Persulfates are commonly used as breakers for aqueous 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 thermal degradation of the polymers. Unfortunately, dissolved persulfates are much too reactive even at moderate temperatures (60–93.3 °G) to be used at concentrations sufficient to thoroughly degrade concentrated, high molecular weight polymers.
New technology described in this paper has been utilized to produce a "delayed " breaker. The breaker is prepared by encapsulating ammonium persulfate with a water-resistant coating. The coating shields the fluid from the breaker so that high concentrations of breaker can be added to the fluid without causing premature loss of fluid properties such as viscosity or fluid loss control. Critical factors in the design of encapsulated breakers, such as coaling barrier properties, release mechanisms, and reactive-chemicals properties are discussed. The effects of encapsulated breaker on fluid rheology were compared for several encapsulated persulfates. Only one material had a coaling 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 borate-crosslinked fluid at 71 °C, 240 g/m3 of the encapsulated breaker caused an improvement in retained permeability from 15% to 49%, but caused only a 20% loss in viscosity in one hour. These laboratory tests indicate that encapsulated breaker may increase well production by improving proppant pack cleanup.
References and illustrations at end of paper.
Recent laboratory investigations have shown that polymeric fracturing fluids can cause significant proppant pack permeability impairment.1–4 Major contributors to this problem are the stability of the polymers below 107.2 °-121.1 °C and the concentration of polymer which occurs during a fracturing treatment. Penny1 has suggested that the polymer is concentrated 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. Hawkins2 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-fold for fluid containing 240 kg/m3 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 showing the effect of final polymer concentration on fracture permeability. His tests showed that the permeability of a 850–425 µm mesh sand pack decreased from about 138 µm2 to about 79 µm 2 for 12 kg/m3 final concentration of polymer and to about 39 µm for 36 kg/m3 polymer. This corresponds to retained permeabilities of 57 and 29%, respectively. Parker and McDaniel 3,4 have emphasized the need to consider filter cake effects, especially when low sand loadings (kg/m2) are used.
Gel breakers are used to reduce the viscosity of and, presumably, the damage caused by polymeric fracturing fluids. The most commonly used breakers are enzymes and persulfate Salts.
