Tail Pipe

Key Takeaways

• Pump submergence and its relationship to pump intake pressure is the primary reason tail pipes are used in artificial lift installations: submergence is defined as the depth of the pump intake below the producing fluid level in the wellbore (the annular fluid level for rod pump installations, or the intake pressure for ESP installations); adequate submergence is required to maintain the fluid pressure at the pump intake above the bubble point of the produced oil (the pressure below which dissolved gas begins to come out of solution and form free gas bubbles in the fluid stream), because free gas entering a reciprocating pump (sucker rod pump) causes gas lock (a condition where the gas compresses and expands in the pump barrel without displacing fluid) or enters an ESP causing gas interference that reduces pump efficiency, increases vibration and motor temperature, and in severe cases causes complete loss of production through gas lock; the tail pipe extends the pump downward below the perforations or the pump hanger depth to maximize submergence by setting the pump as deep in the fluid column as the mechanical configuration of the completion allows; in wells with rapid pressure decline where the pump cannot keep up with the falling fluid level, tail pipe extension (running a longer tail pipe in a workover) is a common remedy to restore submergence and pump efficiency before resorting to a pump size change or a change in artificial lift method.
• Gas separation using a downward-extending tail pipe exploits the natural buoyancy of gas bubbles in the wellbore annulus to separate free gas from the produced liquid before the liquid is drawn to the pump intake: in wells producing above the bubble point or in wells where free gas enters the wellbore through the perforations, the annular fluid column below the pump is a mixture of oil, water, and free gas; when the tail pipe extends below the perforations and the pump is set above the perforations with a packer, the produced fluids enter the annulus below the packer through the perforations and gas naturally migrates upward through the annular fluid column while liquid falls downward to the bottom of the wellbore; the pump draws liquid from below through the tail pipe, while gas migrates up the annulus above the packer and is produced through the annular gas outlet (a ported sleeve or casing perforations above the packer); this "natural gas separator" or "annular gas separation" design is a fundamental completion concept for rod pump wells in gassy formations, and the tail pipe length and pump setting depth relative to the perforations determine the effectiveness of the separation; in wells where natural separation is insufficient (very high gas-oil ratio), downhole gas separators (rotary or vortex-type devices mounted below the pump) provide additional separation before the fluid reaches the pump intake.
• Tail pipe design in ESP installations has specific requirements related to the motor cooling, pump intake geometry, and gas handling capacity that differ from rod pump tail pipe design: ESP motors are cooled by the produced fluid flowing past the motor exterior as it moves from the perforations upward to the pump intake, which requires that the ESP assembly be oriented with the motor below the pump and the fluid intake between the motor and the pump (a geometry called "standard mount"); in standard mount ESPs, the tail pipe below the motor serves to anchor the assembly below the perforations, ensuring that formation fluid flows upward past the motor for cooling before entering the pump intake; inverted or shrouded ESP installations (used in wells where natural gas production is too high for the pump to handle without gas separation) use a shroud (a large-diameter tubing sleeve surrounding the ESP assembly) to force fluid to flow down past the pump intake and up past the motor before entering the pump, effectively extending the tail pipe function to the entire length of the shroud; the motor temperature in an ESP without adequate flow past the motor or without adequate tail pipe submergence rises rapidly above safe operating limits, triggering thermal protection shutdown and eventually causing motor insulation failure, so tail pipe sizing is critical for ESP motor longevity in wells with high gas or low flow rate conditions.
• Perforated tail pipe sections are used in wells where the produced fluid contains sand or other particulates that would damage the pump if allowed to enter freely: a perforated or slotted tail pipe section at the bottom of the tail pipe assembly acts as a coarse screen that passes fluids and small particles while blocking larger sand grains, gravel pack media, or scale fragments that have settled to the bottom of the wellbore; the slot or perforation size is selected to pass the produced particle size distribution (from particle size analysis of produced solids) while excluding the larger particles that would cause pump impeller or pump barrel wear; perforated tail pipes are simpler and less restrictive than formal sand screens but provide a degree of protection in wells with moderate sand production where full gravel pack completion is not warranted; in wells with high sand production rates, perforated tail pipes may clog rapidly as sand accumulates above the perforations and bridges across the openings, requiring the tail pipe to be pulled and cleaned or replaced in a workover; the tail pipe connection to the pump intake must maintain the same or larger cross-sectional flow area as the pump intake to avoid restriction that would reduce submergence and increase the pressure drawdown at the pump intake, potentially causing the flowing fluid to flash below its bubble point inside the tail pipe before reaching the pump.
• Tail pipe string design in multilateral or stacked completion wells requires careful analysis of the interaction between multiple producing zones and the artificial lift system: in wells with two or more producing intervals at different depths completed with a single pump, the tail pipe may need to span multiple perforated intervals, drawing commingled fluids from both zones simultaneously; commingled production through a single tail pipe and pump eliminates the ability to control the relative contributions of the two zones (which can cause the higher-pressure zone to dominantly produce and suppress the lower-pressure zone), but in low-rate wells where separate completions and separate artificial lift systems for each zone would not be economical, commingled production through a single tail pipe is the practical solution; production logging (through-tubing spinner flowmeters or PLT tools run inside the tail pipe) can identify the zonal contributions to commingled production, and chemical injection through the tail pipe (corrosion inhibitor, scale inhibitor, or paraffin inhibitor injected below the pump intake) can treat the produced fluid at the point of entry into the tail pipe to prevent scale or deposit formation inside the pump and production tubing above the pump.