Gas Lift -Heriot Watt University PDF

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Gas Lift

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CONTENTS 1. 2. 3.

4.

5.

6. 7.

8.

9.

INTRODUCTION GAS LIFT INTRODUCTION GAS LIFT APPLICATION 3.1. Gas Lift Advantages and Limitations 3.2. Review Example Gas Lift Completion Designs GAS LIFT DESIGN OBJECTIVES 4.1. Gas Lift Design Constraints 4.2. Gas Lift Design Parameters 4.3. The Surface Gas Network THE UNLOADING PROCESS DESCRIBED 5.1. Safety Factors 5.2. Gaslift Valve Spacing Criteria Summarised SIDE POCKET MANDRELS 3.6.1 Other Uses of Side Pocket Mandrels GAS LIFT VALVE MECHANICS 7.1. Casing or Inflow Pressure Operated (IPO) Valves 7.2. Dome Pressure Calibration 7.2.1. Temperature Correction 7.3. Valve Performance 7.3.1. Dynamic Valve Performance 7.3.2. Valve Performance Flow Model 7.4. Proportional Response Valves 7.5. Dynamic Valve Response and Gas Lift Completion Modeling 7.6. Well Stability GAS LIFT DESIGN PROCEDURES 8.1. An Example Design - Optimising The Performance of a Gas Lifted Well 8.2. An Example Design - Gas Lift Unloading Calculations 8.3. Further Gas Lift System Considerations 8.4. Further Gas Lift System Calculations OPERATIONAL PROBLEMS 9.1. Gas Quality 9.2. Solids 9.3. Changes in Reservoir Performance 9.4. Gas Supply Problems 9.5. Well Start - Up (Unloading) 9.6. Well Stability 9.7. Dual Gas Lift 9.8. Trouble Shooting 9.9. Trouble Shooting Techniques 9.10. Some Field Examples of Operational Problems

10. 11. 12. 13.

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FIELD PRODUCTION OPTIMISATION NEW TECHNOLOGY FOR CONTINUOUS FLOW GAS LIFT INTERMITTENT GAS LIFT GRAPHICAL GAS LIFT DESIGN EXERCISE FOR WELL EDINBURGH - 2 13.1. Introduction 13.2. Initial Condition - The "Dead" Well 13.3. Construction of The "Equilibrium Curve" 13.4. The Unloading Process 13.5. Gas Lift Optimisation Exercise FURTHER READING

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LEARNING OBJECTIVES: Having worked through this chapter the Student will be able to: •

Describe the gas lift process.

•

Explain the impact of the key gas lift process variables.

•

Identify application areas/advantages for gas lift.

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Discuss the limitations of the gas lift process.

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Describe the well unloading process.

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Identify and explain the action of gas lift hardware components.

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Design a gas lift completion.

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Identify reasons why efficient gas lift depends on availability of high quality data.

•

Construct a methodology for revenue optimisation with limited gas availability.

•

Describe the intermittent gas lift and plunger lift processes.

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Gas Lift

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1. INTRODUCTION Chapter 2 introduced the concept of artificial lift and discussed the different types of equipment that a Production Technologist can choose from. It was complete apart from gas lift, the subject of this chapter. The objective of installing gas lift in a completion is to increase the drawdown on the producing formation by injecting gas into the lower part of the tubing string and consequently reducing the flowing gradient in the production string. The concepts of multiphase flow and well performance discussed in Chapter 1 are obviously very important here. We will first introduce the basics of gas lift and discuss its advantages and disadvantages. The design, operation and maintenance of the gas lift valves, which control the gas injection from the annulus into the tubing, will then be described. The procedure to design a gas lift completion string using one of the commercially available computer programs will be discussed. A manual design exercise will illustrate the design process. Typical gas lift operational problems and their solution will then be dealt with and the need for continual optimisation of the gas lift reviewed. Finally, some of the most recent developments in gas lift technology will be discussed.

2. GAS LIFT INTRODUCTION A continuous flow gas lifted well completion has been sketched in figure 1. The completion differs from the natural flow completions discussed earlier in that:

Produced Fluid and Injected Gas to Separator

Injected Gas (Control and Metering)

(c) Large Gas Bubble Displaces Liquid Slug Gas

Gas

(b) Gas Bubble Expands as the Hydrostatic Pressure Reduces

Liquid

(c) Displacement of Liquid Slugs by Gas Bubbles Liquid Liquid

(b) Expansion of Gas Bubbles

Gas Lift Valves

(a) Injected Gas Reduces Average Fluid Density Gas

Gas Injected at "Operating Valve"

(a) Reduction of Fluid Density Producing Formation

Figure 1 Gaslifted Well Completion

Perforations

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(i) Gas, at a controlled volume and pressure, is injected into the tubing/casing annulus. (ii) The tubing string has been fitted with a number of gas lift valves. These valves are installed at carefully spaced intervals so that any liquid present above them in the casing/tubing annulus (e.g. due to killing of the well) can be removed by injection of gas at the top of the well annulus leading to the liquid U-tubing into the tubing and its subsequent ejection from the well. The gas injection point into the tubing is then transferred to successively deeper gas lift valves (see section 3.5 for details). (iii) The gas is injected into the tubing through the “operating valve”. The injected gas enables the well to resume production by : (a)

the injected gas reducing the average fluid density above the injection point.

(b)

some of the injected gas dissolving into in the produced fluids, providing they are undersaturated with respect to the gas solubility. The remainder, in the form of bubbles, will expand due to reductions in the hydrostatic pressure as the fluids rise up the tubing.

(c)

the coalescence of these gas bubbles into larger bubbles occupying the full width of the tubing. These bubbles are separated by liquid slugs, which the gas bubbles displace to surface. This is called slug flow.

The design of a gas lift completion thus consists of two separate distinct parts: (i) Choice of the installation depth, type and design of the gas lift valves placed above the operating valve so that any liquid in the tubing and casing/tubing annulus can be unloaded via the wellhead (see section 3.5). (ii) Optimisation of the flowing gas lifted well. The well essentially behaves as a conventional flowing well, except that the gas/liquid ratio (GLR) suddenly increases at the operating valve depth (see section 3.8). The wellbore opposite the perforations is treated as the node pressure when the system is analysed using the “nodal analysis” process discussed in chapter 1.12. The analysis equates the following at any given flow rate: Inflow to Node (the perforations): Preservoir - Pdrawdown = Pperforations Outflow from Node (the perforations): Pseparator + Pflowline + Pchoke + P(tubing above operating valve) + Ptubing below operating valve = Pperforations The pressure drop across the tubing below the gas injection valve is estimated with using multiphase flow correlations (chapter 1.1.7) or pressure traverse curves (chapter

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1.1.6) using the “natural” gas liquid ratio. The pressure drop between the gas injection valve and the surface is calculated using the “enhanced” gas liquid ratio calculated from the sum of the {lift + produced} gas rate divided by the liquid production rate. Figure 2 illustrates a pressure traverse across the well when it has reached steady state operation. The gas is being injected at the wellhead at a pressure of 1100 psi. The pressure of the gas in the annulus increases with depth due to its density (typically at the rate of 30 psi/1000 ft). The gas is initially being injected at the valve 4 at 3800 ft. The well is producing with a 500 psi drawdown. The flowing pressure gradient from the producing perforations to the operating gas lift valve is equal to 0.44 psi/ft. There is a 250 psi pressure drop across the gas lift valve and the average fluid gradient above the injection valve has been reduced 0.27 psi/ft by the injected gas. The situation for deeper gas injection is also sketched in which the gas is being injected through valve 7 at 5000 ft. The gas lift pressure is now just sufficient to allow injection to occur if the pressure drop across the gas lift valve is restricted to 50 psi. It can also be seen that the deeper injection allows the drawdown to increase to 850 psi.

Produced Fluid and Injected Gas to Separator

Injected Gas (Control and Metering)

0

2 3 4

Depth (Ft. TVD)

1

2000

3000

4000

ient rad eG n s ur res ject io gP In ubin int of o gT win eP Flo Abov

1000

Wellhead Annular Gas Injection Pressure (psi) 500 1000 1500 2000 2500

3000

Casing (Gas) Pressure Gradient

Gas Injection at Valve 4

5

Pressure Drop Across Valves Gas Injection at Valve 7 5000 Operating Gas Lift Valve

ts ien ad Gr on re ct i su je es In Pr of g int bin Po Tu w ng elo wi B Flo

6 7

Flowing Bottom Hole Pressure, Valve 4

6000

Producing Formation

7000

Figure 2 Flowing Bottom Hole Pressure, Valve 7

Pressure Traverse Through a Well

Perforations

Reservoir Pressure

Drawdown, Valve 4 gas injection Drawdown, Valve 7 gas injection

It can be appreciated from this diagram that the gas injection pressure is the main control on the depth of gas injection while the gas injection rate also contributes to the extent of the reduction in the flowing pressure gradient. These parameters can be adjusted as required on a day-to-day basis. The pressure settings of the gas lift valves Department of Petroleum Engineering, Heriot-Watt University

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(which control the pressure levels at which the valve opens and closes - see section 7.3) can be adjusted when required using wireline techniques - see section 6). The depths at which the valves are set can only be altered by pulling the tubing and recompleting the well with a tubing string in which the spacing between the side pocket mandrels has been altered. Increases in the gas injection rate through a gas lift valve set at a given depth will increase the fluid production rate until a maximum is reached (figure 3). At this point the “reduction in average fluid density in the tubing due to a slight increase in the gas injection rate” is being exactly counterbalanced by the “increased frictional pressure losses due to the greater mass of fluid flowing in the tubing”. Further increases in the gas flow rate will result in the friction term increasing relatively faster than the hydrostatic head reduction term. This is the “technical optimum gas injection rate” at which the well production is maximised.

Production Rate

Economic optimum gas injection rate where marginal extra gas injection cost balances marginal extra production revenue.

Maximum liquid production or technical optimum gas injection rate

Unstable flow below this rate due to too low gas injection rate

Some wells flow "naturally" without gas lift. Others require "Kick off" gas to initiate production

Figure 3

Gas Injection Rate

Effect of gas rate on well production

“The maximum economic gas injection rate” will be somewhat lower - this is the gas injection rate at which the marginal cost of providing extra injection gas is equal to the marginal revenue from the extra well production. Figure 3 also illustrates that gas lift may be applied to increase the production from wells in which will flow naturally at a low(er) rate. The second case illustrated is for a well which is “dead” and does not produce without some form of artificial lift. Gas then has to be injected at a certain rate (“kick-off” gas) before any well production is possible.

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Gas Lift

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An efficient gas lift system depends on a continuous supply of gas at the specified pressure. A considerable infrastructure is required for gas lift. This is normally only installed when there are a number of wells in the area using gas lift as the preferred form of artificial lift. A typical gas lift system arrangement is shown in figure 4. This figure shows several wells producing into a production manifold. The gas is then separated, compressed and dried in a dehydration unit. Any excess gas may be sold or make up gas imported, as required by the demand of the gas lift system. The lift gas is supplied to the gas lift manifold, after which the injection gas flow rate and casing head pressure are adjusted before injection into the individual wells.

Import make up gas

Surplus sales gas Dehydration unit

Compressor Gas

3 Phase Separator

Oil to storage

Water to disposal Injection Gas manifold

Injection gas presssure and flow rate measurement P F

Production pressure and flow rate measurement P F

Production manifold

Figure 4 Gas lift system

The metering and control equipment for a gas lifted well that is being individually tested is illustrated in figure 5. Both manual and automatic lift gas control are illustrated.

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Wing Valve Choke Box

Safety Valve Inlet Valve

(Orifice) Gas Flow Meter

Master Valve Data Logger

Gas Oil

Echometer (Measures fluid level in annulus)

Water Oil Pipe Line Gas Lift Pipe Line

Unloading Gas Lift Valves

Casing Tubing

Operating Gas Lift Valve

Packer

Data Logger

Production test Separator (Orifice) Flow Meter

Needle Valve to Control Lift Gas

Main Valve

Manual control

Gas Lift Manifold

Producing Formation

OR Flow meter that automatically adjusts choke setting

Perforations Main Valve

Automatic control

Figure 5 Metering and control of a

Gas Lift Manifold

3. GAS LIFT APPLICATIONS The process described above is called “continuous flow gas lift”. “Intermittent gas lift” is used in low rate production wells. This approach involves switching off the injection gas at regular intervals so as to allow the fluid level in the well to build up. The gas injection is recommenced, and the fluid in the tubing lifted to surface, when a sufficient depth of produced fluid is present in the well. The cycle is then repeated. Intermittent gas lift is thus used for cases when the outflow capacity of the gas lifted tubing is greater than the formation’s capacity to produce fluid into the well. The module on multiphase flow in vertical tubing explained how the flowing gas will by-pass some of the liquid in the tubing (the slip phenomenon). This liquid will fall back down the well each time the gas lift is switched off. Fall back can be avoided by installing a plunger at the bottom of the well. Gas injection now occurs underneath this plunger, which rises upwards, displacing the liquid above it to the surface. The plunger falls to the bottom of the well when the gas is switched off. The downhole completion is arranged so that inflowing fluid can collect above the plunger while a check valve ensures that the injected gas can not be injected into the formation. The cycle can now be repeated at a regular time interval. This will depending on the well 8

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gas lifted well.

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productivity and the volume of liquid displaced to the surface by the plunger. This method is described in greater detail in chapter 3.12. Gas lift has been applied to a wide range of production scenarios - as can be seen from Table 1. In fact, gas lift is the only artificial lift method that actually works better in a well that is producing at a significant gas/liquid ratio. Gas lift is often the preferred artificial lift method for wells with a: (i)

high gas-oil ratio;

(ii) high productivity index; (iii) (relatively) high bottom hole pressure due to reservoir pressure support being provided by a natural or artificial water drive.

Table 1 Continuous flow gas lift applications

1 2

Production wells which will not flow naturally. Increase production rate in flowing wells.

3 4

Unload liquid from wells that will flow naturally once on production. Unload liquid in wet gas wells which would otherwise cease to flow.

5 6

Back flow injection wells. Lift aquifer wells.

The key point of gas lift is that a reliable, adequate (in terms of pressure and flow rate) gas supply has to be available at all times. The proviso at the end of the sentence is the key one. When the field/wells are operating normally the (lift) gas system (figure 3) will be fully charged with gas. This gas will be recovered and recirculated many times. Extra volumes of “make-up” gas associated with the current oil production will only be required to make good any losses from the system, as well as any gas used for compression or other power requirements. When planning a gas lift installation for a field one should specifically allow for the: (i) decrease in (fresh or make-up) gas supply as the field reserves are depleted and the well water cut increases. This can result in gas being imported during the late project life, particularly for offshore developments when the produced gas is also used to generate the platform’s electrical power. (ii) case when none of the wells flow naturally. An external gas source is then required to bring the (first) well(s) onto production after a facility shutdown. (Vapourised, liquid) Nitrogen can be used for this purpose if there is no provision to import natural gas. (iii) fact that, if only a low rate gas supply is available, it will take a long time to return all the wells to production after a shutdown. (iv) choice of lift gas injection pressure has to be made at an early stage in the project lifetime when the gas compressor specifications are drawn up and little information may be available about actual well performance.

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3.1 Gas Lift Advantages and Limitations These are summarised in tables 2 and 3. They are self explanatory if read in conjunction with the above discussion.

Operation of gas lift valves is unaffected by produced solids (sand etc.) Gas lift operation is unaffected by deviated or crooked holes. Use of side pocket mandrels allows easy wireline replacements of (inexpensive) gas lift valves when deviation 0.25" are installed. Both the Thornhill-Craver and the Winkler-Eads equations have an idealised, mechanistic basis - the equations are not “tuned” using the actual flow test data measured in

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the API test procedure described above. These gas flow rate measurements can be represented by: (i) a Flow Coefficient (Cv). This is a measure of the gas flow rate as a function of pressure differential...