PROSPECTSFORWORLDWIDE pipeline construction began 1998 under clouds of uncertainty. Turmoil in Asian financial markets that began in 1997 had deepened and spread.
As the year began, previously robust forecasts for Asian oil and gas demand were being trimmed, and important energy projects in the region were being re-evaluated, delayed, or even canceled.
Oil and gas demand forecasts determine pipeline operators` plans for new construction. Plans reflected uncertainty for the future:
- Near-term, for 1998 only, operators expected to lay more than 23,000 miles, 27% more than was envisioned a year earlier for 1997.
- Longer term, however, for construction completed after 1998, operators had become more conservative, planning to lay slightly more than 44,000 miles, down by nearly 17% from the more than 53,000 miles envisioned a year earlier.
For both 1998 and the period beyond, a total of more than 67,000 miles of crude oil, product, and natural gas pipeline was planned (Fig. 1).
Major areas of planned pipeline construction include North America, especially between Canada and the U.S.; Latin America, especially to bring gas to fast-growing Brazil and booming Chile; Europe`s Caspian Sea region to move huge supplies of crude oil; and the North Sea, to bring more gas to meet Europe`s burgeoning gas demand.
Oil & Gas Journal`s pipeline construction data indicated these trends and derived from a survey of world pipeline operators, industry sources, and published information.
For 1998 only, companies indicated they expected to spend more than $26 billion on oil and gas pipelines worldwide. For projects completed after 1998, companies expected to spend $50 billion to lay more than 44,000 miles of line.
Table 1 shows construction projections for both 1998 and the longer term.
Cost estimates are based on U.S. average cost per mile for onshore and offshore gas pipeline construction as found in Oil & Gas Journal`s 1997 Pipeline Economics report.
Cost projections assume 90% of all construction will be onshore and 10% offshore. Pipelines of 32 in. OD or larger are assumed to be onshore projects.
Canadian gas for the U.S.
The biggest North American story remained activity to move gas from Alberta and northeastern British Columbia to the U.S.
Alliance Pipeline proposed in June 1996 to build a system that would bypass Alberta`s NOVA Gas Transmission system and thus reduce costs to Canadian shippers. Alliance proposed a 1,864-mile, 1.3 bcfd line from western Alberta to near Chicago.
That proposal prompted a couple of other proposals and talk of several more, forced NOVA to re-evaluate its "postage stamp" transportation rate within the province, and spurred the interprovincial carrier, TransCanada PipeLines Ltd. to revise its facilities proposal to respond to the implicit competition of Alliance or something similar.
It also played a large part in merger plans announced early in the year between NOVA and TransCanada.
From the first, Alliance was opposed by NOVA, which said the Alberta section would duplicate its pipeline facilities. Talks on a possible deal between NOVA and Alliance broke down in 1997.
Alliance was unique in its plan to carry not only gas but also liquids in a high-pressure, dense-phase line from Alberta to near Chicago, with the liquids stripped out and resold somewhere south of the Canada-U.S. border.
The U.S. Federal Energy Regulatory Commission (FERC) approved the U.S. portion of the pipeline, subject to completion of an environmental review. Alliance partners, consisting mostly of Canadian gas producers, hoped to begin service by late 1999.
Competing with Alliance`s efforts were TransCanada`s plans, approved by Canada`s National Energy Board (NEB), for an $824.5 million (Canadian) natural gas pipeline construction program.
The line would cross Saskatchewan, Manitoba, Ontario, and Quebec and include 192 miles of pipeline looping, 11 compressor units, and additional metering facilities at five existing stations. Completion was planned for November 1998.
This would add about 352 MMcfd of firm transportation service from Empress, in eastern Alberta, and 65 MMcfd of short-haul firm transportation service from St. Clair, Ont. About 16% of the capacity is for domestic consumption.
Other plans to move western Canadian gas to the U.S. had also been advanced.
The NEB approved application by Foothills Pipe Lines Ltd., Calgary, to build an $18 million (Canadian) decompression-recompression station at Empress to provide 690 MMcfd of incremental natural gas export capacity, a 45% increase, for the eastern leg of the pipeline expansion starting Nov. 1, 1998.
And Canada`s Northern Pipeline Agency approved Foothills`s design for the rest of the $167 million project, which called for 71 miles of 42-in. pipeline. Gas delivered through Foothills`s eastern leg is shipped to Midwest U.S. markets on Northern Border pipeline.
FERC had already approved a plan to double capacity of the Northern Border pipeline system to 1.5 bcfd. The plan, which competes for some of Alliance`s customers, would bring gas from Foothills to Ventura, Iowa, and the Chicago area. The project was slated for completion by November 1998.
On the eastern side of the continent, activity to bring Sable Island gas offshore Nova Scotia to the Maritimes provinces and on to the U.S. pushed projects closer to realization.
Mobil Corp. began construction early in 1998 on the Sable Offshore Energy Project to bring as much as 460 MMcfd of gas and 20,000 b/d of NGL ashore from offshore Nova Scotia.
Initial construction included building and installing six offshore platforms, drilling up to 30 wells, building an onshore gas plant, and laying more than 250 miles of pipe.
The gas was targeted for the U.S. Northeast and spawned a flurry of planned pipelines for eastern Canada and the U.S.
Portland Natural Gas Transmission System (Pngts) and Maritimes & Northeast Pipeline wanted to construct about 100 miles of 30-in. jointly owned pipeline in the U.S. and an interconnection with the upstream portions of the proposed 290-mile Pngts system and the 729-mile Maritimes & Northeast system.
More U.S., gulf activity
Activity was similarly heating up south of the U.S. border with Canada as a result of efforts to move Canadian gas to southern markets.
Texas Eastern Transmission Corp. was boosting gas-throughput capacity by 250 MMcfd through its Lebanon, Ohio, lateral pipeline in Indiana and Ohio. The $31-million expansion will provide more capacity for the company`s Spectrum project to move as much as 500 MMcfd of gas from Chicago to the East Coast. There, the gas could compete with Canadian gas moving from the Sable Island project.
PanEnergy Corp. received more than enough support from shippers for the 500 MMcfd it sought for the Excelsior and Spectrum gas pipelines from Chicago to the eastern U.S.
And partners in the Viking Voyageur gas-pipeline project for a 775-mile pipeline from Emerson, Man., to near Joliet, Ill., increased the size of that line to 42-in. from 36-in. and increased capacity to 1.4 bcfd from 1.2 bcfd.
Construction was to get under way early in 1999, and first gas delivery was slated for November 1999. Partners are Northern States Power Co., TransCanada, and Nicor Inc.
Tennessee Gas Pipeline Co. planned Eastern Express Project 2000, an extension of the Eastern Express project, all part of an effort to move 400-500 MMcfd of incremental supplies in this case, to the New York City area.
And Northern Natural Gas Co. received more than 650 MMcfd, exceeding the target volume of 450 MMcfd, for its East Leg 2000. The project involved construction of a branch line, border station infrastructure, and mainline loop, all to be operating by Nov. 1, 1999, to move gas from Canada to Iowa, Illinois, and Wisconsin.
And Crossroads Pipeline Co. along with CNG Transmission Corp. and East Ohio Gas Co. proposed to deliver natural gas from U.S. and Canadian supply basins through the Chicago area to the eastern U.S.
Crossroads said a 20-mile pipeline to link Chicago to the U.S. East via Crossroads`s existing interconnection with Natural Gas Pipeline Co. of America could be in service by late 1999. Crossroads also has interconnections with Panhandle Eastern Pipeline Co., Trunkline Gas Co., and Columbia Gas Transmission.
Elsewhere in the U.S., Nautilus Pipeline Co., Houston, moved ahead with its 101 mile, 600-MMcfd line in the central gulf. And the $308 million, 210-mile Destin pipeline was nearing completion at mid-1998 to transport up to 1 bcfd to interstate pipelines in Mississippi.
Latin America: gas for power
One of the most important and largest pipeline projects in South American petroleum history picked up speed in 1997 and early 1998.
The initial 32-in., 345 mile segment in Bolivia between Rio Grande and Puerto Suarez near the Brazilian border was under way, along with the 324-mile segment from Corumba, Brazil, on the countries` border to near Campo Grande, Brazil.
The main line will stretch eventually as far as Sao Paulo with laterals carrying gas southward through the states of Paraná, Santa Catarina, and Rio Grande do Sul to Canoas on the outskirts of Porto Alegre.
The 1,898-mile pipeline is part of efforts to secure fuel for electric power generation for growing populations of Brazil.
Enron Corp., for example, planned a $500-million, 480-MW gas-fired power plant in Brazil`s Mato Grosso state. Design for two other plants-a 500-MW plant in Macaie and a 700-MW plant, both in Rio de Janeiro state-is under way; both will be gas-fired.
Elsewhere in the Southern Cone, installation was to be complete by November on the Chilean section of Gasoducto Atacama Cia. Ltda.`s 300-MMcfd, 914-km, 20-in. natural gas pipeline from Argentina`s Neuquen basin to a combined-cycle, electric power plant being built at Mejillones, Chile.
GasAtacama secured contracts for 160 MMcfd of gas. Of that total, 127 MMcfd will be shipped to the 710-MW plant. Total cost of the pipeline and plant, scheduled for completion early in 1999, will be about $750 million.
A portion of the 127 MMcfd of gas shipped to Mejillones will be transported further south to a 350-MW plant Endesa was building at Taltal, Chile. The 160-mile Gasoducto Taltal extension was expected to cost $30 million.
Another pipeline from the Neuquen basin, this one to the BíoBío region of Chile, was expected to begin flowing gas by late 1999. The $342-million Gasoducto del Pacifico was being pushed by NOVA Gas International as part of a $400-million integrated natural gas project.
It will move gas from Loma de la Lata via a 530-km, 20 and 24-in. mainline and 105 km of 10 and 16-in. laterals. Initial delivery capacity will be 140 MMcfd.
Elsewhere in Latin America, 1997 saw important developments in Mexico:
- The first privately owned and operated gas pipeline in Mexico started up at yearend.
Under a $20 million contract, Willbros Group designed and built a 45-mile, 24-in. gas pipeline joining El Paso Natural Gas Corp.`s system at its Hueco compressor station east of El Paso to the Samalayuca I and II power plants in Chihuahua, Mexico.
- Energía Mayakan SRL de CV, a joint venture of TransCanada, Bechtel Corp.`s International Generating Co. unit, and Mexico`s Gutsa Construcciones SA, received from Mexico`s Energy Regulatory Commission approval to build and operate a natural gas pipeline to supply customers in the Yucatan Peninsula for 30 years.
The $260-million, 700-km pipeline will originate at Ciudad Pemex, Tabasco, and deliver gas to industrial customers in Campeche and Merida. Construction will begin this year with initial deliveries of 270 MMcfd slated to start September 1999.
TransCanada will own and operate the line in a 26-year contract.
Caspian Sea
Oil from the Caspian Sea region began flowing early in 1998 through a rehabilitated line between Baku and the Russian Black Sea port of Novorossiisk.
Also proposed was another rehabilitated line between Baku and the Georgian port of Supsa to supplement the more northerly route; it would cost more than $1.5 billion to complete. But together, these lines would quickly become unable to handle rapidly increasing volumes of Caspian production.
A new line along the Baku-Novorossiisk route was possible with a capacity of 1 million b/d, costing around $2 billion.
But oil, whether in Novorossiisk or Supsa, must move to the Mediterranean Sea to reach world markets. The traditional option route was across the Black Sea and through the narrow, crowded Bosporus straits, a route the Turkish government would like to discourage.
It wanted the oil to continue south from Supsa along a new 1,235-mile pipeline to the Turkish Mediterranean Sea port of Ceyhan at a cost estimated by the oil companies involved to reach almost $3 billion.
Each of the routes involves the Azerbaijan International Operating Co., a group of 11 oil companies headed by Amoco Corp. and BP, and stems from their $8 billion plans to develop offshore fields Azeri, Chiag, and Buneshli.
Reserves in these fields are estimated at 4 billion bbl.
Another group, the Caspian Pipeline Consortium, had announced plans to build a 900-mile oil line from Tengiz, Kazakhstan, around the north of the Caspian Sea and across Russia to Novorossiisk. This group includes Chevron Corp. and Mobil Corp. and is shooting for a start-up capacity of 560,000 b/d with ultimate (2012) capacity of 1.3 million b/d.
Again, however, the oil must get from Novorossiisk to world markets beyond the Bosporus.
The most direct route out of the region would involve a pipeline directly south from Tengiz, across western Turkmenistan, and over Iran to the Persian Gulf. The U.S. ban on companies` doing business with Iran, however, made this route most problematic.
Moving natural gas out of the region also met with political obstacles.
Unocal Corp. had plans to build a gas pipeline from Turkmenistan through Afghanistan to Pakistan and world markets via the Arabian Sea.
Unocal is the major stakeholder in Central Asia Gas Pipeline Ltd. (CentGas), a group of Turkemenistan and six international oil and engineering firms.
CentGas planned a 2 bcfd, 790-mile line from southeastern Turkmenistan to Lultan, Pakistan, at an estimated cost of almost $2 billion. A 400-mile extension to New Delhi was being considered and would cost another $600 million.
And Royal Dutch/Shell received approval by the governments of Iran, Turkemenistan, and Turkey to build a 1,500-km, $1.6 billion gas line from Turkmenistan via Iran and Turkey to Europe.
Plans to move gas via pipeline for consumption by countries in the region advanced briskly.
Turkmenistan built a 200-km gas line from Korpedzhe field to the northern Iranian gas grid at Kord Kuy. The 4 billion cu m/year line will double capacity by 2006.
And Turkmenistan signed an agreement to supply Turkey, via pipeline, with 15 billion cu m/year of gas. Turkey had in place a contract with Russia for 3 billion cu m/year via a 1,200-km pipeline across the Black Sea.
European activity
Elsewhere in Russia, plans were disclosed early in 1998 for an oil pipeline from the Timan-Pechora oil fields in Russia`s Komi republic to a new port at Primorsk near Leningrad or to the Finnish oil terminal at Porvoo on the Gulf of Finland.
The system would carry 140,000 b/d of oil, with possible expansion to 600,000 b/d by 2010. Were the line to use the Primorsk route, it would be 2,718 km long, of which 1,885 km already are in place.
On the gas side out of Russia, Germany`s Wingas, a 65/35 joint venture of Wintershall AS and Russian gas giant Gazprom, was at work on a new pipeline link for gas to Germany from Russia`s Yamal Peninsula.
The Jagal pipeline extends 330 km from Mallnow in Brandenburg to Ruckersdorf in Thuringia, where it joins the existing Stegal gas pipeline in Germany.
The 48-in. Jagal pipeline will be able to move as much as 28 billion cu m/year of gas and cost more than $560 million. It was to be completed in 1999 and form part of the Yamal-Europe pipeline system, which will carry Russian gas more than 4,000 km from western Siberia to European markets.
Wingas said forecasts show that western Europe will require an extra 150 billion cu m/year of gas by 2010, one third of which will be met by the Yamal-Europe project.
Gazprom took its plans to diversify its entry points to the European gas market a step further in an agreement with Finland`s Neste Oy.
The two companies in 1997 formed a 50-50 joint venture to build a pipeline to take gas from Russia to Finland and on to Sweden and the European Union gas market.
Russia exports 3.5 billion cu m/year of gas to supply Finland. Under the agreement, Finland will increase its consumption to 4.5 billion cu m/year.
The venture`s plan for the North European gas route is to lay a pipeline to carry about 45 billion cu m/year of Russian gas to the Nordic and European markets. Gas would be flowing by 2005.
Southern peninsula activity
Countries that make up Europe`s Iberian and Italian peninsulas stepped up their efforts to expand regional transmission systems and diversify natural gas supplies.
This activity responded to projections that yearly natural gas demand growth through 2010 would exceed the average annual demand growth for all countries of the European Union.
Diversifying sources; another record
Italy`s natural gas demand was growing faster than that of any other European country, according to Italian gas-transmission operator SNAM SpA, Milan. As a share of total energy demand, gas demand in Italy was likely to grow from slightly more than a quarter in 1996 to more than a third by 2010.
As a result, SNAM was actively negotiating and signing gas contracts with existing and new suppliers to ensure and diversify gas supply to the peninsula over that period.
For European supplies to Italy, expansions on two major cross-country pipelines will have been completed by 2001 along with a third new line in France that will tie into an existing line from the Netherlands.
Additionally, gas imports from the south may receive a major boost shortly after 2001 when SNAM hopes to bring onstream a new, subsea gas pipeline to Sicily from a gas processing plant on the Libyan coast near Algeria.
Agip was due to develop the NC41 gas and condensate field off Libya near Bouri oil field with twin gas and condensate lines to an onshore gas treatment plant at Sabratah. To these volumes will be added dry gas production from Wafa field, some 400 km to the south.
SNAM expected up to 8 bcm/year of processed gas then to move through a new 500-km, 32-34 in. pipeline to Sicily. The line would be laid in water up to 700 m deep, setting a subsea pipelay record.
New contract volumes due from Russia will be satisfied with planned expansion of the section from Slovakia across Austria. The new contract will need 378 km of 40 in. pipeline. Gas supply was to begin in October 1999.
Volumes moving from the Netherlands on the TENP-Transitgaz system began to see added capacity in 1995 when a 15-km loop near Mittelbrunn, Germany, came into service.
More looping 37 km south from this expansion and replacement of 95 km of pipe south from Schwarzach, across the border from Strasbourg, with larger 1,200-mm (48-in.) pipe, were planned by 2000.
Additional expansion of this route, up to double its capacity, has been discussed by SNAM and Ruhrgas.
A major expansion in delivery capacity from this direction will occur to accommodate up to 10 bcm/year of gas, mostly from contracts with Norway.
SNAM said that part of the gas would arrive through the North Sea pipeline NorFra, landing at Dunkerque, on the French coast. Other volumes would travel through Zeepipe and be delivered at Blaregnies on the Belgium-France border.
These volumes would merge in a planned pipeline across France to the Swiss border where it would connect with Transitgaz via a 50-km connection in Switzerland that will join the existing TENP-Transitgaz system.
Gaz de France said engineering was under way for a French line to run between Taisnières-sur-Hon and the French-Swiss border; size of the line would be between 36 and 44 in.
The Transitgaz line across the Alps to Italy will then be in need of expansion. The existing line reaches an altitude of 2,400 m, the highest gas pipeline in Europe. In the 36 km of tunnels needed to cross the Alps, some sections have a gradient of 85% and have been equipped with funicular railways for maintenance.
Expanding capacity through this area with looping of the existing 34-in. line is impossible, given that the tunnels are 6 m in diameter. SNAM said the existing pipeline will therefore be pulled from the tunnels and replaced with 48-in. pipe.
The new agreement, said SNAM, is important because Norway joins the other areas as a new gas supplier to Italy, thus diversifying the country`s suppliers.
It is also the first time that a physical link will exist with the French gas pipeline network, a further step towards interconnection of the European networks.
GME consequences
On the Iberian peninsula, as 1998 began, Spain was deeplyinto pipeline construction that would by yearend add 818 km of 10, 12, 20, 26, and 30-in. line in three geographic clusters (Fig. 2).
Byyearend 1999, an additional 360 km of 24 and 26-in.was planned.
By 2000, then, Enagás`s trunkline system will be able to deliver 1.5 bcfd to local distributors and power generators.This will be a 36% increase over its delivery capacity on Jan. 1, 1997, of slightly more than 1.1 bcfd.
As a result of completion of Gazoduc Maghreb Europe (GME; 858-mile, 48-in. from Algeria,across Morocco and the Strait of Gibraltar, toCórdoba), Enagáshad already laid and begun operating connections on its soil.
Three areas of ongoing construction in Spain are as follows:
- In the northwest, Galicia. The Portuguese system has been extended from the border near Tuy northward to near La Coruña.This expansionwas being carried out in place of a planned LNG terminal at Ferrol.
In November 1997, 48 km of lateral work of 4, 6, and 8 in. was completed in the corridor between Villalba and Lugo.
Early in 1998, installation of approximately 207 km of 20-in. line was completed between Tuy and Villalba (82 km) and Valga and Villalba (125 km). In March 1998, related 52 km of 10-in. lateral pipeline were installed between Pontevedra and Orense.
- In the southeast, between Gartagena and Valencia. In January 1998, Enagás completed construction on 71 km of 30-in. mainline between Cartagena and Orihuela, east of Murcia, and by July was to have finished a 26 km, 12-in. lateral from this new line west to Murcia.
Capacity on this new system was to be near 600,000 cu m/year (approximately 58 MMcfd). As a result, natural gas send-out capacity at the Cartegena LNG plant had been increased.
- In the west: Ruta de la Platta, between Oviedo in the north and Almendralejo in the south. Enagás was to complete construction in April 1998 on 164 km of 20-in. line from Aranda de Duero westward to Zamora and at nearly the same time begin to purchase materials for continuing with 26-in. pipe 66 km south to Salamanca.
Additionally, by November 1998, the company expected to complete 250 km of 20-in. north from Zamora to the León-Oviedo area.
Engineering was under way for construction on the south leg of this project, from Almendralejo northward to Salamanca; completion was set for some time in 1999.
Under study is a dedicated line from near the GME connection at Córdoba northeast to France. LACQ is running full, at 2 bcm/year. And there is the possibility of installing compression to bring Norwegian gas across France and the Pyrennes.
In Portugal, the Portuguese gas company Transgás began moving gas through the first high-pressure natural gas pipeline in Portugal.
As in Spain, much of the new gas supply is for electric-power generation. The 220 km, 28 in. line runs from Campo Maior, on the Spanish border near Badajoz, to Monte Redondo. Its delivery capacity is nearly 13 million cu m/day (457 MMcfd).
Spurring construction of the Campo Maior-to-Monte Redondo line was the line opened in 1997 between Córdoba and Campo Maior connecting the Portuguese system with the GME via Spain.
Portuguese construction developed this route along the Atlantic spine of the country, consisting of two main sections: 170-km segment south from Monte Redondo to Setúbal and 220 km north from Monte Redondo to Braga. This segment consists of 163 km of 28 in. pipeline to Porto and 43 km of 20-in. line to Braga.
In addition, approximately 200 km of branchlines in two sections were laid to move gas to cities and power stations.
The first section consisted of four segments: 16 in., 21 km to Almada; 28 in., 32 km to Lisbon; 20 in., 1 km line to Carregado power station; and an 8 in., 24 km line to Torres Vedras and Caldas da Rainha
The second segment of branchlines consisted of 8 km of 8 in. line to Aver; 9 km of 16 in. line to Vila Nova de GAO; 7 km of 24 in. line to Tapada power station; and 13 km of 6 in. line to Monomer.
Asian question mark
A great many transportation projects were on tap for Asia, most of which were tied to power generation plants, especially in Indonesia, Thailand, and China.
The region`s financial crisis, however, trimmed the previously optimistic scenarios for energy demand.
Here are some that could nonetheless survive even if in contracted form:
- Russia and China had spent 3 years studying two pipelines linking the nations and working on agreements for an early start.
One of the lines would connect gas fields in Russia`s Irkutsk region with Rizhao in eastern China`s Shandong Province. In its final stages, the line could extend to South Korea and Japan.
The other pipelines, from western Siberia to China`s Shanghai through the Zinjiang Uygur Autonomous Region, would ease energy bottlenecks in the booming eastern and southeastern areas of China.
The entire network of 3,500 km of line could cost as much as $10 billion and take 8-10 years to complete. Peak transportation capacities could reach 20 billion cu m/year over a 30-year life of the lines.
- Elsewhere in Asia, Chevron Asiatic Ltd. proposed to install a $2 billion (Australian) natural gas pipeline between Papua New Guinea and Australia. The line will pass through the Torres strait.
- Also, Enron Corp. and Royal Dutch/Shell Group were moving toward construction of a Bangladesh-to-India gas pipeline that will tap gas reserves in Myanmar, India`s Tripura state, and Bangladesh.
- Nearby, the Myanmar section of a Myanmar-to-Thailand pipeline had been completed, but the 260-km Thai section was under attack from environmental and human rights activists.
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Discovery project partners Mapco Inc., Tulsa, and Texaco Natural Gas installed in late 1997 a 12-in., 10-mile lateral in 200 ft of water in the Gulf of Mexico. The line brings gas from Chevron`s South Timbalier 37 platform to Discovery`s 30-in. mainline in South Timbalier 41. Photograph by Brian Kanof, courtesy of Mapco Inc.
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Gasoducto GasAndes, the first natural gas pipeline to bring Argentine production to Chile, crossed the Andes in its 287 miles between La Mora, Argentina, and Santiago, Chile. A second line connecting the two countries is under construction.
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Construction of major gas pipelines within and through Germany, such as here for Ruhrgas earlier this decade, has solidified supply links between Russian fields and West European markets. More is under way and planned. Photograph courtesy of Mannesmannröhre-Werke AG, Düsseldorf.
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Expansion of the Trans-Mediterranean pipeline allowed Italian gas-transporter SNAM S.p.A. to increase imports from Algeria to 25 billion cu m/year. Here welded 24-in. pipe along the Trentino Alto Adigeregion awaits cover.
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