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By: Gatut Widianoko ( Weatherford ) Herry Subekti ( BP – Indonesia ) PowerPoint Presentation
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By: Gatut Widianoko ( Weatherford ) Herry Subekti ( BP – Indonesia )

By: Gatut Widianoko ( Weatherford ) Herry Subekti ( BP – Indonesia )

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By: Gatut Widianoko ( Weatherford ) Herry Subekti ( BP – Indonesia )

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  1. CASING HEAD PRESSURE FINE TUNING inDual String Gas Lift WellWith Injection Pressure Operated Valve ASME – WORK SHOP - KUALA LUMPUR 2003 By: Gatut Widianoko ( Weatherford ) Herry Subekti ( BP – Indonesia ) Wahyu Jatmiko ( BP – Indonesia )

  2. Abstract After two ( 2 ) years gas lift optimization performed with concentrated in gas lift change out, starting this year 2003, Bp -Indonesia begin to focus on Casing Head Pressure Tuning. The first year, the gas lift optimization had made 3500 bopd oil gain, and the second year had made 4000 bopd oil gains. This year, up-to the second quarter 2003, BP had made 4500 bopd oil gains. This total gains is came from 40 % gas lift change out, and 60 % from Casing Head Pressure Tuning. Today we are going to talk about the steps of casing head pressure tuning of the BP-Indonesia gas lift optimization on dual string gas lift well as follow : 1) Identify the gas lift well problems ; 2) Nodal analyzing to determine the well potential ; 3) Optimize point of injection of both string by gas lift change out ; 4) Perform Tuning Casing Head Pressure to optimize both string.

  3. SUMATERA • KALIMANTAN • SULAWESI AV AVS • J A V A AA BIMA ZU APN P ARDJUNA MX LL MR E B “O” AREA POD MM MQ L BZZ MB KLY K KLX KL F ARIMBI KNA KK U O X CILAMAYA JAKARTA GG Gas Accumulation GG CIREBON 25 50 KM 0 Offshore North West Java Oil Field

  4. BP Wells General Conditions • Old Oil Field with more than 30 years old • High FGOR with 1000 : 1 or more • Low PI with only about 1 – 3 blpd / psi • Low Production with about 200 - 500 blpd • Low Static Pressure with average ~ 600 psi • Limited Casing Pressure with ~ 600 psi only • Flowing Tubing Pressure is about 180 psi • Shallow well - reservoir depth ~ 3000 ft TVD • Limited data (SBHP and PI is normally unknown) • Old wells - may have leaking valve or tubing • Some gas lift valves installed 5-10 years ago • Some gas lift header choke stuck open/close

  5. ECHO - WELLs COMPLETION DIAGRAM NOT TO SCALE 2-7/8” SSSV @ 248’ 2-7/8” SSSV @ 286’ 1012’ 1050’ 1898’ 1866’ 2-7/8” SPM 2-7/8” SPM 2625’ 2652’ 3007’ 3032’ 2-7/8” WB-1D SSD @ 3100’ Packer @ 3111’ MD 2-7/8” WB-1D SSD @ 3183’ 2-7/8” WB-1D SSD @ 3164’ EZ-22B ( Squeezed-Off ) Packer @ 3340’ 2-7/8” WB-1D SSD @ 3383’ EZ-23 ( 3389’ - 3406’ ) Packer @ 3504’ 2-7/8” WB-1D SSD @ 3584’ EZ-24B ( 3590’ - 3609’ ) Packer @ 3900’ EZ-27 ( 4016’ - 4021’ ) ( 4025’ – 4031’ ) ( 4035’ – 4043’ ) ( 4050’ – 4062’ ) PBTD @ 4205’ MD 9-5/8” Shoe @ 4285’ MD Dual Completion Find CHP problems Adjust CHP , Reduce / increase Slowly until get best production rate. Repeat it if needed. Keep best this CHP as operating pres. Great savings of time & efforts

  6. CHP Fine Tuning Candidates Wells( Gas Lift Optimization ) • Suddenly production rate drop • Suddenly the well dead • Casing Head Pressure unstable • Suddenly gas injection rate increase/decrease • Inaccurate gas rate measure • Robbing, and cause one (1) string dead or drop • The well shutdown under maintenance • The well shut-in while service status • Gas lift Change out is being perform • Suddenly Casing Head Pressure Increase • Suddenly Casing Head Pressure decrease • Suddenly Flowing Tubing Head Pressure increase

  7. Casing Head Pressure TuningSteps in Dual Gas Lift well • Use graphical method to construct the well condition. Draw the static and flowing pressure gradient, etc. • Select Kick Off and best Operating pressure available. Use 90% (max) off Kick Off as Operating pressure. • Select best point of injection of both string ( close or same depth ) and operating port size (close or same size). • Use same surface opening and closing pressure for both string valve. • Perform gas lift well performance by software on each string to determine optimum condition . • Perform CHP tuning by open the Gas Lift Header Choke and set at the kick off pressure selected. • Adjusts the CHP slowly to reach the Best Surface Operating Pressure selected. • Record the Rates. Select the best rate and keep best CHP.

  8. Graphical Method (To determine best Point of Injection, KO and OP) Echo- Wells PRESSURE (p s i) 500 1000 1500 FTP CHP 0 D E P T H Ft T V D 0.1 p s I / ft Casing Pressure FL 1000 #1 Tubing Pressure #2 2000 #3 0.45 p s i / ft #7 3000 Mid Perforation FBHP 1200 p s i 4000 Operating Pres. Kick Off

  9. Gas Lift Well Performance Gas Injection Rate Vs Production Rate Optimum Point Q l Q i Q I : Gas in Rate mscfd Q l : Prod. Rate blpd

  10. Why Do Casing Head Pressure tuning instead of Gas Injection Rate Tuning ?

  11. Gas Measurement Problems • Not each platform has a good measurement facilities • Some Gas Measuring inaccurate • Gas Injection rate not recorded • Gas in VS CHP does not make sense We Decided • Using CHP as parameter to optimize gas injection • Adjust CHP to find a best production rate of both String • Measure Gas In, after best CHP reached / selected • Record and keep best CHP of each Well

  12. WHAT IS BEST CHP Back to The Original Operating Pressure Design • Where is the existing CHP ? • Is it too high ? • Any un-loader valve reopen? • Is the existing gas in too much ? • Do We need to decrease it ? OR • Is it too low ? • Is the existing gas in too low ? • Can the existing CHP pressure reach the operating valve ? • Do we need to Increase it ? • Any actions needs to be done ?

  13. Decreasing CHP (To determine Best Operating Pressure) Existing CHP Too High Echo- Wells PRESSURE (p s i) 1500 FTP 0 500 CHP 1000 D E P T H Ft T V D 0.1 p s I / ft Casing Pressure FL 1000 #1 Tubing Pressure #2 2000 #3 0.45 p s i / ft #7 3000 Mid Perforation 1200 p s i FBHP 4000 Best Operating Pres. Kick Off

  14. Increasing CHP (To determine Best Operating Pressure) Existing CHP Too Low Echo- Wells PRESSURE (p s i) 500 1000 1500 FTP CHP 0 D E P T H Ft T V D 0.1 p s I / ft Casing Pressure FL 1000 #1 Tubing Pressure #2 2000 #3 0.45 p s i / ft #7 3000 Mid Perforation FBHP 1200 p s i 4000 Operating Pres. Kick Off

  15. Some Wells Sample of CHP tuning at BP-Indonesia Best CHP Oil Gains : 250 b o p d Best CHP : 520 p s i Sample : A

  16. Some Wells Sample of CHP tuning at BP-Indonesia 440 Best CHP Oil Gains : 70 b o p d Sample : B

  17. Some Wells Sample of CHP tuning at BP-Indonesia Best CHP Oil Gains : 80 b o p d Sample : C Best CHP : 590 p s i

  18. Sample of One PlatformCHP Tuning Results * Total Gains for one platform by CHP tuning : 150 b o p d * Gas gains is not recorded * Working Days : 10 days.

  19. Total Oil Gains by CHP Tuning YTD up to 2nd Qtr

  20. Total Oil Gains by Gas Lift Change Out YTD up to 2nd Qtr’ 03

  21. Total Oil Gains After Gas Lift Optimization YTD up to 2nd Qtr’ 03

  22. Tuning Results VS Gas Lift Change Out Results up to 2nd Qtr’ 03

  23. Well Work Percentage TOTAL GAS LIFT JOB YTD UP TO 2nd Qtr’ 03 Total Wells analyzes : 190 wells Completed by Wire line : 31 wells : 87 Wells potential : 18 Wells had optimum : 5 New wells : 44 Wells CHP Tuning : 36 Wells Needs FGS & SBHP survey

  24. Total Oil Gains After Gas Lift Optimization YTD Up to 2nd Qtr’ 03

  25. CHP Tuning – Lessons Learned ( With Injection Pressure Valve ) • Enough Kick Off (KO) and Operating (OP) Pressure to reach deepest point of injection is required • Differential pressure between KO and OP is ~10% of casing pressure, (or at least 50psi). • Use graphical method to select best point of injection and best draw down of both (200 – 500 psi) strings. • Surface opening pressure of both string are same. Use at least 10 psi less than the CHP available. • Surface closing pressure of both strings must be at least 20 psi above OP, and 30 psi less than KO • To avoid “gas robbing” - depth point of injection of both strings must be close or equal; same thing in the port size • Perform CHP tuning to reach Optimum Conditions • Watch the CHP performance and Keep it at best CHP.