Major gas projects fuel surge in long-term plans

In the short term, however, for 2001 only, worldwide pipeline construction plans continue to be timid as those near-term plans dropped to slightly more than 11,000 miles from nearly 16,000 miles planned for 2000 a year ago.

But with crude oil and natural gas prices continuing strong into 2001, especially in North America, and virtually every forecast saying that strength will continue, pressure on operators to add infrastructure sooner rather than later is increasing.

And energy demand forecasts may provide the impetus.

Late last year, the US Energy Information Administration (EIA) raised its estimate of US energy demand for as far out as 2020 (OGJ, Dec. 4, 2000, p. 32).

The agency projected that demand would reach 127 quadrillion btu (quads) in 2020 from 96 quads in 1999, an increase of 5% from its forecast in late 1999. EIA said that its projections reflected optimism over long-run economic growth in the US.

The agency said it expected world oil prices, which increased in both 1999 and 2000, to begin falling in 2001.

And natural gas prices within 2 years, said EIA, would retreat from their highs of late 2000.

If those prices fall back, EIA's confidence in US economic strength may be ratified. Continued high energy prices, however, will almost certainly dampen energy demand, in particular, even as they retard or arrest economic growth in general.

And EIA's revision upward came ahead of cascading events in December 2000 and January 2001 clearly indicating that the long-running US economic expansion was coming to an end.

Complicating the picture last month was the decision by the Organization of Petroleum Exporting Countries (OPEC) to cut production to shore up declining oil prices.

For 2020, EIA forecast a world oil price of more than $22/bbl ($US 1999), similar to the projection in 1999. The average wellhead price of gas would reach more than $3/Mcf in 2020, pushed by expected demand growth for gas, primarily for electricity generation.

US oil demand, said EIA, will grow at 1.3%/year-to 25.8 million b/d in 2020 from 19.5 million b/d in 1999-led by demand growth in transportation that currently accounts for about 70% of US petroleum consumption.

US crude oil production in the agency's forecast will decline at 0.7%/year during 1999-2020 to 5.1 million b/d, a drop of 200,000 b/d from its 1999 forecast.

Total US natural gas demand will increase by 62% during 1999-2020, rising to 34.7 tcf from 21.4 tcf. Natural gas demand for electricity generation, excluding cogeneration, will triple over that period, said EIA, as 89% of the generation capacity built over the next 2 decades will be gas-fired.

Start-up last year of a major gas-pipeline project to move Canadian supplies into the US Midwest is pushing to completion many ancillary projects south of the border.

But the sharply colder winter in North America and the lack of major additions to storage in the Lower 48 have pushed up natural gas prices and highlighted infrastructure problems that had heretofore gone unnoticed.

Although plans for Canadian pipeline construction, especially to move more natural gas into the US, jumped in a year's time, far fewer miles of pipeline are planned for the US in the short term.

Outside the US, and again with a view of the long term, significant pipeline mileage is planned for Asia, the Middle East, and Canada.

For 2001 and beyond 2001, more than 52,600 miles of crude oil, product, and natural-gas pipeline are planned (Fig. 1), up by more than 20% from the combined near and long-term projections of a year ago (OGJ, Feb. 7, 2000, p. 36).

These trends are evinced in the latest Oil & Gas Journal pipeline construction data derived from a survey of world pipeline operators, industry sources, and published information.

Bases, costs

For 2001 only (Table 1), companies indicated plans to complete more than 11,000 miles of oil and gas pipeline worldwide at a cost of nearly $17 billion. For 2000 only, companies had predicted more than 16,000 miles at more than $17 billion.

For projects completed after 2001 (Table 2), companies expect to spend more than $63.5 billion to lay more than 41,500 miles of line. Last year, when these companies looked beyond 2000, they expected to spend less than half as much-about $30 billion-to lay nearly 27,500 miles of line.

• Projections for 2001 pipeline mileage reflect only projects expected to be completed by yearend 2001, including construction in progress at the first of the year or set to begin during it.
• Projections for mileage in 2001 and beyond include construction that might begin in 2001 and be completed in 2002 or later. A few long-term projects that OGJ judges as probable are included even if they will not break ground until after 2002.

An example would be plans for a natural gas transportation system from Alaska's North Slope, regardless of the route it takes.

Cost estimates are based on US average costs per mile for onshore and offshore gas-pipeline construction as found in Table 4 of OGJ's most recent Pipeline Economics Report (OGJ, Sept. 4, 2000, p. 68).

These projections assume, based on historical analysis, that 90% of all construction will be onshore and 10% offshore and that pipelines 32 in. OD or larger are onshore projects.

Under these assumptions and with OGJ pipeline-cost data, here is a breakout of costs by line size:

• Total onshore construction (10,309 miles) for 2001 only will cost $15.5 billion:

  -$1.8 billion for 4-10 in.
  -$4.4 billion for 12-12 in.
  -$4.3 billion for 22-30 in.
  -$5.0 billion for 32 in. and larger.

• Total offshore construction (776 miles) for 2001 only will cost nearly $1.4 billion:

  -$240 million for 4-10 in.
  -$571 million for 12-20 in.
  -$570 million for 22-30 in.

• Total onshore construction (38,713 miles) for beyond 2001 will cost $58.5 billion:

  -$2.5 billion for 4-10 in.
  -$10.7 billion for 12-20 in.
  -$25.7 billion for 22-30 in.
  -$19.6 billion for 32 in. and larger.

• Total offshore construction (2,862 miles) for beyond 2001 will cost slightly more than $5.0 billion:

  -$326.6 million for 4-10 in.
  -$1.4 billion for 12-20 in.
  -$3.3 billion for 22-30 in.

Western US gas boom

The last year saw a boom in plans to move natural gas out of US Rocky Mountain producing areas to markets. Units of three pipeline companies that through various business units dominate gas movements out of the area-Questar Corp., Salt Lake City; Williams, Tulsa; and Coastal Corp., Houston-have been especially active.

In July 2000, the US Federal Energy Regulatory Commission (FERC) issued a final order approving Questar's plans to move natural gas through the Southern Trails Pipeline.

The 693-mile, 16-in. line, built in 1957 to move oil to Southern California refineries, is being converted to move 80-90 MMcfd across New Mexico and Arizona and 120 MMcfd in California.

In December, FERC granted preliminary approval for Questar to construct a 75-mile natural gas pipeline.

The $80 million, 24-in. Main Line 104 will extend from Price, Utah, to Payson, Utah, then 18 miles west, where it will tie into Williams' Kern River Gas Transmission Co. pipeline near Elberta, Utah.

Questar said the 1,400-psi line will be in service before the 2001-02 heating season and will provide at least 272 MMcfd of firm gas transportation for delivery to Wasatch Front markets and the proposed interconnect.

The company said the pipeline will move coal-seam gas from central Utah. Final FERC approval depends upon an environmental impact statement.

Questar awarded Sterling Construction, Sterling, Colo., a contract to build the pipeline. Mountain West Construction Co., Fruita, Colo., will design and install 9,300 hp of additional compression at Questar Pipeline's Oak Springs compressor station near Price, Utah.

Also in July 2000, Kern River announced an open season on its natural gas system to determine interest for firm year-round transportation to Nevada and California and to determine interest for capacity relinquishment from existing firm shippers, said the company.

The open season extended through Aug. 18.

Kern River said that, because significant expansion of its mainline system from Wyoming to Southern California could be achieved through addition of compression, the "relative costs for serving new and existing loads could result in an overall lowering of Kern River's rolled-in rate for all [the pipeline's] shippers."

The proposed commencement date for the offered service was May 1, 2002.

Response for the open season led to Kern River's filing with FERC in November 2000 to construct an expansion of its system, the "California Expansion Project," to move an additional 124.5 MMcfd of firm transportation capacity from Wyoming to California markets.

The application proposes construction of three new compressor stations, an additional compressor at an existing facility in Wyoming, restaging a compressor in Utah, and upgrading two meter stations. The $80 million project is being driven, said the company, by:

• Diversion of Canadian gas supplies to markets in the US Midwest.
• Increased production in the Rocky Mountain basin.
• Strong economic growth in Kern River's markets.
• Increased demand for gas-fired electricity generation.

Also in July 2000, Northwest Pipeline, another Williams unit, extended its deadline for shippers to execute precedent agreements for firm natural gas transportation on the proposed Grants Pass lateral expansion in Oregon.

At that time, the 260-mile Grants Pass lateral was fully contracted to serve existing markets in western Oregon between the Washougal compressor station near Portland and the terminus of the lateral near Grants Pass, Ore.

Targeted in-service date is Nov. 1, 2002.

Into US Midcontinent

Another unit of Williams that is based in Owensboro, Ky., held an open season in August and September 2000 for interest in firm gas transportation service on the proposed Western Frontier Pipeline from the Cheyenne Hub in northeastern Colorado to Hugoton station on Williams' Central pipeline system in southwest Kansas.

The Western Frontier Pipeline, said the company, would provide about 540 MMcfd of firm service from the Rockies' producing basins, including Powder River, into the Midcontinent.

The project would involve construction of some 400 miles of mainline and addition of 13,000 hp of compression with service set to start in November 2003.

In addition to access to the Central system, Western Frontier "would have access to other major Midcontinent pipelines including ANR Pipeline, Panhandle Eastern Pipeline, Northern Natural Gas, and Natural Gas Pipeline of America," said the company.

Western Frontier also would provide "seamless transport at an incremental cost to the growing Oklahoma intrastate markets via the Central system," said the company.

In January 2000, Coastal Corp. unit Colorado Interstate Gas Co. (CIG), Colorado Springs, announced the route for a new pipeline lateral to deliver natural gas to a planned 478-Mw power plant south of Colorado Springs.

The 85-mile, 16 or 20-in. Nixon lateral will deliver up to 85 MMcfd to the plant to be constructed by Front Range Power LLC. It will run from CIG's Watkins station, east of Denver, and follow existing CIG right of way to a meter station near the proposed power plant.

In-service is planned for August 2002.

And in August 2000, Coastal Corp. affiliate Wyoming Interstate Co. (WIC), Colorado Springs, started up its expansion of the Medicine Bow lateral in northeast Wyoming. At the time, the company announced plans for even more facilities.

Additional compression increased capacity on the Medicine Bow lateral to 380 MMcfd from 260 MMcfd. The line extends from the southern end of the Powder River basin near Douglas, Wyo., to WIC's mainline southwest of Cheyenne, Wyo.

In September 2000, Coastal filed with FERC for more capacity out of the Powder River basin. The company wants to loop the entire Medicine Bow lateral with another 155 miles of 36-in. pipe and add 14,340 hp of compression at an estimated cost of $168 million. This loop will initially increase WIC's capacity out of the basin by 675 MMcfd.

The new loop will be in service by December 2001.

Coastal said that, since 1998, WIC has invested more than $108 million to increase transportation capacity out of the Powder River basin.

Elsewhere in the region in October, CIG completed its Picketwire lateral loop in the Raton basin in southern Colorado.

The 20-in., 12.5-mile pipeline adds 33 MMcfd of delivery capacity for transportation of more coalbed methane.

Since initial construction of the Picketwire loop in 1994, CIG has invested nearly $45 million in facilities directly tied to Raton basin production, including the 115-mile Campo lateral and the Cucharras lateral.

Rounding out Rocky Mountain activity, in September 2000, expansion of the Trailblazer Pipeline, which runs eastward out of the Rocky Mountains to Beatrice, Neb., was fully subscribed at 300 MMcfd. Company officials said the $54 million expansion would be completed by fourth quarter 2002.

Added will be 50,000 hp of new compression and an increase in the existing 5,200 hp compression at Station No. 602 by 4,800 hp.

Trailblazer is operated by Kinder Morgan Energy Partners' Natural Gas Pipeline of America.

In other Western US gas pipeline activity, at mid-2000, a group consisting of US and Mexican companies announced plans to build a $230-million, 212-mile pipeline to serve northern Mexico.

The proposed North Baja pipeline would begin at an interconnection with the El Paso Natural Gas Co. system near Ehrenberg, Ariz., cross southeastern California and northern Baja California, Mexico, and end at an interconnect with the Rosarito pipeline south of Tijuana.

Sempra Energy International, a unit of Sempra Energy, San Diego; Pacific Gas & Electric Corp.'s National Energy Group, San Francisco; and Mexico's Proxima Gas SA de CV plan jointly to build and operate the 400-MMcfd line consisting of 30-in. pipe and a single compressor station in Arizona.

The companies target January 2003 for in-service.

PG&E will build and operate the 77-mile US portion. A joint venture of Sempra and Proxima will be responsible for the Mexican segment.

More gas for Florida

Plans advanced last year in the eastern US to move natural gas across the eastern Gulf of Mexico to southern Florida markets.

Buccaneer Gas Pipeline LLC partners Duke Energy and Williams expect to receive approval this year for their 674-mile gas pipeline across the eastern Gulf of Mexico from Mobile Bay to a point just north of Tampa Bay.

In August, FERC concluded in a draft environmental impact statement that construction and operation of the line with "adoption of recommended mitigation measures would have limited adverse environmental impact and would be an environmentally acceptable action," according to the companies.

Earlier in the year, Buccaneer partners announced having signed a letter of intent with a joint venture of Saipem Inc. and European Marine Contractors Ltd. to oversee construction of the offshore portion of the $1.5 billion project.

The pipeline would move up to 900 MMcfd of gas to Florida. Its offshore portion would consist of 400 miles of 36-in. pipe from the coast of Alabama to the eastern coast of Florida in water depths of 20-500 ft.

A competing project, the 744-mile, $1.6 billion Gulfstream Natural Gas System LLC, proposed by Coastal Corp., signed a letter of intent with Berg Steel Pipe Corp., Panama City, Fla., in early 2000 to supply the project's 36-in. pipe. The contract anticipates construction start-up in June 2001 and pipeline in service in June 2002.

This project will also start at Mobile, Ala., but land at Manatee County, Fla., and involve a further 292 miles of onshore mainline and laterals, ranging in diameter from 16 to 36 in. Gulfstream's planned capacity is 1.13 bcfd.

Both projects target electricity-generating capacity in the southern reaches of the state.

Also in the Gulf of Mexico last year, construction began on the deepest pipeline there yet: the Canyon Express natural gas gathering system, a 55-mile line in 7,000 ft of water in the Mississippi Canyon area 120 miles southeast of New Orleans.

The dual 12-in. line will have a capacity of 500 MMcfd and is due for completion in summer 2002.

TotalFinaElf affiliate Elf Exploration Inc. is operator of the line that will move gas to the Canyon Station platform in East Main Pass Block 261, south of Mobile Bay. Platform construction will begin this summer with installation slated for second quarter 2002.

US product action

In refined product news in the US, CMS Energy Corp., Marathon Ashland Petroleum LLC, and TEPPCO Partners LP formed a limited liability company in March 2000 to own and operate a new interstate refined products line from the US Gulf of Mexico to Illinois. Each company would own a third of the consortium.

The joint venture planned to build a 70-mile, 24-in. line connecting TEPPCO's Beaumont, Tex., facility with the start of an existing 720-mile, 26-in. line extending from Longville, La., to Bourbon, Ill.

The new Centennial Pipeline will intersect TEPPCO's existing mainline near Lick Creek, Ill., where a new 2 million bbl products-storage terminal will be built.

CMS Panhandle Pipe Line Cos. has filed with FERC to convert the line from gas to product service; the companies expect conversion to be completed by yearend 2001.

In August 2000, Pioneer Pipeline Line Co. began to build its 262-mile expansion of a line carrying products from refineries in Montana and Wyoming to Salt Lake City. Pioneer Pipe Line is jointly owned by Conoco Inc. and Sinclair Oil Corp.

The project will replace an 8-in. line with a 12-in. line and increase capacity to 3 million gpd from 2 million gpd. Start up of the expansion was expected by late 2000 or early 2001.

In December 2000, GATX Terminals Corp, a unit of Chicago-based GATX Corp., agreed to sell its US pipeline and terminal business to Kinder Morgan Energy Partners LP, Houston, for $1.5 billion.

Assets included in the sale are Calnev Pipe Line Co. and Central Florida Pipelines Co., along with 12 terminals that store petroleum products and chemicals.

The 550-mile Calnev system originates in Colton, Calif., and in 1999 moved 112,000 b/d of gasoline, diesel, and jet fuel to the Las Vegas market. Calnev interconnects with Kinder Morgan's 3,300-mile refined products system at Colton.

The 195-mile CFPL system originates in Tampa, Fla., and consists of a 16-in. gasoline line and a 10-in. jet fuel and diesel line, moving 85,000 b/d in 1999.

Combined storage capacity of the 12 terminals is 35.6 million bbl for both petroleum and chemicals.

Canada

The massive 1.3-bcfd Alliance dense-phase, natural gas pipeline started up in late 2000, moving supplies from eastern British Columbia, across Alberta and the upper US Midwest, and to the Aux Sable gas plant near Chicago.

Construction was completed in late summer, but delays due in part to debris in the line pushed back commissioning and initial commercial flow for several weeks.

Designed to provide Western Canadian Sedimentary Basin producers with an alternative route to US markets, the line has radically altered the existing gas-transportation structure in Alberta.

As a direct consequence of Alliance, intraprovincial transporter Nova Gas Transmission Inc. merged with interprovincial TransCanada PipeLines Ltd. (TCPL), which subsequently had to retreat from what had been aggressive and varied worldwide activity in a $3-billion (Can.) series of divestitures.

As part of its retrenchment, TCPL at mid-year 2000 announced it had sold to TC PipeLines its 49% interest in the 111-MMcfd, Malin, Ore.,-to-Reno, Nev., Tuscarora gas pipeline. TC is a limited partnership owned one third by TCPL; Sierra Pacific Resources controls the remaining interest.

Also, TCPL announced in November 2000 that it would collect some $190 million (Can.) through the sale of its natural gas pipelines and marketing interests in Mexico to a unit of Gaz de France SA and of a Venezuelan gas-processing facility to Williams International.

The Mexican sale to Gaz de France unit GDF International SA consists of:

• 67.5% of Energía Mayakán S de RL de CV, a pipeline company that owns and operates a 435-mile natural gas pipeline in Mexico.
• 100% of TransCanada del Bajio S de RL de CV, a pipeline company that is currently building a 124-mile natural gas line in Mexico.
• 50% of TransNatural S de RL de CV, a natural gas marketing company.
• 100% of TransCanada International (Mexico) SA de CV, a company offering bundled energy services to industrial natural gas consumers in Mexico.

The Venezuelan asset sale to the Williams unit consists of:

• 49.25% of Accroven SRL, which will own and operate a gas liquids extraction, fractionation, and refrigeration facility currently under construction.
• 47.5% of Accroserv SRL, a related company.

The Accroven project, in the Eastern Cryogenic Complex of Venezuela, includes the construction and operation of two 400-MMcfd gas liquids extraction plants, a 50,000 b/d gas liquids fractionation plant and associated storage and refrigeration facilities for Petroleos de Venezuela SA (PDVSA).

Construction on the project began in mid-1999, with the three plants scheduled for operation in May 2001.

Effective date of both transactions was Sept. 30, 2000. The Mexican sale was to close in first quarter 2001, pending consents and approvals.

The company said it expected to receive all consents and approvals to close the Venezuelan deal by fourth quarter 2000.

TCPL CEO Doug Baldwin said the sales brought the company close to completion of its divestiture program, aimed at selling assets in order to focus on its core natural gas transmission, power, and marketing services in Canada and the northern tier of the US.

The company's noncore asset sales or agreements since December 1999 are worth about $3.4 billion (Can.), said Baldwin.

At about the same time, TCPL indicated completion of the proposed $1.35 billion (Can.) Millennium pipeline (Dawn, Ont., to Westchester County, NY) would likely be delayed for more than a year as a result of regulatory setbacks.

FERC had denied approval for the US portion; TCPL was hoping to delay hearings on the Canadian portion. Planned start-up for Millennium was pushed back to November 2001 at the earliest.

Also at mid-2000, Canada's National Energy Board approved AEC Suffield Gas Pipeline Inc.'s application to build and operate a 190-MMcfd natural gas pipeline from southeastern Alberta to southwestern Saskatchewan.

The $22.3-million (US) North Suffield Pipeline, expected to be in place by yearend 2000, consists of about 60 miles of 16-in. pipe and associated control facilities near the Suffield Military Training Block.

And Central Alberta Midstream, a venture of Chevron Corp. unit Chevron Resources Canada and BP unit Amoco Canada, began construction of a 44-mile, 12-in. sour-gas pipeline in northern Alberta.

The line will connect sour-gas production in the south Wapiti area to Central's processing facilities in the Kaybob region. The line will extend from the end of the Simonette pipeline to Central facilities near the Gold Creek plant operated by Rio Alto Exploration Ltd.

More dehydration and compression facilities are being built at Gold Creek to handle wet sour production. The pipeline should be completed by April.

In heavy-oil transportation action, Alberta Energy Co. Ltd. (AEC) in fourth quarter 2000 announced plans to expand the Cold Lake pipeline in northeastern Alberta.

AEC, Koch Pipelines Canada, and Canadian Natural Resources Ltd. formed the Cold Lake Pipeline partnership with AEC holding a 70% interest; the others, 15% each.

The partnership will construct the Hardisty transmission line, a 155-mile, 24-in. line to move heavy oil from the Cold Lake area to Hardisty, Alta., at a cost of $143 million (Can.).

The line will connect at Hardisty with the Express pipeline, Koch Hardisty terminal, and other facilities, said the company, and will have an initial capacity of 200,000 b/d. Start-up is planned for January 2002.

In the same area, construction began in August 2000 on the Corridor Pipeline project. It will link the two major components of the Athabasca Oil Sands Project of Shell Canada Ltd., Chevron Canada Resources Ltd., and Western Oil Sands Inc.

Those components are the Muskeg River mine, north of Fort McMurray, Alta., and the upgrader being built adjacent Shell Canada's Scotford refinery, near Fort Saskatchewan, Alta.

Corridor will also link the upgrader with marketing terminals in Sherwood Park, near Edmonton, said Trans Mountain Pipe Line Co. Ltd., which is building and will operate the system on behalf of Corridor Pipeline Ltd.

Corridor and Trans Mountain are both wholly owned by BC Gas Inc.

The 280-mile system will move about 215,000 b/d of diluted-bitumen in a 24-in. pipe from Muskeg River mine to the upgrader. A 12-in. return line, in the same ditch, will carry the diluent necessary to dilute the bitumen to the mine.

After the diluted bitumen is upgraded to synthetic crude, 103,000 b/d will move through a 20-in. line on the 27-mile upgrader system to terminals in Sherwood Park. The upgrader system includes a 16-in. return line, in the same ditch, that will supply feedstock material to the upgrader.

The pipeline system will also consist of seven pump stations, each with capacity of 54,000 hp, and seven storage tanks, three at the mine and four at the upgrader.

Outside North America

Peru has finally signed a contract for the development and transportation of Camisea natural gas.

A consortium led by Argentina's Pluspetrol in partnership with US firm Hunt Oil Co. and South Korean company SK Corp. won the contract to exploit the Camisea fields with a royalty of 37.24%.

Tecgas, a unit of the Techint Group, leads the consortium for transport and distribution of the gas and natural gas liquids in partnership with Hunt, SK, Algerian company Sonatrach, and Peru's Gra

The consortium bid $1.45 billion to construct and operate the pipeline. The companies have up to 44 months to start up operations but agreed to make every effort to begin commercial operations within 36 months.

Tecgas is holding talks with Colombia's Promigas, in which Enron is a partner, and another company that has not been named for distribution of natural gas in Lima and Callao. Spain's Gas Natural withdrew from the consortium shortly before the bid was presented.

Camisea's fields, discovered by Royal Dutch/Shell Group in the mid-1980s, have estimated natural gas reserves of 13 tcf of gas and 600 million bbl of condensate.

The other big story out of Latin America last year centered on plans in Ecuador to build another crude oil line.

At yearend, the government was negotiating terms of a contract with two bidders, OCP Ltd. and Williams, over plans to build a 300-mile oil line nearly parallel to the existing pipeline, known by its Spanish-language acronym SOTE. The new line would double the current 400,000-b/d transportation capacity.

OCP consists of Repsol-YPF Ecuador SA (25.1%), AEC (27.3%), Agip Oil Ecuador BV (9.6%), Kerr McGee Ecuador (5.1%), Occidental del Ecuador Inc. (23.9%), and Techint International Construction Corp. (Buenos Aires; 9%).

Elsewhere, Repsol-YPF is currently analyzing construction of a liquids, gas, and oil pipeline connecting Buenos Aires and Asuncion, Paraguay, which would cost at least $220 million.

The 800-mile pipeline project was to go before the company's board this month.The pipeline would require a year to be built and would reduce use of ships to transport gas and oil to Paraguay.

Elsewhere, a $1.7 billion contract awarded by Blue Stream Pipeline Co. BV to a consortium led by Saipem SPA took effect in December, according to Bouygues Offshore SA, a partner in the consortium. Blue Stream is a 50:50 joint venture of Italian company ENI SPA and Russia's Gazprom,

The contract includes design, engineering, procurement, and construction of the offshore section of the Blue Stream pipeline system in the Black Sea. The line will link Russian gas fields to Turkish customers.

The Saipem consortium, which also includes Mitsui Co. Ltd., Sumitomo Corp., and Itochu Corp., began work on the project in early 2000 (OGJ, Feb 21, 2000, p. 33).

The offshore section of the system will consist of a compressor station at Beregovaya, Russia, and two 236-mile offshore pipeline systems that will be laid in varying depths, the deepest of which is 2,150 m.

Gas transportation will begin immediately after the laying of the first line. Work should be complete in 2003.

In Asia, Thailand has begun operation of a west-east onshore pipeline that removes the bottleneck in the flow of natural gas from Burma's Gulf of Martaban.

Completion of the 96-mile, 30 in. Ratchaburi-Wang Noi pipeline enabled the Petroleum Authority of Thailand (PTT) to increase its reception of gas from the offshore Yadana and Yetagun fields to nearly 800 MMcfd.

About 280 MMcfd of the Burmese gas are being delivered through the $247.9-million line to the 2,000-Mw Wang Noi combined cycle complex, one of the country's largest power generators.

The new line was linked to PTT's Burmese gas transmission system from the Thai border province of Kanchanaburi to Ratchaburi, a distance of 260 km.

Saipem Asia Sdn. Bhd-Mitsui & Co, an Italian and Japanese consortium, built the 300-MMcfd Ratchaburi-Wang Noi pipeline, which can be expanded to 500 MMcfd.

About 500 MMcfd of Burmese gas goes to the Ratchaburi generating station owned by the government and Tri Energy Ltd.'s 700-Mw combined-cycle plant in the same province.

Over the past 2 years PTT's offtake of Burmese gas fell far below the contractual rates, 525 MMcfd from Yadana and 200 MMcfd from Yetagun, due to the delay in the construction of Ratchaburi power plant (with the ultimate capacity of 3,645 Mw).

The Thai state energy firm's purchase of Burmese gas averaged 18,600 boed in the first 9 months of 2000. Most of the gas was from Yadana.

PTT said its take of Burmese gas will grow to 900 MMcfd in 2001 to feed the three power stations (OGJ Online, Aug 24, 2000).

Rehabilitation of the pipeline was reportedly discussed in early December during a visit to Baghdad by Lebanese trade and finance ministers. No timeline was given for the project.

Syria and Lebanon had agreed in November to refurbish the segment of the line, which had been closed for nearly 20 years, linking oil facilities in the Syrian city of Homs.

Flowing?

Some reports had indicated that the segment of the pipeline linking Iraq and Syria had been restarted, with an estimated 150,000 b/d of Iraqi crude flowing through the line.

Baghdad said in November that it would export up to 200,000 b/d of its crude at discounted prices to Syria to be used in domestic refineries, while Damascus would export an equivalent amount of Syrian Light and Suwaidiyah crudes at market prices.

Iraq indicated that sales to Syria would fall outside of the oil-for-food program, under which Baghdad is allowed to export unlimited quantities of oil in exchange for humanitarian goods. The US and the UK did not oppose exports through the pipeline, so long as they are conducted under UN auspices and all revenues go towards the humanitarian program.

Iraqi and Syrian officials, however, repeatedly denied that the pipeline had resumed pumping, and the US State Department said in December that it had been assured again by Syrian diplomats that Damascus does not intend to break with UN sanctions.

Damascus had more than doubled its December loading program for its heavy Souedie crude exports, however, suggesting that Syria was in fact taking in Iraqi barrels.

Syrian oil exports reached between 490,000 and 500,000 b/d in December, a sharp increase from normal levels of 350,000 b/d, OPECNA reported.

Malaysia considers alternative route for Thai-Malay line
The new Thai government must decide the fate of the Thai-Malay gas pipeline and the related gas-separation plant.

The project faces continued opposition in southern Thai province of Songkhla, and Thailand's Office of Environmental Policy and Planning last year rejected the environmental impact assessment for the Thai-Malay gas-separation facility for the second time.

Meanwhile, Malaysia is considering alternative routes.

Offshore production

The pipeline, which would move gas from the offshore Thai-Malay Joint Development Area, has been delayed several times. Work must begin this year to meet contract requirements of delivery in mid-2002.

For the first 5 years, Malaysia will take all 390 MMcfd, since there is insufficient demand in Thailand.

As planned, the 34-in., 168-mile line would run offshore from Block A-18, one of the three gas-prone tracts in the JDA. From Songkhla, it would link via a 36-in., 56-mile line to Kedah in northern Malaysia.

The project by Trans Thai-Malaysia Ltd., a 50:50 joint venture of Petroleum Authority of Thailand and Petronas, also includes two 425-MMcfd gas-separation units in Songkhla.

The Thai Council of State ruled late last year that Industry Minister Suwat Liptapanlop could endorse the project without cabinet approval. But Suwat decline, to act before the election last month.

Malaysia, through state oil firm Petronas, has been pressuring Thailand to decide by Mar. 1, 2001. It has criticized Thai authorities' handling of local opposition that has blocked the line and separation plant (OGJ Online, Oct. 23, 2000).

Instead, Malaysia has unofficially suggested a line be laid from Block A-18, operated by a 50:50 joint venture of Triton Energy Ltd., Dallas, and Petronas Carigali, to Kerteh on the eastern coast of Malay Peninsula. The 34-in. offshore line would be 193 miles long.