Factors Affecting Gelling Agent Residue Under Low Temperature Conditions

Abstract

Member SPE-AIME Abstract The relative reduction in both formation permeability and fracture flow capacity caused by permeability and fracture flow capacity caused by the residue remaining after water based fracturing fluids are broken is often very important in the final selection of a fracturing fluid. Therefore, it is important to understand some of the factors which can affect the amount of residue produced from the gelling agents and the changes in relative flow which may result. One of the most important factors in determining the amount of residue produced is the type of gelling agent used as a viscosifier. In general, the following order is commonly used as a guideline to determine the relative-residue content of a number of gelling agents: guar gum >derivatized guar gum >derivatized cellulose. Test results have shown that this relative order can be changed by varying the break time, breaker concentration, crosslinker and pH of the fluid system. For example, data has shown that a cellulose fluid can potentially cause more reduction to both fracture flow capacity and formation permeability than commonly used derivatized guar gelling agents. The information which will be presented in this paper will contain results of an investigation into paper will contain results of an investigation into the effect of breaker concentration, breaker type, break time, crosslinker and pH of a fluid system on the relative flow reduction caused by a variety water based fracturing systems. Fluids prepared with standard guar and cellulose gelling agents broken at low temperatures in a variety of porous media have been investigated. The importance of evaluating an entire fracturing fluid system and not just the specific gelling agent to determine which fluid should provide the optimum production increase from a hydraulic fracturing treatment will also be presented. presented Introduction The use of aqueous based fracturing fluids has become extremely popular over the last 20 to 25 years. Currently these fluids account for over 90% of the liquid volume used in hydraulic fracturing. It is apparent that as the problems associated with water based fluids have been solved, they have gained further use in the industry. A variety of gelling agents for water exists which achieve the viscosity necessary to perform a fracturing treatment and water is safe and economical. In addition to providing viscosity and then breaking, these polymers should cause a minimum amount of damage to both the formation and created fracture system. It is known, however, that a large number of the water-soluble polymers used in fracturing may leave an insoluble material (residue) after breaking. This insoluble material may influence flow in both the fracture and formation by simply blocking or restricting pore spaces. A number of researchers have shown that this is undoubtedly the case with a variety of polymers. In an excellent study by Cooke, a numerical correlation was made between the volume of polymer residue left by various polymers and the amount of permeability reduction in 20/40 mesh sand. The permeability reduction in 20/40 mesh sand. The results of this study indicate that when the residue volume is increased (guar >cellulose derivature > polyacrylamide), the amount of reduction in fracture polyacrylamide), the amount of reduction in fracture conductivity is also increased. There are several factors involved in the degradation of these polymers which could potentially affect the amount of residue remaining from each polymer: breaker type, breaker concentration, break polymer: breaker type, breaker concentration, break time, and break temperature. The type of breaker used to degrade a polymer (i.e., acid, enzyme, oxidizer) is very important. Since each breaker type operates under a different mechanism to degrade the polymer, there is a different set of factors associated with each breaker which affects the amount of residue or potential flow damage seen with a single polymer. polymer. P. 151