CTFR 17/691,181 CTFR 78950 DETAILED ACTION Notice of Pre-AIA or AIA Status The present application, 17/691,181, was filed March 10, 2022 and claims priority from Provisional Application 63/159,746, filed March 11, 2021 . The effective filing date is after the AIA date of March 16, 2013, and so the application is being examined under the “first inventor to file” provisions of the AIA. 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. Status of the Application This Final Office Action is in response to Applicant’s communication of March 9, 2026 . Claims 1-13, 15-18 and 20 are pending, of which claims 1, 12, and 18 are independent. In the current amendment, claims 1, 2, 12, 13, and 18 were amended, and claims 14 and 21 were newly cancelled. Claim 19 was previously cancelled. All pending claims have been examined on the merits. Claims 14 and 21 were previously indicated as reciting allowable subject matter, however, relevant prior art has been found and applied. Claim Rejections - 35 USC § 103 07-20-02-aia AIA This application currently names joint inventors . In considering patentability of the claims the examiner presumes that the subject matter of the various claims was commonly owned as of the effective filing date of the claimed invention(s) absent any evidence to the contrary. Applicant is advised of the obligation under 37 CFR 1.56 to point out the inventor and effective filing dates of each claim that was not commonly owned as of the effective filing date of the later invention in order for the examiner to consider the applicability of 35 U.S.C. 102(b)(2)(C) for any potential 35 U.S.C. 102(a)(2) prior art against the later invention. 07-20-aia AIA 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. 07-23-aia AIA The factual inquiries set forth in Graham v. John Deere Co. , 383 U.S. 1, 148 USPQ 459 (1966), that are applied for establishing a background for determining obviousness under 35 U.S.C. 103 are summarized as follows: 1. Determining the scope and contents of the prior art. 2. Ascertaining the differences between the prior art and the claims at issue. 3. Resolving the level of ordinary skill in the pertinent art. 4. Considering objective evidence present in the application indicating obviousness or non-obviousness. 07-21-aia AIA Claim s 1-13, 15-18, and 20 are rejected under 35 U.S.C. 103 as being unpatentable over US-9,528,364-B2 to Samuel et al. (“Samuel”. Eff. Filed on Jan. 25, 2013. Published on Dec. 27, 2016) in view of US 2023/0266500 A1 to Soroush (“Soroush”. Eff. Filed on Jul. 31, 2020), and further in view of US 5,205,164 A to Steiger et al. (“Steiger”. Filed Aug. 31, 1990. Published April 27, 1993) . In regards to claim 1, A method for monitoring wellbore integrity throughout a wellbore lifecycle using modeling techniques comprising: (See Samuel, col. 6, lines 30-36: “In step 110, the method 100 determines whether the entire life cycle of the well is complete. If the entire life cycle of the well is not complete, then the method 100 returns to step 102 where the well temperature and pressure are updated based on a new set of real-time data measured for the well. If the entire life cycle of the well is complete, then the method 100 ends.”) drilling the wellbore, wherein drilling is part of a drilling phase of a life cycle of the wellbore, wherein the life cycle of the wellbore includes the drilling phase, a completion phase, a stimulation phase, a production phase, and an injection phase; (See Samuel, col. 3, lines 52-65: “Quantifying the complexity of well integrity can be based on physical reasoning and can be characterized with safety factors for load conditions. This will provide additional insight about the severity of risk involved. The present disclosure therefore, provides a coupled engineering analysis. This methodology puts the engineering calculations under one quantifiable value to test the susceptibility of the string under various conditions. The load profiles based on the top of the cement, production and injection operations, and the history of the well are important to ensure the integrity of the well . For example, sustained annulus pressures in the annuli are an indication of barrier failures, which, in turn, affects the integrity of the casing, tubing, and well as a whole.”) (See Samuel, col. 5, lines 56-65: “Referring now to FIG. 1, a flow diagram of one embodiment of a method 100 for implementing the present disclosure is illustrated. The method 100 performs a coupled engineering analysis for well integrity management during all operations throughout the life of the well starting from drilling, through completion and later production . Drilling activities are related to operations such as tripping in, tripping out, drilling, sliding, backreaming and other operations . The operational parameters are monitored such as weight on bit, flowrate and fluid related parameters during drilling.”) (See Samuel, col. 6, lines 30-36: “ In step 110, the method 100 determines whether the entire life cycle of the well is complete . If the entire life cycle of the well is not complete, then the method 100 returns to step 102 where the well temperature and pressure are updated based on a new set of real-time data measured for the well. If the entire life cycle of the well is complete, then the method 100 ends .”) performing drilling phase analysis, wherein drilling phase analysis includes determining second input data associated with the wellbore; (See Samuel, col. 6, line 65 to col. 7, line 5: “I n step 210, the method 200 determines if the integrity determination for the casing, wellbore, surface equipment and drillstring is complete . If the integrity determination is not complete, then the method 200 returns to steps 202-208 until the integrity determination is complete for the casing, wellbore, surface equipment and drillstring. If the integrity determination is complete, then the method 200 returns to step 104 in FIG. 1.”) determining drilling in-situ stresses of the wellbore during the drilling phase; (See Samuel, col. 6, lines 58-64: “In step 208, the drill string integrity is determined using techniques well known in the art. The drill string integrity is used to estimate the stresses, fatigue limits, buckling conditions, and stretching along with the other operating parameters of the drill string and to prevent any loss of drill string in the well bore due to material failure or differential sticking.”) determining a drilling phase mud window; (See Samuel, col. 6, lines 48-52: “In step 204, the well bore integrity is determined using techniques well known in the art. The well bore integrity is used to maintain the well bore within the operating mud weight window, and prevent losing the well bore due to excess pressure at the bottom and complete loss of mud or a well bore collapse .”) utilizing the drilling in-situ stresses and the drilling phase mud window to create an updated wellbore integrity model; (See Samuel, col.3, line 67 to col.4, line 15: “The coupled engineering analyses may address various parameters such as wellhead movement, annular pressure buildup, maximum allowable surface pressure, temperature and pressure effects on well integrity, casing wear, corrosion, erosion, zonal isolation and a tubing or casing safety factor. The results of this analysis suggest that well integrity should be monitored in real time so that the engineering calculations can be calibrated for better prediction, thereby reducing risk factors under different discrete operation scenarios . The estimation of the risk and risk factors are essential at the start of a project. Due to uncertainties involved while drilling, these factors need to be updated with all available data . The coupled engineering analysis is carried out to prevent erroneous results when considered in isolation . Individual risk factors are estimated to arrive at a comprehensive unified approach. Individual risk factors also provide background risk estimates.”) predicting from the updated wellbore integrity model whether there is a first issue with the wellbore, wherein the updated wellbore integrity model utilizes at least one of the following: soil mechanics, fluid flow, or thermal expansion to predict the first issue; (See Samuel, col.5, line 56 to col.6, line 9: “Referring now to FIG. 1, a flow diagram of one embodiment of a method 100 for implementing the present disclosure is illustrated. The method 100 performs a coupled engineering analysis for well integrity management during all operations throughout the life of the well starting from drilling, through completion and later production. Drilling activities are related to operations such as tripping in, tripping out, drilling, sliding, backreaming and other operations. The operational parameters are monitored such as weight on bit, flowrate and fluid related parameters during drilling . The completion activities are related to completion and workover operations to check the tubing related integrity along with the integrity of other related downhole completion tools. It also affects the casing exposed to completion operation and fluid . The production activities are related to production of fluids such as oil, gas and water . The production operation may affect the casing and tubing due to corrosion and erosion. The coupled engineering analysis will couple all these underlying operations and the calculation of one parameter will affect the other calculations in the relevant loop.”) However, under a conservative interpretation of Samuel , it could be argued that Samuel does not explicitly teach the italicized portions below, which are taught by Soroush : creating an initial wellbore integrity model that determines a geomechanical stability of a wellbore for drilling, the wellbore for harvesting fluid hydrocarbons, (See Soroush, para. [0003]: “To ensure safe and cost-effective drilling operations, pre-drill and real-time determination of the rock properties, field stresses and pore pressure, and consequently the safe operating mud weight window is an added value. The common practice in the oil and gas industry is to develop pre-drill wellbore stability models including pore pressure gradient (PPG), collapse gradient (CG) and fracture gradient (FG). The prerequisite for a wellbore stability model is developing a one dimensional geomechanical model that includes continuous profiles for rock formations' mechanical properties, which can include: Young's Modulus, YM; Poisson's Ratio, PR; Uniaxial Compressive Strength, UCS; Friction Angle (FA), pore pressure (Pp), vertical stress (Sv), minimum horizontal stress (Shmin) and maximum horizontal stress (SHmax).”) wherein creating the initial wellbore integrity model includes determining the wellbore and determining first input data of a subsurface into which the wellbore is planned; (See Soroush, para. [0094]: “ As shown in FIG. 4, one example of a practical embodiment of a drilling system 400 includes a computer 410 that receives EDR data 412 and vibration data from a vibration transducer 422 that has been affixed to a drill bit unit 420 . The computer 410 is programmed to run the AI system to generate geomechanical and wellbore stability models and to generate useful information based there, such as a mud weight window . In a real time embodiment, the computer can supply control information to a SCADA system associated with a drilling rig 432 to generate mud formulations that comply with a calculated mud weight window as the wellbore 430 is being drilled. In a practical application, the model can be used to generate requirements for a mud weight window at the specific bit location based on the geomechanical model. A mud meeting the requirements of the mud weight window can then be generated.”) performing a second phase of the wellbore; and performing second phase analysis, wherein the second phase analysis includes determining third input data associated with the wellbore during at least one of the following: the completion phase, the stimulation phase, the production phase, or the injection phase. (See Soroush, para. [0094]: “As shown in FIG. 4, one example of a practical embodiment of a drilling system 400 includes a computer 410 that receives EDR data 412 and vibration data from a vibration transducer 422 that has been affixed to a drill bit unit 420. The computer 410 is programmed to run the AI system to generate geomechanical and wellbore stability models and to generate useful information based there, such as a mud weight window. In a real time embodiment, the computer can supply control information to a SCADA system associated with a drilling rig 432 to generate mud formulations that comply with a calculated mud weight window as the wellbore 430 is being drilled . In a practical application, the model can be used to generate requirements for a mud weight window at the specific bit location based on the geomechanical model. A mud meeting the requirements of the mud weight window can then be generated.”) The Examiner interprets that Soroush’s disclosure that “ In a real time embodiment, the computer can supply control information to a SCADA system associated with a drilling rig 432 to generate mud formulations that comply with a calculated mud weight window as the wellbore 430 is being drilled ” reads upon the claimed features. It would have been obvious to a person having ordinary skill in the art (PHOSITA), before the effective filing date of the claimed invention, to include in the method and system for “Well integrity management using coupled engineering analysis”, as taught by Samuel , with the method and system for “Geomechanics and wellbore stability modeling using drilling dynamics data”, as further taught by Soroush , because Soroush teaches in para. [0114]-[0119] that the benefits of using wellbore stability model include: (See Soroush, para. [0114]-[0119]: “The benefits of the system may include: [0115] Providing PPG, CG and FG from surface/mudline all the way to the bottom of the well, [0116] Saving significant time and money on logging (specifically for the overburden where no petrophysical analysis needed), [0117] Providing real-time opportunity for risk identification and mitigation (increases safety in rig-site), [0118] Minimizing non-productive time (NPT) related to influx, lost circulation, and formation collapse, and [0119] establishing calibrated geomechanical model for any prospective operations (completions, stimulation, reservoir modeling, production etc.”) However, under a conservative interpretation of Samuel in view of Soroush , it could be argued that Samuel in view of Soroush does not explicitly teach the italicized features below, which are taught by Steiger : in response to predicting the first issue with the wellbore, performing a first corrective action to the first issue, wherein the first corrective action includes introducing a fluid into the wellbore to alter the mud weight ; (See Steiger, col. 1, lines 15-32: “Subsurface formations encountered in oil and gas drilling are compacted under in situ stresses due to overburden weight, tectonic effects, confinement and pore pressure. When a hole is drilled in a formation, the wellbore rock is subjected to increased shear stresses due to a reduction in confinement at the wellbore face by removal of the rock from the hole. Compressive failure of the rock near the wellbore will occur if the rock does not have sufficient strength to support the increased shear stresses imposed upon it . However, if the hole is filled with drilling fluid with sufficient density (mud weight) to increase the wellbore pressure or confining pressure to a proper level, the shear stresses imposed on the wellbore rock will be reduced and the hole will remain stable . If the wellbore pressure is increased too much, lost circulation or hydraulic fracturing of the formation will occur as a result of tensile failure of the wellbore rock.”) It would have been obvious to a person having ordinary skill in the art (PHOSITA), before the effective filing date of the claimed invention, to include in the method and system for “Well integrity management using coupled engineering analysis”, as taught by Samuel , with the method and system for “Geomechanics and wellbore stability modeling using drilling dynamics data”, as further taught by Soroush , and to further include the “Methods for determining in situ shale strengths, elastic properties, pore pressures, formation stresses, and drilling fluid parameters” as taught by Steiger , because all three references are in the same art of oil well integrity and/or stability by using mathematical models, and further because Steiger expressly teaches “methods for determining the in situ strengths, pore pressures, elastic properties and formation stresses, of low permeability rocks such as shales and for determining desired parameters for fluids used in drilling wellbores”. (See Steiger , col. 1, lines 9-14). In regards to claim 2, 2. The method of claim 1, further comprising: determining second phase in-situ stresses of the wellbore during the drilling phase; determining a second phase mud window; updating the updated wellbore integrity model based on the third input data, the second phase in-situ stresses, and the second phase mud window; predicting from the updated wellbore integrity model whether there is a second issue with the wellbore during the second phase; and in response to predicting the second issue with the wellbore, performing a second corrective action to correct the second issue. The Examiner interprets that these claimed features are “mere duplication of parts” of the method steps recited in claim 1. Duplication of Parts – MPEP § 2144.04(IV)(B) In re Harza, 274 F.2d 669, 124 USPQ 378 (CCPA 1960) (Claims at issue were directed to a water-tight masonry structure wherein a water seal of flexible material fills the joints which form between adjacent pours of concrete. The claimed water seal has a "web" which lies in the joint, and a plurality of "ribs" projecting outwardly from each side of the web into one of the adjacent concrete slabs. The prior art disclosed a flexible water stop for preventing passage of water between masses of concrete in the shape of a plus sign (+). Although the reference did not disclose a plurality of ribs, the court held that mere duplication of parts has no patentable significance unless a new and unexpected result is produced.). In regards to claim 3, 3. The method of claim 1, wherein the second phase includes at least one of the following: the completion phase, the stimulation phase, the production phase, or the injection phase. (See Samuel, col.5, line 56 to col.6, line 9: “Referring now to FIG. 1, a flow diagram of one embodiment of a method 100 for implementing the present disclosure is illustrated. The method 100 performs a coupled engineering analysis for well integrity management during all operations throughout the life of the well starting from drilling, through completion and later production . Drilling activities are related to operations such as tripping in, tripping out, drilling, sliding, backreaming and other operations. The operational parameters are monitored such as weight on bit, flowrate and fluid related parameters during drilling. The completion activities are related to completion and workover operations to check the tubing related integrity along with the integrity of other related downhole completion tools . It also affects the casing exposed to completion operation and fluid. The production activities are related to production of fluids such as oil, gas and water . The production operation may affect the casing and tubing due to corrosion and erosion. The coupled engineering analysis will couple all these underlying operations and the calculation of one parameter will affect the other calculations in the relevant loop.”) In regards to claim 4, 4. The method of claim 1, wherein the first corrective action includes at least one of the following: providing computer output depicting hoop stress around the wellbore, providing computer output depicting radial stress around the wellbore, providing computer output depicting an overburden stress around the wellbore, providing computer output depicting strain distribution around the wellbore, providing computer output estimating the pressure along a depth of the wellbore, introducing fluid into the wellbore to alter mud weight of mud in the wellbore, or determining a number of casings to place in the wellbore and a depth of a casing in the wellbore. (See Soroush, para. [0108]-[0112]: “Parameters that are extracted by the analysis can include: Pore pressure, In-situ stresses (Sv, Shmin, and SHmin), Collapse gradient (CG), and Fracture gradient (initiation, FGi; propagation, FGp; and reopening, FGre”) (See Soroush, para. [0113]: “The methodology combines the developed knowledge related to bit-rock interaction with signal processing and artificial intelligence to estimate geomechanical properties from drilling dynamics data measured downhole and acquired at a high sampling rate. In one embodiment, the system includes a software package that uses drilling dynamics data to produce profiles of rock properties, pore pressure and principal stresses along the borehole in real-time and post-drill. It provides 1-D geomechanical and wellbore stability models along vertical, deviated, or horizontal wells.”) (See Steiger, col. 1, lines 15-32: “Subsurface formations encountered in oil and gas drilling are compacted under in situ stresses due to overburden weight, tectonic effects, confinement and pore pressure. When a hole is drilled in a formation, the wellbore rock is subjected to increased shear stresses due to a reduction in confinement at the wellbore face by removal of the rock from the hole. Compressive failure of the rock near the wellbore will occur if the rock does not have sufficient strength to support the increased shear stresses imposed upon it . However, if the hole is filled with drilling fluid with sufficient density (mud weight) to increase the wellbore pressure or confining pressure to a proper level, the shear stresses imposed on the wellbore rock will be reduced and the hole will remain stable . If the wellbore pressure is increased too much, lost circulation or hydraulic fracturing of the formation will occur as a result of tensile failure of the wellbore rock.”) In regards to claim 5, 5. The method of claim 1, wherein the second input data includes at least one of the following taken during the drilling phase: wellbore depth data, dimension data of a casing in the wellbore, dimension data of cement in the wellbore, minimum horizontal stress gradient data, maximum horizontal stress gradient data, overburden stress gradient data, pore pressure gradient data, fluid pressure gradient data, mud weight gradient data, seismic data, shear acoustic velocity data, compressive acoustic velocity data, porosity data, density data, elastic moduli data, Young’s modulus data, Poisson’s ratio data, rock strength data, or rock stress data. (See Soroush, para. [0095]-[0102]: “A methodology used to conduct post-mortem and real-time wellbore stability analysis based on drilling dynamics data. The subject drilling data can include: Depth, Weight-on-bit, Torque-on-bit, ROP Bit angular velocity, Fluid pressure, and Three-axis acceleration measured downhole near the bit at a high sampling rate.”) In regards to claim 6, 6. The method of claim 1, wherein creating the updated wellbore integrity model includes benchmarking at least one of the following: geometry, boundary conditions, and mesh distribution to publish analytical solutions, and wherein the updated wellbore integrity model includes forecasts of stimulation and production decline curves to estimate the pressure along a predetermined depth of the wellbore over time. (See Soroush, para. [0122]: “Based on the available data from several offset wells, high depth resolution 1D geomechanical models, including rock properties, pore pressure and in-situ stresses can be developed based on log-based classical analytical methods. These models can be used as benchmark to train the algorithms and optimized them to the specific type of formations presents in the study fields.”) In regards to claim 7, 7. The method of claim 1, further comprising determining a mud weight window for the wellbore along a depth of the wellbore during the drilling phase, and wherein the mud weight window is utilized to update the updated wellbore integrity model. (See Soroush, para. [0016]: “Requirements for a mud weight window at the specific bit location are generated based on the geomechanical model. A mud meeting the requirements of the mud weight window is generated.”) (See Soroush, para. [0094]: “As shown in FIG. 4 , one example of a practical embodiment of a drilling system 400 includes a computer 410 that receives EDR data 412 and vibration data from a vibration transducer 422 that has been affixed to a drill bit unit 420. The computer 410 is programmed to run the AI system to generate geomechanical and wellbore stability models and to generate useful information based there, such as a mud weight window. In a real time embodiment, the computer can supply control information to a SCADA system associated with a drilling rig 432 to generate mud formulations that comply with a calculated mud weight window as the wellbore 430 is being drilled. In a practical application, the model can be used to generate requirements for a mud weight window at the specific bit location based on the geomechanical model. A mud meeting the requirements of the mud weight window can then be generated.”) In regards to claim 8, 8. The method of claim 1, wherein the second phase is the completion phase and wherein the third input data includes data for the completion phase, including at least one of the following: post drill hole shape data, stress distribution data, material properties of a casing in the wellbore , material properties of cement in the wellbore, fluid properties data stress data based on fluid changes and stress data independent of fluid changes. (See Soroush, para. [0114]: “ The wellbore stability model provides a safe operating mud weight window for drilling operation and help optimizing the mud design (pressure and composition) and casing design . A reliable safe operating mud weight window is required for safe and economic drilling of any wells. It helps significantly to identify and mitigate drilling hazards, minimize non-productive time (NPT) and reduce the cost of drilling. The methodology provides safe operating mud weigh window without requirement of wireline logging or LWD, by using only drilling dynamics data which are typically available.”) In regards to claim 9, 9. The method of claim 1, wherein the second phase is the injection phase and wherein the method further comprises determining injection in-situ stresses along a depth of the wellbore during the injection phase, wherein the injection in-situ stresses include at least one of the following: an overburden stress in the wellbore, minimum horizontal stress, maximum horizontal stress , orientation of horizontal stresses, or pore pressure. (See Soroush, para. [0003]: “The prerequisite for a wellbore stability model is developing a one dimensional geomechanical model that includes continuous profiles for rock formations' mechanical properties, which can include: Young's Modulus, YM; Poisson's Ratio, PR; Uniaxial Compressive Strength, UCS; Friction Angle (FA), pore pressure (Pp), vertical stress (Sv), minimum horizontal stress (Shmin) and maximum horizontal stress (SHmax) .”) (See Soroush, para. [0041]: “It is followed by estimation of the minimum horizontal stress (Sh) using the “Pure Friction Failure” model, since it yields the best matching results with the drilling experiences and fracturing results: Sh=(1, sin(FA))+P p sin (FA)”) (See Soroush, para. [0042]: “The magnitude of the maximum horizontal stress (SH) is estimated using the Mohr-Coulomb failure criterion using the following equation and is calibrated to the wellbore failure evidence captured from image logs and drilling incidents reports.”) In regards to claim 10, 10. The method of claim 1, wherein performing the drilling phase analysis, determining the drilling in-situ stresses, determining the drilling phase mud window, creating the updated wellbore integrity model, and predicting whether there is the first issue with the wellbore are repeated throughout the drilling phase. (See Samuel, claim 3: “The method of claim 1, further comprising repeating the steps in claim 1 until a life cycle of the well is complete.”) In regards to claim 11, 11. The method of claim 1, further comprising updating the updated wellbore integrity model for each phase of the life cycle of the wellbore. (See Samuel, col. 6, lines 30-36: “In step 110, the method 100 determines whether the entire life cycle of the well is complete. If the entire life cycle of the well is not complete, then the method 100 returns to step 102 where the well temperature and pressure are updated based on a new set of real-time data measured for the well. If the entire life cycle of the well is complete, then the method 100 ends.”) In regards to claim 12, 12. A system for monitoring wellbore integrity throughout a wellbore lifecycle using modeling techniques comprising: (See Samuel, col. 6, lines 30-36: “In step 110, the method 100 determines whether the entire life cycle of the well is complete. If the entire life cycle of the well is not complete, then the method 100 returns to step 102 where the well temperature and pressure are updated based on a new set of real-time data measured for the well. If the entire life cycle of the well is complete, then the method 100 ends.”) a wellbore drill for drilling a wellbore to harvest fluid hydrocarbons; (See Samuel, col.6, lines 58-64: “ In step 208, the drill string integrity is determined using techniques well known in the art . The drill string integrity is used to estimate the stresses, fatigue limits, buckling conditions, and stretching along with the other operating parameters of the drill string and to prevent any loss of drill string in the well bore due to material failure or differential sticking.”) a sensor for detecting a characteristic of the wellbore; (See Samuel, col.6, line 65 to col.7, line 5: “In step 210, the method 200 determines if the integrity determination for the casing, wellbore, surface equipment and drillstring is complete. If the integrity determination is not complete, then the method 200 returns to steps 202-208 until the integrity determination is complete for the casing, wellbore, surface equipment and drillstring. If the integrity determination is complete, then the method 200 returns to step 104 in FIG. 1.”) The Examiner interprets that it is inherent that sensors produce the data used in Samuel’s steps 208 and 210. a fluid introduction device for introducing fluid into the wellbore; (See Samuel, col.7, lines 16-28: “ In step 304, the tubing integrity is determined using techniques well known in the art. The tubing integrity is used to estimate the stresses, fatigue limits, and metal losses due to corrosion or erosion and to maintain the operating conditions within the specified ranges of temperature and pressure . Use of proper tubing loads is important to estimate the design safety factors and, thereby, the well integrity. Some of the loads that need to be considered are: burst condition due to a tubing leak ( this load can be used for both production and injection scenarios representing high-surface pressure : a worst-case scenario based on gas gradient extending upward from the reservoir pressure at the perforation may also be considered)”) The Examiner interprets that the use of a fluid introduction device is inherent in the “injection scenarios” of Samuel. and a computing device that is coupled to the wellbore drill, wherein the computing device stores logic, that when executed by the computing device, causes the system to perform at least the following: (See Samuel, col.12, lines 30-38: “The present disclosure may be implemented through a computer-executable program of instructions, such as program modules, generally referred to as software applications or application programs executed by a computer. The software may include, for example, routines, programs, objects, components and data structures that perform particular tasks or implement particular abstract data types. The software forms an interface to allow a computer to react according to a source of input.”) cause the wellbore drill to drill the wellbore, wherein drilling is part of a drilling phase of a life cycle of the wellbore, wherein the life cycle of the wellbore includes the drilling phase, a completion phase, a stimulation phase, a production phase, and an injection phase; (See Samuel, col. 3, lines 52-65: “Quantifying the complexity of well integrity can be based on physical reasoning and can be characterized with safety factors for load conditions. This will provide additional insight about the severity of risk involved. The present disclosure therefore, provides a coupled engineering analysis. This methodology puts the engineering calculations under one quantifiable value to test the susceptibility of the string under various conditions. The load profiles based on the top of the cement, production and injection operations, and the history of the well are important to ensure the integrity of the well . For example, sustained annulus pressures in the annuli are an indication of barrier failures, which, in turn, affects the integrity of the casing, tubing, and well as a whole.”) (See Samuel, col. 5, lines 56-65: “Referring now to FIG. 1, a flow diagram of one embodiment of a method 100 for implementing the present disclosure is illustrated. The method 100 performs a coupled engineering analysis for well integrity management during all operations throughout the life of the well starting from drilling, through completion and later production . Drilling activities are related to operations such as tripping in, tripping out, drilling, sliding, backreaming and other operations . The operational parameters are monitored such as weight on bit, flowrate and fluid related parameters during drilling.”) (See Samuel, col. 6, lines 30-36: “ In step 110, the method 100 determines whether the entire life cycle of the well is complete . If the entire life cycle of the well is not complete, then the method 100 returns to step 102 where the well temperature and pressure are updated based on a new set of real-time data measured for the well. If the entire life cycle of the well is complete, then the method 100 ends .”) perform drilling phase analysis, wherein the drilling phase analysis includes determining second input data associated with the wellbore; (See Samuel, col. 6, line 65 to col. 7, line 5: “I n step 210, the method 200 determines if the integrity determination for the casing, wellbore, surface equipment and drillstring is complete . If the integrity determination is not complete, then the method 200 returns to steps 202-208 until the integrity determination is complete for the casing, wellbore, surface equipment and drillstring. If the integrity determination is complete, then the method 200 returns to step 104 in FIG. 1.”) determine drilling in-situ stresses of the wellbore during the drilling phase; (See Samuel, col. 6, lines 58-64: “In step 208, the drill string integrity is determined using techniques well known in the art. The drill string integrity is used to estimate the stresses, fatigue limits, buckling conditions, and stretching along with the other operating parameters of the drill string and to prevent any loss of drill string in the well bore due to material failure or differential sticking.”) determine a drilling phase mud window; (See Samuel, col. 6, lines 48-52: “In step 204, the well bore integrity is determined using techniques well known in the art. The well bore integrity is used to maintain the well bore within the operating mud weight window, and prevent losing the well bore due to excess pressure at the bottom and complete loss of mud or a well bore collapse .”) utilize the drilling in-situ stresses and the drilling phase mud window to create an updated wellbore integrity model; (See Samuel, col.3, line 67 to col.4, line 15: “The coupled engineering analyses may address various parameters such as wellhead movement, annular pressure buildup, maximum allowable surface pressure, temperature and pressure effects on well integrity, casing wear, corrosion, erosion, zonal isolation and a tubing or casing safety factor. The results of this analysis suggest that well integrity should be monitored in real time so that the engineering calculations can be calibrated for better prediction, thereby reducing risk factors under different discrete operation scenarios . The estimation of the risk and risk factors are essential at the start of a project. Due to uncertainties involved while drilling, these factors need to be updated with all available data . The coupled engineering analysis is carried out to prevent erroneous results when considered in isolation . Individual risk factors are estimated to arrive at a comprehensive unified approach. Individual risk factors also provide background risk estimates.”) predict from the updated wellbore integrity model whether there is a first issue with the wellbore, wherein the updated wellbore integrity model utilizes at least one of the following: soil mechanics, fluid flow, or thermal expansion to predict the first issue; (See Samuel, col.5, line 56 to col.6, line 9: “Referring now to FIG. 1, a flow diagram of one embodiment of a method 100 for implementing the present disclosure is illustrated. The method 100 performs a coupled engineering analysis for well integrity management during all operations throughout the life of the well starting from drilling, through completion and later production. Drilling activities are related to operations such as tripping in, tripping out, drilling, sliding, backreaming and other operations. The operational parameters are monitored such as weight on bit, flowrate and fluid related parameters during drilling . The completion activities are related to completion and workover operations to check the tubing related integrity along with the integrity of other related downhole completion tools. It also affects the casing exposed to completion operation and fluid . The production activities are related to production of fluids such as oil, gas and water . The production operation may affect the casing and tubing due to corrosion and erosion. The coupled engineering analysis will couple all these underlying operations and the calculation of one parameter will affect the other calculations in the relevant loop.”) However, under a conservative interpretation of Samuel , it could be argued that Samuel does not explicitly teach the italicized portions below, which are taught by Soroush : create an initial wellbore integrity model that determines a geomechanical stability of the wellbore for drilling, (See Soroush, para. [0003]: “To ensure safe and cost-effective drilling operations, pre-drill and real-time determination of the rock properties, field stresses and pore pressure, and consequently the safe operating mud weight window is an added value. The common practice in the oil and gas industry is to develop pre-drill wellbore stability models including pore pressure gradient (PPG), collapse gradient (CG) and fracture gradient (FG). The prerequisite for a wellbore stability model is developing a one dimensional geomechanical model that includes continuous profiles for rock formations' mechanical properties, which can include: Young's Modulus, YM; Poisson's Ratio, PR; Uniaxial Compressive Strength, UCS; Friction Angle (FA), pore pressure (Pp), vertical stress (Sv), minimum horizontal stress (Shmin) and maximum horizontal stress (SHmax).”) wherein creating the initial wellbore integrity model includes determining the wellbore and determining first input data of a subsurface into which the wellbore is planned, wherein at least a portion of the first input data is received from the sensor; (See Soroush, para. [0094]: “ As shown in FIG. 4, one example of a practical embodiment of a drilling system 400 includes a computer 410 that receives EDR data 412 and vibration data from a vibration transducer 422 that has been affixed to a drill bit unit 420 . The computer 410 is programmed to run the AI system to generate geomechanical and wellbore stability models and to generate useful information based there, such as a mud weight window . In a real time embodiment, the computer can supply control information to a SCADA system associated with a drilling rig 432 to generate mud formulations that comply with a calculated mud weight window as the wellbore 430 is being drilled. In a practical application, the model can be used to generate requirements for a mud weight window at the specific bit location based on the geomechanical model. A mud meeting the requirements of the mud weight window can then be generated.”) perform a second phase of the wellbore; and perform second phase analysis, wherein the second phase analysis includes determining third input data associated with the wellbore during at least one of the following: the completion phase, the stimulation phase, the production phase, or the injection phase. (See Soroush, para. [0094]: “As shown in FIG. 4, one example of a practical embodiment of a drilling system 400 includes a computer 410 that receives EDR data 412 and vibration data from a vibration transducer 422 that has been affixed to a drill bit unit 420. The computer 410 is programmed to run the AI system to generate geomechanical and wellbore stability models and to generate useful information based there, such as a mud weight window. In a real time embodiment, the computer can supply control information to a SCADA system associated with a drilling rig 432 to generate mud formulations that comply with a calculated mud weight window as the wellbore 430 is being drilled . In a practical application, the model can be used to generate requirements for a mud weight window at the specific bit location based on the geomechanical model. A mud meeting the requirements of the mud weight window can then be generated.”) The Examiner interprets that Soroush’s disclosure that “ In a real time embodiment, the computer can supply control information to a SCADA system associated with a drilling rig 432 to generate mud formulations that comply with a calculated mud weight window as the wellbore 430 is being drilled ” reads upon the claimed features. It would have been obvious to a person having ordinary skill in the art (PHOSITA), before the effective filing date of the claimed invention, to include in the method and system for “Well integrity management using coupled engineering analysis”, as taught by Samuel , with the method and system for “Geomechanics and wellbore stability modeling using drilling dynamics data”, as further taught by Soroush , because Soroush teaches in para. [0114]-[0119] that the benefits of using wellbore stability model include: (See Soroush, para. [0114]-[0119]: “The benefits of the system may include: [0115] Providing PPG, CG and FG from surface/mudline all the way to the bottom of the well, [0116] Saving significant time and money on logging (specifically for the overburden where no petrophysical analysis needed), [0117] Providing real-time opportunity for risk identification and mitigation (increases safety in rig-site), [0118] Minimizing non-productive time (NPT) related to influx, lost circulation, and formation collapse, and [0119] establishing calibrated geomechanical model for any prospective operations (completions, stimulation, reservoir modeling, production etc.”) However, under a conservative interpretation of Samuel in view of Soroush , it could be argued that Samuel in view of Soroush does not explicitly teach the italicized features below, which are taught by Steiger : in response to predicting the first issue with the wellbore, performing a first corrective action to the first issue, wherein the first corrective action includes introducing a fluid into the wellbore to alter the mud weight ; (See Steiger, col. 1, lines 15-32: “Subsurface formations encountered in oil and gas drilling are compacted under in situ stresses due to overburden weight, tectonic effects, confinement and pore pressure. When a hole is drilled in a formation, the wellbore rock is subjected to increased shear stresses due to a reduction in confinement at the wellbore face by removal of the rock from the hole. Compressive failure of the rock near the wellbore will occur if the rock does not have sufficient strength to support the increased shear stresses imposed upon it . However, if the hole is filled with drilling fluid with sufficient density (mud weight) to increase the wellbore pressure or confining pressure to a proper level, the shear stresses imposed on the wellbore rock will be reduced and the hole will remain stable . If the wellbore pressure is increased too much, lost circulation or hydraulic fracturing of the formation will occur as a result of tensile failure of the wellbore rock.”) It would have been obvious to a person having ordinary skill in the art (PHOSITA), before the effective filing date of the claimed invention, to include in the method and system for “Well integrity management using coupled engineering analysis”, as taught by Samuel , with the method and system for “Geomechanics and wellbore stability modeling using drilling dynamics data”, as further taught by Soroush , and to further include the “Methods for determining in situ shale strengths, elastic properties, pore pressures, formation stresses, and drilling fluid parameters” as taught by Steiger , because all three references are in the same art of oil well integrity and/or stability by using mathematical models, and further because Steiger expressly teaches “methods for determining the in situ strengths, pore pressures, elastic properties and formation stresses, of low permeability rocks such as shales and for determining desired parameters for fluids used in drilling wellbores”. (See Steiger , col. 1, lines 9-14). In regards to claim 13, it is rejected on the same grounds as claim 2. In regards to claim 14, it has been cancelled. In regards to claim 15, 15. (Original) The system of claim 12, wherein the sensor includes at least one of the following: a pressure sensor, a chemical sensor, an acoustic sensor, a temperature sensor, an optical sensor, or a piezoelectric sensor . (See Soroush, para. [0015]: “The disadvantages of the prior art are overcome by the present invention which, in one aspect, is a method of generating a geomechanical model of a wellbore, in which at least one vibration sensor is affixed to a drill bit unit. Electronic drilling recorder data regarding drilling of the wellbore is received. Bit vibration data is received from the vibration sensor.”) The Examiner interprets that the claimed piezoelectric sensor is a vibration sensor. In regards to claim 16, it is rejected on the same grounds as claim 3. In regards to claim 17, it is rejected on the same grounds as claim 4. In regards to claim 18, 18. A non-transitory computer-readable medium for monitoring wellbore integrity throughout a wellbore lifecycle using modeling techniques that stores logic that, when executed by a computing device, causes the computing device to perform at least the following: (See Samuel, col. 6, lines 30-36: “In step 110, the method 100 determines whether the entire life cycle of the well is complete. If the entire life cycle of the well is not complete, then the method 100 returns to step 102 where the well temperature and pressure are updated based on a new set of real-time data measured for the well. If the entire life cycle of the well is complete, then the method 100 ends.”) cause a wellbore drill to drill the wellbore, wherein drilling is part of a drilling phase of a life cycle of the wellbore, wherein the life cycle of the wellbore includes the drilling phase, a completion phase, a stimulation phase, a production phase, and an injection phase; (See Samuel, col. 3, lines 52-65: “Quantifying the complexity of well integrity can be based on physical reasoning and can be characterized with safety factors for load conditions. This will provide additional insight about the severity of risk involved. The present disclosure therefore, provides a coupled engineering analysis. This methodology puts the engineering calculations under one quantifiable value to test the susceptibility of the string under various conditions. The load profiles based on the top of the cement, production and injection operations, and the history of the well are important to ensure the integrity of the well . For example, sustained annulus pressures in the annuli are an indication of barrier failures, which, in turn, affects the integrity of the casing, tubing, and well as a whole.”) (See Samuel, col. 5, lines 56-65: “Referring now to FIG. 1, a flow diagram of one embodiment of a method 100 for implementing the present disclosure is illustrated. The method 100 performs a coupled engineering analysis for well integrity management during all operations throughout the life of the well starting from drilling, through completion and later production . Drilling activities are related to operations such as tripping in, tripping out, drilling, sliding, backreaming and other operations . The operational parameters are monitored such as weight on bit, flowrate and fluid related parameters during drilling.”) (See Samuel, col. 6, lines 30-36: “ In step 110, the method 100 determines whether the entire life cycle of the well is complete . If the entire life cycle of the well is not complete, then the method 100 returns to step 102 where the well temperature and pressure are updated based on a new set of real-time data measured for the well. If the entire life cycle of the well is complete, then the method 100 ends .”) perform drilling phase analysis, wherein the drilling phase analysis includes determining second input data associated with the wellbore; (See Samuel, col. 6, line 65 to col. 7, line 5: “I n step 210, the method 200 determines if the integrity determination for the casing, wellbore, surface equipment and drillstring is complete . If the integrity determination is not complete, then the method 200 returns to steps 202-208 until the integrity determination is complete for the casing, wellbore, surface equipment and drillstring. If the integrity determination is complete, then the method 200 returns to step 104 in FIG. 1.”) determine drilling in-situ stresses of the wellbore during the drilling phase; (See Samuel, col. 6, lines 58-64: “In step 208, the drill string integrity is determined using techniques well known in the art. The drill string integrity is used to estimate the stresses, fatigue limits, buckling conditions, and stretching along with the other operating parameters of the drill string and to prevent any loss of drill string in the well bore due to material failure or differential sticking.”) determine a drilling phase mud window; (See Samuel, col. 6, lines 48-52: “In step 204, the well bore integrity is determined using techniques well known in the art. The well bore integrity is used to maintain the well bore within the operating mud weight window, and prevent losing the well bore due to excess pressure at the bottom and complete loss of mud or a well bore collapse .”) utilize the drilling in-situ stresses and the drilling phase mud window to create an updated wellbore integrity model; (See Samuel, col.3, line 67 to col.4, line 15: “The coupled engineering analyses may address various parameters such as wellhead movement, annular pressure buildup, maximum allowable surface pressure, temperature and pressure effects on well integrity, casing wear, corrosion, erosion, zonal isolation and a tubing or casing safety factor. The results of this analysis suggest that well integrity should be monitored in real time so that the engineering calculations can be calibrated for better prediction, thereby reducing risk factors under different discrete operation scenarios . The estimation of the risk and risk factors are essential at the start of a project. Due to uncertainties involved while drilling, these factors need to be updated with all available data . The coupled engineering analysis is carried out to prevent erroneous results when considered in isolation . Individual risk factors are estimated to arrive at a comprehensive unified approach. Individual risk factors also provide background risk estimates.”) predict from the initial wellbore integrity model whether there is a first issue with the wellbore, wherein the updated wellbore integrity model utilizes at least one of the following: soil mechanics, fluid flow, or thermal expansion to predict the first issue, and wherein performing drilling phase analysis, determining drilling in-situ stresses, determining the drilling phase mud window, creating the updated wellbore integrity model, and predicting whether there is the first issue with the wellbore are repeated throughout the drilling phase; (See Samuel, col.5, line 56 to col.6, line 9: “Referring now to FIG. 1, a flow diagram of one embodiment of a method 100 for implementing the present disclosure is illustrated. The method 100 performs a coupled engineering analysis for well integrity management during all operations throughout the life of the well starting from drilling, through completion and later production. Drilling activities are related to operations such as tripping in, tripping out, drilling, sliding, backreaming and other operations. The operational parameters are monitored such as weight on bit, flowrate and fluid related parameters during drilling . The completion activities are related to completion and workover operations to check the tubing related integrity along with the integrity of other related downhole completion tools. It also affects the casing exposed to completion operation and fluid . The production activities are related to production of fluids such as oil, gas and water . The production operation may affect the casing and tubing due to corrosion and erosion. The coupled engineering analysis will couple all these underlying operations and the calculation of one parameter will affect the other calculations in the relevant loop.”) However, under a conservative interpretation of Samuel , it could be argued that Samuel does not explicitly teach the italicized portions below, which are taught by Soroush : create an initial wellbore integrity model that determines a geomechanical stability of a wellbore for drilling and harvesting fluid hydrocarbons, (See Soroush, para. [0003]: “To ensure safe and cost-effective drilling operations, pre-drill and real-time determination of the rock properties, field stresses and pore pressure, and consequently the safe operating mud weight window is an added value. The common practice in the oil and gas industry is to develop pre-drill wellbore stability models including pore pressure gradient (PPG), collapse gradient (CG) and fracture gradient (FG). The prerequisite for a wellbore stability model is developing a one dimensional geomechanical model that includes continuous profiles for rock formations' mechanical properties, which can include: Young's Modulus, YM; Poisson's Ratio, PR; Uniaxial Compressive Strength, UCS; Friction Angle (FA), pore pressure (Pp), vertical stress (Sv), minimum horizontal stress (Shmin) and maximum horizontal stress (SHmax).”) wherein creating the initial wellbore integrity model includes determining the wellbore and determining first input data of a subsurface into which the wellbore is planned; (See Soroush, para. [0094]: “ As shown in FIG. 4, one example of a practical embodiment of a drilling system 400 includes a computer 410 that receives EDR data 412 and vibration data from a vibration transducer 422 that has been affixed to a drill bit unit 420 . The computer 410 is programmed to run the AI system to generate geomechanical and wellbore stability models and to generate useful information based there, such as a mud weight window . In a real time embodiment, the computer can supply control information to a SCADA system associated with a drilling rig 432 to generate mud formulations that comply with a calculated mud weight window as the wellbore 430 is being drilled. In a practical application, the model can be used to generate requirements for a mud weight window at the specific bit location based on the geomechanical model. A mud meeting the requirements of the mud weight window can then be generated.”) perform a second phase of the wellbore; and perform second phase analysis, wherein the second phase analysis includes determining third input data associated with the wellbore during at least one of the following: the completion phase, the stimulation phase, the production phase, or the injection phase, wherein the updated wellbore integrity model is updated throughout the life cycle of the wellbore. (See Soroush, para. [0094]: “As shown in FIG. 4, one example of a practical embodiment of a drilling system 400 includes a computer 410 that receives EDR data 412 and vibration data from a vibration transducer 422 that has been affixed to a drill bit unit 420. The computer 410 is programmed to run the AI system to generate geomechanical and wellbore stability models and to generate useful information based there, such as a mud weight window. In a real time embodiment, the computer can supply control information to a SCADA system associated with a drilling rig 432 to generate mud formulations that comply with a calculated mud weight window as the wellbore 430 is being drilled . In a practical application, the model can be used to generate requirements for a mud weight window at the specific bit location based on the geomechanical model. A mud meeting the requirements of the mud weight window can then be generated.”) The Examiner interprets that Soroush’s disclosure that “ In a real time embodiment, the computer can supply control information to a SCADA system associated with a drilling rig 432 to generate mud formulations that comply with a calculated mud weight window as the wellbore 430 is being drilled ” reads upon the claimed features. It would have been obvious to a person having ordinary skill in the art (PHOSITA), before the effective filing date of the claimed invention, to include in the method and system for “Well integrity management using coupled engineering analysis”, as taught by Samuel , with the method and system for “Geomechanics and wellbore stability modeling using drilling dynamics data”, as further taught by Soroush , because Soroush teaches in para. [0114]-[0119] that the benefits of using wellbore stability model include: (See Soroush, para. [0114]-[0119]: “The benefits of the system may include: [0115] Providing PPG, CG and FG from surface/mudline all the way to the bottom of the well, [0116] Saving significant time and money on logging (specifically for the overburden where no petrophysical analysis needed), [0117] Providing real-time opportunity for risk identification and mitigation (increases safety in rig-site), [0118] Minimizing non-productive time (NPT) related to influx, lost circulation, and formation collapse, and [0119] establishing calibrated geomechanical model for any prospective operations (completions, stimulation, reservoir modeling, production etc.”) However, under a conservative interpretation of Samuel in view of Soroush , it could be argued that Samuel in view of Soroush does not explicitly teach the italicized features below, which are taught by Steiger : in response to predicting the first issue with the wellbore, performing a first corrective action to the first issue, wherein the first corrective action includes introducing a fluid into the wellbore to alter the mud weight ; (See Steiger, col. 1, lines 15-32: “Subsurface formations encountered in oil and gas drilling are compacted under in situ stresses due to overburden weight, tectonic effects, confinement and pore pressure. When a hole is drilled in a formation, the wellbore rock is subjected to increased shear stresses due to a reduction in confinement at the wellbore face by removal of the rock from the hole. Compressive failure of the rock near the wellbore will occur if the rock does not have sufficient strength to support the increased shear stresses imposed upon it . However, if the hole is filled with drilling fluid with sufficient density (mud weight) to increase the wellbore pressure or confining pressure to a proper level, the shear stresses imposed on the wellbore rock will be reduced and the hole will remain stable . If the wellbore pressure is increased too much, lost circulation or hydraulic fracturing of the formation will occur as a result of tensile failure of the wellbore rock.”) It would have been obvious to a person having ordinary skill in the art (PHOSITA), before the effective filing date of the claimed invention, to include in the method and system for “Well integrity management using coupled engineering analysis”, as taught by Samuel , with the method and system for “Geomechanics and wellbore stability modeling using drilling dynamics data”, as further taught by Soroush , and to further include the “Methods for determining in situ shale strengths, elastic properties, pore pressures, formation stresses, and drilling fluid parameters” as taught by Steiger , because all three references are in the same art of oil well integrity and/or stability by using mathematical models, and further because Steiger expressly teaches “methods for determining the in situ strengths, pore pressures, elastic properties and formation stresses, of low permeability rocks such as shales and for determining desired parameters for fluids used in drilling wellbores”. (See Steiger , col. 1, lines 9-14). In regards to claim 19, it has been cancelled. In regards to claim 20, it is rejected on the same grounds as claim 4. In regards to claim 21, it has been cancelled. Response to Amendments Re: Claim Rejections - 35 USC § 112 The Applicant’s arguments in the response filed August 28,2025 are persuasive in regards to the 35 USC § 112 rejections. Therefore, the rejections are withdrawn . Re: Claim Rejections - 35 USC § 101 The Applicant’s arguments in the response filed August 28,2025 are persuasive in regards to the 35 USC § 101 rejections. Therefore, the rejections are withdrawn . For example, independent claim 1 recites (emphasis added): “ drilling the wellbore … determining drilling in-situ stresses of the wellbore during the drilling phase ; determining a drilling phase mud window; utilizing the drilling in-situ stresses and the drilling phase mud window to create an updated wellbore integrity model ;” For example, independent claim 12 recites (emphasis added): “create an initial wellbore integrity model that determines a geomechanical stability of the wellbore for drilling, wherein creating the initial wellbore integrity model includes determining the wellbore and determining first input data of a subsurface into which the wellbore is planned, wherein at least a portion of the first input data is received from the sensor ”. Re: Claim Rejections - 35 USC § 103 Applicant’s amendments to the claims necessitated the new 35 USC § 103 grounds of rejection. Claims 14 and 21 were previously indicated as reciting allowable subject matter, however, relevant prior art has been found and applied. However, new art has been applied, and the rejections have been amended . Conclusion 07-96 AIA The prior art made of record and not relied upon is considered pertinent to applicant's disclosure. US 2014/0202772 A1 to Kulkarni et al. See para. [0114]-[0120] and [0180]: (See Kulkarni, para. [0114]-[0120]: “In an embodiment according to the invention, a method of managing or controlling a drilling operation in a well is provided, the method comprising the steps of: (A) obtaining composition and initially uniform mud weight of a drilling fluid; (B) obtaining wellbore flow conditions in the well operation, including trip-in and trip-out timings, rate of drill pipe rotation, and drilling fluid circulation rate; (C) estimating an initial equivalent circulation density for the drilling fluid based on the initial uniform mud weight of the drilling fluid; (D) estimating or experimentally determining a sagged fluid mud weight (MWs) for the drilling fluid ; (E) re-evaluating a later equivalent circulation density based on the estimated MWs; and (F) modifying the drilling fluid or the wellbore flow conditions to manage or control the well or avoid an equivalent circulation density difference greater than 0.05 ppg in the well, or preferably to avoid an equivalent circulation density greater than 0.1 ppg.”) (See Kulkarni, para. [0180]: “The model and methods according to the invention will serve as a useful tool to the mud engineers to evaluate the sag behavior for a given fluid and to make speedy decisions at the rig site to optimize fluid formulations; this will consequently save the corresponding down-time and wellbore stability related issues.”) The following two references have the same assignee as the present application, and therefore are ineligible for use in a 35 USC 103 rejection. They were also filed too recently to qualify as prior art. US 2023/0184992 A1 to Albahrani et al. See para. [0018] and [0119]: [0118] By providing a monitoring system with the drilling fluid system, the computing system may provide more robust recommendations for maintaining wellbore stability in response to measured and predicted wellbore structure from a drilling process , based on a generated adjusted FEM model of the wellbore from detected cavings. [0119] Additionally, while-drilling and post-drilling processes according to embodiments of the present disclosure may also include adjusting at least one drilling parameter based on a generated adjusted FEM model of the wellbore. For example, in addition to or in the alternative to altering an amount of drilling fluid additives to the drilling fluid to change a mud weight in the wellbore , altering a cementing plan, altering a lost circulation plan, altering a drill speed, or altering another drilling parameter may be recommended and/or performed based on an adjusted FEM model of the wellbore generated according to while-drilling or post-drilling processes according to embodiments of the present disclosure . US 11,920,413 B1 to AlFaraj et al. See col.5, lines 24-41: A wellbore planning system (150) may be used to generate the wellbore plan. The wellbore planning system (150) may comprise one or more computer processors in communication with computer memory containing the geophysical and geomechanical models, information relating to drilling hazards, and the constraints imposed by the limitations of the CT string (116) or drillstring and the wellbore drilling system (100). The wellbore planning system (150) may further include dedicated software to determine the planned wellbore path and associated drilling parameters, such as the planned wellbore diameter, the location of planned changes of the wellbore diameter, the planned depths at which casing (if used) will be inserted to support the wellbore and to prevent formation fluids entering the wellbore , and the drilling mud weights (densities) and types that may be used during drilling the wellbore . The wellbore planning system (150) may be implemented on one or more computer systems such as the one shown in FIG. 9, discussed later . 07-40 AIA Applicant's amendment necessitated the new ground(s) of rejection presented in this Office action. Accordingly, THIS ACTION IS MADE FINAL . See MPEP § 706.07(a). Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a). A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any extension fee pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the date of this final action. Any inquiry concerning this communication or earlier communications should be directed to Examiner Ayal Sharon, whose telephone number is (571) 272-5614, and fax number is (571) 273-1794. The Examiner can normally be reached from Monday to Friday between 9 AM and 6 PM. If attempts to reach the examiner by telephone are unsuccessful, the examiner’s supervisor, SPE Christine Behncke can be reached at (571) 272-8103 or at christine.behncke@uspto.gov. The fax number for the organization where this application or proceeding is assigned is 571-273-8300. Information regarding the status of published or unpublished applications may be obtained from Patent Center. Unpublished application information in Patent Center is available to registered users. To file and manage patent submissions in Patent Center, visit: https://patentcenter.uspto.gov. Visit https://www.uspto.gov/patents/apply/patent-center for more information about Patent Center and https://www.uspto.gov/patents/docx for information about filing in DOCX format. For additional questions, contact the Electronic Business Center (EBC) at 866-217-9197 (toll-free). If you would like assistance from a USPTO Customer Service Representative, call 800-786-9199 (IN USA OR CANADA) or 571-272-1000. Sincerely, /Ayal I. Sharon/ Examiner, Art Unit 3695 May 26, 2026 Application/Control Number: 17/691,181 Page 2 Art Unit: 3695 Application/Control Number: 17/691,181 Page 3 Art Unit: 3695 Application/Control Number: 17/691,181 Page 4 Art Unit: 3695 Application/Control Number: 17/691,181 Page 5 Art Unit: 3695 Application/Control Number: 17/691,181 Page 6 Art Unit: 3695 Application/Control Number: 17/691,181 Page 7 Art Unit: 3695 Application/Control Number: 17/691,181 Page 8 Art Unit: 3695 Application/Control Number: 17/691,181 Page 9 Art Unit: 3695 Application/Control Number: 17/691,181 Page 11 Art Unit: 3695 Application/Control Number: 17/691,181 Page 12 Art Unit: 3695 Application/Control Number: 17/691,181 Page 13 Art Unit: 3695 Application/Control Number: 17/691,181 Page 14 Art Unit: 3695 Application/Control Number: 17/691,181 Page 15 Art Unit: 3695 Application/Control Number: 17/691,181 Page 16 Art Unit: 3695 Application/Control Number: 17/691,181 Page 17 Art Unit: 3695 Application/Control Number: 17/691,181 Page 18 Art Unit: 3695 Application/Control Number: 17/691,181 Page 19 Art Unit: 3695 Application/Control Number: 17/691,181 Page 20 Art Unit: 3695 Application/Control Number: 17/691,181 Page 21 Art Unit: 3695 Application/Control Number: 17/691,181 Page 22 Art Unit: 3695
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