API, food industry challenge EPA's E15 waiver
The American Petroleum Institute and nine national food and retail industry trade associations asked the US Appeals Court for the District of Columbia on Nov. 9 to review the US Environmental Protection Agency's Oct. 13 partial waiver allowing ethanol limits to rise to 15% in gasoline sold to 2007 and newer model year cars and light trucks.
The groups contend that EPA's decision was premature, lacks statutory authority, and was made before thorough testing to determine the new fuel blend's safety, performance, and environmental impacts has not been completed. Ethanol's present allowable limit in gasoline is 10%.
"Ongoing testing by our industry and the US Department of Energy to determine whether E15 is safe has not been completed," said Bob Greco, API's downstream operations director. "Results so far have revealed potential safety and performance problems that could affect consumers and the investments they've made in their automobiles."
He said the US oil and gas industry is the nation's largest ethanol consumer, and supports a workable renewable fuel standard and a responsible introduction of increased biofuels in a manner that protects motorists. "Rushing to allow more ethanol before we know it is safe could be disastrous for consumers and could jeopardize the future use of renewable fuels," Greco warned.
Growth Energy, an ethanol advocacy group which sought the waiver from EPA, responded that the food trade associations, which include the Grocery Manufacturers Association and the American Frozen Food Institute, are challenging EPA's decision to slow down progress on renewable fuels.
"In 2008, these big food companies gouged consumers while trying to shift the blame to America's ethanol producers and farmers, so we're not surprised by their actions today," said Growth Energy chief executive Tom Buis.
"We will fully evaluate their lawsuit, but the expansion of renewable fuels in America should be based on science. As extensive testing has shown, E15 is a good fuel for American motorists," he said.
Chevron to buy Atlas, gain Marcellus foothold
Chevron Corp. has agreed to acquire Atlas Energy, a Pittsburgh independent producer with a major land position in the Marcellus shale gas play, for $3.2 billion cash plus assumption of debt of $1.1 billion.
Chevron will acquire a gas resource estimated at 9 tcf, including 850 bcf of proved reserves, and about 80 MMcfd of production.
Atlas Energy's Appalachian basin assets include 486,000 net acres in the Marcellus shale, 623,000 net acres in the Utica shale, and a 49% interest in Laurel Mountain Midstream LLC, which owns more than 1,000 miles of intrastate gas pipeline and gathering lines in the Marcellus play.
Atlas Energy also has production from the Antrim shale in Michigan and 100,000 net acres in the Collingwood-Utica shale.
Chevron will become operator of the Marcellus joint venture Atlas Energy formed in April with an affiliate of Reliance Industries Ltd., Mumbai, and will assume the acquired company's 60% share of the venture. Reliance will still fund 75% of the operator's drilling costs up to $1.4 billion (OGJ Online, Apr. 21, 2010).
Before completion of the deal, Atlas Energy will distribute units of Atlas Pipeline Holdings LP to shareholders and acquire a 49% interest in Laurel Mountain Midstream from the pipeline partnership for $403 million.
It will sell all investment partnerships, 175 bcf of gas reserves, and certain other assets to Atlas Pipeline Holdings for $30 million in cash and $220 million in new units in the pipeline partnership.
Sharjah establishes national oil company
Sharjah, a member of the United Arab Emirates, has established a national oil company.
Sharjah National Oil Corp. will "have a corporate character" and "enjoy financial and administrative independence and practices its operations on commercial bases," said a decree from Sultan bin Mohammed Al Qasimi, ruler of Sharjah.
Sharjah produces gas and condensate onshore and gas offshore, all at modest and mostly declining rates. Crescent Petroleum, based in Sharjah, and Russia's Rosneft Oil Co. are exploring a large onshore concession.
Dallas firm fracs Thrace basin tight gas sands
TransAtlantic Petroleum Ltd., Dallas, pumped the first modern frac stimulation in Turkey in October at the Kepirtepe-1 well on Thrace basin License 3791.
The operation, in partnership with state owned Turkiye Petrolleri AO, was designed to test noncommercial gas shows in tight Oligocene Mezardere sands at 12,000 ft. The single-stage frac was pumped using TransAtlantic's high-pressure, high-volume pumping units, sand blenders, and support equipment.
Initial flow rates exceeded 4 MMcfd of gas with some condensate and water. TransAtlantic expects to complete cleaning the perforations and testing the well with coiled tubing and nitrogen units in late-November.
The initial flow rate, while preliminary, points to potential production from unconventional tight sands, and the company expects to continue applying modern frac technology to existing and new wells (see map, OGJ, Oct. 4, 2010, p. 56).
By yearend, the company expects to have completed single-stage fracs in four of the five known reservoirs on its Thrace basin acreage. After refining the frac techniques on the less expensive reentries, the company will drill locations optimized for unconventional potential.
Five rigs should be running by mid-2011, including two on shallower conventional targets and three on deeper targets.
Chief's Marcellus output tops 100 MMcfd
Chief Oil & Gas LLC, private Dallas operator, said its Marcellus shale production in Pennsylvania has reached 100 MMcfd of gas equivalent from 42 wells and that it expects to end 2010 at 115 MMcfed.
The most recent well the company placed on production exceeded 15 MMcfd on choke from a 4,994-ft lateral in central Pennsylvania. The company holds 600,000 gross acres in Pennsylvania, West Virginia, and Maryland.
Of 93 wells drilled, 15 await a pipeline and 36 await completion. The company expects to be running seven rigs at yearend, up from three at the start of 2010. Twenty wells are being drilled or remain to be drilled this year.
The company has drilled and completed wells in Lycoming, Bradford, Susquehanna, Wyoming, Clearfield, Blair, Somerset, Greene, and Fayette counties, Pa., and in Marshall County, WV. Estimated ultimate recoveries are 3.75 to 7 bcf.
Recent wells placed on line average 4.7 to 8 MMcfd from an average 2,568-ft lateral in northeastern Pennsylvania, where cumulative output has exceeded 1 bcf from each of three multiwell pads in two counties.
In central Pennsylvania, two recently completed wells averaged 4.9 MMcfd and 5.3 MMcfd with from 4,864-ft and 4,143-ft laterals, respectively.
Oklahoma Mississippian horizontal play grows
SandRidge Energy Inc., Oklahoma City, is expanding activity in a horizontal play for oil in the Mississippian formation on the Anadarko basin shelf in northwestern Oklahoma as part of the company's transition to liquids production from gas.
The company has completed 20 wells and said completion results have exceeded expectations and that it may monetize part of its acreage in 2011.
The play's core involves drilling horizontal wells in existing vertically drilled and producing reservoirs in Woods, Alfalfa, and Grant counties, Okla., along the Kansas line. SandRidge, which has leases in both states, hopes to enlarge its holding to 500,000 acres by yearend 2010 from the current 400,000 acres that contain 1,200-2,500 potential drilling locations.
The company sees operated activity at 10 rigs in the 2011 first quarter compared with eight at yearend and five at present. It will drill more than 100 Mississippian wells in the coming year and drilled its first well in January 2010. Rigs, services, and infrastructure are readily available.
Most leases have 3-year primary terms with 2-year options. With 10 rigs, the company believes it can hold 250,000 acres, the spread it originally viewed as optimum for SandRidge.
Assuming Oct. 28 strip pricing, the expected rate of return is 100% based on a type curve of 386,000 boe on expected ultimate recovery of 300,000-500,000 boe/well, 53% crude oil. Estimated cost to drill and complete a well, including salt water disposal facilities, is $2.7 million.
The expansive carbonate stratigraphic trap is 250-500 ft thick at 6,000 ft TVD with porosity developments of up to 100 ft. Thousands of vertical wells penetrate the reservoir.
The company's shift to oil will continue in 2011, as the company runs only a single rig at Pinon gas field in the Texas Val Verde basin. With Permian basin acquisitions and success in the Midcontinent Mississippian oil play, SandRidge hiked its 2010 capital budget to $1.1 billion from $875 million and set its 2011 spending at $1.1 billion. It expects to drill more than 900 oil wells next year.
Drilling & Production — Quick TakesWintershall to drill wells in Emlichheim steamflood
Wintershall is now drilling the first of 16 new wells at its Emlichheim steamflood on the German-Dutch border. The wells will be drilled during the next 5 years and will include 12 horizontal and 4 vertical wells.
The company also will supplement the new wells with 13 extended reach wells from existing production sites. It plans to spend more than €60 million.
Currently the company produces 140,000 tons/year of crude from the field and with the new wells it expects to maintain this production level to at least 2016. It estimates that the steamflood will recover ultimately more than 40% of the oil in place. Wintershall started steamflooding at Emlichheim in 1981.
OGJ's enhanced oil survey indicates that production from the steamflood is from Valangian unconsolidated sands at a 2,500-2,700 ft depth (OGJ, Apr. 19, 2010, p. 50). The crude has a 22° gravity and a 350 cp viscosity at 100° F.
Artificial islands to lift Upper Zakum flow
ExxonMobil Corp. says two pilot wells have demonstrated feasibility of plans to expand development of supergiant Upper Zakum oil field off Abu Dhabi with extended-reach drilling from artificial islands.
The technology is analogous to methods the company and partners are using at the Sakhalin-1 project in northeastern Russia (OGJ Online, Sept. 29, 2010).
ExxonMobil holds a 28% interest in Zakum Development Co. (Zadco), operator of Upper Zakum field, which holds an estimated 50 billion bbl of oil. The field lies 50 miles northeast of Abu Dhabi city.
Zadco is building four artificial islands in 15-80 ft of water in a project designed to raise Upper Zakum production by nearly 40% to 750,000 b/d. ExxonMobil reported confirmation of the plans via the pilot wells at the Abu Dhabi International Petroleum Exhibition early this month.
Upper Zakum field, discovered in 1964 by an operating company of Abu Dhabi National Oil Co. (ADNOC), covers more than 450 sq miles and produces from mostly low-permeability reservoirs through 450 wells drilled from 90 platforms. Typical well depths are 7,000-8,000 ft.
The field, which began production in 1983, has four offshore oil-processing centers linked by pipeline to export facilities on Zirku Island about 35 miles away. According to ExxonMobil, less than 10% of the field's oil has been produced.
ADNOC, which owns 60% of Zadco, has let a contract to National Marine Dredging Co. of Abu Dhabi to build four oval islands, 2,000-2,600 ft in diameter, from sand and rock barged from quarries in the United Arab Emirates. Construction is to be completed in 2012.
Exxon interest in Zadco is 28%. Japan Oil Development Co. holds 12%.
Production starts from Gjoa field off Norway
Production started from Gjoa oil and gas field in Blocks 35/9 and 36/7 off Norway on Nov. 7.
Statoil operated the project during the development phase and GDF Suez E&P Norge AS will assume operatorship during the production phase.
The semisubmersible production unit on the field will also serve as a development hub for other discoveries in the area such as the Vega gas satellite, in Blocks 35/11 and 35/8, to come on stream soon (OGJ, Oct 4, 2010, p. 58).
Gjoa's semi is the world's first production floater, and second platform off Norway, to receive its power from shore, according to Statoil. It receives electricity from a 100-km cable from Mongstad north of Bergen. Troll A was the first platform off Norway to be powered from shore.
Statoil said the Gjoa-Vega development cost 40 billion kroner and estimates a recovery from Gjoa of 82 million bbl of oil and condensate and 40 billion cu m of gas. The company expects Vega to recover 26 million bbl of condensate and 18 billion cu m of gas.
Gjoa will produce through five subsea templates while Vega will have three subsea templates.
The Gjoa semi is 45 km from shore and in about 360-m of water. A 55-km pipeline will transport oil from Gjoa to the Troll II line that goes to the Mongstad refinery. Rich gas will go through a 130-km pipeline to the Far North Liquids and Associated Gas System (FLAGS) that is connected to the St Fergus terminal in the UK.
Gjoa was discovered in 1989 and Vega in 1981. GDF holds a 30% interest in Gjoa. Partners are Petoro AS 30%, Statoil 20%, AS Norske Shell 12%, and RWE Dea Norge AS 8%. Statoil is the operator of Vega and holds a 60% interest in the field. The remaining 40% interest is held by Petoro.
PROCESSING — Quick TakesEssar to further boost refinery capacity
Essar Oil Ltd., Mumbai, has decided to further expand distillation capacity of its 300,000-b/d refinery at Vadinar, Gujarat, India.
The company said a project to boost capacity to 375,000 b/d and raise processing complexity was 72% complete on Oct. 31, on target for mechanical completion of all but two units next March. A coker and vacuum gas oil hydrotreater remain about 3 months behind schedule (OGJ, Aug. 30, 2010, Newsletter).
By revamping six units, Essar plans to push capacity to about 415,000 b/d. The units are fluid catalytic cracking, diesel hydrodesulfurization, sour water stripping, diesel hydrotreating, vacuum gas oil hydrotreating, and delayed coking.
The company expects to complete optimization of those units by September 2012.
Petrobras refineries to use UOP technologies
Petroleo Brasileiro SA (Petrobras) has chosen UOP LLP hydrocracking and hydrotreating technologies for two refineries it plans to build in Brazil.
UOP LLC said basic engineering for the refineries, Premium I at Maranhao and Premium II at Ceara, is under way.
Petrobras plans to start the first Premium I train, with capacity of 300,000 b/d, in 2014, and the Premium II refinery, also with 300,000 b/d of capacity, in 2017. It plans later to start a second Premium I train with 300,000 b/d of capacity.
The refineries are designed for maximum diesel yield. They will use UOP Unicracking and Unionfining technology to produce ultralow-sulfur diesel.
They also will use Foster Wheeler Selective Yield Delayed Coking technology for optimum yields of diesel feedstock from residual oil. UOP also is providing front-end engineering design services. Process Consulting Services Inc. is designing the crude and vacuum systems through an alliance with UOP.
Total, Chinese firm eye coal-based olefins
Total SA and China Power Investment Corp. have agreed to study construction of a petrochemical plant based on methanol derived from coal in China.
They signed a letter of understanding in a step toward construction of a facility in Inner Mongolia that would produce 1 million tonnes/year of polyolefins, starting after 2015.
Total said it would contribute expertise in producing olefins from methanol as well as an olefins-cracking process it has tested at a purpose-built semicommercial plant in Feluy, Belgium. It also will study capture and storage of carbon dioxide with knowledge it has gained from a pilot project in Lacq, France.
West Texas carbon dioxide plant starts up
SandRidge Energy Inc., Oklahoma City, began operation of its Century gas treatment plant in Pecos County, Tex., on Sept. 26.
The Val Verde basin plant was processing 85-90 MMcfd of raw gas in early November, and SandRidge and is troubleshooting compressor vibration issues. The company calls the plant the largest single industrial source carbon dioxide capture facility in North America.
SandRidge plans to shift a further 170 MMcfd of raw gas from nearby legacy plants to Century by the end of November, by which time all of the high-CO2 gas the company produces will be processed at Century. SandRidge will retain and sell the methane separated from the inlet gas, while Occidental Petroleum Corp., a partner in the Century plant, will ship the extracted CO2 for use in Oxy's enhanced oil recovery projects in the Permian basin (OGJ, Dec. 7, 2009, p. 41).
Oxy said the new CO2 stream is expected to hike its Permian output by as much as 50,000 boe/d within 5 years. The company operates 28 active CO2 projects in the basin.
SandRidge, meanwhile, has begun to emphasize oil and liquids drilling and production over gas the past 2 years. Continuance of this shift means it will run only a single rig in the Val Verde basin through the end of 2011, down from 34 rigs in the 2008 third quarter (OGJ, Nov. 24, 2008, p. 34). It therefore expects its gas production to decline.
The company holds 550,000 acres in the West Texas overthrust, about 500,000 acres of which expires in 2011-12. Pinon field proper is held by production.
Oxy said last month it expects the Century plant to yield about 180 MMcfd of CO2 next year to support its Permian EOR operations. Oxy said it is contracting additional CO2 from other sources and "will use penalty payments due from the operator for underproduction to support these activities."
TRANSPORTATION — Quick TakesAnalyst forecasts strong onshore pipeline spending
Energy business analysts Douglas-Westwood forecast in its World Onshore Pipelines Report 2011-15 spending of $193 billion on onshore pipeline projects worldwide through 2015.
The report notes that in developed economies the global economic downturn had the dual effect of destroying energy demand and reducing available credit, leading to the delay or cancellation of many proposed pipeline projects. Such delays will reduce annual expenditure in 2012 before what Douglas-Westwood describes as long-term and industry-specific drivers take over to move expenditures higher.
Beyond 2012, according to the report, continued growth in global oil and gas demand and associated production increases will require increased investment in pipeline systems. In North America, increasing levels of investment in unconventional energy sources will require major investment in new pipeline projects to link the energy sources with existing networks and markets.
Douglas-Westwood forecasts an 11% increase in kilometres of pipelines installed over the period 2011-15, compared with 2006-10.
Nearly 74% of the associated expenditure is expected to occur in Asia, Eastern Europe and the former Soviet Union, and North America, with more than 68% of it to be spent on gas pipelines. Asia stands out as the largest forecast market—by both length of pipeline construction and associated expenditure—accounting for $55 billion of forecast capital expenditure.
Southcross announces SESH interconnect
Southcross Energy announced construction of an 8-mile, 12-in. OD natural gas pipeline in Jones County, Miss.
The new line will connect Southcross' existing system with the 1-bcfd Southeast Supply Header (SESH) pipeline system. Southcross says the interconnect will augment its gas supply and allow it to provide expanded service to its regional customers, including the South Mississippi Electric Power Association, an electric generation and transmission cooperative.
Southcross expects the new line to enter service in April 2011.
Southcross operates the largest intrastate natural gas pipeline system in Mississippi, which includes 640 miles of transmission and gathering pipelines. Southcross is also active in the Eagle Ford shale, reaching agreement with Boardwalk Pipeline Partners LP in June to modify existing pipeline systems to more efficiently transport Eagle Ford gas volumes (OGJ Online, June 16, 2010).
The 274-mile SESH links the onshore gas supply basins of East Texas and northern Louisiana the US Southeast.
More Oil & Gas Journal Current Issue Articles
More Oil & Gas Journal Archives Issue Articles
View Oil and Gas Articles on PennEnergy.com