Note: Descriptions are shown in the official language in which they were submitted.
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PLUNGER LIFT PISTON
This is a division of copending commonly owned Canadian Patent Application No.
2,301,791 filed March 21, 2000.
This invention relates in general to a plunger lift system for moving liquids
upwardly in a
petroleum well, and more particularly to a multipart piston used in such
system..
BACKGROUND OF THE INVENTION
There are many different techniques for artificially lifting formation liquids
from hydrocarbon
wells. Reciprocating sucker rod pumps are the most commonly used in the oil
field because they
are the most cost effective, all things considered, over a wide variety of
applications. Other types
of artificial lift include electrically driven down hole pumps, hydraulic
pumps, rotating rod pumps,
free pistons or plunger lifts and several varieties of gas lift. These
alternate types of artificial lift are
more cost effective than sucker rod pumps in the niches or applications where
they have become
popular.
One of the developments that has evolved over the last thirty years are so-
called tubingless
completions in which a string of tubing, usually 2~/a" O.D., is cemented in
the well bore and then
used as the production string. Tubingless completions are never adopted where
pumping a well
is initially considered likely because sucker rod pumps have proved to be only
slightly less than a
disaster when used in a 2 7/8" tubingless completions. Artificial lift in a
2~/e" tubingless completion
is almost universally limited to gas lift or free pistons. Thus, tubingless
completions are typically
used in shallow to moderately deep wells that are believed, at the time a
completion decision is
made, to produce all or mostly gas, i.e. no more liquid than can be produced
along with the gas.
Gas wells reach their economic limit for a variety of reasons. A very common
reason is the
gas production declines to a point where the formation liquids are not readily
moved up the
production string to the surface. Two phase upward flow in a well is a
complicated affair and most
engineering equations thought to predict flow are only rough estimates of what
is actually occurring.
One reason is the changing relation of the liquid and of the gas flowing
upwardly in the well. At
times of more-or-less constant flow, the liquid acts as an upwardly moving
film on the inside of the
flow string while the gas flows in a central path on the inside of the liquid
film. The gas flows much
faster than the liquid film. When the volume of gas flow slows down below some
critical value, or
stops, the liquid runs down the inside of the flow string and accumulates in
the bottom of the well.
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If sufficient liquid accumulates in the bottom of the well, the well is no
longer able to flow
because the pressure in the reservoir is not able to start flowing against the
pressure of the liquid
column. The well is said to have loaded up and died. Years ago, gas wells were
plugged much
quicker than today because it was not economic to artificially lift small
quantities of liquid from a
gas well. At relatively high gas prices, it is economic to keep old gas wells
on production. It has
gradually been realized that gas wells have a life cycle that includes an old
age segment where a
variety of techniques are used to keep liquids flowing upwardly in the well
and thereby prevent the
well from loading up and dying. There are many techniques for keeping old gas
wells flowing and
the appropriate one depends on where the well is in its life cycle. For
example, the first technique
is to drop soap sticks into the well. The soap sticks and some agitation cause
the liquids to foam.
The well is then turned to the atmosphere and a great deal of foamed liquid is
discharged from the
well. Later in its life cycle, when soaping the well has become much less
effective, a string of 1"
or 1'h" tubing is run inside the production string. The idea is that the
upward velocity in the small
tubing string is much higher which keeps the liquid moving upwardly in the
well to the surface. A
rule of thumb is that wells producing enough gas to have an upward velocity in
excess of
10'/second will stay unloaded. Wells where the upward velocity is less than
5'/second will always
load up and die.
At some stage in the life of a gas well, these techniques no longer work and
the only
approach left to keep the well on production is to artificially lift the
liquid with a pump of some
description. The logical and time tested technique is to pump the accumulated
liquid up the tubing
string with a sucker rod pump and allow produced gas to flow up the annulus
between the tubing
string and the casing string. This is normally not practical in a 2~/8"
tubingless completion unless
one tries to use hollow rods and pump up the rods, which normally doesn't work
very well or very
long. Even then, it is not long before the rods cut a hole in the 2 ~/s"
string and the well is lost. In
addition, sucker rod pumps require a large initial capital outlay and either
require electrical service
or elaborate equipment to restart the engine.
Free pistons or plunger lifts are another common type of artificial pumping
system to raise
liquid from a well that produces a substantial quantity of gas. Conventional
plunger lift systems
comprise a piston that is dropped into the well by stopping upward flow in the
well, as by closing
the wing valve on the well head. The piston is often called a free piston
because it is not attached
to a sucker rod string or other mechanism to pull the piston to the surface.
When the piston
reaches the bottom of the well, it falls into the liquid in the bottom of the
well and ultimately into
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contact with a bumper spring, normally seated in a collar or resting on a
collar stop. The wing valve
is opened and gas flowing into the well pushes the piston upwardly toward the
surface, pushing
liquid on top of the piston to the surface. Although plunger lifts are
commonly used devices, there
is more art than science to their operation.
A major disadvantage of conventional plunger lifts is the well must be shut in
so the piston
is able to fall to the bottom of the well. Because wells in need of artificial
lifting are susceptible to
being easily killed, stopping flow in the well has a number of serious
effects. Most importantly, the
liquid on the inside of the production string falls to the bottom of the well,
or is pushed downwardly
by the falling piston. This is manifestly the last thing that is desired
because it is the reason that
wells die. In response to the desire to keep the well flowing when a plunger
lift piston is dropped
into the well, attempts have been made to provide valued bypasses through the
piston which open
and close at appropriate times. Such devices are to date quite intricate and
these attempts have
so far failed to gain wide acceptance.
Disclosures of some interest relative to this invention are U.S. Patents Nos.
2,074,912 and
3,090,316.
SUMMARY OF THE INVENTION
In this invention, a multipart piston includes separate pieces that are
independently allowed
to fall inside the production string toward the productive formation. The
cross-sectional area of the
separate pieces are such that upward flow of gas is substantially unimpeded
and the pieces fall
through an upwardly moving stream of gas and liquid. Thus, the piston of this
invention is normally
dropped into a well while it is flowing. This has a great advantage because
the liquid in a film on
the inside of the production string does not fall into the bottom of the well.
When the lower piece nears the bottom of the well, it falls into any liquid
near the bottom
of the well and contacts a bumper spring which cushions the impact of the
device. When the upper
piece reaches the lower piece, they unite into a single component that has a
cross-sectional area
comparable to existing plunger lift pistons, i.e. any gas entering the
production string from the
formation is under the piston and pushes it upwardly, thereby pushing any
liquid upwardly in the
well to the surface.
Preferably, one of the pieces is a sleeve having a central passage through
which the gas
flows as the sleeve falls in the well. The other piece is preferably a mandrel
having a pin that fits
into the sleeve and substantially blocks flow in the central passage when the
pieces are united.
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The flow passage around the mandrel is basically on the outside as the it
falls in the well. The
mandrel provides one or more centralizers which hold the pin in the center of
the production string
to align with the central passage of the sleeve.
When the united components reach the well head at the surface, and in
accordance with
the invention of the parent application, a decoupler separates the sleeve from
the mandrel and
allows the mandrel to fall toward the bottom of the well. Conveniently, a
catcher holds the sleeve
and then releases the sleeve after the mandrel is already on the way to the
bottom.
A bypass for produced formation products is conveniently provided in the well
head to
insure that the sleeve and mandrel separate.
In summary, therefore, the present invention may be considered as providing a
plunger lift
piston for lifting liquids from a well producing through a production string
communicating with a
hydrocarbon formation, comprising: a sleeve providing a passage therethrough
and a member for
closing the passage in the sleeve, the sleeve and the member being movable
independently
downwardly into the well, the sleeve and the member being united in the well
near the hydrocarbon
formation and providing an exterior seal for upward movement together in the
well for pushing
liquid, above the piston, upwardly, the sleeve having a first ratio of
downwardly facing surface area
to weight and the member having a second ratio of downwardly facing surface
area to weight, the
first ratio being higher than the second ratio.
These and other aspects of this invention will become more fully apparent as
this
description proceeds, reference being made to the accompanying drawings and
appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is a schematic view of a well equipped with a plunger lift system of
the parent
application;
Figure 2 is an exploded vertical cross-sectional view of the piston of this
invention, showing
the sleeve and mandrel;
Figure 3 is a bottom view of the mandrel;
Figure 4 is a top view of the mandrel;
Figure 5 is a broken isometric view of the sleeve;
Figure 6 is an isometric view of the mandrel, the top of the mandrel being
broken away from
the bottom for purposes of illustration;
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Figure 7 is a broken isometric view of the bottom of the mandrel, taken at
45° relative to
Figure 6;
Figure 8 is a horizontal cross-sectional view of Figure 6, taken substantially
along line 8--8
thereof, as viewed in the direction indicated by the arrows; and
Figure 9 is a vertical cross-sectional view of the lower end of the mandrel of
Figure 6.
DETAILED DESCRIPTION
Referring to Figures 1-9, a hydrocarbon well 10 comprises a production string
12 extending
into the earth in communication with a subterranean hydrocarbon bearing
formation 14. The
production string 12 is typically a conventional tubing string made up of
joints of tubing that are
threaded together. Although the production string 12 may be inside a casing
string (not shown),
it is illustrated as cemented in the earth. The formation 14 communicates with
the inside of the
production string 12 through perforations 16. As will be more fully apparent
hereinafter, the plunger
lift 18 may be used to lift oil, condensate or water from the bottom of the
well 10 which may be
classified as either an oil well or a gas well.
In a typical application of this invention, the well 10 is a gas well that
produces some
formation liquid. In an earlier stage of the productive life of the well 10,
there is sufficient gas being
produced to deliver the formation liquids to the surface. The well 10 is
equipped with a
conventional well head assembly 20 comprising a pair of master valves 22 and a
wing valve 24
delivering produced formation products to a surface facility for separating,
measuring and treating
the produced products.
The plunger lift 18 of this invention comprises, as major components, a piston
26, an upper
bumper 28, a decoupler 30, a catcher assembly 32, a lower bumper 34 and a
bypass 36 around
the piston 26 when it is its uppermost position in the well head assembly 20.
The piston 26 is of unusual design and is made in at least two pieces which,
in a preferred
embodiment of the invention, comprises an upper sleeve 38 and a lower mandrel
40. The sleeve
38 comprises a tubular body 42 having a central passage 44, a fishing neck 46
at the upper end
thereof and a sealing surface 48 at the lower end thereof.
The exterior of the sleeve 38 provides a seal arrangement 50 to minimize
liquid on the
outside of the sleeve 38 from bypassing around the exterior of the sleeve 38.
The seal
arrangement 50 may be of any suitable type, such as wire wound around the
sleeve 38 providing
a multiplicity of bristles or the like or may comprise a series of simple
grooves or indentations 52.
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The grooves 52 work because they create a turbulent zone between the sleeve 38
and the inside
of the production string 12 thereby restricting liquid flow on the outside of
the sleeve 38.
The mandrel 40 is of more complex configuration and comprises a body 54 having
a robust
lower end 56 which takes repeated impacts against the lower bumper, a first
centralizes section 58
providing a series of outwardly extending arms 60 and a second centralizes
section 62 providing
a series of outwardly extending arms 64. The arms 60 are preferably 90°
out of phase with the
arms 64 so the centralizes sections 58, 62 orient the axis 66 of the mandrel
40 substantially
coincident with the axis of the sleeve 38 and of the production string 12. The
arms 60, 64
preferably have the same outer dimension as the sleeve 38.
Above the centralizes section 62 is a circular plate 68 having a series of
peripheral slots 70
providing a flow bypass between the centralizes arms 64. Above the plate 68 is
a pin 72 which
extends into the sleeve 38 and provides a frustoconical sealing surface 74, a
snap ring groove 76
and a pair of fishing grooves 78. The pin 72 is substantially shorter than the
sleeve 38 so, in the
upwardly moving or nested position of the piston 26, the pin 72 terminates
below the fishing neck
46 of the sleeve 38.
A sealing member 80 slips over the pin 72 and fits onto the sealing surface 74
of the
mandrel 40. A washer 81 may be provided above the sealing member 80 for
abutting a snap ring
(not shown) which fits in the groove 76 and holds the sealing member 80 in
position. When the
mandrel 40 nests inside the sleeve 38, the sealing member 80 seals against the
sealing surface
48. The sealing member 80 may be of any suitable type and is shown as a
Harbison-Fisher nylon
seal ring, model 80-190H-10, 1 3/" HR pump seal.
As will be more fully apparent hereinafter, the mandrel 40 is first dropped
into the well 10,
followed by the sleeve 38. The mandrel 40 and sleeve 38 accordingly fall
separately and indepen-
dently into the well 10, usually while the well 10 is producing gas and liquid
up the production string
12 and through the well head assembly 20. By separately, it is meant that the
mandrel 40 and
sleeve 38 are not connected. By independently, it is meant that the mandrel 48
and sleeve 38 are
capable of moving independently of one another even if they are tethered
together in some fashion.
When the mandrel 40 and sleeve 38 reach the bottom of the well, they nest
together in preparation
for moving upwardly.
In one aspect, the sleeve 38 and mandrel 40 each have a flow bypass so they
separately
fall easily into the well 10 even when there is substantial upward flow in the
production string 12.
When they reach the bottom of the well, they unite into a single component
which substantially
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closes the flow bypasses, or at least restricts them, so gas entering through
the perforations 16
pushes the piston 26 upwardly in the well and thereby pushes liquid, above the
piston 26, upwardly
toward the well head assembly 20.
Looked at in another perspective, the sleeve 38 and mandrel 40 each have a
surface area
which is selected so that they separately fall easily in the well but, when
they are united into the
piston 26, the piston 26 is pushed upwardly in the well thereby pushing any
liquid upwardly toward
the well head assembly 20. The selection of the surtace areas of the sleeve 38
and mandrel 40
is preferably done so that a given pressure differential will move the mandrel
40 before moving the
sleeve 38. In other words, the mandrel 40 is easier to move than the sleeve
38. The reason is that
is if the mandrel 40 can be constructed so it always pushes from below, there
is no tendency for
the sleeve 38 to separate from the mandrel 40 during upward movement in the
well 10.
This may be illustrated in the following example. A standard size 2'/s" tubing
used as a
production string weighs 6.5 #/foot and has a nominal internal diameter of
2.441" which, of course,
is not perfect and which is interrupted in an assembled string by a gap in the
coupling of adjacent
joints. A conventional one piece plunger lift has an O.D. of about 2.330" and
can successfully lift
liquid from the bottom of a well. A piston 26 of this invention may have a
sleeve 38 with an O.D.
of 2.330" and an I.D. of 1.750" so the downwardly facing area of the sleeve 38
is approximately
1.857 square inches. A mandrel 40 for such a sleeve will have a plate 68 of an
O.D. of 2.125" and
its downwardly facing surface area is somewhat less than 3.547 square inches
because of the slots
70. When the sleeve 38 is nested onto the mandrel 40, the O.D. of the sleeve
38 is slightly larger
than the plate 68. It will be seen that the area of the mandrel 40 is larger
than the area of the
sleeve 38 so that any pressure drop applies a greater force to the mandrel 40
than to the sleeve
38. In addition, the ratio of downwardly facing surface area to weight of the
mandrel 40 is greater
than the ratio of downwardly facing surface area to weight of the sleeve 38.
Alternatively stated,
the ratio of weight to downwardly facing surface area of the sleeve 38 is
greater than the ratio of
weight to downwardly facing surface area of the mandrel 40.
The upper bumper 28 is of conventional design and comprises a helical spring.
Bumpers
of this type are well known in the plunger lift art and are commercially
available.
The lower bumper 34 sits, or is part of, a conventional collar stop 82 that is
supported in the
gap provided by couplings between adjacent joints of the production string 12.
In a well (not
shown) having a tubing string inside a casing string cemented in the earth,
the lower bumper 34
typically sits in a seating nipple (not shown) in the tubing string. The lower
bumper 34 includes a
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body 84, a relatively long spring 86 and an anvil 88 providing a conventional
fishing neck 90.
Because the mandrel 40 falls into the bottom of the well 10 when it is
flowing, there is little or no
liquid accumulated adjacent the formation 14. Thus, the mandrel 40 tends to
strike the lower
bumper 34 at higher velocities than conventional plunger pistons. For this
reason, a longer, softer
bumper spring is desired.
The decoupler 30 acts to separate the piston 26 when it reaches the well head
assembly
20. The decoupler 30 comprises a rod 92 sized to pass into the top of the
sleeve 38 and is fixed
to a piston 94. The piston 94 is larger than a conduit 96 in which the rod 92
reciprocates and is
thus prevented from falling into the well 10. The top of the well head
assembly 20 is closed with
a screw cap 98. A stop 100 on the rod 92 limits upward movement of the sleeve
38. A series of
grooves 101, similar to the grooves 70, allow formation products to pass
around the stop 100 and
into a flow line 102 connected to the wing valve 24. It will be seen that the
piston 26 moves
upwardly in the well 10 as one piece. When the sleeve 38 passes onto the end
of the rod 92, the
rod 92 ultimately contacts the top of the pin 72, stopping upward movement of
the mandrel 40 and
allowing continued upward movement of the sleeve 38. The end of the rod 92,
below the stop 100,
is longer than the pin 72 so the mandrel 40 is pushed out of the sleeve 38
thereby releasing the
mandrel 40 which falls toward the bottom of the well 10.
The bypass 36 helps prevent the piston 26 from sticking in the well head
assembly 20 and
may include a valve 103. The bypass 36 opens into the well head assembly 20
below the bottom
of the sleeve 38 when it is in its uppermost position in the well head
assembly 20. Thus, there will
be a tendency of gas flowing through the well head assembly 20 to move through
the bypass 36
rather than pinning the sleeve 38 against the stop 100.
A catcher 32 may be provided to latch onto the sleeve 38 and thereby hold it
for a while to
provide a delay period between successive cycles of the piston 26 and to make
certain that the
sleeve 38 and mandrel 40 fall separately toward the bottom of the well 10. To
these ends, the
sleeve 38 is provided with an elongated groove 104 to receive a ball detent
106 forced inwardly into
the path of the sleeve 38 by an air cylinder 108 connected to a supply of
compressed gas (not
shown) through a fitting 110. A piston 112 in the cylinder 108 is biased by a
spring 114 to a
position releasing the ball detent 106 for movement out of engagement with the
slot 104. Pressure
is normally applied to the cylinder 108 thereby forcing the ball detent 106
into the path of travel of
the sleeve 38. The exterior surfaces of the slot 104 are beveled to cam the
ball detent 106 against
the force of the compressed gas so the ball detent 106 passes into the slot
104 thereby latching
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onto the sleeve 38 when it is on the decoupler 30 and preventing it from
falling immediately into the
well 10. Upon a signal from a controller (not shown), gas pressure is bled
from the cylinder 108
allowing the spring 114 to retract the piston 112 and allowing the weight of
the sleeve 38 to push
the ball detent 106 out of the slot 104 thereby releasing the sleeve 38 for
movement downwardly
into the well 10.
When it is desired to retrieve the mandrel 40 or the piston 26, the decoupler
30 is replaced
with a similar device having a stop 100 but eliminating the rod 92. This
causes the piston 26 to
impact the bumper 28 without dislodging the mandrel 40. The piston 26 is held
in its upward
position by the flow of formation products around the piston 26 in conjunction
with the catcher 32
which latches onto the sleeve 38.
Operation of the plunger lift 18 of this invention should now be apparent. The
mandrel 40
is first dropped into the well 10. It falls rapidly through a rising stream of
produced products onto
the bumper 34 which substantially cushions the impact and minimizes damage to
the mandrel 40.
When the sleeve 38 is released by the catcher 32, it falls through the well 10
to the bottom.
Because the pin 72 of the mandrel 40 is aligned with the axis 66, the sleeve
38 passes over the
pin 72, impacts the top of the plate 68 and seals against the sealing member
80. The combined
downwardly surface area of the sleeve 38 and mandrel 40, in their united
configuration, is sufficient
to allow gaseous products from the formation 14 to push the piston 26, and any
liquid above it,
upwardly to the well head assembly 20.
As the piston 26 approaches the well head assembly 20, a slug of liquid passes
through the
wing valve 24 into the flow line 102 toward a surface treatment facility. The
sleeve 36 passes over
the rod 92 which stops upward movement of the mandrel 40 thereby releasing the
mandrel 40
which drops into the well 10 in the start of another cycle. The sleeve 38 is
retained by the catcher
32 for a period of time depending on the requirements of the well 10. If the
well 10 needs to be
cycled as often as possible, the delay provided by the catcher 30 is only long
enough to be sure
the mandrel 40 will reach the bottom of the well 10 before the sleeve 38. In
more normal situations,
the sleeve 38 will be retained on the catcher 30 so the piston 26 cycles much
less often.
A prototype of the plunger lift system has been tested. In a 6000' gas well
that loads up and
dies with produced liquid, it took seven minutes for the mandrel and sleeve to
fall separately to the
bottom of the well through the upwardly moving column of gas and water,
recombine and return
to the surface with'/4 barrels of water.
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Although this invention has been disclosed and described in its preferred
forms with a
certain degree of particularity, it is understood that the present disclosure
of the preferred forms
is only by way of example and that numerous changes in the details of
construction and operation
and in the combination and arrangement of parts may be resorted to without
departing from the
spirit and scope of the invention as hereinafter claimed.
