Shale Rock Samples Research Articles

Study the impact of operational parameters on interface temperature during rotary drilling

Abstract In this article, an attempt is made to measure the temperature at the interface between bit and rock samples were studies and the correlation of factors (bit diameter, spindle speed, rate of penetration, depth, thrust and torque) effects on interface temperature was investigated. The experiments were conducted on shale rock samples by using grounded thermocouples method. During rotary drilling operation effects of factors influence on temperature rise were determined. The most influencing factors are depth (0.718), thrust (0.744) and rate of penetration (0.553) have a strong and moderate positive correlation whereas, bit diameter and spindle speed has weak positive correlation of 0.267 and 0.108 respectively. This study shows that the quantitative degree of relationship between the operational parameters and interface temperature during rotary drilling.

Ultrahigh-Resolution 3D Imaging for Quantifying the Pore Nanostructure of Shale and Predicting Gas Transport

The pore and fracture microstructures are key to understanding gas flow in shales. The experimental determination of these microstructures is dependent on the measurement technique employed and its resolution. High-resolution three-dimensional imaging techniques coupled with image analysis and numerical simulations have been employed to characterize the petrophysical properties of shale samples. In this work, our particular focus is on using the Nano-CT and focused ion beam scanning electron microscopy (FIB-SEM) techniques at the same location in a shale rock sample to investigate the effect of their different resolutions and fields of view on the resulting imaged nanopore structure, as well as to determine any differences in the consequent measurements of the shale petrophysical properties. These petrophysical properties include porosity, permeability, pore volume and size distribution, the pore aspect ratio, the surface area to volume, and pore connectivity. The reconstructed matrix, kerogen, and pore space volumes from each approach showed significant scale-dependent differences in the microstructure. The shale sample displayed a high kerogen content with high connectivity. Porosity from the reconstructed shale volumes was observed to be 0.43 and 0.7% for FIB-SEM and Nano-CT approaches, respectively. The pore volume, size, surface area to volume ratio, and two orthogonal pore aspect ratio distributions have also been determined from the reconstructed image data by three-dimensional (3D) image analysis. These data show that voids within the rock are oblate at all scales. Permeabilities have been calculated from both the FIB-SEM and Nano-CT images and fall in the range of 2.55–9.92 nD. A simulation has also been produced based on the permeability calculation and parameters from the image analysis. The results of the simulation show connectivity in the x-, y-, and z-directions for both the FIB-SEM and Nano-CT images, with very low connectivity in the x-direction but higher connectivity in the y- and z-directions.

Nanofabrication of synthetic nanoporous geomaterials: from nanoscale-resolution 3D imaging to nano-3D-printed digital (shale) rock

Advances in imaging have made it possible to view nanometer and sub-nanometer structures that are either synthesized or that occur naturally. It is believed that fluid dynamic and thermodynamic behavior differ significantly at these scales from the bulk. From a materials perspective, it is important to be able to create complex structures at the nanometer scale, reproducibly, so that the fluid behavior may be studied. New advances in nanoscale-resolution 3D-printing offer opportunities to achieve this goal. In particular, additive manufacturing with two-photon polymerization allows creation of intricate structures. Using this technology, a creation of the first nano-3D-printed digital (shale) rock is reported. In this paper, focused ion beam-scanning electron microscopy (FIB-SEM) nano-tomography image dataset was used to reconstruct a high-resolution digital rock 3D model of a Marcellus Shale rock sample. Porosity of this 3D model has been characterized and its connected/effective pore system has been extracted and nano-3D-printed. The workflow of creating this novel nano-3D-printed digital rock 3D model is described in this paper.

Micro- and Nano-Scale Pore Structure in Gas Shale Using Xμ-CT and FIB-SEM Techniques

Shale is a complex rock composed of a complex mixture of matrix minerals and kerogen and having a complex pore microstructure. The pore microstructure is highly dependent upon the scale at which it is considered. Such a microstructure is important for the assessment of the potential of gas shales based on the connectivity and pores at each scale and the ability of the rock to be hydraulically fractured. In this work, the three-dimensional (3D) structure of Bowland shale has been investigated at both microscopic and nanoscopic scales on the same sample for the first time using (i) a combination of serial sectioning, using focused ion beam (FIB) milling and scanning electron microscopy (SEM), and (ii) X-ray micro-computed tomography (Xμ-CT). The reconstructed matrix, kerogen, and pore space volumes from each approach showed significant scale-dependent differences in the microstructure. The shale samples displayed a high kerogen content with high connectivity. Porosity in the shale rock sample was observed to be prevalent in either the inorganic matrix, the kerogen, or both. Furthermore, the porosity from the reconstructed shale volumes was found to vary with locations, as sampled by FIB-SEM, within the shale samples taken for Xμ-CT. Pore volume, scale invariant surface area to volume ratios, and two orthogonal pore aspect ratio distributions were extracted from the reconstructed image data by 3D image analysis. These data show that voids within the rock are oblate at all scales. However, the smaller pores visible by FIB-SEM present higher scale invariant surface area to volume ratios, indicating that they are more likely to interlink the larger pores visible by Xμ-CT and form a small scale but highly connected pore network for fluid flow. Permeabilities have been calculated from both the FIB-SEM and Xμ-CT images and fall in the range 2.98 to 150 nD, broadly agreeing with experimental determinations from another author.

Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

Apparent liquid permeability (ALP) in ultra-confined permeable media is primarily governed by the pore confinement and fluid–rock interactions. A new ALP model is required to predict the interactive effect of the above two on the flow in mixed-wet, heterogeneous nanoporous media. This study derives an ALP model and integrates the compiled results from molecular dynamics (MD) simulations, scanning electron microscopy, atomic force microscopy, and mercury injection capillary pressure. The ALP model assumes viscous forces, capillary forces, and liquid slippage in tortuous, rough pore throats. Predictions of the slippage of water and octane are validated against MD data reported in the literature. In up-scaling the proposed liquid transport model to the representative-elementary-volume scale, we integrate the geological fractals of the shale rock samples including their pore size distribution, pore throat tortuosity, and pore-surface roughness. Sensitivity results for the ALP indicate that when the pore size is below 100 nm pore confinement allows oil to slip in both hydrophobic and hydrophilic pores, yet it also restricts the ALP due to the restricted intrinsic permeability. The ALP reduces to the well-established Carman–Kozeny equation for no-slip viscous flow in a bundle of capillaries, which reveals a distinguishable liquid flow behavior in shales versus conventional rocks. Compared to the Klinkenberg equation, the proposed ALP model reveals an important insight into the similarities and differences between liquid versus gas flow in shales.

Empirical ratio of dynamic to static stiffness for propped artificial fractures under variable normal stress

The stiffness coefficient is a key parameter of rock fractures that controls the properties and behavior of a rock mass. According to the displacement discontinuity theory, the dynamic stiffness of rock fractures can be back analyzed using stress wave propagation. This study aims to measure the dynamic stiffness of rock fractures then develop an empirical ratio to describe the relationship between dynamic and static stiffness. Propped artificially fractured shale and granitic rock samples are employed. Mechanical and ultrasonic tests are conducted on two artificial rock fractures during uniaxial loading and unloading. As normal stress changes from 1 MPa to 50 MPa, the average dynamic normal stiffness of shale and granitic rock fractures changes from 330 GPa/m to 1960 GPa/m and from 90 GPa/m to 2320 GPa/m, respectively. For both artificial fractures, the dynamic stiffness is higher than the static stiffness but approaches the static stiffness with increasing normal stress. The ratio of dynamic to static normal stiffness is approximately 2.0 at a normal stress of 15 MPa; this ratio approaches 1.0 with increasing normal stress and varies widely under low normal stress. This study provides a method for evaluating the static or dynamic stiffness of rock fractures, which has important applications for seismic surveys or acoustic logs in the field of geological engineering.

Macro- and micro-compression testing of shales

In this study, macro- and micro-geomechanical properties of shales were investigated at millimeter- and micrometer-scale using an example of the Woodford Shale. Geomechanical properties, such as uniaxial (unconfined) compressive strength and Young's modulus, were quantified at the millimeter-scale and compared with results from micro-compression testing experiments of FIB-SEM-nanofabricated micro-pillars. Size-scale and compositional/structural heterogeneity effect on elasto-plastic deformation and failure behavior of shales were investigated. Also, relationship between elemental/mineral composition and unconfined compressive strength and Young's modulus, at a micrometer-scale, was discussed. It was shown that geomechanical properties of shales are scale-dependent and are strongly affected by compositional/structural anisotropy. In particular, micro-compression testing experiments showed non-uniformly distributed compressive strength and Young's modulus within the investigated Woodford Shale rock samples. It was demonstrated, that geomechanical properties of shales, investigated at the micrometer-scale, tend to be affected by different minerals and/or pores, while the same properties, investigated at the millimeter-scale, are governed by different micro-facies (and/or micro-fractures) present within the rock. This shows that geomechanical properties of shales can be dramatically different depending on the scale of investigation and compositional/structural heterogeneity of these rocks, and therefore are not easily transferable across the scales.

Determination of inorganic and organic permeabilities of shale

Shale oil resources have become important energy supplies worldwide, but their storage features and flow mechanisms remain unclear. It is now well-accepted that shale formations are complex systems with both inorganic and organic contents. This study aims to characterize the permeabilities for inorganic and organic pore systems separately in shale samples using an innovative modeling approach validated with experimental data. Oil and water vacuum–imbibition tests were first conducted along with helium porosity measurements for four shale rock samples. A mathematical model considering imbibition and diffusion was then proposed and used to match the lab-measured oil and water imbibition curves. The critical parameters for these shale samples, including inorganic/organic porosities, fluid saturations, and permeabilities were successfully determined using this approach. Among all the samples in the study, the results showed that 33.93 to 40.54% of total oil in place was stored inside kerogen as either the free oil within the organic pores or the dissolved oil. Moreover, the flow of this part of the oil was controlled by the organic permeability as well as by the diffusion coefficient, which was different than the flow character of oil in the inorganic pore system. The organic permeabilities of the samples used in this study were between 2.24 × 10−6 and 1.59 × 10−5 md, which were 243 to 2741 times less than each sample's corresponding inorganic permeability. The sensitivity analysis indicated that organic permeability significantly affected the oil imbibition rate. The proposed methodology should be adopted in future reservoir characterizations, and the determined permeabilities for both inorganic and organic pore material should accordingly be considered in future reservoir simulations in order to accurately describe fluid flow in shale reservoirs.

Correlative core- to pore-scale imaging of shales

Abstract Unconventional reservoirs (e.g., shales) remain poorly understood, compared to conventional reservoirs, due to their complex compositional and structural anisotropy. These heterogeneities profoundly influence petrophysical and geomechanical properties of shales. Current advances in correlative multi-scale and multi-modal 2D/3D imaging provide a tremendous opportunity to image and characterize shales across multiple length scales – from core-to pore-scale. In this study, a Mancos Shale rock sample was characterized across multiple length scales – from a few centimeters to a few nanometers via digital rock analysis using correlative micro 3D X-ray computed tomography (micro-CT), micro 3D X-ray microscopy (micro-XRM), light microscopy (LM), scanning electron microscopy (SEM), and focused ion beam (FIB) – SEM (FIB-SEM) image datasets. These multi-scale/-modal 2D/3D image datasets were then correlated with each other and used to reconstruct digital rock 2D/3D models from which petrophysical properties (porosity and mineralogy) were quantified. Additionally, the SEM/FIB-SEM imaged porosity was compared with bulk porosity measured with the traditional laboratory technique of helium porosimetry. The micro-CT, LM, and (low-resolution) SEM indicated that the investigated Mancos Shale rock sample consisted of interlaminated silt- and mud-rich laminae. The silt-rich laminae were characterized further using micro-XRM, whereas mud-rich laminae were characterized in great detail using high-resolution SEM and FIB-SEM. The SEM and FIB-SEM showed the presence of various fine-grained minerals (clay) and micrometer- and nanometer-sized pores within the mud-rich laminae, whereas micro-XRM showed coarse-grained minerals (quartz) cemented with the mud-rich nanoporous matrix within the silt-rich laminae. Furthermore, the results indicated that micro-fractures significantly contributed to the porosity of the investigated core-plug rock sample.

Groundwater risk assessment investigations for oil shale exploitation in El-Lajjun area of central Jordan

Oil shales are sedimentary rocks that contain organic material in its inorganic matrix. The oil shale deposits of Jordan have been investigated since the 1960s. An extensive investigation studies have been commenced to evaluate the quality and quantity of these resources. In 2006, the government of Jordan invited pioneer companies in oil shale field to submit their proposal to utilize and develop the oil shale of Jordan using different extraction technologies. Jordan is considered one of the driest countries in the world, which poses an additional challenge for oil shale development, because a vast quantity of water is needed for this process. El-Lajjun study area is located in central Jordan; the oil shale in the study area was deposited in marine environment; it comprises massive beds of brown-black, kerogen-rich, bituminous chalky marl. Ten representative oil shale rock samples were collected for risk assessment investigations from different localities of oil shale exposures. A standardized laboratory Fischer assay test delivered oil shale characteristics. Sequential extraction was used to evaluate mobility and distribution of the trace elements Ti, V, Cr, Co, Zn, As, Zr, Cd, Pb, and U. Column leaching experiments were performed to simulate the leaching behavior of the above elements from oil shale and spent shale to evaluate the possible negative impact on groundwater in the study area. Results of sequential extraction indicate that concentration of trace elements and trace elements are richer in oil shale and in the spent shale compared to most rocks and soils. The concentrations in the leachate were below the maximum contaminant levels of the Environmental Protection Agency (EPA) and the Jordanian standards for drinking water. The significance of this study lies in that its utilizes for the first time the sequential extraction and column leaching techniques to investigate the Jordanian oil shale rocks.

Shales Leaching Modelling for Prediction of Flowback Fluid Composition

The object of the paper is the prediction of flowback fluid composition at a laboratory scale, for which a new approach is described. The authors define leaching as a flowback fluid generation related to the shale processing. In the first step shale rock was characterized using X-ray fluorescence spectroscopy, X-ray diffractometry and laboratory analysis. It was proven that shale rock samples taken from the selected sections of horizontal well are heterogeneous. Therefore, the need to carry a wide range of investigations for highly diversified samples occurred. A series of leaching tests have been conducted. The extracts were analyzed after leaching to determine Total Organic Carbon and selected elements. For the results analysis significant parameters were chosen, and regression equations describing the influence of rocks and fracturing fluid parameters on the flowback fluid composition were proposed. Obtained models are described by high values of determination coefficients with confidence coefficients above 0.99 and a relatively low standard deviation. It was proven that the proposed approach regarding shale leaching can be properly described using shale models at a laboratory scale, however scaling up requires further investigations.

Pressure pulse-decay tests in a dual-continuum medium: An improved technique to estimate flow parameters

The pressure pulse-decay permeability (PDP) measurement is a well-established technique to measure the permeability of tight rock samples such as shale. The conventional applications of the PDP measurement almost exclusively treat shale samples as a single-continuum system, even though the gas flow in some shale samples may be more accurately characterized by a dual-continuum, which is due to the large range of pore size distribution and chemical/mineralogical difference between organic and inorganic matters. However, studies about measurements of flow parameters for dual-continuum shale rock samples are very limited in literature. Liu et al. (2016) proposed a new analytical technique to characterize the dual-continuum behavior of a test sample using the PDP measurement with the same upstream and downstream reservoir volumes. In this study, a more general analytical technique is proposed and allows for using different upstream and downstream reservoir volumes in the PDP setup. With this new technique, all the existing PDP systems in laboratories can be conducted to characterize the dual-continuum behavior of a test sample without the need of modifying the upstream and downstream reservoir volumes, and the measured flow parameters of samples can be used as input parameters in the reservoir simulation of the dual-continuum system. The validity and practical usefulness of the new technique is demonstrated by the successful identification and characterization of the dual continuum behavior of test samples in laboratory.

Biofacies, Taphofacies, and Depositional Environments in the North of Neotethys Seaway (Qom Formation, Miocene, Central Iran)

Abstract This research attempted to reconstruct the sedimentary environment and depositional sequences of the Qom Formation in Central Iran, using biofacies and taphofacies analyses. The Qom Formation in the Andabad area (3°48′12.6″ N, 47°59′28″ E) is 220 m in thickness. The thickness of the Qom Formation in the Nowbaran area (35°05′22.5″ N, 49°41′00″ E) was found to be 458 m. In both areas, the formation consists mainly of shale and limestone. The lower boundary between the Qom and Lower Red Formations is unconformable in both areas. In the Nowbaran area, the Qom Formation is covered by recent alluvial sediments. In the Andabad area, the Qom Formation is unconformably overlain by the Upper Red Formation. A total of 122 limestone and 15 shale rock samples were collected from the Andabad area, and 94 limestone and 24 shale rock samples were collected from the Nowbaran area. Analysis of the collected samples resulted in the recognition of nine biofacies, one terrigenous facies, and five taphofacies within the Qom Formation in both areas. Based on the vertical distributions of biofacies, the Qom Formation is deposited on an open shelf carbonate platform. This carbonate platform can be divided into three subenvironments: inner shelf (restricted and semirestricted lagoon), middle shelf, and outer shelf. Two third-order and one incomplete depositional sequences were identified in the Nowbaran area, but in the Andabad area, three third-order and one incomplete depositional sequences were distinguished.

Water-rock interaction of the Jilh and Tawil aquifers in the Wadi Sirhan Basin, NW Saudi Arabia

A total of 79 groundwater samples from the Upper Silurian-Lower Devonian Tawil and Triassic Jilh aquifers in NW Saudi Arabia were analysed for hydrochemical and strontium isotopic composition. A sequential extraction and 87Sr/86Sr analysis were conducted on 32 cutting samples from the groundwater host rocks and the underlying shale bed. The chemical composition of the groundwater was distinct from that of the host rock lithologies in terms of elemental abundance (i.e., Na+ was dominant in the groundwater and K and Ca were the main constituents of the aquifer units). Principal component analysis (PCA) of water samples showed a positive loading of Na+ and negative loadings of Ca2+ and SO42-. The replacement of gypsiferous waters by Na+-rich waters is suggested by this ion exchange. The shale rock samples showed Na to be the dominant chemical constituent. 87Sr/86Sr ratios of the groundwater (0.707673-0.711577) and host rock samples (0.707930-0.712477) suggest that groundwater inherits the Sr signature of the rock from the exchangeable, carbonate, and the oxides phase, reflecting reducing conditions in Tawil aquifer. The elevated groundwater 87Sr/86Sr ratios were found in deeper sections of the aquifers, which coincided with the radiogenic 87Sr/86Sr of the deeper aquifer lithologies and the underlying shale bed.

Prediction of rock interlocking by developing two hybrid models based on GA and fuzzy system

Rock shear strength parameters (interlocking and internal friction angel) are considered as significant factors in the designing stage of various geotechnical structures such as tunnels and foundations. Direct determination of these parameters in laboratory is time-consuming and expensive. Additionally, preparation of good quality of core samples is sometimes difficult. The objective of this paper is introducing and evaluating two hybrid artificial neural network (ANN)-based models by considering genetic algorithm (GA) and fuzzy inference system for prediction of interlocking of shale rock samples. Therefore, hybrid GA-ANN and adoptive neuro-fuzzy inference system (ANFIS) were developed and to show the capability of the hybrid models, the predicted results were compared to those of a pre-developed ANN model. In development of these models, the results of rock index tests, i.e., point load index, dry density, p-wave velocity, Brazilian tensile strength and Schmidt hammer were taken into account as the input parameters, whereas the interlocking of the shale samples was set as the output. The results obtained in this study confirmed the high reliability of the developed hybrid models, however, ANFIS predictive model receives slightly higher performance prediction compared to GA-ANN technique. The obtained results of the developed models were (0.865, 0.852), (0.933, 0.929) and (0.957, 0.965) for ANN, GA-ANN and ANFIS models, respectively, based on coefficient of determination (R2). ANFIS can be introduced as an innovative model to the field of rock mechanics.

Determination of organic and inorganic hydrocarbon saturations and effective porosities in shale using vacuum-imbibition method

Shale oil is a significant unconventional energy resource worldwide. Shale formations are complex systems, with both inorganic and organic content and porosities. Oil saturation in a shale oil formation consists of two components: inorganic saturation (free oil-dominated) and organic saturation (ad- and absorbed oil-dominated). Shale porosity includes inorganic and organic porosities. There is no reported research that identifies the two porosities and saturations. We therefore recently performed, for the first time, two types of vacuum-imbibition tests - water imbibition and oil imbibition - on 20 shale oil rock samples to distinguish these two porosities and two saturations. In case of 100% oil saturated, the final imbibed oil volume in oil imbibition test represents the total oil content that a sample can hold, the final imbibed water volume in water imbibition test represents the inorganic content, and the difference between the two represents the organic content. Helium saturation tests were conducted to determine the total pore volume in shale rock samples. The content of ad- and absorbed oil is obtained from the difference between the total imbibed oil volume and the pore volume. The difference between the organic content and the ad−/absorbed oil content represents the organic pore volume, thereby obtaining the organic and inorganic porosities. Our results indicate that, for the shale rock samples tested, the maximum possible oil content in organic matter ranges from 6% to 55% of the total oil content, and 50% to 90% of the organic oil content is ad- and absorbed in kerogen. The organic porosity ranges from 2% to 50% of the total porosity. Both the organic oil saturation and the organic porosity exhibit a growing trend with total organic carbon of shale rock samples.

Applications of thermal desorption coupled to comprehensive two-dimensional gas chromatography/time-of-flight mass spectrometry for hydrocarbon fingerprinting of hydraulically fractured shale rocks

Development of shale gas resources through the use of hydraulic fracturing has raised a multitude of environmental concerns and motivated research towards the understanding of shale gas systems. Previous research has demonstrated the potential of utilizing hydrocarbon distributions towards the fingerprinting of a potential environmental contamination event arising from shale gas operations. However, to apply hydrocarbon distributions from shale gas wells towards point-source identification and apportionment, a better understanding of hydrocarbon origins must be achieved. Here we present an efficient and repeatable thermal desorption method, as a sample introduction methodology for GC × GC analysis of shale rock samples that results in comparable chromatograms to those produced by solvent extraction. This novel and robust characterization technique of shale cores from Marcellus and Utica formations by thermal desorption followed by GC × GC enables the understanding of hydrocarbon speciation within the native rock with minimal sample preparation time and solvent use. The detailed shale chemistry gives insight into utilizing hydrocarbon differences towards point-source identification methodologies of environmental contamination events associated with unconventional gas development. Additionally, this analytical technique may provide a more detailed analysis of hydrocarbons than what is currently implemented in the industry to pinpoint the most advantageous areas to exploit by hydraulic fracturing, yet avoiding undesirable areas such as those with a high abundance of sulfur containing compounds.

Thermogravimetry as a tool for measuring of fracturing fluid absorption in shales

Water-based fracturing fluids are used for gas shale stimulations. The fluids are pumped under pressure into the well to create conductive fractures in hydrocarbon-bearing zones. The chemical additives vary depending on the geological and technical conditions of the well. One of the requirements of good fluid coherence is its low absorbency relative to the formation rock. Standard water absorption tests for rocks are usually performed on cubic samples (50 × 50 × 50 mm) soaked in water. In case of rocks which are drilled from the borehole, obtaining such large samples is very difficult; therefore, an attempt was made to determine the rock absorption on small samples, using the TG analysis. Thermogravimetric (TG/DTG) experiments were conducted in temperature range 40–300 °C in synthetic air environment. Shale rock samples were soaked in water and fracturing fluid. The absorption of the rocks is related to the shale’s mineral composition, which was also determined by thermal analysis (TG/DSC).

Experimental Study and Numerical Modeling of Fracture Propagation in Shale Rocks During Brazilian Disk Test

Reliable prediction of fracture process in shale-gas rocks remains one of the most significant challenges for establishing sustained economic oil and gas production. This paper presents a modeling framework for simulation of crack propagation in heterogeneous shale rocks. The framework is on the basis of a variational approach, consistent with Griffith’s theory. The modeling framework is used to reproduce the fracture propagation process in shale rock samples under standard Brazilian disk test conditions. Data collected from the experiments are employed to determine the testing specimens’ tensile strength and fracture toughness. To incorporate the effects of shale formation heterogeneity in the simulation of crack paths, fracture properties of the specimens are defined as spatially random fields. A computational strategy on the basis of stochastic finite element theory is developed that allows to incorporate the effects of heterogeneity of shale rocks on the fracture evolution. A parametric study has been carried out to better understand how anisotropy and heterogeneity of the mechanical properties affect both direction of cracks and rock strength.

Cross-Scale Molecular Analysis of Chemical Heterogeneity in Shale Rocks

The organic and mineralogical heterogeneity in shale at micrometer and nanometer spatial scales contributes to the quality of gas reserves, gas flow mechanisms and gas production. Here, we demonstrate two molecular imaging approaches based on infrared spectroscopy to obtain mineral and kerogen information at these mesoscale spatial resolutions in large-sized shale rock samples. The first method is a modified microscopic attenuated total reflectance measurement that utilizes a large germanium hemisphere combined with a focal plane array detector to rapidly capture chemical images of shale rock surfaces spanning hundreds of micrometers with micrometer spatial resolution. The second method, synchrotron infrared nano-spectroscopy, utilizes a metallic atomic force microscope tip to obtain chemical images of micrometer dimensions but with nanometer spatial resolution. This chemically “deconvoluted” imaging at the nano-pore scale is then used to build a machine learning model to generate a molecular distribution map across scales with a spatial span of 1000 times, which enables high-throughput geochemical characterization in greater details across the nano-pore and micro-grain scales and allows us to identify co-localization of mineral phases with chemically distinct organics and even with gas phase sorbents. This characterization is fundamental to understand mineral and organic compositions affecting the behavior of shales.