Coupling Geomechanics and Transport in Naturally Fractured Reservoirs

Large amounts of hydrocarbon reserves are trapped in naturally fractured reservoirs which are challenging in terms of accurate recovery prediction because of their joint fabric complexity and lithological heterogeneity. Canada, for example, has over 400 billion barrels of crude oil in fractured carbonates in Alberta, most of this being bitumen of viscosity greater than 106 cP in the Grosmont Formation, which has an average porosity of about 13-15%. Thermal methods are the most common exploitation approaches in such viscous oil reservoirs which, in the case of steam injection, are associated with up to 275-300°C temperature changes, leading to considerable thermoelastic expansion. This temperature change, combined with pore pressure changes from injection and production processes, leads to massive effective stress variations in the reservoir and surrounding rocks. The thermally-induced (thermoelastic) stress changes can easily be an order of magnitude greater than the pore pressure effects because of the high intrinsic stiffness of the low porosity limestone and bounding strata. Study of these stress-pressure-temperature effects requires a thermo-hydro-mechanical (THM) coupling approach which considers the simultaneous variation of effective stress, pore pressure, and temperature and their interactions. For example, thermal expansion can lead to significant joint dilation, increasing the macroscopic, joint-dominated transmissivity by an order of magnitude in front of and normal to the thermal front, while reducing it in the direction tangential to the heating front. This leads to strong induced anisotropy of transport processes, which in turn affects the spatial distribution of the heating arising from advective heat transfer.