Improved Rock-Physics Model for Shale Gas Reservoirs

2012 Annual Meeting
DOI /10.1190/segam2012-0927.1 Page 1
Shale-gas rock physics
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Summary Unconventional resources such as shale gas are becoming increasingly important exploration, development, and production targets. However, geophysical characterization of these unconventional reservoirs remains challenging because of limited understanding of geophysical responses to reservoir properties such as total organic carbon (TOC). We have developed an improved anisotropic rock-physics model to incorporate TOC effects, in addition to effects of mineralogy, porosity, and fluid content, on seismic and electrical properties of shale gas. The modeling results suggest that an increase in the organic content generally reduces P-impedance, and Vp/Vs ratio, while increasing the velocity anisotropy and resistivity. This general trend is further modified by mineralogical compositions. Introduction While much US natural gas production comes from conventional resources, recent growth is dominantly from unconventional resources such as shale gas and tight gas. As a potentially large resource for future gas production, shale gas is garnering increasing attention from the industry. All shale-gas rocks are not alike, and some are better producers than others. Despite having quite different geologic settings, many shale-gas formations share features such as heterogeneity, low matrix porosity and permeability, and in some cases, brittleness. For example, fine-grained rock properties may change significantly at the centimeter scale vertically and at the dekameter scale laterally, and many common attributes can be identified for fine-grained source, reservoir, and seal rocks. Economic shale-gas development candidates require ample organic matter to generate sufficient volumes of hydrocarbons, i.e., relatively high total organic carbon (TOC). Some of these reservoirs were buried deep enough to generate gas, and now are shallow enough for economic drilling. Some are also brittle enough to facilitate hydraulic fracturing. The complexity of shale-gas formations has prompted researchers to attempt to understand the controls on production from different disciplines, such as geochemistry, geology, geomechanics, seismic, and rock physics. We studied geophysical responses of shale-gas rocks by incorporating organic matter (e.g., kerogen) into an anisotropic rock-physics model, which allows us to predict elastic and electrical properties of shale gas and to characterize TOC from a suite of log measurements. Preliminary studies suggest that the presence of organic matter reduces both P- and S-wave velocities, density, and Vp/Vs, while increasing velocity anisotropy. The influence of organic matter on resistivity varies with the level of maturity. As the source rock matures, a portion of the solid organic matter is transformed into hydrocarbons that displace part of the formation water, thereby increasing effective resistivities. However, if the maturity becomes extremely high, organic matter may transform into electrically-conductive graphite, which can reduce the effective resistivity significantly. Studying the effective elastic and electric properties using the rock physics model helps to improve our understanding of various shale-gas formations. Rock physics model Rock-physics models provide crucial links between microscopic rock properties and macroscopic physical characteristics, such as seismic velocity and resistivity, and the basis for predicting rock/fluid properties from geophysical data. Among the many factors influencing the properties of shale gas, organic matter is of particular importance not only because it is indicative of gasproduction potential, but also because of its unique velocity, density, and resistivity characteristics. Organic matter differs from fluid in that it is solid-like material with non-zero bulk and shear moduli, while fluids typically do not resist shear deformation.
constituent minerals and fluids with different shapes, alignments, and physical properties. The solid background is estimated by mixing different minerals such as quartz, calcite, and clays using Reuss-Voigt-Hill averaging. A dry rock frame is then formed by introducing inclusions into the solid background, where for example the inclusion space contains inter-particle pores or pores within clay. In the new TOC rock-physics model, organic matter is treated as part of either solid mineral (background) or inclusion space, or both, depending on specific applications. Bayuk et al. (2008) discussed a physical model of organic-rich shale, where kerogen is considered to be load-bearing material and forms the background matrix, which is then embedded with clay, silt grains, and pore/cracks. Wu et al. (2012) also suggest mixing kerogen with shale to form a kerogen-shale composite in the calculation of effective rock properties. Note that in this study we use the term inclusion space instead of pore space to avoid confusion with the common usage of fluid-filled pores. Inclusion space refers to the space occupied by any in-fill material including fluids and solids (e.g., organic matter). Experiences from various shale gas formations suggest that modeled results using organic matter treated as inclusion-filling material generally match well with measured velocity and resistivity log data. If organic matter is considered as part of the inclusion space, inclusions (or voids) in the rock are partitioned into fluid-filled pores and solid-filled volumes (kerogen volumes). Thus two types of material substitutions, namely fluid substitution and solid substitution (Ciz and Shapiro, 2007), can be used to attain the effective elastic properties of the rocks (Figure 1). Observations from nano-scale images of various source rock samples suggest that the spatial distribution of fluidfilled pores (as well as organic matter-filled inclusions) can be very complicated. For example, fluid-filled pores can sit between different mineral grains (inter-particle), within mineral grains (intra-particle), or within organic matters. This has to be handled with care when calculating the effective rock properties. For fluid-filled pores within organic matter, they can be treated as a pore system independent of organic matter-filled inclusion space. Alternatively, this part of fluid can be mixed with organic matter to form an effective medium before being incorporated into the rock physics workflow. Compared to fluid substitution discussed in the literature (e.g., Gassmann, 1951; Biot, 1956; Brown and Korringa, 1975), solid substitution is relatively straightforward. Ciz and Shapiro (2007) extended Brown and Korringa’s (1975) results to the case of solid in-fills by assuming interconnected inclusion space for the material and stress