No description available.

“Introduction to the Canadian Oil Sands”, “Canada’s Oil Sand Industry: An Overview”, “Heavy Oil Technologies”, and so many other topics about heavy oil have become the hotcakes in the oil industry. A number of new projects are in Execute phase for the development of heavy oil assets. This clearly shows the increasing demand for heavy oil. An oil industry is working hard to meet the world oil demand by developing deep water, HPHT, heavy oil, shale sands and all other non-conventional reservoirs but the main challenge is to develop and operate them in a risk free environment. Understanding the reservoir and fluid properties and developing new technologies help the industry to reduce the risk in developing non-conventional fields. A major problem in heavy oil field is to understand the behaviour of heavy oil. The viscous oil flows sluggishly in the formations and hence it is difficult to transport through unconsolidated formations and is very difficult to produce by conventional methods. Viscous oil recovery entails neatly designed enhanced oil recovery processes like Steam Assisted Gravity Drainage and the success of such technologies are critically dependent on accurate knowledge of reservoir, well and fluid properties of oil under variety of pressure and temperature conditions. This research project has provided some solutions to the challenges in heavy oil field development and can help the oil industry to optimise heavy oil production. Detailed experimental understanding of PVT properties has allowed this project to contribute to the knowledge. Reservoir, well and fluid properties were studied thoroughly and demonstrated the criticality of each parameter on the efficiency of Steam Assisted Gravity Drainage. An user friendly SAGD simulator is a big output of this research which allows the user to optimise the heavy oil recovery and enables to do risk assessments quickly during design phase of SAGD. A SAGD simulator is developed.

L’évaporation d’une solution saline en milieu poreux intervient dans diverses situations comme lors de l’injection de dioxyde de carbone dans des aquifères salins ou dans des processus de dégradation des monuments ou de la végétation. Un aspect clé est la cristallisation des sels dissous à la surface ou au sein du milieu poreux résultant de l’évaporation de la solution. Dans la première partie de ce manuscrit, nous étudions le séchage d’un milieu poreux modèle initialement saturé par une solution aqueuse de chlorure de sodium pour différentes tailles moyennes de pores et différents flux d’évaporation. Ceci nous permet d’obtenir une caractérisation des cristaux formés en surface (efflorescence) en fonction de ces paramètres. Nous nous intéressons ensuite tout particulièrement au cas où l’efflorescence forme une croûte d’apparence compacte. Un aspect intrigant est que cette croûte ne bloque pas complètement l’évaporation. Le taux d’évaporation est réduit d’un ordre de grandeur environ. Une modélisation de la croissance de la croûte est développée pour expliquer ce phénomène. Dans une deuxième partie du manuscrit, nous nous intéressons au phénomène relié à la croissance d’un efflorescence “rampante” à la surface d’un substrat solide, dans notre cas la surface externe d’un tube capillaire droit dont une extrémité est plongée dans une solution de chlorure de sodium. Les lois de croissance de ce phénomène sont caractérisées à partir du suivi temporel par double pesée de la masse d’eau évaporée et de la masse de sel qui précipite ainsi que de la géométrie de l’enveloppe externe de la couche de sel recouvrant progressivement le capillaire. Ici encore, l’analyse du phénomène de croissance est confortée par une modélisation numérique simple. Un aspect important de ce travail est le recours à des techniques de visualisations modernes (microtomographie à rayons X, microscopie électronique à balayage, scanner de surface à lumière structurée) pour obtenir autant d’informations que possible sur la structure des efflorescences et les mécanismes de croissance mis en jeu dans ces expériences. / Evaporation of saline solution in porous media occurs in various situations such as injection of carbon dioxide in saline aquifers or in degradation processes on monuments or on vegetation. A key aspect is the crystallization of dissolved salts on the surface or in the porous medium resulting from the evaporation of the solution. In the first part of this manuscript, we study the drying of model porous media model initially saturated with an aqueous solution of sodium chloride, for different average pore sizes and different evaporation fluxes. This allows us to obtain a characterization of the salt crystals formed on the surface (efflorescence) depending on these parameters. We are particularly interested in the case when the efflorescence forms an apparently compact crust. An intriguing aspect is that the crust does not completely block the evaporation. The evaporation rate is in fact reduced by an order of ten. To explain this phenomenon, a model of the growth of the crust is developed. In a second part of the manuscript, we are interested in the growth of a salt efflorescence by “creeping” on a solid substrate, here the outer surface of a straight capillary tube, with one end immersed in a sodium chloride solution. The growth laws of this phenomenon are characterized by weighing both the mass of water evaporated and the mass of salt that precipitates, as well as recording the geometry of the outer casing of the salt layer gradually covering the capillary. Again, the analysis of this growth phenomenon is supported by a simple numerical model. An important aspect of this work is the use of up-todate visuablisation techniques (such as X-ray micro-tomography, scanning electron microscopy and structuredlight surface scanning) to get as much as possible additional information on the efflorescence structure and growth mechanism at play in these experiments.

The energy demand has increased dramatically in the last century, and so to have global CO2 emissions. Two critical challenges for the geo-energy sector are to develop different approaches for harvesting energy and to actively decrease atmospheric CO2 emissions. Addressing these challenges requires efficient, sustainable, and affordable technical solutions. Complex fluids are ubiquitous and offer great potential for geo-engineering applications such as the development of geo-energy, enhanced oil recovery and CO2 geological sequestration and utilization. This thesis will present new results on interfacial phenomena in CO2-fluid-mineral systems, including interfacial tension hysteresis, the effects of surface-active components on interfacial tension (surfactants, nanoparticles, organo-bentonites and asphaltenes), and the interfacial pinning of immiscible fluids on substrates. Pore-scale phenomena come together in the study of the physical properties of CO2 and its implication for both storage and assisted gravity oil drainage. Finally, we provide a better understanding of the interfacial phenomena of complex fluids and their interactions within porous media that can lead to efficient and sustainable geo-energy systems.

The transport of components and phases plays a fundamental role in the success of an EOR process. Because many reservoirs have harsh conditions of salinity, temperature and rock heterogeneity, which limit process options, a robust system with flexibility is required. Systematic experimental study of formulations capable to transport surfactant as foam at 94°C, formulated in sea water, is presented. It includes methodology to conduct core floods in sand packs using foaming surfactants and to develop “surfactant blend ratio- salinity ratio maps” using equilibrium phase behavior to determine favorable conditions for oil recovery in such floods. Mathematical model able to reproduce the foam strength behavior observed in sand packs with the formulations studied is presented. Visualization of oil recovery mechanism from matrix is realized using a model system of micro-channels surrounded by glass beads to mimic matrix and fractures respectively. The observations illustrate how components may distribute within the matrix, thereby releasing oil into the fractures. The use of chemicals to minimize adsorption is required when surfactant adsorption is important. The presence of anhydrite may limit the use of sodium carbonate to reduce adsorption of carbonates. A methodology is presented to estimate the amount, if any, of anhydrite present in the reservoir. The method is based on brine software analysis of produced water compositions and inductively coupled plasma (ICP) analysis of core samples. X-ray powder diffraction (XRD) was used to verify the mineralogy of the rock. X-ray photoelectron spectroscopy (XPS) was used to obtain surface composition for comparison with bulk composition of the rock. Adsorption of surfactants was measured using dynamic and static adsorption experiments. Determining the flow properties of the rock samples via tracer analysis permitted the simulation of the dynamic adsorption process using a mathematical model that considers the distribution of adsorbed materials in the three different regions of pore space. Using this method allows one to predict adsorption in a reservoir via simulation.

The aim of the study is to investigate matrix-fracture interaction, gas oil gravity drainage (GOGD) and diffusion mechanisms with CO2, N2 and CH4 gas injection in a fractured system. Effects of injected gas type, initial gas saturation and diffusion coefficient on oil recovery are studied by an experimental and simulation work. In the experimental study, Berea sandstone cores are placed in a core holder and the space created around the core is considered as a surrounding fracture. System is kept at a pressure of 250 psi by CO2, N2 and CH4 gases and at a reservoir temperature of 70 &deg / C. Experiments with cores having similar initial saturations resulted in the highest ndecane recovery in CO2 experiment followed by CH4 and N2. The highest solubility of CO2 in n-decane and density difference between CO2 and CO2-ndecane mixture are considered as the reason of results. CO2 injection tests with n-decane and brine saturated core with and without initial gas saturation indicate that availability of initial gas saturation in matrix increased recovery. A simulation study is continued using CMG (Computer Modeling Group Ltd.) WinProp (Microsoft Windows&trade / based Phase-Behavior and Fluid Property Program) and GEM (Generalized Equation-of-State Model Compositional Reservoir Simulator). Simulation results of CO2 experiment with initial gas show that dominant effect of GOGD decreases and diffusion becomes more effective at final production stages. Simulation study indicates an immediate, sharp decrease in oil saturation in matrix. Oil in matrix migrates into fractures and moves downward as a result of GOGD with gas injection.

Water-flooding in water-wet fractured reservoirs can recover significant amounts of oil through capillary driven imbibition. Unfortunately, many of the fractured reservoirs are mixed-wet/oil-wet and water-flooding leads to poor recovery as the capillary forces hinder imbibition. Surfactant injection and immiscible gas injection are two possible processes to improve recovery from fractured oil-wet reservoirs. In both these EOR methods, the gravity is the main driving force for oil recovery. Surfactant has been recommended and shown a great potential to improve oil recovery from oil-wet cores in the laboratory. To scale the results to field applications, the physics controlling the imbibition of surfactant solution and the scaling rules needs to be understood. The standard experiments for testing imbibition of surfactant solution involves an imbibition cell, where the core is placed in the surfactant solution and the recovery is measured versus time. Although these experiments prove the effectiveness of surfactants, little insight into the physics of the problem is achieved. This dissertation provides new core scale and pore scale information on imbibition of anionic surfactant solution into oil-wet porous media. In core scale, surfactant flooding into oil-wet fractured cores is performed and the imbibition of the surfactant solution into the core is monitored using X-ray computerized tomography(CT). The surfactant solution used is a mixture of several different surfactants and a co-solvent tailored to produce ultra-low interfacial tension (IFT) for the specific oil used in the study. From the CT images during surfactant flooding, the average penetration depth and the water saturation versus height and time is calculated. Cores of various sizes are used to better understand the effect of block dimension on imbibition behavior. The experimental results show that the brine injection into fractured oil-wet core only recovers oil present in the fracture; When the surfactant solution is injected, the CT images show the imbibition of surfactant solution into the matrix and increase in oil recovery. The surfactant solution imbibes as a front. The imbibition takes place both from the bottom and the sides of the core. The highest imbibition is observed close to the bottom of the core. The imbibition from the side decreases with height and lowest imbibition is observed close to the top of the core. Experiments with cores of different sizes show that increase in either the length or the diameter of the core causes decrease in the fractional recovery rate (%OOIP). Numerical simulation is also used to determine the physics that controls the imbibition profiles. %The numerical simulations show that the relative permeability curves strongly affect the imbibition profiles and should be well understood to accurately model the process. Both experimental and numerical simulation results imply that the gravity is the main driving force for the imbibition process. The traditional scaling group for gravity dominated imbibition only includes the length of the core to upscale the recovery for cores of different sizes. However based on the measurements and simulation results from this study, a new scaling group is proposed that includes both the diameter and the length of the core. It is shown that the new scaling group scales the recovery curves from this study better than the traditional scaling group. In field scale, the new scaling group predicts that the recovery from fractured oil-wet reservoirs by surfactant injection scales by both the vertical and horizontal fracture spacing. In addition to core scale experiments, capillary tube experiments are also performed. In these experiments, the displacement of oil by anionic surfactant solutions in oil-wet horizontal capillary tubes is studied. The position of the oil-aqueous phase interface is recorded with time. Several experimental parameters including the capillary tube radius and surfactant solution viscosity are varied to study their effect on the interface speed. Two different models are used to predict the oil-aqueous phase interface position with time. In the first model, it is assumed that the IFT is constant and ultra-low throughout the experiments. The second model involves change of wettability and IFT by adsorption of surfactant molecules to the oil-water interface and the solid surface. Comparing the predictions to the experimental results, it is observed that the second model provides a better match, especially for smaller capillary tubes. The model is then used to predict the imbibition rate for very small capillary tubes, which have equivalent permeability close to oil reservoirs. The results show that the oil displacement rate is limited by the rate of diffusion of surfactant molecules to the interface. In addition to surfactant flooding, immiscible gas injection can also improve recovery from fractured oil-wet reservoirs. In this process, the injected gas drains the oil in the matrix by gravity forces. Gravity drainage of oil with gas is an efficient recovery method in strongly water-wet reservoirs and yields very low residual oil saturations. However, many of the oil-producing fractured reservoirs are not strongly water-wet. Thus, predicting the profiles and ultimate recovery for mixed and oil-wet media is essential to design and optimization of improved recovery methods based on three-phase gravity drainage. In this dissertation, we provide the results from two- and three-phase gravity drainage experiments in sand-packed columns with varying wettability. The results show that the residual oil saturation from three-phase gravity drainage increases with increase in the fraction of oil-wet sand. A simple method is proposed for predicting the three-phase equilibrium saturation profiles as a function of wettability. In each case, the three-phase results were compared to the predictions from two-phase results of the same wettability. It is found that the gas/oil and oil/water transition levels can be predicted from pressure continuity arguments and the two-phase data. The predictions of three-phase saturations work well for the water-wet media, but become progressively worse with increasing oil-wet fraction. / text

This report offers a comparative valuation of two bitumen production technologies, using real options analysis (ROA) techniques to incorporate strategic flexibility into the investment scenario. By integrating a probabilistic cost model into a real options framework, the value of an oil recovery facility is modeled to reflect the realistic alternatives available to decision-makers, where the course of the investment can be altered as new information becomes available. This approach represents a distinct advantage to traditional discounted cash flow (DCF) estimation, which is unable to capture operational adaptability, including the ability to expand, delay, or abandon a project. The analysis focuses on the energy inputs required for the recovery of heavy oil bitumen from Alberta, Canada, and examines both natural gas and nuclear steam plants as heat sources. The ACR-1000 reactor is highlighted as a substitute for conventional natural gas-fueled means of production, in light of the recent volatility of natural gas prices and the potential for emissions compliance charges. The methodology includes a levelized cost assessment per barrel of bitumen and estimation of cost ranges for each component. A mean-reversion stochastic price model was also derived for the both natural gas and oil price. By incorporating cost ranges into a ROA framework, the benefit of retaining project flexibility is included in its valuation. Formulated as a decision tree, built-in options include the initial selection to pursue nuclear or natural gas, site selection and licensing, the ability to switch heat source in the planning stage, and the final commitment to construct. Each decision is influenced by uncertainties, including the course of bitumen and natural gas price, as well as emissions policy. By structuring the investment scenario to include these options, the overall value of the project increases by over $150 million. The ability to switch technology type allows for an assessment of the viability of nuclear steam, which becomes economically favorable given high natural gas prices or high emissions taxes. Given an initial selection of natural gas SAGD, there is a 25% probability that a switch to nuclear steam will occur, as evolving financial conditions make nuclear the optimal technology. / text

No description available.

The development of fast and efficient computer hardware technology has resulted in the rapid development of numerous computational software tools for making statistical inferences. The computational algorithms, which are the backbone of these tools, originate from distinct areas in science, mathematics and engineering. The main focus of this thesis is on computational tools which can be employed for estimating unmeasured variables in a process using all the available prior information. Specifically, this thesis demonstrates the application of a variety of tools for soft sensing of process variables and uncertain parameters of physiochemical process models, using routine data available from the process. The application examples presented in this thesis come from broad areas where process uncertainty is inherent and includes petrochemical processes, mechanical valve actuators, and upstream production processes in petroleum reservoirs. The mathematical models that are employed in different domains vary significantly in their structure and their level of complexity. In the petrochemical domain, the focus was on developing empirical soft sensors which are essentially nonparametric mathematical models identified using routine data from the process. The Support Vector Regression technique was applied for identifying such nonparametric empirical models. On the other hand, in all the other application examples in this thesis the physical parametric models of the process were utilized. The latter application examples, which cover a major portion of this thesis, demonstrate the application of modern state and parameter estimation algorithms which are firmly grounded on Bayesian theory and Monte Carlo techniques. Prior to the chapters on the application of state and parameter estimation techniques, a tutorial overview of the Monte Carlo simulation based state estimation algorithms is provided with an attempt to throw new light on these techniques. The tutorial is aimed at making these techniques simple to visualize and understand. The application case studies serve to illustrate the performance of the different algorithms. All case studies presented in this thesis are performed on processes that exhibit significant nonlinearity in terms of the relationship between the process input variables and output variables. / Process Control