Modern completion techniques have greatly increased the production rate capability of wells. Many wells have the potential to produce more liquid and gas, but the use of tubing anchors in certain wellbore locations chokes the gas flow up the casing and results in increased back pressure against the formation that restricts production from the well. A gaseous liquid column can form above the tubing anchor and cause high pressure in the gas below the tubing anchor that restricts the liquid and gas flow from the reservoir.
Often times, low pump fillage and low production rates are blamed on a poor gas separator when actually the separator is operating efficiently and is separating the liquid from the gas. In the condition described, all of the liquid in the wellbore below the tubing anchor falls to the pump and is being removed by the pump. The problem is that high pressure in the gas column below the tubing anchor is restricting production from the well. Additional production is available if the high pressure that is restricting production from the formation is removed. The accumulation of a gaseous liquid column above the tubing anchor indicates that liquid exists above the tubing anchor when only free gas exists from the tubing anchor down to the pump. Limited liquid production falls down the casing wall while the casing annulus is almost completely filled with gas if the pump is set below the formation.
Field testing using automated fluid level measurement equipment to perform fluid depression tests verifies that a gaseous liquid column exists above the tubing anchor and a gas column exists below the tubing anchor in some wells. This field data was acquired on several wells and is shown to verify the above analysis of the well's performance. This fluid distribution condition is not general known.
Locating the tubing anchor below the pump prevents this condition and will improve production in these wells.