Permian Basin 2018

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PERMIAN BASIN: TECHNOLOGY | October 2018 | 33 The industry understands well how water, oil and gas will flow through a sand pack. The choke point is really out where the rock governs produc- tion, according to MacKay. "Most operators will agree that they are limited by the performance of the reservoir and not nec- essarily the conductivity of the proppant pack, so having a test that is particular to that regime is really important. These small features are where the capillary pressure are highest, and if pressure within them is not managed you end up with a fairly high threshold pressure to initiate flow from the reservoir through the proppant pack and into the well," MacKay said. "This test allows us to do exact, meaningful laboratory measurements that compare the various available surfactants—mea- surements that commute consistently to a thresh- old pressure for the initial of flow in that well. If we trot out all of the surfactants that are available, the measurement gives us a way of baselining their performance against one another, and even decid- ing whether or not surfactants are going to make a difference at all. My experience with this over many dozens of wells and tests, especially in the Permian Basin, is that the rock wants what it wants. Some- times it wants a little bit of surfactant. Sometimes it wants a lot." The service company remains engaged with its family of diverters, including the Broadband Sequence fracturing service with diverter technol- ogy that can direct the flow of fluid from perfora- tions that are accepting fluids to those that are not, perhaps due to stress fields. Although diversion is common in the industry, the missing piece has been how to make accurate, prescriptive statements about how to engineer diverter pill size in real time, and about how to determine whether or not there has been success in redirecting the flow of fluid. "Pressure changes are nice, but unless you are running something like distributed temperature sensing, which is more complicated and costly, you don't really get a notion where the fluid is going," MacKay said. "By incorporating some techniques from seismic processing, we have learned how to interpret some parts of the wave form of the water hammer that occurs naturally when we stop the pumps in hydraulic fracturing. If we're running pumps at 80 or 100 bbl/min and then we shut down, this induces a water hammer in the well. It acts like a sound wave. It is a pressure wave that starts at the front of the well and goes all the way down to where the bridge plug is. It reflects off of that plug and comes all the way back. In so doing, it is attenuated a little as it passes features in the well that were taking fluid. We can identify the dif- ference between zones that are taking fluid and those that are not, if we have access to the signal processing math." Dry friction reducers are another technology that has been floating around the patch for a while, but an ultimate answer has remained elu- sive. There are some noted benefits in the wellsite delivery equation regarding the use of dry friction reducers—spills on soil, handling of liquids on location, reblending requirement after delivery, and not having to depend on liquid transport, instead going to sacks on a flatbed or bulk trans- port of dry polymer. ShalePrime service follows a scientific process and engineered workflow to study rock-fluid interactions using a small amount of formation material. (Photo courtesy of Schlumberger)

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