Browsing by Subject "Surfactant"
Now showing 1 - 20 of 32
Results Per Page
Sort Options
Item A Study of Microfluidic Reconfiguration Mechanisms Enabled by Functionalized Dispersions of Colloidal Material for Radio Frequency Applications(2010-07-14) Goldberger, Sean A.Communication and reconnaissance systems are requiring increasing flexibility concerning functionality and efficiency for multiband and broadband frequency applications. Circuit-based reconfiguration mechanisms continue to promote radio frequency (RF) application flexibility; however, increasing limitations have resulted in hindering performance. Therefore, the implementation of a "wireless" reconfiguration mechanism provides the required agility and amicability for microwave circuits and antennas without local overhead. The wireless reconfiguration mechanism in this thesis integrates dynamic, fluidic-based material systems to achieve electromagnetic agility and reduce the need for "wired" reconfiguration technologies. The dynamic material system component has become known as electromagnetically functionalized colloidal dispersions (EFCDs). In a microfluidic reconfiguration system, they provide electromagnetic agility by altering the colloidal volume fraction of EFCDs - their name highlights the special considerations we give to material systems in applied electromagnetics towards lowering loss and reducing system complexity. Utilizing EFCDs at the RF device-level produced the first circuit-type integration of this reconfiguration system; this is identified as the coaxial stub microfluidic impedance transformer (COSMIX). The COSMIX is a small hollowed segment of transmission line with results showing a full reactive loop (capacitive to inductive tuning) around the Smith chart over a 1.2 GHz bandwidth. A second microfluidic application demonstrates a novel antenna reconfiguration mechanism for a 3 GHz microstrip patch antenna. Results showed a 300 MHz downward frequency shift by dielectric colloidal dispersions. Magnetic material produced a 40 MHz frequency shift. The final application demonstrates the dynamically altering microfluidic system for a 3 GHz 1x2 array of linearly polarized microstrip patch antennas. The parallel microfluidic capillaries were imbedded in polydimethylsiloxane (PDMS). Both E- and H-plane designs showed a 250 MHz frequency shift by dielectric colloidal dispersions. Results showed a strong correlation between decreasing electrical length of the elements and an increase of the volume fraction, causing frequency to decrease and mutual coupling to increase. Measured, modeled, and analytical results for impedance, voltage standing wave ratio (VSWR), and radiation behavior (where applicable) are provided.Item Accounting for reservoir uncertainties in the design and optimization of chemical flooding processes(2012-08) Rodrigues, Neil; Delshad, Mojdeh; Pope, Gary A.Chemical Enhanced Oil Recovery methods have been growing in popularity as a result of the depletion of conventional oil reservoirs and high oil prices. These processes are significantly more complex when compared to waterflooding and require detailed engineering design before field-scale implementation. Coreflood experiments that have been performed on reservoir rock are invaluable for obtaining parameters that can be used for field-scale flooding simulations. However, the design used in these floods may not always scale to the field due to heterogeneities, chemical retention, mixing and dispersion effects. Reservoir simulators can be used to identify an optimum design that accounts for these effects but uncertainties in reservoir properties can still cause poor project results if it not properly accounted for. Different reservoirs will be investigated in this study, including more unconventional applications of chemical flooding such as a 3md high-temperature, carbonate reservoir and a heterogeneous sandstone reservoir with very high initial oil saturation. The goal of the research presented here is to investigate the impact that select reservoir uncertainties can have on the success of the pilot and to propose methods to reduce the sensitivity to these parameters. This research highlights the importance of good mobility control in all the case studies, which is shown to have a significant impact on the economics of the project. It was also demonstrated that a slug design with good mobility control is less sensitive to uncertainties in the relative permeability parameters. The research also demonstrates that for a low-permeability reservoir, surfactant propagation can have a significant impact on the economics of a Surfactant-Polymer Flood. In addition to mobilizing residual oil and increasing oil recovery, the surfactant enhances the relative permeability and this has a significant impact on increasing the injectivity and reducing the project life. Injecting a high concentration of surfactant also makes the design less sensitive to uncertainties in adsorption. Finally, it was demonstrated that for a heterogeneous reservoir with high initial oil saturation, optimizing the salinity gradient will significantly increase the oil recovery and will also make the process less sensitive to uncertainties in the cation exchange capacity.Item Characterization of an alkyl diamine surfactant for gas mobility control in gas enhanced oil recovery and conformance control(2016-05) Liebum, Madalyn Marie; Nguyen, Quoc P.; DiCarlo, DavidThe objective of this research is to characterize the properties and performance of an amine-based “switchable” surfactant, Duomeen TTM, at various environmental conditions. In particular, bulk characterization measurements namely, aqueous stability, solubility, partition, and rheological behavior were tested and applied in core flooding experiments using carbonate rock saturated in very saline brine. Aqueous stability provides insight about how Duomeen TTM solutions tolerate with changes in salt concentration, pH, and temperature. This surfactant becomes more hydrophilic as pH decreases and transforms into a viscoelastic solution at moderate to high salt concentrations. This viscoelasticity is intensified by changes in pH, temperature, and surfactant concentration of the solution, where surfactant concentration limits the aggregation density of the solution, pH influences the protonation process in the head group, and temperature controls the minimization of free energy by breaking, reformation, and branching of micellar networks. Furthermore, solubility measurements were conducted for a series of pressures and temperatures in pure CO2 as well as in gas mixtures composed of CO2 and CH4. It is shown that Duomeen TTM is very soluble in CO2, but becomes less soluble when methane is present in the system. Partition experiments amongst brine and CO2 reveal Duomeen TTM is very water soluble at low pH, in agreement with the aqueous stability results. Finally, these bulk characterization results were applied in core flooding experiments where in-situ viscoelasticity or gel development capabilities were tested with surfactant dissolved in solution at different salinities. In-situ viscosification is mainly dependent on the salinity contrast between the injective solution and resident brine as well as the rheological behavior of the surfactant solution at different salinities. This in-situ gel development provides mobility control by blocking thief zones and high permeable regions in porous media. In all, this ability to viscosify in-situ makes Duomeen TTM applicable for near-wellbore conformance control and CO2 mobility control in CO2 enhanced oil recovery.Item Development and application of a 3D equation-of-state compositional fluid-flow simulator in cylindrical coordinates for near-wellbore phenomena(2011-12) Abdollah Pour, Roohollah; Torres-Verdín, Carlos; Sepehrnoori, Kamy, 1951-; Delshad, Mojdeh; Demkowicz, Leszek; Johns, Russell T.Well logs and formation testers are routinely used for detection and quantification of hydrocarbon reserves. Overbalanced drilling causes invasion of mud filtrate into permeable rocks, hence radial displacement of in-situ saturating fluids away from the wellbore. The spatial distribution of fluids in the near-wellbore region remains affected by a multitude of petrophysical and fluid factors originating from the process of mud-filtrate invasion. Consequently, depending on the type of drilling mud (e.g. water- and oil-base muds) and the influence of mud filtrate, well logs and formation-tester measurements are sensitive to a combination of in-situ (original) fluids and mud filtrate in addition to petrophysical properties of the invaded formations. This behavior can often impair the reliable assessment of hydrocarbon saturation and formation storage/mobility. The effect of mud-filtrate invasion on well logs and formation-tester measurements acquired in vertical wells has been extensively documented in the past. Much work is still needed to understand and quantify the influence of mud-filtrate invasion on well logs acquired in horizontal and deviated wells, where the spatial distribution of fluids in the near-wellbore region is not axial-symmetric in general, and can be appreciably affected by gravity segregation, permeability anisotropy, capillary pressure, and flow barriers. This dissertation develops a general algorithm to simulate the process of mud-filtrate invasion in vertical and deviated wells for drilling conditions that involve water- and oil-base mud. The algorithm is formulated in cylindrical coordinates to take advantage of the geometrical embedding imposed by the wellbore in the spatial distribution of fluids within invaded formations. In addition, the algorithm reproduces the formation of mudcake due to invasion in permeable formations and allows the simulation of pressure and fractional flow-rate measurements acquired with dual-packer and point-probe formation testers after the onset of invasion. An equation-of-state (EOS) formulation is invoked to simulate invasion with both water- and oil-base muds into rock formations saturated with water, oil, gas, or stable combinations of the three fluids. The algorithm also allows the simulation of physical dispersion, fluid miscibility, and wettability alteration. Discretized fluid flow equations are solved with an implicit pressure and explicit concentration (IMPEC) scheme. Thermodynamic equilibrium and mass balance, together with volume constraint equations govern the time-space evolution of molar and fluid-phase concentrations. Calculations of pressure-volume-temperature (PVT) properties of the hydrocarbon phase are performed with Peng-Robinson's equation of state. A full-tensor permeability formulation is implemented with mass balance equations to accurately model fluid flow behavior in horizontal and deviated wells. The simulator is rigorously and successfully verified with both analytical solutions and commercial simulators. Numerical simulations performed over a wide range of fluid and petrophysical conditions confirm the strong influence that well deviation angle can have on the spatial distribution of fluid saturation resulting from invasion, especially in the vicinity of flow barriers. Analysis on the effect of physical dispersion on the radial distribution of salt concentration shows that electrical resistivity logs could be greatly affected by salt dispersivity when the invading fluid has lower salinity than in-situ water. The effect of emulsifiers and oil-wetting agents present in oil-base mud was studied to quantify wettability alteration and changes in residual water saturation. It was found that wettability alteration releases a fraction of otherwise irreducible water during invasion and this causes electrical resistivity logs to exhibit an abnormal trend from shallow- to deep-sensing apparent resistivity. Simulation of formation-tester measurements acquired in deviated wells indicates that (i) invasion increases the pressure drop during both drawdown and buildup regimes, (ii) bed-boundary effects increase as the wellbore deviation angle increases, and (iii) a probe facing upward around the perimeter of the wellbore achieves the fastest fluid clean-up when the density of invading fluid is larger than that of in-situ fluid.Item Development of a chemical treatment for condensate blocking in tight gas sandstone(2011-05) McCulley, Corey Alan; Pope, Gary A.; Sharma, Mukul M.Gas wells suffer a decrease in productivity because of the formation of a liquid hydrocarbon “condensate” in the near wellbore area. This "condensate" forms near producing wells when the flowing pressure is below the reservoir fluid's dew point. Several methods have been shown to temporarily alleviate this problem, but eventually the condensate bank reforms and the productivity again decreases. The use of surfactants to alter the near wellbore wettability to neutral wetting is a potential longer term solution to liquid blocking in these reservoirs. This alteration increases the gas and liquid relative permeabilities and thereby the productivity by reducing the residual liquid saturation. This enhancement allows the accumulated liquid to flow and is durable as long as the wettability alteration is persistent. This solution has been shown to be successful through core flood experiments and field trials in high permeability sandstones, but no improvements had been observed in low permeability cores. As the global demand for energy increases, the petroleum industry has begun to develop unconventional (low permeability) assets, new techniques are needed to maintain and improve their productivity. Liquid blocking in these wells can have a much larger impact on both the gas and condensate production in such low permeability formations. Applying this technique increases both gas and condensate mobility and should increase the economic producing life of these wells. Core flood experiments were conducted to investigate the ability of a chemical treatment to alter the wettability of low permeability sandstones. Previous experimentation did not find any improvement because the increased capillary forces prevented the treatment solution from being easily displaced. This concealed the benefit achieved when the wettability was altered. These experiments recorded smaller relative permeability increases compared to higher permeability core floods, so super critical carbon dioxide was tested as an alternative solvent. While the new treatment was more injectable, it was not as successful at altering wettability. Progress has been made on a solution to liquid blocking in low permeability sandstones, but additional research needs to be completed to further optimize this method.Item Development of a four-phase flow simulator to model hybrid gas/chemical EOR processes(2015-05) Lotfollahi Sohi, Mohammad; Pope, Gary A.; Delshad, Mojdeh; Sepehrnoori, Kamy; Mohanty , Kishore K; Johnston, Keith PHybrid 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.Item Development of a four-phase thermal-chemical reservoir simulator for heavy oil(2014-12) Lashgari, Hamid Reza; Sepehrnoori, Kamy, 1951-Thermal and chemical recovery processes are important EOR methods used often by the oil and gas industry to improve recovery of heavy oil and high viscous oil reservoirs. Knowledge of underlying mechanisms and their modeling in numerical simulation are crucial for a comprehensive study as well as for an evaluation of field treatment. EOS-compositional, thermal, and blackoil reservoir simulators can handle gas (or steam)/oil/water equilibrium for a compressible multiphase flow. Also, a few three-phase chemical flooding reservoir simulators that have been recently developed can model the oil/water/microemulsion equilibrium state. However, an accurate phase behavior and fluid flow formulations are absent in the literature for the thermal chemical processes to capture four-phase equilibrium. On the other hand, numerical simulation of such four-phase model with complex phase behavior in the equilibrium condition between coexisting phases (oil/water/microemulsion/gas or steam) is challenging. Inter-phase mass transfer between coexisting phases and adsorption of components on rock should properly be modeled at the different pressure and temperature to conserve volume balance (e.g. vaporization), mass balance (e.g. condensation), and energy balance (e.g. latent heat). Therefore, efforts to study and understand the performance of these EOR processes using numerical simulation treatments are quite necessary and of utmost importance in the petroleum industry. This research focuses on the development of a robust four-phase reservoir simulator with coupled phase behaviors and modeling of different mechanisms pertaining to thermal and chemical recovery methods. Development and implementation of a four-phase thermal-chemical reservoir simulator is quite important in the study as well as the evaluation of an individual or hybrid EOR methods. In this dissertation, a mathematical formulation of multi (pseudo) component, four-phase fluid flow in porous media is developed for mass conservation equation. Subsequently, a new volume balance equation is obtained for pressure of compressible real mixtures. Hence, the pressure equation is derived by extending a black oil model to a pseudo-compositional model for a wide range of components (water, oil, surfactant, polymer, anion, cation, alcohol, and gas). Mass balance equations are then solved for each component in order to compute volumetric concentrations. In this formulation, we consider interphase mass transfer between oil and gas (steam and water) as well as microemulsion and gas (microemulsion and steam). These formulations are derived at reservoir conditions. These new formulations are a set of coupled, nonlinear partial differential equations. The equations are approximated by finite difference methods implemented in a chemical flooding reservoir simulator (UTCHEM), which was a three-phase slightly compressible simulator, using an implicit pressure and an explicit concentration method. In our flow model, a comprehensive phase behavior is required for considering interphase mass transfer and phase tracking. Therefore, a four-phase behavior model is developed for gas (or steam)/ oil/water /microemulsion coexisting at equilibrium. This model represents coupling of the solution gas or steam table methods with Hand’s rule. Hand’s rule is used to capture the equilibrium between surfactant, oil, and water components as a function of salinity and concentrations for oil/water/microemulsion phases. Therefore, interphase mass transfer between gas/oil or steam/water in the presence of the microemulsion phase and the equilibrium between phases are calculated accurately. In this research, the conservation of energy equation is derived from the first law of thermodynamics based on a few assumptions and simplifications for a four-phase fluid flow model. This energy balance equation considers latent heat effect in solving for temperature due to phase change between water and steam. Accordingly, this equation is linearized and then a sequential implicit scheme is used for calculation of temperature. We also implemented the electrical Joule-heating process, where a heavy oil reservoir is heated in-situ by dissipation of electrical energy to reduce the viscosity of oil. In order to model the electrical Joule-heating in the presence of a four-phase fluid flow, Maxwell classical electromagnetism equations are used in this development. The equations are simplified and assumed for low frequency electric field to obtain the conservation of electrical current equation and the Ohm's law. The conservation of electrical current and the Ohm's law are implemented using a finite difference method in a four-phase chemical flooding reservoir simulator (UTCHEM). The Joule heating rate due to dissipation of electrical energy is calculated and added to the energy equation as a source term. Finally, we applied the developed model for solving different case studies. Our simulation results reveal that our models can accurately and successfully model the hybrid thermal chemical processes in comparison to existing models and simulators.Item Development of ASP formulations for reactive crude oil in high clay, high temperature reservoirs(2012-08) Tipley, Kyle Andrew; Pope, Gary A.; Weerasooriya, Upali P.Surfactant formulations consisting of surfactant, alkali, polymer, and electrolyte have been developed using well defined screening processes established through experimentation in labs around the world. Due to recent advances in chemical enhanced oil recovery, surfactants can be used to extend the life of mature reservoirs with increasingly diverse conditions. High temperatures, complex geochemistry, or high clay content can provide significant challenges when developing formulations for chemical flooding. Through careful selection and screening of surfactants and chemicals, oil recovery of greater than 90% can be achieved in laboratory corefloods despite these difficulties. The objective of this research was to determine the ideal surfactant formulation using a sulfate surfactant for a reservoir with high clay content at 85 ºC. Advances in our laboratory have shown sulfate surfactants to be stable under specific conditions at elevated temperature. In addition, new methods of synthesizing surfactants have yielded a vast array of structures and iterations of novel surfactants to test for EOR applicability. Experiments contained within include surfactant screening both with and without the presence of crude oil and evaluation of polymer and microemulsion viscosity. From these results, a series of corefloods were performed in Berea and reservoir corefloods that yielded oil recovery of 90% and above with low surfactant retention.Item Development of improved ASP formulations for reactive and non-reactive crude oils(2010-12) Yang, Hyun Tae; Huh, Chun; Pope, Gary A.; Weerasooriya, UpaliThe ability to select low-cost, high-performance surfactants for a wide range of crude oils under a wide range of reservoir conditions has improved dramatically in recent years. Surfactant formulations (surfactant, co-surfactant, co-solvent, alkali, polymer, and electrolyte) were developed by using a refined phase behavior approach. Such formulations nearly always result in more than 90% oil recovery in core flood when good surfactants with good mobility control are used. The advances that have improved performance, reduced cost, increased robustness, and extended the range of reservoir conditions for these formulations are described in this work. There are thousands of possible combinations of the chemicals that could be tested for each oil and each chemical combination requires many observations over a long time period at reservoir temperature for proper evaluation. It would take too long, cost too much and in many cases not even be feasible to test all combinations. In practice the scientific understanding is used to match up the surfactant/co-surfactant/co-solvent characteristics with the oil characteristics, temperature, salinity, hardness and so forth. Synthesized and new surfactants with much larger hydrophobes and more branching than previously available were tested. New classes of co-solvents and co-surfactants with superior performance were test to improve aqueous solubility. These new developments resulted in improved ASP formulations for both oils that react with alkali to make soap and oils that do not. Many of these developments are synergistic and taken together represent a breakthrough in reducing the cost of chemical flooding and thus its commercial potential.Item Development of novel surfactants and surfactant methods for chemical enhanced oil recovery(2014-08) Lu, Jun, active 21st century; Pope, G. A.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.Item Direct Numerical Simulations of Interfacial Turbulence at Low Froude and Weber Numbers(2014-05-22) Zhang, QiSea surface temperature accessible through use of remote sensing techniques (IR imaging, etc.) suggests abundant flow and thermal field information at the ocean surface that is closely related to subsurface turbulent activities. The suggested information includes wind stress, surface dissipation, underneath velocity and vorticity, and heat and gas transportation. Due to the constantly outgoing interfacial latent and sensible heat flux, the very surface of the ocean is often cooler than the bulk. This so called ?cool skin layer? below the very surface is greatly involved in the underlying interfacial turbulence and is the primary support of using sea surface temperature imaging to detect the subsurface activities. In addition, studies have shown that for this detection method the effects of ubiquitous surfactants (surface free agents) to the subsurface turbulence should also be considered. In the case when the wind stress at the surface is far less significant than the buoyancy force in the water phase, the cool skin layer accumulates and triggers free convection. A series of numerical simulations is conducted to reproduce such a free convection flow to obtain detailed statistics and structural features in order to investigate the correlation between the surface temperature and the subsurface activities of the flow. The simulations are also aimed at the quantitative evaluation of the surfactant effects on the flow. The results of the simulations demonstrate that the surface temperature is statistically and structurally correlated to the subsurface activities in various patterns, and that surfactant has a certain influence to the subsurface turbulence with an overall effect of reducing the average surface temperature. Based upon the framework of the controlled flux method, a novel approach to actively determine the interfacial gas transfer velocity at the free convection surface is proposed and numerically investigated. The proposed and simulated approach employs a temporal volumetric heating source to suppress the free convection. The heating source is defined and parameterized with respect to the physical properties of radiation absorption in water phase. Observation and interpretation of the surface temperature evolution and the flow features during and after the heating suggest the effective suppression of the free convection, the onset of the Rayleigh instability and the re-establishment of the free convection. Based on that, an analytical conduction model is formulated to obtain the heat transfer velocity at the free surface from the surface temperature. The gas transfer velocity is then inferred through similarity.Item An experimental and simulation study of the effect of geochemical reactions on chemical flooding(2010-12) Chandrasekar, Vikram, 1984-; Delshad, Mojdeh; Pope, Gary A.The overall objective of this research was to gain an insight into the challenges encountered during chemical flooding under high hardness conditions. Different aspects of this problem were studied using a combination of laboratory experiments and simulation studies. Chemical Flooding is an important Enhanced Oil Recovery process. One of the major components of the operational expenses of any chemical flooding project, especially Alkali Surfactant Polymer (ASP) flooding is the cost of softening the injection brine to prevent the precipitation of the carbonates of the calcium and magnesium ions which are invariably present in the formation brine. Novel hardness tolerant alkalis like sodium metaborate have been shown to perform well with brines of high salinity and hardness, thereby eliminating the need to soften the injection brine. The first part of this research was aimed at designing an optimal chemical flooding formulation for a reservoir having hard formation brine. Sodium metaborate was used as the alkali in the formulation with the hard brine. Under the experimental conditions, sodium metaborate was found to be inadequate in preventing precipitation in the ASP slug. Factors affecting the ability of sodium metaborate to sequester divalent ions, including its potential limitations under the experimental conditions were studied. The second part of this research studied the factors affecting the ability of novel alkali and chelating agents like sodium metaborate and tetrasodium EDTA to sequester divalent ions. Recent studies have shown that both these chemicals showed good performance in sequestering divalent ions under high hardness conditions. A study of the geochemical species in solution under different conditions was done using the computer program PHREEQC. Sensitivity studies about the effect of the presence of different solution species on the performance of these alkalis were done. The third part of this research focused on field scale mechanistic simulation studies of geochemical scaling during ASP flooding. This is one of the major challenges faced by the oil and gas industry and has been found to occur when sodium carbonate is used as the alkali and the formation brine present in situ has a sufficiently high hardness content. The multicomponent and multiphase compositional chemical flooding simulator, UTCHEM was used to determine the quantity and composition of the scales formed in the reservoir as well as the injection and production wells. Reactions occurring between the injected fluids, in situ fluids and the reservoir rocks were taken into consideration for this study. Sensitivity studies of the effect of key reservoir and process parameters like the physical dispersion and the alkali concentration on the extent of scaling were also done as a part of this study.Item Experimental development of a chemical flood and the geochemistry of novel alkalis(2012-08) Winters, Matthew Howard; Pope, Gary A.; Weerasoriya, UpaliSurfactant-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.Item Experimental investigation of the effect of increasing the temperature on ASP flooding(2011-12) Walker, Dustin Luke; Pope, Gary A.; Weerasooriya, UpaliChemical 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.Item Experimental investigation of viscous forces during surfactant flooding of fractured carbonate cores(2016-08) Parra Perez, Jose Ernesto; Pope, G. A.; Balhoff, Matthew T.The objective of this research was to investigate the effects of viscous forces on the oil recovery during surfactant flooding of fractured carbonate cores, specifically, to test the effects of using surfactants that form viscous microemulsions in-situ. The hypothesis was that a viscous microemulsion flowing inside a fracture can induce transverse pressure gradients that increase fluid crossflow between the fracture and the matrix, thus, enhancing the rate of surfactant imbibition and thereby the oil recovery. Previous experimentalists assumed the small viscous forces were not important for oil recovery from naturally fractured reservoirs (NFRs) since the pressure gradients that can be established are very modest due to the presence of the highly conductive fractures. Hence, the most common approach for studying surfactants for oil recovery from NFRs is to perform static imbibition experiments that do not provide data on the very important viscous and pressure forces. This is the first experimental study of the effect of viscous forces on the performance of surfactant floods of fractured carbonate cores under dynamic conditions. The effects of viscous forces on the oil recovery during surfactant flooding of fractured carbonate cores were tested by conducting a series of ultralow interfacial tension (IFT) surfactant floods using fractured Silurian Dolomite and Texas Cream Limestone cores. The viscosity of the surfactant solution was increased by adding polymer to the surfactant solution or by changing the salinity of the aqueous surfactant solution, which affects the in-situ microemulsion viscosity. The fractured cores had an extreme permeability contrast between the fracture and the matrix (ranging from 2500 to 90,000) so as to represent typical conditions encountered in most naturally fractured reservoirs. Also, non-fractured corefloods were performed in cores of each rock type for comparison with the results from the fractured corefloods. In all the experiments, the more viscous surfactants solutions achieved the greater oil recovery from the fractured carbonate cores which contradicts conventional wisdom. A new approach for surfactant flooding of naturally fractured reservoirs is presented. The new approach consists of using a surfactant solution that achieves ultralow IFT and that forms a viscous microemulsion. A viscous microemulsion can serve as a mobility control agent analogous to mobility control with foams or polymer but with far less complexity and cost. The oil recovery from the fractured carbonate cores was greater for the surfactant floods with the higher microemulsions, thus, it is expected that using viscous microemulsion can enhance the oil recovery from naturally fractured reservoirs.Item Forecasting of isothermal enhanced oil recovery (EOR) and waterflood processes(2011-12) Mollaei, Alireza; Delshad, Mojdeh; Lake, Larry W.; Patzek, Tadeusz W.; Edgar, Thomas F.; Lasdon, Leon S.Oil production from EOR and waterflood processes supplies a considerable amount of the world's oil production. Therefore, the screening and selection of the best EOR process becomes important. Numerous steps are involved in evaluating EOR methods for field applications. Binary screening guides in which reservoirs are selected on the basis of reservoir average rock and fluid properties are consulted for initial determination of applicability. However, quick quantitative comparisons and performance predictions of EOR processes are more complicated and important than binary screening that are the objectives of EOR forecasting. Forecasting (predicting) the performance of EOR processes plays an important role in the study, design and selection of the best method for a particular reservoir or a collection of reservoirs. In EOR forecasting, we look for finding ways to get quick quantitative results of the performance of different EOR processes using analytical model/s before detailed numerical simulations of the reservoirs under study. Although numerical simulation of the reservoirs is widely used, there are significant obstacles that restrict its applicability. Lack of necessary reservoir data and time consuming computations and analyses can be barriers even for history matching and/or predicting EOR/waterflood performance of one reservoir. There are different forecasting (predictive) models for evaluation of different secondary/tertiary recovery methods. However, lack of a general purpose EOR/waterflood forecasting model is unsatisfactory because any differences in results can be caused by differences in the model rather than differences in the processes. As the main objective of this study, we address this deficiency by presenting a novel and robust analytical-base general EOR and waterflood forecasting model/tool (UTF) that does not rely on conventional numerical simulation. The UTF conceptual model is based on the fundamental law of material balance, segregated flow and fractional flux theories and is applied for both history matching and forecasting the EOR/waterflood processes. The forecasting model generates the key results of isothermal EOR and waterflooding processes including variations of average oil saturation, recovery efficiency, volumetric sweep efficiency, oil cut and oil rate with real or dimensionless time. The forecasting model was validated against field data and numerical simulation results for isothermal EOR and waterflooding processes. The forecasting model reproduced well (R2> 0.8) all of the field data and reproduced the simulated data even better. To develop the UTF for forecasting when there is no injection/production history data, we used experimental design and numerical simulation and successfully generated the in-situ correlations (response surfaces) of the forecasting model variables. The forecasting model variables were proven to be well correlated to reservoir/recovery process variables and can be reliably used for forecasting. As an extension to the abilities of the forecasting model, these correlations were used for prediction of volumetric sweep efficiency and missing/dynamic pore volume of EOR and waterflooding processes.Item Imbibition of anionic surfactant solution into oil-wet matrix in fractured reservoirs(2013-05) Mirzaei Galeh Kalaei, Mohammad; DiCarlo, David Anthony, 1969-; Pope, G. A.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.Item Improving liquid chemical intervention methods to control pathogens on fresh-cut fruits and vegetables(Texas A&M University, 2006-08-16) Troya, Maria RosaFactors that affect liquid chemical intervention methods of controlling pathogens on fresh-cut produce were investigated. The relationship between produce tissue structure (intercellular space, cell size, and cell distribution) and the sanitizing effectiveness of liquid chemical treatment was studied. Experiments determined if sanitizer contact with bacteria could be improved through the use of surfactants and different application methods (drop application method, negative pressure differential, and sonication). To test these factors, a model sanitizer, H2O2, and a model microorganism: Salmonella Typhimurium, along with various fresh-cut produce (apple, pear, carrot, and potato) were tested. Microscopic analysis revealed a very complicated pore structure consisting of irregular capillaries. S. Typhimurium was found to survive in all produce tested, and washing did not significantly reduced inoculated bacteria regardless of the bacterial incubation time or produce type. The results showed that a 3% H2O2 solution reduced S. Typhimurium in produce and the solution??s efficiency varied in the following descending order: potato>apple>carrot>pear. In seven min treatments, bacteria were reduced by 2.5 CFU/ml in potato, 2.3 CFU/ml in apple, 1.5 CFU/ml in carrot, and 0.7 CFU/ml in pear. There was no direct evidence on how intercellular space, its percentage or cellular distribution and shape affected efficiency, but some possibilites were discussed. The rate and extent of liquid penetration, and how varying pore diameter in each cell or air space prevent complete chemical treatment penetration were also analyzed. It was determined that bacterial density has a slight effect in bacterial reduction but this depends on type of produce inoculated. The use of surfactants did not improve bacterial reduction in either washing or chemical treatments, and neither did the use of drop application method or temperature differential. On the other hand, applying the chemical treatment with a surfactant while using a sonicator did improve the treatment??s efficiency. This thesis provides a number of factors to be considered when designing a chemical treatment and a guideline for further research in areas such as rate and extent of liquid chemical treatment penetration into fresh-cut produce.Item Kinetics of Anionic Surfactant Anoxic Degradation(2010-07-14) Camacho, Julianna G.The biodegradation kinetics of Geropon TC-42 (trademark) by an acclimated culture was investigated in anoxic batch reactors to determine biokinetic coefficients to be implemented in two biofilm mathematical models. Geropon TC-42 (trademark) is the surfactant commonly used in space habitation. The two biofilm models differ in that one assumes a constant biofilm density and the other allows biofilm density changes based on space occupancy theory. Extant kinetic analysis of a mixed microbial culture using Geropon TC-42 (trademark) as sole carbon source was used to determine cell yield, specific growth rate, and the half-saturation constant for S0/X0 ratios of 4, 12.5, and 34.5. To estimate cell yield, linear regression analysis was performed on data obtained from three sets of simultaneous batch experiments for three S0/X0 ratios. The regressions showed non-zero intercepts, suggesting that cell multiplication is not possible at low substrate concentrations. Non-linear least-squares analysis of the integrated equation was used to estimate the specific growth rate and the half-saturation constant. Net specific growth rate dependence on substrate concentration indicates a self-inhibitory effect of Geropon TC-42 (trademark). The flow rate and the ratio of the concentrations of surfactant to nitrate were the factors that most affected the simulations. Higher flow rates resulted in a shorter hydraulic retention time, shorter startup periods, and faster approach to a steady-state biofilm. At steady-state, higher flow resulted in lower surfactant removal. Higher influent surfactant/nitrate concentration ratios caused a longer startup period, supported more surfactant utilization, and biofilm growth. Both models correlate to the empirical data. A model assuming constant biofilm density is computationally simpler and easier to implement. Therefore, a suitable anoxic packed bed reactor for the removal of the surfactant Geropon TC-42 (trademark) can be designed by using the estimated kinetic values and a model assuming constant biofilm density.Item Laboratory investigation of low-tension-gas (LTG) flooding for tertiary oil recovery in tight formations(2012-12) Szlendak, Stefan Michael; Nguyen, Quoc P.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.