Doctor of Philosophy

dissertationUnconventional resources (shale resources) have played a key role in increasing oil production in the past decade in the U.S. The sizes of pores in shales storing the oil are believed to be on the order of nanometers. It is believed that the fluids present in such small nanometer-scale pores have different properties compared to properties measured in the bulk. Fluid bubble points at given temperatures in the nano-sized pores are affected by the influence of pore walls in the vicinity of the fluid molecules. Bubble points affect the proportion of liquid or gas extracted from a given well and, thus, impact the economic viability of oil production. Hence, an accurate measure of a bubble point is important. Most studies on phase behavior of confined fluid systems have focused on modeling pore size dependence upon critical properties with no direct experimental evidence. In this work, direct bubble point measurements of hydrocarbon mixtures in several porous materials are provided. Two different synthesized mesoporous silica materials, SBA-15 and SBA-16, having nano-sized pores of about 4 nm, were used. Mesoporous monoliths with only nano-sized pores and no macro pores were also synthesized using a unique procedure developed in this study. Finally, to see the industrial application of this work, the Niobrara rock which is from one of the famous shale reservoirs in the U.S. was used. These porous materials were characterized well by X-ray diffraction (XRD), nitrogen adsorption/desorption isotherm (BET), transmission electron microscopy (TEM), and scanning electron microscopy (SEM). Binary mixtures of hydrocarbons (decane-methane, octane-methane) with 90:10 mole ratio were employed. The phase diagrams of those hydrocarbon mixtures were modeled using a commercial thermodynamic simulator. The bubble point of bulk (no porous medium) mixtures of decane-methane and octane-methane, and the bubble point with porous materials (SBA-15, SBA-16, and mesoporous monoliths) were measured experimentally. Experiments were also performed with micrometer-sized sand particles and the Niobrara rock. The bubble point results of the hydrocarbon mixtures in the porous materials and the Niobrara rock were lower than those in the bulk, while the bubble points with sand were closer to those with bulk measurements. Differential Scanning Calorimetry (DSC) and Thermogravimetric Analysis (TGA) results showed that the boiling points of pure decane and decane saturated in the monolith were different, possibly due to the confinement effect. This study shows the phase behavior of hydrocarbons in a confined system is different from that in the bulk system

Modelling The Underground Hydrogen Storage : A State-of-the-Art Review of Fundamental Approaches and Findings

The authors gratefully acknowledge the funding support by the Net Zero Technology Centre (NZTC), UK and the industrial sponsors to accomplish this work under the Hydrogen Innovation Grant scheme.Peer reviewedPublisher PD

Petrophysical modeling and simulation study of geological CO₂ sequestration

textGlobal warming and greenhouse gas (GHG) emissions have recently become the significant focus of engineering research. The geological sequestration of greenhouse gases such as carbon dioxide (CO₂) is one approach that has been proposed to reduce the greenhouse gas emissions and slow down global warming. Geological sequestration involves the injection of produced CO₂ into subsurface formations and trapping the gas through many geological mechanisms, such as structural trapping, capillary trapping, dissolution, and mineralization. While some progress in our understanding of fluid flow in porous media has been made, many petrophysical phenomena, such as multi-phase flow, capillarity, geochemical reactions, geomechanical effect, etc., that occur during geological CO₂ sequestration remain inadequately studied and pose a challenge for continued study. It is critical to continue to research on these important issues. Numerical simulators are essential tools to develop a better understanding of the geologic characteristics of brine reservoirs and to build support for future CO₂ storage projects. Modeling CO₂ injection requires the implementation of multiphase flow model and an Equation of State (EOS) module to compute the dissolution of CO₂ in brine and vice versa. In this study, we used the Integrated Parallel Accurate Reservoir Simulator (IPARS) developed at the Center for Subsurface Modeling at The University of Texas at Austin to model the injection process and storage of CO₂ in saline aquifers. We developed and implemented new petrophysical models in IPARS, and applied these models to study the process of CO₂ sequestration. The research presented in this dissertation is divided into three parts. The first part of the dissertation discusses petrophysical and computational models for the mechanical, geological, petrophysical phenomena occurring during CO₂ injection and sequestration. The effectiveness of CO₂ storage in saline aquifers is governed by the interplay of capillary, viscous, and buoyancy forces. Recent experimental data reveals the impact of pressure, temperature, and salinity on interfacial tension (IFT) between CO₂ and brine. The dependence of CO₂-brine relative permeability and capillary pressure on IFT is also clearly evident in published experimental results. Improved understanding of the mechanisms that control the migration and trapping of CO₂ in the subsurface is crucial to design future storage projects for long-term, safe containment. We have developed numerical models for CO₂ trapping and migration in aquifers, including a compositional flow model, a relative permeability model, a capillary model, an interfacial tension model, and others. The heterogeneities in porosity and permeability are also coupled to the petrophysical models. We have developed and implemented a general relative permeability model that combines the effects of pressure gradient, buoyancy, and capillary pressure in a compositional and parallel simulator. The significance of IFT variations on CO₂ migration and trapping is assessed. The variation of residual saturation is modeled based on interfacial tension and trapping number, and a hysteretic trapping model is also presented. The second part of this dissertation is a model validation and sensitivity study using coreflood simulation data derived from laboratory study. The motivation of this study is to gain confidence in the results of the numerical simulator by validating the models and the numerical accuracies using laboratory and field pilot scale results. Published steady state, core-scale CO₂/brine displacement results were selected as a reference basis for our numerical study. High-resolution compositional simulations of brine displacement with supercritical CO₂ are presented using IPARS. A three-dimensional (3D) numerical model of the Berea sandstone core was constructed using heterogeneous permeability and porosity distributions based on geostatistical data. The measured capillary pressure curve was scaled using the Leverett J-function to include local heterogeneity in the sub-core scale. Simulation results indicate that accurate representation of capillary pressure at sub-core scales is critical. Water drying and the shift in relative permeability had a significant impact on the final CO₂ distribution along the core. This study provided insights into the role of heterogeneity in the final CO₂ distribution, where a slight variation in porosity gives rise to a large variation in the CO₂ saturation distribution. The third part of this study is a simulation study using IPARS for Cranfield pilot CO₂ sequestration field test, conducted by the Bureau of Economic Geology (BEG) at The University of Texas at Austin. In this CO₂ sequestration project, a total of approximately 2.5 million tons supercritical CO₂ was injected into a deep saline aquifer about ~10000 ft deep over 2 years, beginning December 1st 2009. In this chapter, we use the simulation capabilities of IPARS to numerically model the CO₂ injection process in Cranfield. We conducted a corresponding history-matching study and got good agreement with field observation. Extensive sensitivity studies were also conducted for CO₂ trapping, fluid phase behavior, relative permeability, wettability, gravity and buoyancy, and capillary effects on sequestration. Simulation results are consistent with the observed CO₂ breakthrough time at the first observation well. Numerical results are also consistent with bottomhole injection flowing pressure for the first 350 days before the rate increase. The abnormal pressure response with rate increase on day 350 indicates possible geomechanical issues, which can be represented in simulation using an induced fracture near the injection well. The recorded injection well bottomhole pressure data were successfully matched after modeling the fracture in the simulation model. Results also illustrate the importance of using accurate trapping models to predict CO₂ immobilization behavior. The impact of CO₂/brine relative permeability curves and trapping model on bottom-hole injection pressure is also demonstrated.Petroleum and Geosystems Engineerin

Interfacial properties of reservoir fluids and carbon dioxide with impurities

Interfacial tension measurements of the binary systems (N2 + H2O), (Ar + H2O), and (H2 + H2O), and ternary systems (CO2 + N2 + H2O), (CO2 + Ar + H2O) and (CO2 + H2 + H2O), are reported at pressures of (0.5 to 50.0) MPa, and temperatures of (298.15 to 473.15) K. The design of a custom-built Interfacial Properties Rig was detailed. The pendant drop method was used. The expanded uncertainties at 95 % confidence are 0.05 K for temperature; 0.07 MPa for pressure; 0.019•γ for interfacial tension in the (N2 + H2O) system; 0.016•γ for interfacial tension in the (Ar + H2O) system; 0.017•γ for interfacial tension in the (H2 + H2O) system; 0.032•γ for interfacial tension in the (CO2 + N2 + H2O) system; 0.018•γ for interfacial tension in the (CO2 + Ar + H2O) system; and 0.017•γ for interfacial tension in the (CO2 + H2 + H2O) system. The interfacial tensions of all systems were found to decrease with increasing pressure. The use of SGT + SAFT-VR Mie to model interfacial tensions of the binary and ternary systems was reported, for systems involving CO2, N2 and Ar. The binary systems (N2 + H2O) and (Ar + H2O), and ternary systems (CO2 + N2 + H2O) and (CO2 + Ar + H2O), were modelled with average absolute relative deviations of 1.5 %, 1.8 %, 3.6 % and 7.9 % respectively. For the (CO2 + Ar + H2O) system, the agreement is satisfactory at the higher temperatures, but differs significantly at the lower temperatures. Contact angles of (CO2 + brine) and (CO2 + N2 + brine) systems on calcite surfaces have also been measured, at 333 K and 7 pressures, from (2 to 50) MPa, for a 1 mol•kg-1 NaHCO3 brine solution, using the static method on captive bubbles.Open Acces

Hydrogen Diffusion through Caprock: On the Effect of Hydrocarbon Gas Composition

Hydrogen storage in a depleted gas reservoir can be one of the most reliable options for seasonal, long-term, and large gigatons volume storage. Hydrogen loss due to molecular diffusion into caprock is one of the concerns of underground hydrogen storage in depleted gas reservoirs. This study evaluated the significance of hydrogen loss into caprock resulting from molecular diffusion. In particular, the impacts of pre-defused hydrocarbons inside the caprock were investigated. For this purpose, one-dimensional models were created, and a numerical simulation of hydrogen diffusion was performed using ECLIPSE 300. Moreover, chemical potential was used as the driving force for hydrogen diffusion and the model was assumed to have some previously diffused hydrocarbon components in the caprock. The fluid properties were modelled using the Peng-Robinson equation of state and the dissolution of gas in the water that occupies the pores of the caprock was neglected. The results showed that the pre-defused hydrocarbons in the caprock influence the concentration and hence the cumulative loss of the hydrogen being diffused through the pores of the caprock. Other reservoir storage factors like pressure, temperate, and porosity also play a vital role in this process. The hydrocarbons have been observed to limit the rate of diffusion into the caprock as the simulation goes from less dense to denser with respect to the pressure and temperature applied. Multiple gases of hydrocarbons also showed to limit cumulative loss to caprock at very low temperatures and high pressure. The gas composition at the boundary influences the caprock and reservoir interaction. Over time, the concentration value of hydrogen in the caprock in reservoir conditions indicates that hydrogen molecules will readily diffuse into the pores of the caprock. The results also showed that hydrogen loss has a direct relationship with the porosity of the caprock, the gas saturation of the caprock, the square root of the diffusion coefficient, and the square root of time