Adsorption and storage characteristics of natural gas in low-permeability porous materials

Shales are generally treated as non-porous formations and are frequently considered as the source rock and the cap layer. Over the past decades, technical breakthroughs in the US such as horizontal drilling, multi-stage hydraulic fracturing, micro-seismic monitoring and multi-well completions have revolutionised the exploitation of shale gas formations. Natural gas in shales is encountered not only as free gas in the pore structure and fractures, but also as adsorbed gas on the pore surfaces. Accurate estimation of the amount of free and adsorbed gas and the precise analysis of the transient flow behaviour in shale gas formations are crucial for predicting production performance, devising or adjusting the production strategy, and fracture design in shale gas reservoirs. Inclusive modelling of the adsorption and desorption processes is quintessential to correctly estimate gas reserves. To ensure that the adsorption mechanism is thoroughly captured, this research considered several isotherm profiles while theoretical results were informed by experimental measurements. Closely matching core flow measurements, the Klotz isotherm model illuminated the adsorption mechanism in shale porous media. Variations in pressure and gas flowrate were deduced at the micro-level. A non-dimensionalisation approach enabled the comparison between micro-scale modelling results with actual core measurements several orders of magnitude apart in spatial and temporal scales. Normalised micro-scale theoretical results, considering the incorporated Klotz isotherm, displayed excellent agreement with actual core measurements shedding light on some of the profound aspects which govern gas flow.