Maintaining the Faith

Five visionaries who changed the path of the oilsands industry, and the wall over which the sixth must climb.Photo: Karl Clark

This article appears in the September 2010 issue of Oilsands Review

By Peter McKenzie-Brown

Oilsands development continually hits a wall of some kind, and obstacles to development seem insurmountable. However, at critical times in the history of the oilsands, a visionary leads the charge over the wall and an important new stage of development takes place. This is the idea behind an excellent presentation titled “Visionaries – Climbing the Wall” given by Dr. Clement Bowman. The present commentary develops that idea, but mostly uses different historical resources.

By the 1920s it was clear that the sands are not underlain by a huge pool of light, source oil. The oilsands are just what they appear to be: huge deposits of sand saturated with thick, gunky bitumen. Encouraged by government, some entrepreneurs tried paving roads with the stuff. No luck; now what?

Enter a research chemist Bowman’s first visionary. With tremendous determination and limited support from the newly fledged Alberta Research Council, his employer, between 1923 and 1930 Clark developed and demonstrated the bitumen extraction process which, with some tweaks, is in use today in oilsands mines. His work made it clear that oil can be extracted from the sands. His name was Karl Clark.

Over the next two decades a few small projects began producing. They were not commercially successful, however, and didn’t use Clark’s extraction process. Each was eventually destroyed by fire. After the Second World War there was no commercial interest in this intractable resource – especially after the 1947 Leduc discovery, which made it clear that large reservoirs of light oil were available in the province.

Despite the legacy of failed commercial efforts, a Canadian politician became the next visionary. He arranged for the province to commission the Bitumount demonstration plant using Clark’s hot water process, and had the entire legislature visit the plant in 1949. He also commissioned an independent evaluation by Sidney Blair – an oilsands expert who began his oilsands career as Karl Clark’s research assistant. Blair concluded that the oil sands were “a commercially viable source of crude oil that could compete on the world market.” The visionary’s name was Ernest Manning, Alberta’s longest-serving premier.

The industry acquired additional oilsands properties and undertook experiments in mineable oilsands development in the 1950s and 1960s. For his part, Manning maintained a life-long belief in the importance of the sands to Canada.

In the 1960s, Alberta announced that it would only approve small oilsands projects. Light oil production was still growing, and the province didn’t want too much competition between oilsands and conventional oil. The province’s insistence on small-scale projects led to thin private sector support.

The visionary who surmounted this obstacle was an octogenarian and a personal friend of Premier Manning. On his insistence, Sun Oil Company filed an application for a 31,500 barrel per day project (later amended to 45,000 barrels per day). In 1967, he told his audience at opening ceremonies for Great Canadian Oil Sands that “No nation can long be secure in this atomic age unless it be amply supplied with petroleum . . . . It is the considered opinion of our group that if the North American continent is to produce the oil to meet its requirements in the years ahead, oil from the Athabasca area must of necessity play an important role.”

The name of this visionary is J. Howard Pew, and he was then chairman of Sun Oil Company, Today, GCOS is known as the Suncor Oilsands Plant.

In 1973, a second commercial project was losing private sector support because of the alarming escalation of costs besetting major North American projects. The Syncrude budget had more than doubled to $2.3 billion, and a major corporate partner pulled out. One man more than any other saved the day. He kept the remaining partners onside while marshalling equity participation in the project from the Alberta, Ontario and federal governments. He set up the first lab dedicated to oilsands research, and developed a long-term plan for upgrading bitumen. He was Syncrude’s first president, Frank Spragins.

In the 1970s, multinational companies had few active development plans for in situ leases. While these deeper deposits represent 80 per cent of the resource, there were no viable in situ technologies for the Athabasca, Peace River, Carbonates, or Wabasca deposits. The major exception was Imperial Oil, which was making limited progress at its Cold Lake site.

Once again a provincial politician took the lead. In 1975, he created the Alberta Oil Sands Technology Research Authority (AOSTRA) to provide government support for private research. During its 15-year life, AOSTRA provided $670 million of funding for oilsands research. Roger Butler’s SAGD process was the single most important advancement from this program. The politician? Premier Peter Lougheed.

Visionary number six has the opportunity to change Canada over this decade, leading the shift to production of cleaner, higher-value products from the oilsands.

There are more major obstacles, they are here and now, and they are environmental. Water, air and land are no longer free; there is a powerful green consciousness demanding that they be protected. Many consumers do not want to use products manufactured from Alberta’s “dirty oil.” Financial markets are concerned about the burden of environmental risk.

Who will help the industry overcome these obstacles? According to Clem Bowman, the next visionary will be able to articulate energy as an integrated system with the oilsands, hydro, natural gas, coal, nuclear and renewable energy all performing key roles. As importantly, that person will have the skills to forge the national will to make Canada a sustainable energy superpower.

Bowman does not conjecture on who this person might be,but his or her name will be marked in history.

He Rocks

 Former "coker rat" Byron Lutes plays the guitar, rides a longboard and - oh, yeah - is leading a serious oilsands contender

This article appears in the August issue of Oilweek.

By Peter McKenzie-Brown
I didn’t expect the answer Byron Lutes gave me when I asked what kinds of books he reads. “I read a lot,” he said. “Just last night I finished When Giants Walked the Earth, by Mick Wall. It’s a biography of Led Zeppelin. It was great.” The choice surprised me. As we talked, however, the title seemed increasingly fitting. Surely if there’s an industry dominated by giants it’s the oilsands, yet here’s a guy leading a small company who wants to become a leader in the game.

Lutes has a ready smile and a lot of confidence in what he’s doing – turning the two-bit shell of a VSX (Venture Stock Exchange) company into a serious oilsands contender.

A chemical engineer by background, the athletic president and chief executive officer of Southern Pacific Resource Corp. graduated from the University of Calgary in mid-1986, just as oil prices collapsed from $30 per barrel to $10 and layoffs within the industry became the order of the day. “Only two of about 50 graduates in my chemical class got jobs after graduation.” Byron Lutes was one of them. As a student he’d worked at Suncor during previous summers, and the company wanted to keep him on.

Instead of getting the typical new hire’s tour of the company, though, he found himself working for Suncor just as it became immersed in labour strife. Employees at the oilsands plant had gone on strike, and he was shipped off to Fort McMurray to help operate the upgrader. “I was a coker rat,” he says. “I was swinging valves and cutting coke. It was a dirty job – all-night shifts – but I loved it because I got to learn a lot coming right out of school. I spent eight years at Suncor, doing various things. I did reservoir engineering and a year and a half stint in marketing. It was a terrific company to work for, and I got a lot of great experience.”

When he was 30, Lutes’ romance with junior oils was about to begin. “One of my former bosses, Sid Dykstra, had set up a company called Newport Energy and he asked me to join him. The company was making about 2,200 barrels of oil a day. Over the next seven years we grew it to about 30,000 and then sold out to Hunt Oil.” He stayed with Hunt for the next three years, running their Canadian operations. “That was a complete change, going from a grassroots, publically traded Canadian company to a private, very large American one. I knew I wasn’t going to stay.”

In 2002 he went to work for ManCal Energy, a privately-held company owned by Calgary’s Mannix family. “We were always growing stuff, developing it and selling it to take a profit. That was part of our game plan. We didn’t want to build up the staff complement, which was about 20 people. ManCal was another really good company to work for.”
 
Food chain
After five years with ManCal, Dave Antony – the chair of Southern Pacific Resource Corp – approached Lutes “out of the blue” to run the company. “It’s been quite a ride. (The company) had a bunch of land in the oilsands and some exploration programs, and they needed someone to come in and lead it.”

Though the oilsands are an area where giants generally do walk the earth, Lutes sees a lot of opportunity for junior oilsands companies. “Smaller companies can move their projects forward faster, from a regulatory, financial, and execution standpoint,” he says. “They can exploit areas that a larger company may have overlooked. They (can) attract and retain top entrepreneurial expertise. There will always be room for different sizes, as in any industry, and the food chain will also likely always be there.”

The story of the resurrection of Southern Pacific illustrates two quite different business models that are part of the industry’s food chain. The company, which has an undistinguished pedigree, was first traded on the old Vancouver Stock Exchange as New Wellington Mines Limited, in 1953. According to Lutes, “Dave (Antony) and his associates find shell companies, clean them up, recapitalize them and put in a management team.” That’s one part of the food chain.

A private company known as Bounty Developments Ltd. illustrates another. Bounty’s “modus operandi is to get land positions and turn them over to another company, keeping an override on the land. They’ve been very successful with that. We made a deal with them, met some work commitments and acquired 219 square miles of land (sections) in the oilsands, most of it raw acreage. We earned an 80 per cent interest in the property.” Southern Pacific has since expanded its oilsands acreage, and now has an average 81 per cent working interest in 301 sections.

To play in the oilsands you need lots of money, and institutional investors in particular won’t touch a company listed on the Venture Exchange – too much risk. Southern Pacific needed to move to the Toronto Stock Exchange, and that required cash flow.

To get there, the company issued equity and took on debt to acquire Senlac, a Saskatchewan heavy oil property producing 5,000 barrels per day. The price was $90 million. “As soon as we had that we were a going concern, and it enabled us to advance to the TSX. That means more due diligence, but a lot more investors now will put their money into the company.” The company began trading on the TSX in June.

SAGD-able
To look to the company’s future, you need to first look a bit deeper into its recent past. When Lutes took on the president’s role at the beginning of 2008, the boom was still around, although it had been soured by Premier Stelmach’s ill-considered and now largely defunct “fair share” royalty revisions.

“When I first joined we were getting ready to start up a major winter drilling program. The company had in the neighbourhood of $60 million in the bank, and we had a lot of core holes to drill but the market was getting choppy. So we were lucky enough – and (chairman) Dave (Antony) was smart enough – to realize it may not be easy to raise equity in the market, so we really conserved our cash.” Lutes pulls out a map. “We cut back on our drilling program but were lucky enough to find in this McKay block a significant resource that we thought could support a good SAGD project. We focused and drilled into this area and found ourselves a project.”

The company’s first oilsands production will come from two pieces of land separated by the McKay River. Especially when he talks about the first of these properties, Lutes gets visibly excited. “It’s a great property to sink our teeth into as our first green-field Athabasca bitumen SAGD project. The reservoir has all the properties you need to make SAGD work, no complications like top gas or bottom water or shale compartments, and this one can use a proven technology.”

He stresses that you shouldn’t “risk the company by using unproven technology. Let the big guys figure that stuff out. We know that SAGD will work. Reservoir thickness ranges from 15 metres to about 30 metres. It’s definitely SAGD-able.” Oil saturation in the reservoir ranges from 70-80 per cent with an average of 75 per cent, he says. The reservoir “is not as thick as some properties further south” like Suncor’s Firebag project. “However, it’s a great property.”

At the low point in the financial crisis, last year Lutes’ team prepared a SAGD proposal for submission to the ERCB. “We designed a 12,000 barrel per day project for two reasons. From a regulatory perspective, it’s the fastest way to get onstream. If you make a proposal for more than 12,600 barrels (2,000 cubic metres) per day, approval takes another year. That’s the first reason. The second is that if you develop a smaller project, you can use standard equipment. Other companies are using the same pots and pans as we’ll be using. That gives us better control of our capital costs, since that equipment is made locally. We don’t have to go to international manufacturers.”

As for expansion and timing, Lutes is characteristically optimistic. “We think we’ve got enough resource to expand. We have contingent resources, and we think we can grow our capacity up to the 36,000 barrel per day range” within two years of construction of the first project. “Our first project is going to be steaming up at the end of 2011, and on full production by 2013. We think we can expand to the east side of the McKay River and also expand the original project on the west side. We hope to have applications in by the middle of 2011. Based on our recent experience, the applications take about 14 months to process.”

The cost of the initial project will be about $428 million. For Phases 2 and 3, Lutes estimates $380 million. “The difference is that infrastructure costs for the next phases will be lower once we are in the area.” Southern Pacific will use cash flow from Senlac in Saskatchewan and from McKay to fund growth in other oilsands leases.

Longboarding
Outside the office, Lutes is both musical and athletic. He’s had an interest in rock music since he and some friends started up a rock band in high school: “I played bass and sang.” The guitar playing is something his three sons – Cory, 19, who is studying engineering at UBC; 11-year-old Kyle; 9-year-old Dylan – have all taken up.
His wife Kathy and he are heavily involved with soccer with the younger boys. Formerly an accountant with TransCanada, she is now a full-time mum and treasurer of her kids’ soccer club. I ask about hockey. “We absolutely love hockey. We watch it religiously but we don’t play it. The reason is that we have a genetic problem,” he deadpans. “We can’t turn right on skates.”

He can turn right on the longboard, however. Essentially a surfboard with wheels, these long skateboards can measure 1.5 metres in length, and good riders can perform complex tricks on them. “I took up longboarding this summer,” he says. “Longboards really cruise. My kids have them, and they are a lot of fun. I figure if the kids want to use them, I might as well go boarding with them. I play basketball with them, too.”

How do you sum up Byron Lutes? A guitar-playing businessman, a longboarding engineer, an executive hooked on rock concerts. Too bad he can’t turn right on his ice skates.

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Low-Carbon Recovery

CO2 based theories of global warming need to be balanced by consideration of other ideas. This chart, which came off the Internet, illustrates an important opposing idea.

By Peter McKenzie-Brown

There are a number of people like Harold Nikipelo out there. The president of Edmonton-based Lifeview Oil and Gas Management Services, Nikipelo thinks he’s developed a better mousetrap – a new tool for heavy and conventional enhanced oil recovery. He joins such innovators as Sonic Technology Solutions Companies and N-Solv Corporation in his efforts to create practical, low-carbon recovery systems.

When you get him started, Nikipelo begins by enumerating the competing systems. Steam-assisted gravity drainage (SAGD) has been advancing for more than 20 years. More recent approaches include Petrobank’s toe-to-heel air injection (THAI) and its CAPRI system, which places a nickel-based catalyst bed in a horizontal wellbore. Other companies are experimenting with pulsed wave-front technology, solvent injection, electrical down-hole heating, steam flooding and the injection of solvent gases like carbon dioxide.

By no means is Lifeview alone in its efforts to find the holy grail of low-carbon recovery. One of the most important trends in bitumen recovery is the drive to produce the stuff with lower emission ratios. In the best of all possible worlds, this means better environmental credentials and lower cost of recovery. For environmental and economic reasons this is the wave of the future. Increasingly, production systems will have to respond to demands for reduced pollution – especially the emission of greenhouse gases (GHGs).

Nikipelo is one of a number of people combining and refining low-carbon recovery technologies in the interest of greener bitumen production. His company has developed a slick experimental production configuration that combines pulsing, thermal flooding, solvent gas injection and toe-to-heel injection. “For the thermal, we are injecting hot gas using a patent-pending three-stage process. The water or wet steam may be alone or combined with a catalyst. Our thermal unit is also generating electricity for our down-hole heating system, which pre-heats the hot gases to maximize potential. All emissions are being sent down-hole. The process greatly reduces both emissions and water usage.” His low-carbon alternative to SAGD begins with the idea of mitigating environmental problems but may also be a lower-cost solution for many producers.

“Our process is focused on using less water than SAGD. When we reduce water usage, we reduce the demand for fuel to generate steam, thus reducing fuel consummation. Our process is focused on zero emissions to atmosphere. All emissions are used in the process and are injected into the bitumen.” As Nikipelo tells the story, when he took his original concept to the Alberta Research Council, Dr. Alex Turta (team leader for enhanced oil recovery) said “You’ve got something important here….it may change the way we look at heavy oil recovery and possibly enhanced conventional recovery as well.” Turta in effect invented the THAI system, and the Lifeview approach is based on a number of his ideas.

According to Nikipelo, Lifeview’s tool injects steam and a scrubbing gas intermittently into the reservoir. This eliminates the requirement for continuous injection. This brings greater buoyancy into the reservoir, Nikipelo says. “It enables the steam to go into the proper part of the reservoir, creating a mobile oil front. At the end of the day, to justify the cost of a small SAGD operation you need a tool that can produce a small, cheap and portable tool – something small and inexpensive enough that can prevent smaller oilsands reservoirs from becoming stranded.”

Whether or not Nikipelo’s idea is an answer to the industry’s low-carbon prayer, it exemplifies a grail that an almost Arthurian roundtable of entrepreneurs and companies are seeking: ways to produce heavy oil and bitumen with lower carbon output.

In the field the smaller, leading edge companies include MEG Energy (Christina Lake in the Athabasca sands), OSUM Oil Sands (Cold Lake oilsands and Grosmont bitumen carbonates at Saleski) and Laricina Energy (also at Saleski and in the Athabasca at Germain). Private companies like Drakkar and Earth Energy Resources are, respectively, testing bitumen carbonate production in Peace country and oilsands in Utah. Also, of course, big, established players like Imperial, Shell, Husky and Cenovus Energy are making good progress in lowering per-unit emissions.

As these players successfully develop low-carbon production technologies, their efforts will simultaneously contribute to both the industry’s image and to its bottom line.

The Image Disaster
Part of the reason this development has become so important is that the oilsands business is now the ultimate whipping boy for petroleum industry critics. This year, things have reached what one can only hope is the bottom of a trough.

True, the year began on a high note. At their ballyhooed meeting in Ottawa, Prime Minister Harper and US president Barack Obama agreed to begin a “clean energy dialogue.” The focus of the talks would be “a cleaner, more secure energy future for both nations”, and it would involve immediate, big investments in energy research and development.

The two countries would collaborate on energy research related to advanced biofuels, clean engines, and energy efficiency, according to the Prime Minister’s website. “To address the energy and environmental challenges that we face together, the two nations agreed to expand collaboration in these and other key areas of energy science and technology.” Suddenly, it seemed, the green agenda had caught on in Ottawa.

Then things went awry, beginning with a devastating critique of the oilsands business in National Geographic. In the autumn, environmental activists staged highly publicized demonstrations at oilsands facilities.

As activist Jordan Poppenk described one such incident, “Activists from Greenpeace successfully broke into a tar sands operation in Alberta...and held up production for hours as they chained themselves to equipment and unveiled a banner reading “Tar Sands: Climate Crime” on a major access road....”

“American, Canadian and French activists broke into Shell Canada’s Albian Muskeg River oilsands mine north of Fort McMurray,” he happily continued, “and successfully halted production at the mine for six hours. The protest lasted for 30 hours and ended with a negotiated settlement between Greenpeace and Shell with the activists leaving peacefully and Shell agreeing not to press charges. The action was timed to coincide with the release of a report by Greenpeace condemning the tar sands as well as a visit by Prime Minister Stephen Harper to U.S. President Barrack Obama. The protest leaked into coverage of the U.S./Canada summit on major U.S. networks.”

At about the same time, environmental and aboriginal groups in the United States filed a federal suit against Enbridge’s proposed Alberta Clipper, on the grounds that recent approval for the bitumen pipeline goes against the public interest.

Smoke and Mirrors
Even such a knowledgeable and thoughtful observer as Jeff Rubin (formerly CIBC’s chief economist) claimed that oilsands facilities “leave an archipelago of tailings ponds – toxic by-products of oil-sand production and death-traps for migrating wildlife.”

Rubin’s tome on deglobalization – Why your world is about to get a whole lot smaller – delivers at least a few shock-jock ideas about the oilsands. “The production of a single barrel of oil pollutes 250 gallons of fresh water,” he said, “and emits over 220 (pounds) of carbon dioxide into the atmosphere.” To put the latter number in context, a barrel of bitumen weighs about 370 pounds.

Rubin does not cite the source of these figures, but they illustrate a second reason why low-carbon recovery has become so vital. The raw cost of eliminating carbon dioxide emissions from bitumen and heavy oil production is high and growing, especially because so much of those emissions are associated with increasingly expensive fuel consumption.

You can slice and dice Rubin’s numbers in many ways, especially since they make no reference to the industry’s mitigation efforts. For example, you might argue that at some point in time just about every volume of water on earth has been polluted by something or other. Natural systems have been purifying water since rain began falling in the pre-Cambrian. At oilsands plants the practice of recycling contaminated water, the use of deep-well injection and industrial evaporation are just some of the solutions that apply.

Carbon dioxide emissions, of course, are a different kind of cat. Once produced, they are devilishly costly to remove from industrial processes and inject into subterranean storage basins. Shell’s Quest carbon capture and storage project, for example, will sequester carbon dioxide from the upgrader at the company’s Scotford complex near Edmonton – an upgrader which receives bitumen from Shell’s Albian plant.

The Quest project will receive $865 million in grants from the governments of Alberta and Canada. In announcing the federal government’s $120 million contribution to the Shell project, Natural Resources Minister Lisa Raitt called carbon capture and storage “the most viable emission-reducing technology for fossil fuels.” She added, “These projects will reduce greenhouse gas emissions while creating high-quality jobs for Canadians now and benefitting our environment for future generations.”

True for mineable oilsands and bitumen upgrading processes, but the argument falls short when in situ production comes into play. Here, players like Lifeview’s Harold Nikipelo offer better, more viable solutions. Let’s begin with a look at the numbers. Under ideal conditions, Shell’s Quest project will have a lifetime cost of about $1.5 billion, including both capital costs and operating expenses. It will sequester about a million tonnes of carbon dioxide per year over its 40-year life. In nominal terms, and assuming excellent operating results, that means the cost of sequestration will be about $37.50 per tonne.

The Benchmark
Assuming these numbers are largely correct, an interesting number falls out of some simple math. If producing a barrel of oil from bitumen releases one tenth of a tonne of CO2 (Rubin’s number), then the nominal cost of eliminating greenhouse gases through carbon capture and storage would be about $3.75 per barrel. If you believe that regulators are going to get serious about eliminating emissions from bitumen production, then technologies that can reduce emissions for less than that $3.75 benchmark may be bargains.

The problem is in accountability. You can count the cost of sequestering carbon dioxide. How do you account for greenhouse gas emissions you don’t produce? This is a question environmental policy-makers can answer. The good news for industry is that as an economic question it can be good for the bottom line. For a lot less than $3.75 per barrel, clever engineers can find ways to forego the production of equivalent weights of greenhouse gases.

“Presently SAGD operations are running two to three barrels of steam to one barrel of oil. Our goal is to reduce that number (by using a different production system),” Nikipelo reiterates. “When we reduce the steam-oil ratio, we reduce both capital and operating costs for water treatment, steam generation and storage facilities. There can be huge savings.”

To calculate per barrel savings you need to plug such other factors as calendar day productivity, ultimate recovery rates and project life into your spreadsheet. Also, the system you employ must be robust (minimal downtime) and affordable. In a political climate deeply concerned about greenhouse gas emissions and water pollution, the oilsands industry’s best new mousetraps are going to trap GHGs in situ, so the industry later has less to capture and sequester.

The Carbonate Question

This article appears in the November, 2008 issue of Oilsands Review. Graphic shows Alberta oilsands in yellow, major heavy oil deposits in blue, Grosmont bitumen carbonate formation in red and bitumen triangle within dashed line. Source of map here.

By Peter McKenzie-Brown

According to one view, planet Earth has two energy super-provinces – one in the Old World, the other in the New. The Old World super-province stretches from North Africa through the Middle East into Siberia. Rich with conventional oil, it’s the source of most of the petroleum traded on global markets.

The New World super-province reaches from northern Alaska and the Beaufort Sea through Alberta’s oil sands down to Venezuela’s Orinoco heavy oil belt, and continues south between the Atlantic coast and the eastern Andes. Richer in oil than its Old World sibling, its conventional resources are mostly in decline. However, this vast region has great volumes of untapped unconventional resources – notably Alberta’s oilsands, Venezuela’s Orinoco heavy oil belt and America’s oil shales.

This article focuses on the least known of those unconventional resources. Bitumen carbonates are common reservoir rocks totally saturated with very heavy oil. They are also the hydrocarbon resource in which Canada leads the world by an almost incomprehensible margin.

Canadian deposits contain 96% of the entire world’s supply of this black, barely mobile oil. That would be just a statistical oddity if not for the volumes of hydrocarbons involved. There are nearly 450 billion barrels in the ground in Alberta. Seventy-one percent of that total (318 billion barrels) is in the Grosmont formation – a massive structure underlying much of the Athabasca oilsands deposit. Another 65 billion barrels of bitumen can be found in the Nisku carbonate, which is associated with the Grosmont. In Peace Country, the bitumen-saturated carbonates contain as much oil as the Peace River oilsands deposit – once again, about 65 billion barrels.

Here’s another way to put those numbers in perspective. Alberta’s bitumen deposits comprise the largest petroleum resource in the world. One fourth of that resource is in carbonate reservoirs.

There is a catch, of course. Like the oilsands many years ago, there are no economic ways to produce oil from these deposits yet. However, in early 2006 a numbered company shelled out C$465 million for oilsands leases in the Grosmont. When the owner of that mystery company turned out to be Shell – not known for taking high risks when large amounts of cash are at stake – many previously skeptical observers began to see these carbonates as a resource whose time was nigh. Is that optimism justified?

Nature of the resource: Carbonates are minerals that contain the carbonate ion, CO3. Probably most of the world’s conventional oil resources are in traps made of these rocks. While the most common reservoir carbonates are limestone (a calcium carbonate) and dolomite (a magnesium and calcium carbonate), reservoirs typically include many other carbonate minerals.

On the surface, Alberta’s bitumen carbonates have the makings of an oil producer’s nightmare. The rocks themselves are full to saturation with huge volumes of highly viscous, heavily biodegraded bitumen – the most viscous bitumen carbonate in the world, in fact. The resource is thicker than molasses. In general, the carbonates have little permeability so the bitumen is in a reservoir that won’t easily let it escape, and for other reasons the reservoir rocks can yield as much trouble as oil. The resource is in the middle of the bush. Once you get the bitumen out of the rock, it isn’t transportable without lots of diluent, and it isn’t commercial without extensive upgrading. For all this Shell paid nearly half a billion dollars?!

What Shell paid for was the potential. The volumes in the ground are so huge that a relatively small amount of production from a sweet spot in the Grosmont could be hugely profitable. In a number of cases worldwide, some bitumen carbonates have gone on production with reasonable results – notably Iran’s offshore Zaqeh field (no longer producing) and France’s Lacq Superieur. As we shall see, Shell’s ace in the hole is technology.

In the 1970s and 1980s, a number of companies conducted experiments on the Grosmont formation, mostly in cooperation with the long-defunct Alberta Oil Sands Recovery and Technology Authority (AOSTRA). Although no commercial oil resulted from these experiments (production was pumped back underground), the technical community began to understand the resource, and to dream about bringing it into production.

According to Roy Coates of the Alberta Research Council (ARC), bitumen carbonates are now at the place where non-mineable oilsands were some decades ago. Commercial development is in the future – maybe 20 years. “That’s when carbonates will be at the stage where SAGD developments are now,” he said. “I don’t consider SAGD really commercial yet. (Producers) are still trying to optimize the process.”

Coates is program manager for the Carbonate Research Program, a 3-year, $2.3 million per year initiative of major companies plus two agencies of the Alberta government. He seems fascinated by the challenges of the Grosmont bitumen carbonate, beginning with the matter of where the stuff came from. “That’s something we’re looking at. I would venture to say that it is the same oil as in the oil sands. We don’t know where the bitumen originated. It could have originated in the carbonates and flowed to the oilsands or vice versa. We don’t know the answer to that. But the properties are so similar that you should consider them to be the same oil.”

Matrix, vugs and fractures: The fact that it is the same oil as the oilsands is one of many problems presented by this resource. Its viscosity is such that it doesn’t flow naturally. Like bitumen from the oilsands, you have to make it thinner to make it flow. That is only the beginning of the problems, however. For example, the bitumen formations are 200 to 1,000 metres deep, which means they are not mineable. Gas drive in the reservoirs is insignificant. The problems get even worse when you consider reservoir permeability and porosity.

According to Coates, the Grosmont carbonate “almost has three systems of permeability and porosity.” The matrix of carbonate rock is very tight, with low permeability. Yet over eons it has somehow become saturated with bitumen. That’s the first system: low-permeability, low porosity rock full of bitumen so viscous it won’t flow without treatment.

The second system harbours other problems. Within those carbonate rocks are large cavities, called vugs – often the diameter of your arm or bigger. For the most part, these structures are leftovers from eras when water ran through the rock, dissolving caverns and other crevasses in it. They fill with rock debris (often overburden), but they also fill with bitumen. These structures can have good permeability and porosity, but they do not always form good producing reservoirs and they cause drilling problems. According to one report, during drilling “the drill bit has been observed to drop several feet as it passed through a large tunnel filled with bitumen...and these irregular tunnels...lead to a loss of mud circulation during drilling.”

The third permeability/porosity system consists of long fractures in the rock. “When you try to heat a reservoir or inject a fluid into it,” said Coates, “because of the fractures you can’t be sure where the steam is going to go.”

These difficulties notwithstanding, in the early years of experimentation on the Grosmont, there were some great successes. According to an AOSTRA report, in the late 1970s Unocal (since absorbed into Chevron) and Canadian Superior (absorbed into Exxon Mobil) conducted a series of field tests to assess steam stimulation, steam drive and combustion on the structure. In one instance, “results were spectacular. Bitumen production rates from a single steam stimulation well of up to 550 barrels per day were obtained”.

Despite these results and those from further trials, the companies abandoned these pilots in the mid-1980s, for two reasons. One was the problem of logistics-related high costs (the Grosmont is in a remote area, without roads and other infrastructure). More importantly, the companies had serious technical concerns about the viability of production – especially in the lower-price environment that followed the oil price shock of 1986.

In situ refining: Of course, that was then and this is now – a world of high prices and improved technologies. In recent years, other companies have been testing Alberta’s bitumen carbonates. One notable player is Husky Energy, which has accumulated substantial holdings in the Grosmont, for relatively small amounts of cash. Husky estimates its Saleski bitumen carbonate properties contain 19.5 billion barrels of original oil in place. You don’t need to coax a large percentage of that oil from the rock to find yourself with a valuable asset. Husky’s tests so far have used technologies that are advances on the methods tested long ago by Unocal and Canadian Superior, but similar in concept.

Shell, however, is different. When Shell made its startling $465 million bid for part of the Grosmont, the company clearly had in mind substantial production volumes. The industry wondered what was going on, until a hint of company thinking came out in a recent interview with Jan van der Eijk, Royal Dutch Shell’s chief technology officer (CTO). The occasion was a wide-ranging discussion of technology, but largely centred on Shell tests at a bitumen carbonate deposit in the Peace River area. New Technology magazine reported the story.

According to journalist Pat Roche, “In what could lead to one of the most revolutionary innovations in the history of the oil and gas industry, Shell has been testing a way to upgrade bitumen in the reservoir for more than two years. Electric heaters raise the subsurface temperature to the point where the reservoir, in effect, acts as a refinery. ‘The product that you produce is almost water white, and it is as mobile as water,’ says van der Eijk.”

This “in situ upgrading process”, as the company calls it, has been more than a decade in the making. It began with tests on oil shale in Colorado. In its oil shale tests, Shell recovered 1,700 barrels of light oil from a 10 by 13 metre area at its Mahogany test site. The company used underground electric heaters like those introduced at Peace River to induce chemical pyrolysis underground. This “in situ conversion process” distilled shale-bound kerogen (a precursor to oil) into synthetic crude oil. A by-product of the tests was shale gas.

The Peace River test was the first to use electric heaters to upgrade oil in the ground.

Journalist Pat Roche continued, “As happens in a refinery, the lighter products are boiled off, leaving the heavier components behind in the reservoir. The upgraded oil can be further refined into products such as gasoline and jet fuel. ‘The product is really impressive,’ [says van der Eijk].

“‘In a refinery,’ he explains, ‘you need to have a certain throughput through a vessel. And that drives you to a certain reaction rate; otherwise, you just don't have enough productivity.’ But in the subsurface, the reservoir serves as a gigantic vessel. ‘And in that sense you can allow much lower reaction rates. The vessel is much larger and you can let it go for a year rather than a minute throughput [in a refinery].’”

Late last year, Shell filed a regulatory application to test its in situ upgrading process in the Grosmont bitumen carbonates. Perhaps its tests in that massive formation will help transform Alberta’s bitumen carbonates from vast stores of puzzling gunk to one of the hydrocarbon jewels of the New World. You can never tell.