This document was produced as part of my final year project of training to obtain a petroleum engineering diploma. The aim of this project is to make a comparative study between continuous and intermittent gas lift systems based on real data from an oil well in Algeria, and to choose the system best suited to increase the production of the well. This study was carried out by a manual design using the method of “fixed pressure drop” for the continuous gas lift system and “fallback gradient” method for intermittent gas lift system. We were able to determine at the end of this study that the system best suited to the current conditions of our well would be the intermittent gas lift system and we also proposed that it should be combine with the "plunger lift " system in order to increase the efficiency of the intermittent gas lift system by eliminating problems linked to the phenomenon of" fallback " thus increase the production of our wells.

1. Gas Lift Design:
Comparative Study of Continuous and Intermittent Gas Lift
(Case Study of a Real Wells in “In Aménas-Algeria”)

2. Introduction
I- Overview on Gas Lifting System
II- Types of Gas Lift
III- Gas Lift Design
Conclusion, Proposition and Perspectives
2

3. When oil is first found in the reservoir, it is under pressure from
the natural forces that surround and trap it. If a hole (well) is drilled
into the reservoir, an opening is provided at a much lower pressure
through which the reservoir fluids can escape.
If the pressures in the reservoir and the wellbore are allowed to
equalize, either because of a decrease in reservoir pressure or an
increase in wellbore and surface pressure, no flow from the reservoir
will take place and there will be no production from the well.
When the reservoir energy is too low for the well to flow, or the
production rate desired is greater than the reservoir energy can
deliver, it becomes necessary to put the well on some form of
artificial lift to provide the energy to bring the fluid to the surface.
3

4. 4
INTRODUCTON
There are six basic types of artificial lift: sucker rod pumping,
hydraulic pumping, centrifugal pumping, progressing cavity pumping,
plunger lift and gas lift as illustrated in Figure 1.

5. 5
Problematic
Design a gas lift system suited to the actual well condition and able to
increase the production of the well.
Objective
The aim of this project is to make a comparative study between continuous
and intermittent gas lift systems based on real data from an oil well in Algeria,
and to choose the system best suited to increase the production of the well.
To reach this objective, we will proceed to a design of a continuous gas lift
system through the method of “fixed pressure drop” and also a design of an
intermittent gas lift system using the method of “fallback gradient”.

6. 6
INTRODUCTION
Gas Lift is the method of artificial lift which utilizes an external source of
high pressure gas for supplementing formation gas to reduce the bottom hole
pressure and lift the well fluids. All version of gas lift use high pressure natural gas
injected in the well stream at some specifics down-hole depth.
APPLICATIONS OF GAS LIFT
Gas lift has many application and approximately 20% of producing wells
worldwide are concerned by this method:
Oil wells: The main target of gas lift in these wells is to increase the production
of depleted fields. It’s often used with wells remaining eruptive but not on the
desired rate of production and even with new wells.
Water wells: Gas lift is used here to produce water from aquifers. For water
wells, rather than gas lift, we speak of air lift.

7.  Starting wells: Kick off wells that will flow naturally once the
heavier completion fluids are evacuated from the production string.
 Injectors clean up: The injection well need to periodically be put
into production to eliminate particles that plug the perforations or
formation pores. This is often achieved by applying gas lift to these
wells.
7

8. 8
ADVANTAGES OF GAS LIFT
Takes full advantage of the gas energy available in the reservoir
Fits all well profiles: deep wells, deviated wells
Handle abrasive fluid and sand
Compatible with wells producing with high GOR and WOR
Minimal surface wellhead requirement
Surface control of production rate
LIMITATIONS OF GAS LIFT
Must have a gas source
Sour gas
Low viscosity crude
Very sensible to wellhead pressure variation

9. 9
PARAMETERS OF GAS LIFT
Wellhead Pressure: a low wellhead pressure thus improves the efficiency of the well and that of the
neighboring wells.
Injection Gas Pressure: the pressure of the injected gas affects the number of valves needed to
unload the well.
Depth of Injection: deeper the injection point will be, more efficient will be the operation of the gas
lift.
GAS LIFT VALVES
We have two family of gas lift valves:
The valves controlled by the pressure of casing (casing operated valves – COV). They are also called
IPO (injection pressure operated valves).
The valves controlled by the pressure of the tubing (tubing operated valves - TOV) They are also
called PPO (production pressure operated valves).

10. 10
INTRODUCTION
There are two basic types of gas lift used in the oil industry. They are called
continuous flow gas lift and intermittent gas lift. The two types operate on different principles
and it is always advisable to treat them as two separate subjects.
CONTINUOUS FLOW GAS LIFT
Continuous injecting gas into the tubing or casing at a predetermined depth.
It will be usually be more efficient for wells that produce at high rates.
TYPES OF CONTINUOUS FLOW GAS LIFT
Continuous Annulus FlowContinuous Tubing Flow

11. 11
ADVANTAGES AND DISADVANTAGES OF CONTINUOUS FLOW GAS LIFT
 Advantages are:
Takes full advantage of the gas energy available in the reservoir
Is a high volume method.
Equipment can be centralized.
Can handle sand or trash best.
Valves may be wireline or tubing retrieved.
Disadvantages are:
Minimum bottom hole producing pressure increases both with depth and volume.
Must have a source of gas.

12. 12
INTERMITTENT GAS LIFT
Injecting of high pressure gas into the tubing at sufficient volume and pressure to lift the fluid
head accumulated above the valve with maximum velocity.
Because of its cyclic nature, intermittent lift is best suited to wells that produce at relative
low rates.
Intermittent Flow Gas Lift Installation

13. 13
ADVANTAGES AND DISADVANTAGES OF INTERMITTENT GAS LIFT
 Advantages are:
Can obtain lower producing pressure than continuous gas lift obtains and at low rates.
Equipment can be centralized.
Valves may be wireline or tubing retrieved.
Disadvantages are:
Is limited in maximum volume.
Causes surges on surface equipment.
Requires more attention than continuous flow.
Cyclic lift causes difficulties with gas measurement and gas supply (compressors)

14. 14
CONDITION CONTINUOUS FLOW INTERMITTENT FLOW
Production Rate (bbl/day) 100 – 75,000 Up to 500
Static BHP (psi) > 0.3 psi/ft < 0.3 psi/ft
Flowing BHP (psi) > 0.08 psi/ft 150 psi and higher
Injection gas (scf/bbl) 50 – 250 per 1000 ft of lift 250 – 500 per 1000 ft of lift
Injection Pressure (psi) > 100 psi per 1000 ft of lift < 100 psi per 1000 ft of lift
Gas injection rate Larger volumes Smaller volumes
This table shows a comparison of the characteristics and parameters of the
continuous flow and intermittent gas lift systems.

15. 15
INTRODUCTION
Modern design procedures can be accomplished by computer, but gas lift
personnel must understand design fundamentals in order to use these tools effectively.
The best method of achieving this understanding is to personally design a system
without computer assistance.
For a proper design of a gas lift system, we must take in account many bias,
and probably the most important one is the casing pressure (or operating pressure) bias.
And base on this casing pressure many techniques have been developed, they are: the
“fixed pressure drop” and “Ppmax – Ppmin” methods for the continuous flow gas lift
system, and the “fallback gradient” and “percent load” methods for the intermittent gas
lift system.
For this project we will use fixed pressure drop for the design of continuous
flow gas lift and the fallback gradient for the design of the intermittent gas lift system.

16. 16
DESIGN OF CONTINUOUS GAS LIFT
 Constant pressure drop method
This is a very simple method for choosing pressure drops, which is based in large part
on field experience. This method entails taking equal casing pressure drops for all
valves in the design. This pressure drop is generally 10 – 50 psi and is based in large
part upon field experience. An advantage of this method is that it allows the engineer to
perform a less conservative design.
Example Design Using Constant pressure drop method
1- Prepare a sheet of graph paper with depth, pressure and temperature scales as shown
in Figure 1, and draw a line at the depth of the mid perforations i.e. 2411 ft TVD.
2- Draw the static gradient line starting from the shut in bottom hole pressure (SIBHP)
of 507.5 psig using a kill fluid gradient of 0.454 psi/ft. If the tubing pressure at surface
was 0 psig then the fluid level would be at 1293.15 ft TVD.
Static gradient = 0.433 × 1.05 = 0.454 psi/ft
Hydrostatic head = 507.5/0.454 = 1117.84 ft
Fluid level depth = 2411-1117.84 = 1293.15 ft

17. 17
3- Draw in the gas injection (casing) pressure line. From the static gas pressure gradient
chart (see annex) we have: for a surface gas pressure of 580 psi/ft and a gas specific
gravity (SG) of 0.64; the casing gradient = 0.015 psi/ft.
So
Gas pressure at depth = 580 + (0.015 × 2411) = 616.165 psi
We start at 580 psi at surface to 616.165 psi to the bottom.
4- Tubing gradient. For this purpose, some curves of gradient are available, and we
have to choose the chart with conditions the nearest possible to our well conditions
(25.16 stb/day, WC=60%, Water specific gravity 1.05 etc...), the nearest curves (see
annex) used for this calculation are function of the gas liquid ratio (GLR).
From the chart the tubing pressure at 2411 ft, with a GLR of 4460 is approximately 140
psi.
So we can draw the flowing gradient line, starting at wellhead pressure of 110 psi to
140 psi at a depth of 2411 ft.

18. 18
5- Space the top mandrel using the static gradient of 0.454 psi/ft. Draw a line
with this gradient starting at 110 psig until it intersects the casing gradient line
(with a DP at valve location of 50 psi) at a depth of 1120 ft TVD.
6- Draw a horizontal line to the left to the flowing gradient line plotted in step
4.
7- From the intersection of the horizontal line and the flowing gradient line,
draw a 0 .455 psi/ft gradient line to intersect the casing gradient line to locate
the depth of the second valve (2100 ft).
8- Draw temperature gradient line: Plot 80°F at the surface; 158°F at 2441 ft.
and draw a straight line between the two points.
9- Determine the temperature at each valve depth.
10- Determine the characteristics of valve

19. 19
Depth
of valves (ft)
Casing pressure when
valve opens Pcvo (psi)
Tubing pressure when valve
opens Ptvo (psi)
Casing surface pressure
when valve opens Pc (psi)
T
(°F)
Valve 1 1120 595 125 567.38 116
Valve 2 2100 545 140 Orifice 148

20. 20
DESIGN OF INTERMITTENT GAS LIFT
 Fallback method
The fallback gradient method uses an average gradient of the tail gas, liquid fallback,
and liquid feed-in to predict the minimum tubing pressure obtainable. This average
gradient or intermittent spacing factor (SF) is dependent on the tubing size and
anticipated production rate. Generally 0.04 psi per foot of depth is the minimum that
should be used for unloading.
Explanation of Graphical Solution Using Fallback Method
1- Prepare a sheet of graph paper with depth, pressure and temperature scales as shown
in Figure 2, and draw a line at the depth of the mid perforations i.e. 2411 ft TVD.
2- Determine the appropriate spacing factor (unloading gradient) for the well from
Intermittent lift spacing factor chart (see annex). This is a function of the anticipated
production rate, tubing size, etc. (In this example it is 0.04 psi/ft).
3- Extend this gradient of 0.04 psi/ft from the wellhead pressure (110 psig) at the
surface to the bottom of the well ((110 + (0.04 × 2411) = 206.44 psig at 2411 ft).

21. 21
4- Plot the surface gas injection pressure. Use pressure 50 psi less than system pressure
(580 - 50 = 530 psig).
5- Extend this pressure to the bottom of the well accounting for the gas column weight
(616.165 psig at 2411 ft).
From the static gas pressure gradient chart (see annex) we have: for a surface gas
pressure of 580 psi/ft and a gas specific gravity (SG) of 0.64; the casing gradient =
0.015 psi/ft.
So
Gas pressure at depth = 580 + (0.015 × 2411) = 616.165 psi
We draw the line starting at 530 psi at surface to 616.165 psi to the bottom (2411 ft).
6- Subtract 100 psi from the surface injection pressure and plot this as the surface
closing pressure of the unloading valves (Pvc = 530 - 100 = 430 psig).
Extend the pressure to the bottom of the well accounting for the gas column weight
(453.8 psig at 2411 ft.). From the rule of Thumb, the pressure at depth Pd is:

22. 22
7- Determine the static gradient of the kill fluid. It is = 1.05× 0.433= 0.454 psi/ft.
8- Extend the 0.454 psi/ft gradient line from the wellhead pressure (110 psig) to
intersect the gas pressure at depth line plotted in step 6: This intersection is the depth of
the top valve (1020 ft).
9- Draw a horizontal line to the left to the spacing factor line plotted in step 4.
10- From the intersection of the horizontal line and the spacing factor line, draw a 0
.454 psi/ft gradient line to intersect the Pvc line to locate the depth of the second valve
(1700 ft).
11- Continue this procedure to determine the third valve depth (2280 ft).
12- Draw temperature gradient line: Plot 80°F at the surface; 158°F at 2441 ft. and draw
a straight line between the two points. Determine the temperature at each valve depth.
13-The final item is to calculate the set pressures of the valves. Read the pressures at the
intersections of the horizontal lines and the Pcv line. The set pressure of a nitrogen
charged valve is calculated by the following equation:

23. 23
Depth of valves
(ft)
Valve surface closing pressure
Pvc (psi)
Valve surface opening
pressure Pvo (psi)
Temperature
(°F)
Valve 1 1020 440 459.3 112
Valve 2 1700 445 464.5 133
Valve 3 2280 455 474 153

24. 24
This project was a real opportunity for me to better understand the different
methods and applications of gas lift systems, to fulfill a technical work and to practice
the design of continuous and intermittent gas lift systems.
The observation that I can make to the management team for the case study
base on the design, is to implement an intermittent gas lift system for this well,
Because:
We can notice after the design of both continuous and intermittent gas lift, we obtain
the deepest point of injection of gas (valve position) with the intermittent gas lift
system. As we have said in chapter I on the parameters of gas lift: “deeper the injection
point will be, more efficient will be the operation of the gas lift”.
Form the table bellow showing the comparison of continuous and intermittent gas lift,
and the well data of our study case. We see that the intermittent flow is the one you will
best correspond to our well.
CONDITION CONTINUOUS FLOW INTERMITTENT FLOW WELL DATA
Production Rate (bbl/day) 100 – 75,000 Up to 500 18.87 – 31.45
Static BHP (psi) > 0.3 psi/ft < 0.3 psi/ft 0.21 psi/ft

25. 2
5
So from all the above I can say that the intermittent gas lift system will best fit
to our well and I will propose to combine to this system the plunger lift system.
A plunger will increase the efficiency of most intermittent gas lift installations
by preventing gas from breaking through the liquid slug (fallback). In very low bottom
hole pressure (as it’s the case of our well), plungers will allow greater pressure
drawdown and thereby increase production from the intermittent lift well by allowing
the lifting of smaller slugs on each cycle.
Subsequent developments, possible on the same subject, may involve a design
simulation by the mean of software such as Pipesim for the continuous gas lift and
Prosper for the intermittent gas lift, and compare the results of these simulation with the
ones obtain by the manual design in this project.
An economical comparative study of continuous and intermittent gas lift can
also be done on the same subject, in matter to help the management team in their choice
on the system who will be put in place on the basis of the economical cost of the total
project.

26. API GAS LIFT MANUEL (1999): Book 6 Of The Vocational Training Series, Third Edition,
150p.
ERIC GILBERTON (2010): Gas Lift Failure Mode Analysis and the Design of Thermally
Actuated Positive Locking Safety Valve, 135p.
LETAIEF BRAHIM (2013): Artificial Lift Design: Esp Pump Sizing And Gas Lift Design,
Memory Project, OGIM, 117p.
MOHAMED ALI ELMURABET (2013): OGIM Artificial Lift Course.
PETRONAS CARIGALI: Advance Gas Lift and Field Modeling Optimization, Kuala Lumpu,
Malaysia, 515p
SCHULMBERGER (2000): Gas Lift Design and Technology, 229p.
SITOGRAPHY: http://www.glossary.oilfield.slb.com/en/Terms/g/gas_lift.aspx.
26