Gas injection, the fastest growing tertiary oil recovery technique, holds the promise of significant recoveries from those depleted oil reservoirs around the world which fall into a pressure range of (50-200) bar mainly. However, its application with the usual techniques is restricted by the need for various surface facilities such as enormous gas supply and storage. The only surface facility that downhole gasification of hydrocarbons (DHG) requires, on the other hand, is a portable electricity generator. DHG consists in producing inert gases, H2, CO, CO2 and CH4 through the steam reforming reaction of a part of the produced oil in a gasifier-reformer reactor positioned alongside the producer well in the reservoir. The gases, mainly H2 -the most effective displacing gas among produced gases- are injected into a gas cap above the oil formation, to increase oil recovery through a gas displacement drive mechanism. So far, DHG has only been tested under laboratory conditions using methane, pentane/reservoir gas and naphtha/reservoir gas as feedstock at conditions of reservoir pressure up to 130 bar. The studies varied reaction temperature, steam to carbon (S/C) ratio, catalyst types and catalyst loading in the gasifier-reformer reactor of a small pilot scale rig. These experimental studies demonstrated that pressure is one of the main factors influencing the effectiveness of the DHG process. From this starting point, the present investigation was directed at extending the pressure range up to 160 bar in the gasifier-reformer reactor using a naphtha fraction as feedstock in order to investigate whether the conversion and H2 concentration in produced dry gas can be maintained at acceptable levels under conditions of high pressure. To this end, experimental studies were carried out within the laboratory using the existing DHG rig on the small pilot scale, which was successfully commissioned and revamped for the purposes of this study. Initially, the investigation focused on exploring operating conditions, namely, steam to carbon (S/C) ratio, length of the gasifier-reformer reactor tube/ catalyst loading and the relative performance of two different catalysts. Subsequently, experiments on shutdown/start up cycles followed by variation of temperature were performed to simulate the effect of sudden electrical disruptions that usually occur in field operations. Experimental results using naphtha at pressure from 80 to 160 bar at 650 ºC, S/C= 6 achieved total feedstock conversion, no coke deposits and, most importantly, high H2 concentration in the produced dry gas (56-63 vol. % plus other gases). The best result was obtained with a crushed HiFUEL R110 catalyst (40-60 wt. % of NiO/CaO.Al2O3) and a reactor tube length of 72 cm, but the results with a C11-PR catalyst (40 wt. % of NiO/MgO.Al2O3) and a reactor tube length of 30 cm were similarly favourable. These results were supported by results of a numerical DHG model which indicated total feedstock conversion and values of H2 around 67 vol. % (using n-heptane as model surrogate). The results suggest that the DHG process is technically feasible at the pressure values studied, perhaps up to 200 bar where there are many hundreds of depleted, light oil reservoirs, especially in North America and other parts of the world below that pressure value.

Made available in DSpace on 2014-12-17T15:42:08Z (GMT). No. of bitstreams: 1 GilianeCMNS_DISSERT.pdf: 1750841 bytes, checksum: cedbb003a4fc658825db6f8e66611748 (MD5) Previous issue date: 2013-06-25 / In this research the removal of light and heavy oil from disintegrated limestone was investigated with use of microemulsions. These chemical systems were composed by surfactant, cosurfactant, oil phase and aqueous phase. In the studied systems, three points in the water -rich microemulsion region of the phase diagrams were used in oil removal experiments. These microemulsion systems were characterized to evaluate the influence of particle size, surface tension, density and viscosity in micellar stability and to understand how the physical properties can influence the oil recovery process. The limestone rock sample was characterized by thermogravimetry, BET area, scanning electron microscopy and X-ray fluorescence. After preparation, the rock was placed in contact with light and heavy oil solutions to allow oil adsorption. The removal tests were performed to evaluate the influence of contact time (1 minute, 30 minutes, 60 minutes and 120 minutes), the concentration of active matter (20, 30 and 40 %), different cosurfactants and different oil phases. For the heavy oil, the best result was on SME 1, with 20 % of active matter, 1 minute of contact time, with efficiency of 93,33 %. For the light oil, also the SME 1, with 20 % of active matter, 120 minutes of contact time, with 62,38 % of efficiency. From the obtained results, it was possible to conclude that microemulsions can be considered as efficient chemical systems for oil removal from limestone formations / O presente trabalho objetivou estudar a remo??o de fra??es de ?leo leve e pesado em rocha calc?ria desintegrada atrav?s de sistemas microemulsionados, comparando as efici?ncias de remo??o em diferentes concentra??es de mat?ria ativa (C/T) e tempo de contato. Os sistemas microemulsionados (SME) s?o constitu?dos por tensoativo, cotensoativo, fase oleosa e fase aquosa. Nos sistemas estudados, tr?s pontos ricos em ?gua da regi?o de microemuls?o foram utilizados para verificar a efici?ncia de remo??o. Os sistemas foram caracterizados para avaliar a influ?ncia do tamanho do agregado, tens?o superficial e viscosidade na estabilidade micelar e compreender como as propriedades f?sicas podem influenciar o processo de remo??o de ?leo. A amostra de rocha calc?ria foi caracterizada por Termogravimetria, ?rea BET, Microscopia Eletr?nica de Varredura, Difra??o de Raios-X e Fluoresc?ncia de Raios-X. A rocha preparada foi colocada em contato com solu??o de ?leo leve e pesado em xileno para permitir a adsor??o de ?leo. Os testes de remo??o foram realizados a fim de avaliar a influ?ncia do tempo de contato (1, 30, 60 e 120 minutos), da concentra??o de mat?ria ativa (20, 30 e 40%), do cotensoativo e da fase oleosa. Para o ?leo pesado, o melhor resultado foi para o SME 1, com 20 % de mat?ria ativa, no tempo de 1 minuto, com 93,33 % de efici?ncia. Para o ?leo leve, o SME 1 no percentual de 20 %, com 120 minutos apresentou o melhor rendimento, com 62,38 %. A partir dos resultados obtidos, concluiu-se que os sistemas microemulsionados apresentam-se como uma alternativa eficaz para remo??o de ?leo em forma??es calc?rias

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