In this paper, the use of microseismic data for calibration and modification of wellbore temperature models will be introduced. Moreover, fracturing fluid distribution obtained using the modified temperature numerical model is coupled with the microseismic field data for several Eagle Ford shale wells to improve hydraulic fracture stimulation characterization. By measuring the temperature change along the wellbore, distributed temperature sensing (DTS) data may provide relative fluid distribution. This information may be used to assess the simple geometry of the hydraulic fractures, the fracture initiation points along the wellbore, wellbore integrity issues, and the effectiveness of isolation tools. With recently published wellbore temperature models, quantitative information about which zones receive the stimulation fluid can be numerically solved. However, DTS measurements and fluid distributions calculated using DTS data are restricted to the wellbore and near wellbore environment. For far field diagnostics of hydraulic fracturing stimulation other measurements are needed, specifically microseismic. By combining these two measurements, a new workflow is created which incorporates both the far field and wellbore measurements to characterize hydraulic fractures, both real-time and after the stimulation job. This workflow is especially useful in reservoirs that are naturally fractured or in wellbores were stress shadowing effects are significant, such as multistage fracturing multiple wells that are in close proximity to each other. In these scenarios the path that the fluid travels may be complex, even in the near wellbore environment. Due to this complexity, fluid distributed calculations based on DTS data may provide misleading results. Using information gained from microseismic, the wellbore temperature models may be modified to increase the reliability of the numerically calculated fluid distributions. The purpose of this paper is to propose how microseismic data may be used to modify the wellbore temperature models, and how stimulation fluid placement determined from the modified models may then be coupled with the microseismic to improve hydraulic fracture stimulation characterization.
A new approach to upscaling and modeling of geomechanical properties using clusters has been set-up for Vaca Muerta Formation in the Neuquén Basin of Argentina. Using wells with core and cross-dipole logging tools, a core calibrated anisotropic model of the formation has been established. Clusters were determined from a logging suite comprising only gamma ray, compressional slowness, and bulk density in a key exploration well, and this cluster group was applied to several more wells in the study area. Using microseismic data obtained from three of the wells in the study area with two fracturing stages each, the vertical extent of microseismic events was determined, and the clusters obtained through our analysis have been upscaled over this interval using Backus averaging. All four upscaled wells show similar results by cluster for elastic stiffness coefficients and Young’s moduli, with a very tight range of values. Poisson’s ratio is more variable and a vague trend with the clusters is noticed. When compared to the core data, similar trends are observed in the stiffness coefficients and Young’s moduli. These clusters have been used as geomechanical facies to populate a 3D MEM which can be used to couple the petrophysical model for the study area, regional stress model, regional structure, and natural fracture network in order to combine the fully coupled geomechanics and flow effects in hydraulic fracturing treatments. The method we have developed allows for anisotropic properties to be applied over a wide area with limited available logging data.