Mud volcanoes constitute an important component of petroliferous basins and their understanding is essential for successful exploration and development of hydrocarbon fields. They occur in both extensional and compressive tectonic settings, along with passive and active continental margins. Although extensive research exists on the geochemistry, geomorphology and stratigraphic evolution of these localized fluid flow structures, little is known about their geomechanical characteristics. This research investigates the geomechanics of mud volcanoes from the South Caspian Basin and West Nile Delta. This is achieved by establishing a workflow for geomechanical assessment of mud volcanoes using a P-wave velocity dataset from across the mud volcano within the offshore South Caspian Basin. This objective is developed further with the availability of seismic and wellbore data from around the Giza mud volcano, offshore West Nile Delta. Preliminary results of this study from the South Caspian Basin enable confidence in estimating the realistic magnitudes of elastic rock properties, stresses and fluid pressures from empirical and analytical correlations. Moreover, analysis of the variations in fluid pressures allow the fluid flow models around the mud volcano to be constrained and their gradients provide preliminary estimates of the drilling window. Structural and stratigraphic analysis around the Giza mud volcano offers insight into the formation of the mud volcano during the Quaternary and how the fault networks on the hanging wall of the arcuate tectonic fault have acted as conduits for primarily the pre-Pliocene fluids exploiting the areas of weakness along the hanging wall of the fault by entraining the Pliocene sediments. Fluid pressure evaluation reveals small overpressures caused by disequilibrium compaction. Further analysis offers insight into the critical fluid pressures that control fault movement, the stresses responsible for rock deformation around the wellbore and the width of the drilling window constrained by the fracturing of the strata. Analysis presented here provides details on the geomechanical significance of mud volcano environments, with implications for engineering practices. Overall, findings contribute to a systematic understanding of mud volcano settings not only from a field exploration and development point of view, but also at a wider scale for basin analysis and relatively small scale for play analysis.

A main aspect of wellbore stability analysis is the selection of an appropriate rock failure criterion. The most commonly used criterion for brittle failure of rocks is the Mohr-Coulomb criterion. This criterion involves only the maximum and minimum principal stresses, s1 and s3, and therefore assumes that the intermediate stress s2 has no influence on rock strength. When the Mohr-Coulomb criterion had been developed, it was justified by experimental evidence from conventional triaxial tests (s1>s2=s3). Based on triaxial failure mechanics, the Mohr-Coulomb criterion has been extensively used to represent rock failure under the polyaxial stress state (s1>s2>s3). In contrast to the predictions of Mohr-Coulomb criterion, much evidence has been accumulating to suggest that s2 does indeed have a strengthening effect. In this research, I have shown that Mohr-Coulomb failure criterion only represents the triaxial stress state (s2=s3 or s2=s1), which is a special case that will only occasionally be encountered in situ. Accordingly, I then developed a new true-triaxial failure criterion called the Mogi-Coulomb criterion. This failure criterion is a linear failure envelope in the Mogi domain (toct-sm,2 space) which can be directly related to the Coulomb strength parameters, cohesion and friction angle. This linear failure criterion has been justified by experimental evidence from triaxial tests as well as polyaxial tests. It is a natural extension of the classical Coulomb criterion into three dimensions. As the Mohr-Coulomb criterion only represents rock failure under triaxial stress states, it is expected to be too conservative in predicting wellbore instability. To overcome this problem, I have developed a new 3D analytical model to estimate the mud pressure required to avoid shear failure at the wall of vertical, horizontal and deviated boreholes. This has been achieved by using linear elasticity theory to calculate the stresses, and the fully-polyaxial Mogi-Coulomb criterion to predict failure. The solution is achieved in closed-form for vertical wellbores, for all stress regimes. For deviated or horizontal wellbores, Mathcad programs have been written to evaluate the solution. These solutions have been applied to several field cases available in the literature, and the new model in each case seems to be consistent with the field experience. / QC 20100629

Drilling operation expanded through deep water environments starting from mid-1980. As water depth increased, hydrate bearing formation in the shallow ocean floor is observed and that started to cause problems during drilling and production operations. Problems due to hydrate dissociation and forming during operations are also reported by the companies working in those environments many times. Although there are several factors affect the dissociation of shallow hydrate bearing sediments, heat flux from deeper sections of the well through shallower section during the operation is the major one. In order to mitigate that risk in this study, Black Sea is taken as a reference drilling environment. Hydrate phase boundary of the region is calculated via using actual temperature and pressure data gathered during drilling operations. Generic wellbore is defined and common drilling operation sequence is simulated in this defined wellbore. Heat transfer from section target depths to the shallow wellbore section is observed during simulations. Reducing effect of low inlet temperatures and a low circulation rate on wellbore temperatures are determined. In addition positive effect of riser boosting on depressing wellbore temperature in the well head is determined. Black Sea deep water hydrate stability zone is determined between 2210-2275m. Target depth limitation for generic well designed in drilling operations is determined as 4600m.

Increasing surface pressure buildup levels and surface venting flow rates on intermediate wellbore casing strings provided an opportunity to analyze wellbore field data to determine a distribution of leakage path permeability values. The gas leakage source in the leaky wellbore originated at depth, and formation gas/fluid traveled along defects in the cement to accumulate at the surface wellhead. The most likely pathway is the cement interface with casing or formation. Due to uncertainty about the location of the leak, and the different methods that were used for calculating leakage parameter values, a range of leakage path permeability values was produced. Most leakage pathway permeability values were greater than intact cement permeability (few microdarcies). This finding supports the practice of using cement filled annuli to provide a safe protective barrier against leakage and to prevent gas flow to surface. Proper cementing techniques are presented in order to identify possible reasons for cracks to form. It is hypothesized that the higher permeability values are a result of cracks in the cement interface with the casing or formation. These types of defects could also be found in wellbores that are in communication with CO2 sequestration reservoirs. The risk of leakage along such existing wellbores associated with CO2 sequestration projects is quantified by the distribution of leakage path permeability. The gas migration path through existing leaky wellbores is an analog for wellbores that are in contact with migrating CO2 plumes. Cracks in the leaky wellbores provide a highly permeable conduit for CO2 to migrate out of the injection zone to the surface. By quantifying leakage path permeability, proper leakage risk assessment can be further developed. / text

During the production and transportation of oil and gas, flow assurance issues may occur due to the solid deposits that are formed and carried by the flowing fluid. Solid deposition may cause serious damage and possible failure to production equipment in the flow lines. The major flow assurance problems that are faced in the fields are concerned with asphaltene, wax and scale deposition, as well as hydrate formations. Hydrates, wax and asphaltene deposition are mostly addressed in deep-water environments, where fluid flows through a long path with a wide range of pressure and temperature variations (Hydrates are generated at high pressure and low temperature conditions). In fact, a large change in the thermodynamic condition of the fluid yields phase instability and triggers solid deposit formations. In contrast, scales are formed in aqueous phase when some incompatible ions are mixed. Among the different flow assurance issues in hydrocarbon reservoirs, asphaltenes are the most complicated one. In fact, the difference in the nature of these molecules with respect to other hydrocarbon components makes this distinction. Asphaltene molecules are the heaviest and the most polar compounds in the crude oils, being insoluble in light n-alkenes and readily soluble in aromatic solvents. Asphaltene is attached to similarly structured molecules, resins, to become stable in the crude oils. Changing the crude oil composition and increasing the light component fractions destabilize asphaltene molecules. For instance, in some field situations, CO₂ flooding for the purpose of enhanced oil recovery destabilizes asphaltene. Other potential parameters that promote asphaltene precipitation in the crude oil streams are significant pressure and temperature variation. In fact, in such situations the entrainment of solid particulates in the flowing fluid and deposition on different zones of the flow line yields serious operational challenges and an overall decrease in production efficiency. The loss of productivity leads to a large number of costly remediation work during a well life cycle. In some cases up to $5 Million per year is the estimated cost of removing the blockage plus the production losses during downtimes. Furthermore, some of the oil and gas fields may be left abandoned prematurely, because of the significance of the damage which may cause loss about $100 Million. In this dissertation, we developed a robust wellbore model which is coupled to our in-house developed compositional reservoir model (UTCOMP). The coupled wellbore/reservoir simulator can address flow restrictions in the wellbore as well as the near-wellbore area. This simulator can be a tool not only to diagnose the potential flow assurance problems in the developments of new fields, but also as a tool to study and design an optimum solution for the reservoir development with different types of flow assurance problems. In addition, the predictive capability of this simulator can prescribe a production schedule for the wells that can never survive from flow assurance problems. In our wellbore simulator, different numerical methods such as, semi-implicit, nearly implicit, and fully implicit schemes along with blackoil and Equation-of-State compositional models are considered. The Equation-of-State is used as state relations for updating the properties and the equilibrium calculation among all the phases (oil, gas, wax, asphaltene). To handle the aqueous phase reaction for possible scales formation in the wellbore a geochemical software package (PHREEQC) is coupled to our simulator as well. The governing equations for the wellbore/reservoir model comprise mass conservation of each phase and each component, momentum conservation of liquid, and gas phase, energy conservation of mixture of fluids and fugacity equations between three phases and wax or asphaltene. The governing equations are solved using finite difference discretization methods. Our simulation results show that scale deposition is mostly initiated from the bottom of the wellbore and near-wellbore where it can extend to the upper part of the well, asphaltene deposition can start in the middle of the well and the wax deposition begins in the colder part of the well near the wellhead. In addition, our simulation studies show that asphaltene deposition is significantly affected by CO₂ and the location of deposition is changed to the lower part of the well in the presence of CO₂. Finally, we applied the developed model for the mechanical remediation and prevention procedures and our simulation results reveal that there is a possibility to reduce the asphaltene deposition in the wellbore by adjusting the well operation condition. / text

[pt] Este trabalho desenvolve uma metodologia para obter experimentalmente a pressão capilar de diferentes fluidos em contato com folhelhos, comparando-a com valores obtidos analiticamente a partir da caracterização dos fluidos e dos folhelhos individualmente. Foram realizados ensaios numa célula de difusão a qual permite simular as condições de pressão aplicadas no campo, avaliar a interação físico- química entre fluidos e rochas, além de determinar os parâmetros de transporte de massa devido a gradientes químicos e hidráulicos. Verifica-se que os valores de pressão capilar obtidos diretamente na célula de difusão são inferiores aos obtidos a partir da equação de pressão capilar utilizando a tensão interfacial, o ângulo de contato e o raio de poros do folhelho. Desta forma, conclui-se que caso seja realizada uma análise de estabilidade considerando a pressão capilar do fluido, este parâmetro deve ser determinado experimentalmente na célula de difusão. Caso contrário, valores superestimados poderão ser encontrados. / [en] A methodology was developed to experimentally obtain the capillary pressure of different fluids in contact with shales and compare these values with analytical results from individual characterization of fluids and shales. Tests were carried out in a diffusion cell, which allows the simulation of in-situ pressure conditions, the evaluation of physical-chemical interactions between fluids and rocks and the determination of mass transport parameters due to hydraulic and chemical gradients. It is observed that the values of capillary pressure directly obtained in the diffusion cell are inferior to the ones obtained from the capillary pressure equation using the interfacial tension, the contact angle and the pore radius of shales. Thus, it can be concluded that, if a stability analysis considering the capillary pressure of the fluid is carried out, this parameter should be experimentally determined in the diffusion cell. Otherwise, overestimated values can be found.

[pt] O conhecimento do comportamento mecânico das rochas é fundamental para o desenvolvimento dos estudos de estabilidade voltados à construção de poços de petróleo. Neste sentido, a estimativa de suas propriedades mecânicas e a determinação do campo de tensões atuante são necessários para compreender as deformações às quais estão sujeitas. De modo a avaliar os efeitos da perfuração no comportamento mecânico das rochas, foram construídos modelos numéricos das litologias comumente descritas no pré-sal de um campo da bacia de Santos em duas etapas. Em um primeiro momento, foi idealizado um estudo de retroanálise de poço a fim de estabelecer a metodologia a ser aplicada neste trabalho. Os resultados numéricos obtidos nesta etapa reproduziram de maneira satisfatória os dados constatados em campo e, desta forma, foi possível validar a técnica utilizada. Em um segundo momento, foram construídos os modelos numéricos de litologias previstas em um poço sintético para um teste cego, tomando por base tanto as propriedades mecânicas estimadas das rochas quanto o estado de tensões in situ determinado em poços de correlação. Por último, os resultados obtidos neste teste foram comparados aos dados reais de um poço da área, de modo que foi possível corroborar a metodologia aplicada neste estudo pela coerência entre os dados numéricos e os constatados em campo. Desta forma, foi possível avaliar o comportamento mecânico das rochas no intervalo do pré-sal de poços correlacionáveis e estimar possíveis problemas geomecânicos a serem encontrados durante a etapa de perfuração. / [en] The modeling of rock mechanical behavior is essential to develop wellbore stability studies. In that sense, estimating rock mechanical properties and the in situ stress field are required tasks to understand the resulting deformations. In order to evaluate drilling effects on rock mechanical behavior, numerical models were constructed to represent the most commonly described rocks in the pre-salt session of an oil field located in Santos basin. Firstly, the author introduced the wellbore retro-analysis methodology proposed for this study. The technique was validated against real wellbore data with a fairly good match. Thereafter, a test model was conducted on a synthetic stratigraphy considering the typical occurrence of pre-salt rocks and the expected in situ stress field, as determined by correlated wellbores data. The numerical results of this test were compared to the data acquired in a local oil well and seemed to provide a reasonable fit, corroborating the applied technique. It was possible to evaluate typical pre-salt rock mechanical behavior by using correlation wellbores and still predict possible wellbore geomechanical problems during the drilling phase.

[pt] A grande maioria dos problemas de estabilidade de poços de petróleo ocorre em trechos de folhelhos, rochas nas quais, uma especificação eficiente da pressão do fluido de perfuração requer previamente uma especificação correta da concentração salina e da temperatura. Todavia, para um dimensionamento adequado das características do fluido de perfuração necessárias à estabilidade do poço, é necessário o uso de modelos matemáticos que considerem um acoplamento adequado entre efeitos poroelásticos, químicos e térmicos. Entretanto, a complexidade matemática das equações de modelos acoplados normalmente leva à adoção de soluções numéricas, que consomem um tempo computacional muito grande e, por isso, esses modelos não são atrativos à aplicação na análise da estabilidade de poços. Este trabalho apresenta um modelo acoplado termo-químico-poroelástico representado por duas soluções, uma numérica, que utiliza o método dos elementos finitos, e outra analítica, baseada no método das transformadas de Laplace. Ao comparar ambas as soluções é demonstrado que a solução analítica consegue representar tão bem quanto à solução numérica os principais processos acoplados presentes durante a perfuração de folhelhos e que influenciam na sua estabilidade e, por esta razão, pode ser utilizada na análise de estabilidade de poços em folhelhos. Através de um estudo de caso, é verificado que um controle eficiente da estabilidade do poço é obtido especificando a pressão do fluido de perfuração em função da sua temperatura e concentração salina. Estes resultados também indicam as razões de alguns problemas não previstos por modelos desacoplados, e que quase sempre ocorrem durante a perfuração em folhelhos. / [en] Wellbore stability problems are most common when drilling through shales. In order to avoid such problems in this kind of rocks the solute concentration and temperature must be properly defined in the drilling fluid composition, which requires considering poroelastic, thermal and chemical effects in a coupled way. The equations complexity of coupled models usually results in numerical solutions that are very time consuming, thus, unattractive for stability analysis. In an opposite way, it is very difficult to develop closed- form solutions for coupled models. This work presents a thermochemoporoelastic model represented by a numerical solution based upon the finite element method and an analytical solution based upon the Laplace transform method. A comparison between the results of the numerical solution and analytical solution shows that the later can reproduce the coupled processes involved in the wellbore stability problem in shales as well as the former, and for this reason the closed-form solution can be applied as a practical tool in wellbore stability analysis. The analysis of a typical wellbore drilled through shales showed that an efficient control of wellbore stability can be obtained through an adequate specification of the drilling fluid pressure when taking in account its solute concentration and temperature. The model was also able to explain some problems not predicted by uncoupled models, but almost always seen while drilling through shales.

[pt] A estabilidade de poços em trechos de folhelho é muito influenciada pelo tipo de fluido de perfuração utilizado. As pressões de poro geradas durante a perfuração e a difusão destas pressões são as principais responsáveis pela estabilidade a curto prazo do poço, assim como pela eventual instabilidade a médio prazo. O efeito membrana e o conseqüente desenvolvimento de pressões osmóticas ao redor do poço desempenham um papel fundamental no balanço das forças que instabilizam a rocha. Esta dissertação se foca no estudo experimental, utilizando uma célula de difusão, do comportamento de folhelhos expostos, após a perfuração, a fluidos de perfuração do tipo base água e salinos, pressurizados com vistas à estabilidade das paredes do poço. São avaliados os aspectos físico-químicos da interação folhelho-fluido, em especial, no tocante ao desenvolvimento de pressão osmótica e efeito membrana. Testes de interação rocha-fluido utilizando folhelhos provenientes da Bacia de Campos e do Mar do Norte demonstraram a eficiência do equipamento em realizar ensaios com fluidos viscosos base água. O estudo das propriedades reológicas deste fluido foi realizado utilizando equipamentos especializados. Verificou-se nos ensaios que o comportamento de transmissão de pressão deste fluido é similar ao da água e que, aparentemente, o coeficiente de reflexão é mais influenciado pela porosimetria do folhelho do que pela sua mineralogia. / [en] Well stability in shale sectors is very much influenced by the type of drilling fluid used. The pore pressures generated during drilling and the diffusion of these pressures are chiefly responsible for the short time stability of the well as well as the eventual instability some time after drilling. The membrane effect and the subsequent osmotic pressure developed around the well play a fundamental role in the force balance that destabilizes the rock. This study focuses on assessing, inside the diffusion cell, the exposed shale behavior, after drilling, using water base mud brines, pressurized considering the wall stability of the well. The physical-chemical aspects of the shale- fluid interation are evaluated, in particular, in relation to osmotic pressure and membrane effects developments. Rock-fluid interaction tests using shale samples collected from Campos Basin and North Sea, showed the efficiency of the equipment in carrying out experiments with viscous base water fluids. The study of reological properties of this fluid was made using specialized equipments. The experiments verified that the fluid pressure transmission behaviour is similar to water and, apparently, the reflection coefficient in more influenced by porosimetry of the shale than by your mineralogy.

[pt] O estudo sobre estabilidade de poços tem como uma de suas principais aplicações a determinação da faixa segura de densidades do fluido de perfuração. A análise de estabilidade de um poço, que determina essa faixa segura, envolve uma série de parâmetros que geralmente apresentam incertezas associadas aos seus valores. Em métodos convencionais, essas incertezas não são consideradas. O objetivo deste trabalho é desenvolver metodologias de análise de estabilidade de poços que considerem as incertezas associadas aos parâmetros. Métodos para quantificação de incertezas associadas aos parâmetros são apresentados para o caso de um poço já perfurado e para o caso de um novo poço em uma região em desenvolvimento. Dois métodos de análise de sensitividade também são apresentados e aplicados ao problema de estabilidade de poços. Para avaliação do efeito que as incertezas associadas aos parâmetros geram no sistema de estabilidade, dois métodos probabilísticos (simulação de Monte Carlo e método FOSM) foram aplicados ao problema, e depois intercomparados. Através do método da simulação de Monte Carlo, desenvolveu- se um simulador computacional para análise probabilística de estabilidade de poços, que permite a consideração das incertezas associadas aos parâmetros. Os métodos probabilísticos de análise fornecem como resposta as probabilidades de ruptura associadas às diferentes pressões internas do poço. Como essas pressões são dependentes da densidade do fluido de perfuração, a avaliação do risco associado à essas pressões constitui um novo critério para a determinação da densidade do fluido de perfuração. / [en] The study on wellbore stability has as one of its main application the determination of the safe range of the drilling-fluid density. The wellbore stability analysis is controlled by a number of parameters that generally present uncertainties associated to their values. In conventional methods, these uncertainties are not considered. The purpose of this work is to develop methodologies of analysis of wellbore stability that consider the uncertainties associated to the controlling parameters. Methods for quantifying the uncertainties associated to the parameters are presented for the case of an open well and for the case of new well located on a development region. Two methods of sensitivity analysis are also presented and applied to the well stability problem. To evaluate the effect that the uncertainties associated to the parameters create on the stability analysis, two probabilistic methods were applied to the problem, and compared to each other. Based upon Monte Carlo method, a computational simulator was developed in order to carry out probabilistic analysis of wellbore stability. The simulator takes into account the uncertainties associated to the parameters. The probabilistic methods of analysis, presented in this dissertation, provide the probability of failure associated to the different internal pressure of the well. As these pressures are dependent upon the density of the drilling - fluid, the evaluation of the risk associated to these pressures constitutes a new criterion to establish the density of the drilling -fluid. / [es] EL estudio sobre estabilidad de pozos tiene como una de sus principales aplicaciones la determinación de la banda de seguridad de las densidades del fluido de perforación. El análisis de estabilidad de un pozo, que determina esa banda segura, incluye una série de parámetros que generalmente presentan errores asociados a sus valores. En métodos convencionales, esos errores no son consideradas. EL objetivo de este trabajo es desarrollar metodologías de análisis de estabilidad de pozos que consideren los errores asociados a los parámetros. Métodos para cuantificación de errores asociadas a los parámetros son presentados para el caso de un pozo perforado y para el caso de un nuevo pozo en una región en desarrollo. Se presentan también dos métodos de análisis de sensitividad y se aplican a problemas de estabilidad de pozos. Para la evaluación de lo que los errores asociados a los parámetros generan en el sistema de estabilidad, se aplican dos métodos probabilísticos (simulación de Monte Carlo y método FOSM). A través del método de la simulación de Monte Carlo, se desarrolla un simulador computacional para el análisis probabilístico de estabilidad de pozos, que permite la consideración de los errores asociados a los parámetros. Los métodos probabilísticos de análisis dan como respuesta las probabilidades de ruptura asociadas a las diferentes presiones internas del pozo. Como esas presiones son dependientes de la densidad del fluido de perforación, la evaluación del riesgo asociado a esas presiones constituye un nuevo criterio para la determinación de la densidad del fluido de perforación.