Abstract

Steam injection through a vertical or horizontal well has been commonly exercised in heavy-oil reservoirs to enhance oil recovery. Thermally-induced effects may enhance the mobility of the formation by increasing the reservoir permeability and reducing the oil viscosity, but it can also crush the sand grain and damage the formation, rupture the casing, and eventually destroyed the well. Sand production and wellbore stability of the heated horizontal well are of great concern in well completion and perforation design. Formation damage due to stress concentrations induced by in- situ stresses and the temperature difference is responsible for sand production and instability. To analyze the formation damage and the induced stresses, a geomechanics model fully coupled to energy transport and fluid diffusion process is employed. Both the sanding risk and stability for open-hole cases subject to a non-isothermal, non-hydrostatic in-situ loading, and underbalanced/balanced drilling conditions are investigated. Critical drawdown is calculated based on the thermo-poroelastic theory. It is concluded that changing bottomhole temperature and injection rate can impose a significant impact on the wellbore stability and sanding potential. Specifically, the risks for sand production and that for wellbore instability can be reduced significantly by controlling wellbore temperature and injection rate.

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