GENERAL INTEREST — Quick Takes
NGSA forecasts stable natural gas prices this winter
US natural gas prices could be relatively stable this winter because of a sluggish economy, production from ample supplies, and strong storage levels, the Natural Gas Supply Association said in its annual forecast. "This year, we see the weather as the most influential factor," NGSA Pres. R. Skip Horvath said. "Of course," he added, "it's also the most difficult to predict."
NGSA, which released its forecast during the US Energy Association's energy supply forum on Oct. 4, said demand from residential and commercial customers could modestly decrease relative to the 2010-11 heating season, which was the coldest in 10 years, because of the National Oceanic and Atmospheric Administration's forecast for comparatively warmer temperatures.
"If the winter turns out to be colder than NOAA's forecast, the demand picture could be considerably stronger," Horvath said.
Figures developed for NGSA by Energy Development Analysis Inc. of Arlington, Va., suggested that demand from customers less sensitive to weather will stay level or grow modestly, the trade association said. Industrial demand is expected to be comparable to last winter, while demand to generate electricity could modestly increase as more utilities switch from coal-fired systems, it indicated.
"Last winter, we witnessed a doubling of fuel switching to natural gas and we expect to see fuel switching continue at last winter's historic levels this winter," said Horvath. "Not only has coal-to-gas switching continued for an unprecedented three straight years, but published [New York Mercantile Exchange] prices suggest that it will continue through 2014."
Production will increase about 5% year-to-year to a record 63 bcfd, driven by onshore activity in shale plays, according to the analysis that ICF Energy of Fairfax, Va., developed for NGSA. It forecast that 2011 production in the Lower 48 will be 22.5 tcf, about 6.3% more than in 2010.
"This is a much higher annual production increase than was the case in recent years," ICF's analysis said. "Going forward into next year, we are forecasting a 3.8% increase, primarily reflecting a modest gas well completion slowdown for the remainder of 2011 and 2012."
NPRA changing name to 'better describe focus'
The National Petrochemical & Refiners Association (NPRA) announced plans to change its name to the American Fuel & Petrochemical Manufacturers (AFPM) effective in late January. A red, white, and blue logo will accompany the new name. A new web site also is planned.
NPRA had been considering a name change for a year, NPRA Pres. Charles T. Drevna said during a conference call from Washington to announce the new name. He noted AFPM will be the fourth name for the organization founded in 1902.
"AFPM will be just as vigorous as NPRA was and is," Drevna said. "We are proud to be high-tech American manufacturers. We're proud to keep America moving." He noted the organization has more than 450 members.
The name change was not intended to diversify the membership base, he said, adding that the new name better describes the organization's focus. The organization hosted focus groups in four US cities to help determine its new name, he added.
"We provide Americans with jobs, we provide Americans with fuel," Drevna said. He said the effective date for the name change would be sometime in late January although the group has no specific date yet.
Interior reaffirms Chukchi Sea oil, gas lease sale
The US Department of the Interior reaffirmed the 2008 sale of federal oil and gas leases in the Chukchi Sea offshore Alaska as it met a federal district court's deadline to file a new record of decision for the sale on Oct. 3.
The ROD affirms a supplemental environmental impact statement that the US Bureau of Ocean Energy Management, Regulation, and Enforcement completed on Aug. 26 in response to the court's order to address specific concerns related to the sale's National Environmental Policy Act analysis, according to one of BOEMRE's successor agencies, the Bureau of Ocean Energy Management. It does not grant approval for lessees to begin operations there, BOEM added.
It said the SEIS, in accordance with the court order, provided additional analysis to supplement the NEPA examination completed in 2007 for OCS Lease Sale 193.
Specifically, the bureau analyzed potential gas development impacts and further reviewed the relevance and importance of information identified as missing or unavailable during the original analysis, BOEM said. The SEIS also analyzes the environmental impacts of a hypothetical very large oil spill scenario that was developed following the 2010 Macondo deepwater well accident and spill into the Gulf of Mexico, it said.
Exploration & Development — Quick Takes
Anadarko sees at least 10 tcf off Mozambique
Anadarko Petroleum Corp. said its latest exploratory well off Mozambique found 140 net ft of gas pay in Miocene and Oligocene sand packages shallower than those in earlier wells and boosted its view of the resource potential of Offshore Area 1 to at least 10 tcf of gas.
The company said results to date in the deepwater Rovuma basin indicate that the Windjammer, Barqentine, Lagosta, and Camarao complex has at least 10 tcf of recoverable gas. The Camarao exploratory well also encountered 240 net ft of gas pay in an excellent quality reservoir and confirmed static pressure connectivity with Windjammer and Lagosta, Anadarko said.
Bob Daniels, Anadarko senior vice-president, worldwide exploration, said, "We are optimistic that our current resource estimates will increase, as we still have significant exploration and appraisal work ahead of us, including the evaluation of two newly acquired 3D seismic datasets and expanded prospect opportunities. We are mobilizing a second deepwater drillship to the Rovuma basin to accelerate the campaign, which includes an extensive reservoir testing program and up to seven exploration/appraisal wells over the next 12 months."
Chuck Meloy, Anadarko senior vice-president, worldwide operations, said, "Given the increased resource potential of this complex, our base case development plans have now been expanded to a minimum of two 5 million tonne/year LNG trains with the flexibility to develop additional trains based upon continued exploration and appraisal success. Once the first two trains are constructed, this infrastructure is expected to provide economies of scale that can reduce expansion costs for any additional trains. Further, we anticipate the results of our drillstem testing program will help determine the optimal number of subsea development wells and offshore facility requirements. We expect to provide further details regarding this world-class development by early next year."
The Camarao discovery well went to 12,630 ft in 4,730 ft of water 5 miles south of Windjammer and 10 miles north of Lagosta. Camarao will be preserved as part of the partnership's drillstem test program, and the drillship will be mobilized north to drill the Barquentine-3 appraisal well.
Anadarko operates the 2.6-million-acre Offshore Area 1 with a 36.5% working interest.
Cairn finds gas at Sri Lanka's first discovery
Cairn Lanka (Pvt.) Ltd. said it found what appears to be gas with liquids potential at the first hydrocarbon discovery in Sri Lanka. Logs and MDT data indicate a gross 25 m hydrocarbon column in a sandstone at 3,043.8-3,068.7 m in the CLPL-Dorado-91H/1z well in 1,354 m of water in the Gulf of Mannar. The sandstone is interpreted to be mainly gas bearing with some additional liquid hydrocarbon potential, Cairn Lanka said.
The discovery is 175 km north-northwest of Colombo and 200 km south of the southernmost discovery in the Cauvery basin off India.
The well is the first in Sri Lanka in 30 years and the first in a three-well program in the Mannar basin. Cairn didn't provide the total depth of the well. Cairn in September 2008 signed official documents to explore 3,000 sq km block SL 2007-01-001, in which it holds 100% participating interest, and committed to a $110 million exploration program.
Further drilling will be required to establish the commerciality of the discovery, Cairn Lanka said.
Iraq Kurdistan Pulkhana find gets two new zones
ShaMaran Petroleum Corp., Vancouver, BC, said it identified two oil-bearing zones in its Pulkhana-9 appraisal well in Iraqi Kurdistan in addition to the two already encountered.
ShaMaran drilled to a total depth of 2,333 m and ran six well tests, recovering oil in four reservoirs. The zones confirmed by previous drilling, the Miocene Euphrates and Cretaceous Shiranish formations, and two new horizons, the Eocene Jaddala formation and an undifferentiated fractured Cretaceous formation below the Shiranish recovered oil on test.
The total prospective pay based on petrophysical analysis of electric logs was more than 800 m in four separate reservoirs. Oil is 28-34° gravity. Due to failure of an external casing packer in the lower zones and possible formation damage due to heavy mud weights, representative flow rates could not be established.
The company will sidetrack the well to establish oil flow rates in the lower two zones using open hole testing that gives the greatest chance of success in fractured carbonate reservoirs. It also will drill another Pulkhana appraisal well and is planning an early production system for the field. ShaMaran also is reentering the Pulkhana-8 well, drilled in 2006, to confirm the Shiranish reservoir in this portion of the field.
ShaMaran, Pulkhana block operator, holds 60% interest. Petoil and the Kurdistan Regional Government hold 20% each.
Upper Cretaceous tested at Iraq's Miran West
Heritage Oil PLC said a production test indicates that future development wells on the Miran West structure in Iraqi Kurdistan could produce at rates of 8,000-10,000 b/d/well of 15° gravity oil from the Upper Cretaceous reservoir at 876 m.
The Miran West-3 well tested at the maximum rate of 1,950 b/d of oil, limited by surface equipment, with little associated gas. Heritage said the test confirms its estimate of gross in place contingent volumes of 53-75 million bbl of oil in Upper Cretaceous at Miran West.
Drilling resumed on prognosis to test the deeper reservoirs discovered by earlier drilling. Heritage said, "Drilling of this well is demonstrating the ability to intersect the productive fracture network associated with multiple faults identified on recently acquired 3D seismic data. We are drilling ahead with a view to conducting the next test in the Lower Cretaceous reservoir."
Interests in the 1,015 sq km Miran block are Heritage 75% and Genel Energy International Ltd. 25%, although there are third party back-in rights.
France withdraws shale gas permits from operators
The French government has withdrawn two permits for shale gas exploration from Schuepbach Energy LLC, Dallas, and one permit from France's Total SA, all involving sites in southwestern France.
"We have decided to abrogate the three research permits," Ecology Minister Nathalie Koscisko-Morizet told Agence France-Presse in a news story published Oct. 3. She said Schuepbach failed to submit plans for drilling using alternate methods than hydraulic fracturing within a 2-month deadline. Schuepbach's plans mentioned fracing.
Total's plan did not mention fracing, but French officials found the plan "not credible," she told AFP.
No comment was immediately available to OGJ from Schuepbach or Total.
French lawmakers in June voted against fracing, which has raised public concerns about possible contamination of drinking water (OGJ Online, Apr. 22, 2011).
Drilling & Production — Quick Takes
Chevron launches solar EOR project
Chevron Technology Ventures launched a demonstration project at Coalinga field in Kern County, Calif., to test the viability of using solar energy to enhance heavy oil production (see video, Table of Contents). The project uses 7,644 mirrors to focus the sun's energy onto a solar boiler on top of a 327-ft tower. The produced steam then is injected into wells at Coalinga.
The field has been producing oil since the 1890s.
The project includes 3,822 mirror systems, or heliostats, each consisting of two 10 by 7-ft mirrors mounted to a 6-ft steel pole. The mirrors track the sun and reflect its rays to a receiver on the solar tower. Using heat from the concentrated sunlight, the solar tower system produces the steam for injection.
The project covers 100 acres, with mirrors covering 65 acres and 35 acres devoted to support facilities.
"This technology has the potential to augment gas-powered steam generation and may provide an additional resource in areas of the world where natural gas is expensive or not readily available," said Desmond King, Chevron Technology Ventures president.
The solar demonstration generates about the same amount of steam as one gas-fired steam generator.
Chevron contracted BrightSource Energy Inc. to provide the technology, engineering, procurement, and construction for the project.
Statoil starts drilling on Gudrun platform
The West Epsilon jack up rig on Sept. 6 started drilling wells on the 16 well-slot Gudrun steel jacket on Block 15/3 in the central Norwegian North Sea, production license P 025.
Gudrun, discovered with well 15/3-1 S, drilled in 1974-75, lies in 110 m of water about 55 km north of Sleipner. The reservoirs, at a 4,200-4,700 m depth, contain oil in the Upper Jurassic Draupne formation and gas in the Middle Jurassic Hugin formation.
Gudrun will cost about 21 billion kroner to develop.
Statoil plans to drill seven production wells through the jacket into the Gudrun high pressure, up to 820 bar, and high temperature reservoirs before installing the platform topsides in 2013, and starting production in first-quarter 2014.
Statoil said the predrilling the wells would avoid depressurization of the reservoir that would complicate further drilling.
Installation of the 7,000-tonne jacket was completed in August.
A pipeline will transport the production to the Sleipner A gravity-based platform for final processing, with gas piped to the adjacent Sleipner T platform for carbon dioxide removal.
Sleipner A also will supply power to the Gudrun platform.
Statoil estimates that Gudrun contains 127 million boe of recoverable reserves.
Total lets engineering contract for Hild
Total E&P Norge AS let a 215 million kroner contract to Aker Solutions for basic engineering to develop Hild field on Norwegian Sea production licenses 40 and 43.
The contract is for engineering of the topsides, jacket, floating storage and offloading vessel, turret and mooring, subsea umbilicals, risers, pipelines, flowlines, transportation, and installation. Aker Solutions expects to finish the work in summer of 2012 and said the engineering work covers more detail then a normal frontend engineering and design study for field development.
Aker Solutions will do the topsides engineering in Oslo and the turret and mooring work in Kristiansand, Norway.
Hild, discovered in 1978, is an oil and gas field about 160 km offshore Norway and 42 km west of the Oseberg field. Water depth is 100-120 m. The unitized field lies on Blocks 29-9, 30-7, 29-6, and 30-4.
The reservoirs are structurally complex, and contain gas at high temperatures and pressure. Three reservoirs are in Middle Jurassic sandstones of the Brent Group at a 3,700–4,400 m depth. Oil also was found in an Eocene reservoir at about 1,750 m.
The Norwegian Petroleum Directorate estimates that the field's recoverable resources are 5.1 million cu m of oil, 16.3 billion cu m of gas, 0.2 million tonnes of NGL, and 3 million cu m of condensate.
The license owners are operator Total E&P Norge 49%, Statoil 21%, and Petoro AS 30%.
PROCESSING — Quick Takes
Murphy completes sales of US refineries
Murphy Oil Corp. has completed the sales of its refineries in Meraux, La., and Superior, Wisc., as it withdraws from the refining business to concentrate on exploration and production (OGJ Online, July 23, 2010).
Valero Energy Corp. bought the 135,000-b/d Meraux refinery and related logistics properties for $325 million plus inventories valued at $300 million. The refinery has a 34,000 b/d hydrocracker and extensive hydroprocessing capacity.
Valero said it plans to integrate feedstocks and product blending with its 250,000 b/d refinery at St. Charles, La., about 40 miles away by river. It is building a 60,000 b/d hydrocracker at St. Charles.
The purchase includes a product terminal, 20% interest in the Collins Product Pipeline and terminal, and 3.2% interest in the Louisiana Offshore Oil Port.
A subsidiary of Calumet Specialty Products Partners LP bought the 33,250 b/d Superior refinery for $214 million plus inventories valued at $220 million (OGJ Online, July 26, 2011).
Murphy also plans to sell its 106,000 b/d Milford Haven refinery in the UK along with its UK retail system.
Iraq refinery to install conversion technologies
State Co. for Oil Projects (SCOP), part of the Iraqi Ministry of Oil, has awarded Axens IFP Group Technologies basic design and license contracts for construction of a refinery in Nassiriya, the supply company announced.
Axens will supply the following process technologies:
• H-OilRC technology for the hydroconversion of 52,000 b/sd of vacuum residue. The plant will convert vacuum resid to low-sulfur distillates and produce a low-sulfur residue. H-Oil technology is employed for heavy oil residue conversion (H-OilRC) and for difficult distillate conversion (H-OilDC) applications.
• Prime-D, gas oil desulfurization hydrotreater. The 105,000-b/sd unit will produce ultralow-sulfur diesel with less than 10 ppm of sulfur.
• Prime-K, kerosene desulfurization hydrotreater with a processing capacity of 24,000 b/sd.
• Butane isomerization unit with a process capacity of about 11,900 b/sd.
The refinery will have a capacity of 300,000 b/sd of oil and deliver high-quality products mainly for the US market.
TRANSPORTATION — Quick Takes
Russia's Novatek increases stake in Yamal LNG
Russia's OAO Novatek said it increased its equity interest in the Yamal LNG project to 100% from 51% by exercising call options through wholly owned subsidiary Novatek North West.
Novatek said it increased its stake through two call options: one for 23.9% purchased in 2009 and the other for 25.1% purchased in March. It said the options' strike price would be paid in installments ending on June 30, 2012.
On Sept. 30, Russia's Deputy Prime Minister Igor Sechin said Middle Eastern companies are interested in joining the Yamal LNG project. "Our Arab partners are holding negotiations with Novatek and a Qatar oil and gas producer is asking to be included in the list of shareholders, but there are other partners as well," Sechin said.
In August, Novatek Chief Financial Officer Mark Gyetvay announced plans to produce as much as 50-51 billion cu m of gas in 2011, up slightly from its previous forecast of 48.9 billion cu m, as a result of strong domestic demand.
Analyst IHS Global Insight underlined Gyetvay's remarks, saying that the company is aiming to extract more gas from its key fields in the Yamal-Nenets region with an eye towards meeting higher domestic consumption requirements.
BG Group signs LNG supply agreement in India
BG Group signed a heads of agreement agreeing to provide LNG in India on a long-term basis to Gujarat State Petroleum Corp. (GSPC). HOA terms call for as much as 2.5 million tonnes/year for a 20-year period starting as early as 2014. The LNG volumes will be sourced from BG Group's global assets.
Financial details were not outlined yet. BG Group and GSPC expect to finalize an LNG sales and purchase agreement in early 2012.
Frank Chapman, BG Group chief executive officer, said the HOA establishes "long-term LNG sales into one of the world's largest and fastest-growing energy markets." He said, "We have been in the Indian gas market for more than 15 years and this agreement brings essential new supplies of natural gas to the country."
Petronet LNG Ltd.—a joint venture of GAIL India, Oil & Natural Gas Corp., Indian Oil Corp., and Bharat Petroleum Corp.—is India's biggest LNG importer (OGJ, Mar. 7, 2011, p. 100). Currently, Petronet LNG is constructing a 2.5 million tpy terminal at Kochi with targeted commissioning of mid-2012. For that terminal, Petronet LNG has a long-term gas supply contract with ExxonMobil Corp. from Gorgon field.
ExxonMobil completes deal for two Alaska tankers
ExxonMobil Corp.'s US marine affiliate, SeaRiver Maritime Inc., signed an agreement with Aker Philadelphia Shipyard for construction of two US-flagged Liberty-class crude oil tankers.
The double-hull 115,000 dwt vessels will be used to transport Alaska North Slope crude to West Coast destinations in the US.
SeaRiver expects construction to begin by mid-2012, with the 730,000-bbl tankers scheduled for delivery in 2014. The ships will replace two existing double-hull tankers.
The vessels will cost $400 million together. Aker will build the ships in partnership with Samsung Heavy Industries. The agreement follows a letter of intent signed earlier this year (OGJ Online, July 26, 2011).
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