THE GLOBAL SURPLUS THAT SUPpressed oil prices in 1998 reduced plans for new pipeline construction for 1999 and beyond.
More than 48,700 miles of crude oil, product, and natural-gas pipeline were planned, according to Oil & Gas Journal`s survey of world pipeline operators, industry sources, and published information.
For 1999 only, companies indicated plans to complete more than 16,000 miles of oil and gas pipeline worldwide at a cost of more than $20 billion. For projects completed after 1999, companies expected to spend a further $39.8 billion to lay more than 32,000 miles of line.
Projections for 1999 pipeline mileage reflected only projects expected to be completed by year-end, including construction in progress at the first of the year or set to begin during it.
Projections for mileage in 1999 and beyond included construction that might begin during the year but be completed later. Some probable long-term projects were included even if their sponsors planned to break ground in 2000 or later.
Construction costs
Cost estimates were based on U.S. average cost per mile for onshore and offshore gas-pipeline construction as found in Oil & Gas Journal`s 1998 annual Pipeline Economics report.
Cost projections assumed, based on historical analysis, that 90% of all construction would be onshore and 10% offshore. Pipelines of 32 in. OD or larger were assumed to be onshore projects.
For the period July 1, 1997, to June 30, 1998, there were 34 land-pipeline construction projects and 2 marine projects proposed to the U.S. Federal Energy Regulatory Commission or Canada`s National Energy Board.
Operators estimated that the 34 land projects would cost more than $3.4 billion. Combined land and marine construction proposed was almost 2,800 miles.
The projects` cost projections indicate much about where companies believe unit construction costs ($/mile) are headed. Moreover, these cost-per-mile figures reveal more about cost trends than aggregate totals.
For proposed gas-pipeline projects in the 1997-98 period surveyed by Oil & Gas Journal, the average land cost per mile was more than $1.2 million (U.S.)/mile. For the 1996-97 period, the average land cost per mile was slightly less than $1.2 million.
For the period ending June 30, 1998, the two marine projects (106.5 miles) proposed averaged more than $1.5 million/mile. For the 12 previous months, the 204 miles of planned offshore pipeline amounted to an average cost of $830,000/mile.
Year-to-year variations in the four major categories of pipeline construction costs-material, labor, miscellaneous, and right of way (R.O.W.)-can also suggest trends within each group.
Materials can include line pipe, pipe coating, cathodic protection, and telecommunications equipment.
"Miscellaneous" costs generally cover surveying, engineering, supervision, contingencies, allowances for funds used during construction (afudc), administration and overheads, and regulatory filing fees.
R.O.W. costs include obtaining right of way and allowing for damages.
For the 34 land and 2 offshore projects surveyed for the 1997-98 period, costs per mile for the four categories were as follows:
- Material-$493,480/mile.
- Labor-$504,566/mile.
- Miscellaneous-$219,008/mile.
- R.O.W. and damages-$34,592/ mile.
In general, cost per mile within a given diameter indicates that the longer the pipeline, the lower the unit cost for construction. And broadly, lines built near populated areas tend to have higher unit (per-mile) costs than those farther away.
Additionally, the need for road, highway, river, or channel crossings and the presence of marshy or rocky terrain strongly affect pipeline construction costs.
Material and labor for constructing land pipelines make up more than 79% of the cost for the period ending June 30, 1998. For offshore projects, material and labor make up more than 83%.
North American events
In 1998, two of North America`s largest pipeline companies merged as a by-product of wrangling over one of the region`s most significant projects in years, the 1,900-mile Alliance dense-phase gas pipeline from Alberta to near Chicago. That project was under way in 1999.
In addition, the U.S. Energy Information Administration (EIA) noted the rapid growth of the U.S. gas-pipeline grid in the decade and forecast more of the same.
U.S. trends
Throughout the 1990s, Oil & Gas Journal reported that North American, especially U.S., pipeline companies had plans to add hefty new capacity. Those forecasts were borne out in a report in 1998 from EIA.
It stated that the U.S. pipeline industry`s capacity to move gas reached more than 84 bcfd in 1997, up 15% over installed capacity reported in 1990. By 1996, gas shipments had increased 24% from 1990 levels with a record 75% utilization of installed capacity.
The agency expected bottlenecks for moving new offshore production beyond onshore Louisiana. But these potential bottlenecks could be partially or completely offset by planned new or expanded underground storage facilities.
EIA also noted significant changes in traditional patterns of gas movement since 1990.
Gas from western and Rocky Mountain producing areas was increasingly moving away from western markets, and key pipeline projects had been built or were planned to accommodate the shifts.
The most extensive development of new pipeline capacity during the following several years, said EIA, would occur along corridors connecting Canada to U.S. Midwest and Northeast markets to handle ever-growing Canadian imports.
Among these was the corridor under development for gas from the Sable Island fields off the Canadian East Coast. Expansions could add as much as 8.6 bcfd to U.S. import capacity from Canada by 2001.
EIA predicted U.S. gas-pipeline development and expansions could add as much as 16 bcfd of capacity during 1999-2000, at a total cost of about $9.5 billion.
EIA said that, while more than 11 bcfd of capacity was added to the U.S. transmission network in 1998, costs were relatively low at $2.9 billion, compared with $3.1 billion projected for 1999 and $6.3 billion for additions in 2000.
The growth of Canadian gas flows to the U.S. Midwest was expected to increase use of the Chicago hub market center as a transshipment point for supplies en route to a growing gas market in the U.S. Northeast. A market center near Leidy, Pa., where several pipelines serving the Northeast interconnect, also was likely to grow.
EIA said the pipeline growth was primarily the result of growing demand for gas as fuel for electric generating plants replacing coal and oil-fired units.
Since 1990, gas use for power generation had grown 17%/year in the Midwest and about 9%/year in the Southeast. Gas use for generation grew less than 1%/year in the Southwest but accounted for more than 22% of all gas consumed there.
Canadian mergers
A year of mergers, 1998 saw the combination of NOVA Corp. and TransCanada PipeLines Ltd., Canada`s two largest pipeline companies. The merged company became at mid-year 1998 the fourth largest energy services company in North America with a combined network of nearly 22,500 miles.
NOVA`s Alberta pipeline unit became part of a wholly owned unit of TransCanada.
Consistent with EIA forecasts was the flurry of construction under way or planned to increase Canadian capacity to move gas south.
In early 1999, the $3.7 billion (Canadian) Alliance Pipeline began construction of its 1,864-mile dense-phase line between Alberta and the U.S. Midwest. Planned completion was October 2000. Alliance had contracts to move up to 1.3 bcfd of gas.
Other major export systems out of Alberta were also in the process of expanding capacities to U.S. markets.
Northern Border Pipeline Co., Omaha, Neb., expanded by 700 MMcfd its 1,213-mile, 1,675 MMcfd system with 390 miles of 36 and 30-in. and added 303,500 hp of compression at a cost of $839 million.
TransCanada let $430 million (Canadian) in pipeline maintenance, looping, and compressor-station construction contracts for 1999 work.
And it wanted to build a $161.8 million (Canadian), 61-mile, 36-in. line across Lake Erie to move gas to U.S. Northeast and Mid-Atlantic markets. The company would connect at St. Clair, Ont., with the planned 442-mile Millennium Pipeline in the U.S.
Initial capacity of the new line would be 700 MMcfd. Both Lake Erie Crossing and Millenium were expected to be in service by Nov. 1, 2000.
The $650 million project was to begin at the Canadian border on Lake Erie and extend across southern New York state to Westchester County, making more than 30 connections to utility customers, pipelines, and gas-storage facilities.
From the east
On the eastern side of the continent, Maritimes & Northeast Pipeline Ltd. Partnership began to lay a 350-mile pipeline from Goldboro, N.S., to St. Stephen, N.B., to move Sable Island gas to Atlantic Canada and the U.S. Northeast. First gas was scheduled to flow by fourth quarter 1999.
Maritimes & Northeast also planned laterals to Halifax, N.S., and St. John, N.B.
The Halifax lateral was to be 75 miles of 12-in. line from a main line near Stellarton, N.S., to a power-generating station at Tufts Cove. Estimated cost of the lateral was $74 million, and volume would be 60 MMcfd.
The St. John lateral was to be 63 miles of 16-in line from Maritimes & Northeast`s main line to St. John at a cost of $91 million to move nearly 131 MMcfd.
Both laterals were due in service Nov. 1, 1999.
In other Canadian activity, Enbridge Inc., Calgary, (formerly Interprovincial Pipe Line Ltd.) planned to begin natural-gas shipments to the Chicago area by October 2000 on the $471-million (U.S.) Vector Pipeline system.
Construction of the 344-mile line from Chicago to Dawn, Ont., near Sarnia, was to be completed in mid-2000. The line would have capacity of 1 bcfd into Chicago and would interconnect with the Alliance pipeline project from Western Canada and an extension of the Northern Border Pipeline system.
U.S. action
In a project related to Alliance and south of the Canadian-U.S. border, four U.S. natural-gas companies planned to develop a major pipeline for delivering gas to U.S. Midwest markets.
The $220-280 million Illinois-Wisconsin Express Project would move gas from Western Canada and major U.S. supply basins.
The project was to be a 36-in., 150-200 mile pipeline from Joliet, Ill., near Chicago, to near Fond du Lac, Wis. The pipeline was scheduled to be in service by November 2001 with initial capacity of 650 MMcfd.
The U.S. Gulf Coast remained a hotspot for gas-line construction plans.
Koch Gateway Pipeline Corp., Houston, planned to expand with an interconnection near Grand Isle, La., and possibly double capacity in a second phase.
Koch would lay about 5 miles of 20-in. lateral line to connect its 36-in. Gulf Coast main line to a processing plant near Grand Isle. This would add 300 MMcfd of capacity. In a second phase, Koch would increase capacity by an additional 300 MMcfd by looping and compression.
Koch`s plans would complement the planned Sea Star Pipeline LLC project adding 600 MMcfd from the South Pass Area and West Delta South Addition to processing at Grand Isle.
Columbia Gulf Transmission Co. was to lay the 56-mile, 660-MMcfd gas line and expand its East Lateral system in southeastern Louisiana by 600 MMcfd.
Also in the area, newly formed Tri-States NGL Pipeline LLC planned to build an NGL pipeline from Alabama and Mississippi to plants in Louisiana. The line would have an initial capacity of 80,000 b/d and final of 150,000 b/d.
The pipeline was to link three gas-processing plants under construction to new and expanded fractionation plants on the Mississippi River.
Williams Cos., Amoco Oil Co., and Enterprise Products Operating LP formed Wilprise Pipeline Co. LLC, a joint venture to build a 30-mile, 12-in., 100,000-b/d pipeline to deliver NGL from Kenner, La., to storage facilities in Sorrento, La. Kenner was to be the terminus of Tri-States Pipeline.
Williams subsidiary Mid-America Pipeline Co. completed at the beginning of fourth quarter 1998 expansion to 125,000 b/d of its NGL pipeline system in the Rocky Mountains. Mapco built a 412-mile pipeline from northeast Utah`s Daggett County to Bloomfield, N.M.
European grid
Natural gas began moving from the U.K. to Europe via the Interconnector pipeline between the Bacton terminal and the Zeebrugge terminal in Belgium. The $725-million, 150-mile, 40-in line can deliver 700 bcf/year of gas to Europe.
Also, Norway`s Statoil and partners began moving gas through the $1 billion, 522-mile, 42-in. Norfra gas line linking Europe via Loon Plage, France, near Dunkerque, to the Troll field off Norway.
The line accounted for 30% of France`s gas imports, was the country`s first direct link to a foreign producing natural-gas field, and bolstered its position as a major distribution hub in Europe`s newly liberalized natural-gas market.
The landing terminal in France, owned 65% by the Norfra group and 35% by Gaz de France (GdF), can treat up to 50 million cu m/day (MMcmd).
To distribute the additional gas supplies, GdF invested 1 billion francs to construct one of France`s largest gas pipelines, the 115-mile, 44-in. Artère des Hauts-de-France. It links the Dunkerque terminal to GdF`s transmission system near the underground storage terminal at Gournay-sur-Aronde, France.
In addition, to move gas that has crossed France for other markets, the Les Marches du Nor-Est gas pipeline was planned to traverse Switzerland on its way to Italy. Half the gas coming from Norway would transit GdF`s network to Spain and Italy, said GdF.
By 2005, France would be receiving an estimated 15 billion cu m/year (bcmy) of gas from Norway-about one third of French gas demand.
At that time, Norway would be France`s leading natural-gas supplier, ahead of Russia and Algeria. And France would become Norway`s second largest gas importer, behind Germany`s Ruhrgas.
For its part, Norway had developed an aggressive plan to increase gas exports. By 2005, it was to be exporting to continental Europe an estimated 75 bcmy of gas, up from 42.3 bcm in 1997.
If needed, according to Statoil, Norway`s five gas pipelines could be expanded with additional compression to ship 100 bcmy.
Latin American network
The dream of a South American gas network took a step toward reality in 1999 with completion of a system connecting Bolivia and Brazil and of two pipelines for moving Argentine gas to Chile.
Government figures and representatives of private industry met in February to dedicate the $2 billion, 1,978-mile Bolivia-Brazil natural-gas export pipeline. The line, with 464 miles to be built in Bolivia, starts from Rio Grande, Bolivia, and passes through the Bolivian town of Puerto 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 capital of Rio Grande do Sul state.
It is designed to transport 8 MMcmd of Bolivian natural gas to southern Brazil. Pipeline capacity might be expanded to 16 MMcmd, depending on market demand.
Argentina, with an estimated 35 tcf of gas reserves, was Bolivia`s most serious competitor for gas markets in Brazil.
But more than 32 tcf would be required over 20 years to meet Argentine demand and to provide exports to Chile. Two projects along this avenue of export began moving gas in 1999.
In the north of Chile, Gasoducto Atacama Cia. Ltda. (GasAtacama) laid a 300-MMcfd, 584-mile, 20-in. natural-gas pipeline from Argentina to Chile. It was the second line to bring Argentine gas to Chile; GasAndes started up in August 1997 supplying gas to Santiago and environs.
The pipeline transports gas from fields in Argentina`s Noreste basin, near Salta, to Mejillones, Chile. Total cost of the pipeline and power plant near Mejillones was estimated at $750 million.
A portion of the 127 MMcfd of gas shipped to Mejillones would be transported further south to a 350-MW power plant Endesa was building at Taltal, Chile. The 160-mile Gasoducto Taltal extension was expected to cost $30 million but had been on hold.
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 by year-end 1999 was to supply natural gas to the communities of Concepción, Talcahuano, Coronel, Penco, and Lirquen.
With second-phase start-up in April 2000, gas would flow to Laja, Los Ángeles, Nacimiento, Lota, Escuadrón, and Arauco.
Total investment in GasPacífico amounted to $317 million (U.S.) divided between investment in Argentina ($127 million) and Chile ($190 million). Initial capacity of the pipe was 3.8 MMcmd (approximately 134 MMcfd).
In another direction, Gasoducto Cruz del Sur SA, a 50-50 venture of BG plc and Pan American Energy LLC, still planned the Buenos Aires-to-Montevideo pipeline. The trunk line from Colonia, Argentina, is 100 miles of 18-in. OD pipe, with laterals to feed several cities. The laterals consist of 77 miles of 3-18 in. OD pipe. The line is part of an intended 528-mile, 24-in. line to Brazil via Uruguay.
Elsewhere in Latin America, the big story in Mexico was the progress made in installing distribution in the country`s major cities.
Kicking off one of the largest privatization projects of its kind in the world, Mexico`s Comisión Reguladora de Energía awarded in 1998 rights to distribute natural gas in Mexico City and the adjacent Valle Cuautitlán-Texcoco region.
Future areas for natural-gas distribution included the El Bajío region, a fast-growing industrial area northwest of Mexico City, Tijuana, Cuernavaca, Puebla, Guadalajara, and the La Laguna region around the cities of Gómez Palacios and Torreón.
Also in Mexico, in the southern states, by fourth quarter 1999 a major new pipeline was to be flowing gas to power generators serving industrial and residential consumers in the Yucatan Peninsula of Mexico.
The project was the first major installation by a consortium whose majority stakeholder was from outside Mexico.
The Yucatan Peninsula gas pipeline was to move gas from a processing plant in the Mexican state of Tabasco to several power plants in the Yucatan Peninsula and to other customers along the pipeline.
The pipeline would be approximately 410 miles long with an initial capacity of 7.4 MMcmd (261.2 MMcfd), increasing to an ultimate capacity of 10.5 MMcmd.
Total initial investment in the pipeline, according to Energía Mayakán S. de R.L. de C.V., the consortium building it, was to be $260 million (U.S.), growing to $276 million by 2004.
The pipeline would receive natural gas at Ciudad Pemex, the gas plant operated in the state of Tabasco by Pemex Gas y Petroquímica Básica, and deliver it to several power plants in the states of Campeche and Yucatan and to other customers along the pipeline.
The power plants were being converted from fuel oil. Conversion of approximately 655 MW of existing power generation to natural gas had taken place along with construction of 855 MW of new natural gas-fired power generation.
Asian changes
Sagging energy demand and prices cast a pall over what had been a healthy burst of pipeline plans for Asia. Projects related to the hot exploration and development plays around Thailand were being re-examined and in many cases delayed in the light of currency uncertainties and energy-demand weakness.
Thailand`s Petroleum Authority of Thailand (PTT) slashed $1 billion from its planned gas-pipeline investment. Weakened demand was behind the group`s decision.
Thailand`s demand growth rate for natural gas dropped to 10%/year in July 1997 to 5%/year by late 1998.
In China, however, the prospects seem somewhat brighter even if fruition appeared no nearer.
China`s total estimated gas resource at year-end 1998 was 38 trillion cu m with proven reserves of only 1.5 trillion cu m. In 1997, the country`s gas production was only 21 bcm. It targeted by 2010 a gas-production level of 72 bcm and 95 bcm in 2020.
To support such production goals, China aimed to develop a national grid capable of moving 150 bcmy. And it intended to develop storage capacity of 15-17 bcm.
The gas could be supplied by pipeline from Russia and Central Asia. Of the projected volume of 30 bcm in 2010, 20 bcm would arrive by pipeline and 10 bcm as LNG.
In 2020, gas imports were projected to reach 60 billion, of which 40 bcm would be by pipeline and 20 bcm as LNG.
Ambitious plans were afoot for oil lines in China, specifically petroleum products.
China National Petroleum Corp. wanted to lay two long-distance refined products pipelines in northeastern China and southwestern China. The first, a 621-mile, 426-mm line, would be completed in 2010 to eliminate a long-standing transportation bottleneck in northern China.
The latter, either 559 miles or 714 miles depending on origin, would move 200,000 b/d to ease supply shortages in southwestern China, where there were no refineries.
These two projects addressed the larger problem of China`s lack of a refined products system. The combined length of products lines in 1998 was only 1,067 miles. The longest line, a 671-mile line from Golmud to Lhasa, had a capacity of only 29,000 b/d.
The country moved 70% of its products by rail, 21% by road, 8% by barge or tanker, and only 1% by pipeline.
On the western borders of Asia, companies and governments maneuvered to find some middle ground between economics and politics in projects to export oil from Central Asia and the Caspian Sea.
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The Dawei River bridge is one of 18 bridges along the service track of the Yadana gas-pipeline project in Myanmar and Thailand. The 36-in., 254-mile subsea and cross-country pipeline started up in 1998 delivering gas to Thailand from the Yadana field offshore Myanmar. Photograph courtesy of Total Myanmar Exploration & Production, Singapore.
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Construction advances along rocky right of way in the Mexican states of Yucatan and Chiapas as the Yucatan Peninsula gas pipeline progresses toward September 1999 start-up. The 410-mile, 16, 22, and 24-in. line was to deliver 3.45 million cu m/day of gas on start-up primarily for electric-power generation in the Mexican states of Tabasco, Chiapas, Campeche, and Yucatan. Photograph courtesy of TransCanada PipeLines Ltd.
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In major and ongoing rehabilitation work along the Trans-Alaska Pipeline, a main line valve is lifted from its site near Delta Junction to be analyzed for sealing problems. The 29-hr operation shut down the pipeline at the end of September 1998. Photograph by David Predeger, courtesy of Alyeska Pipeline Service Co.
