9 StepVariable Speed

Pumping System

Accessories andOptional Equipment

ElectricCable

OptimumSize Of

Components

PumpType

TotalDynamic

Head

GasCalculations

ProductionCapacity

BasicData

12

34

56

7

9

8

TABLE OF CONTENTSPAGE NO.

Centrilift's 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

AutographPCTM..................................................................... 28

THE 9 STEP

3THE 9 STEP

The Centrilift Educational Development Cen-ter (EDC) offers high quality education andtraining programs, both for Centrilift associateswho design, build and service our products, andfor our valued customers.

Our modern training facility includes full me-dia-equipped classrooms, a shop training area,and a media development center. In addition toa permanent staff of professional, experiencedinstructors, numerous members of the Centriliftorganization are on call in their areas of exper-tise.

There are three standard programs that are of-fered to our customer. All have a commonobjective to improve the overall reliability of theESP system by understanding its strengths andlimitations. This includes improving the operat-ing life and drastically reducing maintenanceand repair costs. The three standard programsare:

The Electrical Submersible Pumping SystemApplicationsThis is a five day course designed for thosepersonnel involved in production operations,which use electrical submersible pumping sys-tems (ESP's) for artificial lift. The course in-cludes an introduction to the individual compo-nents of an ESP system, including their perfor-mance characteristics and limitations.

This program is an in-depth technical seminardealing with the sizing and application of ESPequipment in harsh environments, which in-clude high GOR, high viscosity and variablespeed operation.

The Variable Speed Controller Technology -Operation-MaintenanceThis is a five day program designed for thosepersonnel directly responsible for the day-to-day operation of Centrilift VSC systems. Eachof the major circuits, as well as the logic circuits,will be discussed in detail. Using simulators andactual VSC systems, participants will demon-strate the actual start-up of a VSC system and setall the necessary operating parameters.

The Installation, Troubleshooting and Ap-plication of ESP EquipmentThis is a five day course designed to prepare oilfield personnel for the installation of electricalsubmersible pumping equipment. The courseprovides instructions of the proper installationtechniques, as well as servicing and pulling ofESP equipment. The course introduces thestudent to the major ESP components and pro-vides a brief explanation of the steps required tosize a complete ESP system.

To satisfy individual requirements, customizedprograms can be developed for specific topicsand can be administered at field locations. Fora complete description of the course contents,schedule and tuition, contact you local Centriliftrepresentative.

Whether our programs are for product informa-tion, technical skills, or skills for working to-gether, the EDC is dedicated to the same goal asall Centrilift associates and facilities. This goalis the pursuit of excellence.

CENTRILIFT'S EDUCATIONAL DEVELOPMENT CENTER

4THE 9 STEP

Step 1 - Basic DataCollect and analyze all the well data that will beused in the design.

Step 2 - Production CapacityDetermine the well productivity at the desiredpump setting depth, or determine the pumpsetting depth at the desired production rate.

Step 3 - Gas CalculationsCalculate the fluid volumes, including gas, at thepump intake conditions .

Step 4 - Total Dynamic HeadDetermine the pump discharge requirement.

Step 5 - Pump TypeFor a given capacity and head select the pumptype that will have the highest efficiency for thedesired flow rate.

Step 6 - Optimum Size of ComponentsSelect the optimum size of pump, motor, andseal section and check equipment limitations.

Step 7 - Electric CableSelect the correct type and size of cable.

Centrilift has established a nine step procedure to help you design the appropriate submersible pumpingsystem for your particular well. Each of the nine steps are explained in the sections that follow, includinggas calculations and variable speed operation. The nine steps are:

Step 8 - Accessory & Optional EquipmentSelect the motor controller, transformer, tubinghead and optional equipment.

Step 9 - The Variable Speed Pumping SystemFor additional operational flexibility, select thevariable speed submersible pumping system. The Electrical Submersible Pumping System

NINE-STEP OVERVIEW

5THE 9 STEP

The design of a submersible pumping unit, un-der most conditions, is not a difficult task, espe-cially if reliable data is available. Although, ifthe information, especially that pertaining to thewells capacity, is poor, the design will usuallybe marginal. Bad data often results in a misap-plied pump and costly operation. A misappliedpump may operate outside the recommendedrange, overload or underload the motor, or draw-down the well at a rapid rate which may result information damage. On the other extreme, thepump may not be large enough to provide thedesired production rate.

Too often data from other wells in the same fieldor in a nearby area is used, assuming that wellsfrom the same producing horizon will havesimilar characteristics. Unfortunately for theengineer sizing the submersible installations, oilwells are much like fingerprints, that is, no twoare quite alike.

The actual selection procedure can vary signifi-cantly depending upon the well fluid properties.The three major types of ESP applications are:1. High water-cut wells producing fresh water or brine.2. Wells with multi-phase flow (high GOR).3. Wells producing highly viscous fluids.

Following is a list of data required:

1. Well Dataa. Casing or liner size and weightb. Tubing size, type and thread(condition)c. Perforated or open hole intervald. Pump setting depth (measured & verti-

cal)

2. Production Dataa. Wellhead tubing pressureb. Wellhead casing pressurec. Present production rated. Producing fluid level and/or pump intake

pressuree. Static fluid level and/or static bottom-hole

pressuref. Datum pointg. Bottom-hole temperatureh. Desired production ratei. Gas-oil ratioj. Water cut

3. Well Fluid Conditionsa. Specific gravity of waterb. Oil API or specific gravityc. Specific gravity of gasd. Bubble-point pressure of gase. Viscosity of oilf. PVT data

4. Power Sourcesa. Available primary voltageb. Frequencyc. Power source capabilities

5. Possible Problemsa. Sandb. Depositionc. Corrosiond. Paraffine. Emulsionf. Gasg. Temperature

STEP 1 - BASIC DATA

6THE 9 STEP

The following is a simplification of proceduresfor predicting well performance. This discus-sion assumes a flow efficiency of one. A dam-aged well or other factors will effect the flowefficiency and could change the well's produc-tivity.

Productivity IndexWhen the well flowing pressure (P

wf) is greaterthan bubble -point pressure (Pb) the fluid flow issimilar to single phase flow, and the inflowperformance curve is a straight line with slope J,as given by the productivity index, PI:

PI = J =

Where:

Q = the fluid test production rate.

Pwf = the well flowing pressure

@ test rate Q.

Pr = the well static pressure.

Note:P

r and P

wf are terms which arealways referenced to the samespecific vertical depth.

Inflow Performance RelationshipIf P

wf is less than Pb, resulting in multi-phaseflow, the IPR method should be used. Therelationship is given by the following equation:

Qo max =

Qo

1 - 0.2( ) - 0.8( )Pwf Pwf 2P

rP

r

This relationship was first used by W.E. Gilbert1and further developed by J.V. Vogel2. Vogeldeveloped a dimensionless reference curve thatcan be used to determine the IPR curve for aparticular well.

STEP 2 - PRODUCTION CAPACITY

Pr - P

wf

Q

Producing Rate (qo/(q

o) max). Fraction of Maximum0

0INFLOW PERFORMANCE

REFERENCE CURVE

Botto

m H

ole

Wel

l Pre

ssur

e (P

WF/P

R).

Frac

tion

of Re

servo

ir Pr

essur

e

7THE 9 STEP

The presence of free gas at the pump intake andin the discharge tubing makes the process ofequipment selection much more complicatedand voluminous. As the fluid (liquid and gasmixture) flows through the pump stages fromintake to the discharge and through the dis-charge tubing, the pressure and consequently,fluid properties (such as volume, density, etc.)continuously go on changing. Also, the pres-ence of free gas in the discharge tubing maycreate significant gas-lift effect and consider-ably reduce the required discharge pressure.

The performance of a centrifugal pump is alsoconsiderably affected by the gas. As long as thegas remains in solution, the pump behaves nor-mally as if pumping a liquid of low density.However, the pump starts producing lower thannormal head as the gas-to-liquid ratio (at pump-ing conditions) increases beyond a certain criti-cal value (usually about 10 - 15%). It is mainlydue to separation of the liquid and gas phases inthe pump stage and due to a slippage betweenthese two phases. This phenomenon has notbeen well studied and there is no general corre-lation describing the effect of free gas on pumpperformance. A submersible pump is usuallyselected by assuming no slippage between thetwo phases or by correcting stage performancebased on actual field test data and past experi-ence.

Ideally, a well would be produced with a sub-mergence pressure above the bubble point pres-sure to keep any gases in solution at the pumpintake. This is typically not possible, so thegases must be separated from the other fluidsprior to the pump intake to achieve maximumsystem efficiency.

There are numerous combinations of equipmentconfigurations and wellbore completions whichare available for enhancing the performance ofESP's in gassy applications. Many of these areidentified in the "Gas Handling Guideline". Spe-cifically, Centrilift offers several optional com-

STEP 3 - GAS CALCULATIONSponents used for separating gas from the fluidgoing to the pump intake. These are listedacccording to increasing efficiency. The first isa reverse flow intake, which uses the naturalbuoyancy of the fluids for separation. The sec-ond is a vortex type intake, which uses the fluidvelocity to set-up a rotational flow to induceradial separation of the gas. The last is a rotarygas separator intake, which utilizes a mechani-cal, rotating chamber to impart a high, centrifu-gal force on the fluid to separate the gas.

It is essential to determine the effect of the gas onthe fluid volume in order to select the properpump and separator. The following calculationsyield the percent free gas by volume.

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 ofmulti-phase correlations to select from. Thecorrelation you select will affect your design, soselect the one that best matches your conditions.The following are Standings3 correlations forsolution gas/oil ratio, and formation volumefactor:

Solution Gas/Oil Ratio

Where:Yg = Specific Gravity GasPb = Bubble-Point Pressure, psi (kg/cm2)T = Bottom-hole Temperature, F ( C)

NOTE: Pump Intake Pressure (PIP) should besubstituted for Bubble Point Pressure whencalculating intake conditions.

0 0

Rs= 0.1342Yg(

Rs = Yg( )

100.00091 x T( F)100.0125 x API

100.0125 x APIxPb

18 0x

100.00091 x (1.8T( C) + 32)

Pb 1.2048

Or in metric,

0

)1.20480 0

8THE 9 STEP

Where: Z = Gas compressibility factor (0.81 to 0.91) T = Bottom-hole temperature degrees Rankine (460 + F), or in metric Kelvin (273 + C) P = Submergence pressure psi, or (kg/cm2)

The gas volume factor, Bg, is expressed in reser-voir barrels/st'd mcf gas (m3/m3)

Formation Volume FactorThe formation volume factor B

o, represents the

increased volume a barrel of oil occupies in theformation as compared to a stock barrel.

Bo = 0.972 + 0.000147F1.175

Where: F = Rs ( ) + 1.25T

T = Bottom-hole temperature, For in metric,

Bo = 0.972 + 0.000147 x

{5.61 Rs( ) + 1.25 (1.8t + 32)}1.175

Where:Yg = Specific Gravity of GasY

o = Specific Gravity of Oil

t = Bottom-hole Temperature, C0

ZTP or in metric, Bg = 0.00377

ZTP

Gas Volume Factor

Bg = 5.04

Total Volume of FluidsWhen these three variables, R

s, B

o and Bg are

known, the volumes of oil, water, and free gascan be determined and percentages of each cal-culated. The total volume of gas ( both free andin solution ) can be determined as follows:

Total Gas = 1,000 = MCFProducing GOR x BOPD

or in metric,

Total Gas = Producing GOR x M3PD = M3

The gas in solution at submergence pressure canbe determined as follows:

Solution Gas =

The Free Gas equals the Total Gas minus theSolution Gas.

The volume of oil (Vo) at the pump intake equals

stock tank barrels times Bo, the formation vol-

ume factor.

The volume of gas (Vg) at the pump intakeequals the amount of free gas times Bg, the gasvolume factor.

The volume of water (Vw) in the formation is the

same as stock tank barrels.

Total fluid volume (Vt) can now be determined.Vt = Vo + Vg + Vw

The percentage of free gas to total volume offluids can now be calculated:

% Free Gas =VgVt

YgY

o

0.5YgY

o

Rs x BOPD1,000

= MCF

0

0

0.5

0

9THE 9 STEP

The next step is to determine the total dynamichead required to pump the desired capacity. Thetotal pump head refers to feet (meters) of liquidbeing pumped and is calculated to be the sum of:1) Net well lift (dynamic lift); 2) well tubingfriction loss; and 3) wellhead discharge pres-sure. The simplified equation is as follows:

TDH = Hd + Ft + Pd

where:

TDH = total dynamic head in feet (meters)delivered by the pump when pumping the de-sired volume.

Hd = vertical distance in feet (meters) betweenthe wellhead and the estimated producing fluidlevel at the expected capacity.

Ft = the head required to overcome friction lossin tubing measured in feet (meters).

Pd = the head required to overcome friction in thesurface pipe, valves and fittings, and to over-come elevation changes between wellhead andtank battery. Normally, this is measured ingauge pressure psi (kg/cm2) at the wellhead andcan be converted to head, in feet (meters) asfollows:

U.S.

Pd =

or

Pd =

Total Dynamic Head = Hd + Ft + Pd

Pd

or

Pd =

METRIC

Pd = Specific Gravitykg/cm2 x 10.01 m/kg/cm2

0.0999 x Sp. Gr.kg/cm2

STEP 4 - TOTAL DYNAMIC HEAD

psi x 2.31 ft/psispecific gravity

psi0.433 psi/ft x sp. gr.

Ft

Hd

DynamicFluid Level

Tubing

Pump

Seal

Motor

10

THE 9 STEP

Refer to the pump selection data table, in theEngineering section of your Centrilift catalog,for pump types and ranges. Pump performancecurves (60 Hz and 50 Hz) are included in the"Pump Curve" section of the catalog. Based onexpected fluid production rate and casing size,select the pump type which will, at the expectedproducing rate, be operating within the pump'soperating range and nearest to the pump's peakefficiency,

Where two or more pump types have similarefficiencies at the desired volume, the followingconditions determine the pump choice:

1. Pump prices and corresponding motor sizesand prices may differ somewhat. Normally,the larger-diameter pump and motor are lessexpensive and operate at higher efficiencies.

2. When the wells capacity is not known, orcannot be closely estimated, a pump with a"steep" characteristic curve should be cho-sen. If the desired volume falls at a pointwhere two pump types have approximatelyequal efficiency, choose the pump typewhich requires the greatest number ofstages. Such a pump will produce a capacitynearest the desired volume even if the welllift is substantially more or less thanexpected.

3. If gas is present in the produced fluid, a gasseparator may be required to achieveefficient operation. Refer to Step 3 todetermine the effect of gas on the producedvolume. The adjusted volume affects pumpselection and the size of the other systemcomponents.

4. In wells where the fluid is quite viscousand/or tends to emulsify, or in other ex-traordinary circumstances, some pump cor-rections may be necessary to ensure a moreefficient operation. In such cases, contact aCentrilift sales engineer for recommenda-tions.

The VSSP System and Pump SelectionUnder the above, or other pumping conditions,also consider the Variable Speed SubmersiblePumping (VSSP) system. For instance, in item2 above, if a well is not accurately known, aVSSP system is ideal. An Electrospeed vari-able speed controller effectively converts asingle pump into a family of pumps. So, a pumpcan be selected for an estimated range andadjusted for the desired production level, oncemore data is collected.

The VSSP system with the Electrospeed im-proves pump operation under other conditionsas well, including gassy wells, abrasive wells,low volume wells, etc. It provides soft starts,eliminates intermittent operation, breaks gaslocks, isolates equipment from power tran-sients, minimizes downhole heating, and more.

Review Step 9when considering the VSSP sys-tem. Variable frequency performance curvesare included in the "Pump Curve" section of theCentrilift catalog. The VSSP System withElectrospeed may provide additional econo-mies of capital expenditure and operatingexpenses, and should be considered in Step 6,"Optimum Size of Components." TheElectrospeed variable speed controller and trans-formers for the VSSP system are discussed inSteps 8 and 9.

STEP 5 - PUMP TYPE

11

THE 9 STEP

Centrilift components are built in a number ofsizes and can be assembled in a variety ofcombinations. These combinations must becarefully determined to operate the submersiblepumping system within production requirements,material strength and temperature limits. Whilesizing components, refer to the Engineeringsection of your catalog for each of the followingtables and charts:

Equipment Combinations in Various CasingsMaximum Loading LimitsMaximum Diameter of UnitsVelocity of a Fluid Passing a MotorShaft HP Limitations at Various Frequencies

A fluid velocity of 1 foot per second (0.305meters per second) is recommended to ensureadequate motor cooling. In cases where thisvelocity is not achieved, a motor jacket may berequired to increase the velocity. Contact yoursales engineer under such conditions.

PumpRefer to the Centrilift performance curve of theselected pump type and determine the number ofstages required to produce the anticipated ca-pacity against the previously calculated totaldynamic head. Performance curves for 60 Hz,50 Hz and variable frequency performance arelocated in the catalog. Note that the pumpcharacteristic curves are single stage perfor-mance curves based on water with (specificgravity of 1.00) . At the intersection of thedesired production rate (bottom scale) and thehead-capacity curve (vertical scale), read thehead value on the left scale. Divide this valueinto the total dynamic head to determine thenumber of stages.

Total Stages =

SeparatorRefer to your catalog for gas separator informa-tion. Make the necessary adjustments in horse-power requirements and housing length.

MotorTo select the proper motor size for a predeter-mined pump size, you must first determine thebrake horsepower required by the pump. Thehorsepower per stage is obtained by again refer-ring to the performance curve for the selectedpump and reading the value of the right scale.The brake horsepower required to drive a givenpump is easily calculated by the following for-mula:

BHP = Total Stages x BHP/Stage x Sp. Gr.

Refer to your catalog for motor specifications.

Seal SectionRefer to your catalog for selection of the properseal section. Series 338 seals are recommendedfor 338 series pumps using 375 series motors.Series 400 seals are recommended for 400 seriespumps using 450 series motors. When 544 or562 series motors are used with a 513 seriespump, the 513 series seal is required. A 513-400series adapter is required whenever a 513 seriesseal section is run with a 400 series pump.

STEP 6 - OPTIMUM SIZE OF COMPONENTS

Total Dynamic HeadHead/Stage

12

THE 9 STEP

Centrilift electric cables are normally availablefrom stock in conductor sizes 1, 2, 4, and 6.These sizes are offered in both round and flatconfigurations as shown in your catalog pricesection under Centriline Power Cable.

Several types of armor and insulation are avail-able for protection against corrosive fluids andsevere environments.

Cable selection involves the determination of:1) cable size;2) cable type;3) cable length.

Cable SizeThe proper cable size is dependent on combinedfactors of voltage drop, amperage and availablespace between tubing collars and casing.

Refer to the Cable Voltage Drop curve (seeengineering section) for voltage drop in cable.At the selected motor amperage and the givendownhole temperature, the selection of a cablesize that will give a voltage drop of less than 30volts per 1,000 ft. (305 meters) or less than 15%of motor nameplate volts is recommended. Thiscurve will also enable you to determine thenecessary surface voltage (motor voltage plusvoltage drop in the cable) required to operate themotor.

Finally, refer to the Equipment Combinationtable (see engineering section) to determine ifthe size selected can be used with the proposedtubing and well casing sizes. Cable diameterplus tubing collar diameter will need to be lessthan the inside diameter (I.D.) of the casing.

In determining the optimum cable size, considerfuture equipment requirements that may requirethe use of a lager size cable.

If power cost is a major concern, the Kilowatt-Hour Loss Curve (see Engineering section) canbe used to justify the cable selection. Althoughpower rates vary widely, this data is valuable indetermining the economics of various cablesizes.

Cable TypeSelection of the cable type is primarily based onfluid conditions, bottom-hole temperature andspace limitations within the casing annulus. Referto your catalog price pages for cable specifica-tions.

Where there is not sufficient space to run roundcable, use electric cable of flat configuration.See Equipment Combinations table in Engi-neering section of your catalog for round cablelimitations based on various casing and tubingsizes. Consult your Centrilift representativewhen temperature or gas is a critical factor.

Cable LengthThe total cable length should be at least 100 ft.(30M) longer than the measured pump settingdepth in order to make surface connections asafe distance from the wellhead. Refer to curveon Recommended Maximum Cable Length (seeEngineering section) to avoid the possibility oflow voltage starts.

Cable VentingIn all wells, it is necessary to vent gases from thecable prior to the motor controller to avoidexplosive conditions. A cable venting box isavailable to protect the motor controller fromsuch gases.

STEP 7 - ELECTRIC CABLE

13

THE 9 STEP

1. DOWN HOLE ACCESSORY EQUIPMENTFlat cable (motor lead extension):Select a length at least 6 ft. (1.8m) longer thanpump, intake (standard or gas separator) andseal section for the motor series chosen. Refer toyour catalog for dimensions.

Flat cable guard:Choose the required number of 6 ft. (1.8m)guard sections to at least equal the flat cablelength. Do not use guards for installation of 400series pump and seal section in 5-1/2" O.D., 20-pound casing and for installation of 513 seriespump and seal section in 6 5/8" O.D., 26-poundcasing.

Cable bands:Use one 30 in. (76 cm) cable band every 2 ft. (60cm) for clamping flat cable to pump. The 22 in.(56 cm) length can be used for all tubing-cablecombinations through 3-1/2" O.D. tubing. For4- 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 fordimensions.

Swaged nipple, check valve, and drain valve:Select these accessories on basis of requiredoutside diameters and type of threads.

2. MOTOR CONTROLLERSThe VortexTM is a state-of-the-art digital controlconsisting of two components:

System UnitThis unit performs all the shutdown andrestart operations. It is mounted in the low-voltage compartment of the control panel.

Display Unit (Optional)This unit displays readings, setpoints andalarms. It is normally mounted in the ampchart enclosure for easy access.

It provides all the basic functions, such asunderload, overload, phase imbalance, phaserotation, etc. and over 90 other parametersincluding password and communicationprotocols.

3. SINGLE-PHASE AND THREE-PHASE TRANSFORMERSThe type of transformer selected depends on thesize of the primary power system and the requiredsecondary voltage. Three-phase isolation step-up transformers are generally selected forincreasing voltage from a low voltage system,while a bank of three single-phase transformersis usually selected for reducing a high-voltageprimary power source to the required surfacevoltage.

On existing systems, some of Centrilift unitswill operate without the use of an additionaltransformer. For new installation of units withhigher voltages, it is usually less expensive toinstall three single-phase transformers, connectedwye, to eliminate the auto-transformer.

STEP 8 - ACCESSORY& OPTIONAL EQUIPMENT

14

THE 9 STEP

where:KVA = Kilo-Volt-Amp or 1,000 Volt-AmpV

s = Surface Voltage

Am

= Motor nameplate current in amps

4. SURFACE CABLEChoose approximate length required for con-necting controller to primary power system or totransformer. Two pieces are generally requiredfor installations using an auto-transformer. Sizeshould equal the well cable size except in thecase of step-up or auto-transformer, where theprimary and secondary currents are not the same.

5. WELLHEADS AND ACCESSORIESSelect the wellhead on the basis of casing size,tubing size, maximum recommended load, sur-face pressure, and maximum setting depth. Elec-tric cable passes through the wellhead wherepressure fittings are not required.

Electric Feed Through (EFT) mandrels are alsoavailable. The electric cable is spliced to pig-tails. The EFT wellheads seal against downholepressure and prevent gas leaks at the surface.Refer to your catalog for specifications.

KVA = 1,000

In choosing the size of a step-up transformer ora bank of three single-phase transformers thefollowing equation is used to calculate totalKVA required:

Vs x A

m x 1.73

6. SERVICING EQUIPMENTCable reels, reel supports and cable guides:Select size of cable reel required to handlepreviously selected cable size. Select set ofcable reel supports based on cable reel size.Cable guides are designed to handle cable sizes1 through 6.Normally, customers retain one cable reel, oneset of reel supports, and one cable guide wheelfor future use.

Shipping Cases:Select type and length of case required to ac-commodate previously selected motor, pump,gas separator and seal.

7. OPTIONAL EQUIPMENTBottom-hole pressure (PHD) sensing device:The PHD provides continuous measurement ofbottom-hole pressures.

Automatic well monitoring:Motor controllers are available for continuousmonitoring of pump operation from a centrallocation. Contact your Centrilift representativefor details.

15

THE 9 STEP

where BHP = Brake Horsepower

New Efficiency = 60 Hz efficiency (there isnegligible loss)

A set of curves can be developed for an arbitraryseries of frequencies with these equations, asshown in the variable frequency performancecurves at the end of this step (figure 1). Eachcurve represents a series of points derived fromthe 60 Hz curve for flow and corresponding headpoints, transformed using the equations above.

Suppose we are given the following data at afrequency of 60 Hz:

Rate = 1,200 BPD

Head = 24.5 ft. (from FC-1200 curve @ 1,200BPD)

BHP = 0.34 BHP (from FC-1200 curve @ 1,200BPD)

If a new frequency of 50 Hz is chosen:

New Rate = x 1200 BPD = 1000 BPD

New Head = ( ) x 24.5' =17'

New Head = ( ) x 60 Hz headNew Rate = 60 Hz

x 60 Hz rateNew Frequency

New BHP = ( )New Frequency60 Hz 3x 60 Hz BHP

2New Frequency60 Hz

2

6050

5060( )

The ESP system can be modified to include anElectrospeed variable frequency controller sothat it operates over a much broader range ofcapacity, head, and efficiency. Since a submers-ible pump motor is an induction motor, its speedis proportional to the frequency of the electricalpower supply. By adjusting the frequency, thevariable speed submersible pump (VSSP) sys-tem offers extraordinary potential for boostingproduction, reducing downtime, and increasingprofits. The VSSP can be used to boost effi-ciency in many cases, including highly viscouswells, waterflood wells etc. It extends the rangeof submersible artificial lift to less than 100 BPD(16 M3PD) and up to 100,000 BPD (16,000M3PD).

It is necessary to understand the effects of vary-ing the speed of a submersible pump, in order toapply the VSSP system. The VSSP system canbe analyzed in terms of varying frequency or interms of maintaining constant head. Sales engi-neers have computerized pump selection pro-grams to assist you in VSSP system selection;what follows is a basic explanation of the prin-ciples involved.

Variable FrequencyThe effects of varying frequency can be seen bypreparing new head-capacity curves for the de-sired frequencies, based on the pump's known60 Hz performance curve data. The Electro-speed controller is commonly used to generateany frequency between 30 and 90 Hz.

Curves for frequencies other than 60 Hz can begenerated by using the centrifugal pump affinitylaws. The equations derived from these lawsare:

STEP 9 - VARIABLE SPEED SUBMERSIBLE PUMPING SYSTEM

16

THE 9 STEP

New BHP = ( ) x 0.34 BHP = 0.20 BHP5060 3By performing these calculations at other pro-duction rates, a new curve for 50 Hz operationcan be plotted. Start by locating the existingpoints on the one-stage 60 Hz curve:

60 Hz

X1 Rate (BPD) 0 950 1200 1550 1875

Y1 Head (Feet) 32' 28.6' 24.5' 15' 0'

Efficiency (%) 0 63.5 64 49 0

Following the above equations, calculate thecorresponding values at 50 Hz:

50 Hz

X1 Rate (BPD) 0 792 1000 12921563

Y1 Head (Feet) 22.2' 19.9' 17' 10.4' 0'

Efficiency (%) 0 63.5 64 49 0

Plotting these coordinates gives the one-stageFC-1200 head-capacity performance curve foroperation at 50 Hz. Similar calculations willprovide coordinates for curves at other frequen-cies, as seen below in the FC-1200 variablespeed performance curve. The vortex shapedwindow is the recommended operating range forthe pump. As long as your hydraulic require-ment falls within this range, you are within therecommended operating range of the pump.

Figure 1

17

THE 9 STEP

3

3 3

3 3

3

3

300

0

100

NAME DESIGN EXAMPLE DATE NOV. 20, 1991COMPANYADDRESSWELL NO. AND FIELD NAMEWELL LOCATION (COUNTY, STATE, OTHER)INSTALLATION: NEW ( X ) OR REDESIGN ( ) PRIMARY POWER SUPPLY: 12,470 VOLTS THREEPHASE 60 HZPRODUCING FORMATIONFORMATION TYPE (SANDSTONE, LIMESTONE, OTHER) SANDSTONE

WELL DATA

API CASING 7 IN. O.D. 32 #/FT. 0 FT. TO 6,900 FT. M. TO M.LINER NONE IN. O.D. #/FT. FT. TO FT. M. TO M.OPEN HOLE FT. TO FT. M. TO M.TOTAL DEPTH FT. M.PERFORATION INTERVALS 6,750 FT. TO 6,850 FT. M. TO M.

FT. TO FT. M. TO M.FT. TO FT. M. TO M.

API TUBING 2 - 7/8 IN. O.D. EUE 8 RDTHREADS

RESERVOIR DATA (FROM TEST AND PRODUCTION DATA)PRESENT PRODUCTION 850 BFPD. M PD PUMPING ( X ), SWABBING ( ), FLOWING ()BOTTOM HOLE STATIC PRESSURE 3,200 PSI G@ 6,800 FT. Kg/Sq. Cm. @ M.BOTTOM HOLE FLOWING PRESSURE 2,600 PSIG @ 850 BFPD Kg/Sq. Cm. @ M PD

PSIG @ BFPD Kg/Sq. Cm. @ M PDPRODUCING GOR S.C.F./S.T.B. M /MWATER CUT 75 %OIL API GRAVITY 32BOTTOM HOLE TEMPERATURE 160 F CWATER SPECIFIC GRAVITY 1.085GAS SPECIFIC GRAVITY 0.7OIL VISCOSITY (1) CP. OR SSU@ F C

(2) CP. OR SSU@ F CPVT DATA SOLUTION GOR FVF. PSIG Kg/Sq. Cm.

SOLUTION GOR FVF. PSIG Kg/Sq. Cm.SOLUTION GOR FVF. PSIG Kg/Sq. Cm.SOLUTION GOR FVF. PSIG Kg/Sq. Cm.

BUBBLE-POINT PRESSURE 1,500 PSIG Kg/Sq. Cm.

CENTRILIFT SPECIFICATIONS

DESIRED PRODUCTION 2,300 BFPD. OR BOPD FLUID M PD, OR OIL M PDDESIRED PUMP (INTAKE) VERTICAL SETTING DEPTH 5,500 FT. M.DESIRED PUMP (INTAKE) PRESSURE PSIG Kg/Sq. Cm.REQUIRED WELL HEAD PRESSURE PSIG Kg/Sq. Cm.GOR THROUGH PUMP %CASING VENTED TO ATMOSPHERE ( ) TO PIPELINE ( X ) NONE ( )ELECTRIC POWER VOLTS CYCLESDESIRED PUMP SERIESDESIRED PUMP TYPECASING PRESSURE PSIG Kg/Sq. Cm.SPECIAL PROBLEMS SAND( ), SCALE( ), CORROSION( ), PARAFFIN( ), H2S( ), POWER SUPPLY( )

18

THE 9 STEP

Step 1 - Basic DataSee Centrilift well data sheet on previous pagefor well data.

Step 2 - Production CapacityDetermine the well productivity at the test pres-sure and production. In this case, the desiredproduction rate and pump setting depth aregiven. The pump intake pressure at the desiredproduction rate can be calculated from the presentproduction conditions.

Since the well flowing pressure (2,600 psi) isgreater than bubble-point pressure (1,500 psi)the constant PI method will most probably givesatisfactory results. First, we can determine thePI using the test data.

PI =

The pump intake pressure can be determined bycorrecting the flowing bottom-hole pressure forthe difference in pump setting depth and thedatum point and by considering the friction lossin the casing annulus. In the given example, asthe pump is set 1,300 feet above the perfora-tions, the friction loss due to flow of fluidthrough the annulus from perforations to pumpsetting depth will be small as compared to theflowing pressure and can be neglected.

Because there is both water and oil in the pro-duced fluids it is necessary to calculate a com-posite specific gravity of the produced fluids.To find the composite specific gravity;

Water cut is 75%;0.75 x 1.085 = 0.8138

Oil is 25%;0.25 x 0.865 = 0.2163

The composite specific gravity is the sum of theweighted percentages:

Composite Sp. Gr. = 0.8138 + 0.2163 = 1.03

The pressure due to the difference in perforationdepth and pump setting depth (6,800' - 5,500' =1,300') can be determined as follows:

PSI =

PSI = = 580 PSI

Therefore, the pump intake pressure will be1,580psi - 580 psi = 1,000 psi.

2.31 Ft/PSI1,300 Ft x 1.03

Head (FT) x Specific Gravity2.31 Ft/PSI

PI = = 1.42 bpd/psi850 bpd

3,200 psi - 2,600 psi

Next, we can determine the new well flowingpressure (P

wf) at the desired production rate(Qd).

Pwf = Pr - ( )

QdPI

Pwf = 3,200 psi - ( ) = 1,580 psi2,300 bpd1.42 bpd/psi

The well flowing pressure of 1,580 psi is stillabove the bubble-point pressure of 1,500 psi,therefore, the PI approach should give goodresults.

DESIGN EXAMPLE

QP

r - P

wf

19

THE 9 STEP

Step 3 - Gas CalculationsIn this third step we need to determine the totalfluid mixture, inclusive of water, oil and free gasthat will be ingested by the pump.

3. Determine the Gas Volume Factor (Bg) asfollows:

Bg =5.04 x Z x T

P

Assuming 0.85 Z factor;

Bg= = 2.62 bbl/mcf

4. Next, determine the total volume of fluids and thepercentage of free gas released at the pump intake:

a. Using the producing GOR, and oil volume,determine the total volume of gas (TG) ;

TG =

or

TG = = 172.5 mcf

b. Using the solution GOR (Rs), at the pump

intake, determine the solution gas (SG);

SG =

or

SG = = 103.5 mcf

c. The difference represents the volume of freegas (FG) released from solution by the de-crease in pressure from bubble-point pressureof 1,500 psi, to the pump intake pressure of1,000 psi.

FG =172.5 mcf - 103.5 mcf = 69 mcf

1,0145.04 x 0.85 x (460 + 160)

1. Determine the Solution Gas/Oil Ratio (Rs ) at

the pump intake pressure with Standing's nomo-graph (see figure 2 ), or by substituting thepump intake pressure for the bubble point pres-sure (Pb) in Standing's equation;

Rs = 180 scf/stb

2. Determine the Formation Volume Factor (Bo)

using the Rs from above and Standing's nomo-

graph (see figure 3) or use Standing's equation asfollows:

Bo = 0.972 + 0.000147 F1.175

where;

F = Rs ( ) + 1.25T0.5Y

o

Yg

F = 180 ( ) + 1.25 x 160 = 361.920.8650.5

0.7

Bo

= 0.972 + 0.000147 (361.92)1.175B

o

=1.12 reservoir bbl/stock tank bbl

Therefore;

BOPD x GOR1,000

1,000(2,300 x 0.25) x 300

1,000

BOPD x Rs

(2,300 x 0.25) x 1801,000

Rs = 0.7( )

100.00091 x T( F)R

s = Yg( )100.0125 x API18 0xPb 1.20480

1.2048

18x

1000100.00091 x 160100.0125 x 32

20

THE 9 STEP

d. The volume of oil (Vo), at the pump intake:

Vo = BOPD x Formation Volume Factor B

o

Vo = 575 bopd x 1.12 = 644 bopd

e. The volume of free gas (Vg), at the pumpintake:Vg = Free Gas x Gas Volume Factor BgVg = 69 mcf x 2.62 bbl/mcf = 181 bgpd

f. The volume of water (Vw), at the pump

intake:V

w = Total Fluid Volume x % Water

Vw = 2,300 BPD x 0.75 = 1,725 bwpd

g. The total volume (Vt) of oil, water, and gas,at the pump intake, can now be determined:Vt = Vo + Vg + VwVt = 644 bopd + 181 bgpd + 1,725 bwpdV

t = 2,550 BFPD

h. The ratio, or percentage of free gas presentat the pump intake to the total volume offluid is:

% Free Gas =

or

% Free Gas = x 100 = 7%

As this value is less than 10% by volume,it would have little effect on the pumpperformance, therefore, a gas separator isnot required. Although, there is significantgas to effect the well fluid composite spe-cific gravity at the pump intake.

i. The composite specific gravity, includinggas, can be determined by first calculatingthe total mass of produced fluid (TMPF)from the original data given:

TMPF ={ (BOPD x Sp. Gr. oil+ BWPD xSp. Gr. water) x 62.4 x 5.6146} + (GOR xBOPD x Sp. Gr. Gas x 0.0752)

or

TMPF = {(575 x 0.865 + 1,725 x 1.085) x62.4 x 5.6146} + (300 x 575 x 0.7 x0.0752) = 839,064 lbs/day

Composite Sp. Gr. =

Composite Sp. Gr. =

Composite Sp. Gr. = 0.939

5. Now that the total volume of fluid entering thefirst pump stage is known (2,550 BFPD) and thecomposite specific gravity has been determinedwe can continue to the next step of designing theESP system.

2,550 x 5.6146 x 62.4839,064 lbs/day

BFPD x 5.6146 x 62.4TMPF

Vt

Vg

181 BGPD2,550 BFPD

21

THE 9 STEP

Step 4 - Total Dynamic HeadSufficient data is now available to determine thetotal dynamic head required by the pump.

TDH = Hd + Ft + Pd

Hd = The vertical distance in feet between theestimated producing fluid level and the surface.

Hd = Pump depth - ( )Hd = 5,500 ft. - ( )Hd = 3,040 ft (926.6m).

Ft = Tubing friction loss. Refer to Friction Loss Charts in the engineering section.

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 (405M3PD), or 4.5 meters per 100 meters. Using thedesired pump setting depth:

Ft = = 270 ft. (82.3m)

Pd = Discharge pressure head (desired wellheadpressure). Using the composite specific gravity:

Pd = = 246 ft. (75 m)

TDH = 3,040 ft. + 270 ft. + 246 ft. = 3,556 ft.

or

TDH = 926.6 m + 82.3 m + 75 m = 1,084 m

5,500 ft. x 49 ft.1,000 ft.

Step 5 - Pump Type SelectionRefer to Pump Selection Table in Engineeringsection of catalog . Select the pump type withthe highest efficiency at the calculated capacity,2,550 BPD (405 M3PD) that will fit in thecasing. Select the 513 series GC2200 pump andlocate it's performance curve.

The head in feet (meters) for one stage at 2,550BPD (405 M3PD) is 41.8 ft. (13 m). The brakehorsepower (BHP) per stage is 1.16.

To determine the total number of stages re-quired, divide the total dynamic head by thehead/stage taken from the curve.

Number stages =

Number of stages = = 85 Stages

Next, refer to your catalog for the GC2200pump. The housing number 9 can house amaximum of 84 stages, 93 stages for a housing10. Because the 84 stage pump is only one stageless than our requirement, it will be our selec-tion.

Once you've decided on the maximum numberof pump stages, calculate the total brake horse-power required as follows:

BHP = BHP/Stage x No. Stages x Sp. Gr.

BHP = 1.16 x 84 x 0.939 = 91.5 HP

Step 6 - Optimum Size of ComponentsGas SeparatorIf a gas separator was required, refer to yourcatalog to select the appropriate separator anddetermine its horsepower requirement.

TDH

Head/stage

PIP x 2.31ft/psiSpecific Gravity

1,000 psi x 2.31 ft/psi0.939

100 psi x 2.31 ft/psi0.939

3,556 ft.41.8 ft.

22

THE 9 STEP

Seal SectionNormally the seal section series is the same asthat of the pump, although, there are exceptionsand special adapters are available to connect theunits together. We will select the 513 seriesGSB seal section.

The horsepower requirement for the seal de-pends upon the total dynamic head produced bythe pump. The Horsepower vs TDH curves inthe Engineering section show a requirement of3.0 horsepower for the 513 series seal operatingagainst a TDH of 3,556 ft. Therefore, the totalhorsepower requirement for this example is 91.5HP for the pump, plus 3.0 HP for the seal, or 94.5HP total.

MotorA 500 series motor (544 or 562) should be usedwith the 513 series pump. In this example wewill select the 100 HP 562 series motor from thecatalog. The motor voltage can be selectedbased on the following considerations:

a. The high voltage, consequently low-cur-rent, motors have lower cable losses andrequire smaller conductor size cables.High voltage motors have superior start-ing characteristics: a feature that can beextremely important if excessive voltagelosses are expected during starting.

b. Although, the higher the motor voltage,the more expensive the motor controllerwill be.

In some cases, the savings due to smaller cablemay be offset by the difference in motor control-ler cost and it may be necessary to make aneconomic analysis for the various voltage mo-tors. However, for this example, we will selectthe high-voltage motor (100 HP 2145 volts, 27amps).

Referring to the Engineering section, it can beseen that all operating parameters are well withintheir recommended ranges (e.g. thrust bearing,shaft HP, housing burst pressure and fluid veloc-ity.

Step 7 - Electric Cable

Determine Cable SizeThe cable size is selected based on its currentcarrying 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 than30 volts per 1,000 ft. All conductor sizes 1through 6) fall in this category. The #6 cable hasa voltage drop of 18.5 x 1.201 = 22.2 volts/1,000ft. (305 m) and is the least expensive. This willbe the cable size used in our example.

Cable TypeDue to the gassy conditions and the bottom-holetemperature, the CPN cable should be used.Check to be sure the cable diameter plus tubingcollar diameter is smaller than the casing I.D.(see Engineering section ).

Cable LengthThe pump setting depth is 5,500 ft. (1676.4 m).With 100 ft. (30.5 m) of cable for surfaceconnections, the total cable length should be5,600 ft. (1,707 m). You will also find that thecable length is within the recommended maxi-mum length (see Engineering section).

Cable VentingA cable vent box must be installed between thewellhead and the motor controller to prevent gasmigration to the controller.

23

THE 9 STEP

Step 8 - Accessory and Miscellaneous EquipmentFlat Cable - Motor Lead ExtensionPump Length = 14.8 ft. (4.51 m)Seal Length = 6.3 ft. (1.92 m)Plus 6 ft. = 6.0 ft. (1.83 m) = 27.1 ft. (8.26 m)

Select 35 ft. (10.7 m) 562 series flat cable.

Flat GuardsCable guards are available in 6 ft. sections,therefore, 6 sections will be sufficient.

Cable BandsThe pump and seal section are approximately 20ft. (6 m) long. Twenty-two inch (56 cm) bandswill be required to clamp to the housing, withbands spaced at 2 ft. ( 61 cm) intervals (10bands).

Above the pump, banding of the tubing pluscable, 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. wouldrequire 367 bands.

Downhole Accessory EquipmentRefer to your catalog for the following:

Swaged NippleThe pump outlet is 2-7/8 inches, as shown ontable 5, so no swaged nipple is required for the2-7/8 inch tubing.

Check ValveThe 2-7/8 inch EUE 8 round thread check valvewill be required.

Drain ValveThe 2-7/8 inch EUE 8 round thread drain valvewill be required.

Motor ControllerThe motor controller selection is based on itsvoltage, amperage, and KVA rating. Therefore,before selecting the controller we must firstdetermine the motor controller voltage. We willassume the controller will be the same as thesurface voltage going down-hole. The surfacevoltage (SV) is the sum of the motor voltage andthe total voltage loss in the cable.

SV = 2,145 volts + ( )Surface Voltage = 2,269 Volts

The motor amperage is 27 amps, the KVA cannow be Calculated:

KVA =

KVA =

KVA = 106

The 6H-CG motor controller suits these require-ments.

TransformerThe transformer selection is based on the avail-able primary power supply (12,470 volts), thesecondary voltage requirement (2,269 volts),and the KVA requirement( 106 KVA). Chose3 37.5 KVA single phase transformers as shownin your catalog.

Surface CableSelect 50 ft. (15.2 m) of #1 cable for surfaceconnection to transformers.

22.2 volts x 5,600 ft.1,000 Ft

1,000

2,269 volts x 27 amps x 1.731,000

SV x Motor Amps x 1.73

24

THE 9 STEP

Pwf = Pr - ( )We will now take the previous example anddesign a new system using a Variable Speed

Controller. To help justify the use of a variablespeed controller, I have added two new condi-tions. Those conditions are:

1. First, assume we need to maintain a con-stant oil production (575 BOPD), although,reservoir data indicates we should see anincrease in water cut (75% to 80%) overthe next few months.

2. To satisfy our economic justification inusing the variable speed controller, weneed to reduce the initial cost and size ofthe downhole assembly.

In order to maintain oil production as the watercut increases, we need to determine the maxi-mum desired flow rate with 80% water.

Maximum Flow Rate = x 100

Max. Flow = x 100 = 2,875 BPD

Step 2 - Production CapacityWe can now calculate the pump intake pressureat the maximum rate of 2,875 BPD. First, wewill make the assumption that even though thewater cut changes, the well's PI will remainconstant. We can now determine the new wellflowing pressure (P

wf) at the maximum desiredproduction rate (Qd).

Pwf = 3,200 psi - ( ) = 1,175 psi1.42 bpd/psi

The new well flowing pressure of 1,175 psi isslightly below the bubble point pressure of 1,500psi, therefore, the PI approach should still givegood results.

The pump intake pressure can be determined thesame as before, although, first we must calculatea 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

The composite specific gravity is the sum of theweighted percentages:

Composite Sp. Gr. = 0.868 + 0.173 = 1.04

The pressure due to the difference in perforationdepth and pump setting depth (6,800' - 5,500' =1,300') can be determined as follows:

PSI =2.31 Ft/PSI

Head (FT) x Specific Gravity

PSI = = 585 PSI

Therefore, the pump intake pressure can now bedetermined; 1,175 psi - 585 psi = 590 psi.

2.31 Ft/PSI1,300 Ft x 1.04

575 BPD20%

% oil

PIQd

2,875 bpd

BOPD

DESIGN EXAMPLE - Variable Speed Pumping System

25

THE 9 STEP

Assuming 0.85 Z factor;

Bg= = 4.40 bbl/mcf

4. Next, determine the total volume of fluids, and thepercentage of free gas released at the pump intake:

a. Using the producing GOR, and oil volume,determine the total volume of gas (TG) ;

TG =

or

TG = = 172.5 mcf

b. Using the solution GOR (Rs), at the pump intake,

determine the solution gas (SG);

SG =

or

SG = = 54.05 mcf

c. The difference represents the volume of free gas(FG) released from solution by the decrease inpressure from the bubble point pressure of 1,500psi, to the pump intake pressure of 1,000 psi.

FG =172.5 mcf - 54.05 mcf = 118.5 mcf

Step 3 - Gas CalculationsNext, we need to determine the total fluid mix-ture that will be ingested by the pump at the newmaximum desired flow rate (2,875 BPD).

..

3. Determine the Gas Volume Factor (Bg) asfollows:

Bg =5.04 x Z x T

P

6045.04 x 0.85 x (460 + 160)

1. Determine the Solution Gas/Oil Ratio (Rs ) at

the pump intake pressure with Standing's nomo-graph (see engineering section ), or by substitut-ing the pump intake pressure for the bubblepoint pressure (Pb) in Standing's equation;

Rs = 94 scf/stb

2. Determine the Formation Volume Factor (Bo)

using the Rs from above and Standing's nomo-

graph (see Engineering section) or use Standing'sequation as follows:

Bo = 0.972 + 0.000147 F1.175

where;

F = Rs ( ) + 1.25T0.5

Yo

Yg

F = 94 ( ) + 1.25 x 160 = 284.56B

o = 0.972 + 0.000147 (284.56)1.175

Bo

=1.08 reservoir bbl/stock tank bbl

Therefore;

BOPD x GOR

1,000(2,875 x 0.20) x 300

1,000

BOPD x Rs

(2875 x 0.20) x 941,000

Rs = 0.7( )

100.00091 x T( F)Rs = Yg( )100.0125 x API18 0xPb 1.204801.2048

18 x 100.00091 x 160100.0125 x 32585

0.70.865

0.5

1,000

26

THE 9 STEP

d. The volume of oil (Vo), at the pump intake:

Vo = BOPD x Formation Volume Factor B

o

Vo = 575 bopd x 1.08 = 621 bopd

e. The volume of free gas (Vg), at the pumpintake:Vg = Free Gas x Gas Volume Factor BgVg = 118.5 mcf x 4.40 bbl/mcf = 521 bgpd

f. The volume of water (Vw), at the pump

intake:V

w = Total Fluid Volume x % Water

Vw = 2,875 BPD x 0.80 = 2,300 bwpd

g. The total volume (Vt) of oil, water, and gas,at the pump intake, can now be determined:Vt = Vo + Vg + VwVt = 621 bopd + 521 bgpd + 2,300 bwpdV

t = 3,442 BFPD

h. The ratio, or percentage of free gas presentat the pump intake to the total volume offluid is:

% Free Gas =

or

% Free Gas = x 100 = 15%

5. As this value is greater than 10% by volume,there is significant free gas to affect pump per-formance, therefore, it is recommended that agas separator be installed. Next, we will have toassume a gas separator efficiency. At 15% freegas, we will assume 90% efficiency of separa-tion.

a. Percent of gas not separated is 10%:Vg = Volume of gas at PIP x % ingestedVg = 521 BPD x 0.1Vg = 52 BPD

b. Total volume of fluid mixture ingestedinto pump is:V

o = 621 BPD

Vg = 52 BPDV

w = 2,300 BPD

Vt = 2,973 BPD

c. The amount of free gas entering the firstpump stage as a percent of total fluidmixture is:

% Free Gas =

% Free Gas =

As the free gas represents only 2% byvolume of fluid being pumped it has nosignificant effect of the well fluid compos-ite specific gravity and may be ignored forconservative motor sizing.

6. Now that the total volume of fluid entering thefirst pump stage is known (2,973 BFPD) and thecomposite specific gravity has been determinedwe can continue to the next step of designing theESP system.

VgV

t

52 BPD2,973 BPD

x 100 = 2%

VgVt

521 BGPD3,442 BFPD

27

THE 9 STEP

Step 5 - Pump Type SelectionWe have now determined both hydraulic re-quirements for our variable speed pumping sys-tem. Those requirements are:

Minimum Hydraulic Requirement Flow Rate 2,550 BPD

Total Dynamic Head 3,556 ft.

Maximum Hydraulic Requirement Flow Rate 2,973 BPD

Total Dynamic Head 4,746 ft.

In our economic justification for using the vari-able speed controller, we elected to reduce thesize on the down-hole unit. To accomplish this,we can follow these guidelines:

1. As the operating frequency increases, thenumber of stages required to generate therequired lift decreases.

2. The closer you operate to the best effi-ciency point, the lower the power require-ment, and the power cost.

3. A fixed frequency motor of a particularframe size has a maximum output torque,provided that the specified voltage is sup-plied to its terminals. The same torque canbe achieved at other speeds by varying thevoltage in proportion to the frequency. Thisway the magnetizing current and flux den-sity will remain constant, and so the avail-able torque will be constant (at no slip rpm).As a result, power output rating will bedirectly proportional to speed, since powerrating is obtained by multiplying rated torquetimes speed.

Step 4 - Total Dynamic HeadSufficient data is now available to determine thetotal dynamic head required at the maximumdesired flow rate (2,973 BPD). The total dy-namic head for the minimum desired flow rate(2,550 BPD) was previously determined to be3,556 ft.

TDH = Hd + Ft + Pd

Hd = The vertical distance in feet between theestimated producing fluid level and the surface.

Hd = Pump depth - ( )Hd = 5,500 ft. - ( )Hd = 4,190 ft (1,277m).

Ft = Tubing friction loss. Refer to Friction Loss Charts in the engineering section.

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 (405M3PD), or 4.5 meters per 100 meters. Using thedesired pump setting depth:

Ft = = 330 ft. (100.6m)

Pd = Discharge pressure head (desired wellheadpressure). Using the composite specific gravity:

Pd = = 226 ft. (68.9 m)

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

5,500 ft. x 60 ft.

100 psi x 2.31 ft/psi

1.04

Specific Gravity

1,000 ft.

1.02

PIP x 2.31ft/psi

590 psi x 2.31 ft/psi

28

THE 9 STEP

Using the variable speed performance curves,select a pump that will fit in the casing, and themaximum flow rate (2,973 BPD) falls at its bestefficiency point (BEP). The GC-2200 satisfiesthese conditions at 81 Hz (see below).

Next, select the head per stage from the curve onthe vertical axis, should read 86 ft. With themaximum total dynamic head requirement of4,746 ft., we can determine the number of pumpstages required.

No. Stages =

No. Stages = = 55 stages

Referring to the pump selection tables in thecatalog, you will find that a housing number 6will support 55 stages of the GC-2200 pump.Therefore, this 55 stage GC-2200 meets ourmaximum hydraulic requirement.

To determine if it meets our minimum hydraulicrequirement, divide the minimum total dynamichead requirement by the number of stages.

Minimum Head/Stage = = 64.7 ft.

Plotting the minimum head/stage (64.7 ft.) andthe minimum flow rate (2,550 BPD) on thecurve below indicates an operating frequency of70 Hz. Note, the minimum hydraulic require-ment is also near the pump's BEP.

55 stgs.3,556 ft.

Maximum Total Dynamic HeadHead/Stage

86 ft.4,746 ft.

29

THE 9 STEP

or

60 Hz. BHP = 170.4 x = 126.2 HP

Select the appropriate model seal section anddetermine the horsepower requirement at themaximum TDH requirement. Select a motorwhich is capable of supplying total horsepowerrequirements for the pump, gas separator andseal. In this example, we will select a 562 seriesmotor, 130 HP 2,145 volt and 35 amps.

Next, using the VSC curve for the GC-2200 findthe BHP/stage at the 60 hertz BEP (1.12 HP). Tocalculate the BHP at the maximum frequency:

BHP @ Max. Hz. =

BHP/Stg. x No. Stgs. x ( ) x Sp. Gr.or

1.12 x 55 x ( ) x 1.04 = 157.6 HPIn this example we decided to use a rotary gasseparator, which is a centrifugal machine. TheHP requirement also changes by a cube func-tion. Referring to the catalog, the 513 seriesrotary gas separator requires 5 HP at 60 Hertz.

Separator HP = 5 x ( ) x 1.04= 12.8 HPTotal BHP for pump and separator = 170.4 HP

To calculate the equivalent 60 Hertz BHP forboth the pump and gas separator:

60 Hz. BHP = BHP @ Max. Hz. x

3Max. Hz.60 Hz.

Next, select the power cable and calculate thecable voltage drop. Based on the motor current(35 amps) and the temperature (160 F), number6 cable can be used. Adding 200' for surfaceconnections, the cable voltage drop is:

Cable Drop = =164 volts

We can now calculate the required surface volt-age (SV) at the maximum operating frequencyas follows:

SV = Motor Volts x ( ) + Voltage DropSV = 2,145 x ( ) + 164 = 3,060 voltsNote: Surface voltage is greater than standard3KV cable. Should select 4KV or higher cableconstruction.

Sufficient data is available to calculate KVA.

KVA =

KVA = = 185 KVA

Referring to the price section of the catalog, wewill select the model 2200 - 3VT, 200 KVA,NEMA 3 (outdoor enclosure) Electrospeed vari-able speed controller. All other accessory equip-ment would be selected as the previous example.

o

24 v x 1.201 x 5,700'1,000

Max Hz.60 Hz.

60 Hz.81 Hz.

SV x Motor Amps x 1.731,000

1,0003.060 x 35 x 1.73

Using the technical data provided in the engi-neering section determine if any load limitationswere exceeded (e.g. shaft loading, thrust bearingloading, housing burst pressure limitations, fluidvelocity passing the motor, etc.).

60 Hz.

381 Hz.

60 Hz.81 Hz.

Max. Hz.60 Hz.

60 Hz.81 Hz.

3

30

THE 9 STEP

After the creation of the well model, the pro-gram will allow you to integrate it with a pumpmodel to graphically represent the system per-formance. This is accomplished on the PumpSizing Screen (see figure 4).

There are several additional screens availablethat allow you to select the appropriate sizingmethod, as well as, the selection of the individualcomponents that make up the ESP system.

This concludes the Nine-Step Sizing Procedure.

Conceived specifically for Centrilift sales engineers as an aid when sizing pumps,AutographPCTM is a computer software program that runs on IBM compatiblecomputers.

AutographPCTM is useful for both fixed speed (50 or 60 Hz) and variable speedapplications, and makes it practical to produce a unique performance curve for eachsizing.

Understanding the basic theory of sizing submersible pumps is considered a prerequisiteto using the computer software; contact your Centrilift sales engineer for details.

The complexity associated with designingVariable Speed Electrical Submersible PumpingSystems, along with the introduction of numerousmultiphase flow correlations, has made them theideal candidate for microcomputer applications.Each application is unique and detailedinformation on well completion, productionhistory and reservoir conditions is extremelyimportant during the initial design phase.

AutographPCTM is a computer software programthat runs on IBM compatible PC's designed togreatly simplify the ESP sizing process. Theprogram approaches the sizing by first creatinga pictorial representation of the well performancebased on specific hydraulic requirements. Thisis accomplished on the Well Information Screen(see figure 3), which is the input document forall the critical well data. 3Standing, M.B. "Volumetric and Phase Behavior of Oil

Field Hydrocarbon Systems", Reinhold Publishing Corp.,New York (1952).

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.

31

THE 9 STEP

Figure 4 - Pump Sizing Screen

Figure 3 - Well Information Screen