OGJ Newsletter

Dec. 16, 2002
In a move to improve their market credibility, ministers of the Organization of Petroleum Exporting Countries apparently agreed last week to raise hike their collective production quotas by 6%, or 1.3 million b/d, while practicing stricter compliance with production limits.

Market Movement

OPEC approves 'paper' quota increase

In a move to improve their market credibility, ministers of the Organization of Petroleum Exporting Countries apparently agreed last week to raise hike their collective production quotas by 6%, or 1.3 million b/d, while practicing stricter compliance with production limits.

Saudi Arabia, OPEC's most powerful member, had urged the group to curb excess production by as much as 2 million b/d while simultaneously hiking the group's total quota by 1.5 million b/d. The result, the Saudis claimed, would be increase only on paper, adding no new barrels of oil to the market.

The new quota target of 23 million b/d is effective Jan. 1. Formal ratification of that decision at OPEC headquarters in Vienna was still pending at OGJ presstime.

Analysts estimate OPEC members currently are producing 2.5 million b/d above their total existing quotas. The amount of cheating increased this fall, leading some observers to question OPEC's credibility. However, some key industry analysts claimed the so-called cheating by some OPEC members was only a means of making up the shortfall in Iraq's oil production during much of that period. They argue that OPEC has worked skillfully to balance oil supplies with world demand.

As a result, the average price for OPEC's basket of seven crudes was $26.70/bbl at midweek, near the top side of the group's targeted range of $22-$28/bbl. OPEC supplies about a third of the world's crude.

A fairly robust increase in world demand for oil is projected into 2003. At the same time, there remains a strong possibility of military conflict between US-led forces and Iraq that might disrupt some Middle East oil supplies.

Nonetheless, some OPEC members expressed concern earlier that continued cheating on production quotas risks a collapse in oil prices when winter demand for heating oil declines next spring. F

Venezuela's production plummets

Oil production by Petroleos de Venezuela SA (PDVSA) fell to 600,000-650,000 b/d, less than a third of its previous output, well into the second week of a general strike aimed at forcing Venezuelan President Hugo Chávez out of office. Venezuela's oil production normally is 3 million b/d but was down to 2.2 million b/d prior to the strike, various sources reported.

Critics blame Chávez's left-leaning policies for deepening the country's economic crisis. Chávez, whose primary support is among Venezuela's poorest residents, described the strike as "a kind of collar-and-tie subversion" backed by business and political opponents "that penetrated the (oil) industry, expropriated it from Venezuelans a long time ago, people who believed that PDVSA was theirs."

The government last week was employing PDVSA retirees, untrained strikebreakers, and apparently even military forces to restore production and transportation of oil and petroleum products. At one point, military personnel commandeered fuel transport trucks from private companies to provide gasoline in the capital city of Caracas, where a serious shortage was reported. However, sources said the government was able to roll out only 200 of the 1,700 fuel transport trucks normally in daily use.

Heavily armed sailors from Venezuela's navy scrambled up ropes to board the Venezuelan Yavire propane tanker and the Pilin Leon oil tanker. The captains of both vessels were arrested, reportedly for refusing to deliver their cargoes as part of the strike. The Yavire was anchored off Anzoategui in central Venezuela, while the Pilin Leon was anchored off western Maracaibo.

At midweek, Venezuelan government officials claimed they had cracked the strike and "broken the blockade" by loading at least five tankers with a total 2.23 million bbl of crude for shipment to the US. However, there were conflicting reports at presstime that none of the tankers were en route because of problems with the loading pumps at the terminal.

Venezuela, the world's fifth largest oil exporter, normally provides 13% of daily US oil supplies. "At this juncture, US refiners have reported few difficulties nominating spot barrels (and potentially withdrawing from Caribbean storage) to replace lost Venezuelan output," reported Matthew Warburton, industry analyst with UBS Warburg LLC, New York. "Yet to the extent that the loss of Venezuelan crudes endures, we would expect light-heavy crude differentials to narrow and Gulf Coast coking margins to be eroded, compared to the healthy levels seen in October (and) November."

Meanwhile, government officials said, Venezuela is losing $50 million/day due to the shutdown of refineries and ports serving PDVSA. Venezuela's total refinery output has been cut to 80,000 b/d from nearly 1 million b/d, sources reported.

Negotiations between the opposing factions appeared to be at an impasse late last week. However, Rafael Ramirez, Venezuela's minister of energy and mines, said a complete restructuring of PDVSA has been ordered.

Industry Scoreboard

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Industry Trends

US LNG imports are accelerating, but an analyst says US natural gas imports and exports will have no net impact on US gas supplies this year.

US gas production is on the decline while LNG imports have grown at an average rate of 60%/year since 1995, Raymond James & Associates Inc. said in a research note.

The Sept. 11, 2001, terrorist attacks on the US slowed LNG imports last year. LNG imports last year at this time averaged 310 MMcfd compared with 750 MMcfd during the first 9 months of this year. Raymond James estimates US imports of LNG will top 1 bcfd in January 2003, which would be 750 MMcfd over last winter's level.

Raymond James analyst Marshall Adkins of Houston said, "While this is more than a twofold increase in LNG imports, don't get excited just yet. Based on our year-to-year supply-demand forecast, the US market is going to need every molecule of that gas, and then some.

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"Specifically, aside from falling US gas production, falling Canadian imports as well as increasing Mexican exports should act to offset the aforementioned increase in LNG imports," Adkins said (see chart).

The analyst forecast a 500 MMcfd decline in Canadian imports of gas this winter compared with last winter. Meanwhile, the US is exporting more than 700 MMcfd of gas to Mexico compared with last winter's average exports of 440 MMcfd.

NO SHARP CHANGES are expected in US or worldwide drilling activity until sometime next year.

That conclusion comes from UBS Warburg LLC's analysis of its December PatchWork Survey. The survey compiles responses from oil and gas operating personnel, who are polled monthly as to their expectations of price and activity levels. Virtually no responses were received from Canada for the December poll, UBS Warburg reported.

When asked in November about drilling plans, 39% of US respondents said they plan to increase drilling in the next 60 days, 18% plan to decrease it, and 43% do not plan any changes.

Outside the US and Canada, meanwhile, 27% of respondents plan an increase in drilling, 18% plan a decrease, and 55% do not plan any change.

Government Developments

FRENCH OFFICALS say they are content with a compromise that European Union energy ministers reached last month calling for the opening of residential natural gas and electric markets by July 2007.

For a decade, the EU has been negotiating to reach an agreement on when to open markets.

In March, EU leaders met in Barcelona and agreed to open the commercial markets in January 2004. But that schedule was extended to July 2004 during a Nov. 25 meeting of the EU energy ministers.

The original date for the residential markets had been 2005, but EU energy ministers last month also reached a compromise calling for residential markets to open by July 2007.

France's Industry Minister Nicole Fontaine had insisted that 2005 was too early (OGJ, Oct. 14, 2002, p. 7).

The EU energy ministers also agreed that a progress report would be compiled in 2006, as requested by France, to evaluate commercial liberalization efforts. Specifically, energy ministers will want to know how prices have evolved, the quality of the service offered, and if all countries have opened their markets at the same level.

IN RELATED news, France's Regulatory Commission for Electricity has said that there is a need for more comparability between Gaz de France and third parties on natural gas tariffs to establish better access for competition.

The commission, in charge of the gas liberalization effort, also called for broadening supply points into France by building new LNG terminals in southern France and by increasing France's interconnections with Spain.

The more competitive access to France's gas network applies to TotalFinaElf SA, which has its own natural gas network, as well as to GdF. Jean Syrota, commission president, said currently nine industrial users with 16 sites have switched from GdF as their gas supplier. This represents 25% of the volumes that are open to free market competition in the first phase of liberalization.

US OIL STORAGE and transfer facilities have been granted at least a temporary reprieve from filing a specialized spill prevention plan with the US Environmental Protection Agency, industry groups say.

EPA notified several trade groups that it has extended the Feb. 17, 2003, compliance deadline for the new regulations. But regulators have not yet set a new deadline or decided if the Spill Prevention, Control, and Countermeasure (SPCC) rule, will be rescinded or revised. In meetings last year with EPA and this year with the White House's Office of Management and Budget, industry requested that the rule be suspended for at least a year.

The American Petroleum Institute, the Petroleum Marketers Association of America, and Marathon Oil Co. filed individual lawsuits challenging the rule.

In November, EPA officials met with API, the Independent Petroleum Association of America, the Texas Independent Producers & Royalty Owners Association, and other interested parties concerning SPCC rule requirements. Industry is concerned that the rule, as currently written, does not detail who is required to file spill reports. In a Dec. 2 letter to its members, IPAA said an extension is needed to clarify the rule.

Quick Takes

Argentine independent Pluspetrol SA, upstream operator of the Camisea natural gas project, expects to begin drilling its third development well on Block 88 within the next month, it said.

Eliseo Bouza, manager of Pluspetrol Camisea, told a news conference Dec. 3 that the company marked a milestone this month with the arrival at the Malvinas camp of up to 80% of the 100,000 tonnes of equipment—including compressors and cryogenic gas plants—targeted for shipment during the current weather window.

Barging is limited to November through March when rains increase river levels enough to move heavy shipments.

On Oct. 26, Houston-based Parker Drilling Co. began drilling the project's second well, San Martin 3. The project's first stage calls for drilling four development wells and a reinjection well, with Camisea slated to begin producing by August 2004. The first two wells are the San Martin 1 and San Martin 3, to be followed by two development wells in Cashiriari natural gas field.

Ricardo Markous, manager of Transportadora de Gas del Peru (TGP) with Argentine's Tecgas as operator, said the consortium spent $300 million on downstream infrastructure. TGP has prepared 350 km of the 720 km route for natural gas and liquids pipelines, installed almost 200 km of pipe, and rebuilt 20 bridges.

Markous said the transport investment is $740 million, and financing costs would raise the total to $800 million.

Gas Natural de Lima y Callao, a Tractebel-led group that will distribute Camisea gas and liquids in the capital city, laid its first pipeline segment for entry into the city Dec. 3, after obtaining approval of its environmental impact assessment. The company said it has outlined half the pipeline route and expected to receive the last shipment of pipe by Dec. 13.

A consortium of ConocoPhillips unit Conoco (UK) Ltd., GDF Britain Ltd., and London-based exploration and production independent Tullow Oil UK Ltd. began natural gas production Dec. 3 from Murdoch K field in the southern sector of the UK North Sea 115 miles northeast of Lincolnshire.

The second Carboniferous field to be produced as part of the $200 million CMS III subsea-based development, Murdoch K attained a production rate of 204 MMscfd on test—a volume greater than that expected from the well design, Tullow said.

Conoco holds a 59.5% interest in the field and operates it, while GDF Britain holds 26.4%; and Tullow 14.1%.

Murdoch K 44/22a-10Y well is a sidetrack of the March 2001 discovery well. The field is one of five natural gas reservoirs the consortium is developing as a single, unitized project containing 430 bcf of natural gas.

Murdoch K and the other fields, Hawksley, McAdam, Boulton H, and Watt, are being developed using the Caister Murdoch System's production and transportation facilities, known collectively as CMS III. The five fields lie on Blocks 44/22a and 44/23a. They are estimated to hold 500 billion cu m of gas (OGJ Online, June 24, 2002).

Hawksley field was brought on stream Sept. 7 with a sustained production rate of 170 MMscfd. The current combined CMS III production rate is 300 MMscfd from two wells.

"We areUpleased with the exceptionally high productivity achieved from the first two producing wells on CMS III, said Tullow Chief Executive Aidan Heavey. "The initial indications are that the reserves in these two fields will be at the upper end of our expectations," he said.

The satellite development contains subsea production centers for each reservoir, interconnecting pipelines, and service umbilicals and control systems linked back to the CMS facilities located at Murdoch field. The subsea infrastructure is now in place, and as each new production well is completed, tie-in and production can be achieved within weeks.

Consort Caister Ltd. is a participant in CMS along with operator ConocoPhillips, GDF Britain, and Tullow. The complex required extensive new and upgraded facilities, including a new bridge-linked accommodation platform installed in May and tie-ins for the CMS III subsea development.

In mid-2003, the group will install a new compression module that will double CMS compression capacity for existing and new production and will provide for future natural gas developments in the area. Produced natural gas is transported from CMS by subsea pipeline to the Theddlethorpe gas terminal on the Lincolnshire coast.

The third development well is being drilled in McAdam field, and production from the well is expected in first quarter 2003.

APACHE CORP., operator of the 2.3 million acre West Mediterranean (Block I) concession off Egypt, recently made its fourth natural gas discovery, El King-1X, in the deepwater portion of the concession. The discovery follows the Houston-based independent's third discovery on the concession last month (OGJ, Nov. 18, 2002, p. 8). The well was drilled 28.5 miles offshore in 2,361 ft of water.

G. Steven Farris, Apache president and CEO, said that the discovery was the first deepwater Miocene oil discovery in the Nile Delta, which confirms industry speculation that such a hydrocarbon system is present. The discovery also tested rich gas in the Miocene middle Abu Madi formation, Farris noted.

The company performed two tests on the well in a 190 ft column in the Abu Madi formation. The first test was conducted in an 8 ft interval at 7,738-7,746 ft and flowed at a maximum of 2,630 b/d of 32º gravity oil and 1.2 MMcfd of gas through a 20/64-in. choke with flowing wellhead pressure of 1,350 psi. The second test, in a 38 ft interval at 7,664-7,702 ft, flowed 31 MMcfd of gas and 757 b/d of condensate through a 50/64-in. choke with flowing wellhead pressure of 2,114 psi.

Apache said it plans to drill a fifth well to evaluate correlative Miocene intervals at depths approaching 11,000 ft. Apache is operator of the El King-1X well and holds a 55% contractor interest in the deepwater portion of the concession. Other concession partners are RWE-DEA AG 35% and BP PLC 10%. x‡

Petroleo Brasileiro SA (Petrobras) has made oil discovery on the BC-60 Block in the northern Campos basin, off the southern coast of the Brazilian state of Espírito Santo, 10 km from the recently discovered Jubarte field. The 1-ESS-116 wildcat was drilled 76 km offshore in 1,478 m of water, encountering a 60 m thick, saturated 19° gravity oil-bearing formation. Area geological studies indicate postulated reserves of 300 million boe. Combined with the estimated reserves of Jubarte field, the amount discovered on the BC-60 Block could total 900 million boe, officials said. Jubarte is producing 17,000 b/d of 17° gravity oil from a single well, the basis for a permanent production project. The Jubarte well is capable of producing 25,000 b/d, but limited processing capability is constraining the flow, said Petrobras officials. Petrobras is drilling another well to determine the commercial viability of the find.

Second, China National Offshore Oil Corp. (CNOOC) has signed a production-sharing agreement with Husky Oil China Ltd., a unit of Husky Energy Inc., Calgary, to explore for oil on deepwater Block 40/30 in the Pearl River Mouth basin of the South China Sea. The block is about 30 km southwest of the gas-bearing PY30-1 structure. The agreement, which follows the recent announcement of two production-sharing contracts with Husky on Blocks 23/15 and 23/20 in the Beibu Gulf basin of the South China Sea, is the first deepwater exploration PSA signed between CNOOC and foreign petroleum companies since it announced the tendering of deepwater areas in September (OGJ Online, Sept. 25, 2002). Other international companies are studying the geological data of the 12 deepwater blocks CNOOC offered. Husky's Block 40/30, which lies about 100 km southeast of Hainan Island in the Pearl River Mouth basin, covers an area of 6,704 sq km in water 600-1,500 m deep. Under terms of the PSA, the exploration period will be divided into three phases, with Husky required to drill one wildcat at least 1,600 m deep in Phase IHusky has agreed to pay 100% of the exploration costs, estimated at $10 million minimum, and CNOOC retains the right to farm in as much as 51% working interest in any commercial discoveries on the block. In other activities in the Pearl River Mouth basin, Husky Oil China recently produced first oil for CNOOC Ltd. from Wenchang field about 140 km east of Hainan Island and 400 km southwest of Hong Kong. (OGJ Online, July 25, 2002). Husky holds 40% and CNOOC Ltd. 60% of those fields.

Statoil ASA has acquired the development rights for an underground natural gas storage facility to be built at Aldbrough, near the Hornsea salt caverns on the eastern coast of England.

The acquisition follows an agreement to buy Aldbrough Gas Storage Co. Ltd. from Intergen, the electric power alliance of Royal Dutch/Shell Group and US engineering company Bechtel Corp.

The new facility, which is scheduled to be operational in 2007, will act as a buffer against possible terminal interruptions and will provide additional security of supply for Statoil's gas deliveries to the UK.

In addition, the facility's rapid injection and withdrawal capability will support the group's UK gas trading activities.

The facility will consist of three underground salt caverns having a total storage capacity of 170-230 million cu m of gas. Drawdown will be via an 8 km gas pipeline tied into Britain's national transmission system. Other necessary construction will be a power line connecting to the Yorkshire Electricity distribution network and a seawater leaching system for leaching out the salt domes.

"This facility will provide us with a back-up for our gas deliveries from the Norwegian continental shelf," said Mike Kelly, vice-president and project director at Statoil UK. "It also gives us a useful trading tool to enhance the value of our gas portfolio," he added.

Gas currently is supplied to the UK via the Vesterled trunkline from the Heimdal platform in the North Sea and the Frigg pipeline to the St Fergus terminal in Scotland.

BP PLC and ChevronTexaco Corp. reported the commercial start-up of their $23 million, 22.5 Mw wind farm constructed at the companies' jointly owned, 400,000 b/d Nerefco refinery near Rotterdam. The wind project consists of nine Nordex turbines, each 120 m tall, and has a generating capacity of 2.5 Mw.

The companies will sell the electricity generated by the farm into the Dutch national power grid.

The companies said that the project represents Europe's first full-scale wind farm on a grassroots refinery site. The farm will displace 20,000 tonnes/year of greenhouse gas emissions, the companies said.

"Placing the project within our refinery optimizes the use of our assets, minimizes any visual or noise impact on the surrounding area, and helps the Netherlands achieve its environmental targets," said Xavier Bontemps, Nerefco refinery manager.

The Dutch government has set a target to increase the amount of electricity generated from renewable sources to 5% by 2005, the companies said. Currently, wind power accounts for roughly 1 Tw-hr of the total Netherlands power market. This figure by 2010 is expected to approach 4 Tw-hr, which equals about 35-45% of the total renewable power generation in the Netherlands, the companies said.

The wind farm is held by BP 69% and ChevronTexaco 31%, the same as the companies' ownership percentages in the Nerefco refinery.

Marathon International Petroleum Ireland Ltd. has awarded a £7 million contract to Technip Offshore UK Ltd., the UK unit of Paris-based Technip-Coflexip, to install a gathering pipeline from the Greensand development in the Celtic Sea off Ireland.

The contract includes all work required to tie back the Greensand well to the Kinsale Bravo platform 7 km away. Within the scope of the contract, Technip Offshore will perform project management, engineering and design, manufacture and installation of the 10-in. rigid flowline and riser system, and the procurement and installation of a 200 m electrohydraulic control umbilical.

Technip Offshore also will carry out all subsea tie-ins, testing, and precommissioning of the completed infrastructure. First gas is slated by July 2003.

Fabrication of the rigid flowlines will be undertaken at Technip-Coflexip's Evanton spoolbase in Scotland and then transported and laid onsite at Greensand by the CSO Apache reel ship. The CSO Wellservicer diving support vessel will carry out installation of the platform riser, umbilical and associated structures, and the tie-ins and testing.

CORRECTION

OGJ's Dec. 9, 2002, Newsletter, p. 8, reported that Argentina's Transportadora de Gas del Sur operates the Argentine national grid. As one of two national gas transmission operators, TGS actually operates only the southern sector, and TGN—Transportadora de Gas del Norte—operates the northern sector.