The geomechanical integrity of shale overburden is a highly significant geological risk factor for a range of engineering and energy-related applications including CO$$_2$$ 2 storage and unconventional hydrocarbon production. This paper aims to provide a comprehensive set of high-quality nano- and micro-mechanical data on shale samples to better constrain the macroscopic mechanical properties that result from the microstructural constituents of shale. We present the first study of the mechanical responses of a calcareous shale over length scales of 10 nm to 100 $$\upmu$$ μ m, combining approaches involving atomic force microscopy (AFM), and both low-load and high-load nanoindentation. PeakForce quantitative nanomechanical mapping AFM (PF-QNM) and quantitative imaging (QI-AFM) give similar results for Young’s modulus up to 25 GPa, with both techniques generating values for organic matter of 5–10 GPa. Of the two AFM techniques, only PF-QNM generates robust results at higher moduli, giving similar results to low-load nanoindentation up to 60 GPa. Measured moduli for clay, calcite, and quartz-feldspar are $$22 \pm 2\,\hbox { GPa}$$ 22 ± 2 GPa , $$42 \pm 8\,\hbox { GPa}$$ 42 ± 8 GPa , and $$55 \pm 10\,\hbox { GPa}$$ 55 ± 10 GPa respectively. For calcite and quartz-feldspar, these values are significantly lower than measurements made on highly crystalline phases. High-load nanoindentation generates an unimodal mechanical response in the range of 40–50 GPa for both samples studied here, consistent with calcite being the dominant mineral phase. Voigt and Reuss bounds calculated from low-load nanoindentation results for individual phases generate the expected composite value measured by high-load nanoindentation at length scales of 100–600 $$\upmu$$ μ m. In contrast, moduli measured on more highly crystalline mineral phases using data from literature do not match the composite value. More emphasis should, therefore, be placed on the use of nano- and micro-scale data as the inputs to effective medium models and homogenisation schemes to predict the bulk shale mechanical response.

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Understanding the mechanical response of coal to CO2 injection is a key to determine the suitability of a seam for carbon capture and underground storage (CCUS). The bulk elastic properties of a coal, which determine its mechanical response, are controlled by the elastic properties of its indiv idual components; macerals and minerals. The elastic properties of minerals are well understood, and attempts have been made to acquire maceral elastic properties (Young's modulus) by means of Nanoindentation. However, due to the resolution of a nanoindent; the response is likely to be a combination of macerals. Here Atomic Force Microscopy is used for the first time to giv e a unique understanding of the local Y oung's modulus of indiv idual coal macerals, with a precision of 1 0nm in both immature and mature coals. The results at this length scale indicate that the mean and modal Young's modulus v alues in all macerals is less than 10GPa.Thermally immature liptinite macerals have a lower modal modulus than the equivalent inertinites. The modulus response is also non-normally distributed and most likely conform to a gamma distribution with shape parameter between 1 .5-2.5. The modal Young's modulus of all macerals increases with maturity, but not at the same rate, whereby the liptinite macerals become stiffer than the inertinites by the gas window.The difference between liptinite and inertinite modulus values is greater within immature coals than mature coals. Modelling of v olumetric strain under CO2 injection indicates an inv ersely proportionate relationship to Y oung's modulus, which suggest that differential swelling is more likely to occur in immature coals. As such it is preferential to target mature coals for CCUS, as the reaction of macerals at higher maturities is more predictable across an entire coal seam.

Quantification of risk to seal integrity in CCS, or gas extraction from hydraulic fracturing, is directly affected by the accessibility of organic pores within organic rich mudrocks. Knowledge of the host organic matter's mechanical properties, which are influenced by depositional environment and thermal maturity, are required to reduce operational risk. In this study we address the effect of both depositional environment and maturity on organic matter Young's modulus by means of Atomic Force Microscopy Quantitative Imaging TM , which is a nondestructive technique capable of nanomechanical measurements. Shales from varying marine depositional environments covering kerogen Types II (Barnett), IIS (Tarfaya), and II/III (Eagle Ford/ Bowland) are analyzed to capture variance in organic matter. The findings show organic matter has a Young's modulus ranging between 0.1 and 24 GPa. These marine shales have a bimodal distribution of Young's modulus to some degree, with peaks at between 3-10 and 19-24 GPa. These shales exhibit a trend with maturity, whereby Young's modulus values of <10 GPa are dominant in immature Tarfaya shale, becoming similar to the proportion of values above 15 GPa within the oil window, before the stiffer values dominate into the gas window. These peaks most likely represent soft heterogeneous aliphatic rich kerogen and stiff ordered aromatic rich kerogen, evidenced by the increase in the stiffer component with maturity and correlated with 13 C NMR spectrocopy. These findings enable increased realism in microscale geomechanical fracture tip propagation models and may allow direct comparison between Young's modulus and Rock-Eval parameters. Plain Language Summary Gas recovery from hydraulic fracturing and validating the top-seal integrity for carbon capture and storage require knowledge of key mechanical properties of the associate mudrock. One key property is elasticity (Young's modulus), which is relatively well constrained for each component of a shale, except for the organic matter. This has historically been due to the difficulties in analyzing elasticity at the resolution of organic matter particles, which can be <1 micron in diameter. Here we use a new technique to measure elasticity at a spatial resolution of between 10 and 50 nm. Organic matter elasticity measurements have been undertaken on a range of shales from marine and lacustrine depositional environments and a range of thermal maturities. The marine-derived organic matter exhibits a bimodal distribution with a peak at around 3-10 and 19-22 gigapascals (GPa). When comparing the shale samples with maturity, a clear bimodal trend is observed within the marine-derived organic matter, which becomes increasingly dominated by a stiffer (higher Young's modulus) peak with maturity.