Oilsands Allies

Inside a growing trend toward industry collaboration in support of environmental technology and strategy

This article appears in the 2012 Heavy Oil and Oilsands Guidebook

By Peter McKenzie-Brown

Momentum is building in Canada’s heavy oil and oilsands sector towards a new reality where project owners are able to work together to achieve successes they could have alone either as quickly or as completely. Make no mistake, competition in the sector is fierce, but not in all areas of development—companies are finding that in many cases it makes more sense to collaborate than to fight.

“The idea has really caught fire,” says Greg Stringham, vice-president of oilsands and markets with the Canadian Association of Petroleum Producers (CAPP). “This is the first time [industry has] come together in such a collaborative manner.”

Canada’s petroleum industry has long been an alphabet soup of industry associations and other forms of joint ventures. But new developments such as the 2010 creation of both the Oil Sands Tailings Consortium (OSTC) and the Oil Sands Leadership Initiative (OSLI) may represent the beginning of an unstoppable trend.

Beyond the OSTC and OSLI, many technical organizations help contribute to industry innovation, including the Canadian Oil Sands Network for Research and Development (CONRAD) and Petroleum Technology Alliance Canada (PTAC). Indeed, OSLI members support both PTAC and CONRAD. But the newer groups are designed to have a wider scope and faster uptake.

Environmental consortia like OSLI and the OSTC are focused on the idea that the industry should share its resources in those technical areas in which everybody can benefit from shared innovations.

The OSTC includes all the major oilsands mining companies: Canadian Natural Resources Limited, Imperial Oil Limited, Shell Canada, Suncor Energy Inc., Syncrude Canada Ltd., Teck Resouces and Total E&P Canada Ltd. Stringham says that the group “Brings together all of the stakeholders that are involved in tailings through collaboration, breaks down the corporate barriers and enables companies to work together to find solutions” to a difficult environmental problem.

Similarly, OSLI is based on the assertion that the industry should only compete in areas where it makes economic sense to compete.

A collaborative network that includes ConocoPhillips Canada, Nexen Inc., Shell, Statoil Canada, Suncor and Total, OSLI has four main areas of focus: water management, technology breakthroughs, sustainable communities and land stewardship. The ultimate beneficiaries of the approach are local communities and the air, water and land affected by oilsands development and production.

One of the key elements of OSLI is that it is designed to reduce cycle times and paperwork. Companies can share research without first signing joint venture agreements, for example. Also, it reportedly honours each company’s intellectual property but honours rules about non-competitive behaviour.

The Public Relations Factor

It’s important to distinguish these new collaborative organizations from others—which are many—that exist. For example, the In Situ Oil Sands Alliance (IOSA) describes itself as having been formed in 2007 to address “Geopolitical, economic, ecological, infrastructure and social realities” facing in situ oilsands producers. Largely the responsibility rests on CAPP’s shoulders to manage oilsands communications.

By contrast, OSTC executive director Alan Fair says his organization and OSLI do very little in terms of communication with the public. “It is quite important to keep [technical] organizations separate from the ones that have communication as their focus. [Our] purpose is to raise the environmental bar for the industry.”

From his perspective at CAPP, Stringham recognizes the importance of both functions. “We understand how foundational environmental performance is. It isn’t only about perception. It’s also about the performance aspects of the development of the oilsands.”

For its part, in 2010 CAPP launched a program called Responsible Canadian Energy based on transparent communication of performance data from energy production operations across the country. Stringham says that the issue isn’t really about collaboration or competition. The industry needs both.

“In downhole and extraction technologies and everything else that’s involved with taking oil out of the ground, the competition is intense. However in the environment, we don’t compete. By working together we can make sure that everybody is using the latest and the best environmental technologies…Environmental issues are not a competitive concern, but something that needs to be worked on collaboratively.”

For example, as Fair points out, there really aren’t any serious issues around land ownership in the oilsands sector anymore. For the most part, land ownership has already been established; properties don’t often change hands.

“Now the public has an expectation that the companies will work together to meet some of these environmental challenges. From a business perspective, any time you can get a group of companies to work together, you eliminate duplication of effort and the industry as a whole becomes much more efficient.”

This is particularly important for an industry that faces not only a volatile market environment and uncertain global outlook, but also an increasing level of hyper-scrutiny from environmental groups.

Role Reversals

In a very real sense, the industry’s use of these technical consortia is a leveraging of one of the great traditions of the oilsands sector. The leading edge of good oilsands development has always been science, and some of the most significant developments have been the result of collaborative groups.

One of the first important investigators of the oilsands industry, about 100 years ago, was a scientist employed by the Geological Survey of Canada named Sidney Ells. In the 1920s came the Alberta Research Council’s Karl Clark, whose hot water extraction process fundamentally transformed the sector.

The continual presence of provincial funding for basic oilsands research--even during the Great Depression, when Alberta defaulted on its debt--has played a vital role in helping make the industry viable.

After the Geological Survey came the Alberta Research Council, which was followed 50 years later by the Alberta Oil Sands Technology and Research Authority (AOSTRA). AOSTRA used government funding to encourage the industry to invest in the oilsands. According to industry consultant Bob Taylor, it “was the major catalyst in leapfrogging oilsands development forward.” AOSTRA’s main focus was to make in situ resources both technically and economically recoverable. More than $1billion of spending in field pilots resulted, and AOSTRA activity led directly to the definitive proof of steam assisted gravity drainage (SAGD).

Fast forward to the present. One of the present iterations of public investment in the industry is Alberta Innovates -Technology Futures. This Crown corporation trend incorporates the 90-year-old Alberta Research Council and plays an important role in moving technologies along the development path. Another is Alberta Innovates – Energy and Environmental Solutions, another highly respected Crown Corporation led by president Eddy Isaacs. It’s an important source of expertise for the sector, with a tremendous reservoir of expertise and experience – for example, senior advisor Duke du Plessis began research on the oilsands more than 50 years ago.

But as it applies to energy, the Alberta Innovates initiatives are relatively small. This raises the question of whether the province – the owner of the resource – is doing enough to encourage the development of new oilsands technologies. Put another way, in recent years there has been no AOSTRA-like leadership in advancing oilsands related technological innovation in the province.

AOSTRA 2 and NASA II?

Last May, the Premier's Council for Economic Strategy recognized this issue, identifying it in a report titled Shaping Alberta's Future. The group proposed creating the Global Centre for Energy, which would “require collaboration among industry, researchers and government,” the report proclaims, adding that “To ensure Alberta realizes the full potential of its energy resources over the decades to come, it is time to launch another large-scale collaborative effort like AOSTRA and make it a strategic priority for the province.” 

The authors suggested a program that is “a crucible for accelerating innovation to transform environmental and operational performance. Design it to be a catalyst and funder of collaborative research, a meeting place of diverse interests, and a showcase of achievement. Make Alberta internationally respected for pioneering research, with authoritative evidence and industrial-strength solutions.”

Unfortunately, the Premier’s Council on Economic Strategy now reports to the Cabinet Office rather than the Premier's Office, Perhaps this explains why there are no bold initiatives in sight.

Doug James and Bob Taylor--the main forces behind the Energy Futures Network, a think tank--have put forward to both government and industry the notion that the province needs to bring more resources to bear on the oilsands. In a paper titled AOSTRA 2, they make a strong case for a new collaborative industry/government research and development program. “This must be a private-public initiative from the beginning,” they argue, “but it would be best if it were industry led.”

The paper is full of ideas and principles, but the authors’ main concern is that “multiple technologies needed to be developed in parallel, both to share cost and risk and to move more quickly.” They propose an organization that sets the goal but doesn’t predetermine how – a bit like NASA’s approach to landing on the moon.

On the issue of NASA, perhaps it’s best to leave the last word to Preston Manning – head of the Manning Foundation for Building Democracy. In a recent presentation to an OSLI “Big Ideas” forum, Manning proposed the notion of collaboration on a continental scale. “Today, both Canada and the US have a somewhat different security concern – the need to reduce North American dependence on offshore petroleum resources and increase the availability and delivery of North American sources energy. So why not agree on sustainable continental energy security as a mutual goal and establish a similar organization to NASA – NASA II, where NASA stands for the North America Sustainability Agency – to bring large-scale public and private resources and scientific expertise in both our countries to bear on the goal of sustainable continental energy security?”

In-situ Step-change

How underground shafts and tunnels changed the future of the oilsands

This article appears in the December issue of Oilsands Review

By Peter McKenzie-Brown

The year was 1976 and the place was a small town called Yarega – about 600 miles northeast of Moscow, near the Arctic Circle. A group of Albertans had gone there to observe a Soviet “oil mine.”

The Soviets had constructed shafts and tunnels into a heavy oil reservoir. Local workers were pumping steam into the reservoir through angled drill holes and production was taking place within the mine. A mining engineer among the Canadians, Gerry Stephenson, describes the project: “The wells that were injecting steam were drilled from an upper level of tunnel, which was above the heavy oil reservoir. So the injection wells were drilled from above but from tunnels. The recovery wells were drilled from tunnels below.”

According to Maurice Carrigy, vice-chair of the Alberta Oil Sands Technology and Research Agency (AOSTRA), “They had a tap, you know like a tap you would see in plumbing, a bathroom tap, and they would turn that on and off to get the oil out.”

Chronically short of cash, the USSR was hoping to sell the technology to the Canadian oil industry. The visit in part reflected a 1972 technology-sharing agreement between Canada and the USSR – one that collapsed in ‘78 when Canada expelled 13 Soviet officials for trying to infiltrate national security services.

The Canadians were not impressed with the oil mine, but they were intrigued. According to Carrigy, it led to a “total revolution in the concept of what you could do with bitumen that you couldn’t do in a traditional reservoir.… You got (the bitumen) into a form where it was either emulsified or liquefied so that you could produce it.”

At least one other group of Canadians had visited a Soviet oil mine. Hugh Lieper, who chaired Canada’s petroleum committee for the technology sharing agreement, also visited one in 1976. He describes being hoisted 800 feet into the mine in an elevator that swung wildly from side to side. At the bottom of the shaft, he found the oil being collected in a large open pit on the operations floor. “When I asked whether the electrical motors on the site were explosion-proof, no one knew what I was talking about.”

AOSTRA’s Carrigy puts the impact of his group’s visit to the Yarega oil mine in perspective. While Canada didn’t use the primitive Soviet technology, it gave credibility to “the idea that we could go below (an oilsands reservoir) instead of working from above.” That way “we could use gravity as the driver in getting the oil out. That would be natural. It would come down and flow in and then we’d take it from below rather than pulling it up to the surface.”

Adds Stephenson, “the system was definitely working, but the mine was very, very primitive. The tunnels were tiny. They weren’t mechanized at all. The piping systems were not much better than you would find in your garden. But it demonstrated that if you heat heavy oil, it will mobilize, it will be possible then to drain it, and if you put in wellheads below the reservoir, you will get production without pumping.”

The Mac of SAGD
A few years after the Canadian expeditions to the USSR, the legendary Roger Butler began developing the two-well SAGD concept, which eventually took the form in use today: injecting steam into a horizontal well and collecting oil through a parallel well below. Clem Bowman, who worked at Imperial Oil with Butler, says he actually developed the theoretical model for SAGD in the early 1970s. However Chi-Tak Yee, who was Butler’s first graduate student at the University of Calgary, says he once saw a document dated 1969 in which Butler had sketched out his preliminary ideas.

Whatever the facts of the matter, in the early 1980s the time was ripe for radical experimentation.

The AOSTRA’s first chairman, Bowman picks up the story. According to him, one day Gerry Stephenson came into his office and said “The oil companies have got it all wrong. The idea of drilling vertical wells into the oilsands and only contacting the pay zone for the few metres where there’s bitumen and having to put multiple wells down in these grid patterns just doesn’t make sense. I’m a mining man and the logical thing to do in a mine is to put down a shaft and to drill horizontal wells from that shaft and then every foot of well that’s drilled is in the pay zone.” Stephenson added that he had gone to the oil companies with this idea without success.

“And so he came to my office and sat there and made his plea that we should build a facility, put down a shaft and he had worked out what the costs would be,” Bowman continued. “According to his numbers, drilling a shaft into the deposit is not an expensive operation and the coal companies know how to handle methane in spades. So we put together a concept called the Underground Test Facility. No oil company would put any money into it but (petroleum executives on AOSTRA’s board) said they would support it technically and they’d have people help us on it.” For the only time in its history, the government agency paid full fare – and for what seemed a most speculative idea. Total budget for shafts, tunnels and infrastructure was about $30 million.

As Bowman continues, “It seemed this was the obvious time to test (Roger Butler’s) principle of gravity drainage.” Butler had left Imperial oil to become part of AOSTRA, and he became a member of the technical team. Maurice Carrigy was the project executive. Today a vice president of MEG Energy, Chi-Tak Yee says that “one of the most fortunate things that I was involved with was the Underground Test Facility project that was essentially the birthplace of SAGD. Think of (the UTF) as the Mac of SAGD development.”

First photo taken under the oilsands;
Stephenson in centre

According to Carrigy, “although we did contemplate going right into the oil sands, we thought it would be better to go down below the oil sands, put the tunnels in a secure and safe place” – a layer of limestone – “and then drill upwards” into the reservoir.

The magnitude of the UTF is hard to imagine. Sinking the shafts was done with a drill bit almost four metres in diameter weighing 230 tonnes. The two shafts were 223 metres deep and neither one deviated from the vertical by more than an inch. As a safety measure, AOSTRA constructed two parallel tunnels through the limestone. More than a kilometre in length, the tunnels were five metres wide by four metres high.

A Subway to the Wellhead

At the UTF’s official opening on June 29th 1987, a senior executive at Shell Canada – up to that time he had been a critic of the project – went to Stephenson and said, “It’s really not a mine, Gerry, is it? This is really impressive. It’s like a subway to the wellhead.”

Then came the tests. The Phase A pilot involved three well pairs 70 metres in length, each with 40-50 metres of exposure to the McMurray formation. According to Stephenson, “steam was injected and the first experiment with SAGD wells began. After a year or so, it was obvious the system was working.”

That was the beginning of a turnaround within the industry, which soon decided to get financially involved. Ten companies each contributed $16 million to the project. That funding enabled the test crew to complete Phase A and to move on to Phase B. It also funded several years of additional experimentation.

Phase B involved another three well pairs, 70 metres apart. According to Stephenson, “the effective length in the reservoir was 500 or 550 metres. They resembled a commercial development” despite having only three producing well pairs. Project engineers expected production to reach about 1,800 barrels a day.

What was the result? “AOSTRA’s staff had estimated that the recovery might be somewhere between 30 percent and 45 percent of the bitumen in place,” he says. “We actually got 65 percent recovery. The steam chambers formed by mobilization of the bitumen spread way beyond the area that we’d expected, so obviously we didn’t need to drill the well pairs as close together on Phase B as we did on Phase A, so we opened them up. Anyway, on Phase A the figures were 65 percent recovery – way beyond what we’d estimated. Over the 10-year life of the well pairs, Phase B got a steam/oil ratio, the most critical figure of all, of 2.3 to one.”

The petroleum industry soon began to develop SAGD projects from well pads. According to Stephenson, however, there are many reasons why SAGD is better done from tunnels underground. “You don’t disturb the surface to the same extent. You can use gravity to your full advantage.” And, he adds, surface schemes require a high-capacity, expensive pump for each producing well. They cost a lot to buy and a lot to service.

Also, he says, “it costs more to pump through a multitude of  8-inch pipelines than it does through a single 18-inch pipeline in a shaft. Another advantage is that you can drill more accurately from underground, and you get better recovery because you can use lower steam pressures. Your production might not be quite as high, but your recovery of the bitumen is going to be better, because you’re allowing a slow process of heat soaking upwards by thermal conductivity.”

He claims still other advantages for the system. “You’re operating in an underground climate in a tunnel. You're doing all your drilling and completion of wells as well as your process manipulation work in a safe working environment at a temperature of 58 F year round and with no snow and ice to hinder and delay your work. You can operate 24 hours a day, 365 days a year, instead of being confined with your drilling and your completions to those periods when you can drill on the muskeg and so on. You can do all these things in a safe environment that allows you to work all year long.”

A visionary but not a dreamer, Stephenson acknowledges that the system also has disadvantages. One is the need for upfront capital: until you’ve constructed the shafts and tunnels you can’t do any drilling at all. Also, of course, some reservoirs simply don’t have the geological features needed to make the system work.

In the latter 1990s the UTF was acquired by Devon Energy, which then sold it to Petro-Canada. When Suncor Energy acquired Petro-Canada, it also acquired the UTF – now known internally as its “Devon Project.” Petro-Canada developed abandonment plans for the facility, and unconfirmed reports say the ERCB approved them. It’s still intact, ‘though its future is in question.