Page 4 - Petroleum Production Engineering, A Computer-Assisted Approach

Guo, Boyun / Petroleum Production Engineering, A Computer-Assisted Approach Guo-prelims Final Proof page xii 29.12.2006 10:39am

xii LIST OF SYMBOLS

n L number of mole of fluid in the liquid phase p sh slug hydrostatic pressure, psia
N max maximum pump speed, spm p si surface injection pressure, psia
n p number of pitches of stator p suction suction pressure of pump, psia
N 1 p cumulative oil production per stb of oil in P t tubing pressure, psia
place at the beginning of the interval p tf flowing tubing head pressure, psig
N f p,n forcasted annual cumulative production of p up pressure upstream the choke, psia
fractured well for year n P vc valve closing pressure, psig
N nf predicted annual cumulative production of P vo valve opening pressure, psig
p,n
nonfractured well for year n p wh upstream (wellhead) pressure, psia
N no predicted annual cumulative production of p wf flowing bottom hole pressure, psia
p,n
non-optimized well for year n p wf i the average flowing bottom-lateral pressure in
N op forcasted annual cumulative production of lateral i, psia
p,n
optimized system for year n p wfo dynamic bottom hole pressure because of
N Re Reunolds number cross-flow between, psia
N s number of compression stages required p c wf critical bottom hole pressure maintained
N st number of separation stages 1 during the production decline, psia
n V number of mole of fluid in the vapor phase p up upstream pressure at choke, psia
N w number of wells P 1 pressure at point 1 or inlet, lb f =ft 2
DN p,n predicted annual incremental cumulative P 2 pressure at point 2 or outlet, lb f =ft 2
production for year n p 1 upstream/inlet/suction pressure, psia
P pressure, lb=ft 2 p 2 downstream/outlet/discharge pressure, psia
p pressure, psia p p average reservoir pressure, psia
base pressure, psia reservoir pressure in a future time, psia
p b p p f
formation breakdown pressure, psia average reservoir pressure at decline time
p bd p p 0
casing pressure, psig zero, psia
P c
critical pressure, psia, or required casing average reservoir pressure at decline time t,
p c p p t
pressure, psia, or the collapse pressure with psia
no axial load, psia DP pressure drop, lb f =ft 2
p cc the collapse pressure corrected for axial load, Dp pressure increment, psi
psia dp head rating developed into an elementary
P cd2 design injection pressure at valve 2, psig cavity, psi
P Cmin required minimum casing pressure, psia Dp f frictional pressure drop, psia
p c,s casing pressure at surface, psia Dp h hydrostatic pressure drop, psia
p c,v casing pressure at valve depth, psia Dp i avg the average pressure change in the tubing, psi
P d pressure in the dome, psig Dp o avg the average pressure change in the annulus,
p d final discharge pressure, psia psi
p eng,d engine discharge pressure, psia Dp sf safety pressure margin, 200 to 500 psi
p eng,i pressure at engine inlet, psia Dp v pressure differential across the operating
p f frictional pressure loss in the power fluid valve (orifice), psi
injection tubing, psi Q volumetric flow rate
P h hydraulic power, hp q volumetric flow rate
p h hydrostatic pressure of the power fluid at Q c pump displacement, bbl/day
pump depth, psia q eng flow rate of power fluid, bbl/day
p hf wellhead flowing pressure, psia Q G gas production rate, Mscf/day
flowing pressure at the top of lateral i, psia glycol circulation rate, gal/hr
p hf i q G
p L pressure at the inlet of gas distribution line, q g gas production rate, scf/d
psia q g,inj the lift gas injection rate (scf/day) available to
p i initial reservoir pressure, psia, or pressure in the well
tubing, psia, or pressure at stage i, psia q gM gas flow rate, Mscf/d
p kd1 kick-off pressure opposite the first valve, psia q g,total total output gas flow rate of the compression
flowing pressure at the kick-out-point of station, scf/day
p kf i
lateral i, psia q h injection rate per unit thickness of formation,
3
pressure at the inlet of the gas distribution m =sec-m
p L
line, psia q i flow rate from/into layer i, or pumping rate,
flowing liquid gradient, psi/bbl slug bpm
P lf
hydrostatic liquid gradient, psi/bbl slug maximum injection rate, bbl/min
P lh q i,max
maximum line pressure, psia liquid capacity, bbl/day
p Lmax q L
p o pressure in the annulus, psia Q o oil production rate, bbl/day
p out output pressure of the compression station, q o oil production rate, bbl/d
psia q pump flow rate of the produced fluid in the pump,
P p W p =A t , psia bbl/day
p p pore pressure, psi Q s leak rate, bbl/day, or solid production rate,
3
p pc pseudocritical pressure, psia ft =day
p pump,i pump intake pressure, psia q s gas capacity of contactor for standard gas
p pump,d pump discharge pressure, psia (0.7 specific gravity) at standard temperature
P r pitch length of rotor, ft (100 8F), MMscfd, or sand production rate,
3
p r pseudoreduced pressure ft =day
P s pitch length of stator, ft, or shaft power, q sc gas flow rate, Mscf/d
ft lb f =sec q st gas capacity at standard conditions, MMscfd
p s surface operating pressure, psia, or suction q total total liquid flow rate, bbl/day
pressure, psia, or stock-tank pressure, psia Q w water production rate, bbl/day
p sc standard pressure, 14.7 psia q w water production rate, bbl/d