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. 

Where They Stand

Candidates for PC leadership weigh in on issues that matter to Alberta's energy industry

An edited version of this article appears in the October issue of Oilweek

By Peter McKenzie-Brown

As this magazine reaches your desk, Alberta’s Progressive Conservative party will be voting on a new leader. The six candidates for this position fit roughly into two groups. The progressives (Doug Horner, Gary Mar, and Alison Redford) make up one; the conservatives (Doug Griffiths, Ted Morton, and Rick Orman) comprise the other.

To help you decide how these candidates stand in the area of energy policy, Oilweek asked for written answers to a series of questions. We wanted to know where they stand on a national energy strategy, natural gas surpluses, bitumen upgrading in the province and the prospect of creating a super-regulator – a one-stop shop for all the province’s regulatory needs. We also wanted to know their best single idea for a change to the business environment.

Four candidates – Doug Horner, Gary Mar, Rick Orman and Alison Redford – responded. Despite repeated requests,. Griffiths and Morton did not, and they had few energy policy ideas on their websites. That’s why they aren’t getting covered in these pages.

1.          What are your thoughts about a national energy strategy?

Orman: “Interprovincial and federal-provincial action is required in some areas, as is meaningful consultation with a variety of stakeholders…. However, I also know that at the end of the day, governments must fulfill their constitutional responsibilities, and should avoid signing onto strategies cobbled together, no matter how well-intentioned. Under Canada’s constitution, responsibility for natural resources belongs to the provinces and if I become Premier I will not abrogate my responsibilities to ensure the interests of Albertans and our industry come first.

“On July 19th this year at the conclusion of the two-day Energy and Mines Ministers, I issued a statement saying I support an Alberta-first Energy Strategy. I also said I would support a broader based strategy but only if it provided Alberta’s energy industry with greater assurances there will not be overlapping regulatory processes. It would also have to enhance market access for producers, and addressed the harmful and inaccurate misconceptions about the energy industry. I suspect that these misconceptions may also be fuelling support for broader-based strategies, but let’s not let the tail wag the dog.”

Redford: “I support a Canadian energy strategy to ensure that Alberta’s resources reach every corner of the country, dispelling the threat of energy insecurity while netting the province strong returns. Alberta must lead the development and implementation of any such strategy. The oil and gas, after all, belong to us. Bitter memories of the Trudeau-era National Energy Program make acceptance of outside plans unacceptable.”

Horner: “It is time we move from reactive to proactive. Canada needs to unite around a comprehensive Canadian Energy Strategy that brings together industry, government, academia and special interest groups to define an integrated strategy for the country across all energy producing sectors and regions. It must be Canada-wide, as a provincial strategy only begs dispute, opposition and envy. With due process, scientific evidence and cohesive decision-making, a Canadian Energy Strategy will allow the country to stand united in its resolve to move all of our energy resources forward, and it will allow industry to understand the conditions under which it has the social right to operate. Alberta must be at the table and engaged with other Provinces and the Federal Government to develop an energy strategy that is fair and understands the jurisdictional authorities and responsibilities.”

Mar: “For a number of years, Canada’s economic, energy and thought leaders have discussed the merits of a coordinated national strategy around energy development that would allow provinces to find common ground toward energy policies. 

“As the world continues to advances its energy needs, this issue becomes of vital importance to Alberta and Canada as a whole, as energy is one the major drivers of our national economy.  

“(We support) the development of a national energy strategy, and feels that Alberta should take the lead role in collaborating with the federal government and other provinces in developing such a strategy. 

“In addition, Alberta needs to ensure we are able to receive the highest price for our products so that our royalty income, which is tied to the commodity prices, is maximized.  This can be accomplished by having export pipelines that not only supply the US but have the option to supply other countries.  This optionality will provide us with the best and highest prices as there will be opportunities to choose the highest price rather than the only price.

“(We support) expanding our markets through physical means as well as through advocacy.  The advocacy will be through Alberta’s ten existing international offices and through some new key ones in the BRIC (Brazil, Russia, India & China) nations.  Both of these will provide the opportunity for more customers and higher prices received for our valuable commodities.”

2.         What are the best ways to deal with the challenge of the surpluses arising from shale gas development? What role, if any, should government play?

Mar: “Commodity prices have always gone up and gone down. The government can smooth out the changes in royalty revenue which is why there is a need for the Sustainability Fund in the short term and the Heritage Fund in the long-term. 

“(We) will develop the Heritage Fund to $40 billion in the next ten years.  This will provide Alberta with the resources to diversify our economy.  By diversifying, the concerns about oil or gas price changes will also be muted.

“A stable, predictable and competitive fiscal and regulatory regime is essential for the maintaining Alberta’s reputation as a competitive jurisdiction for investment. 

“(We are) committed to maintaining the current royalty regime for conventional oil, natural gas and the oil sands.  This will ensure the energy industry has the confidence it needs to make long-term investments in Alberta.”

Redford: “The best way to keep natural gas profitable is to expand its uses and our customer base. I want to see gas increasingly used to generate electricity; it’s cleaner burning than coal and with our growing population requiring more power, gas offers a ready solution to both our environmental and demographic needs.

“When it comes to cultivating more customers, we should turn west to the Pacific Rim. Many Asian economies are looking for fresh energy resources to fuel their growth. I want to see pipelines carrying our natural gas westward to satisfy their thirst and reap enormous returns for Alberta.

“My government will do its part to help both. I will diversify the Alberta Government’s $2 billion investment in carbon capture down other avenues like natural gas-fueled electricity cogeneration to encourage the industry to further refine this technology and adopt it widely. I will also aggressively promote Alberta’s energy riches in East Asia and work closely with the British Columbia government to get approval for the necessary infrastructure. Finally, I will provide a comprehensive range of incentives to ensure that provincial companies can build the pipelines and transport the gas at competitive rates.”

Orman: “I believe we are in the midst of developing a new business model for Alberta’s natural gas resources. The Shale Gas plays in both Canada and the US have the potential of bringing on huge surpluses of gas in the near future, and in the integrated North American market place, we are seeing prices well below those of five years ago. Natural gas producers need new markets and working together we need to identify the infrastructure necessary to get us to new markets. As Premier this would be a priority of the government. The other changes affecting the future of the natural gas industry is the push to replace coal fired electrical generation with natural gas. That remains of course a business decision for the electrical generation industry. Today we are also seeing the transportation industry looking at natural gas fuelled cars and trucks. As with natural gas fired electrical generation, there is a positive environmental impact. The worldwide demand for liquid natural gas is one of the solutions that will be needed to meet the demand for energy over the next 40 years. Estimates show that as the population of the world increases, the demand for energy will continue to increase. The ability to export liquid natural gas off the West Coast will be fundamental to being able to service increased world demand.”

Horner: “Alberta has a geological challenge, a geographic challenge, an economic challenge and a fiscal challenge when it comes to natural gas. As gas prices have fallen and will remain low for the foreseeable future, these four challenges will continue to threaten the predictability and sustainability of our provincial revenue base. Much of this reality cannot be changed; however, the government can use the following levers of public policy to advance our position:

·         Support investment in applied research and technology prototypes that focus on economic extraction of natural gas;

·         Ensure a stable royalty environment that supports the profitable exploration and production of natural gas;

·         Support the development of the necessary infrastructure – linear, port and LNG production – to improve the speed and cost associated with exporting natural gas to new markets; and

·         Refrain from overheating the economy and increase immigration to ensure our wage rates keep our industries competitive, productive and profitable.”

3.         Should there be more upgrading of bitumen in Alberta? Should government facilitate?

Horner: “Yes – significantly more. My support for the Bitumen Royalty in Kind (BRIK) program has been unwavering, as it is designed to maximize the value of our energy resources here in Alberta. The Canadian Energy Research Institute estimates about half of potential revenue and more than half of potential jobs are lost when upgrading and refining is exported. A made-in-Alberta approach to upgrading bitumen prior to export can double the related GDP and increase wealth to Albertans.

“However, as our production increases the ERCB estimates that Alberta-based bitumen upgrading capacity will decline from 61% to 52% by 2016, which is well short of the stated government goal of 72%. We need to approve additional BRIK supply agreements similar to the existing North West Upgrader today, as we cannot wait until 2016 to await studies that further prove the business case that we know to be true today.

“For example, the $6.6 billion AFNEC (Alberta First Nations Energy Centre) initiative would become the only First-Nations-owned petroleum refinery dedicated to bitumen-based refining, would process 93,000 barrels of bitumen per day over a 30-year term, and would set a world-leading environmental standard with water usage, air pollution, and greenhouse gas emissions well below existing comparable conventional crude refineries. This is an example of ‘getting it done right.’”

Mar: “The Bitumen Royalty in Kind (BRIK) Program is aimed at fostering value-added oil sands development, enhancing the bitumen market in Alberta and sharing with industry in the gains, while working to mitigate the risks in processing bitumen to further value-added products.

 

“BRIK is still in its infancy and it will take some time to evaluate whether the Government of Alberta’s participation in the BRIK projects will achieve the objectives of increasing value-added bitumen upgrading in Alberta.

“(We) will follow through with the development of the current BRIK initiatives by North West Upgrading/Canadian Natural Resources Limited and the Enhance Energy Project and carefully evaluate the results that Albertans are receiving to ensure that the goals, objectives and outcomes of the initial BRIK projects are met.”

Redford: “There should be more bitumen upgrading in the province, but only if the market can sustain it. The government should not generally play a role in this sector except in special cases such as the Northwest Upgrader.”

Orman: “Today we upgrade roughly 62% of the bitumen produced in Alberta. When the Northwest Upgrader is operational additional bitumen will be upgraded within the province. We know there are very promising new upgrading technologies being developed by companies within the province; as these advance through the demonstration and piloting stages there will be additional options for producers with respect to how they will develop their bitumen. Some markets of course will continue to want raw bitumen shipped to them. The role of the Alberta government is to advocate value-added processing, encourage new upgrading technologies, create a stable and predictable business environment and let the open marketplace function.”

4.         Do you think there should be a single “super regulator” for renewable and non-renewable resources in Alberta?

Redford: “I want to see a single entry point into the regulatory system. This will require breaking down barriers between regulators so they are closely connected, allowing them to collaborate, share information and reach decisions more effectively and transparently, in less time and at reduced cost to companies. However, a degree of separation is still necessary to maintain distinct and unique regulatory specialties.”

Horner: “Establishing a super regulator for renewable and non-renewable resources is a tremendous step toward reducing regulatory bureaucracy, inefficiency and redundancy in our energy industries. We must maintain the highest level of productivity and competitiveness in our most significant industry, and a super regulator has the potential of reducing the costs of applications, monitoring and compliance if implemented effectively. This just makes sense.

“What does not make sense is the centralization and “super-boarding” of all ministerial responsibilities that it cannot manage. This approach mistakes a structural change for increased effectiveness. Support for an energy super regulator comes only with effective governance and the competency needed to support our world-class industry ... and we can make that happen.”

Orman: “My gut tells me that whenever government starts talking about a ‘Super Government Agency’ trouble is likely not far behind. We have the devastating example in health care in Alberta moving organizationally from model to model to model. This did nothing to improve frontline service delivery, and every Albertan is now paying the price. I know in the case of the single energy regulator a lot of work went into the development of the model being proposed. I am told though that support within government and within industry is very mixed. Morale in government is low so do you really want to introduce massive change at a time when there is a backlog of work including applications working their way through the review and approval process. Organizational change on the level we are looking at would be huge and one can easily envisage an exodus of staff, which will do nothing to speed up service or the quality of service for industry. I am prepared to keep an open mind on this but I will have to be convinced.”

Mar:  “A stable, predictable regulatory regime is essential for the energy industry to make important long-term investment decisions and maintain Alberta’s reputation as a competitive jurisdiction for investment.

“There is a need to modernize the energy regulatory system in Alberta. This does not mean reducing or relaxing regulations, rather it means reducing overlap and duplication to make the regulatory system more efficient and responsive to today’s realities.

“(We are) committed to moving forward with the implementation of the Regulatory Enhancement Project, and its efforts to create a new, single regulator for Alberta’s energy resource development industries. Done right, this project will deliver an efficient regulatory system that supports the province’s competitiveness while ensuring public safety, strong environmental management and respects the rights of landowners”

5.         If you could make a single change to the business environment for Alberta's energy industry, what would it be?

Mar: “See my response to Question 4, above.”

Redford:  “I would simplify the approval process for new technologies. The health and future of both Alberta and the energy industry depend on innovation. The sooner the government signs off on new advances, the sooner they can be put to use in the field.”

Orman: “A return to government that is knowledgeable, predictable, responsive and fair – starting with the repeal of Bill 36 the Alberta Land Stewardship Act (ALSA).”

Horner: “Beyond supporting a pipeline to the west coast, the change that would bring the most immediate positive change to the energy industry as well as our other industries is a new immigration agreement that puts Alberta in charge of determining the number of new immigrants to enter the province as well as the job categories which they can occupy. This is of the highest priority for the future prosperity of the province, and is a critical component to unlocking the potential of our province.”

Sizing them up

There is more to government than energy policy: Think health care and the environment, for example. Also, leadership is an ineffable quality that is almost impossible to measure. It reflects judgement, people skills and, ultimately, the efforts of the leader’s team.

Granting those limitations, the following tables summarize the experience of the six leadership candidates in terms of education, business background and legislative experience.

1.       Doug Griffiths

• Education: Degrees in Philosophy and Education.
• Work experience: Teaching.
• Legislative Experience: First elected in a 2002 by-election. Served on legislative committees and as Parliamentary Assistant to three ministers.

2.      Doug Horner

• Education: Diploma in Business Administration (SAIT).
• Work experience: Bank manager; moved to Nebraska to look after international marketing and sales of specialty grains for ConAgra; returned to Calgary to set up an agribusiness trading company.
• Legislative Experience: First elected in 2001. Ministries of Agriculture and Rural Development; Advanced Education and Technology; Deputy Premier; born into a multi-generational political family.

3.      Gary Mar

• Education: Bachelor of Commerce, Bachelor of Laws
• Work experience: Lawyer.
• Legislative Experience: Served in the Legislature from 1994-2006. Ministries of Learning; Community Development; Environment; Health and Wellness; International and Intergovernmental Relations. Alberta’s Washington-based Minister-Counsellor (2007-2011), with a mandate to champion Alberta’s energy interests.

4.      Ted Morton

• Education: BA in political science; MA and PhD in political economy.
• Work experience: Professor at U of C; assignments as visiting professor, some of them international.
• Legislative Experience: Elected in 2004. Ministries of Sustainable Resource Development; Finance and Enterprise.

5.      Rick Orman

• Education: BA, Eastern Washington University
• Work Experience: Co-founded a land services business; Manager of Land and Contracts at Signalta Resources; founded Nexus Resources Ltd. in 1982; in 1994 founded Kappa Energy Company, which merged with Vanguard Oil; in 2003 co-founded Exceed Energy and served as Vice-Chairman until 2005; presently on the board of Daylight Energy.
• Legislative Experience: Served in Legislature 1986-1993. Ministries of Career Development and Employment; Labour; Energy. Lost 1993 PC leadership campaign to Ralph Klein.

6.      Alison Redford

• Education: Law
• Work experience: Technical Advisor on constitutional and legal reform issues in various parts of Africa for international government bodies; one of four International Election Commissioners to administer Afghanistan's first parliamentary elections; assignments in Bosnia and Herzegovina, Serbia, Namibia, Uganda, Zimbabwe, Mozambique, the Philippines, Vietnam.
• Legislative Experience: Held PC staff positions in Ottawa for Secretary of State Joe Clark and in the then-Prime Minister’s office (1989-90). Elected to the Legislature in 2008; Ministry of Justice and Attorney General.