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.

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^

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Summary The crystalline nature of hydrated Portland cement is dependent primarily on temperature. The calcium silicate hydrate (CSH) gel is produced at low temperatures and, upon curing at higher temperatures, will convert to one or more crystalline phases. The better cementing compositions contain a low lime-to-silica (C/S) ratio. Xonotlite is a phase commonly produced above 150 deg. C (302 deg. F) when approximately 35% fine silica is added to Portland cement. Generally, it has good strength but moderate permeability, Truscottite, produced when an even larger quantity of silica is added to the cement, has lower permeability than xonotlite but is slightly more difficult to produce and to stabilize. Pectolite can be produced by introducing sodium into a truscottite-type formulation. Once formed, pectolite is very stable but typically has high permeability. The addition of carbonate to any of these formulations may produce scawtite. Scawtite appears to be an inferior phase by itself, but in small quantities it can be helpful in strength development. Introduction The failure of wells in several geothermal fields has been directly attributed to degradation of cement. This implies that the cementing materials used to complete geothermal wells had not been sufficiently evaluated. For the past 3 years, under the auspices of the U.S. DOE, we have studied geothermal cementing materials in an attempt to identify suitable systems. A major portion of this study was devoted to research on the behavior of calcium silicate hydrates at the high temperatures found in geothermal zones. The literature contains many references pertaining to calcium silicate hydrates in wells at temperatures up to 150 deg. C (302 deg. F), but little has been published concerning higher temperatures. Portland cement is the material normally used to seal steel pipe in a borehole. Originally designed for hydration at or near atmospheric temperature, Portland cement can be adapted for use in petroleum or geothermal wells with bottomhole temperatures approaching 370 deg. C (700 deg. F). The hydration chemistry and phase equilibria of Portland and similar calcium silicate cements change with increasing temperature. At atmospheric temperatures, tricalcium silicate (C3S)* and dicalcium silicate (C2S), which comprise about 75% of the dry Portland cement composition, react with water to form a CSH gel with variable composition and calcium hydroxide (CH). A cement slurry becomes rigid when less than one-half, and sometimes less than one-fourth, of the cement has hydrated. At this point, pores begin to close and free movement of water is no longer possible within the cement. Consequently, a true gel is formed that is strong and impermeable. Calcium ions migrate from C3S and C2S particles into the water trapped in pores. Silica migrates from quartz (sand) grains into the water at various locations. The resulting calcium silicate reaction products are high in calcium at one point and high in silica at another. Aluminum ions released by another important compound in Portland cement, tricalcium aluminate (C3A), are also of concern. Considering the number of calcium silicate compounds and aluminum substitutions possible, it is surprising that reasonably pure cement phases are commonly obtained. As temperature increases to about 120 deg. C (247 deg. F), CSH gel converts to other crystalline forms. If excess calcium hydroxide is present, alpha dicalcium silicate hydrate (alpha-C2SH), a very weak and porous material, is produced. Fine silica is normally added to Portland cement to prevent this. If at least 35% silica is added to Portland cement, to bermorite (C5S6H5 approximately), also a strong and impermeable binder, usually is formed. JPT P. 1373^

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