DETAILED ACTION
This office action is in response to application filed on June 30, 2023.
Notice of Pre-AIA or AIA Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Information Disclosure Statement
The information disclosure statements (IDS) submitted on 06/30/2023 and 11/01/2024 are in compliance with the provisions of 37 CFR 1.97. Accordingly, the information disclosure statements are being considered by the examiner.
Specification
The disclosure is objected to because of the following informalities:
[0088]: Language “In some implementations, any or all of the components of the computer (1200), both hardware or software (or a combination of hardware and software), may interface with each other or the interface (1204) (or a combination of both) over the system bus (1203) using an application programming interface (API) (1207) or a service layer (1208) (or a combination of the API (1207) and service layer (1208)” should read “In some implementations, any or all of the components of the computer (1200), both hardware or software (or a combination of hardware and software), may interface with each other or the interface (1204) (or a combination of both) over the system bus (1203) using an application programming interface (API) (1207) or a service layer (1208) (or a combination of the API (1207) and service layer (1208))” in order to correct for minor informalities (i.e., add missing parenthesis)
Appropriate correction is required.
Claim Objections
Claim 1 is objected to because of the following informalities:
Claim language “A method, comprising:” should read “A method[[,]] comprising:” in order to correct for minor informalities.
Claim language “determining a plurality of attenuation parameters based, at least in part, on the filtering region, the attenuation parameters being configured to attenuate the artifact” should read “determining a plurality of attenuation parameters based, at least in part, on the filtering region, the plurality of attenuation parameters being configured to attenuate the artifact” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 6 is objected to because of the following informalities:
Claim language “determining a plurality of mechanical parameters corresponding to a formation of the subsurface region of interest based, at least in part, on the target region” should read “determining [[a]]the plurality of mechanical parameters corresponding to [[a]]the formation of the subsurface region of interest based, at least in part, on the target region” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 7 is objected to because of the following informalities:
Claim language should read “The method of claim 1, wherein the plurality of attenuation parameters are frequency independent” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 9 is objected to because of the following informalities:
Claim language “determining a plurality of attenuation parameters based, at least in part, on the filtering region, the attenuation parameters being configured to attenuate the artifact” should read “determining a plurality of attenuation parameters based, at least in part, on the filtering region, the plurality of attenuation parameters being configured to attenuate the artifact” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 10 is objected to because of the following informalities:
Claim language “The non-transitory computer-readable medium of claim 9, further comprising computer-executable instructions …” should read “The non-transitory computer-readable medium of claim 9, further comprising the computer-executable instructions …” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 11 is objected to because of the following informalities:
Claim language “The non-transitory computer-readable medium of claim 9, further comprising computer-executable instructions …” should read “The non-transitory computer-readable medium of claim 9, further comprising the computer-executable instructions …” in order to provide appropriate antecedence basis.
Claim language “determining a plurality of mechanical parameters corresponding to a formation of the subsurface region of interest based, at least in part, on the target region” should read “determining [[a]]the plurality of mechanical parameters corresponding to [[a]]the formation of the subsurface region of interest based, at least in part, on the target region” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 12 is objected to because of the following informalities:
Claim language “The non-transitory computer-readable medium of claim 9, further comprising computer-executable instructions …” should read “The non-transitory computer-readable medium of claim 9, further comprising the computer-executable instructions …” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 13 is objected to because of the following informalities:
Claim language “A system, comprising:” should read “A system[[,]] comprising:” in order to correct for minor informalities.
Claim language “a seismic acquisition system configured to record seismic data regarding a subsurface region of interest …” should read “a seismic acquisition system configured to record seismic data associated with a subsurface region of interest …” in order to provide appropriate antecedence basis.
Claim language “obtain seismic data associated with the subsurface region of interest” should read “obtain the seismic data associated with the subsurface region of interest” in order to provide appropriate antecedence basis.
Claim language “determine a plurality of attenuation parameters based, at least in part, on the filtering region, the attenuation parameters being configured to attenuate the artifact” should read “determine a plurality of attenuation parameters based, at least in part, on the filtering region, the plurality of attenuation parameters being configured to attenuate the artifact” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim 18 is objected to because of the following informalities:
Claim language “determine a plurality of mechanical parameters corresponding to a formation of the subsurface region of interest based, at least in part, on the target region” should read “determine [[a]]the plurality of mechanical parameters corresponding to [[a]]the formation of the subsurface region of interest based, at least in part, on the target region” in order to provide appropriate antecedence basis.
Appropriate correction is required.
Claim Rejections - 35 USC § 101
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 1-2, 4-14 and 16-20 are rejected under 35 U.S.C. 101 because the claimed invention is directed to a judicial exception without significantly more.
Regarding claim 1, the examiner submits that under Step 1 of the 2024 Guidance Update on Patent Subject Matter Eligibility, Including on Artificial Intelligence (see also 2019 Revised Patent Subject Matter Eligibility Guidance) for evaluating claims for eligibility under 35 U.S.C. 101, the claim is to a process, which is one of the statutory categories of invention.
Continuing with the analysis, under Step 2A - Prong One of the test:
the limitation “determining a plurality of mechanical parameters corresponding to a formation of the subsurface region based, at least in part, on the plurality of time-space waveforms” is a process that, under its broadest reasonable interpretation in light of the specification, covers performance of the limitation using mathematical concepts to manipulate data and obtain additional information (i.e., plurality of mechanical parameters, see specification at [0048]-[0054]). Except for the recitation of the extra-solution activities (e.g., source/type of data being evaluated) and/or the particular technological environment or field of use, the limitation in the context of the claim mainly refers to applying mathematical concepts to manipulate data to obtain additional data.
the limitation “generating a filtering region based on an artifact identified in the plurality of time-space waveforms” is a process that, under its broadest reasonable interpretation in light of the specification, covers performance of the limitation using mental processes to select a portion of the data (i.e., filtering region, see specification at [0056]). Except for the recitation of the extra-solution activities (e.g., source/type of data being evaluated) and/or the particular technological environment or field of use, the limitation in the context of the claim mainly refers to performing mental evaluations/observations/judgement for data selection.
the limitation “determining a plurality of attenuation parameters based, at least in part, on the filtering region, the attenuation parameters being configured to attenuate the artifact” is a process that, under its broadest reasonable interpretation in light of the specification, covers performance of the limitation using mathematical concepts to manipulate data and obtain additional information (i.e., plurality of attenuation parameters, see specification at [0058]-[0061]). Except for the recitation of the extra-solution activities (e.g., source/type of data being evaluated) and/or the particular technological environment or field of use, the limitation in the context of the claim mainly refers to applying mathematical concepts to manipulate data to obtain additional data.
the limitation “filtering the time-space waveforms based, at least in part, on the plurality of mechanical parameters and the plurality of attenuation parameters to generate a plurality of filtered time-space waveforms” is a process that, under its broadest reasonable interpretation in light of the specification, covers performance of the limitation using mathematical concepts to transform data (i.e., plurality of filtered time-space waveforms, see specification at [0064]). Except for the recitation of the extra-solution activities (e.g., source/type of data being evaluated) and/or the particular technological environment or field of use, the limitation in the context of the claim mainly refers to applying mathematical concepts to transform (filter) data.
the limitation “generating a seismic image of the subsurface region using the plurality of filtered time-space waveforms” is a process that, under its broadest reasonable interpretation in light of the specification, covers performance of the limitation using mathematical concepts to transform data (i.e., seismic image, see specification at [0037], [0079]). Except for the recitation of the extra-solution activities (e.g., source/type of data being evaluated) and/or the particular technological environment or field of use, the limitation in the context of the claim mainly refers to applying mathematical concepts to transform data into an image representation.
Therefore, the claim recites a judicial exception under Step 2A - Prong One of the test.
Furthermore, under Step 2A - Prong Two of the test, this judicial exception is not integrated into a practical application when considering the claim as a whole. In particular, the additional elements recited in the claim:
“obtaining seismic data associated with a subsurface region of interest, wherein the seismic data comprises a plurality of time-space waveforms” generally links the use of the judicial exception to a particular technological environment or field of use (see MPEP 2106.05(h)), while also adding extra-solution activities (e.g., mere data gathering, source/type of data to be manipulated) (see MPEP 2106.05(g)).
Accordingly, these additional elements, when considered individually and in combination, do not integrate the judicial exception into a practical application because they do not impose any meaningful limits on practicing the abstract idea when considering the claim as a whole. The claim is directed to a judicial exception under Step 2A of the test.
Additionally, under Step 2B of the test, the claim, when considered as a whole, does not include additional elements that, when considered individually and in combination, are sufficient to amount to significantly more than the judicial exception because the additional elements
generally link the use of the judicial exception to a particular technological environment or field of use (e.g., seismic data processing), which as indicated in the MPEP: “As explained by the Supreme Court, a claim directed to a judicial exception cannot be made eligible “simply by having the applicant acquiesce to limiting the reach of the patent for the formula to a particular technological use.” Diamond v. Diehr, 450 U.S. 175, 192 n.14, 209 USPQ 1, 10 n. 14 (1981). Thus, limitations that amount to merely indicating a field of use or technological environment in which to apply a judicial exception do not amount to significantly more than the exception itself, and cannot integrate a judicial exception into a practical application” (see MPEP 2106.05(h)); and
recite extra-solution activities (i.e., mere data gathering by selecting a particular data source/type to be manipulated), which as indicated in the MPEP: “Another consideration when determining whether a claim integrates the judicial exception into a practical application in Step 2A Prong Two or recites significantly more in Step 2B is whether the additional elements add more than insignificant extra-solution activity to the judicial exception. The term “extra-solution activity” can be understood as activities incidental to the primary process or product that are merely a nominal or tangential addition to the claim. Extra-solution activity includes both pre-solution and post-solution activity. An example of pre-solution activity is a step of gathering data for use in a claimed process” (see MPEP 2106.05(g)).
The claim, when considered as a whole, does not provide significantly more under Step 2B of the test.
Based on the analysis, the claim is not patent eligible.
Similarly, independent claims 9 and 13 are directed to a judicial exception (abstract idea) without significantly more as explained above with regards to claim 1.
With regards to the dependent claims they are also directed to the non-statutory subject matter because:
they just extend the abstract idea of the independent claims by additional limitations (Claims 2, 6, 8, 10-12, 14, 18 and 20), that under the broadest reasonable interpretation in light of the specification, cover performance of the limitations using mental processes and/or mathematical concepts, and
the additional elements recited in the dependent claims, when considered individually and in combination, refer to extra-solution activities (e.g., mere data gathering using a data type or source), generic computer components and/or field of use (Claims 4-7, 11, 16-19), which as indicated in the Office’s guidance does not integrate the judicial exception into a practical application (Step 2A – Prong Two) and/or does not provide significantly more (Step 2B) when considering the claimed invention as a whole.
Examiner’s Note
Claims 3 and 15 were evaluated for patent eligibility under 35 U.S.C. 101 using the SUBJECT MATTER ELIGIBILITY TEST FOR PRODUCTS AND PROCESSES described in the 2024 Guidance Update on Patent Subject Matter Eligibility, Including on Artificial Intelligence (see also 2019 Revised Patent Subject Matter Eligibility Guidance) to determine patent eligibility under 35 U.S.C. 101.
Regarding claim 3, the examiner submits that under Step 1 of the test for evaluating claims for eligibility under 35 U.S.C. 101, the claim is to a process, which is one of the statutory categories of invention.
Continuing with the analysis, under Step 2A - Prong One of the test, the examiner submits that claim 3 recites a judicial exception (i.e., abstract idea, as indicated above with respect to claims 1-2), and
the limitation “planning, using a wellbore planning system, a planned wellbore trajectory to intersect the drilling target in the subsurface region based, at least in part, on the seismic image” is a process that, under its broadest reasonable interpretation in light of the specification, covers performance of the limitation using mental processes and/or mathematical concepts to manipulate data and obtain additional information (i.e., a planned wellbore trajectory, see specification at [0045], [0082]). Except for the recitation of the extra-solution activities (i.e., source/type of data being evaluated), the addition of generic computer elements (i.e., a wellbore planning system) used to facilitate the application of the judicial exception, and/or the field of use, the limitation in the context of this claim mainly refers to performing mental evaluations and/or applying mathematical concepts to manipulate data and obtain additional information.
Therefore, the claim recites a judicial exception under Step 2A - Prong One of the test.
Furthermore, under Step 2A - Prong Two of the test, the claim recites:
“drilling a wellbore guided by the planned wellbore trajectory using a drilling system” which, when considering the claim as a whole, integrates the judicial exception into a practical application by effecting a transformation or reduction of a particular article to a different state or thing (e.g., drilling a wellbore based on the claimed analysis) (see MPEP 2106.05(c)).
Therefore, these additional elements, when considered individually and in combination, integrate the judicial exception into a practical application. The claim, when considered as a whole, is eligible at Prong Two of the Revised Step 2A (see 2019 Revised Patent Subject Matter Eligibility Guidance – Revised Step 2A, see also MPEP 2106.04(d)).
Similarly, claim 15 is directed to patent eligible subject matter as explained above with regards to claim 3.
Subject Matter Not Rejected Over Prior Art
Claims 1-2, 4-14 and 16-20 are distinguished over the prior art of record for the following reasons:
Regarding claim 1.
Virgilio (US 20110134722 A1) discloses/teaches:
A method (Fig. 3; [0004], [0023]-[0024]: data processing for geophysics exploration using a simultaneous joint inversion of surface wave and refraction wave data is presented (see also [0061])), comprising:
obtaining seismic data associated with a subsurface region of interest (Fig. 3, item 300; [0062]: seismic data is acquired for a survey area (see also [0009], [0017], [0045], [0057])), wherein the seismic data comprises a plurality of time-space waveforms ([0063]-[0064], [0066]: seismic data includes surface waves and refracted waves (see Fig. 4A));
determining a plurality of mechanical parameters corresponding to a formation of the subsurface region based, at least in part, on the plurality of time-space waveforms (Fig. 3, items 210; [0063]-[0064], [0066]: seismic data is processed to extract wave properties including dispersion or velocity (mechanical parameters, see also [0046], [0050], [0057], [0059]), with this data being used to estimate visco-elastic parameters in the near surface (see [0056], [0071]));
generating a filtering region ([0059]: subsets of the surface waves and refracted waves datasets corresponding to selected areas of interest (filtering region) are used during independent steps (see also [0064])); and
determining a plurality of attenuation parameters based, at least in part, on the filtering region ([0063]-[0064], [0066]: seismic data is processed to extract wave properties including attenuation (attenuation parameters, see also [0046], [0050], [0057], [0059]), with this data being used to estimate visco-elastic parameters in the near surface (see [0056], [0071])).
Xie (US 20190302292 A1) discloses/teaches:
A method (Fig. 5; [0002], [0013]: a method for processing seismic data for seismic exploration is presented), comprising:
obtaining seismic data associated with a subsurface region of interest, wherein the seismic data comprises a plurality of time-space waveforms (Fig. 5, item 510; [0046]: seismic data for an explored subsurface formation is acquired (see also [0004], [0013]));
determining a plurality of mechanical parameters corresponding to a formation of the subsurface region based, at least in part, on the plurality of time-space waveforms (Fig. 5, items 520 and 530; [0047]-[0048]: a velocity model associated with the explored subsurface formation is obtained by performing a visco-acoustic full waveform inversion (FWI), which implies the determination of mechanical parameters (see [0049]));
determining a plurality of attenuation parameters (Fig. 5, items 520 and 530; [0047]-[0048]: a quality factor associated with the explored subsurface formation is obtained by performing a visco-acoustic full waveform inversion (FWI), which implies the determination of attenuation parameters (see [0049])); and
generating a seismic image of the subsurface region ([0049]: the velocity model and the Q model are used to identify natural resources in the explored subsurface formation (see [0002])).
Sun (US 20160131781 A1, IDS reference) discloses:
“Described below are methods, systems, and computer readable storage media that provide a manner of creating a high-resolution velocity model combining tomography with seismic inversion. To this end, seismic tomography techniques such as migration velocity analysis are used, in some embodiments, to generate a low-resolution background velocity model for a volume representing a geological medium. The low-resolution background velocity model is used, in turn, as an input to jump start impedance inversion and obtain a high-resolution velocity model. The high-resolution velocity model is used for drilling hazard prediction and mitigation by detecting regions of the volume of the geological medium that have velocities anomalously lower than the background trend, since low velocity anomalies can be caused by anomalously high fluid pressure (e.g. drilling hazards)” ([0012]: a high resolution velocity model is created by combining tomography and seismic inversion in order to detect regions having anomalous velocities, the process including a depth domain filtering to remove noise or artifacts in the seismic image gathers (see [0031]-[0032]); the reference does not determine attenuation parameters for attenuating an artifact identified in the plurality of time-space waveforms, but instead, it combines a velocity model and an attenuation model to identify (not attenuate) anomalies (see Fig. 1))).
The closest prior art of record, taken individually or in combination, fail to teach or suggest (see italic text):
“generating a filtering region based on an artifact identified in the plurality of time-space waveforms;
determining a plurality of attenuation parameters based, at least in part, on the filtering region, the attenuation parameters being configured to attenuate the artifact;
filtering the time-space waveforms based, at least in part, on the plurality of mechanical parameters and the plurality of attenuation parameters to generate a plurality of filtered time-space waveforms; and
generating a seismic image of the subsurface region using the plurality of filtered time-space waveforms”
in combination with all other limitations within the claim, as claimed and defined by the applicant.
Regarding claim 9.
Virgilio (US 20110134722 A1) discloses/teaches:
A non-transitory computer-readable medium (Fig. 10, item 1010 – ‘storage’) comprising computer-executable instructions stored thereon that, when executed on a processor (Fig. 10, item 1005 – ‘processor’; [0082], [0084]: a computing apparatus comprises processor and storage, which includes an application to perform data processing for geophysics exploration using a simultaneous joint inversion of surface wave and refraction wave data (see [0004], [0023]-[0024], [0061])), cause the processor to perform:
obtaining seismic data associated with a subsurface region of interest (Fig. 3, item 300; [0062]: seismic data is acquired for a survey area (see also [0009], [0017], [0045], [0057])), wherein the seismic data comprises a plurality of time-space waveforms ([0063]-[0064], [0066]: seismic data includes surface waves and refracted waves (see Fig. 4A));
determining a plurality of mechanical parameters corresponding to a formation of the subsurface region based, at least in part, on the plurality of time-space waveforms (Fig. 3, items 210; [0063]-[0064], [0066]: seismic data is processed to extract wave properties including dispersion or velocity (mechanical parameters, see also [0046], [0050], [0057], [0059]), with this data being used to estimate visco-elastic parameters in the near surface (see [0056], [0071]));
generating a filtering region ([0059]: subsets of the surface waves and refracted waves datasets corresponding to selected areas of interest (filtering region) are used during independent steps (see also [0064])); and
determining a plurality of attenuation parameters based, at least in part, on the filtering region ([0063]-[0064], [0066]: seismic data is processed to extract wave properties including attenuation (attenuation parameters, see also [0046], [0050], [0057], [0059]), with this data being used to estimate visco-elastic parameters in the near surface (see [0056], [0071])).
Xie (US 20190302292 A1) discloses/teaches:
A non-transitory computer-readable medium (Fig. 6, item 604 – ‘RAM’) comprising computer-executable instructions stored thereon that, when executed on a processor (Fig. 6, item 602 – ‘processor’; [0050]-[0051]: a seismic data processing apparatus comprises processor and memory, which stores executable code to process seismic data for seismic exploration (see [0002], [0013])), cause the processor to perform:
obtaining seismic data associated with a subsurface region of interest, wherein the seismic data comprises a plurality of time-space waveforms (Fig. 5, item 510; [0046]: seismic data for an explored subsurface formation is acquired (see also [0004], [0013]));
determining a plurality of mechanical parameters corresponding to a formation of the subsurface region based, at least in part, on the plurality of time-space waveforms (Fig. 5, items 520 and 530; [0047]-[0048]: a velocity model associated with the explored subsurface formation is obtained by performing a visco-acoustic full waveform inversion (FWI), which implies the determination of mechanical parameters (see [0049]));
determining a plurality of attenuation parameters (Fig. 5, items 520 and 530; [0047]-[0048]: a quality factor associated with the explored subsurface formation is obtained by performing a visco-acoustic full waveform inversion (FWI), which implies the determination of attenuation parameters (see [0049])); and
generating a seismic image of the subsurface region ([0049]: the velocity model and the Q model are used to identify natural resources in the explored subsurface formation (see [0002])).
Sun (US 20160131781 A1, IDS reference) discloses:
“Described below are methods, systems, and computer readable storage media that provide a manner of creating a high-resolution velocity model combining tomography with seismic inversion. To this end, seismic tomography techniques such as migration velocity analysis are used, in some embodiments, to generate a low-resolution background velocity model for a volume representing a geological medium. The low-resolution background velocity model is used, in turn, as an input to jump start impedance inversion and obtain a high-resolution velocity model. The high-resolution velocity model is used for drilling hazard prediction and mitigation by detecting regions of the volume of the geological medium that have velocities anomalously lower than the background trend, since low velocity anomalies can be caused by anomalously high fluid pressure (e.g. drilling hazards)” ([0012]: a high resolution velocity model is created by combining tomography and seismic inversion in order to detect regions having anomalous velocities, the process including a depth domain filtering to remove noise or artifacts in the seismic image gathers (see [0031]-[0032]); the reference does not determine attenuation parameters for attenuating an artifact identified in the plurality of time-space waveforms, but instead, it combines a velocity model and an attenuation model to identify (not attenuate) anomalies (see Fig. 1))).
The closest prior art of record, taken individually or in combination, fail to teach or suggest (see italic text):
“generating a filtering region based on an artifact identified in the plurality of time-space waveforms;
determining a plurality of attenuation parameters based, at least in part, on the filtering region, the attenuation parameters being configured to attenuate the artifact;
filtering the time-space waveforms based, at least in part, on the plurality of mechanical parameters and the plurality of attenuation parameters to generate a plurality of filtered time-space waveforms; and
generating a seismic image of the subsurface region using the plurality of filtered time-space waveforms”
in combination with all other limitations within the claim, as claimed and defined by the applicant.
Regarding claim 13.
Virgilio (US 20110134722 A1) discloses/teaches:
A system (Figs. 10-11 – “computing systems”), comprising:
a seismic acquisition system configured to record seismic data regarding a subsurface region of interest (Fig. 3, item 300; [0062]: seismic data is acquired for a survey area using sources and receivers (see also [0009], [0017], [0045], [0057])), wherein the seismic data comprises a plurality of time-space waveforms ([0063]-[0064], [0066]: seismic data includes surface waves and refracted waves (see Fig. 4A)); and
a seismic processor (Fig. 10, item 1005 – ‘processor’) coupled to the seismic acquisition system ([0062], [0082]-[0084]: seismic data is acquired by the processor for analysis, which implies coupling between the components) and configured to:
obtain seismic data associated with the subsurface region of interest (Fig. 3, item 300; [0062]: seismic data is acquired for a survey area (see also [0009], [0017], [0045], [0057])),
determine a plurality of mechanical parameters corresponding to a formation of the subsurface region based, at least in part, on the plurality of time-space waveforms (Fig. 3, items 210; [0063]-[0064], [0066]: seismic data is processed to extract wave properties including dispersion or velocity (mechanical parameters, see also [0046], [0050], [0057], [0059]), with this data being used to estimate visco-elastic parameters in the near surface (see [0056], [0071])),
generate a filtering region ([0059]: subsets of the surface waves and refracted waves datasets corresponding to selected areas of interest (filtering region) are used during independent steps (see also [0064])), and
determine a plurality of attenuation parameters based, at least in part, on the filtering region ([0063]-[0064], [0066]: seismic data is processed to extract wave properties including attenuation (attenuation parameters, see also [0046], [0050], [0057], [0059]), with this data being used to estimate visco-elastic parameters in the near surface (see [0056], [0071])).
Xie (US 20190302292 A1) discloses/teaches:
obtain seismic data associated with the subsurface region of interest (Fig. 5, item 510; [0046]: seismic data for an explored subsurface formation is acquired (see also [0004], [0013]));
determine a plurality of mechanical parameters corresponding to a formation of the subsurface region based, at least in part, on the plurality of time-space waveforms (Fig. 5, items 520 and 530; [0047]-[0048]: a velocity model associated with the explored subsurface formation is obtained by performing a visco-acoustic full waveform inversion (FWI), which implies the determination of mechanical parameters (see [0049]));
determine a plurality of attenuation parameters (Fig. 5, items 520 and 530; [0047]-[0048]: a quality factor associated with the explored subsurface formation is obtained by performing a visco-acoustic full waveform inversion (FWI), which implies the determination of attenuation parameters (see [0049])); and
generate a seismic image of the subsurface region ([0049]: the velocity model and the Q model are used to identify natural resources in the explored subsurface formation (see [0002])).
Sun (US 20160131781 A1, IDS reference) discloses:
“Described below are methods, systems, and computer readable storage media that provide a manner of creating a high-resolution velocity model combining tomography with seismic inversion. To this end, seismic tomography techniques such as migration velocity analysis are used, in some embodiments, to generate a low-resolution background velocity model for a volume representing a geological medium. The low-resolution background velocity model is used, in turn, as an input to jump start impedance inversion and obtain a high-resolution velocity model. The high-resolution velocity model is used for drilling hazard prediction and mitigation by detecting regions of the volume of the geological medium that have velocities anomalously lower than the background trend, since low velocity anomalies can be caused by anomalously high fluid pressure (e.g. drilling hazards)” ([0012]: a high resolution velocity model is created by combining tomography and seismic inversion in order to detect regions having anomalous velocities, the process including a depth domain filtering to remove noise or artifacts in the seismic image gathers (see [0031]-[0032]); the reference does not determine attenuation parameters for attenuating an artifact identified in the plurality of time-space waveforms, but instead, it combines a velocity model and an attenuation model to identify (not attenuate) anomalies (see Fig. 1))).
The closest prior art of record, taken individually or in combination, fail to teach or suggest (see italic text):
“generate a filtering region based on an artifact identified in the plurality of time-space waveforms;
determine a plurality of attenuation parameters based, at least in part, on the filtering region, the attenuation parameters being configured to attenuate the artifact;
filter the time-space waveforms based, at least in part, on the plurality of mechanical parameters and the plurality of attenuation parameters to generate a plurality of filtered time-space waveforms; and
generate a seismic image of the subsurface region using the plurality of filtered time-space waveforms”
in combination with all other limitations within the claim, as claimed and defined by the applicant.
Regarding claims 2, 4-8, 10-12, 14 and 16-20.
They are also distinguished over the prior art of record due to their dependency.
Allowable Subject Matter
Claims 3 and 15 are objected to as being dependent upon a rejected base claim (see Claim Rejections - 35 USC § 101 section), but would be allowable if rewritten in independent form including all of the limitations of the base claim and any intervening claims.
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure.
Lichman, Eugene et al., US 20050043892 A1, Systems and methods of hydrocarbon detection using wavelet energy absorption analysis
Reference discloses using wavelet energy absorption analysis for hydrocarbon detection.
Krohn; Christine E., US 20140039799 A1, Seismic Inversion for Formation Properties and Attentuation Effects
Reference discloses seismic data inversion by estimating source signature for obtaining amplitude attenuation and velocity dispersion effects.
Sun; Yonghe J. et al., US 20230140168 A1, SYSTEM AND METHOD FOR COMPENSATING FOR ATTENUATION OF SEISMIC ENERGY
Reference discloses compensation for seismic energy attenuation.
Any inquiry concerning this communication or earlier communications from the examiner should be directed to LINA CORDERO whose telephone number is (571)272-9969. The examiner can normally be reached 9:30 am - 6:00 pm.
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/LINA CORDERO/Primary Examiner, Art Unit 2857