GENERAL INTEREST — Quick Takes
SEAB subcommittee studies safety risks of shale gas
Increased transparency and best practices were emphasized in a preliminary, 90-day report from the Shale Gas Subcommittee of the Secretary of Energy Advisory Board (SEAB). The subcommittee focused on ways to reduce environmental and safety risks of US shale gas production.
The recommendations are open to public comment, and the subcommittee is scheduled to submit a final report in November.
The seven-member SEAB subcommittee issued recommendations for key areas of shale gas production although it stopped short of outlining specifics of achieving those recommendations, which largely seek to protect air and water quality.
Public concern and debate about shale gas has grown with expanding US shale gas production. Possible pollution of drinking water from methane and chemicals used in hydraulic fracturing stimulation is a key concern. Other concerns involve possible air pollution and community disruptions, such as increased truck traffic associated with shale gas exploration and production.
The subcommittee's preliminary report called for full disclosure of chemicals used in fracing as well as for creation of a national database to consolidate all information already available to the public about shale gas.
Regional diversity of shale gas and evolving technology prohibit one best engineering practice for all locations and for all time, the subcommittee report said.
"The subcommittee shares the prevailing view that the risk of fracturing fluid leakage into drinking water sources through fractures made in deep shale reservoirs is remote," the report said. "Nevertheless, the subcommittee believes there is no economic or technical reason to prevent public disclosure of all chemicals in fracturing fluids with an exception for genuinely proprietary information."
Many companies already post this information on their own individual web sites, said subcommittee member Stephen Holditch, chairman of the Department of Petroleum Engineering at Texas A&M University.
The subcommittee recommends gas producers measure and publicly report the composition of fracing fluids pumped into the ground and publicly report the composition of fluids coming back out, Holditch said.
The subcommittee also called for additional field studies on possible methane leakage from gas wells to water reservoirs.
Holditch said gas producers should measure water quality and methane levels in existing water wells before gas drilling. Producers should publicly report the composition of water stocks and flow throughout the fracing and cleanup processes.
"Effective action requires both strong regulation and a shale gas industry in which all participating companies are committed to continuous improvement," the report said.
Holditch noted that the US Department of Energy (DOE) has no mechanism or authority to implement the recommendations because DOE is not a regulator of air quality or water quality. The subcommittee talked with the US Department of the Interior and also the US Environmental Protection Agency, he said.
RPSEA selects small producer program projects
The Research Partnership to Secure Energy for America (RPSEA) selected eight proposals under the unconventional resources program and three proposals under the small producer program for negotiations leading to the awarding of $12.4 million.
The awards are a part of the US Department of Energy's National Energy Technology Laboratory program for ultradeepwater and unconventional natural gas and other petroleum resources research and development program established under the Energy Policy Act of 2005.
The project and project lead for the unconventional resources program are:
• NORM mitigation and clean water recovery from Marcellus frac water, GE Global Research.
• Lowering drilling cost, improving operational safety, and reducing environmental impact through zonal isolation improvements for horizontal wells drilled in the Marcellus and Haynesville shales, CSI Technologies Inc.
• Development of noncontaminating cryogenic fracturing technology for shale and tight gas reservoirs, Colorado School of Mines.
• Novel engineered osmosis technology: a comprehensive approach to the treatment and reuse of produced water and drilling wastewater, Colorado School of Mines.
• A geomechanical analysis of gas shale fracturing and its containment, Texas A&M University.
• Diagnosis of multiple fracture stimulation in horizontal wells by downhole temperature measurement for unconventional oil and gas wells, Texas A&M University.
• Predicting higher-than-average permeability zones in tight-gas sands, Piceance basin: an integrated structural and stratigraphic analysis, Colorado School of Mines.
• Technology Integration Program. Houston Advanced Research Center
The project and project lead for the small producer program are:
• Game changing technology of polymeric-surfactants for tertiary oil recovery in the Illinois basin, Power Environmental Energy Research Institute.
• Predicting porosity and saturations from mud logs and drilling information using artificial intelligence with focus on a horizontal well, Correlations Co. Inc.
• Identifying and developing technology for enabling small producers to pursue the residual oil zone fairways of the Permian basin, San Andres, University of Texas of the Permian Basin.
IPIC acquires Total's 48.83% stake in CEPSA
Total SA sold its entire 48.83% interest in Compania Espanola de Petroleos SA (CEPSA) to Abu Dhabi's sovereign fund International Petroleum Investment Co. (IPIC) for €3.7 billion.
"The transaction allows the Group to further reduce its exposure to European refining," said Total SA, which has cut its European refining capacity by 550,000 b/d day since early 2007.
Total remains active in Spain, expanding its lubricant, specialty product, and chemical operations. IPIC and Total also plan to expand their partnership, especially in exploration and production.
CEPSA is Spain's second-ranked oil company, with a refining capacity of 528,000 b/d, a retail network of around 1,750 service stations in Spain and Portugal, and oil and gas production of 55,000 boe/d.
IPIC held a 47.06% interest in CEPSA before it launched its takeover bid, first buying a 9.5% stake in CEPSA in 1988, and then boosting the stake to about 47.1% in 2009 in a €3.31 billion transaction.
According to one industry observer, this week's deal with Total consolidates the presence of IPIC in the Iberian market and in Europe, and also opens the doors to Latin America, where Cepsa already has modest activities, notably in Colombia, Peru, Panama and Brazil.
Exploration & Development — Quick Takes
Shell to probe N. Raton's deep Pennsylvanian
Shell Western Exploration & Production Inc. will drill the deepest wildcat yet in the northern part of the Raton basin in southeastern Colorado.
The company listed a proposed depth of 14,493 ft for its 2-19 Klikus, in 24-29s-69w, Huerfano County, 2 miles west of La Veta, Colo. Primary objectives are Pennsylvanian sands, zones never before tested in the region, according to IHS Inc.
The location is about 20 miles northwest of shallow coalbed methane and shale gas production in western Las Animas County and 50 miles south of Sheep Mountain carbon dioxide field in northern Huerfano County.
Ron Broadhead, principal petroleum geologist at the New Mexico Bureau of Geology and Mineral Resources in Socorro, said Shell's Pennsylvanian exploration might be aimed at what he calls an "elevator basin." Sparse evidence to the south in the New Mexico part of the Raton basin suggests that an elevator basin underlies the western part of the Raton basin in Colorado, Broadhead said.
But Shell, which is producing gas from and further exploring low-permeability Pennsylvanian rocks in the Tucumcari basin in east-central New Mexico, would be unable to lease the deeper parts of the Raton basin in New Mexico because an El Paso Corp. affiliate owns the minerals in most of that area, Broadhead points out.
Broadhead has touched on the deep Pennsylvanian play in Open-File Report 510, Natural Gas Potential of North-Central New Mexico, and on the AAPG Search and Discovery web site.
Aldous N. Sea find could exceed 200-400 MMboe
Operator Statoil ASA said its Aldous Major South oil discovery in the North Sea off Norway is estimated to have 200-400 million bbl recoverable, could be expanded to the north and south, and with the adjacent Avaldsnes find may support stand-alone development.
Lundin Petroleum AB, which has 10% interest in Aldous Major South, said the 16/2-8 discovery on the Aldous South prospect in PL265 is most likely an extension of the Avalsdnes discovery made by Lundin Petroleum in PL501 in the Greater Luno area (see map, OGJ, Apr. 4, 2011, p. 50).
The preliminary recoverable estimate applies to the part of the structure in PL265, Statoil said. Avaldsnes/Aldous Major South is a "world class oil discovery and likely to be one of the largest Norwegian fields found in recent years," Lundin Petroleum said.
The 16/2-8 well went to 2,083 m true vertical depth in 112 m of water 4 km west of the Avaldsnes discovery well in PL501, where Lundin Petroleum is the operator with a 40% interest and Statoil has 40%. Alvaldsnes found a 17-m oil column.
Aldous Major South encountered gross oil column in excess of 65 m in Jurassic sandstone. Early data acquisition program confirmed excellent reservoir characteristics with a high net-to-gross ratio and the same oil-water contact as the Avalsdnes discovery well indicating likely communication.
The Transocean Leader will complete the 16/2-8 well and spud the Aldous Major North well, which Statoil said also has a considerable potential. The partnership of Statoil, Petoro 30%, Det norske oljeselskap 20%, and Lundin plans two appraisal wells in PL 265 next year, which which a rig is secured.
The result of the Lundin-operated 16/2-7 drilling appraisal well on the Avaldsnes structure will help further clarify the area's potential, Statoil said.
Iraq Kurdistan Swara Tika oil discovery gauged
Two Texas operators have gauged a large oil discovery on the Sarsang block north of Dohuk on the Zagros fold belt in Iraqi Kurdistan.
The Swara Tika-1 discovery well went to a total depth of 12,500 ft and encountered 1,500 ft of gross oil column. Flow rates were established from three zones totaling more than 7,000 b/d of light oil plus associated gas. Tubing size and test equipment capacity limited the flow rates.
Hillwood International Energy, a private Dallas independent, operates the 340,000-acre Sarsang block, which is adjacent to the license that contains the Tawke oil field discovery (OGJ Online, July 27, 2011). Marathon Oil Corp. has 25% interest in Sarsang.
Drilling & Production — Quick Takes
Substation boosts Syria Block 26 oil output
Gulf Sands Petroleum PLC started up the 3,000 b/d EFP 2 oil processing substation in Syria, hiking Block 26 oil production facility capacity to more than 24,000 b/d.
The substation, 1.8 km west of the Khurbet East Early Production Facility, separates gas from produced oil and pumps the stabilized crude into storage tanks in the EPF complex for delivery into the Khurbet East pipeline. Well KHE-19H has been tied into the substation and is estimated to be producing at a rate of more than 2,900 b/d of oil on a restricted choke.
The reconciled production rate achieved at the expanded facilities as of Aug. 6, 2011, was 24,054 b/d from Khurbet East and Yousefieh fields, comfortably achieving and exceeding the company's previously announced yearend 2011 target of 24,000 b/d.
Gulfsands is operator with 50% interest in Block 26. Emerald Energy PLC, a subsidiary of Sinochem Resources UK Ltd., holds the other 50%.
Meanwhile, well KHE-19H achieved a flow rate of 5,516 b/d of 26° gravity oil, the highest yet measured from any well in Khurbet East field. The oil is similar in quality to that produced in the central part of the field. The rate was obtained during a 2-hr main flow period on a 48⁄64-in. choke with 132 psi average wellhead pressure and no formation water.
Narrowed to a 32⁄64-in. choke, the well was flowed for a further 3 hr at an average 3,828 b/d at 210 psi average wellhead pressure until tanks were full. The 67-m horizontal productive section is in a sidetrack drilled in a south-southeasterly direction from the original KHE-19 vertical hole.
Ensco deepwater semi to drill off Brunei
Ensco PLC has taken delivery of the ultradeepwater Ensco 8504 semisubmersible drilling rig from Keppel FELS Ltd. in Singapore and will prepare it for work off Brunei.
The unit will undergo sea trials and final outfitting before starting work off Brunei for Total E&P Deep Offshore Borneo BV. The contract is for the drilling of three exploration wells over at least 180 days. Total has four options to extend the contract.
The semi is the fifth of seven comparable rigs Keppel FELS is building for Ensco.
With 2 million lb of hoisting capacity and variable deck load capacity of 8,000 tons, it can drill to 35,000 ft and be modified to drill and complete wells in as much as 10,000 ft of water.
India pushes RIL to boost KG-D6 drilling
Reliance Industries Ltd., Mumbai, is under pressure from the Indian government to "expeditiously drill more development wells in D1 and D3 fields" on deepwater Block KG-D6 in the Krishna-Godavari basin off eastern India.
In a written reply to the Rajya Sabha, upper house of the Indian Parliament, Minister of State for Petroleum and Natural Gas Shri R.P.N. Singh confirmed that the Directorate General of Hydrocarbons had advised RIL to increase drilling.
According to Singh, average gas production during April-June from the block was 48.6 million standard cu m/day (MMscmd). The rate specified by the field development plan for D1 and D3 gas fields and MA oil field during the period is 70.39 MMscmd.
According to DGH records, RIL has drilled 28 wells on its KG-DWN-98/3 (D6) license area, awarded under a production sharing contract in 2000 as part of the first round of India's New Exploration License Program with a minimum work program of 8 wells. Water depth is about 8,000 ft.
In a financial report last month, RIL said KG-D6 gas production for the quarter that ended June 30 totaled 156.2 bcf, down 18% from the same quarter a year earlier. Crude oil production from the block was down 41% at 1.41 million bbl for the quarter. Condensate production totaled 210,000 bbl, up 82% from the previous year.
RIL operates the block with a 90% interest. Niko Resources Ltd., Calgary, holds 10%. The block is part of a $7 billion deal approved recently by the government under which BP will acquire 30% interests in 21 Indian blocks from RIL, with the Indian company remaining operator (OGJ Online, July 22, 2011).
PDO to pilot solar EOR in Oman
Petroleum Development Oman plans to install its first solar enhanced oil recovery pilot in one of its thermal EOR projects in southern Oman.
The 7 Mw solar EOR installation will reduce the amount of natural gas burned to generate steam in the project, according to GlassPoint Solar Inc.
Spanning more than 4 acres, the GlassPoint system will produce 11 tons/hr of high temperature (312˚ C.), high pressure (1,450 psi) steam. The company said the completed project will be 27 times larger than its solar EOR system installed at Berry Petroleum Co.'s 21Z oil field in Kern County, Calif. (OGJ Online, Feb. 24, 2011).
PROCESSING — Quick Takes
Dutch firm to buy Wilhelmshaven refinery
A private Dutch company has agreed to buy the 260,000 b/d Wilhelmshaven refinery on Germany's North Sea coast from ConocoPhillips for an undisclosed amount.
The buyer is Hestya Energy BV, Amsterdam, which says it focuses on the European midstream oil business and "is building a portfolio of high quality, strategic assets through the acquisition of existing facilities and investment in Greenfield developments."
Hestya lists its shareholders as Riverstone Holdings LLC, a private equity firm, and AtlasInvest, a private investment company.
The deal includes tank farm and marine terminal.
ConocoPhillips last year canceled a major upgrade of the Wilhelmshaven refinery in line with plans to lower its refining holdings (OGJ, Aug. 2, 2010, Newsletter).
Ecopetrol advances Barrancabermeja upgrade
Ecopetrol SA has moved into the second phase of a major upgrade and expansion of its 250,000-b/sd Barrancabermeja refinery in Colombia.
The state-owned oil company has released Foster Wheeler's Global Engineering and Construction Group to perform work under the new phase. The release includes additional project management consultancy and front-end engineering design; detailed engineering for crude-unit revamps; assistance with selection for engineering, procurement, and construction contracts; and control and supervision of EPC and construction contractors.
The project will raise refining capacity to 300,000 b/sd. It includes a new crude unit, delayed coker, hydrocracker, coker naphtha hydrotreater, and hydrogen and other units (OGJ, Nov. 28, 2008, Newsletter).
Ecopetrol started up a hydrotreament complex at the refinery last year (OGJ, Oct. 25, 2010, Newsletter).
Work to start on Jurong condensate project
Jurong Aromatics Corp. (JAC) will break ground Aug. 26 on a large condensate processing complex on Jurong Island, Singapore.
The facility will process 4.5 million tonnes/year (tpy) of condensate to produce 1.44 million tpy of aromatics and 2.47 million tpy of petroleum products, including jet fuel, diesel, and low-sulfur fuel oil. It will have a condensate splitter to produce heavy naphtha feedstock.
Aromatic yields will be 800,000 tpy of paraxylene, 438,000 tpy of benzene, and 200,000 tpy of orthoxylene.
JAC is a group of eight shareholders led by SK Group of South Korea. SK E&C is the engineering, procurement, and construction contractor. SK affiliates will perform maintenance and repair after completion, provide feedstock, and buy products.
ChemOne Pte. Ltd. is developer of the project, construction of which is expected to take 36 months.
Construction was delayed by the financial crisis of 2007. The project resumed after reorganization of JAC ownership.
Albertan gas plant to expand
Pembina Pipeline Corp., Calgary, will expand capacity by 50 MMcfd at one of its gas plants at the Cutbank shallow gas processing complex to meet high plant utilization and strong demand. The complex is in west central Alberta.
On completion of the $26 million (Can.) expansion, the complex will have total raw gas processing capacity of 410 MMcfd, an increase to Pembina of 16%. The Cutbank expansion will occur at the Musreau gas plant, one of the three plants that make up the complex.
Pembina expects the expansion, subject to regulatory and environmental approval, to be in service by mid-2012. The company entered into contracts with minimum terms of 5 years with area producers for the entire expansion capacity on a fee-for-service basis.
Pembina transports crude oil and NGLs produced in Western Canada, owns and operates oil sands pipelines, and has a growing presence in midstream and gas services.
TRANSPORTATION — Quick Takes
Plains All American boosts Mesa pipeline capacity
Plains All American Pipeline has increased the available throughput capacity of the 80-mile Mesa Pipeline crude oil system by about 100,000 b/d to roughly 420,000 b/d.
The Mesa System, originating near Midland, Tex., delivers crude oil to Alon's Big Spring, Tex., refinery and feeds both the West Texas Gulf Pipeline, serving markets south and east of Cushing, and the Basin Pipeline system, which delivers crude oil to the Cushing hub.
Mesa is jointly owned by subsidiaries of Plains All American and Sunoco Logistics.
Parnon plans Oklahoma crude oil pipeline
Parnon Gathering Inc., Tulsa, will lay 109 miles of 8-in. crude oil pipeline between Cherokee and Cushing, Okla.
The Great Salt Plains Pipeline will have design capacity of 18,000 b/d, expandable to 35,000 b/d. It will deliver crude to Parnon's tanks at Cushing.
Commissioning is scheduled in March 2012. A second phase might extend the pipeline westward to serve Granite Wash and new tight-formation plays in western Oklahoma, the company said.
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