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Combustion noise is relevant to current aviation, rocket, and ground-based gas turbine engines, as it contributes to environmental noise pollution and can trigger thermoacoustic instabilities. These consequences are particularly prevalent in lean, premixed, prevaporised combustors, which are designed to reduce nitrous oxide (NOx) emissions. As a result, there is a need to better understand the mechanisms that drive sound generation in such systems. There are two components to combustion noise: direct noise - generated by the unsteady heat release of a flame - and indirect noise - produced by the acceleration of entropic, vortical, or compositional inhomogeneities. Separation of the respective contributions has proven to be complex to achieve in real engines - for this purpose, model experiments have been developed. These are non-reacting experiments that use unsteady, synthetic perturbations to emulate the fundamental physics of combustion acoustics processes and provide clear data for comparison with theory. Indirect noise models have been theorised for compositional perturbations and experimental validation has been provided via the measurement of acoustic waves (i.e. the output), while assuming a constant compositional perturbation (i.e. the input). This thesis follows on from such experiments by simultaneously measuring both acoustic and compositional waves in a model setup, making use of numerical, analytical, and experimental studies. It first builds upon a previous model experiment through a numerical investigation on the generation, mixing, and convection of entropic and compositional waves generated by heat addition and gas injection. The computed temperature and mass fraction fields are compared with experimental results and inform the design of a new model setup - the Canonical Wave Rig (CWR). The CWR is then used to study direct and indirect noise under simplified, well-controlled conditions. Subsonic and sonic (choked) conditions are investigated for a convergent-divergent nozzle. Acoustic, entropic, and compositional perturbations are generated via the co-flow injection of air or methane into a low Mach number mean flow of air. Spontaneous Raman spectroscopy (1.5 kHz) is employed for the time-resolved measurement of the local concentration upstream of the nozzle. Single pulse experiments in the infra-sound range are used to validate the derived analytical model for direct noise due to co-flow injection. The measurement of non-reverberated indirect noise is made for the first time and is contrasted with results obtained via dereverberation (i.e. removing the effect of pressure build up due to acoustic reflections). Indirect noise transfer functions are calculated using the acoustic and compositional measurements, and issues pertaining to the methods applied are highlighted. Lastly, the pulse burst injection of methane at frequencies up to 250 Hz is presented. The goal of these experiments is to provide data at more realistic frequencies and amplitudes.

During miscible gas injection for enhanced oil recovery, the composition of the fluids can change throughout the reservoir as the oil and gas phases develop miscibility. Miscibility improves oil recovery but adds difficulties in predicting the behavior of the flood. The fluid properties will change throughout the reservoir with regions of the reservoir exhibiting separate gas and oil phases, where in other regions the components form only a single phase. In particular, measuring and modeling relative permeability as these regions are traversed creates many challenges. One practical challenge is that in simulators each phase is associated with a relative permeability; this can create discontinuities when phases disappear across miscibility boundaries. These discontinuities can cause errors in the relative permeability calculations and sometimes crash the simulator. Some newer relative permeability models attempt to resolve these issues by changing the standard “oil” and “gas” method of phase labeling and instead labeling phases according to a physical property that is continuous and tied to composition, most notably the fluid density or Gibbs free energy (GFE). Ideally, a relative permeability model will be based on experimental measurements. There are several examples of two-phase relative permeability experiments in the literature, but far fewer three-phase experimental data to test models with. A handful of all relative permeability experiments focus on studying changes in relative permeability brought about by changes in fluid composition with increasing capillary number. However, there is also evidence to suggest that composition can impact relative permeability even at capillary numbers well below the capillary desaturation threshold. In this research, two-phase gas/oil core flood experiments were performed with ethane as the gas phase and equilibrated octane as the oil phase. Pressure was varied so that the composition (density and GFE) of the gas and oil were changing. The capillary number was kept low and constant to prevent capillary desaturation of the oil phase. The experiments were then repeated with an added residual brine phase to test the effect of composition with a third phase present. The results show that changing the density and GFE of the oil and gas phases in either two-phase or three-phase flow had no impact on the relative permeability curves. However, significant changes were observed when comparing two-phase to three-phase oil and gas relative permeabilities. When only gas and oil were flowing in the core, the oil phase formed a continuous layer on the pore surfaces. The addition of residual brine caused the oil to become non-spreading, reducing the relative permeability of both the oil and gas phases in the absence of a continuous layer of oil. These findings verify previous history-matched relative permeabilities in literature and show that phase connectivity is more significant than compositional parameters alone. The relationships between Corey parameters and compositional parameters (density and GFE) were also evaluated to determine when it is appropriate to use compositional models in reservoir simulation

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

Waterflooding in low permeability, fractured and oil-wet carbonate reservoirs yields extremely low oil recovery due to bypassing through fractures and little imbibition into the matrix resulting in a large amount of oil remaining in the reservoir. Gravity-aided gas injection is studied at the lab-scale in this work to enhance oil recovery from fractured reservoirs. The miscibility of the gas with a model oil (decane with naphthenic acid) is varied by enriching the methane with ethane. Mobility of the gas is decreased by incorporating the gas in foam or glycerol-alternating-gas floods. As the miscibility increases, the oil recovery increases, but reaches a plateau above the near-miscible conditions. The foam flood improves oil recovery by diverting gas into the matrix, if the gas is sufficiently soluble in the oil and the gas-oil capillary pressure is sufficiently low. The pressure gradient generated in the fracture by foam helps in the diversion of the gas into the matrix. Glycerol-alternating-gas floods result in minor additional oil recovery over foam floods because the pressure gradients are about the same as those observed in foam floods. Secondary foam flooding achieves similar ultimate oil recovery values as tertiary foam flooding, but at faster rates. Simulations of gas floods show the presence of three different gas fronts during the experiments. Miscible and near-miscible foam floods increased the oil recovery to high values (about 85% OOIP) in core floods and their scale-up to field-scale warrants further study.

Abstract: Solvent injection is a widely used method to enhance oil recovery (EOR). Mixtures of reservoir oil and solvents can exhibit complex multiphase behavior at temperatures typically below 120°F, in which a third solvent-rich liquid (L2) can coexist with the oleic (L1) and gaseous (V) phases. Reliable design of such gas injection requires a detailed understanding of oil recovery mechanisms in three-hydrocarbon-phase flow. In prior research, three-hydrocarbon-phase displacement exhibited a higher level of miscibility with leaner gas (i.e. at a higher level of methane dilution), which resulted in a nonmonotonic trend of oil recovery with respect to gas enrichment. However, no theoretical explanation was given as to why oil displacement was more efficient at a lower level of gas enrichment. Details of oil recovery in three-hydrocarbon-phase flow are not fully understood. This research is concerned with details of oil recovery in three-hydrocarbon-phase flow by use of compositional simulation. First, the mass transfer on multiphase transitions between two and three phases is studied for oil displacement by three hydrocarbon phases. Simple conditions are derived for the multiphase transitions that yield high local displacement efficiency by three hydrocarbon phases. A nonmonotonic trend of oil recovery can occur when local oil displacement by three hydrocarbon phases becomes more efficient, but slower, with decreasing pressure or decreasing gas enrichment. Secondly, an improved method for robust phase identification is developed and implemented in a 1D convective flow simulator with no volume change on mixing. This part of research is important for further confirmation of the oil-displacement mechanisms identified for three-hydrocarbon-phase flow at different flow conditions (e.g., different relative permeabilities). The new method uses tie triangles and their normal unit vectors tabulated as part of the simulation input information. The method can properly recognize five different two-phase regions surrounding the three-phase region; the two two-phase regions that are super-CEP, and the three different two-phase regions that originate with the corresponding edges of the three-phase region in the sub-CEP region. Finally, the displacement mechanisms of three-hydrocarbon-phase flow derived in a preceding part are confirmed by use of different relative permeability models for various oil displacements. Simulation results confirm that the effect of relative permeability on displacement efficiency diminishes as the miscibility level increases. The distance parameters derived before can properly represent the interaction of phase behavior and mobilities since they are derived from mass conservation, not only from thermodynamic conditions.

A numerical reservoir model was created to optimize CO₂ Huff-and-Puff operations in the Bakken Shale. Huff-and-Puff is an enhanced oil recovery treatment in which a well alternates between injection, soaking, and production. Injecting CO₂ into the formation and allowing it to “soak” re-pressurizes the reservoir and improves oil mobility, boosting production from the well. A compositional reservoir simulator was used to study the various design components of the Huff-and-Puff process in order to identify the parameters with the largest impact on recovery and understand the reservoir’s response to cyclical CO₂ injection. It was found that starting Huff-and-Puff too early in the life of the well diminishes its effectiveness, and that shorter soaking periods are preferable over longer waiting times. Huff-and-Puff works best in reservoirs with highly-conductive natural fracture networks, which allow CO₂ to migrate deep into the formation and mix with the reservoir fluids. The discretization of the computational domain has a large impact on the simulation results, with coarser gridding corresponding to larger projected recoveries. Doubling the number of hydraulic fractures per stage results in considerably greater CO₂ injection requirements without proportionally larger incremental recovery factors. Incremental recovery from CO₂ Huff-and-Puff appears to be insufficient to make the process commercially feasible under current economic conditions. However, re-injecting mixtures of CO₂ and produced hydrocarbon gases was proven to be technically and economically viable, which could significantly improve profit margins of Huff-and-Puff operations. A substantial portion of this project involved studying alternative numerical methods for modeling hydraulically-fractured reservoir models. A domain decomposition technique known as mortar coupling was used to model the reservoir system as two individually-solved subdomains: fracture and matrix. A mortar-based numerical reservoir simulator was developed and its results compared to a tradition full-domain finite difference model for the Cinco-Ley et al. (1978) finite-conductivity vertical fracture problem. Despite some numerical issues, mortar coupling closely matched Cinco-Ley et al.'s (1978) solution and has potential applications in complex problems where decoupling the fracture-matrix system might be advantageous.

CO₂ injection in oil reservoirs provides the dual benefit of increasing oil recovery as well as sequestration. Compositional simulations using phase behavior calculations are used to model miscibility and estimate oil recovery. The injected CO₂, however, is known to react with brine. The precipitation and dissolution reactions, especially with carbonate rocks, can have undesirable consequences. The geochemical reactions can also change the mole numbers of components and impact the phase behavior of hydrocarbons. A Gibbs free energy framework that integrates phase equilibrium computations and geochemical reactions is presented in this dissertation. This framework uses the Gibbs free energy function to unify different phase descriptions - Equation of State (EOS) for hydrocarbon components and activity coefficient model for aqueous phase components. A Gibbs free energy minimization model was developed to obtain the equilibrium composition for a system with not just phase equilibrium (no reactions) but also phase and chemical equilibrium (with reactions). This model is adaptable to different reservoirs and can be incorporated in compositional simulators. The Gibbs free energy model is used for two batch calculation applications. In the first application, solubility models are developed for acid gases (CO₂ /H2 S) in water as well as brine at high pressures (0.1 - 80 MPa) and high temperatures (298-393 K). The solubility models are useful for formulating acid gas injection schemes to ensure continuous production from contaminated gas fields as well as for CO₂ sequestration. In the second application, the Gibbs free energy approach is used to predict the phase behavior of hydrocarbon mixtures - CO₂ -nC₁₄ H₃₀ and CH₄ -CO₂. The Gibbs free energy model is also used to predict the impact of geochemical reactions on the phase behavior of these two hydrocarbon mixtures. The Gibbs free energy model is integrated with flow using operator splitting to model an application of cation exchange reactions between aqueous phase and the solid surface. A 1-D numerical model to predict effluent concentration for a system with three cations using the Gibbs free energy minimization approach was observed to be faster than an equivalent stoichiometric approach. Analytical solutions were also developed for this system using the hyperbolic theory of conservation laws and are compared with experimental results available at laboratory and field scales.

Global energy consumption is increasing and hence the need for fossil fuels such as oil. Yet, conventional oil production from known reservoirs is about to reach its peak. So, more needs to be done to meet the demand in the near future. Enhanced oil recovery (EOR) among others is one of the ways to add to global oil production. Gas injection is considered one of the largely utilized EOR methods. Especially, gas supported gravity drainage process has great potential for production from dipping fractured reservoirs to assist the displacing fluid for producing more oil. This thesis presents an experimental investigation that evaluates the optimum performance of three-phase flow of gravity drainage under different miscibility conditions. In the experiments, glass bead models were used as the porous medium and analog fluids (a quaternary three-phase system of H2O, n-butyl alcohol “NBA”, hexadecane “C16¬” and NaCl) were used instead of actual water, oil and gas. An analogy between these fluids and reservoir fluids was constructed based on similar behaviours of the interfacial tensions of both systems. Simulated injection schemes include the continuous gas injection “CGI”, water alternating gas “WAG” and simultaneous water and gas injection “SWAG”. Various fracture patterns and injection rates were also used in the experiments in order to investigate their impacts. In addition, upward WAG injection under near-miscible condition in fractured glass beads model was investigated and its efficiency is compared to the downward near-miscible WAG flooding. The CGI scheme versus WAG and SWAG injection schemes under different conditions using the NBA-rich “oleic” phase indicates that CGI in the vertical injection gives a better performance than the WAG and SWAG injections. However, the CGI consumes more gas injection than the SWAG and WAG schemes, respectively. This implies that WAG injection seems to be more stable and feasible. For injection direction of displacing fluid, an upward injection has lower recovery and injection efficiency factors than downward injection of displacing fluid due to early gas breakthrough, which is related to the density difference between displacing and displaced fluids. The comparison between different miscibility experiments shows that the oil recovery is gradually increased under near-miscible and miscible conditions. The immiscible flood has a slightly sharp breakthrough compared to other two floods which leaves behind a higher residual oil. In addition, decreasing oil recovery and injection efficiency are noticed with reducing the miscibility between gas and oil-phase in the fracture model. This is believed to be a result of interfacial tension and capillary pressure effect, which could dominate the mass transfer between the matrix and fracture. In addition, the oil recovery in miscible flooding is lower than the near-miscible flooding since the gas phase is completely miscible and the oil phase which can pass easily through the fracture. Accordingly, the gas phase breakthrough occurs early in the miscible flooding. The comparison between intermediate and high flow rate of 1:1 WAG ratio and 0.2 PV slug size injections under immiscible condition in the conductive vertical fracture model is studied in this thesis. In contrast, intermediate flow of displacing fluid has a lower oil recovery than the high injection rate. This might have happened due to increasing possibility of mass transfer between the matrix and fracture. On the other hand, different injection rates (from the low to the high flow rate) under near-miscible condition in isolated vertical fracture model are investigated. Those lead to that the oil recovery slightly increases with reducing flow rate since the low injection rate has more stability of the diffusion and dispersion between the displacing and displaced fluids. Several fracture shapes (Isolated, double and conductive vertical fracture models) have been investigated. It is clearly shown that the conductive vertical fracture model has a lower oil recovery than other models and its gas breakthrough occurs early. The isolated vertical fracture model has a high oil recovery because it has two media, which are before and after the fracture. These sections can delay gas breakthrough and thereby increase oil production. Furthermore, the oil recovery factor is inversely proportional with the length of the fracture inside the model. The flow regions of all experiments are investigated using scaling laws reported by Zhou et al. (1994). The calculated scaling law numbers indicate that the optimum oil recovery and injection efficiency occur in the gravity-dominated region, which is represented by the low injection rate and near-miscible fluids.

Multiple hydrocarbon phases are observed during miscible gas floods. The possible phases that result from a gas flood include a vapor phase, an oleic phase, a solvent-rich phase, a solid phase, and an aqueous phase. The solid phase primarily consists of aggregated asphaltene particles. Asphaltenes can block pore throats or change the formation wettability, and thereby reduce the hydrocarbon mobility. The dissolution of injected gas into the aqueous phase can also affect the gas flooding recovery because it reduces the amount of gas available to contact oil. This is more important in CO₂ flooding as the solubility of CO₂ in brine is much higher than hydrocarbons. In this research, we developed efficient and fast multi-phase equilibrium calculation algorithms to model phase behavior of asphaltenes and the aqueous phase in the compositional simulation of gas floods. The PC-SAFT equation of state is implemented in the UTCOMP simulator to model asphaltene precipitation. The additional computational time of PC-SAFT is substantially decreased by improving the root finding algorithm and calculating the derivatives analytically. A deposition and wettability alteration model is then integrated with the thermodynamic model to simulate dynamics of precipitated asphaltenes. Asphaltene deposition is shown to occur with pressure depletion around the production well and/or with gas injection in the reservoir domain that is swept by injected gas. It is observed that the profile of the damaged area by asphaltene deposition depends on the reservoir fluid. A general strategy is proposed to model the phase behavior of CO₂/hydrocarbon/water systems where four equilibrium phases exist. The developed four-phase reduced flash algorithm is used to investigate the effect of introducing water on the phase behavior of CO₂/hydrocarbon mixtures. The results show changes in the phase splits and saturation pressures by adding water to these CO₂/hydrocarbon systems. We used a reduced flash approach to reduce the additional computational time of the four-phase flash calculations,. The results show a significant speed-up in flash calculations using the reduced method. The computational advantage of the reduced method increases rapidly with the number of phases and components. We also decreased the computational time of the equilibrium calculations in UTCOMP by changing the sequential steps in the flash calculation where it checks the previous time-step results as the initial guess for the current time-step. The improved algorithm can skip a large number of flash calculation and stability analyses without loss of accuracy.

Hollow cathode discharge studies have shown the existence of energetic ions at high discharge currents that are likely responsible for the high erosion rates and erosion patterns observed on the keeper electrode of the hollow cathode. This thesis uses experimental methods to study the effects of neutral gas injection in the xenon hollow cathode discharge plume on the production of energetic ions to determine the injection conditions that yield optimum hollow cathode operation and life. Parameters considered include the flow split between the cathode internal flow and the external gas injectors, the number of external gas injection sites, the locations of these injection sites, and the orifice size of the injectors, all as a function of the discharge current level. Two lanthanum hexaboride hollow cathodes of diameters 1.5 cm and 2 cm are studied for discharge currents of up to 100 A and 250 A, respectively. Internal measurements of the 1.5-cm-dia. cathode with a Langmuir probe reveal plasma potential and electron temperature profiles that are characteristic of hollow cathodes and relative insensitivity to the discharge and flow conditions. Plasma density measurements inside the cathode show that the density is sufficiently high and in contact with the entire 2.5-cm insert length only at relatively low internal cathode flow rates so that space-charge limitations on the emitted electron current density are not an issue. At high internal cathode flows, the density peak is pushed toward the orifice plate and the plasma contact with the insert is reduced. A retarding-potential analyzer is used to make ion energy measurements in the discharge plume of the 2-cm-dia. cathode at discharge currents of 25 to 250 A and at various gas-flow conditions. In general, increasing discharge current increases the energetic ion production at any given flow rate or injection location. External gas injection reduces energetic ion production with fewer energetic ions at higher external injected flow. Further, collimated gas-jet injection performs better than point-source (distributed) injection. Increasing cathode internal flow for constant external flow also reduces energetic ion production. The greatest reduction of energetic ion production occurs when both the internal and external flows were at their maximum values. Lifetime estimates of the keeper electrode surface due to sputter-erosion by ion bombardment are calculated to determine the impact of the energetic ion generation on the cathode life. High discharge current operation at low cathode gas flow produced very energetic ions that limited keeper lifetimes to less than 5,000 hours. Applying sufficient internal cathode gas flow and external gas injection extended the keeper life to over 10,000 hours at discharge currents of up to 200 A. For higher discharge current operation, more cathode flow and/or injected flow will be required to increase keeper life, but this could not be explored in detail due to pumping speed limitations of the current facility.

Minimum miscibility pressure (MMP) is a key parameter in the design of gas flooding. There are experimental and computational methods to determine MMP. Computational methods are fast and convenient alternatives to otherwise slow and expensive experimental procedures. This research focuses on the computational aspects of MMP estimation. It investigates the shortcomings of the current computational models and offers ways to improve the robustness of MMP estimation. First, we develop a new mixing cell method of estimating MMP that, unlike previous "mixing cell" methods, uses a variable number of cells and is independent of gas-oil ratio, volume of the cells, excess oil volumes, and the amount of gas injected. The new method relies entirely on robust P-T flash calculations using any cubic equation-of-state (EOS). We show that mixing cell MMPs are comparable with those of other analytical and experimental methods, and that our mixing cell method finds all the key tie lines predicted by MOC; however, the method proved to be more robust and reliable than current analytical methods. Second, we identify a number of problems with analytical methods of MMP estimation, and demonstrate them using real oil characterization examples. We show that the current MOC results, which assume that shocks exist from one key tie line to the next may not be reliable and may lead to large errors in MMP estimation. In such cases, the key tie lines determined using the MOC method do not control miscibility, likely as a result of the onset of L₁-L₂-V behavior. We explain the problem with a simplified pseudo-ternary model and offer a procedure for determining when an error exists and for improving the results. Finally, we present a simple mathematical model for predicting the MMP of contaminated gas. Injection-gas compositions often vary during the life of a gasflood because of reinjection and mixing of fluids in situ. Determining the MMP by slim-tube or other methods for each possible variation in the gas-mixture composition is impractical. Our method gives an easy and accurate way to determine impure CO₂ MMPs for variable field solvent compositions on the basis of just a few MMPs. Alternatively, the approach could be used to estimate the enrichment level required to lower the MMP to a desired pressure.

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.

Reservoir, fluid, and oil recovery data were gathered for ongoing and completed projects which implemented immiscible gas injection as an enhanced oil recovery process. A data base consisting of information from 24 immiscible gas injection projects was compiled. Selected fluid, reservoir, and oil recovery parameters were analyzed using frequency plots and statistical analysis techniques in an effort to determine if correlation could be found between oil recovery and reservoir and fluid parameters. Because of the small amount of oil recovery information available, it was not possible to explore whether or not there was correlation between oil recovery and reservoir and fluid parameters. In spite of this, the study did generate some significant results. Several of these results are: the reservoir oil targeted for immiscible gas flooding tended to be a high gravity (≥ 35° API), low viscosity (≤ 0.5 cp) crude, most of the producing formations were deep (>7000 feet), high temperature (>150°F), high pressure (>3000 psi) reservoirs, and permeabilities of the producing formations tended to be low (