Api rp 11v5 2008 (2015) (american petroleum institute)

Recommended Practices for Operation, Maintenance, Surveillance, and Troubleshooting of Gas-lift Installations API RECOMMENDED PRACTICE 11V5 THIRD EDITION, JUNE 2008 REAFFIRMED, MARCH 2015 Recommended Practices for Operation, Maintenance, Surveillance, and Troubleshooting of Gas-lift Installations Upstream Segment API RECOMMENDED PRACTICE 11V5 THIRD EDITION, JUNE 2008 REAFFIRMED, MARCH 2015 Special Notes API publications necessarily address problems of a general nature With respect to particular circumstances, local, state, and federal laws and regulations should be reviewed Neither API nor any of API's employees, subcontractors, consultants, committees, or other assignees make any warranty or representation, either express or implied, with respect to the accuracy, completeness, or usefulness of the information contained herein, or assume any liability or responsibility for any use, or the results of such use, of any information or process disclosed in this publication Neither API nor any of API's employees, subcontractors, consultants, or other assignees represent that use of this publication would not infringe upon privately owned rights Classified areas may vary depending on the location, conditions, equipment, and substances involved in any given situation Users of this recommended practice should consult with the appropriate authorities having jurisdiction Users of this recommended practice should not rely exclusively on the information contained in this document Sound business, scientific, engineering, and safety judgment should be used in employing the information contained herein API is not undertaking to meet the duties of employers, manufacturers, or suppliers to warn and properly train and equip their employees, and others exposed, concerning health and safety risks and precautions, nor undertaking their obligations to comply with authorities having jurisdiction Information concerning safety and health risks and proper precautions with respect to particular materials and conditions should be obtained from the employer, the manufacturer or supplier of that material, or the material safety data sheet API publications may be used by anyone desiring to so Every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them; however, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use or for the violation of any authorities having jurisdiction with which this publication may conflict API publications are published to facilitate the broad availability of proven, sound engineering and operating practices These publications are not intended to obviate the need for applying sound engineering judgment regarding when and where these publications should be utilized The formulation and publication of API publications is not intended in any way to inhibit anyone from using any other practices Any manufacturer marking equipment or materials in conformance with the marking requirements of an API standard is solely responsible for complying with all the applicable requirements of that standard API does not represent, warrant, or guarantee that such products in fact conform to the applicable API standard All rights reserved No part of this work may be reproduced, stored in a retrieval system, or transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise, without prior written permission from the publisher Contact the Publisher, API Publishing Services, 1220 L Street, N.W., Washington, D.C 20005 Copyright © 2008 American Petroleum Institute Foreword This document is under the jurisdiction of the API Committee on Standardization of Production Equipment (Committee 11) This document presents recommended practices for the operation, maintenance, surveillance, and troubleshooting of gas-lift systems Other API specifications, API recommended practices, and Gas Processors Suppliers Association (GPSA) documents are referenced and should be used for assistance in design and operation Nothing contained in any API publication is to be construed as granting any right, by implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters patent Neither should anything contained in the publication be construed as insuring anyone against liability for infringement of letters patent This document was produced under API standardization procedures that ensure appropriate notification and participation in the developmental process and is designated as an API standard Questions concerning the interpretation of the content of this publication or comments and questions concerning the procedures under which this publication was developed should be directed in writing to the Director of Standards, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C 20005 Requests for permission to reproduce or translate all or any part of the material published herein should also be addressed to the director Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years A one-time extension of up to two years may be added to this review cycle Status of the publication can be ascertained from the API Standards Department, telephone (202) 682-8000 A catalog of API publications and materials is published annually and updated quarterly by API, 1220 L Street, N.W., Washington, D.C 20005 Suggested revisions are invited and should be submitted to the Standards Department, API, 1220 L Street, NW, Washington, D.C 20005, standards@api.org iii Contents Page 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 1.10 1.11 Gas-lift Operating System Components and Potential Problems Purpose Gas-lift System Components Gas-lift System Operating Problems Surface Facility Problems Metering and Control Problems Gas-lift Valve Problems Well Equipment Problems Gathering System Problems Well Testing Problems Production Handling Problems Information Handling Problems Surveillance and Control Problems 2.0 2.1 2.2 2.3 2.4 2.5 Gas-lift Operating Problems Purpose Under-lifted and Over-lifted Wells Ineffective Gas Distribution 14 Unstable Gas-lift Operation 15 Types and Causes of Unstable Operation 17 Other Problems 19 3.0 3.1 3.2 3.3 Surface Gas-lift Compression, Dehydration, and Distribution 21 Purpose 21 Compression Facility 21 Gas Dehydration Facility 23 Gas-lift Distribution System 24 4.0 4.1 4.2 Gas Injection Metering and Control 27 Purpose 27 Gas Metering 27 Injection Control 29 5.0 5.1 5.2 Gas-lift Valves 32 Purpose 32 Unloading Valves 32 Operating Valve(s) 34 6.0 6.1 6.2 6.3 6.4 6.5 Well Equipment—Tubulars, Completion, and Wellhead 35 Purpose 35 Casing Annulus 36 Tubing 37 Completion 38 Wellhead 40 Wellhead Monitoring and Control 41 7.0 7.1 7.2 Gathering System—Flowline and Manifold 43 Purpose 43 Flowline 43 Manifold 46 v Page 8.0 8.1 8.2 8.3 Well Production Rate Testing 47 Purpose 47 Well Test Scheduling 47 Well Test Equipment 52 Well Test Measurements 53 9.0 9.1 9.2 9.3 Production Handling System 56 Purpose 56 Oil Handling System 56 Water Handling System 57 Gas Handling System 57 10 10.0 10.1 10.2 10.3 10.4 10.5 Guidelines for Collecting and Using Operating Information 57 Purpose 57 Well Test Information 57 Downtime Information 61 Pressure and Temperature Surveys 61 Injection Pressure and Rate Measurements 66 Wellhead Production Pressure, Temperature, and Rate 67 11 11.0 11.1 11.2 Manual and Automated Well Operation and Control 68 Purpose 68 Manual Operations 68 Automated Operations 69 12 12.0 12.1 12.2 12.3 12.4 12.5 Procedures for Initial Unloading and Kick Off 71 Purpose 71 General Unloading Recommendations 71 Unloading Continuous Gas-lift Wells 72 Restarting (Kick Off) Continuous Gas-lift Wells 74 Unloading Intermittent Gas-lift Wells 75 Restarting (Kick Off) Intermittent Gas-lift Wells 76 13 13.0 13.1 13.2 13.3 13.4 13.5 Procedures for Adjusting (Fine Tuning) Gas-lift Injection Rates 76 Purpose 76 Continuous Gas-lift Wells with Steady Pressure 76 Continuous Gas-lift Wells with Variable Injection Pressures 77 Intermittent Wells with Time Cycle Control 77 Intermittent Wells with Choke Control79 Do Not Use Flowline Chokes79 14 14.0 14.1 14.2 14.3 14.4 Gas-lift Troubleshooting Tools 80 Purpose 80 Two-pen Pressure Charts, or Equivalent 80 Acoustical Surveys 101 Tagging Fluid Level 103 Flowing Pressure Surveys 103 15 Recommended Practices for Dealing with Wells That Produce Sand 109 15.0 Purpose 109 15.1 Recommended Practices 109 16 16.0 16.1 16.2 16.3 Typical Locations of Gas-lift Problems 110 Purpose 110 Gas-lift Injection or Inlet Problems 110 Gas-lift Production or Outlet Problems 112 Downhole Problems 113 Page 17 Possible Causes and Cures of Common Malfunctions of Gas-lift Systems 117 18 Gas-lift Troubleshooting Checklist 119 Bibliography 123 Figures Gas-lift System Components 2 Problem of Injecting Gas Through an Upper Gas-lift Valve 11 Problem of Under Injection—Injecting Too Little Gas 11 Problem of Over Injection—Injecting Too Much Gas 13 Determining the Optimum Gas Injection Rate 13 Problem of High Injection Pressure Causing an Upper Valve to Open 14 Problem of Under Injection—Causing Operating Valve to Flood 19 Hydrate Conditions 24 Water Content vs Temperature and Pressure 25 10 Finger Distribution System 26 11 Looped Distribution System 26 12 Unloading a Continuous Gas-lift Well 74 13 Adjustable Choke for Continuous Gas-lift Control 77 14 Adjustable Choke with a Pressure Regulator 78 15 Installation of Pressure Measurement Devices 81 16 Continuous Gas-lift—Good Operation 82 17 Continuous Gas-lift—Wellhead Backpressure Too High 82 18 Intermittent Continuous Gas-lift—Good Operation 83 19 Comparison of Intermittent and Continuous Injection 83 20 No Gas Injection Control 84 21 Continuous Injection 84 22 Continuous Injection—Frozen Gas Input 85 23 Well is Flowing 85 24 Continuous Injection—Kick Off After Idle Period 86 25 Flowing Well—Loads Up Periodically 86 26 Continuous Gas-lift—Normal Backpressure Higher Than Test Backpressure 87 27 Continuous Injection—Well Shut In 87 28 Continuous Injection—Well is Heading Periodically 88 29 Continuous Injection—Well is Unloading 89 30 Intermittent Injection—Varying Injection Frequencies 90 31 Intermittent Injection—Varying the Injection Pattern 91 32 Intermittent Injection—Injection Pressure Too High 92 33 Intermittent Injection—Well Loading Up 93 34 Intermittent Injection—Well Choked 94 35 Intermittent Injection—Well Has Leaks 95 36 Intermittent Injection—Well Has Tubing Leak 96 37 Intermittent Injection—Well Has Large Tubing Leak 97 38 Intermittent Injection—Gas Injection Pressure Too Low 98 39 Intermittent Injection—Plugging 99 40 Intermittent Injection—Injection Rate Too Low 100 41 Typical Acoustical Recording 101 42 Typical Acoustical Recording 102 43 Flowing Pressure Survey 106 44 Results of Flowing Pressure and Temperature Surveys Conducted During Intermittent Operation of High Capacity Well to Locate Operating Valve 108 45 The Gas-lift System 111 Introduction These recommended practices are offered to assist gas-lift system operators, analysts, technicians, engineers, and others in understanding how to effectively plan, operate, maintain, troubleshoot, and provide surveillance of gas-lift systems and gas-lift wells This document may be used in a gas-lift training course or as reference material It can be obtained in booklet form as an API publication, or on CD ROM or cassette in Adobe PDF format These recommended practices discuss continuous gas-lift with injection in the casing/tubing annulus and production up the tubing Annular flow gas-lift (injection down the tubing and production up the annulus), dual gas-lift (two tubing strings in the same casing), and intermittent gas-lift are mentioned; however, most of the discussion focuses on “conventional” continuous gas-lift Many of the recommended practices in this document may be pertinent to the other forms of gas-lift, but they should be considered and used with caution Other recommended practices will address dual gas-lift (API 11V9) and intermittent gas-lift (API 11V10) This document includes: — Gas-lift Operating System Components and Potential Problems Sections through 11 describe the several components of an operating gas-lift system and discuss a number of problems that may be encountered and must be addressed to operate a gas-lift system effectively and efficiently These sections are new to this edition of the document A comprehensive checklist of system components is provided and associated problems are discussed The list can be used when troubleshooting or de-bottlenecking a gas-lift system These sections are recommended for use as: — part of a training course dealing with gas-lift system operation; — a review before beginning a major gas-lift system study; — a review before designing and/or modelling a gas-lift system; — a review before trying to troubleshoot difficult gas-lift system problems — Recommended Practices for Gas-lift Operation, Maintenance, Surveillance, and Troubleshooting Sections 12 through 17 are revisions/upgrades of information that has been in existence since the first edition of this document These sections contain recommended practices for common gas-lift operations: — initial unloading of the completion or workover fluid from the annulus of the gas-lift well; — re-starting or kick off after a period of downtime; — adjusting or fine-tuning the gas injection rate for optimum operation These sections discuss commonly used gas-lift troubleshooting tools They conclude with sections that review the potential locations of gas-lift problems, a table of possible causes and cures of some common gas-lift system problems, and a troubleshooting checklist These sections are recommended for use as: — part of a training course dealing with gas-lift system operation; — part of a training course dealing with gas-lift system maintenance; — a review before trying to troubleshoot a difficult gas-lift operating problem 114 API RECOMMENDED PRACTICE 11V5 — monitor the production pressure If it bleeds down as the injection pressure drops, then a hole or leak in the tubing is indicated If the production pressure holds, find the casing fluid level at the new casing pressure using the acoustical sounding device; — check for a rise in the casing fluid level This is indication of tubing-casing communication or a packer leak; — verify that there is no hole if the production pressure and casing fluid level hold If no hole is present, both the check valves and gas-lift valves will be closed as the injection pressure bleeds to zero 16.3.2 Estimate the Operating Gas-lift Valve by Surface Pressure Closing Method This method can be used to estimate which is the operating gas-lift valve IPO valves will continue to transmit gas until the injection pressure drops to the closing pressure of the valve The operating gas-lift valve can sometimes be determined by shutting off the injection gas and observing the pressure to which the injection pressure decreases and stabilizes This pressure is the surface closing pressure of the operating gas-lift valve By comparing this pressure with the design surface closing pressure of each valve, the operating valve can often be determined However, note that the temperature and production pressure will also affect the “closing” pressure of the valve The observed surface “closing” pressure is not the same as the design closing pressure unless the production pressure and temperature at the depth of the valve are equal to the “design” production pressure and temperature values This method gives an approximate indication of the operating valve; it is not as accurate as a flowing pressure survey As the injection gas is turned off and the casing pressure begins to decrease, the tubing pressure will also change due to the decreased gas injection into the tubing This will affect the closing pressure of the valve 16.3.3 Check for a Well “Blowing Dry Gas” Check for gas injection through an upper valve, with no production The term “blowing dry gas” means the well is injecting gas but has no production When using IPO valves, verify the injection pressure is not above of the design operating pressure This may cause one or more upper unloading valves to open, and gas may be injected above the fluid level in the tubing In addition, upper valves can be open if the temperature is well below the design value Verify that no hole exists in the tubing by the method described above In addition, “sound” the casing fluid level with a sonic fluid level detection device If the upper unloading valves are not held open by excess injection pressure, if no hole exists, and if the casing fluid level shows that the well has been fully unloaded to the operating valve or orifice, the well is probably lifting from the bottom valve or orifice Verify operation from the bottom valve or orifice by comparing the surface closing pressure with the design pressure of the bottom valve or orifice The bottom valve is usually designed (“flagged”) so its surface operating pressure and closing pressure are significantly less than the other valves in the string If the well is equipped with PPO valves and has an IPO valve on the bottom, blowing dry gas can indicate operation on the bottom valve, after the possibility of a hole in the tubing has been eliminated, because PPO valves will not remain open if there is no fluid pressure If the well is blowing around and is operating from the bottom valve, this indicates a lack of inflow from the formation It is advisable to tag bottom to see if the perforations have been covered by sand or debris If the well is equipped with a standing valve, verify the standing valve is not plugged Standing valves are not used in continuous gas-lift wells 16.3.4 Troubleshoot a Well Not Taking Gas Eliminate the possibility of a frozen or plugged input choke, a closed injection gas valve, or closed valves on the outlet side If PPO valves are used without an IPO valve or orifice on bottom, this condition may indicate that all the fluid has RECOMMENDED PRACTICES FOR OPERATION, MAINTENANCE, SURVEILLANCE, AND TROUBLESHOOTING OF GAS-LIFT INSTALLATIONS 115 been lifted from the tubing and not enough production pressure remains to open the valves Check for inflow problems If IPO valves are used, verify the well started producing above the design fluid rate A higher production rate may have caused the temperature to increase sufficiently to close (”lock-out') the valves If high temperature is the problem, the well will produce periodically then quit If this is not the problem, verify the valve set pressures are not too high for the available injection pressure If the well has a surface or sub-surface safety valve, verify that it is open 16.3.5 Troubleshoot a Well That is Flowing in Slugs Evaluate several factors that can be cause this situation With IPO valves, one cause may be port sizes are too large This might occur if, for example, a well was initially designed for intermittent lift and was placed on continuous gas-lift due to higher than anticipated fluid production rates Large production pressure effects will exist because of the high tubing effect factors of the valves; the well will lift until the fluid gradient is reduced below the point where the production pressure would keep the operating valve open Injecting through an oversized orifice at the operating depth can also cause slugging Temperature effects may also cause slugging If the well started producing at a higher than anticipated fluid rate, the temperature could increase; this could cause the valve set pressures to increase and cause them to close or “lock out.” When the temperature cools sufficiently, the valves will open again; the well will produce in cycles or heads Check production inflow from the formation With IPO valves that have a high production pressure effect, or with PPO valves, slugging can occur with limited inflow from the formation The valves will not open until the tubing (production) pressure has risen far enough, thus creating a condition where the well will self intermit whenever adequate inflow has occurred Evaluate tubing size Heading can be caused if the tubing size is too large for the production rate being lifted Evaluate multi-pointing Slugging can result from any condition that causes a well to work from two or more valves, such as an excessively long valve spacing in wells with a low injection rate, varying injection pressure, insufficient gas injection rate, valve interference caused by flowline chokes, or incorrectly designed gas-lift valve set pressures and temperatures 16.3.6 Evaluate a Well That is Stymied and Will Not Unload This condition occurs when the fluid column (tubing) pressure is heavier (higher) than the available gas-lift injection pressure Apply injection gas pressure to the top of the fluid column (usually by using an equalizing line) This may temporarily drive some of the fluid column back into the formation, thereby reducing the height of the fluid column, and allow the well to unload with the available gas-lift pressure Clearly, this will not work if there is a standing valve in the tubing The check valves in the gas-lift valves will prevent the fluid from being displaced from the tubing back into the casing Do not use this process, which is referred to as “rocking” the well, if there is any chance of sand production This can damage the sand control system in the well It may also cause plugging of the formation interface to the wellbore by injecting fine material back into the formation For PPO valves, “rocking” the well in this fashion may open an upper valve and permit the unloading operation to continue 116 API RECOMMENDED PRACTICE 11V5 Sometimes a well can be “swabbed” to allow unloading to a deeper valve, but “swabbing” should be avoided if at all possible due to the chances of sticking a swab cup, inadvertently unseating and pulling a retrievable gas-lift valve with the swab, getting “blown up the hole,” or “sucking” sand into the wellbore Use these methods with extreme caution Wells can be seriously damaged by pushing fluid back into the reservoir and/or by “rocking.” Unless there is a history of successfully using these techniques in a field, they should only be used as a last resort Consider these other possible approaches to unload a “stymied” well: — find a way to temporarily reduce the wellhead backpressure; — find a way to temporarily increase the gas-lift injection pressure For example, ft may be possible to use a nearby gas well or a nitrogen truck to initially unload the well Alternatively, it may be possible to temporarily raise the discharge pressure from the compressor by temporarily raising the set pressure on the sales gas pressure regulator (However, this may cause many unintended problems in a gas-lift system that serves many wells.); — finally, it may be less expensive to pull the tubing and re-space the gas-lift mandrels than to risk causing damage to the formation or the sand control system in the well 16.3.7 Correct any Valve That is Hung Open Identify this if the gas-lift pressure will bleed below the surface closing pressure of any valve in the hole; but tests show that no hole is present Try shutting the wing valve on the flowline, allow the casing pressure to build up as high as possible, and open the wing valve rapidly This will create a high differential pressure across the seat of the operating valve and may remove any trash holding the valve open Repeat the process several times if required Valves can sometimes be held open by salt deposition If this is suspected, pump several barrels (m3) of fresh water into the casing to dissolve the salt Where fresh water sensitive formations exist, verify this technique will not allow the water to contact the formation If the above actions not help, the gas-lift valve may be cut or eroded, or the bellows may be de-pressured In this case, pull and replace the valve 16.3.8 Correct Too Wide Mandrel Spacing In some instances, a well will not fully unload due to excessively wide mandrel spacing This occurs when a well produces at a higher rate or has a higher reservoir pressure than anticipated during the valve design This situation is essentially the same as the “stymied” well discussed above If necessary, after considering all of the risks, the following procedures may be tried: — try “rocking” the well as discussed when the well is “stymied,” as this will sometimes allow working down to lower valves But be careful!; — if a high-pressure gas well (or a nitrogen truck) is nearby, use the high pressure for unloading If IPO valves are used, this will require sufficient lift gas volume to over-ride the gas passage capability of the upper valve(s) to allow the injection pressure to build up; — produce the well to an atmospheric tank or pit to minimize wellhead backpressure; RECOMMENDED PRACTICES FOR OPERATION, MAINTENANCE, SURVEILLANCE, AND TROUBLESHOOTING OF GAS-LIFT INSTALLATIONS 117 — try re-spacing the gas-lift mandrels, or as a last resort installing a pack-off gas-lift valve or orifice between existing mandrels, if the problem is severe and cannot be solved by one of the other methods; — installing a pack-off valve, or any other action that places a hole in the tubing, is not recommended as a long-term solution If the well is stymied due to too wide mandrel spacing, and if there is enough extra production potential to justify a workover, the recommended action is to work over the well to re-space the gas-lift mandrels so the well can work down to the desired operating depth 17 Possible Causes and Cures of Common Malfunctions of Gas-lift Systems Malfunction Communication Between Casing and Tubing Possible Cause(s) Gas-lift valve cut or stuck open Possible Cure(s) — Replace leaking or unseated valve — Check unloading procedures to avoid erosion — Consider using different (harder) materials for seats Gas-lift valve or dummy unseated — Replace unseated valve or dummy Gas-lift mandrel leak — Pull tubing, replace leaking mandrel Packer leak — Reset packer Tubing or tubing head leak — Pull tubing, repair leak, and re-run Circulating sleeve leak — Close circulating sleeve — Use pack-off for short-term correction Injection Pressure Above/Below Normal or Heading Lifting from a higher gas-lift valve — Analyze well and adjust to work down Gas-lift valve plugged — Pull and replace valve Higher temperature keeping valves open — Pull and redesign valves for higher closed temperature — Check by running a temperature survey Gas-lift valve set pressures increase — Pull valves, check for tail plug or gasket leaks Well lifting from upper gas-lift valve — Pull valve(s) and replace them, or if necessary, redesign or re-space them Well lifting from more than one valve, injection pressure is heading — Well lifting from orifice, but heading — Port size too large, pull and replace Redesign valves and re-tune injection to prevent multi-valve operation and heading — Try lowering casing pressure Small fluid per intermittent cycle — Reduce intermittent cycle frequency Injection meter reading incorrect — Check meter, orifice, connecting lines differential pressure taps, 118 API RECOMMENDED PRACTICE 11V5 Malfunction High Back Pressure at Well Head Sudden Drop in Production (Valve Operation Appears Normal) Fluid Slug Velocity Less Than 1,000 ft (304.8 m) in Intermittent Gas-lift Well Possible Cause(s) Possible Cure(s) Plugged flowline — Check for partially closed valves, plugged check valves, paraffin, or sand High separator pressure — Check backpressure regulator Using too much gas — Adjust injection control to optimize gas Choke in flowline — Remove any chokes or restrictions Flowline too small — Loop line or replace with larger line Plugged formation — Clean out well, consider stimulation Plugged tubing — Tag bottom If plugged, clean out or pull tubing Too much or too little gas — Adjust injection control to optimize gas Standing valve stuck open/ closed — Pull standing valve and clean it Subsurface safety valve closed — Correct cause of premature closing, reset safety valve, pull valve is no longer needed Fluid load heavy — Increase injection cycle frequency Low injection pressure — Increase pressure or space valves closer Operating valve partially plugged — Flush with fresh water or solvent Tubing partially plugged — Cut paraffin or flush well with solvent Poor injection valve response — Increase injection gas rate to achieve rapid injection pressure build-up Operating valve port too small — Pull valve and replace with larger port RECOMMENDED PRACTICES FOR OPERATION, MAINTENANCE, SURVEILLANCE, AND TROUBLESHOOTING OF GAS-LIFT INSTALLATIONS 18 Gas-lift Troubleshooting Checklist Gas-lift Troubleshooting Checklist Page Field: Well: Date: Gas Injection Inlet or Source Problems Possible Gas Injection Source/Supply Problems [ ] Injection control choke or valve size may be too large — Upper valve(s) may be reopening — Too much gas may be injected [ ] Injection control choke or valve size may be too small — May not be able to unload the well — Too little gas may be injected [ ] Injection control choke or valve may be plugged — Choke or control valve may be frozen [ ] Bad pressure gauges may be causing excessive or insufficient gas injection pressure [ ] Gas-lift supply may be turned off or shut down [ ] Gas-lift line pressure may be too low [ ] Gas-lift line pressure may be fluctuating [ ] Gas-lift intermitter may be stopped — Cycle or injection time may be wrong [ ] Gas-lift intermitter being used on continuous gas-lift well [ ] Gas-lift intermitter may be malfunctioning [ ] Other problems/comments: Corrective Action: 119 120 API RECOMMENDED PRACTICE 11V5 Gas-lift Troubleshooting Checklist Page Gas-lift Well Production Outlet Problems Possible Gas-lift Well Production Problems [ ] Master valve or wing valve may be closed [ ] There may be high wellhead backpressure due to: — A flowline choke — Flowline choke body may be too restrictive — An excessive number of 90º turns — A long flowline — A plugged or partially plugged flowline, with sand or paraffin — Emulsion — Hilly terrain — A number of canal crossings — A small flowline internal diameter — A valve closed at the header or manifold — A valve with a restricted internal diameter — A plugged or jammed flowline check valve — A valve leaking at the header allowing backpressure from other wells — Separator operating pressure may be too high — Separator orifice plate may be sized too small [ ] Other problems/comments: Corrective Action: RECOMMENDED PRACTICES FOR OPERATION, MAINTENANCE, SURVEILLANCE, AND TROUBLESHOOTING OF GAS-LIFT INSTALLATIONS Gas-lift Troubleshooting Checklist Page Downhole Problems Possible Downhole Gas-lift Problems [ ] There appears to be no fluid feed-in Fluid is standing at or below bottom gas-lift valve [ ] Perforations appear to be covered by sand or other material [ ] There may be a restriction(s) in the tubing string [ ] Mandrel spacing may be too wide to allow the well to be unloaded [ ] The bottom valve may not be set deep enough [ ] There may be a valve worn, cut out, or unseated [ ] There may be a dummy cut out or unseated [ ] There may be a gas-lift mandrel leak [ ] There may be a tubing leak [ ] There may be a leaking pack-off gas-lift valve [ ] The gas-lift valve pressure(s) may be set too low Cannot close one or more valves [ ] The gas-lift valve pressure(s) may be set too high Cannot open one or more valves [ ] Excessive injection or production pressure appears to be re-opening valve(s) up the hole [ ] The well is lifting from the bottom valve but: — Well may be under producing due to excessive wellhead backpressure — Well may be under producing due to low casing pressure or insufficient lift gas — Well is unstable due to too large an orifice or choke [ ] The well has dual gas-lift and: — One side of the dual may be robbing most of the gas — Too high or too low temperature may be affecting the valves in one string [ ] Other problems/comments: Corrective Action: 121 Bibliography [1] API Specification 11V1, Specification for Gas Lift Equipment [2] API Recommended Practice 11V2, Gas-lift Valve Performance Testing [3] API Recommended Practice 11V7, Recommended Practice for Repair, Testing, and Setting Gas Lift Valves [4] API Recommended Practice 11V8, Recommended Practice for Gas Lift System Design and Performance Prediction [5] API Recommended Practice 11V10, Recommended Practices for Design and Operation of Intermittent and Chamber Gas-lift Wells and Systems [6] ISO 17078-2 1, Petroleum and natural gas industries—Drilling and production equipment—Part 2: Flow control devices 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PROGRAMS (ICP®) Phone: 202-682-8064 Fax: 202-682-8348 Email: icp@api.org API QUALITY REGISTRAR (APIQR®) API ENGINE OIL LICENSING AND CERTIFICATION SYSTEM (EOLCS) Phone: 202-682-8516 Fax: 202-962-4739 Email: eolcs@api.org > ISO 9001 Registration > ISO/TS 29001 Registration > ISO 14001 Registration > API Spec Q1® Registration Phone: 202-962-4791 Fax: 202-682-8070 Email: certification@api.org API PERFORATOR DESIGN REGISTRATION PROGRAM Phone: 202-682-8490 Fax: 202-682-8070 Email: perfdesign@api.org API TRAINING PROVIDER CERTIFICATION PROGRAM (API TPCPTM) Phone: 202-682-8490 Fax: 202-682-8070 Email: tpcp@api.org API PETROTEAM (TRAINING, EDUCATION AND MEETINGS) Phone: 202-682-8195 Fax: 202-682-8222 Email: petroteam@api.org API UNIVERSITYTM Phone: 202-682-8195 Fax: 202-682-8222 Email: training@api.org Check out the API Publications, Programs, and Services Catalog online at www.api.org Copyright 2008 – API, all rights reserved API, API monogram, APIQR, API Spec Q1, API TPCP, ICP, API University and the API logo are either trademarks or registered trademarks of API in the United States and/or other countries .5VTGGV09 9CUJKPIVQP&% 75#  #FFKVKQPCNEQRKGUCTGCXCKNCDNGVJTQWIJ+*5 2JQPG1TFGTU  6QNNHTGGKPVJG75CPF%CPCFC   QECNCPF+PVGTPCVKQPCN (CZ1TFGTU  1PNKPG1TFGTU INQDCNKJUEQO +PHQTOCVKQPCDQWV#2+2WDNKECVKQPU2TQITCOUCPF5GTXKEGU KUCXCKNCDNGQPVJGYGDCVYYYCRKQTI Product No G11V53