Citgo indicted for environmental violations
A federal grand jury in Corpus Christi, Tex., returned a 10-count criminal indictment on Aug. 9 against Citgo Petroleum Corp., its Citgo Refining & Chemicals Co. subsidiary, and the environmental manager at its 156,750 b/cd refinery in Corpus Christi.
The indictment said Citgo violated the Clean Air Act (CAA) and the Migratory Bird Treaty Act (MBTA). Citgo denied all charges, saying it is confident that no criminal conduct will be found once the evidence is heard.
Citgo was indicted on two counts of operating the refinery in violation of the National Emission Standard for Benzene Waste Operations and two counts of operating open-top tanks as oil-water separators without the legally required emission controls.
CAA regulations require Citgo to control the emission of benzene from wastewater produced at the refinery.
The indictment charged refinery environmental manager Philip Vrazel with failing to inform the Texas Commission on Environmental Quality for the year 2000 about all points in the refinery wastewater system where benzene was generated.
Citgo was indicted for operating its refinery in 2000 with more than 57 Mg of benzene in waste streams that were exposed to the air. A megagram is equal to 1 tonne.
Federal regulations limit refineries to operating with no more than 6 Mg of benzene in their exposed waste streams.
In addition, Citgo was charged for operating in 2001 with more than 7 Mg of benzene in its exposed waste streams.
During an unannounced inspection in March 2002, state inspectors found 4.5 million gal of oil in the two open-top tanks, the indictment said.
Citgo Refining and Vrazel also face five counts of violating the MBTA for the illegal taking of protected birds. The birds were found coated with oil after landing in open tanks that are legally required to be fitted with nets or other equipment to keep out birds.
If convicted, Citgo faces fines of up to $500,000 or twice the gross economic gain (whichever is greater), and 5 years of probation. If convicted, Vrazel faces fines of up to $500,000 and up to 5 years in prison.
IEA: Production closures linger in Nigeria
While the loss of 200,000 b/d of crude oil supply from Prudhoe Bay field in Alaska captures attention and roils markets, a larger disruption continues in Nigeria.
There, notes the International Energy Agency, sabotage and accidents in traditional producing areas of the Niger Delta are offsetting production gains from deepwater fields.
In its August Oil Market Report, IEA says “shuttered” Nigerian production peaked at 785,000 b/d in July before receding to 750,000 b/d by the beginning of August. The country’s average production in July was 2.26 million b/d, IEA says. Output was 2.5 million b/d as recently as late 2005.
Disruptions in July, according to IEA, include:
- Continuing shut-ins along Royal Dutch Shell PLC’s Bonny and Forcados systems of 360,000 b/d because of attacks on surface facilities by militant groups.
- Shut-in of Shell’s offshore EA platform near the Forcados terminal of 115,000 b/d (OGJ, Feb. 27, 2006, p. 28).
- A July 21 accidental pipeline rupture that forced a 180,000 b/d cut in production of Bonny crude.
- Associated product cuts by Chevron Corp. of 25,000 b/d.
- Production closures since 2003 by Chevron of 70,000 b/d.
- An attack on the Ogbainbiri pumping station operated by a subsidiary of Eni SPA, which shut in 35,000 b/d of production in late July. Flow resumed early in August.
Before its July pipeline accident, Shell said it didn’t expect to restart much of its 475,000 b/d of lost output until early next year or possibly not before presidential elections in April 2007, IEA reported. Deepwater production so far hasn’t been hurt by the attacks plaguing onshore output. New deepwater projects are coming on stream in a trend that IEA says “may well continue, with rising deepwater supply providing an offset to sporadic attacks on facilities nearer the coast and onshore.”
But it adds: “Such a scenario likely undermines plans for production capacity to reach 2.9-3 million b/d by 2007.”
ONGC seeks oil interests in Venezuela
ONGC Videsh Ltd. (OVL), the overseas investment subsidiary of India’s state-owned Oil & Natural Gas Corp. (ONGC), is approaching Latin American countries such as Venezuela for oil and gas opportunities.
A partnership between ONGC and state-owned Petroleos de Venezuela SA is expected shortly.
ONGC and PDVSA recently held an in-depth meeting in New Delhi to discuss mutual energy cooperation; indications are that OVL may seek exploration opportunities in Venezuela jointly with other international oil and gas companies.
PDVSA’s high-level delegation, led by company Vice-Pres. Luis Vierma Perez, discussed business opportunities OVL is pursuing in Venezuela.
Venezuelan delegates proposed that ONGC buy Venezuelan crude on a long-term basis.
Both sides agreed to establish a group to study energy collaboration.
ONGC is one of the few multinational companies invited by the Venezuelan government to participate in a reserves assessment in the Orinoco heavy oil belt (OGJ, Nov. 21, 2005, p. 54).
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Exploration & Development - Quick TakesApache’s Gnu-1 tests lead to development plans
Test results for Apache Corp.’s Gnu-1 exploration well off Australia’s North West Shelf has led to evaluation of natural gas and condensate development options, including the possibility of constructing a 56-mile pipeline to the mainland. The well is in Reindeer-Caribou field on the WA 209P permit in the northeast section of Apache’s Carnarvon basin acreage.
The Gnu-1 well, which lies in 200 ft of water, was drilled into the Early Jurassic North Rankin formation and produced on test 26 MMcfd of gas and 61 b/d of condensate through a 11⁄4-in. choke with 954 psi of flowing wellhead pressure. Perforations were at 11,259-87 ft MD.
Gnu-1 logged 378 ft of net pay in the Jurassic Legendre formation, the main reservoir. This is 78 ft of new pay (more than previously recorded in the field). The Legendre pay zones, about 3,500 ft uphole from the North Rankin reservoir, will not be tested, as an earlier Legendre well tested 35 MMcfd of gas and 165 b/d of condensate. When developed for production, the Legendre sands are expected to deliver more than 100 MMcfd of gas.
Apache said it plans to develop this field with an objective of starting production in 2008. The company has five additional seismically defined prospects in the immediate vicinity of the field, the first of which it plans to spud later this year.
A portion of the gas is dedicated to existing contracts, and sufficient markets exist for the balance, Apache said.
Apache operates the well and holds a 55% working interest; Santos Ltd. has 45%.
Tierra del Fuego yields another discovery
Antrim Energy Inc., Calgary, expects further drilling around the Los Patos 1005 new-field discovery in Tierra del Fuego, Argentina.
During production testing, the well flowed 345 b/d of 43° gravity crude with 2% water from perforations in 6 ft of net pay in an 8-m interval of the Cretaceous Springhill formation. The well, drilled to 2,318 m TD, now is flowing naturally at 300 b/d through a 20-mm choke.
Antrim holds a 25.78% interest in a group that holds three licenses in Tierra del Fuego. Operator Roch SA holds 24.29%, Apco Argentina Inc. 25.78%, San Enrique 12.62%, and DPG 11.54%.
The group recently announced an earlier discovery in the Las Violatas 105 well (OGJ Online, June 6, 2006).
Shell delivers gas from E8 field off Malaysia
Shell Malaysia said it delivered natural gas from E8 field off Sarawak, Malaysia. Production started July 24 and is stabilizing toward a target flow of 600 MMscfd. Sarawak Shell Bhd. operates E8, a key component of the E11 Hub Integrated Gas project operated by Shell Malaysia. Production from surrounding fields goes to the E11 complex for processing before being delivered onshore via pipeline to the Petronas LNG complex at Bintulu.
One of five fields developed to ensure supply to the LNG complex, E8 made the E11 complex the biggest gas production facility in terms of volume in Sarawak waters. The other four fields are E11, F23, F6, and F13. The other E11 satellite gas field developments, F13 West and F13 East, are expected to come on stream within 3 years. Shell Malaysia and Petronas each have a 50% interest in the E11 Hub Integrated Gas Project.
Drilling & Production - Quick TakesEast Azeri deck installed in Caspian Sea
The East Azeri platform deck in the Azeri-Chirag-Gunashli (ACG) field in the Azerbaijani sector of the Caspian Sea was lowered into position July 28, reported Statoil ASA, which holds an 8.56% interest in the BP PLC-operated field.
The 16,000-tonne topsides took 2 days to transport to the field from the construction site near Baku. The platform’s jacket was positioned in 150 m of water during March.
Following the positioning of the deck, all that remains to production, expected towards yearend, is offshore hookups and commissioning of facilities, Statoil’s ACG project manager said.
ACG field will initially produce 260,000 b/d of oil and will produce more than 1 million b/d of oil on reaching peak production in 2009, the company said.
The oil will be sent to the Sangachal terminal in Azerbaijan for processing and export primarily through the recently completed Baku-Tbilisi-Ceyhan pipeline to the Mediterranean.
Thailand, Cambodia still torn over gulf claims
Thailand and Cambodia have failed to resolve their disagreement about terms of production sharing from their overlapping territorial claims in the Gulf of Thailand.
The issue was high on the agenda of an Aug. 10 meeting in Phnom Penh between Thai Prime Minister Thaksin Shinawatra and his Cambodian counterpart, Hun Sen.
The matter has stalled both countries from developing energy resources from the 30,000 sq km area in the gulf’s upper half, which is believed to be gas-prone.
In 2001, both countries agreed to adopt the Joint Development Area (JDA), a scheme embraced earlier by Thailand and Malaysia, for developing oil and gas in the disputed zone without resolving the exact maritime boundaries.
The original model negotiated by the two sides called for a 50-50 split of resources arising from the middle portion of the JDA, with differing sharing ratios on areas flanking the area, depending on the proximity to their territorial claims.
Phnom Penh authorities are pressing for a 60-40 sharing ratio, according to Thai officials. In the southernmost part of the Gulf of Thailand, production from the Thailand-Malaysia JDA is split equally. Bangkok has been eager to tap gas from the Cambodia-Thailand JDA to meet its fast-growing fuel demand, particularly for electric power generation.
ConocoPhillips starts up Alpine satellite field
ConocoPhillips has started bringing wells on stream in the first Alpine satellite oil field, Fiord, which lies 5 miles north of Alpine on Alaska’s North Slope.
Fiord is expected to have peak production of 22,500 b/d gross in 2008. Near-term production was up to 15,000 b/d while wells were still being brought on stream. The development plan envisions 17 wells. Using horizontal well technology and enhanced oil recovery, Fiord is supported by aircraft and accessible by an ice road in the winter. It has no permanent road.
A second Alpine satellite field, Nanuq, is slated for startup later this year. Production from Fiord and Nanuq will be processed through Alpine facilities. Together, the two satellite fields cost $650 million and are expected to reach peak production of 35,000 b/d in 2008.
ConocoPhillips Alaska Inc. has a 78% interest in Alpine, Nanuq, and Fiord fields, and Anadarko Petroleum Corp. has 22% interest.
Total starts gas production off the Netherlands
Total SA’s Dutch unit Total E&P Nederland has brought on stream L4G natural gas field off the Netherlands in the Dutch section of the North Sea, reported field partner Lundin Netherlands BV, the Dutch unit of Swedish oil firm Lundin Petroleum AB.
The single L4G subsea development well has a production potential of about 1 million cu m/day of gas, Lundin said.
A new deck extension has been built on the L4A receiving platform to accommodate L4G gas flow. From there, gas production will be exported to the Uithuizen terminal in Groningen province via existing facilities.
The field’s entire gas output has already been sold to Gasunie Trade & Supply BV, a gas-trading venture of the Dutch state, Royal Dutch Shell PLC, and ExxonMobil Corp.
The L4G project is combined with the installation of a pipeline between the K6GT and the K6C platforms. This reengineering of the gas flows from the K6-L7 area permits an optimization of the gas production. Total E&P Nederland, operator, holds a 55.66% interest in the field. Its partners are Energie Beheer Nederland BV 40% and Lundin 4.34%.
Myanmar steps up Yetagun gas field production
Myanmar has agreed to step up natural gas production from Yetagun field to increase supplies to neighboring Thailand, according to an official from the Ministry of Energy. He said a verbal agreement had been reached between Myanmar and PTT Exploration & Production (PTTEP), a unit of Thailand’s PTT PLC. Gas from Myanmar currently makes up about 20% of Thailand’s supply.
“Although the partners have agreed to increase production, it takes time to reach a final agreement,” the ministry official said.
Thailand reportedly wants to buy 100 MMcfd of gas in addition to the 400 MMcfd of gas it pipes from the offshore reserves in the Andaman Sea.
That gas comes mainly from Yetagun field, which is operated by Malaysia’s Petronas, Japan’s Nippon Oil, and PTTEP, and Yadana field operated by France’s Total SA, Unocal Corp., and PTTEP.
Allegheny South oil field starts production
Italy’s Eni SPA started oil production from Allegheny South field on Green Canyon Block 298 in the deepwater Gulf of Mexico. The field lies 260 km south of New Orleans.
Oil flowed at 3,000 b/d through Eni’s existing Allegheny platform. Allegheny South came on stream 18 months after discovery (OGJ, Feb. 28, 2005, Newsletter). Eni wholly operates the Allegheny platform, which has been in production since 1999. The facility also handles production from King Kong field. Eni’s current net production in the Gulf of Mexico is 44,000 boe/d.
Goosander oil field starts flow off UK
Production has begun from Goosander oil field on Block 21/12 in the Greater Kittiwake Area of the UK North Sea (OGJ, Aug. 7, 2006, p. 37).
Dana Petroleum PLC said it and 50-50 partner Venture Production PLC, the operator, expect the subsea waterflood development to reach a peak annual average production rate of 9,500 b/d.
The partners reentered and completed the Goosander discovery well, 21/12-3, for tieback to the Kittiwake platform. They plan to drill a water-injection well next year.
The field is expected to produce 15.2 million bbl of oil and 2.6 bcf of natural gas over 7-10 years.
The Venture-Dana combine produces oil from three other fields in the Greater Kittiwake area: Kittiwake, Mallard, and Gadwall.
Processing - Quick TakesTotal starts up hydrocracker at Normandy refinery
Total SA has begun start-up of a hydrogen production unit at its 342,000 b/d refinery in Normandy. The steam methane reformer start-up is part of the company’s strategy to increase diesel production over 3 years by 3 million tonnes/year (OGJ Online, Sept. 12, 2005).
The €550 million distillate hydrocracker project was completed in 26 months. The next steps consist of bringing the sulfur recovery units on stream this month then commissioning the hydrocracker, which will be gradually ramped up to reach full product availability by Sept. 30.
The units will produce 1.3 million tonnes/year of sulfur-free automotive diesel, 200,000 tonnes/year of sulfur-free kerosine, 500,000 tonnes/year of high quality bases for lubricants and specialty fluids, and 400,000 tonnes/year of naphtha feedstock for petrochemicals.
India OKs Gujarat aromatics, olefins complex
India has approved a $1.05 billion aromatics and olefins complex that Oil & Natural Gas Corp. plans to build next to its subsidiary Mangalore Refinery & Petrochemicals Ltd. and its Dahej petrochemical complex in Gujarat, India.
At the same time, the government is discouraging ONGC, the country’s largest oil and gas producer, from foraying into fuel retailing.
“Worldwide, refineries are being converted into refinery-cum-petrochemical complexes to gain from the high margins on petrochemicals,” said Petroleum Sec. M.S. Srinivasan. “Naturally, ONGC would also be encouraged to set up petrochemical complexes wherever they have refineries or have a natural gas source,” he said.
Indian Oil to propose Nigerian refinery
Indian Oil Corp. (IOC) hopes to build a 6 million tonne/year refinery in Nigeria’s Edo state.
IOC Chairman and Managing Director Sarthak Behuria will visit Nigeria Aug. 21 to discuss the $2 billion proposal with Nigerian President Olusegun Obasanjo.
IOC hopes to secure a 12-15 year crude supply contract in conjunction with the refinery proposal and will negotiate for equity stakes in Nigerian production. It now imports 2 million tonnes/year of crude from Nigeria National Petroleum Corp. under a term contract and hopes to double or triple the rate.
Transportation - Quick TakesBomb blast shuts Pakistani gas pipeline
An 18-in. gas transmission pipeline burst 12 km from Sui gas field in Pakistan’s troubled Balochistan Province Aug. 8 in an apparent bombing (see map, Dec. 5, 2005, p. 22).
The line carries 110 MMcfd of gas from Sui Southern Gas Co. Ltd.’s franchise areas in Sindh and Balochistan provinces. The company stopped flow soon after the blast.
The Pakistan army was summoned to provide security during repair work, which was expected to take 2 days.
PNG-Australia gas pipeline on ice
Australian Gas Light Co. and Malaysia’s Petronas, partners in the proposed Papua New Guinea-Australia natural gas pipeline, have decided to scale back front-end engineering and design activities on the pipeline’s Australian leg even though most of the budgeted FEED activities have been completed.
AGL managing director Paul Anthony cited a dearth of critical foundation customers and escalating costs as the reasons for the decision to table the project.
Anthony added that the pipeline project is unlikely to proceed without an alternative ownership structure for the pipeline. Earlier this year he had emphasized that by saying AGL may bring in international partners with more pipeline experience to reduce the company’s 50% equity in the line.
AGL’s separate agreement to buy gas from the project remains subject to the upstream Papua New Guinea gas project’s reaching financial close.
Early this year AGL finalized acquisition of a 10% stake in the Papua New Guinea highland gas fields feeding the pipeline-a move that gave the company a stake in every aspect of the project, including wellhead, pipeline, and retail operations (OGJ Online, May 26, 2006).
Loan approved for S. Sumatra-W. Java gas line
Asian Development Bank has approved a $75 million loan to finance part of a 661-km natural gas pipeline in Indonesia that would extend from South Sumatra to West Java province. The loan is ADB’s second this month for Indonesia’s energy sector.
ADB made the loan to PT Perusahaan Gas Negara (PGN), and said it would support additional loans of as much as $125 million provided by other international financial institutions and commercial banks.
The $652.5 million project involves the construction of a pipeline to transport gas from major fields in South Sumatra to the major gas-consuming areas of West Java. The pipeline is one of two PGN is building to address a gas shortage in West Java.
The project is ADB’s second nonsovereign guaranteed operation in Indonesia’s oil and gas sector. The first one, a $350 million loan to help develop the Tangguh LNG project in Irian Jaya Barat province, was signed on Aug. 1.
Port of Bordeaux, 4Gas plan LNG terminal
The Port of Bordeaux in France and 4Gas of the Netherlands have agreed to jointly develop a €400 million LNG import terminal at the mouth of the La Gironde River at Le Verdon, France.
About 97% of the regional gas and gasoline consumed is accessed through the port, one of the largest in France.
4Gas will begin work immediately on environmental, safety, and engineering studies required for permit applications. The Port said it will renovate an existing jetty and work with 4Gas on all marine aspects.
Construction is expected to begin in 2008, and the terminal to start operations in 2011.
4Gas, dedicated exclusively to LNG, is a new company formed by shareholders of Petroplus International NV, Amsterdam, following its development of the Dragon LNG project under construction in Milford Haven, Wales. Dragon is scheduled to be operational in 2007. 4Gas also is developing the LionGas LNG terminal in Rotterdam, expected to come on line in 2010.
The Carlyle Group and Riverstone Holdings LLC are majority shareholders in RIVR, which owns the majority of the 4Gas shares.
