Understanding gas-enhanced methane recovery in graphene nanoslits via molecular simulations

Shale gas and coalbed methane are energy sources that mainly consist of methane stored in an adsorbed state in the pores of the organic-rich rock and coal seams. In this study, the graphene nanoslit model is employed to model the nanometer slit pores in shale and coal. Grand canonical Monte Carlo and molecular dynamics modeling methods are used to investigate the mechanisms of adsorption and displacement of methane in graphene-based nanoslit pores. It is found that as the width of the slit pore increases, the adsorption amount of gas molecules increases, and the number density profile of adsorbed methane molecules alters from monolayer to multilayer adsorption. The minimum slit pore width at which methane molecules can penetrate the slit pore is determined to be 0.7 nm. Moreover, it is demonstrated that by lowering the temperature, the adsorption rate of the methane increases since the adsorption is an exothermic process. Enhancing methane recovery was investigated by the injection of gases such as CO2 and N2 to displace the adsorbed methane. The comparison of adsorption isotherms of gas molecules provides the following order in terms of the amount of adsorption, CO2 > CH4 > N2, for the same slit pore width and the same temperature and pressure conditions.Cited as: Bekeshov, D., Ashimov, S., Wang, Y., Wang, L. Understanding gas-enhanced methane recovery in graphene nanoslits via molecular simulations. Capillarity, 2023, 6(1): 1-12. https://doi.org/10.46690/capi.2023.01.0

Supercritical carbon dioxide enhanced natural gas recovery from kerogen micropores

As the global energy demand increases, a sustainable and environmentally friendly methane (CH4) extraction technique must be developed to assist in the transition off of fossil fuels. In recent years, supercritical carbon dioxide (CO2) has been poised as a candidate for enhanced gas recovery (EGR) from CH4-rich source rocks, potentially with the reservoir serving as a carbon sink for CO2. However, the underlying molecular-scale mechanisms of CO2-EGR processes are still poorly understood. Using constant chemical potential molecular dynamics (CMD), this study investigates the CH4 recovery process via supercritical CO2 injection into immature (Type I-A) and overmature (Type II-D) kerogens in real-time and at reservoir conditions (365 K and 275 bar). A pseudo-second order (PSO) rate law was used to quantify the adsorption and desorption kinetics of CO2 and CH4. The kinetics of simultaneous adsorption/desorption are rapid in immature kerogen due to better connected pore volume facilitating fluid diffusion, whereas in overmature kerogen, the structural heterogeneity hinders fluid diffusion. Estimated second order kinetic rate coefficients reveal that CO2 adsorption and CH4 desorption in Type I-A are about two times and an order of magnitude faster, respectively, compared to those of in Type II-D. Furthermore, overmature Type II-D kerogen contains inaccessible micropores which prevent full recovery of CH4. For every CH4 molecule replaced, at least two and six CO2 molecules are adsorbed in Type-II-D and Type I-A kerogens, respectively. Overall, this study shows that CO2 injection can achieve 90 % and 65 % CH4 recovery in Type I-A and Type II-D kerogens, respectively

Doctor of Philosophy

dissertationShale plays have revolutionized oil and gas production in the United States. In the last decade, many shale gas and liquid plays have been explored and developed in the US and elsewhere. Prospective shales consist of a complex organic component known as kerogen which is a precursor to oil and gas. Shales have pores with dimensions in the range of nanometers in the organic and inorganic constituents. The presence of organic matter and nanometer pores affect the thermodynamic properties of fluids in these rocks. A hypothesis has been proposed and proved through modeling and experiments to account for the influence of kerogen on thermodynamic properties of hydrocarbon fluids. Kerogen preferentially absorbs hydrocarbons and subsequently swells in volume. This splits oil in liquid-rich shale plays into two phases â€" a retained phase and a free phase, both of which remain in equilibrium. The retained and free phases together form in-situ oil; equilibrium of in-situ oil with gas was studied to investigate the effect of kerogen on saturation pressures of oils in shales. Results indicate a bubble point suppression between ~ 4150 kPa and ~ 16350 kPa from an original value of 28025 kPa for produced Eagle Ford oil. This is attributed to the presence of kerogen. This suppression depends on the type and level of maturity of the kerogen. The confinement of hydrocarbon fluids in the nanometer pores present in shales also changes the behavior of these fluids. Pore-wall â€" fluid interactions become dominant at the nano-scale and conventional equations of state(EOS) fail to include the effect of these confined state interactions. Gibbs Ensemble Monte Carlo simulations were performed in this work to investigate the thermodynamic properties of pure components and fluid mixtures in confined pores. Suppression of critical densities and critical temperature of confined decane, decaneâ€"methane, and decaneâ€"carbon-dioxide was observed from the bulk properties. This leads to changes in the saturation pressures of fluids in the confined state. Experiments on kerogen isolated from a shale and oil were performed with a differential scanning calorimeter and a thermogravimetric analyzer. These experiments complimented the modeling results and thus, verified the effect of kerogen and hydrocarbon fluid confinement observed in the models. Finally, for gas-rich shales, a carbon dioxide injection as the most effective method was evaluated for enhanced production of gas sorbed in kerogen. Molecular modeling indicates that the carbon dioxide can replace methane sorbed in the kerogen and the kerogen matrix decreases in volume during this process. The carbon dioxide shows higher retention in the kerogen than methane, indicating the viability of enhanced gas recovery and carbon dioxide sequestration

A New Multicontinuum Model for Compositional Gas Transport in a Deformable Shale Formation

A new multi-continuum compositional gas simulation model is presented for deformable organic-rich source rocks. The model describes the advective and diffusive mass balance equations for each hydrocarbon components in the organic and inorganic continua. It accounts for the presence of dispersed kerogen with sorbed-gas corrected dynamic porosity. Maxwell-Stefan theory is used to predict the pressure- and composition-dependence of molecular diffusion. The coupled nonlinear system of equations for the multi-component gas transport and geomechanics are discretized using the control volume finite element method, and linearized using the Newton-Raphson iteration scheme. Any fractures in the reservoir domain is modeled using the discrete fracture model. The simulation is based on a new multi-scale conceptual flow model, in which the kerogen is considered to be discontinuous and dispersed in the inorganic matrix at reservoir simulation scale. Scanning Electron Microscopy images, as well as the expected slow transport in the nanoporous organic matrix in comparison to the advective transport in the organic matrix form the basis for this new numerical model. A simple mass balance equation is introduced to enable kerogen to transfer reservoir fluids to the inorganic matrix that is collocated in the same grid-block. The advective-diffusive transport takes place between neighboring grid blocks only in the inorganic matrix. The simulation results indicate that the multi-scale nature of the rock is important and should not be ignored because this could result in an overestimation of the contribution of kerogen to production. Although the adsorbed fluid can contribute significantly to storage in these source rocks, its contribution to production could be severely limited by the lack of kerogen continuity at the reservoir scale and by a low degree of coupling between the organic and inorganic pores. The contribution of Maxwell-Stefan diffusion to the overall transport in organic-rich source rocks appears to be more significant at lower values of matrix permeability, and as the permeability decreases in response to pressure decline during production. The coupled geomechanics and flow simulation results indicate that production of reservoir fluids can induce higher compressive stresses that can in turn reduce fracture conductivity, and lead to faster production decline

Structure-Transport Properties of Fluids in Narrow Pores: Relevance to Shale Gas

Shale gas has attracted significant attention in the past decade. Pioneered by the USA since the 1940s, the production of shale gas in Europe is still in its early stage and has not been attempted in Africa. Oil and gas production from shale is technologically difficult, in part due to very small sizes of pores in shale formations and poor pore connectivity. Experimental characterization has revealed heterogeneous nature of shale, and a network of connected pores is actually not visible at the resolution of tens of nanometers. Poor pore connectivity in shale rocks is responsible for its low permeability. To produce oil and gas from shale formations, more advanced technology such as horizontal drilling and hydraulic fracturing is required. However, recovery is still very low as oil rate drops rapidly. To improve production, enhanced oil recovery (EOR) is proposed. In order to design advanced EOR technologies, fluid–fluid and fluid–rock interactions in nanopores are crucial. This thesis seeks to better understand the behaviour of fluids confined in narrow pores. The techniques of choice are based on molecular dynamics simulations, conducted at the atomic resolution. The pores considered are of slit-shaped geometry and of dimensions as small as 1–2.2 nm carved out of silica, muscovite, MgO, alumina and graphite. The fluids simulated include hydrocarbons, such as n-butane and n-octane, as well as a few other fluids, including H2O, CO2, H2S and N2. The results show, in qualitative agreement with literature observations, that confinement affects the structure of aqueous H2S due to perturbation of water coordination around H2S. It was also found that injection of H2S or CO2 could help to displace hydrocarbon from the confining pore surfaces, and that the performance of the injected gas depends on the chemistry of the surface. CO2 and H2S could displace hydrocarbons from inorganic surfaces but not from organic surface. Analysis of the interaction energy between confined fluids and the pore surfaces shows that the results depend on gas–surface and hydrocarbon–surface interactions. At the conditions simulated, CO2 or H2S suppressed hydrocarbon mobility due to pore crowding. These findings could contribute to designing advanced EOR strategies for achieving both improved hydrocarbon production, acid gas sequestration as well as natural gas sweetening

Coal-Seq III Consortium: Advancing the Science of CO2 Sequestration in Coal Seam and Gas Shale Reservoirs

AbstractCoal-Seq III is a 3-year public-private consortium primarily sponsored by the U.S. Department of Energy (DOE) and performed by Advanced Resources International (ARI) in partnership with Southern Illinois University (SIU), Oklahoma State University (OSU), and Higgs-Palmer Technologies. The consortium has a primary objective to advance scientifically-based simulation capabilities for CO2 storage in coalbed methane and gas shale reservoirs in the presence of multi- component gases and other fluids in order to improve how current simulation tools model the effects of high pressure CO2 on the integrity and swelling/shrinkage of the coal matrix and its permeability as well as proper algorithms for the adsorptive capability of wet coals.To accomplish this goal, coal samples from various U.S. basins are being used in the laboratory to study the potential existence of a change in mechanical properties for the coal (weakening/failure) under high-pressure CO2 injection and depletion. Laboratory experiments also include the investigation of coal shrinkage (during production) and swelling (during injection) under field replicated conditions. In addition; new improved adsorption models are being developed to realistically simulate sequestration in wet coal and gas shale reservoirs. Based on the laboratory and theoretical results, three new geochemical and geo-mechanical modules will be developed. Finally, the feasibility of storing CO2 in shale reservoirs will be studied using actual datasets, leveraging the basic science work developed by this effort.To do so, the Coal-Seq III Consortium work will calibrate the accuracy of these modules with data from large-scale field studies, such as the DOE sponsored CO2 injection demonstration within the San Juan basin's Fruitland coal, and incorporate these modules into an advanced, coupled simulation model. The end result will be improved tools that are informed by Coal-Seq laboratory efforts and that have been tuned with field injection data. This paper will describe the efforts to date in meeting these research objectives

Understanding Gas and Energy Storage in Geological Formations with Molecular Simulations

Methane (CH4), the cleanest burning fossil fuel, has the potential to solve the energy crisis owing to the growing population and geopolitical tensions. Whilst highly calorific, realising its potential requires efficient storage solutions, which are safe and less energy-intensive during production and transportation. On the other hand, carbon dioxide (CO2), the by-product of human activities, exacerbates global heating driving climate change. CH4 is abundant in natural systems, in the form of gas hydrate and trapped gas within geological formations. The primary aim of this project was to learn how Nature could store such a large quantity of CH4 and how we can potentially extract and replace the in-place CH4 with atmospheric CO2, thereby reducing greenhouse gas emissions. We studied this question by applying molecular dynamics (MD) and Monte Carlo (MC) simulation techniques. Such techniques allow us to understand the behaviour of confined fluids, i.e., within the micropores of silica and kerogen matrices. Our simulations showed that CH4 hydrate in confinement could form under milder conditions than required, deviating from the typical methane-water phase diagram, complementing experimental observations. This research can contribute to artificial gas hydrate production via porous materials for gas storage. Besides that, the creation of 3D kerogen models via simulated annealing has enabled us to understand how maturity level affects the structural heterogeneity of the matrices and, ultimately CH4 diffusion. Immature and overmature kerogen types were identified to having fast CH4 diffusion. Subsequently, our proof-of-concept study demonstrated the feasibility of recovering CH4 via supercritical CO2 injection into kerogens. Insights from our study also explained why full recovery of CH4 is impossible. A pseudo-second-order rate law can predict the kinetics of such a process and the replacement quantity. A higher CO2 input required than the CH4 recovered highlights the possibility of achieving a net-zero future via geological CO2 sequestration

Factors Governing the Enhancement of Hydrocarbon Recovery via H2S and/or CO2 Injection: Insights from a Molecular Dynamics Study in Dry Nanopores

Although enhanced oil recovery (EOR) is often achieved by CO2 injection, the use of acid gases has also been attempted, for example, in oil fields in west Canada. To design EOR technologies effectively, it would be beneficial to quantify the molecular mechanisms responsible for enhanced recovery under various conditions. We report here the molecular dynamics simulation results that probe the potential of recovering n-butane confined in silica, muscovite, and magnesium oxide nanopores, all proxies for subsurface materials. The three model solid substrates allow us to identify different molecular mechanisms that control confined fluid behavior and to identify the conditions at which different acid gas formulations are promising. The acid gases considered are CO2, H2S, and their mixtures. For comparison, in some cases, we consider the presence of inert gases such as N2. In all cases, the nanopores are dry. The recovery is quantified in terms of the amount of n-butane displaced from the pore surface as a function of the amount of gases present in the pores. The results show that the gas performance depends on the chemistry of the confining substrate. Whereas CO2 is more effective at displacing n-butane from the protonated silica pore surface, H2S is more effective in muscovite, and both gases show similar performance in MgO. Analysis of the interaction energies between the confined fluid molecules and the surface demonstrates that the performance depends on the gas interaction with the surface, which suggests experimental approaches that could be used to formulate the gas mixtures for EOR applications. The structure of the gas films in contact with the solid substrates is also quantified as well as the self-diffusion coefficient of the fluid species in confinement. The results could contribute to designing strategies for achieving both improved hydrocarbon production and acid gas sequestration

Molecular Simulation Study Of Enhanced Oil Recovery Methods In Tight Formation

The Middle Bakken Formation of the Williston Basin is a typical tight formation with the predicted primary oil recovery of less than 10%, which results in large amounts of oil remaining in the reservoir. Therefore, an effective enhanced oil recovery (EOR) method for recovering the residual oil is crucially important. To obtain the microscopic EOR mechanisms, molecular simulation methods including Monte Carlo (MC) simulations and molecular dynamics (MD) simulations were applied to study the various EOR methods, such as CO2 injection, hydrocarbon gas injection, and nanofluid flooding. A series of molecular models, including bulk systems, interfacial systems, and nanoconfined systems, were built to evaluate the potentials of the injected fluids to improve oil recovery.CO2 injection is a successful EOR technology that is being widely applied in North American oil fields. Studies have suggested CO2-based EOR is technically possible in the Middle Bakken Formation. The swelling of the crude oil/CO2 system plays a crucial role in the CO2 flooding process. Therefore, a better understanding of the effect of CO2 on crude oil swelling and viscosity reduction is critical for a successful CO2 EOR project. In this dissertation, a series of n-alkane/CO2 systems were studied by performing configurational-bias Monte Carlo (CBMC) simulations and MD simulations. The effects of alkyl chain length, pressure, and temperature on the CO2 solubility and the swelling factor were investigated. The solubility of CO2 and the swelling factor of CO2 saturated n-alkane are positively correlated to the pressure, while negatively correlated to the alkyl chain length and temperature. With more CO2 dissolved, the interaction energy between n-alkane molecules becomes less negative, which indicates the swelling of the n-alkane/CO2 system. N-alkanes with longer alkyl chain have more negative intermolecular interaction energy, and thus have a smaller swelling factor after saturating with CO2. With the increase of the CO2 mole fraction, the viscosity of the n-alkane/CO2 system is reduced. N-alkanes with longer alkyl chains have a larger viscosity reduction with increasing amounts of dissolved CO2. Besides CO2, hydrocarbon gases, like methane and ethane, can also mobilize the residual oil and enhance oil recovery. The gas solubility, volume swelling factor, oil diffusion coefficient, minimum miscibility pressure (MMP), and the oil extraction from nanoslits were then studied to compare the efficiency of different gases in the EOR process. Based on the Bakken oil composition, a molecular model of the crude oil containing different types of alkanes was built. MD simulations were carried out to study the interfacial interactions between the Bakken crude oil and the injected gases and the oil extraction from the calcite nanoslits. At various pressures and reservoir temperature, density profiles were plotted to show the distributions of different components, and the solubility of gases in crude oil was calculated. The simulation results show that all three gases hold great potential in further improving oil recovery. At constant temperature and pressure, ethane holds the highest solubility in crude oil and can induce the most pronounced oil swelling. Meanwhile, ethane can achieve the lowest MMP and the most significant oil diffusion coefficient. Without the effect of nano-confinement, ethane is most effective in mobilizing crude oil. However, CO2 is more effective in extracting oil from the nanoslits. Recent studies have also reported various types of nanoparticles (NPs) for improving oil recovery either alone or in combination with surfactants. The mechanisms of surface-modified silica (SiO2) NPs in improving oil recovery were investigated. Interfacial tensions (IFTs) of octane (C8H18)/water systems in the presence of different NPs were calculated. Quartz nanochannels were constructed to study the effect of NPs on oil flow through nanopores in rocks. Both water-wet and oil-wet surfaces were considered. Simulation results indicate that IFT reduction depends strongly on the distribution and the interfacial concentration of NPs. Surface-modified NPs with both hydrophilic and hydrophobic functional groups can reduce the IFT between oil and water. However, the IFT reduction is not significant in terms of EOR application. The alkanes/water/NPs transportation in confined nanochannels shows that the initial rock wettability affects the water flooding performance and the final oil recovery. The surface-modified NPs hold a higher capacity in detaching oil droplets from the oil-wet mineral surface regardless of their abilities to change interfacial tension. Surface modification is crucial to improve the surface properties of SiO2 NPs. The strong interactions between NPs and oil/rock lead to oil detachment and incremental oil recovery. The chemical composition of the functional groups and the surface coverage of the hydrophilic/hydrophobic functional groups should be carefully tuned to achieve the highest oil recovery rate. Molecular simulation study provides better insight into the interactions between oil components and injected fluids or mineral surfaces at the molecular level. The effect of injected fluids on the properties of the oil can be clearly explained. The application of molecular simulation methods could play an important role in interpreting experimental results and providing guidance for practical oil recovery processes in the Bakken Formation

Evaluation Of CO2 Enhanced Oil Recovery In Unconventional Reservoirs

The recent advances in horizontal drilling and hydraulic fracturing have enabled a profitable oil and gas recovery from unconventional geologic plays. The Bakken is one of the largest oil-bearing tight formations in North America, with an estimated original oil in place of 600 billion barrels; however, only a small fraction (7% to 12%) of this oil is recoverable using currently available technologies.CO2 injection can be an effective technique to enhance oil recovery from unconventional reservoirs. It can assist with extracting residual oil and overcoming injectivity problems in tight formations. Previous CO2 enhanced oil recovery (EOR) pilot tests performed in the Bakken Formation indicated that cyclic CO2 injection might be a promising technique for enhanced oil recovery; however, no clear consensus has been reached, and the reported results have revealed that CO2 EOR mechanisms in unconventional reservoirs are still poorly understood. This study addresses the knowledge gap related to CO2 EOR in unconventional reservoirs, investigates the side effects of CO2 injection, and compares the EOR performance of different gases to determine the optimum EOR scheme in tight formations. We investigated and analyzed the effects of different parameters on CO2 performance using samples from the Middle Bakken member and Three Forks Formation. The factors studied include CO2 Huff-n-Puff (HnP) injection parameters, sample size, water presence within the fractures, and the volume of CO2 in contact with the rock matrix during the HnP experiments. The injected CO2 can interact with the in-situ reservoir fluids and rock minerals, which can impact and alter several reservoir attributes. The potential changes in rock wettability, pore size distribution, and effective porosity before and after exposure to CO2 were evaluated. The results indicate that CO2 can alter wettability and increase the hydrophilicity of the rock. The nuclear magnetic resonance spectroscopy technique was used to determine fluid distribution before and after CO2 injection. The results confirm that carbonic acid can dissolve portions of the dolomite, calcite, and feldspar in the rock and create new micro- and nanopores. We compared the EOR performance of CO2 and hydrocarbon gases to determine the most effective gases. Then we introduced a novel gas EOR scheme to boost oil mobilization and achieve higher recovery factors