Pipeline construction mileage expected to be unchanged for 2000 and beyond, despite robust economic forecasts
As 2000 began, Oil & Gas Journal was predicting-for the second year in a row-flat or reduced activity in world pipeline construction, for both near and long-term.
Despite a sustained run-up in world crude oil prices in 1999 and first-quarter 2000, operating companies` plans for petroleum (oil, condensate, and NGL) and natural gas pipeline installation during 2000 reflected almost no change from those announced a year earlier for 1999.
Plans for pipeline construction to begin in or after 2000 and be completed much later actually fell. This prospect was evident despite several long-distance proposals floated whose likelihood Oil & Gas Journal discounted.
With the world`s economies, spearheaded by the churning US economic engine, nearly fully recovered from the downturn of 1997-98, however, some of those visionary projects, especially for Asia, might come into clearer focus, sharpened by growing energy demand.
In terms of economic prospects, a year had made a dramatic difference.
As petroleum markets entered 2000, prices for crude oil in nominal terms were the highest they had been since the Persian Gulf War of early 1991. Prices of oil products were rising, although they hadn`t risen in 1999 nearly as quickly as those for crude oil. And in most regions, prices of natural gas also didn`t climb in step with those of crude oil.
A year earlier, oil prices were abysmal. In January 1999, the International Energy Agency (IEA) forecast world oil-demand growth in 1999 at only 1.5%, a revision from 2% of a month earlier.
But during 1999, the Organization of Petroleum Exporting Countries (OPEC), supported by several non-OPEC producing countries, cobbled together and mostly adhered to a series of production quotas.
Despite the resulting rise in prices of crude oil, oil demand continued to rise. At the start of 2000, IEA said world oil demand would rise to an average 77.3 million b/d from 75.5 million b/d in 1999.
World crude oil prices by February 2000 were fluctuating around $30/bbl, nearly triple their levels of a year earlier.
For 2000, nevertheless, pipeline operating companies projected slightly less than 16,000 miles worldwide of crude oil, petroleum product, and natural gas pipeline construction to be completed. That level was essentially even with what OGJ had reported a year earlier.
Plans for construction beyond 2000 were off by slightly more than 14%.
For 2000 and beyond 2000, therefore, nearly 43,500 miles of crude oil, product, and natural gas pipeline were being planned, off by more than 10% from the combined near and long-term projections of a year earlier (Fig. 1; table).
With economic recovery evident in both Asia and Latin America, however, prospects for many projects OGJ regarded as too problematic to include in its numbers appeared likely to improve. There was even the glimmer of life apparent in a natural gas line from Alaska`s North Slope.
During 2000, major volumes of Canadian natural gas were to begin flowing into the US Midwest, pushing to completion many ancillary projects south of the border. At the same time, gas from offshore eastern Canada was to begin moving in growing volumes to the US Northeast.
The possibility loomed of a surplus of deliverability to those two markets, however, especially if the long-running US economic boom lost steam or weather patterns in the regions continued warmer than historically normal.
Elsewhere, gas grids evolved in both Latin America and Europe.
Bases, costs
For 2000 only, companies indicated plans to complete nearly 16,000 miles of oil and gas pipeline worldwide at a cost of more than $17.6 billion. For 1999 only, companies had predicted nearly 17,000 miles at more than $20 billion.
For projects completed after 2000, companies expected to spend a further $30.2 billion to lay nearly 27,500 miles of line. In 1999, when these companies looked beyond 1999, they expected to lay more than 32,000 miles at a cost of nearly $40 billion.
Combined projected expenditures for oil and natural gas pipelines in 2000 and later were set at $47.8 billion.
Projections for 2000 pipeline mileage reflected only projects expected to be completed by yearend, including construction in progress at the first of the year or set to begin during it.
Projections for mileage in 2000 and beyond included construction that might have begun in 2000 but would be completed in 2001 or later. A few long-term projects that OGJ judged as probable were included even if they would break ground in 2001 or later.
Cost estimates were based on U.S. average costs per mile for onshore and offshore gas-pipeline construction as found in OGJ`s Pipeline Economics Report.
The installment of that report immediately before the pipeline survey detailed pipeline-construction filings during the 12 months ending June 30, 1999, and implied these near-term prospects for specifically gas-pipeline construction on the U.S. interstate system:
- Nearly 900 miles of land pipeline were proposed in 39 projects, compared with almost 2,800 miles for the 12 months before June 30, 1998. No offshore projects were proposed for US waters under federal jurisdiction.
- Nearly 234,000 hp of new or additional compression were applied for, compared with more than 550,000 hp for the same period the year before.
For the 12 months ending June 30, 1999, the 39 land projects would cost more than $979 million.
For proposed US gas-pipeline projects in the 1998-99 period surveyed, the average land cost was slightly more than $1.1 million/mile. For the 1997-98 period, the average land cost was slightly less than $1.2 million/mile.
OGJ`s cost 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 (14,832 miles) for 2000 only will cost $16.3 billion.
- Total offshore construction (1,158 miles) for 2000 only will cost more than $1.3 billion.
- Total onshore construction (25,813 miles) for beyond 2000 will cost $28.4 billion.
- Total offshore construction (1,604 miles) for beyond 2000 will cost nearly $1.8 billion.
North American picture
In 2000, Alliance Pipeline was to begin flowing gas and associated liquids through its massive high-pressure system from northeast British Columbia, across Alberta and Saskatchewan, to near Chicago. It was one of the most important gas-pipeline projects built in North America since the first lines linked Canadian producers and US markets.
The Alliance project reconfigured the Alberta gas-transportation picture, led to the merger of the nation`s two largest gas pipeline companies, and-most significantly-relieved bottlenecks preventing large volumes of Canadian gas from reaching US markets.
And on the downstream end of the system, companies were scrambling to receive approval for or install transportation infrastructure associated with Alliance.
Millennium Pipeline would extend 440 miles from Lake Erie, at a point on the Canada-US border, to Mount Vernon, NY. It was to link Canadian and US supplies with growth markets in the US Northeast and mid-Atlantic.
Upstream of Millennium, several projects were proposed and were under review early in 2000 by the US Federal Energy Regulatory Commission (FERC) to take volumes from Alliance. These included the TriState Pipeline from near the Aux Sable gas plant in Illinois, terminus for Alliance, to connect with TransCanada PipeLines`s (TCPL) proposed Lake Erie crossing, and ultimately Millennium, to Pennsylvania and points east.
The Independence Pipeline, a venture of a unit Williams, Coastal, and National Fuel, would build 370 miles of 36-in. pipeline from western Ohio to Pennsylvania.
The related MarketLink project was to be a 42 and 36-in. expansion of Williams` Transco system in Pennsylvania and New Jersey. Construction was to be complete by the fourth quarter of 2000.
Another project to bring Canadian gas to the US Midwest was the Vector Pipeline, a venture of Enbridge Inc., Calgary, and MCN Energy Group Inc., Detroit. Construction of the 360-mile line in the US and Canada began soon in 1999.
Yet another project growing out of the terminus of Alliance south of Chicago was the Atlantic Alliance Pipeline, envisioned to carry up to 735 MMcfd to New York, Pennsylvania, and New England.
It would use existing facilities and ROW and targeted full deliverability by Nov. 1, 2001. The project is a joint venture of El Paso Energy Corp. unit Tennessee Gas Pipeline Co. and Consolidated Natural Gas Co. unit CNG Transmission Corp.
Also in late 1999, Guardian Pipeline project partners applied to the FERC to build and operate a 147-mile, 36-in. interstate gas line with interconnection near Jolliet, Ill., with Alliance, Northern Border Pipeline, Midwestern Gas Transmission, and Natural Gas Pipeline of America to northern Illinois and southern Wisconsin.
Capacity on Guardian was slated for 750 MMcfd with possible expansion to 1.1 bcfd. Cost was estimated at $230 million.
On the western side of North America and to move more Western Canadian Sedimentary basin (WCSB) gas, BC Hydro, Vancouver, and Williams Gas Pipeline, wanted to build an 84-mile link of Northwest Pipeline at Sumas, Wash., to Vancouver Island. The project would initially move gas to industrial and residential customers.
The Georgia Strait Crossing was to be a 32-in. and 16-in. line to move gas from Sumas, Wash., to Cherry Point, Wash., in an established utility corridor.
From Cherry Point, the line would travel 44 miles across the Strait of Georgia, through Boundary Pass and the Satellite Channel in water depths of up to 1,200 ft. Approximately 23 miles of pipe would be in Canadian waters, and 21 miles in US waters.
The line would come ashore on Vancouver Island north of Mill Bay and travel inland about 8 miles to connect with the Centra Gas Transmission System near Shaw Lake.
Additional compression would be installed at the existing Sumas compressor station and an additional compressor facility on either the US mainland or Vancouver Island.
Still under regulatory review as 2000 began, the $120 million project would begin construction during summer and fall 2002 with completion set for November 2002. Williams would be operator. Capacity was projected to be 85 MMcfd.
Florida, Alberta
Elsewhere in the US, Florida Gas Transmission Co. in late 1999 filed for Phase V approval from the FERC of the 4,800-mile system.
This would consist of 231 miles and an additional 90,000 hp of compression at a cost of $438 million. The new pipeline and equipment would be in service by spring 2002.
Competition for gas to serve the growing Florida power market began heating up in 1999.
Two projects were proposed to move gas from, roughly, Mobile Bay across the Gulf of Mexico to near Tampa and inland to power plants.
Buccaneer Gas Pipeline Co. LLC, a unit of Williams wanted to lay 420 miles of large diameter line from the Williams Gas Pipeline-Transco Compressor Station 82 in Coden, Ala., to north of Tampa. Service was to begin in April 2002.
Coastal Corp. planned the Gulfstream Natural Gas System to stretch 700 miles from near Mobile Bay to Palm Beach, Fla. Target in-service date was June 2002.
Also in the US South, Carolina Power & Light and the Albemarle-Pamlico Economic Development Corp. (APEC) planned to build an 850-mile gas line and distribution system to eastern North Carolina.
CP&L planned to lay 600 miles of transmission line, ranging from 4 to 12 in., and 250 miles of distribution line in five phases. APEC said it anticipated a North Carolina Utilities Commission order by June 2000.
Elsewhere in North America, the Corridor pipeline in northern Alberta was moving ahead. It was a 306-mile, 12 and 24-in. part of the Alberta Athabasca oil sands project undertaken by Shell Canada Ltd. with Western Oil Sands Inc. and Chevron Canada Resources. Target date for operation was 2002.
The system would move diluted bitumen from the Muskeg River mine to an upgrader adjacent to Shell`s Scotford refinery near Fort Saskatchewan, Alta. Cost of constructing the pipeline and tankage was estimated at $600 million (Canadian). The pipeline was to be operated by BC Gas subsidiary TransMountain Pipeline Co. Ltd.
A 24-in. line would move 215,000 b/d to the upgrader; a 12-in. return line would transport 65,000 b/d of solvent to the Musket River mine. A 20-in. line was to transport 95,000 b/d of synthetic crude oil from the upgrader to terminals in the Edmonton-Strathcone, Alta., area. A 16-in. return line would move 8,000 b/d of supplementary feedstock to the upgrader.
Latin American network
Major natural gas networks began flowing gas in 1999 as South America moved closer to energy integration.
Early in the year, the $2 billion, 1,978-mile Bolivia-Brazil natural gas export pipeline was dedicated by officials from Bolivia and Brazil.
The line consists of 464 miles in Bolivia from Rio Grande and passes throughPuerto Suarez on the border with Brazil.
It then extends to the Brazilian town of Corumba and crosses the states of Mato Grosso do Sul, Sao Paulo, up to the city of Campinas and on to Parana and Santa Catarina states, terminating at Porto Alegre, the capitalofRio Grande do Sul state.
Capacityfor Bolivian gas is 8 MMcmd to move to southernBrazil, expandable to 16 MMcmd.
The project was considered a cornerstone of efforts to establish an energygridinthe SouthernCone nationsof South America.If,for example,Boliviansuppliesproved unequal in volume or timing to meet demand in Brazil, gas in northern Argentina could be moved through a reversed line to Bolivia and on to the new line to Brazil.
Elsewhere from Argentina, Gasoducto Cruz del Sur SA, a 50-50 venture of BG PLC and Pan American Energy LLC, planned to move gas between Buenos Aires and Montevideo and ultimately Brazil.
The trunkline from Colonia, Argentina, would be 100 miles of 18-in. OD pipe, with laterals to feed several cities. The laterals would consist of 77 miles of 3-18 in. OD pipe. The line was to become part of an intended 528-mile, 24-in. line to Brazil via Uruguay.
On the western side of the continent, two more systems tapping Argentine gas began moving supplies into Chile.
In the north, Gasoducto Atacama Cia. Ltda. (GasAtacama) was completed, a 300-MMcfd, 584-mile, 20-in. natural-gas pipeline from Argentina to Chile. It became the second line to bring Argentine gas to Chile; GasAndes started up in August 1997, supplying gas to Santiago.
GasAtacama is a joint venture of four companies, including major shareholders CMS Energy Corp., Dearborn, Mich., and Chilean power generator Endesa, Santiago, each with 40%. Remaining ownership is split between two Argentine gas producers: Pluspetrol Energy, 16%, and Astra, 4%.
The pipeline transports gas from gas fields in Argentina`s Noreste basin, near Salta, to Mejillones, Chile. Total cost of the pipeline and power plant near Mejillones was estimated in 1998 to run $750 million.
A portion of the gas shipped to Mejillones was to be transported farther 160 miles south to a 350-Mw plant Endesa was building at Taltal, Chile.
In the south of Chile, construction of the 335-mile Gasoducto del Pacífico from Loma de la Lata in Argentina`s Neuquén Province to Concepción-Talcahuano, in Region VIII, was supplying natural gas to the communities of Concepción, Talcahuano, Coronel, Penco, and Lirquen.
Gasoducto del Pacífico shareholders are TransCanada International, Calgary (30%), Gasco (Chile, 20%), El Paso International (US, 21.8%), ENAP (Chile, 18.2%), and YPF (Argentina, 10%).
Total investment in GasPacífico amounted to $317 million (US), divided between investment in Argentina ($127 million) and Chile ($190 million).
Initial capacity of the pipe was 3.8 MMcmd.
In the Mexican Yucatan peninsula, another TCPL project, Energía Mayakán, started up in late 1999. The 435-mile, 24-in. line is capable of moving 370 MMcfd of gas from Ciudad Pemex, Tabasco, to power plants in Campeche and Yucatan.
Russian work
A flurry of rehabilitation work was under way in early 2000 and scheduled to start as Russia tried to bring its leaky oil and gas pipelines up to the standards of Europe and North America. Financing woes forced many of these projects to jump between active and on-hold. Delays were chronic.
But a couple of major projects did make substantial progress in 1999.
Russian gas transmission company Gazprom finished Phase 1 of the Yamal-Europe transcontinental gas pipeline project.
The 4,000-km pipeline was to carry gas from the Yamal Peninsula region of western Siberia through Belarus and Poland and into eastern Germany, where it connected with the Western Europe gas grid.
Gazprom began the first phase of the Yamal-Europe project by debottlenecking its existing gas pipeline network and adding new sections. The system`s capacity reached 30 billion cu m/year.
The Polish section began flowing in November 1999. Gazprom planned to route 14 bcm/year of gas through Poland. Gas deliveries to Poland were likely to double in a few years.
The company planned to increase gas exports by up to 45 bcm/year by 2010.
Elsewhere in Russia, work progressed on the 40-42 in., 900-mile crude oil pipeline from the western Kazakhstan Tengiz oil field to the Russian port city of Novorossiisk on the Black Sea. The line traversed the Astrakhan Oblast and the Kalmykia, Stavropol, and Krasnodar Krais. Completion was expected by mid-2001.
In late 1999, the Caspian Pipeline Consortium (CPC) began laying pipe for the 450-mile section from Komsolmoskya, Russia, to Novorossiisk.
CPC equity interest holders are Russia, 24%; Kazakhstan, 19%; Chevron Caspian Pipeline Consortium Co., 15%; Lukarco BV, 12.5%; Rosneft-Shell Caspian Ventures Ltd., 7.5%; Mobil Caspian Pipeline Co., 7.5%; Oman, 7%; Agip International (NA) NV, 2%; BG Overseas Holdings Ltd., 2%; Kazakhstan Pipeline Ventures LLC, 1.75%; and Oryx Caspian Pipeline LLC, 1.75%.
A 40-in. system with pumping ran from Tengiz around the north of the Caspian Sea to Komsomolskya. From there, said CPC officials in late 1999, a new pumping station and a 40-in. line would be built as far as Kropotkin and another pump station. From Kropotkin to the coast, the line would be expanded to 42 in.
Injection points and metering were to be at Tengiz, Atyrau, Komsomolskya, and Kropotkin for crude oil dedicated to the export markets. Initial capacity would be 28.2 million tonnes/year slated to flow by June 2001; maximum capacity would be 67 million tonnes/year.
Overall budget for the initial construction segment was $2.4 billion.
At the marine terminal were to be built four 100,000-cu m crude oil-storage tanks and a 56-in. onshore loading line. Two more offshore loading lines (42-in. each) together with single point mooring systems also were planned.
The pipelines would consist of 258 km of 42 in., 480 km of 40 in., 5.7 km of major drilled river crossings, and 47 isolation valve installations. And new pump stations were to be installed at Kropotkin and Komsomolsk along with refurbishment of the existing station at Astrakhan.
CPC said it expected tank and other construction to be fully under way in 2000 and predicted first oil loading for June 30, 2001, with mechanical completion of the tank farm by Dec. 1, 2001.
Another oil line in the region was finished in 1999. Early oil was flowing from the Chirag field in the Caspian Sea along the 115,000 b/d, 830-km line from Sangachal, near Baku, to Supsa, Georgia, on the Black Sea.
In northeastern Europe, an ambitious plan was conceived to provide crude-oil export capabilities in the Baltic region for Russia`s production from Timan-Pechora and western Siberia.
The Baltic pipeline system would consist of existing operating pipelines as core facilities into which would be integrated a new pipeline at the eastern supply point and an extension of its western terminals in Primorsk and Porvoo on the coast on the Gulf of Finland.
The new facilities were required from Kharyaga to Usa in the east, which would be connected to the existing pipelines Usa-Ukhta (720 mm, 427 km), Ukhta-Yaroslavl (820 mm, 1,135 km), and Yaroslavl-Kirishi refinery (720 mm, 520 km), the western terminus.
To accommodate the export volumes, missing sections of a second line would loop the existing Yaroslavl-Kirishi refiner segment and extend to the Kirishi pump station.
From Kirishi pump station, the pipeline would be built northwest to the proposed Port of Primorsk terminal, and from there the new line would continue to the Finnish border and thence to the Port of Porvoo in Finland.
A new Kharyaga-Usa pipeline would have a capacity of 254,000 b/d in a 530-mm line with one intermediate pump station. Without an intermediate station, a 610-mm line would have capacity of 308,000 b/d.
After looping of the 720-mm Yaroslavl-Dirishi refinery segment, capacity would reach 650,000 b/d. The new Kirish-Primorsk line would be able to carry 260,000 b/d. The 226-km segment to Porvoo from Primorsk would also carry 260,000 b/d.
Total cost of the project, as estimated in late 1999 by Gulf Interstate Engineering, Houston, and including pipeline and terminal work, was to reach $763 million.
Oil production from the Timan-Pechora region was forecast to peak in 2005 at 258,000 b/d; the Kharyaga-Usa segment was to be designed for this throughput.
The western segment, Kirishi-Primorks-Porvoo, would be designed to export 240,000 b/d. During construction of the Primorsk terminal, the pipeline between Yaroslavl and Primosk was to be expanded to accommodate the throughput committed to Primorsk for export.
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Pipelaying for the Bolivia-Brazil pipeline was completed in 1999. Here lowering-in progresses through the environmentally sensitive Pantanal region. Photo courtesy of Halliburton Co., Dallas.
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Construction of Alliance Pipeline in the US made major strides in 1999 as work progressed toward completion of the project around mid-2000. Photograph from Alliance Pipeline Ltd., Calgary.
