1. PLUNGER LIFT SYSTEMS
By C E Mason
V1.01

2. Overview
Simple ways to look for well loading in the office and in the field.
What makes a plunger work.
Types of plunger lift equipment.
Installation and optimization of plunger lift.

3. Introduction
Plunger Lifts are one of the most cost effective and efficient ways to artificially enhance fluid production from Oil and Gas wells and will extend the economical life of the well, increasing the total fluid and gas recovery.

4. “How can I tell if I might need a plunger lift system?”
There are many indications that a well is liquid loading, some indicators are found in the field and some are indications that can be seen in the office. One way is to plot production curves. You will see a deviation from the expected decline at the point of liquid loading (see fig.1).

5. Production Plot (fig.1)

6. Check The Flowing Pressures
When recording the flowing tubing and casing pressures, if you observe a large pressure differential between the tubing and casing, this may indicate a flow restriction due to fluid build up in the tubing.

7. Checking The Flow Rate
When a large differential between the tubing and the casing is observed, the next step is to compare the well’s flow rate to the required critical flow rate (the minimum flow rate that the well has to maintain in order to lift the heaviest produced liquid up the tube string to surface). If the well is flowing below the minimum required critical rate, then the well can be liquid loading.

8. Indications of loading in the field
Erratic daily fluid production
Erratic gas flow on the
production chart (slugging)

9. Loss of Fluid Production
A rapid decrease or complete stop of fluid production may cause some confusion and can mislead operation personnel to believe that the well is not loading up, or that the well has stopped producing fluid. This is usually caused by the well dropping below it’s critical flowing rate, making the well unable to unload any produced fluid.

10. “How will a plunger lift system help?”
The plunger creates an interface between the fluid (above the plunger) and the gas (below the plunger), by decreasing the amount of gas that can break through or “Bullet” through the liquid. The plunger will allow the well to produce with greater efficiency and will allow the well to flow with lower GLR’s. (gas to liquid ratio).

11. FALL BACK (fig2.0) Liquid Gas Fall back Gas breakthrough Gas bullet
Turbulence
area

12. How will the well respond?
When you install a plunger lift, the well will (in most cases) return to the original decline plot. With a plunger lift, the sooner liquid loading is identified the better, and the greater the long term benefits will be.

13. Add plunger lift (fig.2.01)

14. Lost production
You will notice on fig 2.01 that the plunger install point returns the production to the point on the decline directly above the plunger installation time, and does not recover the lost production between the load point and the installation point. In most cases this production will not be recovered until the end of the well’s production life and usually requires additional lifting methods like a beam lift..

15. What do I need to see if my well is a plunger lift candidate
Conventional plunger lift
300 scf per bbl of liquid per 1000ft tubing depth.
Or 1.75 e^3 m^3 per 1000 liters of liquid per 1000 meters tubing depth

16. Pace Maker Plunger system
Because this type of plunger is reliant on the formation inflow for it’s drive it could be considered a velocity plunger.
Estimated minimum gas rate equal to 65% of critical rate for gas and fluid rate of 100bbls per MMCF/d or less

17. Using the Casing as storage with a conventional plunger system
The casing is used as a storage area and will allow the well to operate and lift larger amounts of fluid.
If the well has a packer installed, the required GLR will increase to 600 scf per bbl per 1000 ft. or3.5e^3 m^3 per 1000 meters deep

18. Pace Maker Plunger system and casing volumes
Because a Pace Maker is not “shut in” for build ups the casing is not a advantage to this system and in some cases can reduce the efficacy of the plunger system

19. Pressure and Required Volume
Another consideration has to be the well’s operating, or flowing pressure. Because gas volumes compress or become smaller when under pressure, it can pass through a small area with very little restriction and low velocities.

20. Compare the volumes
Generally, every time a gas loses half of it’s pressure, it doubles in area.
100 psi
200 psi
400 psi

21. At the bottom
With the example on the previous page, you can see how a well flowing at 600 or 700 psig BHP could bubble 4 E^3 or 140 mcf of gas past a plunger without ever causing it to move. The amount of gas that will bubble past the plunger will increase as the plunger wears out, or if it has a poor seal surface (solid steel). The greater the difference between the plunger O.D. and the tubing I.D. the more gas you can slip by without creating any differential across the plunger.

22. Calculate the Fluid column weight
Water
10 KPA per meter
0.45 PSI per foot
Oil
7 kpa per meter
0.30 PSI per foot
You can use this to estimate the required pressure differential required to lift the fluid column.
These weights are for quick field estimating only

23. Fluid shear
Fluid shear is calculated by using the height of the fluid column * velocity * tubing smoothness *,*,*,…. So to make this easy I have found that you can use the following formula.
Total fluid height x .2 psi.
This is based on the assumption that the plunger will travel at a maximum of 1000 ft per minute.

24. Fluid Height
Standard 2 3/8” tubing will have a fluid height of ft per gallon, or m3 per meter.
Standard 2 7/8 tubing will have feet per gallon or m3 per lin meter.
or use:
H=M/(0.25*3.14)((D*D)
D = Internal tubing diameter in meters (mm/1000) example 2 3/8” tubing =
M= Amount of fluid in meters^3
H= Fluid column height

25. Tubing sizes can make the difference in operations
If you use ¾” I.D. coiled tubing, you will find the area is O.44 of an inch, and with the parameter of 1 Bbl. of fluid to lift in the tubing, you would require 460 psi+ line pressure to over come the static head that is produced in the coiled tubing.
Compared to 2 3/8” tubing with an area of 2.83 inches you would require psi+ tubing flowing pressure to overcome the static head.

26. Limited Life Time
Therefore, most small tubing has a very limited lifetime in a flowing well and will have to be resized throughout the life of the well in order to keep the well operating properly. Fluid viscosity and tubing length will effect the life of small bore tubing.

27. The Large Tubing Advantage
Larger tubing will produce the well without the friction loss or restriction that is caused by small bore tubing. However, it may not be able to keep the well flowing above it’s flowing critical velocity, and in turn cause the well to load up by leaving the heavier liquids in the near well bore area and tubing string.

28. The Plunger Advantage
The advantage with the larger bore pipe is the volume of gas you can produce without excess friction loss allowing the well to produce with the lowest possible sand face pressure. When you add a plunger lift, the large bore tubing is able to lift large amounts of fluid and remove a major part of the back pressure on the sand face, while keeping the friction loss to a minimum.

29. X-SECTION The Size Is Out There
As plungers start to exceed 3” inches in diameter, a very high flow rate or a very efficient seal is required (the larger the area the greater the flow rate). This is due to the cross sectional area of the tubing in conjunction to the amount of gas being produced, which equals the gas velocity. This must be compared to the amount of bypass area between the plunger and the tubing wall.

30. Bypass Areas
3 1/2 & 2 3/8 “Plungers & the space between average tubing I.D and the plunger O.D.
Average
space
between
seal and
wall =
.05”

31. Bypass Area in inches
The amount of area that gas and liquids can bypass around the plunger in 3 1/2” is quite large and would equal a 0.690” hole through the middle of the plunger. A 2 3/8” plunger will have a bypass area of This is if both plunger seals are an average of 0.05” from the tubing wall. (Nominal pipe size verses drift size)

32. Conventional type Plunger Seals
The solid plunger or bar stock plunger is one of the least efficient plungers at lower gas velocities. This is due to the ridged seal face that requires the plunger O.D. to be under sized in order to keep it from hanging up on tubing imperfections.

33. Pad Plunger
Although the pad plunger is a metal to metal seal, the ability to expand and contract following the tubing I.D. allows this plunger to be very efficient. This plunger may not work properly with solids (sand/ scale) or large amounts of paraffin's.

34. Brush Plunger
The brush plunger is a very efficient plunger. This is due to the long seal area that can expand to the maximum I.D. of the tubing. The brush plunger was designed to run in wells that had a large amount of produced solids in the production string. The brush is able to sweep the tubing walls clean while not hanging up on small particles in the tubing.

35. Pace Maker Plunger
The Pace Maker plunger uses a solid Titanium sleeve and titanium or ceramic composite valve ball this is based on fluid production and flow rates. Because of the sever service ( up to 150 cycles per day ) this type if plunger can experience. The seal type is a solid ring design. With out moving parts.

36. Too Heavy to lift
One of the most common loading problems is the slow build up of heavier fluid (water ) in the well bore.

37. The Slow Build Up
Many wells will flow for long periods of time producing condensate and small amounts of water, but with the well flowing near, or at critical rate, or a well with fluctuating line pressures will allow the water to drop out of the fluid emulsion in the tubing and build up in the bottom of the well bore.

38. Flowing Well Bore
Producing zone

39. Gaining Weight
Water or heavy fluids will slowly displace the lighter fluid in the lower well bore area until it reaches the point where it will enter the tube bore and the total weight of the fluid emulsion increases. This will cause the well’s flow rate to fall below flowing critical rate, causing the well liquid load.

40. Loaded or Saturated Well Bore
Producing zone

41. Using a plunger
A plunger lift will stop the emulsion separation in the tubing and will carry the water or heavy fluids to the surface. Each cycle stopping near well bore saturation.

42. 60% Loss
While some wells will operate for long periods of time in a slug state, your production can be as low as 40% of your total possible production with the well operating in a unloaded state.

43. Typical Pressure Graph (slugging)

44. Gas & Liquid Production With A Slugging Well

45. Reduce Your Cost
Plunger lifts reduce maintenance costs on rotating equipment by eliminating their use.
Plunger lifts reduce bottom hole costs by eliminating the bottom hole pump and reducing the amount of tubing wear, and in turn increases tubing life.

46. Operating procedures

47. Disclaimer
This Operating procedure is not intended to cover all situations, times may arise where additional precautions, good judgment and common sense will be necessary to do your job or task, in a safe and efficient manner. This operating procedure is only a guide for typical plunger operations and maintenance.

48. Operating A Plunger Lift Well
Operating a plunger lift can become a simple and safe procedure built into your daily operating program. As with all moving equipment it must be checked for damage and normal wear and tear. This can be done by following this outline or similar routine:

49. Opening & Closing The Well Head
The first thing to remember on all wells (not just plunger lift wells) is the following:
Before you bring a well on line, check that both the wing valve(s) and master valve(s) are in the closed position. If you have a plunger lift installed with a timer, ensure that the timer or control box is in the closed position.

50. Check Before You Open Before opening any of the well head valves:
Open the master valve(s) completely. Open your wing valve(s), then open the timer. This procedure will stop any accidental damage to the master valve from the plunger or other items (hydrates, sand, etc.) striking the gate.

51. Closing The Well Head
When closing the well head, always start by closing the control box first (if applicable) then the wing valve(s), followed by the master valve(s).

52. Removing The Plunger From The Well Head
First, set the catcher on the lubricator to catch or hold the plunger.
After the plunger has been locked into the catcher, shut-in the well as described previously.
Following your companies venting requirements, vent the trapped pressure off the lubricator, insuring it is completely vented.

53. Check, Then Check Again
One way to check that the vent is not plugged is to open the wing valve slightly to see if you get an increased flow out of the vent.

54. Removing The Cap Leaving the lubricator vent open, remove the cap.
DO NOT FORCE THE CAP! if it is hard to remove, this may be a sign that their is trapped pressure and/or a possible hydrate in the lubricator. BEFORE YOU REMOVE THE CAP DOUBLE CHECK FOR PRESSURE.
Remove plunger from lubricator.

55. Replacing The Plunger In The Lubricator
Ensure all valves are closed Set the catcher into the catch position Place the plunger in the lubricator with the fish neck up Make sure the plunger will not drop through the catcher and strike the gate on the master valve, this can cause the gate to leak and the plunger to be blown out of the lubricator, possibly causing injury or equipment damage.

56. Always Pressure Up Slowly
Replace the cap.
Close the vent on the lubricator.
Pressure up the lubricator by cracking open the wing valve and slowly pressuring up the lubricator to check for any leaks.

57. If There Are No Leaks
Close the wing valve and open the master(s) valve slowly until they are full open.
Open the wing valve and equalize between well and the control valve. If you wish to drop the plunger to bottom, reset control box to the closed cycle and release plunger from catcher.

58. Start In The Open Cycle
To start in the open cycle, open the control box then release the plunger from the catcher.
Remember that if you drop the plunger and turn the well on shortly after, the plunger will resurface at a high rate of speed. Over time this will cause the plunger and lubricator to fail.

59. Hydrate Control
Some things that may help to control hydrates in the well head are flowing both the top and bottom flow ports. If the well continues to hydrate, methanol injection into the lubricator may be required.

60. Be Sure Before You Blow down the welll
Remember that a hydrate can form in the tubing and if the well appears to be loaded CHECK OUT THE POSSIBILITY OF A HYDRATE before pulling the well to atmosphere.

61. Danger, Danger, Danger!
If a hydrate formed below the well head and it moves while the well is being pulled to atmosphere, it can have a catastrophic effect to the integrity of the well head, lubricator and the plunger. DO NOT ASSUME THE WELL IS LOADED, BE SURE. There is a common misconception that hydrates do not form in wells with plunger lifts. If their is any chance there is a hydrate in the tubing, follow your company’s procedure to remove the hydrate first.

62. Operation of Daily, Monthly and Yearly Maintenance
A plunger lift system is not an install and forget item. They require some daily attention to keep them running smoothly. A daily routine for a plunger lift system could be as follows:

63. Daily Visually check the lubricator for leaks.
Check the pressures on the casing and tubing.
Record this information and what cycle it is in: Open, Delay, Closed or Backup.
Check the separator (if required) for a proper fluid level.
Inspect the condition of the controller and wires running to it.

64. Daily cont.
Read the plunger arrival times and look for a trend. Is the plunger arriving faster or slower?
Adjust the flow time accordingly. One rule of thumb is: The plunger should travel between 700 to 1000 ft. per. minute or 215 to 300 meters per minute.

65. Monthly
Remove and inspect the plunger, top cap and seal. Replace worn or damaged parts. Measure the plunger O.D. to check for wear. Inspect pad sections for cracks. Check the plunger fish neck for any damage.

66. 6 Months
Remove and completely discharge and then recharge gel cell batteries on a properly sized charger (Maximum. output 6 volt 1 Amp./hour) in the spring and fall.

67. Thank You Thank you for taking the time to see this presentation.
Please feel free to contact Premier Production Solutions with any questions.
I hope this has helped you understand the function and operation of a plunger lift system.

68. Where To Get More Information
For more Information on Equipment & Sales please call:
or or fax
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