Formation testing is one of the key steps of reservoir evaluation and provides essential information about static pressure of reservoir layers, water-hydrocarbon contact depth and hydrocarbon volume in place. In a gas bearing zone drilled with water-based mud (or oil-based mud), the pressure measurements in the gas zone are influenced by mud filtrate (liquid) invasion effect. The formation tester measures the pressure of filtrate, which is less than the reservoir pressure for the gas phase by an amount equal to the capillary pressure.

In tight formations, a reliable determination of pressure gradient is challenging due the low reservoir permeability, weak mud cake build-up on the wellbore wall, continuous invasion of the mud filtrate from the wellbore into the reservoir, and by the effect capillary pressure that causes mud filtrate to be imbibed into the reservoir. Thus, the measured pressure in tight reservoirs may be different than the actual formation pressure as a result of the supercharging effect.

This paper examines the estimation of the true formation pressure in tight gas reservoirs using numerical simulation approach and evaluates the effect of filtrate invasion and capillary pressure on the measured formation pressure and the gas-water contact depth. The results highlighted that due to the mud filtrate invasion into a gas zone in a tight reservoir, the measured pressure may be less than the actual reservoir pressure, and also pressure gradient may be over-estimated. Therefore in tight gas reservoirs, the under-estimated reservoir pressure and over-estimated pressure gradient may make the measured water-gas contact depth to be different than the actual water-gas contact depth.

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