Browsing by Author "Jia, Na"
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- ItemOpen AccessDevelopment of a Comprehensive and General Approach to In Situ Combustion Modelling(2024-03-26) Gutiérrez, Dubert; Moore, Robert Gordon; Mehta, Sudarshan A.; Aguilera, Roberto; Hejazi, Hossein; Hassanzadeh, Hassan; Jia, NaModelling of the in situ combustion (ISC) process is a challenging task, mostly due to the complexity of the chemical reactions taking place. Also, the applicability of currently available kinetic models is typically limited to the reservoir systems they were originally developed for. The objective of this study was to derive a general chemical reaction framework that could be used to develop a kinetic model for a wide variety of crude oils. The work is based on the modelling of high-pressure ramped temperature oxidation (HPRTO) experiments, and combustion tube (CT) tests, performed on three different oil systems: a volatile oil which is near critical at reservoir conditions (38.8°API), a low-shrinkage light oil (33.1°API), and a bitumen sample (6.5°API). A kinetic model was derived for each of the cases based on the history match of a HPRTO experiment. The resulting models were validated by history matching a CT test for each of the crude oils, while using the same set of developed reactions. The modelling approach chosen is an extension of the methodology originally proposed by Belgrave et al. in 1993, which is arguably the most comprehensive kinetic model available in the air injection literature. However, their model was developed from experiments performed on Athabasca bitumen, and it fails to represent the ISC process as it occurs in light oil reservoirs encountered at high pressure. For example, Belgrave’s model is based on the deposition and combustion of semi-solid residue commonly known as “coke”, which is rarely present during the ISC of light oils at high pressure. As in Belgrave’s model, this study also describes the original oil in terms of maltenes and asphaltenes. The main difference lies on the presence and importance of oxygen-induced cracking reactions, as well as the combustion of a flammable mixture, which takes place in the gas phase. Also, a unique feature of these simulations is that, apart from history matching traditional variables such as thermocouple temperatures, produced gas composition and fluid recovery, they also capture changes in the physical properties of the produced oil, such as viscosity and density, as well as the amount of the residual phases in the post-test cores. This thesis changes a paradigm deeply rooted in the original ISC theory, by deriving a general chemical reaction framework that is used to develop a kinetic model for a wide variety of crude oils, with API gravities ranging between 6.5 and 38.8. This allows the consolidation of a new and comprehensive general theory for the description of the in situ combustion process as applied to oil reservoirs. One of the features of the modelling approach is that the pseudo-components representing the fuel used by the ISC process are not present in the original oil. Such fuel species are products of oxidation and cracking reactions, which may undergo combustion reactions when in contact with oxygen. Therefore, the method is not limited to a fluid characterization based in terms of maltenes and asphaltenes, and could potentially be applied along with any other type of characterization of the original oil. This facilitates its implementation and coupling with existing field-scale models (i.e., black oil, thermal, or fully compositional), which seek to assess the feasibility of the in situ combustion process on a particular reservoir of interest.
- ItemOpen AccessEffect of residual oxygen in combined co2 flooding and sequestration process(2007) Jia, Na; Moore, R. GordonCarbon dioxide flooding is a well-established enhanced oil recovery process. The cost of a combined CO2 miscible flood/sequestration process depends on the purity of injected CO2 stream. Oxygen contaminant is of particular interest as it can modify the native oil properties through low temperature oxidation reactions; promote corrosion in the piping. This study investigated the influence of various levels of oxygen as an impurity in CO2 on the selected light oil. Effects of oxygen concentration in the feed gas reaction temperature, pressure, time and the presence of core matrix and brine on compositional changes and rheological properties in the partially oxidized oil have been investigated. It was found that the asphaltenes and coke yields of the reacted oil were higher than the original oil's values following the injection of pure CO2 or CO2/O2 gas mixtures. Asphaltenes plus coke yields increased with increasing temperature when oxygen was present. The presence of core promoted the production of asphaltenes but retarded the formation of coke. It showed that asphaltenes plus coke contents increased smoothly with increasing oxygen concentration in the feed gas. With enough reaction time, the sum of coke and asphaltenes would flatten out when the oxygen concentration was above 5 mol%. Viscosities and densities of the modified oil were higher than those of the original oil. Phase behavior observations and swelling experiments for different concentrations of CO2/O2 mixtures injected into the light oil were conducted to investigate the complex phase phenomenon that occurred during the carbon dioxide flooding process. Multi-phase equilibrium calculations were conducted to predict the component distribution. The effect of oxygen/carbon dioxide gas mixtures on Athabasca bitumen was studied in this thesis. The results showed influence of the gas mixtures on compositional changes and rheological properties of the Athabasca bitumen. A kinetic model for describing low temperature oxidation reactions was developed. It explained the mutual conversion between the maltenes and asphaltenes, and the oil compositional changes as a function of the reaction time. Development of this kinetic model provided a better understanding of the reaction mechanism when an oxygen containing gas was injected into a reservoir.
- ItemOpen AccessMulti-scale Numerical Studies on Characterization of Shale Gas Reservoir Development(2018-05-17) Zhan, Jie; Chen, Zhangxing (John); Moore, Robert Gordon; Huang, Haiping; Jia, Na; Hejazi, Seyed HosseinFrom three different perspectives, this thesis addresses one issue: how to reliably and objectively assess and forecast the shale reservoir performance with an advanced understanding of the shale reservoir specialty. With enhanced hydraulic characterization, Chapter 2 provides an advanced modelling scheme using the commercial platform to reduce history-match errors and forecast uncertainty. In Chapter 3, an integrated multi-scale numerical simulation platform is established. Based on the multi-scale characterization platform, the insights obtained at the micro-scale such as nanopore surface coverage evolution and induced heterogeneity can provide a better understanding of the macro reservoir performance, which leads to more reasonable and objective evaluation on the reservoir transient response. In Chapter 4, based on an integrated modelling workflow, the reservoir performance for carbon dioxide (CO2) sequestration in both dry and liquid-rich shale reservoirs is assessed. A more accurate shale reservoir model representing the most important features of shale formations is proposed. The objective of the work is to determine the most critical factors dominating the success of the CO2 sequestration and enhanced oil and gas recovery (EOR/EGR), which gives valuable guidance in field applications.
- ItemOpen AccessNumerical Modeling of Multi-mechanistic Gas Production from Shale Reservoirs(2020-08-26) Mohagheghian, Erfan; Hassanzadeh, Hassan; Chen, Zhangxin; Aguilera, Roberto; Sarma, Hemanta Kumar; Wong, Ron Chik-Kwong; Jia, NaShale and ultratight gas reservoirs have recently been contributing to the energy industry and gas market to a large extent. The dynamics of shale gas transport in porous media is of practical importance in several scientific and engineering applications. The characteristics of the transport inside the pore space are governed by the mechanisms that occur at the pore level. Recent advances in computational power provide the opportunity to investigate these phenomena further. In this study, a methodology is developed to create a model in which all the major transport mechanisms involved in shale gas flow are taken into account. The mechanisms include viscous flow, gas slippage, Knudsen diffusion, competitive adsorption of different gaseous components, pore size variation and real gas effect. The model is then utilized on one hand to derive parameters such as apparent gas permeability and matrix-fracture fluid exchange term (a.k.a. shape factor) which can reduce the computational load while preserving the accuracy and on the other hand to study the response of shale gas reservoirs to the feasibility and potentials of carbon storage and enhanced gas recovery as well as phenomena such as nano-confinement and chromatographic separation. The compositional effects of shale gas can be lumped into a single component using the apparent permeability which deems to capture the relevant physics and can replace the Darcy permeability. The shape factor required for Darcy scale simulation of shale gas reservoirs obtained from the detailed numerical simulations of multi-mechanistic multi-component shale gas flow can be modeled versus dimensionless pressure to capture the transient behavior of the matrix-fracture fluid transfer in a time-independent fashion. The stronger adsorption of CO2 over CH4 to shale surface makes the partially depleted shale gas reservoirs a promising target for CO2 storage as well as enhanced natural gas recovery. Up to 55% of the injected CO2 can be trapped as adsorbed phase and up to 16% incremental methane recovery can be achieved. The phase behavior of the confined shale gas is significantly different than the behavior of the bulk fluid. Nano-confinement could shift critical properties significantly. The effect of confinement on phase diagrams and compositional variations of the gas in place was also investigated via numerical simulations. The computed apparent permeability and shape factor can be directly used in the macroscale reservoir simulators to accurately predict the performance of a shale gas reservoir and the outcomes of this study will find applications in the design and implementation of an efficient CO2 injection and investigating compositional effects in shale gas simulations.