Ripudaman Manchanda

Impact of Completion Design on Fracture Complexity in Horizontal Wells

A proppant-filled fracture induces mechanical stresses in the surrounding rock that cause a reduction in the horizontal-stress contrast and stress reorientation around the open fracture. A 3D geomechanical model is used to simulate the stress reorientation caused by open fractures and to generate horizontal-stress-contrast contour maps. The reduction in horizontal-stress contrast can lead to increased fracture complexity. This paper describes ways to increase fracture complexity by varying the completion design. In this paper, we identify the impact of operator-controllable variables in a completion design on fracture complexity. This can lead to more-effective completion designs that improve well productivity, reservoir drainage, and, ultimately, the estimated ultimate recovery (EUR). The possibility of greater fracture complexity and reduced/ effective fracture spacing and, thus, a higher drainage area is demonstrated for the alternate fracturing sequence in comparison to the conventional fracturing sequence. The Young’s-modulus value of the shale and the in-situ horizontal-stress contrast are shown to be significant factors controlling the extent of fracture complexity generated in a given reservoir. In addition, the effect of proppant mass injected per stage is also shown to significantly impact fracture complexity. We provide optimal ranges of fracture spacing and proppant volume for the various shale formations analyzed. The use of these guidelines should result in more fracture complexity than would otherwise be observed. The results presented in the paper provide the operator with the knowledge to design completions and fracture treatments (proppant volume, fracture spacing, and sequencing) to maximize reservoir drainage and to increase EURs. This should lead to more-effective completion designs.

Time Dependent Fracture Interference Effects in Pad Wells

Hydraulic fracturing in shale formations induces microseismic events in a region we refer to as the microseismic volume. Many of these microseismic events are signatures of failure in the formation that are believed to be a result of induced unpropped (IU) fractures beyond the primary propped fracture. Areally extensive microseismicity may be evidence that these IU fractures occur and extend spatially beyond the propped fracture during pumping in many unconventional reservoirs. We present evidence that these fractures close over time after pumping is stopped and that this closure of IU fractures can have a significant impact on stress interference between fractures. To illustrate these effects, microseismic and radioactive-tracer data are presented for four laterals drilled and fractured from a single pad. Two wells on this pad were fractured with the consecutive-fracturing sequence, and the other two wells were fractured with the zipper-fracturing sequence. Geomechanical simulations were performed to model the pad scenario and explain the microseismic and tracer observations, with emphasis on the two different fracturing sequences. Our simulations show that the opening of the IU fractures results in significant temporary changes to the stress field in the rock. One consequence of this is that later fracture stages tend to propagate into the open-fracture networks of IU fractures created earlier because of stress reorientation. This can lead to inefficient usage of fluid, proppant, and capital because the region that is being stimulated has already been stimulated by the previous stage. By analyzing the net pressure, radioactive-tracer data, and microseismic data from the four-well pad, we show that these IU fractures close over time because the fracture fluid leaks off. This reduces the stress shadow, and subsequent induced fractures are no longer subjected to the significantly altered stresses, allowing for more-efficient fracture-network coverage by subsequent fractures in a horizontal well. On the basis of the data presented and computer simulations, we propose the idea of maximizing the time between fracturing in the microseismic volume of a recently fractured region (within operational constraints). The time required for the IU fractures to close can be estimated from our models and varies on the basis of the reservoir and fluid properties from several hours to days. One example of how this is accomplished in practice is zipper fractures. However, our work suggests that there also may be other fracture-sequencing strategies for accomplishing this.

The Effect of Pore Pressure on Hydraulic Fracture Growth: An Experimental Study

Laboratory experiments are conducted in this study to investigate hydraulic fracture initiation and propagation in porous test specimens in the presence of multiple fluid injection sources and anisotropic far-field stresses. Numerous laboratory observations of fracture growth are documented via clear, high resolution images and digital image correlation analyses. It is clearly shown that injection-induced stresses can appreciably affect hydraulic fracture trajectories and fracturing pressures. We show that induced hydraulic fractures, under our laboratory conditions, are attracted to regions of high pore pressure. Induced fractures tend to propagate towards neighboring high pore pressure injection ports. The recorded breakdown pressure in the fracturing experiments decreases significantly as the number of neighboring injectors increases. When a hydraulic fracture is induced near an injection port that is maintained at a relatively high injection pressure, a secondary fracture can grow at a markedly lower fluid pressure than that of the main fracture. The influence of an adjacent fluid injection source on the hydraulic fracture trajectory can be minimized or suppressed when the applied far-field differential stress is relatively high. Multiple fractures induced from closely spaced injection ports tend to grow towards neighboring ports and perpendicularly to the applied maximum far-field stress. The experimental observations in this paper can serve as benchmark evidence for numerical hydraulic fracturing simulators that are used for modeling field applications.