Investigation of ESP Performance

This paper was prepared for presentation at the 2011 Society of Petroleum Engineers - Gulf Coast Section Electric Submersible Pump Workshop held in The Woodlands, Texas April 25-29 2011.

This paper was selected for presentation by the ESP Workshop Panels (Rotating and Permanent) following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the ESP Workshop Panels and are subject to correction by the author(s). The material, as pre-sented, does not necessarily reflect any position of the ESP Workshop or its panel mem-bers. The author(s) retain copyright to this paper and have given permission to the ESP Workshop to publish it in proceedings (electronic and hardcopy). Any other electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the author(s) is prohibited.

Abstract The paper reports on developmental research on the

effects of viscosity and two phases, liquid gas flow on Electrical Submersible Pumping (ESP) which are multis-tage centrifugal pumps for high rate and high boost appli-cations.

Multiphase viscous performance of a full-scale elec-trical submersible pumping (ESP) system at Shells Gas-mer facility has been studied experimentally. The objec-tive of this study is to predict the operational conditions that cause degradation and gas lock for light and high viscosity fluids to support ESP operation in Shell Interna-tional E&P Inc (Shell) Deepwater major Projects BC-10 and Perdido. The ESP systems studied used a 1025 series tandem WJE 1000 mixed flow type pump. The test facili-ty work was performed using pumps with 32 stages mov-ing fluids with viscosity from 2 to 450 cP at various speed, intake pressure and gas void fractions (GVF, aka gas volume fractions). ). Additional tests with 4 stage WJE1200 were conducted at the Centrilift facility in Cla-remore using single phase viscous fluid.

The ESP system is an important artificial lift method commonly used for medium to high flow rate wells. Mul-tiphase flow and viscous fluids cause problems in pump applications. Free gas inside an ESP causes many opera-tional problems. Under two-phase flow conditions, loss of pump performance or gas lock condition can be observed. Under viscous fluids, the pump performance degrades as well.

No work has been carried out on ESP performance in viscous fluid for multiphase flow. The testing at Shells Gasmer facility revealed that the ESP system is robust and performance tracked theoretical predictions over a wide range of flow rates and light viscosity oils

The main technical contributions of this study are the data collection and analysis of pump head degradation under two important variables, high viscosity and two-phase flow inside the ESP.

Background Shell is the operator in two major projects where

there has been significant advancements in deepwater subsea boosting technology, operations, and surveillance: Perdido in the Gulf of Mexico (on stream since March 2010) and BC-10 offshore Brazil (on stream since July 2009). These novel projects continue the long tradition of Shells leadership in the challenging deepwater environ-ment by development and application of a novel seafloor boosting system [1].

Electrical submersible pumps (ESP) were selected as the subsea boosting system used by both the Perdido and BC-10 assets for increased ultimate recovery and higher production rates. The subsea boosting system is located in a seafloor caisson. the caissons inside are used to collect production fluids from the manifolded subsea wells. Ex-tensive testing and qualification of the subsea boosting system was undertaken prior to final configuration selec-tion including construction of the worlds only 1500-hp ESP test facility capable of controlling multi-phase fluid viscosities and temperatures in Shell Gasmer Prototype test facility in Houston [1].

Pump performance degrades due to friction losses re-sulting from the fluid viscosity. As the viscosity increases, the maximum flow capacity of the pump is reduced and the required brake horsepower (BHP) increases. Further-more, multiphase flow causes several problems in pump application in gassy oil fields. Most critical behavior un-der two-phase flow is pump gas locking which is related to a potential unstable conditions where ESP system can be damaged and/or even cause a system failure.

To mitigate the risks further, Shell performed full-scale tests of caisson ESP systems to validate the perfor-mance of the ESP components over the range of fluids viscosity, GVF and flow rates expected in the field. These tests were conducted at a land-based facility rather than offshore to reduce costs and minimize delays due to logis-tics. A full-scale ESP system and test loop were con-structed in 2006 at Shells Gasmer Facility to test subsea boosting technologies.

A comprehensive test plan was implemented and per-formance tests had been carried out for these systems. This paper considers configuration G and H testing and analysis only. Test results of the configuration A to C were discussed by Gilyard [1].

Details of the ESP equipment used for the testing, is given in table 1. The ESP system included a 1025 series tandem, 32 stage, WJE 1000 pump. This ESP system used 875 series tandem seals, a single 2000 hp variable speed drive (VSD) and a 1500 tandem hp motor. A

Large-Scale Experimental Investigation of ESP Performance With High Viscosity Fluids and Gas Lissett Barrios, Charles Deuel, David Knowles, Sandeep Patni and Stuart Scott, Shell E&P; Ketan Sheth, SPE, Baker Hughes

2 Lissett Barrios, Charles Deuel, David Knowles, Sandeep Patni, Stuart Scott and Ketan Sheth

shroud was used to ensure that fluids are directed past the motor to ensure adequate cooling of the motor.

ESP was tested for various parameters including, inlet pressure, viscosity, speed, flow rate, % GVF and its effect on the ESP performance and reliability. Testing provided guidelines for the field operations. Various test parameter envelope is given in table 2. Three different oils were used for viscosities varying from 1 to 450 cP. For safety considerations the injected gas was restricted to nitrogen.

The primary test objectives were to: Validate hydraulic performance maps of the caisson

ESP systems Establish ESP system performance curves (flow rate,

head, speed curves) over a wide range of GVFs and viscosities

Determine ESP performance at high GVF and predict gas locking and/or instable behavior

System Schematic The test facility consisted of the caisson ESP system and the supporting surface facilities. The caisson ESP system consisted of: A 300-foot deep cased hole, 45-inch ID A 300-foot caisson vessel, 36-inch OD suspended in

the cased hole One of a number of configurations of ESP suspended

inside the caisson from its top tubing hanger Power and instrument cables running to and from the

ESP, including medium-voltage, subsea electrical power connectors

Instruments connected to the ESP and to the produc-tion tubing to measure pressure, temperature, flow, level and vibration at various locations within the caisson

A control system for operating the ESP through its variable-frequency drive

Variable-frequency drives to power the ESP(s)

Test loop schematic is shown in Fig 1. It uses pneu-matic and motorized flow control, Coriolis flow metering, and variable speed drive control. The system is charged with either a low, medium or high viscosity oil depending on the test requirements. Fluid viscosity delivered to the caisson from the supply vessel ranged from 2-450 cP and was controlled by a heat exchanged located downstream of the supply vessel.

Coriolis flow meters ELITE series, with +/-0.05% mass and volume flow accuracy; +/-.35% gas flow accu-racy; +/-0.0002g/cc density accuracy were used to meas-ure incoming liquid to the caisson and multiphase fluid from the ESP discharge. Pressure and temperature trans-mitters used were located at the pump intake and dis-charge to measure pump total differential pressure. Horse power was calculated from motor KW and efficiency and RPM were measured from variable speed drive control unit.

Once a targeted single phase (liquid) flow rate, intake pressure, RPM, temperature etc. at the test pump is estab-

lished and stable for a period of time, gas is injected into the liquid near the intake of the pump at a specified flow rate. Numerous tests were performed varying pressures and temperatures, flow, rpm, and torque. Data was rec-orded using automated data collection system. The data was then analyzed and corrected for speed.

There is a difference between average data and instan-taneous data performance. Average data can be repeated as these are independent of the test system and is used for drawing trends and analysis. While instantaneous data includes flow loop effects and may not be repeatable and therefore, generally not used for the trending and analysis. However, some data in this analysis are instantaneous data for showing the awareness of possible trends.

Fig. 2 shows a photograph of the experimental facili-ty. This facility is a fully instrumented state-of-the-art flow loop, capable of testing the ESP multistage prototype performance. The experimental setup consists of two ma-jor sections: Well flow and receiving section and the sub-sea section..

Well Flow and Receiving Section. The fluid generation and receiving section simulates

well flow to the caisson and receives the processed fluids from the caisson. The inlet section to the caisson is in-strumented to monitor and control the fluids entering the caisson for both gas and liquid. Downstream of the cais-son is instrumented to simulate the backpressure the sub-sea system might encounter from a riser and measure the separation performance of the caisson.. Flow to the cais-son is controlled with a flow control valve and differential pressure is used to push the fluids to the caisson. The liquid is carried through an 8 inch pipe from the Supply vessel, reducing to a 4 inch Coriolis flow meter which provides the liquid flow rate measurements. At this point in the mixing station, gas may be blended to the oil flow from the N2 compressor. A 6 V-cone flow meter for high flow rate or a 2 turbine meter for lower flow rates is used to measure gas flow. A flow control valve is used to control the gas to be blended with the oil flow. After the liquid and the gas are mixed in the intake line, the two-phase mixture is delivered to the subsea section..

System Capacity. The facility is designed for testing of a wide variety of

test conditions and equipment configurations. These con-ditions are: Oil flowrates 10,000 30,000 B/D Oil viscosity - 1.0 900 cP Gas flowrates - 0.5 55 mmscf/D Operating pressure 500 1,000 psia Operating temperature - 70 150 F

Subsea Equipment Section - The subsea equipment section is used to mimic the

functionality of equipment that was to be installed at Per-dido and BC-10. The caisson set-up accommodates the ESP assembly in the vertical position. A variable speed drive is located close to the system to control the opera-

2011 ESP Workshop Large-Scale Experimental Investigation of ESP Performance With High Viscosity Fluids and Gas 3

tion of the motor which allows the rotation of the motor in any direction and at any speed.

Testing The main objective of this study is to evaluate the per-

formance of the pump under two-phase conditions and viscous fluids. Therefore, the working fluids selected were mineral oil for the liquid phase and nitrogen for the gas phase. The viscosity of the oil is shown in table 3.

To investigate the behavior of gas/oil mixture viscous flow inside the ESP, pump performance is determined as a function of liquid and gas flow rates, inlet pressure, out-let pressure, and physical properties of the fluid.

Test Results/Data Analysis Single Phase Viscous Flow.

WJE 1200 4 stage pump was tested in water at 3500 rpm (60 Hz) speed. Viscosity correction factors for the pump were developed by testing at two speed 2625 and 3500 rpm, up to 2500 cP, in the R&D viscous test loop of pump plant in Claremore, OK. The pump performance curves for the head and BHP at 2625 rpm, up to 2500 cP is shown in the Figs. 3 and 4. The ESP pumps were also tested in Gasmer test facility to verify the viscous pump performance. Pump overperformed at the very low viscos-ities on the head flow performance. This is due to higher reduction in leakage losses than the increase in viscous losses. Overall, viscous performance did match with the previous testing. As viscosity increases, the head flow performance deteriorates and BHP performance increases, resulting lower efficiency and reduced performance.

Two Phase Viscous Flow. Effect of Speed. In viscous applications, affinity laws for speed

changes to the pump performance are not accurate and hence cannot be directly applied. [2]. As speed increases, (a) The Reynolds number increases and the friction fac-tors move from laminar to transition to turbulent region, resulting in lower friction and smaller flow correction factors; (b) Mixing losses at the impeller and diffuser inlet and exit are often considered as little dependent on the Reynolds Number; (c) Disk friction losses grow with de-creasing Reynolds Number or increasing viscosity; and (d) mechanical losses are essentially independent from the viscosity of the fluid pumped; (e) head increases with the square of the speed; (f) friction losses increases by the power of 2.5, and not cubic ration of the speed. Because of the above reasons, at constant viscosity, BHP does not increase by cubic ration of the speed. This fact is also supported by the increase in the efficiency of the pump with the increase in the operating speed at constant vis-cosity [3, 4].

Effect of GVF. Addition of gas has considerable effect on the pump

performance, depending upon the viscosity of the fluid. Fig 5 shows the two-phase pump performance at 50 Hz for light oil (2 to 6 cP) and 500 psia pump intake pressure

for instantaneous GVF up to 46%. The pump behaves as homogeneous flow up to 30% GVF, following the manu-facture curves, there was no effect of gas on the pump performance. Head flow pump performance was even better at higher flow rates than the water performance. The reason for this may be that at higher flow rates, high-er flow velocities carried the bubbles easily and further reduction of friction losses due to increase in the Rey-nolds number. At GVF higher than 30%, the pump started experiencing head degradation, and at GVF higher than 40%, severe head degradation was observed. Fig. 6 shows the effect of reduction of BHP in direct proportion to the density of the mixture due to addition of gas.

Fig. 7 shows the two-phase pump performance at 50 Hz for heavier oil at 180 cP and 500 psia pump intake pressure for GVF up to 55% . Similar results were ob-served, as GVF increases, pump experiences higher de-gradation. Up to 20-22% GVF, the pump behaves as ho-mogeneous flow following the manufacturer curves. At GVF higher than 22%, the pump started having head de-gradation. Severe head degradation was observed at GVF of 35%. Higher gas effect was observed at higher viscosi-ty. Head flow pump performance is affected by the lower percentage of GVF approximately 20%. Performance decreases as GVF increases, showing effect of two phase losses.

Knowing the oil and gas properties and laboratory testing of how they react with each other is very important to better understand the performance of the two phase flow behavior.

Effect of viscosity. Head flow performance at various GVFs are shown

in Fig. 8 for 500 psia intake pressure at 2 cP and 180 cP liquid viscosity and up to 44% GVF at the pump intake. Performance decreases as GVF increases, showing the impact of two phase losses as stated before. Comparison of all % GVF data for 1 cP and 180 cP, shows the effect of viscosity and reduction of performance as viscosity increases while in two-phase flow conditions. As viscosi-ty increases, the performance in two-phase deteriorates. Higher the GVF, higher the degradation as viscosity in-creases.

Based on the above comparisons, the effect of gas is more prominent than the effect of the viscosity. There are two scenarios: (A) Oil and gas are miscible. In this case, as pressure increases, part of the gas goes into oil and reduces the effective viscosity of the fluid and mixture. (B) Oil and gas creates emulsion. This situation will in-crease the effective viscosity of the mixture and perfor-mance will further deteriorate.

Effect of inlet pressure on two phase flow. Figs. 9 to 13 show the effect of pressure on the two

phase flow performance of the pump for light and heavy oil.

For light oil at 2 cP, the pump intake pressure has no effect on performance up to 18% GVF, and small effect for GVF up to 47% as shown in Figs. 9 and 10. The ef-fect of intake pressure is clearly visible for heavy oil as


shown in Figs. 11 and 12, since performance improves with the increase in the intake pressure. Dash lines representing higher intake pressure showing improved head flow performance across the operating range. Addi-tionally, deterioration of the performance at the lower flow rates decreases with the increase in the intake pres-sure. Higher intake pressure may also improve stable operation at the lower flow rates.

Effect of the intake pressure is more pronounced for heavy oil than the light oil fluid as well. Fig. 13 shows the effect of reduction of BHP in proportion to the intake pressure and the density of the mixture due to addition of gas.

Performance Summary Two phase flow guidelines developed for the

WJE1000 pump performance are concluded in Tables 4 and 5. Table 4 shows the minimum GVF handling capa-bilities at various intake pressures and viscosities. Mini-mum stable operation limits for various intake pressure and viscosities are given in Table 5. There are four major trends

1. Effect of pressure at three different viscosities, referring Table 4, (move horizontally using constant viscosity and minimum % GVF) at constant viscosity, minimum %GVF handling capacity of the pump increases as intake pressure increases. Also due to increase in viscosity, from 2 to 100 to 225 cP viscosities, gas handling ca-pabilities of the pump increases.

2. Effect of viscosities at three different intake pressure, referring Table 4, (move vertically using constant pressure and minimum GVF) at constant intake pressure, minimum GVF han-dling capacity of the pump increases with in-crease in viscosity. Also due to increase intake pressure from 290 to 550 to 900 psi, gas han-dling capabilities of the pump increases.

3. Maximum GVF at minimum flow rate, referring Table 5, (limit on the left hand side of the opera-tion) - (move horizontally, constant viscosity and increasing intake pressure) at constant viscosi-ty, stable operation of minimum flow limits and %GVF handling capabilities is further expanded to the lower flow rates (indicating higher stable operation at lower flow rates) as pressure in-creases.

4. Maximum GVF at minimum flow rate, referring Table 5, (limit on the left hand side of the opera-tion) - (move vertically, constant intake pressure and increasing viscosity) at constant intake pressure, stable operation of minimum flow lim-its and GVF handling capabilities is further ex-panded to the lower flow rates (indicating higher stable operation at lower flow rates) as viscosity increases.

Conclusions Pump manufacturer need to supply guidelines for

predicting performance of multistage pump in viscous and two phase flow conditions.

Stage by stage performance calculation of mul-tistage pump is recommended for viscous multi-phase flow applications. Viscosity and gas vo-lume should be calculated from first stage as a one stage pump, corrected by pressure and tem-perature rise, and then should be used for second stage and so on.

As intake pressure increases, gas behaves more as liquid than as a gas and chances of gas going back to solution increases, (a) lowering fluid vis-cosity if gas miscible in liquid or (b) if gas not miscible, then mixture viscosity will increase by creating emulsion.

An increase in GVF will decrease the BHP re-quirement of the pump due to reduction in the mixture density. However, it may increase the BHP requirement if it creates emulsion.

At constant viscosity, minimum % GVF han-dling capacity of the pump increases as intake pressure increases. Also due to increase in vis-cosity, from 2 to 100 to 225 cP viscosities, gas handling capabilities of the pump increases.

At constant intake pressure, minimum GVF han-dling capacity of the pump increases with in-crease in viscosity. Also due to increase in take pressure from 290 to 550 to 900 psi, gas han-dling capabilities of the pump increases

At constant viscosity, stable operation of mini-mum flow limits and % GVF handling capabili-ties is further expanded to the lower flow rates (indicating higher stable operation at lower flow rates) as pressure increases.

At constant intake pressure, stable operation of minimum flow limits and GVF handling capabil-ities is further expanded to the lower flow rates (indicating higher stable operation at lower flow rates) as viscosity increases.

Pumps should be run at the highest possible op-erating speed for viscous two phase flow condi-tions, considering thrust, NPSH, operating flow range, efficiency and erosion.

Nomenclature FAT = Factory acceptance test BEP = Best efficiency point BHP = Brake horsepower, hp GVF = Instantaneous gas void fraction (gas volume /

total fluid volume) cP = Centipoise, dynamic viscosity cSt = Centistokes, kinematic viscosity DP = Differential pressure across the pump

Acknowledgments The authors would like to acknowledge Shell and Baker Hughes for permission to publish this paper.


Centrilift is a trademark of Baker Hughes Incorpo-rated.

References 1. Gilyard, D., Brookbank, E. B., The Development of Subsea

Boosting Capabilities for Deepwater Perdido and BC-10 Assets, SPE 13493, Oct 2010

2. Sheth, K.K., Crossley, A., Viscosity Correction Factors, SPE Gulf Coast ESP Workshop, April-May 2009.

3. Stepanoff, A. J., Centrifugal and Axial Flow Pumps, 2nd Edition, John Wiley & Sons, pp 307-318, 1957

4. Ippen, A. T., The Influence of Viscosity on Centrifugal Pump Performance, Trans. A.S.M.E. , Vol. 68, No. 8, P 823, 1946

Figures

Table 1ESP Components in the Initial Configurations

Unit Motor Seal Chamber Section Pump Motor Jacket

Configuration G and H

1500 hp, 725 Series, 4160 Volt, 212 Amp, Tandem

Tandem 875 Series With High Load Bear-ing.

32 Stage WJE1000 Tandem Compression Pump with Integral Intake and Discharge Head

Yes, 100 foot 10.75-inch OD 40.5 lb/ft J-55 Casing

Table 2Configuration G and H Test Parameters

Minimum Maximum

Total Discharge Flow Rate ( oil + Gas) BPD 7000 11000 35000 40000 Intake Pressure (psi) 250 1000 % GVF 10 60 Viscosity (Cp) 2 350 Speed (Hz) 50 70 Pump hp 300 1225 Motor Loading (%) 45 % 110 % Amps 98 235 % Thrust Loading of seal bearing 150 %

Table 3Viscosity of Test Fluids

Viscosity - cP Temperature Light Medium Heavy

Degrees F Conosol C 201 Hygold L201 AC 2501 70 2.8 110.2 1756.9 104 1.9 35.2 432.0 150 1.2 11.9 102.9

Table 4Effect of Viscosity and Intake Pressure on GVF Handling Capabilities


Table 5Effect of Viscosity and Intake Pressure on Minimum Two Phase Flow Handling Capabilities

Oil SupplyTankOil SupplyPump

Mix Point

SubseaEquipment

CaissonSeparator& Pump

DensityMeter

N2Sup

ply SuctionScrubber

GasCompressor

Gas Cooler

Blowdown toAtmosphere

Oil Cooler

Warm-upValve

Choke

Relief

Spec Break5000 psi600#

Motor

ESP

FlowDevelopmentSpool

DischargePressure Control

Valve

Caisson Separator / ESP TestNon-Separated Flow Loop Diagram

M

M

FlowControlValve

FlowControlValve

Service LineRecycle Valve

PrimarySeparator

SupplyVessel

M

Liquid CarryoverSeparator

BalanceLine

M

LegendOilGasMulti-Phase

Gas Booster

RecirculationPump

ElectricHeater

ElectricHeater

Vent toAtmosphere

M

Vent Drum

Drain Line

Drain Line

Drain Line

Drain Line

M

LiquidCarry-overMeter

Clamp-on GVFMeterM

M M

Fig. 1Gasmer Test Facility.


Fig. 2Photograph Of Test Facility.

0

20

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DP

stag

e, ps

i/stg

Total flow, bpd

WJE1200 Head Flow 45 hz

2800 CP 2200 CP 1790 CP 1225 CP 995 CP 835 Cp 765 Cp670 cp 535 Cp 445 Cp 410 Cp 380 Cp 313 Cp 280 Cp210 Cp 155 cp 129 Cp 107 Cp 80 Cp 49 Cp Water

`

Fig. 3Viscous Head-Flow Pump Performance.


0

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BH

P, H

p/s

tg

Total flow, bpd

WJE1200 BHP Flow 45 hz

2800 CP 2200 CP 1790 CP 1225 CP 995 CP 835 Cp 765 Cp670 cp 535 Cp 445 Cp 410 Cp 380 Cp 313 Cp 280 Cp210 Cp 155 cp 129 Cp 107 Cp 80 Cp 49 Cp Water

`

Fig. 4Viscous BHP-Flow Pump Performance.

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Tota

l DP

, ps

i

Total Inlet flow (Oil+Gas), bpd

50 hz, Light Oil 2-6cp- 500 psia

FAT- 2-6 cp GVF= 10-13% GVF=14-18%GVF= 19-22% GVF=25-27% GVF= 30-32%GVF=34-37% GVF=40-44% GVF=45-46%

Fig. 532 Stage WJE1000 Pump Performance 500 Psia Intake Pressure At 2-6 Cp And 50 Hz.


400

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600

700

800

900

0 5000 10000 15000 20000 25000 30000 35000 40000 45000

BHP

(HP)

Total Inlet Flow (Oil + gas)

900 PSI, 50 Hz, 1 Cp

15% GVF 25% GVF 30% GVF 40% GVF 45% GVF FAT Oil

Fig. 6Comparison Of Viscous Two Phase BHP - Flow Pump Performance For 32 Stage WJE1000 Pump At 500 Psi Intake Pressure, 50 Hz and 1 cP Oil (Light Oil).

0

500

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1500

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2500

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Tota

l DP

, ps

i


50 HZ, Heavy Oil 180cp- 500 psia

FAT- 180cp GVF=22-24% GVF=25-27%GVF=36-38% GVF=39-43% GVF=50-55%

Fig. 7 32 Stage WJE1000 Pump Two Phase Performance 500 Psia Intake Pressure At 180 Cp And 50 Hz.


0

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800

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1200

1400

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Tota

l DP

, ps

i


50Hz, 500 psia

2 cp GVF=25-27% 2 cp GVF=34-37% 2 cp GVF=40-44%

180 cp GVF=25-27% 180 cp GVF=36-38% 180 cp GVF=39-43%

Fig. 8Comparison Of 32 Stage WJE1000 Pump Performance For 2 And 180 Cp At 500 Psia And 50 Hz.

Fig. 9Comparison Of 32 Stage WJE1000 Pump Performance At 250, 500 And 900 Psia, 2 To 6 Cp And 50 Hz.

0

500

1000

1500

2000

2500

0 10000 20000 30000 40000

Total D P , psi

Total Inlet flow (Oil + Gas), bpd

50 Hz, Light Oil 2 -6 cP Intake Pressure Comparison

FAT- 2-6 cP GVF=15 -18% 250 psiaGVF= 20 -22% 250 psia GVF=14 -18% 500 psiaGVF= 19 -22% 500 psia GVF=15 -18% 900 psiaGVF= 20 -24% 900 psia


0

500

1000

1500

2000

2500

0 10000 20000 30000 40000 50000

Tota

l DP

, ps

i


50 hz, Light Oil 2-6cp- Pressure Comparison

Manufacture Performance- Light Oil GVF=40-44% 500psiaGVF=45-46% 500 psia GVF=40-43% 900 psiaGVF=45-47% 900 psia

Fig. 10Comparison of 32 Stage WJE1000 Pump Performance At Higher GVF At 500 And 900 Psia, 2-6 Cp And 50 Hz.

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 5000 10000 15000 20000 25000 30000 35000 40000

Tota

l DP

, ps

i


250 & 900 psia, 50 Hz, 80 Cp

15% GVF 900 PSI 23% GVF 900 PSI15% GVF 250 psi 25% GVF 250 PSI40% GVF 900 PSI 45% GVF 900 PSI40 % GVF 250 PSI 45 % GVF 250 PSIFAT-80cp

Fig. 11Comparison of 32 Stage WJE1000 Pump Performance At 250 And 900 Psia, 80 Cp And 50 Hz.


0

500

1000

1500

2000

2500

0 10000 20000 30000 40000

Tota

l DP

, ps

i


50 Hz, Heavy Oil 180cp- Pressure Comparison

GVF=25-27% 250 psia GVF=40-42% 250 psiaGVF=25-27% 500 psia GVF=39-43% 500 psiaFAT- 180cp

Fig. 12Comparison of 32 Stage WJE1000 Pump Performance At 250 And 500 Bar, 180 Cp And 50 Hz.

400

450

500

550

600

650

700

750

800

0 10000 20000 30000 40000 50000

BH

P, H

p


250, 500 & 950 PSI, 50 Hz, 180 Cp

250 PSI 30% GVF 250 PSI 35% GVF 500 PSI 40% GVF 260 CP

900 PSI 30% GVF 900 PSI 35% GVF 900 PSI 40% GVF 265 CP

Fig. 13Comparison Of 32 Stage WJE1000 Pump In Viscous Two Phase BHP - Flow Pump Performance At Various Intake Pres-sures, 50 Hz And 180 Cp Oil (Heavy Oil).

Documents

Investigation of ESP Performance