Identifying Volcanic Ash Beds and Lamina-scale Stratigraphy Using Rock Mechanical Properties
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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.
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.
Drilling Through Depletion in the Bakken; Using Drill Bit Geomechanics to Inform Fracture Stimulation
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.
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