Construction plans sag in face of stubborn recession, war prospects

Feb. 3, 2003
Sobriety, even fear, returned to pipeline operators' outlook for new construction in 2003 and beyond, after optimism a year ago drove plans and proposals unrealistically high. The change in direction has resulted from the continued, stubborn economic downturn, now sharpened by war fears.

Sobriety, even fear, returned to pipeline operators' outlook for new construction in 2003 and beyond, after optimism a year ago drove plans and proposals unrealistically high. The change in direction has resulted from the continued, stubborn economic downturn, now sharpened by war fears.

Many ambitious and long-term pipeline projects that comprised last year's rosy scenario for work (OGJ, Feb. 4, 2002, p. 64), especially in the Western Hemisphere, have been quietly shelved or at least delayed during the year.

The irony, especially for North America, is that predictions for strong and growing natural gas demand have rarely been more robust. Since second quarter last year, natural gas prices have stubbornly held well above $3/Mcf and in recent weeks hovered steadily near $5/Mcf.

But pipeline operators reflect the general industry reluctance to commit resources for large, long-term projects. This nervousness shows up in drastically lower numbers for Oil & Gas Journal's 2003 pipeline construction outlook, derived from a survey of world pipeline operators, industry sources, and published information.

Throughout 2002, operators announced plans to build more than 38,000 miles of crude oil, product, and natural gas pipeline beginning in 2003 and extending into the next decade (Fig. 1). For the short term, operators planned to install only 12,500 miles in 2003 alone.

Dashed hopes

At the beginning of 2002, hopes that the US recession was approaching an end and that such a recovery would pull along the rest of the world fizzled. And speculation that energy demand would follow recovery proved to be just that—speculation.

And, as 2002 began, the fear that operators might put the brakes on some pipeline projects whose numbers had fueled a very optimistic construction outlook at the time proved to be well-founded, witness the current drastically reduced outlook for 2003 and beyond.

Energy prices, however, have risen, especially since mid-2002, despite the continued worldwide recession. They have been pushed up less by market forces than by fears of war in the Middle East and, at yearend, by politically based supply disruptions in Venezuela. That country furnishes about 14% of all oil and products to the US.

But the long-term driving force in US energy pricing, according to the annual forecast from the US Energy Information Administration, is and will continue to be natural gas demand. And demand for that fuel, especially in the US, continues to be robust.

By 2025, EIA said last month, US gas demand will grow 54% and fuel "large, new and imported supply projects." Emphasis here is on "imported."

Growth in domestic natural gas supplies, EIA said, will depend on more gas from unconventional production (tight sands, coalbed methane, shale) and–most importantly for the present discussion–"construction of an Alaskan natural gas pipeline that delivers gas supplies" to the Lower 48 in 2021.

Such unconventional production will grow to 9.5 tcf by 2025, from 5.4 tcf in 2001, an increase of about 76%. Total Alaskan production will grow to 2.6 tcf by the same date, from 0.4 tcf in 2001, a projected increase of 550%.

If US demand is to be met, however, imports must grow significantly, said EIA, echoing every other analysis of the US market. And those imports will take the forms of more LNG and expanded pipeline deliveries.

Total net imports will grow to 7.8 tcf by 2025, from 3.6 in 2001. Of the projected import growth, LNG will account for 2.1 tcf, up from 0.2 tcf in 2001.

Pipelines, in other words, will carry the bulk of increased imports of natural gas into the US for domestic consumption. And most of those pipeline volumes must come from Canada, which has been rapidly expanding delivery capacity in recent years.

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EIA said that US petroleum demand will likewise depend more on imports: Net imports for both crude oil and refined products will comprise 68% of total petroleum demand by 2025, up from 55% in 2001. Moreover, constraints on additional US refining capacity will push product imports higher as a portion of overall imports: to 34% in 2025 from 15% in 2001.

Bases, costs

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Table 1 shows that, in 2003 only, companies plan to complete more than 12,500 miles of oil and gas pipeline worldwide at a cost of more than $15 billion. For 2002 only, companies had planned more than 17,000 miles at a cost of nearly $25 billion.

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Table 2 indicates that, for projects completed after 2003, companies plan to lay nearly 26,000 miles of line and spend more than $31billion. When these companies looked beyond 2002 last year, they anticipated spending $66 billion to lay more than 47,000 miles of line.

  • Projections for 2003 pipeline mileage reflect only projects likely to be completed by yearend 2003, including construction in progress at the start of the year or set to begin during it.

  • Projections for mileage in 2003 and beyond include construction that might begin in 2003 and be completed in 2004 or later.

    Also included are some long-term projects judged as probable, even if they will not break ground until after 2004.

    Cost estimates are based on US average costs-per-mile for onshore and offshore gas-pipeline construction as found in Table 4 of OGJ's most recent Pipeline Economics Report (OGJ, Sept. 16, 2002, p. 52).

    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 (11,690 miles) for 2003 only will cost more than $14 billion:
    —$228 million for 4-10 in.
    —$3.7 billion for 12-12 in.
    —$5.1 billion for 22-30 in.
    —$5.1 billion for 32 in. and larger.

  • Total offshore construction (829 miles) for 2003 only will cost slightly more than $1 billion:
    —$25.6 million for 4-10 in.
    —$419 million for 12-20 in.
    —$571 million for 22-30 in.

  • Total onshore construction (24,876 miles) for beyond 2003 will cost more than $30 billion:
    —$762 million for 4-10 in.
    —$4.5 billion for 12-20 in.
    —$6.0 billion for 22-30 in.
    —$18.8 billion for 32 in. and larger

  • Total offshore construction (more than 1,000 miles) for beyond 2003 will cost nearly $1.3 billion:
    —$85.5 million for 4-10 in.
    —$510.3 million for 12-20 in.
    —$677.4 million for 22-30 in.

    What's happened and happening

    The following reviews many but not all of the world's pipeline projects in some of the more active regions. The US review occupies a disproportionately large share of this discussion and reflects the country's dominance of the world's energy use.

    Get the gas

    Last year saw start-up of one of the most significant, politically if not technically, pipelines in recent US pipeline history: In May, the Gulfstream Natural Gas System began delivery of 1.1 bcfd of natural gas to Florida energy markets, spanning the eastern Gulf of Mexico from producing areas in Alabama and Mississippi.

    Construction began almost a year earlier for the 581-mile pipeline, the largest natural gas pipeline in the Gulf of Mexico, says the company. It originates near Pascagoula, Miss., and Mobile, Ala., and crosses the gulf with more than 430 miles of 36-in. pipe to Manatee County, Fla. There, 130 miles of pipe, ranging from 36 in. to 16 in., cross Manatee, Hardee, Polk, and Osceola counties.

    Gulfstream Natural Gas System LLC is a joint venture between Williams Cos. and Duke Energy Corp. subsidiary Duke Energy Gas Transmission.

    Elsewhere in the gulf, development this quarter of the Red Hawk gas field on Garden Banks Block 668 in 5,300 ft of water will lead to construction later this year of a 16 in., 86-mile line to connect with ANR Pipeline Co. on Vermilion Block 397.

    El Paso Energy Partners LP will install the 330-MMcfd line for Red Hawk field's equal-interest partners Ocean Energy Inc. and Kerr-McGee Oil & Gas Corp. and plans to begin flow in mid 2004.

    Also, commissioning is nearing completion and start-up is planned for this month on Pioneer Natural Resources Co.'s multiwell Falcon deepwater project, 100 miles east of Corpus Christi in 3,400 ft of water on East Breaks Blocks 579 and 623.

    The 32.6 mile, 10-in. production pipeline will move untreated natural gas and condensate from two wells in Falcon field to an El Paso Energy Partners LP host platform, Falcon Nest, in shallow water on Mustang Island Block 103.

    From estimated reserves of 175-240 billion cu ft (equivalent), field production is expected to reach 175 MMcfd (equivalent).

    Shell Oil Co. plans two pipelines, one for gas and one for crude oil, to be completed in time for late 2004 production start-up of the Magnolia development, a joint project of Conoco/Phillips (75%) and Ocean Energy (25%), in 4,700 ft of water in Garden Banks 783 and 784.

    The 16-in. natural gas pipeline will cost $47 million with a planned 275-MMcfd capacity, and a 14-in. oil pipeline will cost $40 million with planned capacity of 75,000 b/d.

    Both will extend 50 miles from the Magnolia tension-leg platform to the Shell-operated Enchilada platform. The gas line will then connect into the Shell-operated Garden Banks gas pipeline system, while the crude oil line will connect into the existing Auger pipeline system.

    Also for Garden Banks production, Shell Gas Transmission LLC and Enterprise Products Partners LP are building the 16 in., 41 mile, 275-MMcfd Triton gas line from the deepwater Gunnison development on Garden Banks Blocks 667, 668, and 669 in 3,150 ft of water to connect with Stingray Pipeline Co. LLC's natural gas pipeline to shore.

    The $40-million line will handle Gunnison's 200-MMcfd production as well as volumes from future developments in the area, Shell said. To be owned by Triton Gathering LLC and operated by Kerr-McGee Oil & Gas Corp., the Triton pipeline will flow as early as November this year.

    Gunnison crude oil production of 40,000 b/d, in early 2004, will move in a 90 mile, 18-in. gathering pipeline from Garden Banks Block 668 to a shallow-water platform on Galveston Block A244.

    Kerr-McGee Oil & Gas Corp., a wholly owned subsidiary of Oklahoma City-based Kerr-McGee Corp., operates and owns a 50% working interest in the Gunnison development. Nexen Petroleum Offshore USA Inc. holds 30%, and Energy Resource Technology Inc., a subsidiary of Cal Dive International Inc., owns the remaining 20%.

    The most ambitious offshore pipeline in North America is also offshore and is planned to bring natural gas from production offshore Nova Scotia, initially in the Sable Island area, to the New York City area.

    The Blue Atlantic pipeline will cover more than 1,000 miles and come ashore to a planned gas separation and processing plant at East Jordan, NS, for liquids and CO2 removal and recompression for the remainder of the journey to US markets.

    Although currently delayed by lower-than-expected production forecasts, Blue Atlantic Transmission System says the 36-in. line will run at 2,180 psi and be able to carry up to 1 bcfd of dried natural gas.

    Current estimated cost of the project runs to $2.5 million (US), including plant costs, with filings to the US Federal Energy Regulatory Commission and Canada's National Energy Board envisioned for second quarter 2004. The East Jordan plant will cost on the order of $400 million, says the company.

    Blue Atlantic Transmission System says it expects a transportation rate of $0.90-$1/Mcf for delivery into the New York and New Jersey markets. Allowing 2 years to permitting, the company expects to begin building in 2006 with start-up by fourth quarter 2007.

    Oil plans

    The most ambitious Gulf of Mexico oil-pipeline plans are part of BP PLC's Mardi Gras system to develop the company's four deepwater fields: Thunder Horse (formerly called Crazy Horse), Holstein, Mad Dog, and Atlantis. BP will operate the systems through wholly owned subsidiary Mardi Gras Transportation Inc. (OGJ Online, Feb. 19, 2002).

    The oil lines are the third major component of BP's proposed Mardi Gras Transportation system in the deepwater gulf. In 2001, the company revealed plans for the related Okeanos and Cleopatra gas gathering systems in covering the same four fields and the Nakika field development.

    This year will see completion and start-up of the first oil line, the 120-mile Caesar pipeline, connecting Holstein, Mad Dog, and Atlantis with Ship Shoal Block 332. It will consist of a 28-in. mainline, with 24-in. laterals to the three fields.

    Initial capacity will be 450,000 b/d and will be the largest installed in water deeper than 5,000 ft in the gulf, according to BP.

    The Caesar Oil Pipeline Co. LLC will own the line, a subsidiary of BP 56%, BHP Billiton Ltd. 25%, Equilon Pipeline Co. LLC 15%, and Unocal Corp. 4%.

    In late 2002, Valero Energy Corp. joined El Paso Energy Partners LP as an equal partner in the $450-million Cameron Highway Oil Pipeline project. Announced a year ago, the pipeline will cover 380 miles to deliver as much as 500,000 b/d from the Mississippi Canyon area and the western gulf to refineries at Port Arthur and Texas City.

    The pipeline will be one of the largest crude oil delivery systems in the gulf, according to El Paso, handling oil movement for the three major deepwater discoveries that make up its initial anchor fields as well as other deepwater oil discoveries.

    In the first leg of the system, El Paso is building a 30-in. OD pipeline to El Paso's Ship Shoal 332 platform and extend it to the High Island area. From High Island, the system will proceed with two 24-in. pipelines, one extending north to Port Arthur and another to Texas City.

    El Paso expects to start up the line in late 2004 and will be operator. Valero and El Paso expect construction to start this year.

    El Paso has shipper agreements with producers BP PLC, BHP Billiton, and Unocal for oil production from the Holstein, Mad Dog, and Atlantis Deepwater Trend discoveries.

    Lowering in progresses last year on the $1.2 billion expansion of the Kern River system from Wyoming to California. The project will start up later this year and more than double delivery capacity after installing 717 miles of loop and adding 163,700 hp of compression. Photograph courtesy of Kern River Gas Transmission Co., Salt Lake City.
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    Two large segments will comprise the third system, not slated to come on stream before 2005. It will serve the Thunder Horse field in the Mississippi Canyon portion of the gulf. Dubbed the Proteus Oil Pipeline, the 28-in. deepwater portion of the system will cover 70 miles from the Thunder Horse platform to a booster station platform to be installed on South Pass Block 89.

    From there, Proteus will connect to Endymion Oil Pipeline, a 90 mile, 30-in. system extending to Clovelly, La., where it will connect with Louisiana Offshore Oil Port storage and offloading facilities. The two lines, Proteus and Endymion, will initially be able to move 420,000 b/d.

    More gas—onshore

    Florida Gas Transmission Co. this month was to have begun upgrades to its Station 18 in Orange Co., Fla., as part of FGT's Phase VI expansion, approved by FERC in July of last year.

    The expansion will add about 121 MMcfd of delivery capacity into Florida with 33 miles of pipeline and 18,600 hp of compression at existing stations. Work to rerate six compressor stations was finished in August 2002.

    The $105-million project received preliminary approval from FERC in February 2001, pending completion of the environmental review. In-service could come as early June.

    FGT said when it announced the Phase VI FERC filing in 2001 that it was supported by long-term firm natural gas transportation contracts with Orlando Utility Commission, Reliant Energy Services Inc., the City of Leesburg, Fla., and South Florida Natural Gas Co.

    FGT has already completed and, in April 2002, placed in service the second stage of its Phase V expansion, adding about 64 miles of pipeline and increasing compression by about 103,000 hp at new or existing compressor stations to provide 298 MMcfd of additional transportation capacity.

    When all stages of Phase V are completed, sometime later this year, FGT will provide a total of 428 MMcfd of new gas transportation service.

    With both Phases V and VI complete, FGT will make available about 550 MMcfd of new capacity to Florida, increasing total capacity to more than 2.2 bcfd.

    FGT is a wholly owned subsidiary of Citrus Corp. and operates the 4,900-mile interstate gas transmission system between South Texas to South Florida. Citrus Corp. is jointly owned jointly by Enron Corp. and El Paso Corp., both of Houston.

    Out west, the largest pipeline construction project under way in North America kicked off work last summer as Kern River Gas Transmission Co., Salt Lake, began a $1.2 billion expansion of its 926-mile pipeline from southwest Wyoming to California. The project will more than double delivery capacity.

    Upon completion by later this year, the pipeline will have total delivery capacity of 1.73 bcfd, an increase of 906 MMcfd.

    Being added are 717 miles of loop in Wyoming (Lincoln and Uinta counties), Utah (Summit, Morgan, Salt Lake, Utah, Juab, Millard, Beaver, Iron, Washington counties); Nevada (Lincoln and Clark counties); and California (San Bernardino and Kern counties).

    And the project is adding 163,700 hp of compression at three new and six existing compressor stations and modifying five existing meter stations. New compressor stations are being installed in Uinta County, Wyo.; Salt Lake County, Utah; and Clark County, Nev.

    Kern River's system began operation in 1992 as a subsidiary of Williams, which sold it in 2002 to MidAmerican Energy Holdings Co., Des Moines, Iowa.

    Kern River also completed last year its High Desert Lateral gas pipeline in San Bernardino County, Calif. The 32 mile, $29-million pipeline can ship up to 282 MMcfd to a new 810 Mw electricity-generating plant owned by High Desert Power Project LLC near Victorville, Calif.

    Construction on the meter stations and pipeline occurred over summer 2002 with start-up in September.

    Kern River says construction of the High Desert Lateral is its third major project in California since 2001. These expansion facilities include the following:

  • 31.6 miles of 24-in. lateral pipeline from interconnects with the Kern River and Mojave Pipeline common facilities and the Pacific Gas & Electric Co.'s system to the gas-fired electricity generating plant.

  • A 20-in. mainline tap on the Kern River-Mojave Pipeline common facilities near Kramer Junction, Calif., and a receipt meter station at the start of the High Desert Lateral.

  • A bi-directional meter station and piping to interconnect with PG&E at the start of the High Desert Lateral, along with piping and valves to accommodate potential future installation of interconnect compression facilities.

  • A delivery meter station at the terminus of the High Desert Lateral.
  • Elsewhere in the US West, Tuscarora Gas Transmission Co., Reno, is nearing completion on an expansion of its pipeline system that delivers natural gas to northern Nevada markets.

    Most of the work has been at three new compressor stations in California, installing a single Solar-70 turbine compressor package at each; total additional compression will be 24,637 hp.

    The Radar and Shoe Tree compressor stations were completed at yearend 2002; the Likely station will start up this year.

    Also last year, Tuscarora built the Wadsworth Lateral, 14 miles of 20-in. in Washoe County, Nev., spending an estimated $58 million. The line expands capacity to 200 MMcfd from 124 MMcfd, most for consumption by power generators.

    Gulf Interstate Engineering Co., Houston, executed the engineering, procurement, and construction (EPC) contract for the compressor stations; Gregory & Cook Inc., Houston, built the lateral.

    Tuscarora Gas Transmission is owned by Tuscarora Gas Pipeline Co. (50%), a wholly owned subsidiary of Sierra Pacific Resources, and by two units of TransCanada PipeLines Ltd., Calgary: TC PipeLines LP (49%) and TCPL Tuscarora Ltd. (1%).

    It operates a 229-mile interstate pipeline system built in 1995. The company says it has firm service contracts for more than 97% of its capacity, including 95% held by Sierra Pacific Power Corp.

    Other western US plans for increasing natural gas supplies to the California market have met with less success.

    Early last year, Kinder Morgan Energy Partners LP and independent power producer Calpine Corp., San Jose, Calif., cancelled joint plans to develop a 1,160 mile, $1.7-billion gas pipeline that would have moved gas to California from New Mexico's San Juan basin.

    The Sonoran Pipeline, announced in 2001, was "unable to secure sufficient binding commitments to make a successful project given market conditions," the companies said.

    In an open season in 2001, the partners had received more than 1 bcfd of binding precedent agreements for the pipeline project's first phase, which would have extended from the Blanco Hub and to near Needles and Topock, Calif. A possible second phase would have delivered gas into northern California.

    Product, bitumen plans

    Colonial Pipeline Co., Atlanta, which annually leads all US petroleum product pipelines in throughput, is proceeding with plans for a new, larger pipeline into East Tennessee to move more gasoline and other liquid fuels, said the company late last year.

    Colonial's East Tennessee Expansion Phase I has been completed, a company spokesman told OGJ last month, uprating pumps and motors to increase flow.

    The 43-mile Phase 2 construction of new 16-in. from Ooltewah (northern Hamilton County) to northern McMinn County, Tenn., will start up mid-summer 2003. Delivery will increase to 125,000 b/d, up from 80,000 b/d in the existing 10-in. line.

    Proposed Phase 3 calls for construction of 24 miles of 16 in. from Loudon County into Knoxville and is set for construction 2004-05.

    Upon completion of the entire project, deliveries to Knoxville will reach 180,000 b/d, and the existing 10-in. line will cease deliveries.

    In other product action, TEPPCO Partners LP this year will expand capacity of its northeastern US LPG delivery system by more than 1 million bbl. The expansion involves construction of three new pump stations on its LPG common carrier pipeline between Middletown, Ohio, and Greensburg, Pa.

    A company spokeswoman told OGJ in January: "We are on track to complete the project by end of third quarter 2003."

    The project is part of the company's overall effort to increase LPG deliverability, including completion last year of an LPG truck rack upgrade at Princeton, Ind., and addition of 3.5 million bbl of brine containment at Mont Belvieu, Tex., by summer this year.

    In Canada, expectations for increased total oil production from Western Canada are running high as more projects are proposed and existing proposals move toward fruition.

    Last year, Enbridge Inc. announced it was studying several routes and plans to move more oil sands production (OGJ, July 15, 2002, p. 27). The company expressed belief that total oil production from Western Canada would more than double in 10 years if all planned oil sands projects come on stream.

    Enbridge estimated that upgraded bitumen from oil sands surface mining could reach 1 million b/d by 2010 and in situ recovery projects could increase production to 0.7-1.2 million b/d in that period.

    Bitumen production by major mining operators Syncrude Canada Ltd. and Suncor Inc. is near 500,000 b/d.

    Also, Bison Pipeline Ltd., a wholly owned subsidiary of BC Gas Inc., is advancing plans to build an $800 million (Can.), 320 miles, 30-in. insulated (3 in.) pipeline to move bitumen from the Athabasca oil sands to near Edmonton, Alta.

    Bison Pipeline Project Manager Norm Rinne told OGJ last month that the regulatory filing had not yet been made but that initial public consultation and environmental studies have been completed.

    "The schedule has not been finalized as we are waiting for producers that are potential shippers to finalize their plans and commit to one of several pipeline alternatives that have been proposed," he said.

    The project has been delayed at least a year from the original in-service date of mid-2005. "If in-service occurs in 2006," he said, "then construction would begin in late 2004."

    Being insulated, the system would make minimal use of diluent, the company has said. Initial capacity would be 100,000 b/d, expandable to 450,000 b/d.

    European projects

    Construction of long-delayed, much-debated Baku-Tbilisi-Ceyhan crude oil export pipeline officially kicked off late last year when contractors began work on building three pumping stations in Turkey and on and offshore terminals for use in construction operations, according to the Caspian News Agency.

    First delivery of line pipe from Japan was expected last month with actual construction of the line to begin by second quarter of this year.

    The line has been pushed by the US government in its efforts to exclude Iran from participating in transportation schemes to move heretofore isolated oil and gas reserves from the rich Caspian Sea region.

    The expensive and technically difficult BTC line marks an end-run around easier Iran-based export routes, excludes the country from participation in major projects, and further isolates it commercially and politically.

    All this is part of efforts to pressure the Muslim regime to cool what Washington sees as its irritating involvement in regional conflicts.

    The other pressure for the longer route has come from Turkey, which pressed hard for an export option that did not involve yet more tanker traffic through the already crowded and narrow Bosporus Strait. And of course construction in Turkey will benefit that country as well.

    BP, for the Baku-Tbilisi-Ceyhan Pipeline Co. (BTC), will operate the 1,093 mile, 42 and 46 in., $4-billion pipeline that will carry Caspian Sea-region crude oil from Baku, Azerbaijan, via Tblisi, Georgia, to Turkey's Mediterranean Sea port of Ceyhan for export. Peak flows on BTC could reach 800,000-1 million b/d.

    The project is managed by an international consortium led by BP and the State Oil Co. of the Azerbaijani Republic (SOCAR). In October, Japan's Inpex Corp. acquired a 2.5% share in BTC Co, taking ownership portions from BP and Turkey's state oil company TPAO.

    As 2003 began, shareholders in BTC Co. were BP (operator, 32.6%), SOCAR (25%), Unocal Corp. (8.9%), Statoil ASA (8.71%), TPAO (6.53%), Agip (5%), TotalFinaElf (5%), Japan's Itochu Corp.(3.4%) and Inpex (2.5%), and the Baku-based Delta Hess Alliance (2.36%).

    Construction is to be completed in 2005.

    Greece's Consolidated Contractors International Co. will handle pipelaying in Azerbaijan, while a joint venture of France's Spie-Capag SA and Petrofac Ltd., London, will handle pipelaying in Georgia and related facilities work in both Azerbaijan and Georgia.

    In December, BP awarded a $34-million contract to Zurich-based power and automation technology group ABB to supply control and safety systems for the pipeline.

    New Delhi-based Punj Lloyd Ltd., in partnership with Turkey's Limak, will construct 206 miles of the Turkish section from the town of Ulas to the Ceyhan terminal.

    The Ulas-Ceyhan stretch of the pipeline crosses hazardous terrain, bisecting seven rivers and negotiating the steep Kocadag and Taurus mountain ranges, said a CNA report last year.

    Also in the region, first gas began flowing on Dec. 29, 2002, through the landmark $3 billion, 770-mile Blue Stream pipeline between Russia and Turkey across the Black Sea, according to Russian press reports. Initial deliveries to Turkey in 2003 will reach 6 billion cu m.

    Blue Stream Pipeline Co. BV is an equal-interest joint venture between Italy's ENI SPA and Russia's OAO Gazprom. The line is significant in both a political and an engineering sense.

    Gazprom operates the 230-mile Russian overland section to the Beregovaya gas compressor station on the Black Sea in the Krasnodar Region of Russia. The joint venture operates the 236-mile subsea portion in the Black Sea, and the Turkish government's Botas Petroleum Pipeline Corp. operates the 304-mile onshore section in Turkey. Landfall, treating, and recompression occur at a terminal near the city of Samsun on the Turkish shore with gas moving on to Ankara.

    Politically, the project marks yet another outlet for Russian natural gas to yet another European market, this one to the south rather than to the west. The cash-starved Russian economy can use all the hard-currency imports it can get.

    It has taken almost exactly 5 years for the project to become reality, beginning with an intergovernmental agreement in December 1997, according to Caspian New Agency reports late last year.

    But the engineering for the line was especially difficult, involving as it did land and subsea design hurdles.

    ENI said last year that advanced technology and high-quality materials enabled construction in the face of "a number of exceptional challenges, including pipelaying at record water depth, the very difficult seabed conditions on both Turkish and Russian sides, and unfavorable weather conditions with winds exceeding 50 knots."

    Capacity from Russia to Turkey is 16 billion cu m/year (1.55 bcfd) under a working pressure of 22-25 MPa (3,188-3,623 psig).

    Blue Stream's marine section consists of twin 24 in. OD, 1.37-in. WT lines. Construction of the subsea segment occurred in the 2001-02 construction season with Saipem SPA's Saipem 7000 semisubmersible pipelay vessel installing the lines in water up to 2,150 m deep.

    In other Caspian Sea area news, plans moved ahead last year for a natural gas pipeline between Turkey and Greece that would extend deliveries of an existing and operating Iran-Turkey pipeline and provide an outlet to Europe for Azerbaijan supplies.

    Initial concepts envision a line between Ankara, Turkey, and Alexandroupolis, Greece, on the northern coast of the Aegean Sea that would carry as much as 500 million cu m/year. Preliminary estimates place the cost at $300 million, various regional media reported last year.

    Early in 2002, representatives from the governments of Greece and Turkey met in Ankara to sign a formal pipeline protocol, prompting a year-long basic and detail engineering study of the route. Targeted completion for such a line is 2005.

    Turkey has repeatedly stated its goal to serve as the main transit country for hydrocarbons out of the Caspian Sea region (OGJ, Jan. 14, 2002, p. 60), and Greece has been looking for opportunities to be the European conduit for natural gas from Iran. Press reports have stated that the Athens government has reserved EU funds to extend its natural gas network to Italy.

    Elsewhere in Europe, shipper interest in Marathon Oil Co.'s Symphony natural gas pipeline in the North Sea, expressed during an open season last year, has prompted the company to expand the initial project.

    Shipper expressions totaled 17 billion cu m/year (1.65 bcfd) of firm transportation capacity. When the project was announced a year ago, planned deliveries were to reach about 900 MMcfd from Norway's Heimdal area in the North Sea to Bacton, on UK's southeast coast.

    The 420-mile pipeline would pass through Marathon-operated UK Brae complex and near the UK's Miller and Britannia complexes.

    Based on the recent open season, however, the project will likely consist of two Symphony Link pipelines originating in the Norwegian North Sea connecting to the main pipeline. Sleipner is a new Symphony component, says Marathon, and will become the primary hub, while Heimdal will provide the second link.

    These links will reinforce gas supply to the UK via the Brae producing complex in the UK North Sea where the main Symphony pipeline will transport gas to Bacton for connection to the UK National Transmission System.

    Marathon says the processing capacities of the hubs on Brae, Sleipner, and Heimdal "will complement the new pipeline system and the services it will offer.

    "The Symphony pipeline will facilitate the connection of UK gas resources including smaller satellite fields, as well as those located offshore Norway, [and] serve the needs of several market conditions, including the projected need for additional gas in the southern UK, the potential to complement the present UK system by providing [its] first dry gas system, and the growing unused off-take capacity at Bacton into the UK."

    At present, the company envisions the following technical elements:

  • Diameters: up to 42 in. from Sleipner to Brae; up to 36 in. from Heimdal to Brae; and up to 42 in. from Brae to Bacton.
  • Lengths: Symphony Sleipner Link, about 34 miles; Symphony Heimdal Link, about 65 miles; Symphony main Brae-to-Bacton, about 420 miles.
  • Capacity: up to 2.4 bcfd of dry, lean natural gas.
  • Pressures: about 2,320-2,610 psi at Sleipner and Heimdal; 1,015-1,160 psi at Bacton.
  • Following the shipper expressions of interest through the 2002 open-season period, Marathon has now embarked on securing shipper commitments. The pipeline could come on stream as early as fourth-quarter 2005, assuming timely regulatory approvals, financing, and final design.

    Middle East gas

    The most significant recent natural gas pipeline project in the Middle East is poised to swing into full construction this year.

    The pipeline, part of the two-part project to be operated by Dolphin Energy Ltd., will originate at Qatar's Ras Laffan terminal and consist of a $1.5 billion, 48-in. export line to move 2 bcfd about 273 miles to markets in the UAE. The pipeline will terminate at a platform off Abu Dhabi that will separate the stream for pipelines to Tawilah, Abu Dhabi, and Jebel Ali, Dubai.

    Project life will be 25 years or longer and ultimate capacity could reach 3.2 bcfd.

    With production set to start up by 2006, development drilling began last year in Qatar's North field along with engineering studies for both upstream facilities and pipeline.

    This year could see start of construction on production and processing facilities and the pipeline.

    In 2001, the state-owned UAE Offsets Group (UOG) selected Occidental Petroleum Corp. to assume the 24.5% interest in the project previously held by Enron Corp., making Occidental the third partner of DEL along with UOG (51%) and TotalFinaElf SA (24.5%).

    Complementing the 273-mile mainline from Qatar to the UAE—and comprising the second part of the Dolphin project—will be a 113 mile, 24-in. line from Al Ain, Abu Dhabi, to the emirate of Fujairah.

    The line will supply 120 MMcfd of gas to the Union Water & Electricity Co. to power a new 656-Mw power generation plant and a 100-million gpd desalination plant.

    The line is due to start operations this year, initially carrying gas supplied by Oman Oil Co. until about 2006 when Dolphin gas will supplant those volumes via interconnections with existing pipelines operated by the Abu Dhabi National Oil Co.

    DEL says that, since February 2002, marine survey specialists Fugro Middle East have been at work plotting the land area for the Qatar gas plant and the pipeline route to the UAE.

    In March last year, Kellogg, Brown & Root received the midstream engineering contract for the pipeline and the riser reception platform.

    Also since early last year, a joint effort of Foster Wheeler Corp. and Sofresid Groupe has been designing final reception facilities for the pipelines to both Jebel Ali and Tawilah.

    Dodsal Pte. of India has the engineering, procurement, and construction contract for the 113-mile line to Fujairah, valued at $65 million.

    By Jan. 16, 2003, contractors were to have submitted bid packages for construction of a logistics base for offshore wells operations in Qatar. The work involved building logistics base, yard, and warehouse for 3 years to support offshore wells operations that would be in operation by October 2003.

    Other Mideast gas

    Qatar has been pressing for a regional natural gas grid, of which the Dolphin system would be the main spine.

    Last year, the country reached agreement in principle with Kuwait on price and a supply of 500-700 MMcfd.

    And, following settlement of long-standing border disputes, Qatar and the island nation of Bahrain are moving toward supply agreements of 300-500 MMcfd.

    But both customers of Qatari gas have been keeping options open for gas from Iran.

    OGJ reported last year that Iran is accelerating development of offshore South Pars gas with a massive investment program in the southern city of Assaluyeh (OGJ, July 22, 2002, p. 22).

    But Iran has also nurtured its position as producer and transit point for gas to European markets, according to reports from CNA last year.

    By mid 2002, an agreement was due to be signed for construction of Iran-Armenia gas pipeline that would promote gas movements from Turkmenistan through Iran to Armenia.

    Construction was to have started by 2003.

    Plans were also afoot last year for a pipeline to move natural gas from Iran to Bulgaria through Turkey. The plan, also according to CNA, involved use of Bulgarian companies in assorted urban construction projects in 18 cities in Iran and payment to take the form of gas and oil.

    The regional news agency said that nearly 4 years ago, Bulgarian construction company Transkomplekt was commissioned by Germany's Pipeline Engineering to draft a feasibility study for a Slovakia-bound gas pipeline from Iran through Turkey, Bulgaria, and Romania.

    And Saudi Arabia continues to develop its natural gas, according to sketchy reports from Saudi Aramco.

    The Haradh gas program, in the eastern part of the country, targets start-up later this year of a gas plant (capacity undisclosed) with four gas processing trains and four sales-gas compression trains, inlet facilities, condensate stabilization, acid-gas handling, and a 230-kv substation.

    Also part of the project are 242 miles of 48 and 56-in. pipelines linking with the Saudi Aramco distribution net. Design pressures will range from 720 to 1,110 psig, says the company, and the pipelines will be complete with scraper traps, emergency and section-isolation valves, and four future gas-compression stations.

    The project will increase the country's gas sales output by 1.5 bcfd and recover 140,000 b/d of condensate and 80,000 tonnes/day of sulfur.

    Africa

    Installation of one of the largest oil pipeline projects in the world has been quietly progressing since mid-year 2002 as ExxonMobil Corp. and partners build a 650 mile, 24-in. pipeline from a $3.5-billion oil development in Chad to an export terminal at Kribi, Cameroon.

    ExxonMobil Corp., through its Esso Chad subsidiary, holds a 40% interest and is the operator; Petronas Carigali of Malaysia has 35%, and ChevronTexaco 25%.

    Drilling began a year ago with 300 development wells planned and first oil expected by yearend 2003. Output from the Doba basin in southern Chad, with estimated recoverable reserves of 1 billion bbl, will reach 225,000 b/d, ExxonMobil said last year in announcing the start of drilling.

    Chad is set to receive between $2.5 billion and $5 billion in direct revenues from royalties, taxes, and dividends, depending on the price of oil, over the field's 30-year life. Cameroon will receive $500 million in pipeline transit fees, taxes, and dividends over the project's lifetime.

    In another African project involving ExxonMobil, through its subsidiary Mobil Equatorial Guinea Inc., construction is under way on about 30 miles of subsea pipelines off Bioko Island, Equatorial Guinea.

    The $900-million Southern Expansion project is set to flow by late 2003 on Block B, about 30 miles northwest of Malabo in 1,400-2,800 ft of water. Plans call for recovery of about 150 million bbl of oil flowing from subsea wells tied back to a floating, production, storage, and offloading (FPSO) vessel that can process 110,000 b/d and store about 2 million bbl.

    In addition to the ExxonMobil unit, Ocean Energy holds 23.75% and the government of Equatorial Guinea 5%.

    Elsewhere in Africa, plans for a gas pipeline liking Nigeria with Ghana appear to have stalled.

    Construction was planned to begin this year.

    Chevron Nigeria has been leading the project, which also includes Royal Dutch/Shell and Nigerian National Petroleum Corp., among others.

    The 600 km, 400-MMcfd line would link Lagos to Takoradi, Ghana, and with supply points at Cotonou, Benin; Lome, Togo; and Tema, Ghana.