The shift of hydrocarbon exploration and production to deepwater has resulted in new opportunities for the petroleum industry(in this project, the deepwater depth greater than 1,000 ft) but also, it has introduced new challenges. In 2001,more than 999 Bcf of associated gas were produced from the Gulf of Mexico, with deepwater associated gas production accounting for 20% of this produced gas. Two important issues are the potential environmental impacts and the economic value of deepwater associated gas. This project was designed to test the viability of storing associated gas in a saline sandstone aquifer above the producing horizon. Saline aquifer storage would have the dual benefits of gas emissions reduction and gas storage for future use. To assess the viability of saline aquifer storage, a simulation study was conducted with a hypothetical sandstone aquifer in an anticlinal trap. Five years of injection were simulated followed by five years of production (stored gas recovery). Particular attention was given to the role of relative permeability hysteresis in determining trapped gas saturation, as it tends to control the efficiency of the storage process. Various cases were run to observe the effect of location of the injection/production well and formation dip angle. This study was made to: (1) conduct a simulation study to investigate the effects of reservoir and well parameters on gas storage performance; (2) assess the drainage and imbibition processes in aquifer gas storage; (3) evaluate methods used to determine relative permeability and gas residual saturation ; and (4) gain experience with, and confidence in, the hysteresis option in IMEX Simulator for determining the trapped gas saturation. The simulation results show that well location and dip angle have important effects on gas storage performance. In the test cases, the case with a higher dip angle favors gas trapping, and the best recovery is the top of the anticlinal structure. More than half of the stored gas is lost due to trapped gas saturations and high water saturation with corresponding low gas relative permeability. During the production (recovery) phase, it can be expected that water-gas production ratios will be high. The economic limit of the stored gas recovery will be greatly affected by producing water-gas ratio, especially for deep aquifers. The result indicates that it is technically feasible to recover gas injected into a saline aquifer, provided the aquifer exhibits the appropriate dip angle, size and permeability, and residual or trapped gas saturation is also important. The technical approach used in this study may be used to assess saline aquifer storage in other deepwater regions, and it may provide a preliminary framework for studies of the economic viability of deepwater saline aquifer gas storage.

To recover oil remaining in petroleum reservoirs after waterflooding, the gravitationally stable mode of gas injection is recognized as a promising tertiary oil recovery process. Understanding the phenomena occurring over the course of the gravity-assisted inert gas injection (GAIGI) process is thus important. Extensive studies on both secondary and tertiary modes of gravity drainage have shown promising results in recovering oil from homogeneous water-wet glass bead packs, sand packs, and sandstone cores, respectively. However, it is not realistic to anticipate similar flow mechanisms and recovery results in all types of reservoirs because the natural hydrocarbon reservoirs are all heterogeneous in terms of their permeability, porosity, and wettability. Such heterogeneities cause irregular displacement patterns, and nonuniform fluid distribution. The impact of heterogeneity of the porous media on the GAIGI process has not been fully addressed in the experimental studies carried out to date; therefore, this thesis aims to fill in the gap of knowledge on this area. The impact of reservoir wettability and pore structure heterogeneities at the macroscopic scale on the recovery efficiency of the GAIGI process was investigated through a systematic experimental study for tertiary recovery of waterflood residual oil. To obtain heterogeneous (in terms of wettability) packings, isolated inclusions of oil-wet consolidated glass beads were embedded in a continuum of unconsolidated water-wet glass beads. Similarly, the heterogeneous porous media exhibiting permeability heterogeneity consisted of large-pore-size isolated regions randomly distributed in a small-pore-size continuum. Upon waterflooding, significantly higher waterflood residual oil saturation was established in both cases of heterogeneous media in comparison to water-wet homogeneous porous media. The amount of waterflood residual oil varied linearly with the volume fraction of heterogeneities in the packings. Experimental results obtained from tertiary gravity drainage experiments demonstrated that the continuity of water-wet portions of the heterogeneous porous media facilitates the residual oil recovery through the film flow mechanism, provided that the oil spreading coefficient is positive. In addition, owing to the high waterflood residual oil content of the heterogeneous media tested, the oil bank formation occurred earlier and grew faster than that in homogeneous media, resulting in a higher oil recovery factor. However, the favorable wettability conditions in both the homogeneous and heterogeneous porous media exhibiting permeability heterogeneity resulted in slightly lower reduced residual oil saturation after the GAIGI process compared to that in the heterogeneous media with wettability heterogeneity under the same condition of withdrawal rate. In addition, the oil recovery factor at gas breakthrough was found to be inversely related to the production rate due to the functionality of gravity and viscous forces over the course of gravity drainage. These two forces were combined into a dimensionless form, defined as the gravity number (Ngv=Kogg/oVpg). It was discovered that there is a correlation between the oil recovery factor at gas breakthrough and the gravity number for both the heterogeneous and homogeneous media. The correlation of recovery factor at gas breakthrough versus the gravity number in heterogeneous media followed a similar trend as that found for homogeneous water-wet porous media. However, at a given gravity number, the recovery factor in heterogeneous media was greater than that in the homogeneous media. This implies that heterogeneous media will be better target reservoirs for applying the GAIGI process compared to the homogeneous reservoirs.

To recover oil remaining in petroleum reservoirs after waterflooding, the gravitationally stable mode of gas injection is recognized as a promising tertiary oil recovery process. Understanding the phenomena occurring over the course of the gravity-assisted inert gas injection (GAIGI) process is thus important. Extensive studies on both secondary and tertiary modes of gravity drainage have shown promising results in recovering oil from homogeneous water-wet glass bead packs, sand packs, and sandstone cores, respectively. However, it is not realistic to anticipate similar flow mechanisms and recovery results in all types of reservoirs because the natural hydrocarbon reservoirs are all heterogeneous in terms of their permeability, porosity, and wettability. Such heterogeneities cause irregular displacement patterns, and nonuniform fluid distribution. The impact of heterogeneity of the porous media on the GAIGI process has not been fully addressed in the experimental studies carried out to date; therefore, this thesis aims to fill in the gap of knowledge on this area. The impact of reservoir wettability and pore structure heterogeneities at the macroscopic scale on the recovery efficiency of the GAIGI process was investigated through a systematic experimental study for tertiary recovery of waterflood residual oil. To obtain heterogeneous (in terms of wettability) packings, isolated inclusions of oil-wet consolidated glass beads were embedded in a continuum of unconsolidated water-wet glass beads. Similarly, the heterogeneous porous media exhibiting permeability heterogeneity consisted of large-pore-size isolated regions randomly distributed in a small-pore-size continuum. Upon waterflooding, significantly higher waterflood residual oil saturation was established in both cases of heterogeneous media in comparison to water-wet homogeneous porous media. The amount of waterflood residual oil varied linearly with the volume fraction of heterogeneities in the packings. Experimental results obtained from tertiary gravity drainage experiments demonstrated that the continuity of water-wet portions of the heterogeneous porous media facilitates the residual oil recovery through the film flow mechanism, provided that the oil spreading coefficient is positive. In addition, owing to the high waterflood residual oil content of the heterogeneous media tested, the oil bank formation occurred earlier and grew faster than that in homogeneous media, resulting in a higher oil recovery factor. However, the favorable wettability conditions in both the homogeneous and heterogeneous porous media exhibiting permeability heterogeneity resulted in slightly lower reduced residual oil saturation after the GAIGI process compared to that in the heterogeneous media with wettability heterogeneity under the same condition of withdrawal rate. In addition, the oil recovery factor at gas breakthrough was found to be inversely related to the production rate due to the functionality of gravity and viscous forces over the course of gravity drainage. These two forces were combined into a dimensionless form, defined as the gravity number (Ngv=Kogg/oVpg). It was discovered that there is a correlation between the oil recovery factor at gas breakthrough and the gravity number for both the heterogeneous and homogeneous media. The correlation of recovery factor at gas breakthrough versus the gravity number in heterogeneous media followed a similar trend as that found for homogeneous water-wet porous media. However, at a given gravity number, the recovery factor in heterogeneous media was greater than that in the homogeneous media. This implies that heterogeneous media will be better target reservoirs for applying the GAIGI process compared to the homogeneous reservoirs.

Nous avons étudié expérimentalement la mise en suspension de particules lorsque l’on injecte du gaz à la base d’une couche de grains immergée dans un liquide, en géométrie confinée (cellule de Hele-Shaw). En configuration verticale, le système atteint toujours un régime stationnaire résultant de la compétition entre l’entraînement des grains par la remontée des bulles, et leur sédimentation. Un modèle phénoménologique permet d’expliquer les propriétés de la suspension ainsi formée, et du lit granulaire non affecté par la remontée de gaz. L’effet de la gravité effective dans le système est ensuite considérée. Lorsqu’un état stationnaire existe, la taille du lit granulaire présente un maximum pour un angle d’inclinaison de la cellule de 30-40 degrés environ. Cette observation s’explique par un phénomène particulier de sédimentation, l’effet Boycott. Les propriétés statistiques de la suspension (densité, homogénéité) et des bulles (taille, forme, orientation) ont été caractérisées. On montre en particulier que l’on atteint un plateau pour l’aire de contact entre les trois phases (gaz/liquide/solide) en fonction du débit, indépendamment de la gravité effective – résultat important dans le cadre d’applications à des réactions catalytiques. Enfin, une large exploration de la gamme des paramètres montre, pour des cellules inclinées et certaines valeurs de débit de gaz, l’existence d’un régime oscillant : la taille du lit granulaire varie entre un état « creusé » (suspension très dense) et un état « comblé » (suspension peu concentrée). Une explication est proposée pour les temps de montée et de descente de ces oscillations. / We have studied experimentally particle suspension when injecting a gas at the bottom of an immersed granular layer, in confined geometry (Hele-Shaw cell). In a vertical setup, the system always reaches a stationary state resulting from the competition between grains entrainment by bubble rise, and sedimentation. A phenomenological model makes it possible to explain the properties of the suspension thus formed, and of the granular bed not affected by the gas rise. The influence of the effective gravity in the system is then considered. When a stationary state is reached, the size of the granular bed displays a maximum for a cell inclination angle of about 30-40 degrees. This observation can be explained by referring to a peculiar sedimentation process, the Boycott effect. Statistical properties of the suspension (density, homogeneity) and bubbles (size, shape, orientation) have been characterized. In particular, we show that the contact surface between the three phases (gas/liquid/solid) reaches a plateau when increasing the gas flow-rate, independent of the effective gravity. This result is important in the frame of possible applications to catalytic reactors. Finally, exploring a large range of parameters, we point out the existence of an oscillatory regime for inclined cells in a given range of gas flow-rates: the granular bed size oscillates between an "excavated" state (dense suspension) and a "filled" state: (dilute suspension). An explanation for the rising and falling time of these oscillations is proposed.

Canada and Venezuela contain massive unconventional oil deposits accounting for over two thirds of newly discovered proven oil reserves since 2002. Canada, primarily in northern Alberta province, has between 1.75 and 1.84 trillion barrels of hydrocarbon resources that as of 2013 are obtained approximately equally through surface extraction or enhanced oil recovery (EOR) (World Energy Council, 2010). Due to their depth and viscosity, thermal based EOR will increasingly be responsible for producing the vast quantities of bitumen residing in Canada’s Athabasca, Cold Lake, and Peace River formations. Although the internationally accepted 174-180 billion barrels recoverable ranks Canada third globally in oil reserves, it represents only a 9-10% average recovery factor of its very high viscosity deposits (World Energy Council, 2010). As thermal techniques are refined and improved, in conjunction with methods under development and integrating elements of existing but currently separate processes, engineers and geoscientists aim to improve recovery rates and add tens of billions of barrels of oil to Canada’s reserves (Cenovus Energy, 2013). The Government of Canada estimates 315 billion barrels recoverable with the right combination of technological improvements and sustained high oil prices (Government of Canada, 2013). Much uncertainty and skepticism surrounds how this 75% increase is to be accomplished. This document entails a thorough analysis of standard and advanced EOR techniques and their potential incremental impact in Canada’s bitumen deposits. Due to the extraordinary volume of hydrocarbon resources in Canada, a small percentage growth in ultimate recovery satisfies years of increased petroleum demand from the developing world, affects the geopolitics within North America and between it and the rest of the world, and provides material benefits to project economics. This paper details the enhanced oil recovery methods used in the oil sands deposits while exploring new developments and their potential technical and economic effect. CMG Stars reservoir simulation is leveraged to test both the feasible recoveries of and validate the physics behind select advanced techniques. These technological and operational improvements are aggregated and an assessment produced on Canada’s total recoverable petroleum reserves. Canada has, by far, the largest bitumen recovery operation in the world (World Energy Council, 2010). Due to its resource base and political environment, the nation is likely to continue as the focus point for new developments in thermal EOR. Reservoir characteristics and project analysis are thus framed using Canada and its reserves. / text

A numerical reservoir model was created to optimize CO₂ Huff-and-Puff operations in the Bakken Shale. Huff-and-Puff is an enhanced oil recovery treatment in which a well alternates between injection, soaking, and production. Injecting CO₂ into the formation and allowing it to “soak” re-pressurizes the reservoir and improves oil mobility, boosting production from the well. A compositional reservoir simulator was used to study the various design components of the Huff-and-Puff process in order to identify the parameters with the largest impact on recovery and understand the reservoir’s response to cyclical CO₂ injection. It was found that starting Huff-and-Puff too early in the life of the well diminishes its effectiveness, and that shorter soaking periods are preferable over longer waiting times. Huff-and-Puff works best in reservoirs with highly-conductive natural fracture networks, which allow CO₂ to migrate deep into the formation and mix with the reservoir fluids. The discretization of the computational domain has a large impact on the simulation results, with coarser gridding corresponding to larger projected recoveries. Doubling the number of hydraulic fractures per stage results in considerably greater CO₂ injection requirements without proportionally larger incremental recovery factors. Incremental recovery from CO₂ Huff-and-Puff appears to be insufficient to make the process commercially feasible under current economic conditions. However, re-injecting mixtures of CO₂ and produced hydrocarbon gases was proven to be technically and economically viable, which could significantly improve profit margins of Huff-and-Puff operations. A substantial portion of this project involved studying alternative numerical methods for modeling hydraulically-fractured reservoir models. A domain decomposition technique known as mortar coupling was used to model the reservoir system as two individually-solved subdomains: fracture and matrix. A mortar-based numerical reservoir simulator was developed and its results compared to a tradition full-domain finite difference model for the Cinco-Ley et al. (1978) finite-conductivity vertical fracture problem. Despite some numerical issues, mortar coupling closely matched Cinco-Ley et al.'s (1978) solution and has potential applications in complex problems where decoupling the fracture-matrix system might be advantageous. / text

Multiple hydrocarbon phases are observed during miscible gas floods. The possible phases that result from a gas flood include a vapor phase, an oleic phase, a solvent-rich phase, a solid phase, and an aqueous phase. The solid phase primarily consists of aggregated asphaltene particles. Asphaltenes can block pore throats or change the formation wettability, and thereby reduce the hydrocarbon mobility. The dissolution of injected gas into the aqueous phase can also affect the gas flooding recovery because it reduces the amount of gas available to contact oil. This is more important in CO₂ flooding as the solubility of CO₂ in brine is much higher than hydrocarbons. In this research, we developed efficient and fast multi-phase equilibrium calculation algorithms to model phase behavior of asphaltenes and the aqueous phase in the compositional simulation of gas floods. The PC-SAFT equation of state is implemented in the UTCOMP simulator to model asphaltene precipitation. The additional computational time of PC-SAFT is substantially decreased by improving the root finding algorithm and calculating the derivatives analytically. A deposition and wettability alteration model is then integrated with the thermodynamic model to simulate dynamics of precipitated asphaltenes. Asphaltene deposition is shown to occur with pressure depletion around the production well and/or with gas injection in the reservoir domain that is swept by injected gas. It is observed that the profile of the damaged area by asphaltene deposition depends on the reservoir fluid. A general strategy is proposed to model the phase behavior of CO₂/hydrocarbon/water systems where four equilibrium phases exist. The developed four-phase reduced flash algorithm is used to investigate the effect of introducing water on the phase behavior of CO₂/hydrocarbon mixtures. The results show changes in the phase splits and saturation pressures by adding water to these CO₂/hydrocarbon systems. We used a reduced flash approach to reduce the additional computational time of the four-phase flash calculations,. The results show a significant speed-up in flash calculations using the reduced method. The computational advantage of the reduced method increases rapidly with the number of phases and components. We also decreased the computational time of the equilibrium calculations in UTCOMP by changing the sequential steps in the flash calculation where it checks the previous time-step results as the initial guess for the current time-step. The improved algorithm can skip a large number of flash calculation and stability analyses without loss of accuracy. / text

Highly fractured and vuggy oil reservoirs represent a challenge for enhanced oil recovery (EOR) methods. The fractured networks provide flow paths several orders of magnitude greater than the rock matrix. Common enhanced oil recovery methods, including gases or low viscosity liquids, are used to channel through the high permeability fracture networks causing poor sweep efficiency and early breakthrough. The purpose of this research is to determine the feasibility of using foam in highly fractured reservoirs to produce oil-rich zones. Multiple surfactant formulations specifically tailored for a distinct oil type were analyzed by aqueous stability and foam stability tests. Several core floods were performed and targeted effects such as foam quality, injection rate, injection type, permeability, gas saturation, wettability, capillary pressure, diffusion, foam squeezing, oil flow, microemulsion flow and gravity segregation. Ultimately, foam was successfully propagated under various core geometries, initial conditions and injections methods. Consequently, fluids were able to divert to unswept matrix and improve the ultimate oil recovery. / text

In gas-condensate reservoirs, gas productivity declines due to the increasing accumulation of liquids in the near wellbore region as the bottom-hole pressure declines below the dew point pressure. This phenomenon occurs even in reservoirs containing lean gas-condensate fluid. Various methods were addressed to remediate the productivity decline, for example, fracturing, gas injection, solvent injection and chemical treatment. Among them, gas injection techniques have been used as options to prevent retrograde condensation by vaporizing condensate and/or by enhancing condensate recovery in gas-condensate reservoirs. It is of utmost importance that the behavior of liquid accumulation near the wellbore should be described properly as that provides a better understanding of the productivity decline due to the originated from impaired relative mobility of gas. In this research, several gas injection techniques were assessed by using compositional simulators. The feasibility of different methods such as periodic hot gas injection and gas reinjection using horizontal wells were assessed using different reservoir fluid and injection conditions. It is shown that both the temperature and composition of the injection fluids play a key role in the remediation of productivity and condensate recovery. The combined effect of these parameters were investigated and the resulting impact on gas and condensate production was calculated by numerical simulations in this study. Design parameters pertaining to field development and operations including well configuration and injection/production scheme were also investigated in this study along with the above parameters. Based on the results, guidelines on design issues relating gas injection parameters were suggested. The various simulation cases with different parameters helped with gaining insight into the strategy of gas injection techniques to remediate the gas productivity and condensate recovery. / text

Independentemente do nível de verticalização ou da sua escala de produção, a redução de custos e o aumento de produtividade têm sido os principais focos internos das empresas da indústria do aço. Dois fatores controlam fundamentalmente o custo de produção do aço: o preço e o consumo dos insumos e matérias-primas. O primeiro depende fortemente do poder de barganha da empresa e das condições de mercado e, muitas vezes, não é possível exercer grande controle sobre ele. Sendo assim, é através da diminuição do consumo específico dos insumos e matérias-primas que a empresa pode obter sucesso na sua missão, internamente, de maximizar seu lucro. Em aciarias elétricas, o consumo dos insumos tem impacto importante na composição do custo final do aço, dos quais se destaca o consumo de energéticos utilizados no forno elétrico a arco, que pode representar até 30% do custo operacional desse tipo de aciaria. Para quantificar o aporte desses diferentes tipos de energia no forno, normalmente é utilizado o indicador de consumo de energia total, que utiliza o poder calorífico de cada tipo de energético na transformação para a unidade de kWh/t. O objetivo desse trabalho foi avaliar o impacto na eficiência energética do forno, medida através do consumo de energia total, da redução da vazão de gás natural nos modos lança e da modificação da proporção entre oxigênio e gás natural (O2/GN) em um dos modos queimador do sistema de injeção de um forno elétrico a arco. Para tanto, foi realizado um teste estatístico dividido em quatro cenários no formato de projeto de experimentos (DOE). O cenário em que as modificações no modo queimador e nos modos lança foram aplicadas conjuntamente apresentou a maior redução no consumo de energia total (2,50%), impulsionada principalmente pelas reduções no consumo de gás natural (16,94%) e no consumo de energia elétrica de forno e forno-panela (-1,90%). Através da análise do carbono de vazamento de todas as corridas não foi possível afirmar que os ganhos em consumo de energia elétrica foram provenientes de uma maior oxidação de ferro da carga nas corridas. / Companies have been extensively focusing on cost reduction and productivity optimization in the last few years, independently of their levels of production or verticalization. The cost of production is basically controlled by two factors: the price and the consumption of raw and input materials. The price depends on the current conditions of the market and the capacity of the company to deal with its suppliers about the price to be paid. Due to that, it is very difficult to control this factor and for this reason, through the reduction in raw material and inputs consumption that companies can achieve their mission of becoming more profitable. In electric steelmaking, consumption of inputs plays an important role on the final billet cost, with particular emphasis to the energy consumption in the electric arc furnace, which can represent up to 30% of the operational cost in a melt shop. To quantify the contribution of different types of energy in the furnace, it is used the performance indicator of total energy consumption, which associates the heat of combustion of each type of energetic in order to use the unit kWh/t. The aim of this study was to evaluate the impact on the energy efficiency of the furnace, measured by the total energy consumption, reducing the flow of natural gas in lance modes and modifying the ratio between oxygen and natural gas (O2/NG) in one of the burner modes of the injection system in an electric arc furnace. Thus, a statistical test divided into four scenarios in the format of design of experiments (DOE) was conducted. The scenario in which the burner mode and lance mode modifications were applied together resulted in the greatest reduction in total energy (2,50%), driven especially by reductions in natural gas consumption (16,94%) and electrical energy consumption of furnace and ladle furnace (1,90%). Through the analysis of tapping carbon of all heats it was not possible to assert that gains in electrical energy were due to a higher oxidation of iron contained in the blend charged.