A significant factor in the success of propped fracturing is the complexity of the created near-wellbore fracture geometry. This paper discusses the cost-effective use of high viscosity gel slugs to reduce near-wellbore complexity (measured as Near Wellbore Pressure Loss or NWBPL) in a high temperature, hard rock environment to a level acceptable for successful fracture stimulation. Determination of a fluid dependent, acceptable level of NWBPL has been obtained through extensive field measurements. Knowledge of this limit assists in determining where gel slugs are required and whether a gel slug injection can be categorised as a success or failure.

The benefit of using higher viscosity fluids in propped fracture treatments for NWBPL mitigation is well documented. However, in some environments, such as those described herein, use of higher viscosity for the propped treatment would be both cost prohibitive and possibly detrimental to well production. A preferred technique involves the removal of NWBPL with a higher viscosity slug and, once assured of gel slug success through accurate diagnosis, a lower gel loading propped treatment can be conducted.

This paper provides guidelines for field application of the gel slug methodology and discusses its inclusion in a pre-frac injection sequence. Like other NWBPL remediation techniques, gel slugs may not provide immediate positive results. Limitations of this technique and conditions for its appropriate use are also included.

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