Natural gas has been used almost as long as crude oil in Canada, but its commercial development was not as rapid. This is because of special properties of this energy commodity: it is a gas, and it frequently contains impurities. The technical challenges involved to first process and then pipe it to market are therefore considerable. Furthermore, the costs of pipeline building make the whole enterprise capital intensive, requiring both money and engineering expertise, and large enough markets to make the business profitable.
Until it became commercially viable, natural gas was often a nuisance. Dangerous to handle and hard to get to market, early oilmen despised it as a poor relation to its rich cousin crude oil. Although early processing procedures were able to remove water, in the 19th century discoveries were only developed if consumers could use the gas just as it came out of the ground. If the gas required further processing or needed to be piped a long distance to market, the producer shut in the well. Flares got rid of gas coming from oil wells.
Natural gas processing changes the commodity in two critical ways. First, it extracts valuable by-products; second, it renders natural gas fit to be transported to a point for commercial sale and consumption. Through the use of evolving technology, the gas processing industry of each era extracts higher percentages of a wider range of hydrocarbons and other commercial by-products than its predecessors. It also removes ever-higher percentages of dangerous and other unwanted impurities. Steady growth has made natural gas a major industry, with 180 cubic kilometres of gas flowing from Canadian fields to market, every year.
Part of a series on Canada's petroleum industry, this entry focuses on the second of these two functions of gas processing - removing impurities from the gas stream - rather than recovering natural gas liquids, described elsewhere. Of course, most large plants perform both functions, and plants have no other ultimate purpose than to quickly, safely and profitably turn raw gas into products to be safely shipped (mostly by pipeline) to market. The discussion covers gas processing as an engineering feat, critical developments in exploration and development and the fundamentals of the marketplace.
Early times A small natural gas industry in Central Canada had already been around for several decades, but the most significant event in the industry's early history was probably the drilling of a well near Medicine Hat in 1890, in search of coal for the railway. The well encountered a large flow of natural gas, and this prompted town officials to approach the Canadian Pacific Railway with a view to drilling deeper for gas. The resulting enterprise led to the development of the Medicine Hat gas field in 1904. The community took advantage of the natural resource and became the first town or city in western Canada with a gas utility.
Natural gas service began in Calgary somewhat later, when A.W. Dingman formed the Calgary Natural Gas Company. He drilled a successful well in east Calgary, laid pipe to the Calgary Brewing and Malting Company site and began providing gas to the brewery on April 10, 1910. As in Medicine Hat, gas mains soon provided domestic fuel and street lighting.
In a parallel development Eugene Coste, who had been a pioneer in the development of Ontario's natural gas industry, moved west. He drilled the locally famous Old Glory gas well near Bow Island, Alberta, in 1909. In 1912, his Canadian Western Natural Gas Company built a 280-kilometre pipeline connecting the Bow Island field to Lethbridge and Calgary in 86 days. It augmented the Dingman enterprise in Calgary, which was unable to supply the growing demands of the city. By 1913, several other towns in southern Alberta boasted natural gas service from the Canadian Western system. Coste's pioneering enterprise provided fuel to nearly 7,000 customers.
Canada's first sweetening plant Sour gas, as it is known, in its natural state is laced with hydrogen sulfide (H2S), which can be lethal if inhaled in even tiny concentrations. (The more general term acid gas refers to natural gas with any acidic gas in it - carbon dioxide (CO2), for example.)
The process of taking hydrogen sulphide out of a gas stream is called "sweetening" the gas. The Union Natural Gas Company of Canada (now Union Gas Ltd.) of Chatham-Kent, Ontario built Canada's first Koppers process sweetening plant in 1924 at Port Alma, Ontario, to scrub Tillbury gas. Hydrogen sulphide is a dangerous substance which at low concentrations has an obnoxious rotten egg smell. This odour annoyed Union's customers and prompted it to build the Port Alma plant. It removed hydrogen sulphide by exposing the sour gas to dissolved soda ash. Although previously used on coal gas, the application at the Port Alma plant was the first time this process sweetened natural gas.
The second Canadian sweetening plant followed a year later in Turner Valley, and used the same process. The first gas found at Turner Valley had been sweet but the Royalite #4 discovery of 1924, from a deeper horizon, was sour. Royalite built the Turner Valley sweetening plant in order to sell its gas to Canadian Western Natural Gas for distribution.
The technology of the day did not render the hydrogen sulphide harmless. Instead, the producer disposed of the substance by burning it and dispersing the by-products into the air from two tall stacks. One chemical result of burning hydrogen sulphide emissions was sulfur dioxide, another toxic gas. Since hydrogen sulphide is heavier than air, it settled to the ground, dispersed enough to be less than lethal.
Hydrogen sulphide was always in the air in small concentrations. Turner Valley had a rotten egg odour on most days.
Gas conservation after Leduc As Alberta became an ever-larger oil producer after the Leduc discovery, the Conservation Board acted to prevent any repetition of the natural gas waste so common in Turner Valley. The board developed a broad conservation policy for natural gas. It prohibited producing natural gas from an oil reservoir's gas cap before the oil was fully produced, and included provisions aimed at conserving the natural gas often produced along with the oil. For this reason, these plants became known as "gas conservation plants."
The first of these new plants was Imperial's Leduc facility (sometimes called Imperial Devon or Imperial Leduc). It sweetened the gas with monoethanolamine (MEA), then extracted the liquid hydrocarbons by refrigeration. Northwestern Utilities Limited bought the gas at $14.12 per thousand cubic metres and distributed it in Edmonton. Trucks transported the propane, butane and "pentanes plus" (the Canadian term for heavier gas liquids) until 1954, when three pipelines began moving the products from Imperial Leduc to Edmonton. When markets could not be found for the propane, the board occasionally granted permission to flare it.
The next important plant built in Canada resulted from the discovery in 1944 of a wet sour gas find by Shell Oil at Jumping Pound, west of Calgary. Calgary, Exshaw (where there was a cement factory) and Banff were all potential markets for Jumping Pound gas, but the sour gas first required processing and sweetening. The gas plant began operating in 1951.
Built "California-style," with few buildings or other provisions for a cold climate, the original Jumping Pound plant ran into problems. During the first winter, water condensation and other cold weather problems led to one operational failure after another. When the second winter arrived, buildings sheltered most of the facilities. Shell Jumping Pound is sometimes referred to as Canada's "sour gas laboratory," for much of the industry's early understanding of sour gas processing came from experience there. It was the first sulphur plant in the world, its sulphur unit going into production in 1952. For this distinction it narrowly beat out the Madison Natural Gas plant which began extracting sulphur at Turner Valley later the same year.
As the Westcoast and TransCanada natural gas pipelines went into operation in 1957, a new and better day dawned for Canadian gas processing. Most of the gas that travelled those pipelines needed processing to meet the specifications of pipeline companies. Consequently, the late 1950s and early 1960s saw a boom in gas plant construction.
In 1957, a new gas plant at Taylor, near Fort St. John, British Columbia, began supplying Westcoast Transmission Co. Ltd. This plant's practices differed from those used in Alberta in a number of ways. For example, although it generally required dehydration, sweetening and processing for liquid hydrocarbons, companies transported the natural gas from northeastern British Columbia long distances before processing it further. Consequently, while planning the Westcoast pipeline, the field operators agreed to process all the gas at a single facility, rather than have individual gas plants in every major production area. At 10 million cubic metres per day, the Taylor plant had the capacity to process as much natural gas as all eleven of the other gas plants operating in Canada combined. The plant was also by far Canada's most northerly. Heavily insulated buildings protected the processing facilities and allowed them to function at temperatures typical of more southerly climes.
Schemata of a gas plant
Selling the products The enormous growth in Canadian processing capacity in the late 1950s and early 1960s created large inventories of natural gas liquids, liquefied petroleum gases and sulfur. Growing supplies sometimes created marketing problems.
Natural gas liquids Sales of gas liquids were seldom difficult because of their ready use in oil refining. Refiners also used butane for blending. Propane, on the other hand, presented a challenge because the volumes available greatly exceeded demand.
Companies set out to widen the market with considerable success. Farmers and small communities not served by natural gas adopted it for home heating fuel. In the early 1960s, markets for liquid petroleum gases grew rapidly.
Companies responded by building "straddle" plants. These facilities straddled gas pipelines to extract additional volumes of gas liquids from the gas stream. Where economic, field processors began "deep cutting" their own gas by installing facilities that culled more LPG from the gas through deep refrigeration. In the early 1970s, companies began extracting the even lighter hydrocarbon ethane at some field processing and straddle plants. Ethane became a feedstock for Alberta's growing petrochemical industry, used in the manufacture of ethylene.
Sulphur From a slow start in 1952, sulphur production from gas processing snowballed as plant construction boomed in the late 1950s and early 1960s. Tough new regulations enacted by the Alberta government in 1960 forced the industry to reduce its emissions of such sulphur compounds as sulfur dioxide and hydrogen sulphide.
Over the years, sour gas processing technology steadily improved. By 1970, more stringent emission standards were technically feasible. The Alberta government announced new, tougher regulations in 1971. Improvements in sulphur extraction technology and the addition of tail gas clean-up units enabled processors to meet these stricter standards.