On July 5, Encana Oil and Gas (USA) Inc. reported that a well it drilled in 2000 in Weld County, Colo., had leaked 840 gallons of produced water -- benzene, toluene, arsenic and other petroleum hydrocarbons.
The cause was "equipment failure," one of those catch-all descriptors for a surface spill, the company said in a filing with regulators.
But it was actually caused by hydraulic fracturing, a process in which operators inject water and chemicals to split apart shale rock and release trapped oil and gas.
Encana knew an operator nearby was fracking, and it had temporarily shut in its well. Still, the frack had communicated, or intersected, with the other well, and the pressures busted the wellhead equipment, resulting in a spill. Drillers call these events frack hits (EnergyWire, Aug. 5).
The threat is to the environment if there's a spill, to workers who may get injured in a gas blowout, and to groundwater if the pressure is enough to propel fracking fluids through cement and into aquifers.
Two things stand out about the frack hits: Wells located more than a mile away can communicate. And they can be avoided if precautions are taken during drilling.
Michael Beck, the founder of Surface Solutions Inc., an Alberta-based company, has seen frack hits in Alberta and British Columbia for several years. The first public acknowledgement of the problem came in 2010 when British Columbia's regulator revealed there had been 18 hits in 2010 and issued a safety alert.
And then on Jan. 13, 2012, a well spouted 20,000 gallons of fracking fluid and oil in Innisfail, Alberta, which made headlines in several newspapers in the province. As the Alberta Energy Regulator investigated, it found 21 fracking communication events, five of which resulted in a spill.
In May this year, the AER released a set of directions for operators to avoid frack hits. Before drilling, they have to survey for older wells that the fracks can hit. They must assess the integrity of the older wells and ensure the cementing is up to par. And they must continuously monitor pressure at nearby wells while fracking to ensure they are OK.
The AER does not specify, however, how close the well bores have to be for the company to become concerned.
Beck said he saw an opportunity. His company monitors pressures in real time for companies that are fracking, including Encana and Penn West Exploration, to ensure they can avoid frack hits.
Ron Gusek, the co-chairman of an Alberta industry group set up to look into such communication events, said the monitoring forms the core of best management practices that the industry has adopted in Canada.
In the United States, there are no regulations in place to monitor offset wells, and the incidents are underreported.
Some states, such as Colorado, require companies to do some collision planning where the well bores are as close together as 150 feet. More often, the companies chat among themselves to figure out whether they will be fracking near a producing well.
The response of companies is typically to shut in the offset well temporarily. But this does not necessarily prevent a spill, as in the Encana spill case in Colorado. That spill was cleaned up and the area was remediated, according to the spill report.
Gusek said improving the casing and other conditions at the offset wells would deal with the situation. In the worst-case scenario, the company may have to stop fracturing in the locations closest to the offset well bore.
"We just want to make sure that people have taken steps to ensure that they eliminate the risk of anything happening," he said in an interview.
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