The Devonian Antrim Shale is an unconventional biogenic gas accumulation with a technical recoverable resource of 19.9 Tcf. However, major knowledge gaps remain regarding understanding of the source rock potential, organic facies assemblages and paleo-depositional conditions of the Antrim Shale members. This work utilized Rock-Eval pyrolysis, reflected light microscopy and solid bitumen reflectance to characterize the source rock quality, organo-facies assemblages, and thermal maturity of the various Antrim Shale members at three different localities in the Michigan Basin. Results showed that the Lachine and Norwood members are richer in organic matter (up to 24 wt%) than the Upper and Paxton members (<8 wt%). Organic matter is mainly dominated by marine Type II kerogen in the black shales of the Lachine and Norwood members, and by Type II and Type II/III in the Paxton Member. Telalginite, which is represented mainly by Tasmanites and Leiosphaeridia cysts, is the dominant organic matter in the black shale members where they account for about two-thirds of the organic matter composition. Solid bitumen, which accounts for less than one-third of the organic matter composition, is second after alginite. Both alginite and solid bitumen populations decline in abundance progressively in the Upper and Paxton members at the expense of inertinite and vitrinite. The dominant organofacies groups in the studied Antrim Shale members can be assigned to the BP type B and type D/E. Organic matter maturity determined from Rock-Eval Tmax and bitumen reflectance varies from immature to marginally mature across the Michigan Basin. The results confirmed that sediment burial depth and lateral position in the basin controlled organic facies assemblages within the Antrim Shale members.

Traditional core flooding experiments can only be used post breakthrough while what happens in the core prior to this time is vital to understand multiphase flow phenomenon for more successful EOR operations. We can overcome this obstacle through a visualized fluid displacement scheme. This can ultimately provide us with a reliable relative permeability curve that can lead to a more accurate reservoir simulation outcome in the field scale. In this study, NMR imaging is employed in a water flood experiment in conjunction with two separate numerical two-phase flow simulation methods (FDM and FEM), to reproduce experimental data. Using the Brooks-Corey equation, random pore size distribution indices (λ) are selected to generate relative permeability curves. Moreover, simulations are performed with FDM, and oil displacement efficiency, saturation maps, and saturation profiles are generated and compared to the experimental results. Next, FEM was employed in COMSOL for further validation and FDM results were found in agreement with the experiments. This way, an appropriate relative permeability curve was generated and assigned to the sample. Results suggest that λ of 0.2 generated the best numerical results with an MSE value of 0.009 in oil displacement efficiency curves, comparable to the experiments. Collectively, integration of imaging techniques with routine experimental fluid displacement procedures presented a detailed insight into complicated nature of multiphase flow phenomena in geomaterials.

Characterizing the kerogen-hosted pore structures is essential to understand the adsorption, transport and storage potential in organic-rich shale reservoirs. In this paper, we first separated the organic matter (kerogen) from the mineral matrix in four different shale samples of the Bakken Formation with different thermal maturities and then analyzed their chemical compositions using the wide-angle X-ray scattering (WAXS) method. Next, we acquired small-angle X-ray scattering (SAXS) to characterize the structure of the organic matter and see how these two will relate. The WAXS results showed that the isolated kerogens have high purity (free of inorganic minerals) and retain different chemical compositions. Moreover, SAXS analysis revealed that the isolated kerogens have similar radius of gyration (Rg) which is around 90 Å and the molecules are in the compact mode. Based on the pore size distribution analysis from the SAXS data, two main peaks were found in all of these four samples with one peak less than 40 Å and the other one larger than 1000 Å. Also, the TEM images revealed that Sample 1 is abundant in pores with sizes around 20 nm while Sample 2 does not have pores of that size, which agrees with the results from the pore size distribution that was obtained from the SAXS method. Ultimately, this study exhibits how different analytical instruments can provide us with useful information from complex structures of geomaterials. For all the samples, two main peaks can be found with one peak less than 40 Å and the other one larger than 1000 Å。

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.

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.

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.

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.

Recently, nanoindentation has become an increasingly popular method for geomechanical analysis of rock samples in petroleum industry. Unloading curves of shale samples from the nanoindentation, which are considered as the pure elastic response, are used to determine the mechanical properties such as Young's modulus. In order to find a suitable model to characterize the unloading behavior of shale samples, in this study, we collected one Bakken Shale sample and performed nanoindentation tests on aliquots. First, the characteristics of the unloading curves were analyzed and then parameters such as: contact displacement and Young's modulus, based on two different prominent models (Oliver-Pharr model and Zeng-Chiu model) were calculated. Finally, values obtained from these two models were compared. The results showed that the unloading curves from the shale samples are nonlinear while Oliver-Pharr and Zeng-Chiu models both can be applied to represent the unloading curves. The mean Young's modulus from Oliver-Pharr model is around 1.2 times the value from Zeng-Chiu model. Using the Mori-Tanaka method, the upscaled Young's modulus value (32.14 GPa) from the Oliver-Pharr model is slight larger than the value from Zeng-Chiu model (28.70 GPa). In conclusion, the Oliver-Pharr model and Zeng- Chiu model can be both applied to study the unloading behavior of the nanoindentation curves.

Bakken shale samples were studied for distribution of adsorbed water using low-pressure nitrogen sorption. By comparing results between dry and wet samples, the distribution of adsorbed water in shale was determined. Two of the isolated kerogen samples show a striking change of pore size distribution (PSD) in large pores (>16 nm), indicating the pronounced distribution of adsorbed water in large pores of organic matter. As for the bulk shale, water can adsorb in both small (16 nm) depending on hydrophilic sites. However, hydrophilic sites in small pores are mainly contributed by inorganic matter, while hydrophilic sites in large pores are composed of inorganic or organic matter. The overall results therefore clarify the contribution of inorganic and organic matter to water adsorption in shale and provide a better understanding of the significance of adsorbed water in shale.

Estimating permeability of carbonate rocks using mercury injection capillary pressure (MICP) data has been carried out by many researchers in the past few decades. However, a major issue with almost all of the existing models is that they focus on a single aperture value from the capillary pressure curve. This study builds a new model to extract permeability from the entire pore throat sizes. Fermic-Dirac function was applied to fit the MICP curve to obtain some critical parameters such as R1 (the large curvature value) and R2 (the small curvature value). Afterwards, the partial least squares regression method was employed to develop a new permeability model. To verify the new model and check other models, we studied ten carbonate rock samples from an Iranian oil reservoir. The results showed that the R1 values vary from 1.00 to 2.73 while R2 values are found between 0.23 and 1.00. The new model performed better than the published models. The idea of building the model for the carbonates can be used in developing the permeability estimating model for shale samples, which could be a new model for the shale permeability estimation.

In this study, three shale samples from the Wolfcamp Formation in Permian basin were selected and studied for creep behavior using two different methods at macro- and micro-scale: triaxial and nanoindentation creep tests. The triaxial creep test showed the effects of axial differential stress on the creep behavior of shale rocks including the strain and contact creep modulus. As the axial differential stress increased, the creep strain value presented an increasing trend. Additionally, based on the grid nanoindentation creep experiments, three different mechanical phases were recognized in these samples; Phase 1: soft mechanical phase, Phase 2: intermediate, and Phase 3: hard mechanical phase. Based on the micro-scale results, at the same creep time periods, phase 1 (clay + organic matter) was found to have a smaller contact creep modulus and larger creep strain value than Phase 3 (quartz). Comparing the results from these two scales of measurements, the contact creep modulus from the triaxial test and the homogenized contact creep modulus from nanoindentation experiments showed some discrepancies. Based on the samples in this study, the contact creep modulus from the triaxial test varied from 0.5 to 4 times the value of the nanoindentation test. The differences between the contact creep modulus from the nanoindentation and triaxial test could be due to the creep strain amplitude. Considering Sample 1 as an example, the creep strain amplitude under the nanoindentation is inferred to be 0.069 which is not equal to the creep strain amplitude from the triaxial test (0.0052 under differential stress of 30 MPa). Ultimately, the contact creep modulus from the nanoindentation can fluctuate based on the samples’ content, while the reason for this is still a question that needs further study. Overall, this study is a preliminary investigation to help us understand how nanomechanical data in complex geomaterials can relate to traditional triaxial data.