DETAILED ACTION
Notice of Pre-AIA or AIA Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Information Disclosure Statement
The information disclosure statement (IDS) submitted on -04/26/2024 and 06/05/2025- is in compliance with the provisions of 37 CFR 1.97. Accordingly, the information disclosure statement is being considered by the examiner.
Claim Rejections - 35 USC § 102
The following is a quotation of the appropriate paragraphs of 35 U.S.C. 102 that form the basis for the rejections under this section made in this Office action:
A person shall be entitled to a patent unless –
(a)(1) the claimed invention was patented, described in a printed publication, or in public use, on sale, or otherwise available to the public before the effective filing date of the claimed invention.
(a)(2) the claimed invention was described in a patent issued under section 151, or in an application for patent published or deemed published under section 122(b), in which the patent or application, as the case may be, names another inventor and was effectively filed before the effective filing date of the claimed invention.
Claim(s) 1-6, 10-20 is/are rejected under 35 U.S.C. 102 a (1)/a (2) as being anticipated by Dickenson et al US 20170167245 A1 herein after “Dickenson”.
Regarding claim 1, Dickenson teaches a method implemented using a computerized monitoring system to monitor a completion assembly disposed in a wellbore, the completion assembly having a plurality of downhole components disposed at depths in the wellbore (para [0002] Embodiments of the present disclosure relate to monitoring systems and methods for use with equipment associated with a borehole or other conduit. In particular but not by way of limitation embodiments relate to systems and methods for monitoring vibration.), the method comprising:
storing, in memory of the computerized monitoring system, a plurality of operational events associated with the downhole components (Fig. 1. [0187] In some embodiments, the processing system 4 stores historic sensor information in the archive 41. This historic sensor information represents historic information regarding vibrations detected by the sensor system 3 and, in particular, by the vibration sensor subsystem 31. The historic sensor information may be stored in association with an identifier for one or more of the items of the equipment 6 (e.g. the pump 61) to which the sensor information relates.);
Examiner views the processor 4 records multiple operational events associated with downhole pumps (i.e., downhole components) using a memory
interrogating an optical fiber disposed along the completion assembly and disposed at least in acoustic communication with the downhole components by (para [0103] In some embodiments the vibration sensor subsystem 31 includes one or more optical fibres 311 and the sensor locations may each be a point along one of the one or more optical fibres 311.
[0104] The vibration sensor subsystem 31 may be a Distributed Vibration Sensing subsystem (“DVS”), which is also known as a Distributed Acoustic Sensing subsystem (“DAS”)):
injecting, using an optical source of the computerized monitoring system, input signals into the optical fiber ([0105] The vibration sensor subsystem 31 may, therefore, include one or more optical fibres 311 (which may be single mode or multimode or a mixture of both) and other components 312. The other components 312 may include an electromagnetic radiation source 312a which is configured to direct (i.e. transmit or emit) electromagnetic radiation along the one or more optical fibres 311);
From Fig. 1 and above paragraph examiner views the optical fiber 311 probed for examination or interrogation (i.e., with radiation source and detector, 312) which is disposed along the completion assembly of a down hole with set of multiple equipment, pumps 6 using a distributed acoustic sensing system. An electromagnetic radiation source 312a (i.e., optical source) is transmitted or input the signal into the optical fiber.
detecting, using an optical detector of the computerized monitoring system, return signals backscattered along the optical fiber (para [0104] Embodiments of the present disclosure may use coherent Rayleigh backscatter, Raman backscatter, or Brillouin backscatter, or another suitable type of backscatter in the Distributed Vibration Sensor subsystem.
[0105] an electromagnetic radiation receiver 312b which is configured to receive electromagnetic radiation from the one or more optical fibres 311. The electromagnetic radiation source 312a and electromagnetic radiation receiver 312b may be associated with a first end of the one or more optical fibres 311 (or a first location) such that the electromagnetic radiation receiver 312b is configured to receive electromagnetic radiation which has been reflected back towards the electromagnetic radiation source 312a (i.e. towards the first end or location).;
Examiner views the electromagnetic (optical) receiver 312b detect or receive the reflected signal backscattered along the optical fiber 311.
processing, using one or more processors of the computerized monitoring system, the return signals into processed signals according to a plurality of spatial resolutions for the downhole components along the optical fiber (para [0109] The use of an element 312c at each sensor location may improve the spatial resolution of the sensor information compared to reliance on intrinsic scattering of the electromagnetic radiation in the one or more optical fibres 311. For example, spatial resolution may be improved from about 5m without the use of the elements 312c to about 10 cm or less using the elements 312c in accordance with some embodiments of the disclosure.
[0133] As discussed above, the processing system 4 is configured to receive the sensor information from the sensor system 3 and this information is indicative of vibrations detected at the sensor location to which the sensor information relates.);
Examiner views the return or reflected signals received from the sensor are processed according to the multiple spatial resolution of the downhole component provided by the sensors 312c and optical fiber 311.
determining, using the one or more processors based on the processed signals, signatures for the downhole components at the spatial resolutions along the optical fiber (Fig. 2, para [0165] As will be appreciated, many of the operations of the processing system 4 are operations on the sensor information in the frequency domain. In some embodiments, the sensor information is divided by the processing system 4 in the time domain and one or more harmonic signatures are generated by the processing system 4—e.g. using statistical analysis.);
Examiner views the sensor signals received from the optical fiber 311 is used to determine a signature for downhole components at the spatial resolution.
and generating, using the one or more processors, baselines of the signatures over a time span for the downhole components (para [0131] The controlling of the one or more items of equipment 6 in a predetermined manner (e.g. in accordance with a predetermined sequence of commands or to generate a predetermined vibration signature) to determine resulting sensor information may be considered to be “active sensing”
[0165] The or each harmonic signature may represent the time period that each harmonic occurred in the sensor information.)
Examiner views the sensor signals received from the optical fiber 311 is used to determine a predetermined or baseline signature or signal for downhole components at the spatial resolution using a time period or time span.
detecting, using the processing unit, a deviation from the baseline in the signature for at least one of the downhole components (Fig. 6, para [0165] The processing system 4 may be configured to determine a status or imminent event in by comparing the or each harmonic signature with one or more harmonic signatures stored in the archive 41 and associated with known statuses or events. For example, the processing system 4 may generate a histogram of harmonic frequency or number versus the number of occurrences to provide the harmonic signature.); and
Examiner views the deviation from the reference or baseline signature is determined by comparing the generated signature to the reference or baseline signature, for example as shown in Fig. 6.
correlating, using the processing unit, the detected deviation to an associated one of the operational events for the at least one downhole component (para [0166] The processing system 4 may be further configured, in the time domain, to generate a representation, which may be a graphical representation, of the vibration amplitude/magnitude at various operating conditions of the one or more items of the equipment 6 (e.g. the pump 61). The operating conditions may be an angular position of a part of the pump 61, for example. This representation may be compared to historic representations stored in the archive 41 to determine a status or imminent event.).
In paragraphs [0164], [0165] and [0166] examiner views the detected deviation of the signature is associated with the operational condition or event of the downhole component like a pump or parts of the pump.
Regarding claim 2, Dickenson teaches the method of claim 1, comprising deploying the optical fiber as part of production tubing, as part of casing, or as a separate line for the completion assembly (para [0119] In accordance with a second optical fibre deployment method, a cable containing one or more optical fibres may be strapped or otherwise attached to the production tubing.).
Regarding claim 3, Dickenson teaches the method of claim 1, wherein the optical fiber comprises one or more of a single-mode optical fiber, a multimode optical fiber, and an engineered optical fiber (para [0105] The vibration sensor subsystem 31 may, therefore, include one or more optical fibres 311 (which may be single mode or multimode or a mixture of both) and other components 312.).
Regarding claim 4, Dickenson teaches the method of claim 1, wherein storing the operational events comprises storing the operational events selected from the group consisting of a leak, a torque buildup, a pressure buildup, a scale buildup, and a flow obstruction (para [0222] This monitoring system 1 may be configured to monitor production under the pump 61 and/or to detect leaking in the completion.).
Regarding claim 5, Dickenson teaches the method of claim 1, wherein interrogating the optical fiber to generate the baselines of the signatures over the time span for each of the downhole components comprises performing the interrogation at least during operational use of the completion assembly over the time span for production from the wellbore (para [0127] In some embodiments, the control system 5 may be configured (e.g. in response to an instruction from the processing system 4) to control the operation of one or more items of the equipment 6 (such as the pump 61) associated with the borehole or other conduit 2 in a manner which is intended to produce a predetermined vibration signature.
[0166] The processing system 4 may be further configured, in the time domain, to generate a representation, which may be a graphical representation, of the vibration amplitude/magnitude at various operating conditions of the one or more items of the equipment 6 (e.g. the pump 61).
Examiner views the baseline or reference signatures are generated using an optical fiber to observe or interrogate the operational condition of the wellbore components at completion during the production or operation of the component of pump in time domain (i.e., provides operational information over a time duration or span).
Regarding claim 6, Dickenson teaches the method of claim 5, wherein the method further comprises initially interrogating the optical fiber over an initial time span after installation of the completion assembly ([0016] The processing system may be further configured to determine a plurality of frequency spectra, with each frequency spectrum relating to a different time period, and to analyse the plurality of frequency spectra to identify one or more changes in the frequency spectra.
[0117] Embodiments of the present disclosure include methods and mechanisms for deploying one or more optical fibres 311 for use with other embodiments.
Examiner views the frequency spectra is analyzed or interrogated over different time period after the fiber optic is deployed or installed in the wellbore completion assembly. and
before the operational use to generate initial ones of the baselines of the signatures ([0033] The vibration sensor subsystem may include at least one Bragg grating at one or more of the sensor locations. These may be evenly distributed along the length of the pumping system or specifically aligned with elements of the pumping system. [0034] In some embodiments, the vibration sensor may include defects, non-linearities or the like that may be used to create reference/baseline outputs. The defects, non-linearities or the like may be disposed/created at known location along the conduit.).
Examiner views the data from vibration sensors disposed along the fiber optic cable are used to create an initial baseline signals or signatures to detect any fault in the wellbore components before use.
Regarding claim 10, Dickenson teaches the method of claim 1, wherein processing the return signals into the processed signals (para [0108] This element 312c may be configured to reflect at least a portion of the electromagnetic radiation emitted by the electromagnetic radiation source 312a back towards the electromagnetic radiation source 312a and, hence, towards the electromagnetic radiation receiver 312b.
[0111] In some embodiments, one or more switches or filters 312d are associated with the one or more optical fibres 311 and/or the electromagnetic radiation receiver 312b and/or the electromagnetic radiation source 312a. The one or more switches or filters 312d are configured to modulate the operation of the vibration sensor subsystem 31 such that both temperature information and sensor information (indicative of vibration) can be obtained from the same one or more optical fibres 311. This modulation may be achieved by modulating over time (e.g. using a switch of the one or more switches or filters 312d) or operating at two wavelengths (one for determining the temperature information and one for determining the sensor information (indicative of vibration)) and filtering using a filter of the one or more switches or filters 312d.)
Examiner views signal modulation as a signal processing on the received or returned signal from sensor element 312c.
and determining the signatures based on the processed signals comprises associating the processed signals to disturbances in the optical fiber caused by acoustic waves associated with the downhole components at the spatial resolutions along the optical fiber (para [0109] The use of an element 312c at each sensor location may improve the spatial resolution of the sensor information compared to reliance on intrinsic scattering of the electromagnetic radiation in the one or more optical fibres 311
[0165] The processing system 4 may be configured to determine a status or imminent event in by comparing the or each harmonic signature with one or more harmonic signatures stored in the archive 41 and associated with known statuses or events. For example, the processing system 4 may generate a histogram of harmonic frequency or number versus the number of occurrences to provide the harmonic signature.
para [0223] As will be understood, the sensor information is indicative of vibrations at the sensor locations and is, more specifically, indicative of changes in the strain on—for example—one or more optical fibres 311 at the sensor locations. The sensor information may also be described as representing one or more acoustic events.).
Examiner views the processor determines a harmonic signature based on the processed returned signal due to vibration/disturbances experienced in or along the optical fiber 311 due to one or more acoustic events sensed by the sensors 312c for spatial resolution at the downhole equipment 6.
Regarding claim 11, Dickenson teaches the method of claim 10, wherein generating the baselines of the signatures over the time span for each of the downhole components comprises generating the baselines from the disturbances (para [0127] In some embodiments, the control system 5 may be configured (e.g. in response to an instruction from the processing system 4) to control the operation of one or more items of the equipment 6 (such as the pump 61) associated with the borehole or other conduit 2 in a manner which is intended to produce a predetermined vibration signature.
[0165] As will be appreciated, many of the operations of the processing system 4 are operations on the sensor information in the frequency domain. In some embodiments, the sensor information is divided by the processing system 4 in the time domain and one or more harmonic signatures are generated by the processing system 4—e.g. using statistical analysis. The or each harmonic signature may represent the time period that each harmonic occurred in the sensor information. The processing system 4 may be configured to determine a status or imminent event in by comparing the or each harmonic signature with one or more harmonic signatures stored in the archive 41 and associated with known statuses or events. For example, the processing system 4 may generate a histogram of harmonic frequency or number versus the number of occurrences to provide the harmonic signature.).
From above paragraphs examiner views the predetermined signatures (i.e., baselines of the signatures) are created over the time period for each of the events or statuses (i.e., vibration or disturbances) of the downhole components.
Regarding claim 12, Dickenson teaches the method of claim 10, wherein detecting the deviation from the baseline in the signature for at least one of the downhole components comprises detecting a change of the disturbance with respect to a threshold, the threshold corresponding to the associated one of the operational events for the at least one downhole component (para [0159] In some embodiments, the processing system 4 is configured to assess changes in harmonic frequencies or in the amplitude/magnitude of vibrations at harmonic frequencies to determine a status or imminent event in relation to the one or more items of the equipment 6 (e.g. the pump 61). This may include comparing harmonic frequencies identified in current sensor information (e.g. from a frequency spectrum thereof) with historic harmonic frequencies stored in the archive 41 to identify one or more changes in the harmonic frequencies and/or the amplitude/magnitude of vibrations at those harmonic frequencies. Changes which are indicative of a status or imminent event may be identified by the processing system 5, which consequently performs one or more of the actions described above (such as outputting control information and/or scheduling maintenance).
[0165] The processing system 4 may be configured to determine a status or imminent event in by comparing the or each harmonic signature with one or more harmonic signatures stored in the archive 41 and associated with known statuses or events. For example, the processing system 4 may generate a histogram of harmonic frequency or number versus the number of occurrences to provide the harmonic signature. [0166] The processing system 4 may be further configured, in the time domain, to generate a representation, which may be a graphical representation, of the vibration amplitude/magnitude at various operating conditions of the one or more items of the equipment 6 (e.g. the pump 61). The operating conditions may be an angular position of a part of the pump 61, for example. This representation may be compared to historic representations stored in the archive 41 to determine a status or imminent event).
Examiner views the deviation from the baseline in signature is detected by comparing each harmonic signature with one or more harmonic signatures stored in the archive 41 associated known statuses or events (i.e., with respect to a threshold), vibration (or disturbances) and operating status of the components in the wellbore. The deviation is visualized in the graphs regarding the vibration amplitude/magnitude at various operating conditions of the one or more items of the equipment 6 (e.g. the pump 61).
Regarding claim 13, Dickenson teaches the method of claim 10, wherein detecting the deviation from the baseline in the signature for at least one of the downhole components comprises detecting the disturbance with respect to an instantiation in the signature, the instantiation corresponding to the associated one of the operational events for the at least one downhole component (Please see above in claim 12 paragraphs [0165] and [0166]. Examiner views the deviation from the baseline in signature is detected or represented (i.e., instantiated) by comparing each harmonic signature with one or more harmonic signatures stored in the archive 41 associated known statuses or events (i.e., with respect to a threshold), vibration (or disturbances) and operating status of the components in the wellbore. The deviation is visualized or instantiated in the graphs regarding the vibration amplitude/magnitude at various operating conditions of the one or more items of the equipment 6 (e.g. the pump 61).
Regarding claim 14, Dickenson teaches the method of claim 1, wherein the method further comprises performing a preventative action based on the correlation of the detected deviation to the associated one of the operational events for the at least one downhole component (para [0159] In some embodiments, the processing system 4 is configured to assess changes in harmonic frequencies or in the amplitude/magnitude of vibrations at harmonic frequencies to determine a status or imminent event in relation to the one or more items of the equipment 6 (e.g. the pump 61)…Changes which are indicative of a status or imminent event may be identified by the processing system 5, which consequently performs one or more of the actions described above (such as outputting control information and/or scheduling maintenance).).
Examiner views the control or maintenance schedule of the downhole component is correlated to the deviation or changes in operational event or condition of downhole component, pump.
Regarding claim 15, Dickenson teaches the method of claim 14, wherein performing the preventative action is selected from the group consisting of: performing a chemical injection in the completion assembly, changing an existing chemical injection in the completion assembly, increasing/decreasing a chemical injection rate in the completion assembly, and increasing/decreasing a frequency of exercising the at least one downhole component (please see above in para [0159] Examiner views the control or maintenance schedule (i.e, preventive action) of the downhole component is correlated to the deviation or changes in operational event or condition (i.e., change increasing/decreasing frequencies) of downhole component.
Regarding claim 16, Dickenson teaches the method of claim 1, wherein the method further comprises identifying, using the processing unit, a failure of the at least one downhole component based on the correlation of the detected deviation to the associated one of the operational events for the at least one downhole component (para [0141] Examples of frequency spectra may be stored in the archive 41 (or elsewhere) representing known events such as: [0142] a. the failure or onset of failure or likely imminent failure of an item of the equipment 6 (e.g. pump 61 failure); and/or [0143] b. the failure or onset of failure or likely imminent failure of a component of an item of the equipment 6 (e.g. a component of the pump 61)
[0159] In some embodiments, the processing system 4 is configured to assess changes in harmonic frequencies or in the amplitude/magnitude of vibrations at harmonic frequencies to determine a status or imminent event in relation to the one or more items of the equipment 6 (e.g. the pump 61). This may include comparing harmonic frequencies identified in current sensor information (e.g. from a frequency spectrum thereof) with historic harmonic frequencies stored in the archive 41 to identify one or more changes in the harmonic frequencies and/or the amplitude/magnitude of vibrations at those harmonic frequencies.
Examiner views the failure of the downhole component like pump is correlated to the deviation or changes in operational event or condition (i.e., change increasing/decreasing frequencies) of downhole component.
Regarding claim 17, Dickenson teaches A programmable storage device having program instructions stored thereon for causing one or more processors to perform a method of claim 1 to monitor a completion assembly disposed in a wellbore (para [0080] Furthermore, embodiments may be implemented by hardware, software, firmware, middleware, microcode, hardware description languages, or any combination thereof. When implemented in software, firmware, middleware or microcode, the program code or code segments to perform the necessary tasks may be stored in a machine readable medium such as storage medium).
Claim 18 and 19 is rejected as claim 1 having similar claim limitations.
Regarding claim 20, Dickenson teaches the completion assembly of claim 19, wherein the components are selected from the group consisting of tubing, a downhole tool, a wellscreen, a subsurface safety valve, a packer, a sliding sleeve, an inflow control valve, a chemical injection device, a gas lift device, and an electric submersible pump (para [0006] Monitoring equipment may be used, in particular, to monitor vibrations associated with equipment such as a pump that may be used in a borehole or a pipe associated with a borehole—an example of such a pump is an Electrical Submersible Pump (“ESP”).).
Claim Rejections - 35 USC § 103
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
Claim(s) 7 is/are rejected under 35 U.S.C. 103 as being unpatentable over Dickension in Martin et al US 20150346370 herein after “Martin”.
Regarding Claim 7 Dickenson teaches, the method of claim 5, however Dickenson does not teach wherein the method further comprises initially interrogating a calibration optical fiber over a calibration time span for one or more of the downhole components before installation of the completion assembly to generate calibration ones of the baselines of the signatures
Martin teaches wherein the method further comprises initially interrogating a calibration optical fiber over a calibration time span for one or more of the downhole components before installation of the completion assembly to generate calibration ones of the baselines of the signatures (para [0012] As shown in FIG. 1, the borehole 1 is a completion well, a well ready for production or injection following a drilling process. The DAS system 100 includes an optical fiber 110 and an interrogation unit 120. In the exemplary embodiment shown by FIG. 1, the interrogation unit 120 is on the surface, and the optical fiber 110 is disposed along a carrier 2. The DAS system 100 also includes a calibration component comprising a vibration tool 140 that outputs vibrations at a specified frequency and amplitude.
Para [0015] According to an embodiment of the invention, the DAS signal is a measure of interference among the Rayleigh scatter originating from multiple nearby points in the optical fiber 110 over time (a number of samples of interference signals from a particular length of the optical fiber 110.
Para [0016] According to yet another embodiment, two or more DAS signals are obtained when the vibration tool 140 is activated at known amplitude and frequency values. The vibration tool 140 may be moved to one or more other known depths and the process of obtaining DAS signals may be repeated. Based on the DAS signals (with or without vibration tool 140 activation), the acoustic output of the DAS system 100 is calibrated using the known frequency, amplitude, and depth of the vibration tool 140 output. The calibration itself (how the DAS signals and known values are used) is according to one or more known techniques. Once the DAS system 100 is calibrated, the vibration tool 140 may be removed from the borehole 1. As noted above, at this point, the DAS system 100 may be used to detect an acoustic event in the borehole 1. Because of the calibration process, the DAS system 100 is able to quantify the event and also discern the depth of the event.)
From Fig. 1 and above paragraphs examiner views DAS with calibration optical fiber 112 is interrogated over calibration time period at each level event (i.e., for each completion assembly component) at a wellbore ready for production (i.e., before the completion assemblies are installed in the wellbore). The signal collected from the calibrated DAS (i.e., signature) is used as a baseline to monitor the completion assemblies in the wellbore during production.
Accordingly, it would have been obvious to one of ordinary skill in the art before the effective filing of the invention to have incorporated Martin into Dickenson for the purpose of calibrating the optical fiber system before installing the wellbore completion components so that the calibrated signal can be used to monitor the components during the production period when the components are in use.
Claim(s) 8, 9 is/are rejected under 35 U.S.C. 103 as being unpatentable over Dickension in view of Alali et al US 20220011464 A1 herein after “Alali”.
Regarding claim 8, Dickenson teaches the method of claim 1, however Dickenson does not teach wherein injecting the input signals into the optical fiber comprises transmitting coherent laser pulses along the optical fiber.
Alali teaches wherein injecting the input signals into the optical fiber comprises transmitting coherent laser pulses along the optical fiber (para [0026] For example, interrogation subsystem 152 may include a coherent laser source that may generate and transmit an optical pulse having a power level sufficient to induce a nonlinear effect (e.g. a Kerr effect) in the optical fiber.).
Accordingly, it would have been obvious to one of ordinary skill in the art before the effective filing of the invention to have incorporated Alali into Dickenson for the purpose of using a coherent laser pulse along the optical fiber so that the reflected so that the signal intensity changes can be accurately monitored.
Regarding claim 9, Dickenson teaches the method of claim 1, however Dickenson does not teach wherein detecting the return signals backscattered along the optical fiber and processing the return signals according to the plurality of spatial resolutions for the downhole components along the optical fiber comprise using Coherent Rayleigh Optical Time Domain Reflectometry (COTDR).
Alali teaches wherein detecting the return signals backscattered along the optical fiber and processing the return signals according to the plurality of spatial resolutions for the downhole components along the optical fiber comprise using Coherent Rayleigh Optical Time Domain Reflectometry (COTDR). (para [0051] The intensity of the reflected light may be measured as a function of time after transmission of the laser pulse. This is known as Coherent Rayleigh Optical Time Domain Reflectometry (COTDR). When the pulse has had time to travel the full length of the fiber and back, the next laser pulse can be sent along the fiber. Changes in the reflected intensity of successive pulses from the same region of fiber may be caused by changes in the optical path length of that section of fiber, as seen in FIG. 3B).
Accordingly, it would have been obvious to one of ordinary skill in the art before the effective filing of the invention to have incorporated Alali into Dickenson for the purpose of using a coherent laser pulse along the optical fiber and COTDR so that the reflected so that the signal intensity changes in time domain can be accurately monitored from downhole components.
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure.
Duncan et al US 20120179378 A1 discussed monitoring downhole components using fiber optic cables/sensors.
Lee et US 20170167249 A1 discussed monitoring vibrations of downhole components using fiber optic cables.
Any inquiry concerning this communication or earlier communications from the examiner should be directed to SHARAD TIMILSINA whose telephone number is (571)272-7104. The examiner can normally be reached Monday-Friday 9:00-5:00.
Examiner interviews are available via telephone, in-person, and video conferencing using a USPTO supplied web-based collaboration tool. To schedule an interview, applicant is encouraged to use the USPTO Automated Interview Request (AIR) at http://www.uspto.gov/interviewpractice.
If attempts to reach the examiner by telephone are unsuccessful, the examiner’s supervisor, Catherine Rastovski can be reached at 571-270-0349. The fax phone number for the organization where this application or proceeding is assigned is 571-273-8300.
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/SHARAD TIMILSINA/Examiner, Art Unit 2857
/Catherine T. Rastovski/Supervisory Primary Examiner, Art Unit 2857
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