The understanding of multiphase flow properties is essential for the exploitation of hydrocarbon reserves in a reservoir; these properties in turn are dependent on the geometric properties and connectivity of the pore space. The determination of the pore size distribution in carbonate reservoirs remains challenging; carbonates exhibit complex pore structures comprising length scales from nanometers to several centimeters. A major challenge to the accurate evaluation of these reservoirs is accounting for pore scale heterogeneity on multiple scales. This is the topic of this thesis. Conventionally, this micron scale information is achieved either by building stochastic models using 2D images or by combining log and laboratory data to classify pore types and their behaviour. None of these capture the true 3D connectivity vital for flow characterisation. We present here an approach to build realistic 3D network models across a range of scales to improve property estimation through employment of X-ray micro-Computed Tomography (μCT) and Focussed Ion Beam Tomography (FIBT). The submicron, or microporous, regions are delineated through a differential imaging technique undertaken on x-ray CT providing a qualitative description of microporosity. Various 3-Phase segmentation methods are then applied for quantitative characterisation of those regions utilising the attenuation coefficient values from the 3D tomographic images. X-ray micro-CT is resolution limited and can not resolve the detailed geometrical features of the submicron pores. FIB tomography is used to image the 3D pore structure of submicron pores down to a scale of tens of nanometers. We describe the experimental development and subsequent image processing including issues and difficulties resolved at various stages. The developed methodology is implemented on cores from producing wackstone and grainstone reservoirs. Pore network models are generated to characterise the 3D interconnectivity of pores. We perform the simulations of petrophysical properties (permeability and formation resistivity) directly on the submicron scale image data. Simulated drainage capillary pressure curves are matched with the experimental data. We also present some preliminary results for the integration of multiscale pore information to build dual-scale network models. The integration of multiscale data allows one to select appropriate effective medium theories to incorporate sub-micron structure into property calculations at macro scale giving a more realistic estimation of properties.

The understanding of multiphase flow properties is essential for the exploitation of hydrocarbon reserves in a reservoir; these properties in turn are dependent on the geometric properties and connectivity of the pore space. The determination of the pore size distribution in carbonate reservoirs remains challenging; carbonates exhibit complex pore structures comprising length scales from nanometers to several centimeters. A major challenge to the accurate evaluation of these reservoirs is accounting for pore scale heterogeneity on multiple scales. This is the topic of this thesis. Conventionally, this micron scale information is achieved either by building stochastic models using 2D images or by combining log and laboratory data to classify pore types and their behaviour. None of these capture the true 3D connectivity vital for flow characterisation. We present here an approach to build realistic 3D network models across a range of scales to improve property estimation through employment of X-ray micro-Computed Tomography (μCT) and Focussed Ion Beam Tomography (FIBT). The submicron, or microporous, regions are delineated through a differential imaging technique undertaken on x-ray CT providing a qualitative description of microporosity. Various 3-Phase segmentation methods are then applied for quantitative characterisation of those regions utilising the attenuation coefficient values from the 3D tomographic images. X-ray micro-CT is resolution limited and can not resolve the detailed geometrical features of the submicron pores. FIB tomography is used to image the 3D pore structure of submicron pores down to a scale of tens of nanometers. We describe the experimental development and subsequent image processing including issues and difficulties resolved at various stages. The developed methodology is implemented on cores from producing wackstone and grainstone reservoirs. Pore network models are generated to characterise the 3D interconnectivity of pores. We perform the simulations of petrophysical properties (permeability and formation resistivity) directly on the submicron scale image data. Simulated drainage capillary pressure curves are matched with the experimental data. We also present some preliminary results for the integration of multiscale pore information to build dual-scale network models. The integration of multiscale data allows one to select appropriate effective medium theories to incorporate sub-micron structure into property calculations at macro scale giving a more realistic estimation of properties.

Les réservoirs carbonatés sont exploités pour leur réserve d’eau potable, de ressource géothermique ou le stockage géologique du dioxyde de carbone. Ces réservoirs sont difficiles à caractériser à cause d’une histoire diagénétique souvent complexe. Cette thèse offre de nouvelles perspectives sur la caractérisation des propriétés pétrophysiques et élastiques des calcaires urgoniens de Provence. Une approche intégrée et multi-échelle est proposée pour caractériser les propriétés pétrophysiques et élastiques des carbonates. Cette étude est basée sur des mesures de vitesse d’ondes P (Vp) et S (Vs) à l’échelle du laboratoire (centimètre–décimètre) et du terrain (mètre–décamètre). En laboratoire, les Vp et Vs ainsi que l’anisotropie sont mesurées sur des plugs et sur des carottes, en utilisant différentes fréquences centrales ultrasonores. Sur le terrain, l’approche consiste à mesurer les Vp et Vs entre deux puits distant de 2 m sur une profondeur de 14 m. Les mesures sont ensuite interprétées en fonction de la géologie observée aux échelles macro- et microscopiques. Les principaux résultats montrent que les Vp et Vs moyennes sont indépendantes de l’échelle de mesure, car elles sont dictées par la porosité. L’anisotropie causée par les fractures (15%) et les hétérogénéités (5%) se manifestent par une variabilité autour des vitesses moyennes. L’approche adoptée ici a permis de définir les interactions entre les propriétés de la matrice, les hétérogénéités, les fractures et les propriétés élastiques des roches carbonatées. Elle a montré que les propriétés élastiques tout comme les structures géologiques varient en fonction de l’échelle. / Carbonate reservoirs are also exploited for water production, geothermal energy, and carbon geological storage. Their Geophysical characterization remains challenging because of complex diagenetic history. This work offers new insights into the characterization of petrophysical, and elastic properties of the Urgonian limestones in the Provence region. An integrated multi-scale approach is proposed to characterize carbonate rocks petrophysical and elastic properties. This study relies on P- and S-wave velocity (Vp and Vs) measurements carried out at laboratory (centimeter–decimeter) and field (meter–decameter) scales. Laboratory scale Vp, Vs, and anisotropy are measured on plugs and cores, while on the field they are measured between two boreholes (crosshole) over a distance of 2 m and 14 m depth. The measurements are then compared to the geology from the macro- to the microscopic scale. The main results show that the average Vp and Vs are porosity related, and are independent from scale. Anisotropy caused by fractures (15%) and heterogeneities (5%) is responsible for variations around the mean velocities. The approach adopted during this work has enabled to scope out the interplay between matrix properties, heterogeneity, fracturing, and elastic properties in carbonate rocks. It has shown that the elastic properties evolve with scale as well as the geological structures.

La capture et le stockage géologique du CO2 constituent une option importante de limitation des émissions de gaz à effet de serre au niveau des pôles industriels et des centrales de production d’énergie. Les gaz capturés à l’issu de ces chaînes de production ne sont pas constitués de CO2 pur mais contiennent une fraction (jusqu’à 10 %) de gaz annexes qui sont essentiellement Ar, N2, SOx et NOx. Ces gaz étant pour la plupart très réactifs il est essentiel de connaître leur impact sur les conditions physico-chimiques du réservoir géologique d’accueil, ainsi que sur l’environnement dans le cas d’une de contamination des aquifères voisins du stockage. Des expérimentations en laboratoire ont simulé le vieillissement de roches de réservoir et couverture en provenance d’un réservoir carbonaté du Bassin aquitain et d’assemblages minéralogiques synthétiques dans des conditions de séquestration géologique. Les roches associées à une saumure sont altérées au contact de divers composés gazeux à 100 bar et 150°C sur une durée d’un mois : CO2 pur, SO2, NO pur et un mélange contenant majoritairement du CO2 et des fractions de Ar, N2, SO2, O2. Chaque expérience est comparée à une expérience témoin où le composé gazeux est remplacé par de l’azote. Le CO2 ne montre qu’une réactivité limitée sur les minéraux des roches. Le NO et le SO2 montrent une réactivité intrinsèque passant par des dismutations en phase aqueuse ou vapeur induisant une forte altération de la roche par une attaque acide couplée à une oxydation poussée des minéraux constitutifs des roches. Le mélange de gaz montre de la même façon une réactivité double : le S02 s’oxyde en acide sulfurique s’attaquant aux carbonates et minéraux argileux et l’O2 oxyde tous les minéraux possédant du fer ou du soufre réduit. Les gaz annexes contrôlent donc la réactivité des roches en grande profondeur. Leur présence pourrait complètement changer le comportement des roches (porosité, rhéologique) lors du stockage. Leur implication devra être anticipée dans chaque cas concret de stockage en fonction de la composition du gaz d’injection, de la minéralogie et des propriétés pétrophysiques des roches. / Capture and geological storage of CO2 are an main option to limit GHEG emissions of industrial poles and power plants. The captured gases are not constituted by pure CO2 but contain a fraction (until 10 %) of other gases : Ar, N2, SOx and NOx. Most of these gases are highly reactive and could have a strong influence on physical and chemical conditions of the milieu and on the environmement if contamination of neighbour aquifers occurs by leakages. Several laboratory experiments investigated the reactivity of carbonated reservoir and cap rocks from the Aquitaine Basin as well as the reactivity of synthetic mineralogical blends in geologically relevant P-T conditions. The rocks, associated to brine, were altered in presence of various gaseous components at 100 bar and 150°C during one month : pure CO2, pure SO2, pure NO and a CO2 mixture containing fractions of Ar, N2, SO2 and O2. Each experiment was compared with a blank in which the initial gas was replaced with pure N2. Pure CO2 show a limited reactivity on the rocks. NO and SO2 show a intrinsic reactivity by disproportionations in aqueous or vapour phases implying a high alteration of rocks by compled acid – base and oxidation mechanisms. The gas mixture show also a double reactivity : SO2 is oxidized in sulphuric acid dissolving carbonates and clay minerals and O2 oxidizes all reduced mineralogical phases. These gases even in limited fractions control the reactivity of rocks. Their presence could change the behaviour of the rock toward gas and induce positive as well as negative transformations. Their implication must be checked for each geological storage as a function of gas composition, mineralogy and petrophysical.

Made available in DSpace on 2014-12-17T14:08:55Z (GMT). No. of bitstreams: 1 AndersonLSL_DISSERT.pdf: 3992478 bytes, checksum: f60081eb3b7bc8ce8a8b75327bfcf669 (MD5) Previous issue date: 2014-02-28 / As rochas carbon?ticas ocupam, numa vis?o global, um expressivo volume da crosta terrestre. De maneira geral, pode-se dizer que essas rochas est?o presentes nas diversas unidades litoestatigr?ficas da Terra. Os reservat?rios carbon?ticos s?o reservas naturalmente fraturadas que exigem uma abordagem diferenciada na modelagem em programas de simula??o num?rica. Os modelos de dupla porosidade s?o descritos por fun??es de tranfer?ncias que modelam o fluxo de ?leo entre matriz e fraturas. Em um reservat?rio carbon?tico naturalmente fraturado o sistema de fraturas ? determinante no escoamento de fluidos dentro da reserva. Os maiores reservat?rios carbon?ticos do mundo est?o situados no Oriente M?dio e na Am?rica do Norte. As maiores reservas de ?leo brasileiras encontradas neste tipo de reservat?rio est?o localizadas nos campos do Pr?-Sal. No Pr?-Sal, um volume significativo de di?xido de carbono ? produzido juntamente com o ?leo. A disponibilidade de um volume considerav?l de di?xido de carbono derivado da produ??o de ?leo no Pr?-Sal favorece a utiliza??o dos processos de EOR (Enhanced Oil Recovery) por inje??o de g?s. O processo de inje??o de di?xido de carbono vem sendo utilizado em uma grande quantidade de projetos pelo mundo. A afinidade existente entre o ?leo e o di?xido de carbono causa uma frente misc?vel entre as duas fases causando inchamento e vaporiza??o do ?leo dentro do reservat?rio. Para o estudo, foi utilizado um modelo base de reservat?rio de dupla-porosidade, desenvolvido pela CMG para o 6? Projeto de Solu??es Comparativas da SPE, que modela sistemas de fraturas e de matriz e a tranfer?ncia de massa fluida entre elas, caracter?sticas de reservat?rios naturalmente fraturados. Foi feita uma an?lise da inje??o de diferentes vaz?es de di?xido de carbono no modelo base e em modelos semelhantes, com aumento e redu??o de 5 e 0.5 pontos nas propriedades de porosidade e permeabilidade da matriz, respectivamente, tendo a produ??o de ?leo como resultado. A inje??o de 25 milh?es de p?s c?bicos por dia de CO2 foi a vaz?o que obteve a melhor fator de recupera??o

[pt] Nesta dissertação é apresentado um estudo comparativo entre dois métodos de descrição do escoamento de fluidos em meios porosos heterogêneos e compostos de elementos arquiteturais de permoporosidade elevada, chamados fraturas e carstes. Fraturas são descontinuidades nas formações desencadeadas por tensão mecânica e carstes são espaços vazios na rocha formados por dissolução. Ambos são característicos das rochas carbonáticas do Pré-Sal, principais reservatórios produtores de petróleo do Brasil. A presença destes elementos traz grande dificuldade de caracterização e, por consequência, introduz grande incerteza nas curvas de produção previstas para cada campo. Os simuladores numéricos em diferenças finitas de Engenharia de Reservatórios, responsáveis pela geração destas curvas, representam de forma aproximada o escoamento nos espaços vazios da rocha devido à formulação aplicada. Além disso, devido à escala de quilômetros de extensão em que normalmente são utilizados, usam células que incluem os três meios (matriz porosa, carste e fratura), cujas escalas são menores que a de cada célula. Nesta dissertação, busca-se entender a equivalência entre simuladores numéricos black oil e o modelo de Brinkman, ainda não utilizado amplamente, que é um modelo físico constituído por equações que representam mais fielmente o escoamento, tanto na matriz porosa, quanto nas regiões de altíssima porosidade e nas fronteiras entre elas. Para esse objetivo, foi desenvolvido um simulador de Brinkman de fluxo monofásico em duas dimensões e capaz de representar o regime não permanente, utilizando o método dos elementos finitos para resolução das equações diferenciais. Os comportamentos não permanente e permanente do simulador criado foram validados por meio de exemplos da literatura. Os valores obtidos para a propagação da pressão e velocidade de fluxo foram comparados com os de um simulador numérico black oil na reprodução do escoamento em camadas selecionadas do modelo do carbonato do Lajedo Arapuá. Foram realizados estudos com modelos de duplo contínuo (que representam, através de parâmetros específicos, o fluxo na matriz porosa e nas fraturas, com um termo de transferência entre eles) buscando, através da variação da permeabilidade efetiva da fratura e do fator de forma, convergência aos resultados do modelo de contínuo único de referência, selecionado após análise dos resultados comparativos com Brinkman. Os resultados mostraram pouca variação entre os resultados dos métodos em cenários nos quais o sistema cárstico é composto por vugs dispersos e desconectados, enquanto que carstes em forma de condutos e com configurações complexas causam alterações na propagação da onda de pressão e nas velocidades de fluxo entre os modelos, principalmente em cenários com valores de permeabilidade mais próximos entre carste e matriz porosa na simulação black oil. A análise em duplo contínuo mostrou ser possível obter, através de modelos homogêneos e com escala até 10 vezes maiores, resultados semelhantes aos obtidos com uma modelagem black oil heterogênea com caracterização do sistema cárstico. Também foi possível concluir que a permeabilidade efetiva de fratura é suficiente como parâmetro de ajuste para encontrar um modelo equivalente, dentro de um critério de valor de variação, ao modelo de contínuo único. / [en] This dissertation presents a comparative study between two porous media fluid flow description methods applied to heterogeneous reservoirs composed of architectural elements of high permo-porosity, called fractures andkarsts. Fractures are formation discontinuities triggered by mechanical stressand karsts are empty cavities inside the formation generated by dissolution.Both are characteristic of Pre-Salt carbonate rocks, which are the main oil producing reservoirs in Brazil. The existence of these elements brings complexityin characterization and, hence, increases the uncertainty in field productionprediction curves. The Reservoir Engineering numerical simulators, based onfinite differences, that generate these curves model the flow behavior insidethe cavities in an approximate manner due to the mathematical formulationapplied. Besides, due to the kilometric scale in which they are usually applied,these models use cells that comprehend the three media (matrix, karst andfractures), whose scales are smaller than the cell’s. This dissertation evaluatesthe equivalence between black oil simulation and the Brinkman model, still notwidely used, which is a physical model made of equations that represent porousmedia flow inside high porosity regions as well as at the porous matrix andits boundaries. With this objective, a two-dimensional single-phase Brinkmansimulator, capable of representing transient flow, was designed using the finiteelements method to solve differential equations. The simulator s transient andpermanent behaviors were validated through literature analytical solutions.The pressure propagation and flow velocity values obtained while simulatingfluid flow inside selected layers from Lajedo Arapuá s carbonate formation werecompared to the ones from a black oil simulator. Studies were performed usingdual-continuum models (which calculate the fluid flow inside porous matrixand fractures separately and use a transfer term to account for the flow between them) seeking, through variation of the fracture effective permeabilityand the shape factor, convergence to the mono-continuum reference model thatwas selected after Brinkman s results comparative analysis. The results showsmall variation between the two methods when the karst system is composedof sparse and disconnected vugs, while conduit shaped karsts with complexconfiguration increase the variation in pressure wave propagation and flowvelocity values between models, especially in scenarios where matrix permeability values were closer to karst permeability values in the black oil model.The dual-continuum analysis showed that it is possible to obtain, through homogeneous and even ten times coarser models, similar results to those obtainedby a heterogeneous black oil model with karst system characterization. It wasalso possible to conclude that fracture effective permeability was sufficient asa fitting parameter in order to achieve equivalent results to those from themono-continuum model, using a threshold criteria.

A significant amount of Viscous Oil (e.g., heavy oil, extra heavy oil, and bitumen) is trapped in Naturally Fractured Carbonate Reservoirs also known as NFCRs. The word VO endowment in NFCRs is estimated at ~ 2 Trillion barrels mostly reported in Canada, the USA, Russia, and the Middle East. To date, contributions to the world daily oil production from this immense energy resource remains negligible mainly due to the lack of appropriate production technologies. Implementation of a VO production technology such as steam injection is expensive (high capital investment), time-consuming, and people-intensive. Hence, before selecting a production technology for detailed economic analysis, use of cursory or broad screening tools or guides is a convenient means of gaining a quick overview of the technical feasibility of the various possible production technologies applied to a particular reservoir. Technical screening tools are only available for the purpose of evaluation of the reservoir performance parameters in oil sands for various thermal VO exploitation technologies such as Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS), Horizontal well Cyclic steam Stimulation (HCS), and so on. Nevertheless, such tools are not applicable for VO NFCRs assessment without considerable modifications due to the different nature of these two reservoir types (e.g., presence and effects of fracture network on reservoir behavior, wettability, lithology, fabric, pore structure, and so on) and also different mechanisms of energy and mass transport. Considering the lack of robust and rapid technical reservoir screening tools for the purpose of quick assessment and performance prediction for VO NFCRs under thermal stimulation (e.g., steamflooding), developing such fast and precise tools seems inevitable and desirable. In this dissertation, an attempt was made to develop new screening tools for the purpose of reservoir performance prediction in VO NFCRs using all the field and laboratory available data on a particular thermal technology (vertical well steamflooding). Considering the complex and heterogeneous nature of the NFCRs, there is great uncertainty associated with the geological nature of the NFCRs such as fracture and porosity distribution in the reservoir which will affect any modeling tasks aiming at modeling of processes involved in thermal VO production from these types of technically difficult and economically unattractive reservoirs. Therefore, several modeling and analyses technqiues were used in order to understand the main parameters controlling the steamflooding process in NFCRs and also cope with the uncertainties associated with the nature of geologic, reservoir and fluid properties data. Thermal geomechanics effects are well-known in VO production from oil sands using thermal technologies such as SAGD and cyclic steam processes. Hence, possible impacts of thermal processes on VO NFCRs performance was studied despite the lack of adequate field data. This dissertation makes the following contributions to the literature and the oil industry: Two new statistical correlations were developed, introduced, and examined which can be utilized for the purpose of estimation of Cumulative Steam to Oil Ratio (CSOR) and Recovery Factor (RF) as measures of process performance and technical viability during vertical well steamflooding in VO Naturally Fractured Carbonate Reservoirs (NFCRs). The proposed correlations include vital parameters such as in situ fluid and reservoir properties. The data used are taken from experimental studies and also field trials of vertical well steamflooding pilots in viscous oil NFCRs reported in the literature. The error percentage for the proposed correlations is < 10% for the worst case and contains fewer empirical constants compared with existing correlations for oil sands. The interactions between the parameters were also considered. The initial oil saturation and oil viscosity are the most important predictive factors. The proposed correlations successfully predicted steam/oil ratios and recovery factors in two heavy oil NFCRs. These correlations are reported for the first time in the literature for this type of VO reservoirs. A 3-D mathematical model was developed, presented, and examined in this research work, investigating various parameters and mechanisms affecting VO recovery from NFCRs using vertical well steamflooding. The governing equations are written for the matrix and fractured medium, separately. Uncertainties associated with the shape factor for the communication between the matrix and fracture is eliminated through setting a continuity boundary condition at the interface. Using this boundary condition, the solution method employed differs from the most of the modeling simulations reported in the literature. A Newton-Raphson approach was also used for solving mass and energy balance equations. RF and CSOR were obtained as a function of steam injection rate and temperature and characteristics of the fractured media such as matrix size and permeability. The numerical solution clearly shows that fractures play an important role in better conduction of heat into the matrix part. It was also concluded that the matrix block size and total permeability are the most important parameters affecting the dependent variables involved in steamflooding. A hybrid Artificial Neural Network model optimized by co-implementation of a Particle Swarm Optimization method (ANN-PSO) was developed, presented, and tested in this research work for the purpose of estimation of the CSOR and RF during vertical well steamflooding in VO NFCRs. The developed PSO-ANN model, conventional ANN models, and statistical correlations were examined using field data. Comparison of the predictions and field data implies superiority of the proposed PSO-ANN model with an absolute average error percentage < 6.5% , a determination coefficient (R2) > 0.98, and Mean Squared Error (MSE) < 0.06, a substantial improvement in comparison with conventional ANN model and empirical correlations for prediction of RF and CSOR. This indicates excellent potential for application of hybrid PSO-ANN models to screen VO NFCRs for steamflooding. This is the first time that the ANN technique has been applied for the purpose of performance prediction of steamflooding in VO NFCRs and also reported in the literature. The predictive PSO-ANN model and statistical correlations have strong potentials to be merged with heavy oil recovery modeling softwares available for thermal methods. This combination is expected to speed up their performance, reduce their uncertainty, and enhance their prediction and modeling capabilities. An integrated geological-geophysical-geomechanical approach was designed, presented, and applied in the case of a NFCR for the purpose of fracture and in situ stresses characterization in NFCRs. The proposed methodology can be applied for fracture and in situ stresses characterization which is beneficial to various aspects of asset development such as well placement, drilling, production, thermal reservoir modeling incorporating geomechanics effects, technology assessment and so on. A conceptual study was also conducted on geomechanics effects in VO NFCRs during steamflooding which is not yet well understood and still requires further field, laboratory, and theoretical studies. This can be considered as a small step forward in this area identifying positive potential of such knowledge to the design of large scale thermal operations in VO NFCRs.

A significant amount of Viscous Oil (e.g., heavy oil, extra heavy oil, and bitumen) is trapped in Naturally Fractured Carbonate Reservoirs also known as NFCRs. The word VO endowment in NFCRs is estimated at ~ 2 Trillion barrels mostly reported in Canada, the USA, Russia, and the Middle East. To date, contributions to the world daily oil production from this immense energy resource remains negligible mainly due to the lack of appropriate production technologies. Implementation of a VO production technology such as steam injection is expensive (high capital investment), time-consuming, and people-intensive. Hence, before selecting a production technology for detailed economic analysis, use of cursory or broad screening tools or guides is a convenient means of gaining a quick overview of the technical feasibility of the various possible production technologies applied to a particular reservoir. Technical screening tools are only available for the purpose of evaluation of the reservoir performance parameters in oil sands for various thermal VO exploitation technologies such as Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS), Horizontal well Cyclic steam Stimulation (HCS), and so on. Nevertheless, such tools are not applicable for VO NFCRs assessment without considerable modifications due to the different nature of these two reservoir types (e.g., presence and effects of fracture network on reservoir behavior, wettability, lithology, fabric, pore structure, and so on) and also different mechanisms of energy and mass transport. Considering the lack of robust and rapid technical reservoir screening tools for the purpose of quick assessment and performance prediction for VO NFCRs under thermal stimulation (e.g., steamflooding), developing such fast and precise tools seems inevitable and desirable. In this dissertation, an attempt was made to develop new screening tools for the purpose of reservoir performance prediction in VO NFCRs using all the field and laboratory available data on a particular thermal technology (vertical well steamflooding). Considering the complex and heterogeneous nature of the NFCRs, there is great uncertainty associated with the geological nature of the NFCRs such as fracture and porosity distribution in the reservoir which will affect any modeling tasks aiming at modeling of processes involved in thermal VO production from these types of technically difficult and economically unattractive reservoirs. Therefore, several modeling and analyses technqiues were used in order to understand the main parameters controlling the steamflooding process in NFCRs and also cope with the uncertainties associated with the nature of geologic, reservoir and fluid properties data. Thermal geomechanics effects are well-known in VO production from oil sands using thermal technologies such as SAGD and cyclic steam processes. Hence, possible impacts of thermal processes on VO NFCRs performance was studied despite the lack of adequate field data. This dissertation makes the following contributions to the literature and the oil industry: Two new statistical correlations were developed, introduced, and examined which can be utilized for the purpose of estimation of Cumulative Steam to Oil Ratio (CSOR) and Recovery Factor (RF) as measures of process performance and technical viability during vertical well steamflooding in VO Naturally Fractured Carbonate Reservoirs (NFCRs). The proposed correlations include vital parameters such as in situ fluid and reservoir properties. The data used are taken from experimental studies and also field trials of vertical well steamflooding pilots in viscous oil NFCRs reported in the literature. The error percentage for the proposed correlations is < 10% for the worst case and contains fewer empirical constants compared with existing correlations for oil sands. The interactions between the parameters were also considered. The initial oil saturation and oil viscosity are the most important predictive factors. The proposed correlations successfully predicted steam/oil ratios and recovery factors in two heavy oil NFCRs. These correlations are reported for the first time in the literature for this type of VO reservoirs. A 3-D mathematical model was developed, presented, and examined in this research work, investigating various parameters and mechanisms affecting VO recovery from NFCRs using vertical well steamflooding. The governing equations are written for the matrix and fractured medium, separately. Uncertainties associated with the shape factor for the communication between the matrix and fracture is eliminated through setting a continuity boundary condition at the interface. Using this boundary condition, the solution method employed differs from the most of the modeling simulations reported in the literature. A Newton-Raphson approach was also used for solving mass and energy balance equations. RF and CSOR were obtained as a function of steam injection rate and temperature and characteristics of the fractured media such as matrix size and permeability. The numerical solution clearly shows that fractures play an important role in better conduction of heat into the matrix part. It was also concluded that the matrix block size and total permeability are the most important parameters affecting the dependent variables involved in steamflooding. A hybrid Artificial Neural Network model optimized by co-implementation of a Particle Swarm Optimization method (ANN-PSO) was developed, presented, and tested in this research work for the purpose of estimation of the CSOR and RF during vertical well steamflooding in VO NFCRs. The developed PSO-ANN model, conventional ANN models, and statistical correlations were examined using field data. Comparison of the predictions and field data implies superiority of the proposed PSO-ANN model with an absolute average error percentage < 6.5% , a determination coefficient (R2) > 0.98, and Mean Squared Error (MSE) < 0.06, a substantial improvement in comparison with conventional ANN model and empirical correlations for prediction of RF and CSOR. This indicates excellent potential for application of hybrid PSO-ANN models to screen VO NFCRs for steamflooding. This is the first time that the ANN technique has been applied for the purpose of performance prediction of steamflooding in VO NFCRs and also reported in the literature. The predictive PSO-ANN model and statistical correlations have strong potentials to be merged with heavy oil recovery modeling softwares available for thermal methods. This combination is expected to speed up their performance, reduce their uncertainty, and enhance their prediction and modeling capabilities. An integrated geological-geophysical-geomechanical approach was designed, presented, and applied in the case of a NFCR for the purpose of fracture and in situ stresses characterization in NFCRs. The proposed methodology can be applied for fracture and in situ stresses characterization which is beneficial to various aspects of asset development such as well placement, drilling, production, thermal reservoir modeling incorporating geomechanics effects, technology assessment and so on. A conceptual study was also conducted on geomechanics effects in VO NFCRs during steamflooding which is not yet well understood and still requires further field, laboratory, and theoretical studies. This can be considered as a small step forward in this area identifying positive potential of such knowledge to the design of large scale thermal operations in VO NFCRs.