2. Dedication
This project owes its existence to a number of people to whom I feel genuinely
obliged
To my dear mother Nassima, my greatest teacher, a teacher of love, compassion
and bravery, you will always be the biggest inspiration in my life.
May God give you long life full of joy and happiness.
To my dear father Jamel, to whom I owe the best of myself, my teacher of love.
This project could not be realized without your belief in me, your encouragement,
your trust, your moral and material support.
May God give you long life full of joy and happiness.
To my beloved brothers; Ahmed and Zied, for always being there by my side,
for the confidence you provide me and for your encouragement.
Finally I thank everyone who in one way or another helped me achieving this
work.
I dedicated this work
Omar Omrane
3. Acknowledgment
This project would not have the spirit that it has without the supervision of
my academic supervisor Mr. Walid HASSEN, Assistant Professor at national
school of engineering of Monastir and my industrial supervisor Mr. Mohamed
Ali KHIYARI, Production engineer at OMV Tunisia. I would like to express
my sincere appreciation of their constant willingness to share their immense
knowledge and experience during this four months period. Their valuable
guidance and support helped in accomplishing this project.
I express my gratitude toward OMV exploration and production staff for
giving me the opportunity to integrate the professional life through this
internship and affording a warm welcome environment during my training
within their company.
I will forever remember, Mrs. Yesmine LAROUSSI and Mr. Brahim
LETAIEF for inspiring positive energy and healthy work environment.
We must not forget the contribution of my beloved friends; Salma
LATRACH, Khaled MNEJJA and Mohamed CHEMAKH for sharing with me
the funniest moments and the lovely experience that we lived during this
internship.
Last and not least, I wish to express my sense of gratitude to all who directly
or indirectly have laid their hand in this venture
4. Summary
List of figures
List of tables
General Introduction................................................................................................................................ 1
Company presentation............................................................................................................................. 2
General description.............................................................................................................................. 3
Objective ............................................................................................................................................. 3
Field of activity ................................................................................................................................... 3
Chapter I: Oil and Gas general overview .................................................................................... 4
I.1. Introduction....................................................................................................................................... 5
I.2. Presentation of the petroleum production system ............................................................................. 6
I.2.1. Definition ................................................................................................................................... 6
I.2.2. Pressure losses across the petroleum production system ........................................................... 6
I.3. Petroleum production engineering................................................................................................... 7
I.3.1. Introduction............................................................................................................................... 7
I.3.2. Production optimization and well performance ......................................................................... 7
I.3.2.1. Well performance: Nodal system analysis.......................................................................... 7
I.3.2.2. Artificial lift ...................................................................................................................... 12
I.4. Properties of reservoir fluids and phase behavior........................................................................... 15
I.4.1. Multiphase flow theory patterns and map.................................................................................... 15
I.4.2. Bubble point............................................................................................................................. 17
I.4.3. GOR (Gas Oil Ratio)................................................................................................................ 17
I.4.4. FVF(Formation Volume Factor).............................................................................................. 17
I.4.4.1. Formation Volume Factor (oil) ......................................................................................... 17
I.4.4.2. Formation Volume Factor (gas)........................................................................................ 17
I.4.5. Water cut (WC)........................................................................................................................ 18
I.4.6. Oil density................................................................................................................................ 18
I.5. Conclusion ...................................................................................................................................... 19
Chapter II: Electrical Submersible Pump(ESP) ...................................................................... 20
II.1. Introduction.................................................................................................................................... 21
II.1.1. General history of ESP ........................................................................................................... 21
II.1.2. General overview of ESP........................................................................................................ 21
II.2. ESP components............................................................................................................................ 22
II.2.1. ESP down-hole components................................................................................................... 23
II.2.1.1 Pump................................................................................................................................ 23
5. II.2.1.2 Gas separator ................................................................................................................... 24
II.2.1.3. Seal section...................................................................................................................... 25
II.2.1.4. Electrical motor................................................................................................................ 26
II.2.2. ESP Surface components........................................................................................................ 26
II.2.2.1. Junction Box.................................................................................................................... 26
II.2.2.2 Power cable....................................................................................................................... 27
II.2.2.3. Motor controller............................................................................................................... 27
II.2.2.4. ESP variable speed drive ................................................................................................. 27
II.2.2.5. Transformer ..................................................................................................................... 27
II.2.3. ESP mainly support equipment............................................................................................... 27
II.3. Performance of an ESP system...................................................................................................... 28
II.4. Evaluation of ESP components...................................................................................................... 29
II.4.1 ESP advantages........................................................................................................................ 29
II.4.2. ESP disadvantages.................................................................................................................. 29
II.5. Conclusion..................................................................................................................................... 30
Chapter III: Case study................................................................................................................... 31
III.1. Hand sizing................................................................................................................................... 32
III.1.1. The 9 steps procedure............................................................................................................ 32
III.1.1.1 Basic data ....................................................................................................................... 34
III.1.1.2. Production capacity ........................................................................................................ 36
III.1.1.3. Gas calculation ............................................................................................................... 39
III.1.1.4. Total dynamic head ........................................................................................................ 43
III.1.1.5. Pump selection................................................................................................................ 45
III.1.1.6. Seal section selection...................................................................................................... 50
III.1.1.7 Motor selection................................................................................................................ 51
III.1.1.8. Power cable selection ..................................................................................................... 53
III.1.1.9. Motor controller selection .............................................................................................. 56
III.2. Software design............................................................................................................................ 60
III.2.1. AutographPC brief overview................................................................................................. 60
III.2.2. AutographPC purpose ........................................................................................................... 61
III.2.3. AutographPC features ........................................................................................................... 61
III.2.4. AutographPC modeling Application (Cherouq 1 well)......................................................... 61
III.2.4.1. Problematic and Purpose ................................................................................................ 61
III.2.4.2. Data required for design................................................................................................. 61
III.2.4.3. Pump sizing screen......................................................................................................... 64
III.2.4.4. Motor sizing screen ........................................................................................................ 65
7. List of figures
Chapter I
Figure I- 1: Petroleum Production System.............................................................................................. 6
Figure I- 2: main pressure losses within production system ................................................................... 7
Figure I- 3: Straight-line IPR (for an incompressible liquid).................................................................. 9
Figure I- 4: Vogel 's inflow performance curve .................................................................................... 10
Figure I- 5: Inflow Performance Relationship....................................................................................... 10
Figure I- 6: TPR curves for different wellhead pressures ..................................................................... 11
Figure I- 7: Operating point................................................................................................................... 12
Figure I- 8: Typical rod pump ............................................................................................................... 13
Figure I- 9: Hydraulic pump.................................................................................................................. 13
Figure I- 10: ESP system....................................................................................................................... 14
Figure I- 11: Gas lift system.................................................................................................................. 14
Figure I- 12: Vertical flow patterns....................................................................................................... 16
Figure I- 13: Horizontal flow patterns................................................................................................... 16
Chapter II
Figure II- 1: Conventional ESP installation .......................................................................................... 22
Figure II- 2: ESP submersible pump cutaway....................................................................................... 23
Figure II- 3: Illustration of impeller and subcomponents...................................................................... 23
Figure II- 4: illustration cutaway of a diffuser ...................................................................................... 24
Figure II- 5: Illustration of a pump stage............................................................................................... 24
Figure II- 6: Pump intake ...................................................................................................................... 24
Figure II- 7: Rotary gas separator.......................................................................................................... 25
Figure II- 8: ESP combined seal section components........................................................................... 26
Figure II- 9: ESP motor cutaway illustration ........................................................................................ 26
Figure II- 10: example performance curve of an ESP pump................................................................. 28
Chapter III
Figure III- 1: Total dynamic head ......................................................................................................... 44
Figure III- 2: Pump performance curve 538 series P37 Centurion pump.............................................. 48
Figure III- 3: Pump performance curve 538 series P23 Centurion pump.............................................. 48
Figure III- 4: Pump performance curve 538 series G31 Centurion pump............................................. 49
Figure III- 5: Horsepower VS Total dynamic head in feet.................................................................... 51
Figure III- 6: well conditions screen capture......................................................................................... 62
Figure III- 7: Pump sizing screen capture ............................................................................................. 64
Figure III- 8: Motor sizing screen capture............................................................................................. 65
Figure III- 9: Seal sizing screen capture................................................................................................ 66
Figure III- 10: Cable sizing screen capture ........................................................................................... 66
Figure III- 11: controller sizing screen capture .................................................................................... 67
Chapter IV
Figure IV- 1: Production decline profile ............................................................................................... 74
Figure IV- 2: Cashflow profile.............................................................................................................. 74
8. List of tables
Chapter I
Table I- 1: Advantages and Disadvantages of artificial lift technologies[4]......................................... 15
Chapter III
Table III- 1: Pump Design data for 3 wells ........................................................................................... 34
Table III- 2: Pump intake pressure calculation steps............................................................................. 38
Table III- 3: Free gas calculation steps.................................................................................................. 41
Table III- 4: Total Dynamic head calculation ....................................................................................... 45
Table III- 5: Required Data for pump selection .................................................................................... 46
Table III- 6: Pump specifications .......................................................................................................... 49
Table III- 7: Seal horsepower estimation .............................................................................................. 51
Table III- 8: required motor power........................................................................................................ 52
Table III- 9: motor selection specification ............................................................................................ 52
Table III- 10: Motor load calculation.................................................................................................... 52
Table III- 11: Line losses per 1000 ft calculation.................................................................................. 53
Table III- 12: Temperature correction factor estimation....................................................................... 53
Table III- 13: Voltage drop per 1000 ft calculation............................................................................... 54
Table III- 14: Total voltage drop calculation ........................................................................................ 54
Table III- 15: Motor nameplate voltage drop calculation...................................................................... 55
Table III- 16: Power cable's operating temperature. ............................................................................. 55
Table III- 17: Surface Voltage calculation ............................................................................................ 56
Table III- 18: Motor controller specifications....................................................................................... 57
Table III- 19: ESP design summary (Cherouq1)................................................................................... 58
Table III- 20: ESP design summary (Shaheen1) ................................................................................... 59
Table III- 21: ESP design summary(Badr6).......................................................................................... 60
Table III- 22: Well input Data (Software Design)................................................................................. 61
Table III- 23: Well Output Data (Software Design).............................................................................. 63
Table III- 24: Pump sizing specifications (Software Design) ............................................................... 64
Table III- 25: Motor sizing specifications (Software Design)............................................................... 65
Table III- 26: Seal sizing specifications (Software Design).................................................................. 66
Table III- 27: Cable sizing specifications (Software Design) ............................................................... 67
Table III- 28: Controller sizing specifications (Software Design) ........................................................ 68
Chapter IV
Table IV- 1: CAPEX calculation........................................................................................................... 72
Table IV- 2: Net Cash Flow calculation................................................................................................ 72
9. Glossary of terms and acronyms
A
API: American Petroleum Institute
AOF: Absolute Oil Flowrate
AWSG: Adjusted Water Specific Gravity
AOSG: Adjusted Oil Specific Gravity
B
BEP: Best Efficiency Point
BHP: Brake Horse Power
BBL: Barrel (42 US Gallons)
BFPD: Barrel of Fluid Per Day
BPD: Barrel Per Day
Bg: gas formation volume factor
Bo: Oil Formation volume Factor
BOPD: Barrel of Oil Per Day
BHT: Bottom-Hole Temperature
C
cP: centripoise
D
DWHP: Desired Wellhead Pressure
E
ESP: Electric submerged pump
F
FVF: Formation Volume Factor
Ft: feet
FL: Friction Loss
Fg: Volume of free gas
G
GOR: Gas Oil Ratio
H
HP: High pressure
HP: Horse Power
I
IPR : Inflow Performance Relationship
ID: Inside Diameter
M
Mg: average molecular weight of gas mixture
Mair: molecular weight of air
π π: mass of gas
mcf: a traditional unit of volume equal to
1000 cubic foot
N
NPSH: Net Positive Suction Head
n: Number of mole
O
OD: Outside Diameter
P
PR: reservoir pressure
Pwf: flowing bottom-hole pressure
PI: Productivity Index
Psc: Pressure in standard condition
PSI: Pound per Square Inch
Psia: pound per square inch, absolute
Psig: pound per square inch, gauge
PIP: Pump Intake Pressure
Pb: bubble point pressure
PSD: Pump Setting Depth
Pd: discharge pressure (well head pressure)
Q
Q: Flowrate
Qd: desired flowrate
R
RPM: Rotation Per Minute
rcf : cubic feet of reservoir volume
R: gas-law constant
rb: barrel at reservoir conditions
Rs: Solution gas Oil Ratio
S
STB: Stock Tank Barrel
scf : standard cubic foot
SGw: Specific Gravity of Water
SGoil: Specific Gravity of oil
SGliquid: Specific Gravity of liquid
SGgas: Specifig Gravity of gas.
T
TPR: Tubing Performance Relationship
TR: Reservoir Temperature
Tsc: Temperature T standard condition
Tg: total volume of gas at the surface
TDH: Total Dynamic Head
V
VSD: Variable speed drives
VLP: Vertical Lift Performance
VR: Reservoir volume
Vsc: Volume at standard condition
W
Wc: Water Cut
π π: density of gas
πΎπ: Specific gravity of gas
π0: average viscosity
10. 1
General Introduction
This report entitled "ESP Design Using Hand Sizing and AUTOGRAPHPC for 3 wells"
incorporates the graduation project in the National Engineering School of Monastir elaborated
in the international oil and gas company OMV.
Oil and gas sector is defined by OPEC(organization of petroleum countries) as "the engine
of the world economy". It is an essential source of energy in numerous domains such as
(transportation, industries, home and medicine...); it has shaped our world in many important
ways.
The amount of oil and gas extraction is dependent on well productivity. Unfortunately only
5% of worldwide wells flow naturally .The others involves the application of artificial
techniques of well activation.
The vitality of oil and gas industry generates inventions in terms of artificial lifting in order to
optimize the production and maximize the oil companies profitability.
The electrical submersible pump renowned for ESP is an efficient form of artificial lift
utilized for lifting moderate to high amounts of fluids (hydrocarbons) with high water cut.
The main objective of this work is to design the ESP for 3 wells ( Chourouq1,
Shaheen1and Badr6) of Anaguid field through 2 methods: the nine hand sizing steps and the
AutographPC method to come up with meaningful sensitivity study in order to expect the ESP
contribution for the forthcoming installation.
This report includes as a first paragraph, a short presentation of the OMV company. Chapter
one and chapter two contain a literature review to be familiar with basic concept of production
engineering such as performance of petroleum system and artificial techniques of activation
with braking the lights on ESP features. The third chapter is the real case study of ESP design
of the 3 wells mentioned previously of Anaguid field, using hand sizing and AutographPC
software. Finally the economic study is done in chapter four to know the profitability of the
ESP installation project.
12. 3
General description
OMV is a German abbreviation ("ΓΆsterreichische mineralΓΆlverwaltung") which means
Austrian mineral oil administration. OMV is an integrated international oil and gas company,
headquartered in Vienna. OMV's main business is in Exploration & Production (E&P), Gas &
Power (G&P) and Refining & Marketing (R&M). With group sales of more than β¬ 42.41
billion and a global workforce of around 26,800 in 2016, OMV is the largest listed
manufacturing company in Austria.
Objective
The main objectives of OMV are:
ο Manage exploration and production of hydrocarbon on behalf of the Tunisian
government.
ο Producing oil that will allow Tunisia to accelerate its economic development and
establish position on the world stage.
Field of activity
οΌ Exploration and production of hydrocarbon
οΌ Marketing of crude oil and petroleum products
οΌ oil Service
οΌ Human Resources Development
13. 4
Chapter I: Oil and Gas general overview
Objective
The main purpose of this chapter is to
be familiar with the concept of oil and
gas highlighting a major section of
this sector which is production
activity.
14. 5
I.1. Introduction
Petroleum production engineering is the series of activities concerned with the ability of a
well to produce. These activities are divided, according to their specification, into upstream
sector and downstream sector:
ο· The upstream sector, it mainly consists in searching and finding oil from underground
(underwater) fields called "Exploration" followed by oil or gas extraction "Production".
EXPLORATION
Reservoir capacity is determined approximately by two different methods:
οΌ Geological survey: In this case geoscientists attempt to locate best areas by examining
different underground layers of rock using advanced technologies and special tools such as
"aerial photography, satellite pictures and specialized machines that measure variation in the
earth's gravity fields."
οΌ Seism survey is a vital part in oil and gas exploration, it involves using sound waves
to form a clear picture of underwater layer rock. Surveyors register the seismic waves that are
produced by an explosion or sound generator. This technique is based on determinations of
the time interval that elapses between the initiation of a seismic wave at a selected shop point
and the arrival of reflected or refracted impulses at one or more seismic detectors.
After designating the specific area based on geoscientists investigation the second step should
be begin which is the initial drilling. If drilled wells, called wildcat well, present good signs
of existing crude oil inside then the well will be completed and the second phase of
production starts.
PRODUCTION
Once oil is found after the preliminary exploration phase and the drilling of exploratory
wells, the production phase can begin: wells are perforated adopting the rotary rig drilling's
technique. During this operation underground water should be protected from oil and gas
contamination, thus outer casings must be inserted in the well then cemented to the exterior
wall. Once the reservoir rock is reached the well is completed with the remaining facilities:
wellhead and surface equipments.
ο· The downstream sector: The downstream sector is the part of the oil industry involved
with purifying crude oil and refining it into different products. It also involves the
transportation and marketing of crude oil and its products.
Once oil starts flowing, it needs to be extracted in large volumes and then taken to special
sites where it is treated carefully before being transported internationally.
The process through which crude oil is purified and treated to remove unusable substances is
called Refining. This process is also used to separate oil into different usable petroleum
products. All this takes place in an oil refinery. Refineries are highly automated and
technologically advanced. That is why a typical refinery costs billions of dollars to build. It
also costs millions to operate, employing hundreds of people and running every day of the
year. All refineries perform three basic functions: Separation, Conversion and Treatment.
Separation
In this phase, a refinery heats crude oil to different temperature levels. Different parts of
crude oil have different boiling points. As the temperature rises, these different parts or
fractions are separated. This is done inside distillation towers.
Conversion
In this phase, high temperatures and pressure, as well as chemical catalysts, are used to
βcrackβ or split heavy hydrocarbon molecules into smaller, more desirable ones. This is the
most widely used conversion method and it is called CRACKING.
15. 6
Treatment
The final phase is treatment. In this step, the fractions produced during separation are
treated to improve their quality. They are then blended with other elements to produce the
final products.
I.2. Presentation of the petroleum production system
I.2.1. Definition
Petroleum production involves two distinct but intimately connected general systems: the
reservoir, which is a porous medium with unique storage and flow characteristics; and the
artificial structures, which include the well, bottom hole, and wellhead assemblies, as well as
the surface gathering, separation, and storage facilities as shown in Figure I-1.
Figure I- 1: Petroleum Production System
I.2.2. Pressure losses across the petroleum production system
The hydrocarbon fluid streams from the reservoir into the well, up the tubing, along the
horizontal flow line and into the oil storage tank. During this process the fluidβs pressure is
reduced from the reservoir pressure to atmosphere pressure in a series of pressure loss
processes (Figure I.2)
These pressure losses can be classified into four main components:
ο· the total pressure losses in the reservoir
ο· the total pressure losses in the completion
ο· the total pressure losses in the tubing
ο· the total pressure losses at the surface
16. 7
Figure I- 2: main pressure losses within production system[1]
I.3. Petroleum production engineering
I.3.1. Introduction
Production engineering technologies attempt to maximize oil and gas production in a most
possible profitable way. It offers different methods and technologies allowing to:
οΌ Evaluate inflow and outflow performance between the reservoir and the wellbore.
οΌ design completion system
οΌ Select the proper artificial lift equipment
οΌ Select equipment for surface facilities
The only way to achieving these previous responsibilities, is for production engineers to
elaborate a detailed analysis of these distinct, yet related parts:
o The components of oil and gas production system
o The fundamentals of well performance
o well completion
o oil wells activation systems
I.3.2. Production optimization and well performance
I.3.2.1. Well performance: Nodal system analysis
Well analysis is the most important step to optimize oil production. Production
optimization aims to find the flow rate of the producing well based on various approaches.
Over the years oil and gas industry have been resorted to a numerous optimization tools and
techniques to support decisions in order to reach the highest production performance possible.
One of these techniques is designing production systems and facilities.
This depends upon 'NODAL' system analysis approach. It involves employing correlations
to predict multiphase flow behavior through pipes, well completions, restrictions and the
reservoir. For this reason experts specialized in production optimization employ tow methods:
Well inflow performance relationship (IPR) and tubing performance relationship.
17. 8
I.3.2.1.1. Inflow performance from the reservoir to the wellbore
The relationship between bottom-hole pressure and corresponding production rates is of a
paramount importance for the description of well behavior. this is called the well's inflow
performance relationship (IPR) and usually obtained by running well tests.
Productivity Index concept
The productivity index is a mathematical measure of the well potential or ability to produce
and is a commonly measured well property. It's the most optimistic approach to describe the
inflow performance of oilfield wells.
To utilize this concept, four assumptions have to be realized:
ο· Radial flow near the wellbore area
ο· A single phase, incompressible liquid is flowing
ο· A homogeneous distribution of the formation permeability
ο· The fluid is fully saturated in the formation
For general flow through porous media:
π =
πΎπ΄(π0 β π1)
ππΏ
I.1
But in our case we're working with oil reservoirs to find the production rate of any oil well or
the Darcy law equation:[2]
π =
7.08. 10β3
βπΎ0(ππ β π π€π)
π΅0 π0 ln((
ππ
ππ€
) β 0.75)
I.2
where
π΅0: liquid volume factor, bbl/STB
π0: average viscosity, cP
ππ: drainage radius of well, ft
ππ€: radius of wellbore, ft
πΎ0: effective permeability, md
β: effective feet of pay(height), ft
ππ: reservoir pressure, psi
π π€π: flowing bottom-hole pressure, psi
If we make the assumption that β, πΎ0, ππ€, ππ, π0 πππ π΅0 are constant for a particular well the
equation becomes:
π = πΎ(ππ β π π€π) I.3
where K is the Productivity Index.
Finally we obtain the equation I.4.
π = ππΌ(ππ β π π€π) I.4
PI is usually found by measurement (down-hole gauge and surface flow rate).
It calculates the highest maximum flow rate (AOF) since no change from producing below
bubble point is assumed.
18. 9
Figure I- 3: Straight-line IPR (for an incompressible liquid) [1]
We can notice in Figure I.3 that the curve of the wellbore flowing pressure (Pwf) in
function of the flow rate (q) is a straight line of a negative slope (β1/PI). Also this graph
shows two important points : The first one ,located on the x-axis, represents the maximum of
the potential rate corresponding to the minimum of the wellbore flowing pressure which is
zero whereas the second one ,located on the y-axis matches the two values of the minimum
flow rate (zero) and the maximum wellbore pressure (Pr: reservoir pressure) that can be
attained.
the maximum flow rate which is impossible to achieve is called typically Absolute Open
Flow Potential typically known for the abbreviation AOF. This latter is used only to compare
between different wells' deliverability. So to obtain the flow rate at any flowing bottom-hole
pressure it's sufficient to know the productivity index PI, the bottom-hole pressure Pwf and
apply the equation I.4. the productivity index is defined as the flow rate per unit pressure
drop.
Voglel's method
When two phase inflow is taking place in the well, straight line IPR are not applicable.
After a thorough study concerned inflow performance relationship of the well with a solution
gas Vogel proposed the following equation.[2]
π
π πππ₯
= 1 β 0.2 (
π π€π
ππ
) β 0.8 (
π π€π
ππ
)
2
I.5
where
Q: liquid rate, STB/day
Qmax: maximum rate at bottom-hole pressure (Pwf), STB/day
PR: average reservoir pressure, psi
Pwf: bottom-hole flowing pressure, psi
Figure I.4 represents Vogel's inflow performance curve.
19. 10
Figure I- 4: Vogel 's inflow performance curve
Sum up IPR
When multi-rate test data is available the straight line IPR and the Vogel IPR curve are
combined to create a new one describing the well performance when the reservoir pressure is
above the bubble point while the wellbore pressure is below. The resulting straight line has a
slope of (1/π). Figure I-5 compares the production rate as a function of drawdown for an
under-saturated oil (straight line IPR, line A) and a saturated oil showing the two phase flow
effects discussed above (curve B).
Figure I- 5: Inflow Performance Relationship[2]
20. 11
I.3.2.1.2. Outflow performance of oil and gas well from the wellbore to the surface
Just as there is a drop in pressure within the formation during production, there is also a
drop in pressure within the tubing from bottom-hole to the surface during vertical flow.
Empirical correlations have been developed to predict pressure losses in the tubing for a wide
variety of vertical flow condition.
From the wellbore up all the way to the separator, analyzing the performance of the wells
need to establish a relationship between the diameters of the pipes, the pressure at the bottom
and the wellhead, fluid properties and the flow of production. This relationship is known as
the common name of "Vertical Lift Performance(VLP)" or "Tubing Performance Relationship
(TPR)".(see Figure I-6)
Figure I- 6: TPR curves for different wellhead pressures
Outflow performance sensitivity
The outflow performance is sensitive to:
ο· Tubing sizing
ο· water cut
ο· GOR or injected lift gas
ο· Size of the sssv (sub-surface-safety valve)
ο· Choke size
ο· Wellhead back pressure
Operating point
The operating point is the interception of IPR curve and VLP curve as shown in Figure I-7.
The draw of VLP curve is based on choosing an optimal diameter because big size increases
hydrostatic pressure losses and small diameter increases friction pressure losses. Very small
Tubing diameter reduces the capacity of production of the well.
21. 12
Figure I- 7: Operating point
I.3.2.2. Artificial lift
I.3.2.2.1 Introduction
Over a period of time since the oil field begin producing the reservoir pressure decrease.
As a result the pressure becomes insufficient to bring up the fluid to the surface. In this case
artificial lift methods are employed allowing additional support.[3]
There are several common artificial lift techniques that have been developed and optimized
for different operating conditions such as rod pumps, electric submersible pumps and
hydraulic pumps) apart from gas lift.
I.3.2.2.2. Artificial lift forms
o Rod Pumps
Rod pumps (Figure I-8) are the most widely used in-land form of artificial lift. this unit is
made up of a surface unit connected to a down-hole with sucker rods. The main role of the
rod pump is creating a reciprocating motion in a sucker-rod string that connects to the down-
hole pump assembly. The conversion of this reciprocating motion to vertical fluid movement
is done by the intervention of a plunger and valve assembly. . This type of pump is used in
low flow rate wells (typically 5- 1500 of barrels of liquid per day).[3]
22. 13
Figure I- 8: Typical rod pump [3]
o Hydraulic Pumps
Hydraulic system transfer energy down-hole by pressurizing special power fluid, usually
water or light refined oil or pumped through well tubing or annulus to a subsurface pump,
which transmits the potential energy to produced fluids. So as shown in Figure I-9 the fluid is
injected into the pump and a small-diameter nozzle, where it becomes a low pressure, high
velocity jet. Produced fluid from the well-bore is mixed with the injected fluid and then goes
into an expanding-diameter diffuser. knowing that in the Bernoulli equation of state:
β +
πΒ²
2π
+
π
ππ
= ππππ π‘πππ‘ II.6
when the pressure goes down the velocity goes up and vice versa. In the diffuser the fluid
underwent a velocity reduction and a pressure elevation. Common pumps consist of jets
(Venturi and orifice nozzles), reciprocating pistons, or less widely used rotating turbines.[6]
Figure I- 9: Hydraulic pump[4]
o Electric Submersible Pump
Electrical submersible pump is known as an economical and effective means of lifting
large volumes of fluid from deep wells under a variety of well conditions. Figure I-10
represents the ESP system .This system is characterized by it centrifugal pumps which contain
spinning impellers keyed on the shaft to put pressure on the surrounding fluid and leading it to
the surface. ESP is very versatile artificial lift method and can be found in operating
23. 14
environments all over the world. They can handle a very wide range of flow rates. The
remainder of this report details the components, sizing and operating principle.[3]
Figure I- 10: ESP system[4]
o Gas Lift
Gas Lift (Figure I-11) is a form of artificial lift where gas bubbles assist in lifting the oil
from the well. It's an additional high pressure gas injected either to the casing or tubing
annulus. The main purpose of gas lift technology is to reduce the well fluid density in order to
be capable to reach the surface. The process is as follows, the injected gas passes through a
valve where it mixes with the fluid and reduce its density. The reservoir pressure then lifts the
combined liquids to the surface where they are separated.[3][4]
Figure I- 11: Gas lift system[3]
24. 15
I.3.2.2.3. Advantages and disadvantages of different artificial lift technologies:
The advantages and disadvantages of the Major artificial lift methods are listed and compared
in Table I-1. Concerning electrical submersible pump advantages and limitations will be
treated in the next chapter.
Table I- 1: Advantages and Disadvantages of artificial lift technologies[4]
Artificial Lift Advantages Disadvantages
Rod Pumps
-Simple to operate
-Unit easy changed
-Can achieve -low BHFP
-Can lift high temperature
viscous oil
-Low intervention cost
-Can be installed in remote
locations without electricity
-Best understood by the field
personnel
-Pump wear with solids
(Sand, Wax...)
-Free gas reduce pump
efficiency
-heavy equipment for
offshore use
-Restricted flow and depth
-Potential wellhead leaks
Venturi Hydraulic Pump
-High volume
-Can use water as power
fluid
-Tolerate high well deviation
-Simplifies completions
significantly
-No moving parts, can
tolerate solids.
-High surface pressure
-Free gas reduce pump
efficiency
-Sensitive to change in
surface flow line-pressure
-Cavitations can occur with
high GOR
-High GOR impacts
performance
Gas Lift
-Solids tolerant
-large volume in high PI
wells
-Simple maintenance
-Unobtrusive
Surface location
-Tolerate high well deviation
-Tolerate high GOR reservoir
fluids
-Fairly low operation cost
-Flexibility: Can change
producing rate by adjusting
injection rates or/and
pressure.
-Lift gas may not be
available
-Not suitable for viscous
crude oil or emulsion
-Casing must withstand lift
gas pressure
I.4. Properties of reservoir fluids and phase behavior
I.4.1. Multiphase flow theory patterns and map
ο Flow theory
The three components of the equation for predicting pressure losses are: elevation or static
components, friction component, acceleration component.
βππ‘ππ‘ππ = πΈπππ£ππ‘πππ βπ¦ππππ π‘ππ‘ππ + πΉππππ‘πππ + π΄ππππππ‘πππ I.7
25. 16
ο Flow patterns
vertical flow
Figure I- 12: Vertical flow patterns
Figure I-12 represents the different vertical flow patterns:
ο Bubble flow: Numerous yet discrete gas bubbles are dispersed in the continuous liquid
phase.
ο slug flow: larger bubbles are formed with sizes similar to the tubing diameter. They are
separated from one another by slugs of liquids.
ο churn flow: Higher velocities change the aspect of the flow; it becomes very unstable
which threatens to damage the pipe.
ο wispy-annular flow: when the flow rates gets even higher the small droplets form clouds
of liquid in the center gaseous core.
ο annular flow: Gas velocity exceeds the liquid's velocity. The liquid travels then in the
tube as thin film on the wall as the gas flows as a continuous phase.
horizontal flow
Figure I- 13: Horizontal flow patterns
Figure I-13 represents the different horizontal flow patterns:
ο Bubble flow: Both gas and liquid move with the same velocity as the gas is dispersed as
bubbles that tend to accumulate at the top of the tubing.
ο slug flow: At higher gas velocities in this regime occurs with its bigger elongated bubbles
and large vibrations caused by the liquid slugs between the bubbles.
ο annular flow: At even greater gas velocities, the liquid forms a continuous annular film
that gets thicker at the bottom of the tube bubble point.
26. 17
ο Stratified flow: At low liquid and gas velocities, the two phases are completely separated.
The liquid goes to the bottom as the gas goes to the top.
ο Wavy flow: Increasing the fluids velocity in a stratified flow, waves are formed.
I.4.2. Bubble point.
The bubble point is defined as the pressure and temperature conditions at which the first
bubble of gas comes out of solution in oil.
Below the bubble point the solution of oil is saturated with gas, meaning that the oil contains
the maximum amount of gas that could it holds. So as the pressure drops along the way from
the bottom-hole to the well-head the gas will be separated from the solution as form of
bubbles and the oil will be unsaturated.
I.4.3. GOR (Gas Oil Ratio)
The oil gas ratio is the ratio between the volume of gas ( measured at standard conditions)
and the volume of oil at standard conditions.
πΊππ =
ππ(πππ‘π, 60Β°πΉ)
ππ(πππ‘π, 60Β°πΉ)
I.8
Where
Vg: volume of gas at standard conditions
Vo: volume of oil at standard conditions
I.4.4. FVF(Formation Volume Factor)
I.4.4.1. Formation Volume Factor (oil)
The oil formation volume factor (FVF/Bo) relates the volume of oil at stock-tank
conditions to the volume of oil at elevated pressure and temperature in the reservoir. Values
typically range from approximately 1.0 bbl/STB for crude oil systems containing little or no
solution gas to nearly 3.0 bbl/STB for highly volatile oils.
π΅π =
ππππ’ππ ππ πππ ππ πππ πππ£πππ, (Pr, ππ ππππππ‘πππ)
ππππ’ππ ππ π π‘πππ π‘πππ πππ ππ π π‘ππππππ ππππππ‘ππππ
I.9
I.4.4.2. Formation Volume Factor (gas)
The formation volume factor of gas is the ratio of the volume of gas at the reservoir
temperature and pressure to the volume at the standard or surface temperature and pressure
(ps and Ts). It is given the symbol Bg and is often expressed in either ((rcf) cubic feet of
reservoir volume per (scf) standard cubic foot of gas) or (barrels of reservoir volume per
standard cubic foot of gas).
π΅π =
ππ
ππ π
= (
π§ππ π
π
) (
ππ π
π§π π ππ ππ π
) =
ππ π π§π
ππ π π
I.10
where
ππ : Reservoir volume
ππ π : Volume in standard condition
π: Reservoir Temperature
π: Number of mole
π§: Compressibility factor (gas deviation factor)
27. 18
π§π π: Compressibility factor at standard condition
R: gas-law constant
ππ π: Temperature in standard condition
ππ π: Pressure in standard condition
ππ π
ππ π
=
14.696(ππ π)
519.67(Β°π )
= 0.0282793
which implies
π΅π = 0.0282793
π§π
π
(rcf/scf) I.11
The n divides out here because both volumes refer to the same quantity of mass.
Compressibility Factor
The compressibility factor is the same mass ratio of the real volume to the ideal volume,
which is a measure of the amount that the gas deviates from perfect behavior, is called the
super compressibility factor, sometimes shortened to the compressibility factor. It is also
called the gas deviation factor and given the symbol z. The gas deviation factor is by
definition the ratio of the volume actually occupied by a gas at a given pressure and
temperature to the volume it would occupy if it behaved ideally.
I.4.5. Water cut (WC)
Water cut is the ratio of water produced to the total volume of fluids produced: oil + water,
both volumes measured in standard conditions. It is expressed as a fraction in percent:
%ππ =
ππ€
ππ‘
Γ 100 I.12
Where:
ππ€: the volume of produced water
ππ‘: the total volume of produced fluid (oil + water)
% Wc: water cut percentage
I.4.6. Oil density
The density of a reservoir gas is defined as the mass of the gas divided by its reservoir
volume, so it can also be derived and calculated from the real gas law:
π π =
π π
ππ
=
πππ
π§ππ π/π
=
ππ πππ πΎπ
π§ππ π/π
=
28.967ππΎπ
π§π π
I.13
Where
ππ : Reservoir volume
π: Reservoir Temperature
π: Number of mole
π§: Compressibility factor (gas deviation factor)
R: gas-law constant
π π: Reservoir volume
ππ: average molecular weight of gas mixture
π πππ: molecular weight of air
π π: density of gas
28. 19
πΎπ: Specific gravity of gas
π π: mass of gas
I.5. Conclusion
In this chapter Our interest was revolved around defining the petroleum production system
and explaining factors that involve in production optimization of the well, quoting the
example of inflow and outflow performance methods and artificial lift systems.
29. 20
Chapter II: Electrical Submersible Pump(ESP)
Objective
This chapter will detailed one of
production invention features to
transfer pressure to the fluid. So that
it will flow from the wellbore to the
surface at the desired rate.
30. 21
II.1. Introduction
II.1.1. General history of ESP
Unlike the other artificial lift methods electrical submersible pump was innovated and
improved by a Russian named Armais Arutunoff in the late 1910s.[5]
In 1911, Arutunoff started the company Russian Electrical Dynamo of Arutunoff (its acronym
REDA still being known all over the world) and developed the first electric motor that could
be operated submersed in an oil well.[5]
In 1926 the first installation of electrical submersible was operated in the El Dorado field in
Kansas.
II.1.2. General overview of ESP
The electrical submersible pump typically called ESP is a powerful and profitable means
of artificial lift representing technical characteristics in order to tolerate harsh environment
conditions and produces moderate to high amounts of well fluids in even extreme regions.
Electrical submersible pump deal with many problems which could be encountered when
producing such as high water cut, sand production, highly deviated wells, high bottom hole
temperature, abrasive and corrosive issues and high viscosity fluid.
ESP installation
ESP consists of an electrical alternative current motor, seal section, gas separator, multi-
stage centrifugal pump, power cable, surface control mechanism and transformers.
The classical or βconventionalβ installation is illustrated in Figure II-1 where the ESP unit is
run on the tubing string and is submerged in well fluids.[7]
The electric submersible motor is at the bottom of the unit just above the perforation zone.
It is connected to the protector (a.k.a. seal section) that ensures the unit safety through many
crucial functions. Overhead of the protector a pump intake or gas separator is settled which
allows well fluids to enter the centrifugal pump excluding from low quantities of free
gas(taken from the solution in the gas separator). Liquid is lifted up to the surface by the
multistage centrifugal pump, the heart of the ESP system. Surface equipments include a
junction box, surface electric cables and a control unit called switchboard that provides
measurement and control functions. The ESP unit receives AC electricity from a set of
transformers (not shown) which supply the required voltage by stepping up or down the
voltage available from the surface electric network.[7]
31. 22
Figure II- 1: Conventional ESP installation[7]
Theory of Operation
ESP constructional and operational features underwent a continuous evolution over the
years, their basic operational principle remained the same.[7]
The whole ESP systems function is to transform electrical power supplying from the
surface through copper resistant cables to head or potential energy in a form of pressure . ESP
units are typically installed over the perforation zone permitting fluid to flow from the
perforated area past the motor aiming to cool it. The motor generates the rotation of a shaft
which connects the seal protector and the pump by a mechanical coupling. So as the impellers
(the rotating part of the pump stage) are keyed to the shaft they will rotate in highly speed at
the same RPM (rotation per minute) of the motor shaft imparting Kinetic energy to the fluid
from a centrifugal force with the intervention of a stationary part of the pump called
diffuser.[3]
II.2. ESP components
ESP Systems include all the necessary components to transfer power from the surface,
convert the power into shaft rotation and impart energy to the produced fluids. A typically
ESP system includes:[3]
ESP down-hole components:
β’ Pump
β’ Gas Separator
β’ Seal
β’ Electric Motor
ESP Surface components:
β’ Junction box
β’ Power Cable
β’ Motor Controller
β’ Transformer
32. 23
II.2.1. ESP down-hole components
II.2.1.1 Pump
Introduction and purpose
Being the major part of the ESP system it's crucial to understand the operating principle of
the submersible pump. The main objective of a multistage centrifugal pump is to lift the fluid
from the bottom-hole up to the surface by converting the energy from rotational shaft into
centrifugal pump.
components
As shown in figure II.2 the submersible pump is made of the following basic components:
ο· Shaft, Impeller, Diffuser, Housing and Intake
Figure II- 2: ESP submersible pump cutaway[3]
Impeller
The impeller is locked to the shaft and rotates at the motor RPM. As the impeller rotates it
imparts centrifugal force on the production fluid. Figure II-3 is an illustration of an impeller
keyed to a shaft, and identifies key subcomponents of the impeller.[3]
Figure II- 3: Illustration of impeller and subcomponents[3]
Diffuser
The diffuser in the Figure II-4 turns the fluid into the next impeller and does not rotate.
33. 24
Figure II- 4: illustration cutaway of a diffuser[3]
pump stage
The pumps stage in Figure II-5 is a combination of an impeller and a diffuser.
Figure II- 5: Illustration of a pump stage[3]
pump Intake
The pump intake in Figure II-6 attaches to the lower end of the pump housing and provides
a passageway for fluids to enter and a flange to attach to the ESP seal.
Figure II- 6: Pump intake[3]
II.2.1.2 Gas separator
Introduction and purpose
Gas production has been a problem since the early days of oil production. It limited
production on many oil wells producing with pumps, It causes a gas locking and cavitations.
For this reason a gas separator should be designed to keep free gas for entering the pump.[3]
Components
The ESP Gas Separator in Figure II-7 is made up of the following major components:[3]
34. 25
- Gas Vent Port, Guide Vane, Inducer or High Angle Vane Auger (Patented), Separation
Chamber, Intake and a Shaft
Figure II- 7: Rotary gas separator[3]
II.2.1.3. Seal section
Introduction and purpose
The electric motor of the ESP system is completely sealed against the produced liquid in
order to prevent short-circuits and burning of the motor after it is contaminated with well
fluids.[7]
ESP motors must be kept open to their surroundings but at the same time must still be
protected from the harmful effects of well fluids. The main reason for this is that since the
motor must be filled up with a high dielectric strength oil, ESP motors operating at elevated
temperatures, if completely sealed, would burst their housing due to the great pressure
developed by the expansion of the oil.[7]
This is guaranteed by connecting a protector (a.k.a. seal) section between the motor and the
centrifugal pump.[7]
Seal sections perform the following vital functions:
β’ Isolates the clean motor oil from wellbore fluids to prevent contamination.[3]
β’ Couples the torque developed in the motor to the pump intake via the protector shaft.
β’ Provides a reservoir for the thermal expansion of the motor's oil.[4]
Seal section types
There are two main types of seal section:[4]
ο· Bag type protectors (positive seal): Designed to physically separate the well fluid and
motor oil.
ο· Labyrinth type protectors: Use the difference in specific gravity of the well fluid and the
motor oil to keep them apart even though they are in direct contact.
Components
Seal Sections are made up of the following major components:[3]
Mechanical Seals, Elastomer Bag(s), Labyrinth Chamber(s), Thrust Bearing, Heat Exchanger
Figure II-8 shows the construction of major components of a typical seal section.
35. 26
Figure II- 8: ESP combined seal section components[3]
II.2.1.4. Electrical motor
Introduction and purpose
The major and sole objective of a motor is the transformation of electrical energy into
motion that turns the shaft. This latter is connected through the seal and gas separator and
turns the pump impellers.[3]
components
Figure II-9 is an ESP Motor made up of the following major components:[3]
- Rotors, Stator, Shaft, Bearings, Insulated Magnet Wire, Winding Encapsulation, Rotor and
Stator Laminations, Housing, Thrust Bearing
Figure II- 9: ESP motor cutaway illustration[3]
II.2.2. ESP Surface components
II.2.2.1. Junction Box
A junction box (vent box) performs three functions. First, it provides a connection point for
the surface cable from the motor control panel to the power cable in the wellbore coming
from the wellhead . Second, it allows for any gas to vent that may have migrated through to
the power cable.
Finally, it provides accessible test point for electrically checking down-hole equipment.[4]
36. 27
During the installation of the junction box it's required to leave a minimum distance from
wellhead (35 ft) and from the switchboard (15ft).
II.2.2.2 Power cable
Banded to the tubing, the power cable is considered as an electrical power transfer means
from the surface to the down-hole motor. This cable must be of specific construction to
prevent mechanical damage, and able to retain its physical and electrical properties when
exposed to hot liquids and gasses in oil wells.[3][4]
The power cable is available on both flat or round construction. It consists of three copper
conductor wires extending from the top of the motor lead to the wellhead. The size of the
cable selected is based on amperage and voltage drop.[3][4]
II.2.2.3. Motor controller
The main function of the motor controller is primarily to protect the ESP motor by
measuring the surface current and voltage to avoid the underload and overload of the motor.
The controller also provides the capability to monitor performance of down-hole electrical
system(current, voltage, frequency, etc).
II.2.2.4. ESP variable speed drive
Variable speed drives (VSD) allows the variation of the ESP performance through the
motor speed control. As the shaft connects the motor to the protector and the pump VSD
modify also the pump impellers rotation speed. By allowing the pump speed to be varied, the
rate and/or head can be adjusted (depending on the application) with no modification of the
down-hole unit.[3]
Its numerous operational features make it one of the ESP assets such as:[3]
ο· Controlling motor speed can avoid heat failure (burning of the motor components)
ο· Control well drawdown
ο· Adjust ESPs with changing well conditions
ο· Decrease system stress at start up
II.2.2.5. Transformer
Since ESP equipments operation need a variable range of voltage from 250 volts up to
4000 volts depending on the power of the components. Voltage transformation is required
because electrical power is usually supplied to oilfield at a voltage of 6000 volts or higher.[3]
Transformers contain a substantial number of secondary voltage taps which allows a wide
range of output voltages. This is required in order to adjust the surface voltage to account for
cable voltage drop that occurs due to setting depths.[3]
II.2.3. ESP mainly support equipment
Most of well fields requires the involvement of some additional support equipment. For
example the most substantial ones are the wellhead, check valves, drain valve, backspin relay
and the centralizer. These equipments depends necessarily on the power available and the
conditions of the well.[3]
Wellhead
The main function of the wellhead is to support the weight of the subsurface equipment
and to maintain annular pressure of the well. It includes the pack-off generally known as the
tubing head bonnet. It's an additional element of sealing around the cable and the tubing. The
highest rated pack-off can resist pressure up to 5000 psi.[3]
Check Valve
37. 28
To avoid fluid falling down-hole during the shut off of the ESP system a check valve
should be installed. Without this equipment reverse rotation of the pump impellers and as a
result the reverse rotation of the pump and motor shaft may occur. In this case it cause a
electrical failure or mechanical damage to the equipment.[3]
Centralizer
Centralizers are used in ESP applications to set the equipment in the center of the wellbore.
This is chiefly practical in deviated wells to eliminate external damage and insure proper
cooling of the equipment..[3]
II.3. Performance of an ESP system
The Brake Horse Power is the power required to drive the pump which needs to cover the
sum of the energy that pump the well fluid and the energy losses arising in the pump and the
tubing due to friction. The mathematical relationship between head, capacity, efficiency and
brake horsepower is expressed as: [3]
π΅π»π =
π Γ π» Γ ππππππππ πΊπππ£ππ‘π¦
ππ’ππ πΈπππππππππ¦
II.1
Where
Q: flow rate, bpd
H: head required, ft
The performance of ESP pumps is characterized by the pump performance curves which are
plotted in figure II-10 in the function of the pumping rate and represent:[7]
ο· the head developed by the pump
ο· the efficiency of the pump, and
ο· the mechanical power (brake horsepower) required to drive the pump when pumping
water.[7]
Figure II- 10: example performance curve of an ESP pump[7]
These curves are experimentally obtained with freshwater under controlled conditions at an
operating temperature of 60ΒΊF. Tests on submersible pumps are made by driving the pump at
a constant rotational speed, usually 3,500 RPM for 60 Hz service. The actual performance
may be obtained by a simple correction using the Affinity Laws.[7]
Affinity Laws
38. 29
These are a couple of equations that link the actual speed of a centrifugal pump and its
performance parameters. There are in total three relationships:
ο The flow rate is directly proportional to the pump's operating speed:
π2 = π1
π2
π1
II.2
ο The head is proportional to the square of the pump's operating speed:
π»2 = π»1 (
π2
π1
)
2
II.3
ο The brake horse power is proportional to the square of the pump's operating speed:
π΅π»π2 = π΅π»π1 (
π2
π1
)
3
II.4
Where:
Q1: the first flow rate, bpd
Q2: the second flow rate, bpd
H1: the first head, ft
H2: the second head, ft
BHP1: the first brake horsepower, HP
BHP2: the second brake horsepower, HP
N1: first rotational speed, rpm
N2: second rotational speed, rpm
II.4. Evaluation of ESP components
II.4.1 ESP advantages
General advantages of using ESP units can be summed up as follows:
ο· Good efficiency over the widest range of production rate ( high to extremely high amount
of liquid)[5][4]
ο· Can achieve high production rates: the maximum is around 30,000 bpd from ft.[4][5]
ο· Suitable for both vertical and deviated well[5]
ο· Can operate reliably in onshore and offshore wells.[4]
ο· Can be flexible to accommodate changing conditions in time (PI, water cut Pwf, Pr, etc)
due to the Variable Speed Drive characteristic.[4]
ο· Can operate under tough conditions such as low bottom-hole pressure, high bottom-hole
temperature, high amount of corrosion and scale. [4][5]
ο· Surface equipment required a minimal space comparing with the other artificial lift
systems(sucker rod...) [5]
II.4.2. ESP disadvantages
The most known of ESP disadvantages are listed below:
ο· Expensive intervention cost: A pulling unit (heavy work-over rig) is required to retrieve
the failed ESP regardless of failed component. [4][5]
ο· Extremely high well temperature cable and motor insulation.[4]
ο· High solids and sand or abrasive materials may cause rapid equipment wear. For this
reason special abrasion-resistant materials are used and that increase the capital cost.[4]
[5]
ο· The presence of free gas at pump suction weakens the submersible pump's efficiency by
gas locking problems and can even totally prevent liquid production.[5]
39. 30
ο· ESP installation required a crucial availability of high voltage electrical power. [5]
ο· Production of high viscosity oils increases power requirements and reduces lift.[5]
II.5. Conclusion
In this chapter we intended to present the electrical submersible pump system. The main
objective was to thoroughly describe the ESP equipments with highlighting the particular
function of each one. We also mentioned the importance and the limitation of the ESP by
enumerating its advantages and disadvantages.
40. 31
Chapter III: Case study
Objective
This chapter includes a detailed
approach to follow in order to come
up with an electrical submersible
pump hand sizing and AutographPC
software.
41. 32
III.1. Hand sizing
III.1.1. The 9 steps procedure
The design of the Electric Submersible pump system follows these nine steps :
Step1: Basic Data
Collect and analyze all the well data that will be used for the design.[3][8]
Step2: Production Capacity
Determine the well productivity at the desired pump setting depth or determine the pump
setting depth at the desired production rate. [3][ 8]
Step3: Gas Calculation
Calculate the fluid volumes, including gas, at the pump intake conditions. [3][ 8]
Step4: Total Dynamic Head
Determine the required dynamic head and so the pump discharge requirement.[3][ 8]
Step5: Pump Type
For a given capacity and head select the pump type that will have the highest efficiency for
the desired flow rate. [3][ 8]
Step6: Optimum Size of Components
Select the optimum size of pump, motor and protector and check equipment limitations. [3][
8]
Step7: Electric Cable
Select the correct type and size of cable.[3][ 8]
Step8: Accessories and Optional Equipment
Select the motor controller, transformer, tubing head and optional equipment.[3][ 8]
Step9: The Variable Speed Pumping System
For additional operational flexibility, select the variable speed submersible pumping system.
Reliable information or data must be available to design a submersible pumping unit.
Although if the information, especially that pertaining to the wellβs capacity, is poor, the
design will not be accurate and will be almost marginal. Bad data often results in a misapplied
pump and costly operation.[3][ 8]
A misapplied pump may operate outside the recommended range, overload or under-load the
motor or drawdown the well at a rapid rate which may result in formation damage. On the
other side, the pump may not be large enough to provide the desired production rate.[3][ 8]
The selection and design procedure may vary significantly depending on the well fluid
properties. The three major types of ESP applications are:[3][ 8]
ο· High water-cut wells producing fresh water or brine.
ο· Wells with multi-phase flow (high GOR).
ο· Wells producing highly viscous fluids.
Following is list of the data required:
A) Wells Data
ο· Casing or liner size and weight.
ο· Tubing size, type and thread (condition).
ο· Perforated or open hole interval.
ο· Pump setting depth (measured and vertical).[3][ 8]
B) Production Data
ο· Wellhead tubing pressure.
ο· Wellhead casing pressure.
ο· Present production rate.
ο· Producing fluid level.
42. 33
ο· Static fluid level and/or static bottom-hole pressure.
ο· Datum point.
ο· Bottom-hole temperature.
ο· Desired production rate.
ο· Gas-oil ratio.
ο· Water cut.[3][ 8]
C) Well Fluid Conditions
ο· Specific gravity of water.
ο· Oil API or specific gravity.
ο· Specific gravity of gas.
ο· Bubble-point pressure and temperature.
ο· PVT data.[3][ 8]
D) Power Sources
ο· Available primary voltage.
ο· Frequency.
ο· Power source capabilities.[3][ 8]
E) Possible Problems
ο· Sand Production.
ο· Corrosion.
ο· Paraffin.
ο· Emulsion.
ο· Gas.etcβ¦[3][ 8]
43. 34
III.1.1.1 Basic data
Table III- 1: Pump Design data for 3 wells
Well name Cherouk 1
Shaheen 1 Badr 6
Well data
API casing
9 5/8"OD(8.681"
ID) 47#/ft
9 5/8"OD(8.681"
ID) 47#/ft
9 5/8"OD(8.681"
ID) 47#/ft
API Tubing
3 1/2"OD(2.991"
ID) 9.3#/ft
3 1/2"OD(2.991"
ID) 9.3#/ft
3 1/2"OD(2.991"
ID) 9.2#/ft
Well Type
Cased and
perforated hole
Cased and
perforated hole
Cased and
perforated hole
Perforation intervals
From 11023.488 ft
to 11305.63 ft
4 zones of perfo:
From 10331 ft to
10492 ft
From 11040 ft to
11335 ft
From 11381 ft to
11492 ft
From 11584 ft to
11686 ft
From 10724,6 ft
to 11568,1 ft
Reservoir data(from test and production data)
Present Production rate 1965 BFPD 1113 BFPD 1432 BFPD
Reservoir pressure 4200 psi 2285 psi 3070 psi
Current Bottom-hole
flowing pressure
3091 psi for 1965
BPD
1193.82 psi for
1065 BPD
1608.78 psi for
1376 BFPD
Producing GOR 1577 scf/stb 800 scf/stb 647 scf/stb
Water cut 89.5% 70% 24%
Oil API Gravity 42.3Β° 40Β° 41Β°
44. 35
Bottom Hole temperature 197Β°F 198Β°F 195.8Β°F
Water specific gravity 1.2 1.2 1.2
Gas specific gravity 0.84 0.825 0.82
PVTdata
Solution gas oil
ratio (Rs)
To be determined from design
Oil FVF (Bo) 1.87 rb/stb 1.43 rb/stb 1.43 rb/stb
Bubble
point
Pressure
4080 psi 1985 psi 1969 psi
Temperature
197 Β°F 199.4 Β°F 211 Β°F
Production
Index(PI)
1.8 bbl/day/psi 1.02 bbl/day/psi 0.98bbl/day/psi
Specifications
Desired Production rate 3000 bpd 1623 bpd 1660 bpd
Desired pump setting
depth
10170.48 ft 10170.48 ft 10170.48 ft
Desired PIP: Pump Intake
Pressure
To be determined within design
Required wellhead
pressure
220 psi 162 psi 184 psi
GOR through pump To be determined within design
Required electric power To be determined within design
45. 36
Desired pump series To be determined within design
Desired pump type To be determined within design
Motor type To be determined within design
Special
problems
Sand No No No
Scale
Deposit
No No No
Corrosion No No No
Paraffin No No No
H2S No No No
III.1.1.2. Production capacity
In this step, we will determine the well productivity at the test pressure and production. In
this case of study the pump setting depth PSD and the desired production rate Qd are given as
well as the production index PI.
The pump intake pressure can for instance be calculated. The pump intake pressure is
necessary to properly feed the pump and prevent cavitation or gas locking.
We will determine firstly the Pressure at well face Pwf at the desired production rate:
ππΌ =
ππ
ππ β ππ€π
III.1
So:
ππ€π = ππ β (
ππ
ππΌ
) III.2
Where
ππ€π: Pressure at well face (bottom hole flowing pressure)
ππ: reservoir pressure
ππ: Desired flow-rate
ππΌ: Productivity index
The pump intake pressure can be determined by correcting the flowing bottom-hole
pressure for the difference in pump setting depth and the datum point and by considering the
friction losses in the annulus.
As there is a mixed solution of water and oil in the produced fluids, itβs required to calculate
a composite specific gravity of the produced fluids. To find the composite specific gravity:
π΄πππ’π π‘ππ πππ‘ππ π πππππππ πΊπππ£ππ‘π¦ = ππ Γ ππΊπ€ III.3
Where
WC: water cut
SGw: Specific gravity of water
III.4
46. 37
πππ ππππππππ πΊπππ£ππ‘π¦ =
141.5
Β°π΄ππ + 131.5
π΄πππ’π π‘ππ πππ ππππππππ πΊπππ£ππ‘π¦ = (1 β ππ) Γ ππΊπππ III.5
Where
SGoil: specific gravity of oil
so:
ππΊππππ’ππ = π΄πππΊ + π΄πππΊ III.6
Where
SGliquid: Composite specific gravity of liquid
AWSG: Adjusted Water Specific Gravity
AOSG: Adjusted Oil Specific Gravity
The pressure due to the difference of perforation depth and pump setting depth can be
determined as follows:
πππΌ =
βπππ(ππ‘) Γ ππΊππππ’ππ
2.31 (
ππ‘
ππ π
)
III.7
where
βπππ(ππ‘)=πππ‘π’π ππππ‘β(ππ‘)βππ’ππ ππππ‘β(ππ‘) III.8
Therefore the pump intake pressure without friction PIP will be:
ππΌπ = ππ€π β πππΌ III.9
The friction to the intake is calculated as follows:
πΉππππ‘πππ π‘π π‘βπ πππ‘πππ(ππ‘) = πΉπΏ Γ (πππ‘π’π ππππ‘β β ππ’ππ π ππ‘π‘πππ ππππ‘β) III.10
Where
FL: Friction Loss
This value of friction loss is determined by use of the chart of friction losses in API tubular
(Appendix A.1.a).
As the pump is setting at liner level (7"OD) and the desired flow rate of the three wells
(Cherouk1, Shaheen1 and Badr 6) are as follows 3000 bbl/day, 1623 bbl/day,1660 bbl/day,
we noticed that the vertical lines don't across the oblique one (Appendix A.1.a). In view of
that fact we assumed that the friction losses in the three cases is the minimum value of the
chart.
So the pump intake pressure PIP w/f considering the pressure losses is
ππΌπ π€π = ππΌπ β πππππ‘πππ π‘π π‘βπ πππ‘πππ III.11
47. 38
Table III- 2: Pump intake pressure calculation steps
Well name Cherouq1 Shaheen1 Badr6
Bottom-hole flowing
pressure at the
desired rate
Pwf(psi)
2533.33 693.713 1376.391
Adjusted Water
specific gravity
1.074 0.84 0.288
Β°API 42.3 40 41
Water Cut WC(%) 89.5 70 24
Specific Gravity of
oil SGoil
0.814 0.825 0.82
Specific Gravity of
Water SGw
1.2 1.2 1.2
Adjusted oil specific
gravity
0.085 0.247 0.623
Specific Gravity of
Liquid SGliquid
1.159 1.087 0.911
Datum depth(ft) 11164.56 11146.35 11146.35
Pump depth(ft) 10170.48 10170.48 10170.48
Head(ft) 994.08 975.87 975.87
PSI 498.97 459.43 385.034
Pump Intake
Pressure without
Friction PIPw/o
Friction
2034.362 psi 234.285 psi 991.358 psi
Friction factor(ft) 0.01 0.01 0.01
Pressure due to
friction (ft)
9.94 9.7587 9.7587
Pressure due to
friction (psi)
4.99 4.594 3.85
Pump Intake
Pressure with
Friction PIPw/f(psi)
2029.371 229.69 987.508
48. 39
III.1.1.3. Gas calculation
In this third step, we need to determine the total fluid mixture inclusive of water, oil and
free gas that will enter the pump.[3][8]
1) We will determine first of all the solution Gas Oil Ratio (Rs) at the pump intake, for this
purpose we will use the Standingβs approach or correlation and substitute the pump intake
pressure for the bubble pressure in the following formula:
π π = ππΊπ Γ (
ππ
18
Γ
100.0125ΓΒ°π΄ππΌ
100.00091Γπ(Β°πΉ)
)
1.2048
III.12
where:
T: reservoir temperature.
SGgas: specifig gravity of gas.
Pb: bubble point pressure
2) Since the oil formation volume factor is given no need to determine it using the Standingβs
approach. We will assume that it will not change remarkably otherwise we could use the
following formula to check the exactitude of our data:
π΅π = 0.972 + 0.000147 Γ {5.61 Γ π π Γ ((
ππΊπππ
ππΊπππ
)
0.5
) + 1.25 Γ (1.8π‘ + 32)}
1.175
III.13
Where:
t: Bottom-hole Temperature, Β°C
Rs: solution gas oil ratio at pump intake
SGoil: specific gravity of oil
SGgas: specific gravity of gas
Bo is measured in (rb/stb) where rb is barrel at reservoir conditions
3) Determine the gas volume factor Bg as follows:
π΅π = 5.04 Γ
π Γ π
π
III.14
Where:
Z: Gas compressibility factor
T: Bottom-hole temperature degrees Rankin (460+Β°F)
P: Submergence pressure, psi (reservoir pressure)
The compressibility factor or the deviation factor Z is not given in the well data table so we
should calculate it.
Based on the gas specific gravity we determine as a first step the pseudo-critical pressure and
temperature referring to the (Appendix A.2)
After determining the Pseudo-critical Temperature Tpc(Β°R) and the Pseudo-critical Pressure
Ppc (psi) we calculate the Pseudo-reduced Temperature Tpr(Β°R) and the Pseudo-reduced
Pressure Ppr(psi).
πππ =
ππ
πππ
III.15
49. 40
πππ =
π
πππ
III.16
where:
T: bottom-hole temperature, Β°R
Pr: reservoir pressure
With these two parameters the deviation factor can be graphically determined from (Appendix
A.3)
4) Next, we will determine the total volume of fluids and the percentage of free gas released
at the pump intake:
a) Using the producing GOR and the oil volume at the surface, we determine the total volume
of gas Tg(mcf):
ππ =
π΅πππ· Γ πΊππ
1000
III.17
where:
Tg: total volume of gas at the surface
BOPD: barrel of oil per day
GOR: producing gas oil ratio (at the surface)
mcf is a traditional unit of volume equal to 1000 cubic foot
b) Using the solution GOR (Rs) at the pump intake, we determine the volume of solution
gas SOLg(mcf):
πππΏπ =
π΅πππ· Γ π π
1000
III.18
where:
SOLg: the volume of solution gas (gas dissolved in the gas and oil solution)
BOPD: barrel of oil per day
Rs: solution gas oil ratio (at pump intake)
c) The difference represents the volume of free gas (Fg) released from solution by the
decrease in pressure from bubble point pressure Pb to pump intake pressure PIP
πΉπ = ππ β πππΏπ III.19
d) The volume of oil (Vo) at the pump intake:
ππ = π΅πππ· Γ π΅π III.20
e) The volume of free gas (Vg) at the pump intake:
ππ = πΉπ Γ π΅π III.21
f) The volume of water (Vw) at the pump intake:
50. 41
ππ€ = π΅πππ· Γ π΅π€ III.22
Where:
BWPD: barrel of water per day
Bw: water formation volume factor
we suppose that Bw =1
g) The total volume (Vt) of oil, water and gas at the pump intake can be now determined:
ππ‘ = ππ€ + ππ + ππ III.23
h) The ratio or the percentage of free gas %Fg present at the pump intake to the total of fluid
is:
%πΉπ =
ππ
ππ‘
III.24
Actually, as long as the gas remains in solution, the pump behaves normally and at high
performance as if itβs pumping a liquid of low density. However, the pump begins producing
lower head than required as the gas/oil ratio (at pumping conditions) increases beyond a
βcriticalβ value (usually about 10 % to 15 % of total fluid volume). If the percentage of free
gas to the total of fluid volume is less than 10 %, the pump can withstand this and the
performance decreases slightly but over 10 %, the performance of the pump decreases
significantly. The main reason for this is that it will occur great slippage between the two
phases present liquid and gas leading to decrease of the pump intake pressure an. Accordingly
the phenomenon of cavitation appears and unfortunately the head required couldn't be
achieved, a separator must be installed to deal with this problem.[3][8]
Table III- 3: Free gas calculation steps
Well name Cherouq1 Shaheen1 Badr6
Specific Gravity of
Gas SGgas
0.84 1.08 0.99
Pump Intake
Pressure PIP(psi)
2029.371 229.69 987.508
Β°API 42.3 41 40
Bottom-hole
Temperature
BHT(Β°F)
197 198 195.8
Solution GOR
Rs(scf/stb)
657.188 56.376 311.814
Specific Gravity of
Oil SGoil
0.814 0.825 0.82
Bottom-hole
temperature(Β°C)
91.66 92.22 91
51. 42
Oil Formation
Volume Factor
Bo(bbl/bbl)
1.87
1.43
1.43
Bottom-hole
temperature
BHT(Β°R)
657 658 655.8
Pseudo-Critical
Pressure Ppc(psi)
665 490 655
Pseudo-Critical
Temperature
Tpc(Β°R)
437.5 650 485
Pseudo-Reduced
Pressure Ppr
6.316 3.515
4.687
Pseudo-Reduced
Temperature Tpr
1.468 1.348 1.352
Compressibility
Factor Z
0.885 0.67 0.72
Reservoir Pressure
Pr(psi)
4200 2285 3070
Gas Formation
Volume Factor
Bg(bbl/mcf)
0.698 0.972 0.775
Barrel of Oil Per
Day BOPD(bbl/day)
315 487 1261.4
Producing
GOR(scf/bbl)
1577 800 647
Total Gas at the
surface Tg(mcf)
496,755 389.549 818.125
Solution Gas at the
intake SOLg(mcf)
207.014 27.451 393.322
Free Gas at the
intake Fg(mcf)
289.74 362.095 422.802
Volume of Oil at
pump depth
Vo(bbl)
589,05 696.315 1803.801
Volume of Gas at
pump depth
Vg(bbl)
202.162
352.102 327.743
52. 43
Volume of Water at
pump depth
Vw(bbl)
2685
1136.178 398.337
Total Volume at
pump depth Vt(bbl)
3476.212 2184.595 2529.881
Percentage of Free
Gas at pump depth
Fg(%)
5,81% 16.11% 12.94%
In our case of study the percentage of free gas is less than 10% by volume just for
Cherouq1, it would have little effect on the pump performance therefore, a gas separator is not
required. But for Shaheen 1 and Badr 6 we should install a gas separator because the
percentage of free gas is higher than 10%. The gas separator should have the same diameter as
the pump, that's means the same series. Our choice is based on the series of the pump.(See
ESP Design summary table.
III.1.1.4. Total dynamic head
This step consists on the calculation of the total dynamic head required to pump the desired
capacity. The total pump head refers to feet of liquid being pumped and is calculated to be the
sum of:
ο· Net well lift (dynamic lift).
ο· Well tubing friction losses.
ο· Wellhead discharge pressure converted to footage.[3][10]
The simplified equation is as follows:
ππ·π» = π»π + πΉπ‘ + ππ III.25
Where:
TDH: Total dynamic head in feet delivered by the pump when pumping the desired volume.
Hd: Vertical distance in feet between the wellhead and the estimated producing fluid level at
the expected capacity (Figure III-1).
Ft: The head required to overcome the friction losses in tubing.
Pd: The head required to overcome friction in the surface pipe, valves etc⦠and to overcome
also elevation changes between wellhead and the tank.
53. 44
Figure III- 1: Total dynamic head[10]
1) Determination of Hd:
The vertical distance between the estimated producing fluid level and the surface (Hd) is
determined as follows:[3][8]
π» π = πππ· β (
ππΌπ Γ 2.31
ππΊππππ’ππ
) III.26
Where:
PSD: pump setting depth, ft
PIP: pump intake pressure, psi
SGliquid: specific gravity of the liquid
2) Determination of the tubing friction losses:
This value is determined by using the chart of friction losses in API tubular (Appendix A.1.b)
πΉπ‘ =
ππ’ππ π ππ‘π‘πππ ππππ‘β Γ πππππ‘πππ ππππ‘ππ
1000
III.27
The discharge pressure head (desired wellhead pressure ) is determined as follows:
ππ(ππ‘) =
π·ππ»π(ππ π) Γ 2.31(
ππ‘
ππ π)
ππΊππππ’ππ
III.28
54. 45
where
Pd: discharge pressure, ft
DWHP: desired wellhead pressure, psi
SGliquid: specific gravity of liquid
Finally, the total dynamic head is the sum of these three terms:
ππ·π» = π»π + πΉπ‘ + ππ III.29
Table III- 4: Total Dynamic head calculation
Well name Cherouq1 Shaheen1 Badr6
Pump intake
pressure PIP(ft)
4043.039 487.885 2502.844
Specific Gravity of
liquid SGliquid
1,159 1.087 0.911
Net Dynamic Lift
Hd(ft)
6127.44 9682.594 7667.635
Friction factor 49 16 16.5
Tubing friction
losses Ft(ft)
498.353 162.72 167.813
Desired Well-Head
Pressure
DWHP(psi)
220 162 184
Discharge Pressure
Pd(ft)
438.298 314.103 466.349
Total Dynamic
Head TDH(ft)
7064.091 10189.426 8301.79
III.1.1.5. Pump selection
1) Determination of the down-hole desired flow rate:
π πππ€πββπππ = π πππ ππ‘ π‘βπ πππ€πββπππ + π π€ππ‘ππ ππ‘ π‘βπ πππ€πββπππ. III.30
π πππ€πββπππ = π΅π Γ π πππ ππ‘ π‘βπ π π’πππππ + π΅ π€ Γ π π€ππ‘ππ ππ‘ π‘βπ π π’πππππ III.31
where
Q down-hole: flow rate of liquid at the pump intake
Q oil at the down-hole: Flow rate of oil at the pump intake
Q water at the down-hole: Flow rate of water at the pump intake
Q oil at the surface: Flow rate of oil at the surface
Q water at the surface : Flow rate of water at the surface
Bo: Oil formation volume factor
Bw: Water formation volume factor
2) choosing the pump:
55. 46
Based on the required rate, we have to choose the pump with the largest diameter which fits in
the Liner 7"OD and be operating at the peak efficiency.
3) The pump performance curve can link a specific production rate with several
characteristics such Head per stage, the brake horse power of the pump and the efficiency
percentage.
4) Determination of number of stages:
We can now calculate the number of stages required:
ππ’ππππ ππ π π‘ππππ =
ππ·π»
π»πππ/π π‘πππ
III.32
Where
TDH: Total Dynamic Head
5) Determination of the total brake horse power BHP:
π΅π»π = ππ’ππππ ππ π π‘ππππ Γ ππΊππππ’ππ Γ (π΅π»π/π π‘πππ) III.33
6) Choosing the level performance:
6.a The Xp performance series
In addition to more head per stage, Centrilift has wider vane openings, in both the impeller
and the diffuser, which reduce the pump plugging and abrasive wear for enhanced run life.
The XP performance series provides abrasion resistance (AR) pump designs
The selection of AR depends basically on flow regime
6.b The Stabilized Severe Duty (SSD):
Used for wells where highly abrasive conditions are present requiring down thrust
protection for radial flow stages, where the diffusers with particle swirl suppression ribs
reduce sand cutting damage.
6.c The Stabilized extreme Duty(SXD):
Used for wells at extremely abrasive conditions and high mixed flow stages are present.
The table below summarizes the required data for pump selection.
Table III- 5: Required Data for pump selection
Well name Cherouq1 Shaheen1 Badr6
Desired rate of
liquid at the surface
Qsurface liquid
3000 bbl/day 1623 bbl/day 1660 bbl/day
Desired rate of oil
at the surface
Qsurface oil
315 bbl/day 486.934 bbl/day 1261.4 bbl/day
Desired rate of
water at the surface
Qsurface water
2685 bbl/day 1123.178 bbl/day 398.337 bbl/day
Oil Formation
Volume Factor
Bo(bbl/bbl)
1.87 1.43 1.43
56. 47
Water Formation
Volume Factor
Bw(bbl/bbl)
1 1 1
Desired rate of oil
at the pump intake
Qoil down-hole
589.05 bbl/day 696.315 bbl/day 1803.801 bbl/day
Desired rate of
water at the pump
intake Qwater down-hole
2685 bbl/day 1123.178 bbl/day 398.337 bbl/day
Desired rate of
liquid at the pump
intake Qliquid down-hole
3274.05 bbl/day 1832.494 bbl/day 2202.138 bbl/day
Desired rate of
liquid at the pump
intake Q liquid down-
hole
520 M3
/day 291 M3
/day 350 M3
/day
Casing OD 9 5/8" 9 5/8" 9 5/8"
Tubing OD 3.1/2" 3.1/2" 3.1/2"
Liner OD 7" 7" 7"
After a thorough checking we choose from the Centrilift pump catalog[6]:
ο· Centurion pump 538 series: P37 (Figure III-2) For Cherouq 1
ο· Centurion pump 538 series: P23 (Figure III-3) For Shaheen 1
ο· Centurion pump 538 series: G31 (Figure III-4) For Badr 6
8) Pump performance curves
58. 49
Figure III- 4: Pump performance curve 538 series G31 Centurion pump[6]
a) Pump's stage and housing number
Referring to (Appendix B.1) we choose the number of stages and housing defining each pump
based on number of stage calculated theoretically.
Table III- 6: Pump specifications
Well name Cherouq1 Shaheen 1 Badr6
Desired rate of
liquid at the pump
intake Q liquid down-
hole
520 M3
/day 291 M3
/day 350 M3
/day
Pump series P37 538-SSD series P23 538- SSD series G31 538-SXD series
Pump OD 5.38" 5.38" 5.38"
Operation range
From 330 to 635
M3
/day at 50.0 Hz
From 160 to 370
M3
/day at 50.0 Hz
From 240 to 580
M3
/day at 50.0 Hz
Efficiency(%) 68 % 64 % 46.66 %
59. 50
Ft/stage 11.5 m 12.25 m 13.1 m
Ft/stage 37.73 ft 40.19 ft 42.978 ft
TDH 7064.091 10189.426 8301.797
Number of stages
calculated
188 254 193
Number of stages
required
the values above go well beyond the technical data sheet reference
values.(Appendices: B.1.a, B.1.b and B.1.c)
For this reason we have to choose two or three housing and summing
its corresponding number of stages to ensure reaching the number
required.
189 254 192
Housing required
2 (NΒ°16 and NΒ°6)
Appendix B.1.a
2 (NΒ°17 and NΒ°5)
Appendix B.1.b
2 (NΒ°18 and NΒ°10)
Appendix B.1.c
Brake Horse Power
per stage
1 KW 0.65 KW 1.15 KW
Brake Horse Power
per stage
1.34 HP 0.872 HP 1.542 HP
Total Brake Horse
Power
293.651 HP 221.448 HP 269.839 HP
Shaft Diameter 0.875" 0.875" 0.875"
Level performance XP performance XP performance XP performance
III.1.1.6. Seal section selection
Normally the seal section series should be the same as that of the pump, although, there are
exceptions and special adapters are available to connect the units together. In our case study,
we will assume that the seal section and the pump are of the same series.[3]
The horsepower requirement for the seal section is based upon the total dynamic head
produced by the pump.[3]
We considered that the seal section and pump are of the same series which is 538[9].
60. 51
The GSB3 model is chosen for Cherouq 1 and Shaheen 1 wells (Appendix B.2.a) and
FSFB3 model is picked for Badr 6 well (Appendix B.2.b). The horsepower required for the
seal section is based upon the total dynamic head produced by the pump such indicated from
the chart below: Figure III-5.[3]
Figure III- 5: Horsepower VS Total dynamic head in feet[3]
The table below shows the Seal horsepower estimation
Table III- 7: Seal horsepower estimation
Well name Cherouq1 Shaheen1 Badr6
Total Dynamic
Head (ft)
7064.091 10189.426 8301.797
Seal horsepower
(HP)
3.4 3.45 3.6
III.1.1.7 Motor selection
The most important criteria for motor selection are :
ο· Horsepower
ο· Voltage
ο· Amperage
ο· Load
ο· BHT
The brake horse power required for the motor is calculated before, we have to take into
account the horse power needed for the seal section to calculate the total horse power needed
for the motor.
πππ‘ππ π΅π»π = ππ’ππ π΅π»π + π πππ π»π III.34
61. 52
The table below calculates the required motor horse power
Table III- 8: required motor power
Well name Cherouq1 Shaheen1 Badr6
Pump BHP (Hp) 293.651 HP 221.448 HP 269.839 HP
Seal HP (Hp) 3.4 3.45 3.6
Required Motor
BHP (Hp)
297.051 224.898 273.439
Bottom hole
temperature (Β°F)
197 198 195.8
Based on these values of total horse power required for the motor , the reservoir
temperature (197 Β°F,198 Β°F,195.8Β°F) and the available power, the motor selection is
performed among the 450 series (Appendix B.3.a).
The table below shows the motor selection specification.
Table III- 9: motor selection specification
Well name Cherouq1 Shaheen1 Badr6
Size(HP) 334 250 334
Voltage(V) 2758 2066 2758
Amperage(Am) 77 77 77
Our choice is based firstly on the size required, secondly on the highest voltage and
consequently the lowest amperage possible. these motors (high voltage/ less amperage)
require smaller conductor size cables and have lower cable losses. High voltage motors have
superior starting characteristics: a feature that can be extremely important if excessive voltage
losses are expected during starting.
The target load of the motor is between 75% to 90% at normal conditions to avoid
overload of the motor resulting in reduced run life of the motor.
πππ‘ππ ππππ =
π πππ’ππππ βπππ π πππ€ππ
πππ‘ππ π»πππ π πππ€ππ
III.35
The table below shows the motor load calculation of the chosen motors.
Table III- 10: Motor load calculation
Well name Cherouq1 Shaheen1 Badr6
Motor Horse
Power(Hp)
334 250 334
Required Horse
Power(Hp)
297.051 224.898 273.439
Motor Load 89. 9% 90 % 81.86 %
62. 53
We can conclude that all motor load values are between 75% and 90% that confirms our
choice.
III.1.1.8. Power cable selection
Many parameters are involved in the choice of the power cable namely, amperage (voltage
drop), conductor temperature (insulation material), insulation voltage rating, gas handling
(decompression protection), corrosive properties of well fluid, available space (casing
clearance).
A) Amperage (Voltage Drop)
Line loss is the normal reduction in available voltage after long distance transmission.
High temperatures impede the ability of the conductor to transmit voltage (resistance).
Voltage drop refers to voltage losses due to distance and temperatures.[3][8]
The conductor size is measured by American Wire Gauge(#AWG). The size goes from 1
to 6 with 1 for the largest size, however the voltage drop increases with the largest diameter.
For this reason it is recommended to select the tightest allowed cable size.
The Voltage Drop per1000 feet (Line losses) is determined from the chart (Appendix B.4.a)
The table below shows the line losses estimation.
Table III- 11: Line losses per 1000 ft calculation
Well name Cherouq1 Shaheen1 Badr6
Amperage(am) 77 77 77
Line Losses
(Volt/1000)
43.33 43.33 43.33
From the chart the voltage drop through cable is identified in the table below, those values
were taken for a temperature of 77Β°F,so a simple multiplication by a correction factor must be
done to take into account this difference (Appendix B.4.b).[3][8]
The table below shows the temperature correction factor estimation.
Table III- 12: Temperature correction factor estimation
Well name Cherouq1 Shaheen1 Badr6
Bottom-hole
temperature (Β°F)
197 198 195.8
Temperature
Correction Factor
1.27 1.26 1.25
B)Cable length
The total cable length should be at least 100ft (30m) longer than the measured pump
setting depth in order to make surface connections at safe distance from the wellhead.
To avoid the possibility of low voltage starts the cable length shall not exceed a maximum
value in order to skip a high cable voltage drop.[8]
The length of cable is the sum of the pump setting depth and at least additive safety length
equal to 100 feet.
63. 54
ππππ‘πππ π·πππ = πΏπππ πΏππ π ππ Γ ππππππππ‘π’ππ πΆππππππ‘πππ πΉπππ‘ππ III.36
The table below shows the voltage drop per 1000 feet calculation.
Table III- 13: Voltage drop per 1000 ft calculation
Well name Cherouq1 Shaheen1 Badr6
Line Losses
(Volt/1000)
43.33 43.33 43.33
Temperature
Correction Factor
1.27 1.26 1.25
Voltage
Drop(Volt/1000)
55.029 54.595 54.163
If we assume a surface cable length to of 100 ft.
πππ‘ππ ππππ‘πππ π·πππ =
(π£πππ‘πππ ππππ)Γπππππ‘β ππ πππππ
1000
III.36
where πππππ‘β ππ πππππ = ππ’ππ πππ‘π‘πππ π·πππ‘β + ππ’πππππ πΆππππ III.37
The table below shows the total voltage drop calculation.
Table III- 14: Total voltage drop calculation
Well name Cherouq1 Shaheen1 Badr6
Pump Setting
Depth(ft)
10170.48 10170.48 10170.48
Surface Cable
length(ft)
100 100 100
Total Cable
Length(ft)
10270.48 10270.48 10270.48
Voltage
Drop(Volt/1000)
55.029 54.595 54.163
Total Voltage
Drop(Volt)
565.175 560.717 556.28
At the selected motor amperage and given down-hole temperature, the selection of a cable
size that will give a voltage drop of less than 30 volts per 1,000 ft. is usually recommended to
insure current carrying capability of cable.[3][8]
If the voltage drop is too low the starting torque may result in shaft breakage. Consider
using a VSD if the nameplate voltage drop is less than 5% (see equation III.38 in the next
page).[3][8]
