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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.

Summary:
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.