What's new in production

	Vol. 230 No. 12
JAMES F. LEA, CONTRIBUTING EDITOR, with O. LYNN ROWLAN

Advances in plunger lift optimization

Liquids begin to accumulate in the tubing in gas wells when the gas velocity drops below the critical rate required to lift liquids. Plunger lift is a popular method used to produce the accumulated liquids, thereby reducing the extra pressure that restricts the flow of gas.

In the most conventional method of plunger lift, the plunger falls back into the well only if the well is shut in. The cycle starts with the plunger on the bumper spring at the bottom of the well, with some liquid column above it. A controller opens a valve at the surface, lowering tubing pressure to the line pressure. The casing gas expands as the pressure drops, pushing the plunger and accumulated liquid (most of it, if plunger is not worn) to the surface. The liquid is expelled and gas flows. When the tubing gas flowrate drops and liquids begin accumulating in the tubing, the surface valve is shut in. The shut-in time must be long enough for the plunger to fall through the gas and then through the accumulated liquids and land on the bumper spring. When the required casing pressure is reached, the well is opened and the cycle is repeated.

Another method uses a plunger that can fall against gas flow. This type of plunger either has an internal valve or consists of two pieces, with a ball that seals in the bottom of a sleeve. The cycle is similar, but there is only a short shut-in time of a few seconds to cause the plunger to fall. The well is reopened, and the device falls against the flow. When a valve plunger hits the bottom of the well, or a two-piece plunger combines at the bottom of the well, the plunger starts back up the tubing with the liquid above it. This system works better early in the life of a loaded well and allows higher production rates due to less shut-in time.

The plunger must stay at the surface long enough to allow liquids to accumulate in the well, and the well must be shut in long enough for the plunger to fall through the gas and liquids accumulated. To optimize this process, it is useful to be able to track the plunger’s position. A few new developments are described here that allow such tracking.

To determine when the plunger has reached bottom, the plunger can be tracked acoustically falling through the gas and the gasified liquid accumulated at the bottom of the well. The operator uses the minimum shut-in time to program the controller, to ensure that the plunger has fallen to bottom before opening the well. If the plunger is not on bottom, it can return to surface with no liquids or a small portion of accumulated liquids, leading to damage and/or well loading.

Echometer has a development that does not require any downhole intervention and allows accumulation of fall rates for typical plungers to assist in setting minimum plunger shut-in times. Also, Production Control Systems (PCS) supplies a “smart plunger” that is instrumented internally and records pressure and temperature. The recorded data can be played back to indicate plunger fall rates and other diagnostic information. If desired, it can even be held at bottom to allow a pressure buildup test.

Tracking a plunger helps determine how the plunger may fall in a deviated or “S”-shaped well. This data is somewhat new to the industry, and is needed for optimal plunger operation.

Fall rates can be used to indicate a hole in the tubing, which is very common in plunger operations and can lead to poor cycling and lost production. The plunger will fall faster above a hole and slower below a hole if there are liquids in the bottom of the well. The surface tubing pressure will increase by a few psi as the plunger falls past a hole. By tracking the plunger, the operator can use this change in pressure to locate the hole.

Another way to confirm a hole location is by “shooting a fluid level” down the casing and down the tubing (once liquids have settled downward); an upkick at the same depth from the tubing/casing shots indicates the hole location.

If a flowing well appears to have begun liquid loading, it is desirable to verify that a hole in the tubing is not the problem before taking action to remove liquids. It is now possible to quickly shut in the well and “shoot a fluid level” down the tubing and casing annulus. The difference in the heights of the gaseous liquid column and tubing fluid gradient are used to confirm the amount of backpressure due to the liquid loading.

An alternative to using an acoustic instrument is to run a wireline pressure survey down the tubing, but this requires intrusion into the well. Using existing methods, it is possible to determine if liquids are present, plus how much pressure the liquids are exerting on the well’s productive zones.

Some simple but effective diagnostic spreadsheets are available to determine the amount of liquid to be lifted each cycle, the casing pressure needed to lift an amount of liquid at the appropriate velocity, and the maximum amount of liquid that can be lifted per day. By using the pressure required to lift liquids, one can estimate how long the plunger may last before compression is needed, and the casing operating pressure needed for a given liquid rate.

There are many electronic controllers that can open when prompted by time, casing pressure buildup, tubing pressure buildup, values of the load factor just before opening the well, use of a mathematical model of the plunger system, and other variables. Similarly, electronic controllers can shut the well in based on time, tubing pressure falloff, casing pressure falloff, a drop across a line restriction, or low flowrate. Determining if the plunger is being operated in an appropriate rise velocity window can assist all control methods. The use of electronic controllers has allowed the more widespread use of plunger lift in recent years.