Note: Descriptions are shown in the official language in which they were submitted.
CA 02766786 2011-12-23
WO 2011/008522 PCT/US2010/040311
SYSTEM AND METHOD FOR INTERMITTENT GAS LIFT
RELATED CASES
The present application claims benefit of U.S. Application Serial No.
61/221,169,
filed on 29 June 2009, which is incorporated herein by reference.
FIELD OF THE INVENTION
[0001] The present invention relates to a system and apparatus for removing
water from a
deep gas well.
BACKGROUND OF THE INVENTION
[0002] Hydrocarbon gas from subsurface earth formations is initially produced
by the
inherent formation pressure of the gas in the formation. Over time, however,
water vapor
in the gas stream condenses on the way to surface. As production rates
decline, the
velocity is no longer able to lift fluids to the surface. Water droplets
coalesce, run down
tubulars, and collect at the bottom of the wellbore. Eventually, the fluid
level rises above
the level of the well perforations. This increases bottom hole flowing
pressure and restricts
production. When this occurs, it is advantageous to remove the liquids from
the well in
order to increase the gas flow rate.
[0003] Possible solutions to this problem include velocity strings, capillary
string injecting
foamers, and pumps to continuously or intermittently pump the water to the
surface to
remove the hydrostatic barrier that the water creates.
[0004] A common practice is to use a plunger to intermittently lift the
liquids. Referring
briefly to Figures 1-2, in conventional techniques a system 10 is used that
comprises a
wellbore 12, gas lift tubing string 14, and an inner tubing string 16.
Wellbore 12 may be
cased. It will be understood that the Figures are not drawn to scale and that
the total depth
of the well may be several thousand feet.
[0005] An annulus 22 is defined between the wellbore or casing and gas lift
tubing string
14. A gas production valve 32, gas lift inlet valve 34, and gas lift outlet
valve 36 control
the flow of fluids at the upper ends of annulus 22, tubing string 14, and
inner string 16,
respectively. At the bottom of gas lift string 14, a standing valve 38
controls the flow of
fluid into tubing string 14 through an opening 28. There is fluid
communication between
CA 02766786 2011-12-23
WO 2011/008522 PCT/US2010/040311
the inside of tubing string 14 and the inside of inner string 16. One or more
perforations 42
enhance the flow of fluids out of the formation and into the wellbore.
[0006] An optional slidable plunger 40 sealingly engages the inside of inner
string 16.
Plunger 40 is designed to allow fluids to flow up through or around the
plunger and into
inner string 16 until plunger 40 starts moving upward, whereupon plunger
changes shape
such that it forms a seal with the inside of inner string 16. For example,
plunger 40 may
comprise chevron type seals that allow the fluid to flow past in one
direction, but tend to
prevent fluid from flowing past in the other direction.
[0007] In operation, gas coming out of the formation flows up annulus 22 and
out through
valve 32. As it does, water enters the well from the formation and/or
condenses and falls
to the bottom of the well. Without significant backpressure in gas lift tubing
string 14,
water collecting at the bottom of the well enters gas lift tubing string 14
through opening
28.
[0008] At some point, it will be desirable to remove a portion of the
collected water. This
may occur when the water level rises to the level of the perforations (as
shown in Figure 1
at 44), after a predetermined period of time, or when a predetermined amount
of liquid has
collected. At this point, gas lift inlet valve 34 is opened, increasing the
pressure inside
string 14 and forcing standing valve 38 closed, as shown in Figure 2. With
standing valve
38 closed, lift gas is forced into inner string 16, advancing plunger 40
upward, along with a
slug of accumulated fluids above and perhaps below it. This system will work
with or
without the plunger, providing there is a long enough water column.
[0009] After the plunger reaches the surface, the lift gas vents until
hydrostatic pressure at
the bottom of the well is sufficient to open the standing valve and the cycle
repeats. While
fluids enter the tubing, the plunger falls back to bottom.
[0010] One advantage of intermittent gas lift techniques is that they lift
fluids without
putting any backpressure on the formation. While useful in shallow wells,
conventional
intermittent gas lift techniques require produced gas to flow up the annulus.
Flowing gas
up the annulus is acceptable in shallow low pressure gas applications;
however, issues such
as high pressure, hydrogen sulfide, sulphur deposition, paraffin deposition,
and local
regulations may prohibit flow up the annulus. Thus, there remains a need for
an effective
technique for removing water from deep gas wells.
SUMMARY OF THE INVENTION
2
CA 02766786 2011-12-23
WO 2011/008522 PCT/US2010/040311
[0011 ] In accordance with preferred embodiments of the invention a system and
technique
are provided for removing water from deep gas wells.
[0012] In some embodiments, the system may be an intermittent gas-lift
apparatus for use
in a well that produces gas and liquid, in which liquids accumulate in a
liquid zone in the
wellbore. The system may comprise a first string extending into the liquid
zone and
having an upper end and a lower end, a second string surrounding the first
string and
defining an annulus therewith, the second string extending a predetermined
axial distance
from the first string lower end such that said annulus has an upper end and a
lower end, the
annulus being closed at its upper and lower ends so as to define a chamber,
the chamber
being in fluid communication with the inside of the first string, a check
valve controlling
the flow of liquid into from the wellbore into the lower end of said annulus,
a gas valve
allowing the flow of gas from the first string into the upper end of the
chamber, and a valve
for controlling the flow of gas into the upper end of the first string.
[0013] The first string may comprise coiled tubing and the second string may
comprise
production tubing. The system includes an optional plunger slidably disposed
in the first
string.
[0014] In other embodiments, the invention comprises a method for producing
gas from a
well that produces gas and liquid, in which liquids accumulate in a liquid
zone in the
wellbore. The method may comprise the steps of: a) providing in the well an
apparatus
comprising: a first string extending into the liquid zone and having an upper
end and a
lower end, a second string surrounding the first string and defining an
annulus therewith,
said second string extending a predetermined axial distance from the first
string lower end,
such that said annulus has an upper end and a lower end, said annulus being
closed at its
upper and lower ends so as to define a chamber, said chamber being in fluid
communication with the inside of said first string, a check valve controlling
the flow of
liquid into from the wellbore into the lower end of said annulus, a gas valve
allowing the
flow of gas from the first string into said chamber, and a valve for
controlling the flow of
gas through the upper end of said inner string; b) allowing liquid to flow
from the wellbore
into the annulus; c) pumping gas into the annulus via the gas valve and
preventing liquid
from flowing out of the annulus until a desired pressure is reached; and d)
allowing gas to
flow out of the annulus via the inner string while preventing gas from flowing
out of the
annulus via the gas valve, such that the gas flowing out of the annulus
propels a slug of
liquid toward the surface.
3
CA 02766786 2011-12-23
WO 2011/008522 PCT/US2010/040311
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] For a more detailed understanding of the invention, reference is made
to the
accompanying wherein:
[0016] Figures 1 and 2 are schematic illustrations of two modes of a prior art
system;
[0017] Figures 3 - 5 are schematic illustrations of three modes of a system
constructed in
accordance with an embodiment of the invention; and
[0018] Figure 6 is a schematic illustration of a system constructed in
accordance with an
alternative embodiment of the invention.
[0019] It will be understood that the Figures illustrate a system that is
designed for use in a
hydrocarbon production well. Positions of equipment are illustrated relative
to the top of
the well (the earth's surface) or the bottom of the well, but such
illustration is schematic
only. The Figures are not to scale and the distance between the top and bottom
of the well
may be several thousand feet.
DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT
[0020] Referring now to Figures 3-5, a system 100 according to the preferred
embodiments
of the present invention is positioned in a wellbore 12. The system 100
includes a
production string 114 and an inner string 116. Inner string 116 preferably but
not
necessarily comprises coiled tubing. At the surface, a production valve 124
controls the
flow of fluids out of production string 114 and a lift gas inlet valve 126 and
a lift gas vent
valve 128 control the fluid into and out of, respectively, inner string 116.
Lift gas is
preferably provided to lift gas inlet valve 126 via a high pressure lift gas
feed line (not
shown). A packer 115 is preferably set at the bottom of production string 114
so as to
isolate the portion of the annulus above that point.
[0021] The system preferably includes a crossover 130 that is preferably
located several
thousand feet from the bottom of the hole. Below crossover 130, a concentric
outer string
118 surrounds inner string 116, forming an annulus 117 therebetween. A gas
check valve
144 is preferably disposed in the wall of inner string 116 near crossover 130.
An
unloading valve 146 is preferably disposed in the wall of outer string 118
near the bottom
of string 118. A standing valve 129 controls the flow of fluids from the
borehole into the
bottom of outer string 118. One or more passageways 123 provide fluid
communication
between the inside of outer string 118 and the inside of inner string 116.
4
CA 02766786 2011-12-23
WO 2011/008522 PCT/US2010/040311
[0022] Referring now to Figure 3, during production, lift gas inlet valve 126
is normally
closed and vent valve 128 is open. Water flows accumulates at the bottom of
the wellbore
and flows into the concentric tubing through standing valve 129, and produced
gas flows
out through production string 114, as indicated by arrow 145.
[0023] Referring now to Figure 4, when it is desired to lift fluids, vent
valve 128 closes
and lift gas inlet valve 126 opens. This allows pressurized gas to flow down
through inner
string 116. Standing valve 129 closes as a result of the pressure differential
between the
inside of outer string 118 and the wellbore and gas check valve 144 allows
high pressure
lift gas to pass from the coiled tubing into annulus 117. Because the system
is closed, the
pressure inside inner string 116 and annulus 117 will rise until it reaches
line pressure, i.e.
the pressure in the high pressure lift gas feed line.
[0024] Referring now to Figure 5, once the pressure inner string 116 and
annulus 117
reaches line pressure, lift gas inlet valve 126 closes. Vent valve 128 opens,
allowing gas
inside the coiled tubing to flow back to the surface and decreasing the
pressure in inner
string 116. Check valve 144 prevents the pressurized gas in annulus 117 from
flowing
back into inner string 116, with the result that the pressurized gas trapped
in annular space
117 expands toward the bottom of the well and up through inner string 116. As
the
expanding gas from annulus 117 flows up through inner string 116, it pushes a
slug of
liquid 150 ahead of it to the surface, thereby reducing the amount of liquid
in the bottom of
the well. After expelling slug 150, the lift gas continues to vent through
valve 128 until the
pressure inside the tubing equals the vent pressure.
[0025] As liquid continues to accumulate at the bottom of the well, the
hydrostatic
pressure of liquid below standing valve 129 eventually becomes higher than the
pressure
inside concentric outer string 118, at which point standing valve 129 opens,
allowing liquid
to again enter concentric string 118 and the cycle repeats.
[0026] If desired, valve 146 at the bottom of the concentric string may be
included and
used for initial unloading of downhole liquids.
[0027] An advantage of the present invention is that produced gas is able to
flow out of the
formation and up though production string 114 without restriction throughout
the entire lift
cycle, as indicated by arrow 145. Standing valve 129 ensures that all lift gas
is confined
within the inner and outer tubing 116, 118. Thus, water can be removed from
the well
without changing the bottom hole flowing pressure. This is in contrast to
conventional
systems, which put additional backpressure on the formation during lift cycles
or require
CA 02766786 2011-12-23
WO 2011/008522 PCT/US2010/040311
the well to be shut in in order to build up sufficient downhole pressure to
intermittently lift
fluids. With the present system, the well will continue to flow at normal
rates with the
normal bottom hole flowing pressure.
[0028] A further advantage of the present system is that it does not require
the installation
of concentric tubing strings extending the full depth of the well. By
contrast, the system
shown in Figures 1 and 2 requires concentric tubing strings from the surface
to the bottom
of the well. For deep wells, the amount of gas required to be injected in
order to perform a
gas lift operation using the system of Figure 1 would be significant. In
addition, by
providing a chamber that extends to less than the full depth of the well,
significant
equipment cost savings may be realized. Still further, the present system
avoids the need
for a downhole pump or similar equipment.
[0029] It is believed that the suitable pressures for application to annulus
117 during the
pressurization portion of the cycle range between 400 psig and 1,400 psig,
depending on
the volume of water per lift, depth, and the axial length of annulus 117. The
length of
annulus 117 can be determined using the expected line pressure and the ratio
of the annulus
volume to the total tubing volume. In some embodiments, it may be desirable to
design the
system such that the ratio of the volume of the gas in the pressured annulus,
when
expanded to vent pressure, to the volume of inner string 116 is in the range
of 5 to 15.
[0030] As mentioned above, the Figures are not to scale. The distance between
crossover
130 and the bottom of inner string 116 is likely to be several thousand feet.
By way of
example only, a 10,000' well might have a production string packer 115 at
around 6,000',
crossover 130 at 6,500', and the bottom of standing valve 129 at 9,990', with
casing
perforations in stages from 7,000' to 9,500'. Thus, the axial length of
annulus 117 may, in
various embodiments, be less than 75%, less than 67%, less than 50%, less than
40%, or
even less than 25% of the total length of inner string 116.
[0031] Not all wells are vertical. If, for example, the well is highly
deviated, liquid in the
well may accumulate in a liquid zone that is not at the remote end of the
wellbore. It will
be understood that references to a liquid accumulation zone include any such
zone,
regardless of whether it is at the end of the wellbore.
[0032] In an alternative embodiment, the principles described above can be
applied using a
combination of a production tubing and an inner string instead of an inner
string supporting
an outer string on a crossover. Referring to Figure 6, such a system
preferably includes a
production string 214 and packer 115 as described above. Instead of a length
of coiled
6
CA 02766786 2011-12-23
WO 2011/008522 PCT/US2010/040311
tubing, an inner tubing string 216 extends through the production string 214.
Both inner
tubing string 216 and production string 214 terminate near the bottom of the
hole. An
annulus 217 is defined between inner tubing string 216 and production string
214. The
upper and lower ends of annulus 217 are preferably sealed by a packer 215 and
a seating
assembly 219, respectively.
[0033] A standing valve 229 controls the flow of fluids into the bottom of
inner string 216.
Fluid passageways 222 through the wall of inner string 216 allow fluids to
flow between
annulus 217 and the inside of inner tubing string 216. Passageways 224 through
the wall
of production tubing 114 allow produced gas to flow from the wellbore into
annulus 217.
Thus, as in the embodiment described above, valve 229 controls the flow of
fluids into
annulus 217.
[0034] The system illustrated in Figure 6 functions in the same manner as the
system of
Figure 3. Thus, pressurized gas is supplied to annulus 217 via inner tubing
string 216 and
the expansion of that gas is used to propel a slug of liquid up out of the
well. An optional
plunger (not shown) may be included within inner string 216 to keep lift gas
from over-
riding the fluid. In some embodiments, standing valve 129 and gas valve 244
can be
maintained with wireline.
[0035] In yet another embodiment (not shown), an intermediate-diameter
conventional
tubing string may be hung from a flow-through tubing hanger disposed between
the
production tubing and an inner string. The inner string may comprise coiled
tubing or
conventional tubing. A seal is provided between the intermediate string and
the inner
string so that the annulus therebetween can receive and contain the
pressurized gas. Once
the annulus has reached line pressure, the pressure in the inner string is
released, the check
valve closes to prevent backflow, and the gas in the annulus expands,
propelling a slug of
liquid upward.
[0036] In each of the embodiments disclosed herein, it will be understood that
the upper
and lower ends of the inner and outer string, the annulus, and the standing
valve could be
configured differently, so long as a chamber is defined and liquids can flow
into the
chamber, gas can be pumped into the chamber, and the expanding gas can be used
to
propel a slug of liquid from the chamber to the surface or a predetermined
outflow point.
7
