Surfactant Retention Research Articles

Interactive roles of co-solvents and lemon-oil composition in the fabrication of dilutable clear emulsions

Clear emulsions are used as flavor carriers by the beverage industry because of their favorable optical properties. A transparent microemulsion with small droplets requires a high concentration of surfactants, and is often non-dilutable, posing a significant challenge to their application in the food industry. The formation of dilutable microemulsions by modulating the compatibility of oil composition and co-solvents was studied. While single-fold lemon oil exhibited poor loading capacity overall, no precipitation occurred due to the stronger interaction between monoterpenes and sucrose monopalmitate (SMP). Conversely, emulsification of five-fold lemon oil with 20 % ethanol demonstrated a higher loading capacity and a stronger dilution stability than other lemon oils. This is likely due to the balanced composition of surface-active monoterpenes and other components in five-fold lemon oil which facilitated the effective use of micellar space and aided in the retention of both surfactants and co-solvents post-dilution. The emulsification of higher-folded lemon oil, however, was favored by the use of propylene glycol as a surfactant exhibiting stronger dilution stability than ethanol, though it required twice as much co-solvent. The high concentration of surface-active monoterpene in the lower-folded lemon oils competes with propylene glycol for interfacial incorporation. This study demonstrated that co-solvents and oil composition play interactive roles in producing dilutable optically clear emulsions, and it provides a blueprint for the food industry to design colloidal systems using a minimum of surfactants.

Influence of surfactant molecular features on tetracycline transport in saturated porous media of varied surface heterogeneities

This study aims to understand how surfactants affect the mobility of tetracycline (TC), an antibiotic, through different aquifer media. Two anionic and cationic surfactants, sodium dodecylbenzene sulfonate (SDBS) and cetyltrimethyl ammonium bromide (CTAB), were used to study their influence on TC mobility through clean sand and humic acid (HA)-coated sand. HA coating inhibits TC mobility due to its strong interaction with TC. Both surfactants promoted TC mobility at pH 7.0 due to competitive deposition, steric effect, and increased hydrophilicity of TC. CTAB had a more substantial effect than SDBS, related to the surfactants' molecular properties. Each surfactant's promotion effects were greater in HA-coated sand than in quartz sand due to differences in surfactant retention. CTAB inhibited TC transport at pH 9.0 due to its significant hydrophobicity effect. Furthermore, in the presence of Ca2+, SDBS enhanced TC transport by forming deposited SDBS-Ca2+-TC complexes. On the other hand, CTAB increased TC mobility due to its inhibition of cation bridging between TC and porous media. The findings highlight surfactants' crucial role in influencing the environmental behaviors of tetracycline antibiotics in varied aquifers.

Retention of Surfactant by Solid–Liquid Interaction and the Process of Improving Oil Recovery by Inducing Hydrophilic Particles

Retention of Surfactant by Solid–Liquid Interaction and the Process of Improving Oil Recovery by Inducing Hydrophilic Particles

Experimental Evaluation of Blends Containing Lineal Alkylbenzene Sulfonates for Surfactant Flooding in Carbonate Reservoirs

Summary About one-half of the proven conventional oil reserves are in carbonate reservoirs. However, conducting surfactant flooding in these reservoirs presents several challenges, including formation heterogeneities, surfactant retention, high temperature and salinity, and oil-wet/mixed-wet conditions. Linear alkylbenzene sulfonates (LASs) are low-cost anionic surfactants that tend to precipitate in high-salinity environments and show high adsorption values in carbonate material. In this paper, the possibility of using petrochemical LASs of different alkyl chain lengths and isomer content to extract oil from carbonate reservoirs was tested using blends with the ionic liquid cocosalkylpentaethoximethylammonium methylsulfate (C1EG). Phase behavior, stability in the presence of divalent ions, and interfacial tension (IFT) measurements were the criteria used to design several optimal formulations containing 36–45% LASs. The structure-performance relationship was further assessed via static adsorption and wettability tests. LASs enriched in isomers with the benzenesulfonic group in external positions of the alkyl chain resulted in lower IFT but significantly higher adsorption, so those surfactants were discarded for the application. Additional oil recoveries achieved with tested formulations ranged from 36.7% to 43.5% of the residual oil in place. The longer the alkyl chain length, the higher the oil recovery. The main mechanism associated with improved oil recovery is IFT reduction. The use of a cost-effective ionic liquid derived from natural raw materials, the stability of the blends, the low adsorption of the chemical, and a significant oil recovery ensure the overall feasibility of the proposal.

Novel Surfactant Compatibility with Downstream Protein Bioprocesses

Downstream processing of antibodies consists of a series of steps aimed at purifying the product and ensuring it is delivered to formulators structurally and functionally intact. The process can be complex and time-consuming, involving multiple filtrations, chromatography, and buffer exchange steps that can interfere with product integrity. This study explores the possibility and benefits of adding N-myristoyl phenylalanine polyether amine diamide (FM1000) as a process aid. FM1000 is a nonionic surfactant that is highly effective at stabilizing proteins against aggregation and particle formation and has been extensively explored as a novel excipient for antibody formulations. In this work, FM1000 is shown to stabilize proteins against pumping-induced aggregation which can occur while transporting them between process units and within certain processes. It is also shown to prevent antibody fouling of multiple polymeric surfaces. Furthermore, FM1000 can be removed after some steps and during buffer exchange in ultrafiltration/diafiltration, if needed. Additionally, FM1000 was compared to polysorbates in studies focusing on surfactant retention on filters and columns. While the different molecular entities of polysorbates elute at different rates, FM1000 flows through purification units as a single molecule and at a faster rate. Overall, this work defines new areas of application for FM1000 within downstream processing and presents it as a versatile process aid, where its addition and removal are tunable depending on the needs of each product.

Surfactant formulation development for shallow reservoirs with high clay content

Sandstone reservoirs with high clay content can potentially adsorb large amounts of surfactants making the chemical flood processes unattractive. The objective of this work was to develop an alkaline-surfactant-polymer (ASP) process for a shallow, clayey sandstone reservoir to minimize surfactant retention. The phase behavior study was conducted to identify commercially available surfactants that display ultralow interfacial tension behavior. The selected surfactant formulations were tested in tertiary ASP core floods in outcrop and reservoir rocks. Many surfactant formulations were identified which gave ultralow IFT, but the formulation with only one surfactant (at 0.5 wt% concentration) in presence of one co-solvent was selected for core floods. The cumulative oil recovery was in the range of 92–96% of the original oil in place (OOIP) in the core floods. The surfactant retention was low (0.15 mg/gm of rock) in spite of the high clay content due to the use of alkali. The study showed that 0.5 PV of ASP slug and 2700 ppm of the polymer were required to make the flood effective. Injection of the ASP slug immediately after the field brine flood with divalent ions did not cause any plugging or adverse effect. The novelty of this work lies in designing ASP formulations with a single surfactant and reducing the residual oil saturations to ∼3% in field cores along with low surfactant retention. This paper illustrates a workflow to identify the chemical formulation, chemical concentrations and slug sizes.

Novel insights into the geochemical evaluation of polymer drive composition on surfactant retention in carbonates using the surface complexation modeling

Surfactant-polymer (SP) flooding is considered an efficient technique to increase the recovery of oil, especially from carbonates reservoirs, because of their complex nature. The objective of this study is to analyze the effect of polymer drive composition on surfactant retention. We developed a geochemical model that uses various surface complexation reactions at the mineral/brine interface, oil/brine interface, surfactant/brine interface, and oil/surfactant interface. We also incorporated four new surface complexation reactions that honor oil/surfactant geochemical interaction to determine the influence of polymer composition on surface retention for the first time. Then we validated the developed geochemical model against coreflooding experimental data. Additionally, we investigated the influence of various parameters of polymer drive on surface retention under high temperature and salinity using the suggested surface complexation model. The findings showed that our surface complexation model can estimate surfactant retention and its concentration in the effluent with a certain accuracy during polymer drive. The developed geochemical model is validated against single-phase and two-phase coreflooding experimental data. The findings revealed that for a more representative and accurate estimation of surfactant retention in chemical flooding, it is important to consider the oil/surfactant surface complexation reactions. Moreover, the detailed and comprehensive analysis showed that with the increase in temperature of the polymer drive, the retention of surfactant increases, and its concentration in the effluent decreases. The latter shows that surfactant retention is a more chemical process as opposed to physio-retention. It is also shown that the injection of a specific composition of polymer drive after a surfactant slug could decrease the surfactant retention, which is related to the force of repulsion between the ionic species and the rock surface. Moreover, the effect of hard ions (calcium and magnesium) in polymer drive is significant where the increase in the concentration of hard ions increases the retention of surfactant. Furthermore, it is important to mention that the lowest level of surfactant retention was achieved through a certain composition of polymer drive, thus the polymer solution dilution is not an effective approach. This is the first study to test a novel formulation of surface complexation modeling that considers the oil/surfactant effect on surfactant retention corresponding to the composition of polymer drive. The suggested framework to determine surfactant retention is conducted for harsh reservoir conditions of temperature and salinity and suggests that the surface complexation reactions for all rock-forming minerals must be considered.

Low retention surfactant-polymer process for a HTHS carbonate reservoir

Development of surfactant formulations for high temperature (100 °C), high salinity (>50,000 ppm) and especially high hardness (>2000 ppm) reservoirs is challenging. Alkali-surfactant-polymer processes have been developed in the past, but requires soft injection brine. The objective of this work is to develop a surfactant-polymer (SP) process for a high temperature, high salinity (HTHS) reservoir that can be injected with available hard brines (such as sea water) to achieve ultra-low IFT, low residual oil saturation, and low surfactant retention in carbonate rocks. Phase behavior experiments were performed to identify a combination of anionic and zwitterionic surfactants. Four tertiary chemical corefloods were conducted in Indiana Limestone cores to test oil recovery and surfactant retention. A copolymer containing acrylamido-tertiary-butyl sulfonate, SAV10xv was identified to be stable at this HTHS condition. Sodium polyacrylate (NaPA) was identified as a sacrificial chemical to reduce surfactant adsorption. The chemical floods were successful in reducing the residual oil saturation to 8–11%. A preflush of NaPA reduced the surfactant retention from 0.133 mg/g to 0.017–0.038 mg/g of rock. Including the NaPA in the chemical slug was not as effective. The use of this surfactant formulation with a preflush of sodium polyacrylate can enhance the oil recovery in high temperature, high salinity carbonate reservoirs with very low surfactant retention.

Adsorption Study of Novel Gemini Cationic Surfactant in Carbonate Reservoir Cores-Influence of Critical Parameters.

Surfactant flooding is an enhanced oil recovery method that recovers residual and capillary trapped oil by improving pore-scale displacement efficiency. Low retention of injected chemicals is desired to ensure an economic and cost-effective recovery process. This paper examines the adsorption behavior of a novel gemini cationic surfactant on carbonate cores. The rock cores were characterized using an X-ray diffraction (XRD) spectroscope. In addition, the influence of critical parameters on the dynamic adsorption of the cationic gemini surfactant was studied by injecting the surfactant solution through carbonate cores in a core flooding apparatus until an equilibrium state was achieved. The concentration of surfactant was observed using high performance liquid chromatography. Experimental results showed that an increasing surfactant concentration causes higher retention of the surfactant. Moreover, increasing the flow rate to 0.2 mL/min results in lowering the surfactant retention percentage to 17%. At typical high salinity and high temperature conditions, the cationic gemini surfactant demonstrated low retention (0.42 mg/g-rock) on an Indiana limestone core. This study extends the frontier of knowledge in gemini surfactant applications for enhanced oil recovery.

Coreflood Tests to Evaluate Enhanced Oil Recovery Potential of Wettability-Altering Surfactants for Oil-Wet Heterogeneous Carbonate Reservoirs

Summary Oil-wetness and heterogeneity are two main factors that result in low oil recovery (OR) by waterflood in carbonate reservoirs. The injected water is likely to flow through high-permeability regions and bypass the oil in the low-permeability matrix. In this study, systematic coreflood tests were carried out in both “homogeneous” cores and “heterogeneous” cores with a wettability-altering surfactant. The homogeneous coreflood tests were conducted to evaluate surfactant retention, as well as to compare tertiary surfactant flooding with secondary surfactant flooding. The heterogeneous coreflood test was proposed to model bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. Surfactant retention results suggest that retention increases as initial oil saturation decreases. The retention of selected surfactant in the target reservoir cores was measured to be within a range of 0.07–0.12 mg/g-rock, which is economically acceptable. The results of homogeneous coreflood tests showed that both secondary waterflood and secondary surfactant flood can achieve high OR (>50%) from relatively homogeneous oil-wet cores. A shut-in phase after the surfactant injection resulted in a surge in oil production, which suggests that enough time should be given for wettability alteration by surfactants. The results of heterogeneous coreflood tests showed that more oil is bypassed in the tighter matrix by waterflood if the permeability is higher in the flooded layer and this bypassed oil is the target for the wettability-altering surfactant floods. Slow wettability-altering surfactant injection leads to imbibition into bypassed regions. When the oil-wet carbonate reservoirs have large unswept regions after waterflood, wettability-altering surfactants can significantly improve OR if enough time is given for imbibition.

Influence of sequential changes in the crude oil-water interfacial tension on spontaneous imbibition in oil-wet sandstone

Crude oil-water interfacial tension in petroleum reservoir is reduced or increased due to surfactant injection or surfactant retention, respectively. Changes in the interfacial tension crucially attribute to a governing capillary pressure and hence an oil displacement in spontaneous imbibition process. The current study attempts to elucidate an influence of such changes on spontaneous imbibition by replacing surfactant concentration consecutively with two approaches: sequential decrease and sequential increase in the interfacial tension. Two fluid flow directions were examined simultaneously: co-current and counter-current flows. With strongly oil-wet wettability, capillarity was a resisting element to oil displacement and therefore controlled by the oil-water interfacial tension. The sequential-reduced interfacial tension was found to weaken such resisting capillary force gradually and resulted in consecutive incremental oil production. On the contrary, the sequential-increased interfacial tension initiated the lowest interfacial tension fluid that produced an immediate large amount of oil, but did not much displace further oil. The current study observed a greater oil recovery obtained from a sequential reduction in the interfacial tension scheme (26.9%) compared to a conventional single reduction scheme (22.4%), with both schemes attaining same interfacial tension at last. In counter-current imbibition, same characteristics of oil displacement were observed as in co-current imbibition, with less oil produced and less sensitive to fluid changes due to negligible gravitational contribution.

Reducing surfactant retention using polyacrylate in Berea sandstone

The efficacy of surfactant flooding as a Chemical Enhanced Oil Recovery (EOR) method depends on the amount of the surfactant loss in the porous medium. Adding alkali to surfactant-polymer (SP) floods lowers surfactant adsorption/retention, but alkali has several key challenges that prevent operators from adopting it as the universal chemical EOR technique. Sodium polyacrylate has been successfully used as a sacrificial agent to reduce surfactant adsorption in static and dynamic adsorption tests. In this study, we evaluated the effect of sodium polyacrylate in Berea sandstone in the presence/absence of petroleum crude oil and compared dynamic adsorption/retention values with and without NaPA. Prior to corefloods, ultra-low interfacial tension surfactant formulations were identified using microemulsion phase behavior experiments for two different crude oils. Corefloods were conducted at corresponding optimum salinity of the surfactant formulations with a negative salinity gradient towards polymer drive. Surfactant concentration in effluent was measured by a high-performance-liquid-chromatography method (HPLC), and the adsorption/retention values were calculated by material balance. In our experiments, surfactant adsorption during single-phase corefloods (in the absence of crude oil) in Berea sandstone cores was found to be around 0.17–0.23 mg/g-rock; addition of a 0.5–1.0 wt % sodium polyacrylate decreased surfactant adsorption to 0.10 mg/g-rock. Surfactant retention in SP oil recovery corefloods in Berea sandstone cores without and with NaPA was found to be 0.20 mg/g-rock and 0.11 mg/g-rock, respectively.

Classification methods of conglomerate reservoirs based on the adsorption and retention law of surfactant-polymer binary systems

Factors such as clay minerals and micropore structure can lead to the adsorption and retention of chemical agents when the components of surfactant-polymer systems enter porous media. This study aims to clarify the influence of adsorption and retention of surfactant-polymer components on reservoir permeability and oil displacement efficiency and then classify the reservoirs into types. The natural cores of conglomerate reservoirs from the Badaowan Formation in the 7th block are selected as research objects to reveal the adsorption law of surfactant-polymer components on different minerals and different micro pores through the dynamic oil displacement method based on physical model and the N element calibration method. Experimental results show that the adsorption capacity of clay minerals for surfactant-polymer components is significantly higher than that of carbonate and skeleton minerals, and different clay minerals differ in adsorption capacity for surfactant-polymer components depending on their cation exchange capacity and end surface adsorption activity. In addition, the adsorption and retention capacities of reservoirs for surfactant-polymer components are closely related to the type and content of clay minerals. The combination type of clay minerals controls the adsorption activity of surfactant-polymer components, and the values of polymer and the surfactant are quantitatively calculated to be 11.3 and 21.4 mg/g, respectively. The adsorption strength of surfactant-polymer components is controlled by the content of clay minerals. With increasing clay content, the adsorption strength of the polymer ranges from 0.5 to 2.5 mg/cm 3 , and that of the surfactant ranges from 1.0 to 4.5 mg/cm 3 . On this basis, the “N element calibration method” is used to determine the occurrence state and content of chemical agents in micropores for different permeability samples after surfactant-polymer binary flooding. Research results show that the polymer and surfactant components mainly have two types of occurrence form in micropores, including the complex pores accumulated by clay minerals and the intersections of small pores and throats. With decreasing reservoir permeability, the number and content of detected N element gradually increase, indicating an increase in the adsorption and retention of polymer and surfactant, and the influence on the reservoir seepage capacity also increases. Finally, the conglomerate reservoirs in the Badaowan Formation from the 7th block are divided into four types after considering the influence of clay minerals and micropore structure on the adsorption and retention of surfactant-polymer components, and the reasonable classification of reservoir types can effectively enhance the oil recovery of surfactant-polymer binary flooding. • The adsorption law of SP binary components on different minerals in conglomerate reservoir was clarified. • The adsorption capacity of polymer and surfactant can be accurately calculated according to the petrophysical volume model. • The N element calibration method was used to determine the occurrence state and content of chemical agent in micro pore after SP binary flooding. • A method of reservoir classification considering the influence of clay minerals and micro-pore structure on the adsorption of SP binary components is established to further EOR.

Potential of ceramic ultrafiltration membranes for the treatment of anionic surfactants in laundry wastewater for greywater reuse

Decentralized greywater treatment is gaining increasing recognition as an alternative for natural water supplies. Laundry wastewater in relatively large amounts of greywater is considered as a valuable resource with high reuse potential. However, organic pollutants with low molecular weights (e.g., anionic surfactants) that originate from laundry additives should be effectively removed. Because anionic surfactants are widely used to produce detergents, the retention of sodium dodecylbenzene sulphonate (SDBS; a typical anionic surfactant in laundry wastewater) was evaluated with a bench-scale ceramic ultrafiltration (UF) membrane filtration system. The results demonstrate that SDBS can be successfully retained with a ceramic UF membrane with a nominal pore size of 1 kDa (~4.0 nm) by carefully controlling several operating parameters. The dynamic phase changes of the surfactant that depend on its concentration affect the SDBS retention performances regardless of the operating parameters. At a high transmembrane pressure (TMP) and room temperature, the SDBS micelles that form on the membrane surface cause a pre-sieving effect induced by concentration polarization, thereby increasing the SDBS retention. As the solution pH increased, electrostatic repulsion between the solute and membrane surface induced higher SDBS retention rates. The retention rate also increased significantly with increasing ionic strength, which was especially pronounced with divalent ions than with monovalent ions because higher ion specificity could reduce the charge repulsion and induce their micellization. These electrostatic and adsorptive interaction could demonstrate a better understanding of surfactant retention mechanisms. Consequently, ceramic UF membranes have the potential of treating laundry wastewater attaining moderately high concentrations of surfactants.

Transport of an Eco-friendly L70-c Bio-based Sucrose Ester Surfactant: Implication for Soil Remediation Purposes

Due to their biodegradability and low toxicity bio-based surfactants are very promising for use in remediation technologies, particularly for hydrocarbon contaminated soils. To enhance the application of surfactant-based technologies for remediation of organic contaminated sites, it is important to have a better understanding of the surfactant transport and retention mechanisms involved in this process, as they will impact the remediation efficiency. In this work, transport and retention mechanisms of an industrial bio-based nonionic sucrose ester surfactant were investigated through batch and column experiments, carried out on sandy porous media under saturated steady state flow conditions. Column transport experiments were conducted at surfactant concentrations ranged from 1 to 10 CMC (critical micellar concentration), for two distinct Darcy flow rates (0.35 and 0.70 cm.min-1). Surfactant transport and retention parameters were estimated by fitting a convection-diffusion transport model (implemented on HYDRUS-1D code) to the observed transport breakthrough curves, in order to provide an adequate description and understanding of the mechanisms involved in the transport and adsorption of these compounds through porous media. The results obtained from column experiments performed under high flow rate combined with high surfactant concentration provided the best conditions for high surfactant recovery in the effluent and low surfactant adsorption rate onto the sand. Numerical HYDRUS-1D simulations permitted to quantify surfactant transport behavior and provided attachment coefficients several order of magnitude greater than detachment coefficients, indicating that surfactant retention was an irreversible process.

In-depth experimental investigations of low-tension gas technique with methane and live oil in high salinity and high temperature sandstone reservoirs

Low-Tension gas (LTG), as an emerging technique, attempts to synergize oil desaturation by microemulsion and mobility control via foam, which is an ideal alternative wherever other tertiary recovery techniques are technically limited. Previously, high oil recovery was achieved with proposed formula and novel injection strategy under harsh conditions (190,000 ppm, 85 °C) [53] with N2 and dead oil, which were robust to wide reservoir scenes (0.5 ft/d, 7 md) [54]. Here, more practical field scenarios are examined with methane and live oil for the first time facilitated by auxiliary tests of bulk foam stability, microemulsion viscosities and surfactant retention. Microemulsion phase behaviors are probed for both N2 and CH4 under reservoir pressure (1200 psi, 85 °C) in sequence to distinguish the impacts of pressure and solution gas. Therewith, pressure drop, effluent salinity and oil recovery are recorded to analyze effects of mobility control, gas type (N2 or CH4) and oil condition (dead or live) through multiple corefloodings stepwise. It is found higher pressure and solubilized methane impose limited impacts on current microemulsion phase behaviors. The developed formula and novel injection strategy satisfy the requirements of mobility control and oil desaturation, through the balance between foam stability and relatively low IFT. The surfactant retention is 0.162 mg/g during LTG process. Neither gas type or oil condition exerts discernible influences indicated by similarly high oil recoveries around 90%. The findings here promote the field implementation of this novel technique for both greenhouse gas utilization and enhanced oil recovery.

Fouling of polyelectrolyte multilayer based nanofiltration membranes during produced water treatment: The role of surfactant size and chemistry

Large volumes of water become contaminated with hydrocarbons, surfactants, salts and other chemical agents during Oil & Gas exploration activities, resulting in a complex wastewater stream known as produced water (PW). Nanofiltration (NF) membranes are a promising alternative for the treatment of PW to facilitate its re-use. Unfortunately, membrane fouling still represents a major obstacle. In the present work, we investigate the effect of surface chemistry on fouling of NF membranes based on polyelectrolyte multilayers (PEM), during the treatment of artificial produced water. To this end, oil-in-water (O/W) emulsions stabilized with four different surfactants (anionic, cationic, zwitterionic and non-ionic) were treated with PEM-based NF membranes having the same multilayer, but different top layer polymer chemistry: crosslinked poly(allylamine hydrochloride) (PAH, nearly uncharged), poly(sodium 4-styrene sulfonate) (PSS, strongly negative), poly(sulfobetaine methacrylate-co-acrylic acid) (PSBMA-co-AA, zwitterionic) and Nafion (negative and hydrophobic). First, we study the adsorption of the four surfactants for the four different surfaces on model interfaces. Second, we study fouling by artificial produced water stabilized by the same surfactants on PEM-based hollow fiber NF membranes characterized by the same multilayer of our model surfaces. Third, we study fouling of the same surfactants solution but without oil. Very high oil retention (>99%) was observed when filtering all the O/W emulsions, while the physicochemical interactions between the multilayer and the surfactants determined the extent of fouling as well as the surfactant retention. Unexpectedly, our results show that fouling of PEM-based NF membranes, during PW treatment, is mainly due to membrane active layer fouling caused by surfactant uptake inside of the PEM coating, rather than due to cake layer formation. Indeed, it is not the surface chemistry of the membrane that determines the extent of fouling, but the surfactant interaction with the bulk of the PEM. A denser multilayer, that would stop these molecules, would benefit PW treatment by decreasing fouling issues, as would the use of slightly more bulky surfactants that cannot penetrate the PEM.

A review on surfactant retention on rocks: mechanisms, measurements, and influencing factors

Surfactants play a vital role in chemical enhanced oil recovery (cEOR). The amount of surfactant loss caused by retention during flooding through reservoir rock is still a challenge in surfactant-based cEOR techniques, and directly impacts the economics of a cEOR project. This review focuses on the mechanisms behind the retention of several surfactants on different rock/mineral types such as sandstone, carbonates, quartz, kaolinite, calcite, etc. Measurement techniques of surfactant retention reported in the literature are also presented. Lastly, this review illustrates retention minimization strategies for different types of surfactants. Alkalis have been widely examined in minimizing surfactant retention, mostly in sandstones. Other chemicals such as ammonia, nano-particles, ionic liquids, polymers, and sacrificial agents have also been used to reduce surfactant retention. This review also discusses the influencing factors that can significantly impact the strategy to minimize surfactant retention.

A practical and economically feasible surfactant EOR strategy: Impact of injection water ions on surfactant utilization

One grand challenge of surfactant technologies in high salinity sandstone reservoirs is the surfactant retention and its utilization for commercial projects. A proven mitigation strategy to reduce surfactant retention is to soften the seawater or produced brine and add alkali with the surfactant and polymer. However, softening produced brine can be costly and the addition of alkali can impose other issues such as scale and produced fluid separation. A comprehensive chemical enhanced oil recovery (CEOR) laboratory program was carried out to compare different surfactant formulations for both alkali-surfactant-polymer (ASP) and surfactant-polymer (SP) implementation in a giant Middle East sandstone oil reservoir with high salinity on the order of 160,000 ppm. The efficacies of ASP and SP floods were investigated in laboratory corefloods and simulations with emphasis on surfactant retention to improve techno-economic feasibility.Both ASP and SP floods were designed with low operational cost in mind and were tested in laboratory corefloods under reservoir conditions. Different injection water salinities were considered for practical field application. The handling and availability of injection water with a suitable composition has significant implications in CEOR projects. The SP design using produced brine with minimum water treatment is an attractive option for field commercial deployment. We considered different injection water salinities, surfactant molecules, and brine treatment requirements for several ASP and SP formulations and injection design strategies.ASP and SP corefloods recovered nearly all the remaining oil after waterflooding. The surfactant retention was lower for SP floods when brine with reduced concentration of Ca2+ and Mg2+ (hardness) was used. Both ASP and SP formulations were also tested for crude oil samples from different zones. A minimal adjustment in injection salinity was required for different oils with our surfactant formulations. Field implementation strategies were evaluated via numerical simulation. The effect of strong aquifer drive on SP performance was shown to be minimized with optimized injection/production strategies. SP was shown to be technically and economically an attractive candidate tertiary process.

Experimental study of combined low salinity and surfactant flooding effect on oil recovery

A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection. In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2. The samples were first reached to initial water saturation, Swi, by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation. The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, Sor, by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding. Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.