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  • a

    = loss ratio, q/(change in rate)

  •  
  • A

    = drainage area, ft2 (m2)

  •  
  • AD

    = dimensionless drainage area

  •  
  • AR

    = rectangular-drainage-area aspect ratio

  •  
  • b

    = Arps decline curve exponent

  •  
  • bf

    = fracture width, ft (m)

  •  
  • B

    = fluid formation volume factor, RB/STB (res m3/std m3)

  •  
  • BCPD

    = stock-tank barrels condensater/day, STB/D (std m3/d)

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  • BOPD

    = stock-tank barrels oil/day, STB/D (std m3/d)

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  • bf

    = fracture width, ft (m)

  •  
  • Bg

    = gas formation volume factor, res ft3/scf (res m3/std m3)

  •  
  • Bo

    = oil formation volume factor, RB/STB (res m3/std m3)

  •  
  • bpss

    = pseudosteady-state intercept

  •  
  • CHP

    = casinghead pressure, psi (Pa)

  •  
  • CA

    = Dietz steady-state shape factor

  •  
  • CfD

    = dimensionless fracture conductivity

  •  
  • cf

    = formation pore compressibility, 1/psi (1/Pa)

  •  
  • cg

    = gas compressibility, 1/psi (1/Pa)

  •  
  • co

    = oil compressibility, 1/psi (1/Pa)

  •  
  • Cr

    = relative conductivity

  •  
  • ct

    = total system compressibility, 1/psi (1/Pa)

  •  
  • cw

    = water compressibility, 1/psi (1/Pa)

  •  
  • d

    = effective decline rate, 1/ unit time

  •  
  • D

    = continuous decline rate, 1/unit of time

  •  
  • Di

    = Arps initial decline rate, 1/unit of time

  •  
  • Dwb

    = wellbore diameter, ft (m)

  •  
  • EUR

    = estimated ultimate recovery, STB (std m3)

  •  
  • FTHP

    = flowing tubinghead pressure, psi (Pa)

  •  
  • fw

    = fraction of water flowing, also called water cut

  •  
  • GOR

    = gas/oil ratio, Mscf/STB (1000 m3/m3)

  •  
  • GWR

    = gas/water ratio, Mscf/STBW (1000 std m3/std m3)

  •  
  • Ga

    = approximate original gas in place estimate, MMscf (million std m3)

  •  
  • Gp

    = cumulative gas production, MMscf (std m3)

  •  
  • Gpmax

    = estimated ultimate gas cumulative production, MMscf (std m3)

  •  
  • h

    = reservoir net-pay thickness, ft (m)

  •  
  • HCPV

    = hydrocarbon pore volume, ft3 (m3)

  •  
  • J

    = productivity index, STB/D/psi (std m3/s/Pa)

  •  
  • k

    = reservoir effective permeability, md (m2)

  •  
  • kf

    = fracture permeability, md (m2)

  •  
  • kfbf

    = fracture conductivity, md-ft (m3)

  •  
  • kg

    = formation effective permeability to gas, md (m2)

  •  
  • kh

    = formation conductivity, md-ft (m3)

  •  
  • ko

    = formation effective permeability to oil, md (m2)

  •  
  • kw

    = formation effective permeability to water, md (m2)

  •  
  • kx

    = effective permeability in x-direction, md (m2)

  •  
  • ky

    = effective permeability in y-direction, md (m2)

  •  
  • kz

    = vertical effective permeability, md (m2)

  •  
  • Lc

    = system characteristic length, ft (m)

  •  
  • LD

    = dimensionless horizontal wellbore length

  •  
  • Lh

    = effective horizontal well length in the reservoir, ft (m)

  •  
  • m

    = slope of line

  •  
  • N

    = number of fractures

  •  
  • N

    = original oil in place in the reservoir, STB (std m3)

  •  
  • Np

    = cumulative oil production, STB (std m3)

  •  
  • OOIP

    = original oil in place in the reservoir, STB (std m3)

  •  
  • OGIP

    = original gas in place in the reservoir, SCF (std m3)

  •  
  • OWC

    = oil water contact

  •  
  • pe

    = pressure at external boundary, psi (Pa)

  •  
  • pi

    = initial reservoir pressure, psi (Pa)

  •  
  • pp

    = real-gas pseudopressure, psia2/cp (Pa/s)

  •  
  • pr

    = average reservoir pressure, psia (Pa)

  •  
  • psc

    = standard-condition pressure, psia (Pa)

  •  
  • ptf

    = flowing tubinghead pressure, psi (Pa)

  •  
  • pwD

    = dimensionless wellbore pressure

  •  
  • pwf

    = sandface flowing pressure, psia (Pa)

  •  
  • q

    = well flow rate, STB/unit of time or Mscf/unit of time (std m3/s)

  •  
  • q2

    = well flow rate at later time t2, stb/d or scf/d (std m3/s)

  •  
  • qD

    = dimensionless flow rate

  •  
  • qlast

    = last measured rate, STB/unit of time or scf/unit of time (std m3/s)

  •  
  • qDd

    = dimensionless decline flow rate

  •  
  • qDdi

    = dimensionless flow rate integral function

  •  
  • qDdid

    = dimensionless flow rate integral derivative function

  •  
  • qEL

    = economic-limit flow rate, STB/unit of time (std m3/s)

  •  
  • qg

    = gas-flow rate, Mscf/unit of time (std m3/s)

  •  
  • qi

    = initial flow rate, STB/unit of time (std m3/s)

  •  
  • qo

    = oil-flow rate, STB/unit of time (std m3/s)

  •  
  • Qmax

    = maximum possible production @q = 0; STB or scf (std m3)

  •  
  • Qp

    = cumulative fluid production, STB or scf (std m3)

  •  
  • QpD

    = dimensionless cumulative production

  •  
  • QpDd

    = dimensionless decline cumulative production

  •  
  • qwD

    = dimensionless well flow rate

  •  
  • re

    = reservoir effective drainage radius, ft (m)

  •  
  • reD

    = dimensionless drainage radius

  •  
  • rw

    = wellbore radius, ft (m)

  •  
  • rwa

    = apparent wellbore radius, ft (m)

  •  
  • rwDz

    = dimensionless wellbore radius

  •  
  • S

    = steady-state skin effect

  •  
  • Sg

    = gas saturation, fraction of pore volume

  •  
  • So

    = oil saturation, fraction of pore volume

  •  
  • Sw

    = water saturation, fraction of pore volume

  •  
  • Swi

    = initial water saturation, fraction of pore volume

  •  
  • t

    = time, days (or months) (s)

  •  
  • T

    = reservoir temperature, °F (K)

  •  
  • ta

    = real-gas pseudo-time function, D-psi/cp

  •  
  • tD

    = dimensionless time

  •  
  • tDA

    = dimensionless time referenced to drainage area

  •  
  • tDd

    = dimensionless decline time

  •  
  • tDmb

    = dimensionless pseudo production time

  •  
  • tmb

    = pseudo production time, days (s)

  •  
  • tmbDd

    = dimensionless decline pseudo production time

  •  
  • tp

    = pseudo production time, days (s)

  •  
  • tpDd

    = dimensionless decline pseudo production time

  •  
  • tpss

    = start of boundary-dominated flow in real time

  •  
  • Tsc

    = standard-condition temperature, oF or oC

  •  
  • Vb

    = bulk volume of the reservoir, acre-ft or RB (res m3)

  •  
  • Vp

    = pore volume of the reservoir, acre-ft or RB (res m3)

  •  
  • WOR

    = water/oil ratio, STBW/stbo (std m3 water/ std m3 oil

  •  
  • Xe

    = drainage areal extent in the x-direction, ft (m)

  •  
  • XeD

    = dimensionless drainage extent in x-direction

  •  
  • Xf

    = effective fracture half-length, ft (m)

  •  
  • XwD

    = dimensionless wellbore location in x-direction

  •  
  • Ye

    = drainage areal extent in the y-direction, ft (m)

  •  
  • Yield

    = STB condensate/MMscf, (std m3/million std m3)

  •  
  • YeD

    = dimensionless drainage extent in y-direction

  •  
  • YwD

    = dimensionless wellbore location in y-direction

  •  
  • z

    = gas-law deviation (supercompressibility) factor

  •  
  • Zw

    = horizontal well standoff from bottom of reservoir, ft (m)

  •  
  • ZwD

    = dimensionless horizontal well standoff from bottom of pay

  •  
  • α

    = Prats (1961) dimensionless fracture capacity

  •  
  • Δp

    = pressure difference, psi (Pa)

  •  
  • ε

    = imaging function

  •  
  • ϕ

    = effective porosity of reservoir, fraction of pore volume

  •  
  • γf

    = gravity of fluid

  •  
  • λ

    = reservoir mobility of a fluid, md/cp (m2/Pa∙s)

  •  
  • λt

    = total system mobility (all fluids), md/cp (m2/ Pa∙s)

  •  
  • μ

    = reservoir fluid viscosity, cp (Pa∙s)

  •  
  • μg

    = gas viscosity, cp (Pa∙s)

  •  
  • μgi

    = initial reservoir gas viscosity, cp (Pa∙s)

  •  
  • μo

    = oil viscosity, cp (Pa∙s)

  •  
  • μoi

    = initial oil viscosity, cp (Pa∙s)

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Contents

Data & Figures

References

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