Report on Gas lift design, operation and troubleshooting

8/9/2019 Report on Gas lift design, operation and troubleshooting

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PROJECT REPORT

OPTIMIZATION, DIAGNOSTICS AND

TROUBLESHOOTING OF GAS LIFT WELLS

SUBMITTED TO:

Ms. Shagun Devshali

AEE (P), Artificial Lift Department

IOGPT, Panvel

(26th

May-25th

June, 2014)

2014

IOGPT

ONGC , Panvel

SUBMITTED BY:

Afzal Akthar

Yatendra Singh

Kshitij Parakh

Ankit Dalal

Ramprakash Chaudhary


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ACKNOWLEDGEMENT

We wish to express our thanks to Dr. V.P.Sharma HOD, Petroleum Engineering Department,

ISMU, Dhanbad, Dr. T.K.Naiyya and Dr. Chandan Guria for helping to arrange such a

wonderful training experience for us.

We wish to sincerely thank Mr. Niladri Sinha, ED-Head, IOGPT, Panvel, Mumbai, Mr. V.V

Manchalwar, GGM(P), HOD-Artificial Lift, Dr. K. R. Rao, DGM (P), In-charge Artificial Lift,

Mr. Om Prakash Pal, DGM(Chem), In-charge Training and Business Development and Mr.

Yogesh Verma, CE(P), In-charge Training for giving us this excellent training opportunity.

We would take this opportunity to acknowledge the support of Ms. Shagun Devshali, AEE(P),

Artificial Lift Group for guiding us through the interactions & suggestions that helped us to

reach the successful completion of our training/project.

We would like to extend heartfelt thanks to the HR department for giving us the opportunity to

have a precious and rewarding experience of training in the Institute Of Oil and Gas Production

Technology, Panvel, Navi Mumbai.

Lastly, we would like to thank the rest of the IOGPT Staff who helped us from time to time

during the training. The whole program really brought us together to appreciate the true value of

teamwork.

Yatendra Singh

Afzal Akhtar

Kshitij Parakh

Ankit Dalal

Ramprakash Chaudhary


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CONTENTS:

Sr. No. Description Page No.

1. Introduction To Artificial Lift 4-10

2. Inflow & Tubing Performance &Multiphase flow 11-25

3. Gas Lift 26-41

4. Troubleshooting 42-51

6. Gas Lift Optimization and Case Studies 52-75

7. Conclusion 76

8. References 77


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1. Introduction

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

and accumulation as oil and gas reserve, 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 a general phenomenon that oil and gas

comes to the surface vigorously by 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 this is what is known as artificial lift. In other words artificial

lift is a supplement to natural energy for lifting well fluid to the surface. Therefore, the flow of

oil from the reservoir to the surface can be fundamentally dichotomized as self-flow period and

artificial lift period.

Artificial lift is a method used to lower the producing bottomhole pressure (BHP) on the

formation to obtain a higher production rate from the well. This can be done with a positive-

displacement downhole pump, such as a beam pump or a progressive cavity pump (PCP), to

lower the flowing pressure at the pump intake. It also can be done with a downhole centrifugal

pump like electrical submersible pump (ESP) system. A lower bottomhole flowing pressure and

higher flow rate can be achieved with gas lift in which the density of the fluid in the tubing is

lowered and expanding gas helps to lift the fluids. Artificial lift can be used to generate flow

from a well in which no flow is occurring or used to increase the flow from a well to produce at a

higher rate. Most oil wells require artificial lift at some point in the life of the field, and many

gas wells use artificial lift for liquid unloading.

To realize the maximum potential from developing any oil or gas field, the most economical

artificial lift method must be selected. The methods historically used to select the lift method for

a particular field vary broadly across the industry. The methods include operator experience;

what methods are available for installations in certain areas of the world; what is working in

adjoining or similar fields; determining what methods will lift at the desired rates and from the

required depths; evaluating lists of advantages and disadvantages; "expert" systems to both

eliminate and select systems; and evaluation of initial costs, operating costs, production

capabilities, etc. with the use of economics as a tool of selection, usually on a present-value

basis.


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General Guidelines (Weatherford)


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2. IPR Performance, Tubing Performance & Multi Phase Flow

2.1. Reservoir deliverability

Reservoir deliverability is defined as the oil or gas production rate achievable from reservoir at a

given bottom-hole pressure. It is a major factor affecting well deliverability. Reservoir

deliverability determines types of completion and artificial lift methods to be used. A thorough

knowledge of reservoir productivity is essential for production engineers.

Reservoir deliverability depends on several factors including the following:

Reservoir pressure

Pay zone thickness and permeability

Reservoir boundary type and distance

Wellbore radius

Reservoir fluid properties

Near-wellbore condition

Reservoir relative permeabilities

Reservoir deliverability can be mathematically modelled on the basis of flow regimes such as

transient flow, steady state flow, and pseudo – steady state flow. An analytical relation between

bottom-hole pressure and production rate can be formulated for a given flow regime. The

relation is called ‘‘inflow performance relationship’’ (IPR). In this chapter, the procedures

used for establishing IPR of different types of reservoirs and well configurations will beaddressed.

2.2. Inflow and Outflow Performance:

2.2.1 Productivity Index :

The productivity index of PI provides a measure of the capability of a reservoir to deliver fluids

to the bottom of a wellbore for production. It defines the relationship between the surface

production rate and the pressure drop across the reservoir, known as the drawdown.

It is defined as:

qPI =

(Pi - Pwf)

Thus, q = PI * (Pi-Pwf)

Well potential, Qmax = PI * Pi


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PI and Pi are constant parameters for a well flowing under steady condition, hence q

depends on Pwf, lower Pwf means higher oil production and vice versa.

Where:

q = stock tank bbls of liquid per day

Pi = shut-in bottom hole pressure (psi)

Pwf = flowing bottom hole pressure (psi)

It is expressed in terms of bpd/psi pressure drawdown. Following are the important

points related to PI :

If reservoir pressure is above the bubble point, PI may be constant over a wide

range of pressure drawdown.

When pressure falls below the bubble pressure, gas separates and occupying a

portion of the pore causing decreasing of PI with increase in pressure drawdown. It changes also with the life of well due changes in reservoir pressure,

composition & properties of reservoir fluids and flow restriction or formation

damage near the well bore.

Thus PI declines with higher well bore pressure drawdown, cumulative reservoir fluid

withdrawals and degree of formation damage.

2.2.2 Inflow Performance Relationship (IPR ) : The inflow performance of a well represents

the ability of that well to give fluids into the wellbore for a given drawdown. The

productivity of a well depends on the type of reservoir and the drive mechanisms along

with reservoir pressure, permeability, etc. The Inflow Performance curve (a Cartesian

plot of bottom-hole flowing pressure versus surface flow rate) is one of the diagnostic

tools used by Petroleum engineers to evaluate the performance (maximum potential) of

a flowing well. The equation that describes this curve is the Inflow Performance

Relationship (IPR). This equation can be determined both theoretically and empirically.

In day to day variations IPR remains constant.

A publication by Vogel in l968 offered

an extra ordinary solution in

determining the Inflow Perform-anceCurve for a solution gas drive reservoir

for flow below the bubble point or gas

cap drive reservoir or any other types

of reservoir having reservoir pressure

below bubble point pressure

Fig.2.1 : Vogel IPR behaviour


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While deriving the equation, Vogel assumed that flow efficiency is 1.00 which implies

that there was no damage or improvement in the well. Standing extended the Vogel's

equation by proposing the comparison chart where he has indicated flow efficiency

either more or less than one. Fetkovich proposed and IPR Equation for Oil well having

reservoir pressure below bubble point pressure which also behaves like gas well so the

IPR equation being used for gas wells will also be applicable for oil wells.

2.2.3 Outflow Performance: After knowing the well potential, we have to design the outflow

system in such a way so that to exploit the inflow. Outflow pressure or tubing intake

pressure depends on the following

parameters:-

Tubing diameter

Depth

Water cut

Gas Liquid Ratio

QL(liquid flow rate)

THP(tubing head pressure)

Tubing intake pressure is defined as the pressure required at the bottom of the tubing to

lift a particular amount of liquid through a specific tubing size, from a specific depth,

with a definite water cut & GLR against a specific tubing head pressure.

2.3. Multi-phase flow: The inflow performance characteristics are governed by the type of

flow – single phase or multi-phase and various correlations have been introduced.

Multiphase flow can occur in both regimes – horizontal as well as vertical and take the

forms as indicated in Fig. 2.4

Fig.2.2 : Variations in Inflow performance curves as predicted by various authors

Fig.2.3 : Outflow performance curve


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Diagrammatic representations and brief description of each of the types of multiphase

flows is given below.

Diagrammatic representations and brief description of each of the types of multiphase

flows is given below.

Horizontal flow :

Fig.2.4 : Different types of Multiphase flows in an oil well


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Vertical flow :

Fig. 2.8 : Variation of flows with gas and liquid flow parameters and application areas for

correlations

2.3.1. Multiphase Flow Concepts in Vertical and Inclined Wells

It is clear that the behaviour of gas in tubing strings is markedly different. It would therefore be

expected that the flow of a gas-liquid mixture would be more complex than for single phase

flow. Each of the phases, both gaseous and liquid, have individual properties such as density and

viscosity which will be a function of pressure and temperature and hence position in the well.

Gas-Liquid Mixtures

In the production of a reservoir containing oil and gas in solution, it is preferable to maintain the

flowing bottom hole pressure above the bubble point so that single phase oil flows through the

reservoir pore space.


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Consider such a case where oil flowing from the reservoir enters the production tubing. The

flow of oil up the tubing and the associated pressure profile is illustrated in Figure. The oil may

enter the tubing at a flowing pressure above the bubble point where no separate gas phase exists.

The changing nature of the flow up the tubing can be considered in various stages from the base

of the tubing:

(a) single phase liquid will occur in the tubing assuming the pressure is below the bubble point

pressure. The pressure gradient is primarily influenced by the density of the liquid phase and is

thus dominated by the hydrostatic head component of the pressure loss. Liquid expansion may

contribute to a very slight reduction in liquid density and thence the hydrostatic gradient.

(b) At the bubble point, the first gas is evolved which will:

(i) Lower the average density of the fluids in the tubing

(ii) Increase the in-situ velocity

The gas is present in the form of discrete bubbles dispersed within the continuous oil phase. The

flow regime is termed “bubble flow” and the pressure gradient will decline provided the decrease

in hydrostatic head pressure loss exceeds the increase in frictional pressure loss.

(c) With continued upwards flow, the pressure on the fluid declines. The decline in pressure

on the fluid will cause:

(i) Expansion of the liquid phase

(ii) Evolution of additional gas components

(iii) Expansion of the existing gas phase.

This section of the tubing would demonstrate a continuously declining pressure gradient

provided the decrease in the hydrostatic component exceeds the increase in frictional gradient.

The above mechanisms will continue to occur continuously as flow occurs up the tubing.

(d) As flow continues higher up the tubing, the number and size of gas bubbles will increase

until such a point that the fraction of the tubing volume occupied by gas is so large that it leads to

bubble coalescence. The coalescence of bubbles will yield a “slug flow” regime characterised by

the upward rise, due to buoyancy, of slugs of gas segregated by continuous liquid columns. Theupwards movement of the slugs will act as a major mechanism to lift oil to surface.

(e) Often, as velocity continues to increase in the slug flow regime, it may be possible that a

froth type transitional flow occurs where both the oil and gas phases are mutually dispersed, ie,

neither is continuous.


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Important parameters which will influence the properties of a multiphase flow system are

slippage and holdup.

1. Slippage

If a gas-liquid mixture flows up a tubing string, the effects of buoyancy on each of the phaseswill not be equal. The lighter of the phases, primarily gas, will rise upwards at an incrementally

higher rate compared to the oil due to the effects of buoyancy.

The slip velocity, Vs, is defined as the difference in velocities of the two phases, ie, for a gas-oil

system.

2. Holdup

Holdup is a term used to define the volumetric ratio between two phases which occupy aspecified volume or length of pipe.

The liquid holdup for a gas-liquid mixture flowing in a pipe is referred to as HL:

HL therefore has a value between zero and one.

Similarly, the gas holdup Hg is defined as

Obviously

3. Fluid Velocity

A difficulty arises as to how to define the velocity of a specific phase. There are two options:

(a) The first option is to define velocity based upon the total cross-sectional area of the pipe

despite the fact that each phase will occupy a fraction of the area. The velocity in this case is

termed the superficial velocity

For gas:


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Where, A = cross-sectional area of the pipe

and for liquid:

(b) A more accurate value for the velocity of each phase is to correct for the holdup of each

phase.

The actual gas velocity:

2.3.3 Correlations for Multi-phase flow : The vertical performance characteristics have been

studied by various authors and correlations are listed below :

Horizontal flow Vertical/ Inclined flow

Lockhart and Martinelli.

Baker.

Andrews et al.

Dukler et al.

Eaton et al.

Beggs & Brill.

Duns and Ros.

Orkiszewski.

Hagedorn and Brown.

Winkler and Smith.

Beggs and Brill.

Govier and Aziz

Flanigan

Beggs and Brill

A typical graphical representation is shown in Fig. 1,.6.

Fig.2.5 : Typical graphical representation of IPR correlations applicable in Multiphase flows


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Many investigators have conducted research into multiphase flow in tubing. Most of the

investigative approaches have made basic assumptions which can be used to classify the

correlations derived as follows:

(1) Methods which do not consider:

(a) slippage between phases,

(b) the use of flow regime or pattern.

(2) Methods which consider slippage between the phases but not flow regimes.

(3) Methods which consider both flow regime and slippage.

2.4. Gradient Curves

Gilbert was the first to introduce the

concept of a pressure gradient curve. The

gradient curve provides a plot of pressure

variations with depth in a tubing string for

a range of specified flow conditions and

as such provides a simplified but less

accurate approach to predicting tubing

performance using a multiphase flow

correlation.

Gilbert obtained data in the form of

pressure traverses upon a range of oil

production wells and the data was plotted

with respect to the following parameters:

Fig.2.8. Depth-Press. gradient curve for 2.875” tubing

•GOR or GLR

•Tubing diameter

•Liquid or oil production rate

His data was restricted to 1.66", 1.9", 23/8", 27/8" and 31/2"; for flow-rates of 50, 100, 200, 400

and 600 BPD. Therefore, for constant values of the above parameters, a range of curves were

obtained by plotting the data, each curve reflecting different tubing head pressure, as shown in

Figure below. The implication of this was that a specific gradient curve would be required for

each tubing head pressure to be considered


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However, by shifting the curves downwards, he found that, for a constant GLR, flow-rate and

tubing size, the curves overlapped, as depicted in Figure below. Then, single curve could be

utilised to represent flow in the tubing under assumed conditions. This curve could be

constructed to pass through the point of zero pressure at surface. The impact of moving the

individual curves down until they overlapped was in effect to extend the depth of the well by a

length which, if added to the top of the tubing, would dissipate the tubing head pressure and

result in zero pressure at the top.

Gilbert was then able to collect all the curves for a constant tubing size and flow-rate together on

the one graph, resulting in a series of gradient curves which would accommodate a variety

of GLRs. He was then able to prepare a series of gradient curves which apply for a constant

liquid production rate and tubing size.

2.5. Effect of Gas liquid Ratio on IPR and VLP curves : Presence of Gas in liquid increases the

Gas liquid ratios (GLR). GLR affects both inflow and outflow performance.

The general shape of the tubing

performance curves reflect the

increasing intake pressure as the liquid

rate increases for a constant GLR due

to the increased pressure drop as

mixture velocity increases.

2.6. Operation of Oil & Gas wells – IPR/VLP interactions: At a given time in the life of a

flowing well, the gas to liquid ratio (GLR) is dependent on the flow conditions in the

reservoir rock as expressed by relative permeability and gas saturation.

Fig.2.6 : Effect of GLR on IPR correlations in Horizontal & Vertical flow

Fig.2.7: Effect of GLR on Tubing Intake curve


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To control the flow rate from the well, the only practical parameter at our disposal (once

the tubing has been installed) is the tubing head pressure. For given tubing size, tubing

depth and gas liquid ratio, the tubing intake pressure is a function of liquid rate and

tubing head pressure, as illustrated by VLP (Vertical Lift Performance) curves. The

pressure required at the intake of the tubing (bottom of tubing) to be able to flow thefluid mixture to the surface is defined as the Tubing Intake Pressure (Pin).

As the tubing head pressure (Pt) is reduced to zero, the tubing intake pressure for a givenliquid rate decreases causing an increase of the drawdown pressure between the wellbore

and the reservoir and a corresponding increase of the flow rate from the reservoir. The

point of intersection of the VLP curve, corresponding to a given tubing head pressure and

the IPR curve for the formation, represents an equilibrium condition and the well will flow.

An increase in tubing head pressure will cause an increase in the VLP pressure and a

corresponding decrease in flow rate. Further decrease in tubing head pressure, say to zero,

will result in achieving the maximum production rate from the well. Once the tubing

pressure is reduced to zero and maximum self-flow rate is achieved, it is not possible to

produce fluid from the well at a higher rate without modifying the installation orintroducing some form of artificial lift.

Fig.2.8 : IPR-TIC interactions in Self-flowing wells and Wells requiring Artificial Lift


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3. GAS LIFT

3.1 Introduction

Gas lift technology increases oil production rate by injection of compressed gas into the lower

section of tubing through the casing – tubing annulus and an orifice installed in the tubing string.Upon entering the tubing, the compressed gas affects liquid flow in two ways: (a) the energy of

expansion propels (pushes) the oil to the surface and

(b) the gas aerates the oil so that the effective density of the fluid is less and, thus, easier to get to

the surface.

There are four categories of wells in which a gas lift can be considered:

1. High productivity index (PI), high bottom-hole pressure wells

2. High PI, low bottom-hole pressure wells

3. Low PI, high bottom-hole pressure wells

4. Low PI, low bottom-hole pressure wells

Fig 3.1


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Wells having a PI of 0.50 or less are classified as low productivity wells. Wells having a PI

greater than 0.50 are classified as high productivity wells. High bottom-hole pressures will

support a fluid column equal to 70% of the well depth. Low bottom-hole pressures will support a

fluid column less than 40% of the well depth. Gas lift technology has been widely used in the oil

fields that produce sandy and gassy oils. Crooked/deviated holes present no problem. Well depth

is not a limitation. It is also applicable to offshore operations. Lifting costs for a large number of

wells are generally very low. However, it requires lift gas within or near the oil fields. It is

usually not efficient in lifting small fields with a small number of wells if gas compression

equipment is required. Gas lift advancements in pressure control and automation systems have

enabled the optimization of individual wells and gas lift systems.

Early application of gas lift adopted the simple “U”-tube or pin-hole principle in producing oil

from shallow wells. Then with the advent of gas lift valves, the gas lift application could be

extended to deeper wells.

Gas lift system is now broadly classified into 2 categories depending upon the duration of lift gas

being injected into the tubing:

1.

Continuous gas lift

2. Intermittent gas lift.

SURFACE GAS NETWORK

It will have become apparent from the above and the following sections that the performance of

the gas lift system will depend on the pressure and flow capacity of the lift gas available at thewell head. The surface piping network should thus be designed to:(i) have minimal (< 100psi) pressure loss between the compressor and the most distant wellhead,

(ii) prevent one well from interfering with a second well by having sufficient pipe volume to

dampen pressure surges and

(iii) provide individual gas measurement and flow control for each well Large diameter pipingencourages all the above - typically 4 in OD piping is used for the main backbone of the system

with individual 2 in OD flow lines installed to each well. A ring main system is an option for

large systems employing more than one compressor - the gas lift manifold for a group of wellsand the compressors being attached to the gas supply ring main as appropriate.

SUB-SURFACE GAS NETWORK

3.2 Gas Lift SystemA complete gas lift system consists of a gas compression station, a gas injection manifold with

injection chokes and time cycle surface controllers, a tubing string with installations

of unloading valves and operating valve, and a down-hole chamber.


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Fig 3.2

Figure 1 depicts a configuration of a gas-lifted well with installations of unloading valves and

operating valve on the tubing string. There are four principal advantages to be gained by the use

of multiple valves in a well:

1. Deeper gas injection depths can be achieved by using valves for wells with fixed surface

injection pressures.

2. Variation in the well’s productivity can be obtained by selectively injecting gas valves set at

depths ‘‘higher’’ or ‘‘lower’’ in the tubing string.

3. Gas volumes injected into the well can be ‘‘metered’’ into the well by the valves.

4. Intermittent gas injection at progressively deeper set valves can be carried out to ‘‘kick off’’ a

well to either continuous or intermittent flow.

3.2.1 Continuous Gas Lift

A continuous gas lift operation is a steady-state flow of the aerated fluidfrom the bottom (or near bottom) of the well to the surface. Intermittent gas

lift operation is characterized

by a start-and-stop flow from the bottom (or near bottom) of the well to the

surface. This is unsteady state flow. In continuous gas lift, a small volume of

high-pressure gas is introduced into the tubing to aerate or lighten the fluid

column. This allows the flowing bottom-hole pressure with the aid of the

expanding injection gas to deliver liquid to the surface. To accomplish this

efficiently, it is desirable to design a system that will permit injection

through a single valve at the greatest depth possible with the available

injection pressure.

Continuous gas lift method is used in wells with a high PI (0.5 stb/day/psi)

and a reasonably high reservoir pressure relative to well depth. Intermittent

gas lift method is suitable to wells with (1) high PI and low reservoir

pressure or (2) low PI and low reservoir pressure.

The type of gas lift operation used, continuous or intermittent, is also governed by the volume of

fluids to be produced, the available lift gas as to both volume and pressure, and the well

reservoir’s conditions such as the case when the high instantaneous BHP drawdown

Encountered with intermittent flow would cause excessive sand production, or coning, and/or gas

into the wellbore.

3.2.2 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

gas expands and in this process it displaces the oil on to the surface. So, the assistance of flowing


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bottom hole pressure is not required when the gas displaces the 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 buildup the level of liquid which depends upon he reservoir pressure and PI ofthe well. Then again next gas injection cycle is initiated to lift oil. In this manner, as the name

suggests, intermittent gas lift works on the principle of intermittent injection of gas in a regular

cycle. It is to be noted that in the cycle the injection time should be as short as possible. A large

volume of gas should be injected quickly underneath the oil slug as a result the oil slug above the

point of gas injection will acquire the terminal velocity( maximum velocity) within shortest possible

time, which would minimize the liquid fallback in the tubing string. Less fluid fallback 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, bigger port size gas lift valves are required. That is why gas liftvalves having port sizes 1/2”, 7/16”, 3/8”, or 5/16” are preferred. In intermittent gas lift application,

two different injection flow rates are considered. One is the normal gas injection rate( called day

rate) required for a well on per day basis and other is the instantaneous gas injection rate, commonly

called per minute demand rate of gas injection. It helps to minimize the injection gas breakthrough

the oil slug and arrests liquid fall back to a desired extent.

Similar to 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 slugcrosses the valve during its upward travel. If the upper valve opens as the slug crosses the valve, the

additional gas further arrests the liquid fall back and thus results in more oil production.

In the light of above discussion it can be comprehended that continuous gas lift system should be

employed when well 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.


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Figure below illustrates a simplified flow diagram of a closed rotary gas lift system for a single

well in an intermittent gas lift operation. The time cycle surface controller regulates the start-

and-stop injection of lift gas to the well. For proper selection, installation, and operations of gas

lift systems, the operator must know the equipment and the fundamentals of gas lift technology.

3.3 Gas Lift Advantages and Limitations

a) Advantages

Fig 3.3: Intermittent gas lift

Fig 3.4: Gas lift Loop


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b) Limitations

3.4 Type of installation- Open, Semi-closed, Closed

1. Open Installation

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

the tubing shoe.

Limitation of open installation:

U tubing through the tubing will occur, especially when reservoir pressure is very low

and the deepest gas lift valve is very near to the perforation.

Fluid level will rise in the annulus in case of compressor upsets and during idle period of

intermittent gas lift. In the absence of a packer, the same liquid is to be U-tubed again

through the gas lift valve before the normal gas injection is resumed.

Production casing will come in contact with the well fluid.

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.

2. Semi-closed Installation

When there is only packer in the tubing annulus and no standing valve.

It is standard practice for intermittent gas lift wells and continuous gas lift wells.


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3. Closed Installation

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

b. When there is a standing or non-return valve in the tubing at the tubing shoe.

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 lowered with the

wire line on the A-nipple or D-nipple. It is also likely that with the production through 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 near to the standing valve. The turbulence created due to gas injection at that place

inhibits the build-up of sand on the standing valve. It is standard practice for continuous gaslift wells.

3.5 Gas Lift Valve

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

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

the gas lift valves open, which allows injection gas to enter the production string to lift fluid

to the surface.

In the course of improvement of gas lift system several types of gas lift valves were

developed. Probably the differential type of valve was a very early development. Now a days

bellow operated nitrogen pressure loaded gas lift valves is most common type of gas lift

valves being used by oil industries.

3.5.1 Component of Gas Lift Valve

1) Body

2) Loading element

3) Responsive element

4) Transmission element

5)

Metering element

1) Body:

The body is the outer cover of the gas lift valve and is generally of 1 ½” O.D. or 1” O.D.

Some pencil type of gas lift valve is also there, which has an O.D. of 5/8” .The body of

the gas lift valve is generally of S.S.-304 or 316.The conventional type of gas lift valve is


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threaded and is screwed with the mandrel. In case of wire line type, the “O” ring or “V”

seal rings are provided on the body for isolating the required portion of the gas lift valve

from the adjacent areas and are housed into the side pocket using wire line operated kick

off tool. The length of gas lift valve i.e. its body varies usually from merely a foot to

around three feet.

2) Loading Element:

The loading element can be spring, nitrogen gas or a combination of both. The spring of gas

charge provides a required balancing force so that the valve can be operated at a desired

pressure. it means that above this pressure the valves opens and below that it gets closed

automatically.

Spring provides the required compression force, so when spring loaded valve is required to

open, the external pressure should be sufficient to overcome the compression force of the

spring. In case of gas charged valve i.e. nitrogen-loaded valve, thee external pressure isrequired to overcome force due to nitrogen pressure to make the valve open for gas injection.

3) Responsive Element:

Responsive element can be metal bellows or piston. Bellows type of gas lift valve is most

prevalent. The bellow is made of very thin metal tube preferably of 3-ply monel metal. Its

thickness is approximately 150th

of an inch. This is hydraulically formed into a series of

convolutions. This form makes the tube very flexible in the axial direction and can be

compared with a similar rubber bellows.

The bellow is regarded as the heart of the gas lift valve. If bellows are properly strengthened,the gas lift valves become very strong. If bellows is of high quality, it is reflected in the

quality of gas lift valve.

4) Transmission Element:

The transmission element is generally a metal rod, whose one end is fitted with the lowermost

portion of the bellow and the other end is rigidly attached with the stem tip.

5) Metering Element:

It refers to the opening or port of the gas lift valve, through which injection gas passes intothe well fluid in the production tubing.


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Fig 3.5: Casing Pressure Operated Valve

Fig 3.7: Pilot Valve

3.5.2 Different Types of Gas Lift Valve

1.Casing Pressure Operated Gas Lift Valve:

As the name implies the Casing pressure

operated gas lift valves operate predominantlywith the pressure of casing. So, its largersurface of opening and closing mechanism i.e.,

the bellows area is directly exposed to casing

and not the tubing pressure. That is, the casing pressure acts on the bellows and tubing pressure

on the downstream side of the seat. If it is

required to reduce the influence of the tubing pressure, it is required to reduce the port size to

as minimum as possible.

2) Fluid Operated Gas Lift Valves (or Tubing Pressure Operated Gas Lift Valve)

As the name implies the fluid operated gas lift valves

operate predominantly with the pressure of tubing.

So, its larger surface of opening and closing

mechanism i.e., the bellows area is directly

exposed to tubing and not the casing pressure. That

is, the tubing pressure acts on the bellows and casing

pressure on the downstream side of the seat. Due to

this, the force balance equations as described for

casing pressure operated valves are reversed. If it is

required to reduce the influence of the casing

pressure, it is required to reduce the port size to as

minimum as possible.

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 thistype 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

Fig 3.6: Tubing Pressure Operated Valve


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Fig 3.8: Gas Lift Valve Schematics

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 valvesection. 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. The

same force balance equation is applied to the pilot section only for the opening and closing of the

valve, since it is the main functional area.

3.6. GAS LIFT VALVE MECHANICS

The mode of action of the upper gas lift

valves, in which the top valves are designedto open and close to allow the fluid in the

casing/tubing annulus to be unloaded so that

deep gas injection can be achieved, wasdescribed in the previous section. The

operating valve is different, being designed

to allow for a continuous flow of gas. The

upper gas lift valves have ports sized to pass

only the required volume of gas, limiting therate at which the unloading takes place. A

larger port is often installed in the operatingvalve so that gas injection can be increased,

if dictated by future well or reservoir

conditions. Dummy valves are installed in

the “Bracketing Envelope” where “live” valves arecurrently not required.

3.6.1. Casing or Inflow Pressure Operated (IPO) Valves

A casing pressure operated valve includes:(i) dome or top section of the valve is charged, via the plug, with nitrogen to the required

pressure (Pdome).

(ii) nitrogen charge acts on the bellows; exerting a force pushing the ball against the choke or port and halting the flow of lift gas into the tubing.

(iii) spring prevents damage to the bellows due to excessive collapse when exposed to forces

much greater than those generated by the nitrogen charge. Such excessive collapse would result


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Fig 3.9: Dome Pressure Calibration

in the bellows losing their elastic response to pressure changes. If this occurs the gas lift valve

needs to be changed.

(iv) choke or port prevents excessive (gas) flow rates.(v) check valve prevents formation fluids flowing from the tubing into the annulus.

Simple, mechanical considerations allow us to derive the following equations:The Closing Force, Fc, tending to seat the ball is given by:

FC = Pdome * Abellows

Where Ax refers to the Area of component x and Py refers to the Pressure at point y.

The Opening Force (FO) is made up of two components: FO1, and FO2, where

FO1 = Ptubing * AportFO2 = Pcasing * (Abellows - Aport)

and FO = FO1 + FO2

The Opening and Closing forces are equal just before the valve opens.

3.6.2 Dome Pressure CalibrationThe dome is charged with nitrogen and the gas lift valve installed in a Test Rack placed

in a temperature controlled enclosure set at 60ºF The simulated Ptubing

is at atmospheric pressure (or O psig). A gradually increasing gas pressure is appliedto simulate Pcasing. The valve opening pressure (Popening) is recorded as the pressure

when gas begins to flow.

Application of the above force balance equation gives:Popening = Pdome/(1 - Aport/Abellows)


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This can be used to confirm that the manufacturing of the gas lift valve is on specification and

that the dome nitrogen pressure, Pdome, has been set correctly. The valve closing pressure

(Pclosing) may be measured by pressurising both the injection and tubing sides so that the valveis fully open. The pressure on the tubing side is reduced and valve closure recognised as the

pressure at which Pcasing no longer decreases in line with Ptubing. The design of the valve

dictates that Pclosing will be lower than Popening, since starting from the open valve situationmeans that the injection pressure acts on the complete bellows area.

The valve spread is defined as the difference between the valve test rack opening and closing

pressures i.e. (Popening - Pclosing). It is a measure of the difference between the effective areaof the bellows and the port.

3.7 GAS LIFT DESIGN

3.7.1.

OBJECTIVES

The gas lift system designed for installation in a specific well should meet the following

objectives:

(i) Maximise the (net) value of oil produced . This normally implies that the:(a) operating valve, through which the gas will be continuously injected, should be situated as

deep as possible and

(b) gas injection rate should equal the economic limit at which the marginal value of the extra oil produced equals the marginal cost of providing this extra gas. Further optimisation is required

when more than one well is being produced and there is insufficient lift gas available to meet this

economic criteria in all wells

(ii) Maximise design flexibi li ty. The gas lift design should be capable of coping with the

expected changes in the well producing conditions during its lifetime, as well as the “unplanned”

uncertainties in reservoir properties and performance. These changes normally involvedeterioration, from a well productivity point of view, due to decreases in the Reservoir Pressure

and Well productivity Index and increases in the Water Cut

Fig: 3.10


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(iii) Minimise well in tervention . This is particularly important in subsea or other wells where

wireline access is difficult or impossible. Well completions with a “dry” tree and deviations less

than 60o allow the option to replace the gas lift valve by a relatively quick, wireline operation.The operating parameters (or valve performance) of the gas lift valves installed in the side pocket

mandrels can thus be adjusted at any time in the well’s life i.e. the tubing production conditions

can be adapted to take into account changes in the reservoir conditions and the well performance.These operating parameters include the:(a) tubing or casing pressures (depending on the type of side pocket mandrel installed) at which

gas flow through the gas lift valve starts and stops and(b) port (or choke) size, which controls the maximum volume of gas that can be injected as well as the

associated pressure drop due to the gas flow through the valve.

This ability to modify the valve performance when required leads to great flexibility in the choice of gas

lift operating parameters, despite the fact that the installation depth of the gas lift valves is fixed. {The(side pocket) gas lift mandrels within which the valve is placed are permanent fixtures in the completionstring, having been installed during the well completion process}.

The flexibility of a particular gas lift design is further increased by installing one or two extra gas liftvalves as possible both above and below the chosen depth of the operating valve. They should be placedas close together as possible, but sufficiently far apart that they do not interfere with each other’soperation (typically 150 m vertical depth apart). This is known as the “bracketing envelope”. Theinclusion of the bracketing envelope mandrels will allow the operating valve to be moved to a slightlyhigher or lower depth, as dictated by the well & reservoir performance changes during the well life. This

procedure maximizes the (liquid) production by, for a given gas injection rate, allowing the well to belifted from as deep as possible commensurate with the current producing conditions.

(i v) Stable Well Operation. Well “heading”, in which the Tubing Head or Casing Head Pressure Showsregular changes should be avoided. Stable operation - with a constant value for the casing and tubing head

pressures - should be aimed for. This is because stable well operation will always produce more oil and,

often, require less lift gas than unstable gas lifted well operation. Casing Head pressure excursions of aslittle as 5 psi can indicate valve multiporting {the gas injection point changing from one valve to anotheror a second valve cycling (opening and closing) in addition to the operating valve}.

3.7.2 Gas lift design parameters

The gas lift design process has to answer the following questions to meet the above objectives:(i) How many unloading valves are required and at what depths should they be placed?

(ii) What are the required settings for the Unloading Valves?

(iii) What is the depth of the operating valve where the gas is continuously injected?

(iv) What is the gas injection (or casing head) pressure?(v) How much lift gas should be injected?

(vi) What is the tubing head pressure for the target flow rate? This is translated into practice

by ensuring that the gas lift valve spacing and pressure setting are such that:(i) the operating valve should have adequate flow capacity and be placed as deep as possible,

(ii) the available lift gas pressure must be able to displace the fluid in the casing to the operating

valve depth.


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3.7.3. Gas-lift DesigningDesigning a gas lift depends on the following important parameters:

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

SBHP

FBHP & corresponding flow rate2) PVT properties

Bubble point pressure

Formation volume factor

Reservoir temperature

3) Depth of perforation interval.

4) Tubing and casing size.5) Available injection pressure

6) Water cut

7) Tubing Head Pressure

8)

Type of reservoir drive mechanism.9) Inclination profile of the well.

10) Specific gravity of kill fluid.

Depth is plotted against pressure and the pressure traverse of the fluids starts from the

flowing BHP at the bottom of the well and moves all the way to the surface. Assuming anaverage flowing gradient beneath the point of gas injection and an average flowing gradient

above the point of gas injection, we start with the tubing pressure and calculate the flowing

BHP as follows:

Pwh + Gta * L + Gfb * (D-L) = Pwf

Where:

Pwh = wellhead pressure

Gta = average flowing gradient above the point of gas injection

L = depth to point of gas injection

Gfb = average flowing gradient below the point of gas injection

D = total depth of well

Pwh = flowing BHP

This is the basis for gas lift design. Continuous flow creates the necessary flowing BHP to allow

the well to produce at a particular flow rate. Gas is injected at such a point that this pressure may

be obtained. Factors such as available pressure, available gas volume, flow configuration sizes

and flowing tubing pressure at the surface will influence production.


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The following procedure serves as a guide for designing a gas li ft installation. All information’s

are plotted on a sheet of rectangular co-ordinate paper:-

1. Depth is plotted on the ordinate with zero depth at top and maximum depth at bottom.

2. Pressure is plotted on the abscissa with pressure increasing from zero at origin to a

maximum.3. the static BHP is plotted at the correct depth(bottom of the well)

4. The necessary draw down in pressure is determined to produce the desired flow rate.

5. The draw down is subtracted from the static BHP to obtain the flowing BHP. This pressure is noted at depth.

6. From the point of static BHP the static gradient line is extended up the hole until it

intersects the depth. this will the static liquid level at the well for Pwh=0 and in the eventthe well is not loaded can be used as a point of location for the first GLV.

7. From the point of flowing BHO the flowing pressure traverse below the point of injection

is plotted.

8. High flow rates of water and low gas liquid ratios this line may be equal.

9.

the surface operating pressure (i.e. pressure that can be maintained at the well site tooperate the gas lift well)is selected

10. the point where the operating casing pressure intersects the flowing gradient line as the point of balance is marked

11. 100 psi from the pressure in the casing at this point is subtracted and the point of

injection is obtained

12. The flowing well head pressure (Pwh) is approximated and the value at the zero depth ismarked.

13. The flowing well head pressure (Pwh) is connected to the point of gas injection by means

of computer calculations. This curve will in turn gives the total GLR required to producethe well.

14. Solution gas is subtracted from the total gas volume, the required injection GLR is

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

The determination of this point of gas injection is correct for a particular well at a particular time

in its life. Depending upon the type of drive mechanism by which the well produces, its

characteristics may change considerably in one or two years.

3.7.4 Gaslift Valve Spacing CriteriaThe chosen installation depths of valves will be based on the following criteria:

(i) Specify a minimum number of gas lift valves. This will not only reduce the cost but also the

number of potential leak paths.

(ii) Gas lift valves to be installed sufficiently far apart that they do not interfere with each other’soperation (150m suggested minimum spacing).

(iii) (continuous) Gas injection through the operating valve occurs as deep as possible based on

current producing conditions.


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4.0 Gas-Lift Troubleshooting

Fig. 4.1 - Gas Lift System

4.1 PROBLEMS ASSOCIATED WITH GAS LIFT

Gas-lift problems are usually associated with three areas: inlet, outlet, and downhole.

Inlet problems may be the input choke sized too large or too small, fluctuating line

pressure, plugged choke, etc.

Outlet problems could be high backpressure because of a flowline choke, a closed or

partially closed wing or master valve, or a plugged flowline.

Downhole problems could include a cutout valve, restrictions in the tubing string, or

sand-covered perforations


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A) INLET PROBLEMS

Choke size is too large : Check for casing pressure at or above design operating pressure.

This can cause reopening of upper-pressure valves and/or excessive gas usage. Approximate

gas usages for various flow rates are included in Fig. 2.

Fig 4.2 - Continuous Flow Gas Lift Operation

Choke sized too small: Check for reduced fluid production as a result of insufficient gas

injection. This condition can sometimes prevent the well from unloading fully. The design

gas:liquid ratio can often give an indication of the choke size to use as a starting point.

Low casing pressure: This condition can occur because the choke is sized too small, it is

plugged, or it is frozen up. Choke freezing can often be eliminated by continuous injection of

methanol in the lift gas. A check of injected-gas volume will separate this case from low

casing pressure based on a hole in the tubing or cutout valve. Verify the gauge readings to be

sure the problem is real.

High casing pressure: This condition can occur because the choke is too large. Check for

excessive gas usage from the reopening of upper pressure valves. If high casing pressure is

accompanied by low injectiongas volumes, the operating valve may be partially plugged or

high tubing pressure may be reducing the differential between the tubing and casing. If this is

the case, remove the flowline choke or restriction. High casing pressure accompanying low

injection-gas volumes may also be caused by higher-than-anticipated temperatures raising the

set pressures of pressure operated valves.


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Inaccurate gauges: Inaccurate gauges can cause false indications of high or low casing

pressures. Always verify the wellhead casing and tubing pressures with a calibrated gauge.

Low gas volume: Check to ensure that the gas-lift line valve is fully open and that the casing

choke is not too small, frozen, or plugged. Check to see if the available operating pressure is

in the range required to open the valves. Be sure that the gas volume is being delivered to the

well. Nearby wells, especially intermittent wells, may be robbing the system. Sometimes a

higher-than-anticipated producing rate and the resulting higher temperature will cause the

valve set pressure to increase, thereby restricting the gas input.

Excessive gas volume: This condition can be caused by the casing choke sized too large or

excessive casing pressure. Check to see if the casing pressure is above the design pressure,

causing upper pressure valves to be opened. A tubing leak or cutout valve can also cause this

symptom, but they will generally also cause a low casing pressure.

Intermitter problems: Intermitter cycle time should be set to obtain the maximum fluid

volume with a minimum number of cycles. Injection duration should then be adjusted to

minimize tail gas. Avoid choking an intermitter unless absolutely necessary. For small gas-

lift systems in which opening the intermitter drastically reduces the system pressure, it may

be possible to reduce pressure fluctuation by placing a small choke in parallel dead wells as

volume chambers. Check to make sure that the intermitter has not stopped, whether it is a

manual-wind or battery-operated model. Wells intermitting more than 200 BFPD should be

evaluated for constant flow application. Less than one barrel per cycle is probably an

indication that the well is being cycled too rapidly.

B) OUTLET PROBLEMS

Valve restrictions: Check to ensure that all valves at the tree and header are fully open or

that an undersized valve is not in the line (1-in. valve in a 2-in. flowline). Other restrictions

may result from a smashed or crimped flowline. Check locations where the line crosses a

road, which is where this situation is likely to occur.

High backpressure: Wellhead pressure is transmitted to the bottom of the hole, reducing the

differential into the wellbore and reducing production. Check to ensure that no choke is in theflowline. Even with no choke bean in a choke body, it is usually restricted to less than full

ID. Remove the choke body if possible. Excessive 90° turns can cause high backpressure and

should be removed when feasible.

High backpressure can also result from paraffin or scale buildup in the flowline. Hot-oiling

the line will usually remove paraffin; however, removal of scale may or may not be possible,


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depending on the type. Where high backpressure is caused by long flowlines, it may be

possible to reduce the pressure by looping the flowline with an inactive line. The same would

apply to cases in which the flowline ID is smaller than the tubing ID. Sometimes a partially

opened check valve in the flowline can cause excessive backpressure. Common flowlines can

cause excessive backpressure and should be avoided if possible. Check all possibilities, and

remove as many restrictions from the system as possible.

Separator operating pressure: The separator pressure should be maintained as low as

possible for gas-lift wells. Often a well may be flowing to a high or intermediate pressure

system when it dies and is placed on gas lift. Make sure the well is switched to the lowest-

pressure system available. Sometimes an undersized orifice plate in the meter, at the

separator, will cause high backpressure.

C) DOWNHOLE PROBLEMS

Hole in the tubing. Indicators of a hole in the tubing include abnormally low casing pressure

and excess gas usage. A hole in the tubing can be confirmed as follows:

1. Equalize the tubing pressure and casing pressure by closing the wing valve with the lift gas

on.

2. After the pressures are equalized, shut off the gas input valve and rapidly bleed-off the

casing pressure.

3. If the tubing pressure bleeds as the casing pressure drops, then a hole is evident.

4. The tubing pressure will hold; if not, then a hole is present since both the check valves and

gas-lift valves will be in the closed position as the casing pressure bleeds to zero.

5. A packer leak may also cause symptoms similar to a hole in the tubing.

Operating pressure valve by surface closing-pressure method: A pressure-operated valve

will pass gas until the casing pressure drops to the closing pressure of the valve. As a result,

the operating valve can often be estimated by shutting off the input gas and observing the

pressure at which the casing will hold. This pressure is the surface closing pressure of the

operating valve, or the closing-pressure analysis. The opening-pressure analysis assumes the

tubing pressure to be the same as the design value and at single-point injection. These

assumptions limit the accuracy of this method because the tubing pressure at each valve is

always varying, and multipoint injection may be occurring. This method can be useful when

used in combination with other data to bracket the operating valve.


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Well blowing dry gas: For pressure valves, check to ensure that the casing pressure is not in

excess of the design operating pressure, which causes operation from the upper valves. Using

the procedure mentioned above, make sure that there are no holes in the tubing. If the upper

valves are not being held open by excess casing pressure and no hole exists, then operation is

probably from the bottom valve.

4.2 TROUBLESHOOTING

Additional verification can be obtained by checking the surface closing pressure as indicated

above. When the well is equipped with fluid valves and a pressure valve on the bottom,

blowing dry gas is a positive indication of operation from the bottom valve after the

possibility of a hole in the tubing has been eliminated. Operation from the bottom valve

usually indicates a lack of feed-in. Often it is advisable to tag bottom with wireline tools to

determine whether the perforations have been covered by sand. When the well is equipped

with a standing valve, check to ensure the standing valve is not stuck in the closed position.

4.2.1 Well will not take any input gas: Eliminate the possibility of a frozen input choke or

a closed input gas valve by measuring the pressures upstream and downstream of the choke.

Also, check for closed valves on the outlet side. If fluid valves were run without a pressure

valve on bottom, this condition is probably an indication that all the fluid has been lifted

from the tubing and not enough remains to open the valves. Check for feed-in problems. If

pressure valves were run, check to see if the well started producing above the design fluid

rate because the higher rate may have caused the temperature to increase sufficiently to lock

out the valves. If the temperature is the problem, the well will probably produce periodically

and then stop. If this is not the problem, check to make sure that the valve set pressures are

not too high for the available casing pressure.

4.2.2 Well flowing in heads: Several causes can be responsible for this condition. With

pressure valves, one cause is port sizes that are too large. This would be the case if a well

initially designed for intermittent lift were placed on constant flow because of higher-than-

anticipated fluid volumes. In this case, large tubing effects are involved and the well will lift

until the fluid gradient is reduced below a value that will keep the valve open. This case can

also occur because of temperature interference. For example, if the well started producing at

a higher-than-anticipated fluid rate, the temperature could increase, causing the valve set pressures to increase and locking them out. When the temperature cools sufficiently, the

valves will open again, thus creating a condition in which the well would flow by heads.

With tubing pressure having a high tubing effect on fluid-operated valves, heading can occur

as a result of limited feed-in. The valves will not open until the proper fluid load has been

obtained, thus creating a condition in which the well will intermit itself whenever adequate


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feed-in is achieved. Because an injection gas rate that is too high or too low can often cause a

well to head, try tuning in the well.

4.2.3 Gas-lift operation stalls and will not unload: This typically occurs when the fluid

column is heavier than the available lift pressure. Applying injection-gas pressure to the top

of the fluid column, usually with a jumper line, will often drive some of the fluid column

back into the formation. This reduces the height of the fluid column being lifted and allows

unloading with the available lift pressure. This procedure is called “rocking the well.” The

check valves prevent this fluid from being displaced back into the casing. For fluid-operated

valves, rocking the well in this fashion will often open an upper valve and permit the

unloading operation to continue. Sometimes a well can be swabbed to allow unloading to a

deeper valve. Ensure that the wellhead backpressure is not excessive or that the fluid used to

kill the well for workover was not excessively heavy for the design.

4.2.4 Valve hung open: This case can be identified when the casing pressure will bleed below the surface closing pressure of any valve in the hole yet tests to determine the

existence of a hole show that one is not present. Try shutting the wing valve and allow the

casing pressure to build up as high as possible, and then rapidly open the wing valve. This

action will create high differential pressure across the valve seat, removing any trash that

may be holding it open. Repeat the process several times if required. In some cases valves

can be held open by salt deposition. Pumping several barrels of fresh water into the casing

will solve the problem. If the above actions do not help, a flat valve cutout may be the cause.

4.2.5 Valve spacing too wide: Try rocking the well when it will not unload. This will

sometimes allow working down to lower valves. If a high-pressure gas well is nearby, usingthe pressure from it may allow unloading. If the problem is severe, the only solution may be

to replace the current valve spacing, install a packoff gas-lift valve, or shoot an orifice into

the tubing to achieve a new point of operation.

4.3 TUNING IN THE WELL

4.3.1 Continuous-Flow Wells

Unloading a well typically requires more gas volume than producing a well. As a result the

input gas volume can be reduced once the point of operation has been reached. Excess gasusage can be expensive in terms of compression costs; therefore, it is advantageous, in

continuous-flow installations, to achieve maximum fluid production with a minimum amount

of input gas. This can be accomplished by starting the well on a relatively small input choke

size, at 1/64 increments, until the maximum fluid rate is achieved. Allow the well to stabilize

for 24 hours after each change before making another adjustment. If for some reason a

flowline choke is being used, increase the size of that choke until maximum fluid is produced


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before increasing the gas-input choke. If the total gas:liquid ratio (TGLR) exceeds the values

shown in Fig. 2, it is possible that too much gas is being used.

5.3.2 Intermittent-Flow Wells

In intermittent lift, the cycle frequency is typically controlled by an intermitter. The

intermitter opens periodically to lift an accumulated fluid slug to the surface by displacing

the tubing with gas. The same amount of gas is required to displace a small slug of fluid to

the surface as is required to displace a large slug of fluid (Fig 3.). As a result, optimal

performance is obtained when the well produces the greatest amount of fluid with the least

number of cycles.

The cyclic operation of the injection gas causes the surface casing pressure to fluctuate

between an opening casing pressure (high) and a closing casing pressure (low). The

difference in the surface opening and closing pressures during a single cycle is referred to as“spread.” Injection-gas volume per cycle increases as spread value increases.

Fig 4.3. - Intermittent Gas Lift: Saw tooth Shape to Surface Casing Pressure

To accomplish this, the initial injection-gas volume and the number of injection cycles must

be more than required. A good rule of thumb is to set the cycle based on 2 minutes per 1,000

ft of lift, with the duration of gas injection based on 1/2 minute per 1,000 ft of lift. Reduce

the number of cycles per day until the most fluid is obtained with the least number of cycles,and then decrease the injection time until the optimal amount of fluid production is

maintained with the least injection time. If one barrel or less is produced per cycle, the cycle

time should probably be increased. Be sure the intermitter stays open long enough to fully

open the gas-lift valve. This will be indicated by a sharp drop in casing pressure. When a

two-pen recorder is used, it will give a saw-tooth shape to the casing pressure line (Fig. 4.3).


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5.4 SOME COMMON MALFUNCTIONS OF GAS LIFT SYSTEM - POSSIBLE

CAUSES & CURES

1. Communication between Casing & Tubing

Causes Cures

A. Valve Stuck Open A. Rock the well, flush the valve

B. Packer leaking B. Reset packer

C. Tubing Leak C. Tubing patch / re-run new tubing

2. Injection Pressure Increases

Causes Cures

A. Upper valve is operating valve A. Adjust injection gas Pressure

B. Valve plugged B. Valve needs to be replaced

C. Temperature rise affecting valves C. Lower TRO pressure of valve

3. High Back Pressure at Wellhead

Causes Cures

A. Plugged flow line A. Needs treatment accordingly

B. Flow line size too small B. Loop flow line or larger line

C. Well using too much

gas

C. Adjust injection choke


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4.5 Troubleshooting: Diagnostic Tools

4.5.1 Calculations: One method of checking gas-lift performance is by calculating the“tubing load required” (TLR) pressures for each valve. This can be accomplished by

calculating surface closing pressures or by comparing the valve opening pressures with the

opening forces that exist at each valve downhole based on the operating tubing, and casing pressures, temperatures, etc. Although this method may not be as accurate as a flowing pressure survey because of inaccuracies in the data used, it can still be a valuable tool in

highgrading the well selection for more expensive diagnostic methods. Weatherford’s

VALCAL gas-lift design software is available for this type of diagnostics.

4.5.2 Well-Sounding Devices: The fluid level in the annulus of a gas-lift well will

sometimes give an indication of the depth of lift. This method involves imploding or

exploding a gas charge at the surface and uses the principle of sound waves to determine thedepth of the fluid level in the annulus. Acoustic devices are fairly economical compared to

flowing-pressure surveys. It should be noted that for wells with packers, it is possible for the

well to have lifted down to a deeper valve while unloading, then return to operation at a valveup the hole. The resulting fluid level in the annulus will be below the actual point of

operation.

4.5.3 Tagging Fluid Level: Tagging the fluid level in a well with wireline tools cansometimes give an estimation of the operating valve subject to several limitations. Fluid feed-

in will often raise the fluid level before the wireline tools can be deployed down the hole. In

addition, fluid fallback will always occur after the lift gas has been shut off. Both of thesefactors will cause the observed fluid level to be above the operating valve. Care should be

taken to ensure that the input gas valve was closed before closing the wing valve, or the gas

pressure will drive the fluid back down the ole and below the point of operation. This is

certainly a questionable method.

4.5.4 Two Pen Recorder:

Fig. 4.4 - Two Pen Recorder Installed

on Well Head

4.5.5. Flowing Pressure Survey In this type of survey, an electronic pressure gauge or bomb

is run in the well under flowing conditions. These recording instruments can also measure

temperature, and both ambient and “quick -response” models are available.Under flowing

conditions, a no-blow tool is run with the tools, which prevents the tools from being blown up

the hole. The no-blow tool is equipped with dogs, or slips, that are activated by sudden

movements up the hole. The bomb is stopped at each gas-lift valve for a period of time,


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recording the pressures at each valve. From this information, the exact point of operation can

be determined, as well as the actual flowing bottomhole pressure (BHP). This type of survey

is the most accurate way to determine the performance of a gas-lift well, provided that an

accurate well test is run in conjunction with the survey. The following procedure explains the

process in detail.

Procedure for Running a Flowing BHP Test When the Well Is Equipped with Gas-Lift

Valves

a. Continuous-Flow Wells

1. Install a crown valve on the well, if necessary, and flow the well to the test separator for 24

hours so that a stabilized production rate is known. Test facilities should duplicate normal

production facilities as nearly as possible.

2. Put the well on test before running the BHP. The test is to be run for a minimum of 6 hours. Agas and fluid test, two-pen recorder chart, and separator chart should be sent in with the pressure

traverse.

3. A pressure bomb must be equipped with one, or preferably two, no-blow tools. Use a small-

diameter bomb.

4. Install a lubricator and pressure-recording bomb. Make the first stop in the lubricator to record

wellhead pressure. Run the bomb, making stops 15 ft below each gas-lift valve for 3 minutes. Do

not shut in the well while rigging up or recording flowing pressures in tubing.

5. Leave the bomb on bottom for at least 30 minutes, preferably at the same depth that the last

static BHP was taken.

6. The casing pressure should be taken with a deadweight tester or “master test” gauge, or a

recently calibrated two-pen recorder.

b. Intermittent-Flow Wells

1. Install a crown valve on the well if necessary, and flow the well to the test separator for 24

hours so that a stabilized production rate is known. Test facilities should duplicate, as nearly as possible, normal production facilities.

2. Put the well on test before running the BHP. The test is to be run for a minimum of 6 hours.Test information, two-pen recorder charts, and separator chart should be sent in with the pressure

traverse.


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3. A pressure bomb must be equipped with one, or preferably two, no-blow tools. Use a small-

diameter bomb.

4. Install a lubricator and pressure recording bomb. Let the well cycle one time with the bomb,

just below the lubricator, to record the wellhead pressure and to ensure that the no-blow tools are

working. Rub the bomb, making stops 15 ft below each gas-lift valve. Be sure to record amaximum and minimum pressure at each gas-lift valve. Do not shut in the well while rigging upor recording flowing pressures in the tubing.

5. Leave the bomb on bottom for at least two complete intermitting cycles.

6. High and low tubing and casing pressures should be checked with a deadweight tester or

“master test” gauge, or a recently calibrated two-pen recorder.

Where to Install a Two-Pen Recorder

Connect Casing Pen Line• At the well, not at compressor or gas distribution header.

• Downstream of input choke so that the true surface casing pressure is recorded.

Connect Tubing Pen Line

• At the well, not the battery, separator, or production header.

• Upstream of choke body or other restrictions. Even with no choke bean,a less -than-full opening

found in most of the chokes.


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5. GAS LIFT OPTIMIZATION:

Under-Performing / Sub-Optimal Wells:

A well is said to be under performing when-

Operating at shallower depths than at desired deeper depths

Wells with insufficient Injection gas

Wells with more Injection gas

Leaking gas lift valves

Tubing leaks

Multi porting

5.1. Production Optimization by Gas lift (Case Studies)

Scope:

The following is the scope of the work

Analysis of self and continuous Gas lift wells

Sensitivity analysis at reduced tubing head pressure(THP)

Sensitivity analysis at increased injection gas rate

Quantify liquid gain

Basis of Study:

Flowing Bottom hole Studies data and corresponding production rates.

Reservoir pressure, PVT and well completion data as given.

Input data as given and considered for well modelling and analysis is placed in Table

given below

Methodology:

Well modelling and analysis has been done using ‘Prosper Software’

Actual pressure gradients and corresponding liquid rate, water cut, THP, and GOR have

been used to determine the matching flow correlations.


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Flowing bottom hole pressure (FBHP) calculated with matching flow correlation is used

to plot IPR and outflow curves for the wells.

Sensitivity analysis of the wells is carried out for the wells for different gas injection rates

and THPs to arrive at envisaged oil/liquid gains.

CASE-1: Wells with insufficient Injection gas

Implications

Loss of production due to not producing the well to its potential

Indicators

Higher rates vis – a – vis higher gas injection rates

Detection

By Sensitivity Analysis ( Gas in – Liquid out curve )

A.

Case Study:

Well : ABCD#5

Input Data :

(i) PVT Properties:

Sand Bassein

Reservoir Temperature 104.44 Deg C

Bubble point ( Pb ) 123.372 Kg/cm

Solution GOR (R s) 45.4 v/v

Oil API 39

(ii) Production Data:

Test Date Liq. Rate Water cut Gas inj rate

07.06.2013 1091.547

STB/day

80% 27,801 M /d

GLV depths (m) 665.27, 1357.01, 1814.02, 2060.67 (C.V)

Port sizes: (1/64t

inch): 12,12,16,20


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(iii) Reservoir Data

Perforation: 2,337.00-2529 M

Reservoir pressure 1083.83 psig at 1512.48 m TVD. (September’13)

FBHP 60.79 Kg/cm a at 2077.74 m MD. (07.06.13)

Reservoir Temp. 102.03 Deg C at 2077.74 m MD. (07.06.13)

* Current Res. pressure of 1083.83 psig a 1821.65 m MD has been considered for the

model.

Analysis:

From FG data of 08

th

June 2013 andother production parameters, the

AOFP of the well is estimated at

3476.0 STB/day with PI of 4.62

STB/day/psi.

Gas injection observed to be

through CV at 2060.67 m.

The following correlations wereused for VLP-IPR matching Fig: 5.1. IPR plot

Tubing Correlation: Petroleum Experts 2

Pipe Correlation: Beggs & Brill


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Fig: 5.2. IPR plot: VLP-IPR matching for the well ABCD#1

It has been observed from simulation that production increases with increase in gas

injection rate as shown in the Table & Fig below:

Inj gas rate in

M3/day

Qliq

STB/day

Qoil

STB/day

10,000 827.0 165.4

20,000 1037.3 207.5

27,801 1089.8 218.0

30,000 1100 220.1

35,000 1120.9 224.2

40,000 1136.0 227.2

45,000 1147.0 229.4

60,000 1163.2 232.6


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Fig: 5.3. Sensitivity Plot

Recommendation:

It is suggested to increase gas injection rate from 27,801 M3/day to 40,000 M

3/day to

enhance liquid production from 1089.8 STB/day to 1136.0 STB/day.

Envisaged liquid gain : 46.2 STB/day.

Envisaged oil gain : 9.2 STB/day.

CASE-2: Wells with injection gas more than required

Implications

Wastage of high pressure gas

Loss of production not only from the individual well, but also from Inter-connected /

other wells flowing to the same platform.

Indicators

No distinctive indicators for minor quantities.

However, characterized by

Drop in production

Higher THPs


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Detection:

By Sensitivity Analysis ( Gas in – Liquid out curve )

A. Case Study:

Well : LMNO#1

Input Data :

(i) PVT Properties:

Sand Muktabasin

Reservoir Temperature 104.444 Deg C

Bubble point ( Pb ) 124.427 Kg/cm

Solution GOR (R s) 111 v/v

Oil API 36.1

(ii) Production Data:

Test Date Liq. Rate Water cut Gas inj rate

17/12/2013 485.245 STB/day 64% 51,365 M /d

GLV depths (m) 842.0732, 1419.20, 1639.329, 1820.732 (C.V)

Port sizes: (1/64t

inch): 12,12,16,24

(iii)Reservoir Data:

Reservoir pressure 60.0984 Kg/cm a at 1422.67m TVD

(August’13)

FBHP 32.479 Kg/cm a at 1835.37 m MD.

(15.08.13).

Reservoir Temp. 97.88 Deg C at 1835.37 m MD. (15.08.13).

* Current Res. pressure of 60.0984 Kg/cm2

a 1835.37 m MD has been considered for the model.

Analysis:

From FG data of 17th

December’13 and other production parameters, the AOFP of the well is

estimated at 731.2 STB/day with PI of 1.38 STB/day/psi


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Fig: 5.4. IPR Plot

Gas injection observed to be through CV at 1820.732 m.

It has been observed from simulation that production of the well has not been optimized.

We are injecting more gas than required. This production is yielded even with a lesser

injection of gas as shown in the VLP-IPR matching graph, the well is producing far from

its optimum production point.

The following correlations were used for VLP-IPR matching

Tubing Correlation: Beggs & Brill

Pipe Correlation: Beggs & Brill

Fig: 5.5 VLP-IPR curve as per on 17/12/13


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Production data with various gas injection rates for total GOR 344.378 and Water Cut of

64%

Inj gas rate inM3/day Qliq STB/day Q

oil STB/day

10,000 458.7 166.51

20,000 503.5 181.2

25,000 511.3 184.1

30,000 513.6 184.9

35,000 511.5 184.2

40,000 506.1 182.2

50,00

Documents

Report on Gas lift design, operation and troubleshooting