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Unloading Water from Oil Wells Using Air

Unloading Water from Oil Wells Using Air. Background. Drilling horizontal wells in the Rocky Mountain Region Drilling operation incurred high drilling fine and fluid losses in formation

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Unloading Water from Oil Wells Using Air

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  1. Unloading Water fromOil Wells Using Air

  2. Background • Drilling horizontal wells in the Rocky Mountain Region • Drilling operation incurred high drilling fine and fluid losses in formation • Operator was using rod pumps to produce wells; Severe plugging of pumps and tubing with drilling fines common • RESULT - repeated workovers and had a consequential cost impact

  3. Clean Out Issues • Before producing wells with rod pumps, operator needed a way to • clean out drilling fines • unload large volumes of water from the formation • Different types of artificial lift methods were considered • Gas lift was determined to be best lift method when considering large volumes of fluid, producing fines, and cost

  4. Injection Gas Source • Natural gas was not available in this area • Screw compressor availability; used in this area for underbalanced drilling • Air considered as injection source • Spontaneous combustion issue • Hydrocarbons-Pressure-Temperature • HP 3000 psi / BHT 200 / high water cuts

  5. COMPRESSOR

  6. Gas Lift Considerations • Well Completion – 2 7/8” tubing inside 5 ½” 17# casing • Fluid rate range of 300 to 2500 BFPD • Screw compressors using air allowed operating pressures up to 1600 psi and injection volumes of 1.5 mmcf/day • Maintain velocities to produce drilling fines

  7. Gas Lift - First Attempts • Rig would land tubing at 2000’ • Air injection through open ended tubing and fluid produce out of casing until blown dry • Rig lowered tubing 1000’ to 1500’ and continued air injection / unloading process • Eventually air injection through tubing was at 8000’ and well clean up • Obtained good results, but at high cost

  8. Gas Lift Design Considerations • Determined annular lift to be best method to produce high fluid rates and drilling fines • 1” IPO valves inside a slimhole SPM were used due to casing constraints • Valve ports were sized to inject up to 1.2mmcf/day

  9. Operation • Drilling rig runs tubing with gas lift mandrels; rig moves off location • Compressors are set on location • Well is unloaded and monitored until solids were cleaned out and a percentage of oil was seen • Workover rig is moved in to pull tubing and remove gas lift mandrels; tubing and rods are run in well for rod pump operation • Gas lift mandrels are used for next well

  10. Pit Gator

  11. Problems / Maintenance • Corrosion inhibitor plugged IPO valves • Due to environment of injecting air, equipment life was shortened • Side pocket mandrels were replaced every 15 to 20 wells; valves replaced every 3 wells • Trained operator to pull and run IPO valves in side pocket mandrels; valve and latch stock is kept at field location

  12. Results • Unloading process is shortened • Greater rod and pump life • Improved wellbore deliverability • Flow back helps optimize rod pump design

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