Despite of terminological similarity there is a big difference in the way Dynamic Modelling, Well Flow Performance and Well Testing define formation pressure and productivity index.
This difference is summarized in the table below:
Formation pressure,
Flow rate,
Producivity Index,
field-average pressure within the 9-cell area
p_{e9, \ i,j} = \frac{1}{9} \sum_{k=i-1}^{i+1} \sum_{l=j-1}^{j+1} p_{k,l}
p_{e9, \ i,j} = \frac{1}{9} ( p_{i,j} + p_{i, \, j+1} + p_{i, \, j-1} + p_{i-1, \, j} + p_{i-1, \, j} + p_{i-1 \, j-1} + p_{i+1, \, j+1} + p_{i-1 \, j+1} + p_{i+1, \, j-1} )
phase flowrate at sandface:
(each fluid phase separately)
phase productivity index:
, ,
field-average pressure within the drainage area
p_r = \frac{1}{A_e} \iint_{A_e} p(x,y,z) dS
surface component flowrate
(each fluid component separately)
and sometimes liquid flowrate
fluid component productivity index:
and sometimes liquid productivity index:
average pressure value along the boudary of drainage area
p_e = \frac{1}{L_e} \int_0^{L_e} p(x,y,z) dl
where is the boundary of drainage area
total flowrate at sandface:
– for Black Oil
– for Volatile Oil
or pseudo-components of Compositional Model
total multiphase productivity index: