Reservoirs with permeabilities of less than 1 md and bottomhole temperatures in excess of 250°F 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 more 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 axe 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 250°F.

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