CTNF 18/700,784 CTNF 93828 Notice of Pre-AIA or AIA Status 07-03-aia AIA 15-10-aia The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA. Notice to Applicant Claims 9-16 have been examined in this application. This communication is the first action on the merits. Information Disclosure Statement (IDS) filed 4/12/2024 is acknowledged. Claim Rejections - 35 USC § 101 07-04-01 AIA 07-04 35 U.S.C. 101 reads as follows: Whoever invents or discovers any new and useful process, machine, manufacture, or composition of matter, or any new and useful improvement thereof, may obtain a patent therefor, subject to the conditions and requirements of this title. Claims 9- 16 are rejected under 35 U.S.C. 101 because the claimed invention is directed to an abstract idea without significantly more. Claims 9-15 are directed to improving signal quality of sensor data. Claim 9 recites a method for improving signal quality of sensor data, and Claim 13 recites a system for improving signal quality of sensor data, which include capturing first and second sensor data; calculating a correlation function; estimate the background noise; and reducing the background noise of the first sensor data via correlation function As drafted, this is, under its broadest reasonable interpretation, within the Abstract idea grouping of “Mental Processes” – evaluation. The recitation of “technical device”, “memory”, “processor”, provide nothing in the claim elements to preclude the step from being “Mental Processes”- evaluation. Accordingly, the claim recites an abstract idea. This judicial exception is not integrated into a practical application. The claims primarily recite the additional element of using computer components to perform each step. The “technical device”, “memory”, “processor” is recited at a high-level of generality, such that it amounts no more than mere instructions to apply the exception using a computer component. See MPEP 2106.05(f). Furthermore, claim 9 and claim 13 recite the additional element of a “sensor”- which is e MPEP 2106.05(h)- field of use . Accordingly, the additional elements do not integrate the abstract idea into a practical application because it does not impose any meaningful limits on practicing the abstract idea. The claims also fail to recite any improvements to another technology or technical field, improvements to the functioning of the computer itself, use of a particular machine, effecting a transformation or reduction of a particular article to a different state or thing, and/or an additional element applies or uses the judicial exception in some other meaningful way beyond generally linking the use of the judicial exception to a particular technological environment, such that the claim as a whole is more than a drafting effort designed to monopolize the exception. See 84 Fed. Reg. 55. In particular, there is a lack of improvement to a computer or technical field in sensor analysis. The claims do not include additional elements that are sufficient to amount to significantly more than the judicial exception because the additional elements when considered both individually and as an ordered combination do not amount to significantly more than the abstract idea. As discussed above with respect to integration of the abstract idea into a practical application, the additional elements of “technical device”, “memory”, “processor” is insufficient to amount to significantly more. ( See MPEP 2106.05(f) – Mere Instructions to Apply an Exception – “Thus, for example, claims that amount to nothing more than an instruction to apply the abstract idea using a generic computer do not render an abstract idea eligible.” Alice Corp., 134 S. Ct. at 235). Mere instructions to apply an exception using a generic computer component cannot provide an inventive concept. The claim fails to recite any improvements to another technology or technical field, improvements to the functioning of the computer itself, use of a particular machine, effecting a transformation or reduction of a particular article to a different state or thing, adding unconventional steps that confine the claim to a particular useful application, and/or meaningful limitations beyond generally linking the use of an abstract idea to a particular environment. See 84 Fed. Reg. 55. Viewed individually or as a whole, these additional claim element(s) do not provide meaningful limitation(s) to transform the abstract idea into a patent eligible application of the abstract idea such that the claim(s) amounts to significantly more than the abstract idea itself. With regards to receiving data and step 2B, it is M2106.05(d)- Receiving or transmitting data over a network, e.g., using the Internet to gather data, Symantec, 838 F.3d at 1321, 120 USPQ2d at 1362 (utilizing an intermediary computer to forward information) and Storing and retrieving information in memory, Versata Dev. Group, Inc. v. SAP Am., Inc., 793 F.3d 1306, 1334, 115 USPQ2d 1681, 1701 (Fed. Cir. 2015). With the regards to Step 2B and “sensor” – it is M2106.05(h)- field of use/ Examiner concludes that the additional elements in combination fail to amount to significantly more than the abstract idea based on findings that each element merely performs the same function(s) in combination as each element performs separately. The claim is not patent eligible. Thus, taken alone, the additional elements do not amount to significantly more than the above-identified judicial exception (the abstract idea). Looking at the limitations as an ordered combination adds nothing that is not already present when looking at the elements taken individually. Dependent Claims 10-12, and 14-16 recite wherein the at least one second sensor is mounted stationary and spaced apart from the first and at least one second technical device; wherein the environmental coupling is affected by at least one of a mechanical factor, an environmental factor, and an electrical factor; wherein the mechanical factor is a vibration, the environmental factor comprises temperature or pressure and where the electrical factor comprises an electric or a magnetic field; and further narrowing the abstract idea. These recited limitations in the dependent claims do not amount to significantly more than the above-identified judicial exceptions in Claims 9 and 13. Regarding Claims, 10 and 14, and the additional elements of “technical device” it is M2106.05(d)- Receiving or transmitting data over a network, e.g., using the Internet to gather data, Symantec, 838 F.3d at 1321, 120 USPQ2d at 1362 (utilizing an intermediary computer to forward information). Regarding claim 10 and claim 14 and the additional element of “sensor” - it is M2106.05(h)- field of use. Claim Rejections - 35 USC § 102 07-06 AIA 15-10-15 In the event the determination of the status of the application as subject to AIA 35 U.S.C. 102 and 103 (or as subject to pre-AIA 35 U.S.C. 102 and 103) is incorrect, any correction of the statutory basis for the rejection will not be considered a new ground of rejection if the prior art relied upon, and the rationale supporting the rejection, would be the same under either status. 07-07 AIA 07-07-aia The following is a quotation of 35 U.S.C. 102 that form the basis for the rejections under this section made in this Office action: A person shall be entitled to a patent unless – 07-08-aia AIA (a)(1) the claimed invention was patented, described in a printed publication, or in public use, on sale or otherwise available to the public before the effective filing date of the claimed invention. 07-15-aia AIA Claim s 9-16 are rejected under 35 U.S.C. 102 a(1) as being anticipated by Thompson et al., US Publication No. 20170261643A1, [hereinafter Thompson] . Regarding Claim 9, Thompson teaches A computer-implemented method for improving signal quality of a first sensor data, the first sensor data being captured by a first sensor which is environmentally coupled to a first technical device, and at least one second sensor data being captured by at least one second sensor which is environmentally decoupled from the first technical device, the method comprising: (Thompson Par. 46-47- FIGS. 1 and 2 are perspective diagrams illustrating an example system 10 for electroseismic and seismoelectric surveying. Example system 10 includes electromagnetic sensors 26, seismic sensors 28, and computing system 30. FIG. 1 illustrates an embodiment in which system 10 is generally configured to utilize signals 14 propagated by a passive electromagnetic source 12 of electromagnetic energy to perform geophysical surveying. FIG. 2 illustrates an embodiment in which system 10 is generally configured to utilize signals 20 and/or 22, which may be propagated by a passive seismic source 40. As illustrated in FIG. 1, sensors 26 and/or 28 generally detect signals generated by subsurface earth formation 16 in response to a electromagnetic signal 14 propagated from passive electromagnetic source 12. Computing system 30 may then process detected signals using various signal processing techniques to identify properties and/or features of subsurface earth formation 16. System 10 may detect seismic signals 20 generated due to the electroseismic interactions between the electromagnetic signal 14 and the subsurface formation 16, either alone or in combination with detecting electromagnetic signal 22, which may be generated as a result of seismoelectric conversions of seismic signals 20. One or more of the detected signals may then be processed to determine one or more properties of the subsurface earth formation. ; Par. 65; Par. 95; Par. 171) calculating, by a processor including memory, a correlation function, utilizing the first and the at least one second sensor data to estimate the background noise, the first and the at least one second sensor being exposed simultaneously to background noise and the processor being connected to the first and the at least one second sensor (Thompson Fig. 1; Par. 70-71; Par. 115- In some implementations, a seismic sensor 28, placed at substantial distance from the drilling operations, generates a time-dependent signal reflective of the electric field generated in the Earth/air environment. In other implementations, an electromagnetic sensor 26 placed at elevation above the surveyed field detects the electric field in the air, distinct from that emanating from the earth. That time-dependent amplitude can be correlated by computing system 30 with the signals detected over a hydrocarbon field operation to model the subsurface. Alternatively, the time-dependence of the signal from the second set of sensors may be used by computing system 30 to filter the data from the first sensor array to remove the background portion of the signal.; Par. 116- In still other implementations, the second set of sensors are placed near, but still removed from, the first sensor array and used to remove, for example, infrastructure noise. The second set of sensors may be placed between the first set of sensors and the source of infrastructure noise. Alternatively, the second set of sensors may be placed at a location where the infrastructure noise generates any additional signal that interferes with the first set of sensors. In one example implementation, the second set of sensors is located near a road to monitor and record the characteristic noises generated by the road. These characteristic noises of the infrastructure are then removed from the signals detected by the first sensor array by computing system 30.; Par. 117-118) ; and reducing the background noise of the first sensor data via correlation function, wherein the at least one second sensor is environmentally coupled to at least one second technical device. (Thompson Par. 117-119-“ Returning to FIG. 3, in block 320, computing system 30 may perform one or more cross-correlations of signals from sensors. In certain example embodiments, the cross correlation is performed between sensors in the first sensor array. In certain example embodiments, the cross correlation is performed between sensors in the second sensor array. In certain example embodiments, the cross correlation is performed between sensors in the third sensor array, discussed below. In certain example embodiments, the cross correlation is performed between one sensor in the first sensor array and a second sensor in the second sensor array. In certain example embodiments, the cross correlation is performed between one sensor in the first sensor array and a second sensor in the third sensor array. In certain example embodiments, the cross correlation is performed between two sensors from two of the first sensor array, the second sensor array, and the third sensor array; Certain implementations perform a cross correlation between time trace signals from two seismic sensors 28 in the first sensor array to reject noise. This cross-correlation may be used to determine the noise that may be dominated by surface waves. The result of the cross correlation is a measure of surface noise that is of minimal value to determine the behavior of the subsurface formation. In some implementations, the result of this cross-correlation may be removed from the signal from the first sensor array by the computing system 30.”) Regarding Claim 10 and Claim 14, Thompson teaches The method according to claim 9,… and The system according to claim 13,… wherein the at least one second sensor is mounted stationary and spaced apart from the first and at least one second technical device (Thompson Par. 114- 115 In some implementations, system 10 includes a second sensor array located apart from the first sensor array. The second sensor array may include one or more the electromagnetic sensors 26 and one or more seismic sensors 28. In some implementations, the second sensor array is located distant to the first sensor array, so that the effects of the drilling operation will be minimized in the second sensor array. The second sensor array may be placed apart from the first set of sensor at a distance substantially equal to or greater than a distance corresponding to the depth of the drilling operation. The second sensor array may be used by computing system 30 to, for example, remove background noise from signals received at the first sensor array (block 315). In other implementations, the signals from the second sensor array are used to determine one or more properties of the subsurface formation away from the region where drilling is taking place. In certain example embodiments, this determination of properties of the subsurface formation is further based on signals from the first sensor array.”) Regarding Claim 11, The method according to claim 9, wherein the environmental coupling is affected by at least one of a mechanical factor, an environmental factor, and an electrical factor. (Thompson Par. 53- Subsurface earth formation 16 may include a polarizable fluid including one or more fluid dipoles 114 associated with a fluid in subsurface earth formation 16. As a result, an electrochemical interaction may form between the polarizable fluid and the solid rock portions at boundary 18. The electrochemical interaction is represented by the “+” symbol in the fluid portion and the “−” symbol in the solid rock portion. Electromagnetic signals 14 may encounter and/or interact with fluid dipoles 114 of subsurface earth formation 16. In particular, the electromagnetic signals 14 may cause a change in the polarization of dipoles 114 in the pore fluid, which in turn may cause a pressure pulse 118 to be generated. For example, electromagnetic signals 14 may modify the electrochemical bonds or move the charges of fluid dipoles 114, thereby effectively creating pressure pulse 118 where the interactions are distorted. Pressure pulse 118 may represent a change in pressure and/or fluid flow that produces a time-varying pressure gradient, which may then propagate and/or be transmitted into the earth formation (or rock) at boundary 18 of subsurface earth formation 16. Electromagnetic signals 14 exist throughout the fluid area and may primarily affect the charges of the dipoles 114 which are at or near boundary 18 of the rock. The pressure gradient produced by pressure pulse 118 may propagate towards the surface as seismic signal 20. In should be noted that the solid rock portion may have an existing natural surface charge over at least a portion of the rock surface. The electrochemical interaction may result in a local pore fluid dipole 114 that causes a local background electromagnetic field. Moreover, the sign of the background electromagnetic field or field polarity direction depends on the surface charge on the solid and the way the fluid screens out that charge. For example, for clay layers, the charge is typically as shown as illustrated. In other materials such as carbonates, however, the charge may be reversed. Thus, an appropriate subsurface formation 16 may be a subsurface source of seismic energy.”; Par. 56-57- Seismic signals 20 may represent any mechanical seismic wave that propagates in the subsurface of the earth and may include, but is not limited to, P- and S-waves. Electromagnetic signals 22 represent any electromagnetic signals, ; Par. 74) Regarding Claim 12, The method according to claim 11, wherein the mechanical factor is a vibration, the environmental factor comprises temperature or pressure and where the electrical factor comprises an electric or a magnetic field. (Thompson Par. 53- Subsurface earth formation 16 may include a polarizable fluid including one or more fluid dipoles 114 associated with a fluid in subsurface earth formation 16. As a result, an electrochemical interaction may form between the polarizable fluid and the solid rock portions at boundary 18. The electrochemical interaction is represented by the “+” symbol in the fluid portion and the “−” symbol in the solid rock portion. Electromagnetic signals 14 may encounter and/or interact with fluid dipoles 114 of subsurface earth formation 16. In particular, the electromagnetic signals 14 may cause a change in the polarization of dipoles 114 in the pore fluid, which in turn may cause a pressure pulse 118 to be generated. For example, electromagnetic signals 14 may modify the electrochemical bonds or move the charges of fluid dipoles 114, thereby effectively creating pressure pulse 118 where the interactions are distorted. Pressure pulse 118 may represent a change in pressure and/or fluid flow that produces a time-varying pressure gradient, which may then propagate and/or be transmitted into the earth formation (or rock) at boundary 18 of subsurface earth formation 16. Electromagnetic signals 14 exist throughout the fluid area and may primarily affect the charges of the dipoles 114 which are at or near boundary 18 of the rock. The pressure gradient produced by pressure pulse 118 may propagate towards the surface as seismic signal 20. In should be noted that the solid rock portion may have an existing natural surface charge over at least a portion of the rock surface. The electrochemical interaction may result in a local pore fluid dipole 114 that causes a local background electromagnetic field. Moreover, the sign of the background electromagnetic field or field polarity direction depends on the surface charge on the solid and the way the fluid screens out that charge. For example, for clay layers, the charge is typically as shown as illustrated. In other materials such as carbonates, however, the charge may be reversed. Thus, an appropriate subsurface formation 16 may be a subsurface source of seismic energy.”; Par. 56-57- Seismic signals 20 may represent any mechanical seismic wave that propagates in the subsurface of the earth and may include, but is not limited to, P- and S-waves. Electromagnetic signals 22 represent any electromagnetic signals,; Par. 74 ) Regarding Claim 13, Thompson teaches A system for improving a signal quality of a first sensor data, the system comprising: a first sensor configured to capture the first sensor data; at least one second sensor configured to capture at least one second sensor data; and a processor including memory, which is connected to the first and the at least one second sensor and which is configured to receive the first and at least one second sensor data; wherein the first sensor is environmentally coupled to a first technical device; wherein the at least one second sensor is environmentally decoupled from the first technical device; (Thompson Par. 46-47- FIGS. 1 and 2 are perspective diagrams illustrating an example system 10 for electroseismic and seismoelectric surveying. Example system 10 includes electromagnetic sensors 26, seismic sensors 28, and computing system 30. FIG. 1 illustrates an embodiment in which system 10 is generally configured to utilize signals 14 propagated by a passive electromagnetic source 12 of electromagnetic energy to perform geophysical surveying. FIG. 2 illustrates an embodiment in which system 10 is generally configured to utilize signals 20 and/or 22, which may be propagated by a passive seismic source 40. As illustrated in FIG. 1, sensors 26 and/or 28 generally detect signals generated by subsurface earth formation 16 in response to a electromagnetic signal 14 propagated from passive electromagnetic source 12. Computing system 30 may then process detected signals using various signal processing techniques to identify properties and/or features of subsurface earth formation 16. System 10 may detect seismic signals 20 generated due to the electroseismic interactions between the electromagnetic signal 14 and the subsurface formation 16, either alone or in combination with detecting electromagnetic signal 22, which may be generated as a result of seismoelectric conversions of seismic signals 20. One or more of the detected signals may then be processed to determine one or more properties of the subsurface earth formation. ; Par. 65; Par. 70-71; Par. 95; Par. 171) wherein the first and at least one second sensing sensor are configured such that said first and at least one second sensing sensor are simultaneously exposed to background noise; wherein the processor is configured to calculate a correlation function utilizing the first and at least one second sensor data to estimate the background noise; (Thompson Fig. 1; Par. 70-71; Par. 115- In some implementations, a seismic sensor 28, placed at substantial distance from the drilling operations, generates a time-dependent signal reflective of the electric field generated in the Earth/air environment. In other implementations, an electromagnetic sensor 26 placed at elevation above the surveyed field detects the electric field in the air, distinct from that emanating from the earth. That time-dependent amplitude can be correlated by computing system 30 with the signals detected over a hydrocarbon field operation to model the subsurface. Alternatively, the time-dependence of the signal from the second set of sensors may be used by computing system 30 to filter the data from the first sensor array to remove the background portion of the signal.; Par. 116- In still other implementations, the second set of sensors are placed near, but still removed from, the first sensor array and used to remove, for example, infrastructure noise. The second set of sensors may be placed between the first set of sensors and the source of infrastructure noise. Alternatively, the second set of sensors may be placed at a location where the infrastructure noise generates any additional signal that interferes with the first set of sensors. In one example implementation, the second set of sensors is located near a road to monitor and record the characteristic noises generated by the road. These characteristic noises of the infrastructure are then removed from the signals detected by the first sensor array by computing system 30.; Par. 117-118) ; wherein the correlation function is utilized to reduce background noise related to the first sensor data; and wherein the at least one second sensor is environmentally coupled to at least one second technical device (Thompson Par. 117-119-“ Returning to FIG. 3, in block 320, computing system 30 may perform one or more cross-correlations of signals from sensors. In certain example embodiments, the cross correlation is performed between sensors in the first sensor array. In certain example embodiments, the cross correlation is performed between sensors in the second sensor array. In certain example embodiments, the cross correlation is performed between sensors in the third sensor array, discussed below. In certain example embodiments, the cross correlation is performed between one sensor in the first sensor array and a second sensor in the second sensor array. In certain example embodiments, the cross correlation is performed between one sensor in the first sensor array and a second sensor in the third sensor array. In certain example embodiments, the cross correlation is performed between two sensors from two of the first sensor array, the second sensor array, and the third sensor array; Certain implementations perform a cross correlation between time trace signals from two seismic sensors 28 in the first sensor array to reject noise. This cross-correlation may be used to determine the noise that may be dominated by surface waves. The result of the cross correlation is a measure of surface noise that is of minimal value to determine the behavior of the subsurface formation. In some implementations, the result of this cross-correlation may be removed from the signal from the first sensor array by the computing system 30.”) Regarding Claim 15 and Claim 16, Thompson teaches The system according to claim 13, … and The system according to claim 14,… wherein the at least one second sensor is coupled for direct communication purposes to the first sensor. (Thompson Par. 70- 71- Computing system 30 represents any suitable combination of hardware, software, signal processors, and controlling logic to process, store, and/or analyze electromagnetic signals 22 and/or seismic signals 20 received from sensors 26 and/or 28. Computing system 30 may include one or more processors, memory, and/or interfaces. Computing system 30 may, for example, include an interface operable to communicatively couple with and/or receive information from sensors 26 and/or 28. Computing system may be operable to receive and/or process passive survey data from sensors 26 and 28. Passive survey data may include, for example, data representative of signals 20 and/or 22. Computing system 30 may include one or more appropriate analog-to-digital converters to digitize signals 20 and/or 22 for digital signal processing. Alternatively or in addition, sensors 26 and/or 28 may include appropriate analog-to-digital converters. Computing system 30 may include a recording and/or storage device operable to receive and store data received from sensors 26 and 28. Computing system 30 may include, for example, digital and/or analog recording devices and/or non-transitory media. In some embodiments, computing system 30 may be capable of processing detected seismic signal 20 and the detected electromagnetic signal 22 in real-time without first recording the signals on a non-transitory medium.) Conclusion 07-96 AIA The prior art made of record and not relied upon is considered pertinent to applicant's disclosure : US Publication No. 20230065864 A1 to Trikha et al.- Abstract-“ Disclosed herein as methods, apparatuses, non-transitory computer readable media, and systems for sensor calibration in at least one enclosure. The calibration may include self-calibration of the sensor, e.g., automatically. The calibration may be performed automatically at or after deployment of the sensor in the enclosure. The calibration may utilize the data of the sensor to be calibrated and/or sensor data of adjacent sensor(s) in the enclosure.” Any inquiry concerning this communication or earlier communications from the examiner should be directed to Chesiree Walton, whose telephone number is (571) 272-5219. The examiner can normally be reached from Monday to Friday between 8 AM and 5 PM. If any attempt to reach the examiner by telephone is unsuccessful, the examiner’s supervisor, Patricia Munson, can be reached at (571) 270-5396. The fax telephone numbers for this group are either (571) 273-8300 or (703) 872-9326 (for official communications including After Final communications labeled “Box AF”). Another resource that is available to applicants is the Patent Application Information Retrieval (PAIR). Information regarding the status of an application can be obtained from the (PAIR) system. Status information for published applications may be obtained from either Private PAIR. Status information for unpublished applications is available through Private PAIR only. For more information about the PAIR system, see http://pair-direct.uspto.gov. Should you have questions on access to the Private PAIR system, please feel free to contact the Electronic Business Center (EBC) at 866-217-9197 (toll-free). Applicants are invited to contact the Office to schedule an in-person interview to discuss and resolve the issues set forth in this Office Action. Although an interview is not required, the Office believes that an interview can be of use to resolve any issues related to a patent application in an efficient and prompt manner. Sincerely, /CHESIREE A WALTON/ Examiner, Art Unit 3624 Application/Control Number: 18/700,784 Page 2 Art Unit: 3624 Application/Control Number: 18/700,784 Page 3 Art Unit: 3624 Application/Control Number: 18/700,784 Page 4 Art Unit: 3624 Application/Control Number: 18/700,784 Page 5 Art Unit: 3624 Application/Control Number: 18/700,784 Page 6 Art Unit: 3624 Application/Control Number: 18/700,784 Page 7 Art Unit: 3624 Application/Control Number: 18/700,784 Page 8 Art Unit: 3624 Application/Control Number: 18/700,784 Page 9 Art Unit: 3624 Application/Control Number: 18/700,784 Page 10 Art Unit: 3624 Application/Control Number: 18/700,784 Page 11 Art Unit: 3624 Application/Control Number: 18/700,784 Page 12 Art Unit: 3624 Application/Control Number: 18/700,784 Page 13 Art Unit: 3624 Application/Control Number: 18/700,784 Page 14 Art Unit: 3624 Application/Control Number: 18/700,784 Page 15 Art Unit: 3624 Application/Control Number: 18/700,784 Page 16 Art Unit: 3624 Application/Control Number: 18/700,784 Page 17 Art Unit: 3624 Application/Control Number: 18/700,784 Page 18 Art Unit: 3624 Application/Control Number: 18/700,784 Page 19 Art Unit: 3624
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