Worldwide gas processing continues to expand, shift balance

Warren R. True
Pipeline/Gas Processing Editor

Construction nears completion earlier this year on inlet-gas and NGL-fractionation expansions at Phoenix Park Gas Processors Ltd.'s plant at Point Lisas, Trinidad & Tobago. Among the largest in the Western Hemisphere now, the plant will fractionate liquids from the nearby Atlantic LNG plant that will start up this month.

Gas processing outside North America in 1998 continued to gain ground on the U.S. and Canada, extending a trend that has been evident for some time.

Percentage gains in inlet capacity, throughput, and NGL production in Latin America, the Middle East, and countries of Asia-Pacific outstripped Canadian growth, while U.S. numbers were contracting.

The growth in gas-processing activity outside North America reflects not only the generally flat gas-production trends and capacity consolidations in the U.S., but also a wider, more fundamental shift in NGL, especially LPG, trading patterns. Experts have been predicting this shift for some time. (See accompanying article, p. 47.)

Nevertheless, at Jan. 1, 1999, U.S. and Canadian gas processing reflected its historic dominance of world activity: Combined for 1998, the two countries held 57% of capacity and produced more than 52% of the world's NGL (Table 1 [65,536 bytes]).

On Jan. 1, 1999, U.S. gas-processing capacity stood at nearly 68.3 bcfd; throughput in 1998 averaged 48.2 bcfd; and NGL production, more than 75 million gpd (1.8 million b/d). All these figures are off from a year earlier.

Canadian gas-processing capacity at the beginning of the year exceeded 46 bcfd with an average of more than 36 bcfd going through the country's plants last year. NGL production exceeded 53 million gpd. All these figures evince increases over 1997.

Underlying these figures is the growth in Canadian gas production in response to expanded takeaway capacity from the province of Alberta, primarily for U.S. markets. Indeed, Oil & Gas Journal data show that Canadian gas production has been steadily increasing for several years (OGJ, Mar. 8, 1999, p. 93; and the second issue of March for preceding year).

These gas-processing activity figures are based on Oil & Gas Journal's most recent exclusive, plant-by-plant, worldwide gas-processing survey (p. 54) and its international survey of petroleum-derived sulfur recovery (p. 94).

For Canadian figures, OGJ's report supplements operator-supplied capacity and production data with figures from the (1) Alberta Energy & Utilities Board (AEUB), (2) British Columbia Ministry of Employment & Investment's Engineering and Operations Branch, and (3) Saskatchewan Ministry of Energy & Mines.

OGJ began incorporating AEUB data in 1994 (for 1993 activity). Specific comparisons of data for 1992 and earlier years must therefore proceed carefully because of lack of response by some operators. Provincial data, nonetheless, confirm general trends indicated in data reported for those years.

In addition, numbers for 1998 plant data for Asia-Pacific, the Middle East, and Europe have been adjusted to reflect fresh information about India, Iran, and Greece, Spain, and Italy. Finally, NGL production for Saudi Arabia, the world's third largest NGL-producing country, is an aggregate published by the U.S. Energy Information Administration.

Gas-processing capacity outside Canada and the U.S. at the start of 1999 stood at more than 86 bcfd; throughput for 1998 averaged 59.5 bcfd; NGL production averaged more than 117 million gpd.

Among regions outside Canada and the U.S., countries of the Middle East hold the most capacity (nearly 21 bcfd), befitting the region's place as the world's largest exporter of NGL, especially LPG. Western Europe (nearly 20 bcfd) and countries of Asia-Pacific (slightly more than 19 bcfd) are almost tied for second place.

Latin American countries, led by new capacity in Argentina, increased capacity to more than 14.8 bcfd.

Table 2 [16,548 bytes] ranks the world's major natural-gas reserves by country at the start of 1999; Table 3 [14,909 bytes], the world's top natural-gas producing countries for 1998; and Table 4 [14,271 bytes], the world's leading NGL producers.

In petroleum-derived sulfur recovery, Canada and the U.S. continued to dominate the world in 1998, holding nearly 56% of processing capacity and 59% of actual production.

For worldwide production of sulfur derived from refining and natural gas, Canada last year accounted for more than 33% of the overall total; the U.S., more than 27%.

North American picture

As integrated as North American natural-gas trade is becoming, it will soon be obsolete to talk about U.S. activity independent of Canadian or of Mexican.

In fact, as U.S. natural-gas production has steadily slowed this decade, production in Canada and Mexico has increased almost as steadily and inexorably.

Canadian production increases target U.S. markets almost entirely. In the 24 months following September 1998, approximately 3 bcfd of new gas-pipeline capacity are set to become available to Canadian producers for moving gas into the U.S.

Mexican gas production has been mostly for domestic consumption, but in the north it has grown with an eye to crossing the U.S. border in the future. Pemex Exploración y Producción said in its annual report for 1997, for example, that Burgos basin completions had allowed the northern producing region to increase its production by more than 20% to 773 MMcfd, the highest level for the region since 1981.

Notwithstanding, the U.S. in 1998 continued to dominate the other countries and regions in gas processing: Its capacity comprised 34% and its NGL production nearly 31%, compared with the rest of the world.

Canadian capacity last year stood at 23% of the world's and its NGL production, almost 22%; Mexican inlet capacity, 2.3%, and its NGL production, 7.3%. In fact, OGJ numbers indicate Mexico ranks second only to Saudi Arabia in NGL production outside Canada and the U.S.

OGJ data for 1998, based on its exclusive survey and other published sources, indicate that nearly 1,500 gas plants were operating worldwide, 558 plants in the U.S., 696 in Canada.

Table 5 [9,433 bytes] indicates a relatively flat trend in new plants, but that situation should change especially for North America and Latin America.

And with the Asian financial crisis apparently easing, that region may witness resurgence in capital plans for new capacity in the form of new plants or expansions of existing ones.

Gulf-processing flurry

In the U.S., fewer plants were operating at Jan. 1, 1999, than began 1998. This reflects an ongoing trend of consolidation and rationalization as companies have merged, exchanged assets, and shut older, less efficient plants.

U.S. capacity utilization remained flat for 1998 at 70.6%, only a fraction off the 70.7% for 1997 but still down from 72% for 1996. In 1995, it stood at 70%. OGJ data indicate that an historic low utilization rate, at least for the modern era of deregulated natural-gas prices, occurred in 1986: 55%.

With more than 18.6 bcfd in gas-processing capacity (up from 17.6 bcfd in 1997), Louisiana continues to lead other U.S. states, followed closely by Texas with slightly more than 16.3 bcfd. Between them, the two states hold nearly 51.3% of the nation's capacity.

In 1998, the two states produced well more than half of the NGL produced in the U.S.: Texas, nearly 41%; Louisiana, more than 15%.

Louisiana capacity is undergoing significant expansion as a spate of new gas plants and expansions tries to anticipate the increased volumes of liquids coming ashore from new gas developments in the Gulf of Mexico.

At the end of 1998, Louisiana gas-plant capacity was up over the same period for 1997 by 1 bcfd, or 6%. Gas throughput, much from offshore Gulf of Mexico production, increased by 343.4 MMcfd, or 2.6%. And the state's gas plants produced more than 11.7 million gpd of NGL, up by 202,500 gpd, 1.7% over 1997.

One major project came on stream in late 1998. Discovery Producer Services started up its 105-mile, 30-in. subsea pipeline from Ewing Bank 873 on the Outer Continental Shelf to the grassroots 600-MMcfd Larose, La., plant, 35 miles south of New Orleans (OGJ, Oct. 19, 1998, p. 73).

The plant performs condensate separation and gas processing and can stabilize as much as 7,500 b/d of condensate.

Also along the Louisiana gulf coast, construction is near beginning on the Neptune gas-processing plant, a 300-MMcfd, $300-million cryogenic plant near Centerville, La. It is planned by Shell Oil Co. unit Tejas Natural Gas Liquids LLC, and Marathon Oil Co. and will serve the newly built Nautilus pipeline and facilities of Manta Ray Pipeline Partners LP.

Oil & Gas Journal's state-by-state data do not reflect operating information on NGL fractionation plants, considering fractionation to be secondary processing. The plant names and locations are listed in the accompanying plant-by-plant data table.

But several fractionator expansions or projects to improve efficiency are planned, under way, or recently completed at several important fractionation plants along the Louisiana gulf coast. These plants are strung along a line from Baton Rouge on the Mississippi River in the east to Lake Charles to the southwest.

Liquids from the large gas-processing plants feed these fractionation plants. And it is feared that the increased liquids coming ashore from the gulf in the near future may overwhelm these plants.

One such fractionation expansion occurred as part of the Discovery project at the 25,000-b/d Paradis, La., plant 20 miles north of the Larose gas-processing plant discussed earlier.

Paradis' four-tower fractionation train was expanded to 42,000 b/d with replacement of all tower trays and internals and three new 1,665-hp gas, engine-driven reciprocating compressors to meet refrigeration demand.

In addition to fractionator expansions in Louisiana, a handful of pipeline projects and alliances have been floated to take raw NGL streams westward to the cluster of fractionators at Mont Belvieu, Tex.

The prospects of new fractionation business have spawned several transactions in the last year.

Notable among them was an NGL alliance announced last month between Enterprise Products Partners LP and Shell Oil Co. unit Tejas Energy LLC in which Tejas will contribute its NGL interests in return for an equity interest in Enterprise's operations.

For Tejas, the offer is significant: It has interests in 11 gas-processing plants, four NGL fractionators, 29 million bbl of NGL storage, and more than 1,800 miles of NGL pipeline.

Enterprise, on the other hand, is one of the U.S.' most active fractionation companies, owning several fractionators, an isobutane complex, two propylene fractionators, an MTBE plant, an NGL import-export terminal, some 35 million bbl of storage, and a 500-mile NGL pipeline network.

Enterprise gains the right to process Shell's current and future Gulf of Mexico gas production and market the recovered NGL.

In another arrangement announced last year and reflecting interest in the potential of processing along the Louisiana gulf coast, Koch Industries Inc., Wichita, struck a deal with Union Pacific Fuels Inc., a unit of Union Pacific Resources Group Inc., Fort Worth, that would give it a portion of UPFI's interests in the Patterson and Calumet (La.) gas plants.

Elsewhere in the U.S., Amoco Production Co. started up its new Hugoton Jayhawk gas plant in southwest Kansas. The new plant replaced both the Amoco-operated Ulysses gasoline plant and the Warren NGL Inc.-operated Jayhawk plant.

The 450-MMcfd plant can recover more than 80% of the C2 and all of the C3+ components in a Y-grade NGL product stream of approximately 31,000 b/d.

And to the northeast of this plant, near Joliet, Ill., construction will begin this year on the 1.6-bcfd Aux Sable Liquid Products LP gas-processing and fractionation plant that will be the termination point for the high-pressure Alliance pipeline, bringing natural gas and NGL down from Alberta. Plant completion is slated for 2000.

In other transactions, Oneok Inc. will buy the Oklahoma midstream natural-gas gathering and processing assets of Koch Midstream Enterprises, a unit of Koch Industries Inc., Wichita, for $285 million. The deal includes eight natural-gas processing plants and about 3,250 miles of gathering pipeline, which connect 1,460 gas wells. Total of the plants' capacities is 515 MMcfd of gas.

Koch Midstream has sold to Duke Energy Field Services Inc., Denver, its South Texas natural-gas gathering, treating, and processing systems for an undisclosed price. The deal includes 1,000 miles of pipeline covering 10 counties, the Three Rivers and Pettus cryogenic processing plants, and a small treating facility in Dewitt County, Tex.

Canadian plans

Total Canadian gas-processing capacity at Jan. 1, 1999, stood at more than 46 bcfd; throughput for 1998 averaged more than 36 bcfd; NGL production, 53.3 million gpd (almost 1.3 million b/d).

Canadian plant utilization in 1998 was level with that for 1997: about 78%.

OGJ's survey and governmental data from Canada's three major producing provinces indicated that 696 plants were operating in Canada in 1998. Alberta alone has 658 plants with 41.6 bcfd capacity.

With that kind of concentration, it goes without saying that as Alberta goes so goes Canada-at least where natural-gas production and processing are concerned. And last year, the restructuring of the industry in Alberta continued.

The merger of NOVA and Trans- Canada symbolized the nature and direction of that restructuring. It took effect during second quarter 1998 even as construction of new pipeline takeaway capacity from the province was in full swing.

The prompt for the fundamental change in Alberta gas movements, the 1,900-mile Alliance pipeline from Alberta to near Chicago, has finally begun construction. Liquids will leave the province in the high-pressure pipeline, by-passing the massive straddle plant complex at Empress in eastern Alberta.

In a land of big gas plants, another appears on the way.

Imperial Oil Ltd., Toronto, announced last year it wanted to spend $250 million (Canadian) to build a 2.5 bcfd straddle plant in the Sundre-Caroline area, northwest of Calgary.

Residue gas of about 2.1 bcfd was to flow down the eastern leg of the Foothills system past Empress; as much as 110,000 b/d of NGL were to be routed back north to Fort Saskatchewan for fractionation.

Since then, however, Imperial has told OGJ that commercial agreements have taken longer than anticipated to conclude, pushing the regulatory application timing back to later this year or early 2000.

Additionally, ongoing technical analysis for the plant has scaled back the planned inlet capacity to 2 bcfd with 1.8 bcfd residue gas and approximately 80,000 b/d NGL production. Start-up is projected for 2001.

Also, Air Liquide, Montreal, will build a $150 million (Canadian) gas processing and power plant at Scotford, Alta., that will serve an existing styrene monomer plant and a monoethylene glycol plant, under construction.

Recently, Gulf Canada Resources Ltd., Denver, started up a 33-MMcfd gas plant near Steen, Alta.

Late last year, Gulf Canada Resources Ltd., Denver, announced plans to sell interests in western Canada gas-processing plants and pipelines for more than $220 million (Canadian).

And Dynegy Canada Inc. (formerly NGC Canada Inc.), a unit of Dynegy Inc., acquired Compton Petroleum Corp.'s midstream gas processing facilities in southern Alberta, including its 82-MMcfd sour-gas plant at Mazeppa.

Under the terms of the agreement, Dynegy Canada last year acquired Compton's interests in the Mazeppa and Gladys gas plants, with combined capacity of 97 MMcfd, 50 km south of Calgary, together with 125 km of associated gathering pipelines. Calgary-based Compton was assured processing and transportation capacity, at set rates, and $60 million (Canadian) on closing.

Alberta Energy Co. (AEC), Calgary, in another deal, reached agreement with the field services division of Westcoast Energy, Vancouver, for 4 years' firm-service gas processing at Westcoast's 700-MMcfd Fort Nelson, B.C., plant.

AEC is delivering natural gas from its Maxhamish field in northeastern B.C. Westcoast earlier this spring began processing and transportation services. AEC will supply as much as 300 bcf of gas over 15 years. AEC's Maxhamish facilities have a design capacity of 70 MMcfd.

Another Canadian company Trans-Canada PipeLines Ltd. (TCPL), Calgary, announced recently that it will sell its U.S. Gulf Coast natural-gas midstream facilities and its U.S. oil marketing and trading units.

TCPL holds ownership interests in six midstream facilities in Louisiana, with processing capacity of up to 2.2 bcfd of natural gas, that produced 90,000 b/d of ethane, isobutane, propane, and natural gasoline in 1998. The company's marketing operations in Houston, Los Angeles, and Charlotte, N.C., marketed 69 million bbl of crude and 85 million bbl of refined products in 1998.

TCPL said it plans to maintain its focus on its Canadian gas/liquids business and Canadian and U.S. northern tier crude oil business.

In the east, Sable Island natural gas, offshore Nova Scotia, will begin moving ashore towards U.S. markets later this year. As much as 578 MMcfd of sales gas is planned for, with more than 20,000 b/d of liquids produced.

The liquids will be separated from the gas as it comes ashore at the Goldboro, Guysborough County, N.S., gas plant, currently nearing completion. They will then be sent via an 8-in., 40-mile pipeline to a fractionation plant in the Point Tupper area.

World developments

As gas production in the Middle East increases, so do projects to produce and export more NGL.

Qatar General Petroleum Corp. last year started up its 800-MMcfd gas plant and condensate recovery plant at Dukhan, Qatar. The construction project included building the gas plant, laying pipelines from Dukhan field to the Mesaieed industrial area, adding storage depots, and building export facilities. The plant's target production capacity is 40,000 b/d of condensate to be transported through the pipeline to the Mesaieed terminal for export. Surplus gas is being re-injected into the Dukhan gas field.

Late last year, Saudi Aramco let a contract to JGC Corp., Yokohama, for design and construction of a 1.6-bcfd gas processing plant slated for completion in November 2001.

The plant is part of Saudi Aramco's $2 billion project to expand production in supergiant Ghawar oil field. Gas processed by the new plant will be used in power generation and petrochemicals production.

Saudi Aramco also hired the Italian unit of Technip and its subsidiary TPL Arabia Ltd. to build sulfur-recovery and utilities plants at Hawiyah gas field in Saudi Arabia. Technip said the plant, to be built 280 km south of Dhahran, will comprise three sulfur units with a capacity of 350 tons/day each, with sulfur-loading facilities and related utilities.

Mechanical completion is slated for November 2001, and the plant is due on stream in first quarter 2002. Hawiyah is expected to deliver 1.6 bcfd of gas to the Saudi master gas system.

The biggest story in Asia-Pacific region in 1998 was the explosion and fire at Esso Australia Ltd./BHP Petroleum Pty. Ltd.'s 530-MMcfd Longford natural-gas treating plant in eastern Gippsland, state of Victoria. The blast killed 2 people, injured several others, and virtually cut off gas supplies to the state for more than 2 weeks.

The plant processes oil and gas from Bass Strait fields and supplies 80% of the state's consumption. It produces 37,700 b/d of LPG and 188,500 of crude oil. Oil production from the fields was shut in for more than 2 months.

To date, no official cause of the explosion has been presented.

Along with every other commodity, China stands to be a major importer of LPG. And recently Energy Transportation Group Inc. and UGI Enterprises Inc., both of New York, formed a 50-50 venture called Chinagas Partners LP.

The partnership acquired a 50% interest in a Chinese joint venture, Nantong Huayang LPG Port Co., to import, store, distribute, and sell LPG at retail outlets along China's Yangtze River. The Chinese partner in the JV is state-owned China National Chemical Supply & Sales Corp. (China Chem).

China Chem operates an LPG import terminal at Nantong on the Yangtze; current sales for the terminal are $33.4 million/year. Chinagas Partners plans an initial investment of $10 million.

In India, the government approved Indian Oil Corp.'s (IOC) proposal to form a joint venture with Petronas of Malaysia to build a 600,000 metric ton/year LPG import terminal at Haldia in West Bengal state. The project is estimated to cost 2 billion rupees.

In Latin America, Petroleos de Venezuela SA continues development of its Accro project, letting a $450-million contract last year to a consortium of TransCanada PipeLines Ltd., Enron Corp., and Technoconsult SA, to build, own, and operate the two NGL-extraction facilities, Accro III and IV.

Included are NGL extraction facilities in San Joaquin and Santa Barbara, Venezuela, and NGL fractionation, storage, and refrigeration facilities in Jose. The units will process 800 MMcfd of gas and fractionate 50,000 b/d of NGL; products are allocated for export. NGL storage capacity will be about 610,000 bbl.

Construction is under way with start-up set for 2001.

Elsewhere, Repsol SA, Madrid, last year purchased a 75% stake in Duragas, an Ecuadoran LPG marketer, valued at $26.2 million. With sales of 300,000 metric tons/year, Duragas has a 49% share of Ecuador's LPG market.

And more recently, Phoenix Park Gas Processors Ltd., started up its $155-million expansion at Point Lisas, Trinidad & Tobago. The project nearly doubled inlet capacity to 1.35 bcfd and almost trebled NGL output to 33,500 b/d. Storage was increased to 750,000 b/d, and a second, deepwater port and terminal were added.

The plant is owned by National Gas Co. of Trinidad & Tobago (NGC) 51%, Conoco 39%, and Pan West Engineers & Constructors 10%.

Much of the impetus for the project was the construction nearby of Atlantic LNG Co.'s LNG plant, the first grassroots LNG export project in the Western Hemisphere in more than 30 years. Liquids from the LNG plant will feed additional fractionation at Phoenix Park.

In Central Europe, Agip SpA, BG plc, Texaco Inc., and Lukoil this year are investing $300 million to construct a gas and condensate processing plant in Russia's Karachaganak gas field. The consortium expected the field to produce 70,000 b/d of condensate in 1998, but it yielded only 22,000 b/d in the first half.

Other projects under way or planned for 1999 are a new gas turbine, a liquids pipeline between Karachaganak and Bolshoy Chagan, and a gas pipeline to western Russia. By 2002, the group will have invested a total of $1.76 billion in the first Karachaganak development phase.

Sulfur recovery

In 1998, petroleum-derived sulfur production capacity worldwide increased to more than 128,000 metric tons/day (mtd) from more than 122,8000 mtd in 1997.

Canada reported more than 33,500 mtd capacity in 1997 (25.9% of the world's total); the U.S. held more than 34,500 mtd (26.7% of the world's total).

Worldwide capacity in 1998 outside the U.S. and Canada was up to more than 61,000 mtd from slightly more than 54,000 in 1997.

Worldwide production of petroleum-derived sulfur increased last year to nearly 64,500 mtd, from 60,500 mtd in 1997.

Canada accounted for nearly 21,750 mtd; the U.S., for more than 15,650 mtd.