Canadian oil sands: Dirty but needed?

Alberta offers the promise of huge oil reserves on America’s front door step. IFandP asks what the benefits and potential pitfalls are.

In Canada, oil companies are quietly harvesting one of the largest reserves of fossil fuels in the planet, but at the same time are coming under fire for the resulting impact on the environment, both in terms of water use and greenhouse gas emissions. Regardless of the drawbacks, the combination of minimal geopolitical and geological risk and close proximity to what is currently the largest market for crude oil in the world has made Alberta’s oil sands seemingly irresistible to oil companies and investors. The rapid commercialisation of the reserves has created conditions reminiscent of the Californian gold rush of 1848-1855, with whole new towns, such as Fort McMurray sprouting up as if from nowhere.

Oil sands, as the name suggests, are essentially bitumen or viscous heavy oil, with a API of 15-16, mixed with sand. Once the oil has been separated from the sand, it is then upgraded (this is necessary due to the fact that heavy oil is substantially discounted, compared to lighter, more easily-refinable oil) and then transported to a refinery, either in Canada or the US. The location of the refinery is contentious, given the large quantities of CO₂ released in the process and the future cost of emissions under possible carbon trading schemes.

Upgrading units are expensive and generate significant CO₂ emissions when in operation, so there is likely to be a shift towards handling the upgrading process at the refinery. This is precisely what is happening at Husky’s 200,000bpd Sunrise project, which will ship its output in the form of bitumen to refineries in the US.

In an interview with IFandP, Barry Munro, Ernst and Young’s Canadian oil & gas industry leader, pointed out that one of the major attractions of the Canadian oil sands is that they offer investors and developers a reserve base of around 50 years. The only other country capable of matching this is Saudi Arabia (see Table 1 for details of the province’s bitumen reserves.).

Mr Munro explained that it is effectively impossible for Canada to reduce its CO₂ emissions by 20 per cent by 2030, when over the same period, it expects to increase its oil production by five-fold. In terms of CO₂/bbl, Canada is about the same as Mexico and Venezuela, he elaborated. However, Canada’s oil companies are far more publicly accountable than PDVSA, Venezuela’s national oil company.

In addition, Canadian interests mesh to a far greater extent with those of the USA, especially given the fact that Hugo Chavez has loudly voiced his opposition to the US, going so far as to call President Bush “Satan” at a UN meeting. Mr Munro is therefore of the opinion that Canada can offer its southern neighbour secure long-term supplies and in the process, edge out its Latin competitor.

The Athabasca River supplies the majority of water to
the oil sands companies in Alberta, but according
to environmentalists this is beginning to have a
detrimental effect on fishstocks in the river as
allocations have reached dangerous proportions.

He also felt that the water card has been somewhat overplayed, claiming that in oil sand production, 90 per cent of the water used is recycled which compares favourably to corn ethanol, given that the latter is five times more water intensive. However, allocations from the Athabasca river, which supplies the oil sand producing regions with the majority of their water, are now greater than 10 per cent of its flow, a proportion which environmentalists warn is dangerous to the fish that inhabit the waters.

Another issue is that of air quality. A US EPA appeal board in June put an end to the proposed expansion of the Wood River III refinery, which is owned by ConocoPhillips and EnCana, by refusing to grant the necessary air permits. The two companies were looking to invest US$4bn in upgrading the refinery to handle the oil sands.

Due to increasing public concern regarding the environmental impact of their activities and mounting pressure from the Canadian government, oil sands companies have banded together in the hope that together they might be able to develop a system capable of economically capturing and sequestering the CO₂ generated from oil sand operations. The resulting organisation called ICO2N (Integrated CO₂ Network), has proposed a scheme which, if realised, “has the potential to reduce Canada’s CO₂ emissions by 20Mt [a year]”, according to its website. The situation is made if not more complicated, then at least more expensive, by the fact that oil sands projects in Canada are located a long way from areas where enhanced oil recovery using CO₂ could be a possibility.

CCS is increasingly looking like it will become a mandatory addition, as opposed to an optional extra, as the Canadian government has ordered that new oil sands projects and coal-fired plants that commence production after 2011, will have to sequester the bulk of their CO₂ emissions by 2018. John Baird, the Canadian environment minister, has estimated that the cost of compliance with such regulation will cost the relevant industries CAD25/t by 2010, before climbing to CAD50 and CAD65/t by 2016 and 2020, respectively.

Companies that fail to take appropriate measures are to face criminal prosecution under the scheme. Given that Canada is already emitting well above its target in terms of greenhouse gases, it is little wonder that the government is starting to take a stand on this issue. Existing oil sands plants will not completely escape, as those started after 2004 will be subject to more robust, cleaner fuel burning standards.

If oil prices remain strong and move back above US$147/bbl in the medium term, then oil sand companies may well be able to simply buy carbon credits as opposed to building their own CCS plants. This is because the Canadian government is setting its own carbon trading market and the credits involved can be used by oil sand operators for compliance with their targets.

The need for natural gas

The other major constraint for the industry as a whole is the amount of natural gas required to treat the oil sands to the point where they can be refined. Currently, this amounts to some 0.6bnft³pd, but it has been estimated that this could increase to 2.2bnft³pd by 2020. When one considers that Canadian gas production dropped 5.9 per cent in 2007, down to 16bnft³pd then its clear that high natural gas use is unlikely to be sustainable in the long term. Interestingly, there signs that nuclear power is being put forward as an alternative. Both Areva and Canada’s own nuclear vendor, Bruce Power, have expressed interest in building up to four 1GW nuclear reactors, with the aim of powering the oil sands industry. In the meantime, Alberta’s provincial government, in association with the industry, has developed “fuel gas best management practices” to ensure that as much gas as possible is conserved.

Bitumen production

There are a number of novel strategies currently being employed to extract the bitumen from oil sands. The traditional open-cast mining approach typically converts four tonnes of material (including overburden) into two tonnes of oil sands, which in turn is processed into 1.2 barrels of bitumen, before finally resulting in a single barrel of synthetic crude. Mr Munro highlighted the efforts of Petrobank, a company which is looking to perfect an in-situ refining process, trademarked as THAI (Toe-to-Heel Air Injection). The method starts a fire underground, which is maintained using air injection wells. The resulting combustion zone warms the oil to the point where it can flow. Horizontal production wells can then harvest the oil.

This approach has several key advantages. Unlike more traditional methods, it requires very little fresh water. The company also claims that it results in 50 per cent lower CO₂ emissions than would otherwise be the case, and because the action occurs beneath the surface, operations have a smaller surface footprint, making reclamation easier and less expensive. Although the system sacrifices some of the reserve in order to heat the oil to the point where it can be extracted, Petrobank claims that THAI can recover an estimated 70-80 per cent of oil-in-place. As the reserve itself provides the energy needed for its extraction, natural gas consumption is also reduced.

Similar techniques include:
• Cyclic steam stimulation, which as the name suggests, injects steam into the oil sands deposit
• Steam-assisted gravity drainage (SAGD) involves injecting steam into a horizontal well to reduce the viscosity of the bitumen to the point where it can flow into a lower parallel wellbore. One advantage from this process is that although the resulting sour crude is sold at a discount, by-products can be used to fuel the process and the required upgrading unit is about half the price of the type normally needed.
• Vapour extraction (also known as VAPEX) uses solvents instead of steam. As 80 per cent of the tar sands in Alberta are too deep to be exploited via open-cast mining, in-situ techniques are likely to remain the methods of choice.

Unfortunately, according to Strategy West, a Calgary-based firm, steam-based in-situ projects are more CO₂ intensive than their open-cast mining counterparts, generating around 65kg/bbl, compared to only 15kg/bbl for mining operations. There is also the emissions from refining to consider. According to a WWF report, refining bitumen from oil sands produces eight times as much CO₂ as processing traditional oil.

As a result of the above, in-situ methods are more sensitive to any changes in greenhouse gas emission regulations or compliance costs, which according to Bob Dunbar, president of Strategy West, are “one of the main uncertainties facing the industry right now” (The Daily Oil Bulletin). Mr Dunbar believes that such costs could add US$5/bbl or more to production costs.

Suncor’s oil sand from Fort McMurray, Alberta, is mined using shovels that
hold 100t, loading huge 240-38t trucks. Image courtesy of Suncor

Although last year saw mining projects account for 286mbbl of bitumen production, significantly more than the 196mbbl from in-situ projects, the latter are growing at a faster rate, increasing by 7.1 per cent in 2007, compared to only 4.3 per cent for mining, according to the Energy Resources Conservation Board of Alberta (ERCB). The Board’s July update states that at year-end 2007, around two-thirds of initial minable established reserves were under active development.

The combination of longitude and lack of coastline, results in cold harsh winters. As a result, oil sands operators in Alberta at the mercy of the weather. This can mean that production is disrupted. For example, recently, the Canadian Oil Sands Trust, reported that instruments at its Syncrude Canada oil sands venture froze up due to temperatures of around -40˚C in January causing output to stop. Full production was not resumed until February. As a result, Syncrude had to reduce its full-year forecast from 115mbbl down to 108mbbl.

Transporting the product

Alberta is landlocked and the US is a strong, profitable and relatively nearby market for synthetic crude, so moving blended bitumen (blending is done to improve its flow characteristics) by pipeline is the preferred method of transportation. Canada’s crude oil pipeline network is already the largest in the world and currently has an asset value of approximately US$20bn, transporting 1.85mbpd of crude a day to international markets according to the Canadian Energy Pipeline Association (CEPA). Despite this impressive scale, the Association has indicated that Canada’s pipeline assets will have to double in size by 2015 in order to meet forecasted production increases.

As can be seen from Table 2, there are a number of pipeline projects recently completed or due for completion. In fact according to CEPA, at least US$20bn worth of projects are on the drawing board. The Keystone pipeline is one of the most ambitious, and is being constructed by a partnership between TransCanada, Calgary, Alberta and ConocoPhillips, at a cost of US$5.2bn. The pipeline has recently won approval from the Canadian government and received US approval to cross the border between the two countries in March. Once constructed it will cover 2148 miles, from Hardisty, Alberta, to Wood River and Patoka in Illinois, and also to Cushing in Oklahoma. The line to Illinois is expected to be complete in late-2009, with the Cushing line following in late 2010.

The challenges ahead

Although changes to GHG emission regulations are a concern, the industry is more influenced by the price of crude, as the costs involved in oil sands production are a quantum leap above conventional oil projects in, for example, the Middle East. There is considerable variation in the oil price suggested by analysts as being the break-even point for oil sands. StatoilCanada claims that US$80/bbl or higher is required, which contrasts with the US$60-70/bbl and US$50/bbl, suggested by Mr Dunbar and Barry Munro, respectively.

In addition, the Albertan oil sands cannot escape some of the problems impacting the oil industry at large, such as the ballooning capital costs associated with new projects. The last four major oil sand projects have experienced cost overruns in excess of 60 per cent and projects expenses are now running 200 per cent above those seen at the beginning of this decade.

A contributing factor to this situation is a labour shortage. This is putting pressure on operators to increase wages and has already delayed the onset of full production at Canadian Natural’s Horizon mine to early 2009, consequently pushing up the cost of the project by eight per cent and taking it to an eye-watering US$9.27bn. A report by the Construction Owners Association of Alberta has warned that a construction labour shortage is expected to continue right through 2009. The inflationary environment has led Imperial Oil to hold off its decision regarding the construction of a US$8bn oil sands mine until the start of next year.

A more abstract issue is that of energy return on investment. Producing crude from oil sands is so energy intensive that it yields only 5-10 per cent of the net energy gained from conventional light crude production. Therefore, it is worth bearing in mind that the oil sands, despite their abundance, may not strictly be the best investment in terms of overall energy gain.

Investment outlook

Regardless of these problems, investment is expected to continue to flow into the region, albeit at a more sober level than that previously experienced. Mr Dunbar expects capital expenditure to average US$25.2bn in 2008-20, with bitumen production reaching 6mbpd by 2020. This is a more optimistic scenario than that envisaged by the ERCB, which in July, released an update predicting that bitumen production will reach 3.23mbpd by 2017 (up from the 1.32mbpd seen in 2007), 1.46mbpd of which, will come from in-situ projects.

Suncor Energy, one of the key players in the Albertan oil sands, is single-handedly looking to spend CAD7.5bn as capital expenditure in 2008, 80 per cent of which has been earmarked for growth projects, primarily in oil sand projects. In addition, ConocoPhillips’ president Kevin Meyers announced back in February that his company is poised to dramatically boost its output from oil sands projects in the coming years. ConocoPhillips currently produces 60,000bpd of crude from oil sands, approximately half of which is from a nine per cent stake in the Syncrude Canada joint venture, with the balance coming from two joint ventures with EnCana.

However, a number of developments have been delayed, such as the Fort Hills expansion and the Kai Kos Dehseh, Sunrise and Joslyn creek mining projects. Canadian Natural Resources Ltd has deferred its upgrader indefinitely and Total has made a similar decision with regard to its Northern Lights project. The investment environment is also complicated by the difficulty of acquiring finance in a post-sub-prime world and with all the major prospective areas already snapped up, exploration activity is likely to essentially be over, according to Michael Kahn, vice-president and director of TD Securities a financing company, involved in oil sands development.

This, coupled with the high costs involved in developing oil sand projects does mean that the industry has little to fear from new entrants at this point in time. The fact that both Mexico and Venezuela are likely to see declines in their oil production due to inadequate investment and the increasing scarcity of oil resources, particularly those accessible to the international oil majors, means that demand for their product is almost guaranteed.

Oil sands companies have been quick to take advantage of the rising price of sulphur, a by-product of bitumen refining, on the international market. ERCB has reported that it has risen from US$50/t in mid-2007 to US$150-350/t. China has been the main importer of sulphur from Alberta, but the province is starting to see stiff competition from the Middle East, which contributed to a 24 per cent decline in exports to China in 2007. The country uses sulphur in the production of phosphate-based fertilisers and sulphuric acid.

Where will it go from here?

So, to summarise, the two most important factors that together determine the prosperity of the oil sands industry are oil prices and the growing issue of CO₂ emissions. While the former may have fallen back, long-term expectations are still bullish, due to the problems facing both international and national oil companies. Also, despite the recent dip in US oil demand, there is little sign that the next administration will be able to wean the country off its oil addiction.

The future requirement for carbon capture and sequestration is more of a concern, as it will involve implementing a number of novel technologies on a massive scale. The risk is fundamentally one of cost. It may well be possible to sequester carbon from oil sands projects, but doing so and still generating an healthy return may be a different matter altogether.

For more information, consider visiting:
http://oilsands.alberta.ca/ – this has a full map of current and proposed oil sands projects in its industry section
www.cepa.com
www.suncor.com