OGJ Newsletter

March 31, 2003
Nigeria, Venezuela figure into OPEC oil export outages

Market Movement

Nigeria, Venezuela figure into OPEC oil export outages

Although markets largely have focused on the US-led war on Iraq and its consequences on world oil supply (see related stories on pp. 20, 22), traders also contemplated the effect of export outages from two other key members of the Organization of Petroleum Exporting Countries—Nigeria and Venezuela.

Supply outages because of civil unrest in these countries have helped support oil prices. Meanwhile, the US Energy Information Administration said in its inventory report that US gasoline inventories declined by 2.1 million bbl to 199 million bbl, while crude stocks increased by 3.7 million bbl to 273.9 million bbl for the week ended Mar. 21.

"Current oil prices are not fully reflecting the tightness in inventories and gasoline problems, let alone the current geopolitical context," said Paul Horsnell, analyst for J.P. Morgan Securities Inc., London.

The contract for benchmark US light, sweet crudes has bounced up and down depending upon traders' changing perceptions of the war in Iraq.

On Mar. 20, the April contract dropped $1.27 to $28.61/bbl on the New York Mercantile Exchange, while the May position was down $1.24 to $28.12/bbl. On Mar. 26, the May contract gained 66¢ to finish at $28.63/bbl, while the June contract rose by 37¢ to $26.83/bbl.

Nigerian crisis

Nigeria's oil industry faces a crisis as political violence escalates in the Warri area and other parts of the Niger Delta region pending an upcoming election. A military-tribal clash reportedly caused 800,000 b/d of Nigeria's oil output to be shut down as of Mar. 26. Several sources reported Ijaw tribal fighters have taken over oil facilities in Bayelsa state.

"Major oil companies have begun airlifting villagers to safety," noted Tyler Dann, an analyst in Banc of America Securities LLC's Houston office.

ChevronTexaco Corp. declared force majeure on Mar. 20 and shut in all of its onshore and swamp production in the western Niger Delta, which accounts for 140,000 b/d of its 450,000 b/d gross Nigerian production.

Royal Dutch/Shell Group also declared force majeure, on Mar. 21, affecting its Bonny and Forcados export terminals. This came after Shell had shut in 126,000 b/d of its 800,000 b/d gross Nigerian production and evacuated personnel (OGJ Online, Mar. 20, 2003).

While Shell expects to make up that loss elsewhere in Nigeria, ChevronTexaco said production disruptions would impact its March and April deliveries. TotalFinaElf SA also has had to shut down some Nigerian facilities.

Horsnell quoted an Ijaw leader as saying tribal fighters were prepared "to take Nigeria 20 years backward" by seizing control of pipeline flow stations and threatening to destroy them.

"Nigeria seems to be doing a pretty good job at going many years backward already, but the Ijaw threat appears to be a serious one," Horsnell said.

On Mar. 26, Horsnell said the status of exports for second half 2003 "is open to question. That implies that market concerns about supposed OPEC overproduction are totally misplaced. Indeed, we may have exactly the reverse problem."

He said supply concerns would be valid even if Nigerian supplies could be guaranteed but that "they cannot beU. We are not confident that any ceasefire with the Ijaw will keep a lid on the problem."

Venezuela oil output

Venezuela was a key supplier of oil to the US before a general strike started in December against the government of President Hugo Chávez.

Government officials claim the country has restored its oil production to more than 3 million b/d, but former officials of gutted state oil company Petroleos de Venezuela SA claim current production actually is 2.4 million b/d.

Current PDVSA COO Luis Marin briefed Washington, DC-based PCF Energy last week in an effort to help convince US officials that Venezuelan crude production is 2.95 million b/d, including synthetic crude, and is expected to average 3 million b/d in April.

Acknowledging inconsistencies in data from government and former PDVSA officials, Marin insisted that production recovery has been much faster and more thorough than many believed possible.

Meanwhile, Venezuela's gasoline exports are to be restored at the end of March, Energy Minister Rafael Ramirez told reporters in Caracas Mar. 26.

His comment came 3 days after PSVSA reported an explosion in the Paraguana refining complex during an attempted restart of the Cardon refinery's 100,000 b/d delayed coker. Caracas-based Petroleumworld online news service reported PDVSA was trying to restart the Cardon refinery's coker and other units shut down during the strike.

Paraguana has been an important source of gasoline for the US. PDVSA told Reuters that the 100,000 b/d cracker at the complex's Amuay refinery was functioning again Mar. 12.

Industry Scoreboard

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Industry Trends

FUTURE SOUTH AMERICAN gas demand largely will be driven by increased gas use for electricity, reported the Paris-based International Energy Agency in a recent study.

In 1995-2000, gas-fired power generation grew by 8.4%/year in South America, compared with 4.5%/year growth for total power generation. The study also forecasts the possibility for additional substitution of gas for oil in the industrial sector.

However, a lack of market and pipeline infrastructure stands in the way of South America developing its abundant natural gas resources, the report emphasized.

Except for Argentina, few South American countries have both large gas reserves and large domestic markets to justify the costs to develop reserves and build a transportation network.

Although gas has high market penetration across all of Argentina's sectors, most South American countries use gas primarily to fuel industry and the energy production sector. But opportunities could develop for summer cooling, said IEA officials. On the other hand, the use of compressed natural gas as a transportation fuel is expanding rapidly.

Gas pipeline interconnections are most advanced in the Southern Cone, encompassing parts of Brazil, Argentina, Chile, Bolivia, Paraguay, and Uruguay where most South American population and industry is located and where energy demand is highest. Both Argentina and Bolivia have abundant nonassociated gas reserves that they want to export to neighboring countries.

In 2001, gas trade in the Southern Cone amounted to 9 billion cu m, 16% of the area's marketed gas production.

Pipeline connections among the Andean countries will be slower to materialize, the study said. While the large gas reserves in the north are too far away to pipe to the Southern Cone, the study found that LNG projects have a promising future.

ASIAN LPG DEMAND finally overtook North America last year in a trend that has been evident since 1990. Similarly, LPG demand in Latin America has overtaken demand in Western Europe.

S. Craig Whitley, a senior principal of Purvin & Gertz Inc., noted these events during the firm's 16th Annual US/International LPG Seminar in The Woodlands, Tex.

The other trend Whitley observed for the 12-year period—and on which the consultant has been reporting for some time—has been the nearly tripling of LPG demand in the Middle East.

LPG demand in Asia reached 55 million tonnes in 2002, compared with 30 million tonnes in the region for 1990 and 53 million tonnes in 2002 for North America. This trend will continue through 2005, said Whitley. He expects Asian demand to reach 65 million tonnes/year and North American demand to barely reach 60 million tonnes/year.

The trend has been driven almost entirely by China whose demand in 2002 was 14 million tonnes, up from 2 million tonnes in 1990. By 2005, Purvin & Gertz predicts Chinese LPG demand will reach 16-18 million tonnes/year and will make up about 40% of all Asian demand.

Historically, LPG demand in Japan has dominated the region, but by 2005 China's LPG demand will be roughly equal to Japan, Whitley forecast.

Government Developments

US Federal energy regulatory commission (FERC) WILL INITIATE a new homeland security system on Apr. 2 that will restrict certain natural gas pipeline and power grid infrastructure information from the general public.

The agency will have a "critical energy infrastructure coordinator" processing requests for information seen as especially sensitive. The coordinator will control access to data the agency deems "critical infrastructure information" that could be potentially useful to terrorists and is exempt from disclosure under the Freedom of Information Act.

FERC's final rule defines critical infrastructure as "existing and proposed systems and assets, whether physical or virtual, the incapacity or destruction of which would negatively affect security, economic security, public health or safety, or any combination of those matters." This includes both proposed and existing systems.

The agency anticipates that some public interest and media groups might ask a court to strike down the rule. The Reporters Committee for Freedom of the Press and the Society of Environmental Journalists argue that the restrictions as written are broad and arbitrary, and do little to improve homeland security. The committee also maintains that the information in question is of little use to a terrorist but could be very important to local communities located near a natural gas pipeline or transmission wire.

FERC disagrees with this argument, saying additional measures must be taken to protect the critical infrastructures that it regulates. The agency cited a statement by the US National Infrastructure Protection Center labeling energy infrastructures as key terrorist targets. (The Department of Transportation, under its Office of Pipeline Safety, oversees oil and gasoline pipelines and has placed its own homeland security-related restrictions on certain data it deems sensitive.)

The rule gives specific examples of protected and unprotected information.

In order to address public interest groups' concerns, FERC agreed to modify its information criteria so that data that identifies the location of a pipeline or transmission grid is not automatically deemed as sensitive information. FERC also plans to release location information that is generally needed to comply with environmental reviews.

"Critical" restricted gas information will include diagrams of valve and piping details at compressor stations, meter stations, LNG facilities, and pipeline interconnections.

Other critical information will be flow diagrams and other drawings or diagrams showing similar details such as volumes and operating pressures, environmental resource reports for LNG facilities, and drawing matching labels with specific buildings onsite, e.g., central gas control centers or gas control buildings.

A ROYALTY-IN-KIND pilot program will be developed under a memorandum of understanding signed Mar. 20 by Louisiana state officials and the US Department of the Interior's Minerals Management Service.

The understanding calls for implementation of the RIK pilot for oil and gas leases in the federal 8(g) zone—the first 3 miles of federal lands beyond the state's 3-mile limit. Louisiana also could include state oil and gas leases in the RIK pilot program.

Nationally, through the RIK program, MMS receives more than 160,000 b/d of crude oil and 400 MMcfd of natural gas in-kind.

Quick Takes

NORSK HYDRO ASA, development operator for Ormen Lange field in the Norwegian Sea, has selected Aker Kværner, Lysaker, Norway, to receive a contract valued at 950 million kroner for engineering and design of the project's onshore Nyhamna processing plant near Aukra, in Møre og Romsdal County, Norway.

The contract is for front-end engineering design, engineering, procurement, and construction management assistance. The work will enable the consortium to establish an investment-decision cost estimate before submitting a formal plan for development and operation (PDO).

The Nyhamna development, due for completion when Ormen Lange field comes on stream in 2007, includes the process plant, utility systems, slug catchers, a tank farm, and power supply and distribution. EPC contracts for these other installations will be awarded during 2003-05, Norsk Hydro said.

Developer Norsk Hydro holds a 17.956% interest in the field and Norske Shell 17.2%. Other shareholders are Petoro AS 36%, Statoil ASA 10.774%, Esso Norge AS 7.182%, and BP PLC 10.888%.

THE ORMEN LANGE project also will require one of the most extensive subsea gas export pipelines on the Norwegian continental shelf, a two-part pipeline with a combined length of 1,200 km from the onshore processing plant to the UK via Sleipner field.

The Ormen Lange licensees (see Gas Processing) chose the route Dec. 18 (OGJ Online, Dec. 23, 2002) for the export pipeline—from the processing plant at Aukra to the Sleipner installation in the North Sea, and from Sleipner to Easington-Dimlington, UK—and gave approval in February to proceed with pipeline construction.

Norsk Hydro plans in June to submit to Norwegian authorities a plan for the installation and operation (PIO) of the most southerly stretch of the pipeline system—between Sleipner and Easington-Dimlington in the southeastern UK.

A corresponding PIO for the northerly section, between Sleipner and the Nyhmna plant, is scheduled for delivery to authorities by October, together with the PDO for deepwater Ormen Lange field itself, which lies 140 km west of Kristiansund, Norway in 1,000 m of water.

Ormen Lange needs pipeline capacity of at least 60 million standard cu m/day. In addition, there is transport capacity demand in other parts of the system for gas from other fields.

"The total export pipeline system tied into Ormen Lange will be the most significant pipeline project ever in the Norwegian offshore sector," a consortium spokesperson said.

The total Ormen Lange investment, including field development and transportation pipelines, is estimated to be 55 billion kroner (2002). The field is the first deepwater development project on the Norwegian Continental Shelf.

"The investment demands large parts of the world's pipeline-laying capacity in 2005 and 2006," says Bengt Lie Hansen, Hydro's head of mid-Norway exploration and development. "Ormen Lange will increase Norwegian gas export(s) by 25%, making Norway the world's next largest gas exporter after Russia," he said.

First production from Ormen Lange is planned for October 2007, with gas production scheduled for 30-40 years. AS Norske Shell is the production phase operator. The field's production is expected to peak at 20 billion standard cu m/year of natural gas, about 20% of the total anticipated Norwegian gas production in 2010, Norsk Hydro said.

The estimated gas reserves on Ormen Lange are 375 billion standard cu m of dry gas and 22 million standard cu m of condensate, making it the largest undeveloped gas field on the shelf.

Kinder Morgan Energy Partners LP has placed into service its Mier-Monterrey natural gas pipeline that stretches from south Texas to Monterrey, Mexico—one of that country's fastest growing industrial areas. "Completing construction of this pipeline on budget and ahead of schedule is a tremendous accomplishment," KMP Chairman and CEO Richard D. Kinder said of the $87 million project that came on line Mar. 20. The 95 mile pipeline interconnects with the southern end of Kinder Morgan's Texas intrastate system in Starr County, Tex. Pemex Gas Y Petroquimica Basica (PGPB) has subscribed for the entire capacity of 375 MMcfd under a 15 year contract (OGJ, Nov. 25, 2002, p. 9). The pipeline will connect with the PGPB gas transportation system and with a 1,000 Mw power plant complex owned by Iberdrola SA and Comision Federal de Electricdad, the national electric power entity.

STATOIL ASA, on behalf of Kristin field licensees, has awarded a 100 million kroner contract to Aker Marine Contractors (AMC) for installation of the semisubmersible Kristin platform in the Norwegian Sea field.

The work, scheduled for completion in spring 2005, includes transport and preinstallation of the anchor system, tow, and platform installation in the southwestern area of the Haltenbanken on the Norwegian continental shelf.

In summer 2004, AMC will transport and pre-install the anchor system—16 suction pile anchors and associated chain and wire moorings—on the seabed in water 5,000 m deep, utilizing the Boa DeepC newbuild construction vessel owned by the Norwegian company Taubåtkompaniet.

This will be followed in spring 2005 by the platform tow from the Aker Stord yard near Bergen to Kristin field, where AMC will connect it to the preinstalled mooring spread.

Kristin is expected to begin producing 126,000 b/d of condensate and 18 million cu m/day of natural gas liquids Oct. 1, 2005. The field ultimately is expected to produce 35 billion cu m of gas until 2016 from 12 subsea wells, including 220 million bbl of condensate and 8.5 million tonnes of natural gas liquids (OGJ Online, Oct. 15, 2002).

Statoil holds a 46.6% interest in Kristin. Its partners are Petoro AS 18.9%, Norsk Hydro AS 12%, ExxonMobil Corp. 10.5%, Agip SPA 9%, and TotalFinaElf SA 3%.

Petroleos Mexicanos (Pemex) has awarded Schlumberger Oilfield Services and ICA Fluor Daniel a $500 million contract to recover natural gas and oil in Chicontepec field. This represents the largest integrated services contract ever awarded in Mexico, Schlumberger said. "For the first time, a service company will directly collaborate with Pemex on the field development plan under an integrated service concept," said Jose Magela Bernades, general manager, Mexico GeoMarket, Schlumberger Oilfield Services. ICA Fluor Daniel is the Mexico-based partnership of Fluor Corp. and Empresas ICA Sociedad Controladora. The consortium will handle field studies, drilling, well completion and intervention services, surface infrastructure, and production development in the field 250 km northeast of Mexico City in Veracruz and Puebla states. Chicontepec covers an area of 11,300 sq km in east central Mexico in the Tampico-Misantla basin. The productive area is a 3,300 sq km oval in the southeastern part of the basin (see map, OGJ, Aug. 30, 1982, p. 100). One of Mexico's largest proven reserves, Chicontepec has 17 billion bbl of OOIP, Pemex has said in the past, although it has since revised its overall national reserve estimates. The Austin chalk of Texas is perhaps the closest geologic analog to Chicontepec because both are relatively shallow. The new project will address production from turbidite deposits in paleochannels. The initial stage of large-scale development for Chicontepec will comprise a field study of several blocks, drilling 200 (vertical) wells, and completing 50 additional wells. The phase also includes optimization of production facilities around the reservoir, reduction of operations and maintenance costs, integration of production installations, construction of an undisclosed number of multiwell drilling pads that will accommodate 18 wells each, use of recycled gas for pneumatic pumps, and minimizing environmental impact. New field studies also will be conducted where Pemex wants to further develop Chicontepec field. The consortium will complete and fracture 250 wells and will establish a production regime and injection strategy.

GREYHAWK GAS STORAGE CO. LLC, Houston, a joint venture of Falcon Gas Storage Co. Inc. and Emera Inc., has called an open season to determine capacity demand at its Wyckoff gas storage project in Steuben County, NY.

Up to 6 MMbtu of working gas storage capacity will be available on a firm basis for terms of 2-10 years, beginning October 2004. The open season closes Apr. 14.

Receipt and delivery points will be via Tennessee Gas Pipeline Co.'s Line 400 (HC line), Dominion Transmission Inc.'s TL-453 line, and Columbia Gas Transmission Corp.'s A5 line.

PETROCHEMICAL INDUSTRIES DEVELOPMENT MANAGEMENT CO., a wholly owned subsidiary of National Petrochemical Co. of Iran (NPC), awarded Paris-based Technip-Coflexip and Tehran-based Iranian engineering firm Nargan a 173 million euros contract for the design and construction of a 500,000 tonne/year steam cracker to be built on Kharg Island in the Persian Gulf.

The steam cracker will produce ethylene from ethane feedstock, which will be supplied by a nearby associated natural gas processing plant.

Under terms of the contract, Technip-Coflexip will carry out basic and detail engineering, supply of equipment and materials, and construction and commissioning supervision for the project.

The engineering firm also will provide its in-house ethylene technology and proprietary furnaces for the project.

Nargan, in which Technip-Coflexip holds a 20% stake, will perform the engineering and procurement related to equipment and materials of local origin. Start-up of the unit is expected in 27 months, the companies said.

In addition, TotalFinaElf SA has awarded Technip-Coflexip a 50 million euro contract for the design and construction of a hydrotreating unit at TotalFinaElf's 109,013 b/cd refinery at Antwerp, Belgium. Construction completion is scheduled for the end of August 2004. The unit, which will have a capacity of 57,500 b/sd of gasoline, is expected to be ready for start-up on Oct. 20, 2004. Part of the "Clean Gasoline Project," the unit will hydrotreat gasoline from the FCC unit without lowering the octane rating. The Clean Gasoline Project will allow the production of gasoline having a sulfur content below 10 ppm so the Antwerp refinery will comply with 2008 European gasoline standards. Technip-Coflexip's engineering center in Paris will handle engineering, equipment and materials procurement, works subcontracting, construction supervision, and precommissioning operations. In other refining news, Basell Polyolefins Co., a 50:50 joint venture of Shell Chemicals Ltd. and Germany's BASF AG, plans to invest 51 million euros to improve the flexibility and performance of the steamcracker at its Etang-de-Berre site on the French Riviera. The JV also will increase the processing capacity at the integrated refinery by 20,000-106,000 b/d, said company officials. It will take a year to complete the improvements, officials said. In 1997, Shell reduced the capacity of the refinery to 86,000 b/d from 140,000 b/d because of overcapacity. Since then, petrochemicals and refining operations have been integrated on the 1,000 hectares site.

NONEXCLUSIVE SEISMIC SURVEYS in search of oil are planned this summer in the Atlantic off Labrador and Newfoundland.

Geophysical Service Inc., Calgary, will acquire 4,000 line km of 2D data off Labrador and a similar amount to the southeast in the Orphan basin east of Newfoundland. The 89 m, ice-strengthened GSI Admiral seismic vessel, capable of towing as many as four streamers 6 km in length, will handle acquisition in July and August, said Davey Einarsson, GSI president, Houston.

GSI has reprocessed about 20,000 line km of data the company acquired in the Labrador Sea starting in 1971 for a major oil company it declined to identify.

The new survey will tie to existing seismic data and to the several wet gas discoveries made on the Labrador shelf in the 1970s-80s (OGJ, July 12, 1982, p. 145). It will extend as far as 100 km off the shelf edge into as much as 3,000 m of water, which may be prospective for oil, said Einarsson.

The Orphan basin lay in ancient times between two basins that are demonstrably oil prone: the Jeanne d'Arc basin off Newfoundland and the Porcupine basin off Ireland, he said. The Orphan basin data will be collected in 1,000-3,000 m of water.

Some expect acreage postings in the Orphan basin soon, which points toward licensing as early as December 2003, Einarsson said.

The Orphan basin is northwest of the Flemish Pass basin, where Petro-Canada, Norsk Hydro Americas Inc., and EnCana Corp. are on an exploratory program that consists of two wells in about 1,000 m of water.