TECHNOLOGY
New plant will tap oil from tar sands First oil to be taken from Athabasca fields will start flowing in September 1967 Nearly 250 years ago, a Cree Indian called "The Swan" returned to a Hudson's Bay Company trading post from a trip to what is now northeastern Alberta, Canada. He brought with him a black tarry substance that oozed from the banks of a river there. If The Swan were able to visit the banks of the Athabasca River today, he would find a patch of the still peaceful countryside aswarm with 2000 construction workers laboring over a complex of tubes, tanks, and towers—building the plant that is the first large-scale attempt to tap the energy locked up in vast beds of the Athabasca tar sands. By the end of September 1967, Great Canadian Oil Sands, Ltd. (80% owned by Sun Oil, Ltd.), expects the new plant to be turning out 45,000 barrels per day of upgraded synthetic crude oil. Banking heavily on the be-
Conditioning drum
lief that it has solved the major technical and economic problems that have thwarted development of the sands over the years, GCOS will pour at least $230 million into the projectroughly half the size of Canada's financial investment in the St. Lawrence Seaway. GCOS is the first company to get pemiission from the Alberta Oil and Gas Conservation Board to build a commercial plant. With Canadian Bechtel, Ltd., as prime contractor, site preparation started in April 1964, as soon as the permit was issued, and construction was under way four months later. Waiting on the sidelines are at least two other companies eager to gamble on the great potential of the tar sands. In 1962, Shell Canada, Ltd., and Syncrude Canada, Ltd., each applied for permission to build 100,000 barrel-
Mixer
Premix tank
Thickener
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C & E N J U L Y 25, 1966
Separation cell
per-day plants. After extensive hearings the following year, the Conservation Board, wary of the effect on existing oil producers, put off a decision until 1969. Three years ago, Shell estimated its project would cost $260 million, while Syncrude (formed by Cities Service Athabasca, Imperial Oil, Ltd., Richfield Oil, and Royalite Oil, Ltd.) figured to spend $356 million. These heady figures point up the enormous importance of Alberta's tar and ultimately—perhaps sooner than some people realize—to the energy reserves of North America. The sands underlay more than 13,000 square miles, about 90% of this in the Athabasca field near Fort McMurray, at a depth of zero to 2000 feet. Total recoverable reserves, after extraction and processing, are more than 300 billion barrels—just about equal to the
COKERS. Bitumen extracted from Athabasca tar sands goes to coker drums, two of which are in background, where coke, coker gas (for a hydrogen plant), and distillate are produced. Hydrogen is used to upgrade naphtha, kerosine, and gas oil distillate fractions. One of three coker heaters is in foreground
worldwide reserves of conventional oil, 60% of which is in the Middle East. By contrast, Alberta's oil reserves from conventional sources are now 6 billion barrels. U.S. oil reserves at the end of 1965 were 39.4 billion barrels, the American Petroleum Institute estimates. Like the Athabasca deposit, the GCOS project itself is big—in some respects the biggest: • The open-pit operation will use two German-made bucket wheel excavators that stand 100 feet tall. Each one will be able to scoop out the more than 100,000 tons of ore that the plant needs each day. • The operation will move more material annually than any other mine in Canada—35 million tons of ore and 15 million tons of overburden. • The world's largest coker will pro-
duce 2900 tons per day of coke. All of this will go to fuel a power plant to generate steam and 65,000 k w ( e ) . • A hydrogen plant, using steam and coker gas, will furnish 60 million cu. ft. of hydrogen per day to the hydrotreating units. • A sulfur recovery system will make 300 long tons per day of the valuable by-product. The GCOS lease covers about 6 square miles, with overburden ranging from zero to 145 feet. The oil-sands layer averages 175 feet thick. GCOS estimates the recoverable reserves at 650 million barrels. The tar itself, about 13% of the usable sands, is quite viscous—6° to 8° API density. (Normal western Canadian crudes run from 33° to 36° API.) The tar, or bitumen, contains 4.5% sulfur and 3 8 % aromatics. The basic extraction method that
GCOS will use has been known for many years. Called the hot-water process, it was developed by the Alberta Research Council, specifically by Dr. Karl A. Clark, who started his pioneering research on the tar sands in 1922 and who is now a consultant to GCOS. The company operated a pilot plant from August 1963 to November 1965 to study the effects of some 200 parameters on extraction efficiency, the crucial phase as far as plant economics are concerned. High-speed conveyers take the sands from the pit to the initial extraction building, where the ore is mixed with steam and hot water in rotary drums similar to cement kilns. The thick, black slurry, called pulp, goes to water-filled separation vats, where the sand settles and the bitumen floats as a froth. The froth is taken to the final extraction plant, diluted with naphtha, and centrifuged to remove more water and most of the residual sand. The bitumen-naphtha solution goes then to storage tanks, which can hold a four- to five-day supply. This acts as a buffer between the extraction and process area, which must operate continuously. Naphtha distilled. In the process area, the naphtha is distilled off, and the bitumen is heated and sent to the coker drums, which produce coke, coker gas (for the hydrogen plant), and a distillate. The latter is fractionated to yield naphtha, kerosine, and gas oil. These are fed to individual Unifiners, where they are treated with hydrogen over a UOP moly catalyst. The hydrotreatment removes sulfur (as hydrogen sulfide for the recovery units) and nitrogen and partially saturates the aromatic fractions of the kerosine and gas oil. The fractions are stored separately, then combined as they enter the pipeline to form a light, high-quality synthetic crude, 40° to 42° API. A 16inch pipeline that GCOS is building will take the crude the 266 miles to Edmonton, where it will join trunk pipelines. Sun Oil has contracted for 75% of the output, and Shell Canada the remainder. Syncrude, if and when it builds its proposed plant, will also use a modified hot-water process. The extraction is similar to the GCOS method to a point, but the effluent water and sand from the separation vats gets secondary recovery treatment like the primary one. The second stage increases oil recovery by about 14%, the company says. Syncrude, too, will have an open-pit operation using large bucket-wheel excavators. Only about 16% of the Athabasca oil-sands deposit (yielding some 50 billion barrels of synthetic crude) are close enough to the surface for openJULY 25, 1966 C&EN 47
DEVELOPMENT PRODUCT FROM SHELL C H E M I C A L
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Trimethylene Glycol ( 1 , 3-propanediol)
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ERSATILE
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Colorless mobile liquid
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Purity
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Immiscible
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C & E N JULY 25, 1966
pit mining. More exotic methods must be found if Athabasca is to realize its full potential. In its 1963 proposal to the Alberta Conservation Board, Shell Canada described an in situ extraction it planned to use. Shell's steam and chemical drive method would make the oil flow without moving the sand. Injection and production wells are drilled in regular patterns, and fractures are produced between the injectors and producers. Steam and "critically prepared" solutions of sodium hydroxide are injected into the fractures, the bitumen is heated and is driven to the producer wells as an oil-in-water emulsion. Based on Shell's extensive field tests (1958-62), the company told the board that 1580 wells, 900 of them production wells, would be necessary to produce 130,000 barrels per day of bitumen. The lease Shell might develop first (one of four) covers 77 square miles and holds reserves of 4.4 billion barrels, excluding sands with less than 6r/c bitumen. There are 840 feet of overburden. Another proposal for developing the deep sands excited a great deal of interest when it was put forth in 1958, made great progress through various government agencies in 1959, ran head-on into high-level government policy, and hasn't yet regained consciousness. Richfield Oil, Imperial Oil, Ltd., and Cities Service Athabasca suggested setting off a 9-kiloton nuclear blast 1250 feet below the surface—and about 20 feet below the oil sands—in a remote, undeveloped area 64 miles south of Fort McMurray. The explosion would create a 230-foot cavity into which millions of cubic feet of oil sands would fall and be heated. Conventional oil-field methods would recover the oil. Test prevented. Whether or not the method would work is anybody's guess, but the companies were willing to foot the $1 million cost of the experiment. The U.S. Atomic Energy Commission, an Alberta technical committee, and a group set up by the Canadian government were for the idea. Unfortunately, the worldwide furor over nuclear testing, the moratorium, and the extreme distaste of the Diefenbaker regime for all things nuclear have thus far combined to prevent the test. A scientist once associated with the project believes that the climate changed with the change of government in Canada and that the test may be considered anew. There is, however, no confirmation of this from the government or the companies involved. Although no one doubts that advancing technology will soon open the
FOUNDATIONS. A tent inflated by air protects the working area where foundations for the final tar sands extraction plant were being poured by Canadian Bechtel during the cold Alberta winter
bulk of Alberta's oil sands to commercial development, the matter of timing is a dilemma to the Alberta Oil and Gas Conservation Board. First, it feels it must protect the conventional oil industry. Since the discovery of oil at Leduc in 1947, companies have invested $6.5 billion in the province. Oil production is prorationed to demand, as far as the North American market is concerned. During the first half of 1966, demand has averaged 523,000 barrels per day, about half of Alberta's capacity. While it is possible to throttle down production of oil wells, the oil-sands plants are more akin to chemical plants. Cutting production below the design capacity can send a company deeply into the red. Even the 45,000 barrel-per-day plant that GCOS is building may operate on the margin between profit and loss. From the looks of it, though, that company is getting in far ahead of anyone else and will gain much valuable experience. Present Alberta policy is to limit production from oil sands to 5 % of the province's production. Even the GCOS plant will ex-
ceed this, so it may be a long time before the plans of Shell and Syncrude get the go-ahead. There is a ray of hope, though, A. R. Patrick, Alberta's Minister of Mines and Minerals, says that discussions will soon start with Japan on possible oil sales to that country. If a substantial deal results, the international market, not subject to prorationing, could change the picture. . Another reason for Alberta's goslow policy is that the province doesn't want to discourage exploration for new oil and gas reserves. Why bother? Aren't there more than 300 billion barrels available in the sands? The answer is simple: The Alberta government last year received nearly $120 million from the sale of Crown leases and licenses. Oil and gas royalties to the province in 1965 totaled about $68 million. Oil threatened. F. K. Spragins, president of Syncrude» warns against a head-in-the-sand attitude. Other energy sources could replace Athabasca oil and hold back major development for many years. He points to the high volume of research in the U.S. on coal hydrogénation and oil shale as the major threats. The present U.S. rate of production, Mr. Spragins notes, is about 8 million barrels per day. By the early 70's, U.S. production from conventional sources will fall short of demand by about 2 million barrels per day. He also foresees Canada's growing markets consuming the country's total production, leaving none for export. Thus, he concludes, the future of North American oil for the long term must come from oil sands, oil shale, or imports. Because it could take four to eight years to build and optimize a large oil-sands plant, Mr. Spragins deplores "the current low level of tar-sands activity." Once oil shales become entrenched in the market, it may be difficult for Canada to break into the petroleum market with any sizable production. Mr. Spragins might take solace from the fact that U.S. federal bureaus, too, often move with all the vigor of a snail. The U.S. docs indeed sit on a treasure trove of its own—a possible total of 2 trillion barrels from oil shales. The Federal Government, however, owns nearly 80v^ of the oil-shale lands s which have been withdrawn from development since 1930. Even so, the Department of the Interior may use up another 10 years before formulating a policy on development of the oil shales. Whatever the pros and cons, the oil sands are at last on their way. How far and how fast are problems Alberta will have to decide soon.
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