PLUNGER LIFT SYSTEMS

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. Erratic daily fluid production Indications of loading in the field • 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. Liquid Turbulence area Gas breakthrough Gas bullet Gas Fall back FALL BACK (fig2.0)

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 efficiency 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. 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 Calculate the Fluid column weight

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 6.158 ft per gallon, or .00202 m3 per meter. • Standard 2 7/8 tubing will have 4.11 feet per gallon or .00302 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 = .00518 • 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 134.5 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-SECTIONThe 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 0.280. 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.