Lost in the Shadows: Surviving Fracturing Hazards with Fluid Tracking

Abstract Every unconventional well has a unique set of objectives with the same end goal: effective stimulation. During stimulation, a host of problems can potentially arise. For these problems, a solution is needed, but it is often difficult to visualize. Hydraulic fracturing operations encounter challenges including stress shadowing, thief zones, and fracture-driven interference on a regular basis. A novel application of controlled source electromagnetics (CSEM), called fluid tracking, monitors and images hydraulic fracturing operations. In this paper, we present case studies showing common fracturing hazards and we describe how fluid tracking provides mitigation insight. When fracturing fluid is injected into the reservoir rock, it changes the subsurface electrical impedance. The fluid tracking method involves measuring these changes to image the fluid movement. Operations consist of using a controlled electromagnetic field and a dense network of receivers arranged over the horizontal well trajectory. The data recorded over the course of a stage are then refined into a map view motion picture indicating where fluid is flowing. After visualizing and tracking fluid, engineers either adjust designs or confirm success before completing the next well. During hydraulic fracturing, areas of high signal amplitude indicate regions where the fluid successfully penetrated the rock. Interpretation provides the azimuth and half-length of each stage's induced fracture network. In the first case study, the operator used fluid tracking to investigate the performance of a new completion design. The design increased the total stage count with tighter spacing than the previous design. Results showed stress shadowing effects and inter-stage interference were greater than expected. Unlike the symmetric fracture geometry predicted by models, this completion had less than 50% of its monitored stages with signal on both sides of the well. Thus, the majority of stages were highly asymmetric. In fact, the asymmetric stimulation contributed to fracture-driven interference (i.e., a "frac hit") on an offset well. The operator found the increased stage design did not create more effectively stimulated rock volume. Instead, the engineer decided to lengthen stages, decreasing the number required to stimulate future wells. This resulted in lower completion costs without sacrificing production. The second case study explores effects of varied geology along a lateral. For one stage, although diverter was applied, fracturing fluid intersected a natural fracture network and was carried away from the intended target zone. Fluid tracking identified the results of ineffective diversion. Although the observation does not indicate a definitive conclusion on how to avoid the fracture network, it certainly showed the diversion method was insufficient. Operators choose to monitor treatments with fluid tracking to diagnose fracturing hazards and inform mitigation strategies as they improve completion designs and approach an optimized stimulation. The more understanding the industry gains on inter-well and inter-stage communication along with other unknowns during fracturing operations, the better equipped engineers will be when they determine which design modifications have the largest impacts.