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Husky Oil Operations Ltd.

Husky Oil Operations Ltd.

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Husky Oil Operations Ltd.

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  1. Husky Oil Operations Ltd. Basic Plunger Lift Training Seminar

  2. Basics Of Plunger Lift • Liquid Loading • Determine Plunger Lift Candidates • Limitations to Plunger Lift Candidates • Rules of Thumb/Load Equations • Mechanical Considerations-Successful P/L Operations • IPR • Plunger Efficiency • Equipment/Controllers • Trouble Shooting • Conclusions Introduction

  3. PLUNGER-LIFT OVERVIEW A typical system is comprised of a: Plunger Bumper Spring Lubricator / Catcher Controller/ Motor Valve

  4. PLUNGER-LIFT OVERVIEW Plunger-lift works on the principle of providing a mechanical interface between the produced liquids and the formation gas.

  5. PLUNGER-LIFT OVERVIEW Plunger travel is normally provided by formation gas stored in the casing annulus during a shut in period. As the well is opened and tubing pressure decreases, the stored gas pushes the plunger to the surface. This cycle is repeated several times a day.

  6. Liquid Loading • All gas wells, at some time during there producing life, will experience liquid loading problems • Once critical velocity is reached, the well will begin to load up regardless of how little liquid is produced • The amount of liquid produced does influence how quickly the subsequent loading up process takes

  7. Liquid Loading • Gas velocity in the tubing has dropped below the minimum required to move liquids up and out of the wellbore. • Liquids are settling in the bottom of the well tubing • Gas flow is in heads (slug flow) or bubble flow (gas bubbles through liquids) • Loads up during flow

  8. Unloading Rates – Rules of Thumb • 73.0mm Tubing @ 689 kPa Line Pressure14e3m3/day • 60.3mm Tubing @ 689 kPa Line Pressure9.9e3m3/day • 38.1mm Tubing @ 689 kPa Line Pressure6.4e3m3/day

  9. Gas Well Flow Regimes Plunger Lift Mist Slug Annular Bubble GasFlow Decreasing Gas Velocity

  10. Cycle to Liquid Loading MCFD Tubing Pressure No Liquid separation is occurring. Well is producing above critical velocity.

  11. Cycle to Liquid Loading MCFD Tubing Pressure Liquid separation is occurring but well is remaining unloaded

  12. Cycle to Liquid Loading Flow line pressure + MCFD Gas Column pressure + Liquidheadpressure = Sandface pressure Tubing Pressure Producing as bubble flow, well below critical rate.

  13. Average Inches of Differential required to unload liquids

  14. Liquid LoadingDetection • Decrease in Production • Wells being swabbed, blown down, etc. • Sales Charts • Production Decline Curves • Pressure difference between casing & tubing

  15. Liquid Loading Detection

  16. Liquid Loading Detection

  17. Liquid Loading Detection

  18. Decline Curves • Decline curves are also a great way of predicting production increases with plunger lift. You should be able to safely say you can bring production back to the normal decline.

  19. Conclusion • Minimum Flow Rate to keep low pressure gas wells unloaded can be predicted • A primary source of fluid load can be condensed water • Such variables as temperature, gas & fluid gravity have little effect on the critical rate, whereas wellbore diameter and pressure have a direct and significantimpact Liquid Loading

  20. Determining Plunger Lift Candidates • Well unloads against line pressure • A plunger will keep a well in this condition longer with only minimum shut in periods • Well will unload against line pressure with shut in • Plunger will decrease shut in and reduce operating Bottom Hole Pressure. • Well has to be vented periodically to unload liquid slug • Plunger will eliminate venting some or all of the time • Plunger will eliminate gas loss if venting is required

  21. Determining Plunger Lift Candidates • Well has to be equalized and unloaded to a tank • Can be set up to automatically equalize every cycle. • Gas Injection • Can add plunger and greatly improve lifting efficiency and reduce injection gas required • Smaller tubing has been installed to maintain flow rate • Possible to plunger lift smaller tubing • Most cases can remove smaller tubing and plunger lift original tubing string

  22. LimitationsDetermining Plunger Lift Candidates • Insufficient Gas Volume/Pressure • *Liquid Volumes Greater than 16m3/day* • Mechanical (Separator, Restrictions, etc.) • Deviations Greater than 60 degrees • Gas/Liquid Ratio (GLR) is not adequate

  23. Does the Gas to Liquid Ratio (GLR) meet the minimum requirements? • 250m3/m3/1000m of lift depth • GLR Calculation – fluid rate per day / gas rate per day • Does the shut in well pressure to line pressure ratio meet minimum requirements? • Slug size of 50% (.5) of the difference between Casing Pressure & Sales-Line Pressure (Load Factor Equation) • Slug size is the difference between Casing Pressure and Tubing Pressure during shut in CANDIDATE SELECTION: IS PLUNGER LIFT APPROPRIATE?

  24. Conservative Rule of Thumb 250m3(.25e3m3) / m3 / 1000m Depth Example: 1.6m3 per day @ 650m Depth Min. Gas Requirements = 260m3 or .26e3m3 Slim Hole or with Packer in Well 500 m3(.5e3m3) / m3 / 650m Depth Example: 1.6m3 per day @ 650 Depth Min. Gas Requirements = 520m3 or .52e3m3

  25. Load Factor Equation Load Factor Equation = [CP – TP]/[CP – LP] • Slug size of 50% of the difference betweenCasingPressure & Sales-Line Pressure (Load Factor Equation) • If calculated value is .5 or less, should have enough pressure to surface plunger

  26. Determining Slug Size In 60.3mm Tubing 1m3 of liquid = 496m (see tubingtables) Tubing Pressure= 3448 kPa Casing Pressure= 2069 kPa 1379kPa /9.8 kPa/m = 141m of fluid in tubing 141/496 = .284 m3 Slug OR: 141 x .00202 = .284m3 (.00202 tubing capacity for 60.3mm tubing, refer to tubing tables)

  27. Pressure Requirements Once slug size has been determined, do you have enough pressure to operate plunger? Required Casing Pressure = (Slug Hydrostatic/50%) + Maximum Line Pressure Example: Required Casing Pressure = 1379kPa slug / .5 + 689kPa Required Casing Pressure = 3448kPa

  28. Rule of Thumb Tubing Size : Volume of Liquid / 1000m 52.40mm 1.54m3 60.3mm 2.00m3 73.00mm 3.02m3

  29. Determining Slug Size

  30. Mechanical Considerations • Well Head • Valves on well head must be full bore equal to the tubing size to allow plunger passage • Some valves are slightly oversized. • Can cause plunger to stall if traveling slowly. • Plunger must reach lubricator for the Arrival Sensor to sense arrival

  31. Effect of Wellhead ID on Plunger Lift Large changes in wellhead ID may cause the plunger to get caught in the wellhead or cause the plunger to stall. Some sample dimensions show the difference in one type of pad plunger’s OD’s and tubular/valve ID’s. Tubing Plunger Valves (ID) (Max OD) (ID) 2-3/8” 1.995 2.000 2.063 2-7/8” 2.441 2.450 2.563 3-1/2” 2.992 2.936 3.063 For 2-3/8” Tubing 2.063” Plunger/Pads Various Wellhead ID’s Cross-section of Plunger in Wellhead 1.995”

  32. Mechanical Considerations • Tubing • Must be continuous I.D. • Holes in tubing • Nipples • Packers • Crimps • Scale • Etc.

  33. Mechanical Considerations • Tubing • Unacceptable tubing will usually prevent successful plunger lift operation. • Worn or Degraded Tubing (Rod Cut) • I.D. Variations (Out of place nipples, blast joints, mixed strings) • Should review well records to determine if tubing is acceptable.

  34. Mechanical Considerations • Tubing Needs to be Gauged Tubing O.D. Min. Gauge O.D. Gauge Length Minimum 73.0mm 58.72mm 50.8mm 60.3mm 48.26mm 50.8mm 52.4mm 41.40mm 50.8mm 48.3mm 38.10mm 50.8mm 42.2mm 31.75mm 50.8mm

  35. Mechanical Considerations • Tubing Size • Once smaller tubing is loaded, much more difficult to unload (hydrostatic pressure vs. surface area) • Installed to early can actually act as downhole choke • Causes increased bottom hole pressure • Only temporary solution • Safety concerns when plunger lifted

  36. 1.66" 2-3/8" • Hydrostatic pressure • In 60.3mm pipe, .16m3 of water = 79m • 79m x 9.8(gradient of water)= 774 kPa hydrostatic pressure • In 31.75mm pipe, .16m3 of water = 195m • 195m x 9.8(gradient of water)= 1911kPa hydrostatic pressure • In 31.75mm pipe, .06m3 of water = 76m • 76m x 9.8(gradient of water)= 744kPa hydrostatic pressure • Surface Area • In 60.3mm pipe, it takes 744kPa to lift .16m3 of water. (76m of water) • In 31.75mm pipe, it takes 1911kPa to lift .16m3 of water. (195m of water) 76m of water in 31.75mm pipe = .06m3 • In 31.75mm pipe, it takes 744kPa to lift .06m3 • of water. (76m of water) Siphon / Velocity String Examples

  37. Mechanical Considerations • Surface Equipment • Separator Capacities • Instantaneous Rates • Fluid • Gas • Dump Valves (Trim Sizes) • Chokes, Elbows, Etc. • Orifice Plate Sizing

  38. Mechanical Considerations • Surface Equipment • Pressures should be monitored from the wellhead through all surface equipment to the sales point. • This allows you to detect restrictions and leaks • Leaks upstream of motor valve will not allow for a good static pressure buildup • Leaks can allow liquid entry into the wellbore during shut in

  39. "The producing tendency of plunger lift is directly opposed to that of the well. Plunger lift requires an increase in casing pressure for increased production whereas the well itself requires a decrease in casing pressure for increased production. The compromise that always yields the greatest production is found when cycling the plunger at the maximum frequency possible without killing the well." J.D. Hacksma, 1972, User's Guide to Plunger Lift Performance

  40. Typical Gas Well – IPR Curve (Inflow Performance Relationship) Higher Pressure Gas Well Lower Pressure GasWell

  41. Inflow Performance Relationship • Outflow Performance • Factors that hinder outflow performance • Controllable , not cost effective to change • Friction • Tubing • Flow Lines • Valves & Fittings (elbows, tees, etc) • Line Pressures (fluctuating) • Tank & Separator Capacities (Within reason)

  42. Inflow Performance Relationship • Outflow Performance • Factors that hinder outflow performance • Controllable – more cost effective to change • Well Head Back Pressure • Pinched Flow Lines • Chokes • Motor Valve Trim/Wafer Trim Size • Dump Valve Trim • Orifice Plate Sizing • Tank & Separator Capacities (Within reason)

  43. Gas Slippage is defined as gas that slips or blows by the plunger during ascent. • Liquid Slippage is defined as liquid fall back by plunger during ascent. • Gas & Liquid slippage are minimized at optimum velocities • If plunger is running too fast, plunger can be pushed through part or all of liquid slug • Mechanical problems can occur when plunger travels too fast • High velocities are a result of too much casing pressure and/or not enough fluid on top of plunger • High velocities may be required for low GLR wells • Much slower velocities are best for higher GLR wells Plunger Efficiencies

  44. Gas Slippage is defined as gas that slips or blows by the plunger during ascent. • Liquid Slippage is defined as liquid that falls back by plunger during ascent. Continued • Slower than optimum velocities can result in gas slippage around plunger • Velocities as low as 122 – 152 MPM are common & desirable Plunger Efficiencies

  45. Well performance and conditions should factor in to your decision on what type plunger to use: • Limited Gas – Often requires best sealing type plunger • Rod Cut Tubing/Scale Build up – Brush • Paraffin or Hydrate – Multiflex – Fishbone solid • High Viscosity Oil – Internal Bypass • High Liquid Volume with Minimum Shut In – Plunger that can get back to bottom as quickly as possible – Internal Bypass • High GLR – UltraFlex, Miniflex, Dual Pad, etc Plunger Efficiencies

  46. Minimum Efficient Rise Velocities (MPM) Approximate • UltraFlex 122 – 183 • FiberSeal 122 – 183 • Duoflex 198 – 244 • Miniflex 229 – 259 • Fishbone 229 – 259 Plunger Efficiencies

  47. Initial Off Times settings should be long enough to insure: • Plunger has time to completely reach bottom • Sufficient pressure build up time to surface plunger with accumulated slug • Average Plunger Fall times are: • Ultra-Flex 46 – 55 MPM • FiberSeal 46 – 55 MPM • Bar Stock 91 – 122 MPM Plunger Lift Cycles

  48. At Kick Off -Shut In on Arrival with minimum Off Time for low GLR wells or short Afterflow times for higher GLR wells • When starting a well after installation, first determine what the minimum off time is, ie: plunger fall time plus pressure build up time. • Once that is established, afterflow can be extended. • These two conditions should equate to the maximum gas production for the well. EACH WELL IS DIFFERENT AND WILL RESPOND DIFFERENTLY!! Plunger Lift Cycles

  49. Rule of Thumb • Low GLR • Short or No Afterflow • High GLR • Longer Afterflow • On initial kickoff, very common to start with too much afterflow, be conservative • Allow well to clean up • PLEASE BE PATIENT – Let the formation dictate how much it will give up. Especially if the well has been flowing in a LOADED condition for an extended period of time. Plunger Lift Cycles

  50. Cycle times may have to be adjusted for several reasons • Well has cleaned up and gas production has increased • Cycles and plunger style may have to be adjusted because of sand production • After flow may need to be adjusted because of tail fluid • Flow control may be necessary to maintain good measurement and still get the most production from the well • Sync Mode to accommodate multiple wells in one facility Plunger Lift Cycles