In thermal recovery processes (e.g. cyclic steam stimulation, SAGD) the reservoir temperature in certain regions may increase substantially (up to ~500°F), which in turn induces significant changes in the rock porosity. The standard treatment of thermal effects on porosity in a conventional thermal reservoir simulator in which reservoir flow is not coupled to geomechanics gives rise to a reduction in porosity with increasing temperature. This is based on the assumptions used in the discretization of the reservoir flow equations viz. (1) thermal compressibility is independent of rock deformation and (2) the rock volume expands while the bulk volume is kept constant. Consequently, the porosity used in a conventional reservoir simulator does not always yield correct results as the porosity may not necessarily decrease with increasing temperature. This paper examines the effect of temperature on porosity from a geomechanical point of view. It shows that the so-called reservoir porosity may increase, decrease or remain constant with increasing temperature not only depending on the type of displacement boundary conditions imposed on the reservoir but also depending on Poisson?s ratio and initial porosity, whereas true porosity always decreases (or stays constant) as temperature increases under drained conditions Equations relating porosity are derived on the fundamental of continuum thermoporoelasticity. These equations will be used to validate the coupling between a geomechanics module and a conventional thermal reservoir simulator subject to a change in temperature. This is illustrated by performing a coupled thermal simulation of a series of confinement configurations along with different values of Poisson?s ratio and initial porosity. The results of the simulation match well with the analytical results.


Porosity changes due to temperature are very important in thermal processes such as cyclic steam stimulation, SAGD (Steam Assisted Gravity Drainage), etc. with temperature increase up to ~500°F (see for example SPE Monograph1). In a conventional reservoir simulator, the porosity is normally assumed to decrease when the temperature increases. This is caused by the assumption that thebulk volume is unchanged while the volume of solid grains increases with temperature. Therefore, the pore volume decreases and leads to a reduction in porosity. This argument is correct only when the bulk volume can be kept constant. However, in reality, the bulk volume may also change with temperature depending on the type of constraints imposed to the boundaries of a porous block. The case of constant bulk volume is only a special case where a porous block is fully constrained in all directions. When a reservoir flow simulator is coupled to geomechanics, two different types of porosity are defined2: True porosityf: The true porosity is the ratio between current pore volume and current bulk volume. This definition can be expressed as:

(mathematical equation available in full paper)

Reservoir porosity f*: The reservoir porosity is defined as the ratio between the current pore volume and initial bulk volume. This definition can be expressed as:

(mathematical equation available in full paper)


Vp = current pore volume

Vb = current bulk volume

V0b = initial bulk volume

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