Time-lapse seismic monitoring repeats 3D seismic imaging over a reservoir to map fluid movements in a reservoir. During hydrocarbon production, the fluid saturation, pressure, and temperature of a reservoir change, thereby altering the acoustic properties of the reservoir. Time-lapse seismic analysis can illuminate these dynamic changes of reservoir properties, and therefore has strong potential for improving reservoir management. However, the response of a reservoir depends on many parameters and can be diffcult to understand and predict. Numerical modeling results integrating streamline fluid flow simulation, rock physics, and ray-Born seismic modeling address some of these problems. Calculations show that the sensitivity of amplitude changes to porosity depend on the type of sediment comprising the reservoir. For consolidated rock, high-porosity models show larger amplitude changes than low porosity models. However, in an unconsolidated formation, there is less consistent correlation between amplitude and porosity. The rapid time-lapse modeling schemes also allow statistical analysis of the uncertainty in seismic response associated with poorly known values of reservoir parameters such as permeability and dry bulk modulus. Results show that for permeability, the maximum uncertainties in time-lapse seismic signals occur at the water front, where saturation is most variable. For the dry bulk-modulus, the uncertainty is greatest near the injection well, where the maximum saturation changes occur. Time-lapse seismic methods can also be applied to monitor CO2 sequestration. Simulations show that since the acoustic properties of CO2 are very different from those of hydrocarbons and water, it is possible to image CO2 saturation using seismic monitoring. Furthermore, amplitude changes after supercritical fluid CO2 injection are larger than liquid CO2 injection. Two seismic surveys over Teal South Field, Eugene Island, Gulf of Mexico, were acquired at different times, and the numerical models provide important insights to understand changes in the reservoir. 4D seismic differences after cross-equalization show that amplitude dimming occurs in the northeast and brightening occurs in the southwest part of the field. Our forward model, which integrates production data, petrophysicals, and seismic wave propagation simulation, shows that the amplitude dimming and brightening can be explained by pore pressure drops and gas invasion, respectively.

Large amounts of CH4 in the form of solid hydrates are stored on continental margins and in permafrost regions. If these CH4 hydrates could be converted into CO2 hydrates, they would serve double duty as CH4 sources and CO2 storage sites. Herein, we report the swapping phenomena between global warming gas and various structures of natural gas hydrate including sI, sII, and sH through 13C solid-state nuclear magnetic resonance, and FT-Raman spectrometer. The present outcome of 85% CH4 recovery rate in sI CH4 hydrate achieved by the direct use of binary N2 + CO2 guests is quite surprising when compared with the rate of 64 % for a pure CO2 guest attained in the previous approach. The direct use of a mixture of N2 + CO2 eliminates the requirement of a CO2 separation/purification process. In addition, the simultaneously-occurring dual mechanism of CO2 sequestration and CH4 recovery is expected to provide the physicochemical background required for developing a promising large-scale approach with economic feasibility. In the case of sII and sH CH4 hydrates, we observe a spontaneous structure transition to sI during the replacement and a cage-specific distribution of guest molecules. A significant change of the lattice dimension due to structure transformation induces a relative number of small cage sites to reduce, resulting in the considerable increase of CH4 recovery rate. The mutually interactive pattern of targeted guest-cage conjugates possesses important implications on the diverse hydratebased inclusion phenomena as clearly illustrated in the swapping process between CO2 stream and complex CH4 hydrate structure.

Removal of CO2 directly from anthropogenic sources (capture) and its disposal in geological formations can take place for medium-term time periods (storage), or it can be permanent (sequestration), with the CO2 eventually becoming dissolved in the aqueous phase. The latter is the main subject of this dissertation. Carbon dioxide sequestration covers a wide range of strategies and alternatives. The main objective of CO2 sequestration alternatives is secure disposal of carbon in large amounts and for a lengthy time scale (typically 1000 years). Injection of CO2 into subsurface formations is generally considered as the main option for CO2 sequestration. Geological sequestration through injection covers a broad variety of target formations: disposal in depleted oil and gas reservoirs, trapping in oil reservoirs, replacing CH4 in coal bed methane recovery processes, trapping in deep aquifers, and salt cavern placement are the major CCS alternatives in geologic formations. In this thesis, hydrogeologic interaction between the injectant (CO2) and the host fluid (saline water) during injection is the main subject of the project. Because of the density and viscosity contrast of displacing and displaced fluids, the pattern of saturation progression is complicated. A set of semi-analytical solutions is developed for quick estimation of the position of isosats (contours of saturation) during primary injection in homogenous cases with simple geometry. All of the mathematical solutions are developed based on two assumptions; incompressible fluids and rocks and vertical equilibrium (capillary-gravity condition) for geometries with large aspect ratio (L >> H). First, a series of analytical solutions for primary drainage for a set of linear relative permeability functions is developed. The first analytical solution is based on the assumption of locally linearized Leverett-J functions, and by using the method of characteristics, a formulation for the isosats’ geometry is obtained. A semi-analytical solution is then proposed for calculation of the position of isosats with linearized relative permeability functions and arbitrary capillary-saturation correlation. The analytical solution is extended to incorporate a specific form of nonlinearity of the relative permeability function. Nonlinear relative permeability functions are also incorporated in another semi-analytical solution, and the positions of the isosats for any arbitrary Leverett-J function and relative permeability functions are developed. Sequential gas-saline injection is also modeled in that chapter. For approximate verification of the analytical solutions, a FEM numerical model is developed and the results of the analytical solutions are compared with the numerical solutions. These new analytical solutions provide powerful tools for prediction of saturation distribution during injection in vertical and horizontal wells, as well as for carrying out stochastic assessments (Monte Carlo simulations) and parametric weight assessment. The domain of applications of the new solutions go far beyond the limited question of CO2 sequestration: they can be used for injection of any less viscous fluid into a reservoir, whether the fluid is lighter or denser than the host fluid (gas injection, water-alternating gas injection, water injection into viscous oil reservoirs, solvent injection).

ABSTRACT MODELING OF CARBON DIOXIDE SEQUESTRATION IN A DEEP SALINE AQUIFER BASBUg, BaSar M.S., Department of Petroleum and Natural Gas Engineering Supervisor : Prof. Dr. Fevzi G&uuml / mrah July 2005, 245 pages CO2 is one of the hazardous greenhouse gases causing significant changes in the environment. The sequestering CO2 in a suitable geological medium can be a feasible method to avoid the negative effects of CO2 emissions in the atmosphere. CO2 sequestration is the capture of, separation, and long-term storage of CO2 in underground geological environments. A case study was simulated regarding the CO2 sequestration in a deep saline aquifer. The compositional numerical model (GEM) of the CMG software was used to study the ability of the selected aquifer to accept and retain the large quantities of injected CO2 at supercritical state for long periods of time (200 years). A field-scale model with two injectors and six water producers and a single-well aquifer model cases were studied. In a single-well aquifer model, the effects of parameters such as vertical to horizontal permeability ratio, aquifer pressure, injection rate, and salinity on the sequestration process were examined and the sensitivity analyses were performed after simulating the field-scale model. The supercritical CO2, one-state fluid which exhibits both gas and liquid-like properties, and gaseous CO2 were sequestered in the forms of free CO2 bubble, dissolved CO2 in brine and precipitated CO2 with calcite mineral in a deep saline aquifer. The isothermal condition was assumed during injection and sequestration processes. The change in porosity and permeability values that might have occurred due to mineralization and CO2 adsorption on rock were not considered in this study. Vertical to horizontal permeability ratio and initial pressure conditions were the most dominating parameters affecting the CO2 saturation in each layer of the aquifer whereas CO2 injection rate influenced CO2 saturation in middle and bottom layers since CO2 was injected through bottom layer.

CO2 injection has been used to improve oil recovery for several decades. In recent years, CO2 injection has become even more attractive because of a dual effect; injection in the subsurface 1) allows reduction of CO2 concentration in the atmosphere to reduce global warming, and 2) improves the oil recovery. In this study, the density effect from CO2 dissolution in modeling of CO2 injection is examined. A method to model the increase in oil density with CO2 dissolution using the Peng-Robinson equation of state and the Pedersen viscosity correlation is presented. This method is applied to model the observed increase in oil density with CO2 dissolution in a West Texas crude oil. Compositional simulation of CO2 injection was performed in a 2D vertical cross section and a 3D reservoir with the density effect. The results show that the density increase from CO2 dissolution may have a drastic effect on CO2 flow path and recovery performance. One main conclusion from this work is that there is a need to have accurate density data for CO2/oil mixtures at different CO2 concentrations to ensure successful CO2 injection projects. While CO2 enhanced oil recovery (EOR) is part of the solution, saline aquifers have the largest potential for CO2 sequestration. A literature review of the CO2 sequestration in saline aquifers is performed. The dominant trapping mechanisms and transport processes and the methods used to model them are discussed in detail. The Aruma aquifer, a shallow saline aquifer in southwest Qatar is used as a case study for CO2 sequestration. A compositional simulation model is prepared for the Aruma aquifer using the available log data and flow test data. It was found that the grid size is a key parameter in modeling CO2 sequestration accurately. It affects the propagation of the CO2 plume and amount of CO2 dissolved in brine.

Carbon dioxide (CO2) sequestration in the sub-surface is a potential mitigation technique for global climate change caused by greenhouse gas emissions. In order to evaluate the feasibility of this technique, understanding the behaviour of CO2 stored in geological rock formations over a range of length- and time-scales is crucial. The work presented in this dissertation contributes to the knowledge in this field by investigating the two-phase flow and entrapment processes of CO2, as well as other relevant fluids, in porous media at the pore- and centimetre-scales using a combination of lab-based nuclear magnetic resonance (NMR) experimental techniques and lattice Boltzmann (LB) numerical simulation techniques. Pulsed field gradient (PFG) NMR techniques were used to acquire displacement distributions (propagators) of brine flow through a model porous medium (100 µm glass bead packing) before and after the capillary (residual) trapping of gas-phase CO2 in the pore space. The acquired propagators were compared quantitatively with the corresponding LB simulations. In addition, magnetic resonance imaging (MRI) techniques were used to characterise the extent of CO2 trapping in the bead pack. The acquired NMR propagators were compared to LB simulations applied to various CO2 entrapment scenarios in order to investigate the pore morphology in which CO2 becomes entrapped. Subsequently, MRI drop shape analysis techniques were used to identify a pair of analogue fluids which matched certain key physical properties (specifically interfacial tension) of the supercritical CO2/water system in order to extend the work to conditions more relevant to CO2 sequestration in the sub-surface, where CO2 is likely to be present in the supercritical phase. As before, NMR propagator measurements and MRI techniques, along with LB simulations, were used to characterise the capillary trapping of the CO2 analogue phase in glass bead packs, as well as two different types of rock core plugs – relatively homogeneous Bentheimer sandstone, and heterogeneous Portland carbonate. In addition to capillary trapping, the effect of vertical permeability heterogeneity, such as is often present in underground rock formations, was investigated for the flow of miscible (water/brine) gravity currents in model porous media (glass bead packs), using MRI techniques such as 2D spin-echo imaging and phase-shift velocity imaging. Finally, a preliminary investigation was made into the effect of particle- and pore-size distributions on the gas/liquid (air/water) interface for porous media consisting of glass bead and sand packs of different average particle size using quantitative MRI techniques.

Carbon dioxide (CO2) sequestration is one of the most attractive methods to reduce the amount of CO2 in the atmosphere by injecting it into the geological formations. Furthermore, it is also an effective mechanism for enhanced oil recovery. Simulation of CO2 injection based on a suitable modeling is very important for explaining the fluid flow behavior of CO2 in a reservoir. Increasing of CO2 injection may cause a structural deformation of the medium. The structural deformation modeling in carbon sequestration is useful to evaluate the medium stability to avoid CO2 leakage to the atmosphere. Therefore, it is important to include such effect into the model. The purpose of this study is to simulate the CO2 injection in a reservoir. The numerical simulations of two-phase flow in homogeneous and heterogeneous porous media are presented. Also, the effects of gravity and capillary pressure are considered. IMplicit Pressure Explicit Saturation (IMPES) and IMplicit Pressure-Displacements and an Explicit Saturation (IMPDES) schemes are used to solve the problems under consideration. Various numerical examples were simulated and divided into two parts of the study. The numerical results demonstrate the effects of buoyancy and capillary pressure as well as the permeability value and its distribution in the domain. Some conclusions that could be derived from the numerical results are the buoyancy of CO2 is driven by the density difference, the CO2 saturation profile (rate and distribution) are affected by the permeability distribution and its value, and the displacements of the porous medium go to constant values at least six to eight months (on average) after injection. Furthermore, the simulation of CO2 injection provides intuitive knowledge and a better understanding of the fluid flow behavior of CO2 in the subsurface with the deformation effect of the porous medium.

No description available.

Accurate phase behavior modeling of hydrocarbon and aqueous mixtures plays a critical role in simulation of compositional flow in subsurface reservoirs, such as miscible gas flooding and CO2 sequestration. As Michelsen proposed his groundbreaking works in stability test and phase split calculation, PT flash calculation has been well developed in the past four decades and become the most popular flash technique. However, as research interests move to more complicated reservoir fluids, some inherent drawbacks of PT flash formulations show up and recent researches focus on a promising alternative called VT flash calculation. In this thesis, VT flash calculation is used in place of PT flash to model phase behaviors of hydrocarbon and aqueous mixtures. A dynamical model, together with a thermodynamically stable numerical algorithm, is developed to calculate equilibrium phase amounts and compositions with/without capillary effect to simulate phase behaviors of unconventional/conventional hydrocarbon mixtures. In order to model water-containing mixtures, the cubic equation of state is replaced by the Cubic-PlusAssociation equation of state, and a salt-based Cubic-Plus-Association model is developed to calculate phase behaviors of CO2-brine systems. The combination of VT flash calculation and the salt-based Cubic-Plus-Association model accurately estimate CO2 solubility in both single- and mixed-salt solutions, and it exhibits close prediction accuracy with a more sophisticated electrolyte Cubic-Plus-Association model. At the end, the ultimate goal is to develop an efficient two-phase VT-flash compositional flow algorithm. The multilayer nonlinear elimination method is used to remove locally high nonlinearities based on the feedback of intermediate Newton solutions. To further improve the computational efficiency, a modified shadow region method is used to bypass unnecessary stability tests. Although nonlinear elimination fails to fully resolve the convergence issue, which roots in the nondifferentiable equilibrium pressure at the points of phase boundary, the number of time refinements is significantly reduced and the improved VT-flash compositional flow algorithm with multilayer nonlinear elimination method successfully simulates a number of numerical examples with and without gravity.

Seismic inversion is the leading method to map and quantify changes in time-lapse (4D) seismic datasets, with applications ranging from monitoring hydrocarbon-producing fields to geological CO2 storage. However, the process of inverting seismic data for reservoir properties is a notoriously ill-posed inverse problem due to the band-limited and noisy nature of seismic data. This comes with additional challenges for 4D applications, given the inaccuracies in the repeatability of time-lapse acquisition surveys. Consequently, adding prior information to the inversion process in the form of properly crafted regularization terms is essential to obtain geologically meaningful subsurface models and 4D effects. In this thesis, I propose a joint inversion-segmentation algorithm for 4D seismic inversion, which integrates total variation and segmentation priors as a way to counteract the missing frequencies and noise present in 4D seismic data. I validate the algorithm with synthetic and field seismic datasets and benchmark it against state-of-the-art 4D inversion techniques. The proposed algorithm shows three main advantages: 1. it produces high-resolution baseline and monitor acoustic impedance models, 2. by leveraging similarities between multiple seismic datasets, the proposed algorithm mitigates the non-repeatable noise and better highlights the real seismic time-lapse changes, and 3. it simultaneously provides a volumetric classification of the acoustic impedance 4D difference model based on user-defined classes, i.e., percentages of seismic time-lapse changes. Such advantages may enable more robust stratigraphic/structural and quantitative 4D seismic interpretation and provide more accurate inputs for dynamic reservoir simulations.