The first goal of this research was to develop and experimentally test new and improved chemical formulations for enhanced oil recovery using a new class of branched large-hydrophobe alkoxy carboxylate surfactants mixed with novel co-surfactants and co-solvents to both lower IFT and alter wettability at high temperatures and high salinities. These novel alkoxy carboxylate surfactants with large branched hydrophobes were tested and found to show excellent performance in corefloods over a wide range of reservoir conditions up to at least 120°C. The number of PO and EO groups in these new surfactants were optimized for a wide variety of oils over a broad range of salinity, hardness and temperature and mixed with various co-surfactants and co-solvents to develop high-performance formulations based on the microemulsion phase behavior. Both ultra-low IFT and clear aqueous solutions at optimum salinity were obtained for both active and inactive oils and both light and medium gravity oils over a wide range of temperatures. Both sandstone and carbonate corefloods using these carboxylate surfactants showed excellent performance at high temperature, high hardness and high salinity as indicated by high oil recovery, low pressure gradients and low surfactant retention. The advent of such a new class of cost-effective surfactants significantly broadens the potential application of chemical enhanced oil recovery processes using surfactants under harsh reservoir conditions. The second goal of this research was to evaluate the effect of buoyancy on oil recovery from cores using ultra-low IFT surfactant formulations under conditions where the use of polymer for mobility control is either difficult or unnecessary, determine the conditions that are favorable for a gravity-stable surfactant flood, and further improve the performance of gravity-stable surfactant floods by optimizing the microemulsion properties, especially its viscosity. The microemulsion viscosity can be varied by adjusting the structure of the surfactants and co-solvents and their concentrations. Predictions made using classical stability theory applied to surfactant flooding experiments were determined to be inaccurate because such theory does not take into account the microemulsion phase that forms in-situ when surfactant mixes with the oil. The modification of the classical theory to account for the effect of the microemulsion on the critical velocity for a stable displacement is one of the major contributions of this research. New experiments were done to test the modified theory and it was found to be in good agreement with these experiments. Furthermore, a new method to increase the stable velocity by optimizing the microemulsion viscosity was proposed and validated by a series of coreflood experiments designed and conducted for that specific purpose. / text

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

Surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) flooding has gained little traction among different tertiary recovery strategies such as thermal and miscible gas flooding; however, many mature onshore reservoirs could be potential candidates. More than four decades of research has detailed technical challenges and successes through laboratory experimentation, chemical flood simulation, and some pilot projects, which have provided technical screening procedures to efficiently filter unfeasible projects. Therefore, technical understanding seems sufficient to advance projects through early development stages; however, a project value identification and realization process ultimately dictates project implementation in the oil and gas industry, with technical feasibility merely supporting overall valuation and project feasibility. A quick early screening methodology integrating important project valuation criteria can efficiently assess large numbers of projects. The relatively few studies detailing chemical flooding valuation from just an economic standpoint reflects the need for an integrated process-oriented framework for quick early screening valuation of chemical flooding opportunities. This study develops an integrated process-oriented framework for early screening and valuation, with an overall objective to quickly filter unfeasible projects based on valuation criteria, rather than technical feasibility alone. A reservoir-to-market model was developed, integrating information from laboratory experiments (phase behavior, core flood), field analogues (well performance and layout), facilities, rigs, costs, scheduling, and economics. Recently published ASP flood data of the central Xing2 area in Daqing, China was used for model inputs. A reservoir-to-market benchmark model for a typical mature onshore field was successfully built and tested, and could value projects using standard economic metrics (net present value, internal rate of return, value investment ratio, unit technical cost, and payback period). Model simplification was achieved through global sensitivity analysis. Using a mean-reversion oil price model, the oil price accounted for 98% of the total sensitivity. . Model efficiency was achieved through discretization of input parameter uncertainties, which sped the screening process. Decision-making between model alternatives given information and different states of nature was performed through decision-tree techniques based on overall project valuation. Overall, this study was novel and provided benefit as a robust, integrated process-oriented framework for chemical EOR project screening, valuation, and decision-making. / 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

Surfactant related recovery processes are of increasing interest and importance because of high oil prices and the urge to meet energy demand. High oil prices and the accompanying revival of EOR operations have provided academia and industry with great opportunities to test alkaline surfactant polymer (ASP) methods on a field scale and to develop novel surfactant systems that can improve the performance of such EOR processes. This dissertation intends to discuss both opportunities through two unique projects, the development of novel surfactants for EOR applications and the design for an alkaline/surfactant/polymer (ASP) field pilot. In Section I of this dissertation, a novel series of anionic Gemini surfactants are carefully synthesized and systematically investigated. The remarkable abilities of Gemini surfactants to influence oil-water interfaces and aqueous solution properties are fully demonstrated. These surfactants are shown to have great potential for application in EOR processes. A wide range of Gemini structures (C₁₄ to C₂₄ chain length, -C2- and -C4- spacers, sulfate and carboxylate head groups) was synthesized and shown to have high aqueous solubility, with Krafft points below 20°C. The critical micelle concentrations (CMC) for these new molecules are measured to be orders of magnitude lower than their conventional counterparts. The significantly more negative Gibbs free energy for Gemini surfactant drives the micellization process and results in ultralow CMC. An adsorption study of Gemini surfactants at air-water and solid-water interfaces shows their superior surface activity from tighter molecular packing, and attractive characteristics of low adsorption loss at the solid surface. All anionic Gemini surfactants synthesized have an extraordinary tolerance to salinity and/or hardness. No phase separation or precipitation occurs in the aqueous stability tests, even in the presence of extremely high concentrations of mono- and/or di-valent ions. Moreover, ultra-low IFT values are reached under these conditions for Type I microemulsion systems, at very low surfactant concentrations. The stronger molecular interaction between the Gemini and conventional surfactants offers synergy that promotes aqueous stability and interfacial activity. Gemini molecules with short spacers are capable of giving rise to high viscosities at fairly low concentrations. The rheological behavior can be explained by changes in the micellar structure. A molecular thermodynamic model is developed to study anionic Gemini surfactants aggregation behavior in solution. The model takes into account of the head group-counter-ion binding effect and utilizes two simplified solutions to the Poisson-Boltzmann equation. It properly predicts the CMC of the surfactants synthesized and can be easily expanded to investigate other factors of interest in the micellization process. Section II of this dissertation studies chemical formulation design and implementation for an oilfield where an alkaline/surfactant/polymer (ASP) pilot is being carried out. A four-step systematic design approach, composed of a) process and material selection; b) formulation optimization; c) coreflood validation; 4) lab-scale simulation, was successfully implemented and could be easily transferred to other EOR projects. The optimal chemical formulation recovered over 90% residual oil from Berea coreflood. Lab-scale simulation model accurately history matches the coreflood experiment and sets the foundation for pilot-scale numerical study. Different operating strategies are investigated using a pilot-scale model, as well as the sensitivities of project economics to various design parameters. A field execution plan is proposed based on the results of the simulation study. A surface facility conceptual design is put together based on the practical needs and conditions in the field. Key lessons learned throughout the project are summarized and are invaluable for planning and designing future pilot floods. / 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