General Guidelines for Failure Analysis Of

Downhole Progressing Cavity Pumps

Table of Contents

Section 1………………………..Introduction Section 2……………….……….Component Description Section 3………………………..General PC Pump Theory Section 4………………………..Failure Modes Section 5………………………..Root Causes Section 6…………………….….Possible Solutions Section 7………………………..Technical Support

Introduction This Failure Analysis Guide is intended to give a general outline of common failure modes of Progressing Cavity Pumping Systems along with their respective root causes and possible solutions. In order to properly understand some of the failure modes covered herein and their respective root causes and solutions, an understanding of progressing cavity technology is crucial. It will be done by first reviewing the basic progressing cavity pump components followed by some basic progressing cavity pump theory. This guide is not intended to give final answers on progressing cavity pump component failures but should help in evaluating whether further investigations are necessary.

Component Description The basic progressing cavity pump components consist of a rotor and a stator the configuration of which is given below. The Progressing Cavity Pump (PCP) is a rotary positive displacement pump consisting of two (2) components. A single external helical rotor rotates eccentrically inside an internal double helical stator of the same minor diameter and twice the pitch length. The rotor cross-section is that of a circle the centers of which lie along a helical path. The centers of the rotor cross-sections are off set from the axis of the rotor. This is what is known as eccentricity. The stator is molded from an elastomeric material that is permanently bonded inside a steel tube. The cross-section is that of two semi-circles connected by two parallel

straight lines. The centers of the semi-circles also lie along a helical path. The minor diameter is equal to that of the rotor.

Progressing Cavity Pump Theory As the rotor rotates within the stator, its circular cross-section at any point along the length travels back and forth across the stator opening in one revolution. This unique geometrical motion is based upon the concept of a hypocycloid. A hypocycloid by definition is the curve traced by a point on the circumference of a rolling circle inside a fixed circle that is twice the diameter. This path is always a straight line. To look at this in terms of a rotor and stator, the centers of the rotor cross-section when viewed axially give us the rolling circle. The centers of the semi-circular portion of the stator cross-section when view axially, give us the fixed circle. You can see this in the following diagram at the right. The pump generates pressure due to interference fit between the metallic rotor and the elastomeric stator (shown in red). This line of contact is called a seal line. One complete sealed cavity (or 360º rotation of the stator helix) will generate a given

amount of pressure. By increasing the number of sealed cavities, you increase the pump’s pressure capabilities.

Failure Modes The rotor of a progressing cavity pump consists of (2) two parts; 1) the rotor base metal and 2) the coating (hard chrome plating). The stator of a progressing cavity pump consists of (3) three parts; 1) a steel tube, 2) a bonding system (glue) and 3) an elastomer contour. Under certain circumstances, failures may occur which are related to one of these two components. General stator description

There are a whole host of failure modes that could be seen on both the rotor and the stator however this section is intended to cover some of the more common failure modes and is not meant to be all encompassing. The following rotor and stator failure modes will be covered - Rotor Failure Modes:

Abrasive Wear Acid Attack Fatigue Failure Pitting Corrosion Improper Rotor Spacing

Stator Failure Modes:

Run Dry Hysteresis Abrasive Wear Swell Gas Permeation / Explosive Decompression Delamination Bond Failure

Bond to tube Bond to elastomer

Rotor Failure Modes

The following failure modes can occur on a progressing cavity pump rotor: Abrasive Wear: Abrasive wear occurs when the hard chrome plating on the rotor becomes worn. This wear can be just on the surface of the chrome or down to the base metal. In either case, the original rotor profile is changed. This change in profile can affect the pump’s performance in that the interference fit between the rotor and stator is no longer what it was initially. Acute abrasive wear where the hard chrome plating is worn down to base metal can go as far as permanently damaging the elastomer. Abrasive wear usually occurs on the crests of the rotor however in acute cases, it can occur on other sections as well. Acid Attack: Acid attack occurs when the pH of the produced fluid drops below 6.0 resulting in a complete stripping off of the hard chrome plating on the rotor. This usually occurs when an operator decides to acidize their well while leaving the pump in the well. Once the hard chrome plating has been stripped from the base metal,

the resulting surface finish is very rough. This rough surface will eventually result in the elastomer wearing and a drop in production. Torsional or Fatigue Failure: A fatigue failure is the result of a material undergoing cyclic stresses and ultimately failing. Fatigue failures are progressive and begin as small stress cracks that grow under the cyclic stress. A progressing cavity pump rotor is rigid and as such any unnecessary side-loading or locking up of the pump can result in the rotor failing. The natural movement of the rotor is eccentric in nature and if a rotor is not inserted adequately during the initial installation, the portion of rotor outside the top of the pump can experience a higher than designed eccentric motion. This excessive motion will raise the cyclic stressed in the rotor and can result in a fatigue failure. Any damage to the rotor surface can reduce the cross-sectional area of the rotor. This reduction in area will increase the load at that point creating a stress riser.

Another failure mechanism of a rotor is torsional fatigue. This type of failure can occur is if the pump locks up for any reason (e.g. solids, elastomer failure). Under this situation, a portion of the rotor locks up while the remaining portion of the rotor wants to keep rotating. As the rotor is not that flexible, the portion of the rotor that continues to move twists off. Pitting Corrosion: Pitting corrosion occurs when some initial damage occurs to the hard chrome plating thereby allowing corrosive attack to the base metal. This initial damage is usually a chemical attack associated with the produced media (oil, water and gas). Despite the hard surface and relatively low coefficient of friction, hard chrome plating is porous and under the right conditions components of the produced fluids enter these pores and begin to corrode the base metal under the chrome. Once a sufficient amount of the base metal has been eroded away under the chrome, the chrome in that area will pop off leaving a pit.

In the most severe case of pitting corrosion, a fatigue failure can occur once the cross-sectional area is less than the minimum acceptable area for the stresses seen within the rotor body. Improper Rotor Spacing: Improper rotor spacing is not a material or application related failure but a failure due to improper installation procedures. For a given set of well conditions, the sucker rods will stretch a given amount. This stretch is dependent upon the rod size, total dynamic head and the effective cross-sectional area of the pump. If the proper amount of stretch is not accounted for, the rotor placement within the stator could either be too high or too low. In either case, excess stresses are placed on the rotor and sucker rods and may result in a torsional fatigue failure of either the rotor or the sucker rods. In the case of being set too low, if a torque anchor is not used the additional torque of the rotor running on the tag bar could result in the stator/tubing unscrewing.

Stator Failure Modes The following failure modes can occur on a progressing cavity pump stator: Run Dry: A pump that has run dry has its elastomer hard, brittle and extensively cracked. In an extreme run dry condition, the stator contour will be completely gone. Hysteresis: Hysteresis is the result of over-pressuring the elastomer. Hysteresis occurs in the minor diameter of the stator (thicker section of rubber). It can occur for a variety of reasons but all as a result of the over-pressuring. Although it is a normal process that occurs as an elastomer ages, its occurrence can be premature based upon several factors. These factors are –

Pump setting depth beyond the pump’s rated pressure. Resulting TDH is beyond the pump’s rated pressure. Improper rotor insertion resulting in less pressure available.

During normal operation, the heat that is generated in the minor diameter areas of the pump due to the flexing of the rubber is dissipated by the produced fluid moving through the pump. However when excessive heat is generated by over-working or over-pressuring the elastomer as would be the case in the above situations, the elastomer is working harder than it is designed for and thereby fails prematurely.

The produced fluid passing through the pump is not adequate to dissipate the heat built up in the minor. This heat build-up reduces the elastomer’s strength and ultimately its ability to generate the necessary pressure. The following three (3) images depict the stages of hysteresis occurrence -

Abrasive Wear: Abrasive wear occurs when the elastomer is worn from the presence of abrasives in the produced fluid. As the percentage of abrasives increases, the chances of prematurely wearing the seal lines that are formed by the interference fit between the rotor and stator also increases. The hardness and angularity of the pumped abrasive can also affect the wear rate. The total differential pressure seen across the pump as well as the pump’s rotational speed play a key role in how abrasives affect the elastomer.

As a result of the elastomer wearing, the slip within the pump increases and as a result, the production will drop off. Elastomer Swell: Elastomer swell can occur either when the stator elastomer is affected by production fluids or treatment chemicals that are incompatible with it (chemical swell) or due to an increase in temperature (thermal swell). Chemical swell is generally caused by the elastomer coming in contact with high API gravity crude oils or incompatible treating chemicals; both of which have a fairly high percentage of aromatics. Aromatics include benzene and compounds that resemble benzene in chemical behavior. The presences of these aromatic compounds cause the stator elastomer to expand and swell. This expansion results in an increase in the interference fit between the rotor and stator thereby in an increase in operating torque as well. Chemical swell is generally permanent and non-reversible once the source of the swelling has been removed.

Thermal swell on the other hand is purely due to an elevation in temperature resulting in the elastomer expanding due to this increase in temperature. This expansion also results in an increase in the interference fit between the rotor and stator thereby in an increase in operating torque as well. Thermal swelling can be predicted and is not permanent. Once the temperature decreases the thermal expansion of the elastomer also decreases. Gas Permeation / Explosive Decompression: Gas permeation occurs when gas; under pressure; enters the elastomer matrix and expands due to a pressure drop. When the gas expands, it often results in blisters or bubbles forming within the elastomer. This pressure drop can be the result of the events such as the fluid level equalizing in the wellbore after a shut down or from the pulling of the pump.

The expanding gas within the elastomer matrix can sometimes expand to the point that the elastomer ruptures. This is called explosive decompression. The rapidly decompressing of the gas entrained within the elastomer matrix tears and chunks the elastomer when it expands. Delamination: The word delamination contains the word lamination which means “in layers”. In elastomeric terms, this means that the elastomer had not knit through its cross-section resulting in layer-like striations within the elastomer. This is often the result of temperature fluctuations during the injection process. These laminations or layers create weak areas within the elastomer and are a prime location for gas that has permeated into the elastomer to gather. When a pressure drop occurs, the gas that has entered these laminated areas expands thereby tearing these weak areas. Visually looking at the laminated areas, the internal surfaces of the laminations are smooth; unlike a torn surface where the surfaces are rough and jagged.

Bond Failure: A bond failure occurs when the bonding agent that keeps the elastomer in the stator tube fails. This can occur at two interfaces. The first interface is between the bonding agent and the elastomer. In this instance, there is no elastomer left on the stator tube but there is bonding agent. A view of the backside of the elastomer will show it to be smooth. The stator tube will also be smooth with a gray or black color. The second interface is between the bonding agent and the stator tube. As in the above instance, there will be no elastomer left on the stator tube however the stator tube will be clean and clear of any bonding agent. A view of the back side of the elastomer will show it to also be smooth.

Root Causes

Although there are generally a host of conditions that can and do contribute to each and every failure, there is often one primary mode that dominates the list. One mode of failure is the underlying cause of the failure upon which the other modes depend. This section will attempt to shed some light on the root causes for the failure modes outlined in the previous section.

Rotor Failures Abrasive Wear: Abrasive wear is the result of pumping too high a percentage of abrasives (i.e. formation sand, frac sand, coal fines, etc.) for the given pump speed and pressure rating. Although progressing cavity pumps can handle sand and abrasives much better than other methods of artificial lift, the pump speed and differential pressure across the pump need to be considered. Acid Attack: Acid attack is caused by the pH of the produced fluid going too acidic or too basic. Generally this is the result of the operator acidizing the well without pulling the pump. The acid used is often hydrochloric or hydrofluoric acid which will strip the chrome plating off of the rotor. Torsional or Fatigue Failure: Torsional or fatigue failures are a result of a material undergoing cyclic stresses. In a rotor, these stresses are often the result of the pump locking up or improper rotor spacing. When the former occurs, sudden locking up of the pump on a rigid shaft

(rotor) results in a torsional failure. In the later case, a rotor that is improperly spaced also places additional stresses on the material. If the rotor is landed too low, the rotor could run on the tag bar, and thereby cause the same stresses as if the pump locked up. If the rotor is spaced too high, the portion of the rotor that is outside the stator can experience undue bending stresses (as a result of the eccentric motion) and fail due to fatigue. Pitting Corrosion: Pitting corrosion is the result of the underlying base metal being attacked resulting in the formation of pits followed by the flaking off of the hard chrome plating. This is usually related to improper handling in the field thereby damaging the chrome plating allowing access to the base metal however in some cases, the porosity of the chrome will allow corrosive fluids to access the base metal as well and the same process occurs. Improper Rotor Spacing: Improper rotor spacing is always caused by the initiator. That is, the person who is installing and spacing out the pump.

Stator Failures Run Dry: A run dry condition is generally caused by the well pumping off. The lack of fluid entry into the pump causes a lack of lubrication within the stator resulting in extremely high temperatures being generated. This high temperature ultimately “burns” the elastomer at the seal lines. On occasion, very high percentages of free gas at the pump intake can result in the same run dry situation.

Hysteresis: Hysteresis is the over-pressuring of the elastomer. This is generally the result of one of the following –

Total Dynamic Head is beyond the pump’s rated pressure. o Set too deep o Producing pressure + wellhead pressure

higher than rated pressure. Improper rotor spacing (rotor spaced too high resulting in not enough pressure capacity.)

Abrasive Wear: Abrasive wear is caused as a result of pumping too high of a percentage of abrasives for the given pump geometry, differential pressure and operating speed. A pump with a large swept rotor angle (SWA) tends to allow sand to settle within the cavities allowing the abrasives to wear the elastomer. Excessive pressure per sealed cavity also increases the abrasive effect on the elastomer. The pump’s operational speed also affects the rate at which the abrasive particles pass through the pump. To high of an RPM will wear the pump faster. Elastomer Swell: Elastomer swell is the result of the elastomer being incompatible with the produced fluid or treating chemical or related to thermal expansion. Swelling from the produced fluid is from the aromatic content of the fluid and will usually reach equilibrium after a specific period of time. Chemical swell from treating chemicals (e.g. corrosion, scale or paraffin inhibitors) on the other hand will not usually reach equilibrium and will continue to swell until the stator opening is completely closed.

Thermal swelling of the elastomer is due to the temperature that the elastomer at its setting depth. Thermal expansion can be pre-determined. Gas Permeation / Explosive Decompression: Gas permeation is the direct result of gas permeating into the elastomer matrix. This can be a result of the specific gas composition combined with the permeability of the particular elastomer. Under the right circumstances (e.g. temperature and pressure), gas can permeate into the elastomer matrix. When a pressure drop occurs (e.g. shut down or pulling), the gas that had permeated into the elastomer rapidly decompresses resulting in explosive decompression. This is evident in the blisters/bubbles that form within the elastomer. Delamination: Delamination is the result of improper “knitting” of the elastomer during the injection process. This can often be due to temperature fluctuations across the stator tube / core cross-section. During the injection process, cooler spots will cause portions of the elastomer to cool prematurely allowing hotter elastomer to pass over it thereby forming layers or laminations. Bond Failure: Bond failures occur as a result of a failure between the bonding agent and the stator tube or between the bonding agent and the elastomer. It is most often a manufacturing defect occurring during the elastomer injection process however there are instances that the bond can be affected as a result of elastomer damage.

Possible Solutions Without a complete understanding of all of the circumstances surrounding a given event, it is impossible to come to a conclusion not only on what the root cause of the problem was, but also what course of action to recommend as a possible solution. This section will share some of the most commonly recommended solutions for the problems discussed in earlier sections.

Rotor Failure Solutions Abrasive Wear: Adding additional seal lines (or stages) will reduce the pressure per sealed cavity thereby reducing the effect of abrasives on the rotor. Running a pump with a larger displacement per RPM will lower the required pump speed and thereby reduce the particle velocity within the pump. Acid Attack: If the well is to be acidized, pull the rotor before conducting the acid job. Swab the well until the pH pf the fluid after the acid job is back to its original level. If the well fluid’s normal pH is normally acidic, a stainless steel chrome plated rotor should be used. Torsional or Fatigue Failure: If the torsional or fatigue failure is the result of an elastomer issue, the solution lies with the elastomer selection (see section on Elastomer Swell). If the failure is due to improper spacing of the rotor, being sure that the rotor is properly spaced within the stator should eliminate this problem.

Pitting Corrosion: Pitting corrosion can be minimized by knowing the fluid composition prior to selecting the equipment materials of construction. This will allow for the proper selection for the rotor material. Proper handling of the rotor during shipping and installation will also minimize damage to the hard chrome plating thereby eliminating places for the corrosive pitting to initiate. Improper Rotor Spacing: This can be eliminated by being sure to space the rotor out properly based upon the Rotor Pullback curves in the LIFTEQ Technical Manual.

Stator Failure Solutions Run Dry: Monitoring the producing fluid level will ensure that the well will not pump off resulting in a run dry condition. If the run dry is a result of high percentages of free gas, lowering the pump setting depth or running a gas anchor will limit/eliminate the gas entry. Hysteresis: As hysteresis generally occurs via an over-pressuring of the pump, there are a few solutions that can be offered. The first consideration should be to be sure that the pump has the correct pressure capabilities for the operating conditions is installed. By installing a pump with higher pressure capabilities, the pressure per sealed cavity will be reduced thereby reducing the over-pressuring of the elastomer. This should include the wellhead pressure. If the over-pressuring was due to the improper spacing of the rotor, be sure that the rotor is

completely engaged in the stator thereby using all of the pump’s pressure capability. Abrasive Wear: When abrasion is a problem, pump speed is generally the first thing to consider. By installing a pump with a higher production capacity, the pump speed will be reduced for the same production rate while reducing the particle velocity within the pump. In addition, increasing the pump’s pressure rating will lower the total differential pressure across the pump thereby decreasing the effects of the abrasives. Elastomer Swell: Proper evaluation of the well conditions (e.g. APIG, bottom-hole temperature) will allow for better application of the elastomer minimizing or eliminating the occurrence of elastomer swell. Gas Permeation /Explosive Decompression: Proper evaluation of the well conditions (e.g. APIG, bottom-hole temperature, % free gas, gas composition) will allow for better application of the elastomer and placement of the pump intake in the wellbore thereby minimizing or eliminating the occurrence of gas permeation. Delamination: Since delamination is generally a manufacturing issue, there is not much to do to resolve it aside from an evaluation of manufacturing processes. Bond Failure: Although bond failures are generally manufacturing related, it can occur due to an incompatibility of the elastomer with the well conditions. The solution would be to check the compatibility of the elastomer with the well fluids.

Troubleshooting Diagnostic Table

Perceived Problems Possible Causes 1. No Production 2. Production Drops off 3. Intermittent Production 4. Pump Will Not Start 5. Motor Stalls @ Pump-up 6. Motor Overheats 7. Pump Consuming Excessive Power 8. Excessive Noise & Vibration 9. Wear on Pump Elements (rotor or stator) 10. Excessive Packing Gland Wear 11. Packing Gland Leakage 12. Pump Locks Up

2, 3, 4, 5, 7, 16, 18, 26, 28, 29, 35 3, 4, 5, 7, 8, 9, 10, 11, 14, 16, 17, 21, 27, 28, 29 4, 5, 7, 8, 14, 15, 17, 27, 28, 29, 34 6, 7, 8, 12, 17, 20, 24, 26, 29, 32, 33, 34, 35 8, 11, 12, 20, 24, 25, 28, 29, 32, 33, 34, 35 6, 8, 11, 12, 15, 18, 20, 24, 26, 28, 32 8, 11, 12, 15, 18, 20, 28, 33, 34 2, 3, 4, 6, 8, 9, 11, 14, 15, 17, 18, 19, 20, 26, 28, 31, 33, 34 1, 11, 15, 18, 27, 28, 34 1, 12, 15, 25, 27, 30 13, 25, 27, 30 9, 11, 12, 20, 26, 27, 28, 29, 33, 34, 35

List of Causes Plan of Action 1. % Abrasion Above Max Recommended 2. Sucker Rods Parted 3. Tubing Parted 4. Inadequate Fluid (reservoir or completion related) 5. Hole in Tubing or Collar 6. Motor Supply or Wiring 7. Pump Intake Blocked 8. Fluid Viscosity Above Design Point 9. Fluid Temperature Above/Below Design Point 10. Fluid Viscosity Below Design Point 11. Discharge Pressure Above Design Point 12. Packing Gland Too Tight 13. Packing Gland Not Tight Enough 14. Excessive Free Gas @ Pump Intake 15. Pump Speed Above Design Point 16. Pump Speed Too Low 17. Drive Belts Slipping 18. Incorrect Rotor Setting 19. Drive Mounting Insecure 20. Drivehead Bearing Wear/Failure 21. Worn Pump (rotor/stator) 24. Low Voltage 25. Abrasives in the Packing Gland Area 26. Failure of Drive Arrangement 27. Incompatible Treating Chemicals 28. Pump Discharge Blocked or Valve Closed 29. Stator Worn/Damaged 30. Packing Gland Destroys Packing 32. Motor is Too Small 33. Incorrect Rotor Spacing 34. Stator Elastomer Swollen 35. Pump Sanded In

1. Select Correct Rotor Fit, Decrease Pump Speed 2. Fish Parted Rod & Replace 3. Fish Parted Tubing & Replace. Tighten Adequately 4. Reduce Pump Speed or Put on a Timer 5. Replace Tubing or Collar 6. Check Electrical Supply & Wiring 7. Pull Up Rotor, Circulate Well 8. Decrease Pump Speed 9. Select Correct Rotor Fit 10. Increase Pump Speed 11. Check Flowline for Blockages or Partially Closed Valve12. Adjust Packing Gland (see Drivehead Manual) 13. Adjust Packing Gland (see Drivehead Manual) 14. Install Gas Anchor, Reduce Speed or Lower Pump 15. Decrease Pump Speed 16. Increase Pump Speed 17. Check Belt Tension & Adjust as Necessary 18. Check & Adjust Rotor Spacing 19. Check & Tighten All Mounting Hardware 20. Remove Drivehead. Replace or Overhaul 21. Replace Worn Components 24. Check Voltage/wiring Sizes 25. Check Packing Type & Condition 26. Check & Replace Failed Drive Components 27. Re-check Materials of Compatibility with Chemicals 28. Relieve Pressure. Clear Blockages 29. Replace worn Parts 30. Check Polished Rod for Excessive Wear & Replace 32. Check & Re-calculate Motor Size 33. Re-space Rotor 34. Re-evaluate Well Characteristics & Elastomer Selection35. Pull Rotor up, Circulate & Re-Set Rotor

Technical Support Contact Information Ken Saveth Sr. Applications Engineer (918) 461-9186 - Office (918) 510-1490 - Cellular Ken.saveth@weatherford.com