Recommended Practice for Design, Operation,
and Troubleshooting of Dual Gas-Lift Wells
Version: October 3, 2008
API RECOMMENDED PRACTICE 11V9 (RP 11V9)
Draft #6, October 3, 2008
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API RP 11V9Recommended Practices for Design, Operation,Page 1
and Troubleshooting of Dual Gas-Lift Wells
Foreword
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API RP 11V9Recommended Practices for Design, Operation,Page 1
and Troubleshooting of Dual Gas-Lift Wells
Table of Contents
SubjectPage
1Introduction
1.1Purpose of this document
1.2Why dual wells exist
1.2.1Lower drilling cost
1.2.2Insufficient surface space
1.2.3Multi-lateral completions
1.2.4Completion/operation concerns
2Dual Gas-Lift Overview
2.1Goals of dual gas-lift
2.1.1Inject in both strings simultaneously
2.1.2Inject as deep as possible in both sides
2.1.3Inject in a stable manner
2.1.4Inject at an optimum rate
2.2Problems associated with dual gas-lift
2.2.1Completion issues associated with dual gas-lift
2.2.2Design issues
2.2.3Operational issues
2.2.4Control issues
2.2.5Surveillance issues
2.2.6Alternatives to dual gas-lift
3Recommended Practices
3.1Practices that are recommended
3.1.1Selecting acceptable dual gas-lift candidates (from Chapter 4)
3.1.2Staffing dual gas-lift operations (from Chapter 5)
3.1.3Dual gas-lift design (from Chapter 6)
3.1.4Dual gas-lift operation (from Chapter 7)
3.1.5Dual gas-lift surveillance (from Chapter 8)
3.1.6Dual gas-lift diagnosis and troubleshooting (from Chapter 9)
3.1.7Dual gas-lift automation (from Chapter 10)
3.1.8Dual gas-lift special issues (from Chapter 11)
3.2Practices that are not recommended
3.2.1Selecting dual gas-lift candidates (from Chapter 4)
3.2.2Dual gas-lift staff (from Chapter 5)
3.2.3Dual gas-lift design (from Chapter 6)
3.2.4Dual gas-lift operation (from Chapter 7)
3.2.5Dual gas-lift surveillance (from Chapter 8)
3.2.6Dual gas-lift diagnosis and troubleshooting (from Chapter 9)
3.2.7Dual gas-lift automation (from Chapter 10)
3.2.8Dual gas-lift special issues (from Chapter 11)
4Candidates and Screening Criteria for Dual Gas-Lift
4.1Wells that are acceptable candidates for dual gas-lift
4.1.1Economics
4.1.2Operational issues
4.1.3Recommended practices for selecting acceptable candidates
4.2Wells that are not good candidates for dual gas-lift
4.2.1Two zones too far apart
4.2.2Low formation GOR
4.2.3Need to intermittent one or both sides
4.2.4Small casing size
4.2.5Recommended practices to avoid some wells
4.3Reasons to consider artificial lift alternatives rather than dual gas-lift
4.3.1If can afford to complete the wells as singles
4.3.2More costly to complete and perform workovers, abandonment
4.3.3Expertise needed to successfully operate duals is lacking in company
4.3.4It is allowed and technically feasible to commingle
4.3.5Potential need for remedial work below end of short string tubing
4.3.6Having duals makes surveillance using casing pressure more difficult
4.3.7Recommended practices to consider alternatives to dual gas-lift
5Commitment Required for Successful Dual Gas-Lift
5.1Commitment required by management
5.1.1Be informed on business issues/economics of dual gas-lift
5.1.2Foster continuous improvement
5.1.3Provide continuity of artificial lift team or champion
5.1.4Allow access for champion to management
5.1.5Provide long term training and support on dual gas-lift
5.1.6Use drilling/completion savings for increased operating/surveillance costs
5.1.7Recommended practices for management of dual gas-lift systems
5.2Commitment required by engineering
5.2.1“Go to school” on dual gas-lift – continuing education
5.2.2Understand API RP 11V8 (Systems) and API RP 11V9 (Dual Gas-Lift)
5.2.3Understand needs and responsibilities of other engineering disciplines
5.2.4Understand operational issues that affect dual gas-lift
5.2.5Awareness of increased impact on duals of adverse downhole concerns
5.2.6Awareness of inter-zone interference
5.2.7Understand personnel issues that affect dual gas-lift
5.2.8Recommended practices for engineering dual gas-lift systems
5.3Commitment required by members of dual gas-lift team
5.3.1“Go to school” on dual gas-lift – continuing education
5.3.2Understand API RP 11V8 (Systems) and API RP 11V9 (Dual Gas-Lift)
5.3.3Be open to perceiving that work on dual gas-lift is advantageous
5.3.4Maintain lines of communication with engineering/champion
5.3.5Participate fully on dual gas-lift team
5.3.6Document economic gains/benefits of working on dual gas-lift
5.3.7Recommended practices for the dual gas-lift team
5.4Commitment required by trainers, others
5.4.1Develop and deliver effective dual gas-lift training programs
5.4.2Recommended practices for trainers, others
6Designing Dual Gas-Lift Wells
6.1Mandrel spacing
6.1.1Design spacing based on requirements of lower zone
6.1.2Design spacing based on requirements of most prolific zone
6.1.3Design spacing for each side of the dual based on its conditions/needs
6.1.4Design with flexibility to allow use of different types of valves
6.1.5Gas-lift mandrel spacing production pressure “design line” options
6.1.6Recommended gas-lift mandrel spacing design procedure
6.1.7Be aware of installation issues
6.1.8Recommended practices for mandrel spacing
6.2When one zone is much deeper than other side
6.2.1Alternatives if two zones are vertically far apart
6.2.2Recommended practices when one zone is significantly deeper
6.3The PPO vs. IPO gas-lift valve debate
6.3.1PPO support, logic, and issues
6.3.2Support, logic, and issues associated with using IPO valves
6.3.3Balanced IPO (continuous or constant flow) valve support, logic, issues
6.3.4Differential valve support, logic, and issues
6.3.5Recommended practices for selecting type of unloading valve
6.4Unloading gas-lift valves
6.4.1Unloading valve design for each type of valve
6.4.2Recommended practices for unloading valve design
6.5Operating gas-lift valve or orifice
6.5.1Alternatives for operating gas-lift valve or orifice
6.5.2Recommended practices for operating gas-lift valve or orifice
6.6Designing for dual gas-lift if mandrels spaced too far apart
6.6.1May need to use IPO, at least in upper mandrels
6.6.2Possible use of pack-off valves
6.6.3Possible use of concentric string
6.6.4Recommended practices if mandrels are too far apart
6.7Review of various dual gas-lift design options
6.7.1PPO valves on both sides
6.7.2IPO valves high in the hole, PPO valves lower in the hole
6.7.3IPO valves on one side, PPO valves on the other side
6.7.4IPO valves on both sides
6.7.5Single point injection
6.7.6Recommended practices for considering various design options
7Operation of Dual Gas-Lift Wells
7.1Installing dual gas-lift equipment
7.1.1Running two strings together “simultaneously”
7.1.2Running two strings separately
7.1.3Consideration if there must be multiple packers on long string
7.1.4Surface-controlled (electric, hydraulic, cable-less) gas-lift valves
7.1.5Chemical lines
7.1.6Testing the packer
7.1.7Recommended practices for installing dual gas-lift equipment
7.2Wireline operations in dual gas-lift wells
7.2.1Possibility of cross flow when changing gas-lift equipment in a dual well
7.2.2Changing gas-lift valves in a dual completion
7.2.3Recommended practices for wireline operations
7.3Recommended wire line procedures
7.3.1Running gas-lift valves in dual gas-lift wells
7.3.2Installing valves when dummy valves are in the other string
7.3.3Recommended practices when performing wireline operations
7.3.4Alternate procedure (with dummy valves in the other string)
7.3.5Installing valves in duals with live valves in the other string
7.3.6Installing valves on the higher pressured zone
7.3.7Other methods
7.3.8Gas-lift valve installation problems
7.3.9Recommended practices for wireline operations
7.4Unloading dual gas-lift wells
7.4.1Options for unloading dual gas-lift wells
7.4.2Recommendations for unloading dual gas-lift wells
7.4.3Recommended practices for unloading dual gas-lift wells
7.5Kicking off dual gas-lift wells
7.5.1Recommendations for kicking off (restarting) dual gas-lift wells
7.5.2Recommended practices for kicking off (restarting) dual gas-lift wells
7.6Operating dual gas-lift wells
7.6.1Keep both zones on production
7.6.2Keep both zones deep, stable, and optimum
7.6.3Inject the correct amount of gas
7.6.4Inject at the correct pressure
7.6.5Operation when one or both zones are being tested
7.6.6Operation during pressure surveys
7.6.7Manual operation
7.6.8Semi-automatic operation
7.6.9Automatic operation
7.6.10Recommended practices for operating dual gas-lift wells
7.7Optimizing dual gas-lift wells
7.7.1Definition of optimization for dual gas-lift
7.7.2Determination of optimum injection rate
7.7.3Gas-lift allocation, staying near optimum
7.7.4Recommended practices for optimizing dual gas-lift wells
8Surveillance of Dual Gas-Lift Wells
8.1Wireline operations in gas-lift completions
8.2Pressure/temperature surveys
8.2.1Static Bottom-hole Pressure (SBHP) Survey
8.2.2Flowing Bottom-hole Pressure (FBHP) Survey
8.2.3Memory Production Logging Tools
8.2.4Recommended practices for running pressure/temperature surveys
8.3Using pressure/temperature surveys to evaluate and diagnose dual gas-lift
8.3.1Determine well’s productivity
8.3.2Diagnose/troubleshoot gas-lift performance
8.3.3Recommended practices for using pressure/temperature surveys
8.4Fluid levels
8.4.1Maximum depth to which well has been unloaded
8.4.2Checking for leaks
8.4.3Recommended practices for running, using fluid levels
8.5Well tests
8.5.1Test each well, with the other producing
8.5.2Test each well, with other well closed in
8.5.3Test both wells, with both wells in test separator at same time
8.5.4Recommended practices for conducting, using well tests
8.6CO2 tracer
8.6.1Can use to determine highest injection point
8.6.2Can tell if either side is multi-pointing
8.6.3Difficult to determine depth of lower injection point(s)
8.6.4Recommended practices for running, using CO2 tracer surveys
8.7Continuous monitoring and control
8.7.1Methods of continuous monitoring
8.7.2What to monitor
8.7.3Manual methods
8.7.4Chart recorders and manual control valves
8.7.5Electronic measurements and flow controllers
8.7.6Production automation systems
8.7.7Optimum monitoring frequency
8.7.8Making use of monitored information
8.7.9Recommended practices for continuous monitoring
9Diagnosis and Troubleshooting
9.1Diagnostic techniques
9.1.1Library of typical problems
9.1.2Comparison with two-pen charts
9.1.3Comparison of flowing pressure surveys
9.1.4Measurements of well performance
9.1.5Calibration of gas-lift model
9.1.6Compare current measurements with calibrated model
9.1.7Exception reporting of deviations
9.1.8Recommended practices for selecting dual gas-lift diagnostic techniques
9.2Methods to locate communication problems
9.2.1Proving communication
9.2.2Methods for Locating Tubing-Casing Communication
9.2.3Recommended practices for locating communication problems
9.3Examples of typical dual gas-lift problems
9.3.1Higher backpressure than the original designed conditions
9.3.2Lower injection pressure than the original designed conditions
9.3.3Higher injection pressure than the original designed conditions
9.3.4One string will not take injection gas or takes too little gas
9.3.5One string taking more injection gas than its designed rate
9.3.6One string has pressure depleted and is shut-in
9.3.7Tubing-casing communication
9.3.8Wells that produce emulsions
9.3.9Sand production
9.3.10Other typical gas-lift problems
9.3.11Recommended practices for understanding example problems
10Automation of Dual Gas-Lift Wells
10.1Gas-lift automation logic
10.1.1Recommended practices for automatic logic
10.2What to measure
10.2.1Required well measurements
10.2.2Optional well measurements
10.2.3Required system measurements
10.2.4Optional system measurements
10.2.5Recommended practices for automatic measurements
10.3What to control
10.3.1Required well control
10.3.2Optional well controls
10.3.3Required system control
10.3.4Optional system controls
10.3.5Recommended practices for automatic controls
10.4Responding to gas-lift system problems
10.4.1Gas-lift system upsets
10.4.2Restarting after an upset
10.4.3Controlling the well during well testing
10.4.4Responding to an obvious gas-lift problem in the well
10.4.5Recommendations for automatic response to gas-lift system problems
11Special Issues
11.1When gas-lift co-exists with a flowing well in the same wellbore
11.1.1Important considerations
11.1.2Recommended practices when a flowing and gas-lift well co-exist
11.2When gas-lift co-exists with a pumping well in the same wellbore
11.2.1Important considerations
11.2.2Recommended practices when a pumping and gas-lift well co-exist
11.3When one or both zones should be intermitted
11.3.1Important considerations
11.3.2Recommended practices when one or both zones should be intermitted
11.4When one zone completed with mandrels, one without mandrels
11.4.1Important considerations
11.4.2Recommended practices when one zone doesn’t have mandrels
11.5How to transition from flowing to dual gas-lift operation
11.5.1When to convert from flowing to gas-lift?
11.5.2Recommended practices to transition from flowing to dual gas-lift
12Dual Gas-Lift Mandrel Spacing Design
12.1Well description
12.2Design assumptions
12.3Mandrel spacing design for the long string
12.4Calculated long string mandrel depths
12.5Calculated short string mandrel depths
12.6Graphical design
13Dual Gas-Lift Unloading Valve Design for PPO Valves
13.1Step 1 --- Depth of perforations
13.2Step 2 --- Injection gas gradient line
13.3Step 3 --- Flowing pressure gradient line
13.4Step 4 --- Transfer pressure for each gas-lift valve
13.5Step 5 --- Safety factor
13.6Step 6 --- Gas-lift valve port size
13.7Step 7 --- Test rack opening pressure
13.8Step 8 --- Opening pressure at depth
13.9Step 9 --- Valve or orifice at operating depth
13.10Graphical method for designing PPO gas-lift valves
13.11Valve calculations for PPO gas-lift valves
API RP 11V9 – Recommended Practice for Dual Gas-Lift
This document is one of a series of recommended practices (RP's) produced by the American Petroleum Institute (API) for use by oil-field engineers, operators, and others around the world. This RP focuses on dual gas-lift.
1Introduction
This API recommended practice provides guidelines and tools to facilitate the effective and efficient design, operation, optimization, and troubleshooting of dual gas-lift completions. As used in this document, a dual completion is one in which there are two producing zones, each with its own tubing string, in a single production casing. So, there are two separate producing wells, with one common annulus.
It is sometimes concluded, in the development of fields with multiple reservoirs, that the economic benefits of dual completions outweigh the operational problems that frequently result from trying to effectively produce a dual completion and the higher operating and workover costs that may occur over the producing life. Thus, dual completions (and occasionally even triples) are sometimes attempted to reduce upfront drilling costs and accelerate production from the multiple reservoirs.
This document focuses on the issues that must be faced when it becomes necessary to artificially lift both sides of a dual completion with gas-lift. Management of the problems facing operators of dual gas-lift wells may be easier and more successful if the recommended practices in this document are followed.
1.1Purpose of this document
The purpose of this document is to provide recommended practices for the design, operation, optimization, and troubleshooting of dual gas-lift wells. Compared to single completions, dual completions have a higher initial cost, have more operating problems, are more difficult and expensive to work over, and often produce less efficiently. Based on experience, most technical gas-lift specialists and operations staff prefer single completions to duals.
It is not the purpose of this document to recommend the practice of dual gas-lift. In many cases, dual gas-lift is problematic and often it is ineffective. Often, it is difficult or even impossible to effectively produce both completions in a dual well using gas-lift, over the long term. If there are other feasible alternatives to produce dual wells, they should be considered.
However many dually-completed oil wells must be artificially lifted - either initially or after reservoir pressures have declined and/or water cuts have increased. And in many cases, the only practical or feasible method of artificial lift for these wells is gas-lift. So, if dual wells must be artificially lifted, and if the only practical or feasible means to do this is with gas-lift, every effort must be made to perform this dual gas-lift function as effectively as possible.