Managing Downhole Failure in a Rod Pumped Well

1. Rod Pump
System Performance
And Evaluation
MELEIHA OIL FILD – AGIBA PETROLEUM COMPANY

2. Agenda
System performance
A. Failure Analysis
(Problem Nature – Reasons – AGIBA Application)
B. Troubleshooting
(Physical Indicators – Common techniques – Common mistakes )

3. Gas Interference
PROBLEM NATURE
• Gas separated and accumulated inside the pump reducing the volumetric efficiency and in the
worst case the well stops pumping due to gas lock.
PROBLEM REASONS
• High GOR or foamy fluids .
• Poor gas venting while production.
Real Gas Interference card from Well S-66

4. Gas interfernce..cont.
Remedial Action
- Increasing the compression ratio by the following Modifications to Standard
Pumps:-
• Longer stroke length, close valve spacing & spaced low (w/o tagging) at well site
• High comp. standing valve cage
- Improve gas venting through annulus .
- Install pump below perforations to allow for gravity separation
- Install gas anchor ( separator ) .
- Use vsp (variable slippage pump ) .

5. GAS ANCHOR ( SEPARATOR ) VARIABLE SLIPPAGE PUMP

6. • In Agiba applications some of the NE wells, SE, Zarif, Faras and Ramel fields are the highest gas to oil ratio
(GOR) wells (over 300 SCF/STB). In 1988 Agiba ran poor-poy type gas separator tests for two of the SE wells.
They did not show any significant improvements and this technique had some limitations:
1. It was not effective for wells producing over 300 BOPD.
2. It Impedes possible wire-line operations in the well in which it is used
Pump Intake setting below perforations
• Seating the pump intake below the perforations is the most
efficient technique if the well conditions allow it.
AGIBA applies the process for some of the Meleiha wells (M-8,
SE-6) as a trials and it was proved to be very efficient most of the
Faras, Raml and Zarif field wells.
Application of the technique created the following advantages:
• Increased pump submergance which resulted in more
production.
• Created a natural gas-separation, which improved the pumps
mechanical performance.
limitations to this technique:
Not recommended for sandy wells where pump-sticking problem
arise.

7. Fluid pound
PROBLEM NATURE :
Incomplete pump fillage creates a hammering effect for S.R.
PROBLEM REASONS :
• Insufficient pump intake pressure .
• pump intake restriction .
CAUSES SEVERE PROBLEMS LIKE :
• Pumping unit base vibration ( loosens the bolts ).
• Gear box teeth damage .
• S.R. Premature fatigue failure S.R. Premature fatigue failure .
• Rod unscrew from bottom .
• Rod buckling and excessive TBG. Wear

8. Fluid pound..cont’
Remedial Action
• Re-optimize the pumping parameters ( S.L. , SPM & P.S. ) .
• Use pump off controller to match pumping rate with the Actual well productivity .
• check pump intake for restriction ( this could be Considered in case of pounding at higher dynamic level) .
• increase pump submergence if possible .

9. Fluid pound..cont’
In Agiba Applications, The reservoir is a depletion drive type and the fast decline in reservoir
pressure was affecting the pump intake pressure. Therefore, the gas and fluid pounding problem
became a serious issue and the decrease in the dynamic fluid level consequently increased the
peak polished rod load due to increasing the net lift.
Split traveling valve cage
from fluid pound
Fractured nickel-carbide standing valve
seat from fluid pound

10. Scale deposition
PROBLEM NATURE AND REASONS
• It was observed that scale formation problems started to appear in some of the Meleiha and
Raml field wells. Chemical analysis showed that it was the calcium carbonate (CaCO3) type. Such
scale precipitates in the upper part of the tubing (surface down to about 300 ft). Presence of
scale restricted operations during pulling and running of the subsurface pump. In some cases it
created stuck pumps and then a work over was needed.
• The reasons for this problem are as follows: -
1. Pressure drop at the wellhead (below 100 psi).
2. High formation water production.
3. High temperature (over 120 F).

11. Scale deposition..cont’
• To prevent scale formation inside the well, it was found that increasing the wellhead pressure
to 150 psi would significantly improve the situation.
STUCK STANDING VALVE DUE TO SCALE

12. Sucker Rod Failures..cont’
A – TENSILE FAILURE :
• It appears as a bottle neck shape due to rod elongation when using improper rod type or creates
excessive tension to free stuck pump ,(actual applied loads tension to free stuck pump exceeds the
allowable loads ) .
B–CORROSION FAILURE :
• The rod is parted due to area reduction as a result of corrosion ( chemical reaction between steel
and CO2 , H2S OR ACID .
C – FATIGUE ( MECHANICAL ) FAILURE :
• It originates from a local increase in stress as small, progressive stress cracks that advance, upon each
applied load, with the action of fluctuating or cyclic stresses to rupture, or final shear tear.
SUCH TYPE IS CONSIDERED THE MOST COMMON TYPE WORLD WIDE .
Caused by Improper make-up, severe fluid pounding , manufacturer defects ,using old rods without
inspection , pump tagging down .

13. Sucker Rod Failures..cont’
D - ROD BUCKLING TENDENCY :
• Buckling tendency happens due to compression loads in the down stroke (the rod should be kept
under tension in all conditions ).
PROBLEMS RELATED TO BUCKLING :
• Excessive rod and tubing wear .
• sucker rod failure or unscrew .
• valve rod and valve rod guide damage .
Reasons :
• severe fluid pounding .
• excessive rod speed ( exceeds free fall speed ) .
• heavy viscous oil .
• improper rod string design .
• pump tagging .

14. Sucker Rod Failures..cont’
ROD BUCKLING TROUBLESHOOTING :
• Eliminate pounding and optimize speed specially in heavy viscous wells
• Use sinker & stabilizer bars to centralize rods and keep in tension .
• Never keep pump strongly tagging down .
CORROSION TROUBLESHOOTING :
• Use corrosion resistant rod type .
• use corrosion inhibitor
MAX TENSILE TROUBLESHOOTING :
• Better rod type selection during the initial design .
• Never exceed the allowable rod load rating during trials to free stuck pump .
FATIGUE TROUBLESHOOTING :
• Re-optimize the well pumping parameters to minimize fluid pounding .

15. Sucker Rod Failures..cont’
TENSILE FAILURE
FATIGUE
Valve rod guide damage
Due to buckling

16. Heavy Oil
• Characteristics of Aghar Field Heavy Oil
- API 10-17
• PCP Vs. S/R System in Aghar Field
- Limited ability to increase the PCP parameters
- Limited well accessibility
• Applying S/R Systems in heavy oil wells
- Small Pumping Units
- Slow pumping rate Real Viscous oil problem from Well AG 4-13

17. Sand Production
PROBLEM NATURE
• When Producing Sand Up through your Production Tubing, Separation Will occur. The Heavier, More
Abrasive Sand, Will Settle Back On Top Of The Rod Pump. The Smaller, Less Abrasive Sand Will Stay
Suspended, And Be Lifted To The Surface. The heavier sand will brake up to small pieces and be carried
between the plunger and barrel.
PROBLEM REASON
• The sand particles will work their way between the Barrel and the plunger, causing abrasion cuts ,
commonly known as “sand cutting”.
• Sand Friction causes rod buckling resulting in failures.

18. Sand Production..cont’
• Two origins in AGIBA
- Formation sands/fines
- Hydraulic fractured Wells sands / propants
• Effect of sand on the total production system
- Sand friction cause rod buckling
- Abrasion/wear for the plunger “Sand Cut”
Wear of Plunger caused by sand production
Sand Cuts

19. Sand Production..cont’
Remedial Actions
• Using Top Hold Down pumps
• High Clearance Pumps
• Sand screens
- Through TBG Screens
- TBG Screens
• Re-completion

20. Stuck pumps
In AGIBA application stuck pumps which existed
only in the Bottom Hold-Down type. This BHD
creates the possibility of sand & debris
accumulating in the dead area between the
pump and the tubing wall.
Such problems was overcome by introducing the
Top Hold-Down pump instead of bottom hold
down.

21. Tubing Wear
PROBLEM NATURE
Tubing failures had longitudinal cracks with an average length of 10 ft. and all the cracks were in
the lower part of the tubing ( up to 500 ft above the pump seating nipple). This tubing interval
was located against the sinker bar portion of the sucker rod string.
• IT IS CONSIDERED AS ONE OF THE COMMON PROBLEMS OF S.R. System world-wide .
TBG. Wear due to rod buckling

22. TBG. Wear ..cont’
PROBLEM REASONS :
• Rod buckling (high speed , insuffecient sinker bar , fluid pounding , pump
tagging down ) .
• Tubing buckling (unanchored tubing or apply insufficient tension ) .
• Use sucker rod system in crooked holes .
• Free water production (represents the main critical reason Since it increases
mutual friction between rods and tubing ) .
• Presence of corrosive fluids ( enhances the erosion corrosion effect )

23. TBG. Wear ..cont’
HOW TO MINIMIZE TUBING WEARS AND CRACKS :
• Eliminate all reasons of rod buckling .
• Apply proper tension for tbg. String ( use KTH hanger ) .
• Use rod guides or wheel guides to centralize rods inside tubing .
• Use anti-friction couplings and blast joints in the hot spots .
• Apply corrosion inhibition programs .
• Minimize pumping speed .

24. WELL
NO. OF W/O DUE
TO TBG LEAK
per year
M-29 3
M-42 3
A-6 3
A-46 3
NE-36 3
M-43 3
M-57 3
A-4 5
NE-14 3
NE-25 3
SE-4 3
E-1X 3
N.NADA-8 3
FALAK-11 3
M-14 3
A-41 3
WELLS FREQUENTLY SUFFERED FROM TBG LEAK
NE-32 2
NE-43 2
M-SW-2 2
SE-20 2
FALAK-7 2
A-37 2
Z-27 2
M-33 2
M-50 4
M-18 4
M-34 4
M-37 4
M-47 4
M-52 3
A-25 3
Z-15 3
M-49 3
• The main problem lead to workover jobs in AGIBA is the tubing leak , which appears in
the form of longitudinal cracks as 2 ft length × 2cm width, caused by contineous friction
between sucker rod and internal tubing wall , especially at the last ten joints ( 300 ft )
right above the pump.

25. Rod Guides
Spiral metal guides were tested in AGIBA fields. The
experience proved that it was not an effective solution for
this condition due to the following difficulties:
a. It required fixed regular schedules for round trips to
replace the worn-out guides.
b. The installing of rod guides created much more
friction, which increased the loads and stresses in the
sucker rod string and the possibility of rod failure.
Due to high loads, there was no way to increase pumping
parameters in order to increase production.
- Valve rod guide worn-out
Due to buckling
- Metal to Metal contact
- High friction

26. Hollow Pump
WELL
PERIOD BETWEEN LAST W/O
& FIRST TBG LEAK
M-14 8 MONTHS
M-37 1 YEAR
M-47 7 MONTHS
A-4 11 MONTHS
A-5 6 MONTHS
A-34 9 MONTHS
FIELD TRIALS (HOLLOW PUMP)
Hollow sucker rod has hole in the middle
The smaller passage and the faster flow velocity can avoid the sand
deposit efficiently while use hollow sucker rod in the sand well.

27. WELL Rate W/C
PERIOD BETWEEN LAST
W/O & FIRST TBG LEAK
E - 1X 215 45 9 MONTHS
M - 37 80 55 6 MONTHS
- Using of roller guide or wheel guide , to eliminate direct contact between sucker rods and internal tubing wall.
- Applying of a KTH flange gives more tension for tubing with slips to prevent tubing buckling.

28. Rod Pump
Trouble Shooting

29. Physical Trouble Shooting Indicators
- Pressure Gages
- Hot Flow Lines
- Hot Polished Rod Load
- Sounds at the Well
- Equipment Vibrations
- Fluid on the Ground
- Ground Shakes

30. Well Head Temperature As A Relation Of Production Rate
(GOR From Zero Up To 100 Scf/Stb)
Well head temperature, oF
Productionrate,bpd
Zero water cut
Zero up to %water cut
up to %water cut
up to %water cut

31. common Techniques for Trouble Shooting
- Has Well’s Production Changed?
- Can the Pump Pressure up the Tubing?
- Is the Pumping Unit Running?
- Is there a noticeable Leak?
- Is fluid going into the tank?
- Has the Fluid Level Changed?

32. Not Recommended
- Why are not we tagging?
- Put on hand and Pump 24 hrs/day.
- Increase SPM in Order to maintain Production.
- Increase SPM because there is a Fluid Level Above the Pump.
- Pull the Well, because no Fluid in the Tank.