by m. ghareeb (lufkin middle east) luca ponteggia (agip, italy) k. f. nagea (agiba petroleum...
TRANSCRIPT
By
M. Ghareeb (Lufkin Middle East)
Luca Ponteggia (Agip, Italy)
K. F. Nagea (Agiba Petroleum company)
Beam Pumping System Efficiency Improvement in Agiba’s Western
Desert Fields
G U
L F O
F S
U E
Z
GU
LF O
F A
QA
BA
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
0 100 km.
ALEX.
MATRUH
RED SEA
ZARIF
EL FARASRAML & R. SW
S I N A
I
FARAS SE
Production History of Western Desert Fields
0
10000
20000
30000
40000
50000
60000
70000
Jan-
85
Jan-
86
Jan-
87
Jan-
88
Jan-
89
Jan-
90
Jan-
91
Jan-
92
Jan-
93
Jan-
94
Jan-
95
Jan-
96
Jan-
97
Jan-
98
Jan-
99
Jan-
00
Jan-
01
Jan-
02
Jan-
03
Jan-
04
Jan-
05
Date
Ava
rag
e D
aily
Pro
du
ctio
n, B
PD GROSS, BPD
NET, BOPD
SR85%
PCP1%
ESP13%
N.F1%
W.D. Artificial Lift Systems
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 2250 193 0.8 480 1.26 210 40
SE 2350 198 0.4 1170 1.6 790 42
36,500 lbsstructure rating
66% loaded
912,000 in-lbsreducer rating61.5% loaded
75 hpElectrical ultra high slip
motor48% loaded
86- H T S (N97) sucker rods 60.3% loaded 30-250-RWBC- 24- 4
2.75” seating nipple at +/- 5000 ft
3.5” Tubing
Tubing anchor catcher
Target production
+/- 1000 BPD / well
Average Static Reservoir Pressure
0
500
1000
1500
2000
2500
1985.5 1986 1986.5 1987 1987.5 1988 1988.5 1989 1989.5
Date
Pre
ssur
e ,P
SIA Two Years Later What
Was Happening?
•Upper part of the 7/8” and in the 3/4 “string. •Fatigue failure plus unscrewed couplings
Very Low Equipment Running Lives
•Rod parting
•Unscrewed and leaking valves•Pump stuck
•Down hole pump problems
S.Rod 55%
D.H.P 43%
Other2%
1988, Failures Distribution
•Fast decline in reservoir pressure
•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
The Main Factors Affecting the Equipment Performances
•Limitations of subsurface pump design
S.Rod 31%
D.H.P 47%
Other 23%
T. wear 21%
S.U 1%
Where we were in 1993?
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
• Tensile failures (applied load exceeds the tensile strength of the rod ) or
• Fatigue Failures
All sucker rod, pony rod, and coupling failures are either
Fatigue Failures
Sucker Rod Failures
1. Mishandling2. Gas or fluid pound 3. Design problem4. Wear or rubbing on tubing5. Corrosion6. Operating problems
Common Rod Failure Causes
• 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
Mishandling
• Stuck Pump
•Traveling and standing valves damage (unscrew).
Down Hole Pump Failure
•Standing Valve
Unscrew
• 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
Common Tubing Failure Causes
Coupling wear Due to tubing
Movement
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
Reservoir Support by Water Injection
0
500
1000
1500
2000
2500
1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006
Date
Pres
sure
,PSI
A
Water Injection
Determining Reason For Failures
• Perform failure analysis
• Track failure occurrences
• Execute corrective action
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
•Upgrade pump materials
30-250 RWAC 24-4
30-175 RHAC 24-4-2
30-225 RHAC 24-4-2
30-200 RWAC 24-4
Downhole Pumps
•Used top hold-down Pump
•Introduced different sizes of subsurface pumps
Modified the Insert pump Anchor
Where are we Today?
Item Size TypeD . H. P. 30-250-RWAC- 24- 4
30-225-RHAC- 24- 4-230-200-RWAC- 24- 4
30-175-RWAC- 24- 4-2
RWACRHACRWACRHAC
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 - 912 D - 365 – 144MII - 640 D - 365 – 144MII - 465 D - 365 – 144MII - 320 D - 365 – 144C - 912 D - 365 - 144
Mark-IIMark-IIMark-IIMark-II
Conventional
Prime mover 75 HP100 HP
Electrical ultra high slip
Well Monitoring
• Service contract for Dynamometer and fluid level
• Pilot test for well controller
Well Head Temperature As A Relation Of Production Rate (GOR From Zero Up To 100 Scf/Stb)
0
200
400
600
800
1000
1200
60 80 100 120 140 160Well head temperature, oF
Prod
uctio
n ra
te, b
pd
Zero water cut
Zero up to 20 % water cut
20 up to 50 % water cut
50 up to 80 % water cut
Beam Unit Maintenance by specialized crew
The Future Plan?
Install Well Controller
• As fields mature alternate solutions must
be determined• Acquire appropriate data to determine true
reason for failures• Continuous monitoring • Flexible operating design
Conclusions
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
Team work and sharing of technology is the key of success for any
improvement
By
M. Ghareeb (Lufkin Middle East)
Luca Ponteggia (Agiba Petroleum company)
K. F. Nagea (Agiba Petroleum company)
Beam Pumping System Efficiency Improvement in Agiba Western
Desert Fields