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This thesis charts the evolution of citizenship and immigration policy in Britain between 1945 and 1962. These years were marked by the movement of small but growing numbers of British citizens and British subjects, Black and Asian, to Britain. At the start of this period, British subjects from the colonies and Commonwealth, in theory, had the freedom to enter and settle in Britain without obstruction. The British Nationality Act of 1948 reaffirmed this freedom. It introduced a definition of British citizenship which included British-born and colonial-born subjects in the same category, and recognised citizens of independent Commonwealth countries as British subjects. The passage of the Commonwealth Immigrants Act of 1962 marked the end of this period. This piece of legislation placed formal restrictions on the entry of certain categories of British citizen and subject for the first time. The primary intention of the Act of 1962 was to frustrate the ability of dark-skinned British and Commonwealth citizens freely to enter and settle in Britain. This project examines why, in the years between 1945 and 1962, Britain's citizenship and immigration policy evolved in this direction. It asks questions about how 'open' entry to Britain actually was before 1962 and demonstrates the subtle and surprising ways in which this freedom was illusory. This dissertation challenges both the temporal and analytical framework of analysis persistent in existing studies. It does so by examining the evolution of British citizenship and immigration policy between 1945 and 1962 through a wider, and longer, lens. It will consider citizenship and immigration policy in more expansive terms, thinking beyond merely the legislative sphere. It also aims to situate these policy developments within their broader imperial and global context, and as part of a longstanding framework of controls on the entry and settlement of non-white British subjects from the colonies.

Various enhanced oil recovery methods (EOR) suffer from poor sweep efficiency due to viscous fingering, channeling, and gravity segregation issues. The water-alternating-gas method (WAG) used in the Al-Shaheen’s Shuaiba reservoir has encountered similar problems, whereby injected gas preferentially flows into higher permeability zones and sweep efficiency is impacted. The goal of this research work was to develop an effective, and economically viable foam system that can utilize waste gas in the Al-Shaheen reservoir as a mobility control solution. This research focused on an optimized surfactant formulation that can generate foam with methane gas at the reservoir conditions in the presence of oil and an oil wet/mixed wet rock. The formulation was tested in water wet and oil wet core flood experiments. Enhancements to the formulation were tested and their improvement to the foam strength was quantified. An anionic surfactant group alkyl-polyglycoside (APG) was first chosen through screening experiments. The bulk foam stability was then evaluated with and without oil presence and showed APG-5 as the best among the APGs. Its adsorption to carbonate Estaillades limestone was estimated around 2.5 mg/g of rock at 55 °C and the reservoir brine salinity of 144,000 ppm. Core flood experiments revealed that a concentration of 3500 ppm is required to achieve strong foam. The foam rheology of APG-5 and methane gas was found to be shear thinning. The ideal foam quality resulting in the strongest foam was found to be between 30 and 50 %. The impact of oil on the APG-5 foam was studied, and found to produce effective foam in presence of residual oil in water wet cores and oil wet cores, with mobility reduction factor (MRF) values of 28 for the former and 24 for the latter. It was also shown through mobile oil experiments that foam can develop even in presence of mobile oil. Oil wet environments were shown to have weaker foams. The use of a wettability altering agent TGT-1 improved the foam propagation and steady state strength. MRF values of ~ 47 were achieved, an increase of 150%. A foam booster (Lauryl Betaine) was tested and found to enhance the propagation and steady state strength of the foam with MRF values of 52. Combining the wettability alteration, and foam boosting in a final formulation achieved and MRF of 85

Mobility control is essential for successful improved or enhanced oil recovery process and can be achieved by injecting a fluid with ideal rheological properties. In water sensitive reservoirs where the use of conventional water-based fluids are impractical, oil-based fluids are a promising alternative. Natural gas liquid (NGL) has become an increasing attractive base fluid for mobility control applications. However, the challenges related to the poor mobility of the fluid resulting from its low density and viscosity must be overcome. Directly or indirectly thickening are promising techniques that modify the rheological properties of NGL to improve fluid mobility. A three-task plan was developed to investigate the direct rheological modification of NGL and characterize these properties in bulk and porous media. The solubility of the chemical additives was investigated in different solvents to represent NGL, including n-hexane and n-pentane. Next, the bulk rheology experiments were conducted to determine the impact of additive concentration, effect of temperature, hysteresis, and NGL composition to properly characterize the rheological properties of the thickened fluid. The third task considered the characterization of thickened fluid in porous media and determine if there was a correlation between bulk and apparent viscosity. An additive was identified that was successful in thickening both n-hexane and n-pentane significantly at additive concentrations as low as 0.25 wt.% at shear rates ranging from 1 s⁻¹ to 2500 s⁻¹⁻. The experiments in porous media combined with bulk viscosity measurements indicated that the sand-pack possibly acted as a natural method of mixing that aided in the viscosity enhancement of the fluid and the formations of macrostructures. Indirect thickening involves foaming the oil-based fluid. The experimental design to test the foaming surfactants involved a two-part additive screening. The additives were investigated in a single hydrocarbon fluid to determine their foaming potential. The additives were then tested in a multiple hydrocarbon system to determine if the addition of a secondary component may promote foamability or stability. Foaming additives were identified that stabilized foam in 100% diesel during the initial screening. Select additives were also successful in promoting foamability and stability in a n-pentane and crude oil mixture

Mobility control mechanisms are key to the success of any enhanced oil recovery processes due to their ability to provide favorable mobility ratio of the injected fluids, thus improving the sweep efficiency during the process. This work is focused on developing effective mobility control mechanisms in challenging carbonate reservoirs that are typically high temperature and high salinity and low permeability formations. The first half of the dissertation is focused on investigating novel foam technology using anionic and cationic surfactants to improve the gas enhanced oil recovery process. Typically, gas injection processes suffer from poor volumetric sweep efficiency due to viscous fingering, channeling, and gravity override. Foam helps to improve the sweep efficiency of the gas floods significantly by reducing the mobility of the gas by orders of magnitude, blocking the high permeability channels and diverting fluids to the bypassed lower permeability channels. Carbonate reservoirs, which are typically oil-wet heterogeneous and low permeability, pose additional challenges for an effective foam EOR process. Crude oils destabilize foam rapidly and the thin oil film on oil-wet rock surfaces makes in-situ foam generation difficult as well. Hence, wettability alteration from oil-wet to water-wet using a surfactant was one of the necessary mechanisms for in-situ foam stability. Low permeability of the carbonates makes strong foam generation challenging due to higher entry capillary pressure in small pore throats that exceeds the critical capillary pressures usually. On the other hand, low interfacial tensions (IFT) of the surfactant formulations helps to lower the entry pressure and stabilize the foam better. This work demonstrated the benefits of two different chemical systems – one that includes use of anionic surfactants for low IFT formulations and the other that includes blends of cationic, non-ionic and zwitterionic surfactants for non low IFT formulations in combination with wettability alteration and foaming to improve oil recovery in oil-wet carbonates after a secondary gas flood process. The second half of the dissertation is focused on developing a novel polymer treatment protocol for successful injection in low permeability carbonate reservoirs through mechanical shear degradation and aggressive filtration tests. The behavior of shear degradation of high molecular weight polymers of different chemistry in varying brine salinities performed with a laboratory blender at a constant speed and varying shearing times followed an exponential decay until a steady state was obtained. Master curves for degraded viscosity predictions were developed to estimate the degraded viscosity of any given polymer in any brine salinity at any given shearing time, given the shearing speed was kept constant. A superimposed master curve for the degradation for all kinds of polymers investigated was established to predict the rate of degradation at any given time. A robust approach of comparison of polymer size distribution from dynamic light scattering (DLS) method and pore throat distribution from mercury injection capillary pressure (MICP) was established for injection qualification of high molecular weight polymers in low permeability carbonates. A novel class of hydrophobically modified acrylamides, also known as associative polymers, were investigated as an alternative to conventional HPAMs and synthetic polymers for injection in low permeability carbonates. The thermo-thickening properties of the associative polymers at elevated temperatures and salinities (with high divalent ions) and higher resistance to shear degradation makes them promising for carbonate reservoirs in comparison to HPAMs, where high polymer dosages are required due to significant viscosity loss in shear degradation. The apparent high viscosities generated from high resistance factors during flow in porous media for associative polymers can be advantageous for optimization of polymer dosage in chemical EOR processes. This work demonstrated a significant potential for application of associative polymers as an effective mobility control agent in carbonate reservoirs, especially in low permeability formations. The novel polymer treatment method for low permeability reservoirs was combined with the development of alkaline-surfactant-polymer (ASP) and surfactant-polymer (SP) technology for improvement of oil recovery in carbonates. The successful polymer transport in low permeability carbonates showed great potential for application of chemical EOR processes like ASP and SP in tight formations. Development of robust SP technology for high temperature and high salinity reservoirs also showed promising results in phase behavior experiments and coreflood experiments. This work demonstrated the benefits of SP technology with optimization of surfactant formulation and coreflood design for lower surfactant retention and higher oil recovery, thus making the process economical

Chemical enhanced oil recovery (EOR) in carbonate reservoirs is a technically and economically challenging process. Low-Tension Gas flooding is developed as an attractive alternative to conventional EOR methods for application in low permeability and high salinity formations, especially in the presence of divalent cations. The process of Low-Tension Gas (LTG) flooding has been investigated on the laboratory scale as a tertiary and secondary recovery process for a low permeability (

In naturally fractured reservoirs, water flood performance and efficiency for oil recovery is usually limited by capillary forces. Wettability and interfacial tension (IFT) between oil and water phases are essential factors that limit the potential for oil production in naturally fractured reservoirs. The permeability of such reservoirs is in range of 1~20 md (majority of carbonate reservoirs) with the matrix wettability preferentially oil-wet to mixed-wet. Hence, water and/or gas flood performances are not efficient due to the tendency of water or gas flow through fractures. Surfactants are used to reduce IFT between oil and water, alter the wettability of matrix to proficiently water-wet, and generate in-situ foam as a drive and for mobility control. Spontaneous imbibition between the fractures and the matrix is achieved by both wettability alteration and ultra-low interfacial tensions. Experimental studies show that co-injection or alternate injection of surfactant solution and gas are very promising to mobilize and solubilize the remaining oil. In this study, we overview to provide a technical background and review the literature extensively in order to understand surfactant flooding and foam performance in porous media. Results show that surfactants are induced to matrix through fractures not only by spontaneous imbibition, but also by foam that diverts surfactant solutions into low permeability matrix. The finding results by several authors in lab-scale indicate that surfactant type, foam properties, capillary pressure properties corresponding to different wetting states, and oil-water interfacial tension are crucial factors that significantly impact the efficiency of such processes. In general, summary of this work shows that foam plays a dominant role as a drive to displace the oil in matrix when capillary forces are not strong to retain the oil in presence of surfactants. Although there is very restricted work that claim foam efficiency in presence of oil, mobilized oils are displaced and moved toward fractures as pure oil bank (oil phase). Some laboratory measurements and simulation study reveal with both core and reservoir scales that such process provides great sweep efficiency and recover a significant amount of remaining oil from the matrix to fracture.

Fines migration is considered one of the mechanisms of permeability alteration associated with water injection in aquifers and oil reservoirs. Numerous studies have argued fines migration as a mobility-control enhanced oil recovery (EOR) mechanism during low-salinity waterflooding (LSW). However, enhanced oil recovery by LSW has been shown to result from the combined effect of various mechanisms. The dependence of oil recovery on fines migration remains unclear. The purpose of this thesis is: (1) to present the conclusive evidence for fines migration and (2) to investigate oil recovery mechanisms associated with fines migration during low-salinity waterflooding. In this thesis, laboratory experiments were designed to render inactive all but the fines migration mechanism. Then, waterflooding results and detailed characterizations of core plugs and produced fluids were used to analyse fines migration-induced formation damage and retention effects on displacement efficiency. Single-phase and two-phase flow experiments were performed on Berea and Obernkirchener sandstones. In the single-phase experiments, core plugs were subjected to waterflooding with monotonically reducing salinities from 40 to 0 g/L NaCl. 80% to 99% decrease in permeability was observed, which were accompanied by large concentration of fines in the produced-water samples. Scanning Electron Microscope (SEM) images of the pores before and after injection showed fines retention and blockage. Produced fines were analysed using SEM integrated with Energy Dispersive X-ray Spectroscopy (SEM-EDS), analysis shows that clay particles were produced during LSW. Micro-CT images were taken and Nuclear Magnetic Resonance (NMR) responses were recorded before and after the single-phase experiments. Micro-CT analysis and NMR responses support the fines migration. Micro-CT images show that clay fines were strained near the core outlet of the core plug. There were three two-phase LSW experiments performed in total. In all of these two-phase LSW experiments, clay migration results were consistent with those of single-phase LSW experiments. Furthermore, the two-phase experiments showed 50% reduction in water relative permeability after LSW. Two out of the three experiments show 3% higher oil recovery in LSW than high-salinity waterflooding. Because no other mechanism was active, the increase in oil recovery was solely a result of enhanced displacement due to fines migration. However, one of the two-phase experiments showed 16% lower oil recovery in LSW than high-salinity waterflooding. It is suggested that mobilized fines caused blockage which restricted the direct contact between oil and water. More experiments are needed to find out conditions under which LSW has positive effect on oil recovery.

The objective of this research was to investigate the effects of viscous forces on the oil recovery during surfactant flooding of fractured carbonate cores, specifically, to test the effects of using surfactants that form viscous microemulsions in-situ. The hypothesis was that a viscous microemulsion flowing inside a fracture can induce transverse pressure gradients that increase fluid crossflow between the fracture and the matrix, thus, enhancing the rate of surfactant imbibition and thereby the oil recovery. Previous experimentalists assumed the small viscous forces were not important for oil recovery from naturally fractured reservoirs (NFRs) since the pressure gradients that can be established are very modest due to the presence of the highly conductive fractures. Hence, the most common approach for studying surfactants for oil recovery from NFRs is to perform static imbibition experiments that do not provide data on the very important viscous and pressure forces. This is the first experimental study of the effect of viscous forces on the performance of surfactant floods of fractured carbonate cores under dynamic conditions. The effects of viscous forces on the oil recovery during surfactant flooding of fractured carbonate cores were tested by conducting a series of ultralow interfacial tension (IFT) surfactant floods using fractured Silurian Dolomite and Texas Cream Limestone cores. The viscosity of the surfactant solution was increased by adding polymer to the surfactant solution or by changing the salinity of the aqueous surfactant solution, which affects the in-situ microemulsion viscosity. The fractured cores had an extreme permeability contrast between the fracture and the matrix (ranging from 2500 to 90,000) so as to represent typical conditions encountered in most naturally fractured reservoirs. Also, non-fractured corefloods were performed in cores of each rock type for comparison with the results from the fractured corefloods. In all the experiments, the more viscous surfactants solutions achieved the greater oil recovery from the fractured carbonate cores which contradicts conventional wisdom. A new approach for surfactant flooding of naturally fractured reservoirs is presented. The new approach consists of using a surfactant solution that achieves ultralow IFT and that forms a viscous microemulsion. A viscous microemulsion can serve as a mobility control agent analogous to mobility control with foams or polymer but with far less complexity and cost. The oil recovery from the fractured carbonate cores was greater for the surfactant floods with the higher microemulsions, thus, it is expected that using viscous microemulsion can enhance the oil recovery from naturally fractured reservoirs.

Since a significant portion of the world's oil reserves resides in naturally fractured reservoirs (NFR), it is important to maximize oil production from these reservoirs. Mobility control EOR techniques, such as water alternating gas (WAG) and foam injection, may be used in NFRs to improve oil recovery. Foam injection may be modeled by empirical or mechanistic models, the latter being capable of representing foam generation and coalescence effects. Numerical models are needed to evaluate EOR techniques in NFR. The Embedded Discrete Fracture Model (EDFM) is capable of representing conductive faults or fractures and describing NFR and unconventional reservoirs as a triple porosity medium (hydraulic fractures, natural fractures, and matrix). This work aims at developing a general EDFM framework to allow the evaluation of different mobility control EOR methods in NFR. The mobility control EOR methods evaluated were the WAG and continuous foam injection. The formulation used to evaluate mobility control by foam injection in NFR was the population balance assuming local equilibrium and the Pc* models. Nanoparticle transport models (Two Site and Two Rate models) were implemented and validated to allow simulation of nanoparticle stabilized foam injection. An EDFM preprocessor was further developed and validated against the in-house fully implicit simulator, unstructured grid models from the literature and fine-grid models using a commercial simulator. Simulation run time was reduced by applying a porosity cut-off in the fracture cells assuming constant fracture conductivity. Validation case studies included multi-fractured wells producing through depletion and a 2D quarter five-spot production scheme (water and miscible gas injection) in NFR. We obtained a good agreement between EDFM, unstructured grid, and fine-grid models. Application case studies included 3D models under water, miscible gas and WAG injection, which confirmed the efficiency of the EDFM in modeling complex fracture networks. We used the EDFM to simulate multilateral well stimulation and we performed an automated history matching of the production data of a field test. The foam model and the nanoparticle transport models were validated against experimental data from the literature. It is concluded that the effect of fractures on hydrocarbon production depends on fracture network connectivity, which may be modeled using the EDFM preprocessor. Simulation results using mobility control EOR methods show considerable improvements in oil recovery due to a postponement in gas breakthrough.

A major portion of the oil across the world is contained in carbonate reservoirs. Most of the carbonate reservoirs are typically oil-wet or mixed-wet, hence water-flooding processes have low oil recovery. Hence the most common mechanisms applied to increase the recovery are through wettability alteration and ultra-low interfacial tension (IFT) formulations with the addition of surfactants, or gas injection to have immiscible and miscible displacement processes, or combination of these processes. Secondary immiscible gas floods have been applied for several years in carbonate reservoirs and the typical recovery is found to be around 35-40% OOIP. The problems associated with many gas injection processes are the inefficient gas utilization, poor sweep efficiency, and low incremental oil recovery due to viscous instability (channeling or fingering) and gravity segregation. These are mainly caused by rock heterogeneity as well as the low density and viscosity of the injected gas. To address these drawbacks foam can be injected into the oil reservoir by co-injection of surfactant solution and gas, or by surfactant-alternating-gas (SAG) mode. The strategy implemented here is to inject a surfactant that causes wettability alteration or ultra-low IFT to recover additional oil followed by gas injection which helps in generation of foam and provides mobility control to achieve better sweep efficiency. The main objective of this research is to study the effect of slug size variation on oil recovery in surfactant-alternating-gas (SAG) processes for carbonate rocks using a wettability alteration anionic surfactant solution. The bulk foam stability in the presence and absence of the crude oil were studied for several surfactants. In addition, phase behavior studies and wettability alteration experiments were performed with the crude oil to screen the surfactant solutions. A propoxy sulfate surfactant, Alfoterra (0.5 wt%) was found to be optimal for these studies. Coreflood experiments in the absence of oil were performed in outcrop Texas Cream limestone rocks to measure the apparent foam viscosity and single phase pressure drop in presence of 80% quality foam, in comparison to 80% quality gas-brine co-injection as a base case. The resistance factor (measured as the ratio of pressure drop with foam and without foam) was found to be 3.5. Coreflood experiments with surfactant-alternating-gas (SAG) mode were performed in oil aged reservoir limestone rocks and outcrop carbonate rocks using Alfoterra (0.5 wt%). The coreflood experiments with a single slug of 0.5 PV surfactant solution showed additional oil recovery of about 25% OOIP in the outcrop rock. The average pressure drop during the experiment was in the range of 5-15 psi. The coreflood experiments with limestone rocks from a reservoir showed an additional oil recovery of about 25% OOIP for 0.1 PV slug size and smaller slug size injection of 0.05 PV showed an additional oil recovery of about 28% OOIP. The average pressure drop recorded was comparatively higher in the range of 40-60 psi for smaller slug sixe injection. Smaller slug size leads to higher oil recovery. The dynamic adsorption measured for Alf S23-7S-90 (S1) in Texas Cream limestone rock was found to be about 0.112 mg/gm of rock.

Hybrid gas/chemical Enhanced Oil Recovery (EOR) methods are such novel techniques to increase oil production and oil recovery efficiency. Gas flooding using carbon dioxide, nitrogen, flue gas, and enriched natural gas produce more oil from the reservoirs by channeling gas into previously by-passed areas. Surfactant flooding can recover trapped oil by reducing the interfacial tension between oil and water phases. Hybrid gas/chemical EOR methods benefit from using both chemical and gas flooding. In hybrid gas/chemical EOR processes, surfactant solution is injected with gas during low-tension-gas or foam flooding. Polymer solution can also be injected alternatively with gas to improve the gas volumetric sweep efficiency. Most fundamentally, wide applications of hybrid gas/chemical processes are limited due to uncertainties in reservoir characterization and heterogeneity, due to the lack of understanding of the process and consequently lack of a predictive reservoir simulator to mechanistically model the process. Without a reliable simulator, built on mechanisms determined in the laboratory, promising field candidates cannot be identified in advance nor can process performance be optimized. In this research, UTCHEM was modified to model four-phase water, oil, microemulsion, and gas phases to simulate and interpret chemical EOR processes including free and/or solution gas. We coupled the black-oil model for water/oil/gas equilibrium with microemulsion phase behavior model through a new approach. Four-phase fluid properties, relative permeability, and capillary pressure were developed and implemented. The mass conservation equation was solved for total volumetric concentration of each component at standard conditions and pressure equation was derived for both saturated and undersaturated PVT conditions. To model foam flow in porous media, comprehensive research was performed comparing capabilities and limitations of implicit texture (IT) and population-balance (PB) foam models. Dimensionless foam bubble density was defined in IT models to derive explicitly the foam-coalescence-rate function in these models. Results showed that each of the IT models examined was equivalent to the LE formulation of a population-balance model with a lamella-destruction function that increased abruptly in the vicinity of the limiting capillary pressure, as in current population-balance models. Foam models were incorporated in UTCHEM to model low-tension-gas and foam flow processes in laboratory and field scales. The modified UTCEM reservoir simulator was used to history match published low-tension-gas and foam coreflood experiments. The simulations were also extended to model and evaluate hybrid gas/chemical EOR methods in field scales. Simulation results indicated a well-designed low-tension-gas flooding has the potential to recover the trapped oil where foam provides mobility control during surfactant and surfactant-alkaline flooding in reservoirs with very low permeability.

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.

Foam reduces gas mobility in porous media by trapping substantial amount of gas and applying a viscous resistance of flowing lamellas to gas flow. In mechanistic foam modeling, gas relative permeability is significantly modified by gas trapping, while an effective gas viscosity, which is a function of flowing lamella density, is assigned to flowing gas. A complete understanding of foam mobility in porous media requires being able to predict the effects of pressure gradient, foam texture, rock and fluid properties on gas trapping, and therefore gas relative permeability, and effective gas viscosity. In the foam literature, separating the contributions of gas trapping and effective gas viscosity on foam mobility has not been achieved because the dynamics of gas trapping and its effects on the effective gas viscosity have been neglected. In this study, dynamics of foam mobility in porous media is investigated with a special focus on gas trapping and its effects on gas relative permeability and effective gas viscosity. Three-dimensional pore-network models representative of real porous media coupled with fluid models characterizing a lamella flow through a pore throat are used to predict flow paths, threshold pressure gradient and Darcy velocity of foam. It is found that the threshold path and the pore volume open above the threshold pressure are independent of the fluid model used in this study. Furthermore, analytical correlations of flowing gas fraction as functions of pressure gradient, lamella density, rock and fluid properties are obtained. At a constant pressure gradient, flowing gas fraction increases as overall lamella density decreases. In the discontinuous-gas foam flow regime, there exists a threshold pressure gradient, which increases with overall lamella density. One of the important findings of this study is that gas relative permeability is a strong non-linear function of flowing gas fraction, opposing most of the existing theoretical models. However, the shape of the relative gas permeability curve is poorly sensitive to overall lamella density. Flowing and trapped lamella densities change with pressure gradient. Moreover, analytical correlations of effective gas viscosity as functions of capillary number, lamella density and rock properties are obtained by up-scaling a commonly used pore-scale apparent gas (lamella) viscosity model. Effective gas viscosity increases nonlinearly with flowing lamella density, which opposes to the existing linear foam viscosity models. In addition, the individual contributions of gas trapping and effective gas viscosity on foam mobility are quantified for the first time. The functional relationship between effective gas viscosity and flowing lamella density in the presence of dynamic trapped gas is verified. A mechanistic foam model is developed by using the analytical correlations of flowing gas fraction and effective gas viscosity generated from the pore-network study and a modified population balance model. The developed model is successful in simulating unsteady-state and steady state flow of foam through porous media. Moreover, the flow behaviors in high- and low-quality flow regimes are verified by the experimental studies in the literature. Finally, the simulation results are successfully history matched with two different core-flood data.

Carbon dioxide (CO₂) flooding is the second most common tertiary recovery technique implemented in the United States. Yet, there is huge potential to advance the process by improving the volumetric sweep efficiency of injected CO₂. Delivering CO₂ into the reservoir as a foam is one way to do this. Surfactants have traditionally been used to generate CO₂ foams for mobility control; however, the use of nanoparticles as a foam stabilizing agent provides several advantages. Surfactant-stabilized foams require constant regeneration to be effective, and the surfactant is adsorbed onto reservoir rocks and is prone to chemical degradation at harsh reservoir conditions. Nanoparticle-stabilized foams have been found to be tolerant of high temperature and high salinity environments. Their nano size also allows them to be transported through reservoir rocks without blocking pore throats. Stable CO₂-in-water foams were generated using 5 nm silica nanoparticles with a short chain polyethylene glycol surface coating. These foams were generated by the co-injection of CO₂ and a nanoparticle dispersion through both rock matrix and fractures. A threshold shear rate was found to exist for foam generation in both fractured and non-fractured Boise sandstone cores. The ability of nanoparticles to generate foams only above a threshold shear rate is advantageous; in field applications, high shear rates are associated with high permeability zones, where the presence of foam is desired. Reducing CO₂ mobility in these high permeability zones diverts CO₂ into lower permeability regions containing not yet swept oil. Nanoparticles were also found to be able to stabilize CO₂ foams by co-injection through rough-walled fractures in cement cores, demonstrating their ability to stabilize foams without matrix flow. Experiments were conducted on the ability of fly ash, a waste product from burning coal in power plants, to stabilize oil-in-water emulsions and CO₂ foams. The use of fly ash particles as a foam stabilizing agent would significantly reduce material costs for potential tertiary oil recovery and CO₂ sequestration applications. Nano-milled fly ash particles without surface treatment were able to generate stable oil-in-water emulsions when high frequency, high energy vibrations were applied to a mixture of fly ash dispersion and dodecane. Oil-in-water emulsions were also generated by co-injecting fly ash and dodecane, a low pressure analog to CO₂, through a beadpack. Emulsions generated by co-injection, however, were unstable and coalesced within an hour. A threshold shear rate was required for the emulsion generation. Fly ash particles were found to be able to stabilize CO₂ foam in a high pressure batch mixing cell, but not by co-injection through a beadpack. Dispersions of fly ash particles were found to be stable only at low salinities (

The petroleum industry has been utilizing surfactant stabilized foams for mobility control and enhanced oil recovery applications. However, if surface-treated nanoparticles were utilized instead of surfactants, the foams could have a number of important advantages. The solid-stabilized foams are known to have a much better stability than the surfactant-stabilized foams, because the energy required to bring nanoparticles to, and detach from the foam bubble surface is much larger than that of surfactants, and thus the resulting foam will be more stable. Since nanoparticles are the stabilizing component of the foam and are solid, they have potential to stabilize foam at high temperature conditions for extended periods of time. Since they are inherently small, nanoparticles, as well as the foam that they stabilize, can be transported through rocks without causing plugging in pore throats. Stable supercritical carbon dioxide-in-water foams were created using 5 nm silica-core nanoparticles whose surface had short polyethylene-glycol chains covalently bonded to it. The foams were made by injecting CO2 and an dispersion of with surface-treated nanoparticles simultaneously through a glass-bead pack. The fluids flowing through this permeable media created shear rates of about 1350 sec-1. Nanoparticle concentration, nanoparticle coating, water salinity, volume ratios between CO2 and water, temperature and shear rates were systematically varied in order to define the range of conditions for foam generation. Using de-ionized water to dilute the nanoparticle concentration, we were able to generate stable foams were at nanoparticle concentrations as low as 0.05 weight percent. Among the different surface coatings that we tested PEG coatings were the only type that was able to stabilize foam. As the salinity of the aqueous phase increased, the nanoparticle concentration required to maintain foam also increased; for example, 0.5 weight percent nanoparticles were required for 4 weight percent NaCl brine. Foam stability was weakly correlated with volume ratios as foams were made across ratios from two to fourteen, and the normalized viscosity ratio increased with the increase of the phase ratio. Foams were created at temperatures up to 95 degrees Celsius. Foam generation was also determined to require a critical shear rate, which increased with temperature. When foam was stabilized by the nanoparticles, the foam exhibited an increase of between two and twenty times in the resistance of flow compared to the two fluids flowing without nanoparticles.

Highly fractured and vuggy oil reservoirs represent a challenge for enhanced oil recovery (EOR) methods. The fractured networks provide flow paths several orders of magnitude greater than the rock matrix. Common enhanced oil recovery methods, including gases or low viscosity liquids, are used to channel through the high permeability fracture networks causing poor sweep efficiency and early breakthrough. The purpose of this research is to determine the feasibility of using foam in highly fractured reservoirs to produce oil-rich zones. Multiple surfactant formulations specifically tailored for a distinct oil type were analyzed by aqueous stability and foam stability tests. Several core floods were performed and targeted effects such as foam quality, injection rate, injection type, permeability, gas saturation, wettability, capillary pressure, diffusion, foam squeezing, oil flow, microemulsion flow and gravity segregation. Ultimately, foam was successfully propagated under various core geometries, initial conditions and injections methods. Consequently, fluids were able to divert to unswept matrix and improve the ultimate oil recovery.

Alkali-Surfactant-Polymer (ASP) or Surfactant-Polymer (SP) flooding are attractive chemical enhanced oil recovery (EOR) methods. However, some reservoir conditions are not favorable for the use of polymers or their use would not be economically attractive due to low permeability, high salinity, or some other unfavorable factors. In such conditions, gas can be an alternative to polymer for improving displacement efficiency in chemical-EOR processes. The co-injection or alternate injection of gas and chemical slug results in the formation of foam. Foam reduces the relative permeability of injected chemical solutions that form microemulsion at ultra-low interfacial tension (IFT) conditions and generates sufficient viscous pressure gradient to drive the foamed chemical slug. We have named this technique of foam assisted enhanced oil recovery as Alkali/Surfactant/Gas (ASG) process. The concept of ASG flooding as an enhanced oil recovery technique is relatively new, with very little experimental and theoretical work available on the subject. This dissertation presents a systematic study of ASG process and its potential as an EOR method. We performed a series of high performance surfactant-gas tertiary recovery corefloods on different core samples, under different rock, fluid, and process conditions. In each coreflood, foamed chemical slug was chased by foamed chemical drive. The level of mobility control in corefloods was evaluated on the basis of pressure, oil recovery, and effluent data. Several promising surfactants, with dual properties of foaming and emulsification, were identified and used in the coreflood experiments. We observed a strong synergic effect of foam and ultra-low IFT conditions on oil recovery in ASG corefloods. Oil recoveries in ASG corefloods compared reasonably well with oil recoveries in ASP corefloods, when both were conducted under similar conditions. We found that the negative salinity gradient concept, generally applied to chemical floods, compliments ASG process by increasing foam strength in displacing fluids (slug and drive). A characteristic increase in foam strength was observed, in nearly all ASG corefloods conducted in this study, as the salinity first changed from Type II(+) to Type III environment and then from Type III to Type II(-) environment. We performed foaming and gas-microemulsion flow experiments to study foam stability in different microemulsion environments encountered in chemical flooding. Results showed that foam in oil/water microemulsion (Type II(-)) is the most stable, followed by foam in Type III microemulsion. Foam stability is extremely poor (or non-existent) in water/oil microemulsion (Type II (+)). We investigated the effects of permeability, gas and liquid injection rates (injection foam quality), chemical slug size, and surfactant type on ASG process. The level of mobility control in ASG process increased with the increase in permeability; high permeability ASG corefloods resulting in higher oil recovery due to stronger foam propagation than low permeability corefloods. The displacement efficiency was found to decrease with the increase in injection foam quality. We studied the effect of pressure on ASG process by conducting corefloods at an elevated pressure of 400 psi. Pressure affects ASG process by influencing factors that control foam stability, surfactant phase behavior, and rock-fluid interactions. High solubility of carbon dioxide (CO₂) in the aqueous phase and accompanying alkali consumption by carbonic acid, which is formed when dissolved CO₂ reacts with water, reduces the displacement efficiency of the process. Due to their low solubility and less reactivity in aqueous phase, Nitrogen (N₂) forms stronger foam than CO₂. Finally, we implemented a simple model for foam flow in low-IFT microemulsion environment. The model takes into account the effect of solubilized oil on gas mobility in the presence of foam in low-IFT microemulsion environment.