Applications of temperature modeling and distributed temperature sensing (DTS) in hydraulic fracture stimulation diagnostics

Abstract

In unconventional oil and gas wells, the key to economic production is the success of the hydraulic fracture stimulation. Determining the effectiveness of the stimulation is often difficult. New technologies can characterize the hydraulic fractures produced from the stimulation. Among these is distributed temperature sensing (DTS). DTS allows for continuous temperature measurements along the wellbore, and through the use of temperature modeling, DTS may be used to diagnose the effectiveness of hydraulic fracture stimulations both during the treatment (real-time) and after the well has been shut in (warm-back). In this study temperature models were used to simulate the wellbore temperature change both during the hydraulic fracture stimulation treatment and after the treatment has been completed. During the treatment, DTS and temperature modeling allows for the tracking of fluid throughout the wellbore. This may be used to determine which perforated zones receive the most stimulation fluid and can also dictate how and where fluid leaves the wellbore. Published temperature models were used to simulate wellbore temperature changes in Eagle Ford study wells. The published models were coded using VBA in order to create a numerical simulation. The numerical model was compared to simplified analytical solutions and an ideal time step and grid size were determined. Several cases were tested using different fluid distributions across the perforated zones. In lieu of DTS data, microseismic was used to assist in setting the parameters of the temperature simulation. Due to high pump rates, small perforated zones, and close perforation spacing, real-time evaluation of hydraulic fracture stimulation treatments in the Eagle Ford study wells resulted in ambiguous results. As a result, a different type of temperature model was derived and implemented in the study, the warm-back temperature model. The derivation of the warm-back model is similar to that of the real-time model but is much simpler and uses different boundary conditions. Like the real-time model, the purpose of the warm-back model is to determine fluid placement along the wellbore into the perforated zones. In this study fluid placement was used to directly determine fracture length. The benefit of the warm-back model is that it is not directly a function of pump rates or completions. As a result, the warm-back model allows for greater understanding of the hydraulic fractures than the real-time model. Microseismic was again used to adjust parameters affecting the temperature simulation.