When Tom and I heard the news earlier this week about the hundreds of ducks killed earlier this week when they landed on a Syncrude tailings “pond”, we both immediately thought of an article we had read late last year in albertaviews magazine; the article was “The Ponds” by the Calgary investigative journalist Andrew Nikiforuk, in the November 2007 issue.
I can’t find a copy of the article online anywhere, but Nikiforuk wrote a similar article for The Globe & Mail the other month, “Liquid Asset: Could the oil sands, Canada’s greatest economic project, come undone simply because no one thought about water?” (March 28, 2008) which you can in fact still find online; many thanks to The Globe & Mail. I recommend it, even if you don’t live in Alberta or Canada because if you’re in North America, the question of an adequate and clean water supply applies to us all.
Some 90% of the water withdrawn from the Athabasca River for the oil sands ends up as waste in tailings ponds. Nearly a dozen ponds line both sides of the river and pose an enduring threat to the entire Mackenzie River basin. Many are already leaking and creating their own tainted wetlands. Even the pro-development Alberta Chamber of Resources considers this primitive form of long-term storage “a risk to the oil sands industry.”
The ponds, which contain a ketchup-consistency mix of water, oil and clay, give off a strong aroma of hydrocarbons and rarely freeze. Minnows dropped into the ponds die within 96 hours; unwary ducks get coated by surface oil and drown.
The ponds, like everything in the oil sands, are supersized. The dykes that contain the ponds can reach 100 metres in height. Although the ponds already cover 55 square kilometres of forest and muskeg, they’ve just begun. Within a decade, they will cover an area of 150 square kilometres.
According to the Alberta Chamber of Resources, the industry spits out six barrels of sand and 11/2 barrels of fine tailings for every barrel of oil it makes. Altogether, the ponds contain 5.5 billion cubic metres of sand and fluid waste.
Syncrude, the largest producer in the oil sands, also owns the largest tailing pond. Every day, Syncrude dumps 500,000 tons of tailings. The Syncrude Tailings Dam is deemed by the U.S. Department of the Interior to be the world’s largest dam by volume of construction material. The pond, built in 1973, covers 22 square kilometres and holds 540 million cubic metres of water, crud and sand. When China completes the Three Gorges Dam this year, Syncrude will surrender the record. “We are still second-best,” quips Randy Mikula, who has been studying the tailings waste problem for 22 years.
As the team leader on the subject at Natural Resources Canada’s CANMET Energy Technology Centre in Devon, Alberta, Mikula calls the tailings waste problem a “frightening” and vexatious issue. Engineers originally thought that the tailings waste would quickly settle, leaving clear water on top. But that never happened, thanks to what Mikula calls “the bad behaviour of clays.” He suspects the waste won’t settle to solid form for thousands of years. “So something has to be done.”
The prospect of a major dyke failure has also raised concerns. Every tailings pond contains polycyclic aromatic hydrocarbons (PAHs), napthenic acids, heavy metals, salts and bitumen. The Canadian Association of Petroleum Producers reports that of 25 PAHs studied by the U.S. Environmental Protection Agency, 14 are human carcinogens. Both PAHs and napthenic acids kill fish.
In 2003, the intergovernmental Mackenzie River Basin Board identified the tailings ponds as a singular threat. It noted that “an accident related to the failure of one of the oil sands tailing ponds could have a catastrophic impact on the aquatic ecosystem of the Mackenzie River basin.”
Peachey, Schindler and other water experts agree. Engineering studies also highlight an uncomfortable truth: The reliability of mine waste containment dykes is among the lowest of all earth-made structures. “The longer the tailings sit there, the more likely there will be a major extreme weather event and a big dyke failure,” predicts Peachey. In Schindler’s view, “the world would forever forget about the Exxon Valdez” if a dyke failed.
The Alberta government is getting worried. Preston McEachern calls the ponds his No. 1 concern: “We know they leak and we capture these leakages or let some fall into poor-quality water formations…but it’s the long term. What do we do as they build up?” The good news, concludes Mikula, is that both industry and government are pouring millions into research on containment.
The bad news is that there is already evidence of downstream health effects. Last November , a study for the Nunee Health Board Society in Fort Chipewyan, 300 kilometres north of Fort McMurray, found elevated levels of mercury, arsenic and PAHs in local waters. The report asked if these contaminants were connected with dramatic increases in fish deformities and rare forms of cancer in the community, and called for a major health study. To date, the Alberta government has not taken up the recommendation.
Downstream users are worried. “We have tremendous concerns in terms of the pace of development and contamination issues,” says Michael Miltenberger, Minister of Environment and Natural Resources for the Northwest Territories. “What happens on the Athabasca affects people as far away as Inuvik.”
Open-pit mines aren’t the only big water users in the oil sands. About 80% of all bitumen deposits lie too deep in the ground for open-pit mining. To access these lower-quality deposits, the oil industry has developed a number of novel technologies. The most popular, steam-assisted gravity drainage, injects high-pressure steam into a bitumen formation with one pipe and then brings the melted hydrocarbon to the surface with another pipe.
Land leased for SAGD production now covers an area larger than Vancouver Island, which means that this kind of drilling could affect water resources over an area 50 times greater than the open-pit mines. The industry calculates that it takes about one barrel of raw water (sometimes taken from deep, salty aquifers) to produce a barrel of oil using SAGD. But researchers suspect it often takes much more water. “It’s just as big a problem as the mines, and it’s not going away,” adds Peachey. “And we don’t have a plan or strategy for it other than reducing water usage as fast as possible.”
SAGD’s thirst for water, mostly used to make steam, has a host of implications. Industry used to think that it needed only two barrels’ worth of steam to melt one barrel of bitumen out of deep formations. But the reservoirs have proved unco-operative. The multibillion-dollar Long Lake project south of Fort McMurray, a joint venture of Nexen and Opti Canada, originally predicted an average steam-to-oil ratio of 2.4:1. But the joint venture now forecasts a 3.3:1 ratio.
This dramatic but typical loss in efficiency means companies have to drain more aquifers to produce more steam. In order to heat the water, the companies purchase more natural gas, which, in turn, means more greenhouse-gas emissions. By some estimates, SAGD could ultimately consume the equivalent of the entire gas supply of Western Canada. “A lot of projects may prove uneconomic in their second or third phases because it takes too much steam to recover the oil,” says one Calgary-based SAGD developer, who asked to remain anonymous.
Due to the spectacular projected growth in SAGD (nearly $4 billion worth of construction a year until 2015), Alberta Environment can no longer accurately predict water demand. The Pembina Institute, a Calgary-based energy watchdog, reported that the use of fresh water for SAGD in 2004 increased three times faster than the government forecast of 5.4 million cubic metres a year. Despite the province’s effort to get companies to switch to salty groundwater, SAGD could still be drawing more than 50% of its volume from freshwater sources by 2015.
SAGD also generates formidable piles of waste. Companies can’t make steam without first desalinating the brackish water. An average SAGD producer generates as much as “15 million kilograms of salts and water-solvent carcinogens,” which simply gets trucked to landfills, the SAGD developer says. Because the waste could eventually contaminate groundwater, John Robertson of CH2M Hill calls the salt disposal problem “a perpetual care issue.” The anonymous SAGD developer adds, “There is no regulatory oversight of these landfills, and these problems will be enormously difficult to fix.”
But the biggest sleeper issue for SAGD production may be overall changes in the water table over time. “If you take out a barrel of oil from underground, it will be replaced with a barrel of water from somewhere,” explains Peachey. Here again, the lack of research data is problematic: Alberta “doesn’t have enough data to understand surface and groundwater connections” in the oil sands region, says Peachey.
Given SAGD’s record as a natural gas burner and producer of greenhouse gas emissions (three times that of conventional oil), both the Canadian government and the industry regard nuclear power as an energy alternative. The French nuclear giant Areva has said it can add four reactors to the province’s grid, while Energy Alberta Corp. has suggested building as many as 11 Candu reactors. While some of these reactors would provide power for bitumen mining, oil shale (a hard-rock form of bitumen) and SAGD operators, others would upgrade bitumen into marketable oil.
But that plan doesn’t solve the water problem, because nuclear power requires enormous volumes of water for cooling. It is estimated that just one reactor, proposed for Grimshaw, would require 20 times the amount of water used by the city of Calgary. Such a plant would also lose nearly 57 billion litres of water a year to evaporation.
The final act of the oil sands process will be reclamation of the land. The mining will eventually dig up an area that is the size of Lake Erie and is largely comprised of boreal wetlands. Wetlands are known as the “kidneys” of a watershed because they regulate flow and remove contaminants. According to Lee Foote, a wetlands specialist at the University of Alberta, no one really knows yet how to reclaim a fen, bog or peatland in the oil sands. He calculates that the cost of replacing the projected 96,000 hectares of mined wetland, depending on the replacement standards adopted, could, at $25,000 a hectare, range between $7 billion and $24 billion. “It’s a significant liability if it can be done at all,” Foote says.
Turning bitumen into cleaner oil requires “upgrading” to create a product that can be refined into fuels and petrochemicals. The process also requires — surprise — lots of water for cooling and refining. Thus, proposals to build as many as 15 upgraders outside Edmonton, along the North Saskatchewan River, have spawned yet another water controversy.
Given that the industry has neither the room nor the labour force to build more upgraders in Fort McMurray, a host of oil companies have proposed building nearly $30 billion worth of upgraders in the area east of Edmonton that has become Alberta’s industrial heartland. Three separate pipelines would supply the upgraders with fresh bitumen.
But the upgraders, like their bitumen-mining cousins, gulp lakes of water. The North West Upgrader, under construction by a Calgary firm, will annually use up to 5.6 billion litres of water from the North Saskatchewan—a river only a third the size of the Athabasca.
Last year, a report done by the engineering firm Morrison Hershfield for Strathcona and Sturgeon counties added up the water footprint for the upgrader boom. Each facility would require anywhere between 16 and 20 megalitres of water a day — the equivalent of six to eight Olympic-sized swimming pools. By 2026, their daily thirst could amount to between 200 and 240 megalitres or the equivalent of more than 80 Olympic-sized swimming pools. In contrast, the city of Edmonton uses 350 megalitres a day and returns most of that water to the river in treated form. The upgraders, however, won’t do that: Some 70% of the water will be consumed or lost to evaporation.
The oil patch rates as the North Saskatchewan basin’s second-highest water user (18%), behind other industry in general. The upgrader boom, however, will make the petroleum sector No. 1. In fact, a recent report for the North Saskatchewan Watershed Alliance says that “nearly all of the projected increase in surface water use will be in the petroleum sector.” By 2015, the upgraders’ demands on the river will increase water use by 278%, and, by 2025, by 339%. John Thompson, author of the report, says the absence of an authoritative study on the river’s ecosystem remains the central issue. “We don’t know what it takes to maintain the river’s health.”