TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFor a number of years, visco-elastic surfactant (VES) fluids have been used for a variety of stimulation treatment applications, including hydraulic fracturing, acid diverting, and gravel packing. VES fluid systems typically offer higher retained permeability and conductivity of the formation sand and proppant pack than polymeric systems. However, preliminary cost, a 200ºF temperature limit, excessive leakoff, and no internal breaker mechanism for dry gas applications have limited VES use.New VES fluid technology has been developed that substantially improves product performance and cost effectiveness. The temperature range has been extended to 300ºF by using newly developed VES stabilizer technology. The system works with high-density brines up to 14.4 ppg. Internal breakers have been developed that permit controlled viscosity break from ambient to 300ºF. Laboratory tests have determined that an internally broken fluid rapidly achieves >90% returned permeability and conductivity of the formation sand and proppant pack without the presence or need for contacting hydrocarbons. Fluid loss control technology has been developed that reduces VES fluid leak-off similar to wall-building fluids, but without filtercake damage. This paper discusses the development of the new VES system chemistry and its properties. The paper also addresses the merits of a viscous fluid that can work in a variety of base fluids for high-pressure applications such as managing surface treating pressure or for gas hydrate inhibition in deep gas or deepwater environments. Breaker technology discussion addresses the ability to ensure and enhance VES fluid viscosity breaking. Fluid loss control technology effective to at least 2000 md is presented. This paper also presents rheological, return permeability and conductivity, fluid loss control, treating pressure, and financial results.

For a number of years, viscoelastic surfactant (VES) fluids have been used for a variety of stimulation treatment applications, including hydraulic fracturing, acid diverting, and gravelpacking. VES fluid systems typically offer higher-retained permeability and conductivity of the formation sand and proppant pack than polymeric systems. However, preliminary cost, a 200°F temperature limit, excessive leakoff, and no internal breaker mechanism for dry gas applications have limited VES use.New VES fluid technology has been developed that substantially improves product performance and cost effectiveness. The temperature range has been extended to 300°F by using newly developed VES stabilizer technology. The system works with high-density brines up to 14.4 ppg. Internal breakers have been developed that permit a controlled viscosity break from ambient to 300°F. Laboratory tests have determined that an internally broken fluid rapidly achieves >90% returned permeability and conductivity of the formation sand and proppant pack without the presence or need for contacting hydrocarbons. Fluid loss-control technology has been developed that reduces VES fluid leakoff similar to wallbuilding fluids, but without filtercake damage.This paper discusses the development of the new VES system chemistry and its properties. The paper also addresses the merits of a viscous fluid that can work in a variety of base fluids for highpressure applications, such as managing surface-treating pressure or for gas-hydrate inhibition in deep gas or deepwater environments. Breaker technology discussion addresses the ability to ensure and enhance VES fluid-viscosity breaking. Fluid loss-control technology effective to at least 2,000 millidarcies (mD) is presented. This paper also presents rheological, return permeability and conductivity, fluid loss control, treating pressure, and financial results.

A high percentage of oil and gas wells worldwide are hydraulically fractured in order to allow a reservoir to become economically producible and to improve the rate of hydrocarbon production. Annual global investments for hydraulic fracturing are at one billion dollars. Crosslinked polymer fluids are the most commonly used fracturing fluid because of cost and performance criteria. The crosslinked polymer fluids exhibit exceptional performance features to initiate and propagate a fracture, carry proppant and control fluid leak-off into the reservoir during a treatment. However, crosslinked polymer fluids leave a significant amount of polymeric filtercake material in the fracture once a treatment is completed. Decades of improving oxidative, enzyme and other breakers for the polymer fluids has only marginally improved from about 30% to about 50% by weight the amount of polymer residue left within the fracture. The result has been a continuation of much lower than optimum hydrocarbon recovery rates for many wells. New surfactant-based fluid technology is being developed that will in many geographic regions replace polymericbased fracturing fluids over the next decade. This paper will introduce a new fluid technology that uses nanoparticles, special internal breakers and low molecular weight viscoelastic surfactants (VES) to achieve the performance features of crosslinked polymer fluids but leaves little to no gel residue. Unique nanoparticles have been found that "pseudo-crosslink" VES micelles together through electrostatic and van der Waals forces. This micelle-networked fluid property will allow unique "pseudo-filtercake" to form on porous media, like crosslinked polymer fluids exhibit, to control fluid leak-off and improve fluid efficiency. The special internal breakers reside within the micelles and go wherever the fluid goes, including the networked micelles composing the pseudo-filtercake. The internal breakers controllably break the viscosity of the VESbased pseudo-filtercake by rearranging the VES micelles to spherical non-viscous structures and dispersed nanoparticles that readily flow back with producing fluids and do not impair the proppant pack conductivity. The primary result will allow a wide range of hydraulically fractured reservoirs to produce at substantially higher sustained rates than presently achievable, particularly for deepwater and other high investment wells. Introduction Crosslinked polymer fluids are the most common type of hydraulic fracturing fluid. These fluids can achieve high viscosities with very low leak-off rates for a wide range of reservoir temperatures and permeabilities. With their efficient leak-off control, crosslinked polymer fluids can be used to generate excellent fracture geometry in most reservoirs. They are also known to have good proppant suspension and placement capability. However, crosslinked polymer fluids have an inherent weakness that decades of developing internal and encapsulated breaker technologies have not been able to resolve: this weakness is the amount of polymer residue that remains within the fracture after a treatment. In most cases residual polymer reduces the proppant conductivity by at least 50%. During the current period of increased global demand for conventional hydrocarbons, a major breakthrough is needed in crosslinked polymer fluid technology where 80% to 100% regained proppant conductivity can be routinely achieved. Without this breakthrough the rates of hydrocarbon recovery will not reach their potential for conductivity-limited reservoirs, and the foremost limitation of crosslinked polymer systems will continue to impact the profitability of oil and gas wells throughout the world.

There are many advantages to using a single component, non-ionic viscoelastic surfactant gel (VES) for sand control and stimulation applications. The VES is highly compatible with a wide range of completion brines and crude oils, is virtually non-damaging to the formation and demonstrates shale-stabilizing characteristics with many types of shale. Another advantage of having a single additive VES system is that it requires a small equipment footprint. With this combination of compact equipment set-up and simplified fluid mixing, complex, high rate, high sand concentration frac jobs are possible where rig space is limited or equipment is limited because of the remote location from full stimulation service. A treatment using a single additive system can typically be performed with only one or two frac pumps, a frac blender, proppant silo or a modified sand infuser and data acquisition equipment. Many offshore facilities have commingled gathering systems many of which must be treated for emulsions with chemicals. This treatment process may be substantially reduced or simplified when a non-ionic VES fluid is used for stimulation compared to a crosslinked gel fluid. The high compatibility with completion brines and crude oils, coupled with the non-damaging nature of the VES itself, reduces the likelihood of formation damage in the well. The VES promotes a fast and more thorough recovery of the stimulation fluid from the formation and if emulsions are generated, it will allow for easier treatment in the surface facility. Since December 2000, non-ionic VES gels have been used in over 30 applications in the Adriatic Sea and in the Gulf of Mexico in brines ranging from seawater with varying amounts of KCl to 10.5 ppg CaCl2. Each application has resulted in enhanced production due to the excellent performance of the fluid. Clean-up rates have been directly related to bottom hole pressure, and have not been complicated with typical clean-up problems such as clay swelling, water blocks, and filter cake plugging of proppant packs. This type of treatment with a minimum equipment set-up has made high rate/volume frac treatments possible without the need of a stimulation vessel. Introduction The fracturing industry has focused on polymer-based fracturing fluids as their chemistry of choice for years1. The benefits of high viscosity and proppant placement have outweighed the disadvantages of formation damage and fluid complexity and sensitivity. Recently, polymer-free VES fluids have emerged as a possible alternative to the polymer-based chemistry2; however, compatibility issues between the VES fluids and various completion brines3 and with crude oils have caused some concern. New developments in VES technology have yielded non-ionic VES fluids that are highly compatible with completion brines and crude oils, without compromising their viscosity, proppant carrying capacity or non-damaging characteristics. These new generation VES fluids require only the base brine and concentrated surfactant for sufficient viscosity generation. The VES fluid can easily be mixed on a stimulation vessel using a standard blender setup, or on a rig from skid mounted equipment. The system requires a minimal amount of rig space due to its single additive design. Brine Compatibility Most polymer-based fracturing fluids are gelled in low weight brine such as 2% KCl4; however, the completion fluid controlling the well is typically a heavier brine. The compatibility of the fracturing fluid with this completion fluid is very important. Emulsion tendencies between the fracturing fluid and the completion brine would cause problems downhole. It is possible to gel polymer-based fracturing fluids in heavy weight brines and seawater; however, special formulas must be developed in order to offset the negative effects of the brine on the system5. An ideal fluid system would be one that is compatible with the completion brine.

Surfactant-based gels (SBGs) exhibiting viscoelastic properties have been introduced recently for sand control and stimulation applications. However, limited data are available on their friction pressure losses through tubing and proppant transport behavior. Therefore, an experimental investigation was performed to study the friction pressure and proppant transport behavior of SBG fracturing and sand control fluids. The friction pressure of the clean and slurry fluids were evaluated in tubing of various configurations and lengths up to 1000 ft. The proppant transport behavior of the fluids was observed through a transparent slot and a High Pressure Fracture simulator, and proppant settling in small-scale laboratory tests. The friction pressure results show that the SBGs exhibit stable and significant drag reduction under most of the flow conditions. The presence of sand in the solutions increases the friction losses through tubing, but to different amounts depending on tubing geometry and configuration. The proppant transport behavior of the SBGs was observed to be comparable to the behavior of the 35- and 40-lbm/Mgal crosslinked gels evaluated under similar slot flow conditions. This study of SBGs provides unique results obtained in a large-scale test facility and in a small-scale laboratory environment. These experimental results, in turn, provide information to aid field personnel in designing gravel packs, frac packs, and other completion and stimulation treatments. These data also will aid in the eventual development of friction pressure and proppant transport prediction methods for SBGs. Introduction Friction Pressure Study. The goal of this flow testing was to observe the friction loss characteristics of viscoelastic SBGs in tube and pipe and to model these characteristics. We chose to use existing methods to predict the friction loss of SBGs ranging in concentration from 2 to 6% (vol) surfactant. Some methods considered were based in part on theoretical considerations while others were empirical in nature. The methods evaluated for straight tube and pipe included the methods of Savins and Seyer1, Seyer and Metzner2, Rodriguez, Zakin, and Patterson3, and Astarita, Greco, and Nicodemo4. The Savins and Seyer method using the correlation of drag reduction ratio and friction velocity gives no concentration invariance when comparing several viscoelastic solutions at different concentrations. The method of Seyer and Metzner requires evaluation of the relaxation time for the polymer solution tested. This relaxation time is a function of wall shear rate, which presents a problem as to what value to use. The method of Rodriguez, Zakin, and Patterson, although offering diameter and concentration invariance, requires a polymer solution relaxation time calculated using the Zimm Theory and a value of the intrinsic viscosity of the polymer solution. We lastly evaluated the method of Astarita, Greco, and Nicodemo for straight tube and pipe. Because this method offers invariance to both diameter and concentration, and because all necessary model parameters are obtained from pipe flow data, we chose to further investigate the Astarita, et. al. method in this paper. For coiled tubing we chose to investigate the empirical correlation from Willingham and Shah5. Proppant Transport Study. Understanding of proppant transport behavior of fluids used for sand control and fracturing applications is important for the success of the treatment6. Most of the proppant transport studies are performed with polymer-based fluids7. Recently SBGs were introduced8 to the industry, but there are few studies on the proppant transport characteristics of these new fluids. The present study tries to fill this gap in the industry and describes the proppant transport behavior of SBGs studied through a slot model of a fracture and small-scale proppant settling tests. Friction Pressure Study. The goal of this flow testing was to observe the friction loss characteristics of viscoelastic SBGs in tube and pipe and to model these characteristics. We chose to use existing methods to predict the friction loss of SBGs ranging in concentration from 2 to 6% (vol) surfactant. Some methods considered were based in part on theoretical considerations while others were empirical in nature. The methods evaluated for straight tube and pipe included the methods of Savins and Seyer1, Seyer and Metzner2, Rodriguez, Zakin, and Patterson3, and Astarita, Greco, and Nicodemo4. The Savins and Seyer method using the correlation of drag reduction ratio and friction velocity gives no concentration invariance when comparing several viscoelastic solutions at different concentrations. The method of Seyer and Metzner requires evaluation of the relaxation time for the polymer solution tested. This relaxation time is a function of wall shear rate, which presents a problem as to what value to use. The method of Rodriguez, Zakin, and Patterson, although offering diameter and concentration invariance, requires a polymer solution relaxation time calculated using the Zimm Theory and a value of the intrinsic viscosity of the polymer solution. We lastly evaluated the method of Astarita, Greco, and Nicodemo for straight tube and pipe. Because this method offers invariance to both diameter and concentration, and because all necessary model parameters are obtained from pipe flow data, we chose to further investigate the Astarita, et. al. method in this paper. For coiled tubing we chose to investigate the empirical correlation from Willingham and Shah5. Proppant Transport Study. Understanding of proppant transport behavior of fluids used for sand control and fracturing applications is important for the success of the treatment6. Most of the proppant transport studies are performed with polymer-based fluids7. Recently SBGs were introduced8 to the industry, but there are few studies on the proppant transport characteristics of these new fluids. The present study tries to fill this gap in the industry and describes the proppant transport behavior of SBGs studied through a slot model of a fracture and small-scale proppant settling tests.