An effective fluid loss control measure that has recently found application in the hydraulic fracturing of gas wells is the addition of an immiscible hydrocarbon phase to aqueous fracturing fluids. In this work the effectiveness and regained permeabilities after employing hydrocarbon and common particulates are assessed. Laboratory studies indicate that reduced hydrocarbon concentrations (less than 5%) may be beneficial in achieving efficient fracture cleanup. A detailed evaluation of the parameters controlling fluid loss of an immiscible hydrocarbon phase in aqueous fluids has led to an optimized hydrocarbon-surfactant system, with which excellent regained permeabilities and efficient fluid loss control are achieved at reduced hydrocarbon concentrations.
A primary role of fluid loss control agents is to maintain adequate injected fluid within the created fracture to achieve desired fracture geometry. At the same time, fluid loss control agents may portray conflicting roles in terms of formation and fracture conductivity damage.
Fluid loss additives serve to minimize formation damage by controlling leak-off, thereby limiting matrix fluid invasion and retention; on the other hand, they may impair flow to returning aqueous fluids and hydrocarbons.
It has been pointed out by Pye and Smith that the use of particulate fluid loss agents can significantly impair regained permeability to oil in 10 and 250 md formation cores. At an injection pressure of 1000 psi, silica flour brought about a 60% reduction in permeability as determined by regained oil flow at 30 psi on Bandera cores (10 md), and a 90% reduction was reported for Berea cores (250 md) under identical conditions. Regained permeability was improved by increasing the differential pressure. For example, regained permeabilities to oil of 45% and 60% were obtained at differential pressures of 1000 and 2500 psi respectively. psi respectively. The degree of damage to fracture conductivity caused by insoluble particulates has been somewhat controversial. Pye and Smith showed that severe damage can be incurred if the insoluble fluid loss additive plus gelling agent to sand ratio exceeds 0.01. Cooke on the other hand found that the damage from the polymer residue was far greater than that caused by the insoluble particulate matter of the fluid loss agent, except at impractical concentrations (1140 lb/Mgal.). One of the major differences in the two above experiments is the manner in which the fluid loss additive was introduced to the sand pack; Pye and Smith flowed a fluid containing the Pye and Smith flowed a fluid containing the particulate additive into the sand, while Cooke packed particulate additive into the sand, while Cooke packed the sand in a fluid containing the particulate. Particulate bridging was possible in the experiment Particulate bridging was possible in the experiment of Pye and Smith while bridging was less likely in the experiments of Cook.
The use of particulate additives in controlling fluid leakoff during the hydraulic fracturing of gas wells can present a more complicated picture in terms of regained permeability. In most cases a limited amount of liquid hydrocarbon and water is produced to dislodge the insoluble particulate matter produced to dislodge the insoluble particulate matter from the fracture surface and/or matrix. Further, the melting points of oil soluble resins are typically exceeded in hot gas well applications resulting in a return of the melted additive to the well bore area where it may solidify on cooling.
An alternative to particulate fluid loss control agents has been the introduction of an immiscible liquid phase to aqueous based fluids. Data concerning regained permeability data after treatment with a fluid containing an immiscible liquid is somewhat limited. McAuliffe has noted that once the aqueous permeability of a 1600 md Boise core was reduced permeability of a 1600 md Boise core was reduced some 90% (10 psi) by injecting a 0.5% crude oil in water emulsion, 15 to 19 pore volume of distilled water (10 psi) resulted in a modest 8.5% regain in permeability to water. He points out, however, that permeability to water. He points out, however, that an increasing pressure gradient would eventually displace the droplets that are wedged into pore throat constrictions. No regained permeabilities at lower permeabilities have been reported.