Carbon Capture, Utilization, and Storage (CCUS) can be widely applied to various depleted petroleum reservoirs, particularly those that can be revitalized through secondary recovery. There are, however, different characteristics of a reservoir that need to be considered before the start of a field secondary recovery, including reservoir type, mineralogy, and porosity/permeability variability. Here we present two case studies of the Jurassic Lower Taylor Sand of the Cotton Valley Sandstone and the Cretaceous Blossom Sand to showcase rapid reservoir characterization for CCUS using portable X–ray fluorescence (XRF) on core and its workflow, and controls on the porosity and permeability of these two Gulf Coast sandstone reservoirs.

High-resolution XRF data were obtained from the core face just after slabbing (sampling resolution ~0.1 to 0.2 ft). The XRF data were then processed through a mineral model, and classified into elemental lithotypes (chemofacies) using hierarchical cluster analysis. Petrology analyses (thin section, scanning electron microscopy [SEM], and X–ray diffraction [XRD]) were then used to help quantify the amount and distribution of potentially reactive pore-facing mineral phases. Lastly, the XRF data were used in conjunction with core-description sedimentary facies for chemostratigraphic correlation, improving the understanding of overall depositional architecture. Relevant analytical parameters from all of these results were parsed or integrated to provide input for reactive transport modeling. Following integration and interpretation, the workflow is inverted. Mathematical relationships were then established between measured rock parameters and XRF elemental data.

The Jurassic Lower Taylor Sand of the Cotton Valley Sandstone in Claiborne Parish, Louisiana, is a relatively deep (~10,000 ft) tight sandstone play. It is a quartz arenite with occasional packstone and grainstone beds, pressure dissolution clays throughout, and interbedded shales. Porosity ranges from 0.8 to 8.6%, with permeabilities generally <0.1 mD. Mineralogy consists primarily of quartz, with plagioclase, feldspars, calcite and minor clay minerals. Previously it was thought that the low permeability was caused by clays, but with the aid of thin sections and XRF, it was found that the calcite cementation restricts fluid flow.

The Cretaceous Blossom Sand of the Austin Group in Panola County, Texas, however, is a much shallower (~2000 ft), friable sandstone, with porosities averaging ~24% and permeabilities ~25 mD. It is an illite-rich, fine-grained quartz arenite to wacke that has been heavily bioturbated. It consists of primarily quartz, calcite, and illite, with minor amounts of plagioclase, muscovite, biotite, hematite, and siderite. The permeability of the fine-grained, calcite cemented sandstone is restricted, similar to the Taylor Sand, more by the degree of calcite cementation rather than clay content, and is influenced by the degree of bioturbation as well. XRF was then used to showcase the horizontal and lateral variability of porosity across Panola County, indicating that the degree of cementation occurs as lenses with little lateral continuity observed between cores.

Overall, while traditional porosity and permeability measurements are conducted sparsely on cores, XRF can be conducted at much higher resolutions, and allows for models of critical reservoir characteristics to be developed for proper and rapid characterization. Once the controls on porosity, permeability, and rock mechanics are understood, then these can quickly be extrapolated to cuttings and even well log data across a region.