Near-term pipeline plans shrink, longer-term growth returns

As 2015 began, operators had announced plans to build more than 41,700 miles of crude oil, product, and natural gas pipelines extending into the next decade, a 21% increase from data reported last year (OGJ, Feb. 3, 2014, p. 90). Most of these plans (more than 66%) are for natural gas, consistent with the share for this segment seen in previous years.

Outlook

In September last year, the US Energy Information Administration (EIA) forecast world liquid fuels consumption to increase by 36% through 2040 (using a 2010 baseline), a period that encompasses the long-term pipeline construction projections described here.

Demand growth will be strongest, according to analysis, among countries outside the Organization for Economic Cooperation and Development (OECD), growing to 63% of world liquid fuels consumption in 2040 from 47% in 2010. This non-OECD growth will be led by Asia, with a 2.6%/year increase in consumption expected, of which China will account for roughly 46%. EIA sees China replacing the US as the world's largest consumer of liquid fuels by 2035.

India's predicted liquid fuels demand in 2040 slipped 1.4 million b/d from EIA's 2013 estimate of roughly 8.2 million b/d. The country's 2010 demand was 3.3 million b/d. EIA expects 43.2-millon b/d of total Asian liquid fuels demand in 2040.

On a far smaller scale, liquid fuel consumption in Africa will grow 2.0%/year during 2010-40, according to EIA.

Non-OECD Asia GDP growth estimates slipped to 5.3%/year through 2040, led by India dropping from 6.1%/year, the highest projected growth rate in the world in EIA's 2013 estimates, to 5.4%/year now. EIA expects a 3.5% global growth rate.

Slowing industrial activity and a sluggish service sector combined with as-yet insufficient structural reforms to lower India's expected economic growth. The country is also trying to reduce subsidies on petroleum products.

Structural issues that have implications for medium to long-term growth in China include its continued labor-intensive and severely polluting production base, a large number of nonperforming loans undermining investment-led growth, acute income inequality, and demographic factors related to an aging population and shrinking workforce.

EIA forecasts up-and-down movement in US liquid fuels consumption through 2040; peaking at 19.3 million b/d by 2019 (from 18.2 million b/d in 2012) before dropping back to 18.5 million b/d by 2032 and remaining at that level or slightly lower through 2040.

EIA projects US crude and lease-condensate production climbing more than 47.7% from 6.7 million b/d in 2012 to 9.9 million b/d in 2018 and remaining at or more than 7.8 million b/d through 2040, with production increases stemming from tight onshore formations.

The agency predicted a 1.6%/year growth rate in US dry natural gas production for 2012-40 in its Annual Energy Outlook (AEO) 2014 forecast, growing to 37.54 tcf from 24.06 tcf. The 56% increase in total gas production over the period results from increased development of shale gas, tight gas, and offshore natural gas.

The 2014 outlook projects the US becoming a net exporter of LNG in 2016 and an overall net exporter of natural gas in 2018, earlier than AEO 2013 by 2 years. EIA sees LNG exports approaching 2 tcf/year by 2020 and reaching more than 5.8 tcf/year by 2039. Net pipeline imports from Canada fall steadily through 2033 and then increase through 2040 to 0.7 tcf and net pipeline exports to Mexico grow by more than 500%, reaching 3.1 tcf in 2040.

For more than 50 years, OGJ has tracked applications for gas pipeline construction to the US Federal Energy Regulatory Commission (FERC). Applications filed in the 12 months ending June 30, 2014, (the most recent 1-year period surveyed) reflected the slowing of near-term construction plans.

• More than 520 miles of gas pipeline were proposed for land construction. For the earlier 12-month period ending June 30, 2013, more than 820 miles were proposed for land construction.

• FERC applications for new or additional compression at the end of June 2014, however, increased, reaching more than 705,000 hp, from more than 450,000 hp.

Bases, costs

For 2015 only (Table 1), operators plan to build more than 6,500 miles of oil and gas pipelines worldwide at a cost of more than $43 billion. For 2014 only, companies had planned more than 9,300 miles at a cost of more than $40 billion.

For projects completed after 2015 (Table 2), companies plan to lay nearly 42,000 miles of line and spend roughly $276 billion. When these companies looked beyond 2014 last year, they anticipated spending roughly $146 billion to lay more than 34,300 miles of line. Land construction costs rose in the meantime from $4.1-million/mile to $6.6-million/mile.

• Projections for 2015 pipeline mileage reflect only projects likely to be completed by yearend 2015, including construction in progress at the start of the year or set to begin during it.

• Projections for mileage after 2015 include construction that might begin in 2015 but be completed later. Also included are some long-term projects judged as probable, even if they will not break ground until after 2015.

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 (6,149 miles) for 2015 only will cost more than $40 billion:

-$3.3 billion for 4-10 in.

-$11.4 billion for 12-20 in.

-$6.8 billion for 22-30 in.

-$18.9 billion for 32 in. and larger.

• Total offshore construction (363 miles) for 2015 only will cost nearly $2.8 billion:

-$424 million for 4-10 in.

-$1.5 billion for 12-20 in.

-$882 million for 22-30 in.

• Total onshore construction (40,008 miles) for beyond 2015 will cost nearly $263 billion:

-$4.8 billion for 4-10 in.

-$30.5 billion for 12-20 in.

-$67 billion for 22-30 in.

-$160 billion for 32 in. and larger.

• Total offshore construction (1,731 miles) for beyond 2015 will cost more than $13 billion:

-$626 million for 4-10 in.

-$3.9 billion for 12-20 in.

-$8.7 billion for 22-30 in.

Action

What follows is a 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 move that gas to market as quickly and efficiently as possible. The following sections look at both natural gas and liquids pipelines.

US, Canada activity

Near-term pipeline construction plans in the US and Canada centered on US crude transportation, with the focus switching to US gas lines farther out.

Gas, NGL

TransCanada Alaska, the state's licensee to build a natural gas pipeline from Alaska's North Slope (ANS), 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, 2012, 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 four companies completed the project's concept selection phase in February 2013.

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 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 the two companies formed 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 3-3.5 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.

This latter option, now named Alaska LNG and including the Alaska Gasline Development Corp., is in prefront-end engineering and design (pre-FEED), expected to complete late this year or early 2016. The US Department of Energy (DOE) in November granted Alaska LNG authority for exports to countries covered by free-trade agreements (FTA) with the US. South Korea is the only large Asian consumer with a US FTA. Approval to such non-FTA destinations as Japan, China, India, and Taiwan is pending.

Large gas pipeline projects in Canada centered on shipping material from shale plays in Alberta and British Columbia to the Pacific Coast for liquefaction and export. In early 2013, Chevron Canada Ltd. announced plans to buy 50% of Kitimat LNG and the proposed Pacific Trail Pipeline. Pacific Trail is a 290-mile, 36-in. OD pipeline that would move gas from Spectra Energy Corp.'s pipeline system to the Kitimat LNG terminal. The BC government in July 2013 extended Chevron and Apache Corp.'s window to start construction on the line to 2018.

Nova Gas Transmission Ltd. (NGTL) will build the Merrick Mainline pipeline, with Chevron and Apache agreeing to take 1.9 bcfd of gas for Kitimat as the line's anchor customers. The 161-mile, 48-in. OD pipeline will move gas from NGTL's system to Pacific Trail. Woodside Petroleum Ltd. bought Apache's interest in Kitimat LNG late last year (OGJ Online, Dec. 15, 2014).

Spectra is itself planning with BG Group PLC jointly to develop a 42-in. OD, 525-mile gas pipeline from northeast BC to supply BG's potential LNG plant in Prince Rupert, BC. The line would move 4.2 bcfd of gas from the Horn River and Montney developments to the coast for liquefaction and export. Canada's National Energy Board (NEB) in late 2013 approved a 25-year natural gas export license for BG, but subsequent new BC-government tax proposals prompted the company to delay final investment decision (FID) on the project to 2017 (OGJ, Apr. 7, 2014, p. 120).

Progress Energy Canada Ltd. in August 2013 signed firm transportation agreements for an interconnection with TransCanada's proposed Prince Rupert Gas Transmission (PRGT) project to provide gas to the proposed Pacific Northwest LNG export plant near Prince Rupert. PNW LNG is owned by Petronas (77%) and Indian Oil Corp. Ltd. (IOC, 10%) in partnership with Progress. Delivery of 2.1 bcfd from TransCanada's Nova Gas Transmission Ltd. system to the 470-mile, 48-in. OD PRGT would begin in 2019.

In the US, projects to move NGLs to market continued to evolve, with some falling by the wayside and others making headway. Enterprise Products Partners (EPP) LP's 1,230-mile Appalachia to Texas ethane pipeline (ATEX Express), running from the Marcellus-Utica shales of Pennsylvania, West Virginia, and Ohio to the US Gulf Coast, entered service early last year with an initial capacity of 125,000 b/d, expandable to at least 265,000 b/d.

Williams Cos. and Boardwalk Pipeline Partners LP's proposed joint-venture Bluegrass Pipeline would also transport mixed NGLs from the Marcellus and Utica shales to US Gulf Coast petrochemical and export markets. The companies initially expected the 200,000-b/d pipeline to enter service second-half 2015 but suspended capital investment on the project last year primarily due to insufficient firm customer commitments (OGJ Online, Apr. 29, 2014).

Kinder Morgan Energy Partners LP and MarkWest Utica EMG LLC have also proposed the Utica Marcellus Texas Pipeline Y-grade transportation project from the Utica and Marcellus shales to Mont Belvieu, Tex. The pipeline would have an initial design capacity of 150,000 b/d and be expandable to 400,000 b/d. The companies held an open season for the project early last year and are currently conducting public outreach, route selection, and permit preparation targeting a second-quarter 2017 in-service date. The first 1,005 miles of the line would consist of converted Tennessee Gas Pipeline system, with 220 miles of newbuild between Natchitoches, La., and Mont Belvieu.

Project Mariner, announced in 2010 by Sunoco Logistics Partners LP and MarkWest Energy Partners LP, will transport 50,000 b/d of Marcellus shale ethane to the US Atlantic Coast for shipment to Gulf Coast chemical producers and European markets. Mariner West, a 65,000-b/d expansion of Project Mariner, began moving ethane to Sarnia, Ont., in 2013.

The combined projects include only 85 miles of new pipeline construction, using existing Sunoco infrastructure for the balance of each route. MarkWest is building ethane storage near Philadelphia, Pa., and Nederland, Tex., as part of the project, and will be using existing storage in Sarnia.

Sunoco held a binding open season in 2012 for Project Mariner East and expects to begin full propane and ethane operations by first-half 2015. The 70,000-b/d system will use Sunoco's existing 8-in. OD pipeline between Delmont, Pa., and Philadelphia, with new pipe between Houston, Pa., and Delmont.

The company late last year announced it had received sufficient shipper interest to move ahead with its 275,000-b/d Mariner East 2 pipeline, largely paralleling the route of the first line. Sunoco expects to put the 300-mile, 16-in. OD Mariner East 2 in service by yearend 2016 (OGJ Online, Nov. 7, 2014).

The Permian basin has Energy Transfer Partners LP and Regency Energy Partners LP joint venture Lone Star NGL LLC building a 533-mile 24 and 30-in. OD pipeline to Mont Belvieu, converting its existing 12-in. OD NGL pipeline along the same stretch to crude and condensate service. The companies expect the new NGL line to be operating by third-quarter 2016 and the converted crude line by first-quarter 2017 (OGJ Online, Nov. 18, 2014).

Crude

TransCanada announced plans in July 2008 for the Keystone Gulf Coast Expansion Project (Keystone XL), providing additional capacity of 830,000 b/d from western Canada to the US Gulf Coast by 2012. The expansion would boost Keystone's total capacity to 1.1 million b/d.

Keystone XL would include 1,179 miles of 36-in. OD line starting in Hardisty, Alta., and extending to a delivery point in Steele City, Neb. Each XL pump 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. Keystone XL, however, remains embroiled in US domestic politics and its future is uncertain.

TransCanada, meanwhile, built its 700,000-b/d Gulf Coast Project crude oil pipeline (originally part of Keystone XL) between Cushing, Okla., and Nederland, Tex., beginning deliveries on the 487-mile pipeline in January 2014.

Energy Transfer Equity LP, Energy Transfer Partners LP, and Phillips 66 formed joint ventures late last year to build two crude oil pipelines that together will connect the Bakken-Three Forks play in North Dakota to the US Gulf Coast.

Dakota Access will run roughly 1,100 miles linking North Dakota and the hub at Patoka, Ill., delivering at least 450,000 b/d via 30-in. OD pipe to various points in the Midwest (Fig. 2). Energy Transfer Crude Oil Co. LLC will deliver from Patoka to Nederland, Tex. The companies expect both to enter service fourth-quarter 2016 (OGJ Online, Oct. 29. 2014).

Magellan Midstream Partners LP in October announced sufficient shipper interest in transporting various grades of crude oil from the Niobrara shale to its storage in Cushing, Okla., to proceed with its proposed 600-mile, 20-in. OD Saddlehorn pipeline. Saddlehorn will carry as much as 400,000 b/d from Platteville, Colo., to Cushing, using existing right-of-way for what Magellan described as a large portion of its route. Subject to regulatory approvals, Saddlehorn could be operational during second-quarter 2016.

Enbridge's North Dakota Pipeline Co. LLC is proposing to build the 612-mile Sandpiper Pipeline Project. Sandpiper will transport light crude oil from Enbridge's Beaver Lodge Station, near Tioga, ND. through Clearbrook, Minn., to an existing terminal in Superior, Wisc. Sandpiper would use 24-in. OD pipe from Beaver Lodge to Clearbrook and 30-in from Clearbrook to Superior. Enbridge's Line 81 ends in Clearbrook and Sandpiper will carry its volumes to Superior.

Sandpiper will generally follow Enbridge's existing pipelines and other infrastructure right-of-way. In Minnesota, more than 75% of the route follows pipelines and other infrastructure already in operation. Enbridge will install new pumping and storage in Clearbrook.

Enbridge is also undertaking its $7.5-billion Line 3 Replacement (L3R) Program, which the company describes as its largest project ever. L3R will replace most of Enbridge's existing 34-in. OD Line 3 with new 36-in. OD pipeline on either side of the Canada-US border, a total of 1,031 miles.

On the Canadian side, Enbridge will replace most of the existing Line 3 between its Hardisty terminal in east-central Alberta and Gretna, Man. In the US, Enbridge will replace Line 3 between Neche, ND, and Superior, Wisc. Enbridge expects the new line to enter service second-half 2017. It will decommission the existing Line 3.

Shell Pipeline is building the 226-mile, 400,000-b/d Westward Ho pipeline between St. James, La., and Sunoco Logistics terminal in Nederland, Tex., to add new westbound capacity following reversal of its Ho-Ho Pipeline to run from Houston to Houma, La. The 30-in. OD Westward Ho will transport offshore US Gulf of Mexico production starting in late 2017 and be expandable to 900,000 b/d. Additional possible delivery points include Lake Charles, La. (Citgo Petroleum Corp., Phillips 66 Co.), Port Neches, Tex. (Motiva Enterprises, Total SA), and Beaumont/Nederland (Phillips 66, Oiltanking Partners LP, Exxon Mobil Corp.).

Enbridge plans for the Northern Gateway Pipeline to transport 525,000 b/d of oil sands crude from near Edmonton to a tanker terminal in BC 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 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.

Enbridge expected to build Northern Gateway during 2014-17, pending regulatory approval of filings made in 2009. BC Premier Christy Clark, however, declared in July 2012 that the environmental risks of the project outweigh its economic benefits and asked that BC be compensated for allowing the pipeline, which was already encountering opposition from environmental groups, to cross its territory.

That same month Northern Gateway announced additional measures to ensure pipeline integrity, including increased WT, more remotely operated isolation valves, more in-line inspections, and staffing at remote pump stations.

In December 2013, a Canadian federal Joint Review Panel recommended the Canadian government approve Northern Gateway, subject to 209 required conditions and following 18 months of community hearings. Northern Gateway received final approval from the Canadian government in July 2014. The project, however, continues to face both environmental and aboriginal opposition. Enbridge in December announced plans to increase aboriginal participation in and control of the project.

TransCanada's Trans Mountain Expansion project would also move crude west from Alberta. The project would use 36-in. OD pipe to twin 987 km (613 miles) of its existing Trans Mountain pipeline. The company filed for NEB approval in December 2013 as part of a targeted late-2017 in-service date. NEB delayed any decision in September after extending meetings with aboriginal groups.

TransCanada in 2013 reached binding long-term shipping agreements to build, own, and operate the Alberta-based Heartland Pipeline and TC Terminals projects. The projects will include a 200-km, 900,000-b/d pipeline connecting Edmonton to Hardisty, and a crude terminal with 1.9 million bbl of storage in the Heartland industrial area north of Edmonton. TransCanada expects the projects to enter service second-half 2015.

TransCanada announced the related Grand Rapids Pipeline project in 2012, a 500-km system to transport crude oil and diluent between production northwest of Fort McMurray and the Edmonton-Heartland region. The system will deliver 900,000 b/d of crude and 330,000 b/d of diluent by early 2017.

Pembina Pipeline Corp. in 2013 reached binding commercial agreements to move ahead with its $2-billion Phase III pipeline expansion. Pembina expects the 540-km expansion to enter service between late 2016 and mid-2017. Phase III will follow and expand certain segments of Pembina's existing pipeline systems from Taylor, BC, southeast to Edmonton, with priority placed on areas in need of debottlenecking. The core of the expansion will entail building a 270-km, 24-in. OD pipeline from Fox Creek, Alta., to Edmonton.

The expansion will have an initial capacity of 320,000 b/d, expandable to more than 500,000 b/d. Once complete, Pembina will have three distinct pipelines in the Fox Creek-to-Edmonton corridor, with a combined capacity of 885,000 b/d, if fully expanded. The expansion will also increase pipeline interconnectivity between Edmonton and Fort Saskatchewan, including Pembina's Redwater and Heartland Hub sites and third-party delivery points in these areas.

Latin America

Petroleos Mexicanos is building the 600-mile Los Ramones natural gas pipeline. The 2.1-bcfd pipeline will start at the US-Mexico border and be complemented on the US side by a 125-mile pipeline from Agua Dulce, near Corpus Christi, to McAllen, Tex., on the border with Reynosa in northern Mexico.

The Mexican project cost is estimated at $3 billion and the US project $650-750 million, according to RBN Energy. When completed, Los Ramones will move gas from South Texas to the state of Guanajuato in central Mexico, a regional hub for the country's auto industry. Los Ramones Phase 1 entered service in December, running 71 miles from the US border to Los Ramones, Mexico, carrying an initial 1 bcfd through 48-in. OD pipe. Phase 2 will run 460 miles of 42-in. OD across five northern Mexico states, entering service in 2015 (Fig. 3).

TAG Pipelines Sur S de RL de CV let a contract to ICA Fluor, a joint venture of Fluor Corp. and Empresas ICA SAB de CV, to build the 1.42-bcfd Ramones II Sur Gas Pipeline (project Phase 3) through San Luis Potosí, Queretaro, and Guanajuato states in Mexico.

ICA Fluor will conduct engineering, procurement, construction, testing, commissioning, and start-up for the 291.7-km, 42-in. OD pipeline. The line will use one compressor station, in the southern portion of the system. The companies expect second-quarter 2016 completion.

Los Ramones is only one of several pipelines expected to come online in the next few years and underpin substantial growth of US gas flows to Mexico. 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, from Sasabe, south of Tucson, Ariz., to Guaymas, Sonora, began shipping 770 MMcfd late last year. 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 dual 25-year firm agreements denominated in US dollars.

CFE also awarded TransCanada'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 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.

Asia-Pacific

China National Petroleum Corp. (CNPC) is building the country's Third West-East (Gas) Pipeline Project (WEPP 3), consisting of 7,378 km spread over one trunkline and eight branches. Three gas storage sites and one natural gas 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 (bcmy) using an operating pressure of 10-12 MPa.

CNPC expects the pipeline to be completed in 2015, connecting to Line C of the Central Asia-China Gas Pipeline which started operations last year. 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. Asia Gas Pipline LLC-a joint venture of KazMunaiGaz and CNPC-let a contract to Rolls-Royce last year for compression on Line C inside Kazakhstan.

KMG and CNPC are also planning a new crude oil pipeline between Atyrau on the eastern coast of the Caspian Sea and China's Xinjiang province. The pipeline would parallel an existing 350,000-b/d line. The companies expect the 1,384-mile, 28-in. OD pipeline to enter service in 2018.

OAO Gazprom and CNPC last year signed a 30-year natural gas supply contract reportedly worth $400 billion. The contract stipulates that 38 bcmy will be supplied from Russia to China. It includes provisions for a price formula linked to oil prices and a take-or-pay clause. Gas will be delivered via the 2,465-mile Power of Siberia trunk line from Chayanda and Kovyktin fields (Fig. 4). Work on the 56-in. OD line began in Yakutsk last September. The companies expect to commission the pipeline's first stage from Yakutia to Vladivostok in 2017 with the full line operating 1 year later.

The two companies later signed an agreement for 30 bcmy to be supplied via a western route provided by the Altai pipeline (OGJ Online, Nov. 11, 2014). The 2,600-km, 56-in. OD line will enter China just west of Mongolia, with completion expected in 2018.

Rosneft and Transneft agreed in September 2012 jointly to build a branch off the Eastern Siberia Pacific Ocean (ESPO) oil pipeline linking it to Rosneft's Komsomolsk-on-Amur refinery. Construction of the 8-million-tonnes/year (tpy) branch began last year. Crude currently arrives at the refinery by rail. Transneft is financing the project with long-term fees paid by Rosneft as part of a separate shipment agreement.

Turkmengaz plans to build a 770-km, 56-in. OD natural gas pipeline from eastern Turkmenistan to the Caspian Sea, moving 30 bcmy by 2016 for continued shipment to Europe.

GSPL India Gasnet Ltd. is building a 2,460-km natural gas pipeline between Mehsana and Jammu. The project received its environmental permits from the Indian government in May 2013. GSPL expects the 42-in. OD pipeline to enter service in 2016 with a capacity of 30 million cu m/day (MMcmd).

Sister-company GSPL India Transco Ltd. is building a 1,585-km pipeline between Mallavaram and Bhilwara. The pipeline will use pipes between 18 and 36-in. OD, also moving 30 MMcmd by 2016 and having received its environmental approvals in 2013. Both pipelines will carry production and imports from India's east coast to consumers in central and northern parts of the country.

GSPL also plans a 1,825-km gas pipeline from Surat to Indian Oil Corp.'s (IOC) 15 million tpy refinery in Paradip. The 36-in. OD west-to-east line passing through Maharashtra and Chhattisgarh includes five spur lines totaling 124 km.

IOC, meanwhile, is building a 680-km NGL pipeline, connecting Paradip and Durgapur with 18, 14, and 12-in. OD pipe. The system will move liquids from the Paradip refinery to LPG bottling plants. Both cathodic protection and mainline pipelay contracts for the project were tendered in 2013, with IOC planning to finish construction this year and begin NGL deliveries on the system during 2016.

Europe

Russia late last year decided against building the 930-km South Stream natural gas pipeline across the Black Sea from Russia to Bulgaria, citing delays on the part of the European Union in taking the steps necessary to move forward. Gazprom Chief Executive Alexei Miller and Mehmet Konuk, chairman of Botas Petroleum Pipeline Corp., signed a memorandum of understanding Dec. 1 on building instead an offshore gas pipeline from the Russkaya compressor station (also South Stream's starting point) under construction in the Krasnodar Territory across the Black Sea to Turkey (OGJ Online, Dec. 2, 2014).

Turkey in July had approved South Stream's environmental impact assessment, including pipe lay for the 63-bcmy project's four parallel strings in its exclusive economic zone starting first-quarter 2015 (OGJ Online, July 25, 2014).

The new pipeline would have the same 63 bcmy overall capacity, with 14 bcmy to be used in Turkey and the balance shipped to a border crossing with Greece, the location of which has yet to be decided. The 448-Mw Russkaya station will provide as much as 28.45 MPa of pressure, enough to have shipped gas on South Stream to Bulgaria without intermediate compression.

Partners in the Shah Deniz consortium made an FID in December 2013 on Stage 2 development of the Caspian Sea natural gas field offshore Azerbaijan, triggering plans to expand the South Caucasus Pipeline (SCP) through Azerbaijan and Georgia, build the Trans Anatolian Gas Pipeline (TANAP) across Turkey, and begin work on the previously selected Trans Adriatic Pipeline (TAP) for shipment into Europe.

SCP expansion will twin the existing Baku-Tbilisi-Ceyhan (BTC) pipelines through Azerbaijan and Georgia, as well as adding two compressor stations to boost capacity by 16 bcmy. Project plans call for 441 km of new 56-in. OD pipe, 385 km through Azerbaijan and another 56 into Georgia, at which point the expansion will connect to the existing SCP.

The first additional compressor station will be 3 km inside Georgia, co-located with an existing BTC station near Rustavi. The second new station will be at a greenfield site on the existing line 139 km downstream, west of Tsalka Lake, Georgia. SCP's current capacity is 7 bcmy. BP expects work to be completed by yearend 2018.

TANAP would run 1,800 km at an estimated cost of at least $7 billion. The 48 and 56-in. OD pipeline will move as much as 30 bcmy by 2018, coinciding with first gas from Shah Deniz II.

The Shah Deniz II consortium in June 2013 selected the Trans Adriatic Pipeline (TAP) as the project's European transport option. TAP will transport as much as 20-bcmy of natural gas from Shah Deniz II through Greece and Albania to Italy, from where it can be shipped further into Western Europe.

The project will use 36 and 48-in. OD pipe, with service expected to begin in 2018. The 36-in. pipe will make up the line's 115-km offshore section, with the 48-in. pipe used onshore. Total planned length is 800 km. The Italian government approved the project in December 2013.

TAP shareholders include BP 20%, SOCAR 20%, Statoil 20%, Fluxys 16%, Total SA 10%, E.On AG 9%, and Axpo 5%. 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 of Shah Deniz Stage 1. Field development, some 70 km off 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 in waters up to 550 m deep; the 16-bcmy upgrade to SCP; and expansion of the Sangachal terminal.

Statoil and its partners in the Polarled Development Project in 2013 filed plans for installation and operation of a 480-km, 36-in. gas pipeline from Aasta Hansteen field in the northern Norwegian Sea to a gas plant operated by Shell at Nyhamna. Aasta Hansteen is on schedule for a third-quarter 2017 production start-up. Fiber-optic cable and rocks for the pipeline were installed last year (OGJ Online, Aug. 26, 2014).

The pipeline will be capable of delivering 70 MMscfd to Nyhamna. It will have a 30-km, 18-in. branch to the Kristin platform connecting Polarled with the Aasgard Transport System. Other possible field tie-ins include Linnorm, via the Draugen platform, and Zidane via Heidrun. Two further branches, of 60 km and 173 km, are possible south of Aasta Hansteen, Statoil said.

Statoil's partners in Polarled are Petoro AS, OMV Group, Royal Dutch Shell PLC, Total, RWE Dea AG, ConocoPhillips Co., Edison SPA, Maersk Oil, GDF Suez SA, and Gassco.

Middle East

Despite a ceremonial groundbreaking in March 2013 between Pakistan's President Asif Ali Zardari and Iran's President Mahmoud Ahmadinejad, the long-contemplated gas export line from Iran to Pakistan remains incomplete. Iran cancelled a $500-million loan to Pakistan for construction of the pipeline in December 2013, citing the effects of ongoing economic sanctions, but 1 year later waived penalties it had imposed on Pakistan for delays in completing its section of line.

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 currently suffers from gas shortages. The Iranian section of the line is built. The section in Pakistan would include 700 km of line from a planned LNG terminal in Gwadar to Nawabshah, with the balance spanning the gap from the Iranian border to Gwadar.

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

The National Iranian Gas Co. (NIGC) plans to build the 1,850-km IGAT IX natural gas trunkline to supply the country's western provinces. The company says the 56-in. OD IGAT IX line could also export gas to Europe through Bazargan at Iran's border with Turkey.

The pipeline would start east of Assalouyeh, passing through Khuzestan, Ilam, Kurdistan and West Azerbaijan provinces before reaching the border. Construction would occur in four sections: Assalouyeh-Ahwaz, 605 km; Ahwaz-Kermanshah, 461 km; Kermanshah-Miyandoab, 348 km; and Miyandoab-Bazargan, 436 km. NIGC expects to ship 110 million cu m/day through the line starting in 2017.

Iraq began technical work last year on twin 1,043-mile pipelines-one crude oil, one associated fuel gas-running from Basra to the Red Sea at Aqaba, Jordan. The oil pipeline would use 56-in. OD pipe and the gas line 36-in. OD, with respective capacities of 1 million b/d and 258 MMcfd. The pipeline would cross 422 miles inside Iraq with the balance in Jordan. A second, 1.25-million b/d leg of the oil line is also planned to Syria's Banias, Mediterranean port, pending improvement of the country's security.

Iraq and Jordan signed an agreement on the project in April 2013. Jordan will retain 150,000 b/d for domestic refining. Jordan will also use roughly 100 MMcfd of the natural gas with the rest used as fuel for the oil pipeline. Iraq is pursuing the project to decrease its dependence on the Persian Gulf as an oil export route. The countries are targeting a 2017 in-service date. SNC-Lavalin Group Inc. won a FEED contract for the pipeline.

Abu Dhabi is building 500-km of 8-4 in. OD CO2 pipeline as part of the Masdar Initiative's carbon capture, use, and sequestration (CCUS) projects. 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.

Abu Dhabi National Oil Co. (ADNOC) formed a joint venture with Masdar in late 2013 to explore and develop commercial-scale CCUS. The JV awarded Dodsal Group an engineering, procurement, and construction contract (EPC) to build a CO2 compression plant and 50-km pipeline to ADNOC crude oil fields, to be completed in 2016.

Oman Gas Co. (OGC) plans to build a 230-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 the 25-MMcmd pipeline to enter service 2017, with an EPC contract to have been awarded by end-2014.

Africa

Uganda, Kenya, and South Sudan plan to build an 806-mile, 24-in. OD crude oil pipeline from production in Uganda and western Kenya to the Kenyan port of Lamu. The World Bank last year pledged $600 million to help build the pipeline. The countries awarded a design contract to Toyota Tsusho in November. Rwanda might also participate. Participants expect completion in 2019.

Kenya Pipeline Co. Ltd. (KPC) in July awarded the construction contract for a 20-in. OD multi-product pipeline from Mombasa to Nairobi to Zakhem International Construction Ltd. Zakhem will build the 450-km pipeline in KPC's existing right-of-way. Construction will include four new pump stations at Pump Station (PS) 1, Changamwe; PS 3, Maungu; PS 5, Mtito Andei; and PS 7, Sultan Hamud. Each station will have two pumps, one in operation and one on standby. Zakhem will also add two booster pumps at PS 14, Kipevu. The companies expect work to take 18 months, targeting a 2016 in-service date.

National Oil Co. Kenya and Indian Oil Corp. are building a 14-in. OD, 352-km products pipeline from an interconnect with an existing line in Eldoret, Kenya, to Kampala, Uganda, and eventually to Rwanda. The countries expect the project to be complete by 2017.