Burgeoning demand for gas is fueling pipeline construction in Eastern and Western hemispheres.
In the East, the North Sea is the focal point for activity. And in the West, the U.S. gas market is the power behind construction.
As predictions of U.S. gas demand increase, Canadian pipeliners adjust expansion plans to be ready to capture greater shares of markets.
Canada's TransCanada PipeLines Ltd. is racing to step up its share of the U.S. market.
TransCanada's Western Gas Marketing Ltd. sold 242.3 bcf of gas in the 3 months ended last June 30, a 9.8% increase from last year.
TransCanada reported lower volumes sold into Canadian markets, while exports into the U.S. continued to rise.
Gas Research Institute (GRI) projects Canadian gas exports to the U.S. by 2000 will reach 2 tcf/year and LNG exports 800 bcf/year.
U.S. gas supplies could increase to 23.9 tcf/year by 2010, mostly from Lower 48 production. GRI says supplies from Canada will make up the balance.
In the past 2 years, TransCanada has spent about $1 billion expanding its interprovincial main line system.
During second quarter 1991, TransCanada increased main line throughput to 393 bcf, up 14.8% from second quarter 1990. Deliveries during first half 1991 increased 11.1% compared with last year, to 753.3 bcf (OGJ, Aug. 12, p. 46).
Last May Canada's National Energy Board (NEB) approved 15 applications for licenses to export a combined 1.6 tcf of gas to the U.S.
Meanwhile, talk of South America's potential power as a unified energy producer is leading Latin American countries to consider cooperating on international pipeline projects. But significant social and fiscal problems prevent progress.
Among other countries, Australia's pipeline construction outlook is being shaped by abundant gas and dwindling oil reserves. Eighty-one percent of the continent's gas reserves are in the west and north, far from industrial and residential markets in eastern and southern Australia, Australian Gas Association figures show. An Australian gas pipeline network is needed to interconnect isolated, regional transportation systems serving factories and coastal urban areas.
Here are some examples of what's going on in selected areas:
CANADIAN PROJECTS
Canadian pipeline construction this year will be worth an estimated $2.22 billion (Canadian), up 24% from 1990, Statistics Canada reports.
Additions to main line and gathering systems will total about 4,200 miles this year, up 5% from 1990 construction levels.
Statistics Canada says most spending will be on gas system expansion and maintenance, with about $1.978 billion earmarked for mainly export related projects.
The largest program is by TransCanada, Calgary, now in the midst of a $2.478 billion (Canadian) expansion program approved earlier this year. Part of the program will connect at Iroquois, Ont., with the Iroquois Gas Transmission System, currently under construction, to deliver gas from western Canada to markets in New England and New York State.
The TransCanada program, including 994 miles of line construction in Saskatchewan, Manitoba, and Ontario, 21 compressor units, and two compressor stations, is scheduled for completion by November 1992. It will boost system capacity by about 830 MMcfd, with 677 MMcfd destined for the U.S. Northeast and the balance for markets in Central Canada.
TransCanada spokesman Bill Scotland said the program is on schedule. He said it will be ready to deliver significant volumes to the Iroquois system in November. Capacity will be expanded rapidly in first quarter 1992 with completion by November 1992.
The company will spend more than $1 billion this year. Spending to the end of August totaled $618 million.
Scotland said contractors finished more than 190 miles of pipeline construction in Ontario in a winter program. Summer construction is under way in Saskatchewan and Manitoba.
More than 370 miles of line will be added this year, with commissioning of new compressor capacity beginning in the fourth quarter.
TransCanada filed an application in July for a $390 million expansion program in addition to the $2.4 billion project under way. Planned loops in Ontario, Saskatchewan, and Manitoba will add 187 miles and 150 MMcfd capacity to the system. About 81 MMcfd will go to domestic markets and 71 MMcfd to U.S. customers.
The company earlier planned a $720 million program but said customers in Ontario and Quebec have reduced requests for added capacity needed in 1992 because of a recession. Some facilities originally planned in the proposed expansion will be postponed but none will be eliminated. TransCanada wants to start construction in the spring of 1992, aiming for completion in the fall. Construction would go ahead in conjunction with the larger expansion program.
NEB last month agreed to review an earlier decision to reject another export related TransCanada project.
NEB denied an application for the Blackhorse extension, a $42.3 million, 13 mile line to connect the TransCanada system in Ontario with the proposed Empire State line near Chippewa on the Niagara River. It is designed to deliver 64.3 MMcfd of Canadian gas and 117.5 MMcfd from U.S. storage facilities to customers in New York state.
NEB agreed to review its decision after the Federal Energy Regulatory Commission approved the U.S. portion of the project, but NEB has not said when the review will be completed. FERC approved the Empire State project and rejected rival proposals by Tennessee Gas Pipeline Co. and CNG Transmission Corp. NEB had said the Blackhorse extension wasn't needed because an existing TransCanada line could be used which connects with the Tennessee system.
NOVA PROGRAM
Nova Corp., Calgary, is the other major contributor to Canadian pipeline construction this year and in 1992.
The company is working on a 5 year, $2.6 billion expansion program for completion in 1995. In 1990, Nova moved a record 2.9 tcf or 8 bcfd through its 10,563 mile system which gathers and distributes gas in Alberta and delivers gas to border export points. About 80% of gas in the Nova system is moved to Alberta border points for export to eastern Canada or U.S. export markets.
Under its expansion program, Nova spending on main line and lateral expansion and related facilities totaled $723 million in 1990, with $625 million budgeted this year and $695 million in 1992.
The company has completed its 1991 winter construction program, which added 367 miles of main and lateral transmission lines and loops to its system, much of it in northern Alberta where most new gas supplies are coming on stream.
A summer construction program scheduled for completion in mid-October will add 115 miles of various diameter line to the system.
Expansion programs will give Nova a total delivery capacity under winter design conditions of 12.1 bcfd for the 1992-93 heating season and 13.5 bcfd by 1995.
Nova's projected capital spending and construction program after the 1992-93 season year will be affected by uncertainty over approval and timing of a number of downstream expansion projects. They include the Northern Border pipeline project to export gas to the U.S. Northeast and the rival Altamont and Pacific Gas Transmission pipeline projects designed to ship more Canadian gas to California.
Nova has planned for a capacity increase of 63 MMcfd in the 1992-93 program to cover increased exports related to the TransCanada-Iroquois projects.
OTHER CANADIAN ACTIVITY
In other major construction activity in Canada, a $346 million pipeline from mainland British Columbia to Vancouver Island is near completion, with deliveries to the island scheduled to begin this month.
The 350 mile system includes 27 miles of underwater line across Georgia Strait in as much as 138 ft of water. The project, by Pacific Coast Energy Corp., a joint venture by Alberta Energy Ltd. and Westcoast Energy Ltd., will deliver gas to pulp mills and communities on the north coast of the mainland and on Vancouver Island.
Ottawa provided a $100 million grant and a $50 million interest free loan for the line. The British Columbia government contributed $55 million. The project had a $70 million cost overrun related to environmental delays, heavy rainfall, and construction problems in the underwater section.
Interprovincial Pipe Line Inc., Edmonton, is considering conversion of its mothballed Sarnia-Montreal crude oil line to move gas to Quebec (OGJ, Aug. 26, p. 13). The line was taken out of service when Montreal refiners switched feedstock from western Canadian oil to imported crude.
Alberta Natural Gas Ltd. (ANG), Calgary, and Foothills Pipe Lines Ltd., also of Calgary, plan a 48 mile, $186 million expansion of their pipeline system in Southeast British Columbia to meet projected demand for as exports to California.
This summer, 29 shippers signed long term contracts for all 877 MMcfd of capacity on ANG's proposed expansion (OGJ, Aug. 5, p. 31).
ANG plans to connect the 48 mile, 42 in. pipeline with Pacific Gas Transmission Co. (PGT) and Pacific Gas & Electric Co. (PG&E) expansions aimed at markets in the U.S. Northwest and California.
The PGT-PG&E expansion is set to begin construction this fall. But NEB is considering an alternate plan by Altamont Gas Transmission Canada Ltd. to serve markets on the U.S. West Coast.
Altamont's 620 mile, 30 in. pipeline would carry as much as 719 MMcfd of gas from Port of Wild Horse, Mont., on the U.S.-Canadian border to interconnect with Kern River pipeline near Opal, Wyo,
Kern River is under construction as a Wyoming-California transmission system.
U.S. SCENE
A busy arena for gas pipeline capacity expansion lies in the Arkoma basin of Arkansas and Oklahoma, and a series of filings for still more capacity is under consideration by FERC.
Southwestern Energy Co. began construction this year of its $73 million, 258 mile Noark system in Arkansas (OGJ, July 8, p. 16). Initial capacity of the line is 141 MMcfd.
Also under construction is an additional 350 MMcfd of capacity on Natural Gas Pipeline Co. of America's AG line (OGJ, July 8, p. 16). The $27 million expansion project includes 8 miles of 30 in. pipeline, expected to be operational by the end of this month, adding 50 MMcfd of capacity. A 16,500 hp compressor station will be added near Paris, Tex., by spring 1992, bringing the system to its planned capacity.
Meantime, Tennessee Gas Pipeline Co. and Columbia Gulf Transmission Co. are seeking FERC approval to lay a 97 mile, 30 in. line from Arkla Energy Resources AC line near Glendale, Ark., to Columbia Gulf's main line near Inverness, Miss., and Tennessee's system near Isola, Miss. (OGJ, July 29, p. 30). Capacity of the proposed $110.7 million GI line is 550 MMcfd.
In a related move, Ozark Gas Pipeline Corp. asked FERC to approve a capacity increase to 330 MMcfd on its 266 mile, 20 in. main line from Pittsburgh County, Okla., to White County, Ark. (OGJ, July 29, p. 30). Ozark plans to begin the $17 million project after the GI line is laid.
Elsewhere, six interstate pipelines still are awaiting a FERC decision on a proposed construction project that would transport as much as 1.2 bcfd of gas from Mobile Bay off Alabama (OGJ, Feb. 4, p. 62).
ANR Pipeline Co., Southern Natural Gas Co., Tennessee Gas Pipeline Co., Texas Eastern Transmission Corp., and Transcontinental Gas Pipe Line Corp. last fall agreed to combine competing projects into a single onshore and offshore system (OGJ, Oct. 8, 1990, p. 42).
The resulting $230 million system will move gas from Mobil Exploration & Producing U.S. Inc. and Shell Offshore Inc. gas processing plants in Mobile County, Ala., through Transco's existing 30 in., 123 mile line, to connect with its main line near Butler, Ala.
Transco currently is moving about 300 MMcfd of gas through the existing line.
Construction of additional onshore facilities and a 77 mile offshore pipeline was to have begun in mid-1991.
SOUTH AMERICA
Andean Pact nations and Group of Three countries-Colombia, Mexico, and Venezuela-are studying the feasibility of laying a products pipeline out of Venezuela capable of supplying Pacific coastal markets of countries in Central and South America. Alternative routes are being considered through Colombia, Costa Rica, and Panama.
Venezuela would operate the line and lead the construction project, which would be financed by joint venture partners.
Officials in Venezuela and Colombia also are studying proposals for two international gas lines.
Sources say Venezuela's government has approved a proposal to lay a $1.1 billion, 950 mile gas pipeline through Venezuela to the Colombian border.
Throughput of the line is expected to be about 220 MMcfd, but diameter and route haven't been disclosed.
Also under discussion is how Venezuela and Colombia will share construction costs. According to reports, 3-4 years will be needed to complete the line.
Venezuela and Colombia also are said to be wrapping up plans to lay a 320 mile pipeline to transport Venezuelan gas to Colombia. Again, alternate routes still are being considered.
If construction begins early in 1992, completion is expected during 1993. Estimated construction costs range to $500 million, and throughput could reach 200 MMcfd.
PDVSA'S PIPELINE PLANS
Petroleos de Venezuela SA (Pdvsa) has disclosed the most ambitious pipeline construction plans in South America.
Pipeline construction plays important roles in all segments of its medium term, $48 billion development plan for 1991-96. The share of expected 1991 outlays reserved for pipeline projects is not known.
Among the pipeline construction goals outlined in its current 5 year program, Pdvsa proposes to lay:
- 1,000 km of oil and gas pipelines to help increase oil production to more than 3.6 million b/d by 1996.
- 1,200 km of pipeline and set up 25 production stations in the Orinoco belt to attain Orimulsion output of 750,000 b/d by 1996.
- 844 km of trunk pipeline and add compression of 765,000 bhp to move 4.63 bcfd of gas by 1996.
- A 400 km propane pipeline between Jose and Valencia, in eastern and central Venezuela, respectively.
Pdvsa also plans to lay a 50 km pipeline off Venezuela's east coast to deliver gas produced from 55 wells and as many as eight platforms to an onshore liquefaction plant and 4.4 million metric ton/year LNG export terminal. The pipeline is part of Pdvsa's $3 billion Cristobal Colon LNG development.
PERUVIAN PIPELINES
Petroleos del Peru SA (Petroperu) plans a $30 million repair and maintenance program on its 860 km, 200,000 b/d North Peruvian trunk pipeline, which moves crude oil from the jungle to a marine terminal at Bayovar.
Crude flow was expected to resume in late August on the trunk line, following repairs about 25 km east of Olmos. Guerrillas were believed to have bombed the line between intermittent crude flows, but Petroperu officials didn't discover the damage until Aug. 24.
No official estimate was available of crude lost as a result of the attack.
Throughput on the North Peruvian line averages 74,000 b/d, nearly one third of Peru's average 1991 oil production. But Petroperu uses the line every 3-4 days because of low production volumes.
Petroperu also has announced plans for pipeline construction to support three developments.
Petroperu wants to lay gas and liquids pipelines to support development of gas and condensate reserves in San Martin/Cashiriari fields in the Camisea area. Initial Camisea production could amount to 900 MMcfd of gas and 50,000 b/d of liquids.
Petroperu plans to lay a 6 in., 11,000 b/d pipeline from Chambira oil field, in northern jungle Block 8, to Corrientes. The 34 km line will allow Petroperu to move Chambira production into a pipeline from Corrientes to the North Peruvian trunk line.
Pipeline construction is included in plans to develop Aguaytia gas/condensate field in Peru's central jungle area of Pucallpa. However, work there is unlikely until armed forces curb activities by guerrillas and drug traffickers.
PIPELINES IN ECUADOR
Ecuador's Ministry of Mines and a group led by Conoco Ecuador Ltd. in late August were to have signed final supplementary documents for development of heavy oil reserves on Block 16 in western Ecuador.
Petroleos del Ecuador (Petroecuador) approved Conoco's development plan early this year, pending approval of the mines ministry (OGJ, Mar. 25, p. 21).
As part of the agreement, Conoco will operate fields in Block 16 and lay a pipeline from Daimi field to Lago Agrio pump station to transport oil to the Pacific Coast.
Petroecuador agreed to supply light crude at international prices to meet blending requirements.
In mid-August, Petroecuador trimmed about $75 million from its 1991 budget of $606 million. Originally, it expected to spend about $72.8 million on pipeline construction (OGJ, May 27, p. 107), including:
- $14.5 million for maintenance and expansion of the Lago Agio-Balao crude oil export pipeline.
- $47.8 million for laying the 130 km Libertad-Manta and 120 km Libertad-Pascuales gas liquids pipelines.
- $12 million to replace 111 km of corroded pipe in the Esmeraldas-Quito products line.
It is unknown how the new austerity measures will affect pipeline maintenance and expansion plans of Petrocomercial, Petroecuador's affiliate responsible for products distribution infrastructure.
BRAZILIAN ACTIVITY
Shell Oil Co. affiliate Pecten Brazil this year began laying a 16 in., 180 km onshore pipeline from a coastal processing plant to a refinery at Cubatao.
Last year, Pecten completed a 16 in., two phase offshore pipeline for production from the Merluza discovery in 430 ft of water about 115 miles off Sao Paulo state in southeastern Brazil.
Merluza reserves are estimated at 303 bcf of gas and 10.6 million bbl of oil.
Meanwhile, Petroleos Brasileiro SA (Petrobras) has shelved plans to lay a 937 km oil pipeline because of budgetary constraints.
The line would have run from the Paulinia refinery in Sao Paulo to the city of Brasilia.
Sources say 80,000-90,000 metric tons of 12 in. and 20 in. coated API line pipe grades X-60, X-65, and OX-70 would have been needed for the project.
An international tender is planned when the project is revived.
NORTH SEA
The biggest project for the U.K. North Sea is BP Exploration's 600 million ($1 billion) upgrading of the Forties crude oil pipeline system.
The company this year completed laying a 105 mile, 36 in. replacement for the offshore section of the line from Forties field to Cruden Bay terminal, north of Aberdeen. BP is seeking permission to abandon the original 32 in. line which is trenched for 93% of the route.
The new offshore line has a capacity of 900,000 b/d and the company is working on boosting capacity of the 130 mile, 36 in. land line from Cruden Bay to processing and export facilities at Kinneil and Hound Point on the Firth of Forth, near the Grangemouth refinery.
Two more pump stations are planned for the line to supplement the single pump station at Brechin. Capacity of the additional stations is not decided.
New processing capacity is needed at Kinneil to boost capacity to 960,000 b/d from 600,000 b/d. A new storage tank will be installed, and a second tanker berthing point is planned for the Hound Point terminal.
Offshore, BP will install another riser platform in Forties field to receive new pipelines from Bruce, Nelson, and Scott oil fields that will be laid during the next 2 years. The riser unit will be linked into Forties' Charlie platform, starting point for the new 36 in. line.
More crude for the Forties system also will come from East Brae and Toni-Tiffany fields through pipeline links into the existing Brae-Forties line.
Liquids from Everest-Lomond field development also will use the Forties system through a "T" on the new 36 in. line.
Everest and Lomond oil and gas fields, where Amoco U.K. Exploration is operator, will provide throughput for the Central Area Transmission System (CATS), a 250 mile, 36 in. gas line to a power station under construction at Teesside in Northeast England. The line is due on stream in first half 1993.
Mobil North Sea Ltd. completed the 203 mile, 30 in. Scottish Area Gas Evacuation (SAGE) line from its Beryl field to St. Fergus and is completing a spur line into the system from the Brae area.
Work is well advanced on the first phase of Mobil's St. Fergus terminal for SAGE. Deliveries from Beryl are to begin in October 1992.
The first phase of the project will cost 310 ($524 million). Mobil has received approval for a 300 million ($507 million) extension to handle gas from Marathon Oil U.K. Ltd.'s Brae area and from Amerada Hess Ltd.'s Scott field.
Also at St. Fergus, Total Oil Marine is building a terminal to receive gas from BP's Miller field for onward transport to a nearby power station and for gas from Bruce field, which will be delivered through the existing Frigg gas line.
SAGE will be competing for third party customers, a business that has become attractive for owners of oil and gas lines. So far, third party users have built their own spur lines into the existing pipeline network.
Elf Enterprise Caledonia, stung by failure of previous owner Occidental Petroleum Caledonia to win more third party business for the oil line from the Claymore-Piper area to its Flotta terminal in the Orkney Islands, is considering extending its pipeline to make the system more attractive.
Elf will spend 50 million ($84 million) to upgrade Flotta terminal. The outlay also will prepare the unit for a 100,000 b/d increase in throughput expected next year from start-up of Piper B platform and Saltire and Chanter fields. Present throughput is 230,000 b/d.
In the southern U.K. North Sea, pipeline projects are under way to deliver gas from Pickerill and Anglia fields, while Ultramar Exploration will deliver the first U.K. gas into the Dutch sector when Markham field is commissioned next year. It straddles the U.K.-Dutch boundary.
Conoco (U.K.) Ltd. and Total Oil Marine agreed to develop Caister and Murdoch gas fields with a single 11 mile pipeline to the Conoco terminal at Theddlethorpe, England. The line is to start up in 1993.
Onshore U.K., work has started on the first independently owned gas pipeline from Conoco's North Sea gas terminal at Theddlethorpe to a new power station at Killingholme in South Humberside. Kinetica Ltd., jointly owned by Conoco and PowerGen plc, expects to complete pipelaying next month and will commission the 420 MMcfd line in May 1992.
In the Norwegian North Sea, Den norske stats oljesleksap AS was forced to make substantial changes to the Zeepipe construction plans after sinking of the substructure for Sleipner A gas platform (OGJ, Sept. 2, p. 30).
Minor changes also could be made to the starting point for the new Europipe gas pipeline project, due to begin deliveries of Norwegian gas to Emden, Germany, in 1995.
CONTINENTAL EUROPE
Reunification of Germany gave a boost to the pipeline industry in continental Europe.
Short links between the West German gas system and the state owned distribution system in the east got under way. In addition, EVG, a subsidiary of Verbundnetz Gas of eastern Germany and Ruhrgas AG, is in the final construction stages of a 300 mile gas line in Thuringia and West Saxony, the first high pressure, large diameter link between the two systems.
The biggest single pipeline project in Germany is a proposal by Wintershall AG, an aggressive newcomer to the long distance pipeline industry. Work on the 370 mile Midal gas line from Emden on the northwest coast of Germany to Ludwigshaven via Rehden, Kassel, Bad Hersfeld, and Aschaffen is scheduled to start early next year with completion by the end of 1993.
As well as providing a trans-German link for North Sea gas, Wintershall plans the 186 Stegal system from Reckrod on the Midal line to St. Katharinen in Czechoslovakia, where the system will join the network importing gas from the Soviet Union. Work is to begin shortly, aiming for start-up in autumn 1992. The line, to be rated at 282 bcf/year, will serve industrial centers in Thuringia and Saxony.
Wintershall has a long term cooperation agreement with the Soviet gas producer, Gazprom, which will participate in both pipeline projects.
New projects also were spawned by integration of oil product distribution systems in eastern and western Germany.
German affiliates of Royal Dutch/Shell and Mobil Corp. proposed product pipelines to link the main West German refining center around Hamburg with new markets in the east.
NORTH AFRICA, EUROPE
The most significant event in Europe this year for pipeliners was an agreement at government level to proceed with a second gas pipeline between North Africa and Europe under the Mediterranean Sea.
The proposed 775 mile pipeline will transport Algerian gas from Hassi R'Mel field through Morocco and link up with the Spanish gas transmission grid near Seville. The project is expected to cost $1.3 billion.
Completion is scheduled for the end of 1995. initial capacity for deliveries to Morocco and Spain will be 950 MMcfd, but that could be doubled when projected connections between the Spanish system and France and Portugal go into operation.
The system will consist of a 48 in. line running for 312 miles through Algeria to the border with Morocco. A 349 mile section will take gas through Morocco to the Strait of Gibraltar, where two 24 in. lines will make the 26 mile submarine crossing into Spain. A further 88 miles of 48 in. line will be needed to complete the link with the Spanish system.
A new company, Omegaz, was formed to survey a route and carry out engineering for the project. Initial studies on the technical aspects of the project, along with financing, are expected to take about a year.
Partners in Omegaz are Algeria's Sonatrach, Ruhrgas AG of Germany, Gaz de France, Enagas of Spain, Gas de Portugal, and Ste. Nationale de Produits Petroliers of Morocco.
A $5.8 million contribution to initial studies will be made by the European Community from funds earmarked to assist economic development in North Africa.
Gas de Portugal's participation in the project is part of a drive by the Portuguese government to introduce natural gas into the country.
The company is part of a combine including Gaz de France, Total, and Ruhrgas that will build a 250 mile high pressure gas line from a proposed LNG terminal at Setubal to Brega and the Spanish distribution system. The project, costing about $700 million, also requires feeder lines to industrial centers in Portugal and a series of underground storage caverns.
Algeria also wants to expand capacity of its pipeline through Tunisia and under the Mediterranean to Italy.
A feasibility study has started on two options: increasing compression on the line that crosses the Mediterranean or laying a loop through Tunisia to Italy.
In Tunisia, the state gas organization plans an extension of its distribution grid. The form of the extension will not be known until British Gas plc makes a final decision on whether to develop Miskar offshore gas reserves. This would require an extension of the system from the south of the country to the northern consuming areas.
If Miskar does not go ahead, Morocco will negotiate for more Algerian gas supplied through the transMediterranean system. The project is expected to cost $60-80 million and may be partly financed with World Bank help.
After a lean period, pipeline activity is picking up in Libya. Proposed development of the 2 billion bbl Murzuk field in the remote southwest part of the country by Libya's National Oil Corp. (NOC) and Rompetrol of Rumania will require a 250 mile pipeline link into the 120,000 b/d pipeline from Hamada al-Hamra to the Mediterranean.
NOC and Italy's Agip SpA also have let contracts for an 82 mile link between a new gas treatment plant in Bu Attifel field and the coast. Substantial gas reserves also have been found in the Ghadames basin of western Libya, where there are no pipeline links to the main centers of consumption on the coast.
In neighboring Egypt, Arab Petroleum Pipelines Co. is spending $120 million to boost capacity of the twin 42 in. lines of the Sumed crude oil system that links the Gulf of Suez to the Mediterranean. A new pump station south of Cairo will increase capacity to 2.4 million b/d from 1.6 million b/d.
In Syria the government's plans to reduce pressure on locally produced crude oil by boosting the use of gas will bring more work for pipeline companies. Syrian Petroleum Co. is seeking bids for a gas gathering system in Central Syria to provide feed for a gas treatment plant at al-Arak. This will be followed by contracts for pipelines from the plant to the main centers of demand in the west and southwest sections of the country.
MIDDLE EAST
The northern section of Iraq's pipeline network escaped from the allied air offensive this year with relatively little damage. It also survived the short-lived Kurdish occupation of northern Iraq.
Industry sources say the 1.6 million b/d system that runs through northern Iraq and Turkey to the Mediterranean port of Ceyhan could handle about 1 million b/d of exports immediately. United Nations restrictions will limit throughput to about 500,00 b/d once the system reopens, possibly as early as the middle of this month.
Turkey says there are about 4.1 million bbl of crude in the pipeline and a further 350,000 bbl in storage at Ceyhan terminal.
The pipeline outlet through southern Iraq and Saudi Arabia to Yanbu was more seriously damaged. Two pump stations on the IPSA line in Iraq were hit by allied bombs and still need substantial rebuilding.
The pipeline is in good shape throughout most of the route through Iraq, although Iraq will need to negotiate transit fees with Saudi Arabia before it can resume exports through Yanbu.
Since the end of the war, Iran has revived its plans for a gas pipeline into Europe through Turkey by reaching an outline agreement with the Turkish government that includes a commitment for Turkey to buy as much as 480 MMcfd of gas from the line,
An outline agreement also is in place for the line to run through Greece. Iran is trying to sell the concept to potential gas buyers in Yugoslavia, Austria, Czechoslovakia, Romania, Italy, and France.
In Saudi Arabia, Saudi Arabian Oil Co. is working on a project to boost capacity of pipelines from eastern province oil fields to Yanbu on the Red Sea coast to 5 million b/d from the current 3.2 million b/d. The extra capacity will be achieved by installing two more pumps at each of the 11 pump stations on the line.
Increasing Saudi production to 8.5 million b/d to avoid supply shortages during the Persian Gulf emergency required a crash program to reactivate pipelines and tiebacks that had been mothballed. About 410 miles of line to and from 15 gas oil separator plants are involved in the exercise.
Petroleum Development Oman's $500 million project to raise capacity of Lekhwair field to 110,000 b/d from 25,000 b/d by 1994 requires several new pipelines. The largest is a 67 mile, 16 in. gas line to the government's gas plant at Yibal.
Yemen's second crude oil export system was completed by the Soviet owned Tyumen Pipeline Construction Association this year. The 127 mile 20 in. line runs from new fields in the Shabwa area to Rudhum on the Gulf of Aden.
The project cost $135 million and with a single pump station plus a pressure reduction station on the coast can handle as much as 135,000 b/d.
While the pipeline part of the Shabwa development is complete, there are still delays in boosting production from Amal and East and West Iyad fields by another Soviet company.
FAR EAST
Ambitious plans to link the main producing areas of Indonesia and Malaysia with the fast growing economies of Thailand, Singapore, and Philippines are still around, although there is little progress toward implementation.
Thailand has two small product pipeline projects under way and will expand its offshore gas grid to accommodate Total's Bongkot field.
In Malaysia, the Peninsula Gas Utilization project is near completion and starting to push more gas into the power generation industry. When fully operational the line will run from gas fields off the eastern coast of the peninsula south to Johor and Singapore, then swing north up the west coast. The system eventually could reach Penang.
AUSTRALIAN WORK
A group led by Santos Ltd. hopes to begin construction in third quarter 1992 of a pipeline project that will begin gas deliveries from Queensland to markets in South Australia. Planning is in preliminary stages.
A pipeline also is being considered between the Amadeus basin in southern Northern Territory and the Moomba gas complex in South Australia. A truly national gas transportation system also could include large diameter pipelines between Dampier, on the coast of Western Australia, and Amadeus and Moomba.
A pipeline interconnecting the gas transportation systems of Victoria and New South Wales would tie in Gippsland basin gas reserves off the coast of southern Australia to a national pipeline network.
Presently, only one other major pipeline project is under way in Australia: Hadson Energy Ltd.'s three part Harriet gas gathering system supporting development of a series of fields off Western Australia (OGJ, Dec.17, 1990, p. 32).
The system will gather wet gas offshore from Harriet, Bambra, Campbell, Sinbad, and Rosette fields for delivery to a treatment plant on Varanus Island. From there, sales lines will transport dry gas 100 km to interconnect on the mainland with a 900 mile, 26 in. main line operated by the State Energy Commission of Western Australia (Secwa).
The Santos group's project will deliver 28 bcf/year of gas from fields in Permit ATP 259 in Queensland to markets in South Australia (OGJ, July 22, p. 24). Condensate will be stripped from the stream for Queensland markets in the Brisbane area.
The pipeline will gather production in Cooper/Eromanga basin fields of Ballera, Munkah, Yanda, and Challum, where the Santos group expects to spend $150-180 million to develop estimated proved and probable reserves of 1 tcf.
Pipeline Authority of South Australia has agreed to buy 280 bcf of Queensland gas during a 10 year period for resale to Electricity Trust of South Australia and South Australian Gas Co. Deliveries are expected by January 1994.
The Santos group expects to strip about 5,500 b/d of condensate from the gas stream at a plant it plans to build at Ballera. Condensate will move by pipeline from Ballera to Jackson, about 60 km east, for transport to Brisbane via an existing pipeline. Details of the Ballera-Jackson pipeline are not complete.
Santos plans to compress gas through Ballera inlet line, then free flow gas 200 km through a 16 in. pipeline to Moomba treatment plant in South Australia, where LPG will be extracted. Expected maximum capacity of Ballera-Moomba pipeline will be 93.6 MMcfd, but average throughput of 78 MMcfd is more likely.
From Moomba plant, dry gas will move to Adelaide through an existing line. LPG will move through a separate liquids line to Port Bonython, on Spencer Gulf in South Australia.
HARRIET GAS PIPELINE
Hadson's Harriet project consists of an offshore gathering system and offshore and onshore sales lines.
Secwa expects to buy 125 bcf of gas during the project's first 10 years, with an option for another 55 bcf at the end of the first term.
The whole project is expected to be in service by mid-1992. Altogether, 30 km of offshore gathering line, 70 km of offshore sales line, and 30 km of onshore sales line, all 12 in., will be constructed.
The onshore sales line will have a maximum capacity of 150 MMcfd. At first, Secwa will take 55 MMcfd of gas at Compressor Station 1,100 km south of Dampier.
The offshore gathering line will connect Campbell field with Rosette, an offshore field drilled from Varanus Island. A short 50 MMcfd spur will deliver Sinbad gas to the gathering line. Another short pipeline, only a few hundred yards long, will deliver combined production from Rosette to the system's Varanus Island processing plant.
A 1,200 hp compressor station is to be built on Varanus Island. Plans call for expanding compression to 4,000 hp as project throughput increases.
Until the gathering system is placed in service, Harriet gas will be flared.
Pipe for the Harriet project was fabricated in Brazil, with shipment expected this month to Malaysia, where it will be coated before being sent to Australia.
Completion of the onshore portion of the project is expected in November 1991.
Secwa plans to install six 12,600 hp turbine compressor sets on its 563.3 MMcfd main trunk line to deliver gas from Dampier on Australia's northwest coast to Bunbury in southwestern Western Australia (OGJ, Aug. 19, p. 31). New main line compression stations are planned at Peter Creek, Yarlardy, and Eneabba, and one unit will be added at Lyndon.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.