Alberta’s shale gas fortunes hinge on water management

Water use in frac jobs flagged as 'critical issue' by ERCB

August 01, 2011

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Illustration by Anthony Tremmaglia

The shale gas “revolution” is buoyed by a tremendous volume of water. More than 35,000 wells perforating basins like the Barnett, Marcellus, Haynesville and Fayetteville in the United States are hydraulically fractured, or fracced, using anywhere from 40 to 170 billion gallons (151 million to 529 million cubic meters) of the precious liquid every year, the Environmental Protection Agency (EPA) reports. Enough water is consumed in the process to meet the annual needs of roughly 40 to 80 cities with municipal populations of 50,000, or one to two cities with populations of 1.2 million to 2.5 million people.

Alberta’s Energy Resources Conservation Board (ERCB) has flagged the insatiable thirst as a “critical issue” as land sales in the liquids-rich Duvernay shale west of Edmonton gather momentum. “Access to sufficient water is critical to development, but cumulative effects on the sources of large water withdrawals must be managed,” the agency says in a winter review of prevailing regulations in jurisdictions within North America where activity levels are the highest.

The call for stewardship represents a potentially significant business opportunity. “We’re in a very good position,” says Kevin Slough, chief executive of Calgary-based FilterBoxx Water & Environmental Corp. His optimism is rooted in a growing facet of the fossil fuel trade. The high volumes of water used to frac gas from shale, separate bitumen from sands and clay or sweep out old reservoirs for hidden pockets of oil has birthed a thriving water treatment and recycling industry. An assessment by United Kingdom-based Global Water Intelligence puts the value of the North American market for handling “produced” water – a catch-all for volumes, both naturally occurring and induced, that are commingled with oil and gas in a given reservoir – at US$2.5 billion annually.

Emerging basins like the Montney in northeastern British Columbia are a potential hotbed for the niche. From 1995 when the province’s Oil and Gas Commission began tracking volumes, more than 679,000 cubic meters of produced water have been reported at 847 wells as of March 2011. Because the basin is considered “dry,” the produced water is comprised mainly of flow-back, or water used during hydraulic fracturing operations that is returned to the surface as wastewater.

Effective handling and treatment of the mixture, which contains a combination of formation and condensed water, plus any number of potent chemicals including benzene, toluene and ethylbenzene, is widely viewed as a linchpin service on which the fortunes of the shale “revolution” turn. Water quality is crucial to economic recovery of trapped gas. Although the ideal blend depends on reservoir conditions, too many contaminants can potentially foul equipment.

Regulatory agencies and independent watchdogs across North America, including the U.S. EPA and Alberta’s ERCB, are still grappling with oversight of the emerging shale gas sector. The lag makes it difficult for companies that specialize in water treatment technology to develop products tailored to meet environmental protocols that continue to evolve. “The economic drivers are so different in each basin,” Slough says. The closest his firm – a specialist in water treatment technology that counts oil sands operators MEG Energy Corp., Cenovus Energy Inc. and Suncor Energy Inc. among its clients – has got to some of the larger frac jobs to date is as a wastewater service provider for a work camp run by Encana Corp. in the remote Horn River basin.

Treating the fracture flow-back water remains a tenuous market opportunity in part because regulatory policies differ from one basin to the next. Licensing disposal wells in Texas around the Eagle Ford shale is “a virtual no-brainer” because it’s so cheap, Slough notes. In the U.S. northeast, though, operators are compelled to haul the flow-back water for disposal, and freshwater is still the main lubricant for frac jobs. That in turn limits the market for treatment technology geared to process the contaminated volumes for reuse. (Regulations in B.C. favor underground disposal of wastewater).

Slough foresees business opportunities emerging in the market as policy-makers in different jurisdictions clarify disposal and treatment standards. “As the regulatory framework gets more sophisticated in dealing with the shale gas produced water, then yes, we see that there’s going to be great opportunities to really pursue that market that aren’t there now, because there’s too much uncertainty as to what needs to happen,” he says.

The oil sands, meanwhile, continue to provide an avenue for growth, mainly because water standards are more clearly defined, says FilterBoxx chief operating officer William Jones. Compared to shale gas projects characterized by unique reservoir conditions where companies use proprietary recipes for chemical cocktails in well completions, operators running steam-assisted gravity drainage projects in northern Alberta “actually know what they need from a quality standpoint,” he says.

Beyond bitumen, the multi-stage hydraulic fracturing and enhanced oil recovery extraction techniques that are giving old reservoirs forsaken as marginal assets a second lease on life represent another area where advanced water treatment technology is poised to play a significant role. FilterBoxx remains a private company. Revenues topped $40 million in 2010, a year that saw the firm partner with global technology provider General Electric as well as Culligan Matrix Solutions to bring potable water to work crews across North America, including in the oil sands. “Produced water isn’t a homogenous quantity,” Slough notes. Neither is handling the stuff a new requirement. “What’s changing a bit is there’s more focus on what you’re going to do with that water,” he adds. “Where we see an opportunity is where the treatment of the produced water becomes a little bit more complex.”

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