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Reservoir quality (RQ) prediction models for sandstones in use by the oil and gas industry primarily emulate mechanical compaction, quartz cementation, and cementation by a few select aluminosilicate minerals during burial. The modeled cements are treated on a kinetic basis using independent Arrhenius-style rate equations, and nonmodeled cements are constrained by empirical observations and data from analog rocks. The nonmodeled cements pose a significant modeling challenge in complex lithic and arkosic sandstones that contain carbonate, clay, or zeolite cements when analog data are not available for constraint. Twenty-nine samples covering a broad range of sandstone compositions were selected from four fields in four different sedimentary basins to investigate the potential of using modern reactive transport models (RTM) to simulate a more comprehensive suite of minerals involved in sandstone diagenesis. A commercially available RTM, GWB® X1t, was configured to model chemical diagenesis in a time–temperature burial framework conceptually similar to that employed in standard industry RQ forward models. Strategies were developed to consistently constrain kinetic parameters, fluid compositions, and fluid fluxes with the goal of standardizing these parameters to reduce configuration and calibration time. Results show that RTM using such standardized parameters can reproduce relative timing and volume changes caused by mineral dissolution and precipitation that are accurate within the uncertainty of the petrographic data constraint. The results suggest that incorporation of RTM into current industry models could provide a valuable improvement to siliciclastic RQ prediction in frontier plays with complex mineralogies wherever calibration data are sparse or unavailable.

Geochemical interactions between shale and hydraulic fracturing fluid may affect produced-water chemistry and rock properties. It is important to investigate the rock–water reactions to understand the impacts. Eight autoclave experiments reacting Marcellus and Eagle Ford Shale samples with synthetic brines and a friction reducer were conducted for more than 21 days. To better determine mineral dissolution and precipitation at the rock–water interface, the shale samples were ion milled to create extremely smooth surfaces that were characterized before and after the autoclave experiments using scanning electron microscopy (SEM). This method provides an unprecedented level of detail and the ability to directly compare the same mineral particles before and after the reaction experiments. Dissolution area was quantified by tracing and measuring the geometry of newly formed pores. Changes in porosity and permeability were also measured by mercury intrusion capillary pressure (MICP) tests. Aqueous chemistry and SEM observations show that dissolution of calcite, dolomite, and feldspar and pyrite oxidation are the primary mineral reactions that control the concentrations of Ca, Mg, Sr, Mn, K, Si, and SO4 in aqueous solutions. Porosity measured by MICP also increased up to 95%, which would exert significant influence on fluid flow in the matrix along the fractures. Mineral dissolution was enhanced and precipitation was reduced in solutions with higher salinity. The addition of polyacrylamide (a friction reducer) to the reaction solutions had small and mixed effects on mineral reactions, probably by plugging small pores and restricting mineral precipitation. The results suggest that rock–water interactions during hydraulic fracturing likely improve porosity and permeability in the matrix along the fractures by mineral dissolution. The extent of the geochemical reactions is controlled by the salinity of the fluids, with higher salinity enhancing mineral dissolution.

Porosity, permeability, and total organic carbon (TOC) in a heterogeneous suite of 21 high-maturity samples (vitrinite reflectance 1.52–2.15%) from the Barnett Shale in the eastern Fort Worth Basin display few correlations with parameters of rock texture, fabric, and composition, these factors being mostly obscured by the effects of a protracted history of diagenesis. Diagenesis in these rocks includes mechanical and chemical modifications that occurred across a wide range of burial conditions. Compaction and cementation have mostly destroyed primary intergranular porosity. The porosity (average 5 vol. % by Gas Research Institute helium porosimetry) and pore size (8 nm median pore-throat diameter) are reduced to a degree such that pores are difficult to detect even by imaging Ar ion–milled surfaces with a field-emission scanning electron microscope. The existing porosity that can be imaged is mostly secondary and is localized dominantly within organic particulate debris and solid bitumen. The grain assemblage is highly modified by replacement. A weak pattern of correlation survives between bulk rock properties and the ratio of extrabasinal to intrabasinal sources of siliciclastic debris. Higher porosity, permeability, and TOC are observed in samples representing the extreme end members of mixing between extrabasinal siliciclastic sediment and intrabasinal-derived biosiliceous debris. Reservoir quality in these rocks is neither more strongly nor more simply related to variations in primary texture and composition because the interrelationships between texture and composition are complex and, importantly, the diagenetic overprint is too strong.

We have developed process-based models for early grain coats and their impact on deep reservoir quality in the Jurassic eolian Norphlet Formation, Alabama, with implications for exploration and development in other conventional and tight-gas continental reservoirs. The Norphlet, a major gas reservoir to depths of 21,800 ft (6645 m) and temperatures of 419F (215C), displays contrasting intervals of high and low reservoir quality within compositionally similar cross-bedded eolian sands. Study results show that grain coats formed soon after deposition are responsible for differences in deep Norphlet porosity of up to 20% and permeability up to 200 md. Three types of grain coats were identified in Norphlet dune sands, each formed in a different part of a shallow groundwater system, and each with distinctive impact on deep reservoir quality. Diagenetic chlorite coats, formed where dunes subsided into shallow hypersaline groundwater, preserve good deep porosity (to 20%) and permeability (to 200 md). Continuous tangential illitic coats, formed in the vadose zone of stabilized dunes exposed to periodic fresh-water influx, preserve good deep porosity (to 15%) associated with poor permeability (1 md) due to linked formation of later high-temperature diagenetic illite. Discontinuous grain coats, formed in active dunes where grains were abraded by eolian transport, are associated at depth with tight zones of pervasive quartz cement, low porosity (8%), and low permeability (1 md). These concepts plus data from 60 wells were used to derive bay-wide predictive tight and porous-zone isopachs that can be used for well placement, geologic models, and field development.