9 Step
9
Variable Speed
Pumping System
8
Accessories and
Optional Equipment
7
Electric
Cable
6
5
Pump
Type
4
3
Total
Dynamic
Head
Gas
Calculations
2
1
Basic
Data
Production
Capacity
Optimum
Size Of
Components
THE 9 STEP
TABLE OF CONTENTS
PAGE NO.
Educational Development Center..................................... 1
Nine-Step Overview
............................................................. 2
Step 1 - Basic Data ............................................................... 3
Step 2 - Production Capacity ..................................................... 4
Step 3 - Gas Calculations ........................................................ 5
Step 4 - Total Dynamic Head .................................................... 7
Step 5 - Pump Type .............................................................. 8
Step 6 - Optimum Size of Components .......................................... 9
Step 7 - Electric Cable ........................................................... 10
Step 8 - Accessory & Optional Equipment ...................................... 11
Step 9 - Variable Speed Pumping System ....................................... 13
Design Example 60 Hertz ....................................................... 16
Design Example Variable Speed ................................................ 22
Aato9-ap�PCTM..................................................................... 28
THE 9 STEP
EDUCATIONAL DEVELOPMENT CENTER
The Variable Speed Controller Technology Operation-Maintenance
This is a five day program designed for those
personnel directly responsible for the day-today operation of VSC systems. Each of the
major circuits, as well as the logic circuits, will
be discussed in detail. Using simulators and
actual VSC systems, participants will demonstrate the actual start-up of a VSC system and set
all the necessary operating parameters.
The Educational DevelopmentCen-ter (EDC)
offers high quality education and training
programs, both for associates who design, build
and service our products, and for our valued
customers.
Our modern training facility includes full media-equipped classrooms, a shop training area,
and a media development center. In addition to
a permanent staff of professional, experienced
instructors,numerous
members
of
the
organization are on call in their areas of expertise.
The Installation, Troubleshooting and Application of ESP Equipment
This is a five day course designed to prepare oil
field personnel for the installation of electrical
submersible pumping equipment. The course
provides instructions of the proper installation
techniques, as well as servicing and pulling of
ESP equipment. The course introduces the
student to the major ESP components and provides a brief explanation of the steps required to
size a complete ESP system.
There are three standard programs that are offered to our customer. All have a common
objective to improve the overall reliability of the
ESP system by understanding its strengths and
limitations. This includes improving the operating life and drastically reducing maintenance
and repair costs. The three standard programs
are:
To satisfy individual requirements, customized
programs can be developed for specific topics
and can be administered at field locations. For
a complete description of the course contents,
schedule and tuition, contact you local
representative.
The Electrical Submersible Pumping System
Applications
This is a five day course designed for those
personnel involved in production operations,
which use electrical submersible pumping systems (ESP's) for artificial lift. The course includes an introduction to the individual components of an ESP system, including their performance characteristics and limitations.
Whether our programs are for product information, technical skills, or skills for working together, the EDC is dedicated to the same goal as
all associates and facilities. This goal is the
pursuit of excellence.
This program is an in-depth technical seminar
dealing with the sizing and application of ESP
equipment in harsh environments, which include high GOR, high viscosity and variable
speed operation.
3
THE 9 STEP
NINE-STEP OVERVIEW
A nine step procedure Is to help you design the appropriate submersible pumping system for your
particular well. Each of the nine steps are explained in the sections that follow, including gas
calculations and variable speed operation. The nine steps are:
Step 1 - Basic Data
Collect and analyze all the well data that will be
used in the design.
Step 2 - Production Capacity
Determine the well productivity at the desired
pump setting depth, or determine the pump
setting depth at the desired production rate.
Step 3 - Gas Calculations
Calculate the fluid volumes, including gas, at the
pump intake conditions .
Step 4 - Total Dynamic Head
Determine the pump discharge requirement.
Step 5 - Pump Type
For a given capacity and head select the pump
type that will have the highest efficiency for the
desired flow rate.
Step 6 - Optimum Size of Components
Select the optimum size of pump, motor, and
seal section and check equipment limitations.
Step 7 - Electric Cable
Select the correct type and size of cable.
Step 8 - Accessory & Optional Equipment
Select the motor controller, transformer, tubing
head and optional equipment.
Step 9 - The Variable Speed Pumping System
For additional operational flexibility, select the
variable speed submersible pumping system.
The Electrical Submersible Pumping System
4
THE 9 STEP
STEP 1 - BASIC DATA
The design of a submersible pumping unit, under most conditions, is not a difficult task, especially if reliable data is available. Although, if
the information, especially that pertaining to the
well’s capacity, is poor, the design will usually
be marginal. Bad data often results in a misapplied pump and costly operation. A misapplied
pump may operate outside the recommended
range, overload or underload the motor, or drawdown the well at a rapid rate which may result in
formation damage. On the other extreme, the
pump may not be large enough to provide the
desired production rate.
Production Data .2
Wellhead tubing pressure .a
Wellhead casing pressure .b
Present production rate .c
Producing fluid level and/or pump .d
intake pressure
Static fluid level and/or static bottom-hole .e
pressure
Datum point .f
Bottom-hole temperature .g
Desired production rate .h
Gas-oil ratio .i
Water cut .j
Too often data from other wells in the same field
or in a nearby area is used, assuming that wells
from the same producing horizon will have
similar characteristics. Unfortunately for the
engineer sizing the submersible installations, oil
wells are much like fingerprints, that is, no two
are quite alike.
Well Fluid Conditions .3
Specific gravity of water .a
Oil API or specific gravity .b
Specific gravity of gas .c
Bubble-point pressure of gas .d
Viscosity of oil .e
PVT data .f
The actual selection procedure can vary significantly depending upon the well fluid properties.
The three major types of ESP applications are:
High water-cut wells producing fresh water .1
or brine.
Wells with multi-phase flow (high GOR). .2
Wells producing highly viscous fluids. .3
Power Sources .4
Available primary voltage .a
Frequency .b
Power source capabilities .c
Possible Problems .5
Sand .a
Deposition .b
Corrosion .c
Paraffin .d
Emulsion .e
Gas .f
Temperature .g
Following is a list of data required:
Well Data .1
Casing or liner size and weight .a
Tubing size, type and thread(condition) .b
Perforated or open hole interval .c
Pump setting depth (measured & verti- .d
cal)
5
THE 9 STEP
STEP 2 - PRODUCTION CAPACITY
Inflow Performance Relationship
The following is a simplification of procedures
for predicting well performance. This discussion assumes a flow efficiency of one. A damaged well or other factors will effect the flow
efficiency and could change the well's productivity.
If Pwf is less than Pb, resulting in multi-phase
flow, the IPR method should be used. The
relationship is given by the following equation:
max =Q
o
Productivity Index
PI = J =
Pr - Pwf
Where:
Q = the fluid test production rate.
Pwf = the well flowing pressure
@ test rate Q.
Pr = the well static pressure.
Note:
Pr and Pwf are terms which are
always referenced to the same
specific vertical depth.
Bottom Hole Well Pressure (PWF/PR). Fraction of Reservoir Pressure
When the wf
well flowing pressure (P ) is greater
than bubble -point pressure (Pb) the fluid flow is
similar to single phase flow, and the inflow
performance curve is a straight line with slope J,
as given by the productivity index, PI:
Q
Qo
)
P
wf
Pr
) (
2
(
Pwf
- 0.8 1 - 0.2
Pr
This relationship was first used by W.E. Gilbert1
and further developed by J.V. Vogel2. Vogel
developed a dimensionless reference curve that
can be used to determine the IPR curve for a
particular well.
0
Producing Rate (qo/(qo) max). Fraction of Maximum
0
INFLOW PERFORMANCE
REFERENCE CURVE
6
THE 9 STEP
STEP 3 - GAS CALCULATIONS
ponents used for separating gas from the fluid
going to the pump intake. These are listed
acccording to increasing efficiency. The first is
a reverse flow intake, which uses the natural
buoyancy of the fluids for separation. The second is a vortex type intake, which uses the fluid
velocity to set-up a rotational flow to induce
radial separation of the gas. The last is a rotary
gas separator intake, which utilizes a mechanical, rotating chamber to impart a high, centrifugal force on the fluid to separate the gas.
The presence of free gas at the pump intake and
in the discharge tubing makes the process of
equipment selection much more complicated
and voluminous. As the fluid (liquid and gas
mixture) flows through the pump stages from
intake to the discharge and through the discharge tubing, the pressure and consequently,
fluid properties (such as volume, density, etc.)
continuously go on changing. Also, the presence of free gas in the discharge tubing may
create significant “gas-lift” effect and considerably reduce the required discharge pressure.
It is essential to determine the effect of the gas on
the fluid volume in order to select the proper
pump and separator. The following calculations
yield the percent free gas by volume.
The performance of a centrifugal pump is also
considerably affected by the gas. As long as the
gas remains in solution, the pump behaves normally as if pumping a liquid of low density.
However, the pump starts producing lower than
normal head as the gas-to-liquid ratio (at pumping conditions) increases beyond a certain “critical” value (usually about 10 - 15%). It is mainly
due to separation of the liquid and gas phases in
the pump stage and due to a slippage between
these two phases. This phenomenon has not
been well studied and there is no general correlation describing the effect of free gas on pump
performance. A submersible pump is usually
selected by assuming no slippage between the
two phases or by correcting stage performance
based on actual field test data and past experience.
If the solution gas/oil ratio (Rs), the gas volume
factor (Bg), and the formation volume factor
(Bo) are not available from reservoir data, they
must be calculated, and there are a number of
multi-phase correlations to select from. The
correlation you select will affect your design, so
select the one that best matches your conditions.
The following are Standings3 correlations for
solution gas/oil ratio, and formation volume
factor:
Solution Gas/Oil Ratio
Rs = Yg
(
Pb
18
Ideally, a well would be produced with a submergence pressure above the bubble point pressure to keep any gases in solution at the pump
intake. This is typically not possible, so the
gases must be separated from the other fluids
prior to the pump intake to achieve maximum
system efficiency.
x
0.0125 x 0API
10
)
1.2048
100.00091 x T( 0F)
Or in metric,
(
0
1.2048
)
0.0125 x API
P x 10
Rb= 0.1342Y
g
s
100.00091 x (1.8T( 0C) + 32)
Where:Yg = Specific Gravity Gas
Pb = Bubble-Point Pressure, psi (kg/cm2)
T = Bottom-hole Temperature, 0F ( 0C)
There are numerous combinations of equipment
configurations and wellbore completions which
are available for enhancing the performance of
ESP's in gassy applications. Many of these are
identified in the "Gas Handling Guideline". Specifically, Centrilift offers several optional com-
NOTE: Pump Intake Pressure (PIP) should be
substituted for Bubble Point Pressure when
calculating intake conditions.
7
THE 9 STEP
Total Volume of Fluids
Gas Volume Factor
When these three variables, Rs, Bo and Bg are
known, the volumes of oil, water, and free gas
can be determined and percentages of each calculated. The total volume of gas ( both free and
in solution ) can be determined as follows:
Bg = 5.04 ZT or in metric, Bg = 0.00377 ZT
P
P
Where: Z = Gas compressibility factor
(0.81 to 0.91)
T = Bottom-hole temperature degrees
Rankine (460 +0 F), or in metric
Kelvin (273 +0 C)
P = Submergence pressure psi, or
(kg/cm2)
Total Gas = Producing GOR x BOPD = MCF
1,000
or in metric,
Total Gas = Producing GOR x M3PD = M3
The gas volume factor, Bg, is expressed in reservoir barrels/st'd mcf gas (m3/m3)
The gas in solution at submergence pressure can
be determined as follows:
Formation Volume Factor
R x BOPD
Solution Gas = s = MCF
1,000
The formation volume factor Bo, represents the
increased volume a barrel of oil occupies in the
formation as compared to a stock barrel.
The Free Gas equals the Total Gas minus the
Solution Gas.
Bo = 0.972 + 0.000147F
1.175
)
0.5
Y
g
+ 1.25T
Where: F = R
s
Yo
The volume of oil (Vo) at the pump intake equals
stock tank barrels times Bo, the formation volume factor.
(
T = Bottom-hole temperature,0 F
or in metric,
The volume of gasg (V ) at the pump intake
equals the amount of free gas times Bg, the gas
volume factor.
Bo = 0.972 + 0.000147 x
)
Yg 0.5
+ 1.25 (1.8t + 32)
Yo
}{
The volume of water (Vw) in the formation is the
same as stock tank barrels.
(
1.175
5.61 Rs
Total fluid volume (V ) cant now be determined.
Vt = Vo + Vg + Vw
Where:
Yg = Specific Gravity of Gas
Yo = Specific Gravity of Oil
t = Bottom-hole Temperature,0 C
The percentage of free gas to total volume of
fluids can now be calculated:
Vg
% Free Gas =
8
Vt
THE 9 STEP
STEP 4 - TOTAL DYNAMIC HEAD
METRIC
The next step is to determine the total dynamic
head required to pump the desired capacity. The
total pump head refers to feet (meters) of liquid
being pumped and is calculated to be the sum of:
1) Net well lift (dynamic lift); 2) well tubing
friction loss; and 3) wellhead discharge pressure. The simplified equation is as follows:
Pd =
kg/cm2 x 10.01 m/kg/cm2
Specific Gravity
or
Pd =
TDH = Hd + Ft + Pd
kg/cm2
0.0999 x Sp. Gr.
Total Dynamic Head = Hd + Ft + Pd
Pd
where:
TDH = total dynamic head in feet (meters)
delivered by the pump when pumping the desired volume.
Hd = vertical distance in feet (meters) between
the wellhead and the estimated producing fluid
level at the expected capacity.
Ft = the head required to overcome friction loss
in tubing measured in feet (meters).
Hd
Dynamic
FluidLevel
P = the head required to overcome friction in the
d
surface pipe, valves and fittings, and to overcome elevation changes between wellhead and
tank battery. Normally, this is measured in
gauge pressure psi (kg/cm2) at the wellhead and
can be converted to head, in feet (meters) as
follows:
U.S.
psi x 2.31 ft/psi
Pd =
specific gravity
Tubing
Ft
Pump
Seal
or
Pd =
psi
0.433 psi/ft x sp. gr.
Motor
9
THE 9 STEP
STEP 5 - PUMPTYPE
Refer to the pump selection data table, in the 4. In wells where the fluid is quite viscous
catalog, forEngineering section of your
and/or tends to emulsify, or in other expump types and ranges. Pump performance
traordinary circumstances, some pump corcurves (60 Hz and 50 Hz) are included in the
rections may be necessary to ensure a more
"Pump Curve" section of the catalog. Based on
efficient operation.
expected fluid production rate and casing size,
select the pump type which will, at the expected
producing rate, be operating within the pump's
operating range and nearest to the pump's peak
The VSSP System and Pump Selection
efficiency,
Under the above, or other pumping conditions,
also consider the Variable Speed Submersible
Where two or more pump types have similar
Pumping (VSSP) system. For instance, in item
efficiencies at the desired volume, the following
2 above, if a well is not accurately known, a
conditions determine the pump choice:
VSSP system is ideal. An Electrospeed variable speed controller effectively converts a
1. Pump prices and corresponding motor sizes
single pump into a family of pumps. So, a pump
and prices may differ somewhat. Normally,
can be selected for an estimated range and
the larger-diameter pump and motor are less
adjusted for the desired production level, once
expensive and operate at higher efficiencies.
more data is collected.
2. When the wells capacity is not known, or
cannot be closely estimated, a pump with a
"steep" characteristic curve should be chosen. If the desired volume falls at a point
where two pump types have approximately
equal efficiency, choose the pump type
which requires the greatest number of
stages. Such a pump will produce a capacity
nearest the desired volume even if the well
lift is substantially more or less than
expected.
The VSSP system with the Electrospeed improves pump operation under other conditions
as well, including gassy wells, abrasive wells,
low volume wells, etc. It provides soft starts,
eliminates intermittent operation, breaks gas
locks, isolates equipment from power transients, minimizes downhole heating, and more.
Review Step 9when considering the VSSP system. Variable frequency performance curves
are included in the "Pump Curve" section of the
Centrilift catalog. The VSSP System with
Electrospeed may provide additional economies of capital expenditure and operating
expenses, and should be considered in Step 6,
"Optimum Size of Components." The
Electrospeed variable speed controller and transformers for the VSSP system are discussed in
Steps 8 and 9.
3. If gas is present in the produced fluid, a gas
separator may be required to achieve
efficient operation. Refer to Step 3 to
determine the effect of gas on the produced
volume. The adjusted volume affects pump
selection and the size of the other system
components.
10
THE 9 STEP
STEP 6 - OPTIMUM SIZE OF COMPONENTS
components are built in a number of sizes and
Total Dynamic Head
of
varietya
in
assembledbe can
Total Stages =
combinations. These combinations must be
Head/Stage
carefully determined to operate the submersible
Separator
pumping system within production requirements,
Refer to your catalog for gas separator informamaterial strength and temperature limits. While
tion. Make the necessary adjustments in horsesizing components, refer to the Engineering
power requirements and housing length.
section of your catalog for each of the following
tables and charts:
Motor
To select the proper motor size for a predeterEquipment Combinations in Various Casings
mined pump size, you must first determine the
Maximum Loading Limits
brake horsepower required by the pump. The
Maximum Diameter of Units
horsepower per stage is obtained by again referVelocity of a Fluid Passing a Motor
ring to the performance curve for the selected
Shaft HP Limitations at Various Frequencies
pump and reading the value of the right scale.
The brake horsepower required to drive a given
A fluid velocity of 1 foot per second (0.305
pump is easily calculated by the following formeters per second) is recommended to ensure
mula:
adequate motor cooling. In cases where this
velocity is not achieved, a motor jacket may be
BHP = Total Stages x BHP/Stage x Sp. Gr.
required to increase the velocity. Contact your
sales engineer under such conditions.
Refer to your catalog for motor specifications.
Pump
Refer to the performance curve of the selected
pump type and determine the number of stages
required to produce the anticipated ca-pacity
against the previously calculated total
dynamic head. Performance curves for 60 Hz,
50 Hz and variable frequency performance are
Note that the pump located in the catalog.
characteristic curves are single stage performance curves based on water with (specific
At the intersection of the gravity of 1.00) .
desired production rate (bottom scale) and the
head-capacity curve (vertical scale), read the
head value on the left scale. Divide this value
into the total dynamic head to determine the
number of stages.
Seal Section
Refer to your catalog for selection of the proper
seal section. Series 338 seals are recommended
for 338 series pumps using 375 series motors.
Series 400 seals are recommended for 400 series
pumps using 450 series motors. When 544 or
562 series motors are used with a 513 series
pump, the 513 series seal is required. A 513-400
series adapter is required whenever a 513 series
seal section is run with a 400 series pump.
11
THE 9 STEP
STEP 7 - ELECTRIC CABLE
In determining the optimum cable size, consider
future equipment requirements that may require
the use of a lager size cable.
Electric cables are normally available from
stock in conductor sizes 1, 2, 4, and 6. These
sizes are offered in both round and flat
configurations as shown in your catalog price
section under Power Cable.
If power cost is a major concern, the KilowattHour Loss Curve (see Engineering section) can
be used to justify the cable selection. Although
power rates vary widely, this data is valuable in
determining the economics of various cable
sizes.
Several types of armor and insulation are available for protection against corrosive fluids and
severe environments.
Cable selection involves the determination of:
cable size; (1
cable type; (2
cable length. (3
Cable Type
Selection of the cable type is primarily based on
fluid conditions, bottom-hole temperature and
space limitations within the casing annulus. Refer
to your catalog price pages for cable specifications.
Cable Size
The proper cable size is dependent on combined
factors of voltage drop, amperage and available
space between tubing collars and casing.
Where there is not sufficient space to run round
cable, use electric cable of flat configuration.
See Equipment Combinations table in Engineering section of your catalog for round cable
limitations based on various casing and tubing
sizes.
Refer to the Cable Voltage Drop curve (see
engineering section) for voltage drop in cable.
At the selected motor amperage and the given
downhole temperature, the selection of a cable
size that will give a voltage drop of less than 30
volts per 1,000 ft. (305 meters) or less than 15%
of motor nameplate volts is recommended. This
curve will also enable you to determine the
necessary surface voltage (motor voltage plus
voltage drop in the cable) required to operate the
motor.
Cable Length
The total cable length should be at least 100 ft.
(30M) longer than the measured pump setting
depth in order to make surface connections a
safe distance from the wellhead. Refer to curve
on Recommended Maximum Cable Length (see
Engineering section) to avoid the possibility of
low voltage starts.
Finally, refer to the Equipment Combination
table (see engineering section) to determine if
the size selected can be used with the proposed
tubing and well casing sizes. Cable diameter
plus tubing collar diameter will need to be less
than the inside diameter (I.D.) of the casing.
Cable Venting
In all wells, it is necessary to vent gases from the
cable prior to the motor controller to avoid
explosive conditions. A cable venting box is
available to protect the motor controller from
such gases.
12
THE 9 STEP
STEP 8 - ACCESSORY& OPTIONAL EQUIPMENT
Display Unit (Optional)
This unit displays readings, setpoints and
alarms. It is normally mounted in the amp
chart enclosure for easy access.
1. DOWN HOLE ACCESSORY
EQUIPMENT
Flat cable (motor lead extension):
Select a length at least 6 ft. (1.8m) longer than
pump, intake (standard or gas separator) and
seal section for the motor series chosen. Refer to
your catalog for dimensions.
It provides all the basic functions, such as
underload, overload, phase imbalance, phase
rotation, etc. and over 90 other parameters
including password and communication
protocols.
Flat cable guard:
Choose the required number of 6 ft. (1.8m)
guard sections to at least equal the flat cable
length. Do not use guards for installation of 400
series pump and seal section in 5-1/2" O.D., 20pound casing and for installation of 513 series
pump and seal section in 6 5/8" O.D., 26-pound
casing.
3. SINGLE-PHASE AND THREE-PHASE
TRANSFORMERS
The type of transformer selected depends on the
size of the primary power system and the required
secondary voltage. Three-phase isolation stepup transformers are generally selected for
increasing voltage from a low voltage system,
while a bank of three single-phase transformers
is usually selected for reducing a high-voltage
primary power source to the required surface
voltage.
Cable bands:
Use one 30 in. (76 cm) cable band every 2 ft. (60
cm) for clamping flat cable to pump. The 22 in.
(56 cm) length can be used for all tubing-cable
combinations through 3-1/2" O.D. tubing. For
4- 1/2" and 5-1/2" O.D. tubing use 30 in. (76 cm)
bands. One band is required for each 15 ft. (5 m)
of setting depth. Refer to your catalog for
dimensions.
On existing systems, some of units will
operate without the use of an additional
transformer. For new installation of units with
higher voltages, it is usually less expensive to
install three single-phase transformers, connected
wye, to eliminate the auto-transformer.
Swaged nipple, check valve, and drain valve:
Select these accessories on basis of required
outside diameters and type of threads.
2. MOTOR CONTROLLERS
The VortexTM is a state-of-the-art digital control
consisting of two components:
System Unit
This unit performs all the shutdown and
restart operations. It is mounted in the lowvoltage compartment of the control panel.
•
•
13
THE 9 STEP
In choosing the size of a step-up transformer or
a bank of three single-phase transformers the
following equation is used to calculate total
KVA required:
SERVICING EQUIPMENT .6
Cable reels, reel supports and cable guides:
Select size of cable reel required to handle
previously selected cable size. Select set of
cable reel supports based on cable reel size.
Cable guides are designed to handle cable sizes
1 through 6.
Vs x Am x 1.73
KVA =
1,000
Normally, customers retain one cable reel, one
set of reel supports, and one cable guide wheel
for future use.
where:
KVA = Kilo-Volt-Amp or 1,000 Volt-Amp
Vs = Surface Voltage
Am = Motor nameplate current in amps
Shipping Cases:
Select type and length of case required to accommodate previously selected motor, pump,
gas separator and seal.
SURFACE CABLE.4
Choose approximate length required for connecting controller to primary power system or to
transformer. Two pieces are generally required
for installations using an auto-transformer. Size
should equal the well cable size except in the
case of step-up or auto-transformer, where the
primaryand secondary currentsare not the same.
OPTIONAL EQUIPMENT .7
Bottom-hole pressure (PHD) sensing device:
The PHD provides continuous measurement of
bottom-hole pressures.
Automatic well monitoring:
Motor controllers are available for continuous
monitoring of pump operation from a central
location.
WELLHEADS AND ACCESSORIES .5
Select the wellhead on the basis of casing size,
tubing size, maximum recommended load, surface pressure,and maximumsettingdepth. Electric cable passes through the wellhead where
pressure fittings are not required.
Electric Feed Through (EFT) mandrels are also
available. The electric cable is spliced to pigtails. The EFT wellheads seal against downhole
pressure and prevent gas leaks at the surface.
Refer to your catalog for specifications.
14
THE 9 STEP
STEP 9 - VARIABLE SPEED SUBMERSIBLE PUMPING SYSTEM
The ESP system can be modified to include an
Electrospeed variable frequency controller so
that it operates over a much broader range of
capacity, head, and efficiency. Since a submersible pump motor is an induction motor, its speed
is proportional to the frequency of the electrical
power supply. By adjusting the frequency, the
variable speed submersible pump (VSSP) system offers extraordinary potential for boosting
production, reducing downtime, and increasing
profits. The VSSP can be used to boost efficiency in many cases, including highly viscous
wells, waterflood wells etc. It extends the range
of submersible artificial lift to less than 100 BPD
(16 M3PD) and up to 100,000 BPD (16,000
M3PD).
New Frequency
New Rate =
New Head =
)
x 60 Hz rate
60 Hz
(
New Frequency 2
)
60 Hz
3
(
New Frequency
New BHP =
60 Hz
x 60 Hz head
x 60 Hz BHP
where BHP = Brake Horsepower
New Efficiency = 60 Hz efficiency (there is
negligible loss)
A set of curves can be developed for an arbitrary
series of frequencies with these equations, as
shown in the variable frequency performance
curves at the end of this step (figure 1). Each
curve represents a series of points derived from
the 60 Hz curve for flow and corresponding head
points, transformed using the equations above.
It is necessary to understand the effects of varying the speed of a submersible pump, in order to
apply the VSSP system. The VSSP system can
be analyzed in terms of varying frequency or in
terms of maintaining constant head. Sales engineers have computerized pump selection programs to assist you in VSSP system selection;
what follows is a basic explanation of the principles involved.
Suppose we are given the following data at a
frequency of 60 Hz:
Rate = 1,200 BPD
Variable Frequency
The effects of varying frequency can be seen by
preparing new head-capacity curves for the desired frequencies, based on the pump's known
60 Hz performance curve data. The Electrospeed controller is commonly used to generate
any frequency between 30 and 90 Hz.
Head = 24.5 ft. (from FC-1200 curve @ 1,200
BPD)
BHP = 0.34 BHP (from FC-1200 curve @ 1,200
BPD)
If a new frequency of 50 Hz is chosen:
Curves for frequencies other than 60 Hz can be
generated by using the centrifugal pump affinity
laws. The equations derived from these laws
are:
New Rate =
New Head =
15
()
( )
50
60
50
60
x 1200 BPD = 1000 BPD
2
x 24.5' =17'
THE 9 STEP
)
3
50
x 0.34 BHP = 0.20 BHPNew BHP =
60
50 Hz
(
X1 Rate 792
(BPD)
0 1292
1000
1563
By performing these calculations at other production rates, a new curve for 50 Hz operation
can be plotted. Start by locating the existing
points on the one-stage 60 Hz curve:
Y1 Head (Feet) 22.2' 19.9' 17' 10.4' 0'
Efficiency (%) 0 63.5 64 49 0
60 Hz
X1 Rate (BPD) 0
Y1 Head (Feet) 32'
0 Efficiency (%)
1875950 1200 1550
0'
0
15' 28.6' 24.5'
49
64 63.5
Following the above equations, calculate the
corresponding values at 50 Hz:
Plotting these coordinates gives the one-stage
FC-1200 head-capacity performance curve for
operation at 50 Hz. Similar calculations will
provide coordinates for curves at other frequencies, as seen below in the FC-1200 variable
speed performance curve. The vortex shaped
window is the recommended operating range for
the pump. As long as your hydraulic requirement falls within this range, you are within the
recommended operating range of the pump.
Figure 1
16
THE 9 STEP
DESIGN EXAMPLENAME
COMPANY
ADDRESS
WELL LOCATION (COUNTY, STATE, OTHER)
WELL NO. AND FIELD NAME
VOLTS THREE INSTALLATION: NEW ( X ) OR REDESIGN (
HZ
) PRIMARY POWER SUPPLY: 12,470
60 PHASE
PRODUCING FORMATION
FORMATION TYPE (SANDSTONE, LIMESTONE, OTHER) SANDSTONE
WELL DATA
API CASING
7 IN. O.D.
LINER NONE
IN. O.D.
OPEN HOLE
TOTAL DEPTH
PERFORATION INTERVALS
API TUBING 2 - 7/8 IN.O.D.
32 #/FT.
#/FT.
0 FT. TO
FT. TO
FT. TO
6,900 FT.
FT.
FT.
FT.
6,850 FT.
FT.
FT.
6,750 FT. TO
FT. TO
FT. TO
M. TO
M. TO
M. TO
M.
M.
M.
M.
M.
M.
M.
M. TO
M. TO
M. TO
EUE 8 RDTHREADS
RESERVOIR DATA (FROM TEST AND PRODUCTION DATA)
3
PUMPING ( X ), SWABBING ( ), FLOWING (
PRESENT PRODUCTION
3
)
3
3,200 PSI G@ BOTTOM HOLE BOTTOM HOLE STATIC PRESSURE 6,800 FT.
Kg/Sq. Cm. @ M.
3
3Kg/Sq. Cm. @
M PD
850 BFPD
FLOWING PRESS3U0R0E 2,600 PSIG @
BFPD
PSIG @
M PD
Kg/Sq. Cm. @
S.C.F./S.T.B.0
PRODUCING GOR
M /M
OIL
75 %
WATER CUT
32
API GRAVITY
°C
160 °FBOTTOM HOLE TEMPERATURE
1.085WATER SPECIFIC GRAVITY
0.7 GAS SPECIFIC GRAVITY
OIL VISCOSITY
(1)
CP. OR
SSU@
°F
°C
(2)
CP. OR
SSU@
°F
°C
SOLUTION GOR
FVF.
PSIG
Kg/Sq. Cm.
PVT DATA
SOLUTION GOR
FVF.
PSIG
Kg/Sq. Cm.
SOLUTION GOR
FVF.
PSIG
Kg/Sq. Cm.
SOLUTION GOR
FVF.
PSIG
Kg/Sq. Cm.
1,500 PSIGBUBBLE-POINT PRESSURE
Kg/Sq. Cm.
M PD
BFPD. 850
3
CENTRILIFT SPECIFICATIONS
3
DESIRED PRODUCTION
2,300 BFPD. OR
BOPD
FLUID M PD, OR
OIL M PD
51,05000FT.
DESIRED PUMP (INTAKE) VERTICAL SETTING DEPTH
M.
DESIRED PUMP (INTAKE) PRESSURE
PSIG
Kg/Sq. Cm.
Kg/Sq. Cm.
REQUIRED WELL HEAD PRESSURE
PSIG
GOR THROUGH PUMP
%
CASING VENTED
TO ATMOSPHERE ( )
TO PIPELINE ( X )
NONE ( )
ELECTRIC POWER
VOLTS
CYCLES
DESIRED PUMP
SERIES
Kg/Sq. Cm.
PSIG
CASING PRESSURE
DESIRED PUMP TYPE
H2S( ), POWER SUPPLY( )PARAFFIN( ),), CORROSION( ),
SAND( ),
SCALE(
SPECIAL PROBLEMS
17
THE 9 STEP
DESIGN EXAMPLE
Step 1 - Basic Data
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 loss
in the casing annulus. In the given example, as
the pump is set 1,300 feet above the perforations, the friction loss due to flow of fluid
through the annulus from perforations to pump
setting depth will be small as compared to the
flowing pressure and can be neglected.
See well data sheet on previous page for well
data.
Step 2 - Production Capacity
Determine the well productivity at the test pressure and production. In this case, the desired
production rate and pump setting depth are
given. The pump intake pressure at the desired
production rate can becalculated from the present
production conditions.
Because there is both water and oil in the produced fluids it is necessary to calculate a composite specific gravity of the produced fluids.
To find the composite specific gravity;
Since the well flowing pressure (2,600 psi) is
greater than bubble-point pressure (1,500 psi)
the constant PI method will most probably give
satisfactory results. First, we can determine the
PI using the test data.
PI =
Water cut is 75%;
0.75 x 1.085 = 0.8138
Oil is 25%;
0.25 x 0.865 = 0.2163
Q
Pr - Pwf
PI =
850 bpd
3,200 psi - 2,600 psi
The composite specific gravity is the sum of the
weighted percentages:
= 1.42 bpd/psi
Composite Sp. Gr. = 0.8138 + 0.2163 = 1.03
Next, we can determine the new well flowing
pressure (Pwf) at the desired production rate
(Qd).
The pressure due to the difference in perforation
depth and pump setting depth (6,800' - 5,500' =
1,300') can be determined as follows:
Qd
= PPwf r
(
( )
PI
2,300 bpd
=
3,200
psi
P
1.42 bpd/psi
wf
)
PSI =
= 1,580 psi
PSI =
The well flowing pressure of 1,580 psi is still
above the bubble-point pressure of 1,500 psi,
therefore, the PI approach should give good
results.
Head (FT) x Specific Gravity
2.31 Ft/PSI
1,300 Ft x 1.03
2.31 Ft/PSI
= 580 PSI
Therefore, the pumpintake pressure will be1,580
psi - 580 psi = 1,000 psi.
18
THE 9 STEP
Step 3 - Gas Calculations
3. Determine the Gas Volume Factor (Bg) as
follows:
In this third step we need to determine the total
fluid mixture, inclusive of water, oil and free gas
that will be ingested by the pump.
5.04 x Z x T
P
Bg =
1. Determine the Solution Gas/Oil Ratio (Rs ) at
the pump intake pressure with Standing's nomograph (see figure 2 ), or by substituting the
pump intake pressure for the bubble point pressure (Pb) in Standing's equation;
)
g
Pb
x
18
s
0.0125 x 0API
10
(
10
R =Y
0.00091 x T( 0F)
(
100.0125 x 32
100.00091 x 160
1000
x
Rs = 0.7
18
Assuming 0.85 Z factor;
B=
g
5.04 x 0.85 x (460 + 160)
= 2.62 bbl/mcf
1,014
Next, determine the total volume offluids and the .4
percentage of free gas released at the pump intake:
Using the producing GOR, and oil volume, .a
determine the total volume of gas (TG) ;
1.2048
)
1.2048
TG = BOPD xGOR
1,000
or
Rs = 180 scf/stb
TG = (2,300 x 0.25) x 300 = 172.5 mcf
2. Determine the Formation Volume Factor (Bo)
using the Rs from above and Standing's nomograph (see figure 3) or use Standing's equation as
follows:
1,000
b. Using the solution GOR (Rs), at the pump
intake, determine the solution gas (SG);
Bo = 0.972 + 0.000147 F1.175
SG =
where;
)
s
0.5
Yg
+ 1.25TF = R
Yo
)
0.5
1,000
(
0.7
+ 1.25 x 160 = 361.92F = 180
0.865
BOPD x Rs
G
(
or
= 103.5 mcf
(2,300 x 0.25) x 180
1,000
S =
c. The difference represents the volume of free
gas (FG) released from solution by the decrease in pressure from bubble-point pressure
of 1,500 psi, to the pump intake pressure of
1,000 psi.
Therefore;
B = 0.972 + 0.000147 (361.92)1.175o
Bo =1.12 reservoir bbl/stock tank bbl
F =172.5 mcf - 103.5 mcf = 69 mcf
G
19
THE 9 STEP
i. The composite specific gravity, including
gas, can be determined by first calculating
the total mass of produced fluid (TMPF)
from the original data given:
d. The volume of oil (Vo), at the pump intake:
oV = BOPD x FormationVolume Factor oB
Vo = 575 bopd x 1.12 = 644 bopd
The volume of free gas (Vg), at the pump .e
intake:
Vg = Free Gas x Gas Volume Factor Bg
Vg = 69 mcf x 2.62 bbl/mcf = 181 bgpd
TMPF ={ (BOPD x Sp. Gr. oil+ BWPD x
Sp. Gr. water) x 62.4 x 5.6146} + (GOR x
BOPD x Sp. Gr. Gas x 0.0752)
or
The volume of water (Vw), at the pump .f
intake:
V = Total Fluid Volume x % Water
w
Vw = 2,300 BPD x 0.75 = 1,725 bwpd
TMPF = {(575 x 0.865 + 1,725 x 1.085) x
62.4 x 5.6146} + (300 x 575 x 0.7 x
0.0752) = 839,064 lbs/day
Composite Sp. Gr. =
g. The total volume (Vt) of oil, water, and gas,
at the pump intake, can now be determined:
Vt = Vo + Vg + Vw
V = 644 bopd + 181 bgpd + 1,725 bwpd
t
Vt = 2,550 BFPD
Composite Sp. Gr. =
2,550 x 5.6146 x 62.4
TMPF
BFPD x 5.6146 x 62.4
839,064 lbs/day
Composite Sp. Gr. = 0.939
h. The ratio, or percentage of free gas present
at the pump intake to the total volume of
fluid is:
Vg
% Free Gas =
Vt
5. Now that the total volume of fluid entering the
first pump stage is known (2,550 BFPD) and the
composite specific gravity has been determined
we can continue to the next step of designing the
ESP system.
or
x 100 = 7% % Free Gas = 181 BGPD
2,550 BFPD
As this value is less than 10% by volume,
it would have little effect on the pump
performance, therefore, a gas separator is
not required. Although, there is significant
gas to effect the well fluid composite specific gravity at the pump intake.
20
THE 9 STEP
Step 4 - Total Dynamic Head
Step 5 - Pump Type Selection
Sufficient data is now available to determine the
total dynamic head required by the pump.
Refer to Pump Selection Table in Engineering
section of catalog . Select the pump type with
the highest efficiency at the calculated capacity,
2,550 BPD (405 M3PD) that will fit in the
casing. Select the pump and locate it's
performance curve.
TDH = Hd + Ft + Pd
H = The vertical distance in feet between the
d
estimated producing fluid level and the surface.
Hd = Pump depth -
)
d
(
PIP x 2.31ft/psi
Specific Gravity
The head in feet (meters) for one stage at 2,550
BPD (405 M3PD) is 41.8 ft. (13 m). The brake
horsepower (BHP) per stage is 1.16.
)
1,000 psi x 2.31 ft/psi
H = 5,500 ft. 0.939
To determine the total number of stages required, divide the total dynamic head by the
head/stage taken from the curve.
TDH
Number stages =
Head/stage
(
H = 3,040 ft (926.6m).
d
Ft = Tubing friction loss. Refer to Friction Loss
Charts in the engineering section.
Number of stages =
Next, refer to your catalog for the pump. The
housing number 9 can house a maximum of
84 stages, 93 stages for a housing
10. Because the 84 stage pump is only one stage
less than our requirement, it will be our selection.
Friction loss per 1,000 ft. of 2-7/8" tubing (new)
is 49 ft. per 1,000 ft. of depth at 2,550 BPD (405
M3PD), or 4.5 meters per 100 meters. Using the
desired pump setting depth:
5,500 ft. x 49 ft.
= 270 ft. (82.3m)
Ft =
1,000 ft.
Once you've decided on the maximum number
of pump stages, calculate the total brake horsepower required as follows:
P = Discharge pressure head (desired wellhead
d
pressure). Using the composite specific gravity:
d
3,556 ft.
= 85 Stages
41.8 ft.
100 psi x 2.31 ft/psi
= 246 ft. (75 m)
P =
0.939
BHP = BHP/Stage x No. Stages x Sp. Gr.
BHP = 1.16 x 84 x 0.939 = 91.5 HP
TDH = 3,040 ft. + 270 ft. + 246 ft. = 3,556 ft.
Step 6 - Optimum Size of Components
Gas Separator
If a gas separator was required, refer to your
catalog to select the appropriate separator and
determine its horsepower requirement.
or
TDH = 926.6 m + 82.3 m + 75 m = 1,084 m
21
THE 9 STEP
Seal Section
Normally the seal section series is the same as
that of the pump, although, there are exceptions
and special adapters are available to connect the
units together. We will select the 513 series
GSB seal section.
Referring to the Engineering section, it can be
seen that all operating parameters are well within
their recommended ranges (e.g. thrust bearing,
shaft HP, housing burst pressure and fluid velocity.
Step 7 - Electric Cable
The horsepower requirement for the seal depends upon the total dynamic head produced by
the pump. The Horsepower vs TDH curves in
the Engineering section show a requirement of
3.0 horsepower for the 513 series seal operating
against a TDH of 3,556 ft. Therefore, the total
horsepower requirement for this example is 91.5
HP for the pump, plus 3.0 HP for the seal, or 94.5
HP total.
Determine Cable Size
The cable size is selected based on its current
carrying capability. Using the motor amps (27)
and the cable voltage drop chart in the catalog,
select a cable size with a voltage drop of less than
30 volts per 1,000 ft. All conductor sizes 1
through 6) fall in this category. The #6 cable has
a voltage drop of 18.5 x 1.201 = 22.2 volts/1,000
ft. (305 m) and is the least expensive. This will
be the cable size used in our example.
Motor
A 500 series motor (544 or 562) should be used
with the 513 series pump. In this example we
will select the 100 HP 562 series motor from the
catalog. The motor voltage can be selected
based on the following considerations:
Cable Type
Due to the gassy conditions and the bottom-hole
temperature, the CPN cable should be used.
Check to be sure the cable diameter plus tubing
collar diameter is smaller than the casing I.D.
(see Engineering section ).
a. The high voltage, consequently low-current, motors have lower cable losses and
require smaller conductor size cables.
High voltage motors have superior starting characteristics: a feature that can be
extremely important if excessive voltage
losses are expected during starting.
Cable Length
The pump setting depth is 5,500 ft. (1676.4 m).
With 100 ft. (30.5 m) of cable for surface
connections, the total cable length should be
5,600 ft. (1,707 m). You will also find that the
cable length is within the recommended maximum length (see Engineering section).
b. Although, the higher the motor voltage,
the more expensive the motor controller
will be.
In some cases, the savings due to smaller cable
may be offset by the difference in motor controller cost and it may be necessary to make an
economic analysis for the various voltage motors. However, for this example, we will select
the high-voltage motor (100 HP 2145 volts, 27
amps).
Cable Venting
A cable vent box must be installed between the
wellhead and the motor controller to prevent gas
migration to the controller.
22
THE 9 STEP
Step 8 - Accessory and Miscellaneous
Equipment
Motor Controller
The motor controller selection is based on its
voltage, amperage, and KVA rating. Therefore,
before selecting the controller we must first
determine the motor controller voltage. We will
assume the controller will be the same as the
surface voltage going down-hole. The surface
voltage (SV) is the sum of the motor voltage and
the total voltage loss in the cable.
Flat Cable - Motor Lead Extension
= 14.8 ft. (4.51 m) Pump Length
6.3 ft. (1.92 m)= Seal Length
6.0 ft. (1.83 m) =
Plus 6 ft.
= 27.1 ft. (8.26 m)
Select 35 ft. (10.7 m) 562 series flat cable.
Flat Guards
Cable guards are available in 6 ft. sections,
therefore, 6 sections will be sufficient.
SV = 2,145 volts +
1,000 Ft
(
)
22.2 volts x 5,600 ft.
Surface Voltage = 2,269 Volts
Cable Bands
The pump and seal section are approximately 20
ft. (6 m) long. Twenty-two inch (56 cm) bands
will be required to clamp to the housing, with
bands spaced at 2 ft. ( 61 cm) intervals (10
bands).
The motor amperage is 27 amps, the KVA can
now be Calculated:
KVA = SV x Motor Amps x 1.73
1,000
Above the pump, banding of the tubing plus
cable, the twenty- two bands can also be used.
The bands should be spaced at 15 ft. (4.5 m)
intervals. The setting depth of 5,500 ft. would
require 367 bands.
KVA =
2,269 volts x 27 amps x 1.73
1,000
KVA = 106
Downhole Accessory Equipment
Refer to your catalog for the following:
The 6H-CG motor controller suits these requirements.
Swaged Nipple
The pump outlet is 2-7/8 inches, as shown on
table 5, so no swaged nipple is required for the
2-7/8 inch tubing.
Transformer
The transformer selection is based on the available primary power supply (12,470 volts), the
secondary voltage requirement (2,269 volts),
and the KVA requirement( 106 KVA). Chose
3 37.5 KVAsingle phase transformers as shown
in your catalog.
Check Valve
The 2-7/8 inch EUE 8 round thread check valve
will be required.
Surface Cable
Select 50 ft. (15.2 m) of #1 cable for surface
connection to transformers.
Drain Valve
The 2-7/8 inch EUE 8 round thread drain valve
will be required.
23
THE 9 STEP
DESIGN EXAMPLE - Variable Speed Pumping System
We will now take the previous example and
design a new system using a Variable Speed
Controller. To help justify the use of a variable
speed controller, I have added two new conditions. Those conditions are:
)
r
wf
1. First, assume we need to maintain a constant oil production (575 BOPD), although,
reservoir data indicates we should see an
increase in water cut (75% to 80%) over
the next few months.
(
2,875 bpd
= 1,175 psi = 3,200 psi - P
1.42 bpd/psi
The pump intake pressure can be determined the
same as before, although, first we must calculate
a new composite specific gravity.
Water cut is 80%;
0.80 x 1.085 = 0.868
Oil is 25%;
0.20 x 0.865 = 0.173
In order to maintain oil production as the water
cut increases, we need to determine the maximum desired flow rate with 80% water.
Max. Flow =
)
(
The new well flowing pressure of 1,175 psi is
slightly below the bubble point pressure of 1,500
psi, therefore, the PI approach should still give
good results.
2. To satisfy our economic justification in
using the variable speed controller, we
need to reduce the initial cost and size of
the downhole assembly.
Maximum Flow Rate =
wf
Qd
=P - P
PI
The composite specific gravity is the sum of the
weighted percentages:
BOPD x 100
% oil
Composite Sp. Gr. = 0.868 + 0.173 = 1.04
575 BPD
x 100 = 2,875 BPD
20%
The pressure due to the difference in perforation
depth and pump setting depth (6,800' - 5,500' =
1,300') can be determined as follows:
Step 2 - Production Capacity
We can now calculate the pump intake pressure
at the maximum rate of 2,875 BPD. First, we
will make the assumption that even though the
water cut changes, the well's PI will remain
constant. We can now determine the new well
flowing pressure (Pwf) at the maximum desired
production rate (Qd).
Head (FT) x Specific Gravity
PSI =
2.31 Ft/PSI
PSI =
1,300 Ft x 1.04
2.31 Ft/PSI
= 585 PSI
Therefore, the pump intake pressure can now be
determined; 1,175 psi - 585 psi = 590 psi.
24
THE 9 STEP
Step 3 - Gas Calculations
3. Determine the Gas Volume Factor (Bg) as
follows:
Next, we need to determine the total fluid mixture that will be ingested by the pump at the new
maximum desired flow rate (2,875 BPD).
Bg =
1. Determine the Solution Gas/Oil Ratio (Rs ) at
.t.hepump intake pressure with Standing's nomograph (see engineering section ), or by substituting the pump intake pressure for the bubble
point pressure (Pb) in Standing's equation;
(
Rs = Yg
0.0125 x 0 APIP
x 10
18
100.00091 x T( 0F)
(
Rs = 0.7
b
)
100.0125 x 32
100.00091 x 160
585
x
18
1.2048
5.04 x Z x T
P
Assuming 0.85 Z factor;
g
5.04 x 0.85 x (460 + 160)
= 4.40 bbl/mcf
604
B=
Next, determine the total volume of fluids, and the .4
percentage of free gas released at the pump intake:
Using the producing GOR, and oil volume, .a
determine the total volume of gas (TG) ;
)
1.2048
TG =
BOPD x GOR
1,000
Rs = 94 scf/stb
or
2. Determine the Formation Volume Factor (Bo)
using the Rs from above and Standing's nomograph (see Engineering section) oruseStanding's
equation as follows:
TG =
b. Using the solution GOR (Rs), at the pump intake,
determine the solution gas (SG);
B
= 0.972 + 0.000147 F1.175
o
SG =
where;
)
0.865
0.5
Yg
+ 1.25TF = Rs
Yo
)
0.5
BOPD x Rs
1,000
or
(
0.7
+ 1.25 x 160 = 284.56F = 94
(2,875 x 0.20) x 300
= 172.5 mcf
1,000
SG =(2875 x 0.20) x 94 = 54.05 mcf
1,000
c. The difference represents the volume of free gas
(FG) released from solution by the decrease in
pressure from the bubble point pressure of 1,500
psi, to the pump intake pressure of 1,000 psi.
(
Therefore;
Bo = 0.972 + 0.000147 (284.56)1.175
Bo =1.08 reservoir bbl/stock tank bbl
FG =172.5 mcf - 54.05 mcf = 118.5 mcf
25
THE 9 STEP
The volume of oil (Vo), at the pump intake: .d
Vo = BOPD x FormationVolume Factor Bo
Vo = 575 bopd x 1.08 = 621 bopd
Percent of gas not separated is 10%: .a
Vg = Volume of gas at PIP x % ingested
Vg = 521 BPD x 0.1
Vg = 52 BPD
The volume of free gas (Vg), at the pump .e
intake:
Vg = Free Gas x Gas Volume Factor Bg
Vg = 118.5 mcf x 4.40 bbl/mcf = 521 bgpd
Total volume of fluid mixture ingested .b
into pump is:
Vo = 621BPD
Vg = 52 BPD
Vw = 2,300 BPD
V = 2,973 BPD
t
The volume of water (Vw), at the pump .f
intake:
Vw = Total Fluid Volume x % Water
Vw = 2,875 BPD x 0.80 = 2,300 bwpd
The amount of free gas entering the first .c
pump stage as a percent of total fluid
mixture is:
g. The total volume (V ) of
t oil, water, and gas,
at the pump intake, can now be determined:
Vt = Vo + Vg + Vw
V = 621 bopd + 521 bgpd + 2,300 bwpd
t
Vt = 3,442 BFPD
Vg
% Free Gas =
% Free Gas =
h. The ratio, or percentage of free gas present
at the pump intake to the total volume of
fluid is:
Vg
% Free Gas =
Vt
Vt
52 BPD
x 100 = 2%
2,973 BPD
As the free gas represents only 2% by
volume of fluid being pumped it has no
significant effect of the well fluid composite specific gravity and may be ignored for
conservative motor sizing.
or
6. Now that the total volume of fluid entering the
first pump stage is known (2,973 BFPD) and the
composite specific gravity has been determined
we can continue to the next step of designing the
ESP system.
521 BGPD
% Free Gas =
x 100 = 15%
3,442 BFPD
5. As this value is greater than 10% by volume,
there is significant free gas to affect pump performance, therefore, it is recommended that a
gas separator be installed. Next, we will have to
assume a gas separator efficiency. At 15% free
gas, we will assume 90% efficiency of separation.
26
THE 9 STEP
Step 4 - Total Dynamic Head
Step 5 - Pump Type Selection
Sufficient data is now available to determine the
total dynamic head required at the maximum
desired flow rate (2,973 BPD). The total dynamic head for the minimum desired flow rate
(2,550 BPD) was previously determined to be
3,556 ft.
TDH = Hd + Ft + Pd
We have now determined both hydraulic requirements for our variable speed pumping system. Those requirements are:
H = The vertical distance in feet between the
d
estimated producing fluid level and the surface.
Maximum Hydraulic Requirement
Flow Rate 2,973 BPD
Total Dynamic Head 4,746 ft.
Hd = Pump depth -
)
(
PIP x 2.31ft/psi
Specific Gravity
)
590 psi x 2.31 ft/psi
H = 5,500 ft. 1.04
d
Minimum Hydraulic Requirement
Flow Rate 2,550 BPD
Total Dynamic Head 3,556 ft.
In our economic justification for using the variable speed controller, we elected to reduce the
size on the down-hole unit. To accomplish this,
we can follow these guidelines:
(
As the operating frequency increases, the .1
number of stages required to generate the
required lift decreases.
Hd = 4,190 ft (1,277m).
Ft = Tubing friction loss. Refer to Friction Loss
Charts in the engineering section.
The closer you operate to the best effi- .2
ciency point, the lower the power requirement, and the power cost.
Friction loss per 1,000 ft. of 2-7/8" tubing (new)
is 60 ft. per 1,000 ft. of depth at 2,973 BPD (405
M3PD), or 4.5 meters per 100 meters. Using the
desired pump setting depth:
Ft =
5,500 ft. x 60 ft.
A fixed frequency motor of a particular .3
frame size has a maximum output torque,
provided that the specified voltage is supplied to its terminals. The same torque can
be achieved at other speeds by varying the
voltage in proportion to the frequency. This
way the magnetizing current and flux density will remain constant, and so the available torque will be constant (at no slip rpm).
As a result, power output rating will be
directly proportional to speed, since power
rating is obtained bymultiplying rated torque
times speed.
= 330 ft. (100.6m)
1,000 ft.
P = Discharge pressure head (desired wellhead
d
pressure). Using the composite specific gravity:
d
1.02
100 psi x 2.31 ft/psi
= 226 ft. (68.9 m)
P =
TDH = 4,190 ft. + 330 ft. + 226 ft. = 4,746 ft.
or
TDH = 1277 m + 100.6 m + 68.9 m = 1,446.6 m
27
THE 9 STEP
Using the variable speed performance curves,
select a pump that will fit in the casing, and the
maximum flow rate (2,973 BPD) falls at its best
efficiency point (BEP). The GC-2200 satisfies
these conditions at 81 Hz (see below).
Referring to the pump selection tables in the
catalog, you will find that a housing number 6
will support 55 stages of the GC-2200 pump.
Therefore, this 55 stage GC-2200 meets our
maximum hydraulic requirement.
Next, select the head per stage from the curve on
the vertical axis, should read 86 ft. With the
maximum total dynamic head requirement of
4,746 ft., we can determine the number of pump
stages required.
To determine if it meets our minimum hydraulic
requirement, divide the minimum total dynamic
head requirement by the number of stages.
No. Stages =
No. Stages =
Minimum Head/Stage =
Maximum Total Dynamic Head
Head/Stage
86 ft.
3,556 ft.
= 64.7 ft.
55 stgs.
Plotting the minimum head/stage (64.7 ft.) and
the minimum flow rate (2,550 BPD) on the
curve below indicates an operating frequency of
70 Hz. Note, the minimum hydraulic requirement is also near the pump's BEP.
4,746 ft.
= 55 stages
28
THE 9 STEP
Using the technical data provided in the engineering section determine if any load limitations
were exceeded (e.g. shaft loading, thrust bearing
loading, housing burst pressure limitations, fluid
velocity passing the motor, etc.).
Next, using the VSC curve find the BHP/stage at
the 60 hertz BEP (1.12 HP). To calculate the
BHP at the maximum frequency:
BHP @ Max. Hz. =
Max. Hz.
BHP/Stg. x No. Stgs. x x Sp. Gr.
60 Hz.
or
81 Hz.
1.12 x 55 x
3
(
) (
3
Next, select the power cable and calculate the
cable voltage drop. Based on the motor current
(35 amps) and the temperature (160 oF), number
6 cable can be used. Adding 200' for surface
connections, the cable voltage drop is:
)
x 1.04 = 157.6 HP
60 Hz.
In this example we decided to use a rotary gas
separator, which is a centrifugal machine. The
HP requirement also changes by a cube function. Referring to the catalog, the 513 series
rotary gas separator requires 5 HP at 60 Hertz.
)
3
81 Hz.
x 1.04= 12.8 60
HPHz.
Separator HP = 5 x
Cable Drop =
24 v x 1.201 x 5,700'
=164 volts
1,000
We can now calculate the required surface voltage (SV) at the maximum operating frequency
as follows:
(
)
Max Hz.
SV = Motor Volts x 60 Hz. + Voltage Drop
(
)
Total BHP for pump and separator = 170.4 HP
To calculate the equivalent 60 Hertz BHP for
both the pump and gas separator:
81 Hz.
+ 164 =
603,060
Hz. voltsSV = 2,145 x
(
Note: Surface voltage is greater than standard
3KV cable. Should select 4KV or higher cable
construction.
60 Hz. BHP = BHP @ Max. Hz. x 60 Hz.
Max. Hz.
or
Sufficient data is available to calculate KVA.
SV x Motor Amps x 1.73
KVA =
1,000
60 Hz.
= 126.2 HP 60 Hz. BHP = 170.4 x
81 Hz.
Select the appropriate model seal section and
determine the horsepower requirement at the
maximum TDH requirement. Select a motor
which is capable of supplying total horsepower
requirements for the pump, gas separator and
seal. In this example, we will select a 562 series
motor, 130 HP 2,145 volt and 35 amps.
KVA =
3.060 x 35 x 1.73
1,000
= 185 KVA
Referring to the price section of the catalog, we
will select the model 2200 - 3VT, 200 KVA,
NEMA3 (outdoor enclosure) Electrospeed variable speed controller. All other accessory equipment would be selected as the previous example.
29
THE 9 STEP
Computer softwares are Conceived specifically for sales engineers as an aid
when sizing pumps,
Sub-pump or Autograph are types of a computer software program that runs on
IBM compatible computers.
Useful for both fixed speed (50 or 60 Hz) and variable speed applications, and
makes it practical to produce a unique performance curve for each sizing.
The complexity associated with designing
Variable Speed Electrical Submersible Pumping
Systems, along with the introduction of numerous
multiphase flow correlations, has made them the
ideal candidate for microcomputer applications.
Each application is unique and detailed
information on well completion, production
history and reservoir conditions is extremely
important during the initial design phase.
After the creation of the well model, the program will allow you to integrate it with a pump
model to graphically represent the system performance. This is accomplished on the Pump
Sizing Screen (see figure 4).
There are several additional screens available
that allow you to select the appropriate sizing
method, as well as, the selection of the individual
components that make up the ESP system.
This concludes theNine-StepSizingProcedure.
1Gilbert,
W.E. "Flowing and Gas-Lift Well Performance."
API Drilling and Production Pratice. 1954, API, p. 143.
2 Vogel,
J.V. "Inflow Performance Relationship for Solution
Gas Drive Wells." J. Pet. Tech., Jan 1968, pp. 83-93.
3Standing, M.B.
"Volumetric and Phase Behavior of Oil
Field Hydrocarbon Systems", Reinhold Publishing Corp.,
New York (1952).
30
THE 9 STEP
Figure 3 - Well Information Screen
Figure 4 - Pump Sizing Screen
31