U.S. patent application number 12/420071 was filed with the patent office on 2009-10-29 for combination injection string and distributed sensing string for well evaluation and treatment control.
Invention is credited to Henning Hansen, Charles R. Price.
Application Number | 20090266537 12/420071 |
Document ID | / |
Family ID | 41213845 |
Filed Date | 2009-10-29 |
United States Patent
Application |
20090266537 |
Kind Code |
A1 |
Hansen; Henning ; et
al. |
October 29, 2009 |
COMBINATION INJECTION STRING AND DISTRIBUTED SENSING STRING FOR
WELL EVALUATION AND TREATMENT CONTROL
Abstract
A method for well intervention includes extending a combination
conduit into a wellbore. The combination conduit includes a first
conduit for moving fluid into the wellbore and a second conduit
having at least one optical sensing fiber therein. A fluid is moved
into the wellbore through the first conduit. A wellbore parameter
is measured through a sensor associated with the at least one
optical sensing fiber.
Inventors: |
Hansen; Henning; (Alicante,
ES) ; Price; Charles R.; (Conroe, TX) |
Correspondence
Address: |
RICHARD A. FAGIN
P.O. BOX 1247
RICHMOND
TX
77406-1247
US
|
Family ID: |
41213845 |
Appl. No.: |
12/420071 |
Filed: |
April 8, 2009 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
61047925 |
Apr 25, 2008 |
|
|
|
Current U.S.
Class: |
166/250.01 ;
166/242.2; 166/305.1; 166/66 |
Current CPC
Class: |
E21B 17/206 20130101;
E21B 47/06 20130101 |
Class at
Publication: |
166/250.01 ;
166/305.1; 166/242.2; 166/66 |
International
Class: |
E21B 43/00 20060101
E21B043/00; E21B 43/16 20060101 E21B043/16; E21B 47/00 20060101
E21B047/00; E21B 47/06 20060101 E21B047/06; E21B 17/00 20060101
E21B017/00 |
Claims
1. A method for well intervention, comprising: extending a
flexible, spoolable combination conduit into a wellbore, the
combination conduit including a first conduit for moving fluid into
the wellbore and a second conduit having at least one optical
sensing fiber therein; moving a fluid into the wellbore through the
first conduit; and measuring a wellbore parameter through a sensor
associated with the at least one optical sensing fiber.
2. The method of claim 1 wherein the wellbore parameter comprises
pressure.
3. The method of claim 1 wherein the wellbore parameter comprises
temperature.
4. The method of claim 3 wherein the measuring temperature is
performed at a plurality of positions along the wellbore.
5. The method of claim 1 wherein the wellbore parameter comprises a
parameter related to fluid level in the wellbore.
6. The method of claim 1 wherein the fluid comprises foaming
agent.
7. The method of claim 1 further comprising controlling a rate of
movement of the fluid in response to measurements of the wellbore
parameter.
8. A wellbore intervention device, comprising: a first conduit
configured to move fluid therethrough; a second conduit including
therein at least one optical fiber; and the first conduit and the
second conduit enclosed in a spoolable, non-metallic
encapsulant.
9. The device of claim 8 wherein the encapsulant comprises glass
fiber reinforced plastic.
10. The device of claim 8 wherein the optical fiber comprises a
distributed temperature sensing element.
11. The device of claim 8 wherein the first conduit and the second
conduit are disposed in the encapsulant to thermally isolate the
first conduit from the second conduit, and the second conduit is
exposed to ambient temperature in the wellbore.
12. The device of claim 8 further comprising a fluid discharge
control valve disposed at one end of first conduit.
13. The device of claim 8 further comprising a pressure sensor
disposed at one end of the second conduit.
14. The device of claim 13 wherein the pressure sensor comprises an
optical sensor.
15. The device of claim 13 further comprising a fluid pump coupled
to the other end of the first conduit, and a control system in
signal communication with the pressure sensor, the control system
configured to operate the fluid pump such that a selected pressure
is maintained in a wellbore when the intervention device is
disposed in the wellbore.
16. The device of claim 8 wherein the first conduit and the second
conduit comprise steel.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Priority is claimed from U.S. Provisional Application No.
61/047,925 filed on Apr. 25, 2008.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND OF THE INVENTION
[0003] 1. Field of the Invention
[0004] The invention relates generally to the field of wellbore
treatment using coiled tubing or similar intervention devices. More
specifically, the invention relates to methods and devices for
controlling injection of dewatering agents in gas wells to optimize
production and to minimize wellbore shut in for retreatment.
[0005] 2. Background Art
[0006] It is known in the art to inject chemicals such as foaming
agents into wellbores that produce natural gas. The foaming agents
combine with water that may be produced from one or more rock
formations in the subsurface. The produced water can at least
partially fill the wellbore. Hydrostatic pressure exerted by the
column of produced water in the wellbore acts against natural gas
entering the wellbore from one or more producing formations. Thus,
hydrostatic pressure of water can reduce gas production. The
foaming agent when introduced into the wellbore combines with the
water and gas to reduce the density of the water by causing it to
create foam. The reduced density foam results in a corresponding
reduction in hydrostatic pressure against the gas producing
formations, thus increasing gas production.
[0007] A common difficulty in using such chemical injection to
improve gas well production is controlling the rate of injection of
the foaming agent. Too little agent will result in insufficient
reduction in the hydrostatic pressure of the water column. Too much
agent can cause excessive foam lifting to the surface, which may
require shutting the well in and cleaning the produced foam from
production equipment at the surface.
[0008] It is known in the art to provide a distributed temperature
sensor into a wellbore using a semi-rigid, spoolable intervention
device. Such a device is sold under the trademark ZIPLOG, which is
a trademark of Ziebel, A.S., Tananger, Norway, the assignee of the
present invention. The ZIPLOG device is based on pushing a semi
stiff spoolable rod into active, high deviation wells to perform
distributed temperature sensing and single point in-wellbore
pressure fluid surveys. Information about the Ziebel ZIPLOG system
can be reviewed on the Internet at the Uniform Resource Locator
http://www.ziebel.biz/newsletters/ZipLog%20Application%20Guide.pdf.
[0009] There exists a need for a system that can combine
distributed sensing in a wellbore with fluid injection capability
for real time monitoring of the effects of the intervention
procedure.
SUMMARY OF THE INVENTION
[0010] A method for well intervention according to one aspect of
the invention includes extending a combination conduit into a
wellbore. The combination conduit includes a first conduit for
moving fluid into the wellbore and a second conduit having at least
one optical sensing fiber therein. A fluid is moved into the
wellbore through the first conduit. A wellbore parameter is
measured through a sensor associated with the at least one optical
sensing fiber.
[0011] A wellbore intervention device according to another aspect
of the invention includes a first conduit configured to move fluid
therethrough. The device includes a second conduit including
therein at least one optical fiber. The first conduit and the
second conduit are enclosed in a spoolable encapsulant.
[0012] Other aspects and advantages of the invention will be
apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] FIG. 1 shows an example of a combination injection
tubing/sensing conduit that may be disposed in a wellbore at one
end of a composite tubing string.
[0014] FIG. 2 shows a cross section of one example of the
combination conduit shown in FIG. 1.
[0015] FIG. 3 shows a cross section of another example of a
combination conduit.
[0016] FIG. 4 shows equipment used to deploy the combination
conduit into a wellbore.
[0017] FIG. 5 shows an example of a pressure control head used with
the combination conduit.
[0018] FIG. 6 shows a foaming agent injection pump coupled to the
upper end portion of the combination conduit.
DETAILED DESCRIPTION
[0019] In a method and system according to the invention, a
distributed sensing system, such as a distributed fiber optic
temperature sensor ("DTS") may be inserted into a wellbore, such as
a gas producing wellbore along with a fluid injection conduit in a
single, spoolable system. The DTS may be of the same type as in the
ZIPLOG system described in the Background section herein. For
purposes of explaining the present invention, the DTS sensing
elements, the pressure sensor and the surface equipment may be
substantially the same as used in the ZIPLOG system.
[0020] In a system according to the invention, the DTS and fluid
injection conduit may be combined into a single, semi-stiff,
spoolable, combination conduit. An example of a combination conduit
10 is shown at a lower end thereof, as inserted into a wellbore, in
FIG. 1. The combination conduit 10 may include a fluid injection
conduit 14. The fluid injection conduit 14 may be made from tubing,
such as stainless steel or other high strength, pressure resistant
material and may have a chemical injection valve 16 of any type
known in the art at its lower end for controllable discharge of
treatment chemical into the wellbore. A substantially parallel
conduit 18 may be disposed in the combination conduit 10 extending
alongside the fluid injection conduit 14. The parallel conduit 18
may also be made from high strength, pressure resistant material
such as stainless steel and may include therein one or more
electrical conductors, and one or more optical fibers. The
foregoing will be further explained with reference to FIGS. 2 and
3. A pressure sensor 20 may be disposed at the bottom end of the
parallel conduit 18 and in some examples may be operated by using
the electrical conductor. In other examples, the pressure sensor 20
may be optical. See, for example, U.S. Patent Application
Publication No. 2008/0204759 filed by Choi, the underlying patent
application for which is commonly owned with the present invention.
Such as sensor uses a device that changes optical path length in
response to changes in pressure applied to the sensor. The one or
more optical fibers (24 in FIG. 3) may include a DTS along its
length. When inserted into the wellbore, the device shown in FIG. 1
may simultaneously discharge chemical or other fluid into the
wellbore through the fluid injection conduit 14 and can both
measure fluid pressure in the wellbore as well as measuring
temperature at locations all along the DTS.
[0021] A cross section view of one example of the combination
conduit 10 is shown in FIG. 2. The fluid injection conduit 14 is
shown next to the parallel conduit 18 that may enclose the one or
more optical fibers 24 and electrical conductors 26. The two
conduits 14, 18 used in the present example combination conduit 10
may be made from stainless steel or similar high strength, pressure
resistant material as explained above. Preferably, the material
used to make the parallel conduit 18 that encloses the optical
fibers 24 is thermally conductive so that the DTS embedded in one
or more of the optical fibers 24 is substantially exposed to
ambient temperature all along the interior of the wellbore. An
encapsulating material may enclose both conduits. Preferably the
parallel conduit 18 having the DTS fiber 24 therein is close enough
to the exterior of the encapsulating material 12 to be exposed to
the ambient temperature in the wellbore, and distant enough from
the injection conduit to isolate the temperature of any injected
fluid from the DTS fiber. The encapsulating material 22 preferably
has low thermal conductivity to thermally isolate the two conduits
14, 18 from each other. Example materials for the encapsulating
material 12 include glass fiber reinforced resin or glass fiber
reinforced thermoplastic. Other materials are also possible,
however, the material is generally non-metallic. The encapsulating
material shown in FIG. 2 may have a substantially rectangular
cross-section, in order to facilitate spooling and unspooling of
the combination conduit 10 from a reel (FIG. 4) without
twisting.
[0022] Another example of a combination conduit is shown in cross
section in FIG. 3, wherein the encapsulating material 12 has a
round cross-section. The example shown in FIG. 3 may be
advantageous when a pressure control device (FIG. 5) is coupled to
a wellhead.
[0023] In using the combination conduit 10 shown in FIGS. 1, 2 and
3, the following procedure may be used. First is to mobilize and
rig up a conventional "cap string" pulling system (not shown), and
pull out any existing cap string system (not shown) disposed in the
wellbore. If no cap string is in use in the wellbore, the foregoing
step is not performed. Next, if desired, perform a slickline gauge
run to tag total well depth and ensure sufficient internal diameter
for safe operation of the combination conduit 10, including the
pressure sensor (20 in FIG. 10 and fluid discharge valve (16 in
FIG. 1). Referring to FIG. 4, an intervention rod injector device
32, such as the Ziebel ZIPLOG injector system referred to in the
Background section herein may be coupled to or disposed above the
wellhead 34. The injector 32 moves the spoolable combination
conduit 10 from a storage reel 30 and deploys the combination
conduit 10 to a selected depth or depths within the wellbore. In
some examples, the reel 30 may be operable to withdraw the conduit
10 from the wellbore if desired.
[0024] When the conduit 10 is disposed to the selected depth in the
wellbore, and referring to FIG. 5, a surface pressure control
("pack off") device 36, which may be coupled to the wellhead 34
before deployment of the conduit 10 can be energized to fix the
conduit 10 in place in the wellbore. Energizing the pack off 36 may
include closing one or more seal rams 37, 39, which may be
performed hydraulically, for example. A shear ram 38 may be
provided in some examples to enable full closure of the well in the
event of failure of the conduit or other equipment in the
wellbore.
[0025] It is then possible to remove the injector (32 in FIG. 4)
and the reel (30 in FIG. 4) in the event the conduit installation
is to be long term or permanent. When the conduit 10 is deployed in
the wellbore, and referring to FIG. 6, a foaming agent injection
pump 42 and a sensor interface connector (not shown) may be coupled
to the upper end portion of the combination conduit 10 that extends
through the pack off unit 36. A data recording system 44 may be
coupled to the optical fibers and electrical conductors (FIG. 2) in
the conduit 10 and the pump 42 may be coupled to the fluid
injection conduit (14 in FIG. 2) The data recording system 44 can
be permanently installed, or it can be brought to the wellbore
location when data are required.
[0026] During operation, measurements of pressure (using the sensor
20 in FIG. 1) and temperature, using the DTS, shown schematically
at 11, can be used to determine whether the foaming agent injection
rate is correct, and if subsurface formations other than those
hydraulically coupled to the wellbore, e.g., producing formation
40, are contributing to the fluids being produced from the
wellbore. The pump 42 may be controlled by a controller (not shown
separately) in the data recording unit 44 to automatically adjust
the foaming agent pumping rate to maintain substantially constant
pressure in the wellbore. In some examples, the measurements of
pressure may be substituted by or supplemented by measurements that
are related to the level of fluid (liquid) in the wellbore, for
example, capacitance and acoustic travel time.
[0027] Methods and systems according to the invention may enable
more efficient production of gas from wellbores as well as more
efficient use of foaming agents to assist in such gas
production.
[0028] While the invention has been described with respect to a
limited number of embodiments, those skilled in the art, having
benefit of this disclosure, will appreciate that other embodiments
can be devised which do not depart from the scope of the invention
as disclosed herein. Accordingly, the scope of the invention should
be limited only by the attached claims.
* * * * *
References