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.