Artificial lift overview with full description for the used methods. The function and the objective of each component for each artificial lift mean is described.

1. SABRATHA UNIVERSITY
Faculty of Engineering
Chemistry & Petroleum Department
Production II
PTE 473
Lecture Presentation
Prepared by: Ibrahim Hrari
Autumn 2018

2. CHAPTER (1)
Introduction to Artificial Lift

4. Field Production Phases
The production of crude oil in oil reservoirs can include up to three distinct phases:
primary, secondary, and tertiary recovery.
 During primary recovery, the natural pressure of the reservoir, combined with
pumping equipment, brings oil to the surface. Primary recovery is the easiest and
cheapest way to extract oil from the ground. But this method of production typically
produces only about 10 percent of a reservoir's original oil in place reserve.
 In the secondary recovery phase, water or gas is injected to displace oil, making it
much easier to drive it to a production well bore. This technique generally results in
the recovery of 20 to 40 percent of the original oil in place.
 When companies talk about enhanced oil recovery, they're really referring to the
tertiary recovery phase. Tertiary recovery involves injecting other gases, such as
carbon dioxide, to stimulate the flow of the oil and to produce remaining fluids that
were not extracted during primary or secondary recovery phases.
 These methods are not used routinely because they are expensive. When the price
of oil increases, there is greater incentive to use them and thus increase, to some
degree, the proven reserves of oil.
 The amount of oil that is recoverable is determined by a number of factors
including the permeability of the rocks, the strength of natural drives (the gas present,
pressure from adjacent water or gravity), and the viscosity of the oil.

5. Primary Recovery
Primary recovery includes:
1) Natural Flow
Because oil, gas and water in underground are under a lot of pressure at first, these fluids
flow up a wellbore all by themselves, much like a soft drink that has been shaken up.
When oil and gas are produced this way, it is called Natural Flow.
These wells are characterized by:
 (PWF > Sum of ΔP losses occurring along the flow path to the surface.)
 Out flow (VLP) intersects with inflow (PI/IPR).

6.  When the above criterion is not met, wells
stop flowing naturally and die.
 Causes that cause wells to die:
1) Pwf drops to a level at which it is no
longer sufficient to overcome ΔP
losses. This drop of Pwf is as a result of
reservoir pressure decline due to the
removal of fluids from the reservoir.
2) Mechanical problems such as:
 very small tubing size, downhole
restrictions, etc.
 Change in flowing fluid properties
(increase in WC or decrease in
GLR.)
 Surface conditions (Sep. pressure,
flow line size).

7.  As a result there will be no intersect between the inflow (PI or IPR curve) and the
outflow (through tubing) which means such well cannot produce naturally at any
flow rate, as in the following figure.
Pressure available from reservoir VS pressure required.
 At this stage, a suitable artificial lift technique is used to bring such wells back to
production.

8. 2) Artificial Lift:
It refers to the use of artificial means to bring dead wells back to production or to
increase the flow rate of naturally flowing wells. Generally, this is achieved
mechanically by using a suitable pump type or by decreasing the weight of the
hydrostatic column of the fluid by injecting gas into the fluid some distance down the
well.

9. Introduction to Artificial Lift

10. Introduction to Artificial Lift
Lift Technology By Lift Capacity

11. Gas lift involves injecting high-pressure gas from the
surface into the producing fluid column through one or
more subsurface valves set at predetermined depths
Introduction to Artificial Lift
Gas Lift

12. There are two main types of gas lift:
Continuous gas lift, where gas is injected in a constant, uninterrupted stream. This
lowers the overall density of the fluid column and reduces the hydrostatic
component of the flowing bottomhole pressure. This method is generally applied to
wells with high productivity indexes.
Intermittent gas lift, which is designed for lower-productivity wells. In this type of gas
lift installation, a volume of formation fluid accumulates inside the production tubing.
A high-pressure “slug” of gas is then injected below the liquid, physically displacing
it to the surface. As soon as the fluid is produced, gas injection is interrupted, and
the cycle of liquid accumulation-gas injection-liquid production is repeated.
Introduction to Artificial Lift
Gas Lift

13. • Advantages: Gas lift can be used in deviated or crooked wellbores, and in high-
temperature environments that might adversely affect other lift methods, and it is
conducive to maximizing lift efficiency in high-GOR wells. Wireline-retrievable gas lift
valves can be pulled and reinstalled without pulling the tubing, making it relatively
easy and economical to modify the design.
• Disadvantages: the availability of gas and the costs for compression and injection
are major considerations. Lift efficiency can be reduced by corrosion and paraffin.
Another disadvantage of gas lift is its difficulty in fully depleting low-pressure, low-
productivity wells. Also, the start-and-stop nature of intermittent gas lift may cause
downhole pressure surges and lead to increased sand production.
Introduction to Artificial Lift
Gas Lift

14. • Downhole pumps are used to increase pressure at the bottom of the tubing string by
an amount sufficient to lift fluid to the surface. These pumps fall into two basic
categories: positive displacement pumps and dynamic displacement pumps.
• A positive displacement pump works by moving fluid from a suction chamber to a
discharge chamber. This basic operating principle applies to reciprocating rod
pumps, hydraulic piston pumps and progressive cavity pumps (PCPs).
• A dynamic displacement pump works by causing fluid to move from inlet to outlet
under its own momentum, as is the case with a centrifugal pump. Dynamic
displacement pumps commonly used in artificial lift include electrical submersible
pumps (ESPs) and hydraulic jet pumps.
Introduction to Artificial Lift
Pump-Assisted Lift

15. Beam pumping is the most common artificial lift
method. It can be used for a wide range of
production rates and operating conditions, and rod
pump systems are relatively simple to operate and
maintain. However, the volumetric efficiency
(capacity) of a rod pump is low. its initial
installation may involve relatively high capital
costs. Its application is very limited for deep,
inclined and horizontal wells.
Introduction to Artificial Lift
Pump-Assisted Lift – Reciprocating Rod Pump

16. As the rotor turns, cavities between the rotor and
stator move upward.
Progressive cavity pumps are commonly used for
dewatering coalbed methane gas wells, for
production and injection applications in waterflood
projects and for producing heavy or high-solids oil.
They are versatile, generally very efficient, and
excellent for handling fluids with high solids content.
However, because of the torsional stresses placed on
rod strings and temperature limitations on the stator
elastomers, they are not used in deeper wells.
Introduction to Artificial Lift
Pump-Assisted Lift – PCP

17. • Hydraulic pump systems use a power
fluid usually light oil or water—that is
injected from the surface to operate a
down hole pump. Multiple wells can be
produced using a single surface power
fluid installation
Introduction to Artificial Lift
Pump-Assisted Lift – Hydraulic Pump

18. With a reciprocating hydraulic pump, the injected power fluid operates a downhole fluid
engine, which drives a piston to pump formation fluid and spent power fluid to the
surface.
A jet pump is a type of hydraulic pump with no moving parts. Power fluid is injected into
the pump body and into a small-diameter nozzle, where it becomes a low-pressure,
high-velocity jet. Formation fluid mixes with the power fluid, and then passes into an
expanding-diameter diffuser. This reduces the velocity of the fluid mixture, while causing
its pressure to increase to a level that is sufficient to lift it to the surface
Introduction to Artificial Lift
Pump-Assisted Lift – Hydraulic Pump
• Used at depths from 1000 to 17,000 feet and are capable of producing at rates from
100 to 10,000 B/D. They can be hydraulically circulated in and out of the well, thus
eliminating the need for wireline or rig operations to replace pumps and making this
system adaptable to changing field conditions. Another advantage is that heavy,
viscous fluids are easier to lift after mixing with the lighter power fluid.
• Disadvantages of hydraulic pump systems include the potential fire hazards if oil is
used as a power fluid, the difficulty in pumping produced fluids with high solids
content, the effects of gas on pump efficiency and the need for dual strings of tubing
on some installations.

19. An electric submersible pumping (ESP) assembly
consists of a downhole centrifugal pump driven by a
submersible electric motor, which is connected to a
power source at the surface
 Advantages:
• The most efficient lift methods on a cost-per-barrel
basis.
• High rate: 100 to 60,000 B/D, including high water-
cut fluids.
• Work in high-temperature wells (above 350°F) using
high-temperature motors and cables.
Introduction to Artificial Lift
Pump-Assisted Lift – ESP

20. • The pumps can be modified to lift corrosive fluids and sand.
• ESP systems can be used in high-angle and horizontal wells if placed in straight
or vertical sections of the well.
• Disadvantages:
• ESP pumps can be damaged from “gas lock”. In wells producing high GOR fluids,
a downhole gas separator must be installed.
• ESP pumps have limited production ranges determined by the number and type of
pump stages; changing production rates requires either a pump change or
installation of a variable-speed surface drive.
• The tubing must be pulled for pump repairs or replacement.

21. Artificial lift considerations should ideally be part of the well planning process.
Reservoir Characteristics
Future lift requirements will be based on the overall reservoir exploitation strategy, and
will have a strong impact on the well design. Some of the key factors that influence
the selection of an artificial lift method.
• IPR: A well’s inflow performance relationship defines its production potential
• Liquid production rate: The anticipated production rate is a controlling factor in
selecting a lift method; positive displacement pumps are generally limited to rates of
4000-6000 B/D.
• Water cut: High water cuts require a lift method that can move large volumes of fluid
• Gas-liquid ratio: A high GLR generally lowers the efficiency of pump-assisted lift
Introduction to Artificial Lift
Artificial Lift selection considerations

22. • Viscosity: Viscosities less than 10 cp are generally not a factor in selecting a lift
method; high-viscosity fluids can cause difficulty, particularly in sucker rod
pumping
• Formation volume factor: Ratio of reservoir volume to surface volume
determines how much total fluid must be lifted to achieve the desired surface
production rate
• Reservoir drive mechanism: Depletion drive reservoirs: Late-stage production
may require pumping to produce low fluid volumes or injected water.
• Water drive reservoirs : High water cuts may cause problems for lifting systems
• Gas cap drive reservoirs : Increasing gas-liquid ratios may affect lift efficiency.
Introduction to Artificial Lift
Selecting an Artificial Lift Method – Reservoir Characteristics

23. • Well depth: The well depth dictates how much surface energy is needed to move
fluids to surface, and may place limits on sucker rods and other equipment.
• Completion type: Completion and perforation skin factors affect inflow performance.
• Casing and tubing sizes: Small-diameter casing limits the production tubing size
and constrains multiple options. Small-diameter tubing will limit production rates, but
larger tubing may allow excessive fluid fallback.
• Wellbore deviation: Highly deviated wells may limit applications of beam pumping
or PCP systems because of drag, compressive forces and potential for rod and
tubing wear.
Introduction to Artificial Lift
Selecting an Artificial Lift Method – Hole Characteristics

24. • Flow rates: Flow rates are governed by wellhead pressures and backpressures in
surface production equipment (i.e., separators, chokes and flowlines).
• Fluid contaminants: Paraffin or salt can increase the backpressure on a well.
• Power sources: The availability of electricity or natural gas governs the type of
artificial lift selected. Diesel, propane or other sources may also be considered.
• Field location: In offshore fields, the availability of platform space and placement of
directional wells are primary considerations. In onshore fields, such factors as noise
limits, safety, environmental, pollution concerns, surface access and well spacing
must be considered.
Introduction to Artificial Lift
Selecting an Artificial Lift Method – Surface Characteristics

25. • Long-range recovery plans: Field conditions may change over time.
• Pressure maintenance operations: Water or gas injection may change the artificial
lift requirements for a field.
• Enhanced oil recovery projects: EOR processes may change fluid properties and
require changes in the artificial lift system.
• Field automation: If the surface control equipment will be electrically powered, an
electrically powered artificial lift system should be considered.
• Availability of operating and service personnel and support services: Some
artificial lift systems are relatively low-maintenance; others require regular monitoring
and adjustment. Servicing requirements (e.g., workover rig versus wireline unit)
should be considered. Familiarity of field personnel with equipment should also be
taken into account.
Introduction to Artificial Lift
Selecting an Artificial Lift Method – Field Operating Characteristics

26. A Comparison Table Showing the Relative Strength of Artificial
Lift Systems

27. Part (I): ESP System

28. ESP Service Providers
 Schlumberger-REDA
 Centrilift – Baker Hughes
 Weatherford
 Wood Group ESP
 ALNAS (Russia)
ESP System
ESP system can be divided into surface
components and downhole components.
 Surface Components:
Transformers
Motor controller Switchboard of
Variable Speed Drive (VSD) or Soft
Start
Junction Box
Cable Venting box
Wellhead
 Downhole Components:
Cable
Cable Guard
Cable Clamps
Pumps
Gas Separator
Seal Section
Motor
Sensor- Data Acquisition
Instrumentation
Drain Valve
Check Valve

29.  Pump Stage
Each stage consists of a rotating impeller and stationary diffuser.
 Impeller in a diffuser
Mixed flow stages
Radial flow stages
Impeller Diffuser

30.  Fluid enters impeller through ‘eye’ near shaft and exits
impeller on outer diameter (OD)
 Diffuser (in blue) redirects fluid into next impeller
Cut-away view of two impellers and diffusers
By stacking impellers and diffusers (multi-staging),
desired lift (TDH-Total Dynamic Head) is achieved

31.  Intake: used when up to 10% free gas at
Pump Intake
Gas dealing devices used in applications
where free gas causes interference with pump
performance:
 Gas Separator: 35% Free Gas at pump
intake
 AGH: 50% Free Gas at pump intake
 Poseidon: 75% Free Gas at pump intake
Homogenizer
(AGH/Poseidon)
Gas Separator
 Pump Intake / Gas dealing devices

32. Protector is installed with ESP to serve the following
functions:
1) Protects motor from contamination by well fluid
2) Absorbs thrust from pump
3) Equalizes pressure between wellbore and motor
 Protector/ seal section

33. There are different types of cables available
in the industry. These include;
 Round Cables
 Flat Cables
Number of conductors also varies from 1,2,4
etc…depending on company. Cables also
vary depending on the type of insulation
based on the working environment, there are
special cable insulation for corrosive fluids
and severe environments.
 Electric power cable

34.  Check valve is located about 2 or 3 joints above the pump
assembly to maintain a full column of fluid above the pump and
to prevent the fluid from return to the formation during shut
down period that cause pump rotate in a reveres rotation, so
when start again need more motor voltage (more power to rotate
the pump stages), which can result in a motor burn and broken
shaft
 Pleader/Drain valve: Usually Located immediately above the
check valve (about 2 joint above the check valve) to prevent
pulling a wet tubing string If a check valve is not run and the
well has no sand problems, there is no reason to run a bleeder
valve as the fluid in the tubing will drain through the pump
while pulling.
 Check and Drain valves

35.  Optional Equipment
 Motor Shroud:
With a shroud, the unit can be set in or below the
perforation. Shroud can serve two purposes:
1) Direct fluid past the motor for cooling.
Allow free gas to separate from the fluid before entering the
pump intake
 Centralizers:
used to center the motor and pump for proper cooling and
prevent cable damage due to rubbing

36.  Y-Tool:
Is a special tool run with ESP to allow for
running bottom hole pressure survey and
production logging tool during the pump
operation down
 Multi sensor:
Used to obtain:
 Bottom hole pressure.
 Bottom hole temperature.
 Cable current leakage.
 Motor temperature.
 Motor vibration.
 Intake pressure