As the oil sands expand, so do the headaches

Posted August 16, 2007 in [Energy]

August 15, 2007, Petroleum Review - All is not well in the land of sandy oil, writes Gordon Cope. As plans to triple production from 1.1mn b/d to over 3mn barrels over the next decade get underway, a number of major hurdles have come to the forefront. First is the growing political will in Canada to curb the growth of greenhouse gas emissions that contribute to global warming; second is the clamour to review the current provincial fiscal regime that allows operators to recoup all their capital investments before paying royalties; and third is the increasing environmental pressure to acknowledge the accumulated impact of so many megaprojects in one place. However, there are other concerns that lie slightly below the radar that may have an even greater impact.

The Regional Municipality of Wood Buffalo, which encompasses Fort McMurray and the surrounding oil sands, is suffering growing pains. The population of this frontier town, carved from the Arctic boreal forest, has almost doubled in the last decade to 64,500, and, according to a government report, it will triple by 2011. Such a growth spurt has placed severe strain on government services. Mayor Melissa Blake stated that there is a dire need for more schools, waste water treatment, housing and services; the health care system alone requires a 100% increase in residential doctors. In 2006, when C$20bn ($18.7bn) in new oil sands applications came before the Alberta Energy and Utilities Board (EUB), the municipality took the unprecedented step of intervening, begging the regulator to slow down the pace of development.

The strains are not limited to Fort McMurray. The two-lane highway which connects the oil sands to Edmonton, some 450 km to the south-west, is woefully inadequate to handle the commercial and passenger traffic load, let alone the truck convoys that slowly trundle boilers and other large prefabricated modules northwards, and must be expanded. Nearby Aboriginal communities, which are courted by project operators to supply contractual services, are also in need of roads, housing, water and sewage treatment. When everything is tallied up, the National Energy Board (NEB) estimates that the region requires C$1.2bn ($1.1bn) to meet all its infrastructure needs.

In March, the Alberta government announced a comprehensive plan to help Wood Buffalo by investing C$396mn ($369.5mn) over the next three years. Over C$200mn ($186.6mn) will be spent on health care, building three new clinics and offering bonuses to attract new staff. Water treatment will receive C$103mn ($96.1mn) in order to complete a facility currently under construction. Housing will receive a C$52mn ($48.5mn) boost to build 300 affordable units. Local officials were pleased with the announcement, but others felt that the initiative was inadequate. 'They're taking baby steps,' said Provincial Opposition Leader Kevin Taft. 'Three hundred housing units for one of the largest industrial developments on the planet just isn't going to make much of a difference.'

Calls have also gone out to industry to contribute to infrastructure needs. Although the oil and gas sector's general opinion is that taxes and royalties should fund such services, there is an understanding that everyone must help. 'What I do believe is that all of us - the town, the cities, the universities, the province and industry itself - have to work together to get this right,' said Shell Canada's head, Clive Mather.

Gas pains

Considering that Canada produces around 17bn cf/d of natural gas, one might not, at first glance, think that a lack of the stuff would be a potential problem. However, conventional fields are fast dwindling and non-conventional sources, such as coal bed methane, tight sands and shale gas are not filling in the gaps.

In order to produce the oil sands, a great deal of natural gas is consumed - in the order of 500 cf to 1,000 cf - to produce one synthetic barrel of oil. Currently, the oil sands consume 0.7bn cf/d, about 1% of North America's total usage. According to the NEB, however, that usage could increase to 2.1bn cf/d, or 3%, in the next ten years. Part of that increase was expected to be met from the production of stranded Arctic gas, but delays in the approval process for the Mackenzie gas project (MGP) pipeline have not only pushed the delivery date back into the mid-next decade, but increases in the budget from C$7bn ($6.5bn) to over C$16bn ($14.9bn) have placed the entire project in doubt.

Oil sands producers have various ongoing strategies to reduce natural gas consumption - including lowering the temperature at which mined bitumen is separated from sands and clays - but much of the natural gas is consumed by in-situ production, such as steam assisted gravity drainage (SAGD), in which water is heated to steam and injected to warm the reservoir sufficiently to allow bitumen to be pumped out. A new production technique called fire flooding, in which air is injected into the reservoir and ignited to form a fire front, has shown promise. However, perhaps one of the most intriguing alternatives is to use nuclear energy. Gary Lunn, Federal Natural Resources Minister, was recently asked about the nuclear option in the oil sands. 'It is not a matter of if, but when, a nuclear reactor will be built to supply energy,' he said. 'Nuclear energy is relatively emission-free, produces no greenhouse gases, and there are no pollutants going out.'

To that end, Energy Alberta Corporation is planning to supply future electricity needs to new oil sands projects by building two Advanced Candu Reactors (ACR) capable of generating 2,200 MW. 'We have a number of off-takers, and we are moving ahead,' says Wayne Henuset, President. 'Three communities in north-central Alberta would like to host them. We hope to put an application for a site in the next 90 days.'

The units will be located far enough away from Fort McMurray to avoid infrastructure and labour issues there. 'We will transport the electricity by transmission lines. There won't be any steam shipped,' Henuset continues. Most of the critical components will be manufactured offsite. Approximately 2,000 workers will be needed during peak construction, and 800 permanent staff to operate. 'We hope to start in 2010-2011, and be in operation by 2016-2017.'

Both facilities will cost C$6.2bn ($5.8bn) in total, and deliver electricity at the cost of C$75/MWh ($70/MWh). 'Natural gas costs a little less, but if they come in with carbon costs, it will be more,' says Henuset.

While nuclear reactors would sideline much of the expected demand in natural gas and reduce the growth in greenhouse gas (GHG) emissions, there is still the issue of radioactive waste. Energy Alberta Corporation's plan is to store spent fuel rods on site until they can be recycled, but such technologies are expensive. In order to weigh all available alternatives, a natural gas-cutting study is being commissioned by EnergyINet, a joint government and industry research organisation. It will look at alternative sources of oil sands energy (including bitumen, coal and coke gasification and nuclear energy), from economic, environmental and sustainability aspects. 'We will be putting all the options into a matrix and evaluate the best possible solution,' explains Soheil Asgarpour, President of Petroleum Technology Alliance Canada.

Water, water everywhere ...

While most conventional oil reservoirs produce lots of unwanted water, the opposite is true for the oil sands. It takes about 10 barrels of fresh water to transport and separate the bitumen from sand and clay before it can be processed into synthetic crude. Most of that is recovered, up to 80%, but between two and four barrels ends up as gelatinous clays in tailings ponds.

Normally, this would not be a great problem. Canada is well known for its abundance of water, and the Athabasca basin in which the oil sands are situated is blessed with a good supply. Unfortunately, that supply varies widely with the seasons. During the spring and summer, run-off from the Athabasca glacier in the Rockies fills the Athabasca River to overflowing, but in the winter, when precipitation falls as snow, the river drops to flows under 100 cm per second (cm/s). The Alberta government, which has already allocated slightly over 11 cm/s to current and future oil sands projects, has placed a cap of 15 cm/s on withdrawals.

Unfortunately, this is still up to 15% of the minimum flow. 'There is a direct relationship between how much water is in a river and the overall health of its fishery,' notes Dan Woynillowicz, a Senior Policy Analyst with the Pembina Institute, a respected environmental NGO (non-government organisation). 'The First Nations downstream rely on the fishery for subsistence and a business. You can take water out, but if you take too much, there will be irreversible changes.'

When flows reach a minimum, Pembina recommends that withdrawals temporarily stop. 'There are options to allow shut off,' says Woynillowicz. 'In the short term, you can increase the amount of storage on site, which is what new projects are building. In the longer term, you can reduce the amount of water going to tailing ponds by producing drier tailings. You can increase the rate of taking tailing pond water back using treatments like RO (reverse osmosis). And you can take steps to reduce fresh water requirements.'

Changes in the type of oil sands production may also help. Currently, most production is mining, but as the oil sands expand to 3mn b/d, about half will be produced in-situ by SAGD, which uses ground water that has been boiled to steam and injected underground to melt the bitumen. While SAGD does not impact the Athabasca River, there is no clear idea about where the groundwater is, how much there is, and how it interacts with surface water.

Eventually, many water concerns may be sidelined by techniques that use no water at all. Fire floods for in-situ recovery eliminates water altogether, as does Vapex, a procedure in which solvents are injected underground to dissolve the bitumen and allow it to flow to the surface.

However, the benefit of these experimental procedures lies in the future, while the need to manage water is in the present. 'Water is emerging as a top-of-mind issue to Albertans,' comments Woynillowicz. 'There will be increasing pressure to protect water resources. I can foresee water being a limiting factor for oil sands growth unless the government takes steps toward managing our water requirements.'

Looking ahead

There is a final, major concern, however, that may make all of the above worries moot. In a recent oil sands report, Wood Mackenzie stated that the capital costs per peak flowing barrel had increased by 55% since the beginning of 2005, primarily due to labour and material shortages. As a result, proposed capital spending budgets for the next decade have risen from C$88bn ($82.1bn) to C$125bn ($116.6bn).

All of this has caused companies to cancel projects or do major re-evaluations. During a recent AGM, Petro-Canada's CEO sought to address the future of the company's Fort Hills oil sands project, slated to deliver 170,000 b/d of synthetic crude by 2011. 'These projects seem to be getting hammered in a number of different ways,' said Ron Brenneman. 'All of these things weigh upon a project. We're going to have to wait and see what it all looks like when we put that against the costs that we see.'