OVERVIEW OF ARTIFICIAL LIFT

Hydrocarbons will normally flow to the surface under natural flow when the discovery well is

completed in a virgin reservoir. The fluid production resulting from reservoir development will

normally lead to a reduction in the reservoir pressure, increase in the fraction of water being

produced together with a corresponding decrease in the produced gas fraction. All these factors

reduce, or may even stop, the flow of fluids from the well. The remedy is to include within the

well completion some form of artificial lift. Artificial lift adds energy to the well fluid which,

when added to the available energy provided “for free” by the reservoir itself, allows the well to

flow at a (hopefully economic) production rate.

Figure 1: Sketch of a well

The purpose of artificial lift is to maintain a reduced producing bottom-hole pressure so the

formation can give up the desired reservoir fluids a well may be capable of performing this task

under its own power. In its later stages of flowing life, a well is capable of producing only a

portion of the desired fluids. During this stage of a wells flowing life and particularly after the

well dies, a suitable means of artificial lift must be installed so the required flowing bottom-hole

pressure can be maintained. Maintaining the required flowing bottom-hole pressure is the basis

for the design of any artificial lift installation; if a predetermined drawdown in pressure can be

maintained, the well will produce the desired fluids.

The commonly used artificial lift methods include the following:

• Sucker rod pumping

• Gas lift

• Electrical submersible pumping

• Hydraulic piston pumping

• Hydraulic jet pumping

• Plunger lift

• Progressing cavity pumping

Each method has applications for which it is the optimum installation. Proper selection of an

artificial lift method for a given production system (reservoir and fluid properties, wellbore

configuration, and surface facility restraints) requires a thorough understanding of the system.

Economics analysis is always performed.

4.1 Sucker rod pump4.1.1 Introduction Sucker Rod Pumps, also called Donkey pumps or beam pumps, are the most common artificial-

lift system used in land-based operations. Motor drives a reciprocating beam, connected to a

polished rod passing into the tubing via a stuffing box. The sucker rod continues down to the oil

level and is connected to a plunger with a valve.

Figure 2 A conventional SRP UnitIt provides mechanical energy to lift oil from bottom hole to surface. It is efficient, simple, and

easy for field people to operate. It can pump a well down to very low pressure to maximize oil

production rate. It is applicable to slim holes, multiple completions, and high-temperature and

viscous oils. The system is also easy to change to other wells with minimum cost. The major

disadvantages of beam pumping include excessive friction in crooked/deviated holes, solid-

sensitive problems, low efficiency in gassy wells, limited depth due to rod capacity, and bulky in

offshore operations. Beam pumping trends include improved pump-off controllers, better gas

separation, gas handling pumps, and optimization using surface and bottom-hole cards.

Types of Sucker Rod Pumps:

There are basically 3 types of Sucker Rod Pumps. They are

a) Conventional type

b) Lufkin Mark II

c) Air balanced Type

4.1.2 Components of SRPConventional pumping units are available in a wide ranges if sizes, with stroke lengths varying

from 12 to almost 200 inches. The strokes for any pumping unit type are available in

increments(unit size). Within each unit size, the stroke length can be varied within limits ( about

six different lengths being possible).

These different lengths are achieved by varying the position of the pitman arm connection on the

crank arm. Walking beam ratings are expressed in allowable polished rod loads (PRLs) and vary

from approximately 3,00 to 35,000 lb. counter balance for conventional pumping units is

accomplished by placing weighs directly on the beam( in smaller units) or by attaching weights

to the rotating crank arm ( or a combination of the two methods for larger units).

The pumping system consists of essentially five parts:

a) The subsurface sucker rod driven pump

b) The sucker rod string which transmits the surface pumping motion and the power to the

subsurface pump. Also included is the necessary string of tubing and/or casing within

which the sucker rods operate and which conducts the pumped fluid fro the pump to the

surface

c) The surface pumping equipment which changes the rotating motion of the prime mover

into the oscillating liner pumping motion.

d) The power transmission unit or the speed reducer

e) The prime mover which furnishes the necessary power to the system

Figure 3 A conventional SRP and its ComponentsThe prime mover is either an electric motor or an internal combustion engine. The modern

method is to supply each well with its own motor or engine. Electric motors are most desirable

because they can easily be automated

The power from the prime mover is transmitted to the input shaft of the gear reducer by a V-belt

drive. The output shaft of the gear reducer drives thecrank arm at a lower speed (4-40 revolutions

per minute [rpm] depending on well characteristics and fluid properties).

The rotary motion of the crank arm is converted to an oscillatory motion by means of the

walking beam through the a pitman arm. The horse’s head and the hanger cable arrangement is

used to ensure that the upward pull on the sucker rod string is vertical all the times (thus, no

bending moment is applied to the stuffing box). The polished rod stuffing box combines to

maintain a good liquid seal at the surface and, thus, foce fluid to flow into the “T” connection

just below the stuffing box.

4.1.3 Construction of SRPAbove Ground

In the early days, pumps were actuated by rod lines running horizontally above the ground to an

eccentric wheel in a mechanism known as a Central Power. The Central Power itself, which

might operate a dozen or more pumps, was powered by a steam or internal combustion engine or

by an electric motor. Among the difficulties with this scheme was keeping the system balanced

as individual well loads changed.

Modern pumps are powered by a prime mover. This is commonly an electric motor, but

combustion engines are used in isolated locations without economic access to electricity.

Common off-grid pumpjack engines run on casing gas produced from the well, but pumps have

been run on many types of fuel, such as propane and diesel. In harsh climates such motors and

engines may be housed inside a shack to protect them from the elements.

The prime mover of the pumpjack runs a set of pulleys to the transmission which in turn drives a

pair of cranks, generally with counterweights on them to assist the motor in lifting the heavy

string of rods. The cranks in turn raise and lower one end of an I-beam which is free to move on

an A-frame. On the other end of the beam, there is a curved metal box called a Horse Head or

Donkeys Head, named so due to its appearance. A cable made of steel (or, occasionally,

fiberglass) called a bridle, connects the horse head to the polished rod, a piston that passes

through the stuffing box. The polished rod has a close fit to the stuffing box, letting it move in

and out of the tubing without fluid escaping. (The tubing is a pipe that runs to the bottom of the

well through which the liquid is produced.) The bridle follows the curve of the horse head as it

lowers and raises to create an almost completely vertical stroke. The polished rod is connected to

a long string of rods called sucker rods, which run through the tubing all the way to the down-

hole pump, usually positioned near the bottom of the well.

Downhole

At the bottom of the tubing is the down-hole pump. This pump has two ball check valves: a

stationary valve at bottom called the standing valve, and a valve on the piston connected to the

bottom of the sucker rods that travels up and down as the rods reciprocate, known as the

traveling valve. Reservoir fluid enters from the formation into the bottom of the borehole

through perforations that have been made through the casing and cement (the casing is a larger

metal pipe that runs the length of the well, which has cement placed between it and the earth; the

tubing, pump and sucker rods are all inside the casing). When the rods at the pump end are

traveling up, the traveling valve is closed and the standing valve is open (due to the drop in

pressure in the pump barrel). Consequently, the pump barrel fills with the fluid from the

formation as the traveling piston lifts the previous contents of the barrel upwards. When the rods

begin pushing down, the traveling valve opens and the standing valve closes (due to an increase

in pressure in the pump barrel). The traveling valve drops through the fluid in the barrel (which

had been sucked in during the upstroke). The piston then reaches the end of its stroke and begins

its path upwards again, repeating the process.

Often, gas is produced through the same perforations as the oil. This can be problematic if gas

enters the pump, because it can result in what is known as gas locking, where insufficient

pressure builds up in the pump barrel to open the valves (due to compression of the gas) and little

or nothing is pumped. To preclude this, the inlet for the pump can be placed below the

perforations. As the gas-laden fluid enters the well bore through the perforations, the gas bubbles

up the annulus (the space between the casing and the tubing) while the liquid moves down to the

standing valve inlet. Once at the surface, the gas is collected through piping connected to the

annulus.

Sucker Rod

A sucker rod is the connecting link between the surface pumping unit and the subsurface pump,

which is located at or near the bottom of the oil well. The vertical motion of the surface pumping

unit is transferred to the subsurface pump by the sucker rods. Two types of sucker rods are in use

today-stcel rods and fiberglass-reinforced plastic sucker rods. It is estimated that slightly less

than 90%of the rods sold in 1985 were steel rods, while slightly more than 10% were fibreglass

rods.

Figure 4 Subsurface Components of SRP

Steel rods are manufactured in lengths of 25 or 30 feet. Fiberglass rods are supplied in 37 1/2- or

30-ft lengths. Both types of rods are connected by a 4-in.-Iong coupling. The pin ends of the

sucker rod are threaded into the internal threads of the coupling. Individual rods are connected to

form rod strings that can vary in length from a few hundred feet for shallow wells to more than

10,000 ft for deeper wells.

4.1.4 Working of the SRPIn normal pump operation, when the plunger of the pump is in the down position and begins to

move upward (up stroke) a differential pressure is created across the traveling valve. The valve

will move against a pressure called pump discharge pressure Pdis. This pressure is the summation

of the hydrostatic fluid column from pump depth to wellhead Phy, wellhead Pwh and losses Ploss

pressures. That differential pressure causes the traveling valve to close, and a low-pressure area

is formed in the void space where the plunger had been. Therefore, a pressure differential forms

across the standing valve. The higher pressure outside of the pump (P intk) forces the standing

valve to open. This will allow the higher fluid pressure in the well to be forced into the low-

pressure area within the pump, thus filling the void space within the pump chamber with fluid.

When the plunger reaches the top of the stroke and starts downward, the pressure inside the

pump will exceed the pressure outside the pump, and the standing valve is forced closed. As the

plunger continues downward, it attempts to compress the fluid, thus causing a pressure

differential (∆ P =Pcomp - Pdis) between inside the pump and the production column. With the

plunger travelling downward, Pcomp (pressure inside pump barrel) causes a force (Fup), which

pushes against the bottom of the travelling valve ball, attempting to open the ball. When this

force is big enough to exceed the force pushing on the travelling valve ball from the fluid column

above the pump (Fdown), the travelling valve ball opens. As the plunger continues downward, the

fluid that was below the travelling valve becomes fluid above the travelling valve. Thus, the fluid

within the pump barrel is transferred through the open travelling valve into the production

column of fluid above the pump. When the plunger reaches the bottom of the pump, the

differential pressure (∆ P) diminishes to zero, the travelling valve closes and the plunger starts

going upward again creating a low pressure P1 within the pump barrel, opening the standing

valve and allowing fluid from the well to enter the pump.

Now it is clear that the two main pump valves (traveling and standing) are working in the

principle of differential pressure. The two valves are one-way check valves opening when

pressure below is greater than that above the valve. Any delay in opening or closing one of them

will reduce the pump volumetric efficiency.

Figure 5 SRP Subsurface Operation Cycle

4.1.5 Advantages of Sucker Rod Pumps• High system efficiency

• Optimization controls available

• Economical to repair and service

• Positive displacement/strong drawdown

• Upgraded materials reduce corrosion concerns

• Flexibility - adjust production through stroke length and speed

• High salvage value for surface & downhole equipment

4.1.6 Limitations of SRP• Potential for tubing and rod wear

• Gas-oil ratios

• most systems limited to ability of rods to handle loads – volume decreases as depth

increases

• Environmental and aesthetic concerns

4.1.7 Sucker Rod Pump ApplicationTypical Range Maximum

Operating Depth 100 - 11,000’ TVD 16,000’ TVD

Operating Volume 5 - 1500 BPD 5000 BPD

Operating Temperature 100° - 350° F 550° F

Wellbore Deviation 0 - 20° Landed Pump 0 - 90° Landed

<15°/100’ Build Angle

Corrosion Handling Good to Excellent

w/oUpgraded Materials

Gas Handling Fair to Good

Solids Handling Fair to Good

Fluid Gravity >8° API

Servicing Workover or Pulling Rig

Prime Mover Type Gas or Electric

Offshore Application Limited

System Efficiency 45%-60%

4.1.8 Problems Faced During SRP workinga) Gas Locking

b) Sand Problems

c) Heavy Oil

A) Gas Locking:

• Gas Lock Occurs when a barrel is completely filled with Gas.

• Gas cannot be compressed enough to overcome the Hydrostatic head acting on the

traveling valve.

• Consequently both valves remain closed and the pump is gas locked.

Causes:

• Not enough pressure generated in compression chamber on down stroke to open traveling

valve.

• Produced fluid in tubing rides up and down with traveling valve, which is not opening.

Effects:

• No fluid produced to the surface.

• Fluid level on backside continues to rise as no fluids are removed from well.

Solution:

• Increase compression ratio in pump through better design/assembly.

• Increase compression ratio in pump through longer stroke or smaller plunger.

• Install II stager valve to remove hydrostatic pressure from traveling valve.

• Reduce gas intake into pump through better down hole separation.

• Increase pump intake pressure by allowing higher fluid level on backside.

B) Sand Problems

Causes:

• Sand can come from the reservoir or a sand-Frac.

• If sand is present from a sand-Frac, it is usually a temporary problem that will clear itself

as the well is pumped.

• If the sand is from the reservoir the problem will be ongoing and special attention must

be given to the design of the pump and its material selection.

Solutions

• Pressure-Actuated Plunger

• Combo Plunger Actuated Plunger

• Chrome Plated Grooved Plunger

• Sand Hogg

• 3-Tube Pump

4.2 Electrical Submersible PumpElectrical submersible pumps (ESPs) are easy to install and operate. They can lift extremely high

volumes from highly productive oil reservoirs. Crooked/deviated holes present no problem. ESPs

are applicable to offshore operations. Lifting costs for high volumes are generally very low.

Limitations to ESP applications include high voltage electricity availability, not applicable to

multiple completions, deep and high temperature oil reservoirs, gas and solids production is

troublesome, and costly to install and repair. ESP systems have higher horsepower, operate in

hotter applications, are used in dual installations and as spare down-hole units, and include

down-hole oil/water separation. Sand and gas problems have led to new products. Automation of

the systems includes monitoring, analysis, and control.

Figure 6 Diagram of ESP

The ESP is a relatively efficient artificial lift. Under certain conditions, it is even more efficient

than sucker rod beam pumping. An ESP consists of subsurface and surface components.

a. Subsurface components

• Pump

• Motor

• Seal electric cable

• Gas separator

b. Surface components

• Motor controller (or variable speed controller)

• Transformer

• Surface electric cable

The overall ESP system operates like any electric pump commonly used in other industrial

applications. In ESP operations, electric energy is transported to the down-hole electric motor via

the electric cables. These electric cables are run on the side of (and are attached to) the

production tubing. The electric cable provides the electrical energy needed to actuate the down-

hole electric motor. The electric motor drives the pump and the pump imparts energy to the fluid

in the form of hydraulic power, which lifts the fluid to the surface

4.3 Hydraulic Lift Pump4.3.1 IntroductionHydraulic piston pumping systems can lift large volumes of liquid from great depth by

pumping wells down to fairly low pressures. Crooked holes present minimal problems. Both

natural gas and electricity can be used as the power source. They are also applicable to

multiple completions and offshore operations. Their major disadvantages include power oil

systems being fire hazards and costly, power water treatment problems, and high solids

production being troublesome. As shown in Figure a hydraulic piston pump (HPP) consists of

an engine with a reciprocating piston driven by a power fluid connected by a short shaft to a

piston in the pump end. HPPs are usually double-acting, that is, fluid is being displaced from

the pump on both the upstroke and the down stroke. The power fluid is injected down a

tubing string from the surface and is either returned to the surface through another tubing

(closed power fluid) or commingled with the produced fluid in the production string (open

power fluid).

Figure 7 Sketch of Hydraulic Lift Pump

4.3.2 Advantages of Hydraulic Lift Pumping1. Free or Wire-line Retrievable

2. Positive Displacement and strong Draw down.

3. Double Acting High Volumetric Efficiency.

4. Good Depth/Volume capability (+15,000 ft.)

4.3.3 Limitation of Hydraulic Pumping1. High initial capital cost

2. Complex to operate.

3. Only economical where there are a number of wells together on a pad.

1.3.4 Hydraulic Piston Lift Application Considerations

4.4. Plunger LiftThe function of plunger lift equipment is to provide for more efficient utilization of lifting gas

energy in any well that is or can be produced in a cyclic manner similar to intermittent gas lift.

Plunger lift incorporates a piston that normally travels the entire length of the tubing string,

providing a solid and sealing interface between the lifting gas and the produced liquid. This

interface changes the flow pattern during a lifting cycle from the familiar bullet shape of gas

penetration of the liquid slug to a pattern whereby gas flow is possible only between the

plunger’s outside diameter and the tubing walls. To lift the plunger and the liquid load above the

plunger, the gas pressure must be greater than these loads. The small quantity of gas that

bypasses the plunger during a cycle flows up through the annular space and acts as a sweep to

minimize liquid fallback. The use of plunger equipment, by minimizing liquid fallback and

eliminating possible gas penetration through the centre of the liquid slug, provides for the most

efficient form of intermittent gas lift production available.

Figure 8 Sketch of Plunger Lift System

4.5. Progressive Cavity Pump 4.5.1 IntroductionA progressive cavity pump is a type of positive displacement pump and is also known as a

progressing cavity pump, eccentric screw pump or even just cavity pump. It transfers fluid by

means of the progress, through the pump, of a sequence of small, fixed shape, discrete cavities,

as its rotor is turned. This leads to the volumetric flow rate being proportional to the rotation rate

(bidirectional) and to low levels of shearing being applied to the pumped fluid. Hence these

pumps have application in fluid metering and pumping of viscous or shear sensitive materials.

The cavities taper down toward their ends and overlap with their neighbours, so that, in general,

no flow pulsing is caused by the arrival of cavities at the outlet, other than that caused by

compression of the fluid or pump components. A progressive cavity pump also can act as a

motor when fluid is pumped through the interior. Applications include well drilling.

Figure 9 Progressive cavity pump

4.5.2 TheoryA PCP consists of a single helical rotor which rotates inside a double internal helical stator.

When the rotor is inserted in the stator, two chains of lenticular, spiral cavities are formed. As

the rotor is turned, the sealed cavities spiral up the pump without changing size or shape and

carry the fluid.

The progressive cavity pump consists of a helical rotor and a twin helix, twice the wavelength

and double the diameter helical hole in a rubber stator. The rotor seals tightly against the rubber

stator as it rotate, forming a set of fixed-size cavities in between. The cavities move when the

rotor is rotated but their shape or volume does not change. The pumped material is moved inside

the cavities.

The principle of this pumping technique is frequently misunderstood. Often it is believed to

occur due to a dynamic effect caused by drag, or friction against the moving teeth of the screw

rotor. However in reality it is due to the sealed cavities, like a piston pump, and so has similar

operational characteristics, such as being able to pump at extremely low rates, even to high

pressure, revealing the effect to be purely positive displacement (see pump).

At a high enough pressure the sliding seals between cavities will leak some fluid rather than

pumping it, so when pumping against high pressures a longer pump with more cavities is more

effective, since each seal has only to deal with the pressure difference between adjacent cavities.

Pumps with between two and a dozen or so cavities exist. When the rotor is rotated, it rolls

around the inside surface of the hole. The motion of the rotor is the same as the smaller gears of

a planetary gears system. As the rotor simultaneously rotates and moves around, the combined

motion of the eccentrically mounted drive shaft is in the form of a hypocycloid. In the typical

case of single-helix rotor and double-helix stator, the hypocycloid is just a straight line. The rotor

must be driven through a set of universal joints or other mechanisms to allow for the movement.

The rotor takes a form similar to a corkscrew, and this, combined with the off-center rotary

motion, leads to the alternative name; eccentric screw pump. Different rotor shapes and

rotor/stator pitch ratios exist, but are specialized in that they don't generally allow complete

sealing, so reducing low speed pressure and flow rate linearity, but improving actual flow rates,

for a given pump size, and/or the pump's solids handling ability

Figure 10 PCP Typical Configuration

4.5.3 Operation of Cavity PumpsIn operation progressive cavity pumps are fundamentally fixed flow rate pumps, like piston

pumps and peristaltic pumps, and this type of pump needs a fundamentally different

understanding to the types of pumps to which people are more commonly first introduced,

namely ones that can be thought of as generating a pressure. This can lead to the mistaken

assumption that all pumps can have their flow rates adjusted by using a valve attached to their

outlet, but with this type of pump this assumption is a problem, since such a valve will have

practically no effect on the flow rate and completely closing it will involve very high, probably

damaging, pressures being generated. In order to prevent this, pumps are often fitted with cut-off

pressure switches, burst disks (deliberately weak and easily replaced points), or a bypass pipe

that allows a variable amount a fluid to return to the inlet. With a bypass fitted, a fixed flow rate

pump is effectively converted to a fixed pressure one.

At the points where the rotor touches the stator, the surfaces are generally traveling transversely,

so small areas of sliding contact occur. These areas need to be lubricated by the fluid being

pumped (Hydrodynamic lubrication). This can mean that more torque is required for starting,

and if allowed to operate without fluid, called 'run dry', rapid deterioration of the stator can

result.

While progressive cavity pumps offer long life and reliable service transporting thick or lumpy

fluids, abrasive fluids will significantly shorten the life of the stator; as abrasive fluids will

shorten the life of any type of pump. However, slurries (particulates in a medium) can be

pumped reliably as long as the medium is viscous enough to maintain a lubrication layer around

the particles and so provide protection to the stator.

Figure 11 Rotor/Stator Pitch Relationship

4.5.4 Typical design factor and operational condition

Design factors

a) Pump displacement is the volume of fluid produced in one revolution of the rotor:

b) Calculated flow rate:

c) Actual flow rate:

where, Qs is the leak rate.

d) Head rating:

Determined by the cavities formed between the rotor and stator

e) Mechanical resistant torque:

Load on the thrust bearings or the load on the drive string.

4.5.5 Operational Conditions

Pumps are chosen based on the following

1) The flow rate and the head rating

2) The diameter and the depth of the equipment

3) The drive system

Specific designs involve the rotor of the pump being made of a steel, coated in a smooth hard

surface, normally chromium, with the body (the stator) made of a molded elastomer inside a

metal tube body. The elastomer core of the stator forms the required complex cavities. The rotor

is held against the inside surface of the stator by angled link arms, bearings (which have to be

within the fluid) allowing it to roll around the inner surface (un-driven). Elastomer is used for the

stator to simplify the creation of the complex internal shape, created by means of casting, which

also improves the quality and longevity of the seals by progressively swelling due to absorption

of water and/or other common constituents of pumped fluids. Elastomer/pumped fluid

compatibility will thus need to be taken into account.

Two common designs of stator are the "equal-walled" and the "unequal-walled". The latter,

having greater elastomer wall thickness at the peaks allows larger-sized solids to pass through

because of its increased ability to distort under pressure. The former have a constant elastomer

wall thickness and therefore exceed in most other aspects such as pressure per stage, precision,

heat transfer, wear and weight, but they are more expensive due to the complex shape of the

outer tube.

4.5.6 Advantages

High metering accuracy for dosing flocculants, precipitants, neutralizing agents or for

sampling.

Continuous, extremely gentle, and non-pulsating pumping.

Low shear rates maintain liquid structure

Excellent self-priming capability, including highly-contaminated and difficult-to-handle

liquids.

Available in various materials of construction.

Suitable for products with dry solids content up to 45%. The pumping system can be run

into deviated and horizontal wells.

The pump handles solids in production well.

The pump handles viscous production well.

Several of the components are off the shelf ESP components.

The production rates can be varied with use of a variable speed controller (VSC).

4.5.7 Disadvantages

The unit does not tolerate heat due to the softening of the stator material.

Gas must be separated to increase efficiency. It will not gas lock but if ingesting large

amounts of gas continuously, or if pumped off, it will overheat and damage will occur to

the stator.

If the unit pumps off the well, the stator will likely be permanently damaged.

The gearbox is another source of failure if well-bore fluids or solids leak inside. This

pump is suited for deviated wells and can be run in most locations of a horizontal well.

4.5.8 Applications

For pumping a wide range of liquids including highly viscous, neutral or aggressive liquids with

entrained air, or with solids content.

4.6 Gas Lift

4.6.1 Introduction

Gas Lift is widely used artificial lift method. As the name denotes, gas is injected in the tubing to

reduce the weight of the hydrostatic column, thus reducing the back pressure and allowing the

reservoir pressure to push the mixture of produce fluids and gas up to the surface. The gas lift

can be deployed in a wide range of well conditions (up to 30,000 bpd and down to 15,000 ft.).

They handle very well abrasive elements and sand, and the cost of work-over is minimized. The

gas lifted wells are equipped with side pocket mandrel and gas lift injection valves. This

arrangement allows a deeper gas injection in the tubing. The gas lift system has some

disadvantages. There has to be a source of gas, some flow assurance problems such as hydrates

can be triggered by the gas lift.

A gas lift can still give some production even if it is badly designed, or if the data are incorrect. It

can operate over a wide range of conditions.

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

Figure 12 Sketch of Gas Lift

4.6.2 Principles of Gas Lifts

Gas lift is the continuous or intermittent injection of gas into the lower section of the production

tubing to sustain or increase the well potential. The injected gas is commingled with produced

fluids, thereby decreasing the flowing gradient, enabling wells to be operated at reduced flowing

bottom-hole pressure, increasing or sustaining production. The additional work required to

increase the production rate of the well is performed at the surface by a gas compressor or

contained in a high pressure gas stream conveyed to the well in the form of gas pressure energy.

The success of any gas lift system depends on an adequate and reliable source of ‘quality’ lift gas

throughout the period when gas lift is required. The gas injection point should be as close as

possible to the top of the completion interval. In this respect, the equilibrium curve concept

should be used as the basis of all gas lift design studies. Lift should be as stable as possible. Gas

lift systems should operate with minimum (practical) back pressure at the wellhead. Completions

should be designed for single-point lift. Lift gas availability should be optimized to enable the

system to operate near continuously in the most profitable configuration (e.g. minimize

compressor down time). All gas lift system designs should address future, as well as present,

operating conditions. Overly conservative design assumptions should be avoided - design factors

should reflect the availability and quality of design data. Surveillance and control

(SCADA/CAO/DCS) should be considered as an integral part of any gas lift system. Good

quality data is a prerequisite for an efficient gas lift design. The ability to control gas distribution

is essential for efficient gas lift operation. Gas lift clearly requires a ‘systems think’ approach in

order to identify bottlenecks in production, disposal or flare systems. Gas lift systems should be

designed with all modes of operation in mind (e.g. start-up, turn down).

Two basic types of Gas Lifts are used widely. They are:

Continuous Gas Lift: It is where gas is continuously injected into the well to gasify the liquid

stream, with the objective of lightening the liquid column - and therefore increasing drawdown

on the formation. This has the result of increasing the well GLR. This method is only applicable

to wells having a lower than optimum natural GLR, and a reservoir pressure high enough to

sustain the desired flow rate when the GLR is increased. Since gas injection pressures are

normally much lower than the static reservoir pressure, gas lift valves are installed in the string

to enable the well to be progressively unloaded, thereby establishing the operating injection

depth as deep as possible. Gas lift string design is concerned with the correct positioning and

operation of the selected valves, taking into account anticipated operating conditions.

Intermittent Gas Lift:

It is where gas is injected under a column of liquid (usually above a standing valve) to displace

that slug of liquid to surface. This operation is repeated as soon as a sufficiently large liquid slug

has accumulated again. The limitations of intermittent gas lift are mainly related to the ‘cycle

time’ which can be achieved between successive slug production, and the volume of liquid that

can be efficiently lifted as a slug; gas tends to break through the slug, and part of the liquid falls

back. Controlling parameters are the inflow performance, the length and diameter of the conduit,

the gas pressure, gas injection rate, and the length, weight and viscosity of the liquid slug. The

introduction of a solid interface (plunger) between the gas and the liquid is a logical step to

decrease liquid fall back. This alternative is known as plunger lift and also as PAIL (Plunger

Assisted Intermittent Lift). Plunger lift may be an attractive alternative to beam pumping for

wells which are no longer efficient under continuous or intermittent gas lift.

Good quality data is considered invaluable when designing an artificial lift system. It is realized

that such data is not always readily available, as individual wells are seldom production tested

prior to the completion phase. Relative to other forms of artificial lift, gas lift is much more

‘forgiving’ with respect to specification errors, improper design assumptions and changing

operating conditions. This intrinsic design and operating flexibility is used in many instances to

help justify the selection of gas lift in the first place. This is particularly true in areas where

uncertainty surrounds reservoir production mechanisms and well performance in the early stages

of field development. The ‘down side’ of this is that gas lift systems can be operated inefficiently

(from necessity or by lack of good system surveillance) for long periods of time – often resulting

in significant production deferral.

Notwithstanding the clear advantages of gas lift in terms of flexibility, when comparing gas lift

installations with other forms of artificial lift, a number of distinct limitations become apparent.

An adequate and reliable source of gas is required throughout the life of the development.

Moreover, if the source gas is poor (e.g. low pressure, wet, corrosive), significant incremental

expenditure will be required to install and maintain, a gas conditioning plant. This can be less of

a problem than in the past as most new developments now include gas treatment for sales or re-

injection. Continuous gas lift is unable to reduce intake pressures to ‘pump off’. As a result of

the physical process, gas lift is unable to reach very low bottom-hole pressures. This will result

in higher back pressure on the reservoir compared to other pumping methods, thereby, restricting

production potential - mind even placing a limit on ultimate recovery. This problem becomes

more evident with increasing depth and declining reservoir pressure.

4.6.3 Advantages of Gas Lift Gas lift can operate over a wide range of producing conditions.

Significant amounts of foreign material can be safely handled (e.g. sand).

Gas lift has inherent gas handling capability, a severe drawback with many other forms of

artificial lift.

Systems can be designed to be low profile and unobtrusive. Offshore installations are

relatively common.

Well intervention / accessibility is excellent (usually full bore access) for well

surveillance and remedial work (PLT, BHP, re-perforating).

Gas lift can be applied to any well configuration (deviated, horizontal and dual).

With a gas lift system the energy source is located on surface. Subsurface components are

easily/cheaply replaced using wire-line (exception being sub-sea wells).

In light of the waste reduction drive, compression facilities and gas treatment will

generally be available in areas where associated gas volumes are significant. (e.g. to re-

inject or export)

Operating costs are generally low and a direct function of fuel costs and system

reliability/integrity.

4.6.4 Disadvantages of Gas Lift Investment may be capital intensive due to compression costs, but may be reduced by

adopting a central distribution plant, and benefitting from “required” compression (sales,

re-injection).

Limited drawdown capability - many deep wells cannot be lifted to abandonment.

Lift gas is not always readily available.

Gas lift may cause emulsions and viscous crude which are difficult to lift efficiently.

Safety precautions must be taken for high pressure gas distribution lines and live ‘annuli’.

Gas lift may exacerbate gas freezing, and therefore hydrate or wax problems.

Additional casing integrity is required.

A total system design approach is essential. With other lift systems this is less important.

Gas lift can be very inefficient without good surveillance practices (i.e. gas lift does not

‘fail’ in the same obvious manner as an ESP or beam pump), and therefore requires close

monitoring to operate efficiently on a continuous basis.

Escalating development costs, both operating and capital, together with the need to conserve

associated and non-associated gas dictate the need for an integrated, total systems approach to

gas lift design. When analyzing any gas lift system, it is essential that all appropriate physical

processes are mapped out and integrated. This will lead to a consistent approach to enhance

system design by matching reservoir and well performance against various process scenarios.

For convenience the ‘integrated system’ is made up of three main component parts: the reservoir,

the well and the surface facilities.

4.6.5 Well PerformanceIn high PI wells, where small changes in drawdown have a large effect on production, significant

gains can be realized by maximizing lift gas injection depth, the converse is also true however

for low PI wells. The natural deterioration of well performance with time should always be

considered in the initial design, particularly in areas where intervention costs are high.

Depending on the forecasted pressure decline (or onset of water production), the gas lift string

should be designed to cater for a range of operating conditions. Where large uncertainty exists,

bracketing of mandrels should be considered. Pessimistic ‘worst case’ or compromise designs

should be avoided, as this will generally result in unnecessarily complicated and sub-optimal

completions.

Tubing size is very important in gas lift design in order to operate at the maximum stable rate.

Too small tubing will result in excessive friction losses. However, too large tubing will cause

unstable flow and heading, particularly if well productivity begins to decline. This can only be

corrected (partially) by increased volumes of lift gas. To assist in optimizing tubing design the

appropriate two phase vertical flow correlations together with good quality fluid property PVT

data, must be used. An increase in water cut may result in a reduction in PI due to relative

permeability affects. This will also increase the density of the produced fluid, and simultaneously

reduce the gas-liquid ratio to the detriment of vertical lift. To assess the long term completion

requirements the effect of water breakthrough and PI reduction should be taken into account

during initial design. Low wellhead back-pressure is also of prime importance, as it allows

increased drawdown and enhances the efficiency of gas lift, and hence productivity. Higher

back-pressure also results in closer valve spacing and shallower injection. It is strongly

recommended that gas lift systems are operated with minimum back pressure at the wellhead.

Emulsions are common in gas lift operations, and can result in a significant increase in produced

fluid viscosity with adverse effects on lift performance. Available evidence suggests that

emulsions are formed at the point of gas injection. Emulsion behavior and its effect on well

productivity can vary greatly from well to well, even in the same field, as the result of varying

water cut and flow pattern in the well. Emulsions can often be successfully eliminated, or at

Yeast significantly reduced, by adding de-emulsifiers to the lift gas stream.

There are several important aspects of gas lift which have a direct influence on well casing

design:

The size of the production casing will be selected in line with the desired well potential,

and on the physical size of the required down-hole equipment (gas lift mandrels, SSSV).

The production casing must be large enough to accommodate the intended completion -

particularly when reviewing the feasibility of multiple tubing strings.

The well and completion should be configured to facilitate through-tubing operations.

Wire-line tools will be used to maintain the well and monitor production performance

(e.g. Flowing Gradient Survey).

There are a number of gas lift operating conditions that can result in the pressure in the

production casing being evacuated to atmosphere (as a result of human intervention, a

surface leak or equipment failure), therefore the collapse rating of the production casing,

and the design of the primary cementation, should be carefully considered during the

design phase.

It should also be noted that during initial kick off operations the production casing can be

exposed to full gas lift pressure on top of a full column of completion fluid. The

production casing and tubing should therefore be designed accordingly.

Surface Facilities: Lift gas volume and pressure are two extremely important considerations

(related to gas lift string design and compressor selection) which play a role in gas lift system

design:

Gas lift volume - It is the total lift gas requirement for the field or group of wells determined by

adding individual well requirements. It is possible to inject too much gas into an individual well.

Production will increase as a function of lift gas volume until a point of maximum production is

reached (the technical optimum). The addition of further quantities of gas beyond this point will

decrease productivity as a result of the dominance of friction pressure. This is especially true

where long flow-lines are installed. Determining the shape of the lift gas performance curve is a

critical step in new ventures where compression capacity is being estimated or in existing fields

where gas availability is constrained. The gas lift performance curve is also important when

optimizing the allocation of lift gas. Sub-optimal gas allocation is known to contribute

significantly to the ‘locked up’ potential in a number of existing gas lift developments.

Gas lift pressure – It is a critical design parameter in gas lift system design. It has a major impact

on completion design (number of valves), well performance (injection depth), system operating

pressure (compressor discharge), and obviously material and equipment specification - all of

which will have a significant impact on costs. Selection of a gas lift pressure that is too high can

result in needless investment in compression and other equipment, whereas pressures that are too

low can cause loss of production potential and production deferment.

The potential benefits of higher injection pressures are:

Higher production rates due to increased pressure drawdown as a result of being able to

inject deeper.

In general, if lifting takes place as deep as possible, less gas volume is required. From a

power point of view therefore it is more efficient to inject deep with a lower injection gas

liquid ratio (IGLR), than to inject shallow with a high IGLR.

Less down-hole equipment (mandrels, valves) leading to increased reliability and reduced

intervention. Equipment performance is a key consideration in an environment where

intervention costs are high (e.g. subsea well, remote platform).

In many instances the relative advantages of high pressure gas lift systems far outweigh those

resulting from low pressure systems. However, in a number of cases gas compressors will be

installed in any case to facilitate gas export or re-injection.

The quality of lift gas is an important consideration which influences both well and facility

design, and will have a significant impact on overall project costs. The following should be kept

in mind when evaluating the feasibility of a lift gas:

A rich (heavy) gas provides higher downh.de pressure, and therefore allows a deeper

injection depth for a given surface injection pressure compared to leaner (less dense) gas.

Heavier fractions (NCL), however, may go back into solution with the produced fluid.

The overall result in this case is that there will be little to be gained by increasing

injection depth. On the other hand, lower volumes of lighter gas at a higher injection

pressure may actually require less compression horse power per unit volume of fluid

produced.

Water in a lift gas system may lead to problems with corrosion, liquid slugging and

hydrates. If hydrate formation is expected in the distribution system, and/or anticipated

corrosion rates are unacceptable, then gas dehydration will be necessary. Glycol

contacting or other gas dehydration systems are employed to condition gas streams for

gas lift applications. Such systems remove hydrocarbons and significant amounts of

water from the gas system. Free water is removed by scrubbers. In cases where

dehydration is not economic, hydrates can be suppressed by chemical injection and

localized heating of problematic equipment.

As well as being potential safety hazards, gas with hydrogen sulphide (H2S) can cause

severe operational problems such as corrosion, excessive compressor maintenance and

fuel contamination. In such cases lift gas can be sweetened, or the appropriate materials

must be used in the gas lift system and wells - with significant incremental cost. The lift

gas supply must also be free from solids. Lift gas must ultimately pass through very small

areas in gas lift valves which can be easily plugged. Rust, salt, scale or chemical residue

should be prevented from accumulating in the system. Operation of dehydration

equipment should consider the consequences of carry-over of dehydration chemicals.

4.6.6 Designing of Gas LiftA gas lift design problem which commonly occurs is the case for a well that has been completed

and produced but now requires a gas lift design and equipment installation. Other cases are

where the existing gas lift design is not suitable, or simply when the tubing is pulled for repair

and the gas lift design needs to be reviewed for modification.

Procedure:

1) Collect relevant reservoir and well data. This includes

Depth of well

Casing and Tubing Program

Perforation Depth

Reservoir Pressure

Drive Mechanism

Production History

Oil Quality

Gas Liquid Ratio

2) Collect information as to how much gas is available for injection purposes and at

what pressure can it be injected by the compressor installed or about to be installed.

3) Decide a target flow rate from inflow and outflow curves which can be feasible. The

standard outflow gradient curves for each nominal size of tubing are available. Using

these curves, plot the outflow performance for different target GLRs which are higher

than the current producing GLR.

4) The amount of gas available for injection decides what target GLR should be chosen.

Different GLRs will require different amounts of gas to be injected. Select the

appropriate target GLR which requires the optimum amount of gas to be injected.

Gas To Be Injected, MCFD =

(Target GLR – Producing GLR) * Liquid Production Rate (bbls/day)/1000

5) Calculate the average gas injection temperature and flowing surface temperature.

Average Gas Injection Temperature =

(Surface Static Temperature + Bottom Hole Temperature)/2

Surface Flowing Temperature =

BHT (oF) – Flowing Temp. Gradient ( o F/ft)* Depth (ft)

100

6) Calculate appropriate Gas Gradient, depending on the specific gravity of gas used

from the standard chart which is attached in the Appendix. This will be required if

solving for valve/mandrel spacing analytically.

7) Valve Spacing

Graphical Solution :

1) In a pressure vs depth graph (as shown in the appendix) , draw a line at the depth

of the perforations

2) Draw Static Gradient Line from Shutting Bottom Hole Pressure (SBHP) using

the kill fluid gradient selected. This will intersect the y-axis at a depth which

signifies the depth from the surface of the kill fluid column in the well.

3) Plot the surface injection pressure on the x-axis. From Gas Column Pressures

Table for a gas with a certain specific gravity, calculate appropriate factor

corresponding to the well depth. These factors are calculated at 80o F and have to

be corrected to the corresponding BHT. This gives the injection pressure

required at bottom hole conditions. Draw the line from surface injection pressure

to the bottom hole injection pressure. This represents surface injection pressure

line.

P at depth = P at surface (1+F) F= Factor from table

F at reqd. temp. = F at 80oF* 540/(460+ Temperature)

4) Select appropriate Flowing Gradient Curve for given size of tubing, Oil gravity,

Gas Specific Gravity, Water Cut and target GLR and plot on graph starting at

given wellhead pressure down to perforation depth.

5) Starting from the wellhead pressure, draw a line parallel to the static gradient

curve and intersecting the injection pressure line at a certain depth. The

corresponding depth gives the depth of the first mandrel.

6) For spacing the second mandrel, draw a line parallel to static gradient line

starting from the corresponding point on the flowing gradient curve of the first

mandrel, till it intersects the injection pressure line at a certain depth, which

gives the depth of the second mandrel. Repeat the process for the spacing of the

successive valves.

7) To ensure proper valve action an arbitrary pressure drop is added into the design.

Adjust the valve depths in accordance with this pressure drop. This pressure drop

helps in building the safety factor of the design. 10 psi is the minimum for this

pressure drop and 45 psi is the recommended maximum. This is built in to the

design to ensure that due to this pressure drop in the casing, the upper valves

close and injection proceeds smoothly.

Analytical Solution:

1) Calculate Setting Depths as follows

Tubing Pressure = Casing Pressure – Pressure Differential

2) For first valve,

Pwh + gs x D(1) = Pg + gg x D(1) – Psf

D(1) = Depth of First Valve

Pwh = Wellhead Pressure

gs = Static fluid gradient (psi/ft)

Pg = Surface Injection Pressure

gg = Gas Gradient (psi/ft)

Psf = Nominal Pressure Differential

3) For subsequent valves

Ppd(n) + gs x Dbv =(Pg – n x PD) + gg x (D(n) +Dbv) – Psf

PD = Selected Pressure Drop

Ppd = Tubing Pressure at Depth

Dbv = Spacing between valves

D(n) = Depth of previous valve.

Depth of current valve = Spacing + Depth of Previous valve.

For 2nd valve n=1, for 3rd valve n=2 etc.

8) Valve Spacing Adjustment: Excessive number of valves should be avoided

although it is good design practice to add an extra valve for safety purposes or

future modifications.

The last few valve depths might need to be adjusted depending on perforation

depth. Usually packer is installed at least 30 ft above the mid perforation depth

and the bottom valve should be another joint above the packer depth. Adjust valve

depths accordingly. Also for economic purposes, a practical space of atleast 200-

250 feet must be maintained between successive valves.

9) Valve selection: Selection of valve must be done based on the manufacturer’s

catalog and pressure, temperature limits as well as size.

10) Valve Pressure Setting :

Calculation of valve test rack opening set pressure, Pvo is critical for proper gas lift

design. This is the injection pressure (P1) to open the valve in a tester with a back

(P2) equal to zero pressure and at a base temperature of normally 60°F. The

valve, in turn, should open in the well under the desired operating pressure and

temperature conditions.

Pvo= (PPEF x Ppd x Piod) x CT

PPEF = Production Pressure Effect Factor

Ppd = Production Pressure Acting on Valve

Piod = Design Injection Gas Pressure

CT = Temperature Correction Factor

CT = 1

1 + 0.00215(Tv - 60)

Piod(n) = Pg + gg x D(n)

COMPARISON OF ARTIFICIAL LIFT SYSTEMS5.1 Artificial Lift - Systems Comparison

Artificial Lift Systems Comparison

  Operating Condition Rod Lift ESP PCP Gas Lift

   Sand Fair Poor Good Good

   Paraffin Poor Good Good Fair

   High GOR Poor Fair Fair Excellent

   Deviated Well Poor Fair Poor Good

   Corrosion Good Fair Good Fair

   High Volume Poor Excellent Poor Good

   Depth Fair Fair Good Fair

   Scale Good Poor Good Fair

   Flexibility (flow rates) Fair Poor Poor Fair

5.2 Artificial Lift - Production Efficiency Comparisons

Typical efficiencies for artificial lift systems vary depending on the flow rate. Jet pumps provide

high volume production rate capacity with no moving parts, but require higher reservoir energy

while piston pumps will produce the well even with very low reservoir pressure.  

Typical Efficiency Comparisons for Various forms of Artificial Lift

EquipmentFlowrate (BFPD)

200 450 600 900 1200 1500 2000

Hydraulic Piston Pump 85% 85% N/A N/A N/A N/A N/A

Hydraulic Jet Pump 30% 30% 32% 32% 32% 32% 32%

Rod Lift Pump 90% 90% N/A N/A N/A N/A N/A

Figure 13 Sketch of all Artificial Lift System

ARTIFICIAL LIFT SELECTION

1.1 Artificial Lift Planning Asset:-

– By definition is any item that is owned or used by an individual or business to add

worth to or generate income

– A useful or valuable quality, person, or thing; an advantage or resource

“An artificial lift asset system integrates all the components installed in the wells, the

associated surface facilities and energy sources that are an integral part of the

flow system to create value. In many fields artificial lift is planned in a reactive mode,

either when the reservoir is no longer able to perform, or when unwelcome formation

water increases flowing bottom hole pressures. In other cases new hydrocarbons are

found in very complex operational environments for artificial lift equipment, such as

remote areas or deep waters”.

“Worldwide remaining reserves are also becoming heavier and more difficult to

produce without artificial lift. In addition, just as the fields mature, the

workforce responsible for driving the petroleum industry is also getting older and

about to retire. New technologies are helping to improve artificial lift performance

providing even more efficient connections between the reservoir and wellbores. In

these contexts, we need to view artificial lift as a system of assets”.

1.2 Objective of artificial lift selection The main objective is to select an adequate artificial lift method to increase

the expected well profitability during a certain period of time

Ultimate objective is usually NOT:-

Maximum hydrocarbon production

Maximum efficiency

Minimum operational costs

Minimum capital investment

Minimum equipment failure or down time.

There are many uncertainties in the oil business and the main objective is

select an artificial lift method to increase the chances of maximizing profit under

safe operational conditions (for humans and for the environment).

The artificial lift techniques need also to be flexible enough to cope

with the expected changes of production conditions and reservoir

performance.

Sometimes more than one method is selected to be used in a well or in a field at

different phases of development. This is usually result of planning or in some

cases a drastic solution for some bad decisions made in the past

– Continuous gas lift to intermittent gas lift

– Beam pumping to electrical submersible pump

– Continuous gas lift to electrical submersible pump

1.3 Planning for Artificial Lift The proper selection of artificial lift system depends on several other disciplines

such as drilling, completion, reservoir management, production layout, flow

assurance, automation, etc....

Artificial lift planning should be considered in the beginning of the field

development plan when reservoir, drilling, completion and production decisions

are being made

For a certain application, the “adequate” method (or methods) results from a

balance of the methods characteristics, reservoir performance, fluid properties,

data quality, physical restrictions, economical restrictions, environmental

conditions, personnel training, energy available, investment and operational costs,

etc..

All possible constraints, production conditions and future changes must be

properly addressed.

This process requires good communication and interaction between all correlated

disciplines.

1.4 What Not to Consider The method selection process sometimes may have a tendency to be driven by

“personal” decisions.

Operators, service companies, product manufacturer may have some

“preferences” not usually justified by a technical analysis.

The selection should be strictly technical and economical. The objective is to

maximize the expected profit through an intelligent management of operational

and investment costs. A well designed system will balance costs, production and

reliability under the various physical, economical, safety, environmental, human

and technical constraints.

1.5 Factors affecting artificial lift selection methods

Location (Onshore, offshore, arctic, remote location, etc)

Existing Infrastructure (Remote well, new well, artificial lift method used in

other wells in the area)

Flow rates (reservoir pressure and productivity index)

GLR and WC behavior

API and viscosity

Depth of well and temperature

Well and casing design

Type of well (vertical or directional)

Sand production, wax, emulsion corrosion and scale conditions

Type and quality of energy available

Environment and environmental issues

Personnel training and experience

Capital investment and operational costs

Workover costs

Reliability

Maintenance

Manufacturers available

Data quality and uncertainty, Etc....

1.6 Artificial Lift Methods attribute tables Several attribute tables are available in the literature – Brown, Clegg-Buckram-

Hein, Neely, etc...

They were developed as an aid in comparing each artificial lift method for each

production characteristic.

They contain a dynamic information and should be updated to reflect new

developments or limitations of the technology.

Very useful since their purpose is to serve as a collection of facts to be considered

and the influence of some conditions on each artificial lift method.

Good Attribute tables avoid a simple ranking of methods

1.7 Economic Analysis After designing the appropriate candidates, a final realistic economic analysis will

indicate the “best” choices.

The economic analysis requires:-

Investment costs and salvage values

Operational costs

Artificial lift system horsepower consumption

Production forecast

Estimate of failure rate for the expected operating conditions

Estimated cost and duration time of repairs