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.

Summary Understanding the causes of damage to fracture conductivity is vital to design fracture treatments for maximum economic value and to analyze the actual well performance. High-viscosity fluids, resulting from retention of polymer within the proppant pack during closure, play a major role in proppant-pack damage. Viscous fluids are not effectively displaced during flowback and production of hydrocarbon unless the viscosities of the phases are similar. The consequences of viscous fingering in the fracture are discussed, and a method is presented for predicting the retained permeability of proppant packs in which guar-based hydraulic fracturing fluids have been broken. Data required for the method are temperature, polymer molecular weight and final polymer concentration. Introduction Proppant pack damage caused by polymeric fracturing fluids has generally been attributed to residue or high polymer concentrations remaining in the fracture after closure. For example, Cooke found that fluids which yielded lower volumetric levels of residue on breaking generally caused less pack damage. Hawkins and Brannon and Pulsinelli placed greater emphasis on the difficulty of removing high polymer concentrations from the proppant pack. High polymer concentrations are the result of the filtration process which occurs during fracture closure. If the formation pore sizes are too small to allow invasion by guar molecules, the guar concentration in the fracture may increase dramatically. According to the calculations of Brannon and Pulsinelli, a concentration factor of 10 is easily achieved for an average proppant concentration of 3 ppga. They reported that high breaker concentrations are necessary to effectively remove damage. Parker and McDaniel had similar concerns about high polymer concentrations, but they were particularly worried about removing the filtercake. This paper discusses the damage to fracture conductivity resulting from channeling or viscous fingering. Fingering will occur during flowback following a fracturing treatment when low-viscosity fluIds (leakoff or formatIon fluid) pass through the degraded fracturing fluid remaining in the proppant pack. Fingering leads to bypassing of part of the pack, which causes a loss of effective fracture area. The extent of fingering can be predicted from the contrast between the viscosity of the fluid in the pack and the viscosity of the displacement fluid.

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.

The relationship between rheology and fluid loss and the effects of shear history, temperature, crosslinker and fluid-loss additive on fluid loss of hydroxypropyl guar gels are discussed. Tests were performed under dynamic conditions using an apparatus performed under dynamic conditions using an apparatus which incorporates in-line mixing of crosslinked fluids, so that fluids whose fluid-loss properties are measured have rheological characteristics similar to those generated under field mixing conditions. Introduction The fluid-loss properties of the fluid used in a hydraulic fracturing job are very important to the success of the treatment. Leakoff affects the fracture volume to fluid volume ratio achieved and so is a consideration in both the engineering and the economics of the treatment. Realistic measurements of fluid-loss properties are necessary so that proper fluid and properties are necessary so that proper fluid and fluid-loss additive(s) selection can be made from among the many available and so that proper job design for a given fluid can be achieved. Efforts have been made in the past to get more realistic measurements by studying fluid loss under dynamic conditions. Tests were performed so that the fracturing fluid was kept moving under pressure past the test surface area. This type of testing began with Hall and Dollarhide, who observed that fluid loss was proportional to time rather than to (time). It has continued through the years, with experimental conditions changing to match the fluid types and treating conditions used at the time. A number of fluid systems are in use today. They include noncrosslinked polysaccharides, borate-crosslinked gels, transition metal-crosslinked gels and delayed-crosslinking systems. On the basis of composition alone, these fluids might be expected to exhibit different fluid-loss characteristics. But a recent study 7 has shown that not only fluid chemistry but also the method of preparation affects fluid rheology. The rheology of a fluid prepared in a lab blender is quite different from the rheoloyy of a fluid generated by injecting crosslinker into a polymer solution flowing in a tube. Under flowing conditions, fluid rheology may also affect fluid loss. Accurate measurement of fluid-loss properties requires that the fluids be generated in a manner which simulates field mixing as closely as possible. This paper describes an apparatus for studying fluid loss under dynamic conditions. The apparatus includes equipment for crosslinking the fluids as they are flowing through tubing. The effects of fluid composition, shear history, temperature and fluid-loss additives are presented. EXPERIMENTAL A schematic diagram of the apparatus used is shown in Figure 1. Base fluid containing hydroxypropyl guar, water and various additives was prepared in large mix tanks and then pumped into the test system with a positive-displacement triplex pump. Crosslinker or crosslinker activator was injected into the polymer stream as it entered a static mixer so that crosslinking polymer stream as it entered a static mixer so that crosslinking was accomplished on the fly. The crosslinker-polymer mixture traveled through tubing prior to heating to provide the desired shear history for the fluid. The shear history could be varied by changing the pump rate or tubing arrangement. In general, the fluid was sheared at least 11 sec at a shear rate greater than 1,600 sec(-1) and at least 90 sec at a shear rate greater than 123 sec(-1). Specifics are presented in Table 1. The fluid was then heated to test temperature in a heat exchanger 6.1 m in length. Heating occurred in one to three minutes at 15 to 45 sec shear rate. The hot fluid passed through 18.3 m of 1.09-cm ID tubing (123 to 370 sec(-1)) before reaching the fluidloss cell. Once through the fluid-loss cell, the fluid passed through a dome-loaded, back-pressure regulator used to pressurize the system and into a large waste tank. Thus, the fluid makes a single pass across the core, better simulating fluid loss near the wellbore than fluid loss far out in the fracture.

MEETING. A13STRACT aused only a 2(r/a loss in viscosity in one hour. These kftratory tests Indicate that encapsulated breaker may Increase well Persulfates are commonly used as breakers for aqueous production by improving proppant pack clearkip. fluids viscosified with guar or cellulose derivatives. These breakers are necessary to minimize permeability damage to proppant or gravel packs at temperatures where there is little INTRODUCTION thermal degradation of the polymers. Unfortunately, dissolved persulfates are much too reactive even at moderate temperatures Recerd laboratory investigabons have shown that polynwrlc (60-93.30C) to be used at concentrations sufficient to thoroughly fracturing fluids can cause significant proppant pack permeablity degrade oonoontrated, Ngh mokmiar weight polymers. New technology described In this paper has been utilized to produce a 'delayed' breaker. The breaker is prepared bv encapsulating ammonium persultate with a water-resistaet coating. The coating shields the fluid from the breaker so that high concentrations of breaker can be added to the fluid v4thout causing premature loss of fluid properties such as viscosity or fluid loss control. Critical factors in the design of encapsulated breakers, such as coating harder properues, release mechanisms, and reactive-chemicals properties are discussed. The effects of encapsulated breaker on fluid dmlogy were compared for several encapsulated persulfates. Only one material had a coating adequate to protect the fluid from premature degradation. Additional rheology and conductvlty damage studies were done with this product. It was found that In a borate-crosslinked fluid at 71-0, 240 g/m3 of the encapsulated breaker caused an improvement in retained permeability from 15% to 490/., but References and illustrations at end of paper. impairment Major contributors to this problem are the stablifty of the polymers below 107.20-121.1 OC and the concentration of polymer which occurs dudng a fracturing treatment. Penny has suggested that the polymer is conoentmted 5-7 times due to fluid loss during pumping and closure. He reported 50% damage for conductivity tests using polymeric fluids when compared with tests run without fracturing fluids. Hawkins pointed out that under worst-case conditions, where all the polymer in the fluid is concentrated in the proppant pack, the concentration increase would be 25-told for fluid containing 240 kgtm3 sand. Higher sand concentrations in the fluid and a larger ratio of fractured area to ProPped fracture area would reduce the concentration factor in the proppant bed. Hawkins presented data shoimng the effect of final polymer concentration on fracture permeability. His tests showed that the permeability of a 850-425 ilm mesh sand pack decreased from about 138 lim2 to about 79 lim2 for 12 kg/m3 final concentration of polymer and to about 39 Jim for 36 kg/m3 polymer. This corresponds to retained permeabilities of 57 and 29%, respectively. Parker and McDaniel have emphasized the need to consider filtercake effect...