Distributed fiber optic sensing in packers for permanent casing and formation deformation monitoring

Abstract

The present specification discloses an apparatus, method and system for monitoring wellbore deformation. The apparatus includes an expandable annular cylindrical packer (108) and a plurality of assemblies (301) mounted on an outer circumferential surface of the packer (108). The plurality of assemblies (301) are configured to be pressed by the packer (108) against a surface of the wellbore (100). Each assembly (301) includes at least one fiber optic coil (302) embedded in a deformable substrate sheet (306), a tray-like container (304) formed of a low thermal conductivity material and edgewise attached to an edge of the sheet by a pressure seal, and an optical coupler (303) configured to couple the fiber optic coil (302) to a fiber optic cable (112). The assembly (301) also includes a pressure-tight compartment containing a high-pressure inert gas, the pressure-tight compartment being formed from the container (304), the sheet (306), and the seal.

Description

Background Art

[0001] Metal loss and deformation can weaken the structural integrity of downhole completion structures. These problems can be caused by material degradation due to natural and man-made processes, such as changes in stress / strain caused by tectonic movements, corrosion and erosion caused by production, explosive perforation, and damage caused by similar stimulation techniques. Typical characterization methods for casing deformation include time lapse caliper log, flux leakage log, electromagnetic shift tool, and ultrasonic tool.

[0002] The main challenges in monitoring casing deformation include inaccurate points / blind spots (the fingers of the caliper may miss areas of high metal loss), lack of real-time visualization, data processing, analysis, and uncertainty in the position of electromagnetic sensors. Therefore, it is crucial to provide a measurement system for real-time monitoring of deformation. Summary of the Invention

[0003] The Summary of the Invention is provided to introduce a series of concepts that will be further described in the following Detailed Description. The Summary of the Invention is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used to help limit the scope of the claimed subject matter.

[0004] In one aspect, embodiments disclosed in this specification relate to a wellbore deformation instrument. The wellbore deformation instrument includes an expandable annular cylindrical packer and a plurality of components mounted on an outer circumferential surface of the packer and configured to be pressed against a wellbore surface by the packer, wherein each of the components includes: at least one optical fiber coil embedded in a deformable base sheet; a tray-like container formed of a low thermal conductivity material and attached to an edge of the sheet along an edge of the container by a pressure seal, wherein a pressure-sealed chamber formed by the container, the sheet, and the seal contains a high-pressure inert gas; and an optical coupler configured to couple the at least one optical fiber coil to an optical fiber cable.

[0005] In one aspect, an embodiment relates to a system. The system includes: a wellbore deformation instrument that includes an expandable annular cylindrical packer and a plurality of components mounted on an outer circumferential surface of the packer and configured to be pressed by the packer against a wellbore surface, wherein each of the components includes: at least one optical fiber coil embedded in a deformable base sheet, a tray-like container formed of a low thermal conductivity material and attached to an edge of the sheet along an edge of the container by a pressure seal, wherein a pressure-sealed chamber formed by the container, the sheet, and the seal contains a high-pressure inert gas, and an optical coupler configured to couple the at least one optical fiber coil to an optical fiber cable; an optical fiber cable deployed in a wellbore extending from a wellhead to a subterranean formation and optically coupled by the optical coupler to each of the at least one optical fiber coils; and an optical analyzer configured to emit laser pulses into the optical fiber cable at the wellhead and receive backscattered laser pulses from each of the at least one optical fiber coils through the optical fiber cable.

[0006] In one aspect, an embodiment relates to a method for monitoring wellbore deformation, including: inserting a wellbore deformation instrument attached to an optical fiber cable into a wellbore at a predetermined depth; expanding the wellbore deformation instrument, wherein expanding the wellbore deformation instrument presses a plurality of deformation sensors against the wellbore surface; at a plurality of monitoring times spaced apart by a time interval, emitting a plurality of laser pulses from an optical analyzer located at the wellhead into the optical fiber cable; detecting backscattered laser pulses from each of the plurality of laser pulses; and determining deformation of the wellbore surface based at least in part on a difference between the backscattered laser pulses for one or more pairs of the monitoring times.

[0007] Other aspects and advantages of the claimed subject matter will become apparent from the following description and the appended claims. BRIEF DESCRIPTION OF THE DRAWINGS

[0008] Specific embodiments of the disclosed technology will now be described in detail with reference to the drawings. For consistency, like elements in the various drawings are represented by like reference numerals.

[0009] Figure 1A A well is shown in accordance with one or more embodiments.

[0010] Figure 1B A cross-section of a well is shown in accordance with one or more embodiments.

[0011] Figure 2 An example of strain and deformation on a casing is shown in accordance with one or more embodiments.

[0012] Figure 3 Shows a wellbore deformation instrument according to one or more embodiments.

[0013] Figure 4 Shows a wellbore deformation instrument with an optical fiber assembled in a spiral pattern.

[0014] Figure 5 Shows a wellbore deformation instrument with an optical fiber assembled in a serpentine pattern.

[0015] Figure 6 Shows a wellbore deformation instrument with an optical fiber assembled in a spiral - serpentine hybrid pattern.

[0016] Figure 7 Shows a wellbore deformation instrument equipped with an optical fiber with a Bragg grating.

[0017] Figure 8 Shows a multi - channel optical fiber with a spiral - serpentine hybrid pattern.

[0018] Figure 9 Shows a schematic diagram of the electronics and signal processing of N light sources and M fiber optic probes.

[0019] Figure 10 Shows a schematic diagram of the electronics and signal processing of N shared light sources and M distributed fiber optic probes.

[0020] Figure 11 Shows a schematic diagram of the electronics and signal processing of N shared light sources and M distributed fiber optic probes.

[0021] Figure 12 Shows a flowchart according to one or more embodiments. Detailed Description

[0022] In the following detailed description of the embodiments of the present disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the present disclosure. However, it will be apparent to those skilled in the art that the present disclosure may be practiced without these specific details. In other instances, well - known features have not been described in detail to avoid unnecessarily complicating the description.

[0023] Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as adjectives for elements (i.e., any noun in the present application). Unless explicitly disclosed, e.g., using terms such as "before", "after", "single", and other such terms, the use of ordinal numbers does not imply or create any particular order of the elements, nor does it limit any element to only a single element. Instead, the use of ordinal numbers is for differentiating between elements. As an example, a first element is different from a second element, and the first element may contain more than one element and be ranked after (or before) the second element in the ordering of the elements.

[0024] In the following description of FIGS. 1 to Figure 12 In the various embodiments disclosed in this specification, for any component described with respect to an accompanying drawing, it may be equivalent to one or more similarly named components described with respect to any other accompanying drawing. For the sake of brevity, the description of these components will not be repeated for each drawing. Thus, each embodiment of the components of each drawing is incorporated by reference into each other drawing having one or more similarly named components, and it is assumed that each embodiment of the components of each drawing optionally exists in each other drawing having one or more similarly named components. Additionally, according to the various embodiments disclosed in this specification, any description of a component in one drawing should be interpreted as an optional embodiment that can be implemented outside of, in combination with, or in place of the embodiment described for the corresponding similarly named component in any other drawing.

[0025] It should be understood that the singular forms "a", "an", and "the" include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to "an autonomous sensor" includes reference to one or more such autonomous sensors.

[0026] Terms such as "approximately", "substantially", etc. mean that the described characteristic, parameter, or value need not be achieved precisely, but that deviations or variations (including, for example, tolerances, measurement errors, measurement accuracy limitations, and other factors known to those skilled in the art) may occur in an amount that does not preclude the effect that the characteristic is intended to provide.

[0027] It should be understood that one or more steps shown in a flowchart may be omitted, repeated, and / or performed in an order different from the order shown. Thus, the scope disclosed in this specification should not be considered limited to the particular arrangement of steps shown in the flowchart.

[0028] The embodiments disclosed in this specification relate to a system and method for permanently monitoring casing and formation deformation using strain and shape sensing fiber optic sensors. This design has several advantages:

[0029] 1. Permanently monitor the deformation of pipelines, pipe fittings, metal and non-metal completion structures, cement pipe strings / casings, and open hole sections;

[0030] 2. Simultaneously monitor deformation at various azimuthal positions within a given height;

[0031] 3. Have multi-point characterization with different resolutions (i.e., the resolution can be increased along the azimuthal axis and the height axis when necessary); and

[0032] 4. Combine downhole testing and stimulation while monitoring, thereby supporting the measurement of formation deformation during coring, stress analysis, and stimulation.

[0033] Figure 1A illustrates a system according to one or more embodiments. Specifically, Figure 1A illustrates a well 100 that can be drilled in a subterranean formation 102. A casing 104 is a pipe that can be lowered into a borehole 106 and is designed to resist compressive and tensile stresses in the subterranean formation 102. The borehole 106 corresponds to the uncased portion of the well 100. The well 100 includes a packer 108. A packer 108 is a device that plugs or blocks a portion of the borehole 106 during a drilling or production operation. The packer 108 has a smaller initial inner diameter and means for radial expansion so as to couple with the casing 104 or the borehole 106. The packer 108 can be lowered into the well with a cable, pipe, or coiled tubing. Some packers 108 are temporarily placed in the well; other packers are permanently installed. When used during hydrocarbon production, the packer 108 is typically used to seal a portion of the well 100 so as to allow for controlled extraction from the well 100.

[0034] Figure 1B illustrates a cross-section of the well 100. The casing 104 is shown installed within the borehole 106, and cement 114 can fill the space between the casing 104 and the borehole 106. A production tubing 116 is located in the annulus within the casing 104.

[0035] According to Figure 1A and Figure 1B , a data transmission cable can be used to connect sensors in the borehole 106 to an optical analyzer 110 at the wellhead 111. The wellhead 111 is located at the earth's surface. In particular, an optical fiber cable 112 is a new technology that can transmit measurements obtained by sensors to the optical analyzer 110 by modulating signals onto a light carrier (such as a laser pulse). The optical fiber cable 112 can be deployed in a wellbore extending from the wellhead 111 to the subterranean formation 102. Another method of using the optical fiber cable 112 to obtain information is to use the cable itself as a sensor. In one or more embodiments, it is shown that the optical fiber cable 112 is used to detect strain and deformation in the casing 104 or the borehole 106.

[0036] Figure 2 illustrates an example of strain and deformation on a casing according to one or more embodiments. Strain and deformation are common in the industry and can be caused by natural and man-made processes. Figure 2 The arrows shown in illustrate examples of directions in which the casing 104 may undergo deformation or strain. Deformation and strain are represented by the difference between the dashed and solid circles.

[0037] Figure 3 illustrates a wellbore deformation instrument 300 according to one or more embodiments. The wellbore deformation instrument 300 can use Figure 1AThe packer 108 in it is part of the tool. The wellbore deformation instrument 300 can be used to measure strains and deformations similar to Figure 2 In one or more embodiments, the wellbore deformation instrument 300 is a tool in which an elastic substrate contacts a metal pipe fitting and deforms with the shape of the metal pipe fitting. Optical fibers mounted on the substrate capture its local deformed shape and strain (e.g., across a grid defined on the substrate, where the covered area is about 1 mm 2 to 100 mm 2 ). The shape is derived from the optical frequency domain or time domain reflectometry (OFDR or OTDR) of the fiber optic sensor, which includes at least three optical fibers (or multi-core optical fibers) arranged in a spiral pattern.

[0038] In one or more embodiments, the wellbore deformation instrument 300 includes a packer 108 and a plurality of components 301 mounted on the outer circumferential surface of the packer 108. In one or more embodiments, the packer 108 is an expandable annular cylindrical packer. The packer 108 serves as a structural support and ensures contact with the metal completion structure, production tubing, or borehole. Ideally, the packer 108 should be thin enough to avoid restricting flow. As shown by the outward arrows, the packer 108 can expand and push against the wall of the casing 104. The packer can also expand and push against the wall of the borehole 106 in the absence of the casing 104. The plurality of components 301 includes at least one fiber optic coil 302 embedded in a deformable base sheet 306, a tray-like container 304, and an optical coupler 303.

[0039] The wellbore deformation instrument 300 can be used to isolate sensors such as the fiber optic coil 302 from the borehole 106 environment, thus avoiding possible temperature or pressure effects caused by it. The fiber optic coil 302 is optically coupled to the fiber optic cable 112 through the optical coupler 303. The optical coupler 303 can be any component configured to couple the fiber optic coil 302 to the fiber optic cable 112. The fiber optic coil 302 can be an optical fiber used as a sensor. To use the fiber optic coil 302 as a sensor, the optical analyzer 110 sends a laser pulse that travels through the fiber optic cable 112 and the fiber optic coil 302, thereby emitting a backscattered laser pulse that is reflected back to the optical analyzer 110 from the end of the fiber optic cable 112. Changes in the characteristics of the backscattered laser pulse indicate physical changes that occur in the fiber optic coil 302.

[0040] Rayleigh backscattering is a type of scattering that occurs when the scattering locations distributed throughout the fiber coil 302 reflect the input laser pulse back to the optical analyzer 110. The optical analyzer 110 measures the changes in the phase, wavelength, and intensity of the backscattered laser pulse. The wavelength change can be used to measure the relative change in temperature in the fiber coil 302. The intensity change can be used to detect pressure changes. The phase change of the backscattered laser pulse can indicate the strain in the fiber coil 302.

[0041] Other scattering effects can be used to obtain data from the fiber coil 302. Brillouin scattering occurs when acoustic phonons traveling within the fiber coil 302 interact with the input laser pulse. The backscattered laser pulse from Brillouin scattering is much weaker than that from Rayleigh backscattering, and multiple backscattered laser pulses associated with the same event need to be summed to obtain an accurate measurement. This limits the applicability of this method to frequencies up to several tens of hertz. However, Brillouin scattering allows the measurement of the absolute value of temperature, which cannot be achieved by Rayleigh scattering. Raman backscattering occurs when light scatters at the molecular spatial scale. The Raman backscattered laser pulse is weaker than that from Brillouin scattering and requires the summation of the signal for many seconds. This limits the applicability of this technique to only the measurement of the absolute value of temperature.

[0042] In one or more embodiments, the fiber coil 302 can be used as a multi-pixel time-of-flight sensing method to characterize deformation. Multi-pixel can refer to each measurement region of one or more fiber coils 302. The multi-pixel time-of-flight sensing method can be a multi-point characterization with different resolutions. For example, the number of pixels or measurements can be increased as needed to provide finer resolution along the azimuthal axis and the elevation axis.

[0043] The optical analyzer 110 uses optical reflectometry to detect physical changes in the fiber coil 302. The optical analyzer 110 can be an optical time domain reflectometer (OTDR) or an optical frequency domain reflectometer (OFDR). The processing of the laser pulse can be done in the time domain with an OTDR or in the frequency domain with an OFDR. Processing with an OFDR provides better resolution than an OTDR, but an OTDR allows for a longer cable length.

[0044] The fiber coil 302 can be a conventional type with intrinsic backscattering, or it can be designed in a specific way, such as using a fiber Bragg grating (FBG), which is capable of selectively reflecting and transmitting light of certain wavelengths. The FBG is used in one embodiment of the fiber coil 302 described herein and can improve the signal-to-noise ratio, thereby increasing the processing speed.

[0045] The fiber coil 302 can be in any of the following configurations:

[0046] 1. A single-mode optical fiber is combined with an optical time domain reflectometer (OTDR) analyzer;

[0047] 2. Multiple non-overlapping optical fibers up to 20 meters in length are combined with an optical frequency domain reflectometer (OFDR) analyzer;

[0048] And

[0049] 3. Multiple non-overlapping optical fibers with three or more fiber Bragg gratings (FBGs).

[0050] The fiber coil 302 can be for fiber sensing of strain and deformation, which can be discrete or distributed. Discrete fiber sensing utilizes FBGs or Fabry - Perot (F - P) cavities. The distributed sensor of the fiber coil 302 is based on the analysis of Rayleigh scattering, Brillouin scattering, or Raman scattering by an optical time domain reflectometer (OTDR) or an optical frequency domain reflectometer (OFDR).

[0051] The tray - shaped container 304 is formed of a low - thermal - conductivity material (such as a glass fiber composite). The low - thermal - conductivity material is attached to the edge of the deformable substrate 306 along the edge of the tray - shaped container 304 through a pressure seal. The tray - shaped container 304, the deformable substrate 306, and the pressure seal can form a pressure - sealed compartment containing a high - pressure inert gas.

[0052] The deformable substrate 306 can be outside the wellbore deformation instrument 300. The deformable substrate 306 can deform to follow the shape of the material it contacts (i.e., the casing 104 or the borehole 106). The deformable substrate 306 can be but is not limited to being constructed of a high - temperature elastomer, a flexible thermoplastic, or a shape - memory polymer (SMP) with low thermal expansion (<0.01 mm / K) and low thermal conductivity (0.03 W / mK to 0.1 W / mK). The SMP uses an electrical signal to return to its original shape, enabling rapid release and recovery of the wellbore deformation instrument 300 and in - situ recalibration.

[0053] The deformable substrate 306 can be radially unconstrained or constrained. The latter can be achieved by using an anisotropic material (such as a composite or plastic with aligned chains in an elastomer matrix) embedding a woven reinforcing material, and an anisotropic hydrogel material with a honeycomb micro / nano structure or a combination thereof. The composite can be glass fiber.

[0054] Figures 4 to 8 Various embodiments of the fiber coil 302 on the deformable substrate 306 in the wellbore deformation instrument 300 installed in the casing 104 are shown. In one or more embodiments, Figure 4Shows the configuration of the wellbore deformation instrument 300 with an optical fiber coil 302 wound in a helical pattern. In this case, the distance between the optical fibers should be at least 10 mm. Thus, the optical fiber coil 302 can travel to the optical analyzer 110.

[0055] Figure 5 Shows the configuration of the wellbore deformation instrument 300 with an optical fiber coil 302 wound in an axial serpentine pattern. In this case, the distance between the optical fibers should be 10 mm or greater to ensure a bend radius greater than 10 mm. The optical fiber coil 302 can be connected to an optical fiber cable 112. The optical fiber cable 112 can be connected to an optical analyzer 110, such as an OFDR.

[0056] Figure 6 Shows the configuration of the wellbore deformation instrument 300 with an optical fiber coil 302 that combines an axial serpentine pattern and a helical pattern. In this case, the distance between the optical fibers of the optical fiber coil 302 should be 10 mm or greater to ensure a bend radius greater than 10 mm. The optical fiber coil 302 can be connected to an optical fiber cable 112. The optical fiber cable 112 can be connected to an optical analyzer 110, such as an OFDR.

[0057] Figure 7 Shows the configuration of the wellbore deformation instrument 300 using multiple distributed FBG sensors horizontally distributed in the optical fiber coil 302. The number of FBG sensors embedded in each optical fiber should be three or more. The maximum number is determined by the length of the optical fiber and the minimum spacing. The FBG sensors are connected to an N×M coupler 700, which can be used to separate the combined laser pulses from one optical fiber to multiple optical fibers with minimal optical loss. Each FBG is tuned to reflect light at a specific wavelength. The optical fiber terminus can be a perfect mirror or can return the transmitted laser pulses to a separate analyzer or optical analyzer 110.

[0058] Figure 8 Shows the configuration of the optical fiber coil 302 in the wellbore deformation instrument 300, where an axial serpentine distribution and a helical distribution are combined and mounted on an anisotropic displacement material. Figure 8The rectangle surrounding the fiber optic coil 302 shown in the figure can be a pixel or a measurement area. The distance between the fibers in this configuration should be 10 mm or greater to ensure a bend radius greater than 10 mm. The fibers can be connected to an N×M coupler 700, which can be used to separate the combined laser pulses from one fiber to multiple fibers with minimal optical loss. The separated fibers can be connected to a switch 800 (such as an optical switch), which converts the laser pulses into electrical data and then forwards them through the fiber optic cable 112 to the optical analyzer 110. The switch 800 can use a 1x2 90 / 10 laser pulse beam splitter, where the end of the 10% transmission arm ends with a mirror or a partially reflective window (90 / 10) to return a portion (<10%) of the input laser pulse (signal) for compensation. The wellbore deformation instrument 300 can use a separate laser for each fiber optic coil 302. For example, each fiber optic coil 302 can be connected to its own laser. Alternatively, the wellbore deformation instrument 300 can use a single laser unit source and the switch 800 to direct the laser pulses to each fiber optic coil 302. In another embodiment, the wellbore deformation instrument 300 can use the switch 800 at each of the N laser sources to direct the laser pulses to each fiber optic coil 302 connected to its N laser source. The possible patterns of the fiber optic cable 112 are not limited by Figures 4 to 8 the example shown.

[0059] Figures 9 to 11 A flowchart showing the possible electronics and signal processing units for N laser sources and M probes is shown. The M probes can be fiber optic coils 302. Thus, in one or more embodiments, the present invention employs N lasers for M fibers, where a switch is used at each of the N lasers to direct light to each of the MN fibers connected to the Nth laser. Those skilled in the art will understand that the measurement / interrogation system can be set up in a variety of ways, depending on the number of light sources, fibers, and analyzers. Figures 9 to 11 Depicts three electronics and data acquisition frameworks that can be used to process measurement data from fiber optic sensors / coils.

[0060] In Figures 9 to 11In [the figure], the area enclosed by the dashed box is on the ground and can be replicated N times to provide parallel analysis. The electronic devices in this configuration control the light source, trigger, time-to-digital converter (TDC) 902, and receiver 904. The receiver 904 has a digital-to-analog converter (D / A) that encodes the signal frequency and amplitude for processing. Those skilled in the art will understand that the electronic devices use a field-programmable gate array (FPGA) 906 as a trigger or initiator. The microprocessor 908 can perform the required calculations to estimate the frequency difference and absorption distribution of the FPGA 906. The FPGA 906 can trigger a pulsed laser 910 (such as a femtosecond pulsed laser (FC)) to send laser pulses. The laser pulses can be sent to the fiber coil 302 through a circulator 912, a delay + Mach-Zehnder interferometer (D+MZI) 914, or an optical analyzer 110. The fiber coil 302 can send the laser pulses through a switch 800 and / or an N×M coupler 700. The TDC 902 counts the time interval between each signal and sends a reset trigger to the FPGA 906 when the maximum set interval occurs. If a single laser is used, an acousto-optic amplitude modulator can be used in addition to each output coupler to distinguish the outputs. The TDC 902 or the receiver 904 can transfer data to the microprocessor 908. The microprocessor 908 can send the calculated values through a transceiver 916 and store them in a memory 918, which is, for example, a supervisory control and data acquisition (SCADA) system. In one or more embodiments, the optical analyzer is configured to emit laser pulses. Alternatively, the pulsed laser can directly pulse the fiber coil.

[0061] In Figure 9 [the figure], a single analyzer configuration is shown, which can utilize a commercial optical analyzer 110 system, such as an OTDR / OFDR system.

[0062] In Figure 10 and Figure 11 [the figure], the D+MZI 914 is used to prepare the optical detection state underground. The resulting interference pattern can be transmitted to the ground for analysis.

[0063] Figure 10 A schematic diagram of the electronic devices and signal processing of a single analyzer configuration is shown, which can utilize an optical analyzer 110, such as a commercial OTDR / OFDR system; N light sources and M fiber probes. This configuration can be used by discrete and distributed systems.

[0064] Figure 11Shows an electronic device for underground heterodyne detection and a signal processing schematic diagram; N shared sources and M distributed optical fiber probes. The optical signal is converted into two radio frequency (RF) signals using the balanced heterodyne detection (BHD) configuration in D+MZI 914. The RF signals are transmitted to the ground for analysis.

[0065] In one or more embodiments, energy is provided to the system by directly harvesting energy from the flow; for example, using a Tesla microturbine. Another option is to use thermoelectric materials designed for low thermal gradients and high pressures to obtain energy from the pressure gradient along the packer. The energy can also be provided through a cable, through an optical communication fiber, or through a downhole battery. If the energy is provided through an optical fiber link, in addition to the transceiver, the system can also include a 1x2 90 / 10 beam splitter and a photovoltaic cell located at the end of the 90% transmission arm. The bandgap of the photovoltaic cell can be designed to extract the maximum power from the incoming signal.

[0066] Figure 12 Shows a flowchart according to one or more embodiments. Specifically, Figure 12 Shows a method and apparatus for a wellbore deformation instrument 300. Figure 12 One or more of the boxes in can be performed using one or more components as described in FIGS. 1 to Figure 11 as described. Although Figure 12 the individual boxes in are presented and described in sequence, those skilled in the art will understand that some or all of these boxes can be performed in parallel and / or iteratively. In addition, these boxes can be performed actively or passively.

[0067] In block 1200, the wellbore deformation instrument 300 attached to the fiber optic cable 112 is inserted into the wellbore at a predetermined depth. The wellbore deformation instrument 300 can be attached to the fiber optic cable 112 through an optical coupler 303 that connects the fiber optic coil 302 in the wellbore deformation instrument 300. The wellbore can be a borehole 106. The wellbore deformation instrument 300 can be inserted by attaching a conveyance mechanism such as a production tubing 116.

[0068] In block 1202, the wellbore deformation instrument 300 expands in the wellbore. The expansion of the wellbore deformation instrument 300 presses a plurality of deformation sensors against the wellbore surface (block 1204). The deformation sensors may be deformable substrates 306 embedded with optical fiber coils 302. In block 1206, at a plurality of monitoring times spaced apart from each other by a time interval, a plurality of laser pulses are emitted from the optical analyzer 110 located at the wellhead 111 into the optical fiber cable 112. The laser pulses may be sent to the optical analyzer 110 by a pulsed laser 910 triggered by the FPGA 906. The optical analyzer 110 may be an optical time domain reflectometer (OTDR) analyzer. In block 1208, the backscattered laser pulses are detected according to each laser pulse. The backscattered laser pulses may be detected, calculated and processed by the receiver 904, the microprocessor 908, the TDC 902 and the transceiver 916. In block 1210, the deformation of the wellbore surface is determined at least in part based on the difference between the backscattered laser pulses at one or more pairs of monitoring times. Blocks 1206 to 1210 may be repeated multiple times as needed.

[0069] Although only a few exemplary embodiments have been described in detail above, those skilled in the art will readily understand that many modifications can be made to the exemplary embodiments without substantially departing from the invention.

Claims

1. A wellbore deformation instrument, comprising: An inflatable annular cylindrical packer; A plurality of components mounted on an outer circumferential surface of the packer and configured to be pressed by the packer against a wellbore surface, wherein each of the components comprises: At least one optical fiber coil embedded in a deformable base sheet; A tray-shaped container formed of a low thermal conductivity material and attached to an edge of the sheet along an edge of the container by a pressure seal, wherein a pressure-sealed compartment formed by the container, the sheet, and the seal contains a high-pressure inert gas, and An optical coupler configured to couple the at least one optical fiber coil to an optical fiber cable.

2. The borehole deformation instrument according to claim 1, wherein, The plurality of components includes a laser and an optical switch.

3. The wellbore deformation instrument according to claim 1 or 2, wherein, The deformable base sheet is made of a high-temperature elastomer, a flexible thermoplastic, or a shape memory polymer (SMP).

4. The wellbore deformation instrument according to any one of claims 1 to 3, wherein, The plurality of components is made of a non-metallic material.

5. The wellbore deformation instrument according to claim 4, wherein The non-metallic material is a glass fiber composite.

6. The wellbore deformation instrument according to any one of claims 1 to 5, wherein, The at least one optical fiber coil includes a plurality of non-overlapping optical fibers.

7. The wellbore deformation instrument according to any one of claims 1 to 6, wherein, The at least one optical fiber coil includes three or more fiber Bragg gratings (FBGs).

8. A system, comprising: A wellbore deformation instrument, the wellbore deformation instrument comprising: An inflatable annular cylindrical packer, A plurality of components mounted on an outer circumferential surface of the packer and configured to be pressed by the packer against a wellbore surface, wherein each of the components comprises: At least one optical fiber coil embedded in a deformable base sheet; A tray-shaped container formed of a low thermal conductivity material and attached to an edge of the sheet along an edge of the container by a pressure seal, wherein a pressure-sealed compartment formed by the container, the sheet, and the seal contains a high-pressure inert gas, and An optical coupler configured to couple the at least one optical fiber coil to an optical fiber cable; An optical fiber cable deployed in a wellbore extending from a wellhead to a subterranean formation and optically coupled to each of the at least one optical fiber coils by the optical coupler; and An optical analyzer configured to emit laser pulses into the optical fiber cable at the wellhead and receive backscattered laser pulses from each of the at least one optical fiber coils through the optical fiber cable.

9. The system according to claim 8, wherein, The plurality of components includes a laser and an optical switch.

10. The wellbore deformation instrument according to claim 8 or 9, wherein, The deformable base sheet is made of a high-temperature elastomer, a flexible thermoplastic, or a shape memory polymer (SMP).

11. The system according to any one of claims 8 to 10, wherein The plurality of components is made of a non-metallic material.

12. The system according to claim 11, wherein, The non-metallic material is a glass fiber composite.

13. The system according to any one of claims 8 to 12, wherein, The optical analyzer is an optical time domain reflectometer (OTDR) analyzer.

14. The system according to any one of claims 8 to 13, wherein, The at least one optical fiber coil includes a plurality of non-overlapping optical fibers.

15. The system according to any one of claims 8 to 14, wherein, The at least one optical fiber coil includes three or more fiber Bragg gratings (FBGs).

16. A method for monitoring wellbore deformation, comprising: Inserting a wellbore deformation instrument attached to an optical fiber cable into a wellbore at a predetermined depth; Expand the wellbore deformation instrument, wherein expanding the wellbore deformation instrument presses a plurality of deformation sensors against the wellbore surface; At a plurality of monitoring times spaced apart from each other by a time interval, emit a plurality of laser pulses from an optical analyzer located at the wellhead into the optical fiber cable; Detect backscattered laser pulses from each of the plurality of laser pulses; and Determine the deformation of the wellbore surface at least in part based on the difference between the backscattered laser pulses for one or more pairs of monitoring times.

17. The method according to claim 16, wherein, The plurality of deformation sensors are a plurality of distributed fiber Bragg gratings (FBGs).

18. The method according to claim 16 or 17, wherein Inserting the wellbore deformation instrument includes attaching a conveyance mechanism.

19. The method according to any one of claims 16 to 18, wherein, The conveyance mechanism is a production tubing.

20. The method according to any one of claims 16 to 19, wherein The optical analyzer is an optical time domain reflectometer (OTDR) analyzer.

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