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Conventional breakers reduce fracturing-fluid viscosity much too rapidly, even at moderate temperatures (140 to 200°F), to be used at the high concentrations required to degrade polymers within proppant packs. A delayed-release, encapsulated breaker was developed that permits the use of high breaker concentrations and thus significantly increaSes fracture conductivity. AbstractPersulfates are commonly used as breakers for aqueous fluids viscosified with guar or cellulose derivatives. These breakers are necessary to minimize permeability damage to proppant packs at temperatures where there is little thermal degradation of the polymers. Unfortunately, dissolved persulfates are much too reactive, even at moderate temperatures (140 to 200 0 P), to be used at concentrations sufficient to degrade concentrated, high-molecularweight polymers thoroughly.New technology described in this paper was used to produce a "delayed" breaker. The breaker is prepared by encapsulating ammonium persulfate (APS) with a water-resistant coating. The coating shields the fluid from the breaker so that high breaker concentrations can be added to the fluid without causing the premature loss of fluid properties, such as viscosity or fluid-loss control. Critical factors in the design of encapsulated breakers (such as coating barrier properties, release mechanisms, and reactive chemical properties) are discussed. The effects of encapsulated breaker on fluid rheology were compared for several encapsulated persulfates. Only one material had a coating adequate to protect the fluid from premature degradation. Additional rheology and conductivity damage studies were done with this product. It was found that in a boratecrosslinked fluid at 160 o P, 2 Ibm/I ,000 gal of encapsulated breaker caused an improvement in retained permeability from 15% to 49 %, but caused only a 20 % loss in viscosity in 1 hour. These laboratory tests indicate that an encapsulated breaker may increase well production by improving proppant-pack cleanup.

Conductivity damage resulting from fracturing fluids has been frequently observed in laboratory tests and is often indicated by production results. Abnormally high breaker concentrations were used in a number of fracturing treatments of gas reservoirs in attempts to minimize proppant conductivity damage and improve well performance. Concentrations of breaker of up to 10 lb/1,000 gal (three to five times the normal concentration) were added to fluids without causing premature loss of viscosity. These concentrations were made possible by encapsulating the breaker with a water-barrier coating and properly scheduling the breaker addition. The breaker addition schedule was optimized to account for the increasing polymer concentrations due to fluid loss as well as the fluid exposure time at the maximum temperature. Improved well performance has been seen when using higher than normal breaker concentrations. The improved performance includes higher production rates. It can be shown that all of these results can be attributed to higher fracture conductivity because of the reduction of proppant conductivity damage.

Backproduction of proppant from hydraulic fractures (proppant flowback) is a continuing operational problem in the oil and gas industry. Up to 20% of the proppant can be flowed back after the treatment. Curable resin-coated proppants are used to control proppant production, but are known to chemically interact with fracturing fluids and may be prone to several failure mechanisms. Curable resin-coated proppants also require either well shut-in or the use of activators at low temperatures. A new method to control proppant flowback relies on fibers mixed with the proppant to stabilize the proppant pack. The main advantage of this patented3 technology is that it is physical rather than chemical. Therefore, proppant flowback is controlled without specific shut-in time, temperature, or pressure constraints. This paper presents flowback results from fractures of dry gas wells (<1 millidarcy permeability) where fiber/proppant mixtures were used to control proppant flowback (11 cases). Fluid flowback rate, gas rate and proppant production were monitored during the cleanup period. These wells are compared to wells where either curable resin-coated proppants or no flowback control were used (15 cases). The fiber/proppant mixtures controlled flowback of proppant for both sand and ceramic proppants when used with all the proppant or in only the last part of proppant (tail-in). Flowback could begin right after the fracturing equipment was rigged down (15 to 30 minutes). Cleanup fluid flow rates were up to ten times higher than previously obtainable with curable resin-coated proppants and less proppant was flowed back. Faster flowback rates also resulted in earlier onset of gas production and reduced flowback time. Fibers allow greater latitude in flowback rate than curable resin- coated proppants without the need for shut-in time. Introduction Propped hydraulic fracturing is successfully used in many formations to enhance production. One associated problem is the backproduction of proppant during cleanup and throughout the life of the well (proppant flowback). Up to 20% of the proppant placed in the fracture can return during the cleanup period. The proppant that flows back has a detrimental wear effect on the production equipment. and requires the use of separators in the production line. Concern about proppant flowback can limit the flow rates during cleanup and production. Curable resin-coated proppants (RCP) are the predominant technology to control proppant flowback. They are used as all or the last part (tail-in) of the proppant in the fracture. The resin coating cures to form a strong proppant pack under conditions of sufficient closure stress, shut-in time, and temperature. Curable RCPs control proppant flowback in many cases but can have several disadvantages. They are known to interact with the fluid chemistry (pH, crosslinkers, breakers, etc.), can reduce fracture conductivity, and may be prone to failure under cyclic loading conditions. Further, RCPs need specific temperature, shut-in time and stress conditions to form a strong bond. Shut-in time can be as long as overnight, and at low temperatures (<150 F) additional chemical activators must be added to promote cure. P. 453

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