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Copyright 2003, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the SPE Production and Operations Symposiumheld in Oklahoma City, Oklahoma, U.S.A., 22 –25 March 2003.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers is

prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836 U.S.A., fax 01-972-952-9435.

AbstractThe West Hewitt Penn Sand Unit, a waterflood in southern

Oklahoma, has utilized progressing cavity pumps (PCP) sinceSeptember 1988. Producing zone depth is approximately

2100’ with PCP producing rates of 200 to 1100 BPD per well.

Through an evolution of PCP configurations and designs a 4+

year pump life can be expected, with only minor repairs.Adjustable rates at the surface, low capital costs, low repair

costs and high electrical efficiency are the attractive

characteristics of this artificial lift method. Improvedidentification of elastomer compatibility with reservoir fluids /conditions; improved prediction of stator-rotor fit over time;

and reduction of top rod / drivehead breaks are the remaining

challenges to improving PCP performance.

IntroductionProgressing cavity pumps have been around since Rene

Moineau in France first described a new simplified pump/

compressor in 1930, which consists of only one moving part1.

These non-pulsating pumps are very efficient (mechanical and

volumetric) and can pump viscous, solid laden and gaseous

/multiphase fluids. Their use in the oilfield first began in the

Canada and California heavy oil fields. Their use has evolvedfor lighter crude oils, deeper and higher temperature

applications, high water cut oil wells, water wells and

dewatering coal bed methane wells.

PCP theory and design considerations have been discussed

sufficiently in the literature1,3-13

and will not be reviewed

here. However, as mention in most all of the referenced papers, the elastomer is the ‘Achilles’ heel’ of the PCP system

(11). It provides the important function of providing the

moving seal lines of the pump. Newer PCPs appeared wellsuited for the moderate rates, shallow depth / pressure, high

water-oil ratios and lighter oil composition found in southern

Oklahoma waterfloods. PCPs are also highly favorable due totheir adjustable rates at the surface using sheaves/ belts,

hydraulics or electrical variable frequency controllers (VFCs);

surface electrical motors instead of downhole motors for

cheaper initial installation, low repair and replacement costs;

high mechanical and volumetric efficiency for lower operatingcosts; lower initial and repair cost of the downhole equipment

and installation; field personnel familiarity to most equipment

elements (rods, gears, motors…); and parts / repair

availability.

Producing Property The West Hewitt Pennsylvanian Unit is located in sections17,18,19,20 of Township 4 south and Range 2 West in Carter

County, Oklahoma, USA. See Figure 1. The 2100’ depth field

was discovered in 1939 with most of the 58 wells now in the

unit (105 wells in the field) drilled within 6 months2. Well

spacing is now 2.5 acres per well. Rotary rigs were utilized for

the drilling to the top of the producing zone; with cable tool

rigs mostly used for completions- the original underbalanced

completion method! In all wells, 7” casing was set to the topor through the zones of interest. Nitroglycerin blasts were

commonly used to stimulate production in the open-hole

sections with slotted 5.5” liners then installed. Initial

production rates up to 2500 BOPD per well (Herrell “A” #8)were obtained. However, by 1968, production had declined to

marginal levels and a waterflood was initiated to increase

production. Currently the field produces an average of 4BOPD per well (range of 1-8 BOPD per well) and 320 BWPD

(range of 50-1200 BWPD per well) with a 77 field average

Water-Oil Ratio (WOR). The field has produced over 2.6

million barrels of oil and 97 million barrels of water since thewaterflood began.

The producing Pennsylvanian sandstone is a steeply dipping(1000-1200’ per mile) fairly symmetrical anticline structure

with a northwest to southeast axis. It is bound by the HealdtonField to the west and the Hewitt Field to the east. The zone

contains over 200’ of net pay in most wells, mostly in 2 zones(Upper and Lower) of the 3rd Hewitt Sand at a 2100-2300’

depth. Oil gravity is 33.5o API with only a mild paraffin

tendency and a sulphur content of 0.65%. Produced water

composition averages 130,000 ppm TDS, 6.0 pH, 30,000-ppmtotal hardness. The water has some carbonate and iron sulfide

scaling tendencies. The field water cut is about 98%.

Reservoir pressure is about 50% of its original pressure or

SPE 80919

Fourteen Years of Progressing Cavity Pumps in a Southern Oklahoma WaterfloodKenneth D. Oglesby, SPE, Oak Resources, Inc.; Jose Luis Arellano, SPE, Petroleum Experts Limited; and Gary Scheer,SPE, Advanced Rotary Pump Systems, Inc.

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2 SPE 80919

slightly less than 500 psi. Well Productivity is about 1.3

barrel / day / psi.

The waterflood began using the existing conventional beam

pumping units with some replacements by larger beam units as

production rates increased. By early the 1970’s some beam

units were replaced with downhole electrical submersible

pumps (ESP) capable of rates exceeding 2000 BPD. ESPs usein this field was exceptionally successful in obtaining long run

years, but were inflexible on rate and expensive to operate. By1988, the increasing field WOR, sharp drop in the oil prices in

1986, high electrical rates, and high ESP capital and repair

costs forced a study into other artificial lift methods. PCP’s

were identified as a potentially good replacement lift methoddue to their targeted producing rates (between the larger beam

units in the field and the smaller ESPs) of 400+ BPD with the

flexibility and cost saving characteristics desired.

In September of 1988, Oak Resources began to install PCPs inseveral wells within the field. Well selection requirements

were: production rates- 400 to 1200 BPD; well productivityhigh enough to allow the dynamic fluid level over the pump to

be 200+’as a safety cushion to prevent the pump from

pumping “dry”; very highly efficient surface motor; and

adjustable rates. No other initial design requirements were

made. Produced fluids and field chemicals were sampled andtested for elastomer compatibility and pump design. To date,

ten (10) wells have utilized these pumps with increased

reliability and efficiency.

Comparison of Artificial Lift Methods In 1996 an in-depth comparative study of artificial lift

methods in this field was conducted as part of a MastersDegree Program at The University of Tulsa. A BMI power

profiler was used to conduct these tests and obtain the powerconsumptions from seven (7) wells in this field. The fluid

levels and flow rates of the oil and water were obtained from

field equipment. Data at multiple rpms/rates were obtained onthe PCPs. A mathematical computer model was proposed to

predict the performance of the PCPs, beam units and ESPs

based on this and other data. The data obtained in this study isgiven in Table1.

From this field data, kilowatts and mechanical / volumetricefficiencies were calculated for each installation. See Table 2.

It was seen that PCPs were 43% more volumetric efficient

than ESPs and 169% more than beam units. PCPs were

calculated to be 11% less mechanically efficient than ESPsand 16% more efficient than beam units. On a power per

barrel (kw/bbl) basis, PCPs were 35% more efficient than

ESPs and 5% more than beam units. These higher efficiencies

for PCPs were in the same direction as an earlier study by

Saveth (6), which showed almost a 50% efficiencyimprovement with PCPs over ESP and beam units. These

higher ratings translate directly into daily electrical savings.

The original OAK study in 1988 estimated PCP installation

costs roughly 25% less than ESPs or conventional beam units

for the same desired midrange (400-800 BPD) production rate.

These savings were confirmed by Saveth (6). While it was

found that the average annual intervention costs are higher for

PCPs, their flexibility and lower electrical costs outweigh this

factor in this field.

PCP Design and Configuration The basic elements of a PCP application in the West Hewitt

Penn Sand Unit are: rotor, stator, rods, tubing, drivehead/

backspin brake, sheaves/ belts, electrical motor and electricalcontrol box. See Figure 2. Each component will be discussed

separately:

Single chrome coated rotors were initially used with later

double chrome coatings and stainless steel rotors preferred

now. Low pH is a problem for chrome coatings, however the5.9-6.0 surface pH did not appear to be a major problem to the

chrome, although some pitting was occasionally seen. Rotor

breakage was minor and was normally a symptom of an

elastomer swelling problem. Undersized rotors were used asswelling of the elastomer was identified. On worn rotors,

wear (rusted steel showing through the chrome) was seen on

the crests at the seal line. Some earlier worn rotors were re-chromed, but this is not recommended due to the loss of crestdimension and resultant lower efficiency.

Stator can be identified by their configuration (lobe count anddesign), stages (for depth) and elastomer. Stators with

1:2 stator lobe configurations and low acrylnitrile (Buna-N)

elastomer elements were originally used. Lab compatibility

tests and the manufacturer’s experience showed no concernfor swelling using the base Buna-N elastomer for this

application. However, swelling did occur over several months

and higher acyrlnitrile elastomers were needed. However, this

change alone did not solve the problem, since ‘high nitrile’ is

not standard over the industry and other manufacturer “highnitrile” pumps still excessively swelled. Therefore, elastomer

composition, in addition to acyrlnitrile, may also be an

important criterion. Only one manufacturer was found to havethe needed elastomer composition of the 4 tried.

Stators diameters began with a 4.5” OD but quickly went to a

3.5” OD high volume design which is the current preferreddesign. All but one PCP had the 1:2 lobe design- the preferred

design currently. A multilobe (5:4) ‘high’ nitrile PCP was

recently tried in well WW2, but vibration, rotor breaking, and

stator back off caused an early termination. Such higher lobecount PCPs are commonly used in drilling wells and are called

downhole ‘mud’ motors. It is possible that the ‘high ‘ nitrile or

the elastomer composition was not suitable for this application(seen before) and it was not a multilobe problem. No further

data is available on this PCP lobe style in this field.

A stop pin is in a sub below the stator and is used to space the

rotor within the stator. This spacing is dependent of the pumprotor-stator fit, depth and rod size. If the rotor is spaced too

low in the pump, the rods will stretch and the rotor will ride on

the pin, causing high vibration. This was seen early in the use

of these pumps, but was quickly remedied.

New rods were used with no rod centralizers in all original

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SPE 80919 3

installations. Most all applications used a 7/8” rod string with

one 1” rod just below the drivehead and one 1” rod

immediately above the rotor. For smaller pumps, ¾” rodstrings were successfully used. No unusual rod wear was seen.

Later, tested rods were used with no adverse affect. Rod

breakage was a continuious, but relatively low cost, problem

in that it normally was the rod / crossover just below the

drivehead that would (body) break. Pony rods were putfurther into the string and on bottom. Pony rods would be

alternated when pulled to move rod-tubing wear points. The possible cause and remedy of these rod / crossover breaks will

be discussed later.

Used tested J55 or N80 tubing was utilized in all PCPapplications with no anchor. Anchors were later installed on 2

wells with PCPs styles/designs that proved to have high

vibration problems- the smaller, high rpm pump designs and

the multilobe pump designs. No other excessive tubing wear

or holes were found to be a problem over the full 14-yearexperience. Weak tubing threads caused problems in 2 wells

with high swelling/ vibration pumps. Makeup torque was keptthe same as with other lift methods with few back off

problems. All installations had a larger OD bottom tubing pup

joint (same size as the stator) above the stator. Some joints

were ‘Baker-Locked’ to the stator of specific pump types after

particular problems due to torque or vibration.

Two drivehead sizes, both with solid straight shafts and grease

inserts, were primarily utilized-

12,300 lbs thrust load / 450 ft-lbs brake torque limit28,000 lbs thrust load / 450 ft-lbs brake torque limit.

Most driveheads were purchased new, but rebuilt / exchanged

heads were utilized after the original purchase. This reuse mayconribute to some of the recent drive problems. A move has

been underway to convert to the newer oil bath and hollow roddesigns. Stuffing box / packing leaks did cause some

environmental problems with sudden ambient temperature

changes contributing to the problem. Teflon packing helpedreduce this problem, but not completely. Drain tubes from the

drivehead cavity around the stuffing box back into the tubing-

casing annulus helped keep minor leaks controlled.

Pumper training is critical to maintain PCP drivehead grease

lubrication. Several drivehead failures were seen in early2002 due to poor lubrication. This may not be as critical in oil

bath installations.

Backspin brakes (BSB) are installed on the drivehead tocontrol the backspin of the rods and sheaves during shutdown.There is danger in the stored energy in the rods (torsion /

spring) and fluid head in the tubing which can cause the rods,

drivehead shaft and connected equipment to reverse spin at

uncontrollable, damaging and unsafe speeds when released.The excessive speed of this reactive backspin can exceed the

strength of the commonly used cast iron sheaves, causing

disintegration and danger to any person nearby. Backspin brakes are installed in all current drivehead models to slow

(not stop) the backspin and prevent this excessive and

dangerous reaction. In addition, if the pump is fully stuck in

the stator and the fluid head in the tubing does not equalize

before the rig crew removes the drivehead, a dangerous

backspin can occur with no brake and with only the elevators

attached.

Sheaves and belts were used to connect the electric motor to

the drivehead shaft. This simple method was found effective

to adjust pump rpm to maximize production rate while

maintaining a safe 200+’ fluid head over the pump suctiondepth. Power bands with less tension are now used on most

applications. No VFCs were used in the field due to the highexpense. Pump off controller were not used since the

dynamic fluid level over the pump suction was kept

sufficiently high.

Only premium efficiency, low slip (”B”), 1200 rpm, TEFC

electrical motor s were used. Mostly 20 hp motors on the

standard applications, but 10hp on the smaller pumps and

rates. Even the larger pumps (1200 BPD) used only 20 Hp

motors. Only the existing electrical control boxes were used.

Operating Considerations Severe and fatal stator elastomer swelling that can take up to 1

year to occur with symptoms of high torque, cause rod parts

and pump seizing. Reducing rotor size did not always correct

the problem.

Separate from the swelling issue, all pumps designs had rod,

pony rod, crossover connection or shaft break problems,

mostly right below the drivehead. It was originally felt that

this was due to poor drive shaft to well rod alignment. Anymis-alignment of the drivehead shaft with the rods would

cause stress on the top rod, connection and/or shaft with every

revolution. The accumulation of this stress/ flexing is knownto cause fatigue and failure. To solve this perceived problem,

driveheads were flanged instead of screwed onto the tubing;the drive shaft and drivehead body were then aligned to

vertical with a bubble balance; and the drivehead-motorassembly was supported by cables and steel frames. While

these steps reduced the breakage problem, it still exists at a

reduced level today.

Another potential cause of this problem is rotor movement

(horizontal and vertical) within the stator during pumping

causing severe (fixed end point) vibration in the rod string tothe surface fixed end. In pumping heavy oils, this vibration

may be dampened by the more viscous fluid. Also, if the rotor

is not spaced out in the stator properly, the rotor’s bottom tip

can ride on the stop pin, causing severe vibration. This lastcause was not thought to be a factor problem durrently. A

possible solution may be a short rod made of a semi-flexible,

high strength material, such as a titanium or composite

material, installed immediately below the drivehead.

Occasionally, ‘swelling’ occurred possibly due to a solid, such

as an iron sulfide or carbonate scale, becoming impacted into

the elastomer at the suction end. This was rare, butdemonstrated in a stuck pump when an undersized rotor was

cut off 2’ and successfully reused in that same stator.

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4 SPE 80919

Wells in which ESPs had very long runs there was a problem

due to large solids buildup in the casing. These wells required

bit cleanouts, circulation and acid before a PCP could be run.PCPs do not pump non-liquified solids very well.

Some pumps had pressure/rate surging problems on startup

due to too tight a rotor fit (due to swelling) or solids build-up

in the pump. Circulating a surfactant (soap) in the well oftenreduced or eliminated this problem.

As with most equipment, PCPs have trade offs between- low

cost, high efficiency or long life. Rarely can all three be

obtained. Larger pump sizing for a lower rpm and a longer

life costs more upfront. A smaller pump with a higher rpm, but shorter life, allows for higher pump efficiency at a lower

cost. Delpassand (12) recommends that since “wear is

assumed proportional to speed squared” it is better to have a

larger pump for lower speed, with more stages for extended

wear. This design may also allow a looser rotor-stator fit forfurther long life. Also note that fewer interventions means

rod-tubing wear points remain the same for longer periodsalthough at a lower rpm. All versions have been used in the

field with no preference formed.

Normal monitoring of the PCPs was done by obtaining

individual well tests using a portable tester; dynamic fluidlevels using a sonic fluid level machine (digital and

analog/strip); volts and amps per leg using a standard volt

meter; and a surface pressure gauge. This data was evaluated

oby itself and used to calculate 3 parameters for monitoringthe wells:

FAP (fluid over pump)= pump depth–dynamic fluid depth;Q/A =total flow rate / average amp; and

VolEff (volumetric efficiency)=(actual rate/rpm) / (designrate / rpm)

These calculated parameters were different for every well andevery installation, but once a successful installation was

obtained these parameters were used to monitor performance.

FAP was monitored to ensure that the pump would not operatewith insufficient fluid and to monitor pump rate. Q/A was

used to indirectly monitor electrical efficiency and torque.

VolEff compared the actual produced volume to the expectedtheoretical volume at that rpm. A sudden change in any

parameter was cause for concern and investigation.

PCP Statistical InformationThe life expectancy of the stator and drivehead were evaluated

using the history available. It should be strongly noted that

the rotor life, drivehead life and the number of interventions,

much less the full installation life, is strongly dependent on thePCP type, ELASTOMER suitability for the application and

the stator-rotor fit.

Stator life was determined by counting the service days

between run-in and pull-out. Rotor life was not determined in

that rotors were harder to keep track and was too dependent on

the stator/elastomer fit. Drivehead life was counted as number

of service days between any repair or exchange. An

intervention was determined to be any event that affected to

well performance, other than sheave changes.

An Event Code was devised to roughly represent the

production loss and overall cost for any level of work required

during the life of a PCP installation. These weighted Event

Codes are summarized with examples in Table 3 below.

Table 3

Event Code Description & examples

0 initial installation of rotor and stator

1 minor rig or sheave change

2 rod part3 replace rotor

4 exchange or repair drivehead

5 replace rod string or tubing leak. Any fishing

6 replace stator

7 replace tubing string8 replace rotor and stator

9 pull all equipment- end PCP pumping

A summation of the Event Codes (i.e. weighted interventions)

for a given stator installation, between the original stator

installation and final pulling, reflects the amount of well

problem during the run. This total weighted intervention costcan be ‘normalized’ by dividing by the number of service days

in the run to allow for a comparative analysis of the success of

each installation. Thus-

‘normalized’ weighted intervention= sum of all run weighted

Event Codes *1000/ # run service days

Stator run life data is shown plotted in Figure 3, stator service

days in the run versus the year of installation. Note that wellswith very recent installations were adjusted with an additional

150 days of life. From this data it was determined that theaverage life of a stator is 3.84 years and has not changed much

over time. However, two separate trends are seen in this data,

a relatively flat / lower trend and an increasing/ higher trend.

This upper trend is reaching 7 years per stator run while thelower trend is holding at 1.5 years. The significant factors

affecting each trend have not yet been determined. Some of

the variation and failures seen in this data were the result ofexperimenting with various pumps styles and types. This

selection process has matured and fewer failures are now

expected.

Average calculated weighted interventions (betweeninstallation and pulling of the stator) have decreased from 20

to about 10 currently. Stuck pumps were the cause of the high

count early in the process. Drivehead and some tubing

problems are the cause of the higher current interventions.With the change to the selected elastomer and newer

drivehead types, these problems will further diminish.

Average service life (between repairs or exchanges) of a

drivehead is over 2.5 years, with a maximum of over 9 years.

The use of rebuilt and not new driveheads saved significant

money, but contributed to this lower lifespan. The newer and

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SPE 80919 5

higher capacity driveheads now converting to will help

increase this life expectancy.

PCP Wish ListBased on the history and the current status of the PCP

installations in this field, the following future improvements

would extend PCP installations life, use and reduce

interventions:1. Standard swell tests are inadequate. Better and quantative

elastomer composition and compatibility testing attemperature, pressure and fluids (oil and water) of the

application is needed. Manufacturers should stand behind

the elastomer recommendations from these tests;

2. Better drivehead to well/rod string alignment method isneeded- or prove that alignment is not a serious problem;

3. Design a pony rod or crossover for immediately below the

drivehead made of a semi-flexible, high strength material,

such as titanium or a composite;

4. 100% testing by the PCP manufacturer prior to shippingwith all test results provided to the customer. Where

possible, the testing of the matched rotor and stator should be done at operating pressure and temperature;

5. Driveheads that are easily installed and removed, easily

aligned and with improved shaft seals to prevent

environmental problems;

6. Emergency fluid catch basin installed in/below thedrivehead seal with a drain into the annulus for leaks.

Conclusions1. PCPs are efficient and low cost alternatives for artificial

lift in southern Oklahoma waterflood wells. Electrical

power savings are 5% below beam-rod units and 35%

below ESPs for comparable production rates. Initial PCPinstallation cost savings are about 25% below beam-rod

units or ESPs for the same production rates.2. Elastomer swelling is a critical concern and must be fully

studied in the lab and field implementation. Elastomer

swell and rotor fit must be customized for each area.Swelling can take many months, showing symptoms of

high startup torques, rod breaks and pump siezures.

3. Rod or drivehead shaft failures are unresolved problems.This is not a major cost problem in this field, but in other

areas it may represent a serious limitation.

4. Applicability of PCPs in other fields should be carefullytested, since elastomer suitablilty and stator-rotor fit can

vary from field to field and well to well.

AcknowledgementsSpecial thanks must go to field personnel Mark Wilson andDavid Howerton for their attention, recommendations and

patience in the evolution of these pumps to make them

successful. Also thanks to Robbins and Myers for standing

behind their product on several occasions and for having theonly low cost elastomer composition that proved effective.

References1. Arellano, Jose Luis; “Field Comparison of Efficiency of

Progressing Cavity Pumps, Beam Units and Electrical

Submersible Pumps”, Masters Thesis in Petroleum

Engineering, The University of Tulsa, 1997.

2. Neustadt Jr., Walter; “West Hewitt Field, Carter County,

Oklahoma”, V1 of Ardmore Geological Society,Petroleum geology of southern Oklahoma symposium,

p162-173, February 1956

3. Lea, Jim and Anderson, DG, “Optimization of

Progressive Cavity Pump System in the Development ofthe Clearwater Heavy Oil Reservoir”, Amoco Canada and

Corod Manufacturing Ltd, 1987.

4. Saveth, Kenneth,” A Comparative Analysis of Efficiency

and Horsepower Between Progressive Cavity Pumps and

Plunger Pumps”, SPE 16194, March 1987, SPEProduction Operations Symposium, Oklahoma City, OK.

5. Saveth, Kenneth, “The Progressing Cavity Pump:

Principles and Capabilities”, SPE 18873, March 1989,SPE Production Operations Symposium, Oklahoma City,

OK.

6. Saveth, Kenneth, “ Field Study of Efficiencies Between

Progressing Cavity Pump, Reciprocating and Electrical

Submersible Pumps”, SPE 25448, March 1993, SPE

Production Operations Symposium, Oklahoma City, OK.

7. Clegg, JD; Bucaram, SM and Hein, NW,”

Recommendations and Comparisons for Selecting

Artificial-Lift Methods”, December 1993, Journal ofPetroleum Technology.

8. Samuel, GR and Saveth, Kenneth, “Progressing CavityPump (PCP): New Performance Equations for Optimal

Design”, SPE# 39786, March 1996, SPE Permian BasinOil and Gas Recovery Conference.

9. Samuel, GR and Miska, Stefan, “Analytical Study of the

Performance of Positive Displacement Motor (PDM):

Modeling for Incompressible Fluid”, SPE 39026, 1997,

Latin American Petroleum Conference, Brazil.

10. Olmos, DE; Ernest, HA; Villasante, JA; Johnson, DH;

Ameglio, AF; and Del Pozo, L; “Hollow Rods:Development of a New Technology for PCP”, SPE

69558, March 2001, SPE Latin American and Caribbean

Petroleum Engineering Conference, Buenos Aires,

Argentina.

11. Mills, RAR and Gaymard, R, ”New Applications for

Wellbore Progressing Cavity Pumps”, SPE 35541, March

1996, International Petroleum Conference & Exhibition

of Mexico.

12. Delpassand, MS, “Progressing Cavity (PC) Pump Design

Optimization for Abrasive Applications”, SPE 37455,March 1997, SPE Production Operations Symposium,

Oklahoma City, OK.

13. Dall’Acqua, Dan; Alhanati, Francisco; Matthews,

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6 SPE 80919

Cam;”PC Pumping System Design Considerations for

Light Oil Applications”, November 1997, SPE-MCS

Progressing Cavity Pump Workshop, Tulsa, OK.

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SPE 80919 7

Table 1 – PCP Well Information obtained during the 1996 Field Tests (1)

Table 2 - Calculated Well Information from the 1996 Field Test (1)

W ells and System Type

W ell Inform ation Units 1A 3A 5A 6A E G I

PCP PCP PCP PCP ESP Beam Beam

Pum p depth feet 2014 2022 2111 2108 2082 2064 2150Fluid D epth feet 1082 1574 1782 1603 1683 1504 1255Liquid Rate bbl / day 1042 288 587 510 1080 257 460

W ellhead Pressure psig 30 30 35 30 42 40 40Casing Pressure psig 0 0 0 0 0 0 0

Avg Am perage am ps 12.6 6 9.8 7.9 29.4 18.7 17.1 Volts volts 800 800 800 800 800 800 800Kilo-w att-hour 5.4 3.9 3.5 2.6 12.26 2.99 1.89Pow er Factor 0.92 0.9 0.99 0.8 0.87 0.79 0.8

Tubing Size inch 2.875 2.875 2.875 2.875 2.875 2.875 2.875

M echanical Efficiency % 88.0 75.0 91.0 85.0 95.1 73.0 73.0

Volum etric Efficiency % 54.8 48.0 59.0 75.0 41.4 18.0 26.0

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SPE 80919 9

Wes t Hew itt Pen n Sa nd Uni t

S tator S erv ice L i fe

0

50 0

1000

1500

2000

2500

3000

8/11 /87 5 /7 /9 0 1 /31 /9 3 1 0/28 /95 7 /2 4 /9 8 4 /1 9 /0 1 1 /1 4 /04

Year o f In sta lla tio n

S e r v i c e D a y s

overa ll trend

improvem ent trend

Figure 3- Stator Service Life versus Installation Date

West Hewitt Penn Sand Unit

PCP Interventions

0

10

20

30

40

50

60

70

8/11/87 5/7/90 1/31/93 10/28/95 7/24/98 4/19/01 1/14/04

Year of Installation

W e i g h t e d N u m b e r o f

I n t e r v e n t i o n s

overall trend

Figure 4-Weighted Interventions per Stator Run by Installation Date

West Hewitt Penn Sand Unit

Drivehead Service Life

0

1000

2000

3000

4000

5000

08/11/87 05/07/90 01/31/93 10/28/95 07/24/98 04/19/01 01/14/04

Year of Installation

S e r v i c e D a y s

Figure 5- Drivehead Service Life by Installation Date

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