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The study of long reach laterals and complex completion scenarios in the Western Canadian Deep Basin has, in the most part, relied on indirect measurements of surface pressures and production analysis to determine the effectiveness of the completion and stimulation process. Distributed sensing using Fibre Optics is one of the few “direct measurements” available at all points in the wellbore, with sampling rates available in seconds.
"Distributed Temperature Sensing (DTS) allows us to visualize the stimulation and completion practices along with the reservoir and its geological characteristics," says Robert Hawkes, Trican Corporate Director, Reservoir Studies. "This technology will allow customers to maximize production, and helps reduce cost in these capital-intensive shale play operations.”
Hawkes is excited about DTS technology, which drastically improves the evaluation of long reach laterals. The complexities of today’s slick water multistage completions cannot be handled by the current industry reservoir simulators because of osmotic effect, water adsorption, and the change in geomechanical properties due to imbibition. Hawkes, who also leads Trican’s Frac AcademyTM study group, says: “The simple analogy is: we used to characterize production behaviour from well testing; we now use fibre optics to conduct “warmback” tests. Because of the distributed measurement offered by fibre optics, we get a detailed production profile of every meter of the lateral length of the wellbore.”
After a hydraulic fracture stimulation treatment is finished, the well undergoes a thermal recovery process (warmback) when it returns to geothermal conditions. The non-stimulated intervals recover faster to the geothermal temperatures, whereas the stimulated intervals lag in time (weeks) due to the additional cooling induced by the volume of injected fluids, or the cooling from production. It is this difference in temperature response that allows for the identification of the stimulated intervals.