Wellbore stability in shale can be enhanced through proper selection of drilling fluid parameters such as mud weight, salt concentration, and temperature. This can be accomplished by analysis of stress/pore pressure variation around the wellbore as a function of mud pressure, chemistry, and temperature. In this paper, we present a stress analysis based on a coupled thermoelastic model of chemically-active porous media saturated by a binary electrolyte fluid that consists of a solute and diluent. We use a robust theory that considers the difference between the thermal expansibility of the pore fluid and that of the solid skeleton, and incorporates direct flows due to hydraulic conduction, chemical solute diffusion, and heat conduction. Two indirect flows namely, flow of diluent by chemical osmosis and flow of solute by thermal filtration are also included. The field equations of the theory are solved to yield stresses and pore pressure, temperature, and solute mass fraction re-distributions that result from drilling. An example is used to show the impacts of the coupling between hydraulic, thermal, and chemical processes on stress and pore pressure distributions. The results indicate an interesting interaction between temperature, chemistry, and stress. Heating can enhance tensile failure in shale while cooling lowers tensile stresses in shale, but may cause failure in compression.
Shale swelling and deterioration are major sources of borehole instability and associated problems. In addition to insufficient mud weight, shale instability is significantly influenced by chemical and thermal gradients. It is well known that hydraulic and chemical osmotic effects cause fluid flux into or out of the formation [8, 1]. The latter is driven by the difference in activity between the drilling fluid and the formation pore fluid [6, 15, 17, 19, 22]. In addition, to flow and thermal stresses arising from thermally-induced pressurization, a temperature contrast between the drilling mud and the formation can also induce irreversible transport processes when drilling in shale sections, namely thermoosmosis and thermo-filtration. Because shales have a very low permeability (order of nanodarcy), hydraulic transport is not the dominant form of fluid movement into the formation. In fact, hydraulic fluid transport is often several times smaller than the contribution of chemical and thermal effects. Mud filtrate invasion due to a thermal gradient while drilling can also be several times larger than hydraulic flow. It tends to alter the pore pressure in the formation and redistribute water within shale, engendering internal surface effects and increasing or reducing shale strength.
The influence of a chemical potential gradient on shale swelling and wellbore instability has been studied [6, 7, 13, 15, 16, 19]. Influence of solute diffusion on pore pressure and osmotic processes has also been investigated using a coupled chemoporoelastic theory [4, 9]. Also, certain phenomena related to thermal processes in porous media have been investigated using a poro-thermoelastic theory [10, 14]. Previous studies have also shown the significance of thermal stress and pore pressure around a wellbore and their impact on bore hole stability [5, 11, 23]. However, the interactions between the chemical and thermal driving forces and their combined impact on fluid flow into or out of the formation and stresses have not been considered. Also, the combined effect of chemical potential and thermal osmosis and their combined impact on fluid flow into or out of the formation has been considered [5].
