Artificial Lift

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Artificial Lift

• By Sekar
• Learning Advisor - Process

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TRAINING TARGETS

• The aim of this section is to help you gain a
  working knowledge of the 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 to push 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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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 production.
• The methods use to recover the oil is called
  artificial lift.

• The two types of artificial lift systems use are
• Gaslift Systems
• Pumping 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
• The vertical height of the column
• The density of the fluid
• The tubing head pressure

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PPTF

• 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.

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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 can be 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 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.
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Artificial Lift methods used in BSP

• The methods of artificial lift used in BSP are
• Gaslifting
• Sucker rod or Beam Pumping
• Plungerlift
• Electrical Submersible Pump

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GASLIFT
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
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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 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.

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DEPTH OF GAS INJECTION
Example 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
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DEPTH OF GAS INJECTION

• 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.

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• 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.

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KICK OFF
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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 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 OF GASLIFT
• Gaslift is a flexible system and can be applied
  in a number of situations
• To artificially lift wells which will not flow
  naturally
• To kick off or unload wells
• To increase production rates in naturally flowing
  wells
• ADVANTAGES
• 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
• DISADVANTAGES
• 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

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• GASLIFT SYSTEM
• A typical gaslift system comprises the following
  components
• (a) A source of high pressure gas (compressor or
  gaswell).
• (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.

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GASLIFT SYSTEM
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• 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.

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• 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.

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BEAM PUMPING UNITS
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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.

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BEAM PUMPING UNITS
Air-balanced Unit
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BEAM PUMP OPERATION
STUFFING BOX
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
box.
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• 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 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 tubing string 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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FMC PACKINGS
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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.
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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 wax problems.
• Plungerlift is a suitable alternative.

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PLUNGERLIFT
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PLUNGERLIFT

• 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.