Understanding the creep behavior of shale is essential to precisely predict borehole instability issues and model fracturing of unconventional shale reservoirs. In this study, the creep behavior of shale in micron scale is investigated by integrating the nano-dynamic mechanical analysis (nano-DMA) grid nanoindentation (15 × 15 indents) and data clustering techniques. The results showed that the creep displacement, the creep rate, and hardness, both can be related through a logarithmic function with creep time. Furthermore, contact creep modulus increased as the hardness or Young’s modulus increased. The clustering analysis revealed that three separate phases are present in the samples where Phase 1(clay/organic matter) has the smallest contact creep modulus and Phase 3 (quartz) the largest. While creep is in progress, the creep displacement, hardness and contact creep modulus of all three phases obey the logarithmic function. Under the same creep time, reduction in the contact creep modulus of Phase 3 appears to be faster than Phase 1 while the creep rate of Phase 3 is much less than Phase 1. Ultimately, contact creep modulus is better correlated with hardness than Young’s modulus.

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.

CO2 sequestration and CO2 enhanced oil recovery (CO2-EOR) are two major processes that can expose the rock to CO2. The behavior of a rock when saturated with CO2 changes over time, affecting both the mechanical and chemical properties of the host rock. CO2 operation involves the injection and pressurization of reservoirs that usually results in changes to the state of in situ stresses that may initiate fractures. This can lead to slippage along pre-existing fracture and fault systems. CO2 storage in tight formations, either for EOR or sequestration purposes, is imperative to contribute to the current energy transition and mitigate climate change. Thus, injection of CO2 may alter the mineralogy, pore structure, mechanics, and other properties and behavior of tight reservoirs, and sometimes may be susceptible to leakage through induced fractures or reactivated faults. Here, we aim to evaluate and reassess studies on CO2 sequestration in tight reservoirs and associated formations. This report focuses on the changes in properties and behavior of tight rocks (shale and tight carbonate rocks) due to CO2 exposure through CO2 sequestration or CO2-EOR. We highlight the most important findings from available studies to date, and we recommend promising areas of research that can advance the knowledge and development of CO2 sequestration in tight formations.

The gas adsorption hysteresis effects have strong implications for the characterization of the micropore structure, which is one of the most important properties of shales. This study describes one of the first investigations of low-pressure CO2 adsorption hysteresis illustrated on the Antrim Shale samples, Michigan Basin. A total of 23 samples were characterized by using a combination of X-Ray diffraction (XRD), Rock-Eval pyrolysis, scanning electron microscope (SEM) imaging and CO2 adsorption. The partial least linear regression (PLS) was employed to study the influence of rock composition on the micropore structures and hysteresis index (HI). The results showed that the micropore parameters (surface area and volume) are positively correlated to the amount of organic matter and clay minerals, and have a negative correlation to non-clay minerals. In the Antrim Shale samples, the CO2 adsorption hysteresis seen under low pressure appears to be controlled mainly by the pore network effect caused by the presence of ink-bottle shaped pores, rather than by the swelling of clays and organic matter.

Nanopore structure development in shale is intimated with lithofacies that demonstrates a large variety in different formations. It is critical to differentiate and quantify the separate impact of lithological components (minerals and organic matter (OM)) on pore structure attributes associated with shale gas storage capacity. In this study, we classified shales into 12 lithofacies for compositional and petrophysical quantification. Parameters of our main target, the Goldwyer shales (argillaceous OM-poor, argillaceous OM-moderate, and argillaceous OM-rich lithofacies) were further compared with other shale lithofacies, pure clays and isolated kerogens, using XRD, Rock-Eval pyrolysis, Ar-SEM and low-pressure CO2/N2 gas adsorption techniques. Results show that argillaceous OM-rich lithofacies (TOC > 2% and illite-dominated clay contents > 50%) develop more interconnected pores with better hydrocarbon storage potential. The argillaceous lithofacies have large amounts of cleavage-sheet pores with large pore volumes; the accumulative pore volume of the pores in diameter from 2 to 17 nm constitutes the major amount of total pore volume that is associated with free gas. The OM-rich lithofacies develop more OM-pores (particularly in pore diameter <2 nm) that contain extraordinarily high specific surface area (SSA); the SSA of micropores makes up the major total surface area that is intimated with adsorbed gas. Further investigation on pure clays and isolated kerogens clarifies that illite mainly controls the pore sizes from 2 to 17 nm, resulting in large pore volumes in argillaceous shales. By contrast, isolated kerogen dominantly controls micropores in diameter <2 nm, leading to a larger surface area with higher adsorbed gas storage in organic-rich shales.