Frac-and-Pack Completion
Abstract
A relatively short, highly conductive fracture created in a reservoir of moderate to high permeability will breach near-wellbore damage, reduce the drawdown and near-wellbore flow velocity and stresses, and increase effective wellbore radius. Fracturing treatments of this type have two stages: fracture created, terminated by tip-screenout, and fracture inflation and packing. Such a two-stage treatment is the basis of a number of well-completion methods, collectively known as frac-and-pack. This technique has been successfully applied, with a range of fracture sizes, to stimulate wells in various reservoirs worldwide.
This chapter discusses the criteria for selecting wells to be frac-and-packed. It is shown how a systematic study of the inflow performance can be used to assess the potential of frac-and-packed wells, to identify the controlling factors, and to optimize design parameters. It is also shown that fracture conductivity is often the key to successful treatment. This conductivity depends largely on proppant size; formation permeability damage around the created fracture has less effect. Appropriate allowance needs to be made for flow restrictions caused by the presence of the perforations, partial penetration, and non-Darcy effects.
The full potential of this completion method can be achieved only if the design is tailored to the individual well. This demands high-quality input data, which can be obtained only from a calibration test.
Keywords
Hydraulic Fracture Fracture Length Fracture Width Fracture Conductivity Skin FactorNotes
Nomenclature
Leakoff area, m2
Fracture area at TSO, m2
Average areal proppant concentration, kg/m2
Formation volume factor, m3/m3
Dimensionless fracture conductivity
Fluid loss coefficient, m/s1/2
Proppant concentration, kg/m3
Proppant concentration in liquid, kg/m3
Average proppant concentration loading, kg/m3
Proppant concentration in slurry, kg/m3
Total compressibility, Pa−1
Perforation tunnel diameter, m
Reservoir net thickness, m
Productivity index, m3/(s × Pa)
Reservoir permeability, m2
Choked or damaged fracture permeability, m2
Fracture permeability, m2
Permeability of damaged region, m2
Perforation tunnel permeability, m2
Perforation tunnel length, m
Total proppant mass, kg
Total proppant mass at TSO, kg
Number of perforations
Number of moles
Number of perforations per unit length, m−1
Reservoir pressure, Pa
Dimensionless pressure
Reservoir pressure at outer boundary, Pa
Initial reservoir pressure, Pa
Standard conditions pressure, Pa
Bottomhole flowing pressure, Pa
Flow rate, m3/s
Pump rate, m3/s
Fluid leakoff rate, m3/s
Universal gas constant, J/(K × mol)
Radius, m
Reservoir radius, m
Dimensionless radius
Near wellbore damage radius, m
Wellbore radius, m
Effective wellbore radius, m
Dimensionless effective wellbore radius
Spurt-loss coefficient, m
Skin factor
Fracture skin factor
Perforation flow skin factor
Choked fracture skin factor
Fluid leakoff skin factor
Partial penetration skin factor
Other possible skin factors
Absolute temperature, K
Standard conditions temperature, K
Dimensionless time
Pumping time, s
Total time to TSO, s
Volume, m3
Clean fluid volume, m3
Total (two-wing) fluid volume, m3
Total fracture volume, m3
Slurry volume, m3
Leakoff volume, m3
Choked or damaged fracture width, m
Fracture width, m
Choked or damaged fracture half-length, m
Propped fracture half-length, m
Depth of damaged region, m
Real gas deviation factor
Pressure gradient, Pa
Perforation pressure drop, Pa
Net pressure at TSO, Pa
Fluid viscosity, Pa⋅s
Proppant particle density, kg/m3
Proppant bulk density, kg/m3
Reservoir porosity, fraction
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