Shale Kerogen Research Articles

Three-dimensional molecular modeling of Dachengzi oil shale kerogen

Three-dimensional molecular modeling of Dachengzi oil shale kerogen

Formation mechanism and structural characteristic of pore-networks in shale kerogen during in-situ conversion process

In-situ conversion process (ICP) appears to be a promising approach to enhance hydrocarbon recovery of shale reservoirs. During the ICP, the pore-networks gradually generate underground and serve as the conduits for the storage and transport of hydrocarbon, which finally decides the recovery ability of the reservoir. Reactive molecular dynamics simulations are used to study the pyrolysis behavior of kerogen under the reservoir conditions. The pyrolysis proceeds in four stages: energy accumulation, oil window, gas window, and steady stage. And during this process, the kerogen pyrolytic pore-networks form under the combined actions of chemical bond breaking and physical deformation. Further analysis demonstrates that the structural characteristic is dependent on the maturities of kerogen and pyrolysis temperature. Low-maturity kerogen creates high-quality pore-networks (∼15% porosity), while the pores in medium- and high-maturity kerogen are scarce and isolated (∼1% porosity). In the simulation, the optimal pyrolysis temperature of pyrolysis is about 2300 K to develop high-quality pore-networks. In addition, a conversion relationship between the simulation temperatures and ICP engineering temperatures is established using Arrhenius equations, and the optimal temperature for ICP engineering is suggested to be ∼730 K.

Two-step pyrolysis degradation mechanism of oil shale through comprehensive analysis of pyrolysis semi-cokes and pyrolytic gases

Despite kerogen's importance as organic matter produced from oil shale, its pyrolytic degradation mechanism remains unexplored. As the potential demand for oil shale utilization increases, identifying the physical relationship between pyrolysis degradation and temperature for kerogen becomes all the more important. Here, we determine the variation in the pyrolysis degradation of the Huadian oil shale through comprehensive analysis using terahertz spectroscopy, thermogravimetric analysis, X-ray diffraction, scanning electron microscopy, infrared spectroscopy, and mass spectroscopy. Through the hybrid detection of pyrolysis semi-cokes and pyrolytic gases, we provide a detailed pyrolysis model for oil shale and show that it can be used to predict the essential characteristics that are amenable to experimental validation. Kerogen in oil shale was first depolymerized into asphalt monomer. The macromolecular organic matter (OM) began to decompose and produce CO2, but the OM did not decompose into low-carbon oil and gas. As the temperature continued to rise, the asphalt monomer decomposed into shale oil and shale gas. The OM in the oil shale generated a large amount of oil and gas. Consequently, these results demonstrate the two-step pyrolysis degradation of oil shale, which provides theoretical support for underground in-situ pyrolysis technology and underground oil shale development.

Hydrocarbon potential and Organofacies of the Devonian Antrim Shale, Michigan Basin

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.

Sticky layers affect oil transport through the nanopores of realistic shale kerogen

Understanding the transport mechanism of hydrocarbons through kerogen nanopores is crucial to shale oil production. However, existing studies primarily focus on single-component hydrocarbons; some important characteristics of shale kerogen were not thoroughly accounted for, such as the rough kerogen surface, the existence of heteroatoms, and the cylindrical pore geometry. We study the adsorption and pressure-driven flow behavior of multicomponent hydrocarbon mixtures through realistic shale kerogen nanopores. For the first time, we show that caused by the strong attraction from the kerogen substrate and its rough surface, hydrocarbons exhibit a parabolic velocity profile only in the central pore, and a sticky layer forms upon the kerogen surface. Our results contradict the fast mass transport reported in previous studies, in which ultrasmooth carbon nanotube or graphene was used to mimic shale kerogen. The existence of a sticky layer decreases the mobilized cross-sectional area of the kerogen pore, which dramatically impedes the transport capability of shale oil. Increasing the driving force or the proportions of light components will shrink the sticky layer and enhance fluid mobility. CO2 injection performs well in recovering the hydrocarbons of the sticky layers by reducing the thickness and viscosity. This study, which stresses the need for taking into account the realistic kerogen structure in future studies, sheds light on the exploitation of shale oil resources and, more generally, for mass transport in nanoporous materials.

Microstructure characterization of kerogen in mature shale: Molecular investigation of micropore development

Micropores (<2 nm) are commonly well developed in shale kerogen, which plays an important role for generation and transport of gas in shales. However, the mechanism of micropores development in kerogen structure has not been fully investigated. In this study, we provide an improved methodology to construct 3-D models of kerogen structure, then we construct such molecular models of kerogen for two well-known shales (the Marcellus shale from USA and Shanxi Formation shale from China), and finally we discussed the influences of chemical composition and disorder degree on the formation of micropores in the mature kerogens. Results show that loss of aliphatic structures and the increase in aromatic structures are favorable for the development of micropores. By comparing the kerogen models of M-1 and SX-2, we found that the morphology of micropores in aliphatic structures is more complex than that in aromatic structures. Analyses from 13C Nuclear Magnetic Resonance (NMR) and Raman spectroscopy indicate that apart from chemical compositions, spatial arrangement of structural groups can also affect the development of micropores. For mature kerogen with a large proportion of aromatic rings, disordered aromatic rings are favorable for the development of micropores.

An inorganic origin of the “oil-source” rocks carbon substance

On the basis of an inorganic concept of the petroleum origin, the phase relationships of crystalline kerogens of black shales and liquid oil at the physicochemical conditions of a typical geobarotherm on the Texas Gulf Coast are considered. At the conditions of the carbon dioxide (CO2) high fluid pressure, the process of oil transformation into kerogens of varying degrees of “maturity” (retrograde metamorphism) takes place with decreasing temperature and hydrogen pressure. Kerogen generation in black shale rocks occurs by the sequential transition through metastable equilibria of liquid oil and crystalline kerogens (phase “freezing” of oil). The upward migration of hydrocarbons (HC) of oil fluids, clearly recorded in the processes of oil deposit replenishment in oil fields, shifts the oil ↔ kerogen equilibrium towards the formation of kerogen. In addition, with decreasing of the hydrogen chemical potential as a result of the process of high-temperature carboxylation and low-temperature hydration of oil hydrocarbons, the “mature” and “immature” kerogens are formed, respectively. The phase relationships of crystalline black shale kerogens and liquid oil under hypothetical conditions of high fluid pressure of the HC generated in the regime of geodynamic compression of silicate shells of the Earth in the result of the deep alkaline magmatism development. It is substantiated that a falling of hydrogen pressure in rising HC fluids will lead to the transformation of fluid hydrocarbons into liquid oil, and as the HC fluids rise to the surface, the HC ↔oil ↔ kerogen equilibrium will shift towards the formation of oil and kerogen. It is round that both in the geodynamic regime of compression and in the regime of expansion of the mantle and crust, carboxylation and hydration are the main geochemical pathways for the transformation of oil hydrocarbons into kerogen and, therefore, the most powerful geological mechanism for the black shale formations.

The molecular model of Marcellus shale kerogen: Experimental characterization and structure reconstruction

A realistic three-dimensional (3D) kerogen molecular model adds significant values in petrographical evaluation in shale, especially it is essential to conduct molecular simulation for gas storage and transport behaviors in shale. In this study, the 3D kerogen molecular structure of Marcellus shale was reconstructed based on molecular simulation, and eight experimental techniques, including 13C nuclear magnetic resonance (13C NMR) spectroscopy, Fourier transform infrared spectroscopy (FTIR), X-ray photoelectron spectroscopy (XPS), high-resolution transmission electron microscopy (HRTEM), elemental analysis, helium porosimetry, low-pressure CO2 adsorption, and radial distribution function (RDF) obtained from synchrotron X-ray. The XPS data provides elemental compositions and the contents of functional groups of carbon, oxygen, nitrogen and sulfur on the kerogen surface. FTIR and 13C NMR spectroscopy provide the contents of aliphatic chains and aromatic rings. The two-dimensional (2D) kerogen molecular structure was initially constructed, and the connection of kerogen fragments was verified by comparing the experimental and calculated 13C NMR spectra. Then, fourteen 2D kerogen molecules were used to reconstruct the 3D kerogen molecular structure. Experimental helium density and micropore volume were used to verify the density and micropore structure of the final 3D model. Experimental RDF data were also used to analyze the spatial distribution of the kerogen atoms. The reconstructed 3D kerogen molecular structure of Marcellus shale contains 5936 atoms (C2856H2492N56O532), and the unit cell dimension is 3.755 × 3.755 × 3.755 nm. This study provides a systematic approach to establish a realistic 3D kerogen molecular model by leveraging the advantages of various techniques. The established Marcellus kerogen model lays the foundation for future fluid transport and storage studies.

Molecular characterization of Dachengzi oil shale kerogen by multidimensional solid-state nuclear magnetic resonance spectroscopy

Solid-state nuclear magnetic resonance (SSNMR) techniques of 13C multiple cross polarization (multiCP), 13C multiCP with recoupled dipolar dephasing (multiCP/DD) and two-dimensional (2D) 1H–13C heteronuclear correlation (HETCOR) were used to characterize Dachengzi oil shale kerogen. Specific structural information was obtained from the quantitative multiCP and multiCP/DD spectra. The protonated aromatic signals distribute widely in the aromatic region and account for 24% of the total aromatic signals. The strong methylene peak in multiCP/DD spectrum indicates the long methylene chain structures. The 2D HETCOR spectra show that oxygen atoms play an important role in the connectivities between different groups. The strong peaks at the 1H/13C chemical shifts of 5/131 and 1.5/131 ppm indicate the high abundance of (–O–CH2)-aromatic and alkyl-substituted aromatic moieties. The connectivities were validated by calculating the chemical shifts of a series of relevant molecular models using quantum chemistry methods. The 13C signal assignment was completed and improved with the multidimensional SSNMR spectra. The results from SSNMR are in agreement with the fast pyrolysis study, and the appearance of (–O–CH2)-aromatic moieties indicates that the methylbenzene homologues in the pyrolysis products can originate from the cleavage of the C–O bonds in (–O–CH2)-aromatic moieties in addition to the β-scission reaction of linear alkylbenzene moieties.

Molecular insights into carbon dioxide enhanced multi-component shale gas recovery and its sequestration in realistic kerogen

Understanding the governing processes of CO2 huff-n-puff in shales is essential for enhancing shale gas recovery and CO2 sequestration. However, existing studies have not fully accounted for the chemical composition and geometry of kerogen nanopores and the reality that natural gas is a multi-component mixture. We used grand canonical Monte Carlo (GCMC) simulations to study the competitive adsorption between CO2 and typical hydrocarbon components (CH4, C2H6, and C3H8). We further studied the recovery mechanisms of CO2 huff-n-puff within kerogenic circular nanopores at reservoir conditions. We probed the effects of pressure, pore geometry, and size on gas recovery and CO2 sequestration efficiency. Although pressure drop readily exploits CH4 in the adsorption layer, the recovery due to CO2 injection primarily occurs within the kerogen matrix for pure CH4. Injecting CO2 facilitates the recovery of heavier hydrocarbons, whereas pressure drawdown exhibits better performance for lighter components. CO2 huff-n-puff may serve as a promising method for gas exploitation in circular pores, whereas pressure drop favors the production in kerogen slit. The tremendously different gas adsorption and recovery behavior in distinct pore geometries and compositions necessitate the study using realistic shale kerogen models. Moreover, enlarging the pore size improves the recovery of each component during pressure drawdown but restrains the performance of CO2 injection; meanwhile, the total gas recovery and CO2 sequestration efficiency increase. This study provides a more in-depth understanding of multi-component gas recovery mechanisms within realistic shale kerogen nanopores and sheds light on the CO2 sequestration in shale reservoirs.

Comparison of in-source solid bitumen with migrated solid bitumen from Ediacaran-Cambrian rocks in the Upper Yangtze region, China

In-source solid bitumen was found in some cracks within the calcareous concretion in an overmature (Rbitumen > 3.5%) black shale of the Lower Cambrian Niutitang Formation from Songtao, Guizhou, China. The solid bitumen (grain size >2 cm) concentrated in source rock, which was formed by the transformation of petroleum-like substances that have not been expelled from source rock. This provides a substitute for studying the physical and chemical properties of in-situ solid bitumen, which usually occurs as finely dispersed particles in black shale. On the other hand, Ediacaran-Cambrian carbonate rocks (which serve as reservoir in the area) contain pyrobitumen derived from petroleum that migrated from the black shale of the Niutitang Formation.A comparative petrological and geochemical analysis was conducted on the in-source solid bitumen from the Lower Cambrian Niutitang Formation and the migrated solid bitumen in the Ediacaran-Cambrian carbonate rocks. The in-source solid bitumen displays a relatively homogeneous optical structure with very weak anisotropy and is visibly different from the migrated bitumen in the Ediacaran-Cambrian carbonate reservoir. This migrated bitumen in the reservoir displays strong anisotropy and optical structure similar to that of coke. Considering a strata like the lower Palaeozoic in South China, which has no vitrinite and is highly over mature, the in-source solid bitumen is likely to be the most suitable organic component for measuring the reflectance and subsequently determining the thermal maturity of organic matter.Interestingly, the in-source solid bitumen displays some inheritance of its parent material. The stable carbon isotope ratios are very similar to those of kerogen in the black shales (approximately −34‰ to −33‰), and the distribution pattern of the trace elements and rare earth elements (REEs) is consistent with that of the Niutitang black shales. The distribution patterns of the trace elements and REEs in the migrated bitumen are basically consistent with those of in-source solid bitumen, however, their stable carbon isotope composition is slightly heavier (−33.6‰ to −31.2‰) than that in the source rocks. In other words, as a key link in the chain, the in-source solid bitumen could connect the migrated bitumen in the reservoir with its source rock. This provides direct support for tracing oil and gas sources in the area by using the element geochemical characteristics of migrated solid bitumen in reservoir.

An insight into quartz mineral interactions with kerogen in Green River oil shale

Green River oil shale is an organic-inorganic macromolecular composite system. Identifying the interactions between nanoscale organic kerogen and the inorganic mineral matrix in oil shale is an important step towards the design of technologies for economic and efficient recovery of shale oil. Quartz (SiO2), one of the tectosilicate minerals present in the Green River oil shale, is modeled to determine the interactions with the 3D kerogen model. The molecular dynamics simulation technique is used as the tool for modeling the interactions. Two models with different orientations of quartz mineral and kerogen are built to evaluate the role of mineral orientation on the molecular interactions. The models are simulated at room temperature and pressure (300 K and 1.013 bar). The kerogen-quartz interactions are evaluated with respect to eight kerogen fragments. We observe that different fragments within the 3D Kerogen molecules interact with the quartz depending upon the quartz orientation. In both cases, the unconstrained ammonium (NH4) ions from the adjacent layer of kerogen migrate to the quartz cavities. All the non-interacting kerogen fragments move away from quartz. The nonbonded interactions between kerogen and quartz are generally electrostatic. The presence of quartz mineral also affects the inter-fragment and inter-layer interactions within the kerogen molecule.

Structural assessments of kerogen-rich oil shale from the Central Kongo formation by solid-state 13C nuclear magnetic resonance and thermal processes

Oil produced from the organic matter-rich sedimentary rocks pyrolysis processes represents one of the most promising and available unconventional fossil fuel reserves that can fill the energy deficit in the near future. In the present study, the kerogen-rich oil shale originated from the Central Kongo (CK) in Democratic Republic of the Congo was subject of numerous characterization studies, such as 13C cross polarization/magic angle spinning nuclear magnetic resonance (13C CP/MAS NMR), simultaneous thermogravimetry/differential thermal analysis (TG/DTA) and fast pyrolysis combined with gas chromatography/mass spectrometry (Py-GC/MS). 13C NMR results indicate that the kerogen carbon skeleton is mainly of aliphatics with methylene chains, in agreement with the molar ratio H/C of 1.71. The predominance of aliphatics over aromatics is indicative of an immature type I kerogen. In addition, thermal analysis revealed a single and narrow pyrolysis process of kerogen at temperature below 456 °C, reflecting the immature type I kerogen in CK oil shale. The results of fast Py-GC/MS show that the studied sample is primarily of aliphatic carbons (n-alkane/n-alkene) and formed of short methylene chains with maximum carbon distribution at C15. The minor components of C20 + suggested marine origin of kerogen with an anoxic reductive environment during the diagenesis of the source rock.

A ReaxFF molecular dynamics study on the hydropyrolysis process of Huadian oil shale kerogen

ABSTRACT The product distribution and reaction mechanism in the process of Huadian oil shale kerogen hydropyrolysis were investigated via reactive molecular dynamics (RMD) simulations with a reactive force field (ReaxFF). A large-scale reactive system based on 10 Huadian oil shale kerogen structural models was used to investigate the effect of heating rates on the product distribution. Reactive force field molecular dynamics was used to simulate the hydropyrolysis process of the 10 models at four different heating rates of 20, 40, 60 and 80 K/ps. The simulation results proved the influence of heating rate on the product distributions, intermolecular interactions and elementary reactions in the process of hydropyrolysis. A conclusion was made about the suitable heating rate for producing useful organic gases and the highest yield of shale oil. This work also analysed the distribution of hydropyrolytic gas product and the reaction mechanism of Huadian oil shale hydropyrolysis, which is an intensive study on the mechanism of hydropyrolysis and the different formation paths of the symmetrical isoformers of typical products at the atomic level. These conclusions will be of great significance for the development and utilisation of oil shale mineral resources.

A Technical Analysis of Oil Shale Firing Power Units Retrofitting for Carbon Capture and Storage (CCS)

In Estonia the significant part of power generation is still based on firing oil shale fuel in thermal power plants despite of the growth of the share of the green energy in recent years. Electricity generation is based on power units utilizing different combustion technologies. A significant part still comprises old units with capacity 185-195 MWe commissioned in early 70s of last century. These pulverized combustion (PC) based units utilize oil shale as a fuel and are operating with subcritical steam parameters, characterizing by relatively low efficiency 26 - 30% (net, LHV based). Due to their low performance, operational issues (intensive fouling of heating surfaces), and remarkable environmental impact, these units were decommissioned or retrofitted with boilers implementing circulating fluidized bed combustion (CFBC) technology in 2004-2005. Implementation of CFBC technology for oil shale combustion significantly reduced both operational issues and environmental impact. With some additional modifications in turbine island allowing to increase rated capacity up to 215 MWe and after increasing steam parameters, the net efficiency of up to 37% was achieved. Consequently, the specific CO2 emissions in the range of 0.99 – 1.05 t/MWhe depending on quality of oil-shale used, was achieved. Recently, the new 300 MWe CFBC based power unit was commissioned. It is operating with subcritical steam parameters: live steam temperature 565 °C and pressure 17 MPa. Net efficiency (LHV based) of that unit is 40 % and specific CO2 emissions up to 0.9 t/MWhe in case of firing only oil shale. In this study the technical viability of retrofitting oil shale based power generation units with CC is described. In the analysis two CC methods were considered: post-combustion (assuming conventional amine process) and oxy-fuel combustion. Among other CC technologies these processes are at the present time characterized by higher technical readiness level, can be applied for existing units with minimal modifications and are applicable for oil shale fuel with it specifics. Besides power generation, Estonia has for almost 100 years of experience in production of shale oil through thermal decomposition of oil shale kerogen in retorts. Currently, solid heat carrier (SHC) method is the main method used for producing shale oil. In this method, direct CO2 emission comes from the preparation of SHC by combustion of solid retorting residue (semi-coke). Mainly two combustion methods are presently applied: lift pipe combustion and CFBC which was recently successfully integrated into shale oil production process. The possibility of utilizing CC technologies in shale oil production units and their technical analysis is described in this study.

Structural characterization of Huadian oil shale kerogen by using 13C DP/MAS NMR

Structural characterization of Huadian oil shale kerogen by using 13C DP/MAS NMR

Predicting the components and types of kerogen in shale by combining machine learning with NMR spectra

This study aims to develop a new method that combines machine learning with nuclear magnetic resonance (NMR) spectra to predict the kerogen components and types. Kerogen is the primary hydrocarbon source of shale oil/gas, and nearly half of the hydrocarbons in shale are adsorbed in kerogen. The adsorption and hydrocarbon generation capacity of kerogen is directly related to its types, molecular components, and structures. Fruitful researches studying kerogen at the molecular level have been conducted. Unfortunately, these methods are complicated, time-consuming, and labor-intensive. Our method has the advantages of high-throughput prediction, high accuracy, and time savings compared with the existing methods. Additionally, this method simplifies the operations from repetitive trial and error. This study proposes a solution to convert non-uniform two-dimensional (2D) graph into a uniform one-dimensional (1D) matrix, which makes 2D graph data available for machine learning models. An automatic labeling platform is constructed that annotated over 22,000 groups of organic matter molecules and their NMR spectra. The results show that the carbon, hydrogen, and oxygen element prediction accuracy reach 96.1%, 94.8%, and 81.7%, respectively. In addition, the accuracy of the three kerogen types is approximately 90% in total. These results reflect the excellent performance of the machine learning method. Therefore, our work provides an automated and intelligent prediction and analysis method, which is a powerful and superior tool in kerogen studies at the molecular level.

Effect of the structure and micropore of activated and oxidized black carbon on the sorption and desorption of nonylphenol

Activated, oxidized, and solvent-extracted black carbon samples (BCs) were produced from a shale kerogen at temperatures ranging from 250 to 500 °C by chemical activation regents (KOH, ZnCl2), oxidative regents (H2O2, NaClO), and organic solvents, respectively. Extracted organic matter (EOM) and polycyclic aromatic hydrocarbons (PAHs) were quantified in BCs, and they increased and then decreased with increasing temperature. Sorption and desorption isotherms of nonylphenol (NP) on BCs were compared with those previously reported for phenanthrene (Phen). The desorption hysteresis coefficients of NP were greater than those of Phen, while the adsorption capacities of NP were different from those of Phen. The micropore volume and micropore size were critical factors for the micropore filling mechanism of NP in BCs. The ZnCl2 activation and oxidation treatments were observed to effectively enhance the adsorption of NP and to remove native PAHs from the investigated BCs. But the KOH activation and oxidation treatments were not as efficient as expected. Moreover, the NP desorption hysteresis suggested that a hydrogen bonding and micropore deformation mechanism occurred on the extracted activated BCs. This finding improves our understanding of the sorption and desorption mechanisms of NP from the perspective of the modified BCs and their applications.

Verification of an Explicitly Coupled Thermal-Phase Field-Mechanical Electromagnetic (TPME) Framework by the Method of Manufactured Solutions

An explicitly coupled two-dimensional (2D) multiphysics finite element method (FEM) framework comprised of thermal, phase field, mechanical and electromagnetic (TPME) equations was developed to simulate the conversion of solid kerogen in oil shale to liquid oil through in-situ pyrolysis by radio frequency heating. Radio frequency heating as a method of in-situ pyrolysis represents a tenable enhanced oil recovery method, whereby an applied electrical potential difference across a target oil shale formation is converted to thermal energy, heating the oil shale and causing it to liquify to become liquid oil. A number of in-situ pyrolysis methods are reviewed but the focus of this work is on the verification of the TPME numerical framework to model radio frequency heating as a potential dielectric heating process for enhanced oil recovery. Very few studies exist which describe production from oil shale; furthermore, there are none that specifically address the verification of numerical models describing radio frequency heating. As a result, the Method of Manufactured Solutions (MMS) was used as an analytical verification method of the developed numerical code. Results show that the multiphysics finite element framework was adequately modeled enabling the simulation of kerogen conversion to oil as a part of the analysis of a TPME numerical model.

Three-Dimensional Imaging and Quantification of Gas Storativity in Nanoporous Media via X-rays Computed Tomography

This study provides the engineering science underpinnings for improved characterization and quantification of the interplay of gases with kerogen and minerals in shale. Natural nanoporous media such as shale (i.e., mudstone) often present with low permeability and dual porosity, making them difficult to characterize given the complex structural and chemical features across multiple scales. These structures give nanoporous solids a large surface area for gas to sorb. In oil and gas applications, full understanding of these media and their sorption characteristics are critical for evaluating gas reserves, flow, and storage for enhanced recovery and CO2 sequestration potential. Other applications include CO2 capture from industrial plants, hydrogen storage on sorbent surfaces, and heterogeneous catalysis in ammonia synthesis. Therefore, high-resolution experimental procedures are demanded to better understand the gas–solid behavior. In this study, CT imaging was applied on the sub-millimeter scale to shale samples (Eagle Ford and Wolfcamp) to improve quantitative agreement between CT-derived and pulse decay (mass balance) derived results. Improved CT imaging formulations are presented that better match mass balance results, highlighting the significance of gas sorption in complex nanoporous media. The proposed CT routine implemented on the Eagle Ford sample demonstrated a 17% error reduction (22% to 5%) when compared to the conventional CT procedure. These observations are consistent in the Wolfcamp sample, emphasizing the reliability of this technique for broader implementation of digital adsorption studies in nanoporous geomaterials.