Abstract Shale gas reservoirs have become a major source of energy in the recent years. Developments in hydraulic fracturing technology have made these reservoirs more accessible and productive. Apart from other dissimilarities from conventional gas reservoirs, one major difference is that a considerable amount of gas produced from these reservoirs comes from desorption. Therefore it is important to understand the adsorption phenomenon and to include desorbed gas and its effect in our analysis. The objective of this work was to imbed the adsorbed gas in the techniques used previously for the analysis of tight gas reservoirs. Most of the desorption from Shale gas reservoirs takes place in later time when there is considerable depletion of free gas and the well is undergoing boundary dominated flow (BDF). For that matter (BDF) methods and utilizing end of transient time, to estimate OGIP, that are presented in previous literature are reviewed to include adsorbed gas in them. (Kings (1990) modified z* and (Bumb and McKee’s (1988) adsorption compressibility factor for adsorbed gas are used in this work to include adsorption in the BDF and end of transient time methods. Employing a mass balance, including adsorbed gas, and the productivity index equation for BDF a procedure is presented to analyze the decline trend when adsorbed gas is included. This procedure was programmed in EXCEL VBA named as Shale gas PSS with adsorption (SGPA). SGPA is used for field data analysis to show the contribution of adsorbed gas during the life of the well and to apply OGIP estimation methods with and without adsorbed gas. The estimated OGIP’s were than used to forecast future performance of wells with and without adsorption. Original gas in place (OGIP) estimation methods when applied on field data from selected wells showed that inclusion of adsorbed gas resulted in approximately 30% increase in OGIP estimates and 17% decrease in recovery factor (RF) estimates. This work also demonstrates that including adsorbed gas results in approximately 5% less stimulated reservoir volume estimate.