World of oil and gas

DISCOVERIES

Statoil hits oil, gas southwest of Johan Castberg

Statoil, operator of production license 532, has completed the drilling of wildcat well 7220/7-3 S, in the Barents Sea, about 15 km southwest of the 7220/8-1 Johan Castberg discovery, and 230 km northwest of Hammerfest. The well encountered a 68-m gross gas column in the Stø formation, and an 86-m gross oil column in the Stø and Nordmela formations. Preliminary calculations of the discovery size are between 7 MMcm and 10 MMcm of recoverable oil equivalents. The well was not formation-tested, but extensive data acquisition and sampling were carried out, said Statoil. The discovery will be considered for tie-in to Johan Castberg field. The well was drilled to a vertical depth of 2,029 m, and was terminated in the Fruholmen formation from the Late Triassic Age, at a water depth of 345 m. Well 7220/7-3 S was drilled by the West Hercules semisubmersible, which is moving on to assignments outside the Norwegian Continental Shelf.

Apache hits two discoveries on Egyptian acreage

Apache has struck two hydrocarbon discoveries on its plot of 6.8 million gross acres in Egypt’s Western Desert. The Herunefer-1X discovery, in the Matruh basin within the eastern portion of the Khalda Offset Concession, encountered pay in the Alamein, Alam El Buieb-6 (AEB), Masajid, Upper Safa and Lower Safa formations. Tests from the Lower Safa and Upper Safa intervals flowed at a combined rate of 49 MMcfgd and 7,700 bcpd. Estimated cost to drill and complete the well was $6 million. The BAT-1X discovery, in the northern Shushan basin of the Khepri-Sethos Development Lease, tested at a rate of 31 MMcfgd and 390 bcpd from a thick Paleozoic Shiffah sandstone interval. The well, which was drilled to a TD of 15,555 ft, also encountered pay in the Cretaceous Upper Bahariya, Lower Bahariya, Alamein, AEB-3C and AEB-3D formations. Estimated cost to drill and complete the well was $5.25 million. Both discoveries were drilled by Khalda Petroleum Company, an Apache-operated JV with Egyptian General Petroleum Company. Apache plans to drill several trend exploration wells in 2014. Alternatives for delivering production to market are under evaluation.

Eni appraises Agulha discovery in Mozambique

Eni has successfully executed the appraisal campaign for its Agulha discovery, in Area 4 offshore Mozambique. The delineation was carried out through the Agulha 2 well, which was drilled in a 2,603-m water depth and reached a TD of 5,645 m. The well is in the southern part of the Area 4 Block, approximately 12 km south of the Agulha 1 discovery well and 80 km off the Cabo Delgado coast. Agulha 2, which is the 12th well drilled successfully in Area 4, proved about 25 m of gas column in good-quality Paleocene reservoir sandstones, and confirmed the field’s southern extension. Eni said it is considering further exploration drilling in the southern part of Area 4 after Agulha 2. Total resources discovered in Area 4 are estimated at approximately 85 Tcf of gas-in-place.

Exxon Mobil reported that its affiliate, ExxonMobil Exploration Argentina, jointly with Gas y Petroleo del Neuquen, has discovered oil and gas in an unconventional shale well in Neuquen Province. Found in the liquids-rich area of the Vaca Muerta play, the Bajo del Choique X-2 well was drilled to a TMD of approximately 15,000 ft. The well’s horizontal leg extends for 3,280 ft. The well was completed in the Vaca Muerta formation, and flowed at an average 770 bopd on a 12/64-in. choke in its first flow test. Data analysis and additional studies are being conducted to fully evaluate this discovery. Appraisal wells will also need to be drilled before a commerciality decision can be made, said the operator. This is the first Exxon Mobil-operated discovery in the Vaca Muerta play, according to Exxon Mobil Exploration Company President Stephen M. Greenlee. Exxon Mobil is operator and holds an 85% working interest in the Bajo del Choique Block. Gas y Petroleo del Neuquen holds 15% interest.

ACQUISITIONS

Shell announced on May 21 that it has agreed to sell its 100% working interest in approximately 106,000 net acres in Dimmit, LaSalle and Webb Counties, Texas, to Sanchez Energy Corporation for approximately $639 million, subject to closing. The sale includes approximately 176 operated producing wells, and associated field facilities and infrastructure. Net production in first-quarter 2014 was approximately 24,000 boed, of which about 60% were crude and NGLs. The acreage holds 60 MMboe of total proved reserves. The agreement is effective Jan. 1, and is expected to close at the end of the second quarter of this year. Shell said that the transaction is part of the restructuring of its North American resource play (shale oil and gas) portfolio, to focus on acreage positions that can reach the scale required by the company. For Sanchez Energy, the additional acreage is expected to bring the company’s total position in the Eagle Ford to approximately 226,000 acres, with up to 3,000 potential drilling locations and average first-quarter 2014 pro forma production of about 42,800 boed, according to the buyer.

IGas Energy and Dart Energy Limited announced that they have reached an agreement, whereby IGas will acquire Dart for an estimated $195 million. This acquisition will result in an onshore UK oil and gas company with the largest acreage under license in the country, totaling more than 1 million net acres, including plots in major shale basins. Dart has canceled its planned listing on the AIM Market of the London Stock Exchange. According to the two company boards, the “financially strengthened group” is complemented by a work program for 13 licenses funded by GDF Suez, and two funded by Total E&P UK. The new entity will possess a team of more than 200 staff members, including subsurface, drilling, commercial and legal experts.

Petrobras began production from well 7-LL-22D-RJS in the Santos basin’s pre-salt Lula field (Lula NE Pilot area) on May 9. The well, with a reported potential of 26,000 bopd, is connected to FPSO Cidade de Paraty via a new platform connection system deployed for the first time at Lula. Using this system, the production riser section is supported by a submerged buoy at a water depth of 240 m; the wellhead is at a water depth of 2,130 m. During 2014, six more wells will be connected to the platform (four production wells and two injectors) using the riser support buoy (RSB) system, ramping up the FPSO to its full production capacity of 120,000 bopd in third-quarter 2014. According to Petrobras, when deployed, the RSB will be immune to platform movements, meaning that rigid steel pipes (steel catenary risers) can be used in some parts of the ultra-deepwater project. Subsea 7 built and deployed the system.

Exxon Mobil said that it shipped the first cargo from its $19-billion Papua New Guinea LNG project, where it began production in April. PNG LNG, operated by affiliate Exxon Mobil PNG Limited, is expected to produce more than 9 Tcf of gas over its estimated 30 years of operations. The first cargo is bound for LNG customer Tokyo Electric Power Co. Inc. (TEPCO) in Japan. Production from the first train started in late April, and production from the second train has also begun, as additional wells come online.

Australian E&P company AWE reported that its Pateke-4H development well was completed successfully and suspended for production at a later date. Output from Pateke-4H is planned for first-half 2015. This will follow installation and commissioning of a subsea flowline and ancillary control equipment, connecting the well to the Tui field gathering system. This work is scheduled to commence in first-quarter 2015. Preparations are being made to relocate the Kan Tan IV rig.

EXPLORATION

BUSINESS

Following extensive public consultation, Cuadrilla Resources has submitted a planning application to the Lancashire County Council to drill, hydraulically fracture and test the flow of gas from up to four exploration wells, at its proposed exploration site at Preston New Road. Once the planning application for the site in northwestern England has been validated by the council, it is anticipated that the application will be decided within a 16-week determination period. Plans will also be submitted to install a network of seismic monitoring stations within a 4-km radius of the proposed exploration site. As part of the process, planning and environmental consultants at Arup have produced a detailed Environmental Impact Assessment (EIA) that will accompany the planning application, Cuadrilla said. A separate planning application for a second proposed exploration site, at Roseacre Wood, was also to be submitted to the council, following the Preston New Road application.

BP said it will seek review by the U.S. Supreme Court of the decisions made by the Fifth Circuit relating to the compensation of claims for losses with no apparent connection to the Deepwater Horizon spill in 2010. The operator said it will ask the Fifth Circuit not to issue its mandate until the Supreme Court has considered the matter. Suspension of the mandate would keep the stay of business economic loss payments in place during that time, according to the announcement. BP’s decision to seek higher review follows the Fifth Circuit’s denial of BP’s request for a rehearing. According to BP, “if the Fifth Circuit’s erroneous ruling were allowed to stand, it would fundamentally redefine the prerequisites for class membership,” which is an issue at hand in this case. “That, in turn, will surely alter the calculus for companies in determining whether to enter into class action settlements or engage in protracted litigation that would delay compensation for true victims,” BP continued in a statement.