day 3 - pcp system installation, monitoring, troubleshooting and diagnostic
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July 2010 G. Moricca 1
3 days course
Progressing Cavity Pump Systems
- day 3 -
PCP System Installation, Start-up,
Monitoring, Troubleshooting and
Diagnostic
G. Moricca
moricca.giuseppe@libero.it
July 2010 G. Moricca 2
Course agenda
Day 1
Overview of Artificial Lift Technology and
Introduction to PCP Systems
Day 2
PCP System Operating Principle, System
Components and Design Procedure
Days 3
PCP System Installation, Start-up, Monitoring
Troubleshooting, and Diagnostic
July 2010 G. Moricca 3
PCP System Installation, Start-up, Monitoring,
Troubleshooting and Diagnostic
PCP system Installation
PCP system Start-up
PCP system Monitoring
PCP system Special applications:— High-viscosity oil wells
— High-sand-cut wells
— Gassy wells
— Directional & Horizontal wells
— Hostile fluid conditions
— High-speed operations
— Elevate temperature applications
PCP system application: a case history
Troubleshooting and Diagnostic Techniques
Day 3 Course agenda
PCP System-
Installation
Start-up
Monitoring
and
Special applications
July 2010 4G. Moricca
Main sources:
‒ Processing Cavity Pumps. H. Cholet. Institut Français du Pétrol
‒ Processing Cavity Pumping Systems. Petroleum Engineering Handbook vol. IV
July 2010 G. Moricca 5
In this section, after some general considerations, a
detailed PCP System operations procedure will be
outlined, including:
— Installation
— Start-up and
— Monitoring
.
PCP Operation best practices
July 2010 6G. Moricca
PCP system
Installation
July 2010 7G. Moricca
General considerations
1. The pump shall be installed below the dynamic level,
because the pump requires a positive inlet pressure to operate
efficiently.
2. However, permanent lubrication of the stator is necessary
to avoid any elastomer failure. It is thus recommended to
record the annular level.
3. In the situation of a high GOR, it is recommended to run down
the pump below the estimated bubble point level, or the
nearest above it. It will then achieved better oil production
performance, and better pump lubrication.
PCP Operation best practicesPCP system installation
July 2010 8G. Moricca
Relation
between
the
rotating
speed and
fluid level
July 2010 9G. Moricca
Incidence on
the flowrate
of the PCP
position in
an oilwell
producing
below
pressure
bubble point
July 2010 10G. Moricca
Possible
pumps
configuration
in high GOR
wells
July 2010 11G. Moricca
Pre-operational checks
1. Confirm that the equipment at the well-site is configured
properly for making the following connections:
— Stator to tubing
— Tubing to drive head
— Rotor to sucker rods
— Sucker rods to drive shaft or polished rod
2. Ensure that the stator OD is sufficiently under the casing
drift diameter and that the rotor major diameter is less
than the tubing string drift diameter.
3. Also ensure that the size of any rod guides or centralizers is
appropriate for the selected tubing size and weight.
4. Visually inspect the various equipment components, new or
used, for any signs of physical or chemical damage.
PCP Operation best practicesPCP system installation
July 2010 12G. Moricca
Running-in stator and tubings
Checking
●Take special care in the
measurement of all the downhole
parts:
— Stator: from the rotor top,
located at lower end screwed
onto the rotor base, to upper
end of the stator
— Tubings, as they are being
fastened
— The fittings that are to be
mounted between the tubings
and the drive head.
●Note all measurements.
PCP Operation best practicesPCP system installation
July 2010 13G. Moricca
Running-in stator and tubings
1. Connect the stator stop to stator base.
2. Clean and dope all tubing threads, to prevent accidental
unscrewing of the drive string. This is essential, especially when
dealing with very heavy oil in cold weather.
3. Connect the stator to first tubing.
4. Run in tubing down to the chosen dept.
5. Mount the tee for connecting the surface flow line.
6. Screw the adapter fitting on the drive head.
PCP Operation best practicesPCP system installation
July 2010 14G. Moricca
Running-in the rotor and the sucker rods
1. Connect the rotor to the first
sucker rod.
2. Run in all the drive strings by
tightening to manufacturer
connection specifications.
3. After last rod is screwed, run
in very slowly and watch for
the drive string to rotate,
indicating that the rotor has
entered the stator.
PCP Operation best practicesPCP system installation
July 2010 15G. Moricca
Running-in the rotor and the sucker rods
4. Lower a further 3-4 ft, then pull
back up very slowly. The reverse
rotation should then confirm
that the rotor has entered the
stator.
5. Resume running in the rotor
very slowly, and watch the
hanging weight indicator so as
to notice the time when the
rotor lands on the lower end of
the stator (indication of hanging
weight decrease).
PCP Operation best practicesPCP system installation
July 2010 16G. Moricca
Running-in the rotor and the sucker rods
6. Lift the rotor very slowly so as
to realise it from its
supporting point (indication of
hanging weight decrease).
Mark the rod at the tee level
or at the fitting located below
the drive head. Repeat the
operation to check.
7. Pull drive string up and
remove upper extra rod.
8. Measure the distance A
between the mark and the
lower part of the sucker rod
that has just removed.
PCP Operation best practicesPCP system installation
July 2010 17G. Moricca
Setting up of the drive head and the motorized driving system
1. Connect the power supply leads to the motor and switch on.
2. When the motor is running, check that the shaft rotates
clockwise when looking down the well.
3. Mark connections and disconnect.
4. Attach a short pony rod on the top of the drive head.
5. Screw and tighten the upper coupling of the rod string to the
drive head shaft that will thereafter be mounted on the
wellhead.
6. Rotate very slowly the assembly mounted thereby.
7. Connect tee to surface flow line.
8. Remove the pony rod and mount the chosen drive system.
PCP Operation best practicesPCP system installation
July 2010 18G. Moricca
PCP system
installation
July 2010 19G. Moricca
PCP system
Start-up
July 2010 20G. Moricca
General consideration
1. If possible, start the pump slowly and increase speed
gradually after a minimum of 5 minutes.
2. After start-up it is normal to hear some noise generated by the
rods if rod guides are not used. The noise should subside once
the produced fluid reaches surface.
3. Continue to monitor the system operation until it is clear that the
unit is functioning properly.
4. If possible, record torque and speed with time during start-up
to obtain breakaway torque information.
PCP Operation best practicesPCP system start-up
July 2010 21G. Moricca
Operating procedure
1. Switch on the motor. If provided with a variable speed drive,
start at low speed, and increase speed progressively
until the determined speed is reached. A time lapse
corresponding to the filling of the tubing is required before the
well fluid reaches the surface.
2. The rotating speed of the pump should be adjusted to the well
productivity. Consequently, the dynamic or submergence
level will be controlled frequently at the beginning of
the operation.
PCP Operation best practicesPCP system start-up
July 2010 22G. Moricca
Operating procedure
3. Once the optimum speed is established, it will be
maintained continuously and frequent on/off operations
should be avoided.
4. If there is sand in the produced oil, it is preferable to have:
— A high rate of flow in the tubing
— A large capacity pump with a low rotating speed
(<250 rpm)
PCP Operation best practicesPCP system start-up
July 2010 23G. Moricca
pump intake pressure
pump discharge temperature
discharge pres.
PCP Operation best practicesPCP system start-up
July 2010 24G. Moricca
PCP system
Monitoring
July 2010 25G. Moricca
● Well monitoring typically refers to periodic or continuous
measurement of production parameters and evaluation of the
pumping system operating conditions.
● Reason for monitoring include:
— Production optimisation
— Failure detection
— Production accounting
The following table
provides a summary
of the measurements
that can be taken
PCP Operation best practicesPCP system monitoring
July 2010 26G. Moricca
High-viscosity
oil wells
July 2010 27G. Moricca
● Over the past decade, PCP systems have become a very popular artificial-lift method for producing heavy oil: API gravity < 18°.
● Fluid viscosity, under down-hole conditions can range from few hundred centipoise to >100.000 cp.
● The production rates also vary significantly: 60 bpd low-GOR wells in Canada more than 2000 bpd horizontal well in Venezuela.
● Production of high-viscosity fluids can result in significant flow losses through the production tubing and surface piping.
● It is critical that system design account for the “worst-case” flow losses, particularly the selection of pump (pressure rating, rod string (torque capacity), and prime mover (power output).
PCP Operation best practicesSpecial application: High-viscosity oil wells
July 2010 28G. Moricca
Figure here below shows a good example of the effects that viscous flow and
water slugging can have on pump loads in a heavy oil well. The data show
that :
1.The axial load and
torque values remain
relatively constant at
about 45 kN and 1100
N-m [10.050 lbf and
800 ft-lbf],
respectively, over the
first hour.
2.Over the next 2 hours,
both loads decline
significantly.
3.The load subsequently
increased again but
remained somewhat
below the initial load
level.
3
1
2
PCP Operation best practicesSpecial application: High-viscosity oil wells
July 2010 29G. Moricca
5.Because the only
significant
difference during
the operating
period was the
viscosity of the
fluid being
produced, these
results clearly
demonstrate the
pronounced effect
that flow losses
can have on PCP
system loads.
4.Fluid samples taken regularly during the monitoring period, confirmed that
the well had gone from initially producing heavy oil at a very low water
cut to producing a large slug of water with relatively little oil during the
period.
Very low WC
Very high WC
Moderate WC
PCP Operation best practicesSpecial application: High-viscosity oil wells
July 2010 30G. Moricca
● Several alternative methods are available to minimize flow losses:
— Use of large-diameter tubing
— Streamlining of the rod string
— Avoid use of large-diameter centralizer
● If changing the equipment configuration is not an option, injection
down the annulus of, viscosity-reducing additives, light oil or
water could be a valid alternative.
● If viscosity-reducing additives are injected, special caution must be
taken to ensure that they will not damage the stator elastomer.
PCP Operation best practicesSpecial application: High-viscosity oil wells
July 2010 31G. Moricca
High-sand-cut
wells
July 2010 32G. Moricca
The sanding problem
● Sand and other solids production can cause problem in PCP
system by:
— accelerating equipment wear
— increasing rod torque and power demand
— flow restriction by accumulating around the pump intake,
within the pump cavities, or above the pump in the tubing
● Also, given its specific gravity of ≈ 2.7, even moderate volumes of
sand can substantially increase the pressure gradient of the
fluid column in the production tubing.
PCP Operation best practicesSpecial application: High-sand-cut wells
July 2010 33G. Moricca
Sand influx
● Severe operational problem generally develop due to short period
of rapid sand influx (slugging).
● Sudden sand influx can also be initiated by operating
practices that cause fairly rapid changes in bottom-hole
pressure.
● Therefore, large adjustments in pump speed should be made
gradually over a few days to allow the well time to stabilize
PCP Operation best practicesSpecial application: High-sand-cut wells
July 2010 34G. Moricca
Sand accumulation
● Sand accumulation inside the tubing just above the pump is a common problem.
● Sand build-up occurs when the produced-fluid stream cannot carry all the sand up the tubing to surface.
● Therefore, it is very important to asses the sand-handling capacity of a PCP system.
● Sand settling and fluid transport velocity (in vertical pipes) can be assessed by comparing the fluid drag forces with the weight of sand particles.
● The ability of the produced fluid to transport sand improves with increasing fluid viscosity and flow velocity.
● Decreasing the tubing size and increasing the flow rate are the easiest ways to improve sand transport capability. However, the use of smaller-diameter tubing must be evaluated in terms of its effect on flow losses.
PCP Operation best practicesSpecial application: High-sand-cut wells
July 2010 35G. Moricca
PCP pump, stator, and rotor selection
● Produced sand tend to be highly abrasive, causing accelerated wear of the pump, rod string, and tubing.
● Because abrasive wear is directly proportional to the number of revolutions, the use of larger-displacement pumps operated at lower speeds can help to extend equipment life.
● Stator wear can be minimised by choosing an elastomer with good abrasion resistance.
● Although the standard chrome coating used on most rotors generally provided good wear resistance, double-thickness chrome coatings are commonly specified for abrasive applications.
● Note that chrome-coated rotors with visible wear can be repaired by replating as long as the underlying base metal has not been worn.
PCP Operation best practicesSpecial application: High-sand-cut wells
July 2010 36G. Moricca
Low productivity
wells
July 2010 37G. Moricca
Low-productivity wells by definition deliver relatively low fluid rate.
● If produced aggressively, can cause gas interference problems that
prevent the pump cavities from filling completely with liquid. This
results in low volumetric efficiency, as illustrated in the figure.
● Pump selection is a
key consideration
in low-productivity
wells: the inflow
problems can be
mitigated by use
of a larger
displacement
pump run at
lower speed.
PCP Operation best practicesSpecial application: Low productivity wells
July 2010 38G. Moricca
Gassy wells
July 2010 39G. Moricca
Gassy wells
● In most operations, dissolved gas begins to evolve as free gas when the pressure drops as the fluid moves toward and then enters the well.
● Depending on the fluid properties and gas volumes, the free gas may coalesce and flow as a separate phase, or, as in many heavy oil wells, it may remain trapped as discrete bubbles within the liquid phase (foamy oil).
● Gas entering the pump causes an apparent decrease in pump efficiency because the gas occupying a portion of the pump cavities.
● The best way to reduce gas interference is to keep any free gas from entering the pump intake.
● When possible, the intake should be located below the perforations to facilitate natural gas separation.
PCP Operation best practicesSpecial application: Gassy wells
July 2010 40G. Moricca
● In gassy wells in which the pump must be seated above the
perforations, passive gas separation that divert free gas up the
casing-tubing annulus can be effective.
● Gas
production
through the
pump can
lead to large
fluctuations
in rod-string
loading, as
illustrated by
field data
shown in
figure.
PCP Operation best practicesSpecial application: Gassy wells
July 2010 41G. Moricca
Directional and
horizontal wells
July 2010 42G. Moricca
Because of the inherent curvature (angle build sections) and angled bottom-hole segment of directional and horizontal wells, optimisation of a PCP system design for such applications begins with the drilling program:
● The first line of defence against rod/tubing-wear and sucker-rod fatigue problems in deviated and horizontal wells is a good wellbore profile.
● Ideally, the planned angle build rate should be kept as low as practical, and additional monitoring is typically required during drilling to ensure that the well closely follows the prescribed path.
● Experiences has clearly demonstrated that closely spaced surveys (<65 ft) help to prevent large local curvature fluctuation.
● Note that slant wells (wells spud at an angle on surface), which typically have no planned curvature, often provide a good alternative to deviated wells for shallow reservoir developments as a means to avoid rod/tubing-wear problems.
PCP Operation best practicesSpecial application: Directional & Horizontal wells
July 2010 43G. Moricca
PCP installations that operate within the curved portions of directional or horizontal wells must be equipped to deal with potential wear and fatigue problems:
● To protect against rod and tubing-wear failures, options include the use of coated centralizers.
● Use of tubing rotator systems has also grown considerably over the past decade because they have proved to be an effective measure for severe wear problems in such applications.
● From a rod-string fatigue perspective, slim-hole or centralizer designs offer the best performance because the inherent curvature localization adjacent to the connection is minimised.
● Keeping the stress in the rod string at reasonable levels under all operating conditions is crucial, and undertaking detailed loading/fatigue analyses is highly recommended at the system design stage to facilitate proper equipment selection for the specific well conditions.
PCP Operation best practicesSpecial application: Directional & Horizontal wells
July 2010 44G. Moricca
Hostile
fluid conditions
July 2010 45G. Moricca
In many applications (e.g. light oil with gravity >40°API) the constituent of the produced fluids pose the greatest difficulty in the successful use of PCP pumps.
● Aromatics such benzene and toluene typically induce swelling of the stator elastomer that generates high-torque condition.
● H2S can cause extended vulcanization, which results in hardening and eventual breakdown of the elastomer material.
● Diffusion of a significant quantity of gas (in particular, CO2) into the stator elastomer can lead to blistering or fracturing of the rubber because of rapid decompression of the pump during shutdowns.
● Performing swell test is highly recommended to assist in pump selection and sizing when fluid compatibility is expected to be an issue.
● To compensate for the substantial swelling expected in some challenging well application, pump may be sized so loosely that they cannot generate any flow at pressure below their rated capacity.
PCP Operation best practicesSpecial application: Hostile fluid conditions
July 2010 46G. Moricca
High-speed
operations
July 2010 47G. Moricca
As the equipment has improved and operators have gained familiarity
with PCP systems, pump operating speeds have increased
substantially.
● Although the initial heavy oil well installations were typically run at
speeds between 30 and 100 rpm, speeds in the 300 to 500 rpm
range are now common, and some operators have been known to
produce high-water-cut wells at speeds up to 1000 rpm.
● Generally, speeds exceeding 500 rpm are not recommended
because they typically lead to reduced pump and surface equipment
life, increased potential for sucker-rod fatigue failures, and vibration
problems.
● Rod strings commonly experience excessive vibrations within
certain speed ranges because of the resonant frequencies of the
system.
PCP Operation best practicesSpecial application: High-speed operations
July 2010 48G. Moricca
● The potentially harmful vibrations can usually be minimized by
adjusting the speed slightly up or down.
● Resonant frequencies of the system will likely change over time with
variations in the load and fluid conditions.
● Additional rod centralization or different types of centralizers
should be used in wells that experience repeated problems.
● Ensuring that PCP installations are equipped with effective braking
systems.
PCP Operation best practicesSpecial application: High-speed operations
July 2010 49G. Moricca
Elevate
temperature
applications
July 2010 50G. Moricca
Elevated-temperature applications can be divided into medium and
high temperature categories.
Medium temperature
● The medium temperature category covers reservoir conditions
ranging from 40°C [104 °F] to ≈ 100°C [212 °F].
● Field experience has proved that PCP pumps can be used successfully
in well producing fluids within this temperature range.
High temperature
● The high temperature category covers reservoir temperature >100°C
[212 °F] including many geothermal wells and most thermal recovery
operations. Thermal operations include mature steam-floods in which
the temperature may be as high as 200°C [425 °F].
PCP Operation best practicesElevate temperature applications
July 2010 51G. Moricca
cont/High temperature
● A general assessment of the values in the product literature from
several different PCP pump vendors indicates that the following
temperature limit:
— 100°C [212 °F] for NBR elastomers
— 125°C [265 °F] for HNBR sulfur cured elastomers
— 150°C [318 °F] for HNBR peroxide cured elastomers
— 200°C [425 °F] for FKM elastomers
The thermal expansion coefficient of elastomers is approximately
an order of magnitude higher than that of steel; therefore
changes cause stator elastomers to expand and contract far more than
the steel tube housing or the mating steel rotor.
It is important to understand that thermal expansion changes are
independent of any fluid-induced swell effect, which can
exacerbate pump sizing problems.
PCP Operation best practicesElevate temperature applications
July 2010 G. Moricca 52
PCP System application
-Case History
July 2010 53G. Moricca
PCP System application: a case history
PDVSA experience
-Venezuela
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PCP System application: a case history
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PCP System application: a case history
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PCP System application: a case history
view of a PCP wells pad
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PCP System application: a case history
309 PCPs producing wells
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PCP System application: a case history
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PCP System application: a case history
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PCP System application: a case history
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PCP System application: a case history
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PCP System application: a case history
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PCP System application: a case history
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PCP System application: a case history
Total E&PExperience
-Canada
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PCP System application: a case history
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PCP System application: a case history
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PCP System application: a case history
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PCP System application: a case history
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PCP System application: a case history
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PCP System application: a case history
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PCP System application: a case history
PetromExperience
-Romania
Jly 2010 G. Moricca 72
PCP System application: a case history
PCP System-
Troubleshooting
and
Diagnostic Techniques
July 2010 73G. Moricca
Main source: Processing Cavity Pumping Systems. Petroleum Engineering Handbook vol. IV
July 2010 G. Moricca 74
This section outlines PCP system troubleshooting and
provide indication for identification of :
1. Possible problem
2. Possible root cause
3. Possible remedial actions
PCP Operation best practicesTroubleshooting and diagnostic
July 2010 75G. Moricca
Troubleshooting and diagnostic
Most PCP equipment vendors provide information describing
troubleshooting procedures and suggestions for solving
problems may be encountered with their equipment .
An example of vendor troubleshooting procedures is reported at
the end of this section.
However, to assist in the diagnosis and correction of operational
problems that may be encountered in PCP system installations,
several problematic operating scenarios, some possible
explanations and corresponding actions that may be taken to
solve the problem are outlined on the following table........
PCP Operation best practicesTroubleshooting and diagnostic
July 2010 76G. Moricca
Source: Processing Cavity Pumping Systems. Petroleum Engineering Handbook vol. IV
July 2010 77G. Moricca
Pump Failure Analysis
● When a PCP pump is pulled during a workover, it should be sent to a pump shop for a thorough examination and pump test.
● Usually, the pump components are first cleaned and visually inspected.
● Inspection of the rotor involves examining the condition of the threads and pin, assessing the amount and location of any wear, and identifying the presence of any heat checking.
● Although equipment is available to perform a full examination of the internals of a stator (e.g. bore-scope camera), not all vendors have these systems, and stator inspections are often limited to the visual checking of the long stator cavity for sign of damage or deterioration.
PCP Operation best practicesTroubleshooting and diagnostic
July 2010 78G. Moricca
Pump Failure Analysis (2)
● The elastomer surface typically is examined to locate any areas of worn, hardened, cracked, swollen or missing rubber.
● If the rotor and stator components show no evidence of failure, the pump will be bench tested.
● If the test results show that the pump is within the accepted performance guidelines for the particular application, it will usually be sent back to the field for redeployment.
● Observation made during failed-pump inspections typically provide information that is crucial to the determination of the root cause of failures.
PCP Operation best practicesTroubleshooting and diagnostic
July 2010 79G. Moricca
Stator Fatigue Failure
● Fatigue failures are characterized by missing rubber primarily along the rotor-stator seal lines.
● The regions of torn or missing rubber are typically shiny and irregular.
● Fatigue failure can be attributed to excessive cyclic deformation of the elastomer.
PCP Operation best practicesTroubleshooting and diagnostic
July 2010 80G. Moricca
Stator Fatigue Failure (2)
● The loss of material along the rotor-stator seal lines leads to increased slip and a rapid decline in pump performance.
● Stators that have missing rubber as a result of fatigue damage are not suitable for reuse and must be scrapped.
PCP Operation best practicesTroubleshooting and diagnostic
July 2010 81G. Moricca
High-temperature Stator Wear
● Stators that have failed because of exposure to high temperatures typically exhibit elastomer surfaces that are hard, brittle, and extensively cracked.
● Heat damage usually produces a rapid decline in the pump’s volumetric efficiency.
● Stators that have failed because of high-temperature damage cannot be repaired and must be scrapped.
PCP Operation best practicesTroubleshooting and diagnostic
July 2010 82G. Moricca
Stator High-pressure Wash
● High-pressure wash or channelling is common stator damage
mechanism characterized by worm-like holes or groves cut in the
alastomer.
● These channels develop during production when a large sand particle
or other debris become embedded in the elastomer material.
● Because the channelling damages the pressure integrity of the pump,
stators with extensive pressure-wash damage are not
recommended for reuse.
PCP Operation best practicesTroubleshooting and diagnostic
July 2010 83G. Moricca
Stator Wear
● Stator wear usually can be attributed to the forced movement of abrasive solids along the stator cavities.
● The rate of abrasive wear is related most strongly to the quantity and abrasiveness of the solid particles contained in the fluid.
● Wear rates are also influenced by elastomer type: soft stator materials are more likely to deform instead of tearing as solids pass through the pump.
● Stators wear produces a gradual decline with time in volumetric efficiency and fluid rate.
PCP Operation best practicesTroubleshooting and diagnostic
July 2010 84G. Moricca
Rotor Wear
● Rotor wear results from normal pumping action.
● Extreme abrasive wear is characterized by material loss through the surface coating and into the underlying base metal of the rotor.
PCP Operation best practicesTroubleshooting and diagnostic
July 2010 85G. Moricca
Rotor Wear (2)
● Worn rotors can be rechromed and reused as long as the wear has not progressed through the chrome surface.
PCP Operation best practicesTroubleshooting and diagnostic
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PCP Operation best practicesTroubleshooting and diagnostic
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PCP Operation best practicesTroubleshooting and diagnostic
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PCP Operation best practicesTroubleshooting and diagnostic
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PCP Operation best practicesTroubleshooting and diagnostic
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René Moineau inventor of progressing cavity pump (1930)
PCP course end
G. Moricca
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