Elastic Properties Of Organic-rich Shales Research Articles

AFM vs. Nanoindentation: Nanomechanical properties of organic-rich Shale

Obtaining elastic properties of organic-rich shales through conventional geomechanical testing could be challenging due to availability of good quality core plugs and significant heterogeneous nature of the samples. In this regard, force spectroscopy methods, nanoindentation and atomic force microscopy (AFM) are two main powerful techniques to characterize elastic properties in nano/microscale. In this study, we investigate the applicability of these two methods on the same samples, by quantifying elastic modulus from the Bakken Shale. AFM provided us with modulus maps of higher resolution compared to the modulus maps from the nanoindentation that were created via geostatistical methods. Moreover, results from these methods were compared to demonstrate the advantages and shortcomings of each and discripancy in the outcome. To do so, multi-cluster deconvolution approach was adopted in the statistical analysis on the nanoindentation data, demonstrating 3 separate clusters and mechanical phases. AFM technique, similarly, distinguished three separate (mineral and organic) phases based on the corresponding modulus values, though with higher accuracy compared to nanoindentation and better distinction and less tolerance. It was found that nanoindentation, because it collects discrete datapoints that are farther apart from each other when thermal maturity is increased in the samples, would have difficulty to separate organic matter from intermediary phases. Overall, the range of modulus for each phase was larger in the data that was obtained by nanoindentation compared to the AFM which can be interpreted to the size of the tip and general higher resolution in the later one which is expected to probe a single particle rather than an aggregate of particles.

Determining elastic properties of organic-rich shales from core, wireline logs and 3-D seismic: A comparative study from the Duvernay play, Alberta, Canada

Mechanical rock properties control the behavior of reservoirs undergoing hydraulic fracturing treatment. These can be measured directly through physical rock sample testing or indirectly using geophysical and petrophysical techniques, which provide proxies for mechanical properties based on elastic-wave velocity. While direct methods provide precise determination of mechanical properties, they represent point measurements that generally lack stratigraphic continuity. Integration of these with vertically and or laterally continuous indirect datasets is therefore critical for play characterization. Using a case study from the Western Canadian Duvernay Formation, we compare elastic moduli determined from core testing with indirect estimates from wireline logs and 3-D seismic inversion. Core-measured Young's modulus values fall within the 21–27 GPa range, compared to higher dynamic values of 30–70 GPa and 52–59 GPa from wireline logs and 3-D seismic inversion, respectively. Core-measured Poisson's ratio ranges between 0.16 and 0.27, which falls within estimates from wireline logs 0.17–0.31 and 3-D seismic 0.18–0.20. Although all three datasets show internal variability in mechanical properties which is at least partly controlled by changes in reservoir geology, correlation between datasets is challenging due to the underlying assumptions of each method. Reconciling indirect and direct estimates is further complicated by core-scale features such as sample integrity and lamination, which are averaged-out by indirect techniques. Additionally, the relationship between elastic moduli and testing confining pressure remains uncertain, encumbering the quantitative integration of core tests made at different pressures. Consequently, considerable care must be exercised when selecting specific core measurements serve as reference data before integrating any indirect mechanical measurement.

A simple effective medium approach for the bulk electrical and elastic properties of organic-rich shales

Shales are widespread in the Earth's crust, and organic-rich shales have become an important energy resource. Geophysical data are becoming increasingly important for characterizing shale reservoirs to find zones of good quality, typically characterized by high kerogen and low clay content. Away from well control, most geophysical characterization of shale reservoirs are based on the effects of kerogen on the elastic properties of the shale rock. However, both clay and kerogen act to reduce the stiffness of shale rocks, and their effects might be inseparable using seismic properties alone. A combination of the elastic and electrical properties of organic-rich shales might improve our ability to locate zones of good quality by decoupling the effects of kerogen and clay. Kerogen is considerably more resistive than clay and should, in theory, increase the bulk resistivity of the shale when present. The effects of shale composition on the joint elastic-electrical properties of shales can be explored using a combination of suitable well data and rock physics modeling. A comprehensive suite of well data could be used to observe trends, with a joint model aiding trend analysis. Effective medium models lend themselves well to estimating joint effective properties of a heterogeneous composite. This is because using the same approach for both the elastic and electrical properties would ensure an equivalent microstructure for both properties, as would be expected in practice. In this study, a joint effective medium model was calibrated and constrained using well data, achieving good correlation with elastic and electrical well log data from two wells. The results show that both kerogen and clay tend to reduce the stiffness of shales as expected, however; kerogen plays a significant role in increasing the bulk electrical resistivity of shales, whereas clay has the opposite effect. This joint elastic-electrical approach could potentially help discriminate kerogen-rich from clay-rich shales, in addition to constraining each individual property.

On the evolution of the elastic properties of organic-rich shale upon pyrolysis-induced thermal maturation

The evolution of the elastic properties of organic-rich shale as a function of thermal maturity remains poorly constrained. This understanding is pivotal to the characterization of source rocks and unconventional reservoirs. To better constrain the evolution of the elastic properties and microstructure of organic-rich shale, we have studied the acoustic velocities and elastic anisotropy of samples from two microstructurally different organic-rich shales before and after pyrolysis-induced thermal maturation. To more physically imitate in situ thermal maturation, we performed the pyrolysis experiments on intact core plugs under applied reservoir-magnitude confining pressures. Iterative characterization of the elastic properties of a clay-rich, laminar Barnett Shale sample documents the development of subparallel to bedding cracks by an increase in velocity sensitivity to pressure perpendicular to the bedding. These cracks, however, are not visible through time-lapse scanning electron microscope imaging, indicating either submicrometer crack apertures or predominant development within the core of the sample. At elevated confining pressures, in the absence of pore pressure, these induced cracks close, at which point, the sample is acoustically indistinguishable from the prepyrolysis sample. Conversely, a micritic Green River sample does not exhibit the formation of aligned compliant features. Rather, the sample exhibits a largely directionally independent decrease in velocity as load-bearing, pore-filling kerogen is removed from the sample. Due to the weak alignment of minerals, there is comparatively little intrinsic anisotropy; further, due to the relatively directionally independent evolution of velocity, the evolution of the anisotropy as a function of thermal maturity is not indicative of aligned compliant features. Our results have indicated that horizons of greater thermal maturity may be acoustically detectable in situ through increases in the elastic anisotropy of laminar shales or decreases in the acoustic velocities of nonlaminar shales, micritic rocks, or siltstones.

Water-Content Effects on Dynamic Elastic Properties of Organic-Rich Shale

Summary Acoustic-velocity measurements are an important nondestructive way to investigate dynamic rock-mechanical properties. Water content and bedding-plane-induced anisotropy are reported to significantly affect the acoustic velocities of siliciclastic sandstones and laminated carbonates. This relationship in organic-rich shales, however, is not well-understood and has yet to be investigated. The mechanical properties of organic-rich shales are affected by changes in water content, laminations, total organic content (TOC), and microstructures. In particular, kerogen density that accompanies changes in the composition of the TOC during maturity can significantly influence the acoustic responses within source rocks. To understand how these variables influence acoustic responses in organic shales, two sets of cores from the Eagle Ford shale were investigated: one set cut parallel to bedding and the other perpendicular to bedding. Textures of the samples from each set were characterized by use of computed-tomography (CT) scanning. Nuclear magnetic resonance (NMR) was used to measure the water content, and X-ray diffraction (XRD) to analyze the mineralogy. Scanning electron microscope (SEM) was also used to characterize the microstucture. Acoustic-velocity measurements were then made on each set at various confining pressures with the ultrasonic pulse-transmission technique. The results show that confining pressure, water content, and laminations have significant impact on both compressional-wave (P-wave) and shear-wave (S-wave) velocity. Both velocities increase as confining pressure increases. Velocities measured from cores cut parallel to bedding are, on average, 20% higher than those cut perpendicular to bedding. Increasing water content decreases both velocities. The impact of water content on shear velocity was found to be significant compared with the response with compressional velocity. As a result, the water content was found to lower both Young's modulus and shear modulus, which is opposite to the reported results in conventional reservoir lithology. In addition, both P- and S-wave velocities show a linear decrease as TOC increases, and they both decrease with increasing of clay content. The mechanisms that lead to water-content alteration of rock-mechanical properties might be a combined result of the clay/water interaction, the chemical reaction, and the capillary pressure changes.

A rock physics model for the characterization of organic-rich shale from elastic properties

Kerogen content and kerogen porosity play a significant role in elastic properties of organic-rich shales. We construct a rock physics model for organic-rich shales to quantify the effect of kerogen content and kerogen porosity using the Kuster and Toksoz theory and the self-consistent approximation method. Rock physics modeling results show that with the increase of kerogen content and kerogen-related porosity, the velocity and density of shales decrease, and the effect of kerogen porosity becomes more obvious only for higher kerogen content. We also find that the Poisson’s ratio of the shale is not sensitive to kerogen porosity for the case of gas saturation. Finally, for the seismic reflection responses of an organic-rich shale layer, forward modeling results indicate the fifth type AVO responses which correspond to a negative intercept and a positive gradient. The absolute values of intercept and gradient increase with kerogen content and kerogen porosity, and present predictable variations associated with velocities and density.

The effect of kerogen on the elastic anisotropy of organic-rich shales

The elastic properties of reservoir rocks are important for geomechanics applications; the most important of which are: analysis of stress changes due to production, analysis of rock deformation and failure, wellbore trajectory optimization, and the design of hydraulic fractures. Organic-rich shales are often observed to be strongly anisotropic due to the partial alignment of anisotropic clay minerals and the bedding-parallel lamination of organic material within the shale. Neglecting shale anisotropy may lead to incorrect estimates of the in situ stress or stress changes resulting from production. As a result, isotropic models may fail to describe geomechanical behavior correctly. The distribution of the organic phase plays an important role in determining the elastic properties of organic-rich shales, and this has a significant effect on production-induced stress changes. The presence of kerogen leads to a decrease in all of the elastic moduli, and has a significant effect on the geomechanical behavior of shales. The change in horizontal effective stress for a given change in pore pressure resulting from production is greater for kerogen-rich shales, and the neglect of anisotropy in predicting such stress changes may lead to significant errors.