World pipeline construction looks to remain robust to century's turn

Construction advanced last year on the 214-mile, 20-in. TransGas de Occidente SA project in Colombia. Start-up is set for second quarter this year. Photo courtesy of TransCanada PipeLines Ltd.

Sidebooms maneuver concrete-coated, 24-in. pipe for Express Pipeline's crossing of the South Saskatchewan River in southern Alberta. Pipe for the entire 784 mile project from Hardisty, Alta., to Casper, Wyo., was laid by yearend. Start-up will occur by mid-1997. Photo by Paul Connor, Calgary.

Near-term prospects, although less promising for 1997 than a year ago for 1996, also suggest continuing strong construction activity.

These scenarios are driven by steady growth in worldwide demand for crude oil, natural gas, and petroleum products.

As has been the case for several years, demand for natural gas, especially in developing regions and for use in power generation, lies behind several major projects.

In Canada, a major restructuring of pipeline transportation got under way in 1996, pushed by western Canadian gas producers' desire to gain access to strong U.S. Midwest demand. This U.S. Midwest demand, coupled with strong markets in the U.S. Northeast, also has pushed several gas gathering projects in the Gulf of Mexico.

Gas-pipeline projects in Latin America and Europe will move ahead this year and later as those areas' economies demand more but cleaner energy.

The latest OGJ pipeline construction data evince these trends and derive from a survey of world pipeline operators, industry sources, and published information.

More than 71,000 miles of crude oil, product, and natural gas pipeline are planned for 1997 and beyond, a jump from plans set a year ago. Construction expected to conclude by yearend, however, is less than comparable plans in place last year.

For 1997 alone, companies expect to complete more than 18,000 miles worldwide at a cost of $17.4 billion. For 1996, companies had predicted more than 21,000 miles at a cost of nearly $13.7 billion.

For projects completed after 1997, companies expect to spend another $50.6 billion to lay more than 53,000 miles of line. Last year, when these companies looked beyond 1996, they had expected to lay more than 45,000 miles at a cost of $29.2 billion.

Projections for 1997 pipeline mileage reflect 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 1997 and beyond include construction that might begin this year but will be completed in 1998 or later. Some probable long-term projects are included even if their sponsors will break ground after 1998.

Cost estimates are based on U.S. average cost per mile for onshore and offshore gas pipeline construction as determined by OGJ's most recent annual pipeline economics report (see Table 4, OGJ, Nov. 25, 1996, p. 46).

Cost projections assume 90% of all construction to be onshore and 10% offshore. Pipelines of 32 in. OD or larger are assumed to be onshore projects.

With these assumptions and using OGJ pipeline-cost data, here is a breakout of costs by line diameter:

• Total onshore construction for 1997 alone will cost more than $15 billion-nearly $2.9 billion for 4-10 in. pipelines, $6.4 billion for 12-20 in., $2.6 billion for 22-30 in., and $3.1 billion for 32 in. and larger.

• Total offshore construction for 1997 alone will cost slightly more than $2.3 billion-$573.8 million for 4-10 in. pipelines, nearly $1.3 billion for 12-20 in., and $528.8 million for 22-30 in.

• Total onshore construction for beyond 1997 will cost slightly more than $45 billion-$2.6 billion for 4-10 in. pipelines, nearly $11.5 billion for 12-20 in., almost $9.8 billion for 22-30 in., and $21 billion for 32 in. and larger.

• Total offshore construction for beyond 1997 will cost more than $4.7 billion-$525 million for 4-10 in. pipe- lines, nearly $2.3 billion for 12-20 in., and $1.9 billion for 22-30 in.

U.S. gulf oil lines

Crude oil began moving through a major new pipeline in the Gulf of Mexico last year.

Phase 1, 16 and 20-in., Poseidon pipeline came on stream in spring 1996, moving crude oil 117 miles from Garden Banks Block 72 to a Leviathan Gas Pipeline Partners LP platform on Ship Shoal South Addition Block 332.

The 24-in. Phase 2 section came on stream later, delivering to shore markets as much as 400,000 bbl of oil through a landing at Caillou Island, La. Poseidon connects near Houma, La., with Texaco Pipeline Inc. systems.

A unit of Texaco Inc. operates the system through Poseidon Oil Pipeline Co. LLC, a 50-50 venture of Texaco and Leviathan, Houston.

Also last year, Shell Oil Co.'s Amberjack pipeline began moving crude oil from the Bullwinkle tension leg platform (TLP) in 2,860 ft of water on Green Canyon Block 143 to Fourchon, La. And another Shell offshore pipeline began shipping crude to Fourchon from the Mars TLP in 2,933 ft of water on Mississippi Canyon Block 807. Both pipelines deliver to Louisiana Offshore Oil Port (OGJ, Feb. 25, 1996, p. 30).

Units of Amoco Pipeline Co., CNG Energy Services Corp., and PanEnergy Field Services Inc. placed in service Dec. 1, 1996, a $50 million oil gathering system in the Central Gulf of Mexico.

The 160,000 b/d pipeline serves Main Pass and Viosca Knoll, where several producers have made discoveries that will begin production by 2000. The system can also gather oil from deepwater Mississippi Canyon wells.

The project consists of 64 miles of 18 in. from Main Pass Block 225 to a Shell crude oil terminal on Main Pass Block 69. From there, oil flows into Louisiana through the Shell Delta Pipeline System. PanEnergy Field Services managed construction for the partners. Amoco Pipeline is operating it and marketing capacity on the system (OGJ, May 20, 1996, p. 29).

Gulf gas plans

Among the many systems proposed to bring Gulf of Mexico gas ashore, Texaco Natural Gas plans to build a gas gathering, transmission, and processing system to support deepwater natural gas development in the central Gulf of Mexico.

A $300 million construction program includes a 105 mile, 30-in. pipeline across five federal planning areas, gas processing at Larose in Lafourche Parish, La., and a natural gas liquids fractionator at Paradis, St. Charles Parish, La. The line will extend from about 130 miles offshore in about 2,000 ft of water to the Larose cryogenic gas processing plant.

Both line and plant will have design capacities of 600 MMcfd, expandable to 750 MMcfd. Completion is expected by third quarter 1997 (OGJ, May 27, 1996, p. 24).

Also in the central gulf, units of Shell, Marathon Oil Co., and DeepTech International Inc., Houston, want to spend $220 million on a gas gathering and transportation system. The new line was initially targeted for start-up later this year.

Marathon says pipe has been purchased and is being coated; lay barges have been hired to begin pipelay this spring.

The project consists of a new interstate line to shore and an expansion of an existing gathering system linking several fields. Nautilus will be a 30-in., 87-mile line from Ship Shoal Block 207 to gas processing facilities near South Bend, La. Nautilus will be able to carry as much as 600 MMcfd.

The existing Manta Ray system upstream of Ship Shoal 207 will be extended to serve both Outer Continental Shelf and deepwater developments around Ewing Bank Block 873 to the east and Green Canyon Block 65 to the west.

In addition, ANR Pipeline Co. has filed with the Federal Energy Regulatory Commission to build 37 miles of 30-in. offshore and onshore pipeline looping to boost capacity by as much as 461 MMcfd.

ANR already delivers 1.1 bcfd via Eugene Island and Ship Shoal blocks. Current maximum throughput capacity is 1.35 bcfd.

Cost estimated in the FERC filing was $51 million. In-service date is set for summer 1998 or earlier, depending on regulatory approvals.

Transcontinental Gas Pipe Line Corp. (Transco) plans a two-phase, $129 million project to add 660 MMcfd to its offshore Southeast Louisiana Gathering System (Selags).

Selags' total capacity after both phases will be 1.935 bcfd. Phase 1 of Selags consists of a 50.7 mile, 30-in. loop from Ship Shoal Block 14 to Ship Shoal 214, increasing Selags' capacity by about 380 MMcfd.

Phase 1 is to be in service by November. Phase 2 calls for installation of 27 miles of 30-in. loop from Ship Shoal Block 214 to a platform to be installed on South Timbalier-South Addition Block 301, at the edge of the shelf. It will add 280 MMcfd by November 1998.

Transco's is the fifth project for the region. All five would add more than 3.5 bcfd of new capacity in the central gulf by January 1999.

Off Alabama

In the Main Pass and Viosca Knoll areas off Southeast Louisiana, Destin Pipeline Co., a unit of Southern Natural Gas Co. (SNG), Birmingham, wants to lay 207 miles of 30-36 in. line to transport as much as 1 bcfd of gas.

A 36 in., 73-mile portion will move from a gathering platform in 350 ft of water at Main Pass Block 248 to landfall near Pascagoula, Miss. Included is a junction platform on Viosca Knoll Block 119.

The 134-mile, 30 and 36-in. shore segment would move gas through central Mississippi, interconnecting with interstate pipelines of Florida Gas Transmission Co. at Lucedal, Miss.; Transco at Quitman, Miss.; and SNG and Tennessee Gas Pipeline Co., at Enterprise, Miss. Destin is to be in service by January 1999.

Off Alabama, Dauphin Island Gathering Partners, Houston, plans several projects. It wants to extend and expand the current Dauphin Island Gathering System (DIGS) to serve producers bringing on line new wells in Viosca Knoll and eastern Main Pass. Demand for takeaway capacity from these producers is expected to exceed current capacity by 376-400 MMcfd.

First-phase work includes installation of 60 miles of 24 in. by next month.

Second-phase work includes construction of a 15-mile, 24-in. loop from a point on the current system in Alabama state waters north of Dauphin Island to the system's onshore terminus near Mobile. To be in place by later this year, it will boost DIGS capacity to more than 900 MMcfd from 450-500 MMcfd. Meanwhile, Dauphin Island Gathering Partners, operator of DIGS, merged with Main Pass Gathering Co., which operates the Main Pass Gathering System (OGJ, Jan. 20, 1997, p. 30).

For deepwater and OCS gas off Louisiana, units of Shell and Amerada Hess Corp. want to lay a 1 bcfd gathering system in the Garden Banks area. The Garden Banks Gas Pipeline LLC would be a 50 mile, 30-in. line to extend from Enchilada platform on Garden Banks Block 128 to a new platform on South Marsh Island Block 76. Service is planned for April (OGJ, Oct. 28, 1996, p. 28).

Canadian changes

In recent years, movement of plentiful, cheaply produced gas from western Canada to lucrative U.S. Midwest markets has been constrained by limited takeaway capacity from Alberta to markets east and south.

Western Canadian gas is low cost, but the expense of moving it east and south has put it at a competitive disadvantage to Gulf of Mexico supplies.

In 1996, several major pipeline projects were floated to bypass traditional routes for gas exports. The implications of some of these projects strike at the very heart of Canada's regulatory mechanisms for ensuring the economic viability of pipeline expansions.

By far the most ambitious is Alliance Pipeline, a 1,900-mile, 36-in. dense-phase pipeline proposed to run from near Fort St. John, B.C., to near Chicago. At its initial proposal, the project was estimated to cost $2.5 billion and be designed to carry about 1 bcfd.

During an open season conducted in fall 1996, Alliance signed up 38 shippers for nearly 1.5 bcfd with eight more shippers at some point of negotiation. The company was to decide whether to expand the line's design capacity or prorate shippers based on the original proposed capacity.

The project grew out of a feasibility study known as the Northern Area Transportation Study. It was pushed to an actual proposal by 17 limited partners, none holding more than 11%, but all are producers to some extent of gas in the northern region.

The project is a direct challenge to Alberta's principal gas pipeline, NOVA Gas Transmission, and thereby to the present system of moving gas across and out of the province. That system, producers say, puts them at a competitive disadvantage when that gas arrives in the U.S. Midwest.

As a response to growing pressures for additional and more affordable capacity out of western Canada to midwestern U.S. markets, TransCanada PipeLines Ltd. in July 1996 revised its system expansion plans for this year. TransCanada more than doubled what it had planned to spend to about $900 million (Canadian) from nearly $264 million.

Also, in a move aimed at a project that challenges its dominance of Alberta gas shipments, NOVA Gas Transmission requested in late 1996 regulatory approval to move up to this year a $99 million (Canadian) expansion originally scheduled for 1998. The project would add 57 miles of large-diameter line to move about 1 bcfd from northwest of Calgary to the Saskatchewan border processing center of Empress.

NOVA's dominance over Alberta gas movements was challenged last year by a proposal backed by PanCanadian Petroleum Ltd., Calgary, and a subsidiary of Westcoast Energy Inc. The Palliser Pipeline project called for nearly 150 miles of mainline and 435 miles of laterals to carry 1.2 bcfd of Alberta gas. Palliser and NOVA at yearend 1996 (OGJ, Dec. 23, 1996, Newsletter) agreed to a toll plan that would, the companies said, eliminate the need for the Palliser Pipeline.

On Jan. 31, NOVA asked Alberta's Energy and Utilities Board (EUB) for approval of a new rate structure. In December, Palliser asked the National Energy Board to suspend its pipeline application, pending EUB approval of NOVA's proposed rate structure.

Whatever its fate, the Palliser project is indicative of the pressures that are changing how the province moves gas within and without its borders. No sooner was the agreement between NOVA and Palliser disclosed than another plan materialized. A group of Amoco Canada, Shell Canada, and CU Gas unveiled plans to build the $450 million (Canadian) Alberta Pipeline Project with 1.1-1.4 bcfd capacity (OGJ, Dec. 30, 1996, Newsletter). Tolls on the 404 mile, 20-36-in. pipeline would substantially undercut NOVA's, said its backers.

Across the continent, gas movements from Nova Scotia offshore fields to eastern Canada and the U.S. Northeast have moved closer to reality.

A group of Sable Island gas developers led by Mobil Oil Canada Ltd. plans the Sable Offshore Energy Project (SOEP), formally proposed to the NEB in October 1996. SOEP calls for development of about 3 tcf of gas in Thebaud, Venture, North Triumph, South Venture, Alma, and Glenelg fields near Sable Island. Proposed facilities include production of gas and natural gas liquids, initial treatment offshore, and transportation by two-phase gathering line to a gas plant in the Country Harbour area of Nova Scotia.

NGL will move via an onshore line to the Point Tupper area for further processing and shipping via the Maritimes & Northeast line into eastern Canada, New England, and the U.S. Northeast. SOEP's planned offshore/ onshore line would be 140 miles.

To move gas from the Sable Island development, two projects have been advanced. Maritimes & Northeast Pipeline LLC is a proposed 729-mile, $975 million pipeline to bring gas from the Sable Island area to New England. In December 1996, the project jumped the first regulatory hurdle to realization: the U.S. Department of Energy approved import-export authorization for as much as 636 bcf for 2 years.

Representatives of Maritimes & Northeast will make a presentation at the Apr. 7, 1997, regulatory hearing for SOEP on building a line from the proposed gas plant at Goldboro, N.S., to the U.S. border near St. Stephen, N.B. PanEnergy and Westcoast Energy Inc. 32.5% each, Mobil 25%, and Eastern Enterprises 10% make up Maritimes & Northeast Pipeline LLC. PanEnergy manages the U.S. portion; Westcoast, the Canadian. Phase I of Maritimes & Northeast in the U.S. is to be a 64-mile, 24-in. line between Dracut, Mass., and Wells, Me.

Phase II, in the U.S., will involve about 230 miles of 24-in. and nearly 2 miles of 30-in. line from the Phase I connect near Wells to near Woodland, Me., near the international border. In its FERC filing in September 1996, Maritimes & Northeast said the direction of flow in the Phase I pipeline will be reversed when Phase II goes into service. Gas will then flow from Country Harbour, N.S., to Dracut.

Alternatively, TransCanada and utility Gaz Metropolitain Co., Montreal, want to build a line from the Sable Island development that would run through Quebec before entering the U.S. TransCanada also wants to ship some Sable Island gas on the proposed Portland Natural Gas System (PNGS) to Boston. TransCanada owns an interest in PNGS.

Express project

The Express crude oil pipeline made swift transition from idea to near-reality in 1996 and early in 1997 is in final stages of commissioning and building storage at its Canadian injection point.

Express Pipeline Ltd. will be a 785-mile, 24 in., 172,000-b/d capacity line to bring Canadian crude oil from near Hardisty, Alta., to Casper, Wyo. From there, much of the crude will move via the Platte Pipeline to near Wood River, Ill., and U.S. Midwest refineries. Some will likely supply Rocky Mountain refineries.

In 1996, pipelay for the entire portion was completed, with pump station installation under way and the last of four 150,000-bbl storage tanks at Hardisty under construction. Express expects to have the system fully operating by yearend.

Interprovincial Pipeline Co. (IPL) completed late last year an expansion that expands crude deliveries to the upper U.S. Midwest by 120,000 b/d. The connection is a bypass between IPL's Westspur, Sask., system and the Portal pipeline. It allows IPL to divert as much as 50,000 b/d around a capacity-constrained section at Cromer, Man., to deliver into Clearbrook, Minn. (OGJ, Dec. 9, 1996, p. 20). In 1998, IPL has said it will complete a Phase 2 expansion of another 170,000 b/d.

South America

A major gas pipeline in the Southern Cone of South America will start up in second quarter 1997.

Gasoducto GasAndes SA, Santiago, Chile, had completed pipelay at yearend 1996 on the $350 million 287-mile, 24-in. line from La Mora, Argentina, to Santiago.

The line will bring gas to fuel several power plants supplying electricity to Santiago. In addition, Metrogas SA, Santiago's gas distribution company and a partner in GasAndes, has been installing the city's first natural-gas distribution system.

NOVA Gas International, 56.5% interest holder in GasAndes and the pipeline's project manager, has said the line's initial capacity will be 124 MMcfd this year, to expand to 212 MMcfd in 2000, and 600 MMcfd by 2007 (OGJ, Nov. 18, 1996, p. 50).

When construction is complete in July 1997, work will start on a 68-mile extension to Quillota, 19 miles from Valparaiso on Chile's Pacific coast.

Another major gas-pipeline project between Argentina and Chile received a setback late in 1996.

NOVA Corp. withdrew from its partnership with CMS Energy Corp., Dearborn, Mich., and Empresa Nacional de Electricidad SA to build the 509-mile, 24-in. GasAtacama pipeline from Argentina's Noroeste basin to Mejillones, Chile (OGJ, Dec. 16, 1996, p. 25).

CMS told OGJ that by April it expects to announce the addition of a major Argentine gas producer as partner in the project. All permits have been obtained, said CMS, and the partners will decide by mid-1997 whether the project will proceed. Its intended market is a proposed 400-MW combined-cycle power plant in Mejillones.

Pipeline partners are also partners in the power plant. The company has said that laterals along the pipeline route are possible to Antofagasta, Tocopilla, and Calma in northern Chile. In a 30-day open season that concluded Jan. 15, CMS Energy said nominated volumes came to more than 180 MMcfd, about 21% more than the originally planned 150 MMcfd anticipated design of the pipeline.

In Colombia, gas will begin flowing in second quarter this year through the 214 mile, 20-in. line being built for TransGas de Occidente SA. Partners in the project are TransCanada 34%, BP International 20%, Gas Natural del Oriente 14%, PetroColombia 12%, and Destillados Agricolas, Fluor Daniel, Inversora Arlloz, and Spie-Capag 5% each. Capacity in the mainline will be about 220 MMcfd, says TransGas' project manager. And more than 260 miles of laterals are being laid to serve 47 communities in addition to the major city of Cali. La Guajira fields in the Mariquita region on the Caribbean coast are supplying the gas.

In nearby Bolivia, with the apparently successful partial privatization of Yacimientos Petroliferos Fiscales Bolivianos (YPFB) late last year (OGJ, Dec. 23, 1996, p. 33), the proposed 3,700-km gas pipeline from Bolivia to Southeast Brazil has taken a major step toward reality.

High bidder for YPFB's pipeline unit Transportadora de Hidrocarburos with $263.5 million was a joint venture of Enron Development Corp. and Shell International Gas Ltd. At least part of the significance of this joint effort is to suggest that the massive gas reserves from Shell's Camisea proposed development in Peru may be available to augment gas supplies headed to Brazil. Previous plans for Camisea included gas and condensate pipelines across the Andes to serve Lima (OGJ, May 20, 1996, p. 38). That still remains a possibility.

The Bolivia-Brazil gas pipeline would kick off at Santa Cruz, Bolivia, extend across the Bolivia-Brazil border to Corumba, Brazil, and on to Campinas and Sao Paulo.

The first 2,840 km would consist of 28-in. line; the remainder, of decreasing diameters of 22, 20, 18, 16, and 14 in. In the original contract between the two countries, Bolivia was to supply 3.7 tcf/year for 20 years (OGJ, Aug. 7, 1995, p. 39).

European gas demand

The pace of expansion to feed Europe's transmission gas system is likely to accelerate the next few years.

The European Investment Bank (EIB), Luxemborg, estimated in late 1996 that gas demand could increase to about 390 billion cu m/year by 2000 from the current level of 330 billion cu m/year.

By 2010, demand could reach 410-450 billion cu m/year (OGJ, Sept. 2, 1996, p. 36). To meet this increase, Europe must look to greater imports mainly from Algeria, Russia, and Norway. Current pipeline import capacity, said EIB, is 200 billion cu m/year with 40 billion cu m/year of LNG coming into the region.

Increasing capacity on the Trans- Med pipeline to Italy is one project that could begin to meet the increased demand, along with completion later this year or in early 1998 of the entire GME pipeline to Spain and Portugal (OGJ, Dec. 2, 1996, p. 50). GME gas could flow through these countries into France. European LNG terminals may also be in for expansion.

Two major projects from the Norwegian North Sea will move ahead to attempt to meet increased European demand. Den norske stats oljeselskap AS (Statoil) let contracts late last year for its 528 mile, 42-in. NorFra gas pipeline from Sleipner field to Dunkirk, France (see related story, p. 30). By 2000, Statoil expects to have started operating the nearly 870-mile, 36-42 in. Europipe II, making deliveries to Germany.

Also, construction on the long-planned, much-discussed pipeline between England and France, known as Interconnector, will get into full swing this year (see related story, p. 40). Pipelay from Bacton will begin next month, with work from the Zeebrugge, Belgium, end beginning in April.

Interconnector will be a 150-mile, 40-in., 1.9 bcfd line that will deliver as much as 815 MMcfd of gas to Britain. Start-up is slated for Oct. 1, 1998.

Offshore gas, eastern oil

Another major European pipeline prospect is a gas line from Danish discoveries in the North Sea and from Norwegian and U.K. offshore pipeline systems to Denmark.

Dansk Olie & Naturgas AS (DONG) expects Danish gas demand to rise to about 9.5 billion cu m/year by 2000. The two pipelines currently bringing gas from Tyra field are running at or near capacity of 7.5 billion cu m/year.

In early 1996, DONG began talks with Norway's gas negotiating committee to secure gas for the future. Any new line would likely be rated at about 4 billion cu m/year and would probably run from the South Arne discovery area to near existing pipeline's landfall north of Esbjerg.

Yet another gas line for Norwegian gas was recently announced. Norsk Hydro AS last month disclosed plans to build a gas pipeline from Oseberg field to the Statpipe terminal in Heimdal field. The $150 million project calls for 68 miles of 36-in. pipe; start-up would come in 2000 (OGJ, Jan. 13, 1997, p. 30).

Elsewhere, aggressive development by 1999 of Russian gas fields Yubileinoye, Yamsovey, and Khavutin could lead to production of as much as 1.4 tcf/year. This gas could flow through a pipeline that would traverse Russian, Belarus, Poland, and Germany. Financing, reports EIB, has yet to be fully arranged, and the extent to which Belarus and Russia can finance their segments is in doubt.

The puzzle of moving Caspian Sea crude oil moved a step closer to being solved in late 1996 when Mobil agreed to participate in a restructured Caspian Pipline Consortium (CPC). The new agreement allows Mobil to exercise its right to acquire a 7.5% equity interest in the planned pipeline.

Overall, the project calls for rehabilitation and upgrading of an existing line from Tengiz to Komsomolsk, construction of a new pipeline from Komsomolsk to the Black Sea, and a loading complex at or near Novorossiisk. Construction would allow Tengiz to produce more than 200,000 b/d by 2000 and nearly 800,000 b/d by 2010.

Pipeline construction is to be completed by yearend 1999 and provide export capacity of 580,000 b/d of Russian oil.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.