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• GAS LIFT - CLASS #

PETE 4046 – Well Design - Production

• E-mail: malmeida@lsu.edu
• Phone: 578 - 0412
• Office: Old Forestry bldg. Room 109
• Office hours: Tuesday - 10:00 to 12:00 noon

Thursday - 10:00 to 12:00 noon

• TA: Daniel C. Braga

E-mail: dbraga3@lsu.edu

Office: Ingram Hall 110 (Poultry Building)

Office hours: 1:30 – 3:30 pm or by appointment

Mauricio de Aguiar Almeida, PhD

Bottom Hole Reservoir Pressure Pressure Bottom Hole Flowing Pressure BHFP

Most common Artificial Lift Systems in the Oil Industry

• Gas Lift (Continuous and Intermittent)
• Electrical Submersible Pumping (ESP)
• Sucker Rod Pumping
• Progressive Cavity Pumping
• Hydraulic Pumping
• Jetting Hydraulic Pumping
• Plunger Lift
• Others Basically we have two categories: Gas Lift and Pump-Assisted Lift

Advantages GAS LIFTING Continuous

1. Takes full advantage of the gas energy available in the reservoir.
2. Is a high volume method.
3. Equipment can be centralized.
4. Can handle sand or trash best.
5. Valves may be wireline or tubing retrieved. Intermittent
6. Can obtain lower producing pressure than continuous gas lift obtains and at low rates.
7. Equipment can be centralized.
8. Valves may be wireline or tubing retrieved. ROD PUMPING
9. Is possible to pump off.
10. Is best understood by field personnel.
11. Some pumps can handle sand or trash.
12. Where suitable, it is usually the cheapest lift method. HYDRAULIC PUMPING
13. High volume can be produced from great depth.
14. It is possible to almost pump off.
15. Equipment can be centralized.
16. Pumps can be changed without pulling tubing. CENTRIFUGAL PUMPING
17. Very high volumes at shallow depth can be produced.
18. Is possible to almost pump off. Disadvantages
19. Cannot pump off and minimum bottom hole producing pressure increases both with depth and volume.
20. Must have a source of gas.
21. Is limited in maximum volume.
22. Cannot pump off.
23. Causes surges on surface equipment.
24. Must have a source of gas.
25. Maximum volume drops off fast with depth.
26. Is very susceptible to free gas in pump.
27. Equipment gets scattered over lease.
28. Pulling rods are required to change pump.
29. Is very susceptible to free gas in pump causing damage.
30. Is vulnerable to solid matter in pumps.
31. Oil treating problems are greatly increased because of power oil in well stream.
32. Well testing can be difficult due to power oil including in well stream.
33. Maximum volume drops off fast with depth.
34. Is very susceptible to free gas in pump causing damage.
35. Control equipment is required on each well.
36. Tubing must be pulled to change pump and cable.

Factors affecting the selection of best system to produce one or more wells

• Number of wells
• Lifting depth
• Production flow rate
• Gas Liquid Ratio (GLR)
• Fluid viscosity
• Produced oil type
• Sand production
• Reservoir production mechanism
• Diameter and condition of the production casing
• Access to the well
• Electric power availability
• Gas availability
• Distance to the production facility
• Equipment availability
• People availability
• Investment
• Operational cost
• Safety
• others

Gas Lift

• Gas lift is an artificial lift method whereby external gas is injected into the produced flow stream at some depth in the wellbore.
• Gas lift utilizes the energy of compression in a high pressure gas to decrease the hydrostatic gradient in a liquid column and thus cause the column to flow to surface.
• This process is accomplished with the use of gas lift valves, which acts as a pressure regulator.

Gas Lift

Gas Inlet Production Unloading Valves Operating Valve

Gas compression station GAS LIFT System Gas injection line Gas export pipeline Injection Gas Manifold Measure & Control Oil Tanks Separator Produced Gas Oil Water Production Manifold Well for water discharge Oil export pipeline Oil (tubing & casing) Production Wells Gas compression station The system is composed of: 1 - High pressure gas source (compressors) 2 - Gas injection controller a) at surface (choke) b) at subsurface (GL valves) 3 - Equipments for separation and storage of fluids (separators, tanks, etc.)

Well Unloading

• Unloading simply means removing all the casing (packer) fluid left in the well

between the tubing and casing at the time of completion and replacing it with

gas down to the point of injection.

• Typically, gas lift pressure available is insufficient to unload the casing-tubing

annulus to the lift valve directly.

• Multiple valves are used to unload the casing-tubing annulus and circulate gas

through the lifting valve.

• As the injection pressure is applied to the annulus all valves in the tubing string

are opened and the fluid is displaced through the open valves into the tubing

and , in open-type installations, is U-tubed around bottom.

Obs. A well can be put on gas lift without unloading valves. However, the

biggest consideration is that casing must tolerate and gas source must

generate the high pressures required.

Gas injection into the casing has begun. Fluid is U-tubed through all the open gas lift valves. No formation fluids are being produced because the pressure in the wellbore at perforation depth is greater than the reservoir pressure i.e. no drawdown. All fluid produced is from the casing and the tubing. All fluid unloaded from the casing passes through the open gas lift valves. Because of this, it is important that the well be unloaded at a reasonable rate to prevent damage to the gas lift valves.

The fluid level has been unloaded to the top gas lift valve. This aerates the fluid above the top gas lift valve, decreasing the fluid density. This reduces the pressure in the tubing at the top gas lift valve, and also reduces pressure in the tubing at all valves below the top valve. This pressure reduction allows casing fluid below the top gas lift valve to be U-tubed further down the well and unloaded through valves 2, 3 and 4. If this reduction in pressure is sufficient to give some drawdown at the perforations then the well will start to produce formation fluid.

The fluid level in the casing has been lowered to a point below the second gas lift valve. The top two gas lift

valves are open and gas being injected through both valves. All valves below also remain open and continue to

pass casing fluid. The tubing has now been unloaded sufficiently to reduce the flowing bottom hole pressure

(FBHP) below that of the shut in bottom hole pressure (SIBHP). This gives a differential pressure from the

reservoir to the wellbore producing a flow of formation fluid. This pressure differential is called the drawdown

The top gas lift valve is now closed, and all the gas is being injected through the second valve. When casing

pressure operated valves are used a slight reduction in the casing pressure causes the top valve to close.

With fluid operated and proportional response valves, a reduction in the tubing pressure at valve depth

causes the top valve to close. Unloading the well continues with valves 2, 3 and 4 open and casing fluid

being removed through valves 3 and 4.