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DISCOVERING LIQUID LOADING IN THE COTTON VALLEY

DISCOVERING LIQUID LOADING IN THE COTTON VALLEY. “27 YEARS “. OF PRODUCTION. History. Over the years we have tried Soap, Compression, Velocity Strings, Cycling, Plungers, etc.. In the past our most successful method was Compression and Hand Cycling.

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DISCOVERING LIQUID LOADING IN THE COTTON VALLEY

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  1. DISCOVERING LIQUID LOADINGIN THE COTTON VALLEY “27 YEARS “ OF PRODUCTION

  2. History • Over the years we have tried Soap, Compression, Velocity Strings, Cycling, Plungers, etc.. • In the past our most successful method was Compression and Hand Cycling. • In 1994 we did a study at one of our fields and found 1.2 BCF of gas in one year shut in for buildup

  3. CORE COMPETENCIES • Created Core Competencies that did not exist • before in the Cotton Valley. • We started from scratch • Recognize liquid loading (denial ) (deferred) • Pilots with Plungers, Soap, Injection stringers, • Coil, Created support, Formed one Team which • works out of a central, control room • We continue to shorten cycle time on new Ideas • and new Technology to implementation • We tried several methods of Deliquification

  4. Is there any one best way to de-water your gas wells? • BP Wells in East Texas 790 • Hand or no Deliquification 224 • Intermitters 200 • Plungers 290 • Injection Strings 32 • Velocity Strings 30 • Pumping Units 12 • Compressors 68 • Casing Tbg Controllers 2

  5. Methods of DELIQUIFICATIONin the Cotton Valley • “Winging in well” over night • Putting well in low pressure system (Compression) • Intermitter valves using automation • Coiled TBG • Injection Strings • Soap Stick Droppers • Injecting soap down the Backside • Plungers

  6. Does each method get the same results on each well?

  7. Any Oil Company Installed Plunger

  8. Cotton Valley Plunger Installation

  9. Issues that effect Plunger operations • Facilities- Can your facility handle large swings in rate (speed control, by pass, and suction control) • Are your tubulars and well head the right size and condition • Do you or your peers have the right training (Critical Velocity, Liquid loading understanding, etc.) • Do you have the tools you need?

  10. ReliabilityA Critical Part lSlug Flow Focus *Speed Control *Tail Chaser *Suction Control Valve

  11. – Severe Loading Hourly Daily Monthly Data

  12. Plunger installed Typical Plunger Operation

  13. What is the Approximate Critical Rate for : 100 PSI Tubing 2 3/8 Tubing 660 MCFD 480 MCFD 380 MCFD 150 MCFD

  14. Lowering Production Tubing

  15. Wells Lost to Loading

  16. Carthage Pettit Production Vastar Flat Decline – 6,000 MCFD BP 1,500 MCFD Target – 4,000 – 8,000 MCFD Low Decline Rate, But Low Activity Level Peer Oil Company 20,000 MCFD 6,000 MCFD

  17. IPR Performance Curve

  18. Low BHP (<200psi) ReservoirOperations to Increase Production • Lower Suction Pressure “0” • Rotary Compressors • Other Modern Low “0” Pressure Compressors • Pumping Units to Remove Water/Condensate • Plungers in some Wells • Acid Stimulation • Add to Well Density

  19. BP – 1st Beam lift on Pettit Well

  20. Wellbore

  21. Velocity Strings 7 Coil installations result In sustained rate Increase. Projects payout < 6 months @$2/MCF. Payout in <3 months @$4/MCF.

  22. Velocity String

  23. Coil installation resulted in sustained rate Increase of +/- 40 MCFD. Cost was +/- $12M. Payout in < 6 months @$2/MCF. Payout in < 3 months @$4/MCF. Install 1-1/2” coil

  24. Install 1-1/4” coil

  25. Compression Install 1-1/4” coil

  26. IPR Plot of Coil Tubing Performance

  27. Selection of Deliquification Method • There is no generally accepted method • There are many factors to consider • This could be subject of best practice… API or otherwise • Consideration of some factors can lead to improved selection • Some (not all) important factors considered here

  28. Some Popular Methods • Electrical submersible pumping • Progressing cavity pumping • Beam pumping • Hydraulic pumping • Gas lift • Velocity strings • Compression systems • Plungers • Foaming • Injection systems

  29. Artificial Lift Selection Process • Make a Rough Cut with Artificial Lift Screening Criteria • Review Feasibility / Functionality of Artificial Lift Methods • Evaluate Cost --- CAPEX, OPEX • Consider Availability, Use of Reservoir Energy • Consider Availability of Required Infrastructure • Consider Availability of Required Operator Training

  30. Artificial Lift Selection • Method CAPEX Elec Line Reser Oper • ESP 115,000 Y L • PCP 35,000 Y M • Beam 45,000 Y M • Hydraulic 45,00 Y M • Gas lift 25,000+ Y M • Velocity String 10,000 Y L • Compression 20,000 Y M • Plungers 7,500 Y M-H • Foaming 10,000 Y H • Injection 40,000 Y L

  31. Increase Rate above Critical with Gaslift, Velocity String, Compression or Foam

  32. Estimate Operating Power Cost from Efficiency Definition • Operating Costs: • Power efficiency may be defined as: as a fraction of the power used to lift liquids divided by the total power supplied. • Assume 20hp load for all methods (when applicable), 4000’ lift, 20 bpd, sp gr =1.0 and efficiency as defined below. Assume 200 bpd for high rate lift methods. • kW = .00000736 x 20 x 4000 x 1.0 x 0.746/  = 0.4356/ • Assume electrical costs of $0.08/ (kW-hr) • $/year = 0.4356 x 0.08 x 365 x 24 /  = 305 /  • $/year  300/ for low rate case of 20 bpd • $/year  3000/ for high rate case of 200 bpd

  33. Screening of Artificial Lift Methods Artificial Lift Screening for Deliquification of Gas Wells Legend: ++ Very well suited for this situation + Well suited for this situation +/- May be OK, depending on details - Poorly suited for this situation -- Very poorly suited for this situation Table 1: Screening matrix for lift methods designed to lift liquids off gas wells.

  34. Selection from Depth-Rate Charts High Rate Lift Rate vs: Depth After Weatherford

  35. Low Rate Lift Rate vs: Depth After Weatherford

  36. Gas Lift, High-Liquids, Velocity String, Compression, Foam Gas Lift, Low Liquids ESP, PCP, Beam, Hyd Recip, Injection Drawdown Plungers Rate Inflow / Outflow for Various Lift Methods

  37. Selection from Decision Tree Examples Presented

  38. Figure 4: An older selection chart developed for AL selection for gas wells in East Texas

  39. Evaluation of Feasibilityof Different Artificial Lift Methods

  40. ESP’s • ESP’s operate from shallow depths to as deep as 10,000’ and deeper. • They can produce low rates but below about 400 bpd, the efficiency of the system suffers. • They can produce 20,000 bpd in some cases. • High temperatures can be a problem with a typical maximum of 275 oF up to 400 oF with special trim. • They are installed in deviated wells, but the unit must be landed such that it is straight even if the wellbore is deviated. • Power must be available and is transmitted down a three phase cable to the motor. • Small disposable units are used for shallow wells such as for coal bed methane to lift water off the coal seams. • High solids concentrations may cause the unit to fail if they are allowed to be pumped, although special abraision resistant units can be used.

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