U.S. patent application number 12/038264 was filed with the patent office on 2009-08-27 for system and method for removing liquid from a gas well.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Thomas Cairney, Bahman Emtiazian.
Application Number | 20090211753 12/038264 |
Document ID | / |
Family ID | 40548076 |
Filed Date | 2009-08-27 |
United States Patent
Application |
20090211753 |
Kind Code |
A1 |
Emtiazian; Bahman ; et
al. |
August 27, 2009 |
SYSTEM AND METHOD FOR REMOVING LIQUID FROM A GAS WELL
Abstract
A technique is employed to remove liquid from a gas well to
improve gas production from the well. An electric submersible
pumping system is deployed into the wellbore and positioned to
remove accumulated liquid. The electric submersible pumping system
is constructed and controlled to maintain a flow of liquid during
operation of the pumping system.
Inventors: |
Emtiazian; Bahman;
(Aberdeen, GB) ; Cairney; Thomas; (Aberdeen,
GB) |
Correspondence
Address: |
SCHLUMBERGER RESERVOIR COMPLETIONS
14910 AIRLINE ROAD
ROSHARON
TX
77583
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
40548076 |
Appl. No.: |
12/038264 |
Filed: |
February 27, 2008 |
Current U.S.
Class: |
166/250.03 ;
166/66 |
Current CPC
Class: |
E21B 43/128 20130101;
E21B 43/121 20130101 |
Class at
Publication: |
166/250.03 ;
166/66 |
International
Class: |
E21B 43/00 20060101
E21B043/00 |
Claims
1. A method of gas well deliquification, comprising: enclosing an
electric submersible pumping system with a shroud; connecting a
tail pipe to a lower end of the shroud; conveying the electric
submersible pumping system into a gas well via a tubing until the
tail pipe enters a region susceptible to liquid accumulation;
operating the electric submersible pumping system to pump liquid
from the region and up through the tubing; and producing gas along
an annulus formed around the shroud and the tubing.
2. The method as recited in claim 1, further comprising directing
the gas into the tubing via at least one gas mandrel installed
below a production packer.
3. The method as recited in claim 1, comprising setting a
production packer in the annulus; and directing the gas through the
production packer via a gas vent valve installed at the production
packer.
4. The method as recited in claim 3, comprising controlling the gas
vent valve via a hydraulic control line.
5. The method as recited in claim 1, comprising using a downhole
sensor to monitor a well characteristic at the electric submersible
pumping system.
6. The method as recited in claim 1, comprising utilizing a gas
handler in cooperation with the electric submersible pumping
system.
7. The method as recited in claim 1, comprising controlling
operation of the electric submersible pumping system to ensure
liquid is not entirely pumped off.
8. The method as recited in claim 5, wherein using the downhole
sensor comprises monitoring a pump intake pressure.
9. The method as recited in claim 8, wherein using the downhole
sensor further comprises monitoring an annulus pressure.
10. A method, comprising: determining accumulation of a liquid in a
gas well; and utilizing an electric submersible pumping system to
pump a sufficient amount of the liquid from the gas well to improve
gas production from the gas well.
11. The method as recited in claim 10, comprising drawing liquid
along the electric submersible pumping system within a shroud.
12. The method as recited in claim 10, comprising controlling
operation of the electric submersible pumping system to avoid gas
lock.
13. The method as recited in claim 10, comprising operating a gas
handler in cooperation with the electric submersible pumping system
to remove gas from the liquid to be pumped by the electric
submersible pumping system.
14. The method as recited in claim 10, wherein utilizing comprises
pumping liquid upwardly through a tubing.
15. The method as recited in claim 14, comprising producing gas
upwardly along an annulus surrounding the tubing.
16. The method as recited in claim 15, comprising directing the gas
into the tubing below a production packer.
17. The method as recited in claim 15, comprising directing the gas
through a production packer via a gas vent valve.
18. A system for use in gas well deliquification, comprising: an
electric submersible pumping system deployed in a gas well; a
shroud positioned around the electric submersible pumping system,
the shroud having an inlet located to receive liquid from a liquid
accumulation region of the gas well; a tubing by which the electric
submersible pumping system is deployed in the gas well, the tubing
defining a liquid flow path and a gas flow path; a production
packer located above the electric submersible pumping system; and a
mechanism to enable gas flow past the production packer.
19. The system as recited in claim 18, wherein the mechanism
comprises a gas mandrel oriented to direct gas into the tubing from
an annulus surrounding the tubing.
20. The system as recited in claim 18, wherein the mechanism
comprises a gas vent valve positioned in the production packer.
21. The system as recited in claim 18, comprising a tail pipe
extending downwardly from the inlet of the shroud.
22. The system as recited in claim 18, comprising a sensor system
positioned downhole to detect parameters indicative of insufficient
liquid entering the electric submersible pumping system.
23. The system as recited in claim 18, comprising a surface control
system, wherein the surface control system selectively reduces the
speed of the electric submersible pumping system to avoid gas lock.
Description
BACKGROUND
[0001] Gas wells exist in a variety of environments throughout many
regions of the world. Generally, a wellbore is drilled and gas is
produced up through the wellbore. Over time, a significant
percentage of the gas wells lose lift capability due to liquid
accumulation in the wellbore. The liquid loading of gas wells
results from formation water influx and/or condensation in the
wellbore at regions of reduced wellbore temperature. Temperature,
well depth, and water-gas ratio are three common factors that
affect the liquid loading of gas wells.
[0002] Often, liquid loading in gas wells occurs late in the field
life of the well when gas flow rates decrease and gas velocities in
the wellbore are not sufficient to lift the condensed liquids to
the surface. The well may flow at a stable rate for many days but a
small reduction in flow rate, or an increase in hydrostatic back
pressure, can trigger instability and load the well with liquid in
days or even hours. Sufficient condensation of water or influx of
water from the formation ultimately can lead to cessation of gas
production. The liquid loading of a gas well creates a particularly
challenging environment for application of any assisted lift
solutions.
SUMMARY
[0003] In general, the present invention provides a system and
method for removing liquid from a gas well, i.e. gas well
deliquification. The system and method involve determining whether
liquid has accumulated, or is likely to accumulate, in a gas well.
An electric submersible pumping system is deployed into the
wellbore and positioned to remove accumulated liquid. Operation of
the electric submersible pumping system is then controlled to
remove sufficient liquid for improvement of gas production from the
gas well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] Certain embodiments of the invention will hereafter be
described with reference to the accompanying drawings, wherein like
reference numerals denote like elements, and:
[0005] FIG. 1 is a front elevation view of an electric submersible
pumping system deployed in a wellbore of a gas well, according to
an embodiment of the present invention;
[0006] FIG. 2 is a front elevation view of another example of an
electric submersible pumping system deployed in a wellbore of a gas
well, according to an embodiment of the present invention;
[0007] FIG. 3 is a front elevation view of another example of an
electric submersible pumping system deployed in a wellbore of a gas
well, according to an embodiment of the present invention; and
[0008] FIG. 4 is a flow chart illustrating one example of a
procedure for conducting a liquid removal operation to improve gas
well production, according to an embodiment of the present
invention.
DETAILED DESCRIPTION
[0009] In the following description, numerous details are set forth
to provide an understanding of the present invention. However, it
will be understood by those of ordinary skill in the art that the
present invention may be practiced without these details and that
numerous variations or modifications from the described embodiments
may be possible.
[0010] The present invention generally relates to a system and
method to remove liquid loading in gas wells. The methodology is
amenable to use in deep, low pressure, high water-gas ratio gas
wells, however the methodology can be used in a wide variety of gas
wells to remove liquid that is limiting or potentially limiting gas
production from the well. An artificial lift mechanism, such as an
electric submersible pumping system, is deployed into the well to a
position at which the liquid can be drawn into the mechanism and
moved to a discharge location, such as a surface location. Use of
the electric submersible pumping system enables deliquification of
the gas well in an economical manner, resulting in continued
operation and/or improved operation of the gas well. The electric
submersible pumping system can be operated intermittently or
continuously, as necessary, to remove sufficient liquid for
improved operation of the gas well.
[0011] Initially, candidate gas wells are selected based on
existing liquid loading or on the potential for liquid loading.
Background information on the environment, reservoir, and specific
gas well can be used to target candidate wells. A variety of gas
well related data also can be collected and analyzed to identify
the reasons for underperformance of the gas well and to evaluate
the potential for improvement. The data may include historical
production trends that are evaluated and analyzed for a given gas
well or for groups of gas wells. Once a candidate gas well is
selected, the artificial lift mechanism can be deployed into the
wellbore to effectively unload liquid from the gas well or to at
least be positioned for future liquid removal.
[0012] Referring generally to FIG. 1, one embodiment of a system 20
for unloading liquid from a gas well is illustrated. In this
example, the artificial lift mechanism is in the form of an
electric submersible pumping system 22 deployed in a wellbore 24 of
a gas well 26. A shroud 28 is deployed around electric submersible
pumping system 22 and encloses the submersible pumping system 22
except for a shroud inlet 30. The shroud 28 can be a made of a
liquid impermeable material, e.g., metal or polymer, and can
connect to an outer radial portion of the electrical submersible
pumping system 22 and extend downward from the connection thereby
providing a space between the shroud 28 and the electrical
submersible pumping system 22. The shroud inlet 30 is located
proximate to the end of the shroud 28 that is distal from the
connection of the shroud 28 to the electrical submersible pumping
system 22. Essentially, the shroud 28 can act as a barrier to fluid
in a radial direction around the electric submersible pumping
system 22, while allowing fluid to enter into the shroud though the
shroud inlet 30. Preferably, the shroud 28 is both fluid
impermeable and liquid impermeable.
[0013] Electric submersible pumping system 22 and shroud 28 are
conveyed downhole into wellbore 24 via a suitable conveyance 32.
Conveyance 32 may comprise a tubing 34, such as production tubing
or coiled tubing, able to convey fluid upwardly along wellbore 24.
For example, conveyance 32 may be used to define a first fluid flow
path 36 along the interior of the conveyance 32 and a second fluid
flow path 38 along the exterior of the conveyance 32 in the annulus
formed between conveyance 32 and the wall defining wellbore 24. In
the embodiment illustrated, liquid is directed through tubing 34
along flow path 36, and gas is produced through the annulus along
second flow path 38.
[0014] Conveyance 32 is used to deliver the shrouded electric
submersible pumping system 22 to a region 40 in which a liquid 42
has collected or is likely to collect. Liquid 42 can result from
condensation or the influx of liquid from a surrounding formation
44. The liquid 42 collects in region 40, generally at a lower
portion of wellbore 24. Once pumping system 22 is positioned at the
desired region 40, a packer 46, e.g. a production packer, is set
and liquid 42 can be removed from region 40 by controlled operation
of the electric submersible pumping system 22.
[0015] Electric submersible pumping system 22 may have a variety of
components depending on the depth of region 40, the characteristics
of liquid 42, the general design of system 20, and other system and
environmental factors. In the example illustrated, electric
submersible pumping system 22 comprises a submersible pump 48
coupled to a pump intake 50. The submersible pump 48 is driven by a
submersible motor 52 coupled to a motor protector 54. Power is
provided to submersible motor 52 via a suitable power cable 56.
[0016] When electric submersible pumping system 22 is operated,
liquid 42 is drawn through shroud inlet 30 and routed upwardly
between pumping system 22 and shroud 28 until the liquid reaches
pump intake 50, as represented by arrows 58. Submersible pump 48
pumps the liquid 42, discharges the liquid 42 into tubing 34, and
delivers the liquid 42 upwardly along flow path 36. In this
example, the liquid 42 is delivered upwardly through a surface
wellhead 60 for delivery to a surface discharge location. In other
embodiments, the discharged liquid 42 could be delivered to a
subterranean storage location. As the liquid loading is reduced,
greater gas production occurs along second flow path 38. The
produced gas is moved past production packer 46 via an appropriate
bypass mechanism 62, as discussed in greater detail below.
[0017] The shroud 28 ensures that a flow of liquid is maintained
along submersible motor 52 to cool the motor. Additionally, shroud
28 can be designed in a variety of configurations to enable removal
of liquid 42 without necessarily submerging pump intake 50 within
the liquid. However, operation of electric submersible pumping
system 22 is controlled to ensure operation only when sufficient
liquid is available at pump intake 50 to avoid gas lock or other
detrimental conditions due to excess gas in submersible pump 48. If
the liquid 42 is about to be pumped off to an extent that it cannot
be drawn through shroud inlet 30, the operational speed of pumping
system 22 is reduced or stopped.
[0018] A sensor system 64 having at least one sensor, but
preferable a variety of sensors, can be used to monitor one or more
well related parameters that are indicative of insufficient liquid
entering the electric submersible pumping system 22. For example,
sensors 64 may comprise pressure sensors positioned to measure a
pump intake pressure and/or an annulus pressure. Data from sensors
64 can be relayed uphole to a surface control system 66 via an
appropriate communication line 68. Communication line 68 may be an
electric line, optical line, wireless communication line, or other
suitable communication line or communication lines. Based on data
from sensors 64, surface control system 66 is used to control, for
example, the operational speed of electric submersible pumping
system 22. By way of example, surface control system 66 may
comprise a variable speed drive that can be used to selectively
control the power supply to submersible motor 52 which, in turn,
controls the operational speed of pumping system 22. Surface
control system 66 may be constructed in a variety of configurations
depending on the monitoring and control functionality required. In
a variety of applications, surface control system 66 further
comprises a computer-based system that can be programmed to collect
and analyze data and to automatically control operation of electric
submersible pumping system 22.
[0019] A more detailed example of one type of deliquification
system 20 is illustrated in FIG. 2. In this embodiment, a tail pipe
70 is connected to shroud 28 and extends downwardly into region 40.
The tailpipe 70 is preferable a hollow tubular member. During
operation of electric submersible pumping system 22, liquid 42 is
drawn upwardly through tail pipe 70 into shroud 28 and then into
electric submersible pumping system 22, which pumps the liquid 42
upwardly along flow path 36. The use of tail pipe 70 and shroud 28
enables removal of liquid 42 from a desired region 40 even when the
electric submersible pumping system 22 is separated from the liquid
42 within region 40.
[0020] Other components can be used in combination with tail pipe
70. For example, a tail pipe screen 72 may be mounted at an inlet
to the tail pipe to screen or filter liquid drawn into tail pipe
70. Additionally, a half mule shoe 74 can be mounted at a lower end
of the tail pipe 70. A check valve 76 also can be mounted in the
flow of fluid through tail pipe 70 to prevent backflow of the fluid
that is drawn into shroud 28. Furthermore, a gas handler 78 can be
combined with electric submersible pumping system 22 to remove
entrained gas from liquid 42, thus further optimizing the
performance of electric submersible pumping system 22. By way of
example, gas handler 78 may comprise an Advanced Gas Handler
available from Schlumberger Corporation.
[0021] In the example illustrated in FIG. 2, the removed liquid 42
and the produced gas are maintained along separate flow paths to
wellhead 60. This configuration of system 20 can be referred to as
a parallel concentric flow system in which liquid is pumped
upwardly along the interior of tubular 34 and gas is produced
through the surrounding annulus to the wellhead 60. One or more gas
vent valves 80 are deployed in production packer 46 and serve as
bypass mechanism 62 to enable the bypass flow of gas past the
production packer 46. The gas vent valves 80 can be constructed in
a variety of configurations that are controllable to selectively
open or close the flow path through packer 46. By way of example,
the gas vent valve 80 may be a hydraulically actuated valve
controlled by hydraulic input supplied through a control line 82.
In the parallel concentric flow embodiment, liquid 42 is lifted
from region 40 through tubing 34, e.g. production tubing or coiled
tubing, to the surface at a wellhead pressure independent of the
produced gas wellhead pressure.
[0022] The ability to control gas vent valves 80 enables selective
placement of a barrier to gas flow and pressure beneath packer 46.
A further barrier can be provided by a tubing installed subsurface
safety valve 84 positioned to provide control over flow of liquid
along flow path 36. The valve 84 may be selectively opened to
enable flow or closed to isolate the region below packer 46. By way
of example, valve 84 may be a hydraulically actuated valve also
controlled via hydraulic input through control line 82 or through
another suitable control line.
[0023] In this embodiment, surface control system 66 comprises a
motor controller incorporated into a variable speed drive so
electric submersible pumping system 22 can be shut off or operated
at a desirable speed to enable sufficient removal of liquid 42 from
region 40 without incurring gas lock. The surface control system 66
is connected to electric submersible pumping system 22 via power
cable 56 routed through an appropriate junction box 86. Application
of the variable speed drive and a motor controller increases the
flexibility of system 20 and directly influences the volume of
liquid 42 that can be lifted to the surface via pumping system 22.
In this way, the liquid removal rate can be fine tuned in an
effective manner to maintain a desired liquid level in wellbore
24.
[0024] Additionally, surface control system 66 receives data from
sensors 64 to facilitate analysis and action based on liquid
removal from region 40. By way of example, sensor system 64 may
comprise a Phoenix Multisensor available from Schlumberger
Corporation. The downhole measurements can be combined with surface
measurements to enable detailed analysis of the lifting performance
and to ensure the liquid pumping operation stays within the limits
of the pump curve associated with the electric submersible pumping
system 22. The downhole sensor data, e.g. wellbore pressure data,
can be provided in real-time to control system 66. Furthermore, the
downhole data and surface data can be analyzed according to a
variety of available wellbore models related to a specific
artificial lift system, e.g. electric submersible pumping system
22. The ongoing evaluation of data provides an efficient and
cost-effective way of maintaining desired operation of electric
submersible pumping system 22 and the consequent removal of liquid
42 from region 40. In many applications, pump intake pressure and
annulus pressure fluctuations provide helpful information related
to the detection and control of liquid loading as well as providing
an indication of the potential for gas lock.
[0025] Referring generally to FIG. 3, another embodiment of system
20 is illustrated. In this embodiment, many features and components
are the same as those described and illustrated with respect to
FIG. 2. However, the gas is produced upwardly along flow path 38
and along a portion of the annulus surrounding tubing 34 before
being diverted into the tubing 34. Within tubing 34, the gas and
liquid 42 are commingled and delivered to the surface.
[0026] In the example illustrated, one or more gas mandrels 88 are
installed below the production packer 46 to serve as bypass
mechanism 62. Each gas mandrel 88 comprises a valve 90, e.g. a gas
vent valve, that enables flow of gas from the annulus into the
interior of tubing 34. The liquid 42 removed from region 40 by
electric submersible pumping system 22 is commingled with the gas
at gas mandrels 88 and delivered upwardly to wellhead 60 through
tubing 34. This technique can be referred to as a shallow diverted
flow technique for the removal of liquid loading in a gas well. The
approach provides independent production of gas and liquid until
the point of convergence via gas mandrels 88 which are positioned
at a shallower depth of the well profile. Diversion of the gas flow
back into tubing 34 below packer 46 can create a strong gas lift
effect which reduces the required horsepower for electric
submersible pumping system 22, thus enhancing the overall
efficiency of the pumping system. Because the gas and liquid are
commingled in the tubing 34, the risk of gas leakage due to lack of
casing integrity at the top section of the wellbore is reduced and
preferably eliminated.
[0027] The number of gas mandrels 88, the orifice sizes, and the
depth of production packer 46 can be varied according to specific
gas well and environmental factors. Additionally, a variety of
other features can be selected or changed in any of the embodiments
described herein. For example, the depth of the electric
submersible pumping system 22 and the length of tail pipe 70 can
vary from one application to another for optimization of the
deliquification procedure. The number of submersible pumps,
submersible electric motors, and other components of electric
submersible pumping system 22 also can vary from one application to
another. Selection of the various components can be affected by a
variety of well related factors, including well depth, bottom hole
temperature, source of water production, bottom hole pressure, gas
composition, and artificial lift technique implemented. In the
shallow diverted flow technique, the addition of gas vent valve 80
is optional to provide a secondary, controllable gas flow path
through production packer 46.
[0028] In operation, a variety of system configurations can be used
to perform many types of deliquification procedures in various gas
wells. One example of such a procedure is provided by the flowchart
illustrated in FIG. 4. In this example, a gas well having liquid
loading or being susceptible to liquid loading is selected, as
indicated by block 92. An artificial lift mechanism is then
prepared by, for example, constructing electric submersible pumping
system 22 with a surrounding shroud 28, as illustrated by block 94.
Selection of the specific type of artificial lift mechanism, e.g.
electric submersible pumping system, depends on a variety of
factors, including well/reservoir analysis, equipment features,
completion configuration, performance envelope, component
constraints and limitations, risk control factors, completion
installation procedures and other factors.
[0029] Once the artificial lift mechanism is selected, the
artificial lift mechanism can be deployed into the gas well 26. In
this example, a shrouded electric submersible pumping system is
deployed into the gas well 26, as illustrated by block 96. The
electric submersible pumping system is then operated to draw
collected liquid from region 40 into the shroud 28, as illustrated
by block 98. The liquid is then pumped to a discharge location,
such as a surface discharge location, as illustrated by block 100.
Reduction of the liquid loading in the gas well increases
production of gas which is directed upwardly along a separate flow
passage, as indicated by block 102. The produced gas is moved past
a production packer by an appropriate bypass mechanism, as
illustrated by block 104. Examples of bypass mechanisms comprise
gas vent valves, installed at the production packer, or gas
mandrels, installed below the production packer, to commingle the
gas with the flowing stream of liquid discharged by the electric
submersible pumping system.
[0030] The liquid at region 40 of the gas well and/or the liquid
flow to electric submersible pumping system 22 is monitored. One or
more sensors can be used to detect and monitor well parameters,
e.g. pump intake pressure and annulus pressure, indicative of
insufficient liquid, as illustrated by block 106. The sensors also
can be used to monitor a variety of other parameters related to
maintaining and/or optimizing production of gas. Based on sensor
data, the electric submersible pumping system is controlled via
control system 66 to maintain the increased gas production while
avoiding gas lock or other detrimental problems associated with
excess gas reaching submersible pump 48, as illustrated by block
108.
[0031] Use of the electric submersible pumping system facilitates
maintenance of flow rates in many types of gas wells that would
otherwise suffer from decreased production or a production
stoppage. Additionally, the electric submersible pumping system
provides excellent dynamic response to the liquid accumulation in a
given gas well or to changes in operating conditions. The electric
submersible pumping system requires little or no stabilization time
to bring liquid to a surface location in the case of intermittent
gas well operation.
[0032] Many configurations of completions and artificial lift
mechanisms can be used to provide an easily controlled system for
removing accumulated liquid from gas wells. The arrangement and
selection of components depends on the size, depth and
characteristics of the gas well and on the design of the electric
submersible pumping system and related components. Various
components can be added or substituted depending on the
requirements of the specific operation that is designed to improve
gas production for a given well.
[0033] Accordingly, although only a few embodiments of the present
invention have been described in detail above, those of ordinary
skill in the art will readily appreciate that many modifications
are possible without materially departing from the teachings of
this invention. Such modifications are intended to be included
within the scope of this invention as defined in the claims.
* * * * *