Gas Lift Optimization and Troubleshooting
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This document provides an overview of gas-lift optimization and troubleshooting. It discusses identifying underperforming wells using metrics like the well performance factor and target injection differential. It then covers optimizing wells by adjusting injection gas rates, removing surface restrictions, redesigning the system, and adding secondary lift. Common inlet, outlet, and downhole problems are outlined along with tests and adjustments to address issues. Tuning the well for continuous flow is also described. Finally, tools for surface and subsurface data collection to aid in troubleshooting are listed.
Gas Lift Optimization and Troubleshooting
- 1. Gas-Lift Optimization and Troubleshooting 4-14-2015 Instructor: Matt Young
- 2. Tweet your takeaway from this educational session. @MidlandEnrgExpo #MEEFlowCo
- 4. Gas-Lift Optimization The purpose of Gas-Lift Optimization: 1. Increase production. 2. Extend life of artificial lift system. 3. Better utilize compressor Hp, and gas volumes. 4. Reduce operating cost. 5. Lower capital expenditure.
- 5. Gas-Lift Optimization Where to Start??? • Casing Pressure • Production Rates • Well closest to the house • New well • Old well
- 6. Gas-Lift Optimization Identifying Candidates and System Issues: Hold production meeting to highlight issues and begin to create list of under- performing wells. Criteria to identify candidates: 1. Well Performance Factor (WPF) = (Gas Injection Rate mcfd)/(Total Fluid Rate bfpd) The higher WPF number are the first well to review for inefficiencies. 2. Target Injection Differential (TID) = (Casing Pressure psi – Flowing Wellhead Pressure psi)/(Casing Pressure psi) Create range for further analysis: Lowest Percentage gets highest importance
- 7. Gas-Lift Optimization Identifying Candidates and System Issues: Well Performance Factor (WPF) = (Gas Injection Rate mcfd)/(Total Fluid Rate bfpd) The higher WPF number are the first well to review for inefficiencies. Well Number Injection Gas Volume Mcfd Total Fluid Production WPF Well Review Importance 8 679 131 5.18 1 2 589 159 3.70 2 6 708 216 3.28 3 3 743 290 2.56 4 1 587 261 2.25 5 5 877 668 1.31 6 7 718 737 0.97 7 4 616 719 0.86 8 9 378 673 0.56 9 10 183 739 0.25 10
- 8. Gas-Lift Optimization Identifying Candidates and System Issues: 1. Target Injection Differential (TID) = (Casing Pressure psi – Flowing Wellhead Pressure psi)/(Casing Pressure psi) Create range for further analysis: Lowest Percentage gets highest importance Well Number Injection Gas Volume Mcfd Total Fluid Production WPF Well Review Importance Operating Casing Pressure FWHP TID Finalize Importance 8 679 131 5.18 1 523 115 78% 1.5 2 589 159 3.70 2 635 106 83% 3.0 6 708 216 3.28 3 727 281 61% 6.5 3 743 290 2.56 4 850 299 65% 5.0 1 587 261 2.25 5 720 147 80% 6.5 5 877 668 1.31 6 1045 118 89% 10.0 7 718 737 0.97 7 1000 269 73% 9.5 4 616 719 0.86 8 1074 308 71% 13.0 9 378 673 0.56 9 1005 118 88% 12.5 10 183 739 0.25 10 1015 99 90% 15.0
- 9. Gas-Lift Optimization Once well selection has occurred… Its time to start Optimizing the wells! 1. Adjustment of injection gas. 2. Removing or reducing surface pressure restrictions 3. System redesign 4. Introduction of secondary artificial lift system
- 10. Gas-Lift Optimization Adjustment of injection gas: 1. Utilize tubing critical velocity charts 2. Build NODAL analysis model to predict gas volume 3. Multi-rate well tests verse adjustments in injection volumes
- 11. Gas-Lift Optimization Adjustment of injection gas: 1. Utilize tubing critical velocity charts
- 12. Gas-Lift Optimization Adjustment of injection gas: 1. Build NODAL analysis model to predict gas volume
- 13. Gas-Lift Optimization Once well selection has occurred… Its time to start Optimizing the wells! 1. Removing or reducing surface pressure restrictions 1. Open/Remove Wellhead Chokes 2. Reduce the number of 90 degree elbows used in flow line 3. Set wellhead compression “Eight elbows equal a bull plug”
- 14. Gas-Lift Optimization Once well selection has occurred… Its time to start Optimizing the wells! 1. Removing or reducing surface pressure restrictions
- 15. Gas-Lift Optimization Once well selection has occurred… Its time to start Optimizing the wells! 1. System redesign 1. Run Flowing Pressure/Temperature Survey 1. Redesign to get optimal injection point and lowest FBHP 2. Adjust for surface or facility conditions 3. Move injection point and EOT deeper into well 4. Apply special application gas lift 1. Dip Tube 2. Deadstring 3. Below packer gas lift
- 16. Gas-Lift Optimization Once well selection has occurred… Its time to start Optimizing the wells! 1. System redesign 1. Run Flowing Pressure/Temperature Survey 1. Redesign to get optimal injection point and lowest FBHP FBHP Survey indicates injection at 2500’, and correct injection should be 3500’. Check for leaking valve, and rerun.
- 17. Once well selection has occurred… Its time to start Optimizing the wells! 1. System redesign 1. Move injection point and EOT deeper into well
- 18. Gas-Lift Optimization Once well selection has occurred… Its time to start Optimizing the wells! 1. Introduction of secondary artificial lift system 1. Plunger Assisted Gas Lift 2. Surfactant or Form Injection
- 19. Gas-Lift Optimization Once well selection has occurred… Its time to start Optimizing the wells! 1. Introduction of secondary artificial lift system 1. Plunger Assisted Gas Lift • Efficiently utilizes the injection gas energy in any well by providing a sealing interface between the lift gas and produced liquids. This change in interface effects the flow pattern thus minimizing fluid fallback. • Benefits of plunger assisted gas lift: • Helps to maintain production on high GLR gas lift wells • Reduces fluid fallback in both continuous and intermittent gas lift wells • Improves efficiency of gas lift system by cutting back on required injection gas volumes • Minimizes paraffin, scale, and other deposits build up on the tubing walls
- 20. General Gas Lift System Problems
- 21. General Gas Lift System Problems • Problems with your gas lift system are often associated with three areas: • Inlet (surface) • Outlet (surface) • Downhole • More often than not, the problem can be found at the surface. Thoroughly explore all potential surface problems before incurring the expense of a rig to investigate downhole causes. • Also, keep in mind that poor optimization is most often caused by inaccurate gauge readings that can occur due to gauge malfunction or blockage. • Always troubleshoot your well at the surface before you call a rig!
- 22. Inlet Problems • Changes in casing pressure and gas volume typically indicate a problem with the inlet. • Low Casing Pressure • Check the choke to see if it is plugged, frozen or too small, well not taking gas • If frozen run warm gas, or set up methanol injection • Check gauge readings to be sure the problem is real • Verify gas volume being injected • Check back pressure regulator
- 23. Inlet Problems • High Casing Pressure • Verify gas injection volume • Over injection can cause high injection pressure • Partially plugged gas lift valve • Check flowing temperature affect on gas lift valve • Higher than normal tubing pressure • Restriction in the tubing
- 24. Inlet Problems • Low Gas Usage • Low manifold pressure in multi-well system • Confirm gas volume through injection meter • Verify correct trim in injection/flow control choke • Verify operating temperatures of gas lift valve • Test injection/flow choke to ensure it is operating appropriately
- 25. Inlet Problems • Excessive Gas Usage • Check the casing pressure • If using manual choke, with low casing pressure, check choke size and replace for smaller choke. • Over injection, gas lifting through multiple gas lift valves • Tubing or collar leak • Cut or washed out gas lift valve
- 26. Inlet Problems • Choke Sizing – Injection Control • The design gas-liquid ratio or designed injection volume can often give an indication of the choke size to use as a starting point. • Faulty Gauges • Check the wellhead casing and tubing pressures with a calibrated gauge. Inaccurate gauges can cause false indications of high or low casing pressures.
- 27. Outlet Problems • High back pressure is a common indicator of a problem with the outlet. • Restriction through choke, debris or choke body. Even with no choke bean in a choke body, it is usually restricted to less than full I.D. Remove the choke body if possible. • Check for paraffin or scale buildup in the flowline. Hot oiling the line will generally remove paraffin. Scale can be reduced and managed with methods such as chemical washes, or continual chemical injections • Flowlines- Loop Lines, add line or remove 90° turns or elbows
- 28. Outlet Problems • Separator Operating Pressure • The separator pressure should be maintained as low as possible for gas lift wells. Often a well may be flowing to a high or intermediate pressure system when it dies and is placed on gas lift. Ensure the well is switched to the lowest pressure system available. Sometimes an undersized orifice plate in the meter at the separator will cause high back pressure. • Valve Restrictions • Check to ensure all valves at the tree and header are fully open. Also, verify the valve is sized properly (for example, a 2-inch valve should be used in a 2- inch flowline). A smashed or crimped flowline is another possibility. Inspect the flowline in places where it crosses a road, for example.
- 29. Downhole Problems • Review all Inlet and Outlet Problems and remove as many restrictions from the system as possible before exploring downhole causes.
- 30. Downhole Problems • Well Blowing Dry Gas • For pressure valves, check to ensure that the casing pressure does not exceed the design operating pressure. Excess casing pressure can result in the upper valves staying open. • Check Tubing for communication • Also check that the tubing is free of holes Verify lift point with echometer or survey, to confirm lift point • Conclude inflow from formation if possible – tag with wireline • If the upper valves are operating properly and no hole exists, then operation is probably from the bottom valve. Additional verification can be obtained by checking the surface closing pressure, and performing a PSC Test.
- 31. Downhole Problems • Well Will Not Accept Input Gas • Eliminate the possibility of a frozen input choke or a closed input gas valve by measuring the pressure upstream and downstream of the choke. • Also check for closed wing valves on the outlet side • Check for feed in problems. If pressure valves were run, check to see if the well started producing above the design fluid rate as the higher rate may have caused the temperatures to increase sufficiently to lock out the valves. • If temperature is the problem, the well will probably produce periodically then stop. • As an additional measure, ensure that the valve set pressures (PSO) are not too high for the available casing pressure.
- 32. Downhole Problems • Well Flowing in Heads • Since too much or too little injection can often cause a well to head, first try “tuning in” the well. • With pressure valves, the well may flow in heads if the port sizes are too large. • In this case, large tubing effects are involved, causing the well to lift until the fluid gradient is reduced below a value that will keep the valve open. With the high tubing effect on fluid operated valves, heading can occur as a result of limited feed in. The valves will not open until the proper fluid load has been obtained, causing the well to intermit itself as adequate feed in is achieved. • Temperature interference may also cause the well to flow in heads. For example, if the well started producing at a higher than anticipated fluid rate, the temperature could increase, causing the valves’ operating pressure to increase and consequently lock them out. When the temperature cools sufficiently, the valves will open again, creating a condition where the well would flow by heads.
- 33. Downhole Problems • Installation Stymied and Well Will Not Unload • Try applying injection gas pressure to the top of the fluid column (usually with a jumper line). • Often, this will drive some of the fluid column back into the formation, reducing the height of the fluid column being lifted and allowing unloading with the available lift pressure. • This condition generally occurs when the fluid column is heavier than the available lift pressure or if the designed fluid weight is less than the actual weight. • The check valves prevent this fluid from being displaced back into the casing. • Sometimes, a well can be “swabbed” or “jetted with N2” to allow unloading to a deeper valve. • Also ensure that the wellhead back pressure is not excessive, or that the fluid used to kill the well for workover was not too heavy for the design.
- 34. Downhole Problems • Valve Hung Open • This case can be identified when casing pressure drops below the surface closing pressure of any valve in the hole, and it has been determined that a hole in the tubing is not the cause. • Try shutting the wing valve to the wellhead and allowing the casing pressure to build up as high as possible, then open the wing valve rapidly. This action will create high differential pressures across the valve seat, removing any matter that may be holding it open. • Repeat the process several times if required. • In some cases, valves are held open by salt deposition. Pumping several barrels of fresh water into the casing will solve the problem. If all other potential causes have been eliminated, a cut out or flat valve may be the cause.
- 35. Downhole Problems • Hole in Tubing – Test with Gas • Indicators of a hole in the tubing include abnormally low casing pressure and excessively high gas usage. A hole in the tubing can be confirmed by the following procedure: 1. Equalize the tubing pressure and casing pressure by closing the wing valve with the gas lift gas on. 2. After the pressures are equalized, shut off the gas input valve and rapidly bleed off the casing pressure. • If the tubing pressure falls as the casing pressure drops, then a hole is indicated. The tubing pressure will hold if no hole is present since both the check valves and gas lift valves will be in the closed position as the casing pressure drops. A packer leak may also cause symptoms similar to a hole in the tubing.
- 36. Downhole Problems • Operating Pressure Valve by Surface Closing Pressure Test (PSC Test) • A pressure operated valve will inject gas until the casing pressure drops to the closing pressure of the valve. • As such, the operating valve’s surface closing pressure can often be determined by shutting off the input gas and noting the pressure at which the casing pressure stabilizes. This pressure is the same as the closing pressure of the valve. Closing pressure analysis assumes two things: 1) the tubing pressure to be zero and 2) there is single point injection. These assumptions limit the accuracy of this method since the tubing pressure at each valve is never zero, and multipoint injection may be occurring. Nonetheless, this method can be helpful when used in combination with other data to bracket the operating valve.
- 37. Downhole Problems • Valve Spacing Too Wide • Try “rocking” the well as indicated when the well will not unload. This may allow injection to work down to lower valves. • If a high pressure gas well is nearby, using the pressure from this well may facilitate unloading or N2 unit. • If the problem is severe, you may need to re-space the valves, install a pack off gas lift valve, or shoot an orifice into the tubing to achieve a new point of injection.
- 39. Tuning the Well • Continuous Flow • Unloading a well generally requires more gas volume injection than when producing the well. • Gas usage can also be costly when using a compressor. As such, it is desirable in continuous flow installations to achieve the maximum fluid production with the minimum amount of input gas. Often, the input gas volume can be reduced once the point of injection has been reached. This can be accomplished by starting the well on relatively small input choke, such as 8/64, and then increasing the input choke size by 1/64 increments until the maximum fluid rate is achieved. Allow the well to stabilize for 24 hours after each change before making another adjustment. If, for some reason, a flowline choke is being used, increase the size of that choke until maximum fluid is produced before increasing the gas input choke.
- 40. Troubleshooting and Optimization Tools Surface Data Collection Tools: • Recording surface pressures on Tubing and Casing • Measurement of lift gas • Well Test • Two-Pin Recorder Subsurface Data Collection Tools: • Computer Calculations • Fluid Level determinations • Pressure/Temperature Surveys
- 41. Troubleshooting and Optimization Tools - Surface Measurement of Gas Volume: • Measurement of injection gas volume is necessary in order to determine the efficiency of the gas lift operation. • Inefficient gas injection may be corrected by changing the rate of gas injection and measuring the total fluid production against the injected gas volume for each change, thus providing a means to determine the most efficient GLR. Well Test: • Accurate gauging for oil and water production is necessary for proper analysis of the operation of the gas lift system. • Knowing the specific gravity of the oil and water allows for determining the efficient point of injection and possible redesign.
- 42. Troubleshooting and Optimization Tools - Surface Well Test: • Surface Casing pressure • Flowing Tubing pressure • Daily Fluid Production rates • Water Cut • A.P.I. gravity of oil • Specific gravity of produced water • Total gas (Injection and formation gas) • Gas Liquid ratio • Injected gas • Notes about sand production, emulsion, slugging • What size injection choke is being used • Flowline chokes, if any
- 43. Troubleshooting and Optimization Tools - Subsurface Computer Calculated Flowing Gradient • Can accurately determine point of injection based off of well test. • Quickly can troubleshoot well based on injection point and improve well performance. • You can do this by calculating the surface closing pressure or comparing the valve surface closing pressures with the opening forces that exist at each downhole valve given the operating, tubing and casing pressures, the temperatures, etc.
- 44. Troubleshooting and Optimization Tools - Subsurface Acoustic Fluid Level • The fluid level in a semi-closed or closed installation will represent the deepest point to which the well has been unloaded. • The fluid level in an open installation will represent the point of balance or where the annulus pressure at the fluid level is equal to the tubing pressure. • The operating valve would be directly above the point of balance. • Can help to determine a hole in the tubing/casing or packer leak.
- 45. Troubleshooting and Optimization Tools - Subsurface Flowing Pressure/Temperature Survey: • Will locate the point of gas injection. • Determine the flowing bottomhole pressure. • Helps accurately calculate the flowing correlation used for the initial design. • Determine flowing gradient above and below the point of injection. Static Pressure/Temperature Survey: • Determine the static bottomhole pressure • Determine a static fluid level • Determine the static fluid gradient
- 46. Ways to Correct a Trouble Gas Lift Well without Direct Intervention
- 47. Ways to Correct a Trouble Gas Lift Well without Direct Intervention
- 49. Gas Lift Equipment Components