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With more than 2 billion barrels of oil to be recovered, StatoilHydro has a huge resource to tap into in the Alberta oil sands, which may last into the second half of this century.
Canada's energy future lies in the oil sands. The total resource constitutes at least 1.7 trillion (1012) barrels, possibly a lot more, making it the largest oil deposit in the world. Based on a benchmark price of USD 62 per barrel, reserves are estimated to be in the region of 175 billion barrels of oil, second only to Saudi Arabia. No wonder the country is eager to exploit the oil sands, as Canadian reserves of conventional oil are dwindling fast, with production down to 1,320,000bopd in 2008.
Output from the oil sands is now catching up with the conventional output, as 1,265,000bopd was produced from them last year. Production has increased about 3% on average per year through the last decade, and is expected to reach 3 million bopd in 2020, and possibly even 5 million bopd by 2030, according to the Canadian Association of Petroleum Producers. To put these numbers into perspective, the total world output last year was roughly 85 million bopd, meaning that crude production from the oil sands will make a significant contribution to our current and future energy balance.
Part of StatoilHydro's future lies in a 110,000 sq km lease, Kai Kos Dehseh, with an estimated 11 billion barrels of oil in place. The Norwegian supermajor is investing heavily in the Canadian wilderness in order to obtain a stable production of roughly 200,000bopd a decade from now.
Production from the Leismer field, the first of four fields in the lease to go on stream, will start in 2010, after the drilling of 23 horizontal producers and 23 injectors into a 20 - 25m thick sandstone reservoir approximately 400m below the surface. About a year later, following the heating of the bitumen in the reservoir, the field is expected produce some 20,000bopd, which will constitute an important milestone in the history of StatoilHydro.
Also, since the company has close to 100% interest, the four fields together will make up the largest net reserves for StatoilHydro in any field on a worldwide basis. No wonder the company is eager to exploit the oil sands.
API GravityAPI gravity is a measure of the weight of petroleum liquid compared to water. If its API gravity is greater than 10, it floats on water; if less than 10, it is heavier and sinks. API gravity = 141.5/SG - 131.5 Light crude: > 31.1 °API |
While the impressive Canadian Rocky Mountains, which run from north to south through Canada west of Calgary, are well suited for year round recreational activities, the expansive flat land to the east is nowadays mostly used for farming (the prairie) , logging (the forests) and - oil and gas production (the subsurface).
The first discovery of hydrocarbons in the Western Canada Sedimentary Basin was made in 1914, when wet gas was found in Turner Valley, less than an hour's drive south of Canada's current oil capital, Calgary (GEO ExPro, No. 6, 2008). The Canadian oil industry changed dramatically, however, when Imperial Oil struck oil in Leduc #1 on February 3 1947, 50 kilometres south of Edmonton. Until then, Canada had depended on imports for 90% of its supplies This giant discovery led to a series of other major oil and gas finds in the area around Edmonton. Within a year, a major oil boom was underway in Western Canada, with important discoveries made in Alberta, Saskatchewan, Manitoba and British Columbia, all in the Western Canada Sedimentary Basin. As a consequence, crude oil replaced coal as Canada's largest source of energy more than 50 years ago (GEO ExPro, No. 2/3, 2005).
The Western Canada Sedimentary Basin (WCSB), underlying most of Alberta, and extending all the way to the Arctic Beaufort Sea, has therefore been the main source of Canadian oil and gas production since the late 1940's. It is estimated that 57% of Canada's conventional hydrocarbon resources are found in this basin.
While we are now fast approaching the 100th anniversary of the first discovery of conventional hydrocarbons in Alberta, there is no doubt that the next century will be dominated by unconventional oil - bitumen that lies to the north and east of the conventional oil reservoirs - buried underneath the vast forests of Alberta.
Extra heavy oilExtra heavy oil (liquid) and bitumen (solid) means petroleum that is heavier than water (<10°API). Bitumen will not flow unless heated or diluted with lighter hydrocarbons. |
"The Canadian oil sands are classified as bitumen because the petroleum is solid. If it had been in a liquid state, we would have called it extra heavy oil," explains Per Markestad, vice president, sustainable technology with StatoilHydro, and the petroleum engineer responsible for the important task of optimizing the company's value chain in the oil sands production scheme.
It is the temperature in the reservoir that determines if it is bitumen or extra heavy oil. In north-eastern Alberta, home of the oil sands, the average surface temperature is around 0°C, giving a fairly low reservoir temperature a few hundred meters below the surface (less than room temperature), while in the Venezuelan Orinoco Belt, also favoured with huge deposits of extra heavy oil, the climate is very different, resulting in a reservoir temperature several tens of degrees higher than in Canada, even if the reservoir is at about the same depth. Both reservoirs have a resource with API gravity 8.5.
"While the petroleum in the Canadian oil sands is as hard as a hockey puck, the Venezuelan extra heavy oil is highly viscous and flows like maple syrup," Markestad says, who has spent the last ten years working with heavy and extra heavy oil, mostly in Canada and Venezuela, taking StatoilHydro into the future of unconventional hydrocarbons.
This particular property of the Canadian oil sands leaves two options for how to produce this huge resource; either surface mining or in situ recovery.
North of boom town Fort McMurray, the oil sands are found less than 75m below the surface and can be mined, as is done by Syncrude, Suncor and Albian Sands (Shell), producing more than 600,000bopd, with altogether 92 billion barrels to be recovered from all leases (equivalent to the recoverable volumes of Saudi Arabia's Ghawar, the world's largest oil field). Oil sands mines have in this way developed into one of the largest earth moving operations in the world (GEO ExPro No. 2, 2004).
The bitumen in the Canadian oil sands is said to be the largest oil deposit in the world. The oil in place is estimated to be at least 1.7 trillion barrels (1,700 billion barrels, the equivalent to the recoverable oil in approximately 150 Prudhoe Bay fields), but may prove to be much higher when more mapping and exploration is done and the carbonate reservoir is included. The recoverable resources, although highly dependent on the oil price, are reported to be in the region of 175 billion barrels of oil (left), giving an overall recovery of only 10%. In comparison, Saudi Arabia's remaining oil reserves are in the order of 250 billion barrels according to the BP Statistical Review of World Energy 2008, while Norway's total original reserves (right) are estimated by the Norwegian Petroleum Directorate to 82 billion barrels of oil equivalents (produced, reserves, and undiscovered).
Most of the resource, however, more than 90%, has to be produced differently, as the overburden is over 75m thick. The in situ method, so called because the sand remains in place during production and no earth moving operations are required, involves injecting steam through a series of wells drilled horizontally into the reservoir. The high pressure and temperature cause the bitumen and the water to separate from the sand particles, and also lowers the viscosity of the bitumen.
This is known as Steam Assisted Gravity Drainage (SAGD) and is the most modern technology adopted to produce deeply buried oil sands.
"The heating of the bitumen with hot steam will make it flow like a highly viscous fluid, more like syrup, and we are planning to produce the Leismer field using huge amounts of steam. For every barrels of oil we produce, we will inject three barrels of water," says Rolf Utseth, vice president oil sand technology. "The majority of this, about 90%, will be reused, while the remaining water will be injected into an aquifer below the reservoir."
"However, we are planning the start-up of a pilot project in which we will inject light hydrocarbons to reduce the viscosity of the bitumen. This is meant to be more energy-efficient, as it means that we will be using less steam, and we also expect to increase the recovery rate this way. But as the solvent we put down is more expensive than the product we extract, we have to be sure that we are getting more oil back than we are putting in."
"Very close inspection of both the water and oil production will thus be extremely important in order to determine if injecting hydrocarbons is a viable solution to recover more oil and reduce the amount of steam we need to use," Utseth says.
In the pilot project, only three well pairs will be subject to this experiment. If successful, the entire Leismer field may use this technology, as well as the three other fields within the lease, meaning that the overall recovery rate of the 11 billion barrel resource might increase.
The StatoilHydro initial estimate is that about 2.2 billion barrels of oil may be produced throughout the life of the Kak Kos Desheh lease, an estimate that is it considers to be conservative.
"We are mapping sandstone layers that are thicker than 10m, but our reserve calculations are based on a cut-off of 15m, meaning that the reserves in the long run may turn out somewhat bigger. We also believe there is a considerable upside in reserves as we learn how to produce this resource effectively and new technology is introduced as we go along," Markestad says.
About 90% of the oil sands in Alberta are buried too deeply below the surface for open pit mining. With more than 70-80 meters of overburden, in situ techniques ("in situ" is Latin for "in place") are required, meaning that the sand is left in place instead of being mined (GEO ExPro, No. 2, 2004).
Steam Assisted Gravity Drainage - SAGD - involves drilling two parallel horizontal wells at the base of the bitumen reservoir, vertically separated by about 5 meters, in a reservoir that may be up to 40 metres thick. Steam, possibly mixed with solvents (light hydrocarbons), is injected into the shallower well and the hot bitumen, which has now acquired a lower viscosity, drains by gravity to the deeper producing well, where it is pumped out.
The basis of the process is that the injected steam forms a "steam chamber" that grows vertically and horizontally, like an expanding balloon, as more and more steam is pumped into the formation. The heat from the steam reduces the viscosity of the bitumen which then flows down into the lower wellbore. In the StatoilHydro operation, each pair of wells is separated horizontally by about 100 metres, and the producing wells are ideally 4 meters above the bitumen-water contact.
The concept of the Steam Assisted Gravity Drainage (SAGD) process was conceived in 1969, but it was not tested until 1980, when it was tried using vertical injectors. This later resulted in the first test of twin, horizontal wells, which proved to be economical. With the low cost of drilling horizontal well pairs, and the very high recovery rates of the SAGD process, SAGD has turned out to be economically attractive to oil companies and the preferred method of in situ recovery.
In those parts of the reservoir that are intersected by hot steam, almost all the oil is recovered. Outside the balloon, however, nothing will be recovered. The challenge is therefore to get the steam to flood the entire reservoir, from top to bottom.
The process is relatively insensitive to shale streaks acting as vertical barriers because the steam results in fracturing, allowing both steam and fluids to flow through. The overall recovery rate using the in situ method may therefore exceed 60-70%, and the same is achieved in heterogeneous reservoirs.
The world is not flush with oil any more. For the last 20 years or so we have in fact been producing more than we have been finding. That means, of course, that if the trend continues, we will one day run out of oil. And as is well known, there is a group of people ("Peak Oil"; www.peakoil.com) strongly advocating that we have reached the point in time in which we will - on a world-wide basis - produce less and less as the reserves are continuously being lowered.
This trend has been obvious in StatoilHydro's own backyard - the Norwegian continental shelf - for several years, meaning that the company sees the need to look abroad to sustain production.
"We have been looking for a long term investment in a long term resource, and in the Canadian oil sands we can foresee a production profile that will take us beyond 2050. Unlike a conventional oil field, here we can stay on a plateau level for 30-40 years," Markestad says. "That means we can look upon oil sands production like an industrial project."
"Another reason to be in Canada is that the country is considered more favourable than many other countries, as it is has a stable political climate and is a member of OECD."
StatoilHydro looked at several projects in the Canadian oil sands before successfully acquiring the North American Oil Sands Corporation (NAOSC) following a bid round about two years ago. "We were looking at reserves, development scenarios, and the organization before we made the bid, and eventually took over the whole company."
Since then StatoilHydro the sole owner of the Kai Kos Desheh lease with four designated fields has been appraising the resource in order to develop a detailed production plan. More than 650 vertical wells have been drilled down to the base of the reservoir at approximately 500 metres depth. Also, 2D and 3D seismic surveys have been shot as there is a need to have a detailed geological knowledge of the reservoir in the McMurray Formation.
"We are now also doing a 3D survey which will end up as a baseline survey for 4D seismic to be used for monitoring production," says Markestad.
"Exploring, appraising and producing the oil sands is very G&G-intensive, and we are now in the process of characterizing the reservoir in much the same way as we do with conventional reservoirs in other places," he says.
While several exploration wells have been drilled this winter, the drilling of the production wells has also begun. Planning to use the SAGD-technique, two wells are drilled in a pair, one above the other (see box), and 6 pairs out of 23 have been completed to date.
Each pair has a life expectancy of some 6-10 years, meaning that more wells have to be drilled later in order to maintain and possibly increase production.
"Producing the oil sands reservoirs is very time consuming because of the oil's high viscosity. You need to let the oil flow slowly down to the producing well. It is like draining a bog, you can't speed up the process. But it pays to be patient. In good reservoirs with clean sandstones the recovery rate may approach 80%, which is unheard of in conventional reservoirs," Per Markestad says, highly optimistic about the future of StatoilHydro's entry in the gigantic hydrocarbon resources of the Canadian outback.
Next edition:
Geological and geophysical challenges in the Leismer field
Updated: 20.05.2009 13:04 by Alf Kvassheim
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