api gas lift manual

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GAS LIFT BOOK 6 OF THE

SERIES CATIONAL TRAINING

THIRD EDITION, 1994

Copyright American Petroleum Institute Reproduced by IHS under license with API

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API GAS LIFT MANUAL Book 6 of the Vocational Training Series

Third Edition, 1994

Issued by AMERICAN PETROLEUM INSTITUTE Exploration & Production Department

FOR INFORMATION CONCERNING TECHNICAL CONTENT OF THIS PUBLICATION CONTACT THE API EXPLORATION & PRODUCTION DEPARTMENT,

SEE BACK COVER FOR INFORMATION CONCERNING HOW TO OBTAIN ADDITIONAL COPIES OF THIS PUBLICATION.

700 NORTH PEARL, 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 individual engineering judgment.

OFFICIAL PUBLICATION

REG U.S. PATENT OFFICE

Copyright O 1994 American Petroleum Institute



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POLICY

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FOREWORD

Artificial l i f t represents an increasingly important part of the oil business. In fact, at the time of this writing, over 90% of the oil wells in the United States used some form of artificial lift. The four basic types of artificial lift used in the oil industry are: rod pumping, electric submersible pumping, hydraulic pumping, and gas lift. As the name implies, gas l i f t is the only one of the artificial lift systems that does not use some form of mechanical pump to physically force the fluid from one place to another. Because of this phenomenon, gas lift has certain advantages over the other systems in some instances and occupies a rather unique and important place as a lift mechanism.

This manual is under the jurisdiction of the Executive Committee on Training and Development, Exploration & Production Department, American Petroleum Institute. It is intended to familiarize operating personnel with the use of gas lift as an artificial l i f t system. It includes information on the basic principles of gas lift, the choice of gas lift equipment, how various types of gas lift equipment work, and how a gas lift system should be designed. Information is also included on monitoring, adjusting, regulating, and trouble-shooting gas lift equipment.

The first edition of this manual was issued in 1965. A second edition was issued in 1984, and editorial errata were published in 1986 and incorporated in a 1988 reprint of the manual. This third edition was developed as an editorial update for consistency with recent API gas lift standards.

It was developed with assistance by volunteer technical reviewers including:

J. R. Blann, Consultant, Lead Reviewer J. R. Bennett, Exxon Production Research Company Joe Clegg, Pectin International John Martinez, Production Associates H. W. Winkler, Consultant



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Other publications in the API Vocational Training Series are:

Book 1: Introduction to Oil and Gas Production, Fourth Edition, 1983 (Reaffirmed 1988) This popular orientation manual contains 81 pages and over 100 photographs and line

drawings. It is written 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 office personnel, and businesses allied with the oil and gas industry. The fourth edition represents a complete revision and updating of the previous edition. Spiral bound, 8 ’ / 2 x 1 1 , soft cover.

Book 2: Corrosion of Oil and Gas Well Equipment, Second Edition, 1990 General aspects of corrosion, sweet corrosion, oxygen corrosion, and electrochemical

corrosion are thoroughly covered. Methods of evaluation and control measures are described in detail Spiral bound, 6 ’ / 2 x 10, soft cover, 87 pages.

Book 3: Subsurface Salt Water Injection und Disposal, Second Edition 1978 (Reaffirmed 1986)

A handbook for the planning, installation, operation, and maintenance of subsurface injection and disposal systems. Design criteria and formulae are given for gathering systems, treating plants, and injection facilities. Alternative equipment and methods are discussed and illustrated. Economic considerations are presented. The book includes a glossary and bibliog- raphy. Soft cover, 6I/2 x 1 O , spiral bound, 67 pages, 1 S illustrations.

Book 5: Wireline Operations and Procedures, Second Edition, 1983 (Reaffirmed 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 operations, including those operations conducted offshore. It is a basic manual presented in a simple, uncluttered manner. Soft cover, 72 pages, 90 illustrations, 6l/2 x IO, spiral bound.

API Specs & RPs (Users should check the latest editions)

Spec 1 1 VI, Specification for Gas Lift Valves, Orifices, Reverse Flow Valves and Dummy Va 1 ves

Covers specifications on gas lift valves, orifices, reverse flow valves, and dummy valves.

RP 1 1 V5, Recommended Practice for Operation, Maintenance, and Trouble-Shooting of Gas Lift Installations

Covers recommended practice on kickoff and unloading, adjustment procedures and trouble-shooting diagnostic tools and location of problem areas for gas lift operations.

RP 1 1 V6, Recommended Practice for Design of Continuous Flow Gas Lift Installations Using Injection Pressure Operated Valves

This recommended practice is intended to set guidelines for continuous flow gas lift installation designs using injection pressure operated valves. The assumption is made that the designer is familiar with and has available data on the various factors that affect a design. The designer is referred to the API “Gas Lift Manual” (Book 6 of the Vocational Training Series) and to the various API 1 1V recommended practices on gas lift.

RP 1 1V7, Recommended Practice for Repair, Testing and Setting Gas Lift Valves This document applies to repair, testing, and setting gas lift valves and reverse flow (check)

valves. It 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 bellows valve is also covered. Other valves, including bellows charged valves in production pressure (fluid) service should be repaired according to these guidelines.



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TABLE OF CONTENTS API GAS LIFT MANUAL

CHAPTER 1 . INTRODUCTION TO ARTIFICIAL LIFT AND GAS LIFT BASIC PRINCIPLES OF OIL PRODUCTION ........................................................................... 1

Factors That Affect Oil Production .......................................................................................... i ARTIFICIAL LIFT .......................................................................................................................... 1

Types of Artificial Lift Systems ............................................................................................... 1 Choosing an Artlflclal Lift System .......................................................................................... 1

THE PROCESS OF GAS LIFT ...................................................................................................... 2 Types of Gas Lift ......................................................................................................................... 2 Continuous Flow Gas Lift .......................................................................................................... 2 Intermittent Flow Gas Lift ......................................................................................................... 3

ADVANTAGES AND LIMITATIONS OF GAS LIFT ............................................................. 4 Choice of Gas Lift System ......................................................................................................... 4

HISTORICAL REVIEW OF GAS LIFT DEVELOPMENT ...................................................... 6 Early Experiments ....................................................................................................................... 6 Chronological Development ...................................................................................................... 6

DEVELOPMENT OF THE MODERN GAS LIFT VALVE ...................................................... 8 Differential Valves ...................................................................................................................... 8 Bellows Charged Valves ............................................................................................................ 9

. . .

Technical Development of Gas Lift Equipment ..................................................................... 6

CHAPTER 2 - WELL PERFORMANCE INTRODUCTION .......................................................................................................................... 11 INFLOW PERFORMANCE PREDICTION .............................................................................. 12

Productivity Index (P.I . ) Technique ....................................................................................... 12 Inflow Performance Relationship (IPR) Technique ............................................................ 12 Vogel IPR Curve ........................................................................................................................ 12 Vogel’s Example Problem ........................................................................................................ 13

WELL OUTFLOW PERFORMANCE PREDICTION ............................................................. 17 Example Problem ....................................................................................................................... 17

PREDICTING THE EFFECT OF GAS LIFT ............................................................................ 19 Comparison of Conduit Size .................................................................................................... 21 Effect of Surface Operating Conditions ................................................................................ 21 Use of Inflow Performance Relationship Curves (IPR) ...................................................... 22 Computer Programs for Well Performance Analysis .......................................................... 22

CHAPTER 3 - MULTIPHASE FLOW PREDICTION INTRODUCTION .......................................................................................................................... 23

Dimensionless Parameters ....................................................................................................... 23 Empirical Data ........................................................................................................................... 23 Basis for Developing Multiphase Flow Correlations .......................................................... 23 Accuracy of Flowing Pressure at Depth Predictions ........................................................... 23 Importance of Reliable Well Test Data ................................................................................. 24

FLOW CORRELATIONS .................................................................................................... 24 PUBLISHED VERTICAL, HORIZONTAL AND INCLINED MULTIPHASE

Papers Evaluating the Accuracy of Multiphase Flow Correlations .................................. 24 Ros-Gray and Duns-Ros Correlations .................................................................................... 25

ENERGY LOSS FACTORS OR NO-SLIP HOMOGENEOUS MIXTURES ............... 25 SIMPLIFIED MULTIPHASE FLOW CORRELATIONS BASED ON TOTAL

Poettmann and Carpenter Correlation .................................................................................... 25 Baxendell and Thomas Correlation ........................................................................................ 25 Two-Phase Homogeneous No-Slip Mixture Correlations .................................................. 26

GENERAL TYPE OF MULTIPHASE FLOW CORRELATIONS ......................................... 26 Typical Pressure Gradient Equation for Vertical Flow ...................................................... 26 Published General Type Correlations .................................................................................... 27



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TABLE OF CONTENTS (Continued)

DISPLAYS OF FLOWING PRESSURE AT DEPTH GRADIENT CURVES ..................... 27 Converting Rgo to Rg. ................................................................................................................. 27 Gilbert’s Curves ......................................................................................................................... 28 Minimum Fluid Gradient Curve .............................................................................................. 28 Displaying Gradient Curves to Prevent Crossover .............................................................. 32

STABILITY OF FLOW CONDITIONS AND SELECTION OF PRODUCTION CONDUIT SIZE ........................................................................................ 32

Conditions Necessary to Assure Stable Multiphase Flow .................................................. 33 Effect of Tubing Size on Minimum Stabilized Flow Rate ................................................. 34

Graphical Determination of Minimum Stabilized Production Rate .................................. 32

CHAPTER 4 - GAS APPLICATION AND GAS FACILITIES FOR GAS LIFT

INTRODUCTION .......................................................................................................................... 35 BASIC FUNDAMENTALS OF GAS BEHAVIOR .................................................................. 35 APPLICATION TO OILFIELD SYSTEMS .............................................................................. 39

Subsurface Applications ........................................................................................................... 39 Pressure Correction ................................................................................................................... 39 Temperature Correction ............................................................................................................ 39 Test Rack Settings ..................................................................................................................... 41 Gas Injection in the Annulus or Tubing ................................................................................ 41 Flow Through the Gas Lift Valve ........................................................................................... 45

SURFACE GAS FACILITIES ..................................................................................................... 49 System Design Considerations ................................................................................................ 49 Gas Conditioning ....................................................................................................................... 49 Reciprocating Compression ..................................................................................................... 50

Piping and Distribution Systems ............................................................................................ 54 Gas Metering .............................................................................................................................. 54

Centrifugal Compression .......................................................................................................... 52

CHAPTER 5 - GAS LIFT VALVES INTRODUCTION .......................................................................................................................... 57 VALVE MECHANICS .................................................................................................................. 57

Basic Components of Gas Lift Valves ................................................................................... 58 Closing Force ............................................................................................................................. 59 Opening Forces .......................................................................................................................... 59 Valve Load Rate ........................................................................................................................ 60 Probe Test ................................................................................................................................... 60 Production Pressure Effect ...................................................................................................... 60 Closing Pressure ........................................................................................................................ 61

VALVE CHARACTERISTICS .................................................................................................... 61 Dynamic Flow Test ................................................................................................................... 6. 1 Valve Spread .............................................................................................................................. 61 Bellows Protection .................................................................................................................... 62 Test Rack Opening Pressure .................................................................................................... 62

TYPES OF GAS LIFT VALVES ................................................................................................ 63 Classification of Gas Lift Valves by Application ............................................................... 63 Valves Used for Continuous Flow ......................................................................................... 63 Valves Used for Intermittent Lift ........................................................................................... 63

Wireline Retrievable Valve and Mandrel ............................................................................. 65 Mandrel and Valve Porting Combinations ............................................................................ 67

Basic Valve Designs ................................................................................................................. 64

CHAPTER 6 - CONTINUOUS FLOW GAS LIFT DESIGN METHODS INTRODUCTION .......................................................................................................................... 69



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TYPES OF INSTALLATIONS .................................................................................................... 69 CONTINUOUS FLOW UNLOADING SEQUENCE ............................................................... 70 DESIGN OF CONTINUOUS FLOW INSTALLATIONS ....................................................... 72

Types of Design Problems ....................................................................................................... 72 Example Graphical Design ...................................................................................................... 72

Downhole Temperature for Design Purposes ....................................................................... 79 Actual Conditions Different From Design Conditions ....................................................... 81

DESIGNING GAS LIFT FOR OFFSHORE INSTALLATIONS ........................................... 82 ADVANTAGES OF CONTINUOUS FLOW OVER INTERMITTENT

Safety Factors in Gas Lift Design .......................................................................................... 77

FLOW GAS LIFT .................................................................................................................. 83 DUAL GAS LIFT INSTALLATIONS ........................................................................................ 83

CHAPTER 7 -ANALYSIS AND REGULATION OF CONTINUOUS FLOW GAS LIFT

INTRODUCTION .......................................................................................................................... 84 Recommended Practices Prior to Unloading ........................................................................ 84 Recommended Gas Lift Installation Unloading Procedure ................................................ 84 Analyzing the Operation of a Continuous Flow Well ........................................................ 85

GAS LIFT WELLS ................................................................................................................ 85 Recording Surface Pressure in the Tubing and Casing ...................................................... 85 Measurement of Gas Volumes ................................................................................................ 85 Surface and Estimated Subsurface Temperature Readings ................................................ 86 Visual Observation of the Surface Installation .................................................................... 86 Testing Well for Oil and Gas Production ............................................................................. 87

METHODS OF OBTAINING SURFACE DATA FOR CONTINUOUS FLOW

METHODS OF OBTAINING SUBSURFACE DATA FOR CONTINUOUS FLOW GAS LIFT ANALYSIS ........................................................................................... 87

Subsurface Pressure Surveys ................................................................................................... 87 Subsurface Temperature Surveys in Casing Flow Wells ................................................... 88

Computer Calculated Pressure Surveys ................................................................................. 88 Temperature Surveys in Tubing Flow Wells ........................................................................ 88 Flowing Pressure and Temperature Survey .......................................................................... 90 Fluid Level Determination by Acoustical Methods ............................................................ 91

Precautions when Running Flowing Pressure and Temperature Surveys ....................... 88

VARIOUS WELLHEAD INSTALLATIONS FOR GAS INJECTION CONTROL .............................................................................................................................. 91

WELL INJECTION GAS PRESSURE FOR CONTINUOUS FLOW SYSTEMS ................................................................................................................. 92

GETTING THE MOST OIL WITH THE AVAILABLE LIFT GAS ..................................... 92 Manual Controls ........................................................................................................................ 92 Semi-Automatic Controls ......................................................................................................... 93 Optimizing Gas Lift Systems .................................................................................................. 93 Automatic Optimization of Injection Gas Use ..................................................................... 95

APPENDIX 7A - EXAMPLES OF PRESSURE RECORDER CHARTS FROM CONTINUOUS FLOW WELLS ............................................................... 96

CHAPTER 8 . INTERMITTENT FLOW GAS LIFT INTRODUCTION ........................................................................................................................ 102 OPERATING SEQUENCE ......................................................................................................... 102 TYPES OF INSTALLATIONS .................................................................................................. 103



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FACTORS AFFECTING PRODUCING RATE ............................................................... 103 Maximum Rate .................................................................................................................. 103 Fallback .............................................................................................................................. 104 Use of Plungers i n Intermittent Lift Systems .............................................................. 105

DESIGN OF INTERMITTENT LIST INSTALLATIONS ............................................ 105 Fallback Method ............................................................................................................... 105 Percent Load Method ....................................................................................................... 108 Variations of Percent Load Method .............................................................................. 109 Production Pressure Operated Gas Lift Valves .......................................................... 109

CHAMBERS .......................................................................................................................... 109 Design of a Gas Lift Chamber Installation .................................................................. 110

CHAPTER 9 - PROCEDURES FOR ADJUSTING, REGULATING AND ANALYZING INTERMITTENT FLOW GAS LIFT INSTALLATIONS

INTRODUCTION ................................................................................................................. 112 CONTROL OF THE INJECTION GAS ............................................................................ 112

The Time Cycle Controller ............................................................................................. 112 Location of Time Cycle Controller ............................................................................... 113 Choke Control of the Injection Gas .............................................................................. 113

UNLOADING AN INTERMITTENT INSTALLATION ............................................... 113 Recommended Practices Prior to Unloading ............................................................... 113 Initial U-Tubing ................................................................................................................ 114 Unloading Operations Using A Time Cycle Operated Controller ........................... 114 Unloading with Choke Control of the Injection Gas ................................................. 114

ADJUSTMENT OF TIME CYCLE OPERATED CONTROLLER .............................. 115 Procedure or Determining Cycle Frequency ............................................................... 115

INJECTION GAS ......................................................................................................... 115 SELECTION OF CHOKE SIZE FOR CHOKE CONTROL OF

VARIATION IN TIME CYCLE AND CHOKE CONTROL OF INJECTION GAS ......................................................................................................... 116

Application of Time Opening and Set Pressure Closing Controller ....................... 116 Application of Time Cycle Operated Controller with Choke in the

Injection Gas Line ........................................................................................................ 116 Application of A Combination Pressure Reducing Regulator and

IMPORTANCE OF WELLHEAD TUBING BACK PRESSURE TO Choke Control 116

REGULATION OF INJECTION GAS ...................................................................... 117 Wellhead Configuration .................................................................................................. 117 Separator Pressure ............................................................................................................ 117 Surface Choke in Flowline ............................................................................................. 117 Flowline Size and Condition .......................................................................................... 117

REGULATION OF INJECTION GAS ...................................................................... 117 Installation Will Not Unload .......................................................................................... 117 Valve Will Not Close ....................................................................................................... 117 Emulsions ........................................................................................................................... 118 Corrosion ........................................................................................................................... 118

...............................................................................................................

SUGGESTED REMEDIAL PROCEDURES ASSOCIATED WITH

TROUBLE-SHOOTING ...................................................................................................... 118

APPENDIX 9A . EXAMPLES OF INTERMITTENT GAS LIFT MALFUNCTIONS ........................................................................... 120



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CHAPTER 10 . THE USE OF PLUNGERS IN GAS LIFT SYSTEM INTRODUCTION ................................................................................................................. 124 APPLICATIONS ................................................................................................................... 124 TYPES OF PLUNGER LIFT .............................................................................................. 124 SELECTING THE PROPER EQUIPMENT ..................................................................... 125

Retrievable Tubing (or Collar) Stop ............................................................................. 125 Standing Valve .................................................................................................................. 125

Plungers .............................................................................................................................. 126 Well Tubing ....................................................................................................................... 130 Master Valve ..................................................................................................................... 131 Second Flow Outlet .......................................................................................................... 131

PROPER INSTALLATION PROCEDURES ................................................................... 131 SUMMARY ........................................................................................................................... 131

GLOSSARY .......................................................................................................................... 132

SYMBOLS ............................................................................................................................ 135

Bumper Spring .................................................................................................................. 126

Lubricator .......................................................................................................................... 131

REFERENCES ..................................................................................................................... 138



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1

CHAPTER 1 INTRODUCTION TO ARTIFICIAL LIFT AND GAS LIFT

BASIC PRINCIPLES OF OIL PRODUCTION

When oil is first found in the reservoir, it is under pressure from the natural forces that surround and trap it. If a hole (well) is drilled into the reservoir, an opening is provided at a much lower pressure through which the reservoir fluids can escape. The driving force which causes these

PRESSURE

fluids to move out of the reservoir and into the wellbore comes from the compression of the fluids that are stored in the reservoir. The actual energy that causes a well to produce oil results from a reduction in pressure between the reservoir and the producing facilities on the surface. Fig. 1-1 illustrates this production process as it occurs in an oil well. If the pressures in the reservoir and the wellbore are allowed to equalize, either because of a decrease in reservoir PRESSUHF

pressure or an increase in wellbore and surface pressure, no flow from the reservoir will take place and there will be no production from the well.

*ELLHEAD 10 PROCESSING AND TREATING

STILL LOWER PRESSURE /

LOWEST

P R E S S U R E

Factors That Affect Oil Production Fig. 1-1 - The production process in an oil well

ARTIFICIAL LIFT

In many wells the natural energy associated with oil will not produce a sufficient pressure differential between the reservoir and the wellbore to cause the well to flow into the production facilities at the surface. In other wells, natural energy will not drive oil to the surface in sufficient volume. The reservoir’s natural energy must then be supplemented by some form of artificial lift.

Types of Artificial Lift Systems There are four basic ways of producing an oil well by

artificial lift. These are Gas L@, Sucker Rod Pumping, Sub- mersible Electric Pumping and Subsurface Hydraulic Pumping. The surface and subsurface equipment required for each system is shown in Fig. 1-2.

Choosing an Artificial Lift System

The choice of an artificial lift system in a given well depends upon a number of factors. Primary among them, as far as gas lift is concerned, is the availability of gas. If gas is readily available, either as dissolved gas in the produced oil, or from an outside source, then gas lift is often an ideal selection for artificial l if t . Experience has shown that produced gas will support a gas lift system if the daily gas 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 installation is adequately designed, wells can be gas lifted over a wide range of producing conditions by regulating the injection gas volume at the surface.



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2 Gas Lift

THE PROCESS OF GAS LIFT

Gas lift is the form of artificial lift that most closely resembles the natural flow process. It can be considered an extension of the natural flow process. In a natural flow well, as the fluid travels upward toward the surface, the fluid column pressure is reduced, gas comes out of solution, and the free gas expands. The free gas, being lighter than the oil it displaces, reduces the density of the 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 flow. This is shown in Fig. 1-3(A). When a well produces water along with the oil and the amount of free gas in the column is thereby reduced, the same pressure differential between wellbore and reservoir can be maintained by supplementing the formation 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 the oil industry. These are called continuous flow and intermittent flow.

Continuous Flow Gas Lift

In the continuous flow gas lift process, relatively high pressure gas is injected downhole into the fluid 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 PUMP PUNP

\ . -

I

PACKER

STANDING VALVE IOPTIONALI

“CONTROL EQUIPMENT

-GAS LIFT VALVE

GAS LIFT (COURTESY DRESSER-GUIEERSONJ

Fig. 1-2 - Artificial lift systems



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Introduction to Artificial Lift and Gas Lift 3

2. Expansion of the injection gas so that it pushes liquid Intermittent Flow Gas Lift ahead of it which further reduces the column weight, thereby increasing the differential between the reser- If a well has a low reservoir pressure or a very low voir and the wellbore (Fig. 1-4B). producing rate, it can be produced by a form of gas lift

3 . Displacement of liquid slugs by large bubbles of gas called intermittent flow. As its name implies, this system produces intermittently or irregularly and is designed to produce at the rate at which fluid enters the wellbore acting as pistons (Fig. 1-4C).

A typical small continuous flow gas lift system is shown from the formation. In the intermittent flow system, fluid is in Fig. 1-5. allowed to accumulate and build up in the tubing at the

F LUI

' ' \d FROM FORMATION OIL & GAS

r 4 I

D COLUMN WEIGHT REDUCED BY

WELL FORMATION GAS IN A NATURAL FLOW

( A )

OIL & GAS ' FROM FORMATION I

FLUID COLUMN WEIGHT REDUCED BY

A GAS LIFT WELL FORMATION AND INJECTED GAS:

(B)

Fig. 1-3 - Reduction in fluid column weight by formation and injected gas



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4 Gas Lift

bottom of the well. Periodically, a large bubble of high the rifle slug. The frequency of gas injection in intermit- pressure gas is injected into the tubing very quickly under- tent lift is determined by the amount of time required for a neath the column of liquid and the liquid column is pushed liquid slug to enter the tubing. The length of the gas in- rapidly up the tubing to the surface. This action is similar to jection period will depend upon the time required to push firing a bullet from a rifle by the expansion of gas behind one slug of liquid to the surface.

ADVANTAGES AND LIMITATIONS OF GAS LIFT

Choice of Gas Lift System The advantages of gas lift can be summarized as follows:

Because of its cyclic nature, intermittent flow gas lift is suited only to wells that produce at relatively low rates. Continuous flow gas lift will usually be more efficient and less expensive for wells that produce at higher rates where continuous flow can be maintained without excessive use of injection gas.

Gas lift is suitable for almost every type of well that requires artificial lift. It can be used to artificially lift oil wells to depletion, regardless of the ultimate producing rate; to kick off wells that will flow naturally; to back flow water injection wells; and to unload water from gas wells.

1. Initial cost of downhole gas lift equipment is usually 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 lifting from near total depth at depletion. Gas lift installations can be designed to lift from one to many thousands of barrels per day.

3. The producing rate can be controlled at the surface.

4. Sand in the produced fluid does not affect gas lift equipment in most installations.

- LIQUID

- GAS

Reduction of Expansion of Gas Fluid Density

(C) Displacement of Liquid Slugs by Gas Bubbles

Fig. 1-4 - Three effects of gas in a gas l i f t well



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5 . Gas lift is not adversely affected by deviation of the wellbore.

6. The relatively few moving parts in a gas lift system give it a long service life when compared to other forms of artificial lift.

7. Operating costs are usually relatively low for gas lift systems.

8. Gas lift is ideally suited to supplement formation gas for the purpose of artificially lifting wells where mod- erate amounts of gas are present in the produced fluid.

9. The major item of equipment (the gas compressor) in a gas lift system is installed on the surface where it can be easily inspected, repaired and maintained. This equipment can be driven by either gas or electricity.

GLYCOL

On the other hand, gas lift also has certain limitations which can be summarized as follows:

l . Gas must be available. In some instances air, exhaust gases, and nitrogen have been used but these are generally more expensive and more difficult to work with than locally produced natural gas,.

2. Wide well spacing may limit the use of a centrally located source of high pressure gas. This limitation has been circumvented on some wells through the use of gas-cap gas as a lifting source and the return of the gas to the cap through injection wells.

3. Corrosive gas lif t gas can increase the cost of gas lif t operations if i t is necessary to treat or dry the gas before use.

DEHYDRATOR SURPLUS GAS

TO SALES

STATION GAS/OI L SEPARATOR

MANIFOLD

INJECTION GAS MANIFOLD (METERING & CONTROL)

ØI

Fig. 1-5 - A typical gas lift system



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4. Installation of a gas lift system including compressors usually requires a longer lead time and greater preparation than does single well pumping systems. In addition, the initial surface installation for gas lift will sometimes be more expensive than equivalent pumping installations. However, the reduced operating cost of the gas lift system will usually far out weigh any additional cost of the initial installation. Also, if the associated gas will be gathered and compressed, as is usually the case, provisions for circulating some of the compressed gas for gas lift will not, in most cases, significantly increase the initial cost.

5. In very low pressured reservoirs, continuous flow gas lift cannot achieve as great a pressure drawdown as can some pumping systems. However, when low flowing bottomhole pressure is desired, the use of intermittent lift and chamber lift forms of gas lift can usually achieve pressure draw downs comparable to pumping systems.

6. Conversion of old wells to gas lift can require a higher level of casing integrity than would be required for pumping systems.

HISTORICAL REVIEW OF GAS LIFT DEVELOPMENT

Early Experiments 3. 1900-1920: Gulf Coast Area “air for hire” boom. Such famous fields as Spindle Top were produced by air lift. Carl Emanual Loscher (German mining engineer) applied

compressed air as a means of lifting liquid in laboratory experiments in 1797. The first practical application of 4. 1920-1929: Application of straight gas lift with wide air lift was in 1846 when an American named Cockford publicity from the Seminole Field in Oklahoma (See lifted oil from some wells in Pennsylvania. Fig. 1-7).

The first U.S. patent for gas lift called an “oil ejector” was issued to A. Brear in 1865 (Fig. 1-6).

FLOW LINE -b.rl

W Fig. 1-6 - Brear Oil Ejector

(May 23, 1865)

Chronological Development

The following chronological development of gas lift was given by Brown, Canalizo and Robertson in a paper published in 1961. (Many of the sketches shown in this chapter are taken from this paper.)

1. Prior to 1864: Some laboratory experiments performed with possibly one or two practical applications.

2. 1864-1900: This era consisted of lifting by compressed air injected through the annulus or tubing. Several flooded mine shafts were unloaded. Numer- ous patents were issued for foot-pieces, etc.

SUBMERGENCE

Fig. 1-7 - Early gas lift nomenclature

5. 1929-1945: This era included the patenting of about 25,000 different flow valves. More efficient rates of production as well as proration caused the development 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 most of them marketing some version of a pressure-operated valve.

7. 1957: Introduction of wireline retrievable gas lift valves.



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Technical Development of Gas Lift Equipment 3 . Kick-off valves (Fig. 1-10 and Fig. 1-1 1) were next

1.

The technical development of gas lift equipment can be employed to provide a means for closing off gas after a lower valve was uncovered. The early kick-off valves were designed to operate on a 10-20 psi pressure dif-

grouped into stages which are described as follows:

Straight gas injection which employed no valves and ferential until the development of the spring-loaded consisted primarily of U-tubing the gas around the differential valve which operated at about 100 psi dif- bottom of the tubing. Several types of early gas and ferential. The kick-off valve was a crude forerunner air lift hookups are shown in Fig. 1-8. of the modern gas lift flow valve.

2

Fig. 1-8 - Early gas (air) lift without valves

Jet collars (Fig. 1-9) were placed up the string to allow gas to enter higher up and thereby reduce the excessive kick-off pressures required for kicking around the bottom.

\:::%ION TURN TUBING TO CLOSE

,-TU BI NG TUBING

GAS "

AS

TUBING

Fig. 1-10 - Taylor kick-off valve

I- FLOW LINE a+-

- - I "" -=-":="" "

FLAPPER TYPE \ SPRING

Fig. 1-9 - Jet collar Fig. 1-11 - Kick-off valves



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A P I T I T L E S V T - 6 94 m 0732290 0532843 912 m 8 Gas Lift

DEVELOPMENT OF THE MODERN GAS LIFT VALVE

Differential Valves Until 1940, the closest thing to the present day gas

lift flow valve was the differential valve (Fig. 1-12) which was operated by the difference in pressure between the injection gas in the casing and the 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 ?-- il-"

v (A) Mechanically controlled valves

- FLOW LINE

CASING + GAS IN TUBING 4

DISK TYPE VELOCITY

(C) Velocity controlled valves

(B) Bryan differential valve

FLOW LINE

(D) Spring loaded differential valves

Fig. 1-12 - Early types offzow valves



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A P I T I T L E + V T - 6 74 D 0732290 0532842 857 W


One type of differential valve, which was very popular around 1940, is shown in Fig. 1-1 3. This valve was originally called the Specific Gravity Differential Vulve. The specific gravity differential valve employed the difference in specific gravity between a 16 foot column of kerosene and a 16 foot column of well fluid for operating pressure. It was very successful in continuous flow wells and may still be operating successfully in some wells. However, the valve’s length and excessive diameter limited its transport- ability and application.

OPERATING VALVE VALVES ABOVE OPERATING VALVE

Fig. 1-13 - Specific gravity type differential valve

Bellows Charged Valves

In 1940, W. R. King introduced his bellows charged gas lift valve. A drawing taken from King’s patent issued on January 18, 1944 is shown in Fig. 1- 14. King’s valve, which is very similar to most present day unbalanced, single- element, bellows charged gas lift valves, allowed for the first time the gas lifting of low pressure wells with 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

Bellows

Stem 8 Seat

4 Fig. 1-14 - King valve (First pressured bellows valve)

and closed by a decrease in pressure, the valve could be operated from the surface by changes in the injection gas pressure. This meant that it was no longer necessary to operate a valve from the surface by rotating or moving the tub ing o r w i re l ine connec ted t o t he su r f ace . The principal of operation of the bellows valve was also far superior to the differential valve for most applications in that the bellows valve was closed by a decrease in gas pressure, whereas the differential type valve opened with a decrease in gas pressure. This meant that fewer of the 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 differential pressure operated valves.

King had good insight into valve construction when he designed his valve. He recognized the need for complete bellows protection, including an anti chatter mechanism. The bellows in the King valve is protected from excessive well pressure by sealing the bellows chamber from the well fluids after full stem travel. Chatter is prevented by the



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A P I TITLE*VT-b 74 m 0732290 0532843 775 m

10 Gas Lift

small orifice. The baffle design also supports the bellows.

POSITIVE STOP FOR STEM

BELLOWS SECTION

GAS INLETS

STEM 8 SEAT INSERT

REVERSE CHECK

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 the design were quickly adopted by almost all valve manufacturers and are still 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 King valve shown in Fig. 1-14. Gas lift valves and mandrels are discussed in detail i n Chapter 5 of this manual.

Fig. 1-15 - Typical modern bellows charged gas lift valve



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Well Performance 11

CHA WELL PEF

'TER 2 IFORMANCE

INTRODUCTION

Well performance is controlled by a large number of factors that are often interrelated. Most students of fluid flow now divide well performance into two basic categories which they call Inflow and Outflow performance. As illustrated in Fig. 2- 1, all flow in the reservoir up to the wellbore is designated as inflow performance and all flow up the tubing and into the production facilities is designated outflow performance.

A well's inflow performance is controlled by the characteristics of the reservoir such as reservoir pressure, produc-

tivity and fluid composition. A well's outflow performance is a direct function of the size and type of producing equipment. Both inflow and outflow performance can be predicted quite accurately, and wells can be designed based on these predictions. In any given well, outflow performance and inflow performance must be equal. That is, we can produce no more fluid from the reservoir than we can lift to the surface and vice versa. Because of this fact, it is extremely important that a well's inflow performance be carefully considered when sizing production equipment.

U '"1

4

NFLOW PERFORMANCE "

"

"" I ' I I I I

Fig. 2-1 - Inflow 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 barrels of oil or liquid that a well is capable of producing at a given reservoir pressure. One way of expressing well productivity is with the Productivity Index (P.I.=J) technique. This involves measuring a well's producing rate, and flowing bottomhole pressure at that rate, then using this information 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 in the same proportion to the 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 the 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

Productivity Index (P.I.=J) Technique technique for predicting well productivity's under such reduced conditions and he called his method of analysis Inflow Performance Relationship (IPR) after the terminology 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 the 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 reservoirs in arriving at oil well productivity, but would give

91 much more accurate projections than could be obtained J = 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 IPR in all two-phase flow conditions.

where: J = Productivity index, 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 Vogel IPR Curve example.

The Vogel IPR dimensionless curve (see Fig. 2-2) is based Given: A well that produces 100 BLPD and has an SSBHP on the following equation: of 1000 psig and a FBHP of 900 psig.

Find: P.I. of the well (qohax = 1.0 - 0.2 (2)- - 0.8 (+) Equation 2.2

Solution:

90

ql 100 BLPD J = 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 static bottomhole pressure (Pws) in the

- -

The P.I. technique allows us to determine the well production 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 index equation, which is a straight ]ine IPR curve. The

q1 J = Equation 2. relationship is that the flow efficiency (FE) must be equal to P,, - P,f 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 from Rate (ql) = 500 BLPD at FBHP (Pw,) of 500 psig the drainage radius to the wellbore radius.



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API T I T L E * V T - b 7 4 m 0732270 053284b 4 T 4

Well Performance 13

PRODUCING RATE AS A FRACTION OF MAXIHUH PRODUCING RATE WITH 100% DRAWDOWN, q,/(q,) M X .

Fig. 2-2 - Vogel’s curve for inflow performance relationship (from Vogel’s papel; SPE 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 be restricted to all oil production if free gas is present with the liquid phase at the flowing bottomhole pressures in the wellbore. If a well produces free gas, and a significant flowing bottomhole drawdown below the initial bubble point pressure is required for the desired daily production 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 in flowing bottomhole pressure drawdown becomes less at the lower flowing bottomhole pressure. Gage pressures will be used in these calculations. A worksheet for performing IPR calculations is given in Fig. 2-3.

Vogel’s Example Problem

The following data for illustrating IPR calculations were used in Vogel’s paper: Given: I . Average reservoir pressure, P,, = 2000 psig

( 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 100 percent drawdown (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 presentation 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 = - - - = 0.75 Pwr - 1500 P,, 2000

From the Vogel IPR curve: Rate Ratio, q o ~ = 0.40 (90) max

The maximum daily production rate represents the maximum 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 = 0.25 P,, 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) max 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, the flowing bottomhole pressure for a production rate of 114 BOPD for the above well can be calculated as follows:

Rate Ratio = 9 0 114

(90) max 162.5 - - = 0.70 -

From the Vogel IPR curve: Pressure Ratio, = 0.50 P,,

Pwr = 0.5 (2000) = 1000 psig



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WORK SHEET FOR NONDIMENSIONAL INFLOW PERFORMANCE CURVE

WELL NO.

FROM BHP SURVEY

GIVEN: (1 ) P, = PSkI

(3) TEST RATE = ~ BFPD

1 .o0

. . . I : : - j

. . . i : ! .

. . ] . . . I : . , . . .

0.80 x = (5 ) = from this curve

0.60

II >

0.40

" : . I :

!

I , . : i . . 0.20

' I '!::

1 I

j . ,

O O 0 .20 0.40 0.60 0 . 8 0 1 .o0

I

Plot BHP(7) versus BFPD(8) for IPR Curve between BHP = O & BHP = P,, & BFPD = O & BFPD I Max. Rate (6)

Fig. 2-3 - Worksheet for performing IPR calculations



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A P I TITLEWVT-6 94 m 0732290 0532848 277 m

Well Performance 15

IPR 2,000

a r m

2 O

FRACTION OF MAXIMUM PRODUCING RATE

FRACTION O F MAXIMUM PRODUCING RATE


FRACTION OFMAXIMUM PRODUCING RATE

Fig. 2-4 - Example problem solution



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FRACTION O F M A X I M U M P R O D U C I N G R A T E F R A C T I O N OF MAXIMUM PRODUCING RATE SINCE TEST RATE AT 1500 PSlG WAS 65 BOPD

X = 162 BOPD = (qo) MAX (G)

IPR


@ ” 0.9 = ___- 0.4 @ 162 BOPD A 6 5 BOPD x 0.9

A = 146 BOPD =qo -

146 BOPD = q O

Fig. 2-5 - Continuation of example problem



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A P I TITLE*VT-b 74 m 0732270 0532850 925 m

Well Performance 17

WELL OUTFLOW PERFORMANCE PREDICTION

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 characteristics, well configuration, conduit size, wellhead back pressure, fluid velocity, and pipe roughness all contribute significantly to outflow performance.

Efforts to predict well outflow performance have been going 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 pressure at depth in a flowing vertical column of multiphase fluid (oil-gas, oil-water-gas, or water-gas) taking into 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 equally well in either system. The development and use of multiphase flow correlations for outflow performance predictions are discussed 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 computer calculations have been plotted into generalized pressure 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 curves calculated for several different well rates, the flowing bottomhole pressure Pwf can be read at a given depth for a specific rate and gas to liquid ratio (Rg]). Separate curves must be used for 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 demonstrates the use of these curves to predict outflow performance 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’/~ inch O.D. 1970 psig @ 5800 ft.

230 psig 1500 psig @ 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 to obtain or calculate a suite of vertical two-phase flowing pressure gradient curves for the conduit sizes to be examined based on producing conditions to be expected. Computer programs available from several sources make the calculation and plotting of such curves both fast and inexpensive. 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 somewhat equal distribution of points along the entire length of the curve.

A page of gradient curves calculated for this particular well and representing the 3000 BOPD rate is 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 flow conditions (800 R,, for 100% 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 this fashion until sufficient points are obtained to represent a full range of producing rates.

The pressure readings are now tabulated 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 the horizontal (X) axis. Fig. 2-7 is a plot of these values and the resulting curves represent the minimum flowing pressure at the formation depth that will be required to overcome gravity, friction, surface pressure and other effects, and produce at the rates indicated.

~



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18 Gas Lift

I

TYPICAL GRADIENT CURVES FOR 3000 B/D RATE

(COURTESY EXXON PRODUCTION RESEARCH CO.)

1 I 4 1 I

TYPICAL GRADIENT CURVES FOR 4000 BID RATE

(COURTESY EXXON PRODUCTION RESEARCH CO.)

Fig. 2-6 - Gradient curves

TABLE 2-1 TABULATION OF POINTS FROM GRADIENT CURVE FOR NATURAL FLOW

7" x 27/8" Annulus - Natural Flow - Rgl as Indicated FBHP @ 5800 ft, psig

100% Oil 25% Wtr 50% Wtr 75% Wtr

Rate, BPD (R,I = 800) (Rgl = 600) (Rgl = 400) (R,[ = 200) 2,000 990 1260 1655 2240 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

1 O00 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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Well Performance 19

4. On the same sheet of graph paper, plot the well productivity line based on either the straight line productivity index or the IPR technique by beginning at a point representing the 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 productivity line by reducing the flowing bottomhole pressure by the amount of drawdown calculated for various 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 productivity 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 in 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

2 SO(

200(

t O O ao v)

@ 0 -

Im $ 1501 g= 5 9 Y

1001

50(

I I l l I I

7” x 2-7 /8” ANNULUS

,SBHP 1970 PSIG

\-Pl = 5.0 BFPD/PSI I I l I I I

2000 4000 6000 8000 10,000 12,00014,

PRODUCING RATE (BFPDI

well when it reaches a water cut somewhere between Fig. 2-7 - Flowing BHP V S . Producing rate for natural 25% and 50%. flow conditions, various water cuts

PREDICTING THE EFFECT OF GAS LIFT

The effect of injecting additional gas into a fluid column from an outside source for gas lift purposes can be determined 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 the total gas liquid 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 line at each producing rate can be used. In the example problem, that is a R,, of 3000 at the 3000 B/D rate. Since this minimum gradient will represent different R,~values at different rates, the calculation of injection gas requirement will depend on the minimum gradient for the rate being considered. Table 2-2 shows a tabulation of the minimum downhole pressure readings at the various rates.

2. Plot the pressures versus rates tabulated in Table 2-2 on Cartesian Coordinate paper in the same manner as in the example for natural flow. Fig. 2-8 shows a curve

plotted for the maximum gas injection rate alongside the curve plotted for natural flow (800 Rgl) for the 100% oil case. A dotted line is also shown on Fig. 2-8 to indicate the 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 by the intersection of the productivity line with the flowing pressure versus rate curves. In this case the 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 conditions of 5000 B/D. A comparison of maximum producing rates possible under both gas lift and natural flow conditions is shown in Table 2-3.

4. Using the above example, it is now possible to evaluate the benefits accruing to gas lift under the given conditions. Also, it is possible to determine the optimum 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 LIFT

7" x 27/8" Annulus - Maximum Gas Lift - R,, Values FBHP @ 5800 ft, psig

Rate, B/D 100% Oil 25% Wtr 50% Wtr 75% Wtr

2,000 690 740 8 O0 1400 2,500 680 740 8 O0 1440 3,000 680 750 815 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 L

G O O ao v)

@J \ NOTE: THIS REPRESENTS MAXIMUA AND NOT OPTIMUM GAS LIFT CONDITIONS

O = I z 3 S Y

1000 5450 B/D

1 5 I';",GAS :EO = , .

'O0 2000 4000 6000 0000 10,000 12,00011

3920 MU/@

P.1 = 5.0 BFPD/PSI

PRODUCING RATE (BFPD)

O

Fig. 2-8 - Comparison of naturalflow with gas lift, 100% oil, no injection gas limit

2500$

l 7" X 2-7/8 ANNULUS

c

\ NOTE: THIS REPRESENTS

\ OPTIMUM CONDITIONS MAXIMUM AND NOT

o- z $ 1500- o = E 3 S Y

1000 -

GAS REO = 4770 MCF/

\PI = 5.0 BFPD/PSI

'O0 - 2d00 4dOO 6d00 8dOO l0,bOO 12,bOOl


100

Fig. 2-9 - Comparison of naturalflow with gas lift, 25% water, no injection gas limit



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API TITLEtVT-b 7Y m 0732290 0532854 5 7 0 m Well Performance 21

(5450 B/D) under the limited gas injection rate of 2180 MCF/Day to the oil produced (5600 B/D) at a maximum 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 MAXIMUM

PRODUCING 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 50 -0- 5000 5500 75 -0- 2600 3380

2500r"--- 7- x 2-718 ANNULUS

NOTE: THIS

OPTIMUM GA5 LIFT t MAXIMUM AND NOT

(o CONDITIONS O O

v)

@J

m v) 1500

f 3 LL \ MAX RATE

1°00- -Y ,MAX RATE -

5000 B/D MAX GAS REQ = 5500 MCF

PI = 5.0 BFPD/PSI

500 2000 4000 6000 Bob0 l0,dOO 12,~0014,000 PRODUCING RATE (BFPD)


c Y O O (o v)

GAS LIFT (MAX RATE)

@J n- $:150/ 7 MAX RATE

2600 B/D z MAX GAS REO = 3380 M U D

3 Y

loo0 t \ NOTE: THIS REPRESENTS

\ MAXIMUM \

AND NOT OPTIMUM Pl = 5.0 BFPD/PSI CONDITIONS

500' 20b0 4000 d o 0 W O O 10,dOO 12,bOOl ~~

100



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 the various pipe sizes under 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 / ~ inch 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 determined by replotting the productivity line for the new productivity 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 a variety of possible surface operating pressures and a comparison made of the producing rates under each condition. Such comparisons are useful in determining the production to be gained from reducing pressure losses in production facilities. They may also be used for determining the optimum design operating pressure at the wellhead.



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22 Gas Lift

Use of Inflow Performance Relationship Curves (IPR)

Although the example problem uses the straight line P.I. technique for predicting inflow performance, IPR curves can also be used for determining the point of intersection,

2500 - " I I l I l I

2-7/8' TUBING

NATURAL FLOW M A X FLOW RATES %H20 BFPD

25 O

2400 2500

5 0 2100 75 500

H PI = 5.0 BFPD/PSI

l e 3

500' 2dOO 40b0 60b0 d o 0 l0 ,AOO 12,bOOI


Fig. 2 -12 - Natural flow, 2'h -inch 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 inflow performance (productivity) with the vertical flow characteristics of the production installation to determine the maximum production rates that are possible under various producing conditions. These programs are usually 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 the parameters on well performance. Many of the computer programs will also plot the information in a graphic form similar to that shown in Fig. 2-14. This demonstrates 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 of a large number of such curves comparing various producing parameters in a very short period of time.

O 0

I L I I I 1 I I 1 I 100 Mo 300 400 500 600 700 Boo

PRODUCTION RATE (BBL./DAYI

Fig. 2-13 - Curve number (1) is an IPR curve and curve number (2) indicates the calculatedpe$ormance characteristics of the outflow system

G A S L I F T PERFORMANCE

YELL ORTA lU6ULRR FLOU 2 716 IN . YRTERCUT - 90 f FWHP = YO0 PSIG SC IWJ CRS = 0.90

""""""""4

cas INJ. PnEssunes

Fig. 2-14 - Computer plots of gas lift well performance



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Multiphase Flow Prediction 23

CHAPTER 3 MULTIPHASE FLOW PREDICTION

INTRODUCTION

There are several words and terms in this chapter which may 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 discussion of the more unique terminology should aid the reader.

Dimensionless Parameters

Most multiphase flow correlations involve numerous dimensionless groups or parameters. Dimensionless groups are commonly used in the analysis of experimental data because the number of measured or assumed values for variables can be greatly reduced by combining several variables 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 unit system. Reynolds number is an 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 the value of a variable or parameter associated with multiphase flow. The value must be established empirically by actual measurements. Generally, interpolation of empirical data will present no problem but extrapolation can be quite dangerous. Interpolation means the determination of values between measured data, whereas extrapolation refers to predicting values beyond the range of the measured data. For example, the investigator does all of the experimental work in l'/d-inch nominal tubing. A general computer program is developed based on these test data for 1'/4- inch nominal tubing and extended to high rates through 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 identified by the investigator or investigators. A typical multiphase flow correlation consists of numerous equations and curves defining the relationships between different independent dimensionless groups, which may be called correlating parameters. These relationships represent 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 production conduit size and the fluid rates and properties. Production conduit is a general term which can mean tubing or tubing-casing annulus, depending upon which is the production string. Most wells are produced through a tubing string.

Basis for Developing Multiphase Flow Correlations

Several of the earlier multiphase flow correlations were based on a total energy loss factor or a no-slip homogeneous mixture for high rate production. The total energy loss factor is analogous to a single-phase friction factor. No-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 the liquid and the gas is based on the daily production rate with no accumulation of liquid in the production conduit. These simplified methods for calculating multiphase flow pressure loss, with a total energy loss factor or a no-slip homogeneous mixture and friction factor, do not require the establishment of the flow regime or pattern. The flow regime for multiphase flow must be determined before the pressure loss can be calculated for the more general type of correlation. Each flow regime has a different set of equations and correlating parameters for calculating a pressure loss. If the flow regime cannot be accurately determined, the calculated pressure loss will be in error and discontinui- ties in the slope of the flowing pressure gradient curves may be apparent.

Multiphase flow in a production conduit represents complex relationships between many variables and dimensionless groups. For the purpose of this discussion, multiphase 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 today that is universally accepted by the petroleum industry for accurately predicting flowing pressure gradients in all sizes of production conduits for the ranges of gas and liquid rates encountered in oil field operation. There is a continuing effort to develop new correlations and to improve those that exist.

Accuracy of Flowing Pressure at Depth Predictions

Accurate flowing pressure at depth predictions in production 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 depth surveys with calibrated instruments and accurate stabilized production data measured during the surveys are



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24 Gas Lift

essential to verify the applicability of a multiphase flow correlation. In other words, the only way to properly evaluate a multiphase flow correlation or set of flowing pressure at depth gradient curves is to compare reliable well 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 gas measurement. The importance of selecting the recommended orifice beta ratios for accurate gas measurement cannot 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 differential pen reading for a given volumetric gas rate. The proper equations for multiphase flow calculations depend upon a correct prediction of the flow regime for the general type of multiphase flow correlations. There are required well and tubular conditions before accurate flowing- pressure-at-depth predictions can be anticipated. The multiphase flow correlations in this discussion are not applicable when an emulsion exists. The production conduit must be full open: i.e., the area open to flow cannot be 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 been rejected based on reportedly reliable well test data after the calculated flowing pressures at depth did not approximate the measured pressures at depth. Further investigation of the reported 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 the production conduit. Field personnel may report the average 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 production test measurements during the survey.

Flowing pressure gradient curves and computer calculated 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 accurate than the “so called” field measurements. An operator should always double-check the field data before condemn- ing a widely proven multiphase flow correlation.

PUBLISHED VERTICAL, HORIZONTAL AND INCLINED MULTIPHASE FLOW CORRELATIONS

This discussion is not intended to replace a text book on multiphase flow. Only the multiphase flow correlations that have received at least limited acceptance by the petroleum industry are mentioned in this chapter. These vertical multiphase flow correlations are the Poettmann and Car- penter3, Baxendell and Thomas4, Duns and RosJ, Johnson6, Hagedorn and Brown7, Orkiszewski*, and Moreland9. The number of detailed investigations of horizontal and inclined multiphase flow are less numerous in the litera- ture. The more widely applied correlations include Bakerlo, Lockhart and Martinelli”, Flanigan12, Eaton13, Dukler, et ali4, and Beggs and Brilll5. The Beggs and Brill correlation for inclined flow may be used for vertical flow calculations by assigning a 90 degree angle of inclination. The reported data base, application and possible limitations are not always available for all multiphase correlations. Generally, internal company improvements and modifica- tions in multiphase flow correlations and computer programs are not public knowledge. Only published information can be used to describe the various multiphase flow correlations.

Papers Evaluating the Accuracy of Multiphase Flow Correlations

There are technical papers I h , 17* lx* that reportedly evaluate the accuracy of several widely used correlations for vertical multiphase flow. Generally, authors of these papers use published data from several sources. These may include flowing pressures at depth and production data from original publications for multiphase flow correlations being compared. A statistical error analysis is performed on the difference between the published measured pressure loss and the calculated pressure loss using computer programs 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 test for all multiphase flow correlations does not always apply. A significant portion of the data may be out of the recognized production rate or production conduit size ranges, noted by the investigators, to be applicable to their multiphase flow correlations. An example is the use of low production rate data to check the Baxendell and Thomas correlations.



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A P I TITLErVT-b '74 m 0732270 0532858 116 m Multiphase Flow Prediction 25

The Baxendell and Thomas correlation is a high rate extension of the Poettmann and Carpenter total energy loss factor curve. All low rate data would be on the Poettmann and Carpenter portion of the curve and not on the extension by Baxendell and Thomas. Another consideration is the manner in which a computer program is written and the correlations that are being used to calculate the fluid properties. The results from two computer programs based on the same multiphase flow correlation can be quite different.

Ros-Gray and Duns-Ros Correlations

Ros Correlation is being compared. The initial paper, which was based on an extensive laboratory investigation by Ros2' was presented at a Joint AIChE-SPE Symposium and a revised version of the same paper was published in the Journal of Petroleum Technology". The final version of the Ros paper was presented by Duns5. The Duns and Ros paper is based on laboratory data only and is not the Ros-Gray correlation that was modified to eliminate dis- crepancies between calculated and accurately measured data from over 600 actual stabilized well tests. The conclusion remains that one particular multiphase flow correlation may prove to be more 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 from Shell Oil Company, is being com- the available correlations in terms of general overall appli- pared to other correlations when in fact the Duns and cability is questionable.

SIMPLIFIED MULTIPHASE FLOW CORRELATIONS BASED ON TOTAL ENERGY LOSS FACTORS OR MO-SLIP HOMOGENEOUS MIXTURES

A simplified multiphase flow correlation based on a total single energy loss factor curve or a simple homogeneous no-slip flow model should be considered for calculating flowing pressures at depth in areas of high rate production when the correlation is based on accurate stabilized flowing well data from the same field or similar well production rates and conduit sizes. The calculations for this type correlation are simple and are reportedz2. 23 to be more accurate in many instances than the more complex general type of correlations.

Poettmann and Carpenter Correlation

The first widely accepted multiphase flow correlation was developed by Poettmann and Carpenter and was published in 1952. The work of Poettmann and Carpenter did more to initiate additional research in vertical multiphase flow than all prior publications combined. Their correlation was based on a total single energy loss factor that accounts for all losses including liquid holdup from gas slippage and for friction and acceleration. The energy balance equation combined a pseudo no-slip homogeneous mixture density gradient and the Fanning equation for single-phase flow where the friction factor was replaced by the total energy loss factor.

Baxendell and Thomas Correlation

Baxendell and Thomas modified the Poettmann and Carpenter correlation using measured data from high rate wells in Venezuela. The total energy loss factor curve was extended for daily mass rates which were significantly higher than the original Poettmann and Carpenter data. The energy loss factor for vertical and horizontal multiphase flow approached a near constant value at very high daily mass rates in a manner analogous to high Reynolds

numbers for fully turbulent single-phase flow on a Moody diagram. The authors assumed that the flattened portion of the energy loss factor curve represents the truly turbulent conditions where little or no gas slippage occurs. The calculated flowing pressures at depth for high rates based on the extended total energy loss curve proved to be exceedingly accurate for wells in Venezuela. Since extension of the energy loss curve was based on well data from the same fields in which the correlation was being used, reasonable accuracy in flowing pressure at depth predictions could be anticipated. The number of variables which affect these pressure predictions are reduced because the fluid properties and conduit sizes are the same for the correlation and the actual wells. The original Poettmann and Carpenter total energy loss factor curve and the extension by Baxen- dell and Thomas is shown in Fig. 3-1.

O I 2 S 4 & 6 7 4

ou x 10-4 O

Fig. 3-1 - Extension of the energy loss factor curve by Baxendell and Thomas4 (Copyright 1961, SPE-AIME, First published in the JPT 1961)



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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 illustrate the application of two-phase homogeneous no-slip correlations for high rate wells. Brown22 notes that a simplified correlation developed from multiphase flow data for an actual production conduit size may assure more accurate pressure loss calculations than the more compli- cated general type of correlation based on laboratory controlled multiphase flow data for conduit sizes which are

generally smaller and shorter than the actual conduits. The importance of properly defined fluid property relationships for calculating flowing pressure gradients was demon- strated by Cornishz3. The advantages and accuracy of a simplified 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 are easily calculated from flowing pressure surveys, and an energy loss factor curve can be shifted to improve the accuracy of the calculated flowing pressures at depth.

GENERAL TYPE MULTIPHASE FLOW CORRELATIONS

A general type of multiphase flow correlation is reportedly applicable for all sizes of typical oil field production conduits and for the liquid and gas rates encountered in oil field operations. The general correlation requires an identification of the flow regime, or flow pattern, to define the proper equations for calculating the flowing pressure gradient in the incremental pipe length under investigation. There may be more than one flow pattern existing between 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 illustrates the need for proper flow regime identification. The pressure gradient equation for at least one flow regime will include liquid holdup based on gas slippage. Liquid holdup represents the relationship between the volume occupied by the liquid and the total volume of the production conduit within the incremental pipe length under investigation. The accuracy of the method for predicting liquid holdup is particularly important for the gas and liquid velocities associated with the lower production rates. Liquid and gas viscosity's and surface tension are usually required input or are default values in the computer programs for the general types of multiphase flow correlations. Accurate pressures at depth predictions are claimed by the developers of most general correlations for even relatively high viscosity crude oil.

Typical Pressure Gradient Equation for Vertical Flow

Although the exact final equations and correlating parameters vary between investigators, the basic typical pressure gradient equation for vertical multiphase flow consists of the following terms:

Equation 3.1 Pressure Gradient - Density Friction Acceleration

Term Term Term Term - + +

The density term includes a liquid holdup correction for gas slippage. The acceleration term is often neglected in all flow regimes except where high fluid velocities exists such as

ANNULAR MIST

FROTH

SLUG

BUBBLE

SINGLE PHASE LlOUlO

Fig. 3-2 - Typical flow patterns for vertical flow of gas- liquid mixtures9



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API TITLErVT-6 74 m 0732270 0532860 8 7 4 W


in the annular mist regime. The contribution of acceleration is reported to be very small in the other multiphase flow regimes.

The flow regime, or flow pattern, map generally is 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 the published Ros flow regime map based on laboratory data. The liquid phase is continuous in Region I; and gas is the continuous phase in Region III. The pressure gradient in the transition area between Regions II and III can be approximated by linear interpolation on the basis of the gas velocity number (RN) value on the abscissa, where R is the ratio of the in-situ superficial velocity of the gas to liquid phases. The flow regime must be established before the proper equations and correlations can be selected for the flowing pressure gradient calculations. The Ros flow regime boundary equations have been used by other investigators.

Y

Gas Veloclty Number R N

Fig. 3-3 - Rosflow region boundaries based on laboratory data’

Published General Type Correlations

The multiphase correlations developed by Ros, Orkis- zewski, Aziz, et. al, are considered general. The original paper by Hagedorn and Brown’ stated that it was unnecessary to separate two-phase flow into the various flow patterns and develop correlations for each pattern. Many computer programs based on the Hagedorn and Brown correlation include separate sets of equations for the different flow regimes and use the Hagedorn and Brown correlations 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 that slug flow occurred in 95 percent of the cases studied. Apparently, Hagedorn did not encounter the bubble flow regime during his experimental work because his tests were conducted in a shallow 1500- foot well. The accepted categories or flow regimes for two- phase flow are ideally depicted by Orkiszewski in Fig. 3-4.

(AI I RI

. . L I . . . :. . .

v .

BUBBLEFLOW \-,

SLUG FLOW SLUG-ANNULAR ANNULAR-MIST \ - /

TRANSITION FLOW

Fig. 3-4 -Ideal flow regimes or categories for multiphase flow as illustrated by OrkiszewskP (Copyright 1967 SPE- AIME, First published in the JPT June 1967)

DISPLAYS OF FLOWING PRESSURE AT DEPTH GRADIENT CURVES

Most displays of flowing pressure at depth gradient curves use the same parameters but may be plotted somewhat differently. Generally, a set of gradient curves will be displayed for a given conduit size, a production rate, and 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 the 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 of 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 Rgl values are associated with lower production rates and lower R,I values with higher production rates.

Converting RgO to Rg,

This family, or set, of curves should always be defined in terms of R,I and not gas-oil ratio (Rgo). The Rgo is equal to the R,] only when the water cut is zero. The first step after selecting the proper set of gradient curves is to convert the



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28

%PI TITLExVT-b 94 m 0732290 0532863 700 m

Gas Lift

total Rgo to total Rgl before determining a flowing pressure at depth.

R g l = fo (Rgo) Equation 3.2 Where:

R,I = gas-liquid ratio, scf/STB f,, = oil cut (1 .O - water cut), fraction Rgo = gas-oil ratio, scf/STB

These 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 the point of gas injection.

Gilbert’s Curves

Gilbert1 published one of the first sets of flowing pressure at depth gradient curves in 1954. Although flowing pressure gradient curves for several conduit sizes were published by Gilbert, the only full-page size curves presented in the API paper were for 27/~-inch O.D. tubing. No multiphase flow correlation was offered for calculating these flowing pressures 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 the fore- runners for the present method of displaying gradient curves. One set of Gilbert gradient curves for 600 barrels per day through 27/8-in~h O.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 represents the minimum possible flowing pressure at depth for a given conduit size and production 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 flowing 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 than shifting the origin of the depth scale to prevent overlaying and crossing over of R,] curves at low flowing pressures at depth. A reversal in the slope of a high R,I curve will result in the higher R,I curves crossing over the low R,I curves at low flowing pressures. An example of overlaying of gradient curves24 is illustrated in Fig. 3-6. and accurate pressure determinations are difficult and confusing at the lower flowing pressures where the curves are crossing over one another.

The minimum fluid gradient curve ignores the reversals in the individual R,I curves and represents a flowing

pressure gradient curve defined by the 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 of tangency for the higher R,, curves increases which infers that these points of tangency occur at increasing chart depths. A set of 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 will be one and the same above the point of tangency. Gradient curves displayed with a minimum fluid gradient curve are easier to apply for certain design determinations. The design calculations may lose some accuracy if gas lift operations should occur in the reversal portion of a high R,] curve. However, most efficient gas lift installations will operate with a total R,I below the range of a severe reversal in the flowing pressure gradient curve and the actual flowing wellhead pressure will exceed the lower pressures where a severe reversal would occur. Gas lift installation designs and analyses have been based on gradient curve displays with a minimum fluid gradient curve without any reported significant error in predictions of flowing pressures at depth or injection gas requirements.

Gradient pressure, psi

Fig. 3-5 - Gilbert’s flowing pressure gradient curves for 600 BPD 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 2.441 IN. I.D.

PRODUCTION RATE 1500 BLPD Q A 8 SPECIFIC GRAVITY 0.65

AVERAQE FLOWINQ TEMP. 150 O F

OIL GRAVITY 36.0 O API WATER SPECIFIC QRAVITY 1 .O7

Fig. 3-6 - Vertical flowing pressure gradient curves without depth displacement to eliminate overlapping 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 I VERTICAL FLOWING PRESSURE GRADIENTS

(ALL a u

2

3

4

Tubing Size 2 in. 1.D. 1 Producing Rate 600 Bblr/Day Oil API Gravity 35" APt I

Gas Specific Gravity 0.65

8

Fig. 3- 7 - Vertical flowing pressure gradient curves plotted with a minimum fluid gradient curvez5



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O 5 10 1 5 20 2 5 30

10

Fig. 3-8 - Vertical flowing pressure gradient curves based on the Shell Ros-Gray correlation with the higher Rg, curves displaced on the depth scale to prevent gradient reversal 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 display of gradient curves will include Ros-Gray curvesh are shown in Fig. 3-8. Flowing pres-

the reversal in 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 the depth scale to prevent the next higher Rgl curve minimum fluid gradient curve.

STABILITY OF FLOW CONDITIONS AND SELECTION OF PRODUCTION CONDUIT SIZE

Multiphase flow correlations are developed based on Graphical Determination of Minimum Stabilized stabilized flowing well data. A correlation can be extended Production Rate beyond its range of validity without the 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 predicted from the curves. Fig. 3-9. A minimum flowing bottomhole pressure 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 1 1 2 1 3 1 4 1 5

Daily Production Rate - 100 STB/day

Well Information: 1. Tubing Size = 2%-inch O.D. 2. Tubing Length = 6000 ft 3. Water Cut (fo) = 0% (All Oil) 4. Formation Rg, = 400 scf/STB 5. Flowing Wellhead Pressure (Pwh) = 100 psig

Fig. 3-9 - Flowing BHP versus daily production rate for a constant gas-oil ratio



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A P I TITLE*VT-b Y Y m 0732290 0532866 292 m


approximately 860 psig at 6000 feet occurs at a daily production rate slightly greater than 500 STB day. The flowing bottomhole pressure increases at lower and higher daily liquid production rates. The unstable flow conditions exist at daily liquid rates less than the rate for the minimum flowing bottomhole pressure. The unstable range should be avoided by producing at a daily rate that is safely above the 500 STB day in this example to assure not slipping into the unstable region. A cyclic heading or surging condition develops as the daily production falls below the liquid rate for this minimum flowing bottomhole pressure. The cyclic conditions are perpetuated and intensified by the fluid flow principles defining a vertical or inclined multiphase flow system and the intlow performance relationship defining the deliverability of a reservoir. As the liquid rate decreases, the flowing bottomhole pressure increases which in turn results in a further decrease in liquid rate. Most wells will reach a severe surging condition 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 for the conditions necessary to assure stable multiphase flow can be related to a minimum free volumetric gas rate requirement for a given production conduit size. The in-situ gas velocity must exceed a minimum value that prevents excessive gas slippage and corre- spondingly high liquid holdup which causes a well to load up and die. Since there is this minimum gas rate requirement, the 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 comparison of injection gas-liquid ratios is not recommended for evaluating the gas lift operations in wells that have a wide range in daily production rate. Also, a minimum gas velocity necessary to prevent excessive liquid holdup explains why stable flowing conditions can be established in smaller conduit sizes for low rate wells. The gas velocity increases as the production conduit size decreases for the same daily

O 1 2 3 4 5 6 7 8 9 10

Daily Production Rate - 100 STB/day

Well Information: 1. Tubing Length = 6000 feet 2. Formation Rg, = 400 scf/STB (All Oil) 3. Flowing Wellhead Pressure = 100 psig

Fig. 3-10 - Flowing B H P versus daily production rate for three different tubing sizes of the sume length und a con- stunt gus-oil ratio



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34 Gas Lift

volumetric gas rate. In 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 Stabilized Flow 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 pressure can be attained for the same daily production with a smaller

conduit size. For example, the predicted flowing bottomhole pressure is approximately 1360 psig at 6000 feet for 1 O0 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, the predicted flowing bottomhole pressure would decrease to approximately 1000 psig for the same daily production rate of 100 STB day. The intake flowing bottomhole pressure versus daily production rate for three commonly used tubing sizes is illustrated in Fig. 3-10. Accurate gradient curves can be used to select the proper conduit size for a well based on the desired daily production rate.

CONCLUSIONS

The ability to predict accurate multiphase flowing pressures at depth in a vertical production conduit has improved significantly since the work of Poettmann and Carpenter in 1952. Research in multiphase flow continues with increased emphasis i n gathering systems including flowlines and inclined flow. The number of wells having deviated production 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 inclined flow will be more complex by requiring profiles of production conduit length versus angle of deviation.

Many companies have their own in-house multiphase

flow computer programs. These programs should be utilized 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 lift installations. The widely used multiphase flow correlations in these computer programs have been verified by actual field measurement to be reasonably accurate when reliable well data are used for input. In conclusion, the advent of multiphase flow correlations which are applicable to the conduit sizes and the daily production rates associated with gas lift operations has changed the design and analysis of continuous flow gas lift wells from an art based on experience to a predictable science.



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Gas Application and Gas Facilities for Gas Lift 35

CHAPTER 4 GAS 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 usually 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 controlled, measured, compressed, and processed with mechanical devices. Therefore, an understanding of gas fundamentals and operating practices is necessary to the successful operation of a gas lift system. Operating practices involving gas are different from those for oil because of the increased pressure and compressibility of the mixtures involved. Also, as a gas that contains even small quantities 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 gas like nitrogen and a mixture of components such as natural gas will be- have differently.

Injection gas for gas lift wells can be affected by various operating and producing conditions including gas supply and production system back pressure. Production conditions such as surface wellhead back pressure and surface temperature are usually estimated in gas lift design and planning because actual measurements will not be available. Gas lift valves downhole will respond to injection gas pressure and production pressure in the wellbore as well as pressure and temperature inside the bellows of the gas lift valve. These conditions must be accurately predicted.

BASIC FUNDAMENTALS OF GAS BEHAVIOR

The pressure of a liquid or gas system can be measured. A pressure gage is the device that is commonly used to measure the pressure of the liquid/gas mixture produced from the 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. In the United 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 between 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 in more than one type of application. In the first type of application the gas can expand. 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 gas behavior differs. The sealed container is a system in which pressure, temperature, and volume are related.

In the sealed container, or bellows, a temperature increase 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 "

TI Tz

In gas lift calculations this equation could be used to determine the change that takes place in the nitrogen pressure in the bellows when a gas lift valve is set in a test rack 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 ("F plus 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 record of the flowing temperature of the'gas through an orifice meter. The gas flow equation is adjusted for the flowing temperature of the gas and corrected to a standard temperature of 60°F. In the calculations shown here, the temperature in degrees Fahrenheit (F) is converted to degrees Rankine (R).



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36 Gas Lift

In this example, the valve bellows pressure in the test rack Deviation factors can be obtained for nitrogen from at 60°F is calculated SO 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 pressure of 1000 psig when it is operating downhole Deviation is a function of the pressure and temperature and, at 150°F. for natural gases, it is also a function of gas specific gravity

(gas specific gravity is based on composition). These com- PI PZ (1000 psig + 15 psi) P? pressibility factors (deviation factors) account for the non- - ~- - or - ideal behavior of gas and improve the accuracy of T I T?

- (150°F + 460) (600F + 460"F) calculations for oil field systems.

or (1015 psia) - - PZ (6 1 O'R) (520"R)

then P? = 865 psia

This is the absolute pressure with ideal behavior. The atmospheric pressure is approximately 15 psi, therefore, the gage pressure is 850 psig.

This example does not take into account the deviation from ideal behavior. A compressibility factor (Z) is used to denote deviation from ideal conditions.

The deviation or compressibility factor (Z) appears in the following equation:

P1 VI P2 V? ~- - Equation 4.2 ZI TI Z? T?

The volume (V) is now included in the pressure, temperature, and deviation relationship. In the example in which bellows is considered a sealed container that changes very little in size VI is equal to VZ and so volume is eliminated from the equation. The Z factor remains, in order to improve the accuracy of the results. To apply the Z factor, the type of gas must be identified because the Z factor for methane is different from the Z factor for nitrogen, which is also different from the Z factor for a natural gas mixture of many components.

So the Z factor is related to the particular gas vapor. Charts are available that list deviation (Z) factors for nitrogen and for natural gas mixtures denoted by some property (usually specific gravity). These charts and tables are not valid if significant quantities of impurities are present in the natural gas mixture. Special charts are needed for those conditions.

It becomes very apparent that the accuracy of the calculation depends on having reliable information for pressure, temperature, and Z factors. The user should be careful to ensure that the table or chart being used represents the actual gas stream being considered.

The previous example is modified as follows:

The gas is nitrogen. At condition 1:

PI = 1015 psia (1000 psig + 15 psi)

T I 150°F

FromFig. 4-1, ZI = 1.013

At condition 2:

P? = unknown (but assume 865 psia)

Tz = 60°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 = 847 psia (Use this PZ to es t imate another Z2

- -

and repeat calculation)

If similar calculations are made with natural gas, Fig. 4-2 and 4-3 are available for estimating the Z Factor. For example, assume the gas specific gravity is 0.7 at condition 1:

PI = 1015 psia (1000 psig)

T I = 150°F

From Fig. 4-3, (use the above data), ZI = 0.885

At condition 2, T? = 60°F. P2 is unknown, but an assumed pressure is needed to estimate ZZ. Assume PZ = 850 psia (835 psig), then Z2 = 0.8 1.

Now apply equation 4.2,

1015 psia - P2 - (0.885) x (610"R) (0.81) x (520"R)

PZ = 792 ps ia (use th i s PZ to es t imate another ZZ and repeat)

Note: Nitrogen (N?) is used in the gas lift valve bellows because N2 behavior is well known. N2 is non-toxic and it is readily available.



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N

PRESSURE, PSlA Fig. 4-1 - Compressibility factors for Nitrogen, Bureau of Mines Monograph 10 Volume 2, “Phase Relations of Gas-Condensate Fluids”



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38 Gas Lift

1 PROBLEM EXAMPLE:

GIVEN: Tavo = 100°F

Fig. 4-2 - Z-Chart (100 - 300 psi) Courtesy Exxon Production Research Company

Fig. 4-3 - Z-Chart (300 - 2000 psi) data from CNGA Bu1 T5-461 and Standing-Katz AIME Transactions 1942



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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 liquid in the reservoir at high pressure and temperature and change to the gas phase inside the wellbore as it moves toward the surface.

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 composition. Various correlations are available for estimating the changes in the properties of crude oils as the pressure and temperature of the production system change. These correlations 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 design and sizing of surface compressors and dehydration facilities. Millions of dollars are spent to design, install, 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 in the laboratory 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 gas sample is used. Often multiple gas samples are taken for chromatograph composition analyses and used for compressor sizing and design. These composition values are 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 reciprocating compressor is also dependent upon this gas composition but is not as sensitive to changes.

Subsurface Applications

Techniques for estimating gas behavior may be applied to subsurface applications in computing injection gas pressure 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 calculations. Computers are often used, producing a data graph for estimates.

Pressure Correction The dome, or bellows, in the gas lift valve is used to

provide a controlled closing pressure so that the gas lift

~~

valve operates much like a back pressure valve on a separator. The closing force in the valve is provided by the nitrogen 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 pressure, downhole fluid pressure, and downhole temperature are used to calculate the bellows pressure needed for the closing force. As previously discussed, this nitrogen pressure 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 temperature correction is 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 upon this 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-known compressibility factors and is safe to handle.

Most manufacturers cool the gas lift valves to 60°F in a cooler and thus have a consistent and repeatable temperature at which to set the nitrogen pressure in the bellows: however, the gas lift valve in the well will not be operating at 60“. It will be at some higher temperature and the downhole bellows pressure (Pbdt) at temperature must be converted to a bellows pressure (Ph”) at 60°F. One correcting method is to use Table 4-1 by H. W. Winkler and the following relationship:

p h v = CT x Phdt Equation 4.3

Where: Pbv = Bellows Pressure (psig) @ 60°F

CT = Temperature Correction Factor, for a downhole temperature at valve (from Table 4-1)

PM = Bellows Pressure (psîg) @ Downhole Temperature (from valve mechanics calculation)

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 slowly bleed- ing the nitrogen from the bellows until the test rack opening pressure just barely opens the valve.



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TABLE 4-1 TEMPERATURE CORRECTION FACTORS FOR

NITROGEN BASED ON 60°F

Pbv = 1000 psig "F Ct "F CI "F Cl "F Cl "F Cl "F C,

61 62 63 64 65

66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85

86 87 88 89 90 91 92 93 94 95

96 97 98 99

1 O0

,998 ,996 ,993 .99 1 ,989

,987 .985 .982 ,980 .978

.976

.974

.972

.970

.968 ,965 .963 .96 1 .959 ,957

.955

.953

.95 1

.949

.947

.945

.943

.94 1

.939

.937 ,935 .933 .93 1 .929 .927

.925

.924

.922 ,920 .9 18

101 102 103 104 105

106 107 108 109 110

111 112 113 114 115 116 117 118 119 120 121 122 123 124 125 126 I27 128 129 130 131 132 133 134 135

136 137 138 139 140

.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

141 142 143 144 145

146 147 148 149 150

151 152 153 154 155 156 157 158 159 160 161 162 163 164 165 166 167 168 169 170 171 172 173 174 175

176 177 178 179 180

.847

.845

.843

.842

.840

.839

.837

.836

.834

.832

.831

.829 ,828 .X26 ,825 .823 .822 .820 .819 .817

,816 ,814 ,813 .81 1 .a10

.808

.807

.805

.804

.803

.801 ,800 .798 .797 .795

.794

.793

.79 1

.790 ,788

181 182 183 184 185

186 187 188 189 190

191 192 193 194 195 196 197 198 199 200

20 1 202 203 204 205 206 207 208 209 210 21 1 212 213 214 215 216 217 218 219 220

,787 ,786 ,784 ,783 .781

.780

.779

.777

.776

.775

,773 .772 .77 1 .769 .768 .767 ,765 .764 ,763 .76 1

.760

.759

.758

.756

.755

,754 .753 .75 1 .750 .749 ,747 ,746 .745 .744 .743

.74 1

.740

.739

.738 ,736

22 1 222 223 224 225

226 227 228 229 230

23 1 232 233 234 235 236 237 238 239 240 24 1 242 243 244 245

246 247 248 249 250 25 1 252 253 254 255

256 257 258 259 260

.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 1 ,710 .708 .707 .706 ,705 ,704 .703 .702 .701 .700 .698 ,697 .696 .695 .694 .693 .692 .69 1

26 1 262 263 264 265

266 267 268 269 270 27 1 272 27 3 274 275 276 277 278 279 280 28 1 282 283 284 285

286 287 288 289 290 29 1 292 293 294 295 296 297 29 8 299 3 O0

,690 .689 .688 .687 .686

.685 ,683 .682 .68 1 ,680

.679

.678

.677

.676

.675 ,674 .673 ,672 .67 1 .670 .669 .668 ,667 ,666 .665 .664 .663 .662 .66 1 .660 .659 ,658 .657 .656 ,655

.654

.654

.653

.652

.65 1

Where: Cl = 1/[ 1 .O + ("F-60) x MPb]

And for Pbv less than 1238 psia

and for Pbv greater than 1238 psia M = 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 predicting nitrogen-charged gas lift valve operation at high pressures and temperatures. Presented at SPE production operations symposium in Oklahoma City, OK, March 13-14, 1989



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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 as follows:

Equation 4.4 Equation 4.5

The test rack opening calculation is based on the corrected bellows pressure at 60°F Pb and the valve data Ab and A,.

Bellows

ATMOSPHERE Pa

Fig. 4-4 - Setting test rack opening pressure

Gas Injection in the Annulus or Tubing

High pressure gas for injection into the well is usually supplied 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 wellhead assembly.

The wellhead gas pressure is required for design purposes. One aspect of design is the change of gas pressure with depth. In most cases, injection gas is put into the tubing-casing annulus of the gas lift well and the gas pressure 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 pressure could decrease with depth.

One of these cases occurs when gas is injected at volumetric 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 tubing 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 flowing 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 flowing 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 (sometimes 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 (stacking) can be made. First, a pipe diameter equivalent to the tubing pipe body is used and the pressure profile is observed. 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 because 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 depth because the weight of the gas increases the pressure. How- ever, the exceptions are the cases just reviewed where significant friction losses actually result in 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 gravity used in the system.

In most systems compressing low pressure separator gas to injection pressure, the high pressure gas specific gravity will be from 0.7 to 0.8. When the reservoir fluid has



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42 Gas Lift

Pressure, PSlG 800 900 1000 1100 1200 1300 1400 1500 1600 1700

O

1 O00

2000

3000

4000

5 5000

e 6000 tl

7000

8000

9000

10 O00 900 1000 1100 1200 1300 1400 1500 1600 1700

Fig. 4-5 - Gas pressure profile with O. 7 SG Gas

~~



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Pressure, PSlG 800 900 1000 1100 1200 1300 1400' 1500 1600 1700

O

1 O00

2000

3000

4000

5000 Q) u,

G n e 6000

7000

8000

9000

10 O00 900 1000 1100 1200 1300 1400 1500 1600 1700

Fig. 4-6 - Gas pressure profile with 0.8 SC Gas



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44

API T I T L E x V T - 6 74 m 0732290 0532877 078 m

Gas Lift

d CD O

m e O

m O O

d d ò d Gas Gradient, PSI/FT

l-

F

r r

(3 5 e

a

2 e

c! v) v)

O O

O O (o

Fig. 4-7 - Injection 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 for a specific gravity of 0.8. For other conditions, a gas gradient 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 (0.04 1 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 Gas passage through a gas lift 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 intermittent flow) will not be efficiently displaced. Thus this flow through the gas lift valve is a critical item. However, for the low rate wells typical of some Gulf Coast locations, gas passage has not usually been a problem. For the high flow rate international oil fields, valve gas passage characteristics are important to successful operation of the well.

Gas passage through a particular valve is difficult to predict. Some data, based on static probe tests and dynamic flow tests (mentioned in the section on gas lift valve mechanics), are available. However, this section will cover differential pressure: that is, the difference between the gas pressure at the location and the fluid pressure at the same location, and the flow capacity of the valve as a square-edged orifice. This orifice assumption is not 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) - Gas flow capacities (0-9750 MCF/D) for known upstream pressure, downstream pressure, and Orì- fice size. Courtesy Camco



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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 the gas into the fluid column. Conversely, at a very low differential pressure, sufficient gas cannot pass and enter into the fluid. Often a minimum of 50 psi is used as a difference between the operating gas pressure and the production. However, inability to accurately estimate the gas pressure at depth and the fluid pressure at depth can result in a differential less than 50 psi. Under such a condition, the well does not unload, or the point of gas injection does not transfer, to the next valve.

High gas flow rates through a valve demand higher injection gas pressure and higher differential pressure. At an operating point, a minimum pressure differential of 100 to 200 psi should be used between the gas and the fluid columns for design purposes.

Gas f low capacity is usually estimated with the Thornhill-Craver equations for flow through a square-edge

orifice. A square-edge orifice is the device used in 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) have been prepared using the Thornhill-Craver equation. They give the gas flow capacity for a known (upstream) gas pressure, (downstream) fluid pressure, and port size (orifice). These charts typically are based on a fixed temperature (usually 60°F) and gas gravity (usually 0.65). 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 temperature approaches fluid flow temperature, volume flow rates through the valve are less than the estimate obtained from the chart. Because of this, downhole gas rates are usually

GAS THROUGHPUT IN MCFD



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corrected to the chart conditions before estimating the port size requirement from the chart. Fig. 4-9 provides information for correcting the gas 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 start to close in response to the nitrogen pressure force inside the 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 orifice that

is the basis for the Thornhill-Craver charts unless the valve is full open.

This restriction to gas flow may affect unloading operations and the well may not operate according to initial design. The small gas passage rate prevents aeration of the fluid column or prevents slug formation for intermittent lifting. The user of the charts should be aware that a gas lift valve probably does not have the exact gas passage characteristics indicated on the chart. Efforts are underway within the industry to correct this problem and one valve manufacturer has published empirically determined dynamic valve performance data for its continuous flow valves.

GAS THROUGHPUT IN MCFD

Fig. 4-8(C) - Gas flow capacities (0-20,000 MCF/D) for known upstream pressure, downstream pressure, and orifice size. Courtesy F: í? Focht



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48

A P I TITLE*VT-6 94 W 0732270 0532BBL 5T9

Gas Lift

300

2 80

200

240

290

zoo

1 ao

1 60

1 40

120

1 O0

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 . i6 1.50 1.1

Fig. 4-9 - Correction factor chart for gas passage charts. From Camco Gas Lift Manual



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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, injection line, separators, treating facilities, compressors and meters. Maximum production, effective use of gas, and lowest investment and operating expense result when the entire system is planned properly.

Current computer technology provides methods to analyze systems so that the “best” values for separator pressure, 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 problems, and lower investment. However, investment for gas lift facilities depends on gas source and quality.

A good source for gas lift gas is a constant pressure, dry gas such as that obtained from a gas processing (NGL) plant. This gas source is good because the pressure is constant and the gas can be 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 in the line. If other sources must be used, such as gas well gas or separator gas, then any one of a number of processes such as compression, dehydration, hydrocarbon processing or sweetening might be required before transport- ing the gas to the wells.

The gas distribution system can be one of two basic designs: (1) A direct connection from the compressor station 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 affects only one well. It is very useful for small systems that have a limited number of wells and short pipelines. The second, or trunk line, method is applicable to large land or offshore (remote wellhead platform) systems. It provides local distribution to each well and permits several 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 that sufficient compression capacity exists) when one part of the system is down for any reason.

A modification to the main trunk line system is the use of a distribution ring so that gas can flow to a local distribution 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 investment requirement for a large field area because the main trunk line is less expensive than a

large number of individual lines. However, major field studies 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 and the heavier gas hydrocarbons will condense in a distribution system and cause either hydrates (freezing) or liquid slugging. Sometimes the heavy hydrocarbon components must be removed by local field processing.

A refrigeration system, or a compressionlexpansion cooling method, can be used to cool the gas stream and condense the liquid hydrocarbons. Only a very rich gas composition causes liquid hydrocarbon condensation. Typical situa- tions where this occurs are: (1) separation at very low pressures where the gas stream going to compression has a high fraction of heavy hydrocarbons, (2) where cold envi- ronmental temperatures cool the gas and condense the heavy elements. Hydrocarbon removal may not be necessary in all cases but water should always be removed for good system performance.

A cooling facility to remove hydrocarbons often removes a significant amount of water vapor in the gas. If a processing facility is unnecessary, then gas dehydration with trimethylene glycol absorption is most commonly used to remove the water vapor from the gas stream.

Water in 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 temperatures on cold winter nights.

The lowest anticipated temperature can be used to predict hydrates with the Katz curves, Fig. 4-10. If “freezing” occurs at the lower temperatures, water removal (105 lb I million scf gas) can be estimated, Fig. 4-1 1. For example, at 1000 psia and 120”F, the water content is 105 lb / million scf gas. At a “freezing” (hydrate) condition of 40°F and 1000 psia, 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” temperature occurs infrequently, methanol can be injected for a limited time until the gas temperature rises above the “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 the required glycol dehydration system illustrated i n Fig. 4- 12.



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50 Gas Lift

Gas with excessive carbon dioxide (COZ) or hydrogen sulfide (HzS) can cause operating problems such as corrosion, excessive compressor maintenance, and fuel contami- nation. These impurities are also potential safety hazards. One type of sweetening facility, applied when gas cannot be used in the field, extracts both C02 and HzS (sour acid gas) with an amine absorption process. In this system, the amine solutions are contacted by the gas flow stream and the acid gas constituents are extracted. The sweet gas returns to the system while the amine solutions are treated remove the C02 and H2S.

When proper inhibition systems and metallurgy are used in the gas lift and well facilities, gas with H2S and or CO2 can be used provided a good glycol dehydration facility removes the water vapor. However, careful monitoring should be used to assure that such systems are functioning properly at all times.

Reciprocating Compression

The reciprocating compressor is a very flexible machine in gas lift applications and has proven very popular over

EXAMPLE:

l . Gas at 1000 psia, 70” F, 0.7 sp. gravity does not “freeze” (this point is just below the hydrate - formation condition for 0.7 sp. gr. gas)

2. Gas at 1000 psia, 40” F, 0.7 sp. gravity will “freeze”

Fig. 4-10 - Hydrate-formation conditions for natural gas. Katz, et al., Handbook of Natural Gas Engineering



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Fig

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Gas A d i c a t i o n and Gas Facilities for Gas Lift

1. Gas at 1000 psia, 120" F has a water Content Of

105 Ib/million scf

2. Gas at 1000 psia, 4'O°F has a water Content Of

9 Ib/million scf

-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 natural gar in equilibrium with liquid water.

. 4-11 - Water content of natural gas in equilibrium with water. Katz, et al., Handbook of Natural Gas Engine



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52 Gas Lift

the years in most Gulf Coast systems. Reciprocating compres- rate. Curves in Fig 4- 13 can be used to estimate horsepower sion is typically used where a low suction pressure gas must requirements. The estimating technique requires an overall be compressed to a high discharge pressure and the volume compression ratio (discharge absolute pressure divided by flow rate is sufficiently low that a centrifugal machine suction absolute pressure) and a breakdown of this ratio would not apply. Reciprocating compressors are capable of into stages. Typically, the compression ratio per stage should handling varying suction discharge pressures and changes be between 2.0 and 3.8. Higher ratios tend to raise the dis- in gas specific gravity or gas flow rate. charge temperature in the compressor cylinder to a value

These compressors can be skid-mounted and installed on location quickly then moved when service is terminated. The high speed-skid mounted units typically have a separa- ble compressor driven by a 1000 rpm engine of 1500 (or less) horsepower. The larger, low speed, integral units (power and compressor cylinders on the same frame) are installed in stations with numerous support utility systems. These 300 rpm units are available in sizes up to 3000 horsepower.

The drivers for the compressors are usually gas engine units but may be electric motors if the proper voltage power source is available. The reciprocating compressors attain their rate flexibility (and field desirability) by unloading cylinder ends or by adding clearance chambers (bottles). Their primary limitation is their low throughput gas volume. For high flow rates at international locations, or offshore, a centrifugal machine may better fi t the application.

Horsepower will depend on the pressure change from suction to discharge, gas specific gravity, and throughput

that causes maintenance problems. The horsepower is read from the curves (given a compression ratio and gas specific gravity) as an uncorrected horsepower per million 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 horsepower, 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 compressor 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 take the gas from a low

Fig. 4-12 - Glycol Dehydration Unit - Courtesy of PETEX



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A P I TITLEaVT-6 94 0732290 0532886 080 m


EXAMPLE:

l . Suction Pressure = 55 psia (40 psig)

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. Use 3 stage machine to keep discharge temperature lower and reduce maintenance problems.

Approximate power required to compress gases

Fig. 4-13 -Approximate Horsepower Required to Compress Gases. GPSA-Engineering Data Book



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A P I TITLExVT-6 94 0732290 0532887 TL7

54 Gas Lift

an electric motor that also operates at high 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 adequate 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 significant amount of horsepower and yet be a physically small package as compared to reciprocating compressors. In addition, they do not have the massive frames of the reciprocating machines, nor do they have the vibrations detrimental to offshore platform facilities.

One critical point in centrifugal compression: the compressor wheels do not operate satisfactorily at conditions significantly different than initial design. For example, assume the gas specific gravity drastically changes because of gas flow stream alteration. The machine may operate at a very low efficiency or perhaps not at all. Thus, the 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 compression ratio, pressure, temperature, and specific gravity of the gas. The methods, for making these initial estimates are contained in the GPSA Engineering Data Book section on centrifugal compressors.

Piping and Distribution System

Piping, separation, cooling, dehydration, and compression, 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 separation and scrubbing that prevents liquid carry- over into a compressor. Typically, both inlet separation and suction scrubbers are necessary. Manifold suction headers should minimize pressure losses to 1 psi. The suction discharge pulsation bottles for reciprocating compressors must be designed to dampen pressure pulses as well as withstand vibration (to prevent cracks due to vibration). An adequate discharge delivery system, away from the compressors, is required in order to feed gas to downstream 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 liquid hydrocarbons or water. Where water is used for testing, a Methanol flush can be used to remove any water that remains in the system. The system design should also include cooling and dehydration processes that would eliminate liquid condensation in the system. Even with these precautions, liquid removal taps should be located at convenient 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 inexpensive measurement methods. However, other means such as vortex shedding meters, turbine meters, or positive displacement meters can also be used. This discussion will be limited to the use of orifice meters with either chart recorders or flow computers since they are the most commonly used devices for measuring gas. The orifice can be used to measure gas because the flow rate of gas is proportional to the differential pressure across the orifice plate. The higher the flow rate through a given orifice size, the greater the differential pressure across the orifice. Rate estimating examples in the GPSA book provide this calculation information. Fig. 4-14 shows GPSA nomenclature used in these calculations.

The typical method for recording the flow rate through an orifice is to use the chart recorder. Charts can be either square root charts or 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 the meter and the differential pressure across the orifice. The differential reading can be set and adjusted by an adjustable choke placed just downstream of the meter. Differential reading, pressure reading, temperature, specific gravity, orifice size, and other factors are used 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 constant calculated for 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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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 =

Fpm =

Fpv =

F, =

F, =

maximum transverse dimension of a straightening vane passage cross sectional area of any passage within an assembled straightening vane

ratio of the orifice diameter to the internal diameter of the meter run, dimensionless the product of multiplying all orifice correction factors volume indicated by th,e number of pulses or counts liquid pressure correction factor. Correction for the change in volume resulting from application of pressure. Proportional to the liquid compressibility factor, which depends upon both relative density and temperature. 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 to change from a gas specific gravity of 0.6 liquid temperature correction factor. Proportional to the thermal coefficient which varies with density and temDerature

F, = steam factor, mercury meter Fsl = seal factor for liquid. Applied only to mercury

F t b = temperature base factor. To change the temperature

Ftf = flowing temperature factor to change from the assumed flowing temperature of 60 "F to the actual flowing temperature

F, = temperature correction factor applied to displacement meter volumes to correct to standard temperature

G, GI = 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 differential 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 volume k = 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 specific 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 meter during proving by the volume registered by the meter

P = pressure, psia Pf = static pressure at either the upstream or downstream

P, = pressure reading on L-10 chart Q = gas flow rate, CU 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 = flowing temperature, deviation from the ideal gas laws = d 1/Z Reynolds number factor. To correct the calculated basic orifice factor to the actual flowing Reynolds number YCR = critical flow constant steam factor Z = compressibility factor

S = square of supercompressibility

"R

Y = expansion factor to compensate for the change in density as the fluid passes through an orifice

Fig. 4-14 - GPSA Nomenclature used in gas metering



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56 Gas Lift

The flow computer, an electronic device, is sometimes used lated in cubic feet (or some multiple) much like a positive to calculate gas rate. It can display the value as 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 electronics specialist to correspond to temperature, meter feature is extremely useful for both short term as well as tube, orifice diameter, and specific gravity factors. long term analysis of the well because well testing accuracy Although the flow computer displays the flow rate as a is improved. percent of full scale, more importantly, the volume is tabu-

? f' r Io

Lo

(See Figure 4-14 for GPSA Nomenclature used in this section)

EXAMPLE GAS RATE (Factors from GPSAl

Q (thousand scf/d) = hu*Pu*24 Hour Coefficient

1.

2.

3.

4.

5.

6.

7.

8.

Gas Pressure at Meter (Pr) = 888 psig from Pg at Meter = (hu)2 Rp/l O0 - 14.7

FPV = 1 .O98 from Z = 0.83 for Pt = 888 psig, Tt = 1 O0 "F

Fb = 21 0.22 from orifice = 1.000, meter tube = 2.067

Ftf = 0.9636 from T, = 100 "F

Fg = 1.1547 from Gf = 0.75 (Gas SP. GR.)

M = 3.162 from Rh = 100 Rp= 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 - Example problem square root (L-IO) chart.



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Gas Lift Valves 57

CHAPTER 5 GAS LIFT VALVES

INTRODUCTION

The heart of any gas lift 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 lift valve are similar. A spring in the regulator (Fig. 5-1A), as in the gas lift valve (Fig. 5-1B), forces the stem tip against the seat. The diaphragm of the pressure regulator and the bellows of the gas lift valve provide an area of influence for upstream pressure greater than the port area. The force that results from this combination of upstream pressure 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 pressure regulator and the gas l i f t valve illustrated are controlling the upstream pressure. The regulated upstream pressure is a function of spring force and effective diaphragm 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 understand the operation of most gas lift valves. API Spec. l lVlS0 covers the manufacture of gas lift valves.

DIAPHRAGM /

DOWNSTREAM

Pressure regulator (A)

Gas

Fig. 5-1 - Elements of a Pressure Regulator and a Gas Lift

+" UPSTREAM

lift valve (B)

Valve

VALVE MECHANICS

Pressure is force per unit area. The common oil field unit Force (Pounds) = Pressure (psi) x Area (sq. in.) of pressure is pounds per square inch (psi). The pound is the force and one square inch is the unit area. As the value of psi 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 entire area is found by multiplying the pressure 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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58 Gas Lift

n

A

1 t F

Fig. 5-2 - Force Diagram

No piston seal

(A)

DOME

PISTON

STEM TI P

PORT

Basic Components of Gas Lift 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 the bellows 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 the flexibility required for movement. A bellows type seal is used in the majority of gas lift valves.

O-Ring piston seal

(B)

Bellows piston seal

(C)

Fig. 5-3 - Basic Gas Lift Valve Components

~~~~



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A P I TITLExVT-b 94 0732290 0532892 3 8 4 m Gas Lift Valves 59

Closing Force

Many gas lift 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, = Pb Ab Equation 5.2

F, = Closing force.

Pb = Pressure inside the dome space sealed by the bellows and valve housing.

Ab = Area of the bellows.

Schematic (B)

Fig. 5-4 - Closing 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 (PI) applied through the side opening and pressure (PZ) applied through the valve port are the pressure sources to produce 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 bellows 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 opening force contributed by this combination is:

F02 = P2 Ap 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 for 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) = Pb Ab - P2 Ap 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 - P2 (Ap /Ab) 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 the 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 0532893 210

60 Gas Lift

Pictorial (A) Schematic

(B)

Fig. 5-5 - Opening Force Diagrams

The pressure (PI) determined by this equation is the balance pressure. Actually the valve stem tip is still on seat and only slight leakage by the stem tip and seat may be observed. An increase in PI or PZ will move the stem tip proportionately further from the seat and allow more gas passage. A decrease in PI or P2 will load the stem tip harder against the seat and cause a tighter stem tip to seat seal. This is the case as the valve closes.

Valve Load Rate

One definition of load rate is the measure of the amount of opening pressure required for each inch of valve stem travel (psihnch). The reciprocal of the load rate, inches of stem travel per psi of opening pressure (inchedpsi), is another form of load rate presentation.

The compressibility of the nitrogen charge in the dome and the spring rate of the bellows (load increase per unit travel), prevents rapid full opening of most valves. Slight increases in PI or P2 normally cause only slight additional valve opening. The amount the valve opens with increases of PI or P2 depends upon the volume of the dome and the stiffness of the bellows. These two conditions can vary between manufacturers, as well as between valves of different styles, made by the same manufacturer. A “stiff’ valve has slight changes in opening and closing stem travel with respect to an increase or decrease in PI or PZ. A “soft” valve will have greater opening or closing stem travel changes with respect to the same increase or decrease in PI or P2. The gas lift design requirements dictate the type valve (hard or soft) required. A probe test is used to obtain the load rate of a particular valve design.

Probe Test

A probe test of gas lift 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 to a valve i n a fashion that will allow the 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 PZ acting on the stem tip area that is sealed by the seat. Without P2 to assist opening, PI 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) over which the valve opening pressure (PI) acts. The result obtained is the amount the valve opening pressure (PI) is reduced in psi.

Pictorial Schematic

Fig. 5-6 - Closing Pressure Diagrams



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

Equation 5.12

Equation 5.13

Equation 5.14

The ratio is called the Production (1 - Ad&)

Pressure Effect Factor (PPEF). Some texts refer to this ratio as Tubing Effect Factor (TEF).

If the PPEF is reported as a decimal,

PPE = Pz PPEF Equation 5.15 And, if reported as a percentage,

PPEF Equation 5.16

1 O0 PPE = P2 -

Closing Pressure

The 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 CHARACTERISTICS

Dynamic Flow Test

A dynamic flow test consists of flowing gas through a gas lif t valve and measuring the gas passage at different pressure 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 conditions 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 a constant injection pressure of 535 psig and 550 psig. Valve specifications and performance test conditions are included in Fig. 5-7. The curve shows that no gas flows at each of two distinct production pressure values for each injection pressure. One, at a production pressure equal to the injection gas pressure of 535 and 550 psig. At this point the valve is open, but the lack of an injection pressure to production pressure differential prevents gas flow. The second point of no flow is at a production pressure of 218 and 294 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 in an intermittent gas lift installation. Even if surface injection gas is stopped after the operating valve is opened, the pressure in the annulus must bleed down from the opening pressure to the closing

2 3 4 5 6

Flowing P r o d u c t i o n Pressure - 100 p s i g

Gas Lift Valve Specifications: Effective Bellows Area = 0.77 sq. in. Ball O.D. on Stem = 0.625 inches Port I.D. = 0.41 inches Angle of Tapered Seat = 45"

Performance Tests: Constant Injection Gas Pressure = 535 and 550 psig Test Rack Closing Pressure = 485 psig Slope of Throttling Range = 9.3 Mscf/Day/psi'ApPf

Fig. 5-7 - Gas lift valve dynamic flow test (Courtesy Teledyne Merla)



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API TITLEwVT-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 injected 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 surface. At some subsequent time, the amount 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 external pressures significantly higher than 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 stops. 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 pressure 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 closing cycle rate. Chatter can alter the bellows' physical characteristics, 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 opening and closing pressure of a valve. Valves must be 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 increase in pressure when heated and will 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, and 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 the well. Although any reasonable temperature could be

.PRESSURE SOURCE, (P,)

Fig. 5-8 - Test 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 to adjusting the opening pressure to the required value. A spring loaded 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 opening pressure (PI) of the valve has been defined as follows:

Pb1 - PZ (&/Ab) PI = Equation 5.17 1 - (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 specified 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 the test rack temperature of 60°F (Pb1 @ 60°F). (See Temperature Cor- rections, Chapter 4, and Table 4- 1 .)

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 TITLE*VT-b 94 0732290 0532896 T 2 T

Gas Lift Valves 63

TYPES OF GAS LIFT VALVES

Classification of Gas Lift Valves by 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 the casing. The valve is physically positioned between the two pressure sources. Both of the pressures are trying to open the valve. When the injected lift gas is in contact with the bellows (largest area of influence), the valve is called an injection pressure operated valve (Fig. 5-9 A&B). When the produced fluid is in 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 in either case. As seen in the illustrations, the receptacle (mandrel) can control how the two pressure sources are ported to the valve.

All calculations (opening pressure, closing pressure, etc.) for a production pressure (fluid) operated valve are the same as those for 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 (PI) acts on the largest area of influence (Ab - AP) and production pressure (P2) acts on the area of the port (Ap).

Production up the tubing Production up the annulus

(A) (B)

Fig. 5-9 - Injection pressure operated valves

Production up the annulus

(A) Production up the tubing

(B)

Fig. 5-10 - Production pressure operated valves

A production pressure operated valve (Fig. 5-10 A&B) has the production pressure (PI) 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 (Ap /Ab) Equation 5.17 1 - (Ap /Ab)

The opening pressure (PI) equation is the same for both cases. The convention of applying PI to the largest area of influence (Ab - AP) and (PZ) to the smallest area of influence (A,) must be followed.

Valves Used for Continuous Flow

A valve used for continuous flow should meter or throttle the gas throughput. The injected gas volume is controlled at the surface.

Valves Used for Intermittent Lift

Intermittent lift usually requires a large volume of gas for a short period of time. Unlike valves used in 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 with no dome pressure (Fig. 5-12) has the following force balance, just as the valve starts to open:

This valve (Fig. 5-1 1) uses a nitrogen charged dome as Psp Ab = PI (Ab - Ap) + P2 Ap Equation 5.20 the only loading element to cause closure. All earlier discussion was directed to this valve. The equation may be rearranged to solve for PS, based

upon the desired conditions at valve depth and for particular 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 the pressures are properly identified with respect to the area elements they are acting on.

After Psp is determined, the test rack opening pressure may be calculated:

PSP P”, = Equation 5.22

(1 - Ap /Ab)

P*

Pressure 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 the seat is a atmospheric pressure in each case.

3. Pilot Valves: Fig. 5-11 - Unbalanced pressure charged valve

A pilot valve (Fig. 5- 13) offers the advantage of a large port combined with close control over valve 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 negligible and are normally not considered when setting the valve’s opening pressure. 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. A fixed orifice is not normally used.

Springs are most commonly applied within a valve in a fashion that causes a 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 is used as a fictitious replacement of dome (bellows) charge pressure. Since temperature effect is negligible, P, represents the Spring valve dome charge in the tester as well as at the operating depth. Fig. 5-12 - Unbalanced spring valve



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A P I TITLExVT-b 9 4 0732290 0532898 AT2

Gas Lift Valves 65

and tubing pressure act on the control section in the same way that they do on an unbalanced injection pressure operated valve. When the control valve opens, the main valve (large port) opens: and when the control valve closes, the main valve closes. Gas flowing through the small port of the control section acts on the piston of the main valve to open it. When the control valve closes, a spring returns the main valve to a closed position.

CONTROL VALVE

MAIN VALVE

PISTON BLEED PORT

Pilot valve

Fig. 5-13 - Pilot valve

4. Other Types of Valves:

New types of valves are constantly being developed to keep pace with the general evolution of gas lift technology. There are many types of special application valves, too numerous to include in this manual.

The principles of operation of most special valves are similar to those of the more widely used types of valves discussed in the foregoing. It should also be noted that almost all types of valves are available in both retrievable or non-retrievable form and with various types of check valves.

Wireline Retrievable Valve and Mandrel

These valve mandrels are commonly called Retrievable or Sidepocket Mandrels. Retrieval in the name comes from the wireline retrievability of the valve.

Unlike conventional valves and mandrels (Fig. 5 -16), the valve is installed within the interior portion of the sidepocket mandrel (Fig. 5-15B). The valve is reached by wireline run through the inside of the tubing (Fig. 5-14A). A valve receiver (Pocket) forms a part of the mandrel and is offset from the main bore of the tubing and mandrel (Fig. 5-15B and 5-15C). In most cases, no through tubing restriction results. Tools that are normally run through the tubing can still be run.

Fig. 5-14A illustrates a well equipped with sidepocket mandrels. Wireline 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 addition to standard weight bar and wireline jars, a kickover tool of some type is used.

Fig. 5-14 - Wireline tool strings and retrievable mandrels



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API TITLEtVT-h 94 0732290 0532899 739 W

66 Gas Lift

The kickover tool has a means of attaching a pulling tool for retrieving valves or a running tool with a valve connected 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 tool with the mandrel pocket (Fig. 5-17B). After the mandrel 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 accommodate the valve packing. The packing bores are smooth 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 annulus. The bottom (and sometimes the top) of the pocket provides a second port that communicates with the tubing (see Fig. 5-15C). The gas lift 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 may be used for this purpose (Fig. 5-15C and 5-17A).

In addition to the pocket, many sidepocket mandrels have aids that are designed to facilitate locating the mandrel with wireline tools and 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 forced alignment. A controlled shoulder within the mandrel can also engage the wireline tools to aid in locating the mandrel. This stop will properly position the tools in a vertical position above the mandrel pocket. Fig. 5-17C shows a stop for this purpose located in the mandrel.

I I

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 - Details of wireline retrievable valve

VALVE MOUNTED OUTSIDE THE MANDREL (TUBING r R 1 ACCESS TO THE VALVE) MUST BE PULLED TO HAVE

CONVENTIONAL GAS LIFT VALVE

REVERSE FLOW CHECK

THREAD FOR INSTALLING VALVE - AND CHECK TO MANDRE’ (C)

Fig. 5-16 - Details of conventional valve

,- K I C K O F TOOL

(A)

VALVE LATCH

SIDEPOCKET MANDREL

GAS LIFT VALVE VERTICALLY AND RADIALLY ALIGNED AND KICKED OVER. READY TO ENTER THE MANDREL SIDEPOCKET.

=l“ LATCH t PORTS

SIDEPOCKEl

STOP SHOULDER POSI- TIONS KICKOVERTOOL AND VALVE VERTICALLY WITH

SIDEPOCKET RESPECT TO THE MANDREL

FINGER SLOT

HELICALSURFACE IS ENGAGED BY THE LOCATING FINGER OF THE KICKOVER TOOL. THE UPWARD FORCE APPLIED TO THE FINGER AGAINST THIS SURFACE CAUSES THE KICKOVER TOOL TO ROTATE INTO ALIGNMENT WITH THE FINGER SLOT.

Fig. 5-1 7 - Sidepocket mandrel, kickover tool and valve (Valve ready to be installed into mandrel 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 mandrel 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 CHECK

Conventional gas lift valve

(A)

Retrievable gas lift valve

(B)

Fig. 5-18 - Retrievable and conventional gas lift valves. Courtesy Cameo, Inc.

Mandrel and Valve Porting combinat ion^^^

It is often inefficient or impractical to use one combination of mandrel and valve porting to satisfy all gas lift installation design requirements. There are two basic configuration 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 in communication with the outside 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 pressure 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 check valve has been turned upside down in the latter two. Also, type 2 and type 4 have crossover seats. This restricts the seat size available in these valves.

Twobasicgasliftmandrelsincludetypel inwhichthesideofthepocketisin communication with theannulus and the bottom of the pocket is incommun- ication with the tubing, and type 2 in which the communication configuration is reversed.

R.".".

"01". l low

Fig. 5-19 - Basic gas lift mandrel types (After Focht, World Oil, January 1981)

Of these basic types of valves, types 1 and 4 are pressure operated. Types 2 and3arefluidoperated.Notethatthecheckvalvesintypes3and4operatein the opposite direction from types 1 and 2.

Fig. 5-20 - Configurations of gas lifr valves (After Focht, World Oil, January 1981)



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68 Gas Lift

There are eight possible configurations using the four occur. The crossover seat restricts the port size available to valve types and two mandrel types (see Fig. 5-21). In Fig. 3 / l~- in~h for the one-inch valve and tos/l6-inch for the 1'h-inch 5-21, Configurations A and B are recognized as the stan- valve. Configuration G is probably better for this purpose. dard type of completion. For tubing flow they are usually preferred. Normally, production pressure-operated instal- Mandrels with more than one pocket, more than two pack- lations are undesirable for high production rate because ing sections in one pocket, and with other porting con- they tend to cause heading or slugging type production. figurations have been used. New combinations are con- When they are used, a problem with configuration B may tinually being considered.

Gas -

A

. . E

Gas

. . B

I I F

m

d

l

C

T 3

D

- o 3 D P a

. - H

By combining the four valve types with the two types of mandrels, eight configurations are available. They are as follows: &valve 1 , mandrel 1, tubing flow, pressure operated; B-valve 2, mandrel 1 , tubing flow, fluid operated; C-valve 3, mandrel 1, annular flow, fluid operated; D-valve 4, mandrel 1, annular flow, Pressure operated; E-valve 1 I mandrel 2. annular flow. pressure operated; F-valve 2, mandrel 2, annular flow, fluid operated; G-valve 3, mandrel 2, tubing flow, fluid operated; and H-valve 4, mandrel 2, tubing flow, pressure operated.

Fig. 5-21 - Combinations of valve types and mandrel types (After Focht, World Oil, January 1981)



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Continuous Flow Gas Lift Design Methods 69

CHAPTER 6 CONTINUOUS FLOW GAS LIFT DESIGN METHODS

INTRODUCTION

Gas lift is a process of lifting fluids from a well by the continuous injection of relatively high pressure gas to reduce the flow gradient (continuous flow) or by the injection of gas underneath an accumulated liquid slug in a relatively short period of time to move the slug to the surface (intermittent lift). Both types are shown schematically in Fig. 6-1. Continuous flow gas lift design will be discussed in this chapter. Intermittent lift design will be discussed in a later chapter.

Continuous flow gas lift is essentially a continuation of natural flow. Gas is injected at some point in the flow pattern 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 lift installations using injection pressure operated valves is covered in API RP 11V652.

L

L INJECTED

f

_I L

INJECTED Q A I

r

Fig. 6-1 - (A) Continuous gas lift performance. ( B ) Intermittent gas lift performance

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 classified 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 continuous flow 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 tubing inside 2’/%-inch O.D. casing to 3Vz-inch O.D. tubing inside 103/4-inch O.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 through tubing. Also, the tubing 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 a packer or standing valve is classified as an open installation. This type of installation is seldom recommended, but well conditions may be such that running a packer is undesirable. 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 its working fluid level. 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 continuous flow. Each time the fluid level is lowered, some fluid 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 no possibility 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 recommended for all continuous flow installations. When a

A 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 flow wells. Once the bilize much quicker when placed back on operation.

CONTINUOUS FLOW UNLOADING SEQUENCE

Continuous flow unloading of a tubing-flow installation due to the pressure exerted by the liquid column 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 the casing is transferred into the 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 pressure 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 the tubing through the top and second valves. With the

PRESSURE , PSI

1OOO-

2000 -

3000 -

t W 4000-

f U

5000-

6000 -

I !

- \

1 I I I

Fig. 6-2 - Fundamentals of gas lift design



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A P I T I T L E a V T - 6 94 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 top valve to uncover the second valve. This This allows the injection gas to enter the tubing through the high injection gas-liquid ratio is required for only a short third valve. time, and the valve must be capable of passing this gas volume.

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 entering tublng

and u-tubed by injection gas pressure throughtopandsecondvalvelmmed-

valve as fluid in annulus is transferred to surface. Into tubing through lower valves.

lately after second valve uncovered.

(D) Fluid In tubing being aerated to surface by injection gasthrough second valve as fluid in annulus is transferred into tubing through third and bottom valves

through second and third valves im- (E) Injection gas entering tubing

mediately after third valve is uncovered.

(F) Produclngrateequalscapacltyof tubing from third valve for available

valve cannot be uncovered. injection pressure. Therefore, bottom

Fig. 6-3 - Continuous 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.

1 o. 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 available

Static bottomhole pressure

Productivity index or inflow performance relationship

Bottomhole temperature

Flowing wellhead temperature

Type of reservoir with expected depletion performance

It is common practice to use the annular space between the casing and tubing to conduct the injection gas down to the 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 design problems. 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 offshore 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 the existing mandrels and then determine 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 well productivity 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 discussed 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 the designer.

TABLE 6-1 CONTINUOUS FLOW GAS LIFT DESIGN CONDITIONS

Production Desired - q Maximum Well Depth - D, 10,000' Static BHP - P,, 3,600 psig Productivity Index - J

Formation R, 300 CF/B Water Cut - F, 65 % Oil Gravity 35" API Water Gravity - SG, 1 .O5 Gas Gravity - SGg 0.65 Casing Size 5 ' / 2 in. OD Tubing Size in. OD Surface Wellhead

Pressure - Pwh 1 O 0 psig Available Gas

Pressure - Pg 1200 psig Gas Injection Rate - qi 500 MCF/D Static Fluid Gradient* - g, 0.465 psitft Bottom Hole

Temperature - Tr 190°F Flowing Temperature - Twh Fig. 6-9 Type Reservoir Waterdrive

(Gross Fluid) 0.4 BLPD/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 explanation follows:



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A P I TITLExVT-b 94 0732290 0532qOb 7 T q


1. On a convenient scale make a depth versus pressure 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 pressure. 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 indicated here.

2. An available gas injection pressure line is drawn. Starting at 1200 psig, the pressure increases with depth due to the static gas column. For the conditions described, the pressure will increase approximately 30 psi per thousand feet of depth. The gas pressure at total depth will be 1500 psig. This represents 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, the tubing gas-liquid ratio would require over 2,000 psig flowing pressure at the bottom of the tubing. Therefore, it would not be possible to inject gas at 10,000 feet. Gas would have to be 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 total liquid 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 point can be drawn upward as represented in Fig. 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 pressure of 100 psig has been specified, a gradient curve can be drawn starting at O depth and 100 psig for this higher gas-liquid ratio. This gradient line intersects the previously drawn gradient line 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 the two curves at approximately 8200 feet. The pressure point is about 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 to inject a limited amount of gas at this point because of the lack of pressure differential at 8200 feet. Assuming no pressure drop has been taken for safety factor, which will be discussed later, it 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 production 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 continuing series of possible injection points for different production rates. It should be emphasized that this is not a gradient curve. A point on the equilibrium 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 pressure is not necessary for developing an equilibrium curve. It is only necessary that adequate pressure be available to inject at the desired point. An equilibrium curve can be very useful in studying gas lift. For example, 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 system pressure 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 equilibrium curve. For a field study it would be necessary to select a typical well productivity and also benefi- cial to 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, changing the tubing to 27/s-inch O.D. will result in a production 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 additional 5 barrels per day. Further increases in the amount of gas injected would result in no increase in production and actually would start to cause loss of production. This demonstrates a very important 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 exists such as an offshore platform were the 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 introduced 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 pressure, the less production that will be obtained for a given set of conditions. The equilibrium curve concepts 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 - Graphical solution for design based on conditions of Table 6-1



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A P I T I T L E x V T - 6 94 m 0732290 0532908 571 m


clude determining what size tubulars to place in the well and the volumes and pressures needed from the gas injection system. These considerations are equally or more important than design of spacing and valve setting. An efficient and properly working system cannot be installed unless both are done.

6. The gradient curve above and below the point of gas injection 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 without 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 tubinghead pressure with a slope equal to the assumed liquid gradient of .465 psi per foot the maximum point of gas injection will be where these 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 approximately 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, the fluid level i n the annulus will be

7. The same criteria of U-tubing from the first valve to the second valve also exists. However, surface casing and tubing pressure are no longer applicable. The

TP 100 PSI 4oo

PRESSURE - PSI

0 1 800 1200 1600 2000 2400 O

200c

400C W u.

I I b

w n

600C

800C

10,ooc

Fig. 6-5 - Graphical solution for design based on conditions of Table 6-I (Continued)



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A P I T 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 equilibrium 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 downhole. However, when the well started to produce at the expected 600 barrel per day rate, a higher pressure would exist opposite the top valve than the pressure used in setting these 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 these valves resulting in a design of 7 valves with the bottom valve located at 8250 feet. Valves are spaced closer together at depth increases because the minimum tubing pressure gets nearer the .available casing 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 2000 2400

200c

W W LL

SOOC

I'

o I- & W

600C

800C

10,ooc ~

Fig. 6-6 - Graphical solution for design based on conditions of Table 6-1 (continued)



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


conventional valves were selected without a spring and with a valve stem area that is 10 percent of bellows area. Then valve 2 would have a calculated domepressureof 1273psig(1334~0.90+715~0.10= 1273). The valve pressure would be set in the shop so that it would have 1273 psi at the operating temperature at 4500 feet. All gas lift companies have charts for making the proper conversion. Thus the valve string would be (Assuming valve port area = 10 percent bellows area):

TABLE 6-2 TABULATION OF PRESSURE WITH DEPTH

Depth Casing Press. Tubing Press. Dome Press. feet Psig Psig Psig

2530 1275 420 1190 4500 1335 715 1273 5900 1375 950 1333 6900 1405 1120 1377 7500 1425 1240 1407 7900 1435 1320 1424 8250 1445 1390 1440

Safety Factors in Gas Lift 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 as safety factor. The following discussion contains various ways of adding safety factor.

The first element of danger in the design is the gas pressure 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, 11 50 psig or less should have been used as working casing pressure if 1200 psig is absolute maximum available.

There are two main considerations in gas lift valve design. 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 to prevent this from occurring.

One means of including safety factor in the design is illustrated in Fig. 6-7. This method introduces 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 below the top valve is slightly closer together. As can be seen from the design, the point at which a minimum 50 psi differential between casing pressure available and tubing pressure 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 illustrated in Fig. 6-8. This was originally introduced under the name Optiflow design. The Variable Gradient design is essentially the same thing. The point of gas injection is determined 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 wellhead pressure selected will be the expected flowing wellhead pressure plus 20 percent of the difference between tubing and casing pressure. In the example, this would be 100 + 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 flowing production pressure line, and is referred to as “Variable



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A P I T I T L E * V T - b 9V W 0732290 0532911 066 W

78 Gas Lift

Gradient” design. The first valve is located in exactly the same manner as previously discussed, using the expected wellhead pressure and anticipated injection gas pressure. However, below this point instead of designing on the basis of expected flowing production pressure with the anticipated 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 dome pressures in the valve. The dome pressure will be set so that the valve will not open without the minimum pseudo production 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 is available at the depth of injection and the anticipated 600 barrels per day should be produced from the 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, this valve 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 pressure effect is 10 percent or less, this does not introduce a sufficient 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 pressure operated valves. Thus, two methods of introducing safety factor for opening the valves are available. However, the method used is 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 400 800 1200 1600 12000 2400

O

2000

F W

~ 4 o o ( l I’ k L W o

6008

8 0 0 C

10,000

I I

3’ \ 6760’ q p g : 7800’

Fig. 6-7 - Example design using casing drop of 20 psi



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A P I T I T L E + V T - 6 94 m 0732290 0532932 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 considerable 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.

Downhole Temperature for Design Purposes The downhole temperature to be used in setting the

valves depends upon the type 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 is used with the gas lift valve mounted in 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 available in most fields and usually consists of a straight line gradient between bottomhole temperature 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 temperature in the bellows is equal to the well fluid temperature. Fig. 6-9 is a chart by Kirkpatrick for determining the flowing 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

W I-

W L L

I' t W P

1

.Fig. 6-8 - Variable gradient design



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A P I T I T L E x V T - 6 94 0732290 0532933 939

80 Gas Lift

I - I

1 I I l I 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 11 12 13 14 16 te 17 10 l o 20

TOTAL FLUID FLOW RATE - 100 BBLWDAY

Fig. 6-9 - Flowing temperature gradient for different flow rates, geothermal gradients, and tubing sizes



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&PI TITLExVT-b 94 0732290 0532714 875

Continuous Flow Gas Lift Desien Methods 81

and bottomhole temperature. This is slightly in error as the well fluids will leave bottom at earth temperature. As the well fluids move up the tubing, they will be warmer than the surrounding earth temperatures and will be cooled by the earth. This cooling rate will increase as the temperature differential between the well fluids and the earth increases. For a given flow rate this will usually increase to some fixed differential and then continue at that differential until the well fluids reach the surface or very near the surface.

A more realistic temperature profile is illustrated in 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 available. 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 Conditions Different From Design Conditions

The previous design discussion has assumed exact knowledge of the well productivity. In actual cases, this seldom happens. Fig. 6-11 shows the effect on an actual productivity 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 productivity, 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 is 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 800 barrels per day will result, with gas being

TEMPERATURE - *F

O 40 80 120 160 200 0 - 1

FLOWING GRADIENT FROM FIG. 6-9

0.7"/100 FT. 2000 -

ASSUMED TEMP. PROFILE IF STRAIGHT LINE IS USED t-

W

E 4000

c X I

-

W O

n ACTUAL IS CURVED (ESTIMATE - NOT CALCULATED)

6000 - EARTH GRADIENT 1.2"/100 FT.

10.000 8ooo8

t- W W IL

I X c W O

n

1

O 40 80 120 160 200 0 - 1

FLOWING GRADIENT FROM FIG. 6-9

0.7"/100 FT. 2000 -

ASSUMED TEMP. PROFILE IF STRAIGHT LINE IS USED

4000 -

ACTUAL IS CURVED (ESTIMATE - NOT CALCULATED)

6000 - EARTH GRADIENT 1.2"/100 FT.

'0.000 8ooo8 Fig. 6-10 - Straight line and actual temperature profiles



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API TITLE+VT-6 94 0732290 0532935 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 the need to always over-predict rather than under-predict the 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 injecting higher in the hole. Sometimes the mistake of underestimating productivity might be overcome by injecting gas in higher quantities than anticipated. However, the problem of working down from one valve to the next may still prevent this benefit.

DESIGNING GAS LIFT FOR 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 spacing mandrels in the tubing string at the time the 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 the

TP 100 P81

PRESURE - PSI

O ~~

400 000 1200 1600 2000 O

200c

k W W

I S

W

L 4ooa

t n

eooa

1sooa

10,000-

\ /U00 B/D

BID

PI = 0.8

Fig. 6-11 - Actual vs. assumed productivity profiles



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API TITLE*VT-b 94 m 0732290 0532’9Lb 648 m


years in 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. Then as valves are placed progressively deeper in the well a gradient from valve to valve is assumed based on lower productivity. An alternate sometimes used is to space on an assumed productivity until some minimum mandrel spacing 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 though this 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 expected system pressure substantially lower than actually exists at this time. In some cases, it is possible to skip mandrels and place the valves at the next lowest mandrel. The process continues downhole in this manner: from the previous 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 INTERMITENT FLOW GAS LIFT

The technology for predicting continuous flow gradients of fluid being produced into the surface equipment has developed greatly over the last 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 lift 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 injected gas is 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 through accumulating liquid head during the build up period and moves on up the tubing. All gas used in the lifting process must be supplied.

2. Continuous gas lift produces at a relatively constant rate. Although gas lift is in the slug flow regime, the slugs are usually relatively small in size and production rate to the separator and other surface facilities is fairly constant. This is not the case with intermittent 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. In continuous gas lift, the gas is injected at a relatively constant rate. This can be done in intermittent lift 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 relatively 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 completions became fairly widespread during the 1960s primarily because of very restrictive allowables. When artificial lift became necessary, dual gas lift was one of the more common methods selected. Although dual gas lift is one of the best methods of dual artificial lift, it is usually very inefficient.

As mentioned earlier, the well productivity must be estimated 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 tubing strings 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 in 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 significantly different operating characteristics - injection 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 artificial lift is required.

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A P I T ITLE*VT-h 94 0732290 0532937 584

84 Gas Lift

CHAPTER 7 ANALYSIS AND REGULATION OF CONTINUOUS

FLOW GAS LIFT

INTRODUCTION Continuous flow gas lift makes up the vast majority (90

percent) 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 controlled. These principles are generally applicable to production 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 the terms 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 the 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 in the well fluids can damage the gas lift valve seats and/or may result in valve malfunction during unloading operation. If valves are injection gas pressure operated, reverse circulation should not be used since circulation will occur through the valves. If mud or dirty fluid must be circulated out, some type of circulating valve

T V W A L T- FLOW aOIIWAT*:

T V W A L CA.- r 1,

I I L

Fig. 7-1 - Casing 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 the wellhead and the tank 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 lift installation in the system.

Recommended Gas Lift Installation Unloading 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 excessive 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 8-10 minutes for a 50 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 gas pressure. 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 this time 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 gas rate to the full designed rate for the well. ing data will be used:

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 the installation. In many instances the operator is content to leave the well alone as long as he thinks it 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 in an attempt to produce more oil from the well. Excessive 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. Measurement 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. Pressure surveys

2. Temperature surveys

There are several methods which may be used for obtain- 3. Fluid level determination by acoustical methods

ing a proper analysis of a gas lift installation. In most 4. Computer calculated pressures in the well

METHODS OF OBTAINING SURFACE DATA FOR CONTINUOUS FLOW GAS LIFT WELLS

Recording Surface Pressure in the Tubing and Casing

Two-pen pressure recorders are relatively inexpensive instruments using two pressure elements of the proper pressure range to record the surface tubing and casing pressures of the well. This 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 range of the recorder should be ' /4 to '/3 higher than the maximum operating pressure of the well. For example, if the maximum wellhead pressure is 700 psig, the recorder should have 1,000 psig maximum range elements. This will permit sufficient sensitivity in the instrument to indicate any small pressure change on the chart.

Some of the important factors to be noted from the recordings* of tubing and casing pressures are:

1 . Increased flowing production pressure would indicate an increase in separator back pressure, paraffin deposition, or sediment in the flowlines. It could also indicate that a choke has been installed in the flowline, an increase has been made in the volume of injection gas, another 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 or volume, injection gas freezing, fluctuating system gas pressure, the well having been switched to a test separator, readjustment of the injection gas control, or a broken flowline.

*Charts 7A1 through 7A14, Appendix 7A, illustrate some of these conditions. The actual problems encountered are those given in the chart interpretations. Other interpretations might be given if the exact trouble is not known.

3 . A continuous flow well on production pressure control would have the periods of gas injection and the periods of natural flow recorded. (Production pressure control is a means of injecting gas into the well at a predetermined drop in production pressure, utilizing the gas lift valves to purge the tubing of 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

Measurement of injection gas volumes is necessary in order to determine the efficiency of 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 condensation from collecting. Some companies favor a permanent meter 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 pressure element indicating the line pressure from the orifice plate, and a differential pressure element indicating the pressure 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 injection and carefully measuring the total fluid production against the injected gas volume for each change, thus providing a means of determining the most efficient gas oil ratio.

Fig. 7-2 - Continuous flow semi-closed installation

The static pressure element on the meter is useful in determining any pressure fluctuation in the gas system that may be detrimental to the efficient operation of the gas lift. Orifice meters are installed at the test separators to measure the total gas out of the well under test. The difference in 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 of the produced fluid at the wellhead 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 effect on 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 temperature gradient when the bottomhole temperature and flowing surface temperature are known. The depth location of each valve 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 temperature and gas weight corrections. These charts may be used to determine the surface operating pressure of each valve. Fig. 7-3 illustrates a continuous flow well that is not producing at its capacity because the producing fluid temperature has raised the pressure of the operating valve to near system pressure. The producing fluid temperature has raised the pressure of the valve (at 1,900 ft.) 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 that are not affected by temperature.

Visual Observation of the Surface Installation

Visual observation of a gas lift installation may sometimes uncover conditions that are detrimental to the overall efficiency of the installation. Maintaining high separator back pressure, long or improperly designed flowlines, restrictions in the wellhead, paraffin or sediment in the flowlines, and too many sharp-angled bends may be the cause of excessive back pressure as indicated by the production

TUBING CASING BDO

I

TEMPERATURE l05'F

6ooo 41; 200 400 600 800 1000 1200 1400 1 6 0 0 leo0 2& 2xK) 2400-m

2000 2510 DESIRED FLOWING PRESSURE -

PSIG FLOWING 6.H.PRESS.

DESIRED PRODUCTION i 1,200 B I D TOTAL FLUID PRESENT PRODUCTION: 465 B/D TOTAL FLUID

STATIC BOTTOM-HOLE PRESSURE : 2,800 PSlG PRODUCTIVITY INDEX (PI1 2 1.5 TUBING SIZE i 2-718-11 EUE BOTTOM-HOLE TEMPERATURE : !72 F PRESENT FLOWING SURFACE TEMPERATURE. 105 F SYSTEM GAS PRESSURE AT WELL: 610 PSlG

Fig. 7-3 - Continuous flow equipment problem for tubing flow well



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A P I T I T L E * V T - h 94 m 0732290 0532920 07’7 m Analysis and Regulation of Continuous Flow Gas Lift 87

wellhead pressure. The possibility of wet gas freezing at sary for the proper analysis of the operation of a gas lift points of restriction, fluctuating system gas pressure, an well. In many field installations only oil production is meas- insufficient differential between system gas pressure and ured and a shakeout is taken to determine the percentage of wellhead operating pressure, and improper surface control water. This can be very inaccurate in many wells because of for the type of gas lift 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- Testing Well for Oil and Gas Production mation is essential to determine the efficient point of gas

Accurate gauging for oil and 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 good means of properly analyzing gas lift installations. A static survey will determine the static bottomhole pressure (or formation pressure), the static fluid level, and the static gradient of the well fluids. A flowing pressure survey will locate the point of gas injection, leaks in the tubing, valve failures, or multi- point injection. It will also determine the flowing gradient below and above the point of 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. It is a common fallacy to wait until trouble develops before making apressure survey. The survey might locate the source of trouble, but the information necessary to improve the installation will not be obtained. Therefore, a pressure survey should be run while the well is supposedly performing 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 producing from a very active water drive reservoir, it is recommended that valves be spaced close together near the estimated point of gas injection. A very common error in gas lift design is failure to space the 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, however, immediately evident from the flowing pressure survey that by respacing the valves there would be an increase in fluid production. It was noted that the fluid level in the casing lacked only a few feet of uncovering the next valve with the available line pressure. In 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, it was possible to relocate valves 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, the spacing was satisfactory for 1’12 to 2 years.

O

1000

2000

3000

k! 4000 r

k W

k 5000

n

6000

7000

8000

I T C o s i n g Pressure Flowing

Tubing = 2;’ - \c I 1 Fluid = 1000 B b l s / O o y

Input G o s - Fluid Ra t io = 400/1

””

Casing Fluid Level

9000 I I I I I l I I O 400 800 1200 1600 2000 2400 2800

PRESSURE, PSlG

Fig. 7-4 - Valve 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 injection is very inefficient, since efficiency in continuous flow is the result of injecting the proper volume of gas at the deepest point for the available pressure. The flowing pressure gradient indicated that 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 pressure survey 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 well in which it seems that too many gas lift valves were used for the installation. This well was



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A P I T ITLESVT-6 94 0732290 0532921 T05 D

88 Gas Lift

TUBING = 2" FLUID = 700 BBLS. / DAY

INPUT GAS-FLUID RATIO = 800- I

I

2000 I \ VALVF DLP-Ta

3000

4000

2400

1"" -2. 2850

. 3300

MULTI -POINT 5000 GAS INJECTION

m@ I o &o lobo tim &;FLOWING B.H,PRESS.

PRESSURE PSlG

Well Data: 2% in. OD tubing in 5% in. casing Gas-liquid ratio - 8OO:l Production 700 bblfluid per day Oil production = 120 B/ D

Fig. 7-5 - Flowing pressure survey for valve repair

O

1000

2000

3000

k! 4000

I- W

I I- ; 5000 o

6000

7000

8000

r Casing Pressure Flowing

Casing Fluid Level

-

-

-

90001 I I I I 1 I O 400 800 1200 1600 2000 2400 2800

PRESSURE, PSlG

Fig. 7-6 - Flowing pressure survey for valve spacing

designed for either continuous flow or intermittent flow gas lift. Under the present operating conditions, four valves would be enough to take care of the well. This was a well, however, in which the water percentage was expected to increase 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 tubing leak. The tubing leak 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.

PRESSURE IN 100 PSlG 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 - - Iniection Gor Prrssurr

W

IA 2500

z 3000 I t- 3500 W

4000

4 5 0 0

a

" V.I*e t 1935'

5000 1 Flowing BHP = 1770 p i g

5 5 0 0 - - - - - __ T.D. = 5540'

WELL DATA:

INJECTION GAS-LIOUID RATIO = 5 5 0 : l 2-IN. TUBING IN 5-112-1N. CASING

PRODUCING WELLHEAD TUBING PRESSURE = 110 PSIG SURFACE INJECTION CASING PRESSURE = 640 PSlG PRODUCTION = 640 B8L FLUI0 PER DAY OIL PRODUCTION = 5 B / D

Fig. 7-7 - Flowing pressure survey to locate tubing leak

A pressure survey of a casing flow gas lift well can be used to determine the point of injection. Fig. 7-8 shows the 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. The well was producing 4,000 bbl of fluid per day at the time the pressure survey was made, of which 97 percent was salt water. The gas liquid ratio was very efficient at 90 CU. ft. of gas per barrel of fluid. The well was



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‘ A P I TITLE*VT-6 94 m 0732290 0532922 941 m


producing its depth allowable of 120 bbl of oil per day under these conditions. However, it was capable of producing 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 PRESSURE

‘ ~ T U B I N G PRESSURE

VALVE DEPTH

OF TUBING - 4000 FT.

2000 3945 PRESSURE PSlG FLOWING

6.H.P

WELL DATA: 2 - I N TUBING IN 5-112-IN C A S I N G INPUT GAS-FLUID RATIO i 90.1 PRODUCTION i 4 0 0 0 BBL F L U I D P E R DAY’ WITER PROOU(T1CN. 91 PERCENT

Fig. 7-8 - Flowing pressure survey of casingflow 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 when 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 flowing wing 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 to 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 some high volume wells with small tubing, it may be necessary to shut the well in and run the gage to bottom as

fast as practicable. The well then must be returned to stabilized 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 surface, caution should be taken when a lightening 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 the gage safely retrieved. The important 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 performance of continuous flow gas lift wells. The usual first objec- tion to this concept is “those computer programs don’t match the well pressures where I come from.” But the computer calculated results can be made to fit “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 available 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 updating PI data.

The prudent operator will make use of computer calculated 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 temperature 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 temperature in a gas lift well. It is interesting to note the comparison of the test rack opening pressure of the valve to the 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 leaks as 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-FLUID RATIO = 200- I VALVE OPEN I NG AT

VALVE TEST DEPTH WRFPCE

2 4 "y I í'o00 990 1150 I100 I DEPTH PRESS.PFESS. PRESS.

6ooo O 500 1000 1500 2OOO 1 0 0 165O

PRESSURE PSIC. TEMPERATURE F.

Fig. 7-9 - Temperature andflowing pressure survey of 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 information 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 combination, with the temperature instrument being at the bottom.

3. Use enough sinker bars to assure that the instruments will move forcefully down the hole and not be pushed up the hole by the flowing fluid.

4. Make the following stops recording the time and depth reading at each stop.

a. At the surface.

b. One or two stops between mandrel stations.

2 3 4

Fig. 7-10 - Typical 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 the plotting of a typical pressure and temperature survey and easily identifies the operating valve or the depth of injection.

Fluid Level Determination by Acoustical Methods

One of the most common and economical methods of locating the fluid level in the annulus of a tubing flow continuous 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, the 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 operating valve would be directly above. However, i n a well containing a packer. It may be that the well originally unloaded to a lower valve; and, as the formation fluid entered the well, the formation gas supplemented the injection gas, permitting the opening of an upper valve. With the 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 operating 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 collars, 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 interpretation 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 in 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. In many cases choking may cause freezing problems. This can be rectified by using a dehydrator 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 to pass over the gas line, thus acting as a heat transfer unit.

Fig. 7-12 - Choke-regulator control, tubing flow well

CAUTION: THIS SYSTEM WILL WORK ONLY WHEN THE REGULATOR CAN BE SET HIGER THAN OPERATING INJECTION GAS PRESSURE (gas pressure in casing

Fig. 7-11 - Choke control, tubing flow well downstream 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 recommended for most types of continuous flow gas lift valves where there is a fluctuating gas system pressure. The regulator 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 installation. 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 - Production pressure control of the injection gas, tubing flow well

WELL INJECTION GAS PRESSURE FOR CONTINUOUS FLOW SYSTEMS

For many years it was a general rule that continuous flow gas lift needed a well injection gas pressure of 100 psi/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 bottomhole pressures as high as 2300 psi.

Gas lift valves are easily adaptable to 1400 psi well gas pressures and several vendors have valves for 2000 psi and higher gas systems.

GETTING THE MOST OIL WITH THE AVAILABLE GAS LIFT

The efficient distribution of circulated gas to each well promise for efficiency, but progress with this method is on gas lift is of 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, it will 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 following chapters. Manual Controls

The details of this component will be discussed as related These controls are the least efficient because they require to the method of control exercised by operating personnel. manual changes in adjustment when any system parameter The methods generally used are manual and semi-automatic changes, and because their duration of efficiency is only as control. A few companies have implemented 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 TITLE*VT-b 9Y 0732290 0532qE‘b 597


A gas injection choke is commonly used for continuous flow and sometimes for intermittent lift. Chokes in intermittent lift wells are usually used only when pilot or production 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. Pcr stays constant because it is partially controlled by the gas lift valves. But if P, increases, inefficiency is introduced because the choke will pass more gas than needed. If P, decreases, the choke will reduce the volume of gas circulated and the volume of produced fluid will be reduced.

Semi-Automatic Controls

The manual surface controls may be improved by installing 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 component 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 pressure varies. The gas rate to the well is a function of Pg2. An increase in Pg will not be harmful.

Basically, the semi-automatic controls preserve efficient gas control as long as the injection gas pressure (Pg) remains constant or increases. Efficiency is maintained with a limited (and defined) decline in P,, but there is still no protection against an excessive decline in P,.

r high pressure gas source

Optimizing Gas Lift Systems

The gas controls discussed previously have been improved to the point that they remain efficient until a defined loss in injection gas pressure (P,) is reached. Therefore, if operating personnel can reduce 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 lift system is optimized when the maximum possible barrels of oil are produced with the available circulated gas volume.

1. Establish Priority System

To accomplish this, the operating personnel must establish a priority system defining which wells get circulated gas when there is a shortage of circulated gas volume. The best basis for a priority system is the circulated gas-oil ratio (or the injected gas-oil ratio, IGOR) for each well in the system. Each time a well is tested the following data are available:

BOPD - barrels of oil/day (qo) BWPD - barrels of water/day TGAS - total gas from test separator, standard cu-

IGAS - lift gas circulated to the well, SCF/D (ig) FGAS - formation gas produced, SCF/D

After the test, calculate IGOR (Rgoi=ig/qo). The well that has the lowest IGOR has top priority for circulated gas. Every effort should be made to circulate the required gas to this well as long as any gas is available.

bic feet per day (SCF/D)

.

Meter run Choke 7 Pcf

1

c L

‘ I Fig. 7-14 - Manually adjustable or positive choke

pressure reducing regulator / Choke

Fig. 7-15 - Pressure reducing regulator and choke



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A P I T I T L E t V T - b 94 m 0732290 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 they should be the first wells to lose circulated gas when the gas volume is reduced due to a loss in injection gas line 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 recognized by the pressure. Table 7-1 illustrates logical conclusions.

TABLE 7-1 STATUS OF HIGH PRESSURE GAS SOURCE

Pressure of Logical Status of High H.P. Gas Symbol Pressure Gas Source Source

Normal N All is well - circulated 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 GAS

Status of H.P. Action

SBN Reduce or stop circulated gas to wells with highest IGOR’s until status returns to AN. Then restart gas to wells in ascending priority numbers until status returns to N.

DBN Stop circulated gas to wells with highest 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 circulated 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-AUTOMATIC ACTION TO OPTIMIZE USE

OF CIRCULATED LIFT GAS

Status Action

N All wells taking gas as adjusted by operating personnel

SBN Gas is stopped to high IGOR wells w/auto reopen. No gas will go to them until status recovers above SBN. These wells will then automatically start taking 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 circulated gas. Operating personnel must personally reset the other wells before circulating gas will be restarted to them.



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Automatic Optimization of Injection Gas Use

Manual and semi-automatic optimization plans are keyed to trigger action only on a loss of pressure in the high pressure gas sources. Their inherent weakness is that they rely completely on the operating personnel to recognize changes in the well’s characteristics or malfunctions in the subsurface equipment. With today’s technology, microprocessors and computers may be used to monitor the well’s performance, evaluate the status of downhole equipment, measure the volume of high pressure gas available

and distribute lift gas in the most efficient manner automatically.

A few companies have already used parts of this technology. An even fewer number have plans to implement completely automatic optimization systems. But automatic gas lift systems can be an economic field proven reality. Until then, operating personnel must do the best they can with manual and semi-automatic surface gas controls, and optimization plans, to get the most oil with the available lift gas.



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A P I TITLE*VT-b 9q W 0732290 0532929 2Tb W

APPENDIX 7A EXAMPLES OF PRESSURE RECORDER CHARTS FROM

CONTINUOUS FLOW WELLS

Operation: Continuousflow, casing choke control, tubingflow Type of well: High productivity, high bottomhole pressure Trouble: None Recommendation: Leave well alone Type of gas lip valves: Injection pressure-operated Remarks: Good continuous flow operation. Well has a high working fluid level.

Note the low back pressure effect. Well producing 2,100 bbl offluid per day - 95 percent water - f r o m water drive reservoir, through 2% in. tubing.

Chart 7-Al

Operation: Continuous flow, casing pressure control with regulator, tubing flow Type of well: High productivity, high bottomhole pressure Trouble: Inadequate production Recommendation: Reduce back pressure Type of gas lijit valves: Pressure operated Remarks: Excessive back pressure may be due to one or more of the following:

1. 2. 3. 4. 5. 6. 7.

Choke inflow line Restriction inflow line (paraffin, snnd, etc.) Flow line too small or too long Separator pressure too high Too many sharp bends inflow line Highly emulsifiedfluid Excessive input gas

Chart 7-A2



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Examples of Pressure Recorder Charts from Continuous Flow Wells 97

Operation: Intermittent injection vs. continuous injection, tubing f low Type of well: Borderline production rate Trouble: Inadequate production Recommendations: A n intermittent and continuous flow production comparison Type of gas lqt valves: Pressure operated Remarks: Compare intermittent to continuous flow to determine most efficient production rate

Chart 7-A3

Operation: Continuous flow, casing choke control, tubing f low Type of well: High productivity, high bottomhole pressure Trouble: None Recommendations: Leave well alone Type of gas l$t vulves: Injection pressure-operated Remarks: The well had been shut in overnight, and thegas had been turned on shortly before the chart was changed. The

casing pressure was at 46Opsig at the beginning at 10:15 a.m. There was agradualpressure rise to 468psig due tofluid temperature increase affecting valve. A t 2:45p.m. the casingpressure increased to 48Opsig and a “kick” can be noted on the tubingpressure. This was due to an upper valve becoming the operating valve. A t I0:OO a.m. the next morning the casing pressure had increased to 490 psig due to temperature effect.

Chart 7-A4



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98

A P I TITLE+VT-b 94 m 0732290 0532933 954 m

Gas Lift

Operation: Continuous flow, casing choke control, tubing flow Type of well: High productivity, high bottomhole pressure Trouble: Choke on gas line froze Recommendations: A gas heater might be installed ahead of the choke, or a jacket might be welded around the choke to

permit the hot flowline fluids to pass 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, tubingflow Type of well: High productivity, high bottomhole pressure Trouble: None, well is flowing Recommendations: h a v e well alone Type of gas lìjt valves: Pressure operated Remarks: Well is flowing; no gas is being injected

Chart 7-A6



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A P I T I T L E + V T - b 94 m 0732290 0532932 890 m

Example of Pressures Recorder Charts from Continuous Flow Wells 99

Operation: Continuous flow, casing choke control, tubing f low Type of well: High productivity, high bottomhole pressure Trouble: Well was closed in to repairflow line Recommendation: None Type of gas lyt valves: Pressure operated Remarks: When the master valve was opened the tubing pressure was 250 psig. Flow immediately started but the

pressure declined to 210 psig at the peak of U-tube. As the gas cleared through the gas lift valve the tubing pressure increased to a maximum of 345 psig, then fell off andfinally stabilized at 285 psig.

Chart 7-A7

Operation: Continuous flow, tubing control, tubing f low Type of well: High productivity, high bottomhole pressure Trouble: Well is flowing, but loads up with water periodically Recommendation: Operating satisfactorily Remarks: The tubing control element is set to inject gas into the well when the pressure decreases to 160 psig. It can be

noted by the rise in casing pressure opposite the drop in tubing pressure

Chart 7-A8



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Operation: Continuous flow, casing choke control, tubing flow Type of well: High productivity, high bottomhole pressure Trouble: Well is being tested in test separator Recommendation: Remove high normal back pressure, or test against same high back pressure for accurate flow test Remarks: It would be impossible to have an accurate production test on the well under the above conditions

Chart 7-A9

Operation: Continuous flow, casing choke control, tubing flow Type of well: High productivity, high bottomhole pressure Trouble: Well is closed in Recommendations: Check to see why it is closed in Type 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: Continuous flow, casing choke control, tubing f low Type of well: High productivity, high bottomhole pressure Trouble: Not serious, well is “heading” Recommendation: Check to see if system gas pressure fluctuates Type of gas lift valves: Pressure operated Remarks: Reasonably good operation. Well has a tendency to “head, ”which could be caused by erratic valve operation

or afluctuating system pressure.

Chart 7-Al I

A choke was used on thegas line to control thegas volume into the casing-tubing annulus. When thegas wasfirst turned on, an immediate surge offluid returned from the tubing as the well was completely full of salt water. When the liquid volume displaced in the annulus stabilized to thegas volume rate of the injection gas, the tubing pressure remained at 50 psig until the top valve was uncovered and gas entered the tubing. A surge in tubing pressure is noted as each valve is uncovered. The wellfinally stabilized on the 4th valve.

Chart 7-Al2 - Unloading continuous f low well



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A P I T I T L E x V T - 6 94 m 0732290 0532935 5 T T m

102 Gas Lift

CHAPTER 8 INTERMITTENT 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 that can be lifted efficiently with continuous flow. Minimum liquid rate usually occurs at about 100 to 150 BLPD in 2 3 / ~ “ tubing, 200 to 300 BLPD in 27/~“ tubing and 300 to 400 in 3‘/2’’ tubing. When the minimum rate is reached, then intermittent lift should be considered. However, there may be a broad range of lower production rates where the two types of gas lift are about equal. In such a case, there would be little justification for change unless there were other contributing factors. Usually intermittent lift is conducted in 23 /~“ tubing; however, there are many successful installations using 27/~” and 3’/2“ tubing.

Intermittent lift is a displacement process. High pressure gas is injected into the liquid column on a cyclic or intermittent basis creating a gas bubble which expands pushing the liquid above it to the surface in a slug. While it is normally associated with low volume producers, intermittent lift has successfully lifted wells at rates in excess of 500 barrels of liquid per day (blpd), although such a rate could probably have been lifted 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 lift should achieve lower average flowing bottomhole pressures than can be obtained with continuous 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 instantaneous gas injection rates separated by periods of no gas injection. With time cycle control, the cyclic high instantaneous injection gas demand rate from the injection line is hard 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 compressors are not well suited to a “flow-no-flow” set of conditions. Because of this problem, the volumetric capacity of the injection system should be large so it can act as an accumulator to help smooth out the flow surges. Gas measurement 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 maximum 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- l . In (A), formation liquids accumulate 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 gas into the tubing- casing annulus. This increases the gas pressure in the annulus until this pressure and the liquid pressure in the tubing are sufficient to open the operating valve. All the rest of the valves remain closed because the gas pressure alone is not sufficient to open the valves. Gas is injected very rapidly into the liquid column creating a gas bubble. As the bubble expands, it pushes the liquid above it to the surface. In (C), the liquid slug has reached the surface at which 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 in the tubing.

Several things are apparent from this explanation. (1) The gas should be injected rapidly. If not, it will just bubble up 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 the bottom 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 the 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 should be large in diameter and short in length. Small diameter, long flowlines are very detrimental to intermittent lift installations because they cause high wellhead pressures. This problem can sometimes be reduced by decreasing the maximum injection gas cycle frequency in high PI wells.



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I API TITLErVT-b 94 m 0732290 0532736 436 m Intermittent Flow Gas Lift 103

[A) Immediotcly Before Gar Injection

Volve Closed

Valve Closed

Volve Closed

Valve Closed

Opereling Volve Open

Volve Closed

V o l v e Closed

Volve Open Opcroting

[C) Injection Cos Entering Tubing Through Volve After Controller Closed

[D) After Gor Injection

Fig. 8-1 - Intermittent lift cycle of operation for conventional closed intermittent installation

TYPES OF INSTALLATIONS

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 standing 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 making it difficult if not impossible to pull.

The other two types of installations (open and semi- closed) will allow the high pressure gas to act on the formation thereby decreasing the efficiency of the lift. An open installation without a packer is not recommended for intermittent lift.

FACTORS AFFECTING PRODUCING RATE

The primary factors affecting the maximum producing rate Maximum Rate in 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 ITLE*VT-b 94 m 0732290 0532937 372 m

104 Gas Lift

installation to installation but 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, the gas alone does not sweep all of the liquid out of the tubing from the operating valve to the surface. 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 to bubble up through the liquid allowing some of the liquid to drop back down. Fallback can be defined 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 wellhead.

1. Development of the Gas Bubble

If the operating valve has a small port or tends to throttle open rather than snap open, gas will enter slowly and tend to rise up through the liquid without providing much lifting action. Gas should enter the tubing quickly to form the gas bubble and to accelerate the liquid slug up the tubing. Consequently, large-ported, snap-acting gas lift valves are

recommended for the operating valve for intermittent flow 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. A minimum slug velocity of 1000 feet per minute 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 a tee to the wing valve, then through another 90" ell or choke tee, then 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 of the tree and then through a sweeping pipe bend to bring the flowline back to the ground as shown in Fig. 8-3.

For estimating purposes, the fallback on a properly adjusted intermittent lift well will be about 5 to 7 percent of the starting slug per 1000 feet of lift.

STARTING LIQUID SLUG AND FALLBACK

TO SEPARATOR

STARTING SLUG t-

TO SEPARATOR

INJECTION GAS

L

". '' ' '1 I OPERATING VALVE

PRODUCED SLUG

FALLBACK

\I

INJECTION GAS

. , OPERATING VALVE *.

AJST AFTER CLOSING

FALLBACK = STARTMG SLUG - PRODUCED SLUG

Fig. 8-2 - Illustrations of starting slug, produced slug, and fallback



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API TITLE*VT-b qq 07322qO 0532938 207 m Intermittent Flow Gas Lift 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, minimizing 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 bottom or 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 designed plungers for wells with sidepocket mandrels are avail-

Fig. 8-3 - Streamlined wellhead for intermittent in- able. For additional information on plungers, see the use of stallation 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 of the tail gas, liquid fallback, and liquid feed-in to predict the minimum tubing pressure obtainable. This average gradient 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 closing pressure for all valves except the Operating 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 valve should be 59 percent of the gas pressure at the operating valve, at the instance the valve opens, for the most 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 pressure 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 pressure 100 psi less than the surface injection pressure will be on the safe side and account for fluctuations in gas pressure.

Because of the normally low, irregular producing rates in intermittent lift wells, the temperature gradient for design purposes is assumed to be geothermal. Also for intermittent lift design purposes, the surface temperature usually is assumed to be 74°F in the U.S. Gulf Coast which is approximately the temperature that would be measured about 50 feet below the ground level. However, surface temperatures vary 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 lift wells. The spacing factor accounts for the increase in pressure 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 TITLE*VT-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 Graphical Solution Using Fallback 5. Method:

A graphical solution is the easiest way to solve the prob- 6. lem. The following is a step-by-step procedure.

1.

2.

3.

4.

Prepare a sheet of graph paper 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 (unloading gradient) for the particular well from Fig. 8-4. This is a function of the anticipated production rate, tubing size, etc. (In this example it 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 this pressure to the 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 100 psi from the surface injection pressure and plot this as the surface closing pressure of the unloading valves (550 psig).

Extend the pressure to the bottom of the well 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 - Intermittent lift spacing factor



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API TITLErVT-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 from 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 (1 300 ft.).

13. Draw a horizontal line to the left to the spacing factor line plotted in step 4.

14. From the intersection of the horizontal line and the spacing factor line, draw a 0.465 psi/ft gradient line to intersect the P,, line to locate the depth of the second valve (2300 ft.).

15. Continue this procedure to 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:

PVC P,, =

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 4 6 8 70 80 90 100 110 120 130 140 150

Depth

1300 2300 3200 4100 4800

C, = 0.841

PVC Temp. c, p v o "- - 668 07 0.038 665 578 107 0.008 655 688 121 0.884 650 600 136 0.860 646 600 148 0.841 640 Uee 616 PSlG

Fig. 8-5 - Example of graphical solution using fallback method



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108 Gas Lift

18. Decrease the set pressure of the 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 general method 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 pressure at the valve at the instant the valve opens for efficient lift. This then becomes the basis of 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 in Fig. 8-6.

PRESSURE - 100 PSlG

2. Plot wellhead pressure ( 6 5 psig) at zero depth (surface).

3. Plot the surface gas injection pressure (650 psig).

4. Extend this pressure to the bottom of the well accounting for the 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 the bottom (0.6 x 20 = 432 psig at 5000 ft.).

7. Extend a 0.465 psi/ft gradient line from the wellhead pressure (65 psig) at the surface to the gas pressure at depth line to locate the top valve (1300 ft.).

8. Draw a horizontal line to the left to intersect the percent load line.

TEMPERATURE - OF

O

1

I- W

k!2

: 2

t 3

O O

I

W n

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 "

401 6(10 406 677 411 686 416 673 421 702 426 716 432 710

Pbt Temp.

614 91 622 100 630 110 637 120 646 120 867 139 661 149

" Ç -

0.936 0.92 1 0.903 0.886 0.87 1 0.856 0.839

- pvo

720 716 710 706 706 700 676 Use 670 PSKi

Fig. 8-6 - Graphical solution using the percent load method



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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 procedure to the bottom of the well. Variations of Percent Load Method Fig. 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. Probably gas Pressure at depth line and the Production Pres- the most commonly used procedure is called the 40 - 60 Sures (PP) on the Percent load line at each valve 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, spacing Determine the temperature at each 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: Still another procedure is a combination of the fallback ~~~~~i~~ 8.3 and percent load methods. Valves are spaced from the

surface using the fallback method until drawdown is Equation 8.4 achieved. Then the 60 percent load method is used from

Pbt = Pg (1 - Ap /Ab) + Pp (Ap /Ab)

(Pd (cf) P"" = 1 - (Ap /Ab) there to the bottom of the well.

For a spring loaded valve the equations are: Production Pressure Operated Gas Lift Valves

Psp = Pg (1 -Ap /Ab) + Pp (Ap /Ab) Equation 8.5

P", =

The foregoing examples of intermittent lift design are intended for use with injection pressure operated gas lift

PS, Equation 8.6 valves. Production pressure operated gas lift valves have 1 - (Ap /Ab) also been used in many intermittent gas lift installations.

Where:

Pbt = Pressure in bellows at temperature at valve depth, psig

PP = Gas pressure, psig ppd = Production pressure at valve depth 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 lift valves are used in 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 150 psi to 300 psi of the 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 pressure 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 static gradient of 0.465 psi/ft and a 250 psi 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 feet. This close spacing results in 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 installation. 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 column of liquid. Fig. 8-7 shows 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 annulus above the liquid to the tubing to prevent gas locking the annular portion of the chamber. At a predetermined time,

the time cycle control at 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 the bleed valve. As the gas pressure continues to increase, the liquid in the annulus is pushed down through the perforated 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 liquid into the tubing forcing the liquid to the surface. At this time



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110 Gas Lift

the chamber valve closes, the tail gas bleeds off, the bleed valve opens and liquid again enters through the standing valve.

The bleed valve can be either a differential gas lift valve set at 50 to 100 psi or a ‘kin. hole in a collar. Some chamber valves have the bleed feature built into them eliminating the need for a separate bleed valve.

Above the chamber, the installation is a standard intermittent lift installation. The bottom unloading valve must be only one joint of tubing above the chamber valve otherwise the 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 the chamber empties to 60 percent of the gas pressure (Pg) at the chamber valve.

P w h i- H y d = 0.60 (PB) Equation 8.7

H y d = 0.60 (PP) - P w h Equation 8.8

UNLOADING GAS

BOTTOM UNLOADING GAS LIFT VALVE

HANGER NIPPLE FOR DIP TUBE

OPERATING CHAMBER GAS LIFT VALVE

STANDING VALVE

Fig. 8-7 - Insert 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:

H Rct + 1.0 CL = Equation 8.10

Rct + - v,, Vt

Equation 8.11

Where:

Rct - - Ratio of Annular Volume to Tubing Volume 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 of 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 UNLOADING GAS L IFT VALVES

OPERATING CHAMBER GAS LIFT VALVE

Standing valve modified f a r

( 0 )

Fig. 8-8 - Two-Packer chamber installation



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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 8.6 1 - (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 it immediately after the slug surfaces.



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CHAPTER 9 PROCEDURES FOR ADJUSTING, REGULATING AND

ANALYZING INTERMITTENT FLOW GAS LIFT INSTALLATIONS

INTRODUCTION

The difference between efficient and inefficient operation of an intermittent flow gas lift installation depends largely upon the means employed to control the injection gas volume to the well. This chapter describes different equipment applications and techniques for injection gas control. In addition, procedures are offered to assure unloading an intermittent installation without damage to the gas lift equipment.

The control of the injection gas for an intermittent installation can be divided into two main categories, viz., time cycle and choke control. The time cycle control with high pressure cutoff, choke control, a pressure reducing regulator, and other pieces of equipment are only variations of the two categories, but these refinements are necessary for some installations to assure the most efficient operation.

Recording of the casing and tubing pressures is recom-

mended during unloading and for a daily re CO - - ~ -#rd of the gas 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 a good indication of the overall operation and proper adjustment of the injection gas volume. For most installations this velocity should be 800 to 1200 ft./min. to assure maximum liquid recovery per cycle.

Increasing the injection gas volume does not always increase the daily production rate from an intermittent installation. Correct regulation of the injection gas volume per cycle, cycle frequency, and other conditions such as paraffin, wellhead chokes, etc., can appreciably affect the daily producing rate and gas requirements.

CONTROL OF THE INJECTION GAS

The Time Cycle Controller

The time cycle operated controller is the most widely used means of injection gas control for intermittent lift installations. Completely automatic time cycle controls containing microprocessors, liquid crystal displays, and long life batteries are now available for controlling the injection gas cycle. These electronic timers are replacing many clock driven pilots. They improve accuracy for adjusting the duration and frequency of the injection gas cycle, and there is less chance of a controller not closing due to clock stoppage. However, the old mechanical time cycle pilot which automatically actuates a motor valve (Fig. 9-1) on the injection gas line at desired set intervals is probably still the most widely used type of surface control. The time cycle pilot usually consists of a timing wheel that is clock driven. The number of gas injection cycles per day is varied by adding or eliminating timing pins, pushing back timing clips, etc., on a timing wheel, depending upon its construction. The cycle frequency may also be changed by using different clocks such as 2-hour, 4-hour, etc., rotation. The duration of gas injection is changed by certain adjustments in the time cycle control.

Time cycle control of the injection gas is applicable for most intermittent installations and is recommended particularly 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. 9-1).

ADJUSTMENT FOR

REVERSE ACTING PRESSURE OPENING

MOTOR VALVE

Fig. 9-1 - Time cycle controller for intermittent gas lift installation



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Procedure for Adjusting, Regulating and Analyzing Intermittent Flow Lift Installations 113

In small rotative gas lift systems, time cycle control is undesirable because of 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 to stagger the period of gas injection. The central timer has a timing wheel for each intermittent installation and the individual motor valve on the injection gas line is opened and closed by a solenoid valve which is actuated by its corresponding timing wheel. Electronic timers can eliminate the need for a central timer. The accuracy of the quartz movement in an electronic timer allows precise staggering of the injection cycles for several wells. When installations will operate with choke control of injection gas, high-rate injection gas removal from the 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 pressure and may result in a lower overall lift efficiency. The injection gas line cannot be included as part of the high pressure storage unless the controller is at the well.

Choke Control of the Injection Gas

For choke control of an intermittent installation, the required injection gas is delivered into the casing through a small choke or metering valve in the injection gas line. These installations may have injection gas or production pressure operated valves. If gas pressure operated valves

are used, the valves must have the desired spread and operating characteristics needed for choke control based on the casing and tubing size. Pilot operated gas lift 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 for small rotative systems because the injection gas demand rate is constant. Smaller injection gas lines can be used and the surface equipment is less expensive than that required for time cycle control. Accurate measurement of the injection gas is 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 for the 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 injection gas line, and well deliverability will hamper or prevent choke control. If the injection gas is wet, a dehydration unit 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 lengthy period of time is required for any appreciable volume of liquid to pass through 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 time.

Straight choke control of the injection gas is not recommended for very low productivity or extremely high capacity 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 the maximum slug size and cycle frequency.

UNLOADING AN INTERMITTENT INSTALLATION

The intermitting cycle is described in Chapter 8. This lation, it is likely that the damage to these valves occurred section supplements the operations discussed in that chap- during unloading. ter by outlining procedures and considerations which are Recommended Practices Prior to Unloading important to the operators in order that damage to equip- The recommended practices prior to unloading intermit- ment may be eliminated and efficient unloading operations tent lift wells are the same as given in Chapter 7 for con- assured. If gas lift valve seats leak in an intermittent instal- tinuous flow wells.



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114 Gas Lift

Initial U-Tubing

Until the top valve is uncovered, injection gas pressure exerted on top of the liquid column in the casing causes fluid from the casing to U-tube into the tubing through open gas lift valves. No bottomhole pressure drawdown occurs during U-tubing operations because the tubing pressure at total depth exceeds the static bottomhole pressure due 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 casing pressure should be increased gradually to maintain a low jluid velocity through the open gas lijì valves. If full line pressure is exerted on top of the fluid column in the casing, a pressure differential that is approximately equal to this line pressure will occur across each valve in the installation. Damage to the valve seats can result from the high fluid velocity through the valves. After the top valve is uncovered, this condition cannot recur because the top 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 if the port size of the top valve is large. It may be advisable to restrict the 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 the gas 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 short duration of gas injection to permit a gradual increase in casing pressure. For example, a 20 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 rate which will cause a 50 psi increase in casing pressure in an 8-10 minute time interval. Once the absolute casing pressure has reached a value of 400 psi the injection rate can be increased to cause a 100 psi increase in casing pressure in the same 8-10 minute time interval. This second rate should be continued until the top valve is exposed to gas allowing the gas in the casing to flow into the 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 based on the expected or desired production from the well. Each lift cycle should deliver from one to two barrels of fluid per inch of tubing diameter. For example, in 2-inch tubing 12 cycles per day should produce from 24 to 48 barrels of fluid per day. Use this relationship to determine the cycle frequency for a particular well. However, during the unloading operations 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 of the Injection Gas

Not all intermittent installations 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 size selected should be considerably smaller than the port size of the gas lift valve to permit the injection pressure in the casing to decrease to the valve closing pressure after a valve has opened. No excessive pressure differential across the valves will occur during initial U-tubing when the casing pressure is increased slowly.

Use the same guidelines as for a time cycle controller. Set the choke so that the casing pressure increase will 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 this choke setting until the top valve is uncovered to gas.

After the top valve is uncovered, adjust the gas rate to 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 the gas lift valves. After 12-18 hours of reduced gas volume is circulated to the well, adjust the gas to the full amount expected to be used for lifting the well’s production.



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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 well changes, 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 increases the time fluid can accumulate above the operative valve in most intermittent installations. The increased slug length at the instant 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 per cycle. These two things work together to yield a lower injected gas liquid ratip (Rgli).

Procedure for Determining Cycle Frequency

The following procedure is recommended for determining the proper cycle frequency and 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 normally required per cycle (approximately 500 CU ft./bbl per 1,000 ft. of lift). Adjusting the controller to 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 day until 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 the proper injection gas cycle frequency.

Step 4

Reduce the duration of gas injection per cycle until the production rate decreases, then increase the duration of gas injection by 5 to 10 seconds for fluctuations in injection gas line pressure.

A time cycle operated controller on the injection gas line can be adjusted as outlined, provided the line pressure remains relatively constant. If the line pressure varies significantly, the controller is adjusted to inject ample gas volume with minimum line pressure. When the line pressure is above the minimum pressure, excessive injection gas is used each cycle.

The following tabulation (Table 9-1) gives data obtained from an intermittent installation and illustrates the effect of cycle frequency and duration of gas injection on operating efficiency.

TABLE 9-1 DATA FROM AN INTERMITTENT INSTALLATION Injection Duration of Duration Total Approximate

Gas 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 3,000 48 30 56 186 2,200 36 40 63 174 1,800 24 60 85 170 1,300

A cycle frequency 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 in 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 CONTROL OF INJECTION GAS

The initial surface choke size selection for controlling the injection gas is calculated to pass the lift 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 valve suited for choke control is opened by both injection gas pressure and production pressure, increasing the injection gas pressure will decrease the production pressure required to open the valve. After an operating valve closes and the slug surfaces, the injection gas and production pressure begin to increase. The rate at which the gas pressure increases is dependent upon the choke size in the injection gas line, whereas the increase in



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116 Gas Lift

production pressure at valve depth is a function of well deliverability and tubing size.

If the injection line choke size is too large, the valve will open at a higher gas pressure than that required for adequate 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 requirement. By decreasing the choke size, the well has a longer

time in which to deliver fluid into the tubing which, in turn, increases the production pressure at valve depth and reduces the gas pressure required to open the valve.

Choke control of the injection gas is all that is 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 production control,

VARIATION IN TIME CYCLE AND CHOKE CONTROL OF INJECTION GAS

Application of Time Opening and Set Pressure Closing Controller

When the injection gas line pressure varies significantly, a pilot, which opens the controller on time and closes it after a predetermined increase in casing pressure, is recommended. The injection gas cycle frequency is controlled by the timing mechanism. The volume of injection gas used per cycle is governed by the casing pressure control. The pipe is adjusted for a long duration of gas injection and the controller remains open until the maximum desired casing pressure is reached regardless of time required for this increase.

Application of Time Cycle Operated Controller With A Choke in the Injection Gas Line

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 duration of gas injection. This combination also extends the advantages of choke control to wells with very low production rates.

Application of A Combination Pressure Reducing Regulator and Choke Control

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 plug easily. 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 the set regulator pressure in most installations. The pressure reducing regulator controls the maximum casing pressure between injection gas cycles. The controlled maximum

casing pressure causes the gas lift valve 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 used surface gas control systems.

1.. 9."

SURFACE GAS CONTROL SYSTEMS A. Time Cycle Controller B. Choke Control C. Choke and Pressure Regulator D. Choke and Time Cycle Controller

Fig. 9-2 - Two-pen pressure chart



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IMPORTANCE OF WELLHEAD TUBING BACK PRESSURE TO REGULATION OF 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 wellhead and flowline conditions that result in the maximum tubing pressure being a true indication of the slug size.

The two surface conditions associated with wellhead tubing pressure that are detrimental to intermittent lift operation are: (1) An excessive increase in 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 slug velocity will be reduced and excessive gas break-through will occur. If the time required for the tubing 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 from 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 possible. The lower the flowing bottomhole pressure, the more

important minimum separator pressure becomes. High separator pressure reduces the starting slug length and production 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, preferably near the tank battery. This allows the slug to leave the vertical conduit and accumulate in the horizontal conduit. A small wellhead tubing choke will significantly reduce the liquid slug recovery per cycle and increase the injection gas requirement.

Flowline Size and Condition

The time required for the wellhead tubing pressure to decrease to separator pressure after a slug surfaces is a primary factor in the maximum producing rate from some installations. 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 recommended in most instances. If more than one well intermits simultaneously, excessive back pressure will result. The flowline must be kept clean of paraffin and other deposits to prevent excessive back pressure. In some wells the production has been more than doubled by removing paraffin from the flowline.

SUGGESTED REMEDIAL PROCEDURES ASSOCIATED WITH REGULATION OF INJECTION GAS

There are several remedial procedures recommended before resorting to pulling the tubing. Information indicating the trouble may often be obtained from recordings of the surface tubing and casing pressure. If the trouble cannot be corrected by surface control, it is recommended that an installation be serviced as soon as possible to prevent a waste of injection gas and loss in 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 accomplished by applying injection gas pressure to the top of the fluid column in the

tubing with line pressure in the casing. Rocking is recommended for two reasons: (1) To force fluid from the tubing and casing into the formation to uncover the top valve in 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 in 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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118 Gas Lift

the tubing should be shut in and the casing pressure increased to a point well above the opening pressure of the valve. The tubing is opened as fast as possible, preferably to atmosphere to prevent overloading surface facilities, and the wellhead tubing pressure is permitted to decrease to separator or atmospheric pressure. The procedure is repeated several times or until the casing pressure decreases to the valve closing pressure. This action creates a high pressure differential across the valve 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 lift and requires more injection gas than would be required if it did not exist. Many times an emulsion can be eliminated or the severity reduced by adding chemical to the injection gas. Ways of lifting an emulsion include the use of a plunger, large-ported valves, pilot operated valves, and/or time 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 casing and tubing. It is most effective when applied to new systems. If either corrosion inhibition or emulsion breaking chemicals are injected directly into the 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 gas without protection for an extended period of time, products of corrosion will accumulate in the gas distribution lines and subsurface equipment. Addition of a corrosion mitigation program will result in a clean up of the “dirty” system and a continued protection of the system.

The first phase, the clean up, can cause temporary operational problems. As the products of corrosion are removed from the system, they will tend to plug the gas lift valves and make the valves perform erratically. As mentioned, these problems are temporary and 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, then isolate deviations from this example and determine possible causes for the particular malfunctions observed. In many cases, and gas lift is no exception, observation of a system in action requires the assistance of recording instruments. The following basic information should be obtained when the installation is operating properly so 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 the 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 bottomhole pressure

The pressure gradient of the produced fluids

Items 1 through 6 can be determined with a 24-hour production test from the well. The volume of fluid produced 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 fluids. A high pressure meter run at the well is required to measure 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 making an operating pressure survey is to run the pressure gage (bomb) during the feed-in period, to a depth just below the bottom valve. The gage should be left below the bottom valve through three complete gas lift cycles. It is important that the 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 through several cycles with the gage in this position; however, the wireline specialist should be cautioned to watch 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 Procedure for Adjusting, Regulating and Analyzing Intermittent Flow Lift Installations 119

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 the well in for a pressure build 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 two tries, bleed all determine the value of items 7 through 9. the pressure off the tubing and casing. This step allows the

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. Shut off the injection gas and wait until the the operating valve, and the flowing bottomhole casing pressure stabilizes before increasing the casing pres- The operating cycles and build up curve should be sure again. Repeat this procedure twice. If this procedure is

plotted on a pressure time diagram. In 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 in areas where iron sulfide depos-

The information obtained from a pressure survey is best to go On seat, so that it tends to break Or crush

depth diagram will illustrate the location of the operating the tubing OPen, increase the casing Pressure the gas

The first sign Of a in the gas lift 'ystem its are common and fresh water will wash salt deposits from generally occurs when the production Operator valves, This fluid should be produced through the valves in that the fluid production is below normal. Each well in the a normal manner so that it tends to wash the valves and system must be checked to determine which well is not pro- carry out 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, the 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 lift valves have lift valve is failing to close tightly, the following procedure back checks. is recommended: Raise the pressure in the casing and tubing 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 the tubing pressure rapidly. This tems and suggests possible causes and possible cures.

TABLE 9-2 POSSIBLE CAUSES AND CURES OF SOME COMMON MALFUNCTIONS OF GAS LIFT SYSTEMS

MALFUNCTION CAUSE CURE COMMUNICATION A. Valve stuck open Rock the well, flush the valve BETWEEN CASING B. Packer leaking Xeset packer AND TUBING C. Tubing leak Pull, inspect and rerun

OPERATING A. Operating valve changed to Adjust injection gas for maximum PRESSURES higher valve in installation production INCREASE B. Valve plugged Pull well

D. Circulating sleeve open Close it

C. Temperature rise in well Exchange for valves which are not affected affecting valves by temperature, or lower the test rack

opening pressure of bellows charged valves.

D. Small fluid heads Reduce cycle frequency FLUID SLUG A. Fluid load very heavy Increase cycle frequency VELOCITY LESS B. Low injection line pressure Increase pressure or space valves closer THAN 1,000 C. Valve partially plugged Flush with fresh water or solvent FEET PER MINUTE D. Tubing partially plugged Run paraffin knife or clean with solvent

E. Too small valve port Exchange for large ported valves HIGH BACK A. Plugged flow line Look for partially closed valves, fouled PRESSURE AT checks, paraffin, sand accumulations WELL HEAD B. High separator pressure Reset back pressure valve or add gas

accumulator tanks

larger line C. Flow line too small Loop flow line or replace it with

D. Well using too much gas Adjust injection control equipment SUDDEN DROP IN A. Plugged formation Clean out well PRODUCTION - B. Plugged tubing Check tubing below operating valve (Valve Open and C. Lower valves plugged Wash or pull Close 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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API TITLE*VT-6 94 W 0732290 0532953 515 W

APPENDIX 9=A TWO-PEN RECORDER CHARTS SHOWING EXAMPLES

OF INTERMITTENT GAS LIFT MALFUNCTIONS

Appendix 9-A contains eleven two-pen recorder charts In each of the charts, the outer trace represents a recording that illustrate most of the common problems that may of the casing pressure and the inner trace represents a occur in an intermittent gas lift operation. These may be recording of the tubing pressure. As other malfunctions are used by the operator in spotting problems before they encountered, representative charts can be added for future become too severe. The charts were hand drawn so that reference. examples of malfunctions could be exaggerated for clarity.



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A : CYCLE FREQUENCY TOO LONG, TUBING KICKS ARE LOW AND THICK.

B : INCREASED CYCLE FREQUENCY YIELDS TALL THIN TUBING KICKS ANO MORE PRODUCTION.

C : CYCLE FREQUENCY TOO FAST. TUBING PRESSURE WES NOT HAVE TIME TO REDUCE TO NORMAL.

Fig. 9-Al

A : INJECTION RATE TOO HIGH. MAY CAUSE MORE THAN ONE W LIFT VALVE TO

CHANGE I N THE PRESSURE DEWNE RATE AFTER A GAS LIFT VALVE CLOSES. OPEN. THIS CONDITION IS MDENCEO ON THE CASING PRESSURE BY A

THE MULTIPLE "POINTS" ON THE TUBING PRESSURE ALSO MDENCE THIS M m w n O N .

B: TOO MUCH GAS. TUBING KICKS ARE TOO HIGH AND TOO THICK. CASING PRES SURE DECLINE IS RATHER SLOW.

ERRATIC GAS SYSTEM PRESSURE. THE PRESSURE HAS DECLINED AFTER TIMER WAS ADJUSTED SO THAT NOW 2 INJECTIONS ARE REQUIRE0 PER CYCLE.

TIMER IS THEN OPENED FOR LONGER INJECTION. WHEN GAS SYSTEM PRESSURE INCREASES, TOO MUCH GAS IS USED.

TO HELP STABILIZE GAS SYSTEM PRESSURE, USE CHOKE ANO TIMER

INJECTION FREQUENCV TOO F M . GAS LIFT VALVE IS NOT LOADED SO W E S NOT OPEN UNTIL SECOND INJECTION. TOO MUCH W IS M D E N T I N TUBING KICK. REDUCE INJECTION FREQUENCY FOR BETTER OPERATION.

Fig. 9-A2

A : WELL LOADING UP. MDENCE OF EXCESSRlE FLUID 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 DECLINE IN PRODUCED FLUID IS EXPERIENCED.

B: WELL UNLOADING. THIS ILLUSTRATES HOW THE FLUID LOAD DECREASES FROM A MAXIMUM WHEN A W LIFT VALVE OPERATES THE FIRST TIME TO A MINIMUM WHEN THE VALVES OPERATE THE LAST TIME JUST BEFORE TRANS FERRING TO THE N m LWYER VALVE

Fig. 9-A4 Fig. 9-A3



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122

A P I TITLE+VT-6 94 m 0732290 0532955 398

Gas Lift

A : CHOKED WELL. RESTRICTION OF CHOKE CAUSES SLUG VELOCITY TO BE SLOW AND PRESSURE REDUCTION PERIOD TO BE LONG. ALSO. TUBING PRESSURE IS TOO HIGH.

B : FLOW LINE RESTRICTION. ABOUT THE SAME EFFECT AS CHOKE. TUBING PRES SURE CHANGES ARE GRADUAL BECAUSE RESTRICTION IS DISTANT FROM WELL HEAD.

Fig. 9-AS

A : LEAK HIGH IN TUBING. LEAK IS SMALL SINCE TUBING KICKS ARE NORMAL. FIRST SIGN OF LEAK IS EVIDENCED WHEN CASING PRESSURE 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 TO A VALLE WELL ABOYE THE TUBING PRESSURE. (FLUID SEAL OVER THE VALVE).

A : LEAK IN SURFACE INTERMITTER. GOOD OPERATION IS MAINTAINED.

B : SMALL LEAK IN TUBING STRING. B E M E N EACH CYCLE. THE CASING PRESSURE

VERY GOOD. DECLINES SLOWLY AFTER THE GAS LIFT VALVE CLOSES. TUBING KICKS ARE

Fig. 9-A6

URGE LEAK IN TUBINGSTRING. AT FIRST. IT SHOWS AS A SMALL LEAK. THEN

GAS LIFT VALVE. WHEN THE LEAK EXCEEDSTHECYCLEGAS 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-A8 Fig. 9-A7



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API TITLExVT-6 9 4 0732290 0532956 224 W

Two-Pen Recorder Charts Showing Examples of Intermittent Cas Lift Malfunctions 123

GAS LINE PRESSURE BECOMES TOO 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 IS AN INDICATOR OF THIS PROBLEM. THE TUBING PRESSURE KICKS ARE ROUNDED AND MISTY BECAUSE OF EXCESSIVE FALL BACK. AS CONDITION GETS WORSE. THE USING PRESSURE STAYS ABOVE VALVE CLOSING PRESSURE AND TUBING PRESSURES STABILIZE. THEN, ONLY GAS IS OBTAJNED FROM FLUID.

B : PLUGGED TUBING. VERY SIMILAR TO SITUATION A, BUT TUBING PRESSURE RE- FLECTS INJECTION CYCLES. VERY L l l l l E FLUID IS PRODUCED.

Fig. 9-AIO

A : NOT ENOUGH W. FALL BACK IS EXCESSIVE W) FLUID RECOVERY IS SMALL. TUBING PRESSURE HAS ROUNDED, SLUGGISH KICKS. CASING PRESSURE OP- ERATING SPREAD IS TOO SMALL,

B: NOT ENOUGH FLUID. 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 0732290 0532957 Lb0

CHAPTER 1 O THE USE OF PLUNGERS IN GAS LIFT SYSTEMS

INTRODUCTION

The function of plunger lift equipment is to provide for more efficient utilization of lifting gas energy i n any well that is or can be produced in a cyclic manner similar to intermittent gas lift.

Plunger lift incorporates a piston that normally travels the entire length of the tubing string, providing a solid and sealing interface between the lifting gas and the produced liquid. This interface changes the flow pattern during a lifting cycle from the familiar bullet shape of gas penetration of the liquid slug to a pattern whereby gas flow is possible only between the plunger’s outside diameter and the tubing walls.

To lift the plunger and the liquid load above the plunger, the gas pressure must be greater than these loads. T.he small quantity of gas that bypasses the plunger during a cycle flows up through the annular space and acts as a sweep to minimize liquid fallback.

The use of plunger equipment, by minimizing liquid fallback and eliminating possible gas penetration through the center of the liquid slug, provides for the most efficient form of intermittent gas lift production available.

APPLICATIONS

Numerous applications exist for plunger installations in through the liquid column and lose lift efficiency. A both are:

I .

2.

3.

4.

gas lift and natural flow wells. The most common uses

To maintain production by cycling in a high gas- liquid ratio well.

To unload accumulated liquid in a gas well.

To reduce fallback in a well being produced by intermittent gas lift.

To improve efficiency in gas lift wells with severe emulsion problems. In such wells, the friction of the emulsion prevents establishment of the required lifting velocity. The slow velocity allows gas to channel

plunger lift system can help eliminate this problem.

5 . To clean the tubing in both gas lift and natural flow wells producing paraffin, scale, and other deposits. Normal production does not have to be cyclic, but the well must be shut in periodically to allow the plunger to operate.

6. For deep intermittent gas lift with low injection gas pressure.

7. To allow intermittent gas lift with surface restrictions.

This chapter is primarily concerned with the use of plungers in intermittent gas lift applications.

TYPES OF PLUNGER LIFT

Three possible types of downhole installations are:

1. Intermittent Gas Lift With a Packer

Normally the well’s bottomhole pressure is so low that the liquid fill-in from the formation is not sufficient to prevent gas break-through of the liquid column during an intermittent lift cycle.

This type of application is one where insufficient Plunger application allows much greater utiliza- gas in available from the formation and all gas is tion of the energy being provided and less fallback, provided by a supplemental source involving an out- thus a corresponding decrease in bottomhole pres- side source of energy. sure and an increase in liquid production.



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A P I TITLESVT-6 94 0732290 0532958 O T 7

The Use of Plungers in Gas Lift Systems 125

\ TO SALES I

Type Well: Insufficient gas from formation. Well being gas lifted on packer. All flow through tubing.

Equipment Required: @ Full bore master valve @ Flow valve @ Lubricator @ Time cycle control valve @ Second flow outlet @ Flow valve

Standard Operation: 1. Plunger at bottom of well. 2. Gas flow through time cycle intermitter opens the

gas lift valve down hole, thereby creating the differential necessary to lift the liquid and plunger to the surface.

3. Gas and liquid delivered through upper outlet. 4. Gas lift valve closes. 5. Plunger arrives in lubricator, partially closing off

6. Tail gas is rapidly dissipated through lower outlet. 7. Plunger falls to bottom and cycle recommences.

upper outlet.

Fig. 10-1 - Typical 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 (No Communication Between Casing and Tubing)

another application of plungers. This type of installation requires that all gas must come directly from the formation during the lifting cycle: and necessitates that the formation Rglf be greatly in excess of that required for conventional plunger lift since the gas required per cycle must be produced during the cycle. No storage period or external source of gas is possible.

Since this text is concerned with gas lift application of plungers, further discussion of plunger application without additional gas will be omitted. A typical surface installation

This is not a gas lif 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, the proper equipment must be chosen. Figs. 10-2, 10-3, and 10-4 show possible variations in downhole installations where gas lift is used in conjunction with the plunger.

Using these figures as a base and starting at the bottom of the well, the equipment is explained under the following headings.

I

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. 10-5 shows a typical tubing stop.

Standing Valve A standing valve prevents liquid in the tubing 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 TITLE*VT-b 94 W 0732290 0532959 T33 m

126 Gas Lift

in Fig. 10-2, it is often omitted from such installations. However, the standing valve should always be run in installations such as those shown in Figs. 10-3 and 10-4. In these types of installations, the standing valve prevents the high pressure lift gas from forcing the liquid 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 independently of the bumper spring. Experience has shown that a plunger falling dry on a bumper spring, standing valve, and stop set together will set up a vibration that rapidly causes a failure of the standing valve ball and seat.

Bumper Spring

The bumper spring, shown in Fig. 10-6, is an essential part of a plunger installation. It prevents excessive shock on the plunger when falling to the bottom, particularly if the well does not have liquid above the tubing stop.

Plungers

There 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.

Equlpment 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 - Downhole equipment variations, gas lift and plunger lift

Equipment 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 - Downhole equipment variations, gas lift and plunger lift



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A P I T I T L E a V T - 6 9 4 m 0732290 0532960 755 m


3. High degree of repeatability of valve operation.

4. Ability to provide a good seal against the tubing during upward travel.

5 . The ability to fall rapidly through gas and liquid.

Figs. 10-7, 10-8, 10-9, and 10-10 show three different plunger types.

Equipment Required

1. Sub-surface plunger 2. Bumper Spring 3. Retrievable Tubing Stop 4. Retrievable Duplex Standing Valve 5. Gas Lift Valves 6. Producing Gas Lift Valve 7. Packer 8. Seating Nipple 9. Seating Nipple

10. Retrievable Gas Lift Valve in Center Mount Mandrel

Fig. 10-5 - Typical tubing stop

Fig. 10-4 - Downhole equipment variations, gas lift and plunger lift Fig. 10-6 - Typical bumper spring



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API T I T L E m V T - 6 94 m 0732290 0532963 691 m

128 Gas Lift

Essentially, there are six variations of 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 types of 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 to their relative effectiveness in fulfilling the five operating characteristics listed previously.

Fig. 10-8 - Wobble washer type plunger with integral valve rod

Fig. 10-7 - Typical plunger with integral valve rod Fig. 10-9 - Brush type plunger without integral valve rod

~ ~~ ~



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A P I TITLE+VT-b 9 4 0732290 0532762 528


Fig. 10-10 - Expanding blade plunger with retractable seal (Photos courtesy Ferguson-Beauregard Inc.) (A) Shows seals in expanded position (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 prevent initial operations. Table 10-2 gives the gages recommended for various tubing sizes.

TABLE 10-1 PLUNGER CLASSIFICATIONS

Operating Characteristics I

Type of Plunger

(1) Expanding blade seal without integral valve rod

2

(2) Expanding blade seal with integral valve rod

1

(3) Expanding blade seal without valve -

(4) Turbulent seal, wobble-washer, etc. without integral valve rod (valve actuating 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 FOR VARIOUS TUBING SIZES

- / Tubing size, in. Minimum gages

O.D. nominal O.D., in. length, ft A

\

1.660 1 'I4 1.250 2 1.900 1 '12 1.500 2 2.063 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 determine the correct gage size.

CAP .......................................... (1) BUMPER SPRING. i . . ......................... STRIKER PAD ................................ (3) FLOW BODY. . ................................ (4) CATCHER ASSEMBLY ........................ ( 5 ) DUAL FLOW OUTLET ................... (4A) (4B)

i2 j

Fig. 10-11 - Typical lubricator parts



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API TITLEWVT-b 74 m 0732290 O532764 3T0 m


Master Valve The master valve of a well must have a full bore equal to,

but not greater than, the tubing size. An undersize valve will not allow plunger passage, and an oversize valve can possibly prevent the plunger from reaching the lubricator because of excessive gas bypassing around the plunger. The plunger must reach the lubricator to allow removal for service 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 separate unit of the flow outlet of an existing tree can be used. If 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 installation. Fig. 10-1 1 shows the various parts of a typical dual flow outlet lubricator.

The cap (1) contains a spring to resist the force of the rising 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 successful plunger installation is the 4. installation of the equipment.

Listed below are the sequential operations involved in running a plunger installation, assuming the well is set on a packer and will not be pulled. 5

1.

2.

3.

Check master valve for proper size

Gage tubing 6.

Set retrievable stop and standing valve just above the bottom of the tubing. (Note: this stop and standing 7. valve are optional)

Set retrievable stop just above the bottom gas lift 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 previously set stop

Run plunger to bottom on a wireline to ensure free travel

Remove wireline lubricator, install plunger lubricator, and commence operation.

SUMMARY

A plunger will increase the efficiency of most intermittent gas lift installations by preventing gas from breaking through the liquid slug. In some instances of very low bottomhole pressure, plungers will allow greater pressure drawdown and thereby increase production from the intermittent lift well by allowing the lifting of 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 slug surfaces; 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 in 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 TITLE*VT-b 9L1 m 0732290 05329b5 237 W

132 Gas Lift

GLOSSARY

-A-

Ager - A water filled pressure chamber used to apply API - American Petroleum Institute. external pressure to gas lift valves to flex the bellows during the pressure setting operation.

Annular Flow - Formation fluids are produced up a system recommended by API. through the tubing-casing annulus and recovered at the surface.

Annulus - The space between tubing and casing. source to lift reservoir fluids from a producing well.

API Gravity - Specific gravity of crude oil as measured by

Artificial Lift -The application of energy from an outside

-B-

Back Pressure - The pressure existing within the produc- BLPD - Barrels of total liquid per day. ing string at the surface in a gas lift well. Also used to designate the fluid pressure at the level of gas injection, the BOPD - Barrels of Oil Per day- pressure against which the operating valve injects gas.

Bellows - The responsive element of a gas lift valve. It performs the same function as the diaphragm operated Bottomhole Pressure (BHP) - Pressure at some given valve. It provides an area for pressure to act on and to move depth i n the well, usually opposite the producing the valve stem. formation.

BWPD - Barrels of water per day.

-C-

Casing Flow - (Same as annular flow.) Continuous Flow Gas Lift - Gas lift operation in which -

Casing Pressure - The 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 - A 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 - A refrigerated water bath used to cool pressure liquids between cycles. charged gas lift valves to 60°F when setting them.

Choke - A type of orifice installed in a line in which fluid is flowing. The purpose is to restrict the flow and control the rate of production. Cross-over Seat - A special seat for a gas lift valve which

directs the pressure applied at the nose of the gas lift valve Christmas Tree - A 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 is used most control the flow of oil and gas. often in fluid operated valves.

-D-

Dead Well - A well that will not flow by itself. Dome - The volume chamber inside the bellows of a gas lift valve.

Dill Core or Schrader Core Valve -Valve in the top of the Drawdown - The difference in pressure (psi) between the gas lift valve used in charging the bellows with nitrogen. static (shut-in) bottomhole pressure and the flowing

bottomhole pressure at a constant rate of fluid production.



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API TITLE*VT-6 9 4 W 0732270 O532766 L73

-E-

Emulsion - A mixture of oil and water that requires treatment before the oil and water will separate.

-F-

Flowline - The surface pipe through which the oil travels Formation (F Gas) Gas - Gas which is produced from the from the well to storage. oil reservoir with the produced liquids.

Flowing Bottomhole Pressure (FBHP) - The Pressure Fluid or Production Operated Valve - A gas lift valve that existing at the depth of the production formation in a well utilizes the pressure in the production conduit as its pri- at a constant rate of fluid production. mary operating medium.

-G-

Gas Lift - A method of artificial lift in which the energy of Gas-oil Ratio (GOR = Rgo) - The number of standard compressed 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 - A pressure regulator mounted on or in the tubing string so that, by manipulation of the injection gas pressure and the producing pressure, the valve will either be open or closed to provide a controllable communication between the tubing and casing for gas passage.

Geothermal Gradient - The naturally occurring increase of temperature with depth in undisturbed ground. Normally given in OFF/100 Ft.

Gas-Liquid Ratio (GLR = RE,) - The number of standard cubic feet of gas produced with a stock tank barrel of liquid Gradient - Change in pressure or temperature per unit (oil and water). change in depth.

-H-

“Head” - The volume of reservoir fluids produced at the surface following a short period of gas injection, as in intermittent operation.

IPR (Inflow Performance Relationship) - The 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 control

which may be adjusted and set to operate a motor valve at Intermittent Flow - Gas lift operation in which gas is predetermined intervals of time and also control the dura- injected periodically into the liquid column, with reservoir tion of the operating or injection period.

-K-

Kick-off Pressure - The gas injection pressure available fluids and wireline gas lift valve into the mandrel pocket for unloading fluids from a gas lift well down to the operat- when installing the valve or guides the pulling tools onto ing valve depth. the valve when recovering the valve.

Kick-Over Tool - The wireline tool which guides the Kick a Well Off - Unload and place a well on gas lift.



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134 Gas Lift

-L-

Latch - The locking device for a wireline gas lift valve to Load Fluid (Kill Fluid) - Liquid used to fill the lock the valve in the mandrel. well before pulling the tubing.

"-

Macaroni String - Tubing inside tubing. Mscf (MCF) - One thousand standard cubic feet of gas. This term is commonly used to express the volume of gas

Mandrel - (See wireline or tubing retrievable.) produced, transmitted, or consumed in a given period of time (scf - standard cubic foot of gas).

Master Valve - A large valve used to shut in a well. Mscf/B (MCFIB) - Thousands of cubic feet per barrel.

-0-

Operating Pressure - The gas injection pressure available to maintain the desired rate of fluid production in a gas lift well under settled continuous or intermittent operation.

-P-

Productivity Index (PI=J) - The ratio of fluid production rate, in barrels per day, to the difference between static and flowing bottomhole pressures (drawdown), in pounds per square inch.

Pit - An emergency tank or shallow pond to hold salt water, etc., prior to disposal.

Pocket - The gas lift valve receiver inside a wireline (retrievable) mandrel.

force for the valve. The gas is usually nitrogen. The responsive element is usually a bellows.

Pressure Operated Valve - A gas lift valve that utilizes injection gas pressure as its primary operating medium.

Pressure Survey - An operation to measure and record the pressures at various depths in the well bore with the well either producing or shut-in. The pressures may be measured and recorded by either a self-contained unit run on a

Pressure Charged Valve - A gas lift 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 instantaneous recording at the surface.

-S-

Specific Gravity - The ratio of the weight of a substance Static Fluid Level - The 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 - Stock tank barrel. The volume of oil, water or total Spring Loaded Valve - A gas lift valve which uses a spring liquid as measured in the stock tank. to provide the closing force for the valve.

Static Bottomhole Pressure - The pressure at formation depth in a well after the well is shut-in and the pressures Stock Tank - A tank for holding the produced liquids at have been stabilized. atmospheric pressure prior to pumping them elsewhere.

scf/STB - Standard cubic feet per stock tank barrel.

-T-

Tail Plug - The plug in the end of a gas lift valve which 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 - An operation to measure and record 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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7

A P I T ITLEaVT-b 94 m 0732290 0532968 T 4 6 m

Glossary 135

applied to the bellows of a gas lift 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 - The process of determining and cor- Tubing Retrievable Gas Lift Valve - Commonly called a recting a problem with a gas lift well. conventional gas lift valve. A gas lift valve mounted on a

Tubing Flow - Formation 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 mounting gas lift valves; consequently the name of conventional gas

Tubing Retrievable Mandrel -Commonly called conven- lift valve.

-W-

Wellhead - The 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 - A gas lift valve mounted Wireline (Retrievable) Mandrel - A 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 diameter of 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, ft.

Depth on nth valve, ft.

Distance between valves, ft.

Depth of gas injection, ft.

Measured depth of deviated wells, ft.

Minimum spacing of gas lift valves or mandrels, ft.

Depth of operative valve or gas injection, ft.

Reference depth of well: Normally measured midpoint of perfs., on top of perfs., ft.

Closing force on gas lift valve, pounds force.

Total opening force on valve, pounds force.

Opening force due to pressure on the bellows, pounds force.

Opening force due to pressure on 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 injection, psi/ft.

Flowing gradient below point of gas injection, 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 temperature gradient, Deg. F/100 ft.

Static Temperature gradient, Deg. F/100 Ft.

Productivity Index (J=PI), BLPD/PSI.

Total number of gas lift valves.

Pressure Drop in Inj. Gas pressure to deter interference, psi.



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A P I T I T L E x V T - 6 94 m 0732290 0532969 982 m 136 Gas Lift

Pressure applied under the bellows of a gas lift valve, psig.

Pressure applied under the stem of a gas lift valve, psig.

Bubble point pressure of the produced oil, psig.

Pressure of bellows at temperature of nth valve, psig.

Bellows pressure at 60 deg. F., psig.

Injection gas pressure downstream of surface choke, psig

Effective opening pressure due to production pressure, psig.

Max available pressure of injection gas at surface, psig.

Injection gas pressure downstream of restriction 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 lifting deeper, psig.

Min flowing pressure at valve 1 while unloading, psig.

Min flowing pressure at nth valve while unloading, psig.

Flowing production pressure at valve 1, psig.

Flowing production pressure at nth valve, psig.

Production pressure effect, psig.

Production pressure effect factor - Mfg. data - (Previously TEF)

Pressure at standard conditions, psig.

Pressure of oil & gas separator, psig.

Pressure safety factor to ensure valve is uncovered, psig.

Spring pressure effect on valve, psig.

Max unloading pressure at nth valve when uncovered, 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 of 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 pressure, psig.

Max production rate below the bubble point, BLPD.

Gas production rate from formation, Mscf d.

Injection gas rate, Mscf/d.

Total gas rate measured (formation + injection), 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 I T I T L E x V T - 6 94 M 0732290 0532970 bT4 m

Glossary 137

S G , Specific gravity of produced water. T,, Temperature at standard conditions, deg. F.

T, Average gas injection temperature, deg. ETt Temperature at valve I depth, deg. F.

TB Surface temperature of injection gas, deg. F. Twh Flowing temperature at wellhead, deg. F.

Formation temperature, deg. F. T"(") Temperature at nth valve, deg. F.

T, Static earth surface temperature, deg. F. Z Gas compression factor at average pressure and

temperature.



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A P I TITLEaVT-b 94 0732290 0532973 530

138 Gas Lift

REFERENCES

1.

2.

3.

4.

5.

6.

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8.

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11.

Gilbert, W.E.: Flowing and Gas-Lift Well Perform- ance, Drilling and Production Practice, 126 (1954), American Petroleum Institute, Production Depart- ment.

Vogel, J.V.: Inflow Performance Relationships for Solution Gas Drive Wells, SPE 1476, a paper presented at the 41st Annual Fall Meeting of the Society of Petroleum Engineers of AIME, Dallas, Texas, October 2-5, 1966, and later published in Transactions, SPE of AIME, Vol. 243 (1968).

Poettmann, F. H. and Carpenter, P.G.: The Multi- phase Flow of Gas, Oil and Water Through Vertical Flow Strings, Drilling and Production Practice, 257 (1952), American Petroleum Institute, Production Department.

Baxendell, P.D. and Thomas, R.: The Calculation of Pressure Gradients in High-Rate Flowing Wells, Jour- nal of Petroleum Technology, 1023-1028 (1961), Society of Petroleum Engineers of AIME.

Duns, H. Jr. and Ros, N.C.J.: Vertical Flow of Gas and Liquid Mixtures from Boreholes, Proceedings, Sixth World Petroleum Congress, Frankfurt, Ger- many, Section II, Paper 22-PG (June 19-26, 1963).

Johnson, A. J.: Vertical Two-Phase Flow Pressure Traverses, Letter from Shell Development Company Outlining Terms, Conditions and Description of Com- puter Program Mk 1X-R for Sale to Industry (Decem- ber 5, 1963).

Hagedorn, A.R. and Brown, K.E.: The Effect of Liquid Viscosity on Two-Phase Flow, Journal of Petroleum Technology, 203-210 (February 1964), Society of Petroleum Engineers of AIME.

Orkiszewski, J.: Predicting Two-Phase Pressure Drops in Vertical Pipe, Journal of Petroleum Tech- nology, 829 (June 1967), Society of Petroleum Engi- neers of AIME.

Moreland, E.E.: Report - Study of Tubing Pressure in Vertical and Deviated Wells Part 6: Moreland - Mobil - Shell - Method, Mobil R&D Lab Memo- randum 1976.

Baker, Ovid: Design of Pipelines for the Simulta- neous Flow of Oil and Gas, Oil and Gas Journal, Vol. 53, 185-195 (1954).

Lockhart, R.W. and Martinelli, R.C.: Proposed Correlation of Data for Isothermal Two-Phase Two Component Flow in Pipe Lines, Chemical Engineering Progr., Vol 45, 39 (1949).

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Flanigan, O.: Effect of Uphill Flow on Pressure Drop in Design of Two-Phase Gathering Systems, Oil and Gas Journal, Vol. 56. 132 (March 10, 1958).

Eaton, Ben A. et al: The Prediction of Flow Patterns, Liquid Holdup and Pressure Losses Occurring During Continuous Two-Phase Flow in Horizontal Pipelines, Journal of Petroleum Technology, 3 15-328 (June 1967), Society of Petroleum Engineers of AIME.

Dukler, A.E., et al: Frictional Pressure Drop in Two- Phase Flow: B. An Approach Through Similarity Analysis, Vol. 10, 44-51 (January 1964), AIChE Journal.

Beggs, H.D. and Brill, J.P.: An Experimental Study of Two-Phase Flow in Inclined Pipes, 607 (May 1973), Journal of Petroleum Technology, Society of Petro- leum Engineers of AIME.

Espanol, J.H. Holmes, C.S. and Brown, K.E.: A Comparison of Existing Multiphase Flow Methods for the Calculation of Pressure Drop in Vertical Wells. Paper No. SPE 2553, 44th Annual Fall Meeting of SPE, Denver, Colorado (September 28 - October 1, 1969).

Vohra, I.R., Robinson, J.R. and Brill, J.P.: Evalua- tion of Three New Methods for Predicting Pressure Losses in Vertical Oil Well Tubing, 829-832 (August 1974), Journal of Petroleum Technology, Society of Petroleum Engineers of AIME.

Lawson, D.J. and Brill, J.P.: A Statistical Evalua- tion of Methods Used to Predict Pressure Losses for Multi-phase Flow in Vertical Oil Well Tubing, 903- 914 (August 1974), Journal of Petroleum Technology, Society of Petroleum Engineers of AIME.

Gregory, G.A., Fogarasi, M. and Aziz, K.: Analy- sis of Vertical Two-Phase Flow Calculations: Crude Oil-Gas Flow in Well Tubing, 86-92 (January - March 1980), Journal of Canadian Petroleum Technology.

Ros, N.C.J.: Simultaneous Flow of Gas and Liquid as Encountered in Oil Wells, Joint AIChE-SPE Sympo- sium, Tulsa, Oklahoma (September 25-28, 1960).

Ros, N.C. J.: Simultaneous Flow of Gas and Liquid as Encountered in Well Tubing, 1037 (October 1961), Journal of Petroleum Technology, Society of Petro- leum Engineers of AIME.

Brown, E.J.P.: Practical Aspects of Predicting Errors in Two-Phase Pressure-Loss Calculations, 5 15- 522 (April 1975), Journal of Petroleum Technology, Society of Petroleum Engineers of AIME.



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API T I T L E x V T - 6 9 4 0732290 0532972 477 m References 139

23. Cornish, R.E.: The Vertical Multiphase Flow of Oil and Gas at High Rates, 825-831 (July 1976), Journal of Petroleum Technology, Society of Petroleum Engi- neers of AIME.

24. Brown, K.E., et al: The Technology of Artificial Lift Methods, Vol. 3A, Pressure Gradient Curves, 261 (1980) PennWell Books, Tulsa, Oklahoma.

25. Brown, K.E., et al: Gas Lift Theory and Practice, Appendix C 163 (1 967), Prentice-Hall, Englewood Cliffs, New Jersey.

26. Doolittle, Jesse S.: Thermodynamics for Engineers, 2nd Edition (1964), International Text Book Company.

27. Frick, Thomas C., Ed.: Petroleum Production Hand- book, Vol. 11 (1962), McGraw-Hill Book Company Inc.

28. Winkler, H.W.: Flowing Well and Gas Lift Systems, Viking Shop (1 973).

29. Winkler, H.W., and Smith S.S.: Camco Gas Lift Manual, Camco, Inc. (1962).

30. Katz, D. L., et al: Handbook of Natural Gas Engi- neering (1 959), McGraw-Hill Book Company, Inc.

3 1. Plant Processing of Natural Gas, Petroleum Extension Service (PETEX), (1974).

32. Engineering Data Book, Gas Processors Suppliers Association (GPSA), (1 972).

33. Martinez, J., and Milburn, F.H.: Handbook for Gas

34.

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Measurement in the Field, Exxon Production Re- search (1 978).

Phase Relations of Gas Condensate Fluids, Bureau of Mines Monograph # 10. Vol. 2,763-764.

Focht, F. T.: World Oil, 105-107 (January 1981).

White, G.W., O’Connell, B.T., Davis, R.C., Berry, R. F., and Stacha, L.A.: An analytical Concept of the Static and Dynamic Parameters of Intermittent Gas Lift, Journal of Petroleum Technology (March 1963), Society of Petroleum Engineers of AIME.

Guiberson Oil Tools, Artificial Lift-Gas Lift En- gineering.

40. Teledyne Merla, Section 5 , Specifications and Valve Performance Data, 1982.

41. Teledyne Geotech, Supervisory System for Gas Lift Control, 1982.

42. Wall, P.T.: 12th Annual Southwest Petroleum Short Course, TTU, 1965, Effect of Back Pressure on Inter- mittent Gas Lift.

43. Redden, J.D., Sherman, T.A.G., Blann, J.R.: Opti- mizing Gas Lift Systems, SPE Paper No. 5 150, 1974.

44. Clegg, J.D.: High Rate Artificial Lift, Journal of Pe- troleum Technology (March 1988) 277-82.

45. Neely, A.B., Gipson, F.W., Capps, B., Clegg, J.D., and Wilson, P.: Paper, SPE 10377, presented at 198 1 SPE Annual Technical Conference and Exhibition, San Antonio, TX, October 5-7,1981.

46. Blann, J.R., and Williams, J.D.: Determining the Most Profitable Gas Injection Pressure for Gas Lift Installation, Journal of Petroleum Technology (Au- gust 1984).

47. DeMoss, E.E., and Tiemann, W.D.: Gas Lift In- creases High Volume Production From Claymore Field, Journal of Petroleum Technology (April 1982) 696-702.

48. Blann, J. R., Jacobson L. and Faber, C.: Produc- tion Optimization in the Provincia Field, Colombia, SPE PE (Feb. 1989) 9-14.

49. Neely, A.B., Montgomery, J.W. and Vogel, J.V.: A Field Test and Analytical Study of Intermittent Gas Lift, SPEJ (Oct. 1974) 502-12.

50. API Spec 11 V1, Specification for Gas Lift Valves, Orifices, Reverse How Valves and Dummy Valves.

5 l . API Recommended Practice 11V5 (RP 1 1 V5), Rec- ommended Practice for Operation, Maintenance and Trouble-shooting of Gas Lift Installations.

52. API Recommended Practice 11V6 (RP 11V6), Rec- 38. FOS, D.L. & Gaul, R. B.: Plunger Lift Performance ommended Practice for Design of Continuous Flow

Criteria with Operating Experience - Ventura Ave. Gas Lift Installations using injection Pressure Oper- Field, Paper No. 801-41H, API D&P Practices 1965, ated Valves. p. 124-1 40.

39. Blann, J. R., Brown, J. S., Dufresne, L. P.: Im- proving Gas Lift Performance in a Large North Afri- can Oil Field, SPE Paper No. 8408, 1979.

53. API Recommended Practice l lV7 (RP llV7), Rec- ommended Practice for Repair, Testing and Setting Gas Lift Valves.



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A P I TITLE+VT-b 94 0732290 0532973 303 m

Order No. 81 1 -!/T063

Additional copies available from AMERICAN PETROLEUM INSTITUTE Publications and Distribution Section 1220 L Street, NW Washington, DC 20005 (202) 682-8375



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api gas lift manual

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