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02-Variable Wellbore Storage

# 02-Variable Wellbore Storage - Variable Wellbore Storage 1...

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Variable Wellbore Storage 1

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Variable Wellbore Storage 2 Upon completion of this section, the student should be able to: 1. Calculate the wellbore storage coefficient for a wellbore filled with a single-phase fluid or a wellbore with a rising or falling liquid level. 2. Describe the conditions that contribute to phase segregation or phase redistribution. 3. Describe the pressure response produced by an injection well when the wellbore fills up during injection and when the well goes on vacuum during shutin. 4. Describe the pressure response for a well with a “leaky packer” or similar two-compartment wellbore.
Variable Wellbore Storage 3

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Variable Wellbore Storage 4
Variable Wellbore Storage 5 Nomenclature: C - Wellbore storage coefficient, bbl/psi q - Flow rate out of wellbore at surface, STB/D q sf - Flow rate into wellbore at sand face, STB/D B - Formation volume factor, bbl/STB p w - Wellbore bottomhole pressure, psi t - Time, hrs

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Variable Wellbore Storage 6 Nomenclature: C - Wellbore storage coefficient, bbl/psi c wb - Compressibility of fluid in wellbore, psi -1 V wb - Volume of wellbore, Bbls
Variable Wellbore Storage 7 Nomenclature: C - Wellbore storage coefficient, bbl/psi c wb - Compressibility of fluid in wellbore, psi -1 A wb - Cross-sectional area of wellbore at gas-liquid interface, ft 2 ρ wb - Density of liquid in wellbore, lbm/ft 3

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Variable Wellbore Storage 8
Variable Wellbore Storage 9

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Variable Wellbore Storage 10
Variable Wellbore Storage 11 Stegemeier and Matthews conducted a statistical study of 120 buildup tests with pressure humps in a South Texas oil field. Pressure humps as large as 180 psi were observed, with an average of 45 psi. Humps occurred at the end of or shortly after the end of the “swan’s neck” on a typical pressure buildup test. Humps occurred at times ranging from 100 to 1000 minutes following shut-in, with most wells humping within 300 to 400 minutes of shutin.

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