Advances in horizontal drilling and large fracturing technology have resulted in many more wells that produce larger volumes of oil than have been common domestically. Artificially lifting large volumes of oil and associated gas to the surface has always been a problem because of the difficulty of separating downhole oil that is to be lifted to the surface from large volumes of gas especially in rod pumped wells. Many downhole gas separators are inefficient, and the percentage of liquid in the pump is actually less than the percentage of liquid in the fluids in the casing annulus surrounding the gas separator.

This paper describes techniques for evaluating the effectiveness of downhole gas separators. Often times, the evaluation of a separator's performance is based on pump fillage and the total gas production from the well instead of the amount of gas present in the gaseous liquid column that exists in the casing annulus surrounding the pump.

This paper also describes a separation technique that diverts the formation fluids into the casing annulus above the pump inlet so that the liquids and gas can separate by gravity. A seating nipple is positioned within inches of the liquids that exist in the casing annulus surrounding the gas separator to reduce the pressure drop so that gas is not released from the oil that flows from the casing annulus into the pump chamber. If the pump seating nipple is positioned above the gas separator fluid exit ports, a pressure drop in the liquids entering the pump occurs and gas will be released into the pump chamber. Also, if the conduit or tube from the liquid in the casing annulus to the pump inlet is restrictive to flow, an excessive pressure drop occurs because of the high velocities associated with the pump plunger upward movement which often approaches 80-100 inches per second on high pump capacity wells.

The separator design can be used with a conventional packer or a special pack-off assembly consisting of elastomer rings on a tube positioned between the separator and the tubing anchor below the separator. The pressure drop across the separator is generally less than 10 psi so flexible elastomer rings can be used instead of a high pressure packer.

The separator is generally used with a tubing anchor, and the tubing anchor should be positioned immediately below the separator instead of above the separator because field data indicates that the tubing anchor can cause an accumulation of gas below the tubing anchor and considerable liquid accumulation above the tubing anchor.

A recent complicating factor that must be considered when evaluating gas separator systems is the recent use of high clearance plungers in the pump. Large plunger clearances for sand problems are common in some areas that result in pump leakage of 50 % of the pump capacity, so the pump appears to be full or almost full when actually the liquid in the pump is circulated liquid that is bypassing the plunger. Field data has been measured and obtained where the pump chamber is full, but the production in the tank is negligible. The operator may think the separator is acting efficiently when the high pump fillage results from plunger leakage and not good separator performance.

The paper describes gas separation techniques and presents field data on several types of downhole gas separators.

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