Visco-Elastic Surfactant (VES) fluids are polymer-free fluids that generate viscosities suitable for fracturing operations without the use of polymer additives. VES fluids do not form polymer filter-cake, and thus, viscous resistance of the fluid flowing through the rock matrix primarily governs fluid loss. This has historically limited the application to fracturing reservoirs with low permeabilities. A new VES fracturing fluid has been developed for use in high permeability reservoirs and successfully pumped in the Gulf of Mexico. The fluid exhibits enhanced fluid efficiency while still maintaining the high proppant pack conductivity associated with the lack of polymer damage. In this paper, laboratory test results for the new fluid are presented along with three high-permeability case histories. The estimated reservoir permeabilities were as high as 167 mD and reservoir heights ranged from 30 -90 feet. In all cases the entire propped fracture design was successfully placed. Introduction Visco-elastic surfactants have been used in oil and gas wells for fracturing stimulation for over ten years1. During this time the technology has evolved from a niche application in gravel packing2 to a mainstream range of applications where clean proppant packs and gravel packs are desired3. In the latest form presented here, a VES fluid utilizing a new surfactant has been formulated and optimized for high permeability operations. Fluid Rheology Viscosity of a VES fluid is created by self-assembly of surfactant molecules in an aqueous solution. Hydrophobic tails of surfactants associate and orient to create rod shaped structures commonly referred to as micelles. Entanglement of these flexible micelles imparts viscosity to the solution as shown in Figure 1. A variety of surfactant types can be used for formulating VES fluids, including anionic surfactants, cationic surfactants, and zwitterionic surfactants4. The new VES fluid presented here utilizes a specially formulated zwitterionic surfactant that creates stable micelles with unusual high-temperature stability. Figure 2 presents the fluid rheology as a function of temperature for different levels of surfactant package concentration. The surfactant package creates useful rheology within concentrations ranging from 3.5% to 6%. The exact surfactant concentration depends on the bottom hole temperature and desired fluid viscosity. Fluid Breaker The VES fluid can break to water-like viscosity by exposure to liquid hydrocarbons or dilution with reservoir brines. Additionally, a new encapsulated breaker has been developed for the zwitterionic VES described here. The encapsulated material uses a polyelectrolyte to disrupt the surfactant micelles and lower the fluid viscosity even in dry gas wells where there is neither brine nor liquid hydrocarbon to assist the breaking process. The effectiveness of this breaker has been measured in a series of proppant pack conductivity tests demonstrating greater than or equal to 95% retained proppant pack permeability. Laboratory Fluid Loss Measurements To model the fluid loss properties, the VES system was injected into 12-inch long sandstone cores at a constant driving pressure of 1000 psi. The cumulative fluid volume flowing into the core was measured as a function of time and the total fluid loss coefficient vs. permeabilities was plotted in Figure 3. Also shown in Figure 3 is the typical trend for total fluid loss coefficient of crosslinked polymer fluids. The results indicate that the fluid loss coefficient for the VES system is comparable to that achieved with crosslinked polymers.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Monterey formation, Belridge Diatomite is a high porosity (45%) low permeability (0.5 -7 md), low Young's modulus (~100,000 psi) oil reservoir with few stress barriers for fracture containment. Due to the low permeability it is desirable to optimize the fracture length per pound of proppant placed. Conventional cross-linked fluids are not well suited for this purpose as they create excessive width -reducing the effective fracture length generated for a given amount of proppant. Post-treatment production tests often show only 30 -100 ft of effective fracture length even for relatively large treatments designed for longer length. Not only is production limited by these shorter-than-designed half-lengths; excessive fracture width combined with low closure stress often leads to serious sand production problems. Pseudo-3D simulations indicated that longer fractures could be realized by significantly reducing fluid viscosity.A novel low viscosity fracturing fluid, designed to address the serious problems unique to low-modulus formations, was field-tested in the Lost Hills field, California. The lowviscosity fluid developed for this application was composed of a linear gel and a fibrous material. Laboratory studies established that the fiber greatly hinders proppant settling, while maintaining a low slurry viscosity required for fracture length creation. Proppant concentrations up to 12 PPA were pumped with this fluid.Seven new wells were treated with the novel fluid. All wells were fractured in multiple stages; 1,250,000 to 1,500,000 lbm of proppant was used in each well. Real-time pressure data was collected on all stages, and treatments on the first two wells were observed with downhole tiltmeters. Both pressure and tiltmeter data indicated that for similar sized treatments, longer fracture half-lengths were achieved with the new fluid -200-400 ft -versus 30-100 ft for conventional crosslinked gels. Production from the test wells compares favorably to offsets, while using 30% less proppant than conventional treatments.Furthermore, it appears that proppant flowback and sanding problems are significantly reduced.

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