History of the petroleum industry in Canada (natural gas)
Dangerous to handle and hard to get to market, early oilmen despised it as a poor relation to its rich cousin crude oil.
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.
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.
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.
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.
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.
Built "California-style," with few buildings or other provisions for a cold climate, the original Jumping Pound plant ran into problems.
For this distinction it narrowly beat out the Madison Natural Gas plant which began extracting sulphur at Turner Valley later the same year.
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.
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.
Improvements in sulphur extraction technology and the addition of tail gas clean-up units enabled processors to meet these stricter standards.
Looking at the large, sophisticated, high-tech enterprise that Canadian gas processing is today, it is hard to imagine the challenges the industry faced as it grew up.
The perceived problem of large gas inventories overhanging the market and keeping down prices did not begin to disappear until the late 1990s.
Crude oil prices dropped throughout the 1980s and natural gas supplies remained abundant, so consumers began taking advantage of the twin surpluses.
Suppliers across the continent began looking for new customers to make up in volume sales what they were unable to earn from low gas prices.
As deregulation put an end to vertically integrated gas delivery and marketing, consuming regions began crying for additional pipeline capacity.
In Alberta, half a continent away from America's east coast and from the San Francisco Bay, cheap gas awaited.
Competition among operators moving the gas to market - not government regulation - was supposed to keep transmission costs reasonable in the new milieu.
As coal, hydroelectric and nuclear-powered generation facilities came under attack for environmental reasons, gas stepped in and sold itself as a clean alternative.
Much of the public outrage occurred because, on some days, the rotten-egg odour of hydrogen sulfide (H2S) in the gas could be smelled as far away as Winnipeg, nearly 1,500 kilometres distant.
[citation needed] When the crew ignited the well, the fire destroyed the Nabors 14E rig (worth about $8 million) in nine minutes; it also scorched 1.6 km2 (400 acres) of forest.
Later in the decade, many large companies began reviewing their existing land holdings, looking for discoveries that had eluded earlier exploration.
The competing corporations were required to respond to these concerns, so the Caroline experience made public consultation an integral part of planning.
In early 2000, as Murphy Oil, Apache (now APA Corporation), and Beau Canada announced their discovery of the Ladyfern Slave Point gas field in a remote area of Northeastern British Columbia, their achievement seemed to herald a new era of successful wildcat exploration.
In little more than a year, production from the new fields rose to more than 700 million cubic feet (20,000,000 m3) per day - and this from an area only accessible during the cold winter months.
It comes from five major sources: In 1985, unconventional gas production received a boost when the United States introduced incentives to encourage the development of energy alternatives.
Developing these resources can have substantial impacts on the environment through closer well spacing, more intensive infrastructure, additional noise from compression, the challenges of water disposal, NIMBY issues, and other factors.
After all, those with an interest in a single land use decision could include petroleum producers, Aboriginal communities, landowners, farmers, ranchers, loggers, trappers, campers, sports and environmental groups, and others.
