DETAILED ACTION
Acknowledgement
This non-final office action is in response to claims filed on 01/08/2025.
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 statement (IDS) submitted on 06/10/2025 is in compliance with the provisions of 37 CFR 1.97. Accordingly, the information disclosure statement is being considered by the examiner.
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 1-20 are rejected under 35 U.S.C. 101 because the claimed invention, “Generating Risk Analysis Reports Using a Risk Model”, is directed to an abstract idea, specifically Certain Methods of Organizing Human Activity and Mental Processes, without significantly more. The claims do not include additional elements that are sufficient to amount to significantly more than the judicial exception because the additional elements individually or in combination provide mere instructions to implement the abstract idea on a computer.
Step 1: Claims 1-20 are directed to a statutory category, namely a process (claims 1-13) and a machine (claims 14-20).
Step 2A (1): Independent claims 1, 8, and 14 are directed to an abstract idea of Certain Methods of Organizing Human Activity and Mental Processes, based on the following claim limitations: “providing/provide,…, a selectable work icon associated with a modular work item of a wellbore plan; based on receiving a work icon selection of the selectable work icon, providing/provide,…, a selectable event icon associated with historical events related to the modular work item associated with the selectable work icon; based on receiving an event icon selection of the selectable event icon, applying/apply a risk model to the modular work item, the risk model performing a risk analysis of an event likelihood and event severity of an event related to the historical events, the risk model generating a risk analysis report of the event; and presenting/present the risk analysis report of the event…. (claims 1 and 14); and receiving a selection of a wellbore plan; for the wellbore plan, receiving a selection of at least one event of a plurality of events; receiving drilling data for a plurality of offset wellbores, the drilling data including at least one of daily drilling reports, drilling equipment information, well construction services reports, or incident information; receiving event data for the plurality of events from the plurality of offset wellbores; based on the selection and the event data, applying a risk model to the wellbore plan, the risk model performing a risk analysis of an event likelihood and event severity of the at least one event, the risk model generating a risk analysis report of the at least one event; and presenting the risk analysis report … (claim 8)”. These claims describe a process of facilitating a user’s request for risk analysis of a well plan. Dependent claims 2-7, 9-13, and 15-20 further describe the data being analyzed, the modeling, and risk analysis results. Facilitating a user’s request for work related information for planning purposes is considered a method of organizing human activity as the response to the request guides the user’s actions/behavior. Performing risk analysis using models can practically be performed in the human mind with pen and paper, thus reflecting mental processes. Therefore, these limitations, under the broadest reasonable interpretation, fall within the abstract groupings of Certain Methods of Organizing Human Activity which encompasses managing personal behavior or relationships or interactions between people including social activities, teaching, and following rules or instructions and Mental Processes which include concepts performed in the human mind such as observations, evaluations, judgments, and opinions. Certain Methods of Organizing Human Activity can encompass the activity of a single person (e.g. a person following a set of instructions), activity that involve multiple people (e.g. a commercial interaction), and certain activity between a person and a computer (e.g. a method of anonymous loan shopping). Mental Processes include claims directed to collecting information, analyzing it, and displaying certain results of the collection and analysis even if they are claimed as being performed on a computer. The courts have found claims requiring a generic computer or nominally reciting a generic computer may still recite a mental process even though the claim limitations are not performed entirely in the human mind. Therefore, claims 1-20 are directed to an abstract idea and are not patent eligible.
Step 2A (2): This judicial exception is not integrated into a practical application. In particular, claims 1, 8, and 14 recite additional elements of “a graphical user interface (GUI) of a computer device; providing on the GUI, a selectable icon; presenting…on the GUI (claims 1 and 14)); presenting…on a display of a computing device (claim 8); and a drilling planning system, comprising a processor and memory, the memory including instructions that cause the processor to: provide, on a graphical user interface (GUI) of a computing device, a selectable icon (claim 14)”. These additional elements do not integrate the abstract idea into a practical application because the claims do not recite (a) an improvement to another technology or technical field and (b) an improvement to the functioning of the computer itself and (c) implementing the abstract idea with or by use of a particular machine, (d) effecting a particular transformation or reduction of an article, or (e) applying the judicial exception in some other meaningful way beyond generally linking the use of an abstract idea to a particular technological environment. These additional elements evaluated individually and in combination are viewed as computing and display devices that are used to perform the abstract process in Step 2A(1). Limitations that recite mere instructions to implement an abstract idea on a computer or merely uses a computer as a tool to perform an abstract idea are not indicative of integration into a practical application (see MPEP 2106.05(f)). Therefore, claims 1-20 do not include individual or a combination of additional elements that integrate the judicial exception into a practical application and thus are not patent eligible.
Step 2B: The claims do not include additional elements that are sufficient to amount to significantly more than the judicial exception. Claims 1, 8, and 14 recite additional elements of “a graphical user interface (GUI) of a computer device; providing on the GUI, a selectable icon; presenting…on the GUI (claims 1 and 14)); presenting…on a display of a computing device (claim 8); and a drilling planning system, comprising a processor and memory, the memory including instructions that cause the processor to: provide, on a graphical user interface (GUI) of a computing device, a selectable icon (claim 14)”. These additional elements evaluated individually and in combination are viewed as mere instructions to apply or implement the abstract idea on a computer. Applying an abstract idea on a computer does not integrate a judicial exception into a practical application or provide an inventive concept (see MPEP 2106.05(f)). Therefore, claims 1-20 do not include individual or a combination of additional elements that are sufficient to amount to significantly more than the judicial exception and thus are not patent eligible.
Claim Rejections - 35 USC § 103
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
The factual inquiries 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 nonobviousness.
Claims 1-7 and 14-20 are rejected under 35 U.S.C. 103 as being unpatentable over Jones (US 2023/0237594 A1) in view of Narayanan et al. (US 2024/0211651 A1).
As per claims 1 and 14, Jones teaches a method for drilling planning, the method comprising (Jones e.g. A method, apparatus and system is provided for assessing risk for well completion (Abstract).); and a drilling planning system, comprising: a processor and memory, the memory including instructions that cause the processor to (Jones e.g. A system comprising: an input interface, an user interface, a processor coupled the input interface and the user interface, wherein the processor receives computer executable instructions stored on a memory that when executed by the processor causes the following: [0009]. FIG. 1 is a schematic diagram of an embodiment of a RTM processing system 100 that may correspond to or may be part of a computer and/or any other computing device, such as a workstation, server, mainframe, super computer, and/or database [0025].):
Jones teaches providing/provide, on a graphical user interface (GUI) of a computing device, an input interface associated with a work item of a wellbore plan; (Jones e.g. A method for assessing risk for well completion, comprising: obtaining, using an input interface, a Below Rotary Table hours and a plurality of well-field parameters for one or more planned runs… [0007]. A system comprising an input interface, an user interface, a processor coupled the input interface and the user interface, wherein the processor receives computer executable instructions stored on a memory that when executed by the processor causes the following: receive a plurality of field parameters that correspond to a plurality of planned runs via an input interface [0009]. FIG. 1 illustrates that the processor 102 may be operatively coupled to one or more input interfaces 104 configured to obtain drilling data for one or more wells sites and one or more output interfaces 106 configured to output and/or display the simulated RTM results, inputted drilling data, and/or other field drilling information [0026].)
Jones teaches based on receiving an input selection of a work item, providing/provide, on the GUI, a selectable event associated with historical events related to the work item …; (Jones e.g. A method includes…determining, using at least one processor, one or more non-productive time values that correspond to the one or more planned runs based upon the well-field parameters… [0007]. FIG. 1 is a schematic diagram of an embodiment of a RTM processing system 100 that may correspond to or may be part of a computer and/or any other computing device, such as a workstation, server, mainframe, super computer, and/or database [0025]. The memory 108 may comprise a RTM module 110 that may be accessed and implemented by processor 102. The RTM module 110 may receive a variety of inputted information relating to field parameters for one or more wells and quantify risks associated with future well completions. Well planners may utilize previous field drilling experience and simulations to estimate how long each planned run will take in real hours assuming the drilling period has about zero NPT. The estimated time for a planned run is referenced throughout this disclosure as Below Rotary Table (BRT) hours. BRT hours is an estimate of how long a drilling operator may take to finish drilling that includes not just pure drilling time, but also tripping and logging time. NPT extends the drilling period by adding the NPT risk distribution to the computed BRT hours to determine the total time for drilling, which includes the time for tool failures [0030]. In assessing and quantifying risks, the unit of exposure of risk for well construction may be identified as a “planned run.” The term “planned run” is defined throughout this disclosure as how drilling operator(s) plan to drill a well. A “planned run” may constitute a specific hole size, drilled length, dog leg (for directional drilling), and bottom hole assembly [0029]. The RTM, as shown in FIG. 2, allows for about three risk modifiers to customize the results to these conditions. The “Location” modifier may be a factor that is computed based on the analysis of the data shown in the RTM's “Country RM” tab, which is shown in FIG. 3. Referring to FIG. 3, the user may initially select the country of interest and subsequently using an input interface (e.g., click on a run button) to update the plot within the RTM. [0039].)
Jones teaches based on receiving an event…selection of the selectable event…, applying/apply a risk model to the…work item, the risk model performing a risk analysis of an event likelihood and event severity of an event related to the historical events, the risk model generating a risk analysis report of the event; and (Jones e.g. The present invention generally relates to determining and predicting risk based on results from failures that originate from an operator's product and service delivery using a risk transfer model (RTM) [0004]. The RTM may comprise a NPT parameter that indicates well failures from the product or service delivery of the drilling operator(s) [0023]. In one embodiment, the RTM may comprises four field-based actuarial variables: hole size (inches), drilling depth (feet (ft.)), drilled length (ft.), and maximum dog leg [0032]. The variables and category criteria included in the RTM may be used to generate NPT event frequency, severity, and risk with suitable data populations in order to provide the required statistical significances [0032]. The NPT event frequency may be a direct function of the bottom hole assembly configuration. Failure of this assembly may be the originating cause of NPT. For well drilling and construction, the probability of a failure of the bottom hole assembly configuration may drive NPT event frequency [0035]. NPT severity may be computed to include modification factors for hole size, depth, drilled length and maximum dog leg. These factors are viewed as environmental factors which influence NPT risk. NPT severity may be a function of the time required to remove a failed bottom hole assembly and re-insert a new one [0035]. Referring to FIG. 3, the user may initially select the country of interest and subsequently using an input interface (e.g., click on a run button) to update the plot within the RTM. The numbers next to the country name represent the percentage of total records that are from each country. This information may inform the user about the general amount of data or drilling activity that has been performed in each country which implicitly relates to the statistical reliability of the risk frequency, severity, and risk results [0039].)
Jones teaches presenting the risk analysis report of the event on the GUI. (Jones e.g. A method includes…outputting, using a graphic display, a risk transfer model results based on a total BRT hours from the Below Rotary Table and the non-productive time distribution produced from the one or more Monte Carlo trials [0007]. FIG. 1 illustrates that the processor 102 may be operatively coupled to one or more input interfaces 104 configured to obtain drilling data for one or more wells sites and one or more output interfaces 106 configured to output and/or display the simulated RTM results, inputted drilling data, and/or other field drilling information [0026]. The graph's horizontal axis represents the NPT event frequency measured in terms of number of NPT events per planned run. The vertical axis is the NPT event severity: average NPT duration per event in hours. The points show the NPT frequency, severity, and risk for each year for the selected country (e.g., United Kingdom in FIG. 3) for a drilling operator [0040]. In FIG. 3, each point represents the annual average NPT performance for the selected country [0041]. In one embodiment, the NPT event frequency, severity, and risk, by year, location, land and offshore as shown in FIG. 4 may include a trend (or pattern) information to assist the user in forecasting future NPT performance by operational location. The user can change this factor by entering their choice in the land and off-shore cell on the input data screen as shown in FIG. 2 [0044].)
Jones does not explicitly teach, however, Narayanan teaches:
Narayanan teaches providing, on a graphical user interface (GUI) of a computing device, a selectable work icon associated with a modular work item of a wellbore plan and based on receiving a work icon selection of the selectable work icon, providing, on the GUI, a selectable event icon (Narayanan e.g. In general, embodiments of the disclosure include systems and methods that use various stochastic assessments to perform project screening and/or ranking of possible projects within a reservoir development plan [0022]. A reservoir development plan may include exploratory operations (e.g., seismic surveys and exploratory pilot wells), well operations (e.g., drilling production wells and injection wells as well as performing various well completions), and ongoing maintenance and operation of wells for developing a reservoir region [0022]. In some embodiments, an adjusted reservoir development plan among various reservoir development plans is presented by a user device using a graphical user interface. A user selection of the adjusted reservoir development plan may be obtained in response to a user input within the graphical user interface. A command may be transmitted in response to the user selection. In some embodiments, a well operation in a reservoir development plan is selected from an injection operation using an injection well, a drilling operation for a well path for a production well, a hydraulic stimulation operation for the production well, a well completion operation for the production well, a well intervention operation for the production well, and/or a well maintenance operation for the production well [0010]. FIG. 2 shows a schematic diagram in accordance with one or more embodiments. As shown in FIG. 2, a well management network (e.g., well management network A (200)) may include a reservoir development manager (e.g., reservoir development manager X (260)), various oil and gas wells (e.g., well A (210), well B (220)), various servers (e.g., service provider server N (270), service provider server C (250)), and various user devices (e.g., user device M (230)), and/or various network elements (not shown) [0046]. The reservoir development manager (e.g., reservoir development manager X (260)) may include hardware and/or software that obtains a screening criterion (e.g., one of screening criteria X (261)) and/or a ranking criterion (e.g., one of ranking criteria X (262)) regarding reservoir development activities, well data (e.g., well data X (263)), and/or service provider data (e.g., service provider data (294)) from data inputs (e.g., user data (233), well data A (291), service provider data (294)) [0050]. For example, the reservoir development manager (e.g., reservoir development manager X (260)) may acquire the screening criterion (e.g., screening criteria X (261)) from a user data (233) collected by a user device (e.g., user device M (230)). The user device (e.g., user device M (230)) may include hardware and/or software to receive real-time user selections (e.g., user selections N (231)) by interacting with a user via a user interface (e.g., user interface O (232)). Specifically, the reservoir development manager (e.g., reservoir development manager X (260)) allows the user to interact with the user device (e.g., user device M (230)) to verify the actual reservoir development plan setup is as per desire and monitor the performance as the self-learning process of the ML algorithm is set up for retro alimentation up on the actual events. When the reservoir development plan setup is not desired, the user can modify the user selections (e.g., user selections N (231)) to adjust the screening criterion via the graphical display (e.g., user interface O (232)) [0050]. Keeping with FIG. 2, in some embodiments, the reservoir development manager (e.g., reservoir development manager X (260)) may include hardware and/or software to generate one or more reservoir development plans within the well management network (e.g., well management network A (200)) using one or more ML algorithms (e.g., ML algorithms X (265)) based on the obtained screening criterion and reservoir development activities, such as drilling exploratory wells, performing stimulation operations of future production wells, etc. [0051]. Turning to FIGS. 4A and 4B, FIG. 4A and 4B show flowcharts in accordance with one or more embodiments [0093]. In Block 400, a screening criterion and/or a ranking criterion is obtained for generating a reservoir development plan in accordance with one or more embodiments. For example, a reservoir development manager may obtain one or more screening criteria or one or more ranking criteria from user inputs to a user device or a database that is associated with a particular reservoir development plan. Screening criteria may include various predetermined thresholds (e.g., thresholds selected by a user or automatically determined by the reservoir development manager) for filtering or removing various wells and well operations from a reservoir development plan. For example, a screening criterion may correspond to a predetermined threshold for a probability of commerciality. For example, if a predicted amount of hydrocarbon production at a predicted price level does not exceed a cost range for developing a specific production well, the screening criterion may identify the production well as lacking a probability of commerciality. As such, the production well may not be selected for development in the geological region of interest [0094].)
The Examiner submits that before the effective filing date, it would have been obvious to one of ordinary skill in the art to modify Jones’s Risk Assessment System’s interface to include selectable work item and event icons associated with a wellbore plan as taught by Narayanan in order to improve robustness of various reservoir development plans (Narayanan e.g. [0039] and [0110]).
As per claims 2 and 15, Jones in view of Narayanan teach the method of claim 1 and the drilling planning system of claim 14, Jones teaches wherein the historical events are based on drilling data for a plurality of offset wellbores, the drilling data including at least one of daily drilling reports, drilling equipment information, well construction services reports, or incident information. (Jones e.g. Disclosed herein are various example embodiments that produces and implements a quantitative RTM that accounts for a variety of well-field characteristics that include, but are not limited to drilling time, location, downhole tools used, distance drilled, and well conditions [0023]. Well planners may utilize previous field drilling experience and simulations to estimate how long each planned run will take in real hours assuming the drilling period has about zero NPT. The estimated time for a planned run is referenced throughout this disclosure as Below Rotary Table (BRT) hours [0030]. In some instances the acquired drilling data may not specify operational type, and thus, may not separate land and off-shore operations from the location or country in the dataset. The acquired drilling data may indicate that the majority of countries are dominated by one type of drilling so in most cases, and thus, computing the country (and field) multipliers may be sufficient to adjust the results to actual performance. In another embodiments, the acquire drilling data may specify land and off-shore operations and could be computed and applied similar to the country risk and field risk modifiers as discussed above [0043].)
As per claims 3 and 16, Jones in view of Narayanan teach the method of claim 1 and the drilling planning system of claim 14, Jones teaches wherein applying the risk model includes applying a Monte Carlo simulation to the modular work item to generate the event severity (Jones e.g. A method, apparatus and system is provided for assessing risk for well completion (Abstract). Outputting, using a graphic display, a risk transfer model results based on a total BRT hours from the Below Rotary Table and the non-productive time distribution produced from the one or more Monte Carlo trials (Abstract). Embodiments of the present invention include quantitatively assessing risk and reliability for drilling and well completion based upon a variety of parameters, such as non-productive time (NPT) [0004]. NPT and BRT distributions may be statistically developed via a Monte Carlo method with the number of trials being supplied by the user as an input parameter. Persons of ordinary skill in the art are aware that a Monte Carlo method typically follows that pattern of determining a domain of possible inputs, generates inputs randomly from a probability distribution over the domain, perform a deterministic computation on the inputs, and aggregate the results [0036]. The NPT severity distribution for each planed run may then be multiplied by the binary frequency function to compute the planned run NPT risk. The NPT risk value may then be modified by factors to account for the specific hole size, depth, drilled length, and maximum dog leg values [0036].)
As per claims 4 and 17, Jones in view of Narayanan teach the method of claim 1 and the drilling planning system of claim 14, Jones teaches wherein the event severity includes an estimate of non- productive time (NPT) associated with the event (Jones e.g. The present invention generally relates to determining and predicting risk based on results from failures that originate from an operator's product and service delivery using a risk transfer model (RTM) [0004]. Embodiments of the present invention include quantitatively assessing risk and reliability for drilling and well completion based upon a variety of parameters, such as non-productive time (NPT) [0004]. Non-productive time extends a drilling period but does not include or determine all of the actual drilling time [0030]. The RTM may standardize key performance indicators that may be used to differentiate drilling operators' products and services in the marketplace. The RTM may comprise a NPT parameter that indicates well failures from the product or service delivery of the drilling operator(s). Other well failures, such as failure operating outside specification, non-product or service delivery not impacted by the drilling operator(s), product relevant notification and in-house product functional failure may be omitted in assessing a drilling operator(s) NPT performance [0023]. The variables and category criteria included in the RTM may be used to generate NPT event frequency, severity, and risk with suitable data populations in order to provide the required statistical significances [0032].).
As per claims 5 and 18, Jones in view of Narayanan teach the method of claim 1 and the drilling planning system of claim 14, Jones teaches wherein the wellbore plan includes a scope of work for a new wellbore. (Jones e.g. The memory 108 may comprise a RTM module 110 that may be accessed and implemented by processor 102. The RTM module 110 may receive a variety of inputted information relating to field parameters for one or more wells and quantify risks associated with future well completions. The RTM analysis may involve transforming acquired raw drilling data into a new data base where the actual run data is summed to produce a new data set where each record is a planned run (Fig. 1 and [0028]). In assessing and quantifying risks, the unit of exposure of risk for well construction may be identified as a “planned run.” The term “planned run” is defined throughout this disclosure as how drilling operator(s) plan to drill a well. A “planned run” may constitute a specific hole size, drilled length, dog leg (for directional drilling), and bottom hole assembly [0029].)
As per claims 6 and 19, Jones in view of Narayanan teach the method of claim 1 and the drilling planning system of claim 14, Jones teaches wherein the event related to historical events includes a plurality of events, and wherein the event icon selection includes a selection of the plurality of events, the risk model performing the risk analysis on each of the plurality of events. (Jones e.g. The RTM, as shown in FIG. 2, allows for about three risk modifiers to customize the results to these conditions. The “Location” modifier may be a factor that is computed based on the analysis of the data shown in the RTM's “Country RM” tab, which is shown in FIG. 3 [0039]. Referring to FIG. 3, the user may initially select the country of interest and subsequently using an input interface (e.g., click on a run button) to update the plot within the RTM. The numbers next to the country name represent the percentage of total records that are from each country. This information may inform the user about the general amount of data or drilling activity that has been performed in each country which implicitly relates to the statistical reliability of the risk frequency, severity, and risk results [0039]. The graph's horizontal axis represents the NPT event frequency measured in terms of number of NPT events per planned run. The vertical axis is the NPT event severity: average NPT duration per event in hours. The points show the NPT frequency, severity, and risk for each year for the selected country (e.g., United Kingdom in FIG. 3) for a drilling operator [0040]. In FIG. 3, each point represents the annual average NPT performance for the selected country [0041]. In one embodiment, the NPT event frequency, severity, and risk, by year, location, land and offshore as shown in FIG. 4 may include a trend (or pattern) information to assist the user in forecasting future NPT performance by operational location. The user can change this factor by entering their choice in the land and off-shore cell on the input data screen as shown in FIG. 2 (Fig. 4 and [0044]).)
As per claims 7 and 20, Jones in view of Narayanan teach the method of claim 6 and the drilling planning system of claim 19, Jones teaches wherein the event icon selection includes un-selecting an event icon associated with an irrelevant event of the plurality of events. (Jones e.g. The RTM, as shown in FIG. 2, allows for about three risk modifiers to customize the results to these conditions. The “Location” modifier may be a factor that is computed based on the analysis of the data shown in the RTM's “Country RM” tab, which is shown in FIG. 3 [0039]. Referring to FIG. 3, the user may initially select the country of interest and subsequently using an input interface (e.g., click on a run button) to update the plot within the RTM. The numbers next to the country name represent the percentage of total records that are from each country. This information may inform the user about the general amount of data or drilling activity that has been performed in each country which implicitly relates to the statistical reliability of the risk frequency, severity, and risk results [0039]. The graph's horizontal axis represents the NPT event frequency measured in terms of number of NPT events per planned run. The vertical axis is the NPT event severity: average NPT duration per event in hours. The points show the NPT frequency, severity, and risk for each year for the selected country (e.g., United Kingdom in FIG. 3) for a drilling operator [0040]. In FIG. 3, each point represents the annual average NPT performance for the selected country [0041]. In one embodiment, the NPT event frequency, severity, and risk, by year, location, land and offshore as shown in FIG. 4 may include a trend (or pattern) information to assist the user in forecasting future NPT performance by operational location. The user can change this factor by entering their choice in the land and off-shore cell on the input data screen as shown in FIG. 2 (Fig. 4 and [0044]). Fig. 4 shows a box icon to select and/or un-select a particular event.)
Claim Rejections - 35 USC § 102
The following is a quotation of the appropriate paragraphs of 35 U.S.C. 102 that form the basis for the rejections under this section made in this Office action:
A person shall be entitled to a patent unless –
(a)(1) the claimed invention was patented, described in a printed publication, or in public use, on sale or otherwise available to the public before the effective filing date of the claimed invention.
Claims 8-13 are rejected under 35 U.S.C. 102(a)(1) as being anticipated by Jones (US 2023/0237594 A1).
As per claim 8, Jones teaches a method for drilling planning, the method comprising (Jones e.g. A method, apparatus and system is provided for assessing risk for well completion (Abstract).):
Jones teaches receiving a selection of a wellbore plan; for the wellbore plan, receiving a selection of at least one event of a plurality of events; receiving drilling data for a plurality of offset wellbores, the drilling data including at least one of daily drilling reports, drilling equipment information, well construction services reports, or incident information; receiving event data for the plurality of events from the plurality of offset wellbores; based on the selection and the event data, applying a risk model to the wellbore plan, the risk model performing a risk analysis of an event likelihood and event severity of the at least one event, the risk model generating a risk analysis report of the at least one event; and presenting the risk analysis report on a display of a computing device. (Jones e.g. A method for assessing risk for well completion, comprising: obtaining, using an input interface, a Below Rotary Table hours and a plurality of well-field parameters for one or more planned runs, determining, using at least one processor, one or more non-productive time values that correspond to the one or more planned runs based upon the well-field parameters, developing, using at least one processor, a non-productive time distribution and a Below Rotary Table distribution via one or more Monte Carlo trials; and outputting, using a graphic display, a risk transfer model results based on a total BRT hours from the Below Rotary Table and the non-productive time distribution produced from the one or more Monte Carlo trials [0007]. A system comprising: an input interface, an user interface, a processor coupled the input interface and the user interface, wherein the processor receives computer executable instructions stored on a memory that when executed by the processor causes the following: receive a plurality of field parameters that correspond to a plurality of planned runs via an input interface, determine a non-productive time risk for each of the planned runs based on the field parameters, generate a total non-productive time risk using one or more Monte Carlo trials, and output the total non-productive time risk via a user interface, wherein the number of Monte Carol trials is received via the input interface [0009]. In assessing and quantifying risks, the unit of exposure of risk for well construction may be identified as a “planned run.” The term “planned run” is defined throughout this disclosure as how drilling operator(s) plan to drill a well. A “planned run” may constitute a specific hole size, drilled length, dog leg (for directional drilling), and bottom hole assembly [0029]. Disclosed herein are various example embodiments that produces and implements a quantitative RTM that accounts for a variety of well-field characteristics that include, but are not limited to drilling time, location, downhole tools used, distance drilled, and well conditions [0023]. FIG. 1 illustrates that the processor 102 may be operatively coupled to one or more input interfaces 104 configured to obtain drilling data for one or more wells sites and one or more output interfaces 106 configured to output and/or display the simulated RTM results, inputted drilling data, and/or other field drilling information [0026]. The memory 108 may comprise a RTM module 110 that may be accessed and implemented by processor 102. The RTM module 110 may receive a variety of inputted information relating to field parameters for one or more wells and quantify risks associated with future well completions. The RTM analysis may involve transforming acquired raw drilling data into a new data base where the actual run data is summed to produce a new data set where each record is a planned run [0028]. In some instances the acquired drilling data may not specify operational type, and thus, may not separate land and off-shore operations from the location or country in the dataset. The acquired drilling data may indicate that the majority of countries are dominated by one type of drilling so in most cases, and thus, computing the country (and field) multipliers may be sufficient to adjust the results to actual performance. In another embodiments, the acquire drilling data may specify land and off-shore operations and could be computed and applied similar to the country risk and field risk modifiers as discussed above [0043]. Well planners may utilize previous field drilling experience and simulations to estimate how long each planned run will take in real hours assuming the drilling period has about zero NPT. The estimated time for a planned run is referenced throughout this disclosure as Below Rotary Table (BRT) hours [0030]. The RTM, as shown in FIG. 2, allows for about three risk modifiers to customize the results to these conditions. The “Location” modifier may be a factor that is computed based on the analysis of the data shown in the RTM's “Country RM” tab, which is shown in FIG. 3 [0039]. Referring to FIG. 3, the user may initially select the country of interest and subsequently using an input interface (e.g., click on a run button) to update the plot within the RTM. The numbers next to the country name represent the percentage of total records that are from each country. This information may inform the user about the general amount of data or drilling activity that has been performed in each country which implicitly relates to the statistical reliability of the risk frequency, severity, and risk results [0039]. The graph's horizontal axis represents the NPT event frequency measured in terms of number of NPT events per planned run. The vertical axis is the NPT event severity: average NPT duration per event in hours. The points show the NPT frequency, severity, and risk for each year for the selected country (e.g., United Kingdom in FIG. 3) for a drilling operator [0040].)
As per claim 9, Jones teaches the method of claim 8, wherein the selection is an event selection, and further comprising receiving a wellbore selection of at least one of the plurality of offset wellbores, and wherein applying the risk model includes applying the risk model based at least in part on the wellbore selection (Jones e.g. A method, apparatus and system is provided for assessing risk for well completion (Abstract). The present invention generally relates to determining and predicting risk based on results from failures that originate from an operator's product and service delivery using a risk transfer model (RTM). Embodiments of the present invention include quantitatively assessing risk and reliability for drilling and well completion based upon a variety of parameters, such as non-productive time (NPT) [0004]. The RTM may comprise a NPT parameter that indicates well failures from the product or service delivery of the drilling operator(s). Other well failures, such as failure operating outside specification, non-product or service delivery not impacted by the drilling operator(s), product relevant notification and in-house product functional failure may be omitted in assessing a drilling operator(s) NPT performance [0023]. In assessing and quantifying risks, the unit of exposure of risk for well construction may be identified as a “planned run.” The term “planned run” is defined throughout this disclosure as how drilling operator(s) plan to drill a well. A “planned run” may constitute a specific hole size, drilled length, dog leg (for directional drilling), and bottom hole assembly [0029]. The variables and category criteria included in the RTM may be used to generate NPT event frequency, severity, and risk with suitable data populations in order to provide the required statistical significances [0032]. To translate the determined NPT risk to another quantifiable risk, such as financial risk, a matrix may be defined in the model reference section that introduces the dollar cost (or loss) per hour of NPT as a function of hole size, depth, and drilled length. This information is entered by the user based on the value of the wells being completed. For example, the NPT time and financial risk may be computed for each planned run and aggregated over all planned runs. The aggregate NPT value may then be added to the total BRT hours to produce the total time to well (or wells) completion distribution [0037].)
As per claim 10, Jones teaches the method of claim 8, wherein applying the risk model includes not applying the risk model to an un-selected event of the plurality of events. (Jones e.g. The RTM, as shown in FIG. 2, allows for about three risk modifiers to customize the results to these conditions. The “Location” modifier may be a factor that is computed based on the analysis of the data shown in the RTM's “Country RM” tab, which is shown in FIG. 3 [0039]. Referring to FIG. 3, the user may initially select the country of interest and subsequently using an input interface (e.g., click on a run button) to update the plot within the RTM. The numbers next to the country name represent the percentage of total records that are from each country. This information may inform the user about the general amount of data or drilling activity that has been performed in each country which implicitly relates to the statistical reliability of the risk frequency, severity, and risk results [0039]. The graph's horizontal axis represents the NPT event frequency measured in terms of number of NPT events per planned run. The vertical axis is the NPT event severity: average NPT duration per event in hours. The points show the NPT frequency, severity, and risk for each year for the selected country (e.g., United Kingdom in FIG. 3) for a drilling operator [0040]. In FIG. 3, each point represents the annual average NPT performance for the selected country [0041]. In one embodiment, the NPT event frequency, severity, and risk, by year, location, land and offshore as shown in FIG. 4 may include a trend (or pattern) information to assist the user in forecasting future NPT performance by operational location. The user can change this factor by entering their choice in the land and off-shore cell on the input data screen as shown in FIG. 2 (Fig. 4 and [0044]). Fig. 4 shows a box icon to select and/or un-select a particular event.)
As per claim 11, The method of claim 8, wherein the wellbore plan includes a portion of a wellbore plan, and wherein applying a risk model includes applying the risk model to the portion of the wellbore plan (Jones e.g. In assessing and quantifying risks, the unit of exposure of risk for well construction may be identified as a “planned run.” The term “planned run” is defined throughout this disclosure as how drilling operator(s) plan to drill a well. A “planned run” may constitute a specific hole size, drilled length, dog leg (for directional drilling), and bottom hole assembly [0029]. The variables and category criteria included in the RTM may be used to generate NPT event frequency, severity, and risk with suitable data populations in order to provide the required statistical significances [0032]. To translate the determined NPT risk to another quantifiable risk, such as financial risk, a matrix may be defined in the model reference section that introduces the dollar cost (or loss) per hour of NPT as a function of hole size, depth, and drilled length. This information is entered by the user based on the value of the wells being completed. For example, the NPT time and financial risk may be computed for each planned run and aggregated over all planned runs. The aggregate NPT value may then be added to the total BRT hours to produce the total time to well (or wells) completion distribution [0037].)
As per claim 12, Jones teaches the method of claim 8, wherein the risk model includes a Monte Carlo simulation of the event severity. (Jones e.g. A method, apparatus and system is provided for assessing risk for well completion (Abstract). Outputting, using a graphic display, a risk transfer model results based on a total BRT hours from the Below Rotary Table and the non-productive time distribution produced from the one or more Monte Carlo trials (Abstract). Embodiments of the present invention include quantitatively assessing risk and reliability for drilling and well completion based upon a variety of parameters, such as non-productive time (NPT) [0004]. NPT and BRT distributions may be statistically developed via a Monte Carlo method with the number of trials being supplied by the user as an input parameter. Persons of ordinary skill in the art are aware that a Monte Carlo method typically follows that pattern of determining a domain of possible inputs, generates inputs randomly from a probability distribution over the domain, perform a deterministic computation on the inputs, and aggregate the results [0036]. The NPT severity distribution for each planed run may then be multiplied by the binary frequency function to compute the planned run NPT risk. The NPT risk value may then be modified by factors to account for the specific hole size, depth, drilled length, and maximum dog leg values [0036].)
As per claim 13, Jones teaches the method of claim 8, wherein the plurality of events include lost-time events, and wherein the event severity includes a lost-time estimate. (Jones e.g. The present invention generally relates to determining and predicting risk based on results from failures that originate from an operator's product and service delivery using a risk transfer model (RTM) [0004]. Embodiments of the present invention include quantitatively assessing risk and reliability for drilling and well completion based upon a variety of parameters, such as non-productive time (NPT) [0004]. Non-productive time extends a drilling period but does not include or determine all of the actual drilling time [0030]. The RTM may standardize key performance indicators that may be used to differentiate drilling operators' products and services in the marketplace. The RTM may comprise a NPT parameter that indicates well failures from the product or service delivery of the drilling operator(s). Other well failures, such as failure operating outside specification, non-product or service delivery not impacted by the drilling operator(s), product relevant notification and in-house product functional failure may be omitted in assessing a drilling operator(s) NPT performance [0023]. The variables and category criteria included in the RTM may be used to generate NPT event frequency, severity, and risk with suitable data populations in order to provide the required statistical significances [0032].)
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure include FOR: Praveen, Jain (AU-2014375331-B2) “System And Method For Making Downhole Measurements” and NPL: Abdulridha, Hayder L et al. “Study on Uncertainty Analysis for Drilling Engineering Applications: Wellbore Stability Assessments.” Arabian journal for science and engineering (2011) 47.9 (2022): 11687–11698.
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/A.M./Examiner, Art Unit 3624
/Jerry O'Connor/Supervisory Patent Examiner,Group Art Unit 3624