"We Were Canadians First"

With the news of former premier Peter Lougheed’s death on September 13, aged 84, an outpouring of grief began throughout Alberta – indeed, throughout Canada. Rarely has a politician ranked so high in the esteem of the people he or she has been chosen to lead. 

This article appears in the November issue of Oilsands Review 

By Peter McKenzie-Brown

The tributes and commentaries ranged from reflections by ordinary citizens to formal commentaries from the great and the good. One of Lougheed’s biographers, Alan Hustak, observed that he was “the architect of modern Alberta” who, among many other achievements, helped turn the province’s petroleum industry into a global powerhouse. Nothing you can say about this great man seems over the top.

Lougheed’s career in the provincial Legislature began in 1967 – coincidentally, the year the Great Canadian Oil Sands (Suncor) plant was commissioned. The convergence is compelling, since several of his greatest achievements were oilsands-related. Energy issues dominated his years in power (1971 to 1985), and he was a decisive figure in what became known as Canada’s energy wars.

Among governmental issues, oilsands remained a core interest to the end of his long life. As he said in an Oil Sands Oral History Project interview 18 months ago, “After I left government in ’85 I said to my successor, Don Getty, ‘Don, I will stay out of most things you’re doing… but the one thing I am going to stay involved in is the oilsands, because I am very interested in its evolution and its development.…’ Things happened so quickly [under] Premier Klein. I have stayed involved in the oilsands in a more public way and I have discussed it frequently with Premier Stelmach as well. Perhaps more than any other, that’s the one subject I have stayed involved in since I left government.”

The Energy Wars: Lougheed’s early political battles began with a shot across the bow from Prime Minister Pierre Trudeau.

Inflation had become a national problem, oil prices were rising, and on September 4, 1973, Trudeau asked the western provinces to agree to a voluntary freeze on oil prices. Nine days later, his government imposed a 40-cent tax on every barrel of exported Canadian oil. The tax equalled the difference between domestic and international oil prices, and the revenues were used to subsidize imports for eastern refiners. At a stroke, Ottawa began subsidizing eastern consumers while reducing the revenues available to producing provinces (mostly Alberta) and the petroleum industry.

This outraged Premier Lougheed, who understood how long and hard the province had fought for control of its natural resources; resource ownership had not been conferred upon the province until 1930. In response, Lougheed announced that his government would revise its royalty policy in favour of a system linked to international oil prices.

His timing was impeccable. Two days later, on October 6, 1973, the Yom Kippur War broke out – a nail-biting affair between Israel and its Arab neighbours. OPEC used the conflict to double the posted price for a barrel of Saudi Arabian light oil to US$5.14. The Saudis and the other Arab states then imposed embargoes on countries supporting Israel, and oil prices rose quickly to $12. These events aggravated tensions among provincial, federal and industry leaders.

The rest of the 1970s were marked by rapid-fire, escalating moves and counter-moves by Ottawa, the western provinces and even Newfoundland. From 1974 to 1985, Ottawa imposed an export tax on conventional crude oil – a move Lougheed called “the most discriminatory action taken by a federal government against a particular province in the entire history of Confederation.”

Lougheed strongly asserted and ultimately resolved, beyond question, Alberta’s ownership of most hydrocarbon and other mineral resources within its provincial borders, and he made it clear to industry itself that the government was in charge. “It was obvious that the oilsands were owned by the people of Alberta,” he explained in the Oral History interview. “We consistently and constantly made sure that the industry understood that the Government of Alberta was the owner, and we weren’t just there in a supervisory or regulatory way. We were extensively involved because we were the owners.”

Canada’s political conflicts over energy climaxed with the introduction of the National Energy Program (NEP) in 1980. Lougheed led negotiations on significant modifications a year later, mainly exempting “new oil,” but the contentious policy was not fully removed until 1986. As the policy collapsed due to severe recession and wrong assumptions about global oil prices, Lougheed played a key role in negotiating a new constitutional agreement for Canada, then retired from office.

Syncrude: One of the positive developments of the energy wars era was the rescue of Syncrude in 1975. The oilsands project’s costs had soared, and one of its partners had pulled out. To a certain extent, that rescue involved a different way of looking at royalties. Lougheed’s interest in petroleum royalties began early in his years in power, before the events of the early 1970s embargo drove oil prices to historically high levels. “We were in a fairly experimental period with the oilsands,” he said, “we had the Great Canadian Oil Sands [project] which was struggling. When Syncrude came along and we got into the negotiations, it was clear we could not approach [the owner’s share] from the perspective of gross revenue….We had inherited from [Ernest Manning’s] Social Credit Government, a good system of royalties for the conventional oil and gas system, which was a percentage of gross revenue. We modified it from time to time in government, but the conventional oil and gas business was based on a percentage of the gross revenue.”

The oilsands were a different kettle of fish. Lougheed continued, “Right from the start it was clear that it wasn’t really fair because of the risk element that came with being involved in such a new process. You know, a lot of people wondered, was it going to work? Would it be economic?” All of those questions led to a discussion between the owner – the Government of Alberta – and Syncrude. ‘What kind of royalty scheme should we have?’ [The discussion] evolved into the whole question of a net profits approach. It was completely different than [the policy used for] the conventional oil and gas industry.”

The 1975 Winnipeg Agreement, which saved the Syncrude project, was one of the few moments of cooperation among governments during the energy wars. Always a savvy negotiator, during those 12 hours of meetings on February 1st, Lougheed committed the province to take a 10 per cent interest in the project for the then-mind-numbing sum of $200 million (about $1 billion in 2012 dollars). Alberta would provide loans that the province could convert into equity, would construct no-risk utilities for the project, and would purchase an ownership interest for cash. This proved to be an extraordinary investment for the people of Alberta, “the owners of the resource.”

AOSTRA: Through the formation of a government agency, Peter Lougheed created a scientific and technical environment that unlocked the secrets of producing bitumen from the deposits too deep for mining, and fundamentally transformed the industry itself.

At the time, work on the deeply buried oilsands reservoirs, which represent about 90 per cent of the resource, had stalled. Imperial had made progress on the Cold Lake deposit, but there were no demonstrated technologies that could commercially unlock deep oil from the Peace River, Athabasca or Wabasca (now seen as an extension of Athabasca) deposits. At the time, there was little likelihood things would improve. Few companies were actively developing oilsands leases outside the mineable area.

Originally called “Project Energy Breakthrough,” the idea was to speed up the development of new in situ oilsands technologies. When legislated into existence in June 1974, the Alberta Oil Sands Technology Research Agency (AOSTRA) became one of the largest research and development programs ever launched in Canada. The act originally limited AOSTRA’s activities to oilsands, but an amendment to the legislation soon gave the agency the authority to fund heavy crude oil research. In 1979, the Crown corporation’s mandate was expanded again to include enhanced recovery of conventional crude. Over its lifetime, AOSTRA funded about $1 billion (1980 currency) in oilsands extraction research.

Initially, the Alberta government agreed to invest $100 million in this technology development fund. During the active life of the corporation, however, AOSTRA spurred the petroleum industry to undertake numerous demonstration projects, representing some $2 billion of research and development spending. In most cases, the authority essentially agreed to match the amount of money a company or industry partnership was willing to invest in oilsands projects.

During the AOSTRA years, the industry launched in-situ demonstration projects in all the major oilsands deposits. These included cyclic steam stimulation (CSS); steam flooding; forward combustion; reverse combustion; and combined forward combustion and water injection (COFCAW). However, AOSTRA’s crowning achievement occurred 25 years ago, when its Underground Test Facility proved the effectiveness of steam-assisted gravity drainage (SAGD.)

Premier Lougheed got excited when he talked about SAGD.  “I think SAGD…should be encouraged by the owner and is being encouraged by the owner. It’s the longer-term asset for the province. Surface mining has its limitations, and involves more environmental and water concerns. So, there is a clear and important distinction when you get into oilsands and that’s what the Alberta Oil Sands Technology and Research Authority had been focusing on….Throughout all of our discussions here, let’s make sure that we are drawing a distinction between SAGD and in situ [those words can be used interchangeably] and surface mining.” Lougheed served on the board of MEG Energy, which was one of the first companies to develop a commercial SAGD operation.

Ideal Model: AOSTRA spurred oilsands experimentation and development, although prospects for further development diminished in early 1986 when a precipitous collapse in oil prices, once again, threatened commercial development. While AOSTRA did not have a mandate to undertake projects on its own, in the 1980s it took a significant risk by constructing the now-legendary Underground Test Facility. The UTF proved steam-assisted gravity drainage (SAGD), which has since emerged as the most important system for developing deep underground oilsands reservoirs.

A noteworthy footnote to this discussion is that the 2009 Summit of the Americas held AOSTRA up as an ideal model for energy development. According to the Centre of International Governance Innovation (CIGI), which sponsored the summit, AOSTRA “engaged the private sector and the university research community in developing technology related to the oilsands, while the government retained the rights to the technology.” A government endowment allowed the organization “to function independently of the electoral cycle. A dedicated expert and respected seven-member board of directors helped secure the private sector’s buy-in.” In addition, “control by the government helped maintain continuity over downturns in the economic cycle.”

CIGI also noted with approval that, before AOSTRA determined its goals, “it conducted two years of extensive consultations with many stakeholders. Only after determining exactly where the technology gaps existed did AOSTRA put out a call for proposals.” Furthermore, “aside from successfully developing new technology, AOSTRA fostered and financed a new generation of academic and scholarly expertise in many aspects of oilsands development. The investment in human resources is often discounted, but has been fundamental for the sector’s success in Alberta.”

Afterword: Much has been said about Lougheed’s impact on the province of Alberta. However, out of the seemingly endless stream of tributes that followed his death came this from former Prime Minister Brian Mulroney, whose government finally dismantled the National Energy Program. “Peter built the modern Alberta: schools, universities, hospitals, highways and whole communities [like modern Fort McMurray]. He always defended Alberta’s interests brilliantly around the federal-provincial table. At the same time, he would be the first to say…‘We were Canadians first.’”

Strategic Advantage

A coal-fired electricity generating facility in the US.

How regulation could help the oilsands reduce America’s CO2 emissions without damaging the economy

This article appears in the September issue of Oilsands Review 

By Peter McKenzie-Brown

An important policy paper about the oilsands slipped under the industry’s radar when it was released last June. Prepared by two Rice University academics – Dagobert Brito (an economist) and Robert Curl (a chemist) – the paper urges the US government to make it policy to import more Canadian crude, arguing the practice would reduce long-term greenhouse gas emissions. More immediately, it could benefit the U.S. economy and trade deficit, and promote energy security.

Yes, you read that correctly: Rather than a villain in the action pic, the oilsands could become part of the SWAT team. Refreshingly, Brito and Curl identified the oilsands as a high-powered tool for CO2 mitigation. In fact, making sure Canadian oil flowed south in greater amounts would be a “golden opportunity” to make the switch to greener fuels.

The diversion of oilsands crude to US Gulf refineries could be done in such a way that both the economy and the environment could benefit. Oilsands development could reduce the US trade deficit and ease economic pressure within the United States to produce coal-to-liquid fuels – the most carbon-intensive transportation fuels known.

“Canadian oilsands and the recent discovery of how to exploit the massive deposits of natural gas locked in shale… make it possible for the United States to reduce its dependence on fuels from outside North America without increasing carbon dioxide emissions,” according to the authors. “We propose that the US government develop policies that redirect our carbon usage, and thus our carbon dioxide emissions, away from the electricity generation sector toward transportation fuels by facilitating the development of Canadian oilsands, and offset the resulting additional carbon emissions by shifting the conversion of electrical generation from coal to gas.”

Misplaced Concern

The collaboration that led to this conclusion began about four years ago. Their collaboration, which has resulted in two widely praised technical papers, began with an off-the-cuff comment. During a conversation “Bob (Curl) said ‘If we didn’t have gasoline we would have to invent it because it’s such a valuable way of storing energy,’” according to Brito. Their discussions continued.

Both men are deeply concerned about the impact of carbon emissions on the environment – especially global warming. Their concern was to find ways to reduce carbon emissions without damaging the American economy. As they looked around the energy world, they saw that the United States was in a unique position to take steps that would reduce emissions.

One reality is that natural gas prices had collapsed as new technologies enabled producers to harvest gas from shale. One likely outcome is lower-cost gas for the rest of this century. Given that environment, they believe the first step the United States should take is to shut down coal-fired generating facilities, fueling them instead with natural gas.

According to Bob Curl, “The good thing about using regulation to require electrical generating facilities to switch to natural gas is that while these prices prevail it’s economic to do so. There is no transfer of funds to government. The regulation basically would be that you can only produce so much carbon per megawatt of electricity generated.”

“We believe concern about additional carbon dioxide emissions from Canadian oilsands production is misplaced,” according to their paper. “The strategic advantage of access to this resource far outweighs the extra carbon dioxide from its production, as this carbon dioxide can be more economically offset elsewhere in the economy.”

According to Curl, “people were opposed to the oilsands for reasons which seemed obscure to us. Many people in this country feel that having access to that much oil is bad because it takes the economic and strategic pressure away from our need to innovate technologically. The New York Times is very specific on this.”

Brito added, “Our position is quite different: It is very easy at the current price of natural gas to reduce emissions from electricity generation.”

“When we were preparing the first (of our two papers), we had some discussion about carbon taxes. Our opinion is that the carbon tax is counterproductive. It’s just a large transfer payment to government. It doesn’t actually reduce carbon emissions. Cap and trade would just result in more efficient coal-fired generating facilities having an advantage over the smaller operations, which would then shut down. It wouldn’t actually reduce carbon-generating activity. We have become advocates of regulation because no transfer payments are involved.”

More jobs would be created to deal with the increased flow of Canadian crude. In addition, according to their scenario, the U.S. would have more access to a secure energy source and the opportunity to burn off its abundant natural gas reserves instead of dirty coal.

Coal-to-Oil

The next step, they say, is to take whatever steps are economically feasible to forestall the conversion of coal into petroleum liquids. “All our calculations indicate that you can make money by converting coal to oil. The capital cost is where most of the money is. It’s a big chemical plant you have to construct,” according to Curl. Curl, the chemist, who explains the problem in graphic terms. “If you turn coal into liquid fuels, you generate 8/10ths of a ton of carbon dioxide for every barrel of liquid fuel you generate. If oil stays above $60 a barrel, oil from coal remains viable. However, as soon as you place a CO2 charge on that, it makes liquids unprofitable.”

The Energy Information Agency forecasts that coal-to-oil conversion will begin in 2020. “There is a lot of buzz about it in this country, yet we wonder why in the world anyone would want to do this. First, the petroleum business is more used to drilling than manufacturing. Second, they’re worried about the possibility of the regulation of carbon dioxide. And to make matters worse, the price of oil is quite volatile. As recently as 2008 oil prices drop below $35 a barrel.”

For environmental reasons, the two academics believe it’s important to discourage companies from going in this direction. However, they have couched their arguments in economic terms.

Of course, the imminent prospect of large-scale coal-to-oil facilities is becoming a bit of a straw man, since new technologies are increasing light oil production throughout North America. For example, in a recent research note ARC Energy’s Peter Tertzakian observed that, after having declined steadily for nearly four decades, in the last three years conventional oil production in Texas has risen from 1 million to 1.7 million barrels per day.

The Rice University academics take the position that Americans are fortunate to be importing oil from Canada. According to Brito, “we contacted some friends who are experts in trade theory. For every dollar of oil that American buys from Canada, we get $.50 back in trade.” In trade terms, this would make bitumen – already a low-cost petroleum resource – an even greater bargain.

“Petroleum is part of the world market,” he added. “We don’t have any illusions about whether oilsands oil will be exported. You guys (Canadians) are going to produce it, and to do that you have two choices. You can send it to the Pacific, or you can send it to the US. And if you send it to the US we can either use it to offset CO2 emissions or not. If you send it to China, they do not have the technologies and systems to use oil to offset CO2 emissions.”

The two academics believe the new pipeline from Cushing to the Gulf will take care of the problem of Canadian oil being bottled up. “The logical thing for Canadians to do is shift their oil to the Gulf coast and from there ship it out as finished fuel.”

Clean Coal?

“If (American governments) put these regulations into effect now, while the price of natural gas is low, they won’t disrupt the power generation industry.” Asked about the impact social policy would have on the coal industry, he said “I hate to put an entire industry out of business, and I wish that coal were clean, but it’s not.” Brito added, “We had to stay inside our area of expertise. Coal mining is simply not one of them. In our paper we couldn’t deal with those issues.”

More than 40% of electricity generation in the United States comes from coal-fired plants, and power utilities buy more than 90 percent of the country’s coal production. Converting electricity generation to natural gas is therefore not exactly a message the powerful coal lobbies in Washington want to hear. Just ask media vice president for the American Coalition for Clean Coal Electricity Lisa Camooso Miller. She worries that converting to other fuels would increase the price of electricity, disproportionately affecting the poor. Nor does she want to see jobs lost.

“We’re committed to ensuring that the future is a clean one, which is why the U.S. power industry invested more than $100 billion in clean-coal technology, reducing emissions by 90 percent in the last 30 years,” according to Miller. “Investments in clean coal technology will provide for the continued use of affordable and abundant coal as an energy source for America.” She added, “It’s important for this country to have a balanced energy portfolio.”

However, clean coal technologies essentially refer to advancements in reducing sulphur dioxide (SO2), nitrogen oxides (NOx), mercury and particulate matter discharges while burning coal. They do not reduce carbon emissions.

The coalition’s website refers to “the coal-based electricity sector’s work to develop and deploy new technologies to capture and safely store CO2 is also evidence of the industry’s commitment to expanding the use of advanced clean coal technologies.” However, it is worth noting that the only large-scale sequestration operation using carbon emissions from an American power plant takes place at the Weyburn field in southern Saskatchewan – an enhanced oil recovery project operated by Cenovus.

Although clean coal methods for removing sulphur, mercury and acids “work okay,” Bob Curl suggested that “schemes for sequestering carbon dioxide are fantasies.” Rather, America urgently needs regulation to “mitigate carbon dioxide sources.” Noting that coal is best understood through chemistry and thermodynamics, economist Bob Brito contends that with present technology there is no such thing as clean coal.

Concerned that a coal-to-liquids fuel industry could rapidly expand, resulting in greatly increased emissions, Curl and Brito believe the United States needs to reallocate resources within the economy in a way that is not likely to occur through market forces – regulation. “Further action will be required to offset carbon dioxide from alternative fuel sources.”

“Two things drove this paper,” Brito added. “One of them was the energy security of the United States. Having Canada right next to us is like having Saudi Arabia next door, except that it’s a Saudi Arabia which respects human rights.” The other was their concern about carbon dioxide emissions, and how that will affect the global environment. “When we looked at the numbers for different nations producing carbon dioxide, it was very clear that the Chinese were just running away with it. If the Chinese go to the same level of per capita CO2 generation that we have in the United States, that alone will increase global CO2 emissions by 50%.”

Briefly put, the two men were thinking globally and acting locally. Convinced that carbon emissions must not get out of control, they developed ideas that would influence emissions in the United States, the world’s second-largest emitter. That sounds like the best place to start.

The Best of the Best

Imperial Oil's Kearl project is poised to open, bringing "green" bitumen to the world. This article appears in the September issue of Oilweek 

By Peter McKenzie-Brown

Imperial Oil has been a big player since Canada’s petroleum industry began. With roots that go back to southwestern Ontario’s 19^th century oil boom, in 1947 the company kick-started the industry’s modern era with its Leduc discovery.

Not so well known is that Imperial has been the consummate pioneer in the oil sands business. In the middle of the last century, the company joined the Syncrude consortium, which in 1962 applied to the Conservation Board for approval to proceed with the Syncrude project. The final decision to proceed with Syncrude didn’t take place until 1975. By that time Imperial had developed the cyclic steam stimulation, which now drives its Cold Lake project. Not so well known is that, as part of its early Cold Lake experimentation, the company conducted the first tests on steam-assisted gravity drainage – the technology of choice for in situ recovery in the Athabasca deposit. Today, SAGD is the source of about half of Canada’s bitumen production.

The folks at Imperial are getting ready to do it again. When commissioned at the end of this year, the Imperial-operated Kearl oilsands project will process oil from a mine 70 kilometres from Fort McMurray. Unlike all the other mine-based projects up there, however, Kearl won’t produce high-carbon oil. Indeed, the product flowing into American refineries will produce no more carbon emissions than those produced by the average barrel now refined in the United States.

The Kearl project is huge. When it reaches full capacity of 345,000 barrels per day around 2020, it will be one of the world’s largest sources of crude. And it will produce low-carbon bitumen for 40-50 years. It will achieve this apparent industrial miracle through advanced oil sand processing techniques and the production of diluted bitumen which doesn’t need to be upgraded. A significant later add-on will be power from energy-saving cogeneration for the provincial power grid.

Imperial’s long experience in oil sands development and management – not least as a charter member of the Syncrude consortium – means the company has depth and breadth of experience. According to Kearl’s designated media spokesman, Pius Rolheiser, “The project will use the best of the best technology.” One of those “best technologies” is high-temperature paraffinic froth treatment (HT-PFT).

Paraffinic Froth: To understand the oil sands revolution Kearl represents, you have to understand froth treatment. “After oilsand is mixed with hot water to liberate the bitumen from the matrix of sand, water, silt, and clays, the bitumen is separated from the resulting slurry,” science and technology writer Diane Cook explained. “In a flotation vessel, the bitumen is removed as a highly viscous mixture of oil, mineral solids, and water called bitumen froth. The froth is then diluted with a hydrocarbon solvent to reduce its viscosity and enhance separation from the emulsified water and solids.”

The earliest plants mixed oilsands with hot water and naphtha in a separation vessel to separate the bitumen from the water, sand and other wastes associated with the ore. The facility skims the froth from the top of the vessel to get a product for further processing. The problem with this approach is that the resulting bitumen blend can contain as much as 3.5 percent sediments and other impurities, which require further processing and upgrading before they can be transported in a regular pipeline.

The key to Kearl’s low-carbon achievement is to use paraffin rather than naphtha. Originally developed by Syncrude in partnership with NRC’s CANMET Energy Technology Centre in Devon, Alberta, high-temperature paraffinic froth treatment removes only lighter hydrocarbons from oil sands ore, leaving undesirable asphaltenes behind. Asphaltenes carry most of the very fine solid particles (“fines”) that create tailings pond nightmares for older plants. According to Rolheiser, through this process “we can return them as waste to the mine.”

Asphaltenes consist primarily of carbon, hydrogen, nitrogen, oxygen, and sulfur, as well as trace amounts of vanadium and nickel. Heavy, gunky hydrocarbons, they contain almost as much carbon as hydrogen. Thus, in the typical refinery, asphaltenes are a low-end product with few uses beyond road pavement and roofing tar. The fewer asphaltenes you pipe into the refinery, the more high-end products the refiner can ship out after processing.

As Cook explained when a Shell-patented version of the process went into use at its Athabasca Oil Sands Project, paraffinic froth treatment “produces a much cleaner, diluted bitumen product that contains less than 0.1 per cent residual water and solids. In this process, the contaminants are readily separated by gravity, without the need for energy-intensive centrifugation, and the light aliphatic solvent is easily recovered from the diluted bitumen without the use of a lot of heat…. As a result, the bitumen has a lower viscosity, which allows the bitumen to be transported by pipeline to upgraders or directly to market with a small amount of diluent added.”

It is in this area that the Kearl project is revolutionary. Although Shell recently applied this process at existing project, Kearl will be the first oilsands mine constructed entirely without reference to an upgrader. According to Rolheiser, “Kearl bitumen will be somewhat lighter than the other marketed diluted bitumen produced in the oil sands.” This is possible because of the higher-quality oil produced through paraffinic processing.

Proposal, Budget, Expansion: This project has been a long time coming. Mobil Canada acquired Lease 36 – the oldest of the leases – in 1952. Imperial acquired lease 87 in 1989. A decade later Imperial and Husky Energy bought lease 6. Once the two companies had the property in their collective hands, Imperial took the lands amenable to surface mining while Husky took the sections that were better developed through in situ technologies.

 Mobil made the first proposal for a Kearl mining and upgrading project in 1997, to be based on lease 31A – an adjacent lease that plays a smallish role in today’s Kearl project. After the 1999 merger of the two majors that gave ExxonMobil its name, the international giant holds 100% of the mining rights to leases 36 and 31A and a 30% interest in the project.

Rolheiser said his company’s affiliation with ExxonMobil has played a key role in project development. Through that storied giant, “Imperial has access to global technologies, assets and expertise. They have executed multibillion-dollar projects all over the world. They have an unprecedented research capability. Our affiliation with them gives us a lot.” Not only did ExxonMobil bring patents and engineering ideas to the table. “It also enabled us to leverage our own expertise.”

Imperial originally conceived Kearl as a three-phase development in its original proposal, with each phase producing about 110,000 barrels per day. It was that project that Imperial began scoping out in 2004/5, with the company then presenting its regulators with a cost estimate of $8 billion for phase one. Estimated costs later rose to $10.9 billion for that phase.

According to Rolheiser that’s because “As we got into the execution of the project (in 2011) we realized that there were some facilities that we didn’t need to duplicate, and in fact we could make the surface footprint somewhat smaller. So we re-configured the project into two phases (instead of three). So, what we’re building today for $10.9 billion is a different development than what we had envisioned building for $8 billion. It includes additional investments in things like tailings management to meet ERCB Directive 74, and regional pipelines (that we hadn’t originally planned for).”

The company plans to begin construction of the expansion phase, for which it has budgeted $8.9 billion, in 2015. After construction and debottlenecking, the full project will be on stream at the end of this decade. The project encompasses a 4.6 billion barrel resource, and Imperial expects initial development costs to total about $6.20 per barrel.

Rolheiser added, “We can now get to our license capacity of 345,000 barrels per day, which was our target when we originally envisioned the project. We’re just going to get there in a different way.” Kearl will operate near capacity for 40 to 50 years, so “commodity prices are likely to have a minimal impact on our planning. For projects like Kearl we really do take a very long view of things. We aren’t even thinking about year-to-year prices. Our current expansion plans are not contingent upon approval of any particular pieces of pipeline infrastructure. They aren’t dependent on whether Gateway goes ahead.”

Well-to-Wheels: According to a 2010 report by IHS CERA, a highly respected American think tank, the Kearl project will result in life-cycle greenhouse gas emissions similar to the average of oil refined in the United States. In Brussels last year, the Jacobs Consultancy, an international firm, gave a report to the Centre for European Policy Studies in which it reached the same conclusion.

These reports differ so markedly from those used by environmentalists because they compare full lifecycle emissions. If you want to make apple-to-apple comparisons of crude oil sources, this is an important concept. True well-to-wheels, calculations account for GHG emissions associated with every stage of a product’s life: extraction, processing, refining, distribution, and use. The IHS CERA and Jacob’s reports add those emissions, for example, to the product’s total. Adding these factors into the equation dramatically changes the GHG estimates.

The case of Nigeria’s Bonny Light oil is dramatic example. During refining, this high-quality oil (35° API with negligible sulphur content) produces relatively low levels of GHG emissions. However, the country’s practice of flaring associated gas during oil production hugely increases the lifecycle emissions of its exports. According to the Jacobs report, in recent years Nigeria has flared 27 cubic metres of natural gas for every barrel of crude it produced. This is the main reason that Jacobs’ full cycle calculation showed Nigerian light crude producing 7% more GHG emissions than the average slate of oils refined in the US.

Well-to-wheels GHG emissions for oil sands and conventional crude oils (kgCO2e per barrel refined products)
Crude	Well-to-retail pump	Well-to-wheels	% difference from average US crude consumed
Canadian oil sands: mining dilbit (Kearl)*	103.6	487.6	0
Average US barrel consumed	103.1	487.1	0
Average oil sands imported to US (2009)	133.5	517.5	6 %
California heavy oil	165.6	549.6	13 %
Nigerian light crude	135.2	519.2	7 %
Canadian heavy oil	82.6	466.6	-4 %
Venezuelan partial upgrader	157.6	541.6	11 %
West Texas Intermediate	54.6	438.6	-10 %

(Source: IHS CERA.)

By contrast, the Kearl project will produce GHG emissions that are virtually identical to those of the average barrel refined in the US, whether you are measuring those emissions at the retail pump or a vehicle’s exhaust (both marked in red on the table).

If you take the chart too seriously, it may seem that only WTI and Canadian heavy oil are greener sources of oil from a GHG perspective among the crudes listed in the table. However, it is worth noting that Canadian and Brent light oils, for example, are not listed. This illustrates the importance of comparing Kearl production to the average slate of oils refined in the US.

Of course, if it is fair game to add emissions from flaring natural gas in the Nigerian calculation, it is also reasonable to deduct them if a producer can make a credible case that its production practices actually offset GHG emissions. The Kearl project does this in two ways.

For one, it was designed without an upgrader – traditionally, a major source of GHG emissions for oil sands mines. Using paraffinic processing makes this possible: just mix the higher-grade bitumen with diluent and ship it by pipeline to an existing refinery. To put the significance of this innovation into context, consider that exports to the US from many countries will become more carbon-intensive as national oil companies export increasingly lower-grade crude – a phenomenon known as “the blackening of the barrel.”

The IHS CERA study forecast that “new mining projects without upgraders (like Kearl) will increase (American) imports of lower-carbon oil blends.” In 2030, the report suggested, “the average carbon intensity of oil sands blends (will) remain about the same as today.” This could mean that Kearl oil will become less carbon-intensive than the average refined in the US.

Kearl’s other big carbon-lowering tool will be the use of cogeneration. Environmentally and economically efficient, cogen involves the simultaneous production of electrical power and heat from a single fuel source. The oil sands industry has used cogen during bitumen production since the 1970s, so the practice is not new. In the quest for reliable self-sufficiency in power, all new mining facilities since then have used cogeneration, though generally aimed at little more than supplying their own projects.

Imperial will also install gas-fired cogeneration units at Kearl, selling some of its production into the grid, though details are still sketchy. According to Rolheiser “They will be added to the operation as a separate project (before 2020), but not as part of initial plant development.”

As the Kearl project moved through the approval and construction phases, most media discussed the project in the context of an anti-Kearl lawsuit from an environmental coalition (Imperial won the case), and concerns within the US about transporting huge modules on state highways. The pity is that, in general, they are unlikely to cover Kearl as an environmental triumph.

A Numbers Game

Photo from here; this article appears in the September issue of Oilweek

For Devon Canada's Cal Watson, coaxing maximum output from heavy oil and bitumen deposits is all about optimizing your operating metrics

By Peter McKenzie-Brown

For Cal Watson, it’s all about the numbers, but here’s one number he doesn’t mention. Devon Energy Canada is number 3 on the 2011 list of Canada’s Best Workplaces (those with more than 1,000 employees). It’s the third year in a row Devon’s been on the list, and it’s the only oil company to be found there. The numbers for this list are crunched by an international research and management consultancy.

The articulate and motivated vice president of thermal operations at Devon Canada is more concerned about other numbers: “In every measurable metric – land use, water use, air, operating expenditures, plant on-stream time, production – our focus and philosophy is to be a top-decile company.” He then cautions, “You can focus on one or two (numbers) and sacrifice the others. We aren’t willing to do that.”

You need to be wary of this kind of statement; it’s often the voice of a company delivering its “messages” to a reporter. Indeed, at the risk of presenting an unpardonable groaner you might say, “elementary, my dear Watson.” However, as we discuss the details of Devon’s Jackfish SAGD projects, it soon becomes clear that in the area of thermal operations Watson is serious indeed. The exciting part is that his numbers represent a sophisticated integration of production into a shrinking environmental footprint.

Background

Born near the heavy oil centre of Lloydminster on a mixed farm in Saskatchewan, fifty-year-old Watson seems almost destined to find himself operating in heavy oil and the oilsands. He earned his B.Sc. in engineering in 1985. On graduation he soon found himself doing reservoir engineering for Husky Energy – far and away Lloydminster’s largest oil industry employer and at the time the largest conventional heavy oil producer in Canada.

As part of a move toward greater centralization, after Husky’s acquisition of Canterra Energy he was transferred to Calgary in the 90s. His new assignments included more work in reservoir engineering (including duties in deep Foothills gas) and three years as a gas marketer.

He was then lured into the employ of Ulster Petroleum, a junior, but found his career buffeted onward by still more corporate acquisitions. Anderson Petroleum bought Ulster. Then Devon bought Anderson. He thus found himself working for one of the relatively few North American oil producers not headquartered in Houston or Calgary. Devon is based in Oklahoma City.

As these events unfolded, Watson began receiving promotions into managerial positions – Central and Southern Plains with Anderson; then, with Devon, combined responsibility for the Foothills Division and a highly technical reservoir engineering group. In 2008, he moved into thermal heavy oil. For the first time, he shifted from exploitation into an operations role with appointments as thermal heavy oil operations manager and, recently, vice president.

He focused on the interrelated issues of “increased operability and reliability.” To illustrate his concern, he notes that in Calgary “we take reliable power for granted because we are part of a grid. (In northeastern Alberta) you have one power line to a facility. The line goes down and that’s all you’ve got; the facility may need to shut down. We are constantly looking at ways to increase reliability. Improved reliability and operability are the fundamental building blocks of a more efficient process. They increase efficiency.”

Jackfish

As an operations guy, Watson found himself with responsibility for Jackfish 1 – a SAGD project that started steaming in August 2007 and began producing at the end of that year. For the first five months of this year, the project’s uptime was a remarkable 98%.

Designed to produce 35,000 barrels per day, in recent months for brief periods it has produced up to 37,500 barrels per day. Until that happened, did he actually think the equipment used in that project could exceed design capacity? Of course. “The equipment is subject to whatever SOR (steam/oil ratio) you can achieve. If you can get an SOR lower than 2.65, you have the opportunity to produce more barrels. The front-end capacity of our facilities is up to 50,000 barrels per day. If we can get the SOR down to the 2.4 range for example, we could certainly hit 40,000 barrels per day production.”

As always, it’s all about the numbers.

When Jackfish 1 went on production it quickly became a big part of the company’s production portfolio. At this writing, Devon Canada produces about 195,000 barrels of oil equivalent (BOE) per day. Jackfish production contributes about 18% of the total. Capital expenditures for the project (including start up) were $620 million – about $18,000 per daily flowing barrel. Today those numbers seem pretty bargain basement.

Consider, for example, that Devon’s sister project, Jackfish 2, involved capital spending of $1 billion. Jackfish 2 started steaming in May of this year. When production reaches design capacity next year, the facility will represent another big piece of Devon’s production portfolio. With Jackfish 2 on stream, Devon Canada’s total production will be 230,000 BOEs per day, and the combined Jackfish projects will represent 30% of the total.

The disparity in costs notwithstanding, Watson says the major components of the two Jackfish projects “are exactly the same. However, for Jackfish 2 we took 1,100 changes into the design – changes related to instrumentation and valving, for example, and measurement points.” Those changes were clearly not made to cut costs; their aim was to “increase operability and reliability.”

While capital costs are up, other expenses are down – notably fuel gas prices since Jackfish 1 went on stream. Even so, the company is constantly focused on better heat integration. “That means you conserve heat, putting it at the end of the plant where you can preheat the water going into the boilers. That way you need less fuel gas to generate steam; it gives you a better fuel efficiency number.”

Fuel prices excluded, operating costs for these projects are only $7 per barrel of production. In addition, there are some economies of scale in having two similar projects 5 miles apart on stream at the same time. There is little sharing of labour at the field level. Each facility has 85 dedicated staff in its own camp. From a district level, however, the two projects benefit from shared services. Watson rattles him off: “Camp (the company will soon house most staff in a single camp), safety, asset integrity, transportation and procurement.”

 

Devon has plans to add Jackfish 3 to its oilsands collective; the company made its submission to regulators a year ago. Today the company is in the detailed engineering and design phase. “We have done procurement for long-lead items like steam generators and long-term contracts have been let,” Watson says. “The kit’s being built. We expect approval at the end of this year or in early 2012.” If all goes according to plan, the project would start steaming in late 2014 or 2015.

Staying the Status Quo

Throughout the technical part of our discussion, Cal Watson was upbeat and focused. However, when we turned to environmental questions something new entered the discussion. It was almost as though the issues became personal. We began by talking about water policy. “Our goal is to meet and exceed regulatory thresholds,” he says, and in this there is nothing new. Then he adds, “Staying the status quo means you are falling behind. Reducing our footprint out there makes a difference.” This seems real.

On Devon’s corporate website, however, there is an article about the company’s decision to use saline water for steam generation. I find the article a bit misleading, because it neglects to mention that using potable water really isn’t an option for SAGD projects. I put the question to Watson, who confirms that using “saline water has not been a significant problem for us at all.” But, he adds, “Water usage as a whole is a sensitive issue.”

According to Watson, when Devon began planning for the project CEO Chris Seasons challenged the design team “to come up with a design that would use no potable water at all. We sent our hydro-geologist out to drill for water and he came up with good source that was saline, so our design team looked for ways to remove solids, hardness, remove magnesium and calcium and do whatever else we needed to do to make it adequate for steam gen. From the beginning, we set our minds to doing that.”

To appreciate the challenge the company faced, consider that regulators define potable water as water with dissolved solids of 4,000 ppm (parts per million) or less. That is setting the bar high for potability – water for human or agricultural use. “We have a source that’s 6,500 ppm,” Watson continues. “Our facility works fine on that. We have also found a higher concentration source (on the property. We did a 6-week test with 12,000 and 14,000 ppm, and that worked just fine, too.”

While Devon may have had little trouble with using saline water, its peers have recognized the company’s efforts. On two occasions the company received water-related CAPP awards. One was a stewardship award for its use of saline water at Jackfish. The other was the CAPP President’s Award for its elegant water policy. This masterfully concise document presents comprehensive policy in eight bullet points.

Wolf Packs

CAPP also presented the company with an environmental performance award for reducing the width of access roads in forested areas and for using waste wood in road construction. Not only has the company has reduced its seismic right-of-way in the forest. The company mulches up waste from the cuts and puts the mulch back on the right-of-way. “In a year or two you can hardly recognize we were ever there.”

This is important because traditional seismic lines present wolf packs with a combination of fast pathways through the bush and line of sight to their prey. To level the playing field, Devon “is adding a saw-tooth every 300 metres to eliminate line of sight and narrowing the right-of-way. Going to hand-cut seismic takes away the ability (of predators) to move quickly through the bush.”

Devon plans to use “less than 15% of our leases during our development – never more than 15%,” according to Watson; “Our goal is to reduce that down. (We will do that through) progressive reclamation of seismic lines and well pads over the full life of the project. As the older pads start to decline, we bring on new pads.” Using that strategy, he calculates that each Jackfish project can “hold production flat for 15 years plus.”

He has other ideas for narrowing the footprint, one of which involves the use of solvent. “We want to try injecting it with our steam. Solvent could increase the size of the steam chamber when it mixes with the bitumen. If solvent enables us to expand the size of our steam chamber, that allows us in the future to push those inter-well spacings out, so we have to drill fewer well pads, or can drill longer horizontal wells and fewer of them.” It could also increase recovery, which is already 65%.

Like the oilsands industry itself, Watson is keenly optimistic about the growing ability of technology to mitigate the environmental impacts of oilsands production. “There are a lot of bright minds out there focused on creating technological advances that simultaneously reduce the footprint and increase production,” he says, citing horizontal drilling and MWD (measurement while drilling). “These have been huge technological developments – they mean we can lower our impact by drilling out as a crow’s foot.” Then there is “a ceramic membrane technology to improve fluid separation, (thereby presenting the) opportunity to develop much greater recovery.” He would continue, but this reporter’s mind by now is overflowing.

If Cal Watson has one big idea, what is it? Perhaps it’s all about numbers. While he provides endless detail about the Jackfish projects, to explain the challenges those projects are facing he constantly comes back to simple metrics – numbers that influence both production and the footprint.

Don’t forget: “You can focus on one or two (numbers) and sacrifice the others. We aren’t willing to do that.

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.

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.