[pt] A demanda global por energia irá aumentar em até 50 porcento nos próximos 20 anos e o petróleo permanecerá sendo a principal fonte de fornecimento de energia. Entre os diferentes tipos de óleos brutos de petróleo, as atenções têm-se concentrado na recuperação de óleos pesados e extrapesados, porque os recursos convencionais de petróleos leves e médios estão globalmente se reduzindo. Os óleos pesados e extrapesados constituem 70 por cento das reservas mundiais, mas devido a sua viscosidade elevada e composição complexa geram problemas. Portanto, a sua recuperação representa um desafio para a indústria do petróleo. Os métodos convencionais só podem ser recuperados cerca 30 por cento do óleo do reservatório e a recuperação avançada de óleo (EOR) que permite obter valores superiores. O método mais utilizado é a injeção de vapor cujo mecanismo principal é o aquecimento do petróleo. Este trabalho apresenta um estudo da influência da presença de nanopartículas no processo de injeção de vapor (aquatermólise), que pode gerar um efeito catalítico promovendo uma melhora no craqueamento incipiente e a consequente diminuição da viscosidade. Um óleo pesado, com viscosidade de 4730 cP a 25 graus Celsius, foi utilizado em escala de bancada para avaliar os efeitos do tempo, da temperatura, do tipo e concentração de nanopartículas (Al2O3-NiO, TiO2 e (Mg,Ni)O) sobre a viscosidade e composição do óleo cru. Os resultados mostraram que a presença de TiO2 e vapor de água podem melhorar a qualidade do petróleo, pela redução das frações pesadas, e diminuir a sua viscosidade em até 13,4 por cento. A técnica foi favorecida com o aumento de temperatura e tempo de aquatermólise. / [en] The global demand in energy will increase by 50 percent over the next 20 years and oil will remain the main source of energy. Among the different types of crude oils, attention has been focused on the recovery of heavy and extra heavy oils, because the conventional resources as light and medium oils are globally decreasing. Heavy and extra heavy oils constitute 70 percent of world reserves, but lead to problems due to their high viscosity and complex composition. Therefore, the recovery of these oils represents a challenge for the oil industry. Conventional methods recover about 30 percent of oil in the reservoir and enhanced oil recovery (EOR) allows to get higher values. The most used method is the injection of steam whose main mechanism of this process is the heating of oil. Consequently there is a reduction of viscosity followed by an incipient cracking, phenomenon affected by the presence of steam water, which needs further studies. This work presents a study of the influence of nanoparticles in the steam injection (aquathermolysis), which can generate a catalytic effect; it enhances the incipient cracking and decreases the viscosity. A heavy oil with viscosity of 4730 cP at 25 Celsius degrees was used in bench scale to evaluate the effects of time, temperature, type and concentration of nanoparticles (Al2O3-NiO, TiO2 and (Mg,Ni)O) on viscosity and composition of the crude oil. The results showed that the presence of TiO2 nanoparticles with steam water may improve the oil quality, by reducing the heavy fractions, and reducing its viscosity up to 13.4 percent.The technique was improved with increasing either temperature or time of aquathermolysis.

A descoberta de petróleo na camada do Pré-Sal fez com que a Petrobras envestisse cerca de 240 bilhões de dólares. Uma etapa crítica desta indústria é o transporte de petróleo, que envolve o sistema água-óleo. O objetivo do presente trabalho é estudar uma corrente água-óleo em um tubo reto e em uma curva, com o intuito de gerar perfis de velocidades, pressões e densidades em CFD. Para as simulações desenvolvidas foram considerados: fluxo 3D, escoamento turbulento na fase óleo e escoamento laminar na fase água, isotérmico e incompressível. Foram realizados estudos nos estados estacionário e transiente. Foi desenvolvido o estudo de convergência da malha. As ferramentas do Phoenics utilizadas para representar a interação entre as fases foram o IPSA e o Algebraic Slip. O IPSA resolve as equações de Navier-Stokes para cada fase. No Algebraic Slip, postula-se que existe um meio contínuo em que existem vários componentes da fase dispersos, podendo estes ser gotas, bolhas ou partículas sólidas. A turbulência foi avaliada utilizando os modelos K- padrão e o K-, porém só houve redução considerável dos resíduos para o K- Padrão. As densidades geradas nas simulações em CFD foram comparadas visualmente com os resultados experimentais obtidos em trabalho anterior para fluxo multifásico. As quedas de pressão obtidas em simulação foram comparadas com os dados da literatura, onde foi possível observar a grande redução da perda de carga ao utilizar a técnica de envolver o óleo com um anel de água na tubulação. As simulações realizadas com o modelo Algebraic Slip, e o modelo de turbulência foram consideradas como validadas. / With the discovery of oil in the pre-salt layer, Petrobras was encouraged to invest about 240 billion dollars. A critical point of this industry is the oil transport, which encompasses oil-water system. The objective of the present work is to study the flow of water and oil into a tube and an elbow, in order to generate distributions of velocity, pressure and density by using a CFD tool. To develop simulations the following is assumed: 3D flow, turbulent flow in oil phase and laminar flow in water phase, isotherm and incompressible flow. Steady-state and transient studies have been done. The mesh convergence has been carried out. The IPSA and Algebraic slip were the Phoenics tools that were used to represent the phases interaction. The IPSA solves the Navier-Stokes equations for each phase. In the Algebraic Slip model, one assumes that a continuum mean exists where the other components are dispersed, which can be bubbles or solid particles. The turbulence was evaluated by using K- standard and K- models; however, the considerable reduction of residue to the K- Standard was observed. The densities modeled by CFD were visually compared to the experimental results that were obtained in a previous work for a multiphase flow. The simulations of head loss were compared to literature data, and it can be seen a big difference between the head loss that was obtained by using water and that no using water. The simulations of Algebraic Slip model and the use of turbulence model were considered as validated.

This thesis presents results of a successful simulation study using CO2-EOR technique to enable production from an offshore heavy oil field, named here as Omega, which is located offshore West Africa at a water depth around 2000 m. The findings and contributions to knowledge are outlined below: 1. Long distance CO2 transportation offshore – The solution to the space and weight constraints offshore with respect to CO2-EOR, is a tie-back via long distance CO2 dense phase transportation from onshore to offshore. 2. Cold heavy oil production (CHOP) using CO2-EOR technique - Based on conditions investigated, Miscible Displacement was found to be more efficient for deepwater production. However, Immiscible Displacement can offer greater reliability with regards to CO2 sequestration. 3. CO2 sequestration during CHOP using CO2-EOR technique – Lower CO2 may be released post start-up operation, followed by gradual decline of CO2 retention after the production peak. CO2 retention increases with increasing reservoir pressure, starting with 17.7 % retention at 800 psig to 32.8 % at 5000 psig, based on peak production analysis. 4. Techno-economic Evaluation – Miscible displacement is asssociated with higher cash flow stream that extend throughout the lifetime of the asset due to continuous production while Immiscible Displacement has a longer payback period (in order of 22 years) due to the time lag between the CO2 injection and the incremental heavy oil production. 5. Mathematical Modelling – Improved mathematical models based on existing theories are proposed, to estimate the CO2 requirement and heavy oil production during CHOP using CO2-EOR technique, and to provide an operating envelope for a wide range of operating conditions. As part of further work, the proposed models will require more refinement and validation across a broad range of operating conditions, could be adapted and modified to increase its predictive capability over time.

Cette thèse présente l'étude du procédé de combustion in situ (CIS) dans un réservoir carbonaté fracturé. Afin de modéliser et de simuler les processus à grande échelle, deux axes principaux sont distinguées, qui correspondent aux petites et grandes échelles. Pour traiter les problèmes à petite échelle, un simulateur commercial de réservoir est utilisé afin d’étudier le processus à l'échelle de la carotte. Tout d'abord, le simulateur est validé pour des procédés simples pour lesquels des solutions analytiques sont disponibles. La validation plus poussée est effectuée en utilisant des résultats expérimentaux publiés dans la littérature. Puis, quelques simulations du système fracturé à l'échelle de la carotte sont effectuées. Le but de ces simulations est d'aborder, la faisabilité du processus CIS dans le système fracturé et de distinguer l'importance relative des divers mécanismes de production pétrolière. Dans l'étape suivante, les tests de tube de combustion et de cellule cinétique sont réalisés, afin de mieux comprendre la physique du processus mais aussi la cinétique de combustion dans un système carbonaté fracturé. Les simulations sont également menées à échelle d'un bloc métrique. Afin d'obtenir la connaissance nécessaire pour le changement d'échelle, des simulations sur plusieurs bloc sont menées et les moyenne des certains paramètres sont estimées. Dans la dernière partie, les conclusions sont présentées et la technique de prise de moyenne est utilisée sur un processus simple (combustion du solide-gaz) afin de donner quelques pistes quant aux enjeux futurs de ce genre de problème. / The aim of the present work is to study the in situ combustion (ISC) process at inter-well scale in a fractured reservoir. Due to the complexity associated with the ISC process, highly heterogeneous nature of the fractured reservoirs and some unsuccessful attempts in the past to put the process into practice, the subject of ISC in fractured systems has been receiving little interest and there are still many essential open questions in this area. It is very challenging to answer the question whether the ISC process could be applied in a heavy oil fractured reservoir or not. And if the answer is positive, what is (are) the dominant oil recovery mechanism(s) and finally, how can we model and simulate this process, at least, at inter-well scale. This work tries to give answers to some of these questions. In this regard, we followed a step by step procedure. In the first step, general literature concerning the combustion process in porous media and particularly that related to the combustion process in an oil reservoir was reviewed. Some other references about the modeling of fracture reservoirs were also reviewed. This led us to distinguish some of the main challenges in this area and define a methodology for the rest of the work. Based on this methodology, the first target was to understand and to characterize the behavior of a combustion front at small (Darcy) scale. The second target was to apply the knowledge of the first part to propose a suitable model for ISC at larger scale. To this end, a commercial thermal reservoir simulator (STARS) was used. The simulator was validated for both simple process for which an analytical solution is available and for a more complex process where the laboratory results are on hand. Then, after the validation part, the numerical tool has been used to widely investigate the conditions where a reaction front can propagate in a fractured core. This allowed us to understand some of the leading mechanisms (oxygen diffusion coefficient for extinction/ propagation of combustion front and matrix permeability for oil production). Some other numerical studies provided us with some understanding about the most important mechanism(s) of oil production. Thereafter, some single block simulations were done to investigate the two-dimensional behavior of the ISC process, based on which the underlying process was found to be diffusion dominated both for heat and mass transfers. These results also helped us to distinguish the characteristic length scale of some important parameters (temperature, coke concentration, combustion front, etc.) which can give useful information about the large scale model. After that, an experimental part has been performed to find propagation conditions of ISC at laboratory scale. This was done by varying both the operational conditions (flowrate, pressure and oxygen concentration) and the characteristics of the fractured system (aperture, surface area, permeability). This permitted us to find that in some suitable conditions there is a possibility to generate a combustion front in a fractured system containing heavy oil. To give an idea about the modeling of the process at larger scale, some fine grid simulations are also performed using a multi-block model. By analyzing the results of this model some guidelines are proposed for the large scale model. At the end, a short discussion about the upscaling of an easy system (solid-gas combustion using an Arrhenius law as a function for the mass sink term in a conductive system) is presented based on an upscaling using the volume averaging method.

Agglomerate formation is a common phenomenon that can cause operating problems in the fluid coking reactor. When agglomerates form they provide longer diffusion paths of the reaction products through the liquid layers and liquid bridges within the agglomerate, which leads to higher mass transfer resistance, trapping of the reaction products and increasing the undesired coke formation reactions. Surviving agglomerates in the reactor can also cause fouling of the reactor interior and defluidization of the bed. The ultimate coke yield was determined for agglomerates of Athabasca vacuum residue and solid particles by heating on Curie-point alloy strips in an induction furnace at 503 oC and 530 oC and in a fluidized bed reactor at 500 oC until all toluene-soluble material was converted. Coke yields from agglomerates were compared to the results from reacting thin films of vacuum residue. The average coke yield from the agglomerates was 23%, while the coke yield from thin films of 20 m thickness was 11%, which supports the role of mass transfer in coke formation reactions. The ultimate coke yield was insensitive to vacuum residue concentration, agglomerate size, reaction temperature and agglomerate disintegration. The temperature profile within agglomerates was measured by implanting a thermocouple at the agglomerate center, and a heat transfer model was used to describe the temperature variation with time. The effective thermal diffusivity of the agglomerates was 0.20 x 10-6 m2/s. Control experiments on reactions in thin liquid films confirmed that heating rates in the range of 14.8 to 148 K/s had no effect on the ultimate yield of coke

Combustion assisted gravity drainage (CAGD) is an integrated horizontal well air injection process for recovery and upgrading of heavy oil and bitumen from tar sands. Short-distance air injection and direct mobilized oil production are the main features of this process that lead to stable sweep and high oil recovery. These characteristics identify the CAGD process as a high-potential oil recovery method either in primary production or as a follow-up process in reservoirs that have been partially depleted. The CAGD process combines the advantages of both gravity drainage and conventional in-situ combustion (ISC). A combustion chamber develops in a wide area in the reservoir around the horizontal injector and consists of flue gases, injected air, and mobilized oil. Gravity drainage is the main mechanism for mobilized oil production and extraction of flue gases from the reservoir. A 3D laboratory cell with dimensions of 0.62 m, 0.41 m, and 0.15 m was designed and constructed to study the CAGD process. The combustion cell was fitted with 48 thermocouples. A horizontal producer was placed near the base of the model and a parallel horizontal injector in the upper part at a distance of 0.13 m. Peace River heavy oil and Athabasca bitumen were used in these experiments. Experimental results showed that oil displacement occurs mainly by gravity drainage. Vigorous oxidation reactions were observed at the early stages near the heel of the injection well, where peak temperatures of about 550ºC to 690ºC were recorded. Produced oil from CAGD was upgraded by 6 and 2ºAPI for Peace River heavy oil and Athabasca bitumen respectively. Steady O2 consumption for both oil samples confirmed the stability of the process. Experimental data showed that the distance between horizontal injection and production wells is very critical. Close vertical spacing has negative effect on the process as coke deposits plug the production well and stop the process prematurely. CAGD was also laboratory tested as a follow-up process. For this reason, air was injected through dual parallel wells in a mature steam chamber. Laboratory results showed that the process can effectively create self-sustained combustion front in the previously steam-operated porous media. A maximum temperature of 617ºC was recorded, with cumulative oil recovery of 12% of original oil in place (OOIP). Post-experiment sand pack analysis indicated that in addition to sweeping the residual oil in the steam chamber, the combustion process created a hard coke shell around the boundaries. This hard shell isolated the steam chamber from the surrounding porous media and reduced the steam leakage. A thermal simulator was used for history matching the laboratory data while capturing the main production mechanisms. Numerical analysis showed very good agreement between predicted and experimental results in terms of fluid production rate, combustion temperature and produced gas composition. The validated simulation model was used to compare the performance of the CAGD process to other practiced thermal recovery methods like steam assistance gravity drainage (SAGD) and toe to heel air injection (THAI). Laboratory results showed that CAGD has the lowest cumulative energy-to-oil ratio while its oil production rate is comparable to SAGD.

The transportation of heavy oil is a pressing problem. Various methods have been devised to mitigate the reluctance to flow of these highly dense and viscous oils. This study is focused on evaluating a case for post-production partial upgrading of heavy oil. Specifically, we analyze the impact of visbreaking, a mild thermal cracking method, on the economic and energy demands of the post-production process. Using conservative modeling techniques and principles we find significant cost and energy savings can potentially result out of visbreaking. Cost savings result as a consequence of reduced diluent usage. Even the most conservative modeling scenario under consideration exhibits significant cost savings in the form of reduced diluent usage; these savings not only offset operational costs but provide short payback periods on capital expenditures. Additionally, the lower gravity blend resulting from visbreaking can also bring about energy and cost savings in pipeline transportation and positively impact the heavy oil value chain from the producer to a refinery or regional upgrading facility. From this basic analysis of the potential of visbreaking, we can recommend investing resources to study its viability in the field. Using this analysis as a tipping off point and with a detailed look at the chemistry of the oil in question it is possible to make a very viable case for visbreaking. In a similar vein, this analysis can serve as a guide in making a case for other partial upgrading methods as well.

The process of vapor extraction (VAPEX) is a recovery process which targets the heavy oil and bitumen resources. Owing to high viscosity values for these unconventional types of oil, the recovery processes in such reserves are still challenging. The unconventional oil recovery processes usually include a mechanism for reducing the oil viscosity by means of heat, solvent, or both. The process of VAPEX utilizes the injection of a light hydrocarbon solvent into a reservoir for recovering the viscous oil in place by diffusing into the oil and by providing sufficient mobility to the oil upon dilution. Although this process offers a variety of advantages over the alternative thermal recovery processes such as SAGD or CSS, it suffers from two major drawbacks. First, the oil production rates obtained in the VAPEX process are considerably lower than those obtained in the thermal processes. Second, the solvent cost is considerably high. We tried to tackle these two problems during this research and we searched for potentials for an improved VAPEX process. Three potentially improved occurrences of a VAPEX project were found when: 1) the injected solvent was superheated, 2) the wettability of media was altered to oil-wet, and 3) the vugs were distributed in the porous media. Warm VAPEX process is introduced in which the VAPEX process is thermally augmented through superheating the solvent vapor. An attractive feature of this process is the capability of the solvent in being able to condense at the bitumen-solvent interface, which provides the opportunity for the bitumen to be upgraded in-situ through asphaltene precipitation. The asphaltene precipitation was not observed during the conventional vapor extraction process and was only observed during the warm VAPEX process. Upon a moderate level of superheating, the production rate of bitumen was sufficiently improved while the solvent content of the produced oil was significantly decreased as a result of decreased solubility of solvent in the oil at elevated temperatures. Therefore, more oil was produced at lower costs. The warm VAPEX experiments were conducted at 4 temperature levels in high and low permeability media using Cold Lake bitumen and Lloydminster heavy oil blend, n-pentane was used as solvent. The warm VAPEX process was found to be more effective for Cold Lake bitumen and for less permeable media. The potential of in-situ upgrading decreased when the level of superheating increased. The second potential for an improved VAPEX process obtained when the wettability of porous medium was altered to oil-wet conditions. Although this wettability condition is harmful to steam-based recovery processes, such as SAGD, it becomes beneficial to VAPEX. For the application of VAPEX process in fractionally wet media the wettability of glass beads was altered to oil-wet conditions through silylation process, and the VAPEX experiments were conducted in a random packing of water-wet and oil-wet beads of similar size at 7 different compositions. A substantial increase in the oil production rate was observed in a completely oil-wet medium, compared to the water-wet medium. By increasing the fraction of oil-wet beads in the packing up to a critical composition, the production rate of live oil increased linearly with the increase in the fraction of oil-wet beads in the packing during the vapor extraction process. Beyond this critical composition, however, the production rate of live oil did not change significantly with further increase in the fraction of the oil-wet beads in the randomly packed medium. Vugs were also found to be beneficial to the production performance of the VAPEX process. The presence of vugs was investigated in synthesized vugular media at 4 different levels of vuggy-to-total pore volume ratios. The performance of vugular media was compared to that of the homogeneous sintered media. The vugs facilitated the production of oil during the VAPEX process by providing flow communication between the vugs and the surrounding matrix, and therefore, by providing a local high permeability pathways towards the production well. A peak in the oil production rate was observed whenever a series of vugs were simultaneously invaded by the solvent vapor. The overall production rate of oil was higher in vuggy media compared to a homogeneous media at the same overall porosity and permeability. Furthermore, the magnitude of residual oil saturation left behind was also slightly lower in vuggy medium because the vugs were perfectly drained. Finally, a constant rate air injection (CRAI) porosimetry method was developed for characterization of vugs in a vugular media. This method was successfully tested in different synthetic vugular media, and the results illustrated higher accuracy in CRAI porosimetry method compared to constant rate mercury porosimetry. CRAI porosimetry method was also employed for identification of higher permeability regions embedded in a matrix of lower permeability. The analysis of a typical porosimetry signal was also modified.

There are many heavy oil reservoirs with thin pay zones (less than 10 m) in the world and in Turkey. Conventional steam injection techniques are not costeffective for such reservoirs, due to excessive heat loss through the overburden. Heat losses can be minimized through controlled heating of the pay zone. One such way is to introduce heat to the reservoir in a controlled manner is microwave heating. Laboratory studies on microwave heating of a scaled model of a heavy oil reservoir with a thin pay zone are presented with an economical feasibility of the method. In this thesis, three different conceptual oil reservoirs from south east Turkey are evaluated: Bati Raman (9.5 API) and &Ccedil / amurlu (12 API) heavy crude oils and paraffinic Garzan (26 API)crude oil. Using a graphite core holder packed with crushed limestone with crude oil and water microwave effects of operational parameters like heating time and waiting period as well as rock and fluid properties like permeability, porosity, wettability, salinity, and initial water saturation are studied. The main recovery mechanisms for the experiments are viscosity reduction and gravity drainage. An analytical model is developed by coupling heat equation with the electromagnetic dissipated power per unit of volume based in Maxwell&#039 / s equation successfully models the experiments for temperatures less than the pyrolysis temperature is presented. Also the experiments are scaled to the model by geometric similarity concept. In economic evaluation, the cost of oil is calculated based on domestic electricity prices.

Fractured viscous oil resources hold great potential for continued oil production growth globally. However, many of these resources are not accessible with current commercial technologies using steam injection which limits operations to high temperatures. Several steam-solvent processes have been proposed to decrease steam usage, but they still require operating temperatures too high for many projects. There is a need for a low temperature injection strategy alternative for viscous oil production. This dissertation discusses scoping experimental work for a low temperature solvent injection strategy targeting fractured systems. The strategy combines three production mechanisms – gas-oil gravity drainage, liquid extraction, and film gravity drainage. During the initial heating period when the injected solvent is in the liquid phase, liquid extraction occurs. When the solvent is in the vapor phase, solvent-enhanced film gravity drainage occurs. A preliminary simulation of the experiments was developed to study the impact of parameter uncertainty on the model performance. Additional work on reducing uncertainty for key parameters controlling the two solvent production mechanisms will be necessary. In a natural fracture network, the solvent would not be injected uniformly throughout the reservoir. Preferential injection into the higher conductivity fracture areas would result in early breakthrough leaving unswept areas of high oil saturation. Conformance control would be necessary to divert subsequent solvent injection into the unswept zones. A variety of techniques, including polymer and silica gel treatments, have been designed to block flow through the swept zones, but all involve initiating gelation prior to injection. This dissertation also looks at a strategy that uses the salinity gradient between the injected silica nanoparticle dispersion and the in-situ formation water to trigger gelation. First, the equilibrium phase behavior of silica dispersions as a function of sodium chloride and nanoparticle concentration and temperature was determined. The dispersions exhibited three phases – a clear, stable dispersion; gel; and a viscous, unstable dispersion. The gelation time was found to decrease exponentially as a function of silica concentration, salinity, and temperature. During core flood tests under matrix and fracture injection, the in-situ formed gels were shown to provide sufficient conductivity reduction even at low nanoparticle concentration. / text