Planned pipeline construction to be completed in 2018 nearly doubled from the previous year, with expected crude and natural gas project completions more than making up for smaller projected products pipeline numbers. Future planned mileage slipped slightly overall as completion of some of the gas and crude projects moved into the current year.
Operators plan to complete installation of 14,657 miles in 2018 alone (Table 1), with natural gas plans (11,936 miles) making up more than 81% of the total, based on data collected by Oil & Gas Journal. By contrast, crude and products pipelines made up nearly 60.5% of total planned construction as recently as 2013.
As 2017 began, operators had announced plans to build more than 33,600 miles of crude oil, product, and natural gas pipelines extending into the next decade, a roughly 2.6% decrease from data reported the prior year (OGJ, Feb. 6, 2017, p. 62). The softer plans for beyond 2018 moderated the slide that occurred over the past 2 years, as the energy market seems to have found its bottom for the time being. Sharp reductions in long-term gas pipeline plans in the Middle East erased gains in other regions.
As a whole, combining both current-year and forward estimates (Fig. 1), increases in planned construction in the US, Europe, Asia-Pacific, and Africa outweighed decreases elsewhere.
EIA forecast world liquid fuels consumption to increase by 18.9% through 2040 (using a 2015 baseline), a period that encompasses the long-term pipeline construction projections described here. This rate of growth was down sharply from EIA's year-earlier forecast, which called for a 34.4% increase from a 2012 baseline.
Demand growth will be strongest, according to its September 2017 International Energy Outlook (IEO), among non-OECD countries, growing at a base-case 1.3%/year rate compared with a 3% decrease in the OECD over the same period. This growth will be led by Asia, with its non-OECD countries making up 80% of the total worldwide demand growth, as both China and India experience rapid industrial expansion and increased transportation demand.
Transportation consumption of liquid fuels in China will grow 36% by 2040, according to EIA. India's transportation-driven demand will more than double, with 142% growth expected.
EIA raised its total Asian liquid fuels demand slightly to 46.6 million b/d from the 46.4-millon b/d previously forecast, all growth coming from the non-OECD countries. Through 2050, OECD Asia demand growth is expected to remain flat as the already larger non-OECD demand in the region expands by 1.7%/year. EIA expects liquid fuels demand in Japan to fall 0.9%/year between 2015 and 2050.
Non-OECD Asia GDP growth slipped to 3.9%/year (from 4.2%) through 2050. India's growth, though still the world's fasteset, slows to 5.0%/year through 2040 from 5.5% in the previous IEO, and to 4.3% through 2050. China's GDP is expected to grow by 4.3%/year through 2040, considerably slower than the 9.6% growth rate over the past 10 years. EIA expects a 3.0% global growth rate through 2040, down from 3.3% last year. The agency expects 2.8%/year global GDP growth through 2050.
The EIA Annual Energy Outlook (AEO) 2017 forecast relatively flat US petroleum consumption through 2040, remaining below its 2005 peak as improved energy efficiency offsets growth in transportation and industrial activity. Consumption of petroleum and other liquids reaches a peak of 20.19 million b/d in 2019 (from a 2015 base of 19.55), dropping to 18.96 million b/d in 2033 before rising to 19.34 in 2040 and a new peak of 20.57 million b/d in 2050.
EIA projects US crude production leveling off between 10 and 11 million b/d through 2040, despite higher prices, as recent productivity gains plateau. Production first reaches 10 million b/d in 2021 and peaks at 10.55 million b/d in 2029.
The agency projects US dry natural gas production to continue growing at nearly 4%/year through 2020, reaching 30.79 tcf that year, with growth tapering off to an average rate of 1%/year through 2040 as export growth moderates and efficiency gains occur. EIA predicts 2040 production of 37.74 tcf.
OGJ tracks applications for gas pipeline construction to the US Federal Energy Regulatory Commission (FERC). Applications filed in the 12 months ending June 30, 2017 (the most recent 1-year period surveyed), totaled fewer miles despite the general upturn in plans.
• 529 miles of gas pipeline were proposed for land construction. For the earlier 12-month period ending June 30, 2016, more than 2,470 miles were proposed for land construction.
• FERC applications for new or additional compression horsepower at the end of June 2017 also fell sharply, totaling almost 600,000 hp from more than 2.2 million hp in June 2016.
For 2018 only (Table 1), operators plan to complete roughly 14,560 miles of oil and gas pipelines worldwide at a cost of nearly $95 billion. For 2017 only, companies had planned roughly 7,750 miles at a cost of more than $59 billion.
For projects completed after 2018 (Table 2), companies plan to lay more than 33,650 miles of line and spend roughly $215 billion. When these companies looked beyond 2017 last year, they anticipated spending roughly $264 billion to lay more than 34,500 miles of line. Land construction costs fell in the meantime from $7.65 million/mile to $5.94 million/mile.
• Projections for 2018 pipeline mileage reflect only projects likely to be completed by yearend 2018, including construction in progress at the start of the year or set to begin during it.
• Projections for mileage after 2018 include construction that might begin in 2018 but be completed later. Also included are some long-term projects judged as probable, even if they will not break ground until after 2018.
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 (14,189 miles) for 2018 only will cost roughly $84 billion:
-$690 million for 4-10 in.
-$8.0 billion for 12-20 in.
-$16.7 billion for 22-30 in.
-$58.8 billion for 32 in. and larger.
• Total offshore construction (477 miles) for 2018 only will cost more than $10.5 billion:
-$286 million for 4-10 in.
-$3.3 billion for 12-20 in.
-$6.9 billion for 22-30 in.
• Total onshore construction (32,710 miles) for beyond 2017 will cost more than $194 billion:
-$15.6 billion for 12-20 in.
-$34.9 billion for 22-30 in.
-$144 billion for 32 in. and larger.
• Total offshore construction (943 miles) for beyond 2018 will cost nearly $21 billion:
-$6.4 billion for 12-20 in.
-$14.5 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.
US, Canada activity
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 pipeline would transport 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 send it on tankers to US and international markets.
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.
The US Department of Energy (DOE) in November 2014 granted the project, now called Alaska LNG and including the Alaska Gasline Development Corp. (AGDC), authority for exports to countries covered by free-trade agreements (FTA), approving exports to non-FTA destinations like Japan, China, India, and Taiwan in May 2015.
Alaska bought TransCanada's share of the project in November 2015 and the producing companies told the state in 2016 that weak market conditions did not warrant proceeding with the US Federal Energy Regulatory Commission (FERC) application and costly design work in 2017. Alaska Gov. Bill Walker said the state would take over the project to keep it on schedule while seeking to reduce costs and searching for both investors and customers.
Chinese and Alaskan officials signed a five-party, $43-billion joint development agreement for the Alaska LNG project in November 2017. China Petrochemical Corp. (Sinopec), CIC Capital Corp., and Bank of China agreed to work with AGDC and the state government on LNG marketing, financing, investment modeling, and establishing China content in Alaska LNG.
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, faltered as a number of LNG projects were cancelled.
In early 2013, Chevron Canada Ltd. bought 50% of Kitimat LNG and the proposed Pacific Trail Pipeline. Pacific Trail is a 290-mile, 36-in. OD pipeline which would move gas to the Kitimat LNG terminal. The British Columbia government in July 2013 extended Chevron and partner Apache's window to start construction on the line to 2018. Woodside bought Apache's interest in Kitimat LNG in late 2014 (OGJ Online, Dec. 15, 2014). A final investment decision on the plant was still pending as of December 2017, the pipeline's fate likely hanging in the balance.
Spectra Energy Corp., meanwhile, lost the basis for its 42-in. OD, 525-mile Westcoast Connector gas pipeline from northeast British Columbia to Royal Dutch Shell PLC's planned LNG plant in Prince Rupert, BC, when the major cancelled the project. Shell's cancellation was followed by Petronas halting development of Pacific Northwest LNG and Nexen stopping plans for its Aurora LNG plant, both of which were also planned for the Prince Rupert area.
TransCanada's proposed Prince Rupert Gas Transmission (PRGT) project to provide gas to Pacific Northwest LNG, however, was proceeding as of January 2018 despite the liquefaction project's cancellation, the pipeline company evaluating other options for the system. The 470-mile, 48-in. OD PRGT is designed to deliver 2.1 bcfd from TransCanada's Nova Gas Transmission Ltd. Operations could begin as early as 2019.
Projects to move natural gas liquids to market, meanwhile, faced headwinds in the US. Kinder Morgan Energy Partners LP (KMEP) and MarkWest Utica EMG LLC's proposed Utica Marcellus Texas Pipeline (UMTP) Y-grade transportation project from the Utica and Marcellus shales to Mont Belvieu, would have an initial design capacity of 150,000 b/d and be expandable to 430,000 b/d. The first 964 miles of the line would consist of converted Tennessee Gas Pipeline system, with 200 miles of new-build between Natchitoches, La., and Mont Belvieu, and 120 miles of laterals to provide basin connectivity. The companies are targeting a fourth-quarter 2018 in-service date but municipal opposition along its route might cause this to be delayed.
FERC ruled in September 2017 that KMEP could proceed with abandonment of its gas line, a necessary regulatory step in the conversion process. New legal challenges, however, were filed in response, with FERC allowing the project to proceed in the meantime.
Project Mariner, announced in 2010 by Sunoco Logistics Partners LP and MarkWest Energy Partners LP to move Marcellus shale NGLs to market, began operations on Mariner West (shipping 65,000 b/d of ethane to Sarnia, Ont.) in 2013. The 70,000 b/d Mariner East segment began propane operations in fourth-quarter 2014 and ethane operations in first-quarter 2016, moving the liquids to the US Atlantic Coast for shipment to Gulf Coast chemical producers and European markets. The combined projects included just 85 miles of new pipeline, using existing Sunoco infrastructure for the balance of each route.
The company in late 2014 announced it had received sufficient shipper interest to move ahead with its 275,000 b/d, 306-mile Mariner East 2 pipeline, largely paralleling the route of the first line. Mariner East 2 will use parallel 20-in. and 16-in. OD pipelines in the same right of way, the latter dubbed Mariner East 2X. Mariner East 2 will carry propane, ethane, and butane; 2X all three of these as well as C3+, natural gasoline, and condensate, or any combination of these products.
Sunoco expects to put the 20-in. line in service second-quarter 2018 and complete work on the 16-in. line by yearend 2018. but this might be delayed by community and legal challenges. Pennsylvania's Department of Environmental Protection (DEP) in January 2018 ordered Sunoco to stop construction until it meets requirements of a DEP order addressing impacts to private wells, construction authorization, and controls to minimize inadvertent releases.
Natural gas pipeline projects in the northeast US also continued to face delays caused by community opposition. EQT Midstream Partners' Mountain Valley Pipeline (303 miles, 42-in. OD, northwestern West Virginia to southern Virginia) is scheduled for a fourth-quarter 2018 startup but as of January 2018 still faced landowner suits regarding property access. National Fuel Gas Supply Corp.'s Northern Access Project (96.49 miles, 24-in. OD, McKean County, Pa., to Erie County, NY), announced more than 2 years ago, remains in limbo following an April 2017 denial by New York's Department of Environmental Conservation of its water quality permits. National Fuel has asked FERC to determine whether it can proceed without the permits.
Enbridge in June 2017 withdrew its FERC application to complete Access Northeast (97 miles, expansion of existing system in New York, Connecticut, and Massachusetts) following opposition. Dominion's Atlantic Coast (600 miles, 42-in. OD, West Virginia to North Carolina) pipeline's erosion and sediment control plan was denied by North Carolina's Division of Energy, Mineral, and Land Resources in January 2018.
The Permian basin has been the area of most rapid growth in US hydrocarbon production over the past year, reflected by an accompanying scramble to build new pipelines between Permian developments and both consuming centers and export destinations.
Kinder Morgan Texas Pipeline LLC (KMTP), DCP Midstream LP, and an affiliate of Targa Resources Corp. will build the Gulf Coast Express Pipeline Project (GCX). About 85% of the project's 1.92-bcfd capacity is subscribed and committed under long-term, binding transportation agreements. GCX's mainline portion consists of roughly 82 miles of 36-in. OD pipeline and 365 miles of 42-in. pipeline starting at the Waha Hub near Coyanosa, Tex., in the Permian basin and ending near Agua Dulce, Tex. GCX's Midland Lateral includes about 50 miles of 36-in. pipeline and associated compression, connecting with the GCX mainline. KMTP expects GCX to be in service in October 2019, pending the receipt of necessary regulatory approvals. Construction is expected to begin this quarter.
Sempra LNG & Midstream and Boardwalk Pipeline Partners LP are planning the Permian-Katy Pipeline project (P2K). The roughly 470-mile, 42-in. OD natural gas pipeline is proposed to transport up to 2 bcfd from the Waha Hub in the Permian basin to Katy, Tex., and on to the Houston Ship Channel. A phased-in startup could begin as early as December 2019.
Epic Y Grade Pipeline LP, a subsidiary of Epic Y Grade Services LP and Epic Midstream Holdings LP, has agreed with BP Energy Co., a subsidiary of BP PLC, for the latter to anchor a 650-mile NGL pipeline liking the Permian and Eagle Ford regions to Gulf Coast refiners, petrochemical companies, and export markets (Fig. 2).
Construction already has begun on the Epic NGL Pipeline, which will have throughput capacity of at least 220,000 b/d with multiple origin points in the Delaware and Midland basins. Destinations will include interconnects near Orla, Benedum, and Corpus Christi, Tex., where Epic's affiliate plans to build a complex with multiple 100,000-b/d fractionators. Epic plans to reach full capacity in 2019.
Enterprise Products Partners likewise plans to have its 250,000 b/d Shin Oak NGL pipeline in service by 2019, running 571 miles of 24-in. OD pipe from the Permian to the US Gulf Coast.
Tellurian Inc. plans to develop a natural gas pipeline network consisting of the previously announced Driftwood Pipeline (DWPL) and two other lines. DWPL, a 96-mile, 48-in. OD pipeline, is expected to be in-service mid-2021, delivering 4 bcfd from Gillis, La., to Driftwood LNG. DWPL is in permitting with FERC.
Tellurian's Permian Global Access Pipeline would be a 625-mile, 42-in. OD pipeline transporting 2 bcfd from the Waha Hub in Pecos County, Tex., and Permian and associated shale plays around Midland, Tex. to interconnects near Gillis, La. Proposed delivery systems include the Creole Trail Pipeline, Cameron Interstate Pipeline, Trunkline Gas Co., Texas Eastern, Transco, Tennessee Gas Pipeline, Florida Gas Transmission, and DWPL, among others.
The company's Haynesville Global Access Pipeline would cross 200 miles with 42-in. OD pipeline, transporting an additional 2 bcfd to the same interstate pipelines near Gillis. Both of these lines are expected to enter in service during 2022.
NAmerico Partners LP's proposed Pecos Trail pipeline would ship more than 1.85 bcfd through 468 miles of 42-in. OD pipe from the Permian basin to Corpus Christi by 2020.
Enbridge Inc.'s $7.5-billion Line 3 Replacement (L3R) Program, which the company describes as its largest project ever, faces continued delays. L3R will replace the majority of Enbridge's existing 34-in. OD Line 3 crude pipeline with new 36-in. OD pipeline on both sides of the Canada-US border, a total of 1,031 miles, doubling its capacity to 760,000 b/d. Enbridge will decommission the existing Line 3 once the new line is complete.
On the Canadian side of the border 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.
Canada's federal government approved L3R construction in late 2016 (OGJ Online, Nov. 30, 2016). Enbridge originally expected the new line to enter service second-half 2017, but the company in December 2017 described its start date as uncertain and perhaps as late as November 2019, given mounting resistance inside the US.
Canada also approved TransCanada's Trans Mountain Expansion project (TMEP) to move crude west from Alberta. The project would use 36-in. OD pipe to twin 980 km of its existing Trans Mountain pipeline. Even while granting the approval, however, Prime Minister Justin Trudeau said "we are under no illusion that the decision will [not] be bitterly disputed," recognizing the likelihood of continued protests and litigation (OGJ Online, Nov. 30, 2016).
TMEP will add 300,000 b/d of the Trans Mountain pipeline system, bringing total capacity to 890,000 b/d. The Westridge marine terminal at Trans Mountain's end in Burnaby, BC, will be expanded with three new berths. Storage additions will include 14 new tanks at an existing terminal in Burnaby and five new tanks at an existing terminal in Edmonton.
TransCanada planned to begin construction in September 2017 and place the expansion into service in late 2019. In January 2018, however, the company said the project could be as much as a year behind schedule due to permitting delays, moving its projected in-service date to as late as December 2020.
The company in October 2017 cancelled its Energy East pipeline project. Energy East plans called for 4,500 km of pipeline capable of shipping 1.1-million b/d of crude from Hardisty, Alta., and Moosomin, Sask., to refineries in eastern Canada and marine terminals in Cacouna, Que., and Saint John, NB. About 3,000 km of the pipeline would have consisted of TransCanada PipeLines Ltd.'s converted Canadian Mainline natural gas pipeline, with the other 1,500 km new-build miles.
TransCanada concluded on open season for its long-sought (originally planned to enter operations in 2012) 830,000-b/d Keystone XL pipeline in January 2018, securing about 500,000 b/d of firm, 20-year commitments and describing the results as sufficient for the project to proceed. It plans to begin primary construction in 2019, pending a final investment decision.
US President Donald Trump issued a presidential permit for the project in March 2017. The Nebraska Public Service Commission in November 2017 approved Keystone XL's route. But land owners have filed suit against the state, protesting the new route, and outstanding permits remain.
The delays and cancellations of pipelines designed to move Canadian oil to market affected both Canadian crude prices and inventories at Cushing, Okla., according to the EIA. The Jan. 18, 2018, edition of its 'This Week in Petroleum,' the agency reported prices of Western Canada Select as trading at their deepest discounts to West Texas Intermediate in nearly 3.5 years and noted that crude stocks in Cushing had declined by 22 million bbl (34%) since the beginning of November 2017 and were 17% below their 5-year average as Jan. 12, 2018.
Permian basin growth inspired a flurry of crude pipeline development in addition to the NGL projects. Buckeye Partners LP subsidiary South Texas Gateway Pipeline LLC launched a binding open season for a 600,000 b/d pipeline from the Permian basin and Gardendale, Tex., to Corpus Christi, Ingleside, and Houston, Tex.
Phillips 66 and Enbridge Inc. are holding an open season for the Gray Oak Pipeline, a 385,000-b/d system that will carry Permian basin production for export and to Texas refineries in Corpus Christi, Freeport, and Houston. Shippers will have the option to select from origination stations in Reeves, Loving, Winkler, and Crane counties in West Texas. The companies expect Gray Oak Pipeline to have an initial capacity of 385,000 b/d and will evaluate expansion of the system based on shipper interest during the open season. The pipeline system is expected to enter service second-half 2019.
Epic is planning a Permian-to-Corpus Christi crude oil pipeline, largely paralleling the path of its Y-grade project (Fig. 2). The 700-mile line would carry as much as 550,000 b/d.
Magellan Midstream in December 2017 proposed a 645-mile, 24-in. OD pipeline from Crane, Tex., to Three Rivers to Corpus Christi, moving both Permian and Eagle Ford crude to the coast. The 350,000 b/d line would include a 200-mile branch from Three Rivers to Houston and is planned to enter service in 2019.
Plains All American's Cactus II pipeline would run 515 miles of 24-in. OD pipe from Wink, Tex., to McCamey and then from McCamey to Ingleside-Corpus Christi, expanding the current Cactus system's capacity to 575,000 b/d from 390,000 b/d.
Substantial growth of US gas exports to Mexico has prompted rapid construction of new transmission capacity both between the countries and inside Mexico. Infraestructura Marina del Golfo (IMG)-TransCanada Corp.'s joint venture with Sempra Energy subsidiary IEnova-will build, own, and operate the 42-in. OD, 497-mile Sur de Texas-Tuxpan natural gas pipeline in Mexico. A 25-year gas transportation service contract for 2.6 bcfd with Comision Federal de Electricidad (CFE), Mexico's state-owned power company, supports the project, expected to enter service in late 2018. The pipeline will begin offshore in the Gulf of Mexico at the border point near Brownsville, Tex., and extend along the coast to Tuxpan, Veracruz, Mexico. It will connect with Cenegas's pipeline system in Altamira and with TransCanada's Tamazunchale and Tuxpan-Tula pipelines, among other transport systems in the region.
Sur de Texas will be supplied by gas from the 2.6-bcfd Valley Crossing Pipeline, to be built by Spectra Energy under a CFE contract. Valley Crossing will extend 168 miles from Agua Dulce hub in Nueces County, Tex., to Brownsville.
TransCanada will own 60% of the $2.1-billion Sur de Texas-Tuxpan project and operate it. IEnova will own the other 40%. Spectra is sole owner of the $1.5-billion Valley Crossing line.
TransCanada previously won bids to build and operate the Tuxpan-Tula (OGJ Online, Nov. 11, 2015) and the Tula-Villa de Reyes (OGJ Online, Apr. 11, 2016) lines. The 36-in. OD, 155-mile Tuxpan-Tula pipeline, carrying 886 MMcfd, is already operating. Tula-Villa de Reyes will start in 2018, moving 550 MMcfd across 174 miles through 36-in. OD pipe. The 220-mile, 42-in. Villa de Reyes-Aguascalientes-Guadalajara line is also scheduled to enter service in 2018.
Refined products shipments from the US to Mexico have also grown. Howard Midstream's Dos Aguilas pipeline will carry clean products 287 miles from Corpus Christi, Tex., to Monterrey, Mexico. Its four 12-in. OD sections comprise the Border Express pipeline from Corpus to Laredo, Tex., the Borrego from Laredo to the international border crossing (a total of 151 miles), Poliducto Frontera from the border to Nuevo Laredo, Mexico, and Poliducto del Norte from Nuevo Laredo to Monterrey (136 miles). Service is expected in 2018.
Pampa Energia subsidiary TGS plans to build a more than 700 mile transmission pipeline system in Argentina to move natural gas produced in the Vaca Meurta shale by companies including YPF SA, Tecpetrol, Dow Argentina, ExxonMobil Corp., Chevron, and Statoil. The 4-million cu m/year pipeline is expected to enter service in 2019.
OAO Gazprom and China National Petroleum Corp. (CNPC) in 2014 signed a 30-year natural gas supply contract reportedly worth $400 billion. The contract stipulates that 38 billion cu m/year (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 (Fig. 3). Work on the 56-in. OD line began in September 2014, with construction of the Chinese section beginning June 2015.
The companies in December 2015 agreed on design and construction of the pipeline's cross-border section under the Amur River. They expect to commission the pipeline's first stage in 2018 with the full line operational the following year. The project stalled mid-2017 due to disputes regarding the gas contract, though Gazprom says it remains on schedule.
Turkmengaz is leading the consortium of national governments planning to build, own, and operate the 1,800-km Turkmenistan-Afghanistan-Pakistan-India (TAPI) natural gas pipeline, designed to carry 33 bcmy by 2022.
The Asian Development Bank (ADB) in 2005 estimated TAPI's cost at $7.6 billion, making the pipeline profitable only at throughputs of 30-33 billion cu m (bcm)/year. The estimated cost was nearly triple ADB's 2002 estimate of $2.6 billion. Persistent delays have since raised TAPI's projected cost to $10 billion.
TAPI would run 200 km through Turkmenistan (starting from Galkynysh gas field in Turkmenistan's eastern Mary province), 773 km through Herat and Kandahar provinces, Afghanistan, and 827 km through Multan and Quetta, Pakistan, to end at Fazilka in northern Punjab province, India
The pipeline would carry 90 million standard cu m/day (MMscmd) of natural gas from the 16-tcf Galkynysh field (formerly South Yolotan-Osman) under 30-year commitments, with India, Pakistan, and Afghanistan (originally set to have received 38, 38, and 14 MMscmd, respectively). Afghanistan, however, has reduced its requirement to just 1.5-4 MMscmd, opening the possibility of India and Pakistan's share growing to as much as 44.25 MMscmd each.
India said its interest remained strong as of August 2017, with Afghanistan saying construction could begin as early as 2018.
GSPL India Gasnet Ltd. is building a 2,052-km natural gas pipeline between Mehsana and Bhatinda. The project received its environmental permits from the Indian government in May 2013. GSPL expects the 42-in. OD pipeline to enter service in 2018 with a capacity of 30-million cu m/day (mcmd). The pipeline will carry production and imports from India's east coast to consumers in central and northern parts of the country.
GAIL (India) Ltd. plans by 2018 to build a 1,825-km gas pipeline from Surat to Indian Oil Corp.'s (IOC) 15 million tonne/year refinery in Paradip. The 36-in. OD west-to-east line passing through Maharashtra and Chhattisgarh includes five spur lines totaling 124 km. Pipelay was underway as of November 2017.
Construction began in July 2015 on the first phase of GAIL's Jagdishpur-Haldia natural gas pipeline. The 2,050-km pipeline-922 km of 36-in. OD trunkline and 1,128 km of 12-30 in spur and feeder lines-will connect eastern India to the national grid. The initial phase will ship 7.4 million cu m/day (cmd), with total capacity reaching 16 million cmd.
The pipeline will cross Bihar, Jharkhand, West Bengal, and Uttar Pradesh states. It will pass through 13 districts in Bihar, supplying refineries both there and in Barauni. It will also supply local gas networks in Barauni, Gaya, and Patna. It is expected to enter service in 2018.
IOC plans to build a nearly 2,000-km LPG pipeline to ship cooking gas from Kandla port and a refinery at Koyali east to consumers in Gorakhpur by 2020. The line would use 10.75 and 12.75-in. OD pipe to move 3.75 million tonnes/year.
The long-discussed Iran-Pakistan natural gas pipeline has been given a new lease on life by the need to link a planned LNG terminal at Gwadar, Pakistan, with consuming markets. A 700-km, 42-in. OD pipeline would run from Gwadar LNG east to Nawabshah and access to the Sui Southern Gas Co. (SSGC) network. An 81-km leg from Gwadar to the Iranian border could complete the pipeline once the larger line has entered service. Pakistan has been slow to build its section of the line due to lack of funding. The Iranian section of the line is built.
Russia, meanwhile, has agreed to build a pipeline in Pakistan connecting an LNG terminal in Karachi with Lahore. The 42-in. OD, 683-mile pipeline would carry 1.2 bcfd north from the coast starting in 2018. The Pakistani government in July 2017 asked SSGC to build the section between Nawabshah and Karachi.
Gazprom and Germany's BASF SE in August 2015 signed a memorandum of intent stipulating cooperation on building the Nord Stream II gas pipeline. The companies would build strings No. 3 and No. 4, connecting the Russian and German coasts under the Baltic Sea and doubling the line's 55-bcmy capacity by 2019. E.On, Shell, and OMV AG each previously had agreed to participate in building the two strings. Intertek was awarded a project inspection and expediting contract in December 2016. In April 2017, Allseas was contracted for pipelay.
Russia in late 2014 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 on instead building 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).
The new pipeline, TurkStream, would have the same 63 bcm/year overall capacity as South Stream, with 14 bcm/year to be used in Turkey and the balance shipped to a border crossing with Greece. 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.
Gazprom in 2016 received permits both for construction and to conduct survey work in Turkey's territorial waters on TurkStream's first two strings. The line's offshore section will consist of four 15.75-billion cu m/year strings. Gazprom hired Allseas Pioneering Spirit to conduct the 900-km offshore pipelay, which had reached Turkish waters as of November 2017.
Partners in the Shah Deniz consortium made a final investment decision (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, collocated 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 end-2018.
TANAP will 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 bcm/year by 2018, coinciding with first gas from Shah Deniz II.
TAP will transport as much as 20-billion cu m/year 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. Service, slowed by Italian protestors, is now expected to begin in 2020. 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.
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 offshore Baku in the Azerbaijan sector of the Caspian Sea, includes 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; the 16 bcmy upgrade to SCP; and expansion of the Sangachal Terminal.
The Poland-Lithuania Gas Interconnector (GIPL), designed to connect the Polish and Lithuanian gas transmission systems, will enter service in 2021. The 28-in. OD pipeline would include 310-357 km of pipe between Holowczyce, Poland, and the Lithuanian border, and another 177 km from the border to Jauniunai, Lithuania.
Iraq began technical work in 2014 on twin 1,043-mile pipelines-one crude oil, one associated fuelgas-running from Basra to the Red Sea at Aqaba, Jordan. The oil pipeline, using 56-in. OD pipe to move 1-million b/d, will cross 422 miles inside Iraq with the balance in Jordan. Jordan will keep 150,000 b/d for domestic refining. Iraq is pursuing the project to decrease its dependence on the Persian Gulf as an oil export route.
Iraq decided in August 2017 to cancel a parallel gas pipeline, citing high costs and associated delays. The pipeline was to have fueled the crude line's pumps, with alternative power sources now being sought.
Saipem in February 2016 signed a memorandum of understanding (MOU) with National Iranian Gas Co. (NIGC) for possible cooperation on NIGC's proposed Iran Gas Trunkline IX (IGAT 9) and Iran Gas Trunkline XI (IGAT 11) pipeline projects, which combined, would cover a distance of 1,800 km (OGJ, Feb. 2, 2015, p. 72). Saipem did not disclose details regarding timelines or estimated values for projects under the MOUs. The MOUs followed suspension of long-standing international sanctions on Iran that prohibited US and many European firms from participating in development of the country's energy sector.
NIGC plans to build the 300-km Iranshahr-Chabahar pipeline by 2018. The pipeline will use 240 km of 56-in. OD line and 60 km of 36-in. OD line, delivering natural gas to power the Chabahar free trade and industrial zone. Iran began construction in March 2017.
The National Iranian Gas Export Co. (NIGEC) in 2016 hired Iranian Offshore Engineering and Construction Co. (IOEC) and Pars Consultant Engineering Co. to perform survey and basic engineering work on a 380-km pipeline intended to carry Iranian gas to Oman. IOEC will complete the offshore study and Pars the onshore.
The onshore section of the pipeline would use 200 km of 56-in. OD pipe in Iran, with the offshore section running 180 km of 36-in. OD pipe from Kuhe Mubarak, Iran, to Sohar Port, Oman. The onshore pipe would deliver gas from the IGAT VII pipeline to Kuhe Mubarak. The two countries reached agreement on the project in February 2017. Delivery of 28 million cu m/day to Oman would begin in 2019.
Oman Gas Co. (OGC) plans to build a 221-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 signed Petrojet as contractor in late 2016 and expects the 25-mcmd pipeline to enter service in 2019.
Uganda and Tanzania plan to build the 897-mile, 24-in. OD heated East Africa Crude Oil Pipeline (EACOP), bypassing Kenya as it transits between fields in Uganda and the Tanzanian port of Tanga. The pipeline, engineered by Gulf Interstate Engineering Co., would transport roughly 300,000 b/d to the Indian Ocean for export.
Total SA suggested this route as an alternative to mitigate security concerns regarding a previously considered Kenyan passage. China National Offshore Oil Corp. Ltd. and Tullow Oil are developing the project with Total. The line is expected to enter service in 2021.
Ethiopia and Djibouti plan to build a 700-km, 40-in. OD natural gas pipeline to transport Ogaden basin gas to a floating LNG liquefaction plant offshore Djibouti. China's Poly-GCL is developing the project with a scheduled 2020 startup date. The 3-million tonnes/year (mtpy) plant, fed by the 2-billion cu m/year pipeline, would be sited at Damerjog port near the Djibouti-Somalia border and expandable to 10 mtpy.
Bulk Oil Storage and Transportation Co. Ltd. (BOST) in late 2015 awarded a front-end engineering and design contract to Penspen for development of Ghana's Natural Gas Interconnected Transmission System (NGITS). The planned 750-km Phase 1 buildout would run from Aboadze to Tema, and from Prestea to Buipe, via Kumasi. The project will use 24-in. OD pipe with completion expected in 2018. A construction contract was signed in April 2017.