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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

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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 -

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W ASHI NGTO N, D .C . 20005.



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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



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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.



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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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API T I T L E t V T - b 94 m 0732290 0532833 T 73 W

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



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A P I T ITLE*VT -b 94 m 0732290 0532832 9 0 T

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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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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A P IT I T L E * V T - 6 9 4 m 07322700532838328 m

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


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-b 9 q m 073229005328392b4 m

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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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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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.



--`,,,``,,` ,̀`,,,`,````,`̀ ``,``-`-`,,̀ ,,`,`,,`---



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



--` , , ,` ` , ,` ` ,` , , ,

` ,` ` ` ` ,` ` ` ` ,` ` -` -` , ,` , ,` ,` , ,` ---



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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` , ,

` ,

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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



FRACTION O F M A X I M U M PRODUCING RATE

Fig.2 -4-

xample problem olution



--` , , ,` ` , ,` ` ,` , , ,` ,` ` ` ` ,` ` ` ` ,` ` -` -` , ,` , ,` ,` , ,` ---



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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`

` ` ` ,

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` , ,

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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



- - ` , , ,

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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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A P I TITLEaVT-h 94 9 0732290 0532855 407 m

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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A P I T I TLE*VT -6 94 m 0732290 0532856 343 m

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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A P I TITLErVT-b '74 m 0732270 0532858 116 m

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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API T I T L E S V T - 6 94 m 0732290 0532859 052 m

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



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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


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


Not for Resale, 07/27/2006 10:42:36 MDTproduction or networking permitted without license fr om IHS

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A P I TITLExVT-6 9 4 m 0 7 3 2 2 9 0 0532864 41T


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

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 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.



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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”



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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



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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



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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



--` , , ,` ` , ,` ` ,` , , ,` ,` ` `

` ,` ` ` ` ,` ` -` -` , ,` , ,` ,` , ,` ---



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



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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



--` , , ,` ` , ,` ` ,` , , ,` ,` ` ` ` ,` ` ` ` ,` ` -` -` , ,` , ,` ,` , ,` ---



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



--` , , ,` ` , ,` ` ,` , , ,` ,` ` ` ` ,` ` ` ` ,` ` -` -` , ,` , ,` ,` , ,` ---



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



--` , , ,` ` , ,` ` ,` , , ,` ,` ` ` ` ,` ` ` ` ,` ` -` -` , ,` , ,` ,` , ,` -

--



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



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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



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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



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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



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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



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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.



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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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` ,

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` ` ` ` ,

` ` - ` - ` , ,

` , ,

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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



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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



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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



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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.



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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)



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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



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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



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A P IT I T L E a V T - 6 9 4 W 0732290 0532904 926


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:



- - ` , , ,

` ` , ,

` ` ,

` , , ,

` ,

` ` ` ` ,

` ` ` ` ,

` ` - ` - ` , ,

` , ,

` ,

` , ,

` - - -



A P I T IT L ExVT - b 94 0732290 0532qOb 7 T q


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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A P I T I T L E t V T - 6 94 m 0732290 0532907 635 m

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



--` , , ,` ` , ,` ` ,` , , ,` ,` ` ` ` ,` ` ` ` ,` ` -` -` , ,` , ,` ,` , ,` ---



A P I T I T L E x V T - 6 9 4 m 0732290 0532908 571 m


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)



--` , , ,` ` , ,` ` ,` , , ,` ,` ` ` ` ,` ` ` ` ,` ` -` -` , ,` , ,` ,` , ,` ---



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)



- - ` , , ,

` ` , ,

` ` ,

` , , ,

` ,

` ` ` ` ,

` ` ` ` ,

` ` - ` - ` , ,

` , ,

` ,

` , ,

` - - -



A P I T ITLE*VT -b 94 m 0732290 05329LO L 2 T m


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



--`,,,``,,``,`,,,`,````,````,``-`-`,,`,,`,`,,`---



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



- - ` , , ,

` ` , ,

` ` ,

` , , ,

` ,

` ` ` ` ,

` ` ` ` ,

` ` - ` - `

, ,

` , ,

` ,

` , ,

` - - -



A P I T I T L E + V T - 6 94 m 07322900532932 TT2


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



- - ` , , ,

` ` , ,

` ` ,

` , , ,

` ,

` ` ` ` ,

` ` ` ` ,

` ` - ` - ` , ,

` , ,

` ,

` , ,

` - - -



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



- - ` , , ,

` ` , ,

` ` ,

` , , ,

` ,

` ` ` ` ,

` ` ` ` ,

` ` - ` - ` , ,

` , ,

` ,

` , ,

` - - -



&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



--` , , ,` ` , ,` ` ,` , , ,` ,` ` ` ` ,` ` ` ` ,` ` -` -` , ,` , ,` ,` , ,` ---



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



--`,,,``,,``,`,,,`,````,````,``-`-`,,`,,`,`,,`---



API T ITLE*VT -b 94 m 0732290 0532’9Lb 648 m


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.



--` , , ,` ` , ,` ` ,` , , ,` ,` ` ` ` ,` ` ` ` ,` ` -` -` , ,` , ,` ,` , ,` ---



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.



- - ` , , ,

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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



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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



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A P I I T L E *V T - h 94 m 0732290 0532920 07’7 m


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



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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



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‘ A P I T I T L E * V T - 6 94 m 0732290 0532922 941 m


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.



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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



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A P I T I T L E + V T - h 9 4 0732290 0532924 714


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


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




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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


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


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 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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A P I T I T L E r V T - 6 94 m 0732290 0532940 967 m


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


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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API T I T L E x V T - 6 9 4 0732290 0532944 502 m


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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A P I T I T L E + V T - b 94 m 0732290 0532945 449 m

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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API T I T L E * V T -6 9Y m 0732290 0532946 385 m

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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API T I T L E * V T -6 94 0732290 0532947 211 m

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.



- - ` , , ,

` ` , ,

` ` ,

` , , ,

` ,

` ` ` ` ,

` ` ` ` ,

` ` - ` - ` , ,

` , ,

` ,

` , ,

` - - -



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



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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



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A P I TITLErVT-b 94 m 0732270 0532750 8Ob m

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



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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.




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A P I T I T L E * V T - 6 94 m 0732290 0532952 689 m

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.



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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.



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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.



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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.



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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.




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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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138 Gas Lift

REFERENCES

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A P I T I T L E x V T - 6 9 4 0732290 0532972 477 m

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(1980) PennWell Books, Tulsa, Oklahoma.25. Brown, K.E., et al: Gas Lift Theory and Practice,

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34 .

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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.



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