Landmark Trinidad LNG export project gets off high center

Dec. 16, 1996
Atlantic LNG Project Layout [45579 bytes] Cabot LNG Corp.'s Mourad Didouche LNG carrier is shown en route to Cabot's Everett, Mass., LNG import complex. Cabot will buy 60% of the output from Trinidad and Tobago's LNG export project, transporting it in the Gamma, an LNG carrier of similar size and design. Photo courtesy of Cabot. Amoco Trinidad Oil Co. continues to prove more gas reserves off Trinidad's eastern coast to dedicate to Trinidad and Tobago's LNG export project.
Cabot LNG Corp.'s Mourad Didouche LNG carrier is shown en route to Cabot's Everett, Mass., LNG import complex. Cabot will buy 60% of the output from Trinidad and Tobago's LNG export project, transporting it in the Gamma, an LNG carrier of similar size and design. Photo courtesy of Cabot.
Amoco Trinidad Oil Co. continues to prove more gas reserves off Trinidad's eastern coast to dedicate to Trinidad and Tobago's LNG export project. Shown is the Gorilla IV jack up drilling rig during the 1995-96 season off Galeota Point. Photo courtesy of Amoco.
Major construction work on Trinidad and Tobago's Atlantic LNG project, the first grassroots liquefied natural gas export project in the Western Hemisphere in more than 25 years, has gotten under way.

Significant civil work got under way at the end of October.

The project, conceived in 1992, calls for building a single-train, $1 billion LNG complex at Point Fortin, in Trinidad.

It is designed to produce 3 million metric tons/year of LNG, with first shipments projected for mid-1999.

The plant's entire output will be exported to markets in the Northeast U.S. and Spain, and the project is being laid out with space for additional LNG trains.

Atlantic LNG Co. of Trinidad & Tobago, the joint venture that will build and operate the plant, has these partners: Amoco Trinidad (LNG) BV, a unit of Amoco Corp., 34%; British Gas Trinidad LNG Ltd., a unit of British Gas plc, 26%; Repsol International Finance BV, a subsidiary of Spain's Repsol SA, 20%; Cabot Trinidad Ltd., a unit of Boston-based Cabot Corp., 10%; and the National Gas Co. (NGC) of Trinidad & Tobago, a government-owned concern, 10%.

Bechtel is the prime contractor for the project, with responsibility for engineering, procurement, construction, start-up, and initial operating services.

Atlantic has already carried out site preparation and some design/engineering work, and orders have been placed for equipment.

Atlantic has signed an agreement with Phillips Petroleum Co. to use its Optimized Cascade LNG process, and financing of $600 million is being arranged by ABN Amro Bank N.V., Barclays Bank plc, and Citibank N.A.

Economic effects

The project ranks as the largest single investment ever made in the Caribbean islands and will have a major effect on the economy of Trinidad and Tobago, a republic of only 1.3 million.

At its construction peak, the project will employ about 2,000 people, the great majority from Trinidad.

However, the plant will be highly automated and will have only 100-150 workers after it goes into commercial operation.

Atlantic, set up in 1995, estimates that the project will have a direct economic benefit of about $6 billion to the island republic during its first 20 years, including taxes and royalties, plus a ripple effect on the general economy.

Small scope, short fuse

Atlantic's investors have kept the project's size and development costs relatively small in comparison with other LNG projects under consideration internationally.

If the project goes on stream in 1999, as planned, it will have a 7-year development cycle, compared with a world average of 14 years or more. The future plant's natural gas requirements (as much as 475 MMcfd) will be met by Amoco's Trinidad operating unit, Amoco Trinidad Oil Co. (ATOC) under a 20-year supply agreement, with an option to extend under certain conditions.

The gas will come from fields in the Atlantic Ocean off Trinidad's southeastern coast, and will be carried to the Point Fortin facility in the west by subsea and onshore pipelines.

Amoco plans to lay a total of 172 miles of pipelines-112 miles of subsea and onshore lines for natural gas and 60 miles for condensates-linking the offshore fields to the plant site.

LNG buyers

Cabot and Repsol affiliate Enagas SA, also a Spanish company, will take 100% of Atlantic LNG's output under another 20-year contract that may be extended under certain conditions.

The two companies see windows of opportunity for LNG in their respective markets, and they contend the Atlantic project will provide them with a competitive advantage over certain planned gas pipelines and competing fuels.

Cabot LNG Corp., which has been importing and distributing LNG in the U.S. Northeast for 25 years, will purchase 60% of overall production and Enagas the remaining 40%.

Repsol is an integrated oil, gas, and petrochemical company that works in Spain and internationally. It owns 45% of Gas Natural, Spain's largest natural gas distributor, which in turn holds 91% of Enagas, the largest importer and wholesaler of natural gas in Spain.

Enagas and Cabot will supply their own LNG tankers.

Phillips process

Phillips' Optimized Cascade LNG process was chosen over Air Products & Chemicals Inc.'s LNG technology (see related story, p. 14).

The only commercial application of the Phillips Cascade system up to now has been at the Kenai LNG plant in Alaska, a joint venture of Phillips and Marathon Oil Co. that went on stream in 1969 with a nameplate capacity of 1.56 million tons/year.

Prior to the Atlantic project, Kenai was the last grassroots LNG export project to be built in the hemisphere.

The plant will use five GE Frame 5 gas turbines for its drivers and have an air cooling system. It will also have several smaller turbines to improve reliability and flexibility and maintain a high level of efficiency.

Along with the new marine terminal for loading LNG carriers, Atlantic is also erecting two LNG storage tanks with capacity of about 100,000 cu m each.

Other spending

Aside from the $1 billion investment estimate for the LNG plant, loading facilities, and marine terminal (a port will have to be dredged at Point Fortin), partners estimate that another $300-400 million or more will be part of the overall project outlay.

Most of these additional investments cover what Amoco will have spent for exploration, development, and production in Trinidad's offshore gas fields, as well as pipeline construction.

Also, Cabot will invest in refurbishing and upgrading its LNG tanker and in raising regasification capacity at its Everett, Mass., terminal.

More capacity?

The Point Fortin site has room for additional LNG capacity, and investors are already studying the possibility of adding another 3 million tons/year.

A British Gas official said that his company expects a second train to be developed, and BG hopes it will be able to sell natural gas to the next stage of the project from existing and prospective fields it operates off northern Trinidad.

In addition to its participation in the LNG project, BG operates the Dolphin field-which started production of gas in March-on behalf of a 50-50 BG-Texaco Inc. partnership, has other offshore interests in Trinidad with Texaco, and operates two licenses.

Amoco project work

Amoco Trinidad is developing two of its offshore gas fields-East Mayaro and South SEG (south-southeast Galeota)-to supply the Point Fortin LNG plant with as much as 475 MMcfd of gas for 20 years starting in 1999.

It plans to drill 65 wells in these two fields the next few years, with 12 wells to be drilled in East Mayaro during 1997-98.

Overall, 40 wells are scheduled for East Mayaro and 25 for South SEG. Wells will be drilled directionally from platforms.

Amoco plans to install two platforms at the outset and may add another later.

Initial separation of natural gas liquids will be carried out on the platforms.

Atlantic intends to sell its mixed NGL stream to Phoenix Park Gas Processors Ltd. (a joint venture of Conoco Inc., NGC, and Pan West Engineers & Constructors) on a netback basis.

Pipeline work

The LNG project will require construction of two subsea pipelines.

A 14-in. condensate line will extend from the offshore platforms about 60 miles to Galena Point. Most of the condensate pipeline will be offshore.

To carry natural gas to the plant at Point Fortin, Amoco will lay about 112 miles of pipeline: 62 miles of 40-in. subsea line and 50 miles of 36-in. line onshore.

The company plans to apply new technology permitting a more cost-effective, smaller-diameter gas pipeline able to carry similar or higher loads than existing pipelines, according to Neil McCleary, Amoco Trinidad's upstream development manager for LNG.

The 36-in. onshore line will be buried from point of entry-near the town of Beach Field on the eastern coast of Trinidad-to the LNG plant.

A slug-catcher will be located onshore to collect liquids formed while the gas moves through cool seawater in the 40-in. line.

The offshore pipelines will be built, owned, and operated by Amoco Trinidad. The onshore segment of the gas pipeline will be built by Amoco Trinidad on behalf of owner NGC, and Amoco will operate the line.

Amoco Trinidad E&D

Amoco has invested more than $1.5 billion for exploration, development, and production in the gas and oil fields off Trinidad's eastern coast since the mid-1960s.

The company expects substantial future capital outlays for offshore development and production, platforms, pipelines, and other facilities to provide the LNG plant with natural gas.

Amoco estimates its capital investments in Trinidad the next 2 decades at $1.2 billion.

During 1976-93, Amoco drilled about 40 exploratory wells in the Atlantic east of Trinidad, with only four discoveries (two crude oil and two gas).

"But 1994 to early 1995 was the big turnaround for us," said Larry Tiezzi, Amoco Trinidad's exploration manager.

The company drilled six exploratory wells, finding gas with three during its 1994-95 exploration program.

Since then, under its 1995-96 exploration program that started in October 1995, the company has drilled eight more wells, discovering large volumes of gas with six. One well was a dry hole and another, a discovery, is still being tested. The eighth well, La Novia, located 35 miles offshore, completed the company's 1995-96 drilling program for Trinidad.

Of its total reserves of 10 tcf, Amoco Trinidad has added about 7 tcf of natural gas and more than 100 million bbl of crude to its reserves in Trinidad since 1994.

This accounts for a major share of the island's proven and probable natural gas reserves, estimated by the government at 18.1 tcf by yearend 1995 vs. 13.9 tcf in 1994.

Trinidad potential

Trinidad's natural gas reserves figure as a major reason for the project's feasibility.

NGC calculates that the country's current estimated reserves will cover 28 years of production, including domestic consumption and the LNG plant requirements.

International companies believe the island republic has additional commercial reserves off the eastern coast and in the north coast offshore, some of which have already been identified.

Earlier this year, Trinidad's Ministry of Energy and Energy Industries issued a public call for bids on nine deepwater blocks to the east and northeast of the main island (OGJ, Oct. 7, p. 38).

This was the first time the country had sought offers for deepwater blocks.

The most recent oil and gas discoveries were drilled in water depths of 200-350 ft from 35-53 miles offshore in the Atlantic.

Amoco's 1 Corallita, the well located farthest offshore, was drilled to 15,124 ft TD and flowed 60.4 MMcfd of gas.

This was the most expensive Trinidad well to date, costing about $13 million. Other wells in the current program cost around $8-9 million each.

Another recent discovery, 5 East Mayaro, drilled to 13,315 ft in 290 ft of water, tested at 34.9 MMcfd of gas and 3,400 b/d of crude.

Amoco's 5-X East Mayaro, 45 miles offshore, tested at 64 MMcfd of gas and 3,700 b/d of crude and condensate.

Tiezzi attributed much of Amoco's recent successes to the use of "Coherency," a patented 3D seismic test developed by his company. Coherency, originally designed to better see faults, unexpectedly allowed Amoco to identify the extent of hydrocarbon deposits located around a particular well, thus reducing the need for much additional drilling.

There are more than 20 oil and gas fields east of Trinidad, and Amoco has discovered most of them. Even though Amoco has drilled as deeply as 18,000 ft, it has mostly worked in Pleistocene to modern structures.

The basin east of Trinidad where Amoco and other companies are drilling offers some very attractive features, according to Tiezzi. These include excellent source rock, good quality reservoir rock, and multiple pay zones.

Investment factors

Accessible and commercially viable natural gas reserves clearly ranked as an important element in deciding to move ahead with the Trinidad LNG project.

But investing companies stress that there were several other key factors.

While Trinidad's natural gas reserves are relatively modest when compared with those of neighboring Venezuela and Middle East producers, the country has been able to attract substantial foreign investment in natural gas E&P because it has the political maturity to allow large-scale foreign participation in these sectors.

It has created a climate attractive for investment, auctioned off a number of exploratory blocks, and brought in capital from several international operators.

Amoco has been operating in Trinidad since 1961, and British Gas began working there in 1989, when it acquired Tenneco Inc.'s offshore interests. Texaco, Enron Corp., and Talisman Energy Inc. are also active there.

Trinidad offers the project a corps of well-educated workers who can be efficiently trained in the many specialized tasks associated with carrying out this $1 billion-plus effort.

The Atlantic LNG project includes a combination of stakeholders from all sectors of the value chain, including private companies that are veterans in Trinidad's natural gas upstream sector (Amoco and BG), two experienced companies that will purchase 100% of the LNG plant's output (Cabot and Repsol's Enagas), and the government-owned natural gas enterprise (NGC), an experienced and profitable firm.

Other, potentially competing LNG projects are larger, costlier, supply-driven, and require longer lead times.

Gas market

NGC says that natural gas demand in Trinidad and Tobago has grown from 150 MMscfd in 1978 to 593 MMscfd at yearend 1995, an average increase of 8.4%/year.

Using a "moderate growth scenario," NGC predicts that natural gas demand in Trinidad and Tobago will rise to 1.6 bscfd by 2000, including the LNG project, petrochemicals, additional light and heavy industrial requirements, plus other domestic demand.

And excluding a second LNG train, NGC projects natural gas demand will jump to as much as 1. 8 bscfd by 2005.

NGC says the country's domestic gas requirements by 2000 will be met by Amoco, British Gas, and Enron, as well as NGC's own operations.

The Atlantic LNG project is by far the largest of several natural gas-related projects that are expected to bring the island investments of $3 billion the next 5-6 years.

Other major projects are being planned or carried out with the help of international investors in methanol, ammonia, other petrochemicals, and iron carbide and hot-briquetted iron.

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