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Understanding geomechanical properties is essential for an optimal completion strategy that ensures commercial productivity in shale reservoirs with ultra-low permeability. This study provides details to identify the variability of Instantaneous Shut-In Pressure (ISIP) in multidisciplinary approaches using petrophysical and geophysical data. ISIP is one of the input data required for well completion design. Operators commonly ignore the variability of ISIP and use uniform geomechanical assumptions due to cost and time constraints. In the case study, the variability of ISIP was observed up to 30 % in a single horizontal well, which could lower the efficiency of hydraulic fracturing with uniform geomechanical assumptions along a horizontal well trajectory. We propose practical approaches to identify the variability of ISIP from a case study in the Eagle Ford shale. MWD (Measurement While Drilling) Gamma Ray log, which is commonly acquired for a geosteering purpose, was utilized to prove its correlation with actual ISIP data gained at frac-stages in horizontal production wells. Correlation between ISIP and microseismic data was analyzed to identify the integrated relationship among the variability of Gamma Ray, ISIP, and hydraulically-induced fracture. In addition, practical approaches using a series of seismic inversion and attribute data were proposed to help identify geological variabilities affecting ISIP. This study was designed to provide operators hands-on approaches to capturing the variability of ISIP under limited data accessibility. We suggest multifunctional ways using the basic datasets commonly available at field sites. It can be applied to mitigate risks concerning well planning, drilling, and completion design in where operators face frequent challenges from geomechanical heterogeneity in global shale plays.

Understanding mechanical rock properties is essential for optimal well placement and hydraulic stimulation design which directly impacts hydrocarbon productivity from shale reservoirs with ultra-low permeability. Current industrial practice is to assess spatial variability of subsurface mechanical properties through analyzing core and dipole sonic logs. Seismic inversion is another commonly applicable approach. However, although numerous existing approaches have contributed to upstream operators mitigating operational risk, these individual or combined evaluations ultimately require significant cost and time for exploration. These approaches also have limitations identifying fine-scale variability within inter-well spacing or along the length of a horizontal well due to sparse pilot-well control and the intrinsic limitation of seismic resolution. In this study, we propose a new approach to capture spatial variability of Young's modulus utilizing MWD (Measurement While Drilling) gamma ray logs of horizontal wells. The MWD gamma ray log is essentially acquired for the purpose of having geometric and stratigraphic information on well position while drilling in real time. And, due to cost and time related issues, shale operators commonly acquire only MWD log rather than core or wireline log set for horizontal production drilling while the massive pad drilling has the advantage of large areal coverage. Under the circumstance, MWD gamma ray log is often only data having geological implication. In purpose of utilizing MWD gamma ray log for geomechanical approaches, we examined a relationship between gamma ray and Young's modulus acquired from pilot wells. The MWD gamma ray logs were converted into Young's modulus logs and ultimately populated for three-dimensional property modeling. To validate the property model, an integrated assessment using wireline logs, microseismic, and three-dimensional seismic data was conducted. The study results demonstrate that this new geomechanical approach utilizing MWD gamma ray logs can be supportive or even serve as an alternative to the existing approaches. The method enables identification of finer-scale spatial variability than sparse pilot-well control and conventional seismic analysis, which is attributed to the advantage of long-lateral, multi-benched, staggered, and dense production well placement. Based on the reliability and cost-effectiveness of the new approach, we expect it could help upstream operators mitigate risk and uncertainty related to geomechanical properties without excessive spending for exploration and ultimately improve hydrocarbon productivity with optimal well completion strategies.