Planned pipeline construction to be completed in 2013 jumped 73% from the previous year, with sharply higher levels of planned crude and products pipelines more than countering somewhat softer natural gas pipeline construction plans.
Operators plan to complete installation of 15,358 miles in 2013 alone (Table 1), with crude and product construction’s combined share of the plans (more than 9,195 miles) making up nearly 60.5% of the total, based on reports from the world’s pipeline operating companies and data collected by Oil & Gas Journal.
Looking forward to beyond 2013, however, for the fifth consecutive year less mileage is planned than had been the previous year, as gas pipeline plans softened in almost all regions.
This shrinkage in natural gas pipeline plans was consistent with 2013-only plans. But long-term construction plans (beyond 2013) saw products line plans relatively flat from the year before as NGL lines in the US begin to be completed.
Larger long-term crude pipeline plans in Canada, Europe, the Middle East, and Africa boosted beyond-2013 crude miles by 14% from global totals the previous year.
Planned product pipeline construction for beyond 2013 registered sharp decreases in the US.
As a whole, combining both current-year and forward estimates (Fig. 1), the US, Canada, Europe, and Africa saw increases in planned construction, with decreases in all other regions.
As 2013 began, operators had announced plans to build more than 44,800 miles of crude oil, product, and natural gas pipelines extending into the next decade, a 1.7% decrease from data reported the previous year (OGJ, Feb. 6, 2012, p. 102). The majority (nearly 66%) of these plans is still for natural gas, but this segment continues to contract globally relative to crude and products.
The downturn in worldwide pipeline construction trends reflects US Energy Information Administration energy consumption forecasts, which show a slowdown in expected growth.
EIA forecast world marketed energy consumption to increase by 53% through 2035 (using a 2008 baseline), a period that encompasses the long-term pipeline construction projections stated here.
Energy demand growth will be strongest, according to the September 2011 analysis (the EIA did not publish an International Energy Outlook in 2012), among countries not members of the Organization for Economic Cooperation and Development (non-OECD), where economic growth remains high, driven in part by strong capital inflows and high commodity prices. Non-OECD growth will be led by China and India where combined energy use will more than double over the projection period to make up 31% of total global demand by 2035. China’s energy demand will be 68% higher than US energy demand by the end of the projection period.
Fuelling this energy demand growth is projected gross domestic product growth in non-OECD Asia of 5.3%/year through 2035—led by China at 5.7%/year, the highest projected growth rate in the world—compared with 3.4%/year worldwide. China’s rate of growth is slightly lower than EIA projections from a year earlier, while non-OECD Asia and worldwide growth were both higher than year-earlier estimates.
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 the EIA. The development of domestic capital markets to help macroeconomic stability and ensure China’s large savings are used efficiently supports medium-term growth projections, said 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. Even so, EIA projects 5.5%/year GDP growth in India 2008-35, up from 5.0% the previous year.
In December 2012 the EIA forecast up and down movement in US liquid fuels consumption through 2040, rising to 19.8 million b/d by 2019 (from 18.9 million b/d in 2011) before dropping back to 18.9 million b/d by 2040. Biofuels consumption increases over most of the projection period.
EIA projects US oil production climbing more than 31.5% from 5.7 million b/d in 2011 to 7.5 million b/d in 2019 and remaining greater than 6 million b/d through 2040, with production increases stemming from tight onshore formations.
The agency increased its cumulative production of dry natural gas estimate for 2011-35 from its Annual Energy Outlook 2012 forecast by 8%, primarily reflecting continued increases in shale gas production. It projects 2040 US production of roughly 34 tcf.
The 2013 outlook projects the US becoming a net exporter of LNG in 2016 and an overall net exporter of natural gas in 2020. EIA sees LNG exports from new liquefaction capacity peaking at 4.5 bcfd in 2027 and net pipeline exports beginning in 2021 as imports from Canada fall steadily and net pipeline exports to Mexico grow by 387%.
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, 2012 (the most recent 1-year period surveyed) demonstrated the continued shift to smaller, more local projects in the US, vs. larger interstate pipeline construction.
• More than 144 miles of gas pipeline were proposed for land construction, and no miles for offshore work. For the earlier 12-month period ending June 30, 2011, more than 286 miles were proposed for land construction.
• FERC applications for new or additional horsepower at the end of June 2012 also slipped, to more than 184,000 hp from just under 233,500 hp.
For 2013 only (Table 1), operators plan to build more than 15,300 miles of oil and gas pipelines worldwide at a cost of more than $50 billion. For 2012 only, companies had planned nearly 8,900 miles at a cost of more than $39.6 billion.
For projects completed after 2013 (Table 2), companies plan to lay more than 44,800 miles of line and spend roughly $144 billion. When these companies looked beyond 2012 last year, they anticipated spending roughly $203 billion to lay more than 45,500 miles of line. Construction costs dropped in the meantime to $3.1-million/mile from $4.4-million/mile.
• Projections for 2013 pipeline mileage reflect only projects likely to be completed by yearend 2013, including construction in progress at the start of the year or set to begin during it.
• Projections for mileage after 2013 include construction that might begin in 2013 but be completed later.
Also included are some long-term projects judged as probable, even if they will not break ground until after 2013.
US average cost-per-mile for onshore pipeline construction (Table 4, OGJ, Sept. 3, 2012, p. 118) on FERC applications submitted by June 30, 2012, was $3.1 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, 2011, or 2012.
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 (14,290 miles) for 2013 only will cost more than $44 billion:
—$578 million for 4-10 in.
—$15.8 billion for 12-20 in.
—$13.4 billion for 22-30 in.
—$14.5 billion for 32 in. and larger.
• Total offshore construction (1,068 miles) for 2013 only will cost more than $5.7 billion:
—$111 million for 4-10 in.
—$3 billion for 12-20 in.
—$2.6 billion for 22-30 in.
• Total onshore construction (42,565 miles) for beyond 2013 will cost nearly $132 billion:
—$2.9 billion for 4-10 in.
—$19.7 billion for 12-20 in.
—$41 billion for 22-30 in.
—$68.4 billion for 32 in. and larger.
• Total offshore construction (2,270 miles) for beyond 2013 will cost more than $12 billion:
—$558 million for 4-10 in.
—$3.8 billion for 12-20 in.
—$7.9 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—Gas, NGL
TransCanada Alaska, the state’s licensee to build a natural gas pipeline from Alaska’s North Slope, received state clearance May 2, 2012, to change the project’s focus to a large-diameter pipeline to an Alaska tidewater site for in-state use, liquefaction, and export.
The move came after TransCanada Corp. and the North Slope’s three major producers—BP PLC, ConocoPhillips, and ExxonMobil Corp.—announced Mar. 30 that they would work together to commercialize ANS gas by focusing on large-scale exports from south-central Alaska as an alternative to a pipeline through Alberta to markets in the US Lower 48. The companies estimated the cost of the project, including the LNG liquefaction plant and export terminal, at $45-65 billion (OGJ Online, Oct. 5, 2012).
To accommodate the transition, state commissioners agreed to defer filing a certificate application for an Alberta line with FERC to October 2014 from October 2012. The Alaska Gas Pipeline Project Office said that about half of the work TransCanada has done so far on the Alberta option, including environmental and engineering studies, could apply to an in-state LNG export line.
Some of the Alberta work would continue under the new project plan, either as dual use for an LNG project or to preserve work on the Alberta option for potential transfer to the state under terms of the license.
TransCanada was awarded rights to build a North Slope gas pipeline under the Alaska Gasline Inducement Act in January 2008. In June 2009 TransCanada agreed with ExxonMobil Corp. affiliates to work together on the pipeline. ExxonMobil shares expenses in advancing the project’s technical, commercial, regulatory, and financial aspects, while TC Alaska remains the AGIA licensee.
The Alaska Pipeline Project initially presented two alternatives for assessment by potential shippers, only one of which would move forward. One option would have transported an estimated 4.5 bcfd of gas from Alaska’s North Slope about 1,700 miles across Alaska to Alberta, where it could be sent on existing pipelines to North American gas markets. The second option called for shipping 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.
Alaska’s Natural Gas Development Authority continues also to develop plans for intrastate gas pipelines, including the Alaska Gasline Development Corp.’s (AGDC) 737-mile, 24-in. OD line intended to bring North Slope gas south. AGDC submitted its plan for the project–the Alaska Stand -Alone Pipeline–to the Alaska legislature in July 2011. It included a revised project timeline with first gas in late 2018 instead of end 2015.
The plan called for public ownership of the line, noting that the lower borrowing costs would allow for the lowest possible tariffs structure, with a private company both to build and operate the system. The plan also noted the apparent commercial feasibility of a 500-MMcfd gas liquefaction anchor tenant for ASAP and estimated the cost of the pipeline at $7.5 billion, with a 30% margin of error.
The system as proposed will run from Prudhoe Bay following the Trans Alaska Pipeline System (TAPS) and Dalton highway corridors to near Livengood, northwest of Fairbanks, at which point it would follow the Parks highway corridor south to its terminus interconnect with the Beluga Pipeline near Big Lake (part of the Enstar Beluga distribution system). The system would include a 35-mile, 12-in. OD lateral to Fairbanks, with a capacity of 60 MMcfd.
AGDC received its final environmental impact statement from the federal government on the project in October 2012.
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 socio-economic impacts of the $16.2-billion (Can.) project, approved it in December 2009. Canada’s National Energy Board followed suit in December 2010 and issued a certificate of public convenience and necessity for the project in March 2011. Imperial Oil Ltd., however, won’t make a final investment decision on the project until later this year
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 (Can.) for the Mackenzie Valley mainline, $3.5 billion (Can.) for the gas gathering system, and $4.9 billion (Can.) for anchor-field development.
A number of projects are under evaluation to move NGLs, primarily ethane, produced in the Marcellus shale to potential consuming centers.
Enterprise Products Partners LP announced in January 2012 that it had received sufficient transportation commitments to support development of its 1,230-mile Appalachia to Texas ethane pipeline (ATEX Express), running from the Marcellus-Utica Shale areas of Pennsylvania, West Virginia, and Ohio to the US Gulf Coast. ATEX Express will have capacity to transport up to 190,000 b/d from Appalachian producing areas to Enterprise’s storage and distribution in Texas.
Originating in Washington County, Pa., the first leg of the system would involve building about 595 miles of new pipeline extending to Cape Girardeau, Mo., closely paralleling an existing Enterprise pipeline. At Cape Girardeau, Enterprise will reverse a 16-in. OD pipeline and place it into ethane service. At the southern terminus of the ATEX Express pipeline, Enterprise will build a 55-mile, 16-in. OD pipeline to provide shippers with access to its NGL storage at Mont Belvieu, Tex.
Enterprise launched a supplemental open season on ATEX in August 2012 to offer additional 15-year binding transportation agreements. The company expects ATEX Express to enter service first-quarter 2014, reaching full capacity by 2018. Chesapeake Energy Corp. signed a long-term contract as anchor shipper in November 2011.
Project Mariner, announced in 2010 by Sunoco Logistics Partners LP and MarkWest Energy Partners LP, would transport 50,000 b/d of Marcellus shale ethane to the Philadelphia area from where it would move via ship to either the US Gulf Coast or Europe (OGJ Online, Aug. 10, 2012). Mariner West, a 65,000-b/d expansion of Project Mariner, would move ethane to Sarnia, Ont. MarkWest expects Mariner West to enter service the middle of this year.
The combined projects would include 85 miles of new pipeline construction, using existing Sunoco infrastructure for the balance of each route. MarkWest would build ethane storage in the Philadelphia, Pa., and Nederland, Tex., areas as part of the project, using existing storage in Sarnia.
Sunoco held a binding open season in 2012 for Project Mariner East and expects to begin propane shipment by second-half 2014 and full propane and ethane operations by first-half 2015. MarkWest says capacity of Sunoco’s existing 8-in. OD pipeline between Delmont, Pa., and Philadelphia could be increased to meet any future increase in demand for space on the system. New pipe would be used between Houston, Pa., and Delmont.
Both the Bakken and Permian plays also saw NGL pipeline proposals.
Oneok Partners LP held an open season in late 2012 for its 600-mile Bakken NGL Pipeline, which will transport unfractionated NGLs from the Bakken shale in the Williston basin to an interconnection with the 50%-owned Overland Pass Pipeline in northern Colorado. Oneok expects the 60,000-b/d pipeline—now under construction—to enter service first-quarter 2013. Oneok expects to complete an expansion of Bakken NGL to 110,000 b/d in third-quarter 2014.
Enterprise Products Partners LP, Enbridge Energy Partners LP, and Anadarko Petroleum Corp. agreed to design and build a 20-in OD, 580-mile NGL pipeline from Skellytown, Tex., to fractionation and storage in Mont Belvieu, Tex. The 280,000-b/d Texas Express Pipeline (TEP) will provide additional takeaway capacity to producers in West and Central Texas, the Rocky Mountains, Southern Oklahoma, and the Midcontinent, according to the joint venture, and additional supplies to Gulf Coast petrochemical facilities. TEP can expand to roughly 400,000 b/d given sufficient market interest.
The joint venture executed 15-year term contracts in March 2012 for 232,000 b/d of the pipeline’s capacity, sufficient to move the project forward. Enterprise will build and operate the pipeline, with Enbridge building and operating the gathering systems. The venture expects the pipeline and gathering systems to begin service second-quarter this year.
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 capacity to 1.1-million b/d at a total capital cost of about $12.2 billion. Keystone XL secured initial firm, long-term contracts for 380,000 b/d for an average of 17 years from shippers.
Keystone XL would include 1,980 miles of 36-in. OD line starting in Hardisty, Alta., and extending to delivery near existing terminals in Port Arthur, Tex. 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 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.
Keystone XL, however, became embroiled in US domestic politics, with the administration of President Barack Obama in November 2011 deferring a decision on the pipeline until 2013 to consider environmental concerns regarding its routing through Nebraska. In May 2012, TransCanada submitted a new application to the US Department of State for the project and in September the company filed a new route for the pipeline, bypassing the Sandhills region, with Nebraska’s Department of Environmental Quality. The State Dept. is to make a decision later this quarter.
TransCanada in the meantime began work on its Gulf Coast Project crude oil pipeline between Cushing, Okla., and Nederland, Tex., despite both the delays to Keystone XL (of which the Gulf Coast Project would be a component) and plans to reverse the Seaway pipeline to deliver crude along a similar route. TransCanada separated the Gulf Coast Project from Keystone XL in February 2012 and in July received the final of three key permits needed from the US Army Corps of Engineers to advance the 485-mile pipeline (OGJ Online, July 27, 2012). It expects to place the pipeline in service by late this year.
Enbridge bought ConocoPhillips’s share of Seaway, joining with EPP in its ownership and jointly announcing that its flow would be reversed to deliver crude from Cushing to the Gulf Coast. Initial capacity of the reversed pipeline was 150,000 b/d, with expansion to 400,000 b/d completed in January 2013. Seaway plans to reach a final capacity of 850,000 b/d by mid-2014.
Enbridge is also building its Flanagan South Project between Flanagan, Ill., and a connection with Seaway at Cushing. The company currently operates the 193,300-b/d Spearhead Pipeline along this route. The 600 mile, 36-in. OD Flanagan South line will open mid-2014 with 600,000 b/d capacity, expandable to 800,000 b/d.
Enbridge plans to build the Northern Gateway Pipeline to transport 525,000 b/d of oil sands crude from near Edmonton, Alta., 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 2013-16, pending regulatory approval of filings made in 2009. Commissioning and start-up would occur 2014-15. Enbridge would also operate the Kitimat terminal. It would have 2 mooring berths, 14 storage tanks for petroleum and condensate, and be called on by roughly 225 ships/year.
British Columbia Premier Christy Clark, however, declared in July 2012 that the environmental risks of the project outweigh its economic benefits and asked that B.C. be compensated for allowing the pipeline to cross. The pipeline was already encountering opposition from environmentalist groups.
That same month Northern Gateway announced additional measures to ensure pipeline integrity, including increased WT, more remote-operated isolation valves, more in-line inspections, and staffing at remotely located pump stations.
Kinder Morgan Energy Partners LP will build and operate a 136-mile, 16-in. OD pipeline to transport gasoline, jet fuel, and diesel from refineries in Norco, La., to an existing petroleum transportation hub in Collins, Miss., owned by Plantation Pipe Line Co. From this hub, the products can move to major markets in the southeastern US.
Kinder Morgan is partnering with Valero Energy Corp. in the joint venture. The pipeline will have an initial capacity of 110,000 b/d with the ability to expand to more than 200,000 b/d. Kinder Morgan began building the pipeline in August 2012 and expects it to be in service September 2013.
The 1,448 km (900 miles), 48-in. OD Gasoducto del Noreste will deliver 3.2 bcfd of Bolivian gas to Argentina as early as 2016 via a connection to Bolivia’s Juana Azurday Integration Pipeline. The Bolivian government, Argentine-state Enarsa, and Gazprom are developing the $2.67 billion project, which will also include 2,683 km of branch lines, a 15,000-km distribution network, and eight compressor plants.
Argentina approved plans for the pipeline in December 2010 and Enarsa issued a call for bids on the project in January 2013. The pipeline will move supplies from Bolivia to the Argentine provinces of Chaco, Corrientes, Formosa, and Misiones and later to Cordoba and Santa Fe. A 38-in. OD section of pipe running 48 km between Bolivia’s Margarita gas field and Salta, Argentina, entered service July 2011.
Petrobras and Odebrecht plan to build the 1,085-km Gasoducto Andino del Sur to move natural gas from Camisea to Juliaca near Lake Titicaca and the Port of Ilo. 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 to enter service in 2014-15, with cities en route before the planned terminus in Ilo likely to get gas before completion of the entire line. The Peruvian government emphasized that the pipeline would be completed “as soon as possible” as recently as August 2012, according to Business News Americas, though other regional media voiced concern that modifications to Block 88 contracts allocating production exclusively to domestic consumption would undermine the project’s feasibility.
Comisión Federal de Electricidad (CFE), Mexico’s state-owned electric utility, awarded Sempra Mexico a contract to build, own, and operate a roughly 500-mile, $1 billion pipeline network connecting the northwestern Mexico states of Sonora and Sinaloa. The network will consist of two segments interconnecting with the US interstate pipeline system in Arizona, shipping natural gas to new and existing CFE power plants currently using fuel oil.
The first segment, a 36-in. OD, 310-mile pipeline, will run from Sasabe, south of Tucson, Ariz., to Guaymas, Sonora, shipping 770 MMcfd by late 2014. The second segment from Guaymas to El Oro, Sinaloa, is a 30-in. OD, 200-mile pipeline moving 510 MMcfd. CFE expects to start the second line in third-quarter 2016. CFE has fully contracted system capacity under two 25-year firm contracts denominated in US dollars.
CFE also awarded TransCanada Corp.’s Mexican subsidiary, Transportadora de Gas Natural de Noroeste (TGNN), the contract to build, own, and operate two new pipelines. The 30-in. OD, 329-mile El Encino-to-Topolobampo Pipeline will run from El Encino, in the state of Chihuahua, to Topolobampo in Sinaloa, at a contracted capacity of 670 MMcfd. TransCanada expects to spend about $1 billion on the pipeline, supported by a 25-year natural gas transportation service contract with the CFE. The company anticipates the pipeline will enter service third-quarter 2016.
TGNN also won the contract for the El Oro-to-Mazatlan Pipeline. The 24-in. OD pipeline will run 257 miles and have contracted capacity of 202 MMcfd. TransCanada expects the pipeline, which will interconnect with the El Encino-to-Topolobampo pipeline, to enter service fourth-quarter 2016 (OGJ Online, Nov. 6, 2012).
China National Petroleum Corp. has started building the country’s Third West-East Gas Pipeline (WEPP 3), consisting of 7,378 km spread over one trunkline and eight branches (OGJ Online, Oct. 23, 2012). Three gas storage sites and one LNG liquefaction plant are also part of the project.
The 5,220-km trunk will start in Horgos, Xinjiang, and end at Fuzhou, Fujian province, crossing 10 provinces and regions including Xinjiang, Gansu, Ningxia, Shaanxi, Henan, Hubei, Hunan, Jiangxi, Fujian, and Guangdong. The pipeline will deliver 30 billion cu m/year (bcm/year; about 1.06 tcf) using an operating pressure of 10-12 MPa (about 1,450-1,740 psi).
CNPC expects the pipeline to be completed in 2015, connecting to Line C of the Central Asia-China Gas Pipeline, also now under construction. WEPP 3 will mainly transport gas from the Central Asia pipeline, using incremental production in the Tarim basin and coal gas in Xinjiang to supplement these supplies.
Transneft is building the second stage of the Eastern Siberia-Pacific Ocean (ESPO) crude pipeline, which transports oil from fields in Eastern Siberia to consumers on the Pacific coast and for export to China. The company expects total capacity of ESPO-2 to reach 50 million tonnes/year (tpy), with construction between Skovorodino and Kozmino complete in 2014.
Rosneft and Transneft agreed in September 2012 jointly to build a branch off ESPO linking it to Rosneft’s Komsomolsk-on-Amur refinery. The branch will have a capacity of 8 million tpy. The companies expect construction to take 4 years.
Crude currently arrives at the refinery by rail. Transneft will finance the design and construction of the offshoot using long-term fees paid by Rosneft as part of a separate shipment agreement.
China National Petroleum Corp. is building and will operate the Myanmar-to-China crude oil pipeline. This line and a companion natural gas pipeline will transport hydrocarbons from the Bay of Bengal across Myanmar to southwestern China. The 440,000-b/d crude pipeline runs 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 operations during 2013.
The natural gas pipeline is likewise scheduled to begin carrying 12 bcmy to southwestern China in 2013. 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. A large oil import port at Kyaukpyu, Myanmar, also built by China will serve as the crude pipeline’s input point. The port can receive vessels up to 300,000 dwt and has storage capacity of 600,000 cu m.
Total estimated project costs are $1.5 billion for the oil pipeline and $1.04 billion for the gas pipeline.
Gazprom and Eni SPA agreed in December 2007 to build the South Stream gas pipeline under the Black Sea and through Bulgaria. The subsea section will be 900-km long, reaching a maximum depth of 2,250 m. The two overland branches of the pipeline will run northwest to Slovenia and Austria and southwest to Greece and Italy.
OAO Gazprom and Bulgarian Energy Holding EAD signed a protocol in August 2012 defining South Stream’s entry point into the Bulgarian gas transmission system, its parameters, and further development of the project (OGJ Online, Aug. 30, 2012).
Intergovernmental agreements have also been reached with Serbia, Hungary, Greece, Slovenia, and Austria. 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. In December 2011, Turkey granted Gazprom permission to lay South Stream though its exclusive economic zone in the Black Sea.
On completion, the €15.5-billion line will transport 30 bcmy. Participants plan to deliver first gas through South Stream by December 2015.
The Shah Deniz consortium in June 2012 selected the 800-mile Nabucco West project, extending from the Turkish-Bulgarian border to Baumgarten, Austria, as the single pipeline option for the potential export of gas from the BP-operated Shah Deniz II project to Central Europe. Development of the South East Europe Pipeline (SEEP) project—undertaken by the Shah Deniz partners along with Bulgaria, Romania, and Hungary—stopped.
The consortium described Nabucco’s greater maturity as giving it the best chance of being developed and delivered on the same yearend 2017 timeline as Shah Deniz II. The consortium said it will cooperate with the Nabucco West project on scope, technical studies, and commercial terms. Nabucco West will have an initial capacity of 10 bcmy, expandable to 23 bcmy to meet demand.
At the same time, Turkey and Azerbaijan agreed to build the 16-bcmy Trans-Anatolian natural gas pipeline, transporting Azeri gas through Turkey to a potential interconnection with Nabucco West. The pipeline would extend 2,400 miles at an estimated cost of $5 billion.
Gas would come from Shah Deniz II. The Trans-Anatolian pipeline was originally proposed in November 2011 as the non-European Union segment of a Southern Corridor natural gas pipeline to supplant the full OMV-led Nabucco pipeline project.
The Shah Deniz consortium in February selected the Trans-Adriatic Pipeline (TAP) as the potential route for Shah Deniz II gas to Italy and since concluded a cooperation agreement with TAP. Shah Deniz will make a final decision between these projects and conclude related gas sales agreements ahead of a final investment decision planned for mid-2013.
BP’s partners in Shah Deniz II are Statoil 25.5%, State Oil Co. of Azerbaijan Republic 10%, Lukoil 10%, Total 10%, Naftiran Intertrade Co. 10%, and Turkish Petroleum AO 9%. BP’s share is 25.5%.
Shah Deniz II will add 16 bcmy of gas production to the roughly 9 bcmy from Shah Deniz Stage 1. Field development, some 70 km offshore Baku in the Azerbaijan sector of the Caspian Sea, will include two new bridge-linked production platforms; 26 subsea wells to be drilled with 2 semisubmersible rigs; 500 km of subsea pipelines built at up to 550 m of water; a 16-bcmy upgrade for the South Caucasus Pipeline; and expansion of the Sangachal Terminal
Galsi SPA and Snam Rete Gas SPA signed a memorandum of understanding in November 2007 to construct the Italian section of the planned 8-bcmy 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 Porto Botte in southern Sardinia in water as deep as 2,850 m; 300 km between Porto Botte 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 bcmy into the system, Enel, 2 bcmy, and Hera Trading, 1 bcmy.
Work on the line was under way in January 2009 with service expected during 2014. The European Commission gave the project a €120-million grant in March 2010 as part of its economic recovery package for the continent.
Environmental concerns on the part of elected officials in Sardinia, however, have slowed progress. Algeria has maintained its interest in the project despite media reports that it would withdraw if Italy backed South Stream and the Trans-Adriatic Pipeline. Galsi shareholders have postponed a final investment decision to May 30, 2013.
The long-contemplated gas export line from Iran to Pakistan suffered new setbacks in 2012. Pakistan President Asif Ali Zardari cancelled a December visit to Iran to finalize details of the project amid growing US opposition, despite Iran having offered to help finance it. The pipeline was originally to have extended to India, but India withdrew amid concerns regarding Pakistan’s ability to guarantee the line’s security.
The 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). Pakistan and Iran signed an agreement in June 2010 for initial deliveries of 750 MMcfd beginning in 2014. Pakistan has 8 bcfd of demand and currently just 4.2 bcfd of supply.
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.
The export pipeline would enter Pakistan in southern Balochistan, running to Sindh province where the country’s main pipeline hub lies. From Sindh, gas would travel through Sui Southern Gas Co.’s existing distribution network. Iranian gas entering Pakistan will be used by independent power producers, according to FACTS Global Energy.
Abu Dhabi is building a 500-km, 8-14 in. OD CO2 pipeline as part of the Masdar Initiative’s carbon capture and sequestration project. Abu Dhabi Future Energy Co. (Masdar) launched the project in 2008 with the stated goal of building the world’s first zero-carbon sustainable city.
Masdar received bids on Phase 1 of the project in October 2012. Phase 1 is a 190-km pipeline connecting three sites. Masdar expects the pipeline system to enter service in 2015.
Abu Dhabi Gas Industries Co. (Gasco) is building twin 297 km, 52-in. OD pipelines to deliver gas from the Habshan 5 gas processing and sulfur production plant through Maqta, to industrial users in the Taweelah industrial hub. Gasco expects work on the 28 million cu m/day system to be completed by June 2015.
Oman Gas Co. (OGC) plans to build a 240 km, 36-in. OD pipeline to deliver natural gas from Saih Nihayda in central Oman to an industrial and maritime hub being developed in Duqm. OGC expects to award a contract for construction of the 25 million cu m/day pipeline in late 2013, with a targeted in-service date of 2016.
The National Iranian Gas Co. (NIGC) completed construction design for a 270 km, 42-in. OD natural gas pipeline to Iraq in May 2012. The pipeline will deliver 25 million cu m/day from western Iran to the al-Mansoureh power plant and Baghdad. NIGC expects the pipeline to enter service by March 2013.
Kuwait Gulf Oil Co. awarded Technip a contract for engineering, procurement, construction, and commissioning of its Gas and Condensate Export System (GCES) project spread over onshore and offshore locations in Saudi Arabia and Kuwait. GCES is designed to deliver a combination of lean gas, condensate, and sour gas through a single 12-in. OD export pipeline from Al Khafji Joint Operations facilities in Saudi Arabia to Kuwait Oil Co.’s tie-in intermediate slug catcher.
Total export pipeline length is 110 km, with 4 km onshore in Saudi Arabia, followed by 47 km offshore, and 59 km onshore in Kuwait. Technip’s operating center in Abu Dhabi will execute the project, scheduled to be completed by second-half 2014. DLB Comanche, which entered the Technip fleet with the acquisition of Global Industries, will complete offshore operations (OGJ Online, Feb. 15, 2012).
Nigerian National Petroleum Corp. (NNPC) has for the time being scaled back plans to build the Trans-Sahara Gas Pipeline, instead now planning a 1,340-km trans-Nigeria line running south-to-north between Calabar and Kano, Bloomberg reported. A looming combination of Caspian pipeline gas and LNG supplies to Europe undermined the current need for a Trans-Sahara line.
NNPC plans to have the Calabar-Kano line in service no sooner than 2016. It could subsequently form the first leg of TSGP.
The 4,127-km TSGP would have transported gas from the Niger Delta in southern Nigeria through Niger and into Algeria and Europe. Cost estimates for the project were $20 billion.
Tanzania is building a 532-km gas pipeline from Mnazi Bay and Songo Songo to Dar es Salaam. The pipeline, with 36-in. OD trunk and 24-in. OD spur, will transport 784 MMcfd to a power plant.
Zambia and Angola agreed in April 2012 to build the Angola-Zambia Refined Petroluem Multi-Product (AZOP) pipeline. The 1,400-km line will run from Lobito, Angola, to Lusaka, Zambia, carrying gasoline, low-sulfur diesel, jet fuel, and LPG. The Zambia Development Agency (ZDA) and Angola-based Basali Ba Liseli Resources Ltd. (BBLR) plan to begin construction early this year to place the line into service in 2016.
The 200,000-b/d capacity pipeline will deliver 80,000 b/d to Zambia. The line will also deliver to Katanga province, Congo, and within Angola.
Oil producers in Uganda are studying potential routes for a 1,300-km crude oil pipeline to Mombasa, Kenya. Total, Tullow, and CNOOC see the export potential of the pipeline as key to their development plans in the region, but the Ugandan government is concerned that local demand be met first.
At the same time, South Sudan has partnered with Kenya to build a 2,000-km crude export pipeline to Port Lamu, Kenya. Construction of the 700,000-b/d pipeline is to start June 2013 for completion in 2015.
Kenya Pipeline Co. tendered for replacement of a 450 km, 14-in. OD products pipeline running from Mombasa to Nairobi. The existing pipeline, installed in 1978, has reached its design capacity.