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.

In horizontal-well, plug-and-perforate completions, various studies have shown that not all perforation clusters are stimulated equally. To increase perforation cluster treatment efficiency, engineers attempt to move the perforations of each stage to similarly-stressed rock. Most of these efforts have not included predictions quantifying efficiency improvements. This paper outlines a methodology for predicting improvements of perforation cluster treatment efficiency and includes a case study verifying the results of the model using pre-treatment diagnostics. In four Western Anadarko Basin wells, the operator measured mechanical rock properties using drill bit geomechanics. These properties were used to calculate the changes in minimum horizontal stress along each ~5,000-ft horizontal well. Within each treatment stage, the engineers chose perforation locations to minimize the difference in minimum horizontal stress. Using offset vertical logs and the geosteering interpretations, the engineers built a high-resolution fracture simulation model for each well. The model included the measured mechanical properties along the wellbore path. Comparing results from a geometric perforation model and the stress-balanced perforation model, the engineers predicted increased perforation cluster efficiencies between 10 and 20%. The four wells were completed using the stress-balanced perforation designs. Like all previous wells in the area, the operator performed step-down rate tests on these wells before each stimulation treatment. The step-down rate test is a common hydraulic fracturing diagnostic to quantify the number of open perforations taking treatment fluid. Compared to the operator's previous geometrically-perforated wells, the wells with the stress-balanced perforation designs showed more open perforations. A higher number of open perforations suggests a greater perforation cluster treatment efficiency. The increase in efficiency measured by the step-down rate tests was consistent with the model predictions. By understanding how stress-balancing perforation clusters will affect perforation cluster treatment efficiency, operators can optimize stimulations. The industry has not widely adopted stress-balanced perforation designs or other ‘engineered’ completion strategies. The results of ‘engineered’ completion studies have often been inconclusive, likely due to small sample sizes and reliance on production results. By combining affordable measurement of rock properties, modeled perforation cluster efficiency, and an affordable measurement of perforation efficiency, this paper provides a methodology for economically optimizing multi-stage stimulations in horizontal wells.

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Seven years ago, some operators in the United States began geo-engineering completions to more efficiently stimulate unconventional horizontal wells. Typically, engineers and geoscientists rely on expensive open-hole logs or the over-simplified use of gamma ray to infer mechanical rock properties along the lateral. Engineers then select treatment stage intervals and place perforation clusters in similarly-stressed, "like rock" to minimize the geomechanical variability. Instead of traditional open-hole logging, this paper discusses geo-engineering applications of drill bit geomechanics. Drill bit geomechanics is an innovative method for formation evaluation and reservoir characterization. It uses direct, continuous, high-resolution measurements of drilling vibrations recorded downhole. Using earthquake seismology models, one can infer rock properties from the measured drilling vibrations. These rock properties include Poisson's Ratio, Young's Modulus of Elasticity, and the presence of fractures perpendicular to the horizontal well. In this study, the Operator collected drill bit geomechanics data while drilling a new well ~8-34 ft below three existing horizontal wellbores, with over seven years of continuous production. The study well was a 9,500-ft lateral in the Bakken Formation in North Dakota. Using drill-bit-geomechanics-derived rock properties, the operator could confidently geo-engineer a completion, accounting for reservoir depletion from the older wells. The drill bit geomechanics data showed dramatic changes in mechanical properties and fracturing where the study well intersected the older wells’ stimulated reservoir volumes (SRVs). The operator had a general idea of the wells’ SRVs from microseismic data acquired during two wells’ stimulations. Using the drill bit geomechanics data from the study well, the operator could more effectively constrain the drainage ellipses from the sparse microseismic data. The operator geo-engineered a 27-stage completion by combining "like rock" of the same reservoir pressure. Measured Instantaneous Shut-In Pressures (ISIPs) during the completion showed significantly lower ISIPs for the partially-depleted stages closest to the older wells. Thus, combining similarly-pressured stages was critical to the completion's success. Well performance has proven to be excellent for the area, even when compared to wells without depletion from older producing wellbores. As shown in this case study, drill bit geomechanics is an economic, useful tool to identify depletion and accurately measure rock properties and fractures at a very high resolution.

Optimizing horizontal well placement is often not limited to identifying the most favorable reservoir, but also identifying the ideal target window within that reservoir. In unconventional reservoirs, the ideal target window must have both appropriate reservoir quality and the mechanical rock properties conducive to effective hydraulic fracturing. This paper presents two case studies from the Permian Basin. The first study directly compares wireline logs and core data with drilling vibration analysis. Analyzing drill bit vibrations, one can process mechanical rock property data. This process is called drill bit geomechanics. These high-resolution drill-bit-derived data were first calibrated to wireline and core data, then applied to target future landing zones. The second case study compares drill bit geomechanics data across three neighboring 10,000-ft horizontal wells, all of which landed in the same target zone. Based on the drill bit geomechanics data, the three wells showed notable differences in mechanical rock quality. The operator found the three wells’ production responses also differed. High frequency measurements of drilling-induced vibrations were recorded through several producing Permian reservoirs. In the pilot well, the recording tool was run behind a coring assembly to obtain mechanical data at in-situ pressure and temperature. Elastic stress-strain relationships were used to solve for the stiffness coefficients and determine relative values of mechanical properties (i.e., Young's Modulus (YM) and Poisson's Ratio (PR)). The resulting mechanical data were compared directly to core analysis, wireline dipole sonic logs, and wireline image logs. In general, the mechanical rock properties derived from drilling vibrations compared well with those from the sonic log and core analysis. One can attribute differences between the datasets to fluid effects and differences in resolution. The drill-bit-derived mechanical properties showed fine-scale changes and thinly-bedded intervals that were not identified by the sonic log. Using sonic measurements to determine in-situ mechanical properties can have non-uniqueness. Analyzing cores also includes challenges of translating exhumed core properties to those of in-situ conditions. Combining the in-situ measurement of mechanical properties from drilling vibrations with the traditional sonic log and core analysis minimized uncertainties. Increased understanding of mechanical properties in the pilot well informed the landing zone target intervals for the horizontal well development plan. Understanding mechanical properties is also critical to effective hydraulic fracture stimulation design and execution. Even within a landing zone, mechanical properties can vary laterally. Measuring and understanding these variations in mechanical properties can improve completions and lead to increased well productivity. Gathering drill bit geomechanics data provides a lower cost and lower risk method to acquire mechanical rock properties in long, horizontal wellbores. These near-wellbore variations in mechanical rock properties are ideal for use in identifying target landing zones for horizontal wells. One can use the data to create high-resolution, laterally variable fracture simulation and reservoir models. By integrating these data sets with mechanical rock properties recorded while drilling, operators can have significantly higher confidence in choosing a target landing zone and improving completions.