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.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

Priority is claimed from U.S. Provisional Application No. 61/047,925 filed on Apr. 25, 2008.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND OF THE INVENTION

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.

SUMMARY OF THE INVENTION

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.

BRIEF DESCRIPTION OF THE DRAWINGS

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.

DETAILED DESCRIPTION

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, 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.

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.

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.

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.

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.

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.

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.

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

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.