Approximately 80 per cent of Alberta’s bitumen deposits lie deeper than 75 metres and cannot be mined. As a consequence, these deep deposits, all capped by rock, are currently being heated to as high as 300 degrees Celsius with highly pressurized steam.

Given that there are more than 100 steam plant facilities poking thousands of holes into irregular layers of bitumen, there is “a need to improve the collective capabilities of operators, service providers and regulatory bodies in the area of caprock integrity management,” noted the event’s organizers.

Industry uses either a steaming tool called steam-assisted gravity drainage or cyclic steam stimulation to melt a resource as hard as a hockey puck.

The overlaying caprock acts as a primary but not always impermeable seal that keeps steamed bitumen from seeping into aquifers, neighbouring industry wellbores and other geological formations, as well as the forest floor and lakes.

In general, industry tries to keep the pressure significantly low enough to ensure the caprock does not break — but high enough to push the melted bitumen out.

It is a very fine line. In 2006, French multinational company Total blew a 300-metre crater in the forest while trying to steam up a shallow formation of bitumen.

Although regulatory reports on the event weren’t published until four years later, the “catastrophic event” put caprock integrity on the agenda and forced Total to abandon its project.

Ever since then, all steam-based bitumen operations, the industry’s most energy-intensive facilities, report yearly on caprock integrity. The Society of Petroleum Engineers devoted a sold-out workshop on the subject last spring in Banff.

Half of all bitumen now produced from the oilsands relies on a form of oil production that injects highly pressurized steam into deep deposits of cold bitumen.

Harvard researcher and University of Calgary graduate Benjamin Cowie traces four significant and costly events in the tarsands to a newly identified geohazard: the erosion of salt formations underneath bitumen deposits by the movement of groundwater.

Echos of fracking

Recent studies by petroleum scientists as well as annual industry progress reports to the Alberta Energy Regulator show that the technologies used to steam deep bitumen deposits have created the same sort of problems now plaguing the hydraulic fracturing of unconventional oil and gas resources across North America.

Both technologies inject highly-pressurized fluids into formations where the resulting pressure can crack or fracture overlying rock and well casings in unpredictable ways. These fractures can bring fluids or gases to the surface, contaminate groundwater or connect with other existing wells.

The end result for both technologies are the same: hydrocarbons go where regulators don’t want them or industry can’t control them.

Alberta regulators described the Total blow-out as a fracking issue in a 2011 presentation. “Given ongoing caprock integrity concerns associated with fracturing and hydro-fracking in the subsurface to initiate production, these findings will have relevance to other shallow thermal and non-thermal operations, including in-situ bitumen/extra-heavy oil operations, and production of other emerging unconventional commodities such as tight oil and shale gas.”

The problem seems most pronounced at cyclic steam operations such as those run by Canadian Natural Resources Ltd. and Imperial Oil, where steam is injected into the ground for weeks at a time from pads that typically contain as many as 20 wells. After a soaking period, melted bitumen is brought to the surface.

Cowie suspects that fractures and faults created by the new hazard have collided with industrial activity along the eastern fringes of bitumen mining in northeastern Alberta.

1. In 2009 bitumen seeped to surface at CNRL’s Primrose operation in Cold Lake. Four more seeps appeared in 2013 resulting in a $50-million cleanup operation. CNRL eventually excavated 82,508 tonnes of impacted earth and drained an entire lake. The fourth largest oil spill in Alberta history is still under investigation.

2. In 2010 Shell’s Muskeg River mine hit a gusher of sulfate-rich and salty groundwater connected to the Devonian while excavating a tailing pond. It took more than a year to contain a rupture that spurted 2,000 cubic metres of salt water an hour. It cost millions of dollars to plug the leak. Researchers say that “it is almost certain that more conduits exist throughout the oilsands region, and that this will not be the last incident of brine discharge in an oilsands system.”

3. In 2006 Total blasted a 75 by 125 metre surface crater in the boreal forest at its Joslyn Creek steam plant resulting in the abandonment of the project. The event rendered nearly 30 million barrels of bitumen unrecoverable. Alberta regulators, which didn’t report on the event for four years, later compared the Total blowout to an uncontrolled frack job in a 2011 presentation. “Given ongoing cap rock integrity concerns associated with fracturing and hydro-fracking in the subsurface to initiate production, these findings will have relevance to other shallow thermal and non-thermal operations, including in-situ bitumen/extra-heavy oil operations, and production of other emerging unconventional commodities such as tight oil and shale gas.”

4. In the 1980s Texaco created a geyser of bitumen and salt water outside of Fort McMurray. There is little literature on the blowout. But it may have connected to a Devonian aquifer too. —Andrew Nikiforuk