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Report on Artificial Gas Lift 1

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Report on Artificial Gas Lift

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    TABLE OF CONTENTS

    S. No. Topics Page no.

    1. Introduction 2

    2. Inflow Performance 2

    3. Outflow Performance 7

    4. Multiphase Flow 8

    5. Artificial Lift 15

    6. Gas Lift 18

    7. Types of Gas Lift Installations 23

    8. Gas Lift Valves 24

    9. Gas Lift Mandrels 33

    10. Gas Lift Designing 35

    11. Gas Lift Unloading 38

    12. Gas Lift Optimization 43

    13. Gas Lift Optimization - Case study 48

    14. Bibliography 60

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    1.0 INTRODUCTION

    In the extraordinary process of formation of oil and gas deep under the earth crust followed by their migration

    and accumulation as oil and gas deep under the earths crust, followed by their migration and accumulation as

    oil and gas reserves, a great amount of energy is stored in them. This energy is in the form of dissolved gas in

    oil pressure of free gas, water and overburden pressure. When a well is drilled to tap the oil and gas to the

    surface, it is the general phenomenon that oil and gas flows to the surface vigorously by the virtue of the energy

    stored in them. Over the years/months of production the decline of energy takes place and at one point of time,

    the existing energy is found insufficient to lift the adequate quantity of oil to the surface. From that time

    onwards man made effort is required and that is known as artificial lift. Therefore, the flow of oil from the

    reservoir to the surface can be fundamentally dichotomized as self flow period and artificial lift period.

    Any artificial lift system depends on the following factors:

    Inflow Performance Curve.

    Drive Mechanism

    Outflow Performance Curve

    Multiphase flow.

    2.0 INFLOW PERFORMANCE CURVE

    It is the graphical representation of the relation between the flowing bottom hole pressure and liquid production

    rate. It is used for evaluating the reservoir deliverability.

    2.1 TYPICAL IPR CURVE:

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    Typical IPR curve for a single fluid is a straight line representing PI i.e. as the drawdown decreases the

    production falls linearly.

    Slope of the IPR curve gives the productivity index.

    P. I. = Q / (Pr Pwf)

    Where,

    P. I. = Productivity index.

    Q = Total quantity of fluid.

    Pr = Reservoir Pressure.

    Pwf = Flowing bottom hole pressure.

    Now, Q (Pr Pwf)

    Q = K (Pr Pwf)

    K = Q / (Pr Pwf)

    Where K is a constant, known as P. I.

    2.2 VOGELS WORK ON IPR

    From general IPR equation i.e.

    J = qo / (Pr Pwf) ............... (1)

    When Pwf = 0, qo = qmax

    That is J = qmax / (Pr 0)

    or J = qmax / Pr ...............(2)

    Comparing equation (1) by (2),

    qo / qmax = (Pr Pwf) / Pr

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    Or qo / qmax = 1 (Pwf / Pr)

    Since IPR curve below bubble point is not a straight line, he created a parabolic equation from the above.

    He distributed {Pwf / Pr} in the following manner

    20 % of {Pwf / Pr} & 80 % of {Pwf / Pr}

    Therefore, the new equation is established as:-

    qo / qmax = 1 [0.2 {Pwf / Pr}] [0.8 {Pwf / Pr}]

    He then plotted dimensionless IPRs in two dimensional plane, where X- axis represents qo / qmax and Y- axis

    represents Pwf / Pr

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    2.3 TYPES OF RESERVOIR DRIVE MECHANISMS:

    a) Solution Gas Drive:

    This means there is no change in the initial size of reservoir. There is no water encroachment for this

    particular type of drive mechanism. In this particular type of drive the driving mechanism is the gas

    coming out of the solution flows along the oil. The gas comes out of the solution but doesnt move

    upward to form a gas cap. Gas bubbles formed in the oil phase remains in the oil phase remains in the oil

    phase resulting in the simultaneous flow of both oil and gas. Oil production is thus the result of the

    volumetric expansion of the solution gas and volumetric expulsion of oil. This type of reservoir drive

    approaches a gas liberation process.

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    b) Water Drive:

    The reservoir volumes of oil dont remain constant. Water encroaches changing the initial volume of the

    container. There is a displacement of the oil by water. This reservoir type could also have a gas phase

    resulting in the combination water depletion drive. There will be an optimum rate of production for this

    reservoir type.

    c) Gas Cap Expansion Drive:

    This type of reservoir drive mechanism may also refer as segregation or gravity drainage. The reservoir

    is in a state of segregation. The drive approaches a differential gas liberation process.

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    OUTFLOW PERFORMANCE

    3.0 Introduction

    It is the pressure required to pump a required amount of liquid at a given well head pressure. It depends on the

    following factors:

    Tubing size

    Tubing head pressure

    Water Cut

    GLR

    Choke Size

    Depth

    The point where the IPR and the outflow curve meet is called the point of operation or the operating point.

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    MULTIPHASE FLOW

    4.0 Introduction

    Single phase flow refers to one fluid medium only and whenever there is more than one fluid medium, for

    example oil, water and gas, it is termed as multiphase medium of fluid flow. The multiphase flow is divided into

    two broad categories

    Horizontal on the surface

    Vertical in the well

    4.1 HORIZONTAL FLOW:

    1. STRATIFIED SMOOTH FLOW : Low gas & liquid flow rates Phases separated by gravity

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    2. STRATIFIED WAVY FLOW: Same as above, with relatively high gas flow rate.

    3. INTERMITTENT SLUG FLOW : Intermittent flow of liquid & gas gas pockets develop

    4. ELONGATED BUBBLE FLOW: Same as above, earlier than slug flow, when gas flow rates are

    lower

    5. ANNULAR FLOW: Gas occupies central portion like a cylinder and liquid remains near the pipe wall;

    central portion entrains liquid droplets. Occurs at very high gas flow rate.

    6. DISPERSED BUBBLE FLOW: At very high liquid flow rate, liquid phase is continuous & gas phase

    is dispersed all around liquid in the form of discrete bubbles.

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    4.2 VERTICAL/INCLINED FLOW:

    1. BUBBLE FLOW

    Occurs at relatively low liquid rates.

    2. SLUG FLOW

    Symmetric about the pipe axis

    Gas phase -like a large bullet shaped gas pocket

    with a diameter almost equal to pipe diameter

    Gas pocket is termed as Taylor Bubble

    3. CHURN FLOW

    Similar to slug flow, though it is chaotic with

    no clear boundaries between the two phases.

    Flow pattern is characterized by oscillatory motion.

    Occurs at high flow rates; liquid slugs become frothy.

    4. ANNULAR FLOW

    Liquid film thickness is almost uniform

    around pipe wall.

    Characterised by a fast moving gas core.

    Liquid film is highly wavy due to high interfacial stress.

  • Page | 11

    4.3 EFFECT OF VARIABLES:

    1. HORIZONTAL FLOW:

    Pipe Diameter Pressure loss (dP) decreases rapidly with increase in Pipe Diameter.

    Flow Rate Higher flow rate increases dP

    GLR Increased GLR increases friction, hence more dP, unlike to vertical flow.

    Viscosity Viscous crude offers more problems in horizontal flow mode.

    Water Cut Its effect is not pronounced.

    Slippage Its effect is not pronounced.

    Kinetic Energy For High flow rates & low density it is considered for computation.

    2. VERTICAL FLOW:

    Tubing Size It has pronounced effect in deciding FBHP requirement.

    Flow Rate It establishes the required FBHP, which influences tubing size selection.

    GLR Increase GLR reduces FBHP requirement, after a point reversal takes place.

    Density Higher density increases dP.

    Viscosity Higher viscosity increases dP.

    Water Cut Higher water cut increases dP.

    Slippage It is observed during unstable flow region.

    Kinetic Energy For High velocity & low density it is considered for computation.

    4.4 MULTIPHASE CORRELATIONS:

    Assumptions Common to all Correlations

    a) Fluid must be free from emulsion.

    b) Fluid must be free from scale / paraffin build up.

    c) Mashed or kinked joints should not exist.

    d) Flow patterns should be relatively stable.

    e) No severe slugging should occur.

    f) Oil should not be very viscous.

  • Page | 12

    4.5 HORIZONTAL CORRELATIONS:

    1. LOCKHART & MARTINELLI: Lockhart & Martinelli presented a very good work on horizontal

    multiphase flow correlations which has been widely used by the industries. This correlation is

    considered fairly accurate for very low gas and liquid rates and small conduit sizes.

    2. BAKER: baker has dealt with the multiphase flow in horizontal pipes especially in hilly terrain.

    While using this method the slug and annular flow regions are found to be more accurate. His

    method is better for pipes sizes greater than 6 inches. Also, his work is found suitable whenever

    there is a case of slug flow. Baker has tried to present different equations for each flow pattern and

    that is main difference between baker and Lockhart & Martinellis approach.

    3. DUKLER ET AL: he identified forces due to pressure, viscous shear forces, forces due to gravity,

    and forces due to pressure, viscous shear forces, forces due to gravity and forces due to inertia or

    acceleration of fluid.

    4. EATON ET AL: Eaton et al conducted an extensive field study covering various gas and liquid

    rates in long tubes. The diameters of tubes were 2 inches and 4 inches. He varied the liquid rates

    from 50 to 2500 BPD in 2inch line and 50-5000 BPD in 4 inch line. For each liquid rate, he varied

    the gas liquid ratio from bare minimum to maximum as allowed by the system. One of the most

    important contributions of Eaton was liquid hold-up correlation. This hold up related to fluid

    properties, flow rate and the flow pattern in the line. Eaton applied a similar dimension analysis to

    this problem as had been done by Ros and also by Hagedorn & brown for vertical flow.

    5. BEGGS & BRILL: the Beggs and Brill method is suitable for a wide range of conditions and is

    considered realistic approach. This method has been extensively tested for large diameter pipes. For

    each pipe size liquid and gas rates were varied and all flow patterns of fluid were observed. The

    liquid hold up in horizontal pipe was first calculated while developing the correlation and the

    variation of liquid holdup with different pipe inclination was found out.

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    4.6 VERTICAL CORRELATION:

    1. HAGEDRON AND BROWN: In most of the oil and gas companies Hagedorn and brown

    correlation is used because they came out with generalized correlation which include almost all

    practical range of flow rates a wide range of GLRs normally all available tubing sizes and the effect

    of fluid properties. This study also includes all of the prior works done on the effect of the liquid

    viscosity. Hagedorn and brown also incorporated a kinetic energy term which was considered to be

    very significant in smaller diameter pipes in the region where fluid was having low density. They

    used Griffith correlation when the bubble flow existed. The liquid hold up was checked to make sure

    that it exceeded the holdup for no slippage to occur.

    2. DUNS AND ROS: Duns & Ros has divided the flow regime mainly into three regions depending on

    the amount of gas present

    The liquid phase is continuous. Bubble flow, plug flow and part of froth flow existed.

    There was alternate phases of liquid and gas flow so this region covered slug flow froth flow

    regime.

    The gas was in a continuous phase and there was mist flow.

    Duns and Ros used these three regions and friction factor as well as liquid hold-up separately for

    each region and developed the correlations. They used four dimensionless groups such as gas

    velocity number, liquid velocity number , diameter number, and liquid viscosity number. This is one

    of the best correlations for the multiphase flow.

    3. ORKISZESKI: He emphasized that liquid hold up was the result of physical phenomenon and that

    the pressure gradient was related to the distribution fashion of liquid and the gas phase. He then

    recognized the four types of patterns viz. bubble, slug, transition, and mixed. He prepared separate

    correlations for each to establish slippage velocity and friction. He took help of Griffith and Wallis

    in establishing his correlation for a slug flow and he used basically Duns and Ros correlation for

    transition and mist flow.

  • Page | 14

    4. WINKLER AND SMITH: in order to give their gradient curves a universal application selected

    some average liquid and gas conditions with corresponding PVT characteristics and thereafter

    demonstrated the effect of every possible variable upon the gradient curve like effect of tubing size,

    effect of flow rate, effect of gas liquid ratio, effect of oil and water gravity, effect of gas gravity,

    effect of well temperature, effect of solution gas-oil ratio etc. these effect are under the assumption

    that there is no paraffin buildup in the tubing wall, no loading of fluid in the bottom of the tubing or

    the breaking out of gas from the fluid.

    5. BEGGS AND BRILL: Beggs and Brill developed the correlation by doing experimentation on a

    small scale test facility. This small scale test facility consisted of 1 inch and 1.5 inch section of

    acrylic pipe of 90ft long which was setup in the Tulsa university fluid flow section. The flow

    parameter studied were gas flow rate , liquid flow rate , average system pressure, pipe diameter( as

    in setup i.e. 1 & 1.5) liquid hold up, pressure gradient, inclination angle and horizontal flow

    patterns. The fluids used were water and air. Liquid holdup and pressure gradient were noted at

    every step. The original flow pattern was modified to include a transition zone between the

    segregated and intermittent flow regimes.

    6. GOVIER AND AZIZ: Govier and Aziz correlation was flow regime dependent. The came out with

    the method for the bubble and slug flow regime in vertical two phase flow.

    7. PETROLEUM EXPERT 3: This correlation combines the best features of existing correlations. It

    uses the Gould et al flow map and the Hagedorn Brown correlation in slug flow, and Duns and Ros

    for mist flow. In the transition regime, a combination of slug and mist results plus original work on

    predicting low-rate VLPs and well stability and original work for viscous, volatile and foamy oils.

    These correlations are useful for

    Selecting tubing sizes.

    Predicting when the well will cease to flow.

    Designing of artificial lift.

    Determining flowing bottom hole pressures from the wellhead pressures.

    Determining the flowing bottom hole pressure, which in turn help in determining P.I. of the well.

    Predicting maximum flow rates possible.

    Predicting whether the well is able to flow as per the present & future profile.

  • Page | 15

    ARTIFICIAL LIFT

    5.1 Definition:

    Artificial lift is a supplement to natural energy for lifting well fluid to the surface either by using gas injection

    or by using gas pumps. It is a technique by which a steady, low bottom hole flowing pressure is created in order

    to lift the fluid from well bore.

    5.2 Purpose:

    The purpose of the artificial lift is to create a steady low pressure or reduced pressure in the well bore against

    the sand face, so as to allow the well fluid to come into the well bore continuously. If a predetermined

    drawdown in pressure can be maintained the well will produce the desired fluids.

    Most wells completed in oil producing sands will flow naturally for some period of time after they begin

    producing. Reservoir pressure and formation gas provide enough energy to bring fluid to the surface in a

    flowing well. As the well produces this energy is consumed and at some point there is no longer enough energy

    available to bring the fluid to the surface and the well will cease to flow. 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.

    When gas lift is used, high-pressure gas provides the energy to enable the well to produce.

    5.3 Artificial Lift Systems:

    There are four basic types of artificial lift:

    1. Sucker rod pumping (SRP)

    2. Hydraulic pumping

    3. Electrical Submersible pumping (ESP)

    4. Gas lift.

    Besides these there are some other Artificial Lift Systems like Jet Pumps, Progressive Cavity Pumps (PCP) and

    Plunger Lift which are used in some wells but the above listed 4 systems are the most commonly used for

    Artificial Lift.

  • Page | 16

    FIGURE: Artificial Lift Systems

    1. Sucker Rod Pumping (SRP):

    Sucker rod pump, abbreviated as SRP is a very old technique in the oil industry for lifting of crude oil from the

    wells and in fact it is the most widely used mode of artificial lift system in the present day scenario. Most of the

    artificial lift wells have been operating on SRP.

    Advantages

    Provides mechanical energy to lift oil

    Efficient, simple and easy to operate

    Pumps a well down to very low pressure

    Applicable to slim holes, multiple completions, and high-temperature and viscous oils

    Easy to change to other wells with minimum cost

    Disadvantages

    Excessive friction in crooked/deviated holes

    Solid-sensitive problems

    Low efficiency in gassy wells

    Limited depth due to rod capacity

    Bulky in offshore operations.

  • Page | 17

    2. Hydraulic Pumping:

    Hydraulic Lift provides the ability to hydraulically circulate the pumps to the surface for maintenance which

    dramatically reduces well downtime and eliminates pulling unit expenses and eliminates pulling unit. expenses.

    Advantages

    Hydraulic pumps can produce from relatively small to large rates, typically 135 to 15,000 B/D, from

    great depths. The deepest recorded installations is at a depth of 18,000 ft.

    Unlike the rod pump system, the hydraulic pump system can be used effectively in crooked or deviated

    wells.

    Pump speed can be easily varied to accommodate changing inflow conditions.

    With a free pump, we can retrieve the pump easily. Maintenance, therefore, is easily accomplished and

    new pumps of the same or different size may be installed as needed.

    Because wellheads and surface facilities are compact, hydraulic pumping systems are ideal for offshore

    or urban production sites.

    Chemicals may be added to the power fluid, especially in OPF systems, to protect tubing and casing

    from corrosion.

    If very limited volumes of free gas are pumped, the hydraulic pump system has the highest efficiency of

    any of the artificial lift systems.

    Disadvantages

    Power oil systems are a fire hazard.

    High solids production is troublesome.

    Oil inventory required for power oil system reduces profitability.

    Where gas is not vented there is a loss of efficiency difficult for field personnel to troubleshoot.

    Some installations require two strings of tubing.

    Treating scale below packer is difficult.

    Problems may develop in treating power water.

    3. Electrical Submersible Pumping (ESP):

    The electrical submersible pump (ESP) is basically a high volume mode of lift system. The minimum capacity

    of ESP is known to be around 200 bpd and the maximum capacity is as high as 90,000 bpd.

  • Page | 18

    Advantages

    Very high volumes at shallow depth can be produced.

    Is possible to almost pump off.

    Disadvantages

    Maximum volume drops off fast with depth.

    Is very susceptible to free gas in pump causing damage.

    Control equipment is required on each well.

    Tubing must be pulled to change pump and cable.

    Gas Lift

    6.0 Introduction

    Gas lift term is a misnomer. In fact, liquid gets lifted with the aid of gas. In earlier times, water was being lifted

    with the help of air. Air was conveyed through tubing and water received on the surface through tubing -

    wellbore annulus. The same system of lifting, i.e. with the air was adopted by oil industry in the beginning for

    lifting oil. But there were problems involved in the use of air as a lifting medium for oil, as mixing of air with

    hydrocarbon not only may form explosive mixture but also causes corrosion because of the presence of oxygen.

    So, from then onwards compressed natural gas or high pressure natural gas is being used in general to lift oil.

  • Page | 19

    Gas lift system is now broadly classified into two categories:-

    (1) Continuous gas lift.

    (2) Intermittent gas lift.

    6.1 CONTINUOUS GAS LIFT

    The basic principle underlying the self flow and continuous gas lift is same. The only difference between them

    is the source of gas. In the case of natural flow, gas comes into the well bore either along with oil or in the

    dissolved condition in the oil whereas, in the latter case, the gas is conveyed down the hole and is injected into

    the oil body. That is why continuous gas lift can be seen as an extension of the self flow period of oil well.

    The basic principle of continuous gas lift is to inject the gas in the oil body at some predetermined depth at a

    controlled rate to aerate the oil column above it and as a result the density of oil column gets reduced to a point

    where a flowing bottom hole pressure for a desired rate of production is sufficient to lift the oil to the surface.

    Thus, oil is produced continuously from the well.

    Gas injection is done at a slow rate and continuously. Because of this reason, the port size of the gas lift valve

    is smaller in comparison with port sizes of the gas lift valves for intermittent gas lift. Generally, the port sizes

    for continuous gas lift are 3/16", 1/40" and 5/16".

    It is also generally intended and the accepted practice that in the continuous gas lift, only one valve will be

    accomplishing the gas injection work and that this valve should be as deep as possible as per the available

    normal gas injection pressure. This valve is termed as 'operating valve'. The valves above it are used to unload

    the well to initiate the flow from the reservoir. Once the gas injection begins through the operating valve the

    upper valves, termed as "unloading valves" are closed. In case there is disruption in gas injection, the well will

    be loaded. So, when gas lift is resumed, the well is required to be unloaded with unloading valves.

    6.2 INTERMITTENT GAS LIFT

    In intermittent gas lift sufficient volume of gas at the available injection pressure is injected as quickly as

    possible into the tubing under a liquid column and then the gas injection is stopped. The volume of gas expands

    and in the process it displaces the oil on to the surface. So, the assistance of flowing bottom hole pressure is not

    required when gas displaces oil. Static bottom hole pressure, flowing bottom hole pressure and

    productivity index of the well govern the fluid accumulation in the tubing.

    In this system, a pause or idle period is provided, when no gas injection takes place. In this period the well is

    allowed to build up the level of liquid which depends upon the reservoir pressure and PI. of well. Then again,

  • Page | 20

    next gas injection cycle is initiated to produce oil. In this manner, as the name suggests, intermittent gas lift

    works on the principle of intermittent injection in a regular cycle. It is to be noted that in the cycle,

    injection time should be as short as possible, so that a large volume of gas can be injected quickly underneath

    the oil slug. As a result oil slug above the point of gas injection will acquire the terminal velocity (maximum

    velocity) within shortest possible time, which would minimize the liquid fall back in the tubing string. Less

    fluid fall back will not only increase production but also help reduce the paraffin accumulation problem in the

    tubing, if oil is paraffinic in nature.

    For injecting large amount of gas, large ported gas lift valves are required. That is why gas lift valves having

    port sizes 1/2", 7/16", 3/8" or 5/16" are preferred. In intermittent gas lift application, two different gas injection

    flow rates are considered. One is the normal gas injection rate required for a well and other is the instantaneous

    gas injection rate, commonly called per minute demand rate of gas injection. The high rate of gas injection is

    calculated on the basis of short duration of gas injection. It helps to minimize the injection gas breakthrough and

    arrests liquid fall back to a desired extent. The other one is the cumulative quantity of injected gas per day,

    called normal gas injection rate.

    Similar to the continuous gas lift, a number of gas lift valves are also installed in the intermittent gas lift well.

    The last valve is located as deep as possible (conventionally last valve is just above the top of perforations). At

    every cycle, the injection of gas takes place through this valve first and as such, it is also termed as operating

    valve. The upper valves may or may not operate, when the liquid slug crosses the valve during its upward

    travel. If the upper valve opens as the slug crosses the valve, the additional gas further arrests fluid fall back

    and thus results in more oil production.

    It can be comprehended that continuous gas lift system should be employed when well has moderate to high

    reservoir pressure and PI. Continuous gas lift characteristically provides high volume of oil production.

    Intermittent gas lift system should be deployed when the well has a poor PI and low reservoir pressure.

    That is why; intermittent gas lift provides comparatively much lower volume of oil production than that of

    continuous gas lift.

    Fig. Continuous Gas Lift Fig. Intermittent Gas Lift

  • Page | 21

    6.3 Few Important Points:

    Injection casing pressure should be greater than tubing pressure.

    Pressure gradient for water is about 0.433psi/ft. But on addition of gas, that is, during continuous gas lift

    this pressure gradient is reduced to about 0.15psi/ft.

    Thus, in case of well with depth around 6000ft well need around 900 psi that is around 60 kg of

    injection pressure for gas.

    But this is true only when weve assumed THP=0.

    So, if THP=20kg(say) then for the same 6000ft depth well require an injection pressure of 60+20=80kg.

    For a well depth of 8000 ft , Injection pr 80 Kg/cm2, THP-10 Kg/cm2 , Approx. Injection depth

    7000 ft.

    Thus, estimation of gas injection pressure depends on depth and THP.

    Specific gravity also effects the estimation. As we go deeper the pressure gradient for gas increases

    from 15psi/100 to about 16-20psi/100 depending on the conditions.

    If THP increases then also production decreases.

    In Intermittent Gas Lift design gradient of .04psi/ft is achieved.

    Fig. Pressure Depth Relations

  • Page | 22

    6.4 Advantages and Limitations of Gas Lift

    The flexibility of gas lift in terms of production rates and required depth of lift cannot be matched by other

    methods of artificial lift for most wells if adequate injection gas pressure and volume are available. Gas lift is

    considered one of the most forgiving forms of artificial lift since a poorly designed installation will normally

    gas lift some fluid. Many efficient gas lift installations with wire line retrievable gas lift valve mandrels are

    designed with minimal well information for locating the mandrel depths upon initial well completion in

    offshore and inaccessible onshore locations. Highly deviated wells that produce sand and have a high

    formation/liquid ratio are excellent candidates for gas lift when artificial lift is needed. Many gas lift

    installations are designed to increase the daily production from flowing wells. No other method is as ideally

    suited for through-flow-line (TFL) ocean floor completions as a gas lift system. Maximum production is

    possible by gas lift from a well with small casing and with high deliverability and bottom hole pressure. Wire

    line retrievable gas lift valves can be replaced without killing a well with a load fluid or pulling the tubing. Sand

    laden well production fluids do not pass through the operating gas lift valve. The reported overall reliability,

    replacement and operating costs for subsurface gas lift equipment are lower than for other methods of lift.

    The most important limitation of gas lift operation is the lack of formation gas or the availability of an

    outside source of gas. Other limitations include wide well spacing and unavailable space for compressors on

    offshore platforms. Gas lift is seldom applicable to single well installation and to widely spaced wells that are

    not suited for a centrally located power system. Gas lift is not recommended for lifting viscous crude, super-

    saturated brine or an emulsion. Old casing, dangerously sour gas and long small ID flow lines can eliminate gas

    lift operations. Wet gas without proper dehydration will reduce the reliability of gas lift operations.

  • Page | 23

    TYPES OF GAS LIFT INSTALLATIONS

    7.1 Closed Installation can be defined as

    When there is a packer in the tubing - casing annulus, below the deepest gas lift valve and when there is a

    standing or non-return valve in the tubing at the tubing shoe.

    7.2 Semi-Closed Installation can be defined as

    When there is only packer in the tubing annulus, below the deepest gas lift valve.

    7.3 Open Installation is defined as,

    When there is neither any packer in the tubing - casing annulus nor any standing valve in the tubing shoe.

    The installation of packer is recommended:

    (i) To prevent U-tubing through the tubing, especially when reservoir pressure is very low and the deepest

    gas lift valve is very near to the perforation.

    (ii) To prevent rise of fluid level in the annulus, especially when there is an idle period of intermittent gas

    lift. So, the same liquid is to be U-tubed again through the gas lift valve before the normal gas injection

    is resumed.

    (iii) To prevent production casing coming in contact with the well fluid.

  • Page | 24

    (iv) In case of offshore wells, it is mandatory to have packer in the annulus. This is primarily due to safety

    aspect for offshore wells to prevent accidental leakage of oil and gas in the sea through leaked casing.

    The installation of standing valve is recommended when reservoir pressure is low and PI is in the range of

    moderately high to high. Generally the lowering of standing valve is decided afterwards during the production

    from the well. For this reason, in most of the places, the general practice is to lower A-nipple or D-nipple or

    equivalent along with the tubing in the initial installation period. If required, the standing valve is either

    dropped or is lowered with the wire line on the A or D-nipple. It is also likely that with the production of fluid

    from the well, the sand slowly gets settled on the standing valve making the standing valve non-operative. So,

    to avoid this problem the deepest gas lift valve should always be placed just above or very near to the

    standing valve. The turbulence created due to gas injection at that place inhibits the buildup of sand on the

    standing valve.

    Generally, semi-closed type of installation is the standard practice for intermittent gas lift wells, whereas open

    or semi-closed are for continuous gas lift wells.

    GAS LIFT VALVES

    8.0 Introduction

    A gas lift valve is analogous to a downhole pressure regulator. The surface areas of the gas lift valve are

    exposed to tubing and casing pressures. So, in response to casing or tubing pressure the gas lift valve opens,

    which allows injection gas to enter the production string to lift fluid to the surface. The bellow operated

    nitrogen pressure loaded gas lift valve is the most common type of gas lift valves being used by oil industries.

    Continuous Gas Lift usually consists of a number of unloading valves with an orifice valve at the operating

    point. In this context the role of the unloading gas lift valve should be to allow smooth, positive and reliable

    unloading of the well to the orifice over many years with continuously changing conditions. There are several

    different types of gas lift valves used in order to achieve this and each uses a particular design technique.

  • Page | 25

    8.1 Injection Pressure or Casing Pressure Operated Valves

    The IPO valves are designed in such a way that the casing pressure is acting on the larger area of the bellows

    and thus they are primarily sensitive to the casing pressure. The drop in casing pressure which occurs during

    unloading is used to close the valves in the correct sequence. The added benefit of this type of operation is that

    when the desired injection point is reached then an additional casing pressure drop can be designed in ensuring

    the upper valves are firmly closed and that fluctuations in tubing pressure are very unlikely to result in the valve

    re-opening.

    8.2 Production Pressure or Tubing Operated Valves

    In the PPO valves the flow path is reversed and thus the tubing pressure is acting on the larger area of the

    bellows making the valve primarily sensitive to the tubing pressure. The drop in the tubing pressure as gas is

    injected is used to close the valve. As this is less predictable than the injection pressure their uses are generally

    limited to dual wells where changes in casing pressure would cause interference between the strings with the

    IPO valve and also in situations where the injection pressure is prone to fluctuate and the production pressure

    can be considered the more predictable.

  • Page | 26

    Therefore, Casing pressure operated valves are preferred over Tubing pressure operated valve.

    8.3 Pilot Operated Gas Lift Valve

    This is a casing pressure operated gas lift valve, but with some fundamental differences in the construction of

    the valve as well as in its operating mechanism. The principle behind the construction of this type of valve is to

    separate the gas flow capacity from the pressure control system.

    The pilot valve has two distinct sections. One is pilot section and the other is power section. The pilot section

    is very similar to an unbalanced type of valve, with the exception that injection gas does not pass through the

    pilot port into the tubing. The power section consists of- a piston, stem, spring and the valve port through which

    injection gas enters into the tubing.

    As the casing pressure reaches the opening pressure of the valve, at first, the pilot section port opens. The gas

    through the pilot port, then, exerts pressure over the piston in the main valve section. The piston is, then pushed

    downward against the compressive force of spring. This causes the downward movement of the stem and the

    valve gets opened. Casing gas then, passes through the main section port to find entry in the tubing. When the

    casing pressure decreases below the closing pressure of the pilot section valve, the pilot section, like in the

    normal casing pressure operated valves, gets closed. Then, the trapped gas between the pilot port and piston is

    bled in the tubing through a specially constructed bleeder line in the main valve section.

  • Page | 27

    8.4 MERITS AND DEMERITS OF DIFFERENT CATEGORIES OF GAS LIFT VALVES

    8.4.1 Advantages of Casing Pressure Operated N2 Charged Bellows with or Without Spring for

    Continuous and Intermittent Gas Lift

    1. The valve is of a very simple design and is rugged.

    2. The calibration of the valve is done very easily

    3. Valves can be repaired easily

    4. Valve can be suited both to continuous and intermittent gas lift by differing the port sizes only.

    Small ported valve generally is suitable for continuous gas lift and bigger ported for intermittent

    gas lift.

    5. N2- charged bellows with spring is not affected by the temperature. So, the opening pressure of

    the valve is not changed with varying temperature in the well.

  • Page | 28

    8.4.2 Limitations of Casing Pressure Operated N2 Charged Bellows with or without spring for continuous

    and Intermittent Gas Lift

    1. Excessive valve spread (difference of pressure at which valve opens and closes) characteristic of

    the valve can result in an excessive injection gas volume to be used in one cycle in intermittent

    gas lift.

    2. For dual installation of gas lift valves in one well, with a common source of gas injection, it is

    very difficult to control the gas injection.

    3. Only bellows type of valve is temperature sensitive. It affects the closing and opening pressure of

    valves.

    4. N2-charged bellows type valve with spring has restricted gas passage; therefore, this valve is not

    suitable for intermittent gas lift.

    8.4.3 Advantages of a Tubing (Fluid) Pressure Operated Gas Lift Valve

    It has got many advantages when used in intermittent gas lift design. The most important application is

    for dually completed gas lift wells, i.e., when two parallel tubings in a well both fitted with gas lift

    valves are used in a well for producing two zones through two different tubings with the help of gas lift.

    8.4.4. Disadvantages of a Tubing (Fluid) Pressure Operated Gas Lift Valve

    1. It is not a good valve for use in the well with low flowing bottom hole pressure.

    2. In absence of any control from the surface, optimum/capacity oil production may not take place.

    3. This type of valve is not recommended for continuous flow. While trying to control the volume

    of gas injection, it may happen that the upper valve opens and desired point of gas injection is

    not maintained. This results in lower production.

    8.4.5 Disadvantages of a Pilot Valve

    1. It is complicated in design and in case, the bleed hole in the power section gets plugged, the

    valve, then, remains in open position.

    2. Pilot valve is not recommended for continuous gas lift since the discharge of gas in the tubing is

    very large and for a very short period.

    However, Pilot Valve can be used for Intermittent Gas Lift.

  • Page | 29

    8.5 SELECTION OF PROPER GAS LIFT VALVE

    Gas Lift Valves for Continuous and intermittent Gas Lifts can be selected considering the following conditions:

    1. Unbalanced, bellows operated N2 -charged with bigger port viz 7/16", 3/8", 1/2" and 5/16" can

    be preferred for intermittent gas lift.

    2. Unbalanced, bellows operated, N2 - charged with smaller port opening viz 1/8", 3/16"and 1/4" can

    be preferred for continuous gas lift. However where because of the high volume production, greater

    port area is required, the gas lift valve of the required port area larger than 1/4" should be utilized.

    3. For dually completed wells, tubing pressure operated valves are certainly better. With unloading

    valves as tubing pressure operated and the operating valve for both the string as casing pressure

    operated valves, are a better proposition. Though, many a times casing pressure operated valves are

    preferred for dually completed wells.

    4. Pilot valve as the operating valve for intermittent gas lift is sometimes a better choice.

    8.6 Force Balance Equations

    Let

    Ab = Effective area of bellows (Sq.in.)

    AV = Area of valve port (Sq.in.)

    Ptd = Tubing pressure at valve depth (psig)

    Pbd = Bellows charge pressure at well temperature (psig)

    Pb = Bellows pressure at 60OF test bench.

    Pod = Operating casing pressure at valve depth

    Potd = Valve opening pressure when there is no pressure exerted over the

    valve port area from the other side i.e. when tubing pressure is zero.

    Pcd = Valve closing pressure in casing at valve depth.

    PTRO = Valve opening pressure at 60oF in the test rack.

    Ct = Temperature correction factor.

  • Page | 30

    Gas lift valve dome pressure at 60oF

    Ct =

    Gas lift valve dome pressure at well temperature

    Td = Temperature at valve depth (OF)

    Pik = Maximum injection pressure available at the surface.

    (i.e. kick off pressure)

    Pwhf = Flowing wellhead pressure.

    Gsf = Static fluid gradient.

    P1 = Normal gas injection pressure available at the surface.

    Two types of situations can be envisaged in the well:

    I) When valve is closed and ready to open.

    II) When valve is open and ready to close.

    I) Valve is closed and ready to open

    Closing force = Pbd x Ab

  • Page | 31

    Opening force = Pod x (Ab) - Pod x (Av) + Ptd x (Av)

    when opening force = closing force,

    Pod (Ab - Av) + Ptd Av = Pbd Ab

    ==> Pod (1-Av/Ab) + PtdAV/Ab = Pbd

    Pbd Av/Ab

    ==> Pod = ------------- - Ptd ---------

    (1 -Av /Ab) (1 -Av/Ab)

    ==> Pod = Potd - Ptd [T.E.F.]

    Pbt

    Where, Potd = -------------

    (1 -Av /Ab)

    And T. E. F. Av /Ab

    (Tubing effect factor) = ---------------

    (1 -Av /Ab)

    ==> Pod = Potd - T E.

    Where, T. E. = Tubing effect = Ptd x T. E. F.

    Note:

    Every gas lift manufacturer is supposed to supply Ab and Av for each type of valve.

    Av/Ab

    Then Av/Ab' (1-Av/Ab) and T. E. F. = ----------

    1-Av/Ab

    can either be calculated or the same would be provided by the manufacturer for each types of valve.

  • Page | 32

    II) When valve is open and ready to close

    Closing force = Pbd x Ab

    Opening force = Pcd x Ab

    Since, opening force = closing force

    Pcd x Ab = Pbd x Ab

    or Pcd = Pbd

    In the open bench calibration of valve, the valve is closed with the force of N2 -gas in the bellows with or

    without spring. Thereafter the pressure is applied to open the gas lift valve. It is a very convenient way of

    calibrating the gas lift valve. It is a case of where valve is closed and ready to open. So, with the little

    modification of the equation, along with converting some terms to surface condition, we get POTB in place of Pod

    and since there is no tubing pressure in the open test bench, so the term containing P td is zero. Thus the

    expression without spring

    Pb

    POTB = --------------

    (1-Av/Ab)

  • Page | 33

    8.7 Nominal Setting Pressure or Test Rack Opening Pressure

    Valves are usually calibrated, or set, in a test rack. For pressure loaded valves it is not practical to

    set the actual dome pressure directly. Rather, the dome is overcharged and the pressure released

    gradually until the valve opens at the required external opening pressure.

    Therefore all valves are calibrated in terms of an extended pressure, applied at the test rack, that

    would open the valve if the dome pressure or/and the spring tension was set correctly. This pressure

    is known as the nominal setting pressure' (Pn) or the 'Test rack opening pressure' (Ptro).

    The nominal setting pressure (Pn) is the external pressure at which the valve opens at a selected

    standard temperature, and with atmospheric pressure under the valve port.

    Pd(60F)

    Ptro = ----------

    1 - R

    GAS LIFT MANDRELS

    9.0 Introduction

    Gas lift mandrel is the port of tubing string. It houses the gas lift valve and check valve. The mandrel's length is

    very short - it ranges from 4'to say 7'to 8'depending upon the length of the gas lift valve and check valve.

    There are two general types of mandrels in use - one for conventional or for fixed valve and the other is for

    wire line retrievable valves. In the conventional mandrel gas lift and check valves are fitted on to the exterior

    side of the mandrel with the valve attachment lugs.

    The mandrel for wire line retrievable valve is of a different type. The gas lift valve is housed inside instead of

    being on to the outside. The eccentric form of the mandrel is required to ease the wire line job for the selective

    setting and retrieval of the gas lift valve.

    Generally, the conventional mandrel is having much less cost than the wire line mandrel. But at the same time

    if the servicing of gas lift valves is required or re-setting of pressure is required, for conventional mandrel,

    entire tubing string is to be pulled out, whereas, only with the help of wire line job, redressal job of the gas lift

    valve is carried out in wire line mandrel type. So, in this sense, wire line mandrels are more cost effective since

    every effort is made to minimize the work over job operations.

  • Page | 34

    Many times, it has been experienced that wire line job is extremely difficult in a well with high paraffin

    deposition in the tubing. Also, scale deposition inhibits the movement of wire line tools. So, with the high

    initial cost of the wire line mandrel coupled with the problems like paraffin, scale in the tubing, onshore wells

    have to be lowered mostly with conventional gas lift mandrels.

    Proper identification with respect to its size is most important for a mandrel. It means how big a mandrel

    with gas lift valve in position (for conventional one) can go into the well given the wells minimum casing I.D.

    So, maximum diameter of mandrel is taken into account with tubing string coupled at its two ends with respect

    to casing drift diameter.

    Fig. Gas Lift Mandrels

  • Page | 35

    GAS LIFT DESIGN

    10.0 Introduction

    The most efficient operation of a gas lift installation depends on proper design. The selection of the valves for

    the well, the spacing of the valves and the determination of proper pressure setting depends upon accurate

    design techniques.

    The design objective is to control the vertical fluid gradient so as to give the desired production rate. The design

    is constrained by the limitations of gas injection pressure, available gas volumes, the nature of the produced

    fluids, the well's inflow performance and the tubing size.

    To design a continuous gas lift installation, the following data is required.

    1) Depth of perforation interval.

    2) Tubing and casing size.

    3) Inclination profile of the well.

    4) API gravity of oil.

    5) Formation gas-oil-ratio.

    6) Specific gravity of injection and formation gas.

    7) Specific gravity of water.

    8) Desired liquid production rate.

    9) Flowing wellhead pressure, FTHP.

    10) Injection gas pressure at well.

    11) Volume of injection gas available.

  • Page | 36

    12) Static bottom hole pressure, SBHP

    13) Productivity index, PI or Inflow Performance Relationship, IPR.

    14) Bottom hole temperature.

    15) Type of reservoir.

    10.1 DESIGN OF CONTINUOUS GAS-LIFT

    The following procedure serves as a guide for designing an installation on the basis. Plot all information on a

    sheet of rectangular coordinate paper.

    1.) Depth is plotted on vertical axis

    2.) Pressure is plotted on horizontal axis

    3.) SBHP is plotted at the correct depth.

    4.) The necessary drawdown in pressure is determined to produce the desired flow rate. For a constant PI,

    drawdown in pressure for any rate is determined.

    5.) The drawdown is subtracted from the SBHP to obtain FBHP and this pressure at depth is noted.

    6.) From the point of SBHP, the static gradient line is extended up the hole to intersect the ordinate. This

    will be the static liquid level in the well for Pwh=0. In case the well is not loaded, can be used as the

    point of location for the first gas lift valve(GLV).

    7.) From the point of FBHP, the flowing pressure traverse is plotted below the point of gas injection

    8.) The surface operating pressure, that can be maintained at the well site to operate the gas lift well is

    selected.

    9.) The kick-off pressure and surface operating pressure are marked at zero depth and are extended

    downwards until it intersect the flowing gradient line .

  • Page | 37

    10.) The point where the operating casing pressure intersects the flowing gradient line is marked as

    the point of balance between the tubing and casing pressure.

    11.) 100 psi is subtracted from the pressure in the casing at this point. Return up the hole a distance

    equivalent to this 100 psi on the FBHP line and this point is noted, This will be the point of gas

    injection. The selection of this differential (100 psi) is extremely important and is controlled by the

    valve spacing.

    12.) The fluid well-head pressure is approximated and this value is marked at zero depth.

    13.) The flowing well-head pressure is connected to the point of gas injection by tracing the

    appropriate flowing gradient curve.

    14.) By subtracting the solution gas from this total gas volume, the required injection GLR is

    obtained, from which the required gas flow rate can be determined.

  • Page | 38

    10.2 DESIGN OF INTERMITTENT GAS-LIFT

    The design of Intermittent Gas-lift can be done either in the multipoint gas injection fashion or in the single

    point gas injection system. In the multipoint injection system, as the liquid slug moves up due to the gas

    injection from bottom valve, the upper gas lift valves will open allowing some gas entry into the tubing that

    helps in lift efficiency. In single point injection, only the bottom valve will operate during each cycle of

    injection gas. Generally for moderate volume of production, multipoint injection is preferred and for a very low

    producing well, single point injection system is adopted. Multipoint, however, has other advantages like it

    reduce paraffin accumulation in the tubing etc.

    The design of multipoint and single point differs materially with the assumed surface closing pressure (Pvc) of

    gas lift valve. If the values of Pvc for the successive lower valves are taken same or with a little difference,

    multipoint design system is obtained. It the values of Pvc for successive valves are comparatively large, then

    single point injection design will result.

    GAS LIFT UNLOADING

    11.0 Introduction

    After gas lift valves have been installed, the first operation is to unload the fluids. The well may be unloaded

    either intermittently or continuously. It is normal for a well placed on continuous gas lift to be unloaded

    continuously, and for a well placed on intermittent gas lift to be unloaded intermittently. If a well is to be placed

    on intermittent flow gas lift, it can be unloaded with fewer valves than a continuous flow installation.

    11.1 Importance

    It is the most important process in installation of gas lift. The objective is to enable injection gas to reach the

    operating gas lift valve without excessive kick-off pressure, so that a final, stabilized production rate can be

    easily obtained. Gas is injected according to API standardization. The gas is injected at the rate of 50psi/10min

    till 400 psi of pressure. After 400psi the gas is injected at 50psi/5min.

  • Page | 39

    11.3 UNLOADING SEQUENCE

    I. No gas is being injected into the casing and no fluid is being produced. All the gas lift valves are

    open.

    II. Gas injection into the casing has begun. Fluid is U-tubed through all the open gas lift valves. No

    formation fluids are being produced.

  • Page | 40

    III. 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.

    IV. The fluid level in the annulus has now been unloaded to just above valve number two.

  • Page | 41

    V. 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.

    VI. 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.

  • Page | 42

    VII. The No. 3 valve has now been uncovered. Valves 2 and 3 are both open and passing gas. The

    bottom valve below the fluid level is also open

    VIII. The No. 2 valve is now closed. All gas is being injected through valve No 3. Valve No 2 is

    closed by a reduction in casing pressure for casing operated valves

  • Page | 43

    GAS LIFT OPTIMIZATION

    12.0 Introduction

    Gas Lift (Continuous gas lift) is one of the most widely used artificial lift mode throughout the world. The gas

    lift system comprises of gas lift well, gas compressor plant, injection gas distribution network and flow line

    network. The performance of total gas lift system would be high only when all the components in the system

    perform well.

    Gas Lift Optimization is a continuous process for maximizing the production, reduction in injection gas and

    thereby reducing costs. Well performance is continuously monitored for identification of under-performing /

    sub-optimal wells with the help of different monitoring tools. Based on the data and model results, suitable

    corrective measures are taken to optimize the wells and continuously maintain the system efficiency. Thus, gas

    lift optimization results in following:

    Enhanced Production

    Effective utilization of resources like injection gas

    More stable well and system operation

    Base for performing wider optimization strategies.

    12.1 IMPORTANT PARAMETERS TO MONITOR

    I) Gas injection pressure (Pso):

    The gas injection pressure, downstream of the surface gas injection choke, roughly gives an idea about the

    depth of the operating valve at the time of recording. Pso below the surface closing pressure of the any valve

    indicates possible malfunction in the system either with the gas lift valve or a possible tubing leak.

    II) Injection Gas rate and Total Gas rate:

    Gas injected into the tubing reduces the density of the fluid column, reduces the FBHP, creates drawdown result

    in well flow. Increase in injection quantity up to a certain level definitely helps in increasing the well production

    but as we well potential is already defined so if more and more gas is injected beyond certain quantity either a

    proportionate increase in production is not obtained or no increase in production or decrease in production is

    obtained. The reason for this is, as gas is being injected into a small conduit gas injection beyond a certain

    quantity would result in frictional losses, the effect of which will overcome the positive result achieved by

    reduction in density that is, the gravitational effect. Moreover, as higher gas injected than the required quantity,

    it results in increased pressure drop in the horizontal flow lines) lines. As in horizontal its just like traffic. So,

    more gas, more mass thus more pressure drop.

  • Page | 44

    Similarly, total gas quantity is to be monitored which will give an idea of injection gas quantity when direct

    measurement of injection gas quantity is not possible.

    The above could be easily explained by the following Gas lift system plot also known as Sensitivity plot.

    Fig. Sensitivity Plot

    III) Tubing Head Pressure (THP):

    Higher tubing head pressure increases the FBHP and would result in loss of production. Suitable remedial

    measures like checking the surface bean and flow line pressure is required.

    IV) Operating Valve Depth:

    The operating gas lift valve can be determined by observing casing pressure when the valve closes. The closing

    pressure analysis will provide desired information, but it should be used with reservation. When knowledge of

    operating valve is needed, a bottom hole pressure traverse or a bottom hole temperature traverse should be run.

    The pressure survey is preferred as it provides information not only to check valve operation, but also to assist

    in redesigning the installation.

    V) Tubing fluid gradient:

    The fluid gradient from the surface to the operating depth will give an indication of the functioning of valve.

    Lighter gradient than the normal indicates more gas injection or vice-versa. Suitable corrective measures can be

    taken.

    12.2 MONITORING TOOLS

    The operating performance of many well changes with time as does the mechanical condition of the gas lift

    valves themselves. Thus, to keep a gas lift installation operating correctly, continuous observation of surface

  • Page | 45

    indications of the well performance is necessary. Such observations include analyzing well tests, casing and

    tubing pressure charts, gas input volumes, flowing pressure traverses, static bottom hole pressures and flowing

    characteristics.

    The following tools are useful to determine the trouble spots in wells:

    1) Two pen pressure recorder: This tool records casing as well as tubing pressure.

    Casing pressure is measured downstream of the injection gas controller or surface choke. Casing

    pressure recording provides an important piece of information from which the gas lift system, the gas-

    lift valve and the time cycle controller performance can be inferred.

    Tubing pressure is measured upstream of choke or other restrictions. Tubing pressure recording gives

    the first indication of the efficiency of the intermittent-lift method or the well capacity to produce

    liquids. The maximum wellhead pressure is a function of several variables, the most important being the

    liquid slug length and its velocity, continuity of liquid slug and any restriction downstream of the

    wellhead.

    2) Well Tests: The importance of obtaining reliable well production tests cannot be overstressed.

    Operational decisions and future expenditures are based on such information. Thus, knowing how much

    fluid is produced and how it is produced is extremely important.

    Well tests should be obtained whenever other observations or changes are made at a problem well and

    should be correlated with information obtained from 2-pen pressure recording, bottom hole pressure

    runs etc.

    3) Closing pressure analysis: Theoretically, the operating gas lift valve can be determined by observing

    casing pressure when the valve closes. But, it may not be always correct as the valve set pressure may

    have changed or the pressure gages cannot be read too closely (10 psi at best),it is apparent that placing

    too much reliance on the calculations is not wise. When knowledge of the operating valve is needed

    bottom hole pressure traverse or bottom hole temperature traverse should be run.

    4) Subsurface pressure survey: A pressure recording instrument is run in the well under flowing

    condition while the well is being tested. This instrument is stopped above and/or below each gas-lift

    valve for a period of time and records the pressure at each valve. From this information exact point of

    operation can be determined as well as the actual flowing bottom hole pressure.

    Flowing pressure survey provides following information:

    The depth of gas injection.

    The flowing bottom hole pressure.

    The P.I. of the well.

    The location of tubing leaks within the range of stops.

  • Page | 46

    A baseline reference of well performance to aid in identification of future problems.

    Provide information for the redesign of valve spacing for maximum production.

    5) Acoustic surveys: The well sounder is an acoustical instrument, which works on echo principal. The

    sound pulse initiated by explosion or implosion travel down the annulus and is reflected by tubing

    collar, gas lift mandrel and the static fluid level. The liquid level in the well reflects most of the sound

    and is recorded as a very large deflection as compared to other reflections.

    Applications of acoustic surveys:

    Casing or tubing fluid level.

    Locate operating valve.

    Estimate static bottom hole pressure.

    Locate the approximate depth of leaks in tubing string

    Locate mandrel depths.

    Limitation:

    The fluid level in the casing does not always indicate the operating valve depth. The casing fluid level

    only indicates the deepest point to, which a well has been unloaded not necessarily the current point of

    operation.

    UNDER-PERFORMING/SUB-OPTIMAL WELLS

    Under-performance of wells can be due to several reasons such as:-

    1) Leaking upper valve/s: In this case many implications are observed such as loss in production as

    operating valve is deprived of desired injection gas. It also poses problems in valve shifting to lower

    valves. It may necessitate re-completion by WOR (onshore).

    Indicators:-The above implication can be identified by Low surface Operating Pressure (Pso/GIP),

    increase in injection gas and total gas quantities/increased GLR, loss in production and drop in system

    pressure.

    Detection:-The above indications can be confirmed by Pressure and Temperature survey.

    2) Multi-porting: In this case many implications are observed such as loss in production as operating

    valve is deprived of desired injection gas. It also poses problems in valve shifting to lower valves. It may

    necessitate re-completion by WOR (onshore).

  • Page | 47

    Indicators:-The above implication can be identified by Low surface Operating Pressure (Pso/GIP),

    increase in injection gas and total gas quantities/increased GLR, loss in production and drop in system

    pressure.

    Detection:-The above indications can be confirmed by Pressure and Temperature survey.

    3) Operating at shallower depth: In this case implications are observed such as loss in production.

    Indicators:-The above implication can be identified by Low surface Operating Pressure (Pso/GIP), drop

    in production.

    Detection:-The above indications can be confirmed by Pressure and Temperature survey.

    4) More injection gas: In this case implications are observed such as loss in production

    not only from the individual well, but also from interconnected/ other wells flowing to the same

    platform and wastage of high pressure gas.

    Indicators:-This anomalies of well is characterized by drop in production and higher THPs.

    Detection:-The above indications can be confirmed by Sensitivity analysis (Gas in-Liquid out curve).

    5) Less injection gas: In this case loss of production is observed as well is not producing to its potential.

    Indicators:-On increasing gas injection there will be increase in production rate.

    Detection:-The above indications can be confirmed by Sensitivity analysis (Gas in-Liquid out curve).

    6) Tubing Leak: In this case many implications are observed such as loss in production as operating valve

    is deprived of desired injection gas. It also poses problems in valve shifting to lower valves. It may

    necessitate re-completion by WOR (onshore).

    Indicators:-The above implication can be identified by Low surface Operating Pressure (Pso/GIP),

    increase in injection gas and total gas quantities/increased GLR, loss in production and drop in system

    pressure.

    Detection:-The above indications can be confirmed by Pressure and Temperature survey.

  • Page | 48

    GAS LIFT OPTIMIZATION CASE STUDY

    13.0 OBJECTIVE

    Optimizations of Gas Lift Wells by performing well performance analysis using PROSPER software.

    13.1 BASIS OF STUDY

    FBHS data and corresponding production rates.

    Reservoir Pressure, PVT and Well Completion data

    13.2 PROCEDURE INCLUDES

    (I) Well Completion Modeling:

    Well Completion means transformation of well from drilling efforts to the production unit.

    Following operations are involved in well completion.

    1. Drilling through the producing zones, coring, logging of zone etc.

    2. Placing the proper production casing and cementing

    3. Perforating

    4. Installing tubing, Packer, Gas Lift valves and Well head assembly.

    5. Well Activation and Stimulation if required.

    (II) PVT properties matching with suitable correlations:

    In PVT Analysis, properties of reservoir fluid are determined. Physical properties of primary

    interest in well performance analysis using PROSPER include:

    1. Solution Gas Oil Ratio (Rs): The gas solubility Rs is defined as the number of standard

    cubic feet of gas which will dissolve in one stock-tank barrel of crude oil at certain

    pressure and temperature.

    2. Bubble-Point Pressure (Pb): The bubble-point pressure pb of a hydrocarbon system is

    defined as the highest pressure at which a bubble of gas is first liberated from the oil.

    3. Formation Volume Factor: The oil formation volume factor, Bo, is defined as the ratio

    of the volume of oil (plus the gas in solution) at the prevailing reservoir temperature and

    pressure to the volume of oil at standard conditions. Bo is always greater than or equal to

    unity.

    4. Oil Viscosity: The viscosity, in general, is defined as the internal resistance of the fluid

    to flow.

    5. Oil API Gravity

    6. Reservoir Temperature

    And the PVT data is matched with suitable correlation.

  • Page | 49

    (III) Well Potential estimation or Inflow Performance (IP) Modeling:

    In IP modeling suitable reservoir model is selected. Reservoir model that can be used are PI

    Entry, Vogels, Composite, Darcy, Fetkovich etc. The Well Potential is estimated with the

    Reservoir pressure-production data using the suitable reservoir model. A well test data is

    provided to be located on the IPR curve. Different Reservoir models require different input

    data. As for example in Vogels we are required to input Reservoir pressure, Temperature,

    Water cut, GOR, Test rate and Bottom hole Pressure.

    (IV) Outflow performance/ vertical lift performance (VLP) modeling:

    This includes selection and matching of vertical multiphase flow correlation like Duns and

    Ros, Beggs and Brills, Hagerdorn Brown, etc. on the basis of actual pressure gradients and

    the corresponding liquid rates, water cut, THP, GOR. Calculated FBHP using various

    correlations is matched with the measured FBHP to select the suitable/matched correlation.

    Further analysis for well performance is carried out using the selected/matched correlation.

    (V) IPR VLP matching:

    After identifying the suitable vertical multiphase flow correlation the inflow-outflow (IPR-

    VLP) matching is carried out with the matched flow correlation so as to continue further well

    performance analysis. Methodology for matching is

    1. Estimate U value. This task is done first since the temperature will affect the PVT used in

    the matching.

    2. Correlation Comparison. This task gives the deviation of calculated data from the

    measured data for various correlations.

    3. Match VLP.

    4. VLP/IPR. This gives the VLP/IPR intersection. If the VLP/IPR intersection shows a

    different rate to the one shown on the test, then the discrepancy lies with the inflow with the

    matched vertical multiphase flow correlation.

    (VI) Sensitivity Analysis:

    This is performed at different Injection depths, Injection Gas rates and THPs considering the

    water cut and GOR. A graph of Liquid Rate V/s Gas Injection Rate is developed

    depending on the various variables (may be 1 to 4 variables) like First node pressure,

    Injection Depth, Injection Rate etc. This helps in determining the optimum conditions for

    injection where we can get optimized production. But the Sensitivity analysis doesnt take

    into account the operability which leads to the requirement of another module which could

    justify the operability at the conditions proposed.

  • Page | 50

    (VII) Quick Look:

    To ascertain the operability of a well at a particular injection depth, injection gas quantity and

    pressure for a desired production rate the QUICKLOOK module of the software is used.

    This module shows graphically the possibility of injection of gas at a given depth for the

    available surface injection pressure and quantities. It calculates pressure traverse in the well

    from two sides i.e. top to bottom and bottom to top. While calculating from top, it

    considers the THP and then according to the flow rate, injection gas quantity and depth

    calculates the FBHP. While calculating from bottom to top, it first calculates FBHP for a

    given flow rate from the IPR and then for a given injection gas rate, point of injection and

    surface injection pressure, it calculates the THP. When the two curves (top to bottom and

    bottom to top) match, then only the well can be said to have the potential to deliver the

    desired liquid from the given depth.

  • Page | 51

    EXAMPLE 1

    OBSERVATIONS:

    Flowing with 24% drawdown.

    Injection Point Second GLV at 1310m.

  • Page | 52

    WELL MODELING AND PERFORMANCE ANALYSIS:

    a) Well Completion Modeling:

    This is done with the given completion details.

    b) PVT Matching:

    The PVT data i.e. solution GOR, bubble point pressure, viscosity, reservoir temperature and oil

    formation volume factor is entered in PVT module of the software which is then matched with

    the various correlations. The matched correlation thus obtained is Lasater Correlation (for Pb,

    Rs and FVF) and Beal Correlation (for viscosity).

    c) Well Potential Estimation or Inflow performance (IP) Modeling:

    The well potential was estimated with the given reservoir pressure production data using

    Vogels IPR model. The maximum potential of the well is estimated to be 253.4 m3/day.

    d) Outflow Performance or Vertical Lift Performance(VLP) modeling:

    FBHS data and corresponding production rates, injection gas rate and injection depth are used

    for selection of suitable vertical multiphase flow correlation. The minimum deviation from the

    measured data is shown by Duns and Ros Modified correlation so that the calculated FBHP

    matches with the measured FBHP. This correlation is used for further analysis of the well.

  • Page | 53

    e) VLP- IPR Matching:

    After identifying the suitable vertical multiphase flow correlation the inflow-outflow (IPR-

    VLP) matching is carried out with the matched flow correlation so as to continue further well

    performance analysis.

  • Page | 54

    f) GL System Analysis:

    The sensitivity analysis envisaged liquid production of 104.7m3/day with reduced THP of

    20 Ksc, injection through GLV 3 at 1699 m depth with 3000m3/day injection gas.

  • Page | 55

    g) QUICK LOOK:

    Simulation through Quick look module in the software confirmed that the injection is

    possible through the above proposed conditions.

    Inference/Conclusions:

    When the THP is reduced to 20Ksc and the gas injection is shifted to the third valve instead of

    the second valve (as gas injection from deeper depth is possible) then on reducing the gas

    injection to the half of the present amount, production can be increased with the gain of 28.7

    m3/day in liquid and of 14.9 m3/day in oil, with saving of 3000m3/day of injection gas.

  • Page | 56

    EXAMPLE-2

    OBSERVATIONS:

    Flowing with 68% drawdown.

    Injection Point Last GLV (Cv) at 2709 m.

    High Water cut 88%

  • Page | 57

    WELL MODELING AND PERFORMANCE ANALYSIS:

    a) Well Completion Modeling:

    This is done with the given completion details.

    b) PVT Matching:

    The PVT data i.e. solution GOR, bubble point pressure, viscosity, reservoir temperature and oil

    formation volume factor is entered in PVT module of the software which is then matched with

    the various correlations. The matched correlation thus obtained is Lasater Correlation (for Pb,

    Rs and FVF) and Beal Correlation (for viscosity).

    c) Well Potential Estimation or Inflow performance (IP) Modeling:

    The well potential is estimated with the given reservoir pressure production data using Vogels

    IPR model. The maximum potential of the well is estimated to be 62.8 m3/day.

    d) Outflow Performance or Vertical Lift Performance (VLP) modeling:

    FBHS data and corresponding production rates, injection gas rate and injection depth is used for

    selection of suitable vertical multiphase flow correlation. The minimum deviation from the

    measured data is shown by Petroleum Expert 3 correlation so that the calculated FBHP matches

    with the measured FBHP. This correlation is used for further analysis of the well.

  • Page | 58

    e) VLP- IPR Matching:

    After identifying the suitable vertical multiphase flow correlation the inflow-outflow (IPR-VLP)

    matching is carried out with the matched flow correlation so as to continue further well

    performance analysis.

  • Page | 59

    f) Sensitivity Analysis:

    There is not much scope for production enhancement from Artificial Lift point of view as

    injection is already being done from the last valve and there is no possibility for going down

    further. And, the sensitivity analysis envisages no substantial increase in liquid production with

    increase in injection gas as the well estimated potential is almost same as the present production.

    Inference/Conclusions:

    There is not much scope for increase in production using Gas Lift as injection is being

    performed from the last valve and the flow potential of well is almost attained. Further increase

    in Gas injection is not going to enhance the production by reasonable amount so production is to

    be continued at the existing conditions.

  • Page | 60

    14.0 BIBLIOGRAPHY

    The Technology of Artificial Lift Methods: Volume 1

    The Technology of Artificial Lift Methods: Volume 2a

    The Technology of Artificial Lift Methods: Volume 2b

    - Kermit E. Brown

    Training Manual for Artificial Lif - IOGPT, ONGC, PANVEL

    Gas Lift Design and Technology - Schlumberger

    Gas Lift Design Guide - Shell

    Production Technology II - Heriot Watt University

    Petroleum Engineering Handbook - Bradley H, Society of Petroleum Engineers,

    Richardson, TX, U.S.A, 1987


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