The continuous rising of anthropogenic emission into the atmosphere as a consequence of industrial growth is becoming uncontrollable, which causes heating up the atmosphere and changes in global climate. Therefore, CO2 emission becomes a big problem and key issue in environmental concerns. There are several options discussed for reducing the amount of CO2 emitted into the atmosphere. CO2 sequestration is one of these options, which involves the capture of CO2 from hydrocarbon emission sources, e.g. power plants, the injection and storage of CO2 into deep geological formations, e.g. depleted oil reservoirs. The complexity in the structure of geological formations and the processes involved in this method necessitates the use of numerical simulations in revealing the potential problems, determining feasibility, storage capacity, and life span credibility. Field K having 32o API gravity oil in a carbonate formation from southeast Turkey was studied. Field K was put on production in 1982 and produced until 2006, which was very close to its economic lifetime. Thus, it was considered as a candidate for enhanced oil recovery and CO2 sequestration. Reservoir rock and fluid data was first interpreted with available well logging, core and drill stem test data. Monte Carlo simulation was used to evaluate the probable reserve that was 7 million STB, original oil in place (OOIP). The data were then merged into CMG/STARS simulator. History matching study was done with production data to verify the results of the simulator with field data. After obtaining a good match, the different scenarios were realized by using the simulator. From the results of simulation runs, it was realized that CO2 injection can be applied to increase oil recovery, but sequestering of high amount of CO2 was found out to be inappropriate for field K. Therefore, it was decided to focus on oil recovery while CO2 was sequestered within the reservoir. Oil recovery was about 23% of OOIP in 2006 for field K, it reached to 43 % of OOIP by injecting CO2 after defining production and injection scenarios, properly.

The aim of the study is to investigate matrix-fracture interaction, gas oil gravity drainage (GOGD) and diffusion mechanisms with CO2, N2 and CH4 gas injection in a fractured system. Effects of injected gas type, initial gas saturation and diffusion coefficient on oil recovery are studied by an experimental and simulation work. In the experimental study, Berea sandstone cores are placed in a core holder and the space created around the core is considered as a surrounding fracture. System is kept at a pressure of 250 psi by CO2, N2 and CH4 gases and at a reservoir temperature of 70 &deg / C. Experiments with cores having similar initial saturations resulted in the highest ndecane recovery in CO2 experiment followed by CH4 and N2. The highest solubility of CO2 in n-decane and density difference between CO2 and CO2-ndecane mixture are considered as the reason of results. CO2 injection tests with n-decane and brine saturated core with and without initial gas saturation indicate that availability of initial gas saturation in matrix increased recovery. A simulation study is continued using CMG (Computer Modeling Group Ltd.) WinProp (Microsoft Windows&trade / based Phase-Behavior and Fluid Property Program) and GEM (Generalized Equation-of-State Model Compositional Reservoir Simulator). Simulation results of CO2 experiment with initial gas show that dominant effect of GOGD decreases and diffusion becomes more effective at final production stages. Simulation study indicates an immediate, sharp decrease in oil saturation in matrix. Oil in matrix migrates into fractures and moves downward as a result of GOGD with gas injection.

Alkaline/surfactant/polymer (ASP) flooding is of increasing interest and importance because of high oil prices and the need to increase oil production. The benefits of combining alkali with surfactant are well established. The alkali has very important benefits such as lowering interfacial tension and reducing adsorption of anionic surfactants that decrease costs and make ASP a very attractive enhanced oil recovery method provided the consumption is not too large and the alkali can be propagated at the same rate as a synthetic surfactant and polymer. However, the process is complex so it is important that new candidates for ASP be selected taking into account the numerous chemical reactions that occur in the reservoir. The reaction of acid and alkali to generate soap and its subsequent effect on phase behavior is the most crucial for crude oils containing naphthenic acids. Using numerical models, the process can be designed and optimized to ensure the proper propagation of alkali and effective soap and surfactant concentrations to promote low interfacial tension and a favorable salinity gradient. The first step in this investigation was to determine what geochemical reactions have the most impact on ASP flooding under different reservoir conditions and to quantify the consumption of alkali by different mechanisms. We describe the ASP module of UTCHEM simulator with particular attention to phase behavior and the effect of soap on optimum salinity and solubilization ratio. Several phase behavior measurements for a variety of surfactant formulations and crude oils were successfully modeled. The phase behavior results for sodium carbonate, blends of surfactants with an acidic crude oil followed the conventional Winsor phase transition with significant three-phase regions even at low surfactant concentrations. The solubilization data at different oil concentrations were successfully modeled using Hand's rule. Optimum salinity and solubilization ratio were correlated with soap mole fractions using mixing rules. New ASP corefloods were successfully modeled taking into account the aqueous reactions, alkali/rock interactions, and the phase behavior of soap and surfactant. These corefloods were performed in different sandstone cores with several chemical formulations, crude oils with a wide range of acid numbers, brine with a wide range of salinities, and a wide range of temperatures. 2D and 3D sector model ASP simulations were performed based on field data and design parameters obtained from coreflood history matches. The phenomena modeled included aqueous phase chemical reactions of the alkaline agent and consequent consumption of alkali, the in-situ generation of surfactant by reaction with the acid in the crude, surfactant/soap phase behavior, reduction of surfactant adsorption at high pH, cation exchange with clay, and the effect of co-solvent on phase behavior. Sensitivity simulations on chemical design parameters such as mass of surfactant and uncertain reservoir parameters such as kv/kh ratio were performed to provide insight as the importance of each of these variables in chemical oil recovery. Simulations with different permeability realizations provided the range for chemical oil recoveries. This study showed that it is very important to model both surface active components and their effect on phase behavior when doing mechanistic ASP simulations. The reactions between the alkali and the minerals in the formation depend very much on which alkali is used, the minerals in the formation, and the temperature. This research helped us increase our understanding on the process of ASP flooding. In general, these mechanistic simulations gave insights into the propagation of alkali, soap, and surfactant in the core and aid in future coreflood and field scale ASP designs. / text

This work investigates the performance of CO₂ soluble surfactants used for CO₂ foam flooding in fractured carbonate reservoirs. Oil recovery associated with the reduction of CO₂ mobility in fractures is assessed by monitoring oil saturation and pressure drops during injection of CO₂ with aqueous surfactant solution in artificially fractured carbonate cores. Distinct novel CO₂ soluble surfactants are evaluated as well as a conventional surfactant. Water flooding and pure CO₂ injection are conducted as baseline. Characterization of fluids and rock are also reported which include Amott test, oil phase behavior and slim tube test. Transport and thermodynamic properties of surfactant and supercritical CO₂ are used to evaluate the process on a core scale using a commercial reservoir simulator. / text

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

No description available.

[pt] A injeção de água é o método de recuperação secundária mais utilizado na indústria do petróleo. No entanto, a alta razão de mobilidade entre a água e o óleo limita a quantidade de óleo deslocada. Uma alternativa para minimizar este problema é a aplicação de tecnologias que agem como agentes de controle da mobilidade. Soluções poliméricas podem ser utilizadas para aumentar a viscosidade da água e consequentemente reduzir a razão de mobilidade. Evidências experimentais têm mostrado que o comportamento elástico de soluções poliméricas pode além de diminuir a razão de mobilidade, contribuir para um melhor deslocamento de óleo em escala de poro, reduzindo a saturação de óleo residual. Esse comportamento em escala de poro ainda não está completamente entendido. Nesse trabalho, um micromodelo de vidro formado por uma rede bi-dimensional de canais foi utilizado como meio poroso. Esse dispositivo tem algumas características importantes de meios porosos e permite a visualização do fluxo em escala de poro. A evolução do deslocamento de óleo pela fase aquosa é acompanhada no microscópio e são obtidas imagens dos perfis de saturação. Três diferentes fases aquosas foram usadas: água deionizada, uma solução de poli(óxido de etileno) de alto peso molecular e uma mistura de água com glicerina com a mesma viscosidade do poli(óxido de etileno). A visualização do fluxo no micromodelo permite obter informações específicas sobre a presença de óleo preso por forças capilares e o movimento da interface óleo/água no interior da rede. Resultados mostraram que as forças viscoelásticas modificam a distribuição de fluidos no meio poroso, melhorando a eficiência de deslocamento em escala de poro e consequentemente a saturação de óleo residual. / [en] Water flooding is the most commonly used oil recovery method in the oil industry. However, the high mobility ratio between the water and oil phases limits the amount of oil displaced by the water phase. An effective alternative to minimize this problem is the application of technologies that act as mobility control agents. Polymer solution is used in many cases as a way to increase the water phase viscosity and consequently reduce the mobility ratio. Experimental evidences have shown that the elastic behavior of some polymer solution may not only improve the mobility ratio but also contribute to a better pore level oil displacement, reducing the residual oil saturation. This pore level behavior is not clearly understood. In this work, a glass microfluidic chip made of a 2-D array of channels is used as a two-dimensional porous space. This device has the principal features of a porous media and provides means for pore level flow visualization. A microscopic is used to monitor the evolution of the water phase as it displaces oil and images of the saturation profiles can be made. Three different water phases were used: pure water, a high molecular weight poly(ethylene oxide) solution and a glycerol-water mixture with the same viscosity of the polymer solution. Flow visualization provides specific information about the presence of the trapped oil phase and the movement of the oil/water interface in the network. Results show that the viscoelastic forces modify the liquid distribution in the porous media, improving the displacement efficiency at pore scale and consequently the residual oil saturation.

[pt] Em um mundo globalizado, a demanda por energia está sempre crescendo. Uma vez que a indústria de óleo e gás é responsável pela entrega da maior parte desta demanda, isso faz dos hidrocarbonetos componentes cada vez mais importantes no mercado mundial. Entretanto tais recursos são finitos, portanto, uma exploração consciente, buscando sempre o máximo desempenho se faz necessária. Como os reservatórios de petróleo, logo após a aplicação das técnicas de recuperação primária e secundária, geralmente ainda possuem cerca de 65 por cento do volume de óleo originalmente contido em seus poros, métodos que visam a redução dessa porcentagem estão ganhando um papel cada vez mais importante na indústria energética. Nesse contexto, esse trabalho apresenta um micromodelo tridimensional representativo de um meio poroso que será utilizado para a análise do escoamento de fluidos na escala de poro. A microscopia confocal será adotada para visualizar os diferentes fenômenos que ocorrem em microescala, permitindo a obtenção de informações específicas sobre a dinâmica dos gânglios de óleo, em relação a sua formação, mobilização e aprisionamento, e assim, ao final do experimento quantificar a saturação residual de óleo em diferentes condições de escoamento. Os resultados obtidos mostram que o uso das suspensões de microcápsulas flexíveis como agente de controle de mobilidade, modifica a distribuição dos fluidos no meio poroso, o que melhora a eficiência de deslocamento do fluido deslocante na escala de poro, e consequentemente diminui a saturação de óleo residual. / [en] In a globalized world, the demand for energy is always growing. Since the oil and gas industry is responsible for delivering most of this demand, this makes hydrocarbon components increasingly important in the worldwide economy. However, such resources are finite, so a conscious exploration always seeking the maximum performance is required. As oil reservoirs after the application of primary and secondary recovery techniques usually still have about 65 percent of the original oil volume contained in their pores, methods that aim its reduction are gaining an increasingly important role in the energy industry. In this context, this work presents a three-dimensional micromodel representative of a porous medium that is used for pore-scale flow analysis. Confocal microscopy is used to visualize the microscale phenomena, leading to specific information about ganglia dynamics, related to its formation, mobilization and entrapment. The residual oil saturation, an important value to measure the amount of oil produced in a given reservoir is determined for different flow conditions. The results show that the suspensions composed by flexible microcapsules could be used as a mobility control agent, since it modifies the fluid distribution in the porous media, improving the pore-scale displacement efficiency, and consequently reducing the residual oil saturation.

[pt] A injeção de água é o método mais comum para manter a pressão e melhorar a recuperação de óleo contido em um reservatório. A eficiência de recuperação de óleo no caso de óleos pesados é limitada pela alta razão de mobilidade entre o fluido deslocante e o fluido deslocado. Como a sede mundial por energia aumenta todo ano, enquanto o fluxo de petróleo dos campos petrolíferos conhecidos juntamente com a descoberta de novos reservatórios declina a uma velocidade considerável, torna-se indispensável utilizar métodos mais efetivos para extrair o petróleo dos reservatórios conhecidos. Diferentes métodos de recuperação avançada de óleo são desenvolvidos em busca de alternativas. A injeção de dispersões, em particular a injeção de emulsões óleoem- água, como um agente de controle de mobilidade do fluido injetado tem sido testada e estudada com relativo sucesso. Porem esta técnica ainda não é totalmente desenvolvida ou compreendida. O uso efetivo de injeção de emulsões como uma alternativa para a recuperação de petróleo requer uma completa análise dos diferentes regimes de fluxo de emulsões dentro do espaço poroso de um reservatório. Se o tamanho de gota da fase dispersa for da mesma ordem de magnitude do tamanho de poro, as gotículas podem se aglomerar e bloquear parcialmente o escoamento através do espaço poroso, controlando assim a mobilidade do fluido deslocante, obtendo assim um deslocamento mais uniforme e um aumento no fator de recuperação. Este trabalho tem como objetivo principal o estudo do processo de deslocamento de óleo em um meio poroso por injeção de água e emulsões óleo-in-água. Diferentes experimentos foram realizados para análise de diferentes aspectos do problema, incluindo a injeção alternada de água e emulsão óleo-em-água a diferentes vazões, injeção alternada de água e emulsão em meios com diferentes permeabilidades conectados paralelamente e visualização do escoamento através de um meio poroso transparente formado por esferas de vidro não consolidadas. Um modelo do escoamento de emulsão foi considerado através da modificação da curva de permeabilidade relativa da fase aquosa, que é escrita como função não só da saturação, mas também da concentração de gotas de emulsão e do número de capilaridade local. O processo de deslocamento de óleo através de injeção alternada água-emulsão foi também estudado numericamente através de um código desenvolvido em Matlab utilizando o modelo TPFA (Two Flux Approximation) and IMPES (IMplicit Pressure and Explicit Pressure Saturation). / [en] Water injection is a common method to maintain reservoir pressure and improve oil recovery. The efficiency of oil recovery in the case of heavy oils is limited by the high mobility ratio between the injected water and oil. As the world thirst for energy is increasing every year while oil production from known oil reservoirs together with the discovery of new oil reservoirs deplete at considerable rate, it becomes indispensable to use more effective methods to produce oil from known reservoirs. The injection of dispersions, in particular of oil-in-water emulsions, as an agent of mobility control of injected fluid has been tested and studied with relative success. However this technique is not completely developed and understood. The effective use of emulsion injection as an alternative for oil recovery needs a complete analysis of different regimes of emulsion flow through the pore space of a reservoir. If the drop size of the dispersed phase is of the same order of magnitude of the pore size or lager, the drops can agglomerate and partially block the flow through the pores, thus controlling the displacing fluid mobility, getting a more uniform displacing front and an increase in the oil recovery factor. The main goal of this work is the study of oil displacement process through a porous media by water and oil-in-water emulsion injection. Different experiments were carried out for analysis of different aspects of the problem, including the alternating injection of water and oil-in-water emulsion at different flow rates, through cores with different permeabilities connected in parallel, and visualization of flow through a transparent non consolidated porous media, formed by glass beads. A model of emulsion flow was considered by modifying the relative permeability curve of the aqueous phase, which is written as a function not only of the aqueous phase saturation, but also as a function of the emulsion drop concentration and local capillarity number. The process of oil displacement by alternated water-emulsion injection was also studied numerically by a code developed in Matlab using TPFA (Two Flux Approximation) and IMPES (IMplicit Pressure and Explicit Pressure Saturation) methods.

Coordenação de Aperfeiçoamento de Pessoal de Nível Superior / Os métodos tradicionais de estimular a produção de petróleo, envolvendo a injeção de água, vapor, gás ou outros produtos, estabeleceram a base conceitual para novos métodos de extração de óleo, utilizando micro-organismos e processos biológicos. As tecnologias que empregam os processos de bioestimulação e bioaumentação já são amplamente utilizadas em inúmeras aplicações industriais, farmacêuticas e agroindustriais, e mais recentemente, na indústria do petróleo. Dada a enorme dimensão econômica da indústria do petróleo, qualquer tecnologia que possa aumentar a produção ou o fator de recuperação de um campo petrolífero gera a expectativa de grandes benefícios técnicos, econômicos e estratégicos. Buscando avaliar o possível impacto de MEOR (microbial enhanced oil recovery) no fator de recuperação das reservas de óleo e gás no Brasil, e quais técnicas poderiam ser mais indicadas, foi feito um amplo estudo dessas técnicas e de diversos aspectos da geologia no Brasil. Também foram realizados estudos preliminares de uma técnica de MEOR (bioacidificação) com possível aplicabilidade em reservatórios brasileiros. Os resultados demonstram que as técnicas de MEOR podem ser eficazes na produção, solubilização, emulsificação ou transformação de diversos compostos, e que podem promover outros efeitos físicos no óleo ou na matriz da rocha reservatório. Também foram identificadas bacias petrolíferas brasileiras e recursos não convencionais com maior potencial para utilização de determinadas técnicas de MEOR. Finalmente, foram identificadas algumas técnicas de MEOR que merecem maiores estudos, entre as técnicas mais consolidadas (como a produção de biossurfatantes e biopolímeros, e o controle da biocorrosão), e as que ainda não foram completamente viabilizadas (como a gaseificação de carvão, óleo e matéria orgânica; a dissociação microbiana de hidratos de gás; a bioconversão de CO2 em metano; e a bioacidificação). Apesar de seu potencial ainda não ser amplamente reconhecido, as técnicas de MEOR representam o limiar de uma nova era na estimulação da produção de recursos petrolíferos existentes, e até mesmo para os planos de desenvolvimento de novas áreas petrolíferas e recursos energéticos. Este trabalho fornece o embasamento técnico para sugerir novas iniciativas, reconhecer o potencial estratégico de MEOR, e para ajudar a realizar seu pleno potencial e seus benefícios. / The traditional methods of stimulating production, involving the injection of water, steam, gas or other products, have established the conceptual basis for new methods of oil extraction, utilizing microorganisms and biological processes. Technologies that employ biostimulation and bioaugmentation processes are widely utilized in numerous industrial, pharmaceutical and agroindustrial applications, and, more recently, in the oil industry. Given the enormous economic dimension of the oil industry, any technology that can increase production or recovery of an oil field creates the expectation of large technical, economic and strategic benefits. In order to assess the possible impact of MEOR (Microbial Enhanced Oil Recovery) on the recovery factor of oil and gas reserves in Brazil, and which techniques might be most indicated, a wide ranging study of those techniques and of various aspects of the geology of Brazil was carried out. Preliminary studies of a MEOR technique (bioacidification) with possible application in Brazilian reservoirs were also carried out. The results demonstrate that MEOR techniques can be effective in the production, solubilization, emulsification or transformation of several compounds, and that they can promote other physical effects in the oil or the reservoir rock matrix. Brazilian oil basins and unconventional resources with potential for utilization of certain MEOR techniques were also identified. Finally, certain MEOR techniques that deserve further studies were identified, involving both more consolidated techniques (such as biosurfactant and biopolymer production, and the control of microbially induced corrosion), as well as those that have not yet fully proven their viability (such as coal, oil and organic matter gasification; microbial dissociation of gas hydrates; bioconversion of CO2 into methane; and bioacidification). Despite the fact that their potential is not yet fully recognized, MEOR techniques represent the dawn of a new era in the stimulation of production of existing oil resources, and even in the production development plans of new oil and other energy resources. This work furnishes the technical basis for suggesting new initiatives, for recognizing the strategic potential of MEOR, and for helping to realize the full potential of MEOR and its benefits.