1. Beam Pumping System Efficiency Improvement in Agiba’s Western Desert FieldsBy
M. Ghareeb (Lufkin Middle East)
Luca Ponteggia (Agip, Italy)
K. F. Nagea (Agiba Petroleum company)

2. AGIBA OPERATING AREAS M E D I T E R R A N E A N S E A CAIRO S I N A I
G U L F O F S U E Z
GULF OF AQABA
CAIRO
MELEIHA
W. RAZZAK
M E D I T E R R A N E A N S E A
EL HAMRA
W E S T E R N D E S E R T
ASHRAFI
100 km.
ALEX.
MATRUH
RED SEA
ZARIF
EL FARAS
RAML &
R. SW
S I N A I
FARAS SE

3. Production History of Western Desert Fields

4. W.D. Artificial Lift Systems

5. Initial Reservoir Data and Fluid Properties
For Meleiha Fields
Res Press. psi
Res. T oF
visc. cp
Pb, psia
Bo, rb/stb
Rs, scf/stb
API MW
2250
195
0.85
450
1.125
250 38
Aman
2300
196
0.8
240
1.175
100 40 NE
193
480
1.26
210 SE
2350
198
0.4
1170
1.6
790 42

6. Electrical ultra high slip 2.75” seating nipple at +/- 5000 ft
36,500 lbs
structure rating
66% loaded
912,000 in-lbs
reducer rating
61.5% loaded
75 hp
Electrical ultra high slip
motor
48% loaded
3.5” Tubing
86- H T S (N97)
sucker rods
60.3% loaded
RWBC
2.75” seating nipple at +/ ft
Tubing anchor catcher
Target production
+/ BPD / well

7. Average Static Reservoir Pressure Two Years Later What Was Happening?

8. Very Low Equipment Running Lives
Upper part of the 7/8” and in the 3/4 “string.
Fatigue failure plus unscrewed couplings
Rod parting
Down hole pump problems
Unscrewed and leaking valves
Pump stuck

9. 1988, Failures Distribution

10. The Main Factors Affecting the Equipment Performances
Fast decline in reservoir pressure
Limitations of subsurface pump design
Down hole pumps were bottom hold-down type
One size of D.H.P. restricted the flexibility
Lack of experience with sucker rod system
Mishandling of high tensile type rods
Weak monitoring system

11. Where we were in 1993?

12. Failure Analyses Failures are divided into four major categories :
Sucker Rod and polished rod failures
Down hole pump failures
Tubing wear
Surface Pumping Unit failures

13. Fatigue Failures Fatigue Failures Sucker Rod Failures
All sucker rod, pony rod, and coupling failures are either
Tensile failures (applied load exceeds the tensile strength of the rod ) or
Fatigue Failures
Fatigue Failures

14. Common Rod Failure Causes
Mishandling
Gas or fluid pound
Design problem
Wear or rubbing on tubing
Corrosion
Operating problems

15. Mishandling Improper handling during pulling and running Tools
Pull rod in double and lay down on racks
Improper coupling make-up
Low experience of pulling unit crew

17. Down Hole Pump Failure Stuck Pump
Traveling and standing valves damage (unscrew).

18. Standing Valve
Unscrew

19. Common Tubing Failure Causes
Mutual friction between sucker rod coupling and tubing inner surface
Tubing and/or sucker rod buckling
Using 1” sucker rods as a sinker bar with full size 2 3/16” coupling
The high water cut wells creates less lubrication and cooling between sucker rod and tubing

20. Coupling wear Due to tubing Movement

21. Corrective Action Reservoir support and water shut off
Acquire appropriate data and determine true cause of failure
Sucker rods
Downhole Pumps
Tubing wear
Gas Interference

22. Reservoir Support by Water Injection

23. Determining Reason For Failures
Perform failure analysis
Track failure occurrences
Execute corrective action

24. Sucker Rod Handling Pull the rods in stands and hang in the derrick
Use sucker rod power tong
Transport sucker rods in special sucker rod baskets
Pulled sucker rods are fully inspected and stored as per API standards
Translate the API standard procedures for rod handling to Arabic and train all relevant personnel

25. Used top hold-down Pump
Downhole Pumps
Used top hold-down Pump
RWAC 24-4
RHAC
RWAC 24-4
RHAC
Introduced different sizes of subsurface pumps
Upgrade pump materials

26. Modified the Insert pump Anchor

27. Where are we Today?

28. Electrical ultra high slip
Item
Size
Type
D . H. P.
RWAC
RHAC
RWAC
RWAC
RWAC
RHAC
Rod string 87
High tensile strength
(140,000 to 150,000 Ib)
Grad “D”
Rod coupling
Standard size
Class T
Tubing
3.5 “ * 9.3 Ib/ft
Surface unit
MII D – 144
MII D – 144
MII D – 144
MII D – 144
C D
Mark-II
Conventional
Prime mover
75 HP
100 HP
Electrical ultra high slip

29. Well Monitoring Service contract for Dynamometer and fluid level
Pilot test for well controller

30. Well Head Temperature As A Relation Of Production Rate (GOR From Zero Up To 100 Scf/Stb)

31. Beam Unit Maintenance by specialized crew
The Future Plan?

32. Install Well Controller

33. Conclusions As fields mature alternate solutions must be determined
Acquire appropriate data to determine true reason for failures
Continuous monitoring
Flexible operating design

34. Applicable Solutions
Proper handling techniques
Top-hold-down pumps
Reduce gas and fluid pounding
Seat pumps below perforations
Tubing anchors >3000’
Appropriate packer selection
Sinker bars

35. Team work and sharing of technology is the key of success for any improvement

36. Beam Pumping System Efficiency Improvement in Agiba Western Desert FieldsBy
M. Ghareeb (Lufkin Middle East)
Luca Ponteggia (Agiba Petroleum company)
K. F. Nagea (Agiba Petroleum company)