Identification and Comparison of True Net Fracturing Pressures Generated by Pumping Fluids with Different Rheology into the Same Formations

Abstract

ABSTRACT Different hydraulic fracture simulators predict different levels of net pressure, especially with respect to changing/varying fluid viscosity. The level and distribution of net pressure in the fracture must be known to accurately calculate fracture width, which has major implications for the correct calculation of the other fracture dimensions and the location of the proppant. Fracture width also determines the amenability of the formation being fractured toward accepting higher proppant concentrations. This paper presents various examples of measured data from fracture treatments pumped in a variety of reservoirs, using fluids with widely varying viscosities. The primary aspect of the dataanalysis technique is the evaluation of friction-pressure data obtained from strategically-timed shut-ins and flow-rate changes. Many of the examples are from research environments where more stringent data gathering techniques were used, as opposed to most commercial situations where such procedures are rarely allowed due to (often unjustified) fear of negative impact on treatment effectiveness. Bottomhole pressure is sometimes seen to change significantly with changing theology. However, shut-ins done immediately after such pressure increases strongly indicate that these increases are due to changing frictional pressure in the perforation-adjacent, near-wellbore region (e.g., due to tortuosity) connecting the wellbore to the fully developed fracture. If this near-wellbore friction is subtracted from measured pressure, the data indicate relative insensitivity of net fracturing pressure to fluid rheology. The primary implications of these observations are: that commonly-ascribed needs for high viscosity fluids are justified only when near-wellbore problems exist, and that viscosity cannot be used to control fracture geometry (versus proppant placement in the fracture).