There is a general uncertainty regarding the issues affecting shale stability in gas shale reservoirs. True swellable smectite is not present in most of the reservoirs currently being exploited. Illite and illite/smectite are the principal clay components, and they do have a distinct fixed water of hydration which is salinity and cation dependent. Historically, two factors had a major impact on the choices made for clay stability in clay rich reservoirs. Today, many hydraulic fracturing treatments are conducted with virtually fresh water, so this comprehensive study was undertaken to identify the role of salinity on the stability of various gas productive shales. Evaluated were various inorganic salts, temporary clay stabilizers and permanent clay/shale stabilizers, and the results of the comparisons will be presented.The petrophysical properties of the samples studied have been extensively characterized and the swelling and erosional characteristics have been examined with capillary suction time (CST), roller oven (RO) and unpropped fracture flow capacity tests. Some shale samples are inherently unstable, regardless of the fluid used in the measurement, while the majority responds positively to more compatible fluids. A few samples are extremely stable in all fluids. The native state of the clay in the shales has been characterized by a variety of tests, including specialized cation exchange and wettability studies, to help understand the fluid/rock interactions.The results of this study have identified the relationship between clay stabilizer type and concentration on the stability of the shale and the impact on flow capacity in the "stimulated reservoir volume". This is a compelling story of rock/fluid interaction studies on actual cores, fit for purpose product development, and supporting field production results.