Reservoirs with permeabilities of less than 1 md and bottomhole temperatures in excess of 250F are commonly encountered in the continuing search for hydrocarbons. Successful completion of these wells often requires the use of Massive Hydraulic Fracturing (MHF) treatments.
The fracturing fluids used in MHF treatments are frequently subjected to excessive shear and prolonged exposure at high bottomhole temperatures. Early fracturing fluids proved unsuitable for these MHF treatments due to a rapid loss of viscosity at high temperatures. As a result, narrow fracture widths, excessive fluid loss and poor proppant transport occurred. Cool-down pads, increased polymer concentrations and delayed polymer hydration systems were employed in an attempt to improve the MHF treatment success ratio.
A laboratory study was undertaken to develop a more efficient high temperature fracturing fluid. Rotational and pipe viscometers were used to evaluate thermal and shear stabilities under reservoir conditions. Fluid loss testing measured the effectiveness of fluid leakoff control. Fluid breakout testing ensured a controlled loss of viscosity and minimal proppant pack gel residue. As a result of this study, a rare efficient high temperature fracturing fluid was developed.
This paper presents laboratory data comparing the thermal stability, shear stability and fluid loss control of the High Temperature Gel (HTG) with those of a conventional titanate crosslinked gel. Field case histories are presented to demonstrate the efficiency with which the HTG system has been used to successfully stimulate low permeability gas wells with bottomhole temperatures in excess of 250F.
Introduction In recent years, the exploration of low permeability gas reservoirs has increased dramatically resulting in a demand for new stimulation techniques to successfully complete these wells. Permeabilities of less than 1 md and bottomhole temperatures in Permeabilities of less than 1 md and bottomhole temperatures in excess of 250F have become commonplace. Successful stimulation of these wells can only be achieved by creating long, conductive, hydraulic fractures.
Massive Hydraulic Fracturing (MHF) treatments are often used to stimulate low permeability gas reservoirs. Many early MHF treatments were limited by fracturing fluids that rapidly lost viscosity at high bottomhole temperatures due to excessive thermal and/or shear degradation. Creation of a narrow fracture width, excessive fluid loss to the formation and reduced proppant transport resulted from the use of these low viscosity fluids. Recent laboratory and field studies have culminated in the development of fluids and application techniques which have increased the success ratio of these MHF treatments in deep, hot, low permeability gas reservoirs.
Three techniques have been used to improve fracturing fluid performance under these extreme reservoir conditions. One technique performance under these extreme reservoir conditions. One technique is the use of cool-down pads. The cool-down pad leaks off into the formation and lowers the temperature in the fracture. The proppant-laden fluid is then exposed to a temperature lower than the proppant-laden fluid is then exposed to a temperature lower than the initial bottomhole temperature. Thus, the fluid is able to maintain a high viscosity for a longer period of time. A disadvantage is that cool-down pads increase the total treatment volume and thus the treatment cost. Another technique commonly employed is to increase the gel's polymer concentration. This aids in the reduction of fluid loss to the formation and in the maintenance of fluid viscosity in the fracture.
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