Surfactant-based Fluids Research Articles

Dual Semi-Interpenetrating Networks of Water-Soluble Macromolecules and Supramolecular Polymer-like Chains: The Role of Component Interactions

Dual networks formed by entangled polymer chains and wormlike surfactant micelles have attracted increasing interest in their application as thickeners in various fields since they combine the advantages of both polymer- and surfactant-based fluids. In particular, such polymer-surfactant mixtures are of great interest as novel hydraulic fracturing fluids with enhanced properties. In this study, we demonstrated the effect of the chemical composition of an uncharged polymer poly(vinyl alcohol) (PVA) and pH on the rheological properties and structure of its mixtures with a cationic surfactant erucyl bis(hydroxyethyl)methylammonium chloride already exploited in fracturing operations. Using a combination of several complementary techniques (rheometry, cryo-transmission electron microscopy, small-angle neutron scattering, and nuclear magnetic resonance spectroscopy), we showed that a small number of residual acetate groups (2–12.7 mol%) in PVA could significantly reduce the viscosity of the mixed system. This result was attributed to the incorporation of acetate groups in the corona of the micellar aggregates, decreasing the molecular packing parameter and thereby inducing the shortening of worm-like micelles. When these groups are removed by hydrolysis at a pH higher than 7, viscosity increases by five orders of magnitude due to the growth of worm-like micelles in length. The findings of this study create pathways for the development of dual semi-interpenetrating polymer-micellar networks, which are highly desired by the petroleum industry.

Insight into functional groups of salt compounds on the performance of viscoelastic surfactant-based fluids

Clean fracturing fluids (CFFs) hold great potential for the development of unconventional reservoirs due to their characteristics (e.g., fracturing-oil expulsion integration and low formation damage). Organic salts, as adjuvants, play a significant role in regulating the performance of CFFs. In this work, four CFFs containing different organic salts were prepared to investigate the impact of functional groups in organic salts on the CFF performance. Results show that the functional groups markedly influence the rheological properties, temperature resistance and drag reduction performances of CFFs through inducing the micelle formation and thus enhancing the micelle network strength. Sodium 4-vinylbenzenesulfonate (SV) with vinyl endowed the CFF with the stronger micelle network. Furthermore, the functional groups were found to impact the adsorption of surfactants at interface, which affects the oil–water interfacial tensions and regulates the spontaneous imbibition performance of CFFs. SV enables a higher imbibition efficiency of 25.6 % after 90 h. Density functional theory (DFT) calculation results confirmed that the functional groups of salts are capable of manipulating the interactions between salt anions and surfactant, ultimately determining the CFF performance. This work provides guidance for the selection of salt additives to improve the CFF performance.

In-Situ Visualization of Imbibition Process Using a Fracture-Matrix Micromodel: Effect of Surfactant Formulations toward Nanoemulsion and Microemulsion

Summary Spontaneous imbibition can help to improve the oil recovery of unconventional reservoirs owing to the significant capillarity. Although the dependence of imbibition dynamics of surfactants on wettability and interfacial tension (IFT) is understood, the mechanisms of nanoemulsion and microemulsion forming surfactants for higher imbibition recovery are not as clear. Herein, we conducted a series of imbibition experiments on a visual fracture-matrix micromodel, aiming to directly observe the imbibition processes of these surfactant formulations. Four surfactant-based fluids, including a common surfactant [fatty alcohol polyoxyethylene ether, sodium sulfate (AES)], a surfactant composition of nanoemulsion (nE-S), an ex-situ nanoemulsion (nE), and a situ microemulsion forming surfactant (mE-FS), were designed and used in this work for comparison with brine. The results suggested that AES, nE-S, nE, and mE-FS could substantially stimulate the imbibition invasion, and mE-FS generated the greatest imbibition depth and sweeping area followed by nE. The imbibition dynamics were governed by the interfacial interactions among oil, aqueous phase, and solid surface, leading to different imbibition patterns for these five fluids. AES and nE-S could reduce the oil-aqueous IFT to 10−1 mN/m and alter the wettability to a weak water-wet state as a result of surfactant adsorption, leading to a slightly higher imbibition invasion compared with brine. AES imbibition produced large oil droplets mainly because of the snap-off effect at the nozzle to the fracture, whereas nE-S produced smaller oil droplets due to the weak in-situ emulsification. nE as a formed nanoemulsion with an internal oil phase demonstrated a lower IFT of 10−2 mN/m and superior capacity in changing surface wettability mainly through the adsorption and spreading of nanosized oil droplets on the surface. The oil phase was heavily emulsified forming dense droplets on the oil-aqueous interface. mE-FS readily formed Winsor Type III microemulsion and produced an IFT of 10−3 mN/m magnitude. The wettability was changed mainly because of the peeling oil film and formation of microemulsion on the surface induced by solubilization. The dynamic increase of the oil-aqueous IFT at the imbibition front caused by the adsorption loss of surfactant to the surface and partitioning to the oil phase promoted capillary-driven imbibition for nE and mE-FS. We modified an imbibition model to incorporate the solubilization effect, leading to a much better fitting with the experimental data.

Effect of Silica Nanoparticles on the Rheological Properties and Filtration Performance of Surfactant-Based and Polymeric Fracturing Fluids and Their Blends

Summary The investigation of nanotechnology applications in the oil and gas industry is increasing gradually; therefore, this technology needs more exploration to unveil promising applications. In this study, an experimental investigation of nanotechnology on the apparent viscosity, viscoelastic properties, and filtration performance of surfactant-based fluids (SBFs) or viscoelastic surfactants (VESs), polymeric fluids, and SBF/polymeric-fluid blends is presented. The concentration of SBF is 5 vol%, whereas that of polymeric fluids is 33 lbm/1,000 gal guar. Besides, both fluids contained 4 wt% potassium chloride (KCl). In addition, Blend-A and Blend-B were prepared by mixing SBF and polymeric fluids in the ratio of 75/25 and 25/75 vol%, respectively. Nanofluids were prepared by adding 20-nm silica nanoparticles, at concentrations of 0.058, 0.24, and 0.4 wt%, to the clean fluids. Apparent viscosity and viscoelastic data were gathered with a rheometer within a temperature range of 75 to 175°F, whereas filtration tests were conducted with a wall-mount filter press at ambient temperature and 100-psi differential pressure. The results indicate an enhancement in the apparent viscosity and viscoelastic properties of surfactant-based and polymeric nanofluids up to a nanoparticle concentration of 0.24 and 0.4 wt%, respectively. Blend-A nanofluids show improvement in apparent viscosity and viscoelastic properties at a nanoparticle concentration of 0.058%. Similarly, Blend-B displayed favorable results up to a nanoparticle concentration of 0.24 wt% at temperatures of 125 to 175°F. Promising filtration results were displayed with surfactant-based nanofluids and Blend-A nanofluids at all nanoparticle concentrations, but the performance at 0.24 and 0.4 wt%, respectively, is slightly better. Polymeric nanofluids and Blend-B nanofluids revealed very good filtration results at all nanoparticle concentrations, but the performance at 0.24 and 0.058 wt%, respectively, is slightly better with a percentage reduction in API filtrate volume of 70.2 and 69.8%, respectively. A trial run was made with a commercially available fluid-loss additive [polyanionic cellulose (PAC)] in polymeric fluids at the same nanoparticle concentrations; the result confirmed that nanosilica facilitates the achievement of a superior filtration property. Comparison of apparent viscosity, viscoelastic properties, filtration performance, and economic analysis revealed Blend-A nanofluid as the preferred choice. Further, Blend-A nanofluid (at 0.058 wt%) is selected as the best on the basis of filtration performance. The selected fluid was optimized at lower nanoparticle concentrations (0.02, 0.01, and 0.002 wt%). Interestingly, using Blend-A nanofluid at 0.002 wt%, compared with the initial recommendation of 0.058 wt%, which costs USD 171.7/bbl, reduces the cost of nanoparticles required for preparing 1 bbl of this fluid to USD 5.8. Therefore, from a filtration-performance standpoint, Blend-A nanofluid is recommended for use at a nanoparticle concentration of 0.002 wt%. The application of nanotechnology on the apparent viscosity, viscoelastic behavior, and filtration properties of SBF, polymeric fluids, and SBF/polymeric-fluid blends can deliver some benefits, if nanoparticle concentrations are selected carefully. These nanofluids will be applicable for oilfield operations such as hydraulic fracturing.

Rheology and flow studies of drag-reducing gravel packing fluids

Viscoelastic additives are widely used as drag reducers in the oil and gas industry, and both polymeric additives and micellar surfactants are commonly used in well gravel packing applications. While the behaviour of polymeric additives such as the polysaccharide xanthan gum is well characterized in the literature, much less is known about how the rheology of the viscoelastic surfactants affects drag reduction, despite widespread use. In this study, we performed a number of rheological tests as well as flow loop experiments on solutions of a zwitterionic surfactant to understand the structural characteristics of the fluids in order to make better process predictions. Unlike xanthan, which displays typical viscoelastic liquid characteristics, zwitterionic surfactant-based fluids display elastic gel-like behaviour. The gel-like behaviour suggests long and relatively unbreakable chain lengths of the wormlike micelles in the viscoelastic surfactant solution at room temperature leading to gelation by entanglement. Also, a shear-thickening behaviour of viscoelastic surfactant samples at higher shear rates is observed, possibly as a result of shear-induced structures. Finally, we present a novel representation scheme to depict the flow loop results for drag in the laminar and turbulent regime, and relate this data to the rheological characterization.

Maximum Drag Reduction Asymptote for Surfactant-Based Fluids in Circular Coiled Tubing

Surfactants are superior to polymers in reducing drag and their advantages are very well established. As drag reducers, several factors, such as concentration, temperature, salinity, shear rate, etc., can affect their behavior. Other unique factors relevant to surfactants may include tubing diameter (scale-up effect), head group structure, counterion, charge, etc. Although, drag reduction envelope is customarily employed to investigate drag reduction phenomena, it is defined only for polymeric fluids in both straight and coiled tubing and for surfactant-based (SB) fluids in straight tubing. No such envelope is available for SB fluids in coiled tubing. The present research aims at experimentally investigating the drag reduction characteristics of the most widely used Aromox APA-T surfactant-based fluids. It is a highly active surfactant used as gelling agent in aqueous and brine base fluids. Flow data are gathered using small and large scale flow loops. Straight and coiled tubing with various sizes (1.27 cm to 7.30 cm o.d.) and curvature ratios (0.01 to 0.031) covering the field application range are utilized. The results show that SB fluids exhibit superior drag reduction characteristics. Their behavior is significantly affected by surfactant concentration, shear, tubing size, and geometry. Higher drag reduction is seen in straight tubing than in coiled tubing and increasing curvature ratio yields higher friction pressure losses. In coiled tubing, SB fluids exhibit better drag reduction characteristics than Shah and Zhou maximum drag reduction (MDR) asymptote for polymeric fluids. Therefore, a new maximum drag reduction asymptote is developed using data gathered in 1.27 cm o.d. tubing. The proposed correlation agrees with Zakin MDR asymptote for SB fluids in straight tubing where the curvature ratio is set to be zero. Employing the proposed correlation, a modified drag reduction envelope can be used to evaluate drag reduction characteristics of SB fluids.

Scale-Up Correlation for the Flow of Surfactant-Based Fluids in Circular Coiled Pipes

This study involves experimental investigation on the flow properties of aqueous surfactant-based (SB) fluids in small and large-scale coiled tubing. It aims at understanding the viscoelastic properties and its effect on the flow behavior of SB fluids in coiled tubing. In spite of SB fluids wide use as friction reducer and/or fracturing fluid in the oil and gas industry, the flow data in large pipe sizes as well as coiled tubing are very scarce. Majority of the available flow data are gathered in straight pipes with small sizes. The scale-up of small-scale flow data is questionable due to the pronounced diameter effect. Furthermore, previous studies have correlated flow behavior of these fluids only through simple power-law model parameters. Limited work with polymeric fluids has been reported that includes fluid elasticity in scale-up procedure and it is nonexistent for highly elastic SB fluids. In this study, the properties of widely used Aromox APA-T, a highly active surfactant used as gelling agent in aqueous and brine base fluids, are thoroughly investigated. Rheological measurements are conducted using Bohlin rheometer for SB fluid concentration of 1.5 vol %, 2 vol %, 3 vol %, and 4 vol %. Flow data are gathered using 1.27 cm, 3.81 cm, 6.03 cm, and 7.30 cm OD coiled tubing with various curvature ratios. This study presents the first attempt to investigate the flow behavior SB fluids in large-scale coiled tubing. The results show that SB fluids exhibit non-Newtonian pseudoplastic behavior. Elastic and viscous properties of SB fluids are very sensitive to surfactant concentration. Friction losses in coiled tubing are significantly higher than those in straight pipes due to secondary flow effect. Increasing curvature ratio yields higher friction pressure loss. Also, small-scale data correlations using only simple power-law model fluid rheological parameters lead to erroneous results when scaled-up to large pipe sizes. New technique, based on the modified Deborah number, which includes fluid elasticity and pipe shear effect, has been developed to correlate data from the small laboratory-scale tubing and large field-scale pipes. Correlation to predict Fanning friction factor of SB fluids in coiled tubing as a function of Deborah number and fluid flow behavior index is presented. Correlation is validated by comparing predictions with the experimental data. It is shown that the new correlation accurately predicts friction factor of SB fluids and thus alleviates the scale-up issue.

Investigation of the Complex Flow Behaviour of Surfactant-Based Fluids in Straight Tubing

Summary In spite of their wide use in hydraulic fracturing and gravel-pack operations, the complex flow behaviour of surfactant-based (SB) fluids in straight tubing is rarely investigated. Accurate prediction of friction-pressure is essential for proper treatment design. Previous correlations from small tubing data and using simple power-law fluid model parameters alone do not scaleup to large tubing sizes for field application. The properties of one of the most popular surfactants, Aromox APA-T, are thoroughly investigated. It is a highly-active surfactant used as the gelling agent in aqueous and brine solutions. Commonly used surfactant concentrations (1.5%, 2%, 3% and 4% by volume) are studied. Rheological and viscoelastic measurements are conducted using the Bohlin rheometer. Flow tests are conducted using 1.27-cm, 3.81-cm, 6.03-cm and 7.30-cm tubing. The results show SB fluid exhibiting a non-Newtonian pseudo-plastic behaviour. Fluid concentration and pipe shear have a significant effect on fluid elasticity. The conventional Fanning friction factor vs. Reynolds number correlation is improved by including a new dimensionless group that accounts for both fluid elasticity and pipe diameter. A new definition of Deborah number is introduced. Thus, a new correlation for predicting friction factors of SB fluid in straight tubing is developed. The scaleup problem is thus alleviated with the present analysis and this provides more accurate friction-pressure estimates.

Application of Cationic Surfactant-Based Fluids for Acid Diversion

Summary This paper examines the use of surfactant gels during matrix acid treatments and describes field trials of these fluids. Unlike available viscoelastic surfactants used today in the field, this surfactant is cationic. If used in live acids, the fluid has a relatively low viscosity when pumped. Once the acid is spent, however, the surfactant molecules increase its viscosity significantly. To enhance diversion further, the acidic fluids or brines can be foamed with this surfactant. Rheological measurements were conducted on Hastelloy®- fitted rotational viscometers at temperatures ranging from 70 to 300°F. The effects of surfactant concentration, shear rate, temperature, and acid additives on the apparent viscosity of various surfactant-based fluids were investigated in detail. The surfactant was stable thermally and hydrolytically with most acid additives. While it was compatible (i.e., still formed a viscosifying gel), some additives adversely affected the apparent viscosity of surfactant solutions at a given temperature. The apparent viscosity of surfactant solutions increased with salt concentration and can be predicted by use of the Carreau-Yasuda model. Coreflood tests indicated that the surfactant delayed acid breakthrough in calcite cores. Acceptable corrosion rates were obtained when this surfactant was added to the acid. The performance of this surfactant was validated with field treatments. The surfactant was used in more than 100 matrix acid treatments (oil producers and water injectors). It was used to increase the viscosity of acids in situ and enhance the stability of foams used for diversion. All wells responded positively to these treatments, and no operational problems were encountered. Downhole gauges confirmed the ability of surfactant-based fluids to divert the acid into various zones.

Polymer-Free Fluid for Fracturing Applications

Summary Polymer residues that stay in the fracture after fracturing can limit the treatment effectiveness. A new and easy-to-prepare, surfactant-based polymer-free fluid, ClearFRAC™, that consists of a quaternary ammonium salt derived from a long-chain fatty acid is described. In brine, it builds fluid viscosity and viscoelasticity due to the formation of highly entangled worm-like micelles. The micelles have a gross structure similar to a polymer chain. Since the viscosity of the fluid depends on the nature of micelles, the fluid can be broken by changing this micellar structure. The breaking occurs when the fluid is exposed to hydrocarbons or diluted with formation water. Therefore, conventional breakers are not required, and the produced oil or gas can act as breakers for this fluid system. The structural characteristics of this viscoelastic surfactant-based fluid to its chemical and physical properties are correlated in this article. Structure, rheology, fluid loss, and conductivity of this surfactant fluid together with its case histories are presented.