Photograph Bryce Meyer
Inside the workspace of a fracking research center, a group of lab coats huddle around a beaker of dirty water mixed with a few drops from an eyedropper filled with vinegar. A few more drops are added, this time from another chemical compound, and then a few more before the water turns from murky brown to light blue and transforms into a viscous paste.
“It’s like flubber,” says David Browne, Trican Well Service Ltd.’s vice-president of communications and marketing, referring to the 1997 Robin Williams film. The hydraulic fracturing fluid being mixed in front of him at Trican’s southeast Calgary completions research center has indeed become like flubber – a gel compound with the consistency of mayonnaise – albeit without the ability to move on its own like in the Disney film.
“You’re using in-field fluids, which is the way the business is going to go. A lot of people are sourcing water from other places, trucking it in or drilling water source wells to frack with.”
A good fracturing fluid, Browne says, needs to initiate a fracture, carry proppant through those fractures and place that proppant – usually sand – in the fractured rock. The goal is to open up the source rock so that the maximum amount of oil or gas can flow back to the surface. Researchers in this laboratory, donning dark grey company-issued lab coats, are working to continuously improve the chemistry used by Canada’s largest publicly listed completions provider in the recovery of oil and gas. Two additional Trican research centers focused on completions operate in Houston and Moscow, and the company is listed beside BlackBerry Ltd. and Bombardier Inc. as one of the 100 largest spenders on research and development in Canada.
Fracking research is big business. Companies like Trican, Calfrac Well Services Ltd. and Halliburton Co. are constantly competing with each other to develop fluids that get the best production results for oil and gas producers and avoid causing damage to the reservoir and its geology. The shale revolution has changed the nature of oil and gas production in North America, but many pressure pumpers are quick to point out that it’s still early days for the technology, which will continue to evolve.
In the 1860s, oil and gas explorers would, under the cover of darkness, drop nitroglycerine bombs down wellbores to stimulate the flow of the resource to the surface. In the 1940s, Stanolind secured a patent for a technique that pumped napalm-thickened gasoline down wellbores to stimulate the flow of hydrocarbons beneath. These crude methods for fracturing oil and gas wells continued through the ’50s, until energy service providers began using a combination of water and sand to open up the pores in hydrocarbon reservoirs in the late ’60s.
Hydraulic fracturing is not a new process or a new concept. However, the “shale revolution,” or the widespread use of hydraulic fracturing paired with horizontal drilling to open up vast new unconventional reservoirs in North America is widely understood to have begun in 2003. That was the year production companies began exploiting the Barnett shale formation in Texas. The Haynesville, Fayetteville, Woodford, Bakken and Montney shales would open up in the months and years that followed until eventually shale production of oil and gas in North America was termed an energy revolution.
Researchers at Trican’s Calgary-based fracking technology facility (pictured) work to find the chemical concoction that will provide producers the highest possible yields during completion
Photography Bryce Meyer
“Hydraulic fracturing has been around now for a little over 65 years,” says Nick Gardiner, Halliburton’s strategic business manager for production enhance-ment. “The pace of technology development has ebbed and flowed like a tide, but it is a significant portion of our customers’ budgets. With customers having that as such a huge portion of their capital spend, they demand that technology marches on, so we have to keep pace with the industry.”
Since 2003, energy service providers have introduced a variety of new technologies that each company claims has made well fracturing more effective at unlocking the resource trapped in the rock. Not all of those new technologies have been as effective as initially hoped and not all have been adopted as widely as the proponents would have liked.
In the last three years, Halliburton (like its competitors) has developed and introduced a suite of new hydraulic fracturing technologies. One innovation is a fracking fluid made entirely from additives sourced from the food industry. Asked whether the fluid is equally effective between different shale plays – like the Eagle Ford and the Bakken, for instance – Gardiner says it works best at shallow to medium depths.
Therein lies the difficulty in developing new hydraulic fracturing processes and technologies. The geological composition of each resource play necessitates a different approach. In northeastern British Columbia, for instance, the radial length of operators’ fracks can measure up to 100 meters – meaning that operators need fracking methods that can place proppant 100 meters out from the wellbore. In Alberta’s Cardium, they might measure 30 meters, and so a different approach is needed.
A major focus for researchers at firms like Halliburton and Trican in recent years has been in the development of fluid additives that will allow them to fracture wells using produced water, which is the water produced as a byproduct along with the oil and gas from a reservoir. The issue that has so far kept completions providers from fracking with produced water is the effect that the saltiness of produced water has on the clay in a reservoir. The salt makes the clay swell, which in turn inhibits the flow of oil and gas out of the well. Halliburton has also introduced a fracking fluid that works with produced water, allowing companies to frack wells without using freshwater.
Calgary-based Gasfrac Energy Services Inc. president Jason Munro says that his company, which has marketed a method that uses liquid petroleum gas as a fracking fluid in place of water, has recently been asked by a customer in Texas to tweak its fracking fluid recipe. The company is now moving toward what Munro calls a hybrid frack, which uses a blend of propane or butane and the hydrocarbons from the reservoir. This way, Munro says, “You’re using in-field fluids, which is the way the business is going to go. A lot of people are sourcing water from other places, trucking it in or drilling water source wells to frack with.”
At Trican’s hydraulic fracturing research center, bottles of murky water with labels bearing names like “Vermilion,” and other oil and gas-producing regions of Alberta, Saskatchewan and B.C. sit on tables. Browne says the company is analyzing samples for each of these regions in order to develop the best fracking fluid combination for each case. As a result, Trican is able to collect produced water from various regions, send that water back to the laboratory, and develop a region-specific fracking fluid designed to work with the well’s geology and at the same time extract as much of the resource as possible.
In one room at Trican’s research center, an array of machines are used to analyze core samples and produced water samples, so that the company understands exactly what chemicals are in each sample. Browne says Trican is able to analyze “right down to the element,” thereby allowing the company to develop and fine-tune its fracturing fluids for each specific region. Research at this lab and others will continue as new shale reservoirs – at new depths and with new geological conditions – in Canada and North America begin production, requiring completions providers to continue to innovate their techniques.
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