DETAILED ACTION
Notice of Pre-AIA or AIA Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Response to Arguments
Applicant's arguments filed 01/23/26 have been fully considered but they are not persuasive.
With respect to the 35 U.S.C. 103 rejection, the applicant first argues:
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This argument is not persuasive because the applicant states that “the claimed invention discloses …” but then cites a section from the substitute specification and not the claims. The examiner could not find the bolded section of “or may not intersect the borehole and may be imaged at locations a few feet to 100 feet or more from the borehole …” anywhere in the claims.
The applicant appears to be substituting “claimed disclosure” with disclosure in the specification. The examiner gives broadest reasonable interpretation to the claimed invention and does not read in unclaimed elements from the specification.
Next, the applicant argues:
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This argument is not persuasive because Hornby does not only apply to straight boreholes, nor does Hornby only disclose a 1-D velocity model. As seen in the rejection below, Hornby also discloses curved wellbores and also 2-D velocity models. Here, the applicant makes a statement that “Hornby admits that boreholes can be curved in general, Hornby discloses a method that is only applicable to straight boreholes.” The applicant gives no basis for such an assertion. However, as seen in the rejection below, Hornby’s disclosure of curved wellbores (paragraph 0022) is very similar to the applicant’s own disclosure of curved boreholes (paragraph 0052). That is, both Hornby and the applicant’s substitute specification give a general statement of wellbores/boreholes being curved, in the context of other variations, including horizontal, vertical, slanted, etc … If the applicant’s arguments of Hornby lacking specific, non-general teachings of “curved” were true, then that would also disqualify the applicant’s own disclosure. Neither the applicant’s substitute specification nor claims give any detail of any specific nexus between the curved path and how the model is exclusively dependent on that curved path. Also, as shown in the new 112 rejection below, the applicant’s disclosure also does not specifically state that the initial velocity model is a 2-D or multi-dimensional model.
Next, the applicant argues:
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This argument is not persuasive because Yogeswaren was applied specifically as a secondary reference to modify the primary reference of Hornby, which does teach “away form the wellbore” and “sonic reflection imaging” (abstract). Yogeswaren was applied to teach a data processing approach, and the examiner contends that it would be obvious to one of ordinary skill in the art to apply data processing approaches to a wide variety of context and applications. The examiner considers Horny and Yogeswaren to be analogous art, given that both are directed to the field of endeavor of borehole analysis.
Furthermore, the phrase “away from the borehole” does not appear in the claims. The applicant appears to be reading in a narrow, unclaimed interpretation and then arguing that Yogeswaren lacks that narrow, unclaimed element. The examiner gives claims their broadest reasonable interpretation. Even if, for argument’s sake, Yogeswaren lacked the element that the applicant asserts that it lacks, if such an element is not claimed, then the argument is moot.
Finally, please note that Yogeswaren incorporates many references into its disclosure. For example, Yogeswaren column 2, paragraph 2 states, “Prior art multiple acoustic logging systems comprise … Such a system is disclosed by Pistre et al, ‘A Modular Wireline Sonic Tool for Measurements of 3D …’” Yogeswaren is not limited to just its immediate disclosure but all of the knowledge and evidence that it incorporates by reference. The applicant appears to be limiting the breadth and vastness of what Yogeswaren discloses, teaches, or suggests. The applicant cited KSR in arguing that “mere common sense and recitation of ‘known’ elements do not necessarily satisfy a motivation to combine analysis.” However, the examiner here is not relying on common sense but on the fact that the primary reference teaches the elements that applicant asserts Yogeswaren lacks, and Yogeswaren itself incorporates by reference a vast library of knowledge regarding what would be known or obvious to one of ordinary skill in the art; such knowledge cannot be ignored or written off as mere common sense.
Next, the applicant argues:
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This argument is not persuasive because the limitation in question is, “wherein the full-waveform sonic dataset has not been preprocessed to separate signals based on propagation direction.” This is an extremely broad limitation, in that there is no context or details given as to what constitutes, “has not been preprocessed.”
Here, the applicant appears to equate “has not been preprocessed” to using sonic logging or sonic reflection imaging data that measures only scalar pressure values. However, neither the applicant’s specification nor claims seem to mention this. Neither the applicant’s specification nor the claims mention polarization (or a lack thereof) either.
The examiner reminds the applicant that broadest reasonable interpretation is applied to the claims, and given the broadness of the claimed limitation, the examiner contends that the basis of rejection (around using travel time tables) may be broad but is reasonable, especially in view of the little that the applicant’s specification discloses about “no pre-processing.” The examiner suggests that the claims be amended to specifically define what constitutes “not been preprocessed” and also show where such a definition is supported in the applicant’s disclosure.
Finally, the applicant argues, “neither Hornby, Yogeswaren, nor Leaney discloses an initial sonic velocity model that varies in at least two spatially dimensions.” However, as seen below, this limitation necessitated a new 112(a) and (b) rejection. For the purposes of examination, the examiner adopted an interpretation of the limitation that is disclosed by the art. If this interpretation does not match the applicant’s interpretation, the examiner suggests clarifying the claims.
The applicant’s other arguments are moot in view of the rejection below.
Appropriate correction is required.
Drawings
As stated in a previous rejection, the Specification and Drawing Amendments of 12/10/24 are accepted.
Claim Objections
Please note that the 01/23/26 claim amendments state that the Application No. is 17/071774. However, the application number is actually 18/738556. It will be construed that the amendment should list an application number of 17/071774.
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Also, claims 8 and 18 of the 01/23/26 amendment state “(Previously presented)” but appear to ignore the amendments made on 04/01/25. The 04/01/25 amendments will be the one that are considered to be pending.
Appropriate correction is required.
Examiner’s Note - 35 USC § 101
As stated in a previous action, in view of the applicant’s amendments of 12/20/24, claims 1-4, 6-8, 11-15, 17-18, and 21-26 qualify as eligible subject matter under 35 U.S.C. 101.
Claim Rejections - 35 USC § 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.
The following is a quotation of the first paragraph of pre-AIA 35 U.S.C. 112:
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 of carrying out his invention.
Claims 1-4, 6-8, 11-15, 17-18, and 21-26 are rejected under 35 U.S.C. 112(a) or 35 U.S.C. 112 (pre-AIA ), first paragraph, 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, or for applications subject to pre-AIA 35 U.S.C. 112, the inventor(s), at the time the application was filed, had possession of the claimed invention.
Independent claims 1 and 13 have been amended to include the following limitation:
wherein the initial sonic velocity model varies in at least two spatially dimensions.
The examiner could not find support for this limitation in the substitute specification of 12/10/24.
The examiner found the following six instances of “spatial” or spatially” in the substitute specification:
[0004] Accurate and detailed velocity models are required for high-resolution sonic imaging, yet conventional methods typically rely only on spatially restricted information acquired at the borehole.
[0006] wherein the trajectory characterizes a spatial path of the borehole through the subterranean region in a first coordinate system.
[0007] wherein the trajectory characterizes a spatial path of the borehole through the subterranean region in a first coordinate system.
[0052] the trajectory may describe the spatial path of the borehole in depth and one or two horizontal space dimensions.
[0093] the sonic velocity model may be spatially smoothly or slowly varying.
[0094] The trajectory may characterize the spatial path of the borehole …
Paragraph 0004 appears to be directed to spatially restricted information and not the spatial dimensions of an initial sonic velocity model.
Paragraphs 0006-0007, 0052, and 0094 appear to be directed to a borehole path trajectory and not the spatial dimensions of an initial sonic velocity model.
Paragraph 0093 does reference an initial velocity model, but it merely states that the model may be spatially smoothly or slowly varying. It does not mention varying in at least two spatially dimensions.
The examiner is unsure if this limitation is merely another way of stating that the initial velocity model is a multi-dimensional or 2D velocity model. However, although the examiner did find disclosure of 2D velocity models in the applicant’s substitute specification, the examiner did not find any support for the initial velocity model being a 2D velocity model. The word “initial” was only found twice, once in paragraph 0070 and once in paragraph 0093 of the applicant’s substitute specification. Neither section discloses that the initial velocity model is a 2D velocity model. Paragraph 0070 states, “the initial velocity model 802 in the first coordinate system is transformed to velocity model in a second coordinate system …” but is silent about the spatial dimensions of the initial velocity model. Paragraph 0093 states, “The sonic velocity model may form an initial velocity model … the sonic velocity model may be spatially smoothly or slowly varying …” but is silent about the spatial dimensions of the initial velocity model.
For the purposes of examination, the examiner will construe any disclosure of multi-dimensional or 2D velocity models to read on the claimed limitation.
All other claims depend on claims 1 and 13 and are rejected as a result of their dependency.
Furthermore, new claims 22-23 and 25-26 disclose the following limitations:
wherein forming the first directional sonic image comprises:
determining, for each of a plurality of origin points, separate by one another by intervals 0.25 feet along the borehole axis, a travel time from each origin point to each image point on a grid of image points
selecting a first origin point, and a portion of the grid of image points, closest to a source location,
wherein the grid of image points extends a greater distance from the first origin point in a shallower/deeper direction along the borehole axis than in a deeper/shallower direction
determining a grid of source travel times comprising the travel times from the first origin point to each of the image points within the portion
selecting a second origin point closest to a receiver location
determining a grid of receiver travel times comprising the travel times from the second origin point to each of the image points within the portion
forming the first directional sonic image based on the grid of source travel time, the grid of receiver travel times, and the full-waveform sonic dataset without pre-separation (or forming the second directional sonic image based on the grid of source travel time, the grid of receiver travel times, and the full-waveform sonic dataset without pre-separation)
The examiner could not find support for this set of limitations in the applicant’s disclosure. While the examiner did find support for a grid of 0.25 ft in the applicant’s substitute specification (paragraphs 0074), the examiner could not find support for all of the limitations related to origin points. In fact, the examiner could not find a single disclosure of “origin point” in the applicant’s substitute specification. The examiner could also not find support for all of the detailed limitations relating origin points to other aspects of the grid. The examiner requests that the applicant show where the combined limitations are supported in the disclosure.
The following is a quotation of 35 U.S.C. 112(b):
(b) CONCLUSION.—The specification shall conclude with one or more claims particularly pointing out and distinctly claiming the subject matter which the inventor or a joint inventor regards as the invention.
The following is a quotation of 35 U.S.C. 112 (pre-AIA ), second paragraph:
The specification shall conclude with one or more claims particularly pointing out and distinctly claiming the subject matter which the applicant regards as his invention.
Claims 1-4, 6-8, 11-15, 17-18, and 21-26 are rejected under 35 U.S.C. 112(b) or 35 U.S.C. 112 (pre-AIA ), second paragraph, as being indefinite for failing to particularly point out and distinctly claim the subject matter which the inventor or a joint inventor (or for applications subject to pre-AIA 35 U.S.C. 112, the applicant), regards as the invention.
Independent claims 1 and 13 have been amended to include the following limitation:
wherein the initial sonic velocity model varies in at least two spatially dimensions.
It is unclear what “spatially dimensions” entails. The examiner is not sure if the claim meant to state “spatial dimensions” or “spatially [insert adjective] dimensions,” such as “spatially perpendicular dimensions.” The scope of the claims change depending on which interpretation is taken. For the purposes of examination, the examiner will construe any disclosure of multi-dimensional or 2D velocity models to read on the claimed limitation.
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.
Claim(s) 1-4, 8, 11, 13-15, and 18 is/are rejected under 35 U.S.C. 103 as being unpatentable over Hornby et al (US PgPub 20210047917) in view of Yogeswaren et al (US Pat 7529150) and Leaney (US PgPub 20090010104). As an illuminating, non-modifying reference, please also note the Wikipedia entry on “curvilinear coordinates,” which has a snapshot of March 7, 2023. This reference is only applied to give context to what would be known to one of ordinary skill in the art.
With respect to claim 1, Hornby et al discloses:
A method (figures 3-4; paragraph 0031 states, “borehole sonic logging tool 102 may be used to develop an improved reflection borehole sonic image by using image-guided velocity models using an iterative process.”; paragraph 0034 states, “Flowchart 400 may depict a method to update a velocity model to achieve an accurate and high-quality borehole sonic image … Flowchart 400 may comprise multiple steps to create the reflection borehole sonic image …”), comprising:
acquiring, using a borehole sonic tool, a full-waveform sonic dataset pertaining to a borehole penetrating a subterranean region (paragraph 0035 states, “The borehole sonic data may include any suitable sonic data for generating a formation image for dip analysis. Suitable data may include full-waveform data and the corresponding velocity logs. The term “full-waveform” data may be defined as data recorded at each receiver of the signal response of the waves impacting the receiver, as a function of time.”), wherein the borehole sonic tool comprises at least one source and at least one receiver (paragraph 0024 states, “Transmitter 128 may be a monopole source …”; paragraph 0025 states, “Borehole sonic logging tool may also include a receiver 130.”)
using a sonic processing system (paragraph 0019 states, “For example, signals recorded by borehole sonic logging tool 102 may be stored on memory and then processed by borehole sonic logging tool 102. The processing may be performed real-time during data acquisition or after recovery of borehole sonic logging tool 102.”):
receiving the full-waveform sonic dataset (figure 4, reference 402; figure 5; paragraphs 0034-0035)
obtaining an initial sonic velocity model pertaining to the subterranean region (figure 4, reference 404; paragraph 0036)
wherein the initial sonic velocity model varies in at least two spatially dimensions (As discussed in the 112 rejection above, for the purposes of examination, the examiner will construe any disclosure of multi-dimensional or 2D velocity models to read on the claimed limitation. Paragraphs 0047-0049 of Hornby state, “An example of an updated 2-D velocity model 800 that may be generated using the relative dip angle is illustrated in FIG. 8. Velocity model 800 may show the combined up-dip and down-dip velocity models … The methods previously described may be initially implemented using an assumption that the relative dip angle of formation 132 is constate (linear) … That may not always be the case … the iterative solution to update the 2-D velocity model along the relative dip angle as a function of depth in flowchart 400 may take into account complex structural changes … After the creation of the 2-D velocity model, step 416 may occur.”)
obtaining a borehole trajectory, wherein the trajectory characterizes a spatial path of the borehole through the subterranean region in a first coordinate system (paragraph 0036 states, “After obtaining the borehole sonic data, step 404 may then be implemented. Step 404 may comprise generating an initial 1-dimensional (1-D) velocity model that follows the path of wellbore 124 as a function of depth.”; Following the path of the wellbore as a function of depth suggests a trajectory.); and wherein the trajectory is curved in the first coordinate system (paragraph 0022 states, “Generally, wellbore 124 may include horizontal, vertical, slanted, curved, and other types of wellbore geometries and orientation.” Please compare this teaching of Hornby with paragraph 0052 of the substitute specification of the current application, which states, “Generally, borehole 124 may include horizontal, vertical, slanted, curved, and other types of borehole geometries and orientations.” Both Hornby and the applicant’s disclosure recognize curved trajectories as known variations of other types of trajectories.)
With respect to claim 1, Hornby et al differs from the claimed invention in that it does not explicitly disclose:
forming a local velocity model, wherein forming comprises transforming the sonic velocity model for a portion of the earth from the first coordinate system into a second coordinate system:
wherein the first coordinate system comprises a vertical axis and at least one horizontal axis
and wherein the second coordinate system comprises a first axis everywhere parallel to the borehole trajectory and a second axis perpendicular to the first axis
forming a sonic image in the second coordinate system from the sonic velocity model in the second coordinate system and the full-waveform sonic dataset, wherein the full-waveform sonic dataset has not been preprocessed to separate signals based on propagation direction
transforming the sonic image from the second coordinate system into the first coordinate system
identifying, using a sonic interpretation workstation, a location of a sonic reflector within the sonic image
identifying a preferred completion plan for the borehole based, at least in part, on the location of a sonic reflector within the sonic image
completing the borehole guided by the preferred completion plan
With respect to claim 1, Yogeswaren et al discloses:
forming a local velocity model, wherein forming comprises transforming the sonic velocity model for a portion of the earth from the first coordinate system into a second coordinate system (figure 14A (see disclosure of “Local” axes); column 12, line 57 – column 13, line 24 state, “Three reference coordinate systems are used to disclose the logging system and are illustrated in FIG. 14A. The borehole 22, with a major axis 120, penetrates earth formation 47. The global coordinate system (X1, X2, X3) references the location of the well borehole with respect to other geographic features including additional well boreholes … The local borehole coordinate system (x1, x2, x3), references the configuration of the borehole 22, at a given depth within the borehole, where depth is measured axially from the surface 26 of the earth.”; The claimed limitation is obvious in view of combination. Hornby et al teaches sonic velocity model to describe borehole logging. Yogeswaren et al teaches representing logging data in multiple coordinate systems that can be transformed from one to another interchangeably.):
wherein the first coordinate system comprises a vertical axis and at least one horizontal axis (figure 14A; column 12, line 57 – column 13, line 24 state, “Three reference coordinate systems are used to disclose the logging system and are illustrated in FIG. 14A. The borehole 22, with a major axis 120, penetrates earth formation 47. The global coordinate system (X1, X2, X3) references the location of the well borehole with respect to other geographic features including additional well boreholes … The local borehole coordinate system (x1, x2, x3), references the configuration of the borehole 22, at a given depth within the borehole, where depth is measured axially from the surface 26 of the earth.”; The global coordinate system will be construed under broadest reasonable interpretation (BRI) to represent the claimed first coordinate system.)
and wherein the second coordinate system comprises a first axis everywhere parallel to the borehole trajectory and a second axis perpendicular to the first axis (figure 14A; column 12, line 57 – column 13, line 24 state, “Three reference coordinate systems are used to disclose the logging system and are illustrated in FIG. 14A. The borehole 22, with a major axis 120, penetrates earth formation 47. The global coordinate system (X1, X2, X3) references the location of the well borehole with respect to other geographic features including additional well boreholes … The local borehole coordinate system (x1, x2, x3), references the configuration of the borehole 22, at a given depth within the borehole, where depth is measured axially from the surface 26 of the earth … The local borehole coordinates (x1, x2, x3) are, therefore, known at any location as the tool 10 is conveyed along the borehole. The local borehole coordinates can therefore, be transformed into the coordinates (X1, X2, X3) of the global coordinate system … The local borehole coordinate system (x1, x2, x3,) is related to the global coordinate system (X1, X2, X3) by continuously measuring the azimuth and the inclination of the borehole as a function of depth.”; The local coordinate system will be construed under broadest reasonable interpretation (BRI) to represent the claimed second coordinate system. Please note how in figure 14A, the arrow for x3 is parallel to the borehole trajectory, and the arrow x1 is perpendicular to the axis represented by arrow x3.)
forming a sonic image in the second coordinate system from the sonic velocity model in the second coordinate system and the full-waveform sonic dataset (obvious in view of combination; As discussed above, Hornby et al discloses sonic image, sonic velocity model, and full-waveform sonic dataset. Yogeswaren et al discloses representing data in second coordinate system. Yogeswaren et al also discloses performing image data and velocity analysis on image data (figure 3, reference 65; column 1, lines 31-35; column 5, lines 32-35; column 8, lines 37-65; column 9, lines 30-52; and column 10, lines 26-55).).
transforming the sonic image from the second coordinate system into the first coordinate system (obvious in view of combination; column 13, lines 14-16 state, “The local borehole coordinates can, therefore, be transformed into the coordinates (X1, X2, X3) of the global coordinate system.”)
identifying, using a sonic interpretation workstation, a location of a sonic reflector within the sonic image (obvious in view of combination; Primary reference Hornby et al paragraph 0028 discloses, “a microprocessor or other suitable circuitry, for estimating, receiving and processing signals.” Hornby et al paragraphs 0041-0042 state, “Manual estimation may occur, for example, from interpretation of the first reflection image … By interpretation of 2-D reflection image …”)
identifying a preferred completion plan for the borehole based, at least in part, on the location of a sonic reflector within the sonic image (obvious in view of combination; paragraph 0055 of Hornby et al states, “the reflection image is typically used for a number of functions, including, but not limited to, providing information for making drilling, completion, and production decisions.”)
completing the borehole guided by the preferred completion plan (suggested by paragraph 0055 of Hornby et al)
With respect to claim 1, it would have been obvious to one having ordinary skill in the art before the effective filing date of the invention to incorporate the teachings of Yogeswaren et al into the invention of Hornby et al. The motivation for the skilled artisan in doing so is to gain the benefit of simplifying the interpretation and analysis of sonic data, as it pertains to a borehole trajectory.
With respect to claim 1, Leaney discloses:
wherein the full-waveform sonic dataset has not been preprocessed to separate signals based on propagation direction (Paragraph 0006 states, “Current hydraulic fracture monitoring comprises methods of processing seismic event locations by mapping seismic arrival times and polarization information into three-dimensional space through the use of modeled travel times and/or ray paths. Travel time look-up tables may be generated by modeling for a given velocity model.” This is consistent with the applicant’s disclosure in paragraphs 0074 and 0080 of the applicant’s substitute specification of 12/10/24, which discloses using travel time tables in the context of “no pre-processing of the full-waveform sonic data to separate up and downgoing arrivals and using the travel time tables …”)
With respect to claim 1, it would have been obvious to one having ordinary skill in the art before the effective filing date of the invention to incorporate the teachings of Leaney into the invention of modified Hornby et al. The motivation for the skilled artisan in doing so is to gain the benefit of simplifying signal analysis by avoiding the need to preprocess signals.
Independent claim 13 represents the system version of method claim 1. It is rejected for similar reasons as claim 1 above.
In the claim amendments of 12/20/24, the last limitation of claim 13 has been amended to state, “a drilling system, configured to drill a future borehole guided, at least in part, by the location of the sonic reflector and the sonic image.” This is slightly different than the wording of the last two limitations of claim 1. Nonetheless, this limitation is also disclosed by modified Hornby et al. Figure 2, reference 200 of Hornby et al shows a drilling system, and reference 102 shows a sonic borehole logging tool.
With respect to claims 2 and 14, Hornby et al, as modified, discloses:
using the sonic processing system (as discussed above):
forming an updated sonic velocity model based, at least in part on the location of the sonic reflector (obvious in view of combination; figure 4 of Hornby discloses an iterative process between references 412-418. Reference 414 discloses “Generate updated velocity model.”)
transforming the updated sonic velocity model from the first coordinate system into a second coordinate system (obvious in view of applying the second coordinate system teachings of Yogeswaren et al to the sonic teachings of Hornby et al.)
forming an updated sonic image in the second coordinate system from the sonic velocity model in the second coordinate system and the full-waveform sonic dataset (obvious in view of applying the second coordinate system teachings of Yogeswaren et al to the sonic teachings of Hornby et al.)
transforming the sonic image from the second coordinate system into the first coordinate system (discussed above with respect to Yogeswaren et al)
identifying an updated location of the sonic reflector within the sonic image (obvious in view of combination; Hornby teaches updating velocity model and interpreting sonic data)
With respect to claims 3 and 15, Hornby et al, as modified, discloses:
wherein forming the sonic image (figure 4) comprises,
iteratively, or recursively, until a stopping criterion is met (Hornby figure 4, reference 418):
forming a candidate sonic image in the second coordinate system from the sonic velocity model in the second coordinate system and the full-waveform sonic dataset (obvious in view of combination, for similar reasons as discussed above. Hornby et al teaches sonic data interpretation in the context of a wellbore. Yogeswaren et al teaches first and second coordinate systems in the context of borehole trajectory.)
identifying a location of a candidate sonic reflector within the sonic image (obvious in view of combination; Hornby et al teaches sonic data interpretation in the context of a wellbore. Yogeswaren et al teaches first and second coordinate systems in the context of borehole trajectory.)
updating sonic velocity model based, at least in part on the location of the candidate sonic reflector (obvious in view of update teachings of Hornby)
designating the sonic image to be the candidate sonic image satisfying the stopping criterion (obvious in view of combination; Hornby discloses stopping condition and sonic images.)
With respect to claim 4, Hornby et al, as modified, discloses:
wherein the stopping criterion is based on a metric quantifying a difference between a current candidate sonic image and a candidate sonic image from a previous iteration (obvious in view of combination; paragraph 0050 of Hornby states, “A subsequent step may be a decision step 418 to determine whether a stop criterion has been met. In decision step 418, a determination step may be made whether change between the updated reflection image and the first reflection image is acceptable.”)
With respect to claims 8 and 18, Hornby et al, as modified, discloses:
wherein forming the sonic image (discussed above) comprises:
forming a first directional sonic image from the full-waveform sonic dataset, wherein the first directional sonic image comprises sonic reflectors that generate downgoing arrivals at every receiver (obvious in view of combination; The abstract of Hornby et al states, “separating up-going arrivals in the borehole sonic data from down-going arrivals in the borehole sonic data …” Paragraphs 0038-0039 state, “step 408 may comprise up- and down-going arrivals in the borehole sonic data. As previously described, the up- and down-going arrivals may have been received along the borehole sonic logging tool 102 …” See also extensive sonic travel teachings of Hornby et al, such as in paragraph 0025. As discussed above, Hornby et al also teaches full-waveform data (see paragraph 0035).)
and forming a second directional sonic image from the full-waveform sonic dataset, wherein the second directional sonic image comprises sonic reflectors that generate upgoing arrivals at every receiver (obvious in view of combination; The abstract of Hornby et al states, “separating up-going arrivals in the borehole sonic data from down-going arrivals in the borehole sonic data …” Paragraphs 0038-0039 state, “step 408 may comprise up- and down-going arrivals in the borehole sonic data. As previously described, the up- and down-going arrivals may have been received along the borehole sonic logging tool 102 …” See also extensive sonic travel teachings of Hornby et al, such as in paragraph 0025. As discussed above, Hornby et al also teaches full-waveform data (see paragraph 0035).)
With respect to claim 11, Hornby et al, as modified, discloses:
determining a high-resolution model of one or more Geomechanics properties based, at least in part, on the sonic image, the updated velocity model, and a well log of one or more formation properties (obvious in view of combination, particularly in view of the geophysical data interpretation teachings of Hornby et al; For example, paragraph 0017 of Hornby et al states, “These images may be used by a geologist and/or geophysical interpreter for a number of things ... By way of example, borehole sonic data may be gathered to construct a structure-guided velocity model …”)
Claim(s) 6-7 and 17 is/are rejected under 35 U.S.C. 103 as being unpatentable over Hornby et al (US PgPub 20210047917) in view of Yogeswaren et al (US Pat 7529150) and Leaney (US PgPub 20090010104), as applied to claims 1-4, 8, 11, 13-15, and 18 above, and further in view of Patterson et al (CA 2676123 A1).
With respect to claims 6 and 17, Hornby et al, as modified, discloses:
The method of claim 1 (as applied to claim 1 above)
The system of claim 13 (as applied to claim 13 above)
With respect to claims 6 and 17, Hornby et al, as modified, differs from the claimed invention in that it does not explicitly disclose:
wherein forming a sonic image comprises performing a pre-stack depth imaging process
With respect to claims 6 and 17, Patterson et al discloses:
wherein forming a sonic image comprises performing a pre-stack depth imaging process (paragraph 0040 of Patterson et al states, “Several migration techniques can be used … using a generalized Radon transform …” Please note paragraph 0040 of the applicant’s substitute specification of 12/10/24, which states, “Using this velocity model geological structure may be imaged away from the borehole using a pre-stack depth imaging code, such as … using pre-stack ray tracing solutions such as Generalized Radon Transform.”)
With respect to claims 6 and 17, it would have been obvious to one having ordinary skill in the art before the effective filing date of the invention to incorporate the teachings of Patterson et al into the invention of modified Hornby et al. The motivation for the skilled artisan in doing so is to gain the benefit of accurate imaging of features.
With respect to claim 7, Hornby et al, as modified, discloses:
wherein performing the pre-stack depth imaging process comprises a Generalized Radon Transform (paragraph 0040 of Patterson et al states, “Several migration techniques can be used … using a generalized Radon transform …”)
Claim(s) 12 is/are rejected under 35 U.S.C. 103 as being unpatentable over Hornby et al (US PgPub 20210047917) in view of Yogeswaren et al (US Pat 7529150) and Leaney (US PgPub 20090010104), as applied to claims 1-4, 8, 11, 13-15, and 18 above, and further in view of Tolman et al (US PgPub 20030010498).
With respect to claim 12, Hornby et al, as modified, discloses:
The method of claim 1 (as applied to claim 1 above)
With respect to claim 12, Hornby et al, as modified, differs from the claimed invention in that it does not explicitly disclose:
wherein the completing the borehole based on the location of the sonic reflector in the sonic image, comprises, at least one of: perforating a steel casing of the borehole to allow an influx of fluids, fracking the subterranean region surrounding a portion of the borehole, and cementing the steel casing into portions of a borehole that cross a geological fault to provide structural strength to the borehole
With respect to claim 12, Tolman et al discloses:
wherein the completing the borehole based on the location of the sonic reflector in the sonic image, comprises, at least one of: perforating a steel casing of the borehole to allow an influx of fluids, fracking the subterranean region surrounding a portion of the borehole, and cementing the steel casing into portions of a borehole that cross a geological fault to provide structural strength to the borehole (paragraph 0003 states, “When a hydrocarbon-bearing, subterranean reservoir formation does not have enough permeability or flow capacity for the hydrocarbons to flow … hydraulic fracturing … is often used to increase the flow capacity … Lateral holes (perforations) are shot through the casing … to allow hydrocarbon flow into the wellbore …”)
With respect to claim 12, it would have been obvious to one having ordinary skill in the art before the effective filing date of the invention to incorporate the teachings of Tolman et al into the invention of modified Hornby et al. The motivation for the skilled artisan in doing so is to gain the benefit of allowing hydrocarbons to flow at optimum rates.
Claim(s) 21 and 24 is/are rejected under 35 U.S.C. 103 as being unpatentable over Hornby et al (US PgPub 20210047917) in view of Yogeswaren et al (US Pat 7529150) and Leaney (US PgPub 20090010104), as applied to claims 1-4, 8, 11, 13-15, and 18 above, and further in view of Borgos et al (US PgPub 20190024501).
With respect to claims 21 and 24, Hornby et al, as modified, discloses:
The method of claim 1 (as applied to claim 1 above)
The system of claim 13 (as applied to claim 13 above)
With respect to claims 21 and 24, Hornby et al, as modified, differs from the claimed invention in that it does not explicitly disclose:
wherein the sonic reflector within the sonic image is a non-intersecting sonic reflector that does not intersect the borehole within the portion of the earth corresponding to the local velocity model
With respect to claims 21 and 24, Borgos et al discloses:
wherein the sonic reflector within the sonic image is a non-intersecting sonic reflector that does not intersect the borehole within the portion of the earth corresponding to the local velocity model (paragraph 0042 of Borgos et al states, “Previously, seismic super resolution constrained a seismic inversion into reflectivity, with the number of reflectors and their respective polarities at best observed at 1D locations of one or a few wells intersecting these reflectors. However, according to the present invention, the seismic inversion may be constrained with additional 2D or 3D information on the expected positions and amplitudes of the reflectors provided continuously along the trajectory of a wellbore drilled within a target formation, without the need to intersect the reflectors.” (emphasis mine).)
With respect to claims 21 and 24, it would have been obvious to one having ordinary skill in the art before the effective filing date of the invention to incorporate the teachings of Borgos et al into the invention of modified Hornby et al. The motivation for the skilled artisan in doing so is to gain the benefit of improved image obtainment of a subterranean section of the Earth.
Examiner’s Note - Allowable Subject Matter
New claims 22-23 and 25-26 disclose the following limitations, which when considered together as a whole, were not found, taught, suggested, or disclosed in the art. The limitations, when considered together, disclose multiple details that were not found in the art. However, as discussed above, the new claims necessitate the above 112(a) rejection. The same details that were not found in the art were also not found in the applicant’s disclosure. An ultimate determination of allowable subject matter cannot be fully determined until the above 112 rejection is overcome.
wherein forming the first directional sonic image comprises:
determining, for each of a plurality of origin points, separate by one another by intervals 0.25 feet along the borehole axis, a travel time from each origin point to each image point on a grid of image points
selecting a first origin point, and a portion of the grid of image points, closest to a source location,
wherein the grid of image points extends a greater distance from the first origin point in a shallower/deeper direction along the borehole axis than in a deeper/shallower direction
determining a grid of source travel times comprising the travel times from the first origin point to each of the image points within the portion
selecting a second origin point closest to a receiver location
determining a grid of receiver travel times comprising the travel times from the second origin point to each of the image points within the portion
forming the first directional sonic image based on the grid of source travel time, the grid of receiver travel times, and the full-waveform sonic dataset without pre-separation (or forming the second directional sonic image based on the grid of source travel time, the grid of receiver travel times, and the full-waveform sonic dataset without pre-separation)
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure.
Kristiansen et al (US PgPub 20200191985) discloses reflection seismology multiple imaging.
Qin et al (US PgPub 20190179043) discloses generating a velocity model for a subsurface structure using refraction traveltime tomography.
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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/LEONARD S LIANG/Examiner, Art Unit 2857
03/10/26
/ARLEEN M VAZQUEZ/Supervisory Patent Examiner, Art Unit 2857