Hydraulic Fracturing of High-Permeability Formations to Overcome Damage

Abstract

Gravel pack operations in poorly consolidated, high-permeability formations are often plagued by relatively low production results, which are caused by the constraints of radial flow, damage to the formation and damage to the gravel pack caused by the treatment fluid. Hydraulic fractures will alter the radial flow for improved production results and will reduce the effects of formation damage caused by the treatment fluid. Data have been generated with several fluid systems that show the damage to the permeability of three different rock types. Fluid loss test results show the expected fluid loss performance of the different fluids. Calculations from recent work are used to show that viscous fluid invasion is also a mechanism for fluid loss control. Fracture conductivity data are provided for 20/40 mesh sands to show performance with the fluids tested. Additional conductivity data with 40/70 mesh sands illustrates the fact that small size gravel pack sands may not provide adequate conductivity for fractured well production. Reservoir simulations compare well performance based on the data provided here. INTRODUCTION Hydraulic fracturing is an established technique for stimulating the production in low-permeability reservoirs and for bypassing damage in moderate-permeability reservoirs. Hydraulic fracturing has recently been applied to high-permeability formations to bypass completion damage and actually stimulate production. Formation fines control in poorly consolidated formations may also be a benefit from hydraulic fracturing. The hydraulic fracture will alter the flow into the wellbore from radial to linear flow. The pressure drop for production will be distributed over the created surface area of the fracture and will not be limited to the surface area of the wellbore or gravel pack radius. This distributed pressure drop will reduce flow rates per-unit area, which will reduce flow velocity which should reduce formation fines movement or production. The lower flow rate over a greater surface area may actually result in higher production rates for the well.1–8 Treatment fluids can damage formation permeability to varying degrees.9 The extent of damage is quantified here for several fluid systems and can be used as a basis to rank fluid systems. This information can also be used to compare radial production and fractured well production when fluid damage to the reservoir is considered in the production calculations.

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