Systems and Methods for Distributed Downhole Sensing Using a Polymeric Sensor System

Abstract

Systems and methods for distributed downhole sensing in which a polymeric sensor system is coupled to one or more pieces of downhole equipment. The polymeric sensor system has multiple electric or nano sensors embedded in a polymeric material such as a tape that can be applied to the downhole equipment to sense parameters at multiple, physically distributed locations. A monitoring unit at the surface of the well may receive data from the embedded sensors. A control unit at the surface of the well may communicate control information through the polymeric sensor system to electrically controlled equipment downhole, eliminating the need for a control line that is separate from the polymeric sensor system.

Description

BACKGROUND

1. Field of the Invention

The invention relates generally to well operations, and more specifically to systems and methods for sensing conditions associated with wells and downhole equipment using sensors that are embedded in polymeric materials.

2. Related Art

In the various phases of petroleum production (including drilling and completion of wells and subsequent production from the wells), it is desirable to have information about conditions relating to the wells and the equipment that is used therein. Conventionally, this information has been obtained using downhole gauges that include different types of sensors. These sensors may measure such parameters as temperature, pressure, vibration, salinity, strain, and so on.

Downhole gauges typically enclose sensors for the desired parameters in a housing that can be positioned at a desired location in the well, often near equipment that is to be monitored. For instance, one type of gauge package that is configured to monitor operating conditions of an electric submersible pump is designed to be connected to the lower end of the pump's motor. The gauge package senses conditions at this one location. The sensor data may be stored within the gauge package for later retrieval, or it may be connected to an electrical line that allows the data to be communicated to a user or to monitoring equipment at the surface of the well.

More recently, techniques have been developed to enable more distributed sensing of well conditions. For instance, an optical fiber may incorporate multiple Bragg gratings along the length of the fiber, and light that is reflected by the Bragg gratings may be analyzed to determine conditions affecting the fiber, and consequently the gratings. In one application, fiber Bragg gratings may be attached to wellbore tubular or casings to enable strain measurements to be made along the lengths of the tubular or casings.

There are a number of disadvantages with these techniques for monitoring downhole conditions. For example, although gauge packages may be versatile in terms of the types of measurements that can be made, they typically only measure conditions at or near the gauge packages. The expense and physical configurations of gauge packages make them impractical for sensing conditions at multiple points. Fiber optic sensing techniques are better adapted to monitoring conditions over greater regions, but fiber optic systems are sophisticated, expensive and more fragile than gauge packages. Additionally, fiber optic systems may be limited in the types of parameters that can be sensed.

It would therefore be desirable to provide systems and methods for sensing conditions associated with the operation of downhole equipment that reduce or eliminate some of the issues described above.

SUMMARY OF THE INVENTION

This disclosure is directed to systems and methods for downhole sensing that address one or more of the issues discussed above. One embodiment comprises a downhole sensing system in which a polymeric sensor system is coupled to one or more pieces of downhole equipment. The polymeric sensor system has multiple electric or nano sensors embedded in a polymeric material. The sensors are positioned in the polymeric material to sense parameters at multiple, physically separate locations on the downhole equipment. The system may include a monitoring unit that is positioned at the surface of a well and is coupled to the polymeric sensor system so that it can receive data from the embedded sensors. The polymeric material may be formed into a tape, so that the tape can be helically wrapped around or otherwise applied to downhole equipment such as casings, production tubing and the like. The polymeric material can be constructed as a tape, sheet, tube or any other form factor. The polymeric material may be applied across multiple sections of production tubing or casing. The sensors may be configured to measure strain, temperature, pressure, vibration, pH, salinity or other parameters. When strain sensors are embedded in a polymeric tape that is helically wrapped around a completion, the monitoring unit may be configured to analyze the strain data and thereby detect deformation of the completion. In one embodiment, the polymeric sensor system is coupled between a surface control unit as well as the monitoring unit, and is configured to convey sensed data to the monitoring unit and control information from the surface control unit to a piece of electrical downhole equipment.

Another embodiment comprises a downhole sensing method. This method includes providing a polymeric sensor system, positioning the polymeric sensor system on downhole equipment, positioning the monitored downhole equipment in a producing zone or other region of a well, and retrieving data relating to the monitored downhole equipment from the polymeric sensor system. The polymeric sensor system may be formed as a tape having networked sensors embedded therein. The tape may be helically wrapped around, for example, a completion, and may be configured to sense strain. By monitoring strain data from the polymeric sensor system and analyzing the strain data, deformation of the completion may be detected. The polymeric sensor system senses selected parameters at multiple, physically separate (e.g., axially spaced) locations on the monitored downhole equipment. The method may include conveying data corresponding to sensed parameters to a surface monitoring unit. The method may also include communicating control information from a surface control unit through the polymeric sensor system to electrical downhole equipment.

Numerous other embodiments are also possible.

BRIEF DESCRIPTION OF THE DRAWINGS

Other objects and advantages of the invention may become apparent upon reading the following detailed description and upon reference to the accompanying drawings. It should be noted that the features illustrated in the drawings are not necessarily drawn to scale.

FIG. 1 is a diagram illustrating an exemplary system in accordance with one embodiment.

FIGS. 2A and 2B are a pair of diagrams illustrating the application of a polymeric sensor system to completion equipment in accordance with one embodiment.

FIG. 3 is a functional block diagram illustrating the communication of control information to downhole equipment via a polymeric sensor system.

While the invention is subject to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and the accompanying detailed description. It should be understood, however, that the drawings and detailed description are not intended to limit the invention to the particular embodiment which is described. This disclosure is instead intended to cover all modifications, equivalents and alternatives falling within the scope of the present invention as defined by the appended claims.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

One or more embodiments of the invention are described below. It should be noted that these and any other embodiments described below are exemplary and are intended to be illustrative of the invention rather than limiting.

As described herein, various embodiments of the invention comprise systems and methods for sensing conditions associated with wells and downhole equipment using sensors that are embedded in polymeric materials. The sensors in the polymeric material are electronic or nano sensors that may monitor a number of parameters that cannot be measured with conventional fiber optic sensor systems. The sensors are positioned to enable distributed sensing, rather than point sensing as in conventional electrical gauge packages, and are networked to allow the polymeric sensor assembly to convey electrical signals therethrough. This may enable communication of control signals, eliminating the need for a separate electrical or hydraulic control line to be provided in order to control downhole equipment.

In one embodiment, a well system uses a polymeric sensor system to monitor conditions associated with a lower completion. The polymeric sensor system utilizes sensors that are embedded in a polymeric tape. The tape is helically wrapped around sections of production tubing that will form the lower completion. The tape is protected by a perforated shroud. As the tubing sections are coupled together on the rig floor, the segments of sensor-embedded tape on the tubing sections are also interconnected. These dry-connects between the tape segments may consist of simple splices of the respective electrical leads, or suitable connectors may be used. The sensors in the tape segments are electrically networked so that sensor data can be communicated through the polymeric sensor system. The sensor data may be communicated to monitoring equipment at the surface of the well, or it may be monitored by equipment that is positioned within the well and configured, for example, to record the data for later retrieval, wirelessly communicate the data to other components of the well equipment, or communicate the data through other means such as power line communication channels.

The assembled lower completion is installed in a producing zone of the well. The producing zone is isolated from the portion above it by a completion packer. The tubing of the upper completion is stabbed into a sub above or through the completion packer at the top of the lower completion. This sub includes one part of a wet-connect that is electrically coupled to the polymeric sensor system. A second, complementary part of the wet-connect is electrically coupled to an electrical line that extends from the lower end of the upper completion to the surface. When the upper completion is stabbed into the lower completion, the wet-connect electrically couples the polymeric sensor system through the electrical line to a monitoring unit at the surface of the well. Sensor data such as strain measurements are communicated from the sensors that are embedded in the tape to the monitoring unit, which can then analyze the data and monitor conditions such as deformation of the completion.

The equipment at the surface of the well may also include a control unit for some components of the completion equipment, such as an electrically controlled valve. A remote control unit located downhole in the well may alternatively be coupled to the polymeric sensor system to monitor the generated sensor data and store or communicate the data, and potentially control associated equipment using the data. The control unit can be electrically coupled to the downhole equipment through the polymeric sensor system, thereby eliminating the need for a separate electrical control line.

Referring to FIG. 1, a diagram illustrating an exemplary system in accordance with one embodiment of the present invention is shown. In this embodiment, a wellbore has been drilled into a subterranean geological formation. A casing 110 is installed in the wellbore and may be cemented in place. Casing 110 is perforated in a producing zone of the formation to allow the hydrocarbons in the formation to enter the wellbore. Completion equipment 120 is installed within casing 110 to enable the removal of the hydrocarbons from the well.

The completion equipment may include casings, tubulars or other equipment that are necessary to enable the production of hydrocarbons from the well. The completion equipment forms an upper completion and a lower completion. The lower completion includes the equipment in the producing zone, which may be isolated by packers 130, 135. The lower completion may, for example, include screens, liners, production tubing and the like to allow pressurized fluids to flow out of the well. The lower completion may also include equipment to facilitate production of oil or other fluids, such as a steam injection system. If the pressure within the formation is insufficient to cause the fluids to flow out of the well, artificial lift equipment such as electric submersible pumps (ESP's) may be used to drive the fluids from the well. The lower completion may also include a sensor system 125 to monitor conditions associated with the completion equipment, or with the well or well fluids.

The upper completion typically consists of production tubing 140 and a safety valve (not explicitly shown in the figure). The upper completion may also include a sensor system to monitor associated conditions. After the lower completion has been installed, the upper completion is normally stabbed into a sub at the top of the lower completion isolation packer. The fluids that flow into the lower completion from the producing zone of the formation stream through the upper completion and out of the well.

In the embodiments disclosed herein, the sensor system is implemented using electrical or nano sensors that are embedded in a polymeric material. The sensors themselves may even be made using conductive polymers, and the polymeric material can form what may be considered a continuous sensor. Because such a sensing system does not sense parameters at a single point, it would be considered for the purposes of this disclosure to incorporate multiple sensors. In one embodiment, the sensors are embedded in a polymeric tape that can be wrapped around the downhole equipment or otherwise applied to the equipment in a manner similar to the manner in which fiber-optic sensors are currently used. The use of polymeric material in the construction of the sensor system provides flexibility which is not found in conventional fiber-optic sensing systems. Further, the polymeric material provides some protection for the sensors, in contrast to conventional fiber-optic sensing systems, which typically need to be installed within a conduit of the type used for hydraulic control lines in order to protect the relatively fragile optical fibers.

While the lower completion may be 100-1000 feet long, it is assembled in sections that are 30 feet long. The sections of the production tubing are assembled one-by-one on the rig floor before being lowered into the wellbore. Sensor system 125 may extend across multiple sections of the lower completion to provide distributed sensing capabilities. Consequently, the components of sensor system 125 that are coupled to one section must be connected to the components that are coupled to the adjacent section when the tubing sections are joined. These connections may be referred to as dry-connects, since they are made in the relatively dry environment of the rig floor. In the present systems, sensor system 125 incorporates sensors that communicate sensed data electrically, so the components coupled to one section can be easily connected electrically (e.g., spliced) to the components coupled to the adjacent section. By contrast, optical dry-connect couplings are substantially more sophisticated alignment, more expensive, and require far more time to complete than the electrical connections.

Sensor system 125 is connected to equipment at the surface of the well by an electrical line 145. Electrical line 145 terminates in a wet-connect connector at the bottom of the upper completion. A complementary connector is provided at the top of the lower completion. When the upper completion is stabbed into the lower completion, the two wet-connect connectors engage each other to make the electrical connection between sensor system 125 and electrical line 145. This electrical wet-connect uses conventional technologies, and is relative simple, reliable and inexpensive. An equivalent fiber-optic wet-connect which would be required to couple a fiber-optic sensing system to a fiber-optic communication line is much more sophisticated and much more expensive than the electrical wet-connect.

In alternative embodiments, sensor system 125 may be coupled to the surface through another sensing system that monitors conditions in the upper completion. The sensing system for the upper completion may, for instance, be a type of polymeric sensor system similar to that used in the lower completion. Alternatively, the sensor system may be coupled to monitoring and/or control equipment that is located downhole in the well. This may eliminate the need for intervention by equipment at the surface of the well and the corresponding need to provide communication and/or control lines that couple the downhole equipment (including the sensor system) to the surface equipment. This may likewise eliminate the need to penetrate interfaces (e.g., packers) within the well. The sensor system may also communicate sensor data through other channels, such as wireless channels, or powerline communication channels.

As noted above, sensor system 125 is connected to equipment at the surface of the well. The surface equipment to which the sensor systems are connected may be, for example, an electronic monitoring unit 150. Sensor data generated by sensor system 125 is communicated through line 145 to electronic monitoring unit 150, where it may be stored, analyzed, forwarded to other devices, viewed by operators, or used in various ways in the operation of the well.

Electronic monitoring unit 150 may be part of a system that is further configured to control at least a portion of the downhole equipment. In order for this system to control the downhole equipment, it is necessary to provide a communication channel through which control information can be communicated downhole to the equipment. In this embodiment, sensor system 125 serves as a part of this communication channel. Sensor system 125 is coupled between the surface equipment and the downhole equipment, and is capable of bidirectional communications. In other words, in addition to communicating sensor data from the sensors to the surface equipment, sensor system 125 communicates control information from the surface equipment to the downhole equipment. As noted above, fiber-optic sensor systems can only communicate sensed information upward to the surface—they cannot communicate control information downhole.

Referring to FIGS. 2A and 2B, a pair of diagrams illustrating the application of a polymeric sensor system to completion equipment in accordance with one embodiment are shown. FIG. 2A is a partial cutaway view of a segment of production tubing having a polymeric tape sensor system applied thereto. In this figure, half of the protective shroud is removed. FIG. 2B is a partial cutaway view of the segment of production tubing with one quarter of the protective shroud removed.

In FIGS. 2A and 2B, polymeric tape 210 is helically wrapped around production tubing 220. Tape 210 has a networked series of sensors embedded therein. A perforated metal shroud 230 is installed around production tubing 220 in order to provide protection for polymeric tape 210 and the sensors therein. In one embodiment, the sensors within polymeric tape 210 are strain sensors. The sensors provide measurements of the strain experienced by the production tubing along its length. These measurements are conveyed to a monitoring unit at the surface of the well, which can determine, in realtime, the deformation of the tubing that causes the sensed strain. The polymeric tape sensor system can alternatively be applied to a well casing to monitor deformation that is caused by compaction and other changes in the condition of the geological formation, and which can lead to loss of the well if not detected at an early stage. The polymeric tape sensor system can also employ other types of sensors to monitor other conditions of the completion, such as temperature, pressure, pH, salinity, viscosity, etc.

As noted above, the polymeric sensor system can be used not only to monitor various conditions downhole, but also to communicate data from the surface of the well to equipment that is installed downhole. Referring to FIG. 3, a functional block diagram illustrating the communication of control information to downhole equipment via a polymeric sensor system is shown. In this figure, a surface unit 310 is coupled to a polymeric sensor system 320, which is in turn coupled to downhole electrical equipment 330.

Polymeric sensor system 320 includes a set of sensors (e.g., 321) embedded in a polymeric material. The sensors are coupled together to form an electrical network. As depicted in the figure, the sensors are serially coupled together, but any suitable topology may be used. A first pair of electrical leads 322 are connected to surface monitoring and control unit 310, and a second pair of leads 323 are connected to downhole equipment 330. The polymeric sensor system need not be connected directly to the surface unit or the downhole equipment, but can be coupled to these components of the system through electrical cables, other sensor systems, or any other suitable means.

As shown in FIG. 3, the data generated by the sensors (e.g., 321) is communicated upward to monitoring and control unit 310 at the surface of the well. The data may be communicated in any suitable format using any suitable modulation scheme. Control data generated by monitoring and control unit 310 is communicated downward, through polymeric sensor system 320, to downhole equipment 330. The topology of polymeric sensor system 320 may be designed to allow the control data for the downhole equipment to be communicated through the networked sensors, or it may include separate conductors for the communication of control data to the downhole equipment.

As described above, one embodiment employs sensors embedded in a polymeric tape which is wrapped around a completion to monitor conditions associated with the completion. Alternative embodiments may be used in other applications as well. For instance, one embodiment may be configured to monitor conditions associated with an ESP. Conventionally, when it is desired to monitor an ESP, a gauge package is mounted on the bottom of the ESP's motor. The gauge package may monitor temperature, pressure, vibration and other conditions, but these conditions are sensed at the bottom of the ESP's motor. Since the motor and pump of the ESP system may be tens of meters long, the conditions at the bottom of the motor may not accurately reflect the conditions that are desired to be sensed, such as vibration of the motor shaft.

In the present embodiment, a polymeric sensor system is applied along the length of the ESP system. For example, a strip of polymeric sensor tape may be positioned on one side of the motor and/or pump. Alternatively, the sensor tape may be helically wrapped around the motor and/or pump in the same manner described above in connection with FIGS. 2A and 2B, or individually wrapped around the motor windings for better thermal mapping and monitoring. The polymeric sensor system may be connected by an electrical line directly to equipment at the surface of the well, or it may be connected to the motor so that sensor data can be communicated to the surface through the motor's power or communication lines.

The polymeric sensor system may incorporate vibration sensors, for example, that measure vibration along the length of the ESP system. Other types of sensors may be used as well. Because the sensors are closer to the shaft of the motor and pump, vibration measurements may be more accurate than measurements made at the bottom of the motor. Further, because the polymeric sensor system senses vibration at multiple points along the length of the ESP motor and/or pump, it may be possible to diagnose conditions based on different levels of vibration at the different measurement points.

The polymeric sensor system may also be integrated into the ESP itself. For instance, when the motor of the ESP is assembled, the polymeric sensor system may be positioned in the slots of the stator and/or rotor so that conditions such as temperature can be monitored within these motor components, both during the manufacture of the motor and during operation of the motor. The polymeric sensor system may itself be formed within the motor (e.g., injected into the motor during its manufacture), thereby facilitating monitoring of motor conditions and potentially helping to secure the motor windings, similar to the manner in which epoxy or varnish is commonly used to secure the windings.

In another alternative embodiment, a polymeric sensor system may be used to provide 3D mapping data. In this embodiment, the polymeric sensor system is positioned around a somewhat flexible joint in a downhole sub. The polymeric sensor system includes strain sensors that can be used to provide a strain profile of the joint. The strain profile can be recorded by a battery powered data sub, or it can be transmitted to the surface for processing. For instance, a data processor may analyze the strain profile data to determine the amount of flexion in the joint as a function of well depth, and then map the path of the well in three dimensions.

Many other alternative embodiments are also possible.

Although the invention has been described with respect to specific embodiments thereof, these embodiments are merely illustrative, and not restrictive of the invention. The description herein of illustrated embodiments of the invention, including the description in the Abstract and Summary, is not intended to be exhaustive or to limit the invention to the precise forms disclosed herein (and in particular, the inclusion of any particular embodiment, feature or function within the Abstract or Summary is not intended to limit the scope of the invention to such embodiment, feature or function). Rather, the description is intended to describe illustrative embodiments, features and functions in order to provide a person of ordinary skill in the art context to understand the invention without limiting the invention to any particularly described embodiment, feature or function.

It should also be noted that the various features, functions, components, steps and specific details of the embodiments described above are subject to variation in alternative embodiments. For example, the polymeric sensor system may have different forms in different embodiments, such as tapes, sheets, extrusions, or other encapsulations. The polymeric sensor system may also be formed or coupled to the downhole equipment in various ways, including bonding, etching, injection and the like. The polymeric sensor system may be configured to sense many different parameters, conditions and characteristics, such as pressure, temperature, pH, salinity, vibration, strain, and many others. The polymeric sensor system may be coupled to many different types of downhole equipment, and the sensor system and equipment may be positioned in different locations within a well, including without limitation upper completions, lower completions, production zones, injection zones, etc.

While specific embodiments of, and examples for, the invention are described herein for illustrative purposes only, various equivalent modifications are possible within the spirit and scope of the invention, as those skilled in the relevant art will recognize and appreciate. As indicated, these modifications may be made to the invention in light of the foregoing description of illustrated embodiments of the invention and are to be included within the spirit and scope of the invention. Thus, while the invention has been described herein with reference to particular embodiments thereof, a latitude of modification, various changes and substitutions are intended in the foregoing disclosures, and it will be appreciated that in some instances some features of embodiments of the invention will be employed without a corresponding use of other features without departing from the scope and spirit of the invention as set forth. Therefore, many modifications may be made to adapt a particular situation or material to the essential scope and spirit of the invention.

Reference throughout this specification to “one embodiment,” “an embodiment,” or “a specific embodiment” or similar terminology means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment and may not necessarily be present in all embodiments. Thus, respective appearances of the phrases “in one embodiment,” “in an embodiment,” or “in a specific embodiment” or similar terminology in various places throughout this specification are not necessarily referring to the same embodiment. Furthermore, the particular features, structures, or characteristics of any particular embodiment may be combined in any suitable manner with one or more other embodiments. It is to be understood that other variations and modifications of the embodiments described and illustrated herein are possible in light of the teachings herein and are to be considered as part of the spirit and scope of the invention.

In the description herein, numerous specific details are provided, such as examples of components and/or methods, to provide a thorough understanding of embodiments of the invention. One skilled in the relevant art will recognize, however, that an embodiment may be able to be practiced without one or more of the specific details, or with other apparatus, systems, assemblies, methods, components, materials, parts, and/or the like. In other instances, well-known structures, components, systems, materials, or operations are not specifically shown or described in detail to avoid obscuring aspects of embodiments of the invention. While the invention may be illustrated by using a particular embodiment, this is not and does not limit the invention to any particular embodiment and a person of ordinary skill in the art will recognize that additional embodiments are readily understandable and are a part of this invention.

The benefits and advantages which may be provided by the present invention have been described above with regard to specific embodiments. These benefits and advantages, and any elements or limitations that may cause them to occur or to become more pronounced are not to be construed as critical, required, or essential features of any or all of the claims. As used herein, the terms “comprises,” “comprising,” or any other variations thereof, are intended to be interpreted as non-exclusively including the elements or limitations which follow those terms. Accordingly, a system, method, or other embodiment that comprises a set of elements is not limited to only those elements, and may include other elements not expressly listed or inherent to the claimed embodiment.

While the present invention has been described with reference to particular embodiments, it should be understood that the embodiments are illustrative and that the scope of the invention is not limited to these embodiments. Many variations, modifications, additions and improvements to the embodiments described above are possible. It is contemplated that these variations, modifications, additions and improvements fall within the scope of the invention as detailed within the following claims.

Claims

1. A downhole sensing system comprising:

one or more pieces of monitored downhole equipment positioned within a well; and

a polymeric sensor system coupled to the pieces of monitored downhole equipment, wherein the polymeric sensor system includes a plurality of sensors embedded in a polymeric material, and wherein the sensors are positioned in the polymeric material to sense parameters at multiple, physically separate locations.

2. The system of claim 1, further comprising a surface monitoring unit coupled to the polymeric sensor system and configured to receive sensor data from the polymeric sensor system.

3. The system of claim 1, wherein the polymeric sensor system comprises a polymeric tape having a plurality of networked sensors embedded therein, wherein the sensors are selected from the group consisting of: electric sensors; and nano sensors.

4. The system of claim 3, wherein the one or more pieces of monitored downhole equipment comprise a completion, wherein the sensors of the polymeric sensor system are configured to measure strain, and wherein the polymeric sensor system is helically wrapped around the completion.

5. The system of claim 4, wherein the polymeric sensor system is coupled to a surface monitoring unit and configured to convey measured strain data to the surface monitoring unit, wherein the surface monitoring unit is configured to analyze the strain data and thereby detect deformation of the completion.

6. The system of claim 1, further comprising a monitoring unit coupled to the polymeric sensor system and configured to receive sensor data from the polymeric sensor system, wherein the monitoring unit is positioned within the well.

7. The system of claim 1, further comprising a control unit coupled to the polymeric sensor system and configured to receive sensor data from the polymeric sensor system, wherein the control unit is positioned within the well and configured to control one or more pieces of the downhole equipment without intervention from equipment positioned at the surface of the well.

8. The system of claim 1, wherein the polymeric sensor system is incorporated into at least one of the pieces of monitored downhole equipment during manufacture of the at least one piece of monitored downhole equipment.

9. The system of claim 1, wherein the sensors in the polymeric material are positioned at locations which are axially spaced along the length of the monitored downhole equipment.

10. The system of claim 1, wherein the polymeric sensor system comprises a set of sensors forming a multi-dimensional sensor array in the polymeric material.

11. The system of claim 1, wherein the polymeric sensor system includes multiple sensor arrays that are electrically interconnected.

12. The system of claim 11, wherein the polymeric sensor system extends over multiple sections of production tubing.

13. The system of claim 1, wherein the polymeric sensor system is configured to convey sensor data in a first direction to a surface monitoring unit and to convey control information in a second direction opposite the first direction to a piece of electrical downhole equipment.

14. The system of claim 1, wherein the one or more pieces of monitored downhole equipment comprise a flexible joint, wherein the polymeric sensor system includes strain sensors that are positioned around the flexible joint, and is configured to provide a strain profile of the joint, wherein the polymeric sensor system is coupled to a data processor that is configured to map a wellbore of the well based on the strain profile.

15. A downhole sensing method comprising:

providing a polymeric sensor system, wherein the polymeric sensor system includes a plurality of sensors embedded in a polymeric material;

positioning the polymeric sensor system on one or more pieces of monitored downhole equipment;

positioning the monitored downhole equipment in a well; and

retrieving data from the polymeric sensor system.

16. The method of claim 15, wherein providing the polymeric sensor system comprises polymeric tape having a plurality of networked sensors embedded therein.

17. The method of claim 16, wherein the one or more pieces of monitored downhole equipment comprise a completion, wherein the sensors of the polymeric sensor system are configured to measure strain, and wherein the polymeric sensor system is helically wrapped around the completion.

18. The method of claim 17, further comprising monitoring strain data from the polymeric sensor system, analyzing the strain data and detecting deformation of the completion.

19. The method of claim 15, further comprising the polymeric sensor system sensing parameters at multiple, physically separate, axially spaced locations on the monitored downhole equipment.

20. The method of claim 15, further comprising communicating control information to one or more pieces of electrical downhole equipment through the polymeric sensor system.

21. The method of claim 15, wherein positioning the monitored downhole equipment in the well comprises positioning the monitored downhole equipment in a producing or injection zone of the well.

22. The method of claim 15, wherein the plurality of sensors comprise strain sensors, wherein positioning the polymeric sensor system on the one or more pieces of monitored downhole equipment comprises positioning the polymeric sensor system around a flexible joint, the method further comprising generating a strain profile of the joint with the polymeric sensor system and map a wellbore of the well based on the strain profile.