U.S. patent application number 11/774361 was filed with the patent office on 2009-01-08 for method of producing a low pressure well.
Invention is credited to Patrick T. Coady.
Application Number | 20090008101 11/774361 |
Document ID | / |
Family ID | 40220559 |
Filed Date | 2009-01-08 |
United States Patent
Application |
20090008101 |
Kind Code |
A1 |
Coady; Patrick T. |
January 8, 2009 |
Method of Producing a Low Pressure Well
Abstract
A method of producing natural gas from a well has a mode that
removes liquid collected in the well by injecting gas. The well has
a string of tubing with a valve at its lower end that is submerged
in the liquid produced by the well. An injection tube extends into
the tubing. With the valve open, natural gas from the well flows up
the tubing annulus and out the well to a gas pipeline and liquid
flows into the tubing as well as into the injection tube.
Periodically, an injection gas is injected down the injection tube
with the valve closed to prevent the injection gas from flowing
into the tubing annulus. This causes liquid collected in the tubing
to be pushed to the surface and out of the well.
Inventors: |
Coady; Patrick T.; (Atlanta,
MI) |
Correspondence
Address: |
BRACEWELL & GIULIANI LLP
P.O. BOX 61389
HOUSTON
TX
77208-1389
US
|
Family ID: |
40220559 |
Appl. No.: |
11/774361 |
Filed: |
July 6, 2007 |
Current U.S.
Class: |
166/370 ;
166/105.5; 166/325; 166/372 |
Current CPC
Class: |
E21B 43/34 20130101;
E21B 43/121 20130101 |
Class at
Publication: |
166/370 ;
166/105.5; 166/325; 166/372 |
International
Class: |
E21B 43/16 20060101
E21B043/16; E21B 43/12 20060101 E21B043/12; E21B 43/18 20060101
E21B043/18; E21B 43/34 20060101 E21B043/34 |
Claims
1. A method of producing natural gas from a well that also produces
liquid, the well having a string of tubing comprising: (a)
installing an injection tube in the tubing and positioning a valve
in a lower portion of a string of tubing with the valve submersed
in the liquid produced by the well; (b) with the valve in the
tubing open, flowing natural gas up the well in an annulus
surrounding the tubing and out of the well to a gas pipeline and
migrating liquid through the valve into the tubing; and (c)
periodically injecting an injection gas down the injection tube and
closing the valve to prevent the injection gas from entering the
annulus, causing the injection gas to flow back up the tubing along
with the liquid collected in the tubing.
2. The method according to claim 1, further comprising: after
flowing liquid from the tubing for a selected interval, stopping
the injection of injection gas, and opening the valve to allow
liquid in the annulus around the tubing to migrate into the tubing,
then repeating step (c) to remove more liquid from the well.
3. The method according to claim 1, wherein the injection gas of
step (c) comprises the natural gas produced by the well.
4. The method according to claim 1, wherein; step (b) further
comprises compressing the natural gas before flowing the natural
gas into the gas pipeline; and step (c) comprises delivering some
of the natural gas after being compressed to the injection tube to
serve as the injection gas.
5. The method according to claim 1, wherein during step (b), the
method further comprises: detecting the level of liquid as it
migrates into the tubing; and when the level of liquid reaches a
selected maximum level, beginning step (c).
6. The method according to claim 1, wherein during step (b), the
method further comprises: monitoring a pressure in the tubing or
the injection tube to provide an indication of the level of liquid
in the tubing to determine when to begin step (c).
7. The method according to claim 1, wherein; the valve of step (a)
is a normally open check valve; and in step (c), the valve is
closed in response to the injection gas pressure.
8. The method according to claim 1, wherein step (b) comprises
positioning a lower end of the injection tube above and in close
proximity to the valve.
9. The method according to claim 1, wherein natural gas continues
to flow up the annulus in step (b) while step (c) is occurring.
10. The method according to claim 1, wherein step (a) comprises
securing the valve to the injection tube, then inserting the
injection tube into the tubing.
11. A method of producing a low pressure gas and liquid producing
well having a string of tubing, comprising: (a) positioning a check
valve within a string of tubing adjacent a lower end of the tubing,
and extending an injection tube from a wellhead into the tubing a
short distance above the check valve; then (b) flowing gas produced
in the well up an annulus surrounding the tubing and out the
wellhead, then compressing the gas produced and delivering the gas
to a gas pipeline; (c) while step (b) is occurring, allowing liquid
produced in the well to flow through the check valve into the
tubing, causing a level of the liquid in the tubing to rise; and
(d) at a selected point, injecting some of the gas compressed in
step (b) down the injection tube, which closes the check valve and
causes the injected gas to flow up the tubing along with liquid
collected in the tubing in step (c).
11. The method according to claim 10, further comprising: after
injecting the gas in step (d) for a selected interval, ceasing step
(d), which causes the check valve to again open and allows liquid
in the annulus to flow into the tubing.
12. The method according to claim 10, further comprising:
monitoring a pressure in an upper end of the tubing or an upper end
of the injection tube during step (c) to determine when to begin
step (d).
13. The method according to claim 10, wherein step (b) occurs
without interruption while step (d) is occurring.
14. The method according to claim 19, wherein step (a) comprises
securing the check valve to the injection tube, then inserting the
injection tube and the check valve into the tubing.
15. A well, comprising: a casing having a downhole casing inlet for
the entry of natural gas and liquid produced by the well; a string
of tubing in the casing and having a tubing inlet positioned below
the casing inlet; a valve in the tubing inlet; an injection tube
inserted into the tubing; a source of gas pressure connected to an
upper end of the injection tube for selectively injecting an
injection gas into the tubing; and a controller having a first mode
wherein the valve is open, natural gas flows up an annulus
surrounding the tubing and out the well, and liquid rises in the
annulus and in the tubing, and a second mode wherein the valve is
closed, injection gas is injected into the injection tube, the
injection gas entering a lower portion of the tubing and pushing
the liquid collected within the tubing up and out the tubing.
16. The well according to claim 15, wherein the valve comprises a
normally open check valve, the valve closing in response to the
injection gas being injected into the injection tubing.
17. The well according to claim 15, further comprising: a pressure
sensor linked to the controller for determining a pressure within
the tubing or the injection tube above the level of liquid while
the controller is in the first mode to determine when the
controller switches to the second mode.
18. The well according to claim 15, further comprising: a gas
compressor at the surface for compressing the natural gas produced
by the well and delivering the compressed natural gas to a gas
pipeline; wherein the compressed natural gas serves as the
injection gas; and wherein the pressure source comprises: an
injection line leading from the gas compressor to the upper end of
the injection tube; and an injection line valve for blocking flow
of compressed natural gas during the first mode and flowing
compressed natural gas down the injection tube during the second
mode.
19. The well according to claim 15, wherein the controller allows
the natural gas to flow up the annulus surrounding the tubing and
out the well while the second mode is occurring.
20. The well according to claim 15, wherein a lower end of the
injection tube is located above and in close proximity to the
valve.
Description
FIELD OF THE INVENTION
[0001] This invention relates in general to producing wells that
have formations containing gas and liquid under low pressure, and
in particular to a method of injecting gas to produce the liquid
without affecting the gas producing formation,
BACKGROUND OF THE INVENTION
[0002] Many wells have formations that contain commercial
quantities of gas but at low pressure. Most of these wells also
produce liquid, which may be a gas condensate or it may be water or
both. A variety of methods are employed in the prior art to produce
the gas depending upon the particular conditions of the well.
[0003] For example, an operator might utilize a plunger lift
system. With the plunger lift system, a string of tubing extends
into the well. The gas is produced up the annulus surrounding the
tubing. The tubing has a plunger and a down hole gas lift valve
that allow liquid being produced to flow into the tubing above the
plunger. Periodically, the operator pressurizes the tubing annulus
with gas pressure to cause the plunger to move upward and lift the
column of liquid in the tubing to the surface. The plunger then
slides back to the lower end of the tubing for another cycle.
[0004] While plunger-lift is a successful method, injecting gas
into the casing annulus of a low pressure gas well causes the
injection gas to enter the gas producing formation. With very low
pressure formations, the operator may not be able to recover most
of the injected gas.
SUMMARY OF THE INVENTION
[0005] In this invention, the operator runs an injection tube into
the tubing and positions a valve at the lower end of the tubing.
With the valve in the tubing open, natural gas being produced by
the well flows up the annulus surrounding the tubing and out of the
wellhead to a gas pipeline. At the same time, liquid migrates into
the annulus and into the tubing. The level of liquid in the annulus
and in the tubing rises and periodically the operator will inject
gas down the injection tube with the valve closed. The gas being
injected down the injection tube lifts the liquid collected in the
tubing to the surface. The operator then shuts off the injected
gas, which causes liquid in the annulus to flow into the lower end
of the tubing, dropping the level of liquid in the annulus.
[0006] Preferably, the valve is a normally open check valve that
closes in response to injection pressure. The operator may
determine the point at which to inject gas either by a timer or by
detecting the approximate level of liquid in the tubing and in the
annulus. Detecting the liquid level may be done by using a pressure
sensor in the tubing or injection tube above the column of liquid.
The injection tube is closed prior to injecting gas, thus the
rising level of liquid will increase the pressure in the chamber
located above the level of liquid in the injection tube.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] FIG. 1 is a schematic view illustrating a well having a
system in accordance with this invention and shown in a normal
production mode.
[0008] FIG. 2 is an enlarged schematic view of the lower portion of
the tubing, the injection tube and the check valve used with the
system of FIG. 1.
[0009] FIG. 3 is a view similar to FIG. 1 but shown in a mode with
liquid previously collected in the tubing being pushed up by
injecting gas into the injection tube.
[0010] FIG. 4 is a sectional view similar to FIG. 2, but showing
the injection gas pushing the liquid from the tubing.
DETAILED DESCRIPTION OF THE INVENTION
[0011] Referring to FIG. 1, the well in this example has a vertical
casing section 11. A branch has been drilled from the original
vertical casing section 11, using a deflecting device 19 to form an
inclined branch or section 13. A substantially horizontal section
15 extends laterally outward from inclined section 13 from a
junction above the lower end of inclined section 13. The portion of
inclined section 13 located below the junction with horizontal
section 15 may be considered a sump section 17. Inclined section 13
and horizontal section 15 are illustrated to be open hole,
containing no casing. Alternately, one or both could contain
casing, a liner with perforations or a slotted liner.
[0012] A string of tubing 21 extends through vertical section 11,
inclined section 13 and into sump 17. Deflecting device 19 serves
to deflect tubing 21 over so that it will enter inclined section 13
while being run. Tubing 21 may comprise joints of conventional
production tubing secured together by threads. Alternately, tubing
21 could comprise a single continuous length of coiled tubing. The
lower end of tubing 21 is preferably located within sump 17 below
the junction of horizontal section with inclined section 13. A
tubing annulus 22 surrounds tubing 21.
[0013] Tubing 21 has an inlet at its lower end that contain a valve
23. As shown in FIG. 2, preferably valve 23 is a normally open
check valve that admits liquid into tubing 21 but blocks outward
flow when closed. As an example, valve 23 may have a valve seat 25
and a ball 27 located on the interior side of seat 25. Ball 27 is
located within a cage 29 that allows limited upward and downward
movement of ball 27 within cage 29. Unless ball 27 is forced
against valve seat 25 under pressure, liquid is free to enter and
exit through seat 25. If the internal pressure within tubing 21 at
seat 25 is greater than the external pressure, ball 27 will seal
against seat 25 to prevent any outward flow of fluid from tubing
21.
[0014] Referring again to FIG. 1, a casing head 31 is located at
the upper end of vertical section 11, forming part of a wellhead.
Casing head 31 has an outlet 33 that discharges natural gas flowing
up tubing annulus 22. Outlet 33 may have a check valve 34 to
prevent any reverse flow down tubing annulus 22. Normally, a
compressor 35 will be required to compress the gas to a sufficient
pressure level before it can be received into a commercial gas
pipeline. Compressor 35 is connected to outlet 33 and may be a type
that is equipped only to compress gas and not receive any
significant quantities of liquid. Alternately, it could be a type,
such as a liquid ring type, that can accommodate a significant
percentage of liquid.
[0015] The wellhead assembly also has a tubing head 37 that
supports tubing 21 and seals the upper end of tubing 21. Tubing
head 37 has an outlet that leads to a liquid/gas separator 39 in
this example. Separator 39 has a liquid outlet 38 for discharging
principally a liquid, which may comprise water, a light hydrocarbon
liquid, or a mixture of both. Separator 39 has a gas outlet 40 that
joins gas outlet 33 at the inlet of compressor 35, downstream from
check valve 34.
[0016] A gas injection line 41 extends from the outlet side of
compressor 35 over to tubing head 37. Gas injection line 41 is
coupled to an injection tube 43 that extends into tubing 21. A
valve 45 selectively opens and closes gas injection line 41. Valve
45 is controlled by control line 47 leading from a controller 49.
Controller 49 may have an adjustable timer for opening and closing
valve 45 at desired intervals.
[0017] Alternately, controller 49 has means for detecting a level
of liquid within tubing 21. The detection may be handled by a
pressure sensor 51 that senses the internal pressure within
injection tube 43 at the wellhead. Pressure sensor 51 is connected
by a signal line 53 to controller 49. When injection valve 45 is
closed, liquid from horizontal section 15 migrates into the lower
end of tubing 21 and also migrates up the open lower end of
injection tube 43. The space in injection tube 43 above the level
of liquid is closed by injection valve 45, thus as the liquid rises
in injection tube 43, the pressure in this closed column increases.
This pressure increase is sensed by pressure sensor 51.
Alternately, pressure sensor 51 could monitor pressure in the upper
end of tubing 21.
[0018] Injection tube 43 comprises a tubing of smaller diameter
than tubing 21. Injection tube 43 preferably comprises continuous
metal coiled tubing, but it could be made up of sections of tubing
secured together by threads. Gas injection tube 43 extends to a
point near the lower end of tubing 21 above valve 23, shown in FIG.
2. Preferably the lower end of gas injection tube 43 is no more
than a few inches from valve 23.
[0019] In the preferred embodiment, check valve cage 29 is secured
to the lower end of injection tube 43, such that check valve 23 is
run into tubing 21 when injection tube 43 is being installed. The
outer diameter of seat 25 preferably forms a seal with the inner
diameter of tubing 21 at the lower end. The sealing arrangement
could be done many ways, such as by an elastomeric or metal ring
sealing against a lip or band located in the inner diameter of
tubing 21 at the lower end. Alternately, check valve 23 could be
mounted to tubing 21 and ran with tubing 21.
[0020] During the first mode of operation, gas injection valve 45
is closed and valve 23 will be open because of the lack of any
pressure differential at seat 25, as shown in FIG. 2 Gas flows from
horizontal section 15 into inclined section 13. The gas flows up
annulus 22 surrounding tubing 21, and through casing head 31 to
compressor 35. Compressor 35 compresses the gas for delivery to a
gas pipeline. The gas being produced will normally not flow into
tubing 21 or injection tube 43 even though check valve 23 is open
because of several factors: check valve 23 is at a lower elevation
than horizontal section 15; check valve 23 is normally submersed in
liquid in sump 17; and the gas in horizontal section 15 is at a
very low pressure, such as about 100 psi.
[0021] The liquid produced along with the gas migrates or flows
into sump 17 and into tubing 21 through the open valve 23. The
liquid will flow into injection tube 43, which is always open at is
lower end, as well as up tubing 21 surrounding injection tube 43.
The level of liquid in tubing annulus 22, tubing 21 and injection
tube 43 will be the same and will rise as the liquid continues to
be produced. As the level of liquid rises in injection tube 43, the
closed chamber in injection tube 43 above the level will become
smaller. This reduction causes an increase in pressure in injection
tube 43 that is sensed by pressure sensor 51, if one is utilized,
which provides a signal to controller 49. At a point previously
selected by the operator, the liquid level will be high enough to
cause controller 49 to open gas injection valve 45. Preferably, the
opening of gas injection valve 45 occurs before horizontal section
15 is completely filled with liquid, which would impede the flow of
gas. Rather than detecting the liquid level, the operator could
determine appropriate times to open and close gas injection valve
45 by trial and error, then use a timer.
[0022] When valve 45 is open, compressed natural gas flows through
injection line 41 and injection tube 43 to the lower end of tubing
21. As shown in FIG. 4, this increased pressure causes ball 27 to
seal against seat 25. The sealing of ball 27 against seat 25 and
the sealing arrangement of seat 25 against the inner diameter of
tubing 21 block the outward flow of injection gas from tubing 21.
The injection gas thus does not flow into horizontal section 15.
Rather, the injection gas turns at valve 23 and begins flowing
upward in tubing 21, pushing the column of liquid above it. Liquid
along with injection gas will flow into separator 39, which
separates the liquid from the injection gas. The liquid flows out
liquid outlet 38 for disposal, re-injection, or if the liquid
contains hydrocarbons, for sale. The injection gas flows through
line 40 back into compressor 35 for re-compressing and delivery to
a gas pipeline.
[0023] When a significant quantity of the liquid has been produced
out liquid outlet 38, controller 49 will close valve 45. Normally,
the amount of time that gas is injected is determined by trial and
error and set by a timer. When injection gas valve 45 closes
initially, the upper end of injection tube 43 will again be closed.
The closure of injection gas valve 45 removes the pressure on ball
27 that caused it to seal against seat 25. The liquid contained
within sump 17 above the lower end of tubing 21 will then flow
through seat 25 into tubing 21 until the level within tubing 21,
injection tube 43, and tubing annulus 22 in sump 17 equal each
other.
[0024] When the pressure level in the chamber above the liquid in
injection tube 43 again reaches the maximum allowable sensed by
sensor 51, controller 49 repeats the cycle. During the injection
period, since valve 23 is closed, the production of gas will
continue unimpeded by the injection through injection tube 43.
[0025] The invention has significant advantages. The system allows
an operator to produce low pressure gas economically. The injection
gas pressure is not applied to the producing formation, thus the
injection gas does not flow into the producing formation. An
electrical or mechanical pump is not required. If tubing is already
in place, the operator does not have to pull the tubing, rather can
run the check valve and injection tube into previously installed
tubing.
[0026] While the invention has been shown in only one of its forms,
it should be apparent to those skilled in the art that it is not so
limited but is susceptible to various changes without departing
from the scope of the invention. For example, although shown with a
well having a branch with an inclined and a horizontal section, the
system could also be employed with a vertical well. The injection
gas could be a hydrocarbon gas from another well or source. The
injection gas could also be a non-hydrocarbon gas, such as carbon
dioxide or nitrogen.
* * * * *