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Publication numberUS20090008101 A1
Publication typeApplication
Application numberUS 11/774,361
Publication dateJan 8, 2009
Filing dateJul 6, 2007
Priority dateJul 6, 2007
Publication number11774361, 774361, US 2009/0008101 A1, US 2009/008101 A1, US 20090008101 A1, US 20090008101A1, US 2009008101 A1, US 2009008101A1, US-A1-20090008101, US-A1-2009008101, US2009/0008101A1, US2009/008101A1, US20090008101 A1, US20090008101A1, US2009008101 A1, US2009008101A1
InventorsPatrick T. Coady
Original AssigneeCoady Patrick T
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Method of Producing a Low Pressure Well
US 20090008101 A1
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.
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Claims(21)
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

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

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.

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.

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

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.

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

FIG. 1 is a schematic view illustrating a well having a system in accordance with this invention and shown in a normal production mode.

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US7784548 *Apr 23, 2008Aug 31, 2010Conocophillips CompanySmart compressed chamber well optimization system
US7789158 *Aug 1, 2008Sep 7, 2010Pine Tree Gas, LlcFlow control system having a downhole check valve selectively operable from a surface of a well
US7971649 *Aug 1, 2008Jul 5, 2011Pine Tree Gas, LlcFlow control system having an isolation device for preventing gas interference during downhole liquid removal operations
US8794305Oct 16, 2012Aug 5, 2014Scott J WilsonMethod and apparatus for removing liquid from a horizontal well
US20120067569 *Oct 25, 2010Mar 22, 2012Alan Keith BrownWell De-Liquefying System and Method
US20120073820 *Sep 27, 2011Mar 29, 2012Rite Increaser, LLCChemical Injector for Wells
WO2013062806A1 *Oct 16, 2012May 2, 2013Wilson Scott JMethod and apparatus for removing liquid from a horizontal well
Classifications
U.S. Classification166/370, 166/372, 166/105.5, 166/325
International ClassificationE21B43/12, E21B43/16, E21B43/18, E21B43/34
Cooperative ClassificationE21B43/34, E21B43/121
European ClassificationE21B43/34, E21B43/12B
Legal Events
DateCodeEventDescription
Feb 28, 2008ASAssignment
Owner name: FLUID COMPRESSOR PARTNERS, LTD., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:DEMAREE, ROBERT;REEL/FRAME:020594/0437
Effective date: 20080214
Dec 6, 2007ASAssignment
Owner name: FLUID COMPRESSOR PARTNERS, LTD., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:COADY, PATRICK T.;REEL/FRAME:020222/0327
Effective date: 20070620