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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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