Petroleum Artificial Lift Overview

2. i
FOREWORD
This book, with named PETROLEUM ARTIFICIAL LIFT OVERVIEW is an
overview of petroleum Artificial Lift, describes Reservoir Production Cycle, Natural
Lift & Artificial Lift, Natural Lift & Artificial Lift, Reservoir Underbalanced and over
balanced Conditions, and Natural Lift Condition, The Main Lift Obstacles, Artificial Lift
Function. The Artificial Lift Systems such The Sucker-Rod Pumping System, Diagram,
Component and Process, The Down Stroke - The Up Stroke, Changing Pressures, The
Fluid Level, The Main Ways to Adjust Pumping Rates, Pump Off Controllers, Free
Gases. Then Gas Lift consist of Advantages & Disadvantages, The Gas Lifts Assembly,
The Mandrels, Gas Lift Process, Other Configurations Gas lift, and ESP (Electric
Submersible Pumping), Also Other Types of Artificial Lift such The Power Oil Systems,
PCP (Progressing Cavity Pumps), Plunger Lift, and Finally Hydraulic or Jet Pump in
common.
This book also describe generally about selecting An Artificial Lift Method such
selecting An Artificial Lift based on Reservoir Characteristics, Hole Characteristics,
Surface Characteristics, and Field Operating Characteristics.
Suggestions and constructive criticism is expected in the preparation of the next
book about Overview petroleum industry.
September, 2018
A. ANRIANSYAH

3. ii
TABLE OF CONTENTS
FOREWORD............................................................................................................................... ¡
TABLE OF CONTENTS.............................................................................................................. ¡¡
1. INTRODUCTION.......................................................................................................................1
1.1 Reservoir Production Cycle...............................................................................................1
1.2 Natural Lift & Artificial Lift...................................................................................................2
1.3 The Type Of Artificial Lift...................................................................................................3
1.4 Reservoir Underbalanced Conditions................................................................................4
1.5 Natural Lift Condition.........................................................................................................6
1.6 The Main Lift Obstacles.....................................................................................................7
1.7 Artificial Lift Function........................................................................................................10
2. ARTIFICIAL LIFT SYSTEMS..................................................................................................14
2.1 The Sucker-Rod Pumping System..................................................................................14
2.1.1 The Sucker-Rod Pumping Surface Diagram..........................................................14
2.1.2 The Down Stroke - The Up Stroke..........................................................................16
2.1.3 The Sucker-Rod Pumping Subsurface Diagram.....................................................17
2.1.4 The Sucker Rods Pump Component and Process.................................................18
2.1.5 Changing Pressures...............................................................................................24
2.1.6 The Fluid Level.......................................................................................................25
2.1.7 The Main Ways to Adjust Pumping Rates..............................................................26
2.1.8 Pump Off Controllers..............................................................................................27
2.1.9 Free Gases.............................................................................................................29
2.2 Gas Lift............................................................................................................................32
2.2.1 Gas Lift Disadvantages...........................................................................................32
2.2.2 Gas Lift Advantages...............................................................................................22
2.2.3 The Gas Lifts Assembly..........................................................................................35
2.2.4 The Mandrels..........................................................................................................36
2.2.5 Gas Lift Process.....................................................................................................40
2.2.6 Other Configurations Gas lift..................................................................................44
2.3 ESP (Electric Submersible Pumping)..............................................................................47
2.3.1 ESP Components...................................................................................................48
2.4 Other Types of Artificial Lift..............................................................................................49
2.4.1 The Power Oil Systems..........................................................................................49
2.4.2 PCP (Progressing Cavity Pumps)...........................................................................50
2.4.3 Plunger Lift..............................................................................................................51
2.4.4 Hydraulic or Jet Pump............................................................................................53
3. SELECTING AN ARTIFICIAL LIFT METHOD........................................................................57
3.1 Reservoir Characteristics.................................................................................................58
3.2 Hole Characteristics.........................................................................................................58
3.3 Surface Characteristics....................................................................................................58
3.4 Field Operating Characteristics.......................................................................................58
4. CONCLUSION .......................................................................................................................58
REFERENCES............................................................................................................................61

4. 1
1. INTRODUCTION
With the time frame for the field appraisal and field development are
completed, and then we are now ready to produce the well. Here it is important to
remember that the steps we take the procedures we use throughout these
process called recovery are vital in determining the present and a future
economic value of our preproduction well.
1.1 Reservoir Production Cycle
As we know from reservoir performance, recovery is the controlled
process of bringing tracked hydrocarbon to the surface. since it is impossible to
commercially produced 100% (one hundred percent) of these trap hydrocarbons,
with present technology good engineering practices dictate that we utilized
different recovery methods both natural and man-made (Artificial) over different
time periods throughout a reservoir production cycle (Pic. 001).
Pic. 001. Reservoir production cycle
In other words the term recovery is used to describe any and all methods
using either natural or man-made (Artificial) energy sources that force the oil and
gas to the surface in a controlled flow that can be captured (Pic. 002).

5. 2
Pic. 002. Natural and man-made (Artificial) energy
1.2 Natural Lift & Artificial Lift
We begin with a discussion of the two sources of energy used in the initial
and subsequent stages of recovery. The first source most commonly used in
recovery is natural, and is called natural lift (Pic. 003). The second source is
man-made and is called artificial lift (Pic. 004).
Pic. 003. Natural lift

6. 3
Pic. 004. Artificial lift
1.3 The Type of Artificial Lift
Defining natural lift and then describing when and why this natural lift
might decrease and be supplemented with artificial lift, this book outlines and
highlights three different type artificial lift and mentions several others that are
used less frequently (Pic. 005). It concludes, with label diagrams of three of the
most popular systems with detail explanations to show how each functions and
why it is selected for its location and production requirements (Pic. 006).
Pic. 005. The type artificial lift

7. 4
Pic. 006. Three most popular artificial lift
1.4 Reservoir Underbalanced Conditions
So let's gets started recovery involved in the initial production stages of
many newly producing wells realized for the most part on the natural energy
present inside the reservoir that was trapped there along with the hydrocarbon
molecules as the reservoirs was being created. In this newly trap reservoir the
pressure inside them is usually greater that at the surface in what is known as
underbalanced conditions (Pic. 007). When the reservoir is un kept, in
underbalanced condition a pressure differential from that inside the reservoir to
that at the surface causes the trapped energy along with the hydrocarbons to be
push to the surface in what is known as natural lift.
Pic. 007. Reservoir underbalanced conditions

8. 5
Let’s we look at an example that we are all familiar with that will help
illustrate what we are talking about, take a moment to visualized a column of a
carbonated leverage as it explodes upwards and out wards (Pic. 008). As we
know in general science the pressure inside the bottle is greater than on the
outside in under balance conditions, this pressure differential remains an
equilibrium only until the cap is removed, and removing the cap the pressure
differential releases energy from inside the bottle, it carries with it the carbonated
liquid that fuse up. The same thing happens inside the reservoir and this release
is known as natural lift.
Pic. 008. Underbalanced conditions carbonated bottle
In this illustration we see a hydrostatic head of a fluid column that
stretches from the surface through the reservoir, as the column deepens PSI is
increases about ½ psi/ft (one half psi per foot) of reservoir depth (Pic. 009), so if
this well were five 5,000 ft (five thousand feet) deep for example, the PSI at the
bottom of the well would be about 2,500 psi (twenty five hundred psi), if the
natural energy of the formation is more than 2,500 psi (two and a five hundred
psi) then the well will flow naturally in natural lift (Pic. 010).

9. 6
Pic. 009. Reservoir hydrostatic fluid column
Pic. 010. Natural lift
1.5 Natural Lift Condition
Know that the wells own its natural energy must be sufficient to not only
pushed liquid (oil and gas) to the surface it must also be enough so that the wells
own natural lift can overcome the hydrostatic bore hole pressure and the friction
created by the hydrocarbons moving up the tubing to the surface (Pic. 011). In
addition there must be sufficient energy to push these liquid or hydrocarbons
through the surface facilities (Pic. 012).

10. 7
Pic. 011. Natural energy overcome pressure, friction, pushes the liquids to surface
Pic. 012. Natural energy pushes the liquids to surface facilities
As we know initial recovery usually relies on natural lift, but like with the
carbonate soda bottle after the initial push the energy inside the reservoir made
dissipate and not be strong enough to continue natural lift.
1.6 The Main Lift Obstacles
What can cause naturally lift to slow down and fail? There are four main
obstacles, the first is encountered within the reservoir itself, as we might guess
the thicker more viscous the fluid the more energy is needed to overcome the
friction to push the fluid through the rock matrix to the wellbore (Pic. 013). Over
time this friction coupled with constriction that reduces the fluid volume can
cause the pressure and for near the wellbore to drop in what is known as
drawdown (Pic. 014). Drawdowns are accelerated when production rate rise and
when the fluids become more viscous.

11. 8
Pic. 013. Overcome the friction
Pic. 014. Constriction and pressure can fall
The second obstacle comes about in fields with denser oils and deeper
depth. The sheer volume of those heavier oils inside deep wells means that to
push these to the surface more energy is needed from the reservoir to lift that
added way to the surface (Pic. 015).

12. 9
Pic. 015. More energy is needed to lift
The third obstacle is specific to very deep wells with high flow rate, in
these wells just the movement of the fluid traveling up the long length of the
tubing and rubbing up against the inside tubing wall create significant friction
(Pic. 016), as the frictional force slows the oils upward movement more energy is
needed to ensure the flow of these fluids (Pic. 017).
Pic. 016. Friction the fluid traveling up of long length

13. 10
Pic. 017. The frictional force slows the oils upward
Finally the fourth obstacle is encountered at the surface having already
been pushed up through the tubing to the surface, the hydrocarbons must now
be pushed into and through the surface facilities that separate and clean them in
preparation for transport. This can require several hundred addition psi (Pic.
018).
Pic. 018. Pushed fluids through the surface facilities
1.7 Artificial Lift Function
When natural lift starts to falter or give out it can no longer be relied on to
get the trapped hydrocarbons to the surface and through the surface facilities.
When this happens the wells production begins to fall and then stops. When
production stops the well is said to have died (Pic. 019). Rise to should however
that when a well dies with commercial quantities of valuable resource is still traps
within the reservoir (Pic. 020), alternative method will be used to bring the well

14. 11
back into production. This is where artificial lift can supplement natural lift. its
here that artificial lift can bring the well back into production (Pic. 021).
Pic. 019. When production stops the well is said to have died
Pic. 020. The hydrocarbons still traps within the reservoir

15. 12
Pic. 021. Artificial lift bring the well back into production
Artificial lift is not limited to just supplementing natural lift used in primary
lift it can also be used to supplement EOR (enhanced oil recovery) when the
pressure in the reservoir falls to less than that at the surface (Pic. 022).
Pic. 022. Artificial lift supplement EOR
Regardless of the reasons for using artificial lift the main determine nerve
for the popularity and extensive use strapped the industry is this relatively low
cost.

16. 13
Artificial lift relay on three main systems, the first three will be examined in
some details (Pic. 023) the other two less lift systems will only be briefly
described (Pic. 024). the main systems are (1) sucker-rod pumping, (2) gas lift,
(3) ESP (electric submersible pumping) and the other less used systems are (4)
power oil, (5) PCP (progressing cavities pumps), (6) Plunger lift, (7) Hydraulic or
Jet Pump.
Pic. 023. First three main systems
Pic. 024. Several less lift systems

17. 14
2. ARTIFICIAL LIFT SYSTEMS
2.1 The Sucker-Rod Pumping System
Let’s begin with the sucker-rod pumping system, also known as the
nodding donkey. The sucker-rod pumping system is probably the most
recognizable peace of oil field equipment, used mostly and onshore fields,
because of their size and weight nodding donkey can easily be seen from many
of the major roads that across the countryside wherever hydrocarbons are being
produced.
2.1.1 The Sucker-Rod Pumping System Surface Diagram
The sucker-rod pumping system uses a surface power source to drive a
downhill pump assembly that generates artificial lift (Pic. 025). here's an example
of a working sucker-rod pump, all along his name the parts and show where each
is located, prime mover, V-belt, gear box, walking beam samson post, horse
head, sucker-rod and counterweights (Pic. 026).
Pic. 025. The sucker-rod pumping system

18. 15
Pic. 026. The sucker-rod pumping system surface diagram
The prime mover located here provides the power that operate the
pumping system, it's power source is usually an electric motors, but field gas
fired engine can also be used when there is no ready source of electricity (Pic.
027). The power from the prime mover is transmitted by the flexible v belt located
there (Pic. 026), the v-belt is attached to the pumping unit in the gearbox, note
here that at this point the motion is rotational, for sucker-rod pumping system to
work this rotational motion from the prime mover must be transformed into a
vertically reciprocated motion (Pic. 028). This transformation is performed by the
gears in the gearbox that is located there (Pic. 026), these gears are attached to
the back end of the walking beam located there (Pic. 026), the walking being
pivots on the samson post. As we can see instead of going around and around in
the rotation motions like the prime over, the walking beam with a horse head
attached to goes up and down in vertically reciprocated motion (Pic. 028).
Pic. 027. The prime mover

19. 16
Pic. 028. Rotational motion transformed into a vertically reciprocated motion
2.1.2 The Down Stroke - The Up Stroke
The sucker-rod is attached to the horse head that now goes up and down
as it travels in and out of the hole. The counterweights located there (Pic. 026),
distribute the power evenly over the up and down in strokes. On the down stroke
the weight of the dropping rods lifts the way to into position, and then on the up
stroke the weight drops lifting the rods and fluid column (Pic. 029).
Pic. 029. The down stroke - the up stroke
So far we have been looking at what is visible above the surface. from this
perspective basically all we can see is a device that converse rotational power
into a vertically reciprocate motion, this means that the sucker-rod attached to
the horse head move up and down, but what is going on down below, how does
the soccer red pumping system provide artificial lift? To answer these questions

20. 17
we need to follow the sucker-rods down into the hole into the subsurface (Pic.
030).
Pic. 030. The sucker-rods down into the hole
2.1.3 The Sucker-Rod Pumping System Subsurface Diagram
This diagram shows the components needed to provide artificial lift in a
sucker-rod pumping system, briefly starting at the horse head and moving down
ward, they are the horse head, the wellhead, the flow line, the tubing and the
pump (Pic. 031).

21. 18
Pic. 031. The components diagram sucker-rod pumping system
2.1.4 The Sucker Rods Pump Component and Process
As we can see the sucker rods are attached to the horse head. These
rods must be in strings long enough to reach from the highest upward position of
the horse head down to the bottom of the hole, where the pump is attached.
These sucker rods come in length of from 25 ft (twenty five feet) to 30 ft (thirty
feet) and the diameter from ½” (one half inch) to 1 1/8” (one and one per eight
inch) made of steel or fiberglass re-enforced by vinyl for corrosive applications,
each has screwed couplings so that the string can be made long enough to reach
the bottom of the well. Keep in mind that all those sucker-rod pumps can come in
many shapes and configurations. They are still run into the hole on a rod string
that latches into the tubing at the bottom of the hole (Pic. 032).

22. 19
Pic. 032. The sucker rods pump
The sucker rods up and down motion or reciprocation motion, strokes the
plunger up and down in the pump barrel. it is this pumping action that provides
the energy that helps lift that produced fluids up the tubing (Pic. 033). It help
provide lift by moving the fluid upward into the tubing 1 (one) stroke at a time
(Pic. 034), in essence each pumping stroke pushes a little more column of fluid
upward into the tubing, this continues as each pumping stroke pushes the ones
above it, until the fluid is pushed out of the well head and into the flow line. This
movement is contingent on the pump having enough energy to push the column
of fluid to the surface.

23. 20
Pic. 033. The sucker rods pumping process
Pic. 034. Lift the fluids - 1 (one) stroke at a time

24. 21
In this illustration we can see the components inside the pump. We have
the sucker rods, the ports, the tubing, the pump barrel, the pump plunger, the
traveling valve, the standing valve, and the seating nipple (Pic. 035). A pump
consists of two telescoping cylinders called the plunger and the barrel. In addition
there are two ball and seat valves (Pic. 036), the upper of most valve is called a
traveling valve, and valve at the bottom is the standing valve. The plunger fits
snugly inside the barrel with a metal to metal seal (Pic. 037).
Pic. 035. The components inside the pump
Pic. 036. A pump consists of plunger and the barrel, two ball and seat valves

25. 22
Pic. 037. The plunger fits snugly inside the barrel with a metal to metal seal
As we can see here the reservoir fluids enter the pump barrel from the
formation into the bottom of the borehole through perforations that have been
made through the casing and cement Cased hole well (Pic. 038). On the up
stroke, the standing valve at the bottom of the pump opens due to a drop in
pressure in the pump barrel, this open standing valve that allows the formation
fluid to fill the pump barrel (Pic. 039). As the barrel fills the plunger reaches it's
uppermost position and then start sits downward movement for its down stroke.
Pic. 038. Reservoir fluids enter the pump barrel (cased hole)

26. 23
Pic. 039. The up stroke - the formation fluid fill the pump barrel
In the down stroke the standing valve now closes which prevents anymore
formation fluid to flow into the barrel (Pic. 040). as the plunger descends through
the fluid in the barrel, the traveling valve opens, through this valves opening the
formation fluid that have been trapped in the barrel during the up stroke is now
swept up through the ports into the tubing and eventually up into the flow line on
the down stroke. Again when the plunger reaches it's uppermost height that
traveling valve closes and as the plunger begins it's downward movement, the
standing valve opens along the barrel to be filled.
Pic. 040. The down stroke prevents fluid flow into the barrel
These steps are repeated as the horse head moves up and down
pumping the oil to the surface.
Now that we've examine the sucker rod pump and shown how it works,
lets now turn our focused to ways that the pumping system hardware can be
adjusted, to optimize the hardware is efficiency as conditions changed over time.

27. 24
Here it is important to keep in mind that for this system to work well, the
amount of formation fluid flowing into the barrel should fill the barrel completely
when the standing valve is open, it should be roughly equivalent to the volume
that the plunger can push upward (Pic. 041).
Pic. 041. Fluid flowing into the barrel should fill completely
As we've mentioned earlier, when the reservoir pressure falls below the
wellhead pressure in onshore wells, the sucker-rod pumping system is the
favorite choice and providing artificial lift.
2.1.5 Changing Pressures
Changing pressures inside the reservoir however, whether decreasing as
the reservoir is produced or increasing during EOR (enhanced oil recovery)
processes means that it is more than to monitor and periodically changed the
pumping rates in artificial lift to adjust to these pressure changes (Pic. 042).
Pic. 042. Monitor and periodically changed the pumping rates

28. 25
Let’s go back to look at the sucker-rod pump as it captures fluid from a
reservoir. as already stated this reservoir fluid that enters the barrel when the
standing valves is open should be roughly equivalent to the amount that is a
pump upward through the traveling valve during enough stroke. In optimal
conditions the pumping system will live all that oil and interest from the wellbore
into the barrel of the pump when this standing valve is open.
2.1.6 The Fluid Level
As a rule of thumb the fluid level in the wells casing tubing annulus at the
wellbore should not rise any higher than at the pump (Pic. 043). What happens
though when optimal conditions are not present, what happens when there is too
much fluid or too little fluid? If too much reservoir fluid is present at the wellbore
and can't flow into the barrel fast enough where standing valve is open then this
fluid outside the barrel will back up and pushed up into the annulus (Pic. 044).
Pic. 043. Fluid level should not higher than at the pump
Pic. 044. If too much Fluid will back up and pushed up into the annulus

29. 26
This can impact the amount of oil entering the wellbore and caused
production to decrease. Likewise if there is too little oil, the pump barrel can't
completely fill with fluid (Pic. 045). This cause a liquid surface to be created
inside the barrel, so that when the plunger falls its slams or slaps into this liquid
surface, what is known as a fluid pound (Pic. 046). The shockwave created when
the plunger hits the liquid surface in this fluid pound can damage balls seats and
rods up and down the string.
Pic. 045. If there is too little oil, the pump barrel can't completely fill with fluid
Pic. 046. Slams or slaps into this liquid surface
2.1.7 The Main Ways to Adjust Pumping Rates
There are four main ways the pumping rates can be adjusted to avoid
excess of fluid rates or fluid pounds. Number one the size of the v-belt sheave or

30. 27
pulley on the gearbox can be either increased or decreased to change the
pumping unit strokes per minute. Number two a different hole in the pumping unit
crank can be used to change the length of the pumping stroke. Number three is a
smaller or larger diameter pump can be used. Number four a pump off controller
on the time clock that automatically turns and electric motors pumping unit on
and off and can be used to optimize pumping loads (Pic. 047).
Pic. 047. Four main ways to adjust pumping rates
2.1.8 Pump off Controllers
Pump off controllers automatically adjust to changing pressures within the
reservoir to optimize oil flow (Pic. 048). here in this example pump off controllers
sense the first tremors in a fluid pound and can therefor automatically shutoff
electric power to the pumping unit before any damage done, restarting again
after approximately 15 (fifteen) minutes, they can function until once again they
sense a problem (Pic. 049).

31. 28
Pic. 048. Pump off controllers function
Pic. 049. Pump off controller’s process
Pump off controllers are especially useful in reservoir where reservoir
pressures fluctuate or declined or when EOR (enhanced oil recovery) process to
start, to stimulate the well. This automatic pump off controllers as well as the
other three adjustments to hardware of pumping equipment can increase the
situations where sucker-rod pumps can be used efficiently (Pic. 050).

32. 29
Pic. 050. Pump off controllers function
2.1.9 Free Gases
Another obstacle that needs to be addressed in the soccer rod pumping
system occurs when free gases present in the reservoir fluid. Just adjusting the
pumping rates either manually or automatically of a sucker-rod pump is not
enough when gas is present. Let’s look at free gas inside the barrel of a sucker-
rod pump to see why. As the plunger drops freed gas in a barrel is more likely to
compress in place instead of flowing up with the rest of the fluid through the
traveling valve on its way to the surface (Pic. 051).

33. 30
Pic. 051. Free gases in barrels
Sometimes, this gas compression can be prevented just by setting the
pump below the casing perforations (Pic. 052) this position foster's oil and gas
separation which in turn allows the gas to be diverted up the casing or tubing
annulus, while the oil flows down into the barrel (Pic. 053).
Pic. 052. Setting the pump below the casing perforations

34. 31
Pic. 053. Gas diverted upthe casing
In addition installing a gas anchor on the tubing that separates oil from gas
can also divert the gas away from the tubing and up through the annulus (Pic.
054).
Pic. 054. Gas anchor on tubing separate oil from gas
The iconic symbol of the onshore oil industry is the sucker-rod pumping
system. they are the preferred choices on wells were conditions demand that
natural lift be supplemented by artificial lift because they are really dependable
low cost, and require minimal witness, because of their weight and bulk, coupled
with the depth and volume limitation however, the sucker-rod pumping system is
not always suitable for all onshore and most offshore installation.

35. 32
Alternative pumping systems therefore have been developed when the
sucker-rod pumping system is not suitable. One of these is called gas lift used
primarily offshore and the other is ESP (electric submersible pumping) used
primarily in wells with very high flow rate well that can support the higher costs
(Pic. 055). Like with the sucker-rod pumping system well illustrate the equipment
needed to use these artificial lift and then explain how each functions.
Pic. 055. Gas lift and ESP
2.2 Gas Lift
2.2.1 Gas Lift Disadvantages
Gas lift is very high maintenance because it requires frequent adjustments
(Pic. 056), coupled with the inefficiency in terms of work done per unit of energy
consumed and the need to always have a supply of injector gas throughout the

36. 33
life of the project (Pic. 057). Gas lift is therefore use primarily when the sucker-
rod pumping system is not suitable.
Pic. 056. Gas lift process

37. 34
Pic. 057. Gas lift disadvantages
2.2.2 Gas Lift Advantages
There are however two advantages that gas lift have over the sucker-rod
pumping system. Gas lift can be used in deep well and it requires minimal
equipment, so it can be ready relative quickly (Pic. 058). to be fully outfitted gas
lift requires only a compressor that sits on the surface, a supply of injector gas for
the compressor to pressurized and then send down the annulus a packer at the
end of the tubing string and unloading valves and operating valves moment at
varying depths in mandrels that are attached to the tubing string (Pic. 059).
Pic. 058. Gas lift advantages

38. 35
Pic. 059. Gas lift equipment diagram
2.2.3 The Gas Lifts Assembly
Once these pieces of equipment are installed, the gas lift is ready to be
brought online. Let’s look an illustration of the gas lifts assembly, here the well
has been equipped for gas lift with a compressor, packer and various unloading
and operating valves at varying levels (Pic. 060). When put into operation gas lift
can be used to return a well to production by supplementing the natural lift (Pic.
061).
Pic. 060. Gas lift Assembly

39. 36
Pic. 061. Gas lifts supplementing the natural lift
2.2.4 The Mandrels
Before we continue so let we put out here that's the unloading and
operating valves are mounted in mandrels. Mandrels are shafts on the tubing
string were tools can be mounted (Pic. 062).
Pic. 062. Mandrels on the tubing string

40. 37
Mandrel Functions
Mandrel mains functions are number one to help maintain the pressure on
the injected gas in the annulus as it makes its way down to the bottom of the hole
and number two to hold the one way valves that enable the compressed gas in
the annulus to be injected into the tubing but that also prevent oil from leaking
back out into the annulus (Pic. 063).
Pic. 063. Mandrels function
Types of mandrels
A. Conventional mandrel
Since these valves in the mandrels must be cleaned periodically, two
types of mandrels are available (Pic. 062), the first is called a conventional
mandrel, and it is run on tubing for the valves have already been set in place
inside the mandrel (Pic. 064). Although a conventional mandrel is simpler to
install, the tubing itself along with the mandrel must pulled when only valves need
to be serviced and clean (Pic. 065).

41. 38
Pic. 064. Conventional mandrel
Pic. 065. Mandrel installed and maintenance
B. Side-pocket mandrel
The second a more popular and widely used mandrel is called a side-
pocket mandrel, a side-pocket mandrel is hung on the tubing in such a way that
the valves can be accessed for servicing and cleaning using through tubing
wireline (Pic. 66). This means that unlike with conventional mandrel, the valves in

42. 39
a side-pocket mandrel can be retrieved and reinserted without pulling the entire
tubing string itself when the valve needs to be serviced (Pic. 067).
Pic. 066. Side-pocket Mandrel
Pic. 067. Mandrel component
Notice that here the side pocket of the mandrel is sufficiently offset, so that
there will be no restriction through tubing wireline tools, when choosing either
conventional or side pocket mandrel it is very important to select the type that
best suited for the conditions of the well (Pic. 080).

43. 40
Pic. 068. The mandrel type based on well condition
2.2.4 Gas Lift Process
Now let's look at how gas lift works, when injected into the tubing string,
the pressurized gas from the compressor tends to form a large bullet-shaped
bubbles that are trailed by smaller bubbles that traveled rapidly up the tubing. the
initial injections of pressurized gas need to be injected in steps or stages starting
near the top of the string and then going deeper at very multiple depth until the
bottom operating valve nearest the wellbore is open and all the other uploading
valve above it have been closed (Pic. 069).
Pic. 069. Gas lift process
Now the well is said to be in steady state operating condition, it will remain
in this condition until the well has to be killed for whatever reason and then when

44. 41
production begins again the whole process of opening and closing opening
valves until the bottom operating one is reached begins again (Pic. 070).
Pic. 070. Mandrel steady state operating condition
It is for this ongoing reason that mandrel needs to be left in place
throughout the production life of the well.
When finally the entire hydrostatic column has been injected with gas from
this bottom opening valve a continuous gas lift operation is achieved. Remember
in this is injected gas bubbles that like into load sufficiently so that lift can occur,
thus its name gas lift.
It can be seen that how the well gets to a steady state operating condition,
to begin the process compressed gas at the surface is released into the annulus,
this pressurized gas pushes the liquid depth down as the gas fields space. When
the compressed gas reaches the top lowering valve, valve in the mandrel in the
tubing string opens letting the gas flow into the tubing string. Once in the tubing
string the gas helps to light and the load of the heavier oil in the hydrostatic
column. Giving the oil enough lift from the remaining energy in the formation so
that it can now be pushed to the surface (Pic. 071).

45. 42
Pic. 071. Gas lift the oil in the hydrostatic column
As more compressed gases pumped into the annulus, the liquid level
continues downward until it reaches the second unloading valve. As the second
valve opens the first one closes. The compressed gas in the tubing having
entered from the second uploading valve flows up to meet the injected gas from
the first valve thus lightening the flow, its again allows more oil in the hydrostatic
column to be pushed to the surface. At the same time the compressed gas in the
annulus continues the step downward path until it reaches the third valve which
now opens. Like the first valve when the second valve opens, the second valve
now closes. The multiple valves in the mandrels at varying depths in the tubing
allow the compressed gas to enter the tubing from ever increasing depths until
the bottom of the whole has reached (Pic. 072).

46. 43
Pic. 072. The multiple valves in the mandrels at varying depths
When the injected compressed gas with pressures helps maintain by the
mandrel above them ultimately interested tubing string through the last valve at
the bottom of the hole. The tubing string is said to be in steady state operating
condition (Pic. 070). Now with the column light with the pressurized gas, the
reservoir pressure should be enough to push the oil in the tubing string
throughout the entire hydrostatic column through the surface.
Let we point out that at the surface as the oil and gas process through the
surface facilities the injected gas is recaptured and recycled through the
compressor and again sent down the annulus as pressurized gas. Any remaining
gas not required for injection can subsequently be sent to market. Most gas lift
wells follow these basic steps to get to the steady state operating condition were
continuous tubing flow lift is achieved (Pic. 073).

47. 44
Pic. 073. Gas lift process diagram
2.2.5 Other Configurations Gas lift
There are however other configurations that can be utilized under special
circumstances (Pic. 074). the first is known as intermittent lift, intermittent means
that the left is not continuous, it comes and goes as conditions warn, used in low
capacity wells it requires only an intermittent valve on the surface. When a gas
line is open for a preset period a single large slugged gases injected down the
casing through the operating valve into the tubing. In the right circumstances this
procedure should be enough to light in the loads sufficiently so that the oil can
overcome any hydrostatic pressure and begin flowing upward (Pic. 075).

48. 45
Pic. 074. Configuration special circumstances
Pic. 075. Gas lift –Intermittent lift
The second type of gas lift is used in dual completed wells and is known
as a dual gas lift (Pic. 076). The final type of gas lift is reserved for large capacity
wells and is known as annulus flow (Pic. 077). Unlike regular gas lift that sense
the compressed gas down the annulus, in annulus flow the compressed gas is
stead pumped into the tubing string where it is then sent through the valves to
the annulus.

49. 46
Pic. 076. Gas lift –Dual gas lift
Pic. 077. Gas lift - Annulus flow
To compare the low cost low maintenance sucker-rod pumping system is
more suitable for typical onshore wells, while the lighter more easily installed gas
system is used mostly offshore (Pic. 078).

50. 47
Pic. 078. Gas lift system is used mostly offshore
2.3 ESP (Electric Submersible Pumping)
There is a third method however that is best suited for wells that have high
volume production known as ESP (electric submersible pumping), these
sophisticated high performance devices are expensive to purchase, expensive to
repair and expensive to operate. Their uses therefore limited to high volume
applications either onshore or offshore where these costs can be justified. Water
drive and water flood production with high water cuts are typical applications (Pic.
079).
Pic. 079. ESP applications

51. 48
2.3.1 ESP Components
Let’s look at the components of an ESP (electrical submersible pump) and
then examine how it works. In this illustration we can see ESP with the power
cable, tubing, pump, pump intake, sealing section and the electric motor that sits
at the bottom (Pic. 080). At the surface the string is attached to a wellhead that is
small and lightweight. The powerful elongated multicentrifugal pumps are pushed
to the bottom hole on tubing with the power cable strapped to the outside of the
string (Pic. 081).
Pic. 080. ESP components diagram
Pic. 081. ESP components at Surface and inside well
This heavily insulated and extremely armored cable powers the electric
motors that is three-phased and operate at from 2,800 (twenty eight hundred) to
3,500 (thirty five hundred) RPM’s (revolutions per minutes) (Pic. 082). It should
be noted that extreme care is taken when pushing this cable to the bottom at the
hole because it can easily be damage. the pump intake includes a gas separator
that diverts that produced gas up to annulus rather than through the pump as

52. 49
seen in this picture (Pic. 083), the pump consist of a rotating impaler in a
stationary diffuser that are stacked on top of one another and stages that operate
in series.
Pic. 082. Cable powers electric motors
Pic. 083. Gas separator that diverts that produced gas up to annulus
2.4 Other Types of Artificial Lift
2.4.1 The power oil systems
There are seveal other less used types of artificial lift (Pic. 084). The
power oil systems provide lift with pressurized power oil that his pump down a
separate tubing string. They are very useful when needing to control corrosive
chemicals, dissolve salt deposits and to reduce viscosity. Power oil systems are
valuable in wells with deviated or crooked holes (Pic. 085).

53. 50
Pic. 084. Other types of artificial lift
Pic. 085. Power oil systems
2.4.2 PCP (Progressing Cavity Pumps)
PCP (Progressing cavity pumps) is best suited for lifting heavy oils or
solid-laden fluids (Pic. 086). Progressing Cavity Pumping (PCP) Systems
typically consist of a surface drive, drive string and 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

54. 51
string and remains stationary during pumping. In most cases the rotor is attached
to a sucker rod string which is suspended and rotated by the surface drive.
As the rotor turns eccentrically in the stator, a series of sealed cavities
form and progress from the inlet to the discharge end of the pump. The result is
a non-pulsating positive displacement flow with a discharge rate proportional to
the size of the cavity, rotational speed of the rotor and the differential pressure
across the pump. In some cases, PCP pumps are connected to Electric
Submersible Pump Motors rather than using a sucker rod string and surface
drive
Pic. 086. PCP (Progressing cavity pumps)
2.4.3 Plunger lift
A plunger lift is an artificial lift method of deliquifying a natural gas well. A
plunger is used to remove contaminants from productive natural gas wells, such
as water, sand, oil, and wax.
The basics of the plunger are to open and close the well shutoff valve at
the optimum times, to bring up the plunger and the contaminants and maximize
natural gas production. A well without deliquification technique will stop flowing or
slow down and become a non-productive well, long before a properly deliquified
well.
Modern wellhead controllers offer a variety of criteria to control the
plunger. The original controllers were just timers, with fixed open and close
cycles. Measuring the various pressures in the systems allows intelligent and
reactive control. The pressures often measures are casing, tubing, line, and
differential. The other times measured are plunger arrive times, flow rates,
temperatures and status of various auxiliary equipment: oil tank level,
compressor status (Pic 87).

55. 52
Pic 087. The plunger lift component
During high flow rates the plunger rests at the top of the well, as
production decreases liquids accumulate at the bottom of the tubing; the well
begins to "load”. Once loading occurs the pressure decreases closing the valve.
The plunger drops from its starting position falling through the tubing, with the
well shut in, pressure builds inside the annulus, and the valve opens lifting the
plunger along with the fluids to the top of the well the fluid is then allowing the
well to free flow (Pic 088).

56. 53
Pic 088. The plunger lift process
2.4.4 Jet Pumps
As a general description, Hydraulic Lift (Jet Pumps) represents pumping
power fluid at high pressure and rate from surface to activate/drive a downhole
pump. Power Fluid can be water or oil (Pic 089).
With Jet Pump applications the completion needs to have minimum 3
flowing conduits:
1. A conduit for power fluid injection (inside of the tubing in case of standard
flow, and in the annular space in case of reverse flow).
2. For reservoir fluid flow (below the JP & packer).
3. And a conduit for commingled fluid flow to the surface.

57. 54
Pic 089. Jet Pump working principle
The jet pump artificial lift system is composed of two principal parts: the
surface pumping equipment and the downhole jet pump. In the surface, the
reciprocating pump transfers energy to the fluid increases its pressure, drove
through surface piping, production tubing (or annular space) until the jet pump,
placed on the bottom.
Surface Equipment consists of the power unit (high-pressure pump with
accessories, motor, gear reducer, controller), power fluid conditioning unit (VCU)
and high-pressure lines (Pic 090)

58. 55
Pic 090. Typical jet pump surface equipment configuration
When the power fluid travels at high pressure through the smaller area of
the jet pump, known as “nozzle“, the Venturi effect occurs increasing the speed
and reducing the pressure. This generates the suction of reservoir fluids in the
space between the nozzle and the throat.
When the power fluid gets into the mixing tube the flow area increases,
reversing the energy transformation, reducing speed, and increasing the
pressure. This allows the reservoir fluids to be lifted to the surface through the
annular space.
The nozzle and throat are the key components of a jet pump. The ratio of
the areas of these two parts is known as the area ratio of the pump and it
determines the performance characteristics of the pump. Pumps with the same
area ratio have the same performance and efficiency curves
There are three typical completion types for wells equipped with downhole
jet pump: Conventional, Parallel and Concentric (Pic 091).

59. 56
Pic 091. Three typical completion types with jet pump
Hydraulic pumping has the following advantages.
 Being able to circulate the pump in and out of the well is the most obvious
and significant feature of hydraulic pumps. It is especially attractive on
offshore platforms, remote locations, and populated and agricultural areas.
 Working fluid levels for jet pumps are limited to approximately 9,000 ft.
 By changing the power-fluid rate to the pumps, production can be varied from
10 to 100% of pump capacity. The optimum speed range is 20 to 85% of
rated speed. Operating life will be significantly reduced if the pump is
operated above the maximum-rated speed.
 Jet pumps can even be used in through flowline installations.
 Jet pumps, with hardened nozzle throats, can produce sand and other solids.
Hydraulic pumping has the following disadvantages.
 Removing solids from the power fluid is very important for positive-
displacement pumps. Jet pumps are very tolerant of poor power-fluid quality.
 Jet pumps have a very long pump life between repairs without solids or if not
subjected to cavitation. Jet pumps typically have lower efficiency and higher
energy costs.
 Jet pumps cannot pump from such low intake pressures.
 Pump speed must be monitored daily and not allowed to become excessive.

60. 57
3. SELECTING AN ARTIFICIAL LIFT METHOD
Here is Artificial lift system Management Cycle for selecting an artificial lift
method, starting from development strategy review, Reservoir data, well data and
others data, then Testing or analysis, and Monitoring (Pic. 092).
Pic 092. Artificial lift system Management Cycle
3.1 Reservoir Characteristics
Artificial lift considerations should ideally be part of the well planning
process. 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. 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.
High water cuts require a lift method that can move large volumes of fluid,
A high GLR generally lowers the efficiency of pump-assisted lift, 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,Ratio of reservoir
volume to surface volume determines how much total fluid must be lifted to
achieve the desired surface production rate, Late-stage production may require

61. 58
pumping to produce low fluid volumes or injected water. High water cuts may
cause problems for lifting systems, Increasing gas-liquid ratios may affect lift
efficiency.
3.2 Hole Characteristics
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 and perforation skin factors affect inflow performance.
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. PCP systems because of drag,
compressive forces and potential for rod and tubing wear.
3.3 Surface Characteristics
Flow rates are governed by wellhead pressures and backpressures in
surface production equipment (i.e., separators, chokes and flowlines). Paraffin or
salt can increase the backpressure on a well.
The availability of electricity or natural gas governs the type of artificial lift
selected. Diesel, propane or other sources may also be considered. 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.
3.4 Field Operating Characteristics
Field conditions may change over time. Water or gas injection may
change the artificial lift requirements for a field. EOR processes may change fluid
properties and require changes in the artificial lift system. If the surface control
equipment will be electrically powered, an electrically powered artificial lift system
should be considered.
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.
4. CONCLUSION
What it is, why with, and where it is needed to begin we discussed two
different sources of energy natural and artificial that can be used in the initial and
subsequent stages of recovery. The first source, natural lift is the most commonly

62. 59
used in recovery in the initial stages of a reservoirs production. The second
source artificial lift is man-made and used in subsequent stages of recovery to
supplement the reservoir natural lift when it is no longer capable of lifting the oil
in the hydrostatic column to the surface (Pic. 093).
Pic. 093. Natural and artificial energy
Defining natural lift and then describing when and why this natural lift
might end and be replaced with artificial lift we outlines and highlighted three of
the seven different types of artificial lift sucker rod pumping system, gas lift and
ESP (electric submersible pumping).
The sucker-rod pumping system also known as the nodding donkey is
used mostly onshore, due to of its size and weight. Because of its relatively low
cost it is the preferred type of artificial lift wherever conditions were.
Gas lift on the other hand is generally used offshore where the sucker-rod
pumping system is not suitable, it can also be used in wells that are deeper than
those, that can be serviced by the sucker-rod pumping system. because of need
for repeated maintenance, its dependence on a source of injectable gas,
however gas lift is the second choice for artificial lift.
The ESP (electric submersible pump) is reserved for wells either onshore
or offshore with higher production rates, they can justify its relatively higher cost.
Like gas lift it can also be used in deep wells.
We briefly mentioned power oil systems and PCP (progressing cavities
pumps), Plunger lift and Jet pump, this book illustrates ways that natural energy
in the reservoir can be supplemented by various lifting techniques to capture as
much of the hydrocarbons as possible in the reservoir (Pic. 094).

63. 60
Pic. 094. Artificial lift system

64. 61
REFERENCES
 Brown, Kermit E. (1980). The Technology of Artificial Lift Methods, Volumes 1, 2a
and 2b. Tulsa, OK: PennWell Publishing Co.
 Brown, Kermit E. (1982). “Overview of Artificial Lift Systems.” Journal of
Petroleum Technology, Vol. 34, No. 10. Richardson, TX: Society of Petroleum
Engineers.
 CHRIS CLARK, RYAN KOSMIC, 2014, Hydraulic jet pumps prove worth for lifting
early production,World Oil®.
 Clegg, J.D., Bucaram, S.M. and Hein, N.W. Jr. (1993). “Recommendations and
Comparisons for Selecting Artificial Lift Methods.” Journal of Petroleum
Technology (December), p. 1128. Richardson, TX: Society of Petroleum
Engineers.
 Cleide Rosemine Gany Vieira, 2015, Model-based optimization of production
systems, Master's Thesis, Department of Petroleum Engineering and Applied
Geophysics, Norwegian University of Science and Technology.
 Clemente-Marcelo Hirschfeldt, 2011, ARTIFICIAL LIFT MANAGEMENT
RECOMMENDATIONS AND SUGGESTIONS OF BEST PRACTICES, Oil
Production Consulting & Training, Universidad Nacional de la Patagonia San
Juan Bosco, Comodoro Rivadavia, Argentina
 David Cosby, Ferguson Beauregard, 2012, Introduction to Plunger Lift, Gas Well
Deliquification Workshop, ALRDC-Texas Tech, Colorado
 Edgar Camargo et. al., 2008, Nodal Analysis- based Design for Improving Gas
Lift Wells Production, WSEAS TRANSACTIONS on INFORMATION SCIENCE &
APPLICATIONS.
 Ezekiel Chikwere, Okotie Sylvester, and Dulu Appah, 2015, Economic Evaluation
of Electrical Submersible Pump (ESP) and Gas Lift Well For Production
Optimization in A Niger Delta Field, International Journal of Engineering and
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 Jhonn Almendras et. al., 2015, Massification of Artificial Lift Systems in
Compositional Reservoir deep North Monagas Venezuela, SPE-WVS-521, the
SPE Western Venezuelan Petroleum Section Program Committee
 Lau Richard, Overview of the Oil Industry – Petroleum Artificial lift, 2014.
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PUMPS (ESPs) IN MAXIMIZING OIL RECOVERY, Master of Engineering,
Dalhousie University, Halifax, Nova Scotia.
 Mohd Fauzi Hamid, Wan Rosli Wan Sulaiman, Fundamentals Of Petroleum
Engineering-PRODUCTION, Department of Petroleum Engineering Faculty of
Petroleum & Renewable Engineering Universiti Technologi Malaysia.
 Moineau, Rene (1930). “Un Nouveau Capsulisme.” Extracts from doctoral thesis,
University of Paris.
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 http://www.mpgpetrole**.com/fundamentals.html
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66. ABOUT THE WRITER
Having more than 10 years of work experiences in Oil and
Gas Industry both exploration and development such as
Bandarjaya / Lampung III Project (at PT. Harpindo Mitra
Kharisama), Reevaluation of Diski Oil field - North Sumatra
basin (at TAC PEP – PKDP), and Preliminary Fractured
evaluation some oil fields (at PT. OPAC Barata-Kejora Gas
Bumi Mandiri), Evaluation for Klamono Block - Salawati Basin
and Evaluation for Tebat Agung Block - South Sumatera Basin (at Trada Petroleum Pte.
Ltd.), Operation of Kampung Minyak oilfield (at KSO Pertamina EP – PKM) and
Formation Evaluation of Tsimororo Field - Madagascar (at Lemigas), J1J3 Oil Fields -
NW Java basin (at ECC).
He Was Graduated from Institute Technology of Bandung, Geology Engineering
Department in 2006 as S.T. (Sarjana Teknik) or Bachelor degree in Geology. Before that
He was graduated from SMUN 2 Cimahi (Senior High School) in 2001, and from SLTPN
9 Cimahi (Junior High School) in 1998, also graduated from SDN KIHAPIT I (Elementary
school) in 1995.