This paper describes a case study from the Fort Worth Basin (USA), where the occurrence of residual gas in the Barnett shale was analyzed using standard basin modeling. The aim of this work was to determine to what extent conventional petroleum system simulation approaches can be applied to an unconventional system like gas shale. A sensitivity analysis was thus performed, to quantify the dependency of the residual mass of gas in the source rock at present day, on parameters involved in the generalized Darcy flow model, i.e., permeability, relative permeability, capillary pressure and adsorption threshold parameters. We found that gas retention in the source rock was mostly controlled by the gas relative permeability, and especially the gas expulsion saturation (i.e., ‘Satex’ value). High capillary pressure in the shale favours gas expulsion, however this process remains limited compared to relative permeability and permeability effects. Surprisingly, adsorption threshold values had nearly no effect on the residual mass of gas: adsorption was indeed largely compensated by the Satex effect. These results demonstrate that conventional basin modelling can reproduce the occurrence of a gas shale play, by adjusting at least gas relative permeability parameters in the source rock, especially the Satex value.


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