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.
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