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

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

Production History of Western Desert Fields

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 193 480 1.26 210 SE 2350 198 0.4 1170 1.6 790 42

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 30-250-RWBC- 24- 4 2.75” seating nipple at +/- 5000 ft Tubing anchor catcher Target production +/- 1000 BPD / well

Average Static Reservoir Pressure Two Years Later What Was Happening?

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

1988, Failures Distribution

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

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

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

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

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

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

Standing Valve Unscrew

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

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

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

Used top hold-down Pump Downhole Pumps Used top hold-down Pump 30-250 RWAC 24-4 30-225 RHAC 24-4-2 30-200 RWAC 24-4 30-175 RHAC 24-4-2 Introduced different sizes of subsurface pumps Upgrade pump materials

Modified the Insert pump Anchor

Where are we Today?

Electrical ultra high slip Item Size Type D . H. P. 30-250-RWAC- 24- 4 30-225-RHAC- 24- 4-2 30-200-RWAC- 24- 4 30-175-RWAC- 24- 4-2 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 - 912 D - 365 – 144 MII - 640 D - 365 – 144 MII - 465 D - 365 – 144 MII - 320 D - 365 – 144 C - 912 D - 365 - 144 Mark-II Conventional Prime mover 75 HP 100 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)

Beam Unit Maintenance by specialized crew The Future Plan?

Install Well Controller

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

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

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