this article is heavily footnoted and i have tried to eliminate all the footnotehis article is heavily footnoted s. if i missed a few, i am sorry, because there are numerous numerical citations throughout. also, it is from a canadian source, so the system of connotation is different than what we use in the u.s.
the original, much longer and heavily footnoted article is from the environmental health perspectrives website.
Digging and Drilling
Sprawling across much of northern Alberta’s boreal forest under an area a little smaller than the U.S. state of Illinois lies a valuable blend of bitumen, sand, minerals, and other materials. For centuries, native peoples valued the tarry blend for repairing canoes. Today, improving technology has made it possible to extract the bitumen and process it into products similar to those produced from crude oil. With today’s technology, about 27 billion m3—or around 10%—of the estimated bitumen deposits can be economically extracted.
That puts Canada’s oil reserves second only to Saudi Arabia’s 42 billion m3 and a little ahead of Iran’s 23 billion. By 2025, bitumen extraction is expected to rise 2.3 times over 2010 activity. No one is willing to hazard a guess about peak activity timing or magnitude because investments are driven by unpredictable factors such as world oil prices, future technological advances, government regulation, development of alternative energy sources, and world events such as terrorism and climate change.
Extracting oil from the sands is expensive, but the 40 or so companies working the fields are finding it lucrative, with net profits of $22.8 billion in 2008. Preprofit expenses include payments to the Government of Alberta: $3.8 billion in 2008 alone compared with $11.9 billion over the preceding 10 years. Alberta has had a financial stake in the oil sands for about 80 years, since the Canadian federal government transferred ownership of most natural resources to their respective provinces.
Surface mining is the only feasible process for extracting bitumen deposits down to a depth of 75 m. These are spread under about 4,800 km2 of the Athabasca oil sands region, or 3.3% of the 142,000-km2 bitumen-bearing zone, and account for about 20% of the estimated reserves and about 55% of current bitumen extraction. When deposits are deeper than 150 m, companies drill down and use steam heat to liberate the bitumen, a process known as in situ extraction. By 2015, in situ extraction is expected to dominate bitumen production, according to Davies.
Each process has its environmental tradeoffs. As of March 2009, surface mining had already disturbed more than 602 km2 of land and led to the creation of about 130 km2 of tailings ponds that contain dozens of toxic substances. Surface mining also requires 4–6 times more fresh water withdrawal than in situ extraction. In situ extraction, on the other hand, has a carbon footprint about one-third greater than that of surface mining. Both processes involve “enormous land disturbance and reclamation issues that encompass . . . the scarred landscape left by surface mines and the forest clearing that is characteristic of in situ production.” All these effects are particularly relevant to the First Nations peoples whose reserves (traditional hunting grounds) are located on or near the oil sands deposits.
Although the RSC panel found no evidence that people are currently being harmed by oil sands activity, that conclusion is based on testing for only a limited number of substances and reliance on some standards that may not be fully protective, says Kevin Timoney, an ecologist and principal investigator with Alberta-based Treeline Ecological Research. Moreover, chronic effects cannot yet be ruled out, and any health impacts later attributed to oil sands development could potentially affect tens of thousands of people living and working in and near the deposits.
There are more than 1,400 known pollutants emitted by oil sands operations. Among the few that are monitored are sulfur oxides (SOX), nitrogen oxides (NOX), hydrocarbons, and fine particulate matter (PM2.5). Emissions of SOX and other sulfur compounds, NOX, and total hydrocarbons have been rising during the past decade, but the RSC panel concluded that “current ambient air quality monitoring data for the region show minimal air quality impacts from oil sands development . . . except for noxious odour emission problems over the past two years.”
Indeed, hydrogen sulfide at three monitored industrial sites has exceeded the 1-hour guideline more than 2,400 times across three locations during the past decade and exceeded the 24-hour standard more than 400 times in the same period. Data on exceedances of the hydrogen sulfide guideline were not available for Fort McKay, a small village 54 km north of the boom town of Fort McMurray, but the RSC authors conclude that there are serious odor problems in this and possibly other locations: “Resolution of the odour problems being caused by oil sands development is clearly necessary.”
Alberta Environment spokeswoman Jessica Potter says her agency expects industry to solve the problem. “We put in effect an environmental protection order [EPO] to ensure this happens,” she says. “EPOs are enforceable by law, and disregarding an EPO can result in criminal charges.” Meanwhile, Davies says his members are working on the issue. “It’s a learn-as-you-go scenario,” he says. “We’re trying to find different ways to fix it.”
Annual average concentrations of SOX, NOX, PM2.5, and carbon monoxide (CO) from 2001 to 2008 in Fort McMurray were about one-third to three-fourths the concentrations in Alberta’s major urban areas of Edmonton and Calgary, although Fort McMurray exceeded provincial 24-hour average PM2.5 allowances 12 times compared with Edmonton’s 9. PM2.5 exceedances at Fort McKay have been more than double those at the village of Anzac, located in the middle of traditional oil and gas operations, although the exceedances cannot be directly attributed to oil sands operations since other activities are occurring in each area. As anecdotal evidence of potential particulate matter concerns, a panel commissioned by Environment Canada to evaluate the impacts of oil sands operations referred to the “ubiquitous dust” that was present during their site visits. Findings in two small air pollutant personal exposure studies involving participants wearing portable monitors in four regional communities demonstrated indoor air provided higher contaminant exposures than ambient air.
Total industry-estimated volumes of SOX, NOX, PM2.5, CO, volatile organic compounds, polycyclic aromatic hydrocarbons (PAHs), lead, mercury, and cadmium put the oil sands industry in anywhere from third to twelfth place—depending on the pollutant—among all Canadian industrial sources.
Downwind from oil sands operations, elevated NOX concentrations that can contribute to aquatic acidification have been detected at least 150 km east of the Alberta–Saskatchewan border, but elevated SOX from oil sands was not detected at any location in Saskatchewan. One study found elevated concentrations of polycyclic aromatic compounds (PACs) in snowmelt within 50 km of oil sands operations. Despite reductions in emissions per barrel of bitumen produced, Hrudey says greenhouse gas emissions from oil sands production are about 5% of Canada’s total and are expected to continue rising because of production increases that outstrip efficiency gains.
In its December 2010 report, an expert panel commissioned by Environment Canada to assess oil sands monitoring research wrote, “[O]ur site visits had an indelible impact. It is hard to forget the sheer extent of landscape disruption, the coke piles and the ubiquitous dust.”
Water pollution can potentially occur via many pathways. Massive tailings ponds associated with surface mining contain numerous toxic contaminants, including naphthenic acids, polar and saturated hydrocarbons, asphaltenes, benzene, phenols, cresols, phthalates, toluene, lead, mercury, arsenic, nickel, vanadium, chromium, and selenium. These can leach at low concentrations through dams and dikes, and although seepage rates must be quantified, the RSC panel notes that “very few published data are available on the dynamics of groundwater flow and the fate of process water contaminants in the impoundment structure.” Volatile contaminants can be transported by air, and if a tailings impoundment were to rupture, local wetlands and waterways would face a catastrophic influx of contaminants.
In situ extraction processes, which use steam heated to more than 250ºC, can alter subsurface dynamics such as leaching of arsenic into groundwater. Deep-well injection of wastes can increase the potential for groundwater and surface water contamination. Groundwater withdrawals have lowered the water table at least 40 m in some locations, altering the flows between surface water and groundwater. Overall, the RSC panel concludes, the complex interactions between surface and subsurface waters are poorly understood.
The Athabasca River is the largest single source for water for the oil sands industry, and maximum allowable water use that could occur would consume 16% of the historical 7-day low river flow. Under the current water management framework for the Athabasca River, oil sands facilities are allocated 3.5% of the average annual river flow and use less than 1%. River flow has fallen about 25–30% since the mid-1970s as precipitation declined and industrial uses increased. There are few financial incentives to reduce water use, but Hrudey says the RSC deemed the regulatory mechanisms in place capable of managing this issue.
Studies have found that many toxics, such as PACs, antimony, arsenic, cadmium, chromium, copper, lead, mercury, selenium, and zinc, can occur at higher concentrations downstream of oil sands operations than upstream (in some cases all the way to Lake Athabasca), and some of these are elevated enough to kill fish. But it remains to be determined if oil sands operations are the primary cause of these higher levels. Concentrations of toxic metals measured in the Athabasca River downstream of oil sands plants were much lower than Canadian requirements for drinking water.
Preparing for the Worst
Toxicity threats could become a major concern if there is a technological or natural disaster. A wide range of process accidents have already occurred, including numerous spills from processing plants and pipelines,23 fires and explosions at facilities, fires on wastewater ponds, and the deaths of more than 2,000 waterfowl that landed on various tailings ponds in multiple incidents.
Companies are required by law to submit environmental impact assessments (EIAs) that include plans for dealing with disasters, Davies says. But those paper plans don’t always reflect a comprehensive analysis of what could go wrong, considering actual past events, according to the RSC authors: “There have been large gaps in information submitted in EIAs that have not been required by the government nor provided by the companies, specifically dealing with consequences of technological disasters.” They also note that EIAs rarely address how a company will deal with extreme weather such as floods, torrential rains, high winds, bitter cold, and droughts and related forest fires.
Annual performance reports (assessments of the performance of oil sands tailings dams during operations and construction), independent dam safety reviews (which are required every five years), and emergency preparedness plans (descriptions of actions to be taken in the event a dam fails) are all available to the public through Alberta’s Freedom of Information and Protection of Privacy (FOIP) Act. Potter says emergency response plans (i.e., call-down lists or telephone trees) are the only documents that are not publicly available.