Asphaltene precipitation, flocculation, and deposition in the reservoir and producing wells cause serious damages to the production equipment and possible failure to develop the reservoirs. From the field production prospective, predicting asphaltene precipitation, flocculation, and deposition in the reservoir and wellbore may avoid high expenditures associated with the reservoir remediation, well intervention techniques, and field production interruption. Since asphaltene precipitation, flocculation, and deposition strongly depend on the pressure, temperature, and composition variations (e.g. phase instability due to CO2 injection), it is important to have a model that can track the asphaltene behavior during the entire production system from the injection well to the production well, which is absent in the literature. Due to economic concerns for asphaltene related problems, companies spend a lot of money to design their own asphaltene inhibition and remediation procedures. However, due to the complexity and the lack of knowledge on the asphaltene problems, these asphaltene inhibition and remediation programs are not always successful. Near-wellbore asphaltene inhibition and remediation techniques can be divided into two categories: changing operating conditions, and chemical treatment of the reservoir. Although, the field applications of these procedures are discussed in the literature, a dynamic model that can handle asphaltene inhibition and remediation in the reservoir is missing. In this dissertation, a comprehensive non-isothermal compositional reservoir simulator with the capability of modeling near-wellbore asphaltene inhibition and remediation is developed to address the effect of asphaltene deposition on the reservoir performance. This simulator has many additional features compared to the available asphaltene reservoir simulators. We are able to model asphaltene behavior during primary, secondary, and EOR stages. A new approach is presented to model asphaltene precipitation and flocculation. Adsorption, entrainment, and pore-throat plugging are considered as the main mechanisms of the asphaltene deposition. Moreover, we consider porosity, absolute permeability, and oil viscosity reductions due to asphaltene. It is well known that the asphaltene deposition on the rock surface changes the wettability of the rock towards oil-wet condition. Although many experiments in the literature have been conducted to understand the physics underlying wettability alteration due to asphaltene deposition, a comprehensive mathematical model describing this phenomenon is absent. Based on the available experimental data, a wettability alteration model due to asphaltene deposition is proposed and implemented into the simulator. Furthermore, the reservoir simulator is coupled to a wellbore simulator to model asphaltene deposition in the entire production system, from the injection well to the production well. The coupled reservoir/wellbore model can be used to track asphaltene deposition, to diagnose the potential of asphaltene problems in the wellbore and reservoir, and to find the optimum operating conditions of the well that minimizes asphaltene problems. In addition, the simulator is capable of modeling near-wellbore asphaltene remediation using chemical treatment. Based on the mechanisms of the asphaltene-dispersant interactions, a dynamic modeling approach for the near-wellbore asphaltene chemical treatments is proposed and implemented in the simulator. Using the dynamic asphaltene remediation model, we can optimize the asphaltene treatment plan to reduce asphaltene related problems in a field. The results of our simulations show that asphaltene precipitation, flocculation, and deposition in the reservoir and wellbore are dynamic processes. Many parameters, such as oil velocity, wettability alteration, pressure, temperature, and composition variations influence the trend of these processes. In the simulation test cases, we observe that asphaltene precipitation, flocculation, and deposition can occur in primary production, secondary production, or EOR stages. In addition, our results show that the wettability alteration has the major effect on the performance of the reservoir, comparing to the permeability reduction. During CO2 flooding, asphaltene precipitation occurs mostly at the front, and asphaltene deposition is at its maximum close to the reservoir boundaries where the front velocity is at its minimum. In addition, the results of the coupled reservoir/wellbore simulator show that the behavior of asphaltene in the wellbore and reservoir are fully coupled with each other. Therefore, a standalone reservoir or wellbore simulator is not able to predict the asphaltene behavior properly in the entire system. Finally, we show that the efficiency of an asphaltene chemical treatment plan depends on the type of dispersant, amount of dispersant, soaking time, number of treatment jobs, and the time period between two treatment jobs. / 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] Testes de formação são normalmente realizados para determinar as propriedades rochosas do reservatório e os dados obtidos costumam ser interpretados com base no pressuposto que o reservatório é homogêneo na direção vertical e descrito por um modelo uni dimensional. No entanto, muitos reservatórios são compostos por diversas camadas que possuem características diferentes. Os poços de produção nesses reservatórios podem receber óleo de mais de uma camada. Em um sistema de reservatório estratificado, o comportamento da pressão e da temperatura não é necessariamente o mesmo de um sistema em camada única e raramente revela as mesmas propriedades médias de todo o sistema. Prever as características das camadas individuais é importante para descrever adequadamente o reservatório e melhorar o gerenciamento da produção. Este trabalho apresenta um modelo numérico, transiente-térmico para um sistema acoplado poço - reservatório 2D, levando-se em consideração efeitos Joule-Thompson responsáveis pelo aquecimento / resfriamento do fluido, expansão/compressão adiabática, além de efeitos de condução e convecção para o poço e o reservatório em um escoamento monofásico. A análise bidimensional do reservatório permite que se simule zonas de estratificação e barreiras. O modelo permite fluxo através de camadas adjascentes com propriedades de rocha diferentes. Pressão e temperatura a uma certa posição no poço produtor são avaliadas ao longo do tempo. Resultados mostram que a análise do transiente de pressão (PTA) e a análise do transiente de temperatura (TTA) podem ser utilizadas para caracterizar diferentes configurações de um reservatório estratificado. / [en] Well formation tests are usually performed to determine rock properties of a reservoir and the obtained data has often been interpreted based on an assumption that the reservoir is homogeneous in the vertical direction and described by a 1-D model. However, many reservoirs are found to be composed of different number of layers that have different characteristics. Production wells in such reservoirs may receive oil from more than one layer. In stratified reservoir system, the pressure and temperature behavior are not necessarily the same as in single layered system, and rarely reveals the same average properties of the entire system. The prediction of the characteristics of the individual layers is important to describe properly the reservoir and improve production management. This work presents a numerical transient-thermal model for a coupled wellbore/2D-reservoir considering Joule-Thompson heating/cooling, adiabatic fluid expansion/compression, conduction and convection effects for both wellbore and reservoir for a single-phase fluid flow. The two-dimensional reservoir model allows the analysis of stratified zones and barriers. The model allows cross flow between the adjacent layers with different rock properties.Wellbore temperature and pressure at a certain gauge depth are evaluated along the time. Results show how pressure transient analysis (PTA) and temperature transient analysis (TTA) can be used to characterize different configuration of stratified reservoirs.

[pt] Este trabalho apresenta um novo modelo térmico analítico que acopla poço e reservatório, constituído por um sistema combinado de reservatório, revestimento e coluna de produção. As soluções analíticas consideram fluxo monofásico de fluido pouco compressível em um reservatório homogêneo e infinito e fornecem dados transitórios de temperatura e pressão ao longo do poço para testes de fluxo e de crescimento de pressão, considerando efeitos Joule-Thomson, de expansão adiabática, de condução e convecção. A massa específica do fluido é modelada como função da temperatura e a solução analítica faz uso da transformada de Laplace para resolver a equação diferencial de fluxo de calor transiente, assumindo o termo aT⁄az totalmente transiente. Com relação à análise de transientes de pressão (PTA), dados de pressão impactados por variações térmicas podem levar à interpretação de falsas heterogeneidades geológicas, pois a perda de calor durante a estática proporciona um aumento da pressão exercida pela coluna de fluido, devido ao incremento de sua massa específica, além de uma contração da coluna de produção, provocando uma mudança na posição do registrador. Esses efeitos podem fazer com que um reservatório homogêneo seja erroneamente interpretado como um reservatório de dupla porosidade, resultando em conclusões inválidas para a modelagem geológica. Os resultados deste trabalho são comparados com a resposta de um simulador comercial não-isotérmico e impactos nas interpretações são extensivamente investigados. Adicionalmente, um estudo de caso de campo é fornecido para validar as soluções analíticas propostas. Comparado à Literatura, o modelo proposto fornece perfis transientes de temperatura mais acurados. / [en] This work presents a new coupled transient-wellbore/reservoir thermal analytical model, consisting of a reservoir/casing/tubing combined system. The analytical solutions consider flow of a slightly compressible, single-phase fluid in a homogeneous infinite-acting reservoir system and provide temperature- and pressure-transient data for drawdown and buildup tests at any gauge location along the wellbore, accounting for Joule-Thomson, adiabatic fluid-expansion, conduction and convection effects. The wellbore fluid mass density is modeled as a function of temperature and the analytical solution makes use of the Laplace transformation to solve the transient heat-flow differential equation, accounting for a rigorous transient wellbore-temperature gradient aT⁄az. Regarding pressure transient analysis (PTA), thermal impacted pressure data may lead to the interpretation of false geological heterogeneities, since the heat loss during the buildup period provides an increase in the pressure exerted by the wellbore-fluid column, due to an increase in the oil mass density, and a change in tubing length, consequently causing a change in the gauge location. These effects can make a homogeneous reservoir be wrongly interpreted as a double-porosity reservoir, yielding invalid conclusions to geological modeling. Results are compared to the response of a commercial non-isothermal simulator and thermal impacts on PTA interpretations are thoroughly investigated. In addition, a field case study is also provided to verify the proposed analytical solutions. The proposed model provides more accurate transient temperature flow profiles along the wellbore when compared to previous models in Literature.