OGJ Newsletter

Jan. 23, 2006
Indonesia’s State Minister for State-Owned Enterprises Sugiharto said discussions were slated for mid-January concerning operation of the oil and natural gas fields on the Cepu Block.

General Interest - Quick Takes

Cepu Block discussions continue

Indonesia’s State Minister for State-Owned Enterprises Sugiharto said discussions were slated for mid-January concerning operation of the oil and natural gas fields on the Cepu Block.

ExxonMobil Corp. and state-owned PT Pertamina each have agreed to a 45% stake in the block with the remaining 10% going to the administrations of district areas where the oil block is located.

But the two sides have failed to agree on who will operate the block. Pertamina wants an operatorship that will change hands every 5 years, with itself assuming the first 5-year term, while ExxonMobil prefers to keep to a memorandum of understanding signed in June 2005 making it sole operator of the block for 30 years (OGJ Online, Dec. 12, 2005).

To help break the impasse, Sigoharto said he would meet the coordinating minister for economic affairs along with a state negotiating team to discuss the issue.

Sigoharto said no progress had been made in solving the matter as there were no negotiations following the Christmas and New Year holidays.

Sugiharto said the project was a high-risk investment and therefore the two companies had to clearly state what they would do in the first 5 years of the block’s operation.

He said the two sides each had been told to submit programs on what they would do as operator of the block, but that only ExxonMobil had submitted such a document so far.

Meanwhile, Pertamina reportedly has rejected a plan by the government to establish a joint operating unit with ExxonMobil for the block, saying it would be impossible to have a joint operator.

Accord reached in Greater Sunrise impasse

The governments of Timor-Leste and Australia have signed an accord to share royalties on a 50-50 basis from Woodside Petroleum Group’s Greater Sunrise gas fields in the Timor Sea.

The field straddles the offshore border between Australian waters and the joint development zone, the Timor Gap, administered by both countries.

The accord also puts aside the pursuit of conflicting maritime boundary claims between the two nations for a period of 50 years as long as the field development goes ahead within 10 years of the treaty’s taking effect.

The deal replaces an agreement signed in March 2003 whereby Timor-Leste would receive only 18% of the Greater Sunrise royalties. This arrangement was ratified by the Australian parliament but never presented to the Timor-Leste parliament because it was regarded as unfair.

Timor-Leste Prime Minister Mari Alkatiri is now confident this new accord will be ratified by his country’s parliament. He said he still expects tough questioning from members who wanted gas from the Greater Sunrise project to be processed in Timor-Leste rather than Australia.

Woodside has said previously that piping the gas across the Timor Trench to Timor-Leste would not be economical. It would rather pipe the gas to Darwin for treatment-probably involving an expansion of the existing ConocoPhillips treatment plant at Wickham Point. ConocoPhillips and Osaka Gas Co. also are members of the Greater Sunrise consortium.

Woodside stopped work on the $3.7 billion project a year ago because of the sovereign risk involved. Although the new accord might help clear away some perceived problems, Woodside is now heavily committed to bringing on stream its Pluto and Browse basin projects off Western Australia.

Consequently, there is no guarantee of an immediate restart of the Greater Sunrise development, although there is speculation that Woodside might consider selling its interest as it did in Blacktip gas field in the Bonaparte Gulf late last year.

In that case, ConocoPhillips is considered a candidate to increase its stake and proceed with the project.

UK gas storage in subsea salt caverns urged

UK lawmakers should consider allowing natural gas to be stored in subsea salt caverns, said Sec. of State for Trade and Industry Alan Johnson.

His comments came Jan. 12 during parliamentary debate on supply security under the Energy Act of 2004.

UK storage laws do not address undersea storage facilities. Johnson cited strong storage potential in numerous geological formations.

“There is already commercial interest in creating these [gas storage] facilities, and they could significantly add to the UK’s gas supply capacity,” Johnson said.

The Department of Trade and Industry commissioned a report by the British Geological Survey that said the southern North Sea is suitable for gas storage in salt caverns. The survey also said a small area in the Irish Sea could provide storage in salt caverns.

Legislation is expected to be introduced when parliamentary time allows, Johnson said, adding that regulations also could be updated regarding onshore gas supply infrastructure.

Issues cited in Alberta’s oil sands growth

Alberta oil sands developments are accelerating in response to high crude oil prices and raising issues for producers, points out Purvin & Gertz Inc. in a report entitled Global Markets for Canadian Oil Sands Crudes.

Announced projects with spending totaling $100 billion (Can.) could triple the supply of bitumen and synthetic crude oil within 10 years, said the report, released from the Calgary office of Purvin & Gertz.

One issue for producers is the need for diluent, which increases in step with bitumen production, Purvin & Gertz said. Upgrading in Alberta could reduce diluent demand, but upgrading requires major capital investment and does not eliminate risks associated with marketing synthetic crude.

And limits on the abilities of traditional refineries to absorb growing volumes of synthetic crude has increased interest in access to new markets, including refining centers on the US Gulf Coast and in California and Northeast Asia.

Price volatility is likely to continue due to the unique characteristics of oil sands crudes and imbalances between residue supply and demand, the report said.

Industry Scoreboard

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Exploration & Development - Quick Takes

Gulfsands secures rigs for drilling in Syria

Gulfsands Petroleum PLC, Houston, has signed letters of intent with MB Drilling Overseas Ltd., Damascus, Syria, for two land-based drilling rigs: the MB Rig 21, which is capable of drilling shallow Cretaceous wells; and MB Rig 3, designed for deeper Paleozoic zone drilling.

Gulfsands and equal partner Emerald Energy PLC, UK, have selected the first two prospects to be drilled on Block 26 in northeast Syria.

The agreements require MB 21 to drill one well with an option for a second well, while the MB 3, which will be shared with another company operating in Syria, is expected to be contracted for 1 year with an option to extend for two additional 1-year periods to enable the drilling of a series of Paleozoic wells during 2006-07. Gulfsands expects to sign definitive rig contracts shortly, and negotiations are under way.

Souedieh North, in the northeast section of the 11,000 sq km block, will be the first prospect to be drilled. The well will be drilled to a TD of 7,216 ft to test Cretaceous reservoirs similar to those producing in the adjacent Souedieh and Karachok oil fields. This prospect has estimated recoverable reserves in excess of 100 million bbl of oil. Gulfsands plans to spud the well May 1.

The second prospect, Tigris, is also in the northeast portion of the block. This well will be drilled to 14,760 ft TD, targeting a series of Carboniferous and Devonian sandstone reservoirs. The Tigris structure is directly underlying Souedieh oil field, the largest known oil field in Syria, where medium gravity oil is produced from mid-Cretaceous sands.

Wireline log evaluation of an existing well drilled some years ago on the structure has identified pay zones in the objective reservoirs. The Tigris-1 well will appraise the potential hydrocarbon accumulation of these reservoirs. The prospect has estimated recoverable reserves of more than 500 million boe. The well is expected to spud by late August.

Gulfsands is further evaluating the existing well and 3D seismic data to more accurately assess the reserves potential of the structure. It said the prospects for significant reserves additions are very good.

It plans to drill 4 wells on Block 26 by August 2007.

PTTEP makes another find in Oman with Shams well

Thailand’s PTT Exploration & Production PLC (PTTEP) has discovered oil, condensate, and natural gas with an appraisal well drilled in the northern part of the onshore Block 44 in Oman.

Two reservoir formations, with a total thickness of 96 m, were discovered with the Shams-4 well, which was drilled to 3,750 m TD.

In the first reservoir formation, testing indicated natural gas with a flow rate of 29 MMcfd and condensate at 1,770 b/d. Testing at the second reservoir formation yielded 6.7 MMcfd of gas and 7,880 b/d of crude.

PTTEP plans to put Shams-4 on production by yearend, PTTEP said. Shams-4 is about 4 km from the Shams-1 gas field, which is due to start producing 50 MMcfd of gas and 4,000 b/d of condensate in July.

Production will be sold to Oman’s Ministry of Oil and Gas (OGJ Online, Apr. 26, 2005).

Max buys Kazakhstan exploration contract

Max Petroleum PLC has acquired the Astrakhansky exploration contract in western Kazakhstan, subject to registration.

A London company focused on Kazakhstan, Max acquired rights to the contract by acquiring Kazgas Ltd. for $43.5 million. Upon registration, the contract will be for a 4-year duration with a 2-year extension option, Max said.

Max plans to shoot seismic surveys and drill one or more exploratory wells in 2007. The contract area covers 1,273 sq km in the Pre-Caspian basin in the Atyrau oblast on the Kazakhstan-Russian border. The southern contract area is in the Voga River delta.The contract area is southeast of Astrakhan gas-condensate field, which OAO Gazprom discovered in 1976. Max said Gazprom reported Astrakhan had original gas reserves of 85 tcf and 3.4 billion bbl of condensate. Gazprom produced 11 bcm of gas from Astrakhan in 2003 (OGJ, Feb. 28, 2005, p. 53).

Initially, Max will target three exploration prospects: Imashevsky South, Imashevsky Southwest, and Imashevsky East. Max expects to find hydrocarbon traps in subsalt Carboniferous carbonates.

A well drilled in 1986 on Imashevsky South had hydrocarbon shows. However, the well was not drilled to an optimum depth for its primary target due to technical limitations. Imashevsky East has seismic coverage indicating a structure below salt. Max said it might reenter and deepen the Imashevsky South well.

Drilling & Production - Quick Takes

Plant to supply nitrogen for Tabasco EOR

Air Products & Chemicals Inc. reported that a new joint venture between its Grupo Infra partner and Tecnologia en Nitrogeno signed a 10-year contract with Pemex Exploration & Production for 90 MMscfd of nitrogen for an enhanced oil recovery (EOR) project in Mexico.

The nitrogen will be injected into Pemex’s Jujo-Tecominoacan oil fields near Villahermosa, Tabasco.

A new air separation plant to supply the nitrogen is scheduled on stream in November 2007. Air Products will provide the engineering and imported equipment, while CryoInfra SA will supply the local equipment and construction and will operate the plant.

Glencoe injecting CO2 in central Alberta

Carbon dioxide injection for enhanced oil recovery has started in central Alberta.

Glencoe Resources Ltd., private Calgary independent, is using the gas to improve recovery of primarily light oil from multiple formations in several depleted oil fields about 100 miles north-northeast of Calgary.

The company hopes to boost the recovery factor to as high as 40% from 10-20%. All of the formations are deeper than 1,300 m.

Glencoe has long-term agreements to purchase CO2 from two industrial plants. It operates about 50 miles of CO2 pipelines and has begun injecting gas from the MEGlobal Canada Inc. plant at Prentiss. A second CO2 separation facility being built near the NOVA Chemicals Corp. petrochemical plant is to go into service in early 2006.

Injection is expected to total 600 tonnes/day of formerly vented CO2 once both plants are operating, said Doug Geeraert, senior vice-president, production for Glencoe.

Penn West Energy Trust, Calgary, began injecting CO2 in the first quarter of 2005 at the Pembina Cardium Unit, Canada’s largest conventional light oil pool producing since the 1950s with 7.8 billion bbl of original oil in place (OGJ, Apr. 12, 2004, p. 45).

Alberta has several pilot projects to which CO2 is trucked, and EnCana Corp. operates the Weyburn Midale CO2 project in southeastern Saskatchewan.

Petrobras buys stake in Equatorial Guinea’s Block L

Brazil’s state-owned Petroleo Brasileiro SA (Petrobras) reported that the government of Equatorial Guinea recently approved Petrobras’s acquisition of a 50% participating interest in a production-sharing contract covering Block L, in the deepwater portion of the Rio (River) Muni basin.

The block covers 4,250 sq km, in 500 to 2,200 m of water. The participating interest in the PSC has been acquired from the current participants in Block L: Chevron Equatorial Guinea Ltd. 22.5%, Amerada Hess Equatorial Guinea Resources Inc. 12.5%, Energy Africa Equatorial Guinea Ltd. 10%, and Sasol Petroleum International (Pty.) Ltd. 5%. Chevron will remain operator of the block with Petrobras having the option of becoming the operator in the event of a commercial discovery.

Block L is near the prolific Block G, operated by Amerada Hess, in which 8 oil fields have been discovered, including Ceiba field, already in production. Drilling of the first exploratory well on Block L is planned for later this year. If successful, first oil may occur by the beginning of next decade.

With this acquisition, Petrobras increases its presence in Africa. The company currently holds interests in Angola, Nigeria, Tanzania, and Libya.

Statoil shuts in Aasgard production again

Statoil ASA has shut in production of 45,000 b/d of condensate and 27.5 million cu m/day of gas from the Aasgard B platform in the Norwegian Sea after sparks and smoke were detected Jan. 15 in an exhaust system in the turbine of one of the export ducts. An investigation is under way.

The Aasgard B shutdown comes just 3 months after a previous shut in of more than 80,000 b/d of condensate and 35 million cu m/day of gas due to a fire in the exhaust section in one of the main generators (OGJ Online, Oct. 25, 2005).

The current shutdown has halted condensate and gas exports from the Statoil-operated platform and Mikkel fields. Mikkel produces about 11,000 b/d of condensate and 4.5 million cu m/day of gas.

Production also has been stopped on Statoil’s Kristin field, which produces 11 million cu m/day of gas and about 62,000 b/d of condensate.

Gas from Statoil’s Heidrun field, which is producing about 1.5 million cu m/day, again will be reinjected while the platform remains shut down.

It is not yet clear when production can resume from Aasgard B.

Chevron lets Blind Faith topsides contract

Chevron Corp. has let a contract to Mustang Engineering, a subsidiary of John Wood Group PLC, for detailed design of the topsides of the semisubmersible production facility for Blind Faith oil and gas field in the Gulf of Mexico (OGJ Online, Oct. 10, 2005).

The field lies in 7,000 ft of water 160 miles southeast of New Orleans on Mississippi Canyon Blocks 695 and 696. The value of the contract was not disclosed.

The production semi, to be located on Mississippi Canyon Block 650, will have an initial capacity of 45,000 b/d of oil and 45 MMscfd of gas. The topsides will be expandable to accommodate production increases.

Production is scheduled to begin during the first half of 2008.

PGS secures tanker for FPSO conversion

PGS Production, a subsidiary of Petroleum Geo-Services ASA, has agreed to buy the shuttle tanker MT Rita Knutsen from Knutsen OAS Shipping for $35 million.

PGS plans to convert the ship to a floating production, storage, and offloading unit for possible use in several imminent projects.

The vessel conversion is scheduled to begin when a firm contract is secured. Rita Knutsen is a double-hull, 124,472 dwt vessel built by Daewoo Shipyard in Korea in 1986.

Australia’s Basker oil field lower interval to flow

Anzon Australia Ltd. is working toward starting production from the lower interval of Basker-2 well in Basker oil field in the Gippsland basin, 75 km off Victoria (see map, OGJ, Oct. 24, 2005, p. 50).

The Basker-2 well started production at an initial 9,500 b/d of oil from the upper of two intervals (OGJ Online, Nov. 28, 2005). Since early December, the well has averaged 8,000 b/d of oil from the upper interval.

Upon completion of an extended production test of Basker-2, the lower interval is expected on stream. A commingled flow from the two intervals is expected in February.

The well, in 155 m of water in Bass Strait, is a subsea completion linked by a 1.9 km flowline to the Crystal Ocean floating production, storage, and offloading vessel, the first FPSO in the Gippsland basin.

Basker-Manta Joint Venture developed the field. Anzon is the operator with a 50% interest, and Beach Petroleum Ltd. has a 50% interest. Beach Petroleum has steadily increased its stake, the Sydney company said.

Processing - Quick Takes

Vietnam gains clearance for Nhon Hoi refinery

The Hong Kong General Chamber of Commerce has signed an agreement with Vietnam’s Binh Dinh province for the construction of a $450 million refinery in the Nhon Hoi economic zone.

The project is expected to be completed in 2010, with a refining capacity of 2 million tonnes/year of oil, increasing to 8-10 million tonnes/year during 2016-20.

Vietnam, Southeast Asia’s third-largest oil producer, earned $7.38 billion from exporting its crude in 2005, up by 30.3% over 2004. But a lack of refineries meant the country had to continue importing all refined products.

To increase its refining capacity, state oil firm PetroVietnam plans to build two new refineries in Dung Quat and Nghi Son.

Last August, Petrovietnam reported that major work contracts were in place for construction of the 140,000 b/d refinery-the country’s first-at Dung Quat in the central province of Quang Ngai (OGJ Online, Aug. 25, 2005).

Statoil, Kvaerner plan Norwegian refinery upgrade

Statoil ASA has signed a letter of intent with Aker Kvaerner ASA for basic and detailed engineering plus procurement and construction management assistance services for an upgrade project at the group’s 200,000 b/cd Mongstad refinery, north of Bergen, Norway.

The engineering contract is valued at €8.7 million, an amount set to increase with the addition of the procurement and construction supervision work.

The contract will be finalized this month, and the project will start Feb. 1.

Statoil has yet to make the final decision whether to execute the full project this year, pending approval from the Norwegian authorities. If approval is granted, the engineering portion of the project is slated for completion by April 2007, and the refinery upgrade is scheduled for completion in late 2008.

The project also includes a new combined heat and power plant and a new gas pipeline from the Kollsnes to Mongstad. The Energy Integration project will substantially improve the energy efficiency of the Mongstad complex, Statoil said.

Transportation - Quick Takes

Shell seeks buyers for Hazira terminal LNG

Royal Dutch Shell PLC’s LNG terminal at Hazira has lost its sole customer, Gujarat State Petroleum Corp. (GSPC), but the company says the facility remains “fully operational.”

Shell India Chairman Vikram Singh Mehta said, “Shell has fulfilled the terms of its contract with GSPC, and the contract has been completed. We are in discussion with a number of potential customers for short, medium, and long-term supplies of gas.”

Mehta confirmed that the terminal had received its last consignment of LNG in October 2005 and that the port’s tugs had been “temporarily redeployed.” He said the LNG terminal “can receive an LNG consignment as and when required.”

Asked why Shell had been unable to find other customers since opening the terminal 9 months ago, Mehta cited the “slow decision-making process” of Indian consumers.

“LNG continues to sell at a discount to liquid fuels that are still being used by certain consumers,” he said.

While Shell’s gas price exceeds the historic domestic gas price, Mehta said, “We think this is a temporary phenomenon and Indian consumers will soon be willing to pay international rates.”

LNG prices exceeded $12/MMbtu last year, while government-controlled prices of domestic gas in India were $3.30-4.85/MMbtu.

Mehta said low administered prices have created a shortage of Indian gas. “We are trying to convince our prospective customers that natural gas is not only cheaper than liquid fuels, but that it is abundant and is environmentally friendly,” he said.

Hindustan Petroleum Corp. has conducted due diligence for the acquisition of an equity stake in Shell’s Hazira venture. Mehta asserted that Shell would remain operator and had no intention to sell the terminal.

China taps GE to expand West-East gas line

China has let a $196 million contract to GE Oil & Gas for equipment needed to expand capacity of the 4,000 km West-East gas pipeline between Xinjiang and Shanghai.

The expansion will raise the pipeline’s capacity to 17 billion cu m/year from 12 billion cu m/year.

GE will provide 20 gas turbines, 24 compressors, and installation services for 12 new compression stations.

The gas turbines and compressors for eight of the compression stations will be shipped and installed in 2006. Equipment for the final four stations will be shipped by the end of 2008 and installed in early 2009. The new stations will be put into operation between August 2006 and September 2009.

In addition to the equipment, GE’s contract includes installation, start-up, and training services and scheduled maintenance for 12 years.

Peru LNG signs deal to export LNG to Mexico, US

Peru LNG Co., a consortium of Hunt Oil Co., South Korea’s SK Corp., and Repsol YPF SA, has signed an agreement with the Peruvian government to export LNG from Peru to Mexico and the western US.

The group will provide Peruvian natural gas to the region for 1812 years.

The companies plan to build and operate an LNG plant and export terminal at Pampa Melchorita, about 168 km south of Lima (see map, OGJ, June 13, 2005, Newsletter). Work will begin during the first half for completion in 2009.

The venture also will lay a 400-km, 32-in. pipeline to transport feed gas from the Chiquintirca community in the Ayacucho Mountains to the LNG plant.

Hunt Oil has a 50% stake in the venture, SK holds 30%, and Repsol YPF holds 20%.

First oil moves from Indonesia’s Tiaka field

Indonesian oil and gas company PT Medco Energi Internasional has shipped the first consignment of crude oil from Tiaka field off central Sulawesi, Indonesia (OGJ, Jan. 5, 2004, p. 37).

Indonesia’s upstream oil and gas regulatory agency, BP Migas, said Medco sent a tanker loaded with 75,000 bbl of crude to PT Pertamina’s refinery at Plaju, South Sumatra.

Pertamina operates Tiaka field, which lies in 175 ft of water on the Senoro Toili Block off Toili in Tolo Bay, in cooperation with Medco E&P Tomori.

The field produces 1,850 b/d of oil from two wells, but Medco aims to raise production to 4,000 b/d of oil by yearend and eventually to 5,000 b/d.

BP Migas said Medco plans to drill three more production wells this year.