EXPLORATION

Norway’s 23rd licensing round attracts 26 companies

The application deadline for licenses in Norway’s 23rd licensing round expired in December, with 26 companies applying for acreage. This round comprises 57 announced blocks or parts of blocks, three of which are in the Norwegian Sea and 54 in the Barents Sea. Thirty four of the announced blocks are situated in the newly opened area of the southeastern Barents Sea, and many of the applications target this acreage in particular. “It is good to see that so many competent companies want to explore in new acreage, during a time when we are experiencing low oil prices and substantial cost cuts,” said Sissel Eriksen, the Norwegian Petroleum Directorate’s exploration director. Norway’s Ministry of Petroleum and Energy plans to award the new licenses sometime before the summer of 2016.

Wintershall eyes Vaca Muerta shale with new investment

Wintershall and local state-owned energy company, Gas y Petróleo del Neuquén, have signed an agreement, under which Wintershall will increase its interest in Argentina’s Aguada Federal Block from 50% to 90%. In March 2015, Wintershall began an owner-operated exploration campaign in the block; the Kassel, Germany-based company already has drilled two vertical exploration wells, which were being tested as of the company’s investment announcement on Dec. 23. The exploration wells aim to provide information about the characteristics of the oil and gas reservoir, which includes promising shale rock of the Vaca Muerta formation.

Schlumberger, Statoil ink contract for Campeche basin survey

Statoil Gulf of Mexico, LLC, has agreed to license a large part of the WesternGeco Campeche wide-azimuth (WAZ), deepwater, multi-client seismic survey in the southern Gulf of Mexico, according to a Schlumberger statement dated Dec. 21. The license also includes collaboration with WesternGeco in the seismic processing phase. “We are pleased to have the opportunity to collaborate with Statoil in this breakthrough project, which is the first WAZ, multi-client broadband survey in Mexican waters of the Gulf of Mexico,” said Maurice Nessim, president of WesternGeco. “The complexity of the geology in the Campeche requires wide-azimuth acquisition to image the subsalt effectively, and we are bringing all of our experience gained in the U.S. Gulf of Mexico to deliver enhanced subsalt imaging to our clients.” A fleet of eight vessels is conducting the survey in the Bay of Campeche for the three-year project. Image: Schlumberger.

USGS doubles Barnett shale gas estimate after new study

The Barnett shale contains estimated, mean volumes of 53 Tcf of shale gas, 172 MMbbl of shale oil and 176 MMbbl of NGLs, according to an updated assessment by the U.S. Geological Survey (USGS). This estimate is for undiscovered, technically recoverable resources. The previous USGS assessment of Texas’ Barnett shale was released in 2003, as part of an assessment of conventional and unconventional reservoirs of the Bend Arch-Fort Worth basin province. That assessment estimated a mean of 26.2 Tcf of undiscovered natural gas and 1.0 Bbbl of undiscovered NGLs within the Barnett shale. Potential oil resources were not assessed quantitatively for the Barnett at that time. “We decided to reassess the Barnett shale, following the successful introduction of horizontal drilling and hydraulic fracturing, setting the stage for the current shale gas boom,” said USGS scientist Kristen Marra, who led the assessment.

DISCOVERIES

Wintershall strikes North Sea oil find

Wintershall Norge, operator of production license 248 in the Norwegian sector of the North Sea, has found oil with wildcat 35/11-18 and appraisal well 35/11-18 A. The wells were drilled about 4 km west of Vega Sør field. The primary exploration target for well 35/11-18 was to prove petroleum in Middle Jurassic reservoir rocks (the Brent group). The secondary exploration target was to prove petroleum in Upper Jurassic reservoir rocks (sandstones in the Heather formation). In the primary target, the well encountered a 275-m thickness of moderate-to-good reservoir quality in the Brent group. The well proved light oil in the Tarbert and Oseberg formation, with columns of 11 m and 3 m, respectively. In the secondary exploration target, the well encountered an 8-m hydrocarbon column of good-to-poor reservoir quality. The objective of appraisal well 35/11-18 A was to investigate the extent of the reservoir and the hydrocarbon columns. The appraisal was drilled about 450 m south of the discovery. The well proved gas and oil in two Upper Jurassic (Heather formation) sandstones, with net thicknesses of 33 m and 24 m, respectively, and poor-to-good reservoir quality. The well encountered oil throughout the Brent group, which is 270 m, with moderate-to-good reservoir quality. The well also encountered a 46-m column of light oil in the Lower Jurassic (Cook formation). Preliminary estimates place the discovery size at between 1 MMscm and 3 MMscm of recoverable oil.

Lundin discovers oil in Rolvsnes prospect, offshore Norway

Lundin Norway has completed the Rolvsnes exploration well as an oil discovery, the company announced on Dec. 22. Well 16/1-25 S is on the southwestern flank of the Utsira High, approximately 6 km south of the Lundin Petroleum-operated Edvard Grieg field and 3 km south of the Edvard Grieg South discovery. The well was drilled to a TD of 2,096 m below mean sea level, in a water depth of 106 m. The well encountered a gross oil column of 30 m in a porous granitic basement. Pressure data and the oil type indicate that the petroleum system is in communication with the Edvard Grieg South discovery, which was made by Lundin Norway in 2009. Extensive data acquisition and sampling were carried out in the reservoir, including conventional coring and fluid sampling. A production test was performed, achieving a production rate of 265 boed through a 36/64-in. choke. Further studies will be required to incorporate all the findings and establish future planning. The gross contingent resource range for Rolvsnes, based on natural depletion drive, including the Edvard Grieg South discovery, is estimated to be between 3 MMboe and 16 MMboe. There remains significant resource upside, including the potential to find a more extensive fracture network and secondary recovery potential. Including this prospective upside potential, the total gross resource estimate is between 10 MMboe and 46 MMboe.

GOVERNMENT/REGULATORY

ConocoPhillips exports first U.S. shale oil

NuStar Energy and ConocoPhillips have exported the first cargo of U.S.-produced oil since the 40-year-old ban was lifted on Dec. 18. ConocoPhillips committed to sell Eagle Ford light crude oil/condensate to international trading company Vitol, according to a NuStar statement announcing the shipment. The cargo departed from the company’s North Beach terminal, in the Port of Corpus Christi, Texas, on Dec. 31. NuStar has invested heavily in recent years to expand its South Texas Crude Oil Pipeline System, to move crude oil from the Eagle Ford shale to Corpus Christi. “Based on our investments in Corpus Christi and our South Texas pipeline system, NuStar was well-positioned, equipped and staffed to immediately begin loading cargoes for export,” said NuStar President and CEO Brad Barron. Image: ConocoPhillips.

Lake Charles LNG project gets green light from FERC

The Lake Charles LNG export project has received approval from the U.S. Federal Energy Regulatory Commission (FERC) to construct and operate a natural gas liquefaction and export facility in Lake Charles, La. FERC approval is the key, remaining regulatory consent for the Lake Charles LNG project, which BG Group is developing with Energy Transfer Equity LP and Energy Transfer Partners, LP. Energy Transfer owns an existing LNG regasification facility in Lake Charles, which will be converted to a liquefaction facility. The project has conditional authorization from the U.S. Department of Energy for the export of up to 2 Bcfgd, or approximately 15 MMtpa of LNG. Final investment decisions from both BG Group and Energy Transfer are expected to be taken in 2016.

NESA agrees to merge with Texas Alliance

The governing bodies of the National Energy Services Association (NESA) and the Texas Alliance of Energy Producers have approved the unification of the membership of both organizations to better serve the needs of their members. “Both organizations believe that this move will be most beneficial for the members of NESA and the Alliance,” said Alliance Chairman George Rogers. The Alliance will establish an Energy Services Section to meet the needs of NESA members.

PRODUCTION

Exxon Mobil increases Banyu Urip output with facility start-up

Exxon Mobil has started the onshore central processing facility at Indonesia’s Banyu Urip field, helping increase production to more than 130,000 bopd. With the central processing facility now online, production will continue to increase in the coming months. Once full-field production is reached, Banyu Urip will represent approximately 20% of Indonesia’s 2016 oil production target. Banyu Urip is expected to produce 450 MMbbl of oil over its lifetime. The project consists of 45 wells producing from three well pads, an onshore central processing facility, a 60-mi onshore and offshore pipeline, a floating storage and offloading vessel, and tanker loading facilities, in the Java Sea. Exxon Mobil, partnering with PT Pertamina EP Cepu and the Cepu Block Cooperation Body, commenced production from Banyu Urip in late 2008, and output has increased as additional facilities have been brought online in 2014 and 2015. Exxon Mobil operates Banyu Urip with a 45% interest.

TAQA announces first oil from Cladhan field

Abu Dhabi National Energy Company PJSC (TAQA) has announced first oil from the new Cladhan field development in the UK sector of the North Sea. The field is developed as a subsea tie-back to the TAQA-operated Tern Alpha platform. Cladhan field is in the northern North Sea, approximately 100 km north east of the Shetland Islands, in a water depth of approximately 150 m. The field lies 17.5 km southwest of the Tern platform and straddles UKCS Blocks 210/29a and 210/30a. The development consists of two producing wells and one injector. TAQA operates Cladhan with a 64.5% interest.

Total’s latest project offshore Congo is operational

Total has brought the Moho Phase 1b project onstream, 75 km off the coast of Pointe-Noire, Republic of the Congo. The Total-operated project has a production capacity of 40,000 boed. Moho Phase 1b, in water depths ranging from 750 m to 1,200 m, involves the drilling of 11 new subsea wells and the installation of what are claimed to be the two most powerful subsea multiphase pumps in the world. It is tied back to the existing floating production unit on Moho Bilondo field, which has been producing since 2008. The nearby Moho Nord development, launched concurrently with Moho Phase 1b in 2013, is ongoing and will add a further 100,000 boed of capacity. “Moho Phase 1b is our ninth start-up since the beginning of the year, and will contribute to our strong production growth in the years to come,” said Arnaud Breuillac, Total’s president of E&P.

BUSINESS

Statoil submits $940-million PDO for North Sea project

Statoil and its partners have submitted a Plan for Development and Operation (PDO) for Oseberg Vestflanken 2 field in the North Sea. The new development will consist of an unmanned wellhead facility, which will both recover oil and gas from new deposits and improve the recovery rate from other producing deposits. The development cost is projected at $940 million, and will facilitate the recovery of about 110 MMboe. Oil accounts for nearly 63 MMbbl of the reserves; the rest is gas. Oseberg Vestflanken 2 will be developed with a simplified, unmanned wellhead facility with 10 well slots. Two of these will be used to inject gas to improve oil recovery. Two production wells also will be drilled from an existing subsea template on Vestflanken. Further injection will take place by obtaining gas, through a new pipeline, from the existing gas injection system in the area. The wells on Vestflanken 2 will be operated from the Oseberg field center, where the oil and gas also will be processed.

Technip wins contract for ultra-deepwater Odd Job field

Technip has been awarded a lump-sum contract by Deep Gulf Energy II, LLC, for the development of Odd Job field. This ultra-deepwater field is in Mississippi Canyon, offshore New Orleans, in the Gulf of Mexico, in water depths ranging from 1,330 m to 1,825 m. The contract consists of project management and engineering services; fabrication and installation of approximately 23 km of pipe-in-pipe flowline; fabrication and installation of approximately 2 km of steel catenary risers; design, fabrication and installation of in-line sled, flowline end termination; fabrication of jumper; and pre-commissioning for the flowline and SCR system. The offshore installation is expected to be performed later this summer by Technip’s vessel, the Deep Blue.

MERGERS/ACQUISITIONS

BP expands in San Juan basin

BP’s U.S. Lower 48 onshore oil and natural gas business has significantly expanded its operations in the San Juan basin, which spans northern New Mexico and southern Colorado, by acquiring all of Devon Energy’s assets in the region. This marks the first major acquisition by this business in more than seven years. The bulk of the acquired assets consist of Devon’s operated interest in the Northeast Blanco Unit (NEBU), a section of federal lands in San Juan and Rio Arriba counties of New Mexico, where BP has had a presence since the 1920s. BP anticipates taking over operations of the unit’s 480 wells, spread across 33,000 gross acres, in the first quarter of 2016.

Cameron shareholders vote in favor of Schlumberger merger

Cameron’s stockholders have voted to adopt the merger agreement providing for acquisition of Cameron by a wholly owned subsidiary of Schlumberger. Upon completion of the transaction, each share of Cameron common stock will convert into the right to receive 0.716 shares of common stock of Schlumberger Ltd. and a cash payment of $14.44. “We are pleased that our stockholders have clearly recognized and endorsed the significant value generated by this transaction,” said Scott Rowe, president and CEO of Cameron, in a statement. “The combination of the two organizations will create a premier oilfield equipment and services company uniquely positioned to deliver superior value to the industry.” The transaction remains subject to regulatory approvals and customary closing conditions. The companies expect the acquisition to close during first-quarter 2016. Image: Cameron.

Tellus calls off Wintershall asset deal

Tellus Petroleum has called off a $602-million deal to buy Wintershall’s interest in a number of assets offshore Norway. Under the deal, Wintershall would have divested its stake in four non-operated fields—Knarr (20%), Veslefrikk (4.5%), Ivar Aasen (6.4615%) and Yme (10%)—on the NCS. The planned transaction also involved a 15% stake in the Wintershall-operated Maria development; equity stakes in seven exploration licenses; and ownership interests in the Utsira High gas pipeline, the Edvard Grieg oil pipeline and the Knarr gas pipeline.

Devon to buy acreage in Anadarko, Powder River basins

Devon Energy has agreed to acquire 80,000 net surface acres, with up to 10 prospective zones, in the Anadarko basin’s STACK play from privately held Felix Energy, a portfolio company of EnCap Investments, for $1.9 billion. In a separate transaction, the company also has agreed to acquire 253,000 net acres in the Powder River basin for $600 million. The transactions will be funded with approximately $1.35 billion of Devon equity issued to sellers and approximately $1.15 billion of cash on hand and borrowings. “These acquisitions materially core up our position in two of the best emerging North America development oil plays and further upgrade our asset portfolio,” said Dave Hager, president and CEO.