Fast Hydrating Fracturing Fluid for Ultrahigh Temperature Reservoirs

Abstract

An increase in the number of explorations of deeper and hotter formations has prompted the need for an ultrahigh- temperature fracturing fluid. Conventional fracturing fluids are typically based on polysaccharides or their derivatives, which can provide enough viscosity to carry proppant deep into the formation at temperatures only up to 177 °C (350 °F). Beyond this temperature, these biopolymers hydrolyze too rapidly to be an effective and cost-efficient carry fluid; therefore, a new fluid was needed. We developed a new fluid system that can deliver the required rheological properties for successful fracturing operations up to bottom hole static temperature of 232 °C (450 °F) without the need for cool-down. This fluid is composed of a fast-hydrating synthetic copolymer and a metal crosslinker. This system has been engineered to provide a controllable crosslink mechanism and viscosity reduction profile to accommodate varying well conditions and job designs. Numerous proppant-pack conductivity tests have shown that this resilient fluid system can be broken and easily cleaned up at temperatures above 149 °C (300 °F). The rheological performance of the fluid, along with its high proppant pack regained permeability, makes the new fluid ideal in ultrahigh-temperature explorations. The fluid has already been successfully applied in the field. Preliminary lab and field implementation results are discussed.

Review on High-Temperature-Resistant Viscoelastic Surfactant Fracturing Fluids: State-of-the-Art and Perspectives

“…Ghosh et al used the enzyme breaker developed to break the cross-linked HPG fluid and regained the matrix fracture permeability to 80%–95%. The retained permeability of the metal-cross-linked synthetic polymer fluid tested by Lee et al with a temperature resistance of up to 232 °C is less than 80% . Abdelrahim et al studied the damage of the residual fracturing fluid to the core through the core-flooding experiment .…”

“…The retained permeability of the metal-cross-linked synthetic polymer fluid tested by Lee et al with a temperature resistance of up to 232 °C is less than 80%. 71 Abdelrahim et al studied the damage of the residual fracturing fluid to the core through the coreflooding experiment. 72 The results indicated that the residual fracturing fluid may reduce the permeability of brine injection by 99% or more.…”

Wormlike Micellar Solutions, Beyond the Chemical Enhanced Oil Recovery Restrictions

“…This event will cause a drop in the amount of oil production from these regions. Another problem that is associated with polymer solutions is the rise in the effect of preferential flow in high-permeability zones because of the decreased viscosity that is caused by the shear-thinning nature of the polymers [12,40,41].…”