Determination of swept volume is important for evaluation of a thermal project. Thermal well testing offers a simple method to estimate the steam zone properties using pressure falloff tests. A composite reservoir model is assumed with two regions of highly contrasting fluid mobilities and the flood front as an impermeable boundary. The swept zone therefore acts as a closed reservoir and pressure response is characterized by pseudo steady state behavior.

Most of the previous studies have considered vertical wells because of the simpler method of well test analysis compared to horizontal wells. However, a steam assisted gravity drainage (SAGD) process using horizontal well pairs is a promising technique in heavy oil recovery.

The applicability of thermal well test analysis in estimating the swept zone properties for vertical and horizontal wells was thoroughly investigated in this study. A thermal simulator was used to simulate pressure falloff tests. The generated pressure data were then analyzed to calculate swept volume and reservoir parameters. Properties of an Athabasca heavy oil sample, measured in the lab, were used as input for numerical simulation purposes.

Results of this work show good agreement between the calculated and simulated values of swept volume, swept zone permeability and skin factor for both vertical and horizontal wells. Estimations depend on the vertical position of the pressure gauge. Effects of gravity, swept region shape, dip, steam quality, steam injection rate, injection time, permeability anisotropy and gridblock density on the results were also investigated. Higher injection rates and longer injection times lead to poorer estimates of the swept volume because of a more irregular shape of the swept region and the possibility of earlier breakthrough. Vertical and lateral distances between the horizontal injector and producer affect the estimation of swept volume. Isotropy and grid refinement do not necessarily improve the estimations.

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