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

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

Adsorption of Carbon Dioxide, Methane, and Nitrogen Gases onto ZIF Compounds with Zinc, Cobalt, and Zinc/Cobalt Metal Centers

ZIF-8, Co-ZIF-8, and Zn/Co-ZIF-8 are utilized in adsorbing nitrogen (N2), methane (CH4), and carbon dioxide (CO2) gases at temperatures between 25 and 55 C and pressures up to 1 MPa. Equilibrium adsorption isotherms and adsorption kinetics are studied. The dual-site Langmuir equation is employed to correlate the nonisothermal adsorption equilibrium behavior. Generally, N2 showed the lowest equilibrium adsorption quantity on the three samples, whereas CO2 showed the highest equilibrium adsorption capacity. Amid the ZIF samples, the biggest adsorption quantities of N2 and CH4 were onto Zn/Co-ZIF-8, whereas the highest adsorption quantity of CO2 was on ZIF-8. The isosteric heats of adsorbing these gases on ZIF-8, Co-ZIF-8, and Zn/Co-ZIF-8 were examined. Moreover, the overall mass transfer coefficients of adsorption at different temperatures were investigated.Scopu

Investigating the factors impacting the success of immiscible carbon dioxide injection in unconventional shale reservoirs: An experimental study

Unconventional shale reservoirs are currently gaining significant interest due to the huge hydrocarbon volumes that they bear. Enhanced oil recovery (EOR) techniques have been suggested to increase recovery from shale reservoirs. One of the most promising EOR methods is gas EOR (GEOR), most notably carbon dioxide (CO2). Not only can CO2 increase oil recovery by interacting with the oil and the shale, but it has also been shown to adsorb to the shale rock and thus is effective in both EOR applications and also carbon storage purposes. This research aims to experimentally investigate several of the interactions that may impact CO2 injection in shale reservoirs in hopes of defining and quantifying the factors impacting these interactions and how these factors can contribute to an improvement in oil recovery from these reservoirs. This research begins by undergoing a review and data analysis on immiscible CO2 injection to investigate its injection methods, mechanisms, governing equations, and factors influencing its applicability. Following this, a mathematical simulation was undergone to investigate the different CO2 flow regimes that could occur during CO2 injection in shale reservoirs. The interaction of the CO2 with the shale rock via adsorption was investigated by undergoing several adsorption experiments. The CO2 interaction with the oil was also investigated by undergoing oil swelling which is considered the main mechanism by which oil recovery can be increased during immiscible CO2 injection, and asphaltene experiments to investigate the factors impacting these two interactions. Finally, cyclic CO2 injection was performed to determine the oil recovery potential of GEOR from shale reservoirs --Abstract, page iv

Shale wettability: Data sets, challenges, and outlook

© 2021 American Chemical Society. The wetting characteristics of shale rocks at representative subsurface conditions remain an area of active debate. A precise characterization of shale wettability is essential for enhanced oil and gas recovery, containment security during CO2 geo-storage, and flow back efficiency during hydraulic fracturing. While several methods were utilized in the literature to evaluate shale wettability (e.g., contact angle measurements, spontaneous imbibition method,and NMR method), we here review the recently published data sets on shale contact angle measurements. The objectives of this review are to (a) develop a repository of the recent shale wettability data sets using contact angle measurements at high pressure and temperature (HPHT) conditions, (b) explore the factors influencing shale wettability, (c) identify potential limitations associated with contact angle methods, and (d) provide a research outlook for this area. On the basis of the data reviewed here, we conclude the following: (1) Shale/oil/brine systems demonstrate water-wet to strongly oil-wet wetting behaviors. (2) Shale/CO2/brine systems are usually weakly water-wet to CO2-wet. (3) Shale/CH4/brine systems are weakly water-wet. The key contributing factors that underpin this high shale wettability variability include, but are not limited to, operating pressure and temperature conditions, total organic content (TOC), mineral matter, and thermal maturity conditions. Thus, this review provides a succinct analysis of the shale wettability contact angle data sets and affords an overview of the current state of the art technology and possible future developments in this area to enhance the understanding of shale wettability

Diffusion Behavior of Methane in 3D Kerogen Models

As global energy demand increases, natural gas recovery from source rocks is attracting considerable attention since recent development in shale extraction techniques has made the recovery process economically viable. Kerogens are thought to play an important role in gas recovery; however, the interactions between trapped shale gas and kerogens remain poorly understood due to the complex, heterogeneous microporous structure of kerogens. This study examines the diffusive behavior of methane molecules in kerogen matrices of different types (Type I, II, and II) and maturity levels (A to D for Type II kerogens) on a molecular scale. Models of each kerogen type were developed using simulated annealing. We employed grand canonical Monte Carlo simulations to predict the methane loadings of the kerogen models and then used equilibrium molecular dynamics simulations to compute the mean square displacement of methane molecules within the kerogen matrices under reservoir-relevant conditions, that is, 365 K and 275 bar. Our results show that methane self-diffusivity exhibits some degree of anisotropy in all kerogen types examined here except for Type I-A kerogens, where diffusion is the fastest and isotropic diffusion is observed. Self-diffusivity appears to correlate positively with pore volume for Type II kerogens, where an increase in diffusivity is observed with increasing maturity. Swelling of the kerogen matrix up to a 3% volume change is also observed upon methane adsorption. The findings contribute to a better understanding of hydrocarbon transport mechanisms in shale and may lead to further development of extraction techniques, fracturing fluids, and recovery predictions

Molecular Dynamics Simulation Study of Carbon Dioxide - Hydrocarbon Mixtures Under Confinement

Reducing carbon dioxide emissions in an attempt to control global warming is a critical issue being addressed at global level today. One method of regulating the amount of COv2 in the atmosphere is by re-injecting COv2 into reservoirs, thus in turn also improving the overall recovery of oil and gas. This is an enhanced oil/gas recovery technique which has received a lot of attention in industry. In this work, a study of the phenomena that allows for improved hydrocarbon recovery using COv2 injection into reservoir pores is presented. Additionally, an attempt to understand the effect of mixture density, concentration, temperature, moisture and the pore material on such systems will be discussed. Furthermore, the ways in which diffusivity of fluid behaves at the center of the pore as well as towards the pore walls is explored in detail in this work. All systems that have been simulated represent a canonical ensemble. Hence, at any given time, the number of molecules, the volume of the pore, and the temperature remain the same as specified at the beginning of a simulation. The work utilizes a methodology developed by Franco et al. to calculate the perpendicular self-diffusion co-efficient by obtaining the residence time from the integration of the survival probability. The methodology further allows for the calculation of the local self-diffusion coefficient in areas of interest as opposed to the global self-diffusion coefficient obtained from the commonly used Einstein relation. Results indicate that all studied characteristics of a system have a significant effect on the mobility and the configuration of the fluid within pore. Furthermore, these characteristics have a greater pronounced effect of the diffusivity at the center of the pore and a lesser effect in the region towards the wall. Further calculating the parallel self-diffusion coefficient of the fluid in the same systems analyzed in this work will provide even greater insight on the behavior of hydrocarbons within nanopores, in the presence of COv2

An Enhanced Carbon Capture and Storage Process (e-CCS) Applied to Shallow Reservoirs Using Nanofluids Based on Nitrogen-Rich Carbon Nanospheres

The authors thank the Universidad Nacional de Colombia, the University of Granada, and the University of Lorraine-Institut Jean Lamour for their logistical and financial support. The authors also thank Philippe Gadonneix and Saray Perez–Robles for their technical support in the experimental tests.The implementation of carbon capture and storage process (CCS) has been unsuccessful to date, mainly due to the technical issues and high costs associated with two main stages: (1) CO2 separation from flue gas and (2) CO2 injection in deep geological deposits, more than 300 m, where CO2 is in supercritical conditions. This study proposes, for the first time, an enhanced CCS process (e-CCS), in which the stage of CO2 separation is removed and the flue gas is injected directly in shallow reservoirs located at less than 300 m, where the adsorptive phenomena control CO2 storage. Nitrogen-rich carbon nanospheres were used as modifying agents of the reservoir porous texture to improve both the CO2 adsorption capacity and selectivity. For this purpose, sandstone was impregnated with a nanofluid and CO2 adsorption was evaluated at different pressures (atmospheric pressure and from 3 × 10−3 MPa to 3.0 MPa) and temperatures (0, 25, and 50 °C). As a main result, a mass fraction of only 20% of nanomaterials increased both the surface area and the molecular interactions, so that the increase of adsorption capacity at shallow reservoir conditions (50 °C and 3.0 MPa) was more than 677 times (from 0.00125 to 0.9 mmol g−1).The authors thank COLCIENCIAS for financing the doctoral studies of Elizabeth Rodriguez Acevedo through the call 647-2014. The authors thank COLCIENCIAS, Agencia Nacional de Hidrocarburos-ANH provided by agreement 272-2017 for the support provided and Universidad Nacional de Colombia for the support provided in the agreement 272-2017. The authors thank to Spanish Ministry of Science, Innovation and Universities, FEDER funds, contract number RTI2018-099224-B-I00. The authors also thank to ERASMUS+ program (agreement F NANCY43) and ENLAZAMUNDOS-SAPIENCIA for the support of academic internships. French authors acknowledge FEDER funds, through TALiSMAN project, for the financial support

Molecular Simulation of Transport and Storage in Shale

Over the past few years, the production of shale hydrocarbons has seen a renewed interest both in science and industry. Indeed, these fluids today constitute a significant energy and economic stake to compensate for the scarcity of so-called conventional resources. This is due to the fact that shale gases and oils represent enormous potential resources and are present all over the world. In shales, hydrocarbons are generally contained in microporous organic nanopores: kerogen. The kerogen is both the source rock of hydrocarbons and their reservoir. In shales, the extreme confinement of fluids in organic matter, high pressure-high temperature thermodynamic condition as well as very low permeabilities, imply a significant change in the state of the fluids (present in adsorbed form) and its transport mechanisms (diffusive). In this dissertation, we studied the physical properties (adsorption, transport) of kerogen as well as its carbon dioxide sequestration potential. The characteristic scales in the shales are of the order of a nanometer, which is accessible today by molecular simulations on supercomputers or even personal computers. Therefore, we have chosen to study kerogens by molecular simulation. The objective of this work is to stimulate a fundamental research on this subject in order to understand and model the mechanisms encountered in the shales and thus to respond responsibly and sustainably to the energy challenges of the years to come. Initially, the simplified kerogen models (carbon nanochannels and nanocapillaries) are developed and transport and storage of different gases are studied. This part of research is beneficial for developing analytical models of gas transport in organic nanopores. Furthermore, kerogens with different maturities were generated by molecular dynamics simulations under thermodynamic conditions typical of this type of reservoir (338 K, 20 MPa). In our simulations, the microporous network of kerogen is created by the inclusion of dummy particles, which were deleted after kerogen structure is created. The average density of the structures of organic matter created is in agreement with the experimental results obtained on such kerogens. The density is very strongly correlated with the stacking of the kerogenic polyaromatic clusters which is a strong indicator of the coherence of the simulated structures with respect to the experiments. We were interested in the transport of hydrocarbons in the kerogen and have identified the mechanisms of mass transfer through kerogens and we have been able to predict their evolution as a function of thermodynamic conditions (composition and pressure). Based on the results, it is demonstrated that the higher the maturity of kerogen, the higher is its adsorption capability. This is in agreement with experimental results of adsorption on kerogen. Furthermore, it is shown that the permeation of fluid through the kerogen membrane can be described by a diffusive formalism. The heavier alkanes have smaller diffusion coefficients and as a result, they may trap inside organic nanopores. Multicomponent diffusion of mixtures containing water and carbon dioxide is investigated and it is shown that water and carbon dioxide have lowest diffusion coefficients compared with hydrocarbons. The diffusion coefficients of hydrocarbons increases in presence of water due to higher adsorption capability of water and filling the adsorption sites. Adsorption molecular simulations of binary mixture of methane and carbon dioxide demonstrate that carbon dioxide have higher adsorption capabilities than methane. Binary mixture diffusion simulation of these two components also shows that carbon dioxide molecules have lower diffusion coefficients compared with methane. Therefore, injection of carbon dioxide into organic matter causes the methane molecules desorb and produce.;In conclusion, this dissertation work consisted of developing models, algorithms, and methodologies to predict the properties and mechanisms governing the behavior of the organic matter contained in the shales by employing molecular simulations . This work aims to improve our understanding of this type of resources