day 3 - pcp system installation, monitoring, troubleshooting and diagnostic

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

[email protected]


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


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


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


PCP system

Installation


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


Relation

between

the

rotating

speed and

fluid level


Incidence on

the flowrate

of the PCP

position in

an oilwell

producing

below

pressure

bubble point


Possible

pumps

configuration

in high GOR

wells


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.



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.



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.



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.




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).




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.



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 system

installation


PCP system

Start-up


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


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.



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)



pump intake pressure

pump discharge temperature

discharge pres.



PCP system

Monitoring


● 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


High-viscosity

oil wells


● 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


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



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



● 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.



High-sand-cut

wells


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


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



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 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.



Low productivity

wells


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


Gassy wells


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


● 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


Directional and

horizontal wells


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


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


Hostile

fluid conditions


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


High-speed

operations


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


● 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


Elevate

temperature

applications


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


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


PCP System application

-Case History


PCP System application: a case history

PDVSA experience

-Venezuela



view of a PCP wells pad



309 PCPs producing wells



Total E&PExperience

-Canada



PetromExperience

-Romania

Jly 2010 G. Moricca 72


PCP System-

Troubleshooting

and

Diagnostic Techniques


Main source: Processing Cavity Pumping Systems. Petroleum Engineering Handbook vol. IV


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


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........



Source: Processing Cavity Pumping Systems. Petroleum Engineering Handbook vol. IV


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.



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.



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.



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.



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.



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.



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.



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.



Rotor Wear (2)

● Worn rotors can be rechromed and reused as long as the wear has not progressed through the chrome surface.



René Moineau inventor of progressing cavity pump (1930)

PCP course end

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