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. Introduction Fracturing fluid is a very critical component of a hydraulic fracturing treatment. Selection of the fracturing fluid, job design, and well turnaround procedure all determine the productivity of a well after a stimulation by hydraulic fracturing.1,2 A fracturing fluid should provide sufficient viscosity to suspend and transport proppant into the fracture, and should break into a low-viscosity fluid after the job is completed. This will facilitate the fracture to clean up by allowing rapid flowback of fluid to the surface. Analysis of the fluid returned to the surface (flowback fluid) after hydraulic fracturing indicates that as little as 30 to 45% of the guar-based polymer pumped during the treatment returned from the well during the flowback period.3 Polymer residues that remain in the fracture significantly contribute to lower proppant-pack permeability, leading to a loss in fracture treatment effectiveness.1 The field success of a viscoelastic surfactant-based (VES) polymer-free fluid4–6 in frac-pack applications led to the development of a similar fluid for hydraulic fracturing. This VES fluid, ClearFRAC can be used for the fracturing treatment of potentially all gas and oil wells below 240°F. The principal advantage of this fluid system is its operational simplicity. This fluid is easy to prepare and requires less equipment at the wellsite. This fluid does not require polymer hydration, biocides, buffers, crosslinkers, or breakers. When flowing back, contact with the produced hydrocarbons or dilution with formation brine can also break ClearFRAC. This new fracturing fluid has been used successfully in more than 2,100 fracturing jobs around the world. Case histories from representative treatments are presented. Theory The presence of two structurally dissimilar groups (a hydrophilic and a hydrophobic) within a single molecule is the most fundamental characteristic of all surfactants. These molecules are composed of groups of opposing solubility tendencies, typically an oil-soluble hydrocarbon chain (hydrophobic) and a water-soluble ionic group (hydrophilic). In aqueous solution these molecules self-associate in an attempt to sequester their apolar regions from contact with the aqueous phase. Micelles can have different structures such as small spheres, disks, or long cylinders.7 When dissolved in brine, a small group of surfactants is able to form micellar structures other than the most commonly encountered spheres or disks. This includes the family of quaternary ammonium compounds, which is the subject of this article. The geometry of the micelles is similar to that of polymer molecules. This network of micellar structure resists distortion, whereby the viscosity increases and imparts viscoelastic properties to the fluid. Unlike guar-based fluids for the VES system, no crosslinker is necessary. There is a repulsive interaction in the micelle structure, primarily between the positively charged head groups. This repulsive force make the micelles assume a spherical shape, leading to a fluid of brine-like viscosity. To counteract this repulsive force, the presence of a counter-anion is necessary. The use of some inorganic and organic8 anions is found to enhance the viscosity of this surfactant fluid. When organic and other hydrophobic substances dissolve in the micelle hydrocarbon core, they will swell the rod-shaped micelle structure and ultimately break it into smaller spherical micelles with resultant loss in fluid viscosity (Fig. 1). Hydrocarbons such as oil and gas have this effect, and will readily reduce the viscosity of VES fluids to that of brine. Therefore, no internal chemical or enzyme breaker is required with this fluid system. Results and Discussion Micelle Structure. The micellar structure of the viscoelastic surfactant in brine was examined using cryotransmission electron microscopy (cryo-TEM). For this study a 4% (by vol) VES surfactant was added to a 3% solution of NH4Cl in a Waring blender and mixed for about 3 minutes. The resulting gel was de-aerated by placing it in a hot water bath. The samples for cryo-TEM were prepared in a controlled environmental vitrification9 system (CEVS) using this gel. Cryo-TEM examination of a VES gel in NH4Cl brine showed that it is composed of highly entangled worm-like [Fig. 2(a)] or long cylindrical [Fig. 2(b)] micelles with crossbridges. Rheology. The rheological performance of the VES fluid was investigated by measuring its viscosity on a Fann 50 or Fann 35 viscometer and/or on a Reciprocating Capillary Viscometer (RCV). The rheology of the fluid was examined at temperatures ranging from 80 to 250°F in the presence of different clay stabilizers. Depending on the application temperature, the amount of the surfactant used ranges from 0.5 to 4% (low concentration for low temperatures). In a typical experiment, the required amount of the surfactant is added to 500 mL of a 3% NH4Cl solution in a Waring blender. The mixture is blended until the vortex is closed. The time required for vortex closure (which ranges from 2 to 5 minutes) depends on the amount of surfactant used. The viscosity of the fluid is examined after de-aerating the fluid by heating in a water bath (?80°C) for about 1 hour.

In vitro data suggest that different in vivo performances are expected for two dihydroxyacetone (DHA)-containing formulations with similar concentrations of DHA and excipients but different commercially available rheology modifiers: one with a cationic polymer-based rheology modifier (blend) [dimethylacrylamide/ethyltrimonium chloride methacrylate copolymer (and) propylene glycol dicaprylate/dicaprate (and) PPG-1 trideceth-6 (and) C10-11 isoparaffin]; and the other with a polyacrylamide-based rheology modifier (blend) [polyacrylamide (and) C13-14 isoparaffin (and) laureth-7]. Both rheology modifiers (blends) contained comparable levels of polymers and were used at 3% w/w (as supplied). Differences in color development were illustrated in vitro with respect to the yellow/red and lightness/chroma parameters, which were confirmed in the followup in vivo studies. The test article with the cationic polymer-based rheology modifier produced a more natural sunless tan, comparable to a desirable sun-induced tan, for all panelists, one that was more uniform and lasted longer compared with the sunless tan generated by the test article with the polyacrylamide-based rheology modifier. A method for HPLC analysis of DHA in sunless tanning formulations was established and utilized to confirm concentrations of DHA in test articles.pp. 85-105 Basic optics of effect materials by S. A. Jones: BASF Corporation,

Polymer residues that stay in the fracture after a hydraulic fracturing treatment can limit treatment effectiveness. A new and easy-to-prepare, polymer-free fluid that consists of a quaternary ammonium salt derived from a long-chain fatty acid is described. In brine, it builds viscosity 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 waters. Therefore, conventional breakers are not required, and the produced oil or gas can act as breakers for this fluid system. The structural characteristics of the polymer-free surfactant fluid to its chemical and physical properties are correlated in this paper. Structure, rheology, fluid loss and conductivity of this surfactant fluid together with its production data are presented. Introduction Fracturing fluid is a very critical component of a hydraulic fracturing treatment. Selection of the fracturing fluid, job design, and well turnaround procedure all help to determine the production of a well after a stimulation by hydraulic fracturing. A fracturing fluid should provide sufficient viscosity to suspend and transport proppant into the fracture, and should break into a low-viscosity fluid after the job is completed. This will facilitate the fracture to clean up by allowing rapid flowback of fluid to the surface. Analysis of the fluid returned to the surface (flowback fluid) after hydraulic fracturing indicates that as little as 30 to 45% of the guar-based polymer pumped during the treatment returned from the well during the flowback period. Polymer residues that remain in the fracture significantly contribute to a lowered proppant-pack permeability leading to a loss in fracture treatment effectiveness. The field success of a viscoelastic surfactant-based (VES) polymer-free fluid in frac-pack applications led to the development of a similar fluid for hydraulic fracturing. The VES fluid can be used for the fracturing treatment of potentially all gas and oil wells below 240 F. The principal advantage of this fluid system is its operational simplicity. This fluid is easy to prepare and requires less equipment at the wellsite This fluid does not require polymer hydration, biocides, crosslinkers, or breakers. The hydrocarbons produced, or dilution of VES gel by other formation fluids, can break this fluid. This new fluid has been used for the successful execution of more than 250 fracturing jobs. Results from representative treatments are presented. Theory The presence of two structurally dissimilar groups (a lyophilic and a lyophobic) within a single molecule is the most fundamental characteristic of all surfactants These molecules are composed of groups of opposing solubility tendencies, typically an oil-soluble hydrocarbon chain (hydrophobic) and a water-soluble ionic group (hydrophilic). In aqueous solution these molecules self-associate in an attempt to sequester their apolar regions from contact with the aqueous phase. Micelles can be small spheres, disks, or long cylindrical structures. When dissolved in brine. a small group of surfactants is able to form structures other than the most commonly encountered spheres or disks. This includes the family of quaternary ammonium compounds, which is the subject of this paper. The geometry of the micelles is similar to polymer molecules. This network of micellar structure resists distortion, whereby the viscosity increases and imparts viscoelastic properties to the fluid. In this system. unlike guar-based fluids, no crosslinker is necessary. There is a repulsive interaction in micelle structure, primarily between the positively charged head groups. P. 553^

Caldesmon, an actin/calmodulin binding protein, inhibits acto-heavy meromyosin (HMM) ATPase, while it increases the binding of HMM to actin, presumably mediated through an interaction between the myosin subfragment 2 region of HMM and caldesmon, which is bound to actin. In order to study the mechanism for the inhibition of acto-HM ATPase, we utilized the chymotryptic fragment of caldesmon (38-kDa fragment), which possesses the actin/calmodulin binding region but lacks the myosin binding portion. The 38-kDa fragment inhibits the actin-activated HMM ATPase to the same extent as does the intact caldesmon molecule. In the absence of tropomyosin, the 38-kDa fragment decreased the KATPase and Kbinding without any effect on the Vmax. However, when the actin filament contained bound tropomyosin, the caldesmon fragment caused a 2-3-fold decrease in the Vmax, in addition to lowering the KATPase and the Kbinding. The 38-kDa fragment-induced inhibition is partially reversed by calmodulin at a 10:1 molar ratio to caldesmon fragment; the reversal was more remarkable in 100 mM ionic strength at 37 degrees C than in 20 or 50 mM at 25 degrees C. Results from these experiments demonstrate that the 38-kDa domain of caldesmon fragment of myosin head to actin; however, when the actin filament contains bound tropomyosin, caldesmon fragment affects not only the binding of HMM to/actin but also the catalytic step in the ATPase cycle. The interaction between the 38-kDa domain of caldesmon and tropomyosin-actin is likely to play a role in the regulation of actomyosin ATPase and contraction in smooth muscle.

Summary This paper examines a new class of viscoelastic surfactants (amphoteric) that are used to enhance sweep efficiency during matrix acid treatments. It appears that surfactant molecules align themselves and form rod-shaped micelles once the acid is spent. These micelles might cause the viscosity to significantly increase, and induce viscoelastic properties to the spent acid. The enhancement in these properties depends on the micelle shape and magnitude of entanglement. The effects of acid additives and contaminants [mainly iron (III)] on the rheological properties of these systems were examined over a wide range of parameters. Viscosity measurements were conducted using specially designed viscometers to handle very corrosive fluids. Measurements were made between 25 and 100°C, and at 300 psi at various shear rates from 58 to 1,740 s-1. Acid additives included corrosion inhibitors, inhibitor aids, an iron control agent, a hydrogen sulfide scavenger, an anti-sludge agent, and a nonionic surfactant. Effects of mutual solvents and methanol on the apparent viscosity were also investigated. It is observed that temperature, pH, shear conditions, and acid additives have a profound influence on the apparent viscosity of the surfactant-acid system. The viscosity and related properties are very different from what were observed with both natural and synthetic polymers. The differences in these properties were characterized and correlated with the type and nature of the additives used. Optimum conditions for better fluid performance in the field were derived. Introduction Previous studies (Thomas et al. 1998) highlighted the need for proper diversion during matrix acidizing treatments of carbonate reservoirs. Various systems were introduced to enhance diversion by increasing the viscosity of the injected acid. Depending on the viscosifiying agent, these systems can be divided into two main categories: polymer-based acids and surfactant-based acids. Acid-soluble polymers have been used to increase the viscosity of HCl, and to improve its performance (Pabley et al. 1982; Crowe et al. 1989). As the viscosity of the acid increases, the rate of acid spending decreases and, as a result, deeper acid penetration into the formation can be achieved (Deysarkar et al. 1984). Addition of suitable synthetic or natural polymers to HCl improved acid penetration; however, acid placement did not significantly improve (Yeager and Shuchart 1997). Crosslinked acids were introduced in the mid-70s, as cited by Metcalf et al. (2000). These acids have much higher viscosity than regular acids or acids containing uncross-linked polymers. Two types of crosslinked acids are available The first type consists of a polymer, a crosslinker, and other acid additives [e.g., corrosion inhibitors and iron control agents (Johnson et al. 1988)]. The acid in this case is crosslinked on the surface and reaches the formation already crosslinked. The second type of crosslinked acid consists of a polymer, a crosslinker, a buffer, a breaker, and other acid additives. The acid in this case reaches the formation uncrosslinked, and the crosslinking reaction occurs in the formation (Yeager and Shuchart 1997; Saxon et al. 2000). In-situ gelled acids were the subject of several lab and field studies. In general, lab and field results were positive; however, there were several concerns raised about these acids. Taylor and Nasr-El-Din (2002, 2003) noted that in-situ gelled acids caused loss of core permeability in tight carbonate cores. Permeability loss was attributed to polymer retention in the core and on the injection face of the core. A similar observation was noted by Chang et al. (2001). Lynn and Nasr-El-Din (2001) noted precipitation of the crosslinker (iron) when in-situ gelled acids were used to enhance the permeability of tight cores at high temperatures. Nasr-El-Din et al. (2002) showed that the crosslinker (Fe(III)) may precipitate in sour environments. Mohamed et al. (1999) reported poor field results when large volumes of polymer-based acids were used to stimulate seawater injectors with tight carbonate zones.