Artificial Lift Artificial Lift By Sekar Learning Advisor

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Artificial Lift Artificial Lift By Sekar Learning Advisor Powered By Docstoc
					 Artificial Lift

        By Sekar
Learning Advisor - Process
   The aim of this section is to help you gain
    a working knowledge of the function and
    operation of the different artificial lift
     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.
•On a natural flowing well the
reservoir pressure P1 available to
push the liquid to the surface is
reduce due to pressure losses in the

•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
            What is the Artificial Lift?
•Initially the reservoir pressure may be
sufficient 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

•The methods use to recover the oil is
called “artificial lift”.

The two types of artificial lift systems use are:
   Gaslift Systems
   Pumping Systems

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
   The vertical height of the column
   The density of the fluid
   The tubing head pressure

•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.
Gradients are
represented on a
diagram or graph of
pressure against

The figure shows the
pressure/depth graph of
fresh water. The gradient
is a straight line and the
pressure at any depth can
be read off at the bottom.
A well filled with fluid
will have a pressure
increase from the surface
to the bottom.
            Flowing Pressure Gradient
When oil, gas and water flow up the tubing there will still be a
pressure gradient. The gradient in multiphase flow situation
depends 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.
  Artificial Lift methods used in BSP

The methods of artificial lift used in BSP are:

   Sucker rod or Beam Pumping
   Electrical Submersible Pump

The technique of increasing the flowing life of a well by
the injection of gas into the tubing is known as gaslift.

   There are two methods of gaslift:

          1) Continuous gaslift
          2) Intermittent 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
•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.

•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 can
inject the gas down to the deepest point of the well but
there are limitations to this.

•To determine this limitations, an example is illustrated
based on the pressure depth graph.
A vertical well is 10,000 feet deep. The tubing is filled with a
liquid 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
The two lines will intersect at a depth
of 3333 feet.
    At 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.
    At 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 maximum
depth 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.
                         KICK OFF
•Kick off is a technique whereby gas is injected through a
number of injection points in turn. This technique will be able to
deepen 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 greater
length 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.
              GASLIFT VALVES

A gaslift valve is like a pressure regulator. Its
function is to admit gas from the annulus to
tubing as required. Wireline retrievable gaslift
valves are normally located in the “side pocket
                  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.
Gaslift is a flexible system and can be applied in a number of
    To artificially lift wells which will not flow naturally
    To kick off or unload wells
    To increase production rates in naturally flowing wells
    It is flexible and can be designed to operate over a wide range of
    changing well conditions
    Poses fewer problems in highly deviated wells
    No moving parts downhole
    There must be an economically available supply of gas.
    Gas compression facilities may be required
    Casing and wellhead equipment must be able to withstand the
    applied pressure
    Gaslift is not so efficient for high viscosity oils
                      GASLIFT SYSTEM

A typical gaslift system comprises the following components:

    (a) A source of high pressure gas (compressor or
    (b) Distribution lines to bring the gas to the wellhead.
    (c) Surface controls.
    (d) Subsurface controls (gaslift valves).
    (e) Flow lines.
    (f) Separation equipment.
    (g) Storage facilities.
    (h) Flow measuring equipment.
                   BEAM PUMPING
•The 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 the
sucker 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.
                 BEAM PUMPING UNITS

In BSP there are two different types of Beam Pumping Units,
the Conventional Unit and the Air-balanced Unit

   Conventional 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 the
crank causes the walking beam to pivot about the centre bearing.
              BEAM PUMPING UNITS

   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 piston
inside 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.

Air-balanced Unit
The rod string is lifted by
means of a cable (bridle)
looped over the horsehead
and connected to the top
member of the rod string
which is called polished rod,
by the carrier bar and
polished      rod     clamp.
Pumping well pressure is
sealed, or packed off, inside
the tubing to prevent
leakage of liquid and gas
past the polished rod. This
seal is called the stuffing
                     FMC PACKINGS
•Le Grand packings are being slowly changed to FMC packings
complete with flapper valve and single block FMC 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

• 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 tubing
string connecting the subsurface pump to the pumping unit.

•Sucker-rods are joined by sucker-rod couplings or by box-pin
Subsurface sucker-rod pumps are cylindrical, reciprocating, positive displacement pumps
that lift liquid from the well to the surface. They are divided into two general types:

    Rod pumps.
    Tubing pumps.
                  SUBSURFACE PUMPS

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 forced
from the barrel through the plunger and into the tubing. Fluid
is lifted toward the surface with each repeated upstroke.

•Plungerlift is a special method of gaslift, as
reservoir pressures in the Seria Field since
continuous gaslift has become increasingly
•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 wax
•Plungerlift is a suitable alternative.


•Plungerlift consists of a plunger cycling up and down the
production tubing, carrying, in each cycle, a slug of produced

•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.

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