Gas Lift Design:

Comparative Study of Continuous and Intermittent Gas Lift

(Case Study of a Real Wells in “In Aménas-Algeria”)

Introduction

I- Overview on Gas Lifting System

II- Types of Gas Lift

III- Gas Lift Design

Conclusion, Proposition and Perspectives

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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.

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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.

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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”.

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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.

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.

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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

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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).

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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 Flow Continuous Tubing Flow

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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.

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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

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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)

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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.

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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.

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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

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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.

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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

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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

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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).

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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:

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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:

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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

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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

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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.

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.

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