Fractured reservoirs have always been considered poor candidates for enhanced oil recovery. This can be attributed to the complexities involved in understanding and predicting performance in these reservoirs. In a fractured system, the high permeability fracture forms the preferred pathway for the injected fluids, and a large amount of oil that is stored in the matrix is bypassed. Hence, a good understanding of multiphase fluid flow in fractures is required to reduce oil bypass and increase recovery from these reservoirs. This research investigates the effect of heterogeneity and injection rates on oil bypass and also the various techniques used for the improvement of sweep efficiency in heterogeneous systems. Several coreflood experiments were performed using homogeneous and heterogeneous cores and a 4th generation X-Ray CT scanner was used to visualize heterogeneity and fluid flow in the core. Porosity and saturation measurements were made during the course of the experiment. The experimental results indicate that injection rates play a very important role in affecting the recovery process, more so in the presence of fractures. At high injection rates, faster breakthrough of CO2 and higher oil bypass were observed than at low injection rates. But very low injection rates are not attractive from an economic point of view. Hence water viscosified with a polymer was injected directly into the fracture to divert CO2 flow into the matrix and delay breakthrough, similar to the WAG process. Although the breakthrough time reduced considerably, water ??leak off?? into the matrix was very high. To counter this problem, a cross-linked gel was used in the fracture for conformance control. The gel was found to overcome ??leak off?? problems and effectively divert CO2 flow into the matrix. This experimental research will serve to increase the understanding of fluid flow and conformance control methods in fractured reservoirs.

Water alternating gas (WAG) injection is a proven technique to enhance oil recovery. It has been successfully implemented in the field since 1957 with recovery increase in the range of 5-10% of oil-initially-in-place (OIIP). In 2004, Herbert L. Stone presented a simultaneous water and gas injection technique. Gas is injected near the bottom of the reservoir and water is injected directly on top at high rates to prevent upward channeling of the gas. Stone's mathematical model indicated the new technique can increase vertical sweep efficiency by 3-4 folds over WAG. In this study, a commercial reservoir simulator was used to predict the performance of Stone's technique and compare it to WAG and other EOR injection strategies. Two sets of relative permeability data were considered. Multiple combinations of total injection rates (water plus gas) and water/gas ratios as well as injection schedules were investigated to find the optimum design parameters for an 80 acre 5-spot pattern unit. Results show that injecting water above gas may result in better oil recovery than WAG injection though not as indicated by Stone. Increase in oil recovery with SSWAG injection is a function of the gas critical saturation. The more gas is trapped in the formation, the higher oil recovery is obtained. This is probably due to the fact that areal sweep efficiency is a more dominant factor in a 5-spot pattern. Periodic shut-off of the water injector has little effect on oil recovery. Water/gas injection ratio optimization may result in a slight increase in oil recovery. SSWAG injection results in a steady injection pressure and less fluctuation in gas production rate compared to WAG injection.

CO₂ enhanced oil recovery (CO₂-EOR) in residual oil zones has emerged as a viable technique to maximize both the oil production and carbon storage. Most CO₂ field projects suffer from inadequate sweep because of high mobility of CO₂ compared to the oil. Gas conformance techniques have the potential to further improve the effectiveness of CO₂-EOR projects. The choice of mobility control to improve the sweep efficiency is critical and simulation studies with hysteretic relative permeability and mechanistic foam model can assist in the choice of technique and optimization of the process for each reservoir. Two promising mobility control practices of Water Alternating Gas (WAG) and foam are evaluated using the in-house compositional gas reservoir simulator (DOE-CO₂). The effect of hysteresis and cycle dependent relative permeability on WAG and foam injections incorporating a new three-phase hysteresis model has been investigated. Simulations are performed with and without hysteresis to assess the impact of the saturation history and saturation path on gas entrapment, fluid injectivity and oil recovery. The foam assisted technique in CO₂-EOR processes has also been investigated. Here foam is generated in-situ by injecting surfactant solution with CO₂ rather than directly injecting foam. A simplified yet mechanistic population-balance model implemented in the in-house simulator has been applied to test the impact of foam. The results have been compared with an empirical foam model which is the standard model in commercial simulators. Simulations have been performed on actual field models for selection and optimization of the CO₂ injection scheme, quantifying the impact of hysteresis, depicting the effectiveness of CO₂-EOR process as against a surfactant flood, the effectiveness of foam assisted floods and insights into low tension gas flooding process. All the above analyses have also been performed on layer cake models with properties replicating the Permian Basin carbonate reservoirs and Gulf Coast sandstone reservoirs. Hysteresis shows an improvement in oil recovery of gas injection schemes where flow reversal takes place. Foam has been found to be effective and the models show lower CO₂ utilizations factors compared to the case without foam. / text

[pt] A redução drástica no valor do barril de petróleo em decorrência do crescimento desacelerado das maiores economias do mundo e da queda no consumo está promovendo uma mudança no comportamento da Indústria de Petróleo, uma vez que a redução dos custos de produção associado ao aumento da produtividade é essencial para o setor. Além disso, os aspectos ambientais estão em evidencia devido ao aumento da temperatura global nos últimos anos. Sendo assim, o Método de Recuperação Avançado WAG (Water Alternating Gas) com injeção de dióxido de carbono (CO2) é capaz de aliar aumento de produção de óleo com redução da emissão de dióxido de carbono na atmosfera. Essa dissertação tem o objetivo de estudar o efeito do WAG-CO2 sobre o fator de recuperação e sequestro de dióxido de carbono em reservatório arenítico. Para isso, serão realizadas simulações numéricas de fluxo contínuo em modelos blackoil e composicional utilizando as ferramentas WinProp, Builder, IMEX e GEM, do pacote de simuladores da CMG (Computer Modelling Group). Sendo o IMEX usado para modelos black-oil e o GEM para composicional. O conhecimento das permeabilidades, fenômenos de histerese e tensão interfacial para a simulação numérica são fundamentais para definir o plano de desenvolvimento e as variáveis do processo, responsáveis pelo acréscimo do fator de recuperação e economicidade. Porém, o IMEX e o GEM não permitem que a tensão interfacial e histerese sejam estudos simultaneamente. O fator de recuperação das simulações considerando tensão interfacial foram, em média, 3 por cento maiores que para os casos com histerese, e 0,6 por cento superiores nas injeções iniciando com o gás. Além disso, o aumento no número de poços produtores e injetores melhorou o varrido do reservatório, porém, aspectos como pressão do reservatório, produção de gás e de água devem ser monitorados. / [en] The drastic reduction in the amount of oil as a result of slowed growth of the world s largest economies and the fall in consumption, is promoting a change in the behavior of the Petroleum Industry, since the reduction in production costs coupled with increased productivity is essential for the sector. Moreover, environmental aspects are evident due to the global temperature rise in recent years.Therefore the Advanced Recovery Method WAG (Water Alternating Gas) with carbon dioxide injection (CO2) is able to combine oil production increase with a reduction in carbon dioxide emissions in the atmosphere. This dissertation is intended to study the effect of WAG-CO2 on the recovery factor and carbon dioxide sequestration in sandstone reservoir. For this, numerical simulations streaming will be held in black-oil and compositional models using the WinProp tools, Builder, IMEX and GEM, the simulator package CMG (Computer Modelling Group). Being the IMEX used for black-oil models and the GEM to compositional. Knowledge of permeability, hysteresis phenomena and interfacial tension for the numerical simulation are essential to define the development plan and the process variables responsible for the increase in the recovery factor and economy. However, IMEX and GEM not allow the interfacial tension and hysteresis be studied simultaneously. The result of simulations for interfacial tension were, on average, greater than 3 percent for the cases with hysteresis, and 0.6 percent higher in injections with starting gas. Furthermore, the increase in number of producing and injection wells improved sweep of the reservoir, however, aspects such as reservoir pressure, gas production and water must be monitored.

Experimental and numerical simulation studies were conducted to investigate the improvement of light oil recovery in carbonate cores during CO2 injection. The main steps in the study are as follows. First, the minimum miscibility pressure of 31ºAPI west Texas oil and CO2 was measured using the slimtube (miscibility) apparatus. Second, miscible CO2 coreflood experiments were carried out on different modes of injection such as CGI, WF, WAG, and SWAG. Each injection mode was conducted on unfractured and fractured cores. Fractured cores included two types of fracture systems creating two shape models on the core. Also, runs were made with different salinity levels for the injected water, 0 ppm, 60,000 ppm, and 200,000 ppm. Finally, based on the experimental results, a 2-D numerical simulation model was constructed and validated. The simulation model was then extended to conduct sensitivity studies on different parameters such as permeability variations in the core, WAG ratio and slug size, and SWAG ratio. The results of this study indicate that injecting water with CO2 either simultaneously or in alternating cycles increases the oil recovery by at least 10 percent and reduces the CO2 requirements by 50 percent. The salinity of the injected water has shown a detrimental effect on oil recovery only during WAG and SWAG injections. Lowering injected water salinity, which increases the CO2 solubility in water, increases oil recovery by up to 18 percent. Unfractured cores resulted in higher recovery than all fractured ones. CGI in fractured cores resulted in very poor recovery but WAG and SWAG injections improved the oil recovery by at least 25 percent over CGI. This is because of the better conformance provided by the injected water, which decreased CO2 cycling through the fracture. CO2 injection in layered permeability arrangements showed significant decrease in oil recovery (up to 40 percent) compared to the homogenous case. For all injection modes during the layered permeability arrangements, the best oil recovery was obtained when the flow barrier is in the middle of the core. When the permeability was arranged in sequence, each injection mode showed different preference to the permeability arrangements. The WAG ratio study in the homogenous case showed that a 1:2 ratio had the highest oil recovery, but the optimum ratio was 1:1 based on the amount of injected CO2. In contrast, layered permeability arrangements showed different WAG ratio preference depending on the location of the flow barrier.

[pt] Na última década a participação dos campos do Pré-Sal brasileiro na produção nacional de petróleo aumentou substancialmente, tornando esses campos responsáveis por mais da metade da produção nacional e com perspectiva de crescimento para os próximos anos. Os reservatórios de petróleo encontrados nessa região são caracterizados por espessuras que podem variar de poucas dezenas a centenas de metros, rochas com boas qualidades permo-porosas e presença de óleo leve, com elevado teor de gás associado e com contaminantes como CO2. Por estas características, diversos sistemas de produção instalados nestes reservatórios foram preparados e deverão adotar o método de recuperação suplementar com injeção alternada de água e gás. No presente trabalho foi feita uma análise paramétrica sobre a influência que propriedades de reservatório como espessura porosa, permeabilidade horizontal, permeabilidade vertical e razão kv/kh, e variáveis operacionais como vazão de operação, razão WAG e tempo de ciclo podem gerar no fator de recuperação em um cenário de produção típico do Pré-Sal brasileiro com e sem o efeito de segregação gravitacional. Pela comparação dos resultados em diversos casos de simulação numérica, foi possível identificar as variáveis com maior impacto e a influência decorrente do efeito gravitacional. Em seguida, a partir de uma análise de sensibilidade foi gerada uma equação para estimar o fator de recuperação em função das variáveis selecionadas. Números adimensionais propostos na literatura para avaliar a segregação gravitacional de fluidos em meio poroso foram calculados e utilizados para gerar outras equações para estimar o fator de recuperação. As estimativas do fator de recuperação feitas por cada função foram comparadas com os valores simulados para cada caso e foram identificadas as funções que apresentaram as estimativas mais próximas. Tais funções poderão ser utilizadas para estimar o fator de recuperação no cenário proposto e com aplicação em análises preliminares para projetos de desenvolvimento de campos de petróleo. / [en] In the last decade, the contribution of Brazilian pre-salt fields in the national oil production has increased substantially, setting these fields as responsible for more than half of the national production and with growth perspectives for years to come. The oil reservoirs found in this region are characterized by thicknesses which can vary from a few tens to hundreds of meters, rocks with favorable matrix properties, and the presence of light oil with a high associated gas content and contaminants such as CO2. Due to these characteristics, several production systems installed in these reservoirs were prepared and should adopt water alternating gas injection as supplementary recovery method. In the present study, a parametric analysis was performed on the influence that reservoir properties as porous thickness, horizontal permeability, vertical permeability, and kv/kh ratio, and operating variables as operating flow rate, WAG ratio, and cycle time can provoke in the recovery factor in a typical Brazilian pre-salt production scenario with and without the effect of gravitational segregation. By comparing the results in several cases of numerical simulation it was possible to identify the variables with the greatest impact and the influence of the gravity effect on recovery. From a sensitivity analysis, equations to estimate the recovery factor as a function of the selected variables or as a function of dimensionless numbers proposed in the literature to assess the gravitational segregation of fluids in porous media were adjusted. The recovery factor estimates made with each function were compared with the simulated values for each case and the functions that presented the best estimates were identified. Such functions can be used to estimate the recovery factor in the application scenario with application in preliminary analyzes for oil field development projects.

Made available in DSpace on 2014-12-17T14:08:56Z (GMT). No. of bitstreams: 1 JofranyaWAP_DISSERT.pdf: 2973696 bytes, checksum: 2de846649570e278d51d0d67ec195c5e (MD5) Previous issue date: 2014-03-06 / After the decline of production from natural energy of the reservoir, the methods of enhanced oil recovery, which methods result from the application of special processes such as chemical injection, miscible gases, thermal and others can be applied. The advanced recovery method with alternating - CO2 injection WAG uses the injection of water and gas, normally miscible that will come in contact with the stock oil. In Brazil with the discovery of pre-salt layer that gas gained prominence. The amount of CO2 present in the oil produced in the pre-salt layer, as well as some reservoirs is one of the challenges to be overcome in relation to sustainable production once this gas needs to be processed in some way. Many targets for CO2 are proposed by researchers to describe some alternatives to the use of CO2 gas produced such as enhanced recovery, storage depleted fields, salt caverns storage and marketing of CO2 even in plants. The largest oil discoveries in Brazil have recently been made by Petrobras in the pre -salt layer located between the states of Santa Catarina and Esp?rito Santo, where he met large volumes of light oil with a density of approximately 28 ? API, low acidity and low sulfur content. This oil that has a large amount of dissolved CO2 and thus a pioneering solution for the fate of this gas comes with an advanced recovery. The objective of this research is to analyze which parameters had the greatest influence on the enhanced recovery process. The simulations were performed using the "GEM" module of the Computer Modelling Group, with the aim of studying the advanced recovery method in question. For this work, semi - synthetic models were used with reservoir and fluid data that can be extrapolated to practical situations in the Brazilian Northeast. The results showed the influence of the alternating injection of water and gas on the recovery factor and flow rate of oil production process, when compared to primary recovery and continuous water injection or continuous gas injection / O m?todo de recupera??o avan?ada com inje??o alternada WAG-CO2 utiliza da inje??o de ?gua e g?s, g?s esse normalmente misc?vel que vai entrar em contato com o banco de ?leo. No Brasil com a descoberta da camada pr?-sal esse g?s ganhou destaque. A quantidade de CO2 presente no ?leo produzido na camada pr?-sal, assim como acontece em alguns reservat?rios ? um dos desafios a serem vencidos com rela??o ? produ??o sustent?vel uma vez que esse g?s precisa ser processado de alguma maneira. Muitos os destinos para o CO2 s?o propostos por estudiosos, que descrevem algumas alternativas para uso do g?s CO2 produzido, tais como, recupera??o avan?ada, armazenamento em campos depletados, armazenamento em cavernas de sal e ainda comercializa??o do CO2 em plantas. As maiores descobertas de petr?leo, no Brasil, foram feitas recentemente pela Petrobras na camada pr?-sal localizada entre os estados de Santa Catarina e Esp?rito Santo, onde se encontrou grandes volumes de ?leo leve com uma densidade em torno de 28? API, baixa acidez e baixo teor de enxofre. ?leo esse que possui uma grande quantidade de CO2 dissolvido e assim uma solu??o pioneira para o destino desse g?s vem sendo a recupera??o avan?ada. O objetivo dessa pesquisa ? analisar quais os par?metros que tiveram maior influ?ncia no processo de recupera??o avan?ada. As simula??es foram realizadas utilizando o m?dulo GEM da Computer Modelling Group, com o objetivo de realizar estudos do m?todo de recupera??o avan?ada em quest?o. Para a realiza??o deste trabalho, modelos semi-sint?ticos foram utilizados com dados de reservat?rio e fluidos que podem ser extrapolados para situa??es pr?ticas do Nordeste brasileiro. Os resultados mostraram a influ?ncia do processo de inje??o alternada de ?gua e g?s sobre o fator de recupera??o e vaz?o de produ??o de ?leo, quando comparados ? recupera??o prim?ria e inje??o cont?nua de ?gua ou inje??o cont?nua de g?s

With the production from mature oil fields declining, the increasing demand of oil urges towards more effective recovery of the available resources. Currently, the CO2 Floods are the second most applied EOR processes in the world behind steam injection. With more than 30 years of experience gained from CO2 flooding, successful projects have showed incremental oil recovery ranging from 7 to 15 % of the oil initially in place. Despite all of the anticipated success of CO2 floods, its viscosity nature is in heterogeneous and naturally fractured reservoirs is challenging; CO2 will flow preferentially through the easiest paths resulting in early breakthrough and extraction ineffectiveness leaving zones of oil intact. This research aims at investigating gel treatments and viscosified water-alternating-gas CO2 mobility control techniques. A set of experiments have been conducted to verify the effectiveness and practicality of the proposed mobility control approaches. Our research employed an imaging technique integrating an X-Ray CT scanner with a CT friendly aluminum coreflood cell. With the integrated systems, we were able to obtain real time images when processed provide qualitative and qualitative evaluations to the coreflood. The research studies included preliminary studies of CO2 and water injection performance in fractured and unfractured cores. These experiments provided a base performance to which the performances of the mobility control attempts were compared. We have applied the same methodology in evaluation of the experimental results to both conformance control gel treatments and viscosified water-alternating-gas CO2 mobility control. The gel conformance control studies showed encouraging results in minimizing the effect of heterogeneities directing the injected CO2 to extract more oil from the low permeability zones; the gel strength was evaluated in terms of breakdown and leakoff utilizing the production data aided with CT imaging analysis. The viscosified water coupled with CO2 investigations showed great promising results proving the superiority over neat CO2 injection. This research serves as a preliminary understanding to the applicability of tested mobility control approaches providing a base to future studies in this category of research.

The WAG injection project feasibility of South Flank of Central Azeri field on the basis of simulation model was studied in this thesis work. The 58 sensitivity scenarios were considered to evaluate and analyze the behavior of WAG in this field. Scenarios are based on the important WAG parameters, such as half slug size volume, cycles, WAG ratio, start time, bottomhole injection pressure etc. The Base Case is set with static and dynamic characteristic close to real field. From the scenarios calculated, the Best (Scenario 53, 9.3% incremental oil) and the Worst (Scenario 52, 3.4% incremental oil) cases were analyzed to get general view of WAG in terms of profitability in comparison to the Base Case. For more profound conviction of feasibility of the WAG project, additional cases with Simultaneous WAG injection and cases with changed permeabilities have been considered. The Best case was re-evaluated under application of Carlson&rsquo / s relative permeability hysteresis model. All results eventually were analyzed in terms of economical profitability &ndash / net present value (NPV). Economical analysis of scenarios is provided at the end of the work.

[pt] Como solução para viabilizar a produção de óleo com alto teor de dióxido de carbono, condição característica do pré-sal brasileiro, foi escolhida a estratégia de reinjeção desse mesmo gás produzido como método de recuperação de petróleo e como instrumento de mitigação da emissão atmosférica desse tipo de GEE (Gas do Efeito Estufa). A combinação de duas técnicas de recuperação, a injeção de água e a de gás, conhecida como WAG (Water Alternated Gas) se mostrou promissora por combinar benefícios como a varredura microscópica do gás com a estabilidade e economia obtidas pela injeção de água. Este projeto tem como objetivo entender o potencial de produção para traçar uma estratégia de otimização de recuperação do óleo aliado ao armazenamento da maior quantidade de CO2 possível, por meio de simulações numéricas de fluxo contínuo por modelos composicionais. A metodologia adotada para este projeto foi a utilização de módulos comerciais de simulação de reservatórios, fornecidos pela CMG (Computer Modeling Group), para ajuste de dados PVT de um fluido com características próximas ao do pré-sal, para que este pudesse ser aplicado em dois modelos sintéticos de reservatórios, para otimização de campo e avaliação deste pós período de produção. Desta forma, o presente trabalho proporciona uma visão do comportamento do método WAG e sua influência sobre o fator de recuperação deste reservatório, além de discutir as interações envolvidas em microescala em um ambiente reativo como um reservatório carbonático na presença do CO2. A partir dos resultados obtidos com a simulação, é possível concluir que as reações químicas entre os componentes aquosos e minerais presentes na formação porosa tem como consequência o aprisionamento do carbono. / [en] The strategy of CO2 produced reinjection is a solution to enable the pre-salt oil production as a petroleum recovery method and as an instrument to mitigate atmospheric emission of this GHG (Greenhouse Gas). The combination of two recovery techniques, water and gas injection, is known as Water Alternated Gas (WAG) has shown a successful combination of benefits such as microscopic gas sweeping with the stability and economy achieved by water injection. This project aims to understand the production potential to outline an optimization strategy of oil recovery coupled with the CO2 maximum storage possible, through numerical simulations of continuous flow by compositional models. The methodology adopted for this project was the use of commercial reservoir simulation modules, provided by CMG (Computer Modeling Group), to adjust PVT data of a fluid with similar characteristics to the pre-salt oil and then it could be applied in two synthetic reservoir models for field optimization and evaluation of this postproduction period. Thus, the present work provides an insight into the behavior of the WAG method and its influence on the recovery factor of this reservoir as well as discussing the microscale interactions involved in a reactive environment as a carbonate reservoir in the presence of CO2. Findings obtained by the simulation process shows that the chemical reactions between the aqueous and mineral components present in the porous formation result in carbon entrapment.