Abstract

This work shows that in tight rocks, the measured gas slip factors increase as water saturation increases, which seems to be consistent with Klinkenberg’s theory. But interestingly, the measured results are always larger than the predicted ones by Klinkenberg’s ideal model. This finding is possibly caused by the heterogeneity of actual samples; however, it has not been considered in Klinkenberg’s model. A heterogeneity coefficient χ is proposed to correct the deviation between actual case and ideal case. For Klinkenberg’s idealized porous media, χ=0.5; but for actual tight sandstones, χ ranges from 0.5 to 3.0. Based on the corrected coefficient, the two-phase gas slippage of our studied samples can be well characterized. The impact of two-phase gas slippage on the relative permeability needs to be concerned. Without correction of gas slippage in the experimental condition (e.g., low pressure condition), the relative permeability for gas flow in reservoir conditions (e.g., high pressure condition) will be overestimated, and the error for our studied samples can be up to 20%.