During waterflooding, or chemical EOR processes with polymers, fractures are frequently generated in injectors. This can have a profound impact on the process performance and reservoir management. A fracture growth model was developed and linked to a reservoir simulator that incorporates the effect of (i) particle plugging due to filtration of solids and oil droplets in the injected fluids; (ii) non-Newtonian polymer rheology (shear-thinning and -thickening) for polymer injection; and (iii) thermal stresses induced by cold water injection. Dynamic fracture growth, which results from the pore pressure increase due to particle plugging or complex polymer rheology, affects the well injectivity and reservoir sweep significantly. With the fracture growth model, simulations can be made not only to make more accurate reservoir sweep and oil recovery predictions, but also to help identify well patterns that may improve reservoir performance. In homogeneous reservoirs, the injectivity is significantly affected by the propagation of an injection induced fracture; but the ultimate oil recovery and reservoir sweep are relatively unaffected. In multi-layered reservoirs, however, reservoir sweep and oil recovery are impacted significantly by the fracture growth. The oil recovery results from our fracture growth model differ substantially from those obtained based on the assumption of no fracture generation or a static fracture. For polymer injection processes, the shear rate dependence of the polymer viscosity is critical in determining the injectivity, fracture growth, and oil recovery. In addition to vertical injection well fractures, horizontal injection well fractures have been simulated by using the fracture growth model. The reservoir stress distribution determines the fracture orientation near a horizontal well. When the minimum horizontal stress orientation is perpendicular to the horizontal injector, a longitudinal fracture is generated, while with the minimum horizontal stress orientation parallel to the injector, a transverse fracture is developed. The impact of static and dynamic transverse/longitudinal fractures on well injectivity and reservoir sweep has been investigated. The impacts of (i) lengths of horizontal injector and producer; (ii) location of water oil contact; (iii) sizes of transverse and longitudinal fractures; (iv) particle concentration in the water, were further investigated. The well injectivity model was validated successfully by history matching injection of water (with particles) and shear rate dependent polymer injection. The history match was performed by adjusting the effective particle concentration in the injected water or the shear rate dependent polymer rheology. Based on history matching the long-term injection rates and pressures, estimates of the fracture length were made. These fracture dimensions could not be independently measured and verified. Based on the simulation results recommendations were made for strategies for drilling well patterns, water quality and injection rates that will lead to better oil recovery. / text

Heavy oil resources are huge and are currently produced largely with steam-driven technology. The purpose of this research was to evaluate an alternative to steam flooding in heavy oils: chemical EOR. Acidic components abundant in heavy crude oils can be converted to soaps at high pH with alkali, reducing the interfacial tension (IFT) between oil and water to ultra-low levels. In an attempt to harness this property, engineers developed alkaline and alkaline-polymer (AP) flooding EOR processes, which met limited success. The primary problem with AP flooding was the soap is usually too hydrophobic, its optimum salinity is low and the ultra-low IFT salinity range narrow (Nelson 1983). Adding a hydrophilic co-surfactant to the process solved the problem, and is known as ASP flooding. AP floods also form persistent, unpredictable and often highly viscous emulsions, which result in high pressure drops and low injection rates. Addition of co-solvents such as a light alcohol (typically 1 wt %) improves the performance of AP floods; researchers at the University of Texas at Austin have coined the term ACP (Alkaline Co-solvent Polymer) for this new process. ACP has significant advantages relative to other chemical flooding modes to recover heavy oils. It is less costly than using surfactant, and has none of the design challenges associated with surfactant. It shows the benefit of nearly 100% displacement sweep efficiency in core floods when properly implemented, as heavy oils tend to produce significant IFT reducing soaps. The use of polymer for mobility control ensures good sweep efficiency is also achieved. Since heavy oils can be extremely viscous at reservoir temperature, moderate reservoir heating to reduce oil viscosity is beneficial. In a series of core flood experiments, moderately elevated temperatures (25-75°C) were used in evaluating ACP flooding in heavy oils. The experiments used only small amounts of inexpensive co-solvents while recovering >90% of remaining heavy oil in a core, without need for any surfactant. The most successful experiments showed that a small increase in temperature (25°) can have very positive impacts on core flood performance. These results are very encouraging for heavy oil recovery with chemical EOR. / text

Surfactant-Polymer (SP) and Alkaline-Surfactant-Polymer (ASP) floods are tertiary oil recovery processes that mobilize residual oil to waterflood. These Chemical EOR processes are most valuable when the residual oil saturation of a target reservoir to waterflood is high. The first steps of designing a SP or ASP flood are performed in a laboratory by developing a surfactant formulation and by performing core flood experiments to assess the performance of the flood to recovery residual oil to waterflood. The two criteria for a technically successful laboratory SP or ASP core flood are recovering greater than 90% of residual oil to waterflood leaving behind less than 5% of residual oil and accomplishing this at a field scalable pressure gradient across the porous medium of approximately 1 psi per foot. This thesis documents the laboratory development of SP and ASP core floods for a continental Unites States oil reservoir reported to contain the minerals anhydrite and gypsum. The significance of these minerals is that they provide an infinite acting source of calcium within the reservoir that makes using the traditional alkali sodium carbonate unfeasible using conventional Chemical EOR methods. This is because sodium carbonate will precipitate as calcite in the presence of free calcium ions. Secondly, this thesis investigates two novel alkalis that are compatible with free calcium ions, sodium acetate and tetrasodium EDTA, for their viability for use in ASP floods for reservoirs containing anhydrite or gypsum. / text

Developing hybrid processes for heavy oil recovery is a major area of interest in recent years. The need for such processes originates from the challenges of heavy oil recovery relating to fluid injectivity, reservoir heating, and oil displacement and production. These challenges are particularly profound in shaley thin oil deposits where steam injection is not feasible and other recovery methods should be employed. In this work, we aim to develop and optimize a hybrid process that involves moderate reservoir heating and chemical enhanced oil recovery (EOR). This process, in its basic form, is a three-stage scheme. The first stage is a short electrical heating, in which the reservoir temperature is raised just enough to create fluid injectivity. After electrical heating has created sufficient fluid injectivity, high-rate high-pressure hot water injection accelerates the raise in temperature of the reservoir and assists oil production. At the end of hot waterflooding the oil viscosities are low enough for an Alkali-Co-solvent-Polymer (ACP) chemical flood to be performed where oil can efficiently be mobilized and displaced at low pressure gradients. A key aspect of ultra-low IFT chemical flood, such as ACP, is the rheology of the microemulsions that form in the reservoir. Undesirable rheology impedes the displacement of the chemical slug in the reservoir and results in poor process performance or even failure. The viscosity of microemulsions can be altered by the addition of co-solvents and branched or twin-tailed co-surfactants and by an increase in temperature. To reveal the underlying mechanisms, a consistent theoretical framework was developed. Employing the membrane theory and electrostatics, the significance of charge and/or composition heterogeneity in the interface membrane and the relevance of each to the above-mentioned alteration methods was demonstrated. It was observed that branched co-surfactants (in mixed surfactant formulations) and temperature only modify the saddle-splay modulus (k ̅) and bending modulus (k) respectively, whereas co-solvent changes both moduli. The observed rheological behavior agrees with our findings. To describe the behavior of microemulsions in flow simulations, a rheological model was developed. A key feature of this model is the treatment of the microemulsion as a bi-network. This provides accuracy and consistency in the calculation of the zero-shear viscosity of a microemulsion regardless of its type and microstructure. Once model parameters are set, the model can be used at any concentration and shear rate. A link between the microemulsion rheological behavior and its microstructure was demonstrated. The bending modulus determines the magnitude of the viscous dissipations and the steady-shear behavior. The new model, additionally, includes components describing the effects of rheology alteration methods. Experimental viscosity data were used to validate the new microemulsion viscosity model. Several ACP corefloods showing the large impact of microemulsion viscosity on process performance were matched using the UTCHEM simulator with the new microemulsion rheology model added to the code. Finally, numerical simulations based on Peace River field data were performed to investigate the performance of the proposed hybrid thermal-chemical process. Key design parameters were identified to be the method of heating, duration of the heating, ACP slug size and composition, polymer drive size, and polymer concentration in the polymer drive. An optimization study was done to demonstrate the economic feasibility of the process. The optimization revealed that short electrical heating and high-rate high-pressure waterflooding are necessary to minimize the energy use and operational expenses. The optimum slug and polymer drive sizes were found to be ~0.25 PV and ~1 PV, respectively. It was shown that the well costs dominate the expenditure and the overall cost of the optimized process is in the range of 20-30 $⁄bbl of incremental oil production. / text

A limited number of laboratory studies and pilot programs have been reported in chemical Enhanced Oil Recovery (EOR) flooding of carbonate reservoirs (Adams & Schievelbein, 1987). Fewer still have involved surfactants in limestone reservoirs. No surfactant/polymer flood on a field wide basis of a carbonate reservoir has ever been documented in the literature (Manrique, Muci, & Gurfinkel, 2010). This void represents a colossal opportunity given that nearly a third of the 32 billion barrels of oil consumed in the world each year come from carbonate reservoirs (Sheng, 2011, pp. 1, 254). This thesis is based on experiments with a high hardness (~5,000 ppm divalent ions) carbonate field. Phase behavior, aqueous stability, and core flood experiments were performed using polymer and various surfactants and co-solvents. Both commercially available and laboratory synthesized surfactants were tested. The objective was to optimize the chemical injection design in order to lower interfacial tension between water and oil in the reservoir. Research was also done with alkali intended for use with hard brines. The main challenges when working with hard brine were poor solubilization and low aqueous stability limits. However, highly propoxylated and ethoxylated surfactants mixed with internal olefin sulfonates, hydrophilic sulfates, and sec-butanol were observed to have very high solubilization ratios, fast phase behavior equilibration times, negligible viscous macroemulsion effects, and excellent aqueous stability. Spinning drop interfacial tensiometer tests confirmed low IFT values were obtained for a range of acceptable salinities with hard brine. Three core floods were performed using one of the surfactant formulations developed. One flood was done with field core, brine, and crude oil and failed to meet expectations because of high levels of heterogeneity (vugs) within the core that lead to an elongated oil bank and low and slow oil recovery. The other floods were done with Estillades Limestone. The first Estillades flood used hard synthetic field brine and had better mobility but poor oil recovery. The last core flood had good mobility and recovered 90% of the residual oil to water flooding, but only after a total of 1.1 pore volumes of 1.0 wt% surfactant solution were injected. The results provided in this thesis constitute proof of concept that S/P flooding can be done in high salinity and hardness reservoirs. / text

Accurate simulation of chemical flooding requires a detailed understanding of numerous complex mechanisms and model parameters where grid size has a substantial impact upon results. In this research we show the effect of grid size on parameters such as phase behavior, interfacial tension, surfactant dilution and salinity gradient for chemical flooding of a very heterogeneous oil reservoir. The effective propagation of the surfactant slug in the reservoir is of paramount importance and the salinity gradient is a key factor in ensuring the process effectiveness. The larger the grid block size, the greater the surfactant dilution, which in turn erroneously reduces the effectiveness of the process indicated with low simulated oil recoveries. We show that the salinity gradient is not adequately captured by coarse grid simulations of heterogeneous reservoirs and this leads to performance predictions with lower recovery compared to fine grid simulations. Due to the highly coupled, nonlinear interactions of the many chemical and physical processes involved in chemical flooding, it is better to use fine-grid simulations rather than coarse grids with upscaled physical properties whenever feasible. However, the upscaling methodology for chemical flooding presented in this work accounts approximately for some of the more important effects, as demonstrated by comparison of fine grid and coarse grid results and is very different than the way other enhanced oil recovery methods are upscaled. This is a step towards making better performance predictions of chemical flooding for large field projects where it is not currently feasible to perform the large number of simulations required to properly consider different designs, optimization, risk and uncertainty using fine-grid simulations. / text

This paper establishes Low-Tension-Gas (LTG) as a method for sub-miscible tertiary recovery in tight sandstone and carbonate reservoirs. The LTG process involves the use of a low foam quality surfactant-gas solution to mobilize and then displace residual crude after waterflood. It replicates the existing Alkali-Surfactant-Polymer (ASP) process in its creation of an ultra-low oil-water interfacial tension (IFT) environment for oil mobilization, but instead supplements the use of foam over polymer for mobility control. By replacing polymer with foam, chemical Enhanced Oil Recovery (EOR) methods can be expanded into sub-30 mD formations where polymer is impractical due to plugging, shear, or the requirement to use a low molecular weight polymer. Overall results indicate favorable mobilization and displacement of residual crude oil in both tight carbonate and tight sandstone reservoirs. Tertiary recovery of 75-95% ROIP was achieved for cores with 2-15 mD permeability, with similar oil bank and other ASP analogous process attributes observed. Moreover, similar recovery was achieved during testing at high initial oil saturation (56%), indicating high process tolerance to oil saturation and potential application for implementation at secondary recovery. In addition, a number of tools and relations were developed to improve the predictive relationship between observed coreflood properties and actual mobilization or displacement mechanisms which impact reservoir-scale flooding. These relations include qualitative dispersion comparison and calculation of in-situ gas saturation, macroscopic mobility ratio at the displacement fronts, and apparent viscosity of injected fluids. These tools were validated through use of reference gas and surfactant floods and indicate that stable macroscopic displacement can be achieved through LTG flooding in tight formations. Furthermore, to better reflect actual reservoir conditions where localized fractional flow of gas can vary substantially depending on mixing or gravity phenomenon, two additional sets of data were developed to empirically model behavior. Through testing of LTG co-injection at a number of discrete fractional flow values over a wide range, recovery was shown to achieve a relative maximum at 50% gas fractional flow which also corresponded with optimal observed mobility control as measured by the previously established tools. Likewise, through testing of surfactant-alternating-gas (SAG) injection cycling, displacement and overall recovery were shown to be improved versus reference co-injection flooding. Finally, by comparing the observed displacement and mobility data among co-injection and surfactant-alternating-gas floods, a new displacement mechanism is introduced to better relate actual displacement conditions with observed macroscopic mobility data. This mechanism emphasizes the role of liquid rate in actual displacement processes and a mostly static gas saturation (independent of gas rate) in altering liquid relative permeability and diverting injected liquid into lower permeability zones. / text

[pt] Os métodos de recuperação terciária ou avançada de petróleo (EOR) permitem fatores de recuperação de até 70 por cento. A injeção de surfactantes aniônicos, amplamente empregados em EOR químico, pode se tornar inviável devido às perdas após precipitação, difusão para o interior de poros sem conectividade e especialmente adsorção sobre a superfície da rocha reservatório. Este trabalho almejou modificar a superfície de nanopartículas de sílica com alcoxisilanos para que possam ser utilizadas como nanocarreadores de surfactantes aniônicos em EOR químico, diminuindo desta forma as perdas por adsorção. Técnicas de caracterização foram empregadas para confirmar a modificação ocorrida na superfície da sílica, obtendo-se graus de modificação estimados entre 11 e 14 por cento. A inserção de grupos alquila (C8 e C16) na superfície da sílica aumentou significativamente a interação com o surfactante aniônico (dodecil sulfato de sódio, SDS), em comparação com as nanopartículas sem modificação, ampliando em até 11x a quantidade de surfactante retido na superfície das nanopartículas. Os nanomateriais híbridos obtidos possuem maior capacidade de manter adsorvido o tensoativo em soluções aquosas e salinas, bem como liberá-lo quando na interface salmoura/óleo. Ao fim, as nanopartículas de sílica modificadas contendo surfactante adsorvido na sua superfície atuaram sinergicamente na redução da tensão interfacial, sem afetar o desempenho do surfactante após liberação na interface água/óleo. Sendo assim, as nanopartículas modificadas com alcoxisilanos obtidas neste trabalho podem atuar como nanocarreadores de surfactantes em fluidos de injeção para EOR químico. / [en] The tertiary oil recovery methods or enhanced oi recovery (EOR) allow a recovery factor up to 70 percent. The injection of anionic surfactants, widely used in chemical EOR, could become unfeasible due to losses after precipitation, diffusion to the interior of non-connected pores and specially adsorption over reservoir rock surface. This work aimed to modify the surface of silica nanoparticles with alkoxysilanes in order to be used as surfactant nanocarriers in chemical EOR, reducing surfactant loss by adsorption. Characterization techniques were employed to confirm the modifications on silica surface, obtaining degrees of modification between 11 and 14 percent. The attachment of alkyl groups (C8 and C16) on the silica surface raised significantly the interaction with an anionic surfactant (sodium dodecyl sulfate, SDS), in comparison to bare silica nanoparticles, increasing up to 11x the amount of adsorbed surfactant over silica s surface. The hybrid nanomaterials obtained in this work have a high capacity to keep the tensoactive in aqueous solutions and brine, as well as releasing it at the brine/oil interface. Finally, the modified silica nanoparticles containing surfactant adsorbed on their surface showed a synergy in reducing interfacial tension, without affecting the surfactant performance after the release at the water/oil interface. Thus, the nanoparticles modified with alkoxysilanes obtained in this work can act as surfactant nanocarriers in injection fluids for chemical EOR.

Hybrid gas/chemical Enhanced Oil Recovery (EOR) methods are such novel techniques to increase oil production and oil recovery efficiency. Gas flooding using carbon dioxide, nitrogen, flue gas, and enriched natural gas produce more oil from the reservoirs by channeling gas into previously by-passed areas. Surfactant flooding can recover trapped oil by reducing the interfacial tension between oil and water phases. Hybrid gas/chemical EOR methods benefit from using both chemical and gas flooding. In hybrid gas/chemical EOR processes, surfactant solution is injected with gas during low-tension-gas or foam flooding. Polymer solution can also be injected alternatively with gas to improve the gas volumetric sweep efficiency. Most fundamentally, wide applications of hybrid gas/chemical processes are limited due to uncertainties in reservoir characterization and heterogeneity, due to the lack of understanding of the process and consequently lack of a predictive reservoir simulator to mechanistically model the process. Without a reliable simulator, built on mechanisms determined in the laboratory, promising field candidates cannot be identified in advance nor can process performance be optimized. In this research, UTCHEM was modified to model four-phase water, oil, microemulsion, and gas phases to simulate and interpret chemical EOR processes including free and/or solution gas. We coupled the black-oil model for water/oil/gas equilibrium with microemulsion phase behavior model through a new approach. Four-phase fluid properties, relative permeability, and capillary pressure were developed and implemented. The mass conservation equation was solved for total volumetric concentration of each component at standard conditions and pressure equation was derived for both saturated and undersaturated PVT conditions. To model foam flow in porous media, comprehensive research was performed comparing capabilities and limitations of implicit texture (IT) and population-balance (PB) foam models. Dimensionless foam bubble density was defined in IT models to derive explicitly the foam-coalescence-rate function in these models. Results showed that each of the IT models examined was equivalent to the LE formulation of a population-balance model with a lamella-destruction function that increased abruptly in the vicinity of the limiting capillary pressure, as in current population-balance models. Foam models were incorporated in UTCHEM to model low-tension-gas and foam flow processes in laboratory and field scales. The modified UTCEM reservoir simulator was used to history match published low-tension-gas and foam coreflood experiments. The simulations were also extended to model and evaluate hybrid gas/chemical EOR methods in field scales. Simulation results indicated a well-designed low-tension-gas flooding has the potential to recover the trapped oil where foam provides mobility control during surfactant and surfactant-alkaline flooding in reservoirs with very low permeability. / text

Chemical EOR processes such as polymer flooding and surfactant polymer flooding must be designed and implemented in an economically attractive manner to be perceived as viable oil recovery options. The primary expenses associated with these processes are chemical costs which are predominantly controlled by the crude oil properties of a reservoir. Crude oil viscosity dictates polymer concentration requirements for mobility control and can also negatively affect the rheological properties of a microemulsion when surfactant polymer flooding. High microemulsion viscosity can be reduced with the introduction of an alcohol co-solvent into the surfactant formulation, but this increases the cost of the formulation. Experimental research done as part of this study combined the process of hot water injection with ASP flooding as a solution to reduce both crude oil viscosity and microemulsion viscosity. The results of this investigation revealed that when action was taken to reduce microemulsion viscosity, residual oil recoveries were greater than 90%. Hot water flooding lowered required polymer concentrations by reducing oil viscosity and lowered microemulsion viscosity without co-solvent. Laboratory testing of viscous microemulsions in core floods proved to compromise surfactant performance and oil recovery by causing high surfactant retention, high pressure gradients that would be unsustainable in the field, high required polymer concentrations to maintain favorable mobility during chemical flooding, reduced sweep efficiency and stagnation of microemulsions due to high viscosity from flowing at low shear rates. Rough scale-up chemical cost estimations were performed using core flood performance data. Without reducing microemulsion viscosity, field chemical costs were as high as 26.15 dollars per incremental barrel of oil. The introduction of co-solvent reduced chemical costs to as low as 22.01 dollars per incremental barrel of oil. This reduction in cost is the combined result of increasing residual oil recovery and the added cost of an alcohol co-solvent. Heating the reservoir by hot water flooding resulted in combined chemical and heating costs of 13.94 dollars per incremental barrel of oil. The significant drop in cost when using hot water is due to increased residual oil recovery, reduction in polymer concentrations from reduced oil viscosity and reduction of microemulsion viscosity at a fraction of the cost of co-solvent. / text