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That pretty much sums it up in the oil business. Technically,
onshore producers are actually in the water business, with oil and gas as a
minority (volumetrically) stream. Over 18 billion barrels of brine are produced
from domestic oil and gas wells annually. Virtually all oil wells and most gas
wells will require artificial lift sooner or later. Published Energy Information
Administration data on onshore operating costs show that half of the onshore
operating expenses are spent lifting fluids, primarily in fuel and electricity
and downhole maintenance. Reducing those expenses was a focus at the
Southwestern Petroleum Short Course, held April 26th - 27th in Lubbock. This
article excerpts insights about reducing downhole costs, specifically those on
plunger lift and rod pump, and the cost of electricity. The conference website (www.peresearch.pe.ttu.edu/
SWPSC/abstracts/abstracts
Received.html) provides abstracts of the 42 papers presented.
Full conference proceedings are available for $55 (ronda.brewer@
ttu.edu). For other references, PTTC has prepared a concise
manual for water management for download (ww.pttc.org/pwm/
produced_water.htm).
Plunger Lifts
The first question to be considered with gas wells that also
produce liquids is: Do I need a plunger? Bob Petree with BP presented a
checklist for a gas well with declining or ceased gas production. There can be a
number of causes for a departure from the normal decline rate, and likewise a
number of solutions. Gas production is dramatically reduced when the pressure
differential between the formation and the wellbore is insufficient to allow the
gas to enter the well. The reduced pressure differential can be as simple as
reservoir pressure depletion, or wellbore problems such as scale, paraffin or
mechanical obstructions.
The first
screening tool to determine if the well is capable of lifting the produced
fluids is to compare the flow rate with the critical velocity, which is easily
determined from available charts for any given bottomhole pressure and tubing
size. (Figure 1) A well near or below its critical pressure is probably loading.
A second symptom of loading can be detected by
comparing the pressure
differential between the casing and tubing while the well is still flowing over
time. As the tubing becomes loaded with fluid there is a compensating buildup of
casing pressure. A
combination of
increasing pressure differential and a well approaching its critical
pressure indicates a good
plunger lift candidate. Petree suggests other confirming steps: |
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The well must produce enough energy to
raise the plunger and fluid. A rule of thumb for the
ordinary plunger is 400 cf/bbl of liquid per 1,000 ft.
depth of well. Anything above that is capable of moving
the plunger.
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The well must be clear of all
obstructions, mechanical or deformation problem with the
tubing or paraffin and scale. These must be removed as
they may actually be causing or contributing to the
loading and will also prevent proper plunger operation.
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The well can be batch treated with a
viscosity-reducing agent, such as a liquid foamer. If it
improves the production, it is a sign of loading and
might provide a less expensive stop gap to the plunger.
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If the well is swabbed and returns to
normal production, it is a clear indication of loading
and in addition can provide information on the unloaded
flow rate.
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Measuring fluid gradient can provide
information on the location of the gas-fluid contact,
but may not give a clear indication if the well is
slugging.
Plunger lift is a relatively simple,
effective and low cost technology to lift fluids, but
equipment selection and operation are critical to the
optimization of production. A plunger installation costs $5
- $10,000 and can be maintained for $1,000/year. The plunger
does not use external power, rather it is an intermittent
device that uses built up reservoir pressure to lift the
fluids.
Consequently, they require that the bottomhole pressure be
at least 150% of the gas sales line pressure. |
Lifting has three cycles: (1) the shut-in
cycle in which the flow line valve is closed and the plunger
falls to the bottom of the tubing, (2) the unloading cycle
occurs after a period of time allowing the pressure to
build, then a controller opens the flow valve and the built
up pressure moves the plunger and fluids collected above it
to the surface, and (3) the afterflow cycle begins when the
plunger arrives at the surface and is held there by the gas
flowing up the tubing. The energy to raise the plunger comes
from the formation and pressure build up in the casing and
can be augmented by injecting gas in the casing.
Derek Ellsworth (PCS) identified six plunger
types in his presentation:
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Pad (or Padded) plunger is the most
common, so called because of the spring-loaded pads that
provide a metal-to-metal seal with the tubing.
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Brush plunger works better where solids
or paraffin interfere with the pads of the pad plunger.
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Solid plunger is the most effective in
removing paraffin; however, it does not have the sealing
capabilities of the pad or brush plunger.
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Bypass plunger requires more energy to
raise, but is preferable as it has internal valves that
open and close, allowing the fluid to flow through it,
falling more rapidly against flow.
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Flexible (snake) plungers can flex to
follow curved coil tubing or tight spots in regular
tubing.
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Internal shock-absorbing plunger is used
if a stationary spring at the bottom of the tubing
collects too much buildup of paraffin or scale.
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State-of-the-Art
Summary