Coal has been developed and used as an energy source for centuries, but the methane associated with coal (‘coalbed methane’, CBM) is among the most recent energy sources to be exploited, along with tight and shale gas reservoirs. Coalbed is a naturally fractured reservoir in which gas storage is mainly controlled by adsorption. Gas flow occurs via diffusion in the matrix (Fick’s law) and laminar flow (Darcy’s law) in the fractures, also known as cleats. Reservoir characterization of CBM reservoirs is challenging because of the complex properties of coal. While core, log and well testing methods have been developed specifically for coal, quantification of, for example, gas in place is complicated due to the existence of adsorbed gas. Numerical simulation history matching can be applied to CBM reservoirs to obtain CBM reservoir properties, but model setup and execution is time consuming, and substantial information is required. Flowing material balance (FMB) is a production analysis method that uses production rates and flowing pressures of a well to estimate original fluids in place. FMB methods have been developed and successfully applied to high permeability saturated (two-phase gas and water flow, below desorption pressure) and undersaturated (single-phase water flow above desorption pressure; two-phase gas and water flow below desorption pressure) coalbed methane reservoirs to obtain estimates of original fluid in place. However, their applicability to low permeability (<10 md) CBM reservoirs is more challenging due to the complication of requiring a saturation-pressure relationship for calculating pseudo-pressures used in FMB calculations. A new FMB model suggested by Clarkson & Salmachi (2017), developed for high permeability undersaturated/saturated CBM reservoirs, does not require a saturation-pressure relationship. The applicability of this method to low-permeability saturated coalbed methane reservoirs is examined in this thesis. For this purpose, simulated cases were generated for a range of permeability values. In some simulation cases, non-static permeability (a function of stress and desorption) was also included in the simulation model to test the accuracy of the Clarkson & Salmachi (2017) method for such cases. In all test cases, including cases with initial permeabilities equal to 0.5 md, the Clarkson & Salmachi (2017) FMB method resulted in gas in place estimates consistent with numerical model input.