Reservoirs with bottomhole temperatures in excess of 250°F are commonly encountered in the ever-expanding 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 investigation was undertaken to develop a more efficient high temperature fracturing fluid. Rotational and pipe viscometers were used to evaluate thermal and shear stabilities at reservoir conditions. Fluid loss testing measured the control of fluid leakoff to the formation. Fluid breakout testing ensured a controlled loss of viscosity and rapid cleanup. 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 are presented to demonstrate the efficiency with which HTG has been used to successfully stimulate wells with bottomhole temperatures in excess of 250°F.

You can access this article if you purchase or spend a download.