Transcript Document
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) MEDITERRANEAN SEA MELEIHA CAIRO ZARIF EL FARAS W. RAZZAK RAML & R. SW FARAS SE 0 100 km. ASHRAFI RED SEA Ja n85 Ja n86 Ja n87 Ja n88 Ja n89 Ja n90 Ja n91 Ja n92 Ja n93 Ja n94 Ja n95 Ja n96 Ja n97 Ja n98 Ja n99 Ja n00 Ja n01 Ja n02 Ja n03 Ja n04 Ja n05 Avarage Daily Production, BPD Production History of Western Desert Fields 70000 60000 GROSS, BPD NET, BOPD 50000 40000 30000 20000 10000 0 W.D. Artificial Lift Systems PCP % ESP % N.F % SR % 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 42 912,000 in-lbs reducer rating 61.5% loaded 75 hp Electrical ultra high slip motor 48% loaded 86- H T S (N97) sucker rods 60.3% loaded 36,500 lbs structure rating 66% loaded 3.5” Tubing 30-250-RWBC- 24- 4 2.75” seating nipple at +/- 5000 ft Tubing anchor catcher Target production +/- 1000 BPD / well Pressure ,PSIA Average Static Reservoir Pressure Two Years Later What Was Happening? . . . Date . . Very Low Equipment Running Lives •Rod parting •Upper part of the 7/8” and in the 3/4 “string. •Fatigue failure plus unscrewed couplings •Down hole pump problems •Unscrewed and leaking valves •Pump stuck 1988, Failures Distribution D.H.P 43% Other 2% S.Rod 55% 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? D.H.P 47% T. wear 21% Other 23% S.U 1% S.Rod 31% 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 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 Common Rod Failure Causes 1. Mishandling 2. Gas or fluid pound 3. Design problem 4. Wear or rubbing on tubing 5. Corrosion 6. 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 Pressure,PSIA Reservoir Support by Water Injection Water Injection Date 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 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? 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 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 Mark-II Mark-II 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 Production rate, bpd Well Head Temperature As A Relation Of Production Rate (GOR From Zero Up To 100 Scf/Stb) Zero water cut Zero up to % water cut up to % water cut up to % water cut Well head temperature, oF 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)