Production of oil from organic shale reservoirs depends on porosity, hydrocarbon saturation, wettability, pore pressure, matrix permeability, and hydraulic fracture surface area plus conductivity. In this work we investigate pore body size, wettability, and movable hydrocarbon volumes using log and core nuclear magnetic resonance (NMR) from the Eagle Ford Shale. Core porosity measurements, scanning electron microscope images (SEM) and mercury injection capillary pressure tests (MICP) are compared with the NMR interpretation for calibration and validation.
Unconventional reservoirs such as shale oil contain hydrocarbon in the form of oil and bitumen in nanopores that are generated in the kerogen matrix during maturation. These hydrocarbon fluids have fast-relaxing times similar to clay-bound water. Therefore, typical NMR T2 or Diffusion-T2 measurement cannot distinguish the hydrocarbon fluid from clay-bound water. Two types of pore systems are present in the Eagle Ford Shale, kerogen-hosted organic matter pores (OM) and inter/intra-granular pore (IP). We show that 2-D T1-T2 mapping is a good tool for fluid type and OM/IP pore wettability identification.
Core pore fluids measured under laboratory conditions are not representative of in-situ conditions because the lighter portion of the hydrocarbons have been expelled during core extraction. Comparison between log-NMR and core-NMR allows the quantification of this expelled hydrocarbon, resulting in a T2 cutoff for movable (expelled) and non-movable fluid. Porosity from core MICP measurement represents the effective porosity which does not include the porosity from bound fluid, defined as a combination of clay-bound water and bitumen or kerogen-bound oil. The comparison between the core MICP porosity and log-NMR total fluid porosity gives a T2 cutoff of effective porosity for NMR log.
ntegration of log-NMR, MICP and SEM gives pore body and throat size distribution with body to throat ratio (BTR). The NMR depth log indicates that the upper Eagle Ford Shale has more movable fluid porosity than the lower Eagle Ford Shale. The regression between 2-D core-NMR fluid porosities and the geochemical log shows that bound water has a linear relation with clastic mineral contents, and bound oil has a linear relation with total organic carbon (TOC). Integration of geochemical log, log-NMR and core-NMR gives the porosity for each fluid type. Fluid porosity results show that oil is the dominant movable fluid. Comparison between log-NMR and core-NMR gives movable hydrocarbon zones with the "best" producibility. Understanding which portion of a shale reservoir contains movable fluids impacts target zone selection and reserve estimates.