OGJ Newsletter

May 11, 2009
General Interest — Quick Takes

Work begins on Calabar Energy City in Nigeria

Work has begun to create an energy city in Calabar, Nigeria, that will allow oil companies to fabricate some of their required material and ease their logistic and infrastructure issues.

Eyo Ekpo, special adviser on projects in Cross River, told OGJ that the 376 hectares of land in Cross River state will be funded and managed through public-private partnership. The land is swamped and the government has begun to reclaim the site at Ekorinim Peninsula for the industrial area and a portion of Pamol Rubber Estate for residential.

Ekpo said, “We have been doing modeling for the past 6-9 months [and] we’re ready to go next year.” He said he was holding discussions with the Oil and Gas Free Zone Authority to acquire tax breaks for companies that would establish operations in the park.

Calabar Energy City (CEC) is an initiative launched by Sen. Liyel Imoke, the governor of Cross River state. Ekpo told OGJ that there would be a 25-hectare tank farm complex with a loading jetty, a river parts complex, a heliport, a medical center, and a hotel and business complex. He said a private company would manage the park and he expects there to be strong interest from companies in using its resources.

For the first phase, oil companies will be able to secure 220-hectare plots under leases on the ecoindustrial park to carry out infrastructure and facilities. The second phase, covering 500 hectares north of Calabar, will focus on zones for residential, sporting, religious, and commercial uses. The industrial area is key to CEC, but both parts will be served by utility and infrastructure services delivered to high standards.

Cross River state is within the Niger Delta, and the project will position Calabar as a secure and viable location for the oil industry, Ekpo told OGJ. It will also create job opportunities in the region and beyond.

CEC will take advantage of the federal government’s policy that requires 60% of man-hours be carried out within the operating region. This has been difficult to meet in the Niger Delta due to the violence and attacks by militants.

Salazar, Locke restore ESA consultation requirement

The US Interior and Commerce departments are revoking a George W. Bush administration order and requiring consultations with their two agencies that administer the Endangered Species Act (ESA), the two departments’ secretaries announced.

Federal agencies will once again have to consult with wildlife experts at the US Fish and Wildlife Service at DOI and the National Oceanic and Atmospheric Administration at Commerce before taking any action which might affect threatened species, Interior Secretary Ken Salazar and Commerce Secretary Gary Locke said on Apr. 28.

The action rolls back an order that Salazar’s predecessor, Dirk A. Kempthorne, said would simplify regulations at the two agencies by not making them review every action involving the ESA unless they considered it necessary. Kempthorne said this would make operations more efficient and let the agencies give more attention to truly pressing matters.

Salazar characterized it as another Bush administration 11th hour regulation. “By rolling [it] back, we are ensuring that threatened and endangered species continue to receive the full protection of the law. Because science must serve as the foundation for decisions we make, federal agencies proposing to take actions that might affect threatened or endangered species have to consult with biologists at the two departments,” he said.

“For decades, the [ESA] has protected threatened species and their habitats. Our decision affirms the administration’s commitment to using sound science to promote conservation and protect the environment,” Locke said.

The two secretaries said that US President Barack H. Obama directed them in March to review the previous administration’s Section 7 regulation in the ESA, which covers consultation. Congress, in the 2009 Omnibus Appropriations Act, authorized them to revoke the regulation, they added.

Locke and Salazar said the two departments would jointly review the 1986 consultation regulations to determine if any improvements are needed.

Environmental organizations applauded the move. “The Bush rules would have allowed agencies with little or no wildlife expertise to make decisions that could mean life or death for animals like the polar bear. Today’s decision restores the important protections for species and their habitats offered by one of our nation’s most fundamental environmental laws,” said Sierra Club Executive Director Carl Pope.

“For decades, the [ESA] has used sound science as the guide to protect America’s most vulnerable plants and animals. Today, the Obama administration reaffirmed that politics should not be the driver of these protections. Our nation needs to start investing in new and better infrastructure projects, and restoring this law will make sure we do so without harming our endangered plants and animals,” said Rebecca Riley, a lawyer with the Natural Resources Defense Council’s Endangered Species Project.

Industry Scoreboard
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Exploration & Development — Quick Takes

ConocoPhillips, Anadarko make NPR-A finds

ConocoPhillips and Anadarko Petroleum Corp. reported the discovery and test production from two wells in the National Petroleum Reserve-Alaska (NPR-A).

Pioneer 1, which was tested in March, and Rendezvous 2, which was tested in winter 2008, both lie in the Greater Mooses Tooth Unit about 20 miles southwest of the Colville River Unit development on the North Slope of Alaska.

Test production rates for these wells ranged from 500 b/d to 1,300 b/d of high-gravity oil. Gas production rates averaged 1.5 MMcfd for each well, the companies said.

“No further delineation drilling is planned for Pioneer or Rendezvous at this time,” the companies said. These two accumulations will be pursued as possible satellite developments with processing at the Alpine facilities in the Colville River Unit.

Operator ConocoPhillips holds 78% interest in the Greater Mooses Tooth Unit, while Anadarko holds 22%.

Barrett probing two eastern Utah gas shales

Bill Barrett Corp., Denver, expects to learn the outcome by mid-2009 at a horizontal well spud late in the first quarter of 2009 seeking gas in Upper Mississippian Manning Canyon shale at 8,000 ft true vertical depth.

The prospect lies in northern Emery County southeast of Price, Utah, along the San Rafael Swell on the Uinta basin southwestern flank. Numerous wells as far west as Drunkards Wash coalbed methane field in Carbon County have had gas shows in Manning Canyon.

The horizontal well offsets an initial vertical well drilled in 2008 that indicated good gas shows and high gas content in core. Bill Barrett holds 50% working interest in the deep prospect.

The company has also drilled two vertical wells to 3,900 ft in the fractured Juana Lopez shale member of the Upper Cretaceous Mancos formation, in which it has 100% working interest. It plans to complete testing those wells in 2010.

StatoilHydro deems Canon find noncommercial

StatoilHydro will permanently plug and abandon its exploration well on the Canon prospect in the Norwegian North Sea after making a gas-condensate discovery that was deemed noncommercial.

The well tested the upper Brent reservoir and the deeper Statfjord sandstone level, producing gas and condensate in the former and penetrating tight sands in the latter that was probably full of water.

Tom Dreyer, StatoilHydro’s vice-president, infrastructure exploration in the North Sea, said the Brent reservoir was thinner than expected.

The exploration well 30/3-10 S reached a TVD of 3,962 m in 122 m of water. StatoilHydro used the West Alpha semisubmersible rig to drill the Canon prospect, which lies 11 km west of Veslefrikk field in the North Sea. The well was drilled to prove petroleum in a fault block between the Huldra and Oseberg fields, said StatoilHydro.

The rig’s charter with StatoilHydro will terminate once the well is completed.

This is the second well to be tested in the Canon structure. An exploration well drilled in 2000 provided inconclusive results about the economic potential of the structure.

StatoilHydro operates production license 052 with an 18% share. Other parters include Petoro 37%, RWE Dea Norge 13.5%, Revus Energy 4.5%, and Talisman Resources Norge 27%.

Heritage reports giant Iraqi Kurdistan find

Heritage Oil Corp. has reported the discovery of a giant oil field in Iraqi Kurdistan with 2.3-4.2 billion bbl of oil in place, of which 50-70% appears recoverable.

Exploration risk of an adjacent structure of similar size is greatly reduced, Heritage Oil said.

The company said it could start trucking production from Miran West-1 by the end of 2009, with individual flow rates likely to be 10,000-15,000 b/d/well.

A fractured gross oil-bearing interval of 710 m produced 27° gravity oil with low sulfur, no water, and a low gas-oil ratio.

The company drillstem tested Miran West-1, the first well ever drilled on the license, over a 500-m gross interval in the Shiranish, Kometan, and Qamchuqua formations. High reservoir pressures that characterize the region were not encountered in the well, Heritage said.

“Testing was severely constrained by the limitations of the downhole and surface testing equipment and the loss of over 100,000 bbl of drilling fluid and lost circulation material due to the highly fractured nature of the reservoirs,” the company said.

More equipment to carry out longer term tests is expected within 6-8 weeks. Further drilling on the license is set for later in 2009.

The Miran West and East structures total 330 sq km.

Heritage Energy Middle East operates the Miran license with 75% interest, and Genel Energy International Ltd. has 25%. Heritage mapped the structures from 332 line-km of seismic shot between April and June 2008.

Drilling & Production — Quick Takes

Tupi pilot begins production off Brazil

The extended production test of the giant presalt Tupi discovery in the Santos basin off Brazil has begun to the BW Cidade de Sao Vicente FPSO, according to Galp Energia SGPS SA, Lisbon, Portugal.

The FPSO, with a 30,000 bo/d processing capability, is moored in 2,170-m of water in Block BM-S-11, about 280 km off Rio de Janeiro’s coast.

Galp Energia says that production will not exceed 14,000 bo/d during the 15-month production test of the Tupi Sul and Tupi-1 wells.

The Tupi field, discovered in October 2006, contains an estimated recoverable 5-8 billion bbl of light 28-30° gravity oil and natural gas.

Operator Petroleo Brazileiro SA has a 65% interest in the block. Partners are BG Group, 25%, and Galp Energia, 10%.

Tahiti field, gulf’s deepest production, starts up

Chevron Corp. announced that oil production from Tahiti field, the deepest producing field in the Gulf of Mexico, started on May 5. Chevron expects daily production to ramp up to about 125,000 bo/d and 70 MMcfd of natural gas by yearend.

Tahiti field, discovered in 2002, is one of the largest in the gulf and contains 400-500 million boe of recoverable resources, according to Chevron. The first phase of the project cost $2.7 billion.

Tahiti lies on Green Canyon Blocks 596, 597, 640, and 641 in 4,100 ft of water about 190 miles south of New Orleans.

Primary pay sands are Lower to Middle Miocene at 23,000-28,000 ft that lie below a 8,000-15,000 ft thick salt canopy.

The deepest producing well has a depth of more than 26,700 ft, a record for the gulf, according to Chevron.

The field produces from two subsea drill centers with six subsea wells tied back to a production facility on a floating truss spar.

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The operator Chevron holds a 58% working interest in the field. Partners are StatoilHydro 25% and Total SA 17%.

Cased laterals pay in Mississippi Selma chalk

Penn Virginia Corp., Radnor, Pa., is producing 13 MMcfed from 20 horizontal Cretaceous Selma chalk wells in Mississippi.

The 20 wells averaged initial 30-day rates of 815 Mcfed compared with 272 Mcfed for vertical wells.

Production in the quarter ended Mar. 31 averaged 23.3 MMcfed, up 14% from the fourth quarter and 17% from the first quarter of 2008.

Results to date indicate that one horizontal well replaces two to three vertical wells and recovers four to five times the reserves of a vertical well. Laterals average 3,000 ft and have seven to eight frac stages.

Penn Virginia plans to cement casing and perforate all future completions. The first 15 wells are open-hole completion and the last five have cemented casing and perforations.

Open-hole completions averaged 761 Mcfed after 30 days and 804 Mcfed after 60 days, while cased-perforated completions averaged 1 MMcfed after 30 days and 1.2 MMcfed after 60 days.

Spud to sales averaged 41 days for the three wells drilled in the 2009 first quarter compared with 49 days for the first 17 horizontal wells. Drilling and completion cost has fallen to $2.5 million/well from $3 million.

Chevron expects production to ramp up to 125,000 bo/d of oil and 70 MMcfd of gas by yearend from Tahiti field. Photo from Chevron.

Processing — Quick Takes

Fire-damaged Tyler, Tex., refinery restarts

A Tyler, Tex., refinery is restarting after repairs to units damaged by a fatal fire Nov. 20.

Delek US Holdings Inc., based near Nashville, Tenn., is resuming operations of the 60,000-b/d facility.

The fire broke out in the area of the saturates gas plant and naphtha hydrotreater, killing one worker and injuring six. Those units and the control room sustained damage.

With 20,200 b/d of fluid catalytic cracking capacity and 6,500 b/d of delayed coking, the refinery yields of 90% light products and less than 2% of heavy oils from mainly light, sweet crude feedstocks.

Two refineries sought for Indonesia’s Batam Island

Indonesia’s Setdco Group and its partner PT Intan Megah have sought permission to build a 300,000 b/d refinery at Tanjung Sauh on Batam Island near Singapore—one of two new facilities apparently set for construction on the island.

“The crude oil will be from the Middle East,” said Evita Legowo, director general for oil and gas at the Ministry of Energy and Mineral Resources. She said the government is still in the process of issuing a permit for the development of the planned refinery, and could release no further details.

Meanwhile, other reports have emerged that Gulf Petroleum Ltd., Qatar’s largest oil company, also plans to build a refinery in Batam.

Gulf Petroleum is preparing documents needed to seek the investment license from the Indonesian government, according to Ismeth Abdullah, chairman of the Batam Free Trade Zone Council.

Gulf Petroleum Pres. Abdul Aziz Abdulaimi and PT Batam Sentralindo Pres. Bang Hawana recently signed a memorandum of understanding on the project.

PT Batam Sentralindo, the operator of the Batam Free Trade Zone, has agreed to provide a 250-hectare plot of land for the refinery project, which plans to sell its products in Indonesia and other Southeast Asian nations.

Meanwhile, reports said that a $1.5 billion refinery joint venture between Indonesia’s state-owned PT Pertamina and Japan’s Mitsui & Co. may stall because the Indonesian government wants an increased stake in the project.

Agreement had been reached to build a residue fluid catalytic cracking unit with a capacity of 60,000 b/d of gasoline in Pertamina’s existing refinery at Cilacap in Central Java, with Mitsui holding an 80% stake and Pertamina 20%.

But the Indonesian government has advised Pertamina to review the project and seek a higher stake, a request that could sink the project altogether according to one source, who said financing for the refinery already has been approved by the Japan Bank for International Cooperation.

Transportation — Quick Takes

EOG to rail Bakken crude to Cushing

EOG Resources Inc., Houston, is implementing a plan to use rail car unit trains to ship crude produced from the Bakken formation in North Dakota to the Cushing, Okla., terminal.

EOG Resources has finalized a strategic transportation arrangement with Burlington Northern Santa Fe railway and expects to have the rail facility operational by February 2010, said Mark Papa, chairman and chief executive officer.

The deal will afford sharply better long-term oil netbacks than it is receiving by shipping its oil by pipeline through the hub at Clearbrook, Minn., Papa said.

The company, which restricted its Bakken oil production for the first 6 months of 2009 due to marketing issues, expects to resume full production in Parshall field in North Dakota by July.

In the Williston basin, EOG Resources is running eight rigs compared with 10 in 2008, and the company has deferred almost all well completions until summer 2009 when fracs can be performed more economically and road conditions improve.

With natural gas prices languishing, EOG Resources’s $3.1 billion capital budget for 2009 is directed toward liquids investments, Papa said.

The company raised its 2009 overall oil and gas production growth target to 5½ % from 3%, driven by a 22% increase in liquids output. Most of the increase is to come from its Bakken and Fort Worth basin Barnett shale plays.

Changes sought in gas line flow posting rules

Calling it a small, but important, adjustment, the Natural Gas Supply Association asked the US Federal Energy Regulatory Commission to slightly change gas pipeline flow-posting requirements.

In an Apr. 30 filing, NGSA asked FERC to consider adopting a “sole-feed” exclusion. This would exempt major noninterstate gas pipelines from reporting if the pipeline has no, or very small volume endusers with total receipts of less than 15,000 million BTUs/day, or if the pipeline feeds into another major pipeline, NGSA said.

Taking this step would reduce the burden and cost of compliance for small-volume pipelines while continuing to provide clear information to regulators and the public, the trade association added.

NGSA said FERC issued in November Order No. 720, which requires certain noninterstate and interstate gas lines to post design capacity and daily scheduled gas flow information. The rule also imposed posting requirements on interstate gas pipelines that provide no-notice service.

Jenny Fordham, NGSA’s energy markets and government affairs director, said the association believes FERC got the new reporting process “about 98% right” when it changed the pipeline reporting requirements last year.

“Our ‘sole-feed’ proposal would further simply the process and capture the same data, just a few miles further downstream. A sole-feed exclusion is consistent with the commission’s desire to establish rules that will increase transparency without additional cost,” she said.

Pacific Connector line moves closer to fruition

The US Federal Energy Regulatory Commission issued a final environmental impact statement (FEIS) on Pacific Connector Gas Pipeline LP’s proposed 36-in. OD sendout pipeline, moving the project one step closer to fruition.

The proposed line would extend from Jordan Cove’s LNG terminal—which was issued its FEIS as part of the same proceeding—about 234 miles southeast across Coos, Douglas, Jackson, and Klamath counties in Oregon to a terminus near Malin, Ore. From there the proposed line would interconnect with the existing pipeline systems of Gas Transmission Northwest Corp., Tuscarora Gas Transmission Co., and Pacific Gas & Electric Co.

The 1-bcfd Pacific Connector pipeline would include 1 compressor station, 4 meter stations, 4 pig launchers-receivers, 16 mainline block valves, 5 communication towers, and additional communications equipment at 8 existing towers.

Pacific Connector has entered into agreements with seven customers who have requested 1.49 bcfd through the proposed line. Upon finalization of LNG supply commitments at the Jordan Cove terminal, Pacific Connector will allocate, if needed, the available 1 bcfd amongst the seven customers.

Its route crosses 218 waterbodies (some multiple times) within 6 hydrological subbasins. Installation under 3 major rivers (Coos, Rogue, and Klamath) will use horizontal directional drilling, while 3 waterbodies (Kentuck Slough, Catching Slough, and the Medford Aqueduct) will be bored, 1 river (South Umpqua) will have diverted crossings, and the remainder of the waterbodies will be dry crossed, except for the open cut wet crossing of a portion of Coos Bay.

Pacific Connector’s current proposed route reduced the crossing of the Coos Bay estuary to less than 2½ miles.


Correction

The story “LNG supply, fuel competition pose major concerns in US” incorrectly identified the speaker for Poten & Partners (OGJ, May 4, 2009, p. 49). Speaking was Jim Briggs.