Shale gas formations are complex and heterogeneous systems, with both organic and inorganic content. Shale gas is contained in porous reservoirs in three forms: as free gas in the matrix pores and natural.fractures, as adsorbed gas on the surfaces of pores within organic matter and clay minerals, and as dissolved gas in kerogen. Identifying the relative proportions of the three different forms of gas in the production stream is important to the design of effective production strategies. In this paper, we performed gas production tests for four shale gas core samples with the same initial gas-in-place, but to different production pressure levels, to evaluate the contributions of the three different forms of gas to the ultimate gas production. The cumulative production curves exhibited several stages, representing different gas production processes. Production of compressed free gas, adsorbed gas, and dissolved gas were identified from the slopes of the cumulative gas production versus time curves. For the shale gas core samples tested, it was found that a portion of the adsorbed gas as well as a portion of the dissolved gas is not producible when the production pressure was above a certain value. The contributions of free gas, adsorbed gas, and dissolved gas to the cumulative gas production varied with the production pressure. Through the analysis of controlling factors, the free gas production has no correlation with total organic content (TOC), shale desorption properties, or stress sensitivity of permeability. At high production pressures, the adsorbed gas production is primarily affected by the shale desorption properties, while, at low production pressures, the adsorbed gas production is primarily affected by the stress sensitivity of permeability. And, although TOC can significantly increase the adsorbed gas content, the adsorbed gas production percentage of gas-in-place and TOC exhibit no correlation. (C) 2016 Elsevier B.V. All rights reserved.