Browsing by Subject "Surfactants"
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Item 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.Item 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.Item 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.Item 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.Item 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.Item Selection and evaluation of surfactants for field pilots(2011-05) Dean, Robert Matthew; Pope, Gary A.; Weerasooriya, UpaliChemical 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 0.005Item Surfactant Screening to Alter the Wettability and Aid in Acidizing Carbonate Formations(2013-02-26) Yadhalli Shivaprasad, Arun KumarSurfactant flooding in carbonate matrix acidizing treatment has been widely used for changing the wettability of the rock and to achieve low IFT values. Optimizing the type of surfactant and concentration for the specific oil field is very important in order to avoid formation damage and to reduce the treatment cost. We built an experimental procedure for screening the right surfactant to alter the wettability and aid in acidizing of Pekisko formation, Canada, which is strongly oil-wet and has high viscosity oil. Five surfactants were tested out of which three are cationic, one amphoteric and the other one was a fluoro-surfactant. Measurements were made of interfacial tension with different surfactant types/concentrations in brine with the oil and xylene, critical micelle concentration of each surfactant, solubility characteristics of the surfactants, compatibility of the chemical additives, wettability of the core after treating with surfactants, and core flooding in the laboratory to simulate matrix acidizing. From the results obtained we noted that the fluoro-surfactant can cause formation damage due to precipitation in the brine. So the compatibility of every chemical additive should be tested first. The use of xylene as a pre-flush solution lowered the CMC and hence reduced the cost of the surfactant treatment. Aromox, an amine based surfactant was best suited for matrix acidizing treatment of the Pekisko formation.