Abstract
During hydraulic fracturing, there is a temperature difference between the injected water and formation rock for shale gas wells. The objective of this study is to investigate how this temperature difference changes with time, and how it affects multiphase-flow modeling during the shut-in and flowback periods. We conducted numerical simulations to investigate the behaviors of fracture temperature in shale gas wells. The results show a significant increase in fracture temperature during the shut-in and flowback periods. Sensitivity analysis suggests that this temperature increase is strongly related to the thermal conductivity of formation rock, matrix permeability, and initial reservoir temperature. Simulation scenarios were further compared to investigate the effect of temperature on flowback data analysis. Without considering the thermal effect, flowback data analysis may yield an earlier fracture cleanup and overestimated fracture volume. In addition, this study suggests that the thermal effect may also have implications for optimizing flowback operations.
Highlights
Hydraulic fracturing is the key technique for economically extracting hydrocarbon from shale reservoirs
We present a simulation study to investigate the following questions regarding the temperature behaviors during the shut-in and flowback periods: (1) How long will it take for fluid temperatures to reach the formation temperature? (2) What are the key parameters controlling the changes in fracture temperature? (3) How does fracture-temperature change impact flowback analysis? To answer these questions, we first simulated the fracturing, shut-in and flowback processes using a thermal simulator to obtain the changes in fracture temperature with respect to time and space
We investigate the effect of w f on the behaviors of fracture temperature during the fracturing, shut-in, and flowback periods
Summary
Hydraulic fracturing is the key technique for economically extracting hydrocarbon from shale reservoirs. The bottomhole temperature data were measured by sensors at wellbore for a short period, and mainly represent the fluid temperature near wellbore It remains unclear about how temperature is distributed in fractures and far-field reservoir, and how long it takes to warm up the fracturing fluids after the fracturing treatment of shale gas wells. Most of the previously-cited flowback studies assumed a constant fluid temperature which reaches the formation temperature as flowback starts, without considering the possible difference between them Fluid properties such as gas viscosity and formation factor are among the key inputs in flowback analysis; fluid properties are a strong function of temperature. We present a simulation study to investigate the following questions regarding the temperature behaviors during the shut-in and flowback periods: (1) How long will it take for fluid temperatures to reach the formation temperature? Implications of temperature on field operations are further discussed in the last sections
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