Browsing by Subject "Surfactants"

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Characterization and Remediation of Aquifers Contaminated by Nonaqueous Phase Liquids Using Partitioning Tracers and Surfactants
(1997-05) Dwarakanath, Varadarajan; Pope, Gary A.; Sepehrnoori, Kamy
The main objectives of this work were the development of the partitioning interwell tracer test for estimation of nonaqueous phase liquid (NAPL) saturation in saturated porous media, performance assessment of surfactant enhanced aquifer remediation using partitioning tracers and screening and selection of environmentally acceptable surfactant solutions for surfactant enhanced aquifer remediation (SEAR) of soils contaminated by NAPLs. The contaminants studied in this work were tetrachloroethylene (PCE), trichloroethylene (TCE), jet fuel (JP4) and contaminant from Hill Air Force Base, site Operational Unit 2 (Hill OU2 DNAPL) and contaminant from Hill Air Force Base, site Operational Unit 1 (Hill OUl LNAPL). The first step in screening partitioning tracers involved performing several batch experiments to determine partition coefficients of about 28 alcohols and 10 NAPLs. Partitioning tracer tests were performed to estimate NAPL saturation in soil packs with known amounts of NAPL. A close match between NAPL saturation estimates based on mass balance and partitioning tracers was obtained in column experiments with several NAPLs thus validating the partitioning interwell tracer test as an effective tool for estimating residual NAPL saturation. The next step involved the development of laboratory procedures for designing field partitioning tracer tests. Two field partitioning tracer tests were designed using these procedures. The first field test was a partitioning interwell tracer test (PITT) performed by The University of Florida and EPA at the Operational Unit 1 site at Hill Air Force Base, Utah and the second test was the PITT performed by INTERA Inc. at the Operational Unit 2 site at Hill Air Force Base, Utah. Surfactants were selected by performing phase behavior experiments with surfactant, NAPL, alcohol, electrolyte and water mixtures. The surfactants used were the anionic surfactants, sodium diamyl sulfosuccinate, sodium dihexyl sulfosuccinate and sodium dioctyl sulfosuccinate. Surfactant solutions with low viscosities and quick equilibration times were selected for use in soil column experiments. Alcohols such as isopropyl alcohol and secondary butyl alcohol were used to minimize gel/liquid crystal formation and emulsions and to lower equilibration times. These favorable characteristics were confirmed by measurement of low pressure losses (hydraulic gradients) across the soil packs during surfactant flooding in several column experiments. The effect of the addition of polymer to the surfactant solution on surfactant remediation was investigated by performing several surfactant remediation experiments with surfactant, alcohol and polymer solutions. Based on all the column experiments, a laboratory procedure for designing field surfactant enhanced aquifer remediation tests was developed. This was used to design a surfactant flood at Hill AFB, site Operational Unit 2. Both the laboratory and field results showed that with the proper surfactant selection, laboratory procedures and process design, more than 99% of the DNAPL can be removed from sandy/gravely soil of the type found in Hill AFB, Utah. This is a much more favorable result than previously reported and a strong indication that surfactant remediation is a viable alternative, perhaps the best alternative for these very difficult DNAPL sites. Partitioning tracers and other site characterization played a key role in this success and were an integral part of all this research. The main contributions of this work were the validation the PITT for estimation of NAPL saturations and performance assessment of surfactant remediation and development of laboratory procedures for selection of both partitioning tracers and surfactants for application in field PITT and SEAR operations.
Chemically enabled CO₂-enhanced oil recovery
(2024-08) Pang, Jieqiong ; Mohanty, Kishore Kumar; Chun Huh; Keith P. Johnston; Ryosuke Okuno; Matthew Balhoff
Carbon-dioxide enhanced oil recovery (CO₂-EOR) is widely used for oil recovery from reservoirs. Additionally, the interest in CO₂ storage in depleted reservoirs and aquifers grows due to global warming. However, continuous gas injection suffers from low sweep efficiency caused by unfavorable mobility ratio, gravity segregation, and reservoir heterogeneity. The water-alternating-gas (WAG) was proposed to overcome these challenges, but still encounters issues. Chemically enabled CO₂-EOR methods, involving the adding of surfactants, polymers, and nanoparticles, are explored to address these challenges. This dissertation aims to develop effective CO₂-EOR strategies, including CO₂ polymer-alternating-gas (CO₂-PAG) and CO₂-foam flooding, through a series of experiments and simulations. Minimum miscibility pressure (MMP) is an important parameter in gas injection projects, indicating the pressure at which injected gas and reservoir oil become miscible during flow. CO₂ floods are efficient at or above MMP, enhancing oil recovery. Slim tube experiments were conducted to measure MMP for various oils and the effects of CO₂ additives and rich gas content on MMP were studied. Conclusions include MMP values for different oils and the limited impact of certain additives on miscibility. Compositional simulations suggested rich gas can notably reduce MMP between crude oil and CO₂. Next, the performance of CO₂ polymer-alternating-gas (CO₂-PAG) flooding for enhanced oil recovery was evaluated through core flood experiments and 2-D visualization experiments, followed by simulation studies. Core flood experiments were conducted using both homogeneous and heterogeneous core samples, with a novel heterogeneous core system developed to mimic layered reservoirs. Incremental oil recovery from PAG flooding was compared to water-alternating-gas (WAG) floods and continuous gas (CG) floods. Additionally, two-dimensional (2-D) visualization flooding experiments were performed in layered heterogeneous sand-packs. Subsequent simulations were conducted to further analyze PAG performance and refine strategies. Findings reveal that PAG flooding demonstrated improved performance in heterogeneous systems, compared to CG and WAG floods. Subsequently, the efficiency of CO₂-foam flooding with wettability alteration was investigated in an oil-wet carbonate reservoir. Three types of surfactants, including a nonionic surfactant Soloterra 843, a cationic surfactant CETAC-30, and a zwitterionic surfactant LMDO, were evaluated as potential foam agents. Contact angle tests using core chips were conducted to assess the wettability alteration capability of these surfactants. Subsequently, foam static stability tests and foam rheology tests were conducted under reservoir conditions to evaluate the performance of various foam formulations. Finally, foam core flood experiments were performed using carbonate core samples. Results from contact angle experiments indicated that CETAC-30 could effectively alter rock wettability from oil-wet to water-wet. Foam stability tests revealed that LMDO exhibited superior stability in generating CO₂-foam in the absence of crude oil, followed by CETAC-30 and Soloterra 843. However, the presence of crude oil adversely affected CO₂-foam stability. Rheological tests demonstrated that the apparent viscosity of CO₂-foam decreased with increasing flow velocity, exhibiting a shear thinning behavior. Furthermore, core flood experiments demonstrated that injecting wettability alteration surfactant, CETAC-30, in form of foam could not only alter the wettability of rocks but also enhance the foam strength. However, the introduction of pre-flushed wettability alteration surfactant may not significantly impact foam strength. Additionally, most of the wettability alteration surfactant injected with CO₂ tended to be used in foam generation, with any remaining surfactant utilized for wettability alteration. Finally, CO₂-foam flooding was evaluated as a method to improve CO₂ storage in a high salinity carbonate reservoir. Several surfactants and nanoparticles were examined to identify an effective foam formulation. Foam stability at the ambient pressure and at the reservoir pressure was used to screen suitable foaming agents. The foam mobility was measured through a carbonate rock at 80% quality with selected foaming agents. Finally, CO₂ flooding, and CO₂-foam flooding experiments were performed in carbonate core samples under the reservoir conditions. Many surfactants and nanoparticles were insoluble in brine at the high salinity and temperature conditions of this study. Through foam stability and rheology tests at the reservoir pressure, a combination of the nonionic surfactant Aspiro S 2410 and the nanoparticle EOR 12-V3 was found to be the most effective. The addition of nanoparticles significantly increased the half-life of the foam at the reservoir pressure. The presence of crude oil had a detrimental effect on CO₂-foam stability. The surfactant-nanoparticle foam exhibited a higher apparent viscosity compared to the foam generated by the surfactant alone. Core flood experiments demonstrated that CO₂-foam flooding with the surfactant-nanoparticle solution achieved higher CO₂ storage and oil recovery compared to both continuous CO₂ injection and CO₂ surfactant-foam flooding.
Design and optimization of surfactants and surface-modified nanoparticles for mechanistic studies of foam stabilization and interfacial interactions
(2021-05-06) Da, Chang; Johnston, Keith P., 1955-; Hirasaki, George J.; Bonnecaze, Roger T.; Rochelle, Gary T.
Surfactants and/or nanoparticles (NP) are shown to stabilize carbon dioxide CO₂-in-water (C/W) foams and nitrogen N₂-in-water (N/W) foams with strong interfacial adsorption and interactions. The first two studies demonstrate that viscous C/W foams may be generated with either a single zwitterionic surfactant or a single switchable diamine surfactant, over a wide temperature range up to 150 °C even at high salinities. The foams have apparent viscosities in the right range to have potential in CO₂ mobility control based on the experimental results in porous media. Moreover, both surfactants are shown to have high thermal stability with negligible chemical degradation after incubation at 135 °C for 30 days, which benefits long-term applications in high temperature reservoir conditions. To another topic, the binary grafting of ether diol and dimethylsilyl ligands on silica NPs are then shown to provide steric stabilization in bulk phase of concentrated brine and raise the NP hydrophobicity to promote interfacial adsorption, producing an interface with a relatively strong surface elastic dilational modulus E'. The NP-laden interface also demonstrates moderate ductility with a relatively slow change in surface pressure Π and E' over a wide range of surface area variation during compression and expansion. Moreover, the combination of an anionic surfactant with NPs grafted with the binary ligands, each of which is interfacial-active, produces a highly viscoelastic air-brine interface at high salinity that enabled highly stable N/W foams from ambient temperature up to 80 °C. The ability to tailor the interfacial properties with surfactants and NPs with independently tunable surfaces is of broad scientific interest and great potential for various applications.
Design and synthesis of surfactants and nanoparticles for mechanistic studies of foams, emulsions and wettability alteration
(2019-08) Alzobaidi, Shehab; Johnston, Keith P. 1955-; Bonnecaze, Roger; DiCarlo, David; Lynd, Nathaniel; Prodanovic, Masa
Surfactants or nanoparticles are shown to stabilize carbon dioxide (CO₂)-in-water (C/W) foams, nitrogen (N₂)-in-water (N/W) foams and CO₂-in-oil (C/O) emulsions and to alter the wettability of oil-wet calcite surfaces to water-wet. Chapter 2 focuses on developing an understanding of the aqueous and interfacial properties of single viscoelastic surfactants to stabilize C/W foams for extended time with highly viscous aqueous phases. Surface modified amphiphilic silica nanoparticles are then investigated as alternatives to surfactants to increase the stability of C/W and N/W foams. Here, the first examples of nanoparticles with known surface modification that stabilize foams in high salinity brines at elevated temperature are presented. The fundamental understanding gained from surfactant design for C/W foam studies is used to design stabilizers for C/O emulsions. Here, polymeric surfactants with polydimethylsiloxane backbones and pendant linear alkyl chains are designed to stabilize novel C/O emulsions despite the low interfacial adsorption driving force, given the low interfacial tension. Finally, silica nanoparticles with various modifications (anionic, cationic and nonionic) are used to mechanistically study wettability alteration of oil-wet calcite surface to water-wet, especially in high salinity environments.
Development of a novel EOR surfactant and design of an alkaline/surfactant/polymer field pilot
(2012-12) Gao, Bo; Sharma, Mukul M.
Surfactant related recovery processes are of increasing interest and importance because of high oil prices and the urge to meet energy demand. High oil prices and the accompanying revival of EOR operations have provided academia and industry with great opportunities to test alkaline surfactant polymer (ASP) methods on a field scale and to develop novel surfactant systems that can improve the performance of such EOR processes. This dissertation intends to discuss both opportunities through two unique projects, the development of novel surfactants for EOR applications and the design for an alkaline/surfactant/polymer (ASP) field pilot. In Section I of this dissertation, a novel series of anionic Gemini surfactants are carefully synthesized and systematically investigated. The remarkable abilities of Gemini surfactants to influence oil-water interfaces and aqueous solution properties are fully demonstrated. These surfactants are shown to have great potential for application in EOR processes. A wide range of Gemini structures (C₁₄ to C₂₄ chain length, -C2- and -C4- spacers, sulfate and carboxylate head groups) was synthesized and shown to have high aqueous solubility, with Krafft points below 20°C. The critical micelle concentrations (CMC) for these new molecules are measured to be orders of magnitude lower than their conventional counterparts. The significantly more negative Gibbs free energy for Gemini surfactant drives the micellization process and results in ultralow CMC. An adsorption study of Gemini surfactants at air-water and solid-water interfaces shows their superior surface activity from tighter molecular packing, and attractive characteristics of low adsorption loss at the solid surface. All anionic Gemini surfactants synthesized have an extraordinary tolerance to salinity and/or hardness. No phase separation or precipitation occurs in the aqueous stability tests, even in the presence of extremely high concentrations of mono- and/or di-valent ions. Moreover, ultra-low IFT values are reached under these conditions for Type I microemulsion systems, at very low surfactant concentrations. The stronger molecular interaction between the Gemini and conventional surfactants offers synergy that promotes aqueous stability and interfacial activity. Gemini molecules with short spacers are capable of giving rise to high viscosities at fairly low concentrations. The rheological behavior can be explained by changes in the micellar structure. A molecular thermodynamic model is developed to study anionic Gemini surfactants aggregation behavior in solution. The model takes into account of the head group-counter-ion binding effect and utilizes two simplified solutions to the Poisson-Boltzmann equation. It properly predicts the CMC of the surfactants synthesized and can be easily expanded to investigate other factors of interest in the micellization process. Section II of this dissertation studies chemical formulation design and implementation for an oilfield where an alkaline/surfactant/polymer (ASP) pilot is being carried out. A four-step systematic design approach, composed of a) process and material selection; b) formulation optimization; c) coreflood validation; 4) lab-scale simulation, was successfully implemented and could be easily transferred to other EOR projects. The optimal chemical formulation recovered over 90% residual oil from Berea coreflood. Lab-scale simulation model accurately history matches the coreflood experiment and sets the foundation for pilot-scale numerical study. Different operating strategies are investigated using a pilot-scale model, as well as the sensitivities of project economics to various design parameters. A field execution plan is proposed based on the results of the simulation study. A surface facility conceptual design is put together based on the practical needs and conditions in the field. Key lessons learned throughout the project are summarized and are invaluable for planning and designing future pilot floods.
Effect of surfactants on methane hydrate formation and dissociation
(2011-05) Ramaswamy, Divya; Sharma, Mukul M.; Bryant, Steven L.
Dissociation of gas hydrates has been the primary concern of the oil and gas industry for flow assurance, mainly in an offshore environment. There is also a growing interest in the rapid formation of gas hydrates for gas storage, transport of natural gas and carbon sequestration. In this thesis, we experimentally measure the kinetics of formation and dissociation of methane hydrates and the effect of various anionic and cationic surfactants such as sodium dodecyl sulfate (SDS), cetyl trimethylammonium bromide (CTAB) and alpha olefin sulfonate (AOS) on the association/dissociation rate constants. The importance and necessity of micelle formation in these surfactants has been studied. The effect of foam generation on the rate of formation of these hydrates has also been measured. SDS was found to significantly decrease the induction time for hydrate formation. There was an added decrease in the induction time when a foamed mixture of water and SDS was used. On the other hand CTAB and AOS had an inhibiting effect. The contribution of micelles towards promoting hydrate formation was demonstrated with a series of experiments using SDS. The micelles formed by these surfactants appear to serve as nucleation sites for the association of hydrates. New experimental data is presented to show that some surfactants and the use of foam can significantly increase the rate of hydrate formation. Other surfactants are shown to act as inhibitors. A new experimental setup is presented that allows us to distinguish between surfactants that act as promoters and inhibitors for hydrate formation.
Effective mobility control mechanisms for EOR processes in challenging carbonate reservoirs
(2019-05) Ghosh, Pinaki, Ph. D.; Mohanty, Kishore Kumar; DiCarlo, David; Sepehrnoori, Kamy; Johnston, Keith P; Werth, Charles
Mobility control mechanisms are key to the success of any enhanced oil recovery processes due to their ability to provide favorable mobility ratio of the injected fluids, thus improving the sweep efficiency during the process. This work is focused on developing effective mobility control mechanisms in challenging carbonate reservoirs that are typically high temperature and high salinity and low permeability formations. The first half of the dissertation is focused on investigating novel foam technology using anionic and cationic surfactants to improve the gas enhanced oil recovery process. Typically, gas injection processes suffer from poor volumetric sweep efficiency due to viscous fingering, channeling, and gravity override. Foam helps to improve the sweep efficiency of the gas floods significantly by reducing the mobility of the gas by orders of magnitude, blocking the high permeability channels and diverting fluids to the bypassed lower permeability channels. Carbonate reservoirs, which are typically oil-wet heterogeneous and low permeability, pose additional challenges for an effective foam EOR process. Crude oils destabilize foam rapidly and the thin oil film on oil-wet rock surfaces makes in-situ foam generation difficult as well. Hence, wettability alteration from oil-wet to water-wet using a surfactant was one of the necessary mechanisms for in-situ foam stability. Low permeability of the carbonates makes strong foam generation challenging due to higher entry capillary pressure in small pore throats that exceeds the critical capillary pressures usually. On the other hand, low interfacial tensions (IFT) of the surfactant formulations helps to lower the entry pressure and stabilize the foam better. This work demonstrated the benefits of two different chemical systems – one that includes use of anionic surfactants for low IFT formulations and the other that includes blends of cationic, non-ionic and zwitterionic surfactants for non low IFT formulations in combination with wettability alteration and foaming to improve oil recovery in oil-wet carbonates after a secondary gas flood process. The second half of the dissertation is focused on developing a novel polymer treatment protocol for successful injection in low permeability carbonate reservoirs through mechanical shear degradation and aggressive filtration tests. The behavior of shear degradation of high molecular weight polymers of different chemistry in varying brine salinities performed with a laboratory blender at a constant speed and varying shearing times followed an exponential decay until a steady state was obtained. Master curves for degraded viscosity predictions were developed to estimate the degraded viscosity of any given polymer in any brine salinity at any given shearing time, given the shearing speed was kept constant. A superimposed master curve for the degradation for all kinds of polymers investigated was established to predict the rate of degradation at any given time. A robust approach of comparison of polymer size distribution from dynamic light scattering (DLS) method and pore throat distribution from mercury injection capillary pressure (MICP) was established for injection qualification of high molecular weight polymers in low permeability carbonates. A novel class of hydrophobically modified acrylamides, also known as associative polymers, were investigated as an alternative to conventional HPAMs and synthetic polymers for injection in low permeability carbonates. The thermo-thickening properties of the associative polymers at elevated temperatures and salinities (with high divalent ions) and higher resistance to shear degradation makes them promising for carbonate reservoirs in comparison to HPAMs, where high polymer dosages are required due to significant viscosity loss in shear degradation. The apparent high viscosities generated from high resistance factors during flow in porous media for associative polymers can be advantageous for optimization of polymer dosage in chemical EOR processes. This work demonstrated a significant potential for application of associative polymers as an effective mobility control agent in carbonate reservoirs, especially in low permeability formations. The novel polymer treatment method for low permeability reservoirs was combined with the development of alkaline-surfactant-polymer (ASP) and surfactant-polymer (SP) technology for improvement of oil recovery in carbonates. The successful polymer transport in low permeability carbonates showed great potential for application of chemical EOR processes like ASP and SP in tight formations. Development of robust SP technology for high temperature and high salinity reservoirs also showed promising results in phase behavior experiments and coreflood experiments. This work demonstrated the benefits of SP technology with optimization of surfactant formulation and coreflood design for lower surfactant retention and higher oil recovery, thus making the process economical
Experimental investigation of surfactant flooding in fractured limestones
(2018-12-06) Mejia, Miguel, M.S. in Engineering; Balhoff, Matthew T.; Pope, G. A.
Carbonates are important candidates for enhanced oil recovery, but recovering oil from oil-wet fractured carbonate reservoirs is challenging. Waterflooding bypasses the rock matrix and recovers little oil. Chemical enhanced oil recovery using surfactants increases oil recovery by lowering the interfacial tension, changing the wettability, and generating viscous microemulsions that improve mobility control. Seven Texas Cream Limestone cores with a permeability of 15-30 md were fractured and saturated with 100% oil. The cores were aged for one week at 78 C to make them oil-wet. The fracture permeability was adjusted so that it was 10,000 times higher than the rock matrix by changing the confining stress. Waterflooding recovered an average of 6.5% of the original oil in place with an oil cut of less than 2% at the end of the waterfloods. Aqueous surfactant-alkali solution was injected after each waterflood. All of the surfactant floods produced oil cuts of more than 25% soon after injection started. Surfactant slugs of 3 PV, 1 PV and 0.3 PV followed by brine drives recovered 45, 44, and 30% of the remaining oil after the waterfloods. The 1 PV and 0.3 PV slug sizes were more efficient in terms of oil recovered for a given mass of injected surfactant. In both cases, a high salinity surfactant solution was injected to produce a viscous microemulsion in-situ. The viscous microemulsion increased oil recovery by promoting crossflow and improving mobility control. Low surfactant retention is vital for the economics of surfactant floods. The experiments show that using sodium hydroxide caused surfactant retention to be very low in fractured limestone cores. The average surfactant retention was 0.17 mg/g-rock. Decreasing the flow rate increased the oil recovery at a given injected pore volume. Thus changing practical design variables (salinity, surfactant slug size, flow rate) has a significant effect on oil recovery.
Experimental Study of CO2 Foam Flow in Porous Media and Application of Fractional-Flow Method to Foam Flow
(2001-08) Dong, Yang; Rossen, William R.
Foam flow in porous media is a complicated process. Recent research using N2 identified two distinct regimes for foam flow: a high- quality regime and a low-quality regime. Pressure gradient is independent of gas flow rate in the high-quality regime and independent of liquid flow rate in the low-quality regime. The purpose of this research is to see whether the two regimes exist for C02 foam. Previous studies with C02 have found one regime or the other, but not both. An apparatus was constructed to conduct high-pressure C02 foam core flooding experiments. The experiments were performed at room temperature of 740F and at pressures above 1500 psig. Surfactant solution and super-critical C02 were co-injected into Berea sandstone cores at various flow rates. Superficial velocities of surfactant solution and C02 ranged from 0.18-1.84 ft/d and 0.48-3.79 ft/d, respectively. The surfactant used was Chaser CD1045 at 0.25 wt % and 0.8 wt % concentration in a synthetic brine of 3 wt % NaCl and 0.01 wt % CaC12. Steady-state pressure drop along the core was recorded. In these results pressure gradient increases with increasing gas flow rate at constant liquid flow rate and decreases with increasing liquid flow rate at constant gas flow rate. The data from the experiments at different surfactant concentrations have the same trend of pressure gradient change with flow rates, but do not show the characters of either flow regime as seen with N2 foam or in other studies with C02. Fractional-flow methods were used to analyze and compare several foam models in the literature. Useful insights about the mechanisms controlling behaviors in these models are obtained from this analysis.
Experimental study of the benefits of sodium carbonate on surfactants for enhanced oil recovery
(2006-12) Jackson, Adam Christopher; Pope, G. A.; Britton, Larry N.
The objective of this work was to evaluate chemical interactions in phase behavior experiments that make surfactant-polymer formulations with alkali complex to design. This experimental study of sodium carbonate shows improvement of microemulsion phase behavior with many crude oils in addition to its classical use to produce soap in-situ and raise pH to reduce potential for surfactant adsorption. Soap is generally not sufficient by itself for chemical flooding because it has low tolerance to calcium ions and low optimal salinity. The blending of synthetic surfactant with sodium carbonate is needed to increase the optimum salinity, increase the tolerance to calcium, and reduce the sensitivity to changes in salinity by broadening the active salinity window. Sodium carbonate can also be added to the surfactant formulation to adjust electrolyte concentration for optimal salinity. Evidence suggests that additional consideration should be given to sodium carbonate in enhanced oil recovery applications because of benefits that extend beyond the traditional application. The research presented in this work discusses experiments that were conducted for the purpose of studying the benefits of sodium carbonate on surfactant phase behavior. After phase behavior screening, the formulations were tested to demonstrate their performance in porous media. Core floods were conducted to test the potential use of chemical flooding for a field application with several low acid crude oils. Two of the core flood experiments with Berea sandstone reduced the residual oil below 1% with chemical injection. An acceptable pressure gradient was maintained and good sweep was obtained using an AMPS polymer at high temperature. Polymer was needed to make the slug and drive sufficiently viscous to recover the mobilized oil and reduce surfactant retention through good sweep efficiency. The experiments reported in this research have contributed to an ongoing effort to design a suitable alkali-surfactant-polymer chemical formulation for the application in a high permeability, high temperature (85 ºC) sandstone reservoir located in Indonesia.
Foam assisted low interfacial tension enhanced oil recovery
(2010-05) Srivastava, Mayank; Nguyen, Quoc P.; Pope, Gary A.; Johns, Russel T.; Srinivasan, Sanjay; Bonnecaze, Roger T.
Alkali-Surfactant-Polymer (ASP) or Surfactant-Polymer (SP) flooding are attractive chemical enhanced oil recovery (EOR) methods. However, some reservoir conditions are not favorable for the use of polymers or their use would not be economically attractive due to low permeability, high salinity, or some other unfavorable factors. In such conditions, gas can be an alternative to polymer for improving displacement efficiency in chemical-EOR processes. The co-injection or alternate injection of gas and chemical slug results in the formation of foam. Foam reduces the relative permeability of injected chemical solutions that form microemulsion at ultra-low interfacial tension (IFT) conditions and generates sufficient viscous pressure gradient to drive the foamed chemical slug. We have named this technique of foam assisted enhanced oil recovery as Alkali/Surfactant/Gas (ASG) process. The concept of ASG flooding as an enhanced oil recovery technique is relatively new, with very little experimental and theoretical work available on the subject. This dissertation presents a systematic study of ASG process and its potential as an EOR method. We performed a series of high performance surfactant-gas tertiary recovery corefloods on different core samples, under different rock, fluid, and process conditions. In each coreflood, foamed chemical slug was chased by foamed chemical drive. The level of mobility control in corefloods was evaluated on the basis of pressure, oil recovery, and effluent data. Several promising surfactants, with dual properties of foaming and emulsification, were identified and used in the coreflood experiments. We observed a strong synergic effect of foam and ultra-low IFT conditions on oil recovery in ASG corefloods. Oil recoveries in ASG corefloods compared reasonably well with oil recoveries in ASP corefloods, when both were conducted under similar conditions. We found that the negative salinity gradient concept, generally applied to chemical floods, compliments ASG process by increasing foam strength in displacing fluids (slug and drive). A characteristic increase in foam strength was observed, in nearly all ASG corefloods conducted in this study, as the salinity first changed from Type II(+) to Type III environment and then from Type III to Type II(-) environment. We performed foaming and gas-microemulsion flow experiments to study foam stability in different microemulsion environments encountered in chemical flooding. Results showed that foam in oil/water microemulsion (Type II(-)) is the most stable, followed by foam in Type III microemulsion. Foam stability is extremely poor (or non-existent) in water/oil microemulsion (Type II (+)). We investigated the effects of permeability, gas and liquid injection rates (injection foam quality), chemical slug size, and surfactant type on ASG process. The level of mobility control in ASG process increased with the increase in permeability; high permeability ASG corefloods resulting in higher oil recovery due to stronger foam propagation than low permeability corefloods. The displacement efficiency was found to decrease with the increase in injection foam quality. We studied the effect of pressure on ASG process by conducting corefloods at an elevated pressure of 400 psi. Pressure affects ASG process by influencing factors that control foam stability, surfactant phase behavior, and rock-fluid interactions. High solubility of carbon dioxide (CO₂) in the aqueous phase and accompanying alkali consumption by carbonic acid, which is formed when dissolved CO₂ reacts with water, reduces the displacement efficiency of the process. Due to their low solubility and less reactivity in aqueous phase, Nitrogen (N₂) forms stronger foam than CO₂. Finally, we implemented a simple model for foam flow in low-IFT microemulsion environment. The model takes into account the effect of solubilized oil on gas mobility in the presence of foam in low-IFT microemulsion environment.
Foam assisted surfactant-gas flooding in naturally fractured carbonate reservoirs
(2018-01-26) Aygol, Hayrettin; Sepehrnoori, Kamy, 1951-; Lashgari, Hamid Reza
In naturally fractured reservoirs, water flood performance and efficiency for oil recovery is usually limited by capillary forces. Wettability and interfacial tension (IFT) between oil and water phases are essential factors that limit the potential for oil production in naturally fractured reservoirs. The permeability of such reservoirs is in range of 1~20 md (majority of carbonate reservoirs) with the matrix wettability preferentially oil-wet to mixed-wet. Hence, water and/or gas flood performances are not efficient due to the tendency of water or gas flow through fractures. Surfactants are used to reduce IFT between oil and water, alter the wettability of matrix to proficiently water-wet, and generate in-situ foam as a drive and for mobility control. Spontaneous imbibition between the fractures and the matrix is achieved by both wettability alteration and ultra-low interfacial tensions. Experimental studies show that co-injection or alternate injection of surfactant solution and gas are very promising to mobilize and solubilize the remaining oil. In this study, we overview to provide a technical background and review the literature extensively in order to understand surfactant flooding and foam performance in porous media. Results show that surfactants are induced to matrix through fractures not only by spontaneous imbibition, but also by foam that diverts surfactant solutions into low permeability matrix. The finding results by several authors in lab-scale indicate that surfactant type, foam properties, capillary pressure properties corresponding to different wetting states, and oil-water interfacial tension are crucial factors that significantly impact the efficiency of such processes. In general, summary of this work shows that foam plays a dominant role as a drive to displace the oil in matrix when capillary forces are not strong to retain the oil in presence of surfactants. Although there is very restricted work that claim foam efficiency in presence of oil, mobilized oils are displaced and moved toward fractures as pure oil bank (oil phase). Some laboratory measurements and simulation study reveal with both core and reservoir scales that such process provides great sweep efficiency and recover a significant amount of remaining oil from the matrix to fracture.
Implementation of a Dual Porosity Model in a Chemical Flooding Simulator
(1999-08) Aldejain, Abdulaziz A; Miller, Mark A; Sepehrnoori, Kamy
Naturally fractured reservoirs occur worldwide and constitute an important reservoir type. The main feature that distinguishes naturally fractured reservoirs from conventional reservoirs is the presence of fractures. These fractures offer permeability enhancement. However, most of the porosity, and therefore the oil, still exists in the matrix blocks between fractures, thus requiring the oil to be transferred into the fracture network before it can be recovered. Recovery by water imbibition derived by capillary forces offers an excellent means of expelling the oil from matrix blocks and into fractures. However, this mechanism leaves behind significant amounts of oil in the matrix block in the form of residual oil. Reducing the residual oil saturation in the matrix blocks could thus lead to a higher oil recovery. One method to accomplish this is through the use of surfactants. Numerical simulation of this process offers a means to better understand and evaluate the application of surfactants in naturally fractured reservoirs. This goal has been accomplished by taking advantage of an existing simulator, UTCHEM. UTCHEM is a 3D, multicomponent, multiphase, compositional, finite-difference simulator. Dual porosity modeling has been implemented in UTCHEM to accommodate simulation of naturally fractured reservoirs. This implementation is accomplished by adding source/sink terms to the fracture network equations to account for the matrix/fracture flow transfer for each matrix gridblock. The matrix blocks are discretized into subgrids to offer better transient flow description. The matrix-block equations are further decoupled from the fracture equations to minimize coding. In addition to the capability of handling surfactant applications in naturally fractured reservoirs, the simulator has many other applications. Tracer studies and the use of tracers in characterization of naturally fractured reservoirs, the use of polymers and the feasibility of such use in waterflooding of naturally fractured reservoirs, and the use of biodegradation processes in oil-spill cleanup are a few of the features available. The simulator has been verified against an analytical solution to a single phase, single-fracture tracer diffusion problem. The solution of a quarter-five-spot waterflood problem using ECLIPSE, a commercial reservoir simulator, has also been compared with the solution using UTCHEM to the same problem. Finally, the simulator has been used to study the effects of the use of polymers and surfactants to improve oil recovery.
Lighting up the stage : ultrafast dynamics of the reverse micelle interface
(2023-12) Garrett, Paul Loman; Baiz, Carlos R.; Lin , Yi-Chih; Webb, Lauren; Tabour , Daniel
Confined reaction environments are known to favorably impact many chemical and physical processes in biology, pharmaceutics, polymer and nanoparticle synthesis, catalysis, and separations. An ideal system for studying confined reaction environments is through utilizing reverse micelles. A reverse micelle is a type of microemulsion in surfactants aggregates containing nanoscopic pools of polar are liquid dispersed in a continuous nonpolar liquid. However, the effects of confinement on the free energy landscape of chemical and physical processes at the interface have not been fully explored. To investigate this, a combination of linear and ultrafast two-dimensional infrared spectroscopies, along with molecular dynamics simulations, are used. These techniques provide sub-picosecond temporal and atomistic structural resolution, enabling the identification of molecular interactions. By analyzing the observed interactions, dynamical information can be extracted with sub-picosecond time resolution. The surfactants at the reverse micelle interface serve as a vibrational probe, allowing for the detection of interactions between encapsulated species and the surfactant-water interface.
Molecular dynamics study of solvation phenomena to guide surfactant design
(2009-12) Dalvi, Vishwanath Haily; Rossky, Peter J.
Supercritical carbon-dioxide has long been considered an inexpensive, safe and environmentally benign alternative to organic solvents for use in industrial processing. However, at readily accessible conditions of temperature and pressure, it is by itself too poor a solvent for a large number of industrially important solutes and its use as solvent necessitates concomitant use of surfactants. Especially desirable are surfactants that stabilize dispersions of water droplets in carbon-dioxide. So far only molecules containing substantially fluorinated moieties e.g. fluoroalkanes and perfluorinated polyethers, as the CO₂-philes have proved effective in stabilizing dispersions in supercritical carbon-dioxide. These fluorocarbons are expensive, non-biodegradable and can degrade to form toxic and persistent environmental pollutants. Hence there is great interest in developing non-fluorous alternatives. Given the development of powerful computers, excellent molecular models and standardized molecular simulation packages we are in a position to augment the experiment-driven search for effective surfactants using the nanoscopic insights gleaned from analysis of the results of molecular simulations. We have developed protocols by which to use standard and freely available molecular simulation infrastructure to evaluate the effectiveness of surfactants that stabilize solid metal nanoparticles in supercritical fluids. From the results, which we validated against experimental observations, we were able to determine that the alkane-based surfactants, that are so effective in organic fluids, are ineffective or only partially effective in CO₂ because the weak C-H dipoles cannot make up for the energetic penalty incurred at the surfactant-fluid interface by CO₂ molecules due to loss of quadrupolar interactions with other CO₂ molecules. Though the effectiveness of purely alkane-based surfactants in carbon-dioxide can be improved by branching, they cannot approach the effectiveness of the fluoroalkanes. This is because the stronger C-F dipole can supply the required quadrupolar interactions and a unique geometry renders repulsive the fluorocarbons' electrostatic interactions with each other. We have also determined the source of the fluoroalkanes' hydrophobicity to be their size which offsets the effect of favourable electrostatic interactions with water. Hence we can provide guidelines for CO₂-philic yet hydrophobic surfactants.
Rational design of ternary blend organic solar cells based on block copolymer additives
(2016-07-05) Kipp, Dylan Robb; Ganesan, Venkat; Bonnecaze, Roger; Milliron, Delia; Truskett, Thomas; Verduzco, Rafael
We utilize a combined computational and experimental approach to study the influence of block copolymer additives on the morphological and device characteristics of organic solar cells based on the conjugated polymer/fullerene bulk heterojunction morphology. Our study is motivated by the question whether such block copolymer additives can be utilized to influence the phase separation morphologies, interfacial properties, and, therefore, the device efficiencies of such organic photovoltaic devices. Towards this objective, we split our project into 3 parts: 1.) We utilize Single Chain in Mean Field simulations to investigate the influence of block copolymers on the morphological and interfacial characteristics of the polymer/fullerene blend. Based on these simulations, we identify a design rule for the formation of the equilibrium, cocontinuous donor/acceptor morphologies that are believed to be desirable for efficient charge collection in organic photovoltaics. We utilize this design rule to identify a large collection of blend formulations that give rise to bicontinuous phases, and identify which of these select blend formulations result from comparable volume mixtures of donors and acceptors, which typically yield high device efficiencies in organic photovoltaics. 2.) Based on the predictions from (1), in experiments, we design thermally-stable morphologies with nanoscale domain sizes and percolating donor/acceptor pathways. We demonstrate the manner in which the experimental results agree with the simulations and, hence, establish the validity of our simulation method for predicting phase behavior. 3.) We develop a kinetic Monte Carlo-based method to predict the device performance characteristics of arbitrary donor/acceptor morphologies and couple the morphology and device-level simulations in sequence to identify the blend formulations and resulting morphological features that give rise to the best device performance overall. We demonstrate that, by appropriately tuning the HOMO and LUMO energy levels of the block copolymer additive, an energy cascade can be exploited to further improve charge separation and device efficiencies. In total, our project constitutes a predictive framework for designing new additive-based organic photovoltaic blend formulations with optimized device properties.
Selection and evaluation of surfactants for field pilots
(2011-05) Dean, Robert Matthew; Pope, Gary A.; Weerasooriya, Upali
Chemical flooding has been studied for 50 years. However, never have the conditions encouraging its growth been as good as right now. Those conditions being new, improved technology and oil prices high enough to make implementation economical. The objective of this work was to develop economical, robust chemical formulations and processes that recover oil in field pilots when properly implemented. This experimental study goes through the process of testing surfactants to achieve optimal phase behavior, coreflooding with the best chemical formulations, improving the formulation and testing it in more corefloods, and then finally recommending the formulation to be tested in a field pilot. The target reservoir contains a light (34° API, 10 cP), non-reactive oil at about 22° C. The formation is a moderate permeability (50 - 300 mD) sandstone with a high clay content (up to 13%). Different surfactants and surfactant mixtures were tested with the oil including alkyl benzene sulfonates (ABS), Guerbet alcohol sulfates (GAS), alkyl propoxy sulfates, and internal olefin sulfonates (IOS). The best formulation contained 0.75% TDA -13PO-SO₄, 0.25% C₂₀₋₂₄ IOS, 0.75% isobutanol (IBA), 1% Na₂CO₃, all which are mixed in a softened fresh water from a supply well. Corefloods recovered 93% of residual oil from reservoir cores. Core flood experiments were also done with the alkali sodium carbonate to measure the effluent pH in a Bentheimer sandstone core with a cation exchange capacity (CEC) of 2 meq/100g. Floods at frontal velocities of 100, 10, and 0.33 ft/D were performed with 0.3 pore volume slugs of 0.7% Na₂CO₃ at 86° C. The effluent was analyzed for ions and pH breakthrough. It was found that the pH breakthrough occurred before surfactant breakthrough would be expected as desired although the pH was lower at a frontal velocity of 0.33 ft/D than at the higher velocities. The Na₂CO₃ consumption was 0.244, 0.238, and 0.207 meq/100 g rock at velocities of 100, 10, and 0.33 ft/D, respectively. In addition, a no-alkaline formulation consisting of a new large hydrophobe ether carboxylate surfactant mixed with an internal olefin sulfonate was tested on an active oil and it successfully recovered 99% of the waterflood remaining oil from an Ottawa sand pack with no salinity gradient and no alkali. The final residual oil saturation after the chemical flood (S[subscript orc]) was only 0.005
Shooting lasers at soap : ultrafast dynamics at surfactant interfaces
(2021-06-10) Baryiames, Christopher Paul; Baiz, Carlos R.; Roberts, Sean; Elber, Ron; Brodbelt, Jennifer; Rosales, Adrianne
Surfactants, by virtue of their amphiphilicity, are used in a wide array of industries to solubilize and stabilize heterogeneous mixtures. However, despite their everyday use, the fundamental physical chemistry of these molecules is still poorly understood. To characterize the molecular interactions that give rise to desirable bulk properties, we use a combination of linear and ultrafast, two-dimensional vibrational spectroscopies in conjunction with molecular dynamics simulations. Together, these methods afford femtosecond temporal resolution and atomistic structural resolution, enabling us to quantify the type and number of intermolecular interactions. Sub-picosecond time resolution also enables us to measure the dynamics of these processes. By observing the surfactant-water interface, we show how detergent interactions with oil, aqueous media, and other surfactants all contribute to the interfacial environment.
Wettability & coalescence modulation of water droplets through surface engineering, surfactants and electrowetting
(2022-04-11) Lokanathan, Manojkumar; Bahadur, Vaibhav; Bogard, David; Mohanty, Kishore; Wang, Yaguo; Hajimirza, Shima
Fluidic separation of two or more immiscible fluids is a key process in several applications. While oil-water separation has been extensively studied, there remain significant avenues for further improvement in the effectiveness, energy consumption and speed of separation. This dissertation includes multiple fundamental studies on the influence of surface engineering (texture and chemistry), surfactants and electric fields towards enhancing separation by controlling wettability of droplets and droplet coalescence. The first task (Chapter 3) details a study of wettability of water (in oil) and oil (in water) on sub-millimeter/micro/nano textured surfaces fabricated on a variety of substrates (metals, polymers, elastomers). Importantly, all the fabrication processes employed involved non-cleanroom-based scalable techniques. Textured metal surfaces coated with Teflon AF were superhydrophobic (in oil) with very low roll-off angles (4°–7°). Uncoated textured metal surfaces were superoleophobic (in water) with roll-off angles of 3°–9°. Secondly, textured polymer and elastomer surfaces exhibited ultrahydrophobicity (in oil); however not all textured elastomers exhibited superoleophobicity (in water). Thirdly, droplet roll-off was not observed on any textured elastomer and polymer surface, despite very favorable contact angles, indicating that high contact angles do not always translate to superhydrophobicity/oleophobicity. Chapter 4 analyzes and quantifies the extent of wettability alteration of water droplets on a hydrophobic surface (in air) via the use of surfactants and electrowetting (EW). Nine surfactants were chosen from the categories of anionic, cationic and zwitterionic surfactants. EW further enhanced wettability of surfactant solutions, and further reduced the contact angle (CA) by as much as 35°. Interestingly, it was seen that the influence of EW in enabling CA reduction was reduced by the addition of surfactants at pre-CMC (critical micelle concentration) levels. Conversely, surfactants strengthened the influence of EW at higher concentrations. Finally, it was seen that at post CMC concentrations, the saturation contact angles were independent of surfactant concentrations. Chapter 5 analyses dielectrophoretic (DEP) control of a water droplet at the interface of two other immiscible liquids. An analytical model was developed which balances gravity, buoyancy, capillary, and dielectrophoretic forces to predict the change in the position of the droplet and the immersion angle. Experiments and analysis were conducted for Bond numbers ranging from 0.1 to 1.7, the latter being the critical size at which a droplet will ‘sink’ due to its weight. The predicted immersion angles and threshold voltage showed a good match with the measurements. Chapter 6 studies the influence of surfactant concentration, applied voltage, frequency and electrode geometry (spacing) on surface electrocoalescence for micron-scale water droplets in hydrocarbon media. Phase maps were developed for various electrocoalescence possibilities to identify the parameter space for significant coalescence using three dimensionless parameters: i) modified electric capillary number (Ca [superscript asterisk over subscript e], ii) frequency (τ), and iii) surfactant concentration (C*). Electrocoalescence effectiveness was quantified using the parameter (δ/α): δ is the droplet density/area and α is the fraction of surface not covered by droplets. Strong coalescence (no surfactant) corresponded to δ/α < 10 droplets/mm², with best-case δ/α = 1.6 droplets/mm², with no droplets < 20 µm diameter and electrocoalesced droplets as large as 750 µm. With surfactant, electrocoalescence weakened; parameter space for strong electrocoalescence progressively reduced with concentration. Nonetheless, electrocoalescence at all concentrations resulted in substantial radius enhancement (after/before electrocoalescence); measured ratio ranged from 3.1-6.3 in the parameter space of Ca [superscript asterisk over subscript e]: 3.3-4.9, and τ ≤ 1.25 ∗ 10⁻². This study also characterized droplet generation (via satellite droplet ejection (SDE)) of 2-10 µm radii droplets. SDE was seen to scale with voltage, frequency and concentration, and inversely with electrode spacing. Overall, it was shown that water droplets can be coalesced or generated using the same microfluidic device; the parametric space to enable fluidic separation and droplet generation was identified. Chapter 7 models the microfluidic system discussed in Chapter 6 using machine learning (ML) algorithms, such as artificial neural network (ANN), eXtreme gradient boosting (XGBOOST) and polynomial regression. Features such as voltage, frequency, electrode spacing, concentration and initial droplet density normalized with uncovered area ratio (δᵢ/αᵢ), were utilized to predict nine targets: uncovered area ratio (α [subscript f]), final droplet density normalized with uncovered area (δ [subscript f]/α [subscript f]), and seven droplet density distribution (radius) bins ranging up to 500 µm. The ANN was the most accurate and consistent among the three ML models with R² of 0.89. The model accurately predicted the droplet distribution bins for three distinct test cases consisting of good coalescence, poor coalescence and satellite droplet ejection (droplet generation). SHAP (Shapley Additive exPlanations) dependence plots highlighted the parametric influence of the features for each output. Overall, this dissertation has led to significant contributions in the field of droplet coalescence and generation. This multidisciplinary work has involved experiments, analytical modeling, numerical simulations and statistical modeling. The results show that surface engineering, surfactants and EW, in conjunction, offer powerful approaches to enhance droplet wettability and coalescence. This research impacts applications in energy (oil-water separation, enhanced oil recovery), pharmaceutical (droplet emulsion generation) and infrastructure (municipal and industrial water treatment, oil spills) areas.