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Vol. 11, No. 44 Week of October 29, 2006
Providing coverage of Alaska and northern Canada's oil and gas industry

Coal gasification options in Alaska

DOE/SAIC studying coal gasification at Nikiski and coal to liquids at Healy; Nikiski plant looks marginally economic

Alan Bailey

Petroleum News

In the portfolio of possibilities for the development of Alaska energy resources, coal gasification has taken a prominent position in the past year.

In November 2005 Agrium announced its Blue Sky project, to use coal gasification as an alternative to natural gas to feed its fertilizer plant at Nikiski on the Kenai Peninsula — in August the company announced that it was progressing to phase two of that project. And Alaska Natural Resources-to-Liquids, with funding from the Alaska Industrial Development and Export Authority and from Chinese Petroleum Corp., is embarking on a feasibility study for a coal-to-liquids plant near the undeveloped Beluga coal field on the west side of the Cook Inlet.

Coal gasification, as envisaged at the Agrium plant, involves combining coal at very high temperatures with pure oxygen, separated from air, to produce hydrogen and carbon dioxide. The hydrogen together with nitrogen, also separated from air, would form feedstock for generating ammonia and urea in the fertilizer plant.

In a coal-to-liquids plant, the coal gasification products, known as syngas, are passed through what’s known as a Fischer-Tropsch reactor to string the syngas components into long-chain, waxy hydrocarbons. The wax is cracked into a series of shorter-chain hydrocarbons, to form syncrude. Syncrude consists predominantly of diesel fuel, kerosene and paraffin waxes.

Coal-to-liquids plants have been operating in South Africa for several decades. And in Alaska, BP’s Nikiski prototype gas-to-liquids plant uses similar technology, with natural gas rather than coal forming the feedstock for the production of the syngas.

Feasibility study

In parallel with the Agrium and Alaska Natural Resources-to-Liquids initiatives, Science International Applications Corp. has been conducting an Alaska coal gasification feasibility study for the National Energy Technology Laboratory, a part of the U.S. Department of Energy. NETL wanted to investigate the potential for operating what is known as an integrated gasification combined cycle (or IGCC) plant in conjunction with the Beluga coal field. An IGCC plant uses the products of coal gasification to generate electricity through a combination of gas and steam turbines; the IGCC technology is more efficient than a conventional coal-fired power station and produces less solid waste.

Robert Chaney, a senior analyst with SAIC, reviewed some of the findings of the DOE/SAIC feasibility study at the October meeting of the Alaska section of the American Society of Mechanical Engineers.

Chaney explained that, with a study already in progress for a coal-to-liquids plant at the Beluga coal field and Agrium moving ahead with its coal gasification proposal, the project team decided to look at some different perspectives on applying coal gasification in Alaska.

“We decided, at DOE’s request, to look at the Agrium plant as a site for a gasification system based on a combined cycle plant design — Agrium is looking at it a little bit differently,” Chaney said. “Then, in the second phase (of the study), because of these plants that are being developed here in the Cook Inlet region, we decided to look at a plant at the Usibelli coal mine in Healy.”

The Agrium plant

Chaney said that the type of coal available for the Agrium plant narrows the selection of available designs of gasification plants to two models — a Shell model and a ConocoPhillips model. Since Agrium is already investigating the feasibility of using the Shell model, the DOE/SAIC project elected to investigate the ConocoPhillips model.

And SAIC looked at electric power generation within the plant using IGCC gas and steam turbines, rather than the conventional fluidized-bed coal combustion power plant of Agrium’s preliminary design. An IGCC plant running in conjunction with the coal gasifier for the fertilizer plant would develop a total power output of about 254 megawatts. The industrial facility itself would consume about 191 megawatts of that power, Chaney said.

“We have 44 megawatts left to sell to the grid,” he said. A previous study had indicated that the Southcentral Alaska grid could, without major modification, absorb up to 70 megawatts of power from Nikiski, he said.

But, with an estimated cost of $1.6 billion for the combined coal gasification and electrical generation plant, the development of the Nikiski plant would not come cheap.

Two sources of coal

SAIC looked at two potential sources of coal for the Agrium plant — Usibelli’s Healy coal mine and the Chuitna coal project in the Beluga coal field.

The Healy coal mine has been in production for many years but the Chuitna project is still under development. Both coal fields contain very similar sub-bituminous coal with a high moisture content and very low sulfur content. Those attributes make the coal excellent for gasification, especially as the moisture would contribute to the gasification process, Chaney explained. However, a relatively short barge route between the west side of the Cook Inlet and Nikiski would favor bringing coal from Chuitna — coal from Healy would have to be barged from railroad depots in either Anchorage or Seward.

SAIC looked at the potential factory-gate price of coal from the two sources. Chaney said that both mines quoted costs at the mine in the range of $1.10 to $1.25 per million British thermal units. But after factoring in the transportation costs, Usibelli coal shipped via Seward turned out to be the most expensive, at $2.58 to $2.73 per million Btu. Coal from Chuitna might cost $1.84 to $1.99 per million Btu.

11.1 percent internal rate of return

SAIC ran an economic model for the plant, using a mid-range coal price of $35 per metric ton (approximately $2.11 per million Btu), coupled with published expected average prices for ammonia and urea. Using the estimated capital cost of the plant; an assumed annual operation and maintenance cost of 8 percent of the capital cost; and a contingency of 25 percent for cost overruns, the internal rate of return for the project came out at 11.1 percent, with a payback year (the year by which revenues would have paid for development costs) of 2023.

Those economics look feasible but marginal.

“Most investors look for something greater than 15 percent,” Chaney said.

But the rate of return is particularly sensitive to changes in the capital cost of the plant; the plant availability when in operation; and the prices of the urea and ammonia products. So, finding ways to trim that capital cost could significantly improve the viability of the project, as would finding good product prices. Negotiating a relatively low coal price would obviously also improve the project economics.

Coal gasification generates large volumes of carbon dioxide. So another way of increasing the project rate of return would be to use the carbon dioxide for enhanced oil recovery in the Cook Inlet oil fields. The study reported that more than 300 million barrels of additional oil might be recovered from the oil fields using carbon dioxide, thus adding significant value to the carbon dioxide from the gasification plant.

“Enhanced oil recovery is a well known technology — there are over 70 oil fields that have used carbon dioxide,” Chaney said, adding as an example that a coal gasification plant in North Dakota pipes carbon dioxide more than 50 miles to the Canadian Weyburn oil field for enhanced oil recovery there.

Healy coal to liquids

In the second phase of the DOE/SAIC study the SAIC analysts are investigating the feasibility of building and operating a coal-to-liquids plant at Usibelli’s coal mine near Healy. The plant would use 4 million tons per year of coal from a new section of the mine at Emma Creek to generate 14,640 barrels per day of syncrude liquids, Chaney said. The plant might also sell 42.5 megawatts of electrical power into the electricity grid.

The liquids would be shipped to Fairbanks by railroad in tank cars for distribution to Alaska refineries — the potential for refining low-sulfur diesel from the products is particularly appealing.

“The preliminary indications are that the refineries would be interested in buying this,” Chaney said.

But the project team has yet to finalize its analysis of the Healy gas-to-liquids concept.

Cook Inlet pipelines

Also in phase two of the study SAIC has been evaluating the potential to lay two pipelines under Cook Inlet to transport coal gasification products from the proposed Beluga coal-to-liquids plant to Nikiski; one pipeline would carry carbon dioxide and the other pipeline would carry a mixture of hydrogen and nitrogen. Under this concept, products from the Beluga plant, rather than a coal gasification plant at Nikiski, would form the feedstock for the Agrium fertilizer plant.

Preliminary results of this study suggest that electricity to power the massive compressors required for the pipelines would account for as much as 70 percent of the operation and maintenance costs of the system, thus making the price of electricity a critical factor in project feasibility, Chaney said.

In addition, transporting the coal gasification products under Cook Inlet would require 32-inch and 16-inch pipelines — the feasibility of laying these pipelines represents a significant unknown.

“Most of the pipelines that are in the Cook Inlet … are 10-inch or less,” Chaney said. “Just the logistics of laying them (the large-diameter pipelines) from a barge is a big deal.”



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