History of the Petroleum Industry in Canada, Part Two

This history is part two of a history of the Canadian petroleum industry, which I wrote for Wikipedia. It is about northern and offshore petroleum frontiers and oil sands. For early development of Canada's conventional petroleum resources and pipelines, see History of the petroleum industry in Canada, part one.

Canada's petroleum frontiers are of two types. The technological frontiers include the oil sands of Alberta, and the huge heavy oil belt that stretches from central Alberta into Saskatchewan, and straddles the borders between the two provinces. Here the resources are known, but technologies to produce oil from them in cost-effective ways are still being developed. The geographical frontiers are the vast petroleum basins in the north, in the Arctic Islands and offshore, and off the coast of Atlantic Canada. These areas are difficult and expensive to explore and develop, but successful projects can be profitable using known production technology. This article covers the early development of both.


Oil sands and heavy oil Chemistry of Petroleum: An early history of Canada’s petroleum industry would not be complete without a chronicle of pioneering efforts to produce the tar sands (now commonly called “oil sands”) of northern Alberta.

To appreciate these resources, it is important to understand the "gravity" of oil and gas. Gravity refers to the weight spectrum of hydrocarbons, which increases with the ratio of hydrogen to carbon in a chemical compound's molecule. Methane (CH4) - the simplest form of natural gas - has four hydrogen atoms for every carbon atom. It has light gravity, and takes the form of a gas at atmospheric pressure. The next heavier hydrocarbon, ethane, has the chemical formula C2H6 and is a slightly heavier gas.

Gases, of course, have no gravity at atmospheric temperatures and pressures. Organic compounds combining carbon and oxygen are many in number. Those with more carbon atoms per hydrogen atom are heavier, and less likely to be gaseous. Most hydrocarbons are liquid under standard conditions, with greater viscosity associated with greater gravity.

The American Petroleum Institute has developed a formula to measure the API gravity of petroleum liquids. Heavy oil and bitumen, which have more carbon than hydrogen, are heavy, black, sticky and either slow-pouring or so close to being solid that they will not pour at all unless heated. Although the dividing line is fuzzy, the term heavy oil refers to slow-pouring heavy hydrocarbon mixtures.

Bitumen refers to mixtures with the consistency of cold molasses that pour at room temperatures with agonizing slowness. It is difficult to grasp the immensity of Canada's oil sands and heavy oil resource. Sand deposits in northern Alberta include four major deposits which underlie almost 70,000 square kilometres of land. The volume of bitumen in those sands dwarfs the light oil reserves of the entire Middle East. One deposit, the Athabasca oil sands, is the world's largest known crude oil resource.

Early Exploration: 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 Ojibwe 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. In 1893, Parliament voted $7,000 for drilling. This first commercial effort to exploit the oil sands probably hoped to find free oil at the base of the sands, as drillers had in the gum beds of southern Ontario a few decades earlier.

 Although the Survey's three wells failed to find oil, the second was noteworthy for quite another reason. Drilled at a site called Pelican Portage, the well blew out at 235 metres after encountering a high-pressure gas zone. According to drilling contractor A.W. Fraser,

The roar of the gas could be heard for three miles or more. Soon it had completely dried the hole, and was blowing a cloud of dust fifty feet into the air. Small nodules of iron pyrites, about the size of a walnut, were blown out of the hole with incredible velocity. We could not see them going, but could hear them crack against the top of the derrick . . . . There was danger that the men would be killed if struck by these missiles.

Fraser's crew unsuccessfully tried to kill the well by casing it, then abandoned the well for that year. They returned in 1898 to finish the job, but again they failed.

In the end, they simply left the well blowing wild. Natural gas flowed from the well at a rate of some 250,000 cubic metres per day until 1918. In that year a crew led by geologist S.E. Slipper and C.W. Dingman finally shut in the well.

These wells helped establish that the bitumen resource in the area was huge. There was now clear recognition of the commercial potential of the oil 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 Hamerstein, 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 working in the area, however.

In 1907 Von Hamerstein made a celebrated presentation to a Senate committee investigating the potential of the oil sands.

I have all my money put into (the Athabasca oil sands), and there is other peoples' money in it, and I have to be loyal. As to whether you can get petroleum in merchantable quantities . . . I have been taking in machinery for about three years. Last year I placed about $50,000 worth of machinery in there. I have not brought it in for ornamental purposes, although it does look nice and home-like. 

History has not been kind to the count, however. 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.

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 per cent of Canada's crude oil production, in the form of synthetic oil.

Heavy Oil Story:Heavy oil is a sister resource to bitumen. It is lighter than bitumen and its reservoirs are much smaller than the great oil sands deposits. Even so, its dimensions are impressive. But like the oil sands, only a small percentage is producible. Often called conventional heavy oil, this low-density oil can be recovered by conventional drilling techniques or by waterflood, a technique of injecting water into the reservoir to increase pressure, thus forcing the oil toward the well bore.

When these techniques work, heavy oil is like the more commercially attractive lighter grades of oil. But heavy oil can also be quite viscous. It can need some form of heat or solvent and pressure before it can flow into a well bore to be produced. When heavy oil requires these techniques to go into production, it is known as non-conventional heavy oil.

The first heavy oil discoveries came with the pursuit of conventional light and medium crude oil. Because much of western Canada's heavy oil is in pools close to the surface, early explorers using older rigs discovered many of those pools before they came upon the deeper light oil reservoirs. One of the first finds was in the Ribstone area near Wainwright, Alberta in 1914. The province's first significant production of heavy oil came from the Wainwright field in 1926. Producers drew almost 6 000 barrels of heavy oil from the field in that year. A small-scale local refinery distilled the heavy goo into usable products.

Elsewhere in Alberta, petroleum explorers made other heavy oil finds as they pursued the elusive successor to the Turner Valley oil field. They developed production from many of these fields, but only in small volumes. The recovery techniques of the day combined with the low price of oil and the nature and size of the finds meant that most of the oil remained undeveloped.

The most important exception was at Lloydminster. While the first discovery occurred in 1938, serious development did not begin until Husky Oil moved into the area after the second world war. Husky Oil was born during the Depression through the efforts of Glenn Nielson, an Alberta farmer driven to bankruptcy when the bank called a loan on his farm. Nielson had moved to Cody, Wyoming, by the time he founded Husky as a refining operation.

He turned his attention back to Canada after the second world war, and decided to set up a refinery at Lloydminster. Steel was scarce, so Husky dismantled a small Wyoming refinery constructed during the war to provide bunker fuel to the American Navy. It loaded the pieces onto 40 gondola cars and shipped them north by railway. The company began reassembling the 400 cubic metre per day facility in 1946, and the refinery went on production the following year. Strategically located between the Canadian Pacific and Canadian National railroad tracks in Lloydminster, the refinery soon began to get contracts for locomotive bunker fuel. The company also found a strong market for asphalt for road building. 

Husky's move into the area spurred drilling and production. Within two years of Husky's arrival, there were oversupplies of heavy oil and shortages of storage space. Producers solved the problem by storing the oil in earthen pits holding up to 16,000 cubic metres each. For a while Husky bought the oil by weight rather than volume since it was clogged with earth, tumbleweed and jackrabbits. The company had to strain and remeasure the stuff before it could begin refining. Husky began producing heavy oil from local fields in 1946, and by the 1960s was easily the biggest regional producer.

In 1963 the company undertook another in a series of expansions to the refinery. To take advantage of expanding markets for Canadian oil, it also began a program to deliver heavy oil to national and export markets. The key to the $35 million project was the construction of a reversible pipeline which could move the viscous heavy oil into the marketplace. The 116-kilometre "yo-yo" pipeline - the first in the world - brought condensate from the Interprovincial Pipe Line station at Hardisty, Alberta. The company began mixing this very light hydrocarbon with heavy oil, enabling it to flow more easily. The company then pumped the blend through its pipeline (hence the nickname "yo-yo") back to Hardisty. From there the Interprovincial took it eastward to market.

These developments made heavy oil for the first time more than a marginal resource. Within five years, area production had increased five-fold to nearly 2,000 cubic metres per day. By the early 1990s, production from the heavy oil belt was some 40,000 cubic metres per day. And Husky was still one of Canada's biggest heavy oil producers.

True North: The first great story in Canada's exploration of the geographical frontiers is that 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 oil 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, 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.

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.


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.


East and west coasts Scotian Shelf: 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 generally be natural gas reservoirs. Second, they would involve high pressures. 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 blowout at West Venture took eight months. West Venture started as a surface blowout, and was swiftly shut in. But the well then blew out underground. High-pressure natural gas burst through the well's casing, and began rushing from a deep zone into a shallow one. In oil industry parlance, the blowout "charged" the shallower geological zone, drastically increasing reservoir pressure. The cost of bringing this one well under control was a phenomenal $200 million.

The industry made other modest oil and gas discoveries in its early years off Nova Scotia - for example, Shell's Onandaga E-84 gas well, drilled to a depth of 3,988 metres in 1969. And in 1973, Mobil spudded the D-42 Cohasset well on the western rim of the Sable sub-basin. Mobil's bit found almost 50 metres of net oil pay in eleven zones of Cretaceous lower Logan Canyon sands. However, a follow-up well five years later found only water-bearing sands, and the company suspended work on the field.

Mobil moved to other Scotian Shelf locations, discovering the promising Venture gas field in 1979. Located on a seismic prospect which had been recognized some years earlier, Mobil had waited to drill the Venture probe because the structure was deep and could contain high-pressure zones like those which had halted drilling at Sable Island in the previous decade. The Venture discovery well cost $40 million, then a startling price for a single well.

Ironically, the first commercial offshore discovery, Mobil's 1973 Cohasset discovery, appeared relatively inconsequential when found. But toward the end of the 1980s, a combination of exploration successes and innovative thinking led to development of a field which most of the industry had seen as uneconomic. In December 1985, Petro-Canada spudded the Cohasset A-52 step-out well to explore the Cohasset structure southwest of Mobil's 1973 discovery well.

Unlike the disappointing 1978 stepout, that hole tested oil at a combined rate of 4,500 cubic metres per day from six zones. Following up on the positive results of the A-52 well, Shell drilled a discovery well at Panuke, eight kilometres southwest of Cohasset. The Shell Panuke B-90 wildcat encountered a relatively thin zone that tested light oil at a rate of 1,000 cubic metres per day. The following year, Petro-Canada drilled the F-99 delineation well at Panuke. That well tested oil at 8,000 cubic metres a day for six days.

While the Cohasset and Panuke discoveries were marginal by themselves, a consulting firm hired by Crown corporation Nova Scotia Resources Limited seized on the idea of joining them together. By forming a joint venture with British-based LASMO plc., which formed a Nova-Scotian affiliate to operate the field, NSRL was able to make the project a financial and technical success, although in the end production was much less than expected.

Newfoundland and Labrador: The bitter-cold Labrador Shelf of Newfoundland and Labrador was another prospective exploration province in the early period of eastern offshore exploration. First drilled in 1971, all wells in those deep waters were drilled from dynamically positioned drillships. Icebergs calved from the glaciersof Greenland and Labrador soon earned this stretch of water the unaffectionate nickname "Iceberg Alley." Icebergs drifting toward drilling equipment posed a unique hazard for the industry in that forbidding environment. But using a blend of cowboy and maritime technology, Labrador drillers handled the problem by lassoing the bergs with nylon ropes and steel hawsers, then towing them out of the way.

 In the end, however, worsening exploration economics and poor drilling results dampened the industry's enthusiasm for the area. Drilling stopped in the early 1980s. It continued, however, in the more southerly waters off the Rock of Newfoundland. The most promising drilling 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 of around 100 million cubic metres. Bringing the field on production would still be a long time coming. It involved settling a jurisdictional dispute between Newfoundland and Canada over ownership of offshore minerals and other issues. Lengthy fiscal negotiations began in 1985, shortly after Mobil submitted a development plan to the two governments.

Not until 1988 did the two governments reach agreement on the development with Mobil, Petro-Canada, Chevron and Gulf - the companies with interests in the Hibernia field. By the terms of this agreement, the federal government would provide $1 billion in grants, $1.66 billion in loan guarantees and other assistance to the $5.2 billion development project. These concessions were necessary because government insistence on a huge, expensive concrete production platform (the Gravity Based System) had made the field uneconomic. A floating platform like those used in the North Sea would be far less expensive, since construction of a Gravity Based System was labour-intensive. However, it arguably has safety advantages in the iceberg-prone Grand Banks. For governments, the high cost factor was actually appealing from a regional development standpoint, since Newfoundland has chronically high unemployment.

In fact, one appeal to governments of this vast project was that, whether profitable to its owners or not, it would generate revenue which would stimulate the economy of Canada's poorest province. The importance of safety was also critical, especially because of an industrial disaster off Canada's east coast early in the 1980s. Since the oil industry began, periods of discovery have occasionally taken a human toll. For Canada's petroleum industry, the worst incident was the Ocean Ranger disaster of 1982. In that terrible tragedy, a semi-submersible offshore drilling rig working in Canada's east coast went down in a winter storm, taking 84 hands into the sea. None survived.

West Coast: A sedimentary basin also exists off the west coast of Canada, and some exploratory drilling has taken place there. From 1967 to 1969, Shell drilled 14 deep dry holes - some west of Vancouver, others in Hecate Strait beside the Queen Charlotte Islands. Exploration off the west coast stopped in 1971 when the federal and British Columbia governments agreed to a moratorium on exploration pending the results of studies into the environmental impact of drilling.

In 1986 a government-appointed commission recommended an end to the moratorium. The province had still not acted by 1989, however, when an American barge spilled oil off the British Columbia coast. A few months later came the disastrous Exxon Valdez oil spill off Alaska. Although neither of these spills was related to crude oil exploration or production, they made it politically impossible for governments to lift the moratorium.


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. This hypothesis is widely known as the Hubbert peak theory, or peak oil. If true, it 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.