Environment Committee on June 16th, 2008

[Dr. Hassan Hamza]

There are studies in that area. There are some numbers that are available now. The ultimate effect is that you don't have to wait for 20 to 30 years. At least you can get projections of what could happen.

You are right; the contamination of underground water is one of the issues that should be looked at.

[The Chair, Conservative, Bob Mills]

Thank you.

We'll go now to Mr. Warawa, please.

[Mark Warawa, Conservative, Langley, BC]

Thank you. This is very interesting.

About a year ago I went up and visited my good friend, the hard-working member of Parliament for Fort McMurray—Athabasca, and had a tour of the river. I was fascinated to actually see rocks with bitumen oozing out of them right along the shore of the river. So it's there naturally too, and to now see this resource being used is very interesting.

I also saw some areas that looked as though they had been reclaimed, different from what they were originally. Of course I think the bison had been returned to that area too.

My question is on water recovery. You had mentioned that with the surface mining it's about 70%, and it's about 90% with in situ. So with the projected trend as we move more to in situ and away from surface mining, because that's where the big resources are, deeper than the 75 metres, will just that formula alone cause the amount of water that's being used to likely go down, then?

[Kevin Stringer]

I think the answer is that it will mean there is less water used per project, but it depends on the number of projects that are out there. But the objective is to get better than 90%. The objective is, at this point, an improvement in water usage and efficiency: the objective that the Alberta government set, and they're working with industry to achieve it, of a further 30% improvement by 2015.

Certainly you're right in terms that, per project, the situation should be better. But with the number of projects that are expected to come along, it will continue to be a significant challenge.

[Mark Warawa, Conservative, Langley, BC]

On the actual volume that's taken out of the river, you mentioned there are high and low volumes in the river. I think I've heard the figure of 2% of the volume, and I've heard the figure of 4%. Is that the average during the year, or a maximum of 2% or 4%? And is the population, which is estimated to be 80,000 to 100,000 people actually living in the Fort McMurray area, part of that volume of water being removed, when you say 2% to 4%?

[Kevin Stringer]

I believe that the 2% of the flow—which is the figure that I've seen most often, and it is true you do see different figures, 1%, 2%, or 3%--speaks to the oil sands. That's the percentage of the flow that is being used by the oil sands. My understanding is it's 1% now and the 2% is expected with projects that are foreseen in the near future.

[Mark Warawa, Conservative, Langley, BC]

I'd like to switch gears a bit. You said that carbon capture and storage is a very important part of future developments, actually absolute reductions in greenhouse gas emissions. Could you share with us the importance of carbon capture and storage and what part it will play? How is it going to make things different from the way we remove bitumen now and in the future? And what are the capital costs associated with it?

[Kevin Stringer]

Again, I'll ask Dr. Hamza to add to what I'm saying.

With regard to carbon capture and storage, one of the things our department is working on is something called a storage atlas, and it's going to point out where in Canada it's possible to store carbon dioxide. The challenge is actually capture. That's the biggest challenge. There are lots of places to store in deep-water aquifers, in old oil wells, in particular in southwestern Alberta. That's an exaggeration, because it goes right up to Edmonton, but the area south and west of Edmonton in Alberta is a particularly good area for that.

What we anticipate is that there will be pipelines from Fort McMurray. The Fort McMurray area is not one of the best areas for it, but just south and west of there it does become good. So there will probably be a pipeline that goes to those areas that would be used and sequestered throughout Alberta and Saskatchewan. Currently, the Weyburn-Midale project in Saskatchewan is one of the biggest in the world, and is looking at monitoring, looking at evaluations, and looking at how this can best be done. We do see it as an opportunity to capture the carbon dioxide and inject it deep into the ground, where it will stay secure for thousands of years.

[Mark Warawa, Conservative, Langley, BC]

I wish we had a lot more time to hear from you. As was suggested, maybe we can hear more in the future, in the fall.

In Weyburn they use the carbon dioxide they've captured, coming up from North Dakota. It's piped up. Carbon dioxide is mixed with the water and it enhances the oil recovery. You've mentioned that in situ is providing a recovery of about 30%. Will that enhance that recovery?

[Kevin Stringer]

That's a good question.

The great thing about carbon capture and storage is that the first opportunity is enhanced oil recovery, that it goes into depleted wells or reserves and could actually enhance the amount of oil you get out of it. You get another 10%, 20%, or 30%, and that's what they're doing in Weyburn. And they're doing it around the world; they're doing it all over the U.S. Whether that works in in situ, I have no idea.

Dr. Hamza.

[Dr. Hassan Hamza]

Yes, it does. What has happened in Weyburn, actually, although we are getting the carbon dioxide from North Dakota, it is an experiment to see how this works. The advantage with Weyburn is that we know the base information, and when we put the carbon dioxide in, we can see the effect of the carbon dioxide. Your objective is to store it for a long time, but you should understand that when you put carbon dioxide with the oil, some of it stays behind and some of it comes back with the oil. So it is extracted and recycled again, and, like the water, you make up the difference with this.

[Mark Warawa, Conservative, Langley, BC]

It also reduces the viscosity so it can flow. That's why you get enhanced oil recovery. Bitumen is quite thick, so if you now inject that along with the water, would that then reduce the viscosity and permit enhanced recovery?

[Dr. Hassan Hamza]

It reduces the viscosity and so on, but there are other ways actually. We'd love to talk more about that, and when we have an opportunity we'll be very happy to continue to do it.

[Mark Warawa, Conservative, Langley, BC]

Chair, if I have any time left I'd like to leave it to you.

[The Chair, Conservative, Bob Mills]

I have lots of questions as well, but our time is up for this section. I think we should move on.

I think I've heard at least three people say we want to have you back. We appreciate your information. This was intended to be base information and we'll get into the details later on.

Thank you very much.

We'll now go to our TV screens. Our next two guests are in Calgary.

Welcome to our guests in Calgary. We can see you on the screen and I trust that you can hear us okay.

[A witness]

Yes, we can. Thank you.

[The Chair, Conservative, Bob Mills]

We do have your written material as well.

I ask you to make a presentation and then we'll go to questions as soon possible with our members.

Let's begin with Mr. Chastko.

[Dr. Paul Chastko, Director, International Relations Program, University of Calgary, As an Individual]

Thank you, Mr. Mills. It is indeed an honour to appear before this committee today, and I hope I can say something of worth to you.

I should point out that I'm a trained historian. I earned my PhD in history from Ohio University. I am currently the director of the University of Calgary's international relations program.

My research interests have focused primarily on international diplomacy and business. In 2002 I completed my doctoral dissertation on this very subject. The title of my dissertation was “Developing Alberta's Oil Sands”, and that has since been turned into a full-length book project, published in 2004.

My book, Developing Alberta's Oil Sands: From Karl Clark to Kyoto, deals with the evolution of the oil sands industry. The oil sands industry began in the 1910s. We have arrived at a point 90 years later where we have a multi-billion-dollar industry. When it began, it was producing only road-top asphalt. That is a rather remarkable transformation. We now have an industry capable of producing 1.1 million, 1.2 million barrels of oil per day. By 2020 this will increase to approximately 3 million barrels per day.

There are a few themes that I developed in the writing of my book. I'll touch on these and give you some suggestions. The first is the capital-intensive nature of oil sands development. With the oil sands, we're dealing with an industry, from its origins and arguably to the present day, that resembles mining industries more than conventional oil industries.

One of the things I found in my research is that the oil sands began the 20th century as a fringe source of petroleum on the margins of the international oil industry. This is how the source was regarded by multinational oil corporations. Yet we saw a series of decisions taken by both the federal and provincial governments that now enables us to benefit from this resource. That is the second theme my book touches on—this public-private leadership. We saw it in the federal government in Sidney Ells, who researched the oil sands in the 1910s. This was carried forward by Karl Clark and the Alberta Research Council in the 1920s. It has been developing since the beginning of the first oil sands plants—from Great Canadian Oil Sands starting commercial production in 1967 to the operations of Syncrude today.

My research shows the importance of this public-private partnership in developing these resources. There has been a strong role for both the private sector and the government. Government did not play a passive role; it made enormous contributions. There is the work of Sidney Ells and the mines branch, the work of the Alberta Research Council in determining the physical properties of the oil sands deposits, research on separation methods, and the establishment of taxation royalty and regulatory frameworks that guide the industry's development today.

It was interesting for me in the last hour to hear the presentation of the members of Natural Resources Canada. I would like to point out exactly how we're dealing with an evolutionary change.

The process of hot water separation that you heard mentioned in the last hour involves taking the oil sands and adding water and heat. With the composition of the oil sands--clay, water, sand, and bitumen--once you add water and heat you get a separation of the oil sands. The bitumen sticks to the clay, floats to the surface, and can be skimmed off.

The process of perfecting this technology took 28 years. It took Karl Clark and the Alberta Research Council from 1920 until 1948 to demonstrate its commercial viability. So when we're talking about the oil sands, I think it's important to recognize that we have dealt for the most part with this industry's history of an evolutionary change. We have truly seen a revolutionary change with the development of in situ methods since the 1970s.

I'll wrap up these brief comments by saying that my research is now focusing on the globalization of the oil industry, and I would be pleased to answer any questions you may have that I hope I can answer on the development of the oil sands.

[The Chair, Conservative, Bob Mills]

Good. Thank you very much.

I'll now move to Ms. Killingsworth, please.

[Colleen Killingsworth, President, Canadian Centre for Energy Information]

Thank you, Mr. Chair.

My name is Colleen Killingsworth and I am the president of the Canadian Centre for Energy Information.

We are a non-profit, third-party energy information resource on all sources of energy across Canada. I'll just point out we are a non-advocacy group and we do rely on a rigorous stakeholder review process for all our original content.

I have a lengthy slide presentation that is put together to serve as extended background and information for you. Please don't let that intimidate you. I will only be speaking to some key highlights per slide.

As world demand for crude oil continues to grow, the oil sands deposits of northern Alberta represent one of the few reliable, long-term sources of supply. The total amount of bitumen in the ground is estimated at 1.7 trillion barrels, of which 174 billion barrels are considered recoverable reserves based on current economics and technology.

Only about 10% of Alberta bitumen resource is considered economically recoverable with current technologies, yet those reserves would be sufficient to sustain production of three million barrels per day for more than 150 years.

The next slide is a graph that shows you Canadian oil production and its projections for growth in the oil sands development and production to 2020.

The next slide shows you where Canada sits within the top five world oil reserves. The oil sands reserves are larger than the reserves of Iran, Iraq, or Russia, and are second in size only to those of Saudi Arabia.

Oil sands deposits underlie 140,800 square kilometres of Alberta, an area larger than the island of Newfoundland or the state of North Carolina. Smaller potential bitumen resources are also being evaluated in northwestern and east central Saskatchewan. Conventional heavy oil deposits in Canada are concentrated around Lloydminster on the Alberta-Saskatchewan border, but heavy oil has also been found in British Columbia, offshore Newfoundland and Labrador, and the Arctic islands.

I won't go into discussing this slide, as it has already been covered by Mr. Stringer, but it shows you the oil sands molecule and how it is developed.

According to the National Energy Board, in 2006 production from the oil sands reached 1.1 million barrels per day, surpassing the oil production of Texas and equal to about one-tenth the output of Saudi Arabia, or 1.3% of the total world crude oil supply.

Dozens of multi-billion-dollar projects are under way to expand oil sands production. The Alberta government envisions oil sands production as high as five million barrels per day by 2030. This would be equivalent to nearly one-quarter of current North American oil consumption.

The growth of the oil sands industry has had far-reaching benefits. Nearly a quarter of a million people are directly and indirectly employed by the oil sands. Studies estimate that the oil sands activity will provide $123 billion in government revenues in Canada between the years 2000 and 2025.

About 18% of Alberta's economically recoverable oil sands bitumen reserves are close enough to the surface to make mining feasible. Most of these are located in the area north of Fort McMurray.

Mining extraction techniques were initially borrowed from other open-pit mining processes and used giant draglines, bucket wheels, and conveyor belts to excavate oil sand and transport it to processing facilities. This system was costly and difficult to maintain, especially in the harsh northern climate.

In the early 1990s substantial savings were achieved by switching to power shovels, oversized trucks, and water-slurry. The switch in technology was a key step in making the oil sands industry cost-competitive with conventional oil producers.

The next slide is a good illustration of the oil sands mining process. Once oil sands ore is mined, it is transported by truck to a slurry system called hydro-transport, where the process of separating the bitumen from the oil sands begins. The slurry is treated with hot water in an extraction plant to recover the bitumen.

Tailings, a mixture of water, clay particles, and some bitumen, is a byproduct of the extraction process. Tailings are stored in ponds, which are later reclaimed.

Once the oil sands ore has been completely mined, the site is reclaimed to a state comparable to what existed prior to the oil sands development.

I'm going to skip over the next slide, as Mr. Stringer has covered this quite well.

The following slide illustrates the SAGD process. This is one of the in situ processes, which more recently has gained popularity and is the most common method used in new, smaller-scale projects. SAGD stands for steam-assisted gravity drainage. In this method, pairs of horizontal wells, one above the other, are drilled into an oil sands formation, with steam injected continuously into the upper well. As the steam heats the oil sands formation, the bitumen softens and drains into the lower well. Pumps then bring the bitumen to the surface.

As shown on the next slide, existing in situ projects use natural-gas-fired boilers to generate steam. Technologies have been developed to use crude bitumen as a fuel if needed for steam generation.

One technology that could reduce energy requirements is called vapour extraction, or VAPEX. In this method, pairs of parallel horizontal wells are drilled, as in SAGD. But instead of steam, natural gas liquids such as ethane, propane, or butane are injected into the upper well to act as solvents so that the bitumen or heavy oil can flow to the lower well. An industry-government conversion is currently evaluating a VAPEX pilot project, and several operators are also testing the technology on their own leases.

In situ, as the next slide says, is expected to disturb only about 10% of the surface land in the development area and utilizes about 90% less water than current mining methods.

The next slide is on upgrading. Once extracted, the bitumen can be sold directly to the market or upgraded by the oil sands operators into a variety of crude oil products. Because most oil refineries are designed to handle only conventional light and medium crude oil, bitumen requires special processing or upgrading to make marketable commodities.

The next slide is a diagram on the upgrading process. Upgrading is usually a two-stage process. In the first stage, coking, hydro-processing, or both are used to break up the molecules. Coking removes carbon, while hydro-processing adds hydrogen. In the second stage, a process called hydro-treating is used to stabilize the products and to remove impurities such as sulphur. The hydrogen used for hydro-processing and hydro-treating is manufactured from natural gas and steam.

As the next slide shows, upgrading produces various hydrocarbon products that can be blended together into custom-made crude oil equivalent or sold or used separately. The Syncrude and Suncor mining projects use some of their production to fuel the diesel engines in their trucks and other equipment at their operations. Suncor also ships diesel fuel by pipeline to Edmonton for sale on the marketplace.

The next slide deals with transporting oil sands products. Whether synthetic crude or diluted bitumen, they are transported in the same manner and in the same pipelines as conventional crude oil. The vast pipeline system extends from the producing areas in northern Alberta to refineries in eastern Canada, the U.S. midwest, and as far south as the gulf coast.

The next slide is a map of the North American crude oil pipeline system.

The next slide shows the benefits of oil sands. Oil sands developers are expected to invest about $45 billion in the oil sands during the next four years. This is in addition to the $34 billion in capital expenditures to date.

As a result of this growth, the number of people directly and indirectly employed by the oil sands industry is expected to total nearly a quarter of a million in just two years.

The economic opportunities extend across Canada and internationally. According to the study by the Canadian Energy Research Institute that examined the impact of the oil sands development over a 20-year period, about 56% of the employment impacts from the oil sands would occur in Alberta, 27% would be in other Canadian provinces, and 17% would occur internationally. The gross domestic product gains outside Alberta are largely due to the demand for steel, vehicles, and other equipment manufactured in other provinces and countries.

Most importantly, this serious study estimates that oil sands activity will provide $123 billion in government revenues in Canada between the years 2000 and 2025. During the same period, an additional $13.5 billion in revenues will be generated for non-Canadian governments, primarily as a result of the oil sands industry relying on international manufacturing sources.

The economic, environmental, and social challenges of the oil sands arise from the nature of the resource, its location, its vast scale, and the rapid acceleration of development since the late 1990s. The soaring demand for labour and services to support the projects, and the effects on the existing aboriginal and non-aboriginal communities, are among the social challenges.

Since the 1970s, the government and oil sands companies have established programs to train and recruit aboriginal people as employees, contractors, and suppliers, and the new projects seek aboriginal involvement where possible.

The chart on the next slide depicts employment due to the oil sands. It shows 56% of oil sands employment in Alberta, 27% in other provinces, and 17% internationally. On government revenue breakdown from the oil sands, 36% of the revenue is in Alberta. Other provinces receive 23%, and Canada as a whole receives 41%.

The National Energy Board estimates that 500 cubic feet--14 cubic metres--of natural gas are used to produce a barrel of upgraded crude oil from mining upgrading projects. About twice that much is used to produce one barrel of bitumen from in situ projects. With respect to other challenges related to energy use, introducing new technologies to improve energy efficiency is generating results. Energy used in oil sands mining and extraction has been reduced by 45% through the use of new technologies, such as hydrotransport and new low-temperature extraction processes.

On challenges related to water use, as we heard Mr. Stringer say, water recycling and the use of non-potable groundwater already has reduced the impact on freshwater resources. And new technologies may reduce the large water requirements for current oil sands production methods. Companies are also working with scientists, government authorities, and forestry companies to reduce the cumulative impacts on soil, vegetation, and wildlife.

There are cooperative programs underway between government, oil companies, and forestry companies to reduce the cumulative impacts on landscapes, forest productivity, and wildlife. These include using low-impact seismic reclamation techniques, which provide for more rapid re-vegetation; protecting caribou habitat; introducing bison to reclaimed land; and, to date, planting more than eight million trees.

Improved pollution controls, such as flue scrubbers, have reduced per-barrel emissions of sulphur oxides, nitrogen oxides, and particulates that can cause smog and acid rain effects.

With respect to greenhouse gas emissions, bitumen extraction and upgrading, as you have heard, produce more than twice as many greenhouse gas emissions per barrel compared to conventional crude oil production. However, about 80% of emissions from oil use occur at the point of final use, such as an automobile or furnace.

Several methods to reduce greenhouse gas emissions have been suggested. One possibility would be to inject emissions underground, known as carbon capture and storage, or carbon sequestration. Some of the carbon dioxide might be used to enhance production from conventional oil fields.

On a per-barrel basis, greenhouse gases and other emissions have already been reduced substantially since the 1990s, but the recent rapid expansion of production has made further emissions reductions a high priority for companies and government authorities.

The next slide shows the life cycle of emissions. If upgraded crude oil from oil sands were not available, additional imports would be required in North America. Some imports, such as Venezuelan heavy crude, actually have higher life cycle emissions than upgraded crude from the Canadian oil sands.

That's the end of my presentation.

[The Chair, Conservative, Bob Mills]

Thank you very much.

We'll go right to questions. I believe we're starting with Mr. Godfrey.

[John Godfrey, Liberal, Don Valley West, ON]

Thank you, Ms. Killingsworth.

I'm curious about one thing you said fairly early on in your remarks. When you were discussing tailings ponds, you suggested--if I interpreted you correctly--that these could later be reclaimed.

My understanding is that the problem with tailings ponds is the suspended clay. After a certain point, it simply doesn't settle down any more. As somebody from the CANMET technology centre in Devon noted, the problem is that it doesn't settle further, that after about three years...although the toxicity does reduce to some degree.

Has the industry managed to find a way of reclaiming the tailings ponds, putting the water back into rivers and having people drink it?

[Colleen Killingsworth]

Thank you, Mr. Godfrey.

They are working on technologies to reclaim the tailings ponds. Beyond that, I will need to provide a further response in writing. As the centre for energy, we ensure that we are providing factually accurate information. I don't want to make a misleading statement, so I will follow up in writing with more of an explanation on how they are planning to reclaim the tailings ponds.

[The Chair, Conservative, Bob Mills]

Send that to the clerk, please. He can distribute it to everybody.

[John Godfrey, Liberal, Don Valley West, ON]

This hasn't actually happened yet, is that right? We haven't actually reclaimed any tailings ponds?

I'm just asking.