M
ED
ST
U
D
Y
ISBN: 0750682701
Publisher: Elsevier Science & Technology Books
Pub. Date: February 2007
,Preface
The advances in the digital computing technology in the students. Chapter 15 describes how to identify well prob-
last decade have revolutionized the petroleum industry. lems. Chapter 16 deals with designing acidizing jobs.
Using the modern computer technologies, today’s petro- Chapter 17 provides a guideline to hydraulic fracturing
leum production engineers work much more efficiently and job evaluation techniques. Chapter 18 presents some
than ever before in their daily activities, including analyz- relevant information on production optimisation tech-
ing and optimizing the performance of their existing pro- niques.
duction systems and designing new production systems. Since the substance of this book is virtually boundless in
During several years of teaching the production engineer- depth, knowing what to omit was the greatest difficulty
ing courses in academia and in the industry, the authors with its editing. The authors believe that it requires many
realized that there is a need for a textbook that reflects the books to describe the foundation of knowledge in petro-
current practice of what the modern production engineers leum production engineering. To counter any deficiency
do. Currently available books fail to provide adequate that might arise from the limitations of space, the book
information about how the engineering principles are ap- provides a reference list of books and papers at the end of
M
plied to solving petroleum production engineering prob- each chapter so that readers should experience little diffi-
lems with modern computer technologies. These facts culty in pursuing each topic beyond the presented scope.
motivated the authors to write this new book. Regarding presentation, this book focuses on presen-
This book is written primarily for production engineers ting and illustrating engineering principles used for
and college students of senior level as well as graduate designing and analyzing petroleum production systems
level. It is not authors’ intention to simply duplicate gen- rather than in-depth theories. Derivation of mathematical
ED
eral information that can be found from other books. This models is beyond the scope of this book, except for some
book gathers authors’ experiences gained through years of special topics. Applications of the principles are illustrated
teaching courses of petroleum production engineering in by solving example problems. While the solutions to
universities and in the petroleum industry. The mission of some simple problems not involving iterative procedures
the book is to provide production engineers a handy guide- are demonstrated with stepwise calculations, compli-
line to designing, analyzing, and optimizing petroleum cated problems are solved with computer spreadsheet
production systems. The original manuscript of this book programs. The programs can be downloaded from the
has been used as a textbook for college students of under- publisher’s website (http://books.elsevier.com/companions/
ST
graduate and graduate levels in Petroleum Engineering. 9780750682701). The combination of the book and the
This book was intended to cover the full scope of pe- computer programs provides a perfect tool kit to petrol-
troleum production engineering. Following the sequence eum production engineers for performing their daily work
of oil and gas production process, this book presents its in a most efficient manner. All the computer programs
contents in eighteen chapters covered in four parts. were written in spreadsheet form in MS Excel that is
Part I contains eight chapters covering petroleum pro- available in most computer platforms in the petroleum
duction engineering fundamentals as the first course for industry. These spreadsheets are accurate and very easy
the entry-level production engineers and undergraduate to use. Although the U.S. field units are used in the com-
U
students. Chapter 1 presents an introduction to the petro- panion book, options of using U.S. field units and SI units
leum production system. Chapter 2 documents properties are provided in the spreadsheet programs.
of oil and natural gases that are essential for designing and This book is based on numerous documents including
analysing oil and gas production systems. Chapters 3 reports and papers accumulated through years of work in
through 6 cover in detail the performance of oil and gas the University of Louisiana at Lafayette and the New
D
wells. Chapter 7 presents techniques used to forecast well Mexico Institute of Mining and Technology. The authors
production for economics analysis. Chapter 8 describes are grateful to the universities for permissions of publish-
empirical models for production decline analysis. ing the materials. Special thanks go to the Chevron and
Part II includes three chapters presenting principles and American Petroleum Institute (API) for providing Chev-
Y
rules of designing and selecting the main components of ron Professorship and API Professorship in Petroleum
petroleum production systems. These chapters are also Engineering throughout editing of this book. Our thanks
written for entry-level production engineers and under- are due to Mr. Kai Sun of Baker Oil Tools, who made a
graduate students. Chapter 9 addresses tubing design. thorough review and editing of this book. The authors
Chapter 10 presents rule of thumbs for selecting com- also thank Malone Mitchell III of Riata Energy for he
ponents in separation and dehydration systems. Chapter and his company’s continued support of our efforts to
11 details principles of selecting liquid pumps, gas com- develop new petroleum engineering text and professional
pressors, and pipelines for oil and gas transportation. books for the continuing education and training of the
Part III consists of three chapters introducing artificial industry’s vital engineers. On the basis of the collective
lift methods as the second course for the entry-level pro- experiences of authors and reviewer, we expect this book
duction engineers and undergraduate students. Chapter 12 to be of value to the production engineers in the petrol-
presents an introduction to the sucker rod pumping system eum industry.
and its design procedure. Chapter 13 describes briefly gas
lift method. Chapter 14 provides an over view of other Dr. Boyun Guo
artificial lift methods and design procedures. Chevron Endowed Professor in Petroleum Engineering
Part IV is composed of four chapters addressing pro- University of Louisiana at Lafayette
duction enhancement techniques. They are designed for June 10, 2006
production engineers with some experience and graduate
,List of Symbols
A area, ft2 fRi flow performance function of the curvic
Ab total effective bellows area, in.2 section of lateral i
Aeng net cross-sectional area of engine piston, in.2 fsl slug factor, 0.5 to 0.6
Afb total firebox surface area, ft2 G shear modulus, psia
'
Ai inner area of tubing sleeve, in.2 g gravitational acceleration, 32.17 ft/s2
' Gb pressure gradient below the pump, psi/ft
Ao outer area of tubing sleeve, in.2
Ap valve seat area, gross plunger cross-sectional gc unit conversion factor, 32.17 lbm—ft/lbf —s2
2 Gfd design unloading gradient, psi/ft
area, or inner area of packer, in. Gi
Apump net cross-sectional area of pump piston, in.2 initial gas-in-place, scf
Ar cross-sectional area of rods, in.2 Gp cumulative gas production, scf
At tubing inner cross-sectional area, in.2 Gp1 cumulative gas production per stb of oil at the
oAPI API gravity of stock tank oil beginning of the interval, scf
B formation volume factor of fluid, rb/stb Gs static (dead liquid) gradient, psi/ft
M
b constant 1.5 × 10—5 in SI units G2 mass flux at downstream, lbm/ft2/sec
Bo formation volume factor of oil, rb/stb GLRfm formation oil GLR, scf/stb
Bw formation volume factor of water, rb/bbl GLRinj injection GLR, scf/stb
CA drainage area shape factor GLRmin minimum required GLR for plunger lift, scf/
Ca weight fraction of acid in the acid solution bbl
ED
Cc choke flow coefficient GLRopt,o optimum GLR at operating flow rate, scf/stb
CD choke discharge coefficient GOR producing gas-oil ratio, scf/stb
Cg correction factor for gas-specific gravity GWR glycol to water ratio, gal TEG/lbm H2O
Ci productivity coefficient of lateral i H depth to the average fluid level in the annulus,
Cl clearance, fraction ft, or dimensionless head
Cm mineral content, volume fraction h reservoir thickness, ft, or pumping head, ft
Cs structure unbalance, lbs hf fracture height, ft
Ct correction factor for operating temperature HP required input power, hp
ct total compressibility, psi—1 HpMM required theoretical compression power, hp/
ST
Cp specific heat of gas at constant pressure, lbf- MMcfd
ft/lbm-R Ht total heat load on reboiler, Btu/h
C̄ p specific heat under constant pressure Dh depth increment, ft
evaluated at cooler DHpm mechanical power losses, hp
Cwi water content of inlet gas, lbm H2O/MMscf ∇ hi pressure gradient in the vertical section of
D outer diameter, in., or depth, ft, or non-Darcy lateral i, psi/ft
flow coefficient, d/Mscf, or molecular J productivity of fractured well, stb/d-psi
Ji productivity index of lateral i.
diffusion coefficient, m2/s
U
d diameter, in. Jo productivity of non-fractured well, stb/d-psi
d1 upstream pipe diameter, in. K empirical factor, or characteristic length for
d2 choke diameter, in. gas flow in tubing, ft
db barrel inside diameter, in. k permeability of undamaged formation, md, or
specific heat ratio
D
Dci inner diameter of casing, in.
df fractal dimension constant 1.6 kf fracture permeability, md
Dh hydraulic diameter, in. kH the average horizontal permeability, md
DH hydraulic diameter, ft kh the average horizontal permeability, md
Di inner diameter of tubing, in. ki liquid/vapor equilibrium ratio of compound i
Y
Do outer diameter, in. kp a constant
dp plunger outside diameter, in. kro the relative permeability to oil
Dpump minimum pump depth, ft kV vertical permeability, md
Dr length of rod string, ft L length, ft , or tubing inner capacity, ft/bbl
E rotor/stator eccentricity, in., or Young’s Lg length of gas distribution line, mile
modulus, psi LN net lift, ft
Ev volumetric efficiency, fraction Lp length of plunger, in.
ev correction factor M total mass associated with 1 stb of oil
ep efficiency M2 mass flow rate at down stream, lbm/sec
Fb axial load, lbf MWa molecular weight of acid
FCD fracture conductivity, dimensionless MWm molecular weight of mineral
FF fanning friction factor N pump speed, spm, or rotary speed, rpm
Fgs modified Foss and Gaul slippage factor n number of layers, or polytropic exponent for
fhi flow performance function of the vertical gas
section of lateral i NAc acid capillary number, dimensionless
fLi inflow performance function of the horizontal NCmax maximum number of cycles per day
section of lateral i nG number of lb-mole of gas
fM Darcy-Wiesbach (Moody) friction factor Ni initial oil in place in the well drainage area, stb
Fpump pump friction-induced pressure loss, psia ni productivity exponent of lateral i
, xii LIST OF SYMBOLS
nL number of mole of fluid in the liquid phase psh slug hydrostatic pressure, psia
Nmax maximum pump speed, spm psi surface injection pressure, psia
np number of pitches of stator psuction suction pressure of pump, psia
Np1 cumulative oil production per stb of oil in Pt tubing pressure, psia
place at the beginning of the interval ptf flowing tubing head pressure, psig
Npf ,n forcasted annual cumulative production of pup pressure upstream the choke, psia
fractured well for year n Pvc valve closing pressure, psig
Npnf,n predicted annual cumulative production of Pvo valve opening pressure, psig
nonfractured well for year n pwh upstream (wellhead) pressure, psia
Npno,n predicted annual cumulative production of pwf flowing bottom hole pressure, psia
non-optimized well for year n pwfi the average flowing bottom-lateral pressure in
Npop,n forcasted annual cumulative production of lateral i, psia
optimized system for year n pwfo dynamic bottom hole pressure because of
NRe Reunolds number cross-flow between, psia
Ns number of compression stages required pcwf critical bottom hole pressure maintained
Nst number of separation stages —1 during the production decline, psia
nV number of mole of fluid in the vapor phase pup upstream pressure at choke, psia
Nw number of wells P1 pressure at point 1 or inlet, lbf /ft2
DNp,n predicted annual incremental cumulative P2 pressure at point 2 or outlet, lbf /ft2
production for year n p1 upstream/inlet/suction pressure, psia
M
P pressure, lb/ft2 p2 downstream/outlet/discharge pressure, psia
p pressure, psia ¯p average reservoir pressure, psia
pb base pressure, psia ¯pf reservoir pressure in a future time, psia
pbd formation breakdown pressure, psia ¯p0 average reservoir pressure at decline time
Pc casing pressure, psig zero, psia
ED
pc critical pressure, psia, or required casing ¯pt average reservoir pressure at decline time t,
pressure, psia, or the collapse pressure with psia
no axial load, psia DP pressure drop, lbf /ft2
pcc the collapse pressure corrected for axial load, Dp pressure increment, psi
psia �p head rating developed into an elementary
Pcd2 design injection pressure at valve 2, psig cavity, psi
PCmin required minimum casing pressure, psia Dpf frictional pressure drop, psia
pc,s casing pressure at surface, psia Dph hydrostatic pressure drop, psia
pc,v casing pressure at valve depth, psia Dpi avg the average pressure change in the tubing, psi
ST
Pd pressure in the dome, psig Dpo avg the average pressure change in the annulus,
pd final discharge pressure, psia psi
peng,d engine discharge pressure, psia Dpsf safety pressure margin, 200 to 500 psi
peng,i pressure at engine inlet, psia Dpv pressure differential across the operating
pf frictional pressure loss in the power fluid valve (orifice), psi
injection tubing, psi Q volumetric flow rate
Ph hydraulic power, hp q volumetric flow rate
ph hydrostatic pressure of the power fluid at Qc pump displacement, bbl/day
U
pump depth, psia qeng flow rate of power fluid, bbl/day
phf wellhead flowing pressure, psia QG gas production rate, Mscf/day
phfi flowing pressure at the top of lateral i, psia qG glycol circulation rate, gal/hr
pL pressure at the inlet of gas distribution line, qg gas production rate, scf/d
psia qg,inj the lift gas injection rate (scf/day) available to
D
pi initial reservoir pressure, psia, or pressure in the well
tubing, psia, or pressure at stage i, psia qgM gas flow rate, Mscf/d
pkd1 kick-off pressure opposite the first valve, psia qg,total total output gas flow rate of the compression
pkfi flowing pressure at the kick-out-point of station, scf/day
lateral i, psia
Y
qh injection rate per unit thickness of formation,
pL pressure at the inlet of the gas distribution m3/sec-m
line, psia qi flow rate from/into layer i, or pumping rate,
Plf flowing liquid gradient, psi/bbl slug bpm
Plh hydrostatic liquid gradient, psi/bbl slug qi,max maximum injection rate, bbl/min
pLmax maximum line pressure, psia qL liquid capacity, bbl/day
po pressure in the annulus, psia Qo oil production rate, bbl/day
pout output pressure of the compression station, qo oil production rate, bbl/d
psia qpump flow rate of the produced fluid in the pump,
Pp Wp/At, psia bbl/day
pp pore pressure, psi Qs leak rate, bbl/day, or solid production rate,
ppc pseudocritical pressure, psia ft3/day
ppump,i pump intake pressure, psia qs gas capacity of contactor for standard gas
ppump,d pump discharge pressure, psia (0.7 specific gravity) at standard temperature
Pr pitch length of rotor, ft (100 8F), MMscfd, or sand production rate,
pr pseudoreduced pressure ft3/day
Ps pitch length of stator, ft, or shaft power, qsc gas flow rate, Mscf/d
ft—lbf /sec qst gas capacity at standard conditions, MMscfd
ps surface operating pressure, psia, or suction qtotal total liquid flow rate, bbl/day
pressure, psia, or stock-tank pressure, psia Qw water production rate, bbl/day
psc standard pressure, 14.7 psia qw water production rate, bbl/d
ED
ST
U
D
Y
ISBN: 0750682701
Publisher: Elsevier Science & Technology Books
Pub. Date: February 2007
,Preface
The advances in the digital computing technology in the students. Chapter 15 describes how to identify well prob-
last decade have revolutionized the petroleum industry. lems. Chapter 16 deals with designing acidizing jobs.
Using the modern computer technologies, today’s petro- Chapter 17 provides a guideline to hydraulic fracturing
leum production engineers work much more efficiently and job evaluation techniques. Chapter 18 presents some
than ever before in their daily activities, including analyz- relevant information on production optimisation tech-
ing and optimizing the performance of their existing pro- niques.
duction systems and designing new production systems. Since the substance of this book is virtually boundless in
During several years of teaching the production engineer- depth, knowing what to omit was the greatest difficulty
ing courses in academia and in the industry, the authors with its editing. The authors believe that it requires many
realized that there is a need for a textbook that reflects the books to describe the foundation of knowledge in petro-
current practice of what the modern production engineers leum production engineering. To counter any deficiency
do. Currently available books fail to provide adequate that might arise from the limitations of space, the book
information about how the engineering principles are ap- provides a reference list of books and papers at the end of
M
plied to solving petroleum production engineering prob- each chapter so that readers should experience little diffi-
lems with modern computer technologies. These facts culty in pursuing each topic beyond the presented scope.
motivated the authors to write this new book. Regarding presentation, this book focuses on presen-
This book is written primarily for production engineers ting and illustrating engineering principles used for
and college students of senior level as well as graduate designing and analyzing petroleum production systems
level. It is not authors’ intention to simply duplicate gen- rather than in-depth theories. Derivation of mathematical
ED
eral information that can be found from other books. This models is beyond the scope of this book, except for some
book gathers authors’ experiences gained through years of special topics. Applications of the principles are illustrated
teaching courses of petroleum production engineering in by solving example problems. While the solutions to
universities and in the petroleum industry. The mission of some simple problems not involving iterative procedures
the book is to provide production engineers a handy guide- are demonstrated with stepwise calculations, compli-
line to designing, analyzing, and optimizing petroleum cated problems are solved with computer spreadsheet
production systems. The original manuscript of this book programs. The programs can be downloaded from the
has been used as a textbook for college students of under- publisher’s website (http://books.elsevier.com/companions/
ST
graduate and graduate levels in Petroleum Engineering. 9780750682701). The combination of the book and the
This book was intended to cover the full scope of pe- computer programs provides a perfect tool kit to petrol-
troleum production engineering. Following the sequence eum production engineers for performing their daily work
of oil and gas production process, this book presents its in a most efficient manner. All the computer programs
contents in eighteen chapters covered in four parts. were written in spreadsheet form in MS Excel that is
Part I contains eight chapters covering petroleum pro- available in most computer platforms in the petroleum
duction engineering fundamentals as the first course for industry. These spreadsheets are accurate and very easy
the entry-level production engineers and undergraduate to use. Although the U.S. field units are used in the com-
U
students. Chapter 1 presents an introduction to the petro- panion book, options of using U.S. field units and SI units
leum production system. Chapter 2 documents properties are provided in the spreadsheet programs.
of oil and natural gases that are essential for designing and This book is based on numerous documents including
analysing oil and gas production systems. Chapters 3 reports and papers accumulated through years of work in
through 6 cover in detail the performance of oil and gas the University of Louisiana at Lafayette and the New
D
wells. Chapter 7 presents techniques used to forecast well Mexico Institute of Mining and Technology. The authors
production for economics analysis. Chapter 8 describes are grateful to the universities for permissions of publish-
empirical models for production decline analysis. ing the materials. Special thanks go to the Chevron and
Part II includes three chapters presenting principles and American Petroleum Institute (API) for providing Chev-
Y
rules of designing and selecting the main components of ron Professorship and API Professorship in Petroleum
petroleum production systems. These chapters are also Engineering throughout editing of this book. Our thanks
written for entry-level production engineers and under- are due to Mr. Kai Sun of Baker Oil Tools, who made a
graduate students. Chapter 9 addresses tubing design. thorough review and editing of this book. The authors
Chapter 10 presents rule of thumbs for selecting com- also thank Malone Mitchell III of Riata Energy for he
ponents in separation and dehydration systems. Chapter and his company’s continued support of our efforts to
11 details principles of selecting liquid pumps, gas com- develop new petroleum engineering text and professional
pressors, and pipelines for oil and gas transportation. books for the continuing education and training of the
Part III consists of three chapters introducing artificial industry’s vital engineers. On the basis of the collective
lift methods as the second course for the entry-level pro- experiences of authors and reviewer, we expect this book
duction engineers and undergraduate students. Chapter 12 to be of value to the production engineers in the petrol-
presents an introduction to the sucker rod pumping system eum industry.
and its design procedure. Chapter 13 describes briefly gas
lift method. Chapter 14 provides an over view of other Dr. Boyun Guo
artificial lift methods and design procedures. Chevron Endowed Professor in Petroleum Engineering
Part IV is composed of four chapters addressing pro- University of Louisiana at Lafayette
duction enhancement techniques. They are designed for June 10, 2006
production engineers with some experience and graduate
,List of Symbols
A area, ft2 fRi flow performance function of the curvic
Ab total effective bellows area, in.2 section of lateral i
Aeng net cross-sectional area of engine piston, in.2 fsl slug factor, 0.5 to 0.6
Afb total firebox surface area, ft2 G shear modulus, psia
'
Ai inner area of tubing sleeve, in.2 g gravitational acceleration, 32.17 ft/s2
' Gb pressure gradient below the pump, psi/ft
Ao outer area of tubing sleeve, in.2
Ap valve seat area, gross plunger cross-sectional gc unit conversion factor, 32.17 lbm—ft/lbf —s2
2 Gfd design unloading gradient, psi/ft
area, or inner area of packer, in. Gi
Apump net cross-sectional area of pump piston, in.2 initial gas-in-place, scf
Ar cross-sectional area of rods, in.2 Gp cumulative gas production, scf
At tubing inner cross-sectional area, in.2 Gp1 cumulative gas production per stb of oil at the
oAPI API gravity of stock tank oil beginning of the interval, scf
B formation volume factor of fluid, rb/stb Gs static (dead liquid) gradient, psi/ft
M
b constant 1.5 × 10—5 in SI units G2 mass flux at downstream, lbm/ft2/sec
Bo formation volume factor of oil, rb/stb GLRfm formation oil GLR, scf/stb
Bw formation volume factor of water, rb/bbl GLRinj injection GLR, scf/stb
CA drainage area shape factor GLRmin minimum required GLR for plunger lift, scf/
Ca weight fraction of acid in the acid solution bbl
ED
Cc choke flow coefficient GLRopt,o optimum GLR at operating flow rate, scf/stb
CD choke discharge coefficient GOR producing gas-oil ratio, scf/stb
Cg correction factor for gas-specific gravity GWR glycol to water ratio, gal TEG/lbm H2O
Ci productivity coefficient of lateral i H depth to the average fluid level in the annulus,
Cl clearance, fraction ft, or dimensionless head
Cm mineral content, volume fraction h reservoir thickness, ft, or pumping head, ft
Cs structure unbalance, lbs hf fracture height, ft
Ct correction factor for operating temperature HP required input power, hp
ct total compressibility, psi—1 HpMM required theoretical compression power, hp/
ST
Cp specific heat of gas at constant pressure, lbf- MMcfd
ft/lbm-R Ht total heat load on reboiler, Btu/h
C̄ p specific heat under constant pressure Dh depth increment, ft
evaluated at cooler DHpm mechanical power losses, hp
Cwi water content of inlet gas, lbm H2O/MMscf ∇ hi pressure gradient in the vertical section of
D outer diameter, in., or depth, ft, or non-Darcy lateral i, psi/ft
flow coefficient, d/Mscf, or molecular J productivity of fractured well, stb/d-psi
Ji productivity index of lateral i.
diffusion coefficient, m2/s
U
d diameter, in. Jo productivity of non-fractured well, stb/d-psi
d1 upstream pipe diameter, in. K empirical factor, or characteristic length for
d2 choke diameter, in. gas flow in tubing, ft
db barrel inside diameter, in. k permeability of undamaged formation, md, or
specific heat ratio
D
Dci inner diameter of casing, in.
df fractal dimension constant 1.6 kf fracture permeability, md
Dh hydraulic diameter, in. kH the average horizontal permeability, md
DH hydraulic diameter, ft kh the average horizontal permeability, md
Di inner diameter of tubing, in. ki liquid/vapor equilibrium ratio of compound i
Y
Do outer diameter, in. kp a constant
dp plunger outside diameter, in. kro the relative permeability to oil
Dpump minimum pump depth, ft kV vertical permeability, md
Dr length of rod string, ft L length, ft , or tubing inner capacity, ft/bbl
E rotor/stator eccentricity, in., or Young’s Lg length of gas distribution line, mile
modulus, psi LN net lift, ft
Ev volumetric efficiency, fraction Lp length of plunger, in.
ev correction factor M total mass associated with 1 stb of oil
ep efficiency M2 mass flow rate at down stream, lbm/sec
Fb axial load, lbf MWa molecular weight of acid
FCD fracture conductivity, dimensionless MWm molecular weight of mineral
FF fanning friction factor N pump speed, spm, or rotary speed, rpm
Fgs modified Foss and Gaul slippage factor n number of layers, or polytropic exponent for
fhi flow performance function of the vertical gas
section of lateral i NAc acid capillary number, dimensionless
fLi inflow performance function of the horizontal NCmax maximum number of cycles per day
section of lateral i nG number of lb-mole of gas
fM Darcy-Wiesbach (Moody) friction factor Ni initial oil in place in the well drainage area, stb
Fpump pump friction-induced pressure loss, psia ni productivity exponent of lateral i
, xii LIST OF SYMBOLS
nL number of mole of fluid in the liquid phase psh slug hydrostatic pressure, psia
Nmax maximum pump speed, spm psi surface injection pressure, psia
np number of pitches of stator psuction suction pressure of pump, psia
Np1 cumulative oil production per stb of oil in Pt tubing pressure, psia
place at the beginning of the interval ptf flowing tubing head pressure, psig
Npf ,n forcasted annual cumulative production of pup pressure upstream the choke, psia
fractured well for year n Pvc valve closing pressure, psig
Npnf,n predicted annual cumulative production of Pvo valve opening pressure, psig
nonfractured well for year n pwh upstream (wellhead) pressure, psia
Npno,n predicted annual cumulative production of pwf flowing bottom hole pressure, psia
non-optimized well for year n pwfi the average flowing bottom-lateral pressure in
Npop,n forcasted annual cumulative production of lateral i, psia
optimized system for year n pwfo dynamic bottom hole pressure because of
NRe Reunolds number cross-flow between, psia
Ns number of compression stages required pcwf critical bottom hole pressure maintained
Nst number of separation stages —1 during the production decline, psia
nV number of mole of fluid in the vapor phase pup upstream pressure at choke, psia
Nw number of wells P1 pressure at point 1 or inlet, lbf /ft2
DNp,n predicted annual incremental cumulative P2 pressure at point 2 or outlet, lbf /ft2
production for year n p1 upstream/inlet/suction pressure, psia
M
P pressure, lb/ft2 p2 downstream/outlet/discharge pressure, psia
p pressure, psia ¯p average reservoir pressure, psia
pb base pressure, psia ¯pf reservoir pressure in a future time, psia
pbd formation breakdown pressure, psia ¯p0 average reservoir pressure at decline time
Pc casing pressure, psig zero, psia
ED
pc critical pressure, psia, or required casing ¯pt average reservoir pressure at decline time t,
pressure, psia, or the collapse pressure with psia
no axial load, psia DP pressure drop, lbf /ft2
pcc the collapse pressure corrected for axial load, Dp pressure increment, psi
psia �p head rating developed into an elementary
Pcd2 design injection pressure at valve 2, psig cavity, psi
PCmin required minimum casing pressure, psia Dpf frictional pressure drop, psia
pc,s casing pressure at surface, psia Dph hydrostatic pressure drop, psia
pc,v casing pressure at valve depth, psia Dpi avg the average pressure change in the tubing, psi
ST
Pd pressure in the dome, psig Dpo avg the average pressure change in the annulus,
pd final discharge pressure, psia psi
peng,d engine discharge pressure, psia Dpsf safety pressure margin, 200 to 500 psi
peng,i pressure at engine inlet, psia Dpv pressure differential across the operating
pf frictional pressure loss in the power fluid valve (orifice), psi
injection tubing, psi Q volumetric flow rate
Ph hydraulic power, hp q volumetric flow rate
ph hydrostatic pressure of the power fluid at Qc pump displacement, bbl/day
U
pump depth, psia qeng flow rate of power fluid, bbl/day
phf wellhead flowing pressure, psia QG gas production rate, Mscf/day
phfi flowing pressure at the top of lateral i, psia qG glycol circulation rate, gal/hr
pL pressure at the inlet of gas distribution line, qg gas production rate, scf/d
psia qg,inj the lift gas injection rate (scf/day) available to
D
pi initial reservoir pressure, psia, or pressure in the well
tubing, psia, or pressure at stage i, psia qgM gas flow rate, Mscf/d
pkd1 kick-off pressure opposite the first valve, psia qg,total total output gas flow rate of the compression
pkfi flowing pressure at the kick-out-point of station, scf/day
lateral i, psia
Y
qh injection rate per unit thickness of formation,
pL pressure at the inlet of the gas distribution m3/sec-m
line, psia qi flow rate from/into layer i, or pumping rate,
Plf flowing liquid gradient, psi/bbl slug bpm
Plh hydrostatic liquid gradient, psi/bbl slug qi,max maximum injection rate, bbl/min
pLmax maximum line pressure, psia qL liquid capacity, bbl/day
po pressure in the annulus, psia Qo oil production rate, bbl/day
pout output pressure of the compression station, qo oil production rate, bbl/d
psia qpump flow rate of the produced fluid in the pump,
Pp Wp/At, psia bbl/day
pp pore pressure, psi Qs leak rate, bbl/day, or solid production rate,
ppc pseudocritical pressure, psia ft3/day
ppump,i pump intake pressure, psia qs gas capacity of contactor for standard gas
ppump,d pump discharge pressure, psia (0.7 specific gravity) at standard temperature
Pr pitch length of rotor, ft (100 8F), MMscfd, or sand production rate,
pr pseudoreduced pressure ft3/day
Ps pitch length of stator, ft, or shaft power, qsc gas flow rate, Mscf/d
ft—lbf /sec qst gas capacity at standard conditions, MMscfd
ps surface operating pressure, psia, or suction qtotal total liquid flow rate, bbl/day
pressure, psia, or stock-tank pressure, psia Qw water production rate, bbl/day
psc standard pressure, 14.7 psia qw water production rate, bbl/d
