Gel Slugs: A Near-Wellbore Pressure-Loss Remediation Technique for Propped Fracturing

Abstract

Abstract 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. Introduction Hydraulic fracturing is a technique used to improve production in many oil and gas wells in the Cooper Basin of Central Australia. Fracturing conditions in the Cooper Basin are varied, with reservoir temperatures ranging from 220°F to over 400°F and closure stress gradients varying from 0.6 psi/ft to over 1.0 psi/ft in tectonically active areas. While placement success is very good, a high level of Near Wellbore Pressure Loss (NWBPL), afflicts approximately 10% of wells. If left untreated, high NWBPL can severely reduce the likelihood of proppant placement and hence impair project economics. Many methods have been developed to minimise NWBPL. These include the use of ‘Tolerance’, ‘Mitigation’ and ‘Remediation’ strategies. ‘Tolerance’ strategies have been developed to ‘live with’ the problem of NWBPL. These techniques include the use of long proppant stages, large pad volumes and shear-rebuilding fluids. ‘Mitigation’ strategies are employed to ensure high NWBPL levels are avoided from the outset. These techniques include the use of specialised perforation schemes such as zero degree phasing1, limited entry2, high energy, large perforations3, and extreme overbalanced techniques4. Other mitigation strategies include the use of high viscosity and high rate initiations5,6. ‘Remediation’ strategies are used to remove NWBPL once it has been observed. These include the use of proppant slugs3 and high viscosity gel slugs. This paper focuses on the use of high viscosity gel slugs to remediate NWBPL, outlining a sequence of field implementation guidelines for the application of gel slugs and three accompanying field examples. The gel slug is not a panacea for high NWBPL, however, studies of the Cooper Basin field data suggest that gel slug success can be predicted by the use of a simple indicator obtained from injection/shut-in pressure behaviour.