The transport of components and phases plays a fundamental role in the success of an EOR process. Because many reservoirs have harsh conditions of salinity, temperature and rock heterogeneity, which limit process options, a robust system with flexibility is required. Systematic experimental study of formulations capable to transport surfactant as foam at 94°C, formulated in sea water, is presented. It includes methodology to conduct core floods in sand packs using foaming surfactants and to develop “surfactant blend ratio- salinity ratio maps” using equilibrium phase behavior to determine favorable conditions for oil recovery in such floods. Mathematical model able to reproduce the foam strength behavior observed in sand packs with the formulations studied is presented. Visualization of oil recovery mechanism from matrix is realized using a model system of micro-channels surrounded by glass beads to mimic matrix and fractures respectively. The observations illustrate how components may distribute within the matrix, thereby releasing oil into the fractures. The use of chemicals to minimize adsorption is required when surfactant adsorption is important. The presence of anhydrite may limit the use of sodium carbonate to reduce adsorption of carbonates. A methodology is presented to estimate the amount, if any, of anhydrite present in the reservoir. The method is based on brine software analysis of produced water compositions and inductively coupled plasma (ICP) analysis of core samples. X-ray powder diffraction (XRD) was used to verify the mineralogy of the rock. X-ray photoelectron spectroscopy (XPS) was used to obtain surface composition for comparison with bulk composition of the rock. Adsorption of surfactants was measured using dynamic and static adsorption experiments. Determining the flow properties of the rock samples via tracer analysis permitted the simulation of the dynamic adsorption process using a mathematical model that considers the distribution of adsorbed materials in the three different regions of pore space. Using this method allows one to predict adsorption in a reservoir via simulation.

Water-flooding in water-wet fractured reservoirs can recover significant amounts of oil through capillary driven imbibition. Unfortunately, many of the fractured reservoirs are mixed-wet/oil-wet and water-flooding leads to poor recovery as the capillary forces hinder imbibition. Surfactant injection and immiscible gas injection are two possible processes to improve recovery from fractured oil-wet reservoirs. In both these EOR methods, the gravity is the main driving force for oil recovery. Surfactant has been recommended and shown a great potential to improve oil recovery from oil-wet cores in the laboratory. To scale the results to field applications, the physics controlling the imbibition of surfactant solution and the scaling rules needs to be understood. The standard experiments for testing imbibition of surfactant solution involves an imbibition cell, where the core is placed in the surfactant solution and the recovery is measured versus time. Although these experiments prove the effectiveness of surfactants, little insight into the physics of the problem is achieved. This dissertation provides new core scale and pore scale information on imbibition of anionic surfactant solution into oil-wet porous media. In core scale, surfactant flooding into oil-wet fractured cores is performed and the imbibition of the surfactant solution into the core is monitored using X-ray computerized tomography(CT). The surfactant solution used is a mixture of several different surfactants and a co-solvent tailored to produce ultra-low interfacial tension (IFT) for the specific oil used in the study. From the CT images during surfactant flooding, the average penetration depth and the water saturation versus height and time is calculated. Cores of various sizes are used to better understand the effect of block dimension on imbibition behavior. The experimental results show that the brine injection into fractured oil-wet core only recovers oil present in the fracture; When the surfactant solution is injected, the CT images show the imbibition of surfactant solution into the matrix and increase in oil recovery. The surfactant solution imbibes as a front. The imbibition takes place both from the bottom and the sides of the core. The highest imbibition is observed close to the bottom of the core. The imbibition from the side decreases with height and lowest imbibition is observed close to the top of the core. Experiments with cores of different sizes show that increase in either the length or the diameter of the core causes decrease in the fractional recovery rate (%OOIP). Numerical simulation is also used to determine the physics that controls the imbibition profiles. %The numerical simulations show that the relative permeability curves strongly affect the imbibition profiles and should be well understood to accurately model the process. Both experimental and numerical simulation results imply that the gravity is the main driving force for the imbibition process. The traditional scaling group for gravity dominated imbibition only includes the length of the core to upscale the recovery for cores of different sizes. However based on the measurements and simulation results from this study, a new scaling group is proposed that includes both the diameter and the length of the core. It is shown that the new scaling group scales the recovery curves from this study better than the traditional scaling group. In field scale, the new scaling group predicts that the recovery from fractured oil-wet reservoirs by surfactant injection scales by both the vertical and horizontal fracture spacing. In addition to core scale experiments, capillary tube experiments are also performed. In these experiments, the displacement of oil by anionic surfactant solutions in oil-wet horizontal capillary tubes is studied. The position of the oil-aqueous phase interface is recorded with time. Several experimental parameters including the capillary tube radius and surfactant solution viscosity are varied to study their effect on the interface speed. Two different models are used to predict the oil-aqueous phase interface position with time. In the first model, it is assumed that the IFT is constant and ultra-low throughout the experiments. The second model involves change of wettability and IFT by adsorption of surfactant molecules to the oil-water interface and the solid surface. Comparing the predictions to the experimental results, it is observed that the second model provides a better match, especially for smaller capillary tubes. The model is then used to predict the imbibition rate for very small capillary tubes, which have equivalent permeability close to oil reservoirs. The results show that the oil displacement rate is limited by the rate of diffusion of surfactant molecules to the interface. In addition to surfactant flooding, immiscible gas injection can also improve recovery from fractured oil-wet reservoirs. In this process, the injected gas drains the oil in the matrix by gravity forces. Gravity drainage of oil with gas is an efficient recovery method in strongly water-wet reservoirs and yields very low residual oil saturations. However, many of the oil-producing fractured reservoirs are not strongly water-wet. Thus, predicting the profiles and ultimate recovery for mixed and oil-wet media is essential to design and optimization of improved recovery methods based on three-phase gravity drainage. In this dissertation, we provide the results from two- and three-phase gravity drainage experiments in sand-packed columns with varying wettability. The results show that the residual oil saturation from three-phase gravity drainage increases with increase in the fraction of oil-wet sand. A simple method is proposed for predicting the three-phase equilibrium saturation profiles as a function of wettability. In each case, the three-phase results were compared to the predictions from two-phase results of the same wettability. It is found that the gas/oil and oil/water transition levels can be predicted from pressure continuity arguments and the two-phase data. The predictions of three-phase saturations work well for the water-wet media, but become progressively worse with increasing oil-wet fraction. / text

Primary cilia are non-motile organelles having 9+0 microtubules that project from the basal body of the cell. While the main purpose of motile cilia in mammalian cells is to move fluid or mucus over the cell surface, the purpose of primary cilia has remained elusive for the most part. Primary cilia are shortened in the kidney tubules of Tg737orpk mice, which have polycystic kidney disease due to ciliary defects. The product of the Tg737 gene is polaris, which is directly involved in a microtubule-dependent transport process called intraflagellar transport (IFT). In order to determine the importance of polaris in the development of neuronal cilia, cilium length and numerical density of cilia were quantitatively assessed in six different brain regions on postnatal days 14 and 31 in Tg737orpk mutant and wildtype mice. Our results indicate that the polaris mutation leads to shortening of cilia as well as decreased percentage of ciliated neurons in all brain regions that were quantitatively assessed. Maintainance of cilia was especially affected in the ventromedial nucleus of the hypothalamus. Furthermore, the polaris mutation curtailed cilium length more severely on postnatal day 31 than postnatal day 14. These data suggests that even after ciliogenesis, intraflagellar transport is necessary in order to maintain neuronal cilia. Regional heterogeneity in the effect of this gene mutation on neuronal cilia suggests that the functions of some brain regions might be more compromised than others.

Surfactants both change the wettability and lower the interfacial tension by various degrees depending on the type of surfactant and how it interacts with the specific oil. Ultra low IFT means almost zero capillary pressure, which in turn indicates little oil should be produced from capillary imbibition when the surfactant reduces the IFT in naturally fractured oil reservoirs that are mixed-wet or oil-wet. What is the transport mechanism for the surfactant to get far into the matrix and how does it scale? Molecular diffusion and capillary pressure are much too slow to explain the experimental data. Recent dynamic laboratory data suggest that the process is faster when a pressure gradient is applied compared to static tests. A mechanistic chemical compositional simulator was used to study the effect of pressure gradient on chemical oil recovery from naturally fractured oil reservoirs for several different chemical processes (polymer, surfactant, surfactant-polymer, alkali-surfactant-polymer flooding). The fractures were simulated explicitly by using small gridblocks with fracture properties. Both homogeneous and heterogeneous matrix blocks were simulated. Microemulsion phase behavior and related chemistry and physics were modeled in a manner similar to single porosity reservoirs. The simulations indicate that even very small pressure gradients (transverse to the flow in the fractures) are highly significant in terms of the chemical transport into the matrix and that increasing the injected fluid viscosity greatly improves the oil recovery. Field scale simulations show that the transverse pressure gradients promote transport of the surfactant into the matrix at a feasible rate even when there is a high contrast between the permeability of the fractures and the matrix. These simulations indicate that injecting a chemical solution that is viscous (because of polymer or foam or microemulsion) and lowers the IFT as well as alters the wettability from mixed-wet to water-wet, produces more oil and produces it faster than static chemical processes. These findings have significant implications for enhanced oil recovery from naturally fractured oil reservoirs and how these processes should be optimized and scaled up from the laboratory to the field. / text

Thermal and chemical recovery processes are important EOR methods used often by the oil and gas industry to improve recovery of heavy oil and high viscous oil reservoirs. Knowledge of underlying mechanisms and their modeling in numerical simulation are crucial for a comprehensive study as well as for an evaluation of field treatment. EOS-compositional, thermal, and blackoil reservoir simulators can handle gas (or steam)/oil/water equilibrium for a compressible multiphase flow. Also, a few three-phase chemical flooding reservoir simulators that have been recently developed can model the oil/water/microemulsion equilibrium state. However, an accurate phase behavior and fluid flow formulations are absent in the literature for the thermal chemical processes to capture four-phase equilibrium. On the other hand, numerical simulation of such four-phase model with complex phase behavior in the equilibrium condition between coexisting phases (oil/water/microemulsion/gas or steam) is challenging. Inter-phase mass transfer between coexisting phases and adsorption of components on rock should properly be modeled at the different pressure and temperature to conserve volume balance (e.g. vaporization), mass balance (e.g. condensation), and energy balance (e.g. latent heat). Therefore, efforts to study and understand the performance of these EOR processes using numerical simulation treatments are quite necessary and of utmost importance in the petroleum industry. This research focuses on the development of a robust four-phase reservoir simulator with coupled phase behaviors and modeling of different mechanisms pertaining to thermal and chemical recovery methods. Development and implementation of a four-phase thermal-chemical reservoir simulator is quite important in the study as well as the evaluation of an individual or hybrid EOR methods. In this dissertation, a mathematical formulation of multi (pseudo) component, four-phase fluid flow in porous media is developed for mass conservation equation. Subsequently, a new volume balance equation is obtained for pressure of compressible real mixtures. Hence, the pressure equation is derived by extending a black oil model to a pseudo-compositional model for a wide range of components (water, oil, surfactant, polymer, anion, cation, alcohol, and gas). Mass balance equations are then solved for each component in order to compute volumetric concentrations. In this formulation, we consider interphase mass transfer between oil and gas (steam and water) as well as microemulsion and gas (microemulsion and steam). These formulations are derived at reservoir conditions. These new formulations are a set of coupled, nonlinear partial differential equations. The equations are approximated by finite difference methods implemented in a chemical flooding reservoir simulator (UTCHEM), which was a three-phase slightly compressible simulator, using an implicit pressure and an explicit concentration method. In our flow model, a comprehensive phase behavior is required for considering interphase mass transfer and phase tracking. Therefore, a four-phase behavior model is developed for gas (or steam)/ oil/water /microemulsion coexisting at equilibrium. This model represents coupling of the solution gas or steam table methods with Hand’s rule. Hand’s rule is used to capture the equilibrium between surfactant, oil, and water components as a function of salinity and concentrations for oil/water/microemulsion phases. Therefore, interphase mass transfer between gas/oil or steam/water in the presence of the microemulsion phase and the equilibrium between phases are calculated accurately. In this research, the conservation of energy equation is derived from the first law of thermodynamics based on a few assumptions and simplifications for a four-phase fluid flow model. This energy balance equation considers latent heat effect in solving for temperature due to phase change between water and steam. Accordingly, this equation is linearized and then a sequential implicit scheme is used for calculation of temperature. We also implemented the electrical Joule-heating process, where a heavy oil reservoir is heated in-situ by dissipation of electrical energy to reduce the viscosity of oil. In order to model the electrical Joule-heating in the presence of a four-phase fluid flow, Maxwell classical electromagnetism equations are used in this development. The equations are simplified and assumed for low frequency electric field to obtain the conservation of electrical current equation and the Ohm's law. The conservation of electrical current and the Ohm's law are implemented using a finite difference method in a four-phase chemical flooding reservoir simulator (UTCHEM). The Joule heating rate due to dissipation of electrical energy is calculated and added to the energy equation as a source term. Finally, we applied the developed model for solving different case studies. Our simulation results reveal that our models can accurately and successfully model the hybrid thermal chemical processes in comparison to existing models and simulators. / text

Orientador: Roberto de Alencar Lotufo / Tese (doutorado) - Universidade Estadual de Campinas, Faculdade de Engenharia Eletrica e de Computação / Made available in DSpace on 2018-08-13T08:32:02Z (GMT). No. of bitstreams: 1 Audigier_RomaricMatthiasMichel_D.pdf: 1753584 bytes, checksum: 1d31eb6f095099ffb5c3ec8d0a96a9cf (MD5) Previous issue date: 2007 / Resumo: Esta tese introduz o novo conceito de transformada de zona de empate que unifica as múltiplas soluções de uma transformada de watershed, conservando apenas as partes comuns em todas estas, tal que as partes que diferem constituem a zona de empate. A zona de empate aplicada ao watershed via transformada imagem-floresta (TZ-IFT-WT) se revela um elo inédito entre transformadas de watershed baseadas em paradigmas muito diferentes: gota d'água, inundação, caminhos ótimos e floresta de peso mínimo. Para todos esses paradigmas e os algoritmos derivados, é um desafio se ter uma solução única, fina, e que seja consistente com uma definição. Por isso, propõe-se um afinamento da zona de empate, único e consistente. Além disso, demonstra-se que a TZ-IFT-WT também é o dual de métodos de segmentação baseados em conexidade nebulosa. Assim, a ponte criada entre as abordagens morfológica e nebulosa permite aproveitar avanços de ambas. Em conseqüência disso, o conceito de núcleo de robustez para as sementes é explorado no caso do watershed. / Abstract: This thesis introduces the new concept of tie-zone transform that unifies the multiple solutions of a watershed transform, by conserving only the common parts among them such that the differing parts constitute the tie zone. The tie zone applied to the watershed via image-foresting transform (TZ-IFTWT) proves to be a link between watershed transforms based on very different paradigms: drop of water, flooding, optimal paths and forest of minimum weight. For all these paradigms and the derived algorithms, it is a challenge to get a unique and thin solution which is consistent with a definition. That is why we propose a unique and consistent thinning of the tie zone. In addition, we demonstrate that the TZ-IFT-WT is also the dual of segmentation methods based on fuzzy connectedness. Thus, the bridge between the morphological and the fuzzy approaches allows to take benefit from the advance of both. As a consequence, the concept of cores of robustness for the seeds is exploited in the case of watersheds. / Doutorado / Engenharia de Computação / Doutor em Engenharia Elétrica