OGJ Newsletter

Feb. 27, 2006
Natural gas reserves in the US Rocky Mountain region are expected to exceed 130 tcf by 2030 if growth continues at the rate indicated by 30 years of statistics, energy consultant Wood Mackenzie Ltd. said.

General Interest - Quick Takes

WoodMac sees growth in Rockies gas reserves

Natural gas reserves in the US Rocky Mountain region are expected to exceed 130 tcf by 2030 if growth continues at the rate indicated by 30 years of statistics, energy consultant Wood Mackenzie Ltd. said.

Rocky Mountain volumes currently account for more than 31% of Lower 48 proved gas reserves, WoodMac said in its report.

The US Energy Information Administration reported Rocky Mountain proved gas reserves rose to 57.5 tcf at yearend 2004 from 19 tcf in 1977.

Of the increase, 90% came from extensions and revisions, predominantly in three states: Wyoming, western New Mexico, and Colorado, WoodMac said, calling the region “the growth play for US domestic gas supply.”

The analysts noted that the resource is dominated by unconventional gas.

Rocky Mountain states as defined in the report involve Colorado, Montana, North Dakota, Utah, Wyoming, and the western half of New Mexico, to include the entire San Juan basin.

Last year, BP PLC, ExxonMobil Corp., and other companies announced expansion plans for operations in the region. ConocoPhillips’s pending $35.6 billion acquisition of Burlington Resources Inc. will boost its gas holdings in the area (OGJ, Dec. 19, 2005, p. 41).

WoodMac based its conclusions about future reserves on two forecasts. The first forecast stems from an extrapolation of the EIA’s Annual Energy Outlook 2006.

Using a trend model to calculate what would happen if Rockies reserves growth from 1977 to 2004 continued at the same pace, WoodMac said the region’s reserves could reach 133 tcf by yearend 2030.

For the second forecast, WoodMac analysts relied on their own modeling applied to a time series in which successive data points are highly dependent on prior data points. That model suggests Rockies reserves could reach 138 tcf by yearend 2030.

“Although both of these forecasts are based on a different set of statistical techniques, the results are very much aligned,” WoodMac said. The forecasts do not include possible changes in regulations, mergers and acquisitions, or technological advances.

Desmarest: Efficiency key to avoiding crisis

Improved energy efficiency is “a critical step in avoiding an energy crisis,” says Thierry Desmarest, chairman and chief executive officer of Total SA.

At a press conference, he pointed out that oil resources remain important, with conventional oil reserves representing 40 years of current consumption, more it did than 30 years ago when consumption was much lower. The challenge, he said, is to reduce oil demand growth to less than 1%/year.

“One cannot let oil demand grow to the peak oil stage,” he cautioned.

High oil prices will concentrate demand to the transport and petrochemical applications. Little oil should be used for electricity and heating, he said.

He advocated development of energy conservation in residential and commercial markets, continued improvements in industrial processes and power plant efficiency through research, increases in transportation efficiency and preparation for technological breakthroughs such as fuel cells, and development of renewable and nuclear energy sources.

He said a long-term role for gas will require expansion of the global LNG market.

Trinidad and Tobago seeks gas for local use

The government of Trinidad and Tobago has told oil and gas companies wanting to be part of future LNG expansions that they will have to commit some of their gas for domestic use.

Prime Minister Patrick Manning set out the condition during a ceremony to mark the completion of Atlantic LNG Co. of Trinidad and Tobago’s Train 4.

“A fifth train is going to come, and we are going to institute a policy that if you want to have access to export gas, you must commit some of your reserves to domestic gas utilization-that policy is well on the way,” Manning said. When the fifth train comes, he added, “we are going to pause, and we are going to have another look.”

There has been increasing concern in the Caribbean island nation about the availability of gas for domestic consumption, including for methanol, ammonia, urea, and aluminum projects already approved by the Trinidad and Tobago government.

Gas producers have been accused of being more interested in exporting LNG than selling gas locally because of a huge differential in returns to the companies.

Trinidad and Tobago accounts for nearly 80% of the LNG imported by the US.

Train 4 has been designed for a capacity of 5.2 million tonnes/year of LNG for export and as much as 12,000 b/d of NGL. It is one of the world’s largest LNG trains in operation. The Train 4 project also features an additional 700 m jetty and a 160,000 cu m storage tank.

Train 4 uses a nominal 804 MMscfd of gas supplied principally by BP Trinidad and Tobago and BG/North Coast Marine Area partners. BG’s supply of gas will come from reserves off east and north coasts and BP’s from the southeast coast.

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Exploration & Development -Quick Takes

Quick Takes

Repsol YPF group finds more oil on Libya’s NC-115

A group led by Repsol YPF SA reported its seventh discovery on Block NC-115 in the Murzuk basin 800 km south of Tripoli.

The well, which produced 2,300 b/d of light crude, is near late 2005 discoveries that produced 2,060 boe/d and 4,650 boe/d, respectively.

Repsol YPF is operator with 32% interest. Other participants are Libyan National Oil Corp., OMV AG, Total SA, and Norsk Hydro AS.

Repsol YPF-operated production in Libya averaged 240,500 b/d last year. Current production from NC-115 is 200,000 b/d.

Gas discovery reported

off South Korea

South Korea’s Korea National Oil Corp. is reported to have made another gas discovery in the Donghae 6-1 area of the Sea of Japan.

The discovery is 75 km southeast of Ulsan, smaller than the Donghae 1 discovery but close enough to be developed with the earlier find (OGJ, Feb. 10, 2003, Newsletter).

The state-owned firm said a pipeline could be built to connect the two fields. Detailed analysis of the gas find will start in March.

North Cuba gets oil find

on western Block 7

Pebercan Inc., Montreal, production-tested an indicated discovery well near the western edge of Block 7 on the North Cuba heavy oil belt east of Havana.

The Tarara-100 well, 50 km west of Canasi and Seboruco oil fields, stabilized at 700 b/d of 16° gravity oil through a 12-mm choke.

The oil quality is similar to that found last year at Santa Cruz and is much better than that from Canasi and Seboruco, the company said (see map, OGJ, Jan. 10, 2005, p. 31).

“The well has found a new shallow field different from the conventional objective of Veloz carbonates,” Pebercan said without identifying the producing formation.

Drilled from shore, the well is drilled to 3,465 m measured depth to the Tarara prospect in the Bay of Cardenas.

Pebercan is “running long-term production and pressure tests to assess the extent and quality of this new potential field, which is at the limit of the available seismic data,” the company said.

“Depending on the results of these tests, an evaluation program will be prepared to develop this new oil reservoir. However, pending the result of the current surveys and tests, there is still nothing to confirm that the productive structure revealed can have a significant impact on the company’s reserves,” Pebercan said.

Pebercan plans to integrate results of the Tarara studies with a new 3D seismic interpretation before it drills Guanabo, the next structure east of Tarara.

India’s D6 gets Cretaceous find

Reliance Industries Ltd., Mumbai, and Niko Resources Ltd., Calgary, are doubling the original size of facilities planned to produce gas from Dhirubhai field in the D6 offshore block in the Krishna-Godavari basin.

The redesigned facilities will be able to accommodate 2.8 bcfd of gas and be expanded to 4.2 bcfd, Niko said. The action “indicates the new view of the reserve and production potential of the gas field,” Niko said without giving figures.

The initial design was for 1.4 bcfd (OGJ Online, Oct. 26, 2004). No clear indication has emerged when D6 gas production will begin or where the gas will be used.

Industry sources placed the gross proved reserves on the KG-DWN-98/3 (D6) block at 12 tcf.

The gas is in 400-2,700 m of water 40-60 km southeast of Kakinada. Reliance and Niko have discovered gas in Pliocene, Pleistocene, and Miocene formations and are beginning to talk of a deeper discovery in the Cretaceous.

MA-1 is the block’s first exploration well with primary target in the Cretaceous, which has potential for both oil and gas. Niko said Reliance has indicated that MA-1 found hydrocarbons in Cretaceous.

Reliance and Niko have approved retaining consulting engineers to estimate hydrocarbons in place in the Cretaceous sequences based on results of drilling and testing and integrating these results with 2D and 3D seismic data acquired in the block.

MA-1 is the block’s 16th consecutive successful exploration well.

Rigs to evaluate deeper-water parts of D6 are under contract and expected to arrive in September and November. A 2,550 sq km 3D seismic survey is planned through March south of the 3D seismic survey shot in 2004 (see map, OGJ, July 18, 2005, p. 34).

Drilling & Production - Quick Takes

Kerr-McGee starts Ticonderoga production

Kerr-McGee Corp. started production Feb. 16 from Ticonderoga oil and gas field on Green Canyon Block 768 in 5,250 ft of water in the Gulf of Mexico.

Ticonderoga has reached peak production of 20,000 b/d of oil and 15 MMcfd of gas.

Two Ticonderoga subsea wells are tied back to Kerr-McGee’s 100%-owned Constitution spar on Green Canyon Block 680 in nearly 5,000 ft of water 190 miles south of New Orleans. Kerr-McGee operates Ticonderoga with a 50% interest. Noble Energy Inc. owns the rest.

Constitution field is expected to go on stream during the second quarter. The Constitution truss spar currently has the capacity to process 70,000 b/d of oil and 200 MMcfd of gas.

Oxy, BP study CO2 injection in California

Occidental Petroleum Corp. and BP PLC are discussing options for injecting carbon dioxide captured at a power plant into Oxy’s mature California oil fields for enhanced recovery and sequestration.

The CO2 would come from a first-of-its-kind hydrogen-fueled power plant to be built alongside BP’s 247,000 b/cd Carson, Calif., refinery by BP and a unit of Edison International SPA.

Technical studies are under way to determine which of Oxy’s fields would be best suited for CO2 flooding. The company produces a net 120,000 b/d of oil equivalent from giant Elk Hills field in the San Joaquin Valley, the THUMS operation at Long Beach, and other fields in the Sacramento Valley.

Oxy injects more than 1 bcfd of CO2 in its Permian basin oil fields in West Texas and New Mexico, resulting in 85,000 b/d of oil production from previously unrecoverable reserves. The CO2 for those projects comes from natural deposits.

Detailed engineering and commercial studies for the proposed $1 billion power plant are expected to be complete in 2006. The final investment decisions are scheduled for 2008. The power plant would be commissioned by 2011.

The plant would convert coke from the refinery into hydrogen and CO2, of which 90% would be captured and separated. The hydrogen stream would fuel a gas turbine to generate electricity. The captured CO2 would be transported by pipeline to an oil field for injection.

The project would prevent emission into the atmosphere of an estimated 4 million tons/year of CO2.

Petrobras starts Golfinho test production

Brazil’s state-owned Petroleo Brasileiro SA (Petrobras) reported that the Seillean floating production, storage, and offloading vessel has begun operations in Golfinho field in the Espírito Santo basin. Production from the field, which is in a test phase to evaluate reservoir behavior, is currently 21,000 b/d of oil.

The Seillean FPSO will operate in the pilot production phase from the field, where the Capixaba and Cidade de Vitória FPSOs are to be sited in the first half of this year and the first half of 2007, respectively. Both units have capacities to process 100,000 b/d of oil.

Golfinho field is producing 28.5º gravity oil, Petrobras said, adding that start-up of these operations represents first oil production from deep water outside of the Campos basin.

Early last year, Petrobras drilled a well within Golfinho field boundary areas that penetrated sandy formations about 90 m thick saturated with high-quality light oil. The well was on the same block as the 1-ESS-123 well, which discovered Golfinho field (OGJ Online, Jan. 11, 2005).

Alberta storms stunt EnCana’s 2005 drilling

Three heavy rainstorms and severe ensuing floods in June 2005 allowed EnCana Corp., Calgary, to complete only 80% of the gas wells it planned to drill last year and add 80% of its forecast gas production additions.

Alberta’s wettest June ever caused 2-3 months of down time in field operations, the company said.

Nevertheless, the company replaced 271% of its 2005 production and hiked proved reserves 18% to 18.5 tcfe. It meanwhile has trimmed its 2006 forecast capital spending by $800 million or 12%. About $500 million of that is to reduce drilling in areas where costs have increased the most.

Record gas and oil prices and overall activity levels in 2005 led to cost increases of 15-30% for goods and services, but the company contained its inflation to the low end of the industry range in 2005 with volume purchasing power and longer term planning initiatives.

EnCana overspent its $6.2 billion 2005 capital budget by $600 million. Items were $200 million for cost inflation, weather delays, and field inefficiencies, $200 million to accelerate coalbed methane drilling and expand in situ oil sands projects, $100 million for land acquisition, and $100 million in foreign exchange.

ExxonMobil to let Aceh contracts expire

ExxonMobil Oil Indonesia said it will let its production-sharing contract for three natural gas blocks in Aceh, Indonesia, expire in 2018.

Maman Budiman, vice-president of public affairs at the Indonesian unit, said gas reserves on the B Block, Pase Block, and North Sumatra Offshore Block don’t warrant extension of the contract.

The blocks produce 1 bcfd of gas, but production is declining, Maman said. The gas is committed to LNG contracts that will expire in 2014.

Processing - Quick Takes

Expansion of Brazilian refinery due by June

Refap SA and Petroleo Brasileiro SA (Petrobras) will complete the expansion of the 120,000 b/d Alberto Pasqualini refinery in Rio Grande do Sul to 180,000 b/d by June.

The $1 billion project includes the installation of catalytic cracking, coking, and diesel hydrotreating units. It will increase the refinery’s ability to process heavy crude and its output of diesel (OGJ, Nov. 21, 2005, p. 18).

Petrobras imports large quantities of light oil to mix with heavy domestic crudes.

RRC, ATC plan Thailand aromatics complex

Aromatics (Thailand) PLC (ATC) has teamed with Rayong Refinery Co. to build a second aromatics complex in Thailand’s eastern Rayong Province. Originally, ATC had planned the complex alone (OGJ Online, Oct. 25, 2005).

The $1.07 billion project includes an aromatics complex and a reforming facility.

The complex will have production capacity of 2.88 million tonnes/year. Output will include 616,000 tonnes/year of paraxylene and 363,000 tonnes/year of benzene.

The facilities are expected to begin commercial operations in third-quarter 2008.

Delays cloud plans for Indonesian refinery

Indonesia’s state-owned PT Pertamina has announced a delay of as long as 2-3 years in construction of a 150,000-200,000 b/d refinery in Tuban, East Java.

Pertamina Director Suroso Atmomartoyo said the firm has found no partner for the project, on which construction was to have begun this year with completion expected in 2008.

President Susilo Bambang Yudhoyono disclosed plans for the refinery last July.

Indonesia imports almost a third of the oil products it uses because its 1.06 million b/d of refining capacity isn’t enough to meet demand.

Last August, China’s Sinopec and Pertamina announced plans to study feasibility of the Tuban refinery.

At the time, Pertamina Pres. Widya Purnama said the study was expected to be completed by the end of 2005, enabling construction of the refinery to begin in 2006.

But Atmomartoyo said Pertamina may have to cancel plans to cooperate with Sinopec due to prolonged and complicated negotiations over costs, which have risen because of brisk worldwide refinery construction.

Indonesia’s Koran Tempo newspaper quoted Atmomartoyo as saying that the cost of the project is now expected to reach $3 billion from an initial projection of $1.6 billion.

Factors other than rising construction costs may be at play in Sinopec’s uncertainty over the refinery project.

Much of the feedstock for Tuban is to come from the Cepu Block, where the start of production is expected to be delayed by a dispute over operatorship between ExxonMobil Corp. and Pertamina (OGJ Online, Feb. 13, 2006).

Transportation - Quick Takes

First shipment from BTC oil line set for May

Azerbaijan’s Minister of Energy and Commerce Natiq Aliyev said the first tanker to lift crude from the Baku-Tbilisi-Ceyhan pipeline will depart the Turkish terminal at Ceyhan in May.

Aliyev said pipeline construction is 99.7% complete. The most time-consuming work, he said, is to test all components of the pipeline, which is now half-full, with a total of 5 million bbl of crude oil pumped in.

He said the oil has reached the second pumping station in Turkey, and the third pumping station is being tested. Some 800 km of the pipeline in Turkey awaits line-fill.

Russian railway’s oil shipments to China up

Russian Railways subsidiary East Siberian Railway increased shipments of crude oil to China by 42.8% year-on-year to more than 790,000 tonnes in January.

ESR said it transported 590,800 tonnes of crude oil through the Zabaikalsk border crossing (up 98% year-on-year) and 199,400 tonnes through Naushki (down 22%).

Meanwhile, ESR is holding talks with operator companies to transport oil to China through Naushki, as OAO Yukos-currently the main supplier through Naushki-may reduce supplies to China to 1.8 million tonnes in 2006, down from 2.4 million tonnes in 2005.

ESR plans to transport as much as 15 million tonnes of oil to China in 2006, almost double the volume in 2005.

Talks start on use of Russia-China oil line

Rosneft has begun negotiations with Kazakhstan’s KazMunaiGaz and KazTransOil, China National Petroleum Corp., and Russia’s Transneft on using the recently completed Atasu-Alaskhankou pipeline to supply China with crude oil.

Rosneft Pres. Sergei Bogdanchikov confirmed that talks had started. He said the main point to be decided is priority of access to pipeline capacity.

CNPC and Kazakhstan’s National Petroleum & Natural Gas Co. completed construction of the 1,000-km pipeline last November. Line fill began in December (OGJ Online, Dec. 15, 2005).

E. Siberia-Pacific oil line changes studied

Russian oil pipeline monopoly Transneft and natural resource watchdog Rosprirodnadzor are jointly considering an alternative site for an oil export terminal as part of the proposed Eastern Siberia-Pacific Ocean pipeline project.

Transneft Pres. Semyon Vainshtok said Kozmino Bay, close to Nakhodka, is currently being considered instead of Perevoznaya Bay.

“According to Natural Resource Ministry information, some additional figures have been received about the negative ecological situation in the area of Perevoznaya Bay,” Vainshtok said. “If this is confirmed, we do not plan to dig our heels in and are ready to reconsider the end point of the pipeline.”

A Transneft-Rosprirodnadzor working group has carried out additional full-scale research of the proposed terminal sites on the shore of the Sea of Japan, and a final decision will be reached when this work is finished, Vainshtok said.

Meanwhile, Transneft’s project to build the Eastern Siberia-Pacific Ocean pipeline system near Lake Baikal is to be carefully studied by the ecological safety and environmental protection commission of Russia’s new Public Chamber.

“We will request information on this issue from Rostekhnadzor and will return to this topic again and again,” said Chairman Vladimir Zakharov at the first meeting of the commission on Feb 13.

He acknowledged that the Transneft pipeline project is necessary but said it has not received sufficient ecological scrutiny.

Another commission member, World of Wildlife Russia Director Igor Chestin, said Transneft provided only one option to build the pipeline. The law requires at least two options.

Chamber members fear the pipeline wouldn’t be able to withstand earthquakes possible in the area of the lake.

In addition, Chestin said, the Transneft pipeline network is subject to up to 600 illegal incisions and oil thefts per year, which result in oil spills.

According to UNESCO, the 3.15-million-ha Lake Baikal is the oldest (25 million years) and deepest (1,700 m) lake in the world. It contains 20% of the world’s total unfrozen freshwater.

Known as the “Galapagos of Russia,” the lake’s age and isolation have produced one of the world’s richest and most unusual freshwater faunas, which is of exceptional value to evolutionary science.

Indonesia renegotiating Fujian LNG price

Indonesia is renegotiating the price of LNG under a contract it signed with China’s Fujian LNG Project in 2002, according to Minister for Energy and Mineral Resources Purnomo Yusgiantoro.

He said the rate for supplies of LNG from BP PLC’s Tangguh LNG project in Papua New Guinea, to Fujian, mainland China, needed to be renegotiated since oil prices have risen sharply since the contract was agreed.

Under the 2002 contract, Yusgiantoro said, the LNG price was set at $2.60/MMbtu if world oil prices exceeded $25/bbl. “The price [of oil] has risen far above that, so we’re renegotiating it,” he said.

The Fujian contract covers LNG supply of 2.6 million tonnes/year over a 25-year period beginning with the first shipment at yearend 2008.

The Tangguh LNG plant has secured long-term LNG sales with three other groups in addition to the Fujian LNG project: K-Power Co. Ltd. and POSCO, both of South Korea, and Sempra Energy LNG Marketing Corp., Mexico.

Pipeline planned from Jordan Cove LNG plant

An equal partnership of Fort Chicago Energy Partners LP of Calgary, Northwest Pipeline Corp., and Pacific Gas & Electric Co. (PG&E) plans a 250-mile gas transmission pipeline from the Jordan Cove LNG receiving terminal and regasification plant being developed by Fort Chicago at Coos Bay, Ore.

The partnership said it will seek market commitments and regulatory approvals for the Pacific Connector line, which will extend to the Northwest Pipeline system near Roseburg, Ore., and the Tuscarora and PG&E gas pipeline systems near Malin, Ore. Northwest Pipeline is a subsidiary of the Williams Cos. Inc.

The group plans to apply by January 2007 for a permit from the Federal Energy Regulatory Commission.

The pipeline, scheduled for completion in 2010, would be able to deliver 1 bcfd of natural gas to the Pacific Northwest and beyond, including California and northern Nevada through existing systems.