Office Action 1: Non-Final Rejection (2024-10-22)
Rejection types: 103 - Obviousness, 112 - Written Description/Enablement

CLAIMS:
WHAT IS CLAIMED IS:
1\. A method for downhole fault detection in a well system, comprising: transmitting a spread spectrum time domain reflectometry (SSTDR) signal downhole via a well electrical cable of the well system; receiving, from the well electrical cable, a reflected SSTDR signal associated with the transmitted SSTDR signal; and determining whether a downhole fault is detected in the well electrical cable or in at least one of a plurality of well devices coupled with the well electrical cable based, at least in part, on a signal analysis of the reflected SSTDR signal and the transmitted SSTDR signal.
2\. The method of claim 1, further comprising: in response to detecting a downhole fault in the well electrical cable or in at least one of the plurality of well devices, determining a location of the downhole fault and a type of the downhole fault, wherein the location of the downhole fault includes a depth downhole of the downhole fault.
3\. The method of claim 2, wherein the well electrical cable includes cable lines and downhole connectors, further comprising: determining whether the downhole fault is in a section of the cable lines, in at least one of the downhole connectors, or in at least one of the plurality of well devices based, at least in part, on the depth downhole of the downhole fault and the type of the downhole fault.
4\. The method of claim 1, further comprising: correlating the reflected SSTDR signal with the transmitted SSTDR signal; and performing the signal analysis based, at least in part, on the correlation of the reflected SSTDR signal with the transmitted SSTDR signal.
5\. The method of claim 1, further comprising: performing the signal analysis of the reflected SSTDR signal and the transmitted SSTDR signal using a machine learning algorithm.
6\. The method of claim 1, further comprising: performing spread spectrum signal analysis on the reflected SSTDR signal and the transmitted SSTDR signal to determine real-time SSTDR data for the well system; accessing historical SSTDR data for the well system; and determining whether a downhole fault is detected based, at least in part, on the real-time SSTDR data and the historical SSTDR data for the well system.
7\. The method of claim 6, further comprising: accessing historical SSTDR data for one or more additional well systems; and determining whether a downhole fault is detected based, at least in part, on the real-time SSTDR data for the well system, the historical SSTDR data for the well system, and the historical SSTDR data for the one or more additional well systems.
8\. The method of claim 1, further comprising: detecting a downhole fault in a first well device of the plurality of well devices based, at least in part, on a depth downhole of the downhole fault and a type of the downhole fault; and determining which component of a plurality of components of the first well device is faulty based, at least in part, on the type of the downhole fault and one or more signal signatures detected in at least the reflected SSTDR signal.
9\. An apparatus for downhole fault detection in a well system, comprising: one or more processors; and a computer-readable medium having instructions stored thereon that are executable by the one or more processors to cause the apparatus to: transmit a spread spectrum time domain reflectometry (SSTDR) signal downhole via a well electrical cable of the well system; receive, from the well electrical cable, a reflected SSTDR signal associated with the transmitted SSTDR signal; and determine whether a downhole fault is detected in the well electrical cable or in at least one of a plurality of well devices coupled with the well electrical cable based, at least in part, on a signal analysis of the reflected SSTDR signal and the transmitted SSTDR signal.
10\. The apparatus of claim 9, wherein the instructions further cause the apparatus to: in response to detection of a downhole fault in the well electrical cable or in at least one of the plurality of well devices, determine a location of the downhole fault and a type of the downhole fault, wherein the location of the downhole fault includes a depth downhole of the downhole fault.
11\. The apparatus of claim 10, wherein the well electrical cable includes cable lines and downhole connectors, and the instructions further cause the apparatus to: determine whether the downhole fault is in a section of the cable lines, in at least one of the downhole connectors, or in at least one of the plurality of well devices based, at least in part, on the depth downhole of the downhole fault and the type of the downhole fault.
12\. The apparatus of claim 9, wherein the instructions further cause the apparatus to: correlate the reflected SSTDR signal with the transmitted SSTDR signal; and perform the signal analysis based, at least in part, on the correlation of the reflected SSTDR signal with the transmitted SSTDR signal.
13\. The apparatus of claim 9, wherein the instructions further cause the apparatus to: perform the signal analysis of the reflected SSTDR signal and the transmitted SSTDR signal using a machine learning algorithm.
14\. The apparatus of claim 9, wherein the instructions further cause the apparatus to: perform spread spectrum signal analysis on the reflected SSTDR signal and the transmitted SSTDR signal to determine real-time SSTDR data for the well system; access historical SSTDR data for the well system; and determine whether a downhole fault is detected based, at least in part, on the real-time SSTDR data and the historical SSTDR data for the well system.
15\. The apparatus of claim 9, wherein the instructions further cause the apparatus to: detect a downhole fault in a first well device of the plurality of well devices based, at least in part, on a depth downhole of the downhole fault and a type of the downhole fault; and determine which component of a plurality of components of the first well device is faulty based, at least in part, on the type of the downhole fault and one or more signal signatures detected in at least the reflected SSTDR signal.
16\. A well system for hydrocarbon recovery, comprising: a well electrical cable; a plurality of well devices coupled with the well electrical cable; and a spread spectrum time domain reflectometry (SSTDR) apparatus coupled with the well electrical cable, the SSTDR apparatus configured to: transmit an SSTDR signal downhole via a well electrical cable of the well system; receive, from the well electrical cable, a reflected SSTDR signal associated with the transmitted SSTDR signal; and determine whether a downhole fault is detected in the well electrical cable or in at least one of the plurality of well devices based, at least in part, on a signal analysis of the reflected SSTDR signal and the transmitted SSTDR signal. .
17\. The well system of claim 16, wherein the SSTDR apparatus is further configured to: in response to detection of a downhole fault in the well electrical cable or in at least one of the plurality of well devices, determine a location of the downhole fault and a type of the downhole fault, wherein the location of the downhole fault includes a depth downhole of the downhole fault.
18\. The well system of claim 17, wherein the well electrical cable includes cable lines and downhole connectors, and the SSTDR apparatus is further configured to: determine whether the downhole fault is in a section of the cable lines, in at least one of the downhole connectors, or in at least one of the plurality of well devices based, at least in part, on the depth downhole of the downhole fault and the type of the downhole fault.
19\. The well system of claim 16, wherein the SSTDR apparatus is further configured to: perform spread spectrum signal analysis on the reflected SSTDR signal and the transmitted SSTDR signal to determine real-time SSTDR data for the well system; access historical SSTDR data for the well system; and determine whether a downhole fault is detected based, at least in part, on the real-time SSTDR data and the historical SSTDR data for the well system.
20\. The well system of claim 16, wherein the SSTDR apparatus is further configured to: detect a downhole fault in a first well device of the plurality of well devices based, at least in part, on a depth downhole of the downhole fault and a type of the downhole fault; and determine which component of a plurality of components of the first well device is faulty based, at least in part, on the type of the downhole fault and one or more signal signatures detected in at least the reflected SSTDR signal.

OFFICE ACTION:
Detailed Action
Claim Rejections - 35 USC § 112
The following is a quotation of 35 U.S.C. 112(b):
(b)  CONCLUSION.—The specification shall conclude with one or more claims particularly pointing out and distinctly claiming the subject matter which the inventor or a joint inventor regards as the invention.
The following is a quotation of 35 U.S.C. 112 (pre-AIA ), second paragraph:
The specification shall conclude with one or more claims particularly pointing out and distinctly claiming the subject matter which the applicant regards as his invention.
Claim(s) 2-3, 8, 10-11 and 15-20 is/are rejected under 35 U.S.C. 112(b) or 35 U.S.C. 112 (pre-AIA ), second paragraph, as being indefinite for failing to particularly point out and distinctly claim the subject matter which the inventor or a joint inventor, or for pre-AIA  the applicant regards as the invention.
In regards to claim 2, the claim recites several time the limitation of “the downhole fault”. Claim 1 defines a downhole fault in line 6 and claim 2 defines a downhole fault in line 2. It is unclear each time the limitation of “the downhole fault” is recited if the limitation is referring to the fault defined in claim 1 or referring to the fault defined in claim 2. For this reason, the claim is indefinite.
Also, Claims 1 and 2 defines a downhole fault in the well electrical cable and a downhole fault in at least one of the plurality of devices. It is unclear each time the limitation of “the downhole fault” is recited if the limitation is referring to the fault of the cable or to the fault of the at least one device. For this reason, the claim is indefinite.
The examiner has interpreted the claim in the following way in order to advance prosecution:
line 2:“in response to detecting [[a]] the downhole fault”, and
lines 4-7: “a location of the detected downhole fault and a type of the detected downhole fault, wherein the location of the detected downhole fault includes a depth downhole of the detected downhole fault.”
In regards to claim(s) 3, the claim(s) is/are indefinite due to its/their dependency on indefinite claim 2.
Also, the claim has the same issues described in the rejection of claim 2 above. For this reason, the claim is indefinite.
The examiner has interpreted the claim in the following way in order to advance prosecution:
line 3 “determining whether the detected downhole fault is”, and
lines 5-6 “at least in part, on the depth downhole of the detected downhole fault and the type of the detected downhole fault”.
In regards to claim 8, the claim has the same issues described in the rejection of claim 2 above. For this reason, the claim is indefinite. The examiner has interpreted the claim in the following way in order to advance prosecution: line 3 “ a depth of the downhole fault in the first well device and a type of the downhole fault in the first well device”, and line 6 “on the type of the downhole fault in the first well device”.
In regards to claim 10, the claim has the same issues described in the rejection of claim 2 above.
In regards to claim(s) 11, the claim(s) is/are indefinite due to its/their dependency on indefinite claim 10.
Also, the claim has the same issues described in the rejection of claim 3 above. For this reason, the claim is indefinite.
In regards to claim 15, the claim has the same issues described in the rejection of claim 8 above.
In regards to claim 16, the claim recites several times the limitation of “the well electrical cable”. The claim defines the cable in line 2 and again in line 6. It is unclear each time the limitation of “the well electrical cable” is recited if the limitation is referring to the cable defined in line 2 or referring to the cable defined in in line 6. For this reason, the claim is indefinite. The examiner has interpreted line 6 of the claim in the following way in order to advance prosecution: “via [[a]] the well electrical cable”.
In regards to claim(s) 17-20, the claim(s) is/are indefinite due to its/their dependency on indefinite claim 16.
In regards to claim(s) 17 and 18, the claims have the same issues described in the rejection of claim 16 above. For this reason, the claim is indefinite.
In regards to claim 17, the claim has the same issues described in the rejection of claim 2 above.
In regards to claim(s) 18, the claim(s) is/are indefinite due to its/their dependency on indefinite claim 17.
Also, the claim has the same issues described in the rejection of claim 3 above. For this reason, the claim is indefinite.
In regards to claim 20, the claim has the same issues described in the rejection of claim 8 above.
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) 1-4 and 9-12 is/are rejected under 35 U.S.C. 103 as being unpatentable over Pacault et al. (US-2005/0046591) in view of Jeon et al. (US-10,338,124).
In regards to claim 1, Pacault teaches a method for downhole fault detection in a well system, the method comprising transmitting time domain reflectometry (TDR) signal downhole via a well electrical cable of the well system and receiving, from the well electrical cable, a reflected TDR signal associated with the transmitted TDR signal [fig. 19, par. 0052 L. 1-12].
Pacault teaches that the method is used to detect a fault in the well electrical cable [fig. 19, par. 0052 L. 1-3]. However, Pacault does not teach that the transmitted signal and the received signal are spread spectrum time domain reflectometry (SSTDR) signals.
On the other hand, Jeon teaches that a fault in an electrical can be detected by transmitting a SSTDR signal and receiving a reflected STTDR signal associated with the transmitted SSTDR signal [col. 2 L. 35-42 and L. 65-67, col. 5 L. 58-64, col. 6 L. 5-11]. Furthermore, Jeon teaches that the method comprises determining whether a downhole fault is detected in the electrical cable based, at least in part, on a signal analysis of the reflected SSTDR signal and the transmitted SSTDR signal [col. 5 L. 62-67, col. 6 L. 63-67, col. 67 L. 1-10].
It would have been obvious to one of ordinary skill in the art, before the effective filing date of the claimed invention, to use Jeon’s teachings of using SSTDR for detecting a fault in the electrical cable in the method taught by Pacault because it will permit the system to detect the fault with more accuracy.
In regards to claim 2, the combination of Pacault and Jeon, as applied in the rejection of claim 1 above, further teaches that in response to detecting the downhole fault in the well electrical cable, determining a location of the detected downhole fault and a type of the downhole fault, wherein the location of the detected downhole fault includes a distance (depth downhole of the detected downhole fault) [see Jeon col. 6 L. 63-67, col. 7 L. 1-10, L. 25-34 and L. 43-52, col. 10 L. 20-25].
In regards to claim 3, the combination of Pacault and Jeon, as applied in the rejection of claim 2 above, further teaches that the well electrical cable includes cable lines and downhole connectors [see Pacault fig. 4 elements 40 (connectors), fig. 19 elements 5a and 5b (cable lines), par. 0033 L. 2-6par. 0036 L. 1-6]. Also, the combination teaches that the system can detect the location and type of the fault in the cable [see Jeon col. 5 L. 62-64]. This teaching means that the method comprises determining whether the downhole fault is in a section of the cable lines or in at least one of the downhole connectors at least in part, on the depth downhole of the downhole fault and the type of the downhole fault.
In regards to claim 4, the combination of Pacault and Jeon, as applied in the rejection of claim 1 above, further teaches that the method comprises correlating the reflected SSTDR signal with the transmitted SSTDR signal; and performing the signal analysis based, at least in part, on the correlation of the reflected SSTDR signal with the transmitted SSTDR signal [see Jeon col. 6 L. 21-25, L. 64-67, col. 7 L. 1-10].
In regards to claim 9, the combination of Pacault and Jeon, as shown in the rejection of claim 1 above, teaches a method performing the functions of the claimed apparatus. Therefore, the combination also teaches the claimed apparatus. Furthermore, the combination teaches that the method is performed by a processor using instructions stored in a computer readable medium [see Jeon col. 10 L. 54-61].
In regards to claim 10, the combination of Pacault and Jeon, as shown in the rejection of claim 2 above, teaches the claimed limitations.
In regards to claim 11, the combination of Pacault and Jeon, as shown in the rejection of claim 3 above, teaches the claimed limitations.
In regards to claim 12, the combination of Pacault and Jeon, as shown in the rejection of claim 4 above, teaches the claimed limitations.
Claim(s) 5 and 13 is/are rejected under 35 U.S.C. 103 as being unpatentable over Pacault et al. (US-2005/0046591) in view of Jeon et al. (US-10,338,124) as applied to claim(s) 1 and 9 above, and further in view of Shin et al. (US-11,762,007).
In regards to claim 5, the combination of Pacault and Jeon, as applied in the rejection of claim 1 above, further teaches that the method comprises performing the signal analysis of the reflected SSTDR signal and the transmitted SSTDR signal [see Jeon col. 5 L. 62-64]. However, the combination does not teach that a machine learning algorithm is used to analyze the signals.
On the other hand, Shin teaches the concept of using machine learning to analyze signals used for fault detection [col. 1 L. 35-39].
It would have been obvious to one of ordinary skill in the art, before the effective filing date of the claimed invention, to use Shin’s teachings of using machine learning for fault detection analysis in the method taught by the combination because it will permit the system to improve over time and detect faults more accurately.
In regards to claim 13, the combination of Pacault, Jeon and Shin, as shown in the rejection of claim 5 above, further teaches the claimed limitations.
Claim(s) 6 and 14 is/are rejected under 35 U.S.C. 103 as being unpatentable over Pacault et al. (US-2005/0046591) in view of Jeon et al. (US-10,338,124) as applied to claim(s) 1 and 9 above, and further in view of Shier (US-11,815,560).
In regards to claim 6, the combination of Pacault and Jeon, as applied in the rejection of claim 1 above, further teaches performing spread spectrum signal analysis on the reflected SSTDR signal and the transmitted SSTDR signal to determine real-time SSTDR data for the well system [see Jeon col. 5 L. 58-64]. The combination also teaches determining whether a downhole fault is detected based, at least in part, on the real-time SSTDR data.
The combination does not teach accessing historical SSTDR data for the well system; and determining whether a downhole fault is detected based, at least in part, on the historical SSTDR data for the well system.
On the other hand, Shier teaches that analysis to detect fault can also comprise accessing historical testing data for the system; and determining whether a fault is detected based, at least in part, on the historical testing data for the system [col. 11 L. 64-67, col. 12 L. 1-3 and L. 45-50].
It would have been obvious to one of ordinary skill in the art, before the effective filing date of the claimed invention, to use Shier’s teachings of using historical testing data to detect the fault  in the method taught by the combination because it will permit the system to detect the fault more accurately.
In regards to claim 14, the combination of Pacault, Jeon and Shier, as shown in the rejection of claim 6 above, further teaches the claimed limitations.
Claim(s) 7 is/are rejected under 35 U.S.C. 103 as being unpatentable over Pacault et al. (US-2005/0046591) in view of Jeon et al. (US-10,338,124) and Shier (US-11,815,560) as applied to claim(s) 6 above, and further in view of Salminen et al. (US-10,513,920).
In regards to claim 7, the combination of Pacault, Jeon and Shier, as applied in the rejection of claim 6 above, further teaches determining whether a downhole fault is detected based, at least in part, on the real-time SSTDR data for the well system and the historical SSTDR data for the well system [see Jeon col. 5 L. 58-64, see Shier col. 11 L. 64-67, col. 12 L. 1-3 and L. 45-50].
The combination does not teach determining whether a downhole fault is detected based, at least in part, on historical SSTDR data for the one or more additional well systems.
On the other hand, Salminen teaches the concept of also using historical data from additional wells to determine a condition downhole [col. 4 L. 49-62]. This teaching means that the method comprises accessing historical data for one or more additional well systems which in the case of the combination is SSTDR data. The teaching also mean that the method comprises determining whether a condition is detected based at least on part on the historical data for the one or more additional well systems which in the case of the combination is a fault condition.
It would have been obvious to one of ordinary skill in the art, before the effective filing date of the claimed invention, to use Salminen’s teachings of using historical data of other wells to detect the condition in the method taught by the combination because it will permit the system to better detect a fault condition in the current well.
Claim(s) 8 and 15 is/are rejected under 35 U.S.C. 103 as being unpatentable over Pacault et al. (US-2005/0046591) in view of Jeon et al. (US-10,338,124) as applied to claim(s) 1 and 9 above, and further in view of Kamata et al. (US-8,174,403) and Furse et al. (US-9,244,117).
In regards to claim 8, the combination of Pacault and Jeon, as applied in the rejection of claim 1 above, does not teach a plurality of well devices coupled to the cable.
On the other hand, Kamata teaches that a plurality of devices can be coupled to the cable [fig. 2 element 107].
It would have been obvious to one of ordinary skill in the art, before the effective filing date of the claimed invention, to use Kamata’s teachings of having a plurality of devices coupled to the electrical cable in the method taught by the combination because it will permit the system to sense different conditions at different depths within the wellbore.
The combination of Pacault, Jeon and Kamata does not teach detecting a downhole fault in a first well device of the plurality of well devices based, at least in part, on a depth downhole of the downhole fault and a type of the downhole fault.
On the other hand, Furse teaches that a device from a plurality of devices coupled to the cable can be identified to have a fault in one of its components based on the type of fault and its location [col. 8 L. 21-28, col. 14 L. 40-43, col. 15 L. 6-14]. This teaching means that the method comprises detecting a fault in a first device of the plurality of devices based, at least in part, on a location/distance of the fault and a type of the fault and determining which component of a plurality of components of the first device is faulty based, at least in part, on the type of fault and one or more signal signatures detected in at least the reflected SSTDR signal.
It would have been obvious to one of ordinary skill in the art, before the effective filing date of the claimed invention, to use Furse’s teachings of detecting faults in the devices coupled to the cable in the method taught by the combination because it will permit the system to let a user know that a device in the wellbore has a fault so it can be repaired or replaced.
In regards to claim 15, the combination of Pacault, Jeon, Kamata and Furse, as shown in the rejection of claim 8 above, further teaches the claimed limitations.
Claim(s) 16-18 is/are rejected under 35 U.S.C. 103 as being unpatentable over Pacault et al. (US-2005/0046591) in view of Kamata et al. (US-8,174,403) and Jeon et al. (US-10,338,124).
In regards to claim 16, Pacault teaches a system for hydrocarbon recovery comprising a well electrical cable and time domain reflectometry (TDR) coupled to the electrical cable and configured to transmit a TDR signal downhole via a well electrical cable of the well system and receive, from the well electrical cable, a reflected TDR signal associated with the transmitted TDR signal [fig. 19, par. 0052 L. 1-12].
Pacault teaches that a device can be coupled to the cable [fig. 19 element 200]. However, Pacault does not teach that a plurality of devices are coupled to the cable.
On the other hand, Kamata teaches that a plurality of devices can be coupled to the cable [fig. 2 element 107].
It would have been obvious to one of ordinary skill in the art, before the effective filing date of the claimed invention, to use Kamata’s teachings of having a plurality of devices coupled to the electrical cable in the system taught by Pacault because it will permit the system to sense different conditions at different depths within the wellbore.
The combination of Pacault and Kamata teaches that the system is used to detect a fault in the well electrical cable [fig. 19, par. 0052 L. 1-3]. However, Pacault does not teach that the transmitted signal and the received signal are spread spectrum time domain reflectometry (SSTDR) signals.
On the other hand, Jeon teaches that a fault in an electrical can be detected by transmitting a SSTDR signal and receiving a reflected STTDR signal associated with the transmitted SSTDR signal [col. 2 L. 35-42 and L. 65-67, col. 5 L. 58-64, col. 6 L. 5-11]. Furthermore, Jeon teaches that the method comprises determining whether a downhole fault is detected in the electrical cable based, at least in part, on a signal analysis of the reflected SSTDR signal and the transmitted SSTDR signal [col. 5 L. 62-67, col. 6 L. 63-67, col. 67 L. 1-10].
It would have been obvious to one of ordinary skill in the art, before the effective filing date of the claimed invention, to use Jeon’s teachings of using SSTDR for detecting a fault in the electrical cable in the system taught by the combination because it will permit the system to detect the fault with more accuracy.
In regards to claim 17, the combination of Pacault, Jeon and Kamata, as applied in the rejection of claim 16 above, further teaches that in response to detecting the downhole fault in the well electrical cable, determining a location of the detected downhole fault and a type of the downhole fault, wherein the location of the detected downhole fault includes a distance (depth downhole of the detected downhole fault) [see Jeon col. 6 L. 63-67, col. 7 L. 1-10, L. 25-34 and L. 43-52, col. 10 L. 20-25].
In regards to claim 18, the combination of Pacault, Jeon and Kamata, as applied in the rejection of claim 17 above, further teaches that the well electrical cable includes cable lines and downhole connectors [see Pacault fig. 4 elements 40 (connectors), fig. 19 elements 5a and 5b (cable lines), par. 0033 L. 2-6par. 0036 L. 1-6]. Also, the combination teaches that the system can detect the location and type of the fault in the cable [see Jeon col. 5 L. 62-64]. This teaching means that the method comprises determining whether the downhole fault is in a section of the cable lines or in at least one of the downhole connectors at least in part, on the depth downhole of the downhole fault and the type of the downhole fault.
Claim(s) 19 is/are rejected under 35 U.S.C. 103 as being unpatentable over Pacault et al. (US-2005/0046591) in view of Kamata et al. (US-8,174,403) and Jeon et al. (US-10,338,124) as applied to claim(s) 16 above, and further in view of Shier (US-11,815,560).
In regards to claim 19, the combination of Pacault, Kamata and Jeon, as applied in the rejection of claim 16 above, further teaches performing spread spectrum signal analysis on the reflected SSTDR signal and the transmitted SSTDR signal to determine real-time SSTDR data for the well system [see Jeon col. 5 L. 58-64]. The combination also teaches determining whether a downhole fault is detected based, at least in part, on the real-time SSTDR data.
The combination does not teach accessing historical SSTDR data for the well system; and determining whether a downhole fault is detected based, at least in part, on the historical SSTDR data for the well system.
On the other hand, Shier teaches that analysis to detect fault can also comprise accessing historical testing data for the system; and determining whether a fault is detected based, at least in part, on the historical testing data for the system [col. 11 L. 64-67, col. 12 L. 1-3 and L. 45-50].
It would have been obvious to one of ordinary skill in the art, before the effective filing date of the claimed invention, to use Shier’s teachings of using historical testing data to detect the fault  in the method taught by the combination because it will permit the system to detect the fault more accurately.
Claim(s) 20 is/are rejected under 35 U.S.C. 103 as being unpatentable over Pacault et al. (US-2005/0046591) in view of Kamata et al. (US-8,174,403) and Jeon et al. (US-10,338,124) as applied to claim(s) 16 above, and further in view of and Furse et al. (US-9,244,117).
In regards to claim 20, the combination of Pacault, Kamata and Jeon, as applied in the rejection of claim 16 above, teaches that a plurality of devices can be coupled to the cable [see Kamata fig. 2 element 107].
The combination of Pacault, Jeon and Kamata does not teach detecting a downhole fault in a first well device of the plurality of well devices based, at least in part, on a depth downhole of the downhole fault and a type of the downhole fault.
On the other hand, Furse teaches that a device from a plurality of devices coupled to the cable can be identified to have a fault in one of its components based on the type of fault and its location [col. 8 L. 21-28, col. 14 L. 40-43, col. 15 L. 6-14]. This teaching means that the method comprises detecting a fault in a first device of the plurality of devices based, at least in part, on a location/distance of the fault and a type of the fault and determining which component of a plurality of components of the first device is faulty based, at least in part, on the type of fault and one or more signal signatures detected in at least the reflected SSTDR signal.
It would have been obvious to one of ordinary skill in the art, before the effective filing date of the claimed invention, to use Furse’s teachings of detecting faults in the devices coupled to the cable in the system taught by the combination because it will permit the system to let a user know that a device in the wellbore has a fault so it can be repaired or replaced.
Conclusion


NEXT OFFICE ACTION: Notice of Allowance
Reasons for Allowance
The following is an examiner’s statement of reasons for allowance:
In regards to claims 1, 9 and 16, applicant’s arguments filed on January 21, 2025, with respect to claim(s) 1, 9 and 16 have been fully considered and are persuasive [see applicant’ arguments pg. 9 L. 7-30, pg. 10 L. 1-2].  Therefore the claim(s) is/are allowed.
Any comments considered necessary by applicant must be submitted no later than the payment of the issue fee and, to avoid processing delays, should preferably accompany the issue fee.  Such submissions should be clearly labeled “Comments on Statement of Reasons for Allowance.”
Conclusion

CITED REFERENCE SUMMARIES: Ref US10513920B2: Claims:
A method of performing a downhole operation in a wellbore, comprising: performing the downhole operation in the wellbore from a rig based on a stuck pipe risk, wherein the downhole operation includes at least one of: drilling the wellbore; tripping a drill string from or into the wellbore; reaming in or back reaming the wellbore; and running a casing or liner string into the wellbore; and while performing the downhole operation, repeatedly: inputting one or more predicted values from a model of the wellbore; inputting one or more measured parameters from one or more sensors of the rig; calculating a deviation of each input measured parameter from a respective predicted value; applying a first weighting factor to each calculated deviation to obtain a respective first alert level; calculating a rate of change of each input measured parameter from a parameter previously measured by the respective sensor; applying a second weighting factor to each calculated rate of change to obtain a respective second alert level; and adding the first and second alert levels and dividing a sum thereof by a maximum alert level to obtain the stuck pipe risk.
performing the downhole operation in the wellbore from a rig based on a stuck pipe risk, wherein the downhole operation includes at least one of: drilling the wellbore; tripping a drill string from or into the wellbore; reaming in or back reaming the wellbore; and running a casing or liner string into the wellbore; and
drilling the wellbore;
tripping a drill string from or into the wellbore;
reaming in or back reaming the wellbore; and
running a casing or liner string into the wellbore; and
while performing the downhole operation, repeatedly: inputting one or more predicted values from a model of the wellbore; inputting one or more measured parameters from one or more sensors of the rig; calculating a deviation of each input measured parameter from a respective predicted value; applying a first weighting factor to each calculated deviation to obtain a respective first alert level; calculating a rate of change of each input measured parameter from a parameter previously measured by the respective sensor; applying a second weighting factor to each calculated rate of change to obtain a respective second alert level; and adding the first and second alert levels and dividing a sum thereof by a maximum alert level to obtain the stuck pipe risk.
inputting one or more predicted values from a model of the wellbore;
inputting one or more measured parameters from one or more sensors of the rig;
calculating a deviation of each input measured parameter from a respective predicted value;
applying a first weighting factor to each calculated deviation to obtain a respective first alert level;
calculating a rate of change of each input measured parameter from a parameter previously measured by the respective sensor;
applying a second weighting factor to each calculated rate of change to obtain a respective second alert level; and
adding the first and second alert levels and dividing a sum thereof by a maximum alert level to obtain the stuck pipe risk.
The method of claim 1 , wherein: the method further comprises analyzing historical data from previously drilled wellbores to obtain one or more allowable deviations and one or more allowable rates of change, and the weighting factors are applied using the respective allowable deviations and allowable rates of change.
the method further comprises analyzing historical data from previously drilled wellbores to obtain one or more allowable deviations and one or more allowable rates of change, and
the weighting factors are applied using the respective allowable deviations and allowable rates of change.
The method of claim 2 , wherein: each of the allowable deviations range between an absolute value of 2-25%, and each of the allowable rates of change range between an absolute value of 2-25%.
each of the allowable deviations range between an absolute value of 2-25%, and
each of the allowable rates of change range between an absolute value of 2-25%.
The method of claim 2 , wherein: the measured parameters and the previously measured parameters comprise hook load and standpipe pressure, each of the allowable deviations and allowable rates of change for hook load are negative, and each of the allowable deviations and allowable rates of change for standpipe pressure are positive.
the measured parameters and the previously measured parameters comprise hook load and standpipe pressure,
each of the allowable deviations and allowable rates of change for hook load are negative, and
each of the allowable deviations and allowable rates of change for standpipe pressure are positive.
The method of claim 2 , wherein: the historical data is further analyzed to obtain a risk threshold, and the method further comprises: comparing the stuck pipe risk to the risk threshold; and alerting a driller if the stuck pipe risk exceeds the risk threshold.
the historical data is further analyzed to obtain a risk threshold, and
the method further comprises: comparing the stuck pipe risk to the risk threshold; and alerting a driller if the stuck pipe risk exceeds the risk threshold.
comparing the stuck pipe risk to the risk threshold; and
alerting a driller if the stuck pipe risk exceeds the risk threshold.
The method of claim 1 , wherein: the method further comprises averaging each calculated deviation with respective previously calculated deviations in a current sample window; each first weighting factor is applied to the respective average calculated deviation.
the method further comprises averaging each calculated deviation with respective previously calculated deviations in a current sample window;
each first weighting factor is applied to the respective average calculated deviation.
The method of claim 6 , wherein: each previously measured parameter is an average of respective previously measured parameters in a previous sample window, the method further comprises averaging each measured parameter with respective previously measured parameters in the current sample window, and each rate of change is calculated using the respective averages of the respective measured parameters in the sample windows.
each previously measured parameter is an average of respective previously measured parameters in a previous sample window,
the method further comprises averaging each measured parameter with respective previously measured parameters in the current sample window, and
each rate of change is calculated using the respective averages of the respective measured parameters in the sample windows.
The method of claim 1 , further comprising displaying a plot of the stuck pipe risk on a driller's console.
The method of claim 1 , further comprising interpolating the predicted values to a current depth of the downhole operation.
The method of claim 1 , wherein: the rig is a drilling rig, and the downhole operation is drilling the wellbore.
the rig is a drilling rig, and
the downhole operation is drilling the wellbore.
The method of claim 10 , wherein: the downhole operation is slide drilling, and the measured parameters comprise hook load and standpipe pressure.
the downhole operation is slide drilling, and
the measured parameters comprise hook load and standpipe pressure.
The method of claim 10 , wherein: the downhole operation is rotary drilling, and the measured parameters comprise hook load, torque, and standpipe pressure.
the downhole operation is rotary drilling, and
the measured parameters comprise hook load, torque, and standpipe pressure.
The method of claim 1 , wherein: the rig is a drilling rig, the downhole operation is tripping a drill string from or into the wellbore, and the measured parameters comprise hook load.
the rig is a drilling rig,
the downhole operation is tripping a drill string from or into the wellbore, and
the measured parameters comprise hook load.
The method of claim 1 , wherein: the rig is a drilling rig, and the downhole operation is reaming in or back reaming the wellbore, and the measured parameters comprise hook load, torque, and standpipe pressure.
the downhole operation is reaming in or back reaming the wellbore, and
The method of claim 1 , wherein: the rig is a drilling rig, and the downhole operation is running a casing or liner string into the wellbore.
the downhole operation is running a casing or liner string into the wellbore.
The method of claim 1 , further comprising calculating the one or more predicted values for the model from the one or more measured parameters.
The method of claim 2 , further comprising modifying the one or more rates of change to account for changes in rotation speed, flow rate, or revolutions per minute during the downhole operation.
The method of claim 1 , wherein the operation further comprises performing a remedial action based on the stuck pipe risk.
The method of claim 2 , further comprising: a deviation ratio is calculated to apply the first weighting factor to each calculated deviation to obtain the respective first alert level; a rate of change ratio is calculated to apply the second weighting factor to each calculated rate of change to obtain the respective second alert level; and each respective first alert level is assigned a first alert level value, wherein: the first alert level value is 0 if the deviation ratio is less than 1; the first alert level value is equal to the deviation ratio if the deviation ratio is greater than or equal to 1 and less than or equal to 3; and the first alert level is 3 if the deviation ratio is greater than 3; each respective second alert level is assigned a second alert level value, wherein: the second alert level value is 0 if the rate of change ratio is less than 1; the second alert level value is equal to the rate of change ratio if the rate of change ratio is greater than or equal to 1 and less than or equal to 3; the second alert level is 3 if the rate of change ratio is greater than 3.
a deviation ratio is calculated to apply the first weighting factor to each calculated deviation to obtain the respective first alert level;
a rate of change ratio is calculated to apply the second weighting factor to each calculated rate of change to obtain the respective second alert level; and
each respective first alert level is assigned a first alert level value, wherein: the first alert level value is 0 if the deviation ratio is less than 1; the first alert level value is equal to the deviation ratio if the deviation ratio is greater than or equal to 1 and less than or equal to 3; and the first alert level is 3 if the deviation ratio is greater than 3;
the first alert level value is 0 if the deviation ratio is less than 1;
the first alert level value is equal to the deviation ratio if the deviation ratio is greater than or equal to 1 and less than or equal to 3; and
the first alert level is 3 if the deviation ratio is greater than 3;
each respective second alert level is assigned a second alert level value, wherein: the second alert level value is 0 if the rate of change ratio is less than 1; the second alert level value is equal to the rate of change ratio if the rate of change ratio is greater than or equal to 1 and less than or equal to 3; the second alert level is 3 if the rate of change ratio is greater than 3.
the second alert level value is 0 if the rate of change ratio is less than 1;
the second alert level value is equal to the rate of change ratio if the rate of change ratio is greater than or equal to 1 and less than or equal to 3;
the second alert level is 3 if the rate of change ratio is greater than 3.
A method of performing an operation in a wellbore from a rig, comprising: performing the operation in the wellbore from the rig based on a stuck pipe risk, wherein the operation includes at least one of: drilling the wellbore; tripping a drill string from or into the wellbore; reaming in or back reaming the wellbore; and running a casing or liner string into the wellbore; and while performing the operation, repeatedly: measuring one or more parameters using one or more sensors of the rig; obtaining one or more predicted values from a model of the wellbore; calculating a deviation of each measured parameter from a respective predicted value; applying a first weighting factor to each calculated deviation to obtain a respective first alert level; calculating a rate of change of each measured parameter from a parameter previously measured by the respective sensor; applying a second weighting factor to each calculated rate of change to obtain a respective second alert level; and adding the first and second alert levels and dividing a sum thereof by a maximum alert level to obtain the stuck pipe risk.
performing the operation in the wellbore from the rig based on a stuck pipe risk, wherein the operation includes at least one of: drilling the wellbore; tripping a drill string from or into the wellbore; reaming in or back reaming the wellbore; and running a casing or liner string into the wellbore; and
while performing the operation, repeatedly: measuring one or more parameters using one or more sensors of the rig; obtaining one or more predicted values from a model of the wellbore; calculating a deviation of each measured parameter from a respective predicted value; applying a first weighting factor to each calculated deviation to obtain a respective first alert level; calculating a rate of change of each measured parameter from a parameter previously measured by the respective sensor; applying a second weighting factor to each calculated rate of change to obtain a respective second alert level; and adding the first and second alert levels and dividing a sum thereof by a maximum alert level to obtain the stuck pipe risk.
measuring one or more parameters using one or more sensors of the rig;
obtaining one or more predicted values from a model of the wellbore;
calculating a deviation of each measured parameter from a respective predicted value;
calculating a rate of change of each measured parameter from a parameter previously measured by the respective sensor;
A drilling system, comprising: a rig operable to perform an operation in a wellbore, the rig including one or more sensors operable to monitor at least one measured parameter selected from the group of: standpipe pressure, hook load, and torque of a top drive; and a programmable logic controller (PLC) in communication with the one or more sensors, wherein the PLC is configured to control the operation based on a stuck pipe risk by: inputting one or more predicted values from a model of the wellbore; inputting one or more of the measured parameters from the one or more sensors of the rig; calculating a deviation of each input measured parameter from a respective predicted value; applying a first weighting factor to each calculated deviation to obtain a respective first alert level; calculating a rate of change of each input measured parameter from a parameter previously measured by the respective sensor; applying a second weighting factor to each calculated rate of change to obtain a respective second alert level; and adding the first and second alert levels and dividing a sum thereof by a maximum alert level to obtain the stuck pipe risk.
a rig operable to perform an operation in a wellbore, the rig including one or more sensors operable to monitor at least one measured parameter selected from the group of: standpipe pressure, hook load, and torque of a top drive; and
a programmable logic controller (PLC) in communication with the one or more sensors, wherein the PLC is configured to control the operation based on a stuck pipe risk by: inputting one or more predicted values from a model of the wellbore; inputting one or more of the measured parameters from the one or more sensors of the rig; calculating a deviation of each input measured parameter from a respective predicted value; applying a first weighting factor to each calculated deviation to obtain a respective first alert level; calculating a rate of change of each input measured parameter from a parameter previously measured by the respective sensor; applying a second weighting factor to each calculated rate of change to obtain a respective second alert level; and adding the first and second alert levels and dividing a sum thereof by a maximum alert level to obtain the stuck pipe risk.
inputting one or more of the measured parameters from the one or more sensors of the rig;
Ref US20050046591A1: Claims:
A method for performing diagnostics on a wired drill pipe telemetry system of a downhole drilling system, comprising: a) passing a signal through a plurality of drill pipe in the wired drill pipe telemetry system; b) receiving the signal from the wired drill pipe telemetry system; c) measuring parameters of the received signal; and d) comparing the received signal parameters against a known reference for variation thereof whereby a fault in the wired drill pipe telemetry system is identified.
a) passing a signal through a plurality of drill pipe in the wired drill pipe telemetry system;
b) receiving the signal from the wired drill pipe telemetry system;
c) measuring parameters of the received signal; and
d) comparing the received signal parameters against a known reference for variation thereof whereby a fault in the wired drill pipe telemetry system is identified.
The method of claim 1 wherein one of the location, type, existence and combinations thereof of the fault is identified.
The method of claim 1 wherein the signal is a waveform.
The method of claim 3 wherein the signal is one of sinusoid, sweep, and combinations thereof.
The method of claim 1 wherein the step of measuring comprises measuring one of the voltage, the current and combinations thereof of the received signal.
The method of claim 5 further comprising determining the impedance of the received signal.
The method of claim 6 wherein step c) comprises comparing the determined impedance against a known reference to identify at least one resonance therein whereby a fault in the wired drill pipe telemetry system is identified.
The method of claim 7 further comprising determining the location of the fault by comparing the determined impedance with an iterative impedance of the known reference.
The method of claim 1 wherein the signal is a pulse.
The method of claim 1 wherein the received signal is received a time delay after passing the signal.
The method of claim 10 wherein step b) comprises measuring one of the time delay, the amplitude, phase and combinations thereof of the received signal.
The method of claim 10 wherein step c) comprises comparing characteristics of the time delay of the received signal against the time delay of a known reference to identify a reflection therein whereby the fault is identified.
The method of claim 1 further comprising removing at least one of the plurality of wired drill pipe and repeating steps a) d).
A method for performing diagnostics on a wired drill pipe telemetry system of a downhole drilling system having a plurality of wired drill pipes, comprising the following steps: passing a signal through the wired drill pipe telemetry system; receiving the signal from the wired drill pipe telemetry system; measuring one of a voltage, a current and combination thereof of the received signal; determining the impedance of the received signal; and comparing the impedance of the received signal with the impedance of a known reference to identify a variation therefrom whereby a fault in the wired drill pipe telemetry system is identified.
passing a signal through the wired drill pipe telemetry system;
receiving the signal from the wired drill pipe telemetry system;
measuring one of a voltage, a current and combination thereof of the received signal;
determining the impedance of the received signal; and
comparing the impedance of the received signal with the impedanc
[Truncated to input limit]