Spontaneous Imbibition Studies in Shale Gas Reservoirs: Insight into Origins of High Salinity Flowback Water
Although hydraulic fracturing fluid is typically fresh water, in shale gas reservoirs, produced water or flowback, is often very saline. This observation suggests that flowback water is gaining salt from the formation. It is not currently known whether the recovered salt comes from dissolution of mineral salts, or interaction between bound water and frac fluid. In the absence of flowback water data, spontaneous imbibition experiments, can provide insight into the physics that governs the principal controls on flowback water salinity. This is the primary objective of this research. In addition, imbibition experiments can be related to clay mineral content (brittleness), total porosity, the relative volume of mineral hosted (water wet) and organic matter hosted (hydrocarbon wet) pore systems, and the in-situ pore fluid salinity. We propose to show that through the use of a novel multidisciplinary experimental approach the origin of high salinity flow back waters in shale reservoirs can be understood. Dual spontaneous imbibition (water and oil), ion expulsion experiments and sample characterization are combined to develop rock properties models. These techniques provide insight into effective characteristic time to reach equilibrium in salinity and imbibed volume, anticipated magnitude of flowback salinity, total porosity and clay mineral content for shale reservoirs. Experimental and modelling results suggest that the summation of the equivalent NaCl in the fluid due to anhydrite (salt dissolution) plus the equivalent NaCl due to the presence of clay minerals, result in the high salinity water associated with the Haynesville, Bossier and the La Luna Formations. Cation exchange capacity and salt volumes from geochemical analysis of equilibrated fluids obtained from imbibition experiments, might be used as a proxy to predict flowback salinity. Imbibition experiment provides a promising technique for estimating organic porosities in gas shale reservoirs and it could provide a basis for a possible GRI total porosity measurement correction, particularly in high carbonate content rocks.