DETAILED ACTION
In response to remarks filed on 12 March 2026
Continued Examination Under 37 CFR 1.114
A request for continued examination under 37 CFR 1.114, including the fee set forth in 37 CFR 1.17(e), was filed in this application after final rejection. Since this application is eligible for continued examination under 37 CFR 1.114, and the fee set forth in 37 CFR 1.17(e) has been timely paid, the finality of the previous Office action has been withdrawn pursuant to 37 CFR 1.114. Applicant's submission filed on 12 March 2026 has been entered.
Status of Claims
Claims 1-20 are pending;
Claims 1, 3, 10 and 15 are currently amended;
Claims 2, 4-9, 11-14 and 16-20 were previously presented;
Claims 1-20 are rejected herein.
Response to Arguments
Applicant’s arguments filed on 12 March 2026 have been fully considered and they are moot since a new secondary reference is being incorporated to the previous combination of references to address the new limitations and a new rejection rearranging the references have been incorporated in view of the new limitations.
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.
Claims 1-3, 5 and 7-20 is/are rejected under 35 U.S.C. 103 as being unpatentable over Sanmartin et al (U.S. Patent Application Publication No. 2016/0187523) in view of Nichols et al (U.S. Patent Application Publication No. 2016/0070018) and Nichols (U.S. Patent No. 6,534,986) “Nichols 986”.
As to Claim 1, Sanmartin discloses a system, comprising:
A control system (120) disposed on a well surface, within a well environment;
A pipe component (108) disposed in a wellbore (104), within a well environment;
A first corrosion recorder (Paragraph 0023: “Embodiments of the present disclosure describe exemplary pipe inspection tools that can improve tool resolution and enhance the identification of corrosion in wellbore pipes being monitored”) coupled to the pipe component, the first corrosion recorder comprising:
A first magnetic field transmitter (702a),
A first magnetic field receiver (706 immediately below 702a),
Wherein the first magnetic field transmitter and the first magnetic field receiver are configured to generate first corrosion sensor data (Paragraph 0061: “The receiver grids 706 may be configured to sense the magnetic fields generated by the transmitter coils 702a-d and provide feedback to a data acquisition and control unit 708”), and
A first communication interface (Line between 706 immediately below 702a and 708 in Figure 7);
A second corrosion recorder (Paragraph 0023: “Embodiments of the present disclosure describe exemplary pipe inspection tools that can improve tool resolution and enhance the identification of corrosion in wellbore pipes being monitored”) coupled to the pipe component, the second corrosion recorder comprising:
A second magnetic field transmitter (702c),
A second magnetic field receiver (706 immediately below 702c),
Wherein the second magnetic field transmitter and the second magnetic field receiver are configured to generate second corrosion sensor data (Paragraph 0061: “The receiver grids 706 may be configured to sense the magnetic fields generated by the transmitter coils 702a-d and provide feedback to a data acquisition and control unit 708”), and
A second communication interface (Line between 706 immediately below 702c and 708 in Figure 7);
A cable (116) disposed in the wellbore and coupled to the control system, the first corrosion recorder, and the second corrosion recorder,
Wherein the first corrosion recorder is configured to transmit the first corrosion sensor data to the control system using the first communication interface (Line between 706 immediately below 702a and 708 in Figure 7), and
Wherein the second corrosion recorder is configured to transmit the second corrosion sensor data to the control system using the second communication interface (Line between 706 immediately below 702c and 708 in Figure 7),
Wherein the first corrosion recorder and the second corrosion recorder are separated (Figure 7) by a predetermined distance within the wellbore (104).
However, Sanmartin is silent about wherein the first corrosion recorder is configured to transmit, over an optical fiber cable, the first corrosion sensor data to the control system and wherein the second corrosion recorder is configured to transmit, over the optical fiber cable, the second corrosion sensor data to the control system. Nichols discloses a first corrosion recorder (40) and second corrosion recorder (46) each configured to transmit over an optical fiber cable (28) to a control system (30). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to make the first corrosion recorder configured to transmit, over the optical fiber cable, the first corrosion sensor data to the control system and make the second corrosion recorder configured to transmit, over the optical fiber cable, the second corrosion sensor data to the control system. The motivation would have been to transmit information to the surface for analysis.
Lastly, Sanmartin as modified (see above paragraph) is silent about wherein the first corrosion recorder and the second corrosion recorder are permanently installed in the wellbore during production operations and are configured to continuously monitor corrosion of the pipe component over a life of the well. Nichols 986 discloses a first recorder comprising a first magnetic transmitter (66) and first magnetic receiver (70) and a second recorder comprising a second magnetic transmitter (68) and second magnetic receiver (72), all of which are permanently installed in a wellbore (12a) during production operations and are configured to continuously monitor over a life of the well (Column 14, Lines 12-14: “This leads to another advantage of having the transmitters/receivers wound on the casing and permanently deployed: there is no practical limit on the time that the signals can be averaged”). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to have the first corrosion recorder and the second corrosion recorder are permanently installed in the wellbore during production operations and are configured to continuously monitor corrosion of the pipe component over a life of the well. The motivation would have been to save costs by avoiding repeated removal and insertion of the recorders (Nichols 986 - Column 5, Lines 43-53: “Measurements with the aforementioned method are difficult to perform once production from the well has begun and production tubing has been run from the surface to the producing zone. The production tubing leaves little or no room for the electromagnetic measurement system to move in the well. Repeated measurements to monitor production or enhanced recovery processes as a result require repeated removal and reinsertion of the production tubing. This is a costly operation, and it is clear that a permanent monitoring system, on the outside of the casing, would be more cost effective”).
As to Claim 2, Sanmartin as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Sanmartin as modified also teaches wherein the first corrosion recorder further comprises a processor (708), a memory (708), and a fiber optic connector configured to couple to the optical fiber cable (116), wherein the first corrosion recorder is configured to receive, over the optical fiber cable (116), a request to acquire the first corrosion sensor data, and wherein the memory (708) is configured to store the first corrosion sensor data until the first corrosion sensor data is transmitted to the control system.
As to Claim 3, Sanmartin as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Sanmartin as modified also teaches wherein the first corrosion recorder comprises a mount fixture (708) configured to permanently couple the first corrosion recorder to the pipe component.
As to Claim 5, Sanmartin as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Sanmartin as modified also teaches wherein the pipe component (108) is a casing.
As to Claim 7, Sanmartin as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Sanmartin as modified also teaches wherein the control system (120) is configured to determine a wall thickness (Paragraph 0074: “Example characteristics of wellbore pipes that may be determined using the inversion method 1200 include, but are not limited to, the number of wellbore pipes in a wellbore, the dimensions (i.e., diameter, wall thickness, etc.) of the wellbore pipes, the presence of a defect (e.g., corrosion, fractures, holes, and decreased wall thickness) in the wellbore pipes, and/or the presence of a conductive or magnetically-permeable feature in the wellbore pipes”) of a predetermined section of the pipe component (108) using the first corrosion sensor data and the second corrosion sensor data; determine whether the wall thickness of the predetermined section satisfies a predetermined criterion; and terminate, in response to determining that the predetermined section fails to satisfy the predetermined criterion, a production operation at the wellbore (Paragraph 0080: “By detecting and estimating the size of smaller defects, predictions that are more accurate can be performed on the useful lifetime of the wellbore pipes or a decision can be made for replacing the flawed sections”).
As to Claim 8, Sanmartin as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Sanmartin as modified also teaches wherein the first corrosion recorder (702a and 706 immediately below 702a) is configured to obtain a command to generate the first corrosion sensor data; and generate, in response to obtaining the command, the first corrosion sensor data using the first magnetic field receiver (706) and the first magnetic field transmitter (702a).
As to Claim 9, Sanmartin as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Sanmartin as modified also teaches wherein the control system (120) is configured to transmit, over the optical fiber cable (116), a first command to the first corrosion recorder (702a and 706 immediately below 702a); and transmit, over the optical fiber cable (116), a second command to the second corrosion recorder (702c and 706 immediately below 702c), wherein the first corrosion sensor data is generated in response to the first corrosion recorder obtaining the first command, and wherein the second corrosion sensor data is generated in response to the second corrosion recorder obtaining the second command (Paragraph 0059: “As illustrated, the electromagnetic sensor 700 may include multiple transmitter coils 702 (shown as transmitter coils 702a, 702b, 702c, and 702d) independently powered by corresponding power sources 208a, 208b, 208c, and 208d, respectively”).
As to Claim 10, Sanmartin discloses an apparatus, comprising:
A magnetic field transmitter (702a-d);
A magnetic field receiver (706);
A cable connector (Line between 706 and 708) configured to couple to a cable (116);
A communication interface (708) coupled to the cable connector;
A processor (120) coupled to the magnetic field transmitter, the magnetic field receiver, and the communication interface; and
A memory (122) coupled to the processor, wherein the memory comprises instructions configured to perform a method comprising:
Obtain a command to generate corrosion sensor data (Paragraph 0023: “Embodiments of the present disclosure describe exemplary pipe inspection tools that can improve tool resolution and enhance the identification of corrosion in wellbore pipes being monitored”),
Generate the corrosion sensor data using the magnetic field receiver (706) and the magnetic field transmitter (702a-d), and
Transmit the corrosion sensor data over the cable (116) using the communication interface (708).
However, Sanmartin is silent about the magnetic field transmitter and the magnetic field receiver being within a sealed case and obtaining, over an optical fiber cable, corrosion sensor data generated by the magnetic field transmitter and the magnetic field receiver. Nichols discloses a sealed case (26) with a magnetic field transmitter (40) and a magnetic field receiver (42) therewithin and obtaining, over an optical fiber cable (28), corrosion sensor data generated by the magnetic field transmitter and the magnetic field receiver. Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to provide a sealed case and to have the magnetic field transmitter and the magnetic field receiver being within the sealed case and obtaining, over an optical fiber cable, corrosion sensor data generated by the magnetic field transmitter and the magnetic field receiver. The motivation would have been to protect the equipment and to transmit information to the surface for analysis.
Lastly, Sanmartin as modified (see above paragraph) is silent about wherein the magnetic field transmitter and the magnetic field receiver permanently installed in the wellbore during production operations and configured to continuously monitor pipe corrosion over a life of a well. Nichols 986 discloses a first recorder comprising a first magnetic transmitter (66) and first magnetic receiver (70) and a second recorder comprising a second magnetic transmitter (68) and second magnetic receiver (72), all of which are permanently installed in a wellbore (12a) during production operations and are configured to continuously monitor over a life of the well (Column 14, Lines 12-14: “This leads to another advantage of having the transmitters/receivers wound on the casing and permanently deployed: there is no practical limit on the time that the signals can be averaged”). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to have the magnetic field transmitter and the magnetic field receiver permanently installed in the wellbore during production operations and configured to continuously monitor pipe corrosion over a life of a well. The motivation would have been to save costs by avoiding repeated removal and insertion of the recorders (Nichols 986 - Column 5, Lines 43-53: “Measurements with the aforementioned method are difficult to perform once production from the well has begun and production tubing has been run from the surface to the producing zone. The production tubing leaves little or no room for the electromagnetic measurement system to move in the well. Repeated measurements to monitor production or enhanced recovery processes as a result require repeated removal and reinsertion of the production tubing. This is a costly operation, and it is clear that a permanent monitoring system, on the outside of the casing, would be more cost effective”).
As to Claim 11, Sanmartin as modified teaches the invention of Claim 10 (Refer to Claim 10 discussion). Sanmartin as modified also teaches wherein the magnetic field transmitter (702a-d) is configured to transmit magnetic flux waves through a ferromagnetic material to cause a magnetic field; wherein the magnetic field receiver (706) is configured to detect a flux leakage caused by a defect in the ferromagnetic material.
As to Claim 12, Sanmartin as modified teaches the invention of Claim 10 (Refer to Claim 10 discussion). Sanmartin as modified also teaches further comprising a processor (120) coupled to the communication interface, wherein the communication interface is configured to transmit the corrosion sensor data regarding a corrosion region of interest to a control system.
As to Claim 13, Sanmartin as modified teaches the invention of Claim 10 (Refer to Claim 10 discussion). Sanmartin as modified also teaches wherein the memory (122) is configured to store the corrosion sensor data.
As to Claim 14, Sanmartin as modified teaches the invention of Claim 10 (Refer to Claim 10 discussion). Sanmartin as modified also teaches wherein the method further comprises recording the corrosion sensor data after the apparatus (14) receives a command to start to determine the corrosion sensor data; wherein the method further comprises generating a corrosion log (at 1210) using the corrosion sensor data; wherein the method further comprises transmitting, using an optical fiber cable (116) connected to the fiber optic connector (Line between 706 and 708), and the communication interface (708), the corrosion log to a control system.
As to Claim 15, Sanmartin discloses a method, comprising:
Transmitting, by a control system (120), a first command to a first corrosion recorder (702a and 706 immediately below 702a) in a wellbore (104);
Transmitting, by the control system (120), a second command to a second corrosion recorder (702c and 706 immediately below 702c) in the wellbore (104),
Wherein the first corrosion recorder (702a and 706 immediately below 702a) and the second corrosion recorder (702c and 706 immediately below 702c) are separated by a predetermined distance within the wellbore (104);
Obtaining, by the control system (122) in response to transmitting the first command, first corrosion sensor data from the first corrosion recorder (Paragraph 0023: “Embodiments of the present disclosure describe exemplary pipe inspection tools that can improve tool resolution and enhance the identification of corrosion in wellbore pipes being monitored”); and
Obtaining, by the control system (122) in response to transmitting the second command, second corrosion sensor data from the second corrosion recorder (Paragraph 0023: “Embodiments of the present disclosure describe exemplary pipe inspection tools that can improve tool resolution and enhance the identification of corrosion in wellbore pipes being monitored”),
Wherein the first corrosion sensor data and the second corrosion sensor data are generated using a plurality of magnetic field receivers (702a, 702c) and a plurality of magnetic field transmitters (706), and
Wherein the first corrosion sensor data describes a first portion of a pipe component (Portion of 108 next to 702a) disposed in the wellbore (104), and
Wherein the second corrosion sensor data describes a second portion of the pipe component (Portion of 108 next to 702c) that is different from the first portion.
However, Sanmartin is silent about transmitting the first and second commands to the first and second corrosion recorders, respectively, over an optical fiber cable, and obtaining the first and second corrosion sensor data from the first and second corrosion recorders, respectively, over the optical fiber cable. Nichols discloses transmitting first and second commands to a first and second corrosion recorder (40 and 42; 44 and 46), respectively, over an optical fiber cable (28), and obtaining first and second corrosion sensor data from the first and second corrosion recorders (40 and 42; 44 and 46), respectively, over the optical fiber cable (28). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to transmit the first and second commands to the first and second corrosion recorders, respectively, over an optical fiber cable, and obtain the first and second corrosion sensor data from the first and second corrosion recorders, respectively, over the optical fiber cable. The motivation would have been to transmit information to the surface for analysis and transmit signals downhole for control.
Lastly, Sanmartin as modified (see above paragraph) is silent about wherein the first corrosion recorder and the second corrosion recorder are permanently installed in the wellbore during production operations and are configured to continuously monitor corrosion of the pipe component over a life of the well. Nichols 986 discloses a first recorder comprising a first magnetic transmitter (66) and first magnetic receiver (70) and a second recorder comprising a second magnetic transmitter (68) and second magnetic receiver (72), all of which are permanently installed in a wellbore (12a) during production operations and are configured to continuously monitor over a life of the well (Column 14, Lines 12-14: “This leads to another advantage of having the transmitters/receivers wound on the casing and permanently deployed: there is no practical limit on the time that the signals can be averaged”). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to have the first corrosion recorder and the second corrosion recorder are permanently installed in the wellbore during production operations and are configured to continuously monitor corrosion of the pipe component over a life of the well. The motivation would have been to save costs by avoiding repeated removal and insertion of the recorders (Nichols 986 - Column 5, Lines 43-53: “Measurements with the aforementioned method are difficult to perform once production from the well has begun and production tubing has been run from the surface to the producing zone. The production tubing leaves little or no room for the electromagnetic measurement system to move in the well. Repeated measurements to monitor production or enhanced recovery processes as a result require repeated removal and reinsertion of the production tubing. This is a costly operation, and it is clear that a permanent monitoring system, on the outside of the casing, would be more cost effective”).
As to Claim 16, Sanmartin as modified teaches the invention of Claim 15 (Refer to Claim 15 discussion). Sanmartin as modified also teaches further comprising performing a well simulation of the wellbore (104) of one or more wells for a first depth interval using the first corrosion sensor data, pipe thickness data, and pipe parameters; and determining a predicted pipe replacement date for the one or more wells using the well simulation (Paragraph 0075: “According to the method 1200, a first numerical inversion operation 1206 may be applied first to obtain shallow mode measurement data 1202. Performing the first numerical inversion operation 1206 may include using forward modelling 1208 and/or a library 1210. Forward modelling 1208 (and 1216 below) provides simulated responses for any given set of pipe configurations or defects and it can be used to determine the thickness of pipes for a given set of signals. Specifically, input to forward modelling 1208, 1216 is the pipe thicknesses, pipe magnetic permeability, pipe conductivity, pipe geometry including any defects, coil geometry (i.e., position, length, radius), core geometry and material. Output to forward modelling 1208, 1216 is simulated receiver signals at the receiver coils”).
As to Claim 17, Sanmartin as modified teaches the invention of Claim 15 (Refer to Claim 15 discussion). Sanmartin as modified also teaches further comprising: performing a well simulation of the wellbore (104) of one or more wells for a second depth interval using the second corrosion sensor data, pipe thickness data, and pipe parameters; and determining a predicted pipe replacement date for the one or more wells using the well simulation (Paragraph 0075: “According to the method 1200, a first numerical inversion operation 1206 may be applied first to obtain shallow mode measurement data 1202. Performing the first numerical inversion operation 1206 may include using forward modelling 1208 and/or a library 1210. Forward modelling 1208 (and 1216 below) provides simulated responses for any given set of pipe configurations or defects and it can be used to determine the thickness of pipes for a given set of signals. Specifically, input to forward modelling 1208, 1216 is the pipe thicknesses, pipe magnetic permeability, pipe conductivity, pipe geometry including any defects, coil geometry (i.e., position, length, radius), core geometry and material. Output to forward modelling 1208, 1216 is simulated receiver signals at the receiver coils”).
As to Claim 18, Sanmartin as modified teaches the invention of Claim 15 (Refer to Claim 15 discussion). Sanmartin as modified also teaches wherein the control system adjusts one or more production parameters of a production operation at the wellbore (104) based on the first corrosion sensor data, pipe thickness data, and/or well simulations of the wellbore of one or more wells at the first portion of the pipe component (Paragraph 0080: “By detecting and estimating the size of smaller defects, predictions that are more accurate can be performed on the useful lifetime of the wellbore pipes or a decision can be made for replacing the flawed sections”).
As to Claim 19, Sanmartin as modified teaches the invention of Claim 15 (Refer to Claim 15 discussion). Sanmartin as modified also teaches further comprising performing a pipe replacement operation based on a well simulation, using the first corrosion sensor data, pipe thickness data, pipe parameters, at a first depth interval of the wellbore (104) of one or more wells (Paragraph 0080: “By detecting and estimating the size of smaller defects, predictions that are more accurate can be performed on the useful lifetime of the wellbore pipes or a decision can be made for replacing the flawed sections”).
As to Claim 20, Sanmartin as modified teaches the invention of Claim 15 (Refer to Claim 15 discussion). Sanmartin as modified also teaches further comprising performing a pipe replacement operation based on a well simulation, using the second corrosion sensor data, pipe thickness data, pipe parameters, at a second depth interval of the wellbore (104) of one or more wells (Paragraph 0080: “By detecting and estimating the size of smaller defects, predictions that are more accurate can be performed on the useful lifetime of the wellbore pipes or a decision can be made for replacing the flawed sections”).
Claims 4 and 6 is/are rejected under 35 U.S.C. 103 as being unpatentable over Sanmartin et al (U.S. Patent Application Publication No. 2016/0187523) in view of Nichols et al (U.S. Patent Application Publication No. 2016/0070018) and Nichols (U.S. Patent No. 6,534,986) “Nichols 986”; and further in view of Newman (U.S. Patent No. 6,003,597).
As to Claim 4, Sanmartin as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Sanmartin as modified also teaches wherein the control system is configured to generate a corrosion log (at 1210) of the wellbore (104) using the first corrosion sensor data and the second corrosion sensor data, and wherein the first corrosion recorder corresponds to a first depth interval in the corrosion log and the second corrosion recorder corresponds to a second depth interval in the corrosion log. However, Sanmartin as modified is silent about wherein the wellbore comprises a packer disposed between the first corrosion recorder and the second corrosion recorder. Newman discloses the placement of a packer (72) between a pair of recorders (Upper 10, Lower 10). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to provide the wellbore with a packer disposed between the first corrosion recorder and the second corrosion recorder. The motivation would have been to better anchor the apparatus to the walls of the wellbore.
As to Claim 6, Sanmartin as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). However, Sanmartin as modified is silent about a feed-through packer disposed in a first section of the wellbore, wherein the feed-through packer is configured to: seal on a wall of the wellbore and a wall of the pipe component, and allow feeding through the optical fiber cable from the first section of the wellbore to a second section of the wellbore. Newman discloses a feed-through packer (72) disposed in a first section of the wellbore, wherein the feed-through packer is configured to seal on a wall (70) of the wellbore and a wall (12”) of a pipe component, and allow feeding through the optical fiber cable (Cable within 12”) from the first section of the wellbore (Portion above 72) to a second section (Portion below 72) of the wellbore. Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to provide a feed-through packer disposed in a first section of the wellbore, wherein the feed-through packer is configured to: seal on a wall of the wellbore and a wall of the pipe component, and allow feeding through the optical fiber cable from the first section of the wellbore to a second section of the wellbore. The motivation would have been to better anchor the apparatus to the walls of the wellbore.
Claims 1-3, 5, 8-13 and 15 is/are rejected under 35 U.S.C. 103 as being unpatentable over Nichols (U.S. Patent No. 6,534,986) “Nichols 986” in view of Sanmartin et al (U.S. Patent Application Publication No. 2016/0187523) and Nichols et al (U.S. Patent Application Publication No. 2016/0070018).
As to Claim 1, Nichols 986 discloses a system comprising:
A control system (22) disposed on a well surface within a well environment;
A pipe component (16a) disposed in a wellbore (12a) within the well environment;
A first recorder (66, 70) coupled to the pipe component, the first recorder comprising:
A first magnetic field transmitter (66),
A first magnetic field receiver (70), wherein the first magnetic field transmitter (66) and the first magnetic field receiver (70) are configured to generate first sensor data, and
A first communication interface (Connections between 66/70 and 21; Column 8, Lines 20-23: “The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith”);
A second recorder (68, 72) coupled to the pipe component, the second recorder comprising:
A second magnetic field transmitter (68),
A second magnetic field receiver (72), wherein the second magnetic field transmitter (68) and the second magnetic field receiver (72) are configured to generate second sensor data, and
A second communication interface (Connections between 68/72 and 21; Column 8, Lines 20-23: “The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith”);
A cable (21) disposed in the wellbore and coupled to the control system (12), the first recorder, and the second recorder Column 8, Lines 20-23: “The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith”),
Wherein the first recorder (66, 70) is configured to transmit, over the cable (21), the first sensor data to the control system using the first communication interface (Column 8, Lines 20-23: “The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith”), and
Wherein the second recorder (68, 72) is configured to transmit, over the cable (21), the second sensor data to the control system using the second communication interface (Column 8, Lines 20-23: “The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith”),
Wherein the first recorder (66, 70) and the second recorder (68, 72) are separated by a predetermined distance within the wellbore (Figure 4),
Wherein the first recorder and the second recorder are permanently installed in the wellbore during production operations and are configured to continuously monitor the pipe component over a life of the well (Column 14, Lines 12-14: “This leads to another advantage of having the transmitters/receivers wound on the casing and permanently deployed: there is no practical limit on the time that the signals can be averaged”).
However, Nichols 986 is silent about the first recorder being a first corrosion recorder and the second recorder being a second corrosion recorder. Sanmartin discloses a first corrosion recorder (Paragraph 0023: “Embodiments of the present disclosure describe exemplary pipe inspection tools that can improve tool resolution and enhance the identification of corrosion in wellbore pipes being monitored”) coupled to a pipe component, the first corrosion recorder comprising a first magnetic field transmitter (702a), a first magnetic field receiver (706 immediately below 702a), wherein the first magnetic field transmitter and the first magnetic field receiver are configured to generate first corrosion sensor data (Paragraph 0061: “The receiver grids 706 may be configured to sense the magnetic fields generated by the transmitter coils 702a-d and provide feedback to a data acquisition and control unit 708”), and a first communication interface (Line between 706 immediately below 702a and 708 in Figure 7). Sanmartin also discloses a second corrosion recorder (Paragraph 0023: “Embodiments of the present disclosure describe exemplary pipe inspection tools that can improve tool resolution and enhance the identification of corrosion in wellbore pipes being monitored”) coupled to the pipe component, the second corrosion recorder comprising a second magnetic field transmitter (702c), a second magnetic field receiver (706 immediately below 702c), wherein the second magnetic field transmitter and the second magnetic field receiver are configured to generate second corrosion sensor data (Paragraph 0061: “The receiver grids 706 may be configured to sense the magnetic fields generated by the transmitter coils 702a-d and provide feedback to a data acquisition and control unit 708”), and a second communication interface (Line between 706 immediately below 702c and 708 in Figure 7). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to make each of the first and second recorders also corrosion recorders. The motivation would have been to increase the utility of the apparatus by also allowing it to obtain corrosion data.
Lastly, Nichols 986 as modified (See above paragraph) is silent about wherein the first corrosion recorder is configured to transmit, over an optical fiber cable, the first corrosion sensor data to the control system and wherein the second corrosion recorder is configured to transmit, over the optical fiber cable, the second corrosion sensor data to the control system. Nichols discloses a first corrosion recorder (40) and second corrosion recorder (46) each configured to transmit over an optical fiber cable (28) to a control system (30). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to make the first corrosion recorder configured to transmit, over the optical fiber cable, the first corrosion sensor data to the control system and make the second corrosion recorder configured to transmit, over the optical fiber cable, the second corrosion sensor data to the control system. The motivation would have been to transmit information to the surface for analysis.
As to Claim 2, Nichols 986 as modified teaches the invention of Claim 1 Refer to Claim 1 discussion). Nichols 986 as modified also teaches wherein the first corrosion recorder further comprises a processor, a memory, and a fiber optic connector configured to couple to the optical fiber cable (Nichols 986 - Column 8, Lines 18-25: “The system 19 may be operated using a computer (not shown) that is generally included in the surface station 22. The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith. The computer (not shown) includes a processor (not shown) and memory (not shown) that stores programs to operate the system 19”), wherein the first corrosion recorder is configured to receive, over the optical fiber cable and from the control system, a request to acquire the first corrosion sensor data, and wherein the memory is configured to store the first corrosion sensor data until the first corrosion sensor data is transmitted to the control system (Nichols 986 - Column 8, Lines 18-25: “The system 19 may be operated using a computer (not shown) that is generally included in the surface station 22. The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith. The computer (not shown) includes a processor (not shown) and memory (not shown) that stores programs to operate the system 19”).
As to Claim 3, Nichols 986 as modified teaches the invention of Claim 1 Refer to Claim 1 discussion). Nichols 986 as modified also teaches wherein the first corrosion recorder (Nichols 986: 66, 70) comprises a mount fixture configured to permanently couple the first corrosion recorder to the pipe component (Nichols 986: Figure 4).
As to Claim 5, Nichols 986 as modified teaches the invention of Claim 1 Refer to Claim 1 discussion). Nichols 986 as modified also teaches wherein the pipe component comprises a casing (Nichols 986: 16a).
As to Claim 8, Nichols 986 as modified teaches the invention of Claim 1 Refer to Claim 1 discussion). Nichols 986 as modified also teaches wherein the first corrosion recorder (Nichols 986: 66, 70) is configured to obtain, from the control system (Nichols: 22) and over the optical fiber cable, a command to generate the first corrosion sensor data; and generate, in response to obtaining the command, the first corrosion sensor data using the first magnetic field receiver (Nichols 986: 70) and the first magnetic field transmitter (Nichols 986: 66).
As to Claim 9, Nichols 986 as modified teaches the invention of Claim 1 Refer to Claim 1 discussion). Nichols 986 as modified also teaches wherein the control system (Nichols: 22) is configured to transmit, over the optical fiber cable, a first command to the first corrosion recorder (Nichols 986: 66, 70); and transmit, over the optical fiber cable, a second command to the second corrosion recorder (Nichols 986: 68, 72), wherein the first corrosion sensor data is generated in response to the first corrosion recorder (Nichols 986: 66, 70) obtaining the first command, and wherein the second corrosion sensor data is generated in response to the second corrosion recorder (Nichols 986: 68, 72) obtaining the second command.
As to Claim 10, Nichols 986 discloses an apparatus comprising:
A magnetic field transmitter (66, 68);
A magnetic field receiver (70, 72) wherein the magnetic field transmitter and the magnetic field receiver are permanently installed in a wellbore (12a) during production operations and are configured to continuously monitor a pipe (16a) over a life of a well (Column 14, Lines 12-14: “This leads to another advantage of having the transmitters/receivers wound on the casing and permanently deployed: there is no practical limit on the time that the signals can be averaged”);
A connector (Connector between 21 and control system 22) configured to couple to a cable (21);
A communication interface (Connector between cable 21 and the receiver 70/72 and transmitter 66/68; Column 8, Lines 20-23: “The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith”) coupled to the connector (via 21);
A processor coupled to the magnetic field transmitter, the magnetic field receiver, and the communication interface (Column 8, Lines 18-25: “The system 19 may be operated using a computer (not shown) that is generally included in the surface station 22. The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith. The computer (not shown) includes a processor (not shown) and memory (not shown) that stores programs to operate the system 19”); and
A memory coupled to the processor (Column 8, Lines 18-25: “The system 19 may be operated using a computer (not shown) that is generally included in the surface station 22. The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith. The computer (not shown) includes a processor (not shown) and memory (not shown) that stores programs to operate the system 19”), wherein the memory comprises instructions configured to perform a method comprising:
Obtain, over the cable (21), a command to generate sensor data,
Generate the sensor data using the magnetic field receiver (70, 72) and the magnetic field transmitter (66, 68), and
Transmit the sensor data over the cable (21) using the communication interface (Connector between cable 21 and the receiver 70/72 and transmitter 66/68).
However, Nichols 986 is silent about the magnetic field transmitter and magnetic field receiver generating and transmitting corrosion data. Sanmartin discloses a first corrosion recorder (Paragraph 0023: “Embodiments of the present disclosure describe exemplary pipe inspection tools that can improve tool resolution and enhance the identification of corrosion in wellbore pipes being monitored”) coupled to a pipe component, the first corrosion recorder comprising a first magnetic field transmitter (702a), a first magnetic field receiver (706 immediately below 702a), wherein the first magnetic field transmitter and the first magnetic field receiver are configured to generate first corrosion sensor data (Paragraph 0061: “The receiver grids 706 may be configured to sense the magnetic fields generated by the transmitter coils 702a-d and provide feedback to a data acquisition and control unit 708”), and a first communication interface (Line between 706 immediately below 702a and 708 in Figure 7). Sanmartin also discloses a second corrosion recorder (Paragraph 0023: “Embodiments of the present disclosure describe exemplary pipe inspection tools that can improve tool resolution and enhance the identification of corrosion in wellbore pipes being monitored”) coupled to the pipe component, the second corrosion recorder comprising a second magnetic field transmitter (702c), a second magnetic field receiver (706 immediately below 702c), wherein the second magnetic field transmitter and the second magnetic field receiver are configured to generate second corrosion sensor data (Paragraph 0061: “The receiver grids 706 may be configured to sense the magnetic fields generated by the transmitter coils 702a-d and provide feedback to a data acquisition and control unit 708”), and a second communication interface (Line between 706 immediately below 702c and 708 in Figure 7). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to have the magnetic field transmitter and magnetic field receiver generate and transmit corrosion data. The motivation would have been to increase the utility of the apparatus by also allowing it to obtain corrosion information and thereby monitor degradation of material.
Lastly, Nichols 986 as modified (See above paragraph) is silent about the magnetic field transmitter and the magnetic field receiver being within a sealed case and obtaining, over an optical fiber cable, corrosion sensor data generated by the magnetic field transmitter and the magnetic field receiver. Nichols discloses a sealed case (26) with a magnetic field transmitter (40) and a magnetic field receiver (42) therewithin and obtaining, over an optical fiber cable (28), corrosion sensor data generated by the magnetic field transmitter and the magnetic field receiver. Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to provide a sealed case and to have the magnetic field transmitter and the magnetic field receiver being within the sealed case and obtaining, over an optical fiber cable, corrosion sensor data generated by the magnetic field transmitter and the magnetic field receiver. The motivation would have been to protect the equipment and to transmit information to the surface for analysis.
As to Claim 11, Nichols 986 as modified teaches the invention of Claim 10 Refer to Claim 10 discussion). Nichols 986 as modified also teaches wherein the magnetic field transmitter (Nichols 986: 66, 68) is configured to transmit magnetic flux waves through a ferromagnetic material to cause a magnetic field; wherein the magnetic field receiver (Nichols 986: 70, 72) is configured to detect a flux leakage caused by a defect in the ferromagnetic material.
As to Claim 12, Nichols 986 as modified teaches the invention of Claim 10 Refer to Claim 10 discussion). Nichols 986 as modified also teaches further comprising the processor coupled to the communication interface (Nichols 986 - Column 8, Lines 18-25: “The system 19 may be operated using a computer (not shown) that is generally included in the surface station 22. The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith. The computer (not shown) includes a processor (not shown) and memory (not shown) that stores programs to operate the system 19”), wherein the communication interface is configured to transmit (Nichols 986 - Column 8, Lines 18-25: “The system 19 may be operated using a computer (not shown) that is generally included in the surface station 22. The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith. The computer (not shown) includes a processor (not shown) and memory (not shown) that stores programs to operate the system 19”), over the optical fiber cable, the corrosion sensor data regarding a corrosion region of interest to a control system (Nichols 986: 22).
As to Claim 13, Nichols 986 as modified teaches the invention of Claim 10 Refer to Claim 10 discussion). Nichols 986 as modified also teaches wherein the memory is configured to store the corrosion sensor data (Nichols 986 - Column 8, Lines 18-25: “The system 19 may be operated using a computer (not shown) that is generally included in the surface station 22. The computer (not shown) is communicatively linked with the transmitters 20 and receivers 24 using cables 21 disposed on the exterior surfaces of the casing 16a, 16b associated therewith. The computer (not shown) includes a processor (not shown) and memory (not shown) that stores programs to operate the system 19”).
As to Claim 15, Nichols 986 discloses a method comprising:
Transmitting, by a control system (22) and over a cable (21), a first command to a first recorder (66, 70) in a wellbore (12a);
Transmitting, by the control system (22) and over the cable (21), a second command to a second recorder (68, 72) in the wellbore,
Wherein the first recorder (66, 70) and the second recorder (68, 72) are separated by a predetermined distance within the wellbore (Figure 4),
Wherein the first recorder (66, 70) and the second recorder (68, 72) are permanently installed in the wellbore during production operations and are configured to continuously monitor a pipe component (16a) over a life of a well (Column 14, Lines 12-14: “This leads to another advantage of having the transmitters/receivers wound on the casing and permanently deployed: there is no practical limit on the time that the signals can be averaged”);
Obtaining, by the control system (22) in response to transmitting the first command and over the cable, first sensor data from the first recorder (66, 70); and
Obtaining, by the control system (22) in response to transmitting the second command and over the cable, second sensor data from the second recorder (68, 72),
Wherein the first sensor data and the second sensor data are generated using a plurality of magnetic field receivers (70, 72) and a plurality of magnetic field transmitters (66, 68), and
Wherein the first sensor data describes a first portion (Portion above 14a) of the pipe component (16a) disposed in the wellbore, and
Wherein the second sensor data describe a second portion (Portion below 14b) of the pipe component (16a) that is different from the first portion.
However, Nichols 986 is silent about the first recorder being a first corrosion recorder and the second recorder being a second corrosion recorder. Sanmartin discloses a first corrosion recorder (Paragraph 0023: “Embodiments of the present disclosure describe exemplary pipe inspection tools that can improve tool resolution and enhance the identification of corrosion in wellbore pipes being monitored”) coupled to a pipe component, the first corrosion recorder comprising a first magnetic field transmitter (702a), a first magnetic field receiver (706 immediately below 702a), wherein the first magnetic field transmitter and the first magnetic field receiver are configured to generate first corrosion sensor data (Paragraph 0061: “The receiver grids 706 may be configured to sense the magnetic fields generated by the transmitter coils 702a-d and provide feedback to a data acquisition and control unit 708”), and a first communication interface (Line between 706 immediately below 702a and 708 in Figure 7). Sanmartin also discloses a second corrosion recorder (Paragraph 0023: “Embodiments of the present disclosure describe exemplary pipe inspection tools that can improve tool resolution and enhance the identification of corrosion in wellbore pipes being monitored”) coupled to the pipe component, the second corrosion recorder comprising a second magnetic field transmitter (702c), a second magnetic field receiver (706 immediately below 702c), wherein the second magnetic field transmitter and the second magnetic field receiver are configured to generate second corrosion sensor data (Paragraph 0061: “The receiver grids 706 may be configured to sense the magnetic fields generated by the transmitter coils 702a-d and provide feedback to a data acquisition and control unit 708”), and a second communication interface (Line between 706 immediately below 702c and 708 in Figure 7). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to make each of the first and second recorders also corrosion recorders. The motivation would have been to increase the utility of the apparatus by also allowing it to obtain corrosion data.
Lastly, Nichols 986 as modified (See above paragraph) is silent about transmitting the first and second commands to the first and second corrosion recorders, respectively, over an optical fiber cable, and obtaining the first and second corrosion sensor data from the first and second corrosion recorders, respectively, over the optical fiber cable. Nichols discloses transmitting first and second commands to a first and second corrosion recorder (40 and 42; 44 and 46), respectively, over an optical fiber cable (28), and obtaining first and second corrosion sensor data from the first and second corrosion recorders (40 and 42; 44 and 46), respectively, over the optical fiber cable (28). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to transmit the first and second commands to the first and second corrosion recorders, respectively, over an optical fiber cable, and obtain the first and second corrosion sensor data from the first and second corrosion recorders, respectively, over the optical fiber cable. The motivation would have been to transmit information to the surface for analysis and transmit signals downhole for control.
Conclusion
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/EDWIN J TOLEDO-DURAN/Primary Examiner, Art Unit 3678
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