GENERAL INTEREST — Quick Takes
Study outlines potential growth from shale energy
Shale oil and gas development has helped create 1.75 million US jobs in the past few years and potentially could be responsible for 2.5 million by 2020 and 3.5 million by 2035, an independent study commissioned by the US Chamber of Commerce and three major trade associations concluded.
Shale energy was responsible for $62 billion in federal, state, and local tax revenue during 2012, according to the IHS-CERA study entitled, America's New Energy Future: The Unconventional Oil & Gas Revolution & the US Economy.
It said between now and 2035, shale energy could contribute more than $2.5 trillion in tax revenue, with more than half going to state and local governments. Oil and gas producers are expected to invest more than $5.1 trillion in shale resource development during that period, the Oct. 23 study indicated.
The study, which was commissioned by the US Chamber's Institute for 21st Century Energy, the American Petroleum Institute, the American Chemistry Council, and the Natural Gas Supply Association, is the first of three reports, with the second listing state-by-state impacts and the third outlining refining, chemical, manufacturing, and other effects.
Report released listing undrilled offshore leases
More than 100 oil and gas producers hold—but are not drilling—nearly 3,700 leases in the Gulf of Mexico covering an area about the size of North Carolina, a new report by the US House Natural Resources Committee's minority staff concluded.
The report noted that the five largest oil companies—BP PLC, ExxonMobil Corp., Chevron Corp., ConocoPhillips, and Royal Dutch Shell PLC—hold 8 million acres, or almost 40% of the total.
"The oil companies are sitting on huge reserves of oil they're not even using, and they come back asking for more areas to be opened up for them to drill," said Rep. Edward J. Markey (D-Mass.), the committee's ranking minority member who requested the Oct. 22 report.
"President Obama is right: When it comes to the oil drilling leases these companies hold on America's public land, they need to use it or lose it to a company that will drill," he maintained.
A spokesman for the American Petroleum Institute said on Oct. 23 that the report is "an attempted distraction by those who are looking to save face for failing to present sound energy policy to the American people who want more development of our own energy resources (over 70%) and those who recognize that it creates more American jobs (over 90%)."
Halcon Resources to acquire Williston basin assets
Halcon Resources Corp. agreed to acquire producing and undeveloped assets in the Williston basin's Bakken and Three Forks formations in North Dakota from privately held Petro-Hunt LLC for $1.45 billion cash-stock transaction.
The assets involve 81,000 net acres primarily in Williams, Mountrail, McKenzie, and Dunn counties. Halcon's board unanimously approved the transaction, which remains subject to closing conditions and regulatory clearance. Closing is expected in December.
The assets being acquired produce on average more than 10,500 boe/d net. Third-party reserve engineers have estimated proved reserves at 42.4 million boe, of which 88% is oil. Currently, five operated drilling rigs are running on the properties.
Upon closing, Halcon will hold interest in more than 135,000 net acres in the Williston basin and companywide average net production of 26,500 boe/d.
Floyd C. Wilson, Halcon's chairman and chief executive officer, said, "This transaction improves our leverage profile and will effectively increase our estimated proved reserves on a pro forma basis by over 58% to approximately 115 million boe, 79% of which is liquids."
Halcon was named Ram Energy Resources until it was bought by Wilson, chief executive of Petrohawk Energy. Wilson also is chairman and president of Halcon.
BHP Billiton Ltd. bought Petrohawk Energy for $12 billion last year. Earlier this year, Halcon bought GeoResources Inc. for nearly $1 billion (OGJ Online, Apr. 25, 2012).
Statoil, Wintershall to swap interests
The Norwegian subsidiary of Wintershall Holding GMBH, Kassel, Germany, has agreed to swap Norwegian North Sea interests with Statoil in a deal intended to make it operator of its first large platform development offshore Norway.
Wintershall Norge will receive a 32.7% interest in Brage oil field, a 15% interest in Gjoa oil and gas field, and a 30% interest in Vega gas and condensate field tied to the Gjoa facility. It also will receive 30% interests in Production Licenses (PL) 090C and 248-248B.
Statoil will retain interests of 5% in Gjoa, 24% in Vega, 15% in PL090C, and 30% in PL248-248B. It will have no remaining Brage interest.
The Norwegian company will receive from Wintershall a 15% interest in the Edvard Grieg license, for which operator Lundin Norway has received development approval, and net proceeds of $1.45 billion (OGJ Online, Oct. 16, 2012). The payment by Wintershall includes a contingent $100 million related to production from Vega.
After the transaction, Edvard Grieg interests will be Lundin 50%, OMV 20%, and Statoil and Wintershall 15% each.
The companies have agreed that Wintershall, subject to approvals by authorities and partners, will become operator of Brage. The field has been on production since 1993 and currently flows about 14,000 b/d of oil with associated gas and condensate through a fixed drilling, production, and accommodation platform on a steel jacket in 140 m of water.
Statoil's production from the properties to be divested totaled 39,000 boe/d in the first half of this year.
The companies signed a memorandum of understanding to form a strategic partnership that includes cooperative research on enhanced oil recovery, on offshore use of a Wintershall biopolymer oil recovery technology, and on unconventional resources in Germany and elsewhere.
Statoil will receive 49% shares of Wintershall's Rheinland and Ruhr concessions in Germany.
Exploration & Development — Quick Takes
ExxonMobil to add Black Sea deepwater rights
ExxonMobil Exploration and Production Romania and OMV Petrom will acquire a 65% interest in the southeastern deepwater extremity of Block 15 Midia in the Black Sea offshore Romania from Sterling Resources Ltd., Calgary.
The sale portion of the Midia block covers 125,000 gross acres 35 km northwest of ExxonMobil and OMV Petrom's Domino-1 giant gas discovery on the Neptun block. The sale portion of Midia also contains the newly identified Anca and Maria prospects. Domino, 150 km off Constanta, has identified a resource of 1.5 to 3 tcf of gas.
As part of the same sale agreement, Sterling's partner Petro Ventures Europe BV is selling its 20% interest in the same acreage.
Sterling will receive $29.25 million upon completion, a contingent $29.25 million on satisfaction of certain conditions relating to a hydrocarbon discovery made on the sale portion, and a further contingent payment of $19.5 million upon first commercial production from the sale portion. Completion is subject to governmental approvals and other conditions.
The sale does not include any of the discoveries or other prospects in the Midia block and will not be affected in any way by the results of the Ioana-1 well currently being drilled (OGJ Online, Oct. 7, 2012).
The previously announced process for partial divestment of Sterling's interest in the Luceafarul, Midia, and Pelican blocks shoreward in Romanian waters continues. However, Sterling will not proceed with the possible sale of its interest in Cladhan field in the UK North Sea.
Mike Anzacot, Sterling president and chief executive officer, said, "This carve-out and sale of an area in deeper waters allows us to focus on the development and exploration of fields and prospects in shallower waters, where drilling and construction should be less expensive. This transaction is additional evidence of the rapidly growing industry interest in the Romanian Black Sea as a new hydrocarbon region where Sterling has a material presence."
ConocoPhillips begins gas flow from Boreas
ConocoPhillips and joint venture partner Karoon Gas Australia reported that the Boreas-1 wildcat well drilled in Browse basin permit WA-315-P offshore Western Australia has flowed natural gas at a stabilized rate of 30.2 MMcfd. The gas flowed through a 40⁄64-in. choke with 3,300 psi flowing wellhead pressure.
The zone tested is a 70-m perforated section of the Plover formation at 4,904-74 m below the rotary table.
The test will continue for 5 days, including shut-in periods, and will also involve downhole sampling of the reservoir fluids as well as production logging.
Boreas is part of the joint venture's assessment of the overall deliverability of the primary reservoir underpinning the Greater Poseidon Trend in the region that contains an estimated contingent resource of 7 tcf of gas on a P50 basis.
ConocoPhillips is operator of the jointly held permits WA-314-P, 315-P, and 398-P, which contain the earlier Poseidon and Kronos gas discoveries. Boreas-1 is 4 km south of Poseidon-1 on a large tilted fault block, which itself is part of the northeast trending structural high of the greater Poseidon structure.
The well, drilled by semisubmersible rig Transocean Legend, is a test of the extent, presence, and quality of the reservoirs within the Boreas fault block.
All well data will be integrated into the existing data files containing the Poseidon and Kronos wells as well as the Poseidon 3D seismic results to further define the size and composition of the greater Poseidon trend.
Following the Boreas test program the Transocean Legend will drill Zephyros-1 and then Proteus-1.
Zephyros will evaluate the flank of a fault block 9 km west of Kronos-1. Proteus will be 15 km east of Zephyros to evaluate a fault block on the eastern flank of the greater Poseidon trend.
Two further wells are planned, but have yet to be named. The JV also has the option of another three wells in the program.
Dana Gas to start up Nile Delta dry gas discovery
Dana Gas PJSC, Sharjah, is preparing a development plan for a discovery of 4-6 bcf of gas in place, its second this year and its 23rd since 2006 in Egypt's onshore Nile Delta.
West Sama-1 in the West El Qantara concession is the first dry gas discovery in the shallow Pliocene Kafr El Sheikh formation in 2012. It will be tied into the company's nearby South El Manzala gas processing plant within a week.
West Sama-1 is near the Sama-1 and Sama-2 dry gas discoveries in the slightly deeper Mio-Pliocene Abu Madi formation.
Dana Gas said it has a sizable portfolio of drillable prospects and that it will continue its exploratory drilling campaign throughout 2013.
The latest new field discovery came after the announcement of commencement of Dana Gas' joint-venture, the Egyptian Bahrain Gas Derivatives Co. NGL extraction plant at Ras Shukheir (OGJ Online, Oct. 22, 2012).
Dana Gas produces gas as operator at 11 Nile Delta fields and in 2011 produced 77.67 bcf of gas and 2.6 million bbl of liquids as Egypt's sixth largest gas producer.
Drilling & Production — Quick Takes
Tax fixes seen lifting UK North Sea output
Oil and natural gas production from the UK North Sea, helped by tax breaks enacted after a surprise rate increase last year, will rebound in the next 5 years before starting a decline likely to be irreversible, according to a forthcoming university study. Alex Kemp, professor of petroleum economics at Aberdeen University, reported highlights of the study at a meeting of the Energy Institute's Aberdeen branch.
After declining by 19% last year to an average 1.8 million boe/d, Kemp said, UK North Sea production will rise to 2.4 million boe/d by 2017 or 2018.
"After 2017-18 there will be a decline, and we cannot see that being reversed," he said. Production still could be 500,000 boe/d in 2042, he added.
The university conducted the study to assess tax breaks introduced by the government for challenging fields after an increase of a supplemental tax on oil and gas producers in the 2011 budget (OGJ Online, May 16, 2011).
"The new allowances have certainly moderated the effect (of the tax hike) very substantially, and it will make a big difference over the medium to longer term," Kemp said.
Firebag bitumen output reaches 120,000 b/d
Suncor Energy says bitumen production from the first three phases of its Firebag in situ project in Alberta reached design capacity of 120,000 b/d at the end of year's third quarter, during which steaming began of wells in the project's fourth phase (OGJ Online, July 28, 2011).
Third-quarter average production was 113,000 b/d at the Firebag complex, more than double the output during the comparable quarter of 2011.
Firebag, in the northern Athabasca oil sands region, produces via steam-assisted gravity drainage supplemented by infill wells to lower steam-oil ratios.
Suncor expects the fourth phase of production to begin by yearend. It expects total Firebag production to reach 180,000 b/d when the fourth phase reaches capacity.
CNPC producing oil from Afghan block
China National Petroleum Corp. is producing 1,950 b/d of oil from Angot field in northern Afghanistan on one of three production-sharing blocks it received in the country's licensing round last year (OGJ Online, Jan. 16, 2012).
The oil is being trucked to Turkmenistan. CNPC is reported to have agreed to build a refinery in Afghanistan.
Angot is a 1967 discovery that has produced oil in the past. It's on the Kashkari block in the Amu Darya basin. CNPC's other blocks, Bazarkhami and Zamarudsay, are nearby.
A second licensing round is to close at the end of this month.
PROCESSING — Quick Takes
Petro Rabigh awards ethylene expansion to JGC unit
Rabigh Refining and Petrochemical Co., a joint venture of Saudi Aramco and Sumitomo Chemical Co., has awarded a contract to JGC Gulf International Co. Ltd. to expand ethylene capacity at Petro Rabigh's refinery and chemicals complex on the Red Sea.
Part of the Phase 2 expansion at the site, the lump-sum contract calls for engineering, procurement, and construction. The expanded plant will be able to produce 300,000 tonnes/year of ethylene and is to be completed in 2015. JCG Gulf is a wholly owned, Saudi Arabia-based unit of JGC Corp.
Petro Rabigh announced in March 2009 that it was studying the expansion (OGJ Online, Mar. 23, 2009).
The recent JGC announcement said that Petro Rabigh has been operating a refining and petrochemicals complex—Rabigh 1—while it was conducting the feasibility study for Rabigh 2. The ethylene plant that JGC Gulf will be expanding can produce as much as 1.3 million tpy. It was built by JGC Yokohama and started up in 2008 as a part of Rabigh 1.
Aramco lets contracts for Jazan refinery, terminal
Saudi Aramco has completed contractor selection for the engineering, procurement, and construction of the Jazan refinery and terminal in the southwest of the country.
Following front-end engineering design in April, Aramco selected Saudi Arabian and international contractors, as follows: Petrofac Saudi Arabia Ltd. and Hyundai Arabia Co. Ltd., Saudi Arabia; Hanwha Engineering & Construction Corp. and SK Engineering & Construction Co. Ltd., South Korea; Tecnicas Reunidas, Spain; and JGC Corp. and Hitachi Plant Technologies Ltd., Japan.
The project is slated for completion in late 2016. It will be a 400,000 b/d refinery with associated terminal on the Red Sea near Jazan. It will process Arabian Heavy and Arabian Medium crude oils, and produce gasoline, ultralow-sulfur diesel, benzene, and paraxylene.
Operations at the refinery will be coordinated with a large integrated gasification combined cycle plant currently under the FEED contract.
The marine terminal will be able to handle very large crude carriers (200,000-400,000 dwt) for supplying oil to the refinery and a range of product carriers to handle the refinery's exports.
Bosnia and Herzegovina refinery due upgrade
Rafinerija Nafte Brod, operator of Bosnia and Herzegovina's only refinery, will use technologies from Honeywell's UOP LLC and ExxonMobil Research & Engineering Co. (EMRE) in an upgrade of its 240,000 b/d facility at Brod.
The licensing agreement is the first under an alliance formed by UOP and EMRE last year.
The refiner will combine UOP Unicracking technology with EMRE's distillate and lubricant dewaxing technologies to increase fuel and lube yields.
The complex will upgrade more than 45,000 b/sd of kerosene, diesel, and vacuum gas oil into high-quality diesel and jet fuels. It also will produce high-quality base oils to be used for production of lubricants at Refineria Ulia Modricha, which is under construction and slated to start up in 2016.
TRANSPORTATION — Quick Takes
Dana Gas loads first cargo from Egyptian plant
Egyptian Bahrain Gas Derivatives Co., a joint venture involving Dana Gas PJSC, loaded the first propane cargo on Oct. 1 from its NGL extraction plant at Ras Shukheir, Egypt. The project has taken more than 2 years to complete.
The plant is fed at 55-80 MMscfd from the nearby Unit 104 gas plant of Egyptian General Petroleum Corp. When fully operating, said the company, the plant will extract 120,000 tonnes/year of propane and butane from a gas stream of 150 MMscfd (OGJ, June 23, 2008, p. 50). The feed gas rate is to increase gradually once gas is received from gas fields in and around Ras Shukheir.
Rashid Al Jawan, executive director and acting chief executive officer of Dana Gas, said the Ras Shukheir plant is the company's third gas processing plant to be commissioned in Egypt. Its total cost was about $125 million. The extraction plant sits adjacent to EGPC's Unit 104 gas plant at Ras Shukheir.
Gas processing and marketing of propane and butane are the main activities of the project, said the company, which expects the plant to recover 100% of the butane in feed gas form and 97% in propane form. The butane is sold in Egypt, while the propane will be exported. Residue gas will be supplied to the national gas grid.
The announcement said Dana Gas holds 26.4% interest in EBGDC through Dana Gas's 66% ownership of Danagaz Bahrain, which holds 40% of EBGDC. Other shareholders include Egyptian Natural Gas Holding Co. (Egas; 40%) and Arab Petroleum Investments Corp., a pan-Arab financial institution based in Saudi Arabia (20%; OGJ Online, July 23, 2007).
Dana Gas operates in the Nile Delta producing gas and associated liquids from 11 fields and is the 50% operator alongside Sea Dragon Energy and produces oil from a field in Upper Egypt.
During 2011, Dana Gas Egypt produced 77.67 bcf of gas and 2.6 million bbl of liquids, it said.
China starts construction on West-East Gas Pipeline
China National Petroleum Corp. has started construction of the country's Third West-East Gas Pipeline (WEPP 3), comprising 7,378 km spread over one trunkline and eight branches. Three gas storage sites and one LNG liquefaction plant are also part of the project. The 5,220-km trunk will start in Horgos, Xinjiang, and end at Fuzhou, Fujian province, crossing 10 provinces and regions. The pipeline will deliver 30 billion cu m/year using an operating pressure of 10-12 MPa.
CNPC expects the pipeline to be completed in 2015, connecting to Line C of the Central Asia-China Gas Pipeline, also now under construction. WEPP 3 will mainly transport gas from the Central Asia pipeline, using incremental production in Tarim basin and coal gas in Xinjiang to supplement supplies.
Rolls-Royce was awarded a contract to supply compression for the project in 2010 (OGJ Online, June 29, 2010).
CN, Tundra Energy to build rail terminal
Canadian National Railway Co. (CN) and Tundra Energy Marketing Ltd. agreed to build an oil rail terminal near Cromer, Man., to transport Bakken crude for producers in Manitoba and Saskatchewan. TEM handles oil on behalf of producers in the Williston basin, including its parent company, Tundra Oil & Gas Partnership.
Scheduled to start operating in second-quarter 2013, the terminal initially will be able to load more than 50 tank cars or 30,000 b/d. Design plans call for terminal to have capacity to accommodate a unit train of 100 tank cars or 60,000 b/d of oil.
TEM executives said the rail terminal will producers a transportation option given inadequate pipeline take-away capacity.
CorrectionIn a recent story about KazEnergy (OGJ, Oct. 22, 2012, p. 23), the oil, gas, and energy association was misidentified as an international trade association. Also, crude oil transportation capacities for Caspian Pipeline Consortium (CPC) and Atyrau-Samara (AS) were listed incorrectly; CPC transports 34.2 million tonnes/year and AS transports 15.4 million tpy. Lastly, the name of the joint venture of Kazakhstan and Gazprom is KazRosGas. |
