Are My Wells Optimized? Test!! (Dec 2016)

Gas wells producing at or near the natural decline curve, or at a high percentage of the Absolute Open Flow using an IPR curve are typically considered “optimized”.  The natural decline curve should be viewed from initial production to current, as opposed to the prior 6 to 12 months. Viewing short term decline curves can lead to production targets reflecting a liquid loaded decline curve as opposed to a natural decline curve.

If the above is unknown or unclear, the next slides suggest indicators pointing toward non-optimized wells.

Shale Tec LLC was created in 2012 to help operators optimize plunger lift capable wells. Shale Tec offers plunger lift optimization coaching, training and in-house workshops.

If your team could benefit from a deeper understanding of plunger lift to maximize production from your plunger lift capable wells, contact Shale Tec LLC today ([email protected])!

Use this simply test to determine if your plunger lift capable wells might be under-performing.

  • Conventional plungers are operated on time.
  • Remote surveillance is not implemented.
  • Venting is routinely used to surface “stuck”
  • Missed plunger arrivals occur frequently.
  • Plunger fall time is a round number (30, 50, 90 minutes).
  • Max plunger rise time is a round number (30, 60, 90 minutes).
  • For wells with afterflow, total close time is longer than fall time.
  • Plunger fall velocity is assumed the same for all wells, regardless of tubing pressure.
  • Critical velocity for horizontal wells ignores the effect of the curved tubing section.
  • Plunger fall velocities have not been verified in gas and gaseous liquid.
  • The arrival sensor occasionally issues a false signal.
  • Liquid load and lift pressure are not recorded for every plunger cycle.
  • When sufficient casing pressure to surface the plunger exists, the plunger is still falling.
  • Plunger lift capable wells are operated by swabbing, intermitting, soap or gas lift.
  • For continuous run plungers, rise velocity is unknown.
  • Optimal rise velocities for conventional plungers have not been established.
  • Casing pressure is not increasing, yet the well remains closed during the pressure build stage.
  • Trend charts are not used to identify and solve problems before production is lost.
  • Production targets are set independent of natural decline curve or IPR curve analysis.
  • Plunger lift operators learn “on the job”, without formal training.
  • When plunger problems occur, the first line of action is to call the plunger company.
  • Standing valves with pressure relief springs have not been considered for all wells.
  • The preventative maintenance plan only includes the plunger.
  • Clear responsibility of each production related personnel position has not been established (lease operator, optimizer, engineer).
  • For stronger horizontal wells and vertical wells with EOT above perforations, afterflow ends before the liquid slug following the plunger to the surface clears the wellhead.
  • Pressure transducers are not calibrated.