Artificial Lift2

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Artificial Lift

By Sekar

Learning Advisor - Process


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TRAINING TARGETS

The aim of t his section is to help you gain a

working knowledge of t he function and

operation of the different artificial lift methods. State the different types of Artificial Lift.

Make a simple sketch of a gaslifted well.

Identify the components on a beam pump.

List the different types of beam pump units.

Explain the operation of a beam pump.

List the different types of subsurface pump.

Explain in simple terms the operation of plungerlift system.Use one

slide per model, if appropriate.


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INTRODUCTION

On a natural flowing well the

reservoir pressure P1 available topush the liquid to the surface is

reduce due to pressure losses in the

system.

These pressure losses are; draw

down pressure loss (P1-P2),

vertical lift pressure loss (P2-P3)

and tubing head pressure loss (P3).

If the reservoir pressure is greater

than these three components then

the well will flow


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Initially the reservoir pressure may besufficient to sustain natural flow.

But it gradually declines as it gets older.

In these cases there maybe plenty of oil

still to be recovered.

But assistance is needed in the

production.

The methods use to recover the oil iscalled artificial lift.

What is the Artificial Lift?

The two types of artificial lift systems use are:

yGaslift Systems

yPumping Systems


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FLOWING WELL PERFORMANCE

Vertical Lift

A significant amount of reservoir pressure is lost

between the bottom of the hole and the tubing head.

This is called the vertical lift pressure loss.

The causes of vertical lift pressure loss in the system

are:yThe vertical height of the column

yThe density of the fluid

yThe tubing head pressure


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If the tubing head pressure is zero psi, the pressure at the bottom

of the well will depend only to the vertical height of the well and

the density of the fluid. This pressure is called the static bottom

hole pressure or the hydrostatic head. The increase in pressure

per unit increase in depth is known as pressure gradient.

This gradient is expressed in pounds per square inch per

thousand feet or PPTF.

Gas gradient is in the range of 75-150 PPTF. Oil gradient is in

the range of 300-400 PPTF. Water gradient is in the range of 430-

470 PPTF.

PPTF


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PRESSURE AND DEPTH GRAPH

Gradients are

represented on a

diagram or graph of

pressure against

depth.

The figure shows the

pressure/depth graph of

fresh water. The gradient

is a straight line and the

pressure at any depth canbe read off at the bottom.

A well filled with fluid

will have a pressure

increase from the surface

to the bottom.


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Flowing Pressure Gradient

When oil, gas and water flow up the tubing there will still be a

pressure gradient. The gradient in multiphase flow situationdepends on the relative volumes of the oil, water and gas. It also

depends on the density of each of these phases. Shown below is an

example of a pressure flowing gradient.


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The methods of artificial lift used in BSP are:

yGasliftingySucker rod or Beam Pumping

yPlungerlift

yElectrical Submersible Pump

Artificial Lift methods used in BSP


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Continuous

gaslift:

Relatively high pressure

gas is continuously

injected into the well

casing from where it

enters the tubing through

gaslift valves located at

intervals along the length

of the tubing.

Due to the "aeration" of

the fluid column the

density of the column is

reduced.


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Intermittent

gaslift:

Although grouped with

continuous gaslift, intermittent

lift is an entirely different type

of artificial lift. Gas injected in

short burst into the annulus,causes the ball valve at the

bottom of the tubing to close

and pushes a slug of liquid from

the bottom hole to the surface.The gas is then shut off and the

ball valve opens to allow fluid to

build up for the next slug.


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DEPTH OF GAS INJECTION

In gaslifting, gas is injected from the annulus into the

tubing somewhere down the well.

But how deep should this injection point to be? We caninject the gas down to the deepest point of the well but

there are limitations to this.

To determine this limitations, an example is illustratedbased on the pressure depth graph.


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Example:

A vertical well is 10,000 feet deep. The tubing is filled with aliquid gradient of 450pptf. The pressure in the tubing at the

surface is zero psi.

A straight line is drawn between the points zero pressure at

surface (zero feet) and 4500 psi at 10,000 ft. This line is called

the static pressure gradient line of the liquid.

If the gas supply pressure at the surface is 1000 psi and the gas

gradient is 150 pptf, the pressure in the annulus is:

1000 psi + (10000 x 150)/1000 = 1500 psi at 10000 ft.The two points for the gas gradient are: 0 feet 1000psi

10000 feet 2500 psi

DEPTH OFGAS INJECTION


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DEPTH OFGAS INJECTION

The two lines will intersect at a depth

of 3333 feet.

yAt depths above 3333 ft the gas

pressure in the annulus is higher

than the liquid pressure in the

tubing. Gas would be able to flow

from annulus to tubing.yAt depths below 3333 ft the gas

pressure in the annulus is less than

the liquid pressure in the tubing.

Gas could not flow in the tubing.

It would appear that the maximumdepth at which we could inject gas

into the tubing is slightly less than

3333 feet. In gaslift situation it is

advantageous to inject the gas as deep

as possible.


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KICKOFF

Kick off is a technique whereby gas is injected through a

number of injection points in turn. This technique will be able todeepen the point of injection.

If we are able to inject gas at a point just above 3333 feet, the

gas bubbles up the tubing. This has the effect of reducing the

gradient of the fluid in the tubing and pressures at all points in

the tubing will decline.

`The gas gradient in the annulus will not change. So the point at

which the annulus and tubing pressures are equal will be deeper

in the well.

If we could now start injecting gas at this point, an even greaterlength of tubing would benefit from the gas. Once again the

pressures in the tubing below the point of injection would

further decline.

The point of balance between the tubing and annulus pressures

will even be deeper.


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KICKOFF


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GASLIFT VALVES

A gaslift valve is like a pressure regulator. Its

function is to admit gas from the annulus totubing as required. Wireline retrievable gaslift

valves are normally located in the side pocket

mandrel.


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CAMCO BKR III

The CAMCO BKR III is a fluid sensitive valve.

Tubing fluid acting under the larger surface area if the

bellow added to the casing press acting under the small

surface area of the valve is the opening force.

When this combined force overcomes 'Bellows Pressure'the valve will move off its seat and injection will start.

The valve will continue injecting until the tubing fluid

gradient is reduced when a valve lower in the tubing string

is open.

When this happens:

'Bellows pressure' overcomes 'Tubing pressure' +

'Casing Pressure' and the valve closes.


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APPLICATIONS OFGASLIFTGaslift is a flexible system and can be applied in a number of

situations:yTo artificially lift wells which will not flow naturally

yTo kick off or unload wells

yTo increase production rates in naturally flowing wells

yADVANTAGES

yIt is flexible and can be designed to operate over a wide range of

changing well conditions

yPoses fewer problems in highly deviated wells

yNo moving parts downhole

DISAD

VANTAGES

yThere must be an economically available supply of gas.

yGas compression facilities may be required

yCasing and wellhead equipment must be able to withstand the

applied pressure

yGaslift is not so efficient for high viscosity oils


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GASLIFT SYSTEM

A typical gaslift system comprises the following components:

y (a) A source of high pressure gas (compressor or

gaswell).

y

(b) Distribution lines to bring the gas to the wellhead.y (c) Surface controls.

y (d) Subsurface controls (gaslift valves).

y (e) Flow lines.

y (f) Separation equipment.

y (g) Storage facilities.y (h) Flow measuring equipment.


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GASLIFT SYSTEM


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BEAM PUMPINGThe pumping unit is that part of the installation at the

surface used to change the rotary motion of the prime

mover (electric motor) to an up and down motion of thesucker rods at the required speed. Speed reduction

between the electric motor and the pitman crank is

accomplished by a combination of V-belt drive and gear

reducers. The crank is rotated by the slow speed shaft on

the gear box.

With one end of the pitman connected to the crank and

the other end to the walking beam, the rotation is changed

to the up and down motion required to operate the

subsurface pump.A set of weights, attached to the crank, counter-balances

the weight of rods and part of the weight of the fluid

which is hanging from the front end of the walking beam

(horsehead). These counter balances assist the electric

motor to lift the rods and fluid on the up-stroke.


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BEAM PUMPINGUNITS

In BSP there are two different types of Beam Pumping Units,

the Conventional Unit and the Air-balanced Unit

yConventional Unit - Pulling action:

The conventional pumping unit is normally crank-balanced and is

the most common unit currently in use in BSP. The rotation of thecrank causes the walking beam to pivot about the centre bearing.


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BEAM

PUMPINGUNITS


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Air-balanced Unit - Push-up action:

On the air-balanced pumping unit the load is counter-

balanced by the use of air pressure working against a pistoninside the cylinder.

A counter balance device is employed to adjust the air

pressure to the level required for perfect counter-balance even

though the well condition may change from day today.

BEAM PUMPINGUNITS


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BEAMPUMPING

UNITS

Air-balanced Unit


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BEAM PUMP OPERATION

STUFFING BOX

The rod string is lifted bymeans of a cable (bridle)

looped over the horsehead

and connected to the top

member of the rod stringwhich is called polished rod,

by the carrier bar and

polished rod clamp.

Pumping well pressure is

sealed, or packed off, insidethe tubing to prevent

leakage of liquid and gas

past the polished rod. This

seal is called the stuffing

box.


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FMCPACKINGS

Le Grand packings are being slowly changed to FMC packings

complete with flapper valve and single blockFMC trees.

The purpose of the flapper and single block tree is to be able to

contain and control well pressure during a sucker/polish rod

failure.

The stuffing-box packing is replaced when it becomes worn and

no longer seals. Below the polished rod are the sucker-rods.

These are solid steel or fibreglass rods running inside the tubingstring connecting the subsurface pump to the pumping unit.

Sucker-rods are joined by sucker-rod couplings or by box-pin

coupling.


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FMCPACKINGS


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SU SURFACE UMPS

Subsurface sucker-r umps are cyli rical, recipr cati , positi e isplaceme t pumpst at lift liqui from t e ell to t e surface. ey are i i e i to t o e eral types:

y Rodpumps.

y Tubi pumps.


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Operating principle

The subsurface pump operating principle is briefly described

as follows. The pumping cycle starts with an upward stroke of

the rods, which strokes the plunger upward in the barrel. The

travelling valve closes, the standing valve opens,and fluid

enters the barrel from the well.

On the downward stroke of the rods and plunger, the standing

valve closes, the travelling valve opens, and the fluid is forcedfrom the barrel through the plunger and into the tubing. Fluid

is lifted toward the surface with each repeated upstroke.

SUBSURFACE PUMPS


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PLUNGERLIFT

Plungerlift is a special method of gaslift, as

reservoir pressures in the Seria Field since

continuous gaslift has become increasingly

inefficient.Usually this has been overcome by converting

wells to beam pump.

However, for certain types of wells conversion

does not work because of sand and waxproblems.

Plungerlift is a suitable alternative.


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PLUNGERLIFT


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PRINCIPLE OF OPERATION

Plungerlift consists of a plunger cycling up and down the

production tubing, carrying, in each cycle, a slug of produced

liquid.

The plunger acts as the interface between the produced liquid

and the injected gas, which drives the plunger to surface.

The plunger prevents significant liquid fall back, thus

improving lift efficiency.

PLUNGERLIFT

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