Book excerpt: We report that porosity and permeability are key variables that link the thermal-hydrologic, geomechanical and geochemical behavior in rock systems and are thus important input parameters for transport models. Recent neutron scattering studies have indicated that the scales of pore sizes in rocks extend over many orders of magnitude from nanometer pores with huge amounts of total surface area to large open fracture systems (multiscale porosity, cf. Anovitz et al., 2009, 2011, 2013a, b, Wang et al., 2013; Swift et al., in press). However, despite considerable effort combining conventional petrophysics, neutron scattering and electron microscopy, the quantitative nature of this porosity in tight gas shales, especially at smaller scales and over larger rock volumes, remains largely unknown (Clarkson, 2011). Nor is it well understood how porosity is affected by regional variation, thermal changes across the oil window and, most critically, hydraulic fracturing operations. To begin providing this understanding we have used a combination of small and ultrasmall angle neutron scattering from the GP-SANS instrument at ORNL/HFIR, and the NG3-SANS (Glinka et al., 1998) and BT5-USANS instruments at NIST/NCNR (Barker et al., 2005), with SEM/BSE imaging to analyze the pore structure of clay and carbonate-rich samples of the Eagle Ford Shale. The Eagle Ford Shale is a late Cretaceous unit underlying much of southeast Texas and probably adjacent sections of Mexico. It outcrops in an arc from north of Austin, through San Antonio and then west towards Kinney County. It is hydrocarbon rich, straddles the oil window, and is one of the most actively drilled oil and gas targets in the US. The first successful horizontal well was drilled in 2008, and 2522 permits were recorded by Sept 1, 2011. While the oil and gas reserves in the Eagle Ford have been known since the 1970's, prior to the invention of horizontal drilling/hydraulic fracturing it was not considered economic. Several important trends in the rock pore structure have been identified using our approach. Pore distributions are clearly fractal but, as was observed for the St. Peter sandstone (Anovitz et al., 2013a), are composed of several size distributions. Initial porosity is strongly anisotropic, as expected for shale. However, this decreases for shale, and disappears for carbonates with maturity. In both cases significant reduction occurs in total porosity, with most of the change coming at the finest scales (