Aqueous Stability Tests Research Articles

Emulsion Formation in Palm Oil Methyl Ester Sulfonate Surfactant to Light Crude Oil

The Enhanced Oil Recovery method is a method that can be attempted to increase the recovery of petroleum. One of the materials that can be used is Methyl Ester Sulfonate surfactant from palm oil, as a vegetable surfactant whose raw materials are widely available in Indonesia. In this study, the compatibility test of Methyl Ester Sulfonate surfactant was carried out on light crude oil type T samples. The study was carried out with various surfactant concentrations, starting from 0.25%, 0.3%, 1%, 1.5%, and 2%. In the aqueous stability test, the results obtained for all clear conditions for the surfactant concentration were measured for 3 days in an oven with a temperature of 60oC. Whereas in the phase behavior test, good results of the upper phase emulsion were obtained at concentrations of 0.3%, 1%, 1.5%, and 2%. The volume of the top phase emulsion ranges from 25% to 37.5%. (Normal). From the results of this study, it can be concluded that for the crude oil sample T, palm oil MES surfactant is stable for use as a surfactant injection fluid, with a surfactant concentration composition that produces a fairly large upper phase emulsion of around 25% - 37.5% at a surfactant concentration of 0.5% - 2%.

Dynamic Monitoring and Enhanced Oil Recovery Evaluation of the Water Flooding Process of Liquid Nanofluids in Tight Reservoirs

The CT scanning technology can observe fluid saturation distribution in the rock at different times during water flooding in tight reservoirs. However, this technology has not been used to study the water flooding characteristics in changing the wettability of liquid nanofluids. First, this study evaluated the basic properties of a nonionic liquid nanofluid, including the contact angle (CA), interfacial tension (IFT), and aqueous stability tests. Then, the water flooding process in tight rocks is dynamically monitored by the CT scanning technology. The water flooding characteristics of liquid nanofluids changing reservoir wettability are analyzed by measuring the rock’s water phase saturation distribution at different times. Finally, the spontaneous imbibition experiment evaluated the enhanced oil recovery of liquid nanofluids. The results show that the particle size of the liquid nanofluid is at the nanometer level (7.5 nm) and can change the wettability of oil-wet to water-wet. Liquid nanofluid has low interfacial tension and can exist stably in brine with a high salinity (20,000–50,000 ppm). In water flooding, the front profile of water phase saturation changes obviously, and it is driven forward with a similar “piston” type. Compared with the brine water, the water invasion front gradually becomes uniform, which is strong evidence that a liquid nanofluid can change the wettability of rocks. Besides, the invasion depth of the fracturing fluid with liquid nanofluids is deeper than that of brine water and displaces more oil. Finally, the spontaneous imbibition test shows that the recovery factor of high-concentration (1 wt %) liquid nanofluids increases by 28.9% compared with that of brine water. This paper provides theoretical support for applying liquid nanofluids in tight reservoirs.

Chemical characteristics, leaching, and stability of the ubiquitous tire rubber-derived toxicant 6PPD-quinone.

We here report chemical characteristics relevant to the fate and transport of the recently discovered environmental toxicant 6PPD-quinone (2-((4-methylpentan-2-yl)amino)-5-(phenylamino)cyclohexa-2,5-diene-1,4-dione or "6PPDQ"). 6PPDQ is a transformation product of the tire rubber antioxidant 6PPD that is ubiquitous in roadway environments, including atmospheric particulate matter, soils, runoff, and receiving waters, after dispersal from tire rubber use and wear on roadways. The aqueous solubility and octanol-water partitioning coefficient (i.e. log KOW) for 6PPDQ were measured to be 38 ± 10 μg L-1 and 4.30 ± 0.02, respectively. Within the context of analytical measurement and laboratory processing, sorption to various laboratory materials was evaluated, indicating that glass was largely inert but loss of 6PPDQ to other materials was common. Aqueous leaching simulations from tire tread wear particles (TWPs) indicated short term release of ∼5.2 μg 6PPDQ per gram TWP over 6 h under flow-through conditions. Aqueous stability tests observed a slight-to-moderate loss of 6PPDQ over 47 days (26 ± 3% loss) for pH 5, 7 and 9. These measured physicochemical properties suggest that 6PPDQ is generally poorly soluble but fairly stable over short time periods in simple aqueous systems. 6PPDQ can also leach readily from TWPs for subsequent environmental transport, posing high potential for adverse effects in local aquatic environments.

Synthesis, insecticidal activity and stability study of novel nitromethylene neonicotinoids with five-membered aromatic heterocycles

Twenty-four novel neonicotinoid analogues with nitromethylene and five-membered aromatic heterocycles were designed and synthesized. All target molecular structures have been confirmed by analytical and spectral data. Some compounds exhibited notable insecticidal activities against aphid (Aphis medicaginis) and brown planthopper (Nilaparvata lugens). The aqueous stability test confirmed that the stabilities of those compounds were superior to the leading compound, and the photostability was even better than that of imidacloprid.

Increasing Reservoir Recovery Efficiency through Laboratory-Proven Hybrid Smart Water-Assisted Foam (SWAF) Flooding in Carbonate Reservoirs

This contribution introduces a new hybrid enhanced oil recovery (EOR) method which combines smart water-assisted foam (SWAF) flooding, known as the SWAF process. The concept of applying SWAF flooding in carbonate reservoirs is a novel approach previously unexplored in the literature. The synergy effect of the SWAF technique has the potential to mitigate a number of limitations related to individual (i.e., conventional water injection and foam flooding) methods encountered in carbonates. In general, carbonate rocks are characterized by a mixed-wet to oil-wet wettability state, which contributes to poor oil recovery. Hence, the smart water solution has been designed to produce a dual-improvement effect of altering carbonate rock wettability towards more water-wet, which preconditions the reservoir and augments the stability of the foam lamellae, which has for some conditions more favorable relative permeability behavior. Then the smart water solution is combined with surfactant (surfactant aqueous solution or SAS) and gas injection produces a synergy effect, which leads to more wettability alteration, and interfacial tension (IFT) reduction, and thus improves the oil recovery. Accordingly, to determine the optimal conditions of smart water solution with an optimal SAS, we conducted a series of experimental laboratory studies. The experimental design is divided into three main steps. At first, the screening process is required so that the candidates can be narrowed down for our designed smart water using the contact angle tests that employ calcite plate (i.e., Indiana limestone or ILS) as the first filter. Following this, the optimum smart water solutions candidates are blended with different types of cationic and anionic surfactants to create optimum SAS formulations. Subsequently, a second screening process is performed with the aim to narrow down the SAS candidates with varying types of gases (i.e., carbon dioxide, CO2 and nitrogen, N2) via the aqueous stability test (AST), foamability test (FT), and foam stability test (FST). We employed the state-of-the-art R5 parameter tests for rapid and accurate results in place of the conventional foam half-life method. The most effective combination of SAS and gas candidates are endorsed for the core-flooding experiments. In this work, two types of crude oils (Type A and B) with different total acid and base numbers (TAN and TBN). Results showed that the greatest wettability changes occurred for SW (MgCl2) solution at 3500 (ppm) for both crude oil types. This demonstrates the efficacy of our designed SW in the wettability alteration of carbonates, which is also supported by the zeta-potential measurements. The concentrations of both SW (MgCl2) and CTAB-based surfactants considerably affect the stability of the SAS (i.e., up to 90% foam stability). However when in the presence of crude oil, for the same SAS solution, the foam stability is reduced from 90% to 80%, which indicates the negative effect of crude oil on foam stability. Moreover, the core floods results showed that the MgCl2-foam injection mixture (MgCl2 + CTAB + AOS + N2) provided the highest residual oil recovery factor of SWAF process of 92% cumulative recovery of original oil in core (OIIC). This showcases the effectiveness of our proposed SWAF technique in oil recovery from carbonate reservoirs. Additionally, changing the large slug of 5 PVs to a small slug of 2 PVs of smart water solution was more effective in producing higher OIIC recovery and in reducing the fluid circulation costs (i.e., thereby, lowering CO2 footprint), making the SWAF process environmentally benign. Thus, it is expected that under optimum conditions (SW solution and SAS), the novel SWAF process can be a potentially successful hybrid EOR method for carbonate reservoirs, having both economic and environmental benefits.

SURFACTANT PROPERTIES EVALUATION FOR CHEMICAL FLOODING

The need of EOR techniques in the late field production period is essential to get the third wind of incremental oil. Chemical injections are proven technologies not only at the laboratory scale but also at the field scale which have been implemented in many parts of the world. Surfactant is an important chemical in this technology, which mostly has been used to reduce the capillary trap of the oil in the reservoirs. The selection of surfactant type which is suitable for a specific oil field to increase the oil production should fulfill the selection criteria. Laboratory works firstly should be done to evaluate the important properties based on the industrial standard procedures. These laboratory tests include compatibility test, aqueous stability test, phase behavior study, micro-emulsion viscosity, interfacial tension determination, thermal stability test, and filtration test.

The Study of Flow Behavior and Performance of Polymer Injection in Homogenous Porous Media Using Etched Micromodel

The implementation of polymer injection on a field scale needs a preliminary laboratory test to analyze the performance and flow behavior of polymer injection in a porous media. Compared to coreflooding method, micromodel provides the visualization of oil displacement mechanism and facilitating a more detailed process description. Understanding the effect of polymer concentration on the incremental of oil recovery factor and its displacement mechanism are essential to know the polymer injection performance with the intention of avoiding failures in the implementation of polymer injection at field scale. We used dry etching technique for the fabrication of acrylic micromodel with homogenous characteristic. In this work, pre-flush (waterflooding) is performed first before doing the polymer injection to determine the incremental oil recovery factor and analyze the effect of polymer concentration on oil recovery factor enhancement in homogenous porous media. They were positioned horizontally then saturated with synthetic brine and light crude oil as the initial condition before starting the injection scenario. The experiment was conducted at room temperature. The entire process of micromodel flooding test was monitored by camera and then for the further analysis was done using Digital Image Analysis (DIA). According to the polymer rheology and aqueous stability test, it can be proven that polymer is a non-newtonian fluid indicated by shear thinning behavior and it can be observed that FP3630S polymer is a good candidate for micromodel flooding test. The micromodel flooding result confirmed that the increasing of polymer concentration will result in higher incremental oil recovery factor. In addition, based on the final condition of the micromodel after the polymer injection process, there is improvement of sweep efficiency due to the front stability resulted by the decreasing of mobility ratio between displacing fluid (polymer solution) and the oil bank.

Surfactant-EOR in tight oil reservoirs: Current status and a systematic surfactant screening method with field experiments

Tight oil reservoirs typically have an estimated ultimate recovery of less than 10% after hydraulic fracturing, where enhanced oil recovery (EOR) technique is needed. Comparing to the gas-EOR, the surfactant-EOR neither alters the current fracturing procedure nor requires special injection facilities, and thus can be economically-viable under the current environment of low oil prices. However, tight rocks have small pores and large specific surface areas, which can make the adsorption rate of surfactants significant and thus limit the penetration depth of surfactants and its enhancement on oil recovery. In the published studies on the surfactant-EOR for shales and other tight reservoirs, this key parameter is only measured with the crushed rock samples, which can be underestimated comparing to that in the intact rock. Moreover, the dispersion coefficient that determines the penetration speed of a surfactant has never been directly measured in the tight rock, and the potential interaction between the surfactant and the friction reducer has neither been studied. In this study, a new form of surfactants is introduced, in which the wettability-alteration surfactants are firstly synthesized into oil-in-water microemulsions and then diluted to a designed concentration in the fracturing fluid. The thermodynamically-stable structure of microemulsion can minimize the adsorption rate of surfactants when transporting in the tight rock. Using coreflood experiments with UV–vis spectroscopy, the adsorption rate and dispersion coefficient of this form of surfactants are directly measured in tight rocks with a range of permeabilities, which are key parameters to modeling the EOR process and further scaling up laboratory findings for designing a field operation. To ensure the success of the surfactant-EOR technique in the field, the chosen surfactant needs to pass the preliminary screening including the aqueous stability test, the emulsion tendency test, the oil-water IFT measurement, and the shearing test; besides, it is also crucial to examine the compatibility between the slickwater and the wettability-alteration surfactant with different electric charges, which is seldom reported yet. In the end, the chosen surfactant is tested in two pairs of horizontal wells on one pad site, whose flowback water is collected and analyzed for better understanding the behavior of this surfactant.

Laboratory Analysis of Foam Generating Surfactants and Their Thermal Stability for Enhanced Oil Recovery Application

The residual oil after primary or secondary oil recovery can be recovered by the methods of EOR (Enhanced Oil Recovery). The objective of this study is screening the surfactants that generate maximum stable foam in the presence of brine salinity at 92oC. Laboratory experiments have been performed to examine and compare the stability of generated foam by individual and blended surfactants in the synthetic brine water. AOS C14-16 (Alpha Olefin Sulfonate) and SDS (Sodium Dodecyl Sulfonate) were selected as main surfactants. Aqueous stability test of AOS C14-16 and SDS with brine water salinity 62070ppm was performed at 92oC. AAS (Alcohol Alkoxy Sulfate) was blended with SDS and AOS C14-16. The solution was stable in the presence of brine salinity at same conditions. Salt tolerance experimental study revealed that AOS C14-16 did not produce precipitates at 92oC. Further, the foam stability of surfactant blend was performed. Result shows that, the maximum life time of generated foam was observed by using blend of 0.2wt% SDS+0.2wt% AOS+0.2wt% AS-1246 and 0.2wt% AOS+0.2wt% IOSC15-18+0.2wt% AAS surfactants as compared to the foam generated by individual surfactants. The success of generated foam by these surfactant solutions in the presence of brine water is the primary screening of surfactant stability and foamability for EOR applications in reservoirs type of reservoirs.

Poly(Oxyethylene)-Amidoamine Based Gemini Cationic Surfactants for Oilfield Applications: Effect of Hydrophilicity of Spacer Group.

Thermal stability, salt tolerance, and solubility in normal and high salinity brine are the major requirements for any surfactant designed for oilfield applications because the surfactant stays in a non-ambient environment inside the reservoir for a long period of time. Herein, a series of new gemini cationic surfactants (GSs) with varying spacer hydrophilicity were synthesized and elucidated using MALDI-ToF-MS, NMR (1H, 13C), as well as FTIR spectroscopy. GSs found to be soluble in normal as well as high salinity brine and aqueous stability tests revealed that GSs possess the ability to retain their structural integrity at high salinity and high temperature conditions because no suspension formation or precipitation was detected in the oven aged sample of GSs at 90 °C for 30 days. Thermal gravimetric analysis displayed a higher decomposition temperature than the real reservoir temperature and the GS with a secondary amine spacer exhibited high heat stability. The significant reduction in surface tension and critical micelle concentration was observed using 1 M NaCl solution in place of deionized water. The difference in surface tension and critical micelle concentration was insignificant when the 1 M NaCl solution was replaced with seawater. The synthesized surfactants can be utilized for oilfield applications in a challenging high temperature high salinity environment.

The alternative solutions of bagasse waste utilization to improve recovery factors in reservoir with high salinity

Surfactant injection is one of the EOR methods used to increase oil recovery. Using of surfactants is intended to reduce the interface tension between oil and water. The types of surfactants commonly used are oil-based surfactants, such as petroleum sulfonate. This condition causes the price of surfactants very dependent on oil prices. As efficient alternative, research on plant-based surfactants sourced from nature is being developed. Like the type of surfactant that will be used in this study is Sodium Lignosulfonate (NaLS) sourced from bagasse waste. The purpose of this study is to add reference of the characteristics of the NaLS surfactant to be used optimally. The screenings in this experiment were Aqueous Stability test, phase behaviour test, and IFT test on 1.5% NaLS concentration and high salinity 75,000 ppm Nacl. The results of aqueous stability test are transparent, the results of phase behaviour test are middle phase emulsion with an emulsion percent of 8.75%, and the results of IFT test obtained value of 1.98 mN/m. Based on these results, surfactants meet the screening parameters so can proceed to the injection stage for determine the value of recovery factor. Recovery factor result for NaLS bagasse waste based surfactant injection is 4.74%.

Silica and Graphene Oxide Nanoparticle Formulation To Improve Thermal Stability and Inhibition Capabilities of Water-Based Drilling Fluid Applied to Woodford Shale

SummaryDrilling-fluid design for shale plays aims to deal with the lack of wellbore stability associated with fluid-invasion, shale-swelling, and cuttings-dispersion phenomena. Although oil-based mud can be used to achieve these goals, environmental and economic concerns limit its application. This research evaluates the potential of using silica (SiO2) nanoparticles (NPs) (SiO2-NPs) and graphene nanoplatelets (GNPs) as drilling-fluid additives in a single formulation to improve shale inhibition and long-term stability of water-based mud (WBM) against temperature effects. The design of the nanoparticle WBM (NP-WBM) followed a customized approach that selects the additives according to the characteristics of the reservoir. Characterization of Woodford shale was completed with X-ray diffraction (XRD), cation-exchange capacity (CEC), and scanning electron microscopy (SEM). The aqueous-stability test and ζ-potential measurements were used to assess the stability of the NPs. NP-WBM characterization included the analysis of the rheological properties measured with a rotational viscometer and the evaluation of the filtration trends at low-pressure/low-temperature (LP/LT) and high-pressure/high-temperature (HP/HT) conditions. In addition, dynamic aging was performed at temperatures up to 250°F for thermal-stability evaluation. Finally, chemical-interaction tests, such as cutting dispersion and bulk swelling, helped to analyze the effect of introducing NPs on the inhibition capabilities of the WBM. Conventional potassium chloride (KCl)/partially hydrolyzed polyacrylamide (PHPA) fluid was used for comparison purposes. The results of this investigation revealed that SiO2-NPs and GNPs acted synergistically with other additives to improve the filtration characteristics of the WBM, with only minor effects on the rheological properties. NPs exhibited high colloidal stability with ζ-potential values less than –30 mV, which warrants their dispersion within the WBM at an optimal concentration of 0.75 wt%. The high thermal conductivity of NPs played a key role in promoting a nearly flat trend in the cumulative filtrate for the NP-WBM at aged conditions, whereas KCl/PHPA suffered a dramatic increase. Also, NP-WBM preserved 43.97% of its initial cuttings-carrying capacity, whereas KCl/PHPA experienced a severe reduction of 95.24% at extreme conditions (250°F). Despite the high illite content of the Woodford shale, the NP-WBM exhibited superior inhibition properties that reduced cuttings erosion and swelling effect by 24.48 and 35.24%, respectively, compared with the KCl/PHPA fluid. Overall, this investigation supports the potential use of nanomaterials to enhance the inhibition capabilities and the long-term stability of WBM for unconventional shales, presenting an environmentally friendly alternative for harsher environments.

Design and characterization of a heterocyclic electrophilic fragment library for the discovery of cysteine-targeted covalent inhibitors.

A fragment library of electrophilic small heterocycles was characterized through cysteine-reactivity and aqueous stability tests that suggested their potential as covalent warheads. The analysis of theoretical and experimental descriptors revealed correlations between the electronic properties of the heterocyclic cores and their reactivity against GSH that are helpful in identifying suitable fragments for cysteines with specific nucleophilicity. The most important advantage of these fragments is that they show only minimal structural differences from non-electrophilic counterparts. Therefore, they could be used effectively in the design of targeted covalent inhibitors with minimal influence on key non-covalent interactions.

Heterocyclic electrophiles as new MurA inhibitors.

An electrophilic fragment library of small heterocycles was developed and characterized in the surrogate GSH-reactivity assay and aqueous stability test that revealed their potential as covalent warheads. Screening the library against MurA from Staphylococcus aureus (MurASA ) and Escherichia coli (MurAEC ) identified heterocyclic fragments with significant inhibitory potency. The validated heterocyclic warhead library might be useful for developing targeted covalent inhibitors for other targets of interest with a new design strategy incorporating heterocyclic electrophiles as warheads.

Best Practices for the Synthesis, Activation, and Characterization of Metal–Organic Frameworks

Metal–organic frameworks (MOFs) are structurally diverse materials comprised of inorganic and organic components. As the rapidly expanding field of MOF research has demonstrated, these materials are being explored for a wide variety of potential applications. In this tutorial review, we give an overview of the current best practices associated with the synthesis, activation, and characterization of MOFs. Methods described include supercritical CO2 activation, single crystal X-ray diffraction (XRD), powder X-ray diffraction (PXRD), nitrogen adsorption/desorption isotherms, surface area calculations, aqueous stability tests, scanning electron microscopy (SEM), inductively coupled plasma optical emission spectroscopy (ICP-OES), nuclear magnetic resonance spectroscopy (NMR), and diffuse reflectance infrared Fourier transform spectroscopy (DRIFTS). A variety of different MOFs are presented to aid in the discussion of relevant techniques. In addition, some sections are accompanied by instructional videos to giv...

Study of blended surfactants to generate stable foam in presence of crude oil for gas mobility control

For controlling the viscous fingering in water-alternating gas injection, addition of foam with formation water is more favorable. Use of foam surfactant is one potential solution for reducing gas mobility. The main objective of this research is to generate stable foam for gas mobility control using surfactant blend formulation. Surfactant blends synergistically exhibit better foaming properties than those of individual surfactants. Surfactant blends improve the foam stability and reduces the destabilizing effect of crude oil. Using foam stabilizers may improve foam stability and apparent viscosity; both of these factors are important for improving gas mobility. Alpha olefin Sulfonate (AOSC14-16) was selected as main surfactant, Octylphenol Ethylene Oxide (TX-100) and Lauryl Amido Propyl Amine oxide (LMDO) were selected as additives. Aqueous stability test was performed at 96 °C. Foam stability test was performed in the absence and presence of crude oil. The foam stability and longevity was recorded above the liquid level. Liquid drainage and Foam half-life were noted with respect to time. The mobility reduction factor of three formulations was performed with CO2 by using Berea sandstone cores at 96 °C and 1400 psi. Experimental result showed that surfactant blend of 0.6 % AOS + 0.6 % LMDO was more stable in presence of crude oil and reduced more gas mobility as compared to an individual surfactant of 0.6 % AOS. The maximum generated foam volume and foam half time indicated better performance of the foaming agent. The surfactant blend formulation plays an important role in controlling gas mobility. Strong stability by these formulations indicates that the foam surfactant formulation is of great significance in the field of enhanced oil recovery.

New Correlation for Optimizing the Surfactant Structure for EOR

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 154262, ’New Correlation To Predict the Optimum Surfactant Structure for EOR,’ by Sriram Solairaj, SPE, Christopher Britton, SPE, Jun Lu, SPE, Do Hoon Kim, SPE, Upali Weerasooriya, SPE, and Gary A. Pope, SPE, The University of Texas at Austin, prepared for the 2012 SPE Improved Oil Recovery Symposium held in Tulsa, 14-18 April. The paper has not been peer reviewed. The oil-recovery efficiency of chemical enhanced oil recovery (EOR) depends on the phase behavior of the microemulsion and on interfacial tension (IFT). The surfactants needed to obtain good phase behavior and ultralow IFT vary greatly, depending on oil characteristics and reservoir conditions. Many new surfactants have been introduced with widely different structures and formulations for application to a wider range of oils and temperature. A new correlation has been developed that uses an extensive data set, taking into account the effects of the propylene oxide number (PON), ethylene oxide number (EON), temperature, brine salinity, and the equivalent alkane carbon number (EACN) of the oil. The new correlation can help identify the most important variables and improve our understanding of the relationship between the variables that affect the optimum surfactant structure. Introduction There was a need for an explicit correlation between the optimum surfactant structure and the most important formulation variables, including parameters for new-generation surfactants, to assist with understanding the complex relationship among important formulation variables and as a guide for efficient selection of the best surfactant structures to be evaluated rigorously in the laboratory for specific oils and conditions. Because the objective was to determine the relationship among the variables for an optimum surfactant structure, only experimental data for optimized formulations were used in the regression analysis. This point is fundamental and must be understood clearly. Many measurements are made for surfactant formulations that have unacceptable behavior (e.g., the IFT is too high). These data were not used to develop the new correlation. Only data for good formulations were used, clearly affecting the outcome of the results. Microemulsion-Phase-Behavior Procedure and Screening Criteria The experiments consisted of micro-emulsion-phase-behavior tests and aqueous-stability tests. Microemulsion-phase-behavior observations are a fast and effective method to screen hundreds of surfactant mixtures and to determine the effects of formulation variables such as salinity, temperature, EACN, surfactant concentration, cosolvent concentration, and water/oil ratio. Qualitative observations regarding microemulsion type, microemulsion viscosity, IFT, equilibration time, and other factors are made visually on all samples over a period of days or weeks, where-as quantitative measurements are made on only a few samples and only after equilibration of the most-promising formulations. Formulations that formed a low-viscosity microemulsion with ultralow IFT and that passed the aqueous-stability test were selected as optimum formulations. Sealed ampoules, at reservoir temperature, were observed for several days, weeks, or in some cases months to determine the stability of the chemicals. The surfactants used in this study included mixtures of several anionic surfactants, including internal olefin sulfonates, alcohol propoxy sulfates, large-hydrophobe Guerbet alkoxy sulfates, and large-hydrophobe Guerbet alkoxy carboxylates.