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1. 3. Artificial Lift System

2. Introduction
 Why is Artificial Lift Needed?
• Well quit
• Fluid Column no longer reaches the surface
• Production declines with depletion of reservoir
energy
• Water cut increases
• Maximize production from naturally flowing wells
 Note that this is different from gas injection for
pressure maintenance
• Injection of gas or water into reservoir to maintain
reservoir pressure
• Improve recovery

3. Types of Artificial lift
 Gas lifting
 Continuous
 Intermittent
 Plunger lift
 Chamber lift
 Rod pumping
 Electrical Submersible pumping
 Hydraulic/Jet pumping
 Progressive Cavity pumping

4. Rod Pumps

5. Beam Pumping/Sucker Rod
Pumps (Rod Lift)
 This type of artificial lift utilizes a positive
displacement pump that is inserted or set in
the tubing near the bottom of the well. The
pump plunger is connected to surface by a
long rod string, called sucker rods, and
operated by a beam unit at surface. Each
upstroke of the beam unit lifts the oil above
the pump’s plunger

6. Beam Pumping/Sucker Rod
Pumps Advantages
 High system efficiency
 Optimization controls available
 Economical to repair and service
 Positive displacement/strong drawdown
 Upgraded materials can reduce corrosion
concerns
 Flexibility -- adjust production through stroke
length and speed
 High salvage value for surface unit and
downhole equipment

7. Beam Pumping/Sucker Rod
Pumps Disadvantages
 Limited to relatively
low production
volumes, less than
1,000 barrels per day.

8. Progressing Cavity Pumps
(PCP Pumps)
 Progressing Cavity Pumping (PCP) Systems
consist of :
- surface drive
- drive string
- downhole PC pump.
The PC pump is comprised of a single helical-
shaped rotor that turns inside a double helical
elastomer-lined stator. The stator is attached to
the production tubing string and remains stationary
during pumping.

9. PCP PUMP ADVANTAGES
 Low capital investment
 High system efficiency
 Low power consumption
 Pumps oils and waters with solids
 Pumps heavy oils
 No internal valves to clog or gas lock
 Quiet operation
 Simple installation with minimal maintenance costs
 Portable, lightweight surface equipment
 Low surface profile for visual and height sensitive areas

10. PCP PUMP DISADVANTAGES
 Limited lift capabilities
(approximately 7,000 ft.
maximum)

11. Electric Submersible Pumps
(ESPs)
 Electric Submersible
Pumping (ESP) Systems
incorporate an electric motor
and centrifugal pump unit run
on a production string and
connected back to the
surface control mechanism
and transformer via an
electric power cable.

12. ESP ADVANTAGES
 High volume and depth capacity
 High efficiency over 1,000 BPD
 Low maintenance
 Minimal surface equipment requirements
 High resistance to corrosive downhole environments
 Use in deviated wells and vertical wells with doglegs
 Adaptable to wells with 4 1/2" casing or larger
ESP DISADVANTAGES
 Poor ability to pump sand

13. Subsurface Hydraulic Pumps
 Hydraulic Lift Systems
consist of a surface
power fluid system, a
prime mover, a surface
pump, and a downhole
jet or reciprocating/piston
pump.

14. HYDRAULIC LIFT SYSTEM
ADVANTAGES
 Jet Lift
- No moving parts
- High volume capability
- "Free" pump
- Multiwell production from a single package
- Low pump maintenance
 Piston Lift
- "Free" or wireline retrievable
- Positive displacement-strong drawdown
- Double-acting high-volumetric efficiency
- Good depth/volume capability (+15,000 ft.)

15. HYDRAULIC LIFT SYSTEM
DISADVANTAGES
 High initial capital cost
 Complex to operate
 Only economical where
there are a number of
wells together on a pad.
 If there is a problem with
the surface system or
prime mover, all wells
are off production.

16. Plunger Lift

17. Gas Lift

18. Gas lift Principles
 The injected gas aerates the fluid column and reduce
the density of the fluid
 As the gas moves up the tubing, it expands
providing the scrubbing action to bring the fluid
column to surface
 With the density of the column reduced, less
reservoir pressure is required to push the liquid to
surface.
 In other words the hydrostatic back pressure to the
reservoir is reduced and the reservoir pressure can
overcome this reduced pressure and initiates the
well to flow.

19. To recap we use gas lift …
 To enable the well that will not flow
naturally to produce
 To increase production rates in natural
flowing wells
 To kick off wells that will later flow
naturally
 To remove or unload fluids from gas
wells.

20. Advantages of Gas lift
 Initial down hole equipment costs lower
 Low operational and maintenance cost
 Simplified well completions
 Can best handle sand / gas / deviated wells
 Flexibility, can handle high rates and high
gas oil ratio wells
 Intervention relatively less expensive
 Can be use offshore, small foot print needed
at the well head
 Electrical power not needed at well head

21. Disadvantages of Gas lift
 Must have a source of gas
 Imported gas from other fields may result in start up
problems
 Possible high installation cost
 Top sides modifications to existing platforms
 Compressor installation
 Limited by available reservoir pressure and bottom hole
flowing pressure
 Significant effort required to operate effectively
 Quite inefficient
 Much of the industry expertise has been (is been) lost

22. Gas lifting Method -
Continuous
 Continuous flow is similar to natural flow and is achieved by
controlling the injection of gas into the fluid column to cause aeration
from the point of injection
 Advantages:
 Take full advantage of the gas energy available in the reservoir.
 Higher production volume
 Equipment can be centralized
 Valves can either be wireline or tubing retrieved
 Disadvantages:
 Must have a continuous source of gas.
 Rates to be above 150 bpd for efficient lifting.
 Bottom hole producing pressure increases both with depths and
volume

23. Gas lifting Method -
Intermittent
 Intermittent flow is by injecting gas of sufficient volume and pressure into
tubing beneath a fluid column to lift liquid to the surface, this usually require
high gas rate to reduce the liquid fallback. The liquid to surface is in slug or
piston form.
 Advantages:
 Can obtain lower producing bottom hole pressure than continuous flow
and at low rates.
 Suitable for well with production below 150 bpd (low P.I wells)
 Can remedy wax deposition in tubing for waxy crud
 Disadvantages:
 Limited in volume.
 Causes surge on surface equipment.
 Equipment must be design to handle the surge.
 Cause interruption to other flowing wells in the production system
 Possible sand production for unconsolidated sands

24. Injecting gas into the well reduces weight of the fluid
column and consequently reducing the flowing bottom hole
pressure. (Optimal production)
Increasing in gas injection causes increase in the frictional
losses in the tubing thus offsetting the reduction of weight in
the fluid column
Pwf
Qliq
500
1900
1600
2000 2200
Optimal injection
point
Non Optimal lifting
1500
Pwf = 1600 psig
Q1 =2000 b/d
Inj. Gas = 1mscf/d
Pwf = 1500 psig
Q1 =2200 b/d
Inj. Gas = 2mscf/d
Produced Fluid + Lift Gas
Gas lifting (IPR Curve)

25. A well’s ability to produce fluid
is related to
a reduction in bottom hole pressure
WELL PRODUCTIVITY

26. WELL PRODUCTIVITY
Required Data
 Static Bottom Hole Pressure
 Pressure in the wellbore at the perforations under no-
flow conditions
 SBHP, Pr, Ps
 Flowing Bottom Hole Pressure
 Pressure in the wellbore at the perforations with the
well producing at a given rate
 FBHP, Pwf , Pf
 Drawdown
 Change in pressure from static to flowing
 SBHP-FBHP = dP
 Fluid Rate
 Well test performed while running FBHP survey = Q

27. PRODUCTIVITY INDEX
One way to quantify a well’s productivity is to
use a relationship known as:
Productivity Index (P.I.)
a straight line relationship between production rate
and drawdown (rate and pressure)

28. Simple Calculation!
Productivity Index
PI = BLPD / dP
Drawdown
dP = BLPD / PI
Liquid Rate
BLPD = dP * PI
PRODUCTIVITY INDEX

29. How to select Artificial lift
Method?

30. How to select
Artificial lift
Method?

31. How to select Artificial lift
Method?

32. Summary (How to Select
Artificial Lift?)

33. Economics of Artificial Lift
 The features, benefits and limitations of one artificial lift
method are relative to those of the other methods under
consideration. Each method should be evaluated from the
standpoint of comparative economics. Brown (1980) lists six
critical bases of comparison:
Initial capital cost
 Monthly operating expense
 Equipment life
 Number of wells to be lifted
 Surplus equipment availability
 Expected producing life of well(s)

34. Gas Lift System Overview

35. IPR Curve
 Productivity Index - J - The ratio of the
production rate of a well to its drawdown
pressure (bpd/psi)
 Drawdown Pressure -Δp- The pressure
drop between the reservoir ( Pe) and the
flowing bottom hole pressure (Pw).

36. Decline Curve
 Decline Curves that plot flow rate vs. time
are the most common tools for forecasting
production and monitoring well performance
in the field.
 The most common forms are daily flow rates
vs. the month. Water and gas rates are
commonly plotted along with the oil rate, or
GOR and WOR. Cumulative production vs.
the months is also very common, both oil and
water can be plotted.

37. Decline Curve
 These plots are plotted both on linear plots
and semi-log plots with the q on the log scale.
Type of Decline Curve
 Exponential Decline
 Hyperbolic Decline
 Harmonic Declines

38. Productivity Index
 Ideally Pw for a Q is measured using a
bottom hole pressure gauge. A build up or
drawdown test is used to calculate Pe along
with other parameters such as a skin factor
(S).
)
( Pw
Pe
Q
PI



39. Productivity Index
Using Radial flow equation
Which gives
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Q
Pw
Pe
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J
rw
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B
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ln(
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

40. END