Kerogen Matrix Research Articles

CO2 Adsorption onto Water-Bearing Shale: Insights from Molecular Dynamics and Implications on CO2 Prestorage Fracturing

Summary Hydraulic fracturing coupled with CO2 injection or CO2 prestorage fracturing is a pivotal technique for enhancing shale oil recovery. Besides, geological CO2 storage offers a feasible solution for mitigating global warming. However, after hydraulic fracturing, the shale matrix is in a water-bearing environment. The complex mechanisms associated with the impact of the injected CO2 on shale oil recovery in the water-bearing kerogen matrix remain unclear. In this work, we explored the adsorption mechanism of five representative components of shale oil in water-bearing kerogen through molecular dynamics (MD) simulation, which may provide useful microscopic insights for industrial CO2 prestorage fracturing. Our research revealed that CO2 could decrease the adsorption capacity of n-octane (OCT; saturated alkanes), thiophene (THIOP), and naphthalene rings (NAPs; aromatic hydrocarbons) onto the kerogen, which consequently improved the recovery of these components. Conversely, the adsorption capacity of pyridine (PYR) and n-octadecanoic acid (STE) was boosted upon the CO2 introduction. This could be attributed to the fact that after CO2 injection, both the quantity and the lifetime of hydrogen bonds between these two components and kerogen were increased. The interaction energy between these two components and the water-bearing kerogen also increased, which was in-line with the changes in molecular van der Waals (vdW) surface electrostatic potential (ESP) and the spatial distribution function (SDF). In addition, to reveal the deeper mechanism, the interactions between the specific sites or functional groups on the kerogen and the different components are analyzed to predict the intermolecular charge transfer. It is believed this work may offer useful insights into the design and implementation of CO2 prestorage fracturing for improved shale oil recovery and CO2 geological storage.

Molecular insights into dual competitive modes of CH4/CO2 in shale nanocomposites: Implications for CO2 sequestration and enhanced gas recovery in deep shale reservoirs

CO2 enhanced shale gas recovery has significant potential for improving the recovery rate of adsorbed gas and facilitating the geological sequestration of CO2. Nevertheless, the feasibility and microscopic mechanisms of CO2 enhanced gas recovery in deep shale gas reservoirs remain to be elucidated. In this study, a quartz-kerogen slit model was constructed to represent the shale composite nanopores of deep shale reservoirs. Utilizing the grand canonical Monte Carlo and molecular dynamics methods, the adsorption and diffusion behavior of CH4, CO2 and their mixtures was investigated under high-temperature and high-pressure conditions representative of deep shale reservoirs. The influences of temperature, pressure and aperture size were analyzed. The microscopic mechanisms governing the CH4/CO2 competitive adsorption in deep shale nanopores were uncovered by considering the competitive interactions between different rock constituents and quantifying the various gas storage states. The results show that the adsorption capacity of CO2 is greater than that of CH4 under the deep shale reservoir conditions. The replacement efficiency of CH4 by CO2 is higher in small shale pores. High temperature has a more significant negative impact on the adsorption of CO2 compared to that of CH4. Compared to mid-deep shale reservoirs, the nanopores of deep shale reservoirs have a higher proportion of free CH4/CO2 states. Quartz exhibits greater affinity for CH4/CO2 than kerogen, but kerogen possesses a larger specific surface area, resulting in a higher adsorption capacity per unit volume. The hierarchy of CH4/CO2 diffusion capacity in various storage states is as follows: dissolved gas in the kerogen matrix < adsorbed gas on the quartz surface < adsorbed gas on the kerogen surface < free gas in the pore center. This study improves the understanding of CO2 enhanced gas recovery in deep shale gas reservoirs.

Molecular dynamics of CH4 adsorption and diffusion characteristics through different geometric shale kerogen nanopores

In shale, pore structure plays an extremely significant effect on CH4 storage and transportation in a reservoir, especially for the reservoir involving large amounts of extremely tiny nanopore and variance of microstructure. In this study, three molecular dynamics models for different types of kerogen nanopores such as serration type, arc type and great-wall type are established, validated and implemented to assess the impact of pore structure on CH4 adsorption and diffusion behaviors in kerogen matrix and nanopore at temperature 320 ∼ 380 K, pressure 5 ∼ 20 MPa and pore size 3 ∼ 5 nm. The simulation results demonstrate that the CH4 density in the bulk of serration-type, arc-type and great-wall-type pores is 1.6, 1.3 and 1.9 higher than that inside kerogen molecules. Increasing temperature can weaken the adsorption capacity of kerogen, but the serration-type pore is the most sensitive to temperature. Regardless of the pore type, increasing pressure can significantly enhance the adsorption capacity of kerogen which is almost unaffected by pore size, whereas the CH4 diffusion coefficient increases with pore size. Furthermore, the great-wall-type pore can adsorb more CH4 molecules due to its smooth surface, followed by change in the arc-type and serration-type pores in turn. Among these types of pores, the CH4 diffusion coefficient is the most insensitive to the size of arc-type pore. Hence, the influences of kerogen pore structure under different conditions of temperature, pressure and pore size are quantified in this work to improve a comprehensive understanding of CH4 adsorption and diffusion behaviors in shale, thereby contributing to high-efficient and sustainable development of shale gas reservoirs.

Changes in Kerogen and Mineral Matrix Characteristics of Rocks of Bazhenov Deposits during Laboratory Modelling of Hydrothermal Processes

Changes in Kerogen and Mineral Matrix Characteristics of Rocks of Bazhenov Deposits during Laboratory Modelling of Hydrothermal Processes

Microscopic Characterization of Deformation Behavior during Kerogen Evolution: Effects of Maturity and Skeleton Moisture Content.

The CH4 storage and seepage capacity of shale kerogen are the main controlling factors of the natural gas production rate, and the porosity and permeability of kerogen are greatly affected by kerogen deformation. Therefore, the study of the deformation rule and CH4 adsorption characteristics of kerogen at different maturities and skeleton moisture contents has an important impact on the proper understanding of the development potential of shale gas reservoirs. In this paper, kerogen maturity (II-A, II-B, II-C, and II-D) and skeleton moisture content (0.0, 0.6, 1.2, 1.8, and 2.4 wt %) were considered. The deformation of kerogen, the adsorption of CH4 after deformation, and the quadratic deformation induced by CH4 were studied by using Grand Canonical Monte Carlo (GCMC) and molecular dynamics (MD). The results show that the kerogen volume strain increases with increasing skeleton moisture content, following the order II-A < II-B < II-C < II-D for the same moisture content. The density of the kerogen matrix decreases, and porosity increases with rising moisture content. The void fraction of immature kerogen decreases with increasing water content, while the opposite is true for postmature kerogen. The presence of skeleton moisture decreases the CH4 adsorption capacity of immature kerogen and increases the CH4 adsorption capacity of postmature kerogen. The chemical structure of immature kerogen is relatively soft, making its volume more affected by CH4 adsorption compared with postmature kerogen. In the same water environment, postmature kerogen has greater CH4 storage, diffusion, and seepage capacity compared to those of immature kerogen, suggesting that reservoirs with high organic matter maturity should be prioritized for development.

Molecular simulation of the competitive adsorption of methane and carbon dioxide in the matrix and slit model of shale kerogen and the influence of water

Carbon dioxide enhanced shale gas recovery (CO2-EGR) technology is of great significance for shale gas extraction and carbon dioxide storage in subsurface, which involves the competitive adsorption in shale nanopores. Adsorption comparisons between the kerogen matrix and slit and between the pure gas and gas mixture are conducted in this study. Kerogen matrix and slit models are built with the type II-A kerogen macromolecules and adsorptions of CH4 and CO2 are modelled. It is seen: 1) The gas absolute adsorption increases with its molar fraction while decreases with temperature. The Langmuir pressure for CO2 decreases while that for CH4 increases with their molar fractions. The adsorption selectivity of CO2 over CH4 decreases with the increase in pressure and the CO2 fraction, while it is higher in the matrix than that in the slit. Water significantly reduces the gas adsorption especially for matrix. 2) CO2 has high affinity to the Sulfur and Nitrogen functional groups, while CH4 molecules mainly adsorb on the Sulfur, Nitrogen and Carbon functional groups, While water are strongly bound to the Oxygen functional groups with water cluster formed at high contents. 3) Lower interaction energies are shown in the matrix compared with the slit due to the adsorption superposition, which results in gases preferentially adsorbed in the matrix then on the slit surface in the kerogen slit model. The water interaction energy is lowest due to the hydrogen bond, while the interaction energy of CO2 is much smaller than that of CH4 indicating its adsorption advantage.

Thermal effects of organic porous media on absorption and desorption behaviors of carbon dioxide

As a result of global warming, people are increasingly concerned about greenhouse gas emissions, particularly carbon dioxide (CO2). Many countries have been promoting carbon capture, storage (CCS) projects in order to alleviate climate degradation and achieve net zero carbon emissions. To study the thermal effects of organic porous media on CO2 absorption and desorption, molecular dynamics coupled with Monte Carlo (MDMC) were used in this study. A part of the CO2 molecules will be trapped within kerogen matrix due to its complex porous structure. The affinity of kerogen to CO2 facilitates CO2′s adsorption within the kerogen porous media, resulting in a heterogeneous distribution of CO2. The kerogen forms high potential energy peaks and low potential energy wells in the matrix, which provide preferred adsorption sites for CO2 in the porous space. The low stress state of CO2 also indicates that it prefers adsorption in the matrix as CO2 performs a lower potential energy state in the kerogen matrix than in the bulk phase. This study examines different thermal effects of kerogen, and results indicate that increasing CO2 thermal motion facilitates its absorption, while a high temperature matrix promotes CO2 desorption. Adsorbed layer provides resistance for CO2′s diffusion behaviors. The free energy of CO2′s diffusion is analyzed in relation to its mechanism, revealing that irregular thermal motion causes uncertainty in the adsorption capacity.

Giant Effect of CO2 Injection on Multiphase Fluid Adsorption and Shale Gas Production: Evidence from Molecular Dynamics.

Carbon dioxide (CO2) injection in unconventional gas-bearing shale reservoirs is a promising method for enhancing methane recovery efficiency and mitigating greenhouse gas emissions. The majority of methane is adsorbed within the micropores and nanopores (≤50 nm) of shale, which possess extensive surface areas and abundant adsorption sites for the sequestration system. To comprehensively discover the underlying mechanism of enhanced gas recovery (EGR) through CO2 injection, molecular dynamics (MD) provides a promising way for establishing the shale models to address the multiphase, multicomponent fluid flow behaviors in shale nanopores. This study proposes an innovative method for building a more practical shale matrix model that approaches natural underground environments. The grand canonical Monte Carlo (GCMC) method elucidates gas adsorption and sequestration processes in shale gas reservoirs under various subsurface conditions. The findings reveal that previously overlooked pore slits have a significant impact on both gas adsorption and recovery efficiency. Based on the simulation comparisons of absolute and excess uptakes inside the kerogen matrix and the shale slits, it demonstrates that nanopores within the kerogen matrix dominate the gas adsorption while slits dominate the gas storage. Regarding multiphase, multicomponent fluid flow in shale nanopores, moisture negatively influences gas adsorption and carbon storage while promoting methane recovery efficiency by CO2 injection. Additionally, saline solution and ethane further impede gas adsorption while facilitating displacement. Overall, this work elucidates the substantial effect of CO2 injection on fluid transport in shale formations and advances the comprehensive understanding of microscopic gas flow and recovery mechanisms with atomic precision for low-carbon energy development.

Mechanisms of CO2-rich industrial waste gas enhanced shale oil recovery in kerogen slit based on adsorption behavior, gas flooding and surfactant synergy study

Enhanced oil recovery (EOR) by injection of CO2-rich industrial waste gas has been proposed as an energy-efficient and environmentally friendly method for shale oil reservoirs, in which the waste gas can be utilized and sequestered to reduce greenhouse gas emissions. In this work, the adsorption behaviors of shale oil and waste gas components in kerogen slits and the effects of gas flooding on EOR were investigated using molecular dynamics (MD) method, which can provide technical guide for shale oil development. In terms of the adsorption behaviors, an intensity decrease of oil adsorption is observed in kerogen slits after the injection of the waste gas components. Desorption of shale oil during injection of SO2 and CO2 is more pronounced in shallow reservoirs, whereas it is more evident for NO and N2 in deep reservoirs. The desorption efficiency can be 10.91 % for pure CO2 injection and 9.09 % for NO injection at a depth of 1000 m, and the relative stability ratios of CO2 and NO sequestration are 77.09 % and 76.06 %, respectively. For gas flooding, the existence of pressure difference provides favorable conditions for gas molecules to pass through the oil zone, and waste gas can be more effective than pure CO2 as driving gas. For the waste gas injection, the percentage of CO2 retained in the kerogen nanopores is much higher than that of pure CO2 injection, suggesting that more CO2 molecules can enter into kerogen matrix to take part in the displacement process. Furthermore, the effect of surfactants on oil desorption and displacement was also investigated and the interaction energy of the surfactant/oil/gas system was calculated and analyzed, finding that addition of the oil-soluble surfactants can be beneficial to shale oil displacement. This work can provide a comprehensive evaluation of the feasibility of CO2-rich industrial waste gas application for EOR, which is of great significance in the effective production of shale oil and the sequestration of waste gas in shale reservoirs.

Molecular insights into the carbon dioxide sequestration in kerogen: An accelerated algorithm coupling molecular dynamics simulations and Monte Carlo methods

Carbon capture and storage (CCS) technology has been applied successfully in recent decades to reduce carbon emissions and alleviate global warming. In this regard, shale reservoirs present tremendous potential for carbon dioxide (CO2) sequestration as they have a large number of nanopores. An accelerated algorithm coupling molecular dynamics (MD) and Monte Carlo (MC) methods (MDMC) were employed in this work to study the sequestration behavior of CO2 in shale organic porous media. The MDMC method is used to analyze the spatial states of CO2, and the results are in good agreement with MD’s results, and MDMC is thousands of times faster compared to the classical MD. With regard to the kerogen matrix, its properties, such as the pore size distribution (PSD), pore volume, and surface area, are determined to describe its different compression states and the effects of CO2 absorption on it. The potential energy distribution and potential of mean force are analyzed to verify the spatial distribution of CO2 molecules. The heterogeneity of the pore structure resulted in heterogeneous distributions of CO2 molecules in kerogen porous media. Moreover, strong compression of the matrix reduces the number of large pores, and the PSD is mainly between 0 and 15 Å. Despite the high interaction force of the kerogen matrix, the high-potential-energy region induced by the kerogen skeleton also contributes to the formation of low-energy regions that encourage the entry of CO2. An increase in temperature facilitates the absorption process, allowing CO2 molecules to enter the isolated pores with stronger thermal motion.

A study on the structures and primary reaction products of kerogens in Longkou oil shale with different densities through supercritical ethanolysis

The difference in the density of oil shale significantly affects the structural characteristics of the kerogen, which brings the change in the pyrolysis behavior, thus leading to different retorting oil yields. The primary reaction (the cleavage of weak covalent bonds into free radicals) in the pyrolysis of oil shale greatly affects the retorting oil yield and quality. In this work, the structural characteristics and primary reaction products of the kerogens in Longkou oil shale (LKOS) with three different densities (<1.3, 1.4 − 1.5, 1.8 − 1.9 g/cm3) were investigated by supercritical ethanolysis, 13C nuclear magnetic resonance (13C NMR) and Fourier transform infrared spectroscopy (FTIR). The weak covalent bonds in the kerogens were broken by ethanolysis at 350 °C to obtain small molecular substances (SMSs) with the carbon conversions of 28 %, 47 % and 54 %, respectively. The SMSs can be divided into aliphatic acid esters, aromatics, alkanes and N-containing organic compounds (NCCs). Among the SMSs, the relative contents of the aliphatic acid esters, whose aliphatic chain lengths distribute in C3-C23, C1-C24 and C1-C28, are the highest. The aromatics are mainly monocyclic, and the NCCs mainly exist as amines. The possible pathways for these ethanolysis products were proposed. The 13C NMR and FTIR analyses of the kerogens and their ethanolysis residues show that the aliphaticity (fal) and average methylene chain length (Cn) increase, while the aromaticity (fa) and average aromatic cluster size (Xb) decrease with the increasing oil shale density. After ethanolysis, the value of fa gradually increases, while that of fal and Cn decrease. Furthermore, the contents of C=O and O-C=O decrease, while that of O-C-O and C-OH increase. The results suggest that the SMSs are connected to the kerogen matrix by weak covalent bonds. The cleavage of C=O, O-C=O and C-O bonds dominates the early stage of the oil shale pyrolysis. During the pyrolysis of oil shale, these weak covalent bonds are first broken and the above SMSs are the most primary reaction products and then undergo the second reactions to yield oil and gas.

Окисление керогена горючих сланцев перманганатом калия в щелочной среде

We carried out the analytical oxidation of kerogen samples from oil shales of Ordovician kukersite from the Baltic region, Domanik shales from Timan-Pechora and Upper Jurassic oil shales of the Kashpir deposit by potassium permanganate in an alkaline medium. We performed a single-stage oxidation with 3.5 % solution of potassium permanganate, followed by analysis of trimethylsilyl derivatives of carboxylic acids using chromatography-mass spectrometry, and multi-stage oxidation by 0.5 % solution of potassium permanganate and analysis of oxidation products using IR spectroscopy. Some n-alkyl structures are peripherally associated with the kerogen matrix in the kerogen of Domanik and Jurassic shales, while in the structure of kukersite kerogen, n-alkyl structures are mainly connecting links for larger fragments. Milder, in case of a multi-stage process, oxidation results in formation of large fragments of kerogen, generally repeating its carbon structure, but more oxidized.

Molecular simulation of methane/ethane mixture adsorption behavior in shale nanopore systems with micropores and mesopores

Shale formation has a broad pore size distribution with both micropores (<2 nm) and mesopores (2–50 nm) in the kerogen matrix in addition to the macropores and fractures. Methane and ethane are two primary hydrocarbon species of shale gas, and the competitive sorption behavior in kerogen micropores and mesopores is not well understood. In this work, grand canonical Monte Carlo (GCMC) was used to study the sorption behavior of methane, ethane, and their binary mixtures (from 1:9 to 9:1) in kerogen nanopore systems with micropores and mesopores at 327 K and pressures ranging from 1 to 50 MPa. Three zones (Zone I: free gas, Zone II: adsorbed gas, and Zone III: absorbed gas) were defined to describe the sorption in micropores and mesopores. The results show different selectivity characteristics of ethane over methane for three different zones. The mass densities of gas molecules in different zones were obtained, which can be used for gas-in-place estimation. The calculated sorption isotherms of shale samples show reasonably good agreement with previous experiments. We show that the Langmuir model can be used to describe the absolute sorption isotherms of pure methane and ethane. For binary mixtures, the absolute sorption of individual gases predicted by the multicomponent Langmuir (ML) model shows a deviation from GCMC simulation results. However, with two correction coefficients, the modified ML models match the absolute sorption amount from the GCMC very well. Finally, a micropore-mesopore (MM) model was derived for the excess-absolute sorption relationship, which significantly improves the prediction accuracy of the absolute sorption in shale gas systems. This research highlights the importance of using kerogen nanopore systems with both micropores and mesopores.

Methane adsorption of nanocomposite shale in the presence of water: Insights from molecular simulations

Accurately predicting gas adsorption in shale gas is essential for estimating production capacity and optimizing extraction processes. However, the complex nature of shale reservoirs (heterogeneous structure, organic–inorganic nanopores, moisture content, etc.) presents significant challenges in understanding the mechanism of methane adsorption. To address these challenges, a nanocomposite shale model incorporating kerogen and illite with slit pore widths of 1 nm, 2 nm, and 4 nm is created. The hybrid grand canonical Monte Carlo (GCMC) and molecular dynamics (MD) simulations are used to investigate methane adsorption in rigid and flexible shale models (kerogen matrix and clay mineral) at three different temperatures, several pressures, and various moisture contents. The simulation results show that the methane density distributions revealed asymmetrical behavior due to the heterogeneous surfaces. Factors such as kerogen flexibility, pore width, moisture content, temperature, and pressure were found to significantly influence fluid behavior. A comparative analysis between the rigid and flexible shale models, considering varying pore widths under both dry and moist conditions, revealed noteworthy differences. Kerogen's flexibility led to increased surface roughness and decreased adsorbed density. Conversely, the presence of water reduced methane adsorption sites in illite, resulting in diverse and complex behaviors dependent on pore widths in the shale model. Finally, the results suggest that using adsorbed volume instead of classical adsorption models is recommended for converting excess adsorption into absolute adsorption. This alternative approach can provide more accurate predictions and enhance the understanding of adsorption in shale gas systems.

Characterization of free and bound bitumen fractions in a thermal maturation shale sequence. Part 2: Structural evolution of kerogen and bitumen during shale oil generation, expulsion and retention

Knowledge of the formation and enrichment mechanisms of shale oil is essential to understanding its mobility and hence a critical aspect for evaluating shale oil exploration and production. Semi-open hydrous pyrolysis experiments were performed on an organic-rich shale to simulate the petroleum generation and expulsion processes of Type II kerogen. The residual rocks matured to different levels (Easy%Ro = 0.50–1.37) were thereafter treated with stepwise extraction to obtain free and bound bitumen fractions. This study focuses on the structural characteristics of kerogen, bitumen fractions, and expelled oil during shale maturation using Fourier transform infrared (FTIR) spectroscopy and quantitative flash pyrolysis–gas chromatography (Py–GC). The results reveal that the composition of expelled oils changes with increasing maturity, whereas an opposite trend in structural composition was observed for kerogen after significant oil expulsion from the shale occurs, beginning at Easy%Ro = 0.79. A notable change is that aliphatic carbon chains of kerogen became shorter and/or more branched while those of expelled oil appeared to be more aliphatic with longer carbon chains at this stage. However, the overall compositional structures of shale bitumen fractions, both in free and bound phases, show only slight changes within the oil window stage. The bound bitumen is generally enriched in oxygenated functional groups as compared to free bitumen, indicating that the bound bitumen is related mainly to the interaction between the mineral surface and the bitumen–kerogen matrix. During maturation, the cracking (including defunctionalization) and condensation of kerogen and bitumen fractions, as well as a compositional fractionation due to oil expulsion, are likely to be the main factors influencing the opposite trend observed in structural compositions between kerogen and expelled oil. These processes may control the quality and content of expelled oil and bitumen in a petroleum system. Nevertheless, kerogen, expelled oil and bitumen show a gradual trend of decarboxylation during shale maturation in general.

Molecular Simulation of Methane Adsorption in Deep Shale Nanopores: Effect of Rock Constituents and Water

The molecular models of nanopores for major rock constituents in deep shale were constructed. The microscopic adsorption behavior of methane was simulated by coupling the grand canonical Monte Carlo and Molecular Dynamics methods and the effect of rock constituents was discussed. Based on the illite and kerogen nanopore models, the discrepancies in microscopic water distribution characteristics were elucidated, the effects of water on methane adsorption and its underlying mechanisms were revealed, and the competitive adsorption characteristics between water and methane were elaborated. The results show a similar trend in the microscopic distribution of methane between different shale rock constituents. Illite and kerogen slit pores have no significant difference in methane adsorption capacity. The adsorption capacity per unit mass of kerogen is greater than that of illite due to the smaller molar mass of the kerogen skeleton and its large intermolecular porosity. Illite has a greater affinity for water than methane. With increasing water content, water molecules preferentially occupy the high-energy adsorption sites and then overspread the entire pore walls to form water adsorption layers. Methane molecules are adsorbed on the water layers, and methane adsorption has little effect on water adsorption. Kerogen is characterized as mix-wetting. Water molecules are preferentially adsorbed on polar functional groups and gather around to form water clusters. In kerogen with high water content, methane adsorption can facilitate water cluster fusion and suppress water spreading along pore walls. In addition to adsorption, some water molecules dissolve in the kerogen matrix.

Prediction of Adsorption and Diffusion of Shale Gas in Composite Pores Consisting of Kaolinite and Kerogen using Molecular Simulation.

Natural gas production from shale formations is one of the most recent and fast growing developments in the oil and gas industry. The accurate prediction of the adsorption and transport of shale gas is essential for estimating shale gas production capacity and improving existing extractions. To realistically represent heterogeneous shale formations, a composite pore model was built from a kaolinite slit mesopore hosting a kerogen matrix. Moreover, empty slabs (2, 3, and 4 nm) were added between the kerogen matrix and siloxane surface of kaolinite. Using Grand-Canonical Monte Carlo (GCMC) and molecular dynamics (MD) simulations, the adsorption and diffusion of pure methane, pure ethane, and a shale gas mixture were computed at various high pressures (100, 150, and 250 atm) and temperature of 298.15 K. The addition of an inner slit pore was found to significantly increase the excess adsorption of methane, as a pure component and in the shale gas mixture. The saturation of the composite pore with methane was observed to be at a higher pressure compared to ethane. The excess adsorption of carbon dioxide was not largely affected by pressure, and the local number density profile showed its strong affinity to kerogen micropores and the hydroxylated gibbsite surface under all conditions and pore widths. Lateral diffusion coefficients were found to increase with increasing the width of the empty slab inside the composite pore. Statistical errors of diffusion coefficients were found to be large for the case of shale gas components present at low composition. A larger composite pore configuration was created to investigate the diffusion of methane in different regions of the composite pore. The calculated diffusion coefficients and mean residence times were found to be indicative of the different adsorption mechanisms occurring inside the pore.

Molecular Dynamics Simulation of Adsorption and Absorption Behavior of Shale Oil in Realistic Kerogen Slits

Exploring the occurrence of shale oil is of guiding significance to the exploration and recovery of shale oil. However, most studies focus on adsorption and neglect absorption or study it independently, which weakens the understanding of the coupling relationship between adsorption and absorption and the occurrence mechanism of shale oil in kerogen and its associated pores. Based on molecular dynamics (MD) simulation, the kerogen matrix with a smooth surface is constructed, and the general amber force field is adopted to calculate the adsorption and absorption of shale oil in a type II kerogen slit, and the influences of temperature, pressure, and pore diameter on the occurrence of shale oil are also discussed. Molecules absorbed in the kerogen matrix are mainly retained in the free space formed by the accumulation of aliphatic carbon. The effects of temperature on the distribution of shale oil in adsorption and absorption are opposite. High temperature improves the desorption of molecules from the adsorption sites and causes a lower adsorption and greater absorption. In contrast, pressure and pore diameter only slightly influence the distribution of shale oil. Unexpectedly, the result under aqueous conditions shows that the shale oil was absorbed quickly before the formation of water clusters. Once the water clusters are formed due to the strong hydrogen bonding and adsorbed near the N-, S-, and O-containing groups on the kerogen surface, the matrix gaps are blocked due to the size exclusion, and the absorption is suppressed. Additionally, we established the evolution of the ratio of free-adsorbed–absorbed oil at different temperatures and pressures, which provides a new idea and a new method for detecting the occurrence and mobility evaluation of shale oil under reservoir conditions.

ГЕОХІМІЧНІ ТРИГЕРИ ВИКИДІВ ВУГІЛЛЯ ТА ГАЗУ ЗА РЕЗУЛЬТАТАМИ ТЕРМОЛІТИЧНОГО АНАЛІЗУ ROCK-EVAL

Purpose. Investigation of the conditions for the occurrence of coal and gas outbursts from a geochemical point of view. Methodology. The paper examines and analyses the results of determining bituminous and hydrogen indices using the Rock-Eval thermolytic analysis method on safe and dangerous areas of coal seams in terms of coal and gas outbursts. Results. It was established that on safe mining seams, coal samples are within the oil window, where microcracks in the coal mass may still contain films of sorbed bituminous components (liquid hydrocarbons), which counteract the accumulation of energy of elastic deformations and the localization of gas accumulation. However, the transition from the area of liquid hydrocarbon generation to the gas window leads to a sharp increase in the volume of generated hydrocarbon gases, mainly due to the cracking of liquid hydrocarbons, that is, the emergence of geochemical triggers for the localization of coal and gas outbursts during coal mining. Scientific novelty. The new experimentally determined values of bituminous and hydrogen indices for coal seams of the Donetsk basin, and their comparison with the results within safe and dangerous mining seams, demonstrate the fact that all the studied coal samples from outburst-prone areas geometrically lie in the area of the gas window, starting from the moment of cracking of already formed liquid hydrocarbons and subsequent generation of dry hydrocarbon gases (mainly methane) due to the thermal degradation of higher carbon compounds first, and then low carbon compounds (wet hydrocarbon gases) and direct generation from the kerogen matrix. Practical significance. Established geochemical criteria that determine the conditions for the occurrence of gas-dynamic phenomena - outbursts of coal and gas during coal mining. Key words: coal and gas outbursts, bitumen index, hydrogen index, microcracks, hydrocarbon generation, gas window.

An integrated multi-scale model for CO2 transport and storage in shale reservoirs

Shale reservoirs have gradually been recognized as promising potential candidates for CO2 geological storage due to their wide geographic distribution and enormous storage potential. CO2 sequestration in shale is a complex multi-scale process with spatial sizes ranging from nano-scale to kilometer-scale. In this study, an integrated multi-scale model, considering CO2 adsorption, dissolution, slip flow, and diffusion, is developed to describe CO2 transport and storage in shale reservoirs with a multi-stage fractured horizontal well. The computationally efficient semi-analytical solution of the multi-scale model is obtained via Laplace transformation and Pedrosa’s substitution. Based on the established model, a workflow for evaluating the CO2 storage capacity of shale reservoirs is proposed. Taking the Longmaxi shale reservoir in the Sichuan Basin as an application case, the results show that the storage capacity can reach up to 29.97 × 108 m3 at a high constrained injection pressure. In addition, sensitivity analysis suggests that CO2 storage capacity is strongly influenced by the adsorption index of clay minerals, kerogen content, solubility coefficient, and inter-porosity flow coefficient of kerogen and inorganic matrix. Most reservoir parameters have negligible effects on storage capacity at low injection pressures, yet significant effects at high injection pressures. More specifically, the CO2 storage capacity can increase by 6.8 folds when the constrained injection pressure is increased from 5.5 to 8.5 MPa. The findings obtained in this study further expand the description of CO2 transport in the shale formation, laying the foundation for highly efficient CO2 sequestration in shale reservoirs.