US, Canadian unconventional gas to aid demand
The trends of declining natural gas well productivity and reserves-to-well ratios are expected to continue through 2015 across all 50 gas basins in the US and Canada, Cambridge Energy Research Associates and IHS reported.
Continued strong market prices will be necessary to motivate enough drilling simply to maintain production on a flat trajectory, said the study, now in its second phase.
In recent years gas production has been buoyed by a shift toward more emphasis on drilling unconventional gas resources such as coalbed methane, gas shale, and tight sandstone.
Study coauthor Robert Ineson, CERA director of North American gas research, said the unconventional gas production stems from “the clear inability of conventional gas resources to keep pace with gas consumption.”
Unconventional gas provides solid supply options for several more years, he said. Producers must develop unconventional plays in a cost-effective manner so that gas can compete economically with imported LNG, coal, and other technologies.
“With unconventional resources dominating production trends in the next decade, the performance of existing and emerging unconventional plays will define the long-run supply curve for indigenous North American natural gas supply,” Ineson said.
Analysts used a gas price of $4-10/Mcf looking out to 2015 to examine the interplay of future gas production costs, the geological potential in the US and Canada, and how gas supply could build at higher market prices.
The most significant driver of rising gas production costs has been and will continue to be declining production on a per-well basis, not costs for equipment, although equipment costs could push a region to an unprofitable position, the study said.
Of the 15 basins having the largest forecast capacity increases from 2005 to 2010, 12 are primarily unconventional resources, the study said.
Shell to boost biofuels R&D investments
Royal Dutch Shell PLC plans to increase its investment in biofuels research and development to improve energy security and help to lower carbon emissions, a senior executive from the company said June 25 at a press briefing in London.
Rob Routs, Shell executive director, downstream, said the company’s focus would be on biofuels-in particular converting waste oils and fats into fuels. This hydrogenated process, Routs said, “is expensive at the moment, but there is some commercial application of it.”
Routs declined to say how much the company plans to spend on biofuels R&D, citing company confidentiality. But he did say the company has invested $1 billion in renewable energy over the past 5 years. Higher oil prices are needed to underpin the long-term commerciality of biofuels and experience in developing biofuels plants will also be a critical factor, he said.
Routs called for subsidies or special tax treatments to encourage the construction of biofuels plants, stressing that these were necessary until plants could be developed on a large scale. “We need a few cents/liter [subsidy] to make it work,” Routs told OGJ.
Routs has deliberately steered the company away from producing ethanol from sugar cane because he foresaw the difficulty of using food crops for fuels. “I don’t think the sugar cane situation in Brazil and the US is sustainable,” he said. “If it’s picked up for fuel production, there will be a clash and I don’t want to get involved in fuel and food competition. Sourcing is a big issue and I don’t see us going into owning land collecting waste products to get into this.”
Shell has joined German company Choren to launch a new biofuels plant that will convert biomass, such as woodchips, into synthetic fuel, which will then be marketed by Choren as SunFuel. The fuel is being used in diesel engines and can reduce emissions. The 15,000 tonne/year plant is due to become operational in late 2007 or early 2008.
Using waste plant material instead of valuable food crops would help the biofuels industry to circumvent the growing political pressure over using crops for fuel.
Routs told OGJ that Shell is working on various cellulose ethanol initiatives. The US government has promised Canadian company Iogen Corp., which Shell has teamed with, an $80 million grant to build an 18 million gal/year plant in Idaho that will produce cellulosic ethanol from plant waste and straw.
Last year, Shell signed a letter of intent with Volkswagen and Iogen to assess the economic feasibility of producing cellulose ethanol in Germany.
Last year Shell sold more than 3.5 billion l. of biofuels, Routs said.
South Korea confirms gas hydrates deposits
South Korea has confirmed deposits of gas hydrates off the eastern coast of the country, about 135 km northeast of the city of Pohang.
The Ministry of Commerce, Industry, and Energy’s oil and gas development division issued a statement June 23 saying the area is within South Korea’s exclusive economic zone.
A drilling program, scheduled to begin in September, calls for at least five wells. South Korea hopes to develop the technology for using gas hydrates by 2015, the government said.
South Korea now imports its oil and natural gas.
Industry Scoreboard
Noble makes discovery off Equatorial Guinea
Noble Energy Inc. has made a gas and condensate discovery on Block I in the Douala basin off Equatorial Guinea.
The discovery well, I-1, was to test the Benita prospect. The well is 25 miles east of Bioko Island and 13 miles south of the 2005 Belinda discovery on Block O.
I-1, drilled in 2,880 ft of water to 10,460 ft TD, encountered an “extremely” high-quality Miocene reservoir with 135 ft of net hydrocarbon pay, Noble said. The reservoir section at the Benita discovery is much thicker than at Belinda, also of Miocene age.
On test the well flowed 1,038 b/d of condensate and 34.3 MMcfd of gas. Production rates were limited by test facilities.
Condensate yields can be increased with the installation of cooling and processing facilities, Noble said.
Additional appraisal work will be necessary to verify the areal extent of the Benita discovery. Any appraisal work will follow the drilling of an additional exploration well in Block I, Noble said.
The company is currently carrying out a multiwell exploration and appraisal program designed to test a number of prospects in the region.
The Songa Saturn drillship will now move back to Block O to drill later this month a Belinda appraisal well 4.5 miles from the O-1 discovery well. Current plans are to return to Block I in the third quarter to drill the second exploration well.
Noble Energy is the technical operator of Block I with a 40% participating interest.
Oil, gas found in Pakistan’s Sindh province
Orient Petroleum Inc. made an oil and natural gas discovery with its Rahim-1 well drilled on Khipro block in Sindh province, Pakistan.
The well, which was spudded Mar. 12, was drilled to 3,200 m. On test the well flowed 800 b/d of oil and 350 Mcfd of gas at 730 psi wellhead flowing pressure through a 32/64-in. choke.
Separately, Oil & Gas Development Co. Ltd. made a gas-condensate discovery on the Thora and Thora East mining lease with the Thora Deep-1 well in Sindh province. The well, which was spudded Nov. 21, 2006, was drilled to 3,906 m. On test, the well flowed 100 b/d of condensate and 9.9 MMcfd of gas at wellhead flowing pressure of 1,880 psi through a 32/64-in. choke.
In addition, OMV Pakistan also made a gas discovery on Gambat Block with the Tajjal-1 well in Sindh province. The well, which was spudded Mar. 16, was drilled to the 3,780 m. The well flowed 20 MMcfd of gas on test.
Statoil proves gas in Algeria’s HTJW-1 well
Statoil AS has tested natural gas in Devonian sandstones with its Hassi Tidjerane West (HTJW-1) well in Algeria, the company reported. Statoil is operator of the project.
The well, drilled on the Hassi Mouina license in Algeria’s Sahara Desert, is the second exploration well completed and tested there, fulfilling Statoil’s license obligations. Statoil did not give the TD of the well or the test production flows.
Statoil, which is working with Sonatrach, finished drilling the first exploration and appraisal well, Hassi Tidjerane 2 (HTJ-2), in March. Statoil holds a 75% interest in Hassi Mouina, and Sonatrach has 25%.
Bill Maloney, senior vice-president for global exploration, said results from both wells were valuable, and that the company would continue with its exploration program to map the resource potential in the block.
“The next location for the [land] rig is Tinerkouk (TNK-1) south in the license, where a third well will be drilled,” Statoil said.
The Hassi Mouina license has four blocks within a 23,000-sq- km area in the Gourara basin.
The area lies in the Western Sahara, northwest of the In Salah gas field in which Statoil has a 31.85% interest.
Statoil has a 75% interest in Hassi Mouina, and Sonatrach has 25%.
Apache tests Exmouth basin well off W. Australia
Houston independent Apache Corp. has completed a successful test of Theo 3-H, the first horizontal well at the Van Gogh development in the Exmouth basin 1,175 km off Western Australia.
Theo 3-H was drilled in 1,205 ft of water to a MD of 10,598 ft. It cut a 4,554-ft horizontal section in the Cretaceous Top Barrow formation.
The well flowed 9,694 b/d of oil on test. Its flow rate was restricted by downhole and surface equipment limitations, Apache said.
The company plans to drill 18 additional long-reach horizontal laterals at Van Gogh later this year, with a target of first production by the end of first quarter 2009. At that time, the field is expected to add 20,000 b/d of oil to the company’s net production.
The $500 million Van Gogh development will use a floating production, storage, and offloading vessel with a processing capacity of 63,000 b/d and storage capacity of 620,000 bbl. Apache operates the development and owns 52.5% interest in the project, while Tokyo-based Inpex Corp. owns 47.5%.
The Pyrenees development, in which Apache holds 28.57% interest, is expected to add 20,000 b/d of oil to the company’s net production as well during 2009. It is anticipated that this field, operated by BHP Billiton Ltd. (71.43%), will receive the formal go-ahead by the end of this month.
Apache currently is drilling the Julimar East-1 appraisal well 3.6 miles northeast of the Julimar-1 gas discovery, which flowed at a combined rate of 85 MMcfd on tests of two Triassic channel sands. Julimar East-1 will appraise the channels tested in the discovery well and will target additional deeper Triassic sands.
Remote Alabama well taps Devonian gas
The Alabama Oil & Gas Board has reported a completion test earlier this year of a modest Devonian gas well off the southern flank of the Black Warrior basin.
EOG Resources Inc., Houston, filed a test rate of 120 Mcfd of gas with 120 psi flowing tubing pressure on a 24/64-in. choke with 118 b/d of water from Devonian perforations at 8,150-8,763 ft. Test date is Mar. 4.
The company’s 1 Bayne Etheridge 36-9 well, in 36-20n-2e, Greene County, Ala., is 13 miles south-southeast of Eutaw, Ala. Permitted to 10,350 ft, it went to TD 9,509 ft.
Generalized stratigraphic charts of the Black Warrior basin show two units in the Devonian, the Chattanooga shale underlain by a thicker cherty limestone.
The well site is 40 miles south of nearest Black Warrior basin production in Pickens County and 3 miles northeast of the ARCO Oil & Gas Co. 1 ARCO-Amoco Koch well, drilled to TD 15,600 ft in 10-19n-2e, Greene County, in 1983-84. It was abandoned.
This well site is 140 miles southwest of a budding play for gas in Cambrian Conasauga shale in the Gadsden, Ala., area (OGJ Online, Jan. 23, 2007).
Drilling & Production - Quick TakesIvanhoe completes Athabasca bitumen test
Ivanhoe Energy Inc. completed an Athabasca bitumen test run at its commercial demonstration plant in Bakersfield, Calif., using HTL, the company’s proprietary heavy oil upgrading technology.
The test run was carried out as outlined in a 2000 technology agreement with ConocoPhillips Canada, which provided Ivanhoe with the Athabasca bitumen.
ConocoPhillips Canada has certain nonexclusive capacity rights to use the HTL technology in Canada. The test run was witnessed by a third-party engineer in preparation for Ivanhoe’s key investment banking arrangements.
Ivanhoe will use information derived from the test for the design and development of full-scale commercial projects in Western Canada (OGJ, Mar. 27, 2006, Newsletter).
The continuous multiday bitumen trial run was successfully concluded when the feed tank was emptied. The trial demonstrated Athabasca bitumen processing in various HTL modes, including “high yield” and “high quality.”
Minke gas field in North Sea begins production
Gaz de France Britain, operator of Minke field in the southern UK North Sea, has begun gas production from a single well subsea development in the field. Minke will produce 60 MMcfd of gas, which will be transported via a 15-km pipeline to the Dutch D15 platform for delivery to Uithuizen in the Netherlands. The well produced as much as 75 MMcfd of gas on test.
GDF Britain, describing Minke’s development as a technically and commercially challenging project, said the gas is being delivered from a field that is far from existing infrastructure. It is on Block 44/24a, about 180 km off Norfolk and is adjacent to the UK-Dutch median line in 45 m of water.
Faroe Petroleum (UK) Ltd., a partner in the field, has agreed to buy its equity share of gas under a traditional oil-indexed contract under a gas sales agreement with Gaz de France.
“Minke Main is one of three undeveloped gas field discoveries we acquired in mid-2006 from ConocoPhillips as a package of license interests,” Faroe Petroleum said. “The other two undeveloped discoveries in the package are the adjacent Minke Graben, which may be drained through Minke Main, and the Orca gas fields, with two tested discovery wells.”
Development decisions on Minke Graben and Orca are anticipated in late 2007 or early 2008.
Ownership interests in Minke field are GDF Britain 15.6%, E.On Ruhrgas UK 42.67%, RWE Dea UK 35.84%, and Faroe Petroleum 5.89%.
Heavy oil production starts at Chetopa field
MegaWest Energy Corp., Calgary, has begun oil production at its demonstration project in Chetopa field, a nonconventional oil development covering 392 acres in Labette County in southeastern Kansas.
The company expects to recover 150,000 bbl of heavy oil from the 15-acre project using thermal recovery. Production currently averages 30-50 b/d from four producing wells. Over the next 3-4 months, this rate is expected to ramp up to 250-300 b/d.
The producing sandstones are analogous to the Bluejacket and Warner sandstones in Missouri, MegaWest said.
The project includes 10 injector sites with twin injectors-one installed above the shale and the other below it, said MegaWest Pres. and Chief Executive Officer George Stapleton.
Of the 20 injector wells in a 10 1/2-acre pattern, the company said 19 are operational. Average depth is 125 ft.
There are 30 production wells in the thermal recovery project. The 26 producers not yet on line are expected to come on stream “as the steam injection operations progress,” said David Sealock, vice-president, corporate services.
MegaWest plans to build a natural gas fuel pipeline by October to facilitate a switch to natural gas from motor oil in the steam generator and therefore reduce the project’s fuel cost, which amounts to about 66% of total project expenses.
The company has allocated $345,000 of its 2007 budget to the Chetopa development, which is expected to ultimately recover 900,000-1 million bbl of oil, Stapleton said.
The company also has plans to start pilot projects in its other holdings in Kentucky, Texas, and Missouri, he said.
MegaWest has a 100% interest in Chetopa field.
SembCorp Marine units win two jack up contracts
SembCorp Marine Ltd. subsidiary PPL Shipyard has received a $190 million contract to build a jack up drilling rig for Offshore Group Corp., the third rig ordered by the company.
Construction of the rig is expected to start in the third quarter, with delivery scheduled for September 2009, SembCorp said.
In May, SembCorp Marine said its subsidiary Jurong Shipyard, won a $442 million contract to build a drilling and production jack up for Petroprod Ltd., with delivery expected in mid-2010.
SembCorp Marine said the harsh-environment jack up will be built based on the CJ70 design with suitability for operations in the Norwegian sector of the North Sea.
Processing - Quick TakesS-Oil to boost Onsan refinery’s paraxylene output
S-Oil Corp. has started a project aimed at increasing paraxylene production at its 520,000 b/cd Onsan refinery and chemical complex in South Korea.
The company has selected ExxonMobil Chemical Technology Licensing LLC’s selective PxMax technology, which will allow for an 8% capacity increase without requiring modification of the paraxylene separation process facilities.
The PxMax method produces a paraxylene-enriched mixture that is further processed into sales grade paraxylene. It replaces a nonselective toluene disproportionation process that produced equilibrium mixed xylenes.
BP, DuPont, and ABF propose UK biofuels plants
BP PLC, DuPont, and Associated British Foods have proposed the construction of a 420 million l./year bioethanol plant at Saltend, Hull, UK. The plant is being proposed to help ensure that the UK has 5% of its transportation fuel come from biofuels by 2010. The plant is due to start operations in late 2009 and will use wheat as feedstock.
The partners also plan to develop a 20,000 l./year biobutanol demonstration plant at the same site by early 2009. Investments in the two initiatives are expected to hit $400 million amid growing political pressure to find alternative energy sources for transportation fuels.
“Although initial production would be bioethanol, the partners will look at the feasibility of converting it to biobutanol once the required technology is available,” BP said.
The partners are talking to grain trading business Frontier Agriculture about securing locally grown wheat as well as with coproduct marketing company AB Agri in relation to DDGS-a byproduct of bioethanol production. It is expected that formal agreements would be finalized after regulatory approvals are obtained.
Aker Kvaerner and its joint venture partner Praj Industries have won the front-end engineering and design work for the bioethanol plant, with Praj bringing technology and process expertise. The contract follows the companies’ recent formation of the BioCnergy Joint Venture, announced June 12.
John Ranieri, head of DuPont Biofuels, said demand was growing significantly for biofuels and it has accelerated the commercial development of biobutanol over the past year.
BP and ABF subsidiary British Sugar would each hold 45% of the plant, with DuPont owning the remaining 10%.
Initial development of biobutanol will start with BP and DuPont sourcing small quantities of biobutanol from China by yearend to test on infrastructure and vehicles.
BP and DuPont launched a partnership last June to develop, produce, and market a next generation of biofuels.
Transportation - Quick TakesExpansions planned for China’s Zhoushan oil port
China’s National Development and Reform Commission has approved an oil port and storage expansion project at Zhoushan port, Ningbo, in eastern China’s Zhejiang province.
NDRC said Zhejiang Jianqiao Energy Development Co. Ltd. will invest 325 million yuan to build the facility, which will include a 50,000-tonne-capacity berth for oil products, a 5,000-tonne-capacity berth, and storage for 290,000 cu m.
The port currently has a throughput capacity of 4 million tonnes/year, NDRC said. However, in May the New China News Agency reported that Zhoushan port handled 2.02 million tonnes of imported crude, up 48.6% from last year. The imports were primarily from the Middle East, the news agency said.
Enbridge again to expand North Dakota pipeline
Enbridge Energy Partners LP, Houston, will conduct a binding open season through Aug. 3 for capacity on the Phase 6 expansion of its North Dakota pipeline system.
The proposed $130 million expansion project, if fully subscribed, would increase system capacity to 155,000 b/d from 110,000 b/d, to be available by yearend.
The system transports oil from western North Dakota and eastern Montana to Clearbrook, Minn., via the Minnesota Pipeline and the Lakehead system. From there shippers can access most major refinery markets along the Great Lakes and in the Midwest and along the US Gulf Coast through current and planned interconnecting pipelines.
Demand has been exceeding eastbound pipeline capacity and there is increased oil production, especially in Richland County, Mont., and western North Dakota oil fields (OGJ, Dec. 11, 2006, p. 42).
Millennium gas pipeline project under way
Millennium Pipeline Co. LLC has begun construction of its 182-mile, 30-in. natural gas pipeline across the Southern Tier and lower Hudson Valley areas of New York.
Construction will continue during the next 2 years, with some restoration work extending into 2009. The pipeline is scheduled to begin service Nov. 1, 2008. It will serve markets along its route and will provide essential service to the New York City markets through its pipeline interconnections.
The project initially was expected to be commissioned late this year, but the in-service date was pushed back due to project delays (OGJ Online, July 17, 2006).
Phase 1 of the project will transport 500 MMcfd of gas from the Dawn, Ont., trading hub and several supply and storage basins. It includes the upgrade of a 186-mile Corning-Ramapo, NY, pipeline section on Millennium, which will replace an existing line of Columbia Gas Transmission Corp., and an 83-mile extension of the 24-in. Empire system from a point near Rochester to Corning, NY. Empire connects to the TransCanada PipeLines Ltd. system at Chippawa on the US-Canada border.
The Millennium Pipeline is jointly owned by affiliates of NiSource Inc., KeySpan Corp., and DTE Energy.