Physical and chemical heterogeneities cause the porous media transport parameters to vary with scale, and between these two types of heterogeneities geological heterogeneity is considered to be the most important source of scale-dependence of transport parameters. Subsurface processes associated with chemical alterations result in changing reservoir properties with interlinked spatial and temporal scale, and there is uncertainty in the evolution of those properties and the chemical processes. This dissertation provides a framework and procedures to quantify the spatiotemporal scaling characteristics of reservoir attributes and transport processes in heterogeneous media accounting for chemical alterations in the reservoir. Conventional flow scaling groups were used to assess their applicability in scaling of recovery and Mixing Zone Length (MZL) in presence of chemical reactivity and permeability heterogeneity through numerical simulations of CO₂ injection. It was found out that these scaling groups are not adequate enough to capture the scaling of recovery and transport parameters in the combined presence of chemical reactivity and physical heterogeneity. In this illustrative example, MZL was investigated as a function of spatial scale, temporal scale, multi-scale heterogeneity, and chemical reactivity; key conclusions are that 1) the scaling characteristics of MZL distinctly differ for low permeability and high permeability media, 2) heterogeneous media with spatial arrangements of both high and low permeability regions exhibit scaling characteristics of both high and low permeability media, 3) reactions affect scaling characteristics of MZL in heterogeneous media, 4) a simple rescaling can combine various MZL curves by merging them into a single MZL curve irrespective of the correlation length of heterogeneity, and 5) estimates of MZL (and consequently predictions of oil recovery) will fluctuate corresponding to displacements in a permeable medium whose lateral length is smaller than the correlation length of geological formation. We illustrate and extend the procedure of estimating Representative Elementary Volume (REV) to include temporal scale by coupling it with spatial scale. The current practice is to perform spatial averaging of attributes and account for residual variability by calibration and history matching. This results in poor predictions of future reservoir performance. The proposed semi-analytical technique to scale-up in both space and time provides guidance for selection of spatial and temporal discretizations that takes into account the uncertainties due to sub-processes. Finally, a probabilistic particle tracking (PT) approach is proposed to scale-up flow and transport of diffusion-reaction (DR) processes while addressing multi-scale and multi-physics nature of DR mechanisms and also maintaining consistent reservoir heterogeneity at different levels of scales. This multi-scale modeling uses a hierarchical approach which is based on passing the macroscopic subsurface heterogeneity down to the finer scales and then returning more accurate reactive flow response. This PT method can quantify the impact of reservoir heterogeneity and its uncertainties on statistical properties such as reaction surface area and MZL, at various scales. / text

Stable dispersions of magnetic nanoparticles that are already in use in biomedicine as image-enhancing agents, also have potential use in subsurface applications. Surface-coated nanoparticles are capable of flowing through micron-size pores across long distances in a reservoir with modest retention in rock. Tracing these contrast agents using the current electromagnetic tomography technology could potentially help track the flood-front in waterflood and EOR processes and characterize the reservoir. The electromagnetic (EM) tomography used in the petroleum industry today is based on the difference between the electrical conductivity of reservoir fluids as well as other subsurface entities. The magnetic nanoparticles that are considered in this study, however, change the magnetic permeability of the flooded region, which is a novel application of the existing EM tomography technology. As the first fundamental step, the magnetic permeability change in rock due to injecting magnetic nanoparticles is quantified as a function of particle and reservoir properties. Subsequently, a new formulation is devised to compute the sensitivity of magnetic measurements to magnetic permeability perturbations. The results are then compared with the sensitivity to conductivity perturbations to identify the application space of magnetic contrast agents. Using numerical simulations, the progress of magnetic nanoparticle bank is monitored in the reservoir through time-lapse magnetic tomography measurements that are expected. Initially, simple models for displacement of injection banks are assumed and the level of complexity is gradually increased to incorporate the realities of fluid flow in the reservoir. The fluid-flow behavior of the nanoparticles is dynamically integrated with time-lapse magnetic response. Since the nanoparticles could help illuminate the flow paths, they could be used to indirectly measure reservoir heterogeneities. Therefore, numerous case studies are demonstrated where reservoir heterogeneity could potentially be inferred. Finally, fundamental pore-scale models are developed as a first step towards the multiple fluid phases extension of the EM tomography application. Using magnetic nanoparticles to improve electromagnetic tomography provides several strategic advantages. One key advantage is that the magnetic nanoparticles provide high resolution measurements at very low frequencies where the conductivity contrast is hardly detectable and casing effect is manageable. In addition, the sensitivity of magnetic measurements at the early stages of the flood is significantly improved with magnetic nanoparticles. Moreover, the vertical resolution of magnetic measurements is significantly enhanced with magnetic nanoparticles present in the vicinity of source or receiver. The fact that the progress of the magnetic slug can be detected at very early stages of the flood, that the traveling slug’s vertical boundaries can be identified at low frequencies, that the reservoir heterogeneities could potentially be characterized, and that the magnetic nanoparticles can be sensed much before the actual arrival of the slug at the observer well, provides significant value of using magnetic contrast agents for reservoir illumination. / text

Direct alcohol fuel cells (DAFC) are attracting considerable interest to meet a variety of energy needs as they offer higher efficiency with less pollution compared to other conventional energy-conversion devices. However, the sluggish alcohol oxidation reaction kinetics and durability problems of the conventional Pt-Ru anode catalyst hamper the commercialization of the DAFC systems. With an aim to overcome these problems, there have been intensive efforts to alloy Pt-Ru with other metals. Although such strategies have led to some enhancement in activity, the durability problem caused by the instability of Ru could still not be alleviated. In this regard, this dissertation focuses on the development of non-Ru electrocatalysts with high activity and durability for DAFC applications. First, Ru-free, Pt-based bimetallic electrocatalysts for methanol oxidation reaction (MOR) were studied. Particularly, Pt-Sn and Pt-CeO₂ catalysts were synthesized, respectively, by a polyol method and a one-step reverse microemulsion (RME) method. The prepared samples are investigated for phase and morphological evaluations by various material-characterization techniques. Cyclic voltammetry and accelerated durability tests revealed that these alternative catalysts have much higher stability with a catalytic activity for MOR comparable to that of Pt-Ru. In the case of Pt-CeO₂, an improved particle morphology is obtained by the RME synthesis, and the advantage of the RME method is reflected by a higher catalytic activity in comparison to that of Pt-CeO₂ synthesized by the conventional synthesis method. It has been known that Pt-Sn is better than Pt-Ru for ethanol oxidation reaction (EOR), and the direct ethanol fuel cells (DEFC) employing Pt-Sn as the anode catalyst have better durability than the DMFC system employing a Pt-Ru anode catalyst. Therefore, this dissertation then focused on the enhancement of the catalytic activity for EOR by incorporating a third metal M to the Pt-Sn catalyst. Following the synthesis and characterization of the Pt-Sn-M (M = Mo and Pd) alloys, the effect of M on the enhanced catalytic activity of Pt-Sn-M is presented. The activity enhancement of the above catalysts is based on the promoting effect of the second or third elements added to Pt. However, in the final chapter of this dissertation, the activity enhancement of Pt nanoparticle itself through the formation of low energy surfaces is investigated. Carbon-supported Pt nanoparticles are synthesized in mixed water-ethylene glycol solvent, and the positive effect of the mixed solvent on both the morphology and surface structure of the Pt nanoparticles for COad oxidation is discussed. / text

Accurate simulation of chemical flooding requires a detailed understanding of numerous complex mechanisms and model parameters where grid size has a substantial impact upon results. In this research we show the effect of grid size on parameters such as phase behavior, interfacial tension, surfactant dilution and salinity gradient for chemical flooding of a very heterogeneous oil reservoir. The effective propagation of the surfactant slug in the reservoir is of paramount importance and the salinity gradient is a key factor in ensuring the process effectiveness. The larger the grid block size, the greater the surfactant dilution, which in turn erroneously reduces the effectiveness of the process indicated with low simulated oil recoveries. We show that the salinity gradient is not adequately captured by coarse grid simulations of heterogeneous reservoirs and this leads to performance predictions with lower recovery compared to fine grid simulations. Due to the highly coupled, nonlinear interactions of the many chemical and physical processes involved in chemical flooding, it is better to use fine-grid simulations rather than coarse grids with upscaled physical properties whenever feasible. However, the upscaling methodology for chemical flooding presented in this work accounts approximately for some of the more important effects, as demonstrated by comparison of fine grid and coarse grid results and is very different than the way other enhanced oil recovery methods are upscaled. This is a step towards making better performance predictions of chemical flooding for large field projects where it is not currently feasible to perform the large number of simulations required to properly consider different designs, optimization, risk and uncertainty using fine-grid simulations. / text

Polymers play a key role in several EOR processes such as polymer flooding, surfactant-polymer flooding and alkaline-surfactant-polymer flooding due to their critical importance of mobility control in achieving high oil recovery from these processes. Numerical simulators are used to predict the performance of all of these processes and in particular the injection rate of the chemical solutions containing polymer; since the economics is very sensitive to the injection rates. Injection rates are governed by the injection viscosity, thus, it is very important to model the polymer viscosity accurately. For the predictions to be accurate, not only the viscosity model must be accurate, but also the calculation of equivalent shear rate in each gridblock must be accurate because the non-Newtonian viscosity models depend on this shear rate. As the size of the gridblock increases, the calculation of this velocity becomes less numerically accurate, especially close to wells. This research presents improvements in polymer viscosity model. Using the improvements in shear thinning model, the laboratory polymer rheology data was better matched. For the first time, polymer viscosity was modeled for complete range of velocity using the Unified Viscosity Model for published laboratory data. New models were developed for relaxation time, time constant and high shear viscosity during that match. These models were then used to match currently available HPAM polymer's laboratory data and predict its viscosity for various concentrations for full flow velocity range. This research presents the need for injectivity correction when large grid sizes are used. Use of large grid sizes to simulate large reservoir due to computation constraints induces errors in shear rate calculations near the wellbore and underestimate polymer solution viscosity. Underestimated polymer solution viscosities lead to incorrect injectivity calculation. In some cases, depending on the well grid block size, this difference between a fine scale and a coarse simulation could be as much as 100%. This study focuses on minimizing those errors. This methodology although needs some more work, but can be used in accurate predictions of reservoir simulation studies of chemical enhanced oil recovery processes involving polymers. / text

Foam-assisted low interfacial tension and foam-improved sweep efficiency are attractive enhanced oil recovery (EOR) methods with numerous studies and researches have been conducted in the past few decades. For example, CO₂-Enhanced Oil Recovery (CO₂-EOR) is very efficient in terms of oil displacement. However, due to the low viscosity of super critical CO₂, the process usually suffers from poor sweep efficiency. One method of increasing sweep efficiency in CO₂-EOR has been identified through the use of surfactants to create "foams" or more correctly CO₂-in-water (C/W) macroemulsions. Polymer flooding techniques such as Alkali -- Polymer (AP), Surfactant -- Polymer (SP), and Alkali -- Surfactant -- Polymer (ASP) have been the only proven chemical EOR method in sandstone reservoirs with many successful pilot tests and field projects. However, the use of polymer is limited in carbonates due to unfavorable conditions related to natural characteristics of this type of lithology. In this case, foam-assisted EOR, specifically Alkali -- Surfactant -- Gas (ASG) process, can be an alternative for polymer flooding. It is a fact that large amount of the world's oil reserves resides in carbonate reservoirs. Therefore, an increase in oil recovery from carbonates would help meet the world's increasing energy demand. This study consists of two parts: (1) the development of new surfactant for creating CO₂ -- in -- water macroemulsions for improving sweep efficiency in CO₂ -- EOR processes; (2) systematic study of ASG method as a novel EOR technique and an alternative for polymer flooding in carbonate reservoirs. Both studies are related to the use of foam as a mobility control agent. In the first part, the design and synthesis of twin tailed surfactants for use at the CO₂/water interface is discussed. The hydrohobes for these surfactants are synthesized from epichlorohydrin and an excess alcohol. Subsequent ethoxylation of the resulting symmetrical dialkyl glycerin yields the water soluble dual tailed surfactants. The general characteristics of these surfactants in water are described. A comparison is carried out between twin-tailed dioctylglycerine surfactants and linear secondary alcohol surfactant based on results from a core flood. The results show that even above the cloud point of the surfactants, the twin tailed surfactants create a significant mobility reduction, likely due to favorable partitioning into the CO₂ phase. The data covers surfactant structures designed specifically for the CO₂-water interface and can be used by producers and service companies in designing new CO₂-floods, especially in areas that might not have been considered due to problems with reservoir heterogeneity. Second part contains a systematic study of ASG process on carbonate rocks through a series of experiments. The purpose is to demonstrate the performance as well as the potential of ASG as a new EOR technique. In this study, basic concepts in chemical EOR are presented, while the design of chemical formulation, phase behavior, and the role of foam are discussed in details. Experimental results showed relatively good recovery, low surfactant retention. However, pressure drop during chemical injections were high, which indicates the formation of both strong foam and viscous microemulsion at the displacement front when surfactant starts solubilizing oil. Overall, ASG showed good performance on carbonate rocks. Optimization can be made on surfactant formula to form less viscous microemulsion and therefore improve efficiency of the process. / text

Accurate phase behavior modeling of hydrocarbon and aqueous mixtures plays a critical role in simulation of compositional flow in subsurface reservoirs, such as miscible gas flooding and CO2 sequestration. As Michelsen proposed his groundbreaking works in stability test and phase split calculation, PT flash calculation has been well developed in the past four decades and become the most popular flash technique. However, as research interests move to more complicated reservoir fluids, some inherent drawbacks of PT flash formulations show up and recent researches focus on a promising alternative called VT flash calculation. In this thesis, VT flash calculation is used in place of PT flash to model phase behaviors of hydrocarbon and aqueous mixtures. A dynamical model, together with a thermodynamically stable numerical algorithm, is developed to calculate equilibrium phase amounts and compositions with/without capillary effect to simulate phase behaviors of unconventional/conventional hydrocarbon mixtures. In order to model water-containing mixtures, the cubic equation of state is replaced by the Cubic-PlusAssociation equation of state, and a salt-based Cubic-Plus-Association model is developed to calculate phase behaviors of CO2-brine systems. The combination of VT flash calculation and the salt-based Cubic-Plus-Association model accurately estimate CO2 solubility in both single- and mixed-salt solutions, and it exhibits close prediction accuracy with a more sophisticated electrolyte Cubic-Plus-Association model. At the end, the ultimate goal is to develop an efficient two-phase VT-flash compositional flow algorithm. The multilayer nonlinear elimination method is used to remove locally high nonlinearities based on the feedback of intermediate Newton solutions. To further improve the computational efficiency, a modified shadow region method is used to bypass unnecessary stability tests. Although nonlinear elimination fails to fully resolve the convergence issue, which roots in the nondifferentiable equilibrium pressure at the points of phase boundary, the number of time refinements is significantly reduced and the improved VT-flash compositional flow algorithm with multilayer nonlinear elimination method successfully simulates a number of numerical examples with and without gravity.

No description available.

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. / text

Une des méthodes de récupération assistée du pétrole les plus utiliséesest l'injection de polymères. L'efficacité de cette méthode est attribuée principalement à laréduction de la mobilité de la phase aqueuse et à la viscoélasticité des polymères. Cetteefficacité dépend de plusieurs paramètres comme la perméabilité, la température, la salinité,l'hétérogénéité, la mouillabilité, le nombre capillaire, etc. De nombreuses connaissances ontété accumulées s’agissant du rôle des polymères dans la récupération du pétrole. Néanmoins,il subsiste encore des questions importantes:• Quel est le meilleur moment pour l’injection de polymère?• Quel rôle joue la mouillabilité dans la récupération ultime de pétrole?• Comment les effets viscoélastiques influencent-ils la récupération?• Quel est le rôle l’adsorption du polymère dans le processus de récupération?Cette thèse, expérimentale, a pour but de fournir des données concernant ledéplacement diphasique (en conditions de mouillabilité intermédiaire et de mouillabilité francheà l’eau) et d’investiguer l’impact réel de la rhéologie sur l’efficacité de déplacement de l’huile.Des injections de polymères sont réalisées à différents stades de précocité (c’est àdire, à différents moments après l’injection d’eau). Les résultats montrent un impact significatifde la précocité du balayage de polymère sur les taux de récupération finale et apparait commeun facteur déterminant à prendre en compte. D’autre part, on observe une récupération plusfaible pour une mouillabilité franche à l’eau que pour une mouillabilité intermédiaire etl’adsorption et la viscoélasticité de la solution de polymère ne sont pas déterminants dans letaux de récupération (dans nos conditions) alors que nos résultats indiquent un changementde mouillabilité durant l’injection de polymère.Des expériences complémentaires de dispersion diphasique ont ensuite mis enévidence un lien direct entre la dispersivité et le taux de récupération final. / Polymer flooding is one of the most developed chemical enhanced oil recoverymethod that has been used successfully since decades. In this chemical EOR method, thepolymer is adding to a waterflood to decrease its mobility. The resulting increase in viscosityas well as a decrease in aqueous phase permeability improve macroscopic oil sweepefficiency. At the pore scale, viscoelasticity is known to be also a key parameter that controlsthe microscopic sweep efficiency. However this sweep efficiency depends on several factorslike the permeability, temperature, salinity, wettability, capillary number, heterogeneity, etc.Therefore several studies are still necessary to have a better understanding of the behaviourof the polymer inside porous media and to optimize the process.• What is the best moment to inject polymer?• What is the role of wettability in final recovery?• How do viscoelastic effects influence recovery?• What is the role of adsorption of the polymer in the recovery process?In our interest to optimize and to understand polymer flooding process we have analysed thedependence of the sweep efficiency with the moment of the polymer injection duringwaterflooding and wettability (Water wet and intermediate wet). The polymer solution isinjected in the core at different maturity times (0PV, Breakthrough, 1PV, 2PV, 3PV, 4PV and6PV).The main results can be summarized in three points .The results show oil recoveryfinal for water wet corefloods is lower than intermediate wet corefloods. On the other hand, theproduction of oil with the injection of polymer is higher than the injection of water due to afavorable mobility ratio. Finally, the final recovery rates are lower when the polymer injectionis late. These results suggest that the history of sweeping can lead to different distributions ofphases (oil/brine) at the end of the waterflood. The sweep efficiency is related to the ability ofthe polymer to disperse throughout the accessible portal space. We have analysed this aspectfrom the point of view of the diphasic dispersion by showing that the dispersivity of the phasesis different at each time of the water injection. The complementary diphasic dispersionexperiments showed a direct link between dispersivity and the final oil recovery.