A coupled conductive–convective thermo-poroelastic solution and implications for wellbore stability

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Steam injection is widely used in heavy oil reservoirs to enhance oil recovery; elevated temperatures increase fluid mobility in several ways, but can also generate damage through shearing, crushing of weak grains, and casing impairment by shear, collapse, or buckling. Disposal of cold produced water by injection can generate thermally induced extensional fracturing, increasing the effective wellbore radius. Drilling with long open-hole sections can lead to rock temperature changes as large as 30–40 °C at the casing shoe through mud heating at depth and upward mud circulation, dramatically impacting wellbore stability. Clearly, thermal stress analysis of open and cased boreholes is of primary interest for drilling and completion planning, as bottom-hole temperature changes can have as large an impact as bottom-hole pressure changes. Local wellbore stresses are the sum of far-field, pore pressure and thermally induced stresses; they may be highly inhomogeneous because of different rock properties and heat transport processes. These stresses, combined with thermal weakening and pore pressure changes, may lead to phenomena such as formation damage, sand production, shale shrinkage, and various modes of instability (shearing, spalling, fracturing, etc.). Previous studies of thermally induced stresses were primarily based on assumptions of low permeability and heat conduction only; this is inadequate when high-permeability formations are encountered. To analyze induced stresses and formation damage, a geomechanics model that is fully coupled to diffusive transport processes is employed. By assuming a constant wellbore pressure and temperature boundary condition, a closed-form solution including heat conduction and convection is obtained for the stresses near a cylindrical wellbore. The stability of an open-hole subject to non-isothermal, non-hydrostatic in situ loading and various conditions is then investigated. Our studies indicate that maximum tangential stresses are found on the wellbore wall during production, but can be displaced into the formation if a cooler wellbore fluid is used. This is a more stable condition because of higher confining stresses deep within the borehole wall.