Papers by George Hirasaki
Spe Journal, Aug 15, 2016
Test results indicate that a lipophilic surfactant can be designed by mixing both hydrophilic ani... more Test results indicate that a lipophilic surfactant can be designed by mixing both hydrophilic anionic and cationic surfactants, which broaden the design of novel surfactant methodology and application scope for conventional chemical enhanced-oil-recovery (EOR) methods. These mixtures produced ultralow critical micelle concentrations (CMCs), ultralow interfacial tension (IFT), and high oil solubilization that promote high tertiary oil recovery. Mixtures of anionic and cationic surfactants with molar excess of anionic surfactant for EOR applications in sandstone reservoirs are described in this study. Physical chemistry properties, such as surface tension, CMC, surface excess, and area per molecule of individual surfactants and their mixtures, were measured by the Wilhelmy (1863) plate method. Morphologies of surfactant solutions, both surfactant/polymer (SP) and alkaline/surfactant/polymer (ASP), were studied by cryogenic-transmission electron microscopy (Cryo-TEM). Phase behaviors were recorded by visual inspection including crossed polarizers at different surfactant concentrations and different temperatures. IFTs between normal octane, crude oil, and surfactant solution were measured by the spinning-drop-tensiometer method. Properties of IFT, viscosity, and thermal stability of surfactant, SP, and ASP solutions were also tested. Static adsorption on sandstone was measured at reservoir temperature. IFT was measured before and after multiple contact adsorptions to recognize the influence of adsorption on interfacial properties. Forced displacements were conducted by flooding with water, SP, and ASP. The coreflooding experiments were conducted with synthetic brine with approximately 5,000 ppm of total dissolved solids (TDS), and with a crude oil from a Sinopec reservoir.
Scientific Reports, Jun 20, 2023
The effects of velocity and gas type on foam flow through porous media have yet to be completely ... more The effects of velocity and gas type on foam flow through porous media have yet to be completely elucidated. Pressure drop and capillary pressure measurements were made at ambient conditions during a series of foam quality scan experiments in a homogenous sandpack while foam texture was simultaneously visualized. New insights into foam-flow behavior in porous media were discovered. Previously accepted "limiting" capillary pressure theory is challenged by the findings in this work, and the "limiting" terminology is replaced with the word "plateau" to reflect these novel observations. Plateau capillary pressure (P c) and transition foam quality were found to increase with velocity. Transition foam quality was found to depend mostly on liquid velocity rather than gas velocity and is physically linked to foam type (continuous vs. discontinuous) and texture (fine vs. coarse). Distinct rheological behaviors also arose in the low-and high-quality foam regimes as a function of velocity. Foam flow was found to be strongly shear thinning in the low-quality regime where foam texture was fine and discontinuous. In the high-quality regime, the rheology was weakly shear thinning to Newtonian for coarsely textured foam and continuous-gas flow respectively. When all other variables were held constant, at ambient conditions, CO 2 foam was found to be weaker with also lower capillary pressures than N 2 foam and the differences in gas solubility is a likely explanation. Foams have numerous promising applications in porous media ranging from enhanced oil recovery to CO 2 storage in geologic formations 1-4. A growing body of literature is dedicated to understanding the complexities of foam flow in porous media. The prediction of pressure gradient and liquid saturations for a given foam-flow system for a set of flow conditions is a general, yet elusive, goal in this field. The challenge lies in the complex interplay among relevant variables such as surfactant formulation, porous media type, and non-aqueous phase type. Because the interactions among these variables are complex, fundamental studies are needed to deduce the true nature of foam in porous media and to identify it by simplifying relationships among the pertinent variables. One such study by Khatib and colleagues provided evidence for a "limiting" capillary pressure 5. This theory greatly simplified foam models, as the capillary pressure could essentially remain a fixed variable. Another study by Hirasaki and Lawson laid the groundwork for predicting apparent viscosities of foams in porous media via a capillary tube model 6. Falls et al. later extended these relationships to complex porous media with converging-diverging geometries 7. In a separate work, Falls and colleagues clearly identified pertinent aspects of the shape and size of foam bubbles and related these features to mechanisms resulting in creation or destruction of bubbles 8. Rossen identified a minimum pressure gradient required to mobilize foam 9,10. Osterloh and Jante also clearly laid out the regimes in which foam flow becomes independent of either the gas or the liquid velocity 11. Kam and Rossen identified the multiple steady states of certain foams 12. Other works have explored the effects of relevant variables such as surfactant type and concentration 13-17 , salinity 17,18 , porous media heterogeneity 19 , porous media permeability 20,21 , and gas type 22-24. These studies and others have significantly advanced understanding of foam flow in porous media, but predictive modeling capabilities have yet to be achieved 25,26 .
Spe Journal, Aug 8, 2019
Oil recovery in many carbonate reservoirs is challenging because of unfavorable conditions, such ... more Oil recovery in many carbonate reservoirs is challenging because of unfavorable conditions, such as oil-wet surface wettability, high reservoir heterogeneity, and high brine salinity. We present the feasibility and injection-strategy investigation of ultralow-interfacialtension (IFT) foam in a high-temperature (greater than 80 C), ultrahigh-formation-salinity [greater than 23% total dissolved solids (TDS)] fractured oil-wet carbonate reservoir. Because a salinity gradient is generated between injection seawater (SW) (4.2% TDS) and formation brine (FB) (23% TDS), a frontaldilution map was created to simulate frontal-displacement processes and thereafter it was used to optimize surfactant formulations. IFT measurements and bulk-foam tests were also conducted to study the salinity-gradient effect on the performance of ultralow-IFT foam. Ultralow-IFT foam-injection strategies were investigated through a series of coreflood experiments in both homogeneous and fractured oil-wet core systems with initial oil/brine two-phase saturation. The representative fractured system included a well-defined fracture by splitting the core sample lengthwise. A controllable initial oil/brine saturation in the matrix can be achieved by closing the fracture with a rubber sheet at high confining pressure. The surfactant formulation achieved ultralow IFT (magnitude of 10 À2 to 10 À3 mN/m) with the crude oil at the displacement front and good foamability at underoptimal conditions. Both ultralow-IFT and foamability properties were found to be sensitive to the salinity gradient. Ultralow-IFT foam flooding achieved more than 50% incremental oil recovery compared with waterflooding in fractured oil-wet systems because of the selective diversion of ultralow-IFT foam. This effect resulted in a crossflow near the foam front, with surfactant solution (or weak foam) primarily diverted from the fracture into the matrix before the foam front, and oil/high-salinity brine flowing back to the fracture ahead of the front. The crossflow of oil/high-salinity brine from the matrix to the fracture was found to create challenges for foam propagation in the fractured system by forming Winsor II conditions near the foam front and hence killing the existing foam. It is important to note that Winsor II conditions should be avoided in the ultralow-IFT foam process to ensure good foam propagation and high oil-recovery efficiency. Results in this work contributed to demonstrating the technical feasibility of ultralow-IFT foam in high-temperature, ultrahighsalinity fractured oil-wet carbonate reservoirs and investigated the injection strategy to enhance the low-IFT foam performance. The ultralow-IFT formulation helped to mobilize the residual oil for better displacement efficiency and reduce the unfavorable capillary entry pressure for better sweep efficiency. The selective diversion of foam makes it a good candidate for a mobility-control agent in a fractured system for better sweep efficiency.
Journal of Colloid and Interface Science, May 1, 2016
The interfacial properties for surfactants at the supercritical CO 2-water (C-W) interface at tem... more The interfacial properties for surfactants at the supercritical CO 2-water (C-W) interface at temperatures above 80 °C have very rarely been reported given limitations in surfactant solubility and chemical stability. These limitations, along with the weak solvent strength of CO 2 , make it challenging to design surfactants that adsorb at the C-W interface, despite the interest in CO 2-in-water (C/W) foams (also referred to as macroemulsions). Herein, we examine the thermodynamic, interfacial and rheological properties of the surfactant C 12-14 N(EO) 2 in systems containing brine and/or supercritical CO 2 at elevated temperatures and pressures. Because the surfactant is switchable from the nonionic state to the protonated cationic state as the pH is lowered over a wide range in temperature, it is readily soluble in brine in the cationic state below pH 5.5, even up to 120 °C , and also in supercritical CO 2 in the nonionic state. As a consequence of the affinity for both phases, the surfactant adsorption at the CO 2-water interface was high, with an area of 207 Å 2 /molecule. Remarkably, the surfactant lowered the interfacial tension (IFT) down to ~5 mN/m at 120 °C and 3400 psia (23 MPa), despite the low CO 2 density of 0.48 g/ml, indicating sufficient solvation of the surfactant tails. The phase behavior and interfacial properties of the surfactant in the cationic form were favorable for the formation and stabilization of bulk C/W foam at high temperature and high salinity. Additionally, in a 1.2 Darcy glass bead pack at 120 °C, a very high foam apparent viscosity of 146 cP was observed at low interstitial velocities given the low degree of shear thinning. For a calcium carbonate pack, C/W foam was formed upon addition of Ca 2+ and Mg 2+ in the feed brine to keep the pH below 4, by the common ion effect, in order to sufficiently protonate the surfactant. The ability to form C/W foams at high temperatures is of interest for a variety of applications in chemical synthesis, separations, materials science, and subsurface energy production.
Energy & Fuels, Nov 10, 2010
Initial processing of bitumen froth obtained using a water-based extraction process from Athabasc... more Initial processing of bitumen froth obtained using a water-based extraction process from Athabasca oil sands yields stable water-in-bitumen emulsions. When the bitumen is diluted with naphtha to reduce its viscosity and density, almost complete separation can be obtained with a demulsifier in the absence of clay solids. However, a "rag layer" persists between the oil and free water layers when clay solids are present. Effects of the naphtha/bitumen (N/B) ratio, demulsifier selection, and silicate dosage on the rag layer formation and product quality have been studied. Emulsions with a N/B ratio of 0.7 are more stable than those with a N/B ratio of 4.0. This can be partially attributed to the difference in viscosity and density affecting the sedimentation velocity. The residual water and solid contents in the oil layer decrease with the addition of silicate. This behavior is attributed to the effect of silicate on clay wettability. Clay solids have toluene-soluble organic contents, which vary as follows: in the oil layer > in the rag layer > in the bottom layer. This result indicates that the solids are the most water-wet in the bottom (water) layer and the most oil-wet in the oil layer. In the same layer, samples with a N/B ratio of 0.7 have a higher toluene-soluble organic content in solids than those with a N/B ratio of 4.0. At 80°C with a N/B ratio of 4.0, emulsion adding 200 ppm of demulsifier PR 6 and 4 Â 10-4 M sodium m-silicate had 0.3-1.5% water and 0.9% solids in the oil layer, with the water content decreasing with an increasing height above the rag layer.
Energy & Fuels, Apr 27, 2007
Canadian oil sands represent a huge oil resource. Stable water-in-oil (W/O) emulsions, which pers... more Canadian oil sands represent a huge oil resource. Stable water-in-oil (W/O) emulsions, which persist in Athabasca oil sands from surface mining, are problematic, because of clay solids. This article focuses on the characterization of water-in-diluted-bitumen emulsions by nuclear magnetic resonance (NMR) measurement and the transient behavior of emulsions undergoing phase separation. An NMR restricted diffusion experiment (pulsed gradient spin-echo (PGSE)) can be used to measure the emulsion drop-size distribution. Experimental data from PGSE measurements show that the emulsion drop size does not change much with time, which suggests that the water-in-diluted-bitumen emulsion is very stable without an added coalescer. The sedimentation rate of emulsion and water droplet sedimentation velocity can be obtained from NMR one-dimensional (1-D) T 1 weighted profile measurement. Emulsion flocculation can be deduced by comparing the sedimentation velocity from experimental data with a modified Stokes' Law prediction. PR 5 (a polyoxyethylene (EO)/polyoxypropylene (PO) alkylphenol formaldehyde resin) is an optimal coalescer at room temperature. For the sample without fine clay solids, complete separation can be obtained; for the sample with solids, a rag layer that contains solids and has intermediate density forms between the clean-oil and free-water layers. Once formed, this rag layer prevents further coalescence and water separation.
All Days, Jul 2, 2013
In the absence of oil in the porous medium, the STARS TM foam model has three parameters to descr... more In the absence of oil in the porous medium, the STARS TM foam model has three parameters to describe the foam quality dependence, fmmob , fmdry , and epdry. Even for a specified value of epdry , two pairs of values of fmmob and fmdry can sometimes match experimentally measured t g f and t app foam, µ. This non-uniqueness can be broken by limiting the solution to the one for which fmdry < t w S. Additionally, a three-parameter search is developed to simultaneously estimate the parameters fmmob , fmdry , and epdry that fit the transition foam quality and apparent viscosity. However, a better strategy is to conduct and match a transient experiment in which 100% gas displaces surfactant solution at 100% water saturation. This transient scans the entire range of fractional flow and the values of the foam parameters that best match the experiment can be uniquely determined. Finally, a three-parameter fit using all experimental data of apparent viscosity versus foam quality is developed. The numerical artifact of pressure oscillations in simulating this transient foam process is investigated by comparing finite difference algorithm with method of characteristics. Sensitivity analysis shows that the estimated foam parameters are very dependent on the parameters for the water and gas relative permeability. In particular, the water relative permeability exponent and connate water saturation are important.
Journal of Chemical & Engineering Data, Jun 21, 2016
The design of surfactants for stabilizing CO2-in-water (brine) (C/W) foams at high temperature is... more The design of surfactants for stabilizing CO2-in-water (brine) (C/W) foams at high temperature is challenging given the low density (solvent strength) of CO2, limited surfactant solubility in brine, and a lack of knowledge of the interfacial and rheological properties. Herein, the tail length of trimethylammonium cationic surfactants was optimized to provide the desired phase behavior and interfacial properties for formation and stabilization of the C/W foams. The headgroup was properly balanced with a C12–14 hydrocarbon tail to achieve aqueous solubility in 22% total dissolved solids (TDS) brine up to 393 K (120 °C) along with high surfactant adsorption (area/surfactant molecule of 154 A2) at the CO2–water (C–W) interface which reduced the interfacial tension from ∼40 mN/m to ∼6 mN/m. For C12–14N(CH3)3Cl, these properties enabled stabilization of a C/W foam with an apparent viscosity of 14 mPa·s at 393 K in both a crushed calcium carbonate packed bed (75 μm2 or 76 Darcy) and a capillary tube downstream o...
All Days, Apr 22, 2006
The applications of foam are 3-D on a field scale. However, most previous research focuses only o... more The applications of foam are 3-D on a field scale. However, most previous research focuses only on properties of foam in 1-D. Experiments were performed in 3-D, and the compositional reservoir simulator UTCHEM was modified to predict foam flow in 3-D. The 3-D experiments demonstrated that, under similar experimental conditions, the mobility of foam in a 3-D tank is greater than that in a 1-D column. They also showed that foam greatly increases lateral gas distribution along the bottom of the tank and the average gas saturation for both homogeneous and heterogeneous packings with the effects being significantly larger in the latter case. The reservoir simulator UTCHEM was modified for foam flow. The foam simulation parameters were measured in 1-D sand columns and the simulator was modified to match the 1-D and 3-D experiments. The proposed model successfully history matched the homogeneous and heterogeneous 3-D sand tank experimental results for average gas saturation, gas injection rate, gas distribution and pressure profile along the tank diagonal 6 inches from the bottom. The results of this study represent an advance in understanding of foam flow in 3-D. The simulator could be used to design a foam process in 3-D. * c P Mobility of water and gas when foam is present. The relative permeability function of water is not directly influenced by the presence of foam 16-17. Foam can only change the water mobility indirectly by changing the water saturation in porous media. For the flow of gas, foam can greatly reduce
Journal of Colloid and Interface Science, Feb 1, 1996
causing rapid drainage were the result of ''marginal regener-Drainage of circular foam films is m... more causing rapid drainage were the result of ''marginal regener-Drainage of circular foam films is much more rapid when it is ation.'' Other authors (12-16) have investigated the mechaasymmetric than when it is axisymmetric. Asymmetric drainage nisms of marginal regeneration in the drainage of vertical stems from a hydrodynamic instability produced by surface-tenfilms. Stein (17, 18) proposed a modified mechanism for sion-driven flow. It is opposed by surface viscosity, surface diffumarginal regeneration that, in essence, attributed it to a hysivity, and system dimensions, which stabilize perturbations havdrodynamic instability. However, no criterion giving the oning short wavelengths. Numerical simulation of this instability is set of this instability was given. carried out. The results (1) clarify the conditions for applicability In a recent paper (19) we developed a linear stability of a simplified linear stability analysis derived previously, (2) show analysis that clarifies the mechanisms of instability and proclearly the circulating surface convection patterns that arise, and (3) confirm the rapid increase in drainage rate. The same instabil-vides a stability criterion. The initial flow, i.e., in the barrier ity is responsible for periodic convection patterns known as ''marring region between the dimple and meniscus for a circular ginal regeneration'' in vertical soap films that also lead to rapid film (see Fig. 1), was approximated by a film initially of drainage. ᭧ 1996 Academic Press, Inc. uniform half-thickness h˙, subject to a uniform pressure Key Words: drainage, asymmetric, of foam films, simulation gradient (0(Ìp/Ìx)) in the direction of flow (x direction). of; film, thin liquid, simulation of asymmetric drainage of; foam, The stability criterion is given by the expression asymmetric drainage of thin liquid film, simulation of; instability, of thin liquid film leading to asymmetric drainage; simulation, of asymmetric drainage of thin liquid film; surface viscosity, effect ͩ D s m s s (0Ìp/Ìx) 2 / sh˙m s G eq a 3m(0Ìp/Ìx) 2 ͪͩ 2p l y ͪ 6 in preventing asymmetric drainage of foam films.
Soft Matter, 2013
We utilize a microfluidic constriction to demonstrate two new mechanisms of in situ foam generati... more We utilize a microfluidic constriction to demonstrate two new mechanisms of in situ foam generation in porous media. The initial foam was generated using a flow-focusing geometry with co-flowing gas and surfactant solution streams and then flowed through a microfluidic constriction. By varying the gas and surfactant solution flow rates, different types of monodisperse foams were generated in which two bubbles (2-bubble foam), three bubbles (3-bubble foam), or more than three bubbles (>3-bubble foam) spanned the channel width. It was expected that the bubbles would snap off upon passing through the constriction; however, in our system, the snap-off mechanism was observed only under unstable conditions, namely, when the foam was wet and had a large bubble size. Instead, the following behaviors were observed as stable foam passed through the constriction: no change, reorientation, and pinch-off, which included two newly observed mechanisms (neighbor-wall pinch-off and neighborneighbor pinch-off). Neighbor-wall pinch-off occurs as a bubble is pinched between the surfaces of a neighboring bubble and the curved wall of the constriction. Neighbor-neighbor pinch-off occurs as a bubble is pinched off between two adjacent neighboring bubbles. The width of the pinched bubble as a function of time before pinch-off was found to scale as a power law with exponents of 0.523 AE 0.06 and 1.004 AE 0.05 for neighbor-wall and neighbor-neighbor pinch-off, respectively.
Journal of Contaminant Hydrology, Feb 1, 2002
Over the last few years, more than 40 partitioning interwell tracer tests (PITTs) have been condu... more Over the last few years, more than 40 partitioning interwell tracer tests (PITTs) have been conducted at many different sites to measure nonaqueous phase liquid (NAPL) saturations in the subsurface. While the main goal of these PITTs was to estimate the NAPL volume in the subsurface, some were specifically conducted to assess the performance of remedial actions involving NAPL removal. In this paper, we present a quantitative approach to assess the performance of remedial actions to recover NAPL that can be used to assess any NAPL removal technology. It combines the use of PITTs (to estimate the NAPL volume in the swept pore volume between injection and extraction wells of a test area) with the use of several cores to determine the vertical NAPL distribution in the subsurface. We illustrate the effectiveness of such an approach by assessing the performance of a surfactant/foam flood conducted at Hill Air Force Base, UT, to remove a TCE-rich NAPL from alluvium with permeability contrasts as high as one order of magnitude. In addition, we compare the NAPL volumes determined by the PITTs with volumes estimated through geostatistical interpolation of aquifer sediment core data collected with a vertical frequency of 5-10 cm and a lateral borehole spacing of 0.15 m. We demonstrate the use of several innovations including the explicit estimation of not only the errors associated with NAPL volumes and saturations derived from PITTs but also the heterogeneity of the aquifer sediments based upon permeability estimates. Most importantly, we demonstrate the reliability of the
Langmuir, Dec 1, 1992
Draining foam or emulsion f h are generally of nonuniform thickness. A thick region or 'dimple" f... more Draining foam or emulsion f h are generally of nonuniform thickness. A thick region or 'dimple" forme in the central part of a circular film. It is separated from the Plateau border by a thinner 'barrier ring". We have developed a new numerical model to simulate the entire drainage process, including the film formation. The model assumes that drainage is arieymmetric and that the fluid interfaces are immobile. The initial conditions are a pair of static hemispherical menisci. Fluid is withdrawn at a constant rate for a specified time to form a film. The condition for the transition from a nearly "plane-parallel" f i to a dimpled film in the absence of disjoining pressure was determined. The ratio of the minimum to maximum thickness in the film and a dimensionless rate of drainage are correlated with the ratio of the maximum possible curvature in the dimple to the curvature in the meniscus. The rate of drainage is always less than that given by the Reynolds theory for drainage between a pair of disks that is pressed by a pressure equal to the capillary pressure. When the film is approximately plane-parallel, the pressure drop from the center of the film to the Plateau border is less than half of that predicted by the Reynolds theory and there is a significant pressure gradient beyond the nominal film radius. When a dimple forms, most of the resistance to flow is in the thin barrier ring. The presence of disjoining pressure makes a qualitative difference in film drainage. Low electrolyte concentrations in a film containing ionic surfactant produce a repulsive disjoining pressure that inhibits formation of the thin barrier ring and thus of the dimple itaelf. The film drains rapidly to ita equilibrium thickness. For high electrolyte concentration, the disjoining pressure is dominated by van der Waals attraction. As a result a thin annular fiIm forms that forces the dimple into a lens with a finite contact angle. These types of behavior are observed experimentally.
All Days, Apr 11, 2011
Alkali in surfactant flooding can sequester divalent ions and reduce surfactant adsorption. When ... more Alkali in surfactant flooding can sequester divalent ions and reduce surfactant adsorption. When the alkali is sodium carbonate and anhydrite (or gypsum) is present, the anhydrite will dissolve and precipitate as calcium carbonate. An anhydrite level of only 0.1% in the rock is enough to retard the breakthrough of a 1% sodium carbonate solution by approximately 0.7 pore volume, which would greatly reduce effectiveness of a process having surfactants sensitive to divalent ions. Different alkalis will also react with anhydrite. A methodology is presented to estimate the amount, if any, of anhydrite present in the reservoir. The method is based on brine software analysis of produced water compositions and inductively coupled plasma (ICP) analysis of core samples. X-ray powder diffraction (XRD) can detect anhydrite when it is abundant, but will not be able to detect the low amounts that can still be harmful to chemical EOR. Produced water and core samples were analyzed from a high-temperature, high-salinity carbonate reservoir, which is a candidate for surfactant EOR. Ten water analyses were obtained from ten wells in five formations. The formation brines ranged from 3-to-20% of TDS. The reservoir rock was mostly dolomite, and reservoir temperature was about 120°C. The saturation index calculated for all formation waters at high salinity (higher than sea water) was positive, indicating over saturation with anhydrite. The saturation index was calculated with ScaleChem for high salinity and PHREEQC, which is limited to lower salinity. The elemental composition of rock samples dissolved in acid was determined by ICP. The mass percent of anhydrite was computed from the elemental analysis. When these methods were applied to the dolomite reservoir of interest, they strongly indicated that anhydrite was present in sufficient amounts to preclude use of sodium carbonate in a surfactant recovery process.
All Days, Feb 18, 1997
A surfactant/foam process is described for the remediation of aquifers contaminated with dense no... more A surfactant/foam process is described for the remediation of aquifers contaminated with dense nonaqueous phase liquid (DNAPL). Foam is used for mobility control to displace DNAPL from low permeability sands that are often unswept during a remediation process. Introduction An area where the technology developed for enhanced oil recovery can be applied to environmental remediation is the application of surfactant to remove nonaqueous phase liquid (NAPL) from aquifers. NAPL can be of two types, those which are less dense than water, called light nonaqueous phase liquid (LNAPL) and those which are more dense than water, called dense nonaqueous phase liquid (DNAPL). We concentrate on DNAPL because there are fewer viable alternatives to surfactant remediation. DNAPL will tend to migrate to the lowest accessible point in the aquifer and to enter lower permeability sediments if the capillary pressure becomes large enough. The challenge is to remove DNAPL from local depressions along the base of an aquifer and from low permeability layers in the presence of higher permeability layers. An approach to improve the sweep efficiency of a displacement process is to use mobility control so that the injected fluid is less mobile than the resident fluids. The common method of mobility control for surfactant flooding is through the generation of an inherently viscous microemulsion phase and through the addition of a polymer. However, Lawson and Reisberg introduced the concept of injecting gas with the surfactant solution to generate an in situ foam for mobility control. This approach has not been as popular because the mobility of foam is not as predictable as with polymers. However, much has been learned about the mobility of foam since that time and some publications on the use of foam for mobility control of surfactant flooding have appeared. Also foam has the potential of selectively reducing the mobility more in higher permeability layers in contact with lower permeability layers. Site Characterization The location for a field test of the surfactant/foam process for aquifer remediation is Hill Air Force Base near Ogden, Utah. This base has been the test site of many remediation technologies during 1996. The Operable Unit 2 (OU2) is a waste disposal site where unlined earthen trenches were used from 1967 to 1975 for the disposal of spent liquid degreasing solvents (primarily trichloroethylene). OU2 is currently being treated by "pump and treat" where the DNAPL and ground water are pumped out and the organic material removed by sedimentation and steam stripping. However, pump and treat treatment alone would have to continue for a very long time because of the low solubility of the contaminants in water and the large volume of DNAPL existing in pools and as a residual saturation. A surfactant flood without mobility control was conducted successfully by INTERA and the University of Texas at a site adjacent to where the surfactant/foam is to be tested. A steam flood test in an adjacent site is planned in the near future. Aquifer structure A structure map of the base of the unconfined aquifer is shown in Fig. 1. The aquifer consists of coarse-grained, unconsolidated sediments of recent alluvium and/or Provo Formation. It is about 50 ft thick and the water table is about 25 ft below ground level. The aquifer is underlain by more than 100 ft of the clay dominated Alpine Formation. This formation will be called the "aquitard". The structure of the aquitard and the water table helps to keep the aquifer confined in a trough or channel. Fig. 2 is a cross section along the long axis of the channel. The disposal trenches were located somewhere near the southern end of this cross-section. P. 471
Soft Matter, 2012
ABSTRACT We demonstrate the use of foam to divert flow from high permeable to low permeable regio... more ABSTRACT We demonstrate the use of foam to divert flow from high permeable to low permeable regions in a PDMS heterogeneous porous microfluidic system. Foam is generated using a flow-focusing microfluidic device with co-flowing gas and aqueous surfactant streams. Foam quality (gas fraction) is modulated by adjusting the flow rate of the aqueous surfactant solution while keeping the gas inlet pressure fixed. The foam is then injected into an aqueous-solution filled heterogeneous porous media containing a high and low permeable region and sweep of the saturated aqueous phase is monitored. Compared with 100% gas injection, surfactant-stabilized foam is shown to effectively improve the sweep of the aqueous fluid in both high and low permeable regions of the porous micromodel. The best performance of foam on fluid diversion is observed in the lamella-separated foam regime, where the presence of foam can enhance gas saturation in the low permeable region up to 45.1% at the time of gas breakthrough. The presented results are useful in understanding and designing foam injection in porous underground formations for aquifer remediation and enhanced oil recovery processes.
Journal of Surfactants and Detergents, Jan 22, 2023
Nonionic surfactants are increasingly being applied in oil recovery processes due to their stabil... more Nonionic surfactants are increasingly being applied in oil recovery processes due to their stability and low adsorption onto mineral surfaces. However, these surfactants lead to the production of emulsified oil that is extremely stable and difficult to separate by conventional methods. This research characterizes the stability of crude oil mixed with a nonionic surfactant, L24–22, in a brine solution. When subjected to gravity separation, a middle oil‐rich and bottom water‐rich emulsion are generated for various water–oil ratios. Thermal treatments can effectively break oil‐rich emulsions, but the bottom water layer remains contaminated with micron‐sized crude oil droplets. A magnetic nanoparticle treatment is shown to demulsify the crude oil emulsions, dropping the total organic carbon (TOC) in the water layer from 1470 to 30 ppm.
Proceedings of SPE/DOE Improved Oil Recovery Symposium, Apr 1, 2002
Energy & Fuels, Jun 2, 2011
Processing of bitumen froth obtained from surface mining process of Athabasca oil sands yields st... more Processing of bitumen froth obtained from surface mining process of Athabasca oil sands yields stable water-indiluted bitumen emulsions. Even with a demulsifier, a "rag layer" forms between the oil and free water layers when clay solids are present. Experiments reveal that wettability of clay solids has a significant effect on emulsion stability. Kaolinite in tolueneÀbrine mixture was chosen as model system to study clay wettability alteration related to emulsion separation in bitumen froth treatment. Sodium naphthenate was added to simulate the presence of naphthenic acid in diluted bitumen. The fraction of the kaolinite that settled to the bottom of the aqueous phase was measured, and was referred to as "water-wet fraction", to characterize the wettability of kaolinite. Without any additives, 96% of the kaolinite was water-wet. Addition of only 100 ppm sodium naphthenate reduced the water-wet fraction to only 18%. Wettability of kaolinite was altered by pH control, silicate, and surfactant under different mechanisms. Addition of 366 ppm silicate at pH 10 resulted in 80% of kaolinite being water-wet. To prevent emulsion formation at high pH, cationic and amphoteric surfactants were evaluated as an alternative to alkali. Over 90% of kaolinite became water-wet when adding alkyl quaternary ammonium bromide, betaine, or amine oxide with optimal dosages.
Uploads
Papers by George Hirasaki