Glossary

Nomenclature

A

a = ash content (dimensionless, mass %)

A = area (ft²) (F.A.S.T. CBM^TM uses acres: 1 acre = 43560ft²)

B

b = Langmuir pressure parameter (equal to )

B_g = gas formation volume factor (ft³/scf)

B_w = water formation volume factor (bbl/STB)

C

c_f = formation compressibility (/psia)

C_L = liquid input volume fraction

C_m = matrix swelling coefficient (microstrain*ton/scf).

c_m = matrix compressiblity (/psi) (note: this c_m is not the same as the one used in the Seidle formulation)

C_p = mechanical strain due to pressure

c_p = mechanical compliance coefficient, represents compressibility of coal matrix (/psia)

c_w = water compressibility (/psia)

C_f = formation compressibility (1/psia)

D

D = inside diameter of pipe (in)

D = nominal decline rate

D_e = effective decline rate

Depth = Landed depth of tubing or casing

Duration = Well Timing, duration of forecast, time interval from start date to end date (months)

E

E = Young’s modulus. Measures opposition of a substance to extensional stress

= horizontal liquid holdup

= inclined liquid holdup

End = Well Timing, end date of forecast (MM/DD/YYYY)

Excess Pres. Drop = Additional pressure loss (ie: to represent a the hydrostatic loss from a suspected column of liquid at the bottom of the wellbore)

F

f = Fanning friction factor (function of Reynolds number)

f = an undefined fraction (0 to 1, usually 0.5, used in calculating matrix shrinkage)

= no-slip friction factor

= Froude Mixture Number

= two phase friction factor

F(x) = probability distribution function

F_N(x) = normal distribution function

G

g = gravitational acceleration

g_c = conversion factor

G_c = gas content (scf/ton)

= recoverable gas content (scf/ton)

G_c,pure = gas content of pure coal (scf/ton)

G_p = gas produced (Bcf)

GIP = gas in place (scf)

H

h = net pay (ft)

I

ID = inside diameter of tubing or casing

IGIP = initial gas in place (Bcf)

K

k = permeability (md)

k = absolute roughness (in)

k/D = relative roughness (unitless)

K = bulk modulus. Mesures opposition of a substance to compressional stress.

k₀ = initial permeability at P₀ and S_w0 (md)

k_g = gas effective permeability (md)

k_w = water effective permeability (md)

k_rg = relative permeability to gas

k_rg0 = endpoint relative permeability to gas

k_rw = relative permeability to water

k_rw0 = endpoint relative permeability to water

L

L = length of pipe section (ft)

Layer = Layer name

M

m(P) = gas pseudopressure at pressure P (psi²/cp)

M = constrained axial modulus

N

n = exponent, used in relative permeability curves

n_w = exponent of the water relative permeability curve

n_g = exponent of the gas relative permeability curve

= Number of wells

N_VL = liquid velocity number

O

OD = outside diameter of tubing or casing

OGIP = original gas in place

= original gas in place, adsorbed

= original gas in place, free gas

OWIP = Original water in place

P

P = pressure, usually average reservoir pressure (psia)

= Abandonment pressure (psia)

P₀ = initial reservoir pressure (psia)

P_c = desorption pressure (psia)

P_i = initial reservoir pressure (psia)

= Aquifer productivity index (bbls/d/psi / m3/d/kPa)

= pressure loss due to friction effects (psi)

= pressure change due to hydrostatic head (psi)

P_L = Langmuir pressure parameter (psia)

P_sc = standard pressure (14.7 psia)

P_wf = bottomhole flowing pressure (psia)

= reservoir pressure at 50% matrix strain (psia)

Q

q_g = gas rate (MCFd)

q_w = water rate (STB/day)

= = Gas rate at end of forecast (Mcf/day / m3/day)

= Maximum gas rate (Mcf/day / m3/day)

= Maximum water rate (bbl/day / m3/day)

R

r_e = external radius of reservoir (ft)

Re = Reynold’s number

RGIP = Recoverable gas in place

r_w = wellbore radius (ft)

% Rec = recovery factor

S

s = skin

S_g = gas saturation (% or fraction)

S_gc = irreducible gas saturation (% or fraction)

S_w = water saturation (% or fraction)

= average water saturation (% or fraction)

S_wc = irreducible water saturation (% or fraction)

= initial water saturation (% or fraction)

Start = well timing, Start date of forecast (MM/DD/YYYY)

Start = layer name, Start date of forecast (MM/DD/YYYY)

T

T = Temperature, usually reservoir temperature (F)

= flowing wellhead temperature

T_sc = standard temperature (60F = 519.67R)

V

V = average velocity (ft/s)

V_m = mixture velocity (ft/s)

V() = adsorbed gas (scf)

V(P) = amount of gas at P, also known as gas content (scf/ton)

V_L = Langmuir volume parameter (scf/ton)

= superficial liquid velocity (ft/s)

W

w_c= water content (dimensionless, mass %)

W_e = water encroached (bbls)

W_p = water produced (STB)

X

= fracture half length

Z

Z = gas compressibility factor (dimensionless)

Z_i = initial gas compressibility factor (dimensionless)

Z* = gas factor for unconventional gas reservoir (dimensionless)

Z*_i = Z* evaluated at initial conditions

Z_sc = standard gas compressibility factor (1)

= elevation change (ft)

Greek Symbols

= gas/liquid surface tension (dynes/cm)

= effective stress.

= effective stress at P₀.

= strain (dimensionless)

= net strain between overburden stress effect and matrix shrinkage as measured experimentally. This is the difference between strain caused by swelling due to gas adsorption and strain caused by applied stress. (strain, dimensionless)

= strain matched to Langmuir isotherm. This is the maximum strain that can occur as P approaches zero.

= viscosity (lb/ft×s)

= no-slip viscosity (cp)

= water viscosity (cp)

= porosity (%)

= final porosity (%)

= initial porosity

= density (lb/ft³)

= coal bulk density (g/cm³) or (lb/ft³)

= gas density (lb/ft³)

= liquid density ( lb/ft³ )

= no-slip density ( lb/ft³ )

= mixture density ( lb/ft³ )

= angle of inclination from the horizontal (degrees)

= Poisson’s ratio

= grain compressibility (1/psi)