The Legislative Ax

By Peter McKenzie-Brown

About 25 years ago I had a brief meeting with Daniel Yergin, the founder of Cambridge Energy Research Associates, who impressed me greatly with his global knowledge of the petroleum industry. When he told me he was writing a petroleum history, I gave him a copy of a brief history of the Canadian oil industry I had just finished – a history that waxed eloquent on the potential of Canada’s oilsands. He promised to read it on the plane going home to Cambridge, Massachusetts.

A few years later he published his magisterial volume The Prize, which received the Pulitzer Prize for general non-fiction but relegated Canadian oil industry history to a single brief footnote about the 1947 Leduc discovery. My only consolation was that his information had almost certainly come from my document. I report this episode because now, 20 years later, his firm has clearly rethought Alberta. Among American think-tanks, CERA is one of the oilsands’ most optimistic cheerleaders.

Getting the Numbers Right
Now the leading subsidiary of an NYSE-listed company, CERA has recently been preparing and releasing a series of thoughtful, detailed analyses of the oilsands under the general title “Oilsands Dialogue.” Available online, the growing package of reports is “must” reading for those concerned with oilsands markets and policy, which are increasingly being influenced by stateside legislation.

A recent offering is an analysis of the gathering phenomenon known as the low-carbon fuel standard, which has the potential to put some of Canada’s most important bitumen markets at risk. Lifecycle analysis of carbon emissions is one measure of the efficiency of fuels used for road transportation. Generally referred to as “well-to-wheel,” this analysis is frequently broken down into stages such as “well-to-pump” and “pump-to-wheel.” The pump referred to is the one you use at the service station to fill your tank.

The tightly-argued CERA report is full of surprises. On the one hand, the researchers found that if you produce only transportation fuel from oilsands production, your average well-to-wheels life-cycle greenhouse gas emissions will be 5% to 15% higher than for the average crude produced in the United States. On the other, they found that average bitumen imported into the United States has well-to-wheels life-cycle greenhouse gas emissions only 6% higher than average. These two sets of statistics appear contradictory, yet the explanation is simple. To achieve maximum refining efficiency, refiners use blends of crude oil. This anomaly illustrates the complexities involved in trying to calculate the well-to-wheels lifecycle for greenhouse gas emissions.

In addition to complexity, there is a certain element of futility. Alberta’s Washington representative, Gary Mar, gives a folksy but adamant commentary on the subject. “Saudi crude is light in terms of GHGs” he acknowledges, and “oilsands oil is not as light as Saudi Arabian oil. However, we are less GHG-intensive than, for example California heavy. We are not quite as good as Nigerian oil but we are close.” Then he zeroes in on his target: “Most of the GHGs, about 80%, are produced during the combustion phase of transportation. The overwhelming majority of GHGs are released into the atmosphere when you’re driving your car or truck” – that is, in the pump-to-wheel stage.

Legislative Options
Given the difficulties in quantifying well-to-pump emissions and the relatively small share of total emissions they represent, the well-to-wheels calculation may make even less sense than America’s Bush-era federal renewable fuel standard – a standard requiring that specified volumes of biofuels, which are energy-intensive to produce, be blended into transportation fuels. Yet “lifecycle analysis of emissions is becoming a new basis for policy in the transportation sector,” the Cambridge study observes. With considerable understatement the authors add that “life-cycle analysis is an evolving discipline that must deal with a number of uncertainties, making it a challenging basis for policy.”

In that context, it’s worth remembering that legislation is more of an ax than a tool for subtle refinement. Even so, low-carbon fuel standard legislation marches on. It took effect this year in California, where legislators hypocritically grandfathered the state’s own heavy oil, which is far more GHG-intensive than any other oil used in the United States. British Columbia’s version will take effect in two years. And according to CERA, 13 other jurisdictions in North America (including Ontario) have expressed interest in this kind of legislation. Such legislation could have a huge impact on bitumen markets. Combined, those jurisdictions represent a third of the US gasoline market and half of Canada’s.

Within the United States, debate on the issue has already led to litigation. For example, a court action launched by groups representing refiners and the petrochemical sector, trucking, a consumers’ alliance, a producers’ is lobby and a clutch of agricultural groups claim that only the US federal government (not the state) has the authority to regulate carbon emissions. Although the case continues to crawl through the legal system, last year a district court in California ruled that low-carbon fuel standards conflict with federal law, including the Energy Independence and Security Act of 2007 and the decades-old Clean Air Act. The ruling described the latter as “comprehensive federal legislation that covers air pollution prevention and control, emissions standards, acid rain reduction, permits, and stratospheric ozone protection.”

Rather than focusing on fuel properties, legislators from oil-importing jurisdictions could probably develop more effective policy by focusing on fuel economy and total demand for transport. Fuel economy standards focus on ways to enable individual vehicles to get greater mileage from a given volume of fuel. Policies that reduce transport demand include fuel taxes, better urban planning and encouraging mass transit, carpooling and, for example, telecommuting.

As North America’s major bitumen producer, Alberta is in a unique position to pass effective legislation, according to Gary Mar; as the owner, regulator and single biggest beneficiary of the oilsands, it is in the province’s interest to do so. Two years ago, the province became the only jurisdiction in North America to place a price on carbon emissions. It did so as part of a larger initiative to get large emitters to reduce their GHG emissions by 12%. “You satisfy the requirement to reduce your GHG emissions in one of three ways,” he says. “You can physically reduce emissions; you can purchase an accredited Alberta offset, or you can pay a $15 per tonne levy into a technology fund that supports development and application of transformative technologies.”

He adds, “It’s not just Alberta companies that can apply for access to money from that fund. Anyone can do it as long as that technology is applied within the province of Alberta.” The funds from this tax go to the newly-created Climate Change and Emissions Management Corporation, a not-for-profit organization whose job it is to reduce greenhouse gas emissions and assist in adapting to climate change.

Last year the agency put out calls for proposals related to renewable energy, energy sufficiency and clean technology, receiving ideas totalling $161 million from 30 organizations, and winnowed them down to 16 “ground-breaking” projects, according to the corporation’s chairman, Eric Newell. He adds that these projects “hold enormous promise, not just for Alberta, but for how the world will tackle the climate change agenda.”

Nancy Pelosi’s Dilemmas
Last September, then-speaker of the US House of Representatives Nancy Pelosi made a much-vaunted visit to Ottawa to confer with Canadian political leaders on energy matters, especially the oilsands. Whether accurately not, she was reported as saying she was “not keen on fossil fuels.” In that context, it is interesting to note that about “two-thirds of Canada’s crude oil equivalent goes to the United States,” according to Gary Mar. In fact, “Alberta alone provides 17% of total US oil imports, while Canada as a whole contributes 23%.”

Bob Taylor points out that from an energy systems perspective, Ms. Pelosi’s comment suggests two dilemmas. Taylor was Alberta’s Assistant Deputy Minister for Oil and now leads a consulting group known as the Energy Futures Network. “Like other citizens of advanced economies,” he says, “she faces the dilemma of cold showers and cold coffee and staying home versus willingly using fossil fuels day-in and day-out.” As a high-profile Congresswoman she carries a particularly big hydrocarbon burden: the kerosene used to fuel the jet that brought her up from Washington, for example, the gasoline that fuelled her limos to and from the airport, and so on.

The second dilemma, says Taylor, is that “her preferred state of ‘not fossil fuels’ belies the current US reality. Eighty-three percent of US energy supply originates from fossil fuels, with petroleum accounting for 37% of those needs. Her constituents will be reliant on a range of fossil fuels, including oil imports, for many years into the future.” To move toward a future which is less reliant on hydrocarbons, he says, involves solving four exceedingly difficult problems.

The first is to reduce or limit energy growth while contending with a growing population in the US and growing gross domestic product per capita.

The second is to reduce the amount of energy wasted in the United States. Taylor points to a Lawrence Livermore National Laboratory study, which found that 61% of the energy used in the United States is “rejected” (wasted). “Smaller motor vehicles, smaller and better insulated homes, a shift towards urban densification would be good places to start.”

The third is to “shift from fossil fuels and non-renewables towards renewables and non-carbon-emitting technologies while maintaining the reliability and affordability that are taken as ‘givens’ by American citizens (and voters).”

The last is to lower GHG emissions from well-to-pump even though the energy input cost of oil production has been rising for decades. This is partly because of the increasing need to use harder-to-produce oils like bitumen as light oil reservoirs have depleted. Also, deeper drilling depths (more energy used to run the rigs, more energy needed for steel) plus more energy for waterflood injection and for pumping oil from greater depths or with a higher water content. The result? According to one study, in 1930 the industry needed to consume the energy equivalent of one barrel of oil to produce 100 barrels. Today expending one barrel of energy produces only ten barrels of crude from American fields. Yet the notion of continuing to use less GHG-intensive crude in refineries is one of the key concepts in low-carbon fuel standards legislation. “It may be a bit like pushing on a string,” says Taylor.

Global Markets
It may also be breaking the law. Low-carbon fuel standards could actually abrogate the North American Free Trade Agreement or World Trade Organization rules. According to an opinion presented in the Globe & Mail newspaper, the courts may interpret the low-carbon standard as being discriminatory against Canadian crude. While NAFTA has some room for manoeuvre based on environment-related issues, to win that battle Americans may have to prove climate change in a court of law. And as we have seen, much of the litigation already on the table is based on US constitutional challenges.

According to Don Murray, president of Calgary-based Advantage Insight Group, other measures may influence the free flow of oilsands blends across the US border. Traditionally, crude oil that originates in North America can move from Canada to the US without duty. However, US importers have to identify the country of origin of their blend components – in the case of bitumen, any overseas diluents combined into the product. “As diluent imports into Canada have increased,” he notes, “the NAFTA status of Canadian heavy blends has been questioned.” He stresses, though, that this argument is still primarily theoretical.

Are Canada’s US markets likely to dry up because of concerns about lifecycle carbon emissions? Probably not. “We are a global player in the energy industry,” according to Gary Mar, “and there is an important relationship between Alberta’s oilsands and United States energy needs. We are committed to being a responsible energy supplier, and we’re poised to become an even more important part of North America’s energy needs.”

According to Andrew Constantinidis, an industry consultant, the industry should be more vocal in telling its American markets that Canadian oil supplies have a special quality about them apart from the fact that they mostly come from the oilsands. Of America’s seven major sources of foreign oil, Canada and Mexico are the only conflict- and repression-free petroleum suppliers. The humanity of that message, he thinks, will trump concerns about greenhouse gases.

Heavy Oil for Tomorrow

An illustration of the SAGD process; source: Value Creation Group of Companies.

Conventional production benefits from technology innovation; this article appears in the 2011 Heavy Oil and Oilsands Guidebook

By Peter McKenzie-Brown

The notion that since conventional oil production has peaked and the world will soon face a crisis of inadequate supply has a lot of true believers, but they seem to be in short supply in the heavy oil sector.

According to Cenovus vice president Dave Goldie, “Technology is opening up new frontiers for oil production – not just in heavy oil and oilsands, but also in light oil. Given everyone’s ingenuity, we are finding ways to access more oil.” The numbers seem to back him up: there are major heavy oil deposits on every continent, and global heavy oil and oilsands deposits embrace more than five trillion barrels in situ – at least potentially, enough supply to meet market demand for a long time yet to come.

At least two technologies developed in Canada that have become familiar in the oilsands sector are being deployed in conventional heavy oil to expand production and increase recovery rates.

Steam Assisted Gravity Drainage
The late Dr. Roger Butler’s steam assisted gravity drainage (SAGD) originated as a procedure for producing bitumen from the oilsands, and the technology has a huge impact on oilsands production. Recently, it has begun to change production economics at some conventional heavy oil reservoirs – notably Baytex Corp.’s Kerrobert project, Husky’s Pikes Peak operation and Senlac in Saskatchewan, owned by Southern Pacific Resources.

Baytex purchased its project from True Energy (now Bellatrix Exploration) in 2009. At present, Baytex Kerrobert produces 2,000 barrels per day, and those volumes are increasing. “We placed a new SAGD well pair on production late in the third quarter of 2010,” says Baytex spokesman Brian Ector. “Subsequent to the end of the quarter, this well pair produced at a 30-day average rate of approximately 1,000 barrels per day. We believe that, through the remaining life of this project, we can drill 11 additional SAGD well pairs. For 2011, we will likely drill two new pairs on the property.”

For Southern Pacific, the Senlac property in many ways was a company maker. The company acquired it from Cenovus for $90 million, and it enabled the company to move to the Toronto Stock Exchange by providing cash flow. “As soon as we had that we were a going concern,” according to company president Byron Lutes. “It enabled us to advance (from Venture) to the TSX. That means more due diligence, but a lot more investors now will put their money into the company.”

Since acquiring the property last spring, Southern Pacific has begun to face the reality of having to develop the property. The company has done some infill drilling, and at the end of last year drilled a SAGD well pair. The previous well pair produced about 1,300 to 1,500 barrels per day, according to Lutes. “From a rate perspective, (the new pair) won’t do better than our other wells (even though they include 650-metre horizontal wellbores) because we are not going to put on bigger pumps. However, we expect better recovery over the life of the well than if the well pairs had a smaller horizontal section.”

Southern Pacific is planning to spend about $10 million a year on the project. That will tie in one SAGD pair a year and will keep field production in the 4,000-5,000-barrel per day range, although he is optimistic that production will occasionally oscillate above 5000 barrels per day. “We estimate that this project will continue to produce at those levels for 10 to 15 years” he adds, and he is extremely optimistic about field economics. “The oil quality is better (12° API) than Athabasca (8° to 9° API), so the steam/oil ratios are typically lower and it takes less diluent to bring your oil up to spec. We will get a $39 per barrel netback on $77 per barrel WTI.”

Netback notwithstanding, Lutes pauses to brag about a recent field acquisition. “We were planning to replace a boiler this year, and the guys found it on Kijiji of all places. It was the exact boiler we needed, unused. It needed a few parts, but we bought it for about $90,000. When you factor in installation we saved ourselves maybe $700,000.”

Toe to Heel Air Injection
If Southern Pacific is a junior producer on the rise, PetroBank is one with global growth aspirations. The company’s THAI production technology involves using a vertical injector to feed air into a horizontal producer to keep underground ignition going. “There’s nothing magic about it,” according to company spokesman David McLellan, although the system has the potential to transform production from heavy oil deposits around the world.

PetroBank is developing its first commercial application of this process in Kerrobert, Saskatchewan. “We’ve had two wells on production there since November 2009, and this year we’re expanding to a 12-well total” says McClellan. “We’ve done the reservoir simulations and modelling and we feel as though each well will be capable of producing about 600 barrels per day. When you go through the pre-ignition cycle you’re trying to establish communication between the injector well and the producing wells. We think it will take 12 to 15 months to get up to full production.”

If the company’s calculations are right, when the project is up and running Kerrobert will be a 7,200 barrel per day facility. “What is really interesting about this project is that existing cold flow production is in the single-digit range – six, seven, maybe ten barrels per day per well.” With that kind of production the recovery factor for the pools would be only 4-7%. On the other hand, “with the THAI system we can recover between 70 to 80% (of oil in place). Five years ago, this was just theoretic. Today we have corroborated that we can do all this.”

McClellan says the Kerrobert project will produce an additional 7,200 barrels per day for capital cost of only $75 million. “That’s capex of only $10,400 per flowing barrel. Even if we got only half the production that we anticipate from those wells that would be a pretty good investment.”

Of particular interest to the company and its licensees is that the THAI process actually upgrades the oil underground, creating an oil with lower viscosity which therefore needs less diluent when it’s pumped into the pipeline. “It’s the heat that does this,” according to McClellan. The process takes 11° API heavy oil that underground and alters it to about 16°. “It is the heat that does this. The system cokes the oil underground, burning the heaviest asphaltines in the reservoir as fuel. The lighter stuff that’s mobilized out in front of ignition drains out into our production wells.”

He adds, “We have every conviction that this is going to be a game changer in heavy oil recovery. Once we have completely proven this technology, then the world will start to change.” Polymer Flooding

Polymer Flooding
Southern Pacific and PetroBank are medium-sized companies. Cenovus and Canadian Natural Resources aren’t. Respectively Canada’s third-largest and largest conventional heavy oil producers, each company has assets at Pelican Lake which exemplify how large producing properties are being used as laboratories. Experimentation in heavy oil production in this area receives important incentives from the province, which has designated it an oilsands production area. This means for royalty purposes the company equalizes production across all wells.

Cenovus initially began producing conventional heavy at Pelican Lake in 1997 from a series of horizontal wells; the field now produces about 24,000 barrels per day. According to Dave Goldie, who has executive responsibility for his company’s Pelican Lake assets, “The main method we’re using right now is polymer flood” – a technique partially pioneered by the Alberta Research Council, and which found one of his first commercial applications at Pelican Lake.

“The injection of polymers creates a more powerful piston effect, and it enables us to better push the oil out of the reservoir,” says Goldie. “Polymer is a pretty benign petrochemical – one of its uses is for disposable baby diapers. It turns water into a thick, viscous fluid which is great for heavy oil production. Over half our wells here at Pelican Lake are now based on polymer flood. We’ve applied this to over 170 wells.” Eventually, the entire field will use polymer flood.

It takes a while for the field to respond to the polymer. “After a period of time you see an increase in production which is associated with this extra push from the polymer flood.” Originally developed as a cold waterflood using horizontal wells, Pelican Lake’s original infrastructure included wells 200 metres apart. With that kind of spacing “it takes up to two years before you see a response. Now we’re infilling those patterns, and that’s increasing production rates. We’re constantly looking at new formulations of the polymer, adapting the well spacings to increase production. With cold waterflood we can get maybe a 12% recovery factor, but with polymer flooding we can more than double that. We keep on experimenting and it’s getting better.”

While polymer flood is the workhorse at the Pelican Lake project, Cenovus is testing a lot of other ideas on the property. According to field superintendent Gary Tebb, “Greater Pelican assets include the Pelican Lake project, which produces from the Wabiskaw. We’re also doing collaborative work with our Ventures team in the Grand Rapids (formation). We have an experimental project to access what we call the immobile Wabiskaw – an area where the oil is extremely viscous. We are also doing some work in the Grosmont zone, which is bitumen carbonate, and one part of the property we are experimenting with polymers plus surf it's actants.”

Dave Goldie clarifies that the Grand Rapids project will involve “in situ combustion using natural gas from a gas cap over the field in another formation. We have a patent pending on that particular scheme,” he adds. “Other companies are doing similar things; there’s a lot of experimentation going on. In these reservoirs different things work in different places.”

Canadian Natural Resources has a similar project at Pelican Lake/Britnell, where the company estimates original oil in place at 4.1 billion barrels. Like the Cenovus project, CNRL began with primary production, shifted to waterflood and, in 2005, to polymer flood. Now producing 38,000 barrels per day, the company expects project production to peak in 2015. It should plateau at more than 80,000 barrels per day – an amount equal to today’s total production from the company’s 10 largest conventional heavy oil projects along the Alberta/Saskatchewan border.

Dr. Sidney Ells

Consummate oilsands pioneer

This article appears in the 2011 Heavy Oil and Oilsands Guidebook

By Peter McKenzie-Brown
The first person with a technical background to devote his career to investigating the oilsands, Dr. Sydney Ells (1880?-1971) was the consummate oilsands pioneer. Until 1930, Ottawa held jurisdiction and ownership of Alberta’s mineral resources, and the federal Mines Department hired him in 1913 to investigate the resource potential of the oilsands. During more than 30 years with the department, he prepared 26 official oilsands reports and 15 maps of the region.

His 1913 report was the first government paper to stress that the oilsands in their own right had enormous economic potential. Previous investigators had proposed seeking light oil reservoirs near or underneath the sands. Working with the Parks Department, he then had 580 acres of prime oilsands property just outside the village of Fort McMurray designated the Horse River Reserve. It was on these lands that he conducted much of his research.

One notable experiment began in 1915. Ells shipped tons of oilsands by water, sleigh, and rail to Edmonton for a road-paving experiment. The stuff was used, without much need for repair, until the 1950s. Ells spent the last two years of the First World War in the armed forces. When the war was over, he returned to his work with the oilsands, soon becoming the federal government’s go-to guy on the oil sands.

Ells generally wintered in Ottawa, but spent summer months in the field. The trip from Edmonton to Fort McMurray in the early days was tremendously difficult. The first leg (145 km) was by wagon to Athabasca Landing. From there, he and his crew descended the river in a primitive scow. The return journey was worse, since it went against the current. Strong men used ropes to haul the scow to Athabasca Landing.

On one memorable occasion, Ells and his cocker spaniel actually walked the distance from Fort Mac to Athabasca Landing. So difficult were the conditions that he spent two days in hospital when he finally reached Edmonton.

In the 1920s Ells continued the paving material tests, with roads as far afield as Camrose, Jasper and Ottawa getting the oilsands treatment. He also arranged for test drilling – not for production purposes, but strictly to analyse the core. He invested a great deal of time and energy measuring geologic features, mapping terrain and cataloguing oilsands specifications. The oilsands got into Sidney Ells’ blood, and he stayed on top of research long after retirement in 1945.

Development efforts increased during the 1920s and 1930s – especially after the Alberta Research Council’s Dr. Karl Clark developed his game-changing hot-water separation process. After Alberta took ownership of the oilsands in 1930, however, Ells’ influence in the area went into decline.

His knowledge and enthusiasm had encouraged many business people and promoters to take an interest in the deposits, however, and his work helped create the cornerstone of today’s oilsands industry. Notably, in 1929 he went to Denver to meet with oil company executive Max Ball to discuss prospects for developing production from the Athabasca deposit. Having received Ells’ endorsement, Ball soon secured oilsands properties from the Dominion government – the last leases to be issued by the feds.

With encouragement from Ells that eventually overcame the discouraging economic conditions of the Great Depression, Ball began constructing the pioneering Abasand plant in 1936 but mining didn’t finally begin until 1941. In its first four months of operation, the plant processed 18,475 tonnes of oil sand to produce 17,000 barrels of oil then burned to the ground. The company rebuilt the plant and, in 1943, the federal government took it over as part of the war effort and experimented unsuccessfully with a cold-water process. Work at Abasand ended in 1945 when fire again destroyed the operation. That wasn’t the end of the Abasand legacy, though. In 1958 its leases became bedrock properties for Great Canadian Oil Sands (now Suncor).

Ells’ pioneering efforts were not rewarded with a truly commercial project during his working career. More than half a century after he began his pioneering investigations, he was a guest of honour at the official opening of the Great Canadian Oil Sands plant in 1967. After years of struggle, GCOS became the first truly commercial oilsands plant. However, Ells’ former colleague, friend and rival didn’t make the opening. Karl Clark had died nine months earlier of cancer.

Rampant Optimism, Tremendous Drive

With deep roots, the great Bitumount oil sands plant (pictured above in the 1930s) was an industrial pioneer

By Peter McKenzie-Brown

Alberta became active in oil sands research at the beginning of the Roaring Twenties, but could not have anticipated the importance of an incorporation registered in 1925. Robert C. Fitzsimmons’s International Bitumen was a seminal effort for the province, although for the man himself it was ultimately a business tragedy.

The company used a hot water process to produce bitumen, and in 1930 made its first sale of commercially produced bitumen in Edmonton. Because it couldn’t be upgraded at this point, the bitumen was used as fence post dip, for roof tar, and for setting pavement.  

Confidently naming his business the International Bitumen Company in 1927, by 1930 Fitzsimmons had constructed a small oil separation plant at Bitumount (Fitzsimmons gave the place its name) on a federal lease. The long-term significance of his operation and its successors can’t be overstated.

Located 89 kilometres north of Fort McMurray, the plant used a process similar to the hot-water separation process developed by Dr. Karl Clark of the Alberta Research Council, but without the chemical additives and refinements. It was constructed on the cheap, mostly from scavenged parts.  

In essence, Fitzsimmons’ approach was to crush the ore, heat it in hot water, divert it into settling tanks, then skim off the oily gunk that rose to the surface. These efforts were only half as efficient in terms of oil recovery as Clark had achieved with his process. The plant was designed to produce 750 barrels per day, but on a good day produced only 250.  However, in the early years the facility did generate a profit. 

After International Bitumen made its first deliveries, the Edmonton Journal gushed that “those shipments of absolutely pure bitumen are the first and second and only shipments in the history of McMurray tar sands to be made for commercial purposes and it certainly (augurs) well for the future development of the much talked of tar sands of northern Alberta.” 

Fitzsimmons had a passion for the oil sands and he was as stubborn as a mule, but two storms were brewing against him. One was the Great Depression. The other was a flood of light crude oil from Texas and Oklahoma, which was driving down prices. In the Dirty Thirties oil prices were as low as $0.67 per barrel ($9 in inflation-adjusted terms), and markets were lousy. Fitzsimmons’ strategy was to focus on roofing and road surfacing as the most likely markets for his bitumen.

He expanded his facilities, adding a small upgrader (he called it a refinery) in 1937-38. By then he had spent the funds entrusted to International Bitumen’s shareholders. Sales were slow, and cash flow problems began frustrating his dreams. In the vernacular of the period, his company was a day long and a dollar short. By the end of 1938, the company was insolvent. 

Fitzsimmons sought support in capital markets in eastern Canada and Chicago without success. In a final attempt to succeed, he established Tar Sands Products Limited in 1941 to sell International Bitumen Company products. The strategy didn’t help, and he couldn’t secure the $50,000 he needed to keep the plant running, eventually applying to the provincial government for either a straight loan or an advance on bitumen for road paving.

After the province declined to help, in 1943 Fitzsimmons sold the failing enterprise to a hard-nosed financier from Montreal, Lloyd Champion, reserving for himself a job as operations advisor. Frustrated, he left that position in 1944 but was soon called back to get the plant, which had been sitting idle for five years, back in operation. Once he got the plant going again, Champion fired him.

Embittered, Robert Fitzsimmons later wrote a document to tell shareholders “what happened to prevent the company’s success after it had reached the stage of commercial production of oil…and also to inform them how its accomplishments were nullified by obstructive tactics in government quarters.”  The cover page of his pamphlet illustrates the depth of his bitterness. Self-published in 1953, its title proclaims that it is “The truth about Alberta’s tar sands.” The cover then asks, “Why were they kept out of production? What happened to International Bitumen Co. Ltd.? Who solved the problem of separation and pioneered the production of oil from these sands? Who stood to gain by suppressing their development?” 

 He died alone in Edmonton in September, 1971. According to oil sands historian Joseph Ferguson, “It is doing great injustice to Canadian initiative, imagination and determination to allow the courage of men like Robert C. Fitzsimmons to be forgotten.” 

The Champion

Champion had acquired Bitumount through a company named Oil Sands Limited. With Fitzimmons out of the picture, in 1944 he transferred most of the Oil Sands assets to a holding company owned by himself and his wife, Ruby.  He then arranged for the province of Alberta to finance to the tune of $500,000 a new and larger plant (costs eventually rose to $750,000), with construction to be undertaken by Oil Sands Limited. The idea was to investigate Karl Clark’s extraction methods in a large-scale demonstration project. Development dragged on until well after the war. 

“The government is building a $500,000 fireproof pilot plant at Bitumount that should be in operation next July,” wrote William Elmer Adkin, the project’s operating engineer, in 1946. “Unless I miss my bet, we’ll prove to the world that oil can be extracted from the tar sand at less than $1 per barrel, a figure that we believe would warrant a large-scale commercial development.”  Adkin did lose his bet, but his comments reflect the determination and optimism of oil sands pioneers that ultimately led to commercial success.

Although Nathan Tanner was the province’s Minister of Mines and Lands, Premier Ernest Manning was the project’s champion. In a speech to the Legislature in 1944, he said “It has been established beyond question that a successful and efficient simple process exists for the separation of oil from the sands and for its refinement into commercial products. Members of the Government have inspected the plant while in actual operation and producing a sufficient volume of clear sand free of oil to prove the practicability of the process.”

Manning supported the funding for the project and had the entire legislature visit the plant in 1949, its second year of operation. Despite his efforts, the plant soon closed. The plant went on production in 1948. However, operations ended after new wells, including the spectacular blow-out at Atlantic Leduc #3, confirmed that the 1947 Leduc light-oil discovery was not a fluke.

The flurry of effort to develop commercial activity in the oil sands, which had climaxed during and just after World War Two, was over. The reason was Alberta’s Leduc oil strike and the other petroleum finds that quickly followed. Bitumen couldn’t compete with inexpensively produced conventional light oil. 

Though interest waned in those years, it did not die.

Manning commissioned an independent evaluation by Sidney Blair. The oil sands expert, who began his career as Karl Clark’s research assistant, based his report on the Bitumount project. Published in 1950, Blair’s study concluded that oil sands development could be economic for projects producing 20,000 barrels or more of oil per day. He envisioned such a plant costing $43 million and generating a 5 to 6 percent annual return on investment. He believed that such an operation could profit in a market where conventional oil was fetching only $2.70 per barrel, because synthetic oil is an attractive feedstock that can yield more valuable refined products than a barrel of conventional oil. Blair concluded that the oil sands were “a commercially viable source of crude oil that could compete on the world market.”

The plant was down, but Lloyd Champion was not out. In 1953 he began forming the Great Canadian Oil Sands consortium, based on his oil sands assets and his business acumen and drive. The Great Canadian Oil Sands consortium, which would later become the Suncor oil sands plant, included Abasand Oils, Canadian Oils Ltd. and Oil Sands Ltd. That effort lurched from crisis to crisis until J. Howard Pew got into the conversation. The chairman of Philadelphia-based Sun Oil Company, Pew soon became the primary financial backer of the project. The Great Canadian Oil Sands plant went into operation in 1967.

Champion sold his interest in the plant around the time it was being commissioned and, like Sidney Ells and Robert Fitzsimmons, died in 1971. As for the Bitumount site, it remained a place for oil sands experimentation and testing until abandoned at the end of the 1950s.

However, on December 4th, 1974 the province declared it a provincial historic site, and today it serves as an important interpretive centre and testament to Alberta’s oil sands pioneers. Its skeletal remains can be found in eight clusters. These range in interest from Fitzsimmons’ small cabin to primitive industrial equipment to garbage dumps and latrines. Bitumount may not look like much, but this is where the modern oil sands industry began. 

The Big Five

Canada's top conventional heavy oil producers in profile. This article appears in the 2011 Heavy Oil and Oilsands Guidebook

By Peter McKenzie-Brown

The five largest conventional heavy oil fields are roughly synonymous with the names of towns and hamlets along Alberta’s border with Saskatchewan. In order, they are Provost, Suffield, Lloydminster, Wainwright and Hayter – no surprise there. However, when you list the five biggest conventional heavy producers a big surprise does surface. The companies are CNRL, Husky Energy, Cenovus, Baytex and…Northern Blizzard.

CNRL (121,000 barrels per day): The biggest Canadian oil company, Canadian Natural Resources is also Canada’s single biggest conventional heavy oil producer. Any one of its top 10 producing fields – two of them produce 14,000 barrels per day each; six produce 9,000 barrels per day each – would make most companies happy. As the company’s website explains, its “crude oil is produced from very distinct assets, using different recovery technologies that are tailored to fit each unique reservoir.” Like Husky, most of CNRL’s conventional heavy oil properties and production are centred on the border town of Lloydminster. The 10 largest of these properties, which individually produce from 4000 to 14,000 barrels per day, collectively contribute 80,000 daily barrels to Canadian Natural's production.

Those projects are being dwarfed, however, by the company's polymer flood operation at Pelican Lake/Britnell which, like the Cenovus property, began life as a cold production operation before converting to waterflood. The company expects production from this field to soon plateau at 80,000 barrels per day.

Husky: At 75,000 barrels per day, Husky Energy is just off the top of the conventional heavy oil hit parade. The pioneer in Canadian heavy oil production – the company has been involved in the area since the 1940s – nearly 80 percent of Husky’s heavy oil production uses primary “cold” production in the Lloydminster area, where the company has a land position of more than 8,000 square kilometres. The remaining 20 percent of Husky’s heavy oil production comes from thermal recovery projects – notably its Pikes Peak SAGD operation. Also located near Lloydminster, the Pikes Peak project is in Saskatchewan.

Cenovus (36,000 barrels per day): The middle company in the line-up is Cenovus. The company has two producing properties which between them account for all of the company’s heavy oil assets. One is at Suffield, which produces about 12,000 barrels per day through conventional methods. More interesting is the companies Pelican Lake property, which produces about 24,000 barrels per day using polymer flood.

Baytex Energy (29,000 barrels per day): Number four in the line-up is Baytex, which generates the bulk of its revenue from heavy oil. According to corporate publications, heavy oil accounts for more than 60% of production and more than 70% of oil-equivalent reserves.

In some ways, Baytex is the odd man out in its conventional heavy oil production. Like the other companies, it has important assets in the heavy oil belt along the Alberta/Saskatchewan border – Ardmore/Cold Lake and Lindbergh on the Alberta side; Carruthers, Tangleflags, and Celtic in Saskatchewan. According to company spokesman Brian Ector, “Development in these areas consists of mainly vertical and horizontal cold drilling, as well as waterflooding at Carruthers.”

However, Baytex also produces conventional heavy from a property in the Peace River Oil Sands. This is unusual. According to Ector, “we developed Seal (the Peace River property) through the use of multi-lateral horizontal wells, and production in the third quarter of last year averaged 10,100 barrels per day. In addition to cold primary development, this year we are embarking on our first commercial cyclic steam stimulation (CSS) project at Seal – a 10-well module scheduled for start-up late in the year.”

Production is approximately 11° API, and the oil flows through “mile-long multi-lateral horizontal wells” from the Bluesky formation at depths of 600-700 metres. Given where it’s located in Alberta, “technically, this is an oilsands lease,” he observes; “it therefore qualifies for the oilsands royalty regime,” which much more attractive to the producer, since it equalizes royalties across all wells.

Northern Blizzard (15,000 barrels per day): A private company, Northern Blizzard pierced the top ranks of heavy oil producers by acquiring assets belonging to Nexen Energy last summer. The price was $975 million; the properties have proved reserves of 39 million barrels of oil equivalent.

The company doesn’t use waterflood or other specialized techniques to produce. According to the company’s chairman, John Rooney, production consists entirely of “cold flow production” – mostly in the Lloydminster area, and mostly from Saskatchewan.

The Outlook
For much of last year, the differential between the prices of Canadian heavy oil and Edmonton par, Canada’s standard for light oil, was very narrow. Indeed, for a brief period last May heavy oil producers were actually able to sell their heavy oil for almost the same price as light oil. This was an extraordinary event – very profitable for producers –and it wasn’t likely to last. It didn’t. At the beginning of 2011, the average difference between light and heavy oil prices had expanded greatly, to about $23. This significantly changed the economic outlook for the sector.

A number of factors have contributed to the widening of the differential. Most importantly, Canadian heavy oil differentials respond to competition at a small number of specialized US refineries. Other heavy oil producers – think Venezuela – also compete in those markets, and competition has picked up in recent months.

Canadian competition has been hamstrung by transportation problems: expanding pipelines to American markets has been slow, and Enbridge’s problems in Michigan have resulted in pipeline shutdowns for maintenance. This is curtailing existing capacity. The rise of the Canadian dollar to parity with that of the US has also contributed to a change in outlook for the Canadian heavy oil producer. The bottom line is that these producers are unlikely to find their conventional heavy oil operations as rewarding in the first half as they were a year ago.