Development of efficiently coupled thermo-hydro-mechanical model to predict hydraulic fracture morphology in heavy oil reservoirs

Abstract

The aim of the study involves examining the effect of heavy oil viscosity on fracture geometry in detail by establishing a heavy oil fracturing model and conventional fracturing model based on thermal–hydraulic–mechanical (THM) coupled theory, Walther viscosity model, and K–D–R temperature model. We consider viscosity and density within the heavy oil fracturing model as functions of pressure and temperature while that as constants within the conventional fracturing model. A heavy oil production well is set as an example to analyze the differences between the two models to account for the thermo-poro-elastic effect. The results show that temperature exhibits the most significant influence on the heavy oil viscosity while the influence of pressure is the least. In addition, a cooling area with a width of 0–1 m and varied length is generated near the fracture. The heavy oil viscosity increases sharply in this area, thereby indicating an area of viscosity increment. The heavy oil viscosity increases faster and is closer to wellbore, and a high viscosity increment reduces the mobility of the heavy oil and prevents the fracturing fluid from entering into the reservoir. The special viscosity distribution results in significant differences in pore pressure, oil saturation, and changing trends between these two models. In the heavy oil reservoir fracturing model, the thermal effect completely exceeds the influence of pore elasticity, and the values of the fracture length, width, and static pressure exceed those calculated in the conventional fracturing model. Thus, a comparison of the measured values indicates that the results obtained by considering viscosity as a function of temperature and pressure are more accurate. Therefore, the results of this study are expected to provide good guidelines for the design of heavy oil fracturing.