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A P I T I T L E * V T - b 9 4 m 0732290 0532824 833 W
GAS LIFTBOOK 6 OF THE
SERIESCATIONAL TRAINING
THIRD EDITION, 1994
right American Petroleum Institute
ded by IHS under license with API Licensee=Vetco Aibel/5925731102
Not for Resale, 07/27/2006 10:42:36 MDTproduction or networking permitted without license from IHS
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A P I TITLE*VT-b 94 m 0732290053282577T m
API GA S LIFT MANUALBook 6 of the Vocational Training Series
Third Edition, 1994
Issued by
AMERICAN PETROLEUM INSTITUTE
Exploration & Production Department
FOR INFORMATION CONCERNING TECHNICAL CONTENT OFTHIS PUBLICATION CONTACT THE API EXP LORATION & PRODUCTION DEPARTMENT,
SEE BACK COVER FOR INFORMATION CONCERNING HOW TO OBTAIN
ADDITIONAL COPIES OF THIS PUBLICATION.
700 NORTH P EAR L, SUITE 1840 (LB-382), DALLAS , TX 75201-2831 - 214) 953-1101.
Users of this publication should become familiar with its scope
and content. This document is intended to supplement rather
than replace ndividual engineering udgment.
OFFICIAL P UBLICATION
RE G U.S. PATENT OFFICE
Copyright O 1994 American Petroleum Institute
right American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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API T I TL E l kV T -6 9 4 W 0732290 0532826 6 0 6 W
POLICY
API PUBLICATIONS NECESSARILY ADDRESS PROBLEMS OF A GENERA L NA-
TURE. WITH RESPECT TO PARTICULAR CIRCUMSTA NCES, LOCAL, STATE ANDFEDER AL LAW S AND R EGULATI ONS SHOULD B E R EVI EW ED.
API I S NOT UNDER TAKI NG TO MEET DUTI ES OF EMPLOYER S, MANUFAC TUR -
E R S ,O RS U P P L I E R ST OW A R NA N DP R O P E R L YT R A I NA N DE Q U I PT H E I R
EMPLOYEES, AND OTHER S EXPOSED, C ONC ER NI NG HEALTH AND SAFETY R I SKS
AND PR EC AUTI ONS, NOR UN DER TAKI NG THEI R OB LI GATIONS UNDER LOC AL,
STATE, OR FEDER AL LAW S.
NOTHI NGCONTA INED IN ANY APIPUBLICATION IS TOB EC ONSTR UEDAS
GR ANTI NG ANY R I GHT, B Y I MPLI C ATION OR OTHER W I SE, FOR THE M ANUFAC -
T U R E , S A L E ,O R U S E O F A N Y M E T H O D , A P P A R A T U S , R P R O D U C T C O V E R E D B Y
LETTER S PATENT. NEI THER SHOULD ANYTHI NG C ONTAI NED I N THE PUB LI C A-
T I O NB EC O N S T R U E DA S N S U R I N GA N Y O N EA G A I N S TL I A B I L I T YF O RI NFR INGEMENT O F LETTER S PATENT.
GENERALLY, API PUBLICATIONS ARE REVIEWED AND REVISED, REAFFIRMED,
OR W I THDR AW N AT LEAST EVER Y FI VE YEAR S. SOMETI MES A ONE- TIME EX-
TENSI ON OF UP TO TW O Y EAR S W I LL B E ADDED TO THI S R EVI EW C YC LE. THI S
PUB LI C ATI ON W I LL NO LONGER B EN EFFECT FIVE YEARS AFTER ITS PUBLICA-
TI ON DATE AS AN OPER ATI VE API PUB LI C ATI ON OR , W HER E AN EXTENSI ON HAS
B EEN GR ANTED, UPON R EPUB LIC ATI ON. STATUS OF THE PUB LI C ATI ON C AN B E
ASC ER TAI NEDFR OMTHEA PIEXPLOR ATI ON & PR ODUC TI OND E P A R T M E N T
(214-953-1101). AC ATALOG OF APIPUBLICATIONSANDMATERIALS SPUB-
LI SHEDA N N U A L L YA N DU P D A T E DQ U A R T E R L YB YAPI . 1220 LST. ,N .W . ,
W ASHI NGTO N, D .C . 20005.
right American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I I T L E *V T - 6 94 m 0732290 0532827 542 m
FOREWORD
Artificial l i f t represents an increasingly important part of the oil b usiness. In fact , at the
time of this writ ing, over 90% of he oil wells in the United States used some form ofartificial lift. T he fou r bas ic type s f artificial lift used in the oil industry are: rod pumping,
electr ic submersible pumping, hydraulic pumping, and gas l if t . As the name implies, gasi f t
is the only one f the ar t if icial l if t sy stems that do es notse some formof mechanical pump
to physically force the f luid from one place to another . Becausef this pheno meno n, gas l if t
has certain advantages over the other systems in some instances and occupies a rather unique
and important place as a l if t mechanism.
This manual s under he urisdiction of theExecutiveCommitteeonTraining and
Development, Exploration & Production Department, American Petroleum Insti tute. I t is
intended to familiar ize operating personnelith the useof gas l if t as n ar t if icial l i f t system.
It includes information on the basic principles of gas lift, the choice of gas l if t equipment,
how various types of gas l if t e quipme nt work, andow a gas l if t system shoulde designed.
Information is also includedon monitoring, adjusting, regulating, and trouble-shooting gaslif t equipment.
The f irst edit ionof this manual was issued n 1965. A second ed i t ion was i ssued n 1984,
and editorial errata were publish ed in 1986 and incorporatedn a 198 8 reprin t f the manual.
This third edit ion was developed as n editorial update for consistency with recentAPI gas
lift standards.
I t was developed with assistance by volunteer technical reviewers including:
J . R. B lann , Consul tan t, Lead Reviewer
J. R. Bennett , Exxon Production Research Company
Joe Clegg, Pectin International
John M artinez, Production Associates
H. W. Winkler , Consultant
right American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
Not for Resale, 07/27/2006 10:42:36 MDTproduction or networking permitted without license from IHS
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API T I T L E x V T - 6 94 D 0732290 OS32828 489 m
Other p ubl icat ions in the API Vocat ional Training Series are:
Book 1: Int roduct ion to Oi l and Gas Product ion, Fourth Edition, 1983 (Reaffirmed 1988)
Thispopularorientation manualcontains81pagesandover 100 photographsand ine
drawings. I t is writ ten as a simple, easy-to-understand style to help orient and train inexperi-
enced oil and gas production personnel. The book is also helpful to students, industry off ice
personnel, and businesses all ied with the oil and gas industry. The fourth edit ion represents
a com plete revision and updating of the previous edit ion. Spiral bound, 8 ’ / 2 x 1 1 , soft cover.
Book 2: Corros ion o f Oi l and Gas Wel l Equipmen t , Second Edi t ion , 1990
Genera laspects of corrosion,sweetcorrosion,oxygencorrosion,andelec t rochemical
corrosion are thoroughly covered. Methods of evaluation and control m easures are de scribed
in detail Spiral bound, 6 ’ / 2 x 10, soft cover, 87 pages.
Book 3: Subsurface Sal t Water Inject ion und Dis pos al , Second Edi t ion 1978 (Reaf f i rmed
1986)
Ah an d b o o k o r h ep lanning , nsta l la t ion ,opera t ion ,an dmain tenance of subsur face
injection and disposal systems. Design criter ia and formulae are given for gathering systems,
treating plants, and injection facil i t ies. Alternative equipment and methods are discussed and
illustrated. Economic considerations are presented. The book includes a glossary and bibliog-
raphy. S oft cover, 6I/2x 1O ,
spiral bound, 67 pages,1S
i l lustrations.
Book 5: Wi r e l i ne O p e r a t i o ns a nd P r o c e d ur e s , Second Edi t ion , 1983 (Reaf f i rmed 1988)
This handbook describes the various surface and subsurface wireline tools and equipment
used in the oil and gas industry. It explains and outlines the application of these tools in
wireline opera t ions, nc lud ing hoseoperations conductedoffshore. I t isabasicmanual
presented in a simple, uncluttered manner. Soft cover, 72 pages, 90 illustrations, 6l/2 x IO,
spiral bound.
A PI Specs & RPs
(Users should check the latest editions)
Spec 1 1 V I , Sp e c i f i c a t i o n f o r G a s L if t Va l v e s , O r i fi c e s , Re v e r se F l o w Va l v e s a nd D um my
Va v e s
Covers specif ications on gas l if t valves, or if ices, reverse f low valves, and dummy valves.
R P 1 1V5, Re c o mme nd e d P r a c t i c e f o r O p e r a t i o n , Ma i n t e na nc e , a nd T r o ub l e - Sho o t i ngf G a s
Lift In stal lations
Covers ecommendedpracticeonkickoffandunloading,adjustmentproceduresand
trouble-shooting diagnostic tools an d loca tion of problem areas for gas l if t operations.
R P 11V6, Recommended Pract i ce for Des ignf Cont inuous Flow Gas L i f t Ins ta l la t ions Us ing
Injec t ion Pressure Opera ted Valves
This ecommendedpractice s ntended to setguidelines orcont inuous lowgas l i f t
installation designs using injection pressure operated valves. The assumption isade that the
designer is familiar with and has available data on the various factors that affect a design. The
designer is referred o the AP I “Gas Lif t Manual” Book 6 of the V ocational T raining Se ries)
and to the various AP I 1 1V recommended practices on gas l i f t .
R P 1 1V7, Recomm ended Pract i ce for Repa i r , Tes ting and Set t ing Gas L i f t Va lves
This document applies to repair, testing, and setting gas lift valves and revers e flow (check)
valves. I t presents guidelines related to the repair and reuse of valves; these practices are
intended to serve both repair shops and operators. The commonly used gas pressure operated
bel lows valve i s a lso covered . Other va lves , inc lud ing bel lows charged valvesn production
pressure (f luid) service should be repaired according to these guidelines.
right American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
Not for Resale, 07/27/2006 10:42:36 MDTproduction or networking permitted without license from IHS
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A P I T I T L E + V T - 6 9 4 0732290 0532829 315
TABLE OF CONTENTS
API GAS LIFT MANUAL
CHAPTER 1.NTRODUCTION TO ARTIFICIAL LIFT AND GAS LIFT
BASIC PRINCIPLES OF OIL PRODUCTION .......................................................................... 1
Factors That Affec t O i l Product ion ......................................................................................... i
ARTIFICIAL LIFT ......................................................................................................................... 1
Types of Artif icial Lif t Systems ............................................................................................... 1Choosing an Artlf lclal Lift System .......................................................................................... 1
THE PR OC ESS OF GAS LI FT..................................................................................................... 2
Ty p es of Gas Lif t ......................................................................................................................... 2
Cont inuous Flow Gas Lif t ......................................................................................................... 2
In termitten t Flow G as Lif t ........................................................................................................ 3
ADVANTAGES AND LI MITATI ONS OF GAS LI FT ............................................................. 4
Choice of Gas Lift System ......................................................................................................... 4
HI STOR I C AL R EVI EW OF GAS LI FT DEVELOPMENT..................................................... 6
Ear ly Exper iments ....................................................................................................................... 6
Chronologica l Development ..................................................................................................... 6
DEVELOPMENT OF THE MODER N G AS LI FT VALVE..................................................... 8Differential Valves ...................................................................................................................... 8
Bel lows Charged Valves ............................................................................................................ 9
. . .
Technica l D evelopment o f Gas L if t Equipment .................................................................... 6
CHAPTER 2- ELL PERFORMANCE
I NTR ODUC TI ON .......................................................................................................................... 11
I NFLOW PER FOR MANC E PR EDI C TI ON .............................................................................. 12
Productivity Index (P . I . ) Technique ....................................................................................... 12
Inf low Per formance Rela t ionsh ip ( IPR) Technique ........................................................... 12
Vogel IPR Curve ....................................................................................................................... 1 2
Vogel’s Example Problem ....................................................................................................... 13
W ELL OUTFLOW PER FOR MANC E PR EDI C TION ............................................................. 17
Example Problem ...................................................................................................................... 17
P R E D I C T I N G T H E E F F E C TOF GAS LIFT ............................................................................ 19Com parison of Conduit Size ................................................................................................... 21
Effect of Surface Operating Conditions................................................................................ 21
Use of Inflow Performance Relationship Curves (IPR)..................................................... 22
Computer Programs for Wel l Per formance Analysis ......................................................... 22
CHAPTER 3- ULTIPHASE FLOW PREDICTION
I NTR ODUC TI ON .......................................................................................................................... 23
Dimension less Parameters ....................................................................................................... 23
Empir ica l Data ........................................................................................................................... 2 3
Basis fo r Develop ing M ul t iphase Flow Corre la tions......................................................... 2 3
Accuracy of Flowing Pressure at Depth Predictions.......................................................... 2 3
Importance of Reliable Well Test Data ................................................................................ 2 4
FLOW C OR R ELATI ONS.................................................................................................... 24
PUBLISHED VERTICAL, HORIZONTAL AND INCLINED MULTIPHASE
Papers Evaluat ing the Accuracyof Multiphase Flow Correlations ................................. 24
Ros-Gray and Duns-Ros Corre la t ions................................................................................... 25
ENER GY LOSS FAC TOR S OR NO- SLIP HOM OGENEOUS M I XTUR ES ............... 25
SI MPLIFI ED MULTI PHASE FLOW C OR R ELATIONS B ASED ON TOTAL
Poet tmann and Carpenter Corre la t ion................................................................................... 25
Baxendel l and Thom as Corre la t ion ....................................................................................... 25
Two-Phase H omogeneous No-Sl ip M ixture Correla t ions ................................................. 26
GENER AL TYPE OF MULTI PHASE FLOW C OR R ELATI ONS........................................ 2 6
Typical Pressure Gradient Equation for Vertical Flow ..................................................... 2 6
Publ ished Genera l Type Corre la tions ................................................................................... 27
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TABLE OF CONTENTS
(Continued)
D I S P L A Y S OF FLOW I NG PR ESSUR E AT DEPTH GR ADI ENT C UR VES.................... 27
Conver t ing Rgo o Rg................................................................................................................. 27
Gilber t ’ s Curves ........................................................................................................................ 28
Min imu m F lu id Gr ad ien t C u r v e............................................................................................. 28
Display ing Grad ien t Curves to P revent Crossover ............................................................. 3 2S T A B I L I T Y O F F L O W C O N D I T I O N S A N D S E L E C T I O N O F
P R O D U C T I O N C O N D U I T S I Z E....................................................................................... 3 2
Condi t ions Necessary to Assure Stab le Mul t iphase Flow................................................. 3 3
Effec t o f Tu bing S ize n Minimum Stab i l ized Flow Rate ................................................. 3 4
Graphica l Determinat ion of Min imum Stab i l ized P roduct ion Rate ................................. 3 2
CHAPTER 4- AS APPLICATION AND GA S FACILITIES
FOR GAS LIFT
I NTR ODUC TI ON .......................................................................................................................... 3 5
B A S I C F U N D A M E N T A L S O F G A S B E H A V I O R ................................................................. 3 5
A P P L I C A T I O N T O O I L F I E L D S Y S T E M S............................................................................. 3 9
Subsur face Appl ica t ions .......................................................................................................... 3 9
Pressure Correction ................................................................................................................... 3 9Tempera ture Correc t ion........................................................................................................... 3 9
Test Rack Set t ings .................................................................................................................... 41
Gas In jec t ion in the Annulus r Tubing ................................................................................ 41
Flow Through the Gas Lif t Valve.......................................................................................... 4 5
S U R F A C E G A S F A C I L I T I ES .................................................................................................... 49
System Design Considera t ions ............................................................................................... 49
Gas Condi t ion ing ...................................................................................................................... 49
Reciprocat ing Compression ..................................................................................................... 50
Pip ing and D ist r ibu t ion Systems ............................................................................................ 5 4
Gas Meter ing .............................................................................................................................. 5 4
Centr i fugal Compression ......................................................................................................... 5 2
CHAPTER 5- AS LIFT VALVESI NTR ODUC TI ON .......................................................................................................................... 5 7
V A L V E M E C H A N I C S ................................................................................................................. 5 7
Basic Com ponents o f Gas Lif t V alves .................................................................................. 58
Closing Force ............................................................................................................................. 5 9
Op en in g Fo r ces .......................................................................................................................... 59
Valve Load Rate ........................................................................................................................ 6 0
Pr o b e Tes t .................................................................................................................................. 6 0
Production Pressure Effect ...................................................................................................... 6 0
Closing Pressure ........................................................................................................................ 61
VALVE C HAR AC TER I STI C S ................................................................................................... 61
Dy n amic F lo w Tes t.................................................................................................................. 6 .
Valve Spread .............................................................................................................................. 61Bel lows Pro tec t ion .................................................................................................................... 6 2
Test Rack Opening Pressure ................................................................................................... 6 2
TYPES OF GAS LI FT VALVES ................................................................................................ 6 3
Classi f ica t ion of Gas Lif t Valves by Appl ica t ion ............................................................... 6 3
Valves Used for C ont inuous Flow ......................................................................................... 6 3
Valves Used for In termit ten t Li f t.......................................................................................... 6 3
Wire l ine Retr ievable Valve and Mandre l ............................................................................. 6 5
Mandre l and Valve Por t ing Combinat ions ........................................................................... 6 7
Basic Valve Designs ................................................................................................................. 6 4
CHAPTER 6- ONTINUOUS FLOW GAS LIFT DESIGN METHODS
I NTR ODUC TI ON .......................................................................................................................... 6 9
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TABLE OF CONTENTS
(Continued)
TYPES OF I NSTALLATI ONS .................................................................................................... 6 9
C ONTI NUOUS FLOW UNLOADI NG SEQUENC E............................................................... 7 0
DESI GN OF C ONTI NUOUS FLOW I NSTALLATIONS ...................................................... 7 2
Types of Design Problems ...................................................................................................... 7 2
Example Graphica l Design ...................................................................................................... 7 2
Downhole Tempera ture for Design Purposes...................................................................... 7 9
Actual Condi t ions Dif feren t From Design C ondi t ions...................................................... 8 1
DESI GNI NG GAS LI FT FOR OFFSHOR E I NSTALLATI ONS ........................................... 82
ADVANTAGES OF C ONTI NUOUS FLOW OVER I NTER MI TTENT
Safety F actors in Gas Lif t Design .......................................................................................... 7 7
FLOW GAS LI FT .................................................................................................................. 8 3
DUAL G AS LI FT I NSTALLATI ONS ....................................................................................... 8 3
C H A P T E R 7 - A N A L Y S I S A N D R E G U L A T I O N O F C O N T I N U O U S F L O W
G A S L I F T
I NTR ODUC TI ON .......................................................................................................................... 84
Recommended Prac t ices Pr ior to Unloading....................................................................... 84
Recommended Gas Lif t Insta l la tion Unloading Procedure............................................... 84Analyzing the Opera t ion of a Cont inuous Flow Wel l ........................................................ 85
GAS LI FT W ELLS ............................................................................................................... 85
Recording S urface Pressure in the Tubing and Casing ...................................................... 85
Measurement o f G as Volumes ................................................................................................ 8 5
Surface and Est imated S ubsur face Tempera ture Readings............................................... 8 6
Visual O bservation of the Surface Installation ................................................................... 86
Test ing Wel l fo r Oi l and Gas Product ion ............................................................................. 87
METHODS OF OB TAI NING SUR FAC E DATA FOR C ONTI NUOUS FLOW
METHODS OF OB TAI NI NG SUB SUR FAC E DATA FOR C ONTI NUOUS
FLOW GAS LI FT ANALYSIS ........................................................................................... 8 7
Subsur face Pressure Surveys .................................................................................................. 87
Subsur face Tempera ture Surveys in Casing Flow Wel ls ................................................... 88
Computer Calcu la ted Pressure Surveys................................................................................ 8 8
Tempera ture Surveys in Tubing Flow Wel ls ........................................................................ 8 8
Flowing Pressure and Tem pera ture Survey .......................................................................... 9 0
Flu id Level Determinat ion by Acoust ica l M ethods ............................................................ 91
Precaut ions when Running Flowing Pressure and Tempera ture Surveys ....................... 8 8
VARIOUS WELLHEA D INSTALLA TIONS FOR GAS INJECTION
C ONTR OL .............................................................................................................................. 91
W ELL I NJEC TION GAS PR ESSUR E FOR C ONTI NUOUS
F L O W S Y S T E M S ................................................................................................................. 92
GETTI NG THE MOST OI L W I TH THE AVAI LAB LE LI FT GAS.................................... 92
Manual Contro ls ........................................................................................................................ 9 2
Semi-Automat ic Contro ls ........................................................................................................ 9 3
Opt imiz ing Gas Lif t Systems ................................................................................................. 9 3
Autom atic Optim ization of Injection Gas U se .................................................................... 95
A P P E N D I X 7 A- X A M P L E S O F P R E S S U R E R E C O R D E R C H A R T S F R O M
C O N T I N U O U S F L O W W E L L S.............................................................. 96
C H A P T E R 8.N T E R M I T T E N T F L O W G A S L I F T
I NTR ODUC TI ON ........................................................................................................................ 10 2
OPER ATI NG SEQUENC E ........................................................................................................ 10 2
TYPES OF I NSTALLATI ONS ................................................................................................. 10 3
right American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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TABLE OF CONTENTS
(Continued)
F A C T O R S A F F E C T I N G P R O D U C I N G R A T E.............................................................. 1 0 3
M a x i m u m R a t e .................................................................................................................. 1 0 3
Fa l lb ack .............................................................................................................................. 1 0 4
Use o f P lu n g e r s i n I n t e r m i t te n t L i f t S y s t e m s ............................................................. 1 0 5
D E S I G N O F I N T E R M I T T E N T L I S T I N S T A L L A T I O N S........................................... 105F a l l b a c k M e t h o d ............................................................................................................... 105
Per cen t Lo ad Me th o d ....................................................................................................... 1 0 8
V a r i a t i o n s of Per cen t Lo ad Me th o d .............................................................................. 1 0 9
Pr o d u c t io n Pr e ssu r e Op e r a t ed Gas L i f t Va lv es .......................................................... 1 0 9
C H A M B E R S .......................................................................................................................... 1 0 9
Design of a Gas Lif t Chamber Insta l la t ion .................................................................. 110
C H A P T E R 9- R O C E D U R E S F O R A D J U S T I N G , R EG U L A T I N G A N D
A N A L Y Z I N G I N T E R M I T T EN T F L O W G A S
L I F T I N S T A L L A T I O N S
I N T R O D U C T I O N ................................................................................................................. 1 1 2
C O N T R O L O F T H E I N J E C T I O N G A S........................................................................... 1 1 2
T h e T i m e C y c l e C o n t r o l l e r............................................................................................ 1 1 2Lo ca t io n o f T ime C y c le C o n t r o l l e r ............................................................................... 1 1 3
C h o k e C o n t r o l o f t h e I n j ec tio n Gas .............................................................................. 1 1 3
U N L O A D I N G A N I N T E R M I T T E N T I N S T A L L A T I O N .............................................. 1 1 3
R e c o m m e n d e d P r a c t i c e s P r i o r to U n l o a d i n g .............................................................. 113
I n i t i a l U- Tu b in g ................................................................................................................ 1 1 4
Un lo ad in g Op er a t io n s Us in g A T ime C y c le Op e r a t ed C o n t r o l l e r ........................... 1 1 4
U n l o a d i n g w i t h C h o k e C o n t r o l of t h e I n j ec t io n Gas ................................................. 1 1 4
A D J U S T M E N T OF T I M E C Y C L E O P E R A T E D C O N T R O L L E R .............................. 1 1 5
P r o c e d u r e o r D e t e r m i n i n g C y c l e F r e q u e n c y ............................................................... 1 1 5
I N J E C T I O N G A S ......................................................................................................... 1 1 5
S E L E C T IO N O F C H O K E S I Z E F O R C H O K E C O N T R O LOF
V A R I A T IO N I N T I M E C Y C L E A N D C H O K E C O N T R O LOFI N J E C T I O N G A S ......................................................................................................... 1 1 6
A p p l i c a t i o n o f T i m e O p e n i n g a n d S e t P r e s s u r e C l o s i n g C o n t r o l l e r...................... 1 1 6
A p p l i c a ti o n o f T i m e C y c l e O p e r a t e d C o n t r o l l e r w i t h C h o k e n the
I n j ec t io n Gas L in e ........................................................................................................ 1 1 6
Ap p l i ca t io n of A C o mb in a t io n Pr e ssu r e R ed u c in g R eg u la to r an d
I M P O R T A N C E OF W E L L H E A D T U B I N G B A C K P R E S S U R E T O
C h o k e C o n t r o l 116
R E G U L A T I O N O F I N J E C T I O N G A S ..................................................................... 1 1 7
W el lh ead C o n f ig u r a t io n .................................................................................................. 1 1 7
S e p a r a t o r P r e s s u r e ............................................................................................................ 1 1 7
S u r f a c e C h o k e i n Flo wl in e ............................................................................................. 1 1 7
F l o w l i n e S i z e a n d C o n d i t i o n.......................................................................................... 1 1 7
R E G U L A T I O N OF I N J E C T I O N G A S ...................................................................... 1 1 7
I n s t a l l a t io n W i l l No t U n lo ad .......................................................................................... 1 1 7
V a l v e W i l l N o t C l o s e ...................................................................................................... 1 1 7
Emu ls io n s ........................................................................................................................... 1 1 8
C o r r o s io n ........................................................................................................................... 1 1 8
...............................................................................................................
S U G G E S T E D R E M E D I A L P R O C E D U R E S A S S O C I A T ED W I T H
T R O U B L E - S H O O T I N G ...................................................................................................... 1 1 8
A P P E N D I X 9 A.X A M P L E S OF I N T E R M I T T E N T G A S L I F T
M A L F U N C T I O N S ........................................................................... 1 2 0
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A P I T I T L E a V T - b 74 m O732270 0532833 846
TABLE OF CONTENTS
(Continued)
C H A P T E R 10.H E U S E O F P L U N G E R S I N G A S L I F T S Y S T E M
I N T R O D U C T I O N ................................................................................................................. 1 2 4
A P P L I C A T I O N S .................................................................................................................. 1 2 4
T Y P E S OF P L U N G E R L I F T .............................................................................................. 1 2 4
S E L E C T I N G T H E P R O P E R E Q U I P M E N T ..................................................................... 1 2 5R e t r i e va b l e Tub i ng (o r C o l l a r ) S t op ............................................................................. 1 2 5
S t a nd i ng Va l ve .................................................................................................................. 1 2 5
P l unge rs .............................................................................................................................. 1 2 6
W e l l T u b i n g ....................................................................................................................... 1 3 0
M a s t e r V a l v e ..................................................................................................................... 1 3 1
S e c o n d F l o w O u t l et .......................................................................................................... 1 3 1
P R O P E R I N S T A L L A T I O N P R O C E D U R E S ................................................................... 13 1
S U M M A R Y ........................................................................................................................... 131
G L O S S A R Y .......................................................................................................................... 1 3 2
S Y M B O L S ............................................................................................................................ 1 3 5
B u m p e r S p r i n g .................................................................................................................. 1 2 6
Lubr i c a t o r .......................................................................................................................... 131
R E F E R E N C E S ..................................................................................................................... 1 3 8
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1
CHAPTER 1INTRODUCTION TO ARTIFICIAL LIFT AND GAS IFT
BASIC PRINCIPLES OF OIL PRODUCTION
When oil is first found in the reservoir, it is under pres-
sure from the natural forces that surround and trap i t . I f a
hole (well) is dri l led into the reservoir , an opening is pro-
vided at a much lower pressure through hich the reservoir
f luids can escape. The driving force which causes hese
PRESSURE
f luids to move out of the reservoir and into the wellbore
come s from the com pression f the f luids that are storedn
the reservoir . The actual energy that causes a well to pro-
d u ce o i l r e su l t s f r o m a reduct ion i n pressure b e tween
the reservoir and the producing facil i t ies on the surface.
Fig. 1-1 i l lustrates this production process s it occurs in an
oil well. If the pressure s n the reservoir and the wellbore areallowed toqualize,i therecause of a decrease i n reservoir P R E S S U H F
pressure or an increase in w ellbore and surface pressure,
no f low from the reservoirwill take place and there will be
no product ion f rom the wel l .
* E L L H E A D10 PROCESSINGAN D TREATING
STILL L OW E RPRESSURE /
LOWEST
P R E S S U R E
Factors That Af fect Oi l Produ ct ionFig. 1-1- he production proc ess in an oil well
ARTIFICIAL L IFT
In many wells the natural energy associated with oil will
no t p roduce a suff icient pressure differential between the
reservo ir and the wel lbore to cause theell to f low into the
production facil i t ies at the surface. In other wells, naturalenergy will not dri ve oil to the surfacen suff icient volum e.
The reserv oir’s natural energy m ust then be supplemented
by so me form of ar t if icial l if t.
Types of Ar t i f ic ia l L i f t Systems
There are four basic ways of produc ing an oil well by
artificial lift. These are as L@ , Sucker Rod Pumping, Sub-
m er s ib le E lec t r i c Pum ping a n d Subs ur face H ydr au l i c
Pumping. The sur face and subsur face equipment required
for each system is shown in Fig . 1-2.
Choosin g an Ar t i f ic ial L i f t System
The choice ofan artificial ift system in a given well
depends upon a number of factors. Prima ry amon g them,
as fa r as gas lift is conce rned, is the availabilityf gas. If ga sis readily available, either s dissolved gas in the produced
oil , or from an outside source, hen gas if t s often an
ideal selection for artificial i f t . Exper ience has shown tha t
produced gas will support a gas l if t system f the daily ga s
rate from the reservoir is at least 10% of the total circulated gas
rate. No other system of artificial lift uses the natural energy
stored in the reservoir as completely as gas lift. If an instal-
lation is adequately designed, wells an be gas l if ted over
wid e r an g e o f p r o d u c in g co n d i t io n s b y r eg u la t ing h e
injection gas volume at the sur face .
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2 Gasif t
THE PROCESS OF GAS LIFT
Gas lif t is the form o f ar t if icial l if t that most clos ely
resembles the natural f low process. I t can be consideredn
extension of the natural flow process.n a natural f low well ,
as he fluid ravels upward oward he surface, he fluid
co lumn pressure i s reduced , gas comes ou t of solution,
an d the free gas expands . The free gas, being lighter than
the oil it displaces, reduces the density ofhe flowing fluid
and further reduces the weight of the fluid column above
the formation. This reduction in the fluid column weight
produces the pressure differential between the wellbore and
the reservoir that causes the well to f low. This is shown n
Fig. 1-3(A). When a well produces water along with he
oil and the amoun t of free gas i n the column is thereby
reduced, the same pressure differential between wellbore
and reservoir can be m aintained by supplementing the for-
mation gas with injection gas as shown in Fig. I-3 (B) .
Types of Gas Lift
There are two basic types of gas lift systems used in th e
oil ndustry. These are called continuous f low and nter-
mittent flow.
Continuous Flow Gas Lift
In the continuous flow gas l ift process, relatively high
pressure gas is injected downho le nto he f luid column.
This injected gas joins the formation gas to lift the fluid to
the surface by one or more of the following processes:
1. Reduction of the fluid density and the column weight
so that the pressure differential between reservoir and
wellbore will be increased (Fig. 1-4A).
HYDRAULIC PUMPPUNP
\-
I
PACKER
S T A N D I N G V A L V E
I O P T I O N A L I
“ C O N T R O LEQUIPMENT
- G A S L I F T V A L V E
GA S LIFT
(COURTESYDRESSER-GUIEERSONJ
Fig . 1-2- rtificial lift systems
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Introduct ionortif icialif tndasift 3
2. Expansion of the injection gas so thatt pushes liquid Intermittentlow Gas Lift
ahead of it which further reduces the column w eight,
thereby ncreasing hedifferentialbetween he eser- If a well has a low eservoirpressureoravery ow
voirndheellboreFig. 1-4B). producingate,taneroducedy a formfasif t
3 . Displacement of l iquid slugs by large bubbles of gascalled intermittent f low. As its name im plies, this system
produces ntermittently or irregularly and s designed o
produce a t he r a te a t wh ich f lu id en te r s he wel lborect ing as p is tons (Fig . 1-4C).
A typical small continuous flow gas lif t system is shown from the formation. n the intermittent f low system , fluid isin Fig. 1-5. allowed o accumulate and build up i n the ubing at he
F LUI
''d FROMFORMATIONOIL & GAS
r 4ID COLUMN WEIGHT REDUCED B Y
WELLFORMATION GAS IN A NATURAL FLOW
( A )
OIL & GAS' FROMORMATIONI
FLUID COLUMN WEIGHT REDUCED B Y
A GAS LIFT WELLFORMATION AND INJ ECTED GAS:
(B )
Fig. 1-3- eduction in fluid column weight by formation and injected gas
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A P I T I T L E a V T - b 9 4 m 0732290 0532837 491 W
4 G asif t
bottom of he well . Periodically, a arge bubble of high the rifle slug. The frequency of gas injection i n intermit-
pressure gas is injected into the tubing very quickly under- tent lift is determinedby the a mount of t ime required for a
neath the colum n of l iquid and the l iquid column is pushed liquid slug to enter the tubing. The length of the gas in-
rapidly up the tubing to the surface. T his action is sim ilaro jection period will depend upon the t ime required to push
fir ing a bullet from a rif le by the expansion of gas behind one slug of l iquid to the surface.
ADVANTAGES AND LIMITATIONS OF GAS LIFT
Choice of Gas Li f t System Th edvantages of gasif taneummarized as fo l lows:
Because of i ts cyclic nature, intermittent f low gas l if t is
suited only o wells hat produce at relatively ow rates.
Continuou s f low g as l if t will usu ally be m ore eff icient nd
less expensive for wells that produce at higher rates where
cont inuous f low can be main ta ined wi thout excessive usef
injection gas.
Gas if t s suitable for almost every ype ofwell that
requires artificial lift. It can be used to artificially lift oilwel ls o dep le t ion , regard less o f he u l t imate producing
rate; to kick off wells that will f low naturally; to back f low
water in jec t ion wel ls ; and to un load w ater f rom gas wel ls .
1. Init ial cost of downh ole gas if t equipme nt s usu-
ally low.
2. Flexibility cannot be equaled by any other form of lift.
Installations can be designed for lifting initially from
near the surface and for l if t ing from nea r total depth
at depletion. Gas l if t installations can be designed to
l i f t f rom one to many thousands of barrels per day.
3. The producin g rate can be controlled at the surface.
4 . Sand i n theproducedfluiddoesnotaffectgas if t
equipment in most nstallations.
- IQUID
- A S
Reduct ion of Expansion of Gas
Flu id Densi ty
(C)Displacement of Liquid
Slugs by Gas Bubb les
Fig. 1-4- hree effects of ga s in a gas l i f t well
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Introduction to Artificial Lift and Gas Lift 5
5 . G as lift is not adversely affected by deviation of the
wellbore.
6. The relat ively few moving par ts in a gas lif t system
give t a ong service ife when compared o other
forms of artificial lift.
7 . Operat ing cos ts are usual ly relat ively low for gas l i f t
sys tems.
8 . Gas l if t is ideally suited to supplement formation gas
for the purpo se f artif icially lif ting we llswhere mod-
erate amountsof gas are presentn the produced fluid.
9. Th e major item of equipment (the gas compressor) in
a gas lif t system is installed on the surface where it
can be eas i ly inspected, repairednd maintained. This
equipm ent can be driven by either gas or electricity.
GLYCOL
On the other hand, gas if t also has certain imitations
which can be summarized as follows:
l . G as must be available. In some instances air , exhaust
gases, and nitrogen have been used but these are gen-
erally more expensive and more difficulto work with
than locally produced natural gas, .
2. Wide well spacing may limit he use of a centrallylocated source of high pressure gas. This limitation
has been circumvented on some wells through the se
of gas-cap gasas a lif ting sourceand the return of the
ga s to the cap through injection wells .
3. Corros ive gas l i f t gas can increase the cos t of gas l i f t
operations if i t is necessary o reat or dry the gas
before use.
DEHYDRATORSURPLUS GAS
T O S A L E S
S T A T I O N
GAS/OI L
SEPAR ATO R
M A N I F O L D
I N J E C T I O N G A S M A N I F O L D
( M E T E R I N G & C O N T R O L )
Ø I
F i g . 1-5-
typical gas l i f t system
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4. Installation of a gas if t system ncluding compres-
sors usually requires a longer lead t ime and greater
preparation than does single well pumping systems.
In addition, the initial surface installation for gas lift
wi l l somet imes be more expensive han equivalen t
pumping installations. However, the reduced operat-
ing cost of the g as lift system will usually far out w eigh
any additional cost of the initial installation. Also, ifthe associated gas will be gathered and compress ed,
as is usually the case, provisions for circulating some
of the compre ssed gas for gas l if t will not, in most
cases, signif icantly ncrease he nit ial cost .
5. In very low pressured reservoirs, continuous flow gas
lift cannot achieve as great a pressure drawdown as
can some pum ping systems. How ever,when low flow-
ing bottomhole pressure is desired, the use of inter-
mittent l if t and chamber if t forms of gas ift can usu-
a l ly ach ieve pressure draw downs comparab le o
pumping systems.
6. Conversion of old wells to gas lift can require a higher
level of casing integrity than would b e required for
pumping systems.
HISTORICAL REVIEW OF GAS LIFT DEVELOPMENT
Earlyxperiments 3 . 1900-1920: Gulf Coast Area “airorire” boom. Such
famous fields as Spindle Top were produced by air
l if t .ar l Emanual Loscher (German mining engineer) applied
co mp r essed a i r a s a mean s o f l if t i n g iq u id in l ab o r a -
tory experiments in 1797. The f irst practical application of 4. 1920-192 9: Application of straight gas if t with wide
air iftw as i n 1846 when n AmericannamedCockfordpublicity rom heSeminoleField in Oklaho ma Seeliftedilo meig .-7).
The f irstU.S. patent for gas lift calledn “oil ejector”was
issued to A . B r ea r in 1865 (Fig . 1 -6) .
FLOW LINE
-b.rl
WFig. 1-6- rear Oil Ejec tor
( M a y 23, 1865)
Chronological Development
The fo l lowing chronologica l developmentf gas liftwas
given by B rown, Canalizo and Robertson in a paper pub-
lished in 1961. (Manyof the sketches shown n this chapter
are taken from this paper.)
1. Pr ior o1 8 6 4 :So me ab o r a tor yexper imentsper -
formed wi th possib ly one or wo prac t ica l app l i -
cations.
2. 1864-1900:Thise raconsis tedof if t ing by com-
pressed air njected hrough he annulus o r tubing.
Severa l f looded mine shaf ts were un loaded . Numer-
ous patents w ere issued for foot-pieces, etc.
SUBMERGENCE
Fig. 1-7- arly gas l i f t nomenclature
5. 1929-1945: This era included the patenting of about
25,000 different flow valves. More eff icient rates ofproduction as well as proration caused the develop-
ment of the flow valve.
6. 1945 to present: Since the end of World War II , the
pressure-operated valve has practically replaced all
other types of gas lift valves. Also in this era, many
additional companies have been formed with mostof
them marketing some version of a pressure-o perated
valve.
7.1957: ntroduction of wireline etr ievablegas if t
valves.
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A P I T I T L E * V T -6 9 4 m 0 7 3 2 2 9 0 0 5 3 2 8 4 0 T 8 b m
Introductionortificialif tndasif t 7
TechnicalDevelopment of Gas LiftEquipment 3 . Kick-off valve s Fig. 1-10 andFig. 1-1 1) were next
1.
The technic al deve lopm ent of gas lif t equipment can beemployed to providea means for closing off gas af ter
a lower valvewas uncovered. The earlykick-off valves
were designed to operate ona 10-20 psi pressure dif-rouped in to s tages which are descr ibed as fol lows:
Straight gas inje ction which employed no valves and ferential until the develo pmen t of the spring-loaded
consisted primarily of U-tubing he gas around he differential valvewhich operated at about100psi dif-
bottom of the tubing. Several types of early gas and ferential. The kick-off valve was a crude forerunner
air lif t hookups are shown in Fig. 1-8. of the modern gas lif t f low valve.
2
Fig. 1-8- arly gas (air) l i f t without valves
Jet collars (Fig. 1-9) were placed up the string to al-
low gas to enter h igher p and thereby reduce the ex-
cessive kick-off pressures required for kicking around
the bot tom.
\%ON TURN TUBING TO CLOSE
,-TU BI NG TUBING
G A S"
AS
TUBING
Fig. 1-10- aylor kick-off valve
I-LOW LINE
a+
-- ""-=":="""
FLAPPER TYPE \SPRING
Fig . 1-9- et collar Fig. 1-11-
ick-off valves
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8 Gas Lift
DEVELOPMENT OF THE MODERN GASLIFT VALVE
Differential Valves
Until 1940, theclosest hing to hepresentday gas
l i f t flow valve was the differential valve (Fig. 1-12) which
was operated by the difference in pressure between the in-
jection gas in the casing and th e fluid in the tubing. The
differential valve opened when there was an increase in
fluid pressure relative to injection gas pressure and closed
when the gas pressure increased relative to the fluid. This
principle of operation meant that the differential valves
had to be spaced close together in order to assure proper
operation of the installation. Little or no surface control
was possible in a differential valve installation.
SEC. A-A ?--l-"
v(A ) Mechanically controlled valves
- LOW LINE
CASING +GA S IN
TUBING4DISK TYPEVELOCITY
(C) Velocity controlled valves
(B ) Bryan differential valve
FLOW LINE
(D) Spring loaded differential valves
Fig. 1-12- arly types o f f zow valves
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Introductionortificialif tndasif t
One type of differential valve, which was very popular
around 1940, is shown in Fig. 1-1 3 . This valve was origi-
nallycalled he Specif ic Gravity Differential Vulve. T h e
specif ic gravity differential valve employed the difference
in specif ic gravity between a 16 foot column of kerosene
and a 16 foo t co lumnof well f luid for operating pressure. I t
was very successful in continuo us flowwells and may still be
o p e r a t i n gs u c c e s s f u l l y ns o m ew e l l s .H o w e v e r , h evalve’s length and excessive diameter l imited i ts transport-
abil i ty and application.
OPERATING VALVE VALVES ABOVEPERATING VALVE
Fig. 1-13- pecif ic gravity type dif ferential valve
Bellows Charged Valves
In 1940 , W. R. King introduced his bellows charged gas
lif t valve. A drawing taken from King’s patent issued on
January 18 , 1944 is shown in Fig .- 14. King’s valve, which
is very s imi lar o most p resen t day unbalanced , s ing le-
element, bellows charged gas l if t valves, allowed for the f irst
t ime the gas l if t ing of low pressure wellswith a controlled
change in the surface injection gas pressure. Since King’s
valve was opened by an increase in injection gas pressure
Gas Charged
Pressure
Chamber
Bel lows
Stem 8 Seat
4Fig. 1-14- ing va lve (Firs t pressured be l lows va lve)
and closed by a decrease in press ure, the valve could be
operated from the surface by chan ges in the injection gas
pressure . This meant ha t t was no onger necessary o
operate a valve from the surface y rotating or moving the
t u b i n go rw i r e l i n ec o n n e c t e d o h e u r f a c e .T h e
principal of operation of the bellows valve was also far
superior to the differential valve for most applications in
tha t he be l lows valve was c losed by a decrease n gas
pressure, whereas the differential type valve opened with
d ec r ease in g as p r e ssu r e . Th i s mean t h a t f ewer o f h e
bellows type gas pressure operated valves were required for
each installation, since the valve relied on the relatively high
injection gas pressure for operation, thereby allowing the
spacing between valves to be much greater than the differ-
ential pressure operated valves.
King had good insight into valve construction when he
designed h is va lve . He recognized the need for com ple te
bellows protection, ncluding an anti chatter mechanism.
The bel lows in the King valve i s p ro tec ted f rom excessive
well pressure by sealing the b ellows chamb er from theel l
f luids af ter full stem ravel. Chatter s prevented by the
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A P I T ITLE*VT-b 74 m 0732290 0532843 7 7 5 m
10 Gasift
small orifice. The baffle design also supports the bellows.
POSITIVE STOP
FO R STEM
BELLOWS SECTION
GA S INLETS
STEM 8SEAT
INSERT
REVERSECHECK
Similar construction is used by several manufacturers in
their present gas lift valves.
The success of the King valve is evidenced by the fact
that the basic principles used in th e design were quickly
adopted by almost all valve manufacturers and are stil l
used with little modification in today’s gas lift valves. Fig.
1-15 is an illustration of a typical modern bellows charged
gas lift valve. Note the similarity between this valve and
the Kingvalveshown i n Fig. 1-14. Gas ift valves and
mandrelsarediscussed in detail i n Chapter 5 of this
manual.
Fig. 1-15- ypical modern bellows harged gas lift valve
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A P I T I T L E t V T - 6 94 m 0732290 0532844 621 m
Well Performance 11
CHAWELL PEF
'TER 2IFORMANCE
INTRODUCTION
Well per formance s con tro l led by a arge number of
factors that are often interrelated. Most students of f luid
f low now d iv ide wel l per formance in to two basic ca tegor ies
which they call Inflow and Outflow performance. A s illus-
trated in Fig. -1, all f low in the reservoir u p to the w ellbore
is designated as inflow performance and all f low up he
tubing and into the production facil i t ies is designated out-
f low performance.
A well's inflow performance is controlledby the charac-
ter ist ics of the re servoir s uch as reservoir pressure, produc-
tivity and f luid composition.A well's outflow performance
is a direct function of the size and typef producing equip-
ment. Both nflow and outf low performance can be pre-
dicted quite accurately, and wells can be designed based on
these predictions. In any given w ell , outf low performance
and nflow performance must be equal. That s, we can
produce no more f luid from the reservoir than we can l if to
t h e s u r f a c e a n d vi c e v e r s a . B e c a u s e o f h i s f a c t , t s
extreme ly mporta nt hat a well's inflow performa nce be
carefully considered when sizing production equipment.
U'"1
4N F L O W P E R F O R M A N C E"
"" I I II I
Fig. 2-1 - nflow and Outflow Performance in a flowing well
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12 Gas Lift
INFLOW PERFORMANCE PREDICTION
A well's inflow performance is usually expressed in terms
of productivity which simply indicates the number of bar-
rels of oil or liquid that a well is capable of producing at a
given reservoir pressure. One way of expressing well pro-
ductivity is with the Productivity Index (P.I.=J) technique.
This involves measuring a well's producing rate, and flow-ing bottomhole pressure at that rate, then using this infor-
mation to calculate a P.1 for the well.
Inflow Performance Relationship (IPR) Technique
The P.I. method assumes that all future production rate
changes will be i n the same proportion o he pressure
drawdown as was the test case. This may not always be true,
especially in a solution-gas drive reservoir producing below
the bubble point pressure. The bubble point pressure is the
condition of temperature and pressure where free gas first
comes out of solution in the oil. When the pressure in the
formation drops below th e bubble point pressure, gas is
released in the reservoir and the resulting two-phase flow
of gas and oil around the wellbore can cause a reduction in
the well's productivity. J. V. Vogel developed an empirical
Productivityndex (P.I.=J)echnique techniqueorredicting well productivity'snderuch
reduced conditions and he called his method of analysis
Inflow Performance Relationship (IPR) after the terminol-
ogy used in an earlier paper written by W. E. Gilbert.'
One definition of Productivity Index and the one that is
used in artificial lift, defines P.I. as th e number of barrels
of liquid produced per day (BLPD) for each pound per
square inch (psi) of reservoir pressure drawdown. Draw-down is defined as the difference in the stabilized static
bottomhole pressure (SSBHP) and the flowing bottomhole
pressure (FBHP). This can be written as an equation using
current engineering symbols as follows:
Vogel2 calculated IPR curves for wells producing from
several fictitious solution gas drive reservoirs. From these
curves he was able to develop a reference IPR curve which
not only could be used for most solution gas drive reser-
voirs in arriving at oil well productivity, but would give
91 much moreccuraterojectionshanould be obtainedJ =
pws P,,Equation 2 .1 using the P.I. method. His work was based entirely upon
results obtained from wells producing in solution gas drive
reservoirs. However, good experience has been obtained
using the Vogel IP R in all two-phase flow conditions.
where: = Productivityndex, BLPD/psi
ql = Liquid Production Rate, BLPD
P,, = Static bottomhole pressure, psig
Pwf= Flowing bottomhole pressure, psig
The calculation of a well's P.I. is given in the following VogelPRurve
example.The Vogel IPR dimensionless curve (see Fig. 2-2) is based
Given: A well hat produces 100BLPD andhasan SSBHP on he following equation:
of 1000 psig and a FBHP of 900 psig.
Find: P.I.f the well (qohax = 1.0 - 0.2(2) -.8(+) quation 2.2
Solution:
90
ql 100 BLPDJ =
P w s - Pwf 1000 psig - 900 psig Note that the initial bubble point pressure (PB) has been
J = 1 BLPD/psi Equation 2.1 substituted for the staticottomholeressurePws) in the
-
The P.I. technique allows us to determine the well produc-
tion if the pressure is drawn down further. Using the same
example, if we draw the FBHP down to 500 psig from the
lowing rate:
above equation to emphasize that the Vogel IPR curve only
applies when Pwf=PS The change i n production with a
change in the flowing bottomhole pressure above the initial
bubble point reservoir pressure is defined by the productiv-
second requirement to assure validity of the Vogel IPR
Of 'Ooo Psig the produce at the ity indexquation, which is a straight ]ine IPR curve . The
q1J = Equation 2. relationship is that the flow efficiency (FE) must be equal to
P,, - Pf unity (FE =1 O) where flow efficiency is defined as the ratio
or rearranging the equation:of the actual to the ideal productivity index. Ideal implies
no skin effect; that is, the absolute permeability and poros-
91 = (J) X (Pws - Pwf) = 1 X 500 ity of the formation remain in the same and unaltered fromRate (ql) =500 BLPD at FBHP (Pw,) f 500 psig the drainage radius to the wellbore radius.
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API T I T L E * V T - b 74 m 0732270 053284b 4T 4
Well Performance 13
P R O D U C I N G RATE AS A FRACTION OF MAXIHUH P R O D U C I N G RATE
WITH 100% DRAWDOWN, q(q) M X .
Fig. 2-2 - ogel’s curve fo r inflow performance relation-
ship (fro m Vogel’s papel; S P E 1476)
Since this discussion is an introduction to the application
of the widely-used Vogel IPR curve and not a detailed
presentation on the concepts of well damage and inflow
performance, the example calculations will be based on the
assumptions that P,, =PB and FE 1.0. Also, the IPR curve
will not berestricted to all oil production if free gas is present
withheiquid hase thelowing ottomhole
pressures in the wellbore. If a well produces free gas, and asignificant flowing bottomhole drawdown below the initial
bubble point pressure is required for the desired daily pro-
duction rate, more accurate production predictions can be
expected using the Vogel IPR curve than using a straight
line productivity index relationship for water-cut wells. The
incremental increase in production for the same incremental
increase n lowingbottomholepressuredrawdown
becomes less at the lower flowing bottomhole pressure.
Gage pressures will be used in these calculations. A work-
sheet for performing IPR calculations is given in Fig. 2-3.
Vogel’s Examp le Problem
The following data for illustrating IPR calculations were
used in Vogel’s paper:
Given: I . Averagereservoirpressure, P,, =2000psig
( p w s =PB)
2. Daily production rate =q o =65 BOPD
3 . Flowing bottomhole pressure, Pwf= 1500 psig
Find: l . Maximum production rate for 100percent draw-
down (Pwf=O psig)
2. Daily production rate for a flowing bottomhole
pressure equal to 500 psig
(See Figures 2-4 and 2-5 for a graphical presenta-tion of the Solution.)
Solution:
1. The maximum production rate, (90) max, is calculated
using the given test q o and corresponding P,r.
Pressure Ratio = - - 0.75wr - 1500
P,, 2000
From the Vogel IPR curve: Rate Ratio, q o~ =0.40(90) m ax
The maximum daily production rate represents the maxi-
mum deliverability of the well if the bottomhole pressure
could be decreased to atmospheric pressure (O psig) by turn-
ing the well upside down and producing through a friction-
less conduit.
2. Pressure Ratio =pwf = 500 = 0.25P,, 2000
From the Vogel IPR curve: Rate Ratio, q o- 0.90
(90) max
q o = 162.5 (0.90) = 146 BOPD
When the valve for (90) ma x is determined, the value of q.
for all values of Pwr can be calculated. Also, the value of P,f
can be calculated for any value of q. less than ( qo ) max . As an
example,helowingottomholeressureor a
production rate of 114 BOPD for the above well can be
calculated as follows:
Rate Ratio = 9 0 114
(90) ma x 162.5
-- 0.70
From the Vogel IPR curve: Pressure Ratio, =0.50P,,
Pwr=0.5 (2000) = 1000 psig
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WORK SHEET FOR
NONDIMENSIONAL INFL OW PERFORMANCE CURVE
WELL NO.
FROM BHP SURVEY
GIVEN: (1 P, = P S k I
(3) TEST RATE = ~ BFPD
1 .o0
. . . : : -
j
. . . i :
! .. . ] . . .
I : .
, . . .
0.80
x = ( 5 ) = f rom th is curve
0.60
II
>
0.40
". I :
!
I,: i . .
0.20
' I
'!::
1I
j. ,
OO 0.20 0.40 0.60 0 . 8 0 1 .o0
I
Plot BHP(7) versus B FPD(8) for IPR Curve between BHP = O & BHP = P,, & BFPD = O & BFPD I Max. Rate (6 )
Fig. 2-3- orksheet or performing P R calculat ions
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A P I T I TLEW VT -6 9 4 m 0 7 3 2 2 9 00 5 3 2 8 4 8 2 7 7 m
Well Performance 15
IP R2,000
arm
2O
F R A C T I O N O F M A X I M U M P R O D U C I N G R A T E
F R A C T I O N O F M A X I M U M P R O D U C I N G R A T E
F R A C T I O N O F M A X I M U M P R O D U C I N G R A T E
FRACTION O F M A X I M U M PRODUCING RATE
Fig.2 -4-
xample problem olution
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FRACTI O N O F M A X I M U MPRO DUCI NGR A T E R A C T I O N OF M AXI M UMPRO DUCI NGR A T E
SINCE TEST RATE AT500PSlGW A S 65BOPD
X = 16 2BOPD = (qo) MAX (G)
IPR
FRACTI O N OF M AXI M UM PRO DUCI NG RATE
@”
.9 =_ _ _ -.4 @162 BOPD
A 65 BOPD x 0.9
A =146 BOPD = q o
-146 BOPD = q O
F i g . 2 -5- on t inuat ion of e x a m p l e p r o b l e m
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A P I T I T L E * V T - b 74 m 0732270 0532850 925 m
Well Performance 17
WELL OUTFLOW PERFORMANCEPREDICTION
Well outflow performance depends upon many complex
factors which are often as difficult to simulate as those for
inflow performance. Such varied parameters as fluid charac-
teristics, well configuration, conduit size, wellhead back pres-
sure, fluid velocity, and pipe roughness all contribute signifi-
cantly to outflow performance.Efforts to predict well outflow performance have been go-
ing on for many years and these efforts have culminated in
much research and development work being done in the area
of multiphase flow correlations. The flow correlations that
have developed from this work attempt to predict the pres-
sure at depth in a flowing vertical column of multiphase fluid
(oil-gas,il-water-gas,rwater-gas)akingnto
account all of the fluid characteristics along with the conduit
configuration and other factors affecting the flow. Since the
producing characteristics of continuous flow gas lift wells
are essentially the same as those for a naturally flowing well,
the flow correlations that have been developed work equallywell in either system. The development and useof multiphase
flow correlations for outflow performance predictions are dis-
cussed in Chapter 3 .
Example Problem
All of the correlations for predicting multiphase flow
require extensive calculations and from a practical standpoint
can only be done with a computer. Fortunately these com-
puter calculations have been plotted into generalized pres-
sure gradient curves that are immediately available to the
operator and engineer. An example of one such gradient curve
is shown in Fig. 2-6A. Using a suite of these gradient curvescalculated for several different well rates, he flowing
bottomhole pressure Pwfcan be read at a given depth for a
specific rate and gas to liquid ratio (Rg]). Separate curves
must be used or each well rate, water cut and Rgl.Fortunately,
many of the variables in two phase flow cause only a small
change and can be generalized. The following example dem-
onstrates the use of these curves to predict outflow perfor-
mance and well performance. Well data for the example
problem follows:
Casing
Tubing
Static BHP (Today)
Flowing Wellhead Back
Injection Gas Pressure
Water Cuts (Assumed)
Pressure Gradient Curves
Pressure
Tubing Setting Depth
Formation Gas Oil Ratio
Productivity Index
Formation Depth
7-inch O.D.
(outside diameter)
2’/~ nch O.D.
1970 psig @ 5800 ft .
230 psig
1500psig @ Surf.
EPR Correlation
(Orkiszewski)
0-25-50-75%
Near 5800 ft.
800 CFA3
5.0 BFPD/psi Drawdown
(Straight Line)5800 ft.
The well under consideration is a high productivity well.
To begin the analysis it is assumed that for this well, and the
given reservoir conditions, maximum flow rates can probably
best be obtained under annular flow conditions. This
may not be true, and the maximum rates for 2’/8 inch tubing
will be checked later.
The first step is toobtain or calculate a suite of vertical
two-phase flowing pressure gradient curves for the con-
duit izes to beexaminedbasedonproducing
conditions to be expected. Computer programs avail-
able from several sources make the calculation and plot-
tingofsuchcurvesboth astand nexpensive.
Generalized curves, available in many textbooks, can
be used if they closely match the actual producing
conditions. The gradient curves used in this example
are not typical, generalized well gradient curves, but
were calculated for these specific conditions.
The suite of gradient curves should cover all ranges of
flow rates that are possible for the particular conduit
being considered. Six to ten rates should be sufficient,
but the actual number will depend on the width of the
producing range being considered. The rates should be
fairly equally divided over the entire range to give some-
what equal distribution of points along the entire length
of the curve.
A page of gradient curves calculated for this particular
welland epresenting he 3000 BOPD ate s
shown in Fig. 2-6A. In this case a line has been drawn
representing the producing formation depth at 5800 ft.The intersection of the depth line with the Rgl line for
natural lowconditions (800 R,, for100%oil)
has been noted with an arrow. The pressure at this
point has been read as 930 psig. Fig. 2-6B shows the
gradient curves for the 4000 B/D fluid rate at 100% oil;
and a similar reading, in this case 940 psig, has been
noted on it. Gradient curve readings are con-tinued in
thisashionntilufficientointsre
obtained to represent a full range of producing rates.
The pressure readings are now abulated in the
manner shown in Table 2-1. Note that the pressures
shown in Table 2-1 are for both 100% oil and various
water cuts. A separate suite of gradient curves is
required for each water cut.
The points shown in Table 2-1 are now plotted on
Cartesian Coordinate paper with flowing pressure at
the formation depth being scaled along the vertical
(Y ) axis and the producing rate plotted along he
horizontal (X ) axis. Fig. 2-7 is a plot of these values
and the resulting curves represent the minimum flow-
ing pressure at he formation depth hat will be
required to overcome gravity, friction, surface pres-
sureandothereffects,andproduceat heratesindicated.
~
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18 Gasift
I
TYPICAL GRADIENT CURVES
FOR 3000 B/D RATE
(COURTESY EXXON PRODUCTION
RESEARCH CO.)
1 I4 1 I
TYPICAL GRADIENT CURVES
FOR 4000 BID RATE
(COURTESY EXXON PRODUCTION
RESEARCH CO.)
Fig. 2-6- radient curves
TABLE 2-1
TABULATION OF POINTS FROM GRADIENT CURVE FOR NATURAL FLOW7" x 27/8" Annulus- atural Flow- glas Indicated
FBHP @ 5800 ft , psig
100%Oil 25% Wtr 50% Wtr 75% Wtr
Rate, BP D (R,I=800) (Rgl =600) (Rgl=400) (R,[ =200)
2,000 990 1260 1655240
2,500
3,000
3,500
4,000
4,500
5,000
6,000
8,000
10,000
12,500
940
930
935
940
960
970
1O00
1080
1180
1320
1180
1130
1110
1120
1120
1135
1160
1240
1320
1440
1535
1465
1420
1390
1375
1370
1370
1440
1500
1600
2190
2140
2100
2060
2020
2000
1960
1980
2000
2080
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A P I TITLExVT-6 94 m 0732290 OS32852 7T 8 m
Well Performance 19
4. On the same sheet of graph paper, plot the well pro-
ductivity line based on either the straight line produc-
tivity index or the IPR technique by beginning at a
point representing he static bottomhole pressure
(SBHP) on the vertical axis. This example uses the
straight line P.I. method. An example using the IPR
curves is given in Fig. 2-13. In this case, the point is
1970 psig at 5800 ft. Continue the plot of the produc-t iv i ty line by reducing the flowing bottomhole pres-
sure by the amount of drawdown calculated for var-
ious rates. For example, at a rate of 5000 B/D and
with a P.I. of 5.0 BFPD psi, the drawdown from the
static pressure of 1970 psig is 1000 psig. Therefore, the
point to be plotted for the extension of the productiv-
it y line is 1970 psig less 1000 psig or 970 psig and is
plotted opposite the 5000 BFPD rate.
5. The points of intersection of the drawdown line with
the flowing pressure curves represent the maximum
producing rate by natural flow which is possible under
the given reservoir and well conditions if flow is up the
2l/8” x 7 “ annulus. In this example, shown i n Fig. 2-7,
the maximum rate indicated is 5000 B/D at zero water
cut and 4250 B/D at a 25% water cut. Note that the
drawdown line does not intersect the 50 % and 75%
waters curves. This indicates that the natural flow is
impossible regardless of rate where the water cut is
50% or more. Natural Flow then would cease on this
2SO (
200(
tO
Oaov)
@0 -Im $ 1501
g=59Y
1001
50(
I I l l I I
7” x 2-7 /8” ANNULUS
,SBHP1970 PSIG
\-Pl = 5.0 BFPD/PSI
I I l I I I2000 4000 6000 8000 10,000 12,00014,
PRODUCING RATE (BFPDI
well when it reaches a water cut somewhere between Fig. 2 -7 - lowing BHP V S . Producing rate for natural
25% and 50%. f low conditions, various w ater cuts
PREDICTING THE EFFECTOF GAS LIFT
The effectof injecting additional gas into a fluidcolumn
from an outside source for gas lift purposes can be deter-
mined in the following manner.
1. Using the same gradient curves and the same method
as for natural flow, determine the flowing pressure at
the formation depth for he otal gas iquid ratio
(formation gas + injected gas). If there is no limit on
the amount of gas that can be injected, the Rgl which
produces the minimum gradient l ine at each produc-
ing rate can be used. In the example problem, that s a
R,, of 3000 at the 3000 B/D rate. Since this min-
imum gradient will represent differentR,~values atif-
ferent rates, the calculation of injection gas require-
ment will depend o n the minimum gradient for the
rate being considered. Table 2-2 hows a tabulation of
the minimum downhole pressure readings at the var-
ious rates.
2. Plot the pressures versus rates tabulated in Table 2-2
on Cartesian Coordinate paper in the same manner as
i n the example for naturallow. Fig. 2-8 shows a curve
plotted for the maximum gas injection rate alongside
the curve plotted for natural flow (800 Rgl) for he
100% oil case.A dotted line is also shown on Fig. 2-8
to ndicate he 1200 Rgl curve which represents a
plot of the flowing pressure for a case where injected
gas is limited to 400 cubic feet per barrel (CF/B)(1200
- 800).
3. The maximum producing rates which are possible
under various conditions are indicated y the intersec-tion of the productivity line with the flowing pressure
versus rate curves. In this case th e maximum rate for
unlimited gas lift is 5600 B/D, and for limited gas lift
(400 CF/B injected gas) is 5450 B/D. These compare
to a maximum natural flow rate under the same con-
ditions of 5000 B/D. A comparison of maximum
producing rates possible under both gas lift and natu-
ral flow conditions is shown in Table 2-3.
4 . Using the above example, it is now possible to evalu-
ate the benefits accruing to gas lift under the given
conditions. Also, it is possible to determine the opti-
mum gas injection rate by comparing the oil produced
right American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I TITLE*VT-6 94 m 0732290 0532853 634
20 Gas Lift
TABLE 2-2
TABULATION OF POINTS READ ON GRADIENT CURVES FOR GAS LIFT7" x 27/8"Annulus- aximum Gas L ift - ,, Values
FBHP @ 5800 ft , psig
Rate, B/D 100%il 25% Wtr 50 % Wtr5%tr
2,000 690 740 8O0 1400
2,500 680 740 8O0 14403,000 680 750 815 1470
3,500 700 760 840 1520
4,000 720 790 910 1540
4,500 750 860 940 1570
5,000 810 890 960 1600
6,000 870 950 1040 1660
8,000 1030 1120 1220 1760
10,000 1180 1280 1360 1860
12.500 1350 1420 1530 1950
2500-7" x 2-7/8 ANNULUS
2000k
LGOOaov)
@ \NOTE: THIS REPRESENTS MAXIMUAAND NOT OPTIMUM GAS LIFTCONDITIONS
O =
I3SY
1000 5450 B/D
15 '; " ,GAS :EO = ,
' O 0 2000 4000 6000 0000 10,0002,00011
3 9 2 0 M U / @
P.1 =5.0 BFPD/PSI
PRODUCINGRATE BFPD)
O
Fig. 2-8- omparison of naturalf low with gas l i f t , 00%
oil , no injection g as l imit
2500$
l7" X 2 - 7 /8 ANNULUS
c
\ NOTE:HISEPRESENTS
\ OPTIMUM CONDITIONSMA XIMUM AND NOT
o -
z $ 1500-
o =E3SY
1000-
GASREO = 4770 MCF/
\ P I = 5.0 BFPD/PSI
' O 0 - 2d00 4dOO 6d00 8dOO 0,bOO2,bOOl
PRODUCINGRATE BFPD)
100
Fig. 2-9- omparison of natu ral f low wi th gas l i ft , 25 %water, no injection gas limit
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A P I T I T L E t V T - b 7Y m 0732290 0532854 570 m
Well Performance1
(5450 B/D)under the limited gas injection rate of 2180
MCF/Day to the oi l produced (5600 B/D) at a maxi-
mum gas injection rate of 4770 MCF/D.
Plots of curves comparing gas lift and natural flow at
25%, 50 % and 75% water cuts and with no injection
gas limit are shown in Fig. 2-9, 2-10 and 2-11.
TABLE 2-3
COMPARISON OF MAXIMUMPRODUCING RATES
FOR NATURAL FLOW AND
GAS LIFT
Max. Rate Max. Rate Inj. Gas
Nat. Flow Gas Lift Required
Water % @/D) @/D) (MCF/D)
O 5000 5600 3920
25 4300 5300 4770
5 0 -0- 5000 5500
75 -0- 2600 3380
2500r"--- 7- x 2-718 A N N U L U S
NOTE: THIS
OPTIMUM GA5 LIFTMAXIMUM AND NOT
(o CONDITIONSO
O
v)
@J
m v) 1500
f3LL \ MA X RATE
1°00-
-YMAXRATE
-5000 B/D
MAX GAS REQ =5 5 0 0 M C F
PI = 5.0 BFPD/PSI
500 2000 4000 6000 Bob0 l0,dOO12,~0014,000
PRODUCING RATE (BFPD)
Fig. 2-10- omparison of natur alf low with gas l i f t,50%
water, no injection gas limit
cY
OO(o
v)
GAS LIFT(MAX RATE)
@J
n -:150/ 7AX RATE
2600 B/D
z MA X GAS REO = 3380 M U D
3Y
loo0 t \NOTE:
THISREPRESENTS
\
MAXIMUM \AND NOT OPTIMUM Pl = 5.0 BFPD/PSICONDITIONS
500' 20b0 4000 d o 0 W O O 10,dOO12,bOOl
~
100
PRODUCING RATE BFPD)
Fig. 2-11- omparison of natu ralf low with gas l if t, 75%water, no injection g a s limit
Comparison of Conduit Size
The effect of conduit size on maximum producing rate
can be seen by comparing bottomhole flowing pressure
versus rate curves prepared for he various pipe sizesunder
consideration. In the example problem, flow through 2' /~
inch tubing was considered as an alternative to annular
flow. Fig. 2-12 shows a plot of the flowing pressure versus
rate curves for various water cuts in 2 7 / ~nch tubing. The
maximum flow rate at each water cut is shown in the table
on Fig. 2-12.
The effect of changing static bottomhole pressures or
formation productivity on producing rates can be deter-
mined by replotting the productivity line for the new pro-
ductivity and with a new static pressure starting point.
Effect of Surface Operating Conditions
To calculate the effect of surface operating conditions,
such as back pressure, on well production, curves should
be prepared for avariety of possible surface operatingpres-
sures and a comparison made of the producing rates under
each condition. Such comparisons are useful in determin-
ing the production to be gained from reducing pressure
losses i n production facilities. They may also be used for
determining the optimum design operating pressure at the
wellhead.
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22 Gas Lift
Use of Inflow Performance Relationship Curves (IPR)
Although the example problem uses the straight line P.I.
technique fo r predicting inflow performance, IPR curves
can also be used for determining the point of intersection,
2500- "
I l I l I
2-7/8' TUBING
NATURAL FLOW
M A X FLOW RATES
% H 2 0 BFPD
25O
24002500
5 0 2100
7500
H PI = 5.0 BFPD/PSI
l e3
500' 2dOO 40b0 60b0 d o 0 0 , A O O 12,bOOI
PRODUCING RATE (BFPD)
Fig. 2 - 1 2- atural f low, 2'h -inc h tubing
which is, in effect, the balance point between inflow and
outflow performance. An example of such a plot is shown
in Fig. 2-13.
Computer Programs for Well Performance Analysis
Computer programs are available that compare well in -
flow performance (productivity) with the vertical flow char-
acteristics of th e production installation to determine the
maximum production rates that are possible under various
producing conditions. These programs aresually available
as adjuncts to gas lift design programs but can be used as
separate tools for well performance analysis.
Most of the computer programs follow very closely the
manual technique discussed in this chapter. However, the
computer versions usually allow the user to input a wide
variety of producing parameters and to study the effect of
each of th e parameters on well performance. Many of the
computer programs will also plot he nformation in a
graphic form similar to that shown in Fig. 2-14. This dem-onstrates the effect of injection gas pressure on producing
rate and injection gas requirements.The great advantage of
the computer programs is that they allow the generation ofa large number of such curves comparing various produc-
ing parameters i n a very short period of time.
O 0
I
L I I I 1 I I 1 I1 0 0 Mo 300 40 0 500 600 700 Boo
PRODUCTION R A T E ( B B L . /D A Y I
Fig. 2-13 - urve number (1) s an IPR curve and curve
number (2) indicates the calculatedpe$ormance character-
istics of the outflow system
G A S L I F T PERFORMANCE
YELL ORTAlU6ULRR FLOU2 716 I N .YRTERCUT - 90 fFWHP = YO 0 P S I GSC IWJ CRS = 0.90
""""""""4
cas INJ. PnEssunes
Fig.2 - 1 4- omputer p lo tsof gas lift well performance
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Multiphase Flow Prediction 23
CHAPTER 3MULTIPHASE FLOW PREDICTION
INTRODUCTION
There are several words and terms in this chapter whichmay be new or confusing to the reader who is not familiar
with multiphase flow studies.A definition of all terms is not
necessary for understanding the basic concepts, but a dis-
cussion of the more unique terminology should aid the
reader.
Dimensionless Parameters
Most multiphase flow correlations nvolve numerous
dimensionless groups or parameters. Dimensionless groups
are commonly used in the analysis of experimental data
because the number of measured or assumed values forvariables can be greatlyeduced by combining several vari-
ables into a single dimensionless group of variables. The
variables are combined in such a manner that all units will
cancel, thus the group becomes independent of the uni t
system. Reynolds number is n example of a dimensionless
parameter or group.
Empirical Data
The word empirical refers to measured data. When there
is no purely mathematical relationship that will accurately
predict t h e value of a variable or parameter associated with
multiphase flow. The value must be established empiricallyby actual measurements. Generally, interpolation of empir-
ical data will present no problem but extrapolation can be
quite dangerous. Interpolation means the determination of
values between measured data, whereas extrapolation re-
fers to predicting values beyond the range of the measured
data. For example, the investigator does all of the experi-
mental work in l'/d-inch nominal tubing. A general compu-
ter program is developed based on these test data for 1'/4-
inch nominal ubing and extended o high rates hrough
large tubing such as 4'h-inch O.D. Predictions beyond the
range of a correlation may be totally in error. Usually a
correlation is identifiedby the investigatoror investigators.A typical multiphase flow correlation consists f numerous
equations and curves defining he relationships between
different independent dimensionless groups, which may be
called correlating parameters. These relationships repre-
sent measured data that have been organized in a manner
that will permit calculation of the flowing pressures at
depth or pressure loss through a flowline based on a pro-
duction conduit size and he fluid rates and properties.
Production conduit is a general term which can mean tub-
ing or tubing-casing annulus, depending upon which is the
production string. Most wells are produced through a tub-
ing string.
Basis for Developing Multiphase Flow Correlations
Several of the earlier multiphase flow correlationswere
based on a total energy loss factor or a no-slip homogene-
ous mixture for high rate production. The total energy loss
factor is analogous to a single-phase friction factor.o-slip
homogeneous flow implies that the gas and liquid have the
same velocity; therefore, the density of the mixture can be
calculated for any desired pressure without a complex gas-
slippage or liquid holdup correlation. In other words, the
pressure loss calculations for multiphase flow and single-
phase flow are similar. The distribution of th e liquid and
thegas sbasedon hedailyproductionratewithno
accumulation of liquid in the production conduit. These
simplified methods for calculating multiphase flow pres-
sure loss, with a total energy loss factor or a no-slip homo-
geneous mixture and friction factor, do not require the
establishment of the flow regime or pattern. The flow
regime fo r multiphase flow must be determined before the
pressure loss can be calculated for the more general type
of correlation. Each flow regimehas a different set f equa-
tions and correlating parameters for calculating a pressure
loss. If the flow regime cannot be accurately determined,
the calculated pressure loss ill be in error and discontinui-
ties in the slopeof the flowing pressure gradient curvesmay
be apparent.
Multiphase flow i n a production conduit represents
complex relationships between many variables and dimen-
sionless groups. For the purpose of this discussion, multi-
phase flow implies the presence of free gas and a liquid
which may be oil and or water. Many of the important
correlating parameters must be determined empirically
because mathematical solutions do not exist. There is no
one multiphase flow correlation available oday hat s
universally accepted by the petroleum industry for accu-
rately predicting flowing pressure gradients in all sizes of
production conduits for the ranges of gas and liquid rates
encountered in oil field operation. There s a continuing
effort to develop ew correlations and to improve those hat
exist.
Accuracy of Flowing Pressure at Depth Predictions
Accurate flowing pressure at depth predictions in pro-
duction conduits are essential to efficient continuous flow
gas lift installation design and analysis. Selecting the best
correlation for specific well production rates and conduit
sizes is not always a simple matter. Flowing pressure at
depthsurveys with calibrated nstrumentsandaccurate
stabilized production data measured during the surveys are
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API T I T L E r V T - 6 94 m 0732290 0532857 28T m
24 Gas Lift
essential to verify the applicability of a multiphase flow
correlation. In other words, the only way to properly evalu-
ate a multiphase flow correlation or set of flowing pres-
sure at depth gradient curvess to compare reliablewell test
data with calculated pressures at depth or with pressures
determined from published gradient curves.
Importance of Reliable Well Test Data
Reliable well test data implies accurate gasmeasurement.
The importance of selecting th e recommended orifice beta
ratios for accurate gas measurement canno t be over-
emphasized because the volumetric gas rate is one of the
most important parameters for defining the flow pattern or
regime. Beta ratio is the ratio of the size of the borehole in
the orifice plate to the internal diameter of the meter tube.
A differential reading in the upper two-thirds of the range
of the element is essential for accurate gas measurement
with an orifice meter, and the beta ratio controls the differ-
ential pen reading for a given volumetric gas rate. The
proper equations for multiphase flow calculations depend
upon a correct predictionof th e flow regime for h e general
type of multiphase flow correlations. There are required
welland ubularconditionsbeforeaccurateflowing-
pressure-at-depth predictionscan be anticipated. Themulti-
phase flow correlations n this discussion are not applicable
when an emulsion exists. The production conduit must be
full open: .e., the area open to flow cannotbe restricted by
scale or paraffin deposition. For accurate predictions the
flow pattern should also be relatively stable without severe
heading or surging.
There have been many instances when a multiphase flow
correlation or set of gradient curves has een rejected based
on reportedly reliable well test data after th e calculated flow-
ing pressures at depth didnot approximate he meas-
uredpressuresatdepth.Further nvestigation of t h ereported production test data may reveal the reason for the
discrepancy. A practice of reducing the flow rate to run a
survey is not uncommon when the wireline operator has
difficulty lowering the subsurface pressure gage into th e
production conduit. Field personnel may report the aver-
age daily production rate as gas-liquid ratio for a well
based on previous production test or an average daily rate
for the last 30 days rather than obtaining accurate produc-
tion test measurements during the survey.
Flowing pressure gradient curves and computer calcu-
lated flowing pressures at depth which are based on a
proven multiphase flow correlation will assure consistent
predictions in the stable flow range of the correlation.
When the actual reported field data are inconsistent and
not repeatable, the flowing pressure at depth predictions
based on computer calculations are generally more accu-
rate than th e “so called” field measurements. An operator
should always double-check the field data before condemn-
ing a widely proven multiphase flow correlation.
PUB LISHE D VERTICAL , HORIZONTAL AND INCLINED MUL TIPHASE
FLOW CORRELATIONS
This discussion is not intended to replace a text book on
multiphase flow. Only he multiphase flow correlations
that have received at least imited acceptance by the petro-
leum industry are mentioned in this chapter. These vertical
multiphase flow correlations are the Poettmann and Car-
penter3, Baxendell and Thomas4, Duns and RosJ,Johnson6,
HagedornandBrown7,Orkiszewski*,andMoreland9.
The number of detailed investigations of horizontal and
inclined multiphase flow are less numerous in the litera-
ture. The morewidely applied correlations includeBakerlo,
Lockhart and Martinelli”, Flanigan12, Eaton13, Dukler, e tali4, and Beggs and Brilll5. The Beggs and Brill correla-
tion for inclined flow may be used for vertical flow calcu-
lations by assigning a 90 degree angle of inclination. The
reported data base, application and possible imitations
are not always available for all multiphase correlations.
Generally, internal company improvements and modifica-
tions in multiphase flow correlations and computer pro-
grams are not public knowledge. Only published informa-
tion can be used o describe he various multiphase
flow correlations.
Papers Evaluating the Accuracy of
Multiphase Flow Correlations
Thereare echnicalpapers I h , 17 * l x * that eportedly
evaluate the accuracy of several widely used correlations
for vertical multiphase flow. Generally, authors of these
papers use published data from several sources. Thesemay
include flowing pressures at depth and production data
from original publications for multiphase flow correlations
being compared. A statistical errornalysis is performed on
the difference between the published measured pressureloss and the calculated pressure loss using computer pro-
grams written by these authors. The conclusions from this
type of error analysis can be misleading to the reader. A
multiphase flow data bank as a benchmark est for all
multiphase flow correlations does notalwaysapply.A
significant portion of the data may be out of the recognized
production rate or production conduit size ranges,oted by
the investigators, to be applicable to their multiphase flow
correlations. An example is the use of low production rate
data to check he Baxendell and Thomas correlations.
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Multiphaselo wrediction 25
The Baxendel l and Thomas cor re la t ion is aigh rate exten-
s ion of the Poet tmann and Carpenter to ta l energy oss fac-
tor curve. All low rate data would be on the Poettmannnd
Carpenter portion of the curve and not on the extensiony
B a x e n d e l la n d T h o m a s .A n o t h e rc o n s i d e r a t i o n s h e
manner n which a computer program s writ ten and he
correlations that are being used to calculate the luid properties.
Th e r e su l ts fr o m wo co mp u te r p r o g r ams b ased on th esame multiphase f low correlation can be quite different.
Ros-Gray and Duns-Ros Correlat ions
Ro s Correlation is being comp ared. Th e initial paper, which was
based on an extensive aboratory nvestigation by Ros2'
was presen ted a t a Jo in t AIChE-SPE Sym posium and a
revised version of he same paper was published in the
Journal of Petroleum Technology". The f inal version of
th e Ros paper was presented by D uns5. The Duns and Ros
paper sb asedon abora torydataonlyand sno t he
Ros-Gray correlation that was modified to eliminate dis-crepancies be tween ca lcu la ted and accura te ly measured
data from over600 actual stabil ized well tests. The conclu-
sion remains that one particular multiphase f low correla-
t ion may prove to be m ore accurate than others for certain
Authors may infer that the Ros-Gray correlation , which production conduit sizes and rates; therefore, a ranking of
can be purchased f rom Shel l Oi l Company, i s be ing com - the available correlations in terms of general overall appli-
p a r ed o o th e r co r r e l a t io n s wh en in f ac t h e Du n s an d cabili ty is questionable.
SIMPLIFIED MULTIPHASE FLOW CORRELATIONS BASED ON TOTAL
ENERGY LOSS FACTORSOR MO-SLIP HO MOGENEOUS MIXTURES
A simplif ied multiphase f low correlation based on a total
single energy loss fac tor curve or a simple homogeneous
no-slip f low model should be considered for calculating
flowing pressures at dep th in areas of high rate production
when the correlation is based on accurate stabil ized f lowing
well data from the same f ield or similar well production
rates and conduit sizes. The calculations for this type corre-
la t ion are s imple and are repor tedz2.3 to be more accura te
in many instances than the more complex general type of
correlations.
Poettmann and Carpenter Correlat ion
The f i r s t w idely accep ted mul t iphase f low cor re la tion
was develo ped by Poettmann and Carpenter and was pub-
lished in 1952. The work of Poet tmann and Carpenter d id
more to init iate additional research in vertical multiphase
flow than all pr ior publications com bined. Their correla-
t ion was based on a o ta l s ingle energy loss fac tor ha t
accounts fo r a l l osses nc lud ing iqu id ho ldup f rom gas
slippage and for fr iction and acceleration. The energy bal-
ance equat ion combined a pseudo no-sl ip homogene ous
mixture densi ty grad ien tand heFan n in gequat ion for
s ing le-phase f low where the f r ic t ion fac tor was rep lacedy
the total energy loss factor .
Baxendel l and Tho mas Correlat ion
B ax en d e l l an d T h o m a smo d i f i ed h e Po e t tman n an d
Carpenter correlation using measured data from high rate
wells in Venezuela. The total energy loss factor curve was
extended for da i ly mass ra tes which w ere s ign i f ican t ly
h igher han he orig ina l Poet tmann and Carpenter da ta .
The energy loss factor for vertical and horizontal multi-
phase f low approached a near constan t va lue a t very h igh
daily mass rates in a manner analogous to high Reynolds
numbers for fully turbulent single-phase f low on a Moody
diagram. The authors assumed that the f lattened portion of
the energy loss factor curve represents the truly turbulent
conditions where l i t t le or no gas sl ippage occurs. The calcu-
lated f lowing pressures at depth for high rates basedn the
extended total energy loss curve proved to be exceeding ly
accura te fo r wel ls n Venezuela . Since extension of the
energy loss curve was based on well data from the same
fields i n which the correlation was being used, reasonable
accuracy in f lowing pressure at depth predictions could be
anticipated. The numbe r of v ariables which affect hes epressure predictions are reduced because the f luid proper-
ties and conduit sizes are the sam e for the correlation and
th eactualwel ls . The originalPoet tmannandCarpenter
total energy loss factor curve and the extension by Baxen-
del l and Thomas is shown in Fig . 3-1.
O I 2 S 4 & 6 7 4
ou x 10-4O
Fig. 3-1 - xtension of th e energy loss factor curve by
Baxende l l and Thomas4 (Copyr igh t 1961 , SPE-AIME,
First published in the JP T 1 9 6 1 )
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26 Gas Lift
Two-Phase Homogeneous No-Slip
Mixture Correlations
Several technical papers have been published that illus-
trate the application of two-phase homogeneous no-slip
correlations for high rate wells. Brown22 notes hat a
simplified correlation developed rom multiphase flow data
for an actual production conduit size may assure moreaccurate pressure loss calculations than the more compli-
cated general type of correlation based on laboratory con-
trolled multiphase flow data for conduit sizes which are
generally smaller and shorter than the actual conduits. The
importance of properly defined luid property relationships
for calculating flowing pressure gradients was demon-
strated by Cornishz3. The advantages and accuracy of asimplified total single energy loss factor correlation or a
two-phase homogeneous no-slip flow model based on
actual measured data from high rate production wells
should not be overlooked. Total energy loss factors areeasily calculated from flowing pressure surveys, and an
energy oss factor curve can be shifted o mprove he
accuracy of the calculated flowing pressures at depth.
GENERAL TYPE MULTIPHASE FLOW CORRELATIONS
A general type of multiphase flow correlation is report-
edly applicable for all sizesof typical oil field production
conduits and for the liquid and gas rates encounteredn oilfield operations. The general correlation requiresn identi-
fication of the flow regime, or flow pattern, to define the
proper equations for calculating the flowing pressure gra-
dient in the incremental pipe length under investigation.
There may be more than one flow pattern existing etween
the lower end of the production conduit and the surface.
The flow regime may be single-phase or bubble flow at
the higher pressures nearer the surface. The flow pattern
schematic from Moreland9 in Fig. 3-2 for vertical flow of
gas-liquid mixtures llustrates he need for proper flow
regime identification. The pressure gradient equation or at
least one flow regime will include liquid holdup based on
gas slippage. Liquid holdup represents he relationship
between the volume occupied by the liquid and th e total
volume of the production conduit within the incremental
pipe ength under nvestigation. The accuracy of the
method for predicting liquid holdup is particularly impor-
tant for the gas and liquid velocities associated with the
lower production rates. Liquid and gas viscosity's and sur-
face tension are sually required input or are default values
in the computer programs for th e general types of multi-
phase flow correlations. Accurate pressures at depth pre-
dictions are claimed by the developers of most general
correlations for even relatively high viscosity crude oil.
Typical Pressure Gradient Equationor Vertical Flow
Although the exact final equations and correlating param-
eters vary between investigators, the basic typical pressure
gradient equation for vertical multiphase flow consists of
the following terms:
Equation 3 .1
Pressure
Gradient - DensityrictionccelerationTerm Term Termerm
+ +
The density term includes a liquid holdup correction for
gas slippage. The acceleration erm is often neglected in all
flow regimes except where high luid velocities exists such as
ANNULAR
MIST
FROTH
SLUG
BUBBLE
SINGLE PHASE
LlOUlO
Fig. 3 -2 - ypical f low pat te rns for ver t ica llow of gas-liquid mixtures9
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API TITLErVT-6 74 m 0732270 0532860 874 W
Multiphase Flow Prediction7
in the annular mist regime. The contribution of accelera-
tion is reported to be very small in the other multiphase
flow regimes.
The flow regime, or flow pattern, mapgenerally s
divided into at least three major regions which are defined
by the continuity,or lack of continuity, of the liquid and gas
phases. Fig. 3-3 is thepublished Ros flow regime map based
o n laboratory data. The iquid phase is continuous in
Region I; and gas is the continuous hase in Region III. The
pressure gradient i n the transition area between Regions I I
and III can be approximated by linear interpolation on the
basis of the gasvelocity number (RN) value on the abscissa,
where R is the ratioof the in-situ superficial velocity of the
gas to liquid phases. The flow regime must be established
before heproperequations andcorrelationscanbe
selected for the flowing pressure gradient calculations. The
Ros flow regime boundary equations have been used by
other investigators.
Y
Gas Ve loc l t y NumberR N
Fig. 3-3- osflow region boundaries based on laboratory
data’
Published GeneralType Correlations
The multiphase correlations developed by Ros, Orkis-
zewski, Aziz, et. al, are considered general. The original
paper by Hagedorn and Brown’ stated that i t was unneces-
sary to separate two-phase flow into the various flow pat-
terns and develop correlations for each pattern. Many
computer programs based on th e Hagedorn and Brown
correlation include separate sets f equations for the differ-
ent flow regimes and use the Hagedorn and Brown correla-
tions for only the slug flow pattern, which is Region II on
the Ros flow regime map in Fig. 3-3. An explanation for
this conclusion by Hagedorn can be found in the paper by
Orkiszewski which notes hat slug flow occurred in 95
percent of the cases studied. Apparently, Hagedorn id not
encounter the bubble flow regime during his experimental
work because his tests were conducted in a shallow 1500-
foot well. The accepted categoriesor flow regimes for wo-
phase flow are ideally depicted by Orkiszewski in Fig. 3-4.
(AI I RI
. .I .. .:. . .
v .
BUBBLEFLOW\- ,
SLUG FLOW SLUG-ANNULARNNULAR-MIST\ - /
TRANSITIONLOW
Fig. 3-4 -Ideal f low regimes or categories for mult iphase
f l o w as i l lustrated by OrkiszewskP (Copyright 1967 SPE-
A I ME , First published in the JPT June 1967)
DISPLAYS OF FLOW ING PRESSUREAT DEPTH GRADIENT CURVES
Most displays of flowing pressure at depth gradient
curves use the same parameters but may be plotted some-
what differently. Generally, a setof gradient curves will be
displayed for a given conduit size, a production rate, nd a
water cut which may be zero; i.e., all oil production.Flow-
ing pressure at depth curves will be drawn for gas-liquid
ratios (R,1) ranging from zero for single-phase liquid to
a maximum practical R,], depending upon he conduit
size and production rate. For example, a maximum R,1 of
10,000 standard cubic feet of gas per stock tank barrel
(scf/STB) would be displayed for a production rate f only
100 STB/day through 2’/rinch O.D. tubing, whereas a R,I
of 1000 to 2000 scf/STB may be the maximum for a higher
production rate of 2000 STB/day through the same conduit
size. In general, higher Rglvalues are associated with lower
production rates and lower R,I values with higher produc-
tion rates.
Converting Rg Oo Rg ,
This family, or set, of curves should always be defined in
terms of R,I and not gas-oil ratio (Rgo).The Rgo s equal to the
R,] only when the water cut is zero. The firs t step after
selecting the proper set of gradient curves is to convert the
right American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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28
%PI T I T L E x V T - b 94 m 0732290 0532863 700 m
Gas Lift
total Rgo o total Rgl before determining a flowing pressure
at depth.
R g l = f o ( R g o ) Equation.2
Where:
R,I = gas-liquid ratio, scf/STBf,, = oil cut (1 O - water cut), fraction
Rgo = gas-oil ratio, scf/STBThese R,] curves always represent total R,I, which is
the formation R,I below the point of gas injection and is the
injection plus the formation R,I about th e point of gas in-
jection.
Gilbert’s Curves
Gilbert1 published onef the first sets f flowing pressure
at depth gradient curves n 1954. Although flowing pressure
gradient curves for several conduit sizes ere published by
Gilbert, the only full-page size curves presentedn the API
paper were for 27/~-inchO.D. tubing. No multiphase flowcorrelation was offered for calculating these flowing pres-
sures at depth. Gilbert’s curves were based on numerous
flowing pressure surveys run in the VenturaField in California.
The Gilbert flowing pressure-depth curves were th e fore-
runners for he present method of displaying gradient
curves. One set of Gilbert gradient curves for 600 barrels
per day through 27/8-in~h .D . tubing is shown in Fig. 3-5.
Note that the depth axis is shifted 5000 feet for the Rgl
curves of 3000, 4000 and 5000 scf/STB. The optimum
R,I, as defined by Gilbert for this daily production rate of
600 barrels through 2’/8-inch O.D. tubing, is 240 scf/STB.
The optimum curve representshe minimum possible flow-ing pressure at depth for a given conduit size and produc-
tion rate. When the R,I exceeds 2400 scf/STB, the flowing
pressure gradient begins to increase rather than decrease.
This increase in flowing pressure gradient is referred to as
a reversal in the slope of a gradient curve. A higher flow-
ing pressure at depth is predicted for R,I of 5000 scf/STB
than for 2400 scf/STB based on these gradient curves.
Minimum Fluid Gradient Curve
Many published gradient curves are displayed with a
minimum fluid gradient curve rather han shifting heorigin of the depth scale to prevent overlayingnd crossing
over of R,] curves at low flowing pressures at depth. A
reversal in t h e slope of a high R,I curve will result in the
higher R,I curves crossing over he ow R,I curves at
low flowing pressures. An example of overlaying of gra-
dient curves24 is illustrated in Fig. 3-6. and accurate pres-
sure determinations are difficult nd confusing at the ower
flowing pressures where the curves are crossing over one
another.
The minimum fluid gradient curve ignores the reversals
in the ndividual R,I curves and represents a flowing
pressure gradient curve definedby th e loci of tangency’s of
the higher R,] curves to form a single curve. As the R,I
increases, the flowing pressure at the depth f tangency for
the higher R,, curves ncreases which nfers hat hese
points of tangency occur at increasing chart depths. A setf
typical flowing pressure gradient curves for 600 STB day
through 23/s-inch O.D. tubingz5 is shown in Fig. 3-7. The
minimum fluid gradient curve and higher R,I curves willbe one and th e same above the point of tangency. Gradient
curves displayed with a minimum fluid gradient curve are
easier o apply for certain design determinations. The
design calculations may lose some accuracy f gas lift opera-
tions should occur i n the reversal portion of a high R,]
curve. However, most efficient gas ift nstallations will
operatewitha otal R,I below he range of a severe
reversal i n the flowing pressure gradient curve and the
actual flowing wellhead pressure will exceed the lower pres-
sures where a severe reversalwould occur. Gas lift installa-
tion designs and analyseshavebeenbasedongradient
curve displays with a minimum fluid gradient curve without
any reported significant error i n predictions of flowing
pressures at depth or injection gas requirements.
Gradient pressure, psi
F i g . 3-5- i lbert’s f lowing pressure gradient curveso r
600 B PD through 27/g-inch O . D . tubing’
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A P I TITLExVT-b 94 0732290 0532862 b 4 7 9
Multiphase Flow Prediction 29
2 -
4 -
6 -
8 -
0 -
2 -
4 -
6 -
8 -
'O -
PRESSURE - 100 PSI
8 16 24 32 40 40 66
VERTICAL FLOWINQ
PRESSURE GRADIENTS(ALL OIL)
TUBING SIZE 2.44 1 IN. I.D.
PRODUCTIONATE 1500 BLPD
Q A 8 SPECIFIC GRA VITY 0.65
AVERAQE FLO WINQ TEMP. 150 O F
OIL GRAVITY 36.0 O API
WATER SPECIFIC QRAVITY 1 O7
Fig. 3-6- ert ica l f lowing pressure grad ien t curves wi thou t dep th d isp lacement to e l imina te overlapp ing of the high
R,I curves24
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API T I T L E t V T - 6 94 m 0732290 0532863 583
30 Gas Lift
O 4 8 12 16 20 24 28
1
IV E R T I C A L FLOWING
P R E S S U R E GRADI ENTS
(ALL a u
2
3
4
Tubing Size 2 in. 1.D.
1roducing Rate 600 Bb l r /Da y
Ol AP Gravity 35" APt I
Gas Specif ic Gravity 0.65
8
Fig. 3- 7- ertical f lowing pressure gradient curves plotted w ith ainimum fluid gradien t curve z5
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A P I TITLExVT-6 9 4 m 0 7 3 2 2 9 0 0532864 41T
Multiphase Flow Prediction 31
O 5 10 1 5 20 2 5 3 0
10
Fig.3-8- ert ical f lowing pressure gradient curvesased on the Shell Ros-Gray correlat ion with the higher g,urves
displaced on the depth scale to prevent gradienteversal overlapping6
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32 Gas Lift
Displaying Gradient Curves to Prevent CrOSSOVer from crossing over the preceding lower RE ,curve. A set of
The most accurate displayof gradient curves will include Ros-Gray curvesh are shown i n Fig. 3 - 8 . Flowing pres-
the reversal i n the flowing pressures at depth for the higher sures at depth are determined in the same manner for the
R,I curves. The R,, curve will be displaced sufficiently displaced R,I curves as for a set of gradient curves with a
on thedepthscale oprevent he nexthigher Rgl curve minimum fluidgradientcurve.
STABILITY OF FLOW CONDITIONS AND SELECTIONOF PRODUCTION CONDUIT SIZE
Multiphase low orrelations redeveloped based n Graphical Determination of MinimumStabilizedstabilizedlowing well data. A correlationanextended Production Ratebeyond its range of validity without th e user recognizing
the limitations. Although smooth gradient curves may be pub- A plot of flowing bottomhole pressure at 6000 feet versus
lished for low liquid rates with low total gas-liquid ratios, daily production rate for a constant Rgl of 400 scf/STB
actual flow conditions may be quite different than would be and a flowing wellhead pressure of 100 psig is shown in
predictedromheurves. Fig. 3-9. A minimumlowingottomholeressure of
18
17
16
15
14
13
12
11
10
9
$3
O 1 2 3 4 5 6 7 8 9 1 0 1 12 1 34 1 5
Daily Production Rate- 00STB/day
Well Information:
1. Tubing Size =2%-inch O.D.
2. Tubing Length =6000 ft
3. Water Cut (fo)=0% (All Oil)
4. FormationRg ,=400scf/STB
5. Flowing Wellhead Pressure (Pwh)100psig
Fig. 3-9- lowing B H P versus daily production rate o r a constant gas-oi l rat io
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A P I T I T L E * V T - b Y Y m 0732290 0 5 3 2 8 6 6 292 m
Multiphaselo wredict ion 33
approximately 860 psig at 6000 feet occurs at a daily pro-
duction rate sl ightly greater than 500 STB day . The f low-
ing bottomhole pressure increases at lower and higher daily
l iquid production rates. The unstable flow condit ions exist
at dai ly iqu id ra tes ess han he ra te for he minimum
flowing bot tomhole pressure . The unstab le range should be
avoided by producing at a daily rate that is safely above the
500 STB day in th is example to assure not s l ipp ing in to the
unstab le reg ion . A cycl ic heading or surg ingcondit ion
develops as the daily production fal ls below the l iquid rate
for this minimum flowing bottomhole pressure. The cyclic
condit ions are perpetuated and intensifiedby the fluid flow
principles defining a vertical or incl ined mult iphase flow
system and he nt low performance relat ionship defining
the deliverabilityof a reservoir. As the liquid rate decrea ses,
the flowing bottomhole pressure ncreases which in turn
results in a fur ther decrease in liquid rate. Most wells will
reach a severe surging condit ion that can best be described
as a loading and unloading state of flow before all flow
ceases and the well is classified as dead.
Conditions Necessary to Assure Stable
Multiphase Flow
An explanation fo r the condi t ions necessary to assure
stable mult iphase flow can be related to a minimum free
volumetric gas rate requirem ent for a given produ ction con-
duit size. The in-situ gas velocity must exceed a minimum
va lue ha t p reven t s excess ive gas s li ppage and co r re -
spondingly high liquid holdup which causes a well to load
up and die. Since here is this minimum gas rate require-
ment, he total gas-liquid ratio to sustain stable flow must
increase as the daily liquid production rate decreases for the
same production conduit size. For this reason, a com pari-
son of injection gas-liquid ratios is not recomm ended for
evaluating the ga s lift operations in wells that have a wide
range in daily production rate. Also , a min imum gas veloc-
ity necessary to prevent excessive iquid holdup explains
why stable flowing conditions can be established in smaller
conduit sizes for lowate wells. The gas elocity increases as
the production conduit size decreases for he same daily
O 1 2 3 4 5 6 7 8 9 10
D a il y P ro d u c t i o n R a te- 00STB/d a y
Wel l In fo rmat ion :
1. T u b i n g L e n g t h =6000 feet
2. Formation Rg,=400 scf/STB (All Oil)
3. Flow in g Wel lhead Pressure = 100psig
Fig. 3-10- lowing B H P versus da i ly produc t i on ra t e for t hree d i f f e ren t t ub ing s i ze s o f t he sume l eng t h und a con-
s tunt gus-oi l rat io
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A P I T I T L E * V T - b 9 4 m 0732290 O532867 L29
34 Gas Lift
volumetric gas rate. n other words, a tubing size can be too
large for a low capacity well or too small for a large capacity
well.
Effect of Tubing Size on Minimum StabilizedFlow Rate
A well may flow with a 2’/s-inch O.D. tubing string and
require artificial lift with a larger size tubing. If the daily
production rate occurs in the unstable range of flow for a
given tubing size, a lower flowing bottomhole pressurean
be attained for the same daily production with a smaller
conduit size. For example, the predicted flowing bottom-
hole pressure is approximately 1360 psig at 6000 feetor 1O0
STB day through 2’/s-inch O.D. tubing in Fig. 3-9. If 1 660-
inch O.D. (l’ /a- inch nominal) tubing were run in the same
well, hepredictedflowing bottomhole pressure would
decrease to approximately 1000 psig for hesamedaily
production rate of 100 STB day. The intake flowing bot-
tomhole pressure versus daily production rate for hree
commonly used tubing sizes s l lustrated n Fig. 3-10.
Accurate gradient curves can be used to select the proper
conduit sizefor a well based on the desired daily production
rate.
CONCLUSIONS
The ability to predict accurate multiphase flowing pres-
sures at depth n a vertical production conduithas improved
significantly since the work of Poettmann and Carpenter i n
1952. Research i n multiphase flow continues with increased
emphasis i n gathering systems ncluding flowlines and
inclined flow. The number of wells having deviated produc-
tion conduits will increase as new wells are drilled from
offshore platforms. Improved multiphase flow correlations
will be developed for deviated production conduits. The
calculations for nclined flow will be more complex by
requiring profiles of production conduit lengthversus angle
of deviation.
Many companies have heir own n-house multiphase
flow computer programs. These programs should be util-
ized by field production personnel for continuous gas lift
installation design and analysis. The majority of the gas lift
manufacturers have computer programs available to design
and analyze gas l i ft installations. The widely used multi-
phase flow correlations in these computer programs have
been verified by actual field measurement to be reasonably
accurate when reliable well data are used for nput. In
conclusion, he advent of multiphase flow correlations
which are applicable to the conduit sizes and he daily
production rates associated with gas l i f t operations has
changed the design and analysis of continuous flow gas if twellsfrom an art based on experience o a predictable
science.
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A P I T I T L E * V T -6 9Y m 0 7 3 2 2 9 0 0 5 3 2 8 b 8 Ob5 m
Gaspplication and Gas Facilitiesorasift 35
CHAPTER 4GAS APPLICATION AND GAS FACILITIES FOR GAS LIFT
INTRODUCTION
Gas handling facilities such as gas compressors, dehy-
drators, meters, and pipelines are the highest cost portions
of the gas lift system. This equipment sually requires more
operating and maintenance effort than any other part of the
gas lift facilities.
Natural gas used to produce liquids by gas lift is con-
trolled,measured,compressed,andprocessedwith
mechanical devices. Therefore, an understanding of gas
fundamentals and operating practices is necessary to the
successful operation of a gas lift system. Operating prac-
tices involving gas are different from those for oil because
of the increased pressure and compressibility of the mix-
tures involved. Also, as a gas that contains even small quanti-
ties of hydrogen sulfide can be very corrosive to certain
equipment and present a hazard to human life. It is impor-
tant to understand that a single component as like nitrogen
and a mixture of components such as natural gas will be-
have differently.
Injection gas for gas l i ft wells can be affected by various
operating and producing conditions including gas supply
and production system back pressure. Production condi-
tions such as surface wellhead back pressure and surface
temperature are usually estimated i n gas lift design and
planning because actual measurements will not be avail-
able. Gas lift valves downhole will respond o njection
gas pressure and production pressure in the wellbore
as well as pressure and temperature inside the bellows of
the gas ift valve. These conditions must be accurately
predicted.
BA SIC FUNDAMENTALS OF GAS BEHAVIOR
The pressureof a liquid or gas system can be measured. A
pressure gage is the device that s commonly used to meas-
ure the pressure of the liquid/gas mixture produced fromthe well as well as the pressure of the gas injected into the
well. The pressure is taken with a gage and is referred to as
gage pressure. n theUnited States it is measured in pounds
per square inch and designated psig. Gage pressure plus
atmospheric pressure (usually about 15 psi) is referred to as
absolute pressure and designated psia. The difference be-
tween gage pressure and absolute pressure is very small at
high pressures. For example, 1000 psig converts to 1015
psia, if atmospheric pressure is 15 psi.
Gas lift systems utilize gas pressure n more than one type
of application. In the first type of application the gas canexpand. In this application, gas goes from the compressor,
through a pipeline to the well, and then goes through a gas
lift valve, where it expands and mixes with the produced
liquids. At each link the gas expands and loses some of its
pressure energy. The second type of application involves a
sealed gas container. An example of this is the nitrogen
which is contained in the bellows of a gas lift valve. In each
of these cases the gasehavior differs. Thesealed container
is a system in which pressure, temperature, and volume are
related.
In thesealedcontainer,orbellows,a emperatureincrease causes a pressure increase inside the bellows
because the nitrogen cannot expand outside the bellows.
This is stated in the following equation:
PI = P2 Equation 4. 1
I Tz
In gas lift calculations this equation could be used to
determine the change that takes place n the nitrogen pres-
sure in the bellows when a gas l i ft valve is set in a test ack at
a temperature of 60°F and then is placed downhole at a
much higher temperature. However, before equation 4.1
can be applied, the effects of temperature must be reviewed.
Temperature affects the gas in the closed container as
well as in the open, expansive application. The indicator of
heat change is the measured degree of temperature. In all
calculations throughout this chapter, the temperatures are
absolute, i.e., degrees Rankine ("Fplus 460). For example,
150°F plus 460 is equal to 610" Rankine (absolute).
A gas expands when heated. Temperature increase after
compression and the subsequent effect on flow through a
pipeline or a gas lift valve are the most common examples
of these phenomena. Gas measurement requires a recordf
the flowing temperature of the'gas through an orifice meter.
The gas flow equation is adjusted for the flowing tempera-
ture of the gas and corrected to a standard temperature of
60°F. In the calculations shown here, he emperature indegrees Fahrenheit (F) is converted odegreesRankine (R).
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A P I T I T L E U V T - b '34 07322'30 0 5 3 2 8 b 9 T T 1
3 6 Gas Lift
In this example, the valve bellows pressure i n the test rack D ev ia t i on fac to rs can be ob t a ined fo r n i t rogen f romat 60°F is calculated S O that the valve can be set to have a Fig. 4-1 and for sweet natural gases from Fig. 4-2 and 4-3.bellows pressureof 1000psig when it is operating downhole Deviat ion is a function of the pressure and temperature and,
at 150°F. for natural gases, it s also a functionof gas specific gravity
(gas speci f ic gravi ty s based on com posi t ion) . These com-
PI PZ (1000 psig + 15si ) P? pressibilityactorsdeviat ionactors)ccountorheon--~-or - i d e a le h a v i o rf g a s a n dm p r o v eh ec c u r a c y o f
T I T?
-
(150°F +460) (600F +460"F) calculation s oroil ield ystems.
or (1015sia) - PZ
( 6 1O'R) ( 5 2 0 " R )
t he n P? =865 s ia
This s he absolu te pressure wi th deal behavior . The
atmospheric pressure is approximately 15 psi , therefore, the
gage pressure i s 850 psig .
This exam ple does not take in to account the devia t ion
from ideal behavior. A compressibi l i ty factor (Z) is used to
denote deviat ion from ideal condit ions.
The deviat ion or compressibi l i ty factorZ) appears in the
following equation:
P1 VI P2 V ?~- - Equat ion 4 .2ZII Z? T?
The volume (V) is now included n the pressure, tempera-
ture, and deviat ion relat ionship. In he example i n which
bellows is considered a sealed container that change s very
little in size VI is equal to V Zand so volume is el iminated
f r o m h e e q u a t i o n . T h e Z f a c t o r r e m a i n s , n o r d e r o
improve the accuracy of th e results. To apply the Z fac tor ,
the type of gas must be identified because theZ fac tor for
methane is di fferen t f rom the fac tor for n i t rogen , which i s
a l so d i fferen t f rom theZ factor for a natural gas mixturef
many components.
So th e Z factor is related to the particular gasapor. Charts
a r ea v a i l a b l e h a t i s td e v i a t i o n (Z) f a c t o r s o rn i t ro -
gen and for natural gas mixtures denoted by some p roperty
(usually specific gravity). These charts and tables are not
valid if significan t quan tities of impu rities are presen tn th e
natura l gas mixture . Specia l chart s are needed for hose
condit ions.
It becomes very apparent that the accuracyof the calcu-
la t ion depends on having re l iab le informat ion for pressure ,
tempera ture , and Z factors. The user should be careful to
ensu re t ha t t he t ab l e o r cha r t be ing u sed rep resen t s t he
actual gas s t ream being considered .
The previous example i s m odi f ied as fo l lows:
The gas is ni trogen. At condit ion 1:
PI = 1015 psia (1000 psig +15 psi)
T I 150°F
F r o m F i g . 4 - 1 , ZI = 1.013
At condi t ion 2 :
P? = unknown butassume865psia)
Tz = 6 0 ° F
2 2 = 0 .992
Now apply equation 4.2
1015 psia Pz
(1 .013) x [(150"F) +460'1 (0.992) x [(60"F ) +460'1
P2 = 8 4 7 p s i a U s e h i s PZ o e s t i m a t e a n o t h e r Z2
-
and repeat calculat ion)
If similar calculat ions are made i th natural gas, Fig. 4 -2
an d4 -3a reava i l ab l e o re s t ima t ing he Z Fac to r .F o r
example , assume the gas speci f ic gravi ty i s 0 .7t condit ion
1:
PI = 1015 sia (1000 psig)
T I = 150°F
From F ig . 4-3 , (use the above data) , ZI =0 . 8 8 5
A tc o n d i t i o n2 , T? = 6 0 ° F . P2 i su n k n o w n ,b u ta n
assumedpressure sneeded oest imate ZZ.A ssume PZ=850 psia (835 psig), then Z2 =0 .8 1.
Now apply equat ion 4 .2 ,
1015sia - P2-(0.885) (610"R) (0.81) x (520"R)
PZ = 7 9 2p s i a u s e h i s PZ oe s t i m a t ea n o t h e r ZZ
and repeat)
Note: Nitrogen (N?) s used in t h e gas ift valve bellows
because N2 behavior is well known. N2 is non-toxic
and i t is readily available.
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E * V T - 6 94 m 0732290 0532870 713 m
G aspplicat ionndasaci l i t ies fo r G a s Lift 37
N
PRESSURE, PSlA
Fig. 4-1-
ompressibil ity fa ctor s for Ni tr oge n, Bureau of M ines Monograph 10 Volume 2 , “Phase Relat ions ofGas-Condensate Fluids”
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I TITLEUVT-b 9 4 m 0732290 0532873 b5T m
38 Gasif t
1PROBLEM EXAMPLE:
GIVEN: Tavo= 100°F
Fig. 4-2- -Chart (100 - 300 psi ) Courtesy Exxon Production Research Company
Fig. 4-3- -Char t (300 - 2000 ps i) data from CNGA Bu1 T5-4 61 and Standing-Katz AIME Transactions 1942
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E a V T - 6 74 W 0732290 0532872 576
Gas Application and Gas Facilities for Gas Lift 39
APPLICATION TO OILFIELD SYSTEMS
Gas behavior applications are important in the produc-
tion of oil and gas because there are changes in temperature
and pressure as the oil and gas move from reservoir to the
surface. Conceivably the “gas” may be a iquid i n the
reservoir at high pressure and temperature and change to
the gas phase inside the wellbore as it moves toward thesurface.
Offset wells in the same reservoir can be a good source
of information relating to crude oil and dissolved gas
characteristics such as gas-liquid ratios and gas composi-
tion. Various correlations are available fo r estimating the
changes in the properties of crude oils as the pressure and
temperature of the production system change. These corre-
lations make it possible to predict the amount of free gas
that will be present in the system under any given condition
of pressure and temperature.
Another area related to gas behavior occurs in the designand sizing of surface compressors and dehydration facili-
ties. Millions of dollars are spent to design, nstall, and
operate these surface facilities. Therefore, good data on gas
properties are necessary to accurately predict gas behavior
within ranges in temperature and pressure. In order to more
accurately describe gas behavior, a reservoir fluid sample is
analyzed n he aboratory for PVT (pressure, volume,
temperature) relationship. This analysis provides the gas
and liquid composition as well as other useful information
on gas and oil properties such as gas specific gravity, liquid
gravity, and gas-oil ratio. If a sample from the reservoir
cannot be obtained, a recombined separator liquid and gassample is used. Often multiple gas samples are taken for
chromatograph composition analyses and used for com-
pressor sizing and design. These composition values ar e
crucial for the design of centrifugal compressors because
the internal wheel design is highly dependent upon gas
specific gravity and the changes that occur in the gas as it
goes from a low pressure to a high pressure. The reciprocat-
ing compressor is also dependent upon this gas composi-
tion but is not as sensitive to changes.
Subsurface Applications
Techniques for estimating gas behavior may be appliedto subsurface applications in computing injection gas pres-
sure profiles, estimating the gas passage through a gas lift
valve and, as previously mentioned, in setting a bellows
(dome) pressure in a gas lift valve. In all cases the funda-
mental methods described here are used to estimate gas
behavioral changes. Most of the time, equations are not
used directly. Tables and charts provide the data needed for
calculati ons. Computers are often used, producing a
data graph for estimates.
Pressure Correction
The dome, or bellows, in the gas lift valve is used toprovide a controlled closing pressure so that the gas lift
valve operates much like a back pressure valve on a separa-
tor. The closing force in the valve is provided by the nitro-
gen pressure in the bellows for most valves, although some
valves use a spring or nitrogen pressure plus a spring. The
valve mechanics equations, estimates of downhole gas pres-
sure, downhole fluid pressure, and downhole temperatureare used to calculate the bellows pressure needed for the
closing force. As previously discussed, this nitrogen pres-
sure within the bellows (approximately constant volume
sealed dome) is dependent upon temperature. The pressure
inside the bellows will vary as the temperature varies.
Temperature Correction
The emperature correction s actually an adjustment
from wellbore temperature to a test rack temperature of
60°F. The wellbore temperature estimate is critical because
the nitrogen pressure setting in the valve is dependent uponthis temperature estimate. Another possible error may
result from poor behavior prediction of the bellows gas. As
mentioned previously, nitrogen is used to lessen chances
of error because it has well-knowncompressibility factors and
is safe to handle.
Most manufacturers cool the gas l i f t valves to 60°F in a
cooler and thus have a consistent and repeatable tempera-
ture at which to set the nitrogen pressure in the bellows:
however, the gas lift valve in the well will not beoperating at
60“. It will be at some higher temperature and the down-
hole bellows pressure (Pbdt) at temperature must be con-verted to a bellows pressure (Ph”) at 60°F. One correcting
method s o use Table 4-1 by H . W. Winkler and he
following relationship:
p h v =CT x Phdt Equation 4.3
Where:
Pbv =Bellows Pressure (psig) @ 60°F
CT =TemperatureCorrectionFactor, for adown-
hole temperature at valve (from Table 4-1)
PM = Bellowsressurepsîg) @ DownholeTemperature(fromvalvemechanicscalcula-
tion)
As an example, calculate the dome pressure at 60°F in a
test rack if Pmt =820 psig at 140°F.
Pbv =(0.848) x (820 psig) =695 psig
This calculation gives the bellows pressure setting at a
laboratory (shop) standard condition. In the shop the valve
is placed in a special test rack fixture and the valve is set by
calculating a test rack opening pressure and then lowly bleed-
ing the nitrogen from the bellows until the test rack openingpressure just barely opens the valve.
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A P I T I T L E r V T - 6 94 m 0732290 0532873 Y 2 2 m
40 Lift
TABLE 4-1
TEMPERATURE CORRECTION FACTORS FORNITROGEN BA SED O N 60°F
Pbv =1000 psig
"F Ct "FCI
"F Cl "F Cl "F Cl "F C,
6162636465
6667686970
71
72737475
7677787980
81
8283
8485
868788
8990
9192939495
96979899
1O0
,998,996,993.991,989
,987.985.982,980.978
.976
.974
.972
.970
.968
,965.963.96.959,957
.955
.953
.95 1
.949
.947
.945
.943
.941
.939
.937
,935.933.931.929.927
.925
.924
.922,920.9 18
101102103104105
106107108109110
11 1
112113
114115
116117118119120
121122123
124125
126I27128129130
131132133134135
136137138139140
.9 16,914.912.910.909
.907
.905,903.901,899
.898
.896
.894,892.890
.889,887.885.883.882
.880
.878
.876
.875
.873
.871
.870
.868
.866
.865
.863
.861
.860,858
.856
.855
.853
.85 1
.850
.848
141142143144145
146147148149150
151
152153154155
156157158159160
161162163
164165
166167168169170
171172173174175
176177178179180
.847
.845
.843
.842
.840
.839
.837
.836
.834
.832
.831
.829,828.X26,825
.823
.822
.820
.819
.817
,816,814,813
.811
.a10
.808
.807
.805
.804
.803
.801,800
.798
.797
.795
.794
.793
.79 1
.790,788
181182183184185
186187188189190
191
192193
194195
196197198199200
20 1202203
204205
206207208209210
211212213214215
216217218219220
,787,786,784,783.781
.780
.779
.777
.776
.775
,773
.772
.771
.769
.768
.767,765.764,763.761
.760
.759
.758
.756
.755
,754.753.751.750.749
,747,746.745.744.743
.74 1
.740
.739
.738,736
22 1222223224225
226227228229230
231
232233234235
236237238239240
24 1242243
244245
246247248249250
251252253254255
256257258259260
.735
.734
.733
.732
.730
.729
.728,727.726.724
.723
.722
.721,720.719
.717
.7 16
.715
.714
.7 13
.7 12
.7 1,710
.708
.707
.706,705,704.703.702
.701
.700
.698,697.696
.695
.694
.693
.692
.691
26 1
262263264265
266267268269270
271
272273274275
276277278279280
28 1282283
284285
286287288289290
29 1
292293294295
296297298
2993O0
,690.689.688.687.686
.685,683.682.68 1
,680
.679
.678
.677
.676
.675
,674.673,672.671.670
.669
.668,667
,666.665
.664
.663
.662
.661
.660
.659,658.657.656,655
.654
.654
.653
.652
.651
Where: Cl =1/[1O +("F-60) x MPb]
And for Pbv less than 1238 psia
and for Pbv greater than 1238 psiaM =3.054 X Pb~2/10000000+ 1.934 X Pbv/1000 - 2.26/1000
M =1.840 X P~v2/10000000 2.298 X Pbv/lOOO - 0.267
Based on SPE paper 18871 by H. W. Winkler and P. T. Eads, Algorithm for more accurately pred icting nitrogen-ch arged ga s
lift va lve opera tion at high pressures and temperatures. Presented at SPE production operations symposium in OklahomaCity, O K , March 13-14, 1989
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E * V T - 6 94 0732290 0532874 369
Gas Application and Gas Facilities for Gas Lift 41
Test Rack Settings
This method of setting test rack opening pressure P,,
allows air pressure to be applied to the valve seat as the
drawing shows in Fig. 4-4. The pressure in the bellows acts
downward (over the bellows area) and the test rack opening
pressure acts upward (over the bellows area less the port
area). The calculated test rack opening P,, pressure is asfollows:
Equation 4.4
Equation 4.5
The test rack opening calculation is based on the cor-
rected bellows pressure at 60°F Pb and the valve data Ab
and A,.
Be l lo ws
ATMOSPHEREPa
Fig. 4-4- ett ing test rack opening pressure
Gas Injection in the Annulus or Tubing
High pressure gas for injection into the well is usually sup-
plied to the gas system from the gas compressor (or high
pressure gas well) and the gas pressure and rate must be
measured and recorded so that actual values are known
rather than assumed. The gas pressure will'decrease as it
passes through the adjustable choke upstream of the well-
head assembly.
The wellhead gas pressure is required for design pur-
poses. One aspect of design is the change of gas pressure
with depth. In most cases, injection gas is put into the tub-
ing-casing annulus of the gas lift well and the gas pres-
sure increases with depth due to the weight (density) of
the gas. Tables or figures, such as Figures 4-5 and 4- 6 give
the increased pressures with depth. These curves show the
gas pressure profile with depth and each line represents a
different surface gas pressure. Although the gas pressure
usually increases with depth, there are cases in which gas pres-
sure could decrease with depth.
One of these cases occurs when gas is injected at volumet-
ric flow rates high enough to cause friction loss. That is, as
the velocity of the gas increases inside the pipe, the pipe
resists the flow and friction develops between the gas and
the pipe walls. The effect of friction is particularly noticea-
ble in miniaturized casing (for example, 1'/4-inch nominal
tubing with 2.30-inch O.D. collars used inside 2.441-inch
I.D. casing).
Another example of friction loss occurs at high annular
(casing) fluid flow rates where gas is injected down the tub-
ing and into the annulus at a high rate for lifting purposes.
These high rate applications, such as in some Middle East
wells, can lead to a significant friction loss in the gas flow-
ing down the tubing. In the Gulf Coast area, the problem is
usually found in wells with small casing.
Gas pressure loss in miniaturized casing is made up of
two components: first, the friction caused by the gas flow-
ing between the pipe body and the small casing and, second,
the more serious problem of friction caused by gas flowing
between the tubing coupling (collar) and the casing. Often,
this small clearance (approximately O. 14-inch) causes a flow
restriction and loss of pressure similar to a choke (some-
times called gas stacking). The methods used to predict the
pressure loss inside the small casing are only approximate
because the non continuous outside diameter on the tubing
is difficult to model.
Usually, the pipe body diameter is assumed to be uniform
and the pressure (friction) loss with depth is calculated. An
estimate of the pressure loss due to the collars (stack-
ing) can be made. First, a pipe diameter equivalent to thetubing pipe body is used and the pressure profile is ob-
served. Second, a case is run with the diameter equivalent
to the collar outside diameter. This effect is observed and
results compared.
The effect of excessive friction loss on the gas lift valve
is a downhole gas pressure that is different from the value
used i n the design. Thus, the valve operation would be
erratic or perhaps the valves would prematurely close be-
cause the pressure at the valve is lower due to the choking
effect of the collars.
In a typical well, the gas profile will increase with depthbecause the weight of the gas increases the pressure. How-
ever, the exceptions are the cases just reviewed where signif-
icant friction losses actually result i n a pressure decrease
(with depth) because the friction loss is greater than the
weight-generated increase.
Since the typical well has negligible friction due to use
of large casing, the design requirement becomes one of
estimating the pressure at depth for the gas specific grav-
ity used in the system.
In most systems compressing low pressure separator gas
to injection pressure, the high pressure gas specific grav-ity will be from 0.7 to 0.8. When the reservoir fluid has
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A P I T I T L E + V T - 6 9 4 m 0732290 0532875 2T 5 m
42 Gas Lift
Pressure, PSlG
800 900 1000 1100 1200 1300 1400 1500 1600 1700
O
1O00
2000
3000
4000
5 5000
e 6000tl
7000
8000
9000
10 O00900 1000 1100 1200 1300 1400 1500 1600700
Fig . 4- 5- a s pressure profile with O. 7 SG Gas
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E + V T - b '74 m 0732290 0532876 L31 m
Gas Application an d Gas Facilitiesor Gas Lift 43
Pressu re, PSlG
800 900 1000100200300 1400' 1500 1600 1700
O
1O00
2000
3000
4000
5000Q)
,
e 6000
7000
8000
9000
10 O00900 1000 1100 1200 1300 1400500 1600 1700
Fig. 4-6- as pressure profile with 0.8 SC Gas
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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44
API T I T L E x V T - 6 74 m 0732290 0532877 078 m
Gas Lift
d
CDO
m eO
mO O
d d ò d
Gas Gradient , PSI/FT
l-
F
rr
(3
5e
a
2e
cv)v)
O
O
OO
(o
Fig. 4-7- nject ion Gas Gradients
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significant C4 to c6 components, the gas specific gravity at
injection pressure will be approximately 0.8. Gas sampling
at the injection gas meter and chromatograph analysis will
give a reliable gas gravity.
Figure 4- 5 shows gas pressure versus depth for a specific
gravity of 0.7 while Fig. 4.6 gives pressure versus depth fora specific gravity of 0.8. For other conditions, a gas gradi-
ent chart is shown in Fig. 4-7.
The graph can be used to estimate the gas gradient (psi/
ft) for use i n a gas pressure at depth calculation. Start
with the surface injection pressure (1000 psig), go to the
gas specific gravity (0.8), and read the gas gradient (0.041
psi/ft). At a depth of 5000 ft., the gas pressure would be
1000 +(0.041 x 5000) or approximately 1205 psig.
The user can read the figures at 0.7 and 0.8 gas specific
gravity or use the chart to estimate pressure gradient. This
pressure at depth is important to design and gas passage
calculations.
Flow Through the Gas Lift Valve
G as passage hrough a gas ift valve is the common
method for introducing gas into the fluid stream. If gas
flow through the valve is restricted, the density of the fluid
column (in continuous flow)will not be sufficiently reduced
or the slug (in ntermittent flow) will not be efficiently
displaced. Thus this flow hrough he gas lift valve is a
critical item. However, for the ow rate wells typical of some
Gulf Coast locations, gas passage has not usually been a
problem. For he high flow rate nternational oil fields,
valve gas passage characteristics are important to success-
ful operation of the well.
Gas passage through a particular valve is difficult to
predict. Some data, based n static probe tests nd dynamic
flow ests (mentioned i n the section on gas lift valve
mechanics), are available. However, this section will cover
differential pressure: that is, the differenceetween the gas
pressure at he ocation and the fluid pressure at he
same ocation, and the flow capacity of the valve as a
square-edged orifice. This orifice assumption is ot always
valid because the stem and the seat do not always have an
open area equal to a square-edged orifice.
Fig. 4-8t.4) - a s f l o w c a p a c i t i e s (0-9750 M CF /D ) fo r known upstream pressure, downstream pressure, and Orì-
fice s ize. Courtesy Cam co
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46
A P I T I T L E r V T - 6 79 m 0732290 0532877 940
Gas Lift
Differential pressure is the difference between the gas
pressure at the valve and the fluid pressure at the valve. A
high differential pressure drives he gas nto he fluid
column. Conversely, at a very low differential pressure,
sufficient gas cannot pass and enter into the fluid. Often a
minimum of 50 psi s used as a difference between the
operatinggaspressureand heproduction.However,
inability to accurately estimate the gas pressure at depthand the fluid pressure at depth can result i n a differential
less than 50 psi. Under such a condition, the well does not
unload, or the point of gas injection doesnot transfer, to the
next valve.
High gas flow rates through a valve demandigher injec-
tion gas pressure and higher differential pressure. At an
operating point, a minimum pressure differential of 100 to
200 psishould beusedbetween hegas and thefluid
columns for design purposes.
Gasflowcapacity is usuallyestimatedwith he
Thornhill-Craver equations for flow through a square-edge
orifice. A square-edge orifice s the device used i n positive
chokes for controlling the production from flowing oil
wells and gas wells. Accuracy diminishes when applied to
gas lift valves. However, the flow equation is usually the
best method readily available for estimating gas passage
through a valve orifice (port).
Charts such as shown in Fig. 4-8 (A) (B) and (C) havebeen prepared using the Thornhill-Craver equation. They
give he gas flow capacity for a known (upstream) gas
pressure, (downstream) fluid pressure, and port size (ori-
fice). These charts typically are based on a fixed tempera-
ture(usually60°F) and gasgravity(usually0.65).Gas
volumes must be corrected for other conditions.
Variations i n gas gravity and higher temperatures in the
well influence chart accuracy. If the gas emperature
approaches fluid flow emperature, volume flow rates
through the valve are less than the estimate obtained from
the chart. Because of this, downhole gas rates are usually
GA S THROUGHPUT IN MCFD
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E * V T - 6 9 4 m 07322900532880 bb2 m
Gaspplication and Gas Facilitiesor Gas Lift 47
corrected to the chart conditions before estimating the port
size requirement from the chart. Fig.-9 provides informa-
tion for correcting thegas volume to other conditions of gas
gravity and temperature.
The restriction to gas flow through a gas lift valve is
caused by a port being only partially open. A reduction in
the gas pressure outside the bellows causes the stem to startto close in response to the itrogen pressure force inside he
bellows. As the valve goes from a full-open position to a
closed position, the effective orifice (port) area never cor-
responds to a completely full-open square-edge orificehat
is the basis for the Thornhill-Craver charts unless thevalve
is full open.
This restriction to gas flow may affect unloading opera-
tions and the well may not operate according o initial
design. The small gas passage rate prevents aeration of the
fluid column or prevents slug formation for intermittent lift-
ing. The user of the charts should be aware that a gas lift
valve probably does not have the exact gas passage charac-teristics indicated on the chart. Efforts areunderway within
the industry to correct this problem and one valve manufac-
turer has published empirically determined dynamic valve
performance data for its continuous flow valves.
G A S THROUGHPUT IN MCFD
Fig. 4 - 8 ( C )- as f low capacities (0-20,000 M C F / D ) f o r known upstream pressure, downstream pressure, and ori-fic e size. Courtesy F: í? ocht
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
Not for Resale, 07/27/2006 10:42:36 MDTeproduction or networking permitted without license from IHS
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A P I TITLE*VT-6 94 W 0732270 0 5 3 2 B B L 5T9
Gas Lift
300
280
200
240
290
zoo
1ao
160
140
12 0
1O 0
60
60
40
.@O
BA818:
Correction Factor =0.0644
Where: G =Ga8 Gravity (Air =1.0)
T =Temperature, O R .
36 1 o0 1 O6 1.10 1.16 1.20 1.26 1.30
CORRECTION FACTOR
1.36 1 i o 1 i 6 1.50 1.1
Fig. 4-9- orrection facto r chart for gaspassage charts. From Camco Gas Lift Manual
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E * V T - b 74 0732270 0532882 435 m
Gaspplication and Gas Facilities for Gasift 49
SURFACE GAS FACILITIES
System Design Considerations
Gas lift wells are not the only component, they are part
of a gas lift system that includes the reservoir, flowline,n-
jection line, separators, treating facilities, compressorsndmeters. Maximum production, effective use of gas, and low-
est investment and operating expense resultwhen the entire
system is planned properly.
Current computer technology provides methods to ana-
lyze systems so that the“best” values for separatorpressure,
injection pressure, flowline size and tubing casing size can
be selected. Gas requirements now and for the future can be
estimated. The money spent for computer technology is
repaid by higher production rates, fewer operating prob-
lems, and lower investment. However, investment for gas
lift facilities depends on gas source nd quality.A good source for gas lift gas is a constant pressure, dry
gas such as hat obtained from a gas processing (NGL)
plant. This gas source is good because the pressure is con-
stant and the gas canbe compressed to a higher pressure, if
necessary. Secondly, a dry gas without hydrocarbon liquid
and water reduces operational problems such as corrosion,
hydrate formation (frozen water and hydrocarbons), and
liquid drop-out (condensation) accumulating in low spots
i n the line. If other sources must be used, such as gas well
gas or separator gas, then any one of a number of pro-
cesses such as compression, dehydration, hydrocarbon pro-
cessing or sweetening might be required before transport-ing the gas to the wells.
The gas distr ibution system can be one of two basic
designs: (1) A direct connection from the compressor sta-
tion to each well, and (2 ) A main trunk line with individual
distribution headers to local wells.
The advantage of a direct connection system is that any
pipeline problem affectsonly one well. It s very useful for
small systems that have aimited number of wells and short
pipelines. The second, or runk line, method is applicable to
large land or offshore (remote wellhead platform) systems.
It provides local distribution to each well and permits sev-eral compressor stations to be connected in parallel so that
the loss of any one station does not shut down the entire
system. With such a system gas is made up from the other
stations (provided hat sufficient compression capacity
exists) when one partof the system is down for any reason.
A modification to the main trunk line system s the use of
a distribution ring so that gas can flow to a local distribu-
tion header from either direction.At the take-off point, the
distribution header sends the flow to each well through a
directly connected pipeline. This trunk line or ring method
typically minimizes nvestment requirement for a largeield
area because the main trunk line is less expensive than a
large number of individual lines. However, major field stud-
ies should include a comparison of the economics of each
method since the cost of pipe and installation varies with
the location.
Gas Conditioning
Water Vapor andhe heavier gashydrocarbons will condense
i n a distribution system and cause either hydrates (freezing)
or liquid slugging. Sometimes the heavy hydrocarbon com-
ponents must be removed by local field processing.
A refrigeration system, ora compressionlexpansion cooling
method, can be used to cool the gas stream and condense
the liquid hydrocarbons. Only a very rich gas composition
causes iquidhydrocarboncondensation.Typicalsitua-
tionswhere hisoccurs are: (1) separation at very owpressures where the gas stream going to compression has a
high fraction of heavy hydrocarbons, (2) where cold envi-
ronmental emperatures cool he gas and condense he
heavy elements. Hydrocarbon removal may not be neces-
sary in all cases but water should always be removed for good
system performance.
A cooling facilityo remove hydrocarbons often removes
a significant amountof water vapor i n th e gas. If a process-
ing acility sunnecessary, then gasdehydration with
trimethylene glycol absorption is most commonly used to
remove the water vapor from the gas stream.
Water i n a gas lift system causes corrosion, liquid slugs,
and hydrates. However, when sour gases are not present,
the gas does not have to be “bone” dry. If no sour gases are
present, the acceptable amount of water is usually set by
the operator, using an estimate of lowest possible gas tem-
peratures on cold winter nights.
The lowest anticipated temperature can be used to pre-
dict hydrates with the Katz curves, Fig. 4-10. If “freezing”
occurs at the lower temperatures, water removal (105 lb Imillion scf gas) can be estimated, Fig. 4-11. For example,
at 1000psia and 120”F, the water content is 105 lb / million
scf gas. At a “freezing” (hydrate) conditionof 40°Fand 1000psia, the water content is 9 lb / million scf. Dehydration
must remove 96 lb / million scf for the gas to flow at 40°F
without “freezing.”
If the“freezing” emperatureoccurs nfrequently,
methanol can be injected for a limited time until the gas
temperature rises above th e “freezing” point. Methanol
(and other liquids) depresses the “freezing” temperature.
Catalytic heaters may also be used at input chokes or other
points where gas expands and cools below the “freezing”
temperature. These methods can reduce the size of he
requiredglycoldehydration ystem llustrated i n
Fig. 4- 12.
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API T I T L E * V T - 6 94 0732290 0532883 371 m
Gas Lift
Gas with excessive carbon dioxide (COZ)or hydrogen
(HzS) can cause operating problems such as corro-
nd fuel contami-
also potential safety hazards.
of sweetening facility, appliedwhen gas cannot be
in the field, extractsboth C 02 and H zS (sour acid gas)
n this system, the amine
are contacted by the gas flow stream nd the acidconstituents are extracted. The sweet gas returns o
solutions are treated remove
C 02 and H2S.
When proper inhibition systemsand metallurgy are used
in the gas lift and well facilities, gas with H2S and or CO2can be used provided a good glycol dehydration facility
removes he water vapor. However, careful monitoringshould be used to assure that such systems are functioning
properly at all times.
Reciprocating Compression
The reciprocating compressor is very flexible machine
in gas lift applications and has proven very popular over
EXAMPLE:
l . Gas at 1000psia, 70”F,0.7
sp. gravity does not “freeze”
(this point is just elow the hydrate-formation condition for0.7sp. gr. gas)
2. Gas at 1000 psia, 40 ” F,0.7sp. gravity will “freeze”
F i g . 4-10- ydrate- formation condi t ions for natural gas . Katz , e t a l . , Handbo ok of Natural Gas Engineer ing
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
Not for Resale, 07/27/2006 10:42:36 MDTeproduction or networking permitted without license from IHS
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Fig
A P I T I T L E * V T - 6 94 m 0732290 0532884 208 m
Gas Ad ic a t i o n and Gas Faci li ti es fo r Gas L i ft
1.Gas at 1000psia, 120"F
has a water Content Of
105Ib/million scf
2. Gas at 1000psia, 4'O°Fhas a water Content Of
9 Ib/millionscf
-70 -60 -50-40 30-20-10 O 10 20 3040 60 80 100 120 140 160 200 230 260 300 400 500 600 700
Temperoture, deg F
Water content of natu ral gar in equilibrium with liq uid water.
. 4-11 - ater contentof natural gas in equilibrium with water. Katz, et al., Handbook of Natural G a s Engine
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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52 Gasift
he years in most Gulf Coast systems. Reciprocating compres- rate. Curves in Fig 4- 3 can be used to estimate horsepower
sion is typically used where a low suction pressure as must requirements. The estimating technique requires an overall
be compressed to a igh discharge pressure and the volume compression ratio (discharge absolute pressure divided by
f low rate is sufficiently ow hat a centrifugal machine suction absolute pressure) and a breakdown of this ratio
would not apply. Reciprocating compressors are capablef into stages. Typically, the compression ratioper stage should
handling varying suction discharge pressures and changes be between 2.0 and 3 . 8 . Higher ratios tend to raise the dis-
n gas specific gravity or gas flow rate. charge temperature in the compressor cylinder to a value
These compressors can be skid-mountednd installed on
ocation quickly then moved when service is terminated.
h speed-skid mounted units typically have a separa-
1000rpm engine of 1500(or less)
The larger, low speed, ntegral units (power
n stations with numerous support utility systems. These
rpm units are available i n sizes up to 3000 horsepower.
The drivers for the compressors are usually gas engine
but may be electric motors f the proper voltagepower
reciprocating compressors attain
rate flexibility (and field desirability) by unloading
ends or by adding clearance chambers (bottles).
primary limitation is their low throughput gas vol-
f i t th e application.
Horsepower will depend on the pressure change from
to discharge, gas specific gravity, and throughput
that causes maintenance problems. The horsepower is read
from the curves (given a compression rationd gas specific
gravity) as an uncorrected horsepower permillion cubic feet
of gas compressed. Horsepower read from the curves is
corrected using the temperature and deviation factors of the
gas at actual flowing conditions. These curves, along with
a more detailed description for estimating compressor orse-
power, are contained in the GPSA Engineering Data Book
(see reference number 32.)
Centrifugal Compression
Centrifugal compressors are more popular where higher
throughput volumes are required. A centrifugal compres-
sor is a high speed rotating machine driven by a turbine or
an electric motor that also operates at high rotating speeds.
The centrifugal compressor can ake the gas from a ow
Fig. 4-12- lycol Dehydrat ion Uni t- ourtesy of PETEX
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A P I T I T L E a V T - 647 3 2 2 9 05 3 2 8 8 6 080 m
G aspplicat ionndasacil i t ies for G as Lift 53
EXAMPLE:
l . Suction Pressure =55 psia (40psig)
2. Discharge Pressure=1250 psia (1235 psig)
3. Overall CR = 1250/55 =22.7
4. Brake HP/million CU. ft. 195
(This is gas compression only.
Need additional HP for coolers/pumps)
5. See GPSA for temperature and Z factor correction
6. Use3 stage machine to keep discharge temperature
lower and reducemaintenance problems.
A p p r o x i m a t epo wer equ i red o compress gases
Fig. 4 - 1 3 -Approx imate Horsepower Required to Compress Gases. GPSA-Engineering Data Book
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
Not for Resale, 07/27/2006 10:42:36 MDTeproduction or networking permitted without license from IHS
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A P I T I T L E x V T - 6 94 0732290 0 5 3 2 8 8 7L 7
54 Gas Lift
an electric motor that also operates at igh rotating speeds.
The centrifugal compressor can take the gas from a low
suction pressure through a discharge pressure adequate for
gas lift injection purposes if the throughput volume is ad-
equate for the machine and if multiple compressor wheels
with interstage cooling are used.The centrifugal machines,
because of their high rotating speed, can develop a signifi-
cant amount of horsepower and yet be a physically small
package as compared o reciprocating compressors. In
addition, they do not have the massive frames of the recip-
rocating machines, nor do they have the vibrations detri-
mental to offshore platform facilities.
One critical point in centrifugal compression: the com-
pressor wheels do not operate satisfactorily at conditions
significantly different han nitial design. Fo r example,
assume the gas specific gravity drastically changes because
of gas flow stream alteration. Theachine may operate at a
very low efficiency or perhaps not at all. Thus, he user must
be very conscious of changes that might alter either specific
gravity, temperature, or pressure of the gas.
Horsepower estimates are based on the overall compres-
sion ratio, pressure, temperature,nd specific gravity of the
gas. The methods, for making these nitial estimates are
contained in the GPSA Engineering Data Book section on
centrifugal compressors.
Piping and Distribution System
Piping, separation, cooling, dehydration, and compres-sion, all must be designed logically to minimize investment
and yet provide good operating and maintenance qualities.
One of the main requirements in gas handling facilities is to
provide separationand scrubbing that preventsiquid carry-
over nto a compressor. Typically, both nlet separation
and suction scrubbers are necessary. Manifold suction
headersshouldminimizepressure osses to 1psi.The
suction discharge pulsation bottles for reciprocating com-
pressors must be designed to dampen pressure pulses as
well as withstand vibration (to prevent cracks dueo vibra-
tion). An adequate discharge delivery system, away from
the compressors, is required in order to feed gas to down-stream coolers and separators prior to glycol dehydration.
The glycol system should contain heat exchanger cooling
between the gas stream and the glycol as well as a method
for easy access and maintenance of the glycol reboiler. Gas
distribution piping should also contain facilities for liquid
removal.
The need for later liquid removal may be avoided by
not putting liquid into a gas system. For example, during
system testing (after construction) a nitrogen purge and
nitrogen pressure test can be used rather than water (how-
ever, tests with water are safer). Another example is iquid
hydrocarbons or water. Where water is used for testing, a
Methanolflushcanbeused oremoveanywater hat
remains in thesystem. The system design should also
include cooling and dehydration processes thatwould elim-
inate liquid condensation in the system. Even with these
precautions, liquid removal taps should be located at con-
venient low elevation spots in the station or in the pipeline
distribution system. Frequent pigging may also be required
to remove water standing in low spots.
Gas Metering
Orifice meter measuring of gas lift gas is one of the easiest
and most inexpensivemeasurementmethods.However,
othermeanssuchasvortexsheddingmeters, urbine
meters, or positive displacement meters can also be used.
This discussion will be limited to the use of orifice meters
with either chart recordersor flow computers since hey are
the most commonly used devices for measuring gas. The
orifice can be used to measure gas because the flow rate f
gas is proportional to the differential pressure across the
orifice plate. The higher he flow rate hrough a given
orifice size, the greater the differential pressure across th e
orifice. Rate estimating examples in the GPSA book pro-
vide this calculation information. Fig. 4-14 shows GPSA
nomenclature used in these calculations.
The typical method for recording the flow rate hrough an
orifice is to use the chart recorder. Charts can be either
square root chartsor standard charts but square root charts
are most commonly used. Two readings from the square
root chart are used instead of the actual gas pressure at h e
meter and the differential pressure across the orifice. The
differential reading can be set and adjusted by an adjust-
able choke placed just downstream of th e meter. Differential
reading, pressure reading, emperature, specific gravity,
orifice size, and other factors areused to calculate the flow
rate (Fig. 4-15). The square root chart equation is:
Qg (thousand scf/d) =Cp x Ch x (24 Hour Coefficient)
Equation 4.6
Where,
Cp=Gas pressure reading for a square root chart
Ch =Gas differential reading for a square root chart
24 Hour Coefficient = A cons tant ca lcul ated fo r the
meter tube, orifice plate,
temperature and gas specific
gravity.
The flow rate is proportional to changes in the differential
reading, making this an easy method for estimating gas
throughout and adjusting the choke.
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A P IT I T L E * V T - 6 9 4 W 0 7 3 2 2 9 0 0532888 953 W
Intermittent Flow Gas Lift 55
a =
A =
P =
C' =
CNT =
CpI =
c,, =
c, =
Ctl =
c,, =
d =
D =
e =
E =
F =
F, =
F b =
Fg =
Fgt =
F w l =
F, =
F,, =
F p b =
F p m =
Fpv =
F, =
F, =
maximum transverse dimension of a straighteningvane passage
cross sectional area of any passage within an as-sembled straightening vane
ratio of the orifice diameter to the internal diameterof the meter run, dimensionless
the product of multiplying all orifice correctionfactors
volume indicated by th,e number of pulses or counts
liquid pressure correction factor. Correction for thechange in volume resulting from applicationof pres-sure. Proportional to the liquid compressibility fac-tor, which depends upon both relative density andtemperature. See API, Manual of Petroleum Mea-surement Standards, Chapter 12 , Section 2
correction factor for effect of pressure on steel
gravity correction factor for orifice well tester tochange from a gas specific gravity of 0.6
liquid temperature correction factor. Proportionalto the thermal coefficient which varies with densityand temDerature
F, = steam factor, mercury meter
Fsl = seal actor or iquid.Appliedonly to mercury
F t b = temperature base factor. To change the temperature
Ftf = flowing temperature factor to change from the as-sumed flowing temperature of 60 "F to the actualflowing temperature
F = temperature correction factor applied to displacementmeter volumes to correct to standard temperature
G, G I = specific gravity at 60 "F
meters
base from 60 "F to another desired base
Gf = specific gravity at flowing temperature
H = pressure, inches of mercury
h, = differential pressure measured across the orifice
h, = differential reading on L-IO chart (see p. 3-42)
h, = differential pressure measured across the orifice plate
dh,pr = pressure extension. The square root of the differen-tial pressure times the square root of the absolute
plate in inches of mercury at 60 "F
in inches of water at 60 "F
correction factor for effect of temperature on steel
orifice diameter, in.
run, in .
orifice edge thickness, in. meter
static pressure
cific heat at constant volumek = ratio of specific heat at constant pressure to the spe-
pipe diameter (published) Of Orifice meter K = a numerical constant. Pulses generated per unit vol-
urne through a turbine or positive displacement
orifice plate thickness, in.
liquid compressibility factor
orifice thermal expansion factor. Corrects for the
metallic expansion or contraction of the orifice plate.Generally ignored between O" and 120 "F
basic orifice factor
specific gravity factor applied to change from a spe-cific gravity of 1.0 (air) to the specific gravity of
the flowing gas
gravity temperature factor for liquids
gauge location factor
manometer factor. Applied only to mercury meters
L = length of straightening vane element
M = meter factor, L-10 charts
MF = meter factor, a number obtained by dividing the
actual volume of liquid passed through the meterduring proving by the volume registered by themeter
P = pressure, psia
Pf = static pressure at either the upstream or downstream
P, = pressure reading on L-10 chart
Q = gas flow rate, C U ftlday
Qh = rate of flow, usually in CU ft/hr or gal/hr
pressure tap, psia
units conversion factor for pitot tubes Rh = maximum differential range, in. of water
pressure base factor applied to change the base pres- R, = maximum pressure range of pressure spring, psi
sure from 14.73 psia
pressure factor to meter volumes to 'Orrect Tb = absolute temperature of reference or base condition,to standard pressure
supercompressibility factor required tocorrect for Tf = flowin g temperature,deviation from the ideal gas laws = d 1/Z
Reynolds number factor. To correct the calculatedbasic orifice factor to the actual flowing Reynoldsnumber YCR = critical flow constant
steam factor Z = compressibility factor
S = square of supercompressibility
"R
Y = expansion factor to compensate for the change indensity as the fluid passes through an orifice
Fig. 4-14- PSA Nomenclature used in gas metering
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A P I T ITLE*VT-b 9 4 0732290 0532889 8 9 T
56 Gas Lift
The flow computer, an electronic device, is sometimes used lated in cubic feet (or some multiple) much like a positive
tocalculategas ate. tca ndisplay hevalueas a displacement counter. This totalizer method measures the
cumulative amount or provide an instantaneous rate read- cubic feet of gas input into the well for any lapsed time, be it
ing. The device has dials that can be adjusted by the a six-hour test, a four-hour test, or a seven-day period. This
electronicsspecialist to correspond to temperature, meter feature is extremely useful for both short term as well as
tub e, or if ice diameter , and spe cifi c gravity factors. long erm analysis of the well because well testing accuracy
Although he flow computerdisplays the flow ateasa is improved.
percent of full scale, more importantly, the volume is tabu-
?f '
rIo
Lo
(See Figure 4-14 for GPSA Nomenclature usedn thissection)
EXAMPLE GASRATE (Factors from GPSAl
Q (thousand scf/d)=hu*Pu*24our Coefficient
1.
2.
3.
4.
5.
6.
7.
8.
Gas Pressure at Meter (Pr) =888 psig from Pg atMeter=(hu)2Rp/lO0 - 14.7
FPV=1 O98fromZ =0.83 for Pt=888 psig, Tt=1O0 "F
Fb=21 0.22from orifice =1.000, meter tube =2.067
Ftf=0.9636fromT, =100" F
Fg=1.1547from Gf =0.75 (Gas SP. GR.)
M =3.162from Rh=100R p = 1000
24 Hour Coeff =0.024.Fpv-Fb-Ftf*Fg.M = 19.5
Q =9.5.6.5.19.5 =1200 (thous. sCf/d)
Fig. 4-15- xample problem square root (L-IO) chart.
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A P I T I T L E m V T - b 74 m 0732270 0532890 501 W
Gas Lift Valves 57
CHAPTER 5GA S LIFT VALVES
INTRODUCTION
The heart of any gas l ift system is the gas lift valve. Gas lift
valves are basically downhole pressure regulators. The func-
tional elements of a pressure regulator and a gas ift
valve are similar. A spring in the regulator (Fig. 5-1A), as n
the gas lift valve (Fig. 5-1B), forces the stem tip against the
seat. The diaphragm of the pressure regulator and he
bellows of the gas lift valve provide an area of influence
for upstream pressure greater han he port area. The
force that results from this combination of upstream pres-
sure and diaphragm or bellows area acts in a direction to
overcome the force of the spring. When this force of pres-
sure times area exceeds the force of the spring, the stem tip
moves away from the seat, opening the valve. Both the pres-
sure egulatorand hegas l i f t valve llustratedare
controlling the upstream pressure. The regulated upstream
pressure is a function of spring force and effective dia-
phragm or bellows area. Practically all gas lift valves use the
effect of pressure acting on the area of a valve element
(bellows, stem tip, etc) to cause the desired valve action. A
knowledge of pressure, force, and area is required to under-
stand the operation of most gas lift valves. API Spec. llVlS0
covers the manufacture of gas l ift valves.
DIAPHRAGM /
DOWNSTREAM
Pressure regulator
(A )
Gas
Fig. 5-1-
lements of a Pressure Regulator and a Ga s Lift
+" UPSTREAM
lift valve
(B )
Valve
VALVE MECHANICS
Pressure is force per unit area. The commonoil field uni t Force (Pounds) =Pressure (psi) x Area (sq. in.)
of pressure is pounds per square inch (psi). Thepound is the
force and one square inch is the unit area. As the value ofpsi If A = in .
changes, the force changes (not the one square inch of area).
If a pressure and area are known (Fig. 5-2).,the total force
(F) action on the entirearea is found by multiplying the pres-sure times the area (A). Then F =10 x 3 =30 Pounds
AndP =10 psi Equation 5.1
F = P x A
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A P II T L E x V T - h 94 0732290 0532871 448
8 Gas LiftnA
1
tF
Fig. 5 - 2- orce Diagram
No p is ton seal
(A)
DOME
PISTON
STEMTI P
PORT
Basic Components of Gas Lif t Valves
Most valve designs use the same basic components. The
arrangement of the components may vary. The basic valve
(Fig. 5-3C) usually includes a bellows, a chamber (dome)
formed by one end of the bellows and the wall and end of
the valve, and a port that is opened or closed by a stem tip.
The stem tip is larger than the port and is attached to thebellows by the stem.
All of the illustrations in Fig. 5-3 have the same basic
components. The piston in Fig. 5-3(A) has no seal, so the
dome cannot be isolated. In Fig. 5-3(B) , the piston has an
O-ring seal. Fair isolation of the dome is obtained with the
O-ring. Small leakage by the O-ring over long periods and
friction of the O-ring cause this form of piston sealing to be
impractical. A metal bellows forms the seal in Fig. 5-3(C).
The lower end of the bellows is welded to a solid plug. The
upper end of the bellows is welded to the valve. Convolu-
tions (wrinkles) i n the bellows provide he flexibilityrequired for movement. A bellows type seal is used in the
majority of gas lift valves.
O-Ring p is ton seal
(B)
Bel lows p is ton seal
(C)
Fig. 5 -3- asic G as Lift Valve Components
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A P I T I T L E x V T - b 94 0732290 0532892 38 4 m
Gas Lift Valves 59
Closing Force
Many gas ift valves (Fig. 5-4) have gas pressure (Pb)
trapped in the dome. This pressure acts on the area of the
bellows and creates a force (Fb) that is applied to the stem.
The stem tip is forced into contact with the upper edge
(seat) of the port. The stem tip and seat portion of the port
are finely matched (often lapped) to form a seal. When the
dome pressure (Pb) and bellows area (Ab) are known, the
force holding the stem tip against the seat is:
F, = Pbb Equation 5.2
F, = Closingorce.
Pb = Pressure inside the dome space sealed by the
bellows and valve housing.
Ab = Area of the bellows.
Schematic
(B)
Fig. 5-4- losing Force Diagrams
Opening Forces
A valve (Fig. 5 - 5 ) starts to open when the stem tip moves
out of contact with the valve seat. This occurs when the
opening force is slightly greater than the closing force,
therefore, just before opening (Fo= R). Two forces usually
work together to overcome the closing force (Fc). Pressure
(P I) applied through the side opening and pressure (PZ)
applied through the valve port are the pressure sources toproduce the two opening forces.
When the stem tip is seated on the port, PI does not act
on the entire bellows area (Ab). The area of the stem tip (A,)
in contact with the seat (Fig. 5-5A) forms part of the bel-
lows area (Ab).A, is isolated from PI by the stem tip and
seat. The area acted on by pressure PI is the bellows area
minus the area of the stem tip isolated by the seat (Ab-A,).
The opening force resulting from pressure PI applied through
the side opening is:
Fol =PI (Ab - Ap) Equation 5.3
The area of the stem tip in contact with the seat (A,) is acted
upon by pressure (Pz) applied through the port. The open-
ing force contributed by this combination is:
F02 =P2p Equation 5.4
The total opening force is the sum of these two forces:
F" =F n I +Foz Equation 5.5
Fo =PI (Ab - Ap) +P2Ap Equation 5.6
Just before the valve port opens, the opening force and
the closing force are equal.
F, =F, Equation 5.7
PI(Ab - Ap) +P2Ap =Pb& Equation 5.8
Solving fo r PI (injection pressure required to balance
opening and closing forces prior to opening an injection
pressure operated valve under operating conditions. Fig.
5-5A):
PI (Ab - Ap) =Pbb - P2p Equation 5.9
Divide each term by Ab:
Ratio of port area to bellows area.
(Obtained from manufacturer's specs.)
Divide both sides by 1 - A,:
Ab
-
-Pb - P2ApAb) Equation 5.11
-1 - (A, /Ab)
Is the pressure in contact with the valve bellows.
Is the pressure in contact with that portion of the
stem tip sealed by the seat (port).
Is the area of the portion the stem tip sealed by
the seat.
Opening force resulting from PI acting on he
bellows area less the port area (Ab - Ap).
Opening force resulting form PZ acting on the
stem tip area in contact with the seat (port).
Total opening force.
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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API T I T L E t V T - 6 94 0732290 532893 210
Gas Lift
P ictorial
(A ) Schematic
(B )
Fig. 5 - 5- pening Force Diagrams
The pressure ( P I ) determined by this equation s he
is still on seat
ight leakage by the stem tip and seat may be
in P I or PZ will move the stem tip
further from the seat and allow more gas
A decrease in PI or P2 will load the stem tip harder
a tighter stem tip to seat seal. This
case as the valve closes.
Valve Load Rate
One definition of load rate is the measure of the amount
pressure required for each inch of valve stem
ihnch). The reciprocal of the load rate, inches of
vel per psi of opening pressure (inchedpsi) , is
The compressibility of the nitrogen charge in the dome
rate of the bellows (load increase per unit
, prevents rapid full opening of most valves. SlightPI or P2 normally cause only slight additional
PI or P2 depends upon the volume of the dome and the
bellows. These two conditions can vary
as well as between valves of differ-
styles, made by the same manufacturer. A “stiff’ valve
or decrease in P I or PZ. “soft” valve
have greater opening or closing stem travel changes
to the same increase or decrease in PI or P2.
a particular valve design.
Probe Test
A probe test of gas l i ft valve will establish the load rate
of the valve. In addition, it establishes the maximum stem
tip travel (to mechanical stops) and discloses stacking of the
convolutions, excessive friction, and bellows yielding.
The valve probe test consists of attaching a depth type
micrometer o a valve i n a fashion hat will allow he
measurement of the stem tip displacement from the valve
seat while pressure is applied. Pressure is incrementally
applied above and below the stem tip in contact with the full
bellows area. A displacement measurement is taken at each
pressure increment.
Production Pressure Effect
As discussed earlier, the valve (Fig. 5-5A) is opened by
the forces of PI acting on the area of the bellows less the
area of the port (Ab-
Ap), and PZacting on the stem tip areathat is sealed by the seat. Without P2 to assist opening, P I
would have to be somewhat greater. The Production Pres-
sure Effect (PPE) represents the amount that the opening
pressure (PI) is reduced as a result of the assistance of PZ .
PPE (sometimes referred to as tubing effect) is obtained
by multiplying production pressure (Pz) by the area over
which it is applied (Ap) and dividing the force obtained by
the area (Ab - AP) overwhich the valve opening pressure (PI)
acts. The result obtained is the amount the valve opening
pressure ( P I ) s reduced in psi.
Pictorial Schemat ic
Fig. 5-6 - losing Pressure Diagrams
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Equation 5.12
Equation 5.13
Equation 5.14
The ratio is called the Production(1 - Ad&)
Pressure Effect Factor (PPEF). ome texts refer to this ratio
as Tubing Effect Factor (TEF).
If the PPEFs reported as a decimal,
PPE= Pz PPEF Equation 5.15
And, if reported as a percentage,
PPEF Equation 5.16
1O0PPE = P2-
Closing PressureThe closing pressure of the valve (Fig. 5-6) will be equal
to the injection gas opening pressure (Pl) if the production
pressure remains constant. The minimum closing pressure
is equal to the dome pressure (Pb) only at a time when the
production, injection and dome pressure are equal.
VALVE CHA RA CTERISTICS
Dynamic Flow Test
A dynamic flowest consists of flowing gas through a gas
l i f t valve and measuring the gas passage at different pres-
sure conditions. Information obtained from the dynamic
flow test and the probe test for a particular valve are used
together to predict gas passage and valve action at condi-
tions other than test conditions.
Fig. 5- 7 represents data that were plotted from a typical
dynamic flow test of an unbalanced single-element bellows-
charged gas lift valve. Injection gas volumetric throughput
is plotted against flowing production pressures using aconstant injection pressure of 535 psig and 550 psig. Valve
specifications and performance test conditions are included
in Fig. 5-7. The curve shows thato gas flows at each of two
distinct production pressure values for each injection res-
sure. One, at a production pressure equal to the injection
gas pressure of 535 and 550 psig. At this point the valve is
open, but th e lack of an injection pressure to production
pressure differential prevents gas low. The second point of
no flow is at a production pressure f 218 and 29 4 psig. This
is the production closing pressure of the valve.
Valve Spread
Spread is the difference between opening and closing
pressure of an injection pressure operated gas lift valve
when its primary opening and closing action is controlled
by changes in injection gas pressure. It is obtained by
subtracting the closing pressure from the opening pressure.
Valve spread controls the minimum amount of gas injected
into the tubing during each cycle i n an intermittent gas lift
installation. Even if surface injection gas is stopped after
the operating valve is opened, the pressure in the annulusmust bleed down from the opening pressure to the closing
2 3 4 5 6
F l owi ng P roduction Pressu re - 100 p s i g
Gas Lift Valve Specifications:Effective Bellows Area =0.77 sq. in.Ball O.D. on Stem =0.625 inchesPort I.D. =0.41 inchesAngle of Tapered Seat =45"
Performance Tests:Constant Injection as Pressure=535and550psig
Test Rack Closing Pressure =485 psigSlope of ThrottlingRange =9.3 Mscf/Day/psi'ApPf
Fig. 5-7-
as lift valve dynamic f low test(Courtesy Teledyne Merla)
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A P I T I T L E w V T - 6 94 0732290 0532895 093 9
62 Gas Lift
pressure of the valve. Depending upon the spread of the
valve and the volume of the annulus, the amount of gas in-
jected during bleed-down may be more than is required for
efficient operation. In an intermittent lift well, the valve
spread should be set so that the amount of gas injected is
less than the minimum required to move the slug to the sur-
face. At somesubsequent ime, heamount of gas
injected into the tubing can be increased by injecting gas
into the annulus at the surface while the valve is open.
Bellows Protection
The bellows in a gas lift valve extends and or compresses
to provide movement of the stem tip to open or close the
valve. It is common for the bellows to be exposed to exter-
nal pressures significantly higher han normal operating
pressure. To prevent damage to the bellows during period
of over pressure, all gas lift valves incorporate some form of
bellows protection. Some of the techniques incorporated are
as follows:
1. Limit bellows travel.
a. Mechanical tops.
b. Hydraulic stop using a confined liquid.
2. Reinforce bellows with support rings.
3 . Hydraulically reform bellows convolutions at higher
than normal external pressure.
4. Isolate bellows to prevent exposure to excessive pres-
sure differentials.
When a gas lift valve opens, pressure in the vicinity of the
control elements (bellows and port) can fluctuate due to the
dynamics of flow. These fluctuating pressures can result in
valve chatter. Chatter is a sustained high opening and clos-
ing cycle rate. Chatter can alter the bellows' physical char-
acteristics, resulting in changes of the valve's opening and
closing pressures. If not controlled, chatter will usually
cause damage to the ball and seat, and can rapidly result in
fatigue failure of the bellows. Hydraulic dampening (dash
pot) is a common means of preventing chatter.
Test Rack Opening Pressure
The design of a gas lift system establishes the desired open-ing and closing pressure of a valve.Valvesmustbe
adjusted in a shop test rack (Fig. 5-8) to an opening pressure
that will give the desired opening pressure in the well.
Gas inside the fixed volume dome of a pressure charged
valve will ncrease in pressurewhenheatedandwill
decrease in pressure when cooled. The pressure change that
occurs as a result of heating or cooling the fixed column of
gas can be calculated. (See Temperature Corrections, Chap-
ter 4, nd Table 4-1.)
It is not practical to set a valve to the required opening
pressure at the temperature the valve will be operating in
t h e well. Although any reasonable temperature could be
.PRESSURE
SOURCE, (P,)
F ig . 5-8- es t ruck
used as a reference for adjusting the valve in the test rack,
most of this work is done at 60*E In practice, a bellows
charged valve is submerged in water maintained at 60°F
prior o adjusting he opening pressure o he required
value. A spring oaded valve does not require cooling
before setting the test rack opening pressure.
The opening pressure (PI) of a particular valve in the
well, under operating conditions, is defined by the gas lift
design. The design also specifies the production pressure
and the temperature at the valve when it opens. The open-
ing pressure (PI) of the valve has been defined as follows:
Pb1 - PZ &/Ab)
PI = Equation 5.171 - (Ad&)
Note: In this equation, the generalized expression (Pb") for
the pressure inside the dome has been replaced with
the bellows charge pressure (Pbt) at well temperature.
This equation can be rearranged to determine the valve
charge (dome) pressure (PbI) required to obtain the speci-
fied opening pressure (PI),
Pbt =PI (1 - Ad&) +P2 (Ad&) Equation 5.18
The dome pressure (Pbt) in this case is at the temperature
of the valve in the well.
Before obtaining the test rack opening pressure, the
dome pressure (Pb,) must be corrected to he est rack
temperature of 60°F (Pb1 @ 60°F). (See Temperature Cor-
rections, Chapter 4, nd Table 4- .)
The opening pressure (PI) equation with Pbv @ 60°F and
the pressure P2 of O psig applied over the seat area at test
rack conditions (Pvo)becomes:
Pbv @ 60°F
P"" - 1 - (AdAb)Equation 5.19
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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API T I T L E * V T - b 94 0732290 0532896 T 2 T
Gas Lift Valves 63
TYPES OF GAS LIFT VALVES
Classification of Gas Lif t Valves b y Application
In the well, a valve is exposed to two pressure sources
that control its operation. One is located in the tubing and
the other in th e casing. The valve is physically positioned
between the two pressure sources.Both of the pressures aretrying to open th e valve. When the injected lift gas is in
contact with the bellows (largest area of influence), the
valve is called an injection pressureoperated valve (Fig. 5-9
A&B) . When the produced fluid is i n contact with the
bellows, the valve is referred to as a production pressure
(fluid) operated valve (Fig. 5-10 A&B). The valve may be
identical n either case. As seen in the llustrations, the
receptacle (mandrel) can control how the two pressure
sources are ported to t h e valve.
All calculations (opening pressure, closing pressure, etc.)
fo r a production pressure (fluid) operated valve are he
same as those or an injection pressure operated valve. It is
necessary to insure that the action of the two pressure
sources on the valve elements is properly represented.
The opening pressure for the injection pressure operated
valve (Fig. 5-9 A&B) has been determined to be:
Pbt - P2 (Ap /Ab)
1 - (Ap Ab)Pl = Equation 5.17
Injection pressure ( P I ) acts on the largest area of influ-
ence (Ab - AP )and production pressure (P2) acts on the area
of the port (Ap).
Productionup theubingProduction uphe annulus
(A ) (B)
Fig. 5-9- njection pressure operated valves
Production up the annulus
(A )
Production up the tubing
(B)
Fig. 5-10- roduct ion pressure operated valves
A production pressure operated valve (Fig. 5-10 A&B)
has the production pressure ( P I ) acting on the largest area
of influence (Ab - Ap).The injection pressure (PZ)acts on
the area of the port (Ap).
The opening pressure for the production pressure Oper-
ated valve is:
Pl = Pbt - P2 (ApAb) Equation 5.17
1 - (Ap /Ab)
The opening pressure (PI ) equation is the same fo r both
cases. The convention of applying P I to the largest area
of influence (Ab - AP)and (PZ) o the smallest areaof influ-
ence (A,) must be followed.
Valves Used for Continuous Flow
A valve used for continuous flow shouldmeter or throttle
the gas throughput. The injectedgas volume is controlled at
the surface.
Valves Used for Intermittent Li ft
Intermittent lift usually requires a large volume of gas for
a short period of time. Unlike valves used i n continuous
flow, a valve used for intermittent lift should fully open
during injection and snap closed.
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A P I TITLE*VT-b 94 m 0732290 0532897 966 m
64 Gas Lift
Basic Valve Designs
l . Unbalanced Pressure Charged Valve:
An unbalanced spring valve withno dome pressure
(Fig. 5-12) has the following force balance, ust as he
valve starts to open:
This valve (Fig. 5-11 ) uses a nitrogen charged dome as Psp Ab =PI (Ab - Ap) +P2Ap Equation 5.20
the only loading element to cause closure. All earlier
discussion was directedohis valve. Thequation may be rearrangedoolveor PS, based
upon the desired conditions at valve depth and for par-ticular valve specifications.
Psp =PI ( 1 - Ap /Ab) +P2 (A, /Ab) Equation 5.2 1
The calculations are the same for an injection pressure
operated valve, so long as he pressures are properly
identified with respect o heareaelements heyare
acting on.
After Psp s determined, the test rack opening pressure
may be calculated:
PSP
P”, = Equation 5.22(1 - Ap /Ab)
P*
P ressure valve
This equation is the same for the production pressure
operated and the injection pressure operated valve. Test
rack pressure contacts the bellows in both cases and the
area of the stem tip in contact with th e seat is a atmos-
pheric pressure in each case.
3 . Pilot Valves:Fig.5-11- nbalanced pressure charged valve
A pilot valve (Fig. 5-13 ) offers the advantageof a large
port combined with close control overvalve spread. The
control section is an unbalanced gas lift valve. Casing
2. Unbalanced Spring Valve:
The dome of this valve (Fig. 5-12) does not contain a
charge. For this reason, temperature effects are negligi-
ble and are normally not considered when setting the
valve’sopeningpressure.Typical high spring rates
(force increase per unit stem travel), cause the spring
valve to function like a variable orifice. This characteris-
tic provides an infinite series of areas for gas passage.
fixed orifice is not normally used.
Springs are most commonly applied within a valve i n
a fashion that causesa closing force. If this spring force
(Fc) in pounds is divided by the area of the bellows (Ab)
in square inches, a value for pressure (psi) is obtained.
This pressure is referred to as Spring Pressure Effect,
and is denoted PS,. A pressure of this magnitude placed
in the bellows would provide the same valve closing force
as the spring.
For the purpose of calculations, Psp s used as a ficti-
tious replacement of dome (bellows) charge pressure.
Sinceemperatureffect is negligible, P, represents the Spr ing valvedome charge in the ester as well as at the operating
depth. Fig. 5-12- nbalancedpringalve
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I TITLExVT-b 94 0732290 0532898 AT2
Gas Lift Valves 65
and tubing pressure act n the control sect ion n the same
way hat hey d o onanunba l anced n j ec t i onp res -
sure operated valve. When the control valve opens, the
main valve ( large port ) opens: and when he cont ro l
valve closes, the main valve closes.as flowing through
the small portof the control sect ion actsn the piston of
the main valve to open it. When the control valve closes,
a spring returns the main valve o a closed position.
CONTROL
V A L V E
M A I N
V A L V E
PISTON
BLEED
PORT
Pilot valve
Fig. 5-13- i lot valve
4. Other Types of Valves:
New types of valves are constantly being developed to
keep pace with the general evolution of gas lift technol-
ogy. There are many types f special application valves,
too numerous to include in this manual .
The principles of operat ion f most special valves are
similar to those of the mo re widely us ed types f valves
discussed in the foregoing. It should also be noted that
almost al l types of valves are available n both retrieva-
ble or non-retrievable form and with various ypes of
check valves.
Wireline Retrievable Valve and Mand rel
These valve mandrels are commonly ca l led Retrievable
or Sid ep o ck e t M a n d r e l s . Retr ieval n henamecomes
from the wireline retrievability of the valve.
Unlike conventional valves and mandrels (Fig. -16), th e
valve is installed within the nterior portion of he side-
pocket mandrel (Fig.5-15B). The valve is reached by wire-
line run through the inside of the tubing (Fig. 5-14A). A
valve receiver (Pocket) forms a part of the mandrel and is
of fse t f rom he ma in bo re of t h e u b i n g a n d m a n d r e l
(Fig. 5-15B and 5-15C). In most cases, no through tubing
restriction results. Tools that are normally run through thetubing can still be run.
Fig. 5-14A illustrates a well equipped with sidepocket
mandrels. Wirel ine methods are being used to run and pull
valves. Fig. 5-14B illustrates a typical wireline tool string
used to run or pull valves in retrievable mandrels. In addi-
tion to standard weight bar and wirel ine jars, a kickover
tool of some type is used.
Fig . 5 - 1 4- ireline tool strings and retrievable mandrels
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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API T I T L E t V T - h 94 0732290 0532899 739 W
66 Gas Lift
The kickover tool has a eans of attaching apulling tool
for retrieving valves or a running tool with a valve con-
nected to it (Fig. 5-17A) to allow installing a valve in the
mandrel. Kickover tools also help locate the mandrel and
align the valve or pulling ool with the mandrel pocket (Fig.
5-17B). After the andrel has been located and the valve or
tool aligned, the kickover tool will “kick” (or swing) the
valve or tool into the offset portion of the mandrel in line
with the mandrel pocket (Fig. 5-17A).At this time, jarring
up or down with wireline techniques will pull or install the
sidepocket (retrievable) valve. Sidepocket mandrels (Fig.
5-15) must have a receiver (pocket) for the gas lift valve. The
pocket will normally have two distinct bores to accommo-
date the valve packing. The packing bores are mooth and
closely controlled dimensionally. Between the two smooth
packing bores is located one of the ports that will allow a
path for communicating between the tubing and the annu-
lus. The bottom (and sometimes he op) of the pocket
provides a second port that communicates with the tubing
(see Fig. 5-15C). The gas ift valve, with its packing, stem,
and seat, controls any communication between the tubing
bore and the annulus. In addition to containing seal bores
and porting, a pocket must have a facility to accommodate
and engage the valve latch. A shoulder or undercut in the
pocket maybeused for his purpose (Fig. 5-15C and
5-17A).
In addition o he pocket, many sidepocket mandrels
have aids that are designed to facilitate locating the man-
drel with wireline toolsand aligning the valve carried by the
tools with the mandrel pocket. An orienting sleeve (Fig.
5-17C) within the mandrel is often used to cause forcedalignment. A controlled shoulder within the mandrel can
also engage he wireline tools toaid in locating the mandrel.
This stop will properly position the tools in a vertical posi-
tion above the mandrel pocket. Fig. 5-17Chows a stop for
this purpose located i n the mandrel.
II
LATCH
LATCH RETAINING SHOULDER
PACKING (VALVE TO POCKET SEAL)
PORTS TO ANNULUS
VALVE
PACKING (VALVE TO POCKET SEAL)
. SIDEPOCKET (VALVE RECEIVER)
PORT TO TUBING
Fig. 5-15- etails of wireline retrievable valve
VALVE MOUNTED OUTSIDETHE MANDREL TUBINGrR1 ACCESS TO THE VALVE)MUST BE PULLED TO HAVE
CONVENTIONAL GAS LIFT VALVE
REVERSE FLOW CHECK
THREAD FOR INSTALLING VALVE
- AN DHECK TO MANDRE’
(C)
Fig . 5-16- etails of conventional valve
,- I C K O F TOOL
(A)
VALVE LATCH
SIDEPOCKET MANDREL
GAS LIFT VALVE VERTICALLYAND RADIALLY ALIGNED ANDKICK ED OVER. READY TO ENTERTHE MANDREL SIDEPOCKET.
=“ATCH
tORTS
SIDEPOCKEl
STOPHOULDER POSI-TIONS KICKOVER TOOL ANDVALVE VERTICALLY WITH
SIDEPOCKETRESPECT TO THE MANDREL
FINGER SLOT
HELICALSURFACE IS ENGAGED BYTHE LOCATING FINGER OF THEKICKOVEROOL. THE UPWARDFORCE APPLIEDTO THE FINGERAGAINST THIS SURFACECAUSESTHE KICKOVER TOOL TOROTATE
INTOL IGNM E NTWITHHEFINGER SLOT.
Fig. 5-17- idepocket mandrel, kickover tool an d valve
(Valve ready o be in stalled intomandrel sidepocket) Cour-tesy Camco, Inc.
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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API T I T L E * V T - 6 94 W 0732290 0532900 280 W
Gas Lift Valves 67
Valves (Fig. 5-18B) used in retrievable mandrels have the
same basic components as the valves (Fig. 5-18A) used in
conventional mandrels. Many of the parts are identical. In
addition to the basic parts, a retrievable valve must have
some means (latch) to lock i t into position within the man-
drel pocket. The valve must also have seals that act between
the valve and mandrel pocket to prevent leakage between
the tubing and casing annulus in either direction.
PACKING (SEAL)
PACKING (SEAL)
REVERSE FLOW CH ECK
Conventionalgas l i f t valve
(A )
Retrievablegas l i f t valve
(B)
Fig. 5-18- etr ievable and convent ional gas lift valves.
Courtesy Cameo, Inc .
Mandr el and Valve Portin g combinat ion^^ ^
It is often inefficient or impractical to use one combina-
tion of mandrel and valve porting to satisfy all gas ift
installation design requirements. There are two basic con-
figuration of mandrels and four configurations of gas lift
valves. Fig. 5-19 shows the two mandrel types. The type 1
or standard mandrel has the holes in the pocket drilled
from the outside or casing side,and the bottom of the pocket
is in communication with the tubing. Type 2 has the holes
in the pocket drilled from the inside or tubing side, and
the bottom of the pocket is n communication with the out-side or casing (annulus) side.
The four configurations of gas lift valves are shown in
Fig. 5-20. Type 1 is a well-known conventional injection
pressure operated valve, and Type 2 is a production pres-
sure operated valve. The other two are not as familiar.
Actually, the only difference between Types 1 and 2 and
Types 3 and 4 is that the heck valve has been turned upside
down in the latter two. Also, type 2 and type 4 have cross-
over seats. This restricts the seat size available in thesevalves.
T w o b a s i c g a s l i f t m a n d r e l s i n c l u d e t y p e l n w h i c h th e s i d e o f t h e p o c k e t i s i n
comm unicat ion wi th theannulus and the bottom ofthe pocket s i n c o mmu n -icat ion wi th the tubing, and type 2 in which the comm unicat ion conf igurat ionis reversed.
R..
"01".
l l o w
Fig. 5-19 - asic gas l i f t mandrel types
(After Focht, World Oil, anuary 1981)
Of these basic types of valves, types 1 an d 4 are pressure operated. Types 2a n d 3 a r e f l u i d o p e r a te d .N o te th a t t h e c h e c k v a l v e s i n t y p e s 3 a n d 4 o p e r a te i nthe opp osi te d i rect ion from types 1and 2.
Fig. 5-20- onf igurat ions of gas lifr valves(After Focht, World O il, Janua ry 1981)
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P II T L E * V T - b 94 0732290 0532903 117
68 Gas Lift
There are eight possible configuration s using he four occur. The crossover seat restricts the port size available to
valve types and two mandrel types (see Fig. 5-21). In F i g . 3 / l ~ - i n ~ hor the one-inch valve and tos/l6-inch for the 1'h-inch
5-21, Configurations A and B are recognized as he stan- valve. Configuration G s probably better for this purpose.
dard type of completion. For tubing flow they are usually
preferred.Normally,productionpressure -operated nstal- Mand rels with more than one pocket, more than two pack-
lationsareundesirable or highproduction atebecause ngsections n onepocket, andwithotherportingcon-
they tend to causeheading or slugging ypeproduction. igurationshave been used.Newcombinationsarecon-
When they are used, a problem with configuration B may tinually being conside red.
Gas-
A
. .E
Gas
. .B
I IF
m
d
l
C
T3
D
-3D
Pa
. -H
By combining the four valve types with the two types of mandrels, eight configurations are available. They ares follows : &valve 1 , mandrel 1, tubing flow,pressure operated; B-valve 2,mandrel 1 , tubing flow, fluid operated; C-valve3, mandrel 1, annular flow, fluid operated; D-valve , mandrel 1, annular flow,
Pressure operated;E-valve 1 mandrel2.annular flow. pressure operated; -valve 2,mandrel2, annular flow, fluid operated; -valve 3,mandrel2, tubing flow,fluid operated; and H-valve 4, mandrel 2, tubing f l o w , pressure operated.
Fig . 5 - 2 1 - ombinations of valve types and mandrel types(After Focht, World Oil, anuary 1981)
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Continuous Flow Gas Lift Design Methods 69
CHAPTER 6CONTINUOUS FLOW GA S LIFT DESIGN METHODS
INTRODUCTION
Gas lift is a process of lifting fluids from a well by the
continuous inject ion of relatively high pressure gas to
reduce the flow gradient (continuous flow) or by the injec-
tion of gas underneath an accumulated iquid slug in a
relatively short period of time o move he slug o he
surface (intermittent lift). Both types are shown schemati-
cally in Fig. 6-1. Continuous flow gas lift design will be
discussed in this chapter. Intermittent l i ft design will be
discussed in a later chapter.
Continuous flow gas lift is essentially a continuation of
natural flow. Gas s njected at some point in he flowpattern causing an increase in gas-liquid ratio above that
point. This increased gas-liquid ratio results in a reduced
flowing gradient. This is shown graphically in Fig. 6-2. For
maximum benefit the gas should be injected as deeply as
possible. The best continuous flow gas lift is accomplished
by injecting gas at the bottom of the tubing. Because of
pressure limitations, however, valves are generally needed
to establish the point of gas injection and this point may be
through a valve or orifice somewhere above total depth.
If injection is through valves, it is generally intended that only
one valve be open during injection. Design of continuous
flow gas ift nstallations using njection pressure oper-ated valves is covered in API RP 11V652.
L
LNJECTED
f
_I
L
INJECTED
Q A I
r
Fig. 6-1 - A) Continuous gas lift performance.( B ) Intermittent g a s lift perform ance
TYPES OF INSTALLATIONS
Continuous flow gas lift may be utilized in numerous
types of installations as well as numerous combinations of
tubing and casing sizes. In general, the flow may be classi-
fied as tubing or annular flow. Flow up the tubing string
covers a range of sizes from ’/.,-inch to 4-inches, and larger.
Slim-hole completions place great emphasis on continuousflow in small pipe. Various water-flood operations and
water-drive reservoirs place emphasis on high producing
rates requiring large tubing sizes.
Annular flow is the injection of gas down the tubing
string and the production of fluids through the tubing-
casing annular space. Typical sizes range from 1-inch tub-
ing inside 2’/%-inchO.D. casing to 3Vz-inchO.D. tubing inside
103/4-inchO.D., or larger, casing. Total fluid producing rates
in excess of 50,000 B/D have been reported through the
annulus of 3Ih-inch O.D. tubing inside large casing. The
principles of tubing and annular flow gas lift ‘are the same.The prediction of annular flow gradients is probably a little
less accurate than that hrough ubing. Also, he ubing
should be large enough to handle the downward gas flow
without excessive pressure drop. The examples used in this
chapter will be tubing flow.
A continuous flow installation through tubing without apacker or standing valve is classified as an open installa-
tion. This type of installation is seldom recommended, but
well conditions may be such that running a packer is unde-
sirable. This type of installation has certain disadvantages.
Any time the well is placed back on production, the fluids
must be unloaded from the annular space. This means that
the gas lift valves will be subjected to cutting by liquid flow
until the well has unloaded to ts working fluid evel. A
varying injection gas line pressure will also cause the fluid
level to rise and fall. This often results in “heading” or
“slugging” of the produced fluids instead of a smooth con-
tinuous flow. Each time the fluid level is lowered, somefluid is pushed through any gas lift valve beneath the fluid
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E t V T - b 914 M 0732290 0532903 T 9 T m
70 Gas Lift
level. Eventually, this valve may become fluid-cut. Another fluid has been unloaded from the annular space, there is nopossibility is that some of the actual production may rise re-entry of fluids into the annulus. Therefore, a stabilized
and come through the gas lift valves beneath the operating level is maintained.
valve because of less friction in the large annular space.
Experience has shown that gas lift valves located beneath
the operating valve will generally be fluid-cut when an open
installation is pulled.
Reverse check valves on the gas lift valves prevent fluids
from entering the casing-tubing annular space and are rec-
ommended fo r all continuous flow installations. When aA semi-closed installation is one in which a packer is run semi-closed installation is inoperative, the fluids do not
but no standing valve is used. This type of installation is rise in the annular space and, therefore, the well will sta-
recommended for most continuous f low wells. Once the bilize much quicker when placed back on operation.
CONTINUOUS FLOW UNLOADING SEQUENCE
Continuous flow unloading of a tubing-flow installation due o the pressureexerted by the iquidcolumn in the
is illustrated in Fig. 6-3. Until the top valve in Fig. 6-3(A) is tubing. In Fig. 6-3(B) all valves are open. The top valve is
uncovered, fluid from he casing s ransferred nto he uncovered, and injection gas is entering the tubing through
tubing through open valves and U-tubed by injection gas this valve. Unloading continues from the top valve which
ressure being exerted on the top of the liquid column in the remains open until the second valve is uncovered.casing. No pressure drawdown across the formation occurs
during U-tubing operations because the tubing pressure at In Fig. 6-3(C) all valves are open. Injection gas is entering
total depth exceeds the static bottomhole pressure. This is he ubing hrough he opandsecondvalves.With he
PRESSURE ,PSI
1OOO-
2000 -
3000 -
tW 4000-
f
U
5000-
6000 -
I!
-\
1 I I I
Fig. 6 - 2- undamentals of gas lift design
yright American Petroleum Institute
ded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P IT I T L E a V T - 6 9 4 W 0732290 0532904 926
Continuous Flow Gas Lift Design Methods 71
fluid level in the casing below the depth of the second valve, In Fig. 6-3(E) the top valve is closed and all other valves
the tubing pressure is less than the casing pressure at valve are open. The second and third valves are uncovered, and
depth, and injection gas enters the tubing through the injection gas is entering the tubing through both valves. The
second valve. The flowing tubing pressure at the depth of flow of injection gas through the second valve has lowered
the top valve is decreased by injecting a high volume of gas the flowing tubing pressure at the depth of the second valve.
through the op valve to uncover he second valve. This This allows the injection gas to enter the tubing through the
high injection gas-liquid ratio s required for only ashort third valve.
time, and the valve must be capable of passing this gasvolume.
In Fig. 6-3(D) the top valve is closed and all other valves In Fig. 6-3(F) the top and second valves are closed, and
are open. Injection gas is entering the tubing through the the third and bottom valves are open. Injection gas is en-
second valve. The third and bottom valves are not un- tering the tubing through the third valve. The bottom valve
covered. Before the top valve will close, the casing pressure is below the fluid level in the casing. The producing ca-
must decrease slightly. The second valve must remain open pacity of the installation is reached with the available in-
until the third valve is uncovered. jection-gas pressure before the bottom valve is uncovered.
ferred into tublng through all valves
(A ) Fluid from casing bring trans-surface by injection gas through top
(B ) Fluld In tublng bemg aerated to (C ) Injection gas enteringublng
and u-tubed by injection gas pressure
throughtopandsecondvalvelmmed-
valve as fluid in nnulus s transferred
to surface. Into tubing through lower valves.
lately after second valve uncovered.
(D) Fluid In tubing being aerated to
surface by injection gasthrough sec-ond valve as fluid in annulus is trans-
ferred into tubing through third and
bottom valves
through second and third valves im-
(E ) Injection gas entering ubing
mediatelyafter hird valve isun-
covered.
(F) Pr oduc lngr a t eequa lscapac l t yo ftubing from third valve for available
valve cannot be uncovered.
injection pressure. Therefore, bottom
Fig. 6 - 3- ont inuous unloading sequence
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A P I T I T L E * V T - 6 94 m 0732290 0532905 862 m
72 Gas Lift
DESIGN OF CONTINUOUS FLOW INSTALLATIONS
To design a continuous flow installation, as much of the
following information as possible should be obtained:
1.
2.
3.
4.
5 .
6 .
7.
8.
9.
1o.11.
12.
13.
14.
15.
Tubing and casing size
Depth to the center of the perforated interval
API gravity of the oil
Formation gas-oil ratio
Specific gravity of the injection and formation gas
Desired daily producing rate (oil and water)
Specific gravity of the water
Flowing wellhead tubing pressure
Injection gas pressure available at well
Volume of injection gas availableStatic bottomhole pressure
Productivity index or inflow performance relation-
ship
Bottomhole temperature
Flowing wellhead temperature
Type of reservoir with expected depletion perform-
ance
It is common practice to use the annular space between
the casing and tubing to conduct the injection gas down tothe point of injection. If gas lift valves are installed, they are
placed on the tubing string to let gas from the annulus join
the well fluids that flow up the tubing. Other arrangements
of equipment, such as annular flow and parallel tubing
strings, can be used with the only limitations being that
there must be a passageway for gas to travel downward to
the point of injection and there must be a conduit through
which the gas and well fluids flow up and out of the well.
Types of Design Problems
In gas lift design, there are three distinct types of designproblems. First is the case where valves are to be designed(spacing and pressure setting) and run with the tubing in an
existing well. A second case, encountered primarily in off-
shore operations, is where wireline mandrels are spaced in
the tubing string for later installation of gas lift valves. This
may include a considerable period of time in which the well
flows prior to the need to install gas lift valves. Mandrel
spacing is frequently done when only limited knowledge of
the well's productivity is known. The third type of problem
is setting valves in existing mandrels. The mandrel spacing
is fixed. In this case, the gas lift designer must determine if
valves are needed in all he existing mandrels and thendetermine the set pressures for the valves.
The initial design will be for the first type of problem and
will consider the case where complete knowledge of the wellproductivity is known. This will illustrate gas lift design
principles. This will be followed by those cases where less
than complete knowledge of the well parameters is known.
Assume continuous flow gas lift design is needed for the
conditions listed in Table 6-1. By far the most important
information needed in gas lift design is the well's producing
characteristics. If exact and complete knowledge of the well
is known, an optimum design can be readily made. Unfor-
tunately, this is seldom, if ever, the case. In the following
design, it is assumed that well information is exact. Also,
the design is made without any safety factor. The need of,
and the means for including, a safety factor will be dis-
cussed later. Depth-pressure gradient data is essential to the
design. It is assumed that gradient curves or a computer
program for calculating gradient data is available to thedesigner.
TABLE 6-1CONTINUOUS FLOW GAS
LIFT DESIGN CONDITIONS
Productionesired - q Maximum
Well Depth - D, 10,000'
StaticHP - P,, 3,600 psig
Productivity Index - J
Formation R, 300CF/BWater Cut - F, 65%
Oilravity 35"API
Water Gravity - SG, 1 O5
Gas Gravity - SGg 0.65
Casingize 5 ' / 2 in. OD
Tubingize in. OD
Surface Wellhead
Pressure - Pwh 1O0psig
Available Gas
Pressure - Pg 1200 psig
Gas Injection Rate - qi 500MCF/D
Static Fluid Gradient* - g, 0.465 psitftBottom Hole
Temperature - Tr 190°F
Flowing Temperature - Twh Fig. 6-9
Type Reservoir Waterdrive
(Grossluid).4LPD/psi
*Static Fluid Gradient is the gradient of the fluid expected
in the tubing and annulus at the time unloading starts.
Example Graphical Design
Gas lift design is best illustrated graphically. Figures
6-4, 6-5, and 6-6 show a graphical solution for design based
on the conditions of Table 6-1. A step-by-step explanationfollows:
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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` ` , ,
` ` ,
` , , ,
` ,
` ` ` ` ,
` ` ` ` ,
` ` - ` - ` , ,
` , ,
` ,
` , ,
` - - -
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A P I T IT L ExVT - b 94 0732290 0532qOb 7 T q
Continuous Flow Gas Lift Design Methods 73
1. On a convenient scale make a depth versus pres-
sure chart. Draw a line 'representing total depth of
the well. Plot the static bottomhole pressure (3600
psi) versus total depth (10,000 feet). A static fluid
gradient line (0.465 psi/ft.) is drawn from the static
bottomhole pressure point at total depth. This cuts
the depth scale at about 2250 feet and represents the
fluid level at shut-in conditions with no surface pres-
sure. This assumes that the formation will freely take
fluid when the pressure is higher in the casing than in
the formation. This is not always the case and the
fluid level might stand higher in the well than indi-
cated here.
2. An available gas injection pressure line is drawn.
Starting at 1200 psig, the pressure ncreases with
depth due to the static gas column. For the condi-
tions described, the pressure will increase approxi-
mately 30 psi per thousand feet of depth. The gaspressure at total depth will be 1500 psig. This repre-
sents the maximum gas pressure available at any
depth. In order to inject gas at the bottom of the well,
the pressure in the tubing must be something less
than 1500 psig. At 1500 psig bottomhole pressure,
the well would produce 840 barrels per day. (Draw-
down =3600 - 1500 =2100 psi. Production =0.4 x
2100 =840 BAI). Assuming 500 MCFA) is injected
at 10,000 feet, he ubing gas-liquid ratio would
require over 2,000 psig flowing pressure at the bot-
tom of the tubing. Therefore, it would not be pos-
sible to inject gas at 10,000 feet. Gas would have tobe injected at some higher point in the tubing string.
3. Assume a producing rate of 400 barrels per day total
fluid. The formation has a water cut of 65 percent
and a gas-oil ratio of 300 cubic feet per barrel. This
represents approximately a 100 gas-liquid ratio. At
400 barrels per day otal iquid production and a
productivity index of 0.4 , the well will require a
drawdown of 1000 psi below the static bottomhole
pressure of 3600 psig. A point can be located at total
depth and 2600 psig. A gradient curve starting at that
pointcanbedrawnupwardasrepresented inFig. 6-4. This line, if drawn all the way to O pressure,
would cut the depth curve somewhere between 3000
and 4000 feet.Above the point of gas injection a total
gas-liquid ratio of approximately 1350 scf/stb will
exist. This consists of the formation gas plus the 500
MCF per day being injected. Since a wellhead pres-
sure of 100 psig has been specified, a gradient curve
can be drawn starting at O depth and 100psig for this
higher gas-liquid ratio. This gradient line intersects
the previously drawn gradient l ine at approximately
5200 feet. Therefore, if gas is injected at the rate of
500 MCF per day at 5200 feet, the formation gas-liquid ratio gradient line will exist from total depth
to the point of injection and the higher ratio gradient
line above that point. The well would produce the
specified 400 barrels per day. The pressure in the
column at the point of injection would be about 700
psig. Therefore, some gas pressure greater than this
amount would have to be available in order to inject.
As shown in Fig. 6-4, a pressure of over 1300 psig
would be available at that point and could easily
inject into the tubing. Following the same procedure,
a gradient curve may be drawn for 600 barrels per
day. This has been done in Fig. 6-4 and shows an
intersection between he wo curves at approxi-
mately8200 feet. Thepressurepoint sabout
1375 psig. The available gas pressure from the gas
gradient line is slightly over 1400 psig and with such a
pressure i t would be possible o nject a imited
amount of gas at this point because of the lack of
pressure differential at 8200 feet. Assuming no pres-
sure drop has been taken for safety factor, which will
be discussed later, i t would be possible to make a
maximum of 600 barrels per day from this well by
gas lifting.
4. If the above procedure is repeated for various rates, a
series of points can be plotted on the depth pressure
curve representing injection points for different pro-
duction rates. This has been done in Fig. 6-5 for
production increments of 100 barrels per day total
fluid. The line resulting from connecting these points
is called an equilibrium curve. This represents a con-
tinuing series of possible injection points for differ-
ent production rates. It should be emphasized thatthis is not a gradient curve. A point on the equilib-
rium curve represents a stabilized condition of gas
injection for a specific set of conditions. Consider the
point on the curve for 400 barrels per day. The point
is at 5200 feet and 700 psig. This point is valid only
for the specified conditions of tubing size, wellhead
back pressure, gas injection rate, well productivity
and other reservoir conditions. The gas system pres-
sure is not necessary for developing an equilibrium
curve. It is only necessary that adequate pressure be
available to inject at the desired point. An equilib-
rium curve can be very useful in studying gas lift. Forexample, when gas lift is selected as an artificial lift
method in a field, a system pressure must be selected.
Three different gas system pressures are shown at
800, 100, and 1600 psig in Fig. 6-5. For the given
well, 800 psi gas could be injected at about 6000 feet
and a production rate of 450 barrels per day would
result. The 1200 psig system gives a production rate
of about 600 barrels per day. If a system pressure of
1600 psig is selected, gas could be injected at the
bottom of the tubing string and a production rate of
approximately 700 barrels per day would result. It
would be of no benefit for this well to have a systempressure greater than 1600 psig.
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74 Gas Lift
5. Other parameters may also be studied with the equi-
librium curve. For a field study it would be necessary
to select a typical well productivity and also benefi-
cial o have anticipated maximum and minimum
productivity wells to examine. Other factors that
could be evaluated would include tubing size. For
example, if the well productivity of Table 6-1 is
assumed and the 1200 psi gas system is used, chang-
ing the tubing to 27/s-inch O.D. willesult in a produc-
tion rate of about 700 barrels per day. Further
increasing the tubing size to 3lh-inch O.D. will result in
a production rate of about 750 barrels per day.
Another parameter to consider is the amount of gas
to be injected. A rate of 500 MCF per day was
arbitrarily selected in this case. This could be the
total available gas or it might be that more gas is
available. In the example shown in Table 6-1, an
increase in injection gas to 750 MCF per day would
result in an increase of 35 barrels per day liquid
production to a total of 635 barrels per day. A
further increase in the amount of gas to 1000 MCF
per day would increase production only an addi-
tional 5 barrels per day. Further ncreases in the
amount of gas injected would result in no increase in
production and actually would start to cause loss of
production. This demonstratesavery mportant
point in gas lift design. Many operators simply
assume that if some gas injected does some good then
more gas would do more good. As gas is injected, it
results in lightening the column but every cubic foot
of gas causes an incremental increase in friction. As
greater and greater amounts of gas are injected, a
point is reached where the increase in friction equals
or exceeds the reduction in pressure due to the
reduced density in the column. Still another factor
that could be investigated with the equilibrium curve
is the effect of tubinghead pressure. In the example
shown, a constant wellhead pressure of 100 psig has
been assumed. This is realistic if a very short flowline
existssuchasanoffshoreplatformwere he
production facilities may be located within 25 or 50
feet of the wellhead. This would not be a realistic
assumption for a flowline several thousand feet long,
particularly if the flowline is small in comparison to
tubing size. A horizontal flow model can be intro-
duced which would cause the tubing pressure to vary
with flow rate. This would affect the equilibrium
curve and the resulting production that could be
obtained from the well. The greater the tubing pres-
sure, the less production that will be obtained for a
given set of conditions. The equilibrium curve con-
cepts lends itself particularly well to modeling on the
computer, where a large number of parameters can
be investigated rapidly. Design considerations in -
PRESSURE, PSI
G7
Fig . 6 -4- raphical solution for design based on conditions of Table 6-1
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A P I T I T L E x V T - 6 9 4 m 0732290 0532908 571 m
Continuous Flow Gas Lift Design Methods 75
clude determining what size tubulars to place in the
well and the volumes and pressures needed from the
gas njectionsystem.Theseconsiderationsare
equally or more important than design of spacing and
valve setting. An efficient and properly working sys-
tem cannot be installed unless both are done.
6. The gradient curve above and below the point of gasinjection for 600 barrels per day as shown in Fig. 6-4
has been redrawn in Fig. 6-6 to demonstrate valve
spacing design. The valve spacing could have been
continued in Fig. 6-4 but the multiplicity of lines
would tend to create a degree of confusion. Two
considerations control valve spacing. First, it must
be possible to displace liquid from the annulus to the
tubing down to the desired operating depth with the
available gas pressure. Secondly, it must be possible
to open any valve under producing conditions with-
out opening the valve above it in the string. The
depressed due to the difference in casing and tubing
pressure at the surface. The gas column pressure is
shown graphically by the available gas pressure line.
If a straight line is drawn from O depth and tubing-
head pressure with a slope equal to the assumed
liquid gradient of .465 psi per foot the maximum
point of gas njection willbewhere hese lines
intersect.
This is shown graphically to be at 2530 feet. If the
well can be unloaded into a pit against atmospheric
pressure, the first valve could be placed approxi-
mately 230 feet deeper. If the static fluid level in the
well is deeper than the calculated location of the first
valve, the first valve could be placed at the static fluid
level. This would entail some risk if the formation
will not freely take fluid when the tubing and casing
annulus are loaded.
location of the first valve is simply an exercise in
U-tubing. If injection pressure is put on the casing
annulus, hefluid evel i n theannuluswillbe
7. The same criteria of U-tubing from the first valve to
the second valve also exists. However, surface cas-
ing and tubing pressure are no longer applicable. The
TP100 PSI 4oo
PRESSURE - PSI
0 1 800 1200 1600 2000 2400O
200c
400CWu.I
I
b
w
600C
800C
10,ooc
Fig. 6-5- raphical solution or des ign based on conditions of Table 6- I (Continued)
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
Not for Resale, 07/27/2006 10:42:36 MDTeproduction or networking permitted without license from IHS
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A P IT I T L E x V T - L 94 W 0732290 0532909 408 W
76 Gas Lift
casing pressure available is still the gas gradient line.
The pressure in the tubing will depend on how much
the pressure is drawn down in the tubing due to the
injection of gas from the casing. From the equilib-
rium curve in Fig. 6-5, it would appear that if gas is
injected at 2500 feet a production rate of a little less
than 200 barrels per day will result. The pressure in
the tubing will be reduced to about 280 psi. However,
it is common practice to use the higher pressure
resulting from a gradient line expected from the
anticipated production rate of 600 barrels a day. This
is about 420 psi. The equilibrium curve theoretically
could be used in spacing the valves working down-
hole. However, when the well started to produce at
the expected 600 barrel per day rate, a higher pres-
sure would exist opposite the op valve han he
pressure used in setting hese valves. This could
cause valve interference. The higher pressure used
for spacing represents some degree of safety factor.Subsequent valves are designed in the same manner
as valves 1 and 2. Fig. 6-6 shows the location of thesevalves resulting in a design of 7 valves with the bot-
tom valve located at 8250 feet. Valves are spaced
closer together at depth increases because the min-
imum tubing pressure gets nearer the .available cas-
ing pressure. It is common practice to carry the
spacing design down to the point where predicted
tubing and casing pressure differential is 50 psi. As
pointed out later, one or two more valves at some
minimum spacing may be added.
8. The closing force (spring or dome pressure) to be set
on each valve is determined using casing and tubing
pressures from Table 6-2. For example, suppose
PRESSURE, PSI
O 400 800 1200 1600 2000400
200c
SOOC
600C
800C
~
Fig. 6-6- raphical solution for design based on conditions of Table 6-1 (continued)
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
Not for Resale, 07/27/2006 10:42:36 MDTeproduction or networking permitted without license from IHS
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A P I T ITLE*VT -b 94 m 0732290 05329LO L 2 T m
Continuous Flow Gas Lift Design Methods 77
conventional valves were selected without a spring
and with a valve stem area hat is 10 percent of
bellows area. Then valve 2 would have a calculated
domepressureof 1 2 7 3 p s i g ( 1 3 3 4 ~ 0 . 9 0 + 7 1 5 ~ 0 . 1 0 =
1273). The valve pressure would be set in the shop sothat it would have 1273psi at the operating tempera-
ture at 4500 feet. All gas lift companies have charts
for making the proper conversion. Thus the valve
string would be (Assuming valve port area =10per-
cent bellows area):
TABLE 6-2
TABULATION OF PRESSURE WITH D EPTH
DepthCasingress. Tubing Press. Dome Press.
feet Psig Psig Psig
2530 1275 420 1190
4500 1335 715 1273
5900 1375 950 1333
6900 1405 1120 13777500 1425 1240 1407
7900 1435 1320 1424
8250 1445 1390 1440
Safety Facto rs in Gas Li f t Design
As stated previously, the example design has been made
completely without safety factor except as described under
item 7. Because of this, it is almost a certainty that it would
not work if installed in a well. All gas lift companies put
some safety factor in their recommended design but do it by
different means. Also, they generally do not label it assafety factor. The following discussion contains various
ways of adding safety factor.
The first element of danger i n the design is the gas pres-
sure used. The available pressure is listed at 1200 psi and
this was used. If this is maximum, then some lower pressure
should be used to allow for minor losses and control of
injection rate. The pressure decrease will depend on field
conditions but should never be less than 50 psi. Therefore,
1150 psig or less should have been used as working casing
pressure if 1200 psig is absolute maximum available.
There are wo main considerations in gas ift valvedesign. It must be possible to displace liquid from the casing
into the tubing down to the desired operating depth with
the available gas pressure, and it must be possible to open
any valve under producing conditions without opening the
valve above it in the string. Spacing design in the example
should be capable of achieving the first consideration.
However, if all dome pressure were set exactly as designed,
and if the well production was exactly as expected with
the gradient anticipated, tubing and casing pressures would
cause all valves to open simultaneously. This, of course,
would be a very undesirable condition and some safety
factor must be included i n order o prevent his fromoccurring.
One means of including safety factor in the design is
illustrated n Fig. 6-7. This method ntroduces a safety
factor by reducing the casing pressure required to open
each valve successively down the hole. In Fig. 6-7, the
example design is redone using a drop in casing pressure of
20 psi at each valve. (The 20 psi drop is an arbitrary amount
selected here.) Thus the first valve is located in exactly the
same manner as previously since maximum casing pressure
will be available to open this valve. However, the operating
pressure required to open the second valve will be dropped
20 psi below that required for the first valve. This can be
done by drawing an available gas pressure line parallel to
the existing line at the reduced pressure. The spacing is
carried out graphically in the same manner as before. How-
ever, the available differential pressure for U-tubing at each
valve is reduced because of the drop in casing pressure
deeper in the well. Thus the spacing of the valves below the
top valve is reduced because of the drop in casing pressure
deeper in the well. Therefore the spacing of the valves be-
low the top valve is slightly closer together. As can be seen
from the design, the point at which a minimum 50 psi dif-
ferential between casing pressure available and tubing pres-
sure occurs at a shallower depth in the well. In this case
the bottom valve would be located at 7800 feet where a
tubing pressure of approximately 1270 psig and casing
pressure of 1320 psig would exist. Projecting a gradient
line from this point back to the producing depth at a gas
liquid ratio of 100 results in an estimated producing
bottomhole pressure of 2180 psig and a production rate of
570 barrels per day. Thus the disadvantage of this method
is that less production will be obtained from the well when
there is not sufficient gas pressure to inject all the way to
the bottom of the hole. In this case using the same amount
of gas but injecting at 450 ft . shallower in the hole results
in a production loss of 30 barrels per day. This illustrates
the desirability of always injecting gas at the maximum
depth possible. However, if the expected tubing gradient
exists in the well, then each valve could be opened with
approximately 20 psi less casing pressure than would be
required to open the valve immediately above it. Thus, the
purpose of being able to selectively open the valves from
the bottom up would be achieved.
A different means of including safety factors is illustratedin Fig. 6-8. This was originally introduced under the name
Optiflow design. The Variable Gradient design is essen-
tially the same thing. The point of gas injection is deter-
mined as previously discussed and shown in Fig. 6-4. Some
pseudo flowing wellhead pressure higher than the expected
wellhead pressure is selected. Generally the pseudo well-
head pressure selected will be the expected flowing well-
head pressure plus 20 percent of the difference between
tubing and casing pressure. In the example, this would be100+0.2 (1200- 100)=320 psi. A straight line is drawn from
this surface pressure to the tubing pressure at the point of
anticipated gas injection. This becomes a pseudo flowingproduction pressure line, and is referred to as “Variable
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E * V T - b 9V W 0732290 0532911 066 W
78 Gas Lift
Gradient” design. The first valve is located in exactly the
same manner as previously discussed, using the expected
wellhead pressure and anticipated injection gas pressure.
However, below this point instead of designing on the ba-sis of expected flowing production pressure with the an-
ticipated gradient, the pseudo production pressure line is
used. These production pressures are used both in spacing
the valves below the first valve and in setting the domepressures in the valve. The dome pressure will be set so that
the valve will not open without the minimum pseudo pro-
duction pressure. This becomes the minimum pressure
needed for U-tubing down the next valve, and requires
closer spacing of valves. In this case, 10 valves are required
to space to the same depth that was obtained with 7 valves
using no safety factor. However, full casing pressure s
available at the depth of injection and the anticipated 600
barrels per day should be produced from he well. The
limitation to this method of design is that the safety factor is
placed on the production pressure; that is, when the well is
producing from the anticipated depth of injection, thisvalve will be open but all valves above it will have less
production pressure than that required to open the valve.This provides sufficient safety factor for valves which have
a high degree of production pressure effect. However, in the
type of valve commonly used where the production pres-
sure effect is 10 percent or less, this does not introduce asufficient safety factor to allow for a working design. With
normal injection-pressure-operated valves it is necessary to
use the method of dropping the injection gas pressure. The
Variable Gradient design can be used with production pres-
sure operated valves. Thus, two methods of introducing
safety factor for opening the valves are available. However,
the method used s dependent upon the type of valve
sèlected.
The amount of safety factor which should be used in any
given design will depend on field conditions. If full allow-
PRESSURE, PSI
O 400 800200600 2400O
2000
’
6008
8 0 0 C
10,000
I I
3’6760’q p g :800’
Fig. 6-7- xample design using casing drop of 20 p si
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
Not for Resale, 07/27/2006 10:42:36 MDTeproduction or networking permitted without license from IHS
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A P I T I T L E + V T - 6 94 m 07322900532932 TT2
Continuous Flow Gas Lift Design Methods 79
able can be made or gas can be injected from bottom with a
design employing substantial safety factor, then the design
engineer has little excuse for lowering the safety factor and
risking an unworkable design. On the other hand, if consid-
erable added production is available, then having to pull an
unworkable string occasionally may be well worthwhile
depending on the cost of tripping the tubing. Saving one
valve in a string design is commendable if minimum risk is
involved but is not in the same league with a sizable increase
in production or a larger decrease in gas usage.
Down hole Temperature for Design Purposes
The downhole temperatu re to be used n setting he
valves depends upon the ype valve used. If a valve is
selected which depends upon a spring to provide the closing
force, the temperature correction is not required. Where
nitrogen charged bellows are used, the temperature at the
operating condition must be corrected. If a conventional
mandrel s used with th e gas l i ft valve mounted i n the
casing-tubing annulus and not in the flow stream of the
tubing, it is generally assumed that earth temperature will
exist in the valve dome. This temperature is readily availa-
ble in most fields and usually consists of a straight line
gradient between bottomhole emperature and ground
temperature a few feet below the surface. If a type valve is
used which mounts inside the tubing and is exposed to the
flowing well fluids, it is generally assumed that the tempera-
ture in the bellows is equal to the well fluid temperature.
Fig. 6-9 is a chart by Kirkpatrick for determining the flow-
ing temperature gradient. Once the flowing temperature at
the surface is determined it is frequently assumed that a
straight line temperature gradient will exist between surface
PRESSURE, PSI
WI-
WL L
I'tWP
1
.Fig. 6 -8- ariable gradient design
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E x V T - 6 94 0732290 532933 939
0 Gas Lift
I
- I1I
I
lI
I
0.3
0.2 -
0.1 -
O
I
1 1 1 1 1 I I I I I 1 I L
1 2 3 4 5 a 7 a o 10 1 1 12 13 146 t e 17 10 l o 20
TOTAL FLUID FLOW RATE - 100 B B L W D A Y
Fig. 6-9- lowing temperature gradient for different flow rates, geothermal gradients, and tubing sizes
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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&PI TITLExVT-b 94 0732290 0532714 875
Continuous Flow Gas Lift Desien Methods 81
and bottomhole temperature. This is slightly in error as the
well fluids will leave bottom at earth temperature. As the
well fluids move up the tubing, they will be warmer than the
surrounding earth temperatures and will be cooled by the
earth. This cooling rate will increase as the temperature
differential between the well fluids and the earth increases.
For a given flow rate this will usually increase to some fixed
differential and then continue at that differential until the
well fluids reach the surface or very near the surface.
A more realistic temperature profile is illustrated n
Fig. 6-10. Various programs for elaborate heat calculations
have been published, but these require a knowledge of heat
transfer coefficients that is usually beyond what is availa-
ble. Fig. 6-10 also shows the straight line assumption that is
used in most design calculations. In actuality, the straight
line temperature gradient will provide some additional
Actual Cond it ions Different From Design Condit ions
The previous design discussion has assumed exact knowl-
edge of the well productivity. In actual cases, this seldom
happens. Fig. 6-11 shows the effect on an actual productiv-
ity greater or less than that which was used in making the
gas lift design. If , for the assumed case, the productivity
turned out to be only half what was assumed, that is, a PI of.2 instead of .4 BLPD/psi, the system will readily unload
down to the bottom valve. Because of the lower productiv-
ity, the well will make substantially less production than
expected. In this case, operating off the bottom valve, the
well would produce about 360 barrels per day. This points
up the benefit of valving somewhat lower than expected
need. In this case, if the well is valved to bottom, it would
make something over 400 barrels a day operating near
bottom.
safety factor since the temperature of all valves above the If, on the other hand, the productivity turned out to be
operating valve s probably somewhat higher than was greater than expected, a different condition would exist.
assumed in setting it. This will cause the dome pressure to Assume that the productivity is double what was predicted,
be higher than anticipated and will give additional force to that is, a PI of .8 instead of .4 BLPD/psi. The equilibrium
keep the valve closed when operating at a lower point. curve for this condition is plotted also on Fig. 6-11. If the
These higher temperatures may not occur if operating at the well is designed for this higher productivity, a production
lower flow rates. rate of close to 800barrels per day will result, with gas being
TEMPERATURE - *F
O 40 80 12060 2000 - 1
FLOWING GRADIENTFROM FIG. 6-9
0.7" /100 FT.
2000 -
ASSUMED TEMP. PROFILE
IF STRAIGHT LINE IS USEDt-W
E 4000
c
I
-
W
O
n ACTUAL IS CURVED
(ESTIMATE - NOT CALCULATED)
6000- EARTHRADIENT
1.2"/100 FT.
10.0008
t-
WWIL
I
Xc
W
O
n
1
O 40 80 12060 2000 - 1
FLOWING GRADIENTFROM FIG. 6-9
0.7" /100 FT.
2000 -
ASSUMED TEMP. PROFILE
IF STRAIGHT LINE IS USED
4000 -
ACTUAL IS CURVED
(ESTIMATE - NOT CALCULATED)
6000- EARTHRADIENT
1.2"/100 FT.
'0.0008Fig . 6-10- traight l ine and actua l tempera ture prof i les
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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API T I T L E + V T - 6 94 0732290 532935 703
82 Gas Lift
injected at about 6800 feet. Although there is a valve at 6900
feet, injected gas will not reach this depth with the existing
spacing design. The well will not be able to unload below
the valve at 5900 feet and this will result in a production rate
of just over 700 barrels per day. The four bottom valves will
be of no benefit unless the productivity later declines and
the well works down to one of these valves. This points up
th e need to always over-predict rather than under-predictthe well productivity if exact data are not available. The
penalty for over-predicting the productivity is that more
valves will be placed in the hole than would have otherwise
been used. That is, spacing would be closer together in the
string. Under-predicting productivity, on the other hand,
results in less production. Also, the efficiency of the system
is reduced due to njecting higher in the hole. Sometimes the
mistake of underestimating productivity might be over-
come by injecting gas in higher quantities than anticipated.
However, the problem of working down from one valve tothe next may still prevent this benefit.
DESIGNING GAS LIFTFOR OFFSHORE INSTALLATIONS
In marine operations, where the pulling of tubing can be duction is anticipated. Also, on the development of multi-very expensive, it is common practice to install gas lift well platforms it may be necessary to do the design spacingmandrels in the tubing string at the time th e well is com- of the mandrels with only minimum productivity informa-
pleted even though a considerable period of flowing pro- tion. Various techniques have been developed over he
TP100 P81
PRESURE - PSI
O~
400 000 1200 1600 2000O
200c
kWW
I
S
W
L 4ooa
tn
eooa
1sooa
10,000-
\ / U 0 0 B /D
B ID
PI =0.8
Fig. 6-11- ctual vs. assumed productivity profiles
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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API T ITLE*VT -b 94 m 0732290 0532’9Lb 648 m
Continuous Flow Gas Lift Design Methods 83
years i n an effort to satisfactorily solve this problem. Some
range of well productivity must be assumed. It is necessary
to place an upper limit on what might be expected from the
well. Usually this upper limit is assumed and then a design is
developed which could handle wells of less productivity
as efficiently as possible. A generally accepted method of
doing this is to design the first two or three valves using
this highest assumed productivity or production rate. Thenas valves are placed progressively deeper in the well a gra-
dient from valve to valve is assumed based on lower pro-
ductivity. An alternate sometimes used is to space on an
assumed productivity unt i l some minimum mandrel spac-
ing is reached. Mandrels are then placed at this minimum
(usually 200 to 500 feet) spacing for several additional
valves or to packer depth. To set valves in existing man-
drels, the designer determines the maximum depth of the
first valve. The valve is placed in the first mandrel that is
at that depth or higher in the hole. Then the next valve
must be spaced from the actual location of the first valve
even hough his might be substantially higher than the
maximum depth that the first valve could have been placed.
For example, in many older fields in the Gulf of Mexico,
mandrels are in place that were designed with expectedsystem pressure substantially lower than actually exists at
this ime. In some cases, it is possible to skip mandrels
and place the valves at the next lowest mandrel. The pro-
cess continues downhole in this manner: from the previ-
ous valve location determine the maximum depth that the
next valve could be spaced and then pick the next higher
mandrel above that depth.
ADVANTAGES OF CONTINUOUS FLOW OVER NTERMITENT FLOW GAS LIFT
The technology for predicting continuous flow gradients of fluid being produced into the surface equipment
has developed greatly over he ast 20 to 30 years. The at a very high rate. The variation in flow rate from
ability to predict intermittent flow such as occurs in inter- the formation is not as great but some variation
mittent gas l i ft is less highly developed. Continuous gas lift occurs and this can be detrimental if a sand problem
has certain advantages over intermittent lift. These are: exists.
1 . Continuous gas lift fully utilizes the formation gas.
The njected gas s added to the formation gas to
arrive at the total optimum ratio needed above the
point of injection. Intermittent gas lift wastes any
formation gas energy because the gas is allowed to
rise hrough accumulating iquid head during he
build up period and moves on up the tubing. All gas
used in the lifting process must be supplied.
2. Continuous gas l if t produces at a relatively constant
rate. Although gas lift is i n the slug flow regime, the
slugs are usually relatively small in size and produc-
tion rate to the separator and other surface facilities
is fairly constant. This is not the case with intermit-
tent lift. The production rate varies widely with a slug
3. If the well is making some sand along with the liquid
production, the shut in period in which flow is not
occurring will allow the sand to fall back around any
equipment in the hole and can be a serious problem.
Where sand is being produced, continuous gas lift is
advantageous.
4. n continuous gas lift, the gas is injected at a rela-
tively constant rate. This can be done in intermittentlift although control of the intermittent lift cycle
works better in most cases if a time cycle controller is
used at the surface and gas is injected into the well
periodically. If the gas lift supply gas system is rela-
tively small, it is very difficult to maintain a constant
system pressure with these periodic surges of gas.
DUAL GAS LIFT INSTALLATIONS
Dual gas lift (the producing of two zones from the same
wellbore by gas lift without commingling the well fluids
in the wellbore) will be discussed briefly. Dual comple-
tions became fairly widespread during the 1960sprimarily
because of very restrictive allowables. When artificial lift
became necessary, dual gas lift was one of the more com-
mon methods selected. Although dual gas l if t is one of the
best methods of dual artificial ift, t s usually very
inefficient.
As mentioned earlier, the well productivity must be esti-
mated when a gas lift design is made. If, as usually occurs,
the productivity is not as estimated, the design will self-
adjust by operating from a different valve or at a slightly
different casing pressure. In most dual systems, both tubingstrings take gas from the same common gas source, the
annulus. In trying to adjust to the different productivities,
the system will frequently allow extra gas to go i n one
tubing string while starving the other side. This results in
one or both zones producing at less than optimum rate. The
most common design procedure is to use valves of signifi-
cantly different operating characteristics - njection
pressure-operated in one string and production pressure
operated in the other. However, efficient dual gas lift has
proved to be a fairly rare occurrence. In the absence of
restrictive allowables, most operators have concluded that
single zone completions are preferable to duals when arti-
ficial lift is required.
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E * V T - h 94 0732290 0532937 584
84 Gas Lift
CHAPTER 7ANALYSIS AND REGULATION OF CONTINUOUS
FLOW GAS LIFT
INTRODUCTION
Continuous flow gas lift makes up the vast majority (90percent) of all wells that are artificially lifted by gas lift. As
previously mentioned, the continuous flow principles are
virtually the same as those at work in a naturally flowing
well; but with gas lift, the volume of gas circulated to the
well is controlled. Hence, the total gas-liquid ratio is con-
trolled. These principles are generally applicable to pro-
duction rates ranging from 100 barrels per day to over
50,000 barrels per day. They are applied by circulating lift
gas down the annulus for tubing flow production or down
the tubing for casing flow production.
From the schematics in Fig. 7-1, it is obvious that theterms casing pressure or tubing pressure are ambiguous and
may mean gas pressure or produced fluid pressure. For
clarity, this chapter will use production pressure to identify
the pressure of the produced fluids. Injection gas pressure
will be used to identify the lift gas pressure at the well.
Operation, maintenance and trouble-shooting of gas lift
installations are covered in API RP llV55’.
Recommended Practices Prior to Unloading
After a continuous flow design is completed and the
equipment is installed in the well, several things should be
done prior to unloading he well by gas lift.
If a well is loaded with mud it should be circulated clean
of mud down to the perforations prior to running gas lift
valves. Abrasive materials n the well fluids can damage the
gas lift valve seats and/or may result in valve malfunction
during unloading operation.f valves are njection gas pres-
sure operated, reverse circulation should not be used since
circulation will occur through the valves. If mud or dirty
fluid must be circulated out, some typef circulating valve
T V W A L T
F L O W aOIIWAT*:T V W A L CA
r 1
ILFig. 7-1- asing and tubingflow installations
should be placed in the mandrel and retrieved after the
circulation is completed, otherwise the fluid could cut the
polished bore in the mandrel where the valve will seal.
If the injection gas line is new, it should be blown clean of
scale, welding slag, etc., before being connected to the well.
This precaution prevents plugging of surface controls, and
the entrance of debris into the well casing.
Separator capacity, stock tank liquid level, and all valves
between he wellhead and he ank battery should be
checked. It is important to check the pop-off safety release
valve for the gas gathering system if this is the first gas liftinstallation in the system.
Recom mended Gas Lift Instal lat ionUnloading Procedure
Care in unloading a gas lift well is extremely important
since more gas lift valves are damaged at this time than at
any other time during the lift of the well. Preventing exces-
sive pressure differentials across gas lift valves reduces the
chance for equipment failure due to sand cutting and liquid
cutting. The following procedure avoids excessive pressure
differential across the valves and is recommended for initial
unloading.
1 . Install a two pen pressure recorder to record the well
gas pressure and production pressure at the surface.
2. Bleed the production pressure down to flowline
pressure.
3 , Remove or open the flowline choke depending on
the well’s expected reaction to gas lift. (An adjustable
choke should be left on the wellhead connection to
the flowline only if the well is expected to flow
naturally after it is “kicked off’ with gas lift.)
4. Slowly control the lift gas into the well so that it takes
8-10minutes for a50 psi increase in well gas pressure.
Continue this rate of injection until the absolute well
gas pressure is about 400 psi.
5 . Increase the lift gas rate into the well so that it takes
about 8-10 minutes for 100 psi increase in the well gaspressure. Continue this rate until gas passes into the
tubing through the top valve.
6 . The gas lift design will have been based on a certain
daily volume of gas injected into the well. At thistime adjust the rate to be only ‘/2 to of the designed
gas injection rate.
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
Not for Resale, 07/27/2006 10:42:36 MDTeproduction or networking permitted without license from IHS
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Analysis and Regulation of Continuous Flow Gas Lift 85
7. After 12-18 hours at the reduced injection rate, adjust instances one or more of the following methods of obtain-
the ga s rate to the full designed rate for the well. ing data willbeused:
Analyzing the Operation of A
Continuous Flow Well
In order to properly evaluate the efficiency of operation
of the continuous flow well, it is necessary to analyze theinstallation. In man y instances the operator is conten t to
leave the well alone as long as he thinks i t is making all
the fluids the well is capable of producing. Quite often, if the
installation were properly analyzed, an improvement could
be made in the injection gas-oil ratio. It is also a common
tendency for the field operator to increase injection gas
rates i n an attempt to produce more oil from the well.
Exces sive injected gas volume may actually increase the
flowing pressure gradient, thereby decreasing production.
Surface Data
1. Recording surface pressure in the tubing and casing
2. Measurem ent of lift gas circulated to the well
3 . Measurement of surface temperature
4. Visual observation of the surface installation
5 . Testing the well for oil, water and gas production
Subsurface Data
1. Pressuresurveys
2. Temperature surveys
There are several m ethods which may be used for obtain-3. Fluid level determination by acoustical methods
in gproper nalysis of agas ift nstallation. In most 4. Computer calculated pressures in the well
METHODS OF OBTAINING SURFACE DATA FOR CONTINUOUS FLOW GASLIFT WELLS
Recording Surface Pressure in theubing and Casing
Two-pen pressure recorders are relatively inexpen sive
instruments using wo pressure elements of the proper pres-
sure range to record the surface tubingnd casing pressures
of the well. Th is instrument will record on a chart any
change in the wellhead pressure of the tubing or casing
during the operational period of the chart. The maximum
pressure rangeof the recorde r should be '/ 4 to '/3 higher thanthe maximum operating pressure of the well. For example,
if the maximum wellhead pressure is 700 psig, the recorder
should have 1,000psig maximum range elements. Thiswill
permit sufficient sensitivity in the instrument to indicate
any small pressure change on the chart.
Some of the important factors to be noted from he
recordings* of tubing and casing pressures are:
1 . Increased flowing production pressure would indi-
cate an increase in separator back pressure, paraffin
deposit ion, or sediment in the flowlines. It could
also indicate that a choke has been installed in theflowline, an increasehas been made in the volume of
injection gas, anoth er well has been added to the flow
system, or that the well has started to flow naturally.
2. Decreased production pressure could indicate a drop
in supply gas pressure r volume, injectio n gas freez-
ing, fluctuating system gas pressure, thewell having
been switched to a test separator, readjustmentf the
injection gas control, or a broken flowline.
*Charts 7A1 hrough 7A14, Appendix 7A, llustrate some of theseconditions. The actual problems encountered are thoseiven in the chartinterpretat ions. Other interpretations might be given if the exact trouble isnot known.
3 . A continuous flow well on production pressure con-
trol would have the periods of gas injection and the
periods of natural flow recorded. (Production pres-
sure control is a means of injecting gas into the well
at a predetermined dro p in production pressure, util-
izing the gas lift alves to purge the tubingof a liquid
loading condition.) The periods of natural flow and
gas injection would be clearly indicated by both the
production and well gas pressure.
4. The changing from one operating valve to another
may be detected.
5. The sanding up or water loading of a well will be
indicated.
6. A hole in the tubing, or a bad gas lift valve will be
indicated.
7. Excessive gas usage may be indicated.
8. Decreased production may be indicated.
Measurement of Gas Volumes
Measuremen t of injection gas volumes is necessary in
order to determine the efficiencyof the gas lift operations.
This is accomplished by the use of an orifice meter or orifice
flow computer which should be located near the injection
gas control to the well.
The meter run should be elevated to prevent condensa-
tion from collecting. Some companies favor a permanentmeter connected to the meter run. Other companies equip
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E S V T - b 94 m 0732290 0532919 357
86 Gas Lift
the meter run with quick connectors to facilitate the use of a
portable meter. The orifice meter consists of a static pres-
sure element indicating the line pressure from the orifice
plate, and a differential pressure element indicating thepressure drop across the orifice plate. This is schematically
illustrated in Fig. 7-2. Periodic injection gas measurement
is required in most states and will give a reliable evaluation
of the efficiency of the gas lift operations. Inefficient gas
injection may be corrected by changing the rate of gas in -
jection and carefully measuring the total fluid productionagainst the injected gas volume for each change, thus pro-
viding a means of determining the most efficient gas oil
ratio.
Fig. 7-2- ontinuous flow semi-closed installation
The static pressure element on the meter is useful i n
determining any pressure fluctuation in the gas system that
may be detrimental to the efficient operationof the gas lift.
Orifice meters arenstalled at the est separators tomeasurethe total gas outof the well under test. The differencen the
injection gas input and the total gas output will represent
the formation gas. Direct reading gas flow computers are
available for instantaneous measurement of gas.
Surface and Estimated Subsurface
Temperature Readings
Surface temperature readings f the produced luid at thewellhead may sometimes aid in analyzing the trouble in a
gas lift well. Where it has been difficult to determine the
cause of inefficient operation, knowing the temperature at
each valve might also disclose that the temperature effecton the valves is preventing the well from producing at its
most efficient rate. If a straight line relationship is assumed,
it is a simple matter to plot a graph of the temperaturegradient when the bottomhole temperature and flowing
surface temperature are known. The depth location of eachvalve may then be located on the chart and the temperature
at each valve may be estimated from the temperature curve.
Most gas lift valve manufacturers have charts for tempera-
ture and gas weight corrections. These charts may be usedto determine the surface operating pressure of each valve.Fig. 7-3 illustrates a continuous flow well that is not pro-
ducing at its capacity because the producing fluid tempera-
ture has raised the pressure of the operating valve to near
system pressure. The producing fluid temperature has
raised the pressure of the valve (at 1,900ft.) to the point that
the differential pressure across the valve will not permit
reducing the flowing fluid gradient to a pressure that would
permit gas entrance through the valve at 2,350 ft. Equip-
ment problems like this can sometimes be eliminated by
using spring adjusted valves hat are not affected by
temperature.
Visual Observationof the Surface Installation
Visual observation of a gas lift installation may some-
times uncover conditions that are detrimental to the overall
efficiency of the installation. Maintaining high separator
back pressure, long or improperly designed flowlines, re-
strictions in the wellhead, paraffin or sediment in the flow-
lines, and too many sharp-angled bends may be the cause ofexcessive back pressure as indicated by the production
TUBING CASING
BDO
I
TEMPERATURE
l05'F
6ooo 41;200 40 0 600 800 1000 1200 1400 1 6 0 0 leo0 2& 2xK)2400m
2000 2510DESIRED FLOWINGRESSURE-
SIG FLOWING 6.H.PRESS.
D ES IR ED PR OD U C TION i 1,200 B I D TOTA L F L U I DPRESENT PRODUCTION: 46 5 B/ D TOTA L FL U ID
STATIC BOTT OM-HOLE RESSURE :2,800 P S l GP R OD U C TIV ITY N D E X (PI1 2 15TU BIN G S IZE i 2-718-11 EU EB O T T O M - H O L E E M P E R A T U R E : 72 FP R E S E N T L OWIN G S U R FA C EEMPERATURE. 105 FS Y STEMGA SPRESSUREATW E L L : 610 P S lG
Fig. 7 -3- ontinuous f low equipment problem or tubingf low well
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I I T L E *V T - h 94 m 0732290 0532920 07’7 m
Analysis and Regulation of Continuous Flow Gas Lift 87
wellhead pressure. The possibility of wet gas freezing at sary for the proper analysis of the operation of a gas lift
points of restriction, fluctuating system gas pressure, an well. In many field installations only oil production is meas-
insufficient differential between system gas pressure and ured and a shakeout is taken to determine the percentage of
wellhead operating pressure, and improper surface control water. This can be very inaccurate in many wells because of
for the type of gas l ift valve in the well should be examined the fluctuations in the amount of water in the flow stream.
where inefficient operation is indicated. Knowing the specific gravity of the oil and water is also
important if the installation requires redesign. This infor-
TestingWell or Oil andGasProduction mation is essential to determinehe fficient point of gasAccurate gauging for oiland water production is neces- injection for the well conditions
METHODS OF OBTAINING SUBSURFACE DATA FOR CONTINUOUS FLOW GAS
LIFT ANALYSIS
Subsurface Pressure Surveys
Subsurface pressure surveys offer a ood means of prop-
erly analyzing gas lift nstallations. A static survey will
determine he static bottomhole pressure (or formation
pressure), the static fluid level, nd the static gradient f thewell fluids. A flowing pressure survey il l locate the point
of gas injection, leaks in the tubing, valve failures, or multi-
point injection. It will also determine th e flowing gradient
below and above the pointof gas injection, and the flowing
bottomhole pressure. By accurately testing the well at the
time the flowing bottomhole pressure is being taken, the
productivity index (PI) of the well may be established. t is a
common fal lacy to wai t unt i l t rouble deve lops be fore mak-
ing apressure survey. The survey might locate the source of
trouble,but he nformationnecessary o mprove he
installation will not be obtained. Therefore, a pressure
survey should be run while the wells supposedly perform-ing satisfactorily. The information obtained might indicate
that respacing the valves would appreciably improve the
production of the well. On wells with high PI’S, and produc-
ing from a very active water drive reservoir, it is recom-
mended that valves be spaced close together near the esti-
mated point of gas injection. A very common error in gas
lift design s failure o space he valves close enough
together. Fig. 7-4 shows a well making 1,000 bbl of oil and
water per day (90 percent water). From all surface indica-
tions, the well was performing satisfactorily. It was, how-
ever, immediately evident from the flowing pressureurvey
that by respacing the valves there would be an increase i nfluid production. It was noted hat he fluid level i n the
casing lacked only a few feet of uncovering the next valve
with the available line pressure. n this example, the valves
were equipped with fixed orifices and no increase of gas
volume could be made through the valves. Since the well
had a PI of 10 BLPD/psi, or greater, the production rate
was increased to 1,600 B/D by respacing the lower valve so
that it would operate 60 ft .nearer the surface. By checking
the static fluid level, t was possible to relocatevalves 1 and
2 from the surface so that two valves could be positioned
below the point of injection. Since the bottomhole pressure
was showing very little drop with time, he spacing wassatisfactory for 1’12 to 2 years.
O
1000
2000
3000
k! 4000
r
kW
k
5000
n
6000
7000
8000
I T C os in g P ressure Flowing
Tubing = 2
- \c I1 Fluid = 1000 B b l s / O o y
Input G o s - Fluid Rat io
= 400/1
””Casing Fluid Level
9000 I I I I I l I IO 400 800 1200 1600 2000 2400 2800
PRESSURE, PSlG
Fig. 7-4- alve spacing from flowing pressure survey
Fig. 7-5 shows a well in which three gas lift valves were
admitting gas. This condition of multi-point njection s
very inefficient, since efficiency i n continuous flow is the
result of injecting the proper volume of gas at the deepest
point for th e available pressure. The flowing pressure gra-
dient ndicated hat too much gas was being injected. A
measurement of the injection gas-liquid ratio showed it to
be 800:1. This was high in comparison with neighboring
wells operating under similar conditions. The pressuresur-
vey did not indicate a need for valve respacing,but rather a
need for the repair of valves 2 and 3. Also valves 6 and 7
could be grouped closer to the point of injection.
Fig. 7-6 shows a ell in which it seems that too many gasl if t valves were used for the installation. This well was
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E S V T - 6 94 0732290 0532921 T0 5 D
88 Gas Lift
TUBING =2"FLUID =700BBLS./ DAY
INPUT GAS-FLUID RATIO=800- I
I2000I \ VALVF DLP-Ta
3000
4000
2400
1 -2. 2850
. 3300
M U L T I -POINT
5000 G A S INJ ECTION
m@ Io &o lobo tim &FLOWNG B.H,PRESS.
PRESSURE PSlG
Well Data: 2% in . OD tubing in 5% in. casing
Gas-liquid ratio- 8OO:l
Production 700 bbl f lu id per day
Oil produ ction =120 B /D
Fig. 7-5- lowing pressure survey fo r valve repair
O
1000
2000
3000
k! 4000
I-W
I
I-;000
o
6000
7000
8000
r Casing Pressure Flowing
Casing Flu id Level
-
-
-
90001 I I I I 1 I
O 400 800 1200 1600 2000 2400 2800
PRE S S URE , P S l G
Fig. 7-6- lowing pressure survey for valve spacing
designed for either continuous flow or intermittent flow
gas lift. Under the present operating conditions, four alves
would be enough to take care of th e well. This was a well,
however, in which the water percentage was expected toincrease considerably. This would result in lowering the
point of gas injection and utilizing the lower valves in the
installation.
Fig. 7-7 shows how a flowing pressure survey was used to
locate a ubing leak. The tubingeak is plainly indicated by
the break in the flowing gradient at 2,070 ft. The normal
point of gas injection is through the valve operating at 2,935
ft. A check on the valve installation showed that there was
no gas lift valve close to the 2,070 ft. depth.
P R E S S U R E IN 100 P S l G
O 2 4 6 8 IO 12 14 I6 18 20
0-I I I , I , I , I I , l , r , l , r , l , l , l l , l l , 1 , 1 1 1 , ~
5 0 0 -
-n i e c t i o n Go r Prrssurr
W
IA2500
z 3000
I
t- 3500
W
4000
4 5 0 0
a
" V.I*e t 1935'
50001F l o w i n g BH P
= 1770 p i g
5500- --- _T.D. =5540'
WELL DATA:
IN JECT IONGAS-LIOUIDRATIO = 5 5 0 : l2-IN. TUBING N 5-112-1N. CASING
PRODUCINGWELLHEADTUBING RES SURE = 110 P S I GSURFACE NJ ECT IONCASINGPRESSURE = 64 0 P S l GPRODUCT ION= 640 B8L FLUI0 P ER DA YOIL PRODUCTION = 5 B / D
Fig. 7-7- lowing pressure survey to locate tubing leak
A pressure survey of a asing flow gas liftwell can be used
to determine the point of injection. Fig. 7 -8 shows he
pressure survey of a casing flow well. The tubing was 2-in.
EUE and extended 4,000 ft. into the well, with the bottom
open-ended. The gage was lowered into the well through
the tubing. The first stop was at 4,000 ft., just below the
bottom of the tubing. Nine stops were made at 500 ft .
intervals, and near the bottom four stops were made at
250 ft. intervals. Thewell was producing 4,000 bbl of fluid
per day at the time the pressure surveywas made, of which
97 percent was salt water. The gas liquid ratio as very effi-cient at 90 C U . ft. of gas per barrel of fluid. The well was
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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‘ A P I T I T L E * V T - 6 94 m 0732290 0532922 941 m
Analysis and Regulation of Continuous Flow Gas Lift 89
producing its depth allowable of 12 0 bbl of oil per day
under these conditions. However, it was capable of produc-
ing a great deal more, and at one time produced over 7,000
bbl per day while it was being regulated. This was still not
the maximum rate for the well and no attempt was made
to reach it .
O
2ooc
40OC
600C
800(
966c
-CASING RESS URE
‘~TU BIN G R E S S U R E
VALVE DEPTH
OF TUBING -4000 FT.
2000 3945
PRESSURE P S l G FLOWING6.H.P
WELL ATA:2- IN TUB ING IN 5 - 1 1 2 - IN C A S I N G
I N PU TGA S -F L U I D RATIO i 90.1PRODUCTION i 4 0 0 0 BB L F L U I D E R D A Y ’WITER ROOU(T1CN. 91 P E R C E N T
Fig . 7-8- lowing pressure survey of cas ingf low gas lift
well
Subsurface Temperature Surveys in Casing
Flow Wells
A temperature survey can also be made inside the tubing
of a casing flow installation to determine the point of gas
injection. As the expanding gas will cool the outside of the
tubing directly above the operating valve, the temperature
gage will record the temperature change. The temperature
survey should be run to the bottom of the well in order to
establish a reliable temperature gradient.
Precautions When Running Flowing
Pressure and Temperature Surveys
Some precautions should be exercised w h e n running
flowing pressure surveys in continuous flow wells. It is
recommended that the well be prepared prior to the survey
by placing the lubricator for the pressure gage in place, with
the addition of a master valve above the flowingwing valve.
It is important to produce the well until a stabilized flow
condition has been established before making the gage run.
It is also necessary o provide a weighted section to the
pressure gage in order to prevent the flow stream from
lifting the instrument, which might result in its damage or
loss. In somehigh volume wells with small tubing, it may benecessary to shut the well in and run the gage to bottom as
fast as practicable. The well then must be returned to stabil-
ized flow and the survey can be started up the hole. It is
recommended that a stop be made every 500 to 1,000 ft.
below the point of gas injection to establish the flowing
gradient in that region of flow. Stops should then be made
approximately 10 ft. below each valve in order to correctly
locate the point of gas injection. This will also locate valve
leaks. Since the higher fluid velocities occur near the sur-face, caution should be taken when a ightening of the
wireline load will indicate that the fluid velocities are trying
to pick up the gage. The well should be closed in at this time,
and t h e gage safely retrieved. The mportant section
(below and above the point of gas injection) will have been
surveyed successfully.
Computer Calculated Pressure Surveys
Pressure surveys that are computer calculated from flow
correlations can be the best means of analyzing the perform-ance of continuous flow gas lift wells. The usual first objec-
tion to this concept s “those computer programs don’t
match the well pressureswhereIcomefrom.”But he
computer calculated results can be made to f i t “the well
pressures where you come from” with a cooperative effort
between the field personnel and the technical groups that
are involved (Le., company engineers or consultants).
Once a fit is accomplished, the benefits are readily avail-
able at a very small cost per run. The results of a computer
calculated pressure survey can be used for redesigning,
trouble-shooting, improving well performance, and updat-ing PI data.
The prudent operator will make use of computer calcu-
lated pressure surveys as often as possible. They will
decrease the number of wireline pressure surveys that are
required with their attendant problems and expense.
Temperature Surveys in Tubing Flow Wells
Temperature plays an important part in the operating of
a pressure-charged valve. For this reason it is necessary to
have accurate bottomhole temperature and surface temper-
ature data under both static and flowing conditions. These
data are necessary for the design of a gas lift installation.
They also may be useful later for locating the depth of the
operating valve.
Fig. 7-9 shows a survey of flowing pressure and tempera-
ture in a gas lift well. It is interesting to note the comparison
of the test rack opening pressure of the valve o he
opening pressures at operating temperature, and finally to the
surface operating pressure. A definite change in both the
producing fluid gradient and the temperature gradient can
be noted at the point of gas injection at 4,000 ft. A flowing
temperature survey can be valuable in locating tubing leaksas well as locating the operating gas lift valve.
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E 8 V T - 6 94 m 0732290 0532923 8 8 8 m
90 Gas Lift
CASING PRESS. SURFACE TEMP.
TUBING =2"
262 GAS-FLUIDATIO =200-
VALVE OPENING A TVALVE TESTDEPTH WRFPCE
2
4"yIí'o00
990 1150 I100
I DEPTH PRESS.PFESS. PRESS.
6oooO 500 1000 1500 2OOO 1 0 0 165O
PRESSURE PSIC. TEMPERATURE F.
Fig. 7-9- emperature andflowing pressure surveyf gas
lift well
I
Flowing Pressure and Temperature Survey
The flowing pressure and temperature survey has long
been one of the primary ways of determining the operating
valve and formation pressure drawdown. The following
procedure is suggested to assure that enough useful infor-
mation will be obtained from the survey to allow you to
make good decisions.1. Run survey under stabilized flowing conditions.
2. Run a pressure and temperature instrument in com-
bination, with the temperature instrument being at
the bottom.
3 . Use enough sinker bars to assure that the instru-
ments will move forcefully down the hole and not be
pushed up the hole by the flowing fluid.
4. Make he following stops recording he ime and
depth reading at each stop.
a. At the surface.
b. One or two stops between mandrel stations.
23 4
Fig. 7-10- ypical acoustic survey of gas lift well
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
Not for Resale, 07/27/2006 10:42:36 MDTeproduction or networking permitted without license from IHS
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A P I T I T L E + V T - h 9 4 0732290 0532924 714
Analysis and Regulation of Continuous Flow Gas Lift 91
c. Four stops around each mandrel as follows:
Stop 1 - 5 0 above
Stop 2 - 25‘ above
Stop 3 - 5‘ above
Stop 4 - 25‘ below
d. From bottom mandrel to perforations as required.
e. At perforations.
5 . Timed duration of stops.
3 min. stops if using a 3 hr. clock; 5 min. stops if using
a 6 hr. clock
Interpretation of the survey data is best evaluated by
plotting the results on a pressure depth diagram. On the
same diagram indicate the depth of the valve stations.
Fig. 7-9 shows he plotting of a typical pressure and
temperature survey and easily identifies the operating valve
or the depth of injection.
Fluid L evel Determinat ion b y Acoust ical Methods
One of the most common and economical methods of lo-
cating the fluid level in the annulus of a tubing flow con-
tinuous flow gas lift well is through the use of acoustical
well-sounding devices. The fluid level in a closed or semi-
closed installation will represent the deepest point to which
the well has been unloaded but may not represent the point
of operation at the present time. In an open installation
with no packer, he pressure in the annulus at the fluid
level would be equal to the pressure in the tubing (this is
often referred to as the “point of balance”), and the oper-
ating valve would be directly above. However, i n a well
containing a packer. It may be that the well originally un -
loaded to a lower valve; and, as the formation fluid en-
tered the well, the formation gas supplemented the injec-
tion gas, permitting the opening of an upper valve. Withthe packer, check valves, and tubing all holding perfectly,
the acoustical device would show the well unloaded to the
lower valve, indicating a false “point of balance.” Peri-
odic sounding should be taken under satisfactory operat-
ing conditions so that they can be used in comparison with
future soundings.
Fig. 7-10 shows a typical acoustic survey of a gas lift
well. The sound impulses decrease with depth but clearly
show all the protruding surfaces on the tubing string, such
as the collars and gas lift valves. As the gas lift valves are
larger and offer more reflective sound surface than the col-lars, a greater impulse is recorded on the chart. The fluid
level in the casing is clearly shown by the large zig-zag
indicating the point of rebound. The rebound reflects a
duplicate of the first recording but to a diminished degree.
The operation of acoustical equipment, and interpreta-
tion of the charts produced, should be done by experienced
personnel. It takes practice, and a certain amount of art
and experience, before a person can correctly interpret the
sound impulses.
VARIOUS WELLHEAD INSTALLATIONS FOR GAS INJECTION CONTROL
Fig. 7-1 1 illustrates a wellhead installation using only a
choke as a gas control. This can be used i n most cases where
the system pressure is reasonably stable. The choking may
be accomplished by the use of an insert or adjustable type
choke or metering valve. n many cases choking may cause
freezing problems. This can be rectifiedy using a dehydra-
tor in the gas system, by using a gas heater ahead of the
choke, or by building a heat exchanger around the choke.
CHOKE
This latter method will permit the hot flowline fluids o pass
over the gas line, thus acting as a heat transfer unit.
Fig . 7-12- hoke-regulator control, ubing fl ow well
CAUTION : THIS SYSTEM WILL WORK ONLY WHEN THE
REGULATOR CAN BE SET HIGER THAN OPERATING
I N JECTI O N G AS PRES S U RE (gas pressure in casingFig . 7-11- hoke control, tubing flo w wellownstream of choke control).
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A P I T I T L E x V T - 6 q V m 0732290 0532925 650 W
92 Gas Lift
PRESS. ELEMENT
Fig. 7-12 shows a wellhead installation that is recom-
mended for most types of continuous flow gas l if t valves
where there is a fluctuating gas system pressure. The regula-
tor is set to operate at a pressure higher than the injection
gas pressure in the casing downstream of the choke control.
The choke is installed in the gas line downstream from the
regulator. The combination of the two permits a constant
gas volume to be injected into the well.
Fig. 7-13 illustrates a production pressure control instal-
lation. This is generally used on wells that have a tendency
to flow. The pressure element on the gas control valve is set
to inject gas when the production pressure drops below its
normal flowing pressure. It is recommended that a choke be
used with the gas control valve to prevent surging of the
well gas pressure.
Fig. 7-13- roduction pressure control of the injection
gas, tubing flow well
WELL INJECTION GAS PRESSURE FOR CONTINUOUS FLOW SYSTEM S
For many years it was a general rule that continuous flow
gas lift needed a well injection gas pressure of 100psi/lOOO
ft. of lift. This led operators in many fields to select an
injection gas system of less than 1000 psig.Today, these pressures are considered low for gas lift
purposes. Also, the approach to design and selection of the
injection gas pressure is more sophisticated. It is related
specifically to the highest expected flowing bottomhole
pressure in the field. This approach led to higher pressure
systems of 1440 psig (ANSI Series 600) and higher.
Some of the deeper oil fields are planned for reservoir
pressure maintenance before the field is completely drilled.Tying the gas lift system design to reservoir performance
allows efficient production at higher flowing bottom-hole pressures as high as 2300 psi.
Gas lift valves are easily adaptable to 1400 psi well gas
pressures and several vendors have valves fo r 2000 psi and
higher gas systems.
GETTING THE MOST OIL WITH THE AVAILABL E GASLIFT
The efficientdistribution of circulatedgas to each well promiseforefficiency, but progress with this method ison gas lift isof primary concern to operating personnel. It is moving slowly. Therefore, the methods that are most com-
this component of the gas lift system with which the opera- monly used today will be discussed first. In all cases, itwill
tor has direct and daily contact. So, it is the component of be assumed that a two-pen pressure recorded for recording
the system that the operator uses to make a system efficient. both casing and tubing pressures is on the well and that a
The principles given here apply to both continuous flow meter run for measuring lift gas is at each well.
discussed in this chapter, and intermittent lift which will be
discussed in the followinghapters. Manualontrols
The detailsof this componentwill be discussed as related These controls arehe least efficient becausehey require
to the method of control exercised by operating personnel. manual changes i n adjustment when any system parameter
The methods generally used are manual and semi-automatic changes, and because their durationof efficiency is only as
control. A few companies have mplemented automatic long as all systems parameters are constant. Manual con-controls. The automatic control method offers the greatest trols are detailed in Fig. 7-14.
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A P I T ITLE*VT -b 9Y 0732290 0532qE‘b 597
Analysis and Regulation of Continuous Flow Gas Lift 93
A gas injection choke is commonly used for continuous
flow and sometimes for intermittent lift. Chokes in inter-
mittent lift wells are usually used only when pilot or pro-
duction operated valves are employed. The choke controls
the rate of circulated gas to the well and does a good job
only as long as P, and PCr remain fixed after the adjustment is
made. Pcrstays constant because t is partially controlled by
the gas lift valves. But if P, increases, inefficiency is intro-duced because the choke will pass more gas than needed. If
P, decreases, the choke will reduce the volume of gas circu-
lated and the volume of produced fluid will be reduced.
Semi-Autom atic Controls
The manual surface controls may be improved by install-
ing a pressure reducing regulator between the control and
the high pressure gas source (Fig. 7-15). This provides a
constant upstream pressure to each and eliminates the inef-
ficiencies caused by increases in upstream pressure.
This control omponent may be used for continuous flow
and some intermittent lift wells (if the intermitting valves
will operate properly with choke control and have correct
operating speed) and is a significant improvement over the
“choke only” installation when injection gas system pres-
sure varies. The gas rate to the well is a functionof Pg2. An
increase in Pgwill not be harmful.
Basically, the semi-automatic controls preserve efficient
gas control as ong as the injection gas pressure (Pg)remains constant or ncreases. Efficiency is maintained
with a limited (and defined) decline in P,, but there is still no
protection against an excessive decline in P,.
righ pressure gas source
Optimizing Gas Lift Systems
The gas controls discussed previously have been im-
proved to the point that they remain efficient until a defined
loss in injection gas pressure (P,) is reached. Therefore, if
operating personnel can educe or eliminate the occurrence
of a degrading P, then another improvement in system
efficiency is accomplished.For this purpose the following definition is acceptable: A
gas lif t system is optimized when the maximu m possible
barrels of oil are produced w ith the available circulated
gas volume.
1. Establish Priority System
Toaccomplish his, the operatingpersonnelmust
establish a priority system defining which wells get circu-
lated gas when there is a shortage of circulated gas
volume. The best basis or a priority system is the circu-
lated gas-oil ratio (or the injected gas-oil ratio, IGOR)for eachwell in the system. Each time a well is tested the
following data are available:
BOPD - arrels of oil/day (qo)
BWPD- arrels of water/day
TGAS - otal gas from test separator, standard cu-
IGAS - ift gas circulated to the well, SCF/D (ig)
FGAS - ormation gas produced, SCF/D
After the test, calculate IGOR (Rgoi=ig/qo). he well
that has the lowest IGOR has top priority for circulated
gas.Everyeffortshouldbe made to circulate herequired gas to his well as long as any gas is available.
bic feet per day (SCF/D)
.Meter run Choke7 Pc f
1
c L
‘ IFig. 7-14- anually adjustable or positive choke
pressure reducing
regulator
/ Choke
Fig. 7-15- ressure reducing regulator and choke
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A P I T I T L E t V T - b 94 m 0 7 3 2 2 9 0 0532927 423 m
94 Gas Lift
2.
By calculating an IGOR for each well from its latest test,
the operator completes the priority list.
The highest IGOR’s are now defined and theyshould bethe first wells o lose circulatedgas when thegas
volume is reduced due to a loss in injection gas ine
pressure.
Implementing Priority System
Keeping the priority list up-to-date is a necessary part
of the system. It is unlikely that a particular well moves
from the lowest to the highest IGOR; but positions on
the priority list will change as well conditions change.
The status of the high pressure gas source can be recog-
nized by the pressure. Table 7-1 illustrates ogical con-
clusions.
TABLE 7-1
STATUS OF HIGH PRESSURE GAS SOURCE
Pressure of Logical Status ofigh
H.P. Gas Symbolressure Gas
Source
Normal N All is well- irculated gas
volume equals available gas
volume
Above AN More gas volume available
Normal than is being circulated to
the wells
Slightly SBN More gas volume is being
Below circulated than is available,
Normal but all wells are producing
Drastically More gas volume is being
Below DBN circulated than is available
Normal and some wells are not
producing
The symbols of Table 7-1 will be used to indicate the
status of the higher pressure gas source.
From the priority list select 20 to 30 percent of the wells
that have the highest IGOR’s.
With the above parameters defined, a priority system can
be implemented manually or automatically, as described in
Table 7-2 and Table 7-3.
TABLE 7-2
MANUAL ACTION TO OPTIMIZE USE OF
CIRCULATED LIFT GA S
Status of H.P. Action
SBN Reduce or stop circulated gas to wells
with highest IGOR’s until statusreturns to AN. Then restart gas to
wells in ascending priority numbers
until status returns to N.
DBN Stop circulated gas to wells with high-
est IGOR’s until status returns to N.
Low pressure shut-in valves should be installed on the
selected wells with high IGOR’s (20 to 30 percent of the
wells) in order to semi-automatically optimize the circu-
lated lift gas. Half of the selected wells should be equipped
with low pressure shut-in valves that automatically reopen
when the system pressure recovers. The other half should be
equipped with low pressure shut-in valves requiring manual
reset to reopen.
TABLE 7-3
SEMI-AUTOM ATIC A CTION TO OPTIMIZE USEOF CIRCULATED LIFT GAS
Statusction
N All wells taking gas as adjusted by
operating personnel
SBN Gas is stopped to high IGOR wellsw/auto reopen. No gas will go to them
until status recovers above SBN. These
wells will then automatically start tak-
ing gas again.
DBN Gas has already been stopped to well
w/auto reopen pilots. Gas will now be
stopped to wells w/manual reset
pilots. If this action allows status to
recover above SBN. the wells w/auto
reopen pilots will again get circulatedgas. Operating personnel must person-
ally reset the other wells before circu-
lating gas will be restarted to them.
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Analysis and Regulation of Continuous Flow Ga sif t 95
Automatic Optimizationof Injection G as Use
M a n u a la nds e m i - a u t o m a t i cop t imiza t i on p l ansa re
keyed to trigger action only on a loss of pressure in the high
pressure gas sources. Their inherent weakness s hat hey
rely completely on he operat ing personnel to recognize
chan ges in the well’s characte ristics or malfunctions in the
subsurface equipment . Wi th oday’s echnology, micro-processorsandcomputersm aybeused omoni tor he
well’s perform ance, evaluate the status of downho le equip-
ment, measure the volume of high pressure gas available
and distribute l i ft gas in the most efficient manner auto-
matically.
A few compa nies have already used parts of this technol-
ogy. An even fewer number have plans to implement com-
pletely automatic optimization systems. But a utomatic gas
lift syste ms can be an econom ic field proven reality. Until
then, operat ing personnel must do the best hey can withmanua landsemi -au toma t i csu r facegascont ro ls ,and
optimization plans, to get th e most oil with the availa ble lift
gas.
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A P I TITLE*VT-b 9q W 07322900532929 2Tb W
APPENDIX 7AEXAMPLES OF PRESSURE RECORDER CHARTS FROM
CONTINUOUS FLOW WELLS
Operation: Continuousflow, casing choke control, tubingflowType o fwell: High produc tivity, high bottomh ole ressure
Trouble: None
Recom mend ation: Leave well aloneType of gas lip valves: Injection pressure-operated
Remarks: Good cont inuous f low operat ion. Wel las a high working f luid evel .Note the low b ack pressure ef fect . Wel l producing2,100 bbl o f f lu id per day- 5 percent water - f rom
water drive reservoir, thr oug h 2% in. tubing.
Chart 7 - A l
Operat ion: Cont inuous f low,asing pressure control with egulator, tubin g f lowType of well: High produc tivity, h igh bottomh ole pressur e
Trouble: Inadequate productionRecom mend ation: Reduc e back pressure
Type o fgas lijit valves: Pressure operatedRema rks: Excessive back pressure may be due o one or more of the fol lowing:
1.
2.
3.4 .
5 .
6.
7.
Choke in f low ineRestriction inflow line (paraffin, snnd, etc.)Flow line too small or too long
Separator pressure to o highToo many sharp bends inf lo w ineHighly emulsif iedfluid
Excessive inp ut gas
Chart 7-A2
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Examples of Pressure Recorder Charts from Continuous Flow Wells 97
Operation: In termittent injection vs. continuou s injection, tubing lo w
Type o fwell: Borderline produ ction rate
Trouble: Inadequate productionRecommendations: A n intermittent and continuouslow prod uctio n omparison
Type o fgas lq t valves: Pressure operated
Remarks: Compare intermittent to continuous fl ow to determine most efficient productio n rate
Chart 7-A3
Operation: Con tinuo us flow , asing choke control, tubing lo w
Type of well: High productivity, high bottomhole ressureTrouble: NoneRecommendations: Leave well alone
Type of gas l$t vulves: Injection pressure-o perated
Remarks: Thewell had been shut in overnight, and thegas ha d been turnedn shortly before he chart was changed. T he
casing pressure was at 46Opsig at the beginn ing t 10:15 a.m. There was agrad ualpress ure rise to 468psig due
to flu id temperature increase affecting valve.A t 2:45p.m. the casingpressure increased to 48Opsig and a “kick”
can be noted n the tubingpressure.his was du e to n upper valve becominghe operating valve.A t I0:OO a.m.
the nex t mo rnin g the asing pressure had increased to 490 psig due to temperature effect.
Chart 7-A4
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98
A P I T ITLE+VT-b 94 m 0732290 0532933 954 m
Ga s Lift
Operation: Continuous flow, casing choke control, tubing flow
Type of well: High productivity, high bottomhole pressure
Trouble: Choke ongas line rozeRecommendations: A gas heater might be installed ahead of the choke,r a jacket mighte welded around the chokeo
permit the hot flowline fluids toass over it, or the well might be placed on intermittent injection
Type of gas l f t valves: Pressure operated
Chart 7-AS
Operation: Continuousflow, tubingflowType of well: High productivity, high bottomhole pressure
Trouble: None, well is lowingRecommendations: h a v e well alone
Type of gas lìjt valves: Pressure operated
Remarks: Well is flowing; nogas is being injected
Chart 7-A6
yright American Petroleum Institute
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A P IT I T L E + V T - b 94 m 0732290 0532932 8 9 0 m
Example of Pressures Recorder Charts fromontinuous Flow Wells 99
Operation: Co ntin uo us flow , asing choke control, tubing lo w
Type of well: High productivity, high bottomholepressure
Trouble: Well was closed in to repa irflow ineRecommendat ion: None
Type of gas lyt valves: Pressure operated
Rem arks: Wh en the master valve was opened the tubing pressure was 250 psig. Flow immediately started but the
pressure declined to 21 0 psig at the peakof U-tube. A s the gas cleared throug h the gas lift valve the tubin g
pressure increased to a m a x i m u m of 345 psig, then ell off and fina lly stabilized at 285 psig.
Chart 7-A7
Operation: Continuous flow, tubing control, tubingl o w
Type of well: High productivity, high bottomho lepressure
Trouble: W ell is flo wi ng , bu t loads up with water periodically
Reco mm endatio n: Operating satisfactorily
Rem arks: The tubing contro l elem ent is set to inject gas into the well when th e pressure decreases to 160 psig. It can be
no ted by the ise in casing pressure opposite the drop in tubin g pressu re
Chart 7-A8
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Operation: Continuous low, casing choke control, tubing flow
Type of well: High productivity, high bottomhole pressure
Trouble: Well is being tested in test separatorRecommendation: Remove high normal back pressure, or test against same high back pressure for accurate flo w test
Remarks: It would be impossible to have an accurate production test on the well under the above conditions
Chart 7-A9
Operation: Continuous flow, casing choke control, tubing flow
Type of well: High productivity, high bottomhole pressure
Trouble: Well is closed in
Recommendations: Check to see why it is closed inType of gas lijìt valves: Pressure operated
Remarks: On checking, it was noted that the well hadproduced its monthly allowable, and had been closed in. This can
hurt some oil wells. It is better to cut the daily production and produce the well constantly.
Chart 7-AIO
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Example of Pressures Recorder Charts from Continuous Flow Wells 101
Operation: Co ntinu ous flow , asing choke control, tubing lo w
Type of well: High produc tivity, high bottom hole pressure
Trouble: Not serious, well is “heading”
Recommendation: Check to see if system gas pressure fluc tua tes
Type ofgas lift valves: Pressure operated
Remarks: Reasonably good operation.Well has a tendencyo “head, ”w hich cou ld e caused by erratic valve operation
or afluctuating system pressure.
Chart 7 - A l I
A choke was used on thega sine to control thegas volume into the casing-tubing annulus. W hen thegas wasfirs t tur
on, an immediateurge of f l u id returned from the tubin gs the well was com plete ly fu l l f salt water. When the liquidvol um e displaced in the annulus stabilizedo t h e g a s v o lu meate of thenjection gas, the tubing pressure remainedt 50
psig until the top valve as uncovered and gas entered the tubing.A surge in tubingpressure is note d as each valve is
uncovered. T he wellfinally stabilized on the 4th alve.
Chart 7 - A l 2- nloading continuous fl ow well
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A P I T I T L E x V T - 6 94 m 0732290 0532935 5T T m
102 Gas Lift
CHAPTER 8INTERMITTENT FLOW GAS LIFT
INTRODUCTION
Continuous flow gas lift normally is more efficient than
intermittent flow gas lift and, therefore, should be used
whenever possible. There are, however, minimum liquid
rates for each conduit size thatan be lifted efficientlywith
continuous flow. Minimum iquid rate usually occurs at
about 100 to 150 BLPD in 2 3 / ~ “ubing, 200 to 300 BLPD in
27/~“ubing and 300 to 400 in 3‘/2’’ tubing. When the min-
imum rate is reached, then intermittent lift should be consid-
ered. However, there may be a broad range of lower pro-
duction rateswhere the two types of gas lift are about equal.
In such a case, therewould be little justification for change
unless there were other contributing factors. Usually inter-mittent lift is conducted in 2 3 / ~ “ubing; however, there are
many successful installations using 2 7 / ~ ”nd 3 ’ / 2 “ tubing.
Intermittent lift is a displacement process.High pressure
gas is injected into the liquid column on a cyclicor intermit-tent basis creatinga gas bubble which expands pushing the
liquid above it to the surfacen a slug. While t is normally
associated with low volume producers, intermittent lifthas
successfully lifted wells at ratesn excess of 500 barrels of
liquid per day (blpd), although such a rate couldprobably
have been ifted more efficiently with continuous flow.
Wells with high productivity indices (PI) and low bottom-
hole pressure or wells with low PI’S requiring low flowing
bottomhole pressures are most suited to this type of lift.
Intermittent ift should achieve ower average flowing
bottomhole pressures than can be obtained with continu-
ous flow in wells producing at low flow rates and at low
flowing bottomhole pressures.
Intermittent gas lift with the more commonly used gas
pressure operated valves requires periods of high instan-
taneous gas injection rates separated by periods of no gas
injection. With time cycle control, the cyclic high instan-
taneous injection gas demand rate from th e injection line ishard on the injection gas system. When a well demands gas,
the pressure in the injection system is pulled down. This
creates problems at the compression station since compres-
sors are not well suited to a “flow-no-flow” set of condi-
tions. Because of this problem, the volumetric capacity of
the injection system should be arge so it can act as an
accumulator to help smooth out the flow surges. Gasmeas-
urement is also very difficult because of the cyclic flow.
Usually intermittent lift wells require more attention than
continuous flow wells to keep them producing at the maxi-
mum efficient rate.
OPERATING SEQUENCE
The operating sequence or cycle after unloading of an
intermittent lift installation using gas pressure operated
valves is shown in Fig. 8- . In (A), formation liquids accumu-
late and rise in the tubing. All gas lift valves are closed.At a
predetermined time (B), the intermitter or controller on the
gas line at the surface opens and injects gasnto the tubing-casing annulus. This increases theas pressure in the annu-
lus until this pressure and the liquid pressure in the tubing
are sufficient to pen the operating valve.All the restof the
valves remain closed because the gas pressure alone s not
sufficient to open the valves. Gas is injected very rapidly
into the liquid column creating a gas bubble. s the bubble
expands, it pushes the liquid above it to he surface. In
(C), the liquid slug has reached the surface atwhich time the
operating valve should close. The intermitter or controller
has already closed. In (D), the slug has moved down the
flowline to the separator, the “tail gas” behind the slug has
bled off, and formation liquids are again accumulating inth e tubing.
Several hings are apparent from his explanation.
(1) The gas should be injected rapidly. If not, i t will just
bubble u p through the liquid without lifting any liquid to
the surface. Consequently, large-ported valves that tend to
“snap” open rather than throttle open are recommended for
the operating valve. ( 2 ) The operating valve should be thebottom valve and should be located just above the packer.
This way the lowest possible flowing bottomhole pressure
can be achieved. (3) The back pressure at he surface should
be as low as possible to minimize fallback, maximize the
initial starting slug, and reduce the amount of gas required
to lift the liquid slug to the surface. Ideally, the flowline
shouldbe arge in diameter and short in length. Small
diameter, long flowlines are very detrimental to intermit-
tent lift installationsbecause they cause high wellhead pres-
sures. This problem can sometimes be reduced by decreas-
ing the maximum injection gas cycle frequency in high PI
wells.
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I API T I T L E r V T - b94 m 0732290 0532736 436 m
Intermittentlowasift 103
[ A) I m m e d io t c l y B e f o r e
G a r n j e c t i o n
V ol ve C lo s e d
V a l v e Closed
V o l v e C lo s e d
V a l v e C lo s e d
Opere l ing
V o l v e Open
V o l v e C lo s e d
V o l v e C lo s e d
V o l v e Open
O p c r o t i n g
[C) I n j e c t i o n Co s Ente r ing
Tu b in g Th r o u g h Vo lve
A f t e r C o n t r o l l e r C lo s e d
[D ) A f t e r Go r n j e c t i o n
Fig.8-1- ntermittent lift cycle of o peration fo r conventional closed intermittent installation
TYPES OF INSTALLA TIONS
The illustrations in Fig. 8- 1 show a closed installation. A
closed installation uses a packer and a standing valve below
the bottom gas lift valve. An open installation has neither a
packer nor a standing valve. A semi-closed installation has
a packer but not a standing valve. The closed installation is
recommended for intermittent lift. Since pressure acts
downward as well as upward the standing valve prevents
the high pressure gas from forcing liquids back into the
formation on each cycle. A tanding valve is normally recom-
mended; however, it can cause problems if the well produces
sand. The sand can collect on top of the standing valve mak-
ing it difficult if not impossible to pull.
The other two ypes of installations (open and semi-
closed) will allow the high pressure gas to act on the forma-
tion thereby decreasing the efficiency of the lift. An open
installation without a packer s not recommended for
intermittent lift.
FACTORS AFFECTING PRODUCING RATE
The primary factors affecting the maximum producing rate Maximum Ratein intermittent lift are ( 1 ) tubing size, (2) depth of lift, The maximum rate at which an intermittent lift well can
(3) injection gas pressure, (4) wellhead back pressure, be produced is limited by the maximum number of times
( 5 ) gas passing ability of the gas lift valve, (6) gas break- the well can be cycled in a 24-hour period. Experience has
through and fall back, (7) bottomhole pressure build-up shown it takes about 3 minutes per 1000 feet of lift to inject
characteristics, and (8) other unusual well conditions such the gas, open the operating valve, lift the slug to the sur-as emulsions. face, and bleed off the tail gas. This time will vary from
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A P I T I T L E * V T - b 94 m 0732290 0532937 372 m
104 Gas Lift
installation to installationbut the time of 3 minutes per 1000
feet of lift is a good rule to use for estimating maximum
production rate and minimum cycle time.
Fallback
In intermittent lift, he gas alone does ot sweep all of the
liquid out of the tubing from the operating valveo the sur-face. Some liquid always falls back. Some of this liquid
wets the walls of the tubing and runs back down. Also, the
gas has a tendency o bubble up through the liquid allowing
some of the liquid to drop back down. Fallback can be de-
fined as the difference between the starting slug and the
produced slug. This is shown in Fig. 8-2.
Gas break-through and fallback are affected by three
things; the development of the gas bubble, the upward
velocity of the liquid slug, and restrictions at the ellhead.
1. Development of the Gas Bubble
If the operating valve has a small port or tends to throttleopen rather than snap open, gas will enter slowly and tend
to rise up through the liquidwithout providing much lifting
action. Gas should enter the tubing quickly o form the gas
bubble and to accelerate the liquid slug up he ubing.
Consequently, large-ported, snap-acting gas lift valves are
recommended for the operating valve for intermittent low
gas lift.
2. Velocity of the Slug
The slower the slug moves up the tubing, the longer the
gas has to break through the liquid. Aminimum slug veloc-
ity of 1000feet perminute is recommended to minimize gas
break-through.
3. Restrictions at the Wellhead
The third factor affecting fallback is restrictions at the
wellhead. The usual flow path through the Christmas tree
into the flowline is rather tortuous; first through aee to the
wing valve, then through another 90"ell or choke tee, hen
through at least one more and probably two or more 90"
ells before reaching the flowline. All this slows down the
slug allowing more liquid to fall back. The flow pattern
through the Christmas tree should be streamlined as much
as possible. For example, the flow could be out the top ofth e tree and then through a sweeping pipe end to bring theflowline back to the ground as shown in Fig. 8-3.
For estimating purposes, the fallback on a properly
adjusted intermittent liftwell will be about 5 to 7 percent of
the starting slug per 1000 feet of lift.
STARTING LIQUID SLUG AND FALLBACK
TOSEPARATOR
STARTINGSLUG t
TOSEPARATOR
INJECTIONGAS
L
".'''1 I OPERATING VALVE
PRODUCEDSLUG
FALLBACK
\I
INJECTIONGAS
. , OPERATINGALVE*.
AJST AFTERCLOSING
FALLBACK =STARTMG SLUG - PRODUCED SLUG
Fig. 8-2- llustrations of starting slug, produced slug, and fallbac k
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API TITLE*VT-b q q 0 7 3 2 2 q O 0532938 2 0 7 m
Intermittent Flow Gasift 105
Use of Plungers in Intermittent Lift Systems
Fallback can be reduced to an absolute minimum by
using a plunger with the installation. The plunger acts as an
interface or piston between the gas and the liquid, minimiz-
ing gas break-through. It also wipes the liquid from the
tubing wall reducing the amount left to fall back. A tubing
stop and bumper spring are installed just above the bottomor operating valve. After each slug surfaces, the plunger
falls back to the bumper spring to start another trip. In such
a system, the plunger would be inoperative if one of the
upper valves turned out to be the operating valve. There-
fore, the installation must be designed so that none of the
upper valves will open while operating from the bottom
valve. If an upper valve opens, it may blow the plunger back
down preventing proper operation of the installation. Some
conventional plunger equipment should not be used with
wireline or side pocket mandrels. However, specially de-
signed plungers for wells with sidepocket mandrels are avail-
Fig. 8-3- t r eaml i ned we l l head for i n t e rmi tt en t i n - able. For additional information on plungers, see the use ofstal lat ion plungers in gas lift operations in Chapter 10.
DESIGN OF INTERMITTENT LIFT INSTALLATIONS
There are many methods of designing intermittent lift
installations. Most of them fall into two basic categories; a
fallback gradient method and a percent load method.
Fallback Method
The fallback gradient method uses an average gradient ofthe tail gas, liquid fallback, and liquid feed-in to predict the
minimum tubing pressure obtainable. This average gra-
dient or intermittent spacing factor (SF) is dependent on
the tubing size and anticipated production rate. Generally
0.04 psi per foot of depth is the minimum that should be
used for unloading.
This method normally uses the same surface closingpres-
sure for all valves except the perating valve which usually
has a lower surface closing pressure. The surface closing
pressure of the unloading valves normally should be 100
psi less than the system gas pressure. In 1963 White et al36
determined that the tubing pressure at the operating valveshould be 59 percent of the gas pressure at the operating
valve, at the instance the alve opens, for themost efficient
operation. The commonly used value is 60 percent. Thus
knowing the gas pressure at the valve, the tubing pressure
can be calculated when the valve opens. After the gas pres-
sure and the production (tubing) pressure at the valve are
known, the P,, (valve closing pressure) of the valve can be
calculated. This will show that the P,, is 50 to 90 psi less
than the gas pressure at the valve depending on the valve
characteristics. Therefore,selecting the surface closing pres-
sure 100 psi less than the surface injection pressure will
be on the safe side and account for fluctuations in gaspressure.
Because of the normally low, irregular producing rates n
intermittent lift wells, the temperature gradient for design
purposes is assumed to be geothermal. Also for intermit-
tent lift design purposes, the surface temperature usually is
assumed to be 74°Fin the U.S . Gulf Coast which is approxi-
mately the temperature that would be measured about 50
feet below the ground level. However, surface temperaturesvary by region, and the correct temperature for the region
should be used.
The intermittent lift spacing factor (unloading gradient)
is determined from Fig. 8-4. This figure was developed from
many flowing pressure surveys on many intermittent ift
wells. The spacing factor accounts for the increasen pres-
sure with depth of the gas in the tubing above the liquid
level, fallback fluid transfer from the casing to the tubing
and feed-in after drawdown is achieved.
Example Design Using Fallback Method:
The following well data illustrates the fallback method
design:
Depth =5000 feet
System gas pressure =700 psig (0.65 gravity)
Surface tubing pressure =65 psig
Static bottomhole pressure =775 psig
Bottomhole temperature =150°F
Producing rate =100 BLPD
Kill fluid gradient =0.465 psi/ft.
Tubing size =Z3/8-in. O.D.Casing size =5'h-in. O.D.
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A P I T I T L E * V T - b 94 m 0732290 0532939 145
106 Gas Lift
Gas lift valve = l'/*-in. O.D.N2 charged, '/M in. seat,A,/& =0.201, 1 - A,/& =0.799
Explanation of GraphicalolutionUsingallback 5 .
Method:
A graphicalsolution is theeasiest way to solve the prob- 6.
lem. The following is a step-by-step procedure.
1.
2 .
3.
4.
Preparea heet of graphpaper with depth,pressure 7.
and temperature scales as shown in Fig. 8-5.
Plot the wellhead pressure (65 psig) at zero depth
(surface).
Determine the appropriate spacing factor (unload-
ing gradient) for the particular well from Fig. 8-4.
This is a function of the anticipated production rate,
tubing size, etc. (In this example i t is 0.04 psi/ft).
Extend this gradient of 0.04 psi/ft from the wellhead
8 .
' 9.
pressure (65 psig) at the surface to the bottom of the
well (265 psig at 5000 ft.).
Plot the surface gas injection pressure. Use pressure
50 psi less than system pressure (650 psig).
Extend his pressure o he bottom of the well
accounting for the gas column weight (720 psig at
5000 ft.).
Plot 700 at the surface; 150°F at 5000 ft.and draw a
straight line between the two points.
Subtract 100psi from the surface injection pressure
and plot this as the surface closing pressure of the
unloading valves (550 psig).
Extend he pressure o he bottom of thewell
accounting for the gas column weight (610 psig at
5000 ft.). This line and the one plotted in step 6 are
almost parallel, but not quite.
Fig. 8-4- ntermittent l if t spacing factor
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Intermittent Flow Gas Lift 107
10. Determine the static gradient of the kill fluid. For
this example it is 0.465 psi/ft.
11. Extend a 0.465 psi/ft gradient line rom the wellhead
pressure (65 psig) to intersect the gas pressure at
depth line plotted in step 6 .
12. This intersection is the depth of the top valve (1 00
ft.).
13. Draw a horizontal line o the eft to the spacing
factor line plotted in step 4.
14. From the intersection of the horizontal line and the
spacing factor line, draw a .465 psi/ft gradient line
to intersect the P,, line to locate the depth of the
second valve (2300 ft.).
15.Continue hisprocedure o total depth.Fig.8-5
shows the depths for the remaining valves.
16. Determine the temperature at each valve depth.
17. The final item is to calculate the set pressures of the
valves. Read the pressures at the intersections of the
horizontal lines and the P,, line. These are the PVC's
of each valve. The set pressure of a nitrogen charged
valve is calculated by the following equation:
Equation 8.1
If the valve is spring loaded, the equation is:
PVCP,, =
I - Ap/Ab
Where:
Equation 8.2
P,, = Valve opening pressure in tester
P,, = Valve closing pressure
CT =Temperature correction factor
1 - A,/& = Manufacturers specification for the
valve.
PRESSURE - 100 PSI0 TEMPERATURE - 'F
O 2 6 8 700 90 1001020 130 14050
Depth
1300
2300
3200
4100
4800
C, =0.841
PVC Temp. c, p v o"- -668 07 0.038 665
57 8 10 7 0.008 655
688 121 0.884 650
600 136 0.860 646
600 148 0.841 640 Uee 616 PSlG
Fig. 8-5- xample of graphical solution using fallback method
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A P I T I T L E * V T - 6 94 m 0 7 3 2 2 9 0 0532743 B T 3 m
108 Lift
18. Decrease the set pressure ofhe bottom valve 25 to 30
psi. This is calledflagging the bottom valve and is
done so that it can be detected on a 2-pen pressure
chart. Also consider using a large ported pilot valve
on bottom.
19. List the results as shown in Fig. 8-5.
Percent Load Method
The other generalmethod is commonly called the percent
load method. As mentioned earlier, the White et al paper
determined that the production pressure at the operating
valve should be approximately 60 percent of the gas pres-
sure at the valve at the instant the valve opens for efficient
lift. This then becomes the basisof this method.
Explanation of graphical solution using percent load
method follows:
(Use the same well data given for fallback design.)
1. Prepare the graph paper as shown i n Fig. 8-6.
PRESSURE - 100 PSlG
2.Plotwellheadpressure ( 6 5 psig)atzerodepth
(surface).
3. Plot the surface gas injection pressure (650 psig).
4. Extend hispressure o hebottom of thewell
accounting for th e gas column weight (720 psig at
5000 ft.).
5 . At the surface plot 60 percent of th,e injection gas
pressure (0.6 x 650 =390 psig at surface).
6. At the bottom of the well, plot 60 percent of the gas
pressure at th e bottom (0.6 x 20 =432 psig at 5000
ft.).
7. Extend a 0.465 psi/ft gradient line from thewellhead
pressure (65 psig) at the surface to he gas pressureat
depth line to locate the top valve (1300 ft.).
8. Draw a horizontal line o the left to intersect theper-
cent load line.
TEMPERATURE - OF
O
1
I-W
k ! 2
:2
t 3
O
O
I
Wn
4
S
Depth
1300
1000
2600
3100
3700
4360
4060
401 PSlG
408 PSlG
41 1 PSlG
416 PSI0
421 PSlG
428 PSlG
432 PSI0
PP P9"01 6(10
406 677
411 686
416 673
42 1 702
426 716
432 710
Pbtemp.
614 91
622 100
630 110
637 120
646 120
867 139
66 1 149
"-0.936
0.92 1
0.903
0.886
0.87 1
0.856
0.839
-v o
720
716
710
706
706
70 0
676 Use 670 PSKi
Fig. 8-6- raphical solution using the percent load method
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A P I T I T L E + V T - 6 94 m 0732290 0532942 73T m
Intermittent Flow Gas Lift 109
9.
10.
11.
12.
13.
14.
From this intersection draw a 0.465 psi/ft gradient Notice that the spacing between valves increases with
line to intersect the gas pressure at depth line to depth and seven valves are required whereas the fallback
locate the depth of the second valve (1900 ft.). method required five valves.
Continue the procedureo the bottom of the well. Variations of Percent oadMethodFig. 8-6 shows the depths of the remaining valves.
Many variations of the percent load method have been
At each valve depth read the gas Pressures (pg) on the devised to reduce the number of valves required. Probablygas Pressure at depth ine and the Production Pres- the most commonly used procedure is called the 40 - 60
Sures (PP) on thePercent oad ineateachvalve percent method. This modification uses 40 percent of the
depth. gas pressure at the surface and 60 percent of the gas pres-
sure at the bottom of the well. In this method, spacingDetermine the temperature ateach valve depth.
between valves decreases with depth and fewer valves are
The set pressure for nitrogen charged valves is calcu-required.
lated by the equations: Stillnotherrocedure is a combination of the fallback
~~~~~i~~ 8.3 andpercent oadmethods. Valves are paced rom the
surface using he fallbackmethoduntildrawdown s
Equation8.4 achieved. Then the 60 percent load method is used from
Pbt =Pg (1 - Ap /Ab) +Pp(Ap Ab)
( Pd (cf)P"" =
1 - (ApAb) there to the bottom of the well.
For a spring loaded valvehe equations are: ProductionPressureOperatedGas if t Valves
Psp =Pg (1 -ApAb) +PpApAb) Equation 8.5
P", =
The foregoing examples of intermittent l i ft design are
intended for use with injection pressure operated gas lift
PS, Equation 8.6 valves. Production pressure operated gas lift valves have
1 - (ApAb) also been used in many intermittent gasiftnstallations.
Where:
Pbt =Pressure i n bellows at tempera-
ture at valve depth, psig
PP =Gas pressure, psig
ppd =Production pressure at valveepth
1 -Ap Ab =Valve manufacturers specification
AP /Ab =Valve manufacturers specification
P", =Valve opening pressure in tester at
60"F, psig
CT =Temperature correction factor
PSP =Spring pressure effect, psig
Normally, when production pressure operated gas ift
valves are used i n intermittent lift installations, there is no
control device on the injection gas line other than a choke
and full line pressure is used. The valves are set to open
when the production pressure is within 150psi to 300psi ofthe gas pressure at the same depth. Spacing of the valves is
determined by the point of balance between the differential
pressure between the gas pressure and the production pres-
sure on one hand and pressure caused by the static gradient
on the load fluid on the other. For example, assuming a
load fluid with a staticgradient of 0.465 psi/ft and a 250psi
differential between production pressure and gas pressure,
the spacing between the valves will be 250 psi divided by
Decrease the set pressure of the bottom valve 25 to 30 0.465 psi/ft or 540 eet. This close spacing results n using
psig to be able to detect i t on a two-pen pressure more valves in an installation than would be required with
chart. injection pressure operated valves.
CHAMBERS
Chambers are a special type of intermittent lift installa-
tion. Usually this system is used in wells that have good
PI'S but very low bottomhole pressures. Consequently, the
reservoir pressure of such wells will not support a long col-
umn of liquid. Fig. 8-7 hows an insert or"bottle" chamber.
Fig. 8-8 shows the more common two-packer chamber. Liq-
uids enter through the standing valve and fill the tubing and
annulus. The bleed valve is open to vent the gas in the an-
nulus above the liquid to he tubing to prevent gas lockingthe annular portion of the chamber. At a predetermined time,
the time cycle controlat the surface opens injecting gas into
the tubing-casing annulus. The chamber valve then opens
and injects gas into the annulus below the top packer. The
gas pressure above the liquid increases and closes thebleed
valve. As hegaspressurecontinues o ncrease, he
liquid in the annulus is pushed down through the perfo-
rated sub just above the bottom packer and up the tubing.
The standing valve prevents the liquids from being forced
back into the formation. The gas then follows the liquidinto the ubing forcing the liquid to the surface. At this time
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API T ITLEbVT-b 94 m 0732290 0532943 b7b W
110 Gas Lift
the chamber valve closes, the tail gas bleeds off, the bleedvalve opens and liquid again enters through the standing
valve.
The bleed valve can be either a differential gas liftalve
set at50 to 100 psi r a ‘ kin . hole in a collar. Some chamber
valves have the bleed feature built intohem eliminating the
need for a separate bleed valve.Above the chamber, the installation is a standard inter-
mittent lift installation. The bottom unloading valve must
be only one joint of tubing above the chamber valve other-
wise th e installation may not work. Two items must be
calculated for a chamber; the chamber length and the set
pressure of the chamber valve.
Design of A Gas Lift Chamber Installation
The length of the chamber is based on equating the
wellhead pressure ( P w h ) plus the hydrostatic head (Hyd) of
the liquid in the tubing above the chamber just as thechamber empties to 60 percent of the gas pressure (Pg) t
the chamber valve.
P w h i- y d =0.60 (PB) Equation 8 .7
H y d =0.60 (PP)- P w h Equation 8 .8
UNLOADING GAS
BOTTOMUNLOADINGGAS LIFT VALVE
HANGER NIPPLE
FOR DIP TUBE
OPERATINGCHAMBERGAS LIFT VALVE
STANDINGVALVE
Fig. 8-7- nsert chamber installation
The height (H) of the liquid column in the tubing is the
hydrostatic pressure (Hfl) divided by the static gradient of
the well fluids (gs).
H =Hyd/gs Equation 8.9
The chamber length (CL) is determined by:
HRct + 1.0
L = Equation 8.10
Rct + -,,Vt
Equation 8.11
Where:
Rct - Ratio of Annular Volume to TubingVolume
Volume of Annulus
Volume of Tubing
If the chamber is too long, it will be difficult if not
impossible to U-tube the liquid out f the chamber into the
tubing. It is always better to have a chamber that is too
short than to have one that is too long.
BOTTOM U N L O A D I N G
G A S L I F T V A L V E S
O P E R A T I N G C H A M B E RG AS LIFT V A L V E
S t a n d i n g v a l v em o d i f i e d f a r
( 0 )
Fig. 8-8- wo-Packer chamber instal la t ion
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Intermittent Flow Gas Lift 111
Usually the chamber valve is a pilot operated valve. The
only production pressure available to assist the injection
gas pressure in opening the chamber valve is the wellhead
pressure. There is no liquid head above the chamber valve.
The equations for calculating the set pressure of nitrogen
charged valve are:
Where:
P, = P w h (approx.)
For a spring loaded valve:
PS,+P, ( 1 - &/Ab) +P, (Ap/&) Equation 8.5
Where:
P", = PS, Equation 8.61 - (AdAt,)
If the chamber valve, vent valve and standing valve are
wireline retrievable, then it will not be necessary to pull the
well to change them. The standing valve should have a
hold-down to prevent it from being blown out of its seating
nipple by the high differential across i t immediately after
the slug surfaces.
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CHAPTER 9PROCEDURES FOR ADJUSTING, REGULATING AND
ANALYZING INTERMITTENT FLOW GAS LIFTINSTALLATIONS
INTRODUCTION
The differencebetween efficient and inefficient operation
means employed o control the njection gas
are offered to assure unloading an
installation without damage to the gas lift
The controlof the injection gas forn intermittent instal-into two main categories, viz., time
control. The time cycle control with high
and other piecesof equipment areonly variations of the
y for
tallations to assure the most efficient operation.
Recording of the casing and tubing pressures is recom-
mended during unloading and for a daily reCO- ~ -#rdof theas
lift operation. It also assists the operator in determining the
proper adjustment of the injection gas volume to the well.
Pressure recorded and orifice meter charts from numerous
intermittent installations are illustrated in this chapter.
Slug velocity is agood indication of the overall operation
and proper adjustment of the injection gas volume. For
most installations his velocity should be 800 to 1200
ft./min. to assure maximum liquid recovery per cycle.
Increasing the injection gas volume does not always in-
crease the daily production rate rom an intermittent instal-
lation. Correct regulation of the injection gas volume per
cycle, cycle frequency, and other conditions suchas paraf-
fin, wellhead chokes, etc., can appreciably affect the daily
producing rate and gas requirements.
CONTROL OF THE INJECTION GA S
The TimeCycle Controller
The time cycle operated controller is the most widely
of injection gas control for intermittent lift
automatic ime cycle controls
microprocessors, iquid crystal displays, and
life batteries are now available for controlling the
n gas cycle. These electronic timers are replacing
y clock driven pilots. They mprove accuracy for
the duration and frequency of the injection gas
there is less chance of a controllernot closing due
automatically actuates a motor valve (Fig.9-1)
at desired set intervals is probably
most widely used type of surface control. The ime
number of gas injection cycles er day is varied
etc., on a timing wheel, depending upon its construc-
cycle frequency may also be changed by using
s such as 2-hour, 4-hour, etc., rotation. The
of gas injection is changed by certain adjustments
Time cycle control of the injection gas is applicable for
most intermittent installationsand is recommended particu-
larly for extremely high capacity and very low capacity
wells. It is flexible since the cycle frequency can be easily
changed to meet various desired producing rates (Fig.-1).
ADJUSTMENT FOR
REVERSE ACTING
PRESSURE OPENINGMOTOR VALVE
Fig. 9-1 - ime cycle control ler for intermit tent gas l i ft
instal lat ion
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Procedure for Adjusting, Regulating and Analyzing Intermittent Flow Lift Installations 1 1 3
In small rotative gas lift systems, time cycle control is
undesirable becauseof the high instantaneous injection gas
volume required from the high pressure system. In such a
system, if several controllers open simultaneously, or near
the same time, the high pressure system loses pressure and
one or more wells may not receive a sufficient volume of
injection gas for that cycle. Between these periods of gas
injection, no gas is needed to lift the well.
Central timers with several timing wheels operated by a
common drive shaft have been used in some fields o
stagger the period of gas injection. The central timer has a
timing wheel for each intermittent installationnd the indi-
vidual motor valve on the injection gas line is opened and
closed by a solenoid valve which is actuated by its corre-
sponding timing wheel. Electronic timers can eliminate the
need for a central timer. The accuracy of the quartz move-
ment i n an electronic timer allows precise staggering of the
injection cycles for several wells. When installations will
operate with choke controlof injection gas,high-rate injec-tion gas removal from he system is eliminated. Such a
system may require pilot operated gas lift valves in the
wells.
Location of Time Cycle Controller
For more intermittent installations, the controller should
be located at the well rather than at the tank battery to
assure the most efficient operations. When the controller is
at the tank battery, both casing and injection line to the well
must be filled in order to increase the casing pressure.This
slows the rate of increase in casing pressureand may resultin a ower overall ift efficiency. The njection gas ine
cannot be included as part of th e high pressure storage
unless the controller is at the well.
Choke Controlof the InjectionGas
For choke control of an intermittent nstallation, he
required injection gas s delivered into he casing through a
small choke or metering valve in the injection gas ine.
These installations may have injection gas or production
pressure operated valves. If gas pressure operated valves
are used, he valves must have he desired spread and
operating characteristics needed for choke controlbased on
the casing and tubing size. Pilot operated gasift valves are
the best type of gas pressure operated valves for choke
control. In some cases large ported single element valves
have been successfully used.
The injection cycle frequency is varied by changing the
choke size. Increasing the choke size increases the cycle
frequency. Choke control is ideally suited forsmall rotative
systems because the injection gas demand rate is constant.
Smaller njection gas ines can be used and the surface
equipment is less expensive than that required for time
cycle control. Accurate measurement of the injection gas s
no problem because of the constant demand of the wells.
Choke control requires a minimum of attention by field
personnel since there is no timing device to wind or check.
The numerous limitations of choke control account forthe predominance of time cycle control. Assuming that the
gas lift valves and annular capacity will permit this type of
operation, problems such as freezing, liquids in the injec-
tion gas line,and well deliverability will hamper or prevent
choke control. If the injection gas is wet, a dehydrationunit
should be considered. Other suggestions for alleviating
freezing are; installation of a heater or locating the chokes
near the compressor, and partially or completely bypassing
the after-cooler.
The problem of freezing is apparent, but the effect of
liquid in the injection gas can be just as serious. A lengthyperiod of time is required for any appreciable volume of
liquid to pass hrough a small choke with the pressure
differentials encountered in most gas lift systems. There-
fore, the gas supplied to the well is shut off during this ime.
Straight choke control of the injection gas is not recom-
mended for very low productivity or extremely high capac-
it y intermittent installations. For very low producing rates,
the choke size becomes too small for practical application;
and for very high producing rates, choke control limits he
maximum slug size and cycle frequency.
UNL OA DING AN INTERMITTENT INSTALL ATION
The intermitting cycle is described in Chapter 8 . This lation, it is likely that the damage to these valves occurred
section supplements the operationsdiscussed in that chap- during unloading.
ter by outlining procedures and considerations which are Recommended Practices Prior to Unloading
important to the operators in order that damage to equip- The recommended practices prior to unloading intermit-
ment may be eliminated and efficient unloading operations tent lift wells are the same as given in Chapter 7 for con-
assured. If gas lift valve seats leak in an intermittent instal- tinuous flow wells.
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114 Gas Lift
Init ial U-Tubing
Until the top valve is uncovered, injection gas pressure
exerted on top of the liquid column in the casing causes
fluid from he casing to U-tube nto the tubing through
open gas lift valves. No bottomhole pressure drawdown
occurs during U-tubing operations becausehe tubing pres-
sure at total depth exceeds the static bottomhole pressuredue to the pressure exerted by the liquid column in the
tubing. If the installation has a standing valve, the valve
will be closed.
Since no reservoir fluid feed-in is possible during the
U-tubing, this operation should not be hurried. The casingpressure should b e increased gradually to maintain a low
id velocity through the open gas lijì va lves. If full line
pressure is exertedon top of the fluid column in the casing,
a pressure differential that is approximately equal to this
line pressure will occur across each alve in the installation.
Damage to the valve seats can result from the high fluid
velocity hrough he valves. After he op valve is un-
covered, his condition cannot recur because he op
valve will always open before a high pressure differential
can exist across the valves below the fluid level.
The first injection gas head immediately after the top
valve is uncovered can overload the surface facilities in
some instances, particularly f the port size f the top valve
is large. Itmay be advisable to restricthe injection gas into
the flowline during the first head. Some installations are
designed with upper gas lift valves having a smaller port
than the lower valves to reduce the gas heads from the
upper valves.
These important facts about protecting theas lift valves
and the surface facilities are reasons enough to conclude
that this step should be done manually and should be
personally observed by the operator.
Unloading Operations Using a time Cycle
Operated Controller
The time cycle operated controller on the injection gas
line should not be adjusted to remain open during initial
U-tubing. It should be adjusted for frequent but shortduration of gas injection to permit a gradual increase in
casing pressure. For example, a0 second injection every 4
or 5 minutes can be used until the top valve is subjected to
gas and the first gas bubble enters the production tubing.
More accurately stated the time cycle controller should be
set to inject gas at a ratehich will cause a50 psi increase in
casing pressure in an 8-10 minute time interval. Once the
absolute casing pressure has reached a valuef 400 psi the
injection rate can be increasedo cause a 100 si increase in
casing pressure in the same 8-10 minute ime interval. This
second rate should be continued until the top valve is
exposed to gas allowing the gas in the casing to flow intothe tubing and upward into the flowline.
After witnessing the initial U-tubing the operator may
adjust the timer to continue the unloading operation.
l . Cycle frequency should be basedon the expected or
desired production from the well. Each lift cycle should
deliver from one o two barrels of fluid per inch of tubing
diameter. Fo r example, in 2-inch tubing 12 cycles per day
should produce from 24 to48 barrels of fluid perday. Usethis relationship to determine the cycle frequency for a
particular well. However,during heunloadingopera-
tions it is best not to exceed two or three cycles per hour
for the first 12 to 24 hours.
2. Injection time should be adjusted to stop when the
liquid slug clears the wellhead and the gas bubble first
reaches the wellhead. This, of course, will be more than
enough gas while the well is operating from the upper
valves, but will be about right as the well unloads to the
bottom valve.
These guidelines are for unloading only. In other words,they are starting points. The well should be checked for
improved adjustments the following day.
Unloading with Choke Control f the Injection Gas
Not all ntermittent nstallations can be unloaded or
operated with choke control of the injection gas. The type
of gas lift valve and the ratio of casing annulus capacity to
tubing capacity must be suited for this type of operation.
The choke ize selected should be considerably smaller han
the port size of the gas lift valve to permit the injectionpressure in the casing to decreaseo the valve closing pres-
sure after a alve has opened. No excessive pressure differ-
ential across the valves will occur during initial U-tubing
when the casing pressure is increased slowly.
Use the same guidelines as or a time cycle controller. Set
the choke so that the casing pressure increase ill be about
50 psi in about 8-10 minutes and continue at this rate until
the casing pressure is about 400 psia. Then increase the
choke size so that the casing pressure increases 100 psi in
8-10 minutes. Maintain his choke setting until the top
valve is uncovered to gas.
After the top valve is uncovered, adjust the gas rateo the
well so that it is a function of the design or expected
production rate from the well. For example, for 100 barrels
per day from 6,000 ft. one could expect to use 150,000
standard cubic feet per day. Therefore, set the injected lift
gas rate to be * h of the 150,000 or 100,000 standard cubic
feet per day. This may not work the well down to the
bottom valve but it will unload safely and without damage
to he gas ift valves. After 12-18 hours of reduced gas
volume is circulated to the well, adjust the gas to the fullamount expected to be used for lifting the well’s production.
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E x V T - 6 9 4 m 0732290 0532948 L58 D
ProcedureorAdjusting, Regulating and Analyzing Intermittentlowiftnstallations 115
ADJUSTMENT OF TIME CYCLE OPERATED CONTROLLER
After an installation is unloaded, the time cycle operated
controller should be adjusted for minimum injection gas
requirement for the desired production. Then the injection
gas cycle frequency and duration of gas injection should be
checked periodically for most wells to assure continued
efficient operation. If the producing rate from a wellchanges, surface control of the injection gas must also be
changed to maintain a minimum injected gas liquid ratio
(R,)¡). If this ratio is excessive as a result of valve spread,
a change in cycle frequency should be considered prior to
redesigning an installation. Decreasing the injection gas
cycle frequency ncreases he time fluid can accumulate
above he operative valve i n most ntermittent nstalla-
tions. The increased slug ength at he nstant the valve
opens results in increased tubing pressure at valve depth,
thus lowering the opening pressure of the operating valve.
The injection gas volume per cycle is reduced because of
decreased valve spread and more liquid is recovered percycle. These two hings work together to yield a lower
injected gas liquid ratip (Rgli).
Procedure for Determinin g Cycle Frequency
The following procedure is recommended for determin-
ing the proper cycle frequencynd duration of gas injection
immediately after the installation is unloaded and anytime
during the life of the well.
Step 1
Adjust the controller for a duration of gas injection
which will assure more injection gas volume than is nor-
mally required per cycle (approximately 500 C U ft./bbl
per 1,000 f t . of lift). Adjusting the controller o stay open
until the slug reaches the surface will result in more gas
being injected into the casing than is actually needed.
Step 2
Reduce the number of injection gas cycles per dayuntil
the well will no longer produce the desired rate of liquid
production.
Step 3
Reset the controller for the number of injection gas
cycles per day immediately before the previous setting in
Step 2. This establishes he proper njection gas cycle
frequency.
Step 4
Reduce the duration of gas injection per cycle until heproduction rate decreases, then increase the duration of
gas injection by 5 to 10 seconds for fluctuations in injec-
tion gas line pressure.
A time cycle operated controller on the injection gas line
can be adjustedasoutlined,provided he inepressure
remains relatively constant. If the line pressure varies signif-
icantly, the controller is adjusted to inject amplegas volume
with minimum line pressure. When th e line pressure s
above theminimum pressure, excessive injection as is used
each cycle.
The following tabulation (Table 9-1) gives data obtainedfrom an intermittent installation and illustrates the effectof
cycle frequency and duration of gas injection on operating
efficiency.
TABLE 9-1
DATA FROM AN INTERMITTENT INSTALLATION
Injection Duration of Duration Total ApproximateGas Cycle Time Between of Gas Daily Average
Frequency, Gas Injections, Injection, Production Injection Rg1i,
CycleslDay Minutes Seconds B/D Cu FUBbl
72 20 56 175 3,00048 30 56 186 2,20036 40 63 174 1,80024 60 85 170 1,300
A cycle requency of 48 cycles per day (30 min. per cycle)
resulted in the maximum producing rate. A cycle frequency
of 24 cycles per day (60 min. per cycle) represented the least
amount of Rgli. There was considerable difference in the
injection R,),. Note the big difference i n Rgl, for 72 cpd
and 36 cpd; yet there was a loss of only 1 BPD with the 36
cpd setting. Finally, the 48 cpd used only 409 mcf/d for 186
BPD while the 72 cpd used 525 mcf/d for only 175 BPD,proving again that more gas circulated to a well does not
always produce more fluid.
SELECTION OF CHOKE SIZE FOR CHOKE CONTROLOF INJECTION GAS
The initial surface choke sizeelection for controlling he
injection gas is calculated to pass the ift gas needed for the
designed production rate.
The final selection of the surface choke or opening
through a metering valve is determined by trial and error
until the desired operation is attained. Since an injection
gas pressure operated gas lift alve suited for choke control
is opened by both injection gas pressure and production
pressure, increasing he injection gas pressure will decrease
the production pressure required to open the valve. After
an operating valve closes and the slug surfaces, he injection
gas and production pressure begin to increase. The rate at
which the gas pressure ncreases s dependent upon thechoke size i n the injection gas line, whereas the increase n
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E m V T - b 94 m 0732290 0532949 094 m
116 Gas Lift
production pressure at valve depth is a function of well
deliverability and tubing size.
If the injection line choke sizes too large, the valve will
open at a higher gas pressure than that required for ade-
quate injection gas storage in the casing. The production
pressure will not reach a value that will result in the lower
gas pressure needed for minimum injection gas require-
ment. By decreasing the choke size, the well has a longer
time in which to deliver fluid into the tubing hich, in turn,
increases the production pressure atvalve depth and reduces
the gas pressure required to open the valve.
Choke controlof the injection gas s all that s needed for
most production pressure operated valve installations. The
gas pressure is allowed to vary with the choke size rather
than attempting to maintain a fixed gas pressure for pro-
duction control,
VARIATION IN TIME CYCLE AND CHOKE CONTROLOF INJECTION GAS
Appl icat ion of Time Opening andSet Pressure Clos ing Contro l ler
When the injection gas line pressure variesignificantly,
a pilot, which opens the controller on time and closes itafter a predetermined increasen casing pressure, s recom-
mended. The injection gas cycle frequencys controlled by
the timing mechanism. The volume of injection gasused per
cycle is governed by the casing pressure control. The pipe
is adjusted for a long duration f gas injection and the con-
troller remains open until he maximum desired casing
pressure is reached regardless of time required for this
increase.
Appl icat ion of Time Cyc le Operated Con tro l lerWith A Choke in the In jec t ion Gas L ine
When the injection gas line pressure greatly exceeds the
operating casing pressure for an intermittent installation, a
choke may be installed in the injection gas line to increase
the durationof gas injection. This combination also extends
the advantagesof choke control o wells with very low pro-
duction rates.
Appl icat ion of A Com binat ion Pressure Reduc ingRegulator and Ch oke Contro l
This type of control is ideally suited for low capacity
wells which would require an extremely small choke to
obtain the minimum injection gas requirement. A small
choke increases the possibility of freezing and will plugeasily. With a pressure reducing regulator, a much larger
choke than that needed for straight choke control can be
used and the starting slug length can be controlled by theset regulator pressure in most installations. The pressure
reducing regulator controls the maximum casing pressurebetween njection gas cycles. The controlled maximum
casing pressure causes the gas liftalve to open only after a
predetermined tubing pressure has been reached in the
tubing.
The two-pen pressure chart in Fig. 9-2 illustrates typically
good intermitting operation from four commonly sed sur-
face gas control systems.
1.. 9."
SURFACE GAS CONTROL SYSTEMSA. Time Cycle Control ler
B . Choke Cont ro lC. Choke and Pressure Regulator
D. Choke and Time Cycle Control ler
Fig . 9-2- wo-pen pressure chart
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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ProcedureorAdjusting,Regulating and Analyzing Intermittentlowiftnstallations 117
IMPORTANCE OF WELLHEAD TUBING BACK PRESSURE TO REGULATIONOF
INJECTION GAS
The maximum wellhead tubing pressure associated with
the surfacing of a liquid slug is an indication of the slug
length and/or restriction in the flowline such as a wellhead
choke, paraffin deposition, etc. It is desirable to have well-head and flowline conditions that result in the maximum
tubing pressure being a true indication of the slug size.
The two surface conditions associatedwith wellhead tub-
ing pressure that are detrimental to intermittent lift opera-
tion are: (1) An excessive increase n tubing pressure before
the entire liquid slug can enter the flowline, and (2 ) a pro-
longed period of time required for the wellhead tubing
pressure to decrease to separator pressure after a slug has
surfaced. Maximum wellhead tubing pressure should occur
following the surfacing of a slug. If the tubing pressure
reaches a maximum before most of the slug enters the
flowline, the slugvelocity will be reduced and excessive gas
break-through will occur. If the time required for the ubing
pressure to decrease after a slug has surfaced is excessive,
the maximum injection gas cycle frequency and producing
capacity of a high capacity well are limited.
Wellhead Configuration
The wellhead should be streamlined to prevent excessive
injection gas break-through rom a decreasing slug velocity.
All unnecessary ells, tees, bends, etc., near the wellhead
should be eliminated. A streamlined wellhead is illustrated
in Fig. 8-3, Chapter 8.
Separator Pressure
Separator pressure should be maintained as low as pos-
sible. The lower the flowing bottomhole pressure, themore
important minimum separator pressure becomes. High
separator pressure reduces the starting slugength and pro-
duction per cycle.
Surface Choke in Flowline
If an intermittent installation must be choked to reduce
the rate of gas entry into a low pressure system, the choke
should be located as far from the well as possible, prefer-
ably near the tank battery. This allows the slug to leave the
vertical conduit and accumulate i n the horizontal conduit.
A small wellhead tubing choke will significantly reduce the
liquid slug recovery per cycle nd increase the injectiongas
requirement.
Flowline Size and Condition
The time required for the wellhead tubing pressure to de-
crease to separator pressure after a slug surfaces is a pri-
mary factor in the maximum producing rate from some in -
stallations. The size and condition of the flowline affects
this time. A flowline should be as large or larger than the
tubing. A common flowline for several wells is not recom-
mended i n most instances. If more than one well intermits
simultaneously, excessive back pressure will result. Theflowline must be kept clean of paraffin and other deposits
to prevent excessive back pressure. In some wells the pro-
duction has been more than doubled by removing paraffin
from the flowline.
SUGGESTED REMEDIAL PROCEDURES ASSOCIATED WITH REGULATIONOF
INJECTION GAS
There are several remedial procedures recommended
before resorting to pulling the tubing. Information indicat-
ing the trouble may often be obtained from recordings of
the surface tubing nd casing pressure. If the trouble cannot
be corrected by surface control, it is ecommended that an
installation be serviced as soon as possible to prevent a
waste of injection gas and loss i n production.
Installation Will Not Unload
When unloading operations cease before reaching the
operating depth, rocking an installation is recommended.
Rocking a gas lift installation is accomplishedby applying
injection gas pressure to the top of the fluid column in the
tubing with line pressure in the casing. Rocking is recom-
mended for two reasons: (1 ) To force fluid from the ubingand casing into the formation to uncover the top valve n a
well without a standing valve, or (2) To increase the tubing
pressure at valve depth to lower the valve opening pressure.
In production pressure operated installations, rocking the
well will open an upper valve and permit resumption of the
unloading operation.
Valve Will Not Close
A continuous high rate of decrease i n casing pressure
below the surface closing pressure of the operating valve
may indicate that this valve is stuck open. When this occurs
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E x V T - 6 74 0732270 0532951 742
118 Gas Lift
the ubing should be shut n and he casing pressure
increased to a point well above the opening pressuref the
valve. The tubing is opened as fast as possible,referably to
atmosphere to prevent overloading surface facilities, and
the wellhead tubing pressure is permitted to decrease to
separator or atmospheric pressure. The procedure is re-
peated several times or until the casing pressure decreases
to the valve closing pressure. This action creates a highpressure differential across thealve seat and will generally
remove any trash holding the valve open.
Salt can plug the bleed port in a pilot valve resulting in
the main valve remaining open after the pilot section closes.
Many times salt deposits can be removed by batching or
pumping fresh water into the casing.
Emulsions
An emulsion is difficult to ift and requires more injection
gas than would be required f it did not exist. Many times an
emulsion can be eliminated or the severity reduced byadding chemical to the injection gas. Ways of lifting an
emulsion include the use of a plunger, large-ported valves,
pilot operated valves, and/orime cycle operated controller
with a maximum pressure control.
Corrosion
Corrosion inhibition can be effectively applied to gas lift
systems. The chemical may be introduced just downstream
of the compressors to protect the gas distribution lines to
each well and to protect the subsurface casingnd tubing. It
is most effective when applied to new systems. If either
corrosion inhibition or emulsion breaking chemicals are
injected directly into he gas, care should be taken to ensure
that the chemical carrier is not of the type that will be
dissolved in the gas, otherwise the heavy elements of the
chemicals may plug the gas lift valves and injection chokes.
If a system is operated with corrosive gaswithout protec-
tion for an extended period of time, products of corrosion
will accumulate in the gas distribution linesand subsurface
equipment. Addition of a corrosion mitigation program
will result in a clean up of the “dirty” system and a con-
tinued protection of the system.
The first phase, he clean up, can cause temporary opera-
tional problems. As the products of corrosion are removedfrom the system, they will tend to plug the gas lift valves and
make the valves perform erratically. As mentioned, these
problems are temporaryand must be weathered to clean up
the system.
TROUBLE-SHOOTING
The basic principle in trouble-shooting is to know what to
expect when a system is functioning correctly, hen isolate
deviations from this examplend determine possible causes
for the particular malfunctions observed. In many cases,
and gas lift is no exception, observation of a system in
action requires he assistance of recording instruments. The
following basic information should be obtained when the
installation is operating properlyso that it may be compared
with later information when trouble occurs.
1.
2.
3.
4.
5 .
6 .
7.
8 .
9.
The volume of fluid being produced from the well
per day (water, oil, gas)
The number of cycledday and the barreldcycle
The injection period/cycle
The amount of gas injected into he well per day, the
scfkycle and the R,s
The lift gas system line pressure
Variations of casing pressure and tubing pressure
during the cycle
The point of gas injection into the tubing (depth of
the operating valve)
The static bottomhole pressure and flowing bottom-
hole pressure
The pressure gradient of the produced fluids
Items 1 hrough 6 can be determined with a 24-hour
production test from the well. The volume of fluid pro-
duced is measured at the tank battery or a metering station.
A low pressure gas meter is needed at the separation point to
measure the volume of gas liberated from the produced flu-
ids. A high pressure meter run at the well is required to mea-
sure the volume of lift gas used. A two-pen pressure recorder
will illustrate the cycle frequency and pressure changes at
the well.
A flowing pressure survey is the only positive way of
determining the operating level and the formation pressure
drawdown. The preferred procedure for makingan operat-
ing pressure survey is to run the pressure gage (bomb)
during the feed-in period, to a depth ust below the bottom
valve. The gage should be left below the bottom valvethrough three complete gas lift cycles. It is important thatthe normal cycle frequency and injection period be used
during this survey to obtain representative data. If the
operator is reasonably certain that the well is not lifting
from the bottom valve, he may move the gage up the hole
one or two valves. The well may be operated hroughseveral cycles with the gage in this position; however, the
wireline specialist should be cautioned towatch for the loss
of weight on the wireline. This indicates that the gage is
being blown up the tubing, and the operator should be
prepared to shut the tubing wing valve at the first sign of
this trouble.
yright American Petroleum Institute
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ProcedureorAdjusting,Regulating and Analyzing Intermittentlowiftnstallations 11 9
After completing the operating portion of the pressure procedure, in addition to opening the valve wide, develops
survey, the operator may lower the gage to the bottom of a high pressure differential across the valve when the tub-
the tubing and shut thewell in for a pressure uild up curve. ing is bled down rapidly. These conditions favor the pas-
Interpretation of the bottomhole pressure record should sage of trash. If this technique fails after wo tries, bleed all
determine the value of items 7 through 9. the pressure off the tubing and casing. This step allows h e
evaluated by plotting the results on a graph. The pressure trash that may be between the valve and seat. Then, with
valve, the producing gradients that exist above and below lift valve opens. Shutoff the injection gas nd wait until the
the operating valve, and the flowing ottomhole casing pressuretabilizes eforencreasing the casing pres-
The opera t ing cycles and build up curve should be sureagain.Repeat hisprocedure wice. If thisprocedure is
plotted on a pressure time diagram. n these forms, the data not successful, it may be advisable to inject fluid down the
are much easier to analyze. casing to clean a leaking valve. A detergent in fresh water
is particularly successful n areas where iron sulfide depos-
The informationobtained rom a pressure survey is best to go O n seat, so that it tends to break Or crush
depthdiagram will illustrate he ocationof the operating the tub ing OPen, increase the casing Pressure th e gas
Theirstign O f a in th e gas lift 'ystem its are common and fresh water will wash salt deposits fromgenerally occurs when the product ion Operator valves, This fluid should be roduced through the valves inthat the fluid production is below normal. Each well in the a normal manner so that i t tends to wash the valves and
system must be checked to determine which well is not pro- carry o u t trash that was i n the valves,
ducing properly. At this point, the two-pen pressure recorded
at the well becomes a most important instrument. In addi- A check to determine the cause of a malfunction is to ap-tion to locating the well that is having trouble, th e two-pen ply pressure on the tubing with no pressure on the casing. A
recorder is the first instrument that the operator uses to de- leak from the tubing would indicate a leaking tubing cou-
termine what is wrong. If investigation indicates that a gas pling or hole in the tubing since the gas l i ft valves have
lift valve is failing to close tightly, the following procedure back checks.
is recommended: Raise the pressure in the casing and tub-
ing to the opening pressure of the gas lift valve so that it is Table 9-2 lists some common malfunctions of gas lift sys-
wide open, then reduce he tubing pressure rapidly. This tems and suggests possible causes and possible cures.
TABLE 9-2
POSSIBL E CAUSES AND CURES OF SOME COMMON MA LFUNCTIONS OF GAS LIFT SYSTEMS
MALFUNCTION CAUSE CURE
COMMUNICATION A. Valve stuck open Rock the well, flush the valveBETWEEN CASING B. Packer leaking Xeset packerAND TUBING C. Tubing eak Pull, inspect and rerun
OPERATING A. Operating valve changed to Adjust injection gas for maximum
PRESSURES higher valve in installation productionINCREASE B. Valve plugged Pull well
D. Circulatingleeve open Closet
C. Temperature rise i n well Exchange for valves which are not affectedaffecting valves by temperature, or lower the test rack
opening pressure of bellows chargedvalves.
D. Small fluideadseduceyclerequency
FLUIDLUG.luid load very heavy Increaseyclerequency
VELOCITY ESS B. Low injectionineressurencreaseressure or spacealvesloserTHAN 1,000 C. Valve partially plugged Flush with fresh water or solventFEETPERMINUTE D. Tubing artially plugged Run paraffin knife or clean with solvent
E. Toomall valve port Exchange fo r largeortedalves
HIGHACK. Plugged flowineookorartiallylosedalves,ouledPRESSURE AT checks,araffin, sand accumulationsWELLEAD. High separatorressureeset back pressure valve or add gas
accumulator tanks
larger lineC. Flow line too small Loop flow line or replace i t with
D. Well using too much gas Adjust injection control equipment
SUDDEN DROP IN A . Plugged formation Clean out wellPRODUCTION- B. Plugged tubing Check tubing below operating valve
(Valve Open andC. Lower valves plugged
Wash or pullClose Near D. Too much or too little gas Readjust injection gas controls
Normal) E. Standing valve stuck open Pull and clean
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A P IT I T L E * V T - 6 94 W 0732290 0532953 515 W
APPENDIX 9=ATWO-PEN RECORDER CHARTS SHOWING EXAMPLES
OF INTERMITTENT GAS LIFT MALFUNCTIONS
Appendix 9-A conta ins eleve n two-pen recorder charts In each of the charts, the outer trace represents a recordingthat illustratemo st of hecommon problems hat may of hecasingpressureand he nner race epresentsa
occur in an intermittent gas lift operation. These may be recording of the tubing pressure. As other malfunctions are
used by the opera tor in spottingproblemsbefore heyencountered,representativechartscan beaddedfo rfuture
become too evere.Thecharts were hand drawn so that eference.
examples of malfun ctions could be exaggerated for clarity.
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A : CYCLE FREQUENCY TOO LONG, TUBING K ICKS ARE LOW AND THICK.
B : INCREASED CYCLEFREQUENCY YIELDSTALL THIN TUBING KICKS ANOMORE
PRODUCTION.
C : CYCLEFREQUENCYTOOFAST. TUBING PRESSURE WE S NOTHAVE TIME TO
REDUCE TO NORMAL.
Fig. 9-Al
A : INJ ECT ION RATE TOO HIGH. MAY CAUSE MORE THAN ONEW IFT VALVE TO
CHANGE INTHE PRESSURE DE WNE RATE AFTER A GAS LIFT VALVE CLOSES.
OPEN. HIS CONDIT ION IS M DE NC E O ON THE CASING RESSURE Y A
THE MULTIPLE "POINTS" ON THE TUBING PRESSURE ALSO MDENC E TH IS
M m wnO N.
B: TOO MUCH GASTUBING KICKS ARE TOO HIGH AND TOO THICK. CASNG PRES
SURE DECLINE IS RATHER SLOW.
ERR ATIC GAS SYSTEM PRESSURE. THE PR ESSUR E HAS DECLINED FTER TIMER
WAS ADJUSTED SO THAT NOW 2 INJECTIONSARE RE QUIRE 0 PER CYCLE.
TIMER IS THEN OPENED FOR LONGER INJ ECTION. WHEN AS SYSTEM PRESSURE
INCREASES, TOO MUCH GAS IS USED.
TO HELP S TABILIZE GAS SYSTEM PR ESSURE, USE CHOKE ANO TIMER
INJECTIONFREQUENCVTOO F M . GAS LIFT VALVE IS NOT LOADED SO W E S
NOT OPEN UNTIL SECOND NJ ECTION. TOO MUCHW S MDENT IN UBING
KICK. REDUCE INJ EC TION FREQUENCY FOR BETTER OPERATION.
Fig. 9-A2
A : WELL LOADING UP. MD E NC E OF EXCESSRlEFLUID LOAD W E N GAS LIFT VALVE
WENS EARLY. AS THIS CONTINUES.PROBLEM IS SHOWN BY SHORTER AND
WlDER TUBING KICKS UNTIL THE LOWER VALVE BECOMES SUBMERGED AND
OPERATION CONTINUES ON AN UPPER VALVE. A DECLINEINPRODUCEDFLUID
IS EXPERIENCED.
B: WELL UNLOADING. THIS ILLUSTRATES HOW THE FLUID LOAD DECREASES
FROM A MAXIMUM WHEN AW IFT VALVE OPERATES THE FIRST TIME TO A
MINIMUM WHE N THE VALVES OPERATE THE LAST TIME JUS T BEFORE TRANS
FERRING TO THE N m WYER VALVE
Fig. 9-A4ig . 9-A3
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122
A P I T I T L E + V T - 6 94 m 07322900532955398
Gas Lift
A : CHOKED WELL. RESTR ICTION OF CHOKE CAUSES SLUG VELOCITY TO BE SLOW
AND PRES SURE REDUCTION PERIODTO BE LONG. ALSO. TUBING PRESSURE IS
TOO HIGH.
B : FLOW L INE RESTRICTION. ABOUT THE SAME EFFECT AS CHOKE. TUBING PRES
SURE CHANGES ARE GRADUAL BECAUSE RESTRICTIONIS DISTANT FROM WELL
HEAD.
Fig. 9-AS
A : LEAK HIGH IN TUBING. LEAK IS MALL SINCE TUBING KICKS ARE NORMAL.
FIRST SIGN OF LEAK IS EVIDENCED WHEN CASING PRESS URE CONTINUES TO
DECREASE AFTER GAS LIFT VALVE CLOSES.WHEN GAS TO C A S I N G IS SHUT OFF
CASING DECLINES TO A VALUE NEAR THE TUBING PRESSURE.
B : LEAK LOW IN TUBING. OPERATING PRESSURE A B W T THE SAME AS ABOVE. MF -
FERENCE SHOWS WHEN GAS TO CASING IS SHUT MF. THEN CASING PRESSURE
DECLINES TOA V A L L E WELL ABOYE THE TUBING PRESSURE. (FLUID SEAL OVER
TH E VALVE).
A : LEAK IN SURFACE INTER MITTER. GOODOPERATION IS MAINTAINED.
B : SMALL LEAK IN TUBING STRING. BE M E N EACH CYCLE. THE CASING PRESSURE
VERYGOOD.
DECLINESSLOWLYAFTERTHE GAS LIFT VALVECLOSES. TUBING KICK S ARE
Fig. 9-A6
UR GE LEAK IN TUBINGSTRING. AT FIRST. IT SHOWS AS A SMALL LEAK. THEN
GA S LIFT VALVE. WHEN THE LEAK EXC EEDSTHECY CLEGAS REQUIREMENT,THE
LEAK IS SUCH THAT THE CASING PRESSURE SOMETIMES FAILS TO OPEN THE
CASING PRESSURE DECLINES WELL BELOW THE NORMAL RANGE AND A SAW
TOOTH PATTERN IS TRACED. THE TUBINGPRESSUREREACHESASTEADY, ELE-
VATED PRESSURE.
Fig. 9-A8ig . 9 - A 7
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API T I TLE x V T - 6 9 4 0732290 0532956 224 W
Tw o-Penecorderhartshowingxamples of Intermittent Cas LiftMalfunctions 123
GAS LINE PRESSUREBECOMESTOO LOW. CASING PRESSURE FAILS TO GET
HIGH ENOUGH. TUBING KICKS CHANGE FROM GOOD SLUGS, TO SMALL SLUGS.
TO A MlSlY SPRAY.
Fig. 9-A9
A : PLUGGED VALVE. VERY SLOW DECLINE OF CASING PRESSURE ISAN INDICATOR
OF THIS PROBLEM. THE TUBING PRESSURE KICKS ARE ROUNDED AND MISTY
BECAUSE OF EXCESSIVE FALL BACK. AS CONDITION GETS WORSE. THE U S IN G
PRESSURE STAYS ABO VE VALVE CLOSING PRESSURE AND TUBING PRESSURES
STABILIZE. THEN, ONLY GAS IS OBTAJ NEDFROM FLUID.
B : PLUGGED TUBING. VERY SIMILAR TO SITUATIONA, BUT TUBING PRESSURE RE-
FLECTS INJ ECTION CYCLES. VERY L l l l l E FLUID S PRODUCED.
Fig. 9-AIO
A : NOTENOUGH W. FALL BACK IS EXCESSIVE W) FLUID RECOVERY IS SMALL.
TUBING PRESSUREHASROUNDED,SLUGGISHKICKS.CASINGPRESSURE OP-
ERATING SPREADS TOO SMALL,
B: NOT ENOUGH F LUID. CASING PRESSURE OPERATING SPRWD IS NOR BUT
TUBING PRESSURE IS ROUNDED AND SLUGGISH.
Fig. 9-A I I
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A P I TITLExVT-b 94 0732290532957b0
CHAPTER 1OTHE USEOF PLUNGERS IN GAS LIFT SYSTEMS
INTRODUCTION
The function of plunge r l i ft equipment is to provide for
more efficient ut i l izat ion of l i ft ing gas energy i n any well
that is or can be produ ced in a cyclic manne r similar o
intermittent gas l i ft .
Plunger l i ft incorporates a piston that normally travels
of the tubing string, providing a solid and
ealing interface between the l i ft ing gas and the produced
iquid . This n terface changes he f low pattern during a
i ft ing cycle from the familiar bullet shape of gas penetra-
of the iqu id s lug o a pa t tern whereby gas f low s
ossible only between the plunger’s outside diameter and
he tubing walls.
To lift the plunger and the liquid load above the plunger,
the gas pressure must be greater than these loads..he sma ll
quanti ty of gas that bypasses the plunger during a cycle
flows up through the annular space and acts as a sweep to
minimize l iquid fal lback.
The u se o f p lunge r equ ipmen t , by min imiz ing i qu id
fal lback and el iminating possible gas pene trat ion through
the center of the l iquid slug, provides for the most efficient
form of intermit tent gas lift production available.
APPLICATIONS
Num erous pplicat ions xist or lunger nstallatio ns in throughheiquid olumn ndose lift efficiency. A
re:
I .
2.
3.
4.
gas l i ft and natural flow wells. The most common uses
To mainta in product ion by cycl ing n a highgas-
l iquid rat io well .
To unload accumulated l iquid in a gas well .
To reduce fa l lback in a well being produced by inter-
mi t ten t gas l i f t .
To mprov e efficiency in gas ift wells with severe
emulsion problems. In such wells, the frict ion of the
emulsion prevents establishment of the required l i ft -
ing velocity. The slow velocity al lows gas to channel
plunger lift system can help eliminate this problem.
5 . To clean the tubing in b oth gas li ft and natural flow
wells producing paraffin, scale, and other de posits.
Normal production does not have to be cyclic, but the
well must be shut n periodically to al low the plungerto operate.
6. For deep interm ittent gas l i ft with low inject ion gas
pressure.
7. To allow intermittent gas l i ft with surface restrict ions.
Th i s chap te r s p rimar i l y conce rned w i th he u se o f
plungers in intermit tent gas l i ft applicat ions.
TYPES OF PLUNGER LIFT
Thre e poss ible typ es of downhole instal lat ions are:
1. Intermittent Gas Lift With a Packer
Normally the well’s bottomhole pressure is so lo w
that the l iquid fi l l -in from the form ation is not suffi-
c i e n t o p r e v e n t gas break - th rough o f he i qu id
column during an intermittent l i ft cycle.
This type of applicat ion is one where insufficient Plunger appl ica t ion a l lows much g reater u t i l iza-
gas in avai lab le from he format ion and a l l gas i s t ion of the energy being provided and less fal lback,
provided by a suppleme ntal source involving an out- thus a corresponding decrease n bottomhole pres-
side sourc e of energy. sure and an increase in l iquid production.
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A P I T I T L E S V T - 6 94 0732290 0532958 O T 7
These of Plungers in Gasiftystems 125
\ TO SALES I
Type Well:
Insufficient gas from formation. Well being gas liftedon packer. A l l flow through tubing.
Equipment Required:
@ Full bore master valve @ Flowvalve@ Lubricator @ Time cycle control valve@ Second lowoutlet @ F low valve
Standard Operation:
1. P lunger at bottom of well.2. Gas flow through time cycle intermitter pens the
gas lift valve down hole, thereby creating the dif-ferential necessary to lift the liquidnd plunger tothe surface.
3. Gas and liquid delivered through upper outlet.4. Gas liftvalve closes.5. P lunger arrives in lubricator, partially clos ing off
6. Tail gas is rapidly dissipated through lower outlet.7. P lunger falls to bottom and cycle recommences.
upper outlet.
Fig. 10-1- ypical well installation for gas lift
2. Conventional Plunger Lift Without a Packer or
With Communication Between Casing and Tubing
Just Above the Packer.
Installations of this type are by far the most widely
used. They are normally applied where the well sup-
plies all of the energy. However, many systems using
supplementary gas are now being installed.
3. Plunger Lift with a Packer (N o Communication
Between Casing and Tubing)
another application of plungers. This type of installa-
tion requires that all gas must come directly from the
formation during he ifting cycle: and necessitatesthat he formation Rglf be greatly i n excess of that
required for conventional plunger lift since the gas
required per cycle must be produced during the cycle.
N o storage period or external source of gas is possible.
Since this text is concerned with ga s lift application of
plungers, further discussion of plunger application without
additional gas will be omitted. A ypical surface installation
This is not a gas l i f t installation, but does represent for gas lift using a plunger is shown in Fig. 10-1.
SELECTING THE PROPER EQUIPMENT
Having determined that a well can be produced with a
plunger and having determined what flow pattern will be
used, he proper equipment must be chosen. Figs. 10-2,
10-3, and 10-4 show possible variations in downhole in-
stallations where gas lift is used i n conjunction with the
plunger.
Using these figures as a basend starting at thebottom of
the well, the equipment is explained under the following
headings.
Retrievable Tubing (or Collar) Stop
When the well’s tubing is not equipped with a seating
nipple, a wireline set stop can be used for positioning the
standing valve or bumper spring. Fig. 10-5shows a typical
tubing stop.
Standing Valve
A standing valve prevents iquid in he ubing from
falling back and contributes to an increase in efficiency of a
plunger installation. Although the standing valve is shown
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API T I T L E * V T - b 94 W 0732290 0532959 T33 m
126 Gas Lift
in Fig. 10-2, it is often omitted from such nstallations.
However, the standing valve should always be run in instal-
lations such as those shown n Figs. 10-3and 10-4. In these
types of installations, the standing valve prevents the high
pressure l i f t gas from forcing theiquid below the standing
valve back into the formation. It should be noted that if
the plunger can fall to bottom dry, an individual stop should
be used to set the standing valve ndependently of the
bumper spring. Experiencehas shown that aplunger falling
dryonabumperspring,standingvalve,andstopset
together will set up a vibrationhat rapidly causes a failure
of the standing valve ball and seat.
Bum per Spr ing
The bumper spring, shown in Fig. 10-6, is an essential
part of a plunger installation. It prevents excessivehock on
the plunger when falling to the bottom, particularly if the
well does not have liquid above the tubing stop.
PlungersThere are five operating characteristics to be considered
when choosing the type of plunger to be used in a well.
These are listed below:
l . High shock and wear resistance.
2. Resistance to sticking in the tubing.
Equlpm ent Required
1. Sub-surface plunger
2. Bumper Spring
3. Retrievable Standing Valve
4. Retrievable Tubing Stop*
5. Gas Lift Valve
'If seating nipple is installed in well, tubing stop may be eliminated
Fig. 10-2- ownhole equipment variations, gas l if t and
plun ger l i ft
Equipm ent Required
1. Sub-surface plunger
2. Bottom Bumper Spring
3. Standing Valve
4. Packer
5. Unloading Conventional Gas Lift Valves
6. Operating Gas Lift Valve
7. Lubricator and Bumper Spring
8. Plunger Catcher
9. Time Cycle Controller
Fig. 10-3- ownhole equipme nt var ia t ions , gas l i f t an dplunge r l i ft
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A P IT I T L E a V T - 6 9 4 m 0732290 0532960 755 m
The Use of Plungers in Gas Liftystems 127
3. High degree of repeatability of valve operation.
4 . Abili ty to provide a good seal against he ubing
during upward travel.
5 . Th e ability to fall rapidly through gas and liquid.
Figs. 10-7, 10-8, 10-9, and 10-10 show threedifferent
plunger types.
Equipment Required
1. Sub-surface plunger2. Bumper Spring
3. Retrievable Tubing Stop4. Retrievable Duplex Standing Valve5. Gas Lift Valves6. P roducing Gas Lift Valve7. Packer8 . Seating Nipple9. Seating N ipple
10. Retrievable Gas L ift Valve inCenter Mount Mandrel
Fig. 10- 5- ypical tubing stop
Fig . 10-4- ownhole equipment var iat ions , gas ift and
plunger li f t Fig. 10-6- ypical bumpe r spring
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A P I T I T L E m V T - 6 94 m 0732290 0532963 691 m
128 Gas Lift
Essentially, there are six variationsf plungers available
and the choice depends on the operating requirements of a
well. There are two types of seals (expanding blade and
turbulent) and three typesof valving systems (valve without
integral rod, valve with integral rod, and no valve at all).
Table 10-1 lists the six plunger types and classifies them
either 1, 2, or 3 (first, second or third choice) according totheir relative effectiveness in fulfilling the five operating
characteristics listed previously.
Fig. 10-8 - Wobble washer ype plunger wi th ntegral
valve rod
Fig. 10-7- ypical plung er w ith in tegral valve rod Fig. 10-9- rush type plunger without integral valveod
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A P I TITLE+VT-b 9 4 0 7 3 2 2 9 0 0532762 528
The Use of Plungers in Gas Lift Systems 129
Fig. 10-10- xpanding blade plunger wi th re trac table seal (Photos courtesy Ferguson-Beauregard nc .)
(A) Shows seals in expanded posi t ion
( B } Shows seals in retracted position
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Well Tubing
The well's tubing must be gauged before running any
subsurface equipment. Bent or crushed tubes will prevent
satisfactory installation and paraffin, scale, etc., can pre-
vent initial operations. Table 10-2 gives the gages recom-
mended for various tubing sizes.
TABLE 10-1
PLUNGER CLASSIFICATIONS
Operatingharacteristics I
Type of Plunger
1) Expanding blade
seal without inte-
gral valve rod2
2) Expanding blade
seal with integral
valve rod1
(3 ) Expanding blade
seal without valve -
) Turbulent seal,
wobble-washer, etc.
without integral
valve rod (valveactuating rod is
2
part of lubricator)
5 ) Turbulent seal,
wobble-washer, etc.with integral valve
1
rod
~
2
6 ) Turbulent seal,
wobble-washer, etc.
without valve
- 1
TABLE 10-2
GAGES FO R VARIOUS TUBING SIZES
- /
Tubing size, in. Minimum gages
O.D. nominal O.D., in.ength, ft
A\
1.660 1I4 1.250 2
1.900 1 12 1.500 22.063 2'/M 1.630 2
2.375 231~ 1.900 2
2.875 2718 2.312 2~
NOTE: There are possible variations in gage requirements
between equipment manufacturers. Check to deter-
mine the correct gage size.
CA P .......................................... (1)
B U M P E R S P R I N G. . . .........................STRIKER PA D ................................ (3)F LO W B O D Y . . ................................ (4 )CATCHER ASSEMBL Y ........................ ( 5 )DUAL FLOW OUTLET ................... 4A) (4B)
i2j
Fig . 10-11- ypical lubricator parts
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API T ITLEWVT-b 74 m 0732290 O532764 3 T 0 m
The Use of Plungers in Gas Lift Systems 131
Master Valve
The master valve of a well must have a full bore equal to,
but not greater than, he tubing size. An undersize valve will
not allow plunger passage,and an oversize valve can possi-
bly prevent he plunger from reaching he ubricator
because of excessive gasbypassing around the plunger. The
plunger must reach the lubricator to allow removal forservice and, where installed, to activate a plunger arrival
system.
Second Flow Outlet
Where the chosen flow pattern of a well requires, a sec-
ond flow outlet is provided. A separatenit of the flow out-
let of an existing tree can be used.f using the existing flow
outlet, a method should be provided to restrict the flow.
This restriction may be necessary to allow the plunger to
lift past the second flow outlet, so that it can activate a
plunger arrival system or be retrieved for service.
Lubricator
A lubricator is an integral part of any plunger installa-
tion. Fig. 10-11 shows the various parts of a typical dual
flow outlet lubricator.
The cap (1) contains a spring to resist the force of therising plunger. The striker pad (3) is the initial contact of the
plunger with the lubricator. With an integral rod plunger,
the valve is opened. Where a plunger without an integral
valve rod is used, the striker pad contains a rod for activa-
tion of the plunger valve.
In the lubricator shown, the cap ( l ) , bumper spring (2) ,
and striker pad (3) are removed as a unit for access to the
plunger for examination and repair. The catcher assembly
(5) holds the plunger in the lubricator for easy removal.
PROPER INSTALLATION PROCEDURES
The next part of a uccessfulplunger nstallation is the 4.
installation of the equipment.
Listed below are the sequential operations involved i n
running a plunger installation, assuming the ell is set on a
packer and will not be pulled. 5
1.
2.
3.
Check master valve for proper size
Gage 6.
Set retrievable stop nd standing valve just above the
bottom of the tubing.Note:histop and standing 7 .
valve are optional)
Set retrievable stop just above the bottom gas l i ft
valve. (Note: proper jarring action to set the stop
may not be possible through the bumper spring, so
the stop should be run independently)
Run retrievable bumper spring and latch to the pre-
viously set stop
Run plunger to bottom on a wireline to ensure free
travel
Remove wireline lubricator, install plunger lubrica-
tor, and commence operation.
SUMMARY
A plunger will increase theefficiency of most intermittent
gas if t nstal lations by preventing gas from breaking
through he iquid slug. In some nstances of very low
bottomhole pressure, plungers will allow greater pressure
drawdown and hereby ncrease production from he
intermittent lift well by allowing the liftingof smaller slugs
on each cycle. In addition, a plunger should be considered
for an intermittent gas lift installation when:
1. The injection gas pressure is low relative to the
required depth of lift;
2 . the flowing wellhead pressure is excessive after a lugsurfaces; and
3. a paraffin deposition problem exists.
There are also well conditions that prohibit the use of a
plunger. Some of these conditions are listed here.
1. Restrictions i n surface wellhead and Christmas tree
valves.
2. Excessive well deviation.
3. Restricted areas in the tubing.
4. Excessive areas in the tubing.
5 . High rate intermittent gas lift operations.
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E * V T - b 9L1 m 0 7 3 2 2 9 0 5 3 2 9 b 5 3 7 W
13 2 Gas Lift
GLOSSARY
-A-
Ager - water filledpressurechamber used to apply API- merican PetroleumInstitute.
external pressure o gas lift valves to flex the bellows during
the pressure setting operation.
AnnularFlow - ormationfluidsareproduced upa system recommended by API.
through the tubing-casing annulus and recovered at he
surface.
Annulus- he pace between tubing and casing. ource to lift eservoir luids romaproducing well.
API Gravity- pecific gravity of crude oil as measured by
Artificial Lift -The application of energy from an outside
-B-
Back Pressure- he pressureexisting within the produc- BLPD- arrels of total liquid per day.ing string at he surface in a gas ift well. Also used to
designate the fluid pressure at the level of gas injection, the BOPD- arrels of Oil Per day-
pressure against which the operating valve injects gas.
Bellows- he responsive element of a gas lift valve. It
performs hesame unctionas hediaphragmoperated Bottomhole Pressure (BHP)- ressureatsomegiven
valve. It provides an area for pressure to act on and to move de pt h i n the well, usually opposite the producing
the valve stem.
BWPD- arrels of water per day.
-C-
Casing Flow- Samesnnular flow.) Continuous Flow Gas Lift- as liftperation in which
Casing Pressure- he pressure, measured at the surface,
within the well casing.
gas is injected continuously into the liquid column. Reser-
voir fluids and‘the injected gas are produced from the
wellhead at the surface without interruption.
Chamber Lift - special type of intermittent gas lift
which uses the tubing-casing annulus or a “bottle” on the.
end of the tubing string for the accumulation of formation Cooler- refrigerated water bath used to cool pressure
liquids between cycles. charged gasiftalveso 60°Fwhen settinghem.
Choke- type of orifice installed in a line in whichfluid is
flowing. The purpose is to restrict the flow and control the
rate of production.
Cross-over Seat- special seat for aas lift valvewhich
directs the pressure applied at the nose f the gas lift valve
Christmas Tree- term applied to the control valves, to the bellows and the-pressure applied to the-holes in the
pressure gages,and chokes assembled at the top of a well to side of the valve to the under side of the seat. It isused most
control the flow of oil and gas. often in fluid operated valves.
-D-
Dead Well- well that will not flow by itself. Dome- he volume chamber nside hebellows of agas
lift valve.
Dill Coreor Schrader Core Valve -Valve in the top of the Drawdown- he difference in pressure (psi) between the
gas ift valve used in charging hebellows with nitrogen. sta tic(shut-in)bottomholepressureand heflowing
bottomhole pressure at a constant ratef fluid production.
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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API T I T L E * V T - 6 9 4 W 0732270 O532766 L73
-E-
Emulsion - mixture of oil and water hat requires
treatment before the oil and water will separate.
-F-
Flowline- he surfacepipe through which the oil travels Formation (F Gas) Gas- as which is produced from the
from the well to storage. oil reservoir with the produced liquids.
Flowing Bottomhole Pressure (FBHP) - he Pressure Fluid or Production Operated Valve- gas l ift valve that
existing at the depth of the production formation in a well utilizes the pressure i n the production conduit as its pri-
at a constant rate of fluid production. mary operating medium.
-G-
Gas Lift-
method of artificial lift in which the energy of Ga s-oi l Ratio (GOR =Rgo)-
he number of standardcompressed gas is used directly to lift fluids to the surface. cubic feet of gas produced with a stock tank barrel of oil.
Gas Lift Valve- pressure regulator mounted on or in the
tubing string so that, by manipulation of the injection gas
pressure and the producing pressure, he valve will either be
open or closed to provide a controllable communication
between the tubing and casing for gas passage.
Geothermal Gradient- he naturally occurring increase
of temperature with depth in undisturbed ground. Normally
given in OFF/100Ft.
Gas-Liquid Ratio(GLR =RE,)- he number of standard
cubic feet of gas produced with a stock tank barrel of liquid Gradient - hange i n pressure or temperature per unit
(oil and water).hange in depth.
-H-
“Head”- he volume of reservoir fluids produced at the
surface following a short period of gas injection, as i n
intermittent operation.
IPR (Inflow Performance Relationship)- he relation- fluids and injected gas being produced from the wellhead at
ship of flowing bottomhole pressure to gross liquid produc- the surface for an interval following each injection period.
ing rate for a particular well. Intermitter (Time Cycle Controller) - A surface controlwhich may be adjusted and set to operate a motor valve at
Intermittent Flow - as lift operation i n which gas is predetermined ntervals of ime and also control the dura-
injected periodically into the liquid column, with reservoir tion of the operating or injection period.
-K-
Kic k-o ff Pressure- he gas injection pressure available fluids and wireline gas lift valve into the mandrel pocketfor unloading fluids from a gas liftell down to the operat- when installing the valve or guides the pulling tools ontoing valve depth. the valve when recovering the valve.
Kick-Over Tool-
he wireline tool which guides the Kick a Well Off-
nload and place a well on gas lift.
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E r V T - 6 9 4 0732290 0532967 DDT m
134 Gasift
-L-
Latch- he locking device for a wireline gas liftalve to Load Fluid(KillFluid) - iquidused ofill he
lock the valve i n the mandrel. well before pulling the tubing.
"-
Macaroni String- ubingnside tubing. Mscf (MCF)- ne thousandtandardubiceet of gas.This term is commonly used to express the volume of gas
Mandrel- Seewireline or tubingetrievable.) roduced,ransmitted, or consumed i n a given period oftime (scf- tandard cubic foot of gas).
Master Valve- arge valve used to shut in a well. Mscf/B (MCFIB) - housands of cubic feet per barrel.
-0-
Operating Pressure- he gas injection pressure available
to maintain the desired rateof fluid production in a gas lift
well under settled continuous or intermittent operation.
-P-
Productivity Index (PI=J)- he ratioof fluid production
rate, in barrels per day, to thedifference between static and
flowing bottomhole pressures (drawdown), in pounds per
square inch.
Pit - n emergency tank or shallow pond to hold salt
water, etc ., prior to disposal.
Pocket - he gas lift valve receiver inside a wireline(retrievable) mandrel.
force fo r thevalve. Thegas is usuallynitrogen.The
responsive element is usually a bellows.
Pressure Operated Valve- gas lift valve that utilizes
injection gas pressure as itsprimary operating medium.
Pressure Survey- n operation tomeasure and record the
pressures at various depths in the well bore with the well
either producing or shut-in. The pressures may be meas-
ured and recorded by either a self-contained unit run on a
Pressure ChargedValve- gas ift valve which uses a gas solid wireline or a unit run on an electric wireline with an
charge inside the responsive element to provide the closing nstantaneous recording at the surface.
-S-
Specific Gravity- he ratio of the weight of a substance Static Fluid Level- he depth below the surface to which
to the weight of an equal volume of a standard substance. reservoir fluids will rise when the producing conduit is open
Water is the standard for liquids and air is the standard for to atmospheric pressure.
gases.STB- tock tank barrel. The volume of oil, water or total
Spring Loaded Valve- gas lift valve which uses a spring liquid as measured in the stock tank.to provide the closing force for he valve.
Static Bottomhole Pressure- he pressure at formation
depth in a well after the well is shut-in and the pressures Stock Tank- tank for holding the produced liquids at
have been stabilized.tmosphericressurerior to pumping themlsewhere.
scf/STB- tandard cubic feet per stock tank barrel.
-T-
Tail Plug- he plug in the endof a gas lift valvewhich is may be measured and recorded at either a self-contained
the final seal on the dome. unit run on a solid wireline or a unit run on an electric
Temperature Survey- n operation to measure andrecord the temperature at various depths in the well bore Test Rack (Tester) -An arrangement of gas lift receivers,
with the well either producing or shut-in. The temperatures gages, valving etc., so that nitrogen gas pressure may be
wireline with an instantaneous recording at the surface.
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A P I T I T L E a V T - b 94 m 0732290 0532968 T 4 6 m
Glossary
applied to the bellows of a gas ift valve and simultaneously tional or standard mandrel. A tubing pup joint with a lug
measured to determine the pressure required to open the for mounting a conventional or tubing retrievable gas lift
gas lift valve. valve. The mandrel is an integral part of the tubing string.
Troubleshooting- he process of determining and cor- Tubing Retrievable Gas LiftValve- ommonly called a
recting a problem with a gas lift well. conventional gas lift valve. A gas l if t valve mounted on a
Tubing Flow- ormation fluids are produced up through
and recovered from the tubing at the surface.
tubing retrievable mandrel. It is necessary to pull the tubing
to recover the valves. This was the first method of mountinggas lift valves; consequently the name of conventional gas
Tubing Retrievable Mandrel -Commonly called conven- lift valve.
-W-
Wellhead- he stack of valves and fittings at the surface The mandrel becomes an integral part of the tubing string.
on top of a well.Wireline (Retrievable) Valve- gas lift valve mounted
Wireline (Retrievable) Mandrel- tubular member with inside the tubing that can be installed and recovered by
an internal receiver for a wireline (retrievable) gas lift valve. solid wireline operations without disturbing the tubing.
SYMBOLS
ck
Cd
CT
Dnv
D,
F,
Total effective area of Bellows, sq. in .
Area of Valve Seat or Port-Ball seat contact
area, sq. in.
Ratio of Gas Lift Valve Port to Bellows area:
From Mfg. Data.
Choke or Port diameterof the Gas Lift Valve,
' / d h inches.
Discharge coefficient for gas flow through an
orifice.
Correction factor for gas passage through a
choke.
Temperature correction factor for nitrogen
gas.
Depth of top valve, f t .
Depth on nth valve, f t .
Distance between valves, f t .
Depth of gas injection, ft.
Measured depth of deviated wells, f t .
Minimum spacing of gas lift valves or man-
drels, f t .
Depth of operative valve or gas injection, ft.
Reference depthof well: Normally measured
midpoint of perfs., on top of perfs., ft .
Closing force ongas lift valve, pounds force.
Total opening force on valve, pounds force.
Opening force due o pressure on the bellows,
pounds force.
Opening force due to pressuren valve stem,
pounds force.
Oil cut fraction of total produced liquid.
Water Cut fraction of total produced liquid.
Gradient, psi/ft.
Flowing gradient above point of gas injec-
tion, psi/ft.
Flowing gradient below point of gas injec-
tion, psi/ft.
Gas gradient of injection gas, psi/ft.
Gradient of oil, psi/ft.
Static gradient of load fluid, psi/ft.
Gradient of produced water, psi/ft.
Flowing production emperature gradient,
Deg. F/100 ft.
Static Temperature gradient, Deg. F/100 Ft.
Productivity Index (J=PI), BLPD/PSI.
Total number of gas l i ft valves.
Pressure Drop i n Inj. Gas pressure to deterinterference, psi.
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E x V T - 6 94 m 0732290 0532969 9 8 2 m
136 Gas Lift
Pressure applied under the bellowsf a gas
lift valve, psig.
Pressure applied under the stem of a gas lift
valve, psig.
Bubble point pressureof the produced oil,
psig.
Pressure of bellows at temperature of nth
valve, psig.
Bellows pressure at 60 deg. F., psig.
Injection gas pressure downstreamof sur-
face choke, psig
Effective opening pressure due to production
pressure, psig.
Max available pressureof injection gas at
surface, psig.
Injection gas pressure downstream of re-striction at surface, psig
Max pressure of injection gas at D,, psig.
Operating gas injection pressure at valve
number 1 , psig.
Operating gas injection pressure at nth valve,
psig.
Surface operating gas injection pressure to
open valve 1,psig.
Surface operating gas injection pressure to
open nth valve, psig.
Max kickoff gas injection pressure at surface,
psig.
Max flowing pressure at valve 1 while lifting
deeper, psig.
Max flowing pressure at nth valve while lift-
ing deeper, psig.
Min flowing pressure at valve 1 while unload-
ing, psig.
Min flowing pressure at nth valve while un-loading, psig.
Flowing production pressure at valve 1, psig.
Flowing production pressure at nth valve,
psig.
Production pressure effect, psig.
Production pressure effect factor- fg.
data- Previously TEF)
Pressure at standard conditions, psig.
Pressure of oil & gas separator, psig.
Pressure safety factor to ensure valve is un-
covered, psig.
Spring pressure effect on valve, psig.
Max unloading pressure at nth valve when un-covered, psig.
Valve closing pressure of valve 1 at depth,
psig.
Valve closing pressure of nth valve at depth,
psig.
Surface closing pressure of valve 1 , psig.
Surface closing pressure f nth valve, psig.
Test rack set opening pressure for valve 1, psig.
Test rack set opening pressure for nth valve,
psig.
Flowing bottomhole pressure at D,, psig.
Flowing pressure at the wellhead, psig.
Static bottomhole formation or reservoir pres-
sure, psig.
Max production rate below the bubble point,
BLPD.
Gas production ratefromformation, Mscfd.
Injection gas rate, Mscf/d.
Total gas rate measured (formation +injec-
tion), Mscf/d.
Total liquid rate, BLPD
Maximum liquid rate of well, BLPD.
Total oil production rate, BOPD.
Production rate at the bubble point, BLPD.
Total water production rate, BWPD
Ratio of gas to liquid, scf/bbl.
Ratio of formation gas to liquid, scf/bbl.
Ratio of injected gas to liquid, scf/bbl.
Ratio of gas to oil, scf/bbl.
Ratio of gas injected to oil, scf/bbl.
Specific gravity of produced gas.
Specific gravity of injected gas.
Specific gravity of oil.
yright American Petroleum Institute
ded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P IT I T L E x V T - 6 94 M 0 7 3 2 2 9 00 5 3 2 9 7 0 b T 4 m
Glossary 137
SG , Specificravity of producedater. T,, Temperature at standard conditions, deg. F.
T, Average gas injection temperature, deg. ETt Temperature at valve I depth, deg. F.
TB Surface temperature of injection gas, deg. F. Twh Flowing temperature at wellhead, deg. F.
Formation temperature, deg. F. T"(") Temperature at nth valve, deg. F.
T, Static earth surface temperature, deg. F.Z Gas compression factor at average pressure and
temperature.
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A P I T I T L E a V T - b 94 0732290 0532973 530
138 Gas Lift
REFERENCES
1.
2.
3.
4.
5 .
6.
7.
8.
9.
10.
11.
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yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
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A P I T I T L E x V T - 6 9 4 0732290 0532972 477 m
References 139
23. Cornish, R.E.: The Vertical Multiphase Flow of Oil
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(1980) PennWell Books, Tulsa, Oklahoma.25. Brown, K.E., et al: Gas Lift Theory and Practice,
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26. Doolittle, Jesse S.: Thermodynamics for E ngineers,
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Measurement in the Field, Exxo n Production Re-
search (1 978).
Phase Relations of Gas Condensate Fluids,Bureau of
Mines M onograph #10. Vol. 2,7 63-7 64.
Focht, F. T.: World Oil, 105-107 (January 1981).
White, G.W., O’Connell, B.T., Davis, R.C., Berry,
R . F., and Stacha,L.A.: An analytical Concept of the
Static and D ynamic Parameters of Intermittent Gas Lift,
Journal of Petroleum Technology (March 1963),
Society of Petroleum Engineers of AIM E.
Guiberson O il Tools, Artificial Lift-Gas Lift En-
gineering.
40. Teledyne Merla, Section 5 , Specifications and Valve
Performance Data, 1982.
41. Teledyne Geotech, Supervisory System for Gas Lift
Control, 1982.
42. Wall, P.T.: 12th Annual Southwest Petroleum Short
Course, TT U, 1965,Effect of Back Pressure on Inter-mittent Gas Lift.
43. Redden, J.D., Sherman, T.A.G., Blann, J.R.: Opti-
mizing Gas Lift Systems, SPEaper No. 5 150, 1974.
44. Clegg, J.D.: High R ate Artificial Lift, Journal of Pe-
troleum Technology (March 1988) 277-82.
45. Neely, A.B., Gipson, F.W., Capps, B., Clegg, J.D.,
and Wilson,P.: Paper, SPE 10377, resented at 198 1
SPE Annual Technical Conference and Exhibition, San
Antonio, TX , Octobe r 5-7,1981.
46. Blann, J.R., and Williams, J.D.: Determining the
Most Profitable Gas Injection Pressure for Gas Lift
Installation, Journal of Petroleum Technology (A u-
gust 1984).
47. DeMoss, E.E., and Tiemann, W.D.: Gas Lift In-
creases High Volume Production From Claymore
Field, Journal of Petroleum Technology (April 1982)
696-702.
48. Blann, J. R., Jacobson L. and Faber, C.: Produc-
tion Optimization in the Provincia Field, Colombia,SPE PE (Feb. 1989) 9-14.
49. Neely, A.B., Montgomery, J.W. and Vogel, J.V.: A
Field Test and Analytical Study of Intermittent Gas
Lift, SPEJ (Oct. 1 974 ) 502-12.
50. API Spec 11V1, Sp ecification for Gas Lift Valves,
Orifices, Reverse H ow Valves and Dummy Valves.
5 l . API Recommended Practice 11V5 (RP 1 1 V5), Rec-
ommended Practice for O peration, Maintenance and
Trouble-shooting of G as Lift Installations.
52. API Recomm ended Practice 11V6 (RP 11V6), Rec-
38. FOS, D.L. & Gau l, R. B.: Plunger Lift Performance ommended Practice for Design of Continuous Flow
Criteria with Operating Experience- entura Ave. Gas Lift Installations using injection Pressure Oper-
Field, Paper No. 801-41H, API D& P Practices 1965, ated Valves.
p. 124-140 .
39. Blann, J. R., Brow n, J. S. , Dufresne, L. P.: Im -
proving Gas Lift Performance in a Large North Afri-
can Oil Field, SPE Paper No. 8 408 , 1979.
53. API Recommended Practice l l V 7 (RP l lV 7) , Rec-
omm ended Practice for Repair, Testing and Setting
Gas Lift V alves.
yright American Petroleum Instituteded by IHS under license with API Licensee=Vetco Aibel/5925731102
Not for Resale, 07/27/2006 10:42:36 MDTeproduction or networking permitted without license from IHS
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