Comparative Study of Different CO2 Injection Modes for Baronia RV2 Reservoir

This project presents an experimental study of comparing different CO2 injection mode for Baronia RV2 reservoir. It is the main objective to determine the most optimum CO2 injection mode for this field. Using a coreflood equipment, CO2 displacements were conducted on four core plugs saturated with Baronia RV2 crude oil

Variable density and viscosity, miscible displacements in horizontal Hele-Shaw cells. Part 2. Nonlinear simulations

Direct numerical simulations of the variable density and viscosity Navier-Stokes equations are employed, in order to explore three-dimensional effects within miscible displacements in horizontal Hele-Shaw cells. These simulations identify a number of mechanisms concerning the interaction of viscous fingering with a spanwise Rayleigh-Taylor instability. The dominant wavelength of the Rayleigh-Taylor instability along the upper, gravitationally unstable side of the interface generally is shorter than that of the fingering instability. This results in the formation of plumes of the more viscous resident fluid not only in between neighbouring viscous fingers, but also along the centre of fingers, thereby destroying their shoulders and splitting them longitudinally. The streamwise vorticity dipoles forming as a result of the spanwise Rayleigh-Taylor instability place viscous resident fluid in between regions of less viscous, injected fluid, thereby resulting in the formation of gapwise vorticity via the traditional, gap-averaged viscous fingering mechanism. This leads to a strong spatial correlation of both vorticity components. For stronger density contrasts, the streamwise vorticity component increases, while the gapwise component is reduced, thus indicating a transition from viscously dominated to gravitationally dominated displacements. Gap-averaged, time-dependent concentration profiles show that variable density displacement fronts propagate more slowly than their constant density counterparts. This indicates that the gravitational mixing results in a more complete expulsion of the resident fluid from the Hele-Shaw cell. This observation may be of interest in the context of enhanced oil recovery or carbon sequestration application

Comparative Study of Different C02 Injection Modes for Baronia RV2 Reservoir

C02 flooding can be executed using several modes of injection teclmique such as continuous injection, simultaneous water and gas (SWAG) injection, water alternate gas (GAS) injection and hybrid WAG. Each of these injection modes will give certain amount of recovery based on their capability to restore formation pressure and also to improve oil displacement or fluid flow in the reservoir. Therefore, experiments or simulations may need to be conducted to determine the most effective injection mode which gives the most optimum recovery for a given reservoir. This project presents an experimental study of comparing different C02 injection mode for Baronia RV2 reservoir. It is the main objective to determine the most optimum C02 injection mode for this field. Using a coreflood equipment, C02 displacements were conducted on four core plugs saturated with Baronia RV2 crude oil. From the results of total oil recovered, it was found that SWAG is the most teclmically feasible mode for the field with over 60% recovery factor

Pore-scale study on porous media flows with chemical reaction using lattice Boltzmann method

Porous media flows with chemical reaction are common in nature and widely exist in many scientific and industrial applications. However, due to the complexity of coupled mechanisms, numerical modelling and comprehensive understanding of such flows face significant challenges. Therefore, this thesis develops novel lattice Boltzmann (LB) models to undertake pore-scale simulations of porous media flows with chemical reaction. These models, with new reaction source terms and boundary schemes, can describe both homogeneous reaction between two fluids and heterogeneous reaction (dissolution or combustion) at the fluid-solid interface. Unlike previous studies, current models recast heat and mass transfer equations to correctly consider the thermal expansion effects and the conjugate heat transfer and species conservation conditions. Separate LB equations are also developed to include different species properties. Density fingering with homogeneous reaction is studied at the pore scale. By changing species contributions to density, diffusion coefficients, initial concentrations, and medium heterogeneities, results obtained demonstrate that reaction can enhance, suppress, or trigger fingering. Then, pore-scale simulations of viscous fingering with dissolution reaction are performed. Effects of fluid diffusion, chemical dissolution, and viscosity contrast are extensively assessed. Results illustrate four fingering regimes as stable, unstable, reactive stable, and reactive unstable. Finally, pore-scale coke combustion in porous media is studied. General combustion dynamics are correctly produced, verifying the superior performance of the present LB model over previous ones. A parametric study demonstrates that the inlet air temperature and the driving force are influential factors and should be constrained within certain ranges for stable combustion fronts. These pore-scale findings provide valuable insights, like temperature fluctuations at the fluid-solid interface, porous structure evolutions, exact reaction and diffusion rates, and medium heterogeneity effects, which are more precise and explicit than macroscopic results. Furthermore, detailed fingering and combustion dynamics under diverse conditions are helpful in scientific and industrial fields

Numerical and physical simulations of the displacement of synthetic oil mixtures

Numerical simulation and experiments are often used to study the mixing phenomenon of the fluids during an unstable displacement process. One of the deficiencies of the conventional compositional reservoir simulators for predicting the unstable displacement process is that these simulators all involve the use of the assumption that fluids in each grid block are in a state of thermodynamic equilibrium. In reality, the different fluid phases coexisting in each grid block may not be in equilibrium with each other because of insufficient contact time. The main objective of this study is to develop a non-equilibrium phase behaviour model for compositional simulation of the unstable displacement process and is to verify the simulation results with experimental data. Physical simulations of the displacement process were carried out in a slim-tube apparatus. Four synthetic oil mixtures were used as displaced fluids and four gases were used as displacing fluids. A total of fifteen experiments were performed at displacement pressures ranging from 2390 psia to 3430 psia and with injection rates varying from 0.048 to 0.127 PV/hr. The results of the experiments are presented. A model has been developed to calculate the non-equilibrium phase behaviour of the fluids under displacement process conditions. The model is based on the mixing parameter model proposed by Todd and Longstaff (1972) and the concept of Murphree efficiency commonly used in multicomponent, multistage separation calculations. Phase behaviour calculations are performed for the fluids over the entire grid block under non-equilibrium conditions. The deviation from equilibrium in respect of each component is considered a function of the equilibrium K-value and the effective mobility ratio of the in-situ fluids. Efficient algorithms for phase behaviour calculations (e.g., flash calculations and saturation pressure calculations) generally used in the numerical simulations are presented. An acceleration scheme based on the dominant eigenvalue method coupled with Newton's method is developed for two-phase flash calculations. Effective switching criteria are suggested for the switch over of the acceleration scheme to Newton's method. The proposed method is robust and fast for flash calculations when the specifications are near the critical state values of the fluid mixtures. The performance of the proposed method is compared with those of other improved methods for flash calculations. An algorithm is developed to accelerate the convergence of phase-boundary calculations using Newton's method. The algorithm takes advantage of the history of the iterates and uses the derivative of the iterates to further improve the iterates after three Newton steps. The performance of the proposed algorithm shows its superiority over that of Newton's method particularly when the specifications are near the critical state values of the fluid mixtures. Comparisons of the performance of the proposed algorithm with that of Newton's method and other acceleration algorithms for Newton's method are presented. Comparisons of the numerical simulation results based on the proposed non-equilibrium phase behaviour model with the experimental data obtained from the slim-tube displacement tests for well-defined hydrocarbon systems and with simulation results based on conventional equilibrium phase behaviour model are presented

Evaluation of various CO2 injection strategies including carbonated water injection for coupled enhanced oil recovery and storage

In view of current interest in geological CO2 sequestration and EOR, this study investigated water-based and gas-based CO2 injection strategies for coupled EOR and storage purposes. For water-based CO2 injection strategy, carbonated water injection (CWI) was investigated as an alternative injection mode that could improve sweep efficiency and provide safe storage of CO2. Despite its potential, CWI has not been very much studied. This thesis presents the details on the performance of CWI of moderately viscous oil (>100 cP), which has not been reported before. The effects of oil viscosity, rock wettability and brine salinity on oil recovery from CWI were also studied and significant findings were observed. To the author’s knowledge, no attempt has been made to experimentally quantify the CO2 storage by CWI process and to model the nonequilibrium effects in the CWI at the core scale using the commercial reservoir simulators. These are amongst the main innovative aspects of this thesis. The experimental results reveal that CWI under both secondary and tertiary recovery modes increase oil recovery and CO2 storage with higher potential when using light oil, low salinity carbonated brine and mixed-wet core. In this study, the compositional simulator overpredicts the oil recovery. The instantaneous equilibrium and complete mixing assumptions appear to be inappropriate, where local equilibrium was not in fact achieved during the CW process at this scale. The author evaluated the use of the transport coefficient (the a-factor) to account for the dispersive mixing effects, and found that the approach gives a more accurate prediction of the CWI process. For the gas-based CO2 injection strategies, a practical yet comprehensive approach using reservoir simulation, Design of Experiment (DOE) and the Response Surface Model (RSM) to screen for and co-optimize the most technically and economically promising injection strategy for coupled EOR and CO2 storage is presented. For the reservoir model used in this study, miscible WAG was found to be most economically promising, while miscible continuous CO2 injection was ranked as the most technically viable. The duration of the preceding waterflood, relative permeability (wettability) and injected gas composition are the three most significant factors to the profitability of oil recovery and CO2 storage through tertiary WAG injection

Simulation Study on Water-Alternating-Gas (WAG) Injection with Different Schemes and Types of Gas in a Sandstone Reservoir

Water-Alternating-Gas (WAG) injection is one of the Enhanced Oil Recovery (EOR) techniques applied in oil and gas industry. In a WAG application, there are a lot of combinations of WAG schemes to be selected from. The common stated problem is to determine the optimum WAG schemes for a certain field. Different WAG schemes can be formed by adjusting the WAG parameters, i.e. WAG ratio, WAG injection rate, WAG cycle sizes and etc. Another problem is the ambiguous feasibility of other type of gas in WAG application. The objective of this Final Year Project (FYP) was to simulate and determine the impacts of WAG parameters on the recovery for a sandstone reservoir, and also to evaluate the feasibility of different types of gas in WAG injections. This project was carried out by using a compositional simulator developed by Computer Modeling Group Ltd (CMG). The inputs needed for the simulations were collected from the literatures available. This study focuses on WAG application in a sandstone reservoir. The performance of each scheme was evaluated based primarily on the ultimate recovery. From these outcomes, various WAG schemes and the impacts of each WAG parameter can be compared, and thus deciding the optimum one. It was concluded that WAG ratio, WAG injection rate and types of WAG gas have profound effects on WAG performance, while WAG cycle sizes has insignificant impact on the recovery

Numerical simulation of surfactant flooding with relative permeability estimation using inversion method

Surfactant flooding attracts significant interest in the hydrocarbon industry, with a definite promise to improve oil recovery from depleting oil reserves. In this thesis, surfactant flooding is the primary area of focus as it has significant potential for integration with other chemical enhanced oil recovery techniques, including polymer, nanofluid, alkali, and foam. This combined approach has the potential to reduce interfacial tension to ultralow levels, decrease adsorption, and offer other benefits. However, due to the various mechanism, surfactant flooding poses a more complex model for simulators by encountering numerical issues (e.g., the appearance of spurious oscillations, erratic pulses, and numerical instabilities), rendering the methods ineffective. To address these challenges, the analytical modelling technique of surfactant flooding was studied, leading to the development of a novel inversion method in the MATLAB programming environment. Numerical accuracy issues were discovered in 1D models that used typical cell sizes found in well-scale models, leading to pulses in the oil bank and a dip in water saturation, particularly for low levels of adsorption, highlighting the need for more refined models. Based on these findings, we examined the surfactant flooding technique in 2D models to recover viscous oil in short reservoir aspect ratios. Instabilities such as viscous fingering and gravity tongue were observed on the flood fronts, and the magnitude of the viscous fingers was influenced by vertical dispersion, resulting in errors in computed mobility values at the fronts. Interestingly, introducing heterogeneity only minimally affected the spreading of the front and did not significantly impact viscous fingering or numerical artifacts. To optimize the nonlinearity of flow behaviour and degree of mobility control at the fronts, a homogenous model was considered to develop the inversion method. In summary, the developed inversion method accurately estimated the two-phase relative permeability curves, which were validated using fractional flow theory. The precision of the inverted curves was further improved using the optimization algorithm, demonstrating the method's ability to predict outcomes closer to the observed values for 2D models with instabilities. The obtained results are of significant value for core flood analysis, interpretation, matching, and upscaling, providing insights into the potential of surfactant flooding for enhanced oil recovery. Additionally, the use of the developed MATLAB Scripts promotes open innovation and reproducibility, contributing to the benchmarking, analytical, and numerical method development exercises for tutorials aimed at improving the overall understanding of surfactant flooding

Improved numerical simulation of non-thermal enhanced heavy oil recovery

The dependence on unconventional resources such as heavy oil is on the rise due to geometric increase in demand for energy and the decline of production from mature conventional oil reservoirs. Heavy oil reservoirs contain oil that has some limited mobility under reservoir conditions and only a small fraction of the oil-in-place can be recovered by primary technique which involve harnessing the internal reservoir energy. The remaining oil after the primary depletion is still mostly continuous and present a valuable target for enhanced recovery. However, most of these reservoirs are relatively thin, making them poor candidates for thermal methods, in addition to associated high energy requirement and adverse environmental effects of the heating process. Therefore, any incremental oil recovery must be through non-thermal methods, such as waterflooding, chemical and gas injection. These methods however suffer from adverse mobility ratio which significantly affect the efficiency of the displacement process. The simulation of these processes for the purpose of reservoir prediction and performance is a herculean task due to the complex physics of instability and compositional effect taking place that is not fully understood. In this thesis, the results of improved numerical simulation techniques of non-thermal heavy oil recovery were presented, demonstrating the viability of the techniques as simulation methods heavy oil non-thermal enhanced heavy oil recovery (EHOR). Several displacement mechanisms were identified through the simulation of the secondary and tertiary processes that contributed to significant incremental heavy oil recovery. A systematic lumping scheme of the heavy oil components into pseudo-components based on the behaviour of the produced oil was proposed. A new methodology for the estimation of relative permeability from displacement with instability and compositional effect using a two-dimensional (2D), high-resolution model to effectively capture the finger, and a versatile, three-parameter function (L.E.T correlation) was demonstrated. A semianalytical approach through a combination of theoretical and an empirical prediction method based on the famous works of Koval, and Todd and Longstaff on viscous fingering was employed for the verification of the estimated relative permeability. Lastly, a multiscale approach to history matching, for the estimation of unstable relative permeability that is computationally more efficient, was proposed. It involves the history matching of a set of coarse grid models to predict the fine-scale relative permeability. In this approach, fine-scale information was resolved without direct solution of the global fine-scale problem. The results showed that the time required to estimate relative permeability using the multiscale approach was only about 35% required to estimate the same relative permeability using a single high-resolution model. The memory requirement for the approach was also about 50% required for simulation of the single high-resolution model. Therefore, the lower memory size and computations required in the multiscale approach mean that a less powerful computer can be used to estimate the relative permeability curves for unstable displacements with accuracy similar to that obtained using a high-resolution model approach

Comparative Study of Different CO2 Injection Modes for Baronia RV2 Reservoir

This project presents an experimental study of comparing different CO2 injection mode for Baronia RV2 reservoir. It is the main objective to determine the most optimum CO2 injection mode for this field. Using a coreflood equipment, CO2 displacements were conducted on four core plugs saturated with Baronia RV2 crude oil