DETAILED ACTION
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 .
Status of Claims
Claims 1, 12, 17 and 20 are amended.
Claims 1-20 are pending.
Claims 1-20 are rejected (Final Rejection).
Response to Amendments
Applicant’s amendment to claim 20 dated 10/09/2025 obviates the prior 35 U.S.C. § 112(b) antecedent basis rejection.
Response to Arguments
Applicant’s arguments, at Pages 9 and 10, filed 10/09/2025, with respect to the rejections under 35 U.S.C. § 101 (hereinafter “Applicant’s § 101 arguments”) have been fully considered but they are not persuasive.
Applicant’s § 101 arguments are that the independent claims 1, 12 and 17 now “recite a practical application, i.e., changing wellsite operations, of the claimed segmenting, thereby reciting details of how a solution to a problem is accomplished (i.e., reducing NPT and ILT).
As an initial matter, the independent claims do not even require that the NPT and/or ILT be reduced, much less, recite details of how that reduction is accomplished. The claims appear to be more of claiming a result (change of NPT and/or ILT) rather than any details of how that may occur. Even if reduction of NPT and/or ILT were a practical application (which is not conceded), the claims do not require any such reduction.
Moreover, Applicant’s “practical application” argument is interpreted as arguing that the claims have integrated the judicial exception into a practical application because the claims allegedly provide “an improvement to other technology or technical field”. See MPEP 2106.04(d). However, the background of the application (Paras. [0002] & [0003] of the specification) appear to indicate that “rig activity classification” for “determining replacement of rig equipment” (e.g., what could be considered a wellsite operation) and for “cost-effective wellsite operations” (e.g., no or minimized NPT and/or ILT) was a part of “inaccurate” traditional methods. That is, the specification appears to indicate that “rig activity classification” existed.
Applicant did discuss these features and argument during the Examiner Interview but as explicitly noted in the Interview Summary dated 10/02/2025, the specification discusses improving accuracy and/or validating the accuracy as the improvement to the existing technology (i.e., practical application). Examiner does not believe that it is Applicant’s contention that they invented tracking NPT and/or ILT, but rather that the “traditional methods” were inaccurate. In addition, if NPT and/or ILT calculations/identifications were pre-existing (conventional), what else would they be used for but to make operations more cost-effective (i.e., “changing wellsite operations based on NPT and ILT”)? MANDAVA et al. (U.S. Patent Application Publication No. 2017/0300845 A1) effectively filed June 2015 and cited in the 35 U.S.C. § 103 rejections below indicate “Invisible Lost Time (ILT)” and “Downtime (DT)” (i.e., non-production time) are “calculated using sensor readings” (Abstract and Paras. [0017] & [0037] of MANDAVA) and “identification, tracking, and application of ILT and IST periods to improve the efficiency of drilling operations” (Para. [0020] of MANDAVA).
In sum, Examiner finds these arguments unpersuasive because there is a disconnect between the alleged specification-based specific improvement (e.g., accuracy, Paras. [0002], [0003], [0024] & [0039] of specification) and what the claim requires: identifying NPT and ILT and using it as it was intended. The Federal Circuit has held that “[e]ven a specification full of technical details about a physical invention may nonetheless conclude with claims that claim nothing more than the broad law or abstract idea underlying the claims.” See Yu v. Apple (Fed. Circ. 2020-1760, 2020-1803) at Page 7 quoting ChargePoint, Inc. v. SemaConnect, Inc., 920 F.3d 759, 769 (Fed. Cir. 2019). Although the invention titled “Auto-Detection And Classification Of Rig Activities From Trend Analysis Of Sensor Data” (emphasis added) may improve the accuracy of the existing technology (a practical application), claim 1, as currently drafted, does not require details of a specific improvement.
For these reasons, the 35 U.S.C. § 101 rejections are maintained and have been modified to address Applicant’s amended claim language.
Regarding the rejections under 35 U.S.C. § 103, Applicant appears to present five arguments, which are discussed below in the same order as presented.
First, Applicant argues that COLEY fails to disclose “generating time series data from obtained sensor data” (as recited in claim 1) “since Coley's stored data forming a record over time is not data from obtained sensor data - it is processed rig state data”. However, this argument is unpersuasive for two reasons. As an initial matter, the claim does not require that the “record over time” (time series data) is actual sensor measurements. That is, the claim does not recite “generating sensor time series data from obtained sensor data, wherein the sensor time series data comprises sensor measurements”. Further, COLEY teaches both generating rig states over time based on sensor measurements (which reads on “time series data from obtained sensor data”) and also rig sensor data (measurements, such as depth) over time. See, e.g., Para. [0014] of COLEY (receive measurements produced by rig sensors … measurements may include values for bit depth, hole depth, … the sensor measurements are preprocessed for application to a rig state model … the rig state model generates a rig state value based on the preprocessed sensor measurements) and Para. [0046] of COLEY (given difference in hole depth and bit depth at times T, T−1, T−2, T−3, T−4, T−5, T−6, T+1, T+2, T+3, T+4, T+5, and T+6 calculated in block 406). Para. [0046] of COLEY clearly shows generating time series sensor data (i.e., sensor measurements, such as depth). See also FIGS. 1-6 of COLEY and corresponding description.
Second, Applicant argues “Coley does not disclose analyzing time series data to identify one or more index points where a trend in the time series data changes since this cited portion does not disclose, inter alia, identifying one or more index points where a trend in time series data changes” (emphasis added). Applicant’s specification appears to indicate that at least one example of the index points “may correspond to one or more changes in the gradient transition”. The previous Office Action had cited to Paras. [0061], [0064] & [0066] of COLEY which discuss drill bit depth changing from increasing to decreasing to identify “reaming down” and “backreaming”, respectively, and asserts “the bit depth changing from increasing to decreasing is interpreted as a time point where the trend changes”. Moreover, the depth increasing could be interpreted as a trend change and decreasing could be interpreted as another trend change. Applicant has not addressed Applicant’s interpretation and hence has not successfully persuaded that a change in trend/gradient does not correspond to changing from increasing to decreasing. Moreover, as further evidence, Applicant’s specification, Paras. [0025]-[0026] appears to indicate that “reaming” is a type of tracked macro activity.
Third, Applicant, at Pages 13 and 14, argues “Coley does not disclose segmenting any time series data, let alone segmenting time series data into any set of time segments” and “[t]here is no disclosure in this cited portion of Coley of time series data, segmenting time series data, a first set of time segments that represent macro activities performed during wellsite operations”. However, “connection”, “trip in” and “trip out” are interpreted as macro activities based on Applicant’s original claim 9 and COLEY teaches the same types of macro activities that are segmented: “connection”, “trip in” and “trip out”. As noted in the Office Action, COLEY teaches if the rig state changes to “connection,” the post-processing module 218 may examine the rig states generated for a predetermined time prior to the change to “connection” … if the post-processing module 218 finds another “connection” rig state preceding the change to “connection” and the bit depth between the two “connection” states has changed by less than a predetermined amount (e.g., less than 10 feet), then the post-processing module 218 may change all rig state values between the two “connection” states to “connection”, Para. [0066]; See also in block 608, if the rig state value received from the rig state model 216 is “static,” then the post-processing module 218 determines whether the “trip in” state or the “trip out” state may be more appropriate … for example, if the rig state preceding “static” is either “trip in” or “trip out,” and time spent in the “static” state is less than a predetermined amount (e.g., 20 seconds) then the post-processing module 218 may change the rig state value to the state preceding “static”, Para. [0064]. Moreover, for this “segmenting” limitation, the Office Action asserts: “[a]lthough COLEY appears to show the detection of the same types of macro and micro activities, COLEY arguably does not explicitly disclose all of the features of segmenting the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points and segmenting each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data. DUNLOP, however, is in the same field of endeavor (automatically detecting the state of a drilling rig, Para. [0002] of DUNLOP) and teaches segmenting the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points and segmenting each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data (a method for automatically detecting a state of a drilling rig, comprising the step of segmenting a signal, by changepoint detectors, into sections each by General Linear Mode to detect temporal features in the data, such as step-changes, ramps etc., and then to determine the probability of each rig state, wherein the set of possible rig states preferably includes more than 10 possible states, and the method preferably generates a probability of each possible rig state, Paras. [0002], [0009], [0114] and [0115], and FIGS. 1-7 of DUNLOP).” Applicant has not addressed the teachings of DUNLOP with relation to segmenting and changepoints/index points.
Fourth, Applicant, at Pages 14 and 15, argues “Coley does not disclose performing statistical analysis within any time segment of a first set of time segments nor does this cited portion of Coley disclose identifying points where statistical properties of the time series data change”. As an initial matter, a “moving average” (as cited from COLEY) is a statistic showing the average change in a data series over time. The moving average (a statistic) captures time series data and shows the average changing over time, while Applicant argues that COLEY does not disclose “statistical analysis within any time segment” nor “points where statistical properties of the time series data change”. It is not clear what Applicant is trying to argue here? Moreover, as further evidence, immediately subsequent to the calculation of the moving averages (block 404), COLEY, at Paras. [0045] & [0046], teaches calculating a difference in the moving averages (block 406) and “calculates changes in difference of hole depth and bit depth … the change values are referred to lagged or leading values … for example, given difference in hole depth and bit depth at times T, T−1, T−2, T−3, T−4, T−5, T−6, T+1, T+2, T+3, T+4, T+5, and T+6 calculated in block 406, the pre-processing module 212 may calculate lagged values as difference of the difference of hole and bit depth as T−(T−1), T−(T−2), T−(T−3), T−(T−4), T−(T−5), and T−(T−6), and calculate leading values as difference of the difference of hole and bit depth at T−(T+1), T−(T+2), T−(T+3), T−(T+4), T−(T+5), and T−(T+6) for depth data sampled at 0.2 hertz … some embodiments may calculate a different number of lagged or leading values, or calculate the lagged and leading values using different time offsets between the difference values used in the calculations … for example, lagged or leading values may be calculated using difference in hole depth and bit depth at times T, T−6, T−11, T−16, T−21, T−26, T−31, T+6, T+11, T+16, T+21, T+26, and T+31 for depth values sampled at 1 hertz.” For these reasons, Applicant’s argument is unpersuasive.
Fifth, Applicant argues, at Paras. 15 & 16, that “Coley does not disclose segmenting each time segment of a first set of time segments into a second set of time segments representing micro activities (performed during wellsite operations) based on identified points of change in statistical properties of corresponding time series data.” This argument is similar to the “Third” argument discussed above and that response to “Third” argument is incorporated by reference. COLEY teaches detecting the same micro activities. Specifically, as noted in the Office Action, COLEY teaches; “if the given rig state is connection, in which a pipe or pipe stand is connected to the drill string 108, then the drilling control system 128 change the operation of the drilling system 100 to reduce the time to perform some operation that performed as part of the connection state”, Para. [0041]; [the connection is interpreted as corresponding as a macro activity [see Applicant’s claim 9], and the “part of the connection state” is interpreted as corresponding to a segmented micro activity]. In addition, as noted in the Office Action, DUNLOP is in the same field of endeavor (automatically detecting the state of a drilling rig, Para. [0002] of DUNLOP) and teaches segmenting the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points and segmenting each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data (a method for automatically detecting a state of a drilling rig, comprising the step of segmenting a signal, by changepoint detectors, into sections each by General Linear Mode to detect temporal features in the data, such as step-changes, ramps etc., and then to determine the probability of each rig state, wherein the set of possible rig states preferably includes more than 10 possible states, and the method preferably generates a probability of each possible rig state, Paras. [0002], [0009], [0114] and [0115], and FIGS. 1-7 of DUNLOP).
For the above reasons, Applicant’s § 103 arguments are unpersuasive. The amendments are newly addressed by the new grounds of rejection under 35 U.S.C. § 103.
Claim Rejections - 35 U.S.C. § 112
The following is a quotation of the first paragraph of 35 U.S.C. 112(a):
(a) IN GENERAL.—The specification shall contain a written description of the invention, and of the manner and process of making and using it, in such full, clear, concise, and exact terms as to enable any person skilled in the art to which it pertains, or with which it is most nearly connected, to make and use the same, and shall set forth the best mode contemplated by the inventor or joint inventor of carrying out the invention.
Claims 1-20 are rejected under 35 U.S.C. § 112(a) as failing to comply with the written description requirement. The claim(s) contains subject matter which was not described in the specification in such a way as to reasonably convey to one skilled in the relevant art that the inventor or a joint inventor, at the time the application was filed, had possession of the claimed invention.
Claim 1 has been amended to recite “[a] computer-implemented method … comprising: identifying non-productive time (NPT) and invisible lost time (ILT) based on the segmenting; and changing wellsite operations based on the identified NPT and ILT.” Applicant’s remarks (filed 10/09/2025) indicate that support for the amendments can be found in Paras. [0002], [0022], [0024] & [0033] of the as-filed specification (PCT Application No. PCT/US2019/058612).
The most pertinent section relevant to NPT and ILT is Para. [0024] of the specification, which recites “Process 200 in this example may provide a way for a well operator to identify when different types of rig activities are performed and make any necessary decisions in real-time to ensure a safe and/or cost-effective drilling operation. For example, complex and/or expensive rig activities may be identified and monitored to calculate and reduce non-productive time (NPT) and/or invisible lost time (ILT)” (emphasis added).
It is not clear that the control of wellsite operations is part of a computer-implemented method in Para. [0024]. Para. [0024] shows that a well operator makes decisions in real-time to ensure cost-effective drilling, i.e., reduce non-productive time (NPT). But the well operator is interpreted as being a person (human being). Thus, it is not clear that the computer-implemented method claim 1, which appear to be directed at an automated action are supported. Applicant-cited Paras. [0002], [0022] & [0033] fail to cure these deficiencies mentioned above.
Accordingly, Applicant has not particularly pointed out where each of the newly added claim limitations originate from in the original disclosure.
Moreover, even if supported, it is not clear how the changing of wellsite operations based on NPT and ILT occurs: i.e., how the computer/processor makes changes to wellsite operations based on the ILT/NPT… e.g., does the computer/processor close a drill when NPT and ILT are above respective thresholds? MPEP 2161.01(I) recites “It is not enough that one skilled in the art could write a program to achieve the claimed function because the specification must explain how the inventor intends to achieve the claimed function to satisfy the written description requirement. See, e.g., Vasudevan Software, Inc. v. MicroStrategy, Inc., 782 F.3d 671, 681-683, 114 USPQ2d 1349, 1356, 1357 (Fed. Cir. 2015) (reversing and remanding the district court’s grant of summary judgment of invalidity for lack of adequate written description where there were genuine issues of material fact regarding "whether the specification show[ed] possession by the inventor of how accessing disparate databases is achieved").” (emphasis added).
Regarding claim 1, the originally-filed specification does not appear to describe how wellsite operations change based on the identified non-productive time (NPT) and invisible lost time (ILT). The specification does not enable one skilled in the art to make or use the invention.
Accordingly, claim 1 is rejected under 35 U.S.C. § 112(a) for failing to comply with the written description requirement.
Claims 1-20 are rejected under 35 U.S.C. § 112(a) as failing to comply with the enablement requirement. The claim(s) contains subject matter which was not described in the specification in such a way as to enable one skilled in the art to which it pertains, or with which it is most nearly connected, to make and/or use the invention.
Regarding claim 1, the claimed ““[a] computer-implemented method … comprising: identifying non-productive time (NPT) and invisible lost time (ILT) based on the segmenting; and changing wellsite operations based on the identified NPT and ILT” is non-enabling. As discussed above, the specification does not enable one skilled in the art to make or use the invention. It is not clear how wellsite operations are changed based on the identified non-productive time (NPT) and invisible lost time (ILT) because the Specification’s detailed description of the NPT and ILT does not discuss any functional steps.
Accordingly, claim 1 is also rejected under 35 U.S.C. § 112(a) for failing to comply with the enablement requirement.
Claims 12 and 17 have substantially similar limitations as recited in claim 1; therefore, they are rejected under 35 U.S.C. § 112(a) for the same reasons. Claims 2-11, 13-16 and 18-20 each depend, directly or indirectly, from one or more of rejected claims 1, 12 and 17. Therefore, claims 2-11, 13-16 and 18-20 each are also rejected under the same rationale since these claims inherit and fail to cure the respective deficiencies of claims 1, 12 and 17.
For compact prosecution, Examiner has made an interpretation of the subject limitations of Claims 1, 12 and 17 (as best understood), which is represented within the mapping of the claims under the 35 U.S.C. §§ 101 and 103 rejection(s).
Claim Rejections - 35 U.S.C. § 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.
To determine if a claim is directed to patent ineligible subject matter, the Court has guided the Office to apply the Alice/Mayo test, which requires:
1. Determining if the claim falls within a statutory category;
2A. Determining if the claim is directed to a patent ineligible judicial exception consisting of a law of nature, a natural phenomenon, or abstract idea; and
2B. If the claim is directed to a judicial exception, determining if the claim recites limitations or elements that amount to significantly more than the judicial exception.
(See MPEP 2106).
Claims 1-20 Step 1, Statutory Category?:
Yes: Claims 1-11 are directed to the statutory category of a process. See MPEP § 2106.03.
Yes: Claims 12-16 are directed to the statutory category of a machine. See MPEP § 2106.03.
Yes: Claims 17-20 are directed to the statutory category of a manufacture. See MPEP § 2106.03.
The following is an analysis based on the 2019 Revised Patent Subject Matter Eligibility Guidance (2019 PEG).
Claims 1-20 Steps 2A and 2B:
Step 2A is a two-prong inquiry. See MPEP 2106.04(II)(A). Under the first prong, examiners evaluate whether a law of nature, natural phenomenon, or abstract idea is set forth or described in the claim. Abstract ideas include mathematical concepts, certain methods of organizing human activity, and mental processes. MPEP § 2106.04(a)(2). The second prong is an inquiry into whether the claim integrates a judicial exception into a practical application. MPEP § 2106.04(d).
Claims 1-20 are rejected under 35 U.S.C. § 101 because the claimed invention is directed to an abstract idea without significantly more. The claim(s) recite a mental process and a mathematical calculation. See MPEP § 2106.04(a)(2)(I) and MPEP § 2106.04(a)(2)(III).
Claim 1 Step 2A Prong One: Does the Claim Recite a Judicial Exception?
For the sake of identifying the abstract ideas, a copy of the claim is provided below. The limitations of the claims that describe abstract ideas are bolded.
1. A computer-implemented method for detecting rig activities during operations at a wellsite, the method comprising:
obtaining, by a computer system, sensor data from rig equipment during wellsite operations;
generating time series data from the obtained sensor data;
analyzing the generated time series data to identify one or more index points where a trend in the time series data changes;
segmenting the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points;
performing statistical analysis on the time series data within each time segment of the first set of time segments to identify points where statistical properties of the time series data change;
segmenting each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data;
identifying non-productive time (NPT) and invisible lost time (ILT) based on the segmenting; and
changing wellsite operations based on the identified NPT and ILT.
The limitations “generating time series data from the obtained sensor data”, “analyzing the generated time series data to identify one or more index points where a trend in the time series data changes”, “segmenting the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points”, “performing statistical analysis on the time series data within each time segment of the first set of time segments to identify points where statistical properties of the time series data change”, “segmenting each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data”, “identifying non-productive time (NPT) and invisible lost time (ILT) based on the segmenting” and “changing wellsite operations based on the identified NPT and ILT” are abstract ideas because they are directed to mental processes, observations, evaluations, judgments, and/or opinions. The limitations, as drafted and under broadest reasonable interpretation, “can be performed in the human mind or by a human using a pen and paper”. See MPEP 2106.04(a)(2)(III). For example, a human could record, with pen and paper, sensor measurements over time; identify where a trend in the sensor measurements changes and segment the recorded measurements based on the identified trend; perform statistical analysis (e.g., averaging) the segmented sensor measurements; further segment the segment based on the averaging/statistical analysis, identify where the time segments are longer than expected/target (e.g., invisible lost time) and allow an operator to make a change based on the ILT and/or downtime/non-production time. In addition, the limitation of “performing statistical analysis on the time series data within each time segment of the first set of time segments to identify points where statistical properties of the time series data change” and “identifying non-productive time (NPT) and invisible lost time (ILT) based on the segmenting” can be performed using mathematical calculations/equations and therefore encompass mathematical concepts. See MPEP 2106.04(a)(2)(I).
Claim 1 Step 2A Prong Two: Does the claim recite additional elements that integrate the judicial exception/Abstract idea into practical application?
Under Step 2A Prong Two, this judicial exception is not integrated into a practical application because the additional claim limitations outside of the abstract idea only present mere instructions to apply an exception, generally link the use of the judicial exception to the technological environment, or insignificant extra-solution activity. In particular, the claim recites the additional limitations of:
• “computer-implemented” and “by a computer system” (mere instructions to apply an exception to a computer – see MPEP 2106.04(d) referencing MPEP 2106.05(f); these limitations can be viewed as nothing more than high level recitations of generic computer components or computer elements used as a tool, and represent mere instructions to apply the abstract idea on a generic computer (see MPEP 2106.05(f)).
• “for detecting rig activities during operations at a wellsite” (general field of use or technological environment – see MPEP 2106.04(d) referencing MPEP 2106.05(h); these limitations can be viewed as nothing more than an attempt to generally link the use of the judicial exception to the technological environment of an oil rig/wellsite (see MPEP 2106.05(h)). Moreover, when reading the preamble in the context of the entire claim, the recitation is not limiting because the body of the claim describes a complete invention and the language recited solely in the preamble does not provide any distinct definition of any of the claimed invention’s limitations. Thus, the preamble of the claim(s) is not considered a limitation and is of no significance to claim construction. See Pitney Bowes, Inc. v. Hewlett-Packard Co., 182 F.3d 1298, 1305, 51 USPQ2d 1161, 1165 (Fed. Cir. 1999). See MPEP § 2111.02.
• “obtaining … sensor data from rig equipment during wellsite operations” (insignificant extra-solution activity – mere data inputting – see MPEP 2106.04(d) referencing MPEP 2106.05(g); this limitation can be viewed as nothing more than mere data gathering in conjunction with the abstract idea (see MPEP § 2106.05(g)).
Claim 1 Step 2B: Do the additional elements, considered individually and in combination, amount to significantly more than the judicial exception?
The Examiner must consider whether each claim limitation individually or as an ordered combination amount to significantly more than the abstract idea. This analysis includes determining whether an inventive concept is furnished by an element or a combination of elements that are beyond the judicial exception. For limitations that were categorized as “apply it” or generally linking the use of the abstract idea to a particular technological environment or field of use, the analysis is the same.
The claim does not include additional elements that are sufficient to amount to significantly more than the judicial exception. As explained above, there are three types of additional elements. The first additional elements are the generic computer components (“computer-implemented” and “by a computer system”), which are high level recitations of generic computer component(s) or computer elements used as a tool, and represent mere instructions to apply the abstract idea on a computer. See MPEP § 2106.05(f). Implementing an abstract idea on a generic computer, does not integrate the abstract idea into a practical application in Step 2A Prong Two or add significantly more in Step 2B, similar to how the recitation of the computer in the claim in Alice amounted to mere instructions to apply the abstract idea of intermediated settlement on a generic computer. See MPEP § 2106.05(f).
The second additional element is “for detecting rig activities during operations at a wellsite”, which is at best viewed as nothing more than an attempt to generally link the use of the judicial exception to the technological environment of an oil rig/wellsite. For the claim limitations that generally link the use of the judicial exception to a particular technological environment or field of use, the claim limitations do not meaningfully limit the claim because the claim limitations employ generic computer functions to execute an abstract idea, even when limiting the use of the idea to one particular environment (e.g., oil rig/wellsite), and does not add significantly more, similar to how limiting the abstract idea in Flook to petrochemical and oil-refining industries was insufficient. See MPEP 2106.05(h). Moreover, as discussed above, the preamble of the claim(s) is not considered a limitation and is of no significance to claim construction. See Pitney Bowes, Inc. v. Hewlett-Packard Co., 182 F.3d 1298, 1305, 51 USPQ2d 1161, 1165 (Fed. Cir. 1999). See MPEP § 2111.02.
The third additional element is “obtaining … sensor data from rig equipment during wellsite operations”, which as explained previously is insignificant extra-solution activity (mere data inputting/gathering). Recitation of obtaining sensor data is mere data gathering that is recited at a high level of generality, and is also well-known. This limitation therefore remains insignificant extra-solution activity even upon reconsideration. Thus, this limitation does not amount to significantly more.
Even when considered in combination, these additional elements represent mere instructions to apply an exception and/or data gathering, which do not provide an inventive concept. The claims do not include any additional elements that are sufficient to amount to significantly more than the judicial exception. See MPEP § 2106.05(f).
Considering the claim limitations as an ordered combination, claim 1 does not include significantly more than the abstract idea. The claim 1 is not patent subject matter eligible. Dependent claims 2-11 are further addressed below after addressing each independent claim.
Claim 12 Step 2A Prong One: Does the Claim Recite a Judicial Exception?
For the sake of identifying the abstract ideas, a copy of the claim is provided below. The limitations of the claims that describe abstract ideas are bolded.
12. A system for detecting rig activities during operations at a wellsite, the system comprising: at least one processor; and a memory coupled to the processor having instructions stored therein, which when executed by the processor, cause the processor to perform a plurality of functions, including functions to:
obtain sensor data from rig equipment during wellsite operations;
generate time series data from the obtained sensor data;
analyze the generated time series data to identify one or more index points where a trend in the time series data changes;
segment the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points;
perform statistical analysis on the time series data within each time segment of the first set of time segments to identify points where statistical properties of the time series data change;
segment each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data;
identify non-productive time (NPT) and invisible lost time (ILT) based on the segmenting; and
change wellsite operations based on the identified NPT and ILT.
The limitations “generate time series data from the obtained sensor data; analyze the generated time series data to identify one or more index points where a trend in the time series data changes; segment the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points; perform statistical analysis on the time series data within each time segment of the first set of time segments to identify points where statistical properties of the time series data change; segment each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data; identify non-productive time (NPT) and invisible lost time (ILT) based on the segmenting; and change wellsite operations based on the identified NPT and ILT” are abstract ideas because they are directed to mental processes, observations, evaluations, judgments, and/or opinions. The limitations, as drafted and under broadest reasonable interpretation, “can be performed in the human mind or by a human using a pen and paper”. See MPEP 2106.04(a)(2)(III). For example, a human could record, with pen and paper, sensor measurements over time; identify where a trend in the sensor measurements changes and segment the recorded measurements based on the identified trend; perform statistical analysis (e.g., averaging) the segmented sensor measurements; further segment the segment based on the averaging/statistical analysis, identify where the time segments are longer than expected/target (e.g., invisible lost time) and allow an operator to make a change based on the ILT and/or downtime/non-production time. In addition, the limitations of “perform statistical analysis on the time series data within each time segment of the first set of time segments to identify points where statistical properties of the time series data change” and “identify non-productive time (NPT) and invisible lost time (ILT) based on the segmenting” can be performed using mathematical calculations/equations and therefore encompass mathematical concepts. See MPEP § 2106.04(a)(2)(I).
Claim 12 Step 2A Prong Two: Does the claim recite additional elements that integrate the judicial exception/Abstract idea into practical application?
Under Step 2A Prong Two, this judicial exception is not integrated into a practical application because the additional claim limitations outside of the abstract idea only present mere instructions to apply an exception, generally link the use of the judicial exception to the technological environment, or insignificant extra-solution activity. In particular, the claim recites the additional limitations of:
• “at least one processor; and a memory coupled to the processor having instructions stored therein, which when executed by the processor, cause the processor to perform a plurality of functions” (mere instructions to apply an exception to a computer – see MPEP 2106.04(d) referencing MPEP 2106.05(f); these limitations can be viewed as nothing more than high level recitations of generic computer components or computer elements used as a tool, and represent mere instructions to apply the abstract idea on a generic computer (see MPEP 2106.05(f)).
• “for detecting rig activities during operations at a wellsite” (general field of use or technological environment – see MPEP 2106.04(d) referencing MPEP 2106.05(h); these limitations can be viewed as nothing more than an attempt to generally link the use of the judicial exception to the technological environment of an oil rig/wellsite (see MPEP 2106.05(h)). Moreover, when reading the preamble in the context of the entire claim, the recitation is not limiting because the body of the claim describes a complete invention and the language recited solely in the preamble does not provide any distinct definition of any of the claimed invention’s limitations. Thus, the preamble of the claim(s) is not considered a limitation and is of no significance to claim construction. See Pitney Bowes, Inc. v. Hewlett-Packard Co., 182 F.3d 1298, 1305, 51 USPQ2d 1161, 1165 (Fed. Cir. 1999). See MPEP § 2111.02.
• “obtain sensor data from rig equipment during wellsite operations” (insignificant extra-solution activity – mere data inputting – see MPEP 2106.04(d) referencing MPEP 2106.05(g); this limitation can be viewed as nothing more than mere data gathering in conjunction with the abstract idea (see MPEP § 2106.05(g)).
Claim 12 Step 2B: Do the additional elements, considered individually and in combination, amount to significantly more than the judicial exception?
The claim does not include additional elements that are sufficient to amount to significantly more than the judicial exception. As explained above, there are three types of additional elements. The first additional elements are the generic computer components (“at least one processor” and “a memory”), which are high level recitations of generic computer component(s) or computer elements used as a tool, and represent mere instructions to apply the abstract idea on a computer. See MPEP § 2106.05(f). Implementing an abstract idea on a generic computer, does not integrate the abstract idea into a practical application in Step 2A Prong Two or add significantly more in Step 2B, similar to how the recitation of the computer in the claim in Alice amounted to mere instructions to apply the abstract idea of intermediated settlement on a generic computer. See MPEP § 2106.05(f).
The second additional element is “for detecting rig activities during operations at a wellsite”, which is at best viewed as nothing more than an attempt to generally link the use of the judicial exception to the technological environment of an oil rig/wellsite. For the claim limitations that generally link the use of the judicial exception to a particular technological environment or field of use, the claim limitations do not meaningfully limit the claim because the claim limitations employ generic computer functions to execute an abstract idea, even when limiting the use of the idea to one particular environment (e.g., oil rig/wellsite), and does not add significantly more, similar to how limiting the abstract idea in Flook to petrochemical and oil-refining industries was insufficient. See MPEP 2106.05(h). Moreover, as discussed above, the preamble of the claim(s) is not considered a limitation and is of no significance to claim construction. See Pitney Bowes, Inc. v. Hewlett-Packard Co., 182 F.3d 1298, 1305, 51 USPQ2d 1161, 1165 (Fed. Cir. 1999). See MPEP § 2111.02.
The third additional element is “obtain sensor data from rig equipment during wellsite operations”, which as explained previously is insignificant extra-solution activity (mere data inputting/gathering). Recitation of obtaining sensor data is mere data gathering that is recited at a high level of generality, and is also well-known. This limitation therefore remains insignificant extra-solution activity even upon reconsideration. Thus, this limitation does not amount to significantly more.
Even when considered in combination, these additional elements represent mere instructions to apply an exception and/or data gathering, which do not provide an inventive concept. The claims do not include any additional elements that are sufficient to amount to significantly more than the judicial exception. See MPEP § 2106.05(f).
Considering the claim limitations as an ordered combination, claim 12 does not include significantly more than the abstract idea. The claim 12 is not patent subject matter eligible. Dependent claims 13-16 are further addressed below after addressing each independent claim.
Claim 17 Step 2A Prong One: Does the Claim Recite a Judicial Exception?
For the sake of identifying the abstract ideas, a copy of the claim is provided below. The limitations of the claims that describe abstract ideas are bolded.
17. A computer-readable storage medium having instructions stored therein, which when executed by a computer cause the computer to perform a plurality of functions, including functions to:
obtain, by a computer system, sensor data from rig equipment during wellsite operations;
generate time series data from the obtained sensor data;
analyze the generated time series data to identify one or more index points where a trend in the time series data changes;
segment the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points;
perform statistical analysis on the time series data within each time segment of the first set of time segments to identify points where statistical properties of the time series data change;
segment each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data;
identify non-productive time (NPT) and invisible lost time (ILT) based on the segmenting; and
change wellsite operations based on the identified NPT and ILT.
The limitations “generate time series data from the obtained sensor data; analyze the generated time series data to identify one or more index points where a trend in the time series data changes; segment the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points; perform statistical analysis on the time series data within each time segment of the first set of time segments to identify points where statistical properties of the time series data change; and segment each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data; identify non-productive time (NPT) and invisible lost time (ILT) based on the segmenting; and change wellsite operations based on the identified NPT and ILT” are abstract ideas because they are directed to mental processes, observations, evaluations, judgments, and/or opinions. The limitations, as drafted and under broadest reasonable interpretation, “can be performed in the human mind or by a human using a pen and paper”. See MPEP 2106.04(a)(2)(III). For example, a human could record, with pen and paper, sensor measurements over time; identify where a trend in the sensor measurements changes and segment the recorded measurements based on the identified trend; perform statistical analysis (e.g., averaging) the segmented sensor measurements; further segment the segment based on the averaging/statistical analysis, identify where the time segments are longer than expected/target (e.g., invisible lost time) and allow an operator to make a change based on the ILT and/or downtime/non-production time. In addition, the limitations of “perform statistical analysis on the time series data within each time segment of the first set of time segments to identify points where statistical properties of the time series data change” and “identify non-productive time (NPT) and invisible lost time (ILT) based on the segmenting” can be performed using mathematical calculations/equations and therefore encompass mathematical concepts. See MPEP § 2106.04(a)(2)(I).
Claim 17 Step 2A Prong Two: Does the claim recite additional elements that integrate the judicial exception/Abstract idea into practical application?
Under Step 2A Prong Two, this judicial exception is not integrated into a practical application because the additional claim limitations outside of the abstract idea only present mere instructions to apply an exception, generally link the use of the judicial exception to the technological environment, or insignificant extra-solution activity. In particular, the claim recites the additional limitations of:
• “instructions stored therein, which when executed by a computer cause the computer to perform a plurality of functions” and “by a computer system” (mere instructions to apply an exception to a computer – see MPEP § 2106.04(d) referencing MPEP § 2106.05(f); these limitations can be viewed as nothing more than high level recitations of generic computer components or computer elements used as a tool, and represent mere instructions to apply the abstract idea on a generic computer (see MPEP § 2106.05(f)).
• “obtain … sensor data from rig equipment during wellsite operations” (insignificant extra-solution activity – mere data inputting – see MPEP 2106.04(d) referencing MPEP 2106.05(g); this limitation can be viewed as nothing more than mere data gathering in conjunction with the abstract idea (see MPEP § 2106.05(g)).
Claim 17 Step 2B: Do the additional elements, considered individually and in combination, amount to significantly more than the judicial exception?
The claim does not include additional elements that are sufficient to amount to significantly more than the judicial exception. As explained above, there are two types of additional elements. The first additional elements are the generic computer components, which are high level recitations of generic computer component(s) or computer elements used as a tool, and represent mere instructions to apply the abstract idea on a computer. See MPEP § 2106.05(f). Implementing an abstract idea on a generic computer, does not integrate the abstract idea into a practical application in Step 2A Prong Two or add significantly more in Step 2B, similar to how the recitation of the computer in the claim in Alice amounted to mere instructions to apply the abstract idea of intermediated settlement on a generic computer. See MPEP § 2106.05(f).
The second additional element is “obtain … sensor data from rig equipment during wellsite operations”, which as explained previously is insignificant extra-solution activity (mere data inputting/gathering). Recitation of obtaining sensor data is mere data gathering that is recited at a high level of generality, and is also well-known. This limitation therefore remains insignificant extra-solution activity even upon reconsideration. Thus, this limitation does not amount to significantly more.
Even when considered in combination, these additional elements represent mere instructions to apply an exception and/or data gathering, which do not provide an inventive concept. The claims do not include any additional elements that are sufficient to amount to significantly more than the judicial exception. See MPEP § 2106.05(f).
Considering the claim limitations as an ordered combination, claim 17 does not include significantly more than the abstract idea. The claim 17 is not patent subject matter eligible. Dependent claims 18-20 are further addressed below.
Dependent Claims 2-11, 13-16 and 18-20
Regarding claims 2-5, 9-11 and 13-16, claim 2 depends from claim 1 and further recites: “wherein generating the time series data from the obtained sensor data comprises using a linear regression to determine a gradient transition of the obtained sensor data over time”, claim 3 depends from claim 2 and further recites: “wherein the one or more identified index points correspond to one or more changes in the gradient transition of the sensor data”, claim 4 depends from claim 2 and further recites: “wherein: positive slope values of a line representing the gradient transition of the sensor data between two identified index points correspond to a first macro activity of well site operations; negative slope values of the line representing the gradient transition of the sensor data between two identified index points correspond to a second macro activity of wellsite operations; and flat slope values of the line representing the gradient transition of the sensor data between two identified index points correspond to a third macro activity of wellsite operations”, claim 5 depends from claim 1 and further recites: “wherein the statistical analysis performed on the time series data identifies where the mean or variance of the time series data changes”, claim 9 depends from claim 1 and further recites: “wherein the macro activities performed during wellsite operations include trip in, trip out, drilling, and making a connection”, claim 10 depends from claim 9 and further recites: “wherein the micro activities performed during wellsite operations include inslip, pre-connection, and post-connection activities of drilling operations”, claim 11 depends from claim 1 and further recites “wherein segmenting each time segment of the first set of time segments into a second set of time segments comprises comparing average values of the operation data before and after the identified points of change”, claim 13 depends from claim 12 and further recites “wherein the plurality of functions comprises functions to calculate one or more operation efficiency descriptors by comparing the time segment duration of at least one macro activity or micro activity with a best practice target duration”, claim 14 depends from claim 13 and further recites “wherein the calculated operation efficiency descriptors include invisible lost time (ILT) and non-productive time (NPT)”, claim 15 depends from claim 12 and further recites “wherein generating the time series data from the obtained sensor data comprises using a linear regression to determine a gradient transition of the obtained sensor data over time, wherein the one or more identified index points correspond to one or more changes in the gradient transition of the sensor data” and claim 16 depends from claim 12 and further recites “wherein: the macro activities performed during wellsite operations include trip in, trip out, drilling, and making a connection; and the micro activities performed during wellsite operations includes inslip, pre- connection, and post-connection activities of drilling operations.” These features have been considered in combination with the features required by the claim(s) from which these claims depend. The bolded portion(s) of the additional feature(s) are considered to further clarify the details of the mathematical concepts and/or the human’s mental activity (e.g., with pen and paper). See MPEP §§ 2106.04(a)(2)(I) and (III). Therefore, these features are considered to be drawn to the abstract idea without adding significantly more, and hence claims 2-5, 9-11 and 13-16 are considered to be ineligible under 35 U.S.C. § 101.
Regarding claim 6, claim 6 depends from claim 1 and further recites: “wherein the sensor data obtained comprises bit depth, borehole depth, and hook load values measured by one or more sensors coupled to the rig equipment during the wellsite operations.” These features have been considered in combination with the features required by the claim(s) from which these claims depend. These additional features are considered to be directed to the insignificant extra-solution activity of data gathering, which cannot provide an inventive concept. See MPEP § 2106.05(g). Therefore, these features are considered to be drawn to the abstract idea without adding significantly more, and hence claim 6 is considered to be ineligible under 35 U.S.C. § 101.
Claim 18 has substantially similar limitations as recited in claim 6; therefore, it is rejected under 35 U.S.C. § 101 for the same reasons.
Regarding claims 7, 8, 19 and 20, claim 7 depends from claim 6 and further recites: “wherein generating the time series data from the obtained sensor data comprises generating a time series curve indicating a difference between respective values of borehole depth and bit depth measured by the one or more sensors during the wellsite operations over a period of time”, claim 8 depends from claim 7 and further recites: “wherein generating the time series data of the obtained sensor data further comprises using a linear regression to determine a gradient for the time series curve with respect to borehole depth and the difference between borehole depth and bit depth”, and claim 19 depends from claim 18 and further recites: “wherein performing statistical analysis on the time series data comprises applying a Pruned Exact Linear Time (PELT) algorithm to the time series data within each time segment of the first set of time segments to detect when a hook load value drops.” These features have been considered in combination with the features required by the claim(s) from which these claims depend. The bolded portion(s) of the additional feature(s) are considered to further clarify the details of the mathematical concepts and/or the human’s mental activity (e.g., with pen and paper). See MPEP §§ 2106.04(a)(2)(I) and (III). Therefore, these features are considered to be drawn to the abstract idea without adding significantly more, and hence claims 7, 8, 19 and 20 are considered to be ineligible under 35 U.S.C. § 101.
Claim 20 has substantially similar limitations as recited in claim 8; therefore, it is rejected under 35 U.S.C. § 101 for the same reasons.
For the foregoing reasons, claims 1-20 are rejected under 35 U.S.C. § 101 as being directed to patent ineligible subject matter.
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.
Regarding claim 5, COLEY as modified discloses the method of claim 1, wherein the statistical analysis performed on the time series data identifies where the mean or variance of the time series data changes (smoothing is applied to the hole depth measurements and the bit depth measurements … the smoothing may include computing a moving average of the hole depth and a moving average of the bit depth, Para. [0044] of COLEY; See also in block 408, the pre-processing module 212 calculates changes in difference of hole depth and bit depth … given difference in hole depth and bit depth at times T, T−1, T−2, T−3, T−4, T−5, T−6, T+1, T+2, T+3, T+4, T+5, and T+6 calculated in block 406, Para. [0046] of COLEY; See also the pre-processed sensor measurements and additional values generated by the pre-processing module 212 are provided to the rig state model 216 for use in producing a rig state value, Para. [0050] of COLEY).
Regarding claim 6, COLEY as modified discloses the method of claim 1, wherein the sensor data obtained comprises bit depth, borehole depth, and hook load values measured by one or more sensors coupled to the rig equipment during the wellsite operations (the drilling control system 128 may acquire measurements of … hookload, measured hole depth, measured bit depth, Para. [0034] of COLEY).
Regarding claim 9, COLEY as modified discloses the method of claim 1, wherein the macro activities performed during wellsite operations include trip in, trip out, drilling, and making a connection (if the rig state changes to “connection,” the post-processing module 218 may examine the rig states generated for a predetermined time prior to the change to “connection” … if the post-processing module 218 finds another “connection” rig state preceding the change to “connection” and the bit depth between the two “connection” states has changed by less than a predetermined amount (e.g., less than 10 feet), then the post-processing module 218 may change all rig state values between the two “connection” states to “connection”, Para. [0066]; See also in block 608, if the rig state value received from the rig state model 216 is “static,” then the post-processing module 218 determines whether the “trip in” state or the “trip out” state may be more appropriate … for example, if the rig state preceding “static” is either “trip in” or “trip out,” and time spent in the “static” state is less than a predetermined amount (e.g., 20 seconds) then the post-processing module 218 may change the rig state value to the state preceding “static”, Para. [0064] of COLEY; See also drilling control system 128 processes the sensor outputs to evaluate and control the drilling process … the drilling control system 128 includes a rig state monitor 144 … the rig state monitor 144 analyzes and processes measurements received by the various sensors of the system 100 to determine the state of the rig at any given time, Para. [0021] of COLEY).
Regarding claim 10, COLEY as modified discloses the method of claim 9, wherein the micro activities performed during wellsite operations include inslip, pre-connection, and post-connection activities of drilling operations (if the given rig state is connection, in which a pipe or pipe stand is connected to the drill string 108, then the drilling control system 128 change the operation of the drilling system 100 to reduce the time to perform some operation that performed as part of the connection state, Para. [0041] of COLEY; See also, regarding pre/post connection states: analyzes rig states immediately prior to a change in state to “connection.” For example, if the rig state prior to the change in state to “connection” is “rotary drilling” and the hole depth is not changing, then the post-processing module 218 may change the state to “circulating and rotating.” If the rig state prior to the change in state to “connection” is “slide drilling” and the hole depth is not changing, then the post-processing module 218 may change the state to “circulating”, Para. [0065] of COLEY; See also next paragraph: if the post-processing module 218 finds another “connection” rig state preceding the change to “connection” and the bit depth between the two “connection” states has changed by less than a predetermined amount (e.g., less than 10 feet), then the post-processing module 218 may change all rig state values between the two “connection” states to “connection”, Para. [0066] of COLEY; See also, regarding inslip, COLEY teaches adjusting includes analyzing each of the hookload values to determine whether the hookload value was acquired while connecting a drill pipe to a drill string … the analyzing includes for each of the hookload values, assigning, to the hookload value, a probability that the hookload value was acquired while connecting a drill pipe to the drill string, Para. [0068]; [Applicant’s specification, at Para. [0025], indicates that adding another section of pipe to the drill string may correspond to an in slip activity]).
Regarding claim 11, COLEY as modified discloses the method of claim 1, wherein segmenting each time segment of the first set of time segments into a second set of time segments comprises comparing average values of the operation data before and after the identified points of change (smoothing is applied to the hole depth measurements and the bit depth measurements … the smoothing may include computing a moving average of the hole depth and a moving average of the bit depth, Para. [0044]; See also the pre-processed sensor measurements and additional values generated by the pre-processing module 212 are provided to the rig state model 216 for use in producing a rig state value, Para. [0050] of COLEY; See also given difference in hole depth and bit depth at times T, T−1, T−2, T−3, T−4, T−5, T−6, T+1, T+2, T+3, T+4, T+5, and T+6 calculated in block 406, the pre-processing module 212 may calculate lagged values as difference of the difference of hole and bit depth as T−(T−1), T−(T−2), T−(T−3), T−(T−4), T−(T−5), and T−(T−6), and calculate leading values as difference of the difference of hole and bit depth at T−(T+1), T−(T+2), T−(T+3), T−(T+4), T−(T+5), and T−(T+6) for depth data sampled at 0.2 hertz, Para. [0046] of COLEY; See also segments of constant mean, Para. [0150] of DUNLOP; See also changepoint detector is used with G 1 (data with constant mean), Para. [0151] of DUNLOP; See also inference is performed via the mean level of the TQA channel (the parameter b for the current segment in the changepoint detector), Para. [0154] of DUNLOP).
Regarding claim 12, COLEY discloses a system for detecting rig activities during operations at a wellsite (drilling control system embodied in a computer, Para. [0024]; See also drilling system and method disclosed herein apply a rig state determination technique that provides improved accuracy of rig state detection versus conventional techniques, Para. [0014]; [rig state is interpreted as corresponding to rig activity during operations]; See also measured values acquired while drilling a wellbore, Para. [0014]; [wellbore is interpreted as corresponding to a wellsite]), the system comprising: at least one processor (processor 202, Para. [0028]); and a memory coupled to the processor having instructions stored therein, which when executed by the processor, cause the processor to perform a plurality of functions (software programming, including instructions executable by the processor 202, is stored in the program/data storage 206 … the program/data storage 206 is a non-transitory computer-readable medium, Para. [0028]; See also code stored in memory (e.g., non-volatile memory), and sometimes referred to as “embedded firmware,” is included within the definition of software, Para. [0012]), including functions to:
obtain sensor data from rig equipment during wellsite operations (receive measurements produced by rig sensors, such as downhole sensors and sensors disposed in surface equipment of the rig, Para. [0014]);
generate time series data from the obtained sensor data (the post-processed rig state may be stored in the rig state data 238 in sequence with previously generated rig states to form a record of the operating states of the drilling system 100 over time, Para. [0039]; See also COLEY teaches both generating rig states over time based on sensor measurements (which reads on “time series data from obtained sensor data”) and also rig sensor data (measurements, such as depth) over time. See, e.g., Para. [0014] of COLEY (receive measurements produced by rig sensors … measurements may include values for bit depth, hole depth, … the sensor measurements are preprocessed for application to a rig state model … the rig state model generates a rig state value based on the preprocessed sensor measurements) and Para. [0046] of COLEY (given difference in hole depth and bit depth at times T, T−1, T−2, T−3, T−4, T−5, T−6, T+1, T+2, T+3, T+4, T+5, and T+6 calculated in block 406). Para. [0046] of COLEY clearly shows generating time series sensor data (i.e., sensor measurements, such as depth). See also FIGS. 1-6 of COLEY and corresponding description);
analyze the generated time series data to identify one or more index points where a trend in the time series data changes (if the rig state value received from the rig state model 216 is “rotating off bottom,” but the bit depth measurements at times about the time corresponding to the rig state determination indicate that drill bit depth is increasing, then the post-processing module 218 may change the rig state value to “reaming down with flow” … if the rig state value received from the rig state model 216 is “rotating off bottom,” but the bit depth measurements indicate that drill bit depth is decreasing, then the post-processing module 218 may change the rig state value to “backreaming without flow”, Para. [0061]; [the bit depth changing from increasing to decreasing is interpreted as a time point where the trend changes]; See also discussion of Paras. [0064] and [0066] in next paragraph with reference to “connection”, “trip in” and “trip out” macro/major states/activities]; See also rig states in Para. [0022]; Paras. [0061], [0064] & [0066] of COLEY discuss drill bit depth changing from increasing to decreasing to identify “reaming down” and “backreaming”, respectively, and Applicant’s specification, Paras. [0025]-[0026] appears to indicate that “reaming” is a type of tracked macro activity);
segment the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points (if the rig state changes to “connection,” the post-processing module 218 may examine the rig states generated for a predetermined time prior to the change to “connection” … if the post-processing module 218 finds another “connection” rig state preceding the change to “connection” and the bit depth between the two “connection” states has changed by less than a predetermined amount (e.g., less than 10 feet), then the post-processing module 218 may change all rig state values between the two “connection” states to “connection”, Para. [0066]; See also in block 608, if the rig state value received from the rig state model 216 is “static,” then the post-processing module 218 determines whether the “trip in” state or the “trip out” state may be more appropriate … for example, if the rig state preceding “static” is either “trip in” or “trip out,” and time spent in the “static” state is less than a predetermined amount (e.g., 20 seconds) then the post-processing module 218 may change the rig state value to the state preceding “static”, Para. [0064]; [“connection”, “trip in” and “trip out” are interpreted as macro activities based on Applicant’s original claim 9]);
perform statistical analysis on the time series data within each time segment of the first set of time segments to identify points where statistical properties of the time series data change (smoothing is applied to the hole depth measurements and the bit depth measurements … the smoothing may include computing a moving average of the hole depth and a moving average of the bit depth, Para. [0044]; See also immediately subsequent to the calculation of the moving averages (block 404), COLEY, at Paras. [0045] & [0046], teaches calculating a difference in the moving averages (block 406) and “calculates changes in difference of hole depth and bit depth … the change values are referred to lagged or leading values … for example, given difference in hole depth and bit depth at times T, T−1, T−2, T−3, T−4, T−5, T−6, T+1, T+2, T+3, T+4, T+5, and T+6 calculated in block 406, the pre-processing module 212 may calculate lagged values as difference of the difference of hole and bit depth as T−(T−1), T−(T−2), T−(T−3), T−(T−4), T−(T−5), and T−(T−6), and calculate leading values as difference of the difference of hole and bit depth at T−(T+1), T−(T+2), T−(T+3), T−(T+4), T−(T+5), and T−(T+6) for depth data sampled at 0.2 hertz … some embodiments may calculate a different number of lagged or leading values, or calculate the lagged and leading values using different time offsets between the difference values used in the calculations … for example, lagged or leading values may be calculated using difference in hole depth and bit depth at times T, T−6, T−11, T−16, T−21, T−26, T−31, T+6, T+11, T+16, T+21, T+26, and T+31 for depth values sampled at 1 hertz”; See also the pre-processed sensor measurements and additional values generated by the pre-processing module 212 are provided to the rig state model 216 for use in producing a rig state value, Para. [0050]);
segment each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data (if the given rig state is connection, in which a pipe or pipe stand is connected to the drill string 108, then the drilling control system 128 change the operation of the drilling system 100 to reduce the time to perform some operation that performed as part of the connection state, Para. [0041]; [the connection is interpreted as corresponding as a macro activity [see Applicant’s claim 9], and the “part of the connection state” is interpreted as corresponding to a segmented micro activity]; See also, regarding pre/post connection states: analyzes rig states immediately prior to a change in state to “connection.” For example, if the rig state prior to the change in state to “connection” is “rotary drilling” and the hole depth is not changing, then the post-processing module 218 may change the state to “circulating and rotating.” If the rig state prior to the change in state to “connection” is “slide drilling” and the hole depth is not changing, then the post-processing module 218 may change the state to “circulating”, Para. [0065] of COLEY; See also next paragraph: if the post-processing module 218 finds another “connection” rig state preceding the change to “connection” and the bit depth between the two “connection” states has changed by less than a predetermined amount (e.g., less than 10 feet), then the post-processing module 218 may change all rig state values between the two “connection” states to “connection”, Para. [0066] of COLEY; See also, regarding inslip, COLEY teaches adjusting includes analyzing each of the hookload values to determine whether the hookload value was acquired while connecting a drill pipe to a drill string … the analyzing includes for each of the hookload values, assigning, to the hookload value, a probability that the hookload value was acquired while connecting a drill pipe to the drill string, Para. [0068]; [Applicant’s specification, at Para. [0025], indicates that adding another section of pipe to the drill string may correspond to an in slip activity]).
Although COLEY appears to show the detection of the same types of macro and micro activities, COLEY arguably does not explicitly disclose all of the features of segment the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points and segment each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data. DUNLOP, however, is in the same field of endeavor (automatically detecting the state of a drilling rig, Para. [0002] of DUNLOP) and teaches segment the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points and segment each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data (a method for automatically detecting a state of a drilling rig, comprising the step of segmenting a signal, by changepoint detectors, into sections each by General Linear Mode to detect temporal features in the data, such as step-changes, ramps etc., and then to determine the probability of each rig state, wherein the set of possible rig states preferably includes more than 10 possible states, and the method preferably generates a probability of each possible rig state, Paras. [0002], [0009], [0114] and [0115], and FIGS. 1-7 of DUNLOP).
It would have been obvious for one of ordinary skill in the art before the effective filing date of the invention to modify the drilling rig state determination (title) of COLEY with the rig state detection (title) of DUNLOP [to arrive at the claimed features] for the purpose of increasing the accuracy of detection of many drilling events (DUNLOP at Para. [0027]).
COLEY also appears to fail to explicitly disclose identify non-productive time (NPT) and invisible lost time (ILT) based on the segmenting; and change wellsite operations based on the identified NPT and ILT.
MANDAVA, however, is in the field of identifying and tracking the drilling process (Para. [0017] of MANDAVA) and teaches identify non-productive time (NPT) and invisible lost time (ILT) based on the segmenting (a method for tracking efficiency of a drilling rig is provided, which may include: receiving, with a controller, at least one measurable parameter for a drilling operation from a sensor system associated with the drilling rig; generating at least one Key Performance Indicator (KPI) based on the drilling operation; calculating, with the controller, at least one performance time period for each of the at least one KPI based on the at least one measurable parameter, receiving, with the controller, at least one target time period; calculating, with the controller, an Invisible Lost Time (ILT) period based on a difference between the at least one performance time period and the at least one target time period; and outputting the ILT period to a user on an output device, Para. [0096]; See also other KPIs may include downtime, Para. [0054]; [downtime corresponds to non-productive time]); and change wellsite operations based on the identified NPT and ILT (“Invisible Lost Time (ILT)” and “Downtime (DT)” (i.e., non-production time) are “calculated using sensor readings” (Abstract and Paras. [0017] & [0037] of MANDAVA) and “identification, tracking, and application of ILT and IST periods to improve the efficiency of drilling operations”, Para. [0020] of MANDAVA; [Examiner’s Note: Para. [0024] of Applicant’s specification show that a well operator makes decisions in real-time to ensure cost-effective drilling, i.e., reduce non-productive time (NPT) and the well operator is interpreted as being a person (human being)]; See also drilling operators generally seek to minimize time losses associated with expected or unexpected events, Para. [0003] of MANDAVA; See also the total ILT time and ILT percentage may allow the user to see a categorized overview of time lost on the drilling rig. This may help the user to target improvements to the drilling process, Para. [0067] of MANDAVA; See also the report is used as a target for other drilling operations and may be used, for example, in step 330 of FIG. 3, Paras. [0068]-[0077] of MANDAVA).
It would have been obvious for one of ordinary skill in the art before the effective filing date of the invention to modify the drilling rig state determination (title) of COLEY with the drilling state efficiency tracking (title) of MANDAVA [to arrive at the claimed features] for the purpose of minimizing time losses associated with expected or unexpected events (MANDAVA at Para. [0003]).
Regarding claim 13, COLEY as modified discloses the system of claim 12, wherein the plurality of functions comprises functions to calculate one or more operation efficiency descriptors by comparing the time segment duration of at least one macro activity or micro activity with a best practice target duration (a method for tracking efficiency of a drilling rig is provided, which may include: receiving, with a controller, at least one measurable parameter for a drilling operation from a sensor system associated with the drilling rig; generating at least one Key Performance Indicator (KPI) based on the drilling operation; calculating, with the controller, at least one performance time period for each of the at least one KPI based on the at least one measureable parameter, receiving, with the controller, at least one target time period; calculating, with the controller, an Invisible Lost Time (ILT) period based on a difference between the at least one performance time period and the at least one target time period; and outputting the ILT period to a user on an output device, Para. [0096] of MANDAVA).
Regarding claim 14, COLEY as modified discloses the system of claim 13, wherein the calculated operation efficiency descriptors include invisible lost time (ILT) and non-productive time (NPT) (Invisible Lost Time (ILT) period based on a difference between the at least one performance time period and the at least one target time period, Para. [0096] of MANDAVA; See also other KPIs may include downtime, Para. [0054]; [downtime corresponds to non-productive time]).
Regarding claim 16, COLEY as modified discloses the system of claim 12, wherein: the macro activities performed during wellsite operations include trip in, trip out, drilling, and making a connection (if the rig state changes to “connection,” the post-processing module 218 may examine the rig states generated for a predetermined time prior to the change to “connection” … if the post-processing module 218 finds another “connection” rig state preceding the change to “connection” and the bit depth between the two “connection” states has changed by less than a predetermined amount (e.g., less than 10 feet), then the post-processing module 218 may change all rig state values between the two “connection” states to “connection”, Para. [0066]; See also in block 608, if the rig state value received from the rig state model 216 is “static,” then the post-processing module 218 determines whether the “trip in” state or the “trip out” state may be more appropriate … for example, if the rig state preceding “static” is either “trip in” or “trip out,” and time spent in the “static” state is less than a predetermined amount (e.g., 20 seconds) then the post-processing module 218 may change the rig state value to the state preceding “static”, Para. [0064] of COLEY; See also drilling control system 128 processes the sensor outputs to evaluate and control the drilling process … the drilling control system 128 includes a rig state monitor 144 … the rig state monitor 144 analyzes and processes measurements received by the various sensors of the system 100 to determine the state of the rig at any given time, Para. [0021] of COLEY); and the micro activities performed during wellsite operations includes inslip, pre- connection, and post-connection activities of drilling operations (if the given rig state is connection, in which a pipe or pipe stand is connected to the drill string 108, then the drilling control system 128 change the operation of the drilling system 100 to reduce the time to perform some operation that performed as part of the connection state, Para. [0041] of COLEY; [the connection is interpreted as corresponding as a macro activity [see Applicant’s claim 9], and the “part of the connection state” is interpreted as corresponding to a segmented micro activity]; See also, regarding pre/post connection states: analyzes rig states immediately prior to a change in state to “connection.” For example, if the rig state prior to the change in state to “connection” is “rotary drilling” and the hole depth is not changing, then the post-processing module 218 may change the state to “circulating and rotating.” If the rig state prior to the change in state to “connection” is “slide drilling” and the hole depth is not changing, then the post-processing module 218 may change the state to “circulating”, Para. [0065] of COLEY; See also next paragraph: if the post-processing module 218 finds another “connection” rig state preceding the change to “connection” and the bit depth between the two “connection” states has changed by less than a predetermined amount (e.g., less than 10 feet), then the post-processing module 218 may change all rig state values between the two “connection” states to “connection”, Para. [0066] of COLEY; See also, regarding inslip, COLEY teaches adjusting includes analyzing each of the hookload values to determine whether the hookload value was acquired while connecting a drill pipe to a drill string … the analyzing includes for each of the hookload values, assigning, to the hookload value, a probability that the hookload value was acquired while connecting a drill pipe to the drill string, Para. [0068]; [Applicant’s specification, at Para. [0025], indicates that adding another section of pipe to the drill string may correspond to an in slip activity]).
Regarding claim 17, COLEY discloses a computer-readable storage medium having instructions stored therein, which when executed by a computer cause the computer to perform a plurality of functions (software programming, including instructions executable by the processor 202, is stored in the program/data storage 206 … the program/data storage 206 is a non-transitory computer-readable medium, Para. [0028]), including functions to:
obtain, by a computer system, sensor data from rig equipment during wellsite operations (receive measurements produced by rig sensors, such as downhole sensors and sensors disposed in surface equipment of the rig, Para. [0014]; See also drilling control system embodied in a computer, Para. [0024]; See also drilling system and method disclosed herein apply a rig state determination technique that provides improved accuracy of rig state detection versus conventional techniques, Para. [0014]; [rig state is interpreted as corresponding to rig activity during operations]; See also measured values acquired while drilling a wellbore, Para. [0014]; [wellbore is interpreted as corresponding to a wellsite]);
generate time series data from the obtained sensor data (the post-processed rig state may be stored in the rig state data 238 in sequence with previously generated rig states to form a record of the operating states of the drilling system 100 over time, Para. [0039] ; See also COLEY teaches both generating rig states over time based on sensor measurements (which reads on “time series data from obtained sensor data”) and also rig sensor data (measurements, such as depth) over time. See, e.g., Para. [0014] of COLEY (receive measurements produced by rig sensors … measurements may include values for bit depth, hole depth, … the sensor measurements are preprocessed for application to a rig state model … the rig state model generates a rig state value based on the preprocessed sensor measurements) and Para. [0046] of COLEY (given difference in hole depth and bit depth at times T, T−1, T−2, T−3, T−4, T−5, T−6, T+1, T+2, T+3, T+4, T+5, and T+6 calculated in block 406). Para. [0046] of COLEY clearly shows generating time series sensor data (i.e., sensor measurements, such as depth). See also FIGS. 1-6 of COLEY and corresponding description);
analyze the generated time series data to identify one or more index points where a trend in the time series data changes (if the rig state value received from the rig state model 216 is “rotating off bottom,” but the bit depth measurements at times about the time corresponding to the rig state determination indicate that drill bit depth is increasing, then the post-processing module 218 may change the rig state value to “reaming down with flow” … if the rig state value received from the rig state model 216 is “rotating off bottom,” but the bit depth measurements indicate that drill bit depth is decreasing, then the post-processing module 218 may change the rig state value to “backreaming without flow”, Para. [0061]; [the bit depth changing from increasing to decreasing is interpreted as a time point where the trend changes]; See also discussion of Paras. [0064] and [0066] in next paragraph with reference to “connection”, “trip in” and “trip out” macro/major states/activities]; See also rig states in Para. [0022]; Paras. [0061], [0064] & [0066] of COLEY discuss drill bit depth changing from increasing to decreasing to identify “reaming down” and “backreaming”, respectively, and Applicant’s specification, Paras. [0025]-[0026] appears to indicate that “reaming” is a type of tracked macro activity);
segment the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points (if the rig state changes to “connection,” the post-processing module 218 may examine the rig states generated for a predetermined time prior to the change to “connection” … if the post-processing module 218 finds another “connection” rig state preceding the change to “connection” and the bit depth between the two “connection” states has changed by less than a predetermined amount (e.g., less than 10 feet), then the post-processing module 218 may change all rig state values between the two “connection” states to “connection”, Para. [0066]; See also in block 608, if the rig state value received from the rig state model 216 is “static,” then the post-processing module 218 determines whether the “trip in” state or the “trip out” state may be more appropriate … for example, if the rig state preceding “static” is either “trip in” or “trip out,” and time spent in the “static” state is less than a predetermined amount (e.g., 20 seconds) then the post-processing module 218 may change the rig state value to the state preceding “static”, Para. [0064]; [“connection”, “trip in” and “trip out” are interpreted as macro activities based on Applicant’s original claim 9]);
perform statistical analysis on the time series data within each time segment of the first set of time segments to identify points where statistical properties of the time series data change (smoothing is applied to the hole depth measurements and the bit depth measurements … the smoothing may include computing a moving average of the hole depth and a moving average of the bit depth, Para. [0044]; See also immediately subsequent to the calculation of the moving averages (block 404), COLEY, at Paras. [0045] & [0046], teaches calculating a difference in the moving averages (block 406) and “calculates changes in difference of hole depth and bit depth … the change values are referred to lagged or leading values … for example, given difference in hole depth and bit depth at times T, T−1, T−2, T−3, T−4, T−5, T−6, T+1, T+2, T+3, T+4, T+5, and T+6 calculated in block 406, the pre-processing module 212 may calculate lagged values as difference of the difference of hole and bit depth as T−(T−1), T−(T−2), T−(T−3), T−(T−4), T−(T−5), and T−(T−6), and calculate leading values as difference of the difference of hole and bit depth at T−(T+1), T−(T+2), T−(T+3), T−(T+4), T−(T+5), and T−(T+6) for depth data sampled at 0.2 hertz … some embodiments may calculate a different number of lagged or leading values, or calculate the lagged and leading values using different time offsets between the difference values used in the calculations … for example, lagged or leading values may be calculated using difference in hole depth and bit depth at times T, T−6, T−11, T−16, T−21, T−26, T−31, T+6, T+11, T+16, T+21, T+26, and T+31 for depth values sampled at 1 hertz”; See also the pre-processed sensor measurements and additional values generated by the pre-processing module 212 are provided to the rig state model 216 for use in producing a rig state value, Para. [0050]);
segment each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data (if the given rig state is connection, in which a pipe or pipe stand is connected to the drill string 108, then the drilling control system 128 change the operation of the drilling system 100 to reduce the time to perform some operation that performed as part of the connection state, Para. [0041]; [the connection is interpreted as corresponding as a macro activity [see Applicant’s claim 9], and the “part of the connection state” is interpreted as corresponding to a segmented micro activity]; See also, regarding pre/post connection states: analyzes rig states immediately prior to a change in state to “connection.” For example, if the rig state prior to the change in state to “connection” is “rotary drilling” and the hole depth is not changing, then the post-processing module 218 may change the state to “circulating and rotating.” If the rig state prior to the change in state to “connection” is “slide drilling” and the hole depth is not changing, then the post-processing module 218 may change the state to “circulating”, Para. [0065] of COLEY; See also next paragraph: if the post-processing module 218 finds another “connection” rig state preceding the change to “connection” and the bit depth between the two “connection” states has changed by less than a predetermined amount (e.g., less than 10 feet), then the post-processing module 218 may change all rig state values between the two “connection” states to “connection”, Para. [0066] of COLEY; See also, regarding inslip, COLEY teaches adjusting includes analyzing each of the hookload values to determine whether the hookload value was acquired while connecting a drill pipe to a drill string … the analyzing includes for each of the hookload values, assigning, to the hookload value, a probability that the hookload value was acquired while connecting a drill pipe to the drill string, Para. [0068]; [Applicant’s specification, at Para. [0025], indicates that adding another section of pipe to the drill string may correspond to an in slip activity]).
Although COLEY appears to show the detection of the same types of macro and micro activities, COLEY arguably does not explicitly disclose all of the features of segment the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points and segment each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data. DUNLOP, however, is in the same field of endeavor (automatically detecting the state of a drilling rig, Para. [0002] of DUNLOP) and teaches segment the time series data into a first set of time segments representing macro activities performed during the wellsite operations, based on the one or more identified index points and segment each time segment of the first set of time segments into a second set of time segments representing micro activities performed during the wellsite operations, based on the identified points of change in the statistical properties of the corresponding time series data (a method for automatically detecting a state of a drilling rig, comprising the step of segmenting a signal, by changepoint detectors, into sections each by General Linear Mode to detect temporal features in the data, such as step-changes, ramps etc., and then to determine the probability of each rig state, wherein the set of possible rig states preferably includes more than 10 possible states, and the method preferably generates a probability of each possible rig state, Paras. [0002], [0009], [0114] and [0115], and FIGS. 1-7 of DUNLOP).
It would have been obvious for one of ordinary skill in the art before the effective filing date of the invention to modify the drilling rig state determination (title) of COLEY with the rig state detection (title) of DUNLOP [to arrive at the claimed features] for the purpose of increasing the accuracy of detection of many drilling events (DUNLOP at Para. [0027]).
COLEY also appears to fail to explicitly disclose identify non-productive time (NPT) and invisible lost time (ILT) based on the segmenting; and change wellsite operations based on the identified NPT and ILT.
MANDAVA, however, is in the field of identifying and tracking the drilling process (Para. [0017] of MANDAVA) and teaches identify non-productive time (NPT) and invisible lost time (ILT) based on the segmenting (a method for tracking efficiency of a drilling rig is provided, which may include: receiving, with a controller, at least one measurable parameter for a drilling operation from a sensor system associated with the drilling rig; generating at least one Key Performance Indicator (KPI) based on the drilling operation; calculating, with the controller, at least one performance time period for each of the at least one KPI based on the at least one measurable parameter, receiving, with the controller, at least one target time period; calculating, with the controller, an Invisible Lost Time (ILT) period based on a difference between the at least one performance time period and the at least one target time period; and outputting the ILT period to a user on an output device, Para. [0096]; See also other KPIs may include downtime, Para. [0054]; [downtime corresponds to non-productive time]); and change wellsite operations based on the identified NPT and ILT (“Invisible Lost Time (ILT)” and “Downtime (DT)” (i.e., non-production time) are “calculated using sensor readings” (Abstract and Paras. [0017] & [0037] of MANDAVA) and “identification, tracking, and application of ILT and IST periods to improve the efficiency of drilling operations”, Para. [0020] of MANDAVA; [Examiner’s Note: Para. [0024] of Applicant’s specification show that a well operator makes decisions in real-time to ensure cost-effective drilling, i.e., reduce non-productive time (NPT) and the well operator is interpreted as being a person (human being)]; See also drilling operators generally seek to minimize time losses associated with expected or unexpected events, Para. [0003] of MANDAVA; See also the total ILT time and ILT percentage may allow the user to see a categorized overview of time lost on the drilling rig. This may help the user to target improvements to the drilling process, Para. [0067] of MANDAVA; See also the report is used as a target for other drilling operations and may be used, for example, in step 330 of FIG. 3, Paras. [0068]-[0077] of MANDAVA).
It would have been obvious for one of ordinary skill in the art before the effective filing date of the invention to modify the drilling rig state determination (title) of COLEY with the drilling state efficiency tracking (title) of MANDAVA [to arrive at the claimed features] for the purpose of minimizing time losses associated with expected or unexpected events (MANDAVA at Para. [0003]).
Claim 18 has substantially similar limitations as recited in claim 6; therefore, it is rejected under 35 U.S.C. § 103 for the same reasons.
Claims 2-4, 7, 8 and 15 are rejected under 35 U.S.C. § 103 as being unpatentable over COLEY (U.S. Patent Publication No. 2021/0285315 A1 in view of DUNLOP et al (U.S. Patent Publication No. 2004/0124012 A1), and further in view of MANDAVA et al. (U.S. Patent Publication No. 2017/0300845 A1) and POP et al. (U.S. Patent Publication No. 2009/0165548 A1).
Regarding claim 2, COLEY as modified discloses the method of claim 1 and generating the time series data from the obtained sensor data (shown in the mapping of claim 1 above) and regression (Para. [0037] of COLEY, Para. [0121] of DUNLOP) but fails to explicitly disclose using a linear regression to determine a gradient transition of the obtained sensor data over time.
POP, however, is in the field of evaluating data collected in a downhole/well log (Para. [0002] of POP) and teaches wherein generating the time series data from the obtained sensor data (the investigation phase may be analyzed to determine the pressure drop over time to determine various characteristics of the pressure trace, Para. [0101]; See also using conventional pressure and temperature sensors, Para. [0201] of POP) comprises using a linear regression (measured pressure rate may be determined from a pressure curve slope … known techniques comprise curve fitting, linear regression, Para. [0327] of POP) to determine a gradient transition of the obtained sensor data over time (the pressure curve near the end of the buildup may in some cases be relatively horizontal or sufficiently flat, and/or the rate of change of pressure may be small or close to zero … this may indicate that the pressure has stabilized and reached formation pressure, and that the final pressure is a good estimate of the formation pressure … in other cases the rate of change of pressure may be large (increasing or decreasing) which may indicate that the formation pressure has not yet been reached … information may also be used to determine that the pretest has not reached stabilization, Para. [0330] of POP).
It would have been obvious for one of ordinary skill in the art before the effective filing date of the invention to modify the regression techniques in the drilling rig state determination (title) of COLEY with linear regression of the well data analysis (title) of POP [to arrive at the claimed features] for the purpose of eliminating delays and errors, and to improve the accuracy of the parameters derived (POP at Para. [0017]).
Regarding claim 3, COLEY as modified discloses the method of claim 2, wherein the one or more identified index points correspond to one or more changes in the gradient transition of the sensor data (the pressure curve near the end of the buildup may in some cases be relatively horizontal or sufficiently flat, and/or the rate of change of pressure may be small or close to zero … this may indicate that the pressure has stabilized and reached formation pressure, and that the final pressure is a good estimate of the formation pressure … in other cases the rate of change of pressure may be large (increasing or decreasing) which may indicate that the formation pressure has not yet been reached … information may also be used to determine that the pretest has not reached stabilization, Para. [0330] of POP).
Regarding claim 4, COLEY as modified discloses the method of claim 2, wherein: positive slope values of a line representing the gradient transition of the sensor data between two identified index points correspond to a first macro activity of well site operations; negative slope values of the line representing the gradient transition of the sensor data between two identified index points correspond to a second macro activity of wellsite operations; and flat slope values of the line representing the gradient transition of the sensor data between two identified index points correspond to a third macro activity of wellsite operations (the pressure curve near the end of the buildup may in some cases be relatively horizontal or sufficiently flat, and/or the rate of change of pressure may be small or close to zero … this may indicate that the pressure has stabilized and reached formation pressure, and that the final pressure is a good estimate of the formation pressure … in other cases the rate of change of pressure may be large (increasing or decreasing) which may indicate that the formation pressure has not yet been reached … information may also be used to determine that the pretest has not reached stabilization, Para. [0330] of POP; [Examiner’s Note: the claim 4 does not require that the first macro activity and the second macro activity are different activities, thus the stabilization activity can be interpreted as corresponding to the first macro activity and the second macro activity, and the not stabilized activity/state is interpreted as corresponding to the flat slope value/third macro activity]).
Regarding claim 7, COLEY as modified discloses the method of claim 6, wherein generating the time series data from the obtained sensor data comprises generating (in block 406, for each measurement of hole depth or bit depth, the pre-processing module calculates the difference of hole depth and bit depth, Para. [0045] of COLEY; See also next paragraph: given difference in hole depth and bit depth at times T, T−1, T−2, T−3, T−4, T−5, T−6, T+1, T+2, T+3, T+4, T+5, and T+6 calculated in block 406, the pre-processing module 212 may calculate lagged values as difference of the difference of hole and bit depth as T−(T−1), T−(T−2), T−(T−3), T−(T−4), T−(T−5), and T−(T−6), and calculate leading values as difference of the difference of hole and bit depth at T−(T+1), T−(T+2), T−(T+3), T−(T+4), T−(T+5), and T−(T+6) for depth data sampled at 0.2 hertz, Para. [0046] of COLEY).
COLEY fails to explicitly disclose a time series curve for generating time series data. POP, however, discloses a time series curve for generating time series data (the pressure curve near the end of the buildup may in some cases be relatively horizontal or sufficiently flat, and/or the rate of change of pressure may be small or close to zero … this may indicate that the pressure has stabilized and reached formation pressure, and that the final pressure is a good estimate of the formation pressure … in other cases the rate of change of pressure may be large (increasing or decreasing) which may indicate that the formation pressure has not yet been reached … information may also be used to determine that the pretest has not reached stabilization, Para. [0330] of POP).
It would have been obvious for one of ordinary skill in the art before the effective filing date of the invention to modify the time series analysis in the drilling rig state determination (title) of COLEY with time series curve-based analysis of the well data analysis (title) of POP [to arrive at the claimed features] for the purpose of eliminating delays and errors, and to improve the accuracy of the parameters derived (POP at Para. [0017]).
Regarding claim 8, COLEY as modified discloses the method of claim 7, wherein generating the time series data of the obtained sensor data (shown in the mapping of claim 1 above), regression (Para. [0037] of COLEY, Para. [0121] of DUNLOP) and sensor data analytics with respect to borehole depth and the difference between borehole depth and bit depth (in block 408, the pre-processing module 212 calculates changes in difference of hole depth and bit depth … given difference in hole depth and bit depth at times T, T−1, T−2, T−3, T−4, T−5, T−6, T+1, T+2, T+3, T+4, T+5, and T+6 calculated in block 406, Para. [0046] of COLEY; See also the pre-processed sensor measurements and additional values generated by the pre-processing module 212 are provided to the rig state model 216 for use in producing a rig state value, Para. [0050] of COLEY) but fails to explicitly disclose using a linear regression to determine a gradient for the time series curve.
POP, however, is in the field of evaluating data collected in a downhole/well log (Para. [0002] of POP) and teaches wherein generating the time series data from the obtained sensor data (the investigation phase may be analyzed to determine the pressure drop over time to determine various characteristics of the pressure trace, Para. [0101]; See also using conventional pressure and temperature sensors, Para. [0201] of POP) comprises using a linear regression (measured pressure rate may be determined from a pressure curve slope … known techniques comprise curve fitting, linear regression, Para. [0327] of POP) to determine a gradient transition of the time series curve (the pressure curve near the end of the buildup may in some cases be relatively horizontal or sufficiently flat, and/or the rate of change of pressure may be small or close to zero … this may indicate that the pressure has stabilized and reached formation pressure, and that the final pressure is a good estimate of the formation pressure … in other cases the rate of change of pressure may be large (increasing or decreasing) which may indicate that the formation pressure has not yet been reached … information may also be used to determine that the pretest has not reached stabilization, Para. [0330] of POP).
It would have been obvious for one of ordinary skill in the art before the effective filing date of the invention to modify the evaluation of the sensor data analytics (including borehole depth and the difference between borehole depth and bit depth) in the drilling rig state determination (title) of COLEY with linear regression of the well data analysis (title) of POP [to arrive at the claimed features] for the purpose of eliminating delays and errors, and to improve the accuracy of the parameters derived (POP at Para. [0017]).
Regarding claim 15, COLEY as modified discloses the system of claim 12, wherein generating the time series data from the obtained sensor data (shown in the mapping of claim 12 above) and regression (Para. [0037] of COLEY, Para. [0121] of DUNLOP) but fails to explicitly disclose using a linear regression to determine a gradient transition of the obtained sensor data over time , wherein the one or more identified index points correspond to one or more changes in the gradient transition of the sensor data.
POP, however, is in the field of evaluating data collected in a downhole/well log (Para. [0002] of POP) and teaches wherein generating the time series data from the obtained sensor data (the investigation phase may be analyzed to determine the pressure drop over time to determine various characteristics of the pressure trace, Para. [0101]; See also using conventional pressure and temperature sensors, Para. [0201] of POP) comprises using a linear regression (measured pressure rate may be determined from a pressure curve slope … known techniques comprise curve fitting, linear regression, Para. [0327] of POP) to determine a gradient transition of the obtained sensor data over time (the pressure curve near the end of the buildup may in some cases be relatively horizontal or sufficiently flat, and/or the rate of change of pressure may be small or close to zero … this may indicate that the pressure has stabilized and reached formation pressure, and that the final pressure is a good estimate of the formation pressure … in other cases the rate of change of pressure may be large (increasing or decreasing) which may indicate that the formation pressure has not yet been reached … information may also be used to determine that the pretest has not reached stabilization, Para. [0330] of POP), wherein the one or more identified index points correspond to one or more changes in the gradient transition of the sensor data (the pressure curve near the end of the buildup may in some cases be relatively horizontal or sufficiently flat, and/or the rate of change of pressure may be small or close to zero … this may indicate that the pressure has stabilized and reached formation pressure, and that the final pressure is a good estimate of the formation pressure … in other cases the rate of change of pressure may be large (increasing or decreasing) which may indicate that the formation pressure has not yet been reached … information may also be used to determine that the pretest has not reached stabilization, Para. [0330] of POP).
It would have been obvious for one of ordinary skill in the art before the effective filing date of the invention to modify the regression techniques in the drilling rig state determination (title) of COLEY with linear regression of the well data analysis (title) of POP [to arrive at the claimed features] for the purpose of eliminating delays and errors, and to improve the accuracy of the parameters derived (POP at Para. [0017]).
Claim 19 is rejected under 35 U.S.C. § 103 as being unpatentable over COLEY (U.S. Patent Publication No. 2021/0285315 A1 in view of DUNLOP et al (U.S. Patent Publication No. 2004/0124012 A1), and further in view of MANDAVA et al. (U.S. Patent Publication No. 2017/0300845 A1) and VIDAL et al. (U.S. Patent Publication No. 2020/0364133 A1).
Regarding claim 19, COLEY as modified discloses the computer-readable storage medium of claim 18, wherein performing statistical analysis on the time series data comprises (rate of penetration sensors 226 detect motion of the traveling block 106 or extension of the line supporting the traveling block 106, or other indications of the drill string 108 descending into the borehole 116, Para. [0027] of COLEY; See also traveling block 106 corresponds to hookload: a sensor associated with the traveling block 106 may be used to measure and provide hookload measurements … hookload refers to the weight of the load supported by the drawworks 136, including the weight of the traveling block 106 and any components supported by the traveling block 106 (e.g., the drill string 108), Para. [0018] of COLEY).
COLEY fails to explicitly disclose applying a Pruned Exact Linear Time (PELT) algorithm to the time series data within each time segment of the first set of time segments to detect.
VIDAL, however, is in directed at the same problem of changepoint analysis and teaches applying a Pruned Exact Linear Time (PELT) algorithm to the time series data within each time segment of the first set of time segments to detect (change-point detection is done using the Pruned Exact Linear Time (PELT) method, Para. [0066] of VIDAL).
It would have been obvious for one of ordinary skill in the art before the effective filing date of the invention to modify the changepoint techniques in the drilling rig state determination (title) of COLEY with the PELT algorithm to detect changepoint as in VIDAL [to arrive at the claimed features] for the purpose of avoiding erroneous conclusions (VIDAL at Para. [0067]).
Claim 20 is rejected under 35 U.S.C. § 103 as being unpatentable over COLEY (U.S. Patent Publication No. 2021/0285315 A1 in view of DUNLOP et al (U.S. Patent Publication No. 2004/0124012 A1), and further in view of MANDAVA et al. (U.S. Patent Publication No. 2017/0300845 A1), VIDAL et al. (U.S. Patent Publication No. 2020/0364133 A1) and POP et al. (U.S. Patent Publication No. 2009/0165548 A1).
Claim 20 has substantially similar limitations as recited in claim 8, except it depends from parent claim 19; therefore, it is rejected under 35 U.S.C. § 103 using POP et al, as applied in claim 8.
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure: KHARE et al. (US 2015/0371344 A1) published Dec. 24, 2015. KHARE was cited in International Search Report and Written Opinion (ISR/WO) issued for International Patent Application No. PCT/US2019/058612 dated July 22, 2020. Both KHARE and the ISR/WO were cited in Applicant’s 02/04/2022 IDS. KHARE, at Para. [0021] teaches “sensor data is processed at 204 to obtain a rig state (or rig state as a function of time) … the rig state describes the state of operation of the drilling rig (the rig activity) at any particular time, for example, the rig may be rotary drilling, slide drilling, tripping out, tripping in, rotating, circulating, idle, etc.” and at Para. [0022] teaches “rig activity report may alternatively and/or additionally include a summary of major activities (a macro activity report) based on predetermined aggregation parameters or a time based reporting format, for example, including an hourly or daily report.” See also ISR/WO mentioned above for further teachings of KHARE.
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 nonprovisional extension fee (37 CFR 1.17(a)) 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 mailing date of this final action.
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JOHN P. HOCKER
Examiner
Art Unit 2189
/JOHN P HOCKER/Examiner, Art Unit 2189
/REHANA PERVEEN/Supervisory Patent Examiner, Art Unit 2189
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