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14/218 ARTIFICIAL LIFT METHODS
the plunger nears the surface, the liquid on top of the from decline curve analysis. Gas and oil reservoirs typically
plunger may surge through the system, causing spikes in have predictable declines, either exponential, harmonic, or
line pressure and flow rate. This continues until the plun- hyperbolic. Initial production rates are usually high enough
ger reaches the surface. After the plunger surfaces, a large to produce the well above critical rates (unloaded) and
increase in flow rate will produce higher tubing pressures establish a decline curve. When liquid loading occurs, a
and an increase in flowline pressure. Tubing pressure will marked decrease and deviation from normal decline can
then drop very close to line pressure. Casing pressure will be seen. By unloading the well with plunger lift, a normal
reach its minimum either on plunger arrival or after, as the decline can be reestablished. Production increases from
casing blows down and the well produces with minimal plunger lift will be somewhere between the rates of the
liquids in the tubing. If the well stays above the critical well when it started loading and the rate of an extended
unloading rate, the casing pressure will remain fairly con- decline curve to the present time. Ideally, decline curves
stant or may decrease further. As the gas rate drops, would be used in concert with critical velocity curves to
liquids become held up in the tubing and casing pressure predetermine when plunger lift should be installed. In this
will increase. manner, plunger lift will maintain production on a steady
Upon shut in, the casing pressure builds more rapidly. decline and never allow the well to begin loading.
How fast depends on the inflow performance and reservoir Another method to estimate production is to build an
pressure of the well. The tubing pressure will increase inflow performance curve based on the backpressure equa-
quickly from line pressure, as the flowing gas friction tion. This is especially helpful if the well has an open annu-
ceases. It will eventually track casing pressure (less the lus and casing pressure is known. The casing pressure gives
liquid slug). Casing pressure will continue to increase to a good approximation of bottom-hole pressure. The IPR
maximum pressure until the well is opened again. curve can be built based on the estimated reservoir pressure,
As with most wells, maximum plunger lift production casing pressure, and current flow rate. Because the job of
occurs when the well produces against the lowest possible plunger lift is to lower the bottom-hole pressure by remov-
bottom-hole pressure. On plunger lift, the lowest average ing liquids, the bottom-hole pressure can be estimated with
bottom-hole pressures are almost always obtained by shut- no liquids. This new pressure can be used to estimate a
ting the well in the minimum amount of time. Practical production rate with lower bottom-hole pressures.
experience and plunger lift models demonstrate that lifting
large liquid slugs requires higher average bottom-hole 14.5.2.2 GLR and Buildup Pressure Requirements
pressure. Lengthy shut-in periods also increase average There are two minimum requirements for plunger lift
bottom-hole pressure. So the goal of plunger lift should operation: minimum GLR and buildup pressure. For the
be to shut the well in the minimum amount of time and plunger lift to operate, there must be available gas to
produce only enough liquids that can be lifted at this provide the lifting force, in sufficient quantity per barrel
minimum buildup pressure. of liquid for a given well depth.
What is the minimum shut-in time? The absolute min-
imum amount of time for shut-in is the time it takes the
plunger to reach the bottom. The well must be shut-in in 14.5.2.2.1 Rules of Thumb As a rule of thumb, the
this length of time regardless of what other operating minimum GLR requirement is considered to be about
conditions exist. Plungers typically fall between 200 and 400 scf/bbl/1,000 ft of well depth, that is,
1,000 ft/min in dry gas and 20 and 250 ft/min in liquids. GLR min ¼ 400 D , (14:23)
Total fall time varies and is affected by plunger type, 1,000
amount of liquids in the tubing, the condition of the tubing where
(crimped, corkscrewed, corroded, etc.), and the deviation GLR min ¼ minimum required GLRforplunger lift, scf/bbl
of the tubing or wellbore. D ¼ depth to plunger, ft.
The flow period during and after plunger arrival is
used to control liquid loads. In general, a short flow Equation (14.23) is based on the energy stored in a com-
period brings in a small liquid load, and a long flow period pressed volume of 400 scf of gas expanding under the
brings in a larger liquid load. By controlling this flow hydrostatic head of a barrel of liquid. The drawback is
time, the liquid load is controlled. So the well can be flowed that no consideration is given to line pressures. Excessively
until the desired liquid load has entered the tubing. A well high line pressures, relative to buildup pressure may in-
with a high GLR may be capable of long flow periods crease the requirement. The rule of thumb also assumes
without requiring more than minimum shut-in times. In that the gas expansion can be applied from a large open
this case, the plunger could operate as few as 1 or 2 cycles/ annulus without restriction. Slim-hole wells and wells with
day.Conversely,a wellwith alow GLRmaynever beable to packers that require gas to travel through the reservoir or
flow after plunger arrival and may require 25 cycles/day or through small perforations in the tubing will cause a greater
more. In practice, if the well is shutting in for only the restriction and energy loss. This increases the minimum
minimum amount of time, it can be flowed as long as requirements to as much as 800–1,200 scf/bbl/1,000 ft.
possible to maintain target plunger rise velocities. If the Well buildup pressure is the second requirement
well is shutting in longer than the minimum shut-in time, for plunger operation. This buildup pressure is the bot-
there should be little or no flow after the plunger arrives at tom-hole pressure just before the plunger begins its ascent
the surface. (equivalent to surface casing pressure in a well with
an open annulus). In practice, the minimum shut-in pres-
sure requirement for plunger lift is equivalent to 1½ times
14.5.2 Design Guideline maximum sales line pressure. The actual requirement may
Plunger lift systems can be evaluated using rules of thumb be higher. The rule works well in intermediate-depth wells
in conjunction with historic well production or with a (2,000–8,000 ft) with slug sizes of 0.1–0.5 barrels/cycle. It
mathematical plunger model. Because plunger lift installa- breaks down for higher liquid volumes, deeper wells (due
tions are typically inexpensive, easy to install, and easy to
to increasing friction), and excessive pressure restrictions
test, most evaluations are performed by rules of thumb.
at the surface or in the wellbore.
An improved rule for minimum pressure is that a well
14.5.2.1 Estimate of Production Rates with Plunger Lift can lift a slug of liquid equal to about 50–60% of the
The simplest and sometimes most accurate method of difference between shut-in casing pressure and maximum
determining production increases from plunger lift is sales line pressure. This rule gives