History of the petroleum industry in Canada
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The Canadian petroleum industry arose in parallel with that of the United States, but developed in quite a different way. Canada's unique geography, geology, resources and patterns of settlement have been key factors in the history of Canada. The development of the petroleum sector helps illustrate how they have helped make the nation quite distinct from her neighbour to the south.
Although the conventional oil and gas industry in western Canada is mature, the country's Arctic and offshore petroleum resources are mostly in early stages of exploration and development. Canada became a natural gas-producing giant in the late 1950s and is second, after Russia, in exports; the country also is home to the world's largest natural gas liquids extraction facilities. The industry started constructing vast networks of pipelines in the 1950s, thus beginning to develop domestic and international markets in a big way.
Despite billions of dollars of investment, her bitumen - especially within the Athabasca oil sands - is still only a partially exploited resource. By 2025 this and other non-conventional oil resources - the northern and offshore frontiers and heavy crude oil resources in the West - could place Canada in the top ranks among the world's oil producing and exporting nations. In a 2004 reassessment of global resources, America's EIA put Canadian oil reserves second; only Saudi Arabia has greater potential. However, many oil experts argue that Saudi potential is highly limited, so Canada could well be number one.
Many of the stories surrounding the petroleum industry's early development are colourful. The developing oilpatch involved rugged adventurers, the occasional fraud, important innovations and, in the end, world-class success. Canadian petroleum production is now a vital part of the national economy and an essential element of world supply.
[edit] Early Origins
The early uses of petroleum go back thousands of years. But while people have known about and used petroleum for centuries, Charles Nelson Tripp was the first Canadian to recover the substance for commercial use. The year was 1851; the place, Eniskillen Township on the north shore of Lake Erie. It was there that Tripp started dabbling in the mysterious gum beds near Black Creek. This led to incorporation of the first oil company in Canada.
Parliament chartered the International Mining and Manufacturing Company, with C.N. Tripp as president, on December 18, 1854. The charter empowered the company to explore for asphalt beds and oil and salt springs, and to manufacture oils, naphtha paints, burning fluids, varnishes and other such products.
International Mining and Manufacturing was not a financial success, but Tripp’s asphalt received an honourable mention for excellence at the Paris Universal Exhibition in 1855. Several factors contributed to the downfall of the operation. Lack of roads in the area made the movement of machinery and equipment to the site extremely difficult. And after every heavy rain the area turned into a swamp and the gum beds made drainage extremely slow. This added to the difficulty of distributing finished products.
When James Miller Williams became interested and visited the site in 1856, Tripp unloaded his hopes, his dreams and the properties of his company, saving for himself a spot on the payroll as landman. The former carriage builder formed J.M. Williams & Company in 1857 to develop the Tripp properties. Besides asphalt, he began producing kerosene.
[edit] A North American first
Stagnant, algae-ridden surface water lay almost everywhere. To secure better drinking water, Williams dug a well a few yards down an incline from his plant. At a depth of 20 metres the well struck free oil. It became the first oil well in North America, remembered as the Williams No. 1 well at Oil Springs, Ontario.
Some historians challenge Canada’s claim to North America’s first oil field, arguing that Pennsylvania’s famous Drake well was the continent’s first. But there is enough evidence to support Williams, not least of which is that the Drake well did not come into production until August 28, 1859. The controversial point might be that Williams found oil above bedrock while “Colonel” Edwin Drake’s well located oil within a bedrock reservoir.
We do not know exactly when Williams abandoned his Oil Springs refinery and transferred his operations to Hamilton. He was certainly operating there by 1860 however. Spectator advertisements offered coal oil for sale at 16 cents per gallon for quantities from 4,000 to 100,000 gallons.
Williams reincorporated there as The Canadian Oil Company (perhaps provisionally as the Canada Rock Oil Company). His company produced oil, refined it and marketed refined products. That mix of operations qualify Canadian Oil as the world’s first integrated oil company.
Exploration in the Lambton county backwoods quickened with the first flowing well in 1860: Previous wells had relied on hand pumps. The first gusher blew in on February 19, 1862 when Hugh Nixon Shaw struck oil at 48 metres. For a week the oil gushed unchecked, eventually coating the distant waters of Lake St. Clair with a black film.
Dr. A. Winchell, in his Sketches of Creation, refers to this oil gusher (though not very accurately) in the following passage.
Though Western Pennsylvania has produced many flowing wells of wonderful capacity, there is no quarter of the world where production has attained such prodigious dimensions as in 1862 upon Oil Creek (Black Creek?) in the Township of Eniskillen, Ontario. The first flowing well was struck there January 11, 1862, and before October not less than 35 wells had commenced to drain a storehouse which provident nature had occupied untold thousands of years in filling for the uses of man. The price had fallen to ten cents a barrel, three years later that oil would have brought ten dollars a barrel in gold. From detailed determinations I have ascertained that during the spring and summer of 1862, no less than five million barrels of oil floated off upon the waters of Black Creek.
Following William’s example, practically every producer in the infancy of the oil business became his own refiner. Seven refineries were operating in Petrolia, Ontario in 1864 and 20 in Oil Springs. Together, they processed about 80 cubic metres of oil per day.
In 1865 oil was selling for $70 per cubic metre ($11.13 per barrel). But the fields of Ontario delivered too much too quickly, and by 1867 the price had dropped to $3.15 per cubic metre ($0.50 per barrel). By 1870, Oil Springs and Bothwell were both dead fields, but other booms followed as drillers tapped deeper formations and new fields.
Although the industry had a promising start in the east, Ontario’s status as an important oil producer did not last long. Canada became a net importer of oil during the 1880s. Dependence on neighbouring Ohio as a crude oil supplier increased after the automobile rolled into Canada in 1898.
[edit] Canadian drillers
Canadians developed petroleum expertise in those early days. The Canadian “oil man” or driller became valued the world over.
Petrolia drillers developed the Canadian pole-tool method of drilling which was especially useful in new fields where rock formations were a matter for conjecture. The Canadian technique was different from the American cable-tool method. Now obsolete, cable-tool drilling uses drilling tools suspended from a cable which the driller paid out as the well deepened.
Canada’s pole-tool rig used rods or poles linked together, with a drilling bit fixed to the end of this primitive drilling “string.” Black-ash rods were the norm in early Petrolia. Iron rods came later. Like the cable tool system, pole-tool drilling used the weight of the drill string pounding into the ground from a wooden derrick to make hole.
The record is not complete enough to show all the locations Canadians helped to drill. However, Petrolia drillers unquestionably helped drill for oil in Java, Peru, Turkey, Egypt, Russia, Venezuela, Persia, Rumania, Austria and Germany. One of the best known Canadian drilling pioneers was William McGarvey. McGarvey acquired oil properties in Galicia (now part of Poland) and amassed a large fortune - then saw his properties destroyed when Russian and Austrian armies swept across the land during the First World War.
Today, Canadian drillers still move to far away places to practice their widely respected skills.
[edit] Early eastern natural gas
The natural gas industry was also born in eastern Canada. Reports from around 1820 tell of youngsters at Lake Ainslie, Nova Scotia, amusing themselves by driving sticks into the ground, pulling them out, then lighting the escaping natural gas.
In 1859 an oil explorer found a natural gas seep near Moncton, New Brunswick. Dr. H.C. Tweedle found both oil and gas in what became the Dover field, but water seepage prevented production of these wells.
An offshoot of the oil drilling boom was the discovery of gas containing poisonous hydrogen sulphide (“sour” gas) near Port Colborne, Ontario. That 1866 discovery marked the first of many gas fields found later in the southwestern part of the province.
Eugene Coste, a young Paris-educated geologist who became the father of Canada’s natural gas industry, brought in the first producing gas well in Essex County, Ontario, in 1889. Canada first exported natural gas in 1891 from the Bertie-Humberstone field in Welland County to Buffalo, New York. Gas was later exported to Detroit from the Essex field through a 20-centimetre pipeline under the Detroit river. In 1897, the pipeline stretched the Essex gas supply to its limit with the extension of exports to Toledo, Ohio. This prompted the Ontario government to revoke the licence for the pipeline. And in 1907 the province passed a law prohibiting the export of natural gas and electricity.
In 1909, New Brunswick’s first successful gas well came in at Stoney Creek near Moncton. This field still supplies customers in Moncton, although the city now has a propane air plant to augment the limited natural gas supply.
The year 1911 saw a milestone for the natural gas industry when three companies using Ontario’s Tilbury gas field joined to form Union Gas Company of Canada, Limited. In 1924, Union Gas was the first company to use the new Seabord or Koppers process to remove poisonous hydrogen sulphide from Tilbury gas. Union became one of the largest corporations in Canada before its acquisition by Duke Energy, a US firm.
[edit] The move west
These were the early days in Canada’s petroleum industry. The cradle was in eastern Canada, but the industry only began to come of age with discoveries in western Canada, notably Alberta. There, the Western Canadian Sedimentary Basin is at its most prolific.
Alberta’s first recorded natural gas find came in 1883 from a well at CPR Siding No. 8 at Langevin, near Medicine Hat. This well was one of a series drilled at scattered points along the railway to get water for the Canadian Pacific Railroad’s steam-driven locomotives. The unexpected gas flow caught fire and destroyed the drilling rig.
This find prompted Dr. George M. Dawson of the Geological Survey of Canada to make a notable prediction. Noting that the rock formations penetrated in this well were common in western Canada, he prophesied correctly that the territory would some day produce large volumes of natural gas.
A well drilled near Medicine Hat in 1890 - this time in search of coal - also flowed natural gas. The find prompted town officials to approach the CPR with a view to drilling deeper wells for gas. The resulting enterprise led to the discovery in 1904 of the Medicine Hat gas sand. Later, that field went on production to serve the city, the first in Alberta to have gas service. When Rudyard Kipling travelled across Canada in 1907, he remarked that Medicine Hat had “all Hell for a basement.”
In northern Alberta, the Dominion Government began a drilling program to help define the region’s resources. Using a rig brought from Toronto, in 1893 contractor A.W. Fraser began drilling for liquid oil at Athabasca. He abandoned the well in 1894.
In 1897 Fraser moved the rig to Pelican Rapids, also in northern Alberta. There it struck gas at 250 metres. But the well blew wild, flowing uncontrolled for 21 years. It was not until 1918 that a crew led by A.W. Dingman succeeded in killing the well.
Dingman, who played an important role in the industry’s early years, began providing natural gas service in Calgary through the Calgary Natural Gas Company. After receiving the franchise in 1908, he drilled a successful well in east Calgary on the Walker estate (a well which continued producing until 1948). He then laid pipe from the well to the Calgary Brewing and Malting Company, which began using the gas on April 10, 1910. Later mains provided the city with domestic fuel and street lighting.
[edit] Oil in the Alberta foothills
The earliest efforts to develop western Canadian oil were those of John George (Kootenai) Brown. This colourful character - a frontiersman with an Eton and Oxford education - was probably Alberta’s first homesteader. In 1874, Brown filed the following affidavit with Donald Thompson, the resident solicitor at Pincher Creek:
I was engaged as a guide and packer by the eminent geologist Dr. George M. Dawson, and he asked me if I had seen oil seepages in that area, and if I did see them, would I be able to recognize them. He then went into a learned discussion on the subject of petroleum. Subsequently some Stoney Indians came to my camp and I mixed up some molasses and coal oil and gave it to them to drink, and told them if they found anything that tasted or smelled like that to let me know. Sometime afterwards they came back and told me about the seepages at Cameron Brook.
In 1901, John Lineham of Okotoks organized the Rocky Mountain Drilling Company. In 1902 he drilled the first oil exploration well in Alberta on the site of these seepages (now in Waterton Lakes National Park). Despite a small recovery of 34? API sweet oil, neither this well nor seven later exploration attempts resulted in production.
In 1909, exploration activity shifted to Bow Island in south central Alberta, where a natural gas discovery launched Canada’s western gas industry. The same Eugene Coste who had found gas in Ohio and again in southern Ontario drilled the discovery well, Bow Island No. 1 (better known as “Old Glory”). Pipelines soon tsported Bow Island gas to Medicine Hat, Lethbridge and Calgary, which used the fuel for heat and light. Eugene Coste became the founder of the Canadian Western Natural Gas Company when he merged the Calgary Natural Gas Company, Calgary Gas Company and his Prairie Fuel Company in August 1911.
In early 1914, oil fever swept Calgary and other parts of southern Alberta. Investors lined up outside makeshift brokerage houses to get in on exploration activity triggered by the 1914 discovery of wet gas and oil at Turner Valley, southwest of Calgary. So great was the excitement that, in one 24-hour period, investors and promoters formed more than 500 “oil companies.” Incorporated a year earlier, the Calgary Stock Exchange was unable to control some of the unscrupulous practices that relieved many Albertans of their savings.
The discovery well that set off this speculative flurry belonged to the Calgary Petroleum Products Company, an enterprise formed by W.S. Herron, William Elder and A.W. Dingman. Named Dingman No. 1 after the partner in charge of drilling, the well produced natural gas dripping with gas liquids, sometimes referred to as naphtha. Stripped from the gas, these liquids were pure enough to burn in automobiles without refining. The mix became fondly known as “skunk” gasoline because of its distinctive odour.
The Dingman well and its successors were really “wet” natural gas wells rather than true oil wells. The high expectations raised by the initial discovery gave way to disappointment within a few years. Relatively small volumes of liquids flowed from the successful wells. By 1917, the Calgary City Directory listed only 21 “oil mining companies” compared with 226 in 1914.
Drilling continued in Turner Valley, however, and in 1924 came another significant discovery. The Calgary Petroleum Products Company, reorganized as Royalite Oil Company, drilled into Paleozoic limestone. The well blew out at 1,180 metres.
The blowout at Royalite No. 4 was probably the most spectacular in Alberta’s history. Initially flowing at 200,000 cubic metres per day, the flow rate increased to some 620,000 cubic metres per day when the well was shut in. The shut in pressure continued to rise and, when the gauge read 7,930 kilopascals, the drillers ran for their lives. In 20 minutes, 939 metres of 21-centimetre and 1,052 metres of 16-centimetre pipe - together weighing 85 tonnes - rose to the top of the derrick. The well blew wild, caught fire, and destroyed the entire rig. The fire blazed for 21 days. Finally, wild well control experts from Oklahoma used a dynamite explosion to blow away the flames. They then applied the combined steam flow of seven boilers to keep the torch from lighting again.
Unknown to the explorers of the day, these wells extracted naphtha from the natural gas cap over Turner Valley’s oilfield. After two years of off-and-on drilling, in 1936 the Royalites No. 1 well finally drilled into the principal oil reservoir at more than 2,500 metres.
This well, which established Turner Valley as Canada’s first major oil field and the largest in the British Commonwealth, used innovative financing. Promoters ordinarily sold shares in a company to finance new drilling programs, but in the Depression money for shares was hard to come by. Instead, R.A. Brown, George M. Bell and J.W. Moyer put together an enterprise called Turner Valley Royalties. That company offered a percentage share of production (a “royalty”) to those willing to put money into the long-shot venture.
Recoverable oil reserves from the Turner Valley field were probably about 19 million cubic metres. Although locals boasted at the time that it was "the biggest oil field in the British Empire," Turner Valley was not a large field by later standards. (By way of comparison, the Pembina field in central Alberta - Canada’s largest - had recoverable reserves of about 100 million cubic metres.) But besides being an important source of oil supply for the then-small market in western Canada, the field had an important long-term impact. It helped develop petroleum expertise in Canada's west, and it established Calgary as Canada’s oil and gas capital.
[edit] Waste and conservation
Enormous waste of natural gas was a dubious distinction that Turner Valley claimed for many years. Royalite had a monopoly on sales to Canadian Western Natural Gas Company, so other producers could not sell their gas. But all the producers wanted to cash in on the natural gas liquids for which markets were growing. So the common practice became to pass the gas through separators, then flare it off. This had greatly reduced the pressure on the oil reservoir, reducing the amount of recoverable oil. But the size of the problem was not clear until the oil column was later discovered.
The flares were visible in the sky for miles around. Many of these were in a small ravine known to locals as Hell’s Half Acre. Because of the presence of the flares, the grass stayed green year-round and migrating birds wintered in their warmth. A newspaper man from Manchester, England, described the place with these florid words:
... Seeing it you can imagine what Dante’s inferno is like ... a rushing torrent of flame, shooting 40 feet high ... a ruddy glow to be seen for 50 miles ... most awe-inspiring spectacle ... men have seen the hosts of hell rising ... the titanic monster glowering from the depths of Hades ...
While the flaring continued, the business community seriously discussed ways to market the gas. For example, in early 1929 W.S. Herron, a Turner Valley pioneer, publicly promoted the idea of a pipeline to Winnipeg. At about the same time, an American company made application for a franchise to distribute natural gas to Regina. The Bank of North Dakota offered to buy 1.4 million cubic metres per day.
By early 1930, there was talk of a pipeline from Turner Valley to Toronto. Estimates showed that gas delivery to Toronto would cost $2.48 per thousand cubic metres.
A parliamentary committee looked into ways to force waste gas down old wells, set up carbon black plants or export the gas to the United States. Another proposal called for the production of liquefied methane.
Unfortunately, the Depression had already gripped Canada, which might have been more severely affected by this economic catastrophe than any other country in the world. Capital investment became less and less attractive and drilling at Turner Valley ground to a halt as the economic situation worsened.
The federal government owned the mineral rights not held by the Canadian Pacific Railway, the Calgary & Edmonton Corporation and by individual homesteads. The government tried to curb the flaring of gas, but legal difficulties made its efforts of little avail. One federal conservation measure succeeded, however. On August 4, 1930 began operations to store surplus Turner Valley gas in the depleted Bow Island field.
An earlier effort to control waste resulted in an Order-in-Council passed April 26, 1922 prohibiting offset drilling closer than 70 metres from any lease boundary. Keeping wells spaced away from each other, as this regulation did, prevents too rapid depletion of a field.
After a bitter appeal to Britain’s Privy Council, the federal government transferred ownership of natural resources to the provinces effective October 1, 1930. Soon after, the Alberta government enacted legislation to regulate oil and gas wells. In October 1931, the Legislature passed legislation (based on a report by a provincial advisory committee) to control the Turner Valley situation. While most operators supported this act, one independent operator successfully launched legal proceedings to have the Alberta act declared ultra vires. The provincial government asked the federal government to pass legislation confirming the Alberta law. Ottawa, however, shrugged off the request saying that natural resources were under provincial jurisdiction
During 1932, the newly created Turner Valley Gas Conservation Board proposed cutting production in half and unitizing the field to reduce waste. But the producers could not reach agreement on this issue, and the idea fell by the wayside. And so legal wrangling tied up any real conservation measures until 1938. In that year, the federal government confirmed the province’s right to enact laws to conserve natural resources.
With this backing, in July 1938 the province set up the Alberta Petroleum and Natural Gas Conservation Board (today known as the Alberta Energy and Utility Board). New unitization rules limited well spacing to about 16 hectares per well. The board also reduced oil production from the field. This reduced the flaring of natural gas, but it came only after the waste of an estimated 28 billion cubic metres. The lessons of Turner Valley made an impression around the world as the need for conservation and its impact on ultimate recovery became better understood. Countries framing their first petroleum laws have often used the Alberta legislation as a model.
Besides contributing to conservation, solving Turner Valley’s technical challenges with innovative technology also helped earn the field a place in early oil and gas history. Uncorrected, drilling holes wandered 22 degrees or more off course. As the field’s high-pressure gas expanded, it cooled rapidly freezing production equipment. This complicated the production process. Other problems involved external corrosion, casing failures, sulphide stress corrosion cracking, corrosion inside oil storage tanks, and the cold winters.
Early drilling was done by wooden cable tool drilling rigs which pounded a hole into the ground. These monsters ruled the drilling scene until the mid-1920s. Rotary drilling (which has since replaced cable tool drilling) and diamond coring made their appearance in Turner Valley in 1925. Nitro-shooting came in 1927 to enhance production at McLeod No. 2. Acidizing made its Canadian debut in 1936 at Model No. 3. Scrubbing gas to extract hydrogen sulphide started in 1925. Field repressurization began in 1944 and waterflooding started in 1948.
Only months after Union Gas completed a scrubbing facility for its Tilbury gas in Ontario, in 1924 Royalite began sweetening gas from the sour Royalite #4 well through a similar plant. This process removed H2S from the gas, but did not extract the sulphur as a chemical element. This development waited until 1952, when a sulphur recovery plant at Turner Valley began producing raw sulphur.
Turner Valley oil production peaked in 1942, partly because the Oil and Gas Conservation Board increased allowable production as part of the war effort. Exploration results elsewhere in western Canada had been disappointing, however. The only discoveries made were small heavy oil fields.
[edit] Leduc
There were no major new strikes until 1947, when Imperial Oil Ltd. discovered light oil just south of Edmonton.
During the 1930s and early 1940s, oil companies tried unsuccessfully to find replacement for declining Turner Valley reserves. Imperial Oil had drilled 133 dry wells in Alberta and Saskatchewan. In 1946, the company decided on one last drilling program from east to west in Alberta. The wells would be “wildcats” - exploratory wells drilled in search of new fields.
The first drill site was Leduc No. 1 in a field on the farm of Mike Turta, 15 kilometres west of Leduc and about 50 kilometres south of Edmonton. Located on a weak seismic anomaly, the well was a rank wildcat. No drilling of any kind had taken place within an 80-kilometre radius.
Drilled started on November 20, 1946. It continued through a winter that was “bloody cold,” according to members of the rig crew. At first the crew thought the well was a gas discovery, but there were signs of something more. At 1,530 metres, drilling speeded up and the first bit samples showed free oil in dolomite, a good reservoir rock. After coring, oil flowed to the surface during a drill stem test at 1,544 metres.
Imperial Oil decided to bring the well in with some fanfare at 10 o’clock in the morning of February 13, 1947. The company invited the mayor of Edmonton and other dignitaries. The night before the ceremony, however, swabbing equipment broke down. The crew laboured to repair it all night. But 10:00 a.m. passed and no oil flowed. Many of the invited guests left.
Finally by 4:00 pm the crew were able to get the well to flow. The chilled onlookers, now numbering only about 100, saw a spectacular column of smoke and fire beside the derrick as the crew flared the first gas and oil. Alberta mines minister N.E. Tanner turned the valve to start the oil flowing (at an initial rate of about 155 cubic metres per day), and the Canadian oil industry moved into the modern era.
Imperial lost no time. On February 12 it started drilling Leduc No. 2, about 3 kilometres southwest of No. 1, trying to extend the producing formation. But nothing showed up at that level and company officials argued over how to proceed. One group proposed abandoning the well, instead drilling a direct offset to No. 1; another group wanted to continue drilling No. 2 into a deep stratigraphic test.
But drilling continued. On May 10 at 1,657 metres, No. 2 struck the much bigger Devonian reef, which later turned out to be the most prolific geological formation in Alberta.
As if to underscore the significance of this discovery, a blow-out occurred in the early development phase on March 6, 1948 during the drilling of Atlantic Leduc No. 3. Out of control for six months, the well ultimately caught fire. Successfully bringing the well under control (achieved on September 9, 1948) required two relief holes and the injection of 160,000 cubic metres of river water. During the blow-out an estimated 180,000 cubic metres of oil flowed to the surface. Workers recovered most of the oil through a series of ditches and gathering pools.
Leduc No. 1 stopped producing in 1974 after the production of some 50,300 cubic metres of oil and 9 million cubic metres of natural gas. On November 1, 1989, Esso Resources (the exploration and production arm of Imperial) began producing the field as a gas reservoir. Thus did Canada’s seminal oil discovery become a gas well on its way to extinction.
[edit] Norman Wells
One of the more exciting chapters in Canada’s early patch history is the story of Norman Wells in the Northwest Territories. During his voyage of discovery down the Mackenzie River to the Arctic Ocean in 1789, Sir Alexander Mackenzie noted in his journal that he had seen oil seeping from the river’s bank. R.G. McConnell of the Geological Survey of Canada confirmed these seepages in 1888. In 1914, T.O. Bosworth, later Imperial Oil’s chief geologist, staked three claims near the spot. Imperial Oil acquired the claims and sent two geologists there in 1918-1919. They recommended drilling.
Led by a geologist, a crew comprised of six drillers and an ox (Old Nig by name) began a six-week, 1,900-kilometre journey northward by railway, river boat and foot to the site now known as Norman Wells. They found oil - largely by luck, it turned out later - after Ted Link, the geologist, waved his arm grandly and said, “Drill anywhere around here.” The crew began digging into the permafrost with pick and shovel, unable to put their cable tool rig into operation until they had cleared away the mixture of frozen mud and ice. At about the 30-metre level they encountered their first oil show. By this time, the river ice had frozen to 1.5 metres and the mercury had plunged to -40 degrees. The crew decided to give up and wait out the winter. They survived, but their ox did not. Old Nig provided many a meal during the long, cold winter.
Drilling resumed in the spring and a relief crew arrived in July. Some of the original crew stayed around to help the newcomers continue drilling. On August 23, 1920, they struck oil at 240 metres. The world’s most northerly oil well had come in. In succeeding months, Imperial drilled three more holes - two successful, one dry. The company also installed enough equipment to refine the crude oil into a type of fuel oil for use by church missions and fishing boats along the Mackenzie. But the refinery and oil field closed in 1921 because northern markets were too small to justify the costly operations. Norman Wells marked another important milestone when in 1921 Imperial flew two all-metal 185-horsepower Junkers airplanes to the site. These aircraft were among the first of the legendary bush planes which helped to develop the north, and forerunners of today’s commercial northern air transport.
A small refinery using Norman Wells oil opened in 1936 to supply the Eldorado Mine at Great Bear Lake, but the field did not take a significant place in history again until after the United States entered World War II.
When Japan captured a pair of Aleutian Islands, Americans became concerned about the safety of their oil-tanker routes to Alaska and began looking for an inland oil supply safe from attack. They negotiated with Canada to build a refinery at Whitehorse in the Yukon, with crude oil to come by pipeline from Norman Wells. If tank trucks had tried to haul the oil to Alaska, they would have eaten up most of their own load over the vast distance.
This spectacular project, dubbed Canol - a contraction of “Canadian” and “oil” - took 20 months, 25,000 men, 10 million tonnes of equipment, 1,600 kilometres of road, 1,600 kilometres of telegraph line and 2,575 kilometres of pipeline. The pipeline network consisted of the 950-kilometre crude oil line from Norman Wells to the Whitehorse refinery. From there, three lines carried products to Skagway and Fairbanks in Alaska, and to Watson Lake, Yukon. Meanwhile Imperial was drilling more wells. The test for the Norman Wells oilfield came when the pipeline was ready on February 16, 1944. The field surpassed expectations. During the one year remaining of the Pacific war, the pipeline pumped about 160,000 cubic metres of oil to the Whitehorse refinery.
The total cost of the project (all paid by US taxpayers) was $134 million, in 1943 US dollars. Total crude production was 315,000 cubic metres (7,313 cubic metres of which spilled.) The cost of the crude oil was $426 per cubic metre ($67.77 per barrel). Refined petroleum product output was just 138,000 cubic metres. Cost per barrel of refined product was thus $975 per cubic metre, or 97.5 cents per litre. Adjusted to current dollars using the US Consumer Price Index, in 2000 dollars the oil would have cost $4,214 per cubic metre ($670 a barrel), while the refined product would have been worth an astonishing $9.62 a litre.
After the war, there was no use for the Canol pipeline. It simply fell out of use, with pipe and other equipment lying abandoned. But the Whitehorse refinery kept on going - in a different locale. Imperial bought it for $1 million, took it apart, moved it to Edmonton and reassembled it like a gigantic jigsaw puzzle to handle production from the fast-developing Leduc oil field.
But the Norman Wells story is not yet complete. The field entered its most important phase in the mid-1980s, when a pipeline connected the field to the Canada-wide crude oil pipeline system. Oil began flowing south in 1985.
Norman Wells was a frontier discovery. It was not Arctic exploration, however, since it was located south of the Arctic Circle. The definitive push into the Arctic took place in 1957 when Western Minerals and a small exploration company called Peel Plateau Exploration drilled the first well in the Yukon. To provision the well, some 800 kilometres from Whitehorse at Eagle Plains, Peel Plateau hauled 2,600 tonnes of equipment and supplies by tractor train. This achievement involved eight tractors and 40 sleighs per train, for a total of seven round trips. Drilling continued in 1958, but the company eventually declared the Peel Plateau well dry and abandoned. Over the next two decades, however, Arctic exploration gained momentum.
[edit] Arctic frontiers
Stirrings of interest in the Arctic Islands as a possible site of petroleum reserves came as a result of "Operation Franklin," a 1955 study of Arctic geology directed by Yves Fortier under the auspices of the Geological Survey of Canada. This and other surveys confirmed the presence of thick layers of sediment containing a variety of possible hydrocarbon traps.
The petroleum industry applied to the federal government for permission to explore these remote federal lands in 1959, before the government had begun regulating such exploration. The immediate result was delay. But in 1960, the Diefenbaker government passed regulations, then granted exploration permits for 16 million hectares of northern land. These permits granted mineral rights to companies in exchange for work requirements.
The first well in the Arctic Islands was the Winter Harbour #1 well on Melville Island, drilled in the winter of 1961-62. The operator was Dome Petroleum. Equipment and supplies for drilling and for the 35-man camp came in by ship from Montreal. This well was dry, as were two others drilled over the next two years on Cornwallis and Bathurst islands. But all three wells were technical successes. There was no doubt now that high Arctic drilling was possible.
The federal government's eagerness to encourage Arctic Islands exploration, partly to assert Canadian sovereignty, led to the formation of Panarctic Oils in 1968. That company consolidated the interests of 75 companies and individuals with Arctic Islands land holdings plus the federal government as the major shareholder.
Panarctic began its exploration program with seismic work and then drilling in the Arctic Islands. By 1969 its Drake Point gas discovery was probably Canada's largest gas field. Over the next three years came other large gas fields in the islands. Those years of drilling established reserves of 500 billion cubic metres of sweet, dry natural gas.
Panarctic also located oil on the islands at Bent Horn and Cape Allison, and offshore at Cisco and Skate. Exploration moved offshore when Panarctic began drilling wells from "ice islands" - not really islands, but platforms of thickened ice created in winter by pumping sea water on the polar ice pack.
The company found lots of gas but also some oil. In 1986, Panarctic became a commercial oil producer on an experimental scale. This began with a single tanker load of oil from the Bent Horn oil field (discovered in 1974 at Bent Horn N-72, the first well drilled on Cameron Island). The company delivered its largest annual volume of oil - 50,000 cubic metres - to southern markets in 1988.
Panarctic's ice island wells were not the first offshore wells in the Canadian north. In 1971, Aquitaine (later known as Canterra Energy, then taken over by Husky Oil) drilled a well in Hudson Bay from a barge-mounted rig. Although south of the Arctic Circle, that well was in a hostile frontier environment. A storm forced suspension of the well, and the ultimately unsuccessful exploration program languished for several years.
[edit] The Mackenzie delta and the Beaufort Sea
The Mackenzie delta was a focus of ground and air surveys as early as 1957, and geologists drew comparisons then to the Mississippi and Niger deltas, speculating that the Mackenzie could prove as prolific. For millions of years sediments had been pouring out of the mouth of the Mackenzie, creating tremendous banks of sand and shale - laminates of sedimentary rock warped into promising geological structures. Drilling began in the Mackenzie Delta-Tuktoyuktuk Peninsula in 1962, and accelerated during the early 1970s. The mouth of the mighty Mackenzie River was not a Prudhoe Bay, but it did contain large gas fields.
By 1977, its established gas reserves were 200 billion cubic metres, and a proposal to construct a pipeline to tap these resources had become a hot political issue. An inquiry by Justice Thomas Berger resulted in a moratorium on such a pipeline, which today is again under consideration.
The petroleum industry gradually shifted its focus into the unpredictable waters of the Beaufort Sea. To meet the challenges of winter cold and relatively deep water, drilling technologies in the Beaufort underwent a period of rapid evolution.
The first offshore wells drilled in the Beaufort used artificial islands as drilling platforms. But the artificial island was a winter drilling system, and was only practical in shallow water. In the mid-1970s, the introduction of a fleet of reinforced drillships extended the drilling season to include the 90 to 120 ice-free days of summer. This also enabled the industry to drill in the deeper waters of the Beaufort Sea. By the mid-1980s, variations on artificial island and drilling vessel technologies had extended both the drilling season and the depth of water at which the industry could operate. They had also reduced exploration costs.
The first well to test the Beaufort was not offshore, but was drilled on Richards Island in 1966. The move offshore came in 1972-73 when Imperial Oil built two artificial islands for use in the winter drilling season. The company constructed the first of these, Immerk 13-48, from gravel dredged from the ocean floor. The island's sides were steep and eroded rapidly during the summer months. To control the erosion, the company used wire laid across the slopes and anchored, then topped off with World War II surplus anti-torpedo netting. The second island, Adgo F-28, used dredged silt. This proved stronger. Other artificial islands used other methods of reinforcement.
In 1976, Canadian Marine Drilling Ltd., a subsidiary of Dome Petroleum, brought a small armada to the Beaufort. It included three reinforced drillships and a support fleet of four supply boats, work and supply barges and a tugboat. This equipment expanded the explorable regions in the Beaufort Sea. Drillships, however, had their limitations for Beaufort work. Icebreakers and other forms of ice management could generally conquer the difficulties of the melting icecap in the summer. But after freeze-up began, the growing icecap would push the drill ship off location if it did not use icebreakers to keep the ice under control.
The most technologically innovative rig in the Beaufort was a vessel known as Kulluk, which originated with Gulf Oil. Kulluk was a circular vessel designed for extended-season drilling operations in arctic waters. Kulluk could drill safely in first-year ice up to 1.2 metres thick. Dome eventually acquired the vessel, which then passed progressively through acquisitions to Amoco and then BP. BP sold this venerable tool for scrap at the end of the millennium.
The major Beaufort explorers experimented with a variety of new technologies and produced some of the most costly and specialized drilling systems in the world. Some of these were extensions of artificial island technologies; design engineers concentrated on ways to protect the island from erosion and impact. In shallow water, the standard became the sacrificial beach island. This island had long, gradually sloping sides against which the vengeance of weather and sea could spend themselves.
[edit] The East Coast offshore
The site of Canada's first salt water offshore well was 13 kilometres off the shores of Prince Edward Island. Spudded in 1943, the Hillsborough #1 well was drilled by the Island Development Company. The company used a drilling island constructed in eight metres of water of wood and some 7,200 tonnes of rock and concrete. The well reached 4,479 metres at a cost of $1.25 million - an extremely expensive well in that era. Part of the Allied war effort, Hillsborough was declared dry and abandoned in September 1945.
In 1967 Shell drilled the first well off Nova Scotia, the Sable Island C-67 well. Located on desolate, sandy Sable Island (best known for its herd of wild horses), the well bottomed in gas-bearing Cretaceous rocks. Drilling stopped there because the technology did not exist to handle the super-pressures the well encountered.
Shell's experience at this well foreshadowed two future developments on the Scotian Shelf. First, major discoveries offshore Nova Scotia would be gas reservoirs. Second, they would involve high-pressure natural gas. In the early 1980s, two discovery wells - Shell's Uniacke G-72 and Mobil's West Venture N-91 - actually blew wild. The Uniacke well took about ten days to bring under control. By contrast, the blow-out at West Venture took eight months.
The most promising exploration off Canada's east coast took place on the Grand Banks - particularly the Avalon and Jeanne d'Arc basins. Exploration began in the area in 1966 and, save one oil show in 1973, the first 40 wells on the Grand Banks were dry. Then, in 1979, came the Hibernia oil strike, which changed the fortunes of the area. Although not large enough to be commercial at the time of discovery, the next nine wildcats were important. However, two discoveries from the mid-1980s - Terra Nova and White Rose - proved to be more easily producible than Hibernia.
Chevron drilled the Hibernia discovery well to earn a commercial interest in that Grand Banks acreage. The field is 315 kilometres east-southeast of St. John's, and water depth is about 80 metres. Between 1980 and 1984, Mobil drilled nine delineation wells in the field at a cost of $465 million. Eight of those wells were successful, and they enabled the industry to establish that the field has recoverable oil reserves between 525 and 650 million barrels.
Since the oil industry began, periods of discovery have occasionally taken a human toll. The worst incident in Canada's east coast was the Ocean Ranger disaster of 1982. In that terrible tragedy, a semi-submersible offshore drilling rig went down in a ferocious winter storm, taking 84 hands into the sea. None survived.
[edit] Alberta’s oil sands
An early history of Canada’s petroleum industry would not be complete without a chronicle of pioneering efforts to produce the tar sands deposits (now commonly called “oil sands”) of northern Alberta.
Explorer and fur trader Peter Pond noticed the deposits when he travelled the Clearwater River to its junction with the Athabasca in 1778 - the first European to do so. He noted “...along the banks of the river are found springs of bitumen which flow along the ground.” Reaching the same area nearly a decade later, Alexander Mackenzie also became interested in the oil sands and the way the Chippewan Indians used the thick black oil for water-proofing their canoes. Despite the fascination of the early explorers, however, the existence of the sands did not excite commercial interests for more than a century.
In 1875, John Macoun of the Geological Survey also noted the presence of the oil sands. Later reports by Dr. Robert Bell and later by D.G. McConnell, also of the Geological Survey, led to drilling some test holes. The Survey theorized that drilling would encounter free oil lower in the sand beds, as Williams had done in the gum beds of Petrolia.
In 1893, Parliament voted $7,000 for drilling. The Geological Survey called tenders and had machinery shipped from Toronto. Drilling started August 15, 1894 at a site near Athabasca. According to his own estimates, McConnell expected to encounter oil sand at between 365 metres and 455 metres.
The hole did not reach this depth, however, because the drillers “ran out of hole” as successively small diameters of casing reduced hole size until further progress was impossible. Neither did further drilling find free oil.
But there was now clear recognition of the commercial potential of the sands, and a long period of exploration and experimentation followed. The point of this research was to find a method of getting oil out of the tar sands at a reasonable price.
Alfred von Hammerstein, who claimed to be a German count, was one of the colourful early players in the oil sands. He had been en route to the Klondike, but stayed and turned his interest from gold to the oil sands. In 1906 he drilled at the mouth of the Horse River, but struck salt instead of oil. He continued drilling in the area, but without success. History has not been kind to the count. He is now generally thought to have been a bit of a dreamer, a lot of a con.
In 1913, Dr. S.C. Ells, an engineer with the federal department of mines, began investigating the economic possibilities of the oils sands. It was then that the idea of using the sands as road paving material was born. In 1915, Dr. Ells laid three road surfaces on sections of 82nd Street in Edmonton. Materials used included bitulithic, bituminous concrete and sheet asphalt mixtures. A report, ten years later, by a city engineer stated that the surface remained in excellent condition. McMurray asphalt also saw use on the grounds of the Alberta Legislature, on the highway in Jasper Park and elsewhere in Alberta.
Although private contractors also mined oil sand as a paving material, the proposition was not economic. Fort McMurray (the village closest to the near-surface deposits) was small and far from market. And transportation costs were high.
- Further information: Athabasca Oil Sands
[edit] Early bitumen production
Instead, researchers began to look for ways to extract the bitumen from the sand. The Alberta Research Council set up two pilot plants in Edmonton and a third at the Clearwater River. These plants were part of a successful project (led by the Research Council’s Dr. Karl A. Clark) to develop a hot water process to separate the oil from the sands. In 1930, the Fort McMurray plant actually used the process to produce three car loads of oil.
At about that time two American promoters, Max Bell and B.O. Jones from Denver, entered the oil sands scene. They reportedly had a secret recovery method known as the McClay process, and they claimed substantial financial backing. They negotiated leases with the federal and Alberta governments and also bought the McMurray plant of the Alberta Research Council. In 1935, Abasand Oils Limited, Bells’ American-backed operating company, started construction of a new plant west of Waterways.
Under the agreement with the government, the plant was to be in operation by September 1, 1936. But forest fires and failure of equipment suppliers to meet delivery dates delayed completion.
The agreement called for mining 45,000 tonnes of sands in 1937 and 90,000 tonnes each year after 1938. The 1,555-hectare lease carried a rental of $2,47 per hectare per year. There was to be a royalty of $0.063 per cubic metre on production for the first five years, and $0.31 per cubic metre thereafter.
Mining at the Abasand plant began May 19, 1941. By the end of September, 18,475 tonnes of oil sand had produced 2,690 cubic metres of oil, but in November fire destroyed the plant. Rebuilt on a larger scale, it was fully operational in June 1942. Between 1930 and 1955, the International Bitumen Company Limited under R.C. Fitzsimmons operated a smaller scale pilot plant at Bitumount.
In 1943, the federal government decided to aid oil sands development, and took over the Abasand plant. The federal researchers concluded that the hot water process was uneconomic because of the extensive heat loss and proposed a “cold” water process. But work at the plant came to an end with a disastrous fire in 1945.
Meanwhile, in July 1943, International Bitumen Company reorganized as Oil Sands Limited. When the Alberta government became disenchanted with federal efforts in the oil sands and decided to build its own experimental plant at Bitumount, the province engaged Oil Sands Limited to construct the plant.
The company agreed to buy the plant within a period of ten years for the original investment of $250,000. The cost of the plant was $750,000, however. A legal claim against Oil Sands Limited resulted in the province taking possession of the plant and property at Bitumount. The plant consisted of a separation unit, a dehydrating unit and a refinery. The plant conducted successful tests using the Clark hot water process in 1948/49 then closed, partly because the recent Leduc discoveries had lessened interest in the oil sands.
Oil Sands Limited eventually reorganized as Great Canadian Oil Sands Limited (now Suncor}, which built and started operation of the first commercial-sized integrated oil sands project in 1967. It had found solutions to the problems of extracting a commercial grade of oil from the sands - problems that had been the concern of financiers, chemists, petroleum engineers, metallurgists, mining engineers, geologists, physicists and many other scientists and pseudo-scientists for may decades. A much later development - although its roots go back to the 1940s, the massive Syncrude plant did not go into operation until 1978 - now supplies some 14% of Canada's crude oil production, in the form of synthetic oil.
[edit] And the future?
The story of the petroleum industry’s early years is a tale of innovation, hard work and a smattering of luck on the part of creative and resourceful people. Industrial activity in those years laid the foundation upon which Canada developed new technical and financial muscle.
Canada’s often severe climate and geological features, remote exploration frontiers and the unique features of oil sands and other indigenous petroleum resources provided challenges which the industry invested billions of dollars to meet. Those investments helped keep Canada in the technological forefront of the global petroleum business.
Also during those years, governmental activity played a big role. Regulatory policy and political issues affected the petroleum industry in many ways. In the early years these matters were exemplified in a positive way by the creation of the Turner Valley Gas Conservation Board and in a negative way by the conflict between that province and the federal government over ownership of natural resources. The energy crises of the 1970s reached a climax in Canada with the promulgation of the traumatic National Energy Program, which proved to be wildly divisive.
And the future? Two global questions have particular resonance for the sector. One pertains to the matter of supply. An increasingly widespread notion has it that the world's oil production will soon peak, and is widely known as the Hubbert peak theory. If true, this hypothesis has huge implications for oil prices, which could become economically destabilizing.
The other trend to which petroleum production is inextricably linked is that of global warming. Fossil fuels like oil and gas are the primary contributors to this phenomenon.
As these issues play out in coming decades, they could have huge impacts on economic and environmental matters in Canada as throughout the world.
[edit] Metric conversions
One cubic metre of oil = 6.29 barrels. One cubic metre of natural gas = 35.49 cubic feet. One kilopascal = 1% of atmospheric pressure (near sea level).
Canada's oil measure, the cubic metre, is unique in the world. It is metric in the sense that it uses metres, but it is based on volume so that Canadian units can be easily converted into barrels. In the rest of the metric world, the standard for measuring oil is the metric tonne. The advantage of the latter measure is that it reflects oil quality. In general, lower grade oils are heavier.
[edit] References and external links
George de Mille, Oil in Canada West, The Early Years, George de Mille Books, printed by Northwest Printing and Lithographing Ltd., Calgary; 1972
Peter McKenzie-Brown, Gordon Jaremko, David Finch, The Great Oil Age, Detselig Enterprises Ltd., Calgary; 1993
J. Joseph Fitzgerald, Black Gold with Grit, Gray's Publishing, Victoria, British Columbia; 1978
External links
