 project offshore Western Australia from the Goodwyn A platform to manifold locations for Lady Nora and Pemberton fields. Phase 2 gas production is expected by Dec. 31.
The Greater Western Flank Phase 2 is in 262-426 ft of water some 29-37 miles southwest of the Goodwyn A platform. Phase 2 includes the drilling of eight wells from Keast, Dockrell, Lady Nora, Pemberton, Sculptor, and Rankin fields.
The contract included procurement, fabrication, installation, and testing of pipeline buckle initiators, pipeline end terminations and foundation mudmats, in-line tee structures and about 21 miles of a 16-in. corrosion-resistant alloy pipeline.
PROCESSINGQuick Takes
Meridian inks deal for start-up at Davis refinery
Meridian Energy Group Inc. has let a contract to GATE Energy, Houston, to deliver commissioning and start-up services for Meridian’s recently approved grassroots 49,500-b/sd high-conversion Davis refinery to be built in Billings County in the heart of southwestern North Dakota’s Bakken shale region (OGJ Online, Aug. 10, 2016).
As part of the letter of intent signed between the two companies, GATE will provide personnel for development planning and execution of the project, as well as its GATE Completion System (GCS), which will ensure the safe and efficient execution of the Davis refinery, on which civil construction recently began, Meridian said.
With official construction activities slated to begin in 2019, the Davis refinery is scheduled to be fully operational in 2020, Meridian said.
This latest contract follows Meridian’s award to SEH Design Build Inc.—a subsidiary of Short Elliott Hendrickson Inc., Bismarck, ND—to deliver site, civil design, and construction services for the project in July (OGJ Online, July 17, 2018).
The North Dakota Department of Health’s division of air quality previously issued Meridian the final permit-to-construct the project—under the first application in history for a full-conversion refinery of this size and complexity to seek and receive permitting to construct under classification as a synthetic minor source of air contaminants—in June (OGJ Online, June 13, 2018).
Alberta refinery ramping up for bitumen feed
North West Redwater Partnership (NWRP) is completing commissioning activities at the first 80,000-b/d phase of its proposed three-phased greenfield bitumen refinery in Sturgeon County, about 45 km northeast of Edmonton, Alta. (OGJ Online, June 22, 2018).
With final inspections and tests now under way on the remaining two units—including an LC-Finer (or residue hydrocracker) and gasifier—the units are well on their way to startup, which will complete commissioning of all ten of operator North West Refining Inc.’s refinery’s units in preparation for switchover to bitumen feedstock from Alberta’s oil sands, NWRP said.
As of Aug. 31, the refinery had reached a total low-sulfur diesel production of 6 million bbl from the plant’s current feedstock of partially upgraded synthetic crude, the operator said.
While construction on the refinery itself is completed, NWRP confirmed testing of the refinery’s flare systems as well as some road construction work will be ongoing until November.
The operator, however, did not disclose a definitive timeframe for when bitumen feed to the completed units would begin.
Upon commissioning of all three 80,000-b/d phases, the Sturgeon refinery—which began producing diesel and other products in November 2017—will process 240,000 b/d of Canadian bitumen feedstock to produce ultralow-sulfur diesel, diluent, and other bitumen products for both Canadian and global markets (OGJ Online, Dec. 19, 2017).
NWRP is a joint venture of NWR (formerly North West Upgrading Inc.), Calgary. Canadian Natural Upgrading Ltd., a wholly owned subsidiary of Canadian Natural Resources Ltd., also is of Calgary.
Idemitsu Kosan commissions unit at Aichi refinery
Idemitsu Kosan Co. Ltd. has commissioned a unit for production of mixed xylenes at its 160,000-b/d Aichi refinery in Chita, Aichi Prefecture, Japan.
Commercial operation of the mixed xylene equipment—which includes reformed gasoline xylene recovery equipment—began earlier this month, the operator said.
With a mixed xylene production capacity of 170,000 tonnes/year, the new equipment not only will contribute to expansion of the petrochemical business but also will enable flexibility to deal with changing supply and demand trend of petroleum products and petrochemical raw materials, Idemitsu Kosan said.
The refinery used to extract mixed xylenes through distilled separation of aromatic ingredients in gasoline.
The mixed xylenes unit comes as part of installation of various new equipment at the Aichi refinery under Idemitsu Kosan’s fifth consolidated medium-term management plan, which calls for promotion of its fuel-to-chemicals business, the company said.
TRANSPORTATIONQuick Takes
Equinor completes Johan Sverdrup crude line install
Equinor ASA has completed installation of a 283-km, 36-in. OD crude oil pipeline connecting its Johan Sverdrup development in the North Sea to the Mongstad oil terminal outside Bergen, Norway. Johan Sverdrup is on the Norwegian continental shelf about 140 km west of Stavanger in 115 m of water. The crude line’s deepest point is 537 m.
The company described the pipeline, consisting of 23,000 joints, as Norway’s largest and longest oil pipeline. It will carry 660,000 b/d once Johan Sverdrup reaches peak production in 2022 (OGJ Online, Aug. 27, 2018). First-phase production from the field of 440,000 b/d is planned for late 2019.
Equinor estimates Johan Sverdrup holds 2.2-3.2 billion boe.
Saipem’s Castorone began pipelay operations at Mongstad in late April. The pipeline was laid through Fensfjord before the vessel set course for Johan Sverdrup.
With the oil pipeline installed, Saipem Castorone is preparing to lay the 156-km, 18-in. OD natural gas pipeline extending from Johan Sverdrup to the Statpipe pipeline, shipping gas from the field to Karsto. Installation of the gas line is expected to be completed by yearend.
Equinor operates the field with a 40.0267% share. Partners include Lundin Norway 22.6%, Petoro 17.36%, AkerBP 11.5733%, and Total SA 8.44%.
KMTP, EagleClaw reach FID on Permian Highway line
Kinder Morgan Texas Pipeline LLC (KMTP), a subsidiary of Kinder Morgan Inc., and EagleClaw Midstream Ventures LLC, a portfolio company of Blackstone Energy Partners, reached a final investment decision to proceed with the Permian Highway Pipeline (PHP) Project.
“With a route identified and the project nearly fully subscribed, we expect to begin stakeholder outreach, environmental surveys and right-of-way activities in the coming months,” said Sital Mody, president of Kinder Morgan Natural Gas Midstream.
The $2-billion PHP Project is expected to be in service in late 2020, assuming timely receipt of the requisite regulatory approvals. It is designed to transport as much as 2 bcfd of gas through 430 miles of 42-in. pipeline from the Waha, Tex., area to the US Gulf Coast and Mexico. KMI also is evaluating the economic and hydraulic feasibility of a 48-in. pipeline with increased transportation capacity (OGJ Online, June 26, 2018).
Committed shippers include EagleClaw, Apache Corp., and XTO Energy Inc., a subsidiary of ExxonMobil Corp., amongst others.
KMTP and EagleClaw will serve as initial partners with equal ownership. KMTP will build and operate the pipeline. Apache, who has been jointly developing the proposed project, holds the option to acquire equity from the initial partners, which it intends to assign to Altus Midstream, a C-corporation anchored by substantially all of Apache’s gathering, processing, and transportation assets at Alpine High in the Delaware basin (OGJ Online, Aug. 9, 2018). KMI’s and EagleClaw’s ultimate ownership interest may vary between 27% and 50%, depending on the outcome of ownership options held by anchor shippers.
Excelerate, TGS to study Argentine liquefaction project
Excelerate Energy LP, The Woodlands, Tex., and Transportadora de Gas del Sur SA (TGS), Buenos Aires, have agreed to study the technical and commercial viability of a liquefaction project in Bahia Blanca, Argentina, to liquefy and export natural gas during the summer season.
Argentina currently imports LNG through two floating import terminals, particularly during the country’s peak winter season. The development of Argentina’s shale gas reserves resulted in a potential excess of gas during the summer months.
“Given the high seasonality of Argentina’s natural gas consumption, LNG has played a critical role in meeting the country’s energy demands,” stated Excelerate’s Chief Commercial Officer Daniel Bustos. “This project will significantly enhance Argentina’s capacity to maximize the use of local resources by allowing a more predictable development of shale gas production while reducing the overall costs of importing LNG.”
The study is expected to be completed by yearend, at which time the companies will share results with government and industry officials and decide on further actions.
Currently, 100% of LNG imported and regasified into Argentina is through Excelerate’s two floating storage and regasification units. The company developed South America’s first LNG import terminal in 2008 in Bahia Blanca, following with the second terminal in 2011 in Escobar, Argentina.
TGS is carrying out a project aimed at the transportation and conditioning of gas derived from the Vaca Muerta basin in Neuquen, Argentina.
