CO2 injection is an effective method for performing enhanced oil recovery (EOR). There are several factors that make CO2 useful for EOR, including promoting swelling, reducing oil viscosity, decreasing oil density, and vaporizing and extracting portions of crude oil. Moreover, the ease with which CO2 becomes soluble in oil makes it an ideal gas for EOR operations. However, there are several problems associated with CO2 flooding, especially when reservoir heterogeneity exists. The efficiency of CO2 is hindered by mobility problems, which result from the unfavorable mobility ratio. In such cases, the injected CO2 leads to an early breakthrough, which means fingering through the target zone occurs while leaving most of the residual and/or trapped oil untouched. Furthermore, an increase in the CO2 to oil ratio makes the EOR project uneconomical. However, if there are techniques available to control the injected CO2 volume, the problems just mentioned can be resolved. Nowadays, several methods are applied to control the CO2 flooding in heterogeneous porous media. In the present study, the CO2 coreflood system was integrated with a computed tomography (CT) scanner and obtained real-time coreflood images of the CO2 saturation distribution in the core sample. Throughout this study, two polymers, Polydimethylsiloxane (PDMS) and Poly (vinyl ethyl ether) (PVEE), were tested to assess their ability to increase the CO2 viscosity and therefore improve sweep efficiency. A drop-in pressure test was first conducted to evaluate the viscosifier's ability to increase CO2 viscosity; therefore, reduce its mobility. The results showed that the PDMS polymer has the greatest influence on increasing the CO2 viscosity and reducing its mobility. Also, the PVEE polymer has lower mobility than that of neat CO2. Based on the coreflood experiments, injection of viscosified CO2 using the PDMS polymer resulted in the highest oil recovery among the other injection tests have been conducted. Also, the laboratory tests show that injecting the viscosified CO2 using the PVEE polymer led to higher oil recovery than from the neat CO2 injection. This research serves as a preliminary study in understanding advanced CO2 mobility control using the thickening agents technique and will provide an insight into the future studies on the topic.

Air injection is an enhanced oil recovery (EOR) process in which compressed air is injected into a high temperature, light-oil reservoir. The oxygen in injected air is intended to react with a fraction of reservoir oil at elevated temperature resulting in in-situ generation of flue gases and steam, which, in turn, mobilize and drive the oil ahead towards the producing wells. To understand and determine the feasibility of the air injection process application to a given reservoir, it is necessary to understand the oxidation behaviour of the crude oil. The aim of this study is to screen two Australian light-oil reservoirs; Kenmore Oilfield, Eromanga Basin, and another Australian onshore oil and gas field “B”* for air injection EOR process, and to understand the oxidation reaction kinetics during air injection. It is carried out by the thermogravimetric and differential scanning calorimetric (TGA/DSC) studies to investigate the oxidation mechanism during an air injection process. There has not been any TGA/DSC evaluation conducted to date with regard to air injection for Australian light-oil reservoirs. A series of thermal tests was performed to investigate the oxidation behaviour of two selected reservoirs in both air and oxygen environments. The first step undertaken in this study is thermogravimetric and calorimetric characterization of crude oils to (i) identify the temperature range over which the oil reacts with oxygen, (ii) examine the oxidation behaviour within the temperature identified, and (iii) evaluate the mass loss characteristics during the oxidation. This study also examines the effect of pressure on oxidation at different temperature ranges and the effect of core material (rock cutting) on oxidation reactions. Finally, kinetic data are calculated from thermal tests results by literature described method. Kenmore and Field B both are high temperature and light-oil reservoirs. Hydrocarbon distribution indicates that Kenmore oil contains 84 mole% of lower carbon number n-C₅ - n-C₁ ₃ compounds. Reservoir B oil also contains a substantial amount (i.e., 95 mole %) of lower carbon number n-C₄ - C₁ ₉ compounds. These lighter components may contribute favourably towards efficient oxidation. However, a high content of lighter ends in the oil may also result in a lower fuel load. Generally, low molecular weight oil gives fastest mass loss from heavy crude oil. Thermal tests on Kenmore oil showed two distinct exothermic reactivity regions in temperatures of 200-340°C and 360-450°C, with a 85-95% mass loss when the temperature reached 450°C. Reservoir B oil showed a wider exotherm range between approximately 180°C-260°C with 90-95% mass loss by temperature 350°C. In the high temperature range, the combustion reactions of Reservoir B oil are weaker than Kenmore oil. This is due to insufficient fuel available for oxidations in high temperature region. Reservoir B oil has more chance to auto ignite; but it has less sustainability to the ignition process. Based on the sustainability study of the ignition process, between the two reservoirs, Kenmore is the better candidate for air injection. Based on the thermal tests, it is concluded that for light-oil oxidation, vaporization is the dominant physical phenomenon. At low temperature range, the addition of the core material enhanced the exothermic reactions of the oil. The elevated pressure accelerated the bond scission reactions. The largest amount and highest rate of energy generation occurred at the low temperature range. Activation energies (E) are calculated from thermal test results and the value of ‘E’ in oil-with-core combined tests is smaller than the oil-only test. This indicates that the rock material has a positive impact on the combustion process. Moreover, the compositional analysis result addresses the composition of oils, which can help understand the oxidation behaviour of light-oils. * For confidentiality reasons, the field name is coded as Field B at the request of the operating company. / http://proxy.library.adelaide.edu.au/login?url= http://library.adelaide.edu.au/cgi-bin/Pwebrecon.cgi?BBID=1381084 / Thesis (M.Eng.Sc.) -- University of Adelaide, Australian School of Petroleum, 2010

Air injection is an enhanced oil recovery (EOR) process in which compressed air is injected into a high temperature, light-oil reservoir. The oxygen in injected air is intended to react with a fraction of reservoir oil at elevated temperature resulting in in-situ generation of flue gases and steam, which, in turn, mobilize and drive the oil ahead towards the producing wells. To understand and determine the feasibility of the air injection process application to a given reservoir, it is necessary to understand the oxidation behaviour of the crude oil. The aim of this study is to screen two Australian light-oil reservoirs; Kenmore Oilfield, Eromanga Basin, and another Australian onshore oil and gas field “B”* for air injection EOR process, and to understand the oxidation reaction kinetics during air injection. It is carried out by the thermogravimetric and differential scanning calorimetric (TGA/DSC) studies to investigate the oxidation mechanism during an air injection process. There has not been any TGA/DSC evaluation conducted to date with regard to air injection for Australian light-oil reservoirs. A series of thermal tests was performed to investigate the oxidation behaviour of two selected reservoirs in both air and oxygen environments. The first step undertaken in this study is thermogravimetric and calorimetric characterization of crude oils to (i) identify the temperature range over which the oil reacts with oxygen, (ii) examine the oxidation behaviour within the temperature identified, and (iii) evaluate the mass loss characteristics during the oxidation. This study also examines the effect of pressure on oxidation at different temperature ranges and the effect of core material (rock cutting) on oxidation reactions. Finally, kinetic data are calculated from thermal tests results by literature described method. Kenmore and Field B both are high temperature and light-oil reservoirs. Hydrocarbon distribution indicates that Kenmore oil contains 84 mole% of lower carbon number n-C₅ - n-C₁ ₃ compounds. Reservoir B oil also contains a substantial amount (i.e., 95 mole %) of lower carbon number n-C₄ - C₁ ₉ compounds. These lighter components may contribute favourably towards efficient oxidation. However, a high content of lighter ends in the oil may also result in a lower fuel load. Generally, low molecular weight oil gives fastest mass loss from heavy crude oil. Thermal tests on Kenmore oil showed two distinct exothermic reactivity regions in temperatures of 200-340°C and 360-450°C, with a 85-95% mass loss when the temperature reached 450°C. Reservoir B oil showed a wider exotherm range between approximately 180°C-260°C with 90-95% mass loss by temperature 350°C. In the high temperature range, the combustion reactions of Reservoir B oil are weaker than Kenmore oil. This is due to insufficient fuel available for oxidations in high temperature region. Reservoir B oil has more chance to auto ignite; but it has less sustainability to the ignition process. Based on the sustainability study of the ignition process, between the two reservoirs, Kenmore is the better candidate for air injection. Based on the thermal tests, it is concluded that for light-oil oxidation, vaporization is the dominant physical phenomenon. At low temperature range, the addition of the core material enhanced the exothermic reactions of the oil. The elevated pressure accelerated the bond scission reactions. The largest amount and highest rate of energy generation occurred at the low temperature range. Activation energies (E) are calculated from thermal test results and the value of ‘E’ in oil-with-core combined tests is smaller than the oil-only test. This indicates that the rock material has a positive impact on the combustion process. Moreover, the compositional analysis result addresses the composition of oils, which can help understand the oxidation behaviour of light-oils. * For confidentiality reasons, the field name is coded as Field B at the request of the operating company. / http://proxy.library.adelaide.edu.au/login?url= http://library.adelaide.edu.au/cgi-bin/Pwebrecon.cgi?BBID=1381084 / Thesis (M.Eng.Sc.) -- University of Adelaide, Australian School of Petroleum, 2010

Solids-stabilized water-in-oil emulsions have been suggested as a drive fluid to recover viscous oil through a piston-like displacement pattern. While crude heavy oil was initially suggested as the base oil, an alternative oil ? used engine oil was proposed for emulsion generation because of several key advantages: more favorable viscosity that results in better emulsion injectivity, soot particles within the oil that readily promote stable emulsions, almost no cost of the oil itself and relatively large supply, and potential solution of used engine oil disposal. In this research, different types of used engine oil (mineral based, synthetic) were tested to make W/O emulsions simply by blending in brine. A series of stable emulsions was prepared with varied water contents from 40~70%. Viscosities of these emulsions were measured, ranging from 102~104 cp at low shear rates and ambient temperature. Then an emulsion made of 40% used engine oil and 60% brine was chosen for a series of coreflood experiments, to test the stability of this emulsion while flowing through porous media. Limited breakdown of the effluent was observed at ambient injection rates, indicating a stability of the emulsion in porous media. Pressure drops leveled off and remained constant at constant rate of injection, indicating steady-state flows under the experimental conditions. No plug off effect was observed after a large volume of emulsion passed through the cores. Reservoir scale simulations were conducted for the emulsion flooding process based on the emulsion properties tested from the experiments. Results showed significant improvement in both displacement pattern and oil recovery especially compared to water flooding. Economics calculations of emulsion flooding were also performed, suggesting this process to be highly profitable.

Fractured reservoirs have always been considered poor candidates for enhanced oil recovery. This can be attributed to the complexities involved in understanding and predicting performance in these reservoirs. In a fractured system, the high permeability fracture forms the preferred pathway for the injected fluids, and a large amount of oil that is stored in the matrix is bypassed. Hence, a good understanding of multiphase fluid flow in fractures is required to reduce oil bypass and increase recovery from these reservoirs. This research investigates the effect of heterogeneity and injection rates on oil bypass and also the various techniques used for the improvement of sweep efficiency in heterogeneous systems. Several coreflood experiments were performed using homogeneous and heterogeneous cores and a 4th generation X-Ray CT scanner was used to visualize heterogeneity and fluid flow in the core. Porosity and saturation measurements were made during the course of the experiment. The experimental results indicate that injection rates play a very important role in affecting the recovery process, more so in the presence of fractures. At high injection rates, faster breakthrough of CO2 and higher oil bypass were observed than at low injection rates. But very low injection rates are not attractive from an economic point of view. Hence water viscosified with a polymer was injected directly into the fracture to divert CO2 flow into the matrix and delay breakthrough, similar to the WAG process. Although the breakthrough time reduced considerably, water ??leak off?? into the matrix was very high. To counter this problem, a cross-linked gel was used in the fracture for conformance control. The gel was found to overcome ??leak off?? problems and effectively divert CO2 flow into the matrix. This experimental research will serve to increase the understanding of fluid flow and conformance control methods in fractured reservoirs.

During waterflooding, or chemical EOR processes with polymers, fractures are frequently generated in injectors. This can have a profound impact on the process performance and reservoir management. A fracture growth model was developed and linked to a reservoir simulator that incorporates the effect of (i) particle plugging due to filtration of solids and oil droplets in the injected fluids; (ii) non-Newtonian polymer rheology (shear-thinning and -thickening) for polymer injection; and (iii) thermal stresses induced by cold water injection. Dynamic fracture growth, which results from the pore pressure increase due to particle plugging or complex polymer rheology, affects the well injectivity and reservoir sweep significantly. With the fracture growth model, simulations can be made not only to make more accurate reservoir sweep and oil recovery predictions, but also to help identify well patterns that may improve reservoir performance. In homogeneous reservoirs, the injectivity is significantly affected by the propagation of an injection induced fracture; but the ultimate oil recovery and reservoir sweep are relatively unaffected. In multi-layered reservoirs, however, reservoir sweep and oil recovery are impacted significantly by the fracture growth. The oil recovery results from our fracture growth model differ substantially from those obtained based on the assumption of no fracture generation or a static fracture. For polymer injection processes, the shear rate dependence of the polymer viscosity is critical in determining the injectivity, fracture growth, and oil recovery. In addition to vertical injection well fractures, horizontal injection well fractures have been simulated by using the fracture growth model. The reservoir stress distribution determines the fracture orientation near a horizontal well. When the minimum horizontal stress orientation is perpendicular to the horizontal injector, a longitudinal fracture is generated, while with the minimum horizontal stress orientation parallel to the injector, a transverse fracture is developed. The impact of static and dynamic transverse/longitudinal fractures on well injectivity and reservoir sweep has been investigated. The impacts of (i) lengths of horizontal injector and producer; (ii) location of water oil contact; (iii) sizes of transverse and longitudinal fractures; (iv) particle concentration in the water, were further investigated. The well injectivity model was validated successfully by history matching injection of water (with particles) and shear rate dependent polymer injection. The history match was performed by adjusting the effective particle concentration in the injected water or the shear rate dependent polymer rheology. Based on history matching the long-term injection rates and pressures, estimates of the fracture length were made. These fracture dimensions could not be independently measured and verified. Based on the simulation results recommendations were made for strategies for drilling well patterns, water quality and injection rates that will lead to better oil recovery. / text

CO₂ enhanced oil recovery (CO₂-EOR) in residual oil zones has emerged as a viable technique to maximize both the oil production and carbon storage. Most CO₂ field projects suffer from inadequate sweep because of high mobility of CO₂ compared to the oil. Gas conformance techniques have the potential to further improve the effectiveness of CO₂-EOR projects. The choice of mobility control to improve the sweep efficiency is critical and simulation studies with hysteretic relative permeability and mechanistic foam model can assist in the choice of technique and optimization of the process for each reservoir. Two promising mobility control practices of Water Alternating Gas (WAG) and foam are evaluated using the in-house compositional gas reservoir simulator (DOE-CO₂). The effect of hysteresis and cycle dependent relative permeability on WAG and foam injections incorporating a new three-phase hysteresis model has been investigated. Simulations are performed with and without hysteresis to assess the impact of the saturation history and saturation path on gas entrapment, fluid injectivity and oil recovery. The foam assisted technique in CO₂-EOR processes has also been investigated. Here foam is generated in-situ by injecting surfactant solution with CO₂ rather than directly injecting foam. A simplified yet mechanistic population-balance model implemented in the in-house simulator has been applied to test the impact of foam. The results have been compared with an empirical foam model which is the standard model in commercial simulators. Simulations have been performed on actual field models for selection and optimization of the CO₂ injection scheme, quantifying the impact of hysteresis, depicting the effectiveness of CO₂-EOR process as against a surfactant flood, the effectiveness of foam assisted floods and insights into low tension gas flooding process. All the above analyses have also been performed on layer cake models with properties replicating the Permian Basin carbonate reservoirs and Gulf Coast sandstone reservoirs. Hysteresis shows an improvement in oil recovery of gas injection schemes where flow reversal takes place. Foam has been found to be effective and the models show lower CO₂ utilizations factors compared to the case without foam. / text

Made available in DSpace on 2014-12-17T15:42:03Z (GMT). No. of bitstreams: 1 EwertonRFT_DISSERT.pdf: 4228292 bytes, checksum: 8fb23445cdaa1e3bfe9b7d317ec439df (MD5) Previous issue date: 2012-10-19 / Coordena??o de Aperfei?oamento de Pessoal de N?vel Superior / This work aims to study the influence of two additives, the monomer, acrylamide and its polymer, polyacrylamide, solubilized in microemulsion systems and applied on enhanced oil recovery. By the microemulsion system obtained, it was chosen points into the phase diagram, presenting these compositions: 25%, 30%, 35% C/T; 2% Fo (fixed for all points) e 73%, 68% e 63% Fa, respectively. However, the monomer and the polymer were solubilized in these microemulsion points with 0.1%; 0.5%; 1% e 2% of concentration, ordering to check the concentration influence at the physicochemical properties (surface tension and rheology) of the microemulsion. Through the salinity study, was possible to observe that the concentrations of 1% and 2% of polymer made the solution became blurred, accordingly, the study of surface tension and rheology only was made for the concentrations of 0.1% e 0.5% of monomer and polymer, respectively. By the surface tension study it was observed that how the concentration of active matter (C/T) was increasing the surface tension was amending for each system, with or without additives. In the rheology study, as it increases the concentration of active matter increases both the viscosity of the microemulsion system (SME) with no additive, as the SME with polymer (AD2). After the entire study, it was chosen the lower point of active matter (25% C/T; 2% Fo e 73% Fa), plus additives in concentrations of 0.1% and 0.5% to be used on enhanced oil recovery. Assays were made on sandstone from Botucatu Formation, where after the tests, it was concluded that among the studied points, the point who showed the best efficiency of advanced shift was the microemulsion system + 0.5% AD2, with a recovery of 28% of oil in place and a total of 96,49%, while the other solution with 0.5% of polymer presented the worst result, with 14.1% of oil in place and 67,39% of efficiency of total displacement / Este trabalho tem como objetivo estudar a influ?ncia de dois aditivos, a acrilamida e seu pol?mero, poliacrilamida, solubilizados em sistemas microemulsionados e aplicados na recupera??o avan?ada de petr?leo. Atrav?s da obten??o do sistema microemulsionado, foram escolhidos pontos do diagrama de fases apresentando as seguintes composi??es: 25%, 30%, 35% C/T; 2% Fo (fixa para todos os pontos) e 73%, 68% e 63% Fa, respectivamente. O mon?mero e o pol?mero foram solubilizados nestes pontos de microemuls?o nas concentra??es de 0,1%; 0,5%; 1% e 2%, visando verificar a influ?ncia da concentra??o nas propriedades f?sico-qu?micas (tens?o superficial e reologia) da microemuls?o. Atrav?s do estudo de salinidade, foi poss?vel observar que as concentra??es 1% e 2% de pol?mero turvaram a microemuls?o, portanto, o estudo de tens?o e reologia foi realizado para as concentra??es 0,1% e 0,5% de mon?mero e pol?mero, respectivamente. Atrav?s do estudo de tens?o superficial observou-se que ? medida que aumenta a concentra??o de mat?ria ativa (C/T) altera a tens?o superficial para ambos sistemas com e sem aditivos. No estudo de reologia, ? medida que aumenta a concentra??o de mat?ria ativa, aumenta tanto a viscosidade do sistema microemulsionado (SME) sem aditivo, quanto o SME com pol?mero (AD2). Ap?s esse estudo, foi selecionado o ponto de menor concentra??o de mat?ria ativa (25% C/T; 2% Fo e 73% Fa) acrescido dos aditivos nas concentra??es 0,1% e 0,5% para serem utilizados na recupera??o avan?ada de petr?leo. Os ensaios foram realizados em arenitos da forma??o Botucatu, onde, ap?s terem sido realizados os testes, concluiu-se que dentre os pontos estudados, o que apresentou a melhor efici?ncia de deslocamento avan?ada foi o sistema microemulsionado + 0,5% de poliacrilamida (AD2), com uma recupera??o de 28% de ?leo in place e total de 96,49%, que ao ser comparada a solu??o de 0,5% do mesmo pol?mero apresentou recupera??o avan?ada de 14,1% de ?leo in place e 67,39% de efici?ncia de deslocamento total. A realiza??o deste trabalho mostrou que a utiliza??o de pol?meros em sistemas microemulsionado aparece como uma alternativa vi?vel na recupera??o avan?ada de petr?leo

A limited number of laboratory studies and pilot programs have been reported in chemical Enhanced Oil Recovery (EOR) flooding of carbonate reservoirs (Adams & Schievelbein, 1987). Fewer still have involved surfactants in limestone reservoirs. No surfactant/polymer flood on a field wide basis of a carbonate reservoir has ever been documented in the literature (Manrique, Muci, & Gurfinkel, 2010). This void represents a colossal opportunity given that nearly a third of the 32 billion barrels of oil consumed in the world each year come from carbonate reservoirs (Sheng, 2011, pp. 1, 254). This thesis is based on experiments with a high hardness (~5,000 ppm divalent ions) carbonate field. Phase behavior, aqueous stability, and core flood experiments were performed using polymer and various surfactants and co-solvents. Both commercially available and laboratory synthesized surfactants were tested. The objective was to optimize the chemical injection design in order to lower interfacial tension between water and oil in the reservoir. Research was also done with alkali intended for use with hard brines. The main challenges when working with hard brine were poor solubilization and low aqueous stability limits. However, highly propoxylated and ethoxylated surfactants mixed with internal olefin sulfonates, hydrophilic sulfates, and sec-butanol were observed to have very high solubilization ratios, fast phase behavior equilibration times, negligible viscous macroemulsion effects, and excellent aqueous stability. Spinning drop interfacial tensiometer tests confirmed low IFT values were obtained for a range of acceptable salinities with hard brine. Three core floods were performed using one of the surfactant formulations developed. One flood was done with field core, brine, and crude oil and failed to meet expectations because of high levels of heterogeneity (vugs) within the core that lead to an elongated oil bank and low and slow oil recovery. The other floods were done with Estillades Limestone. The first Estillades flood used hard synthetic field brine and had better mobility but poor oil recovery. The last core flood had good mobility and recovered 90% of the residual oil to water flooding, but only after a total of 1.1 pore volumes of 1.0 wt% surfactant solution were injected. The results provided in this thesis constitute proof of concept that S/P flooding can be done in high salinity and hardness reservoirs. / text

This paper establishes Low-Tension-Gas (LTG) as a method for sub-miscible tertiary recovery in tight sandstone and carbonate reservoirs. The LTG process involves the use of a low foam quality surfactant-gas solution to mobilize and then displace residual crude after waterflood. It replicates the existing Alkali-Surfactant-Polymer (ASP) process in its creation of an ultra-low oil-water interfacial tension (IFT) environment for oil mobilization, but instead supplements the use of foam over polymer for mobility control. By replacing polymer with foam, chemical Enhanced Oil Recovery (EOR) methods can be expanded into sub-30 mD formations where polymer is impractical due to plugging, shear, or the requirement to use a low molecular weight polymer. Overall results indicate favorable mobilization and displacement of residual crude oil in both tight carbonate and tight sandstone reservoirs. Tertiary recovery of 75-95% ROIP was achieved for cores with 2-15 mD permeability, with similar oil bank and other ASP analogous process attributes observed. Moreover, similar recovery was achieved during testing at high initial oil saturation (56%), indicating high process tolerance to oil saturation and potential application for implementation at secondary recovery. In addition, a number of tools and relations were developed to improve the predictive relationship between observed coreflood properties and actual mobilization or displacement mechanisms which impact reservoir-scale flooding. These relations include qualitative dispersion comparison and calculation of in-situ gas saturation, macroscopic mobility ratio at the displacement fronts, and apparent viscosity of injected fluids. These tools were validated through use of reference gas and surfactant floods and indicate that stable macroscopic displacement can be achieved through LTG flooding in tight formations. Furthermore, to better reflect actual reservoir conditions where localized fractional flow of gas can vary substantially depending on mixing or gravity phenomenon, two additional sets of data were developed to empirically model behavior. Through testing of LTG co-injection at a number of discrete fractional flow values over a wide range, recovery was shown to achieve a relative maximum at 50% gas fractional flow which also corresponded with optimal observed mobility control as measured by the previously established tools. Likewise, through testing of surfactant-alternating-gas (SAG) injection cycling, displacement and overall recovery were shown to be improved versus reference co-injection flooding. Finally, by comparing the observed displacement and mobility data among co-injection and surfactant-alternating-gas floods, a new displacement mechanism is introduced to better relate actual displacement conditions with observed macroscopic mobility data. This mechanism emphasizes the role of liquid rate in actual displacement processes and a mostly static gas saturation (independent of gas rate) in altering liquid relative permeability and diverting injected liquid into lower permeability zones. / text