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Why GARP Works

Gas interference in the rod pump

Gas is a compressible fluid and free gas in a rod pump reduces the pump’s liquid lift efficiency since it takes up space in the pump that could have been occupied by liquids. Work performed by the pump will be used to compress the gas at the expense of pumping the liquid

  • Rod pumps are single acting and generally pump liquids only on the up-stroke. During the down-stroke, the pump chamber is filling with liquids and virtually no fluid velocity is induced in the casing annulus by the pump. Most down-hole gas separators rely on this period of no velocity for the gas to escape to the surface
  • If the cross-sectional area of the gas separator is too small for the production rate induced by the pump, gas will be drawn downward into the pump intake, i.e., the downward liquid velocity induced by the pump will be high enough to draw the gas bubbles sufficiently downward to prevent the gas bubbles from rising out of the gas separator before the “quiet” period is over
  • A common misconception is that adding length to the dip tube of the gas separator will prevent the gas bubbles from entering the pump intake. This is not true, even though it will take the bubbles longer to reach the intake
  • The best gas separators have large cross-sectional areas which lowers the downward velocity of the gas bearing liquid
  • Tubing anchors are used to prevent movement of the tubing string during the rod pumping cycle. During normal pumping operations, gas and liquids may flow around the tubing anchor (in either the up or down direction). Gas from the reservoir must travel around the tubing anchor to reach the surface. Any liquids that flow above the tubing anchor or liquids that condense from the gas in the shallower and colder regions of the well-bore must also travel around the tubing anchor to reach the pump below the anchor. The small cross-sectional area around the tubing anchor causes a restriction in the flow path. Gas may be attempting to flow up and around the tubing anchor while liquids are simultaneously attempting to flow down and around the tubing anchor resulting in a “traffic jam”, which results in a buildup of free gas below the tubing anchor that can eventually reach the intake of the pump. The buildup of liquids above the tubing anchor also increases back pressure on the reservoir.
  • High fluid level wells present new challenges to even the best gas separators since the back pressure induced on the reservoir fluids will reduce the size of the gas bubbles and thus their buoyancy. This reduction in buoyancy has a negative effect on gas separators that rely on gravity to separate the gas from the liquids. In other words, a gas separator that works great for lower fluid level wells may not work so well for a high fluid level well.

How GARP® reduces gas interference  

GARP® utilizes a specially designed tool called the Bi-Flow Sump Gas Separator Assembly which creates a sump for the pump intake. Gas breaks out of the liquids in the large cross-sectional area of the casing-production tubing annulus and the liquids are forced to fall to enter through the pump intake that is a sufficient distance below the gas break-out depth for optimum gas separation.

  • For wells with sufficient liquid levels, a conventional tubing anchor may be used if it is placed below the Bi-Flow Sump Assembly. Since the tubing anchor is placed below the pump intake, it will not be a restriction for gas or liquid flow.
  • For wells with insufficient fluid levels, a packer placed in the vertical section is recommended instead of a tubing anchor since the packer will prevent liquids from falling back down the reservoir and will give time for the rod pump to pump the liquids to the surface
  • For wells with high fluid levels, the bi-flow sump gas separator assembly can be modified to allow a higher entry point into the casing annulus. This effectively lowers the back pressure on the reservoir fluid that results in an increase in gas bubble size and an increase in gas separation efficiency of the bi-flow sump separator. Plus, if foamy oils are a problem, the distance that the oil has to travel to the pump intake will give more time for the gas bubbles to break out of the oil.

Additionally, GARP®’s patent pending solids separation and containment system (Solids Shield) is strongly recommended to be placed above the tubing anchor or packer to prevent solids from falling on top and potentially sticking them in place.

Back pressure on the reservoir

  • The differential pressure between the reservoir face and the wellbore is a major contributing factor in determining the production rate from the reservoir. The higher the pressure differential, the higher the production rate. In other words, liquids that accumulate in the wellbore above the reservoir, exert back pressure on the reservoir which lowers the pressure differential
  • Rod pumps are filled with liquids via gravity, i.e., they require a liquid level to exist above the pump. Therefore, rod pumps cannot recover stagnant liquids below the pump

How GARP® reduces back pressure 

  • For wells with sufficient gas-liquid ratios and reservoir pressure, GARP® Lite reduces back pressure by utilizing a smaller inner diameter velocity string that concentrates the reservoir gas to more efficiently lift liquids from below to above the pump
  • For wells that need extra energy to lift liquids up to the pump, GARP® with gas assist uses an additional gas injection string to provide low volume/ low pressure gas lift to raise these liquids from below the pump to above the pump
  • GARP® can reduce the back pressure on the following wells:
  • Wells with dog-legs in the vertical section that prevent deeper pump settings due to high wear on the rods
  • Horizontal/deviated well-bores
  • Wells with deep reservoirs
  • Wells with long perforated intervals
  • Wells with high set liners or casing restrictions

Stuck Pumps

  • Should the rod pump need to be pulled for any reason (ex. for routine rod pump maintenance and repair), an operator may find that the pump is stuck in the seating nipple. A solution to this problem is to un-set the tubing anchor and pull the production tubing as well, which is expensive, time consuming and carries an added element of risk
  • The main reason the pump is stuck is due to a high differential pressure that is acting on a build-up of solids on top of the seating nipple. There is a full column of liquid above the seating nipple and normally a relatively small column of liquids below the seating nipple

How GARP® can free a stuck pump

  • For GARP® installations that utilize a packer instead of a tubing anchor, an optional standing valve may be placed in the production tubing string below the packer which will allow the casing annulus to be loaded with liquids. Now the differential pressure across the seating nipple has been substantially reduced or eliminated which will aid in freeing the stuck pump
  • Works for even very low bottom hole pressure wells

Trash in the pump barrel  

  • Trash in the pump barrel may result in reduced or no production by:
    • preventing the standing valve or traveling valve from fully opening/closing
    • preventing the full loading of liquids in the pump chamber
    • sticking a plunger in place or preventing a full pump stroke

How GARP® can free a stuck pump/plunger

  • The same standing valve used above allows liquids to be circulated down the casing annulus and up through the pump barrel and production tubing; thereby potentially circulating out the trash in the pump to the surface
  • Works for even very low bottom hole pressure wells

Unintentional Load Water Injection

Many reservoirs are sensitive to water being injected into the reservoir. Some possible negative consequences:

  • Reduction in permeability
  • Reduction in production (either temporary or permanent)
  • Scale formation
  • Bacteria contamination resulting in H2S production

How GARP® solves unintentional injection issues

  • The same standing valve used above will close when load water is pumped into the wellbore, preventing unintentional injection into the reservoir

Solids issues

Wellbore solids come in all shapes and sizes and originate from the following sources

  • Drilling fines
  • Cement fines
  • Formation fines
  • Frac sand
  • Equipment debris (perforating guns, packers, rust, metal debris…)
  • Precipitates (scale, salt, etc)

Solids can be detrimental when they interfere with production operations such as plugging, sticking, or eroding down-hole equipment.

How GARP® solves solids issues

  • As part of the GARP® gas separation process, reservoir liquids are introduced into the casing annulus. Over time, even a small amount of solids in the reservoir liquids could build up on top of the packer or tubing anchor and potentially stick it in place. To prevent this from occurring, GARP® provides one or more Solids Shield(s) which trap solids before they can fall on top of the packer/anchor.
  • If a well has a history of solids causing problems in the pump, GARP® provides a method of placing a sand screen around the Bi-Flow Sump Separator that can be back-washed in-situ and the solids can be removed to the surface without pulling the screen out of the well.