The design and analysis of well tests for heavy oil producers is complicated due to both the mechanics of artificial lift and the properties of the fluids produced. Traditional analysis methods and assumptions used for light oils and flowing wells are only practically applicable and therefore special methods are required to ensure accurate reservoir information is obtained.

One mechanical complication for wells lifted by means of rod and progressive cavity pumps is the presence of a rising fluid level in the open annular space during the shut-in period. Wells are stopped at the surface because downhole shut-in is not feasible for both economic and mechanical reasons. Wellbore storage then becomes the determinant factor in the prediction of the shut-in period duration. Another complication is that the bottomhole pressure data is rarely directly measured due to the high cost of downhole recorders and their requirement to remove lift equipment. Pressure data is therefore calculated from fluid levels determined by acoustic methods.

The cases considered were heavy oil wells in Saskatchewan and Alberta. Completed in the Bakken and the middle Lloydminster sandstone reservoirs, they were at saturation pressure at the initial conditions. Some of these reservoirs have been subjected to waterflooding after a period of primary production. Therefore, in addition to the mechanical condition of the well, multiphase flow and fluid property variation make the traditional pressure analysis inaccurate. Oil viscosity, for example, could not be treated as a constant in the well drainage area because of the rather high pressure drop necessary to produce the wells.

Numerical simulation was conducted to evaluate the impact of multiphase flow and the variation of viscosity as a function of pressure at reservoir temperature in the pressure response of heavy oil wells. Based on simulation results, the applicability of pseudopressure functions in the well test design and analysis was evaluated.

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