Christopher E. Smith
Planned pipeline construction to be completed in 2011 fell by more than 28% from the previous year, with sharp drops in planned crude and products pipelines more than countering expanded natural gas construction plans.
Operators plan to complete installation of 8,327 miles in 2011 alone (Table 1), with natural gas construction's share of the plans (more than 6,600 miles) making up nearly 80% of the total, based on reports from the world's pipeline operating companies and data collected by Oil & Gas Journal.
Looking forward, to 2011 and beyond, reveals that for the third consecutive year less mileage is planned than had been the case the previous year, as the uncertain economic recovery and still-evolving regulatory environments constrain infrastructure development plans.
In contrast to 2011 plans, however, long-term construction plans (2011 and beyond) saw growth in both crude and products lines, while plans for gas pipelines shrank, with expanded crude line plans in Latin America, NGL plans in the US, and ethanol plans in Brazil leading the way.
Larger long-term crude pipeline plans in the US, Europe, the Middle East, and Africa, in addition to Latin America, helped boost 2011 and beyond miles by nearly 25% from global totals the previous year.
Planned product-pipeline construction for 2011 and beyond registered increases in every region but Africa.
As a whole, combining both current-year and forward estimates (Fig. 1), both Europe and Latin America saw increases in planned construction, with decreases seen in all other regions.
As 2011 began, operators had announced plans to build more than 47,000 miles of crude oil, product, and natural gas pipelines beginning this year and extending into the next decade, the second consecutive decrease of more than 14% from data reported the previous year (OGJ, Feb. 15, 2010, p. 40) in this report and the third consecutive year during which plans contracted. The vast majority (more than 74%) of these plans is for natural gas pipelines, a decrease from the previous year as that segment contracted while crude and products grew.
The downturn in worldwide pipeline construction trends once again reflects the current economic unrest, but runs counter to US Energy Information Administration energy consumption forecasts, which show continued growth.
EIA forecast world marketed energy consumption to increase by 49% through 2035 (using a 2007 baseline), a period that encompasses the long-term pipeline construction projections stated here.
Energy demand growth will be strongest, according to the midyear 2010 analysis, among countries outside the organization for Economic Cooperation and Development, many of which it describes as already out of recession. This non-OECD growth will be led by China and India, where combined energy use as a percentage of world energy consumption will grow by 50% over the projection period to 30%. US demand-share will contract during the same period to 16% from 21%.
Fuelling this energy demand growth is projected gross domestic product growth in non-OECD Asia of 5.2%/year through 2035—led by China at 5.8%/year, the highest projected growth rate in the world—compared with 3.2% worldwide. Each of these levels is lower than EIA projections from a year earlier, reflecting continued economic uncertainty.
Structural issues that have implications for medium to long-term growth in China include the pace of reform affecting inefficient state-owned companies and a banking system carrying a large number of nonperforming loans, according to EIA. China also raised its interest rates in December 2010. Development of domestic capital markets to help macroeconomic stability and ensure China's large savings are used efficiently supports medium-term growth projections, according to the EIA.
EIA described the acceleration of structural reforms as essential to stimulating potential growth and reducing poverty in India over the mid- to long-term. EIA projects 5.0%/year GDP growth in India 2007-35.
In December 2010 the EIA forecast a 17% increase in total US liquid fuels consumption, including both fossil liquids and biofuels to an average 22 million b/d in 2035 from 18.8 million b/d in 2009. The agency said biofuels account for most of the growth, with expectations of additional waivers keeping the biofuel portion of future liquid fuels at roughly 2 million b/d, flat from the previous year's forecast.
EIA projects US oil production climbing 5.5% to 5.7 million b/d in 2035 from 5.4 million b/d in 2009, with production increases stemming from enhanced oil recovery efforts onshore, shale oil plays, and increased offshore activity.
The agency said the addition of shale gas resources in existing plays that can be produced at prices of less than $7/Mcf resulted in higher shale gas production overall and a higher rate of development in the 2011 reference case than in the 2010 reference case. Estimates of technically recoverable unproved shale gas reserves grew to 827 tcf from 347 tcf between the two reports. EIA cited updated shale gas resources in existing plays (noting key additions in the Marcellus, Haynesville, and Eagle Ford shales) and an assumption of increased well productivity for the newer plays in more than doubling reference case shale gas production in 2035 from the 2010 report, while noting considerable uncertainty about the ultimate amounts of recoverable shale gas.
The 2011 outlook projects higher cumulative US natural gas imports by pipeline through 2035 than did the updated Annual Energy Outlook 2010, citing increased shale gas production and resources and decreased domestic consumption in Canada. The 2011 outlook also removes the Alaska natural gas pipeline from its projections, citing increased capital cost assumptions and lower natural gas wellhead prices over the projection period.
Total US net imports of LNG in 2035 in the 2011 reference case are lower than in the 2010 reference case, due in part to less world liquefaction capacity and greater world regasification capacity over the projection period, as well as increased use of LNG outside North America.
OGJ has for more than 50 years tracked applications for gas pipeline construction to the US Federal Energy Regulatory Commission. Applications filed in the 12 months ending June 30, 2010 (the most recent 1-year period surveyed), indicate a slowing in US interstate pipeline construction.
• More than 520 miles of pipeline were proposed for land construction and no miles for offshore work. For the earlier 12-month period ending June 30, 2009, more than 2,180 miles were proposed for land construction.
• FERC applications for new or additional horsepower at the end of June 2010 also fell, to slightly less than 200,000 hp as compared with almost 645,000 hp a year earlier.
For 2011 only (Table 1), operators plan to build more than 8,300 miles of oil and gas pipelines worldwide at a cost of more than $42.5 billion. For 2010 only, companies had planned more than 11,575 miles at a cost of nearly $44.3 billion.
For projects completed after 2011 (Table 2), companies plan to lay more than 47,000 miles of line and spend roughly $241 billion. When these companies looked beyond 2010 last year, they anticipated spending roughly $207 billion to lay nearly 55,200 miles of line.
• Projections for 2011 pipeline mileage reflect only projects likely to be completed by yearend 2010, including construction in progress at the start of the year or set to begin during it.
• Projections for mileage in 2011 and beyond include construction that might begin in 2011 but be completed in 2012 or later. Also included are some long-term projects judged as probable, even if they will not break ground until after 2011.
US average cost-per-mile for onshore pipeline construction (Table 4, OGJ, Nov. 1, 2010, p. 108) on FERC applications submitted by June 30, 2010, was $5.1 million. There were no offshore applications submitted.
US average cost-per-mile for offshore construction (Table 7, OGJ, Sept. 14, 2009, p. 69) on projects completed in the 12 months ending June 30, 2009, was $5.37 million. These costs were used again in this year's report due to the absence of offshore filings to FERC in the 12 months ending June 30, 2010.
Based on historical analysis and a few exceptions and variations notwithstanding, these projections assume that 90% of all construction will be onshore and 10% offshore and that pipelines 32 in. OD or larger are onshore projects.
Following is a breakdown of projected costs, using these assumptions and OGJ pipeline-cost data:
• Total onshore construction (8,059 miles) for 2011 only will cost more than $41 billion:
—$1.5 billion for 4-10 in.
—$4.3 billion for 12-20 in.
—$6.4 billion for 22-30 in.
—$28.8 billion for 32 in. and larger.
• Total offshore construction (268 miles) for 2011 only will cost more than $1.4 billion:
—$179 million for 4-10 in.
—$505 million for 12-20 in.
—$752 million for 22-30 in.
• Total onshore construction (45,961 miles) for beyond 2011 will cost more than $234 billion:
—$3.8 billion for 4-10 in.
—$26.6 billion for 12-20 in.
—$31.8 billion for 22-30 in.
—$172 billion for 32 in. and larger.
• Total offshore construction (1,356 miles) for beyond 2011 will cost more than $6.8 billion:
—$449 million for 4-10 in.
—$3.1 billion for 12-20 in.
—$3.7 billion for 22-30 in.
What follows is a quick rundown of some of the major projects in each of the world's regions.
Pipeline construction projects mirror end users' energy demands, and much of that demand continues to center on natural gas, with the industry remaining focused on how to get that gas to market as quickly and efficiently as possible. The following sections look at both natural gas and liquids pipelines.North America activity
BP PLC and ConocoPhillps have joined resources to build a 4-bcfd natural gas pipeline (Denali) extending from Alaska's North Slope to market in Canada and the US (Fig. 2). The Denali partners selected Argonne National Laboratory in May 2009 as a third-party contractor for environmental impact statement preparation. Denali earlier awarded Bechtel Corp. an engineering contract for the project's mainline.
TransCanada Alaska meanwhile began the prefiling process on its own Alaskan natural gas pipeline. TransCanada was awarded rights to build a North Slope gas pipeline under the Alaska Gasline Inducement Act in January 2008. AGIA requires TransCanada to meet certain requirements that will advance the project in exchange for a license providing up to $500 million in matching funds.
In June 2009 TransCanada agreed with ExxonMobil Corp. affiliates to work together on an Alaska gas line. ExxonMobil will share expenses in advancing the project's technical, commercial, regulatory, and financial aspects, while TC Alaska remains the AGIA licensee. TransCanada already has NEB authorization for its project.
TransCanada's Alaska Pipeline Project closed its initial open season July 30 after receiving bids from potential natural gas shippers. The open season called on potential gas shippers to make bids of 20 years or more to reserve capacity on the proposed pipeline. TransCanada intends to use these commitments to secure financing for the pipeline, estimated to cost $32-41 billion to build. Details to be assessed include gas volumes, route preferences, and conditions attached to the bids by shippers.
The Alaska Pipeline Project presented two alternatives for assessment by potential shippers, only one of which will move forward. One option would transport an estimated 4.5 bcfd of gas from Alaska's North Slope about 1,700 miles across Alaska to Alberta, Canada, where it could be sent on existing pipelines to North American gas markets. The second option would transport an estimated 3 bcfd of gas about 800 miles to Valdez, Alas., where shippers could liquefy the gas in a plant constructed by others and ship it on tankers to US and international markets.
Denali concluded its open season Oct. 4, 2010.
Alaska's Natural Gas Development Authority is continuing to develop plans for intrastate gas pipelines, including a 460-mile system of various diameters from Beluga in southern Alaska to Fairbanks that would be used initially to transport gas from Cook Inlet but eventually connect to either Denali or the Alaska pipeline project to bring ANS gas south. The Alaska legislature required in May 2010 that a plan be submitted by July 2011.
In Canada, the proposed Mackenzie Valley pipeline would stretch more than 750 miles to transport Mackenzie River Delta gas to Alberta and beyond. Plans call for initial capacity of 1.2 bcfd, expandable to 1.9 bcfd. Canada's Joint Review Panel, examining the environmental and socioeconomic impacts of the $16.2 billion (Can.) project, approved the project in December 2009. The National Energy Board followed suit in December 2010 (OGJ Online, Dec. 20, 2010), but Imperial Oil Ltd. had pushed its investment decision date out to 2013 in March.
In addition to Imperial (34.4%) partners in the project include ConocoPhillips Canada (15.7%), Shell Canada (11.4%), ExxonMobil Canada (5.2%), and the Aboriginal Pipeline Group.
Costs include $7.8 billion for the Mackenzie Valley mainline, $3.5 billion for the gas gathering system, and $4.9 billion for anchor-field development.
Competing projects to move Rockies natural gas west narrowed to one during 2010, with El Paso Corp. announcing Aug. 2 that the Ruby Pipeline Project had received approval from FERC to begin construction. Ruby will extend 680 miles, using 42-in. OD line pipe and to transport natural gas from an existing supply hub at Opal, Wyo., to interconnections near Malin, Ore. Initial design capacity is 1.5 bcfd. El Paso began construction of the pipeline July 31 and anticipates having it in service March 2011.
Pipeline rights-of-way will cross four states: Wyoming, Utah, Nevada, and Oregon. El Paso has proposed four compressor stations totaling 160,500 hp: one near Opal hub in southwestern Wyoming; one south of Curlew junction, Utah; one at the project mid-point, north of Elko, Nev.; and one in northwestern Nevada.
El Paso has entered into agreements with Global Infrastructure Partners (GIP), whereby GIP will invest up to $700 million in the Ruby project. Upon satisfaction of various closing conditions, GIP will then acquire a 50% equity interest in the project.
A number of projects are being evaluated to move NGLs—primarily ethane—produced in the Marcellus shale to potential consuming centers in both the Gulf Coast and Midcontinent.
El Paso Midstream Group Inc., a subsidiary of El Paso Corp., on Aug. 9, 2010, began a 30-day, nonbinding open season to solicit interest for its proposed Marcellus Ethane Pipeline System (MEPS). MEPS would transport as much as 60,000 b/d of ethane at fractionation plants in the Marcellus shale to destination interconnect points with third-party ethane pipelines and storage near Baton Rouge, La. MEPS would use a combination of new pipeline and existing pipeline segments, expected to be acquired from Tennessee Gas Pipeline Co. and converted to ethane service. El Paso has targeted an in-service date of Apr. 1, 2013.
Both MarkWest Liberty Midstream & Resources LLC and Cumberland Plateau Pipeline Co. LLC also have proposed systems to move Marcellus ethane to the US Gulf Coast (OGJ Online, June 4, 2010). Cumberland Plateau's plans include a 1,050-mile ethane pipeline extending from the Marcellus shale to near Baton Rouge. Cumberland Plateau plans to begin building the 14-16 in. OD, 75,000-125,000 b/d pipeline in 2013, pending regulatory approvals, to meet a 2014 in-service date.
Buckeye Partners LP and Nova Chemicals Corp. signed a memorandum of understanding in February 2010 regarding evaluation and development of a mixed NGL pipeline running 400 miles from the Marcellus basin in Pennsylvania to the refining and petrochemical complex in the Sarnia-Lambton area of Ontario. The Union Pipeline Project (UPP), subject to final agreements and regulatory approval, would ship the NGLs principally for use as petrochemical feedstock.
Kinder Morgan Energy Partners LP announced Apr. 20, 2010, plans to modify and expand the existing Cochin Pipeline system to facilitate transportation of NGL from the Marcellus shale basin to fractionation plants and chemical markets near Sarnia, Ont., and Chicago.
KMEP plans to build 250 miles of NGL pipeline from the Marcellus shale in southern Pennsylvania to the Cochin interconnect at Riga, Mich. From Riga, the company anticipates product will travel through the existing Cochin system to Windsor, Ont., and then through the Windsor-Sarnia Pipeline to Sarnia. KMEP also plans to reverse the eastern leg of its Cochin line to move NGL from Riga to Chicago, where it expects to build an additional pipeline to connect to existing fractionation facilities and chemical plants.
The line will transport mixed NGL (Y-grade), as well as purity NGLs such as ethane, and will have an initial throughput of 75,000 b/d, expandable to 175,000 b/d.
Enbridge Inc. announced its own plans Mar. 22 to develop an NGL pipeline from the Marcellus shale to the US Midwest. The proposed line would deliver into the existing NGL system in the Chicago area, including the Aux Sable plant (OGJ Online, Mar. 24, 2010).
TransCanada announced plans in July 2008 for the Keystone Gulf Coast Expansion Project (Keystone XL), providing additional capacity of 500,000 b/d from Western Canada to the US Gulf Coast by 2012. The expansion would boost the Keystone system's total capacity to 1.1-million b/d at a total capital cost of about $12.2 billion. Keystone XL has secured firm, long-term contracts for 380,000 b/d for an average of 17 years from shippers.
Keystone XL includes 1,980 miles of 36-in. OD line starting in Hardisty, Alta., and extending to a delivery point near existing terminals in Port Arthur, Tex. Keystone XL will also include 41 pump stations—33 in the US and 8 in Canada—at roughly 50-mile intervals. Each station will use two to three 6,500 hp electric pumps, providing a total of up to 19,500 hp/station. Each station could be expanded to 32,500 hp as part of boosting the combined Keystone system's throughput to 1.5 million b/d.
In August TransCanada withdrew its request to the US Pipeline and Hazardous Materials Safety Administration for a special permit that would have allowed Keystone XL to operate at a slightly higher pressure than allowed under US regulations for oil pipelines (OGJ Online, Aug. 6, 2010). Pending receipt of necessary permits, TransCanada expects to begin construction on Keystone XL in 2011.
TransCanada launched a binding open season to obtain firm commitments from interested parties for its Cushing Marketlink Project, providing crude oil transportation from Cushing, Okla., to the US Gulf Coast. The project would involve construction of $70 million of facilities at Cushing and use facilities making up part of Keystone XL to deliver crude to near existing terminals in Nederland, Tex. Pending necessary regulatory approvals, TransCanada plans to place Cushing Marketlink in service first-quarter 2013.
Altex Energy is pursuing a completely newbuild 36-in. pipeline running directly from northern Alberta to the US Gulf Coast. The line's initial capacity would be 425,000 b/d. The pipeline project has been delayed by a lack of oil sands-supplied growth, according to Altex, which is working with Canadian National Railway on an interim option instead to use rail for transport of undiluted (or underdiluted) bitumen. Canadian National owns track up to Fort McMurray and the Peace River areas, and the delivery systems to eastern Canada, Chicago, Canada's West Coast, and Louisiana, according to Altex. As production volumes increase, the company still anticipates permitting and building a new-technology pipeline to the US Gulf Coast.
Enbridge plans to build the Northern Gateway Pipeline to transport 525,000 b/d of oil sands crude from near Edmonton to a tanker terminal in British Columbia for shipment to China, other parts of Asia, and California. A line running parallel to the crude line would ship 193,000 b/d of condensate from the coast to Alberta.
Enbridge expects to build Northern Gateway in 2012-14, pending regulatory approval of filings made in 2009. Commissioning and start-up would occur 2014-15. Enbridge would also operate the Kitimat terminal. The terminal would have 2 mooring berths, 14 storage tanks for petroleum and condensate, and be called on by roughly 225 ships/year.
As of December 2010, however, Enbridge was still involved in discussions with First Nations representatives who are attempting to thwart construction of the pipeline.
Kinder Morgan Energy Partners LP is continuing development of its $400 million CALNEV pipeline expansion. Expansion of the 550-mile pipeline involves construction of a 16-in. pipeline from Colton, Calif., to Las Vegas, Nev., and will increase the system's capacity to 200,000 b/d, transporting products for the military at Nellis Air Force Base. A further capacity increase to more than 300,000 b/d is possible with the addition of pump stations.
The new pipeline will parallel existing utility corridors between Colton and Las Vegas. Following its completion, the existing 14-in. line will be transferred to commercial jet fuel service for McCarran International Airport and any future airports planned in Las Vegas, with the 8-in. pipeline that currently serves the airport purged and held for future service.
Start-up of the line is scheduled for late 2012, but Kinder Morgan was still awaiting final permitting at end-2010.
Holly Corp. and Sinclair Transportation Co. plan jointly to build a products pipeline extending from Wood Cross, Utah, refineries to a terminal north of Las Vegas. The UNEV Pipeline project includes construction of associated terminals in Cedar City, Utah, and northern Las Vegas.
The 400 mile, 12-in. line will cost about $300 million and have initial capacity of 62,000 b/d, expandable to 120,000 b/d. It will serve refineries and shippers along its route and interconnect to the Pioneer Pipeline. Construction started July 6, 2010. UNEV Pipeline LLC expects mechanical completion of the pipeline in early 2011, with service to begin later in 2011. UNEV has said it will initially operate the pipeline at 30,000 b/d. Construction of the Cedar City and Las Vegas terminals are nearing completion. Holly owns 75% of UNEV, with Sinclair holding the balance.
The 1,700 km, 48-in. OD Gasoducto del Noreste will deliver 3.2 bcfd of Bolivian gas to Argentina as early as 2015. The Bolivian government, Argentine-state Enersa, and Gazprom are developing the $2.67 billion project.
Argentina approved plans for the pipeline in December 2010. State regulatory agency Enargas will stage an auction sometime early in 2011 to bid the project, which will move supplies from Bolivia to Argentine provinces Chaco, Corrientes, Formosa, and Misiones, and later to Cordoba and Santa Fe. It is estimated that construction will take 3 years and will cost about $1.8 billion.
Petrobras and Odebrecht plan to build the 1,085-km Gasoducto Andino del Sur in Peru to move natural gas from Camisea to Juliaca near Lake Titicaca and the Port of Ilo (Fig. 3). The pipeline would draw on fields operated by both Petrobras and Repsol YPF and deliver the gas to copper mines and other end-users, including both residential and industrial customers in Cusco, Arequipa, Matarani, and Ilo. The project is expected to enter service in 2013-14, with cities en route before the planned terminus in Ilo likely to get gas before completion of the entire line.
Colombia's Ecopetrol is joining with six other firms to build and operate a 450,000-b/d oil pipeline that will transport crude from Araguaney, in the Casanare Department of central Colombia, to the Covenas Export Terminal on the Caribbean Sea. Ecopetrol said all phases of the project are due for completion by yearend 2012 or start of 2013. The first phase includes 40,000-b/d of truck off-loading built in Banadia in December 2010. Remaining phases include construction of the 120,000 b/d Araguaney-to-Banadia line and the 330,000 b/d Banadia-to-Covenas line.
Ecopetrol will hold a 55% stake in Oleoducto Bicentenario de Colombia (OBC), the company that will build, own, and operate the new line. The other partners are Pacific Rubiales 32.8%, Petrominerales 9.6%, Hocol 0.96%, Grupo C&C Energia Barbados 0.5%, Rancho Hermoso SA-Canacol Energy Ltd. 0.5%, and Vetra Exploracion & Produccion Colombia 0.5%.
PetroChina expects to bring its second West-East Pipeline (WEPP II) into service in early 2011. The pipeline is part of the larger Asian Gas Pipeline, running from Turkmenistan to eastern China. The Chinese trunkline section covers 3,400 miles, connecting Xinjiang province to Guangzhou and Shanghai. The development also calls for 1,240 miles of branch lines. WEPP II will carry 30 billion cu m/year from Central Asia to consuming centers in China.
The Chinese section (WEPP II) will use 1.1 million tonnes of X80 42-in. OD UO pipe and 3.2 million tonnes of X80 18-in. OD spiral pipe. PetroChina let contracts to both GE Oil & Gas and Rolls Royce to supply compression for the Western China section of the pipeline, running from the Kazakhstan-China border to Zhongwei.
The non-Chinese portions of the line, which starts at the Turkmen gas fields near the Amu Darya river before entering Uzbekistan at Olot and continuing through southern Kazakhstan to China, were commissioned in December 2009. In addition to gas from Turkmenistan and Uzbekistan, the line will be supplied by gas from Kazakhstan's Karachaganak, Tengiz, and Kashagan fields. China National Petroleum Corp. has signed a 30-year agreement for supply of 30 billion cu m/year of gas through the line.
CNPC expects the entire project to be operating by yearend 2011.
The first stage of the 4,700-km East-Siberia Pacific Ocean oil pipeline, including construction of a 2,400-km oil pipeline from Taishet to Skovorodino near the Chinese border and of a rail oil terminal at Kozmino on Perevoznaya Bay at a combined cost of $14.1 billion, was inaugurated in December 2009.
First phase of the line carries up to 30 million tonnes/year of oil, about half earmarked for China via a branch pipeline from Skovorodino to the oil hub of Daqing in northern China and the other half shipped to Kozmino via rail. The full ESPO line will eventually carry 80 million tpy.
The second stage involves building a pipeline link between Skovorodino and Kozmino to replace the rail line by 2012.
The 50 million tpy shipped along the Skovorodino-Kozmino route would largely be exported to Japan but hinge entirely on the combination of continued development of the Siberia's other fields and Russia's continued desire to export to Japan. The November 2010 confirmation by Japan Oil, Gas & Metals National Corp. of rich oil reserves in three East Siberian fields boosted likelihood of near-term completion of the ESPO branch to Kozmino.
Myanmar awarded China National Petroleum Corp. exclusive rights to construct and operate the proposed Myanmar-to-China crude oil pipeline. This line and a companion natural gas pipeline would transport hydrocarbons from the Bay of Bengal across Myanmar to southwestern China. Plans call for the 440,000-b/d crude pipeline to run between Maday Island in western Myanmar through Ruili in China's southwestern Yunnan province and on to a new 200,000-b/d refinery in Anning. Both the pipeline and refinery are to begin operating by 2013.
CNPC began building a large oil import port at Kyaukpyu, Myanmar, in October 2009 to serve as the pipeline's input point. The port will be able to receive vessels up to 300,000 dwt and will have storage capacity of 600,000 cu m.
The natural gas pipeline is scheduled to begin carrying 12 billion cu m/year to southwestern China in 2013. Construction began in mid-2010. The pipeline will parallel the route of the crude pipeline to Ruili. From there it will run to Kunming, the capital of Yunnan province, before extending to Guizhou and Guangxi in South China.
The crude line will transport oil carried by tanker from the Middle East, while the gas line will carry material from Myanmar's offshore A-1 and A-3 blocks. Total estimated project costs amount to $1.5 billion for the oil pipeline and $1.04 billion for the gas pipeline.
The new pipelines will give China better access to Myanmar's resources and will speed deliveries and improve China's energy security by bypassing the congested Malacca Strait, which currently ships most of China's imported crude oil.
Construction of the 1,200-km Nord Stream natural gas pipeline, which will extend through the Baltic Sea from Vyborg, Russia, to Greifswald, Germany, began Apr. 9, 2010. Russia's Gazprom projects completion of the first 27.5 billion cu m/year Nord Stream line in 2011, with a parallel line of the same capacity to follow in 2012. The line will pass through Russian, Finnish, Swedish, Danish, and German waters.
Nord Stream AG says pipe laying for the line's first construction phase will be carried out through April 2011 by Saipem SPA's Castoro 6 and Castoro 10 as well as Allseas Group SA's Solitaire.
Work started in early December 2005 on the Russian onshore section of the Nord Stream pipeline in Babayevo. This 56-in. segment will stretch 917 km to the Baltic Sea coast near Vyborg, linking existing gas pipelines from Siberia to the project. Seven compressor stations will provide the necessary pressure.
A joint venture consisting of Gazprom (51%), Wintershall AG (15.5%), E.ON Ruhrgas AG (15.5%), NV Nederlandse Gasunie (9%), and GDF Suez (9%) is building the pipeline. For the two-leg option, the total cost for the offshore project will amount to more than €7 billion, with Gazprom investing an additional €1.3 billion in the onshore section.
The Ostsee-Pipeline-Anbindungs-Leitung (OPAL), a Wintershall-Gazprom (Wingas) joint venture, will eventually extend 470 km to link Nord Stream to Eastern Europe. About 400 km of the pipeline's overall length have already been laid. Wingas expects to start the line in 2011 with Nord Stream. Wingas also is planning construction of the 440-km North European gas pipeline (NEL), which will transport Nord Stream gas from Greifswald to Rehden in Lower Saxony. NEL is scheduled to come on stream in 2011 and has a planned capacity of 20 billion cu m/year.
Russia began production at the 825.2 billion cu m Yuzhno Russkoye gas field in December 2007. Gas from this field will be shipped through Nord Stream once it is completed. In February 2010, Gazprom announced a 3-year production delay to 2016 from its Shtokman gas field (OGJ Online, Feb. 8, 2010). Shtokman is to be another supply source for Nord Stream.
Gazprom and Eni SPA agreed in December 2007 to build the South Stream gas pipeline under the Black Sea and through Bulgaria (Fig. 4). The subsea section will be 900-km long, reaching a maximum depth of 2,250 m. Under consideration are two options for the balance of the overland route: a northwestern route to Slovenia and Austria and a southwestern route to Greece and Italy.
Bulgaria and Russia reached agreement in January 2008. Intergovernmental agreements have also been reached with Serbia, Hungary, Greece, Slovenia, and Austria. Gazprom anticipates making a final investment decision on the project by mid-April 2011. On completion, the €15.5-billion line could distribute gas to northern and southern Europe, with an estimated capacity of 30 billion cu m/year. Participants plan to deliver first gas through South Stream by December 2015.
Electricite de France (EDF) signed a memorandum of understanding with OAO Gazprom in December 2009 for "at least 10%" of the consortium in charge of building South Stream. Gazprom also completed a feasibility study in November 2010 with Romania's Transgaz SA for a potential future leg of the pipeline. Austria's OMV AG and Gazprom signed a cooperation agreement in April 2010 for construction of the Austrian section of South Stream from the Austrian-Hungarian border to the Baumgarten distribution hub.
OMV also, however, continues to advance the 56-in. Nabucco pipeline, which will bring some combination of Central Asian, Caspian, and Middle Eastern gas to the Baumgarten hub in Austria near the Slovakian border at a rate of 31 billion cu m/year, before moving it on to Western Europe (Fig. 4).
Feasibility studies have led to a two-stage construction plan. The first phase, starting in 2011, calls for 2,000 km of pipe between Ankara, Turkey, and Baumgarten, allowing 8 billion cu m/year of gas from the existing Turkish pipeline network to be transported through the line by 2014. Second-stage construction would begin in 2012 and build eastward from Ankara to the Iranian and Georgian borders, bringing total pipeline length to 3,300 km.
Turkey wants Iranian gas for Nabucco. The US supports construction of Nabucco, citing the need to move gas into Europe though economically viable and secure routes, but would likely oppose Iranian exports through it. Turkmenistan is building a 620-mile domestic East-West gas pipeline to transport gas from its Southern Yolotan-Osman field near the border with Afghanistan to its Caspian Sea coastal region but has remained noncommittal as to whether the gas would then be moved across or around the Caspian to potentially supply Nabucco or follow a different path, maintaining for the time being that it has enough gas to supply multiple export routes.
Nabucco is expected to cost around $11 billion. Nabucco has six shareholders: Turkey's Botas, Bulgaria's Bulgargaz, Romani's Transgaz, Hingary's MOL, Austria's OMV, and Germany's RWE.
To deliver gas from Bovanenkovo field Russia is building a multi-line gas transmission system connecting the Yamal Peninsula and central Russia. Construction calls for 1,420-mm OD pipes designed to work at higher pressures than existing Russian lines.
Total pipeline length will exceed 2,400 km, consisting of the Bovanenkovo-Ukhta pipeline (1,100 km, 140 billion cu m/year) and the Ukhta-Torzhok gas pipeline (1,300 km, 81.5 billion cu m/year). Connection to the Ukhta hub will allow shipment through the Yamal-Europe pipeline.
Gazprom began building the 72 km subsea section of the Bovanenkovo-Uktha line, crossing Baidarate Bay, in August 2008. Construction of the main trunkline began in December 2008. Concrete-covered pipes for the subsea section were still being shipped as of November 2010, however, with estimates placing completion of the line at as late as 2013 despite Gazprom's earlier statements that Bovanenkovo gas would begin shipment during 2011.
Galsi SPA and Snam Rete Gas SPA signed a memorandum of understanding in November 2007 to construct the Italian section of the planned 8 billion cu m/year Galsi natural gas pipeline, which will deliver Algerian gas to Italy via Sardinia.
Galsi shareholders are Sonatrach, Edison SPA, Enel SPA, Hera Trading, Regione Sardegna, and Wintershall AG.
The project envisions four pipeline segments: 640 km onshore between Hassi R'mel gas field in Algeria and El Kala on the Algerian coast; 310 km between El Kala and Cagliari on Sardinia in water as deep as 2,850 m; 300 km between Cagliari and Olbia on the northern Sardinian coast; and 220 km between Olbia and Pescaia, southeast of Florence, in water as deep as 900 m.
Sonatrach will deliver 3 billion cu m/year into the system, Enel 2 billion cu m/year, and Hera Trading 1 billion cu m/year.
Work on the line was under way in January 2009, with service expected by 2012-13. The European Commission gave the project a €120 million grant in March 2010 as part of its economic recovery package for the continent.
Iran and Pakistan continued laying the groundwork during 2010 toward building the long-contemplated gas export line from Iran. The $7 billion project would transport as much as 2.2 bcfd of natural gas from South Pars field in the Persian Gulf through 1,850 km of 56-in. OD line (Iran, 1,100 km; Pakistan, 750 km).
The Iran-Pakistan pipeline would be an extension of Iranian Gas Trunkline (IGAT) VII, which began flowing gas in September 2010. Running 907 km from Assaluyeh to Iranshahr in Iran's Sistan-Baluchestan province, the 56-in. OD line can carry 1.8 bcfd of South Pars gas, with National Iranian Gas Co. planning expansion to 2.9 bcfd.
FACTS Global Energy Group, Honolulu, said the export pipeline will enter Pakistan in southern Balochistan, running to Sindh province where the country's main pipeline hub lies. From Sindh, gas would travel through SSGC's existing distribution network. Iranian gas entering Pakistan will be used by independent power producers, according to FACTS.
Pakistan and Iran signed an agreement in June 2010 for initial deliveries of 750 MMcfd beginning in 2014.
IGAT IX, slated for 2014 completion and also termed the Europe Gas Export Line, would move South Pars 9-10 gas 1,863 km from Asalouyeh to the Turkish border. Construction on the stretch from Asalouyeh to Bidbolyand was completed as of June 2008.
Iran has expressed interest in finding an international partner on a build-own-operate basis for the balance of IGAT IX, which could link with either the proposed Trans-Adriatic pipeline or the proposed Nabucco pipeline for exports farther west.
In July 2010 Turkey denied press reports indicating it had reached agreement with Iran for shipment of gas to Turkey, with private Turkish firm Som Petrol ending up being the counterparty.
Nigeria, Algeria, and Niger hope to start gas exports via the proposed 30 billion cu m/year Trans-Sahara gas pipeline in 2015. Once built, the 4,300-km line would transport gas from the Niger Delta in southern Nigeria through Niger and into Algeria and Europe. Cost estimates for the project are $13 billion.
According to the feasibility report published by engineering company Penspen Consulting, TSGP would comprise a 48-56-in. pipeline from Nigeria to Algeria's Mediterranean coast at Beni Saf and subsea pipelines of 20-in. between Beni Saf and Spain.
Nigeria's militant Movement for the Emancipation of the Niger Delta (MEND) has said it would attack any such pipeline. Algeria, Niger, and Nigeria signed an agreement in July 2009 to start the process of building the TSGP. Russia's OAO Gazprom announced around the same time that it would invest in the TSGP through a 50-50 joint venture, called Nigaz, with state-owned Nigerian National Petroleum Corp. Gazprom said Nigaz intends to explore for gas and to develop infrastructure for its development and transport—up to and including a section of pipeline that could form part of the TSGP.
No date has yet been given for the start of work on the TSGP, however, and Algeria's invitation in August 2010 for India to join the project was seen by some as an indication the project might be in trouble.
South Africa's New Multi-Products Pipeline (NMPP) project will move diesel, gasoline, and jet fuel from an import terminal in Durban roughly 525 km northwest to the inland Gauteng region. Transnet Ltd. received the final environmental impact report for NMPP in November 2008, with the report submitted at the same time to the Department of Environmental Affair and Tourism for a decision. Transnet completed its internal review of the project in December 2010.
NMPP will include as many as 10 pump stations, with four planned at start-up and others added as needed to meet demand. NMPP will consist of three inland 16-in OD pipelines, a 24-in. OD trunkline from the Port of Durban to Jameson Park in Gauteng, and storage facilities in both Durban and Gauteng.
The 24-in. OD pipeline will supplement the existing 12-in. Durban-Johannesburg Pipeline (DJP) completed in 1965 and operating at capacity. The trunkline will be completed third-quarter 2011 and be operating by yearend. The 16-in. pipelines are complete, running between Kendall and Watloo, Alrode and Langlaate, and Alrode and Jameson Park. Transnet expects the full system to be operating at capacity by yearend 2013.
Algeria's Sonatrach is building a 784-km natural gas pipeline, GK3, from Hassi R'mel to an LNG terminal at Skikda. The 48-in. OD pipeline would run 275 km from Hassi R'mel to Chaiba and then 509 km from Chaiba to Skikda. Gas from the line would go into power generation and the planned Galsi pipeline in addition to being used for LNG at Skikda. Sonatrach intends to complete the pipeline in third-quarter 2011, with construction ongoing as of October 2010.