[pt] A inundação com água de baixa salinidade é uma estratégia de recuperação avançada de petróleo (EOR) em reservatórios carbonatados, onde a concentração e composição da salmoura são cruciais para a remoção do óleo. Este estudo investigou os aspectos químicos e físicos da inundação com água de baixa salinidade e seu impacto na recuperação de petróleo, focando na interação e modificações na interface óleo-calcita. Medidas de FTIR foram utilizadas para caracterizar a adsorção e quantificar a remoção de óleo mineral Nujol em monocristais de calcita clivados no plano (104), antes e após condicionamentos nas salmouras em diferentes condições. Os resultados mostraram que o Nujol forma um filme contínuo na superfície da calcita, impedindo sua dissolução nas condições de condicionamento nas salmouras de menor teor de sal. A quantidade de óleo removido variou conforme a salinidade da salmoura. Nas condições experimentais investigadas, a superfície de calcita recém clivada é mais eficientemente convertida de oleofílica para hidrofílica quando condicionada em condição de salinidade intermediaria (LS75). A remoção de óleo foi quantificada por meio de análise FTIR semiquantitativa, variando de aproximadamente 20 por cento de óleo removido para água de formação (FW) até cerca de 81 por cento após condicionamento em LS75. A análise espectroscópica indicou uma competição entre a incorporação de espécies iônicas da salmoura na interface e a dissolução da calcita, afetando diretamente na cristalinidade da superfície. O condicionamento com água deionizada (DW) não resultou na remoção ideal de óleo devido à maior dissolução e readsorção de moléculas de óleo. O estudo também constatou que o magnésio exerceu maior influência na remoção de óleo da superfície em comparação com o cálcio. As superfícies previamente hidratadas com FW e DW apresentaram alterações significativas. A hidratação com FW não necessariamente causa dissolução, mas promove a adsorção de grupos OH, criando pontos de ancoragem para o óleo. Em contraste, a hidratação com DW resultou na perda de cristalinidade, gerando defeitos na superfície. Em ambos os casos, foram observadas mudanças nas bandas de vibração características do nujol, sugerindo diferentes interações do óleo com a superfície. Comparando a quantidade de óleo adsorvida nas três condições estudadas, a calcita hidratada com FW apresentou a maior quantidade de óleo adsorvido, associado à adsorção de íons na superfície. / [en] Low salinity water flooding is an advanced oil recovery (EOR) strategy in carbonate reservoirs, where the concentration and composition of the brine are crucial for oil removal. This study investigated the chemical and physical aspects of low salinity water flooding and its impact on oil recovery, focusing on the interaction and modifications at the oil-calcite interface. FTIR measurements were used to characterize the adsorption and quantify the removal of mineral oil Nujol on calcite single crystals cleaved along the (104) plane, before and after conditioning in brines under different conditions. The results showed that Nujol forms a continuous film on the calcite surface, preventing its dissolution under aging conditions in lower salinity brines. The amount of oil removed varied according to the salinity of the brine. Under the experimental conditions investigated, the freshly cleaved calcite surface is more efficiently converted from oleophilic to hydrophilic when conditioned in intermediate salinity condition (LS75). The oil removal was quantified using semiquantitative FTIR analysis, ranging from approximately 20 percent for formation water (FW) to about 81 percent after conditioning in LS75. Spectroscopic analysis indicated a competition between the incorporation of ionic species from the brine at the interface and the dissolution of calcite, directly affecting the surface crystallinity. Conditioning with deionized water (DW) did not result in optimal oil removal due to increased dissolution and re-adsorption of oil molecules. The study also found that magnesium had a greater influence on oil removal from the surface compared to calcium. The surfaces previously hydrated with FW and DW showed significant alterations. Hydration with FW does not necessarily cause dissolution but promotes the adsorption of OH groups, creating anchoring points for the oil. In contrast, hydration with DW resulted in a loss of crystallinity, generating defects on the surface. In both cases, changes in the characteristic vibration bands of nujol were observed, suggesting different interactions of the oil with the surface. Comparing the amount of oil adsorbed under the three conditions studied, the calcite hydrated with FW showed the highest amount of adsorbed oil, associated with ion adsorption on the surface.

Reservoir simulation is a powerful tool to model fluid flow within oil and gas reservoirs and predict their behaviour. This dissertation is devoted primarily to model some thermal enhanced oil recovery (TEOR) methods. Two software were used for this purpose and namely; Comsol Multiphysics® and CMG® (Computer Modelling Group). The dissertation can be classified into three parts and all of them are standalone that discuss different topics within TEOR. The work starts with reviewing enhanced oil recovery (EOR) methods with concentration on thermal methods (TEOR) for heavy oil and bitumen. Basics of mathematical modelling of single, two-phase, and three-phase flow in porous media that is the base of all commercial and scientific reservoir simulation software are reviewed. Formulations of the set of representative PDEs are reviewed and other formulations are suggested and applied directly in subsequent sections in Comsol Multiphysics®. Part-1: The application of finite element method (FEM) in reservoir simulation has been discussed and evaluated using Comsol Multiphysics package which is based on Galerkin approach. In the demonstrated problems, the mathematical model is solved using mathematics module in Comsol Multiphysics. Energy equation in 1D, Buckley-Leverett benchmark, two-phase flow model on ¼ inverted 5-spot scheme in 3D, and SAGD process PDE model are all solved and discussed. FEM using Comsol Multiphysics looks promising at moderate mobility ratios. Part-2: A comparison of water flooding with steam injection in heavy oil reservoirs as secondary stage is demonstrated and discussed. The whole modelling was achieved by CMG-STARS. A comparison of five different scenarios is shown. SPE4 comparative project data were used for this purpose. The results showed that steam can achieve more recovery in a short period of time with an ultimate recovery factor higher than cold recovery followed by steam flooding process. Part-3: A series of flooding and in-situ combustion experimental work that has been achieved in Kazan Federal University in cooperation with Institute of Drilling Engineering and Fluid Mining (IBF) is elaborated briefly and discussed. Four experiments with different core samples (consolidated and unconsolidated) were run between 05-2020 and 05-2021. The samples were taken from a Russian extra-heavy oilfield with initial viscosity around 600,000 cP. The results were evaluated and a numerical model was built using CMG-STARS. The numerical results were correlating the experimental results. Relative permeability data were history matched for flooding processes and this data was used for in-situ combustion model. Modelling of the reactions in in-situ combustion was a challenge to match the experimental results. The final results showed that steam injection was not the best recovery method for this oilfield and in-situ combustion was the best available technique with the highest recovery factor.

La thèse a pour but d’étudier les effets de changements de mouillabilité de roches dans des conditions d’injections d’eau douce en tant que méthode de récupération d’hydrocarbures. Afin d’identifier le ou les mécanismes à l’origine du gain additionnel de récupération nous avons utilisé un microtomographe RX. Nous avons ainsi imagé les états de saturations finales d’un milieu poreux rempli de saumures et d’huiles. Une fois le drainage primaire réalisé nous avons effectué deux phases d’imbibitions : avec une saumure (récupération secondaire) puis une imbibition d’eau douce (récupération tertiaire). L’analyse de la mouillabilité à l’échelle du pore a permis de mettre en évidence l’effet de la température et de la salinité sur la mouillabilité. Nous avons montré que les changements de mouillages des roches n’étaient pas occasionnées par la seule expansion de la couche électrique en revanche des changements de mouillabilité ont été montrés. Ces changements s’expliquant par des transitions de mouillages de second ordre observées non seulement pour des gouttes d’huiles sur de l’eau mais également sur un substrat en verre. Au final, la mouillabilité en milieux poreux doit être mise en évidence à une échelle sous-Micrométrique ce qui est relativement nouveau dans le domaine pétrolier. / The aim of the thesis is to study rock wettability change effects caused by Low Salinity brine injection as tertiary recovery method. To identify the underlying mechanism or mechanisms of additional oil recovery X-Ray imaging technology was applied. We have also imaged the end-Point saturations of filled by brine and water core samples. Once the primary drainage is realized we carried out two phases imbibitions: with high salinity brine (waterflooding) and with low salinity brine (tertiary recovery mode). The wettability analysis at pore scale permitted to put in evidence the thermal and saline effects playing a decisive role in rock wettability. We have showed wettability changes are not caused by only electrical double layer expansion, however wettability changes was shown. These changes are explained by wettability transition of second order and observed not only for oil droplet on brine, but also for oil deposited on glass substrate. Finally, the pore space wettability needs to be evidenced at sub-Micrometric scale that is new for the petroleum domain.

L'injection de tensioactifs est une méthode très appliquée dans le domaine de la récupération améliorée des hydrocarbures. Cependant, son efficacité repose sur la capacité de ces agents chimiques à mobiliser l'huile résiduelle en diminuant la tension interfaciale entre l'huile et l'eau. Des modèles à l'échelle du réservoir calculent l'efficacité de la récupération d'huile résiduelle par injection de solutions contenant des tensioactifs. Les mécanismes physiques pris en compte dans les modélisations font intervenir la physico-chimie du système roche-fluide et une courbe globale donnant la saturation résiduelle en huile en fonction du nombre capillaire (courbe de désaturation capillaire). Cette donnée est majeure dans le calcul de l'efficacité de récupération d'huile par injection de solutions de tensioactifs. En effet la mobilisation de l'huile résiduelle laissée en place après injection d'eau n'est possible qu'en augmentant considérablement le nombre capillaire. La prédiction de l'efficacité d'un procédé chimique de récupération passe par la compréhension, à l'échelle du pore, du processus de mobilisation des ganglions d'huile suivant la structure poreuse et le nombre capillaire. L'objet de cette thèse est de caractériser la récupération d'huile tertiaire en fonction du nombre capillaire dans diverses roches mouillables à l'eau. Ces courbes permettront de quantifier l'effet de la microstructure, les hétérogénéités du milieu poreux et diverses propriétés pétrophysiques sur la récupération d'huile. Cette thèse permettra aussi de caractériser les différents mécanismes d'action de tensioactifs sur la mobilisation d'huile résiduelle dans le milieu poreux. L'expérimentation par tomographie RX est utilisée. La tomographie RX permettra de caractériser les courbes de désaturation capillaire à l'échelle de Darcy et visualiser localement le déplacement d'huile résiduelle à travers les milieux poreux. Des essais d'écoulement diphasique sous micro-CT permettront d'observer in-situ et d'étudier les interfaces eau/huile et leurs évolutions en 3D au sein du milieu poreux en fonction du nombre capillaire. / Oil recovery by surfactant injection is related to oil-water interfacial tension and rock properties through the capillary number. In the modeling of oil recovery by surfactant injection, fluid flow physical mechanisms are represented through the capillary desaturation curve (CDC). This curve is central in the evaluation of oil recovery efficiency. In order to mobilize residual oil trapped after waterflooding by capillary forces, chemical EOR rely on increasing capillary number to extremely high values. The mechanisms governing oil release can be described at the pore scale where the balance of capillary and viscous forces is achieved. This description will help to predict the efficiency of surfactant based EOR processes by taking into account the porous geometry and topology, the physico-chemical properties of the fluids and the different phase interaction. The objective of this work is to characterize capillary desaturation curves for various strongly water-wet sandstones. These curves will be used to study the relationship between tertiary oil recovery and the pore structure, porous media heterogeneity and petrophysicals properties. The other aim of this work is to map the different mechanisms of oil recovery by surfactant injection. Experiments under X-Ray tomography are proposed. X-Ray tomography will be applied to characterize capillary desaturation curve at Darcy scale and to visualise the two phase flow saturation after injection. Pore scale experiments based on X-Ray micro-tomography imaging are performed to describe the different mechanisms of oil mobilization.

The topic of this thesis is carbon dioxide (CO2) capture and storage (CCS), which is a technology that is currently being promoted by industries, scientists and governments, among others, in order to mitigate climate change despite a continued use of fossil fuels. Because of the complex nature of CCS and the risks it entails, it is controversial. The aim of this thesis is to analyse how the technology may be further developed in a responsible manner. In the first part of the thesis different methods for capturing CO2 from industrial processes as well as power plants are analysed. The aim is to identify early opportunities for CO2 capture, which is considered important because of the urgency of the climate change problem. Three potential early opportunities are studied: i) capturing CO2 from calcining processes such as cement industries by using the oxyfuel process, ii) capturing CO2 from pressurised flue gas, and iii) capturing CO2 from hybrid combined cycles. Each opportunity has properties that may make them competitive in comparison to the more common alternatives if CCS is realised. However, there are also drawbacks. For example, while capturing CO2 from pressurised flue gas enables the use of more compact capture plant designs as well as less expensive and less toxic absorbents, the concept is neither suitable for retrofitting nor has it been promoted by the large and influential corporations. The second part of the thesis has a broader scope than the first and is multidisciplinary in its nature with inspiration from the research field of Science and Technology Studies (STS). The approach is to critically analyse stakeholder percep-tions regarding CCS, with a specific focus on the CCS experts. The thesis sheds new light on the complexity and scientific uncertainty of CCS as well as on the optimism among many of its proponents. Because of the uncertain development when it comes to climate change, fossil fuel use and greenhouse gas emissions, the conclusion is that CCS has to be further developed and demonstrated. A responsible strategy for a future development of CCS would benefit from: i) a search for win-win strategies, ii) increasing use of appropriate analytical tools such as life-cycle analysis, iii) a consideration of fossil fuel scarcity and increasing price volatility, iv) funding of unbiased research and v) increasing simultaneous investments in long-term solutions such as renewable energy alternatives and efficiency improvements. / QC 20100727

Canada has the second largest proven oil reserves next to Saudi Arabia which is mostly located in Alberta and Saskatchewan but is unconventional heavy oil and bitumen. The tar sands are found at the surface and are mined, yet 80% of the 173 billion barrels of heavy oil and bitumen exist in-situ according to the Canadian Association of Petroleum Producers (CAPP). Two factors inhibit the economic extraction and processing of Canadian heavy oil; its enormous viscosity ranging from 1000 to over 1 million mPa.s and the asphaltene content (high molecular weight molecules containing heavy metals and sulphur). Heavy oil and bitumen were only included in the reserves estimates through the efforts of Canadian enhanced oil recovery (EOR) research. Viscosity reduction is the one common element of in-situ methods of heavy oil recovery with the exception of cold production. Currently, steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) are being used commercially in the field where the oil’s viscosity is reduced by injecting steam. Thermal methods are energy intensive requiring vast volumes of water such that any improvement would be beneficial. Solvent extraction is one alternative requiring no water, the solvent is recoverable and reusable, and depending on the mode of operation the heavy oil is upgraded in-situ. Vapour Extraction (VAPEX) and enhanced solvent extraction (N-SolvTM) are two such methods. VAPEX and N-Solv reduce the bitumen’s viscosity via mass transfer and a combination of mass and heat transfer, respectively. A light hydrocarbon solvent (instead of steam) is injected into an upper horizontal well where the solvent mixes with the heavy oil, reduces its viscosity and allows the oil to drain under gravity to a bottom production well. The idea of using solvents for heavy oil extraction has been around since the 1970s and both VAPEX and N-Solv are patented processes. However, there is still much to be learned about how these processes physically work. Research to date has focused on varying system parameters (including model dimensions, permeability, heavy oil viscosity, solvent type and injection rate, etc.) to observe the effect on oil production from laboratory scale models. Based on an early mass balance model by Butler and Mokrys (1989) and an improvement by Das (1995), molecular diffusion alone cannot account for the produced oil rates observed from laboratory models. Until recently, very little progress had been made towards qualifying and quantifying the mass transfer mechanisms with the exception of the diffusivity of light hydrocarbons in heavy oil. Mass transfer can only be by diffusion and convection. Differentiating and quantifying the contribution of each is complex due to the nature and viscosity of the oil. The goal of this thesis is to investigate the mass transfer mechanisms during the solvent recovery of heavy oil. Quantifying the diffusion of light hydrocarbon solvents has been an active topic of research with limited success since the mid 1990’s. The experimental approach presented here focused on capturing the rate of solvent mass transfer into the bitumen by measuring the bitumen swelling and the butane uptake independently. Unlike early pressure decay methods, the pressure is held constant to not violate the assumed equilibrium solvent concentration at the interfacial boundary condition. The high solubility of solvent in heavy oil complicates the physical modeling because simplifying assumptions of a constant diffusion coefficient, constant density and a quiescent liquid should not be used. The model was developed from first principles to predict the bitumen swelling. The form of the concentration dependent diffusivity was assumed and the diffusivity coefficients initially guessed. The swelling (moving boundary) was fixed by defining a new dimensionless space coordinate and the set of partial differential equations solved using the method of lines. Using the non-linear regression (lsqnonlin) function in MATLAB®, optimising for the difference in predicted and experimentally found bitumen heights and independently validating the result using the solvent uptake, the diffusivity of butane in heavy oil (at 25oC) was found to be Dsb = 4.78 x 10-6ωs + 4.91 x 10-6 cm2/s where ωs is the solvent mass fraction. Diffusion alone has proven inadequate in predicting oil recovery rates from laboratory scale models. It is logical to assume that convective mass transfer plays a role at mixing the solvent and bitumen while draining via gravity through the reservoir porous matrix. Solvent extraction experiments were conducted in etched glass micromodels to observe the pore scale phenomena. The pore scale mechanisms were found to differ depending on how the solvent extraction was operated, with non-condensing (VAPEX) or condensing (N-SolvTM) solvent. Observations show increased convective mixing and an increased rate of interface advancement when the solvent condenses on the bitumen surface. Evidence of trapped butane vapour being mobilised with the draining live oil and a technique of observing solvent extraction using UV light confirm that the draining live oil is on average one pore deep. While the interface appears from a distance to be uniform, at the pore scale it is not. Live oil can drain from one to two pores via capillary displacement mechanisms in one section of the interface and via film flow only in another area (James and Chatzis 2004; James et al. 2008). This work also shows the detrimental impact of having a non-condensable gas present during solvent extraction (James and Chatzis 2008). In summary, this work emphasises the mass transfer and drainage displacement mechanisms of non-condensing (VAPEX) and condensing (N-Solv) solvent extraction methods of heavy oil recovery.

Canada has the second largest proven oil reserves next to Saudi Arabia which is mostly located in Alberta and Saskatchewan but is unconventional heavy oil and bitumen. The tar sands are found at the surface and are mined, yet 80% of the 173 billion barrels of heavy oil and bitumen exist in-situ according to the Canadian Association of Petroleum Producers (CAPP). Two factors inhibit the economic extraction and processing of Canadian heavy oil; its enormous viscosity ranging from 1000 to over 1 million mPa.s and the asphaltene content (high molecular weight molecules containing heavy metals and sulphur). Heavy oil and bitumen were only included in the reserves estimates through the efforts of Canadian enhanced oil recovery (EOR) research. Viscosity reduction is the one common element of in-situ methods of heavy oil recovery with the exception of cold production. Currently, steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) are being used commercially in the field where the oil’s viscosity is reduced by injecting steam. Thermal methods are energy intensive requiring vast volumes of water such that any improvement would be beneficial. Solvent extraction is one alternative requiring no water, the solvent is recoverable and reusable, and depending on the mode of operation the heavy oil is upgraded in-situ. Vapour Extraction (VAPEX) and enhanced solvent extraction (N-SolvTM) are two such methods. VAPEX and N-Solv reduce the bitumen’s viscosity via mass transfer and a combination of mass and heat transfer, respectively. A light hydrocarbon solvent (instead of steam) is injected into an upper horizontal well where the solvent mixes with the heavy oil, reduces its viscosity and allows the oil to drain under gravity to a bottom production well. The idea of using solvents for heavy oil extraction has been around since the 1970s and both VAPEX and N-Solv are patented processes. However, there is still much to be learned about how these processes physically work. Research to date has focused on varying system parameters (including model dimensions, permeability, heavy oil viscosity, solvent type and injection rate, etc.) to observe the effect on oil production from laboratory scale models. Based on an early mass balance model by Butler and Mokrys (1989) and an improvement by Das (1995), molecular diffusion alone cannot account for the produced oil rates observed from laboratory models. Until recently, very little progress had been made towards qualifying and quantifying the mass transfer mechanisms with the exception of the diffusivity of light hydrocarbons in heavy oil. Mass transfer can only be by diffusion and convection. Differentiating and quantifying the contribution of each is complex due to the nature and viscosity of the oil. The goal of this thesis is to investigate the mass transfer mechanisms during the solvent recovery of heavy oil. Quantifying the diffusion of light hydrocarbon solvents has been an active topic of research with limited success since the mid 1990’s. The experimental approach presented here focused on capturing the rate of solvent mass transfer into the bitumen by measuring the bitumen swelling and the butane uptake independently. Unlike early pressure decay methods, the pressure is held constant to not violate the assumed equilibrium solvent concentration at the interfacial boundary condition. The high solubility of solvent in heavy oil complicates the physical modeling because simplifying assumptions of a constant diffusion coefficient, constant density and a quiescent liquid should not be used. The model was developed from first principles to predict the bitumen swelling. The form of the concentration dependent diffusivity was assumed and the diffusivity coefficients initially guessed. The swelling (moving boundary) was fixed by defining a new dimensionless space coordinate and the set of partial differential equations solved using the method of lines. Using the non-linear regression (lsqnonlin) function in MATLAB®, optimising for the difference in predicted and experimentally found bitumen heights and independently validating the result using the solvent uptake, the diffusivity of butane in heavy oil (at 25oC) was found to be Dsb = 4.78 x 10-6ωs + 4.91 x 10-6 cm2/s where ωs is the solvent mass fraction. Diffusion alone has proven inadequate in predicting oil recovery rates from laboratory scale models. It is logical to assume that convective mass transfer plays a role at mixing the solvent and bitumen while draining via gravity through the reservoir porous matrix. Solvent extraction experiments were conducted in etched glass micromodels to observe the pore scale phenomena. The pore scale mechanisms were found to differ depending on how the solvent extraction was operated, with non-condensing (VAPEX) or condensing (N-SolvTM) solvent. Observations show increased convective mixing and an increased rate of interface advancement when the solvent condenses on the bitumen surface. Evidence of trapped butane vapour being mobilised with the draining live oil and a technique of observing solvent extraction using UV light confirm that the draining live oil is on average one pore deep. While the interface appears from a distance to be uniform, at the pore scale it is not. Live oil can drain from one to two pores via capillary displacement mechanisms in one section of the interface and via film flow only in another area (James and Chatzis 2004; James et al. 2008). This work also shows the detrimental impact of having a non-condensable gas present during solvent extraction (James and Chatzis 2008). In summary, this work emphasises the mass transfer and drainage displacement mechanisms of non-condensing (VAPEX) and condensing (N-Solv) solvent extraction methods of heavy oil recovery.

No description available.

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.