US20090266537A1 - Combination injection string and distributed sensing string for well evaluation and treatment control - Google Patents
Combination injection string and distributed sensing string for well evaluation and treatment control Download PDFInfo
- Publication number
- US20090266537A1 US20090266537A1 US12/420,071 US42007109A US2009266537A1 US 20090266537 A1 US20090266537 A1 US 20090266537A1 US 42007109 A US42007109 A US 42007109A US 2009266537 A1 US2009266537 A1 US 2009266537A1
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- United States
- Prior art keywords
- conduit
- wellbore
- fluid
- combination
- disposed
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
- 238000002347 injection Methods 0.000 title description 19
- 239000007924 injection Substances 0.000 title description 19
- 238000011156 evaluation Methods 0.000 title 1
- 239000012530 fluid Substances 0.000 claims abstract description 30
- 238000000034 method Methods 0.000 claims abstract description 14
- 239000000835 fiber Substances 0.000 claims abstract description 9
- 230000003287 optical effect Effects 0.000 claims abstract description 9
- 239000004088 foaming agent Substances 0.000 claims description 10
- 239000013307 optical fiber Substances 0.000 claims description 9
- 239000008393 encapsulating agent Substances 0.000 claims description 4
- 238000005259 measurement Methods 0.000 claims description 4
- 229910000831 Steel Inorganic materials 0.000 claims 1
- 239000011152 fibreglass Substances 0.000 claims 1
- 239000010959 steel Substances 0.000 claims 1
- 239000000463 material Substances 0.000 description 13
- 239000007789 gas Substances 0.000 description 9
- 238000004519 manufacturing process Methods 0.000 description 7
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 7
- 230000015572 biosynthetic process Effects 0.000 description 5
- 238000005755 formation reaction Methods 0.000 description 5
- 239000000126 substance Substances 0.000 description 5
- 239000004020 conductor Substances 0.000 description 4
- 239000006260 foam Substances 0.000 description 4
- 230000002706 hydrostatic effect Effects 0.000 description 4
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 4
- 239000003795 chemical substances by application Substances 0.000 description 3
- 229910001220 stainless steel Inorganic materials 0.000 description 3
- 239000010935 stainless steel Substances 0.000 description 3
- 230000008901 benefit Effects 0.000 description 2
- 239000003365 glass fiber Substances 0.000 description 2
- 239000003345 natural gas Substances 0.000 description 2
- 238000004140 cleaning Methods 0.000 description 1
- 239000002131 composite material Substances 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
- 239000007788 liquid Substances 0.000 description 1
- 230000007774 longterm Effects 0.000 description 1
- 238000012544 monitoring process Methods 0.000 description 1
- 238000005086 pumping Methods 0.000 description 1
- 238000011160 research Methods 0.000 description 1
- 239000011347 resin Substances 0.000 description 1
- 229920005989 resin Polymers 0.000 description 1
- 238000011268 retreatment Methods 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
- 238000003860 storage Methods 0.000 description 1
- 229920001169 thermoplastic Polymers 0.000 description 1
- 239000004416 thermosoftening plastic Substances 0.000 description 1
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/20—Flexible or articulated drilling pipes, e.g. flexible or articulated rods, pipes or cables
- E21B17/206—Flexible or articulated drilling pipes, e.g. flexible or articulated rods, pipes or cables with conductors, e.g. electrical, optical
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
Definitions
- 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.
- 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.
- 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.
- 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.
- 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.
- a wellbore intervention device 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.
- 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.
- FIG. 2 shows a cross section of one example of the combination conduit shown in FIG. 1 .
- FIG. 3 shows a cross section of another example of a combination conduit.
- FIG. 4 shows equipment used to deploy the combination conduit into a wellbore.
- FIG. 5 shows an example of a pressure control head used with the combination conduit.
- FIG. 6 shows a foaming agent injection pump coupled to the upper end portion of the combination conduit.
- 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.
- DTS distributed fiber optic temperature sensor
- the DTS may be of the same type as in the ZIPLOG system described in the Background section herein.
- the DTS sensing elements, the pressure sensor and the surface equipment may be substantially the same as used in the ZIPLOG system.
- 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.
- 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.
- FIG. 2 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.
- 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.
- 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.
- FIG. 3 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.
- 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.
- 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.
- the reel 30 may be operable to withdraw the conduit 10 from the wellbore if desired.
- 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.
- a foaming agent injection pump 42 and a sensor interface connector 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.
- measurements of pressure using the sensor 20 in FIG. 1
- temperature using the DTS, shown schematically at 11
- 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.
- 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.
- 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.
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- Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Geophysics (AREA)
- Mechanical Engineering (AREA)
- Measuring Fluid Pressure (AREA)
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.
Description
- Priority is claimed from U.S. Provisional Application No. 61/047,925 filed on Apr. 25, 2008.
- Not applicable.
- 1. Field of the Invention
- 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.
- 2. Background Art
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- Other aspects and advantages of the invention will be apparent from the following description and the appended claims.
-
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. -
FIG. 2 shows a cross section of one example of the combination conduit shown inFIG. 1 . -
FIG. 3 shows a cross section of another example of a combination conduit. -
FIG. 4 shows equipment used to deploy the combination conduit into a wellbore. -
FIG. 5 shows an example of a pressure control head used with the combination conduit. -
FIG. 6 shows a foaming agent injection pump coupled to the upper end portion of the combination conduit. - 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.
- 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, inFIG. 1 . Thecombination conduit 10 may include afluid injection conduit 14. Thefluid injection conduit 14 may be made from tubing, such as stainless steel or other high strength, pressure resistant material and may have achemical injection valve 16 of any type known in the art at its lower end for controllable discharge of treatment chemical into the wellbore. A substantiallyparallel conduit 18 may be disposed in thecombination conduit 10 extending alongside thefluid injection conduit 14. Theparallel 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 toFIGS. 2 and 3 . Apressure sensor 20 may be disposed at the bottom end of theparallel conduit 18 and in some examples may be operated by using the electrical conductor. In other examples, thepressure 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 inFIG. 3 ) may include a DTS along its length. When inserted into the wellbore, the device shown inFIG. 1 may simultaneously discharge chemical or other fluid into the wellbore through thefluid injection conduit 14 and can both measure fluid pressure in the wellbore as well as measuring temperature at locations all along the DTS. - A cross section view of one example of the
combination conduit 10 is shown inFIG. 2 . Thefluid injection conduit 14 is shown next to theparallel conduit 18 that may enclose the one or moreoptical fibers 24 andelectrical conductors 26. The twoconduits 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 theparallel conduit 18 that encloses theoptical fibers 24 is thermally conductive so that the DTS embedded in one or more of theoptical fibers 24 is substantially exposed to ambient temperature all along the interior of the wellbore. An encapsulating material may enclose both conduits. Preferably theparallel conduit 18 having theDTS fiber 24 therein is close enough to the exterior of the encapsulatingmaterial 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 twoconduits 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 inFIG. 2 may have a substantially rectangular cross-section, in order to facilitate spooling and unspooling of thecombination conduit 10 from a reel (FIG. 4 ) without twisting. - Another example of a combination conduit is shown in cross section in
FIG. 3 , wherein the encapsulatingmaterial 12 has a round cross-section. The example shown inFIG. 3 may be advantageous when a pressure control device (FIG. 5 ) is coupled to a wellhead. - In using the
combination conduit 10 shown inFIGS. 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 thecombination conduit 10, including the pressure sensor (20 inFIG. 10 and fluid discharge valve (16 inFIG. 1 ). Referring toFIG. 4 , an interventionrod injector device 32, such as the Ziebel ZIPLOG injector system referred to in the Background section herein may be coupled to or disposed above thewellhead 34. Theinjector 32 moves thespoolable combination conduit 10 from astorage reel 30 and deploys thecombination conduit 10 to a selected depth or depths within the wellbore. In some examples, thereel 30 may be operable to withdraw theconduit 10 from the wellbore if desired. - When the
conduit 10 is disposed to the selected depth in the wellbore, and referring toFIG. 5 , a surface pressure control (“pack off”)device 36, which may be coupled to thewellhead 34 before deployment of theconduit 10 can be energized to fix theconduit 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. Ashear 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. - It is then possible to remove the injector (32 in
FIG. 4 ) and the reel (30 inFIG. 4 ) in the event the conduit installation is to be long term or permanent. When theconduit 10 is deployed in the wellbore, and referring toFIG. 6 , a foamingagent injection pump 42 and a sensor interface connector (not shown) may be coupled to the upper end portion of thecombination conduit 10 that extends through the pack offunit 36. A data recording system 44 may be coupled to the optical fibers and electrical conductors (FIG. 2 ) in theconduit 10 and thepump 42 may be coupled to the fluid injection conduit (14 inFIG. 2 ) The data recording system 44 can be permanently installed, or it can be brought to the wellbore location when data are required. - During operation, measurements of pressure (using the
sensor 20 inFIG. 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. Thepump 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. - 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.
- 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.
Claims (16)
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.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
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US12/420,071 US20090266537A1 (en) | 2008-04-25 | 2009-04-08 | Combination injection string and distributed sensing string for well evaluation and treatment control |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
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US4792508P | 2008-04-25 | 2008-04-25 | |
US12/420,071 US20090266537A1 (en) | 2008-04-25 | 2009-04-08 | Combination injection string and distributed sensing string for well evaluation and treatment control |
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US20090266537A1 true US20090266537A1 (en) | 2009-10-29 |
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ID=41213845
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
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US12/420,071 Abandoned US20090266537A1 (en) | 2008-04-25 | 2009-04-08 | Combination injection string and distributed sensing string for well evaluation and treatment control |
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Cited By (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2011043768A1 (en) * | 2009-10-07 | 2011-04-14 | Ziebel, As | Combination injection string and distributed sensing string |
EP2351906A2 (en) | 2010-01-07 | 2011-08-03 | Henning Hansen | Retrofit wellbore fluid injection system |
WO2011127411A2 (en) * | 2010-04-08 | 2011-10-13 | Schlumberger Canada Limited | Fluid displacement methods and apparatus for hydrocarbons in subsea production tubing |
US8602688B2 (en) | 2008-12-03 | 2013-12-10 | Ziebel As | Method to stop wellbore fluid leakage from a spoolable wellbore intervention rod |
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