It is widely understood that injection and production activities can induce additional stress fields that will couple with the in situ stress field. An increased shear stress may cause serious casing stability issue, and casing integrity is one of the major issues in the development of an oilfield. In this thesis, I will present a methodology for semi-quantitatively addressing the physical processes, the occurrence, and the key influential factors associated with large-area casing shear issues in Daqing Oilfield. In the research, I will investigate reservoir heterogeneity and the far-field stress field in the Daqing Oilfield, China; I will review fundamental theories of rock strength, rock failure, casing shear, and techniques for coupling fluid flow and mechanical response of the reservoirs; and I will present mathematical simulations of large-area casing shear in one typical area (X1-3B) in Daqing Oilfield, under different regimes of water-affected shale area ratio and block pressure difference. Heterogeneity in Daqing Oilfield varies according to the scale. Mega-heterogeneity is not too serious: the geometry of the oilfield is simple, the structure is flat, and faults are numerous and complex, but distributed evenly. Macro-heterogeneity is, however, intense. Horizontal macro-heterogeneity is associated with lateral variations because of different depositional facies. Vertical macro-heterogeneity of Daqing Oilfield because of layering is typified by up to 100 individual sand layers with thickness ranging from 0.2 to 20 m and permeability ranging from 20 to 1600 mD (average 230 mD). Furthermore, there are a number of stacked sand-silt-shale (clastic lithofacies) sequences. Mercury porosimetry and photo-micro-graphic analyses were used to investigate the micro-heterogeneity of Daqing Oilfield. This method yields a complete pore size distribution, from several nanometers to several thousands of micro-meters as well as cumulative pore volume distributions, pore-throat aspect ratios, and fractal dimensions. The fractal dimension can be used to describe the heterogeneity at the pore scale; for sandstones, the larger the fractal dimension of a specific pore structure, the more heterogeneous it is. Reservoir sandstones of Daqing Oilfield have similar porosity and mineralogy, so their micro-heterogeneity lies in a micro-structure of considerable variability. Differences in micro-structure affect permeability, which also varies considerably and evidences a considerable amount of micro-scale anisotropy. Finally, the number and nature of faults in the oilfield make the macro-scale heterogeneity more complex. Rock strength is affected by both intrinsic factors and external factors. Increased water saturation affects rock strength by decreasing both rock cohesion and rock friction angle. In Daqing Oilfield, is seems that a 5% increase of water content in shale can decrease the maximum shearing resistance of shale by approximately 40%. Hysteretic behavior leads to porosity and permeability decreases during the compaction stage of oilfield development (increasing σ'). Also, injection pressures are inevitably kept as high as possible in the pursuit of greater production rates. These lead to non-homogeneous distributions of pressures as well as in changes of material behavior over time. Loss of shear strength with water content increase, inherent reservoir heterogeneity, and long periods of high-pressure water injection from a number of wells are three key factors leading to casing shear occurring over large areas in Daqing Oilfield. Reservoir heterogeneity and structural complexity foster uneven formation pressure distribution, leading to inter-block pressure differences. Sustained long-term elevated pressures affect overburden shale mechanical strength as well as reducing normal stresses, and the affected area increases with time under high-pressure injection so that the affected areas overlap at the field scale and alter the in situ stress field. Once the maximum compressive stress parallels or nearly parallels the differential pressure, and the water-affected shale area is big enough, the shear stability of the interface between the shale and the sandstone is severely compromised, and when the thrust stress imposed exceeds the shearing resistance, the strata will slip in a direction corresponding to the vector from high-pressure to low-pressure areas. The change in this slip and creep displacement field is the major reason for the serious casing deformation damage in Daqing Oilfield. To quantify the scale effect of the water-affected shale area on casing stability, coupled non-linear poroelastic fluid flow was simulated for a typical area. The Daqing Oilfield simulation result is in coincidence with the in situ observation of disturbed stress fields and casing displacement. The water-affected area has a scale effect on the casing stability. The ratio of the water-affected shale formation area to the total area influences the stability coefficient much more than the block pressure difference. In the studied area, under conditions of injection pressure of 12.7 MPa and no more than 2.5 MPa block pressure difference, the water-affected ratio should be smaller than 0.50 or so in order to maintain areal casing stability. By history matching, in the studied area under current development condition and considering the water-affected ratio, so long as the injection pressure and pressure differential between blocks are controlled to be less than 12.7 MPa and 0.86 MPa respectively, formation shear slip along a horizontal surface will no longer occur.

It is widely understood that injection and production activities can induce additional stress fields that will couple with the in situ stress field. An increased shear stress may cause serious casing stability issue, and casing integrity is one of the major issues in the development of an oilfield. In this thesis, I will present a methodology for semi-quantitatively addressing the physical processes, the occurrence, and the key influential factors associated with large-area casing shear issues in Daqing Oilfield. In the research, I will investigate reservoir heterogeneity and the far-field stress field in the Daqing Oilfield, China; I will review fundamental theories of rock strength, rock failure, casing shear, and techniques for coupling fluid flow and mechanical response of the reservoirs; and I will present mathematical simulations of large-area casing shear in one typical area (X1-3B) in Daqing Oilfield, under different regimes of water-affected shale area ratio and block pressure difference. Heterogeneity in Daqing Oilfield varies according to the scale. Mega-heterogeneity is not too serious: the geometry of the oilfield is simple, the structure is flat, and faults are numerous and complex, but distributed evenly. Macro-heterogeneity is, however, intense. Horizontal macro-heterogeneity is associated with lateral variations because of different depositional facies. Vertical macro-heterogeneity of Daqing Oilfield because of layering is typified by up to 100 individual sand layers with thickness ranging from 0.2 to 20 m and permeability ranging from 20 to 1600 mD (average 230 mD). Furthermore, there are a number of stacked sand-silt-shale (clastic lithofacies) sequences. Mercury porosimetry and photo-micro-graphic analyses were used to investigate the micro-heterogeneity of Daqing Oilfield. This method yields a complete pore size distribution, from several nanometers to several thousands of micro-meters as well as cumulative pore volume distributions, pore-throat aspect ratios, and fractal dimensions. The fractal dimension can be used to describe the heterogeneity at the pore scale; for sandstones, the larger the fractal dimension of a specific pore structure, the more heterogeneous it is. Reservoir sandstones of Daqing Oilfield have similar porosity and mineralogy, so their micro-heterogeneity lies in a micro-structure of considerable variability. Differences in micro-structure affect permeability, which also varies considerably and evidences a considerable amount of micro-scale anisotropy. Finally, the number and nature of faults in the oilfield make the macro-scale heterogeneity more complex. Rock strength is affected by both intrinsic factors and external factors. Increased water saturation affects rock strength by decreasing both rock cohesion and rock friction angle. In Daqing Oilfield, is seems that a 5% increase of water content in shale can decrease the maximum shearing resistance of shale by approximately 40%. Hysteretic behavior leads to porosity and permeability decreases during the compaction stage of oilfield development (increasing σ'). Also, injection pressures are inevitably kept as high as possible in the pursuit of greater production rates. These lead to non-homogeneous distributions of pressures as well as in changes of material behavior over time. Loss of shear strength with water content increase, inherent reservoir heterogeneity, and long periods of high-pressure water injection from a number of wells are three key factors leading to casing shear occurring over large areas in Daqing Oilfield. Reservoir heterogeneity and structural complexity foster uneven formation pressure distribution, leading to inter-block pressure differences. Sustained long-term elevated pressures affect overburden shale mechanical strength as well as reducing normal stresses, and the affected area increases with time under high-pressure injection so that the affected areas overlap at the field scale and alter the in situ stress field. Once the maximum compressive stress parallels or nearly parallels the differential pressure, and the water-affected shale area is big enough, the shear stability of the interface between the shale and the sandstone is severely compromised, and when the thrust stress imposed exceeds the shearing resistance, the strata will slip in a direction corresponding to the vector from high-pressure to low-pressure areas. The change in this slip and creep displacement field is the major reason for the serious casing deformation damage in Daqing Oilfield. To quantify the scale effect of the water-affected shale area on casing stability, coupled non-linear poroelastic fluid flow was simulated for a typical area. The Daqing Oilfield simulation result is in coincidence with the in situ observation of disturbed stress fields and casing displacement. The water-affected area has a scale effect on the casing stability. The ratio of the water-affected shale formation area to the total area influences the stability coefficient much more than the block pressure difference. In the studied area, under conditions of injection pressure of 12.7 MPa and no more than 2.5 MPa block pressure difference, the water-affected ratio should be smaller than 0.50 or so in order to maintain areal casing stability. By history matching, in the studied area under current development condition and considering the water-affected ratio, so long as the injection pressure and pressure differential between blocks are controlled to be less than 12.7 MPa and 0.86 MPa respectively, formation shear slip along a horizontal surface will no longer occur.

Stress and permeability variations around a wellbore and in the reservoir are of much interest in petroleum and geothermal reservoir development. Water injection causes significant changes in pore pressure, temperature, and stress in hot reservoirs, changing rock permeability. In this work, two- and three-dimensional finite element methods were developed to simulate coupled reservoirs with damage mechanics and stress-dependent permeability. The model considers the influence of fluid flow, temperature, and solute transport in rock deformation and models nonlinear behavior with continuum damage mechanics and stress-dependent permeability. Numerical modeling was applied to analyze wellbore stability in swelling shale with two- and three-dimensional damage/fracture propagation around a wellbore and injection-induced microseismic events. The finite element method (FEM) was used to solve the displacement, pore pressure, temperature, and solute concentration problems. Solute mass transport between drilling fluid and shale formation was considered to study salinity effects. Results show that shear and tensile failure can occur around a wellbore in certain drilling conditions where the mud pressure lies between the reservoir pore pressure and fracture gradient. The fully coupled thermo-poro-mechanical FEM simulation was used to model damage/fracture propagation and microseismic events caused by fluid injection. These studies considered wellbore geometry in small-scale modeling and point-source injection, assuming singularity fluid flux for large-scale simulation. Damage mechanics was applied to capture the effects of crack initiation, microvoid growth, and fracture propagation. The induced microseismic events were modeled in heterogeneous geological media, assuming the Weibull distribution functions for modulus and permeability. The results of this study indicate that fluid injection causes the effective stress to relax in the damage phase and to concentrate at the interface between the damage phase and the intact rock. Furthermore, induced-stress and far-field stress influence damage propagation. Cold water injection causes the tensile stress and affects the initial fracture and fracture propagation, but fracture initiation pressure and far-field stress are critical to create a damage/fracture plane, which is normal to the minimum far-field stress direction following well stimulation. Microseismic events propagate at both well scale and reservoir-scale simulation; the cloud shape of a microseismic event is affected by permeability anisotropy and far-field stress, and deviatoric horizontal far-field stress especially contributes to the localization of the microseismic cloud.

[pt] A exploração crescente de campos de petróleo desafiadores é acompanhada por uma também crescente preocupação pública e de companhias petrolíferas em relação a questões ambientais e de segurança. Estudos dos principais acidentes recentes relacionados a exploração de hidrocarbonetos indicam que análises geomecânicas aprofundadas podem ser a chave para prevenir tais ocorrências. Efeitos geomecânicos podem ser muito relevantes durante análises de reservatórios. Há diversas possibilidades para considerar esses efeitos, mas a análise acoplada iterativa tem mostrado ser uma das melhores soluções, pois apresenta resultados precisos em um período de tempo computacional viável. O grupo de pesquisa PUC-Rio/GTEP tem desenvolvido um programa de acoplamento que gerencia o simulador de fluxo (IMEX ou Eclipse) e o programa de elementos finitos (Abaqus ou uma solução em GPU mais rápida chamada Chronos), de uma forma interativa. O referido programa fornece uma solução abrangente para geomecânica de reservatórios. No entanto, a geração de malha, a preparação de dados e a avaliações de resultados são barreiras para a sua aplicação na rotina de trabalho da indústria. Esta dissertação apresenta a elaboração de um fluxo de trabalho desenvolvido em um modelador geológico para aplicar a simulação acoplada de fluxo-tensão para reservatórios reais de hidrocarbonetos. Este fluxo de trabalho permite de forma simples e direta a geração de malha de elementos finitos, a definição de parâmetros mecânicos, supervisão da execução da solução acoplada e, por fim, a avaliação dos resultados de fluxo e tensão em um mesmo ambiente de visualização. / [en] The growing exploration of challenging oil fields is followed by an increasing concern by members of the public and oil companies about environmental and safety issues. Studies of recent major accidents indicate that geomechanics analyses can be the key to prevent future incidents. Geomechanical effects can be very relevant during reservoirs analyses. Actually, there are many possibilities available to consider such effects, but iterative-coupled analysis has shown to be one of the best solutions because it presents accurate results in a feasible computational timeframe. The GTEP/PUC-Rio research group has developed a coupling program that manages both the flow simulator (IMEX or Eclipse) and the finite element solver (Abaqus or a faster in-house GPU solution called Chronos) in an interactive way. The mentioned program provides a wide-ranging solution for reservoir geomechanics. However, mesh generation, data preparation and results evaluations are bottlenecks for its application in the industry s work routine. This dissertation presents the development of a workflow included in a geological modeler to apply the coupled flow-stress for real hydrocarbon reservoir simulation. This workflow allows in a simple and direct manner the generation of a finite element mesh, the definition of mechanical parameters, the supervision of coupled solution execution and the evaluation of results (flow and stress) in a single viewing environment.

[pt] A produção de um reservatório de petróleo é um processo acoplado entre fenômenos geomecânicos e de fluxo, os quais impactam o próprio reservatório e suas rochas adjacentes. Ensaios laboratoriais mostraram que amostras de um reservatório carbonático do Campo B, um campo de petróleo localizado na Bacia de Campos, são muito sensíveis às deformações causadas pela depleção. Desta forma, o objetivo deste trabalho é avaliar aspectos geomecânicos e de produção do desenvolvimento do Campo B, utilizando diferentes esquemas de acoplamento hidromecânico. Foram realizadas simulações hidromecânicas parcialmente acopladas entre o simulador de fluxo IMEX e o programa de análises geomecânicas CHRONOS (um código de elementos finitos executado em GPU) através de uma metodologia que permite análises tanto em uma, quanto em duas vias. Foi construído um Mechanical Earth Model 3D do Campo B no modelador geológico GOCAD através de um workflow específico para esta tarefa. Então, foram confrontadas respostas de respostas de fluxo e geomecânicas entre simulações feitas em uma via e em duas vias. Primeiramente, a permeabilidade não foi considerada como parâmetro de acoplamento. Neste caso, não foram encontradas diferenças significativas entre os resultados dos dois tipos de acoplamento. Posteriormente foram realizadas novas simulações em duas vias, porém considerando variações das permeabilidades decorrentes da depleção do reservatório. Os resultados destas novas análises divergiram da simulação acoplada em duas vias na qual esta propriedade foi mantida constante ao longo do tempo. Logo, neste caso, negligenciar o acoplamento da permeabilidade pode gerar erros significativos. Também foram feitas análises quanto à performance computacional das simulações hidromecânicas realizadas ao longo desta Dissertação. / [en] The production of a petroleum reservoir is a coupled process between geomechanical and flow phenomena, which affect the reservoir and its surrounding rocks. Laboratory tests have shown that samples of a carbonate reservoir from Field B, an oil field located in the Campos Basin, are very sensitive to deformations caused by depletion. Thus, this study aims to assess production and geomechanical aspects of Field B development by different hydromechanical coupling schemes. Therefore, partially coupled hydromechanical simulations between the flow simulator IMEX and the geomechanical analysis software CHRONOS (a finite element code running on GPU) were performed using a methodology which allows either one-way or two-way coupling. A 3D Mechanical Earth Model of Field B was built in GOCAD, a geological modelling software, through a specific workflow for this task. Then, flow and geomechanical results were compared between one-way and two-way coupling simulations. Initially, permeability was not considered as a coupling parameter. In this case, there were no significant differences between the results. Afterwards, more two-way coupling simulations were performed, but at this time, considering variations of permeabilities due to depletion. The results of these new simulations diverged from the two-way coupling case in which permeabilities were kept constant throughout the simulation. Therefore, in this case, neglecting permeability coupling can lead to significant errors. Computational performance of the hydromechanical simulations performed along this Dissertation were also evaluated.

Submitted by Fabio Sobreira Campos da Costa (fabio.sobreira@ufpe.br) on 2016-07-04T11:22:15Z No. of bitstreams: 2 license_rdf: 1232 bytes, checksum: 66e71c371cc565284e70f40736c94386 (MD5) TeseLeoCabral_vrsFinal.pdf: 37484380 bytes, checksum: b61e5bb415f505345e69623ffd098b9e (MD5) / Made available in DSpace on 2016-07-04T11:22:15Z (GMT). No. of bitstreams: 2 license_rdf: 1232 bytes, checksum: 66e71c371cc565284e70f40736c94386 (MD5) TeseLeoCabral_vrsFinal.pdf: 37484380 bytes, checksum: b61e5bb415f505345e69623ffd098b9e (MD5) Previous issue date: 2015-07-08 / A disciplina de geomecânica de reservatórios engloba aspectos relacionados não somente à mecânica de rochas, mas também à geologia estrutural e engenharia de petróleo e deve ser entendida no intuito de melhor explicar aspectos críticos presentes nas fases de exploração e produção de reservatórios de petróleo, tais como: predição de poro pressões, estimativa de potenciais selantes de falhas geológicas, determinação de trajetórias de poços, cálculo da pressão de fratura, reativação de falhas, compactação de reservatórios, injeção de CO2, entre outros. Uma representação adequada da quantificação de incertezas é parte essencial de qualquer projeto. Especificamente, uma análise que se destina a fornecer informações sobre o comportamento de um sistema deve prover uma avaliação da incerteza associada aos resultados. Sem tal estimativa, perspectivas traçadas a partir da análise e decisões tomadas com base nos resultados são questionáveis. O processo de quantificação de incertezas para modelos multifísicos de grande escala, como os modelos relacionados à geomecânica de reservatórios, requer uma atenção especial, principalmente, devido ao fato de comumente se deparar com cenários em que a disponibilidade de dados é nula ou escassa. Esta tese se propôs a avaliar e integrar estes dois temas: quantificação de incertezas e geomecânica de reservatórios. Para isso, foi realizada uma extensa revisão bibliográfica sobre os principais problemas relacionados à geomecânica de reservatórios, tais como: injeção acima da pressão de fratura, reativação de falhas geológicas, compactação de reservatórios e injeção de CO2. Esta revisão contou com a dedução e implementação de soluções analíticas disponíveis na literatura relatas aos fenômenos descritos acima. Desta forma, a primeira contribuição desta tese foi agrupar diferentes soluções analíticas relacionadas à geomecânica de reservatórios em um único documento. O processo de quantificação de incertezas foi amplamente discutido. Desde a definição de tipos de incertezas - aleatórias ou epistêmicas, até a apresentação de diferentes metodologias para quantificação de incertezas. A teoria da evidência, também conhecida como Dempster-Shafer theory, foi detalhada e apresentada como uma generalização da teoria da probabilidade. Apesar de vastamente utilizada em diversas áreas da engenharia, pela primeira vez a teoria da evidência foi utilizada na engenharia de reservatórios, o que torna tal fato uma contribuição fundamental desta tese. O conceito de decisões sob incerteza foi introduzido e catapultou a integração desses dois temas extremamente relevantes na engenharia de reservatórios. Diferentes cenários inerentes à tomada de decisão foram descritos e discutidos, entre eles: a ausência de dados de entrada disponíveis, a situação em que os parâmetros de entrada são conhecidos, a inferência de novos dados ao longo do projeto e, por fim, uma modelagem híbrida. Como resultado desta integração foram submetidos 3 artigos a revistas indexadas. Por fim, foi deduzida a equação de fluxo em meios porosos deformáveis e proposta uma metodologia explícita para incorporação dos efeitos geomecânicos na simulação de reservatórios tradicional. Esta metodologia apresentou resultados bastante efetivos quando comparada a métodos totalmente acoplados ou iterativos presentes na literatura. / Reservoir geomechanics encompasses aspects related to rock mechanics, structural geology and petroleum engineering. The geomechanics of reservoirs must be understood in order to better explain critical aspects present in petroleum reservoirs exploration and production phases, such as: pore pressure prediction, geological fault seal potential, well design, fracture propagation, fault reactivation, reservoir compaction, CO2 injection, among others. An adequate representation of the uncertainties is an essential part of any project. Specifically, an analysis that is intended to provide information about the behavior of a system should provide an assessment of the uncertainty associated with the results. Without such estimate, perspectives drawn from the analysis and decisions made based on the results are questionable. The process of uncertainty quantification for large scale multiphysics models, such as reservoir geomechanics models, requires special attention, due to the fact that scenarios where data availability is nil or scarce commonly come across. This thesis aimed to evaluate and integrate these two themes: uncertainty quantification and reservoir geomechanics. For this, an extensive literature review on key issues related to reservoir geomechanics was carried out, such as: injection above the fracture pressure, fault reactivation, reservoir compaction and CO2 injection. This review included the deduction and implementation of analytical solutions available in the literature. Thus, the first contribution of this thesis was to group different analytical solutions related to reservoir geomechanics into a single document. The process of uncertainty quantification has been widely discussed. The definition of types of uncertainty - aleatory or epistemic and different methods for uncertainty quantification were presented. Evidence theory, also known as Dempster- Shafer theory, was detailed and presented as a probability theory generalization. Although widely used in different fields of engineering, for the first time the evidence theory was used in reservoir engineering, which makes this fact a fundamental contribution of this thesis. The concept of decisions under uncertainty was introduced and catapulted the integration of these two extremely important issues in reservoir engineering. Different scenarios inherent in the decision-making have been described and discussed, among them: the lack of available input data, the situation in which the input parameters are known, the inference of new data along the design time, and finally a hybrid modeling. As a result of this integration three articles were submitted to peer review journals. Finally, the flow equation in deformable porous media was presented and an explicit methodology was proposed to incorporate geomechanical effects in the reservoir simulation. This methodology presented quite effective results when compared to fully coupled or iterative methods in the literature.

[pt] O desenvolvimento de campos de petróleo afeta significativamente o meio geológico ao redor do reservatório. Os efeitos geomecânicos decorrentes da exploração podem ser nocivos à integridade de componentes presentes no sistema, notadamente os poços. O objetivo deste estudo foi analisar os efeitos do desenvolvimento do reservatório sobre a integridade de poços, empregando simulações de natureza fluido-mecânica e multi-escala. Para as análises globais, foi implementada e validada uma configuração de acoplamento fluido-mecânico parcial, utilizando o programa de simulação de reservatórios IMEX e o programa de análise de tensões ABAQUS, baseada na metodologia de acoplamento parcial desenvolvida pelo Grupo de Tecnologia e Engenharia de Petróleo da PUC-Rio. A conexão teórica entre modelos de poço e reservatório foi estabelecida através de um workflow multi-escala, desenvolvido para nortear a análise de integridade de poços em virtude dos efeitos de produção. Para a otimização da conexão numérica entre os modelos de diferentes escalas, foi desenvolvido um módulo gerenciador de análises locais, denominado Módulo APOLLO, capaz de incluir na simulação local as etapas de perfuração e completação do poço, bem como os efeitos geomecânicos provenientes da simulação global acoplada. Análises acopladas e multi-escala foram realizadas em dois poços hipotéticos, presentes em um modelo de reservatório com a geometria do Campo de Namorado. Através das ferramentas desenvolvidas nesta Tese, foi possível realizar uma previsão detalhada e precisa do mecanismo que levou os poços avaliados ao colapso. Constatou-se que o caráter dos estados limites observados foi essencialmente tridimensional, bem como dependente da abordagem de acoplamento empregada na simulação global. / [en] The development of petroleum fields affects substantially the geological environment around the reservoir. The geomechanical effects arising from hydrocarbon exploration may present harmful effects on the integrity of the system components, particularly the wells. The aim of this work was to analyze the reservoir development effects over the well integrity, employing fluid-mechanical and multi-scale simulations. For the global analyzes, it was implemented and validated a fluid-mechanic partial coupling configuration, using the reservoir simulation software IMEX and the stress analysis software ABAQUS, based on the coupling methodology developed by the Group of Technology and Petroleum Engineering of PUC-Rio. The theoretical connection between the models of reservoir and wells was established by a multi-scale workflow, which was developed to guide the well integrity analysis due to production effects. In order to optimize the numerical connection between distinct scale models, it was developed a local analysis manager, called APOLLO module, which can include the steps of drilling and completion, as well as the geomechanical effects from the global simulation, in the local simulations. Coupled multi-scale analyzes were performed in two hypothetical wells, present in a reservoir model based on the geometry of the Namorado Field. Through the tools developed in this Thesis, it was possible to perform a detailed and accurate prediction of the mechanism that leads the evaluated wells to the collapse. It was found that the character of the observed limit states was essentially three-dimensional, as well as dependent of the coupling approach employed on the global simulation.

[pt] Atrelado aos cenários cada vez mais complexos de extração de energia, o estudo de fenômenos acoplados em meios porosos - notadamente térmicos, hidráulicos, químicos e mecânicos - tem se apresentado como essencial na previsão de comportamento de meios geológicos no que diz respeito à disposição de rejeitos radioativos, armazenamento de dióxido de carbono, engenharia de reservatórios geotérmicos e geomecânica de reservatórios. Assim, este trabalho objetiva desenvolver um esquema de acoplamento termo-hidro-mecânico-químico iterativo visando a simulação do armazenamento geológico de dióxido de carbono, empregando um simulador de fluxo composicional (GEM) e um programa de análise de tensões (ABAQUS ou CHRONOS). A idealização das metodologias de acoplamento foi efetuada através dos processos hidro-mecânico, termo-hidro-mecânico e termo-hidro-mecânico-químico, bem como as validações e aplicações em casos reais. Os casos de validação, realizados empregando modelos simplificados monofásicos, apresentaram resultados satisfatórios quanto ao comportamento hidro-mecânico e termo-hidro-mecânico. Adicionalmente às validações, os esquemas termo-hidro-mecânico e termo-hidro-mecânico-químico foram aplicados em dois casos reais de armazenamento de CO2 apresentados na literatura, projeto In Salah (Argélia) e aquífero Utsira (Noruega), respectivamente. De maneira geral, os resultados encontrados, para ambos os casos estudados, representaram acuradamente as respostas encontradas em campo, fato que evidencia a qualidade, robustez e aplicabilidade dos esquemas de acoplamento propostos neste trabalho. / [en] Considering the increasingly complex scenarios of energy extraction, the study of coupled phenomena in porous media - notably thermal, hydraulic, chemical and mechanical - has been considered as essential in order to predict the behavior of geological media with regard to radioactive waste storage, CO2 geological storage, geomechanics of geothermal reservoirs and reservoir geomechanics. Thus, this work aims to develop a thermo-hydro-mechanical-chemical iterative coupling scheme in order to simulate the geological storage of CO2, employing a compositional flow simulator (GEM) and a stress analysis program (ABAQUS or CHRONOS). The idealization of the coupling methodologies was carried out through the processes hydro-mechanical, thermo-hydro-mechanical and thermo-hydro-mechanical-chemical, as well as the validations and applications in real cases. The validation cases, performed employing simplified single-phase models, presented satisfactory results regarding the hydro-mechanical and thermo-hydro-mechanical behaviors. Additionally to the validations, the thermo-hydro-mechanical and thermo-hydro-mechanical-chemical schemes were applied in two real cases of CO2 geological storage reported by the literature, In Salah project (Algeria) and Utsira aquifer (Norway), respectively. In general, the results found, in both cases studied, accurately represented the behavior observed in the field, which in turn highlights the accuracy, robustness and applicability of the coupling schemes proposed in this work.

[pt] Reservatórios de petróleo e gás estruturalmente compartimentados por falhas geológicas selantes são encontrados em diversas regiões do mundo. Durante a fase de explotação, a integridade do selo destas falhas pode ser comprometida pelas deformações decorrentes dos processos de depleção e/ou injeção de fluidos. Estas deformações, em conjunto com as propriedades físicas e geométricas das rochas e falhas presentes, podem alterar significativamente o estado de tensões do maciço rochoso fazendo com que uma falha reative e se torne hidraulicamente condutora. A esse fenômeno estão associados riscos de exsudação, perda de integridade de poços e outros potencias problemas geomecânicos. Na literatura, diversas modelagens numéricas têm sido utilizadas a fim de caracterizar e prever os fenômenos de reativação e/ou abertura de falhas geológicas. A maior parte de estas abordagens faz uso de modelos bidimensionais considerando seções críticas na hipótese de estado plano de deformação. Essas simplificações são adotadas a fim de evitar a complexidade geométrica e o alto custo computacional de uma modelagem tridimensional. No entanto, a configuração tridimensional dos planos de falha pode induzir a reativação em direção a zonas mais críticas do que aquelas contidas numa única seção. Neste trabalho apresenta-se uma metodologia para análise de reativação de falhas geológicas e discute-se a importância do uso dos modelos 3D na previsão do comportamento geomecânico de reservatórios compartimentados por falhas geológicas. São apresentados 3 modelos diferentes. O primeiro exemplo traz um modelo bidimensional apresentado na literatura, faz-se uma comparação dos resultados com representação por meio do elemento de interface, por meio do continuo equivalente e por meio de um elemento solido com fraturas embutidas. O segundo exemplo faz-se um comparativo entre a utilização de elementos quadrilaterais e triangulais para a representação da falha em modelos 3D. Para o terceiro modelo foram realizadas simulações numéricas considerando modelos 2D e 3D em um simulador in-house baseado no método dos elementos finitos. Para a representação do meio continuo foram utilizados elementos quadrilaterais para o caso 2D, e elementos hexaédricos e tetraédricos para o caso 3D. Para a representação das falhas geológicas foram utilizados elementos de interface de espessura nula segundo o critério de ruptura de Mohr-Coulomb. Da comparação dos resultados, constata-se que as análises 2D e 3D forneceram previsões de reativação similares. No entanto, as previsões de pressões de abertura foram distintas em ambos os modelos devido às diferentes trajetórias de migração de fluido. Particularmente em modelos com geometria irregular confirma-se a importância do emprego de modelo 3D. / [en] Oil and gas reservoirs that are structurally compartmented by sealing geological faults are common in several areas around the world. During production, the deformations from the processes of fluid depletion and/or injection can compromise the integrity of the seal of the faults. This deformation, together with the physical and geometrical properties from the rocks and faults can significantly change the stress state. Therefore, it might cause fault reactivation, turning it in a hydraulic conduit. Related to this phenomenon, are the exudation, loss of wellbore integrity and other potential geomechanical problems. There are several numerical modelling techniques available in literature to characterize and predict the reactivation and/or opening of geological faults. In most of these modelling approaches, bi-dimensional models are used for critical sections through the assumption of plane strain conditions. The reason for using 2D models is to avoid the geometrical complexity and the high computational costs associated to three-dimensional modeling. On the other hand, the fault planes in the three-dimensional approach can show fault reactivation in a more critical direction e than the one represented by the bi-dimensional model. In this work, a methodology is presented in order to assess geological fault reactivation. In addition, the importance of using 3D models in the prediction of the geomechanical behavior of reservoirs compartmented by geological faults is discussed. Three different models are presented. The first example is based on a two dimensional model from the literature. A comparison between approaches using interface elements, equivalent continuum elements and solid element with fractures is carried out in the first example. The second example brings a comparison between the quadrilateral and triangular elements to represent faults in a 3D model. In addition, an analysis was carried out considering 2D and 3D models using an in house software based on the finite element method. To simulate the continuum medium, quadrilateral elements are used in the 2D case and in the 3D case hexahedral and tetrahedral elements are employed. In addition, to represent the geological faults, interface elements with zero thickness are used in association with the Mohr-Coulomb failure criterion. In the case study, predictions of fault reactivation were similar in the 2D and 3D models. However, fault opening pressures were different in both models, due to the 3D fluid migration path. It also confirmed the importance of using 3D models when simulating irregular geometries.

Heavy oil production depends on the understanding of mechanical and flow properties of unconsolidated or weakly consolidated sands under different loading paths and boundary conditions. Reconstituted bitumen-free Athabasca oil-sands samples were used to investigate the geomechanics of a steam injection process such as the Steam Assisted Gravity Drainage (SAGD). Four stress paths have been studied in this work: triaxial compression, radial extension, pore pressure increase and isotropic compression. Absolute permeability, end-point relative permeability to oil & water (kro and krw), initial water saturation and residual oil saturation were measured while the samples deformed. Triaxial compression is a stress path of increasing mean stress while radial extension and pore pressure increase lead to decreasing mean stress. Pore pressure increase experiments were carried out for three initial states: equal axial and confining stresses, axial stress greater than confining stress and confining stress greater than axial stress. Pore pressure was increased under four boundary conditions: 1) constant axial and confining stress; 2) constant axial stress and zero radial strain; 3) zero axial strain and constant confining stress; and 4) zero axial and radial strain. These experiments were designed to mimic geologic conditions where vertical stress was either S1 or S3, the lateral boundary conditions were either zero strain or constant stress, and the vertical boundary conditions were either zero strain or constant stress. Triaxial compression caused a decrease in permeability as the sample compacted, followed by appreciable permeability enhancement during sample dilation. Radial extension led to sample dilation, shear failure and permeability increase from the beginning. The krw and kro increased by 40% and 15% post-compaction respectively for the samples corresponding to lower depths during triaxial compression. For these samples, residual oil saturation decreased by as much as 40%. For radial extension, the permeability enhancement decreased with depth and ranged from 20% to 50% while the residual oil saturation decreased by up to 55%. For both stress paths, more shear-enhanced permeability was observed for samples tested at lower pressures, implying that permeability enhancement is higher for shallower sands. The pore pressure increase experiments showed an increase of only 0-10% in absolute permeability except when the effective stress became close to zero. This could possibly have occurred due to steady state flow not being reached during absolute permeability measurement. The krw curves generally increased as the pore pressure was increased from 0 psi. The increase ranged from 5% to 44% for the different boundary conditions and differential stresses. The kro curves also showed an increasing trend for most of the cases. The residual oil saturation decreased by 40-60% for samples corresponding to shallow depths while it increased by 0-10% for samples corresponding to greater depths. The reservoirs with high differential stress are more conducive to favorable changes in permeability and residual oil saturation. These results suggested that a decreasing mean stress path is more beneficial for production increase than an increasing mean stress path. The unconsolidated sands are over-consolidated because of previous ice loading which makes the sand matrix stiffer. In this work, it was found that over-consolidation, as expected, decreased the porosity and permeability (40-50%) and increased the Young’s and bulk moduli of the sand. The result is sand which failed at higher than expected stress during triaxial compression. Overall, results show that lab experiments support increased permeability due to steam injection operations in heavy oil, and more importantly, the observed reduction in residual oil saturation implies SAGD induced deformation should improve recovery factors. / text